Oil & Gas Inquirer December 2011

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Despite wet spring,

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Saskatchewan’s oil industry firing on all cylinders

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2011

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Technology

DECEMBER 2011 • OIL & GAS INQUIRER

Flat Out

By Darrell Stonehouse Despite wet spring, Saskatchewan's oil industry firing on all cylinders

Technology Stars

By Jacqueline Louie, James Mahony, Elsie Ross, Maurice Smith & Darrell Stonehouse Our annual look at the best in new exploration, drilling, completion, production and HSE technologies.

R E G I O N A L

37

N E W S

British Columbia

57

• Fracturing sand mines needed

• Juniors squeezed by technological advances, competition from former

By Lynda Harrison

41

Whitecourt

45

trusts

Northwestern Alberta • Clean energy project launched at

By Pat Roche

61

carbon capture project

• Cenovus cutting costs, lessening

By Lynda Harrison

49

By Pat Roche

65

By Pat Roche

Central Canada • Suncor CEO calls for national energy

Central Alberta • Why CO2 EOR never took off in Alberta

Saskatchewan • Aquistore Project plans first well for

Northeastern Alberta environmental footprint

Southern Alberta

conversation

67

International • Tight oil resource huge, says North Dakota researcher

I N

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Statistics at a Glance

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• Timing the market: A look at the factors to consider when deciding when to sell

By Adam Mallon

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OIL & GAS INQUIRER • DECEMBER 2011

9

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Editor’s Note Vol. 23 No. 10 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com

Darrell Stonehouse | dstonehouse@junewarren-nickles.com

Stranded Oil

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News that the U.S. State Department is delaying a decision on whether to give the Keystone XL Pipeline approval until it comes up with an alternate route avoiding groundwater supplies beneath Nebraska has angered many in the oil industry on both sides of the border.

South of the border, President Barack Obama is being accused of making a political decision not in the best interests of the country. The argument goes that the delay is a cynical attempt at pandering to environmental extremists to shore up votes prior to next year’s election at the cost of energy security and tens of thousands of pipeline-related jobs.

There is, of course, more to it than that. Right now the bottleneck in the U.S. crude supply chain at Cushing, Okla., that the Keystone XL would alleviate is providing significant short-term benefits to the U.S. economy. The price differential between West Texas Intermediate and world prices like Brent Crude has been as wide as $25 per barrel in the past year, cutting energy prices at a time when the U.S. economy needs all the help it can get.

There is also a belief among some in the U.S. industry that what’s needed is not more pipeline capacity from Canada to the Gulf Coast but instead improved transportation infrastructure and changed oil flows between Oklahoma and the Gulf Coast. They point out that with the Keystone and Alberta Clipper pipelines coming on stream in 2010 there is no shortage of capacity upstream of Cushing. Also, they add that foreign oil is still being shipped north from the Gulf Coast to Cushing. Reversing those pipelines could go a long way in reducing the crude oil glut in the Midwest. The recently proposed Wrangler pipeline from Cushing to Texas refineries could also break the bottleneck.

Here in Alberta, the Keystone XL delay came as a surprise. Just months ago, Prime Minister Harper said approval of the pipeline was a “no-brainer.” There was widespread confidence that the arguments saying the pipeline would relieve reliance on foreign oil from geopolitical hot spots and provide desperately needed jobs would win the day. Confidence remains that Keystone XL will still be built, but industry eyes are quickly shifting westward towards markets in Asia Pacific.

Approval of Enbridge’s Gateway Project running from the Hardisty, Alta., oil hub to the B.C. coast is now on the front burner, as is a doubling of capacity of Kinder Morgan’s Trans Mountain pipeline. But both export expansions are expected to meet stiff opposition from First Nations and environmentalists as they move through the approval process.

The stakes in this great pipeline debate couldn’t be higher for Canadians, and Albertans in particular. Oilsands production is rapidly cranking up, with predicted flows of three million barrels per day by 2020. Total Canadian production is expected to reach 4.7 million barrels per day by 2025, with 3.7 million of those barrels coming from northeastern Alberta.

But this all hinges on having market access. The federal government needs to step up to the plate and deal with this issue now. If the United States doesn’t need or want any more Canadian oil, other markets need to be cultivated. Otherwise, we’re going to see the world’s third-largest reserves stranded for a generation.

N E X T

I S S U E

GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2011 1080554 Glacier Media Inc. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240.

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

January/February 2012 In our January/February issue, Oil & Gas Inquirer looks at field activity in northwestern Alberta and the progress of enhanced oil recovery schemes across western Canada.

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OIL & GAS INQUIRER • DECEMBER 2011

11

Stats

AT A GLANCE Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

MONTH

OIL

GAS

OTHER

T O TA L

MONTH

OIL

GAS

D RY

T O TA L

Oct 2010 Nov 2010 Dec 2010

678 868 1,061

581 989 559

39 75 78

18 165 238

1,316 2,097 1,936

453 774 1,846

Jan 2011 Feb 2011 Mar 2011

409 723 1,069

201 378 1,081

33 38 64

17 99 164

660 1,238 2,378

112 100 97

1,003 433 245

Apr 2011 Jun 2011 Jul 2011

618 428 298

509 197 97

46 12 15

81 183 88

1,254 820 498

93 146 19

728 1,531 904

Aug 2011 Sept 2011 Oct 2011

922 1,448 1,153

262 445 321

28 24 20

80 155 49

1,292 2,072 1,543

Oct 2010 Nov 2010 Dec 2010

404 579 676

460 847 403

46 169 294

910 1,595 1,373

Jan 2011 Feb 2011 Mar 2011

226 353 650

145 294 974

82 127 222

Apr 2011 Jun 2011 Jul 2011

419 209 105

472 124 43

Aug 2011 Sept 2011 Oct 2011

452 1,028 626

183 357 259

Wells Drilled In British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS DRILLED

C U M U L AT I V E *

MONTH

OIL

GAS

OTHER

TOTAL

Oct 2010 Nov 2010 Dec 2010

42 43 49

608 651 700

Oct 2010 Nov 2010 Dec 2010

201 217 340

12 3 2

11 64 11

224 284 353

Jan 2011 Feb 2011 Mar 2011

62 69 55

62 131 186

Jan 2011 Feb 2011 Mar 2011

136 321 316

4 6 8

3 7 4

143 334 328

Apr 2011 Jun 2011 Jul 2011

41 54 56

172 419 479

Apr 2011 Jun 2011 Jul 2011

183 217 185

11 25 5

11 89 3

205 331 193

Aug 2011 Sept 2011 Oct 2011

40 92 35

519 611 646

Aug 2011 Sept 2011 Oct 2011

413 352 457

2 4 29

13 29 46

428 385 532

*From year toto date * from year date

561266 V.J. Pamensky Canada Inc 1/4h · tqc Stats 12

SERVICE

DECEMBER 2011 • OIL & GAS INQUIRER

FAST NUMBERS

15,100

4,650

Number of wells PSAC is forecasting for 2012.

Number of wells expected to be

drilled in Saskatchewan in 2012.

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, November 11, 2011 Source: Rig Locator

Alberta, October 2011 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

Western Canada

AC T I V E

OIL WELLS

GAS WELLS

(Per cent of total)

Alberta

Oct 11

Oct 10

Oct 11

Oct 10

Alberta

354

206

563

63%

Northwestern Alberta

150

68

83

79

British Columbia

51

25

76

67%

Northeastern Alberta

90

92

1

6

Manitoba

21

3

24

88%

Central Alberta

331

185

63

33

Saskatchewan

102

32

134

76%

Southern Alberta

55

67

112

345

WC Totals

528

269

797

66%

TOTAL

626

412

463

259

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada, November 11, 2011 Source: Rig Locator

Alberta, October 2011 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

AC T I V E

Western Canada Alberta

398

259

657

61%

British Columbia

20

11

31

65%

Manitoba

19

3

22

86%

Saskatchewan

148

45

193

77%

WC Totals

585

318

903

65%

QC

1

-

1

100%

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

BITUMEN WELLS

Alberta

Oct 11

Oct 10

Oct 11

Oct 10

Northwestern Alberta

0

5

11

2

Northeastern Alberta

0

0

90

62

Central Alberta

33

11

141

82

Southern Alberta

31

32

0

0

TOTAL

64

48

242

146

812947 CARES Ltd 1/4h · tqc OIL & GAS INQUIRER • DECEMBER 2011

13

Feature

Flat out Photo: photos.com

By Darrell Stonehouse

14

DECEMBER 2011 • OIL & GAS INQUIRER

Feature

Despite wet spring, Saskatchewan oil industry firing on all cylinders The numbers tell the story.

Despite a wet spring keeping crews out of the field, in the first nine months of 2011, 2,383 wells were completed in Saskatchewan, a 38 per cent hike in rig releases compared to 1,839 wells last year.

The total includes 282 outposts and a total of 408 exploratory wells.

And next year promises to be even better, according to the Petroleum Services Association of Canada's 2012 drilling forecast released in early November. The forecast calls for 4,650 wells to be drilled in Saskatchewan next year, nearly a third of all wells to be drilled in western Canada.

The figure represents a 15 per cent increase over 2011.

Saskatchewan is in the midst of an oildrilling boom, and it is just beginning to pick up steam.

The provincial government, which has provided a stable regulatory and royalty regime to encourage investment, gets part of the credit. The province’s effort on this front was recently recognized by oil executives and managers polled by the Fraser

Institute as the best in Canada and 11th best in the world.

“Saskatchewan understands the petroleum industry and how important it is to maintaining a prosperous economy,” says Gerry Angevine, Fraser Institute senior economist and co-author of the report.

“Industry executives stress that long-term energy policy stability, low royalties and clear regulatory frameworks are their top priorities when choosing where to invest.

Saskatchewan offers investors confidence in each of these areas.”

But most of the credit for the boom lies in technological advances in horizontal drilling and multistage fracturing that have opened up Saskatchewan’s massive tight oil resource to exploitation. Saskatchewan had initial oil in place of around 46 billion barrels with around 13 per cent of that believed recoverable with existing and future technologies. Its current reserve base is around 1.2 billion barrels, but that is increasing rapidly with new technologies opening up three large resource plays with combined oil in place of around 12 billion barrels.

OIL & GAS INQUIRER • DECEMBER 2011

15

Feature

The Bakken The Bakken play in the southeast is leading industry activity in the province.

Over the last five years PetroBakken Energy Ltd. and Crescent Point Energy Corp. have consolidated much of the play through corporate takeovers and land sales. Crescent Point has done an amazing 140 acquisitions in the Bakken and Lower Shaunavon.

Crescent Point president and chief executive officer Scott Saxberg told the recent Canadian Association of Petroleum Producers investment symposium that the company now has over 1,000 net sections of land in the Bakken and over 3,800 drilling locations. Saxberg said technology in the play continues to evolve.

16

DECEMBER 2011 • OIL & GAS INQUIRER

“In the last six months alone we’ve gone from cemented liners using 10–20 stages with larger fracs, to now dialing it in more and going with 25-stage, cemented-liner, smaller-sized fracs,” he explained. “We’re penetrating more rock and seeing significant improvements in productivity.”

The change in technology is radically altering the province’s drilling sector.

Saskatchewan set a record in drilling horizontal wells in 2010, with 1,531 wells drilled. That’s an 88 per cent increase over the figure for 2009 and a 13 per cent increase over the previous record set in 2008.

Horizontal wells accounted for 56 per cent of the 2,730 oil wells drilled in Saskatchewan in 2010. In the first eight months this year, 1,211 horizontal holes were sunk compared

Photo: Joey Podlubny

A very wet spring slowed drilling in southeastern Saskatchewan, but activity has since picked up with 2,383 wells drilled in the province in the first nine months of the year.

to 941 wells in the first eight months of 2010, an increase of 29 per cent.

Industry continues refining its stimulation technologies to increase fracture density and expand the boundaries of the Bakken play as well. Packers Plus Energy Services Inc. released its QuickFRAC technology in May of this year. The new technology is capable of fracturing 60 stages downhole while only pumping 15 treatments at surface. Using limited-entry diversion techniques and the company’s proprietary technology, the system allows a producer to fracture several isolated stages at one time through a process known as batch fracturing. Aside from cutting costs, the new technology increases fracture density in the reservoir.

Feature

Bakken Oil in Place: Over 25 billion barrels Oil in Place/Section: 4.5 million barrels Horizontal Incremental Recovery: 8–18% Depth: 1,600 metres Porosity: 10 Permeability: 0.1–1 millidarcies Net Pay: 4 metres Average API: 42

Lower Shaunavon Oil in Place: 4.3 billion barrels Oil in Place/Section: 5 million–10 million barrels Horizontal Incremental Recovery: 8–12% Depth: 1,350 metres Porosity: 18 Permeability: 0.5 millidarcies Net Pay: 5 metres Average API: 23

Viking Oil in Place: 6 billion barrels Oil in Place/Section: 5 million–10 million barrels Horizontal Incremental Recovery: 10–15% Depth: 700 metres Porosity: 23 Permeability: 1–50 millidarcies Net Pay: 6 metres Average API: 38

PetroBakken also announced the first commercial application of CleanTech completion fluid in the Bakken in May. The new fluid allows better control of fracture treatments, enabling the company to avoid breaking out of the pay zone into water zones.

“It’s a process that allows us to carry a lot of sand in our fracture treatments into the reservoir, but we get to deliver it at very low rates and very low pressures— which avoids the breaking out of the formation,” says company president and chief executive officer John Wright.

By maintaining the frac within the Bakken formation, the operator avoids breaking into other zones, which may cause water incursion.

“This allows us to increase the economic practicality of drilling at the peripheral edges of the Bakken play and expands our opportunities,” Wright says.

He said CleanTech is “creating value where before we had written off the potential for the Bakken. And now we’re applying this technology to all of the wells in this region.”

One of the major concerns with the new extended-reach horizontal drilling and multistage fracturing technology was that high decline rates would make wells uneconomic before recovering most of the potential reserves available. In May, Wright cited the 68 per cent increase in reserve bookings for the company’s first six Bakken wells as validation of its technology and play concepts.

Independent evaluators assigned 100,000 barrels of proved-plus-probable oil reserves per well to each of the original six horizontal Bakken wells drilled by the company in 2006. Bookings increased in 2007, 2009 and again last year, when evaluators estimated the ultimate recovery would be 168,000 barrels of oil per well.

“By the way, these are not in any way the best wells we drilled. They’re the first wells we drilled into the Bakken,” Wright says. “But over the last four years, the reserve assignments for these wells has increased 68 per cent without us doing anything to them—just by proving over time the validity of our technology.”

Of the 1.8 billion barrels of discovered petroleum initially in place on the company’s Bakken lands, only five per cent has been booked as proved-plusprobable 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,” Wright adds. “And that’s not only going to increase our ultimate reserves, but it will mitigate the decline rates.”

Lower Shaunavon The Lower Shaunavon medium oil resource play in southwestern Saskatchewan is also booming. Southwestern Saskatchewan had 455 wells rig released in the third quarter alone, up 102 per cent from 225 wells last year.

With more than four billion barrels of original oil in place, the pool is one of the largest oil pools ever discovered in western Canada. Crescent Point Energy has over

450 net sections in the play. Since then, it has been proving up that acreage and turning the massive resource into reserves.

“The Lower Shaunavon is three years behind the Bakken,” says Crescent Point’s Saxberg. “What we’re basically doing is taking the technology and knowledge from the Bakken and applying it there.”

Saxberg says Crescent Point and other players like Cenovus Energy Inc. and Wild Stream Exploration Inc. have had great success in expanding the Lower Shaunavon play and adding to the resource base. Last year, Crescent Point drilled a series of stepout wells in the northern part of the play and added 150 million barrels of oil in place to its resource tally. Crescent Point and Cenovus found by drilling in the heart of the play that what was originally thought were two different fields were actually connected, adding another 150 million barrels.

“In the southern part of the field, we rediscovered an area of the Upper Shaunavon, a tight oil play drilled vertically in the past,” Saxberg says. “Ourselves and Wild Stream have been drilling the pool and we believe there are 700 million barrels of oil in place.

“That’s one billion barrels of oil in total for the three areas,” he adds. “Five or six years ago, this would have been the biggest oilfield discovered in 50 years, so it’s a pretty incredible amount of new oil.”

Crescent Point controls 90 per cent of the Shaunavon play. The company is currently focused on building infrastructure as it prepares to increase drilling in the region. It expects to drill 44 net wells in the Shaunavon area in 2011 and expects to significantly increase drilling to around 100 wells next year following the completion of this year’s infrastructure projects.

The Viking The Viking tight oil play in the Dodsland/ Kindersley area is the third of the major resource plays underway in Saskatchewan.

L ess prol i f ic t ha n t he Ba k ken a nd Shaunavon plays, its lower drilling and completion costs are a significant attraction for developers, as is its four billion barrels of oil in place with only 12 per cent produced.

Junior producer Compass Petroleum Partnership is working the Viking play.

“Our main focus has been in the Dodsland/Kindersley area,” says Bruce Beynon, vice-president of exploration.

“In Lucky Hills, we probably have about OIL & GAS INQUIRER • DECEMBER 2011

17

Feature 21 net sections, largely 100 per cent working interest, on our land base. In the last 13 months, the company has drilled about 25 Viking horizontal wells in the Lucky Hills area.”

Benyon says the Viking is shallow in this part of the basin.

“It’s a shaley reservoir; it occurs at about 700 metres vertical depth,” he says. “We tend to drill 1,500-metre monobore wells.

“We end up on average with about a 600metre horizontal lateral section that we end up then fracking and completing,” Beynon says, adding that in this area, most of the analysis shows 36- or 38-degree API light oil.

“On the royalty side on Crown lands, Saskatchewan has a royalty incentive where royalties are 2.5 per cent on the first essentially 36,000 barrels of oil,” he notes.

“There are very high netbacks given the oil price, low royalties and very reasonable operating costs.”

Beynon adds that operators are able to drill multiple horizontal wells per section, with some having gone to 16 per section.

“We’re only at four wells per section now but definitely looking at developing it on at least eight wells per section,”

he says. “I think the first leg of activity has really stuck close to existing pools and now it’s starting to branch out. In parts of westcentral Saskatchewan, there are townships that have only a couple of penetrations in the entire township. You’re still in a fairway where you’re going to have Viking sands.

You are a bit more on the exploratory side, so is that sand going to be oil saturated or could it be gas saturated or could it be water saturated?

“There’s a bit of an exploratory phase away from these main pools, and obviously those exploratory lands are still available and probably going to be cheaper than land in the hearts of pools.”

Still to come in the Viking are drilling plans from Devon Canada Corporation, which has a huge land base in the area. David Hager, executive vice-president of exploration and production, says the company drilled and completed two wells in the second quarter, one of which had initial production of 90 barrels of oil per day.

The company expects this play to be economic with well costs in the $1 million– $1.2 million per well range, initial production of approximately 40 barrels per day and

1-800-661-1436 © 2011 Meridian Manufacturing group. registered trademarks Used Under License.

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estimated ultimate recovery of 50,000 barrels per well.

“While these results are encouraging, we’re still in the early stages of evaluating the potential on our 900,000 net acre position. If successful, we could have more than 1,000 Viking drilling locations,” Hager says.

Conventional light oil plays While tight oil plays are generating the buzz in Saskatchewan, conventional oil plays are still being developed.

Southeastern Saskatchewan has been the backbone of the province’s conventional light oil industry since the Weyburn field was discovered in the early 1950s. Drilling in the area continues almost 60 years later as producers target known resources and test new play types.

PetroBakken Energy is one of the major players in the conventional Mississippian light oil play in southeastern Saskatchewan with current production of around 5,000 barrels of oil and natural gas liquids per day.

PetroBakken plans on spending $40 million in the area in 2011. It has drilled 17 wells this year, with another 25 planned. It has

ExpEriEncE thE advantagEs of Meridian’s Exclusive Baked on powder coating, heavy duty Built construction, Workmanship and customer service.

Feature over 300 drilling locations identified, with around 950 undeveloped sections of land in the play for future growth.

Typical new wells in the Mississippian/ Jurassic-age light oil pools generate initial production rates between 75 and 200 barrels of oil equivalent per well, says the company. Each well is expected to recover around 80,000 barrels of oil equivalent over its lifespan.

PetroBakken says the big advantage of the conventional play in southeastern Saskatchewan is that it is relatively lowrisk and provides long-life production, high netbacks and steady cash flows. The company sees opportunity in using horizontal wells to down-space within the play to add future production.

NAL Energy Corporation is another believer in southeastern Saskatchewan’s conventional oil resource. In September, NAL said it had four rigs operating targeting Mississippian light oil. The majority of drilling in Saskatchewan has been focused in the greater Hoffer area where 48 (24 net) wells have been drilled since 2010. Of these 48 wells, 45 are currently on production and internal expectations are that production

in the area will grow to over 1,800 barrels of oil per day (gross) by year-end from approximately 200 barrels of oil per day (gross) in 2010.

At Hoffer, results-to-date continue to validate a significant light oil resource in the area, the company said. Individual well outcomes at Hoffer have varied, with initial first-month production averages of 40–300 barrels per day.

the past 12 months. The Mississippian reser voi r does not requ i re f rac t u re stimulation, but efforts are under way to increase production. The company has recently been using underbalanced drilling techniques on a number of wells, whic h have delivered en ha nced initial production results. It has also been testing acid stimulation techniques in the play.

The Mississippian reservoir does not require fracture stimulation, but efforts are underway to increase production.

In 2011, NA L’s drilling program has identified two new pool discoveries in the greater Hoffer area at Neptune and Oungre. These discoveries have validated the play’s potential and added significant additional Mississippian light oil drilling inventory for 2012 and beyond, says the company.

NAL has been testing different drilling techniques in its Hoffer program over

NAL continues to add to its land base in the area with over 11 sections of land acquired adjacent to existing producing acreage. Potential for continuity of the play across the acquired acreage is supported by mapping that reflects the stratigraphic nature of the play, the presence of bypassed pay in several wellbores and observations made from NAL’s proprietary 3-D seismic.

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Feature Construction of a central gathering, treating and water disposal facility at Hoffer is expected to be completed by yearend 2011. Throughput capacity of the facility is designed to be 5,000 barrels per day of oil and water. Once commissioned, operating costs in the area are expected to drop to approximately $6 per barrel of oil equivalent from $10 per barrel at present.

NAL says another important factor in driving interest in conventional oil exploration in southeastern Saskatchewan is the royalty rate on new pool discoveries. In Saskatchewan, royalties of 2.5 per cent are paid on the first 100,000 barrels of oil produced from each well.

Heavy oil

Photo: Joey Podlubny

Heavy oil plays also continue generating interest.

In the Lloydminster/Kindersley area in western Saskatchewan there are an estimated 21 billion barrels of oil in place, with

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production averaging more than 200,000 barrels per day. However, recovery rates are less than 10 per cent.

Baytex Energy Corp. president and chief executive officer Anthony Marino told the Peters & Co. Limited investment symposium in mid-September that there are currently a variety of production techniques in use in heavy oil fields. There’s cold vertical production with sand (CHOPS) and cold horizontal production without sand, which Marino said is becoming quite common. Then there’s waterfloods using both cold and hot water, which have long been the preferred enhanced-recovery techniques.

Marino said steam assisted gravity drainage (SAGD), used in Alberta’s oilsands industry, is gaining a foothold in heavy oil development and has room to grow.

Baytex purchased a SAGD operation at Kerrobert, Sask., in 2009. At the time it was producing 1,000–1,500 barrels per day.

Since then the company has drilled three new SAGD pairs.

Its initial SAGD well pair, which began production late in the third quarter of 2010, continues to exceed 1,000 barrels of oil per day at a cumulative steam-oil ratio of about 2.7.

Cumulative production from this well pair stands at 325,000 barrels after 10 months of production. Two additional SAGD well pairs were drilled during the second quarter. After June 30, one of the new well pairs was put on production at initial rates topping 1,000 barrels per day.

Start-up of the second new well pair is planned for later in the third quarter.

Baytex has identified at least nine further SAGD well pair locations at Kerrobert and plans to drill four additional stratigraphic test wells later this year to optimize the placement of these future well pairs. The company is also doing eng ineer ing and procurement work to increase the steam plant capacit y in 2012.

A drilling rig at work in southeastern Saskatchewan. PSAC expects around 4,600 wells to be drilled in the province next year.

DECEMBER 2011 • OIL & GAS INQUIRER

Feature

Photo: Joey Podlubny

Husk y Energ y Inc. plans on doubling its thermal heavy oil production in Saskatchewan to about 40,000 barrels per day in roughly five years, it reported in July.

“Our current thermal production is in the range of about 18,000–20,000 barrels per day today,” Rob Peabody, Husky’s chief operating officer, told analysts after the company released second-quarter results. “With these projects coming on stream over the next five years, we’re looking to increase our thermal production into the range of about 40,000 barrels a day.”

Husky’s total heavy oil production is roughly 100,000 barrels per day, most of it from the Lloydminster area.

Peabody said the increase in thermal heavy oil output will be offset somewhat by declines in cold heavy oil production.

“As we’re moving toward the edge of the reservoir with some of the cold heavy oil

wells, F&D [finding and development] costs are rising. And by bringing on these thermal projects, we actually help drive our F&D costs back down.”

Rev iew i ng it s t her ma l heav y oi l construction progress, Husky said its 8,000-barrel-per-day Pikes Peak South project is on target for first oil in mid2012. Pikes Peak South was 67 per cent completed on June 30.

Husky continued its 3,000-barrel-perday Paradise Hill development, which will use existing Bolney infrastructure.

The project was 28 per cent complete on June 30 and is to be operational by the third quarter of 2012.

Construction of a single thermal pilot well pair at Rush Lake was completed in the second quarter with first production expected in the third quarter.

Husky said four more commercial thermal projects are in the early delineation and concept selection phase.

BlackPearl Resources Inc. is another conventional heavy oil producer looking at thermal technology to increase recovery.

BlackPearl has an aggressive conventional drilling program underway at Onion Lake, drilling 63 wells in the second quarter and targeting 110 wells for the year. The company has 13 million barrels of established reserves in the play, with another 80 million barrels of contingent resource.

“In addition to conventional development, a portion of the Onion Lake lands are amenable to thermal development,” company president and chief executive officer John Festival said in releasing BlackPearl’s second-quarter results. “In fact, the majority of the contingent resource estimates for Onion Lake are based on thermal development in the area.”

The areas BlackPearl is targeting for SAGD development have net pay zones in excess of 15 metres, making the technology workable. It expects to recover 50–70

Heavy oil drilling is also keeping the oil flowing with Saskatchewan producing around 200,000 barrels per day.

OIL & GAS INQUIRER • DECEMBER 2011

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per cent of the resource in place, compared to around five to eight per cent through primary development. BlackPearl is predicting steam to oil ratios in the 2.5–3.5 range, putting it in line with the top quartile of SAGD bitumen projects.

Nea rby, Pet roba n k E nerg y a nd Resources Ltd. continues moving forward with commercial development of its thermal development using its toe to heel air injection (THAI) methodology.

Petrobank has spent much of the last two years working through the challenges of proving the THAI technology in shallower pay zones of Saskatchewan’s heavy oil fields. But the two pilot wells are now on track, reaching combined peak production of 355 barrels per day early this year, before declining to 40 barrels per day this summer due to ongoing work at the facility.

A 10-well commercial expansion at Kerrobert is well underway. In August, Chris Bloomer, senior vice-president and chief operating officer, heavy oil, said that eight of the 10 new well pairs are on air injection and in the initial production phase.

Petrobank continues expanding its land base at Kerrobert. In May, it acquired 566 acres of petroleum rights on the Kerrobert trend adjacent to the 4,092 acres of land that it purchased in March. This is the third acquisition of land that it has made in six months on the same trend as Kerrobert, and it currently controls 11,517 net acres of land on the trend. To define the resource potential of its new lands, the company purchased three third-party 3-D seismic surveys and plans to drill two stratigraphic delineation wells.

Southern Pacific Resource Corp. is also using SAGD at its STP-Senlac Thermal Project located near Unity in southwestern Saskatchewan. Southern Pacific’s aim at Senlac is maintaining production levels on an annual basis between 4,000 and 5,000 barrels per day. This summer, the property achieved an average production rate of 4,829 barrels per day. This increased production level is primarily a result of the recent addition of Phase H, which consists of two SAGD well pairs placed on production in April 2011.

As part of its development strategy, Southern Pacific is now drilling and preparing Phase J for production. Phase J consists of three SAGD well pairs; these well pairs may not all be needed until later in the fiscal year, and they will be layered into the facility as capacity permits.

Experience, leadership, performance.

Since it was established in late 2008, CanElson Drilling Inc. has grown quickly to become one of Canada’s premier drilling contractors. In addition to building its own drilling rigs, the company is expanding its fleet of drilling and service rigs through acquisition. CanElson now operates a fleet of 35 rigs (32 net).

With operations in Western Canada, West Texas, North Dakota and Mexico, CanElson Drilling Inc. is setting new standards for rig utilization.

With right-sized, purpose-built rigs built for horizontal and resource play drilling and experienced, well-trained crews, the company is achieving new records for cost-effective, efficient drilling operations.

Suite 700, 808 - 4th Avenue SW, Calgary, AB, Canada T2P 3E8 Phone 403.266.3922 Fax 403.266.3968 www.CanElsonDrilling.com TSX: CDI

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il is found in the minds of men,” according to the legendary geologist Wallace Pratt.

That old truism still holds water today, but getting that oil and natural gas to the surface is an entirely different matter. That requires exploration, drilling, completion, production and other technologies that can produce petroleum economically, safely and with minimal harm to the environment.

In this issue, we recognize eight technologies from across the industry spectrum that have had, or will have, a big impact on the exploration and production of petroleum in western Canada going forward in our second annual Technology Stars feature.

Western Canada’s conventional oil and gas industry has been on a technology-inspired tear in the last five years, driven largely by the application of extended-reach horizontal drilling and multistage fracturing tools on tight reservoirs.

These technologies continue being fine-tuned, and both drilling and completions service providers are well represented in the 2011 Technology

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Stars lineup. Also well represented are production technologies targeted at draining producing oilfields. And with growing pressure for industry to operate in a safe and environmentally benign fashion, new tools answering these public demands are also on display.

Somet imes, tec h nolog ica l c hange is as simple as changing the shape of the iron being used. Other times, it involves the application of space-age information technology measuring activity miles beneath the surface of the earth.

But what is common across the board is that people behind the advances are all looking for ways to make things work better. So as much as Technology Stars is a salute to the tools featured, it is also a nod to the people and companies behind those tools.

The staff at the Oil & Gas Inquirer, and its sister publication New Technology Magazine, would like to thank all those who sent in nominations for the 2011 Technology Stars.

Keep on innovating, and we’ll be here to tell your stories.

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VISAGE information software a new tool in exploration

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aunching a new oil and gas company has always been a challenge, but an innovative Calgary-based software company is helping to reduce some of that initial exploration risk.

T he tool developed by V ISAGE Information Solutions allows for the rapid access, analysis and visual interpretation of more than 710,000 wells in the Western Canadian Sedimentary Basin.

VISAGE Information Solutions Inc.

RUNNER-UP

PRODUCT: Visual analytics software technology SERVICE: Real-time exploration play screening tool

MINING FOR DATA

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Elkhorn Resources Inc. used that visual analytics technology to screen exploration areas in building its business plan, says Korey Galbraith, vice-president of engineering, who nominated VISAGE as a Technology Star.

“It’s a very powerful tool, but very userfriendly,” he says. “With the click of a button, we were able to analyze different play types and technical concepts utilizing all publicly available information and all in real time.

The VISAGE product enabled us to make quick and accurate decisions that were thoroughly researched and well-founded.”

The start-up company had identified the geographic area in which it wanted to operate—Manitoba, southeastern

Saskatchewan and North Dakota—and used the software to look at a number of different plays from an engineering perspective to complement the geology.

For example, Elkhorn was able to determine the average type curve for a well in the Spearfish play in different settings in order to decide if it was going to become a Spearfish player.

In the end, Elkhorn narrowed its focus to an eight-township area in southeastern Saskatchewan. It identified an area with available land that was prospective for the application of the technology to drive strong economic returns. As an operator, Elkhorn uses the technology to focus in on a particular area and to give it a better understanding of the economics for a potential play type with the actual numbers to back it up, based on public production data.

“It’s a very, very large data set,” says Galbraith. The VISAGE software gives an operator the ability to look at that data and make sense of it, sorting through it and normalizing it against a number of variables.

“I t y pically will look at 150 –200 wells, and it’s [in] a matter of less than a minute,” he says. “The efficiency of it is real time in my mind with the data sets I am running.

“When you are a small company like ours, every software product has to have a direct cost benefit, which VISAGE definitely does. We run very lean on our staff so we have to make it efficient to be able to do what we need to do, and that’s what this tool does.”

Because all of the plays Elkhorn is involved with are technology-driven, it has benefited from being able to see what other companies have learned in drilling their wells. “It definitely gets you up that [technology] curve quicker,” says Galbraith.

Percentile (cumulative probability) distributions provided a comparison of various completions attempted on the target reservoirs, leading to the conclusion that if single-leg horizontal wells could be fracture stimulated, they could yield the same production potential as multi-leg horizontal wells.

The software’s ability to generate representative type curves (rate versus time) that can be easily updated has allowed the company more time to actually analyze the data, he says. The results are shared within the multidisciplinary engineering,

geology and geophysics teams in order to “truth” the technical models.

A nother V ISAGE innovation is a method of combining cumulative probability distributions with type curves to provide a visual tool to communicate the variability in the production rates that make up type curves.

V ISAGE, which was formed by a group of former Schlumberger Canada Ltd. employees, went commercial about 6.5 years ago, says president Bertrand Groulx. Initially, it focused on production operations.

More recently, VISAGE has incorporated into its software the mechanisms that will enable operators to easily and rapidly navigate massive amounts of public information. Exploration and exploitation companies are interested in adding the software as another tool in the exploration process, he says. It can help them find the “hot wells,” who is drilling them and what technologies they are using.

Groulx says it would take him less than two minutes, starting from scratch, to bring up all the data for a type curve for the northeastern B.C. Montney formation, based on data from 2,000 Montney wells.

“You are not actually just analyzing data, you are exploring it because once I get those Montney wells up, I can group by company and actually see a type curve by company, and see which is the better

company, and that takes literally two seconds,” he says. “I can group by drilling contractor and who has drilled the most wells, who has got the best record, and I can look at horizontal length [and] azimuth direction of my wells.”

Because of its speed, the tool allows engineers the time to do what they are actually being paid to do: analyze and explore data. “The frustration that I hear from engineers is that they spend the bulk of their time hunting and gathering data— grunt work—and very little time actually doing stuff with it,” says Groulx.

He says his company chose a licensing model that would allow it to grow the company while making it palatable and low-risk for clients. “Because we are user-based, we are a rounding error in the grand scheme of things if you want to try out one licence. But if we prove to be very effective, there are some companies where we have [several] users, from operators all the way up to the [chief financial officer].”

Elkhorn has a floating licence so that anyone can use the product, but only one person at a time. “They make it so that the product is affordable for small entities such as ourselves,” says Galbraith.

And because the software continues to fund VISAGE’s development, “it is constantly getting better, and our ‘to-do’ list from clients on how to make the tool more powerful never gets shorter,” says Groulx.

“It will always be evolving.”

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Leak detectives use fibre optics to find even the smallest liquid leaks downhole

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HiFi Engineering Inc.

RUNNER-UP

PRODUCT: Fibre optics–based LeakSonar technology SERVICE: Locates wellbore gas and liquids leaks

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By James Mahony

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or oil and gas producers, the “optics” of finding downhole leaks just got a little brighter. Last year, a Calgary-based company rolled out a tool for finding natural gas leaks in wellbores. Since then, industry uptake has been promising, and the team has broadened and refined its fibre optics–based method.

Today, engineers at Hifi Engineering Inc. are applying the same fibre optics tools to the task of finding leaks of liquid in wellbores, says Hifi president John Hull.

Ever since Alberta’s Energy Resources Conservation Board (ERCB) turned its attention to leaks, the industry has taken notice. Whether due to casing vent flow or migration, natural gas leaks are a common concern for producers, not least because the ERCB requires them to be monitored and, in some cases, reported.

According to Hull, finding downhole leaks of liquids—as opposed to gas—was usually not a problem, especially at higher volumes, since these are usually easier to detect with traditional tools, such as microphones. But as flow rates decline, the leak becomes harder to detect and, at very low flow rates, it might not be detected at all with conventional methods.

That’s a gap Hifi plans to fill with its LeakSonar technology. On the market for a year now, the technology puts specially treated fibre optic line downhole, where it

" Optics" of leak detection improving

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serves both as acoustic sensor and transmitter of data. In effect, the fibre optic line becomes an optical “microphone” and a conduit to transmit data uphole, and can be deployed on wireline. Because a fibre optic line becomes the transmission line, much larger amounts of data can be carried than would be the case with wires or cables.

While many fibre optic lines have limited sensitivity, Hifi’s proprietary technology converts the line into a super-sensitive sensor capable of detecting very faint sounds that other sensory tools would miss entirely, says Hull, an engineer with fibre optics expertise. Those sounds might include background noise, but they might also include the sounds of low-flow liquid leaks, including water and hydrocarbon liquids.

Hull says LeakSonar represents an order-of-magnitude difference from traditional technology, especially when it comes to acoustic sensitivity. Indeed, he compares Hifi’s leak-detecting technology to the high-fidelity, digital music recordings usually found on compact discs.

“Think of it as if you’re trying to identify a song, and I give you the best CD out there with headphones, versus an old, scratchy record. If you listen to the CD, you can hear the little things, like cymbal taps, whereas with the scratchy record, you’re not going to hear the background sounds, and that’s where the clues are,” he says.

“Anybody can listen to the loud sounds in a well, but it’s finding the really, hard-to-find ‘snaps’ or fluid flow that’s important.

“The clues lie in [sounds] that we can’t really hear with our ears,” he adds. “You can’t hear a lot of this stuff with your ears.

But if you look at the fibre optic data, you’ll notice there’s a lot there that we’re missing.”

While Hull won’t say exactly how he treats the fibre optic line to make it sound-sensitive, he acknowledges that LeakSonar technology alters the line and uses its own processing software to interpret the logs when the downhole survey is made. Like other logging technologies, the LeakSonar tool starts at the bottom of the well and is pulled upward slowly on wireline, generating data as it goes.

While logging is ongoing, a section of fibre optic line about 10 metres long is exposed to the wellbore, and it picks up sounds within the wellbore, as well as those outside the casing. For example, the sounds of liquid flowing between the production casing and surface casing would be detectable.

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Hifi’s LeakSonar tool is only used after a well is completed, or later, when it’s producing. While testing is done, all production is stopped, and the production tubing is usually pulled from the well to allow the wireline operator to place the tool into the well.

The real breakthrough achieved by LeakSonar’s software is in recognizing the acoustic signature for liquid leaks, including very low-volume leaks too faint to be detected by other tools. Hull describes LeakSonar as “many times more sensitive” than tools like traditional acoustic microphones. In processing the data generated, Hifi’s software uses passive sonar technology, he says.

Finding applications for LeakSonar might not take long, and a few major Canadian producers are already using the technology. While shallow gas wells are a common application, there’s also a use for LeakSonar in testing steam assisted gravity drainage wells, especially those with very low water flow, Hull says.

Reading the logs resulting from a LeakSonar survey is not difficult. Hull points out that the area shaded in red (see photo) represents a leak of liquid. In the final analysis, the logs also facilitate well remediation. When a leak, whether gas or liquid, is detected, the operator can make repairs by applying a cement squeeze to fill the cracks.

Later, when the cement has had time to set, the operator can run another LeakSonar log to ensure that all leaks have been filled. If not, another cement squeeze can be done to fill the remaining holes.

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ilflow Solutions Inc. is helping customers enhance heav y oil production, recovery and transmission, by resolving viscosity-related issues in wells, reservoirs and pipelines.

“It’s unique patented technologies that mobilize heavy oil,” explains Oilflow Solutions chief executive officer Fred Meyer. “As a result, the heavy oil behaves as a lower-viscosity oil.”

Since January 2010, the Calgary firm has treated more than a million barrels of heavy oil with Proflux technology—Technology Stars’ runner-up for Best Production Technology.

Proflux’s chemistry is non-toxic, bio­ degradable, recyclable and compatible with standard oilfield processes and other industry production chemicals.

The initial development of this unique chemistry was over eight years ago. In 2007, Oilflow established its first Canadian operations and a research and development facility located in Calgary. Since opening operations in Canada, Oilflow has successfully commercialized several products and applications, with more to follow.

In commercial well applications, Alberta’s largest heavy oil companies have seen production more than double by utilizing Wellflux in cold production. Jetflux has been used to successfully clean out bitumen and sand from horizontal wells and restore production. Proflux for Workovers helps customers complete their work-over operations in steam assisted gravity drainage environments.

The Terraflux reservoir application is undergoing core studies with a major western Canadian oil and gas company, and is also the subject of an independent university study.

Initial indications show that the product significantly improves recoverable oil by improving enhanced oil recovery polymer technology.

Headquar tered in downtown Calgar y with a dedicated research and development facilit y in nor theastern Calgar y, Oilflow S olu tio ns al s o h as o p e ra tin g b ase s in Lloydminster, and Peace River, Alta., to support service and delivery of its applications throughout western Canada.

Internationally, Oilflow is expanding the Wellflux product into the Venezuelan market by partnering with one of the world’s largest oilfield service companies.

“Through collaboration with customers and industry, Oilflow’s goal is to provide game-changing chemical-based technologies that enhance production and recovery,” says Meyer. “Additionally, we want to help resolve issues related to transmission of heavy oil in a cost-ef fec tive and environmentally friendly manner.”

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Baker Hughes' AziTrak system improves horizontal drilling accuracy

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aker Hughes is helping operators steer their oil and gas reservoirs in the right direction with its deep azimuthal resistivity measurement tool for subsurface navigation.

“We’ve provided the ultimate GPS for drilling today,” says Darren Drake, drilling systems sales manager for Baker

Hughes. “We created something that allows you to be forward-looking for the first time ever. This deep-reading resistivity tool allows you to look ahead and steer accordingly—it allows you to see what you couldn’t see before. So instead of being in the pay zone some of the time, you can be in the pay zone all of the time.”

RUNNER-UPAziTrak deep azimuthal resistivity tool

SERVICE: The AziTrak tool improves steering while drilling horizontal wells

Steering Straight TOP: AziTrak’s unique capability for early bed boundary detection allows operators to identify pinching reservoir sands.

AziTrak’s deep resistivity image verifies the direction of the boundaries.

BOTTOM: AziTrak’s distanceto-bed detection allows field operators to react to formation dip changes to avoid reservoir exit. The AutoTrak-AziTrak combination is a fit-for-purpose geo-steering system.

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“It’s a game-changer,” says Adeniyi Ogundana, drilling applications advisor for Baker Hughes. “It’s a true proactive geosteering tool—because it delivers necessary navigation data in real time and on time.

We don’t have to wait until we’re out of the zone before we react or make a decision.

“Drilling has become more complex. This tool will help companies stay in that sweet spot, even when the zone gets very thin. They are able to stay in the reservoir for as long as they plan and have maximum production. You can use the tool to make real-time decisions, but it also stores the collected data in its memory.”

The AziTrak system allows drillers to optimize wellbore The AziTrak tool is one placement in real time. of very few deep azimuthal resistivity tools available to The Baker Hughes AziTrak™ deep azithe market. “Ours is direct measurement. muthal resistivity measurement tool—the You measure it and that’s it,” Drake says.

Technology Stars’ Best Drilling Technology “There’s a benefit to using a tool that does winner—offers another option for horinot require data inversion.” zontal drilling. It’s designed to enhance The hurdle for most operators conreservoir performance and efficiency by sidering this technology, he adds, is the optimizing wellbore placement in real cost—five times that of conventional tools.

“The value this tool delivers, however, time, providing distance to reservoir top greatly outweighs the cost. Clients worldand/or bottom and measuring formation resistivities with a deep-reading azimuthal wide are sold on the technology’s benefits. resistivity tool that creates a 3-D image of The people who use it the first time get it the subsurface. The AziTrak tool brings a very quickly,” Drake says. “At the end of 360-degree view of the downhole envithe day it’s about money and about best production—and when you have it, people ronment and provides operators with the will not go back.” capacity to detect, measure and visualize Calgar y-based Pradera Resources bed boundaries, and detect the oil-water contact in the reservoir hours sooner than Inc., a 100 per cent oil-focused junior when using conventional sensors. exploration and production company The technology integrates measurementthat chases Slave Point and Gilwood oil in while-drilling (MWD) and logging-whilethe Slave Lake, Alta., region, had excellent results using the AziTrak tool. Last drilling (LWD) capabilities into one tool, by using multiple-propagation signals and March, Pradera became the first company detection for precise navigation data. The in Canada to use the AziTrak tool, in the Baker Hughes surface tool captures data Slave Point zone north of Slave Lake. from all of the downhole MWD/LWD sen“Deep-reading azimuthal resistivity sors via mud-pulse or wired-pipe telemtools allow us to maximize the amount etry that transmits real-time navigational of the horizontal section of the welldata and memory-quality images. bore within the zone’s prime porosity When the AziTrak tool is deployed region, for optimization of the wellbore with the Baker Hughes AutoTrak™ rotary placement,” says Daniel Jalbert, vicesteerable system, field specialists can benpresident of operations for Pradera. “The efit from the short sensor to bit spacing technology provides excellent benefits. and apply early steering decisions, such With the proper interpretation, the tool that the wellbore can be optimally placed will enable you to place your wellbore within the reservoir. within your zone of interest better than

traditional technologies. By placing the wellbore in the optimum position, we get higher production rates, and we’ve been able to defer the costs of wellbore stimulations until production rates warrant. You end up with a more economic wellbore.”

These types of results are reservoirspecific, Jalbert adds. “It won’t apply to every zone or reservoir where you run this tool.” And, like any other type of technology, he notes, in order to achieve the greatest success the deep azimuthal resistivity tool requires a ver y high degree of involvement on the operator’s part. “Having that level of involvement on the side of the operator is imperative in order to have success with the tool, to optimize the geosteering of the wellbore placement—because it’s the geologic interpretation of the results you’re getting back that is so critical.

It requires a 24/7 team approach to achieve success.”

“ We created something that allows you to be forward-looking for the first time ever. This deep-reading resistivity tool allows you to look ahead and steer accordingly—it allows you to see what you couldn’t see before."

OIL & GAS INQUIRER • DECEMBER 2011

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Disintegrating frac balls poised to eliminate flow-back restrictions

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BEST COMPLETIONS TECHNOLOGY: 2011

Baker Hughes Inc.

RUNNER-UP

PRODUCT: IN-Tallic disintegrating frac balls SERVICE: Frac balls that dissolve downhole in presence of brine

By Maurice Smith

T

he introduction of fracture systems using ball-and-seat technology to activate downhole sleeves and segregate multiple sections of horizontal wellbores represented a clever innovation to enable multistage fracturing. But if the balls do not flow out of the well after fracturing is completed, they can impede production flow, necessitating the dispatch of a workover rig or coiled tubing unit to mill out the obstruction before production can be optimized.

Now, an oilfield services major thinks it has a solution that is as nifty as the invention of the multistage fracturing technology itself—frac balls just as robust as the originals, but which melt away in the presence of salt water, or brine.

Darryl Firmaniuk, manager of engineering for completion systems in Canada for Baker Hughes, likens them to a candy of his youth. “It’s almost like a jawbreaker where you have it dissolve in your mouth where it eventually disappears.”

Called IN-Tallic frac balls, they were designed specifically for formations like

The incredible shrinking ball

the prolific Bakken in the Williston Basin that straddles the border of southern Saskatchewan and North Dakota, where multistage hydraulic fracturing has opened up millions of barrels of new reserves in the past decade.

“If the formation pressure is very low, it can be difficult to get regular frac balls off seat or to flow back to surface,” Firmaniuk says. Where production velocity is not high enough, residual frac/formation sand can also pile up in low portions of the wellbore, causing obstructions that further restrict egress of frac balls.

“It depends on your formation and how much residual frac/formation sand you have in your liner after fracturing operations. If a ball is able to come off seat and hits a sand dune on the low side of the well, then the ball may not be able to climb over the sand dune and start moving up the wellbore.”

Standard phenolic (typically a resin made of phenol and an aldehyde) frac balls must be able to withstand being fired downhole at speeds of up to 160 kilometres per hour into a stationary seat and to hold up to pressure differentials during fracking of 10,000 pounds per square inch or more.

Thus, they don’t break down easily.

“The regular balls are very robust, very durable in terms of the material they are made of, and they will stay integral for a long, long time,” says Firmaniuk. “So we thought about developing a ball that would be able to dissolve enough to come off the seat it landed on to do the frac job, and then it would be able to continue to disintegrate in the liner over time to leave an un­obstructed wellbore.”

IN-Tallic balls are composed of a proprietary controlled electrolytic metallic nanostructured material—combining specific metallic alloys—that is as light as aluminum but as strong as steel.

Nanostructured materials, built or designed on a nanometre scale—measured

Baker Hughes’ IN-Tallic controlled electrolytic metallic frac balls are designed to dissolve downhole. At left, a ball in its seat measures 3.5 inches. It shrinks to 2.9 inches after 100 hours and 1.5 inches after 210 hours. At right, little is left after 460 hours.

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in the range of a billionth of a metre— take on properties as defined by quantum physics, potentially making them act in unique ways. According to the company, the IN-Tallic balls’ decomposition process works through electrochemical reactions controlled by nanoscale coatings within the composite grain structure.

The balls start with a shiny surface and when exposed to brine, they effervesce “almost like an antacid tablet,” describes Firmaniuk. As disintegration takes place; they take on a grainy texture.

The rate of disintegration can vary somewhat depending on such factors as temperature and the salinity of the fluids present, but generally it should take approximately 24 hours to shrink enough to become unseated, Firmaniuk says. They become pea-sized in about 20 days. Application of G Y S TA R S acid can speed up that process.

LO O The presence of brine, whether from the slick water frac or from production fluids, acts as the catalyst for the reaction. “Usually the ball doesn’t have to get to the size of a pea to come out of the well; the ball only has to get to a small enough size that its going to not be a 2011 WINNER problem during the production phase of the well,” says Firmaniuk.

2011

RUNNER-UP

Ground Effects Environmental Services Inc. PRODUCT: ElectroPure SERVICE: Treats frac flowback and produced water

A

n ele c t r ici t y - b as e d , c h e mic al-f re e technology for treating hydraulic fracturing flowback and produced water introduced

by Ground Effects Environmental Services Inc. in 2010 promises to remove 99 per cent of

They do require special handling, since exposure to any moisture could degrade them. “These balls come sealed in a bag that doesn’t allow the ball to be exposed to the environment. Only when they are ready to be dropped in the hole are they taken out of this protective barrier.”

While more costly than regular frac balls, they are certainly cheaper than the cost of bringing in a coiled tubing unit to mill out an obstruction, as can be required when regular balls do not flow back to surface.

In multistage fracturing operations where a number of balls are used—consecutively smaller in size as they go deeper into the well—companies have the option to use a mix of phenolic and IN-Tallic balls.

Since the smaller phenolic balls are lighter, it most often makes sense to select IN-Tallic balls in the larger sizes, which are less likely to come off seat and flow back up to surface.

IN-Tallic ball sizes range from one-inch to 3.75-inch diameters. They are primarily used in combination with Baker Hughes’ FracPoint, the company’s main multistage fracturing system in Canada.

After considerable use in the U.S. Bakken and Three Forks formations, Baker Hughes had run one installation for a major

operator in Canada and was on the verge of a second run when this article went to press.

“From what we know on the first job for this client, the fracturing operations went very well. The balls performed from an impact and a pressure integrity perspective as they were designed,” says Firmaniuk.

The company is running laboratory tests to compare results with those in the field (using fluids particular to the Canadian setting), as was done extensively on U.S. trials, and will prepare a case study when all the results are in, he says.

Eventually, the balls are likely to go international, he says. With a specialized technology such as IN-Tallic that works in challenging environments, there is plenty of potential for growth. “Anywhere that water-based fracs are used, and especially where they’re combined with low formation pressures where existing balls don’t come out of your well very easily, the ball would be of interest.”

Still, the balls are likely to remain a somewhat-niche product, where low pressures tend to be a problem. “For customers who want peace of mind that they are going to have a non-restricted liner at the end of the day, these balls may be a solution for them.”

most contaminants while eliminating water transportation costs for the treated volume.

The company’s proprietary ElectroPure technology uses a two-stage, vacuum-enhanced electro-catalytic oxidation process to destabilize and remove such contaminants as polymers, total suspended solids, guar gum, iron, scaling agents, bacteria, hydrogen sulphide and almost any other contaminant found in frac water. It has successfully processed some of the most difficult-to-treat types of waste water, including gel and hybrid frac water, says Sean Frisky, founder and president of Ground Effects.

Reuse of the treated water in fracturing operations—which can guzzle up to 70 million litres per frac—eliminates the need, and cost, to replace the treated volume with fresh water, while reducing greenhouse gas emissions. Though not treated to drinking water quality, it’s more than adequate for fracture operations and other industrial uses.

In addition to stationary systems, Reginabased Ground Effects operates six mobile turnkey systems, consisting of three-trailer packages capable of treating from 500 to 3,000 cubic metres of produced or flowback water per day.

Two more systems are expected to be in operation this month, with more planned for the future.

The systems can be controlled and optimized remotely by satellite or cellular phone link, with real-time critical process information and intelligent trending available.

Besides frac water treatment, Frisky says the technology will be applied to produced water and the growing oilsands market for recycling of steam assisted gravity drainage water. “We are getting very good response to the technology. In fact, we are getting interest on a global scale,” he says.

OIL & GAS INQUIRER • DECEMBER 2011

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National Oilwell Varco’s Dreamcatcher technology recycles old tires into oil spill clean-up products

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WINNER

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BEST HSE TECHNOLOGY: 2011

National Oilwell Varco Inc.

RUNNER-UP

PRODUCT: Dreamcatcher oil spill technology products and services

By Jacqueline Louie

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ational Oilwell Varco Canada’s Dreamcatcher™ oil spill technology products and services are saving recycled tires from the landfill—and they’re making the planet a greener place at the same time.

Designed to remediate and prevent soil and water contamination, Dreamcatcher’s line of patented technologies and services is the Technology Stars’ Best Environmental Technology winner.

The technology that all Dreamcatcher products are based on takes a used rubber

tire and degrades it into two compounds: the Smart Crumb, a fine rubber crumb used for adsorbing oil spills on land; and Aqua Fiber, a fibre/rubber compound used to adsorb oil spills on water. Both are oleophilic (oil attracting) and hydrophobic (water repelling), which allows them to quickly filter hydrocarbons from water.

After Dreamcatcher’s Smart Crumb product adsorbs hydrocarbons, it can then be used to produce asphalt products. After the Aqua Fiber is used to adsorb hydrocarbons, it can be remediated and used to replace sand and gravel in residential and commercial concrete and asphalt applications.

Dreamcatcher’s infused products are lighter and stronger than regular concrete, the company says, and can be used in many common applications including pre-cast paving stones, sidewalks, driveways and roads.

National Oilwell Varco Distribution Services Group is the global distributor

SERVICE: Dreamcatcher technology uses recycled tires to remediate and prevent soil and water contamination

A new use for old tires From left: Shane Exton, Tom Jackson and Wayne Bennett; Dreamcatcher technology was exhibited at this year’s Global Clean Energy Congress in Calgary.

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Strad Energy Services Ltd. PRODUCT:

WorkSafe Rig Mat

TECH

of the Dreamcatcher oil spill technology products and ser vices, which were invented and patented by Wayne Bennett, president and founder of ESSI International Environmental Sentry Services Inc., based in Irma, west of Wainwright, Alta.

“The technology designed from recycled rubber tires allows our customers to be proactive or reactive to environmental issues,” says Bennett, who has brought 35 years of experience working in the oil industry to his inventions.

“What triggered my research into rubber tires was my desire to create products that could be utilized several times in a cradle-to-grave product. We create the products, we use them for oil spill remediation and at the end of the day when they can no longer be used for oil spills, we turn them into flexible rubber concrete that does not require sand or gravel. I believe there is nothing like it.”

Dreamcatcher’s manufactured line of environmental products includes commercial filtration systems used to remove contaminants from water; pipeline spill kits; wellhead bags, used to protect the immediate environment around a producing wellhead; spill response products; truck spill kits and several other products.

In addition to Dreamcatcher, Bennett adds, there are other good products out on the market. However, “the unfortunate part about the majority of them, is they are used once and then disposed of and end up in the landfill.”

That’s something that Dreamcatcher works hard to avoid.

Using recycled tire by-products that would otherwise be landfilled, and not raw materials, helps reduce its environmental footprint.

National Oilwell Varco Distribution Services—an exhibitor at the recent inaugural Global Clean Energy Congress & Exhibition in Calgary—holds the exclusive global distribution rights to the Dreamcatcher oil spill technology products and services. National Oilwell Varco Distribution Services recently created a separate business group focused around alternative energies called NOV EnviroGreen Products and Services, which includes the Dreamcatcher products, solar, wind and environmentally friendly compounds, cleaners and degreasers. “The real value to that is being able to remove waste from landfills, being able to use rubber tires to adsorb hydrocarbons and then recycling

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The WorkSafe Rig Mat reduces tripping hazards at worksites while protecting the ground

2011

RUNNER-UP

them into concrete products so that no waste ever enters landfills,” says Shane Exton, product line manager with National Oilwell Varco Distribution Services.

Currently, National Oilwell Varco Distribution Services is working with a number of oil and gas companies to help them meet their frac water filtering needs, by designing a filter to clean and reuse frac water. The ability to closely work with customers is one of National Oilwell Varco’s strengths, Exton says. “It’s really about how we can work closely with our customers to develop solutions around today’s most advanced environmental issues. It’s such a new product line, we have the ability to work hand in hand with customers to develop unique solutions around their environmental issues.”

Canadian actor, singer and producer Tom Jackson, O.C., LLD, Chancellor of Trent University in Peterborough, Ont., has been a believer in Dreamcatcher technology from early on and is one of its biggest champions. “Green technology as it relates to this Dreamcatcher brand of technologies will seriously impact the size of the footprint the oil and gas industry has on the globe,” says Jackson, who is National Oilwell Varco’s Distribution Services vicepresident, global business development, based in Canada.

“This technology takes a waste product that is bad for the planet and puts it to use.

At the end of the day, the opportunity to further recycle this product into concrete and asphalt products is part of the magic.

You take a recycled tire and you put it into asphalt and concrete, and what happens in between is you save the planet.”

S

trad Energy Services’ WorkSafe Rig Mat™ is “a very simple technology, but very effective,” says Strad chief operating officer, Rob Grandfield.

Introduced to the market last October, the WorkSafe Rig Mat features a proprietary square tube end made from engineered steel.

It was Jared Bathelt, a line foreman at Strad’s Nisku, Alta., manufacturing plant, who invented the square end design, which creates a flat working surface with no gap and no rounded edge, reducing tripping hazards at worksites while protecting the ground at the same time.

The Technolog y Stars’ runner-up for Best HSE Technology, the WorkSafe Rig Mat “is changing how rig mats are being built,” Grandfield says. “It’s a safer, more user-friendly rig mat. It doesn’t gather mud. It’s easier to clean, and it’s all-around better.”

Traditionally, rig mats have always been built with a rounded pipe end. “It has always been a problem when you butt them up to each other. There’s a gap, which is a safety issue, because you can roll your ankle—or it just gathers dirt,” Grandfield notes.

Strad’s WorkSafe Rig Mat can be used not only at drilling sites, but also at a variety of other locations, including pipeline, construction site and facility access.

In North America, Strad holds 60 per cent of the market share for rig mat manufacturing.

The WorkSafe Rig Mat now makes up 80 per cent of the rig mats it now sells. Strad can build the WorkSafe Rig Mat to fit any project size; the mats are also available for rent.

“It’s just been fantastic—companies have really embraced it,” Grandfield says. “We’re really proud of it and proud to be recognized as one of the game-changers out there.”

Strad Energy Services is a publicly traded Calgary-based service company that provides complete customer solutions in drilling-related oilfield equipment and services; it also supplies servicing and production equipment for the production side of the industry.

The flat surface of the WorkSafe Rig Mat protects workers from falls

OIL & GAS INQUIRER • DECEMBER 2011

35

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British Columbia

Fracturing sand mines needed

By Lynda Harrison

OCT/10

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Photo: Joey Podlubny

Test results of the silica sand in June and July proved the quality of the sand meets or exceeds API/ISO specifications for proppants used in hydraulic fracturing and gravel-packing operations, reported the company.

Athabasca has indicated it now intends to obtain a National Instrument 43-101 technical report and confirm the economic viability of frac sand production.

Athabasca Minerals holds permits over 479,240 hectares (1.18 million acres) of land in the Fort McMurray area.

According to the company, the Alberta Geological Survey has identified a rich variety of industrial minerals such as silica sand, limestone, gypsum and salt in these areas, which can also be processed to meet oilsands industry demand.

Meanwhile, Stikine Energy Corp. has initiated a frac sand pilot plant in Abbotsford, B.C., and aims to supply that

province’s shale gas industry. However, unanticipated maintenance work has caused a delay to its operations and opportunities to test sand.

Stikine has two deposits: the Angus, about 100 kilometres southwest of the Montney, and the Nonda, about 150 kilometres northeast of the Horn River Basin.

Proppant testing of initial samples shows that the operation has not yet been optimized to produce API/ISO sand specifications. Changes have been made to equipment settings, new samples will be shipped to test and the company will report on results from its process work on Nonda material.

The pilot plant had previously demonst rated production of Nonda 100 mesh sa nd t hat ac h ieves A PI / ISO – recommended specifications for proppants. Bench-scale testing on a variety of Nonda samples has also reliably produced sand samples that meet or exceed recommended specifications, reported the company.

Accord i ng to si ster publ ic at ion Oilweek magazine, the company plans to mine suitable quartz-pure sandstone deposits near the t wo gas plays and use innovative but proven techniques to mine the sand for use as proppant.

Basically, the company plans to accelerate the erosion process.

T he deposits are at t he surface, a l low i ng for si mple recover y f rom open pits. Stikine’s president and chief executive officer, Scott Broughton, told Oilweek the pilot work has demonstrated that the sand grains liberate readily from their rock matrix.

He said Nonda is a massive deposit of what amounts to 100 per cent silica sa ndstone. T he Nonda ha s e x ac t ly what ’s being pumped into the Horn River Basin: 40/70 sand and 100 mesh, said Broughton.

Local sources of sand are needed to cut transportation costs for fracking proppants.

Oil and gas producers will have fracturing sand closer to their operations, thereby improving the economics of their plays if proposed sand mines are built in the Wood Buffalo region of northern Alberta and in northeastern British Columbia.

“If there’s anything going on up in northeastern B.C. that would allow us to get frac sand cheaper, we would be looking at it,” said Rob Spitzer, chairman of the Horn River Basin Producers Group. “I know there’s some activity there; it would save us some costs—certainly on transportation.”

Athabasca Minerals Inc. is planning pilot-scale production of frac sand at its proposed Firebag frac sand project, where it has 12,800 hectares of land accessible by major roads and near water and power sources in Alberta’s Fort McMurray Wood Buffalo region.

BRITISH COLUMBIA WELL ACTIVITY

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OIL & GAS INQUIRER • DECEMBER 2011

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British Columbia

The Angus is also a very large deposit with coarser material. Both were chosen for their proximity to the gas projects, the size of their resource and suitability of grain size.

About 900,000 tonnes of frac sand is being pumped into the Montney and Horn River basins per year, but with no quarry nearby, the closest source is in the Peace River area of Alberta, around 600 kilometres away. Sand is also being sourced as far away as Saskatoon, Sask., Nebraska and Texas. Producers are paying $200–$450

per tonne for the sand, and 80 per cent of that cost is in the shipping.

Art Jarvis, executive director, south, of Energy Services B.C., said having a nearby mine would be a huge advantage for producers in both of those areas. Jarvis said currently they are shipping sand by rail and then trucking it from Fort St. John and Fort Nelson in British Columbia, so transportation costs would definitely be cheaper, he said.

Jar vis would welcome the added long-term employment it would bring to

northeastern British Columbia. “I don’t see any disadvantage to it.”

In August, EOG Resources, Inc. said it could save as much as US$400 million during development of its resource plays by supplying its own proppant sand for fracture stimulations.

With the proliferation of tight oil and natural gas plays in North America in recent years, sales—and also prices—of frac sand have skyrocketed.

In response, Houston-based EOG is developing its own sand mine in Chippewa County of northwestern Wisconsin.

Progress spending $465 million in 2012 to advance north Montney joint venture Progress Energy Resources Corp. plans to invest roughly $465 million in 2012 to cont i nue t he development of it s northern Montney resource base, initiate the first phases of development on its joint venture lands with PETRONAS and pursue light oil opportunities in the Deep Basin.

“In 2011, we executed on a number of key initiatives that have strengthened our balance sheet while attracting a st rong joint vent ure par t ner,

$8 0 0 m i l l ion i nc lud i ng t he Nor t h M o n t n e y J o i n t Ve n t u r e ( N M J V ), or $ 4 6 5 m i l l ion ne t to t he c om pany. Approximately $380 million will be invested in Progress’ North Montney program, $50 million in the NM J V, including capital for the detailed feasibilit y study of the LNG project and $35 million in the Deep Basin targeting the company’s Dunvegan light oil play.

Progress anticipates drilling approximately 35– 40 horizontals on existing

were feeding into this facility, will be directed to the new Gundy facility and a further seven to nine wells will be drilled in 2012 at Town South.

A n e x pa n sion of t he P r og r e s s operated gas processi ng faci lit y at Kobes will be undertaken in 2012 to bring capacity to 50 million cubic feet per day. Four to five wells are planned for 2012.

At Town North, an additional two wells are planned for 2012 to fill the

In terms of its North Montney program, the company has built the industry’s largest Montney land position at over 1,250 net sections, or approximately 825,000 net acres, spanning 560 kilometres from northwestern Alberta to northeastern British Columbia.

PETRONAS, to accelerate development of our north Montney assets and provide expertise in LNG [liquefied natural gas] development and market access,” said Michael Culbert, Progress’ president and chief executive officer, in a prepared statement. “The focus of our 2012 capital program will continue to be on our north Montney resource base and expansion of our light oil play in the Deep Basin.”

For 2012, Progress will have a capital investment program of approximately 38

DECEMBER 2011 • OIL & GAS INQUIRER

development pods with another six to eight wells targeting delineation drilling on its vast northern Montney land holdings. Approximately 25–30 gross wells are planned for the company ’s NMJ V lands. In the company’s emerging Dunvegan light oil play, six to eight wells are expected to be drilled.

At Tow n Sout h, t he 50 -m i l l ioncubic-foot-per-day facility is operating at capacity and enters into its maintenance phase heading into 2012. The last of the Gundy-area wells, which

e x i st i ng 25 -m i l l ion- c ubic-foot-p erday processing facility while at Gundy, t he gas processing facilit y is being expanded to 50 million cubic feet per day and eight to 11 wells are planned for 2012.

At west Gundy, the company’s newest pod development is on a 20-section, 100 per cent working interest block of land adjacent to Progress’ Kobes pod. Plans for 2012 are to drill eight to 12 wells in this area and construct a 25-million-cubicfoot-per-day facility in the first quarter.

British Columbia

The third horizontal at Caribou will be completed with plans to move to full development in 2013. At Nig, the partneroperated pod development is 25 kilometres to the east of Town and currently has one tested horizontal with three additional wells to be completed by the first quarter of 2012. In the NMJV, 25­–30 wells will be drilled at Altares, Lily and Kahta in 2012.

Progress expects to average 50,000– 52,000 barrels of oil equivalent per day for 2012 and exit at approximately 58,000 – 60,000, imply ing growth of approximately 15–20 per cent on a pershare basis.

In terms of its North Montney program, the company has built the industry’s largest Montney land position at over 1,250 net sections, or approximately 825,000 net acres, spanning 560 kilometres from northwestern Alberta to northeastern British Columbia. The primary focus of the company’s north Montney program remains in the Foothills of northeastern British Columbia, where Progress holds approximately 625,000 net acres of largely contiguous Montney rights.

Progress continues to pursue its strategic plan, set out in November 2010, of doubling its production base over the next five years by developing multiple 50-million-cubic-foot-per-day development pods.

During the quarter, Progress closed the transaction to create a strategic partnership with PETRONAS to develop a portion of Progress’ Montney assets in the Foothills of northeastern British Columbia. Progress sold a 50 per cent working interest in its Altares, Lily and Kahta properties (NMJV) to PETRONAS for $1.07 billion.

As well, the partners will explore opportunities to develop LNG export capacity in British Columbia. Progress received 25 per cent of the total consideration ($267.5 million) in cash at closing. The remaining $802.5 million will be in the form of a capital carry whereby PETRONAS will fund 75 per cent of Progress’ 50 per cent interest.

Three rigs will be operating on the NMJ V properties in the fourth quarter. The LNG Export Joint Venture has selected an engineering firm to undertake the technical detailed feasibility as well as initiate the site selection process.

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Clean energy project launched at Whitecourt

Waste heat will be used to generate about 14 megawatts of electricity from Alliance Pipeline facilities.

In November, NRGreen Power Limited Partnership and General Electric (GE) announced plans for a new recovered energy project that will produce power without additional emissions using the first global application of GE’s innovative ORegen system.

The technology will be installed at Alliance Pipeline’s Windfall Compressor Station near Whitecourt, Alta., to generate electricity through the use of waste heat. The ORegen system is the latest in organic Rankine cycle technology, and its introduction at the Global Clean Energy Congress in Calgary marked its official debut in the market.

“This technology recovers heat energy that would otherwise be lost to the atmosphere and transforms it into electric energy without producing any new emissions. It makes for a very clean form of electricity generation,” said Murray Birch, president and chief executive officer of NRGreen, an affiliate of Alliance Pipeline. “When constructed, the

Whitecourt facility will reliably generate and deliver up to 14 megawatts of electricity per hour—enough power for 14,000 Canadian homes. Partnering with GE has provided us with one of the most efficient wasteheat recovery units we’ve seen to date.”

NRGreen works to develop clean energy by converting waste heat generated at compressor stations along the Alliance Pipeline system to produce emissionfree electric power. The company currently has four waste-heat recovery units operational in Saskatchewan at Kerrobert, Loreburn, Estlin and Alameda.

While its Whitecourt Recovered Energy Project (WREP) marks the company’s fifth waste-heat recovery installation, it is the first to employ GE’s ORegen system.

Construction of the WREP will commence in May 2012. NRGreen is jointly owned by Veresen Inc. (50 per cent) and Enbridge Income Fund Holdings Inc. (50 per cent).

“This is a significant milestone for GE, as it is not only the first NRGreen project to utilize ORegen, but also the first ever commercial application for GE,” said Paolo Ruggeri, head of solutions at GE Oil & Gas. “The ORegen is part of a growing family of products that have been qualified under GE ‘ecomagination’ and will help reduce the emissions footprint of power generation facilities such as these. The system is a best-in-class waste-heat recovery technology, and this project demonstrates that it is ready to be applied across the globe.”

The ORegen system recovers waste heat from gas turbine exhaust and converts it into electric energy. The benefits of deploying the systems are substantial, improving overall plant efficiency by up to 50 per cent or more and producing electric power with no additional fuel by recovering heat from all types of gas turbine exhaust (or any other low- to mediumgrade waste heat source). The system is ideal for remote locations because, unlike many cogeneration technologies, it does not require water utilization or the use of on-site manned operational supervision.

The project will be funded in part by Alberta’s Climate Change and Emissions Management (CCEMC) Corporation.

The CCEMC is an Alberta-based, not-forprofit, independent corporation with a mandate to reduce greenhouse gas emissions and adapt to climate change by supporting the discovery, development and deployment of clean technologies.

NRGreen’s project with ORegen technology meets this mandate. Supplementing NRGreen’s substantial investment, the CCEMC will contribute $7 million to the Whitecourt Recovered Energy Project.

The Climate Change and Emissions Management Fund is financed by payments from companies complying with the Alberta government’s annual greenhouse gas emissions requirements.

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

OCT/10

OCT/11

WELL LICENCES

277

324

▲

OCT/10

OCT/11

WELLS SPUDDED

216

276

▲

OCT/10

OCT/11

WELLS DRILLED

184

264

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2011

41

Northwestern Alberta/Foothills

Pembina’s proposed Resthaven deep cut gas plant gaining support Pembina Pipeline Corporation will expand its natural gas–handling assets in westcentral Alberta as part of a project to modify and expand an existing shallow cut gas plant to develop an enhanced natural gas liquids (NGLs) extraction facility.

Once operational, the initial phase of the Resthaven facility will have gross capacity of 200 million cubic feet per day of gas and 13,000 barrels per day of liquids extraction capability, with an ultimate capacity of 300 million cubic feet per day.

Plans also call for Pembina to construct a 44-kilometre, six-inch-diameter pipeline to transport the extracted liquids from the Resthaven facility to its Peace Pipeline, which delivers product into Edmonton.

Once the project is completed, Pembina will own approximately 65 per cent of the Resthaven facility and 100 per cent of the NGL pipeline.

Pembina estimates that the Resthaven facility, associated NGL pipeline and storage will cost approximately $230 million net to Pembina. Subject to regulatory approval, Pembina expects the new facilities to be in service in late 2013.

P e m b i n a ’s i n v e s t m e n t i n t h e Resthaven facility is supported by longterm firm service agreements with two of the major area producers, while the NGL

pipeline is underpinned by long-term firm service agreements with the Resthaven facility owners.

“The Resthaven facility represents a strategic step in building out our gas services business,” Bob Michaleski, Pembina’s president and chief executive officer, said in a news release. “This opportunity will generate additional value through integration with our conventional pipelines and midstream and marketing services.”

Under a long-term processing agreement with Pembina, Encana Corporation expects to boost its extraction of NGLs at Resthaven to about 8,000 barrels per day in the initial phase from about 1,000 barrels per day, said the company. The second expansion is expected to provide Encana with another 4,000 barrels per day of extracted NGLs. Encana has also secured capacity on Pembina’s NGL pipeline.

The Resthaven agreement is the third step in the company’s plans to capture additional value from its liquids-rich natural gas production in Alberta’s Deep Basin, Renee Zemljak, Encana’s executive vice-president, marketing, midstream and fundamentals, said in a news release.

Over the next few years, Encana expects its NGL extraction to triple to

about 30,000 barrels per day from about 10,000 barrels per day as a result of investments in third-party midstream companies at three Deep Basin plants— Resthaven, Musreau and Gordondale, she said.

“The addition of deep cut facilities adds significant value to our natural gas production due to the price uplift that is generated when we extract and sell higher-value ethane, propane, butane and condensate,” Zemljak said.

In December 2011, Encana will take the first step in its NGL extraction initiative with the addition of about 5,000 barrels per day of NGL production from expanded facilities that Pembina has installed at its Musreau gas processing plant, about 30 kilometres northwest of the Resthaven plant.

Late last year, Encana agreed to a long-term processing arrangement with a midstream company to construct a new 120-million-cubic-foot-per-day gas processing plant in the Gordondale area, about 100 kilometres northwest of Grande Prairie, Alta. It expects to extract an additional 3,000–4,000 barrels per day of NGLs from the plant, which is expected to be in service in late 2012.

— DAILY OIL BULLETIN

Birchcliff reports record production Fresh off a quarter that saw it set a production record and post improved financial results, Birchcliff Energy Ltd.’s top official reaffirmed that a public sale process is the “appropriate course of action” to attract a reasonable offer to purchase the company.

“In short, if Birchcliff receives a reasonable bid, the resulting sale will create value for our shareholders. In the event the sale process is not successful, we are very well positioned to execute our business plan with exceptional enthusiasm and a very large and stable asset base,” president and chief executive officer Jeff Tonken said.

In early October, Birchcliff’s board of directors announced a public sale process, seeking offers to purchase all of the outstanding shares of the company. At the 42

DECEMBER 2011 • OIL & GAS INQUIRER

time of that announcement, Seymour Schulich, who holds about 26 per cent of outstanding shares and is the company’s largest shareholder, said he was in full support of the potential sale of the company.

“If a reasonable price cannot be achieved at this time, I am happy to continue as Birchcliff’s major shareholder, and I will continue to support Birchcliff at every opportunity,” he said.

Tonken said that Birchcliff does not intend to make any further announcements regarding the sale process unless and until the board of directors has approved a specific transaction or otherwise deems that disclosure of developments is appropriate.

Meanwhile, third-quarter production averaged 17,648 barrels of oil equivalent

per day (75 per cent natural gas and 25 per cent light oil and natural gas liquids), up 35 per cent from 13,110 barrels per day in the third quarter of 2010.

The company said this significant increase in production volumes over the past year was primarily a result of its Montney/Doig horizontal natural gas drilling program and the completion of Phases 1 and 2 of the PCS Gas Plant in the Pouce Coupe, B.C., area. Birchcliff also achieved drilling successes in both the Worsley area and in its East area.

As a result of severely abnormal weather conditions, including a significant amount of rain and flooding, and frequent unexpected third-party processing outages, Birchcliff expects its forecast yearly average production to be between 18,100 and 18,200 barrels equivalent per

Northwestern Alberta/Foothills

day—slightly below its previous guidance of 18,500 barrels equivalent per day.

Birchcliff said that based on estimates from field reports, current production is approximately 19,400 barrels equivalent per day.

Output for the first nine months of this year increased to 17,572 barrels equivalent per day from 11,968 barrels equivalent per day for the same period in 2010.

The company said it continued to reduce operating costs per barrel equivalent to

Birchcliff drilled 19 (15.4 net) wells during the third quarter. $6.39, down 12.8 per cent from the third quarter of 2010 and down 5.2 per cent from the second quarter of 2011.

Birchcliff drilled 19 (15.4 net) wells during the third quarter.

T he compa ny ’s ac t iv it ies on t he Mont ney/ Doig nat ura l gas resource play included the drilling of five (4.9 net) horizontal natural gas wells using multistage fracture stimulation techniques. Of these wells, one (1.0 net) well was an exploration well that was successf ul in finding a new pool, the other four (3.9 net) wells were development wells.

Birchcliff said its strateg y for the Montney/Doig play has “evolved into a full-cycle” exploration, exploitation, development and production program.

“We continue to aggressively add to our undeveloped land inventory, we continue to build out our infrastructure, we are now drilling infill wells on 300-metre inter-well spacing. Further evaluation is being conducted to suppor t dow n-spacing to less t han 300 metres, as has been done by other competitors on the play,” the company said.

T he company said it continues to explore to geographically and stratig r aph ic a l l y e x p a n d t h e M ont n e y/ Doig play. Of the wells drilled to date i n 2011 on t he play, f ive (5.0 net)

horizontal wells were explorator y in nat u re a nd successf u l ly fou nd new pools and proved new lands.

Birchcliff also continues to expand its infrastructure to control the play and reduce operating costs per barrel of oil equivalent. “This provides economic ef f iciencies as well as strategic control and reserve capture in the area,” the company said.

To date in 2011 at its Worsley light oil play, Birchcliff has drilled 14 (14.0 net) horizontal and one (1.0 net) vertical successful development oil well. The company said its 2011 drilling program to date has successf ul ly delineated and extended the pool to the west and south, which increased its estimate of original oil in place. “ W it h t h i s s u c c e s s , a s i z e a bl e number of follow-up locations have b ee n ide nt i f ied…. T he wate r f lo o d response is meeting our expectations, and we are committed to further expansion of the waterf lood area, particularly in the southeast area of the pool,” Birchcliff said.

— Daily Oil Bulletin

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Northeastern Alberta

Cenovus cutting costs, lessening environmental footprint

By Lynda Harrison

OCT/10

OCT/11

OCT/10

OCT/11

WELLS SPUDDED

52

120

WELLS DRILLED

63

126

Photo: Joey Podlubny

he said. Foster Creek supply costs are $38 per barrel while five years ago they were $48 per barrel. When oil prices fell in 2009 the company was still generating “pretty good” cash flow, he said.

Costs have dropped, he said, for two reasons: one is the delinking of WTI and natural gas prices, and the other is the company’s use of technologies such as wedge wells and electrical submersible pumps. Technologies of the future will drop the supply cost further, he added.

A project’s steam to oil ratio (SOR) is one of the most important parameters of economic success and environmental friendliness, the meeting heard. The average SOR in California, still one of the largest thermal producers, is 5.5, said Chhina.

“That just tells you how long we’ve come in improving this business, and the goal is to continue to drop this SOR. At Christina Lake, we think we can get the

SOR down to 1.7. We proved it earlier this year, but now we’re ramping up for Phase C.” Phase C of Cenovus’s SAGD operation at Christina Lake came on stream in August with oil production ahead of schedule. Phase C is currently processing about 5,000 barrels of oil per day and is expected to average between 18,000 and 20,000 barrels per day gross during the third quarter.

The company’s projects under construction— Christina Lake phases D and E and Foster Creek phases F, G and H—are experiencing the effects of inflation, he said. While previous projects were built at $18,000 per flowing barrel, Christina Lake is being built at $22,000 per flowing barrel.

Foster Creek’s SOR is 2.1, meaning 2.1 barrels of water have to be converted to steam and injected into the reservoir to extract one barrel of bitumen.

“I dare you to go around the world and find any project that’s executed with this much disturbance with 70 per cent recovery factors and makes good money,” said Chhina, referring to Foster Creek, currently producing more than 100,000 barrels per day. “You’ll see a lot of mess when you visit a lot of the old projects. This is state of the art and we just got started.

We’ve got a long ways to go yet.”

He said hiring local workers and small contracts kept Foster Creek, built in the expensive boom years of 2006-08, on budget and on time. It also helps that Cenovus can hire people for one project and, once completed, send them to another in a “manufacturing” approach.

Mining projects don’t have that option, he noted.

Also, as the company has so many projects on the go, its components can be built in Cenovus’ own fabrication yard

Cenovus Energy says its cost-cutting efforts make its SAGD operations profitable at prices as low as $38 per barrel WTI.

Amid controversy over how to get oilsands production to new markets, and oil’s consumption in general, a Calgary-based in situ oilsands company continues to look for ways to bring down costs and reduce its environmental footprint, an energy audience heard in October.

H a rbi r C h h i n a , e xe c ut ive v ice president, oilsands, for Cenovus Energy Inc., told more than 200 attendees at the Oilsands Review Speaker Series event at the Calgary Petroleum Club that while his company and the steam assisted gravity drainage (SAGD) industry have come a long way in 10 years and that it has a bright future, there is much to be improved.

Although currently fetching much higher prices, Cenovus can make a nine or 10 per cent after-tax return at as low as $38 per West Texas Intermediate (WTI) barrel at its Foster Creek SAGD project, NORTHEASTERN ALBERTA WELL ACTIVITY

OCT/10

OCT/11

WELL LICENCES

150

68

▼

▲

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2011

45

Northeastern Alberta

in Nisku, Alta., said Chhina. The company built 144 modules there for Phase C of Christina Lake and is expanding the yard by 50 per cent.

Cenov us builds projects in three phases and if prices collapse during one phase it can slow down work on subsequent phases, he said.

In situ oilsands projects like Cenovus’s use huge amounts of water at their water treatment plants. “Sometimes I feel we haven’t designed these plants properly.

All the junk, the backwash from the filters and stuff all goes into one tank, which is our skim tank, and so what we’re looking at now is to clean up every stream

“Ten years ago, I used to tell the guys if it has an 80 per cent probability of success, let’s put it in the field. Today, I tell the guys 30 per cent. If you think there’s a one-in-three chance the thing will work, let’s get after it because we’re spending so much capital, $1 billion in operating costs, you don’t have time to monkey around. You have to get after this stuff now.”

Now testing solvent-aided processes for the third time, Cenovus is not stopping at steam and butane, he said. The company is also look ing at C 1 to C 8 including methane, propane, hexane and octane because more t han one

“If you've got a bright idea, we'll listen to it.”

— Harbir Chhina, executive vice-president, oilsands, for Cenovus Energy Inc.

because our operation’s become so big.”

The company is investigating the use of a variety of technologies including hydrocyclones and avoiding the use of warm lime softeners. “If you’ve got a bright idea, we’ll listen to it,” he told his audience.

Cenovus is working on introducing more mechanical separation to improve reliability and reduce its reliance on a large amount of chemicals. Chhina said he feels like he’s addicted to heroin because he can’t run the company ’s water treatment plants without them.

The company is currently working on 140 technologies, all at varying stages of development, and he would be happy if 20 per cent of them reach fruition.

solution will be needed, he said, adding Cenovus will soon start a CO2-steam test as well.

Last week the company drilled a well in the Wabasca area of Alberta, testing combustion with up to 120-degree temperatures. Combustion “is working like a charm,” he said.

One of the challenges Cenovus faces is opposition from environmentalists, he noted. The overall oil and gas industry has not done a good enough job of telling its story and educating the public about what it’s up to, he said, so Cenovus is running ads on television, trying to get the message out, he said.

“Major oil companies can’t find enough oil to replace what they’re producing, and

80 per cent of the world’s reserves are controlled by national governments.

Fossil fuels are here for at least the next 50–100 years. We don’t have any alternatives, and they ’ll come but they ’ll come slowly.”

California will have a new low-carbon f uels standard as of next year and Cenovus’s projects meet that standard because of their low SOR, said Chhina.

“Once they find out we meet them they’ll probably get pissed off and change that standard, but we’ll probably find another way to comply,” he said.

T he Un ited St ate s on ly st a r ted importing Cenovus’s bitumen three or four years ago when Americans started realizing t hey were r unning out of heavy oil, and now the country needs TransCanada Corporation’s proposed Keystone XL pipeline as much as Canada does, he said.

“But t hey did wake us up,” said Chhina. “We didn’t expect controversy like this on a pipeline, so we have to start to look for other alternatives to get our oil out of North America, and Cenovus has started to sell oil to Asian count r ies t his year t hrough K inder Morgan Canada Inc.’s Trans Mountain oil pipeline. That pipeline’s going to get expanded, too. There’s lots of controversy around these pipelines, but we need these pipelines and so does the rest of the world.”

Cenovus’s oil, likely from its oilsands operations, was not sold directly to Asia, Rhona DelFrari, spokeswoman, told the Daily Oil Bulletin. Chhina was referring to a small amount of oil that was sold to a Canadian company, which in turn sent it to Asia, said DelFrari.

Connacher advancing solvent recovery A 12-week “steam-with-solvent” field t r ia l i n t wo stea m assisted g rav it y drainage (SAGD) wells at Connacher Oil and Gas Limited’s Algar project resulted in higher bit umen production rates and a lower steam-oil ratio, the company reported.

Dat a recent ly subm it ted to t he Energy Resources Conservation Board

46

DECEMBER 2011 • OIL & GAS INQUIRER

registry, which will shortly be available in the public domain, demonstrated that during the months of August and September, bitumen production volumes from the Pad 203 wells were up 23 per cent from the April 2011 baseline. These results were accompanied by an average SOR reduction of 15 per cent, said Connacher, noting that the results of the

proprietary “SAGD+” process surpassed its original expectations.

Volumetric concentrations of solvent injection were generally in the 10 per cent range and, as part of the field trial, have been increased to 15 per cent during the month of October, which Connacher anticipates will result in further productivity improvements.

Northeastern Alberta

In addition, solvent recover y has reached 85 per cent or better, well above levels considered necessar y for economic application, with regard to the relative values of bitumen and solvent, said the company. Connacher believes t his is t he f irst time t his has been achieved at field level.

T he baseline wells were chosen because they had achieved a stable level of production since being placed on stream in 2010 when Algar began production. The SOR decrease was also limited by the necessity to manipulate steam injection rates to maintain normal operating pressure during the continuing high-pressure steam injection phase at Algar. This will be modified at a later date as it transitions its Algar operation to low-pressure SAGD, said Connacher.

As data is assimilated and assessed, the trial may be expanded to include additional wells on the pad, it said. In addition to the obvious benefit of higher per-well productivity, which can serve to enhance the present worth of longlife reserves, Connacher anticipates that

Production volumes are up 23 per cent with the solvent flood. over time the application of SAGD+ can also contribute to improved recovery factors, but to what extent remains to be determined.

However, any decision to expand the pilot, which would also require facility modifications to fully capture and recycle the recovered solvent, will await a full-cycle economic assessment of the project, said Connacher. With the current economic and capital market uncertaint y, the company suggested it would be prudent to constrain new investment activity in the short term until there is evidence of increased clarity on crude oil, solvent and bitumen pricing, and the outcome of other business initiatives currently underway has been determined.

— DAILY OIL BULLETIN

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Central Alberta

Why CO2 EOR never took off in Alberta

By Pat Roche

OCT/10

OCT/11

OCT/10

OCT/11

WELLS SPUDDED

347

316

WELLS DRILLED

338

324

Photo: Joey Podlubny

What went wrong?

Bruce Peachey, an Edmonton-based consulting engineer and longtime EOR advocate, offered some answers in a presentation to a Petroleum Technology Alliance Canada (PTAC) conference on CO2 management.

Topping the list is rate of return.

“It can’t just be economic. It has to be more economic than anything else that shareholders’ money can be invested in,” Peachey said.

And drilling wells for primary production is still more economic than CO2 EOR. Recent advances in horizontal drilling and multistage fracturing have commercialized light oil resources that were previously uneconomic.

“CO2 EOR reserve estimates must be based on economic reality, not wishful thinking,” Peachey said. “So we really

need to look at what the economics are that are going to drive the people that have to implement CO2 EOR—not just saying if we provide the CO2 , it will happen.

Because it really won’t unless it’s the best economic option.”

Making CO 2 EOR more economic than other investments is a challenge, he acknowledged, but noted the investment climate for CO2 EOR is much friendlier in the United States than in Canada.

“The U.S. Department of Energ y spends a lot of money doing this. We hardly spend any money doing similar things in Canada,” Peachey said. While the Alberta government’s $2-billion commitment to putting CO2 in the ground does indeed have an EOR component, the primary goal is CO2 disposal.

Peachey believes any major producer considering a significant investment in CO2 EOR will look at the United States first because of the advantage of existing operations, cheap CO2 and public policies specifically crafted to encourage EOR with few strings attached to greenhouse gas management.

“They’re not doing EOR to get rid of greenhouse gases, they’re doing it to make money. The same as Weyburn,” he said, referring to the primary reason Cenovus’s predecessor, PanCanadian Petroleum Limited, decided to sanction Canada’s first big CO2 EOR investment.

“CO2 EOR operators in the U.S. are doing it when and where it’s economic with more plentiful and lower-cost CO2. Because they can get those natural CO2 sources, it’s cheap. They can do it a lot more economically than we can,” Peachey said.

Although much of the CO2 for U.S. EOR projects comes from wells drilled exclusively to produce CO2 , the gas is also captured from natural gas processing plants—and that business has some big players.

CO2 floods haven't taken off in Alberta because producers have better investment opportunities,

according to Bruce Peachey.

A f e w y e a r s a go, it s e e me d a s i f en hanced oil recover y (EOR) using CO2 would be the next big thing in western Canada.

With strong oil prices, proven technolog y and a vast light oil resource amenable to CO 2 EOR, an investment dec ision seemed l i ke a sla m dun k.

Although a few producers have done small projects, no one has plunged into a large CO 2 EOR venture since t he Cenov us Energ y Inc. project at Weyburn, Sask., began injecting 11 years ago.

Even Enhance Energy Inc.—which has Alberta government financial support to build a pipeline to supply CO 2 for EOR—has announced an agreement with only one producer, Fairborne Energy Ltd., to supply CO2 to a relatively small oilfield at Clive in central Alberta.

CENTRAL ALBERTA WELL ACTIVITY

OCT/10

OCT/11

WELL LICENCES

247

273

▲

t

t

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2011

49

Central Alberta

According to the Massachusetts Institute of Technology’s carbon capture and sequestration (CCS) website, ExxonMobil Corporation spent $86 million to start capturing CO2 stripped from natural gas processed at its Shute Creek gas plant at La Barge, Wyo., in 2008. An expansion to capture 50 per cent more CO2 was completed last December.

The gas stream has an extraordinarily high CO2 cut of 65 per cent and the CO2 is sold to oil producers for EOR, according to the MIT website. In a brochure on its website, ExxonMobil boasts the La Barge plant captured nearly four million tonnes of CO2 in 2008, which it says was more than any such project in the world.

“The most successful example of CO2based EOR is in the Permian Basin of western Texas, where significant investment by ExxonMobil and others has resulted in the recovery of an additional one billion barrels of oil production. Approximately 25 per cent of today’s production in the Permian Basin is generated by CO2 enhanced oil recovery,” the ExxonMobil brochure says.

Meanwhile, back in Canada, lack of a large, cheap CO2 supply is cited by producers as a key reason why CO2 EOR didn’t materialize in Alberta.

EOR operators want high-purity CO2.

Flue gases from industrial emitters such as coal-fired power plants contain more nitrogen than CO2 , and separating out the CO2 would be prohibitively expensive.

Bitumen upgraders in the Fort McMurray, Alta., area emit huge volumes of near-pure CO2, but the distance from the light oilfields of central Alberta would make transportation uneconomic.

Peachey agrees the CO2 supply outlook in Alberta is dramatically lower than was expected about two years ago.

A half-dozen bitumen upgraders were proposed for the so-called Heartland Industrial Area near Edmonton, but Peachey believes only North West Upgrading Inc.’s upgrader/diesel refinery is likely to be built.

Royal Dutch Shell plc completed its Scotford upgrader expansion in the Edmonton area earlier this year.

Meanwhile, more of Alberta’s bitumen producers are opting to upgrade their production in the United States. “It is more energy efficient and less greenhouse-gas intensive to upgrade where the refineries are, which is in the U.S. Gulf Coast,” Peachey said.

However, he believes there are opportunities to capture CO2 economically from western Canadian natural gas processing plants that are located near mature light oilfields. Also, he noted one pilot in Saskatchewan is using natural-source CO2.

Natural CO2 deposits are a key reason why CO2 EOR is cheap in certain areas of the United States. Peachey said the U.S. Department of Energy National Energy Technology Laboratory found the cost of getting CO2 is about $2 per thousand cubic feet for U.S. EOR producers.

In western Canada, the lowest-cost supplies are currently vented from gas plants, he said. “And you also need the gas plants to recycle the CO2. So not only do we need the gas plants as potential CO2 sources, we need them to collect the gas and treat it so we can reinject it.”

He added, “So why haul coal to Newcastle? If you’re right under a gas plant that’s venting CO2, why not use CO2 from that source?”

He argues that CO2 EOR has to overcome the misconception that it is done for CCS. “It isn’t. It’s done to make money. The oil companies…that own the reservoirs have to be the ones to make money.”

He said another misconception is that producers will do it if it makes money.

“If it makes the most money they can make with their investment, they will do it.

So if they have other options like drilling horizontal wells in the Bakken that make them more money quicker for the same investment, then that’s what they’re going to do,” he said.

“So just because you give them CO2—even if you give it to them for free—doesn’t necessarily mean they’re going to do it.”

But even the United States hasn’t seen a boom in construction of CO2 pipelines or new CO2 EOR projects. The reason is that competing processes are more economic.

The first competing process is primary production, which is relatively low cost, low energy and high volume. “It’s what shareholders expect oil companies to do,” Peachey said. Hence he believes the technology advances that created a drilling boom in light oil formations such as the Cardium will significantly delay large-scale CO2 EOR. The next competing process is secondary recovery, which has moderate energy and investment demands and is long duration. A PTAC study last decade concluded there are far more waterflood opportunities in western Canada than are currently being pursued.

“If you look at the cost options, it is always cheaper to inject water than to inject a gas,” said Peachey, who believes waterflooding will always be more economic than CO2 EOR. “As soon as you get into gas, there are a lot of costs associated with generating the gas, recirculating it, recompressing it.”

Tertiary recovery, on the other hand, requires patient capital due to long lead times as the project is planned, permitted, piloted, built and the reservoir slowly responds. It requires more energy, more

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Central Alberta

people and more planning. Since most of western Canada’s light oil pools have multiple owners, secondary and tertiary development requires extensive negotiation to reach unitization agreements.

“It’s a lot easier to drill wells one at a time than to do a field-wide development with EOR,” Peachey said.

And unless the CO2 is being captured from a gas plant, CO2 EOR also has the added complication of inter-industry

agreements for the CO2 supply. An electricity producer may want to contract for CO2 disposal over the 40-year life of a planned generating unit, but the western Canadian oil industry doesn’t operate on such long timelines.

Peachey notes the competition for capital doesn’t recognize national borders. “As long as we can still produce primary oil from anywhere in the world, it’s going to be hard to justify EOR…

without some sort of subsidy or support like the U.S. has.”

Describing skilled labour as at least as much of a constraint as capital, he said small oil and gas producers “have a hard time finding people to drill wells, let alone to do EOR.” And given the fragmented ownership of most light oil pools in western Canada and the relatively short life cycle of most junior producers, he noted EOR isn’t typically even on their radar.

Insignia reports Cardium success Two Cardium horizontal wells completed in the second quarter have been placed on production at Pembina, Insignia Energy Ltd. has reported.

The 05-20-048-05W5 well (50 per cent working interest) was placed on production June 14. The well produced for 55 days at a gross average rate of 140 barrels per day of oil and 575 thousand cubic feet per day of natural gas for a total of 235 barrels of oil equivalent per day (118 barrels per day net to Insignia). The well was then shut in to construct new gas gathering facilities. The well is expected to be back on production early in the fourth-quarter.

The 05-19-048-04W5 well (41 per cent working interest) was equipped to produce and be placed on production August 29. The well has produced a gross average rate of 200 barrels per day of oil (80 barrels per day net to Insignia) and negligible gas over the first 33 days of production.

Also at Pembina, Insignia successfully drilled and completed two (1.5 net) Cardium horizontal wells.

The 11-30-048-05W5 well (100 per cent working interest) was drilled and completed in August. The well was production tested for 105 hours at average rates of 395 barrels per day of oil and 135 thousand cubic feet per day of gas for a total of 415 barrels of oil equivalent per day. The well is currently shut in to obtain a reservoir pressure and to equip the well to produce. It is expected to come on production early in the fourth quarter.

The 04-20-048-05W5 well (50 per cent working interest) was drilled in August and completed in September.

It was production tested for 155 hours at average rates of 400 barrels per day of oil and one million cubic feet per day of natural gas. The well was expected to come on production early in the fourth quarter.

At Caroline, Alta., Insignia drilled and completed one (0.9 net) vertical well at 07-36-033-07W5. The well was completed and stimulated in the Lower Mannville and Viking formations. As

was previously disclosed, the well had a production test on the Mannville zone of 5.3 million cubic feet per day at a flowing pressure of 1,000 pounds per square inch.

Production equipment has been installed and the well was placed on production at a restricted rate of1.7 million cubic feet per day on September 14.

Insignia expects its capital expenditures for 2011 to remain within the appr ove d budget of $25 m i l l ion – $27 million. Two (one net) horizontal wells that were to be drilled at Pouce Coupe, B.C., this year now are anticipated to be drilled next year and the capital has been reallocated to the Caroline property.

Planned activities for the remainder of 2011 include drilling two (2.0 net) vertical wells at Caroline and one (0.4 net) horizontal well at Pembina.

Production for the third quarter, based on field estimates, was approximately 2,900 barrels of oil equivalent per day.

— DAILY OIL BULLETIN

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Central Alberta

Nextraction reports production from Provost Viking Pool Next raction Energ y Cor p. has completed testing its first Viking horizontal light oil well in the Provost Viking pool.

The 1,200-metre horizontal leg was fractured in 13 stages and flowed at an average rate of 177 barrels of oil equivalent per day during the first five days of testing.

Average f low rates were comprised of 109 barrels per day of oil and 410 thousand cubic feet per day of natural gas, with a 75 per cent water cut.

To market and sell the natural gas associated with the oil reser ves, the company plans to construct a pipeline as production volumes are sufficient to warrant economic viabilit y of the pipeline. Permitting of the pipeline is under way, and the company expects construction to be completed late in the fourth quarter.

In an effort to determine if gas rates could be reduced to allow the well to continue producing during pipeline

construction, the company inserted a bridge plug in the well isolating five fractured inter vals from production.

A fter installing a downhole pump in the well, the company tested the eight open fractured inter vals for 11 days at an average rate of 73 barrels of oil equivalent per day, comprised of 38 barrels of oil and 210 thousand cubic feet of gas per day, with a 91 per cent water cut.

P r o duc t ion f r om t h e we l l w i l l continue when the pipeline is operat ion a l f or g a s s a l e s . P r o duc t ion facilities to handle the f luid product ion a re cur rent ly being ex pa nded, and Nextraction has sufficient water i njec t ion c apac it y to ha nd le the water.

“Our first well in Provost was successful and is one of the more productive wells in the field,” president Mark Dolar said in a news release. “The gas adds economic benefit to the project, and we

are encouraged to drill a second well in the area.”

Nextraction owns 5.25 sections in its Provost pool including 100 per cent working interest in one section and 50 per cent working interest in an additional 4.25 sections with a joint venture partner.

Reg ulator y approva ls have been received for the second horizontal well and the well is expected to spud shortly.

The company said successful completion of the first well further validates its low-risk drilling inventor y of up to 36 wells. Nextraction has identified 21 locations, which include four locations at 100 per cent interest and 17 locations at 50 per cent interest (resulting in a further 8.5 net wells).

In addition, another 15 locations may be dr illed at a 50 per cent interest (7.5 net wells), should down-spacing be warranted.

— DAILY OIL BULLETIN

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Central Alberta

Duvernay wells to spud this quarter, says Encana Encana Corporation plans to spud three Duvernay shale wells in the fourth quarter of this year—two in the Willesden Green area and one at Simonette, a company official said in October.

“It ’s still early days but we are very excited about the potential of the Duvernay shale to add significant liquids volume to the production profile of the Canadian division,” Mike Graham, president of the division, said in a conference call to discuss third-quarter financial results. “We expect to be even more active in this play next year.

Encana is setting the intermediate casing on its first horizontal Duvernay well and thinks that in the long-term it can get the cost to drill and complete in and around the range of $12 million per well. The wells are relatively deep at about 3,500 metres, he said.

“It’s similar to the Horn River; it’s essentially the same formation just on the south side of the Peace River Arch,” he said.

“With the liquids we forecast, we think anywhere from 100 to 200 barrels per

million cubic feet; we think it’s going to be a very economic project for us,” said Graham. Encana holds about 365,000 net acres in what it believes to be some of the best liquids-rich acreage in the play.

Daily Oil Bulletin records show Encana spudded a horizontal deep pool wildcat October 5 in the Willesden Green area with a surface location of 8-5-43-6W5.

8,000 feet. It plans to complete the well in the fourth quarter with a 25 interval stimulation program.

Encana also saw strong results with a well drilled in the Falher formation.

The well was completed with 20 stimulation intervals and is producing at a rate of about eight million cubic feet per day. Well performance is above

“It’s similar to the Horn River; it’s essentially the same formation just on the south side of the Peace River Arch.”

— Mike Graham, president, Encana Canadian Division

The confidential well has a projected depth of 4,585 metres and the projected zone listed as the Beaverhill Lake.

At the Bighorn resource play, Encana drilled its longest horizontal well to date in the third quarter. The well was drilled in the Wilrich formation and had a total measured depth of about 19,000 feet and a horizontal length of about

expectations both in terms of rate and on a cumulative basis.

“We are ver y encouraged by t he well results we are seeing f rom the numerous zones across the Bighorn key resource play where we have an inventor y of over 700 net locations,” said Graham.

— DAILY OIL BULLETIN

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Central Alberta

Provident spending $280 million in 2012-13 In response to increased opportunities in its key regions, Provident Energy Ltd. plans to increase growth-capital spending to approximately $280 million over the next two years, up from its earlier target of $140 million.

The figure includes $135 million in 2012 and $145 million in 2013. Based on

crude oil storage agreement with a major producer and will be providing two underground storage caverns totalling approximately one million barrels of storage capacity on a fee-for-service basis. As part of the arrangement, Provident will convert one of its existing product caverns and will reconfigure one of the five

At Redwater, Alta., the midstream operator has entered into a 10-year crude oil storage agreement with a major producer and will be providing two underground storage caverns totalling approximately one million barrels of storage capacity on a fee-for-service basis. a substantial increase in new long-term fee-for-service opportunities, Provident’s target is to deploy between $100 million and $125 million in growth capital annually beyond 2013.

At Redwater, Alta., the midstream operator has entered into a 10-year

54

DECEMBER 2011 • OIL & GAS INQUIRER

caverns currently under development to accommodate the storage of crude oil products.

The caverns are expected to be placed into crude oil service in the second quarter of 2012 and the second quarter of 2013.

Incremental capital associated with the

cavern conversions to crude oil has been included as part of Provident’s updated capital guidance.

In its Redwater West region, increased liquids-rich natural gas drilling in the Montney area of British Columbia and growing activity levels in the Alberta oilsands have significantly increased the demand for natural gas liquid (NGL) infrastructure and logistics services.

In the Empress East region, liquidsrich drilling in the Appalachian shale plays in the United States and the company’s expanding footprint as a crude oil and NGL services provider in the Bakken area have increased demand for transportation, storage and fractionation services. “ O v e r r e c e nt we e k s , we h a v e announced long-term, fee-based storage agreements for over 2.5 million barrels of capacity, ref lecting the strong market fundamentals around Provident’s key assets,” Doug Haughey, president and chief executive officer, said in a news release.

— DAILY OIL BULLETIN

Central Alberta

Crocotta boosts 2011 exit guidance, expenditures Due to a successful capital program, Crocotta Energy Inc. is increasing its 2011 exit guidance from 4,500 barrels of oil equivalent per day to a range of 5,500 –6,100 barrels per day, and net capital expenditures to $79 million from $51 million.

Since mid-June, Crocotta has successf ul ly dr i l led a nd completed a n

additional four (3.2 net) Bluesky horizontal wells at Edson, Alta., resulting in 1.0 net Bluesky oil well and three (2.2 net) Bluesky liquids-rich gas wells.

In addition, the company has drilled an additional t wo (1.6 net) Bluesk y horizontals and two (2.0 net) vertical step-out Bluesky wells that have not been completed.

Current production is estimated at over 5,000 barrels of oil equivalent per day, with an additional 1,000 barrels per day restricted due to infrastructure constraints.

Crocotta is currently constructing additional pipelines and facilities to accommodate the additional production with a projected completion date of mid-December.

— DAILY OIL BULLETIN

PSAC expects 2012 to be a better year The 2012 Canadian Drilling Activit y Forecast, released in early November by the Petroleum Services Association of Canada (PSAC), forecasts a total of 15,100 wells drilled (rig released) across Canada for 2012. This is 10 per cent more than the expected final tally of 13,700 for 2011.

“Drilling activity levels are increasing,” said Mark Salkeld, president and chief executive officer of PSAC. “Generally, activity continues to increase across all major activity areas, and we are optimistic that activity is going to continue to rise in the years ahead.”

On a provincial basis for 2012, PSAC estimates 9,255 wells to be drilled in Alberta and 640 in British Columbia, representing

an increase of nine per cent in Alberta and an increase of four per cent in British Columbia over expected 2011 drilling levels. Saskatchewan’s drilling rate in 2012 will see a 15 per cent increase to 4,650 wells. Drilling in Manitoba will see a one per cent increase to 525 wells.

“We all know that oil and gas activity is predicated on price,” continued Salkeld.

“In 2012, oil prices will be adequate to sustain oil drilling–related activity. As a result, we are forecasting an increase in drilling for oil in regions like central and southern Saskatchewan and northeastern Alberta.

Gas pricing, on the other hand, remains relatively low, and we are not expecting any significant gas price turnaround in 2012.

Thus, we are expecting to see 80 per cent of wells drilled in the basin be oil and liquidsrich gas wells. This compares to an expected 74 per cent of drilled wells being focused on oil in 2011.”

PSAC is basing its 2012 forecast on average natural gas prices of C$3.50 per thousand cubic feet (AECO) and crude oil prices of US$85 per barrel (WTI).

“We were being conservative in our forecast for 2012 because of restrained capacity due to labour and equipment shortages,” explained Salkeld. “Now more than ever, industry and government have got to come together to address the pressing issues constraining productivity and the labour issue that is not going away.”

Vermilion expects Cardium output of 6,000 barrels per day Vermilion Energy Inc.’s Canadian production rose to 12,987 barrels of oil equivalent per day in the third quarter from 11,233 barrels per day in the same period last year.

The company’s overall production averaged 34,676 barrels of oil equivalent during the quarter, up from 31,298 barrels in the third quarter of last year.

In the third quarter, production additions from Vermilion’s Cardium program served to more than offset natural declines and volumes used in the commissioning of the oil processing facility in Drayton Valley, Alta.

Vermilion remained focused on development of that light oil play with completion of a 15,000-barrel-per-day oil processing facility, which was commissioned on August 2, on schedule and under budget. Installation of several pipelines to transport Cardium production in the Drayton Valley region was completed during the quarter.

The company reported Cardium-related production of about 4,000 barrels of oil equivalent per day at the end of the third quarter.

The company said it drilled 14 (11.7 net) new operated Cardium wells in the third quarter.

While adverse weather in the third quarter led to delays in the completion and tie-in of Cardium-related volumes, the company said it remains on target to exit 2011 with Cardiumrelated production of more than 6,000 barrels per day with 55–60 net wells on production.

The rest of the new 15,000-barrel-perday oil facility’s capacity will be available to process partner and third-party production— both for fees that will enhance Vermilion’s revenue, Lorenzo Donadeo, Vermilion’s president and chief executive officer, told the company’s third-quarter results conference call.

Ve r m i l ion’s net C a rd iu m pr o duction will probably peak around t he 10,0 0 0 –12 ,0 0 0 -ba r re l-p e r- day

range, Donadeo said in response to an analyst’s question.

Capital plans for the fourth quarter include the drilling of about 14–16 gross operated wells and participation in about eight to 12 gross non-operated wells. This activity level should result in a projected 50-net-well drilling program for the full year of 2011 with an estimated 42–47 of the 2011 wells on production by year’s end.

Vermilion completed all of its Cardium wells in the third quarter using water-based fracture stimulation treatments. Continued implementation of water-based fracs and broader use of multi-well pad-based drilling is expected to continue to reduce overall program costs.

Oil and natural gas liquids production now represents nearly 45 per cent of Vermilion’s Canadian output, up from 37 per cent in the third quarter of 2010.

OIL & GAS INQUIRER • DECEMBER 2011

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Southern Alberta

Juniors squeezed by technological advances, competition from former trusts

By Pat Roche

OCT/10

OCT/11

OCT/10

OCT/11

WELLS SPUDDED

360

156

WELLS DRILLED

356

163

Photo: Joey Podlubny

But the junior producers have the highest gas weighting—which CIBC predicts will average about 52 per cent at year’s end, down from about 61 per cent in the first quarter of 2008.

The disappearance of the income trusts—which as a group favoured growth by mergers and acquisitions rather than through the drill bit—forced the juniors to change their business model.

Blessed with legacy oil assets shed by senior producers, the former trusts are focusing on opportunities opened up by advances in horizontal drilling and multistage fracture technology—in other words, focusing on internal growth rather than acquisitions.

This meant the juniors couldn’t routinely be bought once they grew to, say, 5,000 barrels of oil equivalent per day, or convert to a trust once they topped 10,000

barrels per day. The ensuing soft mergerand-acquisition (M&A) market has forced the small companies to focus more on longerterm internal growth.

But this means that the juniors are competing head-on with the former trusts for services such as pressure pumping.

Gill said dividend-paying corporations (the former trusts) increased capital spending by 85 per cent since 2008, while the juniors have increased spending by 67 per cent. He said the juniors now have a much greater need for new capital as they try to finance their growth into intermediatesized companies.

“So now you have larger, betterfinanced companies…wanting to put more money into the basin, increasing the competition for services,” Gill said. “ A small company with a smaller budget is finding it harder to compete out there against the larger E&Ps [exploration and production companies] who are throwing a lot more money after plays.”

In addition to contending with soft gas prices, a tougher business model, a soft M&A market and competition for services, Gill said juniors must also contend with a changed risk profile wrought by technological advances.

Increasingly long horizontal wells with an ever-increasing number of frac stages has opened up previously inaccessible resources of oil and liquids-rich gas in western Canada.

But w it h t he good news comes increased risk. Relatively expensive horizontal wells now make up a larger percentage of the wells drilled by small producers. “From a risk perspective, this makes a smaller producer more risky on a per-well basis,” Gill said.

“You go from drilling a well that costs $1 million to wells that cost $5 million.

You have, for example, a $40-million budget. All of a sudden, if you have

Natural gas–focused juniors are having a tough time competing with liquids-focused intermediate players.

It’s no secret that western Canada’s small producers as a group have been hardest hit by low natural gas prices because of their heavy gas weighting.

But the juniors have also been hurt by the disappearance of the income trusts— which increased competition for services— and the shift to expensive horizontal multi-frac wells, which made drilling riskier on a per-well basis.

This was part of the message Adam Gill, an analyst at CIBC World Markets, delivered to a CFA Society breakfast in October.

CIBC World Markets estimates the 2011 gas weighting of Canadian senior producers at 40 per cent versus 60 per cent oil and natural gas liquids. It found the former trusts that converted to dividend-paying corporations also have a relatively strong oil weighting, though not as much as the senior producers’ group.

SOUTHERN ALBERTA WELL ACTIVITY

OCT/10

OCT/11

WELL LICENCES

201

98

t

t

t

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2011

57

Southern Alberta

missteps on one or t wo wells, you’re in a serious situation on meeting your guidance. Whereas if you have a misstep on one or two wells when you’re drilling 40 wells, it ’s not such a big deal,” he said.

For this reason, Gill is wary of small companies in costly plays.

“Let’s, just for example, say they’re drilling the Duvernay and they’re drilling four $10 -million wells. A ll of a sudden the risk profile of their drilling program has increased substantially.”

So how is the market reacting to the challenges facing juniors in this changed business environment?

Gill said that since 2008 the market has divided the juniors into “haves” and “have-nots.” Criteria for being a “have” include management teams the market

loves and hot plays such as the Montney in 2008, the Cardium in 2009 and 2010 and a tight carbonate player today.

Not surprisingly, the “haves” trade at a premium to the “have-nots.”

“But what ’s interesting is you’ve seen that premium increase,” said Gill.

“A nd I think this is ref lective of the market understanding that there are bigger challenges for this space than there were in the past. And if you are a ‘have-not’—you don’t have a hot play with a large inventory [or] your management team isn’t maybe as adaptable in horizontal multi-frac wells as maybe the other guys—the market is going to really punish you.

“The premium from 2008 to 2010 was 2.5 times. And now we’re seeing the premium between top-tier companies

and everybody else spread to five times,” he said.

To find bargains, Gill advised investors to search out “have-nots” that the ma rket is under va luing. “ You wa nt to find a value name that can go from being in a ‘have-not’ position to a ‘have’ and get that premium.”

He said one criterion for such investments should be a good oil weighting, or oil growth potential.

A l s o, h e a d v i s e d i n v e s t o r s t o look for producers t hat have a l o w e r- r i s k d r i l l i n g p r o f i l e t h a n average —for example, juniors drilli ng wel l s t hat cost $2 . 5 m i l l ion – $3 million versus those drilling Deep Basin wells costing maybe $5 million– $8 million per well, or $10 million per well in the Duvernay.

Earnings up at Precision One of Canada’s largest drillers has posted higher earnings and revenue in this year’s third quarter.

In the three months (ended Sept. 30, 2011) Precision Drilling Corporation’s net e a r n i ng s r o s e to $8 3.47 f r om $56.29 in last year’s third quarter.

While Canadian activity was hampered by an extended spring breakup early in the third quarter, it rebounded in the quarter’s last two months and is now nearing levels seen last winter, the company said in a news release.

In Canada, Precision averaged 114 rigs operating in the third quarter, 32 rigs more than the 2010 period and up 68 rigs over this year’s second quarter.

With higher levels of market activity and new-build rigs entering the f leet, the company expects its active rig count this winter to surpass that of last winter.

Despite labour concerns expressed by other drilling contractors, Precision said it was able to effectively staff its rigs during the activity ramp-up in the quarter, and expects to be able to continue to do so throughout the winter.

In Canada, Precision reported 51 per cent drilling rig utilization in the third quarter, up f rom 37 per cent in last year’s period. In the year to date, the 58

DECEMBER 2011 • OIL & GAS INQUIRER

company saw utilization rise to 44 per cent f rom 35 per cent in last year ’s period. According to Rig Locator, the contractor’s third-quarter utilization rate was 46.5 per cent, and 40.3 per cent in the year to date (Rig Locator’s calculations exclude experimental and East Coast Canada wells).

S o f a r i n 2 011, t h e c o m p a n y reported “substantially higher” drilling activity in Canada and the United States than last year. Management believes oil and liquids-rich natural gas drilling will continue to drive Tier 1 and Tier 2 rig counts higher in North America.

Measured from spud to rig release, Precision reported 9,487 drill rig operating days in the third quarter, up from 6,816 days in last year’s quarter. In the year to date, the contractor posted 24,393 operating days, up from 19,315 days in the first nine months of 2010.

Precision said it believes the vast majorit y of oil and liquids plays are economic at oil prices below those seen in the past year. According to industry sources, on Oct. 14, 2011, the U.S. active land drilling rig count was up about 21 per cent from the same point in 2010, while the Canadian drilling rig count had also increased about 21 per cent.

In the third quarter, Precision’s gross capital expenditures for the purchase of property, plant and equipment were $219.68 million, up from $35.79 million in the 2010 period. Capital spending in the period included $136.59 million for expansion capital and $83.09 million for maintenance and upgrading of existing assets.

In the United States and international markets, the company’s average active rig count of 106 rigs in the third quarter was up 13 rigs over the 2010 period and up four rigs over this year’s second quarter.

T his year, total capital spending is expected to reach about $880 million, of which $398 million was spent i n t he f i rst n i ne mont hs. T he tota l includes $14 4 million in sustaining and in f rast r uct ure spending, based upon expected activity. As well, $508 million is slated for expansion capital, including the cost to complete rigs from the 2010 new-build rig program a nd some of t he new-bui ld r igs for 2011. Total capital spending includes about $228 million to upgrade 15–20 rigs in 2011 and purchase long leadtime items.

— DAILY OIL BULLETIN

Southern Alberta

More oil pipelines needed, says study Planning and approvals are urgently needed to meet the timelines necessary for bringing future pipeline projects on stream to meet the re-emerging need for crude oil pipeline capacity out of western Canada, says a Calgary consultant.

Depending on future crude production, more pipeline capacit y such as TransCanada Corporation’s Keystone XL or a significant alternative will be needed by 2014-16, Tom Wise, a vicepresident with Pur v in & Gertz, Inc. and the author of a new report, Crude Pipeline Restrictions Leaving Western Canada, said in an inter view. In the short term, the 591,000-barrels-per-day Keystone XL with its committed volumes could attract volumes from the Enbridge Inc. mainline, which could take a few years to fill up again, he said.

However, even with Keystone XL in operation, additional pipeline capacity would be needed for Canadian crude exports by 2017-18, according to Wise. In the Canadian Association of Petroleum Producers’ (CAPP) 2011 forecast growth scenario, oilsands-blended bitumen and synthetic crude production would rise to 2.74 million barrels per day in 2017 from a projected 1.93 million barrels per day this year.

While the current capacity of major pipelines exiting western Canada is 3.49 million barrels per day compared to a supply of 2.7 million barrels per day, the CAPP forecast projects a western Canadian oil supply of 3.85 million barrels per day in 2017.

Most of the crude export pipelines out of western Canada have been working near capacity, except for those operated by Enbridge, which is the largest transporter of Canadian crude with 1.87 million barrels per day of capacity, Wise noted.

“Purvin & Gertz estimates that the current takeaway capacity to deliver crude to refineries and connecting carriers exceeds the nominal capacity, leaving western Canada by more than half a million barrels per day,” he said.

New refining capacity for Canadian heav y crude coming on stream in the United States Midwest and Gulf Coast will increase the takeaway capacity.

However, the growth in light Bakken production from North Dakota imported

i nto C a n ada to acce s s E nbr idge ’s Ca nadia n main line ult imately w i l l reduce the capacity of the line to export Canadian crudes, he said. Nearly 200,000 barrels per day of crude is coming into Cromer, Man., and Regina, Sask.

An Enbridge affiliate’s North Dakota pipeline transports nearly 185,000 barrels per day of oil to the Enbridge mainline at Cromer. The Bakken Expansion projec t, wh ic h wou ld add a not her 145,000 barrels per day of capacit y, is currently awaiting a decision from the National Energy Board following a hearing earlier this month.

Plains A ll A merican Pipeline L.P. a l so pla n s to re ve r se it s Wa sc a n a Pipeline by late next year to transport 50,000 barrels per day of crude from it s ter m i nus on t he Sask atc hewa n-

supply available to Enbridge may be less than its capacity for a few years because of committed volumes on Keystone XL, said Wise.

Pur v in & Ger tz’s study, which is now available, estimates the takeaway capacity in different years, based on refineries and connecting carriers. It determines the spare capacity at present and adds capacity for new pipeline projects. It compares Pur vin & Gertz and CAPP supply forecasts with usable pipeline capacity in the future.

The study identifies major bottlenec k s i n t he E nbr idge s y stem a nd assesses the impacts of new proposals such as the Flanagan South and Wrangler projects.

“We look at Enbridge at the border and then we go further downstream

“Purvin & Gertz estimates that the current takeaway capacity to deliver crude to refineries and connecting carriers exceeds the nominal capacity leaving western Canada by more than half a million barrels per day.”

Montana border to the Enbridge mainline. The Wascana pipeline would be fed by a new 12-inch pipeline f rom Trenton, N.D., that would connect to it at the border.

Beyond that, at Superior, Wis., and Chicago, Enbridge’s f ull capacit y of 1.8 million barrels per day is not fully used because there is not enough takeaway or refining capacity, said Wise.

E nbr idge, t houg h, i s prop osi ng to expand Line 5 from Superior to Chicago by 50,000 barrels per day.

Beyond Chicago, Enbridge currently has an open season for 400,000 barrels per day of capacity on the proposed Flanagan South Pipeline from Flanagan, Ill., to Cushing, Okla. Enbridge, in a joint venture with Enterprise Products Partners, is also proposing to build the 800,000-barrel-per-day Wrangler pipeline from Cushing to the Gulf Coast with a mid-2013 start-up date.

For heavy crude, Enbridge’s nominal capacity should match takeaway capacity by 2014, after the start-up of major refining projects. A lthough bitumen blend supply is growing rapidly, the

t h rough Super ior a nd Ch icago a nd Sarnia [Ont.] and we sort of work back from there to see how much they could actually pump,” he said. “They can’t pump more out of western Canada than they can deliver downstream.”

One project to provide additional capacit y for western Canadian light crude is currently before the National Energy Board. In response to customer dema nd, E nbr idge i s prop osi ng to reverse the 30-inch Line 9 to operate in an eastward direction from the Sarnia terminal to the North Westover station, with a target in-service date in the fall of 2012.

The $16.91-million project would transport light crude to the Westover ter m i na l for del iver y to con nec ted r e f i ne r ie s, i nc lud i ng I mp e r i a l O i l Limited’s Nanticoke refinery. The target will be to maintain an annual capacity of 152,000 barrels per day with an initial design capacity of 169,000 barrels per day on Line 9 (Sarnia terminal to Westover terminal), expandable to 250,000 barrels per day.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • DECEMBER 2011

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Saskatchewan

Aquistore Project plans first well for carbon capture project

By Pat Roche

OCT/10

OCT/11

OCT/10

OCT/11

WELLS SPUDDED

324

342

WELLS DRILLED

341

367

Photo: Joey Podlubny

of CO2 to oil companies for enhanced oil recovery (EOR).

In June, Sask atc hewa n’s Energ y and Resources Minister, Bill Boyd, said negotiations with potential EOR operators were under way a nd ex pressed optimism that a CO2 sales pact could be reached.

Meanwhile, planning for t he Aquistore project—which is not tied to oil production— continues and the group hopes to drill a CO2 injection well next month, pending rig and crew availability, said Ken Brown of the Petroleum Technology Research Centre (PTRC), based in Regina, Sask., which is leading the project.

B e s i d e s t h e P T RC , S a s k P o w e r and t he Saskatchewan gover nment, Aquistore partners include oilfield giant Schlumberger Limited, which will operate the drilling of the well; SaskEnergy

Incorporated, the province’s natural gas distributor; oil pipeline giant and CCS proponent Enbridge Inc.; Reginabased refiner and refined products marketer Federated Co-operatives Limited a nd f e de r a l ly f u nde d Su s t a i n able Development Technology Canada.

The Aquistore project itself (excluding Sask Power’s CO 2 capture investment) is expected to cost $21.4 million, Brown said.

C O 2 w i l l b e i nj e c t e d i n t o t h e W i n n ip eg- D e adwo o d f or m at ion at 2,200 metres. Brown said casing and other equipment have been procured for the planned well. The surface location isn’t far from the power generator’s coal mine. “ It ’s ac t u a l l y b e i n g d r i l le d on SaskPower land, so it’s not a major issue from local agriculture’s point of view,” he said.

Brown discussed the Aquistore project in a presentation to a Petroleum Technology Alliance Canada conference on carbon management.

Southeastern Saskatchewan is home to Canada’s only large CO 2 injection scheme, the EOR project at Weyburn operated by Cenovus Energy Inc. Brown said the Weyburn project, which began injecting 11 years ago, is producing about 30,000 barrels of oil per day—20,000 barrels per day of which are attributed to the CO 2 f lood.

Weyburn’s CO 2 is delivered through a 180-mile pipeline from a coal gasification plant in North Dakota.

Unlike Weyburn—which is a commercial oil production venture designed to turn a profit—Aquistore is a research and demonstration project using technologies for the capture, transportation and storage of CO 2 . The goal is to involve research institutions, policymakers, industry and the public.

Apache CO2 project. A third CO2 project is now underway in Saskatchewan.

W hile A lberta’s four planned carbon capt ure and storage (CCS) projects have been getting attention because of the province’s pledge of $2 billion, a Saskatchewan research group has been preparing its own project.

If everything goes according to plan, the Aquistore project would inject one million tonnes of CO2 per year into deep saline aquifers, starting in 2014.

Saskatchewan, through its governmentow ned elec t r ic ut i l it y, Sa sk Power, wants to capture CO 2 from a planned expansion of the Boundary Dam coalfired power plant near Estevan in southeastern Saskatchewan.

C a rb on c apt u r e i s e x p e c te d to account for roughly two-thirds of the power project’s estimated $1.24-billion price tag. SaskPower has said it would only do carbon capture if it could offset at least some of the cost through the sale SASKATCHEWAN WELL ACTIVITY

OCT/10

OCT/11

WELL LICENCES

346

375

▲

▲

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • DECEMBER 2011

61

Saskatchewan

“We’re trying to develop the best technologies, best methods for saline formations. It’s similar to some of the ones that are planned for Alberta. But it’ll have its differences and each one will provide unique information,” Brown said.

Depending on crew availability, the Aquistore project plans to acquire highresolution 3-D seismic data over 30 square kilometres before year’s end. The goal is to gather baseline information, identify potential faults that could affect storage integrity and characterize the storage complex.

Brown said the project is looking at installing a permanent seismic array over 3.5 square kilometres. While permanent installation of downhole sensors for passive seismic monitoring isn’t uncommon, permanent surface arrays are extremely rare.

He said a time-lapse seismic study is being done to test the feasibility of the proposed array geometry. The receiver burial depth is under discussion due to mining in part of the survey area.

Monitoring wells are to be drilled next year. Proposed monitoring methods

include real-time pressure and temperature monitoring, passive seismic, downhole fluid sampling, time-lapse logging, time-lapse VSPs, groundwater monitoring and soil-gas monitoring.

Under the current schedule, smallscale CO2 injection would begin next year and ramp up through 2013.

Dependi ng on how quic k ly t he planned Alberta projects start injecting, Brown said Aquistore could be Canada’s first pure (meaning not EOR) commercialscale CCS project.

Photo: Joey Podlubny

Set fracturing rules or government will: lawyer

Fracking operations are under increasing scrutiny by both the public and regulators.

If Canada’s oil and gas sector does not police its use of hydraulic fracturing, government will enter the field and do so, an industr y conference heard in October.

“If the industry doesn’t voluntarily come up with its own rules, obviously the regulators will,” said Duff Harper, an environmental lawyer with Calgary firm Blake, Cassels & Graydon L LP. 62

DECEMBER 2011 • OIL & GAS INQUIRER

Give n t he mome nt u m for c h a nge, much of it from the public, Harper told his audience it’s time to “get ahead of the curve.”

“It makes sense, and really, at this point, this is what the public demands.

I think the days of proprietary control over fracking fluids is going the way of the dodo bird,” he said. Earlier, he discussed the tension between landowners,

intent on knowing what’s in fracturing fluids used in wells on their lands, and service companies that may prefer to guard their proprietary formulas.

“The public is saying, ‘It’s great for companies to have proprietary control over fracking f luid, but if it contaminates the water I may be drinking, I want to know what it is. What are you actually adding?’” he said, noting the pendulum of disclosure has swung from not releasing information toward releasing complete information.

Harper said there’s “not a lot of legislation” that specif ically addresses unconventional gas or hydraulic fracturing in Canada. Historically, the provinces concerned have relied on their conventional oil and gas legislation, although he suggested changes are in the wind, adding that the provinces, rather than Ottawa, will likely lead the way.

Harper is not certain that regulators will move to impose a full-disclosureof-additives regime, but said “ we’re moving in that direction. Several states in the U.S. have indicated there will be disclosure. I would expect that some provinces will bring in legislation that will require disclosure. W hether it ’s right across the board, I can’t say, but the industry is behind it,” as evidenced by new principles adopted recently.

In September, B.C. Premier Christy C l a rk a n nou nc e d he r gove r n me nt would implement a new, online registry to track fracturing f luid additives and disclose fracking operations. In t hat respect, Br itish Columbia may

Saskatchewan

be ahead of A lber ta, where Har per said, “we’ve still got our standard regulatory approach.”

“There haven’t been a lot of legislative changes yet. We’ve got changes on other industry issues, but not with respect to hydraulic fracturing, per se,” he told the Canadian Institute’s conference, Responding to Increasing Natural Gas Supply in North America.

When legislation regulating hydraulic fracturing does come, it will likely come from those provinces where development of shale gas and unconventional resources is being pursued or planned.

In particular, he cited British Columbia, Alberta, Saskatchewan and Quebec.

G e ne r a l ly, Ha r p e r sa id Ca n ada is seeing “a move afoot for transparency” when it comes to disclosure about the facts of fracturing operations and the f luids involved. Last month, the Canadian A ssociation of Pet roleum Producers (CAPP) introduced five principles to guide CAPP members involved in hydraulic fracturing.

Those principles include a promise to safeguard the quality and quantity of groundwater, to measure and disclose industry’s water usage in fracturing, to support the use of fracturing fluids with the least environmental risk, and to encourage disclosure of fluid additives.

CAPP’s principles represent a “complete sea change from proprietary control,” Harper said. “They may not be reasonable from a proprietar y view, but they’re reasonable principles from a balanced, env ironmental point of view. I would expect that industry will look at those very closely, with respect to adherence.”

W het her or not t he federal government will assert jurisdiction over hyd r au l ic f r ac t u r i ng i n Ca n ada i s another question, and Harper said much would depend on Ottawa’s approach, if it enters the field at all.

“If they can come up with a trigger that, constitutionally, they have authority over, that’s certainly possible. One of the ways would be through water contamination associated with fisheries.

If that exists, it may be a possibility, but it would not be universal to all fracking scenarios, because [many] would u s e g r ou nd w ate r a nd not i mp ac t surface water.”

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63

Central Canada

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Suncor CEO calls for national energy conversation

Suncor president and CEO Rick George.

Canada needs a national sustainable energy strategy, and governments can play an important part in engaging citizens in a discussion about this country’s energy future, Suncor Energy Inc.’s top executive said in October.

“As a society, we need to get to a constructive dialogue on greening our economy and the energy that we need to fuel it—and doing so on practical and realistic terms,” Rick George, Suncor president and chief executive officer, said in an acceptance speech after being named the Energy Council of Canada’s Energy Person of the Year.

“A nt i- oi l s a nd s c a mp a i g n s . T he polarized debate over the Keystone XL pipeline. NIMBYism. These all point to the importance of getting our citizens engaged in a realistic, fact-based dialogue about Canada’s collective energy future,” he said.

W hile a national strateg y would respect provincial jurisdiction, it would also allow for a broad, integrative perspective—including the strong bonds

between Canada and the United States on energy, environment and economy, said George. “It must also include access to new markets in Asia.”

A s u s t a i n able e ne r g y s t r ateg y, though, must go well beyond the issue of basic energy production, he said. “We need to look at how we use energy: the cars we make, how we plan and build cities, the role of mass transit, and a stronger conservation ethic from business and consumers.”

Ca nada’s l i kely energ y requ i re ments in 10, 20, and even 50 years dow n t he road need to be assessed based on what k i nd of soc iet y t h is cou nt r y wa nt s to bu i ld, look i ng at ways in which today’s energy strengths bridge to a strong energy future, audience members were told.

George said it’s impossible to overstate the importance of long-term vision and a collaborative effort.

“Industry needs to look well beyond annual balance sheets, governments need to look beyond elections, and environmental organizations need to look beyond what they’re ‘against’ and figure out what they’re ‘for’ in terms of real solutions,” he said.

W hile the Suncor chief executive officer ack nowledged the legitimate role of these organizations in the discussion, “what we all need to keep in mind is that the dialogue cannot focus on only one aspect of the challenges our society faces,” he said. “We can’t focus on environment and forget the economy or social considerations. Just as we can’t focus on jobs and forget about the environment or social well-being.”

George said he has seen dramatic and positive change in the oilsands over his past 20 years as Suncor chief executive officer, and that has been most apparent in the area of technology.

“In the early days of our industry, the technology focus was directed toward the challenge of reducing costs; it was a simple matter of survival,” he said.

“Obviously, that’s still very important.

But more and more we’re seeing the

technology focus go toward reducing energy inputs and land disturbance, as well as improving land reclamation and other changes required to reduce our environmental footprint.”

These cost and environmental goals are not incompatible, George emphasized. “We must do both. Because what it really comes down to is that we need to develop this resource in a way that harnesses both Canadian and global intellectual capital, is consistent with Ca nad ia n v a lue s, a nd b enef it s a l l Canadians,” he said.

W h i le s ome p e r s on s c ho o s e to ig nore t he improvements t hat have been made and assume that decadesold data can simply be extrapolated into the future, that’s neither true nor fair, said George.

“We don’t look at the future of automobile technology based on the model of a 1985 Chevy. We don’t even look at hybrid technology based on the model of a first-generation Prius. Think about the computer you were using 15 years ago— could you compare it to an iPad 2?”

Te c h nolog y w i l l b e t he g a me c ha nger needed to ef fec t ively a nd r e s p o n s i bl y m a n a g e t h e oi l s a n d s resource, he said.

“Just as with many technological changes, improvements in the oilsands have mostly been a journey with a lot of small steps,” he said. “A nd while improvements don’t usually happen in a single leap, we have had a few that have transformed the industry.”

Last year, Suncor rolled out a new technology—tailings reduction operations—that will significantly reduce the need for ponds to store liquid mine tailings, he said.

“Five new storage ponds that would have been built under ‘business as usual’ will now never happen,” George pointed out. “And with this technology, all but one of the existing tailings ponds will be much more rapidly reclaimed. The time to reclaim disturbed land to natural habitat will be reduced by decades.”

— DAILY OIL BULLETIN OIL & GAS INQUIRER • DECEMBER 2011

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Tight oil resource huge, says North Dakota researcher

Tight oil production is expected to reach 2 million barrels per day by 2020.

Low-permeability formations in Canada and the United States could contain 6.48 billion to 8.36 billion barrels of technically recoverable oil, a Calgary conference heard in October.

Contributing the biggest share of the technically recoverable tight oil resource is the Bakken formation of North Dakota, Montana and Saskatchewan with an estimated 3.65 billion to 4.3 billion barrels, said James Sorensen, senior research manager at the University of North Dakota’s Energy & Environmental Research Center in Grand Forks, N.D. The estimates—which Sorensen discussed at a Petroleum Technology Alliance Canada tight oil and gas forum—were compiled from a variety of sources, including the U.S. Geological Survey, the U.S. Department of Energy and state agencies.

The second-biggest to the fourth-biggest (depending on whether the low or high range of the estimate is used) is the Cardium formation of Alberta with 660 million to 1.89 billion barrels of technically recoverable oil.

“The Eagle Ford in Texas is at 900 million barrels of estimated recoverable oil resource, based on what I was able to come up with

in reasonable sources and by talking with folks in industry,” Sorensen said, adding that people working in the Eagle Ford “feel pretty strongly that [Eagle Ford] has actually got the potential to be on par with the Bakken.”

Recoverable oil resource in the tight Monterey formation in California is estimated at 718 million barrels, but Sorensen noted this play faces “a lot of regulatory issues.”

He said other tight oil plays to watch are the Niobrara in Colorado and Wyoming (240 million barrels of recoverable resource), the Atoka-Cherokee in Colorado (146 million barrels) and the Mancos in New Mexico (75 million barrels).

“There’s definitely a lot of activity going on in those. And as more work is done, I think those numbers may go up as well,” Sorensen said.

Though best known for shale gas, the Barnett shale in Texas is also estimated to contain 56 million barrels of recoverable oil resource.

Sorensen’s smallest estimate of technically recoverable resource is for the Exshaw (Bakken equivalent) formation in Alberta and Montana (30 million barrels of oil), but that play is in its infancy.

On the production side, the leader has been the North Dakota Bakken/Three Forks, which produced more than 350,000 barrels per day last year, up from less than 50,000 barrels per day around the middle of the last decade, he said.

The Bakken in North Dakota is deeper, which makes exploitation more capital intensive, but initial production (IP) rates are higher. “To see an IP over 1,500 barrels a day is not uncommon,” Sorensen said.

As in Canada, North Dakota Bakken wells have steep decline curves during their first year of production, but Sorensen said the wells continue to remain economically viable. While cautioning that it’s too soon to say what the cumulative production may be for a North Dakota Bakken well, Sorensen said he is “almost ready” to concur with estimates of 500,000 barrels of oil.

North of the border, Bakken oil production climbed to a peak of 64,000 barrels a day in Saskatchewan and 16,000 barrels a day in Manitoba, said Ken Brown of the Petroleum Technology Research Centre, based in Regina, Sask. He said Saskatchewan’s Bakken output recently fell, but attributed this to the months of extremely wet weather and flooding that halted field activity.

Sorensen expects tight oil production from the North Dakota portion of the Bakken and Three Forks formations will average 500,000 barrels per day next year. In fact, Sorensen said some analysts are predicting North Dakota’s Bakken/Three Forks oil output will climb as high as 800,000 barrels per day.

Considering that the recovery factor in the Bakken is only one to two per cent, an increase of a couple of percentage points would translate into a huge increase in production.

“There [are] already operators out there looking for ways to bump that up,” Sorensen said. “And I’m sure that the history of the oil production industry will tell you that will happen.”

He said technologies to boost Bakken recoveries may include CO2 injection and even polymer flooding.

In Texas, Eagle Ford tight oil output was about 77,000 barrels per day last year and is rapidly expanding, Sorensen said.

— Daily Oil Bulletin OIL & GAS INQUIRER • DECEMBER 2011

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Wanted: Sales Account Manager JuneWarren-Nickle’s Energy Group (JWN) is looking for you to be our Sales Account Manager. This is a permanent, full-time commission-based position in our Edmonton office. We are the most trusted source of energy information in Canada for over seventy years.

We want you because you thrive in a high-energy, commissionbased environment and you have substantial knowledge of the oil and gas industry. If this sounds familiar, contact us today by sending your resume to hr@junewarren-nickles.com or visit www.junewarren-nickles.com to find out more.

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business advice

BUSINESS INTELLIGENCE Timing the market

A look at the factors to consider when deciding when to sell

By Adam Mallon

In my role as a mergers and acquisitions advisor to the oilfield service

preferring to wait until revenues and profitability approach pre-crash levels.

industry, one of the most frequent questions I get from owners contemplat-

It is hard to blame any owner for taking this approach, as most buyers will

ing a sale of their business is, “Is this the right time to sell?” Given the volatil-

put the highest weight to the most recent year’s results, and if those aren’t

ity of the markets over the past couple of years, it is a good question and

strong, you can expect that offers will be affected. While buyers purchase

one that is rarely easy to answer.

based on optimism and with an eye to the future, when pricing a company

To obtain the best possible price, a company has to be posting strong results. Growth is always a good selling feature, but in a slow economy, sta-

they always give the heaviest weight to what the company has actually accomplished as opposed to what it hopes to do in the future.

bility can be just as important. The more potential buyers that can be identi-

It is important to remember that the current optimism could be fleeting.

fied, the better, as it may lead to competition for the opportunity to acquire,

The marketplace can change very quickly, as we saw in fall 2006. We had sev-

and some buyers may be willing and able to pay more than others to secure

eral companies garnering significant interest from income trusts, but when

the deal. Ultimately, though, there are a number of factors to consider and

the federal government passed the bill eliminating advantages associated

some business owners may choose to go to market even if they are not in

with the trust structure, many of them immediately pulled back.

this type of ideal situation.

The internal factors surrounding a sale are often much more impor-

The external economy can play a significant role in several ways.

tant in determining timing than the external ones. Shareholder disputes,

Generally, in a recession or depression, there will be fewer transactions

divorce, injury, retirement or simply a desire to do something different

taking place. Obviously, during a downturn, performance may be hampered,

can make it easy to decide to take your company to market. When meet-

which tends to depress both the value you might receive as well as the

ing with clients, we often point out that the owner is likely to make much

number of interested parties. While some buyers may see an opportunity

more money owning the company than they will by selling it, so economics

to purchase an underperforming company at a lower price, many worry that

cannot be the biggest determinant of when to sell. If a shareholder is look-

they won’t be able to right the ship and pass in favour of companies that

ing for a lifestyle change, delaying going to market will only increase the

haven’t seen as severe a drop in performance.

time until he or she is able to have that.

A downturn across the board can remove many buyers from the market

The last and possibly most important thing to remember when trying

due to their own underperformance, or even just because of uncertainty. In

to time the market is that selling a business is not a quick process. Most

fall 2008, we were marketing several companies and saw the buyers with-

of the time, we expect that a sale mandate may take between six and 18

draw, simply because with the markets crashing around them, they wanted

months to complete, but we have also had good, strong companies that

to know where the bottom was before committing any resources.

have taken three to four years to sell. Finding the right buyer who is will-

With a return to optimism in the markets, a lot of these buyers are look-

ing to pay the right price can take a long time, and often circumstances

ing at acquisitions again. Both public companies and private equity groups

may mean that the right buyer isn’t ready to buy at the time the company

started returning to the market, bolstered by little debt and cash-rich bal-

first hits the market. While it may help to hit the market during a boom

ance sheets, and with a measure of urgency as investors tend to look harshly

time, there are no guarantees as to when the company may finally sell.

upon unemployed cash.

As a result, if the decision to sell is made, it is helpful to get the company

On the other side, coming off some of the worst years in a decade, a lot of business owners are holding off on entertaining discussions about selling,

on the market early as opposed to waiting until what is perceived to be an optimal time.

Recent MNP transactions and announcements in the oilfield services sector: • • • •

Hank’s Maintenance & Service Company Ltd. in Estevan, Sask., sold to Ironbridge Equity (June 2011) KEM Enterprises Ltd. in Fort McMurray, Alta., sold to Entrec Transportation Services Ltd. (September 2011) Healey Enterprises Ltd. in Fort Nelson, B.C., sold to Stuwalk Energy Inc. (September 2011) American Process Holdings Inc. in Edmonton, Alta., sold to CCS Corporation (October 2011)

For a complete list of MNP transactions, please see www.mnpcorporatefinance.ca.

OIL & GAS INQUIRER • DECEMBER 2011

69

Political Cartoon

Advertisers' Index

70

ABB Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Dragon Products . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Activated Environmental Solutions Inc . . . . . . . 68

Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 47

Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 36

Annugas Compression Consulting Ltd . . . . . . . . . 7

Falvo Electrical Supply Ltd . . . . . . . . . . . . . . . . . 56

Platinum Energy Services Corp . . . Inside front cover

ATCO Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . 63

General Motors of Canada Ltd . . . . . . . . . . . . . . 10

Propak Systems Ltd . . . . . . . . . . . . . . . . . . . . . . . 3

Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . 64

Guard-All Structures . . . . . . . . . . . . . . . . . . . . . 40

Beaver Plastics Ltd . . . . . . . . . . . . . . . . . . . . . . . 43

Joint Utilities Safety Team . . . . . Outside back cover

Risley Equipment Inc . . . . . . . . . . . . . . . . . . . . . . 48 Stewart Steel Inc . . . . . . . . . . . . . . . . . . . . . . . . . 60

Bilton Welding and Manufacturing Ltd . . . . . . . . 66

Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . . 68

Black Sivalls & Bryson (Canada) Ltd . . . . . . . . . . 50

LoTech Manufacturing Inc . . . . . . . . . . . . . . . . . . 68

Brent Gedak Welding . . . . . . . . . . . . . . . . . . . . . 56

LJ Welding & Machine . . . . . . . . . . . . . . . . . . . . . 48

Brother’s Specialized Coating Systems Ltd . . . . 51

MCI Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

Brownlee LLP . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Mercer Valve Canada . . . . . . . . . . . . . . . . . . . . . 36

Canadian Standards Association . . . . . . . . . . . . 60

Meridian Mfg Group . . . . . . . . . . . . . . . . . . . . . . 18

CanElson Drilling Inc . . . . . . . . . . . . . . . . . . . . . . 24

Millennium Directional Service Ltd . . . . . . . . . . 54

CARES Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 40

Vertigo Theatre Society . . . . . . . . . . . . . . . . . . . 52

Contain Enviro Services Ltd . . . . . Inside back cover

Northgate Industries Ltd . . . . . . . . . . . . . . . . . . 56

Virtus Group LLP . . . . . . . . . . . . . . . . . . . . . . . . 53

Diversified Glycol Services Inc . . . . . . . . . . . . . . 63

Northstar . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . 12

Do All Metal Fabricating . . . . . . . . . . . . . . . . . . . 64

Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . 52

ZCL Composites Inc . . . . . . . . . . . . . . . . . . . . . . . 19

DSG Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Ocean Fluids & Filtration . . . . . . . . . . . . . . . . . . 40

DECEMBER 2011 • OIL & GAS INQUIRER

Suncor Energy Inc . . . . . . . . . . . . . . . . . . . . . . . . 44 Systech Instrumentation Inc . . . . . . . . . . . . . . . . 9 Trans Peace Construction (1987) Ltd . . . . . . . . . 43 TransGas Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 United Centrifuge . . . . . . . . . . . . . . . . . . . . . . . . 22 ULTERRA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23