Oil & Gas Inquirer April 2012

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Midstream expands to capture liquids growth, gas export opportunities and oilsands diluent needs Plus: Instrumentation and

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Photo: Aaron Parker

Feature

The Medicine Hat & District Chamber of Commerce Proudly presents the biennial

Redwater is emerging as a nexus between the oilsands and the natural gas industry, with natural gas liquids providing diluent to ship raw bitumen.

Medicine Hat Exhibition & Stampede

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chief executive officer, during the company’s fourth-quarter results conference call.

“If you look at some of the independent data that’s put out there, the Western Canada Sedimentary Basin has some of the most economic gas because of the liquids components in North America today,” Bertram said. “I think you’re seeing some Canadian producers bringing some of that capital back from the U.S. dry shale plays, and we hope to redeploy in some liquids-rich plays. We’re just in the right spot, so I continue to remain optimistic that the first areas to get shut in and areas that won’t be drilled are the dry gas areas.”

In the fourth quarter, Keyera invested $36.9 million to acquire additional ownership interests in several gas plants in the west-central and foothills areas of Alberta, including the Strachan, Minnehik Buck Lake, Bigoray and Paddle River gas plants.

A number of producers continue to target liquids-rich gas from the Glauconite zone. In addition, many of the high-value land parcels purchased in 2011 targeting the liquids-rich Duvernay shale are also in this area. As a result of producer success in 2011 and their prospective future production, Keyera is considering an expansion of the Carlos pipeline, and the possible construction of a new pipeline to deliver gas to Rimbey from lands west of the plant.

If there is sufficient producer support for these projects, Keyera may also consider an expansion of the Rimbey gas plant to recover additional quantities of ethanerich NGLs, it said.

In the Simonette region, a producerowned 12-inch gathering pipeline began

May 8 & 9, 2012

GOLF TOURNAMENT

delivering gas to the plant in the fourth quarter. Another producer is currently constructing a 65-kilometre, 12-inch gathering pipeline to Keyera’s Simonette gas plant from lands east of the plant.

Other producers are actively drilling wells and targeting multiple geological zones around the plant.

Producers in the area have provided sufficient expressions of interest to allow detailed engineering estimates to be prepared for a plant expansion and addition of deep-cut facilities. Should commitments be secured and terms and conditions met in a timely manner, Keyera’s goal would be to complete the project by late 2013.

Refurbishment of the turbo-expander at the Minnehik Buck Lake gas plant is complete and currently undergoing commissioning.

At the Strachan gas plant, the upgrade of the turbo-expander is expected to be complete in the second half of 2012. Projects to enhance propane recoveries at the Brazeau River and Nordegg River gas plants were also completed in the fourth quarter and will allow producer customers to extract significantly more propane from their gas streams, said Keyera.

With the anticipated increase in NGL production in western Canada, Keyera is evaluating an expansion of its Fort Saskatchewan fractionator, which would allow the facility to accept an ethane-rich stream of NGLs for processing. Keyera is currently in discussions with customers interested in securing capacity in the new facility and, assuming commercial terms

May 7, 2012

can be reached, construction could begin later in 2012.

Pembina Pipeline Corporation is also expanding its midstream operations in response to increasing liquids production, chief executive officer Bob Michaleski said in announcing its year-end results.

At its Cutbank complex, Pembina plans to expand Musreau’s shallow-cut gas processing capability by 50 million cubic feet per day, at a cost of $26 million and subject to regulatory and environmental approvals that should be in service by the middle of this year, said Michaleski.

Pembina has ordered much of the long– lead time equipment for its new Saturn and Resthaven gas processing plants and is currently in the consultation phase. It is working with its stakeholders and regulatory bodies on route selection and environmental planning for the pipeline portion of the work and is completing engineering work, he said.

Subject to regulatory and environmental approval, both projects should be complete in the latter part of 2013.

The company continues to investigate several other opportunities to expand its gas service business. Many new developments are close to its existing infrastructure, and with new technologies and a supportive price for NGLs, it expects to see the need for increased gas-handling requirements, he said.

“These new gas volumes, in combination with the liquids value embedded in the gas, have created interest in new and updated gas plants with enhanced liquids-extraction capacity and ethane-plus transportation opportunities,” says Michaleski.

Demand for diluent is also driving expansion in the midstream. Keyera is well underway in advancing its plans to be a significant diluent supplier to the oilsands.

In the Edmonton/Fort Saskatchewan area, the first of the two oilsands service agreements with Imperial Oil Limited began in December, with the completion of solventhandling facilities at the Alberta Diluent Terminal (ADT). These facilities allow the delivery of solvents by rail for Imperial’s Kearl oilsands project.

Work on Keyera’s Fort Saskatchewan Condensate System (FSCS), including a 21-kilometre, 20-inch condensate pipeline connection to the Polaris pipeline and a new pump station at the Edmonton terminal, continued during the fourth quarter and should official show be complete by sponsor mid-year 2012. FSCS is an integrated network of infrastructure through which Keyera will provide diluent-handling services for Imperial Oil and Husky Energy

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FEATURES

6

APRIL 2012 • OIL & GAS INQUIRER

13

Building the web

17

Easy access

By Darrell Stonehouse Midstream expands to capture liquids growth, gas export opportunities and oilsands diluent needs

By Darrell Stonehouse Innovators drive down cost of wellsite monitoring while making data access mobile

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G e n era l Ne w s

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Slave Point carbonate cranking up

Devon Canada targets liquids

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Stats at a Glance

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Editor’s Note

Vol. 24 No. 3 editorial Editor

Darrell Stonehouse | dstonehouse@junewarren-nickles.com

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An $18-billion failure

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It’s provincial election time in Alberta, and already the public is being misdirected with trivial issues like MLA committee pay and new impaired driving laws.

As of March, however, there hasn’t been a peep about the biggest issue facing the province—the $18 billion it is expected to lose this year because it has failed to diversify markets for growing oilsands production.

Synthetic crude oil was trading at $21 per barrel under West Texas Intermediate (WTI) in mid-March as oversupply cut demand at U.S. refineries. Western Canadian Select, a heavy blend of crude shipped from Alberta, was trading at a $34-per-barrel discount. Add to this WTI trading at around an $18-per-barrel discount to global barrels like the North Sea standard Brent Crude.

In mid-March, synthetic crude was selling at almost a $40-per-barrel discount to global prices while Canadian Select was facing a differential of over $50 per barrel.

According to Raymond James Ltd., raw bitumen producers, who must dilute product with condensate for it to flow to markets, are in even worse shape. Facing a 35 per cent discount against WTI, high condensate prices above WTI are adding to costs and lowering the implied price of bitumen being exported to around $45 per barrel. All told, CIBC World Markets estimate that the province is losing $18 billion per year because of the failure to diversify markets for oilsands production, and this state of affairs is expected to continue until at least 2014.

How did we end up here?

As owner of the resource and ultimate decision maker on when and how the oilsands are developed, the buck stops with the provincial government.

Five years ago, at the peak of the last boom, it was obvious that oilsands production was going to skyrocket. When the province should have been working with industry and other governments to develop new markets for the resources owned by Albertans, instead they were messing with the royalty structure.

They could have partnered with British Columbia on a revenue-sharing agreement to get production to the coast and onward to Asian markets. Instead, they decided to blow $2 billion on carbon sequestration schemes.

One could argue that the government couldn’t have predicted the rise of tight oil plays in the United States and Canada adding to supply, or the economic collapse in 2008 cutting U.S. demand, which has lead to the current situation. But underlying that is the knowledge that U.S. oil demand has been stagnant and declining since 1998, and the rise of demand in China hasn’t exactly been a secret.

Five years of inaction and complacency are now costing the province billions of dollars that could be going into health care, education or—better yet—returned to its rightful owners: the people of Alberta.

The Redford Conservatives need to make the case they’ve learned from this failure and have a plan to correct it. Otherwise, in the near future we could be talking about Premier Smith.

That is if the whole sad affair even becomes a blip on the public’s radar.

N E X T

I S S U E

May 2012 In our May issue, we review activities in the red-hot Bakken play in southeastern Saskatchewan, while tracking the latest fracture stimulation and completions technologies.

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

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MINI B&W FSC logo OIL & GAS INQUIRER • APRIL 2012

9

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

Feb 2011 Mar 2011 Apr 2011

353 650 419

294 974 472

127 222 112

774 1,846 1,003

Jun 2011 Jul 2011 Aug 2011

209 105 452

124 43 183

100 97 93

433 245 728

Sep 2011 Oct 2011 Nov 2011

1,028 626 557

357 259 241

146 19 36

1,531 904 834

Dec 2011 Jan 2012 Feb 2012

568 215 491

300 131 177

72 35 50

940 381 718

MONTH

OIL

GAS

Feb 2011 Mar 2011 Apr 2011

723 1,069 618

378 1,081 509

Jun 2011 Jul 2011 Aug 2011

428 298 922

Sep 2011 Oct 2011 Nov 2011 Dec 2011 Jan 2012 Feb 2012

D RY

SERVICE

T O TA L

38 64 46

99 164 81

1,238 2,378 1,254

197 97 262

12 15 28

183 88 80

820 498 1,292

1,448 1,153 1,170

445 321 331

24 20 27

155 49 42

2,072 1,543 1,570

988 419 846

359 190 244

27 15 21

115 31 52

1,489 655 1153

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

TOTAL

Feb 2011 Mar 2011 Apr 2011

69 55 41

131 186 172

Feb 2011 Mar 2011 Apr 2011

321 316 183

6 8 11

7 4 11

334 328 205

Jun 2011 Jul 2011 Aug 2011

54 56 40

419 479 519

Jun 2011 Jul 2011 Aug 2011

217 185 413

25 5 2

89 3 13

331 193 428

Sep 2011 Oct 2011 Nov 2011

92 35 92

611 646 738

Sep 2011 Oct 2011 Nov 2011

352 457 524

4 29 4

29 46 32

385 532 560

Dec 2011 Jan 2012 Feb 2012

58 53 66

796 53 119

Dec 2011 Jan 2012 Feb 2012

332 142 296

4 10 6

61 8 20

397 160 322

*From year toto date * from year date

561266 V.J. Pamensky Canada Inc 1/4h · qpv STATS 10

OTHER

APRIL 2012 • OIL & GAS INQUIRER

FAST NUMBERS

663

1,317

U.S. rigs drilling for gas in March; a 10-year low.

U.S. rigs drilling for oil in March; a 25-year high.

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, February 13, 2012 Source: Rig Locator

Alberta, March 2012 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada Alberta British Columbia

Manitoba Saskatchewan WC Totals

AC T I V E

OIL WELLS

Alberta

Mar 12

GAS WELLS Mar 11

Mar 12

Mar 11

378

210

588

64%

Northwestern Alberta

162

92

2

3

45

14

59

76%

Northeastern Alberta

50

50

0

0

6

13

19

32%

Central Alberta

207

172

17

11

68

54

122

56%

Southern Alberta

68

43

42

101

497

291

788

63%

TOTAL

487

357

259

115

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada, February 13, 2012 Source: Rig Locator

Alberta, March 2012 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada Alberta

AC T I V E

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

Alberta

Mar 12

Mar 11

BITUMEN WELLS Mar 12

Mar 11

518

234

752

69%

Northwestern Alberta

2

3

19

17

British Columbia

28

11

39

72%

Northeastern Alberta

0

0

50

50

Manitoba

12

9

21

57%

Central Alberta

17

11

63

56

Saskatchewan

153

42

195

78%

Southern Alberta

24

44

0

0

WC Totals

711

296

1,007

71%

TOTAL

43

58

132

123

796016 Expertec Van Systems Inc 1/4h · qpv OIL & GAS INQUIRER • APRIL 2012

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413088 Annugas Compression Consulting Ltd full page 路 fp feature

Illustrations: Photos.com

Feature

Building the

Web

Midstream expands to capture liquids growth, gas export opportunities and oilsands diluent needs

By Darrell Stonehouse

W

ith natural gas prices floundering at lows not seen in a decade, western Canadian midstream operators are refocusing their efforts to take advantage of a boom in natural gas liquids (NGL) exploration and development in the western reaches of the basin, while building out infrastructure to supply oilsands diluent needs. The midstream is also being stretched to handle coming international exports of natural gas.

Midstream companies have never had more opportunities than they do now, both from bitumen production growth and NGL development in the Western Canadian Sedimentary Basin, a panel of midstream companies told attendees at a recent CIBC investor conference at Whistler, B.C. “I think it’s fair to say that, from our viewpoint, we see this period that we’re entering as probably the best growth period for companies of our kind in close to the history of the business,” said Doug Haughey, president and chief executive officer of Provident Energy Ltd., which was recently bought by Pembina Pipeline Corporation.

Haughey pointed to the recent growth in liquids-rich gas drilling as one factor driving investment in new infrastructure.

In addition, there is significant growth in demand from oilsands for diluent and NGLs as a solvent, he said.

Also, probably contrary to what anyone predicted five years ago, the industry is seeing substantial new ethane-based investments in petrochemicals in North America, while there is potential for new capacity additions in Alberta and the potential for new capital to be expended in the Sarnia region of Ontario, he said.

Haughey said he believes the fundamentals driving growth in the midstream are very strong. Alberta can consume all the ethane the industry produces, all the butane will stay in Alberta and the province has far more condensate demand than supply, he said. He added that the market for propane, which is mainly the only product that leaves the province in large quantities, is going to be robust.

While Pembina has historically been strong on pipelines, it is now also strong on gas liquids and related businesses—for

example, the expansion of its NGL transportation system to Edmonton and a doubling of capacity at its Redwater fractionator, he said.

There is also significant potential for new diluent opportunities and a “huge amount” of liquids production coming on stream, according to Haughey.

Another major midstream operator, Keyera Corp., says it is evaluating several expansion projects to accommodate anticipated growth in producer volumes where significant drilling occurred throughout last year around its Strachan, Rimbey, Simonette and Edson gas plants.

In these areas, producers are targeting the Montney, Duvernay, Glauconite and other liquids-rich zones. As a result of this activity, throughput increased significantly at all these gas plants during the year, and activity in the areas west and southwest of the Rimbey gas plant continues to be very strong, the company reported along with its fourthquarter results.

Keyera is “reasonably optimistic” that it is in the right spot to see continued drilling in liquids-rich areas, said Jim Bertram, OIL & GAS INQUIRER • APRIL 2012

13

Photo: Aaron Parker

Feature

Redwater is emerging as a nexus between the oilsands and the natural gas industry, with natural gas liquids providing diluent to ship raw bitumen.

chief executive officer, during the company’s fourth-quarter results conference call.

“If you look at some of the independent data that’s put out there, the Western Canada Sedimentary Basin has some of the most economic gas because of the liquids components in North America today,” Bertram said. “I think you’re seeing some Canadian producers bringing some of that capital back from the U.S. dry shale plays, and we hope to redeploy in some liquids-rich plays. We’re just in the right spot, so I continue to remain optimistic that the first areas to get shut in and areas that won’t be drilled are the dry gas areas.”

In the fourth quarter, Keyera invested $36.9 million to acquire additional ownership interests in several gas plants in the west-central and foothills areas of Alberta, including the Strachan, Minnehik Buck Lake, Bigoray and Paddle River gas plants.

A number of producers continue to target liquids-rich gas from the Glauconite zone. In addition, many of the high-value land parcels purchased in 2011 targeting the liquids-rich Duvernay shale are also in this area. As a result of producer success in 2011 and their prospective future production, Keyera is considering an expansion of the Carlos pipeline, and the possible construction of a new pipeline to deliver gas to Rimbey from lands west of the plant.

If there is sufficient producer support for these projects, Keyera may also consider an expansion of the Rimbey gas plant to recover additional quantities of ethanerich NGLs, it said.

In the Simonette region, a producerowned 12-inch gathering pipeline began 14

APRIL 2012 • OIL & GAS INQUIRER

delivering gas to the plant in the fourth quarter. Another producer is currently constructing a 65-kilometre, 12-inch gathering pipeline to Keyera’s Simonette gas plant from lands east of the plant.

Other producers are actively drilling wells and targeting multiple geological zones around the plant.

Producers in the area have provided sufficient expressions of interest to allow detailed engineering estimates to be prepared for a plant expansion and addition of deep-cut facilities. Should commitments be secured and terms and conditions met in a timely manner, Keyera’s goal would be to complete the project by late 2013.

Refurbishment of the turbo-expander at the Minnehik Buck Lake gas plant is complete and currently undergoing commissioning.

At the Strachan gas plant, the upgrade of the turbo-expander is expected to be complete in the second half of 2012. Projects to enhance propane recoveries at the Brazeau River and Nordegg River gas plants were also completed in the fourth quarter and will allow producer customers to extract significantly more propane from their gas streams, said Keyera.

With the anticipated increase in NGL production in western Canada, Keyera is evaluating an expansion of its Fort Saskatchewan fractionator, which would allow the facility to accept an ethane-rich stream of NGLs for processing. Keyera is currently in discussions with customers interested in securing capacity in the new facility and, assuming commercial terms

can be reached, construction could begin later in 2012.

Pembina Pipeline Corporation is also expanding its midstream operations in response to increasing liquids production, chief executive officer Bob Michaleski said in announcing its year-end results.

At its Cutbank complex, Pembina plans to expand Musreau’s shallow-cut gas processing capability by 50 million cubic feet per day, at a cost of $26 million and subject to regulatory and environmental approvals that should be in service by the middle of this year, said Michaleski.

Pembina has ordered much of the long– lead time equipment for its new Saturn and Resthaven gas processing plants and is currently in the consultation phase. It is working with its stakeholders and regulatory bodies on route selection and environmental planning for the pipeline portion of the work and is completing engineering work, he said.

Subject to regulatory and environmental approval, both projects should be complete in the latter part of 2013.

The company continues to investigate several other opportunities to expand its gas service business. Many new developments are close to its existing infrastructure, and with new technologies and a supportive price for NGLs, it expects to see the need for increased gas-handling requirements, he said.

“These new gas volumes, in combination with the liquids value embedded in the gas, have created interest in new and updated gas plants with enhanced liquids-extraction capacity and ethane-plus transportation opportunities,” says Michaleski.

Demand for diluent is also driving expansion in the midstream. Keyera is well underway in advancing its plans to be a significant diluent supplier to the oilsands.

In the Edmonton/Fort Saskatchewan area, the first of the two oilsands service agreements with Imperial Oil Limited began in December, with the completion of solventhandling facilities at the Alberta Diluent Terminal (ADT). These facilities allow the delivery of solvents by rail for Imperial’s Kearl oilsands project.

Work on Keyera’s Fort Saskatchewan Condensate System (FSCS), including a 21-kilometre, 20-inch condensate pipeline connection to the Polaris pipeline and a new pump station at the Edmonton terminal, continued during the fourth quarter and should be complete by mid-year 2012. FSCS is an integrated network of infrastructure through which Keyera will provide diluent-handling services for Imperial Oil and Husky Energy

Feature Inc., under long-term agreements in place with both companies.

The expected capital cost is approximately $60 million. Approximately $36.8 million has been spent since work began on the project in 2010. Subject to weather conditions and equipment delivery schedules, the balance of the expenditures required to complete these projects is expected to be incurred in 2012.

A l so i n Ja nua r y, t he compa ny announced an agreement with a subsidiary of Enbridge Inc., to solicit interest in the possible construction of a diluent transportation pipeline and a rail-and-truck terminal to serve the oilsands. Keyera is in discussions with oilsands producers with the intention of securing sufficient interest to underpin these projects.

With the glut in dry gas supplies, the midstream is likely to be stretched as new liquefied natural gas (LNG) terminals are built to export gas to higher-demand international markets in Asia. Growth in natural gas production in the United States is destroying demand for western Canadian gas, stranding trillions of cubic feet from markets.

“In essence, what we’re looking at is the Canadian market could have nearly three billion cubic feet per day of supply that needs to find an alternative home, besides the U.S. and besides the domestic Canadian market,” Rick Margolin, manager, west region with BENTEK Energy LLC, told a recent Canadian Energy Research Institute natural gas conference. “That’s why Canada really needs to develop its exports.”

There are a number of LNG export projects in the planning stages, with the proposed KM LNG Operating General Partnership (KM LNG), or Kitimat LNG export facility, which is 40 per cent owned by its managing partner Apache Canada Ltd., 30 per cent owned by EOG Resources, Inc., with 30 per cent held by Encana Corporation, the furthest ahead.

A final investment decision was expected soon, but some of the partners signalled recently that a decision may not happen until mid-year or perhaps later in 2012.

“They are targeting an in-service date of 2015,” Margolin said. “That’s a pretty optimistic scenario. I think our LNG group at BENTEK has said that they’ve only seen one LNG project in the world ever get built on time.”

The B.C. government has said it’s committed to having the province’s first LNG plant in operation by 2015 and three LNG facilities operating by 2020.

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rs o t a v Inno down e e driv f wellsit le i o cost oring wh it mon g data in mak mobile ss acce house

Photos: Photos.com

By Darrell

Stone

T

he digital oilfield continues advancing as technology providers drive down costs of wellsite monitoring while making the information more easily interpreted and readily available as communication technology evolves.

Calgary-based Advanced Flow Technologies Inc. (AFTI) of Calgary released Watch-DOG, a low-cost technology for monitoring oil wells, in January. Watch-DOG provides producers with secure Internet access to simple flow/no flow information that tells producers if a well is flowing or not.

“Watch-DOG provides the basic information oil producers need to know. Just because a pumpjack is going up and down does not mean that oil is being pumped,” says Len Johnson, president of AFTI. With Watch-DOG, anyone with an Internet connection can see if the well is producing oil, and the technology uses simple colourcoded icons on a map to show the location of production problems.

Watch-DOG, which is smaller than a breadbox and can easily be user installed, is so low-cost it can pay back in as little as a day or two, adds Johnson.

The new oil well monitoring technology costs a fraction of the more complex supervisory control and data acquisition systems and provides information that is extremely easy to access and understand.

The Watch-DOG technology for monitoring gas wells passed its first wintertime test with flying colours.

Watch-DOG is designed to monitor gas wells for freeze-ups, alerting producers with colour-coded icons on a map when a well is in danger of freezing.

“On average, 15 per cent of our clients’ wells were in danger of freezing during last week’s cold snap,” said Johnson in mid-January.

“Watch-DOG clearly identified which wells were in danger of freezing and which wells could be ignored. With today’s low gas prices, it is more important than ever to provide information to field staff, which allows them to target only wells which are in danger of freezing.

“One of our clients, a major gas producer, has advised us that their wintertime production losses were half of last year’s experience as a result of using our technology,” added Johnson.

Zedi Inc. is working on a number of fronts to bring down the cost of wellsite monitoring and to make the process more user-friendly and efficient. The Smart-Alek is Zedi’s flagship oilfield monitoring system. Smart-Alek is a remote plug-andplay EFM device that automatically monitors oil and gas production data from the field and transmits it to the customer on a secure web-based user interface, Zedi Access. It collects high-resolution data directly from the wellhead and delivers it via existing cellular or satellite infrastructure to any authorized user with Internet access, at any time of the day. Data is stored both locally and centrally, providing backup to ensure it isn’t lost.

In April, Zedi announced its latest product offering, Zedi Access Mobile, which puts the power of the Zedi Access web application directly in the palms of oil and gas producers. With no software to download, users can immediately access existing Zedi OIL & GAS INQUIRER • APRIL 2012

17

Feature

Photo: Joey Podlubny

Wellsite data is moving from the laptop to the smartphone as the technological revolution continues.

Access functionality, such as notification of sensors in alarm state and viewing graphical representations of sensor trends, on any smartphone, including the iPhone.

Zedi Access Mobile, spawned from feedback at customer advisory group meetings, leverages technology to improve work practices and maximize a field operator’s production operations experience. It has experienced significant interest in the market since commercialization. In addition to Zedi Access Mobile, Zedi continues to develop mobile capabilities for its other software applications including Roughneck, an asset management and health, safety and environment application.

“Our customers were clear on their need to access data through portable devices while in the field,” says James Freeman, Zedi’s chief marketing officer. “With this development, Zedi continues to show leadership in innovations that help customers improve operational efficiency. Delivery of accurate, timely information to the smartphone is a strong part of that future.”

Previously, data displayed on Zedi Access was only accessible through a desktop or laptop computer, reducing a field operator’s ability to react to situations that arise throughout the day. Using a web-enabled smartphone and Zedi Access Mobile, a field operator can access information immediately, eliminating the need to carry a laptop or return to the field office. This delivers tangible improvements in both efficiency and effectiveness. Zedi Access Mobile also provides a quick and simple view of trends, which can be invaluable for the early detection of developing issues that could prohibit production, such as freeze-off or hydrate formation at the wellhead.

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General News

Photo: Joey Podlubny

Fracturing operating practices unveiled by CAPP

CAPP is launching fracturing operating practices to ensure industry is responsible in protecting water resources.

The Canadian Association of Petroleum Producers (CAPP) has announced new Canada-wide hydraulic fracturing operating practices designed to improve water management, and water and fluids reporting for shale gas and tight gas development across Canada.

“The hydraulic fracturing operating practices demonstrate the Canadian natural gas industry’s continued efforts to ensure responsible resource development and protection of Canada’s water resources,” said David Collyer, CAPP president. “Applying these new operating practices will contribute to improving our environmental performance and transparency over time, both of which contribute to stronger understanding of industry activity and better relationships with the public, stakeholders and government.”

Developed by natural gas producers, the hydraulic fracturing operating practices apply to all CAPP members exploring for and producing natural gas in Canada.

In September 2011, CAPP announced the industry’s Guiding Principles for Hydraulic Fracturing, which obligate

CAPP members to sound wellbore construction, fresh water alternatives, recycling where feasible, voluntary water reporting, fracturing fluid disclosure, and technical advancement and collaboration.

The operating practices announced in February support the guiding principles and strengthen industry’s focus on continuous performance improvement.

CAPP said it expects the hydraulic fracturing operating practices to inform and complement regulatory requirements.

In its hydraulic fracturing operating practices, the association said Canada’s shale and tight gas industry supports a responsible approach to water management and is committed to continuous performance improvement. Protecting the country’s water resources during sourcing, use and handling is a key priority for industry, it said. “We support and abide by all regulations governing hydraulic fracturing operations, water use and protection.”

In addition, CAPP commits to the following specific operating practices.

• Fracturing fluid additive disclosure: To disclose on a well-by-well basis the

chemical ingredients in fracturing fluid additives that are identified on Material Safety Data Sheets for each additive, including trade names, general purpose and concentrations. This information will be made publicly available.

• Fracturing fluid risk assessment and management: To better identify and manage the potential health and environmental risks associated with fracturing fluid additives, and ultimately increase the market demand for more environmentally sound fracturing f luids. The process for developing well-specific risk management plans for hydraulic fracturing fluid additives will be made publicly available.

• Baseline groundwater testing: To develop domestic water well sampling programs and to participate in regional groundwater monitoring programs; establish a process for addressing stakeholder concerns regarding water well performance; and to continue to collaborate with government and other industry operators.

• Wellbore construction and quality assurance: To ensure that wellbores are designed and installed in a manner t hat maintains integ r it y before hydraulic fracturing begins, including creating a continuous cement barrier to protect groundwater and developing remedial plans in the unlikely event that a wellbore is compromised.

Wellbore construction and quality assurance practices will be made publicly available as they relate to this practice.

• Water sourcing, measurement and reuse: To safeguard surface water and groundwater quantity by assessing and measuring water sources, ensuring no withdrawal limits are exceeded, monitoring water sources as required to demonstrate the sustainability of the source, as well as collecting and reporting water-use data. Water measurement, sourcing and reuse practices will be made publicly available.

OIL & GAS INQUIRER • APRIL 2012

21

General News

Fluid transport, handling, storage • and disposal: To identify, evaluate and mitigate potential risks related to the transport, handling, storage and disposal of fluids (i.e. fracturing fluids, produced water, flowback water and fracturing fluid wastes) and ensure a quick response to accidental spills.

Fluid transport, handling, storage and

disposal practices will be made publicly available.

“The establishment of Canada-wide hydraulic fracturing principles and practices is part of the natural gas industry’s ongoing efforts to ensure safe development of Canada’s shale gas resources,” said Collyer. “Shale gas can and is produced responsibly ever y day across

Canada and the United States with almost 200,000 wells fractured in western Canada over the last 60 years. With increased focus on fracturing from coast to coast, the Canadian industry wants to be at the forefront of transparency and to establish clear and consistent practices across the country.”

— DAILY OIL BULLETIN

New oilsands projects making huge advances

Photo: Joey Podlubny

By Elsie Ross

Tehnical advances are making oilsands development more sustainable.

Significant differences in new projects, which have benefited from greater industry collaboration, will challenge current public perceptions of the oilsands, executives from two European-owned projects told a recent oilsands conference.

“The projects we are working on today, the projects that are on the drawing boards, are in many ways radically different from projects that are already in operation,” said Gary Houston, vice-president of the Northern Lights project for Total E&P Canada Ltd., whose company is about to begin construction of its 110,000-barrelper-day Joslyn mine in northern Alberta.

“There is a step-change happening with industry, and when the Joslyn mine comes on stream in 2018, you are going to see stuff that is radically different from what we are used to seeing in the oilsands industry,” he said. “We are anxious to get out there and to demonstrate that we are 22

APRIL 2012 • OIL & GAS INQUIRER

making huge advances—step-changes— in all of these areas.”

Houston also predicted that within the next five or six years, the industry will have resolved the issue of tailings management. “With the amount of effort, with the amount of energy, with the great collaboration around this topic, it is definitely one that is going to be locked down within a very short time.”

Statoil Canada Ltd., which last year started up its Leismer SAGD project ahead of schedule and under budget, is also finding that persons have changed their view by 180 degrees after touring its site, Lars Christian Bacher, company president, told the InSight, Inc. oilsands symposium.

“This is about showing them what the oilsands is all about and sometimes, more importantly, what it is not about.”

Public sentiment in Norway, where the government owns 65 per cent of Statoil,

also has totally changed from what it was a few years ago, he said.

“Part of this is being open and transparent,” Bacher suggested. Statoil has always said it wants to report its results and use an independent third party for verification.

For its part, Total has several other projects in addition to the Joslyn mine that will be developed with Suncor Energy Inc., Occidental Petroleum Corporation and Inpex Corporation. It is part of the Fort Hills mine project with Suncor and Teck Resources Limited, and is a 50/50 partner with Suncor in the Voyageur upgrader that will process bitumen from the two mines.

Total also is partnering with operator ConocoPhillips Canada on the Surmont SAGD project where construction is underway on a Phase 2 expansion that will add 100,000 barrels a day of production by 2015.

With construction about to begin, it’s time for Total to deliver on its promises, Houston told the conference. As a global business, Total has promised its customers around the world that it will meet energy demand while developing its resources in a responsible way. “On a more local basis, we are going to manage our projects to reduce impact on the environment and on our stakeholders.”

At Joslyn, Total has incorporated a number of the best practices from other oilsands projects, including a 90-day water storage pond so there will be no need to draw water from the Athabasca River during low winter flows, alleviating the effect on aquatic life.

General News

However, the best thing that is currently happening in the industry is collaboration, such as the Oil Sands Tailings Consortium in which everyone puts their best ideas on the table for common use by all parties, Houston said. “That’s true collaboration; that’s where we’re really going to get a step-change in our performance as an industry.”

For its part, Total plans to avoid the production of mature fine tailings at its Joslyn plant from the beginning. The issue is worth working on and “not just because we don’t like the pictures in National Geographic,” he said.

At present, a lot of energy goes into the tailings ponds in the form of hot water. If companies can meet the Energy Resources Conservation Board’s tailing requirements, that water could be recovered, which would increase efficiency while reducing greenhouse gases and operating costs, said Houston. “There are a number of big wins just by capturing that water.”

Total is adding f locculants, which results in thickened tailings. “We’re starting to get something that doesn’t look like a pond but like a mud pie,” he said. “That’s moving in the right direction.”

With less water going in, tailings can be reclaimed faster. “We’re talking about taking something that in the past has been 30 years and counting with no end in sight, from a reclamation point of view, to something where in a matter of probably not weeks, but certainly in a couple of years, you can take this tailings and reclaim it.”

Total also will be segregating its tailings at the Joslyn mine, something that’s also being implemented at other mines but that wasn’t being done 10 years ago, Houston told the conference.

Statoil also sees room for future improvements in SAGD development as the technology is still in the early stages, said Bacher, who noted that the ramp up of Leismer production compared to that of other SAGD plants has been the best in industry. “You can be proud of it, but to me the most important lesson is that it is an illustration that the learning curve works,” he said.

Statoil has also developed an oilsands technology centre in Calgary producing research that is helping not only to improve economics but also to reduce the environmental footprint, the conference heard. “And technology development is in Statoil’s DNA,” said Bacher.

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How does the Canada Revenue Agency select who to audit?

Can I make an anonymous disclosure to the CRA’s Voluntary Disclosure Program before unnecessarily divulging incriminating information about me?

Does the CRA need a court order in order to garnish my wages for an unpaid tax debt?

Are there additional penalties charged by the CRA for continuously underreporting income?

The CRA’s primary selection method is to categorize taxpayers by groups (based on different criteria, such as profession, type of business, and income levels) that have either a low or a high tax compliance rating. Although all groups do receive minimal attention regardless of their tax compliance rating, the CRA will focus their efforts on groups that are least likely to be filing accurate tax returns with the aim of improving that group’s tax compliance. For a detailed response to this and other tax audit questions, visit www.fightthecra.ca/tax-audit

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Yes, an anonymous or “No-Name” disclosure can be made to test the waters and find out whether or not you qualify for the Voluntary Disclosure Program. However, there are important conditions that you should know prior to submitting your anonymous application, which may be viewed at fightthecra.ca/vdp (FAQ #5) No, the CRA does not. They may notify your employer directly and require garnishments to begin immediately. See fightthecra.ca/collections-actions for more information about salary garnishments, bank account seizures and property liens.

Yes, the CRA will impose penalties for repeated misrepresentation on tax returns if it occurs twice within a four year period. The federal and provincial fines are equivalent to 10% of the unreported income for the current year. See fightthecra.ca/taxevasion for more information.

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British Columbia

Talisman focuses on Montney

By Richard Macedo

Photo: Joey Podlubny

“We’re early into the Duvernay. We’ve just drilled and completed our first well —it’s coming online as we speak,” said Paul Smith, executive vice-president of North American operations. “Our second well has been drilled and will come online before the end of the first quarter. The program is on track.

“It’s encouraging to see the results that we’re seeing from competitor wells around us. I’m sure...you saw [the] Yoho [Resource Inc.’s] well...which is not too far away from one of our wells.”

John Manzoni, president and chief executive officer, said that gas prices in North America are now clearly reflecting the oversupply conditions that existed through last year.

“Prices fell steadily through the fourth quarter toward the levels we’re seeing today,” he said. “We believe this condition is unlikely to correct itself for some time, although actions are now being taken

Talisman continues to optimize its Montney development plans, while working on its gas-to-liquids feasibility study with partner Sasol.

Talisman Energy Inc. says it’s looking at liquefied natural gas (LNG) as an option for its Montney gas assets in British Columbia.

“The Montney gas play is very large and strategic and we are looking at both GTL [gas to liquids] and LNG as options, but no decisions have been [made] as of now,” Dave Mann, a company spokesman, said in February.

In the Montney, the company planned to reduce its program to four rigs from 11 in the fourth quarter of last year, primarily due to low gas prices. Talisman will continue its program to optimize recovery in the thick Montney shale.

Tony Meggs, a senior advisor who oversees gas monetization, said the GTL study is “progressing well.” The company and Sasol Limited are looking into the feasibility of building a GTL plant somewhere in western Canada.

“We’re very busy right now bringing all the results of the work together for an immediate decision on whether or not to proceed into the next phase,” he said.

“The next phase is not the final investment decision, it’s a [front-end engineering and design] study. We’re doing this in a measured way.

“I would add that this is not the only option we’re looking at. We’re looking at other monetization options, such as LNG, to ensure that we have pursued all possible avenues to realizing the full value for the gas that we’re producing.”

In the second quarter of last year, Talisman acquired a significant amount of acreage in the liquids-rich Duvernay shale in Alberta, where it now holds roughly 360,000 net acres. The company started a pilot program last year and plans to drill at least six wells in 2012.

We’re looking at other monetization options, such as LNG — Tony Meggs, Talisman senior advisor who oversees gas monetization

across the industry to cut back dry gas activity. Today’s prices are unsustainable in the medium term, but we think they may last for 12 months, anyway.”

Manzoni added that oil prices are underpinned at or around current levels, although political and other economic events could create volatility.

“Our plans are based on assumption of about $85 [West Texas Intermediate], which might be a little on the conservative side,” he said.

BRITISH COLUMBIA WELL ACTIVITY

FEB/11

FEB/12

WELL LICENCES

118

64

▼

FEB/11

FEB/12

WELLS SPUDDED

59

64

▲

FEB/11

FEB/12

WELLS DRILLED

68

67

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • APRIL 2012

25

British Columbia

Mitsubishi to send gas to Japan Japan’s Mitsubishi Corporation will take a portion of its planned Cutbank Ridge natural gas production in British Columbia for distribution to the Japanese market, an Encana Corporation executive said.

In February, Encana announced the sale of undeveloped Cutbank Ridge acreage to Mitsubishi for $2.9 billion. Encana also vowed to reduce its North America supply by up to 600 million cubic feet per day—partly by cutting 2012 capital spending by 37 per cent from 2011 levels, and partly by shutting in gas production.

During a conference call with analysts, Encana was asked whether deals such as the Mitsubishi investment would put more gas into a glutted North American market.

“We’re expecting to take some 600 million cubic feet per day off the market this year. Any of the [joint ventures] that we’ve been doing will not contribute production anywhere near those levels. I suspect they’d be relatively minor in the next year or so,” said Encana president Randy Eresman.

However, he ack nowledged that spending would ramp up over time under the Cutbank joint venture partnership, which will be owned 60 per cent by Encana and 40 per cent by Mitsubishi.

When asked whether the level of spending on the Encana/Mitsubishi Cutbank partnership is mandated by the joint venture agreement, Eresman said, “What we have is a five-year plan which has been agreed to with partners, and that plan will be updated

every year. Right now it anticipates...roughly a $5-billion spend over that period.”

When asked where Mitsubishi is expected to deliver its share of Cutbank production, the Encana president said, “Our partner already announced, I believe, that they intend to take some quantity of their production back to Japan, to the Japanese marketplace.”

In the Encana press release announcing the deal, Jun Yanai, Mitsubishi’s executive vice-president and head of its energy business group, said, “Mitsubishi looks forward to tapping new natural gas supplies for the long-term development and eventual delivery to world markets.”

Encana executives didn’t say whether Mitsubishi might become the “anchor off-taker” or major LNG buyer for the planned Kitimat LNG project.

Encana, Apache Corporation and EOG Resources, Inc. are currently doing the front-end engineering and design (FEED) study on a proposed gas liquefaction plant that would export western Canadian gas from Kitimat, B.C., to Asia via LNG tankers.

Eresman told reporters in a conference call that Encana and its Kitimat LNG partners hope to make a decision by mid-year on whether to proceed with the project.

Noting that Apache—not Encana—is the operator, Eresman said certain conditions must be met before the LNG export plan gets a green light. These include offtake agreements for a significant portion of the throughput, completion of the FEED

study and reducing the financial risk to an acceptable level.

The Encana president said the Kitimat partners agreed very early in the project that they would be willing to provide an equity interest to a significant off-taker that would anchor the project by taking a substantial portion of the LNG. “In this case, we would be expecting Asian buyers to commit to taking a certain amount of the capacity of the facility [through] a long-term commitment,” he said. “In exchange for that long-term commitment, we would be guaranteed a price that they take it at.

“And we would also provide them with an opportunity to take an equity interest in a portion of this facility, and possibly also provide them with an equity interest in some associated upstream capacity.”

Kitimat LNG partners haven’t said how much of an equity interest they’d be willing to give up in exchange for long-term contracts.

When asked whether Encana is considering selling its stake in Kitimat LNG, Eresman said, “We have not made any decisions nor commitments to reduce our interest,” beyond possibly providing equity to an off-taker.

He suggested that completing the FEED study will increase the likelihood of reaching agreements with off-takers, since the FEED study will provide a detailed cost estimate.

— DAILY OIL BULLETIN

B.C. unveils gas strategy B.C. Premier Christy Clark announced British Columbia’s natural gas strategy in February, with LNG exports being a cornerstone of the plan.

“We are creating new and exciting opportunities by diversifying our natural gas sector, strengthening job prospects for British Columbians and opening the door to new clean energy projects,” she said. “My government is positioning liquefied natural gas [LNG] as a cornerstone of British Columbia’s long-term economic success.”

The Natural Gas Strategy and a complementary strategy focusing specifically on the development of a new LNG sector, were recently released by Clark. Their four 26

APRIL 2012 • OIL & GAS INQUIRER

priorities commit the province to: greater emphasis on market diversification to increase the value of British Columbia’s natural gas; support job creation together with industry, educators and communities; continued strong leadership on clean energy and climate change moving forward; and a redefinition of the province’s self-sufficiency policy to ensure that British Columbia is well-positioned for power expansion.

Over the next five years, job openings are expected to increase as a result of growth in the natural gas sector and the emergence of a LNG industry.

Development of LNG is expected to produce

approximately $20 billion in new private sector investment. This investment will create 800 new long-term jobs for British Columbians working in LNG facilities and up to 9,000 more jobs during construction.

Indirectly, growth and a new LNG industry will support thousands of spin-off jobs in the fields of transportation, engineering, construction and environmental management, the government said.

“B.C.’s natural gas will help with the transition to a low-carbon global economy by displacing Asia’s current reliance on other carbon-intensive fuels like coal and diesel,” Clark added. “To protect our environment here, we also plan to

British Columbia

introduce more ambitious means of offsetting greenhouse gas emissions, such as carbon capture and storage, while balancing growth.”

BC LNG Export Co-operative LLC and Kitimat LNG will access clean energy from the province’s existing grid, the government said. As new infrastructure is built and the industry expands, future energy

needs will be served by local, clean energy, with British Columbia’s natural gas used to support energy reliability if required.

Discussions are now underway with LNG proponents to assess power requirements for future projects.

Clark said that investments in critical infrastructure to power future LNG facilities will be balanced with the need to keep

rates affordable for British Columbians. To do this, proponents will be required to make capital investments towards new infrastructure needed to power LNG operations.

“British Columbia is in a foot race with countries such as Australia, Qatar and the United States who are interested in exporting LNG, so we are moving quickly,” said Minister of Energy and Mines, Rich Coleman.

B.C. frac registry online British Columbia has become the first prov ince in Canada to enforce t he public disclosure of ingredients used for hydraulic fracturing.

The registry that provides a transparent account of B.C. hydraulic fracturing operations—FracFocus.ca—includes a database of the ingredients used to support natural gas extraction, and extensive content about the regulations and safety procedures governing industry activity.

As of Jan. 1, 2012, public disclosure for hydraulic fracturing fluid is mandatory in

British Columbia. By law, a list of ingredients used must be uploaded to the registry within 30 days of finishing completion operations—the point when a well is able to produce gas.

Hydraulic fracturing is subject to strict regulations in British Columbia, says the government. The province has instituted laws to ensure the process protects groundwater and the environment. The government says there has never been an incident of harm to groundwater from hydraulic fracturing within British Columbia.

The province built the FracFocus website to accommodate future participation by other jurisdictions so there can be one national site for disclosure information.

The government says that the website delivers on a commitment made by Premier Christy Clark during the BC Oil & Gas Conference in Fort Nelson last September, where she promised an online registry to increase the transparency of hydraulic fracturing in the province.

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Slave Point carbonate cranking up

Photo: Aaron Parker

By Elsie Ross

Penn West is one of the dominant drillers in the Slave Point play, with some wells coming in with over 500 barrels of oil per day.

Clustered in parallel trends around the edges of the Peace River Arch in northern Alberta, the Slave Point carbonate play is the latest to owe its success to horizontal wells and multistage fracturing technology.

“People have known for a long time [that] there’s a lot of oil there; they just haven’t been able to get it out,” says Brad Hayes, president of Petrel Robertson Consulting Ltd. “There are big fairways to play in there; it’s not just some little trend.”

However, the low-permeability Upper Devonian play presents some challenges for those hoping to exploit it, according to Hayes. The Peace River Arch was once a highland, and the reefs grew around the edges. “As the sea level changed, the reefs grew in different places, so there’s quite an intricate set of maps you can draw to find these reefs at all different spots,” he says.

“It’s not quite as simple a picture as in central Alberta, where there’s a widespread platform and the reefs build up from it.” It can be difficult to distinguish one level from another, and attempting to map a continuous carbonate package can be tricky if there are not a lot of existing wells, he cautions.

But with large, original, 39 API degree oil in place, existing infrastructure, reservoirs amenable to secondary recovery through waterfloods and the ability to downspace, the Slave Point resource play offers a lucrative target with both reef and platform production, making that challenge worth the effort.

Penn West Exploration Ltd., which is chasing the Swan Hills carbonate to the south, was one of the first players in the Slave Point horizontal play. In both formations and in Penn West wells, interest wells and competitor wells, these plays,

“have seen the highest consistent production of oil in any of the tight oil plays in western Canada,” Rob Wollmann, senior vice-president of exploration, told Penn West’s investor day last fall.

“Specifically, we are seeing wells producing 200, 300, 400, 500 or even more barrels a day.”

T hat emerg i ng potent ia l hasn’t escaped the notice of industry, and over the past two years it has sparked a rash of drilling and what one executive described as a Gold Rush, with one parcel on the edge of the Peace River Arch fetching more than $5,000 per hectare.

JuneWarren-Nickle’s Energy Group records show that since January 2000, operators have licensed 680 wells, listing the Slave Point as the targeted formation.

With the evolution of horizontal drilling and multi-fracturing technology, activity has accelerated over the past two years with 391 wells (with oil as the objective) licensed since Jan. 1, 2010. Of those, 381 have been horizontal wells.

The Slave Point has also attracted some strong bids in recent Crown land sales. At the September 21 sale, a 4,736-hectare licence was sold for $24.99 million at an average price of $5,276 per hectare with the broker acquiring the rights to more than 18 sections on the edge of the Peace River Arch at 91-12W5, 92-12W5 and 92-13W5, north of where Penn West and Pinecrest Energy Inc. have been active. At the August 10 sale, a 5,248-hectare licence near Loon Lake west of Red Earth Creek sold for $22.9 million ($4,363 per hectare), the highest price in the sale.

Other companies in the Slave Point include Lone Pine Resources Canada Inc. (spun off from Canadian Forest Oil Ltd.), Harvest Operations Corp., Pace Oil & Gas Ltd., Devon Canada Corporation, NAL Energy Corporation (partnered with

NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

FEB/11

FEB/12

WELL LICENCES

218

263

▲

FEB/11

FEB/12

WELLS SPUDDED

281

313

▲

FEB/11

FEB/12

WELLS DRILLED

296

298

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • APRIL 2012

29

Northwestern Alberta/Foothills

Penn West), and privately held Quarto Resources Inc. (Red Earth) and Dolomite Energy Inc. (Otter).

Estimates of original oil in place in the Slave Point reservoirs range from six million to 10 million barrels of oil equivalent per section (90–94 per cent oil) on primary recovery. Secondary recovery (waterfloods) can boost the primary rate from 15–16 per cent to about 25 per cent, with estimated incremental recovery factors of between 50 and 100 per cent over primary recovery and production increases of 2–2.5 times.

Penn West has been pursuing the play at Sawn Lake, Otter and Red Earth, and was able to get in and acquire land at the Slave Point carbonate play, “ahead of the Gold Rush and the heated land price battles that have been going on farther south in the industry,” Hilary Foulkes,

executive vice-president and chief operating officer, told a recent investor conference. At Red Earth and Sawn Lake, the company has been seeing some stellar results, “some of the best oil production we have seen anywhere in the basin,” according to Wollmann.

The company has pioneered the use of dual-lateral wells in the Slave Point at Sawn Lake and Otter, and has been drilling 50 or 60 dual-lateral wells in those areas, “almost like a cookie-cutter operation,” said Foulkes. “The trunk lines are in place so it’s a ‘drill to fill’ for us in this region.”

At a cost of $6.5 million–$7.5 million for a dual lateral, compared to $4.5 million– $5 million for a single horizontal well, the dual laterals are actually more economic, Mark Fitzgerald, Penn West’s senior vicepresident of development, said at the investor day. Based on the type curve,

reserves are 300,000–340,000 barrels per well from the Slave Point for a single well, and 425,000–475,000 barrels for a dual well. The average one-month production rate is 275 barrels per day from a single well, and 475 barrels per day from a dual lateral well, while the three-month rates are 250 barrels of oil equivalent per day and 375 barrels of oil equivalent per day, respectively.

Penn West has a 100 per cent battery and is filling an existing pipeline, drilling four wells with eight laterals per section. It uses sand fracs for completing the wells, which Wollmann said are cheaper than (and just as effective as) acid fracs with 20 stages per lateral and 20–30 tonnes per stage. The area is accessible for most of the year and the company will continue to improve the access, he said.

Strategic to focus on light oil Light oil–weighted Strategic Oil & Gas Ltd. plans to spend $60 million in 2012 and anticipates drilling a total of 20 (17 net) wells, excluding major land and corporate acquisitions.

The company said its capital program is expected to be financed through a combination of cash flow, debt and the capital raised through a recently completed $42.3-million financing.

In announcing its 2012 guidance, the company estimates that funds from operations for the year will come in at between $34 million and $38 million, while average production will be 2,400 barrels of oil equivalent per day. Strategic plans to exit the year producing 3,000 barrels per day with 80 per cent of output being light oil.

The company achieved 2011 exit production of 1,880 barrels per day (71 per cent oil). Production for the month of December averaged 1,655 barrels per day, representing an increase of over 400 per cent from December 2010.

Operationally, four new wells were put on production during December 2011.

The vertical Keg River well 102/15-22 is producing light oil with an initial 30-day 30

APRIL 2012 • OIL & GAS INQUIRER

production rate (IP 30) of 355 barrels per day. Strategic said it has contracted a second rig at Steen River that will enable the drilling of up to nine wells during the first quarter.

At Steen River, Strategic acquired 43 sections (27,201 acres) with Sulphur Point light oil potential. At Amber, Strategic acquired 56 sections (35,741 acres) in the northwestern Alberta Muskwa play fairway with light oil potential in two zones.

The company noted that it is well positioned to exploit the light oil potential at Steen River, Maxhamish and Amber.

At the company’s North Marlowe property in northwestern Alberta at Steen River, two new vertical Keg River wells are producing light oil with an IP 30 of 185 barrels per day and 355 barrels per day. In December 2011, Strategic drilled its first Keg River vertical well at the West Marlowe field, which is 16 kilometres west of the North Marlowe field. The well is producing light oil with an IP 30 of 125 barrels per day.

The first horizontal well drilled in the Sulphur Point zone at North Marlowe is 700 metres long, has no fracture stimulation and

is producing light oil with an IP 30 of 150 barrels per day. A second Sulphur Point horizontal well is currently being drilled.

Strategic aims to develop the Sulphur Point reservoir, which extends over the 58 sections of land, with horizontal wells.

The company said it has cored and tested light oil in the Muskeg Stack, which is a zone that lies below the Sulphur Point zone and is aerially extensive. Strategic plans to drill a horizontal well during the first half of this year to evaluate the Muskeg Stack.

At Amber in northwestern Alberta, Strategic acquired 56 sections (35,741 acres) of land targeting t wo zones with light oil potential—the Jean Marie carbonate and the Muskwa shale. The company said that the Jean Marie has an average net pay of eight metres containing approximately seven million barrels of light oil per section. The Muskwa shale has an average thickness of 25 metres within the mature oil– generation window. Strategic intends to drill up to two multistage fractured horizontal wells at Amber.

— DAILY OIL BULLETIN

Northwestern Alberta/Foothills

Birchcliff growing in northwest Birchcliff Energy Ltd. continues to increase its daily production rate, while year-overyear, proved plus probable reserves grew by just under 37 per cent at year-end 2011.

The company said that estimated average production to date, in February, was in excess of 21,100 barrels of oil equivalent per day, up from 20,400 barrels per day in January of this year.

Average production in the fourth quarter of 2011 was 19,812 barrels equivalent per day, a 21 per cent increase over fourth quarter. Average production last year was 18,136 barrels per day, a 39 per cent increase over 2010 average production of 13,079 barrels equivalent per day.

The company expects continued material production growth in 2012, primarily as a result of the commissioning of the Phase 3 expansion of the Pouce Coupe South (PCS) gas plant in the fourth quarter.

Birchcliff’s reserves evaluation, undertaken by AJM Deloitte and effective Dec. 31, 2011, estimates the company’s proved plus probable reserves increased to 275.4 million barrels equivalent at year-end 2011, from 201.1 million barrels a year earlier. Proved plus probable reserves are comprised of 85 per cent natural gas and 15 per cent light oil and natural gas liquids.

Birchcliff noted that it added 2.2 barrels equivalent of proved developed producing reserves for each barrel that was produced during the year, representing a 220 per cent reserve replacement on a proved-developed producing basis. As well, the company added 12.2 barrels equivalent of proved plus probable reserves for each barrel that was produced during the year—a 1,223 per cent reserve replacement on a proved plus probable basis.

AJM estimates that Birchcliff’s reserve life index is 36 years on a proved plus probable basis and 20 years on a total proved basis, in each case using reserves estimates at Dec. 31, 2011, and assuming an average daily production rate of 21,100 barrels equivalent per day.

Birchcliff added that the corporate sale process that it announced on Oct. 3, 2011, is continuing. To date, the company has not entered into an agreement with any party and is currently in negotiations. At this time, there can be no assurance that the ongoing negotiations will result in a successful transaction.

— DAILY OIL BULLETIN

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Northeastern Alberta

Alberta changing approach to oilsands regulation

By James Mahony

FEB/11

FEB/12

FEB/11

FEB/12

WELLS SPUDDED

150

156

WELLS DRILLED

175

162

Photo: Joey Podlubny

energy projects [rather than] merging all of those government departments,” said Harper, with the Calgary office of Blake, Cassels & Graydon LLP. “It will be interesting to see how well the government progresses, over what time frame they implement it and exactly what powers the new regulator will have.”

A bigger change, according to Harper, is the regionally focused approach to regulation represented by the government’s Lower Athabasca Regional Plan (LARP), expected to become law in the near future. The plan represents a shift in industry regulation, he said.

“LARP will be a bit of game-changer for everybody in the oilsands industry,” he said. “It increases the importance of looking at your oilsands operation in the context of other industry operations in your area. You can no longer look at your project in isolation. Today, you have to look at it in concert with others in your region.”

If anything stands out from LARP, it’s the plan’s cumulative effects-management approach to oilsands operations, he said.

“That’s the additional item that LARP brings to the regulatory environment that doesn’t currently exist.”

Harper told the conference that once it becomes law in Alberta, LARP will, in practice, work like a “super regulation,” in that it will prevail over other regulations as well as approvals that an oilsands project developer might have obtained.

“As an oilsands operator, you will have to be responsible for compliance with your existing approval. You may also have to be aware of existing cumulative regional impacts, and ensure that you’re also complying with those.” As for timing, his expectation is that LARP will be finalized sometime this year or next, at the latest.

Federally, he said some environmental laws are under review, and may have implications for Canadian oilsands developers. The statutes that may be retooled include the Species At Risk Act as well as the Canadian Environmental Assessment Act (CEAA), among others. Word is that CEAA will be “streamlined” insofar as it affects major projects.

Other changes affecting oilsands operators may also be in the works. For example, under Alberta legislation, the province’s “large emitters” of greenhouse gases (GHG) pay a per-tonne fee if they emit beyond 100,000 tonnes per year. However, Harper said recent indications suggest the province may reduce the threshold level below 100,000 tonnes, possibly as low as 50,000 tonnes (no figure could be confirmed).

Perhaps more controversial was another move the Alison Redford government has already made, one which could have a more profound effect on managing carbon emissions in Alberta. According to Harper, the province recently changed the wording of the regulation that stipulates

The Lower Athabasca Regional Plan (LARP) will require operators to look at development on a regional basis.

Development of Alberta’s oilsands industry continues to gain steam, but the sector was warned yesterday to stay ahead of forthcoming changes in the way it’s regulated.

In early February, the Alberta government brought the long-discussed goal of creating a “one-stop” regulator for the industry a step closer, and the issue came up at Insight Information’s Canadian Oil Sands Summit later in the month.

Legislation establishing the new body is being written, the conference heard.

Duff Harper, a Calgary environmental lawyer, addressed the conference and agreed the task of creating a single regulator poses a challenge for the Alberta government, but said the scope of the job is narrowed somewhat, since only the upstream oil and gas sector would fall under the new body’s jurisdiction.

“It will be a daunting challenge...but it’s going to be a focused regulator for NORTHEASTERN ALBERTA WELL ACTIVITY

FEB/11

FEB/12

WELL LICENCES

131

277

▲

▲

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • APRIL 2012

33

Northeastern Alberta

the $15-per-tonne fee. Now, instead of setting out a specified fee, the regulation says the price will be set by order of the minister.

“That change was done with extremely little publicity,” he said. Noting that he’s heard nothing from the government on the point and does not speak for it, Harper said he thinks the change gives the government “the ability to continuously raise the price as time goes by, without having to modify a regulation. I doubt very much that it means the price is going to go down.”

While the last year has seen many changes in the oilsands sector, Harper predicted there

is more to come, and believes at least some of the impetus for the new initiatives has come from concerns raised by the public and by unnamed domestic and international organizations. “Perhaps the government has been listening and they’re trying to respond to those international issues,” he said.

Other changes that are in the works will affect oilsands tenure, an official from Alberta’s Energy Department told the audience. “We’re going to open up tenure in a holistic manner and will decide what is the best solution,” said Dana Woodworth, chief of oilsands strategy and operations.

Earlier, the conference heard that most of Alberta’s oilsands leases in the Athabasca area are spoken for, but that recently, some five-year term leases have expired and reverted to the province. As for particulars, Woodworth offered few details of just what the province has in mind.

Shortly after he spoke, however, an executive in the audience stood up to challenge the province’s approach to regulating the industry. “Central planning—planning by a public authority—didn’t work in the 20th century and we’re not going to make it work in the 21st,” he told Woodworth.

MEG sets new production record MEG Energy Corp. set a quarterly production record of 30,032 barrels of bitumen per day at its Christina Lake SAGD project in the fourth quarter of 2011, exceeding plant design capacity by 20 per cent, following a successful plant turnaround in September.

Along with the higher production, the company achieved a steam-oil ratio (SOR) of 2.3, reflecting the quality of the reservoir and the effort of its employees to maintain efficient and reliable operations, Bill McCaffrey, MEG president and chief executive officer, said in a conference call to discuss fourth-quarter and year-end results.

The SOR was also significantly better than the facility design rate of 2.8, said the company. The SOR for the year was 2.4.

Production also benefited from the flush production, which occurred as heated bitumen continued to drain in the steam chamber towards the producing wells during the turnaround and the debottlenecking activities carried out on the Phase 2 high-pressure steam separator, also during the turnaround, said McCaffrey.

The debottlenecking is among MEG’s initiatives designed to test the throughput capacity of the plant, he said. “We believe this initiative alone added about 1,000 barrels per day to our base production levels and that flows right to the bottom line.”

Annual production for 2011 averaged 26,605 barrels per day, an increase of 25 per cent over 2010 volumes of 21,257 barrels per day. It was the first year in which MEG had an opportunity to demonstrate a full year of production at commercial volumes, Operating costs for the three months were $13.16 per barrel compared to $13.89 34

APRIL 2012 • OIL & GAS INQUIRER

per barrel for the same period in 2010. After including the contribution of revenue from power sales at MEG’s cogeneration facilities, net operating costs declined to $8.50 per barrel in the fourth quarter of 2011 from $11.01 per barrel in the fourth quarter of 2010.

Low operating costs, coupled with relatively narrow light-heavy crude differentials and high benchmark prices, contributed to a fourth-quarter, cash-operating netback of $54.64 per barrel compared to $36.56 per barrel in the same period of 2010.

During the fourth quarter, MEG made continuing progress on the next major stage of the growth plan, Christina Lake Phase 2B, which provides for an additional 35,000 barrels per day of design capacity. Capital investment in 2011 of more than $984 million focused on Christina Lake Phase 2B development and resource delineation at Christina Lake, Surmont and the growth properties and expansion of the Access Pipeline.

Approximately $710 million of the estimated $1.4-billion project cost for Phase 2B has been invested to date and approximately 60 per cent of the total budget is locked in. As of Dec. 31, 2011, detailed engineering was 93 per cent complete. All materials and project modules have been ordered, with delivery and on-site construction scheduled to continue through 2012 with completion targeted in 2013, and MEG believes it is on track to meet its cost estimate, said McCaffrey.

In addition to ongoing construction of Phase 2B, MEG’s $1.37-billion 2012 capital budget targets investments to begin development of future phases of the Christina Lake and Surmont projects, and

investments in infrastructure to accommodate growth and add value to planned production by advancing MEG’s market diversification strategy.

In 2012, MEG will focus on further reducing costs, continuing to lower its SOR and finding ways to continue to increase production and plant throughputs, said McCaffrey.

One initiative is infill wells, which the company is doing in the more mature parts of its operation. In late December, it began steam stimulation on two of the pilot wells.

Although a bit ahead of the original schedule, the timing is right as MEG believes infill wells should be most effective on well clusters that are three to four years old. As of late January, both wells had been converted to producers and the company is pleased with the initial results.

A second initiative is MEG’s noncondensable gas pilot project. Late last year, it began injection of natural gas to free up steam previously directed to three of its wells on Pad A. McCaffrey said the company is pleased with the initial performance and has already seen a 10–15 per cent reduction in the steam required while still maintaining the productivity of the initial well pairs.

“While it’s still early days, the initial results, I feel, are very encouraging,” he said.

A third initiative involves new well pairs on the company’s current operational phases. MEG initiated steam circulation in one of its four well pairs in mid-December and is in the process of converting the lower well to a producer. As more steam becomes available, it will start injection into the other additional wells.

— DAILY OIL BULLETIN

Northeastern Alberta

Imperial sanctions Cold Lake expansion

Photo: Joey Podlubny

of the expansion. “We believe it’s a better project and we are quite excited to be moving ahead with it,” said Rolheiser.

The project amendments included a 170-megawatt cogeneration facility to enhance the plant’s energy efficiency, a reduction in the number of wellpads which reduces the environmental footprint, and the addition of sulphur recovery facilities. Imperial will be developing the same resource with about 40 per cent fewer surface pads as the result of advances in drilling technology, he said.

The Nabiye plant is in 23–66–3W4, about three kilometres east of May Lake and about eight kilometres north of Marie Lake.

The project comprise phases 14, 15 and 16, northeast of Imperial’s existing operations that currently produce about 160,000 barrels of bitumen per day from the Leming, Maskwa, Mahihkan and Mahkeses projects.

Imperial’s Cold Lake facility is the largest and longest-running in situ oilsands operation in Canada and includes four steam generation and bitumen production plants.

Imperial's Cold Lake operations. A new phase will add 40,000 barrels of production in 2014.

Imperial Oil Limited has approved a $2-billion expansion of its Cold Lake cyclic steam stimulation (CSS) operation in northeastern Alberta.

The Nabiye project, expected to start up by year-end 2014, will increase Cold Lake production by more than 40,000 barrels per day to about 200,000 barrels per day.

The project will access 280 million barrels of recoverable reserves, compared to the 250 million barrels initially envisioned

when Imperial first began planning the development a decade ago, said company spokesman Pius Rolheiser.

The Nabiye expansion will include development of a new steam generation and bitumen-processing plant, field production pads and associated facilities.

Imperial received original regulatory approvals for Nabiye in 2004, but in 2010 obtained approval for an amended application to improve the environmental performance

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First Nations refinery in limbo

By Elsie Ross

FEB/11

FEB/12

FEB/11

FEB/12

WELLS SPUDDED

246

230

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238

217

Photo: Joey Podlubny

The project is designed to upgrade bitumen to produce 100,000 barrels per day of gasoline, diesel, jet fuel and petroleum products primarily for export via pipeline to the West Coast. The company was proposing to acquire 93,000 barrels per day of the 125,000 barrels per day of bitumen it would process from the government under its Bitumen Royalty in-Kind (BRIK) program. Plans called for construction commencement in 2014, with facility start-up in 2017.

After concluding negotiations on a conditional commitment agreement with government bureaucrats, Teedrum was waiting for caucus and cabinet approval, which would have enabled it to proceed to the next step—a $200-million front-end engineering-and-design study, “at no risk to the government,” that would have taken about two years and determined whether it should proceed further.

Energy Minister Ted Morton delivered the bad news at a February 8 meeting attended by the three Grand Treaty chiefs representing the majority of Alberta First Nations, and Eric Newell, the Teedrum chair and former chief executive officer of Syncrude Canada Ltd., who has since resigned, said Horn. In a letter to the company, Morton cited the economics of the project.

More than a year ago, the Alberta government invited Teedrum and AFNEC to engage in government-to-government negotiations on the terms of the conditionalcommitment agreement. At the time, the government under the North West Partnership Trade Agreement assessed that government-to-government negotiations were appropriate and that no request for proposals (RFP) was required for AFNEC’s application under the BRIK program, given the First Nations co-ownership of the project.

In May 2011, AFNEC and governme nt bu reauc r at s conc luded t hei r negotiations on the agreement and recommended it to caucus and cabinet.

PwC Canada, which conducted a comprehensive evaluation on behalf of the federal government, had a strong recommendation on the value of the project.

However, the ministerial working group felt the timing was too close to former premier Ed Stelmach stepping down, and asked that a decision be deferred until after a new premier was in office.

“We were assured all things were fine, pending political approval by the cabinet and caucus,” Horn said.

The conditional-commitment agreement demonstrated the economics and appropriate risk-and-return thresholds for each party, including milestone obligations demonstrating future feasibility.

The project’s viability was further supported by analysis conducted internally

Plans for a First Nations–owned bitumen refinery are in trouble after the provincial government declined to provide supply for the project.

Alberta First Nations chiefs are still hopeful they can negotiate a deal with the Alberta government after Premier Alison Redford’s government declined to sign a conditional-commitment agreement for government-owned bitumen volumes for a proposed refinery in the province’s Industrial Heartland region, a company official said.

“We’re perplexed. I just think it’s a big setback in the relationship between First Nations and the Alberta government,” said Ken Horn, president of Teedrum Inc. The company has already invested about $30 million in the $6.6-billion project.

The proposed Alberta First Nations Energy Centre (AFNEC) had been under development for the past four years, and the company had partnered with the government of India on some of the engineering and had raised significant equity, said Horn.

CENTRAL ALBERTA WELL ACTIVITY

FEB/11

FEB/12

WELL LICENCES

301

262

▼

▼

▼

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • APRIL 2012

37

Central Alberta

by energy ministry officials, as well as by third-party industry and financial experts, he noted.

Horn said that initially the Alberta gove r n me nt , wh ic h wou ld ow n 75 per cent of the product, was worried about markets for the ref ined product. However, Teedrum had a partnership with global energ y trader Vitol, which agreed to take all finished products from the government on a weekly basis. Teedrum was also prepared to bid for capac it y on K i nder Morga n Ca nada’s proposed Tra ns Mounta i n expansion.

Horn said his group was told this week there will be another RFP for more BRIK barrels in the immediate future.

He could not say at this point whether it would participate. “The chiefs bowed out of the first RFP [won by North West Upgrading Inc.] because they viewed,

and so did the government, that we should be dealing on a government-togovernment basis.”

P wC determined a market valuation of $50 million pre-BR IK agreem e n t a n d $1 b i l l i o n p o s t – s i g n e d conditional agreement. “It was obvious to have the government say ‘Let’s see what happen s at no r i sk to us, and in t wo years if things look winwin-win we’ll move ahead, and if not, everybody goes away.’”

Teedrum would have raised money from the equity markets and the company’s Chinese and Indian partners.

Teedrum had memorandums of understanding with both the Chinese and Indian governments in a competitive process, and would have selected one nation or the other as a partner to come in. Depending on the cost of the equity, it was looking at partnership percentages

of between 15 per cent and 40 per cent.

“China is still interested in engineering, procurement and construction contracts through Sintec.”

AFNEC will contribute an estimated $100 billion to Canadian gross domestic product over 20 years, with the potential of billions of dollars in new revenue f lowing directly to Alberta taxpayers over the course of the agreement.

“This project fits the federal and provincial interest in making the most of our natural resources,” Horn said in a statement. “Building a refiner y bui lds a n economy. It c reates jobs, supports social initiatives benefiting A lberta taxpayers and attracts international investment to the province. In this case, it would also allow the First Nations to become active participants in a major oilsands project and all of the related benefits.”

Alberta diesel production profitable, says North West chairman By producing diesel f uel in A lberta, t he $5-billion Nor t h West upg rader can capture nearly twice the margin of upgraded synthetic crude oil (SCO), an oilsands conference heard in February.

Not only does diesel sell for about $25 per barrel more than SCO, but the hydrocrack ing process produces about 1.3 bar rels of diesel f uel for every barrel of bitumen, compared to coking, which produces about 0.8 barrels of SCO, Ian MacGregor, chairman of North West Upgrading Inc., told the Insight Canadian Oilsands Summit. “ E s se nt i a l ly, it ’s f ac tor y-pr o duce d diesel fuel.”

There’s a strong demand for diesel in western Canada, the conference heard.

“Every element of our economic activity is related to diesel fuel, and we are getting short because no new refinery has been built for years.”

“We also think it’s a lot easier to export diesel than it is to export bitumen because bitumen requires a refinery on the other end that’s configured to accept 38

APRIL 2012 • OIL & GAS INQUIRER

it,” he said. “Diesel goes wherever there’s a tank and if you think of where the world’s markets are going, all developing countries essentially run on diesel and the best ones are in the Far East.”

North West, which already has project approval, is currently working on engineering for the 150,000-barrel-perday refinery near Redwater, which would be built in three 50,000-barrel-per-day stages. The project has yet to be sanctioned by its 50/50 owners—North West and Canadian Natural Resources Limited (CNRL)—but the anticipated start-up date is late in 2014 or early 2015.

Under a 30 -yea r cost- of-ser v ice agreement with the A lberta government, North West will produce diesel fuel from the 37,500 barrels per day of bitumen provided by the province’s Bitumen Royalty in-Kind (BRIK) program while CNRL will contribute the additional 12,500 barrels per day.

“There’s sort of a weak understanding that if everything worked out right there would be another 37,500 from the

government and 12,500 from CNRL,” MacGregor later told reporters.

“I think they want to see how that is going to work,” he said. “That’s a logical thing to do when you are working at this scale, and I think if we do a really good job, which we plan to do, then there’s going to be more.”

With its 25 per cent royalty after payout from all oilsands projects that it takes in bitumen, the government will be the province’s largest bitumen producer over time, MacGregor noted.

The province selected North West to upg rade its bit umen fol low i ng a tender process that attracted a number of bidders, he said. “We think we won because we had the best economics, the thing that produced the best value for them.”

W h i le some have c r it ic ized t he government ’s deal with North West, MacGregor pointed out that his company has assumed the cost-overrun risk— “which is not trivial in a project such as this”—as well as the operating-cost risk.

Photo: Joey Podlubny

Central Alberta

A shortage of diesel fuel in western Canada, combined with export potential, will make the North West upgrader a money-maker, says Ian MacGregor.

And because the province has more sources of revenue for its bitumen but the same upgrading costs, it gets about twice as much money as anyone else from the conversion, he said.

“If North West Upgrader had been in operation last year, it would have made $500 million more than if it had sold raw bitumen,” said MacGregor. “So if anybody thinks that’s a subsidy, I want one.”

Responding to a quest ion about how much upgrading should be done in A lberta, he suggested a balanced approach is needed with bitumen, synthetic crude and finished products. “If you follow the portfolio approach, you will optimize the economics at every point in the curve.”

If companies tried to build too many upgraders in Alberta at the same time, the cost would go up so much they would become uneconomic, but, “I think we should always be building one here,” said MacGregor.

As far as North West is concerned, “CO2 is the big threat to the oilsands,” he

told the summit. A 50,000-barrel-per-day refinery produces the equivalent amount of CO2 as that produced by 300,000 cars.

Although the Alberta oilsands contribute only two per cent of the world’s CO2 emissions, “it’s a visible target and it’s easy to chase,” said MacGregor. “The searchlight is on oilsands and we have to do something about CO 2 —at least that’s what we believe.”

For its refinery, North West will use a gasification process that takes the bottom of the barrel of bitumen—the heavier residuals, or coke—and converts that into hydrogen. “If you put enough hydrogen in, it eventually turns into diesel.”

A major advantage of gasification in hydrogen production is that it produces pure CO2 , which can be injected into depleted reservoirs for enhanced oil recovery. The reservoirs in the area could accept about two billion tonnes of CO2 from the oilsands—about 50 years’ worth at the current rate of production, he said.

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Southern Alberta

Devon Canada targets liquids

By Elsie Ross

FEB/11

FEB/12

FEB/11

FEB/12

WELLS SPUDDED

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Photo: Aaron Parker

Jackfish 1 averaged 31,400 barrels per day in 2011, continuing its excellent trend of plant reliability and efficiency, said Hager. At Jackfish 2, Devon exited the year producing approximately 14,200 barrels per day and will continue to ramp up for the remainder of this year.

In January, Devon began site clearing at Jackfish 3 after receiving regulatory approval in December 2011. Although field construction will not begin until spring, the project is already 20 per cent complete because of the company’s decision 18 months ago to place orders for long–lead time project components. Plant start-up is targeted for late 2014.

At Pike, Devon’s operated oilsands 50/50 joint venture with BP plc, this winter’s appraisal program is underway and should confirm the resource potential for a 105,000-barrel-per-day first phase of the steam assisted gravity drainage

(SAGD) development, he said. The winter drilling program consists of more than 100 stratigraphic test wells and the acquisition of 50 square miles of 3-D seismic.

Devon expects to begin the regulatory process as early as this summer. Pike is expected to support additional phases of development.

With the initial phase of Jackfish running near capacity and the second phase continuing to ramp up, the company this year expects to grow its thermal production by more than 50 per cent over 2011 to an average of more than 50,000 barrels per day. Devon is on track to achieve its goal of increasing its net SAGD oil production to between 150,000 and 175,000 barrels per day by 2020, representing a 17–19 per cent compounded annual growth rate by the end of the decade, analysts heard.

On the exploration front in Canada, Devon continues to evaluate the oil and liquids-rich potential of numerous play t y pes across its more than four million net acres. The most encouraging results from its 2011 program came in the Ferrier area in west-central Alberta where it is targeting Cardium oil. Devon drilled eight wells in the area and saw 30-day initial production rates of up to 940 barrels equivalent per day.

Hager said t he compa ny is a lso encouraged by early results of the Viking light oil play in Saskatchewan, although it is still in the early stages of evaluating these and several other emerging liquids plays in Canada. Devon plans to continue this effort in 2012, spending approximately $350 million drilling some 90 exploratory wells.

Total exploration and development capital spending for 2011 was $6.56 billion, of which $1.55 billion was spent in Canada.

Crews drilling a Devon well last fall. Devon plans on focusing its Canadian exploration efforts on oil and liquids in 2012.

Oklahoma City–based Devon Energy Corporation plans to spend more than US$1.1 billion in Canada this year, with plans to drill about 90 exploration wells targeting oil and liquids along with continued thermal oil development.

Thermal oilsands projects at Jackfish/ Pike will attract the majority of capital with $800 million in spending, while an additional $350 million has been allocated for exploration, Dave Hager, executive vice-president, exploration and production, said in a conference call to discuss fourth-quarter and 2011 results.

Canadian production averaged 188,700 barrels equivalent per day (net) of royalties in the fourth quarter, and 183,600 barrels per day for the year. The yearly figure included 34,800 barrels per day from Jackfish/Pike and 39,200 barrels per day from Devon’s heavy oil production at Lloydminster, Alta.

SOUTHERN ALBERTA WELL ACTIVITY

FEB/11

FEB/12

WELL LICENCES

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53

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Source: Daily Oil Bulletin

OIL & GAS INQUIRER • APRIL 2012

41

Southern Alberta

Photo: Joey Podlubny

Natural gas producers may be paying customers this summer

Transportation and storage contracts could put gas producers in a tough situation this summer.

Natural gas could have a negative value in Alberta during the coming summer as storage fills to capacity, a conference heard in February.

“I could see a situation where people would be paying others to take their gas,” Ed Kallio, director of gas consulting at Ziff Energy Group, told the Canadian Energy Research Institute’s 2012 Natural Gas Conference.

It’s conceivable that deals could be done where producers would actually pay buyers a fee that is less than the penalties they would otherwise face under transportation contracts, Kallio said.

Also, producers could face penalties under storage contracts if they don’t get their gas out on time.

“So in order to mitigate that penalty, you would sell that gas to someone else [for] just a little bit under what that penalty might be. And we have seen that [in the past],” Kallio said.

42

APRIL 2012 • OIL & GAS INQUIRER

“Because we’re so fat with storage right now—because of this pushback from the Ruby and Bison and even [Rockies Express] pipelines, and you’ve got high toll structure on TransCanada Corporation’s system—we’re going to get into a real pickle as we get through the summer and all that gas is looking for a home,” he said.

Extreme situations typically occur on weekends when there is less liquidity in the market. “During the shoulder season, demand drops off. That’s where companies can get into kind of a momentary penalty situation and they would sell their gas at a negative value,” Kallio said.

There appears to be an industry-wide consensus that the short-term North American gas-price outlook is bleak. For the longer term, many are pinning their hopes on liquefied natural gas (LNG) exports to Asia.

The price differential between Japan and Henry Hub in the southern United States is now about $14 per thousand cubic feet or higher, said Mike Dawson,

“ We're going to get into a real pickle as we get through the summer and all that gas is looking for a home" — Ed Kallio, director of gas consulting, Ziff Energy Group

president of the Canadian Society for Unconventional Resources.

The problem, he said, is that none of these projects are likely to come to fruition before 2015-16.

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That’s when a liquefaction plant planned for the port of Kitimat B.C., (owned by Apache Corporation, Encana Corporation and EOG Resources, Inc.) and the associated Pacific Trails pipeline may come on stream.

But most of that project’s planned output of 1.5 billion cubic feet per day is expected to come mainly from the Horn River shale play, which currently isn’t producing significant volumes, Dawson

said. In other words, the Kitimat LNG project is mainly about bringing on new production rather than relieving the existing supply glut.

“My personal thoughts are [that] I don’t believe that the Kitimat LNG project is going to have a heck of a lot of impact in terms of natural gas pricing in North America for any of the other producers— simply because you have a constrained

gas supply coming out of the Horn River,” he said.

But if five LNG export terminals were shipping up to six billion cubic feet a day, “sure, that’ll have a huge impact,” Dawson said, but he cautioned that enormous volumes of shale gas are expected to come on stream in the United States over the next few years.

— DAILY OIL BULLETIN

DeeThree reports Bakken discovery DeeThree Exploration Ltd. says its fifth horizontal Bakken well has been drilled on the eastern portion of its Lethbridge, Alta., property to a planned total depth with a horizontal lateral of approximately 970 metres, in a significant, porous Bakken target zone.

The horizontal lateral was successfully fracture stimulated, placing 112 tonnes of sand over 14 stages using an energized water-based system.

After stimulation, the well was flowed for cleanup for four days up the 4.5-inch frac string with final stabilizing flowing rates of approximately 550 barrels per day of 30 degrees API reservoir oil and 60 thousand cubic feet per day of natural gas.

Final water cuts were approximately 10 per cent with further remaining load water from the fracture stimulation to be recovered. The well is currently shut in to remove the frac string and install a smaller-diameter production string.

The well is expected to be placed on production, shortly after which it will

undergo additional testing and evaluation procedures. The well will be tied in to DeeThree’s extensive oil and gas processing infrastructure. The well is located approximately 35 kilometres from DeeThree’s original Bakken discovery well.

The company said it is very pleased with the results of its Bakken exploration and development program on the Lethbridge property to date. The company’s greatly increased understanding of the Bakken play derived from the 2011 four-well Bakken test program and its extensive 3-D seismic, which has resulted in a more targeted approach to drilling on its acreage. This has resulted in DeeThree’s most significant Bakken discovery well to date.

Over the course of the six months preceding the drilling and completion of the well, DeeThree strategically added to its extensive land position in the Bakken fairway through its acquisition of an additional 17 sections of Crown land that are on trend

with this discovery well. DeeThree said it will continue to delineate this exploration discovery using its in-house geotechnical knowledge with follow-up drilling locations that are currently in the licensing process. The Bakken play will continue to be a primary focus for DeeThree.

Meanwhile, DeeThree said the farmee, under the farmout and joint venture agreement described in a prior DeeThree news release, has elected to terminate the agreement, after having drilled only one well of the four-well commitment. This well is currently producing.

The farmee earned a 60 per cent working interest in the well and in 6 sections of the farmout lands, and has no right to earn additional interests in the farmout lands.

A termination fee of $3 million has been paid to DeeThree. The lands subject to the agreement are located approximately 41 kilometres from the discovery well described above and targeted a different Bakken interval.

— DAILY OIL BULLETIN

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Southern Alberta

Southern Alberta Petroleum Show expanding coverage The oil and gas industry has an over 100-year history in southern Alberta, helping to build the city of Medicine Hat into a regional economic powerhouse. The Medicine Hat Chamber of Commerce has been a voice for the business community since its founding in 1900. Since 2006, the chamber has been using that voice to promote the oil and gas industry every second year through the Southern Alberta Petroleum Show.

“As a representative of the various industries within our region, we recognize that the oil and gas sector has always played an impor tant role in maintaining and grow ing a healthy and successf ul business communit y for Medicine Hat and area residents,” said chamber executive director Lisa Kowalchuk. “For this reason, we have taken a primar y role in showcasing this industry by organizing a biennial petroleum industry show since 2006.

This year, we have taken that initiative one step further by a broadened focus, new brand and new features.”

Kowalchuk said that the show, running from May 7 to 9, will be bringing industry together to provide service and supply companies with an opportunity to present their technologies, innovations and equipment to potential customers operating across western Canada with a focus on oil and gas plays.

“I n addit ion, we have a lso recognized the growing diversification within oil and gas companies, as well as the growth and expansion of alternative energ y producers,” she said.

“We are pleased to add this new focus to our show to bring the opportunity for all of those in the energy industry to net work and share resources and information. We have broadened the scope of the show, by branding it as the Southern Alberta Petroleum Show and maximizing the potential to showcase t he sout her n A lber ta reg ion.”

Medicine Hat is well positioned as a regional location for industr y and for a n i ndust r y-foc used show, sa id Kowalchuk.

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“We are situated along the No. 1 and No. 3 highways, close to the U.S. border and along the Ports-to-Plains Corridor, which provides a transportation network from Mexico to northern Alberta, and access to the CPR railway, as it dissects the city centre,” she noted. “As an industry, we have tremendous import/ export opportunity as bilateral trade f lows bet ween Montana and Canada climb upwards of $6.5 billion, with the largest proportion of trade coming in the sectors of energy, chemicals and metals.

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Saskatchewan

Manitoba, Saskatchewan report strong land sales

By James Mahony

FEB/11

FEB/12

FEB/11

FEB/12

WELLS SPUDDED

245

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WELLS DRILLED

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392

Photo: Joey Podlubny

interested, and we’ve been seeing the price per hectare creep up year after year. The companies may have to up their bids to ensure they get what they want at a land sale.”

Manitoba typically holds four land sales a year, and Lowdon said this year would be no different. At the year’s first sale, 56 lease parcels, covering 8,557.04 hectares (21,144.45 acres), were sold for a bonus amount totalling $8.02 million. The average price per hectare for lease parcels sold was $936.76, or $379.10 per acre.

The highest price per hectare was paid

by Scott Land & Lease Ltd. for a parcel in the Daly area. The firm paid $6,001.11 per hectare ($2,428.61 per acre) as a tender bonus.

Adding to Manitoba’s competitive atmosphere is a mineral rights environment that differs from Alberta’s. Unlike Alberta, most of Manitoba’s mineral rights are freehold, while Crown rights make up about 20 per cent of the land. In Alberta, the

reverse is true, with roughly 80 per cent of mineral rights held by the Crown, and roughly 20 per cent held by freeholder landowners.

“We don’t have a lot of Crown land in Manitoba. If you want to be a player, it’s fairly competitive,” said Lowdon. As for last year’s $13.14-million record, he is fairly confident it will fall at the next sale. “We’ll have some interesting properties coming up in future sales, and I think producers will be interested.”

The high-flying prices Manitoba has seen in the last few years are a far cry from only a few years ago, when land sales were not so lucrative. Lowdon recalls one land sale, roughly three years ago, when the province took in a grand total of $18,000.

For its part, Saskatchewan collected a tidy $28.73 million in its first land sale of the year, held Feb. 6, 2012, bringing the province’s total take for fiscal 201112 to $234.1 million, provincial staff said in a news release. As in Manitoba, fierce competition among producers was seen as the driver behind the strong prices being paid for Crown oil and gas rights in Saskatchewan.

“This was another solid land sale…and a very good start to the year,” Bill Boyd, Saskatchewan’s energy and resources minister, said. “What we saw was fierce competition among junior companies for dispositions, and strong interest in geological plays across the province beyond the Bakken and Lower Shaunavon.

“Major companies are busy working their existing inventories, and Saskatchewan is coming off its second-best year for oil well drilling [and] the signs are pointing to a great year ahead,” Boyd added.

February’s sale included 182 lease parcels that drew $26.4 million in bonus bids and six petroleum and natural gas exploration licences that sold for $2.3 million.

Land sales indicate strong drilling activity for Saskatchewan and Manitoba in 2012.

After breaking its own record in 2011, Manitoba’s first land sale of 2012 has broken all previous records for a single sale, while neighbouring Saskatchewan took in $28.73 million at its February 6 land sale.

Manitoba’s Petroleum Branch said its February 8 land sale yielded bids totalling $8.02 million. That compares with the record $13.14 million Manitoba collected for oil and gas rights in all of 2011. If the trend continues, the province would need to collect just over $5 million in the next sale, set for May 9, 2012, to beat last year’s record.

According to Keith Lowdon, director of Manitoba’s Petroleum Branch, the record sale is part of a longer-term trend toward more competitive bidding by oil and gas producers, whose numbers have risen in recent years as news of the province’s accessible, light oil reservoirs has spread.

“Manitoba is a lot more competitive now,” Lowdon said. “There are more companies SASKATCHEWAN WELL ACTIVITY

FEB/11

FEB/12

WELL LICENCES

377

461

▲

▲

▲

Source: Daily Oil Bulletin

OIL & GAS INQUIRER • APRIL 2012

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Technology News

Reservoir Quality—not frac—key to shale development

Photo: Aaron Parker

By Pat Roche

Despite the fracking technological revolution, the quality of the reservoir remains the most important factor in well economics.

Reservoir quality is the key determinant of well performance in shale reservoirs and the effect of the fracture stimulation is secondary, a Canadian Society of Petroleum Geologists luncheon heard in February.

So benchmarking to separate out the effect of reservoir quality on well performance can be a valuable tool for evaluating the stimulation effect and the changes that may be made to the frac treatment, said Randall Miller, president of the Integrated Reservoir Solution Division of Houston-based Core Lab. “I think the fracture stimulation design has a secondary impact on well performance, and needs to be optimized,” Miller told the technical luncheon attendants (about 850 people).

“The post-frac evaluation is critical in understanding the completion efficiencies and…frac-design modifications that need to be made,” he said.

Miller, a geologist, told the Daily Oil Bulletin he was using the term “shale” in the broad sense, and acknowledged that most of the rocks behind the so-called shale plays are technically not shales.

“We would classify them more as mudstones. They have a considerably lower clay content than what a true shale would be; and then in some cases, some of these ‘shales’ are actually carbonates, or marls [calcium carbonate or lime-rich mudstones containing variable amounts of clays and silt] like the Eagle Ford,” he said.

“We call it shale because that’s what everybody has grown accustomed to— the investment community, the public, the people in the industry. I prefer the term ‘source-rock reservoir.’”

Intended to bridge the gap between engineering and geoscience, Miller’s technical presentation dealt with hydraulic fracturing and the role of data in improving well performance and deliverability predictions.

The Core Lab executive focused on the role benchmarking can play in the analysis of well completions and wellstimulation effectiveness, and the need to optimize future frac treatments.

He said source-rock reservoirs require a great deal of technical work to exploit them fully at the lowest possible cost, and the key

to understanding these reservoirs is the integration of everything from core information to reservoir engineering to the geology.

While source-rock reservoirs contain enormous volumes of oil and natural gas, the technical challenges are also huge.

“We’re talking nanodarcies here as opposed to millidarcies. You’re looking at three, four, in some cases five times the order of magnitude lower-permeability,” said Miller.

That means a different approach than was taken with conventional reservoirs.

“Most stimulation designs treat the lateral as if it’s homogenous.... I think maybe what we’re seeing on the way forward may be that stimulation designs may need to take into account more geology,” Miller said.

“Perhaps that includes logging more lateral wells,” he said, but added, “Of course, there is cost associated with that; but I do think that you can determine reservoir quality for these shales, and that is the primary control in production, and the secondary control is the frac.”

Ulterra drill bits set records across U.S. resource plays Ulterra drill bits are proving their worth in tight resource plays across the United States, setting numerous records in the last six months.

In February, a new 12.25-inch U616M, six-bladed matrix, polycrystalline diamond compact (PDC) bit with 16-millimetre cutters set a Roger Mills County footage record in western Oklahoma. The Ulterra bit drilled 7,065 feet from surface casing down to a depth of 8,115 feet, saving the operator an estimated $44,500 versus the closest offset, and $88,500 versus the average of five offset wells.

This generation U616M is the result of extensive bit design and cutter testing in the Granite Wash play.

“A unique cutting profile along with the latest cutter technology gives the bit OIL & GAS INQUIRER • APRIL 2012

47

Technology News

unmatched durability in transitional drilling,” says Ryan Wedel, Ulterra applications engineering supervisor. “This allows the bit to maintain a high rate of penetration throughout the interval in a variety of interbedded formations.”

The U616M has set multiple footage records in the Granite Wash play.

In January, an Ulterra bit set records in the Eagle Ford play in Texas. The new U616M, 8.75-inch, six-bladed matrix bit with 16-millimetre cutters drilled from surface casing to total depth at a record pace of 93 feet an hour. All three intervals—the vertical, curve and lateral—were drilled with the same bottomhole assembly, reaching total depth without a trip out of the well. A total of 9,953 feet were drilled in 107 hours, a time savings of 37.5 hours over the fastest competitor offset of 144.5 hours.

Cost savings were $73,566 versus the direct offset and $133,024 versus the average of five competitor offsets.

The U616M bit embodies Ulterra’s aggressive directional design philosophy and incorporates new technology that makes it the first bit on the market that can maintain the high instantaneous rates of

penetration (ROP) required in the drill-out, as well as the ability to track straight in the lateral section. By contrast, curve bits typically follow passive designs, which make them directional-friendly but hinder their performance in the drill-out and lateral.

“Our number one goal in designing the U616M was to increase slide efficiency and reduce unnecessarily high slide percentages,” said Jacob Wendt, applications engineer.

The curve and lateral intervals are where the majority of the sliding takes place. To reduce or eliminate sliding, the bit must withstand the entire drill-out or vertical interval with an unscathed cutting structure and continue into the curve and lateral with the directional friendliness of a fresh bit.

The U616M cutting structure is designed to maintain sharpness throughout all three drilling intervals. Controlling how the PDC cutters interact with the formation minimizes torque fluctuations, resulting in better tool-face control, and minimized bit-induced stick-slip and reduced impact damage. The combined directional friendliness and performance

advantages of the U616M increase slide efficiency and motor yields to reduce slide percentage, increase overall ROP, keep the bottomhole assembly on bottom drilling longer and reduce total on-bottom drilling hours.

In September, in its first run in the Haynesville shale in the northeastern United States, Ulterra’s 6.75-inch UD511 bit set a new same-rig record for drilling a curve section, drilling the curve in 35 hours at an ROP of 23.4 feet an hour. The UD511 saved $33.5 per foot compared to the fastest competitor offset. The five-bladed bit with 11-millimeter cutters was a departure from the typical drilling program, in which seven-bladed, 11-cutter bits and two-plus degree bend motors have been used to ensure steerability while achieving build rates necessary to hit the target. Average penetration rates for the seven-bladed bits have been 12–15 feet an hour, although an Ulterra UD711 bit achieved a penetration rate of 20 feet an hour.

According to Chris Hearn, application engineer for Ulterra, the steel-body design and short-gauge configuration of the UD511 bit contribute to its superior performance.

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APRIL 2012 • OIL & GAS INQUIRER

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BUSINESS INTELLIGENCE Tax implications of operating a personal services business A look at the new rules proposed and how they may affect the industry Co-authored by Kim Drever, CA (MNP Grande Prairie) and Dylan Hughes, CA (MNP Calgary).

It is not uncommon for individuals to provide contract services through a personal business corporation to oil and gas companies.

From a tax perspective, it’s important to know whether these personal business corporations are classified as Personal Services Businesses (PSBs) for income tax purposes. On Oct. 31, 2011, the federal government released proposed legislation that, if enacted, could have a significant impact on the income tax rates of PSBs and how oil and gas companies contract with these corporations.

A typical client-contractor arrangement involves an individual (contractor) setting up a corporation, the corporation entering into work contracts with one or several oil and gas companies (the clients), the contracting company providing services to the client, the client paying the contracting company and the contracting company paying a salary to the contractor. In certain instances, a family member of the contractor may also be employed by the corporation. This arrangement typically provides numerous benefits to all parties involved.

Determining whether or not the activities of a corporation fall under the PSB classification for income tax purposes is very important. Generally, unless a PSB employs more than five fulltime employees or provides services to an associated corporation, income from a PSB is not eligible for the lower small-business tax rates. PSB income would be subject to the general corporate income-tax rates, which are eight to 19 per cent higher than the small-business rates (it varies by province). The Canada Revenue Agency outlines some of the factors that indicate an employeeemployer relationship, but there may be other factors to consider. If the contract terms lean towards the contractor being an employee and the contractor or someone related to him/her owns 10 per cent or more of the issued shares of the corporation, income earned by the contractor will generally be viewed as income from a PSB. This is where the October 31 proposed legislation comes in.

Under the proposed rules, income from a PSB earned in a tax year beginning after Oct. 31, 2011, will be subject to the maximum federal and provincial corporate-tax rates. These are even higher than the general corporate-tax rates that PSB income is currently taxed at. This effectively removes the potential for income tax deferrals. Contractors operating through a corporation should step back and assess their situation. Are they operating as a PSB? Are they at risk of being characterized as a PSB? Since a PSB determination is highly fact-specific and based on the cir-

cumstances of each contractual arrangement, it is a good idea to consult with a tax advisor to be sure.

What does this mean for the oil and gas industry?

In Alber ta, the federal and provincial combined corporatetax rate on PSB income would increase from 25 to 38 per cent. In Saskatchewan, the combined tax on PSB income would increase from 27 to 40 per cent. For these two provinces, that results in a whopping 13 per cent increase in corporate income tax. Don’t forget, in addition to these increased corporate income-tax rates, the contractor is still subject to personal income tax on any salaries or dividends paid by the corporation (refer to table).

Given the potential for additional tax liabilities to contractors securing work through a corporation, oil and gas companies may need to dust off their standard boilerplate contractor agreements and revisit their compensation strategy in order to continue to attract top talent willing to work on a contract basis.

Regardless of whether you work as a contractor in the industry or hire contractors to work for your business, the new PSB rules, if enacted, will impact your business. To get ahead of the curve, contact an experienced tax advisor who can help you understand the new rules and develop a tax plan that suits your needs.

AB

SK

Current

Proposed

Current

Proposed

Combined Federal & Provincial Corp.-Tax Rate

25%

38%

27%

40%

Total Corp. and Personal Tax on Income Earned Through a Corp.*

39%

50%

45%

55%

Total Personal Tax on Income Earned Directly by Contractor

39%

39%

44%

44%

0.47%

10.96%

1.11%

10.89%

Tax “Cost” of Earning Income Through a Corp. vs. No Corp.

Based on 2012 enacted rates.

Top personal marginal rates shown. *Assumes contractor receives dividend income from corporation.

OIL & GAS INQUIRER • APRIL 2012

49

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APRIL 2012 • OIL & GAS INQUIRER

Feature

Photo: Aaron Parker

can be reached, construction could begin later in 2012.

Pembina Pipeline Corporation is also Redwater is emerging as a nexus between the oilsands and the expanding its midstream operations in natural gas industry, with natural response to increasing liquids production, gas liquids providing diluent to chief executive officer Bob Michaleski said in ship raw bitumen. announcing its year-end results.

At its Cutbank complex, Pembina plans to expand Musreau’s shallow-cut gas processing capability by 50 million cubic feet per day, at a cost of $26 million and subject to regulatory and environmental approvals that should be in service by the middle of this year, said Michaleski.

Pembina has ordered much of the long– lead time equipment for its new Saturn and Resthaven gas processing plants and is currently in the consultation phase. It is working with its stakeholders and regulatory bodies on route selection and environmental planning for the pipeline portion of the work and is completing engineering work, he said.

Subject to regulatory and environmental chief executive officer, during the company’s delivering gas to the plant in the fourth quarapproval, both projects should be complete in the latter part of 2013. fourth-quarter results conference call. ter. Another producer is currently construct“If you look at some of the independent ing a 65-kilometre, 12-inch gathering pipeline The company continues to investigate data that’s put out there, the Western Canada to Keyera’s Simonette gas plant from lands several other opportunities to expand its gas Sedimentary Basin has some of the most ecoeast of the plant. service business. Many new developments are nomic gas because of the liquids components Other producers are actively drilling close to its existing infrastructure, and with in North America today,” Bertram said. “I wells and targeting multiple geological zones new technologies and a supportive price for think you’re seeing some Canadian producers around the plant.

NGLs, it expects to see the need for increased bringing some of that capital back from the Producers in the area have provided suffigas-handling requirements, he said.

U.S. dry shale plays, and we hope to redeploy cient expressions of interest to allow detailed “These new gas volumes, in combination in some liquids-rich plays. We’re just in the engineering estimates to be prepared for a with the liquids value embedded in the gas, right spot, so I continue to remain optimistic plant expansion and addition of deep-cut have created interest in new and updated facilities. Should commitments be secured gas plants with enhanced liquids-extraction that the first areas to get shut in and areas that won’t be drilled are the dry gas areas.” and terms and conditions met in a timely capacity and ethane-plus transportation In the fourth quarter, Keyera invested opportunities,” says Michaleski. manner, Keyera’s goal would be to complete $36.9 million to acquire additional ownerthe project by late 2013.

Demand for diluent is also driving ship interests in several gas plants in the expansion in the midstream. Keyera is well Refurbishment of the turbo-expander at west-central and foothills areas of Alberta, underway in advancing its plans to be a sigthe Minnehik Buck Lake gas plant is complete including the Strachan, Minnehik Buck Lake, and currently undergoing commissioning. nificant diluent supplier to the oilsands.

Bigoray and Paddle River gas plants.

At the Strachan gas plant, the upgrade of In the Edmonton/Fort Saskatchewan A number of producers continue to target the turbo-expander is expected to be comarea, the first of the two oilsands service liquids-rich gas from the Glauconite zone. In plete in the second half of 2012. Projects to agreements with Imperial Oil Limited began in December, with the completion of solventaddition, many of the high-value land parcels enhance propane recoveries at the Brazeau handling facilities at the Alberta Diluent purchased in 2011 targeting the liquids-rich River and Nordegg River gas plants were Duvernay shale are also in this area. As a result also completed in the fourth quarter and will Terminal (ADT). These facilities allow the GMC.GM.CA of producer success in 2011 and their prospecallow producer customers to extract signifidelivery of solvents by rail for Imperial’s tive future production, Keyera is considering an cantly more propane from their gas streams, Kearl oilsands project. MOBILE ENABLED expansion of the Carlos pipeline, and the possaid Keyera.

Work on Keyera’s Fort Saskatchewan STRONGER MORE sible construction of a new pipeline to deliver SMARTER With the anticipated increase in NGL Condensate System (FSCS), including a gas to Rimbey from lands west of the plant. production in western Canada, Keyera 21-kilometre, 20-inch condensate pipeline 1 3 2 there is sufficient producer support ® &isTRAILER evaluating expansion of its Fort connection the Polaris and a new (7,215 lb.IfCAPACITY) (397 hp) to • (765 lb.-ft.)pipeline STABILITRAK SWAY an CONTROL for these projects, Keyera may also conSaskatchewan fractionator, which would pump station at the Edmonton terminal, consider an expansion of the Rimbey gas plant allow the facility to accept an ethane-rich tinued during the fourth quarter and should PROVEN DURAMAX® DIESEL ANDstream ALLISON TRANSMISSION ® to recover additional quantities of ethaneof NGLs for processing. Keyera is be complete by mid-year 2012. FSCS is an 4 rich NGLs, it said. currently in discussions with customers integrated network of infrastructure through In the Simonette region, a producerinterested in securing capacity in the new which Keyera will provide diluent-handling 60,000 KMS BETTER THAN FORD owned 12-inch gathering pipeline began facility and, assuming commercial terms services for Imperial Oil and Husky Energy

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Photo: Aaron Parker

Feature

Redwater is emerging as a nexus between the oilsands and the natural gas industry, with natural gas liquids providing diluent to ship raw bitumen.

chief executive officer, during the company’s fourth-quarter results conference call.

“If you look at some of the independent data that’s put out there, the Western Canada Sedimentary Basin has some of the most economic gas because of the liquids components in North America today,” Bertram said. “I think you’re seeing some Canadian producers bringing some of that capital back from the U.S. dry shale plays, and we hope to redeploy in some liquids-rich plays. We’re just in the right spot, so I continue to remain optimistic that the first areas to get shut in and areas that won’t be drilled are the dry gas areas.”

In the fourth quarter, Keyera invested $36.9 million to acquire additional ownership interests in several gas plants in the west-central and foothills areas of Alberta, including the Strachan, Minnehik Buck Lake, Bigoray and Paddle River gas plants.

A number of producers continue to target liquids-rich gas from the Glauconite zone. In addition, many of the high-value land parcels purchased in 2011 targeting the liquids-rich Duvernay shale are also in this area. As a result of producer success in 2011 and their prospective future production, Keyera is considering an expansion of the Carlos pipeline, and the possible construction of a new pipeline to deliver gas to Rimbey from lands west of the plant.

If there is sufficient producer support for these projects, Keyera may also consider an expansion of the Rimbey gas plant to recover additional quantities of ethanerich NGLs, it said.

In the Simonette region, a producerowned 12-inch gathering pipeline began

delivering gas to the plant in the fourth quarter. Another producer is currently constructing a 65-kilometre, 12-inch gathering pipeline to Keyera’s Simonette gas plant from lands east of the plant.

Other producers are actively drilling wells and targeting multiple geological zones around the plant.

Producers in the area have provided sufficient expressions of interest to allow detailed engineering estimates to be prepared for a plant expansion and addition of deep-cut facilities. Should commitments be secured and terms and conditions met in a timely manner, Keyera’s goal would be to complete the project by late 2013.

Refurbishment of the turbo-expander at the Minnehik Buck Lake gas plant is complete and currently undergoing commissioning.

At the Strachan gas plant, the upgrade of the turbo-expander is expected to be complete in the second half of 2012. Projects to enhance propane recoveries at the Brazeau River and Nordegg River gas plants were also completed in the fourth quarter and will allow producer customers to extract significantly more propane from their gas streams, said Keyera.

With the anticipated increase in NGL production in western Canada, Keyera is evaluating an expansion of its Fort Saskatchewan fractionator, which would allow the facility to accept an ethane-rich stream of NGLs for processing. Keyera is currently in discussions with customers interested in securing capacity in the new facility and, assuming commercial terms

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APRIL 2012 • OIL & GAS INQUIRER

can be reached, construction could begin later in 2012.

Pembina Pipeline Corporation is also expanding its midstream operations in response to increasing liquids production, chief executive officer Bob Michaleski said in announcing its year-end results.

At its Cutbank complex, Pembina plans to expand Musreau’s shallow-cut gas processing capability by 50 million cubic feet per day, at a cost of $26 million and subject to regulatory and environmental approvals that should be in service by the middle of this year, said Michaleski.

Pembina has ordered much of the long– lead time equipment for its new Saturn and Resthaven gas processing plants and is currently in the consultation phase. It is working with its stakeholders and regulatory bodies on route selection and environmental planning for the pipeline portion of the work and is completing engineering work, he said.

Subject to regulatory and environmental approval, both projects should be complete in the latter part of 2013.

The company continues to investigate several other opportunities to expand its gas service business. Many new developments are close to its existing infrastructure, and with new technologies and a supportive price for NGLs, it expects to see the need for increased gas-handling requirements, he said.

“These new gas volumes, in combination with the liquids value embedded in the gas, have created interest in new and updated gas plants with enhanced liquids-extraction capacity and ethane-plus transportation opportunities,” says Michaleski.

Demand for diluent is also driving expansion in the midstream. Keyera is well underway in advancing its plans to be a significant diluent supplier to the oilsands.

In the Edmonton/Fort Saskatchewan area, the first of the two oilsands service agreements with Imperial Oil Limited began in December, with the completion of solventhandling facilities at the Alberta Diluent Terminal (ADT). These facilities allow the delivery of solvents by rail for Imperial’s Kearl oilsands project.

Work on Keyera’s Fort Saskatchewan Condensate System (FSCS), including a 21-kilometre, 20-inch condensate pipeline connection to the Polaris pipeline and a new pump station at the Edmonton terminal, continued during the fourth quarter and should be complete by mid-year 2012. FSCS is an integrated network of infrastructure through which Keyera will provide diluent-handling services for Imperial Oil and Husky Energy