Oil & Gas Inquirer October 2012

OCTOBER 2012 ■ $6.00

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How to clean up in tHe energy business.

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A N o r t h A m e r i c A N L e A d e r i N e N v i r o N m e N t A L A N d e N e r g y s e r v i c e s

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Crescent Point Energy Corp - Flat Lake S.A.I.T. Polytechnic - Calgary Campus Suncor Energy - Wilson Creek

Phone: 403 945 3561

Email: [email protected]

Web: www.nrgps.ca

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TREATERS & F.W.K.O’s

Creating Innovative Energy Solutions with Wisdom & Integrity

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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 2012 Modern Group Inc. All rights reserved.

U.S. owned and operated. Founded in 1963.

Make it happen.

1 2012 Sierra 3500HD DRW 4x4 Regular Cab with available Duramax® Diesel and Allison® transmissions, when properly equipped. Based on WardsAuto.com 2012 Large Pickup segmentation, 2012 Model Year competitive data for Ford Super Duty F-350 and Ram 3500 Heavy Duty pickup trucks and latest published information available at time. Excludes other GM models. 2 2012 Sierra 3500HD DRW 2WD Regular Cab. Based on WardsAuto.com 2012 Large Pickup segmentation, 2012 Model Year competitive data for Ford Super Duty F-350 and Ram 3500 Heavy Duty pickup trucks and latest published information available at time. Maximum payload capacity includes weight of driver, passengers, optional equipment and cargo. Excludes other GM models. †Available Duramax® Diesel.

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o i l & g a S i n Q u i r e r • O C T O B E R 2 0 1 2 7

Keeping readers regionally informed

F E A T U R E S

49 Central Alberta Drill bit success helps Spartan grow

production

53 Southern Alberta Deethree boosts budget to $110 million

57 Saskatchewan renegade fi nds growth across

Saskatchewan

27 Liquids glut taking shape in western Canada By�Paul�Wells

59 Water-based fluid system improves shale drilling

33 British Columbia Proposed Kitimat oil refi nery must make

economic sense, says industry

� By�Richard�Macedo

39 Northwestern Alberta Birchcliff production continues to climb

45 Northeastern Alberta Land-use plan will cancel oilsands leases

� By�Lynda�Harrison

10 Stats at a Glance

62 Political Cartoon

G E N E R A L N E W S

R E G I O N A L N E W S

T E C H N O L O G Y N E W S

I N E V E R Y I S S U E

On the coverphoto: photos.com

OCTOBER 2012 $6.00

Can

adia

n P

ublic

atio

n M

ail P

rodu

ct A

gree

men

t #40

0692

40

PLUS TRACKING TIGHT GAS DEVELOPMENT IN NORTHEASTERN BC

WITH OIL PIPELINE CONSTRAINTS, TRUCKS AND TRAINS ARE PICKING UP THE SLACK

ROADRAIL

ROADto

WITH OIL PIPELINE

ROADRAILRAIL

ROADRAILRAILtotoRAIL

With pipeline capacity tight, trucking and rail pick up the slack

Road to rail Stranded

By�Godfrey�Budd By�Darrell�Stonehouse

Northeastern B.C. gas supply continues to grow, but new markets still years away

211 Cover feature

For more information about Dry Ice Blasting, contact Medius Industrial toll-free at 1.800.675.5771, in Regina at 306.565.3395, or in Yorkton at 306.620.6632. Visit them online at mediusindustrial.ca.

industrialH E A V Y D U T Y R E S T O R A T I O N

New industrial cleaning method taking off and paying off in oil fields

ive years ago the term dry ice blasting was virtually unheard of in the oil and gas industry. Today, however, the process is rapidly becoming the preferred method of cleaning among the industrial, commercial, utility, and environmental sectors. Regina-based Medius Industrial is now bringing the technology to Saskatchewan oil fields. So, how does it work? And why is it so quickly replacing previous cleaning techniques?

Dry Ice Blasting at a glance Tiny CO2 (ice) pellets are blasted at supersonic speeds through a jet of compressed air at -78 degrees C or -109.3 degrees F. Upon contact with the ice, contaminants shrink and lose adhesion from subsurfaces. The dry ice is then converted back into carbon dioxide gas and evaporates into thin air. The process effectively and efficiently removes contaminants such as bitumen, corrosion, chemicals, acids, and heavy oils without causing any damage to the underlying surface or creating any secondary waste.

Greater profitsThe benefits of CO2 blasting are many, leading more and more industries to move away from traditional less

efficient cleaning and restoration methods. The oil and gas sector, in particular, has seen a spike in the use of this new technology. Because the process allows for equipment to be cleaned hot whilst online, there is no need for disassembly or shutdown. This equates to less downtime and greater profitability. Dry ice blasting is also non-toxic, non-abrasive, non-conductive and environmentally responsible.

More versatilityChris Krasowski, General Manager for Medius Industrial says, the possibilities with their dry ice blasting service are virtually limitless, “One of the greatest advantages to our dry ice blasting process is its extreme versatility. Clients can use it to clean piping, wellheads, valves, vessel interiors and, well... pretty much anything they need cleaned.” Those in the oil and gas sector find the system particularly attractive as it reduces the chance of foreign materials such as sand or debris from entering and damaging process equipment.

With oil drilling set to increase by 6% in Saskatchewan during 2012, dry ice blasting will undoubtedly be an option more will be considering.Photos courtesy of Cold Jet

BEFORE

AFTER

F

“After cleaning a surface, dry ice pellets convert back into carbon dioxide gas, which means there’s virtually no residue left behind other than the contaminants removed during cleaning.” - Chris Krasowski, General Manager, Medius Industrial

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Editor’s Note

O I L & G A S I N Q U I R E R • O C T O B E R 2 0 1 2 9

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

Send your emails to [email protected]. Please mark them as "Le� er to the Editor" if you want them published.

N E X T I S S U E

November 2012In the November issue, we look at the North Dakota and Alberta Bakken tight oil plays, along with an in-depth analysis of the booming Manitoba oil plays.

A generation has passed since the Alberta Conservative government last threw taxpayer money at private enterprise in an e� ort to diversify the province’s economy.

That foray into the private sector resulted in billions of dollars wasted in e� orts such as MagCan, a $200-million magnesium project south of Calgary that went belly up less than a year after opening, costing the province $108 million in loan guarantees.

It appears today’s Redford Conservatives have forgotten the lessons of the past.In early September, the government announced it was investing $745 million of its

$2-billion sustainability fund in Shell Canada Limited’s Quest carbon capture and storage (CCS) project, aimed at reducing greenhouse gas emissions from its oilsands operations. The total price tag for the project is $1.35 billion. The federal government is also throwing in $120 million of other people’s money to build the project. Shell will be majority owner of Quest and act as designer, builder and operator. The project will also form the core of Shell’s CCS research program and help develop Shell’s CO2 capture technology.

Good news for Shell, which is getting $865 million from taxpayers to fund the project.But there are a lot of questions to be asked about why the governments are fi nancing a pri-

vate venture with public money. The fi rst is, can the Alberta government really a� ord this project given it is running a $3-billion defi cit in 2013? Even worse, should the federal government be giving money to private industry when it is running a $21-billion defi cit in 2012-13?

Another question is, what happens when other oilsands operators or coal-fi red power generators want to develop CCS projects? Will taxpayers foot half of their bills, too? Or is Shell special—and, if so, why?

Then there are the technical questions. Is burying CO2 the best option for handling the greenhouse gas, or is it just that the oil industry’s geological and engineering expertise has created blinders hiding other, more viable options? In other words, if the only tool you have is a hammer, you tend to see every problem as a nail. Maybe there are ways to view CO2 as a resource rather than a waste product. Maybe public money would be better spent investigating these other options.

The province, for its part, views CCS as part global-warming solution and part public-relations exercise. Energy Minister Ken Hughes said as much in announcing the funding for Quest.

“Technologies like CCS will play an instrumental role in helping to lower greenhouse gas intensity from the oilsands and demonstrate to the world Alberta’s commitment to responsible energy development,” Hughes said.

And that’s all fi ne and good. But we’ve seen from MagCan and other boondoggles that government is a poor judge of what emerging technologies will drive future economic growth. It should stick to regulating and let private enterprise come up with its own solu-tions rather than pouring public money in a hole.

Darrell Stonehouse | [email protected]

Dumping money in a hole

Vol. 24 No. 8EDITORIALEDITORDarrell Stonehouse | [email protected] WRITERSGodfrey Budd, Lynda Harrison, Richard Macedo, Paul WellsEDITORIAL ASSISTANCE MANAGERSamantha Sterling | [email protected] ASSISTANCELaura Blackwood, Brandi Haugen

CREATIVEPRINT, PREPRESS & PRODUCTION MANAGERMichael Gaffney | [email protected] SERVICES MANAGERTamara Polloway-Webb | [email protected] LEADCathlene OzubkoGRAPHIC DESIGNERPeter MarkiwCREATIVE SERVICESJanelle Johnson

SALESSALES MANAGER—ADVERTISINGMaurya Sokolon | [email protected] ACCOUNT EXECUTIVEDiana SignorileSALESNick Drinkwater, Rhonda Helmeczi, Mike Ivanik,Nicole Kiefuik, David Ng, Sheri StarkoFor advertising inquiries please contact [email protected] TRAFFIC COORDINATOR—MAGAZINESDenise MacKay | [email protected]

DIRECTORSPRESIDENT & CEOBill Whitelaw | [email protected] & DIRECTOR OF SALESRob Pentney | [email protected] OF EVENTS & CONFERENCESIan MacGillivray | [email protected] OF THE DAILY OIL BULLETINStephen Marsters | [email protected] OF DIGITAL STRATEGIESGord Lindenberg | [email protected] OF CONTENTChaz Osburn | [email protected] OF PRODUCTIONAudrey Sprinkle | [email protected] OF MARKETINGKim Walker | [email protected] OF FINANCEKen Zacharias, CMA | [email protected]

OFFICESCalgary 2nd Flr-816 55 Avenue N.E. | Calgary, Alberta T2E 6Y4Tel: 403.209.3500 | Fax: 403.245.8666 Toll-Free: 1.800.387.2446Edmonton220-9303 34 Avenue N.W. | Edmonton, Alberta T6E 5W8Tel: 780.944.9333 | Fax: 780.944.9500Toll-Free: 1.800.563.2946

SUBSCRIPTIONSSubscription Rate In Canada, 1 year $49 plus GST, 2 years $69 plus GST Outside Canada, 1 year $99

Subscription Inquiries Telephone: 1.866.543.7888Email: [email protected]: junewarren–nickles.com

GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2012 JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240. Postage Paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 80 Valleybrook Dr, North York, ON M3B 2S9

Made in CanadaThe 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.

10 O C T O B E R 2 0 1 2 • o i l & g a S i n Q u i r e r

STATSAT A GLANCE

WCSB Oil & Gas CompletionsSource: Daily�Oil�Bulletin

M O N T H O I L G A S D R Y S E R V I C E T O TA L

Aug 2011 922 262 28 80 1,292Sep 2011 1,448 445 24 155 2,072Oct 2011 1,153 321 20 49 1,543

Nov 2011 1,170 331 27 42 1,570Dec 2011 988 359 27 115 1,489Jan 2012 419 190 15 31 655

Feb 2012 846 244 21 52 1,153Mar 2012 996 180 33 66 1,275Apr 2012 608 192 31 157 988

Jun 2012 376 25 40 8 449Jul 2012 660 92 16 105 873Aug 2012 682 148 9 67 986

Wells Drilled in British ColumbiaSource: B.C. oil and gas Commission

*�from�year�to�date

M O N T H W E L L S D R I L L E D C U M U L AT I V E *

Aug 2011 40 519Sep 2011 92 611Oct 2011 35 646

Nov 2011 92 738Dec 2011 58 796Jan 2012 53 53

Feb 2012 66 119Mar 2012 39 158Apr 2012 86 244

Jun 2012 13 334Jul 2012 57 401Aug 2012 53 454

*From�year�to�date

Saskatchewan CompletionsSource: Daily�Oil�Bulletin

M O N T H OIL GA S OTHER TOTA L

Aug 2011 413 2 13 2Sep 2011 352 4 29 Oct 2011 457 29 46 2

Nov 2011 524 4 32 0Dec 2011 332 4 61 Jan 2012 142 10 8 10

Feb 2012 296 6 20 22Mar 2012 414 0 40 Apr 2012 172 0 49 221

Jun 2012 144 0 10 1Jul 2012 232 0 16 2Aug 2012 296 4 9 0

Alberta CompletionsSource:�Daily�Oil�Bulletin

M O N T H O I L G A S O T H E R T O TA L

Aug 2011 452 183 93 2Sep 2011 1,028 357 146 1,1Oct 2011 626 259 19 0

Nov 2011 557 241 36 Dec 2011 568 300 72 0Jan 2012 215 131 35 1

Feb 2012 491 177 50 1Mar 2012 515 147 55 1Apr 2012 403 141 127 1

Jun 2012 205 12 37 2Jul 2012 348 46 95 Aug 2012 380 98 63 1

DSI THRU-TUBING INCProof in Performance

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average price received per thousand cubic feet of natural gas in the WCSB in 2011, according to Ziff energy.

$.$.average full-cycle fi nding and development costs per thousand cubic feet of natural gas in the WCSB in 2011, according to Ziff energy.

F A S T N U M B E R S

Drilling Activity: CBM & Bitumenalberta, September, 2012 Source:�Daily�Oil�Bulletin

C O A L B E D M E T H A N E B I T U M E N W E L L S

Alberta Aug 12 Aug 11 Aug 12 Aug 11

Northwestern Alberta 0 0 8 9

Northeastern Alberta 0 0 46 58

Central Alberta 0 0 85 102

Southern Alberta 10 2 0 0

TOTAL 10 2 1 169

Service Rig Count by Province/TerritoryWestern Canada, September 12, 2012 Source:��Rig�Locator

A C T I V E D O W N T O TA L A C T I V E

Western Canada (per cent of total)

Alberta 435 328 57%

British Columbia 10 19 2 34%

Manitoba 15 5 20 75%

Saskatchewan 157 42 199 79%

WC TOTALS 1 1,011 1%

Drilling Activity: Oil & Gasalberta, September 12, 2012 Source:��Daily�Oil�Bulletin

O I L W E L L S G A S W E L L S

Alberta Aug 12 Aug 11 Aug 12 Aug 11

Northwestern Alberta 102 91 59 108

Northeastern Alberta 46 58 0 13

Central Alberta 183 255 13 26

Southern Alberta 49 45 26 34

TOTAL 0 449 181

Drilling Rig Count by Province/TerritoryWestern Canada, September 12, 2012 Source:� Rig�Locator

A C T I V E D O W N T O TA L A C T I V E

Western Canada (per cent of total)

Alberta 252 322 44%

British Columbia 39 16 66%

Manitoba 11 11 22 50%

Saskatchewan 88 46 1 66%

WC TOTALS 0 0%

As a major Capital Region land developer,

Trans America Group knows all about

breaking new ground, something it has done

with the newly opened Fort Industrial Estates

in Fort Saskatchewan, Alta., just minutes from

northeast Edmonton. Fort Industrial Estates

can lay claim to being the “Fort’s” first major

industrial subdivision since East Gate Industrial

Park opened there in the 1960s. Adjacent to

Highway 15, the new 1,100-acre industrial

zone is strategically positioned to serve the

surrounding Alberta Industrial Heartland and

lies right on the path toward the numerous Fort

McMurray–area oilsands operations.

Trans America draws on an outstanding

40-year record in industrial, commercial and

residential development within the Edmonton

region (where it holds some 7,000 acres) as

well as outside Alberta. The company’s many

achievements include spearheading develop-

ment of the pioneering Acheson Industrial Area

just west of Edmonton.

Closer to Oilsands Action

Fort Industrial Estates is head-on competition

for Nisku/Leduc. That extensive industrial

swath south of Edmonton is home to scores of

distribution, manufacturing and fabrication

firms focused mainly on the conventional oil

and gas and oilsands sectors.

Besides offering significantly lower land

prices, Fort Saskatchewan is on the high-load

corridor allowing high, wide and heavy loads to

roll unimpeded to the oilsands. Bulky modules

prefabricated to the south already edge past

Fort Saskatchewan en route to Fort McMurray.

Fabricating oilsands-bound structures in Fort

Saskatchewan could cut transportation time

and costs by avoiding Edmonton.

Marvin Horwitz, Manager of Property Solutions

with Trans America Group, explains that Fort

Industrial Estates offers two major develop-

ments—a subdivision covering about 400 acres

and a bulk land area of some 700 acres.

The subdivision includes pre-supplied utilities

(service road, sewage, water and electrical) and

will be subdivided into 50 to 75 lots, most sized

two to six acres—but with some ranging up to 25

acres. The subdivision is ideally suited for light

industrial, warehouse and/or office use. Normally,

occupants will build their own facilities. However,

Trans America recently completed two

90,000-square-foot buildings, each configured to

meet either the needs of a single tenant or multi-

ple occupants. The Fort Industrial Estates

Heartland Building I is already 35 per cent leased.

Lots Competitively Priced

Sales are proceeding briskly on individual lots.

Buyers include a major Western Canadian oil

and gas distribution and service firm, which has

bought a four-acre plot and plans on building a

40,000-square-foot warehouse and distribution

centre. In September, Access Pipeline turned

sod on a 1.3-hectare (3.2-acre) lot for a

32,000-square-foot office/warehouse and

maintenance facility. Negotiations are conclud-

ing with an investment group on 30 acres for

modular construction facilities. At $350,000 to

$450,000 per acre, these serviced sites are

highly cost-competitive. Nisku/Leduc prices are

about $600,000 per acre.

“Tremendous” Relationship With City

Most of the Estates bulk land is earmarked for

“industrial users” seeking larger parcels.

Those locating in the bulk-land area will benefit

from Fort Saskatchewan’s zoning flexibility,

which permits landowners to customize road

access and to install certain self-serviced utili-

ties (such as on-site water wells and septic

fields). Trans America’s Horwitz emphasizes:

“We have a tremendous relationship with the

City of Fort Saskatchewan, which has a great

‘can-do’ attitude.”

Within the bulk area, where un-serviced land

sells for about $100,000 an acre (versus

$300,000 to $400,000 in Nisku/Leduc), there

is still flexibility in possible lot configuration and

sizes (100-acre-plus lots are still available). The

zone already has dawn the attention of a major

transport company, which is contemplating a

100-acre lay-down yard. Also, a modular manu-

facturer has eyes on about 180 acres.

Gateway to Alberta’s Industrial Heartland

Longer-term, the economic health of Fort

Saskatchewan will rest less on new industrial

construction than on routine servicing of plant

operations. For ongoing maintenance and

major turnarounds, plants want quick, local

access to expertise, products and services.

Fort Industrial Estates’ placement in the

Industrial Heartland should prove beneficial.

If Heartland Centre makes a business case

for Fort Saskatchewan, then the City, branding

itself as the Gateway to Alberta’s Industrial

Heartland, also helps make the new industrial

subdivision an attractive proposition.

Affordable Housing, Community Amenities

an Asset

Affordable housing becomes a definite asset

for employers wishing to attract employees to

the Fort Saskatchewan area. The city has seen

population increase by 32 per cent since 2003,

bringing it to 20,000-plus, a level expected to

double in the next three decades.

Major residential developers active in the

Capital Region have a Fort Saskatchewan

presence. The fact that many of these develop-

ers have held the land supplies for some time

means that residential lots, like For t

Saskatchewan’s commercial and industrial

land, typically sell for less than in nearby

municipalities and this has helped curb housing-

cost increases.

“Our homebuilders tell us that Fort

Saskatchewan remains one of the most

affordable communities in the Capital Region,”

says City Economic Development Director

Terry Stacey.

Besides readily available housing and nearby

employment, residents benefit from the many

amenities and public facilities, matching or

exceeding even those of larger communities. A

source of pride is the eight-year-old Dow

Centennial Centre, a multi-faceted community

centre with the 536-seat Shell Theatre, meeting

space, an ice surface, a soccer pitch and a gym-

nasium. The community offers more than 50 kilo-

metres of paved walking and biking paths, many

within the North Saskatchewan River Valley.

seizing industrial opportunity

For business expansion or relocation information contact Economic Development at: 780.992.6231 or visit www.fortsask.ca

Strategically Located Fort Industrial Estates in Fort SaskatchewanBuilds on Trans America Group’s Land Development Experience

advertisement advertisement

As a major Capital Region land developer,

Trans America Group knows all about

breaking new ground, something it has done

with the newly opened Fort Industrial Estates

in Fort Saskatchewan, Alta., just minutes from

northeast Edmonton. Fort Industrial Estates

can lay claim to being the “Fort’s” first major

industrial subdivision since East Gate Industrial

Park opened there in the 1960s. Adjacent to

Highway 15, the new 1,100-acre industrial

zone is strategically positioned to serve the

surrounding Alberta Industrial Heartland and

lies right on the path toward the numerous Fort

McMurray–area oilsands operations.

Trans America draws on an outstanding

40-year record in industrial, commercial and

residential development within the Edmonton

region (where it holds some 7,000 acres) as

well as outside Alberta. The company’s many

achievements include spearheading develop-

ment of the pioneering Acheson Industrial Area

just west of Edmonton.

Closer to Oilsands Action

Fort Industrial Estates is head-on competition

for Nisku/Leduc. That extensive industrial

swath south of Edmonton is home to scores of

distribution, manufacturing and fabrication

firms focused mainly on the conventional oil

and gas and oilsands sectors.

Besides offering significantly lower land

prices, Fort Saskatchewan is on the high-load

corridor allowing high, wide and heavy loads to

roll unimpeded to the oilsands. Bulky modules

prefabricated to the south already edge past

Fort Saskatchewan en route to Fort McMurray.

Fabricating oilsands-bound structures in Fort

Saskatchewan could cut transportation time

and costs by avoiding Edmonton.

Marvin Horwitz, Manager of Property Solutions

with Trans America Group, explains that Fort

Industrial Estates offers two major develop-

ments—a subdivision covering about 400 acres

and a bulk land area of some 700 acres.

The subdivision includes pre-supplied utilities

(service road, sewage, water and electrical) and

will be subdivided into 50 to 75 lots, most sized

two to six acres—but with some ranging up to 25

acres. The subdivision is ideally suited for light

industrial, warehouse and/or office use. Normally,

occupants will build their own facilities. However,

Trans America recently completed two

90,000-square-foot buildings, each configured to

meet either the needs of a single tenant or multi-

ple occupants. The Fort Industrial Estates

Heartland Building I is already 35 per cent leased.

Lots Competitively Priced

Sales are proceeding briskly on individual lots.

Buyers include a major Western Canadian oil

and gas distribution and service firm, which has

bought a four-acre plot and plans on building a

40,000-square-foot warehouse and distribution

centre. In September, Access Pipeline turned

sod on a 1.3-hectare (3.2-acre) lot for a

32,000-square-foot office/warehouse and

maintenance facility. Negotiations are conclud-

ing with an investment group on 30 acres for

modular construction facilities. At $350,000 to

$450,000 per acre, these serviced sites are

highly cost-competitive. Nisku/Leduc prices are

about $600,000 per acre.

“Tremendous” Relationship With City

Most of the Estates bulk land is earmarked for

“industrial users” seeking larger parcels.

Those locating in the bulk-land area will benefit

from Fort Saskatchewan’s zoning flexibility,

which permits landowners to customize road

access and to install certain self-serviced utili-

ties (such as on-site water wells and septic

fields). Trans America’s Horwitz emphasizes:

“We have a tremendous relationship with the

City of Fort Saskatchewan, which has a great

‘can-do’ attitude.”

Within the bulk area, where un-serviced land

sells for about $100,000 an acre (versus

$300,000 to $400,000 in Nisku/Leduc), there

is still flexibility in possible lot configuration and

sizes (100-acre-plus lots are still available). The

zone already has dawn the attention of a major

transport company, which is contemplating a

100-acre lay-down yard. Also, a modular manu-

facturer has eyes on about 180 acres.

Gateway to Alberta’s Industrial Heartland

Longer-term, the economic health of Fort

Saskatchewan will rest less on new industrial

construction than on routine servicing of plant

operations. For ongoing maintenance and

major turnarounds, plants want quick, local

access to expertise, products and services.

Fort Industrial Estates’ placement in the

Industrial Heartland should prove beneficial.

If Heartland Centre makes a business case

for Fort Saskatchewan, then the City, branding

itself as the Gateway to Alberta’s Industrial

Heartland, also helps make the new industrial

subdivision an attractive proposition.

Affordable Housing, Community Amenities

an Asset

Affordable housing becomes a definite asset

for employers wishing to attract employees to

the Fort Saskatchewan area. The city has seen

population increase by 32 per cent since 2003,

bringing it to 20,000-plus, a level expected to

double in the next three decades.

Major residential developers active in the

Capital Region have a Fort Saskatchewan

presence. The fact that many of these develop-

ers have held the land supplies for some time

means that residential lots, like For t

Saskatchewan’s commercial and industrial

land, typically sell for less than in nearby

municipalities and this has helped curb housing-

cost increases.

“Our homebuilders tell us that Fort

Saskatchewan remains one of the most

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says City Economic Development Director

Terry Stacey.

Besides readily available housing and nearby

employment, residents benefit from the many

amenities and public facilities, matching or

exceeding even those of larger communities. A

source of pride is the eight-year-old Dow

Centennial Centre, a multi-faceted community

centre with the 536-seat Shell Theatre, meeting

space, an ice surface, a soccer pitch and a gym-

nasium. The community offers more than 50 kilo-

metres of paved walking and biking paths, many

within the North Saskatchewan River Valley.

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P erhaps the Oracle of Omaha knew something hardly anyone else did. In November 2009, with news of Warren Buffett’s purchase of Burlington Northern Santa Fe (BNSF) Railway via his investment com-pany, Berkshire Hathaway Inc., speculation varied widely as analysts sought to fathom the justifi cation

for his breaking his rule of paying less, not more, in this instance. To secure the $44-billion deal, the then-79-year-old tycoon had paid 2.8 times the book value of BNSF. The surprise purchase of the second biggest of the four remaining U.S.-based transcontinental railroads came just 12 months after Berkshire’s worst year on record since Buff et took the helm in 1965. Was Buff ett’s bottom-of-the-business-cycle deal a bet on a U.S. economic rebound? On China? On a greener industrial economy? Should the ratings agencies pull Berkshire’s triple-A credit rating? Those were some of the questions being asked.

Fast forward to May 2012, and Nebraska’s Lincoln Journal Star reports that profi t for Berkshire’s wholly owned railway subsidiary is up almost 16 per cent, and that “Warren Buff ett’s railroad contin-ued to contribute to Berkshire Hathaway as one of its most profi table businesses—moving coal, cars, corn and other freight.”

Also in May, a 104-car train, which had originated on BNSF rail-way, was set to provide the 300,000-barrel-per-day Irving Oil refi n-ery in Saint John, N.B., with its fi rst shipment of Bakken crude.

A lack of pipeline capacity to handle Bakken oil from both Saskatchewan and North Dakota has been helping to create a glut in the Pad 2 and Cushing, Okla., markets, constraining oil exports from the region and prompting producers to fi nd shipping alternatives to pipe.

Just after Labour Day, BNSF said it has expanded operational capacity in the Williston Basin area to meet the anticipated require-ments of growing Bakken shale oil production, hiring 560 workers in North Dakota and Montana and investing about $200 million for replacing and upgrading railway infrastructure in the region and buying new equipment. Dave Garin, BNSF group vice-president for industrial products, said the rail company increased annual ship-ments of Bakken crude from 1.3 million barrels in fi scal year 2008 to 88.9 million barrels in fi scal year 2012, according to a recent AP story.

The railroad now has shipping capacity for up to one million barrels per day of crude oil from western North Dakota and eastern Montana. Current daily shipments average 243,500 barrels.

The increased capacity looks well aimed for a growing demand potential. Oil output from the Bakken in North Dakota alone reached over 600,000 barrels per day in June, after doubling in under two years.

The growth in BNSF’s petroleum shipments refl ects the recent increase in rail shipments across the United States as the company accounts for 58 per cent of all petroleum tank cars hauled by Class 1 carriers.

The trend to increased rail shipment of crude has been growing for some time. A year ago, almost to the day, Harold Hamm, founder

and chief executive of Continental Resources Inc., the largest pro-ducer in the U.S. Bakken shale, said that Cushing was becoming increasingly obsolete, as 92 per cent of the company’s then-60,000-barrel-per-day output was not being shipped to Cushing. Among other shipping operations, Continental railed crude to St. James, La.

The company’s use of rail is no stray blip on the radar, but would appear to mark a continent-wide shift. By mid-September 2011, the six major Class 1 railroads in the United States originated 7,765 tank cars carrying petroleum and refi ned products, according to the Association of American Railroads. This marked a big 19.2 per cent increase over 6,508 tank cars that originated at the same point in 2010, making crude and petroleum products the fastest-growing shipped category of goods on the U.S. railroad network.

Rail takes off in CanadaIn its annual forecast released in June, the Canadian Association of Petroleum Producers (CAPP) said that crude oil transport by rail will increase sharply in the short term because of the ability to add rail capacity relatively fast—and in small increments as needed, using existing railroad and other infrastructure.

The CAPP forecast says that growing oilsands, conventional and oil shale production is creating a need for additional transportation infrastructure. At present, much of the focus in western Canada’s oilpatch for this issue is on four main pipeline options: Keystone XL, which would ship oilsands diluted bitumen or “dilbit” to multiple U.S. destinations, including the Cushing hub, with possible con-nections to refi neries on the Gulf Coast; Northern Gateway, which would ship oilsands product to northern British Columbia for export to China; the Trans Mountain expansion, which expands capacity of an existing pipe from the Edmonton area to Vancouver. “Unless two out of three are done in the next few years, there will be ongoing capacity issues. Also, the TransCanada west-to-east line could ship oil instead of gas,” says Trent Stangl, vice-president of marketing and investor relations at Crescent Point Energy Corp., referring to the fourth option being looked at.

The company is active in the Saskatchewan Bakken and in the Shaunavon area, and its experience is illustrative of the shipping and transportation challenges faced by operators in the region. Compared to Alberta, where there are many options, Saskatchewan has only one main crude oil line for exporting out of the province, says Stangl.

The Enbridge main line, which services Saskatchewan, is a large system, he says, shipping oil from the Edmonton area to Chicago, southern Ontario and the Gulf, but mostly it has fed Pad 2 around the Chicago area—which is part of the supply system for the Cushing hub. “The big issue is that the Cushing market is oversupplied as a result of more North American light crude and heavy crude. There’s not a lot of spare capacity on the system,” Stangl says.

The company became concerned about access to markets in the wake of the Enbridge spill in Michigan in 2010, which, Stangl notes, Ph

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followed about three months after BP plc’s Macondo disaster in the Gulf of Mexico. According to the U.S. Environmental Protection Agency, the spill leaked about one million U.S. gallons of oilsands crude into Talmadge Creek, which fl ows into the Kalamazoo River. It was the sequel to the spill, no doubt, that set off alarm bells in some boardrooms. The spill drew intense scrutiny, and the delay in returning to previous fl ow volumes made shippers like Crescent Point nervous. The bottom line was that the number of barrels shipped along Enbridge line 6B remained reduced for longer than would have been typical in the past. “It highlights the risk of being tied to one pipeline system,” says Stangl.

As a backup option, the company decided to ship some of its crude oil production by rail.

But because of the added fl exibility and better access to markets other than the saturated Cushing system aff orded by rail shipments, shipping by rail morphed from a backup option to a key part of a two-part structure that now shapes shipping strategy at Crescent Point.

The new strategy is related to the current price diff erential between the mostly landlocked West Texas Intermediate (WTI) and the pricier, seaborne Brent Crude. The spread between the two benchmark crudes has at times nudged the $30 range, but the recent reversal of the Seaway pipeline between Cushing and the Gulf will now send crude to the coast, and is expected to bring the two prices closer together within a couple of years. For now, however, shipping by rail means that a producer can send product almost anywhere on the continent. A shipper can take advantage of the fact that crude prices at or near a coast tend to refl ect Brent values. “So you’re less impacted by price diff erentials,” says Stangl.

Some companies in these circumstances are targeting markets that want to pay less than Brent but are willing to pay more than WTI. “If you’ve been buying water-borne Brent, you’re happy to pay less for the same product. So there’s an opportunity for both buyer and seller. The key is that it frees one from Brent and the other from WTI,” says Stangl.

The company plans to have a rail-loading facility in each of its main areas of operations. Much of the necessary rail infrastructure is already in place.

In some respects, the shift to more transport of crude by rail harks back to the 1950s and 1960s, when more oil was shipped that way, says Calvin Nankivell, co-owner of Cliff Nankivell Trucking

Nearly 250,000 barrels of oil per day are being shipped by truck and train out of the u.S. Bakken.

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Ltd., based in southeastern Saskatchewan. One of his bigger clients has been shipping crude by rail, he says.

The Saskatchewan communities of Willmar, Bienfait and Stoughton, and the Manitoba area of Woodnorth are among loca-tions for rail terminals that service southeastern Saskatchewan’s petroleum transport requirements.

The eff ects of the constrained pipe capacity are rippling across the region’s oilpatch. Several trucking outfi ts in the region say busi-ness is steady but has not returned to levels seen at the end of last winter. Despite the switch to rail, producers still can’t always access the shipping capacity for their oil.

Oilsands operators are now looking to ship bitumen by truck and train to markets across North america.

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“Rail can’t keep up. They can’t seem to get enough rail cars to ship all the oil,” says George Lawrence, owner of Stage Oilfi eld Transport Ltd. of Estevan.

Producers on the U.S. side of the Bakken have more options for where and how they ship, he says. In southeastern Saskatchewan, the shipping-capacity shortage reined in fi nding and development activi-ties that would otherwise have happened, and this has had a knock-on eff ect on the trucking sector. “We’re one of the busier companies in town, and we’re running only at about half-speed,” Lawrence says.

One tack, he says, that some companies have taken is to leverage their share within a pipeline’s quota system via acquisition. “Instead of more drilling, some of the bigger E&Ps [explorers and producers] are buying smaller companies so they can have more room on the pipe,” he says.

An oil leak in late July this year, of about 1,200 barrels that spilled out of an Enbridge pipeline in Wisconsin that was delivering crude to the Chicago area refi neries, also didn’t help matters in the region this past summer, says Lawrence. The Wisconsin spill happened just a day or so shy of the second anniversary of the 2010 Kalamazoo spill.

Oil hauling picks up slack for truckersBut the region’s slowdown seems to have coincided with the end of last winter. In February, there were about 100 rigs in the area, says Dennis Day, general manager of Fast Trucking Service Ltd. Today, he estimates that there are about 60 drilling rigs active in the region. In the last three months, he says, business has picked up for his company, which hauls rigs and oilfi eld equipment, not oil.

Other factors have also likely had a role in dampening activity levels, says Day. These include service costs, a drop in commodity


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prices, and global economic and stock market uncertainty. A year ago, “we were at 120 per cent capacity; now, we’re at about 75 per cent capacity,” he says, adding that he expects the current activity level to remain.

A slight slowdown appears to have occurred, he says, in the North Dakota Bakken, where costs for the 12,000-foot wells drilled there are in the $7-million to $12-million range, and sev-eral times the cost of the 5,000-foot holes drilled in parts of the Saskatchewan Bakken.

The region’s trucking businesses have seen an infl ux of competi-tion as the Bakken’s oilpatch heated up in recent years. “There used to be just a few trucking companies here, but now it’s very competi-tive,” says Lana Emde, director of administration at Brady Oilfi eld Services LP.

The short-haul outfi t benefi ted from hauling water for the frack-ing boom in the region and, starting about four months ago, began hauling oil to rail terminals.

The lack of pipe capacity has perhaps combined with the fracking boom to create another shortage. “We could grow by about 15 more trucks but we can’t get the tank trailers. We’ve had 10 on order. They were supposed to come in July, then August. Now, it’s September. We’re still waiting,” Emde says.

Shale oil and gas formations have a well-earned reputation for het-erogeneity, and this, to some extent, appears to translate into varying commodity attributes—as one might expect. But within quite a small area the diff erence in corrosion potential can be marked. “Tank trailers used to last about fi ve years. Now, it’s barely one, and they have to be in the shop. Tanks seem to be corroding about fi ve times as fast in this area. We’re in Halbrite. Tanks at a sister company in Oxbow, northeast of here, last a bit longer than ours do,” says Emde.

Overall, in southeastern Saskatchewan, trucking and rail trans-port for oil has grown in the last couple of years, says Ray Frehlick, president of Estevan, Sask.–based Prairie Mud Service. Staging points or terminals for loading oil onto railcars are continuing to sprout in the region, with some existing ones expanding and new ones—like the one at Tribune—being built.

The growth, he says, continues, although “we can’t move oil by truck as cheaply as by pipe.”

In the Lloydminster area, a trend to trucking and rail transport for the region’s heavy crude originates not so much from pipeline capacity issues but, apparently, from hard-headed business calcula-tion. Twin Butte Energy Ltd., an intermediate oil and gas producer based in Calgary, began shipping a percentage of its production last winter. “It’s driven by economics. There’s a better netback by rail than there is by pipe,” says Bob Bowman, vice-president of operations at Twin Butte.

Charges are either less severe, he says, or virtually nil on several fronts—among them, blending, quality adjustments and sulphur content. Railcar restrictions for sulphur are more relaxed compared to pipelines. Factors like these off set the greater per-mile costs associated with hauling oil by railcar. “For every cube of heavy oil, which is typi-cally in the 12- to 16-degree-API range, you have to buy one third of a cube [of diluent] to blend with the crude to meet pipe specs. That’s an extra cost,” Bowman says.

Considerations like these could perhaps wind up breathing much longer life into the current crude oil railcar boom than one might associate with a temporary shortage of sales pipe. As Mike Hillis, a dispatcher at Lloydminster-area Nitro Heavy Hauling Ltd., says, “Rig hauling is slow, but oil hauling is picking up.”

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How important is developing a liquefi ed natural gas (LNG) export market for northeastern B.C. tight gas supplies to the province’s economy?

Just exporting Horn River shale supplies alone could add as much as $161 billion to the province’s gross domestic product (GDP) over the next quarter century, according to a report from the Canadian Energy Research Institute (CERI).

The CERI study is called Pacific Access: Part III—Economic Impacts of Exporting Horn River Natural Gas to Asia as LNG. The study examines the economic results of developing wells in Horn River, transporting the gas to the Kitimat LNG terminal and exporting it to Asia.

CERI projects that if gas demand remains high in Asia and prices remain linked to crude oil markets, Horn River produc-ers could see netbacks as high as $7 per thousand cubic feet on LNG exports.

The report says development of the Horn River Basin to meet output of the Kitimat LNG terminal for the period of 2010-35 will result in a total of 834,000 jobs (person-years) in Canada, of which 768,000 will be based in British Columbia. The GDP will be $161 billion, the majority of which will be in British Columbia at $152 billion.

STRANDEDnortheastern B.C. gas supply continues to grow, but new markets still years awayBy Darrell Stonehouse, with notes from the Daily�Oil�Bulletin staff

Employee compensation in British Columbia will be $39.4 billion, and tax revenues will amount to $36.8 billion.

The construction and operation of the Kitimat LNG terminal will generate 112,000 jobs in Canada, with British Columbia secur-ing 97,000 of those jobs. There will be $7.8 billion in GDP gener-ated, with $6.6 billion based in British Columbia, and $4.6 billion in employee compensation will happen nationally, with $2.2 billion in taxes generated.

The planned Pacifi c Trail Pipeline to take Horn River gas to the coast will generate 31,000 jobs, of which 24,700 jobs will be based in British Columbia, and the GDP will be $2 billion, with $1.5 bil-lion being generated in British Columbia. Employee compensation in British Columbia will be $1 billion, with $471 million in taxes payable.

The Horn River, of course, is just one part of the massive and growing tight gas resource in northeastern British Columbia. Across the board, eff orts are underway to fi nd means to monetize the gas resource. But uncertainty over when new LNG export facil-ities will be built is slowing development.

Just how prolific the tight gas plays are is illustrated by Quicksilver Resources Inc.’s fi rst multi-well pad in the Horn River

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Basin completed this summer. Individual wells on the eight-well drilling pad tested at rates in excess of 20 million cubic feet per day, with the highest at 27 million cubic feet per day, while being con-strained for testing purposes. These wells were drilled with 6,000- to 8,500-foot laterals. The pad is estimated to have the capacity to produce in excess of 150 million cubic feet per day of gas.

Once initial production rates are established, Quicksilver’s cur-rent plan is to restrict the fl ow from the pad to optimize midstream commitments under various agreements, and subsequently to increase production to meet increased throughput commitments as necessary or if natural gas prices improve.

Despite the success of the pad, the company has put drilling on hold in the Horn River for the remainder of the year.

“Quicksilver is aggressively attacking costs and capital expen-ditures in this low-commodity price environment. We have proac-tively amended our credit facility, reduced capital spending and pushed out capital commitments in the Horn River Basin and our other operating areas,” said Glenn Darden, president and chief executive offi cer.

“Our team has been working hard on the downstream part of this project, and we are making good progress on connecting

this large supply of gas with end users,” Darden told a conference call. “We believe that the Horn River is well positioned for the export market.”

Drilling is down slightly in the Montney as companies target liquids-rich areas while looking for ways to monetize dry gas supplies.

Progress Energy Resources Corp. has turned to targeting light oil in the Dunvegan Formation and areas of the Montney with high liquids recovery across its huge land base. Liquids production for the second quarter was almost 7,000 barrels per day, 18 per cent higher than the same period in 2011.

Producers look to monetize Montney gasProgress, which is in the midst of being taken over by Malaysian partner PETRONAS, continues to study the feasibility of exporting LNG to Asian markets. During the second quarter, the LNG export joint venture between Progress and PETRONAS Canada selected a site for the planned facility in Prince Rupert, B.C., at Lelu Island, sub-ject to further feasibility study. The study was expected to be com-pleted by the end of August. Concurrent with the detailed feasibility study on the LNG facility, two major pipeline companies are partici-pating in a detailed feasibility study to develop a pipeline solution

the Pacifi c Ocean at Kitimat. Five LNG projects are planned for the region to take northeastern B.C. gas to asia.

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to deliver gas from lands held in partnership between Progress and PETRONAS to the anticipated LNG facility on the West Coast. The pipeline study was expected to be completed in early September.

Drilling at Talisman Energy Inc. and Sasol Limited’s joint ven-ture lands at Farrell Creek and Cypress in the Montney is under pressure due to low gas prices, higher drilling and completion costs, and high depreciation, Sasol reported in August. The 50/50 partnership has cut the number of rigs active in the play to three, in response to low gas prices.

Talisman has also stepped away from the partnership’s efforts to monetize Montney gas through a gas-to-liquids (GTL) facility. Sasol has decided to continue studying the potential for the facility.

Sasol pioneered GTL technology, which converts natural gas to liquid fuels such as diesel. The petrochemical maker oper-ates commercial-scale GTL plants overseas. GTL may be one way to monetize North American gas reserves amid a continen-tal gas glut.

“The reduction in the number of rigs will not impede the de-risking of the assets that is currently underway. The partnership will still achieve its land-retention objectives. Sasol remains fully aligned with Talisman on its asset development strategy. We

remain committed to economically viable appraisal and production activities and prudent capital spending at both Farrell Creek and Cypress A,” the company said in its global update.

“This is managed in a way that does not jeopardize our gas-to-liquids…ambitions with respect to GTL gas cover requirements,” Sasol added.

While most producers are focused on LNG exports, Sasol says there is room for both technologies.

“I think LNG is an alternative gas monetization technology. But if you take a country like Qatar where they’re quite big in LNG, they also now have two GTL competitors with Sasol and Shell having GTL plants there,” said Nereus Joubert, head of Sasol’s Canadian operations. “The opportunity is so big in western Canada and the U.S. that I think there’s more than enough space for both technologies to be deployed successfully.”

Regarding Sasol’s proposed 48,000-barrel-a-day GTL plant in western Canada, Joubert said, “There are still one or two things we would like to study a little bit in more detail. We will take it through our review and governance processes in the next couple of months and make a decision…before the end of the year whether to proceed to the next phase.”

Joubert said Talisman’s opting out of the potential front-end engi-neering design (FEED) “on its own won’t necessarily result in Sasol not going forward. We certainly have the financial ability to do a project like this on our own. But we still have to make that decision.”

He said Sasol will decide before the end of this year whether to proceed to FEED.

Liard discovery adds to gas glutWhile producers look for ways to turn existing tight gas resources into marketable reserves, they continue adding new supplies.

Early this summer, Apache Corporation reported it had discov-ered a massive new resource in the Liard Basin.

Net estimated sales gas is 48 trillion cubic feet of natural gas (eight billion barrels of oil equivalent) across 430,000 acres held with a 100 per cent working interest. The resource estimate at Liard is based on recent drilling, test results and earlier well con-trol points, the company said.

“The D-34-K well is one of the best shale wells we’ve seen in any play,” said Steven Farris, Apache’s chairman and chief execu-tive officer. “Our analysis indicates that the formation characteris-tics are remarkably consistent across the basin.”

According to the company’s investor day presentation on the D-34-K, the horizontal well had a vertical depth of 12,600 feet, a lateral length of 2,900 feet with six frac stages. The 30-day initial production rate was 21.3 million cubic feet per day, 3.6 million cubic feet per day per frac, and estimated ultimate recovery is 17.9 billion cubic feet.

It’s believed to be the most prolific shale gas resource test in the world, the company stated.

In terms of the commercial outlook for the Liard, infrastruc-ture already exists. All Apache wells are connected to a sales gas pipeline, there’s access to major incremental infrastructure, it’s

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connected to the North American gas market and will have access to Asia Pacifi c via LNG.

“Like all gas prospects, it is challenged by gas prices,” John Bedingfi eld, vice-president of worldwide exploration and new ven-tures, said. “This is, in my view—certainly in my estimation—the best shale gas reservoir in the world, certainly from a performance perspective.”

This was the fi rst time the company has spoken publicly about Liard, he added.

The development model includes pad drilling with 12 wells per pad, 600-metre inter-well spacing, two rigs drilling per pad with 110–120 drill days per well.

“We’re not going to jump into the development on this right away, but it’s a tremendous resource,” Bedingfi eld said. “What we’re doing now here is we’re drilling tenure wells to hold the acreage together.”

“There are competitive issues that western Canadian gas is facing in our traditional markets in the U.S. northeast with the growth of the Marcellus and also Rockies gas,” Edward Kallio, director, gas consulting, with Ziff Energy Group, said. “You’ve got this tremendous productive potential in our basin, in the Horn River play and in the Liard now. But the gas has no place to go. When producers can’t recover those full-cycle costs, when they can’t replace the gas that they’re producing with new gas, they stop drilling. And that’s what we’re seeing.

“It’s imperative that we continue to develop these LNG lique-faction proposals,” Kallio said. “But it takes a long time to get these things permitted and built. We’ve heard about delays on Kitimat LNG to 2017, now.

“Royal Dutch Shell plc is looking at around 2019 at the earliest on their plan, and there could be some slippage there,” he added. “We’re going to be in a painful environment here in western Canada. That Liard/Horn River gas won’t be coming on stream unless and until we build some export [capacity].” Ph

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General News


and propane. Ethane is basically at the point where it is being rejected and left in the gas stream. It’s a combination of supply that has been fairly robust, and you’ve also had a lot of the crackers down for maintenance and expansion,” he said.

“I think that underlying all that is that most liquids plays in western Canada are probably half-ethane and -propane, and those are more of the marginal products out of the whole liquids’ stream. When you look at it, it’s really only condensate that’s strong in Canada.”

Vanderburg said the reality is that the average NGL price is “all over the map,” mostly because diff erent liquids bring in diff erent prices depending on the compo-sition and destination of the liquids. In the fi rst quarter of 2012, of 83 producers that trade in Canada and operate domes-tically and abroad, the average NGL

price ranged from $18.39 per barrel for Antrim Energy Inc. to $112.80 per barrel for Corridor Resources Inc. The median was $63.37.

But Vanderburg added that the NGL volumes for the companies at the extremes of this list are low enough that an increase or decrease in the average price would have a minimal impact on their bottom line.

“The same cannot be said for com-panies w it h high l iquids volumes. Companies with high liquids volumes will be hit to varying degrees depend-ing on the volume and composition

Already weary and apprehensive because of rock-bottom natural gas prices and uncertainty in the crude oil market, western Canadian producers are likely to become even more white-knuckled as a natural gas liquids (NGLs) glut begins to take hold.

Recently the near-term saviour for many companies, the rush to exploit liq-uids during a period of low natural gas prices has created oversupply, not unlike when the service sector overbuilds during a cyclical high only to be hammered when the cycle descends.

Already, oil and gas companies in the United States that have depended on natural gas liquids to lift profits are beginning to rein in spending or sell some assets after the industry drilled its way into a glut of NGLs. And that trend has crept northward over the border where many Canadian companies are now facing the same predicament.

“Natural gas players that rely on natural gas liquids to make ends meet are feeling the pinch. That much is true. What’s equally true, however, is that some

natural gas players are feeling the pinch more than others. Not all natural gas liq-uids are created equal,” noted Geoffrey Vanderburg, managing director with Bryan Mills Iradesso.

“Some of the more theatrical observ-ers have said natural gas liquids are walking off the fracking cliff with natural gas. They believe the success of fractur-ing in liquids-rich shale gas plays has not only reduced the price of natural gas, it has also pushed down the price of natu-ral gas liquids to the point where they’re no longer propping up natural gas to the point of profi tability.”

Chris Theal, president and chief executive officer of Kootenay Capital Management Corp., said that with the exception of condensate, other liquids stripped from the natural gas stream con-tinue to lose value.

He said that on average, NGLs were priced at about 55 per cent of West Texas Intermediate last year, while in recent months it has been more in the 37 per cent range.

“I think where you’re really seeing it is with the lighter liquids—ethane

the ethane that drives the petrochemical industry is quickly reaching saturation point, driving down prices for already embatt led natural gas producers.

Phot

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Liquids glut taking shape in western CanadaBy paul Wells

“��Ethane�is�basically�at�the�point�where�it�is�being�rejected�and�left� �in�the�gas�stream.�It’s�a��combination�of�supply�that�has�been�fairly�robust,�and�you’ve�also�had�a�lot�of�the�crackers�down�for�maintenance�and�expansion.”— Chris Theal, president and chief executive

offi cer, Kootenay Capital Management Corp.

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General News

Twenty-four of the 100 exploration and production companies tracked by the Daily Oil Bulletin have reduced their 2012 capital plans from original budgets, while 16 have announced increases.

Overall, spending for the 100 companies is now anticipated at $59.26 billion com-pared to $59.7 billion initially announced, a diff erence of about $435 million.

The largest cuts came from two of Canada’s larger entities. Leading the way so far is Canadian Natural Resources Limited, which has cut capital expendi-tures by $680 million to $6.52 billion from $7.2 billion.

During a recent conference call, the company said that targeted capital expenditures for 2012 are being reallo-cated from natural gas to higher-return primary heav y crude oil projects in response to the uncertain outlook on commodity prices. Capital allocation reductions were primarily in the areas of Horizon oilsands expansion and North American natural gas.

“Canadian Natural’s ability to quickly and eff ectively reallocate capital and at the same time increase production confi rms the strength of Canadian Natural’s assets, our capital fl exibility, the eff ectiveness of

our strategies and the ability of our teams to effectively execute,” said Steve Laut, president.

Talisman Energy Inc. was second on the list after axing $400 million from its cap-ital budget this year. In January, Talisman projected capital spending of just over $4 billion, a drop of roughly $500 million from 2011. The company now expects to spend $3.6 billion on this year’s exploration and development program.

“I see no reason to continue spending money in dry gas shales when it doesn’t remunerate,” Talisman president and chief executive officer John Manzoni told the

Producers report slight drop in expenditures

of their liquids,” he said. “Condensate prices have been hovering around West Texas Intermediate oil prices while propane and ethane have been trading much lower.”

Although they are sure to feel the hurt, Vanderburg said western Canadian

producers have an advantage over their U.S. brethren courtesy of the oilsands.

“In addition to the composition of the NGLs, liquids producers in Canada can be expected to do better than their U.S. counterparts because of the higher demand for diluents in Canada. Oilsands

producers use condensate as diluent to cut the viscosity of bitumen,” he said.

“It is a key input for dilbit and synbit and there continues to be demand for that prod-uct. As a result, condensate and butane have been trading at a 20 per cent to 30 per cent premium in Canada versus the U.S.”

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General News

company’s first-quarter earnings confer-ence call in May.

In l ight of the persistent weak-ness in North American natural gas prices, Progress Energy Resources Corp. announced in early May that it would chop 2012 capital spending by roughly $100 million to a total of $270 million net. (The company had earlier reduced spend-ing to $365 million from the original 2012 budget of $465 million.)

Other companies with relatively large reductions in planned 2012 capital spend-ing include ARC Resources Ltd., which cut spending by $160 million to $600 mil-lion and Penn West Petroleum Ltd., which lopped off $125 million and now plans to spend $1.53 billion (gross) from an initial budget of $1.65 billion.

During the company’s second-quarter conference call, Penn West’s president and chief executive officer, Murray Nunns, said

the current industry climate made the cuts necessary.

“Export access from Canada and increased access to U.S. refining is nec-essary for western Canadian produc-ers to fully realize the potential value of Canadian oil,” Nunns said. “Taking into consideration the impact of ongoing dif-ferential volatility and the hydrocarbon pricing on our price realization, we have adjusted our capital plans accordingly for the remainder of 2012.”

Many gas-weighted juniors have also downgraded spending plans—and for obvious reasons, given lingering low natu-ral gas prices.

But the situation isn’t all dire—of the 100 companies, 16 have bucked the trend and increased spending this year.

On top of t hat l i st i s E nca na Corporation, which upped its budget by $600 million to US$3.5 billion; MEG Energy Corp., which increased its origi-nal budget by $380 million to $1.75 bil-lion; and PetroBakken Energy Ltd., which added an additional $175 million and will now spend $875 million compared to its original budget of $700 million.

— DailY oil BulleTinPhot

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Capital expenditures are down about $435 million for the top 100 oil companies tracked by the Daily OIl Bulletin.

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General News

Operators across Canada have r ig released 5,912 wells over the first seven months of 2012, off almost eight per cent from 6,416 wells drilled during January–July of 2011.

Of the wells drilled across Canada to the end of July, 798 stil l have no final status (oil, gas, dry or service). Of

those with a status designation, 3,902 (about 66 per cent) were reported as an oil well and only 11 per cent were listed as a gas well.

This year’s seven-month rig release count for oil wells is off slightly from 4,156 rig releases in the comparable period last year.

While the number of rig releases declined year-over-year to the end of July, total metres drilled lifted to 12.03 million

metres from 11.45 million metres in the fi rst seven months of 2011.

Alberta saw a close to 11 per cent decline in rig releases to 3,705 to the end of July, off from 4,156 in the comparable period last year, although metres drilled lifted to 7.86 million metres from 7.23 mil-lion metres.

In Saskatchewan, a total of 1,598 wells were rig released in the January–July period compared to 1,642 a year ago (off just three per cent). Total metres drilled increased to 2.52 million metres from 2.48 million metres.

Saskatchewan’s r ig release total included 179 outpost holes versus 119 in Alberta. Meanwhile, operators in Alberta drilled 120 new pool wildcats compared to 52 in Saskatchewan.

The rig release tally in British Columbia declined 27 per cent in the fi rst seven months of the year to 275 from 377 a year ago. Metres drilled also decreased, to 1.04 million metres from 1.31 million metres.

Manitoba was the only western province to see an increase in its rig release count. Over the seven-month period, a total of 319 wells have been rig released, up close to 48 per cent from 216 a year ago. Operators in the province have drilled 593,837 metres to the end of July compared to 392,214 metres in last year’s period.

Operators rig released 932 wells in July, down 10.9 per cent from 1,046 wells a year ago. Alberta operators drilled 559 wells, off 10 per cent from 622 rig releases in July 2011, while Saskatchewan opera-tors drilled 271 wells compared to 350 a year ago (off close to 23 per cent).

B.C. operators dr i l led 24 wells last month versus 49 in July 2011 and Manitoba operators rig released 76 wells, up 280 per cent from 20 wells rig released a year ago.

— DailY oil BulleTin

Fewer wells, more metres drilled in first seven months

Manitoba�was�the�only�western�province�to�see�an�increase�in�its�rig�release�count.�Over�the�seven-month�period,�a�total�of�319�wells�have�been�rig�released,�up�close�to�48�per�cent�from�216�a�year�ago.

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British Columbia

BRITISH COLUMBIA WELL ACTIVITY

aug/11 aug/12

WeLL LICeNCeS 128 58 ▼

aug/11 aug/12

WeLLS SPuDDeD 55 4 ▼

aug/11 aug/12

WeLLS DrILLeD 48 37 ▼

Source: Daily Oil Bulletin

Shell's Scotford refi nery. David Black is fl oating plans for a similar refi nery capable of processing 550,000 barrels per day of bitumen on the B.C. coast.

Phot

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in terms of jobs as well as government revenues,” Stringham added. “Refi neries, however, compete in a very competi-tive marketplace. Any such project has to attract commercial interest and investors to succeed, and ultimately, commercial interests should decide on the economic viability of the proposal.”

Enbridge spokesman Graham White said Black has shared some details of his proposal with the company.

“Our focus remains on the regulatory process reviewing our application for Northern Gateway,” he said. “Enbridge Northern Gateway remains committed to the regulatory process reviewing our application for the project. The formal hearings, as part of the Joint Review Panel process, are set to begin September 4 where issues related to the project are to be reviewed in public and in detail.”

Black’s proposed refinery will be located at the 3,000-hectare Dubose location, which is 25 kilometres north of Kitimat and 25 kilometres south of Terrace, B.C. The Dubose site is Crown-land zoned for industrial use. The Enbridge pipelines are planned to run through the property.

The refi ned fuels will be piped 40 kilo-metres south of the Dubose property to a marine terminal site on the Douglas Channel. Enbridge currently plans to use this site as its proposed crude oil shipping terminal.

Petroleum coke and sulphur by-products will be loaded onto ships at Kitimat if a bulk marine terminal is avail-able or shipped by rail to Ridley Island at Prince Rupert, B.C., for loading.

A natural gas cogeneration facility will be built at the Dubose site, which will provide steam and electric power for the refi nery.

In prepared remarks, Black said that this proposed Kitimat refi nery will feature four key advantages for British Columbia and Canada. First, the refi nery removes

Newspaper publisher David Black is hoping to construct a $13-billion refinery near Kitimat, B.C., which would have the capacity to process all of the output of the planned Enbridge Inc. Northern Gateway pipeline.

While it’s still early in the process for some analysts to evaluate it, an industry representative said that commercial inter-ests should decide on the economic viabil-ity of the proposal.

Black, owner of newspaper chain Black Press Ltd., said his company Kitimat Clean Ltd. is submitting an environmental assessment application to build a world-scale oil refi nery at Kitimat.

The refinery will be state-of-the-art and designed specifi cally for processing oilsands heavy crude oil. The plant will process up to 550,000 barrels per day of dilbit. The diluent will be separated and returned to Edmonton via the proposed Enbridge secondary pipeline.

The plant will produce 240,000 barrels per day of diesel, 100,000 barrels per day of gasoline and 50,000 barrels per day of kerosene, or aviation fuel. It’s hoped that construction will begin in 2014 and be fi n-ished by 2020.

Greg Stringham, vice-president of markets and oilsands with the Canadian Association of Petroleum Producers, noted that access to new markets is crucial to the success of the country’s oil and natural gas industry.

“Market opportunities for producers extend from eastern Canada to the U.S. Gulf Coast to the West Coast,” he said. “Broadly speaking, the recent refi nery proposal is an example of the several types of potential opportunities that are being evaluated in the context of West Coast oil exports.

“The goal is safe and responsible market access while delivering benefi ts to British Columbia and Canadians, benefi ts

Proposed Kitimat oil refinery must make economic sense, says industryBy richard Macedo

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British Columbia

the threat of offshore pollution from a heavy crude oil spill.

“Transportation of refined fuels is much safer. Gasoline, kerosene and diesel all evaporate. No extensive remediation would be required if there ever were an accident,” he stated. “Second, a refinery creates a great many construction jobs. Roughly 6,000 workers will be hired for five years.”

In terms of permanent jobs, Black said the proposal will employ approximately 3,000 full-time workers, half of them via private contractors.

“These primary jobs will likely result in several thousand additional secondary jobs,” he added. “All of these jobs will be based in an area of the province that has experienced a considerable decrease in per-manent employment over the past 10 years.”

Also, he said, the province would ben-efit from new tax revenues.

The refined products produced by this refinery will be marketed throughout the Pacific Rim. A key opportunity is to market to China.

Overall operating costs will be com-parable to or less than those of refineries in China, Taiwan, Korea, Japan and most other countries, Black said, adding that Kitimat employee and contractor wages of $300 million per year will be higher than those in some of these countries. But this economic disadvantage would be offset by North American natural gas costs, which are much lower than in Asia. In addition, shipping costs across the Pacific for refined fuels will be 30 per cent lower than for crude oil because no diluent has to be shipped out or shipped back.

Black added that the concept has been worked on for nearly a year, and various levels of government have been briefed.

“We hope that the citizens of Kitimat and Terrace, the Haisla, the Kitselas and all other local communities along the coast will agree to the proposal after a full and complete review,” he stated. “We think the refinery is the best solution to a main concern of most of these communi-ties—a possible catastrophic disaster at sea from a heavy crude oil spill.

“We think that the general population of B.C. would be in favour of the Northern Gateway pipeline if it can be built safely and if a refinery is built.

“We have discussed the opportunity at length with Enbridge and with many of the oilsands producers. Some part-ners in the Gateway pipeline are not in favour of a Kitimat refinery at this time. They remain hopeful they will be allowed to export heavy crude by tanker from Kitimat.”

“�Transportation�of�refined�fuels�is�much�safer.�Gasoline,�kerosene�and�diesel�all�evaporate.�No�extensive�remediation�would�be�required�if�there�ever�were�an�accident.”

— David Black, owner, Kitimat Clean Ltd. and Black Press Ltd.

The Dreaded CRA Tax Audit:tax tips for the self-employed

*Visit www.�ghtthecra.ca/free-consultation for details

Does the CRA target small business owners and the self-employed?The CRA focuses on those groups who are more likely to omit ormisrepresent information on their tax returns, one of whom is,according to the CRA, the self-employed.

Is there anything I can do to avoid a tax audit?

1. File on time! Nothing places a red flag faster than a late taxreturn, so get your return in by the deadline. The same holdstrue for filing too early.

The following strategies can be used to reduce the number of redflags that may come up with your file, thereby reducing the likelihood of an audit:

2. Be honest and consistent. The CRA has tools to investigate and gather information about your industry. If your numbers don’t fit the typical profile, then chances are you will be audited. Also, major changes in income, expenses or tax deductions from one year to the next will raise suspicion.

3. Avoid declaring business losses year after year. A reasonable amount of losses is fine; however, continuous business losses over a few consecutive years will alert the CRA.

4. Select your partners wisely. Any close association you make with other businesses or individuals who had or currently have problems with the CRA may result in a tax audit.

I am being audited. What can I do to lessen the potential blow?1. Consult a tax lawyer. Yes, a tax lawyer is advising you to consult a lawyer. Nevertheless, the key to being audited without your tax bill doubling is to ensure the audit is conducted fairly - without intimidation. This is best achieved with the representation of a tax lawyer, who is trained to know the law and the CRA’s internal policies and, unlike other tax professionals, is trained to fight for your rights.2. Be nice. No one likes being audited, but taking it out on the auditor will get you nowhere.3. Be on guard. Avoid getting chatty and volunteering more information than necessary that can later be used against you.4. Be organized. It may be tempting to dump a box full of financial records onto the auditor’s lap, this will only serve to motivate the agent to work harder to find omissions and mistakes in your return. Keeping your records organized will, at the very least, lend credibility to you as a responsible businessperson.5. Inform yourself. Knowing your rights will help you be better prepared when facing an audit. The CRA publishes the Taxpayer’s Bill of Rights, and although some of these rights are not technically legal rights, it is still useful to know the principles behind which the CRA hopes to conduct their tax audits. i


British Columbia

While Alberta will cash in the most on upstream oilsands development result-ing from new projects spurred by addi-tional pipeline capacity to export markets, British Columbia stands to be the largest beneficiary of the actual construction and operation of the lines, said a report released in July.

“While rail is emerging as a serious option to pipeline transportation, the former is subject at the present time to limited availability of rolling stock and storage capacity. The least-cost way to move oilsands output to East Asian mar-kets is by pipeline to Pacific port and super-tanker across the Pacific Ocean,” Canadian Energy Research Institute (CERI) said in its report Pacific Access: Part II—Asia-Directed Oil Pathways and Their Economic Impacts.

“The lion’s share of economic impacts from pipeline construction and operation would occur in the provinces of British Columbia and Alberta, where the pipelines would be located. Of the other provinces,

Ontario and Saskatchewan would experi-ence the greatest economic impacts.”

The study, the second in a series of three, examined alternative trans-portation modes and markets. CERI’s Regional Input-Output model is intro-duced in the study and used to calcu-late the potential economic impacts of construction and operation of two major proposed crude pipeline projects in western Canada: the Trans Mountain Pipeline Expansion (TM X) and the Northern Gateway Pipeline.

According to CERI, construction and operation of Enbridge Inc.’s Northern Gateway pipeline to Kitimat, B.C., will bring more than $8.9 billion in total addi-tional gross domestic product (GDP) to the Canadian economy over the next 25 years—$4.7 billion of that amount will go to British Columbia, $2.9 billion to Alberta and $608 million to Ontario.

Of all regions in British Columbia, Nechako, closely followed by the North Coast, will see the most direct GDP benefi t

from Northern Gateway construction and operation—Nechako earning $655 million over the next 25 years, the North Coast earning $575 million.

In Alberta, the Upper Peace regions will see the most direct GDP benefi t from Northern Gateway construction and operation—$502 million over the next 25 years.

Employment in Canada (direct, indi-rect and induced) is expected to ramp up to 30,000 jobs at the peak of construction and settle down to 2,500 jobs during the operation phase.

Northern Gateway will generate over $2.3 billion in tax revenues over the 25-year period, with $1.45 billion going to the federal government, $545 million to provincial and regional governments in British Columbia, $162 million to pro-vincial and municipal governments in Alberta, and $83 million to provincial and municipal governments in Ontario.

Additionally, construction and opera-tion of Kinder Morgan Canada’s TMX

B.C. would gain most from oilsands pipelines, says report


British Columbia

pipeline will bring more than $8 billion in total additional GDP to the Canadian economy over the next 25 years—$4.4 billion of that amount will go to British Columbia, $2.4 billion to Alberta and $523 million to Ontario.

Of all regions in British Columbia, the Thompson/Okanagan area will see the most direct GDP benefi t from TMX construction

and operation, with $980 million over the next 25 years.

In Alberta, the Upper Athabasca will see the most direct GDP benefi t from TMX con-struction and operation at over $500 million during the next 25 years.

CERI noted that employment in Canada (direct, indirect and induced) is expected to ramp up to 35,000 jobs at the peak of

construction and settle down to 2,500 jobs during the operation phase.

Aside from the associated economic ben-efi ts of the proposed pipelines, CERI noted that a “pipeline to tidewater on the Pacifi c Coast is the most economic way of reaching Asian refi neries, which are capable of accept-ing both bitumen and synthetic crude oil.”


B.C. report links fracturing to tiny earthquakes in northeastA BC Oil and Gas Commission report shows that seismicity observed in the Horn River Basin study area was induced by fault movement resulting from the injec-tion of fl uids during hydraulic fracturing.

The commission initiated the inves-tigation after anomalous seismic activ-ity was recorded in a remote area of the Horn River Basin between April 2009 and December 2011. The report concluded that all events occurred during or between hydraulic fracturing stage operations.

“Dense array data accurately placed the depth and location of events at or near hydraulic fracturing stages. Only one event was reported as ‘felt,’ and no events were felt beyond 10 kilometres of the epi-centres,” the report said.

“The investigation determined that movement associated with the events was confi ned to the targeted gas-bearing shales. No injuries or property damage were reported as a result of the induced seismicity, and only one event was reported by Natural Resources Canada (NRCan) to have been felt at the surface.”

Since 2009, there have been 31 earth-quakes in the Etsho area of the Horn River Basin, an increasingly active natural gas extraction area. The earthquakes ranged in size from 2.2 to 3.8 on the Richter scale, which typically means they can be felt but rarely cause damage. Before 2009, the area had not experienced any recorded earthquake activity.

In undertaking the investigation, the commission noted that more than 8,000 high-volume hydraulic fracturing comple-tions have been performed in northeast-ern British Columbia with no associated anomalous seismicity.

Brad Hayes, president of Petrel Robertson Consulting Ltd., said the report is a “scientifi cally rigorous and complete report” that investigated a number of seis-mic events that occurred in the Horn River Basin and detected by a Natural Resources Canada regional seismic/earthquake-monitoring network.

“The events were of very low magni-tude, such that only one was reported as being felt at surface by crews in the bush nearby. No damage or risk to the public was assessed,” he said.

“The study conclusively linked these seismic events to hydraulic fracturing activities in horizontal wellbores drilled to develop shale gas in the Horn River Basin. Hydraulic fracturing, by its nature, induces fractures, and therefore very small-scale deformations, into the target shale reservoir.”

Hayes noted that intensive monitor-ing of the hydraulic fracturing operations showed almost all the energy and defor-mation to be confi ned to the target shale, more than 2,000 metres below the surface.

“However, it appears that some of the fracturing operations caused limited movement on pre-existing natural faults in the shales and thus triggered the recorded seismic events. The study concluded that injection of water into the Debolt aquifer at much shallower depths was not related to the seismic events,” Hayes said.

While no damage or public risk was assessed as a result of the seismic events, Hayes said the commission makes several recommendations to improve detection and characterization of future events. With such information, the province of British Columbia can ensure that appropriate regulations are in

place to adequately monitor such events and to mitigate any potential issues.

“This report is an excellent example of the scientifi cally sound and proactive stance taken by Canadian regulators, such as the BC Oil and Gas Commission, to ensure the safe and eff ective operation of unconventional hydrocarbon resource development in our country,” Hayes said.

In the report, the commission makes seven recommendations based on the investigation, which include the submis-sion of micro-seismic reports, establish-ment of a notification and consultation procedure, studying the relationship of hydraulic fracturing parameters on seis-micity, and upgrading and improving British Columbia’s seismograph grid and monitoring procedures.

“Improvements to the seismographic grid network have already begun through funding provided by Geoscience B.C. The upgraded grid will provide improved monitoring for induced seismicity and will form the basis for the monitoring, detec-tion, notifi cation and consultation proce-dure,” the commission said in its report.

In addition, the commission said it has initiated a broader study with the University of British Columbia to examine factors related to the extent, magnitude, impact and control of induced seismicity in northeastern British Columbia.

“The intent of this research is to pro-vide insights into predicting the location and magnitude of seismic events based on hydraulic fracturing parameters and geomechanics, and to establish protocols for prediction, detection, monitoring and mitigation of these events,” it said.


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Successful winter drilling has resulted in a 27 per cent increase in production for Birchcliff energy.

Birchcliff production continues to climb

aug/11 aug/12


aug/11 aug/12


aug/11 aug/12



Tonken said. “The PCS gas plant will pro-cess our Montney/Doig natural gas for more than 30 years, and once the Phase 3 expansion is operating, we will be able to process a significant amount of incremen-tal natural gas without incurring further material facilities capital.”

Second-quarter 2012 earnings were $416,000 as compared to $10.12 million for the same period last year.

“Even with the AECO natural gas spot price averaging $1.89 per mcf [thousand cubic feet] for the second quarter of 2012, we were able to show positive earnings, highlighting our low-cost structure,” Tonken said.

Year-to-date net income decreased to $4.15 million from $19.71 million during the first half of 2011.

Birchcl i f f generated f unds f low from operations in the second quar-ter of $25.99 million as compared to $34.27 million during the same period in 2011.

The company says the decrease is mainly attributed to significantly lower natural gas prices, with the AECO nat-ural gas spot price having decreased 51 per cent from the second quarter of 2011. Funds f low was also negatively impacted by lower realized oil wellhead prices, positively offset by higher aver-age daily production, lower net general and administrative expenses, decreased interest expense and royalty expense.

Drilling activities during the second quarter of 2012 resulted in nine (nine net) wells, of which all were successful. The company also spent significant time and effort on evaluating and developing new resource plays in the Peace River Arch area of Alberta, with a focus on oil plays.

In the second quarter of 2012, Birchcliff’s activities on the Montney/Doig natural gas resource play included the drilling of eight (eight net) horizontal

Birchcliff Energy Ltd. reported record production during the second quarter, averaging 22,039 barrels of oil equiva-lent per day, a 27 per cent increase from second-quarter 2011 volumes of 17,324 barrels per day.

“In the second quarter, we achieved record production levels for Birchcliff as our past infrastructure and development investments in t he Montney/Doig natural gas resource play con-tinue to pay off,” president and chief executive officer Jeffery Tonken said in a statement. “Birchcliff continues to focus on reducing its operating costs to meet our goal of being one of the lowest-cost producers in the industry. Complementing that, Birchcli f f has and continues to have top decile find-ing and development costs. We believe that, ultimately, the lowest-cost pro-ducer who has a significant, low-cost

inventor y of repeatable natural gas opportunities will create signif icant value for its shareholders.”

First-half 2012 output increased to 21,550 barrels equivalent per day from 17,532 barrels per day. Total company production is expected to be approxi-mately 26,000 barrels equivalent per day at the end of 2012. The company anticipates that by the end of 2012, the Pouce Coupe South (PCS) gas plant will have throughput of approximately 100 million cubic feet per day out of a total capacity of 150 million cubic feet per day. Therefore, there is expected to be approximately 50 million cubic feet per day of processing capacity available to Birchcliff for future production growth.

“The PCS gas plant is the cornerstone of our strategy to control and expand our production and further reduce our operat-ing costs per [barrels of oil equivalent],”


Northwestern Alberta/Foothills

wells using multistage fracture stimula-tion techniques.

To date in 2012, the company has drilled and cased 19 (19 net) horizontal wells, of which 12 (12 net) wells have been completed, and eight (eight net) are on production—two (two net) of these wells are Middle/Lower Montney exploration wells that continue to expand this play trend. Birchcliff also drilled and cased one (one net) vertical exploration well.

Birchcliff had two rigs drilling con-tinuously through breakup on separate multi-well pads. Seven wells were drilled on one pad and four wells were drilled on the second pad.

“We are currently preparing to com-mence the completion operations on the seven-well pad,” Tonken said.

Birchcliff believes that it has approxi-mately 1,850 net future Montney/Doig hori-zontal natural gas drilling locations on its

lands based on a development scenario of four wells per section per stratigraphic play.

Birchcliff says it has been success-ful in acquiring further lands since June 30, 2012. As a result, its undeveloped land position has increased to 568,995 (531,454 net) acres from its June 30, 2012, undeveloped land position of 552,355 (514,814 net) acres, resulting in a 93 per cent average working interest.


Celtic exploration drilling pays offBy paul Wells

Celtic Exploration Ltd.’s production during the second quarter averaged 19,406 bar-rels of oil equivalent per day, an increase of 28 per cent from 15,203 barrels per day in the second quarter of 2011.

The company noted that the K3 gas plant, through which Celtic produces approximately 4,000 barrels of oil equiv-alent per day of production, was offl ine for approximately six weeks commencing in the latter part of May for planned turn-around maintenance operations, which negatively aff ected second-quarter 2012 average production.

The company estimates that it cur-rently has approximately 8,000 barrels of oil equivalent per day of production behind pipe from wells that have been drilled and are awaiting tie-in. Celtic expects the majority of these behind-pipe volumes to be brought on stream late in the third quarter of 2012.

During the quarter, Celtic drilled eight (5.8 net) wells with an overall net success rate of 100 per cent.

In the southern part of the greater Resthaven, Alta., area, Celtic drilled and cored a vertical well located near Smoky at 13-28-58-01W6 in the fi rst quarter of 2012.

And president and chief executive offi -cer David Wilson and his team were pleased, if not surprised, at what they found.

“We hit what they call a Coquina zone in our Smoky well. We think it ’s quite significant, as these types of zones can be extremely productive,” he said during the company’s second-quarter conference call.

“It was not something we were expect-ing in the area where we’re drilling…but as we look around there, we feel we can map it over the better part of a township. So it’s pretty signifi cant, as we’re talking extremely high porosity.”

Upon evaluation of the core samples, the well has encountered a Coquina rock interval, with porosity of up to 19 per cent and permeability of 205 millidarcies.

“To put that in perspective, that’s about 2,000 times higher porosity than the type of reservoir we’re used to seeing out there,” Wilson said.

Celtic believes that wells with these characteristics will likely be highly pro-ductive. As a result, Wilson said the com-pany plans to re-enter the wellbore and drill it horizontally as soon as freeze-up, in December 2012.

“Depending on the results, we might change our program and start doing quite a few operations down in that area,” he said.

At Kaybob, the company contin-ued its delineation of the Devonian Duvernay play by drilling three (2.5 net) wells. All three wells were cased and rig released prior to June 30, 2012. However, Wilson said completion activity on the wells has been held up due to the extremely wet conditions in the Kaybob area, with the first of the three wells expected to begin completion operations by mid-August.

A Duvernay well located at 04-11-60-20W5 (33.3 per cent working interest) that was drilled during the first quarter

Celtic has 8,000 barrels of oil equivalent behind pipe awaiting tie-in to processing facilities.

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of 2012 was completed in July; however, operations had to be shut down due to wet weather conditions. A production test is expected to start after the frac-ture string is pulled and production tubing has been installed, as soon as weather permits.

At Inga, in British Columbia, the company participated in the drilling of two (0.8 net) wells. One well has been completed and is on production and the second well is currently being completed. Celtic continues to remain encouraged by the results at Inga.

At Resthaven, Celtic drilled three (2.5 net) wells all in the northern area, which has higher liquid yields. These wells have not been completed to date, once again due to wet weather conditions. However, the company has commenced completion operations on two of the three wells.

In the Kaybob-Fir area, the company has commenced its Dunvegan light oil drilling program and has cased one well that is currently awaiting completion. A second well is currently drilling in the horizontal lateral section. A third well was suspended after running surface casing due to wet weather and poor road conditions; however, drilling operations have now re-commenced.

At K arr, A lta., nor th of Celt ic ’s Resthaven land block, the company had previously tested a vertical well located at 10-21-65-03W6 (100 per cent work-ing interest).

The well was swabbed and f lowed for 122 hours and during the last 48 hours of the test, the well was producing 36.5-degree-API oil at a rate of 257 bar-rels per day and associated gas at a rate of 679,000 cubic feet per day, at a fl ow-ing wellhead pressure of 690 kilopascals (100 pounds per square inch).

Based on public information, this is the highest Montney oil rate tested from a vertical well in the near vicinity, and Celtic believes that it has discovered a new Montney oil pool. As a result, the company has recently acquired an addi-tional nine sections of land on the play and is currently drilling a horizontal leg out of the original wellbore.

Celtic re-confi rmed its exit 2012 pro-duction guidance of 29,900 barrels of oil equivalent per day. In addition, the com-pany’s 2012 net capital expenditure pro-gram remains at $322 million.




Delphi cautious on gas price, but keeps drillingBy richard Macedo

Delphi Energy Corp. remains cautious on natural gas pricing for the remainder of the year as the demand for power to meet cooling requirements dissipates as summer comes to an end.

Consequently, the company has been increasing its natural gas hedges for the remainder of the year and is now approxi-mately 66 per cent hedged at an average fl oor price of $2.94 per thousand cubic feet.

Production during the second quarter of 2012 averaged 8,636 barrels of oil equivalent per day, a three per cent decrease from the comparative quarter of 2011 and a decrease of four per cent from the fi rst quarter of 2012. The slight decrease in production compared to the fi rst quarter was attributed to produc-tion downtime associated with scheduled maintenance at SemCAMS’ K3 sour natural gas processing facility and scheduled main-tenance of the Dow Fort Saskatchewan ethylene production facility affecting the company’s liquid sales at Wapiti, Alta.

The company estimates the total impact of the downtimes incurred in the second quarter was an average of approximately 450 barrels per day (55 per cent liquids). Delphi reported a net loss in the second quarter of $3.53 million compared to net income of $5.76 million during the same period last year.

Capital spending during the second quarter was $11.39 million, which primar-ily included the drilling of one (one net) well and completion of the construction

of the 100 per cent owned Bigstone East Montney facility and gathering system. For the six months ended June 30, Delphi’s net capital expenditures were $53.1 million. Of the capital invested, 33 per cent related to the construction of the Montney facility and 65 per cent was directed towards drilling for new production and reserves.

Delphi continues to evaluate its options to monetize a portion of the new Montney facility in conjunction with its feasibility

study to integrate this new facility with its ownership in the existing 80 million cubic feet per day of sweet natural gas processing facility at Bigstone to create a Montney pro-cessing facility that off ers the lowest possible cost structure and best natural gas liquids recovery effi ciencies for the company.

At Bigstone East, the 30-million-cubic-foot-per-day compression and dehydra-tion facility was completed with start-up in mid-May. The new facility and infra-structure provide Delphi with the cap-acity to develop the existing Bigstone East land base and generate processing reve-nue from excess capacity. The facility has been designed to be readily expanded in

15-million-cubic-foot-per-day increments to handle increased company and third-party volumes.

Subsequent to the end of the quarter, Delphi successfully completed its third Montney well (100 per cent working interest) with a surface location of 05-14-60-23W5 involving a 20-stage, oil-based fracturing program. This is the second well from this surface location, but this well’s extended-reach horizontal lateral was drilled to the north versus the south.

The well has been brought on produc-tion through the company’s 100 per cent owned compression and dehydration facil-ity. Subsequent to completion and fractur-ing operations, the well was fl ow tested at an average rate of 16 million cubic feet per day at a flowing pressure of 6,170 kilopascals over the fi nal 24 hours of the initial four-day flow period. The well was also producing approximately 800 barrels per day of free condensate at the end of the test, although 100 per cent of the load fl uid hadn’t been recovered. (Load oil recovery stands at 72 per cent after the four-day fl ow period.)

Delphi’s three extended-reach hori-zontal wells and existing vertical well tests have effi ciently evaluated eight sections of land, and with competitor drilling activity all around the company’s 18 (14.75 net) sec-tions, the remaining 30 net Montney hori-zontal locations identifi ed at Bigstone East have been largely de-risked.


Cold production to begin at Dawson, says PetrobankPetrobank Energy and Resources Ltd. has received regulatory approval to start the cold production phase on a two-well dem-onstration project at Dawson to condition the reservoir prior to initiating proprietary toe to heel air injection (THAI) produc-tion, for which it already has approval.

It expects to begin conventional cold production from horizontal wells in the Bluesky formation in the third quarter of this year, with the THAI demonstra-tion beginning in 2013, Chris Bloomer, chief operating officer, heavy oil, said

in a conference call to discuss second-quarter results.

“We believe that placing the two hori-zontal wells on cold production and pro-ducing conventional heavy oil will create a broader drawdown area along the horizon-tal well and is a potential for signifi cantly faster start-up and ramp-up under THAI toe to heel air injection,” he said.

Dawson is a diff erent type of reservoir than Petrobank’s Kerrobert, Sask., THAI operations in that it has no bottom water, which would enable it to pull on the wells

harder in a cold-production scenario with-out worrying about water influx from below, said Bloomer. The company decided to take the opportunity to do that and get more of the well involved in production earlier on, conditioning the reservoir ahead of the combustion front, providing much faster development of the combustion front and drainage over a longer portion of the horizontal well, which would mean a more rapid start-up and production, he said.

“It is an option for us to do that and the learnings from that will help us to

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At Kerrobert, THAI production con-tinues to ramp up with fi eld estimates for August production averaging more than 400 barrels of oil per day as of mid-month compared to 280 barrels a day in July, as the company continues air injection to build out the THAI combustion front, said the com-pany in reporting second-quarter results.

Production of about 1,000 barrels per day is needed for the company to break even, said Bloomer.

Petrobank has moved towards a bal-anced approach at Kerrobert, spreading the air injection across the whole fi eld, gener-ating a consistent burn on the combustion front, minimizing the drawdown and the opportunity for the breakthrough of combus-tion gas into the production wells, said John Wright, president and chief executive offi cer.

“We have been very careful and very cautious in this process and we are starting to see what we consider very good results,” he said. “The single greatest measure of the efficacy of the THAI process…is the fact we are seeing consistently upgraded crude produced across the field.” The average sales oil quality is consistently upgraded at 14 degrees API compared to the native average of 10 degrees API, according to Bloomer. The single biggest event has been that the combustion front is starting to act like a much more elastic, homogeneous burn front, analysts heard. “It’s starting to join together and link up,” said Wright. “It’s not a series of individual points.”

This is the stage at which Petrobank is looking at ramping up air injection and withdrawal rates and starting to fully implement the THAI process, he said. “There’s no question we have taken it slowly; we’ve perhaps been overcautious, but we have some history with our pilots of creating point breakthroughs and very high fl ow rates, which is what these wells are capable of, but not necessarily creating a full reservoir application of the combus-tion front that allows for the best recovery and the best sweep of the fi re front itself.”

At present, the company is injecting air at only eight per cent of full fi eld design, so “we’ve got a lot of room to run here,” said Wright, while declining to predict when it will see major production growth. “We’ve got to let the reservoir tell us what it can take and at what rate. The per-well design is for about 85,000 cubic metres of air injec-tion per day.”


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thirteen oilsands companies are affected by the province's new land-use plan.

Land-use plan will cancel oilsands leasesBy lynda Harrison

the Mines and Minerals Act legislation to determine the amount of compensa-tion owed.

The province has been consulting with industry throughout, so none of this is a surprise to the affected companies, the conference call heard.

LARP, three years in the making, is set for implementation September 1.

McQueen said that the last period of “hyper growth” in the province demon-strated the need for orderly, long-term land-use planning, and in this new era of growth the need to plan for the area that contains Alberta’s main economic driver is abundantly clear.

She said seven out of 10 Albertans who consulted on the draft LARP supported the plan’s strategic direction.

LARP includes plans, called manage-ment frameworks, for air quality, surface-water quality and groundwater in an effort to manage cumulative effects in the region.

These frameworks outline monitoring, evaluation and reporting requirements, set early warning triggers to determine the need for action and identify what actions may be taken.

The government has identified 38 parameters it will monitor and track for surface-water quality. Groundwater management has interim triggers that will be finalized when more data on thresholds is obtained.

The use of management frameworks is a new approach to accomplish cumu-lative effects management, said the government.

Government will conduct a regional strategic assessment of what potential cumulative effects might be in the sub-region of the southern Athabasca oilsands area where increased in situ activity is expected, said Bev Yee, assistant deputy minister of Alberta environment.

The Alberta government expects to shell out about $30 million to producers whose leases will be cancelled in areas set aside for conservation in northeast-ern Alberta, now that the province has approved the Lower Athabasca Regional Plan (LARP).

Oi l and gas companies w i l l be allowed to continue to operate in con-servation and recreation areas while oilsands companies’ tenures will be can-celled largely because of their footprint, said an Alberta government official in a recent conference call.

There are 16 energy companies—13 with oilsands agreements, six with metal-lic and industrial minerals agreements, and four companies with petroleum and natural gas agreements—within conser-vation areas, a press conference heard.

Within areas set aside for recreation, 16 energy companies hold tenure: six oilsands

companies, 13 oil and gas companies, and one metallic and minerals company.

Another roughly $30 million of tax-payers’ money will be spent implement-ing those recreational areas, bringing total costs for the plan to about $60 mil-lion, said Diana McQueen, minister of environment and sustainable resource development.

She stressed her estimates were a rough guess and final costs will be deter-mined after negotiations with the ousted energy companies are complete.

Compensat ion wil l be based on the amount paid for the leases, inter-est and development expenditures. Alberta’s Ministry of Environment and Sustainable Resource Development said it will not be releasing the names of the companies involved.

The Department of Energy will be working with those companies under

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This will allow government to set thresholds specifi c to this region so it can eventually develop a sub-regional plan, said Yee.

“Limits in these frameworks are clear boundaries in the system that are not to be exceeded. Triggers are used as warning signals to allow for evaluation, adjustment and innovation on an ongo-ing basis. This proactive and dynamic management approach will help ensure trends are identif ied and assessed, regional limits are not exceeded, and the air and water remain healthy for the region’s residents and ecosystems,” said a government release.

The Lower Athabasca Region covers approximately 93,212 square kilometres and is in the northeastern corner of Alberta.

The region includes a substantial por-tion of the Athabasca oilsands area, which contains approximately 82 per cent of the province’s oilsands resource and much of the Cold Lake oilsands area.

The new conservation areas and existing conserved lands in the Lower Athabasca Region will result in more than two million hectares of conserved

lands to support wildlife movement and habitat stability.

It’s the largest amount of land set aside for conservation in Alberta since the form-ing of Wood Buff alo National Park in the 1920s, the conference call heard.

The conservation areas will be man-aged to minimize or prevent new land disturbance. Land disturbance associated with exploration, development and extrac-tion of in situ and minable oilsands, metal-lic and industrial minerals, and coal are not considered compatible with the man-agement intent of conservation areas.

Commercial forestry operations are “generally considered” incompatible with conservation areas; however, selected areas may allow a limited level of ecosys-tem forestry or natural disturbance-based vegetation management.

No new oilsands, metallic and industrial minerals, or coal tenure will be sold in con-servation areas designated under the LARP.

New petroleum and natural gas tenure sold in a conservation area will include a restriction that prohibits surface access.

Existing petroleum and natural gas tenure will be honoured in new and existing

conservation areas, new provincial recre-ation areas and existing provincial parks for recreation, in accordance with exist-ing policy.

This includes all subsurface and sur-face activities needed to explore for, develop and extract the resource defi ned in the existing agreement. Care must be taken when exploring, developing and extracting the resource in order to mini-mize impacts of activities on the natural landscape, historic resources, wildlife, fi sh and vegetation.

This also includes renewing subsur-face and surface dispositions, approvals and agreements for existing activities.

Applications for new surface dispo-sitions (for example, a new disposition for a well, road, pipeline or facility, etc.) required to access an existing subsurface commitment would also be honoured as necessary extensions to an existing com-mitment, subject to review through the current application and approval process.

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Bitumen production at Southern Pacific Resource Corp.’s STP-McKay thermal pro-ject is expected to begin in the fourth quar-ter of this year as operations are continuing to progress well with the circulation period advancing on all the fi rst 12 steam assisted gravity drainage well pairs, the company has reported.

The first pad of six well pairs began steaming on July 1, with second pad fol-lowing on July 13. To date, the plant has been running very well, delivering all

steam requirements to the wellbores at a 99 per cent on-time load factor. All start-up issues have been resolved with minimal interruption.

The wells are readily accepting steam and warming up in a manner that ensures good conformance along the horizontal sections. They are forecast to need three to four months of steam circulation before being placed into production. Southern Pacific expects bitumen production to begin in the fourth quarter of 2012.

Southern Pacific’s rail marketing arrangements are progressing well in preparation for implementation in January 2013. The company earlier announced a unique arrangement to transport its bitumen product to the U.S. Gulf Coast via rail. The arrangement includes dedicated loading and offl oading capacity at two new rail terminals at Lynton, Alta., and Natchez, Miss. Both ter-minals, as well as approximately 500 railcars, are under construction and on schedule.


Southern Pacific updates STP-McKay project

Existing surface or subsurface commit-ments related to petroleum and natural gas within a protected area cannot be used as a basis to access new subsurface rights within a protected area (such as whether to access new subsurface deeper rights, new lateral subsurface rights or additional new rights).

LARP establishes six new conservation areas, bringing the total conserved land in

the region to two million hectares, or 22 per cent—an area three times the size of Banff National Park.

LARP also includes a plan for urban development around Fort McMurray in the Regional Municipality of Wood Buffalo. The region’s mayor, Melissa Blake, who helped form the plan, said it will mean a sound environment with social balance and opportunities to recreate.

It commits the province to a regional trail system plan, development of tailings management, biodiversity and surface water–quantity frameworks, and to work with aboriginal communities on initiatives to incorporate traditional knowledge into environmental planning.

The government is committed to com-pletion of a tailings management frame-work by 2013.

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Successful exploration at Keystone Pembina has Spartan's production up 45 per cent from the first quarter of 2012.

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Strong drilling results from its Keystone core area helped Spartan Oil Corp. increase second-quarter production by 45 per cent to 2,750 barrels of oil equivalent per day (83 per cent oil and liquids) from 1,903 bar-rels per day in the first quarter of 2012.

The increase in production came primarily from the company’s Pembina Keystone core area as it brought on 5.9 net new wells.

Output for the six months ended June 30, 2012, was 2,327 barrels per day.

The second quarter of 2012 repre-sented an important milestone for Spartan in that it marked the company’s first full year of operations. The company began operating on June 1, 2011.

During the past year, Spartan said it has grown from a company with a small pro-duction base characterized by high oper-ating costs, into a high-growth company

with some of the lowest operating costs in its peer group.

All of this growth has been achieved through the drill bit. From June 2011 to June 2012, the company has drilled 34 (30.6 net) horizontal wells and partici-pated in an additional four (1.0 net) hori-zontal wells targeting Cardium light oil at its Keystone property with a 100 per cent success rate.

During this period, Spartan has increased production by 358 per cent.

Despite wet weather and extended road bans, the company was able to drill continuously throughout breakup at its Keystone property. Spartan drilled or par-ticipated in 11 (10.7) net wells in Pembina during the second quarter of 2012.

The company said that wet weather and a minor landowner dispute impacted the timing of bringing new wells on production

during the second quarter. A total of six (5.9 net) wells were brought on produc-tion in the second quarter, leaving 12 (11.7 net) drilled wells in inventory at the end of the quarter.

Spartan said it is encouraged by the drilling results at Keystone and initial rates continue to meet or exceed the com-pany’s internal type curve.

“With a full year of operations com-pleted, management’s confidence in the Keystone asset continues to grow,” the company said in its second-quarter release.

Spartan now has a total of 29 hori-zontal wells at Keystone that have at least 30 days of production. The average 30-day initial production (IP30) oil rate for these wells is 172 barrels per day.

Included in this number are 14 wells that the company drilled in the interior of Unit 2. The Unit 2 wells have achieved an average IP30 oil rate of 128 barrels per day.

Spartan drilled three (1.5 net) wells in southeastern Saskatchewan during the second quarter. Two (1.0 net) of these wells were at the company ’s Torquay property and were funded 90 per cent by Spartan’s partner.

The company said it has identified numerous prospective oil targets in both of the wells and is expecting to complete the wells during the third quarter.

Spartan now has two rigs drilling con-tinuously in Keystone and it expects to drill an additional 31 (30.1 net) Cardium horizontal wells from July through to the end of 2012. In total, the company is bud-geting to drill 49 (46.6 net) Cardium hori-zontal wells during 2012.


Drill bit success helps Spartan grow production

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Central Alberta

Bonavista acquires Deep Basin gas propertiesBonavista Energy Corporation has entered into an agreement to acquire natural gas–weighted properties in its Deep Basin core area in west-central Alberta for an estimated $155-million purchase price at closing.

The acquisition has an eff ective date of July 1, 2012, and is expected to close on or about Oct. 1, 2012. The completion of the transaction is subject to customary regula-tory approvals and other conditions.

To accommodate the acquisition, Bonavista’s board of directors has approved an increase in its 2012 capital budget to $410 million, including $10 million of development expenditures allocated to the acquired properties. This revised capital budget consists of $385 million in explo-ration and development spending, and $25 million in net acquisition spending.

The acquisition is consistent with Bonavista’s strategy of acquiring high-quality, multi-zone oil and natural gas assets with significant low-risk devel-opment opportunities and extensive gathering, compression and processing infrastructure. At closing, production

from the acquired properties is estimated to be 6,700 barrels of oil equivalent per day (94 per cent natural gas).

The properties are on approximately 113,000 net acres of land adjacent to Bonavista’s existing Deep Basin land position.

The company has identifi ed approximately 27 high-impact horizontal drilling loca-tions off ering the potential to signifi cantly enhance production and resource recovery. The primary zones include the Wilrich and Bluesky as well as several secondary horizons such as the Rock Creek, Notikewin, Gething, Cadomin and Second White Specks.

In addition, the acquired properties off er numerous low-risk vertical drilling locations and recompletion opportunities with a predictable, low-cost production

base that is well positioned for a gradual improvement in natural gas prices.

Total proved-plus-probable reserves are 24.15 million barrels equivalent (18.52 mil-lion barrels proved) comprised of 133 billion cubic feet of natural gas (102 billion cubic feet proved) and 2.08 million barrels of oil and natural gas liquids (1.52 million proved).

The transaction doubles Bonavista’s land position in the Deep Basin, enhancing its operational presence and creating an opportunity to improve both capital and operational effi ciencies in the area. It also improves Bonavista’s control of strategic infrastructure in the Deep Basin including operatorship of two processing facilities totalling 102 million cubic feet per day of gross licensed throughput capacity.

The acquisition metrics of the deal are approximately $23,000 per flowing barrel equivalent and $10.56 per barrel of proved-plus-probable reserves, including future development capital and adjust-ing for land and seismic value of approxi-mately $6.8 million.


The�transaction�doubles�Bonavista’s�land�position�in�the�Deep�Basin,�adding�113,000�net�acres.

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Central Alberta

Fairborne cleans up balance sheet, focuses on Deep BasinFairborne Energy Ltd. has entered into two asset purchase and sale agreements for the divestiture of certain dry natural gas assets for gross proceeds of $189 million, subject to certain closing adjustments and conditions.

Closing of the transactions is antici-pated to occur on or about Oct. 2, 2012.

T he disposit ion assets inc lude Fairborne’s greater Marlboro area (Marlboro, McLeod and Westerose) and its shallow gas/coalbed methane assets in the Clive area. Combined, they represent current daily production of approximately 8,700 barrels of oil equivalent (95 per cent natural gas), 23.1 million barrels of proved reserves and 32.8 million barrels of proved-plus-probable reserves (93 per cent natural gas) as evaluated by GLJ Petroleum Consultants Ltd.

The company will retain its interest in the Clive oilfi eld where work is progress-ing on a CO2 flood to capture significant remaining oil reserves. Production from its Wild River natural gas well is scheduled to recommence in September after being shut in due to low gas prices.

Fairborne currently has $185 million of net debt (before costs associated with its previously announced strategic review pro-cess). Net proceeds from the transactions will be used to reduce bank debt and will virtually eliminate the company’s debt.

In the future, Fairborne will focus on the delineation and exploitation of its large land base in the greater Harlech area where it has 312 (201 net) sections of land in the heart of the liquids-rich Deep Basin fair-way. With 4,500 barrels equivalent per day of current production post-transactions, a recently announced resource study of 131 million barrels of best-estimate eco-nomic-contingent resource attributable to its working-interest share in the Cardium Formation and nominal debt, the company will have the cash fl ow, balance sheet and inventory of opportunities to deliver signifi -cant economic growth for the future.

The company said the transactions will position it as a highly focused, organic-growth vehicle with significant balance sheet flexibility to deliver per-share growth in production, reserves, cash

fl ow and net asset value. The production base and upside potential of the remain-ing assets are represented by high work-ing interest, operated, condensate-rich production with significant upside in a number of plays at Harlech.

These plays include the Cardium, which GLJ recently evaluated as to its potential (131-million-barrel-of-oil-equivalent best-estimate economic-contingent resource eff ec-tive Mar. 31, 2012) and the Wilrich resource play. The Wilrich is similar to the gas field Fairborne developed at Marlboro where it grew production 325 per cent in the three years following its fi rst Wilrich horizontal well.

The new Fairborne will have current production of 4,500 barrels equivalent per day of which 25 per cent will be oil and natural gas liquids (80 per cent oil and con-densate), 330 (183 net) unbooked Cardium horizontal drilling locations and operating netbacks of $15.50 per barrel.

The new company will have 23 million barrels equivalent of proved-plus-probable reserves including 15.3 million proved.


September Expertec ad for Oil & Gas InquirerCMYK press res pdf: 7.0625” x 2.25”

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Central Alberta

Hyperion plays up Niton-McLeod light oil playA junior producer said a land deal and farm-in it recently signed covering the Niton-McLeod area of Alberta could hold up to 171 million barrels of petroleum in place and add as many as 177 (158 net) Cardium light oil wells to the company’s drilling inventory.

During its annual meeting in June, executives with Hyperion Exploration Corp. hinted about a pending deal, but would not make any announcements, since nego-tiations were then continuing. In August, the junior announced the deal as part of a

broader plan, without naming the senior pro-ducer with which the farm-in portion of the deal was signed. In this year’s first quarter, Hyperion produced an average 1,300 barrels of oil equivalent per day (about 60 per cent crude oil and natural gas liquids).

The deal began with land Hyperion acquired in November 2010, covering 10,080 (9,864 net) undeveloped acres of Cardium light oil–prospective Crown lands in the Niton area. Then, in this year’s second quar-ter, the junior acquired another 15,040 net acres, also Cardium prospective, through a Crown land sale and smaller deals. Hyperion paid about $4 million in all for this acreage.

Then, earlier this month, Hyperion closed a deal with a senior producer to access 10,560 (7,611 net) Cardium acres under a rolling-option farm-in. This deal commits

Hyperion to drill one horizontal Cardium well every 135 days to earn a predetermined earning block of land, with an initial spud date of Oct. 15, 2012. A total of four earn-ing blocks are included in the farm-in, three of which have associated option lands that require another three wells to fully earn (one for each option block).

Added to the land Hyperion picked up in November 2010, the new undeveloped land deal and farm-in makes for a total 35,680 (32,515 net) acres of Cardium rights in the Niton-McLeod area, with an average 90 per cent working interest. The total petroleum initially in place, effective Aug. 15, 2012, is internally estimated by Hyperion to be up to 171 million barrels of light oil, with a pri-mary recovery factor of 12.5 per cent.

Hyperion expects the combined, undevel-oped land deal and farm-in will add up to 177 (158 net) Cardium light oil wells to its drilling inventory, bringing the junior’s total inventory of potential wells to 215 (196 net) Cardium light oil horizontal drilling locations.

In a press release, Hyperion said the Niton-McLeod area contains substantial deep-well control over the lands, which has allowed the company to reduce Cardium geological risk. The Cardium in this acreage exhibits typical Cardium reservoir character-istics, including high-quality, water-free light oil, according to management.

Hyperion has analyzed two Cardium cores, conducted a petrophysical study on drill cuttings from legacy Cardium well-bores in the area and said the results suggest Cardium reservoir characteristics, including permeability, porosity, thickness and water saturation, are consistent with other success-ful Cardium horizontal programs.

Within the Hyperion acreage are five legacy, vertical wells that showed light oil productivity from reservoir rock that does not contain a conglomerate facies. Most of these wells were shut in years ago and produced relatively small volumes of oil, but demon-strated the potential for horizontal drilling. The tight but thick portion of the reservoir contains the majority of the oil in place and is Hyperion’s target within the Cardium.

Hyperion has drilled one net horizontal well in the area that is exceeding expecta-tions. The well was drilled adjacent to a legacy well that produced material amounts of light oil and solution gas (about 100,000 barrels of oil and 400 million cubic feet of gas). Despite reporting localized pressure depletion from the vertical well, the horizon-tal is continuing to produce about 60 barrels per day in its fifth month of production, man-agement said.

As well, management said the Niton-McLeod land base is situated in a network of solution gas infrastructure near under-used gas processing facilities. An oil pipeline tie-in near the south end of Hyperion’s asset base could reduce future operating costs by eliminating trucking, management said. The Cardium in Niton-McLeod is relatively shal-low and will contribute to below-average costs for drilling and completion compared to other Cardium plays, the company added.

Management said at least two wells will be drilled in this year’s fourth quarter, with another two planned for the first quarter of 2013, in the Niton-McLeod area. Hyperion is also considering financing alternatives to further accelerate development, the com-pany said in its news release.


Hyperion�expects�the�combined,�undeveloped�land�deal�and�farm-in�will�add�up�to�177�(158�net)�Cardium�light�oil�wells�to�its�drilling�inventory.


Southern Alberta

SOUTHERN ALBERTA WELL ACTIVITY

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Deethree is enjoying success in proving up its alberta Bakken lands near Lethbridge, with two rigs drilling in the play.

After already reaching its year-end pro-duction goal of 5,000 barrels of oil equiva-lent a day, DeeThree Exploration Ltd. has raised its capital budget to $110 million.

The company’s initial 2012 budget of $57 million had already been increased in the first quarter to $82 million. Reflecting the strength of its oil targets in the Exshaw formation in the Lethbridge area of south-ern Alberta (Alberta Bakken) and in its Brazeau Belly River properties, DeeThree boosted its operating netback per barrel to $30.86 in the second quarter, a 25 per cent increase from the first quarter of 2012.

Continued success in the company’s Exshaw and Belly River oil plays drove sig-nificant production increases early in the third quarter, enabling DeeThree to recently hit its 2012 exit target of 5,000 barrels a day. The company is currently operating two drilling rigs on its Exshaw play.

DeeThree now expects to exit 2012 at about 6,000 barrels equivalent a day (76 per cent oil and natural gas liquids), up 20 per cent from its previous guidance.

Through the second half of 2012, DeeThree plans to deploy its capital pri-marily on its Exshaw properties with plans to drill another eight (eight net) wells this year. The company says its expanded budget is fully funded through cash flow and funds available from its credit facility.

In the second quarter, DeeThree’s capi-tal spending totalled about $30 million and included the drilling of seven (6.8 net) wells with 100 per cent success. The com-pany boasts 100 per cent drilling success this year.

Through the second quarter, DeeThree continued to develop the Exshaw, drilling four (four net) wells. One of the company’s two most recently completed wells tested

at 808 barrels equivalent a day over nine days, the other at 630 barrels a day over eight days.

The sixth location drilled this year was a step-out that is significant as the first well drilled by DeeThree on the Crown lands that comprise part of its Exshaw properties.

This well is subject to a five per cent Crown royalty holiday that DeeThree says is expected to drive substantial netback and cash-flow benefits.

Based on the success of this well, the company acquired an additional 22 sections of offsetting Crown land in the second quar-ter, and DeeThree now has 39 sections of Crown land that it believes to be highly pro-spective for Exshaw potential in addition to its extensive freehold land in the area.

The 2012 drilling program has success-fully tested the upper Exshaw formation over an eight-mile east-west by three-mile north-south fairway. DeeThree intends to further test the limits of the known Exshaw oil pool through the second half of the year by drilling an additional eight Exshaw wells.

To accommodate anticipated additional production increases from its Exshaw drilling program, the company is cur-rently installing an amine plant to handle CO2 from solution gas. Also, it is design-ing and procuring equipment for a second 4,000-barrel-a-day expandable oil facility, which is to be operational by year’s end.

In its Brazeau Belly River light oil play, DeeThree continued to have success during the second quarter with three (2.8 net) horizontal wells drilled.

These wells targeted different sands than previously drilled in this multi-zone play. Two wells were drilled into the upper Belly River sands highlighted by a 30-day initial production rate of 400 bar-rels equivalent a day (76 per cent oil and natural gas liquids) on the first location

DeeThree boosts budget to $110 million


Southern Alberta

and 222 barrels a day (100 per cent oil) on a fi ve-day test on its most recently com-pleted well.

The third well was drilled into a lower Belly River marine sand that tested at 512 barrels a day (78 per cent oil and natu-ral gas liquids) over eight days and has recently been brought on stream. These results have confirmed the multi-zone potential of the hydrocarbon-bearing Belly River package over DeeThree’s sig-nifi cant land position at Brazeau.

The success of these three wells has resulted in a substantial increase in the company’s drilling inventory and reserves at Brazeau, as DeeThree’s 2011 year-end

reserve report didn’t attribute any reserves associated with the exploitation of these sands through horizontal drilling.

DeeThree also announced results of a reserves and resource evaluation on its Bakken assets in the Lethbridge area of Alberta as of July 31, 2012, report-ing total contingent oil and prospective undiscovered original oil in place of 479.3 million barrels.

The evaluation was prepared by Sproule Associates Limited.

The best estimate of ultimate poten-tially recoverable oil resources is 57.5 million barrels of oil, while contingent oil resources in place were 222.1 million

barrels with a best estimate of recoverable resource of 21.8 million barrels, in addi-tion to the reserves produced and booked to date.

Prospective oil resources are 257.2 million barrels with a best estimate of recoverable resources of 30.9 million bar-rels. Total proved-plus-probable reserves were 4.9 million barrels of oil equivalent (95 per cent oil), booked as a result of the fi rst six-well drilling program in 2012.

Average proved-plus-probable reserves of 263,000 barrels per well were booked for the fi rst six wells drilled in 2012.


Princess play drives Crew resultsCrew Energy Inc.’s second-quarter pro-duction jumped 72 per cent thanks to suc-cessful drilling programs in the Princess, Alta., Septimus, B.C., and Kobes, B.C., areas, combined with the acquisition of Caltex Energy Inc.

P roduc t ion du r i ng t he qua r ter increased to 28,192 barrels of oil equiva-lent per day (52 per cent liquids) from 16,443 barrels per day for the compara-ble period in 2011. First-half output was 29,286 barrels per day versus 16,028 barrels per day during the f irst six months of 2011.

The company noted that second-quarter production was seven per cent below the fi rst quarter of 2012 due to the shut-in of 1,200 barrels equivalent per day of uneconomic natural gas produc-tion and the inability to truck clean oil from single-well batteries in Alberta and Saskatchewan.

As well, an eight-week outage at a third-party facility resulted in the cur-tailment of 700 barrels equivalent per day of natural gas and associated liquids throughout the quarter.

During the second quarter of 2012, Crew drilled a total of three (1.6 net) wells resulting in two (1.3 net) oil wells and one (0.3 net) natural gas well. In addition during the quarter, the com-pany completed 12 (11.3 net) wells and recompleted 20 (19.1 net) wells within the Princess, Lloydminster, on the

Alberta-Saskatchewan border, and Tower, B.C., oil-focused areas.

The company continued to add to its infrastructure, spending $11.7 million on pipelines and upgrading its batteries and facilities pre-dominantly in the Princess and Septimus areas. Crew also closed minor dispositions of non-core undeveloped lands in central Alberta for $4.3 million.

A c t i v it y at P r i nc e s s focused on the completion and tie-in of the company’s drill-ing program. By the end of the second quarter, a total of 15 wells had been brought on pro-duction with the remainder to be completed and tested in the third and fourth quarters.

Four vertical wells drilled in the first quarter outside existing pool boundaries confirmed the extension of the Pekisko oil trends and further supports Crew’s long-term inven-tory of drilling locations. Production aver-aged 6,850 barrels equivalent per day for the quarter, with production impacted by spring breakup as well as a turnaround at the company’s West Tide Lake facility.

Crew says its Tilley waterfl oods con-tinue to show positive response with the

Pekisko N pool production rate 110 per cent above pre-waterfl ood conditions, and the Pekisko K pool production rate 80 per cent above pre-waterfl ood conditions.

The company has initiated injection into three new Alderson waterfl oods and expects to have two West Tide Lake water-floods on injection in the third quarter, Ph

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Crew's second-quarter production climbed 72 per cent year over year, driven by growth in its Pekisko oil play.

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Southern Alberta

and one additional Alderson waterflood in the fourth quarter for a total of six new waterfloods in 2012.

Crew plans to drill an additional eight (7.5 net) wells at Princess for the remain-der of 2012 to further delineate its large undeveloped land base (86 per cent of 460 net sections are undeveloped).

At the end of the second quarter, Crew started the second phase of its 2012 heav y oil dri l l ing program at Lloydminster and drilled one (one net) oil well in the second quarter.

The company plans to drill an addi-tional 10–15 wells and continue with the successful recompletion program target-ing secondary hydrocarbon zones within existing wellbores. Crew says that these workovers have very strong econom-ics as capital costs range from $50,000 to $100,000 with results comparable to the drilling, completion and equipping of a new well at a cost of approximately $500,000.

Crew drilled one (0.33 net) Montney oil well at Tower in the second quarter. Given this well’s proximity to its existing infrastructure in the area, Crew was able to bring the well on production immedi-ately following the initial completion.

The company says it is proceed-ing with necessary approvals to drill up to eight (six net) additional wells, the timing of which will be determined based on the performance of the first two wells and capital availability.

At Septimus, Crew diverted a total of 14 wells from the western edge of the Septimus field into the newly acquired si x-inch Sept imus/ Tower pipel ine, which is now connected to the Septimus gas plant. Gathering system pressures were reduced by approximately 1,400 kilopascals, resulting in a three-million-cubic-foot-per-day increase in produc-tion (27 barrels of liquids per million cubic feet).

Crew also has two (two net) Montney horizontal wells drilled in the first quar-ter for which completions were deferred, given the weakness in natural gas prices. The company is expected to proceed with the completion and tie-in of these wells in the third or fourth quarter.

At Kobes, Crew is planning to drill one well late in the year to continue its entire 23 net section land block for an additional 10 years.


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Southern Alberta

Angle grows at Harmattan, Lone PineAngle Energy Inc. achieved record pro-duction for the second quarter, averaging 15,569 barrels of oil equivalent per day, an increase of 20 per cent as compared to the same period in 2011.

The company’s light crude oil and con-densate production increased 49 per cent to 3,270 barrels per day, while total light oil and natural gas liquids production increased by 25 per cent to reach 6,872 barrels per day, all as compared to the second quarter of 2011.

First-half 2012 output averaged 15,318 barrels equivalent per day, a 19 per cent increase from 12,859 barrels per day during the first six months of last year.

Drilling expenditures totalled $9.4 mil-lion during the second quarter of 2012. During the first half of 2012, drilling expenditures totalled $46.3 million.

The company noted that drilling costs per well have decreased compared to the second quarter of 2011, primarily due to the utilization of more efficient drilling techniques.

Completion expenditures were $15.8 million in the second quarter of 2012 versus $9 million in the comparable period of 2011. Angle completed 12.1 net wells compared to five net wells during the comparable period of 2011. The decrease in the per-well cost was due to Angle switching to water-based frac-turing in 2012 compared to oil- or propane- based fracturing in 2011.

To date in 2012, Angle has equipped and tied in 23 gross wells at a total cost of $9.2 million, compared to 12 gross wells for $6.7 million in the same period of 2011.

During the second quarter of 2012, Angle drilled seven (seven net) wells, all of which were successful. In Harmattan, the company drilled one (one net) horizontal Mannville B liquids-rich natural gas well and five (five net) horizontal Cardium oil wells. In Lone Pine Creek, Angle drilled one (one net) horizontal Mannville oil well.

During the six months ended June 30, 2012, Angle drilled 26 gross wells at an average working interest of 88 per cent, with a 100 per cent success rate. Activity has primarily been focused in the Harmattan area on the Mannville B liquids-rich natural gas and Cardium oil plays and, to a lesser extent, on the Cardium oil play in the Ferrier and Edson areas.



SaskatchewanPh

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SASKATCHEWAN WELL ACTIVITY

Despite a wet spring, renegade recorded record average production in the second quarter.

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Renegade Petroleum Ltd. had record aver-age production in the second quarter and its 96 per cent light oil weighting and hedging allowed the company to post net-backs of $51.03 per barrel of oil equivalent during the period.

The netback was reached despite large pricing differentials during the quarter. In addition, Renegade has maintained significant financial flexibility with only $69 million drawn on its existing $125 million operating line as of June 30.

Renegade has an extensive land base of approximately 186,000 undeveloped acres, which provides the company with a drilling inventory of over 809 potential gross (729 net) drilling locations.

During the second quarter, Renegade experienced a longer-than-anticipated breakup in west-central Saskatchewan in the Viking and in the Souris Valley and Frobisher trends in southeastern

Saskatchewan. Conditions in west- central Saskatchewan and southeastern Saskatchewan have improved dramati-cally since the end of July, and Renegade is currently in its full-scale drilling pro-gram. Renegade’s current production is approximately 4,200 barrels per day, based on field estimates, and management anticipates being in a position to success-fully execute on its previously announced capital program for the year.

Production in the second quarter aver-aged 3,712 barrels per day, up 120 per cent from the comparable quarter of 2011. Production for the three months, ended June 30, 2012, consisted of 96 per cent light oil and four per cent natural gas and natural gas liquids.

Renegade achieved a 100 per cent success rate drilling 12 (11.3 net) wells in the second quarter, including 10 (10 net) wells in the Viking in west-central

Saskatchewan and two (1.3 net) wells in southeastern Saskatchewan.

Subsequent to June 30, 2012, Renegade drilled and completed eight (5.2 net) south-eastern Saskatchewan wells. In southeast-ern Saskatchewan, Renegade is focused on the Souris Valley trends in Crystal Hills and Redvers and the Frobisher trends in Wordsworth and Queensdale.

The Crystal Hills well drilled in the second quarter, located along the Souris Valley trend, had a 30-day initial produc-tion rate of 120 barrels per day. This well was drilled as a single-leg horizontal in order to establish reservoir data from one of three productive cycles.

Renegade completed its first horizontal well in the Redvers area in late July. Initial production from this well was 80 barrels per day un-optimized due to facility con-straints. The well was drilled as a single-leg horizontal as it was the company’s first horizontal well drilled into the pool.

Due to the success of this horizontal well, as well as the acquisition of 18 square kilometres of 3-D seismic during the quar-ter, Renegade now anticipates moving closer to a full-scale development plan in the area. Renegade is currently in the pro-cess of drilling its second and third wells in the pool in order to exploit the multiple cycles that have been previously defined by vertical production.

The company now has two drilling rigs active in southeastern Saskatchewan with plans to keep them active for the remainder of 2012. The focus of the drilling activity for the balance of the year will be in Crystal Hills, Redvers, Wordsworth and Queensdale.

Throughout the quarter, the company has continued to focus on processing capacities with Phase 2 upgrades being completed in Wordsworth and Crystal Hills. The recently initiated construction of a new production facility in the Redvers area, which is scheduled to be completed

Renegade finds growth across Saskatchewan

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Saskatchewan

Novus Energy Inc. expanded its Viking acreage position in the second quarter, while continuing to report drilling success.

In addition to the 124 net sections of Viking rights the company holds in the Dodsland area of Saskatchewan, Novus recently amassed 46 net sections of Crown lands prospective for Viking oil in the Provost area of Alberta, on trend with its existing Dodsland assets. The acquired land is proximate to historical vertical Viking oil production and recent success-ful horizontal drilling activity on both sides of the Alberta/Saskatchewan border targeting Viking oil. Novus believes the assembled acreage meaningfully increases the company’s future drilling and develop-ment inventory. Drilling on these lands is planned for early 2013.

During the second quarter of 2012, Novus drilled 13 (13 net) wells, all of which were Viking horizontal oil wells in the greater Dodsland area. Eight wells (eight net) were completed by June 30. For

the fi rst half of 2012, Novus drilled 26 (26 net) wells, all of which were Viking hori-zontal oil wells in the greater Dodsland area. Sixteen (16 net) wells were com-pleted by June 30.

Novus has completed the installation of the main infrastructure in the Flaxcombe area by adding 11,000 metres of emulsion lines that tie into the main transmission line feeding its facility. Thirty-six wells currently have gas conservation and are tied in, with new wells tied in as they are completed. Load water recovered is being handled by the company-owned disposal facility. Produced water coming into the main facility is injected into a second well tied into the plant, while sales gas fl ows to a sales line, making it an enclosed system.

Additionally, upgrades have been completed at the main facility. It is now fully enclosed and electrified with two treaters, and treating capacity exceeding 13,000 barrels per day. The facility also has 11,000 barrels of storage.

Corporate operating costs have con-tinued to materially decrease, falling to $9.96 per barrel in the most recent quar-ter, a decline of 39 per cent from $16.30 in the second quarter of 2011. The company’s second-quarter 2012 operating costs for its Viking production were $7.38.

The company has 625 net high-quality risked Viking oil drilling locations on its 124 net sections of land in Dodsland based on an eight-well-per-section drilling den-sity. This already-signifi cant opportunity base does not refl ect the ability to down-space from eight to 16 wells per section or the future potential to waterfl ood the reservoir. Novus believes that the develop-ment of the Viking resource is in its early stages, and that there is further signifi cant upside to recovery factors by applying sec-ondary recovery methods. The 625 Viking locations do not include potential loca-tions on the company’s recently acquired Alberta Viking lands.


Novus expands Viking acreage

in the fourth quarter of 2012, will support Renegade’s development program for the second half of 2012.

Renegade is currently in various stages of licensing 17 locations at Senex and con-tinues to move forward with plans to start drilling activities late in the third quarter to early in the fourth quarter of 2012, with an anticipated program of up to three hor-izontal wells. Total drilling and comple-tion cost estimates for the program are expected to be $10 million.

I n west- cent ra l Sa sk atc hewa n, Renegade drilled 10 (10 net) wells in the second quarter of 2012, bringing the 2012 total to 29 (28.5 net) wells. Of the 10 wells drilled, five were completed within the quarter due to limited access to locations caused by an extended breakup in west-central Saskatchewan.

Renegade has now drilled and brought onto production 12 (12 net) wells based on 40-acre spacing. The production results in west-central Saskatchewan continue

to show a strong correlation to the off set 80-acre spacing well type curves.

The company is planning on initiat-ing waterflood pilots in the southeastern Dodsland and Lucky Hills areas by the end of 2012 to further complement the growth of the areas being drilled on 40-acre spacing. In addition, Renegade has received approval for a pilot waterfl ood in the Dodsland pool, and management expects to begin water injection into the fi eld by late 2012.



Technology News

Baker Hughes has introduced the LATIDRILL water-based drilling fluid system to help operators enhance wellbore quality and increase drilling effi ciency in extended lat-eral sections in unconventional shale plays.

The LATIDRILL system is more envi-ronmentally favourable than oil-based fl uid systems and off ers the hole stability and superior drilling speed and perfor-mance normally associated with invert emulsion systems.

Tested under rigorous laboratory conditions and proven in the field, the LATIDRILL system improves wellbore stability by controlling the clay hydra-tion typically associated with the use of a conventional water-based fl uid.

Clay hydration can lead to slough-ing shale and borehole enlargement. T he L ATIDR IL L system uses a pro-pr ie t a r y we l lb or e s t abi l i z e r t h at me c h a n ic a l ly m a i nt a i n s we l lb or e integrit y and l imits non-productive t ime associated w ith hole stabi l it y issues. By del iver ing a more stable wellbore in long horizontal sections, the L ATIDRILL system reduces pore pressure t ransmission, minimizing or even eliminating mud losses. The LATIDRILL system improves drilling ef f ic ienc y w it h specia l ly pur posed lubricants that coat metal surfaces, drill cuttings and formation walls to reduce torque and drag, particularly

Water-based fluid system improves shale drilling

Schlumberger Limited has announced the release of the Rhino XC on-demand reamer. This next-generation reaming tool provides unlimited activation of the fl ow actuation system to reliably enlarge boreholes.

Building on Rhino XS hydrauli-cally expandable reamer technology, the Rhino XC reamer actuation system, with ream-on-demand capabilities, provides complete control of reamer cutter-block deployment, regardless of well-inclination angle. Its flow activation system elimi-nates the need for time-consuming pumpdown device activation, allowing the reamer to be placed below inner diameter–restricted bottomhole-assembly components resulting in a reduced pilot-hole interval at total depth.

“With its on-demand capabilities and unlimited activations and deactivations of

the cutter blocks, customers can optimize their under-reaming program in real time,” said Dean Watson, president, drilling tools and remedial, Schlumberger. “In deepwa-ter environments, this provides huge sav-ings for our customers by enabling faster and [more] reliable activation.”

The Rhino XC reamer is eff ective in a variety of formations where simultaneous drilling and reliable hole enlargement are essential. The reamer’s one-piece, balanced design increases torque and load-carrying capacity while reducing drilling-generated vibrations that produce undergauge and irregular boreholes. Once activated, the reamer effectively enlarges wellbores for improved casing running, cement clearance and equivalent circulating density control.

In off shore Norway, one North Sea cus-tomer undertook a long and challenging

9 ½–inch by 10 ¼–inch section with the potential for several hole-related issues. For f lexibility in handling borehole instability, the operator required on-demand capability to close reamer fl ow to the annulus. The Rhino XC was run, allowing cycling of the reamer mul-tiple times during the course of the run, simply by changing the pump fl ow rate in a predetermined sequence. The resulting 9,283-foot run was completed in just over 300 circulating hours, a new run-length record for the client.

Schlumberger is the world’s leading supplier of technology, integrated proj-ect management and information solu-tions to customers working in the oil and gas industry worldwide. Schlumberger Limited has principal offices in Paris, Houston and The Hague.

Schlumberger introduces new reamer to cut drilling times

in high-pressure/high-temperature applications.

The lubricants also allow for the delivery of greater amounts of hydraulic horsepower to the drill bit and result in faster rates of penetration. Because the LATIDRILL system is water-based, dis-posal of oily cuttings is unnecessary, and clean-up time on the rig can be reduced by as much as two days compared to that of oil-based systems. Operators can realize greater value by packaging the LATIDRILL system with the full range of Baker Hughes shale solutions, including the StarTrak imaging tool, the AutoTrak rotary steerable system, and the Hughes Christensen Talon 3-D PDC bit.

Portage College is once again expand-ing and will soon open the first Pipeline Training Centre in Alberta. The Pipeline Training Centre will coexist with the Heavy Equipment Training Centre at Portage College’s newest campus in Boyle, Alta.

Synergies between the heavy equip-ment operator and pipeline training

program offerings are functional and technology driven. Each sector has high employability rates and are both directly tied with Alberta’s oil and gas industry.

The program will cover five areas of pipeline training: construction, opera-tion, maintenance, environment and regulatory policy.

“The overall design of the program is to train entry-level pipeline staff with practical skills to advanced levels of system, pipe design, testing, controls, environmental, overall maintenance activities and response planning,” says Stuart Leitch, Portage College Community & Industry Training Initiatives director.

Portage College opening Pipeline Training Centre


Technology News

CanElson Drilling Inc. has announced a long-term contract for a new $8-million bi-fuel (natural gas and diesel) drilling rig.

President and chief executive officer Randy Hawkings stated, “Given our modern fl eet of deep capacity drilling rigs and our growing bi-fuel capability on our drilling rigs, we expect to continue outperforming the industry and contracting new build rigs as we move forward.”

The new CanElson bi-fuel drilling rig will have three diesel engines capable of operating on a combination of natural gas and diesel fuel or on diesel fuel only, in the event that natural gas is either unavailable or becomes uneconomic. In bi-fuel mode, natural gas displaces a signifi cant amount

of the diesel fuel that would otherwise be consumed. CanElson expects that the displacement of diesel fuel will result in significant fuel cost savings for bi-fuel drilling rigs.

The new bi-fuel drilling rig will be the second new rig with bi-fuel capacity to be assembled by CanElson at its facility in Nisku, Alta. The fi rst new build bi-fuel rig (Rig 32 in CanElson’s fl eet) was delivered last month. The new rig (Rig 34) is scheduled for delivery in December.

For each of the new bi-fuel rigs, CanElson’s wholly owned subsidiary, CanGas Solutions Inc., is investing approxi-mately $200,000 for bi-fuel capability. This $200,000-bi-fuel investment is incremental

to the $7.8 million it costs for a diesel-fuel drilling rig (excluding top drive).

CanElson’s investment in each of its two new bi-fuel rigs is underpinned by long-term committed contracts. CanElson will arrange to truck compressed natural gas (CNG) to the bi-fuel rigs using trailers owned by CanGas.

As previously disclosed, CanElson is also assembling two additional rigs (Rig 33 and Rig 35), both for delivery to West Texas under long-term contracts with pro-ducers there. Rig 33 is scheduled for deliv-ery in October and Rig 35 is scheduled for delivery in January 2013.

Beyond that, CanElson has ordered long lead items for another new rig (Rig 36).

VeruTEK Technologies Inc. and Wavefront Technology Solutions Inc. have executed a partnership agreement to apply their chemical solutions and fl uid delivery tech-nology platforms to enhanced oil recovery (EOR) and well stimulation approaches for heavy oil as well as conventional and tight reservoirs.

The combination of VeruTEK GasGen e nv i r on me nt a l l y f r ie nd l y f lu id s , delivered by Wavefront f luid-pulsing technology, provides tremendous oppor-tunity for improved production in many formations.

Under t he ter ms of t he ag ree-ment, Wavefront may identif y and engage prospects interested in a joint Ve r uT E K / Wa v e f r ont s olut ion f or enhanced oil recovery, well stimula-tion and environmental applications. Wavef ront w i l l resel l co -bra nded VeruTEK products.

Additionally, VeruTEK may introduce Powerwave and Primawave as highly dif-ferentiated alternatives for injection and will provide assistance to Wavefront to secure clients who use VeruTEK products and services.

“We are extremely pleased to work with VeruTEK, a leader in green chemical solutions,” said Wavefront president and chief executive officer Brett Davidson. “This agreement is part of Wavefront’s strategy to leverage Powerwave and Primawave through strategic alliances in both the energy and environmental sectors. Wavefront is confi dent alliances will bring greater exposure to the fi eld-proven technologies of both compa-nies, as well as supplementary revenue streams,” said Davidson.

“VeruTEK has experienced excellent results working with Wavefront tech-nology, and we are excited to partner in

oil and gas applications. The Wavefront dynamic injection approach is ideal for oil recovery revitalization, particularly when used with VeruTEK’s innovative GasGen chemistry,” said VeruTEK chief executive offi cer Dan Socci.

VeruTEK is a green chemistry com-pany that provides high-performing chemical solutions to the oil and gas and environmental industries. The company has developed and patented innovative and env ironmentally f r iendly gas-generating chemicals to enhance for-mation permeability and hydrocarbon recovery. The VeruTEK technology plat-form addresses applications including production stimulation, EOR and envi-ronmental remediation.

Wavefront is a technology-based leader in fl uid injection technology for improved/enhanced oil recovery and groundwater restoration.

CanElson announces contract for new $8-million bi-fuel drilling rig

VeruTEK and Wavefront combining green chemistry with fluid injection technology

“The pipeline industry is crucial to Alberta’s economic prosperity. Portage College’s Pipeline Training Centre will be built, designed and operated in partnership with the many companies forming the indus-try,” says Portage College president Trent Keough. “The Pipeline Centre will also allow

for research and fee for service opportunities where companies can do their own training on site. Alberta needs this facility and the industry needs skilled workers.”

Portage College is expected to offer the first pipeline training program in September 2013.

Portage College is a public, board-governed college operating under the Alberta Colleges Act. The college has been serving the region for over 40 years and is the fi rst choice for learners in northeastern Alberta. Portage boasts nine campus locations, which are stra-tegically located throughout the region.

We’ve MovedAs of August 27, 2012, the Edmonton office of JuneWarren-Nickle’s Energy Group is now located at:

220–9303 34 Avenue NW, edmonton, AB T6e 5W8

Our contact numbers will remain the same.

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Technology News

Pending a signed contract, construction of Rig 36 is possible in the fi rst quarter of 2013. CanElson continues to require committed con-tracts prior to full assembly of additional rigs.

CanElson’s capital program will be financed out of cash flow and existing debt facilities with fi nancial capability for

additional growth and maintaining divi-dend payments.

CanElson operates contract drilling rigs in Canada, the United States and Mexico for oil and natural gas exploration and devel-opment companies. CanElson also assem-bles new drilling rigs at a facility in Nisku,

operates contract oil and gas service rigs in Mexico, and operates a CNG trans-portation and related services business. CanGas is a Calgary-based CNG transport company and a North American leader in the development and utilization of con-tainerized natural gas transport.

The U.S. Department of Energy has announced the selection of 14 new research projects across 11 states that will be a part of an expanding portfolio of projects, designed to increase the understanding of methane hydrates’ potential as a future energy supply.

Methane hydrates are 3-D ice-lattice structures with natural gas locked inside, and are found both onshore and off shore—including under the Arctic permafrost and in ocean sediments along nearly every con-tinental shelf in the world. The announced projects build on the completion of a suc-cessful, unprecedented test earlier this

year that was able to safely extract a steady fl ow of natural gas from methane hydrates on the North Slope of Alaska.

“While research on methane hydrates is still in the early stages, these research eff orts as part of President Obama’s all-of-the-above energy strategy could potentially yield signifi cant new supplies of natural gas and further expand U.S. energy supplies,” said U.S. Secretary of Energy Steven Chu.

The research will advance the under-standing of the nature and occurrence of deepwater and Arctic gas hydrates and their implications for future resource development

and environmental performance. While prior Department of Energy research and outside studies have confirmed that the resource volume present appears to be sub-stantial, and the accumulations that can be explored for and produced using exist-ing technologies are potentially numerous, signifi cant research remains to analyze the role of gas hydrates in the natural environ-ment; demonstrate that gas hydrates can be produced commercially in an environ-mentally responsible manner; and further assess resource volumes, particularly in deepwater settings.

U.S. Department of Energy advances research on methane hydrates


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Oil & Gas Inquirer October 2012