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Table of Contents

Keeping readers regionally informed

F E A T U R E S

12

Freeze-frac and flood pulse by Graham Chandler

Made-in-Alberta improved oil recovery techniques can draw more crude from conventional reservoirs

18

Knocking out NOX

33

One billion barrels and counting

by James Menzies

In 2010, heavy truck engines will be cleaner thanks to a pair of competing technologies—but which choice is best for the oilpatch?

Imperial Oil just produced its billionth barrel of bitumen from its Cold Lake project, a historic achievement

With all the uncertainty about the economy, look for our Recession to Recovery logo for coverage on how companies are handling the downturn, preparing for the rebound, and, in some cases, even thriving. 6

DECEMBER 2009 • OIL & GAS INQUIRER


Table of Contents

R E G I O N A L

25

N E W S

British Columbia

41

• B.C. land sale takes in $370M, the sixth-

• Drilling days per well rise despite

largest bonus on record

steep overall activity downturn

• Pipeline companies and contractors

• Oilpatch lenders work with junior

appear in court over 2007 oil spill

31

49

44,500 boe

Northeastern Alberta

• Saskatchewan's October land sale

• Husky prepares to drill new wells at its Tucker oilsands project • Epcor and Suncor sign water deal

nets $32.4M

53

Quebec electric car battery plant

• Alberta extends its bitumen royalty-inkind program

Central Canada • French company invests $120M in

Central Alberta • Berens Cardium well tests 270 barrels

Saskatchewan • PetroBakken pushes daily output to

generate meager revenue

37

• Electric cars may end oil age

55

East Coast • Korea’s KNOC buys Harvest for $4.1B,

per day

including Atlantic refinery

57

International • Royal Dutch Shell cuts 5,000 as Q3 net profit falls by 62 per cent

I N

from all the staff at

producers to get through the downturn

Northwestern Alberta/Foothills • Alberta’s Crown land auctions in October

33

Southern Alberta

Merry Christmas

E VE R Y

I S S U E

10 Statistics at a Glance

61

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Political Cartoon

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OIL & GAS INQUIRER • DECEMBER 2009

7


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Editor’s Note Vol. 22 No. 1 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com

Mike Byfield | mbyfield@junewarren-nickles.com

Publisher Agnes Zalewski | azalewski@junewarren-nickles.com

Recession to recovery, really

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Low natural gas prices and new completions technology are driving deep changes in the western Canadian patch. The freeze-frac and flood pulse techniques highlighted in this month’s cover article represent that trend. At long last, we’re seeing an effective push to draw a higher percentage of conventional crude from known reservoirs. In fact, oil and gas opportunities of many types may well prove richer than ever before within the fairly near future. What do I, or anyone else, know for sure? Frankly, nothing. But here are some enticing signals that can be heard these days from pretty credible sources: Virtually all producers are gradually girding themselves to tackle thousands of known oil and gas pools, applying multi-stage fracs to horizontal wells along with other refinements. Although they’re hurting financially due to low gas prices and misgovernment, these firms will continue to milk value from the wealth of public data available for the Western Canadian Sedimentary Basin. Decline rates from horizontal wells in some American shale gas plays are rumoured to be more discouraging than initially expected by many producers. These are early days, when a lot of wells remain on tight-hole status, but the reports are persistent. Producers who’ve bought large oil-prospective acreage in Saskatchewan (i.e. the Bakken and Shaunavon plays) typically must drill that land within two or three years. Oil prices have recovered nicely, drilling rigs are available, and capital spending is being quietly expanded. I’m told it’s hard to raise even modest capital for promising new petroleum technology. Why? Because many experienced service and supply investors believe that the share values of existing companies will inevitably spurt upward within a year or two. Why gamble on unknown technology when easier pickings are everywhere? Historically, natural gas prices usually go against the trend expected by most producers. The reason is simple and ironic. If most producers anticipate a long spell of low prices, they drill less. When producers don’t drill, gas supply tightens. Prices then rise more quickly than expected. If I have a long-term concern, it’s the barriers to recovery in Alberta’s shallow gas and coalbed methane sectors. The burden of provincial royalties and regulations needs to be reviewed and reformed to whatever degree proves necessary. Politically, the Stelmach Conservatives who made the mistakes in the first place are not likely to undertake these corrections with much enthusiasm. JuneWarren-Nickle’s Energy Group—Canada’s primary publisher in the petroleum business—has been producing articles under its “Recession to Recovery” theme. Recovery will happen, and hopefully we’ve already bottomed out. As Bill Andrew, CEO of Penn West Energy Trust, likes to predict, a generation of unprecedented energy opportunities is shaping up in western Canada.

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Industry outlook for 2010

If you know an admirable person to profile in

After producers and service companies slogged

On The Job—he or she may be a veteran or

through an exceptionally tough 12 months in

apprentice, field or shop, wise or a little crazy—

Made in Canada The opinions expressed by contributors to the 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.

2009, industry analysts are weighing the impact

please give me a call at (780) 944-9333, or

of higher oil prices, ongoing weakness in the

email mbyfield@junewarren-nickles.com.

natural gas market, and new technologies over

In fact, feel free to sound off about any

the coming year.

concern at all—that’s a personal invitation.

OIL & GAS INQUIRER • DECEMBER 2009

9


Stats

FAST NUMBERS

$350 million

AT A GLANCE

Capital spending budgeted by EnCana Corporation for the Horn River Basin in 2010

$400-500 million EnCana’s 2010 capital budget for the Cutbank Ridge/Montney play

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

T O TA L

MONTH

OIL

GAS

D RY

SERVICE

T O TA L

Nov 2008 Dec 2008 Jan 2009

273 496 156

1,075 1,793 606

136 200 96

1,484 2,489 858

Nov 2008 Dec 2008 Jan 2009

594 917 248

1,313 2,380 813

142 173 70

45 137 47

2,094 3,607 1,178

Feb 2009 Mar 2009 Apr 2009

116 321 111

899 979 344

120 317 140

1,135 1,617 595

Feb 2009 Mar 2009 Apr 2009

269 433 111

1,060 1,121 342

113 165 61

36 86 12

1,478 1,805 526

May 2009 Jun 2009 Jul 2009

71 36 79

187 143 178

53 42 77

311 221 334

May 2009 Jun 2009 July 2009

71 177 79

187 211 31

46 45 6

35 27 3

339 460 119

Aug 2009 Sept 2009 Oct 2009

101 146 132

212 155 160

80 78 77

393 379 369

Aug 2009 Sept 2009 Oct 2009

250 146 331

267 155 196

36 45 32

37 9 12

590 355 571

Wells Drilled In British Columbia

Wells Drilled In Saskatchewan

Source: B.C. Oil and Gas Commission

Cumulative to November 6, 2009 Source: Saskatchewan Energy & Resources

MONTH

WELLS DRILLED

C U M U L AT I V E *

Nov 2008 Dec 2008 Jan 2009

61 79 125

840 919 125

Feb 2009 Mar 2009 Apr 2009

117 75 33

242 317 350

May 2009 Jun 2009 Jul 2009

26 19 34

376 395 429

Aug 2009 Sept 2009 Oct 2009

36 38 25

465 503 528

* from year to date

OIL

GAS

OTHER

D RY

T O TA L

Vertical Wells

Lloydminster Kindersley Swift Current Estevan

340 72 35 45

6 29 175 0

24 6 3 18

8 29 9 38

378 136 222 101

33 16 61 502

0 0 0 0

0 0 0 0

0 0 0 0

33 16 61 502

373 88 96 547

6 29 175 0

24 6 3 18

8 29 9 38

411 152 283 603

Horizontal Wells

Lloydminster Kindersley Swift Current Estevan Total Wells

Lloydminster Kindersley Swift Current Estevan

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S P O T P R I C E S at AECO trading hub in Alberta

GAS STOR AGE

Source: Natural Gas Exchange Inc.

Source: U.S. Energy Information Administration

5.0

in the United States

4.00 $3.77/GJ Total vol.: 1,921 TJ Transactions: 199

4.5 4.0

3.75

3.83 Tcf Year ago: 3.49 Tcf 5-year avg: 3.41 Tcf

3.5 3.0

Oct 21

Oct 28

Nov 4

Nov 11

3.50

Nov 18

Oct 16

Oct 23

Oct 30

Nov 6

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada November 13, 2009 Source: Rig Locator

Alberta October 2009 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada Alberta British Columbia

Manitoba Saskatchewan WC Totals Northwest Territories

AC T I V E

177

409

586

30%

36

74

110

33%

3

4

7

43%

70

65

135

52%

286

552

838

43%

0

2

2

0%

OIL WELLS

Alberta

GAS WELLS

Oct 09

Oct 08

Oct 09

Oct 08

Northwestern Alberta

19

114

31

379

Northeastern Alberta

9

31

0

16

95

132

24

255

9

37

105

284

132

314

160

934

Central Alberta Southern Alberta TOTAL

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada November 13, 2009 Source: Rig Locator

Alberta October2009 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

AC T I V E

Western Canada 316

443

759

42%

British Columbia

18

20

38

47%

Manitoba

7

2

9

78%

115

65

180

64%

456

530

986

46%

0

2

2

0%

Saskatchewan WC Totals Northwest Territories

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

Alberta

Alberta

Nov 13

BITUMEN WELLS

Oct 09

Oct 08

Oct 09

Oct 08

Northwestern Alberta

0

0

1

16

Northeastern Alberta

0

0

9

29

Central Alberta

6

66

61

58

Southern Alberta

0

49

0

0

TOTAL

6

115

70

103

OIL & GAS INQUIRER • DECEMBER 2009

11


BLANK PAGE FOR DUPLEXING


Feature

Freeze-frac and FLOOD pulse Made-in-Alberta improved oil recovery techniques can draw more crude from conventional reservoirs by Graham Chandler

N

orth America’s largest recorded earthquake hit Alaska 45 years ago. As expected, the quake briefly but significantly stimulated oil and gas production in the Western Canadian Sedimentary Basin. But Tim Spanos, a physics professor at the University of Alberta, noticed an unusual timing in the increased output. Based on rates of wave propagation, “you should have seen the changes in Alberta 24 to 48 hours after the quake, not three or four days,” says Brett 12

DECEMBER 2009 • OIL & GAS INQUIRER

Davidson, CEO of Edmonton’s Wavefront Technology Solutions Inc. After several years of researching this phenomenon, Davidson and Spanos teamed up with Maurice Dusseault, a geological engineering professor, to create an improved oil recovery process called Powerwave. Improved recovery technologies of this calibre, notably multiple-stage hydraulic fracturing in long-reach horizontal wells, have already shaken up the natural gas industry and brought tight oil reserves

within reach. Field innovations may soon dictate re-evalutions of classic oilfields as well. According to the Canadian Association of Petroleum Producers, western Canadian conventional oil reserves stood at a little under three billion barrels at the end of 2007. That estimate, however, is based largely on vertical drilling technologies and simple secondary recovery through waterflood. Wavefront’s Powerwave technology is not fracing, but it serves a similar purpose:


Feature

opening up more of a formation in order to get more oil out. Usually employed with traditional waterfloods, Powerwave pulses the water at the end of its injection stream, at sub-hertz frequencies, sending out waves at velocities of 80 to 300 metres per second to expand pores and increase permeability. “What we’re introducing is this big fluid wave, much like your heartbeat,” explains Davidson. “Your heart beats, it sends out this large volume of fluid at a high rate, and that allows our vascular

[blood vessels] to dilate [i.e. expand].” Another analogy the Wavefront CEO uses is a garden hose. “You have a steady stream coming out of the end. When you put a kink in it, the flow stops,” he says. “You are storing energy; the hose acts like an accumulator.” When the hose is unkinked, the water flow will surge for a while, then settle back to its normal stream rate. Powerwave essentially provides a more even distribution of the injected fluid in

the reservoir to increase sweep efficiency. “Water travels the path of least resistance,” says Davidson. “So when I inject it in the ground it doesn’t go in as this wall of water; it goes in as discrete ‘fingers.’ Those fingers are the path of least resistance.” Again applying the physiological analogy, he says if you open up your hand and saw your fingers, “in between your fingers is the oil that’s missed by the water I’m injecting.” The pulse momentarily expands the pore spaces to accept the accelerated fluid. OIL & GAS INQUIRER • DECEMBER 2009

13


Feature Photo: Triple D Technologies

Darrell Kosakewich, president of Triple D Technologies (inset), has built a horizontal well bore frac technology powered by the expansion of water when it freezes.

A frac permanently alters the reservoir rock. In contrast, Powerwave is “open, close, open, close,” Davidson says. “You are allowing that fluid to push the oil out. You’re getting to stranded oil.” In fact, waterflood pulsing is seldom combined with traditional fracturing methods. “When you frac, you’re really adding in an extreme path of least resistance. Most fluid will want to go up that frac and it will be even harder to divert water away from it,” the Wavefront co-founder explains. The earliest field-wide application of Powerwave for production enhancement was undertaken at Isley, Alta., with Wascana Energy Inc. about 10 years ago. The pilot project succeeded. “Oil production increased by about 37 per cent while water cuts were lowered by as much as 20 per cent,” says Davidson. Since then, Powerwave has been effective over a broad range of reservoirs including carbonate rocks, unconsolidated sand, consolidated sands, oil shales, and diatomites says Davidson. The pulsing technology adapts to differing permeabilities according to bleed off rates. “The bleed-off 14

DECEMBER 2009 • OIL & GAS INQUIRER

rate in the high permeability is much faster than the low,” Davidson says. “So basically you have to design your implementation with that in mind.” It has been applied to previously fractured systems; and demonstrated in viscosity ranges from 8°API to over 40°API. Some companies have asked Wavefront to improve recovery from natural gas wells. “Our technology will work in a gas stimulation, but it won’t work for a field-wide gas stimulation,” Davidson says. “Methane is so compressible that, if I pressurize a field, I’m really just compressing the gas [rather than dilating the reservoir rock pores].” Typically, Powerwave is applied when water cuts start increasing. “We’re dealing with water cuts of upwards of 98 per cent per barrel of fluid produced. That means for each barrel of fluid produced you have 98 per cent water and 2 per cent oil,” says Davidson. “Using the results from the eastern Alberta Powerwave project, the nominal cost per barrel of incremental oil recovered is $4.48.” The technology added about 10 years to the field’s productive life.

Powerwave is catching on. “We currently have programs running in Alberta [a recent addition was the Pembina field, which after 55 years has produced just 20 per cent of oil in place], Alaska, Michigan, Ontario, Mississippi, Texas, California, and Saskatchewan,” says Davidson. Wavefront recently signed a deal with Pemex, Mexico’s state-owned petroleum monopoly. Next may be steam f looding, says Davidson, which has its own unique considerations. “When it comes to injecting the steam, it too goes the path of least resistance. If you can pulse the steam, you are going to get better uniform coverage of the reservoir.” Wavefront is talking to potential clients now—there’s no shortage of possibilities, thanks to the popularity of steam assisted gravity drainage (SAGD) in the deeper oilsands. F r o m s t e a m t o i c e . Tr i p l e D Technologies, another firm based in Edmonton, has come up with a groundbreaking technology that harnesses the nine per cent expansion of water as it freezes. This immense force not only


Photos: Triple D Technologies

Feature

Triple D has used Technicoil's hybrid rigs to insert a carbon dioxide–driven freezing loop downhole, generating 5 to 10 metres of radial fracturing around the well bore.

bursts water pipes but routinely carves slabs of rock off mountain sides. Darrell Kosakewich, Triple D’s president, came up with the brainwave when he froze a lump of coal and found it shattered. Four years ago, the company allied itself with Pace Industrial Inc., designing and testing downhole refrigeration technology. Their method uses concentric coiled tubing,

Temperatures of -45.5 degrees Celsius at 105 pounds per square inch gauge generate compressive forces from the ice expansion estimated at about 2,400 to 4,000 pounds per square inch. To avoid breakage of the well casing, the freezing is applied through a slotted liner or a perforated zone. The Triple D president says the CO2 mechanism is

[Triple D Technologies] pegs its frac cost at about 25 per cent of traditional frac methods. or jointed pipe and coiled tubing, to circulate liquid CO2 along a water-filled horizontal wellbore. The CO2 flows through a central refrigerant tube, then boils off and returns to surface through the annulus. As the water freezes in the wellbore, its expansion cracks the rock formation. The process typically fracs between 5 and 10 metres radially around the wellbore, Kosakewich says, “and 85 per cent of your production is near the wellbore.”

normally placed between packers at the liner perforation point, enabling the operator to freeze that section. “Typically on a workover, we would move Technicoil’s hybrid rig on a hole to pull out the existing tubulars and then run in our closed loop string of 2 7/8 inch,” says Kosakewich. “We’d fill the hole with produced water. Without moving the service rig off, we would run in our refrigeration coil with our bottomhole assembly.”

Then the liquid CO2 is pumped down, with vapour returns either flared or recirculated. “This process runs continuously for 24 hours, or intermittently if multiple freeze thaws are required,” continues Kosakewich. “Once the frac is complete, the four-hour thaw cycle starts, either naturally or through hot oil circulation.” Once thawed, the installation is reversed and the production string is reinstalled. Field applicat ions to date have included fracing a coalbed methane well, with a disappointing result. After the frac, water production increased, normally a precursor to increased gas flow in a coalbed methane well. In this case, however, a frozen flow back line went unnoticed, which choked off the water flow pre-maturely. “This stoppage may be the reason why gas production didn’t increase,” Kosakewich says. Typically, he says, “the presence of water in a formation is our friend—mature fields, coals and sandstones and shales.” Substantial interest remains, however: the next test will be on a non-producing well in an undisclosed white shale location. OIL & GAS INQUIRER • DECEMBER 2009

15


Photo: Triple D Technologies

“The white shale has the same characteristics as Horn River formations,” says Kosakewich. Before-and-after logging of the test well should reveal much about how the freeze frac would perform there. “Horn River wells are expensive, and I don’t think anyone wants to experiment with them [directly],” the Triple D CEO notes. His company pegs its frac cost at about 25 per cent of traditional frac methods. Equally encouraging, freezing can be used as an initial frac. “A hydraulic frac afterwards would really drive it hundreds of metres from what we’ve done,” Kosakewich says. He thinks freeze fracs could significantly enhance SAGD production in northern Alberta. “The McMurray formation is interlaced with various strata of shale, which basically caps your ability to migrate the steam right through the

“Our cost is down to around $600,000 from $800,000 a well. That saves almost $200,000. We’re approaching the same costs as for a vertical well.” — Steve Sugianto, CEO, Galleon Energy Inc.

reservoir,” Kosakewich says. “If we frac that shale, it would provide the permeability for the steam to migrate.” Because the shale layers are very thin, he reckons freeze frac could crack entire layers from top to bottom. Any reservoirs with high water content are natural homes for freeze fracs. “When you’re five per cent oil and the rest water, it works perfectly,” says Kosakewich. Longexploited formations like the Pembina, Leduc, Viking, and the Peace River Arch are all good candidates, according to Triple D. Outside the oilsands, the hottest play in Alberta these days is the Pembina Cardium, where producers are applying horizontal fracs to Canada’s largest onshore oilfield. Galleon Energy Inc. says the same technology has immense potential further north in the Peace River Arch, where it holds the largest contiguous land block. Steve Sugianto, Galleon’s CEO, says, “A lot of our present production has been through traditional drilling, so 16

DECEMBER 2009 • OIL & GAS INQUIRER

Galleon Energy sees opportunities to apply multi-stage horizontal frac technology in the Peace River Arch.

applying horizontal wells improves our recovery.” Galleon has moved quickly in this direction with its northwestern Alberta operations. “For example, in the Eastern Montney, 90 per cent of our drilling and production is horizontal right now. We only need verticals to look at delineations and define where to expand out,” Sugianto says. “We see at least a doubling of recovery [of the total oil in the ground]—and compared with the older technology, the incremental cost is only 50 per cent.” With 400 wells scheduled for that project, Galleon expects the combination of higher recovery volumes and lower average recovery costs to boost its bottom line significantly. On a highly encouraging note, exploration and development costs continue to decline as drilling crews gain experience

with horizontal multi-frac technologies. “We’re down to about 8 days now from 12 [to complete a well]. For a horizontal well, that’s huge,” Sugianto enthuses. “Our cost is down to around $600,000 from $800,000 a well. That saves almost $200,000. We’re approaching the same costs as for a vertical well.” Galleon thinks its Eastern Montney economics can now compete with the Barnett and Marcellus shale gas prospects in the United States. Further down the road, Galleon will examine cutting-edge improved recovery technologies like freeze fracturing and waterflood pulse. “Those technologies may be applied to more mature projects, and much of ours isn’t even drilled at this point,” Sugianto says. “In the future, especially in the oil part, we will do enhanced recovery, but we’re not there yet.”


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Knocking out NOX In 2010, heavy truck engines will be cleaner thanks to a pair of competing technologies—but which choice is best for the oilpatch?

by James Menzies

H

eavy-duty truck operators who have not been paying attention to the U.S. Environmental Protection Agency’s (EPA’s) impending emissions restrictions will be sticker shocked when they purchase their next rig. A Class 8 truck built after Jan. 1, 2010, will cost up to $10,000 more than today. In most cases, the increase will be applied as a “nonnegotiable” emissions surcharge. The good news is that 2010 engines will operate cleaner—and more efficiently—than they do today. But that cleanliness comes at a cost. Like the EPA did in 2002 and 2007, the American agency is mandating lower emissions from all on-highway heavy-duty truck engines. The latest targets are oxides of nitrogen (NOX), which must be slashed to 0.2 grams per horsepower-hour—about a 90 per cent reduction from today’s levels. NOX particles can directly damage lung tissue as well as aggravate existing 18

DECEMBER 2009 • OIL & GAS INQUIRER

conditions like bronchitis, emphysema, and even heart disease. In 2007, the EPA restricted particulate matter emissions. The solution proved to be diesel particulate filters (DPFs), which will remain a mainstay on 2010 trucks. In that case, all North American engine manufacturers chose similar technical paths to complying with the EPA standards. With respect to NOX particles, in contrast, new truck buyers will have to choose between two vastly different solutions. Most engine manufact urers (Cummins, Detroit Diesel, Mack, Paccar, and Volvo) will be using an exhaust aftertreatment system known as selective catalytic reduction (SCR). Already widely deployed in Europe, SCR consists of an

SCR catalyst and requires the addition of diesel exhaust fluid (DEF)—a urea/water mixture that’s housed in a separate tank. The DEF is dosed in small amounts into the exhaust stream, creating a chemical reaction within the SCR catalyst that converts NOX into harmless nitrogen and water vapour. SCR will be used in conjunction with exhaust gas recirculation, or EGR (adopted in 2002 to comply with the first round of EPA emissions standards). Since SCR eliminates NOX downstream in the SCR catalyst, exhaust gas recirculation rates can now be reduced. This allows manufacturers to create more NOX within the cylinder and focus on better tuning engine parameters for optimum performance and fuel economy—SCR’s strongest


On an SCR NOx reduction system, the driver or maintenance manager must monitor and ensure that the DEF tank (shown in inset) is topped off.

selling point. (This marks the first time engine manufacturers have had the opportunity to improve fuel economy while complying with EPA standards rather than suffering a loss.) In fact, engine manufacturers using SCR are touting a three to five per cent net fuel mileage improvement even after the added expense of the DEF urea/water mixture, which is expected to cost about the same as diesel and will be burned at about a one per cent ratio. (To put that in real-world terms, a highway truck with a 13-gallon DEF tank will be able to travel the equivalent of New York to Los Angeles and then back to Denver before running out of DEF, according to Dave McKenna, powertrain products marketing manager with Mack.)

Initial concerns about DEF availability seem to be unfounded. A distribution network is already taking form at North American truck stop fuel islands and the urea/water mix should be available in tote jugs of various sizes at truck stops as well as truck and engine dealers. That being said, the fluid does freeze at 12 degrees Fahrenheit, which is no doubt unsettling for truckers operating in the Canadian oilpatch. Fortunately, the DEF tank is heated and will almost instantly thaw enough of the fluid upon engine start-up to allow the driver to be on his or her way unhindered. EPA 2010 engines will be equipped with sophisticated on-board diagnostics that will read the truck’s tailpipe emissions and detect whether or not the system

is functioning and DEF is being used as required. If the truck runs out of DEF on the road, engine power will be downgraded and eventually the driver will be unable to start the engine until the DEF is topped off. While SCR is new to North America, it has been widely used around the world and extensive field testing has been conducted here as well. Detroit Diesel recently announced it has completed more than 25 million miles of real-world testing for its BlueTec SCR system in North America. “The 2010 BlueTec technology will be one of most extensively tested emissions technology systems in our company’s history,” says David Siler, director of marketing with Detroit Diesel. OIL & GAS INQUIRER • DECEMBER 2009

19


Feature

For the first time, however, EPA emissions compliance will require operator involvement. The driver or maintenance manager will have to monitor DEF levels and ensure the fluid is periodically topped off. That’s part of the reason Navistar decided to take a different path. This manufacturer will ramp up EGR levels, avoiding exhaust aftertreatment altogether. “Emissions [compliance] with SCR is not passive,” says Tim Shick, director of business and product strategy, big bore engine business for Navistar. Speaking from the company’s engineering facility in Melrose Park, Ill., Shick comments, “[SCR technology] requires customer involvement and driver involvement, and all things being equal, we thought that customers would prefer not to be involved.”

While its competitors have strong European connections and already had SCR experience under their belts, Navistar decided to take a “clean sheet approach” to 2010. “We weren’t drawn to SCR by prior experience; we had no investment in it,” Shick notes. Instead, Navistar will be employing the same technology it uses today, only on a broader scale. In its simplest terms, EGR refers to the removal of oxygen from the cylinder by displacing it with exhaust gas, which is inherently hot. The exhaust gas must first be cooled before being circulated into the cylinder—hence the term “cooled” EGR. The process reduces the temperature of combustion and discourages the formation of NOX in the cylinder, but at the same time, cooling the combustion temperature also causes inefficiencies. “The challenge with EGR is, how do we get that efficiency back?” Shick explains. The answer, Navistar has concluded, comes

in the form of a high-pressure common rail (HPCR) fuel system that allows it to boost fuel pressure beyond 30,000 pounds per square inch. The higher pressure makes fuel more burnable. HPCR fuel systems also discourage the formation of soot, Shick points out. The challenge with advanced EGR is that with every increase in EGR flow rates, the engine’s parameters must be re-tuned to gain back the corresponding loss of efficiency. It’s a fine balance that requires constant engineering. Fortunately for Navistar, it has earned EPA credits for exceeding previous emissions targets. Navistar will cash in some of those credits to buy some breathing room and as a result will only reduce NOX to 0.5 grams per horsepower-hour on Jan. 1, gradually dialing NOX levels down to the mandated 0.2 grams by the time its credits run out (expected to occur sometime in 2012).

The DEF is dosed into the exhaust stream, creating a chemical reaction within the SCR catalyst that converts NOx into harmless nitrogen and water vapour.

20

DECEMBER 2009 • OIL & GAS INQUIRER


Feature

Cummins Aftertreatment System Diesel Oxidation Catalyst

Diesel Exhaust Fluid (DEF) Dosing Valve

Wall-Flow Filter

Cummins Particulate Filter

The process of ramping down to 0.2 grams from 0.5 grams should be seamless to the customer. Shick says Navistar will increase EGR flow rates by more than 10 per cent compared to today’s levels and will cope with the extra heat rejection by increasing the cooling system by about one frame size. (For instance, a 13-litre EGR-only engine in 2010 will require the same cooling capacity that a 15-litre engine needs today.) In summary, SCR is a proven technology that will be adopted by all but one engine manufacturer. It will improve fuel

Decomposition Reactor

SCR Catalyst

Slip Catalyst

Selective Catalytic Reduction (SCR) Catalyst

economy, but will also require bulky new components, a separate tank to house DEF, and some degree of driver involvement. Navistar’s advanced EGR on the other hand, is the devil you know, but it raises the question, how much is too much EGR? Navistar will ramp EGR flow rates up to unprecedented levels, but is confident it can recapture any loss of efficiency through the constant modification of engine parameters and the use of a highpressure common rail fuel system. Its main selling points are that it requires no driver interaction, keeps frame rail space

free and clear of additional components, and alleviates concerns about the availability and cost of DEF—particularly in remote regions. Naturally, there’s a lot at stake for engine manufacturers heading into 2010. There’s been a flurry of rhetoric, mudslinging, court challenges, and lawsuits in the months leading up to the rollout of these products. The best advice for customers is to familiarize themselves with both options and make an informed decision. James Menzies is Executive Editor of Truck News and Truck West magazines.

What’s it going to cost? The following are the price increases for trucks with EPA 2010-compliant engines. (Noticeably absent is Caterpillar, which has been effectively chased from the on-highway engine market by the challenge of meeting the world’s most stringent emissions standards to date.) In most cases, the premium will be applied as a non-negotiable emissions surcharge (all prices in U.S. dollars):

Daimler Trucks North America:

Volvo Trucks North America:

Freightliner and Western Star trucks with the Detroit Diesel DD13, DD15, and DD16: Freightliner trucks with the Cummins ISX15:

$9,000 $9,000

International trucks with the and MaxxForce 13: (Note: International trucks will not be available with EPA 2010-compliant Cummins engines.)

22

DECEMBER 2009 • OIL & GAS INQUIRER

$9,600

Mack Trucks:

Navistar International: International MaxxForce 11

Volvo trucks with the Volvo D11, D13, and D16, as well as the Cummins ISX:

$8,000

Not yet announced, but expected to be in the same ballpark as parent company Volvo.

Not Announced

Paccar (Kenworth and Peterbilt): Pricing for trucks with Paccar’s new MX 12.9-litre engines not yet announced.

Not Announced


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British Columbia

B.C. land sale takes in $370M, the sixth-largest bonus on record by Richard Macedo

Land sales revenue reflects the ongoing strength of B.C.'s non-conventional gas plays.

British Columbia hit a home run in the Montney formation with its October land sale, which now has the province firmly head and shoulders above its western Canadian neighbours in auction revenues, even though 2009 has been a year of weak natural gas prices and strengthening oi l pr ices. T he prov ince produces mainly natural gas, while Alberta and Saskatchewan benefit from substantial oil production as well as natural gas. B.C. hauled in $370 million in bonus bids ($5,625 per hectare), its sixth-largest sale on record, bringing the calendar year total to $700.6 million. By comparison, Alberta has collected $268.9 million year-to-date, while Saskatchewan’s auctions have produced $83.2 million. To the same point last year, B.C. had accumulated $2.5 billion in bonus bids for a per-hectare price of $3,656. Three parcels were responsible for roughly $265 million, or over 70 per

cent of the land sale total. Most of the land was picked up near the Altares area, with one parcel scooped up by broker Canadian Coastal Resources Ltd. going for $117.3 million for two tracts at 94-B-8 and 94-B-9. In all, 32 parcels in the general area earned the majority of tender bonus for the sale, a government spokesperson said. Daily Oil Bulletin records show Talisman Energy Inc. is the busiest operator in the Altares area with the Montney formation being the most frequent target. Others licensed in the area include Northpoint Energy Inc., Canbriam Energy Inc., and Progress Energy Resources Corp. The land sale results had the brass at Canadian Spirit Resources Inc. (CSRI) grinning from ear to ear as the megabucks plunked down were near the company’s sandbox. Through two joint ventures, CSR I is eva luat i ng t he produc t ive

capability of both its shallow Gething play (Shell Canada as operator) and its deeper Montney play (Canbriam as operator). Both of these plays are located on the company’s principal resource property at Farrell Creek. “We’re very pleased with the amount of money that’s being spent on the land sale because we have a significant position in the Montney,” said CEO Don Gardner. A licence in B.C.’s October land sale went for $60.9 million ($16,315 per hectare) and was picked up by Basm Land & Resources Ltd. The southeastern corner of the 3,738-hectare parcel is directly adjacent to the northwestern corner of the company’s west block, Gardner said. Canadian Spirit recently announced that Canbriam, operator of the Montney project, spudded a vertical well at the Farrell Creek b-17-I location targeting the Montney formation. It was anticipated that the well would be drilled and completed by Canbriam by late November and is part of a multi-well program planned for the area. Canbriam will fund the cost of this well pursuant to a joint-venture agreement. Immediately north of the company’s lands, Talisman is in the process of completing several horizontal wells and is constructing an expandable central sweet gas processing facility with a capacity of up to 30 million cubic feet per day. “Talisman is one of the major players in the area,” Gardner noted. “There are a number of other possible larger players as well. I think the Montney activity in northeast B.C. has been moving in a northwesterly direction. This sale has certainly confirmed that Talisman and other players appear to have a very high regard for the Montney potential in this area. Somebody’s spending an awful lot of money.” — DAILY OIL BULLETIN

BRITISH COLUMBIA WELL ACTIVITY

OCT/08

OCT/09

OCT/08

OCT/09

OCT/08

OCT/09

WELL LICENCES

165

82

WELLS SPUDDED

30

53

WELLS DRILLED

60

30

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2009

25


British Columbia

Quicksilver sees Horn River Basin as its next big development project Quicksilver Resources Inc. has not disclosed total Canadian capital spending planned for 2010, the company has announced that it will invest about US$50 million in British Columbia’s Horn River Basin, including infrastructure costs. Also included in that figure are two wells planned for the basin in 2010. As for possible joint ventures in the Horn River area, the jury is still out, although the company has had discussions on that score in recent months. “It’s all about value,” says Glenn Darden, Quicksilver president and CEO. “We’re not in a big hurry…. We don’t have to do anything. The more we learn about the Horn River, the more we like it. Obviously, a lot of activity is happening around us, which makes us even prouder of our position. If we can get the right structure and the right price, we’d be willing to do something, but at this point, there’s not a big hurry to do that.” Despite budget cuts, the company’s Horseshoe Canyon gas volumes in Alberta grew nine per cent this year, to 63 million cubic feet per day. Yet, the biggest news from Canadian operations was progress on the Horn River play, Darden says. “One of

our goals in 2009 was to convert this prospect into our next big development project. We are well on our way to doing this,” he said, noting that the company’s D-50A well averaged 10 million cubic feet per day in the first month of production, from a 3,300-foot lateral well drilled in the Muskwa shale. “Later this month, we’ll begin completion on a second well, three miles east of the initial well. The C-60D well will be completed in the Lower Klua section of the shale,” Darden says. “Although still in the

says, adding, “We’re beginning to put infrastructure in place for long-term development,” he added. “The [Horn River] project could be several times larger than our current reserve base. We can grow production organically at 20 per cent over the next several years, and stay well within cash flows. We will keep pushing.” In Alberta, the company drilled four (three net) operated coalbed methane wells in the Horseshoe Canyon formation in the third quarter, and expects to drill

“...We firmly believe [the Horn River] will be a world-class production basin." — Glenn Darden, President and CEO, Quicksilver Resources Inc.

early stages, we firmly believe [the Horn River] will be a world-class production basin. Our 127,000 net acres is now surrounded by significant production from other operators.” Over the next three years, Quicksilver has to drill eight more wells to convert its exploratory licences to leases. It then has 10 to 12 years to develop its entire acreage. The company has secured firm transportation agreements that will ramp up volumes over the next five years, Darden

three (two net) operated coalbed methane wells in the rest of 2009. The company now expects to participate in a total of 145 (42 net) wells in Alberta in all of 2009. Total Canadian gas production rose to 67.8 million cubic feet per day in the third quarter, from an average 62.5 million cubic feet per day in last year’s quarter, while natural gas liquids production rose to three barrels per day from nil in the 2008 period. — DAILY OIL BULLETIN

Pipeline companies and contractors appear in court over 2007 oil spill Kinder Morgan says it will defend itself against charges stemming from a 2007 rupture of its pipeline in the Vancouver area. On Oct. 5, representatives for Kinder Morgan, Trans Mountain Pipeline, and two contractors appeared in provincial court for the first time in this case. “Kinder Morgan Canada believes the charges have been inappropriately laid against it and intends to defend the regulatory charges vigorously,” the company said. Its own investigation into the rupture concluded that “it resulted from the actions of a third-party contractor working on behalf of the City of Burnaby.” Kinder Morgan has launched a civil case against the city and the excavation contractor. Kinder Morgan and Trans Mountain Pipeline each face seven counts and the 26

DECEMBER 2009 • OIL & GAS INQUIRER

two contractors each face six. The charges, which carry maximum penalties of $1 million apiece, were laid in July, but this was the first court appearance for the group. They will appear again on Jan. 13. Some 234,000 litres of crude oil gushed out of the underground line leading to a waterfront shipping terminal. The resulting 15-metre-high geyser coated neighbouring yards in thick, black crude, while more oil seeped into nearby Burrard Inlet, soaking a number of birds. The Transportation Safety Board concluded earlier this year that a 50-year-old pipeline map combined with lax construction procedures triggered the eruption. The charges include introducing waste into the environment and unlawfully carrying on work that resulted in the harmful

alteration, disruption, or destruction of fish habitat. The safety board report concluded the pipeline rupture wouldn’t have happened if National Energy Board rules and the agreement with Kinder Morgan had been followed. The contractor digging the new sewer line assumed the 1957 map showing the pipeline route under the roadway was accurate, when in fact in some places it was out by several metres. The mechanical digger struck the oil line five times before puncturing it twice. The accident forced 250 people from their homes, with damage serious enough to 11 of the homes that the families had to move temporarily. There are 26 lawsuits outstanding as a result of the accident. — CANADIAN PRESS


British Columbia

Photo: Joey Podlubny

Husky tests two shale gas wells in northeastern B.C

Husky CEO John Lau

Husky Energy Inc. says it has completed and tested two promising exploratory wells to evaluate the shale gas potential in the Montney and Doig formations in northeastern British Columbia. The Calgary-based integrated oil and gas company said on Oct. 29 that the drilling results were “very encouraging.” Husky said one well flowed gas from the Doig formation at a rate of 2.9 million cubic feet per day. Another well produced 5.4 million cubic feet per day from the Montney play and 2.9 million cubic feet per day from the Doig formation. The land position covers an area of about 4,600 hectares close to Husky infrastructure and has all-season access. “The recoverable resource potential from these wells are substantial and among the best vertical tests from the Doig/Montney play,” Husky president and chief executive officer John Lau said in a release. “These results are encouraging for Husky to expand its strategy in unconventional resource play development in this area.” Husky plans to drill the first horizontal well on this land in 2010. The pace of development depends on well test results and the market conditions of natural gas. In another development, Husky said it acquired another 5,000 hectares of land in the Doig Montney play, raising the company’s exploration property in the area to more than 9,600 net hectares. “The acquisition enhances Husky’s position in the Doig/Montney play, which has become one of North America’s most promising plays for natural gas development,” Lau said. OIL & GAS INQUIRER • DECEMBER 2009

27


British Columbia

EOG Horn River well achieves record initial production Planning a “slow but steady” ramp-up in activity, EOG Resources, Inc. expects to drill 12 shale gas wells this winter in the Horn River basin of northeastern British Columbia. Over the summer, the company completed seven wells drilled last winter in a program focused on improving operations and completion techniques along with determining optimum spacing. Mark Papa, EOG’s chairman and CEO, said three wells in one pattern had initial production of 23.4 million cubic feet (MMcf), 19.3 MMcf, and 17.2 MMcf per day while four wells in the second pattern tested at rates of between 16 MMcf and 18 MMcf per day. EOG plans to produce the wells throughout the coming winter to evaluate the performance of each pattern. “We believe the three high rate wells are among the best in the play, topping our 16 MMcf per day well completed last year,” he said. The company also was able to reduce its drilling days by 42 per cent and well costs by 35 per cent over 2008 levels and has set cost targets for each area that provide attractive rates of return.

T he B.C . gove r n me nt r e c e nt ly approved EOG’s application for royalty incentives for a significant portion its acreage, which is a big step forward in making this play competitive with other shale plays, said Papa. In the third quarter, EOG also signed a memorandum of understanding with Kitimat LNG to supply 200 MMcf per day of gas for its proposed liquefied natural gas (LNG) export terminal. Every year between 2010 and the targeted terminal 2013 start-up date, there will be a slow ramp-up in production with the aim of at least 200 MMcf per day of production by that date, said Papa. “But it’s fair to say…we are in the very early stage in learning how to best deplete this asset,” he said. “Our strategy is we are going to slowly increase our activity and really not just get in a big hurry on this asset, similarly to what we are talking about in the Marcellus [shale]…particularly in a gas market that has been uncertain for us right now.” In the third quarter of this year, EOG’s Canadian production averaged 42,200 barrels

of oil equivalent per day in the third quarter, up slightly from 41,444 barrels of oil equivalent a day in the third quarter of 2008. Sales included 219 MMcf per day of gas, down from 224 MMcf per day a year earlier. Although EOG won’t finalize its 2009 capital budget until early 2010, it expects that at least 60 per cent of its North American budget will be allocated to oil activity. “EOG is successfully transferring its technical expertise in drilling horizontal natural gas wells to unconventional oil and liquids rich reservoirs,” said Papa. The forecast 50 per cent growth in liquids in 2010 will come primarily from the Barnett Combo in Texas, the North Dakota Bakken, and Waskada, Man. horizontal plays. “For the past year we have been telling people that horizontal drilling in unconventional rock is a game changer and our 50 per cent annual growth rate provides solid evidence,” said Papa. EOG reported positive well results from crude oil drilling activity in its North Dakota Bakken areas where it is operating a five-rig program. In the Bakken Core, two wells commenced

Looking Back... ST TRUC FA

LTD. CE

NG SERVI KI

1954 GMC

Looking Forward...

1966 International

2007 Kenworth

28

DECEMBER 2009 • OIL & GAS INQUIRER


British Columbia

production at rates of 880 barrels of oil per day and 1,150 barrels per day, respectively. The Bakken Lite step-outs beyond the core area are continuing to yield good results, said Papa. In addition, EOG drilled and tested its first wells in the Three Forks formation to determine the prospects across its acreage position. Initial results from the first two wells indicate encouraging pressure and flow rates in a portion of its acreage. “We are very encouraged to find that the pressure that exists in the Three Forks did not indicate pressure depletion from the core,” he said. “There is certainly a strong indication that we may have another oilfield below our core oilfield.” In 2010, EOG plans to operate a 14-rig drilling program in North Dakota, focusing on the Bakken Core and Bakken Lite, as well as further drilling and testing of the Three Forks. “We continue to believe the Bakken and the Three Forks will be big long-term plays for both EOG and the industry and we’ll have a significant part in the infrastructure,” said Papa. In Manitoba, the Waskada horizontal oil project is performing better than expected with forecast 2010 production

of 6,000 barrels of oil per day net. EOG expects to increase that to over 12,000 barrels per day in 2012. On the North American gas side, the company has a 2010 growth target of three per cent in 2010 with flat production in the first half of the year and then a six per cent increase, mainly from the Haynesville shale. “We don’t see any economic rationalization for growing gas production in adverse markets,” said Papa. EOG expects North American gas prices to begin improving in mid-2010 and continue to strengthen through the second half of the year as supply tightens due to reduced production and normal declines. Given a year-end 2009 gas rig count of 740, EOG estimates that North American production will be down 3.2 billion cubic feet per day in December of this year and down five billion cubic feet per day by June 2010 relative to the end of 2008, he said. The forecast reflects a projected 800 MMcf per day decline in Canada, offset by increased LNG imports of one to two billion cubic feet per day. — DAILY OIL BULLETIN

West sets $60M capital budget After three quarters of 2009 in which it l i m ited c apit a l e x pend it u re s to within cash f lows, West Energy Ltd. has increased its fourth-quarter capital budget to $25 million as it accelerates spending on its Cardium light oil resource play. The light oil focused company plans to drill eight horizontal wells by year-end and establish its Montney light oil project at Two Rivers in northeastern British Columbia, where it will spud its first horizontal well. With the Two Rivers drilling results in the fourth quarter of this year, West also has plans for f ur t her Mont ney horizontal drilling activ it y in 2010. In 2010, West anticipates spending appr ox i m ate l y $6 0 m i l l ion on a n exploration and development program on existing properties. The program will include 24 Cardium horizontal oil wells, 3 Pembina Mannville oil wells, and any Pembina Nisku wells when licences are obtained. — DAILY OIL BULLETIN

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Northwestern Alberta/Foothills

Alberta’s Crown land auctions in October generate meager revenue

Low Crown land sales, reduced drilling, and high inventories continue to dog Alberta.

A lberta’s t wo land sales in October yielded $32.8 million in bonus bids, including $10.9 million from the sale on Oct. 28 and $21.9 million on Oct. 14. To date, the province has raised $279.9 million in revenue in 2009. Alberta’s lowest land sale total over the past decade was $501.5 million in 2002, and this year’s total appears likely to be lower. T he Oct. 28 land sale generated $193.88 per hectare (ha) on 56,691 ha, with most of the money plunked down in the province’s northern region. Broker Scott Land & Lease Ltd. produced the land sale bonus high, paying $1.5 million ($1,138 ha) for a 1,280 ha licence at sections 26 and 34 at 48-20W5 and sections three to five at 49-20W5. Daily Oil Bulletin records show operator activity in the Minehead area by Tourmaline Oil Corp. The company rig released a well in September for gas at

11-9-49-20W5 with the Poker Chip shale as the projected zone. Several sections located to the northeast at 49-19, 50-19, and 50-20W5 have been posted for the Nov. 18 land sale. In the Foothills region, Canadian Coastal Resources Ltd. paid $795,924 for a licence at sections 23 to 25 and 34 to 36 at 62-12W6. The 1,536 ha parcel went for an average of $518.18 per ha. Second Wave Petroleum Inc. produced the lease high, paying $416,000 ($1,625 per ha) for a 256 ha parcel at section 36 63-10W5 for petroleum and natural gas below the base of the Bluesky-Bullhead. Oilsands parcels generated $657,168 in bonus bids during the late October sale on 4,224 ha. Bristol Land & Leasing Ltd. paid the bonus high of $181,027 ($2,828 per ha) for a parcel at 54-6W4 in the Cold Lake oilsands area. Centennial

Land Services Ltd., meanwhile, plunked down $179,747 ($351.07 per ha) for a parcel in the Athabasca oilsands area at 77-25W4. Year-to-date, revenue from oilsands leases has plunged to $6.7 million versus $275.4 million for the same period last year. The Oct. 14 sale produced a perhectare price of $203.88 for 107,470 ha of rights sold. In Alberta’s mid-October sale of 2008, bids totalled $38.7 million in revenue on 117,707 ha at $328.92 per ha. Scott Land & Lease Ltd. paid the bonus high at the mid-October land auction, picking up a 768 ha lease for $1.4 million. The broker acquired one tract at the northern half and southeastern quarter of section 14 and sections 16 and 22 at 26-3W5. The second tract was located in the southwestern quarter of section 14. Plunkett Resources Ltd. produced the per-hectare high of $3,932 for a 256 ha lease, a total bonus of just over $1 million. The company picked up two tracts at 47-10W5. Tract one included the southern half and northwestern quarter of section nine, while the second was for the northeastern quarter of section nine. Tract one includes petroleum and natural gas to the base of the Rock Creek member, while the second tract is for petroleum and natural gas below the base of the Cardium formation and to the base of the Rock Creek member. Daily Oil Bulletin records show Baytex Energy Ltd. spud a well in the Pembina area at 6-20-47-10W5 in January targeting the Nordegg member. Windfall Resources Ltd. paid $1.03 million—the licence high—for sections 18, 19, 30, and 31 at 112-21W5; section 6 at 113-21W5; and sections 21, 25, 27, 28, and 34-36 at 112-22W5. The parcel totalled 3,072 ha. — DAILY OIL BULLETIN

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

OCT/08

OCT/09

OCT/08

OCT/09

OCT/08

OCT/09

WELL LICENCES

348

216

WELLS SPUDDED

277

119

WELLS DRILLED

269

106

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2009

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Northeastern Alberta

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Imperial produces its one billionth barrel of crude oil at Cold Lake

Cold Lake is Canada's first in situ oilfield to produce more than one billion barrels.

More than four decades after Imperial Oil Limited broke ground for the first thermal in situ field pilots at Cold Lake in northeastern Alberta and 25 years after the first commercial production, the project has surpassed one billion barrels of cumulative production. Only three other fields in Canada have achieved that milestone and Cold Lake is the only in situ project to have done so, said the company in reporting thirdquarter results. Over the years of operation, technological advancements have tripled recovery rates while reducing fresh water use and surface land disturbance. In September, Imperial filed amendment applications for the Cold Lake Nabiye in situ expansion project, which had received regulator y approval in 2004. The project, if sanctioned, will add about 30,000 barrels a day of production from a new plant. The expansion will

access 250 million barrels of previously undeveloped resource at Cold Lake. Further north, the Kearl oilsands mining project has been proceeding with detailed design, procurement, and construction activities with a current workforce of about 3,000 employees and contractors. Kearl will be developed in three phases and could ultimately produce more than 300,000 barrels of bitumen per day before royalties. The first phase of the project is expected to start up in late 2012. Imperial holds a 71 per cent interest in the project and is the operator in the joint venture with ExxonMobil Canada. Earnings from both upstream and downstream operations at Imperial Oil Limited took a hit in the third quarter of 2009, with net income down 61 per cent from the third quarter of 2008. Net income for the three months ended Sept. 30, 2009, declined to $547 million from

a record $1.39 billion in the comparable period a year earlier. Lower oil and natural gas prices resulted in a $560-million reduction in upstream earnings to $439 million from $999 million in 2008, while downstream earnings slipped to $62 million from $270 million due to lower demand for products, which translated into lower margins. The chemicals segment also was off sharply to $27 million from $82 million per year earlier primarily due to lower margins for polyethylene products. In the third quarter, capital and exploration expenditures increased to $575 million from $360 million in the same period in 2008. For the first nine months of 2009, capital and exploration expenditures were $1.6 billion, an increase of 72 per cent. Total production averaged 303,500 barrels of oil equivalent in the quarter, down from 309,500 barrels of oil equivalent per day in the comparable 2008 period. Heavy crudes make up most of the company’s output. Its gross production of conventional crude oil averaged 25,000 barrels per day in the first nine months of 2009, essentially the same as the corresponding period of 2008. Gross production of Cold Lake heavy oil averaged 145,000 barrels per day compared to 143,000 barrels in the same quarter last year. The cyclic nature of production at Cold Lake and lower maintenance activities contributed primarily to the increase. The company’s average realizations for Cold Lake heavy oil were down about 40 per cent in the third quarter of 2009 compared to 2008, although the decline was less than the 43 per cent decline for lighter crude oil due to the narrowing price spread between light crude and Cold Lake heavy oil. — DAILY OIL BULLETIN

NORTHEASTERN ALBERTA WELL ACTIVITY

OCT/08

OCT/09

OCT/08

OCT/09

OCT/08

OCT/09

WELL LICENCES

138

105

WELLS SPUDDED

76

78

WELLS DRILLED

78

89

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2009

33


Northeastern Alberta

Husky prepares to drill new wells at its Tucker oilsands project With improving crude oil prices, Husky Energy Inc. is developing plans to drill a number of new infill and replacement wells to increase production at its Tucker oilsands project in northeastern Alberta over the next year. In releasing its third-quarter results on Oct. 22, the company said it continues to pursue operational strategies to achieve full implementation of the steam assisted gravity drainage (SAGD) process in this reservoir. The majority of the wells in the project are in steady state SAGD operational mode, and production rates were approximately 4,300 barrels of oil equivalent per day at the end of the quarter. In a report, Peters & Co. Ltd. says the company hopes to be producing nearly 10,000 barrels per day by the end of 2010 from the facility designed for 30,000 barrels per day. The report said Husky now expects a steam to oil ratio of four to one compared to the initial target of three to one. “More importantly, this new plan will require the drilling of more wells, additional steam generating capacity, and upsizing of all the facilities, including the water treatment plant,” said Peters &

Despite earlier development troubles, Husky is pressing ahead with its Tucker SAGD project.

Co., which estimates this will cost about $250 million. Husky expects to complete front-end engineering design (FEED) by the end of this year on its Sunrise integrated oilsands thermal project it is developing with partner BP plc (50 per cent) north of Fort McMurray, Rob Peabody, Husky

COO, said in a conference call to discuss its third-quarter financial results. The plan is to move the project into f ull engineering, procurement, and construction phase next year, he said. “We had anot her meeting w it h our partner the other day and I think both partners are very aligned on the way

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forward on Sunrise and very committed to the project.” Bitumen production of 60,000 barrels per day from the first phase is expected to begin approximately four years after project sanction planned in 2010 with total gross production currently planned to increase to 220,000 barrels per day, subject to project sanction and market conditions. Work on optimization to simplif y its scope and take advantage of t he r e c e nt e c onom ic dow nt u r n i n t he demand for goods and services is progressing on schedule with FEED about 60 per cent complete. At the third quarter, Husky had spent $1.49 billion of its 2009 upstream capital budget of $2.09 billion. The company has budgeted $725 million for oil and gas in western Canada and $65 million for oilsands. Another $800 million is allocated for the east coast of Canada and $500 million for international operations. At Bullmoose-Sukunka in northeastern British Columbia, the Burnt River c-A61-A (55 per cent working interest) and the Sukunka a-27-F (20 per cent working interest) wells have been tied in and are capable of producing at rates in excess of 30 million cubic feet per day

from the Belcourt formation. Both wells have commenced production. Husky is finalizing negotiations with a partner to participate in another Belcourt formation test that is expected to spud later this month. During the first nine months of 2009, Husky spent $53 million primarily on the Mizzen exploration well in the Flemish Pass off the coast of Newfoundland. An application has been submitted to the Canada-Newfoundland and Labrador Offshore Petroleum Board for a significant discovery licence based on the results of the December 2008 Mizzen exploration well in which Husky has a 35 per cent working interest. Offshore Greenland, Husky continues to evaluate a 7,000 kilometre 2-D seismic program acquired in the third quarter of 2008 on Blocks 5 and 7. A $55-million airborne gravity and magnetics acquisition was completed in the second quarter of 2009 and is currently being evaluated. Husky has completed acquisition of the first of two 1,000 square kilometre 3-D programs over Block 7 and is currently working on the acquisition of a second 1,000 square kilometre 3-D program over Block 5.

Epcor and Suncor sign water deal Epcor Utilities Inc. will become the primary provider of potable water and domestic waste water services at Suncor Energy Inc.’s oilsands operations under a new deal announced on Oct. 20. Under the agreement, Epcor will acquire potable water and waste water facilities under a sale lease-back agreement at Suncor’s Steepbank, Firebag, and Borealis sites for about $100 million, and will take over some waste water operations at the Suncor Base Plant. As a result, Epcor is providing potable water and domestic waste water services to more than 6,000 Suncor oilsands workers. Lease payments will be made to Epcor over 20 years. The deal, which closed Oct. 8, includes operations and maintenance of three waste water treatment plants, two water treatment plants, and various collection and distribution systems. Epcor will perform upgrades as part of regularly scheduled maintenance to the facilities over the next year.

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Central Alberta

Photo: Joey Podlubny

Alberta extends its bitumen royalty-in-kind program

Alberta has provided two more preparation years for firms planning to process royalty bitumen.

When the Alberta government’s bitumenin-kind initiative was first announced in July, any upgraders hoping to process that crude were required to be up and running by 2016. But on Oct. 19, the Alberta government said it had decided give participants until 2018. Under the bitumen royalty-in-kind program, the province will take its royalty payments from producers in bitumen rather than in cash. The province would then supply up to 75,000 barrels per day of that raw product to an Albertabased project, which would process it into value-added products like gasoline or diesel. It’s seen as a way to ensure oilsands processing jobs and investment stay in the province, rather than flow south of the border, where many refineries have been retrofitted to handle the heav y crude from northern Alberta.

If anyone wants to see Alberta’s oilsands upgrading industry get a boost from the government as quickly as possible, it’s businesses in Alberta’s Industrial Heartland, just outside Edmonton. But the executive director of Alberta’s Industrial Heartland Association acknowledged on Oct. 20 that there are good reasons for the province to start up its bitumen royaltyin-kind initiative two years later than originally planned. “Obviously we’d like to see construction sooner than later, but we also want to make sure it’s the right project, and the best project for the region,” Neil Shelly said. It takes about two years for a new project to go through the regulatory process in Alberta. And if it’s a large development, construction could take three or four years. “The initial timelines they initially had on this one were a little more constrictive on that, and it kind of

eliminated a whole group of potential new players that couldn’t invest in the region,” Shelly said. “It would have made it more difficult if not impossible for these new entrants to apply to the program.” That’s not to say there won’t be downsides that come from the delay. Shell Canada Ltd. is currently the only company building a major project in the region. Once the expansion to its Scotford upgrader wraps up some time next year, there may not be any reason for skilled labourers, who were so scarce during the boom, to stay in the area. “We spent a long time building up that skills base,” Shelly said. “If there’s no projects on the go in the area after next year, we potentially could lose that skills base and it we’ll be back at square one again when the projects are ready to go in 2016 or 2018.” Potential participants in the program have until Jan. 27, 2010, to file their applications, and a decision on which projects will be approved would likely be made toward the middle of the year, Alberta Energy spokesman Jerry Bellikka said. “If you want to get to full capacity and use 75,000 barrels per day, it’s going to take some time, longer than first estimated, in order to bring those projects in,” he said. The royalty-in-kind program fell short even before the province announced the delay, said the president of the Alberta Federation of Labour (AFL). “The fact that they’re pushing it back another two years, frankly, doesn’t surprise us,” said Gil McGowan. “And given the paltry effort that the program provides, it’s really not going to change the big picture.” “For those who are not familiar with the oilsands industry, 75,000 barrels per day may sound like a lot. But it’s really little more than a drop in the bucket,” McGowan said. — CANADIAN PRESS

CENTRAL ALBERTA WELL ACTIVITY

OCT/08

OCT/09

OCT/08

OCT/09

OCT/08

OCT/09

WELL LICENCES

339

209

WELLS SPUDDED

344

175

WELLS DRILLED

337

168

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2009

37


Central Alberta

Berens Cardium well tests 270 barrels per day Berens Energy Ltd. says its Pembina Cardium horizontal oil well located at 01-14-48-11W5 tested the equivalent of 270 barrels per day of oil at the end of a 48-hour period. The well was scheduled to be placed on production by early November. Berens operated the well and has a 50 per cent working interest. The well was drilled to a horizontal length of 600 metres. Drilling was terminated short of the original design length of 1,000 metres as a result of isolated drilling

and reservoir conditions on this well. The well was subsequently completed with a five-stage frac treatment. A second horizontal oil well (Berens’ 60 per cent working interest) is currently drilling at 15-21-50-12W5 with initial test results expected in midNovember. Four additional Pembina C a r d iu m hor i z ont a l oi l we l l s a r e planned for the first quarter of 2010 to assess the extent of this resource play across the Berens’ lands.

A successful first-quarter 2010 program has the potential to establish a significant inventory of horizontal Cardium oil wells on existing lands to add to an already stron- inventory of natural gas wells in the Pembina region, according to Berens. It holds a total of 68 sections (38 net) of Pembina Cardium rights on the west flank of the existing Pembina Cardium oilfield, much of which is expected to be prospective for this emerging oil resource play. — DAILY OIL BULLETIN

Stealth receives downspacing approval for shale gas play Stealth Ventures Ltd. has received spacing approval from the Alberta Energy Resources Conservation Board (ERCB) to proceed with eight wells per section on two sections of land in the Wildmere area. Currently the ERCB allows four wells per section drainage on all Stealth lands in Wildmere. After months of analysis, a regulatory approval precedent has been set for

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DECEMBER 2009 • OIL & GAS INQUIRER

sections 10-50-6W4 and 29-49-5W4 to allow for eight wells per section from the current four within a holding. Fekete Associates Inc. completed extensive rate transient analysis on location 15-1050-06W4, which had over two years of production data and showed ultimate well density will approach 18 wells per section (36-acre spacing) to ultimately

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Central Alberta

Imperial Oil reviews security after environmental protests Imperial Oil Ltd. is looking at security after several high-profile occupations of Alberta oilsands projects by environmentalists, the company’s CEO said on Oct. 15. Greenpeace protesters who took over a Shell plant near Edmonton and blocked production at a Suncor Energy (TSX:SU) upgrading refinery near Fort McMurray

that may be changing our thinking somewhat,” he said. RCMP officers were called in and 16 Greenpeace protesters were arrested after demonstrating at the Shell oilsands upgrader plant near Edmonton earlier in October. Break-and-enter charges were laid in that instance. Mischief charges were laid

“I think we’re generally concerned that it’s occurring and wish that organizations like [Greenpeace] would be able to participate in a manner that’s a little more constructive."

— Bruce March, CEO, Imperial Oil Ltd.

have changed the way companies think about protecting their sprawling projects, Bruce March told reporters following a speech to Calgary’s business community. “I think what we’ve seen with the Greenpeace excursions are elements that are very well planned out, they’re very well prepared, they’re effectively executed, they’re very organized, and

after a Sept. 30 attempt to block production at Suncor’s upgrader near Fort McMurray. March said Imperial has always had security in place to keep trespassers out, primarily for safety reasons, but the latest incursions mean Canada’s largest oil producer and refiner may have to rethink its strategies. As many companies expand Canadian oilsands projects and planned pipelines

to carry heavy crude to U.S. refineries, environmentalists have raised the pressure on the industry, warning that the rapid growth will harm the environment, produce more greenhouse gases, and deplete water resources. “I think we’re generally concerned that it’s occurring and wish that organizations like [Greenpeace] would be able to participate in a manner that’s a little more constructive,” March said. However, he acknowledged that such tactics by environmental groups have been very successful at positioning the oilsands as an international climate change menace. But he added he’s convinced that the world will be willing to listen to a different story from industry and the Canadian government when it comes to the upcoming climate change conference in Copenhagen. “We think we have a pretty good story to tell around our development, and we’re not concerned about getting an equal chance to view those things at all,” March said. — CANADIAN PRESS

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DECEMBER 2009 • OIL & GAS INQUIRER


Southern Alberta

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Drilling days per well rise despite steep overall activity downturn

In order, Canada’s busiest drillers during 2009 have been Precision, Ensign, Savanna, and Trinidad.

Precision Drilling Trust was the most active drilling contractor in Alberta during the first nine months of 2009, completing 1,248 wells drilled and 1.71 million metres of hole. In Saskatchewan, Ensign Drilling Inc. ranked first with 336 wells and 452,290 metres. Trinidad Drilling Inc. was the most active contractor in both British Columbia (102 wells and 302,644 metres of hole) and Manitoba (83 wells and 195,790 metres). Overall, Precision was the top contractor in Canada for the first three quarters of 2009 with 1,607 wells and 2.32 million metres drilled. Its biggest customers were Canadian Natural Resources Limited (338 wells), EnCana Corporation (185 wells), and Devon Canada Corporation (143 wells). Precision increased its market share slightly to nearly 27 per cent this year from 25.35 per cent in the first nine months of 2008.

Ensign ranked second with 1,462 wells and 1.64 million metres of hole. Its biggest customers were EnCana (286 wells), Canadian Natural Resources (244 wells), and Enerplus Resources Fund (101 wells). Savanna Energy Services Corp. ranked third place (1,142 wells and 1.09 million metres) and Trinidad Drilling ranked fourth place (375 wells and 861.208 metres). Savanna’s biggest customer was EnCana (628 wells), while Trinidad’s number one client was Manitoba operator Tundra Oil & Gas Partnership (82 wells). While the number of wells drilled by contractors plunged this year to only 5,987 from 11,562 a year earlier and operating days fell 38 per cent to 41,032, the average number of drilling days it takes to drill a well continued to rise, mainly because of the growing use of horizontal wells and the collapse in shallow gas drilling.

In western Canada, it took on average 10.16 days to drill a well in the first nine months of 2009, up 20 per cent from last year and the most since 1991. B.C. was at a 20-year high of 26.88 days per well, 29 per cent above last year, while Saskatchewan drillers took on average 8.08 days, up from 6.9 days in the same period of 2008. In the third quarter of 2009, contractors only booked 13,851 operating days, down 50 per cent from the same period last year. Only two contractors experienced more operating days this year (to the end of September) than in 2008—Partner Drilling Ltd. with a 15-day increase to 420 days and Panther Drilling Corp. with a one-day increase to 366 days. The highest rig utilization numbers for the first three quarters of 2009 were posted by smaller contractors, with Panther Drilling leading the way with a 67 per cent utilization rate for its two rigs. Eagle Drilling Services (51 per cent utilization for its five rigs) and Partner Drilling (39 per cent utilization rate for its four rigs) ranked second and third. The same three companies had the highest metres drilled per rig for the nine-month period. Partner Drilling, a Vancouver-based contractor using rigs built in China, was the leader in average wells drilled per rig with 26.5 wells drilled on average by its four rigs. Partner Drilling finished 106 wells in the first nine months of 2009, 83 of which were drilled by Husky Energy Inc., controlled by Hong Kong billionaire Li Ka-shing through his holding company Hutchison Wamphoa. Partner Drilling and Advance Drilling Ltd. (which also uses Chinese rigs) have the same head office address in Vancouver and the same president. Advance Drilling owns 10 rigs and drilled 104 wells to the end of September. Bonanza Drilling Inc. ranked second by average wells per rig with nearly 21 wells drilled by each of its five rigs. — DAILY OIL BULLETIN

SOUTHERN ALBERTA WELL ACTIVITY

OCT/08

OCT/09

OCT/08

OCT/09

OCT/08

OCT/09

WELL LICENCES

681

251

WELLS SPUDDED

624

108

WELLS DRILLED

624

109

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2009

41


Southern Alberta

Oilpatch lenders work with junior producers to get through the downturn Low natural gas prices and tighter credit are making for lean times, but Canadian lenders are trying to work with junior producers rather than forcing insolvency. “By and large, we’re not getting heavyhanded,” said Bruce Edgelow, Energy Group VP for ATB Financial Services, who believes his approach is in line with those of other lenders to the junior sector. S p e a k i n g a t t h e P l a y m a k e r ’s Symposium in Calgary, he acknowledged the current environment, mainly due to low gas prices, has stretched juniors who tend to have more gas than oil production. “Are we having tough discussions? Yes, but the banking community is not going to get heavy-handed and [trigger] receiverships unless we are driven to it through other unsecured pieces,” Edgelow told the conference in October. “We are hunkering down and working with our clients.” Juniors are a sector of the industry that’s been under severe pressure, Bill Sembo, vice-chairman of RBC Capital Markets, told a Calgary conference last

April. In a more recent interview, he said the situation has not changed much since last spring. “I think we’re still probably in the same situation as before, in that certain [producers] were probably at the upper limit of their borrowing capacity,” Sembo said, adding that for those companies, securing more credit could be problematic. In addition to challenges securing credit, the cost of credit is higher this year. “On average, I would say the cost of borrowing has gone up by 100 to 150 basis points,” said John Swendsen, VP of energy lending for the National Bank of Canada, although he estimated that change has occurred over the past two years, from the time the credit squeeze began in mid2007. “If [companies] borrowed at the [Bank of Canada] prime rate plus one half [percentage point] two years ago, they’re probably paying more like prime plus one and a half or thereabouts today.” Banks base their loans to producers on the value of their reserves in the ground,

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DECEMBER 2009 • OIL & GAS INQUIRER

adjusted for additions and revisions. While some producers are assessed annually, most juniors are evaluated twice yearly. Things could get more difficult early next year, when loans are reviewed with the annual reserves determination since many producers have cut capital spending this year and aren’t replacing production with new reserves. That coupled with a lower gas price forecast could materially reduce borrowing capacity. In reality, Swendsen said, lenders talk to their clients in the junior sector almost monthly. “We have ample opportunity to say, ‘Listen, you’re getting close to the top of your [credit] lines and if gas prices contract, you’re going to have some challenges, so let’s start looking at it now,’” he said. In reviewing reserves, evaluators assume a certain gas price. That figure can have a huge effect on the value of the reserves and on how much credit the junior can qualify for. One lender said this is where the industry was cut some slack,


Southern Alberta

since the gas price applied on this year’s evaluations was higher than it could have been. “The 2009 marketplace got a bit of a bump because the reserves analysts gave them a bit of a reprieve on the price being used, [but] I’m not sure that that’s going to carry forward into 2010,” said ATB’s Edgelow. “We think 2010 [prices] might be even tougher.” With companies stretched, some will be forced to sell properties to raise cash despite current lower gas prices. Gary Leach, president of the Small Explorers and

Celtic Exploration Ltd. “You definitely would not be fetching the best price today. If I had to pick one of the two, I think people would be more inclined to raise [equity].” “It ’s up to the management and boards of companies to ask themselves, ‘What are we going to do?’” said John Rossall, president and CEO for ProspEx Resources Ltd. “Do they sell assets to reduce debt, hunker down, or seek some sort of merger? There are a number of alternatives in those situations.”

With companies stretched, some will be forced to sell properties to raise cash despite current lower gas prices. Producers Association of Canada (SEPAC), cited specialists in the asset divestiture business who say business has not been as brisk as expected, given the pressures producers are under. As well, he said more management teams could move to recapitalize existing, weaker juniors, as happened recently with Eagle Rock Exploration Ltd. “It’s a nasty time to be selling natural gas properties— or any others,” said David Wilson, president and CEO of

As for mergers, one issue they raise is management entrenchment, accordi ng to ba n kers. Two ju n iors m ight agree to merge, for example, but differ about who should step aside to make it happen. Rarely do executives from both sides land on their feet in such scenarios. Those considering a merger therefore know that without it, they at least have a job and a salary. With it, they might have neither.

“Management entrenchment is huge,” said ATB’s Edgelow. “[Executives] are concerned that…they cannot go out and start another company if they sell the current one, and they’re not sure they’ll be able to find a job…. So, the entrenchment is real, and we have to deal with it.” “As far as juniors go, I think bankers have tried to demonstrate a fair bit of flexibility,” said Leach. “They understand there is not much to be gained by trying to push companies into [insolvency]. If they can help them restructure, assist in asset dispositions, mergers, or acquisitions, that will help restructure balance sheets.” Bruce Edgelow’s closing comments at the Playmaker’s Symposium echoed that view. “We do not want a fire sale, whether it’s E&P companies or oilfield services. That gets us nowhere,” he told the audience. “These are tough times, but we’re working alongside our clients to make sure we can hang in there as best we can. The discussions are getting longer, more protracted, and we’re having to work harder than ever, but there’s a huge resolve to make sure we come out of this on the other side.” — DAILY OIL BULLETIN

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43


Southern Alberta

Nabors reports Q3 loss in Canada and plans to reduce costs Nabors Industries Ltd. reported an operating loss of US$10.4 million in Canada in the third quarter as business didn’t improve coming out of the seasonally slow second-quarter spring breakup. The company is aiming to reduce costs north of the border. Nabors lost US$13.5 million during the comparable quarter last year. Rig years for the three months ended Sept. 30 dropped to 12.3 in 2009 from 35.8 in 2008. Canadian well servicing rig hours fell to 31,686 from 67,141 for the respective periods. Rig Locator records show only 57 wells drilled by Nabors in Canada during the three months ended Sept. 30, 2009, down from 190 wells for the same period last year. For the first nine months of 2009, the contractor’s well count fell to 225 from 515 a year earlier. Its two biggest customers over the first nine months of 2009 were Royal Dutch Shell (53 wells) and Apache Canada Ltd. (50 wells). “Third-quarter activity was essentially flat with an average of 12 rigs operating at an average margin per rig day of $8,248, compared to 11 rigs at $10,156 in the

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second quarter,” noted Gene Isenberg, Nabors’ chairman and CEO. “In the fourth quarter, we expect to realize further cost savings plus an increase in rig activity that should be sufficient to achieve at least a return to break-even operating income. There is very limited visibility for fullyear 2010. However, we think that firstquarter results will be in line with the

finding out what they are,” Isenberg told analysts. “The shallow singles drilling…is [going to be] much less important down the road than it is now. We not only have the rigs that work in, say, the British Columbia shales… [but] we own a ton of acreage there.” Isenberg said in a statement that the quarter likely represents the low point for the U.S. Lower 48 drilling, U.S. offshore,

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first quarter of 2009, reflecting further cost reductions and the seasonal high in activity.” Cost reductions Nabors has had elsewhere in the company “have not yet occurred to the same degree in Canada but they shall,” he said in a conference call, although no specifics were provided. Most of the increased activity will be in the further delineation and development of the Horn River and Montney shale plays in northeastern British Columbia. “The enormous potential of the British Columbia shales, we’ve only scratched the surface in

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Canadian, and other operating segments, leading to a bottoming out for its consolidated operating income. “One reason for our optimism is t he higher for ward prices for cr ude and gas, which currently are over $85 a nd $7, respec t ively, i n 2011,” t he company CEO said. Nabors reported a net income of US$42.5 million for the third quarter, down from $194 million a year ago. Nine-month profits fell to $317.9 million from $582.4 million for the same period in 2008. — DAILY OIL BULLETIN

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DECEMBER 2009 • OIL & GAS INQUIRER


Southern Alberta

Nine-month well count declines by two-thirds from peak year 2006 Northeastern Alberta and Manitoba were the only bright spots in a dismal third quarter, which saw only 1,966 new wells drilled in Canada, down 63 per cent from 5,293 wells a year earlier. For the first nine months of 2009, industry drilled 5,719 new wells, off 53 per cent from 12,053 rig releases to the end of September 2008. This year’s count is the lowest since 1992, when only 1,118 wells were finished through September. The peak year was 2006, when 17,747 wells were finished at the three-quarter mark. W h i le a l l prov i nce s saw sha r p declines from last year, British Columbia and Manitoba fared relatively better with the former province showing a drop of 30 per cent to 458 wells this year, while the latter province had a 31 per cent decline to 163 wells from 236 in the first nine months of 2008. Operators in Alberta drilled 3,922 wells through September, down 52 per cent from 8,227 wells in the first three quarters of last year.

Industry rig released 1,163 new wells in Saskatchewan over the first three quarters of 2009, 60 per cent below the 2,922 wells drilled the previous year. September brought only 711 new wells drilled, according to Daily Oil Bulletin records. That is the most since Febr uar y t his year, but 59 per cent below the 1,733 wells rig released in September 2008. Metres drilled last mont h dropped 50 per cent to 1.11 million metres as the average depth per well climbed to 1,565 metres from 1,294 a year earlier. Manitoba was the only province showing an increase in activity last month with 32 wells drilled, up from 27 a year ago. During the third quarter, Manitoba drilling held steady with 94 wells, down only one well from the same three months in 2008. The only region that showed an increase compared to last year was northeastern Alberta where 224 wells were finished, up from 172 in 2008.

Central Alberta and southwestern Saskatchewan were the worst hit regions in the third quarter with only 129 wells in the former area, off 77 per cent from 549 last year (the peak was 2005, when the region saw 1,194 wells) and only 126 wells in the latter area, down from 797 wells a year ago. (Southwestern Saskatchewan is the gas drilling region of the province.) Producers rig released only 213 wells targeting natural gas in Saskatchewan over the first nine months of 2009 compared to 919 last year. In Alberta, wells targeting conventional natural gas fell to only 1,950 from 4,782 last year. During the peak gas drilling years, the count was over 9,000 wells. Producers also rig released 578 wells targeting coalbed methane to the end of September. That compares to 956 last year and a 2006 peak of 1,649 coalbed methane wells. — DAILY OIL BULLETIN

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Southern Alberta

CNRL tops EnCana as most active operator in third quarter EnCana Corporation was easily the dominant operator of new wells drilled in the first nine months of 2009 even though its effort was much reduced from last year. The company chopped its drilling by 706 wells or 37 per cent compared to 2008. But in the third quarter of 2009—a period marked by very low drilling due to miserly natural gas prices—Canadian Natural Resources Limited was the number one operator with 315 wells, almost all targeting oil or bitumen deposits, with EnCana second at 237 wells. For the first three quarters of 2009, EnCana was the most active operator with 1,196 wells, followed by Canadian Natural Resources’ 579 wells. EnCana dominated southeastern Alberta drilling (837 wells but way down from 1,361 a year earlier) and northeastern British Columbia (85 wells versus 163 last year). Canadian Natural Resources was most active in eastcentral Alberta (238 wells) and northeastern Alberta (147 wells). Husky Energy Inc. ranked third to the end of September with 297 wells with Devon Canada Corporation fourth on 235 wells.

For both the third quarter and ninemonth period, the four companies with the largest year-over-year decline in drilling were EnCana, Husky, EOG Resources Canada Inc., and Enerplus Resources Fund. EOG was very active in southwestern Saskatchewan last year but cut backs affected its shallow gas

(656,487 metres), ConocoPhillips Canada Limited (350,863 metres), Husky (254,996 metres), and Devon (257,874 metres). Ranked by exploratory metres of hole drilled, the top five operators were EnCana, Talisman Energy Inc., Canadian Natural Resources, ConocoPhillips, and Shell.

No one came close to Tundra Oil & Gas Partnership in Manitoba. drilling program this year while Enerplus reduced its southwestern Saskatchewan activity to only 71 wells this year from 278 in the first nine months of 2008. There were few companies increasing their drilling activity this year, but some of the more prominent ones were StatoilHydro Canada Ltd. (34 wells t his year), Shelter Bay Energ y Inc. (up 32 wells to 41), Progress Energy Resources Corp. (up 22 wells to 34), and Tourmaline Oil Corp. (12 wells this year, none in 2008). Ranked by metres drilled, the top operators of the first three quarters of 2009 were EnCana (1.48 million metres), Canadian Natural Resources

By prov ince, EnCana, Canadian Natural Resources, and ConocoPhillips dominated in Alberta while EnCana, Shell, Murphy Oil Company Ltd., and Talisman were the most active operators in British Columbia to the end of September. In Saskatchewan, TriStar Oil & Gas Ltd. headed the Daily Oil Bulletin’s list with 163,840 metres drilled, followed by Crescent Point Energy Corp. (140,746 metres), Petrobank Energy And Resources Ltd. (109,593 metres), and Husky (99,124 metres). No one came close to Tundra Oil & Gas Partnership in Manitoba where it drilled 192,504 metres of hole with 83 wells at an average depth of 2,377 metres. — DAILY OIL BULLETIN

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DECEMBER 2009 • OIL & GAS INQUIRER


Southern Alberta

CERI says oilsands will boost American jobs and GDP As oilsands investment on new projects ramps up in Canada starting in 2013, demand for U.S. goods and services will expand to an estimated $40.4 billion in 2020 and $42.2 billion in 2025. Those figures are included in a recently released study by the Canadian Energy Research Institute (CERI), which pegs the capital investment and operating costs needed during the 2009–2025 period at $379 billion. Entitled Canada’s Oil Sand s and Economic Impact on the United States’ Economy, the study was commissioned by the American Petroleum Institute. Alberta’s oilsands could bring an estimated 343,000 new jobs to the United States between 2011 and 2015, and $34 billion to its gross domestic product by 2015, the expected peak year for oilsands capital spending. The CERI study covers the period from 2009 to 2025. The production forecast envisions raw bitumen production slowly climbing from current levels of about 1.2 million barrels per day to around 4 million barrels per day in 2025.

The probable range of oilsands production—highly dependent on oil prices and increased liquidity in capital markets—is widening with CERI estimating 1.9 million to 2.9 million barrels a day in 2015 and an even wide range of 3.5 million to 5.1 million barrels per day for 2025. Total investments on new oilsands projects to 2025 are estimated at $218 billion under its low-case economic slowdown scenario. “What is often not clearly understood is that the large investment in the oilsands industry contributes to increased economic activity in the rest of North America by stimulating demand for goods and services across a wide range of industries,” said the CERI report. While manufacturing—such as production of the huge trucks used in oilsands mining—will gain the most, finance and insurance sectors also benefit. Professional, scientific, and technical services in the United States alone are expected to see an average US$4.2 billion a year increase in output. The economic benefits of oilsands development and production do not fall to one industry but are broadly

shared across many industrial sectors. This is because oilsands development requires a large quantity of inputs from broad segments of the manufacturing and service sectors of the Canadian and U.S. economies. On average, U.S. output of goods and services increases by $62 billion per year over the period of analysis, 2009–2025. Steel products that would generally be manufactured in western Canada from scrap steel include casing, tubing, and other welded pipe; I-beams; tubular beams; and other simple structural components. More sophisticated and metallurgically altered steel products would be imported from the United States (primarily the upper Midwest) and overseas, or else manufactured in Ontario from steel produced in Ontario using metallurgical coal imported from the United States (primarily Appalachia). Some of the manufactured products that are likely to be sourced in the upper Midwest include trucks, shovels, dump hoppers, conveyer equipment, pumping equipment, tanks, and some boilers and chemicals. — DAILY OIL BULLETIN

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Saskatchewan

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PetroBakken pushes daily output to 44,500 boe

PetroBakken has a fleet of 13 drilling rigs working in southeastern Saskatchewan.

PetroBakken Energy Ltd., the spinoff of Petrobank Energy and Resources Ltd.’s Canadian business unit and TriStar Oil & Gas Ltd., said pro forma production averaged 41,526 barrels of oil equivalent (boe) per day during the third quarter. The newly formed company, which began trading on the Toronto Stock Exchange on Oct. 6, 2009, said it continues to add production from both the Bakken and Mississippian reservoirs in southeastern Saskatchewan through horizontal drilling and that it is now producing approximately 44,500 boe per day. During the third quarter, the pro forma PetroBakken entity drilled 89 (67.3 net), including 71 (51.4 net) Bakken development wells. The result of the expanded drilling program was an increase in production from the company’s non-Alberta assets to 32,448 boe per day,

and currently these assets are producing approximately 35,500 boe per day. “Our non-A lbertan production is expected to continue to increase through the fourth quarter with 13 rigs now working in southeast Saskatchewan, compared

figure that includes PetroBakken’s anticipated Alberta asset sales. Production from the company’s Alberta assets averaged 9,078 boe per day in the third quarter. But PetroBakken plans to sell the majority of its Alberta production to focus on high-netback light oil and highimpact resource plays, such as the Bakken play in southeastern Saskatchewan and Montney and Horn River plays in northeastern British Columbia. The company said proceeds from the contemplated disposition will be used to further solidify its balance sheet. The sale process is underway with data rooms open enabling interested parties the opportunity to review the assets. Results of the process are expected to be known later this year. The company said its Bakken drilling program has shifted to drilling primarily bilateral horizontal wells with 15-stage fracture stimulations per horizontal leg, for a total of 30 stimulations in each well. With 30 fracture stimulations per well, the company said that more time is required to completely recover the load fluid from the fracture stimulations, which creates a situation where oil rates increase as the load fluid is recovered. Recently, 10

The company has more than 500,000 undeveloped acres which provide a development inventory of over 350 drilling locations. to only five rigs in June 2009,” the company said in its third-quarter release. “Activit y and production growth through the balance of 2009 is expected to remain strong as we complete the inventory of wells awaiting completion and maintain our new drilling pace on our Bakken and conventional Mississippian pools.” As a result, the company said it is well positioned to exceed its exit 2009 production guidance of 37,000 boe per day, a

bilateral wells were put on production at initial rates between 250 and 300 barrels per day with relatively flat to increasing production rates. Through the application of leading edge technology to over 1,300 identified Bakken drilling locations, the company said the Bakken is expected to provide strong organic growth for years to come. PetroBakken is also strongly posit i o n e d i n v a r i o u s s o ut h e a s t e r n

SASKATCHEWAN WELL ACTIVITY

OCT/08

OCT/09

OCT/08

OCT/09

OCT/08

OCT/09

WELL LICENCES

455

261

WELLS SPUDDED

478

190

WELLS DRILLED

485

192

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2009

49


Saskatchewan

Saskatchewan conventional oil plays in the Midale, Frobisher, Alida, and Tilston formations. Current production of approximately 10,000 boe per day from these Mississippian aged reservoirs provides a stable platform of low-decline production. The company has more than 500,000 net undeveloped acres of land in the area which its says provides a low-risk development inventory of over 350 locations and the opportunity for seismically driven step-out and exploration drilling. Addit iona l long-ter m g row t h is expected to come from PetroBakken’s large land position within the Montney and Horn River natural gas resource plays. The company has 17 sections of land (100 per cent working interest) with

Montney potential in the Monias area of northeastern British Columbia, with a further 97 (84 net) sections north of Fort Nelson in the Horn River Basin. PetroBakken said it is well positioned to develop these unconventional resource plays given the experience of its technical team, having successfully drilled and operated over 450 horizontal wells with multi-stage fracture stimulations. At Mon ias, t he compa ny ’s f i r st Montney horizontal well was drilled in the fourth quarter of 2008, adjacent to its five million cubic feet per day gas plant. Based on the success of that well, a second well was drilled during the third quarter of 2009 and is currently being completed. The new well is a dual-leg horizontal well with high-density fracture stimulation

designed to continue to increase production rates and expected ultimate gas recoveries. The company’s first horizontal well in the Horn River Basin was drilled in the first quarter of 2009 in an area that offers multi-season access due to proximity to roads. Based on the successful results obtained from that well, PetroBakken plans to tie the well in this winter. It also plans to drill a second well in the area later this year. “Our immediate operational goal for both of these prolific resource plays is to identify optimal technology applications that lower the gas price required to provide a competitive rate of return that will ultimately allow us to initiate major fullscale developments,” the company said.

Saskatchewan's October land sale nets $32.4M Saskatchewan’s October provincial land sale drew $32.4 million—the highest of the year so far—with an average per-hectare price of $524.24 for 61,828 hectares. The 2008 sale during the same month attracted $223.4 million on 192,368 hectares at an average of $1,161 per hectare. Despite the meteoric drop in revenue, the province remains optimistic. “This shows we continue to be on the right track,” said Energy Minister Bill Boyd. “Revenue from the October sale is over double that received from the August sale. This is a clear message from industry that Saskatchewan continues to be an attractive place to invest.” In a similar trend to its western neighbours, Saskatchewan’s land sale revenues this year lag badly from 2008’s record pace,

with $83.2 million rolling into government coffers so far this calendar year compared to just over $1 billion collected in the same period last year. October’s sale included three petroleum and natural gas exploration licences that sold for $3.8 million and 273 lease parcels that attracted $28.6 million in bonus bids. The Lloydminster heav y oil area received the most bids with sales of $13.3 million. The Weyburn-Estevan area was next at $12.1 million, followed by the Kindersley-Kerrobert area with bonus bids totalling $4.6 million and the Swift Current area at $2.4 million. The highest price paid for a single lease parcel was $3.03 million for the southeast portion at 25-8-10W2. Windfall Resources Ltd. acquired this 57.47-hectare lease parcel,

located 42 kilometres east of Weyburn. This parcel also had the highest price on a perhectare basis at $52,847. Broker Scott Land & Lease Ltd. paid $3 million for a 129.09-hectare lease for the southern half of 24-6-11W2. Daily Oil Bulletin records show several producers targeting the Bakken formation in the Midale area. O & G Resource Group Ltd. paid the bonus high for an exploration licence, acquiring a 1,619-hectare block for just over $2 million for sections 21-23, the northeast portion of section 26 and sections 27, 28, and 36 at 39-24W3. The next sale of Crown petroleum and natural gas dispositions will be held on Dec. 7. — DAILY OIL BULLETIN

Glamis buys Saskatchewan light oil properties for $108M Glamis Resources Ltd. has agreed to buy the core assets of privately held Connaught Energy Ltd. as well as partnership interests from a private company. Glamis said it is getting high-quality, high-netback, light oil assets focused in its southeastern Saskatchewan core area for $108 million in cash and 88.3 million Glamis shares. The producing properties are mostly operated with high working interests and control of key producing infrastructure, and 50

DECEMBER 2009 • OIL & GAS INQUIRER

are associated with a light oil-prospective undeveloped lands. The acquisitions provide Glamis with conventional high-netback light oil assets and a dominant position in an emerging high-impact Bakken light oil play, adding to the company’s Bakken exposure. Current production of the combined assets is 1,500 barrels of oil equivalent a day (96 per cent light oil). The deal includes 3.3 million barrels of oil equivalent of reserves with a reserve life index of six years. It also

includes 63,625 net acres of undeveloped land, 25 square miles of seismic data, and 185 (137.4 net) drilling locations, including 131 (98.3 net) Bakken locations. Glamis agreed to buy Connaught Energy for $60 million in cash and 83.3 million Glamis shares. Unspecified non-core assets of Connaught will be distributed to current Connaught shareholders as part of the deal. — DAILY OIL BULLETIN


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S A L E S / R EN TA L S / SER V I C E / 1. 8 0 0.G L EN T E L 52

DECEMBER 2009 • OIL & GAS INQUIRER


Central Canada

French company invests $120M in Quebec electric car battery plant Electric cars may end oil age

he added. “Such a technology is not good for a big quantity of energy,” said Bolloré, who indicates there’s no risk of overheating with his technology. “For a car, of course, it would be very dangerous.” Bolloré Group plans to hire 200 new workers—on top of the facility’s 70 employees—to build batteries for his company’s electric car, BlueCar, and its 22-passenger Microbus. Both vehicles are produced in Italy. Automakers around the globe are racing to advance technology to extend the range of electric vehicles and to lower the price. At last month’s Frankfurt auto show, almost every major carmaker unveiled an electrified vehicle. The world’s lithium-ion battery market is expected to surge from $31.9 million this year to $21.8 billion by 2015, according to business consulting firm A.T. Kearney. Bolloré, listed by Forbes last year as worth an estimated US$1.4 billion, expects his cars to eventually be priced for the general public. “It will be a popular car—that’s what I think, but time will tell,” he said.

Deutsche Bank is the latest organization to predict that world oil demand will fall as greater efficiency of automobiles will effectively end the oil age. The bank has issued an analysis titled The Peak Oil Market, that concludes world oil demand will reach a peak in 2016 and then begin to decline due to increased efficiency, and particularly the rapid growth in electric cars. Transportation is the last major market where oil dominates as a fuel and it is now under threat in its biggest market, the United States. The report said “disruptive technology” like the hybrid and electric car will likely have a far greater positive impact on oil efficiency than the market currently expects. Recently, IHS Cambridge Energy Research Associates predicted that emerging markets like China will drive world oil demand recovery as the recession eases but demand from Organization for Economic Co-operation and Development (OECD) countries is unlikely ever to return to its 2005 high. IHS added that the peak of OECD oil demand does not mean that the end of the oil age in developed economies is imminent. The size of the decline in oil demand from the peak year of 2005 to 2030 is expected to be fairly modest. A chief economist of the International Energy Agency (IEA) recently said that the demand for oil, gas, and coal should peak by 2020, provided there is an agreement reached at the Copenhagen Climate Change Conference later this year. Deutsche Bank, meanwhile, found that by 2020 the global average mile per gallon (mpg) of newly purchased light vehicles will have increased by a bit more than 50 per cent compared to 2009, from roughly 29 mpg to about 44 mpg. The impact will be concentrated in U.S. gasoline, the largest single element of global oil demand (12 per cent) and will be dramatic enough to cause the peak of global oil demand around 2016.

— CANADIAN PRESS

— DAILY OIL BULLETIN

Manufacturers around the world are striving to create electric cars that go farther and cost less.

A French billionaire who’s in the thick of the global rush to mass manufacture affordable, reliable electric cars says he has the battery power to win the race. Vincent Bolloré announced on Oct. 27 that his company, Bolloré Group, will invest $120 million in a battery-producing factory east of Montreal. The facility, purchased from HydroQuebec by Bolloré in 2007, already churns out a few hundred electric-car power plants a year. With this investment, he aims to boost production to 15,000 annually. The batteries will be built using lithium-metal-polymer technology, which give his cars a range of 250 kilometres and a top speed of 130 kilometres per hour. Bolloré said his company is a leader in the technology. “It’s the first big factory in the world for
[lithium-metal-polymer batteries],” he said. He added that his product is safer than the lithium-ion batteries that major automakers, such as General Motors and Nissan, are counting on to propel their soon-to-be-released lines of electric cars. Lithium-ion batteries, often used in laptops and mobile phones, have been known to overheat and even catch fire,

OIL & GAS INQUIRER • DECEMBER 2009

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DECEMBER 2009 • OIL & GAS INQUIRER


East Coast

Photo: Harvest Energy Trust

Korea’s KNOC buys Harvest for $4.1B, including Atlantic refinery

A Korean acquisition of Harvest Energy could revive expansion plans for the Come By Chance refinery.

St a t e - o w n e d K o r e a N a t i o n a l O i l Corporation (K NOC) announced on Oct. 21 that it will acquire Har vest Energ y Trust for C$4.1 billion in a deal that enhances its North American growth strategy while securing oil and gas reserves for the country’s importdependent petroleum needs. About a year ago, Harvest shelved a $2-billion expansion to its refinery at Come By Chance in eastern Newfoundland. With KNOC at the helm, the odds of that project going ahead are greater, said Harvest CEO John Zahary. “That’s something that is certainly much more in the realm of possibility…but that’s something we have to look at down the road,” he said. The refinery was started in the 1960s by U.S. entrepreneur John Shaheen with the hope of importing Middle Eastern crude and refining it into fuel for the North American market. A succession of losses and owners, including the provincial government and Petro-Canada, ensued. In 1987, the refinery was reopened by Bermuda-based Newfoundland Energy Ltd. Harvest bought it three years ago. The trust had been searching for a partner to

help fund a planned major expansion to handle 190,000 barrels per day, up from 115,000 barrels per day currently. The expansion was shelved last year due to the economic downturn. Under the agreement, KNOC will buy all the issued and outstanding trust units of Harvest Energy for a total cash consideration of approximately $1.8 billion plus the assumption of $2.3 billion in debt. “Korea National Oil Corporation is excited about this acquisition and believes Har vest is a perfect fit for KNOC’s North American growth strategy. KNOC has ambitious plans for future growth and is committed to a long-term investment strategy in Canada,” said Young-won Kang, president of KNOC. “We are very pleased to be joining forces with a Harvest team that has such a deep and rich experience as well as a proven track record of success.” Harvest Energy said the deal—which equates to $10 per Harvest unit—represents a 47 per cent premium over the 30-day weighted average trading price of the units on the Toronto Stock Exchange up to and including Oct. 20, 2009. The

trust’s share prices were over $35 earlier this decade. Zahary said Harvest’s portfolio of opportunities includes large oil in place assets coupled with production and throughput expansion opportunities in the upstream and downstream segments respectively and that “continued investment by KNOC will supplement this growth.” In addition to its conventional oil and gas properties in western Canada, Harvest has holdings in both the Peace River and Cold Lake regions. In 2006, KNOC bought an oilsands lease near Cold Lake, Alta. from Newmont Mining Corporation for $270 million. At the time, KNOC said it planned to produce 30,000 to 35,000 barrels of oil per day, for 20 years, from the site and that initial production was expected around 2008, with full-scale operations to begin in 2010. However, that project has since been deferred. Har vest produced an average of 52,745 barrels of oil equivalent in the second quarter of this year, down from 55,574 barrels of oil equivalent per day in last year’s period, with heavy oil volumes dropping 14 per cent, and light oil production slipping about 4 per cent from prioryear figures. The trust’s year-end 2008 proved-plus-probable reserves were 219.9 million barrels of oil equivalent. K NOC said t he transaction w ill increase South Korea’s self-sufficiency rate—the amount of oil its companies produce versus its demand—to 8.1 per cent from 6.3 per cent. It will now own 3.02 billion barrels of proved oil reserves. Peter Tertzakian, chief energy economist at Calgary-based ARC Financial Corp., told the Daily Oil Bulletin that the KNOC-Harvest deal is indicative of what he believes is a growing trend as emerging economies look to meet their growing energy demands. “Economies, like Korea, that continue to industrialize, mobilize, and urbanize at a fast pace over the long-term recognize that they need to scramble for the world’s strategic energy assets,” he said. — DAILY OIL BULLETIN and CANADIAN PRESS OIL & GAS INQUIRER • DECEMBER 2009

55


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International

Royal Dutch Shell cuts 5,000 as Q3 net profit falls by 62 per cent

— ASSOCIATED PRESS

— ASSOCIATED PRESS

Photo: Royal Dutch Shell

“In comparative terms, Shell was a lway s goi ng to h ave a mou nt a i n t o c l i m b f o l l o w i n g B P ’s s t e l l a r performance earlier in the week,” said analyst Richard Hunter of Hargreaves La nsdow n in a note. (BP is Shel l’s largest European rival.) “Unfortunately, these numbers leave it some way short of the summit.” Shell pumped 2.93 million barrels of oil per day in the third quarter, f lat from a year ago. The company’s earnings from production fell 82 per cent to $1.54 billion, ref lecting the fall in oil prices. Shell sold oil at $63 per barrel in the third quarter from $111 a year ago. Henry said the recent recovery in oil prices to around $78 per barrel is speculative. “Fundamentally, we don’t see demand turning yet and there’s plenty of supply available,” he said. Shell’s refining earnings fell 47 per cent to $1.29 billion, including a gain of $536 million because of a rise in the estimated value of inventories. Shell said refining margins worsened due to lower demand.

Exxon Mobil Corp. reported on Oct. 29 that oil production is bouncing back with crude prices. However, the world’s largest publicly traded oil company cautioned that a worldwide glut in petroleum supplies may still cool the latest surge in oil, squeezing refiners and keeping profits in oilpatch well below their peak last year or even the past several years. Exxon Mobil reported that profits from July to September dropped 68 per cent, to US$4.73 billion. The results were the best of the year so far, but they’re less than onethird of what Exxon earned in the same period of 2008, when crude prices spiked above US$147 per barrel. In fact, excluding the previous two quarters of this year, Exxon has not reported quarterly profits this low in at least the past four years. The company, based out of Irving, Texas, gets most of its income from oil and gas production. In the third quarter of 2009, it increased production by three per cent to 3.69 million barrels of oil equivalent per day. Yet the returns are not as good because crude fetched an average of $50 less per barrel when compared with the year-ago period. Exploration and production, or Exxon’s upstream business, saw earnings drop 63 per cent to $4.01 billion in the third quarter. Its oil refining business posted a loss of $203 million in the United States compared with a profit of $978 million in the same three-month period of 2008. Exxon has operations around the world, including Canada, where it owns about 70 per cent of Calgary-based Imperial Oil Ltd., Imperial announced that its net profits fell to C$547 million from nearly $1.4 billion in the same period last year. Imperial said its operating revenue was $5.55 billion.

Shell, whose global assets include Norway’s Ormen Lange gas field (above), may have to cut more jobs.

Royal Dutch Shell PLC reported a 62 per cent fall in profit for the third quarter of this year due to lower oil prices, and said it plans to cut 5,000 jobs. Shell said net profit was US$3.25 billion (2.21 billion euros), down from US$8.45 billion in the same period a year ago. Sales fell 43 per cent to $75 billion. Shell CFO Simon Henry said the company is not expecting a swift economic recovery and this year will cut around five per cent of its workforce, some 5,000 jobs, primarily in middle management. “In Europe there are few if any signs of demand recovering…. In the United States, if anything, there’s some bottoming, improvement in one or two subsectors, but not yet firm enough to call a recovery,” Henry said. The job cuts come on top of 500 layoffs among senior management earlier this year. Around 15,000 employees will also be forced to apply to keep their jobs, and cuts among the rank and file are possible in 2010, he said. He said the company will take a restructuring charge of “several hundreds of millions” in the fourth quarter.

Exxon Mobil boosts production in Q3, but profits fall with crude prices

OIL & GAS INQUIRER • DECEMBER 2009

57


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We welcome Michelle to the team and wish her continued success.

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On the Job

onthe

JOB Careers in the Oilpatch

JoAnn Weiss

Age: 48 going on 38 Title: Parts Person, Safety Auditor, Entrepreneur Companies: Kinetic Safety Consulting Inc., Mechanics In Motion, and Safety Auditing & Services Inc.

What was your introduction to the oilpatch? I received my journeyman parts ticket with R. Angus Caterpillar in Grande Prairie and then got into service rigs. At Beta Well Service, I worked as the Girl Friday. For Cenalta Well Servicing, I did everything from office work and hotshot driving to safety support, which helped get me into my present businesses.

What’s your simplest tip for avoiding strain and stress injuries? Let’s say a crew drives three or four hours to get to a lease site, and then the boss is in a hurry to get his guys unloading tools, rigging in, and whatever’s needed to get the job underway. In that situation, just a few minutes of stretching makes a big difference. In fact, stretching before work or when you’re stiff will reduce overall workplace injury rates by 25 per cent. Lifting technique is also critical. Mechanics In Motion teaches several different types of lifts and stretches. Our four-hour program blends classroom, field video review, and practical hands-on with the client’s equipment, customized for each customer.

Why did you focus on safety in particular? I grew up on a farm in this district, which meant hauling slop pails, throwing hay bales over fences, and other heavy work. Years later, I tripped in a pothole while jogging. When I went for treatment, the physiotherapist explained that farm work had damaged my lower back and hips from improper lifting. It’s so much better to prevent these problems rather than ignoring the risks until you’re actually in trouble. I believe oil and gas safety training should extend from how an oilfield worker moves bags of cement through to evading that deer when it pops up in front of your headlights. You run three small businesses—how do they connect? Oil and gas workers move objects that are heavy, awkwardly shaped, in low or high placement, and so on. Our custom training program Mechanics in Motion reduces severity of soft tissue injure from pushing, pulling, heavy lifting, handling, and repetitive work. Kinetic Safety employs three retired police officers who instruct the Proactive Driving Course candidates on how to remain safe and avoid being involved in collisions in all situations. Safety Auditing and Services does conventional safety audits to help reduce injuries in the workplace.

How does Kinetic Safety’s driver training work? Our Proactive Driver Training Course enables candidates to practice skid avoidance and recovery utilizing a Swedish skid system mounted on a pickup truck. Our 16-point Commentary Drive exercise shows how a driver must drive to avoid a collision. There’s quite a bit more as well. Although it’s fun and we have passionate instructors, we’re very serious about accident avoidance. Why did the Desk and Derrick Club name you Canadian Energy Person of the Year for 2009? I’ve been active in the club for 22 years, along with the Grande Prairie Petroleum Association. I’ve help organize the association’s golf tournaments and bonspiel for many years, along with Clay Shoot and Hockey tournament. I’ve done other volunteer and charity work in the community. I love this industry—in my experience, it’s got more than its share of genuine, down-to-earth, honest people.

OIL & GAS INQUIRER • DECEMBER 2009

59


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We’re increasing our editorial content with stories and columns focusing on how companies are handling the downturn, preparing for the rebound, and, in some cases, even thriving. They’ll be easy to find. Just look for the special Recession to Recovery logo in each issue of Oil & Gas Inquirer.

www.brownleelaw.com

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Tools of the Trade

TOOLS

Who is Phoenix Heli-Flight? Operating since 1991, Phoenix Heli-Flight is a locally owned helicopter charter operation serving the Fort McMurray and northeastern Alberta region. We utilize seven of the newest Eurocopter single and twin turbine engine heli-

OF THE TRADE

copters for both passenger and cargo transport to support many business

A LOOK AT NEW TECHNOLOGIES

Helicopter Flight Data Management or HFDM is a safety management system

sectors requiring vertical lift or operating in remote areas. How does Helicopter Flight Data Management improve performance? that uses onboard sensors to gather information about every movement the helicopter makes. The data from the helicopter is then analyzed to verify that the pilot is flying within limits set by the company and the helicopter manu-

Phoenix Heli-Flight Fleet

facturer. A 3-D computer graphic playback of any flight lets the company use the visual presentation as a training aid for all pilots. What is Outerlink? Outerlink is a satellite-based tracking and communication system that, unlike most other tracking systems, uses a geostationary satellite to bounce signals rather than connecting via orbiting telephone satellites. The advantage is affordable accuracy as Phoenix receives four times the position reporting data for 25 per cent of the cost of a satellite telephone–based system. This system also provides two way voice messaging and it automatically sends electronic messages to our managers if the helicopter is having any mechanical problems. What is Heli-Flight’s Safety Management System? In 2009 Phoenix Heli-Flight implemented a Safety Management System (SMS). The SMS documents provide the structure and performance measurement tools to ensure that the company’s safety and quality assurance goals are being met by auditing and documenting all areas of company activity. Beyond safety, what are your company’s most important priorities? Personnel and aircraft. Our helicopter fleet is the most modern in Canada. We have a great team of veteran bush pilots who are factory trained on our machines as well as highly experienced in virtually every aspect of helicopter operations in this region.

Answered by Paul Spring, President and Owner of Phoenix Heli-Flight

OIL & GAS INQUIRER • DECEMBER 2009

61


Political Cartoon

Advertisers' Index 1174365 Alberta Ltd . . . . . . . . . . . . . . . . . . . . . . 48 Acklands-Grainger Inc . . . . . . . . . . . . . . . . . . . . 17 Allan R. Nelson Engineering (1997) Inc . . . . . . . . 51 All Weather Shelters Inc . . . . . . . . . . . . . . . . . . 27 Annugas Compression Consulting Ltd . . . . . . . 21 Bear Slashing Ltd . . . . . . . . . . . . . . . . . . . . . . . 30 Bidell Equipment LP . . . . . . . . . . . . . . . . . . . . . 32 Bilton Welding and Manufacturing Ltd . . . . . . . 58 Black Sivalls & Bryson (Canada) Ltd . . . . . . . . . . 11 Brews Supply Ltd . . . . . . . . . . Outside back cover Brother’s Specialized Coating Systems Ltd . . . 10 Brownlee LLP . . . . . . . . . . . . . . . . . . . . . . . . . . 60 CJS Coiled Tubing Supply . . . . . . . . . . . . . . . . . 54 Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . 58 Crimtech Services Ltd . . . . . . . . . . . . . . . . . . . 48 Crompton Western Canada Inc . . . . . . . . . . . . . 44 Dean’s Pump Service Ltd . . . . . . . . . . . . . . . . . 39 Delta Industrial Valves Inc . . . . Inside back cover DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Dicks Boiler Ltd . . . . . . . . . . . . . . . . . . . . . . . . . 54

62

DECEMBER 2009 • OIL & GAS INQUIRER

Diversified Glycol Services Inc . . . . . . . . . . . . . 30 Double S Oilfield Services Ltd . . . . . . . . . . . . . 54 Enviro Vault Ltd . . . . . . . . . . . . . . . . . . . . . . . . . 51 Eveready Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Falvo Electrical Supply Ltd . . . . . . . . . . . . . . . . 58 Fast Trucking Service Ltde . . . . . . . . . . . . . . . . 28 Flexpipe Systems . . . . . . . . . . . . . . . . . . . . 34/35 Glentel Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 Global Oil & Pipe Inc . . . . . . . . . . . . . . . . . . . . . 56 Hi-Way 13 Transport Ltd . . . . . . . . . . . . . . . . . . 48 Infosat Communications . . . . . . . . . . . . . . . . . 46 Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . 56 Kangabags . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 LJ Welding & Machine . . . . . . . . . . . . . . . . . . . . 38 LoTech Manufacturing Inc . . . . . . . . . . . . . . . . .38 Meridian Mfg Group . . . . . . . . . . . . . . . . . . . . . 42 MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . 56 Norsteel Buildings Ltd . . . . . . . . . . . . . . . . . . . . 51 Northern Alberta Institute of Technology . . . . 36 Northstar Energy Services Inc . . . . . . . . . . . . . . 4

Oil Lift Technology Inc . . . . . . . . . . . . . . . . . . . . 29 OilPro Oilfield Production Equipment Ltd . . . . 56 Pedestal Supply . . . . . . . . . . . . . . . . . . . . . . . . 30 Pembina Controls Inc . . . . . . . . . . . . . . . . . . . . 36 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 Petroleum Services Association of Canada . . . 24 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . 32 Phoenix Heli-Flight . . . . . . . . . . . . . . . . . . . . . . 47 Platinum Energy Services Corp . . . Inside front cover Propak Systems Ltd. . . . . . . . . . . . . . . . . . . . . . . 3 ProstAid Calgary Society . . . . . . . . . . . . . . . . . 52 PRO-V MFG. INC. . . . . . . . . . . . . . . . . . . . . . . . . 45 RTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 SafeHouse Habitats . . . . . . . . . . . . . . . . . . . . . 36 Sage Energy Corp. . . . . . . . . . . . . . . . . . . . . . . . . 5 Singletouch . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Systech Instrumentation . . . . . . . . . . . . . . . . . . 7 T & E Pumps Ltd . . . . . . . . . . . . . . . . . . . . . . . . 30 Trans Peace Construction (1987) Ltd . . . . . . . . 32 Vertigo Theatre Society . . . . . . . . . . . . . . . . . . 40


Electrical Supplies when you need them

Automation

Brews Supply Ltd. – offering a broad range of electrical products, in stock and ready to ship!

Wire Handling

With over 80 years in business, Brews knows what the oilpatch needs from an electrical supply company.

Distribution Equipment

Heating Equipment

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Enclosures

Meet the Newest Member of Your Crew Brady’s high performance wire ID materials are now available in an easy-to-use, economical printer – the BMP™21 Portable Label Printer. Simple to operate and quick to print, the BMP™21 label printer creates clear, legible labels that stick and stay stuck - even in the harshest environments. Easy one-handed operation with magnet accessory • Continuous Permasleeve Wire Markers • Continuous Self-Laminating Labels up to 1.5” • For more information visit www.brewssupply.com

BREWS Supply Ltd. Toll Free 1.800.661.6884 www.brewssupply.com Calgary (Head Office) 12203 40th St. S.E. PH 403.243.1144 Edmonton 18003 111th Avenue N.W. PH 780.452.3730


Oil & Gas Inquirer - December 2009  

FRAC FREEZE & FLOOD PULSE Made-in-Alberta innovations can draw more crude from conventional oil reservoirs

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