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Keeping readers regionally informed

FEATURES

1 Cover feature

TCA provides engineered steel containment solutions for the Western Canadian Oil & Gas Industry

21

ENGINEERED CONTAINMENT ADVANTAGES

Road to rail

Stranded

With pipeline capacity tight, trucking and

Northeastern B.C. gas supply continues to

rail pick up the slack

grow, but new markets still years away

ByGodfreyBudd

ByDarrellStonehouse

GENERAL NEWS

27 Liquids glut taking shape in western Canada ByPaulWells

REGIONAL NEWS

49 Central Alberta

33 British Columbia 

Proposed Kitimat oil refinery must make

Drill bit success helps Spartan grow

economic sense, says industry

production

ByRichardMacedo

• 12" • 25" • 33" • 45" • 57" • Coming Soon 66" • Crossover Steps Available for all Wall Heights

Custom site designs available

Deethree boosts budget to $110 million

Birchcliff production continues to climb

57 Saskatchewan

45 Northeastern Alberta

renegade finds growth across

Land-use plan will cancel oilsands leases

Saskatchewan

ByLyndaHarrison

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oil & gaS inQuirer • OCTOBER 2012

7


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

F

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

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.

BEFORE

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

AFTER Photos courtesy of Cold Jet

More versatility Chris 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.

“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

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.

industrial HEAV Y DUT Y RESTOR ATION


Editor’s Note

Vol. 24 No. 8 EDITORIAL EDITOR

Darrell Stonehouse | dstonehouse@junewarren-nickles.com

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

Dumping money in a hole

Godfrey Budd, Lynda Harrison, Richard Macedo, Paul Wells EDITORIAL ASSISTANCE MANAGER

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A generation has passed since the Alberta Conservative government last threw taxpayer money at private enterprise in an effort to diversify the province’s economy. That foray into the private sector resulted in billions of dollars wasted in efforts 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 financing a private venture with public money. The first is, can the Alberta government really afford this project given it is running a $3-billion deficit in 2013? Even worse, should the federal government be giving money to private industry when it is running a $21-billion deficit in 2012-13? Another question is, what happens when other oilsands operators or coal-fired 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 publicrelations 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 fine 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 solutions rather than pouring public money in a hole.

Subscription Inquiries Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: 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 Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

N E X T

I S S U E

November 2012 In 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.

Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as "Letter to the Editor" if you want them published.

OIL & GAS INQUIRER • OCTOBER 2012

9


STATS AT A GLANCE

Alberta Completions

WCSB Oil & Gas Completions

Source:DailyOilBulletin

Source: DailyOilBulletin

MONTH

OIL

Aug 2011 Sep 2011 Oct 2011

452 1,028 626

Nov 2011 Dec 2011 Jan 2012

GAS

OIL

Aug 2011 Sep 2011 Oct 2011

922 1,448 1,153

262 445 321

 0 1

Nov 2011 Dec 2011 Jan 2012

1,170 988 419

50 55 127

1 1 1

Feb 2012 Mar 2012 Apr 2012

37 95 63

2  1

Jun 2012 Jul 2012 Aug 2012

T O TA L

183 357 259

93 146 19

2 1,1 0

557 568 215

241 300 131

36 72 35

Feb 2012 Mar 2012 Apr 2012

491 515 403

177 147 141

Jun 2012 Jul 2012 Aug 2012

205 348 380

12 46 98

GAS

D RY

SERVICE

T O TA L

28 24 20

80 155 49

1,292 2,072 1,543

331 359 190

27 27 15

42 115 31

1,570 1,489 655

846 996 608

244 180 192

21 33 31

52 66 157

1,153 1,275 988

376 660 682

25 92 148

40 16 9

8 105 67

449 873 986

Wells Drilled in British Columbia

Saskatchewan Completions

Source: B.C. oil and gas Commission

Source: DailyOilBulletin

MONTH

WELLS DRILLED

C U M U L AT I V E *

MONTH

OIL

GAS

OTHER

TOTAL

Aug 2011 Sep 2011 Oct 2011

40 92 35

519 611 646

Aug 2011 Sep 2011 Oct 2011

413 352 457

2 4 29

13 29 46

2  2

Nov 2011 Dec 2011 Jan 2012

92 58 53

738 796 53

Nov 2011 Dec 2011 Jan 2012

524 332 142

4 4 10

32 61 8

0  10

Feb 2012 Mar 2012 Apr 2012

66 39 86

119 158 244

Feb 2012 Mar 2012 Apr 2012

296 414 172

6 0 0

20 40 49

22  221

Jun 2012 Jul 2012 Aug 2012

13 57 53

334 401 454

Jun 2012 Jul 2012 Aug 2012

144 232 296

0 0 4

10 16 9

1 2 0

*Fromyeartodate *fromyeartodate

10

MONTH

OTHER

OCTOBER 2012 • oil & gaS inQuirer


FAST NUMBERS

.

.

$

$

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

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

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, September 12, 2012 Source: RigLocator

alberta, September 12, 2012 Source:DailyOilBulletin

AC T I V E

DOWN

T O TA L

AC T I V E (per cent of total)

Western Canada Alberta

OIL WELLS

Alberta

Aug 12

GAS WELLS Aug 11

Aug 12

Aug 11

252

322



44%

Northwestern Alberta

102

91

59

108

British Columbia

39

16



66%

Northeastern Alberta

46

58

0

13

Manitoba

11

11

22

50%

Central Alberta

183

255

13

26

Saskatchewan

88

46

1

66%

Southern Alberta

49

45

26

34

0





0%

TOTAL

0

449



181

WC TOTALS

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada, September 12, 2012 Source:RigLocator

alberta, September, 2012 Source:DailyOilBulletin

AC T I V E

DOWN

T O TA L

AC T I V E (per cent of total)

Western Canada Alberta

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

Alberta

Aug 12

Aug 11

BITUMEN WELLS Aug 12

Aug 11

435

328



57%

Northwestern Alberta

0

0

8

9

British Columbia

10

19

2

34%

Northeastern Alberta

0

0

46

58

Manitoba

15

5

20

75%

Central Alberta

0

0

85

102

Saskatchewan

157

42

199

79%

Southern Alberta

10

2

0

0

WC TOTALS

1



1,011

1%

TOTAL

10

2

1

169

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oil & gaS inQuirer • OCTOBER 2012

11


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

A

s 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 development 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 developments—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 multiple 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 concluding 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 utilities (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 manufacturer 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 developers 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 housingcost increases. “Our homebuilders tell us that For t 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 gymnasium. The community offers more than 50 kilometres 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


Feature

ROAD to RAIL WItH PIPeLINe CaPaCItY tIGHt, truCKING aND raIL PICK uP tHe SLaCK

Photo: Photos.com

By godfrey Budd

14

OCTOBER 2012 • oil & gaS inQuirer


Feature

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 company, Berkshire Hathaway Inc., speculation varied widely as analysts sought to fathom the justification 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 Buffet took the helm in 1965. Was Buffett’s bottom-of-the-businesscycle 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 profit for Berkshire’s wholly owned railway subsidiary is up almost 16 per cent, and that “Warren Buffett’s railroad continued to contribute to Berkshire Hathaway as one of its most profitable businesses—moving coal, cars, corn and other freight.” Also in May, a 104-car train, which had originated on BNSF railway, was set to provide the 300,000-barrel-per-day Irving Oil refinery in Saint John, N.B., with its first 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 find shipping alternatives to pipe. Just after Labour Day, BNSF said it has expanded operational capacity in the Williston Basin area to meet the anticipated requirements 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 shipments of Bakken crude from 1.3 million barrels in fiscal year 2008 to 88.9 million barrels in fiscal 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 reflects 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 producer in the U.S. Bakken shale, said that Cushing was becoming increasingly obsolete, as 92 per cent of the company’s then-60,000barrel-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 refined 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 Canada In 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 connections to refineries 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, oil & gaS inQuirer • OCTOBER 2012

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• • • • • • • • • • • • •

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

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

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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 flows 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 flow 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 flexibility and better access to markets other than the saturated Cushing system afforded by rail shipments, shipping by rail morphed from a backup option to a key part of a twopart structure that now shapes shipping strategy at Crescent Point. The new strategy is related to the current price differential 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 reflect Brent values. “So you’re less impacted by price differentials,” says Stangl.


Feature

Oilsands operators are now looking to ship bitumen by truck and train to

Photo: Joey Podlubny

markets across North america.

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 locations for rail terminals that service southeastern Saskatchewan’s petroleum transport requirements. The effects of the constrained pipe capacity are rippling across the region’s oilpatch. Several trucking outfits in the region say business 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.

“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 Oilfield 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 finding and development activities that would otherwise have happened, and this has had a knockon effect 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 refineries, 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 truckers But 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 oilfield 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

oil & gaS inQuirer • OCTOBER 2012

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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 several times the cost of the 5,000-foot holes drilled in parts of the Saskatchewan Bakken. The region’s trucking businesses have seen an influx of competition 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 competitive,” says Lana Emde, director of administration at Brady Oilfield Services LP. The short-haul outfit benefited from hauling water for the fracking 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 heterogeneity, and this, to some extent, appears to translate into varying commodity attributes—as one might expect. But within quite a small area the difference in corrosion potential can be marked. “Tank trailers used to last about five years. Now, it’s barely one, and they have to be in the shop. Tanks seem to be corroding about five 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 transport 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 calculation. 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 offset the greater per-mile costs associated with hauling oil by railcar. “For every cube of heavy oil, which is typically 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.”


Feature

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

By Darrell Stonehouse, with notes from the DailyOilBulletin staff

H

ow important is developing a liquefied 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 producers 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.

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 securing 97,000 of those jobs. There will be $7.8 billion in GDP generated, 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 Pacific 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 billion 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, efforts are underway to find means to monetize the gas resource. But uncertainty over when new LNG export facilities will be built is slowing development. Just how prolific the tight gas plays are is illustrated by Quicksilver Resources Inc.’s first multi-well pad in the Horn River oil & gaS inQuirer • OCTOBER 2012

21


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

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OCTOBER 2012 • oil & gaS inQuirer

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 liquidsrich 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 gas Progress, 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, subject to further feasibility study. The study was expected to be completed by the end of August. Concurrent with the detailed feasibility study on the LNG facility, two major pipeline companies are participating in a detailed feasibility study to develop a pipeline solution

Photo: Joey Podlubny

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 constrained for testing purposes. These wells were drilled with 6,000to 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 current plan is to restrict the flow 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 expenditures in this low-commodity price environment. We have proactively 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 officer. “Our team has been working hard on the downstream part of this project, and we are making good progress on connecting


Feature

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-toliquids…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 engineering 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.

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 venture 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 operates commercial-scale GTL plants overseas. GTL may be one way to monetize North American gas reserves amid a continental gas glut. “The reduction in the number of rigs will not impede the derisking 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

Liard discovery adds to gas glut While 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 discovered 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 control 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 executive officer. “Our analysis indicates that the formation characteristics are remarkably consistent across the basin.” According to the company’s investor day presentation on the D-34K, 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, infrastructure already exists. All Apache wells are connected to a sales gas pipeline, there’s access to major incremental infrastructure, it’s OIL & GA S IN Q UIRER • O C T O B E R 2 0 1 2

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connected to the North American gas market and will have access to Asia Pacific via LNG. “Like all gas prospects, it is challenged by gas prices,” John Bedingfield, vice-president of worldwide exploration and new ventures, 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 first 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,” Bedingfield 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 liquefaction 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].”

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General News

Liquids glut taking shape in western Canada By paul Wells 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 different liquids bring in different prices depending on the composition and destination of the liquids. In the fi rst quarter of 2012, of 83 producers that trade in Canada and operate domestically and abroad, the average NGL the ethane that drives the petrochemical industry is quickly reaching saturation point, driving down

Photo: Joey Podlubny

prices for already embatt led natural gas producers.

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 liquids 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 liquids are created equal,” noted Geoffrey Vanderburg, managing director with Bryan Mills Iradesso. “Some of the more theatrical observers have said natural gas liquids are walking off the fracking cliff with natural gas. They believe the success of fracturing in liquids-rich shale gas plays has not only reduced the price of natural gas, it has also pushed down the price of natural gas liquids to the point where they’re no longer propping up natural gas to the point of profitability.” 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 continue 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

“Ethaneisbasicallyatthepoint whereitisbeingrejectedandleftin thegasstream.It’sacombination ofsupplythathasbeenfairly robust,andyou’vealsohadalotof thecrackersdownformaintenance andexpansion.” — Chris Theal, president and chief executive officer, Kootenay Capital Management Corp.

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 t hat t he 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 compa n ies w it h h igh l iqu ids volu mes. Companies with high liquids volumes will be hit to varying degrees depending on the volume and composition oil & gaS inQuirer • OCTOBER 2012

27


General News

of their liquids,” he said. “Condensate prices have been hovering around West Texas Inter mediate 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 product. 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.”

Producers report slight drop in expenditures 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 compared to $59.7 billion initially announced, a difference 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 expenditures 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 reallocated from natural gas to higher-return primar y 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 effectively reallocate capital and at the same time increase production confi rms the strength of Canadian Natural’s assets, our capital flexibility, the effectiveness 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 capital 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

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General News

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

company’s first-quarter earnings conference call in May. In light of the persistent weakness 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 spending to $365 million from the original 2012 budget of $465 million.)

Other companies with relatively large reductions in planned 2012 capital spending include ARC Resources Ltd., which cut spending by $160 million to $600 million 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 necessary for western Canadian producers to fully realize the potential value of Canadian oil,” Nunns said. “Taking into consideration the impact of ongoing differential 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 natural gas prices. But the situation isn’t all dire—of the 100 companies, 16 have bucked the trend and increased spending this year. O n top of t h at l i s t i s E nc a n a Corporation, which upped its budget by $600 million to US$3.5 billion; MEG Energy Corp., which increased its original budget by $380 million to $1.75 billion; 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 BULLETIN

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General News

Fewer wells, more metres drilled in first seven months O perator s ac ross Ca nada 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 still have no final status (oil, gas, dry or service). Of

metres from 11.45 million metres in the first 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 million metres.

Manitobawastheonlywesternprovincetoseeanincreaseinitsrig releasecount.Overtheseven-monthperiod,atotalof319wellshave beenrigreleased,upcloseto48percentfrom216ayearago. 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

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 rig 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 first 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 operators drilled 271 wells compared to 350 a year ago (off close to 23 per cent). B.C . operators dr i l led 24 wel ls 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

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British Columbia

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

Shell's Scotford refi nery. David Black is floating plans for a similar refi nery capable of processing

Photo: Joey Podlubny

550,000 barrels per day of bitumen on the B.C. coast.

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 interests should decide on the economic viability 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 worldscale oil refinery at Kitimat. The refinery will be state-of-the-art and designed specifically 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 finished 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 refinery 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 benefits to British Columbia and Canadians, benefits

in terms of jobs as well as government revenues,” Stringham added. “Refi neries, however, compete in a very competitive 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 Crownland zoned for industrial use. T he Enbridge pipelines are planned to run through the property. The refined fuels will be piped 40 kilometres 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 byproducts will be loaded onto ships at Kitimat if a bulk marine terminal is available 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 refinery. In prepared remarks, Black said that this proposed Kitimat refinery will feature four key advantages for British Columbia and Canada. First, the refi nery removes

BRITISH COLUMBIA WELL ACTIVITY WeLL LICeNCeS

aug/11

aug/12

128

58

WeLLS SPuDDeD

aug/11

aug/12

55

4

WeLLS DrILLeD

aug/11

aug/12

48

37

Source: Daily Oil Bulletin

oil & gaS inQuirer • OCTOBER 2012

33


British Columbia

“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 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 permanent employment over the past 10 years.” Also, he said, the province would benefit 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 comparable 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 communities—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 partners 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.”

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British Columbia

B.C. would gain most from oilsands pipelines, says report While Alberta will cash in the most on upstream oilsands development resulting from new projects spurred by additional 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 markets is by pipeline to Pacific port and super-tanker across the Pacific Ocean,” Canadian Energ y 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 experience the greatest economic impacts.” The study, the second in a series of three, examined alternative transportation modes and markets. CERI’s Regional Input-Output model is introduced in the study and used to calculate the potential economic impacts of construction and operation of two major proposed crude pipeline projects in western Canada: the Trans Mountain Pipeline E x pansion ( T M X ) and t he 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 additional 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 benefit

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 benefit from Northern Gateway construction and operation—$502 million over the next 25 years. Employment in Canada (direct, indirect 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 provincial and municipal governments in Alberta, and $83 million to provincial and municipal governments in Ontario. Additionally, construction and operation of Kinder Morgan Canada’s TMX

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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.

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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.

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35


British Columbia

pipeline will bring more than $8 billion in total additional GDP to the Canadian economy over t he 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 benefit from TMX construction

and operation, with $980 million over the next 25 years. In Alberta, the Upper Athabasca will see the most direct GDP benefit from TMX construction 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 benefits of the proposed pipelines, CERI noted that a “pipeline to tidewater on the Pacific Coast is the most economic way of reaching Asian refineries, which are capable of accepting both bitumen and synthetic crude oil.” — DailY oil BulleTin

B.C. report links fracturing to tiny earthquakes in northeast A 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 injection of fluids during hydraulic fracturing. The commission initiated the investigation after anomalous seismic activity 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 epicentres,” 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 seismicit y, and only one event was reported by Natural Resources Canada (NRCan) to have been felt at the surface.” Since 2009, there have been 31 earthquakes 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 completions have been performed in northeastern British Columbia with no associated anomalous seismicity. 36

OCTOBER 2012 • oil & gaS inQuirer

Brad Hayes, president of Petrel Robertson Consulting Ltd., said the report is a “scientifically rigorous and complete report” that investigated a number of seismic events that occurred in the Horn River Basin and detected by a Natural Resources Canada regional seismic/earthquakemonitoring network. “The events were of very low magnitude, 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 monitoring of the hydraulic fracturing operations showed almost all the energy and deformation 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 scientifically sound and proactive stance taken by Canadian regulators, such as the BC Oil and Gas Commission, to ensure the safe and effective 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 submission of micro-seismic reports, establishment of a notification and consultation procedure, studying the relationship of hydraulic fracturing parameters on seismicity, 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, detection, notification and consultation procedure,” 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 provide 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. — DailY oil BulleTin


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Northwestern Alberta/Foothills

Birchcliff production continues to climb

Photo: Joey Podlubny

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

Birchcliff Energy Ltd. reported record production during the second quarter, averaging 22,039 barrels of oil equivalent 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 i nvest ment s i n t he Mont ney/ Doig natural gas resource play continue to pay off,” president and chief executive officer Jeffer y 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. Complement ing t hat, Birc hc lif f has and continues to have top decile finding and development costs. We believe that, ultimately, the lowest-cost producer who has a significant, low-cost

inventor y of repeatable nat ural gas opportunities will create significant 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 approximately 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 operating costs per [barrels of oil equivalent],”

Tonken said. “The PCS gas plant will process 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 incremental 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 lowcost structure,” Tonken said. Year-to-date net income decreased to $4.15 million from $19.71 million during the first half of 2011. Bi rc hc l i f f generated f unds f low from operations in the second quarter 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 natural 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 average 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 t he second quar ter of 2012, Birchcliff’s activities on the Montney/Doig natural gas resource play included the drilling of eight (eight net) horizontal

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY AUG/11 AUG/12

WELL LICENCES

312

217

AUG/11 AUG/12

WELLS SPUDDED

268

182

AUG/11 AUG/12

WELLS DRILLED

239

163

Source: Daily Oil Bulletin

OIL & GA S IN Q UIRER • O C T O B E R 2 0 1 2

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Northwestern Alberta/Foothills

wells using multistage fracture stimulation 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 continuously 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 commence the completion operations on the seven-well pad,” Tonken said. Birchcliff believes that it has approximately 1,850 net future Montney/Doig horizontal 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 successful 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. — DailY oil BulleTin

Celtic exploration drilling pays off Celtic Exploration Ltd.’s production during the second quarter averaged 19,406 barrels 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 equivalent per day of production, was offl ine for approximately six weeks commencing in the latter part of May for planned turnaround maintenance operations, which negatively affected second-quarter 2012 average production. The company estimates that it currently 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 first quarter of 2012. And president and chief executive officer 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. 40

OCTOBER 2012 • oil & gaS inQuirer

“It was not something we were expecting 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 significant, 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 productive. As a result, Wilson said the company 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 continued 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 04-11-6020W5 (33.3 per cent working interest) that was drilled during the first quarter

Photo: Joey Podlubny

By paul Wells

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


Northwestern Alberta/Foothills

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 fracture 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 a r r, A lta., nor t h of Celt ic ’s Resthaven land block, the company had previously tested a vertical well located at 10-21-65-03W6 (100 per cent working 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 barrels per day and associated gas at a rate of 679,000 cubic feet per day, at a flowing 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 additional 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 production guidance of 29,900 barrels of oil equivalent per day. In addition, the company’s 2012 net capital expenditure program remains at $322 million.

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Northwestern Alberta/Foothills

Delphi cautious on gas price, but keeps drilling By 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 approximately 66 per cent hedged at an average floor 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 first quarter of 2012. The slight decrease in production compared to the first quarter was attributed to production downtime associated with scheduled maintenance at SemCAMS’ K3 sour natural gas processing facility and scheduled maintenance 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 primarily 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

Delphi'sthirdMontneywellwas producingapproximately800 barrelsperdayoffree condensate. 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 processing facility that offers the lowest possible cost structure and best natural gas liquids recovery efficiencies for the company. At Bigstone East, the 30-million-cubicfoot-per-day compression and dehydration facility was completed with start-up in mid-May. The new facility and infrastructure provide Delphi with the capacity to develop the existing Bigstone East land base and generate processing revenue 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 thirdparty 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 05-1460-23W5 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 production through the company’s 100 per cent owned compression and dehydration facility. Subsequent to completion and fracturing operations, the well was flow tested at an average rate of 16 million cubic feet per day at a flowing pressure of 6,170 kilopascals over the final 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 fluid hadn’t been recovered. (Load oil recovery stands at 72 per cent after the four-day flow period.) Delphi’s three extended-reach horizontal wells and existing vertical well tests have efficiently evaluated eight sections of land, and with competitor drilling activity all around the company’s 18 (14.75 net) sections, the remaining 30 net Montney horizontal locations identified at Bigstone East have been largely de-risked. — DailY oil BulleTin

Cold production to begin at Dawson, says Petrobank Petrobank Energy and Resources Ltd. has received regulatory approval to start the cold production phase on a two-well demonstration project at Dawson to condition the reservoir prior to initiating proprietary toe to heel air injection (THAI) production, 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 demonstration beginning in 2013, Chris Bloomer, chief operating officer, heavy oil, said 42

OCTOBER 2012 • oil & gaS inQuirer

in a conference call to discuss secondquarter results. “We believe that placing the two horizontal wells on cold production and producing conventional heavy oil will create a broader drawdown area along the horizontal well and is a potential for significantly faster start-up and ramp-up under THAI toe to heel air injection,” he said. Dawson is a different 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 without 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


Northwestern Alberta/Foothills alter our start-up processes in other projects, too.” At Kerrobert, THAI production continues to ramp up with field 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 company 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 balanced approach at Kerrobert, spreading the air injection across the whole field, generating a consistent burn on the combustion front, minimizing the drawdown and the opportunity for the breakthrough of combustion gas into the production wells, said John Wright, president and chief executive officer. “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 flow rates, which is what these wells are capable of, but not necessarily creating a full reservoir application of the combustion front that allows for the best recovery and the best sweep of the fire front itself.” At present, the company is injecting air at only eight per cent of full field 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 injection per day.”

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Northeastern Alberta

Land-use plan will cancel oilsands leases By Lynda Harrison

companies, 13 oil and gas companies, and one metallic and minerals company. Another roughly $30 million of taxpayers’ money will be spent implementing those recreational areas, bringing total costs for the plan to about $60 million, said Diana McQueen, minister of environment and sustainable resource development. She stressed her estimates were a rough guess and final costs will be determined after negotiations with the ousted energy companies are complete. Compensat ion w i l l be based on the amount paid for the leases, interest and development expendit ures. 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

the Mines and Minerals Act legislation to determine the amount of compensation 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 demonstrated 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 management frameworks, for air quality, surfacewater 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 cumulative effects management, said the government. Government will conduct a regional strategic assessment of what potential cumulative effects might be in the subregion of the southern Athabasca oilsands area where increased in situ activity is expected, said Bev Yee, assistant deputy minister of Alberta environment.

AUG/11 AUG/12

AUG/11 AUG/12

Photo: Joey Podlubny

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

T he A lberta government expects to shell out about $30 million to producers whose leases will be cancelled in areas set aside for conservation in northeastern Alberta, now that the province has approved the Lower Athabasca Regional Plan (LARP). Oi l a nd ga s compa n ie s w i l l be allowed to continue to operate in conservation and recreation areas while oilsands companies’ tenures will be cancelled 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 metallic and industrial minerals agreements, and four companies with petroleum and natural gas agreements—within conservation areas, a press conference heard. Within areas set aside for recreation, 16 energy companies hold tenure: six oilsands NORTHEASTERN ALBERTA WELL ACTIVITY AUG/11 AUG/12

WELL LICENCES

32

143

WELLS SPUDDED

126

122

WELLS DRILLED

123

125

Source: Daily Oil Bulletin

OIL & GA S IN Q UIRER • O C T O B E R 2 0 1 2

45


Northeastern Alberta

This will allow government to set thresholds specific to this region so it can eventually develop a sub-regional plan, said Yee. “Limits in these f ramework s 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 ongoing 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 portion 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 conser vation 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 forming of Wood Buffalo National Park in the 1920s, the conference call heard. The conservation areas will be managed to minimize or prevent new land disturbance. Land disturbance associated with exploration, development and extraction of in situ and minable oilsands, metallic and industrial minerals, and coal are not considered compatible with the management intent of conservation areas. Commercial forestry operations are “generally considered” incompatible with conservation areas; however, selected areas may allow a limited level of ecosystem forestry or natural disturbance-based vegetation management. No new oilsands, metallic and industrial minerals, or coal tenure will be sold in conservation 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 recreation areas and existing provincial parks for recreation, in accordance with existing policy. This includes all subsurface and surface 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 minimize impacts of activities on the natural landscape, historic resources, wildlife, fish and vegetation. This also includes renewing subsurface and surface dispositions, approvals and agreements for existing activities. Applications for new surface dispositions (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 commitment, subject to review through the current application and approval process. Applications for seismic programs associated with existing subsurface commitments will be reviewed through the current application and approval process.

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Northeastern Alberta

Existing surface or subsurface commitments 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 completion of a tailings management framework by 2013.

Southern Pacific updates STP-McKay project Bitumen production at Southern Pacific Resource Corp.’s STP-McKay thermal project is expected to begin in the fourth quarter of this year as operations are continuing to progress well with the circulation period advancing on all the first 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 following 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 startup 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 offloading capacity at two new rail terminals at Lynton, Alta., and Natchez, Miss. Both terminals, as well as approximately 500 railcars, are under construction and on schedule. — DailY oil BulleTin

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JUNE 2012 • oil & gaS inQuirer

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Central Alberta

Drill bit success helps Spartan grow production

Successful exploration at Keystone Pembina has Spartan's production up 45 per cent from the

Photo: Joey Podlubny

first quarter of 2012.

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 barrels 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 represented 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 production base characterized by high operating 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 participated in an additional four (1.0 net) horizontal 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 participated 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 production 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 company’s internal type curve. “With a full year of operations completed, 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 horizontal 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 t hese wel ls were at t he compa ny ’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 continuously 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 budgeting to drill 49 (46.6 net) Cardium horizontal wells during 2012. — DAILY OIL BULLETIN

CENTRAL ALBERTA WELL ACTIVITY AUG/11 AUG/12

WELL LICENCES

327

267

AUG/11 AUG/12

WELLS SPUDDED

334

278

AUG/11 AUG/12

WELLS DRILLED

339

259

Source: Daily Oil Bulletin

OIL & GA S IN Q UIRER • O C T O B E R 2 0 1 2

49


Central Alberta

Bonavista acquires Deep Basin gas properties 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.

Thetransactiondoubles Bonavista’slandpositionin theDeepBasin,adding 113,000netacres. The company has identified approximately 27 high-impact horizontal drilling locations offering the potential to significantly 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 offer 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 million 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 efficiencies 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 adjusting for land and seismic value of approximately $6.8 million. — DailY oil BulleTin

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Bonavista 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 effective 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 regulatory 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 exploration and development spending, and $25 million in net acquisition spending. The acquisition is consistent with Bonavista’s strategy of acquiring highquality, multi-zone oil and natural gas assets with significant low-risk development opportunities and extensive gathering, compression and processing infrastructure. At closing, production


Central Alberta

Fairborne cleans up balance sheet, focuses on Deep Basin Fairborne 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 anticipated to occur on or about Oct. 2, 2012. T he d i sposit ion a sset s i nc lude Fairbor ne’s g reater Ma rlboro a rea (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 oilfield where work is progressing 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 process). 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 fairway. With 4,500 barrels equivalent per day of current production post-transactions, a recently announced resource study of 131 million barrels of best-estimate economic-contingent resource attributable to its working-interest share in the Cardium Formation and nominal debt, the company will have the cash flow, balance sheet and inventory of opportunities to deliver significant 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 pershare growth in production, reserves, cash

flow and net asset value. The production base and upside potential of the remaining assets are represented by high working 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 bestestimate economic-contingent resource effective 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 first 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 condensate), 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. — DailY oil BulleTin

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51


Central Alberta

Hyperion plays up Niton-McLeod light oil play A 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 negotiations were then continuing. In August, the junior announced the deal as part of a

Within the Hyperion acreage are five Hyperion to drill one horizontal Cardium well every 135 days to earn a predetermined legacy, vertical wells that showed light oil earning block of land, with an initial spud productivity from reservoir rock that does not date of Oct. 15, 2012. A total of four earncontain a conglomerate facies. Most of these ing blocks are included in the farm-in, three wells were shut in years ago and produced of which have associated option lands that relatively small volumes of oil, but demonrequire another three wells to fully earn (one strated the potential for horizontal drilling. for each option block). The tight but thick portion of the reservoir contains the majority of the oil in place and is Added to the land Hyperion picked up in November 2010, the new undeveloped land Hyperion’s target within the Cardium. deal and farm-in makes for a total 35,680 Hyperion has drilled one net horizontal (32,515 net) acres of Cardium rights in the well in the area that is exceeding expectaNiton-McLeod area, with an average 90 per tions. The well was drilled adjacent to a cent working interest. The total petroleum legacy well that produced material amounts Hyperion expects the combined, initially in place, effective Aug. 15, 2012, is of light oil and solution gas (about 100,000 internally estimated by Hyperion to be up barrels of oil and 400 million cubic feet of undeveloped land deal and to 171 million barrels of light oil, with a prigas). Despite reporting localized pressure farm-in will add up to 177 (158 net) mary recovery factor of 12.5 per cent. depletion from the vertical well, the horizonCardium light oil wells to its Hyperion expects the combined, undeveltal is continuing to produce about 60 barrels oped land deal and farm-in will add up to 177 per day in its fifth month of production, mandrilling inventory. agement said. (158 net) Cardium light oil wells to its drilling broader plan, without naming the senior proinventory, bringing the junior’s total inventory As well, management said the Nitonducer with which the farm-in portion of the of potential wells to 215 (196 net) Cardium McLeod land base is situated in a network deal was signed. In this year’s first quarter, light oil horizontal drilling locations. of solution gas infrastructure near underHyperion produced an average 1,300 barrels In a press release, Hyperion said the used gas processing facilities. An oil pipeline of oil equivalent per day (about 60 per cent tie-in near the south end of Hyperion’s asset Niton-McLeod area contains substantial crude oil and natural gas liquids). deep-well control over the lands, which has base could reduce future operating costs by The deal began with land Hyperion allowed the company to reduce Cardium eliminating trucking, management said. The September Expertec Oil &in Gas InquirerCardium in Niton-McLeod is relatively shalacquired in November 2010, covering 10,080 geological risk.ad Thefor Cardium this acreage (9,864 net) undeveloped acres of Cardium exhibits typical Cardium reservoirxcharacterlow and will contribute to below-average CMYK press res pdf: 7.0625” 2.25” light oil–prospective Crown lands in the istics, including high-quality, water-free light costs for drilling and completion compared Niton area. Then, in this year’s second quaroil, according to management. to other Cardium plays, the company added. There15,040 is annetadditional 1/8” has bleed included in the tiff file. ter, the junior acquired another Hyperion analyzed two Cardium Management said at least two wells will you use prospective, the tiff file in your publication, put a study 1 pton blackbeborder it. quarter, with drilled in around this year’s fourth acres,If also Cardium through a cores, conductedplease a petrophysical Crown land sale and smaller deals. Hyperion another two planned for the first quarter of drill cuttings from legacy Cardium well2013, in the Niton-McLeod area. Hyperion paid about $4 million in all for this acreage. bores in the area and said the results suggest Then, earlier this month, Hyperion Cardium reservoir characteristics, including is also considering financing alternatives to closed a deal with a senior producer to access permeability, porosity, thickness and water further accelerate development, the com10,560 (7,611 net) Cardium acres under a saturation, are consistent with other successpany said in its news release. rolling-option farm-in. This deal commits ful Cardium horizontal programs. — DAILY OIL BULLETIN

52

O C T O B E R 2 0 1 2 • OIL & GA S IN Q UIRER


Southern Alberta

DeeThree boosts budget to $110 million

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 primarily 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 capital spending totalled about $30 million and included the drilling of seven (6.8 net) wells with 100 per cent success. The company 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 quarter, and DeeThree now has 39 sections of Crown land that it believes to be highly prospective for Exshaw potential in addition to its extensive freehold land in the area. The 2012 drilling program has successfully 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 currently installing an amine plant to handle CO2 from solution gas. Also, it is designing 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 barrels equivalent a day (76 per cent oil and natural gas liquids) on the first location

AUG/11 AUG/12

AUG/11 AUG/12

DeeThree is enjoying success in proving up its Alberta Bakken lands near Lethbridge,

Photo: Joey Podlubny

with two rigs drilling in the play.

After already reaching its year-end production goal of 5,000 barrels of oil equivalent 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 southern 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 significant 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. SOUTHERN ALBERTA WELL ACTIVITY AUG/11 AUG/12

WELL LICENCES

110

67

WELLS SPUDDED

113

79

WELLS DRILLED

122

84

Source: Daily Oil Bulletin

OIL & GA S IN Q UIRER • O C T O B E R 2 0 1 2

53


Southern Alberta

and 222 barrels a day (100 per cent oil) on a fi ve-day test on its most recently completed 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 natural 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 significant 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, reporting 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 potentially 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 addition 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 barrels. Total proved-plus-probable reserves were 4.9 million barrels of oil equivalent (95 per cent oil), booked as a result of the first six-well drilling program in 2012. Average proved-plus-probable reserves of 263,000 barrels per well were booked for the first six wells drilled in 2012. — DailY oil BulleTin

Crew Energy Inc.’s second-quarter production jumped 72 per cent thanks to successful drilling programs in the Princess, Alta., Septimus, B.C., and Kobes, B.C., areas, combined with the acquisition of Caltex Energy Inc. P r o duc t ion du r i ng t he qu a r te r increased to 28,192 barrels of oil equivalent per day (52 per cent liquids) from 16,443 barrels per day for the comparable period in 2011. First-half output was 29,286 barrels per day versus 16,028 barrels per day during the first six months of 2011. The company noted that secondquarter 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 production 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 curtailment 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 company completed 12 (11.3 net) wells and recompleted 20 (19.1 net) wells within t he Princess, L loydminster, on t he 54

OCTOBER 2012 • oil & gaS inQuirer

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 predominantly in the Princess and Septimus areas. Crew also closed minor dispositions of non-core undeveloped lands in central Alberta for $4.3 million. Ac t iv it y at Pr incess focused on the completion and tie-in of the company’s drilling program. By the end of the second quarter, a total of 15 wells had been brought on production 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 Crew's second-quarter production climbed 72 per cent year over confirmed the extension of year, driven by growth in its Pekisko oil play. the Pekisko oil trends and further supports Crew’s long-term invenPekisko N pool production rate 110 per tory of drilling locations. Production avercent above pre-waterflood conditions, and aged 6,850 barrels equivalent per day for the Pekisko K pool production rate 80 per the quarter, with production impacted by cent above pre-waterflood conditions. spring breakup as well as a turnaround at The company has initiated injection the company’s West Tide Lake facility. into three new Alderson waterfloods and Crew says its Tilley waterfloods conexpects to have two West Tide Lake watertinue to show positive response with the floods on injection in the third quarter,

Photo: Joey Podlubny

Princess play drives Crew results


Southern Alberta

— Daily Oil Bulletin

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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 remainder 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 drilling program at Lloydminster and drilled one (one net) oil well in the second quarter. The company plans to drill an additional 10–15 wells and continue with the successful recompletion program targeting secondary hydrocarbon zones within existing wellbores. Crew says that these workovers have very strong economics 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 immediately following the initial completion. The company says it is proceeding 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-i nc h Sept i mus/ Tower pipel i ne, which is now connected to the Septimus gas plant. Gathering system pressures were reduced by approximately 1,400 kilopascals, resulting in a three-millioncubic-foot-per-day increase in production (27 barrels of liquids per million cubic feet). Crew also has two (two net) Montney horizontal wells drilled in the first quarter 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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OIL & GA S IN Q UIRER • O C T O B E R 2 0 1 2

55


Southern Alberta

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Angle Energy Inc. achieved record production 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 condensate 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 million 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 fracturing in 2012 compared to oil- or propanebased 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 liquidsrich natural gas and Cardium oil plays and, to a lesser extent, on the Cardium oil play in the Ferrier and Edson areas. — Daily Oil Bulletin

56

O C T O B E R 2 0 1 2 • OIL & GA S IN Q UIRER


Saskatchewan

Renegade finds growth across Saskatchewan

Saskatchewan. Conditions in westcentral Saskatchewan and southeastern Saskatchewan have improved dramatically since the end of July, and Renegade is currently in its full-scale drilling program. Renegade’s current production is approximately 4,200 barrels per day, based on field estimates, and management anticipates being in a position to successfully execute on its previously announced capital program for the year. Production in the second quarter averaged 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) southeastern Saskatchewan wells. In southeastern 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 production 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 constraints. The well was drilled as a singleleg 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 quarter, Renegade now anticipates moving closer to a full-scale development plan in the area. Renegade is currently in the process 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

AUG/11 AUG/12

AUG/11 AUG/12

Photo: Gerald Ford

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

Renegade Petroleum Ltd. had record average production in the second quarter and its 96 per cent light oil weighting and hedging allowed the company to post netbacks 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 WELL ACTIVITY AUG/11 AUG/12

WELL LICENCES

425

282

WELLS SPUDDED

440

323

WELLS DRILLED

462

344

Source: Daily Oil Bulletin

OIL & GA S IN Q UIRER • O C T O B E R 2 0 1 2

57


Saskatchewan

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 continues 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 horizontal wells. Total drilling and completion cost estimates for the program are expected to be $10 million.

I n we s t- c e nt r a l Sa sk atc he w a 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 westcentral 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 initiating 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 waterflood in the Dodsland pool, and management expects to begin water injection into the field by late 2012. — DailY oil BulleTin

Novus expands Viking acreage 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 successful 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 development 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 first half of 2012, Novus drilled 26 (26 net) wells, all of which were Viking horizontal oil wells in the greater Dodsland area. Sixteen (16 net) wells were completed 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 flows 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 continued to materially decrease, falling to $9.96 per barrel in the most recent quarter, 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 density. This already-significant opportunity base does not reflect the ability to downspace from eight to 16 wells per section or the future potential to waterflood the reservoir. Novus believes that the development of the Viking resource is in its early stages, and that there is further significant upside to recovery factors by applying secondary recovery methods. The 625 Viking locations do not include potential locations on the company’s recently acquired Alberta Viking lands. — DailY oil BulleTin

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OCTOBER 2012 • oil & gaS inQuirer

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Technology News

Water-based fluid system improves shale drilling Baker Hughes has introduced the LATIDRILL water-based drilling fluid system to help operators enhance wellbore quality and increase drilling efficiency in extended lateral sections in unconventional shale plays. The LATIDRILL system is more environmentally favourable than oil-based fluid systems and offers the hole stability and superior drilling speed and performance 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 hydration typically associated with the use of a conventional water-based fluid.

Clay hydration can lead to sloughing shale and borehole enlargement. T he L AT I DR I L L s y stem uses a pro pr ietar y wellbore stabilizer t hat m e c h a n i c a l l y m a i nt a i n s w e l l b or e integ r it y and limits non-productive t i me a ssoc iated w it h hole stabi l it y issues. By del iver i ng a more stable wellbore in long horizontal sections, the L ATIDR IL L system reduces pore pressu re t ra n sm ission, m i n i m izi ng or even eliminating mud losses. The L ATIDR ILL system improves drilling ef f ic ienc y w it h spec ia l ly pu r posed lubricants t hat coat metal surfaces, drill cuttings and formation walls to reduce torque and drag, particularly

i n h igh-pressu re/ h igh-temperat u re 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, disposal 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.

Schlumberger introduces new reamer to cut drilling times Schlumberger Limited has announced the release of the Rhino XC on-demand reamer. This next-generation reaming tool provides unlimited activation of the flow actuation system to reliably enlarge boreholes. Building on R hino XS hydraulically 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 eliminates 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 pilothole 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 deepwater environments, this provides huge savings for our customers by enabling faster and [more] reliable activation.” The Rhino XC reamer is effective 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 offshore Norway, one North Sea customer 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 ondemand capability to close reamer flow to the annulus. The Rhino XC was run, allowing cycling of the reamer multiple times during the course of the run, simply by changing the pump flow 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 project management and information solutions to customers working in the oil and gas industry worldwide. Schlumberger Limited has principal offices in Paris, Houston and The Hague.

Portage College opening Pipeline Training Centre Portage College is once again expanding 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 equipment 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, operation, 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. oil & gaS inQuirer • OCTOBER 2012

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Technology News “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 industry,” 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, boardgoverned college operating under the Alberta Colleges Act. The college has been serving the region for over 40 years and is the first choice for learners in northeastern Alberta. Portage boasts nine campus locations, which are strategically located throughout the region.

VeruTEK and Wavefront combining green chemistry with fluid injection technology VeruTEK Technologies Inc. and Wavefront Technology Solutions Inc. have executed a partnership agreement to apply their chemical solutions and fluid delivery technology 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 env i ron menta l ly f r iendly f luids, delivered by Wavefront f luid-pulsing technology, provides tremendous opportunity for improved production in many formations. Unde r t he te r m s of t he ag r e e ment, Wavef ront may ident i f y a nd engage prospects interested in a joint Ve r uT E K / Wa v e f r o n t s o l u t i o n f o r enhanced oil recovery, well stimulation and environmental applications. Wave f r ont w i l l r e s e l l c o -br a nde d VeruTEK products.

Additionally, VeruTEK may introduce Powerwave and Primawave as highly differentiated 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 confident alliances will bring greater exposure to the fieldproven technologies of both companies, as well as supplementary revenue streams,” said Davidson. “VeruTEK has experienced excellent results working with Wavefront technology, 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 officer Dan Socci. VeruTEK is a green chemistry company that provides high-performing chemical solutions to the oil and gas and environmental industries. The company has developed and patented innovative a nd env iron menta lly f r iendly gasgenerating chemicals to enhance formation permeability and hydrocarbon recovery. The VeruTEK technology platform addresses applications including production stimulation, EOR and environmental remediation. Wavefront is a technolog y-based leader in fluid injection technology for improved/enhanced oil recovery and groundwater restoration.

CanElson announces contract for new $8-million bi-fuel drilling rig 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 fleet 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 significant amount 60

OCTOBER 2012 • oil & gaS inQuirer

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 first new build bi-fuel rig (Rig 32 in CanElson’s fleet) 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 approximately $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 producers there. Rig 33 is scheduled for delivery 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).


Technology News Pending a signed contract, construction of Rig 36 is possible in the first quarter of 2013. CanElson continues to require committed contracts prior to full assembly of additional rigs. CanElson’s capital program will be financed out of cash flow and existing debt facilities with financial capability for

additional growth and maintaining dividend payments. CanElson operates contract drilling rigs in Canada, the United States and Mexico for oil and natural gas exploration and development companies. CanElson also assembles new drilling rigs at a facility in Nisku,

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

U.S. Department of Energy advances research on methane hydrates 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 offshore— including under the Arctic permafrost and in ocean sediments along nearly every continental shelf in the world. The announced projects build on the completion of a successful, unprecedented test earlier this

year that was able to safely extract a steady flow 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 efforts as part of President Obama’s all-ofthe-above energy strategy could potentially yield significant 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 understanding 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 substantial, and the accumulations that can be explored for and produced using existing technologies are potentially numerous, significant research remains to analyze the role of gas hydrates in the natural environment; demonstrate that gas hydrates can be produced commercially in an environmentally responsible manner; and further assess resource volumes, particularly in deepwater settings.

See the heart of the oilsands like you’ve never seen it before!

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oil & gaS inQuirer • OCTOBER 2012

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TOG E T HE R WE CAN

For over 10 years MaXfield has quietly been gaining the expertise and experience to handle your next project. From custom vessels to structural steel, piping and modular packaged equipment, MaXfield is now your one-stop shop for industrial fabrication.

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Oil & Gas Inquirer October 2012  

Road to Rail - With oil pipeline constraints, trucks and trains are picking up the slack