Oil & Gas Inquirer April 2013

OIL&GAS April 2013 ~ $6.00

pu zz le

INQUIRER

Western Canada's Exploration & Production Authority

Putting together the LNG

PM40069240

Midstream operators begin building the supply chain for LNG exports

Plus: New ERCB rules to impact petroleum measurement and control schemes

Tundra Now Represents ABB, the World Leader in Measurement & Instrumentation Solutions ABB measurement products provide the best-in-class technology, reliability and service in the business. » Wired & Wireless Transmitters: Pressure, Temperature, Differential Pressure, Level and more » Flow: Magnetic, Vortex, Swirl, Coriolis, Thermal Mass, Variable Area, Totalflow Computers, & Differential Flow Elements » Analytical: Totalflow Natural Gas Chromatographs, pH, ORP, Combustion Gas Analyzers, and more » Valve Actuation: Actuators and Positioners » Recorders & Controllers: Process Recorders, Controllers & Indicators

Boilers & Water Treatment

Calgary Office 7523 Flint Road S.E. Calgary, AB T2H 1G3 | 403.255.5222

Motors & Drives

Instrumentation & Controls

Pipe, Valves & Actuation

Panels & Buildings

Artificial Lift

Service & Support

Regional Offices Edmonton, Saskatoon, Fort McMurray, Red Deer, Grande Prairie, Swift Current

We’ve come to Canada in full force.

With the support to back it up.

From our double conicals to our people, Dragon is fully committed to Canada. Start with our Canadian direct sales force, based at our location in Red Deer. They’re equipped with the expertise and inventory to readily support your operation, and many units can be delivered immediately.

Plus, spare parts are available 24/7 for all makes and models. Dragon’s Rocky Mountain Canadian Series is severe-duty engineered to perform in the harshest conditions. Our skilled engineers understand the unique stresses of Canadian worksites, and they’ve utilized automated robotic welding, thicker heads and shells, strengthened weld seams and more to answer the challenge.

Every Dragon unit is built in our state-of-the-art facility, and we can adjust our production to quickly meet specific orders. Whatever you need, we’ve got your equipment, and we’ve got your back. Make it happen. www.dragonproductsltd.com — 1-403-340-3600 © Copyright 2013 Modern Group Inc. All rights reserved.

Make it happen.

U.S. owned and operated for over 50 years.

BUSINESS PARK • GRANDE PRAIRIE

The Business Core for Grande Prairie

• 150,000 Sq Ft of office & light industrial • 3,000 - 10,000 Sq Ft drive-in and dock loading bays • Professional appearance • Precast concrete construction • Conveniently located at a key intersection

• Built to suit offices • Ample parking • Air conditioning • Strategic highway visibility • Immediate occupancy

FOR LEASE Greg Dobko

RE/MAX Grande Prairie

780-538-0288 or toll free 1-866-538-0288 gdobko@gregdobko.com

Open house every Tuesday!

11am-2pm. Unit 101- Building 3, 7001 98th Street Clairmont, Alberta T0H 0W0

www.CrossroadsCentron.com T r u s T e d • r e l i a b l e • K n o w l e d g e a b l e | P h o n e 4 0 3 - 2 5 2 - 1 1 2 0 | c e n T r o n g r o u P. c o m

CONTENTS

APRIL.

in the news

13

U.S. water management lessons could help global shale operators

regional news

17

British Columbia

29

Northeastern Alberta

41

Southern Alberta

Artek Exploration continues targeting

MEG files for 3,000-barrel-per-day

DeeThree Exploration updates

Inga condensate play in 2013

partial-upgrading technology facility

2013 guidance

23

35

47

Northwestern Alberta

Central Alberta

Saskatchewan

Apache to spend $600 million in

Swan Hills synthetic gas project

A tale of two Bakkens: Canadian and U.S.

Canada this year

funding cancelled

plays different animals, says analyst

tech news

50

Western Hydrogen Ltd. gets federal funding for hydrogen technology

features Cover Feature

52 Putting together the LNG puzzle Midstream operators begin building the supply chain for LNG exports

56 The dilution solution A mix of growing natural gas liquids drilling and demand for condensate to dilute bitumen to make it pipeline-ready drives midstream growth

60

Managing flow and measurment

New software expected to help producers meet tougher field measurement reporting requirements

every issue

10 Stats at a Glance 62 Political Cartoon Cover composite: Peter Markiw; Photo: istockphoto.com/MsLightBox

OIL & GAS INQUIRER • APRIL 2013

7

UV Resistant Shield

Corrosion Resistant Liner

Steel Reinforcements

2"– 8", up to 3,000 psi

next generation line pipe. FlexSteel is the only spoolable pipe durable enough for direct installation in rough terrains without the risk of failure. With a steel core that provides unmatched structural integrity, FlexSteel’s brute strength is the clear choice when failure is not an option. learn more at flexsteelpipe.com.

Editor’s Note Vol. 25 No. 3 EDITORIAL EDITOR

Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS

The future, in the rear-view mirror

Lynda Harrison, Carter Haydu, Pat Roche CONTRIBUTING PHOTOGRAPHER

Joey Podlubny

EDITORIAL ASSISTANCE MANAGER

Marisa Sawchuk | msawchuk@junewarren-nickles.com EDITORIAL ASSISTANCE

Kate Austin, Laura Blackwood, Tracey Comeau, Matthew Stepanic CREATIVE PRINT, PREPRESS & PRODUCTION MANAGER

Michael Gaffney | mgaffney@junewarren-nickles.com CREATIVE SERVICES MANAGER

Tamara Polloway-Webb | tpwebb@junewarren-nickles.com CREATIVE LEAD

Cathlene Ozubko GRAPHIC DESIGNER

Peter Markiw

CREATIVE SERVICES

Paige Pennifold production@junewarren-nickles.com SALES SALES MANAGER—ADVERTISING

Monte Sumner | msumner@junewarren-nickles.com SENIOR ACCOUNT EXECUTIVES

Nick Drinkwater, Diana Signorile SALES

Sammy Isawode, Mike Ivanik, Nicole Kiefuik, David Ng, Tony Poblete, Sheri Starko For advertising inquiries please contact adrequests@junewarren-nickles.com AD TRAFFIC COORDINATOR—MAGAZINES

Denise MacKay | atc@junewarren-nickles.com DIRECTORS CEO

Bill Whitelaw | bwhitelaw@junewarren-nickles.com PRESIDENT

Rob Pentney | rpentney@junewarren-nickles.com DIRECTOR OF SALES & MARKETING

Maurya Sokolon | msokolon@junewarren-nickles.com DIRECTOR OF EVENTS & CONFERENCES

Ian MacGillivray | imacgillivray@junewarren-nickles.com DIRECTOR OF THE DAILY OIL BULLETIN

Stephen Marsters | smarsters@junewarren-nickles.com DIRECTOR OF DIGITAL STRATEGIES

Gord Lindenberg | glindenberg@junewarren-nickles.com DIRECTOR OF CONTENT

Chaz Osburn | cosburn@junewarren-nickles.com DIRECTOR OF PRODUCTION

Audrey Sprinkle | asprinkle@junewarren-nickles.com DIRECTOR OF FINANCE

Ken Zacharias, CMA | kzacharias@junewarren-nickles.com OFFICES Calgary

nd Flr-  Avenue N.E. | Calgary, Alberta TE Y Tel: .. | Fax: .. Toll-Free: ...

Edmonton

220-9303 34 Avenue N.W. | Edmonton, Alberta T6E 5W8 Tel: .. | Fax: .. Toll-Free: ...

SUBSCRIPTIONS Subscription Rate

In Canada,  year $ plus GST,  years $ plus GST Outside Canada,  year $

Remember 2007?

Back then, it looked like Alberta’s oil industry was set to explode.

There were no fewer than seven bitumen upgraders and other facilities worth $94 billion planned for the Industrial Heartland surrounding Edmonton. The province was forecasting that industry would be upgrading more than three million barrels per day by 2020.

The government was also laying the groundwork for a massive petrochemical cluster based on oilsands by-products it estimated would total 300,000–750,000 barrels per day by 2020.

Demand for natural gas had the conventional industry drilling at a record pace, with around 10,000 shallow gas wells drilled in southeastern Alberta in 2007. Prices in Alberta reached as high as $12 per thousand cubic feet.

Fast forward five years.

Only one of the seven proposed upgraders planned in the Industrial Heartland is going ahead. Around one million barrels per day of synthetic crude is being produced, and it is unlikely to get much beyond 1.5 million barrels per day, or half of what the province was forecasting, by 2020.

While Williams Energy Canada is currently expanding its petrochemical operations at Redwater that use oilsands off-gases from Suncor Energy Inc., the only person talking about a world-class petrochemical cluster these days is environmentalist David Suzuki.

The shallow gas drilling industry is dead, and the only profitable gas being drilled is in the liquids-rich fields in western Alberta and northeastern British Columbia. Gas output has declined to less than 13 billion cubic feet per day from over 17 billion cubic feet per day, and analysts predict it will reach 12 billion cubic feet per day before the smoke clears.

The reversal in the western Canadian petroleum industry’s fortunes has been nothing short of amazing.

While the current supply glut and lack of markets is hindering sales growth, in the background the framework is being erected to get the future back on track.

Efforts to reach the Gulf Coast, Canada’s west coast and eastern Canadian refineries are taking shape.

On the gas front, efforts are well under way to develop an LNG export industry that Ziff Energy Group says could ultimately take 10 billion cubic feet per day of Canadian gas. It would bring the industry back to profitability and allow it to produce as much as 20 billion cubic feet per day.

Right now, that bright future predicted in 2007 seems a pipe dream, but it also illustrates just how fast things can change in the other direction.

Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com

Subscription Inquiries

Telephone: ... Email: circulation@junewarren-nickles.com Online: junewarren–nickles.com GST Registration Number RT. Printed in Canada by PrintWest. ISSN - | ©  JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number .

Postage paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 80 Valleybrook Dr, North York, ON M3B 2S9 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

N E XT I S S U E May 2013 Tracking developments on the ground in northeastern British Columbia, and a review of advances in extended reach horizontal drilling and multistage fracturing technologies.

Want to sound off on any content in Oil & Gas Inquirer?

Send your emails to dstonehouse@junewarren-nickles.com.

Please mark them as ”Letter to the Editor” if you want them published.

MINI B&W FSC LOGO OIL & GAS INQUIRER • APRIL 2013

9

FAST NUMBERS

.

million barrels per day

Canadian oil production in December 2012.



million barrels per day

Canadian synthetic crude production in December 2012.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

M O NTH

OIL

GAS

Feb 2012





Mar 2012





T O TA L

MONTH

OIL





Feb 2012









1,153





Mar 2012









1,275

OTHER

GAS

D RY

SERVICE

T O TA L

Apr 2012









Apr 2012









988

Jun 2012









Jun 2012









449

Jul 2012









Jul 2012









873

Aug 2012









986

Aug 2012









Sep 2012









Sep 2012









908

Oct 2012

,







1,269

Oct 2012









Nov 2012









Nov 2012









1,250

Dec 2012









Dec 2012









1,054

Jan 2013









Jan 2013









645

Feb 2013









Feb 2013









1,161

Wells Drilled in British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS DRILLED

C U M U L AT I V E *

MONTH

OIL

GAS

OTHER

TOTAL

Feb 2012

66

119

Feb 2012









Mar 2012

39

158

Mar 2012









Apr 2012

86

244

Apr 2012









Jun 2012

13

334

Jun 2012









Jul 2012

57

401

Aug 2012

53

454

Sep 2012

11

465

Oct 2012

28

493

Nov 2012

78

571

Dec 2012

65

636

Jan 2013

31

31

Feb 2013

42

73

*From year-to-date

Jul 2012









Aug 2012









Sep 2012









Oct 2012









Nov 2012









Dec 2012









Jan 2013









Feb 2013









Gas Migration Testing…

Effective technology at half the cost

• • • •

Environmental Drilling Pipeline Inspections Steamers Invasive Plant Inventories

• • • •

Hydro-Seeding Weed Control GasTrak Leak Detection No Flame Heaters

Cold Lake • Drayton Valley • Drumheller • Edson • Edmonton Rocky Mountain House • Stettler • Swift Current

1-888-542-9156 | WWW.WESTCOUNTRY.CA 10

APRIL 2013 • OIL & GAS INQUIRER

STATS

AT A

GLANCE

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, March 13, 2013 Source: Rig Locator

Alberta, March 2013 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada Alberta

AC T I V E

OIL WELLS

Alberta

Feb 

GAS WELLS

Feb 

Feb 

Feb 







%

Northwestern Alberta









British Columbia







%

Northeastern Alberta









Manitoba







%

Central Alberta









Saskatchewan







62%

Southern Alberta



69











%

TOTAL









WC TOTALS

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada, March 13, 2013 Source: Rig Locator

Alberta, March 2013 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada

Alberta

AC T I V E

C OA L B E D M E T H A N E

Alberta

Feb 

Feb 

BITUMEN WELLS Feb 

Feb 







%

Northwestern Alberta









British Columbia







%

Northeastern Alberta









Manitoba







%

Central Alberta









Saskatchewan





203

83%

Southern Alberta









WC TOTALS







%

TOTAL









OIL & GAS INQUIRER • APRIL 2013

11

industrial electrical supplies when you need them

AUTOMATION

Since 1927, Brews Supply – Offering a broad range of industrial electrical products, in stock and ready to ship!

CABLING SOLUTIONS

Brews carries a complete range of industrial electrical supplies to fill all your needs, from automation to wiring devices and everything in between.

DISTRIBUTION EQUIPMENT HEATING EQUIPMENT

ew

s 24 h

INDUSTRIAL CONTROL

hot

UTILITY PRODUCTS

vi ce

r

r

B

SAFETY

b

ut r ton se

ENCLOSURES

HIGH PERFORMANCE SENSORS FOR DEMANDING APPLICATIONS Eaton’s Enhanced 50 Series photoelectric sensors offer flexibility, durability and high optical performance with a fully potted construction. These sensors are ideal for use in wash down, high shock, high vibration and Alberta’s cold climates (To –25° C!) Three output types, four time-delay functions, six sensing modes and four connection styles allow you to tailor the sensor to meet your exact needs.

Visit www.BrewsSupply.com/50_series or contact your Brews Supply sales representative for more information.

BREWS SUPPLY

Toll Free 1.800.661.6884

Calgary (Head Office) 12203 40th St. S.E. P. 403.243.1144

www.brewssupply.com

Edmonton 18003 111th Avenue N.W.

P. 780.452.3730

IN THE

NEWS Issues affecting Canada’s E&P industry

U.S. water management lessons could help global shale operators

Photo: Joey Podlubny

Countries and operators that are embarking on the global development of shale gas resources may benefit from the United States’ experience in water management, according to a report from Accenture.

The report—“Water and Shale Gas Development: leveraging the US experience in new shale developments”—identifies water as one of the key challenges that make the development of shale gas different from conventional gas.

The research looks at how countries with proven reserves, such as Argentina, China, Poland and South Africa, can leverage U.S. lessons and trends in water regulation, water use and management, and water movements to develop shale gas reserves economically and sustainably.

The report also identifies implications of shale gas development for oil and gas companies, and highlights areas in which these operators should aim to build their

capabilities to succeed in the current operating landscape.

“Successful oil and gas operators will be those that understand the local water challenges, leverage the learnings from the U.S. plays, and develop the right water sourcing, use/reuse, treatment, disposal and supply chain strategy,” said Melissa Stark, executive director and clean energy lead for Accenture’s energy industry group. “One key opportunity for new geographies where infrastructure is a challenge is to explore sharing the development of infrastructure, water treatment facilities and the development of the local supply market.”

The report emphasizes that countries will have different issues, options and solutions to the water challenges depending on the geology of the shale and the particular regional characteristics.

For example, the report compares the water sourcing challenges in South Africa’s

Sign at a recent protest in Alberta. Understanding local water challenges will help operators develop shale resources, says a new Accenture report.

Karoo basin with Poland, and shows how different the flowback volumes and total dissolved solids (TDS) levels are across U.S. plays. Flowback is the injected fracture fluid mixed with the formation water containing dissolved minerals from the formation that flows back to the surface after fracking. Flowback water contains clays, chemical additives, dissolved metal ions and TDS. The report also emphasizes that in this constantly evolving landscape, water management options can change, and proactive engagement with operators in developing regulation will help the implementation of effective solutions and reduce the cost of compliance.

One area that provides immediate opportunities for some operators is logistics, according to the report. Implementing a logistics operating model that addresses the water movement challenges will improve congestion, efficiency and reporting of water movements. In some new markets, there are opportunities to design “for the basin” and even to share excess capacity and infrastructure, such as water treatment facilities.

The report points out that there will be increased focus on reducing the water intensity of production processes, and operators can achieve this by delivering efficiencies in operations, and by maximizing opportunities for end-to-end reuse of waste water and water treatment. As the report notes, there are opportunities to work with treatment suppliers to gain leverage from new water treatment technologies.

Operators will also need to carefully assess the increased requirements for data on the flows of all materials throughout the life cycle of shale gas operations.

Capturing, storing and reporting this data will require a new level of data management for operators—as well as regulators—to effectively use the data to support environmental impact assessments.

OIL & GAS INQUIRER • APRIL 2013

13

In The News

Shale boom to affect more than extraction industry, says RBC Capital

On the heels of record-low natural gas prices, RBC Capital Markets and the Economist Intelligence Unit Limited published results from a survey last month focusing on the U.S. shale gas boom and its implications for North American economies and businesses. The report examines how the surge in unconventional gas production is transforming sectors such as energy and transportation.

“We are entering a paradigm shift in the way that businesses and national governments look at energy, particularly as it relates to underlying market drivers, business models, risks and economic impact stemming from the shale gas boom,” said Marc Harris, RBC Capital Markets’s cohead of global research.

“The coming years will be transformative for companies, particularly those in the energy, infrastructure, manufacturing and transportation sectors, which will, in turn, create opportunities for both investors and corporations,” added Richard Talbot, the other co-head of global research for RBC Capital Markets.

Most exploration and development companies that took part in the survey believe shale gas prices have bottomed out. The vast majority (87 per cent) predict natural gas prices will stay the same or increase over the next two years. In fact, 73 per cent of respondents anticipate a price increase of 10 per cent or more in the next five years. Until then, companies are moving away from dry gas and are focusing instead on liquids-rich plays, such as wet gas and shale oil.

14

APRIL 2013 • OIL & GAS INQUIRER

The shale gas boom is making U.S. companies think twice: companies in the energy, manufacturing and transportation industries are reassessing underlying market drivers, business models and risks as a result of the shale gas boom. On an economy-wide level, respondents expect that shale gas will improve country competitiveness in both the United States (52 per cent) and Canada (48 per cent).

T he shale gas boom is impacting industries differently: consider manufacturing and transportation. Low-cost shale gas will be especially beneficial to companies that rely on feedstock or direct energ y usage to compete on a global level. In industries like petrochemicals and fertilizers, where feedstock or energy inputs can account for up to 90 per cent of total production costs, low-priced shale gas will be a game changer. The impact on the transportation industry will be subtler. Rather than a complete transformation to gas-based usage, diversification will likely take place across the industry.

According to more than half (54 per cent) of those surveyed in the report, shale gas could lead to natural gas becoming a significant U.S. export in the medium term.

However, revenues generated from natural gas exports will not necessarily have a significant positive impact on the state of the overall U.S. economy. The implications on job creation will be positive, but energy security and environmental concerns could limit the scale of natural gas exports in the United States.

Lack of transparency also remains an obstacle to investment. A lack of transparency regarding chemical usage from producers is a deterrent to gas-related investments, according to 25 per cent of institutional investors responding to the survey. While the industry does engage in some reporting on the topic, some of it remains incomplete or inaccurate and presents an issue for potential and existing investors. Improved transparency, increased environmental risk management and implementation of best practices will help the industry maintain its licence to operate while at the same time capturing the benefit of production currently lost to fugitive emissions.

Infrastructure will be challenged to keep up with demand dynamics. While sourcing infrastructure investment capital is unlikely to be a major bottleneck to the growth of the gas industry, regulatory risks remain prevalent. Regional pipeline supply dynamics are rapidly changing in response to changing demand conditions. Notably, an increase in natural gas liquids demand production has created an infrastructure bottleneck in some regions, for example, in the northeastern United States.

I mple me nte d by t he E conom i st Intelligence Unit and sponsored by RBC Capital Markets, the report draws insight from a survey of 357 North American C-suite executives across a variety of industries, in-depth interviews with key experts and leading companies involved in the shale gas boom, and desk research based on the latest data, documents and reports from within the industry.

Photo: Joey Podlubny

An RBC survey found the U.S. shale gas boom will benefit the manufacturing and petrochemical industries.

In The News

A decade of unconventional oil production growth ahead, says GlobalData A new report from research and consulting firm GlobalData states an increase in global unconventional oil production will be led by North America over the next decade.

“Unconventional resource development was pioneered in North America, and the global industry still relies upon the region for technological breakthroughs,” commented Matthew Jurecky, director of oil and gas research at GlobalData.

The firm’s study states that global production of unconventional oil, which includes oilsands and extra-heavy oil, will more than double to over 5.75 million barrels per day by the end of the current decade from approximately 2.71 million barrels per day in 2011.

In 2011, unconventional oil production accounted for 3.2 per cent of the global total oil production of 83.6 million barrels per day.

“Over the next decade, crude oil contributions from unconventional reservoirs will grow, owing to the large resource potential, relatively low cost of entry, and established development momentum,” says Jurecky.

“Emerging hydrocarbon basins in harsh environments such as the Arctic, or those with little infrastructure such as East Africa, have massive resource potential, but large upfront costs and long lead times make them long-term plays rather than short-term opportunities.”

Booming North American tight oil development is expected to play a major role in global production gains. From 551,000 bar-

Jurecky says. “Most other unconventional basins have one or maybe two of these variables, but no basins have all of them.”

According to GlobalData, Canadian oilsands will continue to contribute the most to the global production of unconventional oil. It is estimated that Canada will produce 3.173 million barrels per day from oilsands in 2020, from approximately 1.6 million barrels per day in 2011. Contributing “ North America has the ideal environment for unconventional projects include Syncrude Canada drilling: resource-rich rock, large contiguous and unpopulated Ltd. adding a Stage acreage.”

3 debottleneck by — Matthew Jurecky, director of oil and gas research, GlobalData 2016 and completing a Stage 4 expanrels per day output in 2011, unconventional sion by 2018. Of the country’s planned oilsands oil production is expected to hit over 1.8 milprojects, Suncor Energy Inc.’s Fort Hills prolion barrels per day by the end of the decade. ject, with a planned capacity of 160,000 barrels per day by 2016, is among the largest.

“North America has the ideal environment for unconventional drilling: resource-rich “Canada’s industry is fuelled by demand rock, large contiguous and unpopulated acrefrom the United States, and its government age, private land ownership, an established continues to look for further demand centers industry and a friendly regulatory environment,” for its crude,” says Jurecky.

BETTER TOGETHER. Western Canada’s leading gauge supplier is now a part of the Unified Valve Group of Companies.

Learn more about how to leverage western Canada’s leading valve and gauge experts and tap into increased customer value at:

www.unifiedvalve.com

OIL & GAS INQUIRER • APRIL 2013

15

Since 1921, we’ve been doing one thing and one thing only: providing PVF products and solutions to our customers. We create savings well beyond the price of our products.

Trusted Supplier, Proven Results

MRC Offers PVF Products and Services Globally

425+ Locations

MRO Solutions

Carbon Steel

24 Automation Facilities

Project Solutions

Stainless Steel

$1B+ Inventory

Logistics Solutions

Alloys & Duplex

www.mrcglobal.com

B.C.

BRITISH COLUMBIA WELL ACTIVITY FEB/12

FEB/13

Wells licensed





FEB/12

FEB/13

Wells spudded





FEB/12

FEB/13





Rigs released

▲

▲

British Columbia

▼

Source: Daily Oil Bulletin

Artek Exploration continues targeting Inga condensate play in 2013

Photo: Joey Podlubny

Artek Exploration Ltd. exited 2012 at a record production level of over 4,000 barrels of oil equivalent per day (approximately 4 4 per cent oi l a nd nat ura l gas liquids).

On the back of this success, Artek announced in Februar y it will spend $55 million to $58 million in 2013 drilling approximately 14–15 gross (eight to nine net) wells. The planned capital program will be weighted 100 per cent to projects targeting oil and condensate with associated natural gas, including up to 10 gross (6.1 net) horizontal wells in the condensaterich Inga/Fireweed area, three to four gross (1.2–1.6 net) vertical wells in the Leduc Woodbend area and one horizontal well in the Peace River Arch area of Alberta.

A f ter a produc t ion-foc used yea r driven by the validation of the company’s Inga Doig play and a development program at Leduc Woodbend, Artek plans to allocate up to 30 per cent of its planned capital investment on exploration projects.

The company will monitor commodity prices closely and has the ability to react to any significant changes in market conditions throughout the year. Assuming the capital program is carried out in its entirety, 2013 average production is forecast to be approximately 4,000 barrels of oil equivalent per day, of which approximately 44 per cent is forecast to comprise of crude oil and natural gas liquids. This would represent more than 40 per cent growth over Artek’s 2012 average production. Exit production is forecast to be approximately 4,300–4,400 barrels of oil equivalent per day.

The Inga/Fireweed program, representing over 85 per cent of total capital investment, targets a balance of development, pool extension, exploration drilling, and strategic facility and land investment.

Six (3.6 net) of the 10 wells planned will focus on Artek’s Inga condensate-rich Doig play, where fi rst-month gross production rates from its fi rst 10 horizontal wells have averaged approximately 1,200 barrels of

Artek plans on spending up to $58 million in 2013 drilling 14 or 15 gross wells.

oil equivalent per day (52 per cent natural gas liquids).

Artek continues to add to its land position in the area and now has over 70 gross sections with Doig mineral rights on which the company estimates there are 58 Doig horizontal locations (35 net) based on its mapping. Up to four gross (2.5 net) horizontal wells are considered to be exploratory, targeting new Doig pools and the Montney formation—which the company believes to have the potential to be liquids-rich. In addition, Artek has accumulated approximately 80 sections of land with Montney mineral rights in and around its operated facility and pipeline network in the greater Inga/Fireweed area. The capital program also includes approximately $3 million in facility investment that should increase Artek’s capacity from 18 million cubic feet per day to approximately 28 million cubic feet per day, and also $3.5 million to $4 million for land and seismic. The company’s strategic holdings and infrastructure tie in to the Spectra mainline and plant and another thirdparty processing facility with medium and deeper-cut liquids extraction capabilities, in addition to straddling the Alliance pipeline system and the Alaska Highway.

All of the above give Artek multiple transportation and processing options, and optimal flexibility in pursuing greater liquids extraction alternatives and anticipated operating netback improvements.

The company currently has three rigs running. Two rigs are drilling in the Inga area where Artek expects to have drilled four horizontal wells, including three Doig wells and one Montney exploration well, prior to breakup. The first exploration horizontal well at Inga has reached total depth and the second horizontal well is near total depth. The third rig is drilling the first of three planned vertical wells targeting Glauconitic oil in the Leduc Woodbend area.

OIL & GAS INQUIRER • APRIL 2013

17

British Columbia

Montney production climbs for Painted Pony Painted Pony Petroleum Ltd. increased fourth-quarter 2012 field-estimated production to 7,290 barrels of oil equivalent per day (76 per cent weighted to gas), a 4 0 per cent i nc rease over four t hquarter 2011.

The company’s field-estimated production for January 2013 averaged 8,100 barrels of oil equivalent per day (77 per cent weighted to gas). This production estimate is up 11 per cent over the fourthquarter 2012 average and 27 per cent over January 2012.

Painted Pony continues to pursue the development and expansion of its Mont ney gas assets in nor t heaster n British Columbia. In the fourth quarter of 2012, the company drilled or participated in drilling four (3.2 net) horizontal wells.

To date in 2013, Painted Pony has participated in drilling one (0.2 net) well and a 100 per cent well is currently being drilled. The company has also completed

two 100 per cent wells in the Blair area of the Montney.

At Blair, Painted Pony has recently started in-line production testing on two Montney wells on the C-62-F/94-B-16 pad to a third-party gas processing facility. Over 10 days, the upper Montney well flowed at an average wellhead rate of 5.8 million cubic feet per day at a f lowing casing pressure of 604 pounds per square inch (psi), and a peak 24-hour rate of 7.1 million cubic feet per day at an average flowing casing pressure of 900 psi.

The most recent 24-hour rate was 5.4 million cubic feet per day at an average f lowing casing pressure of 458 psi. The lower Montney well at 62-F f lowed on cleanup and initial production test for five days with an average 3.8 million cubic feet per day at an average f lowing casing pressure of 405 psi. The peak 24-hour rate was 4.5 million cubic feet per day at a f lowing casing pressure of 500 psi.

At Gundy (Cameron), Painted Pony has recently participated in the drilling of two (0.4 net) non-operated Montney wells on the C-68-J/94-B-09 pad. These two wells were to be completed and production tested prior to the end of the fi rst quarter.

A further two (0.4 net) Montney wells were expected to be drilled on the nearby C-75-J pad, also before the end of the first quarter.

At Townsend (Kobes), Painted Pony completed the acquisition of mineral interests in late December 2012. Subsequent to closing this acquisition, the company has started drilling its fi rst Montney well on these lands at A-B-11-J/94-B-09. This 100 per cent working interest well is targeting liquids-rich gas from an upper Montney interval. The B-11-J well, plus an adjacent cased lower Montney well on the same pad, were expected to be completed and production tested prior to the end of the fi rst quarter.

The exploration of Painted Pony ’s Montney well at West Blair (Daiber)

www.defopt.com

Oil and Gas Well Optimization 8

• Removal of liquids in “loaded” or “loading” gas wells • Plunger Tracking • Pumping well optimization and analysis

6

4

5

3

1

D

C

C

B

ISO VIEW

OPTION: PHOSPHATE COATING 4140 MAT' PLUNGER GENERAL TOLERANCES

• Pressure data logging

2

D

DRAWING REFERENCES:

MACHINED TOLERANCES UNLESS OTHERWISE SPECIFIED: FRACTIONAL 1/16" ANGULAR: MACH .5 BEND 1.0 TWO PLACE DECIMAL 0.010 THREE PLACE DECIMAL 0.005

A

DIMENSIONS IN INCHES. METRIC SHOWN AS [XX.XX] IN MILLIMETERS AS ALTERNATE MATERIAL:

AISI 4140 HTSR (Rc 28-34) FINISH:

-

SCALE

PROPORTIONAL UNLESS INDICATED

8

7

6

5

4

3

INIT: DRAWN BY:

BPT

CHECKED BY:

LG

ENG APPR:

BPT

DATE

CLIENT:

Internal Engineering

20080805 TITLE:

20100712 18" Solid Spiral Fish Bone

A

20100712 2 3/8" Artificial Lift Plunger

THIS DRAWING AND THE INFORMATION CONTAINED THEREIN IS THE PROPERTY OF DEFINITIVE OPTIMIZATION AND IS SUPPLIED SOLELY FOR THE PURPOSE FOR WHICH IT IS INTENDED. THE DRAWING AND ALL INFORMATION CONTAINED THEREIN SHALL NOT BE COPIED IN WHOLE OR IN PART AND MAY NOT BE PASSED TO A THIRD PARTY WITHOUT THE WRITTEN PERMISSION OF COPIES OF THIS DRAWING IS ISSUED SUBJECT TO RETURN UPON REQUEST. DEFINITIVE OPTIMIZATION.

2

SIZE DWG NO:

B KEI-PLUN-2375-201-006-01

WEIGHT: 8.75 Lb

SHEET 1 OF 1 REV: 02 1

• DIR 17 Flow Measurement • AAWS (Automatic Acoustic Well Sounder) • Surface facility optimization • Field surveys focused on facility optimization • Sales, installation and maintenance • In house enineering • Custom built equipment to suit your needs • Superior products/professional service

ERCB and OGC Regulatory and Compliancy Testing

Canadian Manufactured for Canadian Environments

General Manager Clint Mason 403-318-9762 Asst. Manager/International Acct Sean Gruner 403-820-4675 Calgary Sales Terry Levinsky 403-200-7635 Drumheller Distribution Centre 403-823-2218

18

APRIL 2013 • OIL & GAS INQUIRER

Photo: Joey Podlubny

British Columbia

A-80-E/94-B-16 has completed initial production testing of potential gas pay in the upper, middle and lower Montney zones.

This well was fracture stimulated across 11 stages, including single stages in the upper and middle Montney zones, plus nine stages in the lower Montney horizontal section.

The well flowed intermittently over a month for a total of approximately 10 flowing days. The last 36-hour test of all three zones had a peak 24-hour wellhead rate of 5.5 million cubic feet per day at an average flowing casing pressure of 911 psi.

The combined average wellhead flow rate for the total 36-hour test was 4.7 million cubic feet per day at an average flowing casing pressure of 758 psi.

A subsequent spinner survey indicated that the upper Montney interval was contributing 47 per cent of the combined wellhead flow. Painted Pony believes that the upper Montney zone represents the preferred target horizon in this area. A further two (two net) upper Montney horizontal wells are planned to be drilled on

3 Clean Equipment “Hot” (no disassembly)

3 Non-Abrasive 3 Non-Toxic 3 Non-Conductive

Painted Pony plans on drilling 12 Montney wells in 2013.

the 80-E pad in 2013 and placed on production early in 2014.

In 2013, the company expects to complete drilling operations on a total of 12 (9.4 net) Montney wells. This proposed program is expected to include activity on the Blair, West Blair, Cameron and Cypress projects, including at least three (2.8 net) wells on the recently acquired Townsend (Kobes) project. A completion is also planned to test the Buckinghorse formation in the greater Blair area.

Painted Pony was not selected as the supplier of natural gas to the Douglas Channel BC LNG Export Co-Operative initial project. However, as a founding member of the co-operative, the company is entitled to bid for supply on any future expansion.

In general, the prospects for construction of liquefied natural gas (LNG) facilities on Canada’s west coast continue to gain momentum. Painted Pony said its Montney gas project is well-positioned to become an important supplier to these export terminals.

3 No Secondary Residue 3 Effectively Cleans Hard-to-Reach Areas 3 Environmentally Responsible 3 Effective Year-Round

BEFORE

(not weather dependent)

industrial

HEAV Y DUT Y RESTORATION

AFTER

Regina: 306.565.3395 • Yorkton: 306.620.6632 • mediusindustrial.ca OIL & GAS INQUIRER • APRIL 2013

19

British Columbia

Diversified Glycol Services Inc. OU TEG

T

T

EG IN SLUDGE

REDUCE

Secor Isnetworld Complyworks Pics Decades of experience

Glycol Transportation Contractor Disposal

COST$!!

All gylcols... Economics work across the province! diversifiedglycol@yahoo.ca

P.O. Box 888 Red Deer, AB T4N 5H3

403-343-9555

1-888-242-7270

How rich

is your natural gas?

“Maxxam’s Petroleum group has designed a technology leap in the analysis of natural gas and natural gas liquids that delivers enhanced detection of higher value components.”

Terry Jacula, C.E.T. General Manager Petroleum Operations

Isn’t it time to get full credit for what you produce?

Find out how Maxxam’s technology leap can maximize your ROI. Call: 780 378 8500 petroleum@maxxam.ca

20

APRIL 2013 • OIL & GAS INQUIRER

maxxam.ca/NGL

Encana continues driving down Montney costs With natural gas prices stalled out for the last four years, developers are focused on driving down costs as a means to stay afloat.

And Encana Corporation is leading that charge, interim president and chief executive officer Clayton Woitas told shareholders in late February.

“ We intend to increase our margins without depending on the natural gas price recovery.”

— Clayton Woitas, interim president and chief executive officer, Encana Corporation

“At the end of the day, the oil and gas industry is the commodity business, and while we can’t control the prices for natural gas, oil or natural gas liquids, we can exert discipline on our cost,” Woitas said. “We intend to increase our margins without depending on the natural gas price recovery.” The company is already reporting success in the Montney play in northeastern British Columbia, said Michael McAllister, executive vice-president for Encana and president of its Canadian operations.

“Last year in Cutbank Ridge, we drilled 35 Dawson Creek Montney wells, where our resource play hub model continues to deliver cost savings driven by reduced drilling times and more efficient completions,” McAllister said. “The use of limited-entry slick water completions has resulted in cost structures going down by 22 per cent, while simultaneously improving unconstrained initial production by 50 per cent in this area.

Returns on our Montney play currently range between 30–40 per cent and we expect our supply cost to be $2.70 per thousand cubic [feet] on an unleveraged basis. If we include the carry capital, our supply costs are expected to come in below $2.

“More importantly, we have transferred Cutbank regional earnings to many of our emerging plays, including the Duvernay,” McAllister added. “In the fourth quarter, we drilled two of the longest laterals in the play at 6,770 feet in Kaybob and 7,280 feet in Willesden Green. We successfully placed 39 slick water fracs in our latest Kaybob well and 40 fracs in our latest Willesden Green well.”

British Columbia

EOG takes writedown on Horn River assets EOG Resources, Inc.’s production in Canada declined in 2012, and the company reported a significant writedown in the country in the fourth quarter, thanks to weak natural gas prices.

The Houston, Texas–based producer saw its 2012 average production in Canada decline to 23,600 barrels of oil equivalent per day from 30,800 barrels per day during the same period of 2011. Natural gas volumes dropped in 2012 to 95 million cubic feet per day from 132 million cubic feet per day the previous year.

“In the fourth quarter, we incurred a significant financial and natural gas– reserve writedown, which is very unusual for EOG,” said Mark Papa, chairman and chief executive officer, in a conference call discussing 2012 fourth-quarter and full-year results. “Approximately 98 per cent of the total financial writedown occurred in Canada as a result of low gas prices.”

EOG has written off the remaining book value of its entire Horn River acreage, along with all proved developed and proved undeveloped reserves because t hey are uneconomic at cur rent gas prices, he said. However, the drilling the company has done to date holds its remaining 127,000 net acres in the Horn River, with an estimated seven trillion cubic feet reserve potential, until 2020, according to Papa.

The company previously was involved in the proposed Kitimat LNG project, but in late December Encana Corporation and EOG sold their positions in the project and Chevron Corporation will take over as operator. Chevron and Apache Corporation now each hold 50 per cent in the project, which has struggled to secure a long-term off-take agreement with an Asian buyer.

“We believe Kitimat is a good project, and with Chevron involved, the project will likely get built,” Papa said. “We simply believed that the substantial go-forward capital required by Kitimat would be best re-invested in U.S. oil shale plays.”

Remote Location WoRk FoRce Housing / oFFices DeaLeR FLeet RequiRements moDuLaR constRuction

oPen camP Locations Ring BoRdeR open camp - North of Ft. St. John Km 92 HigH SieRRa - East of Ft. Nelson Km 178 HigH SieRRa - Northeast of Ft. Nelson BucKingHoRSe Lodge - Mile 175 on the Alaska Hwy JanvieR, aLBeRta Km 227 on Hwy 881 conKLin coRneR, aB Km 175 on Hwy 881

12345 - 121 Street • Edmonton, AB T5L 4Y7 P 780.448.9222 • F 780.454.7900

1.800.207.9818 northgateindustries.com

OIL & GAS INQUIRER • APRIL 2013

21

industrial electrical supplies when you need them

AUTOMATION

Since 1927, Brews Supply – Offering a broad range of industrial electrical products, in stock and ready to ship!

CABLING SOLUTIONS

Brews carries a complete range of industrial electrical supplies to fill all your needs, from automation to wiring devices and everything in between.

DISTRIBUTION EQUIPMENT HEATING EQUIPMENT

ew

s 24 h

INDUSTRIAL CONTROL

hot

UTILITY PRODUCTS

vi ce

r

r

B

SAFETY

b

ut r ton se

ENCLOSURES

FROM ENTERPRISE TO PLANT Panduit delivers system expertise and innovations that improve reliability, security and safety while reducing operating costs. Targeted to specific plant needs, Panduit’s Industrial Automation solutions are comprised of 5 core “INs”: • IN-ROOM™ Control Room or Industrial Data Centre • IN-ROUTE™ Industrial Pathways, Network Zone Enclosures • IN-PANEL™ Control Panels, Electrical Panels and MCC’s • IN-FIELD™ On the Machine, In the Process Area, or Outdoors • IN-FRASTRUCTURE™ Power Distribution, Lighting, HVAC Security, Safety Visit www.BrewsSupply.com/panduit_automation or contact your Brews Supply sales representative for more information.

BREWS SUPPLY

Toll Free 1.800.661.6884

Calgary (Head Office) 12203 40th St. S.E. P. 403.243.1144

www.brewssupply.com

Edmonton 18003 111th Avenue N.W.

P. 780.452.3730

NORTHEASTERN ALBERTA WELL ACTIVITY FEB/12

FEB/13

Wells licensed





FEB/12

FEB/13

Wells spudded





FEB/12

FEB/13





Rigs released

▼

▼

▼

Source: Daily Oil Bulletin

N.W. Northwestern Alberta

Apache to spend $600 million in Canada this year

Photo: Joey Podlubny

Apache plans to drill over 150 wells in Canada this year.

Apache Corporation plans on spending as much as $600 million in 2013 assessing resource plays in northwestern Alberta and across western Canada.

The announcement of the expenditure comes after the company reported a decline in Canadian production in 2012. In the fourth quarter, production in Canada dropped to 115,963 barrels of oil equivalent per day from 125,252 barrels per day during the same period of 2011. For the full year, Apache averaged 122,201 barrels per day in Canada compared to 125,636 barrels during the same period of the previous year.

Preliminary exploration and development spending in Canada for 2013 is US$600 million. Gathering, transmission and processing facilities spending this year in Canada is estimated at $80 million.

“We are in the process of completing our resource assessment in Canada for liquidsrich gas and oil opportunities,” said Rodney Eichler, president and chief operating officer, during a conference call discussing fourth-quarter and full-year 2012 results.

“We anticipate identifying several thousand economic wells in our various plays, which should allow us to add another North American onshore growth region as we ramp up activity over the next couple of years.

“In Canada, our 2013 program includes over 150 wells with a focus on oil and liquidsrich gas opportunities and horizontal exploitation of the Sparky, Bluesky, Beaverhill Lake, Dunvegan and Viking oil plays,” he added. “We also intend to test the Montney and the Duvernay within our substantial acreage positions in these plays.”

In 2012, the company drilled 169 wells in Canada (137 net) and averaged five rigs for the year, with a drilling success rate of 86 per cent.

In the fourth quarter, the company drilled 14 wells (12 net) and averaged four rigs.

Apache began its first operated horizontal drilling in the Dunvegan play during the quarter. A total of six wells were drilled, four operated and two non-operated, with an average per-well initial production of 267 barrels of oil per day. Production was restricted on all wells as they were producing through temporary production facilities.

Notable well highlights include strong results in the liquids-rich Bluesky play. The company continues to evaluate potential in the liquids-rich Montney and Duvernay.

Results at House Mountain have remained strong, Apache reported, as the Swan Hills waterflood continues to be developed. This has been an attractive play for the company and is expected to contribute to growing liquids production in 2013.

In 2012, Apache also initiated operations in the Virginia Hills Non Unit. This began a seven-well horizontal Swan Hills oil program, which is continuing in 2013. Initial results are positive and could lead to several additional drilling opportunities.

Apache has roughly seven million gross acres in Canada and, during 2012, replaced approximately 153 per cent of its Canadian production.

In the Brownfield area, Apache drilled nine horizontal Viking wells that came on production in the fourth quarter; 2012 Viking oil production began at 1,450 barrels of oil per day and exited at 2,250 barrels per day, an increase of 55 per cent.

At Sparky, Apache drilled six wells in the fourth quarter with 100 per cent drilling success and an overall average initial production of 75 barrels of oil per day per well. Apache

169 Numer of wells Apache drilled in Canada last year

increased total production from 1,700 barrels per day in the third quarter to 2,700 barrels per day, with a peak of 3,000 barrels per day in the fourth quarter as some wells came online.

The liquids-rich Bluesky/Glauconite play is pervasive across Apache’s acreage. The company’s initial focus has been horizontal drilling in the Kaybob and W5 development areas. This horizontal program has made a significant production impact in the Kaybob area, where Apache grew overall production by 50 per cent over the last two years to 21,000 barrels equivalent per day from 14,000 barrels.

In terms of the proposed Kitimat LNG facility, where Chevron Corporation will take over as operator (Chevron and Apache hold 50 per cent each), the project is still in the front-end engineering and design stage, but site work is underway. Negotiations with offtakers are continuing, but no time frame was given for a final investment decision.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • APRIL 2013

23

Northwestern Alberta

Birchcliff sets $184.6-million capital budget Drilling and development expenditures of $148.7 million will account for the lion’s share of Birchcliff Energy Ltd.’s $184.6-million capital budget for 2013, up from an earlier preliminary estimate of $160 million, says the company.

The natural gas–weighted producer plans to drill a total of 31 (30 net) wells this year. That number includes 15 horizontal gas wells in the Middle/Lower Montney formation for a total of $89.8 million, and 10 Charlie Lake horizontal oil wells at Worsley at a cost of $34.7 million.

The budget also calls for two Basal Doig/Upper Montney horizontal gas wells ($11.6 million), one Doig/Montney vertical exploration gas well ($4.6 million) and three (two net) other oil wells.

Birchcliff reported that it outperformed its 2012 public production guidance, reduced its operating costs and added significant reserves at extremely low costs, resulting in material cash flow and net income, all in a difficult natural gas price environment.

Cash flow for the three months ended Dec. 31, 2012, was up 31.1 per cent to $39.8 million, while net income was $6.31 million, an increase of 89.5 per cent over the comparable 2011 figure of $3.33 million.

Fourth-quarter average production of 26,655 barrels equivalent per day was up 34.5 per cent, from 19,812 barrels per day in the fourth quarter of 2011.

Birchcliff drilled three Montney/ Doig horizontal natural gas wells, one Montney/Doig vertical exploration well and one (0.03 net) Charlie Lake horizontal oil well in the fourth quarter, all of which were successful.

The Phase III expansion of the Pouce Coupe South natural gas plant was completed and operational in October 2012 with a total licenced processing capacity of 150 million cubic feet per day for the plant. The plant is currently processing approximately 105 million cubic feet per day.

Natural gas accounted for approximately 78 per cent of production in 2012, with 22 per cent natural gas and 22 per cent crude oil and natural gas liquids.

Birchcliff drilled a total of 38 (35.1 net) wells in 2012, with 100 per cent drilling success. The figure included 24 (24 net) wells in its Montney/Doig natural gas resource play, including 22 (22 net) horizontal natural gas wells in the Pouce Coupe area using multistage fracture stimulation technology and two vertical exploration wells.

The company also drilled and fracture stimulated 11 horizontal wells in its Worsley light oil resource play.

Birchcliff increased its undeveloped land base to 506,024 net acres, up from 493,968 net acres at year-end 2011.

The company also continued to expand its footprint on the Montney/Doig gas resource play in the Pouce Coupe area of northwestern Alberta with the acquisition of contiguous blocks of high working

Are You SIRIUS? Introducing a Sirius Quality product for AC chemical injection All the advantages of the Sirius pump and more!

Set your controller to the rate you want in L/day... DONE! No manual adjustments and wasted manpower.

Low rates and accuracy mean no more over-injecting expensive chemicals.

• • • •

THE GEMINI

1-866-436-6301 www.siriuscontrols.com 24

APRIL 2013 • OIL & GAS INQUIRER

No more tightening packing No more guessing at flow rates No more tolerating over-injecting Designed with chemical compatibility in mind.

100% Teflon based seals compatible with nearly every chemical.

Yes We ARE! Profitable Environmental Solutions

Northwestern Alberta

interest land through private transactions and Alberta Crown land sale purchases.

As a result of land acquisitions, production performance and drilling success, Birchcliff increased the number of potential Montney/Doig horizontal gas well drilling locations to 1,929 wells.

In the Peace River Arch, the company developed new resource plays, including extensive technical work and the acquisition of a total of 76,909 acres of large contiguous blocks of prospective lands at a 100 per cent working interest. Birchcliff noted that in the area numerous new wells have been drilled, completed and brought on production, targeting new tight oil/shale resource plays, including the Montney, Charlie Lake, Nordegg and the Duvernay.

The company said it believes its new lands are prospective for one or more of these new resource plays, and some are also prospective for the Montney/Doig gas play or the Worsley light oil resource play.

Pinecrest Energy Inc. spending $136 million this year Pinecrest Energy Inc. has approved a 2013 capital budget of $136 million, focused on drilling, completion, equipping, tie-in and waterflooding the Slave Point light oil resource play in the company’s Greater Red Earth core area.

Pincrest expects to drill 30–34 Slave Point wells this year, along with constructing related pipelines and facilities. The remainder of the capital will be spent on waterfloods and maintenance work at Red Earth. The company expects to exit 2013 at 6,000 barrels per day of light oil production.

The positive results of Pinecrest’s joint waterflood and the historical waterfloods in the Greater Red Earth area provided the company with sufficient confi rmatory data to proceed with several waterflood schemes. In an effort to accelerate the company ’s abilit y to implement fully developed horizontal well waterf lood schemes in 2013, Pinecrest elected to drill

12 gross (12.0 net) infill horizontal wells in the third and fourth quarters of 2012. These wells were drilled on three sections of land at eight horizontal wells per section, with 1,400-metre laterals.

Initial results from the company’s fi rst 100 per cent operated waterflood scheme, called Evi-Project #2, have been very encouraging and in accordance with company expectations. Uninterrupted water injection commenced on Dec. 20, 2012, and early results have seen oil production from the offset wells increase from 95 barrels per day to 280 barrels per day.

Pinecrest has received Energy Resources Conservation Board approval for four additional 100 per cent operated waterfloods. Its Loon-Project #1 was scheduled for injection mid-February 2013, and the other three projects throughout the second and third quarter.

An additional two schemes have been applied for, with approvals anticipated

OIL & GAS INQUIRER • APRIL 2013

25

Northwestern Alberta

NEMO®

SY Pumps with bearing housing and drive shaft  Industrial applications in oil and chemical industries  For low fluids with or without solids  Capacities up to 2,200 gpm/500 m standard, up to 3,400 psi/240 bar as high pressure  Four rotor/stator geometries for optimized performance  Design with bearing housing and drive shaft allows for universal use of all types of drives.

NETZSCH, the world market leader with 60 years of experience and over 500,000 progressing cavity pump installations worldwide. With sales, production and service on 6 continents ensuring customer support to provide

NETZSCH Pumps & Systems - Solutions you can trust

Learn more.



NETZSCH Canada, Inc. Tel: 705-797-8426 email: info@netzsch.ca www.netzsch.ca

subscribe to Dailyoilbulletin.coM for the neWs of the Day. eVery Day.

Tımeless Like clockwork, the Daily Oil Bulletin has been providing oilpatch news every day at noon for seventy-five years.

We’re proud of our history and this significant anniversary.

But we’re not standing still.

While we’re celebrating our seventy-five years in business, we’re looking to the future for ways to improve our service to you.

Watch for our neW-look Website appearing in 2013.

CELEBRATING SEVENTY-FIVE YEARS dailyoilbulletin.com

26

APRIL 2013 • OIL & GAS INQUIRER

to be obtained within the next four to five weeks, after which all of these projects are scheduled to be phased in throughout the second and third quarters of 2013. The locations of the seven waterflood schemes are dispersed throughout the Greater Red Earth area, encompassing the Evi, Otter, Loon and Red Earth fields. All of the proposed waterflood schemes will utilize existing wells and similar capital costs, resulting in the same or better capital efficiencies as the initial Evi-Project #1 waterflood.

Strategic positioned for Steen River growth in 2013 Strategic Oil & Gas Ltd. used 2012 to position itself for growth on its stacked tight oil play at Steen River in northwestern Alberta.

During 2012, Strategic expanded its land holdings at Steen. Strategic acquired approximately 100,000 hectares at an average cost of $16 per hectare, well below the 2012 Alberta average cost of $360 per hectare. Strategic’s undeveloped land position has now grown to 155,984 net hectares.

In late 2012, Strategic drilled two vertical Keg River wells. Its 02/11-28 well was drilled into the existing Keg River pool, and its 02-13 well was drilled as a step-out well to test a potential new Keg River structure.

The well 02/11-28, producing at an oil rate of over 200 barrels of oil equivalent per day, is outperforming the Keg River type curve.

Vertical step-out well 02-13 resulted in a new Keg River pool discovery on the eastern side of the rim. The vertical well has intersected a lower permeability Keg River reservoir that has been mapped to extend over five square kilometres with an estimated original oil in place of 40 million barrels. The vertical well is currently producing at 50 barrels of oil equivalent per day. This new Keg River pool will be an ideal candidate for horizontal development.

In 2013, Strategic drilled three step-out vertical wells at Steen River. Two of the three vertical wells were targeting new pools, with the third well extending an existing Keg River pool. All three wells have been cased with promising shows while drilling and on logs. The three wells are currently being

Northwestern Alberta

flow tested to a temporary battery and are expected to be tied-in during March.

Strategic completed its first multistage frac well 03/12-18 into the Muskeg formation in the fourth quarter of 2012. Due to limited fluid handling capability at the West Marlowe field, the horizontal well has been flowing into a pipeline against a back pressure of 4000–5000 kilopascals, which limits the drawdown on the well. The well is currently producing 180 barrels of oil equivalent per day (45 per cent light oil) with limited drawdown. Strategic is planning to tie the well into the newly acquired facility and optimize the drawdown in March 2013.

In 2013, Strategic drilled a Muskeg stack horizontal well 14-18, following up on the success of the horizontal well 03/12-18. A second muskeg horizontal well is currently underway from the same pad, and completion operations will commence on both wells once the second drilling operation is completed.

In order to prove up the Muskeg stack fairway, Strategic completed a vertical well 07-28 in the Muskeg stack. This well is located approximately 15 kilometres east of the first Muskeg stack horizontal well. This well is currently producing at 75 barrels of oil equivalent per day. A third Muskeg stack horizontal well has been spudded at 13-28, keying off of a successful vertical test of the Muskeg Stack in that region of the field. Strategic will be tying in the three new muskeg stack horizontal wells in March 2012.

In addition, Strategic has undertaken four recompletions in existing wellbores to confirm the resource potential of several zones, as well as testing completion techniques to improve the initial production potential of the wells. The results have been very encouraging and these wells are being placed on production to ascertain their longer-term performance.

Strategic’s current corporate production is 3,100 barrels of oil equivalent per day (91 per cent oil). The current production does not include any new production from the wells drilled to date in 2013. The new wells will be tied into Strategic’s facility at Steen River starting in March 2013.

Approximately 50 per cent of Strategic’s current light oil production is transported by rail. The rail option gives Strategic exposure to Brent and West Texas Intermediate pricing for its crude. The company reaffirms its earlier production guidance of an average of 4,000 barrels of oil per day for 2013.

Custom solutions…

From a custom manufacturer.

1-888-227-4923 Phone: (403) 227-7799 Fax: (403) 227 -7796 E -Mail: sales@bilton.ca W ebsite: www.bilton.ca

Pressure Vessels By

Over

12,000

Vessels Built to Date

Separators Dehydrators Treaters FWKOs Scrubbers Swab Vessels

Line Heaters Steam Splitters Coil Rolling Drip Pots External Level Cages Filter Vessels

5715-56 Avenue, Edmonton, Alberta p: 780.434.0222 | f: 780.436.1467 e: info@penfabco.com

www.penfabco.com

OIL & GAS INQUIRER • APRIL 2013

27

ZEECO: smokeless, reliable well site flaring

At Zeeco, we understand the everyday realities of the oil and gas production fields. Our engineered flares and reliable pilots meet the strictest regulations and operate safely, smokelessly, and with fewer service issues. From well site and tank vent flares to compressor and central gathering site flares, Zeeco can deliver exactly what you need. Choose the flare company with the experts and field experience to back you up, no matter how remote the play. Choose a company where humans answer the phone and where deadlines mean something.

Choose Zeeco.

open • enclosed • high / low pressure • rentals Meet the Zeeco team at the Williston Basin Petroleum Conference, Booth #Q90.

Zeeco, Inc. 22151 E. 91st St., Broken Arrow, OK 74014 USA ZEECO® is a registered trademark of Zeeco, Inc. in the U.S. ©Zeeco, Inc. 2013

+1-918-258-8551 sales@zeeco.com zeeco.com

NORTHEASTERN ALBERTA WELL ACTIVITY FEB/12

FEB/13

Wells licensed





FEB/12

FEB/13

Wells spudded





FEB/12

FEB/13





Rigs released

▼

▲

▲

Source: Daily Oil Bulletin

N.E.

Northeastern Alberta

MEG files for 3,000-barrel-per-day partial-upgrading technology facility

By Pat Roche

Photo: Joey Podlubny

MEG Energy Corp. is preparing to dramatically increase the scale of its testing of a partialupgrading process the company believes will enable bitumen to be pipelined without diluent.

MEG also believes the process—called HI-Q—can convert bitumen into a crude oil that will have a broader market reach than either diluted bitumen (dilbit) or synthetic crude oil.

“The HI-Q process seeks to improve the economics and lower the barriers to entry for converting bitumen into product oil with broader market reach than dilbit or synthetic crude oil, requiring no transport diluent and with higher market value than dilbit,” the company says in a regulatory application filed with the Alberta Energy Resources Conservation Board. “Broad adoption of the process will reduce Alberta’s dependence on imported diluents and make better use of the available crude oil pipeline infrastructure delivering Alberta crude to [the] United States and global market.”

While the process does improve the value of the crude by eliminating the need for transportation diluent, MEG hesitates to call it “upgrading” because it is essentially just improving the viscosity, says spokesman Brad Bellows.

For bitumen producers who don’t have their own upgraders, diluent delivery pipelines are a significant capital cost, and the ongoing purchase of diluent is a major operating cost. It takes roughly half of a barrel of natural gas condensate—the most common diluent—to pipeline a barrel of bitumen. (As a general rule of thumb, half a barrel of condensate is blended with one barrel of pure bitumen; hence, the condensate is roughly one-third of the diluted bitumen. So, besides the cost of diluent-delivery pipelines, bitumen sales pipelines must be one-third bigger to accommodate the diluent.)

Given that condensate usually costs a lot more than bitumen, buying an expensive product to ship a cheaper commodity isn’t an ideal economic proposition—at least for the bitumen seller.

MEG is advancing a number of plans to add value to its bitumen production from its Christina Lake operations.

MEG has applied for regulatory approval to build a 3,000-barrel-per-day demonstration project in the Heartland industrial area northeast of Edmonton.

The company will still need diluent to ship bitumen to its partial-upgrading site from its Christina Lake steam assisted gravity drainage (SAGD) project in northeastern Alberta. But unlike many small SAGD producers, MEG owns 50 per cent of a pipeline system (ACCESS) that delivers diluted bitumen to the Edmonton distribution hub.

The advantage of the new process, if it’s commercialized, is that diluent would

32,292 barrels per day

MEG’s production in the final quarter of 2012 be returned to the field from the upgrader.

Diluted bitumen is largely shipped to distant markets, so dilbit sellers typically have to buy new diluent for every barrel of bitumen shipped.

MEG’s fourth-quarter production averaged 32,292 barrels of bitumen per day. It hopes to grow to 260,000 barrels per day by 2020. If the company decides to build a commercial-scale HI-Q facility, the current thinking is that it would be built at a central location, rather than one at each SAGD project, Bellows says.

Since 2003, the Calgary-based producer, in collaboration with the Western Research Institute (WRI) of Laramie, Wyo., has been developing HI-Q, which it calls a “lowintensity, low-cost, field-deployable, heavycrude quality-improvement process.”

The Canadian bitumen producer says it built and successfully operates a five-barrelper-day test project at WRI in Laramie. MEG now hopes to build a “pre-commercial, OIL & GAS INQUIRER • APRIL 2013

29

Northeastern Alberta

field-demonstration pilot” that would operate for three years.

It describes HI-Q as “mild thermal cracking with advanced solvent deasphalting” (SDA). Solvent deasphalting extracts asphaltenes and resins.

“Although similar processes have been operated successfully in a host of industrial applications, several innovations make the HI-Q process novel,” MEG states.

The company highlights three features: • The design minimizes gas production, eliminates coke production and maximizes liquid yield from heavy residue conversion.

MEG says this requires a high level of process reactor measurement and control, which presents a unique set of challenges.

• The selectivity of the SDA process and the asphaltene separation are unique and outside the realm of the typical application of solvent deasphalting in a refinery/upgrading complex.

• The combination and optimization of these two technologies, with specific process objectives applicable to Alberta bitumen and heavy oil, is “new and unique,” MEG says.

Cenovus pursues all transportation options

By Lynda Harrison

Not waiting around for the controversial Keystone XL pipeline to be approved to take its production south, Cenovus Energy Inc. says it is moving a total of 40,000 barrels per day of oil to tidewater and intends to get in on a proposed pipeline to Quebec.

“We believe it is very important for Canada to move volumes to export off the east coast as well as to Quebec for refineries there, so we will be having significant participation when that line goes to open season also,” says Don Swystun, executive vice-president of refining, marketing, transportation and development.

TransCanada Corporation is proposing to convert part of its natural gas mainline to Quebec into a crude oil carrier, and has said it expects most shipments would be light oil, either from the Saskatchewan Bakken or oilsands synthetic crude oil.

Cenovus’ portfolio approach to market access also has the company moving about 20,000 barrels per day on the Pegasus pipeline

Held in conjunction with:

CONNECTING YOU WITH NORTH AMERICA’S GAS & OIL INDUSTRY

JUne 11-13, 2013 CALGARY, ALBERTA, CANADA

staMPede PaRK gasandoilexpo.com

RegisteR to attend Enter reference code: oginQ @petroleumshow #GOE13

30

APRIL 2013 • OIL & GAS INQUIRER

to the Gulf Coast, about 11,500 barrels per day on the Trans Mountain pipeline to the west coast and some volumes by barge, and increasing production transported by rail, a fourthquarter results conference call heard.

Cenovus has committed to ship about 175,000 barrels per day between Northern Gateway and Trans Mountain, and about 150,000 barrels per day is committed to TransCanada’s Keystone XL and Enbridge Inc.’s Gulf Coast expansion pipeline, says Swystun.

Cenovus is also increasing the amount of production it sends by rail this year to 10,000 barrels per day from the current 6,000 barrels per day, and plans to acquire more insulated cars to transport blended bitumen, he adds.

The company’s objective is to have fixed transportation arrangements for 40–50 per cent of its forecast production through firm capacity on pipelines and longer-term arrangements on rail, says Brian Ferguson, president and chief executive officer.

Northeastern Alberta

“We are in no way betting all of our eggs in one basket on Keystone XL,” he notes.

Constraints on market access are having a negative impact on realized pricing for Canadian oil producers, said the company, reporting its fourth-quarter results.

Congestion on pipelines linking oilfields in western Canada to U.S. markets contributed to a widening of the average discount between West Texas Intermediate (WTI) and Western Canadian Select (WCS) in 2012. The average WTI-WCS differential was US$30.37 per barrel in December 2012, compared to US$11.72 per barrel in December 2011.

“Widening oil price differentials are becoming an increasingly important issue, not just for producers, but for all Canadians,” says Ferguson. “With the third-largest oil reserves in the world, we have a tremendous opportunity to capitalize on the growing global demand for energy. However, without pipeline access to new markets, we will continue to leave billions of dollars in lost revenues on the table every year, to the detriment of the entire Canadian economy.”

Oilsands offers unique reclamation challenges

By Carter Haydu

With the rapid growth in oilsands production, the reclamation of large areas of boreal forest is an ever-increasing responsibility for companies that carries with it reforestation challenges quite different from those found in the logging industry.

Fortunately, the petroleum industry is enthusiastic about properly returning land to forest once developments are complete, and it is developing new techniques to accomplish this, says Catherine Newhook, president of Next Generation Reforestation Ltd. “There’s a lot that has to be done, and they’re trying to do it right,” she says. Her Beaverlodge, Alta.–based business, for example, is currently working with Nexen Inc. on a winter wetland planting program, revegetating bogs disturbed by oilsands production and other human activities.

“It’s an experimental trial of a winterplanting technique,” says Nexen environmental specialist Jeremy Reid. “We have a bunch of wet areas, muskeg, around our site, and these areas are hard to access during summer, which is when we would normally plant.”

Due to the difficult planting conditions associated with the area, Reid says there’s a rather high mortality rate for saplings planted in hotter months. Therefore, as part of the multi-company Oil Sands Leadership Initiative, Nexen headed a research project to develop a means of planting saplings in the area during winter, when vehicles can also more easily access the site.

“So we used some heavy machinery we wouldn’t get on these wet sites in the summer, and we did the planting in the winter.”

We’ve got what you need.

Gaugetech® is a leading manufacturer/distributor of pressure gauges, temperature instruments and related products serving the petrochemical, pulp and paper, hydraulic industries, HVAC and OEM industries.

We have grown to serve the needs of a broad customer base within a wide range of industries becoming one of Western Canada’s best sources for quality pressure and temperature instruments.

Today, we are a total solutions supplier offering quality products, services and support to our many varied and valued customers, while striving to meet and exceed customer expectations with product availability and timely delivery anywhere in North America.

Visit www.gaugetech.ca or call us at 1.800.661.9039

Pressure Gauges • Needle Valves •Manifold Valves • Gauge Valves • Thermometers • Accessories OIL & GAS INQUIRER • APRIL 2013

31

Northeastern Alberta

ISO 9001-2000 CERTIFIED

BELZONA WESTERN LTD CALGARY, ALBERTA CANADA PH: 403-225-0474 TOLL FREE: 1-800-268-4553 FAX: 403-278-8898 WEB SITE: www.belzona.ca E-MAIL: belzona1@telus.net Belzona Polymeric Coatings combat erosion, corrosion and abrasion in high temperature immersed conditions. Rebuild and line tanks, process vessels and plant equipment.

Contact us for advice on Belzona Know How Solutions and Procedures.

-180˚ C Immersion Temperatures -Safe VOC Free Formulations -Brushable or Sprayable -Resists Rapid Decompressions -Belzona 1111 – 1311 -1391 – 1521 – 1591

-Amine Tower – Strippers -Exchangers – Chemical Tanks -Flare Knock Out Drums -Oil – Gas Separators -Outstanding Cavitation Resistance -Pressure Resistant

May 4 to June 2 Directed by Mark Bellamy TICKETS Production Sponsor

32

403.221.3708

www.vertigotheatre.com

Government Funders

APRIL 2013 • OIL & GAS INQUIRER

VERTIGO THEATRE 115 9TH Ave SE (at the Calgary Tower)

Media Sponsor

According to Reid, the trial with Next Generation near Grande Prairie saw about 50,000 winter saplings successfully planted during the winter of 2012. The winter tree planting project was a collaboration between oil and gas companies, the government of Alberta and Grande Prairie Regional College.

“It was a shared effort.”

This winter, Nexen will be planting about 100,000 saplings as part of its overall replanting schedule of about 350,000 saplings for 2013.

“It’s one tool in our tool box of reclamation that we can use to increase our success.”

While “it sounds counterintuitive,” he says it is certainly possible to successfully plant a sapling in the dead of winter. As northern Alberta trees usually survive cold winters, the treeplanters simply have to get the baby trees into the ground in a way that allows them to flourish before they quite literally die of shock in the elements.

“So what we do, from our nurser y stock, we take them during the winter time and put them into cold storage. We have to wrap them i ndiv idua l ly...a nd then we transport them in the cold. So storage is -4 [degrees Celsius], which is a good soil temperature for these trees. Then, we transport them in -4 [degrees Celsius] to the site and then we maintain them at that temperature.

“So when we pl a nte d t he m i n Grande Prairie, it wa s about -20 [degrees Celsius], but we did what is Reclaiming in situ operations is a challenge due to called a snow cache, the fragmented nature of the land disturbance. which is sort of like an igloo, and we covered them with snow so they were insulated, and they stayed at about -4 [degrees Celsius]...and then as soon as we took them out of that snow cache, we put them straight into the ground.”

Such innovative techniques as winter planting are necessary, Newhook says, as there are definitely differences between reforestation for oilsands development and for the longerestablished logging industry. For example, whereas logging companies leave larger areas of cleared lands upon which reforestation companies plant saplings, she says the sorts of sites oil and gas companies need reclaimed are often a lot smaller.

“The scale isn’t the same, and in forestry where it might be a 100-hectare cut block, this might be one hectare because you’re just doing a lot of leases and access roads. So instead of a milliontree contract, it’s just like, ‘we need 2,000 trees planted over here.’”

Photo: Joey Podlubny

Exclusive Authorized Distributor

Northeastern Alberta

TANK GAUGING SYSTEMS

“With logging you still have most of the forest floor intact, the soil is intact

TGS-5012 SOUR (Glycol Filled) • Glycol filled to prevent freezing • Add magnetically activated switches

and you have lots of coarse, woody • • • •

for planting. But in an oilsands mining

running into all sorts of issues with no real soil development; you run into soil chemistry issues with high salts in the soils that have to be overcome and leached out, because plants don’t like high salt content.”

0.1 0.2

0.3

0.3

0.4

0.4

0.5

0.5 TGS

0.6

780-474-2365

0.6

0.7

0.7

0.8

0.8

5.4 5.5

5.4 5.5

5.6

5.6

5.7

5.7

5.8

5.8

TGS

TGS

TGS-5010 SOUR PULLEY SYSTEM • • • •

Grease-sealed pulley Large indicator & signboard Add point switch Tank-in-service installation

Tank-in-service installations Field calibrated Sweet and sour service CSA Class 1, Div 1 EX

-6 -5 -4 -3 -2 -1

TGS-5020 SOUR/6020 SWEET SERVICE • Coned roof float prevents build-up • Simple installation • Excellent for retrofit applications • Tank internals: stainless steel, teflon fibreglass • Magnetically activated switches • 4-20mA electronic output (optional) • Pneumatic output (optional) X

0E

S2

TG

CSA– Class 1, Div 1 Explosion Proof

been dug up and replaced. So you’re

0.2

DNB ELECTROMECHANICAL – 4-20mA

debris that creates good microsites scenario, of course, everything has

0.1

-6 -5 -4 -3 -2 -1

SWITCHING THE INDUSTRY • • • •

TGS20EX magnetically activated electric switch PS35 magnetically activated pneumatic switch NVM mechanically activated pneumatic switch LSX mechanically activated electric switch

Edmonton: 780.474.2365 Calgary: 403.685.8867 www.tankgaugingsys.com

— Scott Formaniuk, co-owner, Tree Time Services Inc.

Because of the change in scale, Newhook says, reforestation for the oil and gas industry can be more expensive. Further, she says, whereas loggers leave the soil fairly loose and ready for saplings, the heavy equipment associated with a petroleum site means the ground is extremely compact, which makes it harder to reintroduce organic materials to the earth.

“It’s the difference between night and day,” says Tree Time Services Inc. co-owner Scott Formaniuk, who believes the differences in reclaiming land for logging verses oilsands production comes down to that level of disturbance associated with either industry.

“With logging you still have most of the forest floor intact, the soil is intact and you have lots of coarse, woody debris that creates good microsites for planting.

“But in an oilsands mining scenario, of course, everything has been dug up and replaced. So you’re running into all sorts of issues with no real soil development; you run into soil chemistry issues with high salts in the soils that have to be overcome and leached out, because plants don’t like high salt content.”

Formaniuk says once an oilsands mining operation is complete, there is not very much woody debris left on the ground. As well, there are reduced levels of fungi, which makes rejuvenating a piece of forest from oilsands development much harder compared with the logging industry.

“So there are a lot more challenges when you’re dealing with an oilsands reclamation scenario. You have to overcome all those challenges.”

OIL & GAS INQUIRER • APRIL 2013

33

CENTRAL ALBERTA WELL ACTIVITY FEB/12

FEB/13

Wells licensed





FEB/12

FEB/13

Wells spudded





FEB/12

FEB/13





Rigs released

C.A.B.

▼

▲

Central Alberta

▲

Source: Daily Oil Bulletin

Swan Hills synthetic gas project funding cancelled

By Pat Roche

Photo: Joey Podlubny

As the North American natural gas glut shows no signs of easing, the Alberta government and its private-sector partner have scrapped plans for a project that would have added synthetic gas to the supply.

Although the Swan Hills Synfuels project would have “unsequestered” CO2 stored in deep unmineable coalbeds, it had nonetheless been approved for funding under the province’s program for carbon capture and storage (CCS).

The idea was that the CO2 produced by the project would have been used for enhanced oil recovery (EOR), but no agreements between Swan Hills Synfuels and oil producers had ever been announced.

The announcement of the fundingagreement cancellation means that only two of the four projects that had originally been approved for funding are now proceeding, and the Alberta government’s funding commitment has been reduced to $1.3 billion from $2 billion.

Last April, power producer TransAlta Corporation abandoned plans to build Project Pioneer, a $1.4-billion CCS facility at an Alberta coal-fired electricity plant, because it could find no buyers for the CO2 and no way to sell emissionreduction credits.

Project Pioneer, a carbon-capture demonstration plant in which Enbridge Inc. and Capital Power Corporation were also partners, was backed by $779 million in funding commitments from the Alberta and federal governments. It would have captured and stored a million tonnes of CO2 a year from the 450-megawatt Keephills 3 power plant west of Edmonton.

But even with that hefty subsidy, TransAlta said it couldn’t make the economics work. The utility said it found no firm buyers for the CO2 that was to be captured at the plant and used for EOR. TransAlta also cited the fact that there was no cap-andtrade system that would let the company and its partners sell emission-reduction credits.

With a 100-year supply of gas, the synthetic gas project was unneeded.

In a six-paragraph news release, the government and Swan Hills Synfuels said the two parties have agreed to discontinue their $285-million CCS funding agreement.

The project had been criticized because it would have sold government-subsidized synthetic gas in a western Canadian market where dry gas is considered uneconomic at current prices.

“Persistent, low prices for Alberta’s natural gas have driven this business decision,” Energy Minister Ken Hughes said in the press release announcing the cancellation. “CCS remains a key part of Alberta’s

285

$

million

Amount of tax payer money that would have been spent on the project

commitment to reducing greenhouse gas emissions and the responsible development of our energy resources.”

In 2011, the province committed $285 million over 15 years for Swan Hills Synfuels to capture CO2 from the gasification of underground coal and sell it for use in EOR. The press release said lower-thanexpected gas prices “pushed back timelines” for the unusual project.

“At present, it’s more economical to purchase natural gas than it is to manufacture synthetic gas,” Swan Hills Synfuels chief executive officer Martin Lambert said in the release. “It’s a market reality that has led to significant delays on the CCS side of the project.”

Deferred project timelines move the ca rbon- capt ure components beyond the scope of the government’s funding requirements, the release said. It said no money has been advanced by the province for the project.

OIL & GAS INQUIRER • APRIL 2013

35

Central Alberta

Providing Integrated Infrastructure Services for Oil and Gas Companies

1.855.408.SITE (7483)

Meanwhile, Alberta is maintaining its funding commitments for the other two projects approved under its CCS program, both of which are oilsands-related.

The fi rst is for construction of the proposed Alberta Carbon Trunk Line, a pipeline that will be operated by Enhance Energy Inc. The project will capture CO2 produced by the North West Upgrading Inc./Canadian Natural Resources Limited bitumen upgrader/refi nery, which is under construction, and deliver the CO2 for injection into central Alberta oilfields to help recover light oil that would otherwise be left in the ground.

Royal Dutch Shell plc’s Quest project will capture CO2 emissions at the company’s Scotford bitumen upgrading and refining complex.

But unlike the Alberta Carbon Trunk Line, there are no plans to generate an economic return to the province from the Quest project.

Instead, Shell’s CO2 will simply be injected into deep saline aquifers.

The government says these two projects combined are expected to reduce greenhouse gas emissions by 2.76 million tonnes per year by 2016.

“Alberta’s unprecedented commitment of $1.3 billion for these projects speaks to how serious we are about climate change and reducing our impact,” Hughes said. No decisions have been made on whether to reallocate the funding that had been earmarked for Swan Hills Synfuels or Project Pioneer.

ALBERTA - SASKATCHEWAN - MANITOBA www.siteenergy.com

the

buyer’s guide to Canada’s oil & gas industry

Penn West’s Duvernay assets could go on auction block

By Pat Roche

SMARTPHONE • WEBSITE • iPAD • GPS • DVD DIGITAL EDITION • PRINTED BOOK

COSSD.COm

36

APRIL 2013 • OIL & GAS INQUIRER

Penn West Exploration may decide to monetize some of its Duvernay assets this year as the senior producer continues to cull its portfolio.

The company reported lower output in the fourth quarter after completing net dispositions of 16,500 barrels of oil equivalent per day of assets last year for $1.6 billion.

Asked during an earnings call how much production Penn West expects to sell this year and the proceeds it expects the sales to raise, president and chief executive officer Murray Nunns said the company isn’t targeting a specific level.

“I think our top priority will be looking at some of our early-life projects. I think a case in point would be the Duvernay. We think there’s tremendous value; we don’t think there’s recognition in the market for that,” Nunns told analysts. “But more importantly, we believe an outside source of funding and extraction of some of the value—given that we’ve only invested $100 million in the Duvernay—is a very good business proposition,” he said. “So something like that would definitely be on the radar screen.”

Penn West said it has a material Duvernay position in the liquids-rich fairway of the Willesden Green area. The company plans a further stratigraphic test in 2013.

In 2013, Penn West’s main focus will be the Spearfish tight oil play where it plans to drill 90–130 wells and spend about $200 million to $250 million.

Central Alberta

Enviro-Tub...

First class secondary containment protecting the product environment and primary container.

Penn West is the biggest landholder in the Cardium light oil play, which president and chief executive officer Murray Nunns described as “the most significant asset in the

To fill or empty the tank…

No need to lift or tilt the Enviro-Tub’s top half

company from a growth and long-term-value perspective.”

This year’s drilling times in the Spearfish were reduced to four days from eight. Penn West currently has five rigs operating in the area. Its natural gas liquids extraction plant remains on plan for start up in the second quarter.

In its carbonates light oil plays, this year’s development program is focusing on the Slave Point play, notably in the Sawn Lake and Swan Hills areas. In the first quarter, completion activity continued on wells drilled and carried over from 2012.

The company reported continued efficiency improvements in these plays. It said reduced drilling times in the Sawn Lake area in recent months resulted in cost savings of between $500,000 and $900,000 per well compared to 2012.

Penn West said the completion of its Sawn Lake battery expansion in late 2012 and the expansion of its gas-handling capacity in the Slave Point area should provide infrastructure capacity for several years of development activity.

As well, the company is continuing to advance its enhanced oil recovery (EOR) strategy in the Slave Point play in 2013, with the start of horizontal waterflood pilots at Sawn Lake and Otter.

Penn West is the biggest landholder in the Cardium light oil play, which Nunns described as “the most significant asset in the company from a growth and long-term-value perspective.”

Analysts were told Penn West’s Cardium production is expected to be “more or less flat” this year, presumably as the company focuses on waterflooding and long-term growth.

The company expects to have three waterflood pilots running in the Cardium by the end of this year, and “we certainly anticipate a much broader program in the Cardium with respect to waterfloods” in 2014, said Rob Wollmann, senior vice-president of exploration.

This year’s Cardium budget includes selective drilling in the Alder Flats and West Pembina areas, and further progression of the company’s EOR strategy, including plans for two horizontal waterflood pilots at Willesden Green.

Penn West said the results of its first horizontal waterflood pilot at Pembina remain very promising, with production of 150 barrels of oil per day from three previously shut in old vertical wells.

The company said an external contingent resource study completed in 2012 estimated 533 million barrels of light oil contingent resources in its Cardium assets. It noted potential recoveries from horizontal multi-fracture waterflooding aren’t reflected in the study.

This year’s Cardium activity is directed to primary development wells as it continues to develop a longer-term integrated strategy of primary development.

Penn West’s forecast exploration and development capital is $900 million. After its 2012 asset sales, the company is forecasting 2013 production of 135,000–145,000 barrels of oil equivalent per day.

Enviro-Tub…

• Gives better double-wall protection for small capacity tanks than any other product on the market.

• One complete totally enclosed portable secondary containment pkg.

• Keeps weather out...snow, rain, water, etc.

• Protection and security for primary container, chemical pumps and site glass.

• Allows for possibility of total recovery of expensive product.

• Permits for use of low cost single wall repairable tanks, plastic or steel.

• Exceeds G-55 guidelines.

Canadian & US Patents Canadian Enviro-Tub Inc Phone: (403) 742-2967 Fax: (403) 742-5239 email: help@enviro-tub.com www.enviro-tub.com

C

A

N

A

D

A

ISO 9001 :2008 REGISTERED FIRM

NEW!

100 Gallon D o u b l e Wa l l C h e m i c a l Ta n k OIL & GAS INQUIRER • APRIL 2013

37

Central Alberta

Bonterra is now producing 13,500 barrels equivalent per day, driven by growth in the Cardium.

Bonterra Energy Corp. spent 2012 expanding production in its Cardium light oil play, and the company said in February it would stay the course in 2013.

Bonterra recently completed the acquisition of Cardium producer Spartan Oil Corp., increasing its current production to approximately 13,500 barrels of oil equivalent per day. The company’s large, concentrated asset base in the Cardium now totals 250.3 gross (193.7 net) sections, positioning Bonterra as one of the most dominant light oil, dividend-paying companies in the Canadian energy sector. The company currently estimates that it has a greater-than-10-year drilling inventory using four wells per section.

Bonterra has approved a capital development program of $90 million for 2013 that mainly targets light oil prospects through its Cardium horizontal drilling program. Currently, 29 gross (28.1 net) operated wells are planned. Bonterra will also participate in drilling 13 gross (4.3 net) non-operated wells during 2013.

Bonterra’s full-year production levels are expected to average between 12,000 and 12,200 barrels of oil equivalent per day.

Operating costs are expected to average approximately $15 per barrel on an annualized basis.

In 2012, Bonterra’s focus on developing its Cardium acreage shifted to main pool development. The company drilled 32 gross (22.6 net) horizontal wells during the year. Bonterra has identified 600 gross (464 net) possible horizontal locations within its acreage. One hundred and five gross (80.8 net) horizontal proved undeveloped locations are reflected in Bonterra’s 2012 reserve report constituting a three-year drilling program.

Bonterra closed the acquisition of Spartan on Jan. 25, 2013. The acquisition advances Bonterra’s strategic objective to maintain and consolidate its position in the Cardium while continuing to exploit this large resource play. The Spartan properties are a strong geographical fit to Bonterra’s asset base, have significant operational synergies and provide additional drilling inventory over the long term. Bonterra has completed extensive geological mapping of the Spartan land base and has fully integrated the assets into its capital program. The Spartan assets are expected to increase the company’s liquids weighting, and the corporate production profi le in 2013 is anticipated to be approximately 75 per cent light oil and natural gas liquids that should result in increased netbacks for the combined entity.

Bonterra has continued to improve and refine its development of the Cardium to both increase well performance and reserve recoveries while minimizing costs. In 2012, the company transitioned to water-based fracs, which has significantly reduced overall well costs and increased per-well production results. In 2013, Bonterra is currently targeting drilling, completion, equipping and tie-in costs to average approximately $2.7 million per well.

“Industry Leading Quality & Service Since 1987” Specialists in internal & external coating applications Epoxies • Metallizing • Plural Spray Pipe • Tanks • Vessels • Bends • Valves 6150 - 76 Avenue, Edmonton, AB T6B 0A6 Phone (780) 440-2855 Fax (780) 440-1050

• 100% Canadian Owned • www.brotherscoating.com 38

APRIL 2013 • OIL & GAS INQUIRER

Photo: Joey Podlubny

Bonterra Energy grows in Cardium

advertisement

U

pon walking into this clean and wellorganized, 15,000-square-foot shop, it does not take long to feel and see the high energy of the staff, led by Branch Manager Frank Coccimiglio.

Frank proudly states that, since opening in 2007, the Leduc branch has installed steam units in hundreds of different vehicles— including pull-behind trailers, fifth-wheel trailers, single-axel 20-foot vans and on tandems with 24-foot van bodies. Pumps & Pressure Inc. installs these state-of-the-art mobile-cleaning systems in “hollow” vehicles supplied by various truck manufacturers. The durable and reliable mobile units not only deliver high-pressure wash, but also wet and dry steam, which is highly valued for cleaning and thawing purposes—mostly, but not exclusively—in western Canada’s oilpatch.

Trucks, typically, are fitted with up to three 600-gallon water tanks and Pumps & Pressure’s own popular Hot Shot diesel-fired heaters, which have capacities from 440,000 to 980,000 BTUs and voltage ranging from 12 to 120. The popular 980,000-BTU, 120-volt heater generates wash pressure that is rated at 10 gallons per minute for 3,000 PSI; wet steam at three gallons per minute for 300 PSI at 160°C; and dry steam at 1.5 gallons per minute at 170°C. Having a pressure-washing and manufacturing career running back almost four decades, Coccimiglio has been with Pumps & Pressure Inc. for 10 years. He credits the rise of the Leduc branch to star-performer status to its quality products, exceptional team spirit and custom builds. He explains: “We listen to

our customers and do our very best to provide them with a top-end product or vehicle. We service what we sell.”

With an overall workforce of 140 and headquarters in Red Deer, Alta., Pumps & Pressure Inc. opened in 1984. Currently, its seven locations stretch from Brandon, Man., to Langley, B.C., and north to Grande Prairie, Alta. Specific locations tend to meet specialized steam-cleaning manufacturing or servicing needs. So, an Edmonton branch, with full design and engineering capabilities, specializes in wash skids, and car- and truck-wash fabrication. The special Red Deer branch’s strengths include the manufacturing of bench tanks for bulk-fluid storage, plus a full-service hydraulic shop, which is supported by a full hydraulic 325HP test bench.

Frank’s Leduc branch recently added a hydraulics division and incorporates a bright Parker Store stocking brand-name products, including Karcher and HydroTek Pressure Washers, SAMSON Lubrication Equipment, DV Systems Air Compressors, CAT pumps, Cox reels, and Parker Hydraulics. The wide selection, including hoses and fittings, supports and complements the quality product manufactured and distributed by Pumps & Pressure Inc. The Leduc team’s meticulous attention to details remains vital to delivery of highend products and services. Frank can’t stress enough that it stems from “listening to what the customer wants and needs.

The biggest reason we are so successful is the staff we have working for us, the quality of our work, prompt delivery time,

competitive pricing, and our ability to change with new technology.”

These sentiments are shared by customers like Claude Bourassa, Vice-President of MAD Oilfield Solutions in Plamondon, Alta. “We at MAD Oilfield Solutions have had the pleasure of having Frank Coccimiglio and his knowledgeable team members at Pumps & Pressure assemble the last five boiler units of various types. They are a group of individuals who pride themselves in providing an end product that is second to none and is userfriendly. His service and parts teams have always been more than accommodating when it comes to trouble-shooting or sourcing out parts and are always willing to go that extra step to be sure they have achieved customer satisfaction.”

Drop by the Leduc branch, and Frank would be more than happy to give you a guided tour as he is extremely proud of his shop and what his team is able to accomplish in this highperformance business.

Pumps & Pressure Inc., in Leduc, is open Monday to Friday from 8 a.m. to 5 p.m. and offers 24-hour on-call service.

For more information, please contact: Pumps & Pressure Inc. T: (780) 980.9294 E: sales@pumpsandpressure.com www.pumpsandpressure.com

SOUTHERN ALBERTA WELL ACTIVITY FEB/12

FEB/13

Wells licensed





FEB/12

FEB/13

Wells spudded





FEB/12

FEB/13





Rigs released

▲

▲

▲

Source: Daily Oil Bulletin

S.A.B. Southern Alberta

DeeThree Exploration updates 2013 guidance

Photo: Joey Podlubny

Building on the operational and exploration success of 2012, DeeThree Exploration Ltd. plans a 2013 capital program of approximately $150 million focused on increasing oil production from its Alberta Bakken property in the Lethbridge area of southern Alberta and its Belly River property in the Brazeau area of central Alberta.

DeeThree is forecasting its 2013 production to be within the range of 6,800– 7,000 barrels per day (76 per cent crude oil and liquids, 24 per cent natural gas) with a targeted exit of 8,500–9,000 barrels per day (81 per cent crude oil and liquids, 19 per cent natural gas), as compared to the 2012 average production of approximately 4,230 barrels per day.

Twent y A lberta Bak ken wells and 11 Belly River wells are planned to be drilled in 2013. The company is planning for five exploration wells and 26 development wells.

In 2013, DeeThree plans to build on the success of its 2012 drilling program

that resulted in the discovery of a significant oil pool on its Alberta Bakken property and the confirmation of the multi-zone potential of its Belly River light oil resource play. The company plans to focus on achieving significant production gains while at the same time further establishing the resource potential of both of its Alberta Bakken and Belly River oil resource plays. The company believes that its 2012 acquisitions of 51 sections (32,640 net acres) that offset its Alberta Bakken play and 34 sections (21,760 net acres) that offset its Belly River light oil play are highly prospective for further exploration and development.

At Belly River, DeeThree drilled a significant light oil well completion early in 2013. DeeThree successfully drilled and completed a horizontal oil well at 5-2747-14W5 into the previously undrilled “D sand,” which is currently being tested at an approximate rate of 1,190 barrels of oil equivalent per day (45 per cent crude

oil and liquids) 44 hours after fracture stimulation. The well is currently flowing on a three-quarter-inch choke at a wellhead pressure of 530 pounds per square inch with the natural gas currently being recovered for sale through the company’s extensive oil and gas sales system.

In 2012, the company was successful in proving the multi-zone potential of the Belly River light oil resource play in Brazeau. This plan will continue in 2013 with the goal to have all six major intervals identified within the Belly River formation tested by the end of the first quarter. With the multi-zone potential hav ing been identified, the company will now look to delineate the extents of each of these zones to ultimately prove the resource potential of each.

The company’s final Alberta Bakken well of 2012 was a two-mile long horizontal extension to the east of its existing Ferguson Bakken oil field. The well encountered excellent pay and gas

DeeThree is planning to drill 20 oil wells into the Alberta Bakken this year. It added 51 sections to the play in 2012.

OIL & GAS INQUIRER • APRIL 2013

41

Southern Alberta

The well had a 30-day initial production rate of

448 barrels per day,

further confirming the company’s geological and seismic modelling.

detection through to the end of the horizontal leg, and significantly extended the known limits of the oil pool to a 40-square-mile fairway. The well had a 30-day initial production rate of 448 barrels per day, further confirming the company’s geological and seismic modelling. The company relied on these results in its recent acquisition of an additional six sections of Crown land that offset the eastern portion of its Alberta Bakken land base. In early 2013, the company will drill additional wells in this area to further delineate this trend over the 15 sections of its eastern lands.

DeeThree has yet to define the western edge of its Ferguson Alberta Bakken pool.

Of the land acquired in 2012, the company acquired 19 sections of highly prospective Crown land on trend to the west of its Alberta Bakken development oil wells. The company is planning to drill one or two wells on this acquired acreage in 2013, with a view to extend the identified size of its Ferguson Alberta Bakken pool. Drilling success on these lands will be significant

as this acreage had little or no oil in place associated to it in the mid-year resource study. The company is currently in the process of licensing wells in the area.

On its nor t her n core area in t he Alberta Bakken, DeeThree has completed an internal geological and geophysical study of its 50-section land base, including 17 recently acquired sections of Crown land situated to the north of its existing core development area. After incorporating the 2012 drilling results and legacy vertical well control to the company’s geological and geophysical mapping, it believes that it has potentially identified two separate and distinct oil prospects in the northern area of its Alberta Bakken play. Both prospects are 12–15 square miles in size and are located five to 10 miles from DeeThree’s existing core development area. The company plans to drill two to four wells testing these prospects in 2013. Drilling success would be significant as no oil resource potential has yet to be assigned to these lands.

www.3ddrillingtools.ca

Grant Heads 7 1/16” - 20” • Automatic Mudsaver 3 1/2” - 4 1/2” Core Certified • Drill Pipe & Collars 8135 Wagner Road, Edmonton, AB

T6E 4N6

Ph. (780)440-1922

1-888-229-9995 24/7

• Drill Pipe HW & Slick • Collars-Monel • Kellys & Drivers • Reamers • Key Seat Wipers • Hole Openers

42

APRIL 2013 • OIL & GAS INQUIRER

• Pipe Tubs, Test Plugs

• Adapter Spools • Flanges

• Blooeyline • Wireline Retrievable Floats • Portable Heaters • Flow Line Adapters • Elevators, Tongs, Slips

Southern Alberta

Marquee Energy to spend $26 million this year Marquee Energy Ltd. announced a $26-million 2013 capital program in February, with the goal of generating 25 per cent production growth while continuing to increase the company’s oil and liquids weighting.

Results for all three wells from the company’s fourth-quarter horizontal drilling program at Michichi in south-central Alberta have exceeded the company’s expectations for the area. These results, along with ownership in facilities and infrastructure at Michichi, have enhanced the already strong economics of Marquee’s Detrital and Banff oil plays.

Marquee continues to be the most active driller on the emerging light oil play at Michichi. Since July of 2011, Marquee has drilled 10 out of the more than 30 horizontal wells licensed by industry in the Michichi area. Marquee spud three horizontal wells during the fourth quarter of 2012. The fi rst well averaged more than 200 barrels of oil equivalent per day over an initial five-day test period and achieved

30-day production of 141 barrels per day (90 per cent oil and liquids). Testing of the second and third wells was limited as they were drilled off an existing multi-well pad site. Over initial test periods, the second well tested greater than 200 barrels per day (one-day test) and the third well tested 173 barrels per day (three-day test). Both

and upgraded to recover associated natural gas liquids. The plant became operational on February 1, and is now capable of processing more than 8 million cubic feet per day. Over half of Marquee’s current Michichi production is now tied into company-owned infrastructure, which is expected to reduce gas-processing costs on this production by as much as 30 per cent. T he The first well averaged more than 200 barrels of oil company has also reduced onequivalent per day over an initial five-day test period. stream times by approx imately of these horizontal wells were expected 50 per cent to an average of 45 days on the to be on production by the end of the fi rst three most recent horizontal wells. quarter. To date, the company has achieved Marquee achieved record monthly a 100 per cent success rate on its fi rst 10 production of approximately 650 barrels wells drilled in the Michichi area, which per day from its Lloydminster property in the company believes further validates the December 2012. The company will also repeatability of the high rate of return oil begin shipping oil by rail from Lloydminster in February, which is expected to improve plays at Michichi. netbacks on the railed production by more Marquee’s wholly owned gas plant, acquired in October 2012, has been expanded than $5 per barrel.

OIL & GAS INQUIRER • APRIL 2013

43

Southern Alberta

Zargon Oil & Gas sanctions Little Bow ASP tertiary recovery project

TuRBoFARMER 41.7

:

UneQUalled aGiliTY and PerFormance The only telehandler designed and built to outperform all lifting methods Increase of your productivity by 20% to 50% Best fuel economy of the industry Capacity: up to 26 000 lb

Merlo: undisputed worldwide leader in telehandlers

P40.17

P38.14

P120.10 HM

merlo in canada: from coast to coast!

QUeBec manulift Quebec City, (418) 651-5441 Varennes, (450) 652-5550 Garage Émile larochelle inc.

Saint-Isidore, (418) 882-5654 Équipements r.m. nadeau Sherbrooke, (819) 846-6828 les entreprises antonio laporte & Fils inc.

Notre-Dame-des-Prairies, (450) 756-1779 centre Kubota des laurentides Mirabel, (450) 434-0000 location Blais Rouyn-Noranda, (819) 797-9292 maniToBa Bobcat of central manitoba ltd.

Winnipeg, (204) 633-1058

44

onTario manulift Burlington, (905) 315-8881 corbeil equipment ltd.

Curran, (613) 673-5184 Hutchinson Farm Supply inc.

Stouffville, (905) 640-2692 delta Power equipment Essex, (519) 776-7374 Exeter, (519) 235-2121 Forest, (519) 786-5335 Watford, (519) 849-2744 Stoltz Sales and Service Listowel, (519) 291-2151 Mildmay, (519) 367-2672 Elmira, (519) 669-1561 GJ’s Farm equipment inc.

Burgessville, (519) 424-9374 anderson equipment Sales Belleville, (613) 969-6246

APRIL 2013 • OIL & GAS INQUIRER

SaSKaTcHeWan e. Bourassa & Sons Assiniboia, (306) 642-3826 Estevan, (306) 634-9444 Pangman, (306) 442-2033 Radville, (306) 869-2277 Weyburn, (306) 842-6626 meadow Power & equipment ltd.

Meadow Lake, (306) 236-4455 alBerTa manulift Langdon, (403) 936-8668

nieboer Farm Supplies Nobleford, (403) 824-3404 edmonton Kubota Edmonton, (780) 443-3800 Kubota country Fairview, (780) 835-5515 BriTiSH colUmBia meinen Brothers agri Services Agassiz, (604) 796-3820 neW BrUnSWicK Valley Sales & Service ltd.

St-André, (506) 473-3439

Zargon Oil & Gas Ltd. has sanctioned the construction of the Little Bow Alkaline Surfactant Polymer (ASP) tertiary recovery facility, marking another step in the commercialization of the project in southern Alberta.

The ASP project entails the injection of large volumes of a dilute chemical solution into a partially depleted oil reservoir to recover incremental oil reserves. With sanctioning, Phases 1 and 2 of the Little Bow ASP project will be Canada’s ninth operational ASP project. After three years of preparation, Zargon is now ready to proceed with the construction phase of the Little Bow project. In particular, the Energy Resources Conservation Board regulatory scheme approval has been obtained, detailed engineering design has been completed, long lead time and large equipment orders have been placed and Class 3 construction cost estimates have been prepared. The project entails the construction of a water-softening plant, chemical handling/mixing facilities and water injection facilities. In addition, there will be oil battery upgrades, pipeline replacements/ upgrades, water injector conversions and well reactivations.

Including the $6.5 million in ASP costs spent in 2012, the total capital cost of the wholly owned Phases 1 and 2 of the Little Bow ASP project is approximately $59 million (excluding the cost of capitalized chemicals).

The scheduling of these expenditures is $38 million in 2013, $4 million in 2014, and $11 million in 2015 relating to the Phase 2 implementation. With sanctioning, field construction will proceed during this summer, which will permit a January 2014 first injection and initial incremental oil volumes by mid-2014.

Based on southern Alberta analog pools and Little Bow reservoir model studies with predicted recoveries as high as a 17 per cent incremental reservoir recovery, Zargon’s internal base case sanctioning economics

Southern Alberta

use a 12 per cent incremental reservoir recovery factor and predict an estimated 4.87 million barrels of proved and probable oil reserves. The increased reserves are due in part to an updated reservoir model with increased chemical injections, and the corresponding Phase 1 and 2 chemical costs for the six-year chemical injection period (2014-20) will be capitalized and are estimated at $66 million.

You need downtime, your pump jack shouldn’t.

The Ecoquip 9000 series Hydraulic Pump Jack is reliable, durable and powerful.

Photo: Joey Podlubny

Zargon expects production to increase by 1,470 barrels per day in the first five years of the project.

Based on Zargon’s base case economics, incremental oil production from Phases 1 and 2 is estimated to average 1,470 barrels of oil per day in the five-year (2016-20) period. The long-life stable production profi le of the ASP project is well suited for Zargon’s dividend-paying business model.

Follow-on capital expenditures for Phases 3 and 4 of the Little Bow ASP project are expected to be completed by 2017, with forecasted total combined Phase 1–4 peak production rates expected to occur in 2020 at a combined incremental production rate of 2,300 barrels of oil per day.

• No unreliable and faulty sensor bars or proximity switches mounted on or near wellhead.

• The only unit using a true N2 counter-balance which ensures an energy efficient and smooth stroke that reduces wear on equipment, rods, pumps or seals.

• 144” stroke length, 35,000lbs lifting capacity and speeds up to 7 strokes per minute all at the same time. No de-rating of performance based on well dynamics.

Pump Jacks

www.ecoquip.ca OIL & GAS INQUIRER • APRIL 2013

45

15th Biennial

SASKATCHEWAN

OIL & GAS SHOW Exhibition Grounds • Weyburn, SK

June 5 & 6, 2013 Show Highlights:

• Awards ceremony • 24-hour security • Keynote speakers • Golf tournament and barbecue • Excellent show facilities with improved outdoor space and storage • First class show management • Social events to broaden exposure • Complimentary loading and unloading • Latest products and services on display • Free passes for attendees

Nominations are now being accepted for the 2013 South East Saskatchewan Oil Person of the Year

Weyburn Review Photo Greg Nikkel

Please download form off our website: www.oilshow.ca Email or send to address below

Sponsored by…

WEYBURN OIL SHOW BOARD

P.O. Box 1450, Weyburn, SK S4H 3J9 Tel: (306) 842.3232 Fax: (306) 842.3265 e-mail sk.oilshow@sasktel.net Web Site: www.oilshow.ca Platinum Sponsors:

SIlver Sponsors: Gold Sponsors:

DEL

Communications Inc.

SASKATCHEWAN WELL ACTIVITY FEB/12

FEB/13

Wells licensed





FEB/12

FEB/13

Wells spudded





FEB/12

FEB/13





Rigs released

▼

▲

▲

Source: Daily Oil Bulletin

S.K. Saskatchewan

A tale of two Bakkens: Canadian and U.S. plays different animals, says analyst

Photo: Gerald Ford

By Carter Haydu

If you thought the Canadian and American portions of the Bakken were created equal, Investment Technology Group, Inc. energy research director Gibson Scott would be quick to point out the reasons why you were wrong.

“Just about the only thing these two plays have in common is that they both begin with the letter ‘B,’” he said during the Hart Energy and Canadian Society for Unconventional Resources (CSUR) DUG Canada conference and exhibition in Calgary.

Geologically speaking, according to Scott, most of the Canadian Bakken is found in localized pools that over eons have risen up and become trapped in small pockets along the incline into Canada from the deeper, more widespread Bakken resource south of the 49th parallel.

“In fact, if you think about it, millions of barrels of oil escaped the United States millions of years before the U.S. banned oil exports in 1975.”

As a result, the Bakken is very different to produce depending on what end of the Williston Basin one is drilling. North of the border in the Bakken-rich areas of southern Saskatchewan, oil and gas are located in shallow pockets that are fairly easy and inexpensive to access.

However, those pockets do not produce a huge amount of oil compared to the prize in North Dakota, where the petroleum is deeper and more costly to attain, but is also greater in volume.

Scott said, “In fact, it’s this crude oil produced from the U.S. Bakken that is having a

significant impact on regional differentials and is changing the landscape of the continent’s oil supply.”

Total production from the U.S. Bakken has surpassed 800,000 barrels per day, according to Scott, while the Canadian Bakken produces at a more modest rate of approximately 100,000 barrels per day.

Despite the more prolific nature of the U.S. Bakken, though, the energy research director believes the less-expensive nature of Canada’s Bakken makes it the more economical option for producers.

“In terms of economics, the Canadian Bakken truly shines,” he said.

In 2009, Scott said, it cost about $6 million to complete an average U.S. Bakken well, and that cost has inflated in 2013 to over $9 million per well. In the Canadian Bakken, by comparison, he said, the average cost to complete a well climbed from $1.6 million in 2009 to about $2 million to $2.9 million currently.

Part of what makes the Canadian Bakken more economical than in the United States, Scott said, is also Saskatchewan’s competitive royalty rates.

However, although the Canadian Bakken is currently superior from an economic perspective, Scott said the “pool of public equities” is much larger in the U.S. portion of the basin, and therefore investors may need to look south for underappreciated opportunities, as might service companies need to shift greater attention south over time.

Despite their differences, the Canadian and U.S. Bakken do have certain challenges in common. For example, Scott noted, there

The North Dakota Bakken is more prolific than in Saskatchewan, but cheaper drilling costs keep Saskatchewan competitive.

is a lack of plentiful pipeline infrastructure to get Bakken volumes to market. As a consequence, rail has become an important transportation option for producers.

“Rail transport has come to the aid of an under-piped system, sopping up…crude and providing operators with flexible access to new markets.

“However, rail is not without its challenges, the greatest of which is rail typically costs much more than pipe in terms of transportation. An integrated network of rail lines means producers will have to stay sharp to make sure they receive the best price for their product.”

OIL & GAS INQUIRER • APRIL 2013

47

Saskatchewan

Development of the Bakken has grown substantially in recent years, thanks in part to a combination of horizontal drilling and hydraulic fracturing. Kevin Heffernan, president of CSUR, said technology has really turned the oil and gas industry upside down over the past five years.

“Everything has been affected,” he said, noting the kinds of developments

industry pursues, how that development is fi nanced, the price received for product, as well as where producers can fi nd markets for products are all being impacted by the range of technological enhancements occurring throughout the industry.

During his presentation at the conference, Alberta’s Minister of Energy Ken Hughes said activities in the Bakken have

“mushroomed production,” and the play wasn’t widely anticipated to become so prolific as quickly as it has. The North American oil and gas industry has changed significantly as a result.

“Everybody knew that was possible, but not everyone was predicting how quickly that would happen or what an impact that would have upon the…continental crude market.”

Producers looked to the Lloydminster area for opportunity in Saskatchewan’s first land sale of 2013.

Saskatchewan’s first land sale of the year attracted $11.91 million in bonus revenue, far below 2012’s inaugural land sale haul of $28.73 million.

The provincial government sold 26,528 hectares at an average of $448.83 per hectare. The same sale of 2012 saw 53,977 hectares exchange hands at an average of $532.36.

48

APRIL 2013 • OIL & GAS INQUIRER

The February 2013 sale included 104 lease parcels that brought in $11.78 million in bonus bids and two petroleum and natural gas exploration licences that sold for $125,000.

W hile investment in t he Bak ken remains strong, industry continues to identif y opportunities province-wide, the government said. The Lloydminster area received the most bids with sales of $5.9 million. The Weyburn-Estevan area was next at $3.7 million, followed by the Swift Current area at $1.3 million and the Kindersley-Kerrobert area at $1 million.

“Land-sale revenues remain steady as producers show confidence in the oil and gas markets and the competitive environment found in Saskatchewan,” said Energy and Resources Minister Tim McMillan.

“It is encouraging that in this climate of record production, industry continues to identify new prospects and compete in our land sale, often fiercely, for the right to explore these prospects.”

Melinda Yurkowski, assistant chief geologist, petroleum geology, with the Saskatchewan Geological Survey, said that production from the Ratcliffe beds in the Mississippian has seen a nearly threefold increase in production. Producing around 3,000 barrels per day in late 2010, the latest reports show it producing about 7,600 barrels per day now from over 360 wells. Oil’s cut is running about 20–25 per cent.

The new wells are mostly in the Skinner Lake, Oungre and Freda Lake fields, and largely drilled by NAL Energy C or p or at ion (n ow c om bi n e d w it h Pengrowth Energy Corporation), although Enerplus Corporation and ARC Resources Ltd. are also heavily involved. There are

584 total Ratcliffe producers, 128 of them drilled since the beginning of 2010.

“Land around the fields looks fairly taken up; however, there are some significant blocks of open Crown not far away and along strike of the production,” Yurkowski noted.

Meanwhile, at February’s land sale, the top purchaser of acreage in the province was Ranger Land Services Ltd., which spent $2.48 million to acquire six lease parcels.

The top price paid for a single lease was $967,554, by Ranger Land, for a 210.44-hectare parcel adjacent to the Northminster North G.P. sand oil pool, eight kilometres northeast of Lloydminster. The broker paid an average of $4,597.77 for several legal subdivisions of section 11 at 51-27W3.

The top price paid for a single licence was $70,183.10, by Tamarack Valley Energy Ltd., for a 1,068.37-hectare block located three kilometres east of the Reflex Lake St. Walburg sand oil pool, 10 kilometres south of Marsden. The company acquired the rights to the southern half of section 13 at 43-27W3.

The highest dollar per hectare was produced by Plunkett Resources Ltd., whose bonus bid of $332,276 worked out to an average price of $10,264.96 for a 32.37-hectare lease located within the Weyburn Midale and Frobisher beds pools, 15 kilometres south of Weyburn. The parcel included legal subdivisions five and six of section 31 at 06-13W2.

Gas-prone areas of t he prov ince attracted bonus bids of $78,383 for 517.99 hectares, an average of $151.32. Parcels offering deeper rights only brought in $1.36 million (11.41 per cent of the sale) for an average price of $891.50.

Photo: Joey Podlubny

Saskatchewan’s first land sale down from last year

Saskatchewan

Saskatchewan oil revenue down According to a recent update, t he Saskatchewan government is forecasting lower-than-budgeted revenue for oil, natural gas and Crown land sales when compared to original budget projections.

According to the Saskatchewan Party government’s third-quarter 2012/2013 update, the province is now expecting oil revenue of $1.32 billion for the fiscal year that ends on March 31, down $278.2 million from budget; natural gas revenue is now pegged at $8.2 million, off $4.3 million from budget figures; and Crown land sales are now forecast at $88.9 million, down $131 million from budget expectations.

Despite this, the government projects the province will fi nish 2012/2013 with a pre-transfer surplus of $8.8 million in its general revenue fund (GRF).

“Given the current world economy, preserving a balanced budget is challenging,” Deputy Premier and Finance M i n ister Ken K rawet z sa id. “ W h i le Sa sk atc hewa n’s economy is st rong,

1.32

$

billion

Oil revenue for the province of Saskatchewan in 2012

resource revenue is down because of falling prices. This decline is offset somewhat by record investment and revenue from a growing tax base, which has expanded thanks to higher employment and population growth.”

In total, GRF revenue is projected to be $11.4 billion, an increase of $104.2 million (0.9 per cent) from the budget estimate.

Oil revenue is forecast to decrease $113.6 million from the mid-year projection, largely due to a lower wellhead price forecast resulting from weaker West Texas Intermediate (WTI) oil prices and a wider light-heavy differential.

At the third-quarter mark, the average 2012/2013 WTI oil price is forecast at US$91.76 per barrel, down from the mid-year projection of US$93.27 per barrel, and off from the original budget estimate of $100.50.

The light-heavy differential has increased from 17.8 per cent at mid-year to 20.4 per cent at third quarter.

As a result, wellhead prices are now forecast to average C$69.29 per barrel in 2012/2013, down from the projection of $72.63 at mid-year. When the budget was tabled, the wellhead price forecast was $82.45.

Oil production for the fiscal year is now estimated at 171.2 million barrels, down from the mid-year forecast of 173.4 million barrels and off from the original budget expectation of 176.9 million barrels.

We worried about withstanding the worst extremes, so you don’t have to.

Westeel liquid storage tanks are engineered to withstand the toughest applications, everything from extreme hot and cold temperatures to operating environments where dents, scrapes and corrosive elements are common. In addition, our tanks are manufactured in ISO 9001:2008 quality controlled facilities using superior steel grades for strength, durability and longevity, and are designed to meet or exceed all current environmental codes, standards, and guidelines.

MF20833-0511

westeel.com 1 800 665 2099

OIL & GAS INQUIRER • APRIL 2013

49

News Tech

The latest regional technology news

Western Hydrogen Ltd. gets federal funding for hydrogen technology Western Hydrogen Ltd. will receive $1.45 million in federal funding from Sustainable Development Technology Canada (SDTC) to help the company continue piloting an innovative hydrogen production technology that is expected to have significant economic and environmental advantages over current hydrogen manufacturing.

By commercializing the molten salt gasification (MSG) process, Western Hydrogen believes it can create significant benefits for hydrogen users—especially those in the hydrogen-intensive oilsands business.

A major advantage of the MSG technology is the ability to produce hydrogen from water and a variety of carbon feedstocks such as

“ The big dream here is to help meet the world’s growing demand for energy with hydrogen made from renewable feedstocks. That’s the holy grail we’re chasing.”

— Neil Camarta, president and chief executive officer, Western Hydrogen Ltd.

petroleum coke, asphaltenes, natural gas or even renewables like algae or glycerol. Conventional hydrogen-production technologies require the injection of air (which creates NOx emissions) or oxygen (which requires expensive air-separation equipment). The result of using MSG is a simpler process that emits fewer emissions relative to conventional hydrogen production technologies.

A second significant advantage is that the system produces a highpressure stream of hydrogen that is easier to purify and use in other processes such as oilsands upgrading. CO2 is also produced at high pressure, which makes it easier to capture for sequestration.

“Coming from an oilsands background, I saw the potential of this technology right away,” says Neil Camarta, president and chief executive officer of Western Hydrogen. “Producing hydrogen is one of the most expensive and carbon-intensive parts of the oilsands business. If we can produce it more cheaply and cleanly—we’ll have a real winner.”

50

APRIL 2013 • OIL & GAS INQUIRER

“Coming from a Cleantech background, we also immediately saw the potential of this technology,” says Vicky Sharpe, president and chief executive officer of SDTC. “MSG technology could significantly reduce the energy use in the oilsands processes and reduce emissions.

Innovation like this exemplifies how Canadian entrepreneurs will help address environmental concerns through market mechanisms.”

Western Hydrogen has constructed and is commissioning a pilot plant near Fort Saskatchewan to test the MSG process. Three phases are anticipated, each testing a different feedstock: asphaltenes, natural gas and a biomass such as glycerol. This pilot testing will build on six years of laboratory testing to date.

Looking further ahead, the potential applications for MSG technology go far beyond Alberta. Countries such as Germany, Japan, Korea and the United States are currently developing low-carbon “hydrogen economies” reliant on rapidly advancing fuel cell technologies. The potential for carbon-neutral hydrogen produced from the MSG process could play an important role in making the switch to a low-carbon energy future.

“The big dream here is to help meet the world’s growing demand for energy with hydrogen made from renewable feedstocks,” says Camarta. “That’s the holy grail we’re chasing.”

GE introduces new lift technologies Building on its reputation as a leader in developing innovative artificial lift technologies to help increase the flow of fluids from oil wells, General Electric (GE)’s Oil & Gas’s drilling and surface business has introduced two new products for the upstream oil production sector, including the company’s first-ever motor cooling system (MCS) and a new high-efficiency electric submersible motor.

Mounted at the base of an electric submersible pump (ESP) string between the motor and sensor, GE’s new MCS is compatible up to 270 horsepower with GE’s E37 motors, and utilizes an auxiliary seal and secondary pump to draw fluid past the equipment and cool the ESP motor when the string is placed below perforations.

By reducing well-fluid recirculation, GE’s MCS system achieves very low motor temperatures, and employs a unique design that allows improved gas avoidance below the perforations and provides an alternative to a shroud, removing certain sizing and pressure constraints.

The MCS also offers more system-design flexibility for downhole equipment when the motor is placed below the perforations, simplifying installation requirements and helping to increase system run-life by

Te c h N e w s

generating fluid flow to cool the motor and protecting the motor lead cable.

The new system is well suited for high gas to oil ratio wells and low wellbore pressures, replacing shroud applications with high interior and exterior pressure differentials and low fluid-flow wells.

The company’s new 4.56-inch high-effi ciency electric submersible motor is in final field trials in North America. The new model is designed to deliver more power and higher efficiencies than existing motors, allowing the motor’s overall length to be reduced per horsepower. Its new design allows more copper in the winding, increasing the maximum horsepower per foot of length by more than 30 per cent.

Shorter equipment strings also simplify installation requirements.

“By adding our new motor cooling system and the high-efficiency motor to our artificial lift portfolio, we are reaffirming our commitment to developing and deploying the latest technologies and services that will help operators increase the efficiency of their production activities, including in maturing fields,” says Gary Ford, president of artificial lift at GE Oil & Gas. GE has begun delivering the MCS to customers in North America, and the system is available globally. Meanwhile, GE plans to offer its new, high-efficiency motor to global customers in 2013.

YEAR ROUND INDUSTRIAL & COMMERCIAL INSTALLATION • Chain Link Fence and Gates • Electric Gate Operators & Access Controls • Pre-Manufactured/Portable Site Enclosures • Industry Leading Health, Safety & Environmental Program

We also offer Safety Fence, T-Posts, Ornamental Fence & Vinyl Fence EDMONTON

Evolution Well Services demonstrates a cleaner and environmentally viable fracturing solution Evolution Well Services demonstrated their new hybrid-powered fracturing technology at Lethbridge, Alta., in February. Various industry professionals witnessed the first demonstration of a mobile natural gas solution that results in lower emissions, lower operating costs in terms of fuel savings, reduced eco footprint and increased efficiencies.

This new technology allows for the use of electrical power to deliver fracturing fluids to the wellbore during fracturing operations. This innovative solution eliminates the use of conventional diesel engines and transmissions along with their associated emissions, eco footprint, maintenance issues and manpower.

Evolution Well Services is an oilfield technology company that provides mobile, modular, electric-powered, high-pressure pumping systems for use in hydraulic fracturing in shale oil gas fields.

Evolution Well Services recently teamed with General Electric to use their mobile TM2500+ gas turbine unit to generate on-site power. The turbine provides fast, high power that is efficient without the traditional emissions associated with existing applications.

Emissions are estimated to be two-thirds less than conventional fracturing methods. This new technology needs 75 percent less manpower to operate and only produces a total of 88 decibels of sound compared to 105–108 decibels of each diesel system.

During the launch event, Eldon Schelske, Evolution Well Services president, said, “going forward, there will be two huge concerns in the industry: not having enough qualified people running this equipment for us, and doing damage to the environment. We hope we’ve addressed environmental concerns with our solution.”

(780)447-1919

12816 - 156 St. Fax: (780) 447-2512 edmonton@phoenixfence.ca

1-800-661-9847

CALGARY

(403)259-5155

6204 - 2nd St. S.E. Fax: (403) 259-2262 calgary@phoenixfence.ca

1-888-220-2525

Two are stronger than one.

Compass Bending has doubled in size to serve you better We have doubled in size to provide our customers with the highest possible level of quality and service.

Additional Services:

• Insulation, taping and coating, including YJ bends • 3D and 5D bends • 10” and 12” bends • Structural Bending

Experience, Quality & Service.

CompassBending.com CompassBending.co 7320 30 Street S.E. Calgary, Alberta T2C 1W2 • Phone: (403) 279-6615 • Fax: (403) 236-4249 • Toll free: (800) 708-7453

OIL & GAS INQUIRER • APRIL 2013

51

Cover Feature

Putting together the LNG

Midstream operators begin building the supply chain for LNG exports

J

ust how important is the construction of liquefied natural gas (LNG) export facilities to getting western Canada’s gas industry back on its feet?

LNG exports to Asia could easily build up to 10 billion cubic feet per day within five years of the first export terminal opening, according to Ziff Energy Group.

“We could get over 20 billion cubic feet a day of total western Canadian gas output pretty quickly if several of the proposed West Coast LNG export projects are realized, which is really good news for our basin. Drill bits will have to start turning to come up with this gas,” said Edward Kallio, the firm’s director of gas consulting, at a recent Ziff-sponsored breakfast in Calgary.

Kallio told the breakfast attendees that while LNG exports won’t drive prices sky-high, they will make dry gas production in the basin profitable once again.

“Every time we look at the cost curve for North American gas, it gets lower. We would have thought it might have come up a bit, but it keeps getting lower,” he said. “So the price impact of more LNG demand is very modest.”

52

APRIL 2013 • OIL & GAS INQUIRER

“We’ve got a lot of resource that’s very modestly priced. And we can sell into Asia without spiking the price. When those drill bits start turning in western Canada to bring on five to 10-plus billion cubic feet a day of supply, we would expect full-cycle costs to be recovered.... And that’s fantastic news for western Canada,” said Kallio. “But it’s going to take some time to bring that gas on, so we’re going to have some pain here in the interim. But good news, looking forward.”

Western Canadian gas output has plunged to about 13 billion cubic feet per day and will probably fall closer to 12 billion cubic feet per day next year, Ziff Energy expects.

“Our gas is being shut out of the U.S. market and even the eastern Canadian market,” Kallio said, referring to the inability of western Canadian gas to compete with cheap output from shale plays such as the Marcellus in the northeastern United States.

“Marcellus is going to get up to 15, maybe 20 billion cubic feet a day by 2020,” Kallio said. “They don’t need our gas.”

When western Canada was producing 17 billion cubic feet per day, about 10 billion cubic feet per day of that was shipped south of the border. Exports to the United States have now plummeted

Photo: iStockphoto.com/MsLightBox

By Darrell Stonehouse

Cover Feature

to roughly five billion cubic feet per day and are headed to three or four billion cubic feet per day, or even lower, Kallio said. Asian exports could make up for that lost market.

Western Canadian midstream operators have been hard at work positioning themselves to take advantage of the coming LNG export boom.

SPECTRA FINDS ITSELF IN POSITION FOR BOOM

Spectra Energy Corp. finds itself in an enviable position as the LNG export economy takes shape, says president and chief executive officer Gregory Ebel.

“Our western Canadian business has $7 billion of expansion growth on their horizon,” he says. “Spectra Energy Transmission West sits in the midst of four world-class gas resources: the Horn River, the Montney, the Cordova and the Liard. The growing gas supply environment in western Canada is attracting significant international investment, with total investment in [the] British Columbia natural gas sector alone projected to reach $250 billion over the next 20 years. Much of that investment likely will be directed towards the development of LNG terminals and pipelines to serve those.”

Spectra is currently working with BG Group plc to construct a major pipeline connecting its northeastern B.C. transmission system to BG Group’s proposed LNG terminal at Prince Rupert.

experience in LNG and LPG operations along the entire value chain and their access to markets in Asia, we believe those business opportunities will bring long-term social and economic value to both Canada and Japan.”

Cornhill says AltaGas is beginning consultation with First Nations, working on feasibility studies as well as permitting and regulatory approvals with a goal of exporting LPG and LNG as early as 2016 and 2017, respectively.

As owner of the Pacific Northwest Pipeline, the only natural gas line running to the west coast, AltaGas finds itself in a leadership role in getting gas to the market. The company already has an 80-million-cubic-feet-per-day contract in place with the BC LNG Export Co-Operative, the smallest of the proposed LNG facilities.

TRANSCANADA BETS ON MONTNEY, HORN RIVER

It will soon have competition, however, from gas pipeline giant TransCanada Corporation. In June 2012, TransCanada was selected by Shell Canada Limited and its partners to build, own and operate the proposed Coastal GasLink Pipeline Project, an estimated $4-billion pipeline that will transport natural gas from the Montney gas-producing region near Dawson Creek to the recently announced LNG Canada LNG export facility near Kitimat, both in British Columbia. The LNG Canada project is a

“LNG players like BG and others will stimulate significant exploration and development in the coming years, and that will require incremental gathering and processing services.”

— Gregory Ebel, president and chief executive officer, Spectra Energy Corp.

“LNG players like BG and others will stimulate significant exploration and development in the coming years, and that will require incremental gathering and processing services,” says Ebel.

“As Spectra Energy is the service provider for 60 per cent of the gathering and processing market in British Columbia today, we’re confident we can capture a significant portion of this additional activity.”

Ebel says while all seven of the currently proposed LNG facilities will likely not be built, enough will be to drive a major increase in midstream opportunities.

“Even with a couple of them going, you’re going to more than exceed the current capacity of gas production in British Columbia today. And nothing’s going on in Alberta. So gas production in British Columbia today, and that’s going to need processing. And that’s where I see some real opportunities for us over the longer term,” he says.

ALTAGAS LOOKS OVERSEAS FOR MARKETS

AltaGas Ltd. recently announced it has formed a partnership with Idemitsu Kosan Co., Ltd., Japan’s second largest petroleum company, to help develop the Asian marketplace. The two companies are investigating exporting both LNG and liquefied petroleum gas (LPG) overseas.

“We believe the access to new markets is critical for the future of the Western Canadian Sedimentary Basin,” says Altagas chairman and chief executive officer David Cornhill. “With Idemitsu’s

joint venture led by Shell, with partners Korea Gas Corporation, Mitsubishi Corporation and PetroChina Company Limited. Shell and TransCanada are working toward the execution of definitive agreements on the Coastal GasLink Pipeline Project. The approximately 700-kilometre pipeline will carry in excess of 1.7 billion cubic feet of gas to tidewater.

In January, TransCanada announced it had been selected by Progress Energy Canada Ltd. to design, build, own and operate the proposed $5-billion Prince Rupert Gas Transmission Project.

This proposed pipeline would transport natural gas primarily from the North Montney gas-producing region near Fort St. John to the recently announced Pacific Northwest LNG export facility in Port Edward, near Prince Rupert, B.C. In addition, TransCanada proposes to extend its existing NOVA Gas Transmission Ltd. (NGTL) system in northeastern British Columbia to connect both to the Prince Rupert Gas Transmission Project and to additional North Montney gas supply from Progress and other parties. This new infrastructure will allow the Pacific Northwest LNG export facility to access both the abundant North Montney supplies as well as other Western Canadian Sedimentary Basin gas supplies through the NOVA Inventory Transfer trading hub and the extensive existing NGTL pipeline network. Initial capital-cost estimates associated with extensions of the NGTL system are approximately $1 billion to $1.5 billion, with an in-service date targeted for the end of 2015.

OIL & GAS INQUIRER • APRIL 2013

53

Cover Feature

Boat at Kitimat, B.C. The port will be the centre for LNG exports if current plans come to fruition.

Oil pipeline giant Enbridge Inc. has also inserted itself into the midstream as the LNG export economy takes shape. Enbridge slipped into the market last year by buying the majority interest in the Cabin gas plant in the Horn River shale play, north of Fort Nelson, B.C. At its October 2012 Investor’s Day, Enbridge president and chief executive officer Al Monaco said the key to developing the LNG market is certainty of supply and his company can play a role in making that happen through the development of midstream infrastructure.

“I think the producers will look to us for that midstream capability,” he said.

Leon Zupan, Enbridge president of gas pipelines, says that as operators continue to use technology to drill up shale gas formations in northeastern British Columbia and Alberta there is the potential to bring on large volumes of gas in a short period. But for that to happen, they must ensure they have established markets to justify drilling the large fields. They must also ensure there is a good supply base in those fields that can be drilled in the right time period and that they have the right infrastructure in place to get the supply to tidewater.

Zupan says Enbridge sees $4.5 billion in potential opportunities, including future phases of Cabin, as more dry gas will be required for LNG exports. The company also sees additional projects as producers are looking for the midstream solutions to process and transport their gas in emerging plays like the Duvernay in Alberta.

Only one liquid level controller is Dual Seal Certified* to comply with Canadian

Electrical Code and National Electrical Code requirements: the Norriseal Series 1001A with electric switch.

It’s easy to install, eliminates the need for costly secondary process seals, and it’s packed with features. Like an explosion-proof switch, NACE option, weather-resistant sealed case, and more.

Install confidence with the Norriseal Series 1001A. For details, call (780) 434-8566 or visit www.albertaoiltool.com. *CSA Certified Dual Seal to ANSI/ISA 12.27.01 standard.

Meets CEC and NEC secondary seal requirement.

54

APRIL 2013 • OIL & GAS INQUIRER

Series 1001A level controller

Photo: Joey Podlubny

ENBRIDGE ENTERS MIDSTREAM

Feature

The

solution A mix of growing natural gas liquids drilling and demand for condensate to dilute bitumen to make it pipeline-ready drives midstream growth

By Darrell Stonehouse

W

estern Canada’s midstream operators are in expansion mode as a result of increased natural gas liquids (NGL) production from west-central Alberta and growing demand for condensate from oilsands developers.

Add in an interest in capturing added value from oilsands byproducts to the mix, and midstream operators find themselves in a land of increasing opportunity.

Midstream operator Keyera Corp. chief executive officer Jim Bertram reported to shareholders in mid-February that Keyera saw significant growth in 2012 as a result of positioning itself as a hub between NGL producers and oilsands producers.

“The combination of increased NGL production and continued interest in oilsands developments have resulted in a number of new business opportunities,” Bertram said.

Bertram said higher NGL production in western Canada and growing demand for fractionation, storage and handling services resulted in a strong year for that segment of the business.

“Our NGL fractionators operated at full capacity for most of the year, with demand for service exceeding available capacity,” he noted.

There was similar demand for condensate from oilsands operators, he added.

“Diluent deliveries increased throughout the year at the Alberta Diluent Terminal, where we moved to 24-hour-a-day operations in the fourth quarter. Demand for storage resulted in higher utilization levels and higher fees,” he explained.

Bertram expects this pattern of growth to continue in 2013.

Total growth capital investment was $446 million in 2012, of which $281 million was acquisitions. Keyera expects its 2013 growth capital investment, excluding acquisitions, to be between $250 million and $300 million.

56

APRIL 2013 • OIL & GAS INQUIRER

“Continued producer activity in west-central Alberta is driving a number of new initiatives at Keyera’s gas plants,” said Bertram. “Producers continue to seek additional services at the Rimbey gas plant to support active drilling programs in the Glauconite and Duvernay geological zones. Gross throughput at Rimbey averaged 319 million cubic feet per day in the fourth quarter of 2012, up 17 per cent from the same period in 2011, and NGL-handling facilities at the plant were running near capacity. In September, we announced that we were constructing a 400-million-cubic-feet-per-day turbo expander at Rimbey to extract up to 20,000 barrels per day of ethane, as well as incremental propane, butane and condensate. Supporting the project is a long-term sales agreement with a large ethane consumer in Alberta and a long-term fee-for-service processing agreement with a large producer. Discussions are ongoing regarding the construction of a pipeline to deliver gas to Rimbey from lands west of the plant, where several producers are drilling Duvernay wells.”

Keyera also has a number of projects underway in its NGL infrastructure segment. At its Fort Saskatchewan facility, construction began on a 30,000-barrel-per-day de-ethanizer, as well as additional underground NGL storage capacity and development of a new brine pond. To support deliveries of NGLs and crude oil to customers by rail, Keyera is developing rail terminals at South Cheecham, south of Fort McMurray, and at Hull, Texas.

In the fourth quarter, Keyera purchased a newly constructed producer-built pipeline connected to the Strachan North gathering system and started receiving volumes at the Strachan gas plant. Keyera also entered into an agreement with a producer in the Minnehik Buck Lake area in Alberta to purchase a pipeline currently under construction. The purchase will occur upon the

Petrochemical companies are looking at oilsands by-products as a feedstock for expansion.

completion of construction, which is expected in the first half of 2013. A similar agreement is in place to purchase a producer-built pipeline that will connect to the Carlos pipeline. Construction of the pipeline is expected in 2013.

Keyera continues to work on the commercial terms necessary for an expansion of the Simonette gas plant.

“In the fourth quarter, several multinational energy companies licensed wells in the lands adjacent to the plant,” said Bertram. “These new entrants, together with other producers, are targeting the Montney, Duvernay and other zones in the region.”

“Given the current projects Keyera already has underway and other opportunities under consideration, if current levels of industry activity are sustained we anticipate that our growth capital investment for the next several years may continue at levels similar to 2013,” Bertram added.

Photo: Joey Podlubny

ENBRIDGE LOOKS SOUTH FOR CONDENSATE SUPPLY

Oil pipeline giant Enbridge Inc. is also looking to increase its role in providing condensates to the oilsands industry. It has an open season underway on its Southern Lights pipeline that would see condensate brought north from the United States to supply the oilsands.

“Southern Lights is all driven, of course, by the expected increase in volumes out of the oilsands, which are going to require more diluent,” Al Monaco, Enbridge chief executive officer and president said in February.

Steve Wuori, president of liquids pipelines and major projects, Enbridge, said some of that condensate would come from the Eagle Ford play in Texas because the condensate is worth more in Alberta.

“We are also working to add to the distribution system for condensates to the various oilsands operators and pursuing a project

or projects to do that from the Edmonton hub, where most of the condensate pool becomes available from Southern Lights and from other sources,” he added. “So we are looking at ways of moving condensates up for diluent needs. As it’s apparent that a lot of the growth will be from dilbit, which is condensate added to bitumen, as opposed to synbit, which is synthetic crude added to bitumen.”

SOLARIS GTL TARGETS DILUENT MARKET

Solaris Synthetic Petroleum Inc. (Solaris GTL) is also advancing plans to become a player in the diluent market. Solaris recently signed an agreement with Praxair Canada Inc. under which Praxair will become Solaris GTL’s atmospheric gases provider.

The agreement with Praxair is the first in what is expected to be a series of agreements that will greatly expedite the ability of Solaris GTL to move forward,” Bill Overend, a spokesman for the Calgary-based company, said in a news release. “Given the Praxair team’s depth of experience and innovative solutions, we’re excited to have them on board.”

Under the deal, Praxair will provide atmospheric gases and world-class technology for all gas-to-liquids facilities to be built and commissioned by Solaris GTL in Canada. The facilities will convert natural gas to value-added liquids including propane and “natural gasoline,” or condensate whose pricing is more aligned to oil prices.

“These will be highly economic plants. The innovation around the Solaris GTL solution will cause you to rethink all you’ve heard about gas-to-liquids,” said Overend. “People commonly think of the Fischer-Tropsch process invented in Germany and used to produce fuels in the Second World War,” he said. “Compared to Fischer-Tropsch, our solution is cleaner, much less capital intensive, and economic even at small scale.”

OIL & GAS INQUIRER • APRIL 2013

57

Feature

Unloading heavy oil. Demand for dilbit to ship heavy oil is driving midstream expansion.

The Solaris GTL plants will use Haldor Topsøe A/S’s methanol technology as well as its MTG technology, the “TIGAS” (Topsøe Improved Gasoline Synthesis). Haldor Topsøe is a global catalyst and technology company headquartered in Denmark.

Solaris GTL expects that its solution will be in high demand not only by oilsands producers, but also by dry gas producers who need to add value to the product they are drilling, said Overend.

With Canadian oilsands production at more than 1.7 million barrels per day and climbing, the demand for condensate used as bitumen diluent is expected to rise for years to come, he said.

Under the new long-term agreement, Williams will extract, transport, fractionate, own and market the natural gas liquids and olefins recovered from the off-gas at the oilsands producer’s upgrader near Fort McMurray. Under the agreement, the NGL/olefins recovered are expected to be approximately 12,000 barrels per day by mid-2015, growing to approximately 15,000 barrels per day by 2018.

The NGL/olefins mixture will be fractionated at Williams’s Redwater facilities into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate. The ethane price risk associated with this deal is

“The scale that we are building here—with fractionation, distribution and storage—gives us the ability to generate significant long-term incremental value from our operations.”

Solaris GTL facilities that could potentially be served by Praxair as part of the memorandum of understanding include greenfield stand-alone plants and brownfield integration projects of varying production capacities, producing from 1,000 barrels per day to 34,000 barrels per day of product.

Initial projects contemplated by Solaris GTL include a plant west of Edmonton, a plant west of Spirit River and a plant at Empress.

Overend said the company expects preliminary front-end engineering design to be underway in the first quarter of 2013 with start-up to occur as early as 2018, assuming timely regulatory approvals.

WILLIAMS BUILDS ON OFF-GAS PETROCHEMICAL BUSINESS

On a different note, Williams Energy (Canada) Inc. continues constructing its own version of the oilsands midstream, this time based on off-gases from oilsands processing.

Late last year, the company signed a new long-term gas processing agreement with a producer in the Canadian oilsands.

58

APRIL 2013 • OIL & GAS INQUIRER

mitigated via the previously announced long-term agreement to supply NOVA Chemicals Corporation with up to 17,000 barrels per day of ethane and ethylene.

The propane recovered will be sold into the local propane market and will potentially be used as feedstock at Williams’s proposed propane dehydrogenation facility in Canada. The other products will be sold into the established markets where Williams sells existing NGLs and olefins produced in Canada.

“This new agreement will build on the unique expertise and largescale infrastructure we’ve built in Canada,” said David Chappell, president of Williams. “The scale that we are building here—with fractionation, distribution and storage—gives us the ability to generate significant long-term incremental value from our operations.

“The new operations will also further reduce greenhouse gas and sulphur dioxide emissions from the upgraders’s oilsands operations, and produce valuable commodities that were previously being burned,” Chappell said.

Photo: Joey Podlubny

— David Chappell, president, Williams Energy (Canada) Inc.

Feature

flow

Managing New software expected to help producers meet tougher field measurement reporting requirements

By Godfrey Budd

A

and measurement

new software package aimed at gathering oil and gas facility data looks set to be effective preventive medicine for what might otherwise have proved one of the worst and most persistent regulatory headaches ever to afflict Alberta’s oil and gas producers.

Last September 11, the Energy Resources Conservation Board (ERCB) released Directive 017, Measurement Requirements for Oil and Gas Operations. Of particular significance in the 300-plus page document were sweeping new requirements for detailed measurement schematics for all upstream oil and gas facilities—from a wellhead to a gas plant to a separator to a flow line—almost any device involved in current production.

A measurement schematic, as described by the ERCB, is a diagram showing the physical layout of a facility and which “traces the normal flow of production from left to right as it moves from wellhead through to sales.”

Besides precise information on legal survey location, identification and facility boundaries, section 1.9.1 of the directive requires the schematics to include flow lines that move fluids in or out of the facility, with their flow direction, and lines that connect “essential process equipment within the facility, including recycle lines and bypasses to measurement equipment.”

The directive’s list does not stop there. It also requires details on measurement points, storage tanks, flares, related fuel use and off-gassing, water sources, types of monitoring equipment and instrumentation—anything, in short, that might affect the final production tally.

60

APRIL 2013 • OIL & GAS INQUIRER

“The schematics must be used by operations and production accounting to ensure that the reported volumes are in compliance with the ERCB reporting and licencing requirements,” says the directive.

The problem—for perhaps quite a few producers—is that they have only vague or incomplete data on field facilities, including the number of producing wells they have. Often, this falls far short of the kind of detailed information on their field assets required under Directive 017.

“Many companies don’t know how much fuel gas they’re using, so fuel gas consumption is not reported, but the government wants to know what’s being produced into the sales pipe—and what’s being consumed in the field,” says Mark Proud, senior executive and co-founder of Manfred James Group Inc., a Calgary-based software developer and engineering consulting firm.

Until now, the information on some companies’s field assets could at best described as sketchy—with the level of detail, sometimes, of the sort found scribbled on a napkin, says Bob Gray, a principal at Prophet Consulting Inc. His Calgary consulting firm helps clients with allocations, production reporting, revenue and royalty optimization.

But under Directive 017, which provides for “an initial window of two years from September 11, 2012,” producers are required to have a comprehensive metering diagram so that accounting programs accurately reflect conditions, production, fuel use, et cetera in the field.

“The ERCB wants to see anything that shows how the required reporting is achieved,” Proud says. The ERCB, he says, “wants granular information on every wellhead and surface facility.”

Feature

“Many companies don’t know how much fuel gas they’re using, so fuel gas consumption is not reported, but the government wants to know what’s being produced into the sales pipe—and what’s being consumed in the field.”

— Mark Proud, senior executive and co-founder, Manfred James Group Inc.

Clearly, a shift in reporting requirements of this scope is not for even the most impeccably organized reams of paper napkins.

With nearly 650 operators, Alberta’s oil and gas industry has about 45,000 surface facilities and 180,000 active wellsites, and measurement schematics for all of them are supposed to be in a resource database by September 2014.

Most would agree that it makes sense to have good measurement schematics, but going out in the field and developing sets of detailed drawings to support them costs time and money. Colin Pashley, field superintendent for regulatory safety and environment with Surge Energy Inc., gives an outline of the traditional process for obtaining the type of field data mandated under Directive 017.

“First, gather the drawings from construction. Send these to the drafting department, then send drawings to the field for verifying, then back to drafting for edits. It involves quite a bit of traffic back and forth,” says Pashley.

Gathering field asset data this way would be further complicated under the new reporting regime, as it requires that all changes made to equipment included in measurement schematics be reflected in timely updates coinciding with reporting schedules. This could be difficult, if not impossible, within the scenario described by Pashley. Production reporting to the Petroleum Registry of Alberta on the previous month must be filed by the 18th of the current month. Updating the field information the old-fashioned way to meet the new requirements might entail more than pressing the refresh button.

If not quite as speedy as hitting a refresh button, the new PIDE Piper software from Manfred James enables companies to report on production volumes and update information on field equipment more efficiently. PIDE stands for piping instrumentation diagram editor.

“Instead of manual drafting, the program drafts and captures multiple images of site equipment. From there, using a drag and drop menu, it develops configurations of the equipment. As you build a schematic, the program can calculate how much fuel is being used. For example, if you note the presence of a chemical pump at the site, the program asks what kind, and calculates how

much fuel it’s using. Consumption is backed out of production, and there’s a tight audit trail,” Proud says.

He says the firm has had its drafting and field group doing this kind of work by hand since 2008, but began developing the PIDE software about 15 months ago. Surge Energy has been using the software for two or three months.

“You can do a quality drawing on site and include all the details required. Using a hand-held tablet, you can sketch with a stylus on the tablet and create a drawing that represents the reality in the field. You capture photos and attach them to drawings—photos, nameplate data, calibration tags, et cetera. The photos back up what you’ve drawn and the appropriateness of the metering equipment is demonstrated by the photos and diagram,” Pashley says.

He says the program improves accuracy and, depending on the scope of a project, can cut months of work down to a matter of days.

“The amount of time saved is phenomenal,” he says.

Another advantage of the program is that, besides largely eliminating the need for skilled draftsmen, personnel from a broad range of skill levels can accomplish the fieldwork, provided they have a laptop, tablet or other comparable digital device.

“Anyone can do this—an operator, pipefitter, engineer, an experienced production accountant with a technical bent,” says Gray of Prophet Consulting.

He notes that for any item on a diagram, the program allows for attributes like size, horsepower, pipe diameter, vent location, vent volumes and so on.

“Without this software, for most operators, even the closest to compliance, it becomes very labour and cost intensive to meet the refresh deadlines, as assets change,” says Mike Hansen, strategic adviser of the oil and gas group at Stantec Inc. It’s because of the requirement of timeliness under Directive 017 for updating field asset data that Manfred James will also be selling PIDE Piper as a licenced application.

“It was originally developed for in-house use at the Manfred James Group,” Proud says.

OIL & GAS INQUIRER • APRIL 2013

61

advertisers' index 3D Drilling Tools Inc . . . . . . . . . . . . . . . . . . . . . . . 42

Do All Industries Ltd . . . . . . . . . . . . . . . . . . . . . . 33

Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Alberta Oil Tool . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Dragon Products . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 51

Annugas Compression Consulting Ltd . . . . . . . . 55

Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 45

Platinum Grover Int. Inc . . . . . . . . . . . . . . . . . . . . 39

Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . 43

Expertec Van Systems Inc. . . . . . . . . . . . . . . . . . 42

Pumps & Pressure Inc . . . . . . . . . . . . . . . . . . . . .40

Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 32

FlexSteel Pipeline Technologies Inc . . . . . . . . . . . 8

Risley Equipment Inc . . . . . . . . . . . . . . . . . . . . . . 21

Bilton Welding and Manufacturing Ltd . . . . . . . . 27

Joint Utilities Safety Team . . . . .inside front cover

Saskatchewan Oil & Gas Show . . . . . . . . . . . . . .46

Brews Supply . . . . . . . . . .12, 22 & inside back cover

Kubota Canada Ltd . . . . . . . . . . . . . . . . . . . . . . . . 3

Sirius Instrumentation And Controls Inc. . . . . . . 24

Brother’s Specialized Coating Systems Ltd . . . . 38

Manulift EMI Ltee . . . . . . . . . . . . . . . . . . . . . . . .44

Site Energy Services . . . . . . . . . . . . . . . . . . . . . . 36

Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . 37

MaXfield Inc. . . . . . . . . . . . . . . .outside back cover

Tank Gauging Systems. . . . . . . . . . . . . . . . . . . . . 33

ClearStream Energy Holdings. . . . . . . . . . . . . . . 59

Maxxam Analytics . . . . . . . . . . . . . . . . . . . . . . . . 20

Tundra Process Solutions Ltd . . . . . . . . . . . . 4 & 34

Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . . 51

MDI Industrial Sales Inc . . . . . . . . . . . . . . . . . . . . 31

Unified Valve Ltd . . . . . . . . . . . . . . . . . . . . . . . . . 15

CRD Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Medius Industrial. . . . . . . . . . . . . . . . . . . . . . . . . 19

Vertigo Theatre Society . . . . . . . . . . . . . . . . . . . 32

Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 37

V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . .11

Definitive Optimization. . . . . . . . . . . . . . . . . . . . 18

MRC Global Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . 16

West Country Oilfield Services & Weed Control . . 10

Diversified Glycol Services Inc . . . . . . . . . . . . . . 20

NETZSCH Canada Inc. . . . . . . . . . . . . . . . . . . . . . 26

Westeel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Northgate Industries Ltd. . . . . . . . . . . . . . . . . . . 21

Zeeco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

62

APRIL 2013 • OIL & GAS INQUIRER

industrial electrical supplies when you need them

AUTOMATION

Since 1927, Brews Supply – Offering a broad range of industrial electrical products, in stock and ready to ship!

CABLING SOLUTIONS

Brews carries a complete range of industrial electrical supplies to fill all your needs, from automation to wiring devices and everything in between.

DISTRIBUTION EQUIPMENT HEATING EQUIPMENT

ew

s 24 h

INDUSTRIAL CONTROL

hot

UTILITY PRODUCTS

vi ce

r

r

B

SAFETY

b

ut r ton se

ENCLOSURES

WEIDMULLER’S TERMSERIES THE ALL-ROUNDER RELAYS AND SOLID-STATE RELAYS FOR ALL APPLICATIONS Weidmuller introduces the next generation of DIN rail mount relay modules with the versatility required for today’s applications.

Features Include: • Fixed voltage or Universal 24-230Vuc input • 6.4mm (SPDT) and 12.8mm(DPDT) configurations • Distinct LED status display • Screw or tension-clamp connections • Unlimited cross-connectivity

Visit www.BrewsSupply.com/all-rounder or contact your Brews Supply sales representative for more information.

BREWS SUPPLY

Toll Free 1.800.661.6884

Calgary (Head Office) 12203 40th St. S.E. P. 403.243.1144

www.brewssupply.com

Edmonton 18003 111th Avenue N.W.

P. 780.452.3730

TOGE THE R WE CAN

For over 10 years MaXfield has quietly been gaining the expertise and experience to handle your next project.

From custom vessels to structural steel, piping and modular packaged equipment, MaXfield is now your one-stop shop for industrial fabrication.

w w w. m a x f i e l d . c a