Oil & Gas Inquirer August 2011

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Keeping readers regionally informed

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New technology, royalty and regulatory changes lead to flash flood of oil development plans in central Alberta

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The hunt for liquids in the Deep Basin

Incremental gains

in Lloydminster's heavy oil fields

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URE IL & PRESS C. N I HOT O S E C I V R SE

After working at his father’s hot oil company for almost a decade, Tim McGregor saw a market for his services for highpressure gas wells in northern Alberta. By the late 1990s, McGregor knew he had enough experience to start his own business, and in 1998, he started Xtreme Hot Oil & Pressure Services Inc. “When I started my business, I knew there was a lot of potential out here. I moved my family from Consort to Hinton and I started with one truck. Now the company has a fleet of 17 units consisting of hot oilers, frac heaters, and fluid pumpers,” says Tim McGregor, president of Xtreme Hot Oil & Pressure Services Inc. Almost 95 per cent of Xtreme’s services are for the drilling and completions of sweet and sour, deep, high-pressure gas wells in northwestern Alberta and northeastern British Columbia. The company offers high-pressure and high-rate pumping which is a key component to coil tubing operations as well as tool placement for the wireline companies for horizontal multi-stage fracing.

Xtreme’s competitive advantage is its five-pronged approach to business.

Doug Sparrow, general manager of Xtreme, says “We build innovative equipment, we provide exemplary service, we employ highly experienced personnel, we hold a perfect safety record, and we build long-term relationships with our customers and suppliers.”

Sparrow says Xtreme’s innovative equipment is very diversified and complex. “Our units are built with the latest industry technology. So, instead of doing jobs singularly, we can complete two jobs with the same unit which results in great efficiency and cost savings to our clients,” says Sparrow.

Sparrow also says a key innovation of Xtreme’s equipment is the software

that the company’s units use. “We use comprehensive software packages, providing real-time, on-site data from the wells. We can then network this software to other services companies. This is a critical service that we offer to our clients as it enables them to make very important next-steps decisions about their wells.

Last year, we saved one of our biggest clients $2 million.”

Xtreme’s frac heaters are rated from 8 to 38 MBTU. These consist of propane and diesel-fired burners, allowing for the heating of frac oil, large tank farms, or bodies of water. The company’s 38 MBTU heater can heat at four degrees per minute on a 400 barrel tank, and is ideal for pond heating.

Xtreme also uses the best pumps.

The company’s X-22 is a multi-purpose pumping unit that is capable of pumping acid, frac oil, methanol, glycol, and water with three different high pressure pumps that are capable of pumping 3,000, 5,000, and 15,000 psi. The X-22 specializes in pressure testing BOPs, wellheads, pipelines, completion projects, and drilling applications.

Not only does Xtreme meet or exceed its clients’ safety programs, but whenever there might be a gap, the company rectifies it. “We have a third-party audit conducted on our safety program every year. If the safety audit recommends that we add to or make changes to our safety program, then we do so. We also employ two safety training coordinators who train all of Xtreme’s staff and ensure that all employees comply with our company’s safety program. Since starting in 1998, the company has had no loss-time incidents ever,” says Sparrow.

Coming from a family-owned business, McGregor operates Xtreme in the

same manner. Says McGregor, “We are a very caring company with a tight-knit family culture and very loyal employees.”

It is this style of business that has allowed Xtreme to provide excellent service to their clients. “We look for and anticipate our clients’ future needs and wants and take actions toward filling those requirements.”

Xtreme also attracts and retains highly experienced personnel. “Our employees have decades of experience in the industry and their dedication and loyalty to the company is reflected in their work.”

And the solid, long-term relationships that Xtreme has built with its clients and suppliers in the past 13 years has solidified their roots and strengthened their ties in the industry. “Our ability to communicate with and work closely and proactively with our clients is paramount to making sure that the company’s services are completed to the highest level of standards.”

Xtreme has 45 employees with bases in Hinton and Drayton Valley with a third base to open very soon. The company operates in the Deep Basin, Ground Birch, and Pembina as well as other areas.

Xtreme provides services to Shell Canada, Tourmaline Oil, Vermilion Resources, PetroBakken, Peyto, Fairbourne, Daylight, Celtic and numerous other companies.

McGregor says Xtreme’s strategy is to continue to build innovative equipment as per their clients’ requirements in conjunction with the company’s parallel growth. “Although very low gas prices have slowed the gas sector in recent years, this period has provided us with needed time to plan our strategy for growth which is to enter new markets on a national level.”

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F E A T U R E S

14

Perfect storm

By Darrell Stonehouse, with notes from Daily Oil Bulletin staff Technological, royalty and regulatory changes create flash flood of conventional and tight oil projects across central Alberta

21

Rocky Mountain high

By Darrell Stonehouse, with notes from Daily Oil Bulletin staff Unique geology drives Deep Basin activity

27

Steady progress

By Darrell Stonehouse Lloydminster producers finding ways to wring incremental value out of heavy oil resource

8

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A few short years ago it looked like western Canada’s conventional oil industry was ready to be put to bed. Reserve additions were few and far between and production was on a steady decline.

That’s all changed.

Extended reach horizontal drilling and multistage fracturing, combined with new regulations allowing for tighter well spacing, have laid the groundwork for prosperity for another generation of Albertans.

A new era of petroleum development in western Canada is here, Penn West Exploration president and chief operating officer Murray Nunns told the audience at the Canadian Association of Petroleum Producers’ investment symposium.

“There’s been 100 billion barrels of conventional oil found in Canada, and only 20 billion barrels have been taken out through vertical technologies,” Nunns explained. “If you eliminate the carbonate and reef plays [that have higher recovery percentages], only 10–12 per cent has been recovered. With the same reservoirs in the U.S., there is 25–35 per cent recovered.

We believe there’s five to 10 per cent we can recover with primary horizontal technology, and another five to 10 per cent with enhanced recovery using horizontal technology.”

That’s another eight billion to 16 billion barrels of oil that could potentially be brought to market.

Penn West’s optimism is shared by another early entrant into the tight oil world, Crescent Point Energy Corp.

Crescent Point is looking to bulk up its already large oil-in-place numbers and has the “potential to double” proved-plus-probable reserves, which currently stand at just under 380 million barrels of oil equivalent, president and chief executive officer Scott Saxberg said at Crescent Point’s annual meeting.

He noted that the company currently has about 10.6 billion barrels of oil in place and has recovered only 3.4 per cent and booked 8.5 per cent (proved plus probable) of that total.

However, Saxberg said that based on analogue data, infill drilling and the company’s own technical data, he believes the recovery factor can be increased to almost 18 per cent.

“You take that difference between what we currently have booked and what we believe based on our technical and historical numbers, and we think we can add almost 630 million barrels of reserves above and beyond our almost 380 million barrels booked to date,” he said.

“That’s an incredible stat. It doesn’t include our waterflood upside. So an additional 10 per cent recovery at Viewfield [Bakken] and an additional five per cent or more recovery at Lower Shaunavon, and you start to throw those numbers around and it gets upwards of 900 million barrels of potential adds. At 3.4 per cent recovery to date, we’re just getting started.”

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September edition In our September issue we track in situ technology advances opening up more and more oilsands resources to development. We also look at future growth in the pipeline industry, and efforts to make pipelines safer.

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OIL & GAS INQUIRER • AUGUST 2011

11

Stats

AT A GLANCE Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

TOTAL

MONTH

OIL

GAS

DRY

SERVICE

TOTAL

Jun 2010 Jul 2010 Aug 2010

126 131 168

117 110 135

41 38 43

284 279 346

Jun 2010 Jul 2010 Aug 2010

295 193 452

153 9 156

40 16 40

16 4 15

504 222 663

Sept 2010 Oct 2010 Nov 2010

357 404 579

638 460 847

59 46 169

1,054 909 1,595

Sept 2010 Oct 2010 Nov 2010

617 678 868

790 581 989

45 39 75

23 18 165

1,475 1,316 2,097

Dec 2010 Jan 2011 Feb 2011

676 226 353

403 145 294

294 82 127

1,373 413 774

Dec 2010 Jan 2011 Feb 2011

1,061 409 723

559 201 378

78 33 38

238 17 99

1,936 660 1,238

Mar 2011 Apr 2011 Jun 2011

650 419 209

974 472 124

222 112 100

1,846 1,003 433

Mar 2011 Apr 2011 Jun 2011

1,069 618 428

1,081 509 197

64 46 12

164 81 183

2,378 1,254 818

Wells Drilled In British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS D R I L L E D

CUMULATIVE *

MONTH

OIL

GAS

OTHER

TOTAL

Jun 2010 Jul 2010 Aug 2010

42 65 45

416 481 526

Jun 2010 Jul 2010 Aug 2010

149 220 198

7 7 12

11 0 7

167 227 217

Sept 2010 Oct 2010 Nov 2010

40 42 43

566 608 651

Sept 2010 Oct 2010 Nov 2010

197 201 217

5 12 3

6 11 64

208 224 284

Dec 2010 Jan 2011 Feb 2011

49 62 69

700 62 131

Dec 2010 Jan 2011 Feb 2011

340 136 321

2 4 6

11 3 7

353 143 334

Mar 2011 Apr 2011 Jun 2011

55 41 54

186 172 419

Mar 2011 Apr 2011 Jun 2011

316 183 217

8 11 25

4 11 89

328 205 331

*From year to date * from year to date

12

AUGUST 2011 • OIL & GAS INQUIRER

FAST NUMBERS

843

$

41

$

million

The record bonus bid at the June Alberta land sale.

million

The amount bid at Saskatchewan’s third-best-ever June land sale.

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada July 14, 2011 Source: Rig Locator

Alberta July 2011 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

(Per cent of total)

Western Canada Alberta

ACTIVE

268

285

553

48%

48

40

88

55%

6

4

10

60%

Saskatchewan

108

49

157

69%

WC Totals

430

378

808

53%

0

0

0

0

British Columbia

Manitoba

OIL WELLS

Alberta

June 11

June 10

June 11

June 10

Northwestern Alberta

27

30

53

79

Northeastern Alberta

46

25

0

0

128

60

46

16

8

14

25

20

209

129

124

115

Central Alberta

Northwest Territories

GAS WELLS

Southern Alberta TOTAL

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada July 14, 2011 Source: Rig Locator

Alberta July 2011 Source: Daily Oil Bulletin

ACTIVE

DOWN

TOTAL

Western Canada Alberta

ACTIVE (Per cent of total)

318

326

644

49%

British Columbia

9

19

28

32%

Manitoba

11

4

15

73%

Saskatchewan

145

54

199

73%

483

403

886

55%

0

0

0

0

WC Totals Quebec

COALBED METHANE

Alberta

BITUMEN WELLS

June 11

June 10

June 11

June 10

Northwestern Alberta

0

1

1

2

Northeastern Alberta

0

0

46

25

Central Alberta

38

3

30

9

Southern Alberta

10

2

0

0

TOTAL

48

6

77

36

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CathedralEnergyServices.com/content/careers OIL & GAS INQUIRER • AUGUST 2011

13

Perfect

Storm

By Darrell Stonehouse, with notes from Daily Oil Bulletin staff

Technological, royalty and regulatory changes create flash flood of conventional and tight oil projects across central Alberta

Photo: Aaron Parker

14

AUGUST 2011 • OIL & GAS INQUIRER

Feature

T

he advent of extended reach horizontal drilling and multistage fracturing has given western Canadian oil and gas producers the tool box needed to turn billions of barrels of conventional oil resource trapped in tight rock formations into reserves.

Combined with an improved royalty scheme in Alberta and regulatory changes allowing tighter down-spacing of wells, the drilling and completion revolution has set off a boom in drilling oily reservoirs across the Western Canadian Sedimentary Basin, said Murray Nunns, president and chief operating officer of Penn West Exploration, at the Canadian Association of Petroleum Producers Investment Symposium in mid-June.

“It’s been a bit of a perfect storm,” said Nunns. “Western Canada has been underdeveloped for the last 40 years. The regulatory and royalty changes and the technology have solved that.”

Nowhere is this more evident than in central Alberta, where oil explorers have amassed huge land bases in legacy fields like the Pembina and Swan Hills, and are now in the process of appraising their resource potential and in some instances moving to full field development. The Viking formation is also being targeted across the region.

Nunns said the size of the potential prize is huge.

“There’s been 100 billion barrels of conventional oil found in Canada, and only 20 billion barrels have been taken out through vertical technologies,” he explained. “If you eliminate the carbonate and reef plays [that have higher recovery percentages], only 10–12 per cent has been recovered. With the same reservoirs in the U.S., there is 25–35 per cent recovered. We believe there’s five to 10 per cent we can recover with primary horizontal technology, and another five to 10 per cent with enhanced recovery using horizontal technology.”

Penn West holds a dominant posit ion in t wo of t he most advanced tight oil plays in central Alberta—the Pembina Cardium and the Beaverhill Lake Carbonate Play surrounding Swan Hills. It is also in the early stages of developing another play with potentially

massive resources in the Colorado Viking Formation in east-central Alberta.

In the Pembina Cardium, Penn West has identified more than 2,500 potential drilling locations on around 665,000 net acres of land. Nunns said the company has completed appraisal of its lands in the play and is now moving to full development.

Wells in the play are being drilled with average horizontal legs of 1,400 metres and completed with around 20 fracture stages. Fracture loads average 20 tonnes per treatment.

Nunns said the company’s appraisal drilling of its Pembina lands shows all parts of the play aren’t equal.

“There’s a pattern to the field. The deeper you are, in west Pembina or Willesden Green, the higher the productivity,” he explained.

In the west Pembina area, average first-month production is 175 barrels per day compared with 125 barrels per day in eastern parts of the field.

Nunns said the next big economic driver in the Cardium is doing more pad drilling in the play. Currently around 25 per cent of Penn West’s wells have been grouped on pads. By year-end, Nunns said that number would be 75 per cent.

“In the appraisal phase, costs are 20–30 per cent higher than in development,” he explained. “We’re now in the phase where we are pad drilling with four to eight wells per pad. This limits rig moves, tie-ins, construction costs.”

Junior producer Bellatrix Exploration Ltd. is also targeting t he Pembina Cardium.

Bellatrix boasts 86 net sections of land in the play with 320 drilling locations.

Company president Ray Smith tracked the technological evolution of the Pembina play at the company’s annual meeting in late May. “The Cardium is a play that’s been a slow developer. When people first got involved in the Cardium, it was basically shorter horizontals fracked with oil, and we slowly started to experiment and optimize to make it better and better,” Smith said.

Bellatrix was one of the first to use water-based fracturing fluids, starting last May after drilling 13 oil wells, Smith said.

Bellatrix uses two different kinds of water fracs—slickwater and foam water.

“One of the reasons we believe we’re getting significantly better results with water fracking is we don’t put in additional constituents in the fracking fluid that will precipitate out against the formation. Some of the gelling agents in oilbased completion fluids precipitate out, and we think that causes an impermeability barrier along the frac face in most cases,” he explained.

In one area of Bellatrix’s Cardium pool at Willesden Green, the company uses a foam-water frac.

“It creates a very long frac face that you can pack with sand to give it maximum conductivity,” Smith said. “In doing that particular frac, we’re finding great results. Those wells are coming on in the 500-barrel-per-day range and are doing 300–350 barrels a day after 30 days, and they’re levelling out at 150 barrels a day after six months.”

In western Pembina, where the rock is tighter, Bellatrix has found that slick­water fracture treatments are more effective.

“In each one of the fracture areas, we create an additional 10 or 15 sub-fractures as we’re stimulating the well.... And as a result I think our company has posted the best results that I’ve seen in the Cardium so far this year,” Smith said.

Bellatrix has drilled 34 operated wells in the area—13 fracked with oil and the remaining 21 fracked with water. Smith displayed charts comparing Bellatrix horizontal Cardium oil production results after water fracs to the results of the original oil fracs. After six months, the water-fracked wells were producing about 130–140 barrels a day—almost double the rate of the oil-fracked wells, which were levelling out at about 70 barrels a day.

Technological advances allowing producers to access more reserves per well, combined with a five per cent royalty holiday for horizontal oil wells, make the Pembina highly profitable, said Smith.

“Overall, our reserve adjudicator has given us, on all of the wells we’ve drilled, an average of 186,000 barrels of oil. When we run that against our finding and develop­ ment costs and lease operating costs and an $80 flat oil price, we’re looking at a rate of return of 500 per cent,” Smith explained.

“Those are stellar economics. One reason OIL & GAS INQUIRER • AUGUST 2011

15

Photo: Aaron Parker

Feature

Service companies across central Alberta are busy drilling and completing tight oil wells.

why they’re so much better than most people’s is this is legacy land. We haven’t spent $2 million or $3 million per section in buying the land.”

The Beaverhill Lake Carbonate Play in the Swan Hills north of Edmonton is another hot tight oil play in central Alberta. Again, Penn West is a leader in the play, with 200,000 net acres of land and 500 drilling locations identified. The

company is developing the play using 1,400-metre horizontals with 15-stage acid fracture treatments.

Nu n n s desc r ibed t he c a rbonate play as a long, extended plat for m.

Historically, explorers have targeted reefs on the platform with great success.

However, sometimes they would “screw up and miss the target, but they would still find a little bit of oil.”

Nunns said those missed wells are what explorers are currently targeting in the carbonate play.

“They’re going out to the platform and following the old vertical wells,” he explained. “Not all the old vertical wells had oil shows—some were tight—so how much of the platform is prospective is unknown.”

Nunns added with well costs at $4 million per well, it’s going to take deep pockets to test the extent of the tight carbonate play over the long term.

“I expect the juniors will probably sell off before drilling all the known vertical parts of the platform,” he explained. “But there is a much bigger prize out there.

We’re looking at 500 locations that are follow-ups to verticals and then beyond that we’re looking at how you explore the rest of the platform.”

Penn West reported that average rates on the first 12 wells it drilled were almost 200 barrels per day, and several wells were in the 250-barrel-per-day range after three months. The company has drilled a total of more than 20 wells into the play to date.

Junior producer Arcan Resources Ltd. is another dominant player in the

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Feature Producers are using a 14-stage fracture stimulation program with a retrievable multi-fracturing tool that allows full wellbore access later if needed. More and more acid is being pumped in each fracture

“

pointed to a competitor’s pilot test of CO2 EOR that showed the recovery factor could be increased to 60 per cent.

A third major play taking shape in central Alberta is in the Colorado Group

We drilled 25 test wells last year, and what we identified out there is a series of oil accumulations we want to now follow up on.

—Murray Nunns, President and Chief Executive Officer, Penn West Exploration

stage to open up more reservoir. Operators are now injecting as much as 1,200 cubic metres of acid per stage. The acid ­treatment is custom-designed for the formation rock.

Jet pumps are being used to enhance cleanup after the fracture stimulation to mitigate any formation damage. And multiwell pads are being used to cut costs.

Gilmet said Arcan has about 600 million barrels of original oil in place on its Swan Hills lands. The company is investing heavily in waterflood facilities to coax as much of that oil to the surface as possible. Gilmet said he expects recoveries of 40 per cent with waterflooding. And further ahead, he

“

Beaverhill Lake play, with 150 net sections of land and 400 horizontal targets identified. Its main target is the Ethel oil pool on the eastern side of the Swan Hills field.

Since beginning its horizontal program at Swan Hills in late 2009, Arcan has drilled 27 horizontal wells into the Beaverhill Lake Carbonate Play, with two wells on the go in the second quarter.

“None of our competitors have drilled anywhere near this number of wells,” Arcan president and chief executive officer Ed Gilmet said at the company’s annual meeting in early June. “And when you’re looking at new technology—that is the horizontal multistage frac technology being used on this play—you have to admit that Arcan has spearheaded the development of this play.”

Arcan is spending $135 million this year, of which $44.2 million was spent in the first quarter. The company plans to drill 20–25 multi-frac horizontal wells at Ethel as well as construction of a pipeline and waterflood infrastructure. Enhanced oil recovery (EOR) plans for water injection at Ethel are underway.

T he technolog y needed to access the tight oil in the carbonate play is advancing, Gilmet told shareholders.

in the eastern reaches of the province.

The play started in the Dodsland area of Saskatchewan, where Penn West began applying horizontal drilling and multistage fracturing to the Viking Formation.

“We’re in full-scale development there,” Nunns said. “But the more curious part of the play is to the east, and we have 500,000 acres there.”

Nunns said Penn West initially thought the Colorado Group was gas prone, making it less desirable given the current price environment.

“On closer examination, we found there is a mix of gas and oily gas throughout

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OIL & GAS INQUIRER • AUGUST 2011

17

Feature

Apache using EOR to drain central Alberta oilfields Apache Canada Ltd. believes that using a variety of enhanced oil recovery techniques will allow the company to increase oil production by over 50 per cent in the next four years in western Canada.

Much of the company’s focus is on oil plays in central Alberta, including the Mannville play near Provost in eastern Alberta, the Swan Hills carbonate play and the Viking play across central Alberta.

Current oil production is about 18,000 barrels per day and Apache has 1.2 million net acres of oil and enhanced oil recovery (EOR) projects that offer opportunities in new waterf loods, waterflood redesign, horizontal drilling, and chemical and miscible EOR. Apache has identified 86 oil and EOR locations for this year with over 500 by 2015, and that number is likely to

increase as it down-spaces and de­velops these areas, Tim Wall, president of Apache Canada Ltd., said at the com­ pany’s recent investor day.

The Mannville light oil play (more than 30 degrees API) at Provost is shallower with well costs of about $600,000, “but the opportunities are huge,” as the 1.3 million gross acres are underdrilled, said Wall. Apache has had a continuous program this year and last and will continue to drill wells there as it de­velops the field going into little pockets of floods with CO2 completing the picture.

At House Mountain, a developed field in Alberta where Apache has been drilling for the past 18 months, the company anticipates rates of up to 1,500 barrels a day with horizontal, multi-frac completions even though this year the

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18

AUGUST 2011 • OIL & GAS INQUIRER

highest rate has been about 600 barrels per day.

The field is a Swan Hills carbonate waterflood that is a prime candidate for down-spacing, said Wall. Apache has successfully drilled horizontal infill wells using multistage acid frac technology and as a result, production is likely to increase substantially over time, he said. The company has an inventory of 33 wells over the next five years and is testing the boundaries of the field.

Because it is mostly oil, the rate of return is better than 100 per cent.

Apache also is exploring various technologies to drive down costs in unconventional oil and natural gas plays, investors were told.

It plans a continuous drilling program in the Viking horizontal light oil

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Feature

The field is a Swan Hills carbonate waterflood that is a prime candidate for down-spacing.

(35 degrees API) play where it has significant acreage with an estimated 50–60 wells over the next five years.

Wall said he believes production could grow substantially and that the Viking could be one of Apache’s major oilproducing fields in Canada. Wells cost $3.9 million to drill and complete with a 30-day average initial production of 225 barrels per day and a 46 per cent rate of return.

the area,” he explained. “We drilled 25 test wells last year, and what we identified out there is a series of oil accumulations we want to now follow up on.”

Nunns said production from the initial wells is higher than in the Viking around Dodsland.

“We see it as something for the future,” he added.

Private explorer Cutpick Energy Inc. has around 333 net sections of land targeting the Viking near Halkirk in east-central Alberta. The company plans spending $150 million on drilling 70 net horizontal development Viking wells this year.

Since March 2010, the company has drilled 45 net Viking horizontal wells, 41 oil and four gas at a 100 per cent success rate. Its March estimated production was about 4,000 barrels per day, 58 per cent oil and liquids.

“We drilled 27 horizontal Viking wells there last year, and in 2011 we expect to drill 70 horizontal wells,” says Pep Lough, vice-president of finance and chief financial officer, adding that virtually all capital spending will be in the Halkirk area.

The company’s Viking oil fairway features high-quality, 35-degree-API sweet

oil. Cutpick has drilled 18 wells in the area and fracked 14 so far this year.

“It’s a little bit tighter than it is in Dodsland. In Dodsland, you’re looking at four to six metres of pay and about 18–20 per cent porosity. Where we are, we’re looking at 14–16 metres of pay and about 12–14 per cent porosity,” he adds.

“There is liquids-rich gas but we are focusing only on the oil.”

“We’re drilling 1,100-metre wells… but they’re coming on at 150 barrels of oil equivalent a day for the first month average,” says Bob Chaisson, president and chief executive officer. “Our one-yearout average rate is about 35–38 barrels of oil equivalent per day, so we’re about 30 per cent higher than, say, Dodsland.”

Chaisson said the company may drill a couple of gas wells this year to establish liquids rates and to test the general performance of the wells.

“In September of ’09 we did our first deal in here,” he says. “What we didn’t want to do was go in and drill a horizontal well here as soon as we had that first deal because as soon as you drill that first one, everyone is all over you.”

OIL & GAS INQUIRER • AUGUST 2011

19

Feature

Unique geology drives Deep Basin activity

By Darrell Stonehouse, Photo: Joey Podlubny

with notes from Daily Oil Bulletin staff

W

ith natural gas prices in a prolonged depression resulti ng f r om t he econom ic downturn and the explosion of shale gas drilling in the United States, drilling for natural gas in western Canada has almost come to a standstill.

T he Deep Basin in west- cent ral Alberta, however, remains a bright spot.

Driving exploration and development is the presence of high-value natural gas liquids (NGLs) such as condensate, propane and butane that are priced based on light oil rather than dry gas. Add to that as many as 17 vertically stacked productive zones in the Cretaceous rock in the play, along with opportunities for long horizontals and multistage fracture plays

in deeper horizons, and the Deep Basin is one of the few profitable gas opportunities in North America right now.

“It is one of the most productive sweet gas provinces on the planet,” Mike Rose, president and chief executive officer of Tourmaline Oil Corp., said of the Deep Basin at a recent FirstEnergy Capital Corp. investor conference in New York.

Rose ought to know. His previous company, Duvernay Oil Corp., was a pioneer in developing the modern techniques used to access Deep Basin gas before being sold to Shell Canada Limited for $6 billion.

Tourmaline controls around 1,650 gross sections of land in the Deep Basin, with around 4,600 potential drilling locations identified.

Rose said Tourmaline is pursuing two different play types in the Deep Basin. The first is the stacked Cretaceous sands where Tourmaline has around 3,100 drilling locations identified using 3-D seismic.

“The rationale for using 3-D is that about half of those 15 zones produce some kind of image,” he said.

The company aims to exploit the stacked resource using vertical wellbores. Its primary development plan for the Cretaceous sands calls for multiphase fracture treatments in vertical wellbores, with four to five fracs per well. It plans on drilling four wells per section.

Tourmaline has drilled about 110 vertical wells in the Deep Basin so far. Rose said the OIL & GAS INQUIRER • AUGUST 2011

21

Feature Photo: Aaron Parker

Deep Basin drillers have as many as 16 vertical horizons to target for gas.

company has identified around 1,500 targets for horizontal exploitation using multistage fracturing to open up the tight rock.

“In certain of the tight sands and the intervening shales, which are resource plays in their own right, it does make sense to go horizontally,” he said.

One horizontal opportunity is the Cardium. In the Deep Basin it is in the gas condensate window and produces 40–45 barrels of liquids per million cubic feet and perhaps more, he said. Tourmaline has more than 1,000 Cardium opportunities in its inventory but so far has drilled only five with plans for a total of up to 15 tests by the end of this year.

“We have had three or four really prolific Cardiums and the liquids have hung in,” he said.

Tourmaline is also targeting the Wilrich formation. While the Wilrich horizontal opportunities are more localized, the company has had some spectacular results from the zone at the north end of the basin, said Rose.

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AUGUST 2011 • OIL & GAS INQUIRER

“Having the 3-D data set is a huge advantage so we can see where we want to direct all those horizontals and some of the zones we can actually image directly,” he added.

Another emerging opportunity is in the Montney, where Tourmaline is partnered 50/50 with Perpetual Energy Inc. Perpetual Energy president and chief executive officer Susan Riddell Rose told shareholders at the company’s annual general meeting in May that although just beginning development, the Montney is showing great promise.

“Our work, combined with our partner and the work of many of the other area operators, has pretty much established that the lands we have captured just on the north end of the play have a tremendous amount of gas in place,” she said.

The company has exposure to 92 gross sections of Montney. During the first quarter, Tourmaline tied in one of three horizontal wells at Elmworth, which were drilled at no cost to Perpetual as a result of

a farm-in arrangement announced in 2009.

During the second quarter an extended inline test was conducted to evaluate the flow characteristics and liquids composition of the Montney formation.

“Our drilling has established a liquids ratio of about 20 barrels per million cubic feet of free condensate and then 25–40 barrels per million cubic feet per day of additional natural gas liquids,” Riddell Rose said. “So in total, 45–65 barrels per million cubic feet of liquids, so it’s very attractive economically once we get to a threshold to bring this on production.”

She added that the one month initial production of offset horizontal wells have ranged from three million cubic per day to six million cubic feet per day.

Riddell Rose noted that competitors in the area have been busy over the past 18 months. During that time, she said a total of nine horizontal and four vertical wells targeting the Elmworth Montney have been placed on production and eight additional horizontal wells have been rig

Feature

released. Four new horizontal wells have also been licensed.

“Area activity is significant. There are gas plants in the area. We can tap into them for early production but not for an extended production period as we see the area development plan working,” Riddell Rose said. “The goal here is to move to a larger area development plan over time and try to crystallize the value from the play within the next 12 months.”

In the Kaybob area of the Deep Basin, Paramount Resources Ltd. is also finding success applying horizontal drilling and multistage fracture treatments. Early in 2010, Paramount drilled two horizontal wells in the Dunvegan and one in the Falher. The Dunvegan well came on at eight million cubic feet per day to 10 million cubic feet per day and is still doing five million cubic feet per day a year later.

The Falher well came on at 12 million cubic per day and has flattened out at six million cubic per day after nine months.

Based on those results, Paramount accelerated its drilling program and planned to drill more than 30 wells. In the Musreau/Kakwa area it drilled two horizontal wells in the Falher that tested 10 million cubic feet per day to 12 million cubic feet per day that are now on stream.

It also tested another formation, the Cadotte, with the well coming on at nearly seven million cubic per day, opening up what Paramount believes is hundreds more locations within the same pool.

At Resthaven/Smoky, Paramount drilled a horizontal Dunvegan well that tested at 15 million cubic feet per day and has another eight wells to drill this year.

Paramount recently acquired about 100,000 net acres of deeper Montney rights below its shallower Deep Basin lands. The company estimates that the Montney has 70 billion cubic feet of gas per section. At Karr-Gold Creek, Paramount has drilled 15 wells into the Lower Montney turbidite play and the wells with 1,500-metre-plus horizontal segments and 20-stage hydrocarbon fracs all appear to be testing more than 10 million cubic feet per day, said Riddell Rose.

The wells cost $6 million to drill, and the three wells on stream are doing about nine million cubic feet per day plus 50 barrels per million cubic feet of liquids Fairborne Energ y Ltd. has been another early adapter of new technology in the Deep Basin. At Marlboro/Pine Creek, OIL & GAS INQUIRER • AUGUST 2011

23

Photo: Aaron Parker

Feature

Deep-cut gas plants add value to liquids-rich supply, raising the equivalent gas price as high as $8 per thousand cubic feet.

Fairborne Energy has been pursuing the liquids rich Wilrich play, and drilled the first horizontal Wilrich well in the basin.

“The results continue to get better and the frac technique is continuing to be modified and we are now doing about 12 fracs per well,” Steven VanSickle, company president and chief executive officer, told the FirstEnergy conference.

New wells in the play are delivering over five million cubic feet per day and 15 barrels per million cubic feet of liquids. The Wilrich reservoir is coursing upward marine sand with 10–15 per cent porosity and an estimated ultimate recovery of 700,000 barrels of oil equivalent per well.

Fairborne also has 222 net sections at Columbia/Harlech with 80 producing wells with most of its activity focused on the Viking shoreline trend.

The typical vertical wells drilled in the area are the stacked Viking, Notikewin and Gething formations.

“The anchor tenant is the Viking, but you can’t see the Viking on seismic,

so that’s what we target most on down­ spacing and drill through to the Gething, a two- to four-metre-thick condensate sand,” said VanSickle.

“The nice thing about Harlech is the free condensate and NGL,” he said. With more than half of the revenue from NGL and condensate, the effective gas price is about $8 per thousand cubic feet. In the last well Fairborne drilled there, it completed a Viking, Middle Mannville and Gething sand that is flowing at two million cubic feet per day and 300 barrels a day of condensate.

Daylight Energy Ltd. is also chasing liquids-rich gas in its Elmworth resource play, where it has a total land base of more than 400 gross (265 net) sections of land, The company’s first Wapiti Montney horizontal well was a 1,000-metre lateral completed with 11 fracs. Initial production was seven million cubic feet per day and the well is still producing five million cubic per day with 50–60 barrels per million cubic feet of high-quality liquids of which half is C5 (condensate) with attracts a

price $2 off West Texas Intermediate. The balance is C3 (propane) and C4 (butane).

“These are very prolific wells,” Brian Prokop, vice-president of capital markets, told the FirstEnergy conference. “You could actually flare off the gas and make a lot of money—not that you could do that.”

Another major target in the Deep Basin is the Nikanassin. A Canadian Forest Oil Ltd. well in the play tested at 32 million cubic feet per day with initial production (one month) of 20 million cubic feet per day and cumulative production of 7.3 billion cubic feet after 16 months, the conference heard. However, the well is not a typical or a tight well in that it had “a little bit of structure and a little bit of fracturing,” he said.

A typical tight Nikanassin well costs $7.5 million to drill and has initial production of 10 million to 15 million cubic feet per day with reserves of 10 billion cubic feet.

Because of the Alberta government’s deep gas royalty holiday, there is effectively five years of royalty-free production, according to Prokop. With operating costs of 40 cents per thousand cubic feet, including processing, the Nikanassin can be profitable with a gas price as low as $2.20 per thousand cubic feet.

While the play can be developed vertically, operators are attempting horizontal wells with the use of new technology, he said. So far, only 15–20 horizontal wells have been drilled into the formation. Daylight is in good company with larger operators such as Apache Canada Ltd., Canadian Forest Oil, Devon Canada Corporation, Royal Dutch Shell plc and ConocoPhillips also active in the area.

“The benefit of the big players is that it will validate this play much more quickly,” Prokop suggested. “The highest risk will not be getting the gas out but how profitable it will be.”

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Steady progress Lloydminster producers finding new ways to wring incremental value out of heavy oil resource

By Darrell Stonehouse

Photo: Joey Podlubny

T

he heavy oil fields surrounding Lloydminster on the AlbertaSaskatchewan border have been the launching pad for many of Canada’s biggest petroleum company success stories, the most famous being Husky Energy Inc. A number of smaller, emerging companies are now trying to follow in the footsteps of past giants, building a base in Lloydminster to provide the cash flow to branch out in western Canada.

Husky was launched in 1938 as a refinery outfit in Wyoming. It moved that refin-

ery to Lloydminster in 1946 to process heavy oil into asphalt and bunker oil. Starting with production of around 600 barrels a day, it has grown from its Lloydminster roots to become a global giant, producing over 300,000 barrels of oil equivalent a day.

But Lloydminster remains the com­ pany’s bread and butter, Husky president and chief executive officer Asim Ghosh told investors at its annual general meeting.

“We consider the base foundation of this company to be western Canada and heavy oil,” he said. “And that base foundation we are regenerating using new technologies.”

Lloydminster producers are testing a variety of technologies including thermal production, biological agents and chemical injections to produce more heavy oil.

Husky has around 2.1 million net acres surrounding Lloydminster, with annual production of around 90,000 barrels per day of heavy and medium-grade oil.

“In many ways you can think of heavy oil as the original resource play— well before the term ‘resource play’ was invented,” said Ghosh with respect to the

OIL & GAS INQUIRER • AUGUST 2011

27

Feature

Steady progress >Steady progress >Steady progress > Steady progress large land base needed for success. “And we’ve been doing the heavy oil resource play at Lloydminster for 70 years.”

There are 10 billion barrels of oil in place on Husky’s Lloydminster lands. The company has produced 800 million barrels. Ghosh said known technologies are expected to access another seven per cent of that oil in place. The company is targeting another eight per cent from emerging technologies. The goal is to maintain production from the area for the long term. And right now that means continuing drilling horizontal wells and building thermal projects to keep the oil flowing.

Husky is currently advancing three thermal projects in the Lloydminster area.

Construction of the 8,000-barrel-per-day South Pikes Peak commercial project was approximately 58 per cent complete at the end of the first quarter of 2011. Production is expected to commence in mid-2012.

Husky commenced its 3,000-barrel-perday Paradise Hill development in the first quarter of 2011, which will utilize existing

28

AUGUST 2011 • OIL & GAS INQUIRER

Bolney infrastructure and is planned to become operational by the third quarter of 2012. Construction of a single thermal pilot well pair at Rush Lake continued during the first quarter of 2011 with anticipated first production in the fourth quarter of 2011. Four additional commercial thermal projects are in the early delineation and concept selection phase.

Horizontal well development also progressed through the first quarter of 2011, targeting new geological horizons in existing regions. Thirty-one of the planned 104 wells for 2011 were drilled in the first quarter in Alberta and Saskatchewan.

Husky is also well underway in piloting novel recovery technologies for the future The company continues operating two solvent-enhanced oil recovery pilots at Edam and Mervin in Saskatchewan. A CO 2 capture and liquefaction plant at its Lloydminster ethanol plant is under construction, with expected completion in the latter half of 2011. This liquefied CO2 is to be used in the ongoing piloting program.

A microbial enhanced recovery pilot in Wainwright continued in the first quarter of 2011 with nine wells continuing to show a substantial response eight months after initial treatments. A second pilot in Devonia Lake has commenced with three cycles of treatments completed with preliminary results showing a 20 per cent increase in oil production.

Junior producer Rock Energy Inc. is trying to follow in Husky’s footprints.

It has been building a base in the heavy oil fields of Lloydminster for the last few years. It is now expanding from that base with a major natural gas play at Elmworth in the Deep Basin.

“The heavy oil play is providing the financial base for our gas play at Elmorth,” chief executive office Allen Bey told the audience at the Canadian Association of Petroleum Producers investment symposium in mid-June.

Rock currently operates 120 heavy oil wells surrounding Lloydminster and has another 190 drilling locations identified. It has

Feature

Photo: Joey Podlubny

Service companies are busy as Lloydminster heavy oil is highly profitable at current prices.

2,200 barrels per day of production on its 60 net sections in the area. Bey said the company is focused on a number of things to ensure its heavy oil play meets expectations. It is zeroed in on maintaining a strong drilling inventory, keeping finding costs low, maintaining low operating costs, using new technologies to

improve recovery rates and finding the best markets possible for production.

“Heavy oil is about looking at the details and making sure you don’t get too far off track,” Bey said about the success of the company in building its base at Lloydminster.

To keep finding costs down, Rock stacks the different productive zones in wells. To keep operating costs down, the company has a number of efforts underway, including operating central production facilities, using casing head gas as fuel for operations and using supervisory

OIL & GAS INQUIRER • AUGUST 2011

29

Feature

Steady progress >Steady progress >Steady progress > Steady progress control and data acquisition (SCADA) to improve well management.

“Another thing heavy oil operators want to do is improve our recovery factor,” said Bey. “We do that with different completion

Radial drilling technology hydraulically jets a one-inch horizontal leg up to 100 metres from the wellbore in four or more directions, acting like a controlled wormhole. This compares with conventional

“ We are selling over 500 barrel per day into the Gulf Coast market, we’re getting over a $6–$7 per barrel premium on our netback over selling it locally.”

— Allen Bey, Chief Executive Officer, Rock Energy Inc.

technologies, things like radial drilling projects, foam stimulation and making sure the wells are cemented properly so we don’t have natural breakdown. We’re also down spacing at appropriate times to improve our recovery factors on a pool basis.”

perforations that only go around one metre into the formation. Preliminary results using the technology show an average increase of 15–20 barrels per day of production, and may add as much as 15,000–20,000 barrels of reserves. The cost is between $100,000 and $130,000 per well.

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Foam stimulation is used to restore or improve production levels in wells.

A surfactant foam is injected through wormholes into the reservoir, and the surfactant reduces the viscosity of the heavy oil near the wellbore and helps in recovering and lifting sand and other debris from the wellbore.

“The key point of all of this is that Rock has 200 million barrels of oil in our heavy oil region and we are only looking at recovering about six per cent of it,” said Bey. “If we can increase our recovery factor by even one per cent, you can see where that kind of leverage would be quite significant for a company like Rock.”

Also significant is the price received for heavy production. Rock has taken the innovative step of leasing 300 railcars to export its production to higher value markets on the Gulf Coast.

“We are selling over 500 barrel per day into the Gulf Coast market,” said Bey. “We’re getting over a $6–$7 per barrel premium on our netback over selling it locally.”

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2011 PRODUCTS

British Columbia

Progress Energy expanding Montney northward

By Richard Macedo

JUN/10

JUN/11

JUN/10

JUN/11

WELLS SPUDDED

58

48

WELLS DRILLED

37

37

Photo: Joey Podlubny

Progress now stands as the largest holder of Montney rights with nearly 900,000 net acres of land focused in northeastern British Columbia. It was an early mover into the region, originally drilling for the Halfway and Debolt gas formations.

“We have, over the course of the last, frankly, 10 years continued to build a position up in this neck of the woods,” Kist said. “The way we primarily play the game is we want to hold all the rights in the stratigraphic column.

That’s the way you can be successful because as time and technology works, it opens up those additional layers. That’s what we do and how we play the game in this whole area.”

Jim Stannard, the company’s vice-president of engineering, noted that previously industry activity essentially stopped at Peace River and didn’t move much further.

“What’s really evolved over the past 18 months has been a rapid ramp up of activity north of the Peace River and really extended

the commercial fairway, if you will, more than doubled the size of it,” he said. “That’s a big part of the story.”

A major advantage of the North Montney is the fact it’s sweet gas and is liquids-rich, which aids economics at today’s low natural gas prices, says Doug Ashton, vice-president of engineering with AJM Petroleum Consultants, which was recently acquired by Deloitte and is now known as AJM Deloitte.

“The data is pretty sparse right now on gas analysis information, so it’s a little bit difficult for us to tell, but it looks like it’s 1.5 to two times the liquids yields that they’re seeing in the Pouce Coupe area. In there, they’re seeing five to 10 barrels per million cubic feet, so in the north area there’s probably more like 15–20 barrels per million,” explained Ashton.

To develop the northern end of the play, Progress will use a pod model. The company will drill a total of 35 horizontal wells this year and is ramping up five pods into various stages.

“Instead of very concentrated development like Talisman Energy’s doing at Farrell, we’re taking a bit more of a small production pod approach,” Stannard noted. “The idea for a pod is to take an area we think is prospective and develop that up to 50 million a day. Our idea is to get multiple of these 50-million-a-day pods on.”

The reason is it allows the company to achieve economies of scale in a concentrated area and development in a number of areas on its land base.

“We want to be showing commercial productivity in a variety of areas,” Stannard said.

Progress has grown proved-plus-probable Montney reserves 386 per cent to roughly 600 billion cubic feet equivalent on 156 net booked wells, which is 4.4 billion cubic feet per well on average. With more than 7,500 potential Montney locations, less than two per cent of the company’s Montney inventory has been booked to date. Given the massive land position and drilling inventory, the report said that the company is seeking farmout partners.

Early drilling by Progress Energy shows the Montney play may be twice as big as first thought.

Since ARC Resources Ltd.’s first horizontal well at Dawson in northeastern British Columbia in 2005, development of the Montney formation has continued to evolve with producers now pushing drilling activity northward, led by Progress Energy Resources Corp., which has a big land base in the area.

Development of the Montney resource play has traditionally occurred closer to the B.C./ Alberta boundary, where producers have been busy drilling in the areas around Dawson, Swan and Groundbirch. But over the past few years, Progress has been amassing a significant land position north around Town-Kobes-Altares-Caribou.

“We really think about this as a fairway,” said Greg Kist, Progress Energy’s vice-president of investor relations and marketing. “There’s a real, distinct fairway here where the productivity, the over-pressure regime, the rock properties and all that are practically identical through this whole fairway.”

BRITISH COLUMBIA WELL ACTIVITY

JUN/10

JUN/11

WELL LICENCES

48

86

▲

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • AUGUST 2011

33

British Columbia

Dawson economic at current prices, say ARC Even at natural gas prices that have hamstrung many gas plays, ARC Resources Ltd.’s Dawson Montney play in northeastern British Columbia remains a moneymaker as well as the company’s growth engine.

“We get asked all the time when we’re in New York, Boston, Geneva, wherever we are: does it make sense for us to be drilling, doing what we’re doing in the Montney, when the price of gas is only $4–$4.50?” said John Dielwart, ARC’s chief executive officer.

“In the case of Dawson, absolutely,” Dielwart told the company’s annual general meeting in May. “At today’s prices—if they stayed flat at this level forever—we’d still get a 40 per cent rate of return on every dollar we spend. And that’s a full-cycle rate of return,” Dielwart told shareholders.

Analysts rank the economics of the liquids-rich gas play in the Montney formation of northeastern British Columbia among

the best in North America. ARC boasts that it unlocked the play, drilling the first horizontal well into the tight formation at Dawson in 2005.

Dielwart described the Dawson field as “the best of the best,” the company’s “meat and potatoes” and the company’s growth engine.

Dawson has an estimated 3.8 trillion cubic feet of discovered gas initially in place and is currently producing about 150 million to 160 million cubic feet a day.

The ARC chief executive displayed a chart of Montney-type curves showing that production rates of wells at Dawson are superior to those at Sunrise/Groundbirch, Swan/Tupper, Parkland and Septimus, as well as those across the border in Alberta.

“There was a notion put forth by companies large and small that it didn’t matter where you were—as long as you had land in that Montney fairway, life would be grand. The reality is that’s not how it works,” Dielwart said.

Encana, PetroChina deal scrapped Encana Corporation and PetroChina International Investment Company, a unit of PetroChina Company Limited, have abandoned plans for a proposed joint venture that would have sped up development of Encana’s Cutbank Ridge natural gas assets.

Earlier this year, Encana said PetroChina would pay $5.4 billion to acquire a 50 per cent stake in Cutbank Ridge. Encana’s Cutbank Ridge property spans northeastern British Columbia and northwestern Alberta, and consists of gas from the Montney, Cadomin and Doig formations.

“After close to a year of exclusive negotiations with PetroChina, we were unable to reach alignment on the planned

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AUGUST 2011 • OIL & GAS INQUIRER

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t ra nsac t ion,” said R a ndy Eresma n, Encana’s president.

Encana said the parties were “unable to achieve substantial alignment with respect to key elements of the proposed transaction, including the joint operating agreement.”

The company said it has retained RBC Capital Markets and Jefferies & Company, Inc. to help find “premium joint venture partners.”

Eresman said: “We have determined that the best way for us to advance our plans to unlock value from our Cutbank Ridge business assets is to offer up a variety of joint venture opportunities for portions of the undeveloped resources, and, separately, to examine a transaction with respect to our midstream pipeline and processing assets in the area.”

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And it isn’t just competitors’ lands that fail to stack up against the Dawson Montney.

“As we move further to the west...we would expect to revert to the mean and become more average,” he said of other Montney lands ARC holds outside the Dawson field.

In all, ARC has an estimated 10.1 trillion cubic feet of discovered gas initially in place on its northeastern B.C. Montney lands— excluding its Attachie and Tower properties where the resource potential hasn’t been assessed. Only 1.38 trillion cubic has been booked as proved-plus-probable reserves.

“So about a 14 per cent recovery factor.

We certainly expect to get much beyond that,” Dielwart said.

Not surprisingly, the area is getting the biggest chunk of the company’s capital budget. Out of a total 2011 program of $625 million, ARC plans to spend $228 million in northeastern B.C. this year.

Meanwhile, Encana said joint venture discussions regarding its Horn River and Greater Sierra gas properties in northeastern British Columbia are well underway.

Encana expects that these trans­ actions, plus other divestitures and joint venture pursuits it began, will generate 2011 proceeds and joint venture investments of bet ween US$1 billion and US$2 billion—more than Encana’s net divestiture target for 2011 of $500 million to $1 billion. Apart from updating its 2011 guidance for net divestitures to between $1 billion and $2 billion, Encana said all other components of its guidance remain unchanged.

— DAILY OIL BULLETIN

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British Columbia

Canadian Natural eyes Septimus expansion

By Elsie Ross With stronger-than-anticipated well performance at its Montney unconventional gas play at Septimus, Canadian Natural Resources Limited plans to drill another eight wells in the area this year, a company official said in late May. The company has been producing 60 million cubic feet per day of gas and 1,800 barrels per day of natural gas liquids at Septimus, well above the 50-million­cubic-feet-per-day design capacity of its plant, company president Steve Laut said in a conference call to discuss first-quarter 2011 results.

With the excellent results and strong cost control, the project now competes with its oil projects with an AECO gas price of $3.50 per gigajoule, Laut said.

Production performance has been strong, and towards the end of this year the company will decide whether to expand the plant to 100 million cubic feet per day of gas and 10,000 barrels a day of liquids, he said.

Initial expectations were for reserves of about four billion cubic feet per well that would result in production of about 200 million cubic feet per day of gas and 10,000 barrels per day of liquids. However, it is now clear based on production performance that reserves will be more than six billion cubic feet per well and close to 300,000 barrels per day of liquids per day, said Laut.

With the excellent results and strong cost control, the project now competes with its oil projects with an AECO gas price of $3.50 per gigajoule, Laut said.

The additional eight wells at Septimus would be drilled in the second half of this year with production coming on stream in 2012.

The company also plans to drill 14 liquidsrich Cardium gas wells at Edson and Wild Hay in northwestern Alberta.

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— DAILY OIL BULLETIN OIL & GAS INQUIRER • AUGUST 2011

35

British Columbia

Cordova exploration challenged by Dene Tha’ The Dene Tha’ First Nation is taking its concerns about shale gas development in northeastern British Columbia to the B.C. Supreme Court.

D e ne T h a’ h a s f i le d a p e t it ion w it h t he cour t challenging t he B.C. Ministr y of Energ y and Mines’ decision to sell oil and gas tenures in the

development, i nc ludi ng negat ive impacts to water quality and quantity, threatened species such as caribou, and the exercise of their Treaty 8 rights.

“We are deeply concerned about the lack of adequate information necessary to understand the impacts of shale gas development to the environment

In the lawsuit, Dene Tha’ asserts that the Ministry of Energy and Mines did not address these concerns and did not engage in a meaningful consultation process with the aboriginal group prior to the government’s decision to sell the tenures. Dene Tha’ said it repeatedly asked British Columbia to undertake the necessary studies prior to the sale, but the

“We are deeply concerned about the lack of adequate information necessary to understand the impacts of shale gas development to the environment and our rights, given that shale gas technologies are new to northeastern B.C.” — James Ahnassay, Dene Tha' Chief

Cordova Embayment in June 2010 for the purpose of shale gas development.

The Cordova Basin is within Dene Tha’s traditional territory where members exercise t hei r const it ut iona l ly protected Treaty 8 rights to hunt, fish, trap and gather. Prior to the sale of the tenures, Dene Tha’ expressed a number of concerns to the ministry about the sa le of t hese tenu res for sha le ga s

and our rights, given t hat shale gas technologies are new to northeastern B.C.,” said James Ahnassay, Dene Tha’ c hief. Ot her concer ns a re t he enormous volumes of water for frack ing, cont a m i n at ion pr oble m s t h at h ave arisen with shale gas development in t he United States, and t he need for studies to identify and address impacts from shale gas technologies, he said.

province ignored the requests even though there was no legal impediment to doing the work.

Nexen Inc. and Penn West Petroleum Ltd. h ave ac r e a ge i n t he C or dov a E mbay me nt . L a s t yea r, M it s ubi sh i Corporation of Japan partnered with Penn West in a joint venture to develop shale gas in the area.

— DAILY OIL BULLETIN

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AUGUST 2011 • OIL & GAS INQUIRER

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Northwestern Alberta/Foothills

First Baytex Seal Project on production by year-end

Photo: Joey Podlubny

By Elsie Ross

Baytex is drilling eight laterals off of one vertical well at Seal.

Heavy oil producer Baytex Energy Corp. plans to have the first permanent 10-well module of thermal enhanced oil recovery development at Seal on production by year-end.

Based on the results of the Cliffdale pi lot, t he compa ny bel ieves it ca n achieve recovery rates of 30 per cent or better in the cyclic steam stimulation project, Anthony Marino, president and chief executive officer, told the com­ pany’s first annual general meeting after Baytex converted to a corporation from a trust. In comparison, recovery rates for primary (cold) development are five to seven per cent.

“The development costs are not as high as you might normally think of for an oilsands lease,” he said.

The modular development with 10 wells at a time makes the project much

easier to execute and should enable Baytex to do it on schedule with less risk of cost overruns, said Marino. Each module will cost about $31 million.

Projected finding and development costs are $7 per barrel, and when peak

steam oil ratio of 2.9 to one. Assuming a natural gas cost of $4 per thousand cubic feet, operating expenses are $14 per barrel.

Baytex has approximately 260 sections of land in the Seal area including 158 sections of 100 per cent oilsands leases acquired earlier this year to the southeast that are yet to be fully delineated. At year-end 2010, reserves had been booked on only 23 sections (21.5 for cold primary and 1.5 for thermal).

Baytex also is continuing to grow its horizontal cold heavy oil development prior to thermal development on its origin­a l oilsands leases to the northeast, the meeting heard.

“The cost metrics are very strong on this project; I think among the best you would find on any upstream pro­ject in the world,” said Marino. Finding and development costs are about $4 per barrel, and last year operating costs were $3.28 per barrel.

The project is usually based on eight laterals from one vertical well. Initial production is 400–500 barrels per day from the multilateral wells for a cost of about $2.1 million per well. The estimated ultimate recovery is 490,000 barrels per well with a recovery factor of five to seven per cent of original oil in place.

“ The cost metrics are very strong on this project; I think among the best you would find on any upstream project in the world.”

— Anthony Marino, President and Chief Executive Officer, Baytex Energy Corp.

rates of 1,900 barrels per day are achieved in the third year there will be a production efficiency “quite competitive with projects in the industry today,” he said.

The estimated ultimate recovery is 4.7 million barrels of oil with a cumulative

This year, Baytex plans to drill about 20 cold wells on its existing lands.

With netbacks for oil about five times those for natural gas on a barrel of oil equivalent basis, Baytex will continue to increase its focus on oil, said Marino.

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

JUN/10

JUN/11

WELL LICENCES

214

297

▲

JUN/10

JUN/11

WELLS SPUDDED

129

121

▼

JUN/10

JUN/11

WELLS DRILLED

80

80

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • AUGUST 2011

39

Northwestern Alberta/Foothills

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AUGUST 2011 • OIL & GAS INQUIRER

Pace proving up Pekisko resource at Haro Pace Oil & Gas Ltd. is reviewing its completion techniques after drilling five horizontal wells at Haro in northern Alberta, which confirmed the Pekisko potential across a large portion of its lands.

An independent evaluation of the company’s Haro Pekisko oil resource was recently completed by McDaniel & Associates Consultants Ltd. The Haro area is an area of seasonal access generally restricted to the winter months from January 1 until spring breakup around the end of March. During this limited season, all drilling, completions, pipelining and operations must be completed.

As a result of this remoteness, a very large oil resource opportunity in the Pekisko formation was underexploited, creating both a challenge and an opportunity for Pace.

With its existing oil and gas operations in the Rainbow area as a foundation and operating base combined with strong operational experience with similar remote programs, Pace established a large land base of over 137 gross (118 net) sections to pursue this opportunity. This past winter, Pace successfully completed its planned Haro program during this limited window of opportunity.

The results confirmed the presence of Pekisko oil across a large portion of company lands and established a year round infrastructure footprint along the 35-kilometre Pekisko oil trend. The primary focus of Pace’s activities was the drilling of five 100 per cent horizontal wells to confirm the continuous nature of the oil bearing Pekisko formation along the trend, construction of over 25 kilometres of oil and gas–gathering pipelines and the installation of field water-handling facilities.

Pace said its activities to date in the Haro area are the early stages of an oil resource development with different techniques and procedures being tested.

“We are encouraged by the continuous nature and extent of the Pekisko oil in the wells we have drilled along the trend, however, we have also encountered higher-thananticipated water cuts in certain wells,” the company said.

Based on these results, Pace is reviewing the information it has compiled and

Northwestern Alberta/Foothills evaluating the various completion techniques to optimize oil production rates. “We remain confident that our continued efforts will identify key processes to develop this large-scale oil resource opportunity economically,” Pace said.

McDaniel has estimated that effective June 15, 2011, Pace’s net working interest discovered petroleum initially in place for the Pekisko formation at Haro is 1.16 billion barrels.

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Bellamont reports Grimshaw drilling success Bellamont Exploration Ltd. has announced further drilling success on its Grimshaw Montney oil pool and a new oil property acquisition.

In the first quarter of 2011, Bellamont successfully drilled and completed two (1.75 net) additional horizontal wells at its Grimshaw Triassic C Montney oil pool at 13-28-83-23W5 well and 16-29-83-23W5 well. Both wells were placed on production on April 7.

To date, the 16-29 well (Bellamont 100 per cent working interest) has produced an average daily rate of approximately 125 barrels per day of oil. The 13-28 well (Bellamont 75 per cent working interest) was facility restricted until May 2, but is now also producing approximately 125 barrels a day.

The economics of Grimshaw are excellent, Bellamont said. The relatively shallow vertical depth (around 900 metres) results in all-in cost per horizontal well of approximately $2 million.

The average initial production rate (first 30 days) for the eight horizontal wells in the pool has been in excess of 110 barrels a day, resulting in on-stream costs of less than $20,000 per barrels per day.

Bellamont has a total of 38 (around 34 net) additional horizontal locations identified in this pool. Only three of these locations were booked in the corporation’s reserve report at the end of 2010.

Bellamont will be drilling three 100 per cent working interest infill wells in the pool immediately following spring breakup, which should add in excess of 300 barrels a day of oil to Bellamont by August.

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Northeastern Alberta

Imperial Cold Lake recovery rates continue to climb

By Elsie Ross

JUN/10

JUN/11

JUN/10

JUN/11

WELLS SPUDDED

44

93

WELLS DRILLED

59

97

Photo: Joey Podlubny

selective technologies that really work with cost scales that are market competitive,” he said. “Our company will continue to have Cold Lake to be really the benchmark of our whole company.”

There are still an estimated 700 million to 800 million barrels of unde­veloped resources at Cold Lake, said T. Glenn Scott, senior vice-president, resources.

To improve in situ recovery from existing wells it is evaluating new steam flooding techniques for late life wells in which it will drill new steam-only injector wells and continue to produce from existing wells. In older development areas, this will encourage the flow of steam from the new injector well toward producing wells, accessing bitumen that cannot be reached with the single injector and producing well, contributing significantly to the higher recoveries.

Imperial has commercialized LASER (liquid addition to steam to enhance recovery) technology in which solvent is added along with steam in mid-life wells, improv ing both recover y and greenhouse gas intensity levels with no additional steam input. Over about two cycles, recovery is up about 35 per cent compa red to a t y pica l c yc lic stea m stimulation well and greenhouse gas emissions are down about 25 per cent.

Scott said the company is also piloting technologies that will allow it to develop in situ resources that don’t readily lend t hemselves to ex ist ing technologies. At Cold Lake, it is piloting solvent-assisted steam assisted gravity drainage where solvent is added to lower pressure steam and the mix is injected into the formation.

It is also preparing to pilot a solvent process targeting more challenging reservoirs where heat can easily be lost out of the formation, making thermal recovery technologies ineffective. This technology could potentially eliminate the use of steam altogether, reducing water use and significantly reducing greenhouse gas intensity.

Imperial has been able to steadily grow production at Cold Lake since s t a r t- up u s i n g a s t a g e d d e v e l o p ment model, said Scott. This phased approach allows it to take advantage of efficient, template facility construction using the company’s “design one, build many” strategy.

This same strategy will be used for Nabiye, the next 30,000-barrel-per-day phase of Cold Lake, which is expected to be on production by 2015.

“This staging allows us to not only realize efficiencies in execution, but also provides the opportunity to apply advances in tec h nolog y to en hance recovery,” he said.

Imperial expects recovery rates to climb to 60 per cent at its Cold Lake operations.

While Imperial Oil Limited’s Cold Lake thermal in situ project has already produced more than one billion barrels of bitumen, it has decades of production yet to come as the company works on new ways to enhance recovery, the company’s top official said late this spring.

“When we started at Cold Lake 30 years ago, we expected recoveries of between 10 and 15 per cent and through the use of technologies and our operating experience and expertise, we’ve got that up to 50 per cent now,” Bruce March, chairman, president and chief executive officer, told an investor day in Toronto.

With some of its new technologies, Imperial is headed to 60 per cent in the next decade, analysts heard.

“The interesting thing about the oilsands is that we have been able to find ways to get more of this resource up using NORTHEASTERN ALBERTA WELL ACTIVITY

JUN/10

JUN/11

WELL LICENCES

36

69

▲

▲

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • AUGUST 2011

45

Northeastern Alberta

Laricina reports first production at Saleski Production began in t he f irst quarter at Lar icina Energ y Ltd.’s stea m assisted gravity drainage (SAGD) pilot in the Grosmont carbonate formation at Saleski as the project progressed from the heating phase to the production ramp-up phase.

Steaming of the first well pair began Dec. 23, 2010 with steaming of the second pair commencing Jan. 30, 2011. The length of the heating phase is within the benchmark of 90–120 days seen in typical McMurray formation SAGD projects, said the company.

The ability to inject steam directly into the reservoir during the heating period has allowed start-up to progress with less steam than in most McMurray SAGD projects, it said.

As production in the first two of the three wells pairs ramps up over the upcoming quarters, Laricina said it will be monitoring the development of each zone’s SAGD production performance curve under sustained operations. Once this ramp-up to the targeted 600 barrels

46

AUGUST 2011 • OIL & GAS INQUIRER

per day per producing well is achieved, the second stage solvent-cyclic (SC)-SAGD, consisting of the injection of solvents, will commence.

Also in the first quarter, the company advanced site preparation, development drilling and detailed engineering for Phase 1 of its Germain SC-SAGD commercial demonstration project and completed an active winter drilling and

In releasing first-quarter results, Laricina said that overall it is encouraged about the knowledge it has gained about the Grosmont C and D reservoirs at Saleski. The results to date have met or exceeded its expectations for the application of SAGD in the Grosmont with the early results consistent and comparing favourably to the t y pical McMurray project benchmarks, it said.

In late 2010, the company contracted to construct a super-single drilling rig that will be dedicated to horizontal drilling at Germain, and it remains on schedule for delivery in June. geophysical program at Saleski, Germain and Burnt Lakes on time and on budget.

In addition, Laricina said it completed initial testing on its electromagnetic heating process and received its first patent approval.

T he Salesk i facilit y has operated at nearly 99 per cent operational uptime and the operational crews are doing an exceptional job at working through the minor challenges in operating a new plant, said Laricina.

Northeastern Alberta

Photo: Joey Podlubny

Capital expenditures for the first qua r ter were $68 m i l lion w it h t he majority used to complete the winter delineation drilling and geophys­i cal prog ra m s; development dr i l l i ng of water source; water disposal and observation wells for the Saleski and Germain projects; site clearing and construction preparation at the Germain commercial demonstration project and equipment procurement for Germain. Full-year capital and operating expenditures are expected to be $340 million.

Late in 2010, Laricina filed the regulatory application for the first commercial phase expansion of the Saleski project by 10,700 barrels per day for a total approved gross capacity of 12,500 barrels per day when combined with the pilot. Front-end engineering and design is under way with detailed engineering and initial procurement expected to commence later this year.

At Germain, site construction for the well pad and central processing site for the 5,000-barrel-per-day commercial demonstration project was completed in the first quarter. The well pad preparation provides

access for drilling operations this summer when Laricina plans to drill the first six of 10 horizontal well pairs.

In late 2010, the company contracted to construct a super-single drilling rig that will be dedicated to horizontal drilling at Germain, and it remains on schedule for delivery in June. The rig will also be suitable for drilling future horizontal wells at Saleski.

Detailed engineering is underway while procurement of facility equipment is approximately 45 per cent complete.

Laricina has contracted multiple fabricators to insure its schedule for module construction remains on track.

Construction camp expansion to its new capacity of 300 personnel was also completed in the first quarter, as were installation of the gas supply line and drilling of water source, disposal and observation wells. These key infrastructure requirements are well in hand for the anticipated late 2012 project start-up.

Laricina exited the quarter with working capital of $294 million, sufficient to fund the balance of the 201 capital and operating spending programs. — DAILY OIL BULLETIN

Development drilling is underway at Germain.

OIL & GAS INQUIRER • AUGUST 2011

47

Northeastern Alberta

Rapid in situ growth expected Average in situ oilsands production in Alberta is expected to rise about five per cent this year but capacity being added will be much larger, setting the stage for more robust production growth next year.

In situ production is expected to reach 793,000 barrels per day of oil this year continuing steady growth from last year’s 756,000 barrels per day thanks to several project expansions as well as existing pro­ jects ramping up, according to a Canadian Association of Petroleum Producers (CAPP) forecast issued last year. In the first two months of 2011, in situ production averaged nearly 832,000 barrels per day so that forecast might be a bit low.

In situ bitumen reserves booked by companies continued to rise in 2010 with 11 companies showing a 761-millionba r rel ju mp i n proved reser ves to 5.13 billion barrels and 12 companies reporting a further 1.06-billion-barrel increase in probable reserves to 7.26 billion barrels, according to Daily Oil Bulletin records.

The larger in situ projects scheduled to start up this year include: Suncor

Energy Inc.’s Firebag Phase 3 (cap­a city of 68,000 barrels per day), Cenov us Energy Ltd.’s Christina Lake Phase C (capacity of 40,000 barrels per day) and Devon Canada Corporation’s Jackfish 2 (capacity 35,000 barrels per day).

According to Oilsands Review magazine records, over 140,000 barrels a day of new

growth rate of 9.7 per cent until 2019, while synthetic crude oil production is projected to increase at an average annual growth rate of 5.9 per cent, with virtually all of this production increase exported from Canada.

In situ growth to date has been fairly steady and is expected to continue this year, said Bob Dunbar, president of Strategy

According to Oilsands Review magazine records, over 140,000 barrels a day of new in situ production capacity will be launched this year. That will decline to 23,000 barrels a day of capacity next year before a series of new projects adds 223,200 barrels per day of capacity in 2013. in situ production capacity will be launched this year. That will decline to 23,000 barrels a day of capacity next year before a series of new projects adds 223,200 barrels per day of capacity in 2013.

The Energy Resources Conservation Board (ERCB) estimates in situ bitumen production will increase at an average annual

West Inc., a Calgary oil sands consulting firm. He does not, however, feel in situ production will continue at the same aggressive rate for the remainder of this decade “just because of the limitations as to what we can bring on stream at any one time.”

Engineering capacity and skilled labour availability are constraints to growth.

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helped by higher-quality reservoirs and having sufficient steam injection cap­ acity while others are being constrained by steaming abilities or have met with other reservoir or facility issues.

Not all projects are full steam ahead.

So far this year Nexen Inc.’s Long Lake project is down by 2,600 barrels per day in the first quarter compared to a year ago due to maintenance, but the company is expecting output to improve and the company has not changed its overall production outlook for 2011.

E T E nerg y L i m ited wa s to have started up its 10,000 barrels per day commercial project this year but its dates have shif ted and the company now ex pects its Phase 1 to star t up 2 013 -14 w it h Ph a s e 2 at a n add itional 40,000 barrels per day to start in 2015-16. The project is in the late stages of the approval process for its Phase 1 application.

BP plc ’s Ter re de Grace pilot of 10,000 barrels per day was timed to start up this year, but a spokesperson said the schedule has changed and did not provide further details.

Photo: Joey Podlubny

Industry is facing some issues that will have to be resolved, such as pipeline capacit y and uncer taint y over TransCanada Corporation’s proposed Keystone pipeline expansion to the U.S. Gulf Coast, he said.

In a recent research note, Peters & Co. L imited noted t hat Cenov us’ C h r i s t i n a L a ke a nd Fo s te r C r e e k , ConocoPhillips Canada’s Surmont, and Royal Dutch Shell plc’s Orion steam assisted gravity drainage (SAGD) pro­ jects (all of them in situ) each posted r e c or d m ont h s f or p r o duc t ion i n February with utilization rates averaging 97 per cent, 98 per cent, 80 per cent and 42 per cent, respectively.

Peters & Co. noted MEG Energ y Cor p.’s Christina Lake project averaged 27,000 barrels per day in February (108 per cent of capacity), while Nexen Inc./OPTI Canada Inc.’s Long Lake project averaged 23,000 barrels per day, the lowest level since May 2010.

T he med ia n-i mpl ied ut i l i zat ion rate for SAGD projects remains below 80 per cent of design capacity, Peters & Co. noted. The better projects have been

In situ bitumen production is expected to increase 9.7 per cent annually for the next eight years.

CAPP forecasts crude oil from in situ oilsands operations will reach 888,000 barrels per day in 2012 and surpass the million mark in 2014.

The ERCB expects production from in situ bitumen projects will surpass that of bitumen from mining projects by 2015.

— DAILY OIL BULLETIN

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With BlackPearl Resources Inc.’s steam assisted gravity drainage (SAGD) pilot pro­ ject set to start up this quarter and expectations of getting polymer in the ground at its Mooney project early this summer, the company is entering the execution phase of its business, shareholders were told at the company’s annual general meeting.

Polymer-injection facilities have been completed at Mooney, where half of the wells have been converted from producers to injectors and should commence injection shortly. The company anticipates it will take six to 12 months of steam injection before it can make initial assessments of the pilot performance, re-pressurize the reservoir and start to see increased volumes.

Peak rates from the first phase of the polymer flood are expected to be 3,000– 4,000 barrels of oil per day. The upgrades required to the existing oil treating facilities will begin in the third quarter this year. The pilot has indicated success, John Festival, president and chief executive officer told the meeting.

“We looked at what was happening next door, at where CNRL [Canadian Natural Resources Limited] and Cenovus [Energy Inc.] were operating and saw very good results,” said Festival. “All of our lab work, all of our simulation work, all of our consultants have told us that this is going to work.”

The company has added $30 million to its capital spending budget for the year and now plans to spend a total of $146 million, Festival told the meeting. He said the increase will be spent on its three core properties: pre-drilling horizontal wells at Onion Lake, installing “lots of extra stuff” to help safely inject steam at its vertical wells at Onion Lake and constructing a battery at Mooney in preparation for Phase 2.

“We’re pre-spending for a lot of these long-term projects,” explained Festival.

The budget now calls for spending of: $69 million at Onion Lake to drill 100–110 conventional heavy oil wells and upgrade infrastructure; $43 million at Mooney to install polymer facilities and convert

Northeastern Alberta wells to polymer injection; $22 million at Blackrod to complete construction of the pilot, begin steaming and complete the commercial phase application, and $12 million on other items.

During the first quarter of 2011 at Onion Lake, BlackPearl drilled 12 wells, below its original plan to drill 35 wells, due to the lack of rig availability and experienced crews during the busy winter months. Rigs are now available and to catch up on its drilling program the company has contracted two additional rigs and now has three rigs operating at Onion Lake. The company still plans to drill between 100 and 120 conventional wells at Onion Lake this year as originally planned.

The BlackPearl Resources budget now calls for spending of $69 million at Onion Lake to drill 100–110 conventional heavy oil wells and upgrade infrastructure.

During the first quarter, BlackPearl undertook an extensive review of thermal development at Onion Lake and as a result plans to submit a 10,000-barrelper-day SAGD development application this summer and, upon approval, will begin drilling some horizontal wells.

Pre-drilling some of the horizontal wells will reduce the risk of reservoir damage caused by lost circulation from drilling through partially depleted zones. SAGD development will not begin until the company has maximized recovery from conventional development.

The company plans to file an application for a 40,000-barrel-per-day commercial development of the Blackrod lease in the first quarter of 2012, and for commercial development to occur in phases, with the first phase of 10,000 barrels per day as early as 2015. Production of 500–800 barrels per day per well pair, and a steamoil ratio of three to 3.5 are expected. The project has the potential for up to 70,000 barrels of oil per day.

Festival told the meeting the company remains on track to average production of between 11,000 and 13,000 barrels per day this year.

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Northeastern Alberta

AOSC advances carbonate play Athabasca Oil Sands Corp. (AOSC) says initial results from the company’s oilsands-related winter drilling efforts “look promising.”

Although AOSC has added more than one million acres of Deep Basin acreage, its bitumen assets remain core to the company and during the quarter it drilled a total of 89 delineation and 38 water wells.

AOSC president and chief executive officer Sveinung Svarte said the drilling program included several wells designed to perform two tests in the Dover West Leduc carbonate formation: a slanted well where steam was injected to assess steam behaviour within the reservoir and two horizontal wells to test heat-conductive behaviour using thermal assisted gravity drainage (TAGD) with four associated observation wells.

“The reason why we looked at [TAGD] is we took samples from this very good rock and heated it up in labs and already at about 140 degrees Celsius, which is 90 degrees lower than normal SAGD [steam assisted gravity drainage], we recovered about 75 per cent of the oil in less than 24 hours. This shows you something about the quality of the rock and

By Paul Wells

how easily it releases the hydro­carbons,” Svarte said during a recent webcast.

“So if you can extract the oil by heating it to 140 Celsius instead of 240 Celsius... it’s a huge saving in energy needs.”

During the TAGD test, AOSC inserted mineral-insulated cable into the wellbores and turned the heaters on to heat the reservoir for six to 10 months. Svarte said the company expects to turn the lower well into a producer this fall or early winter.

“If successful, TAGD could be the key to producing bitumen carbonate reefs global­ly,” he said. “These types of reservoirs could be heated at lower temperatures, thus needing less energy and potentially saving significant operating costs.”

Svarte said the company also injected quantities of steam into the highly fractured reservoir and observed that a good steam chamber was formed. He said the initial conclusion is that SAGD remains a viable option to heat the bitumen in this formation, which management believes is good news.

In addition to further steam tests, Svarte said the company anticipates applying for a

TAGD pilot of up to 12,000 barrels per day in late 2011 with a view to obtaining regulatory approval in late 2012 or early 2013.

Construction would commence shortly thereafter with start-up in late 2013 or early 2014.

AOSC also drilled 22 delineation wells in the Birch area, the company’s largest asset in net acreage with approximately 470,000 acres of contiguous land containing 1.15 billion barrels of contingent resource (best estimate). Svarte said the preliminary drilling results looked positive so management requested the regulatory group begin preparation of a commercial application and environmental impact assessment.

On March 31, 2011, AOSC filed its regulatory application to construct a 12,000­-barrel-per-day SAGD project at Hangingstone, located about 20 kilometres southwest of Fort McMurray. This is expected to be the company’s first wholly owned oilsands production with first steam anticipated as early as the fourth quarter of 2013.

— DAILY OIL BULLETIN

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Central Alberta plays drive record land sale

By Richard Macedo

JUN/10

JUN/11

JUN/10

JUN/11

WELLS SPUDDED

160

197

WELLS DRILLED

143

169

Photo: Joey Podlubny

“The most interesting result in this land sale is the focus on conventional oil in the Cardium formation,” said Energy Minister Ron Liepert in a statement. “This is the result of our previous changes to the royalty structure which encourages the use and deployment of new technologies in accessing the resource.”

Licences from around 38-6W5 and 47-10W5 combined for bonus bids of nearly $450 million. Top price paid for a single parcel was $106.5 million submitted by Meridian Land Services (90) Ltd. for a 7,872-hectare licence.

The broker picked up several tracts at 41-03W5, 42-03W5, 41-04W5, 42-04W5, 41-05W5 and 42-05W5 northwest of Red Deer, Alta.

Cavalier Land Ltd. scooped up an adjacent 6,656-hectare licence for $93.9 million at an average of $14,103 per hectare. All the large bonus parcels were acquired through brokers.

Daily Oil Bulletin records show several companies have licenced wells in the area with the Glauconitic sandstone as the total

depth zone, including TAQA North Ltd., Penn West Petroleum Ltd. and Bonavista Energy Corporation.

“Absolutely amazing, particularly the sheer volume of land that sold for more than $5,000 per hectare,” said Brad Hayes, president of Petrel Robertson Consulting Ltd. “Most of these lands were posted in a part of west-central Alberta that has been extensively developed in shallower horizons [like] Belly River through Rock Creek.”

He added that most of the postings were thus deep rights below the base of the Rock Creek.

“You have to conclude that we are looking at one or more deep plays,” Hayes said. “Most of the postings are in the Devonian West Shale Basin, away from known reefal buildups of Leduc or Swan Hills age.

“The pattern of posting large parcels and bidding big dollars is the way that resource plays have been pursued and it appears that the Duvernay is the most likely candidate for these lands. The fact that the lands are posted in the middle of the basin and not further west, where it is deeper and more mature, would indicate that liquids or liquids-rich gas are what people are looking for.”

Geoff Ready, an oil and gas analyst with Haywood Securities Inc., said the large packages were leased for Duvernay shale potential in west-central Alberta.

“Obviously they were posted in large blocks to narrow the list of potential bidders,” he said. “These results may also reflect positively on a few different junior companies who hold deep rights in the area.”

Chris Theal, president and chief executive officer of Kootenay Capital Management Corp., said the larger bonuses were for Jurassic and deeper rights, “so clearly [there are] deeper pockets in play.”

“The second large block at South Pembina and Willy Green included Cardium rights,” he said. “We are seeing high values for land being paid in new regions where horizontal, multifrac technologies are believed to be applicable.

The land sale indicates that producers will be drilling the Duvernay shale in the near future.

Alberta established a new record for bonus revenue at a single land sale in early June, taking in a massive $843 million in bonus bids, surpassing the $651.4 million paid at the Feb. 8, 2006, sale that was driven by a play for carbonates near Fort McMurray.

A total of 273,621 hectares exchanged hands at an average price of $3,081 per hectare. With this massive payday, the government’s land auction revenue for the year has now swelled to $1.8 billion on just over two million hectares at an average of $882.48. To the same point last year, $782.6 million had filled the provincial treasury on 1.3 million hectares at an average of $579.87 per hectare.

With 14 sales still scheduled this year, the province could set a new calendar-year record for bonus bids. In 2010, the province attracted revenue of $2.4 billion second only to the 2006 tally when Alberta received $3.43 billion thanks to heavy spending for oilsands acreage.

CENTRAL ALBERTA WELL ACTIVITY

JUN/10

JUN/11

WELL LICENCES

276

312

▲

▲

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • AUGUST 2011

55

Central Alberta

“Recall, there was no well completion in the Alberta Bakken prior to the $50­-million land sale last summer. We see guys moving Viking potential east into Sylvan Lake, where limited Viking activity has happened, but the play expands on mapping and technology. So, I would expect Alberta land sale activity to reflect companies’ desire for continued access to where they can apply technology to extract oil/gas from tight rock.”

In terms of other significant parcels, Canadian Coastal Resources Ltd. had the land sale per-hectare high of $14,389, paying a bonus of $57.1 million for a 3,968-hectare licence parcel. The broker acquired several sections at 40-05W5 and 40-06W5 for petroleum and natural gas below the base of the Rock Creek member.

Other highlights of the sale included Basm Land & Resources Ltd. picking up a 7,680-hectare licence at 41-05W5 for $85.5 million, which worked out to an average of $11,128.

Centennial Land Services Ltd. scooped up a 7,732-hectare licence for $71.9 million at an average of $9,310, acquiring 10 tracts and several sections in the area around 42-03W5.

Redwater CO2 EOR unlikely without “significant” penalties for emitters ARC Resources Ltd. is continuing its technical assessment of using CO2 for enhanced oil recovery (EOR) at Redwater, but the company is “very discouraged” by its commercial prospects.

The giant oilfield in central Alberta presents a “very, very large enhanced oil recovery opportunity” and its assessment has been “an important science project” for ARC, John Dielwart, the company’s chief executive officer, told ARC’s annual general meeting.

For the last several years ARC has been injecting CO2 into the reservoir to see if the gas might increase the amount of lucrative light oil that can be ultimately recovered from the vast field.

CO2 injection ended last summer, but the oil production phase of the pilot continues.

The company is continuing to gather data and is now assessing whether a commercial CO2 EOR project might be technically viable.

“We have made no final conclusions in that regard. But what I can tell you is we’re very encouraged from a technical perspective,” Dielwart said.

“We’re very discouraged, however, from a commerciality perspective,” he told

shareholders. “Because our position all along was we are not going to expose your company to a huge liability to purchase CO2.”

From ARC’s perspective, the problem is that the major CO2 emitters still don’t face any significant penalties for emitting.

“Therefore the only way we can get CO2 from the emitters is to buy it,” the ARC chief executive officer explained.

“We view CO2 as a waste product, not a profit centre for the emitter. And we’re not prepared to move forward with any project here if we have to pay significant amounts for the CO2.”

If ARC concludes that CO2 EOR is technically possible at Redwater, but isn’t commercially viable, “then we wait and see what happens to CO2 emissions legislation,” Dielwart said. “...So there may or may not be a project for us down the road.”

Although ARC hasn’t operated a commercial CO2 EOR project, the company has plenty of experience reversing production declines.

— DAILY OIL BULLETIN

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Central Alberta

Bellatrix sketches out remainder of 2011 With an extra $70 million in spending planned for the remainder of 2011, Bellatrix Exploration Ltd. plans on growing its operations across central Alberta.

As prev iously reported, Bellatrix increased its capital budget to $170 million from $100 million, which includes the $59.1 million spent in the first quarter. Bellatrix will use cash flow, the proceeds of its recent financing, and to the extent necessary, bank debt to fund its 2011 program.

This year Bellatrix expects to drill 63 (47.57 net) wells.

Of the 63 wells, the company anticipates drilling, nine potential McLaren heavy oil wells in the Frog Lake area of Alberta and a total of 54 (38.57 net) Cardium and Notikewin wells in the Pembina and Ferrier areas of Alberta, for an estimated cost of $138.7 million.

As well, the company anticipates spending $2.2 million on land and seismic acquisitions, $12.2 million on wellsite equipping and field facilities, $13.7 million related to the acquisition of property

interests and $3.2 million in costs associated with ongoing abandonment of wells.

On top of the $170-million capital program, Bellatrix expects to use up to $10 million from a joint venture partner that would earn a non-convertible gross overriding royalty in any resulting production.

During the first quarter the company’s capital program was focused on exploiting its Cardium oil and Notikewin liquids-rich gas resources by drilling 21 (12.1 net) wells coupled with increasing its undeveloped acreage on the Cardium play by 14,042 net acres (21.9 sections), which replaces more than the inventory drilled to date.

Increased unscheduled facility and well downtime and infrastructure construction delays occurred in the first quarter due to extremely cold weather in Alberta. As a result, sales volumes were flat with the fourth quarter of 2010 at 10,084 barrels of oil equivalent a day (about 39 per cent oil and natural gas liquids).

The estimated field production level for April increased to 12,134 barrels a day (39 per cent oil and natural gas

liquids) as a direct result of the firstquarter drilling success.

During the quarter Bellatrix established 100 per cent drill bit success drilling 21 (12.07 net) wells consisting of 15 (9.67 net) oil wells and six (2.4 net) liquids-rich gas wells.

Last May, Bellatrix modified its fracturing proppant-carrying fluid from oilbased to water-based as a component of its on­going optimization program. The results exceeded its expectation, reducing well costs by $500,000, while more than doubling the post-frac production rates.

The wells tested were in four different areas of the Cardium—Norbuck, Lodgepole, Willesden Green and West Pembina.

The March 28 CIBC Resource Play Watch listed five of Bellatrix’s Cardium producers in the top eight producing wells based on peak initial production rate, which represents the maximum monthly producing rate in a well’s first eight months of production. A total of 497 wells were reviewed.

— DAILY OIL BULLETIN

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57

Central Alberta

Deep Basin drives Cequence growth be generated at current natural gas prices.

Liquids yields of 45 barrels per million cubic feet in the Montney and 25 barrels per million cubic feet in the Wilrich are expected.

Cequence also completed facility work at Simonette in April to increase productive capacity to 37 million cubic feet a day through the Keyera Simonette gas plant.

The company increased its average production by 235 per cent over the first quarter of 2010 and nine per cent over the fourth quarter of 2010. Average production in the first quarter of 2011 was 8,185 barrels of oil equivalent per day. Production growth compared to the first quarter of 2010 resulted from acquisitions completed in 2010 and the success of the company’s drilling program.

Capital expenditures of $45.6 million in the first quarter of 2011 were focused on the Simonette area of the Deep Basin. Drilling and completion expenditures of $30.6 million were designed to test the potential of both the Wilrich and Montney resource plays at Simonette.

In 2011, Cequence continued to add to its land base at Simonette with 7,200

Photo: Joey Podlubny

Production additions from Cequence Energy Ltd.’s winter drilling program were restricted by existing gathering systems and compression at Simonette. The initial phase of facility expansion was completed and Cequence began to produce additional volumes in May. The company said it is on track to meet or exceed its average production guidance for 2011 of 9,200 barrels of oil equivalent per day and an exit production rate of 10,000 barrels a day.

During the first quarter of 2011, Cequence said it established the economic viability of two separate resource plays in the Montney and Wilrich at Simonette. Two Wilrich horizontal wells, two Montney horizontal wells and two vertical delineation wells were completed in the quarter. Results from the initial horizontal wells completed in the winter drilling program are very encouraging, Cequence said.

Based on observed initial production rates and natural gas liquids yields of Montney and Wilrich wells, management believes that strong economic returns can

Cequence grew production last year by 235 per cent.

net acres acquired, resulting in current landholdings at Simonette of 72,400 net un­developed acres.

For the remainder of 2010, Cequence said its drilling program will be focused on the continued horizontal and vertical delineation of its resource base at Simonette, with a minimum of four to five wells targeting the Montney and Wilrich zones, and two wells targeting new prospects. Drilling was expected to resume in early July, following spring breakup.

— DAILY OIL BULLETIN

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AUGUST 2011 • OIL & GAS INQUIRER

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Central Alberta

Forest Oil continues growing oil, liquids production D a i l y p r o du c t i o n f o r Fo r e s t O i l Corporation rose in Canada in the first quarter, a period during which the company continued working its Evi light oil play and its Nikanassin resource play.

Canadian Forest Oil Ltd. production climbed to 13,917 barrels of oil equivalent per day from 11,717 barrels the previous year.

Forest holds roughly 48,000 gross and 41,000 net acres in the Evi light oil play in north-central Alberta. During the first quarter, Forest resumed operations in the Evi area with a three-rig development program, drilling a total of 17 short lateral length horizontal wells using new pad drilling techniques and increasing the number of fracture stimulation stages from an average of six to 10 stages.

As of March 31, 11 of these wells were in various stages of completion. Seven of the 11 wells have achieved average maximum initial production rates of 300 barrels per day while the remaining four wells are cleaning up after fracture stimulation. The six uncompleted wells were expected to be completed after spring breakup.

“At that same time, we will put three rigs back to work in the field and continue that program throughout the remainder of this year,” said J.C. Ridens, executive vice­president and chief operating officer.

The wells drilled in Evi are all short laterals averaging about 1,800 feet in length and were stimulated on average with 10 frac stages compared to six frac stages used in 2010 for that same lateral length.

“The Canadian business unit was the first company to drill horizontal Slave Point carbonate wells in this area, which provides valuable data for our continuing drilling program,” Ridens said.

The typical Evi well is forecast to cost $2.3 million to drill and complete. The company has 242 future wells identified, Ridens said.

Forest holds about 214,000 gross and 127,000 net acres in the Nikanassin resource play. The area provides access to a minimum of 10 different stacked-pay producing intervals, many of which can be completed with production commingled in a single wellbore.

During the first quarter of 2011, Forest completed four vertical wells that had average initial 24-hour production rates of nine

million cubic feet of gas equivalent per day.

The results from these four wells bring Forest’s average 24-hour initial production rates from its Nikanassin resource program to 11 million cubic feet per day.

Through production log information relative to the stacked pay intervals, Forest has identified specific zones for which it initiated a horizontal drilling program to isolate completions in the most productive intervals. The company’s first horizontal test had a 24-hour initial production rate of 6.4 million cubic feet per day from a single interval. This first horizontal well was drilled with a 2,200-foot lateral and completed with seven fracture stimulation stages. The well was not drilled to planned specifications of a 4,000-foot lateral and 12 fracture stimulation stages due to slowerthan-expected drilling rates and operational time constraints.

Forest intends to evaluate and monitor the horizontal well performance and plans to conduct additional horizontal operations in the second half of 2011.

— DAILY OIL BULLETIN

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Central Alberta

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Second Wave Petroleum Inc. says it has a “simple” strategy for growth: focus on oil resource plays at Judy Creek, northwest of Edmonton, where it has 90,000 undevelop­­­ed net acres.

“We’re going to concentrate on delineating and developing the Pekisko, while also exploring the Beaverhill Lake and Ellerslie formations,” Colin Witwer, president and chief executive officer, told the company’s annual general meeting.

During the first quarter of 2011, Second Wave faced operating challenges due to a fire at the company’s Judy Creek gas plant. As a result of the damage, Second Wave shut in approximately 1,650 barrels of oil equivalent per day of net production until repairs could be made.

“It took us approximately 61 days to replace the gas plant,” Witwer said. “We ended up re-licensing it, expanding it and improving the design of the gas plant to ensure that didn’t occur in the future.”

Upon start-up and commencement of production through the gas plant, however, Second Wave experienced another four weeks of operational hurdles.

The net impact of the lost production exceeded 800 barrels per day for the first quarter.

The company is currently planning to restart its Pekisko drilling program at the end of the third quarter with up to six (six net) Pekisko horizontal wells to be drilled by year-end.

To date, one (one net) well has been drilled in 2011 and is awaiting completion.

The company expects that all Pekisko wells drilled in 2011 and 2012 can be drilled off of existing producing pads, which should facilitate reduced cycle times and lower capital commitments per well than what had previously been ex­perienced during the delineation drilling phase.

The company had eight (eight net) Pekisko horizontal oil wells at year-end 2010 with less than 30 days of production prior to the Judy Creek gas plant outage in December. The company said the eight wells have continued to meet management’s expectations with aggregate production rates from the wells increasing since the start-up of the company’s gas plant in February.

Production from all eight wells is currently limited by surface pumping capacity and the company continues to

monitor the performance of the wells to evaluate the feasibility of optimization alternatives.

Pursuant to its Beaverhill Lake joint venture agreement, Second Wave has now drilled its first two (0.8 net) horizontal oil wells in 2011.

To date, one (one net) well has been drilled in 2011 and is awaiting completion.

The first well (0.4 net), located at 15-36 - 063-10W5, tested at rates of 1,825 barrels of oil equivalent per day (86 per cent oil) over a 15-day period and is currently pumping to permanent facilities at rates of approximately 350 barrels of oil equivalent per day after cumulative oil production of approximately 32,000 barrels.

Production from the 15-36 well is currently limited due to surface pumping capacity and management intends to monitor the operations of the well over the next few months to determine if a larger pumping system is required.

The second well (0.4 net) has been drilled and cased and is currently awaiting completion and subsequent tie-in.

The company anticipates drilling a total of 14 (5.6 net) Beaverhill Lake wells within its Judy Creek joint venture lands in 2011, including the two (0.8 net) wells drilled to date in 2011.

At Judy Creek, the company curr e nt l y h a s 5 0,0 0 0 g r o s s a c r e s of Beaverhill Lake mineral rights within the area covered by the joint venture agreement. The company also holds or has an option on an additional 9,200 acres of Beaverhill Lake mineral rights in Judy Creek at a 100 per cent working interest outside of the joint venture agreement area.

In addition, the company plans to drill, complete and tie-in five (five net) Ellerslie vertical wells during the year.

Capital expenditures for 2011 are budgeted at $50 million, including $41 million for drilling and completions, $6 million for facilities and pipelines, and $3 million for land and seismic.

— DAILY OIL BULLETIN

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Southern Alberta

Crescent Point saying little about initial Alberta Bakken wells

By Paul Wells

JUN/10

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Photo: Joey Podlubny

not going to talk to them until we move to a development program out there and we can ensure our shareholders and people what our game plan is out there.”

According to the company’s first-quarter release, Crescent Point drilled seven (3.5 net) oil wells in the period, including one net well in an unconventional zone. The company expects to spend $31 million in southern Alberta in 2011, drilling 14 net wells.

“We’re in our first phase of development, so it’s super early days,” Saxberg said.

“The way I describe it...is it’s the first period of the hockey game, we’ve had three shifts and got a couple of shots on net...and we don’t know what the score of the game is going to be and we don’t know who is going to win it.”

Company-wide, Saxberg said Crescent Point is looking to bulk up its already large oil-in-place numbers and has the “potential to double” proved-plus-probable

reserves, which currently stand at just under ­­380 million barrels of oil equivalent.

He noted that the company currently has about 10.6 billion barrels of oil in place and has recovered only 3.4 per cent and booked 8.5 per cent (proved plus probable) of that total. However, Saxberg said that based on analogue data, infill drilling and the company’s own technical data, he believes the recovery factor can be increased to almost 18 per cent.

“You take that difference between what we currently have booked and what we believe based on our technical and historical numbers, and we think we can add almost 630 million barrels of reserves above and beyond our almost 380 million barrels booked to date,” he said.

“That’s an incredible stat. It doesn’t include our waterflood upside. So an additional 10 per cent recovery at Viewfield [Bakken] and an additional five per cent or more recovery at Lower Shaunavon...and you start to throw those numbers around it gets upwards of 900 million barrels of potential adds. At 3.4 per cent [recovery to date], we’re just getting started.”

Saxberg said that in his mind, the company’s early-stage waterflood project in the Viewfield Bakken is a “real game changer.”

“We’re just in the phase of implementing waterflood throughout the field.... It’s a game changer for the company and it changes our five-year model and how you look at waterflood in the growth of the company,” he said.

“Right now a 20 per cent recovery is what we believe will occur on primary with infill drilling at eight wells per section. With the waterf lood and the way it’s trending, we see over 30 per cent. The net impact of that...is basically a ­­75 per cent increase on our net asset value from primary to waterflood.

It’s a huge, huge impact.”

Results of exploration work in the Bakken play in southern Alberta are being kept under wraps.

Crescent Point Energy Corp. is keeping a lid on releasing information pertaining to its early-stage southern Alberta Bakken play, and president and chief executive officer Scott Saxberg is offering no apologies for remaining tight-lipped.

“We are in the midst of an exploration program out there, so it’s very competitive.

We’ve got competitors out there that are buying land that we’re competing with, so we don’t disclose those numbers,” Saxberg said after a shareholder at the company’s annual general meeting asked him about the results of three exploration wells drilled during the second half of 2010.

“We’d love to, but because of competition we don’t.... We’re early days on production. The production on the first couple of wells is public, you can go to the records there,” he added. “What we’ve described to people is to take whatever conclusions you like out of those results because we’re SOUTHERN ALBERTA WELL ACTIVITY

JUN/10

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132

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Source: Daily Oil Bulletin

OIL & GAS INQUIRER • AUGUST 2011

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Southern Alberta

CAODC ups well forecast

By Elsie Ross Based on the high level of winter drilling activity in the first quarter, the Canadian Association of Oilwell Drilling Contractors (CAODC) has boosted its forecast activity for western Canada this year.

In a revised forecast released in early June, the association estimates that 13,128 wells will be drilled this year, up from its October 2010 forecast of 11,811 wells.

CAODC is projecting that 433 rigs on average, out of a fleet of 802, will be active for a utilization rate of 54 per cent. The forecast anticipates 154,314 operating days for the year.

Over the last three quarters of 2011, CAODC expects a 24 per cent jump in activity, mainly on the oil side.

The adjusted forecast calls for 200 rigs or 25 per cent of the fleet to be drilling on average during breakup, up from the earlier estimate of 160 rigs. CAODC projects that 467 rigs, or 58 per cent of a rising fleet of 805 rigs, will be active in the third quarter. During the last three months of 2011, 530 rigs are shown as active, a utilization rate of 65 per cent (815 rigs—10 more rigs added).

The CAODC forecast projects a 20 per cent increase in operating days to 154,300 over the 128,600 shown in October and an 11 per cent rise in the number of wells completed to be 13,128, an increase of 1,300 over the 11,811 wells anticipated in the October projection.

The difference between the larger increase in anticipated days and the well count change is explained by the 10 per cent rise in the time taken to drill the average well. The forecast now assumes 11.8 days per well, up from 10.8 days per well in the previous forecast.

CAODC’s revised forecast confirms the shift to oil well completions, away from nat­ ural gas drilling. Approximately 60 per cent of the wells being completed are directed at oil, and those wells are increasingly horizontal.

Many are seeing the application of multistage fracking technology, which had been most prevalent in the Bakken play in Saskatchewan and Manitoba, but is now widely used in the Cardium and Viking formations of Alberta.

Natural gas drilling is focused on resource plays containing a high liquids

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content, with shallow gas completions significantly down.

In the first three months of this year, rig utilization averaged 68 per cent in western Canada; some 11 per cent higher than the CAODC October projection. The industry ran an average of 534 drilling rigs, up from the 480 anticipated. The first-quarter strength in activity was based on high commodity prices, a favourable investment climate and “good geology.”

In the first quarter, Alberta utilization averaged 67 per cent (385 rigs running out of a fleet of 571); in Saskatchewan the utilization was 71 per cent (78 rigs out of 109 available); in British Columbia, 64 per cent (56 out of 88 available rigs) and in Manitoba, 77 per cent utilization (14 out of 18 rigs available).

In the Northwest Territories, utilization averaged 50 per cent (one out of two rigs active).

The revised forecast assumes an oil price of US$90 per barrel West Texas Intermediate and C$4 per gigajoule at AECO for natural gas.

— DAILY OIL BULLETIN

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Southern Alberta

Alberta Bakken results encouraging, says Murphy CEO Murphy Oil Corporation says it has drilled and completed its f irst t wo Exshaw shale appraisal wells in a sixwell program in the Alberta Bakken play in southern Alberta.

“At this early stage, from what we have seen, it’s encouraging but it’s not an Eagle Ford [Texas],” David Wood, president and chief executive officer, said in a conference call to discuss first-quarter 2011 results.

The wells are currently being evaluated, and while it’s still early, “we are pleased the wells have flowed within our expectations,” he said. “We will continue to add acreage in this new play as it fits within our understanding.”

Because it plans to pick up additional land, he declined to provide more information about the wells.

“If we can get wells that are better than 200 barrels a day to start, then I would regard that as being good and I would say that the first two wells would get into that bucket,” said Wood. “What we need to do is see some performance from those wells from initial flow and then put a pump on and see how they produce.”

And while he would like to add more acreage, “I am not so sure I would add the acreage in the places that I was going to want to add the acreage prior to the well results.”

For Wood, the keys in looking at the play are the presence of water and the kind of reservoir pressure. Water is going to be patchy with some parts of the play having it and some not while some areas will have more over-pressure, which would mean Murphy should expect better rates, he said.

Murphy rig released horizontal, newpool, wildcat wells with bottomhole locations of 16-04-001-20W4 and 14-02002-21W4 in the Regan area earlier this year. The wells were drilled to total depths of 2,960 and 3,060 metres, respectively, with the Wabamun Group just below the Exshaw listed as the projected zone in both cases.

— DAILY OIL BULLETIN

Service companies boosting budgets to meet demand Many of the companies comprising Canada’s service and supply industry benefitted during the first quarter from the swing to drilling and completing oil and liquids-rich natural gas targets with horizontal wells and multistage fracs, while oilsands activity bolstered financial results for other suppliers.

Activit y was so brisk during the quarter that many service companies announced plans to hike their 2011 cap­ital budgets to meet demand for equipment and services. Capital investments for 2011 have been increased to $4.42 billion, up $930.65 million from initial capital spending plans of $3.49 billion.

Companies offering fracturing services are bulking up on their hydraulic horsepower. Drillers are adding rigs. They are reacting to higher demand for their equipment and services as Canadian producers

have ramped up their spending plans by around 11 per cent or $2.2 billion since January, according to investment research firm Peters & Co. Limited.

Peters has hiked its forecast well count in Canada to 12,500 wells this year and 13,000 wells next year, and it also expects some price increases by service companies leveraged towards resource play development in the third quarter.

In the first quarter (ended March 31), capital spending of 43 Canadian service and supply firms tracked by the Daily Oil Bulletin more than doubled to $1.07 billion from $441 million during the yearprior quarter.

Net of acquisitions in both years, capital spending by 43 service companies totalled $998.92 million for the three months ended March 31, 2011, compared to only $296 million a year earlier.

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The largest year-over-year increase in capital spending was reported by Pembina Pipeline Corporation, up $202.80 million to a total of $223.30 million for the quarter, which included spending to expand its oilsands and heavy oil business through the Nipisi and Mitsue pipeline projects, and the $57-million acquisition of a terminalling and storage facility near Edmonton.

CanElson Drilling Inc. (up $70.19 million in spending), Precision Drilling Corporation (up $57.32 million) and Calfrac Well Services Inc. (up $50.80 million) also reported large increases to their first­quarter capital investments.

During the first three months of 2011, net income and cash flow rose 89 per cent and 48 per cent, respectively, compared to the year-prior quarter.

— DAILY OIL BULLETIN

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Saskatchewan

PetroBakken enhanced recovery scheme gains momentum

By Pat Roche

JUN/10

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Photo: Joey Podlubny

the company estimates its base decline rate for 2011 will be 40 per cent.

Waterflooding is by far the most common EOR technique in western Canada and Crescent Point Energy Corp., the other big Bakken player, is encouraged by waterflood tests in areas it operates.

But the rock isn’t homogenous and waterflooding won’t work on significant portions of PetroBakken’s Bakken lands, the company’s modelling indicated.

The goal is to increase reservoir pressure, which falls as oil is extracted. In the areas targeted for natural gas EOR, the permeability is so low that it isn’t possible to inject water fast enough to offset production from nearby oil wells, said Rene Laprade, PetroBakken’s senior vice-president of operations. Hence there wouldn’t be sufficient re-pressuring of the reservoir to enhance oil recovery.

CO2 would work, a brief test indicated. In February 2010, PetroBakken shut in one of its

Bakken wells for a “very short” CO2 injection and soak period. In the ensuing 14 months, two offsetting wells each recovered more than 6,000 barrels of additional oil, Wright said.

This test and reservoir modelling convinced PetroBakken that gas injection would enhance oil recovery. There are two reasons the company is piloting dry natural gas injection rather than CO2.

The first is an abundant supply of cheap solution gas from the company’s own nearby gas plant. The second is existing facilities can be used without worrying about corrosion.

The company has allocated $20 million this year for five pilot projects to evaluate the effectiveness of injecting natural gas to increase ultimate oil recovery.

Methane injection began in March on the first pilot at a preliminary low rate of half a million cubic feet a day. The second injection well is drilled and injection is to start in July or August.

“We’ve got four more wells to drill through the end of this year. And so by early 2012 we should have five EOR projects going,” Wright said.

PetroBakken will use the pilots to test different concepts or well configurations.

For example, in the second pilot—which will inject natural gas at a rate of about two million cubic feet a day—gas will be injected along the entire horizontal section of the injection well, so the flood front will hit the toe of each of the four perpendicular producing wells.

“As gas breaks through at the toe of each well, we have the ability to simply plug off the toe area of the producing horizontal well and mitigate the cycling of the gas at that port,” Laprade explained. “The front would continue to move along the horizontal producing leg to the next port, where we would again plug that port off as the gas breaks through.”

The company hopes to make public some preliminary data from the first pilot by year’s end, and to release further results by mid-2012. If the results are favourable, “I would expect there’d be a significant acceleration in pilots,” said Laprade.

PetroBakken is using natural gas rather than CO 2 to coax more oil out of the ground.

While CO2 for enhanced oil recovery (EOR) hasn’t taken off in a big way in western Canada (partly because of the high cost of extraction), conventional gas may make sense for pressure maintenance in some depleting oil reservoirs, now that prices for gas and oil are so far apart.

PetroBakken Energy Ltd. has 1.8 billion barrels of light oil in place in the tight Bakken formation in southeastern Saskatchewan.

Only five per cent has been booked as provedplus-probable reserves.

“We actually think there’s a potential for reserve booking of more than 25 per cent once you include the effect of our enhanced oil recovery programs,” John Wright, PetroBakken’s president and chief executive officer, told the company’s 2011 annual meeting. “And that’s not only going to increase our ultimate reserves, but it will mitigate the decline rates.”

Because Bakken wells have steep first-year decline curves and most of PetroBakken’s wells have been drilled in the past couple of years, SASKATCHEWAN WELL ACTIVITY

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Source: Daily Oil Bulletin

OIL & GAS INQUIRER • AUGUST 2011

67

Saskatchewan

New CO2 project in the works An agreement could be reached by year’s end for Saskatchewan’s third commercial enhanced oil recovery project using CO2, says the province’s energy minister.

Saskatchewan, through its governmentowned electric utility, SaskPower, has committed funding to capture CO2 from one generating unit at its Boundary Dam coal-fired power plant near Estevan in southeastern Saskatchewan.

So far, one element required for an enhanced oil recovery project to proceed has been lacking—an agreement with an oil producer to take the CO2. But that could change in the coming months, said Bill Boyd, Saskatchewan’s energy and resources minister.

“We’re in discussions with a number of oil companies about that very thing. In fact, I had a breakfast meeting this morning with one of them,” Boyd said on the sidelines of the Canadian Business Conferences’ tight oil symposium in Calgary.

“They are very, very interested in enhanced oil recovery benefits of CO2 and the storage of it. It looks very, very positive. I think they’re into advanced discussions with SaskPower,” the minister said of the oil producers, which he didn’t name.

“We think that will conclude probably later this year perhaps. And for a project to come on stream, I think they’re looking at

about late 2013, early 2014 for a very, very significant project,” Boyd said.

Two commercial CO2 projects in southeastern Saskatchewan—Weyburn and Midale—import the gas from a coal gasification project in North Dakota.

Meanwhile, he said the province continues to get applications for new waterfloods, by far the most common form of enhanced recovery in western Canada.

“All of these have improved the economics and the recovery rates of various pools in Saskatchewan, and our government is extremely supportive of them all,” Boyd said.

Meanwhile, the minister is confident about the long-term prospects for commercializing large bitumen deposits in northwestern Saskatchewan.

Across the border in Alberta, more and more commercial projects are coming on stream to extract the vast in situ oilsands resource. And in recent years, Alberta’s development activity has been moving further east. But the Saskatchewan oilsands have yet to see commercial production.

“I think there’s a fairly significant engin­e ering challenge, to be honest,” Boyd said. “It looks like there is no caprock above the oilsands on the Saskatchewan side. There’s a clay belt, but no caprock.

And so there’s concern if you’re using steam, that that may result in oil going to

the surface, of course, which would not be acceptable.”

The most recent push to exploit the Saskatchewan oilsands was mounted

by Calgary-based Oilsands Quest Inc. The company raised about $337 million since 2006 but so far has failed to establish a commercial project.

Despite the company’s lack of commercial results, Boyd believes Oilsands Quest “is still very much on the job.”

The minister said the company is still looking at various ways to extract the bitumen, which is too deep for mining.

“So I think there’s an ongoing effort in place there—in fact, I had a conversation with the proponents from Oilsands Quest yesterday about their plans going forward,” Boyd said. “I’m encouraged by what we’re seeing.”

He noted t hat Petrobank Energ y and Resources Ltd. also has a stake in the Saskatchewan oilsands. Petrobank holds a 23,040-acre oilsands licence at Sutton, Sask., not far from Oilsands Quest’s Axe Lake lease.

“There’s a large amount of oil that can be recovered in the future,” Boyd said of the province’s bitumen resource.

“I think we will see it when the technology is in place that ensures that it can be done in a reliable, safe fashion.”

— DAILY OIL BULLETIN

Saskatchewan June land sale draws $41M Saskatchewan’s June land sale brought in $40.9 million in revenue, the third-best on record for a June sale, bringing total bonus bids so far this year to $193.1 million.

A total of 72,694 hectares exchanged hands at the June 6 sale at an average of $563.36 per hectare.

After three sales so far in 2011, the province has sold 389,488 hectares at an average of $495.85 per hectare for a total bonus of $193.13 million. To the same point last year, Saskatchewan had taken in $275.8 million in auction revenue for 249,670 hectares at an average of $1,104.

“It’s always exciting to watch the action when prime Bakken and Shaunavon parcels are posted, and this sale was no exception. I was also pleased to see that all corners of the oilpatch continue to 68

AUGUST 2011 • OIL & GAS INQUIRER

contribute to the sale, from St. Walburg in the north to Consul in the southwest to Storthoaks in the southeast and points in between,” Energy and Resources Minister Bill Boyd said.

June’s sale featured eight licences that sold for $3.5 million and 260 lease parcels that attracted $37.4 million in bonus bids.

The Weyburn-Estevan area received the most bids with sales of $21.5 million. The Lloydminster area was next at $7.9 million, followed by the Kindersley-Kerrobert area at $6.1 million and Swift Current at $5.4 million.

The top purchaser of acreage in the province was Prairie Land & Investment Services Ltd., which spent $8.4 million to acquire 18 lease parcels. Prairie paid the top price for a single parcel, submitting a bid of roughly $3.8 million for a 62.28-hectare

lease within the Viewfield Bakken pool, 20 kilometres east of Stoughton. The broker picked up the northeastern portion of section 16 at 8-6W2. It also produced the per-hectare high of $60,302.

The top price paid for a single licence was $1.7 million tendered by Sandstone Land & Mineral Company Ltd. for a 1,489-hectare block situated at section 18-50-26W3 between the Big Gully McLaren and Aberfeldy Sparky oil pools, 20 kilometres northeast of Lloydminster.

Parcels offering deeper rights brought in $6.3 million (15.49 per cent of the sale) for an average price of $5,184 per hectare.

The next land sale is scheduled for August 8.

— DAILY OIL BULLETIN

Saskatchewan

Saskatchewan bringing in new flaring rules

Photo: Joey Podlubny

With crude production from plays like the Bakken and Lower Shaunavon on the upswing and associated gas following suit, the Government of Saskatchewan is introducing tougher rules on flaring and venting that it hopes will reduce greenhouse gas emissions while providing secondary economic benefits.

On June 22, the government announced its new Upstream Petroleum Industry Associated Gas Conservation Standards, which are designed to reduce emissions from the flaring and venting of associated gas. They establish a specified limit for the amount of natural gas that can be flared and vented from an oil well or associated facility. If that limit is exceeded, the producer is required to conserve and store the associated gas, and then either use or sell it.

Speaking to a Small Explorers and Producers Association of Canada (SEPAC) event, Saskatchewan’s Minister of Energy and Resources Bill Boyd said that while there will be a cost for compliance to the new meas­ures, both industry and the province will benefit long-term.

“Flaring is a concern to some people.

There is obviously a resource that’s being flared off and we want to try to capture some of that—or all of that—to the [greatest] extent that we possibly can and turn it into a useful energy source,” he said. “I think the new measures will help to move things in that direction. Obviously, there are some costs associated with that and we understand that. We do, though, think the benefits outweigh the downside.”

Boyd noted that there will be economic benefits from investments in new gasgathering systems and processing facilities, as well as the eventual sale of the gas.

Some of Saskatchewan’s associated nat­u ral gas is rich in ethane, propane and butane. These can be processed into value-added products such as liquefied petroleum gas.

As well, Boyd said the initiative will also help reduce Saskatchewan’s greenhouse gas emissions. He pointed out that it’s estimated that 68 per cent of the greenhouse gases emitted through oil and gas production is from the flaring and venting of associated natural gas.

Wet weather has slowed operations in southeastern Saskatchewan this spring and early summer.

“The new standards will mean a significant reduction in these emissions, possibly as much as a 49 per cent reduction. This is consistent with our overall goal of work ing with industr y to grow Saskatchewan’s economy in an en­v ironmentally responsible manner,” Boyd said in a press release announcing the new standards.

The new rules were jointly develop­e d by industr y and the government. A steering committee was established with representatives from the Canadian Association of Petroleum Producers, SEPAC, TransGas Limited, the provincial government and SaskPower.

T he com mit tee released dra f t standards for review and comment by industr y and the public in 2010. This process is now complete and the comments have been incorporated into the new standards.

“There’s been pretty good consultation with industry, I believe, in respect to it. We’re very pleased that the industry

sees it as a responsible thing moving forward,” Boyd told the SEPAC gathering.

Gar y Leach, executive director of SEPAC, said the new rules will be familiar to Alberta’s operators and the fact that they were developed in consultation with industry is helpful.

An economic value test is applied to the volume of vented or flared associated gas if the volumes exceed 900 cubic metres per day, and if the value equals or exceeds the prescribed value then conservation measures must be introduced to ensure the gas is deployed for power use, or is sold or re-injected into an oil or gas pool.

Implementation will be phased in.

T he standards w ill come into ef fect July 1, 2012, for new wells and facilities licensed on or after that date. For ex isting wells and facilities already licensed prior to July 1, 2012, the new st a nda rds have a n i mplement at ion date of July 1, 2015.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • AUGUST 2011

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Northern Frontier

Mackenzie Plain Horn River play advancing slowly

Photo: Joey Podlubny

By Richard Macedo

An old gas well in the Mackenzie Delta. Drillers are now looking for gas in the Mackenzie Plain.

The Northwest Territories is in the midst of investigating the potential for shale gas in the Mackenzie Plain through a fiveyear study, but at this point it’s difficult to assess the unconventional potential of the Horn River Group strata because it remains largely unexplored.

The Mackenzie Plain is relatively well-explored in other strata with peak activ it y occur ring in t he late 1960s and 1970s. During this time, industry focused on the pursuit of a second Norman Wells oilfield. This exploration phase resulted in the drilling of 76 exploration wells, the majorit y of which occurred in a narrow corridor near the town of Norman Wells.

Beyond t his immediate v icinit y, e x plor at ion i n t he M ac ke n z ie Plain region has been much sparser.

At present, t he on ly produc t ion i n the Mackenzie Plain occurs from the Norman Wells oilfield. But recent discoveries along the eastern mountain f ront of t he Mac kenzie ra nge have renewed interest in the area.

The potential for additional hydrocarbon discoveries in the Mackenzie

Plain exists, particularly in Cambrian, Devonian and Cretaceous strata.

To advance the geoscience k now­ ledge of key pet roleum plays, a f i v e -y e a r (2 0 0 9 -2 014) f i e l d - a n d subsurface-based study is being conducted by t he Nor t hwest Ter r itor ies

the Canadian Societ y of Exploration Geophysicists and the Canadian Well Logging Society. “Therefore, the strata may contain significant quantities of natural gas.

“Total organic content appears fairly similar to that contained in Horn River and Montney in northeastern British Columbia. In terms of maturit y, the Mackenzie Plain is generally less mature than the other two intervals. The major dif ferences occur in t he contents of silica and clay where Horn River strata in the Mackenzie Plain displays much higher silica and less clay.

“We realize we still have a lot of work to do to fully characterize these rocks.”

In the Mackenzie Plain, Middle to Upper Devon ia n Hor n R iver Group comprises the Hare Indian, Ramparts and Canol for mations. T hese st rata are well known for their source rock potential and consist of interbedded organic-rich, siliceous, f ine-grained siliciclastics and limestone.

Fie ld a nd subsu r f ace st ud ie s i n 2 010 we r e c on duc t e d t o e v a lu at e the shale gas potential of Horn River Group strata. Field methods involved measurement and detailed sampling of fou r Hor n R ive r Gr oup outc r op

The potential for additional hydrocarbon discoveries in Mackenzie Plain exists, particularly in Cambrian, Devonian and Cretaceous strata.

Geoscience Office (NTGO). One goal is to assess the unconventional potent i a l of M idd le to Up p e r D e v on i a n Horn River Group strata.

“Hor n R iver st rata in Mackenzie Plain is laterally equivalent to highly prolific gas-bearing strata [in British Columbia],” Ryan Lemisk i, a pet ro leum geologist w ith the N TGO, told the joint convention of the Canadian S o c i e t y o f P e t r ol e u m G e ol o g i s t s ,

sect ions in t he nor t her n Mac kenzie Mountains and collection of detailed spectral gamma ray data by a handheld scintillometer. Subsurface invest igat ion i nvolved desc r ibi ng a nd sampling s e v e r a l e x p l o r a t i o n w e l l s i n t he Mac kenzie Pla i n.

Across the border in British Columbia from 2006 to 2008, Crown petroleum and natural gas rights purchased in the Horn River Basin increased almost OIL & GAS INQUIRER • AUGUST 2011

71

Northern Frontier

eightfold from $126 million to almost $1.1 billion. In 2009, bonus payments from sales of petroleum and natural gas rights in the basin reached $316 million or 35 per cent of the $893 million provincial total. In 2010, bonus payments totalled $131.3 million or 15 per cent of the $844 million total.

“Over 75 per cent of the land is tenured in the Horn River Basin to date,” Christopher Adams, an oil and gas specialist with the Ministry of Energy, told the conference.

T he c ur rent c ha l lenge for ma ny operators in the Horn River Basin is the short-term economics of shale gas.

As the northernmost shale gas play in North America, the region has limited inf rastr ucture, is far f rom key consumer markets and, like other shale gas plays, finds itself contending with weak natural gas prices and an abundance of North American gas supply.

Some sha le ga s operator s have announced that they will be pursuing oil prospects or gas fields with high liquids content and will lower capital spending in the Horn River play in 2011.

Husky big spender at Northwest Territories land sale

By Elsie Ross The Canadian federal government has taken in more than $534 million in work commitments, including the top commitment of $366 million from Husky Oil Operations Ltd., in this year’s call for bids on 11 parcels of land in the Central Mackenzie Valley of the Northwest Territories.

In addition, two exploration licence parcels in the Mackenzie Delta/Beaufort Sea totalling 211,195 hectares went to Arctic Energy & Minerals Limited for a total work commitment of $2 million.

In the Central Mackenzie Valley, Husky bid $188 million each for t wo adjacent parcels, each 87,748 hectares, between 17 and 75 kilometres southeast of Norman Wells.

“We are not speculating at the moment what may or may not be there,” Colleen McConnell, a company spokeswoman,

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said. “Obviously it’s an area of interest for us; we think it’s prospective,” noting that there is an existing petroleum system at Norman Wells.

Husk y already holds exploration licences in the Central Mackenzie Valley, including a Significant Discovery Licence for the 2004 Summit Creek B-44 natural gas and light oil discovery well drilled into two Devonian-age reservoirs It also operates a lease over Tulita District Land Corporation freehold parcels.

The well on the EL397 licence was operated by Husky and tested at 20 million cubic feet per day of natural gas and 6,300 barrels per day of light oil. It is 50 kilometres southwest of Tulita and 80 kilometres from the existing Enbridge Inc. oil pipeline, which transports 39,400 barrels of light oil per day between Norman Wells and Zama, Alta.

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Northern Frontier

In addition to Husky, six companies acquired licences in this year’s offering: ConocoPhillips Canada Resources Corp.; Shell Canada Limited; Imperial Oil Resources Ventures Limited and ExxonMobil Canada Ltd. (each 50 per cent); as well as MGM Energy Corp. and 6362 N.W.T. Limited (each 50 per cent).

ConocoPh i l l ips wa s t he secondhighest bidder with a commitment of $66.71 million for an 87,495-hectare parcel adjoining Husky’s parcel on the west, while the Imperial/ExxonMobil joint venture bid $21.5 million each for two parcels totalling 179,480 hectares.

Two a dj a c e nt p a r c e l s t o t a l l i n g 175,065 hectares southwest of Norman We l l s we nt to She l l for a tot a l of $36.39 million.

MGM and its partner acquired three exploration licences totalling 254,000 gross hectares for a total work commitment of $5 million. MGM is the operator of all land parcels.

A l l C e n t r a l M a c k e n z i e Va l l e y e x plor at ion l ice nce s compr i se t wo consecutive periods of five and four years each. A company is required to

drill one exploratory well deep enough to evaluate a prospective horizon as a condition to obtaining tenure to the second period.

The lands acquired by MGM, along with its existing exploration licence EL 454, are prospective for multiple D e von i a n-age d sh a le pl ay s, wh ic h the company believes are liquids-rich at a depth of 750 –2,500 metres, and Paleozoic structural plays. These plays are located within 10 to 30 kilometres of existing oil pipeline infrastructure.

MGM, a long w it h its pa r t ners, w i l l begin developing a program to evaluate the prospects.

In 2007, Husky (75 per cent) and I nte r n at ion a l F r ont ie r R e s ou r c e s Corporation (25 per cent) bid $4.89 million in work expenditures to acquire EL443 farther south.

In 2004, Husky was part of a joint venture (29.48 per cent working interest) with Northrock Resources Ltd. (32.5 per cent interest), which bid work commitments of $24.8 million for a 90,632-hectare parcel (EL423) approximately 90 kilometres south of Norman Wells. Other partners were

EOG Resources Canada Inc. (26.4 per cent), Pacific Rodera Energy Inc. (6.63 per cent) and International Frontier Resources (five per cent).

In 2008, Husky as operator (75 per cent work i ng i nte r e st) d r i l l e d t h e D a h a d i n n i B -20 wel l on t he E L 423 l icence. T h e w e l l w a s d r i l l e d t o a t o t a l d e p t h o f 2 ,42 0 m e t r e s , a n d wa s logged a nd aba ndoned a s a d r y hole. T he wel l f ul f i l led t he work com m it ment on t he E L 423 e x plorat ion l icence a nd e x tended t he ter m f or a s e c on d p e r io d of f ou r y e a r s .

I n 2 010, it su r r e nde r e d t he pa r ce l, ac c or d i n g to t he Nor t he r n O i l a nd Gas Direc torate a n nua l repor t.

The partners picked up the additional land af ter t he Summit Creek discovery. Last fall, Husky re-entered and worked over t he Summit Creek wel l, accordi ng to t he Oi l a nd Gas Directorate’s 2010 annual report.

In early 2010, Explor Geophysical Ltd. conduc ted a non- e xc lusive 2-D seismic program (Brackett Lake sur vey) in the Tulita District of Sahtu, acquiring 60 kilometres of data.

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AUGUST 2011 • OIL & GAS INQUIRER

Central Canada

Canada losing millions due to lack of global market

Photo: Andrea Lorenz

By Lynda Harrison

Peter Tertzakian says Canada is losing $50 million a day by not having more markets for its oil.

Canada is missing out on millions of dollars a day by not trading its oil and natural gas on the global market, a recent economic conference in Calgary heard.

North American oil is trading at a big discount relative to global prices, said Peter Tertzakian, chief energy economist and managing director for ARC Financial Corp.

“Canada needs to get in the game even quicker than Canada thinks it needs to get in the game,” said Tertzakian.

Historically, Canada’s oil has traded at a premium to par with Brent oil and in the last year has been declining so that the “haircut” Canada’s industry is realizing now is about $20 a barrel, he said. That discount, multiplied by the 2.5 million barrels a day Canada exports to the United States, equals $50 million in lost revenue. The royalties on that, based on a rough estimate of 20 per cent, equals $10 million per day, he told the University of Calgary’s Haskayne School of Business conference, entitled Commodities, the Economy and Money.

The same applies for natural gas—“the fuel of the future”—which Asian Pacific markets are demanding and paying more for, he said. The Japanese, for instance,

are paying $12 to $13 per million British thermal units, while North America pays $4 per million British thermal units.

“I’ll do the math for you: we’re probably losing $30 million to $40 million a day on the gas side.”

Australia is trading with the Asian market, but Canada can compete, he said.

“I think it’s time and I think there’s a sense of urgency to it.”

Tertzakian also suggested that in the interest of energy self-sufficiency, future prosperity and national secur­ it y Canada should build an oil pipeline from west to east. Eastern Canada imports 800,000 barrels per day of oil from Nigeria, Venezuela and the North Sea, and pays full price while western Canada sells it at a discount. “W hat sense does that make?”

He believes China’s demand growth for oil will start to moderate in 2015 as the countr y diversifies its energ y sou rce s a nd become s more energ y efficient, but right now all eyes are on China. It’s the number one country to watch in oil markets because that’s where the bulk of new demand growth

is, and this puts Canada in a difficult spot, he said.

“That’s because 80 per cent of our revenues from selling oil and gas right now come from oil so we have a concentration risk here, and if anything happens to the Chinese economy, the price of oil is going to go down and that will affect us very directly here in Canada.”

He said the biggest impediment to wider exporting of Canada’s oil and gas is its citizens’ perception of the im­p ortance of the industry.

Judged by product sales, oil and gas is Canada’s largest industr y, he said, noting Canadian industry revenue estimates for 2011, including $115 billion in the oil and gas industr y, $65 billion in the automobile manufacturing industr y, $10 billion in forestr y and logging, $8 billion in wheat and barley, and $1 billion in uranium.

Dema nd for oi l is stag nat i ng or declining in Canada and the United States while production is rising, so prices will fall, predicted Tertzakian.

Canada is now increasingly producing more oil (3.3 million barrels per day and the world’s sixth-largest producer) than natural gas (15.5 billion cubic feet per day and the third-largest producer in the world) and is exporting 2.5 million barrels of oil per day.

The latest data puts Canada as the world’s third-largest expor ter of oil after Saudi Arabia and Russia, having recently pushed aside Iran thanks to oilsands growth, said Tertzakian.

“Whatever metric you take us on, whether it ’s dollars, volume, reser ve size, whatever, we are world-class, but we are the only country of this group that does not export beyond one country, and that is the United States. That has worked for us because those 1950s Chevrolets and Buicks continue to proliferate to the point where there’s now 230-some million vehicles on the road [in the United States] per day and the traffic jams, and the culture of driving has perpetuated the need for more and more oil.”

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AUGUST 2011 • OIL & GAS INQUIRER

East Coast

Nova Scotia triples offshore resource estimate

Photo: Joey Podlubny

By Pat Roche

There's plenty of petroleum to be found offshore Nova Scotia, according to its government.

Nova Scotia has completed a two-year, $15-million study that provides reasons exploration wells drilled off the province’s coasts in recent years have been largely unsuccessful.

The play fairway analysis was designed to identify key hydrocarbon-bearing fairways and the petroleum play types that may exist in these fairways.

A final report based on this massive geological mapping effort will be posted to a website for free download, said Sandy MacMullin, director of petroleum resources with Nova Scotia’s department of energy.

The detailed analysis also led to a ­tripling in the province’s estimate of offshore resource potential to 120 trillion cubic feet of natural gas and eight billion barrels of oil. MacMullin cautioned these are unrisked estimates of in-place resource potential.

After more than a decade of only gas production, most people probably see offshore Nova Scotia as a gas province.

The presence of oil, however, was proven by the Cohasset-Panuke project, which yielded 44 million barrels of light, sweet crude by the time production ended in late 1999.

“So we’ve identified and explained why that oil is there, and where some oil potential actually remains in the Sable

area as well as northeast of the Sable area,” MacMullin said.

He said the play fairway analysis suggests the immediate Sable Island area and areas to the south, southeast and northeast of Sable are largely gas prone, while the regions to the southwest of Sable Island are largely oil prone.

Meanwhile, MacMullin said the dry-hole explanations vary with individual wells. For example, new seismic imaging shows that a structural high southwest of Sable Island drilled about a quarter century ago was in fact an erosional feature—not a structure at all.

“But it would have appeared as a high back then with the quality of the seismic that companies had back then. And a lot of companies drilled these highs,” he said.

More recently, about six deepwater wells were drilled off the province’s coast in the past decade. One of these—Annapolis G-24—found gas, but not enough to warrant testing. The rest were dry.

Deepwater exploration targeted tur­ bidites—sediments deposited by turbidity currents and characterized by well-developed primary structures.

But the geological analysis suggests the features seen on seismic were the ancient shelf slope edge—rather than the bottom of a slope feature where the turbidite would have amassed.

“When we did some reprocessing of our data, it became more obvious why certain of these deepwater plays failed. That wouldn’t have been obvious when the seismic was analyzed, and before the wells were drilled back five, six, seven years ago,” MacMullin said.

Geoscientists commissioned by the government to do the analysis had the benefit of hindsight, the advantage of more data than any individual company would have had when deciding to drill—including data from the wells that were subsequently drilled—and insights gleaned from reprocessing and reinterpreting seismic data.

The goal is to put the province back on the course it set more than two decades ago when its first offshore project was planned.

Nova Scotia had the distinction of hosting Canada’s first offshore hydrocarbon production when Cohasset-Panuke went on stream in 1992. That was followed by the Sable gas project in 1999. Completion of the Maritimes & Northeast Pipeline— which ships Sable gas to markets in Atlantic Canada and New England— sparked a flurry of exploration drilling early last decade.

But Nova Scotia’s 800-kilometre-by200-kilometre offshore area has since fallen on hard times.

Early last decade there were nearly 60 exploration licences in the waters managed by the Canada-Nova Scotia Offshore Petroleum Board. Today there are only four—all held by small companies that lack the wherewithal to drill unless they find big partners.

Without new exploration, there won’t be any new production to replace the maturing Sable project and the smallish Deep Panuke project, which is slated to flow first gas before year’s end. The province’s last call for offshore exploration bids—which was on lands nominated in the Sable Island area in the 2009-10 fiscal year—attracted no bids.

After more than four decades of drilling, the Nova Scotia seabed remains thinly explored—even by offshore standards.

Since 1967, only 207 wells have been drilled compared to more than 15,000 in the Gulf of Mexico.

OIL & GAS INQUIRER • AUGUST 2011

77

East Coast

N.B. tightens natural gas development rules The New Brunswick government’s natural gas steering committee has announced stronger requirements for natural gas development to better protect and inform residents.

“The possible expansion of the natural gas industry is a great opportunity for our province in terms of potential jobs and other economic benefits,” said Natural Resources Minister Bruce Northrup, who chairs the steering committee.

“If this industry is to take root and grow, we are going to ensure it is done in a careful and responsible manner that benefits all New Brunswickers.”

Under the new requirements, oil and natural gas companies that want to engage in exploration, development and production will have to conduct baseline testing on all potable water wells within a minimum distance of 200 metres of seismic testing and 500 metres of oil or gas drilling before operations can begin.

They will also have to provide full disclosure of all proposed, and actual, contents of all fluids and chemicals used in the hydraulic fracturing process and establish a security bond to protect property owners from industrial accidents, including drinking water contamination or loss, that places the burden of proof on industry.

The provincial government has also committed to develop a formula so land­owners and nearby communities can share in the financial benefits of the natural gas industry.

“Given that this may be the most significant economic opportunity for our province in a generation, we are moving decisively to put in place the necessary requirements to better protect New Brunswickers while allowing exploration to continue,” said Energy Minister Craig Leonard.

“While no one can yet say how viable our natural gas reserves may be, the government is committed to laying the groundwork now so we will be ready if it is proven that we have commercially viable reserves.”

Environment Minister Margaret-Ann Blaney said the new requirements are part of the natural gas action plan being developed under the direction of the committee.

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mechanisms to protect the environment and residents of New Brunswick.”

Blaney said the government will continue to develop its regulatory framework. She said she hoped to gain additional insights at a provincial natural gas forum at which about 40 participants, representing a broad cross-­ section of New Brunswickers, have been invited to take part in a dialogue on what natural gas development could mean for the province.

“We are still working on how we will need to enhance our current policies and regulations if the natural gas industry takes off,” said Northrup. “The provincial forum will help us make these sorts of decisions.”

Blaney said the forum is part of the provincial government’s wider commitment to ongoing citizen engagement. She said the government has made a commitment to support the responsible expansion of the natural gas sector while ensuring the safety and security of New Brunswickers and groundwater supplies.

“As we have said all along, if we cannot do this in a safe and responsible manner while protecting our drinking water, we won’t do it at all,” she said.

— DAILY OIL BULLETIN

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International

Canadian service companies push frac technology overseas

Photo: Joey Podlubny

By Graham Chandler

Pressure pumping companies are finding work around the world.

As has happened many times in the past, technologies successfully implemented in western Canada’s oil and gas fields are spreading across the globe and for specialists in multistage completions and fracking, international demand is growing rapidly.

Companies such as Packers Plus Energy Services Inc., Trican Well Service Ltd. and Calfrac Well Services Ltd. are travelling a lot these days.

It was five years ago and multistage horizontal fracturing had just been perfected in the Barnett shale of northeastern Texas. Calgary-based service company Packers Plus, just five years old at the time, was pretty content to grow with this new technology in North America. Then it teamed up with leading oilfield services company Schlumberger Limited and foreign doors opened.

“We didn’t expect it to happen as quickly as it did,” says Dan Themig, president of Packers Plus. “Schlumberger caught on to the concept, and we caught on with some wells.”

“There is without a doubt interest in taking this technology abroad,” says

Mark Salkeld, president of the Petroleum Services Association of Canada. He says several countries are hungry for it, attracting Canadian service companies.

Packers’ Themig couldn’t agree more.

He recalls how quickly initial forays overseas bore fruit. “At the time we were on a good growth path in North America, but once we made our business arrangement with Schlumberger I took off on the road: France, Algeria, the Middle East, China, Italy, Saudi Arabia and Bahrain. The early adopters were West Africa, Saudi Aramco and Kuwait Oil [Company], and shortly after that we started working in Argentina and Mexico. We have since branched out to Romania in the Black Sea and are now working in China and Russia.”

He sees Saudi Arabia as a particularly exciting market. “One area is their Kuf gas field,” he says. “A lot of people don’t realize it but the Saudis are short on natural gas and they need it to run their power plants and desalinization.”

The country recently announced plans to boost drilling in order to maintain its 12.5-million-barrel-per-day production capacity. Themig talks about helping

Saudi Aramco, using Canadian fracking technology in older oilfields.

“We’ve kind of redefined productive rock in some of their formations,” he says.

“We did a well for Aramco where we ran a six-stage job in what had previously been considered unproductive rock—and the well came in at 12,000 barrels per day.”

Success stories like that are being repeated in many basins around the world and attracting a lot of attention.

“Another one which is scary and exciting at the same time is China. We’ve got ongoing work in three basins there that have been tremendously successful. And LUKOIL [Oil Company] out of Russia has just successfully installed and fracked five wells and are now back with some sizable packages in the range of 50 wells,” Themig said.

It was potential in Russia that initially attracted several Canadian service com­ panies to market fracking overseas.

Dale Dusterhoff, chief executive officer of Trican Well Service, recalls his company’s first foreign ventures.

“We entered the fracturing business in 1998 here,” he says. “Then in 2000 we entered Russia, because that was where we could apply our model of introducing our technology. Russia is a heavy fracturing market.”

At the time, they were all vertical fractures, but then in the mid-2000s the Canadian market started to switch over to some horizontal fracturing so that’s where they branched out.

“We entered the U.S. in 2007 [Barnett shale] and that was all horizontal multistage fracturing.”

Trican reported Russian revenues of $259 million last year with a further $64.7 million in revenues from that country in the first quarter of this year.

T he mid-2000s is when another market leader in horizontal multistage fracturing, Calfrac Well Services, started operations in Russia.

“In the early part of 2000 we saw a huge transformation beginning in North America,” recalls Tom Medvedic, senior vice-president, corporate development.

OIL & GAS INQUIRER • AUGUST 2011

81

International

But Calfrac knew that penetrating international markets would take time.

“You need to establish a base of operations around reputation, relationships with clients in each area and leverage off those, to broaden them, expand them.”

Calfrac saw Russia as the third-largest fracturing market after the United States and Canada so it initiated operations there in 2005.

The company’s Russian revenues were $76.6 million last year with a further ­$26.3 million booked in the first quarter of 2011.

Then things took off internationally: “Mexico in 2007, Argentina in 2008 and we will be in Colombia later this year,” he says.

Latin A merican revenues in 2010 reached $50.57 million.

The company’s international growth platform is based on North American technology rapidly gaining broad application in foreign jurisdictions. And it’s just a start: “The horizontal side of things is just beginning to catch hold internationally,” he says.

Fracking expertise marketed overseas hasn’t been limited to the shale boom as many countries begin evaluating their shale potential with the new technologies.

“There are actually a variety of formations,” says Packers’ Themig. “The stuff in

Saudi Arabia, for example, is carbonates.

In China, there are super tight gas but also some shale plays, and in Russia it is usually tight rock, sandstone or sandstone shales more like the Montney.”

Other areas—the Norwegian and British sectors of the North Sea, for instance—are in chalk formations.

“What we are seeing is the technology being applied in a huge variety of reservoirs,” says Themig. “Some people think our technology is applicable just to shales and supertight rocks, but we can talk about using multistage fracking in prolific reservoirs.”

U.S. Midwest oilsands choke point by 2015, says IHS CERA The U.S. Midwest won’t be able to take any additional volumes of Canadian oilsands production as early as 2015, five years earlier than estimated by a U.S. government department, due to limited refinery capacity in that region, says IHS CERA in a report released in late June.

The U.S. Department of State, relying on a third-party report, estimated in its draft environmental impact statement on the proposed Keystone pipeline expansion that Canadian oilsands production won’t be affected until 2020 should the Keystone pipeline not proceed. But it based that conclusion on when oilsands production would fill current pipeline capacity, not refinery capacity in the Midwest region.

IHS CERA released its special report on the role of Canadian oilsands in the U.S. market as the comment period on the draft environment­al report expired.

Considering the potential for oilsands production to double in the next decade, “by 2015, oilsands dilbit exports will likely exceed the Midwest refiners’ ability to process the heavy crude,” the report says.

While it is possible that some Midwest refiners could further upgrade their refineries, IHS CERA noted the growing supplies of light oil production coming from North Dakota and Montana, which has risen from less than 10,000 barrels a day in 2003 to a projected 400,000 barrels per day this year. Volumes could reach 800,000 barrels a day in the 2016-18 period and Oklahoma and Kansas output is rising too, all of which raises the question of why refiners would embark on costly expansions to use heavier oil from Canada rather than use growing volumes of U.S. domestic light oil.

The report challenges another assumption in the draft environmental impact statement that assumes that if Keystone is not approved, the U.S. Gulf Coast refiners would replace the planned additional Canadian oilsands imports with imports of lighter Middle Eastern oil supplies.

IHS CERA notes that the Gulf Coast refiners have invested large sums to process heavier oils and the region is already home to 30 per cent of the world’s coking capacity. Refiners are not likely to leave that capacity idle and would likely source heavy oils from current suppliers in Brazil, Colombia, Mexico and Venezuela.

“Therefore, when considering the incremental emissions resulting from substituting Canadian oilsands supply for other crudes, heavy crude oils should be assumed to be the primary substitute.”

— DAILY OIL BULLETIN

Enbridge hunting for international growth Enbridge Inc. is once again actively on the outlook for international investments after earlier selling off international assets at a premium, to redeploy the proceeds in North American projects, the company said in May. “There are some good opportunities in South America as a result of new develop­m ents in Colombia,” Patrick Daniel, president and chief executive officer, said in a conference call to discuss first-quarter results.

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AUGUST 2011 • OIL & GAS INQUIRER

“We were very happy with our investment in Colombia and the way in which we were treated there,” he said.

Daniel later told repor ters t hat Enbridge is looking at greenfield oil pipeline opportunities in Colombia to move to export points, including owning and operating an oil terminal.

E nbr idge i s a l so look i ng at t he inter nat iona l ma rket f rom t he perspective of energy moving into China, India and other developing countries

in t he for m of liquef ied nat ura l gas (LNG) projects.

“Not that we are in the LNG business, but there are gas pipelines associated with LNG projects that might work for us,” he said.

In Australia, Enbridge is eyeing pipelines that would transport natural gas to liquefaction points where LNG is exported, primarily to southeast Asian markets, Daniel told reporters.

— DAILY OIL BULLETIN

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TOOLS

Roto-Launch OF THE TRADE Pig Caddy A LOOK AT NEW TECHNOLOGIES

Describe the Roto-Launch Pig Caddy automatic launcher and multi-pig receiver system.

Roto-Launch Inc. has been providing “Next Generation” automated and conventional pigging equipment to the industry since 2001. In liquidrich gas fields, condensed liquids accumulate in the low points of the pipelines that make up the gathering system. If left unchecked, these liquids can cause a multitude of operational problems such as slugging, and the formation of hydrates, which can block a pipeline. These liquids need to be routinely removed by sending an operator to insert a utility pig into the flow using a launcher on the upstream end of the pipeline. Flow takes the pig, along with the liquids, to the downstream end of the pipeline where it is caught in a receiver and then removed by an operator. In some of these fields the volume of liquids produced demands that some pipelines be pigged once a day or more, making it very hard for operators to maintain the proper pigging frequency. A single gas-gathering system can consist of a network of pipelines that number in the hundreds, meaning that most major producers are managing thousands of these pig traps. The Pig Caddy Automatic Launcher and Multi-Pig Receiver were developed to help producers maintain aggressive pigging schedules while reducing operator involvement. The Pig Caddy Automatic Launcher allows the operator to pre-load and store up to seven pigs that can be launched remotely on demand and at predetermined intervals. The Pig Caddy Multi-Pig Receiver is designed to safely catch these pigs at the other end of the pipeline where the operator can easily unload the pigs and return them to the launcher.

How does the system work?

The Pig Caddy Launcher is a very simple gravityfed system mounted above the pipeline, and like any launcher can be isolated and de-pressured for re-loading. Once loaded with seven pigs the launcher is pressurized and put into service.

A wireless signal is sent to the launcher, which energizes a solenoid valve that controls a pneumatic actuator mounted on the launcher. The actuator advances the pig delivery system inside the launcher and drops the lead pig into the flow where it is carried to the receiver. The Pig

Caddy Multi-Pig Receiver is fitted with a drawbar internally which collects all the pigs and keeps them inline and off the bottom, while letting the li­q uids sweep through. When the receiver is full, it is de-pressured, opened and easily unloaded by extracting the drawbar. The Pig Caddy System is designed to fit existing infrastructure and accommodates the use of smart pigs. All Pig Caddy equipment is manufactured to the highest industry standards and is easy to maintain.

What benefits or advantages does the Pig Caddy offer and how is it better than competitive products?

The obvious benefits of automated pigging are that it significantly reduces operating costs and improves operator safety. However, automated pigging does offer much more. It allows the producer to pig more aggressively, which can significantly increase productivity and production from your gathering system while reducing operator involvement. The ability to pig aggressively mitigates liquid-related problems like slugging, hydrates, freeze-ups and corrosion. Liquid accumulation can restrict production and even cause a shutdown. Clearing accumulated liquids aggressively improves the overall efficiency of the gathering system, which increases production and also helps maintain pipeline integrity.

The feature that sets Pig Caddy apart is that there is no need to automate any valves in order to send or receive a pig. The launcher is designed to be self-draining to prevent freezing and spillage. The receiver is a flow-through design that traps pigs, not liquids.

Where is the Pig Caddy at work and how is it performing in the field?

There are over 100 Pig Caddy and previous generation Roto-Launch systems operating in gas fields throughout western Canada. Many major producers are using this technology to help manage the operation of their gathering systems including Encana Corporation, Apache Corporation, ConocoPhillips Canada, BP Canada plc, Canadian Natural Resources Limited, Murphy Oil Corporation and others. One major producer automated an entire gathering system using Pig Caddy in the Montney Play in northeastern British Columbia, a development called the Noel Field.

The current operator, Apache, is operating over 45 Pig Caddy Launchers and Receivers in this field alone. The reliability of this technology has been proven over time. Some of our automated launchers have been launching pigs every day for over 10 years and some launch as many as five pigs a day. Plant and field operators will testify that Pig Caddy takes the hassle out of pigging.

Answered by Howard Venius, VP Sales & Marketing, Roto Launch

OIL & GAS INQUIRER • AUGUST 2011

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