Oil & Gas Inquirer April 2012

APRIL 2012 $6.00

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

plus: InstrumentatIon and automatIon Innovators drIve down cost of wellsIte monItorIng whIle makIng data access mobIle

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14 A P R I L 2 0 1 2 • O I L & G A S I N Q U I R E R

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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 eco-nomic 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 owner-ship 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 prospec-tive future production, Keyera is considering an expansion of the Carlos pipeline, and the pos-sible 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 con-sider an expansion of the Rimbey gas plant to recover additional quantities of ethane-rich NGLs, it said.

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

delivering gas to the plant in the fourth quar-ter. Another producer is currently construct-ing 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 suffi-cient 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 com-plete 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 signifi-cantly 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 pro-cessing 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 cur-rently in the consultation phase. It is working with its stakeholders and regulatory bodies on route selection and environmental plan-ning 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 sig-nificant 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 solvent-handling 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, con-tinued 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

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

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Keeping readers regionally informed

F E A T U R E S

Building the webBy Darrell Stonehouse

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

Easy accessBy Darrell Stonehouse

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

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I n E V E R y I S S U E

37 Central AlbertaFirst Nations refinery in limbo

By Elsie Ross

41 Southern AlbertaDevon Canada targets liquids

By Elsie Ross

45 SaskatchewanManitoba, Saskatchewan report strong land sales

By James Mahony

21 Fracturing operating practices unveiled by CAPP

47 Ulterra drill bits set records across U.S. resource plays

25 British ColumbiaTalisman focuses on Montney

By Richard Macedo

29 Northwestern AlbertaSlave Point carbonate cranking up

By Elsie Ross

33 Northeastern AlbertaAlberta changing approach to oilsands regulation

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50 Political Cartoon10 Stats at a Glance

49 Business IntelligenceTax implications of operating a personal services business

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N E X T I S S U E

Editor’s Note

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

Send your emails to [email protected]. Please mark them as "Letter to the Editor" if you want them published.

Darrell Stonehouse | [email protected]

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

An $18-billion failure

Vol. 24 No. 3EDIToRIAlEdItOR Darrell Stonehouse | [email protected] wRItERS Kim Drever, Dylan Hughes, Richard Macedo, James Mahony, Pat Roche, Elsie RossEdItORIAL ASSIStANCE MANAGER Samantha Kapler | [email protected] ASSIStANCE Laura Blackwood, Alison Dotinga, Brandi Haugen

cREATIVEPRINt, PREPRESS & PROdUCtION MANAGER Michael Gaffney | [email protected] SERVICES MANAGER Tamara Polloway-Webb | [email protected] LEAd Cathlene OzubkoGRAPhIC dESIGNER Peter MarkiwCREAtIVE SERVICESChristina Borowiecki, Janelle Johnson, Jeremy [email protected]

SAlESSALES MANAGER—AdVERtISING Maurya Sokolon | [email protected] ACCOUNt EXECUtIVE Diana SignorileSALES Nick Drinkwater, Ellen Fraser, Rhonda Helmeczi, Nicole Kiefuik, Jeff LeHoux, David Ng, Tony Poblete, Sheri StarkoFor advertising inquiries please contact [email protected] tRAFFIC COORdINAtOR—MAGAzINESDenise MacKay | [email protected]

DIREcToRSPRESIdENt & CEO Bill Whitelaw | [email protected] & dIRECtOR OF SALES Rob Pentney | [email protected] OF EVENtS & CONFERENCES Ian MacGillivray | [email protected] OF tHE DAily oil BullEtinStephen Marsters | [email protected] OF dIGItAL StRAtEGIES Gord Lindenberg | [email protected] OF CONtENt Chaz Osburn | [email protected] OF PROdUCtION Audrey Sprinkle | [email protected] OF MARkEtING Kim Walker | [email protected] OF FINANCE Ken Zacharias, CMA | [email protected]

oFFIcESCalgary 2nd Floor, 816 – 55 Avenue N.E. | Calgary, Alberta t2E 6Y4tel: 403.209.3500 | Fax: 403.245.8666 toll-Free: 1.800.387.2446Edmonton 6111 – 91 Street N.w. | Edmonton, Alberta t6E 6V6tel: 780.944.9333 | Fax: 780.944.9500toll-Free: 1.800.563.2946

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Made in Canadathe opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

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 prov-ince—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 esti-mate 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 dol-lars 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.

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561266V.J. Pamensky Canada Inc

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StatsAT A GLANCE

WCSB Oil & Gas CompletionsSource: Daily oil Bulletin

M O N T H O I L G A S D R Y S E R V I C E T O TA L

Feb 2011 723 378 38 99 1,238Mar 2011 1,069 1,081 64 164 2,378Apr 2011 618 509 46 81 1,254

Jun 2011 428 197 12 183 820Jul 2011 298 97 15 88 498Aug 2011 922 262 28 80 1,292

Sep 2011 1,448 445 24 155 2,072Oct 2011 1,153 321 20 49 1,543Nov 2011 1,170 331 27 42 1,570

Dec 2011 988 359 27 115 1,489Jan 2012 419 190 15 31 655Feb 2012 846 244 21 52 1153

Wells Drilled In British ColumbiaSource: B.C. Oil and Gas Commission

* from year to date

M O N T H W E L L S D R I L L E D C U M U L AT I V E *

Feb 2011 69 131Mar 2011 55 186Apr 2011 41 172

Jun 2011 54 419Jul 2011 56 479Aug 2011 40 519

Sep 2011 92 611Oct 2011 35 646Nov 2011 92 738

Dec 2011 58 796Jan 2012 53 53Feb 2012 66 119

*From year to date

Saskatchewan CompletionsSource: Daily oil Bulletin

M O N T H OIL GA S OTHER TOTA L

Feb 2011 321 6 7 334Mar 2011 316 8 4 328Apr 2011 183 11 11 205

Jun 2011 217 25 89 331Jul 2011 185 5 3 193Aug 2011 413 2 13 428

Sep 2011 352 4 29 385Oct 2011 457 29 46 532Nov 2011 524 4 32 560

Dec 2011 332 4 61 397Jan 2012 142 10 8 160Feb 2012 296 6 20 322

Alberta CompletionsSource: Daily oil Bulletin

M O N T H O I L G A S O T H E R T O TA L

Feb 2011 353 294 127 774Mar 2011 650 974 222 1,846Apr 2011 419 472 112 1,003

Jun 2011 209 124 100 433Jul 2011 105 43 97 245Aug 2011 452 183 93 728

Sep 2011 1,028 357 146 1,531Oct 2011 626 259 19 904Nov 2011 557 241 36 834

Dec 2011 568 300 72 940Jan 2012 215 131 35 381Feb 2012 491 177 50 718

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Drilling Activity: CBM & BitumenAlberta, March 2012 Source: Daily oil Bulletin

C O A L B E D M E T H A N E B I T U M E N W E L L S

Alberta Mar 12 Mar 11 Mar 12 Mar 11

Northwestern Alberta 2 3 19 17

Northeastern Alberta 0 0 50 50

Central Alberta 17 11 63 56

Southern Alberta 24 44 0 0

TOTAL 43 58 132 123

Service Rig Count by Province/TerritoryWestern Canada, February 13, 2012 Source: Rig locator

A C T I V E D O W N T O TA L A C T I V E

Western Canada (Per cent of total)

Alberta 518 234 752 69%

British Columbia 28 11 39 72%

Manitoba 12 9 21 57%

Saskatchewan 153 42 195 78%

WC TOTALS 711 296 1,007 71%

Drilling Activity: Oil & GasAlberta, March 2012 Source: Daily oil Bulletin

O I L W E L L S G A S W E L L S

Alberta Mar 12 Mar 11 Mar 12 Mar 11

Northwestern Alberta 162 92 2 3

Northeastern Alberta 50 50 0 0

Central Alberta 207 172 17 11

Southern Alberta 68 43 42 101

TOTAL 487 357 259 115

Drilling Rig Count by Province/TerritoryWestern Canada, February 13, 2012 Source: Rig locator

A C T I V E D O W N T O TA L A C T I V E

Western Canada (Per cent of total)

Alberta 378 210 588 64%

British Columbia 45 14 59 76%

Manitoba 6 13 19 32%

Saskatchewan 68 54 122 56%

WC TOTALS 497 291 788 63%

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

1,317663U.S. rigs drilling for gas in March; a 10-year low.

F A S T N U M B E R S

413088Annugas Compression Consulting Ltd

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With natural gas prices flounder-ing at lows not seen in a decade, western Canadian midstream operators are refocusing their

efforts to take advantage of a boom in natu-ral gas liquids (NGL) exploration and devel-opment 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 view-point, we see this period that we’re entering as probably the best growth period for com-panies of our kind in close to the history of the business,” said Doug Haughey, presi-dent 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 invest-ments 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 fundamen-tals 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 prov-ince 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 transpor-tation 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 antici-pated 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 fourth-quarter results.

Keyera is “reasonably optimistic” that it is in the right spot to see continued drilling in liquids-rich areas, said Jim Bertram,

Midstream expands to capture liquids growth, gas export opportunities and oilsands diluent needsBY dARRELL StONEhOUSE

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839601Veyance Technologies, Inc

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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 lso in Januar y, t he company announced an agreement with a subsidiary of Enbridge Inc., to solicit interest in the pos-sible 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 mid-stream is likely to be stretched as new lique-fied natural gas (LNG) terminals are built to export gas to higher-demand international markets in Asia. Growth in natural gas pro-duction 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 con-ference. “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 f inal 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 com-mitted to having the province’s first LNG plant in operation by 2015 and three LNG facilities operating by 2020.

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FEATUrE

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

Calgary-based Advanced Flow Technologies Inc. (AFTI) of Calgary released Watch-DOG, a low-cost technology for moni-toring 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 colour-coded 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 experi-ence 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 f lagship oilfield monitoring system. Smart-Alek is a remote plug-and-play EFM device that automatically monitors oil and gas pro-duction 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 autho-rized 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 appli-cation directly in the palms of oil and gas producers. With no soft-ware to download, users can immediately access existing Zedi

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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 opera-tor 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.

FEATUrE

Photo: Joey Podlubny

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

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General News


Fracturing operating practices unveiled by CAPP

chemical ingredients in fracturing fluid additives that are identified on Material Safety Data Sheets for each additive, including trade names, gen-eral 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 envi-ronmental risks associated with frac-turing 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 sam-pling programs and to participate in regional groundwater monitoring pro-grams; establish a process for address-ing stakeholder concerns regarding water well performance; and to con-tinue to collaborate with government and other industry operators. • Wellbore construction and quality assurance: To ensure that wellbores are designed and installed in a manner that maintains integrit y before hydraulic fracturing begins, including creating a continuous cement barrier to protect groundwater and develop-ing 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 assess-ing and measuring water sources, ensuring no withdrawal limits are exceeded, monitoring water sources as required to demonstrate the sus-tainability of the source, as well as collecting and reporting water-use data. Water measurement, sourcing and reuse practices will be made pub-licly available.

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

“The hydraulic fracturing operat-ing practices demonstrate the Canadian natural gas industry’s continued efforts to ensure responsible resource develop-ment 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 trans-parency over time, both of which contrib-ute to stronger understanding of industry activity and better relationships with the public, stakeholders and government.”

Developed by natural gas produc-ers, 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 con-struction, fresh water alternatives, recy-cling 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 con-tinuous 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 manage-ment and is committed to continuous performance improvement. Protecting the country’s water resources during sourcing, use and handling is a key pri-ority 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 fol-lowing specific operating practices.

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

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

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General News

• Fluid transport, handling, storage and disposal: To identify, evaluate and mitigate potential risks related to the transport, handling, storage and dis-posal 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 pub-licly available.“The establishment of Canada-wide

hydraulic fracturing principles and prac-tices is part of the natural gas industry’s ongoing efforts to ensure safe develop-ment of Canada’s shale gas resources,” said Collyer. “Shale gas can and is pro-duced responsibly every day across

Canada and the United States with almost 200,000 wells fractured in west-ern 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

Significant differences in new projects, which have benefited from greater indus-try collaboration, will challenge current public perceptions of the oilsands, execu-tives 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 differ-ent from projects that are already in opera-tion,” 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-barrel-per-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

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 defi-nitely 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 find-ing 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,

New oilsands projects making huge advancesBy Elsie Ross

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

“Part of this is being open and trans-parent,” 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 produc-tion 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.

Tehnical advances are making oilsands development more sustainable.

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General News

However, the best thing that is cur-rently happening in the industry is col-laboration, 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 col-laboration; 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 require-ments, 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 start-ing 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 some-thing 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 tail-ings 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 produc-ing 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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British Columbia

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

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

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Talisman focuses on MontneyBy Richard Macedo

“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 pro-gram 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

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.

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 con-tinue 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 fea-sibility 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 mea-sured 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 pos-sible 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


British Columbia

Mitsubishi to send gas to JapanJapan’s Mitsubishi Corporation will take a portion of its planned Cutbank Ridge natu-ral 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 acre-age 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 spend-ing 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 mil-lion 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 acknowledged that spending would ramp up over time under the Cutbank joint venture partner-ship, which will be owned 60 per cent by Encana and 40 per cent by Mitsubishi.

When asked whether the level of spend-ing on the Encana/Mitsubishi Cutbank part-nership 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 announc-ing the deal, Jun Yanai, Mitsubishi’s execu-tive vice-president and head of its energy business group, said, “Mitsubishi looks forward to tapping new natural gas sup-plies 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 part-ners 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 condi-tions must be met before the LNG export plan gets a green light. These include off-take 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 cer-tain amount of the capacity of the facility [through] a long-term commitment,” he said. “In exchange for that long-term com-mitment, 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 con-sidering 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 reach-ing agreements with off-takers, since the FEED study will provide a detailed cost estimate.


B.C. unveils gas strategyB.C. Premier Christy Clark announced British Columbia’s natural gas strategy in February, with LNG exports being a cor-nerstone 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 natu-ral gas [LNG] as a cornerstone of British Columbia’s long-term economic success.”

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

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 commu-nities; continued strong leadership on clean energy and climate change moving forward; and a redefinition of the prov-ince’s self-sufficiency policy to ensure that British Columbia is well-positioned for power expansion.

Over the next five years, job open-ings 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, engi-neering, construction and environmental management, the government said.

“B.C.’s natural gas will help with the transition to a low-carbon global econ-omy 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

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British Columbia has become the first prov ince in Canada to enforce the public disclosure of ingredients used for hydraulic fracturing.

The registry that provides a transpar-ent account of B.C. hydraulic fracturing operations—FracFocus.ca—includes a database of the ingredients used to sup-port 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 ingredi-ents 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 ground-water and the environment. The govern-ment 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 partici-pation by other jurisdictions so there can be one national site for disclosure information.

The government says that the web-site 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 trans-parency of hydraulic fracturing in the province.

B.C. frac registry online

introduce more ambitious means of off-setting greenhouse gas emissions, such as carbon capture and storage, while bal-ancing growth.”

BC LNG Export Co-operative LLC and Kitimat LNG will access clean energy from the province’s existing grid, the govern-ment 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 facili-ties 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 infrastruc-ture 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.

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NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY

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WELL LICENCES 218 263 ▲

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WELLS DrILLED 296 298 ▲


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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.

“have seen the highest consistent pro-duction 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 pro-ducing 200, 300, 400, 500 or even more barrels a day.”

T hat emerging potent ial 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 sec-tions 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

Clustered in parallel trends around the edges of the Peace River Arch in north-ern Alberta, the Slave Point carbonate play is the latest to owe its success to horizontal wells and multistage fractur-ing 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 wide-spread 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, res-ervoirs 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 chal-lenge 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 for-mations and in Penn West wells, interest wells and competitor wells, these plays,

Slave Point carbonate cranking upBy Elsie Ross



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 equiv-alent 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 oper-ating officer, told a recent investor con-ference. 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 vice-president 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 pro-duction 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 bat-tery and is filling an existing pipeline, drilling four wells with eight laterals per section. It uses sand fracs for com-pleting 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.

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 com-bination of cash flow, debt and the capi-tal raised through a recently completed $42.3-million financing.

In announcing its 2012 guidance, the company estimates that funds from opera-tions for the year will come in at between $34 million and $38 million, while aver-age 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 pro-duction of 1,880 barrels per day (71 per cent oil). Production for the month of December averaged 1,655 barrels per day, represent-ing 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

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 fair-way with light oil potential in two zones. The company noted that it is well posi-tioned to exploit the light oil potential at Steen River, Maxhamish and Amber.

At the company’s North Marlowe prop-erty 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 con-taining 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 hori-zontal wells at Amber.


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

The company said that estimated aver-age 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 quar-ter 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 mate-rial 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, under-taken 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 proba-ble 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 produc-tion 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 suc-cessful transaction.


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Northeastern Alberta

NORTHEASTERN ALBERTA WELL ACTIVITY

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Alberta changing approach to oilsands regulationBy James Mahony

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

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 pro-ject 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 environmen-tal laws are under review, and may have implications for Canadian oilsands devel-opers. 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 opera-tors 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 prov-ince 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 govern-ment 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

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

In early February, the Alberta gov-ernment 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 environmen-tal lawyer, addressed the conference and agreed the task of creating a single regu-lator 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

energy projects [rather than] merging all of those government departments,” said Harper, with the Calgary office of Blake, Cassels & Graydon LLP. “It will be inter-esting 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 regula-tion represented by the government’s Lower Athabasca Regional Plan (LARP), expected to become law in the near future. The plan rep-resents 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 look-ing at your oilsands operation in the con-text of other industry operations in your area. You can no longer look at your pro-ject in isolation. Today, you have to look at it in concert with others in your region.”





the $15-per-tonne fee. Now, instead of set-ting 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 audi-ence. “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 chal-lenge 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 recordMEG Energy Corp. set a quarterly produc-tion 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 reser-voir and the effort of its employees to main-tain efficient and reliable operations, Bill McCaffrey, MEG president and chief execu-tive officer, said in a conference call to dis-cuss fourth-quarter and year-end results. The SOR was also significantly better than the facility design rate of 2.8, said the com-pany. The SOR for the year was 2.4.

Production also benefited from the flush production, which occurred as heated bitu-men continued to drain in the steam cham-ber towards the producing wells during the turnaround and the debottlenecking activi-ties 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 bar-rels 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

per barrel for the same period in 2010. After including the contribution of revenue from power sales at MEG’s cogeneration facili-ties, 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 rela-tively 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 bar-rels per day of design capacity. Capital invest-ment in 2011 of more than $984 million focused on Christina Lake Phase 2B develop-ment and resource delineation at Christina Lake, Surmont and the growth properties and expansion of the Access Pipeline.

Approximately $710 million of the esti-mated $1.4-billion project cost for Phase 2B has been invested to date and approxi-mately 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 construc-tion scheduled to continue through 2012 with completion targeted in 2013, and MEG believes it is on track to meet its cost esti-mate, 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 accom-modate growth and add value to planned production by advancing MEG’s market diversification strategy.

In 2012, MEG will focus on further reduc-ing costs, continuing to lower its SOR and finding ways to continue to increase produc-tion and plant throughputs, said McCaffrey. One initiative is infill wells, which the com-pany 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 sched-ule, the timing is right as MEG believes infill wells should be most effective on well clus-ters 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 non- condensable 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 maintain-ing 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.


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Imperial Oil Limited has approved a $2-billion expansion of its Cold Lake cyclic steam stimulation (CSS) operation in northeast-ern 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 bar-rels 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 pro-duction 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

Imperial sanctions Cold Lake expansion

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

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 facili-ties. Imperial will be developing the same resource with about 40 per cent fewer sur-face pads as the result of advances in drill-ing 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 bar-rels of bitumen per day from the Leming, Maskwa, Mahihkan and Mahkeses projects.

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Central Alberta

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WELLS SPUDDED 246 230 ▼

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

First Nations refinery in limboBy Elsie Ross

Alberta First Nations chiefs are still hope-ful 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 engi-neering and had raised significant equity, said Horn.

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 com-pany 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 conditional-commitment agreement. At the time, the government under the North West Partnership Trade Agreement assessed that government-to-government negotia-tions were appropriate and that no request for proposals (RFP) was required for AFNEC’s application under the BRIK pro-gram, given the First Nations co-ownership of the project.

In May 2011, AFNEC and govern-ment bureauc rats conc luded t heir negotiations on the agreement and rec-ommended it to caucus and cabinet. PwC Canada, which conducted a com-prehensive evaluation on behalf of the federal government, had a strong recom-mendation 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 agree-ment demonstrated the economics and appropriate risk-and-return thresholds for each party, including milestone obli-gations demonstrating future feasibility. The project’s viability was further sup-ported by analysis conducted internally


Central Alberta

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

Horn said that initially the Alberta gover n ment, wh ic h would ow n 75 per cent of the product, was worried about markets for the ref ined prod-uct. However, Teedrum had a partner-ship with global energy trader Vitol, which agreed to take all finished prod-ucts from the government on a weekly basis. Teedrum was also prepared to bid for capacit y on K inder Morgan Canada’s proposed Trans Mountain 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-to-government basis.”

PwC determined a market valua-tion of $50 mill ion pre-BR IK agree-me nt a nd $1 bi l l ion p o s t– s ig ne d conditional agreement. “It was obvi-ous to have the government say ‘Let ’s see what happens at no r isk to us, and in two years if things look win-win-win we’ll move ahead, and if not, everybody goes away.’”

Teedrum would have raised money from the equity markets and the com-pany’s Chinese and Indian partners. Teedrum had memorandums of under-standing 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 poten-tial of billions of dollars in new revenue f lowing directly to Alberta taxpayers over the course of the agreement.

“This project f its the federal and provincial interest in making the most of our natural resources,” Horn said in a statement. “Building a ref inery builds an economy. It creates jobs, supports social initiatives benefiting Alberta taxpayers and attracts inter-national 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.”

By producing diesel fuel in Alberta, the $5-bil l ion North West upgrader 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 hydrocracking process produces about 1.3 barrels of diesel fuel for every barrel of bitumen, compared to coking, which produces about 0.8 bar-rels of SCO, Ian MacGregor, chairman of North West Upgrading Inc., told the Insight Canadian Oilsands Summit. “E ssent ia l ly, it ’s fac tor y-produced 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 get-ting 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

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 pro-ject approval, is currently working on engineering for the 150,000-barrel-per-day refinery near Redwater, which would be built in three 50,000-barrel-per-day stages. The project has yet to be sanc-tioned 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 -year cost-of-ser v ice agreement with the Alberta govern-ment, 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) pro-gram while CNRL will contribute the additional 12,500 barrels per day.

“There’s sort of a weak understand-ing 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 pro-ducer over time, MacGregor noted.

The province selected North West to upgrade its bitumen fol lowing 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 hile some have cr it ic ized the 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.

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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 any-body thinks that’s a subsidy, I want one.”

Responding to a quest ion about how much upgrading should be done in Alberta, he suggested a balanced approach is needed with bitumen, syn-thetic 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 con-tribute 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 CO2—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 con-verts 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 pro-duces 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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A shortage of diesel fuel in western Canada, combined with export potential, will make the North West upgrader a money-maker, says Ian MacGregor.

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SOUTHERN ALBERTA WELL ACTIVITY

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Devon Canada targets liquidsBy Elsie Ross

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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 con-tinued 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 produc-tion, said in a conference call to discuss fourth-quarter and 2011 results.

Canadian production averaged 188,700 barrels equivalent per day (net) of royal-ties 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.

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 com-plete 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 win-ter’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 acqui-sition 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 run-ning near capacity and the second phase continuing to ramp up, the company this year expects to grow its thermal produc-tion 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 produc-tion to between 150,000 and 175,000 bar-rels 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 types across its more than four mil-lion 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 the company is also encouraged by early results of the Viking light oil play in Saskatchewan, although it is still in the early stages of evaluat-ing these and several other emerging liquids plays in Canada. Devon plans to continue this effort in 2012, spend-ing approximately $350 million drilling some 90 exploratory wells.

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


Southern Alberta

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 trans-portation 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 pen-alty might be. And we have seen that [in the past],” Kallio said.

“Because we’re so fat with stor-age right now—because of this push-back 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 liquid-ity in the market. “During the shoul-der 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,

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.

Natural gas producers may be paying customers this summer

“ 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

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

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DeeThree reports Bakken discoveryDeeThree 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 evalu-ation 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 discov-ery well.

The company said it is very pleased with the results of its Bakken explora-tion and development program on the Lethbridge property to date. The com-pany’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 pre-ceding the drilling and completion of the well, DeeThree strategically added to its extensive land position in the Bakken fair-way 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 loca-tions that are currently in the licensing pro-cess. 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 work-ing 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.


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 vol-umes of shale gas are expected to come on stream in the United States over the next few years.


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Southern Alberta Petroleum Show expanding coverageThe 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 power-house. The Medicine Hat Chamber of Commerce has been a voice for the busi-ness 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 rec-ognize that the oil and gas sector has always played an important role in maintaining and growing a healthy and successful business communit y for Medicine Hat and area residents,” said chamber executive director Lisa Kowalchuk. “For this reason, we have taken a primary role in showcasing this industry by organizing a biennial petroleum industry show since 2006. This year, we have taken that initia-tive one step further by a broadened focus, new brand and new features.”

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

“In addit ion, we have a lso rec-ognized the growing diversif ication within oil and gas companies, as well as the growth and expansion of alter-native 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 network 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 show-case the southern A lberta region.” Medicine Hat is well positioned as a regional location for industry and for an industr y-focused show, said Kowalchuk.

“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 net-work from Mexico to northern Alberta, and access to the CPR railway, as it dis-sects the city centre,” she noted. “As an industry, we have tremendous import/export opportunity as bilateral trade f lows between Montana and Canada climb upwards of $6.5 billion, with the largest proportion of trade coming in the sectors of energy, chemicals and metals. We recognize that now is the time to showcase the industr y and provide an opportune time to bring industry together in our region. Now more than ever we need to start focusing on diver-sification and looking at addressing our economy as a whole, through develop-ment of our energy resources, focusing on diversification in oil and gas produc-tion, exportation of goods and services in the industry and a stronger focus on technologies, manufacturing and entre-preneurial development.”


SASKATCHEWAN WELL ACTIVITY

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WELLS DrILLED 251 392 ▲


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

Manitoba, Saskatchewan report strong land sales By James Mahony

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 2011-12 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 dis-positions, 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 par-cels that drew $26.4 million in bonus bids and six petroleum and natural gas explora-tion licences that sold for $2.3 million.

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 total-ling $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 pro-ducers, 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

interested, and we’ve been seeing the price per hectare creep up year after year. The com-panies 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 par-cels, covering 8,557.04 hectares (21,144.45 acres), were sold for a bonus amount total-ling $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 environ-ment 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

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Reservoir Quality—not frac—key to shale developmentBy Pat Roche

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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 sec-ondary, a Canadian Society of Petroleum Geologists luncheon heard in February.

So benchmarking to separate out the effect of reservoir quality on well perfor-mance can be a valuable tool for evaluat-ing 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 atten-dants (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 mud-stones. 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 mud-stones 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 tech-nical presentation dealt with hydraulic fracturing and the role of data in improv-ing well performance and deliverability predictions.

The Core Lab executive focused on the role benchmarking can play in the analysis of well completions and well-stimulation 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 inte-gration 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 lat-eral 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 res-ervoir 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 playsUlterra 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



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unmatched durability in transitional drill-ing,” says Ryan Wedel, Ulterra applica-tions engineering supervisor. “This allows the bit to maintain a high rate of penetra-tion 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 sur-face 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, reach-ing 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 typi-cally 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 per-centages,” 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 cut-ting structure and continue into the curve and lateral with the directional friendli-ness of a fresh bit.

The U616M cutting structure is designed to maintain sharpness through-out all three drilling intervals. Controlling how the PDC cutters interact with the for-mation 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 drill-ing 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 fast-est 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.

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 per-sonal business corporations are classified as Personal Ser vices 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 (con-tractor) 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 contrac-tor may also be employed by the corporation. This arrangement typi-cally provides numerous benefits to all parties involved.

Determining whether or not the ac tivities of a corporation fall under the PSB classification for income tax purposes is ver y impor tant. Generally, unless a PSB employs more than five full-time employees or provides ser vices to an associated corpora -tion, 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 employee-employer 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 Oc tober 31 proposed legislation comes in. Under the proposed rules, income from a PSB earned in a tax year beginning af ter Oct. 31, 2011, will be subject to the maximum fed-eral and provincial cor porate -ta x rates. These are even hig her than the general corporate-tax rates that PSB income is currently taxed at. This ef fec tively removes the potential for income tax deferrals. Contrac tors operating throug h a corporation should s tep back a nd assess t h eir sit ua tion . A re t h ey opera ting as a P SB? Are they at risk of being charac terized as a P SB? Since a P SB determination is hig hly fac t- specif ic 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 corporate-

tax 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 con-tractor is still subject to personal income tax on any salaries or divi-dends 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 strateg y 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, con-tact an experienced tax advisor who can help you understand the new rules and develop a tax plan that suits your needs.

Co-authored by Kim Drever, CA (MNP Grande Prairie) and Dylan Hughes, CA (MNP Calgary).

BUSINESSINTELLIGENCE

Tax implications of operating a personal services business

A look at the new rules proposed and how they may affect the industry


Based on 2012 enacted rates. Top personal marginal rates shown.

*Assumes contractor receives dividend income from corporation.

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%

Tax “Cost” of Earning Income Through a Corp. vs. No Corp. 0.47% 10.96% 1.11% 10.89%

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Tundra Process Solutions Ltd . . . . . . . . . . . . . . . 2

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