Page 1


CONTENTS

FEBRUARY.

in the news

9

Futures show long-term oil price declining and gas price remaining flat, says Deloitte

regional news

13

British Columbia

21

Northeastern Alberta

29

Southern Alberta

Painted Pony targeting Montney in 2014

SAGD chosen for Imperial Oil’s proposed

Medicine Hat and LGX want review of

Athabasca oilsands project

greater sage-grouse protection order

17

25

33

Northwestern Alberta

Central Alberta

Saskatchewan

New report looks at infrastructure

Bellatrix sets gross budget at over

Saskatchewan resource sector

needs in Peace Country

$600 million

momentum to continue in 2014

features

Cover Feature

38 43

Breaking the Duvernay Explorers hope to commercialize massive shale play in 2014

every issue

6 Stats at a Glance 46 Political Cartoon

Heavy advances Producers continue pushing forward with technologies to capture more heavy oil resource

Cover design: Peter Markiw

OIL & GAS INQUIRER • february 2014

3


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Editor’s Note Vol. 26 No. 2 EDITORIAL EDITOR

Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS

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Last month the National Energy Board (NEB) released a study pegging the marketable gas resource in the Montney Formation straddling Alberta and British Columbia at 449 trillion cubic feet. “At current consumption rates, the Montney gas resource would meet Canadian needs for 145 years,” said NEB chief executive officer Gaetan Caron. “The report clearly shows that the Canadian energy market will be well supplied with natural gas far into the future.” No kidding. The NEB report went on to say the total ultimate potential for natural gas in western Canada is 632 trillion cubic feet, but that number is likely to increase substantially. How much? Well, the Alberta government currently pegs the Duvernay’s total resource at 443 trillion cubic feet. The Muskwa likely has another 419 trillion cubic feet, the Nordegg another 148 trillion cubic feet and the Wilrich another 246 trillion cubic feet for a total 1,256 trillion cubic feet of resource. If only 10 per cent of this resource is produced, you can add another 100 years of supply. And, “this is not the end, this is a beginning for us,” Dean Rokosh, section leader for energy resource appraisal at the Alberta Energy Regulator, said in releasing the province’s resource estimate. “Those numbers will get larger and probably be substantially larger.” Then there’s the Horn River and Liard Basin in northeastern British Columbia. The NEB’s medium estimate of marketable gas for the Horn River is 78 trillion cubic feet. For the Liard Basin, which is in the early stages of

exploration, the number is expected to be even higher. Apache is claiming almost 50 trillion cubic feet of gas on its land base. Using cigarette-pack math, the numbers add up to an over 300-year supply of natural gas in the tank, with more to come. What does all this mean? For the foreseeable future, Canadian natural gas producers aren’t going to feel the pull of demand for their product. Instead, they are going to be pushing supply, and when an industry is pushing supply, it is competing on price and price alone. The immediate results of this are obvious. Without liquids content, drilling for natural gas is a good way to lose money. In fact, I will go as far as to say dry gas is becoming a by-product of liquids production. This means the wet parts of the Montney, Duvernay and Wilrich will be where the action is. Many in the industry are betting on liquefied natural gas (LNG) exports to save them, but they will only allow for some production growth. Last month the NEB issued four approvals for LNG export licences for proposed terminals, bringing the total to seven. “I was not surprised to see these decisions here,” Edward Kallio, director of gas consulting for Ziff Energy, a division of HSB Soloman Associates LLC, said after the announcement. “Canadians aren’t going to be left wanting for gas even after this gas is exported and accounting for Canadian and export demand.”

Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com

Subscription Inquiries Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: junewarren-nickles.com GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2014 JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240. Postage paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 80 Valleybrook Dr, North York, ON M3B 2S9 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

N E XT I S S U E March 2014 Inside Canada’s oilfield manufacturing business, plus a review of the massive Montney play on the Alberta/British Columbia border.

Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as ”Letter to the Editor” if you want them published.

OIL & GAS INQUIRER • FEBRUARY 2014

5


FAST NUMBERS



trillion cubic feet

Alberta government medium estimate of Duvernay natural gas resource.



billion barrels

Alberta government medium estimate of Duvernay liquids and oil resource.

alberta Completions

WCSb Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin T O TA L

MONTH

OIL

GAS

D RY

SERVICE

51



Dec 

802

164

17

71

9



Jan 

542

87

7

9



67



feb 

899

161

17

83

,

149

119



Mar 

949

198

21

127

,

91

129



apr 

581

146

18

127



273

56

1

75



M O NTH

OIL

GAS

Dec 

483

105

Jan 

313

59

feb 

449

124

Mar 

544

apr 

481

OTHER

T O TA L ,

Jun 

179

14

73



Jun 

Jul 

263

59

51



Jul 

671

103

15

51



817

72

1

39



aug 

394

46

34



aug 

Sep 

357

72

29



Sep 

735

113

1

30



Oct 

528

153

72



Oct 

953

204

8

79

,

Nov 

463

164

44



Nov 

852

218

9

62

,

Dec 

298

137

52



Dec 

675

180

20

72



Wells Drilled in british Columbia

Saskatchewan Completions

Source: B C Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS DRILLED

C U M U L AT I V E *

MONTH

OIL

GAS

Dec 

65

636

Dec 

282

1

34



Jan 

31

31

Jan 

174

0

5



feb 

42

73

feb 

358

0

31



Mar 

66

139

apr 

Mar 

323

0

19



69

208

Jun 

45

330

apr 

88

1

5



Jul 

49

379

Jun 

80

0

2



aug 

26

405

Jul 

358

1

13



Sep 

43

422

Oct 

52

474

Nov 

58

532

Dec 

45

45

*From year-to-date

OTHER

TOTAL

aug 

362

1

6



Sep 

347

0

1



Oct 

380

0

15



Nov 

339

0

27



Dec 

321

0

39



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february 2014 • OIL & GAS INQUIRER


STATS

AT A

GLANCE

Drilling rig Count by Province/Territory

Drilling activity: Oil & Gas

Western Canada, January 14, 2014 Source: Rig Locator

Alberta, December 2013 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada alberta

AC T I V E

OIL WELLS

Alberta

GAS WELLS

Dec 

Dec 

Dec 

Dec 

429

133



76%

Northwestern alberta

97

147

90

64

british Columbia

67

11



86%

Northeastern alberta

52

112

0

0

Manitoba

13

7



65%

Central alberta

162

200

11

5

Saskatchewan

108

35



76%

Southern alberta

22

65

38

44

WC TOTaLS







%

TOTaL









Service rig Count by Province/Territory

Drilling activity: CbM & bitumen

Western Canada, January 14, 2014 Source: Rig Locator

Alberta, December 2013 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada

alberta

AC T I V E

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

Alberta

BITUMEN WELLS

Dec 

Dec 

Dec 

Dec 

304

211



59%

Northwestern alberta

0

0

5

15

british Columbia

9

13



41%

Northeastern alberta

0

0

52

112

Manitoba

6

7



46%

Central alberta

0

0

86

88

Saskatchewan

103

46



69%

Southern alberta

6

4

1

0

WC TOTaLS







%

TOTaL





OIL & GAS INQUIRER • february 2014

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IN THE

NeWS Issues affecting Canada’s E&P industry

declining

futures show long-term oil price declining and gas price remaining flat, says Deloitte Deloitte LLP’s resource Evaluation & Advisor y group released its current Canadian domestic oil and gas price forecast in early January, along with a stern word of caution for investors. Deloitte’s analysis of the trends in futures pricing since 2010 gives a strong indication that oil is on its way down and that natural gas prices will remain flat as far out as 2021 and 2022. In the commentary accompanying Deloitte’s Dec. 31, 2013, forecast, Andrew Botterill, senior manager, Resource Evaluation & Advisory, tracked the futures trends for Henry Hub Natural Gas, AECO gas and West Texas Intermediate (WTI) oil from March 2010 through December 2013. “The trends suggest that the long-term futures market for gas is predicting continued

oversupply in North America,” Botterill commented. “The other interesting trend is the ever-decreasing value of natural gas during the last year of each dataset. The December 2013 futures price for natural gas is $6.04 per thousand cubic feet. That’s a far cry from the $8.50 per thousand cubic feet futures price listed three years ago.” With respect to WTI oil, Botterill noted the key observation is that, regardless of the starting price at the time, the long-term futures price has been in a downward trend since March 2011. “The moral of the story,” said Botterill, “is that energy companies and investors need to plan with caution and factor in the long-term implications of their decisions. What you see today, you may not be able to realize tomorrow.”

Deloitte’s Dec. 31, 2013, forecast shows WTI oil at US$95 per barrel for 2014, decreasing to US$90 for 2015 and eventually levelling out at US$85 per barrel by 2018. Deloitte continues to forecast a C$5 per barrel differential between WTI and Edmonton Par that will decrease to C$2 per barrel over the long term to match pipeline tariffs between the two markets. With respect to natural gas, Deloitte’s Dec. 31, 2013, forecast shows natural gas at an Alberta AECO real price of C$3.70 per thousand cubic feet in 2014, rising to C$3.85 for 2015 and up to C$5.70 by 2024. Deloitte’s NYMEX real price is forecast at US$4.10 per thousand cubic feet throughout 2014, rising to US$4.15 for 2015 and up to US$6 by 2024. — DAILY OIL BULLETIN

Deloitte resource evaluation & advisory Canadian domestic forecast base case forecast effective Dec. ,  Natural gas liquids pricing edmonton Par prices

Natural gas pricing

WTI at Cushing, Okla US$/bbl current

Edmonton City Gate C$/bbl current

WCS 20 5 deg API Hardisty C$/bbl current

Bow River 25 deg API Hardisty C$/bbl current

Heavy oil 12 deg API Hardisty C$/bbl current

Ethane C$/bbl current

Propane C$/bbl current

Butane C$/bbl current

Pentanes + condensate C$/bbl current

Alberta reference average price C$/mcf current

NYMEX US$/mcf current

2014

$95 00

$95 75

$72 75

$80 00

$68 75

$10 20

$33 50

$76 60

$105 35

$3 45

$4 10

2015

$91 80

$92 30

$70 30

$76 30

$66 30

$10 95

$32 30

$73 85

$101 55

$3 70

$4 25

2016

$91 55

$95 20

$72 20

$77 35

$68 20

$11 40

$52 35

$76 15

$104 70

$3 85

$4 40

2017

$91 25

$94 80

$72 80

$76 80

$68 80

$12 00

$52 15

$75 85

$104 30

$4 05

$4 60

2018

$92 00

$95 60

$72 60

$75 65

$68 60

$12 75

$52 60

$76 50

$105 15

$4 30

$4 85

2019

$93 85

$97 50

$74 50

$76 50

$70 50

$13 65

$53 65

$78 00

$107 25

$4 60

$5 20

2020

$95 70

$99 45

$76 45

$78 45

$72 45

$14 85

$54 70

$79 55

$109 40

$5 00

$5 55 Source: Deloitte

OIL & GAS INQUIRER • february 2014

9


In The News

Nova Scotia

by Pat roche

Drill ship off Newfoundland. Rigs will be returning to Nova Scotia in 2015 with Shell planning seven deepwater tests.

royal Dutch Shell plc plans to drill up to seven deepwater exploration wells in the Shelburne Basin, about 250 kilometres southeast of Halifax. Water depths range between 1,000 and 3,000 metres over the planned project area, a geological region known as the Shelburne Basin on the southwestern Scotian Slope. The area is about 1.5 hours from Halifax by helicopter, and 12 hours at a vessel speed of 12 knots (22 kilometres an hour). In a project description fi led with the Canadian Environmental Assessment Agency, Shell says up to seven wells will be drilled over four years from 2015 to 2019. The federal agency, which will decide whether to require an environmental assessment, is currently seeking public comments. In its project description, Shell says a single environmental assessment will meet the requirements of both the Canadian Environment Assessment Act and the Canada-Nova Scotia Off shore Petroleum Board (CNSOPB). 10

february 2014 • OIL & GAS INQUIRER

However, the CNSOPB will also require a report on the expected economic benefits and various safety and environmental considerations such as a spill contingency plan. Specific spending estimates weren’t provided. Shell’s total work commitment offshore Nova Scotia under the exploration licences issued in March 2012 and January 2013 is about $998 million. Exploration licences 2427 and 2428 (which were part of the January 2013 award, along with 2429 and 2430), aren’t part of the Shelburne Basin project for which regulatory approval is being sought. The project area covers 7,870 square kilometres, or 40 per cent of the total area of Shell’s licences (19,845 square kilometres). The project will be divided into two separate drilling “campaigns,” or programs. Specific drilling locations haven’t been determined yet. The fi rst well location will be based on the results of the Shelburne Basin 3-D seismic survey shot last summer.

Shell said the choice of rig, which hasn’t yet been made, will depend on suitability and availability. The project will require an ultra-deepwater, year-round drillship or semi-submersible. An onshore supply base, two or three support vessels and helicopter support will be needed. The location of the supply base, which will be owned and operated by a third party, hasn’t been determined yet. Shell said one of four industrial port locations will be chosen for the supply base—the Halterm Container Terminal, Richmond Terminals or Woodside Atlantic Wharf, all in Halifax harbour, or Mulgrave Marine Terminal on the Strait of Canso. The supply base contract is expected to be awarded in the first quarter of 2014. Pending regulatory approvals, preparation of the onshore supply base is expected to begin as early as the fourth quarter of 2014. This includes setting up a drillingmud batch plant and large storage silos, and delivery of materials such as casing and wellhead equipment. Support vessels and the drilling rig would be mobilized in the second quarter of 2015. Each well is expected to take about 130 days to drill. Shell’s preferred drilling months would be May through September when weather is more likely to be favourable, but it says it could also occur during the rest of the year. Shell’s off shore Nova Scotia experience began half a century ago when the company acquired its fi rst leases off the province’s shores in 1963. The supermajor has participated in 77 of the nearly 200 wells drilled off shore Nova Scotia, including the fi rst gas discovery well, Onondaga B-84, in 1969. Shell drilled 24 wells and had an active exploration program through the 1980s, which included the first deepwater well, Shubenacadie H-100, and significant new gas discoveries—Glenelg, Alma and North Triumph—which led to development of the currently producing Sable Offshore Energy Project (31.3 per cent Shell). The company holds 28 significant discovery licences offshore Nova Scotia. Shell’s last 100 per cent well was drilled in 2002 on the old Onondaga B-84 discovery.

Photo: Joey Podlubny

Shell plans seven deepwater wells off Nova Scotia


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B.C.

brITISH COLuMbIa WeLL aCTIVITy DEC/12

DEC/13

Wells licensed

42

100

DEC/12

DEC/13

Wells spudded

38

57

DEC/12

DEC/13

50

67

Rigs released

British Columbia

Source: Daily Oil Bulletin

Painted Pony targeting Montney in 2014

Me plignias iur, occusandis voluptaquo omnimo voluptium explaudaes con et.

Photo: Joey Podlubny

Painted Pony has over 2,000 drilling locations on over 200 Montney sections of land.

Painted Pony Petroleum Ltd. has approved a 2014 capital expenditure budget of $149 million, with 92 per cent of the budget directed toward the continued development of the junior producer’s Montney natural gas project in northeastern British Columbia. The 2014 capital budget includes the drilling of 21 (18.6 net) wells, including 18 (17 net) horizontal wells targeting the Montney and three (1.6 net) wells directed at light oil projects in Saskatchewan. As a result of the robust liquids yields realized at the Townsend and Daiber areas, Painted Pony is directing capital in 2014

toward facilities infrastructure to realize full value from the company’s development activities. At Townsend, high liquids content (condensate and natural gas liquids) is limiting Painted Pony’s ability to place wells on production. To address this issue, the company is constructing a 100 per cent working interest, 25-million-cubic-feet-per-day gas dehydration and condensate stabilization facility. This facility is expected to be completed before the end of the first quarter of 2014. In addition, high initial production rates associated with recently completed

wells at the 44-C/94-B-16 pad require Painted Pony to expand the previously constructed compression and dehydration facility. The facility has a current capacity of 25 million cubic feet per day, and will be expanded to 50 million cubic feet per day in the second quarter of 2014. Jeremy McCrea, a managing director with AltaCorp Capital Inc., said this will help not only the company’s liquids value, but also its takeaway capacity, which is needed. In a note, he stated that although fullyear production wasn’t provided, “its presentation suggests a range between 12,400 and 12,700 barrels equivalent per day.” Painted Pony has over 2,000 locations on over 203 Montney sections. Recent 30-day initial production rates have averaged eight million cubic feet per day on the past six wells under an openhole design (including additional fracs), “and we suspect as the company has further data on these recently drilled wells, and a clearer outlook on the gas price environment, we could see production guidance increase materially. Investors also shouldn’t count out JVs [joint ventures] as a potential source of funding as well,” AltaCorp stated. The majority of the 17 wells in 2014 will be drilled on existing pads and will use existing infrastructure as the company continues to grow its premiere British Columbia Montney assets. During 2014, Painted Pony intends to drill eight Montney horizontal wells at Blair, two Montney horizontal wells at West Blair and two (one net) Montney horizontal wells at Daiber. In addition, the company will build on its successful 2013 activities on the liquids-rich Townsend block, by drilling a total of six Montney horizontal wells at the 56-H and 11-J pads. — DAILY OIL BULLETIN OIL & GAS INQUIRER • february 2014

13


British Columbia

Neb approves four more LNG export licences by richard Macedo

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february 2014 • OIL & GAS INQUIRER

The National energy Board (NEB) approved four liquefied natural gas (LNG) export licences with 25-year terms for projects proposing to send the chilled gas overseas. The export licence applications that were approved include Prince Rupert LNG Exports Ltd. (BG Group); Pacific NorthWest LNG (PETRONAS) WCC LNG Ltd. (Exxon Mobil Corporation/Imperial Oil Limited); and Woodfibre LNG Export Pte. Ltd. The approvals were in addition to three others that had already received a green light by the board. Those include Kitimat LNG proposed by Chevron Corporation and Apache Corporation, the small-scale B.C. LNG Export Co-Operative project and LNG Canada led by Royal Dutch Shell plc. The NEB has a further four projects in the queue awaiting export approval. These include AltaGas Ltd.’s Triton LNG Limited Partnership and Aurora LNG proposed by Nexen Energy ULC and CNOOC Limited, both planned for the B.C. North Coast. The NEB also has received an export application from Veresen Inc., which is seeking a licence to export gas from Canada to supply the Jordan Cove LNG terminal planned for Coos Bay, Ore. On the East Coast, Pieridae Energy Canada Ltd. has filed an export licence for its planned liquefaction facility in Goldboro, N.S. “I think [the board] fully recognizes the challenges facing the Canadian gas market,” said Christopher Theal, president and chief executive officer of Kootenay Capital Management Corp. “We have a new-found abundance of competitively priced supply, in excess of domestic demand requirements. “[The] U.S. Northeast, which was a key export market from Canada, has become a self-sufficient market, thereby reducing the need for distant Canadian gas; it underscores the need for new markets for Canadian energy.” Edward Kallio, director of gas consulting with Ziff Energy, a division of HSB Solomon Associates LLC, added that the approvals by the board are based on sound evidence.


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449 trillion cubic feet

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“I think if there were questions, and the evidence didn’t support the applications, that they would be asking questions,” he said. “All four of these, the supply/demand market evidence was ours. “We used the same template as in the Shell application, and on that one we had no hearing as well,” Kallio added. “They did their own resource evaluation just recently in the Montney and they came up with a huge resource there.” In December, the NEB, B.C. Oil and Gas Commission, the Alberta Energy Regulator and the British Columbia Ministry of Natural Gas Development jointly released the fi rst study ever to estimate the marketable unconventional petroleum resources in the Montney Formation, which produced an estimate of 449 trillion cubic feet of marketable natural gas. “I was not surprised to see these decisions here,” Kallio said. “Canadians aren’t going to be left wanting for gas even after this gas is exported and accounting for Canadian and export demand.” The NEB said that recent developments in gas production technology have resulted in a significant increase in the Canadian gas resource base and North American gas supply. One of the major effects of this increase is lower demand for Canadian gas in traditional gas markets in the United States and eastern Canada. As a result, the Canadian gas industry is seeking to access overseas gas markets through exports of LNG. “When evaluating LNG export licence applications, the board considers if the quantity of gas proposed to be exported is surplus to Canadian requirements, taking into account trends in the discovery of gas in Canada. Each application is assessed on its own merits,” said the NEB. “The board determined that the quantity of gas proposed to be exported for each application will be surplus to Canadian requirements. “The board is satisfied that the gas resource base in Canada, as well as North America, is large and can accommodate reasonably foreseeable Canadian demand, the LNG exports in these applications, and a potential increase in demand. The Canadian natural gas market will continue to respond appropriately to changes in supply and demand.”

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NOrTHWeSTerN aLberTa WeLL aCTIVITy DEC/12

DEC/13

Wells licensed

290

362

DEC/12

DEC/13

Wells spudded

194

166

DEC/12

DEC/13

185

148

Rigs released

Source: Daily Oil Bulletin

N.W. Northwestern Alberta

New report looks at infrastructure needs in Peace Country by elsie ross

Photo: Joey Podlubny

New natural gas opportunities in northeastern British Columbia and northwestern Alberta in response to growing liquefied natural gas (LNG) demand are changing the dynamics of infrastructure systems in northeastern British Columbia and northwestern Alberta, says a new study on the area. “The developing North Montney and shale gas resources present a unique opportunity to integrate and utilize the area infrastructure for the benefit of both current and developing resources,” according to the resource and infrastructure study by consultants Gas Processing Management Inc. and Ziff Energy, a division of HSB Solomon Associates LLC. “Growing shale and tight gas production, when coupled

Gas-processing capacity in the North Montney needs to be rationalized to manage supply growth.

with the declining existing resource base, will require constructing new infrastructure and utilizing, retooling and expanding existing facilities.” The North Montney and Shale Gas Growth Study is the northward continuation of the previously released South Montney and Tight Gas Study. It analyzes the area west of Fort St. John to the Yukon and Northwest Territories, including the North Montney tight and Horn River plays, Liard and the Cordova shale basin. The study, forecasts the production by sub-region until 2024 in terms of natural gas, ethane, natural gas liquids (NGLs) and condensate, Bill Gwozd, senior vicepresident of gas services for Ziff, said in an interview. It also lays out a blueprint for cooperatively using the existing gas gathering and processing infrastructure, and identifies new area infrastructure to effectively and efficiently process growing gas production. “In some cases, it’s not adequate; in other cases, it’s way too big,” Gwozd said. For example, while some of the new production is expected to contain significant volumes of NGLs, the area contains limited takeaway capacity for liquids, the report found. It provides information for western LNG development and the impact that will have on the 34 sweet and sour gas plants and gathering systems in the area. In cases where the infrastructure is inadequate, the consultants can forecast how much plant capacity is required, in what year and what type—sour gas processing, NGL (C3+) or deep cut. The study also indicates where long-reach lateral pipelines will be required to transport the supply back to the plant.

The report found the study infrastructure has an existing processing capacity of 5.1 billion cubic per day with planned expansions to 5.7 billion cubic feet per day. However, only 2.2 billion cubic feet per day of gas currently is processed in the area, which translates into upwards of three billion cubic feet per day of surplus unused capacity, it notes. “We believe that a structured approach to develop a common gas gathering and processing strategy in gas growth regions, along with a repositioning analysis in maturing regions, will improve utilization and effectiveness of the infrastructure, extend overall gas field production and ultimately result in the development and recovery of more resources,” says the report. Where existing infrastructure presents an economically viable alternative to gather and process the developing gas or new infrastructure is required, the study emphasizes a coordinated industry approach to reduce capital employed and operating expenses. For example, in the Kaybob area (northern Duvernay), there are existing underutilized long-reach gathering pipelines that could transport gas to underutilized sour gas plants, said Gwozd. In cases where existing facilities are not expected to play a role in the growing resource volumes, the study emphasizes a coordinated industry approach to reduce both capital employed and operating expenses. But how will that come about? Gwozd said he believes that the Alberta government “needs to step up quicker” to encourage greater consolidation rather than continuing to study the issue because the consultants have already provided a blueprint. The consultants, he said, have discussed the issue with Ken Hughes, the former energy minister, and with the Alberta Energy Regulator, which has raised the issue of more cooperation among companies in the new shale plays when it comes to infrastructure development. OIL & GAS INQUIRER • february 2014

17


Northwestern Alberta

“Growing shale and tight gas production, when coupled with the declining existing resource base, will require constructing new infrastructure and utilizing, retooling and expanding existing facilities.” — The North Montney and Shale Gas Growth Study, Ziff energy, a division of HSb Solomon associates LLC

The reductions in the gas cost allowances from the proposals in the report would save the Alberta and B.C. government “tens of millions of dollars,” said Gwozd. For example, if two gas plants were consolidated, the overall cost of capital would drop as would the gas cost allowance. The province could also receive increased royalties if it were to accept some of the report’s recommendations, he said. At present, a gas plant operator whose load factor drops to 35 per cent may achieve a “minimum turndown rate” and “you have to walk away from your assets in the ground,” he said. However, if the plant were to be kept full with gas transported via a long-reach gathering pipeline, “you could salvage the resource, produce it longer and produce more royalties for the people of Alberta.” Ultimately, though, “the challenges related to developing or repositioning an area for a step-change in performance are much more than technical; any analysis must address business factors that will ultimately determine if solutions can be implemented,” the report cautions.

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february 2014 • OIL & GAS INQUIRER

The North Montney and Shale Gas Growth Study is the fourth in a series of seven resource and infrastructure analyses that address developing western Canada unconventional tight (Cretaceous, Duvernay and Montney) and shale gas growth. Two more studies will be released in 2014: “Gas West” in June and “NGL East” in December, said Gwozd. The “Gas West” study, which is currently underway, takes the gas supply from the four regions (Montney, North Montney/ shale gas, tight gas/Northern Duvernay and tight gas/Southern Duvernay) and assigns it to the four pipelines that would be required to move gas to the West Coast for LNG exports. That study will also include a module assessing the heating requirements of the gas in Asia. “If they need the heating value, that would mean that additional liquids would be needed for that purpose.” The “NGL East” study will assess the liquid-transportation systems for fractionation products and outline what would be required to move all the liquids to Edmonton.


Northwestern Alberta

Photo: Aaron Parker

Donnycreek targets Kakwa Montney in 2014 Donnycreek energy Inc. say s it ha s increased its 2014 capital budget for its Kakwa and Wapiti properties to $49.2 million from $38.9 million with the addition of five additional Montney wells to be drilled at Kakwa. That will bring the total number of wells drilled to 12 gross (5.5 net) on the company’s 18.75 gross (8.75 net) section Kakwa land block by July 31, 2014. The funding for the work is expected to be funded from cash on hand and cash from operations. Donnycreek ’s sevent h hor izontal Montney well at Kakwa spud on Nov. 10, 2013, targeting the middle Montney Formation from a surface location at 16-08-063-05W6 with a bottom hole location at 16-17-063-5W6. The 16-17 well (50 per cent working interest) has been drilled to a total measured depth of 5,191 metres from the same drilling pad as the discovery well at 13-17-063-05W6 and completion operations were expected to begin in

January 2014. Completion operations are under way at Donnycreek’s sixth horizontal middle Montney well (50 per cent working interest) at 16-25-063-06W6. The recently completed and tested 05-23- 063- 06W6 hor izonta l m iddle Montney well (50 per cent working interest)

Donnycreek plans 12 gross wells at Kakwa in 2014.

is tied into existing company-owned infrastructure, including the 16-07-063-05W6 compressor station and condensate stabilization facility. The facility (50 per cent working interest) is designed to handle 3,000 barrels per day of condensate and 15 million cubic feet per day of natural gas. Donnycreek said it expected all three wells to be on production by Feb. 1, 2014, together with the three existing producing middle Montney Kakwa wells. At Wapiti, the company is in process of drilling a 75 per cent operated working interest stratigraphic Montney test well. The well is being drilled from a location at 13-26-064-08W6 and will log and evaluate the Montney Formation. It is programmed to allow for the well to be kicked off horizontally. Donnycreek holds a 75 per cent working interest in 328 gross (246 net) sections of Montney petroleum and natural gas rights at Wapiti. — DAILY OIL BULLETIN

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NOrTHeaSTerN aLberTa WeLL aCTIVITy DEC/12

DEC/13

Wells licensed

226

285

DEC/12

DEC/13

Wells spudded

97

101

DEC/12

DEC/13

124

107

Rigs released

Source: Daily Oil Bulletin

N.E.

Northeastern Alberta

SaGD chosen for Imperial Oil’s proposed athabasca oilsands project by elsie ross

Photo: Joey Podlubny

Imperial Oil resources Ventures Limited is proposing to develop its first in situ project in the Athabasca oilsands and for the first time will use the steam assisted gravity drainage (SAGD) technology that it patented but has never employed commercially. The company has filed an integrated application seeking regulatory approval for its proposed $7-billion Aspen project on its Muskeg lease south of its Kearl mining operations and about 45 kilometres northeast of Fort McMurray. Imperial plans to use SAGD to access 1.1 billion barrels of recoverable bitumen resource (410 million barrels of probable reserves and 690 million barrels of contingent resource) from the McMurray Formation.

The preliminary capital construction c o s t i n 2 013 dol l a r s i s e s t i m ate d at $7 billion, with future construction costs of $4 billion. Total estimated project operations costs (including natural gas) are $15 billion. Aspen would be developed in three phases, with construction of the first phase proposed to start in 2017 and first production in 2020, assuming regulatory approval in the fourth quarter of 2015. As currently envisioned, the second phase would come on production in 2022 and the third phase in 2024. Each phase would have processing facilities with an initial processing capacity of 45,000 barrels per day. The concept plan includes future debottlenecking of the central processing facility that could increase

bitumen production to about 162,000 barrels per day. In its application to the Alberta Energy Regulator, Imperial says it selected the SAGD process because it is a proven technology for oilsands recovery in the McMurray Formation. SAGD has been used at Suncor Energ y Inc.’s nearby Firebag and MacKay River operations and is planned for use at the Husky Energy Inc. Sunrise project. The resource is too deep to be mined because the average overburden thickness above the bitumen-bearing formation is typically deeper than 210 metres, says Imperial. Imperial is also considering enhanced recovery using solvents at Aspen but that would be the subject of another application.

Imperial plans on using SAGD for the first time at its Aspen project 45 kilometres northeast of Fort McMurray.

OIL & GAS INQUIRER • february 2014

21


Northeastern Alberta

It is still evaluating solvent-assisted SAGD as part of a pilot project at Cold Lake, Imperial spokesman Pius Rolheiser said in an interview. The company says it will continue to explore emerging technologies and opportunities that will enhance the project, where practicable, such as exploring opportunities to manage drill-cuttings disposal through integration with regional oilsands mining operations. The development would occur on a 52-section lease area within townships 93 and 94, ranges 06W4 and 07W4, about 25 kilometres east of Fort MacKay. Imperial owns a 100 per cent working interest in the oilsands lease within the project area and retains the right to develop the resources within the McMurray Formation. The project will include cogeneration units, well pads and associated field facilities, and related infrastructure. Inclusion of cogeneration will be a separate

business decision made for each phase of development. The central processing facility (CPF) will be developed in three phases that will be co-located in a single plot space and centrally located to the SAGD well pads. Imperial will develop SAGD wells and well pads within the development area for the start-up of each new CPF phase. The SAGD well pairs are expected to have a lifespan of about 15 years. As the wells reach the end of their expected lifespan, new wells will be developed in the project area over the 40-year life of the project. Imperial plans to drill about 370 well pairs (one steam and one injection) in the project area. To assess the potential environmental effects of the project, 48 well pads with seven to 21 wells per pad have been included in the project footprint. “This is a conservative estimate of the project footprint required for the recovery of

the resource in place,” says the company in its application. The overall project execution plan is based on maximizing the use of modules, says Imperial. Modules will be fabricated and assembled primarily in the Edmonton area and will be transported by truck to the site. The company plans to develop a detailed module-transportation logistics plan to minimize the effect of module movement on highway and local road traffic. The construction phase will be approximately six years, between 2017 and 2023. The average size of the construction workforce will be 450, peaking at 700 in 2019, 2021 and 2023. Imperial estimates that about five per cent of the construction workforce will be recruited from the nearby area, 70 per cent from other parts of Alberta and about 25 per cent from elsewhere. The operations phase will last at least 30 years beginning in 2020 with an estimated average workforce of about 215.

upgrader pilot projects aimed at cutting costs, environmental harm by Joseph Caouette

a pair of pilot plants in central Alberta—one now operating and another planned—offer the potential for cleaner, cheaper bitumen upgrading, say the proponents. Western Hydrogen Ltd. recently held a grand opening for its molten salt gasification pilot plant in Fort Saskatchewan, Alta. The project produced fi rst hydrogen back in September, but the event was the fi rst opportunity for many in the industry to see the technology up close. Using a process fi rst developed by the U.S. Department of Energy at its Idaho National Laboratory, the plant produces hydrogen using only water and a carbonaceous feedstock, such as petroleum coke or biomass. According to the company, produced water from oil operations could even be used in the process—the carbon content of the water might even be seen as a plus. The two inputs are fed into a highpressure reactor containing a molten salt bath, and hydrogen and CO2 is produced. Because the gases come out at pressures 22

february 2014 • OIL & GAS INQUIRER

of up to 2,000 pounds per square inch, the CO2 is ready for use in sequestration and enhanced oil recovery. At the same time, the plant should also lower the supply cost of hydrogen while also reducing

“It turns out if you mix sodium and bitumen at about 350 degrees Celsius, the sodium goes in and grabs all the bad stuff. It’s like a cruise missile for sulphur, for example, and it takes all of that out of the oil.” — Neil Camarta, president and chief executive officer, Western Hydrogen Ltd.

greenhouse gas emissions compared to other methods of hydrogen production. The process could be useful in a variety of fields—representatives from the German consulate were at the event,

eyeing up the plant’s potential for their country’s renewable energy sector—but the most immediate opportunities lie in the oilsands, where hydrogen is a crucial input for upgraders. If the company’s leadership is any indication, the oilsands will undoubtedly play a big part in the commercialization of Western Hydrogen’s process. Guy Turcotte, the company chair, is the former founder and chair of Western Oil Sands Inc., which was sold to Marathon Oil Corporation in 2007. Neil Camarta, the president and chief executive officer, has a long history of his own in the industry, including senior executive roles at Shell Canada Limited, Petro-Canada and Suncor Energy Inc. Camarta said the company has already seen a fair amount of interest from some oilsands producers. “The most hydrogen intensive place on earth is just down the road—Shell’s [Scotford] upgrader, the one I built, and another one just like it,” he said.


Northeastern Alberta

Photo: Joey Podlubny

Western Hydrogen’s new molten salt gasification pilot project will provide hydrogen to upgrade bitumen.

“When you upgrade oil from sands, take the bitumen molecule and try to make gasoline from it, you have to go through a lot of heavy lifting and it takes hydrogen every step of the way,” he added. “We’re right in upgrader alley, right in the heart of the biggest hydrogen consumption place on earth.” Currently, the plant is running on asphalt purchased from a local supplier. “The reason we’re running that is because it’s probably the worst thing you could think of to run through here. It’s heavy and it’s hard to handle. So if we can run it on asphalt, we can run it on anything,” Camarta explained.

As the pilot progresses over the next couple of years, the plant will cycle through a wide range of feedstocks, including natural gas, petroleum coke and renewable sources such as glycerol. Unlike the steam methane reformers that commonly use natural gas to produce hydrogen, the molten salt gasification process is very flexible when it comes to feedstocks. “This machine can run on gas, but the same machine can be switched over to other feedstocks,” Camarta said. “We have to make some adjustments to the front-end, but the same machine can use alternate feedstocks, depending on what’s the cheapest and what’s available.”

Next year, Camarta and crew will be returning to the same site to build another pilot plant under the name Field Upgrading Ltd. The company, spun off from Western Hydrogen, will use a molten sodium process to upgrade bitumen. “It turns out if you mix sodium and bitumen at about 350 degrees Celsius, the sodium goes in and grabs all the bad stuff,” Camarta said. “It’s like a cruise missile for sulphur, for example, and it takes all of that out of the oil.” Because sulphur helps bind the larger molecules, the bitumen is broken down, and heavy metals are removed. Beyond sodium, all that the process requires is a modest quantity of hydrogen or methane. “You go in with really heavy oil and come out with oil that’s light enough that you can pump it without adding diluent,” Camarta said. The process produces sodium sulphite, which must be broken down to recycle the sodium salts for reuse. For that, Field Upgrading turned to technology from Ceramatec, Inc., a research firm based out of Salt Lake City, Utah. The sodium sulphite is placed in a ceramic membrane reactor, where electricity is applied, ionically removing the sodium and leaving behind elemental sulphur. According to the company, the process will require less hydrogen and produce lower emissions than current industry methods of bitumen upgrading. “That’s the idea—come up with a cheaper and cleaner way to upgrade oil and bring upgrading back to Alberta,” Camarta said. He said the company plans to order the pilot plant in the fi rst quarter of 2014, with delivery slated for the final quarter of the year. Start-up is scheduled for the fi rst quarter of 2015.

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CeNTraL aLberTa WeLL aCTIVITy DEC/12

DEC/13

Wells licensed

215

185

DEC/12

DEC/13

Wells spudded

143

143

DEC/12

DEC/13

140

152

Rigs released

Source: Daily Oil Bulletin

C.A.B. Central Alberta

bellatrix sets gross budget at over $600 million

Photo: Aaron Parker

Bellatrix plans to operate or participate in 146 wells in 2014, including 115 Cardium wells and 31 Mannville wells.

With the closing of its acquisition of Angle Energy Inc., Bellatrix Exploration Ltd. has set an initial gross capital budget of $610 million for 2014, including jointventure partner capital. In 2013, Bellatrix entered a jointve nt u r e pa r t ne r sh ip w it h Dae wo o International Corporation and Devonian Natural Resources Private Equity Fund. Also in September of the same year, the company announced that Grafton Energy Co I Ltd. has doubled its stake in a joint venture, slated for the Willesden Green and Brazeau areas of west-central Alberta, to $200 million from $100 million. And in November 2013, the company closed the previously announced $240-million jointventure partnership with TCA Energy Ltd. However, Bellatrix’s net 2014 capital budget remains at the previously announced level of $370 million. This is a hefty increase from the rapidly growing intermediate producer’s current 2013

capital budget of $240 million and its initial 2013 budget of $180 million. The company also announced its borrowing base has been increased by $245 million to $500 million. Bellatrix expects to roughly double its average output to about 44,000 barrels equivalent per day in 2014, compared to estimated average 2013 production of about 22,250 barrels per day. It expects to end 2014 at about 47,000 barrels per day, compared to forecast 2013 exit production of about 40,000 barrels per day (37 per cent oil and natural gas liquids). The net capital budget of $370 million consists of drilling and completion spending of $250 million, facility and infrastructure spending of $100 million, as well as land, geological and other related spending of $20 million. Bellatrix plans to operate or participate in 146 (76.27 net) wells in 2014, resulting in 115 (65.71 net) Cardium

oil wells and 31 (10.56 net) Mannville condensate-rich gas wells. Bellatrix plans to continue to operate 10 rigs in its two core resource plays—Cardium oil and condensate-rich Mannville gas. Bellatrix plans to continue growing through its core Cardium and Notikewin/Falher assets using its large prospect inventory. The company has developed an inventory of 742 net remaining Cardium locations, 381 net Notikewin/Falher and 128 Mannville locations, representing a net remaining investment of $4.97 billion (based on current costs). Bellatrix said it has 424,452 net undeveloped acres and about 2,000 net exploitation drilling opportunities with capital requirements of $10.1 billion, representing 30 years of drilling inventory based on current annual cash flow and costs. Bellatrix said it continues to focus on adding Cardium and Notikewin prospective lands. — DAILY OIL BULLETIN OIL & GAS INQUIRER • february 2014

25


Central Alberta

Centrica energy beginning work on former Suncor assets by elsie ross

26

february 2014 • OIL & GAS INQUIRER

Centrica plans on drilling 75 wells in 2014 in areas where it controls infrastructure.

over the longer term, it will look to drive more of the technical work and the drilling itself as it comes up to speed on the projects. With the recent acquisition, 220 former Suncor employees (70 in the office and 150 in the field) moved over to Centrica. The company says it has assembled a strong technical team that includes two geophysicists and 12 geologists with experience in these types of assets as well as engineers and production engineers, said Brian Keller, development director for Centrica Energy in Canada. As a geologist, Morningstar said he’s amazed with the progress over the past two to three years of new play types such as the Wilrich, Fahler or Notikewin, noting that there have been some great well results in a number of those different horizons thanks to fracturing and longreach horizontal drilling. Centrica anticipates spending $237 million in 2014 on its organic program, with most of that spent on drilling and completions with plans for 75 (60 net) wells. “We are looking for oil or liquids-rich gas,” he said. “Where we can drill and develop opportunities within our own infrastructure, clearly that adds more value.” The three focus areas will be the former Suncor assets at Hanlan/Robb in the Deep Basin and Ferrier in west-central Alberta, along with Centrica’s legacy Carrot Creek property, also in the Deep Basin.

The Hanlan/Robb area has been primarily a Mississippian prospect producing sour gas from the deep Turner Valley Formation, which has held the rights for the company, said Morningstar. The company, he said, sees a big contingent resource within the Turner Valley that could be developed at some point in the future. Centrica is now beginning to turn its attention to the uphole Cretaceous in the area. A major advantage is the infrastructure, including the Hanlan/Robb gas plant that gives the company the capacity to process its production through its own infrastructure, he said. Centrica owns 50 per cent of the 380 million cubic feet per day of sour capacity and holds roughly a 45 per cent interest in 45 million cubic feet per day of sweet capacity that could be expanded. With the plant pretty much full, it is thinking about an expansion. At Ferrier, where Centrica acquired the 80-million-cubic-feet-per-day sweet gas plant from Suncor, the company will be chasing the liquids-rich Glauconite play in the Gilby area as well as some Cardium oil at Ferrier where it owns the Ferrier Cardium unit, a big oil pool. Centrica extracts C3+ (propane and butane) at the Ferrier gas plant, hauling out its own condensate and making its own fracturing fluid, said Morningstar. “It allows us to extract additional value from the liquids.”

Photo: Joey Podlubny

Centrica energy Canada’s Wes Morningstar has an enviable problem: how to best develop $1 billion worth of primarily conventional natural gas assets it and partner Qatar Petroleum International acquired from Suncor Energy Inc. earlier in 2013. “While some of it is truly a conventional asset, there are other pieces of the portfolio where we think we can use additional or enhanced methods to recover additional hydrocarbons,” the company’s Calgary-based senior vicepresident said in an interview. When Suncor decided to focus on its oilsands assets, Centrica jumped at the chance to pick up about 41,000 barrels equivalent per day of production (90 per cent natural gas) and associated infrastructure mainly in central and southern Alberta. The deal also included more than one million acres of undeveloped land in western Canada. “This was a great deal for both companies,” said Morningstar. “It’s a deal where they got what they wanted out of it and we think we got what we wanted.” A lt hough t he acquisit ion was announced in April, Centrica has actually had access to the assets since late September when the deal closed. “Part of the last two months has been coming up to speed on the current operations that are ongoing, because we fi nd ourselves in the middle of a number of interesting prospects right now,” said Morningstar. “We are finding there is a reasonable amount of activity on that undeveloped land.” For example, at Hanlan/Robb and Lovett-Basing River, Centrica is partnered with operator Tourmaline Oil Corp. in the Wilrich liquids-rich gas play and found itself in the middle of that play within those undeveloped lands. Centrica has been fielding independent operations notices from companies who are active in some of these areas, offering it a chance to participate in drilling a well, he said. “We are trying to look at the technical merits of the opportunities and in most cases we are saying we are interested.” For the most part—and for now—Centrica doesn’t mind being in a non- operated position, said Mor ningsta r. However,


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SOuTHerN aLberTa WeLL aCTIVITy DEC/12

DEC/13

Wells licensed

92

73

DEC/12

DEC/13

Wells spudded

56

43

DEC/12

DEC/13

59

56

Rigs released

Source: Daily Oil Bulletin

S.A.B. Southern Alberta

Medicine Hat and LGX want review of greater sage-grouse protection order by Carter Haydu

Photo: Alberta Wilderness Association

A battle is brewing over a federal protection order for greater sage-grouse in southeastern Alberta that will limit oil production in the region.

In an effort to protect the Manyberries oilfield, the City of Medicine Hat, in conjunction with LGX Oil + Gas Inc., has filed a notice of application for judicial review related to the federal government’s emergency order to protect the greater sage-grouse. The applicants want the court to quash, alter or suspend the order for six months so the federal environment ministry can consult with the two stakeholders. “It’s not difficult to comply with the order,” councillor Bill Cocks, chair of the city’s energy committee, said. “It’s just difficult to continue with operation of the oilfield if we comply with the order.” For example, Cocks said, height restrictions under the emergency order prohibit equipment higher than a barbed wire fence, which makes it impossible for a drilling rig to access the municipally owned energy interests in the Manyberries oilfield of southeastern Alberta. He added the noise restrictions also basically prohibit resource development.

“I can tell you that we paid about $48.3 million to acquire the oilfield, and we have drilling operations and we have already increased production by 100 barrels per day from the 400 barrels per day that were being produced at the time we took it over. So this is a significant impact.” The applicants suggest their costs of forgone production arising from new wells at Manyberries would be at least $80 million. Cocks said, “These are pretty big numbers, and the emergency order would mean a pretty significant hit to the City of Medicine Hat’s oilfield operations.” Last month, federal Environment Minister Leona Aglukkaq announced publication of an emergency order to protect the sage-grouse under the Species at Risk Act (SARA), which will come into force on February 18. The emergency order aims to protect important habitat for this species on approximately 1,700 square kilometres of provincial and federal Crown lands in

Alberta and Saskatchewan, and introduces restrictions on activities on these lands that impact sage-grouse populations. The order does not apply on private lands and does not limit grazing on federal or provincial Crown lands. Impac ted la nds under t he order include most of the Medicine Hat–owned oil properties in the Manyberries area, as well as the majority of LGX’s Manyberries properties. The city and LGX made the judicial review application because they believe certain SARA provisions are beyond the federal parliament’s jurisdictional powers. Further, the applicants suggest the minister of the environment and governor general in council failed to consult with LGX and the city, and therefore did not adhere to requirements of procedural fairness and natural justice in recommending and making the order. According to an LGX news release, as a result of the failure to properly consult all stakeholders, the federal government relied on a number of erroneous facts and assumptions, rendering the decisions unreasonable. LGX and the city will pursue compensation for losses arising from any impact to their operations at Manyberries. LGX and the city will also seek additional relief to protect their respective interests at Manyberries. LGX said that it has been in full compliance with the province’s legislative and regulatory framework for the protection of the species, which has been in place since 1996, and the company expects to obtain provincial support to quash the federal order, given the “grave infringement on OIL & GAS INQUIRER • february 2014

29


Southern Alberta

the Province of Alberta’s constitutional jurisdiction over surface rights, mineral rights and regulation of the oil and gas industry at large.” According to Cocks, the City of Medicine Hat’s efforts to protect the endangered bird have been extensive, and he hopes to continue working toward ensuring that sage-grouse populations thrive.

“It is our goal to work with the federal government to devise initiatives that will benefit both the sage-grouse and the City of Medicine Hat, as we have been doing with the provincial government over the last two years.” He noted that the sage-grouse population in Alberta is only a portion of the birds’ total numbers in North America, as

the species also exists in Saskatchewan, as well as several U.S. jurisdictions, including Montana, Wyoming, Idaho, Oregon and Nevada. A spokesperson for Env ironment Canada declined to comment on the Med ic i ne Hat / L GX jud ic ia l rev iew application, as the issue is still before the courts.

LGX announces big Valley light oil well test results LGX Oil + Gas Inc. says that its Big Valley (Three Forks) Formation horizontal well at 13-02-009-24W4 was recently completed with a 20-stage hydraulic fracture stimulation and has achieved peak oil rates in excess of 3,500 barrels per day in extended production test results. The 13-02 well has been flowing back for 136 hours up a 4.5-inch diameter frac string and has produced 9,360 barrels of 31 degree API light oil for an average daily rate of approximately 1,650 barrels of oil per day and 570 thousand cubic feet per day of associated solution gas, for an oil equivalent rate of 1,745 barrels equivalent per day over the test period. Peak oil rates in excess of 3,500 barrels per day have been measured during the flowback period. The well is still flowing 85 barrels of oil per hour and 700 thousand cubic feet per day of gas with a 10 per cent water cut. Legacy cautioned that while the production rates are useful in confi rming the presence of hydrocarbons, they are not determinative of the rate at which the 13-02 well will begin production and later decline.

Peak oil rates in excess of 3,500 barrels per day have been measured during the flowback period for LGX Oil + Gas Inc.’s well at 13-02.

LGX has a 100 per cent interest in the well prior to the recovery of 200 per cent of the drilling, completion, equipping and tie-in costs, at which point its interest will revert to 80 per cent. The company said it plans to continue to evaluate the well and has procured surface production equipment for installation post-flowback to facilitate a long-term production test. With the positive test results from 13-02 validating the geophysical and

geological model, LGX estimates that up to 20 sections of LGX land offsetting the 13-02 well may be prospective for Big Valley and Banff oil production. In addition, Legacy said it and other producers have received notice from the federal environment minister of an emergency order for the protection of the greater sage-grouse pursuant to the Species at Risk Act to address the imminent threats to its survival and recovery, including protecting the habitat in southeastern Alberta and southwestern Saskatchewan identified in the order to help stabilize the sage-grouse population and begin its recovery. The area affected by the order includes LGX’s Manyberries property. The company is reviewing the order and is consulting with other oil and natural gas producers, the minister of the environment, the Alberta government and the Canadian Association of Petroleum Producers to understand and quantify the potential impacts of the order to LGX and its operations in the area. — DAILY OIL BULLETIN

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Hemisphere has drilled 12 consecutive Glauconitic horizontal wells at Jenner.

Hemisphere energy Corporation has kicked off operations for its winter drilling program, with three development wells planned in the Atlee Buffalo and Jenner areas of southeastern Alberta. The company’s fi rst well of the winter drilling program is underway in the newly acquired Atlee Buffalo property. The horizontal development well is targeting the oil-bearing sandstones of the Glauconitic Formation. Hemisphere anticipates the well will take approximately one week to drill before the rig moves to the Jenner area to drill the remaining planned wells. In Jenner, Hemisphere plans to drill two development horizontal wells targeting the Glauconitic Formation. The wells will be located near existing pipeline infrastructure and will use the recently completed upgrades to increase the fluid-handling capacity at Hemisphere’s main facility. Hemisphere has drilled 12 consecutive successful Glauconitic horizontal oil wells in its Jenner property where it has two oil processing facilities, access to more than 35 sections of land, and a growing inventory of low-risk development drilling locations and medium-risk exploration prospects.

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SaSKaTCHeWaN WeLL aCTIVITy DEC/12

DEC/13

Wells licensed

312

386

DEC/12

DEC/13

Wells spudded

169

209

DEC/12

DEC/13

223

264

Rigs released

Source: Daily Oil Bulletin

S.K. Saskatchewan

Saskatchewan resource sector momentum to continue in 2014 by elsie ross

Photo: Joey Podlubny

building on the strength of the past two years, the Saskatchewan government is looking at another healthy year in the oil and gas sector, said the province’s energy and resources minister. “We think the fundamentals that have driven the results in recent years are still in place,” Tim McMillan said in a recent interview. “We’ve got great reserves, and we have got companies that are very engaged in our province and are very pleased with the regulatory environment in our province,” he said. “We think the price of oil has been relatively strong this past year and that it is going to drive further production and investments.” In 2012, Saskatchewan repor ted record oil production of 172.9 million barrels (473,600 barrels per day), and preliminary figures for 2013 indicate it is on track to set a new record, he said. In its fi rst-half financial outlook, the government had

projected 2013 production of 175.5 million barrels, up from its budgeted estimate of 171.8 million barrels. According to the Daily Oil Bulletin, 3,388 wells, including 3,223 with oil as an objective, were drilled in the province as of Dec. 23, 2013, compared to 3,219 wells, including 3,013 with oil as an objective, in 2012. While only a few years ago Saskatchewan was primarily a heavy oil province, production is increasingly diversified, said McMillan. The Bakken Formation in the southeastern part of the province is the focus of light oil activity, but there are other pools in the south in addition to the heavy oil in the Lloydminster/Kindersley area near the Alberta border. “The southeast has really come on in recent years, and we expect the strength there will continue,” he said. “They are building upon strength in some of the technology gains that allowed some access

Around 3,223 oil wells were drilled in Saskatchewan in 2013, up from 3,013 in the previous year.

to pools that we have known about for decades to be produced economically.” Crescent Point Energy Corp., the largest player in Saskatchewan, expects to spend approximately $781 million of its $1.75-billion 2014 budget in the Viewfield Bakken and Flat Lake resource plays of southeastern Saskatchewan. Plans call for drilling approximately 215 net wells in the Viewfield area and 48 net wells at Flat Lake. The company’s waterflood plans for 2014 include the conversion of 30 producing wells to water injection wells in the Viewfield Bakken play. Crescent Point also plans to continue to invest in infrastructure projects to accommodate sustained growth of its Bakken production. At the same time, some of the technology that is used in the southeast is also being used in other parts of the province, said McMillan. For example, the horizontal approach to producing wells is being used in some of the province’s heavy oil plays to very good success. After several decades where vertical wells were used to produce most heavy oil, the province is seeing the use of new technologies and methods to bring new life to the heavy oil sector, according to the minister. “Today, several of our large producers are going to pads and utilizing horizontals, and some wells are produced very successfully with steam as well.” Husky Energy Inc., for example, has invested $500 million in two thermal heavy projects at Lashburn and one just north of Paradise Hills, and “the reports have been pretty positive.” Crown land sales also are another source of revenue for the province, OIL & GAS INQUIRER • february 2014

33


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although the 2013 total take of $67.37 million for 111,340 hectares was down from the $105.69 million it received in 2012 for the sale of 397,119 hectares. “I think industry has transitioned capital from land acquisition to production,” McMillan said. “We are seeing families moving here for the development jobs.” Wit h t hat ha s come subst a nt ia l growth on the infrastructure side by both the industry and the government, which has been investing in highways and communities, informed by a growth plan out to 2020 that it approved in 2012. There could be a lot of Crown land once again available in 2014, added McMillan. “There was a very large take-up in 2008– 2009, and companies have five years to develop it or it reverts back to the Crown, so [we] are in [a] very positive position with some of those lands,” he said. Although drilling activity has ramped up substantially, the tradition is that a very high proportion of Crown lands will revert back, said the minister. So what could change the picture for the province? “One of the biggest challenges in the past year has been pipeline capacity,” said McMillan. “Industry has answered the call and the percentage of crude leaving the province by rail has risen dramatically and that’s very positive, but the fact that has to happen is a challenge.” The province, though, still believes that pipelines are the most efficient way to move crude oil, according to McMillan. At present, Bakken oil can access the Enbridge Inc. mainline, which also accepts crude from the North Dakota Bakken that is imported into Canada at Steelman, Sask. “There are a lot of very good projects under development and we will try to support them where we can,” he said. Saskatchewan views Asian markets, specifically China, as extremely important to the province’s long-term future. “Getting access to the West Coast is something that is very important to us.” From that perspective, the recent recommendation from the joint review panel to the federal government that it approve Enbridge’s Northern Gateway project with 209 conditions was good news, he said. “From Saskatchewan’s point of view, we don’t think any pipeline should go forward that isn’t environmentally responsible, so


Saskatchewan

having appropriate conditions in place is something we would expect of any pipeline.” TransCanada Corporation’s proposed Energy East Pipeline from western Canada to Saint John, N.B., also “makes a lot of sense,” as it would enable refineries in Quebec and Saint John to replace imported oil used with Canadian crude, McMillan suggested. For its part, the Saskatchewan government will try to maintain its position as the preferred place for industry to invest capital, he added. “We think we have a royalty system that is competitive, but the bigger piece is the relationship and the structure in the way in which we deal with the regulations with industry,” said the minister. “Industry has said it’s very important that when they have a problem, they can pick up the phone and call someone and that isn’t the case in every province. “The level of service we provide is part of our competitive advantage.”

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raging river sets $215-million Viking development budget after a record year in 2013, light oil–focused Raging River Exploration Inc. plans to undertake a $215-million development capital program that is expected to result in the drilling of up to 209 net horizontal Viking oil wells in southwestern Saskatchewan next year. Total on-stream costs (drilling, completion and equipping) represent $195 million, or 90 per cent, of the approved budget. Another $5 million has been allocated to waterflood optimization and expansion with the remaining $15 million allocated to land, seismic and maintenance capital. The expenditures are expected to increase 2014 average daily production by 73 per cent to 9,500 barrels per day (95 per cent oil) and its exit rate by 38 per cent to 11,000 barrels per day (95 per cent oil). Raging River also reported that it has surpassed its exit guidance of 8,000 barrels per day for this year. As a result of its continued

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success, it now expects fourth-quarter 2013 production to be between 7,300 barrels per day and 7,400 barrels per day, resulting in a further increase to average 2013 production guidance to 5,500 barrels per day from 5,400 barrels per day. This has been a record year, said Raging River, noting that it had more than doubled production and cash flow per share while maintaining a pristine balance sheet. The company also expanded its drilling inventory through methodical step-out drilling across its asset base, successfully drilling more than 50 previously undrilled sections. Raging River said that play expansion will again be a key value driver in 2014, with approximately 24 per cent of its drilling locations scheduled to test undrilled sections. The company has 200 net sections of prospective Viking acreage with 108 net sections tested. Upon completion of the 2014 program, it expects to have tested in excess of 160 of these sections. Raging River said it has a drilling inventory of 1,900 wells. The capital budget includes 45 wells at Dodsland, 66 at Beadle, 42 at Greater Lucky Hills, 22 at Kerrobert, and 34 at Plato and Forgan. All are net wells. Forecast funds from operations for 2014 of $181 million combined with its existing credit facilities will provide ample funds to execute the budget while maintaining a strong balance sheet, said Raging River. Raging River netback guidance per barrels calls for oil and gas sales of $82.90, royalties of $8.40, operating expense of $12.80, transportation expense of $2, cash taxes of $4.30 and an operating netback of $59.70 per barrel. — DAILY OIL BULLETIN

Photo: Joey Podlubny

Raging River plans to drill 209 Viking oil wells in 2014.


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E

Cover Feature

verything about the Duvernay shale play is big. Covering around 100 square kilometres in west-central Alberta, the emerging shale play is three times as big as the Eagle Ford shale play in Texas, its closest analog. The Alberta government’s mid-range resource estimate for the play shows 443 trillion cubic feet of natural gas, 11.3 billion barrels of natural gas liquids, and almost 62 billion barrels of oil. From 2009 to 2013, the industry has spent around $3 billion in the Duvernay acquiring land and drilling test wells to unlock this vast resource, with individual wells costing as much as $20 million. This year, however, could prove the year that the industry breaks the play wide open, if efforts to commercialize the play prove out. Talisman Energy Inc. has nearly 350,000 acres in the Duvernay play, divided into north and south core areas. In the South Duvernay, Talisman reported in November it continues to evaluate its acreage with five appraisal wells drilled to date. Two wells were completed during the quarter, with seven-day average rates of 2.8 million cubic feet per day of gas and 730 barrels per day of condensate for the first well, and 1.6 million cubic feet per day and 365 barrels per day of condensate for the second well. Year-to-date drilling and completions costs average $16.2 million per well, down 16 per cent compared to 2012, despite drilling wells with longer horizontal sections and more fracture stages. Company president and chief executive officer Hal Kvisle says Talisman is taking a step-by-step approach to unlocking the Duvernay’s potential. “In the Duvernay South, we went in there, initially, and drilled some relatively short lateral wells with relatively few fracs, just to try and understand the reservoir rock a little bit better,” Kvisle told shareholders. “We spent a fair bit of time and money with those initial wells, coring and doing things that I think are necessary to really set the path forward. [With] these four recent wells, we increased the lateral length, we increased the number of fracture stages. We’re nowhere near the top end of frac stages that we’ve seen from some other operators, both in the Duvernay and in similar places in North America. But we went with about 15 stages on the most recent wells. One of the things we were trying to determine, we were trying to verify our understanding of where the phase windows are, whether we’re in an oily part of the South Duvernay, some of the richer gas parts or lean dry gas parts.” Kvisle said so far drilling results have matched the company’s models for the play. “Now the big challenge, really, is to always work to improve the production rates,” he explained. “We’re probably looking at more fracs over the horizontal section or some additional modifications to frac fluid, and we’re very attentive to what our competitors are doing. And of course there’s going to be great learning in this play by industry as a whole, as we move forward. But, on our side, our number one priority is to bring the cost down by about one-third to drill and case a horizontal well and fracture stimulate it.” Talisman has also changed directions in the North Duvernay, where it had previously announced it planned to divest. “Now, we’re not at all negative on our position in the North,” said Kvisle. “We have a higher liquids content in our wells in the South Duvernay, but in the north we’ve got some pretty OIL & GAS INQUIRER • february 2014

39


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february 2014 • OIL & GAS INQUIRER

interesting situations. We’ve got a significant land block, called Waskahegan, that is surrounded by some exceptionally good wells drilled by competitors, and we look forward to doing some drilling on Waskahegan in the year ahead. We’ve got our other blocks, which kind of sit in the rich gas retrograde windows, and we think those could be quite attractive with very high recoveries of natural gas liquids once they’re tied into processing plants. And then we’ve got a relatively dry gas part that would have significant NGL [natural gas liquids] recovery liquids, and we have infrastructure that would enable those to be tied in to the Saturn deep cut plant, where we currently send a lot of our Wild River gas. And we think that’s a pretty interesting value proposition for Talisman, given our capacity in that kind of a deep cut situation.” “So all told, I think the North Duvernay and the South Duvernay are big prizes for this company, but one of the realities is the billions of dollars of capital that it would take to fully delineate and develop the Duvernays is significant,” he added. “Six months ago, we considered selling the North Duvernay to generate capital that we could invest in the South Duvernay. We’ve now shifted our focus, given the market out there, to looking at more of a 50/50 joint venture across the full Duvernay and recognizing that we’ve got some very significant and capable infrastructure in the Edson region. We think that could play quite a big role in the way we go about developing some of these lands.” Kvisle said Talisman will continue appraising the Duvernay through the first half of 2014. “We’re not going to be embarking on pad drilling in the Duvernay until late 2014, at the earliest. And that might push into 2015, just depending on how things go,” he said. “But one thing to note is the Duvernay is a relatively deep play. It’s a couple of thousand feet deeper than much of the Montney that people drill. And so, industry wide, we’ll take longer to get these wells down and use a little higher pressure on the stimulation. So it’s challenging that way, but these are all problems and hurdles that I think industry will make great progress on here in the next 12–18 months. We’re doing that ourselves and we’re watching very closely, and working cooperatively with a number of industry partners. So we’re pretty optimistic about it. I think you’ll see more wells from us in the Duvernay in 2014.” Encana Corporation is also optimistic the industry will advance the commercialization of the play in 2014. Encana plans to invest between $250 million and $300 million of its capital in this play, running a six- to eight-rig drilling program with plans to drill 15–20 net wells in 2014. Total investment in the Duvernay, including the carry capital contributed as part of Encana’s jointventure agreement with PetroChina Company Limited, will be in the range of $1 billion to $1.2 billion for the year, with as many as 40 wells drilled into the play. “In the Duvernay, we will move to pad-based drilling in the northern portion, the Kaybob area, and expect to reach a decision on commerciality for the Willesden Green over the southern portion of the Duvernay during the year,” president and chief executive officer Doug Suttles told shareholders during the company’s 2014 guidance call. Chevron Canada Limited is also pushing Duvernay development in the Nothern Duvernay around Kaybob. Chevron announced in late 2013 it had successfully concluded its initial 12-well exploration drilling program in the liquids-rich portion of the Duvernay shale play. Five wells have been completed and are tied into production facilities and an additional four wells are waiting on completion and tie-in.


Cover Feature

Duvernay resource potential Unit

Adsorbed gas content (per cent)

Natural gas (tcf)

Natural gas liquids (billion bbl)

Oil (billion bbl)

Duvernay P50

68

443

11 3

61 7

Duvernay P90–P10

5 6–8 5

353–540

7 5–16 3

44 1–82 9

Source: Alberta Geological Survey

The company said its acreage is well positioned in the condensate-rich and volatile-oil portion of the play. Liquids yield for the completed wells range from 30 to 70 per cent with initial production rates up to 7.5 million cubic feet of natural gas per day and 1,300 barrels of condensate per day. “Early results of our Duvernay exploration program are encouraging,” said George Kirkland, vice-chair of Chevron. “This discovery creates a foundation for future growth in Canada.” “Well performance and condensate yields exceeded our expectation and strengthen our plans going forward. Near-term plans include transitioning to a two-rig drilling program to optimize well and completion design, and full field spacing requirements,” added Jeff Shellebarger, president of Chevron North America Exploration and Production Company. With the acquisition of Alta Energy Luxembourg S.a.r.l. and affiliates’ acreage announced earlier this year, Chevron now has approximately 325,000 net acres in the Kaybob area of the Duvernay play. “The Duvernay is a very attractive development area and Chevron continues to be very encouraged by reservoir and performance data from results to date,” said Leif Sollid, a Chevron spokesperson. “The company is planning an appraisal program which will be executed prior to full development. Goals of the appraisal program include optimizing well design, well spacing requirements and completions design.” Asked whether comparisons with the Eagle Ford are still fair, he said that the Duvernay is similar to Eagle Ford in that it is a wet condensate shale play, with gradations of fluid content and distinct higher value sweet spots. “Eagle Ford is considerably more mature in its development cycle,” Sollid said. Chevron expects Duvernay to follow a similar path, and believes Chevron’s acreage is nicely located in the best part of the play. He added the company is not in a position to disclose at this time how many wells it plans to drill next year. The appraisal program will start in the second half of 2014. Technological improvements are what will drive development in the Duvernay, says a pioneer in developing the play. The improvements will likely result from operators moving to slightly longer laterals and smaller fracs with more stages, as in the Marcellus and Eagle Ford shale plays, Brian McLachlan, president and chief executive officer of Yoho Resources Ltd., told the Peters & Co. Limited 2013 Energy Conference. Some of the majors here are already moving in that direction, he said. “I don’t think we have to go out two kilometres, but even adding two or three stages will make quite a difference to your IP and it doesn’t cost that much more,” he said. In response to a question, McLachlan acknowledged that the Duvernay is not an easy formation to fracture with some frac

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february 2014 • OIL & GAS INQUIRER

pressures in the 80,000 kilopascal range. “We had that problem early, but we think we have put in the right ‘cocktail’ to overcome that problem,” he said. “In the last well pair, we were having problems in the fi rst couple of stages and we changed the type of ‘food’ we were using and we had no problems at all after that.” Some operators, said McLachlan, have been introducing gel into their system, which appears to break down the formation even better. Asked about the company’s choice of completion techniques, he said some of the early Yoho wells used the ball-and-drop system while others used “perf and plug.” While partner Celtic Exploration Ltd. favoured a ball-drop system because it was familiar with it in the Montney, Yoho had a bit of a problem with it because “when things go wrong, they go very wrong,” said McLachlan. “I would think that as time goes on, when you are very comfortable with what you are doing, maybe the ball- drop [system] makes sense.” The only downside that is being seen in the United States is that operators are going back into wells and refracturing them and “that is going to be awfully hard to do with a ball-drop system in there,” he said. “You need a perf-and-plug system.” The prize in the Duvernay is 100 billion to 120 billion cubic feet of gas per section in place with liquids-rich gas of 100–160 barrels per million cubic feet (65 per cent condensate), with expected average well recoveries of approximately one million barrels equivalent. The company has 57 (21.75 net) sections of land, all of which are contained within the rich gas condensate window of the play. Yoho will develop its lands with 1,500- to 1,800-metre horizontal sections, with full development likely of seven to eight wells per section. “We have demonstrated that pad drilling will reduce capital costs with the last two Yoho-operated wells at Tony Creek costing a little less than $11 million to drill, case and complete,” said McLachlan. The wells qualify for both the deep case royalty credit as well as the shale gas royalty break, which totals five years of five per cent royalty. Yoho estimates that 145–150 additional net wells are required for full development. Yoho has drilled eight horizontal and two vertical wells to date with eight horizontal wells currently producing. It currently has five operated horizontal wells drill-ready, which includes two well pads and a single horizontal well.


Feature

Producers continue pushing forward with technologies to capture more heavy oil resource

Photo: Joey Podlubny

By Darrell Stonehouse

riven by strong returns, the technological toolbox for coaxing more of the over 30 billion barrels of conventional heavy oil trapped in western Canadian reservoirs continues to grow as developers reinvest in heavy oil plays. Traditionally, heavy oil producers have developed the stacked heavy oil plays found along the border of Alberta and Saskatchewan by drilling vertically into a zone, producing it, then moving to another zone using the same wellbore. In the last few years, however, a number of new methods to access reserves are gaining ground, including horizontal drilling, thermal recovery methods and surfactant floods. Speaking at Husky Energy Inc.’s 2014 outlook, chief operating officer Robert Peabody said Husky plans on drilling 550 wells across its heav y oil portfolio in 2014. While over half of these wells will be traditional vertical wells, the company is spending significantly on horizontal wells and thermal developments.

“One hundred and twenty-five wells will be supporting thermal developments and 140 will be horizontal cold production wells, which we use to produce from thin reservoirs,” he noted. “Cold horizontal production is expected to exceed 10,000 barrels per day in 2014.” While horizontal production is growing, Peabody said thermal production is the company’s focus in the near term. “Thermal production has emerged as the central driver behind our expected steady growth in heavy oil production in 2014 and beyond,” he explained. “Steaming is underway at the 3,500-barrel-per-day Sandall project and we’re preparing for first oil in the first few months of 2014. We’re continuing to build the 10,000-barrel-per-day commercial project at Rush Lake with commissioning set for mid-2015.” Economics is the driving force behind the company’s thermal efforts, said Peabody. “Year-to-date operating costs from all our heavy oil thermal projects now on production were a little under $10 a barrel. OIL & GAS INQUIRER • february 2014

43


Feature

Combine that with low finding and development costs in the $10- to $15-per-barrel range and a premium product price about $10 per barrel more than you’d get for a typical Fort McMurray bitumen barrel, and you can see why these projects generate very strong returns,” he explained. “Our production from heavy oil thermals in the Lloyd region reached 37,000 barrels per day in 2013 and that’s up 40 per cent from last year, and we’re on track to grow this production by another 50 per cent to 55,000 barrels per day by 2017.” Canadian Natural Resources Limited is also using horizontal technology to turn more of its massive heavy oil resource into reserves. Canadian Natural plans on drilling 120 horizontal heavy oil wells in 2014, company president Steve Laut said at its annual investor’s conference early this winter. Another major focus in 2014 will be expanding its polymer flooding success at Pelican Lake into other heavy oil areas, along with increasing waterflooding. Polymer is a non-toxic powder that is mixed with water to create a fluid that is more viscous than water. Injected into the reservoir, the polymer solution—which has a viscosity similar to corn oil—increases oil recovery by improving the sweep efficiency and reducing the amount of bypassed oil. “With a current recovery factor of approximately 10 per cent in primary heavy oil, we continue to work at enhanced recovery methods. We have several of these projects under way with waterflooding progress being made at Lone Rock, South Epping and Salt Lake,” said Scott Stauth, Canadian Natural’s senior vicepresident of North American operations. He was referring to three properties in the greater Lloydminster area of Saskatchewan. At southwest Epping, the company also recently sanctioned a polymer flood pilot, according to a slide in Stauth’s presentation. The multi-well Lone Rock polymer pilot is under construction at 47-27W3. “We plan to use our learnings from Pelican, doubling or even tripling the recovery factors,” Stauth said. “Our Lone Rock and Epping waterflood project has proven very successful.” According to a graph on Stauth’s presentation, Sparky Formation oil production at the Lone Rock and South Epping waterflood pilots climbed to nearly 700 barrels per day this year with 28 producers, up from virtually nothing in January 2011. “We had immediate results from initial injection in both areas,” Stauth said. Water injection began in February 2011 at the Lone Rock pilot and in May 2012 at south Epping.

“When we implement our polymer pilot in this area, we will have more insight to compare success rates of polymer versus water for future development in this grade of oil,” he said. Canadian Natural said the oil is 15–17.5 degrees API with dead oil viscosities ranging between 700 and 2,300 centipoise at 20 degrees Celsius. In addition to the pilot under construction at Lone Rock to test polymer flooding in Lloydminster heavy oil, Canadian Natural is planning a chemical-flooding pilot in medium crude, according to a presentation by Lyle Stevens, senior vice-president, exploitation. The pilot in medium-gravity crude will be an alkaline surfactant polymer (ASP) flood at Grand Forks (12-13W4) in southern Alberta. Construction is to start in the fourth quarter of this year. Laut described polymer flooding as driving significant reserves growth for Canadian Natural and “an important component of our transition to a longer-life, low-decline asset base.” Pelican Lake operating free cash flow is expected to top $300 million this year, and reach almost $600 million per year in 2016 once capital spending on the polymer flood development has been completed. Stevens said Canadian Natural’s incremental capital cost of polymer flooding is in the range of $13–$17 per barrel, depending on the reservoir properties and the existing well density. This includes all the incremental wells, the polymer-mixing facilities, the water-treating facilities, the additional production facilities, maintenance capital and the polymer itself. He said incremental operating costs are about $4 per barrel, mainly associated with handling the polymer and water. “When we started piloting the polymer flood in 2005, it was an untested process in this type of reservoir, and there were no commercial applications with this quality of oil,” Stevens said. “The success of the polymer flood is very obvious,” Stevens said, displaying a graph showing compound annual growth of 27 per cent in Pelican Lake output since the 2007 low point in primary production. “It’s this wedge of production that will continue to grow as we methodically convert the rest of the field to polymer flood,” he said. “Keep in mind that portions of the field have now been on polymer flood for seven years, so this growth is on top of production declines from the mature flood areas.” Stevens displayed a graph of the average output of 17 producing wells at Horsetail Lake, one of the most mature Pelican Lake areas on polymer flood. “In this area, polymer injection commenced in 2006 and average production is still over 150 barrels per day per well and

CAPP western Canadian crude oil supply forecast 2013–2020 Blended supply to trunk pipelines and markets (thousand barrels per day)

Conventional heavy oil

Actual

Forecast

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

309

312

334

340

356

361

365

370

372

371

367

660

703

752

841

855

857

834

807

788

777

775

OILSANDS Upgraded light (synthetic) 1 2

1,134

1,302

1,413

1,532

1,744

1,907

2,133

2,353

2,593

2,835

3,194

TOTAL OILSANDS AND UPGRADERS

1,794

2,005

2,166

2,374

2,599

2,763

2,967

3,160

3,381

3,611

3,969

Total heavy supply

1,443

1,614

1,747

1,872

2,100

2,267

2,498

2,722

2,965

3,205

3,561

Oilsands heavy

1Includes upgraded conventional 2Includes imported condensate, manufactured diluent from upgraders and upgraded heavy volumes coming from upgraders

44

february 2014 • OIL & GAS INQUIRER


Photo: Joey Podlubny

Feature

slowly declining,” he said. “Current total recovery in this area is approximately 20 per cent—more than three times what was achieved on primary.” Stevens cautioned: “We do have significant variation in performance across the field due to variations in reservoir properties and oil quality. But overall performance is still very strong.” He implied the project involved a significant learning curve: “Although polymer flooding sounds simple, the reality is it’s taken a huge amount of development work to make it a technical success and, most importantly, an economic success.” Canadian Natural is working on various technology improvements related to polymer flooding. It is evaluating the use of surfactants to help reduce the residual oil that’s left behind as the polymer flood sweeps through the reservoir. It is also continuing to test new polymers that have the potential to reduce costs and improve performance.

“Water treating plays a complex role in performance of the polymer. In the last few years, we’ve made significant advances in the design of our treating facilities and we continue to work on this front to improve performance and costs,” Stevens said. In the areas where Canadian Natural has polymer flood operations, its independent reserves evaluator now estimates ultimate recoveries will average 25 per cent. “Overall, the polymer flood has resulted in Canadian Natural achieving a very impressive fourfold increase in reserves over primary recovery in the developed regions,” Stevens said. “We’ve proven that taking our time and staging the development has improved both the oil recovery and costs.” He said commercial polymer flooding is “still in its infancy as a recovery process.” Over the next few years he expects to see more applications of the technology, improved performance, improved economics and increased oil recovery.

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Oil & Gas Inquirer February 2014  

443 trillion cubic feet of natural gas 11.3 billion barrels of natural gas liquids 61.7 billion barrels of oil = Duvernay

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