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CONTENTS

MAY.14

in the news

9

Alberta testing play-based approach to unconventional well approvals

regional news

13

British Columbia

21

Northeastern Alberta

29

Southern Alberta

Time is of the essence for B.C. LNG

Oilsands capital spending of $25 billion forecast for 2014

Production up at LGX

17

25

33

Northwestern Alberta

Kaybob the sweet spot for Duvernay, says Yoho

Central Alberta

Saskatchewan

Gear Energy sets production record

Central Alberta plays drive Vermilion Energy production record

features

COVER

FEATURE

38 Prairie flood Enhanced recovery gains ground in tight oil, heavy oil and conventional plays

every issue

6 Stats at a Glance 46 Political Cartoon

44 Winds of change Emerging oil plays breathe new life into southern Alberta oilpatch

Cover design: Peter Markiw Photo: Logray-2008/Thinkstock

O I L & G A S I N Q U I R E R • M AY 20 14

3


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Editor’s Note Vol. 26 No. 5 EDITORIAL EDITOR

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

Carter Haydu, Richard Macedo, Pat Roche, Elsie Ross, Paul Wells

Waiting for the green light

EDITORIAL ASSISTANCE MANAGER

Tracey Comeau | tcomeau@junewarren-nickles.com EDITORIAL ASSISTANCE

Kate Austin, Matthew Stepanic CREATIVE PRINT, PREPRESS & PRODUCTION MANAGER

Michael Gaffney | mgaffney@junewarren-nickles.com

With low gas prices and large price discounts on

similar amount this year in the Bakken and in the

Tamara Polloway-Webb | tpwebb@junewarren-nickles.com

oil coming out of western Canada, the petroleum

Cardium in Alberta.

CREATIVE LEAD

industry seems to be spinning its wheels a bit as

CREATIVE SERVICES MANAGER

Cathlene Ozubko GRAPHIC DESIGNER

Peter Markiw

CREATIVE SERVICES

Ginny Tran Mulligan production@junewarren-nickles.com SALES SALES MANAGER—ADVERTISING

2014 unfolds. But there are plenty of signs it could gain trac-

On the gas side, it is becoming evident that the liquids-rich Duvernay play is for real. Shell Canada Limited has drilled 38 wells in the play

tion in the second half of the year as long-standing,

and reported over 10,000 barrels of oil equivalent

progress-impeding blockades are removed.

in production at the end of 2013. Around 200

On the oil side, June marks the time frame

wells are expected to be drilled this year.

Monte Sumner | msumner@junewarren-nickles.com

when the federal government says it will

SENIOR ACCOUNT EXECUTIVES

announce its decision on whether the Northern

ing for liquefied natural gas (LNG) exports off

Gateway Pipeline will be approved. If yes, expect

the west coast. Progress Energy Canada Ltd.

confidence in oilsands operators to improve

reported running 26 rigs this winter in the

substantially.

Montney, with president and chief executive

Nick Drinkwater, Tony Poblete, Diana Signorile SALES

Rhonda Helmeczi, Sammy Isawode, Mike Ivanik, Nicole Kiefuik, David Ng, James Pearce For advertising inquiries please contact adrequests@junewarren-nickles.com AD TRAFFIC COORDINATOR—MAGAZINES

Lorraine Ostapovich | atc@junewarren-nickles.com DIRECTORS CEO

Bill Whitelaw | bwhitelaw@junewarren-nickles.com PRESIDENT

Also of note is the emergence of a number of

There are also signs operators are prepar-

officer Michael Culbert telling the Daily Oil

new tight oil plays, as well as growing explora-

Bulletin it spent $2 billion last year. It has also

tion into shale oil plays, which promise huge new

spent $1.5 billion on acquisitions and has been

resources to target. The shale oil plays include the

an active buyer at land sales.

Second White Specks in west-central Alberta and

Progress is working to identify 15 trillion

Rob Pentney | rpentney@junewarren-nickles.com

the Muskwa shale in northwestern Alberta, where

cubic feet of proved-plus-probable reserves

DIRECTOR OF SALES & MARKETING

Husky Energy Inc. continues experimenting with

by year-end 2014, when its parent company

drilling and completion methods. Montney tight oil

PETRONAS will decide whether to proceed with

Ian MacGillivray | imacgillivray@junewarren-nickles.com

is moving out from its base at Kaybob South to Ante

an LNG project.

DIRECTOR OF THE DAILY OIL BULLETIN

Creek and west into British Columbia at Parkland

Maurya Sokolon | msokolon@junewarren-nickles.com DIRECTOR OF EVENTS & CONFERENCES

Stephen Marsters | smarsters@junewarren-nickles.com

It also appears that a number of other operators

and Tower. Encana Corporation and Canadian

are preparing to begin the ramp-up of drilling in

Gord Lindenberg | glindenberg@junewarren-nickles.com

Natural Resources Limited are pushing Montney

the Horn River and Liard basins in preparation

DIRECTOR OF CONTENT

oil development north into the Peace River Arch.

for LNG exports. A number of large rigs designed

And Tourmaline Oil Corp. and Birchcliff Energy

to drill the massive shale gas wells are under con-

Ltd. are rapidly developing a Charlie Lake oil play

struction and, more importantly, under contract.

in northwestern Alberta as well.

Pressure pumpers are also reporting early discus-

DIRECTOR OF DIGITAL STRATEGIES

Chaz Osburn | cosburn@junewarren-nickles.com DIRECTOR OF PRODUCTION

Audrey Sprinkle | asprinkle@junewarren-nickles.com DIRECTOR OF FINANCE

Ken Zacharias, CMA | kzacharias@junewarren-nickles.com OFFICES Calgary nd Flr-  Avenue N.E. | Calgary, Alberta TE Y Tel: .. | Fax: .. Toll-Free: ...

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Service companies are also seeing the beginnings of a growing workover market in existing tight oil plays. In the North Dakota Bakken, service rigs are in high demand as wells mature and

sions about equipment needed in 2015. It seems the predicted boom of a few years ago that stalled out is beginning to fi re up. Get ready—by 2015, the race could be back on.

require intervention to maintain production levels. This is now spreading to Saskatchewan where

Darrell Stonehouse

Lightstream Resources Ltd. spent $30 million

Editor

on workovers last year and expects to spend a

dstonehouse@junewarren-nickles.com

Subscription Inquiries Telephone: ... Email: circulation@junewarren-nickles.com Online: junewarren-nickles.com GST Registration Number RT. Printed in Canada by PrintWest. ISSN - | ©  JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number . Postage paid in Edmonton, Alberta, Canada. If undeliverable, return to:

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Selling Canadian technology overseas, plus a

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.

look at Canadian explorers operating around the world.

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.

O I L & G A S I N Q U I R E R • M AY 20 14

5


FAST NUMBERS

2

million barrels per day

Needed oil export capacity by 2020, says Ziff Energy, a division of HSB Solomon Associates LLC.

5.1

million barrels per day

Western Canadian oil production by 2022, says Ziff Energy, a division of HSB Solomon Associates LLC.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin OTHER

T O TA L

MONTH

















M O NTH

OIL

GAS

Mar 



Apr 



Jun 



OIL

GAS

D RY

SERVICE

T O TA L

Mar 









Apr 













Jun 









,

Jul 









Jul 











Aug 









Aug 











Sep 















,

Sep 







Oct 









Oct 

Nov 









Nov 







,

Dec 









Dec 











Jan 









Jan 











Feb 









Feb 









,

Mar 









Mar 









,

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

Mar 





Mar 







Apr 





Apr 





Jun 





Jun 





Jul 





Aug 

Jul 











Sep 





Aug 





Oct 





Sep 





Nov 





Oct 







Dec 





Nov 







Jan 





Dec 







Feb 





Jan 







Mar 





Feb 





Mar 







*From year-to-date

GAS

OTHER

TOTAL

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STATS

AT A

GLANCE

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, April 11, 2014 Source: Rig Locator

Alberta, March 2014 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada Alberta British Columbia

Manitoba Saskatchewan WC TOTALS

AC T I V E

OIL WELLS

Alberta

GAS WELLS

Mar 

Mar 

Mar 







%

Northwestern Alberta















%

Northeastern Alberta









%

Central Alberta















%

Southern Alberta















%









TOTAL

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada, April 11, 2014 Source: Rig Locator

Alberta, March 2014 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

AC T I V E (Per cent of total)

Western Canada

Alberta

Mar 

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

Alberta

Mar 

Mar 

BITUMEN WELLS Mar 

Mar 







%

Northwestern Alberta

British Columbia

%

Northeastern Alberta





Manitoba

%

Central Alberta











%

Southern Alberta









%

TOTAL







Saskatchewan

WC TOTALS

O I L & G A S I N Q U I R E R • M AY 20 14

7


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IN THE

NEWS Issues affecting Canada’s E&P industry

unconventional

Alberta testing play-based approach to unconventional well approvals By Pat Roche

The Alberta Energy Regulator (AER) is preparing to launch a pilot project to test the concept of play-based approvals for unconventional oil and gas developments. Development of major resource plays such as the liquids-rich Duvernay shale is expected to involve a multitude of operators with large equipment deployments over vast areas. Given the level of activity usually associated with big unconventional developments, the AER’s predecessor tossed around the idea a couple of years ago of shifting to a comprehensive, or play-based, approval process for large unconventional developments, instead of considering individual applications in isolation. Until now, there hasn’t been a concrete plan to test such an approach in the field. “We’re going to move out very quickly with a pilot project,” AER chief executive officer Jim Ellis told an Economics Society of Calgary lunch.

The location of the pilot hasn’t been announced yet, but Ellis said “10 or 12 major companies” are working there now, and a big increase in activity is expected. “They have a lot of activity they want to do. What we want to do is help them understand that not every company is going to have its own pipeline, not every company is going to get its own road. We’re not going to have a gas plant for every company.” Because a play-based approach would have the potential to improve the economics as well as reduce the environmental impact, Ellis indicated the industry is receptive to the idea. But he acknowledged it would require a different mindset for producers as well as regulators. “Companies don’t really work together like that. That’s not normally the way companies work. They compete with one another…. You’ve got to find a way to work closer together,” he said.

Known as the unconventional resource framework, the proposed regime would manage activities based on the overall play, instead of just considering specific projects within the play. The duration of the planned test hasn’t yet been determined, but “we want to pilot it as quickly as we can and then start moving forward with it,” Ellis told the Daily Oil Bulletin. “We have the teams set up in place right now,” he said, adding the project will be headed by an AER vice-president. Once the location has been announced, the industry and community stakeholders will be brought in. “We’ll look at a new application process,” Ellis said in an interview. “We’ll look at a different way to deal with the stakeholder engagement and that sort of thing. If it works, then we’re going to broaden it out to more opportunities across the province.”

pipeline repurposing

Shale gas juggernaut to spur pipeline repurposing, CERI conference hears By Elsie Ross

The growth in natural gas production from low-cost plays, such as the Marcellus and Utica shales along with the Eagle Ford in Texas, will require a realignment of pipelines throughout North America, a gas conference heard in March. “Even eastern Canadians don’t want western Canadian gas; they just want the

cheapest gas,” Edward Kallio, director, gas consulting, with Ziff Energy, a division of HSB Solomon Associates LLC, told the Canadian Energy Research Institute conference. “All the pipeline infrastructure around North America is going to have to realign to this truth that this gas production is growing,” he said.

It’s growing because it’s cheap to develop, with producers in the liquids-rich areas of the Marcellus and the Eagle Ford able to earn a return at US$3.50–US$4 per million British thermal units, according to Kallio. “That’s the marginal gas; that’s where the rigs are going.” Current natural gas capacity out of the Western Canadian Sedimentary Basin is O I L & G A S I N Q U I R E R • M AY 20 14

9


In The News

15.7 billion cubic feet per day, and Ziff is forecasting that will decline to just over five billion cubic per day by 2020, as a projected 19 billion cubic feet per day of Marcellus and Utica production displaces western Canadian gas. At the same time, western Canadian oil production is forecast to increase to about 5.1 million barrels per day in 2022, and Ziff sees another one million barrels per day after that. “We need more oil pipe; we certainly don’t need more gas pipe.” Between now and 2020, there will be a need for roughly an additional two million barrels per day of oil export capacity, said Kallio. TransCanada Corporation’s proposed 1.1-million-barrel-per-day Energy East project to convert unused gas pipeline to oil service and build new pipe, coupled with one million barrels per day of planned new rail capacity, should handle the incremental two million barrels per day of western Canadian crude forecast to come on production by 2020, he said. “If there are problems with the rail, if there are problems with the Energy East conversion, if we don’t get Keystone [XL], Trans Mountain, if we don’t get any of

that, then we are in trouble,” he said. “We stay around three million barrels a day and that’s where we top out,” said Kallio. “Differentials crater, and you can’t add more oilsands production or even incremental tight oil production.” Natural gas demand would also be affected because current oilsands demand for gas is about 1.3 billion to 1.4 billion cubic feet per day, the conference heard. “By 2020, with this view, we are going to three billion cubic feet per day. If we don’t get this, we top out at 1.3 [billion], 1.4 billion cubic feet per day on the gas-demand side.” Current western Canadian natural gas production is about 13 billion cubic per day, down from 16 billion cubic feet per day in 2000. “It is a dire scenario” unless producers can access export markets and liquefied natural gas (LNG) projects with three billion cubic feet per day of gas demand come to fruition, he said. “I certainly hope that the B.C. government gets this on the LNG side.” In terms of providing new oil market access, Energy East “is a great proposition for shippers,” with a toll of roughly $4 –$5 per barrel from the Alberta-Saskatchewan border to tidewater, based on a 36-inch-diameter

pipeline, said Kallio. The Ontario Energy Board is reviewing the project’s effect on consumers and has contracted Ziff to do the market analysis. Another western Canadian candidate for repurposing is the Alliance Pipeline, a bullet line that transports liquids-rich gas from northeastern British Columbia to the Chicago area, where liquids are extracted at the Aux Sable Liquid Products Inc. plant, Kallio suggested. Ziff is forecasting that Alliance volumes will decline to 870 million cubic feet per day from the current 1.5 billion cubic feet per day. “We see the Alliance system as potentially having problems down the road,” he said, noting that in 2010 less than 10 per cent of the shippers on the line opted to recontract in 2015, when their contracts are set to expire. “We could see repurposing to oil, we could see them stripping liquids out, potentially around Edmonton and turning it into a dry gas line.” Kallio said that while he’s sure Alliance has looked at conversion to an oil pipeline, if it were to cross the border it would require a U.S. presidential permit, and there is no assurance it would get one in light of what Keystone XL has faced.

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M AY 20 14 • O I L & G A S I N Q U I R E R

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B.C.

BRITISH COLUMBIA WELL ACTIVITY MAR/13

MAR/14

Wells licensed



129

MAR/13

MAR/14

Wells spudded



65

Rigs released

MAR/13

MAR/14



82

British Columbia

Source: Daily Oil Bulletin

Time is of the essence for B.C. LNG By Richard Macedo

Liquefied natural gas (LNG) exports out of western Canada will occur, according to Jihad Traya, associate director, North American natural gas, with IHS CER A, but a coordinated effort by the industry, the government and other participants is needed to ensure the projects are successfully built. “Is it 16 projects? Most likely not,” he told the Canadian Energy Research Institute 2014 natural gas conference. “By 2025, our view is that we see at least four billion cubic feet a day of exports.” In British Columbia, just over a dozen export projects have been officially proposed, but the vast majority will not be built. “There is a timeline on this; there is limited time,” he said. What’s attractive about B.C. LNG is that the buyers can participate in the upstream industry with relative ease. The cost escalation happening in Australia, though, should serve as an example to proponents in western Canada of what happens when several projects are built simultaneously. “If you were to have all projects go ahead and commence at once, or four at the same time, you will run into not only cost escalations, but supply issues and

constraints,” Traya said. “A measured and staged cooperative effort by industry, government and all other participants is required to make western Canadian LNG that much more successful, or increase the potential for its development.” Japan will remain one of the key countries fuelling natural gas demand, Traya added. “We do see Japan levelling off, but as Japan levels off, the rest of Southeast Asia grows,” he said. T he t r ad it ion a l L NG i mp or t i ng count r ies — Japa n, Sout h Korea a nd Taiwan—have no interconnecting pipeline inf rastr ucture and v ir tually no indigenous resources, and therefore rely on LNG to meet almost all of their gas demand. A Chevron Corporation executive recently noted that just five years ago, 17 countries were importing LNG; today, 26 countries are doing so, and this is expected to increase. “In terms of supply, Russia is a big, big factor,” Traya said. “Russia has vast resources and is moving to not only monetize those resources, but use it as a geopolitical tool, and that has a lot of implications. It’s a lot easier to make an economic decision under an autocratic regime than it is under the regimes of

Asian imports of liquefied natural gas (bcf/d) Country Japan









8.39

9.04

10.34

11.5

South Korea

3.36

4.30

4.77

4.8

Taiwan

1.07

1.45

1.58

1.6

India

1.18

1.18

1.65

2.0

China

0.72

1.23

1.61

1.9

14.71

17.21

19.95

21.8

Total Pacific Basin

Sources: International Gas Union; International Group of Liquefied Natural Gas Importers

North America and western Europe. We see Russia as a potential new supply source and a very aggressive supply source.” Ines Piccinino, assistant deputy minister, upstream development division, with the B.C. government, said that there are upwards of 16 LNG proposals in the province, “some of them not necessarily disclosed in terms of providing details. “ Some of t he m we k now ab out because we’ve been approached by potential investors that mentioned their interest,” he said. LNG imports in Japan rose sharply in the wake of the Fukushima disaster, and Hiroshi Hashimoto, senior analyst with the Institute of Energy Economics, Japan, noted that “some progress has been observed in the Canadian LNG export projects and some of those projects include Japanese involvement.” In a recent report he helped author, Hashimoto states that although Japan’s LNG imports in 2013 grew only marginally by 0.2 per cent year-on-year, the corresponding payment increased significantly to ¥7 trillion in 2013 from ¥6 trillion in 2012. However, the average unit price declined to US$16.10 per million British thermal units in 2013 from US$16.18 in 2012. The main cause of the huge increase in payment was the weaker Japanese yen in 2013. “Japanese LNG buyers interested in LNG from the United States…is mostly based on the fact that prices here are much lower than prices over there,” he noted. Will LNG prices be oil-, AECO- or Henry Hub–linked? “There’s a lot of discussion around this because it really changes the dynamics of how traditional transactions occur,” Traya said. “The IHS view is that there is room in North America for an oil-linked price, but most likely a combination of an oil- and Hub-linked price. “Is that link going to be to AECO or to Henry Hub? Most likely Henry Hub.” O I L & G A S I N Q U I R E R • M AY 20 14

13


British Columbia

Progress Energy completes two Montney acquisitions Progress Energy Canada Ltd., the Canadian subsidiary of Malaysia’s PETRONAS, has closed its previously announced agreement to acquire assets in northeastern  British Columbia from Talisman Energy Inc. In a second transaction, Progress said it closed an acquisition in January in the Julienne area of British Columbia for approximately $130 million, which includes four Montney wells that are awaiting completion and about 33,500 net acres of undeveloped Montney lands in the heart of the company’s North Montney Joint Venture B.C. holdings. While Progress didn’t announce from whom it had acquired the land, Enerplus Corporation said in November it had entered into an agreement to sell its Montney interests at Julienne Creek for $130 million. “These two acquisitions continue to build upon our natural gas resource base in the North Montney. With the complementary fit, we have captured operational

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synergies as well as additional strategic assets,” said Michael Culbert, president and chief executive officer of Progress. The acquisition from Talisman includes about 127,000 net acres of Montney land and has current production of approximately 12,500 barrels of oil equivalent per day. “We announced this transaction in November 2013, and its closure, coupled with other previously announced deals, means we have achieved over $2 billion in dispositions within 12 months,” said Hal Kvisle, president and chief executive officer of Talisman. “During the next 18 months, we will continue to focus our portfolio and aim to divest a further $2 billion of longdated, capital-intensive assets. We will use proceeds from dispositions to maintain a strong balance sheet.” Talisman retains its Groundbirch and Saturn assets, including approximately 48,000 net acres of prospective Montney land. — DAILY OIL BULLETIN


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NORTHWESTERN ALBERTA WELL ACTIVITY MAR/13

MAR/14

Wells licensed



288

MAR/13

MAR/14

Wells spudded



185

MAR/13

MAR/14



240

Rigs released

Source: Daily Oil Bulletin

N.W. Northwestern Alberta

Kaybob the sweet spot for Duvernay, says Yoho By Richard Macedo

Early on, Yoho Resources Inc. felt that Kaybob was going to be a prime area for the Duvernay shale gas play, said Brian McLachlan, president and chief executive officer. “So far, our predictions are coming true. So far, we’re seeing the best wells in the Kaybob area,” he told the company’s annual meeting. “The overall thickness of 50 metres or greater at Kaybob is certainly number one.” The company holds 59 (23.5 net) sections prospective for the Duvernay. The junior producer was one of the early entrants into the play, which is now dominated by major companies like Exxon Mobil Corporation, Chevron Corporation, Encana Corporation, Royal Dutch Shell plc and Talisman Energy Inc. “The more thickness you have, the more reserves in place,” he added. “We’re Active North Duvernay landholders Acreage (net sections)

Wells drilled (/)

Exxon Mobil

169

16

Athabasca Oil

550

14

Encana/ PetroChina

578*

18

Trilogy

207

8

Chevron

508

22

Shell

n/a

78

Yoho

22

4

Husky

86

12

EOG

155

3

Apache

n/a

1

Talisman

243

4

Bounty

200

8

*Total acreage in both North and South Duvernay. Sources: BMO Capital Markets; Keyera Corp.; JuneWarren-Nickle’s Energy Group

seeing rock quality in this Kaybob area that’s second to none on the trend. The continuous nature of the porosity in the Kaybob area is also very important when you’re drilling horizontal wells and fracturing.” McLachlan said after the meeting that Kaybob “is our number one…underlying value play. We’re taking a little bit of a slower approach to it because there’s a lot of wells being drilled around us that we can learn off of.” During his presentation, he said there’s a web of infrastructure at Kaybob, although more will be developed. “There’s roads, there’s pipelines, there’s gas plants existing—they may not be ideal, but they’re there, and we can at least get our production on stream, which is great,” McLachlan said. “Not only are we seeing an increase in the drilling activity in this area, [but] somewhere in the order of about $400 million is currently being plowed into the ground in the form of gas plants and major pipelines. “That’s a lot of money. If someone is spending $400 million on this play, they certainly have a good idea that this play is what they think it’s going to be.” Activity in the Duvernay has started to increase, and while it didn’t climb “as fast as we had expected earlier,” he noted the majors are developing the play and “they do things in their own time. “Quite frankly, I think you’re starting to see a lot of dollars being spent,” McLachlan noted, adding that since 2009, roughly $3 billion has been spent on land. “Over 100 horizontal wells have been drilled, mostly at Kaybob,” he said. “We expect to see 175–200 wells drilled in 2014—horizontal wells—on this play.” For fiscal 2014, Yoho has an overall capital program of between $40 million and $42 million, which includes drilling four (1.5

net) wells at Kaybob. The first well has been drilled and cased and completion will happen after breakup. The second well is currently drilling, the third well was spudded but suspended due to breakup and drilling will continue after breakup. The fourth well is drilled and cased, and completion should start soon. Pointing to a presentation slide that highlights earlier wells, McLachlan said the company continues to see consistent liquids/gas ratios. “I think that’s very important,” he said. “There’s been a lot of progress made in the way that people frac these wells and the way we do things. We do expect continued and substantial improvement in the IP [initial production] rates and the EURs [estimated ultimate recoveries]. “Yoho has taken a little bit of a quieter approach to this play because there’s a pile of wells being drilled around us,” McLachlan added. “Our learning curve is very steep right now, learning off the majors, basically. Since we drilled the early wells in the play, I think that’s probably the way to play this thing.” He said that the Duvernay will likely be developed at six to eight wells per section. A pad drilling development scenario would result in an average of $10 million to $11 million per well (drill, case, complete), “depending on how long your laterals are, how many stages you’re [fracturing]. “We do qualify for five years’ royalty holiday; that’s five years at five per cent,” McLachlan added. “If you get too far into the oil window, you lose some of that—you’re no longer deep gas, you’re deep oil, so that’s why I think it’s very important to stay in that high-liquids gas window. The second reason to stay in that high-liquids gas window is we believe that gas acts as your lift for your liquids and without it, I don’t think your productivity is going to be as impressive.” O I L & G A S I N Q U I R E R • M AY 20 14

17


Northwestern Alberta

Horizontal drilling helps boost Charlie Lake activity as producers report strong reserves gains By Richard Macedo

While it’s not expected to become a blockbuster play in North America on the scale of the Montney, the Charlie Lake Formation has quietly been yielding solid reserves gains for operators working there. One of the most active Charlie Lake operators is Tourmaline Oil Corp., which is running three rigs in the Peace River High Charlie Lake oil complex. The company recently reported that Charlie Lake reserves on the Peace River High rose to 49.75 million barrels of oil equivalent, a 101 per cent increase over 2012 reserves of 24.75 million barrels of oil equivalent. In 2013, Tourmaline spent $53 million consolidating land on this new regional oil play, and in aggregate 514 sections were acquired on the trend. The company believes that the regional pool could ultimately yield

18

M AY 20 14 • O I L & G A S I N Q U I R E R

over 500 million barrels of oil equivalent. The producer said it controls over 75 per cent of the prospective trend as currently mapped. Tourmaline plans to complete four concurrently stimulated horizontal well pairs prior to breakup. The company drilled approximately 35 new wells in 2013, and about 45 are planned for 2014. Tourmaline said Charlie Lake is a significant resource-style play, but not as large as the Montney, for example. The average cost to drill and complete is $3.6 million. Charlie Lake is of Triassic age, somewhat younger than the Montney and older than the Nordegg, and is found in northeastern British Columbia and adjacent to Alberta as far north as Township 90. It consists of sandstones, siltstones and marginal marine carbonate rocks

deposited on a broad, low-relief coastal plain, or sabkha, noted Brad Hayes, president of Petrel Robertson Consulting Ltd. Because the climate was arid, evaporite minerals—particularly anhydrite—precipitated in the system and tightly cemented many of the sandstones and siltstones. “Where good reservoir quality is preserved, Charlie Lake sandstones and carbonates can be high-quality oil pools such as at Brassey and Boundary Lake,” he said. “In Alberta, the Charlie Lake is capped by the Worsley Member, which locally contains reservoir-quality sandstones.” Hayes said that the Charlie Lake play has traditionally been a conventional oil and gas target. “Operators have explored for small but highly productive pools using detailed


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stratigraphic mapping and seismic. The biggest discovery was the Boundary Lake oil pool in 1955,” he noted. “Brassey was a highprofile light oil find in the late 1980s.” Charlie Lake has attracted more interest lately, as companies have realized that existing pools in the Worsley Member are better exploited and more economic using horizontal wells. “In addition, the widespread, relatively poor-quality reservoirs in the Worsley, previously seen as uneconomic, can now be produced over much larger areas using horizontal wells and appropriate stimulation,” Hayes said. “Oil quality is good, the reservoir is at moderate depths and relatively large—multi-section to township scale—prospective areas exist.” In addition to Tourmaline, Birchcliff Energy Ltd. also reported higher reserves in the Charlie Lake play for 2013. Estimated proved-plus-probable reserves are 38.9 million barrels of oil equivalent, including 19.6 million barrels proved, for the Worsley Charlie Lake light oil pool on the Worsley Charlie Lake light oil resource play. Birchcliff said this continues the growth trend for its Charlie Lake reserves since July 1, 2007, the effective date of the acquisition of the property. At that time, recoverable reserves were estimated at 15.1 million barrels on a proved-plus-probable basis, and 11.3 million barrels on a proved basis. Both the original oil in place and the estimated recoverable reserves continue to increase, said the company, which reported that the Worsley Charlie Lake light oil pool continues to be a topquality asset. This year, $29.2 million will be spent on eight Worsley Charlie Lake horizontal oil wells. The company holds 181,541 net acres that are prospective for the Charlie Lake light oil resource play. “Our main pool holding over 400 million barrels of oil in place is in Worsley, Alta. Our land is mostly large blocks of 100 per cent owned, contiguous blocks which helps with repeatability, pad drilling and the construction of infrastructure,” said Jeffery Tonken, Birchcliff president and chief executive officer. “We believe the play has significant growth potential on land we currently own.” He added that the play stretches across the Peace River Arch and has become popular because of the economics and the opportunity of growth due to the application of horizontal drilling and fracturing, which is enabling further resources to be unlocked. “New technology, horizontal wells, completion techniques and resulting recoveries, together with higher light oil prices, have driven this play,” Tonken said. “This formation is only found in the Peace River Arch, so it will be limited to northwestern Alberta.” Drilling and completion costs, on average, are roughly $2.5 million per well, Birchcliff said.

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NORTHEASTERN ALBERTA WELL ACTIVITY MAR/13

MAR/14

Wells licensed



58

MAR/13

MAR/14

Wells spudded



196

MAR/13

MAR/14

Rigs released



191

Oilsands capital spending of $25 billion forecast for 2014 Alberta oilsands capital expenditures are likely to top $25 billion this year as operators continue to ramp up production, despite the current challenges of tight pipeline capacity. Based on publicly available information, the Daily Oil Bulletin has calculated $23.78 billion in planned spending in 2014. The figure does not include numbers for projects such as Long Lake operated by Nexen Energy ULC, now a unit of CNOOC Limited, as the new owner no longer provides that information. The Canadian Association of Petroleum Producers is projecting another strong year, with expenditures in line with 2013 spending of about $25 billion, said Martyn Griggs, manager of oilsands. “We don’t see a major uptick or a major downtick either,” he said. “In any other industry, they would be stunned with that level of investment.” The oilsands has bounced back strongly since 2009, when expenditures of $18 billion reflected a significant pullback in response to the global economic downturn, Griggs noted. Canadian Natural Resources Limited and Suncor Energy Inc. will be the two biggest spenders this year. Canadian Natural has forecast capital expenditures of $4.68 billion, of which up to $3.55 billion has been allocated to its Horizon mining operation and $1.13 billion to thermal in situ projects. Planned spending at Horizon includes up to $1.58 billion for Phase 2B and up to $770 million for Phase 3. In situ allocations include $600 million for Primrose and future projects, and $450 million for Kirby North Phase 1. For its part, Suncor has budgeted $4.45 billion for its oilsands operations, including $1.35 billion for advancing the Fort Hills mine joint venture with Total E&P

N.E.

Northeastern Alberta

Source: Daily Oil Bulletin

Alberta capital expenditures Year

Conventional oil and gas (C$ billion)

Oilsands (C$ billion)

2012

21.5

20.4

2013

24.5

21.6

2014

25.0

22.1

2015

25.0

23.4

2016

25.0

22.2

2017

25.5

21.5

2018

26.0

20.0

2019

26.0

19.8

2020

26.5

19.8

2021

26.5

19.1

2022

27.0

18.1

Source: Canadian Association of Petroleum Producers

Canada Ltd. and Teck Resources Limited. The mine will produce up to 73,000 barrels per day of bitumen as early as the first quarter of 2017. Husky Energy Inc. plans to spend $400 million for its 60,000-barrel-per-day (30,000-barrel-per-day net) Sunrise thermal in situ project. First oil should come on production in late 2014. The estimated total cost of the project is $2.8 billion. Syncrude Canada Ltd.’s total budget for 2014 is $2.76 billion. The majority will be directed to its major projects, the Mildred Lake mine train replacement ($965 million) and the centrifuge tailings management project ($812 million). The Mildred Lake mine train replacement project is targeted to be in service in the fourth quarter of 2014, with the tailings management project expected to be in operation in the first half of 2015.

For Canadian Oil Sands Limited, which indirectly owns a 36.74 per cent interest in the Syncrude joint venture, the majority of its $1.01-billion expenditure for 2014 will be the Mildred Lake mine train replacement (Canadian Oil Sands share $355 million) and the centrifuge tailings management project (Canadian Oil Sands share $298 million). Cenovus Energy Inc. and ConocoPhillips Canada plan to spend a combined total of $1.64 billion at their Christina Lake joint venture, $1.52 billion at Foster Creek and $460 million at the new Narrows Lake project. All 50/50 joint ventures are in situ projects. On its own, Cenovus has budgeted an additional $160 million for in situ emerging oilsands assets. Total E&P Canada will spend $2 billion in the oilsands this year, with the vast majority ($1.24 billion) allocated to the Fort Hills mine project. The company is also working on Surmont Phase 2, a joint-venture in situ project, with 50/50 partner ConocoPhillips. MEG Energy Corp. plans capital spending of $1.8 billion this year. Spending will include the implementation of Phase 2 of its RISER production enhancement initiative and the ramp-up of Christina Lake Phase 2B. The budget includes investment in a major brownfield expansion within Phase 2B, which the company anticipates will raise its overall production to 115,000–125,000 barrels per day by early 2017. MEG also budgeted $125 million in 2014 for a field pilot test of its proprietary HI-Q technology. This “pipeline-spec-upgrading” process is designed to lower the viscosity of the company’s bitumen sufficiently for pipelining without diluent. At the Athabasca Oil Sands Project joint venture operated by Royal Dutch Shell plc, planned capital spending is $1.47 billion (Shell’s share is $882 million). Teck Resources has a capital budget of $995 million, with $850 million for its share of the Fort Hills mining project. It has allocated an additional $105 million for its O I L & G A S I N Q U I R E R • M AY 20 14

21


Northeastern Alberta

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M AY 20 14 • O I L & G A S I N Q U I R E R

proposed new Frontier mine, a 240,000barrel-per-day project about 110 kilometres north of Fort McMurray. Devon Canada Corporation capital expenditures of $900 million for thermal in situ oilsands projects will include completing construction of the Jackfish 3 in situ project. Athabasca Oil Corporation plans to spend $328 million on the Hangingstone in situ project. The figure includes $225 million for the project itself, with first steam expected near the end of this year; $58 million on Hangingstone regional infrastructure and production support; and $45 million for regional activities and to advance the regulatory approval for a Hangingstone expansion. The company has also allocated another $20 million for other in situ projects. At Lindbergh, Pengrowth Energy Corporation has budgeted $365 million for the completion of its 12,500-barrel-per-day in situ project. First steam is expected in the fourth quarter of 2014, with first oil in early 2015. Harvest Operations Corp., a wholly owned subsidiary of Korea National Oil Corporation, will spend $131 million as it continues work on its BlackGold project, a 10,000-barrel-per-day in situ project. Connacher Oil and Gas Limited has a $58-million capital budget. The $50 million allocated for growth will include nine new infill wells at Pod 1 and continued engineering work on its proprietary solvent steam assisted gravity drainage technology at Algar, along with a mini steam expansion at Pod 1. Baytex Energy Corp. will spend about $24 million on thermal projects. — DAILY OIL BULLETIN

Ivanhoe suspends work on Tamarack project By Elsie Ross

Following a thorough review, Ivanhoe Energy Inc. said it has suspended activity on its 20,000-barrel-per-day Tamarack oilsands project, citing regulatory uncertainty about the timing of a new regulatory framework for shallow steam assisted gravity drainage (SAGD) projects. The Alberta Energy Regulator (AER) has not indicated a timeline for the new


Northeastern Alberta

1984

rules, and until there is greater regulatory certainty as to how the project can obtain approval, Ivanhoe only plans to spend money on essential items, said Hilary McMeekin, a company spokeswoman. The company said it considers its decision appropriate and in the best interests of all stakeholders, given the resulting delay in the approval process. “Ivanhoe believes its application, as submitted, adheres to best practices for safe reservoir development,” it added. At a meeting with the AER late last year, Ivanhoe was advised that the regulator would not continue to process its Athabasca oilsands project until 3-D seismic has been collected and interpreted over the entire initial development area and the maximum operating pressure meets the interim guidelines. The company does not plan to do that work at the present time, McMeekin said. At Tamarack, the reservoir depth is about 100 metres, according to McMeekin. Ivanhoe estimates that the regulatory uncertainty affects up to one million barrels per day of future shallow SAGD projects, representing a significant percentage of the overall forecasted oilsands production growth. The AER has not indicated how much production might be affected, Darin Barter, a spokesman, said in an email. The AER has said that four other projects in addition to Ivanhoe’s Tamarack will be affected by the review: Southern Pacific Resource Corp.’s STP-McKay thermal project, Phase 2; Value Creation Inc.’s Advanced TriStar; Grizzly Oil Sands ULC’s Thickwood; and SilverWillow Energy Corporation’s Audet. Ivanhoe is working with the other affected resource owners and the AER to support the early issuance of a longterm policy for shallow SAGD projects, McMeekin said. In the meantime, Ivanhoe will concentrate on commercializing its patented and proprietary heavy-to-light partial upgrading technology, she said. In Ecuador, its other core area, the company hopes to obtain government approval in the next few months for a financial partner it is bringing in to develop Block 20. “We also are looking at other technologies we might be able to use at Tamarack in the interim.” Looking ahead, the company will rightsize the organization, establish key partnerships, create greater financial strength and commercialize heavy-to-light technology.

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CENTRAL ALBERTA WELL ACTIVITY MAR/13

MAR/14

Wells licensed



155

MAR/13

MAR/14

Wells spudded



187

MAR/13

MAR/14



216

Rigs released

Source: Daily Oil Bulletin

C.A.B. Central Alberta

Central Alberta plays drive Vermilion Energy production record By Paul Wells

Photo: Joey Podlubny

Helped by strong performance from its Cardium and Mannville resource plays in Alberta, Vermilion Energy Inc. achieved record production of 41,005 barrels of oil equivalent per day during 2013, an increase of eight per cent as compared to 37,803 barrels per day a year earlier. Approximately 75 per cent of the yearover-year production growth was achieved organically through continued development of the Cardium and Mannville plays, and successful conventional drilling programs in France and Australia. “We remained focused on the continued development of our successful Cardium light oil play, growing related production to more than 9,300 barrels per day in Q4,” chief executive officer Lorenzo Donadeo told the company’s 2013 year-end conference call. “We have considerable inventory to progress the play toward targeted production levels of 12,000–14,000 barrels equivalent per day over the next few years.”

Cardium well performance remains predictable, reflective of the high-quality, consistent nature of the reservoir underlying the company’s land position in the West Pembina region. Since entering the play in 2009, Vermilion has brought a total of 223 (158.9 net) Cardium wells online. This year, the company expects to drill 30 net wells into the play. Entering 2014, the company has an inventory of nearly 200 net economic one-mile-equivalent wells remaining to be drilled. Donadeo said that Vermilion continues to review a significant inventory of more than 120 additional locations that may become economic as the company expands the use of extended-reach horizontal wells (greater than one mile in length) and further optimizes completion technology and well design. “We have also initiated a water injection pilot to test applicability of waterflooding to this reservoir as a means to

Successful drilling in the Cardium and Mannville liquids plays allowed Vermilion Energy to achieve record production of over 41,000 barrels per day in 2013.

increase potential recoveries. During 2014, we anticipate drilling more than 30 net Cardium wells,” Donadeo said. In addition to the Cardium, the company has also begun development of its significant inventory of Mannville condensate-rich natural gas wells in the West Pembina area. In 2013, Vermilion drilled a total of six (3.7 net) condensate-rich gas wells. Drilling results to date have exceeded the company’s initial expectations with respect to both gas production rates and associated liquids yields. This has resulted in robust economics and anticipated rates of return in excess of 100 per cent. Results from 2013 drilling activities, and those of other operators, demonstrated the strong economics and prospects of the Mannville play. In 2014, the company plans to drill eight (5.7 net) Mannville wells, and Vermilion expects drilling activity to increase in future years as it continues to develop the play and expand its inventory of economic prospects. Donadeo said that Vermilion is also appraising its position in the Duvernay condensate-rich resource play, where the company has amassed 317 net sections at the relatively low cost of approximately $76 million ($375 per acre). “Our position comprises three largely contiguous blocks in the Edson, Drayton Valley and Niton areas. To date, we have drilled three vertical stratigraphic test wells, and are currently drilling our fi rst horizontal well,” he said. “The first horizontal test is in the downdip part of our Edson block, where condensate yields are expected to be lower than the average in our overall land position. We selected this location because of its proximity to one of our vertical stratigraphic test wells, allowing us to conduct microseismic monitoring while we frac the horizontal well after breakup.” The company anticipates that the horizontal well production results and fracture O I L & G A S I N Q U I R E R • M AY 20 14

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Central Alberta

geometries from the microseismic data will assist it in optimizing completions on future horizontal wells. “We are confident we will be able to project the results to higher-condensate-yield drilling locations as we move to the northeast in our acreage position, which encompasses the entire breadth of the condensate-rich window,” Donadeo said. “Our Duvernay rights generally underlie our Cardium oil and Mannville condensate-rich gas rights, which creates the potential for infrastructure, operational and timing advantages if we progress to full development of the Duvernay resource play.”

Shell positive on Duvernay, reviewing other resource plays

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Royal Dutch Shell plc says it’s had positive early results in the Duvernay shale play in Alberta, where it holds roughly 360,000 net acres. The Anglo-Dutch company’s acreage is located in the Kaybob and Pembina areas. It has over 1,100 potential drilling locations “on what we’ve already de-risked in the Kaybob area,” said Marvin Odum, upstream Americas director, during an investor day presentation. “Shell’s equity in this area is about 95 per cent,” he added. “We’re doing well here with 38 wells drilled in 2013, and we recently achieved over 10,000 barrels equivalent of production for Shell.” Upstream Americas profitability has been impacted by losses in resource plays such as shales, the company said. Shell is shrinking this portfolio and cost base, with 2014 spending to be reduced by 20 per cent compared to 2013, and redirecting onshore investment

10,000

barrels of oil equivalent per day Shell’s current Duvernay production

to the lowest-cost-gas acreage with the “best integration potential,” and into ongoing exploration in liquids-rich shales. At the same time, profitable growth should continue in deepwater and heavy oil, where an industry-leading development program is underway, the company said. “Shell is active in a number of LRS [liquids-rich shale] plays in North America,” Odum said. “In addition, we’re selling our Eagle Ford, Mississippi Lime and Rockies LRS positions. Drilling results there were mixed, and this acreage doesn’t have enough materiality for a company of our size.


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Shell has identified 1,100 Duvernay drilling locations.

“This was the main factor behind the $2-billion after-tax impairment charge that we took in the second quarter of 2013. We’re talking to several potential buyers for those assets.” Company-wide, the $35-billion organic investment program for 2014 and the $15-billion divestment targets for 2014-15 announced earlier this year reflect “an ongoing commitment to grow the company and at the same time increase divestments to more typical levels, after a slowdown in 2013.” Asset sales announced so far in 2014 total some $4.5 billion. Project start-ups from 2010 onward added $9 billion (over 20 per cent) to Shell’s 2013 cash flow, “with more growth to come from Shell’s industry-leading project flow.” Shell is conducting a major review of its resource play portfolio in the Americas. A presentation slide listed Kaybob, Pembina and Groundbirch in the “grow” category, while Deep Basin and Foothills were in the “fi x-or-divest” category. “There are some major decisions ahead of us, particularly on the dry gas side,” Odum said. “This may lead to further divestments and, potentially, more impairments. “At the same time, we’re continuing to work on the cost structure. This includes reducing the overall size of the organization around these assets while we’re cutting back on the portfolio and reducing our growth aspirations,” he added. “We’re continuing to work on drilling costs and supply chain costs.” Shell owns 40 per cent of the LNG Canada project and is its operator, with Korea Gas Corporation, Mitsubishi Corporation and PetroChina Company Limited as partners. “We hope to go into FEED [front-end engineering and design] there later this year, with FID [final investment decision] around the middle of this decade, followed by four to five years of construction and then LNG [liquefied natural gas] shortly after that,” Odum said. — DAILY OIL BULLETIN

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SOUTHERN ALBERTA WELL ACTIVITY MAR/13

MAR/14

Wells licensed



36

MAR/13

MAR/14

Wells spudded



28

MAR/13

MAR/14



40

Rigs released

S.A.B.

Southern Alberta

Source: Daily Oil Bulletin

Production up at LGX

Photo: Aaron Parker

LGX Oil + Gas Inc.’s 2013 production averaged 898 barrels of oil equivalent per day, a 209 per cent increase from 291 barrels per day during 2012. Crude oil and natural gas liquids production was 619 barrels per day for the year ended Dec. 31, 2013, compared to 146 barrels per day in 2012. The increase in average production was mainly due to the reverse acquisition of Bowood Energy Inc.’s southern Alberta assets in the third quarter of 2012 by Legacy Oil + Gas Inc., as well as the acquisition of the Manyberries properties in southeastern Alberta in the fourth quarter of 2012. Fourth-quarter output averaged 965 barrels per day compared to 685 barrels per day for the comparable 2012 period. A net loss of $20.33 million was recognized in 2013 compared to net income of $3.42 million during 2012. The loss was primarily due to exploration and evaluation

LGX drilled two successful wells into the Alberta Bakken play targeting the Big Valley in 2013.

expenses offset by increased operating netback on increased production volumes, the LGX reverse acquisition gain recognized in 2012, and increased share-based payments. As well, higher general and administrative expenses and finance costs in 2013 compared to 2012—due primarily to higher production volumes—also contributed to the net loss. The company drilled two (two net) Big Valley oil wells with a 100 per cent success rate in 2013. LGX expects to spend $13.4 million in 2014 focused on light oil development with the majority of capital (90 per cent) directed to drilling, completions and tieins on the Alberta Bakken play. The capital spending is distributed as follows: drilling, completions and tie-ins, $11.2 million; recompletions and workovers, $1.9 million; and other, $300,000. The company is planning to drill two (1.6 net) development wells in 2014, targeting high-quality light oil in the Alberta Bakken play. No capital has been budgeted for acquisitions, although the company continues to evaluate new opportunities, both within and beyond its core areas. LGX anticipates a 2014 average production rate of 1,100 barrels per day and exit rate of 1,400 barrels per day. Following the success of the 14-02 well (530 barrels per day of light oil for the fi rst 30 days of production) in the Alberta Bakken play, LGX has identified numerous locations on its 95-square-mile 3-D seismic program, centred over its lands on the Blood First Nation reserve. LGX has budgeted to drill two development wells, which are expected to spud in the second and third quarters of 2014, along with performing recompletions on the Blood First Nation reserve based on the 2013 drilling success.

Analysis of the 3-D seismic has indicated an area of potentially highly fractured reservoir adjacent to a vertical well drilled in 2012. The company is evaluating this area further for potential re-entry to drill a horizontal leg that would open up another development area on the Blood First Nation reserve. — DAILY OIL BULLETIN

Drillbit success boosts DeeThree reserves DeeThree Exploration Ltd. increased its proved-plus-probable reserves at year-end 2013 by 95 per cent to 39.41 million barrels of oil equivalent (77 per cent oil and natural gas liquids [NGLs]) as compared to 2012. Total proved reserves increased 83 per cent to 26.28 million barrels of oil equivalent (75 per cent oil and NGLs) as at yearend 2013 from 14.36 million barrels (78 per cent oil and NGLs) at Dec. 31, 2012. Predominately all 2013 reserve additions were added through the drillbit or as a result of technical revisions with only $12 million spent in 2013 on acquisitions comprised mainly of undeveloped land in the company’s core areas. DeeThree also spent approximately $10 million at Crown land sales throughout 2013. The company’s reserve additions were predominately a result of the successful 2013 drilling program in its two core properties—the Belly River property in the Brazeau area of west-central Alberta and the Alberta Bakken property located in the Lethbridge area of southern Alberta. O I L & G A S I N Q U I R E R • M AY 20 14

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Southern Alberta

“The reserve additions demonstrate the high quality of the Belly River and the Alberta Bakken properties and represent a successful return on the company’s rapid pace of development,” DeeThree said in a press release. DeeThree recorded impressive reserve gains in each of its core properties as a result of its 2013 delineation program. The proved-plus-probable reserves of the Belly River property increased 147 per cent to 18.8 million barrels of oil

equivalent in 2013 from 7.6 million barrels in 2012. The Belly River reserves include 40 proved undeveloped locations that have been assigned to the property at year-end as compared to the 28 horizontal locations that DeeThree plans to drill in 2014 (1.4 times budget). Similarly, the proved-plus-probable reserves of the Alberta Bakken property increased 80 per cent to 19.2 million barrels of oil equivalent in 2013 from 10.7 million barrels in 2012.

The Alberta Bakken reserves include 32 proved undeveloped locations that have been assigned to the property at year-end as compared to the 18 horizontal locations that DeeThree plans to drill in 2014 (1.8 times budget). Based on resource studies completed on the Belly River property and the Alberta Bakken property, DeeThree said it expects this trend to continue into the future as the company further drills and delineates its two core properties. — DAILY OIL BULLETIN

Goldenkey hits pause on Lethbridge drilling project By Carter Haydu

Goldenkey Oil Inc. has paused plans to drill oil wells within Lethbridge, Alta., city limits, as the Calgary-based company is delaying its Penny project regulatory submissions in anticipation of an update from the provincial government regarding its urban drilling policy. “We sort of decided to wait and see a little bit,” David Hill, an independent

consultant working with Goldenkey, said. “We understand soon there is going to be some policy announcement or recommendations coming forward from the provincial government regarding oil and gas development within urban boundaries, and we thought, ‘Let’s adjust our application in case there is anything that comes up there

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M AY 20 14 • O I L & G A S I N Q U I R E R


Southern Alberta

seismic data of the Lethbridge site about three years ago that showed potential oil in the Big Valley Formation, which led the company to lease Crown land and forge a plan for development. The company went through the process of site selection and geological analysis and selected three wells—two directional and one vertical—with a typical one-stage frac to complete the wells. However, city council voted unanimously to oppose the project, and the community group No Drilling Lethbridge recently handed more than 11,000 signatures from residents opposed to oil and gas exploration within their municipality to the Alberta legislature. Lethbridge Mayor Chris Spearman said that just because Goldenkey has postponed its application does not mean the city is going to cease its worries over the proposed drilling project. “We’re still concerned that they are going to proceed at some point, and we are very concerned about the location,” he said, adding the city worries about what an urban drilling project in a portion of Lethbridge that is poised for growth could mean in terms of municipal planning. “There are three exploratory wells, but they are very close to existing residential developments—our newest developments. We’re spending $40 million on an ice complex that is two ice rinks and a curling centre. We’re spending $55 million on an aquatic centre, and we are thinking of expanding that into a leisure centre. We have a $35-million mixed-commercial development. This is the fastest-growing area of Lethbridge on the west side of the river, and the exploratory wells are in the path of the next phase of residential development.” Lethbridge-West MLA Greg Weadick, who opposes drilling within his city’s limits, was recently appointed to a task force that will work with Alberta Energy Minister Diana McQueen on devising recommendations for government pertaining to urban drilling in Alberta. “We have some planning underway to review the policy regulations we have in place right now, and to look at those and see if they are adequate in terms of urban drilling,” McQueen said. “We will look at those, work with stakeholders and, certainly, municipalities, as well as the regulator and others to have a discussion as to whether these are adequate policies with regards to safe developments because that is usually the issue.” According to McQueen, the province would also look at how it can ensure stakeholders throughout Alberta are aware of the current measures placed on the industry to ensure safety within urban areas. If the province decides that there cannot be any urban drilling, then Hill said Goldenkey would have to take stock and, because the rules changed mid-stream, probably approach the Crown for other options. “I’m not sure exactly what our path would be from whatever comes out of that, but we would have to consider anything and everything that they could announce.” Goldenkey sees the Penny project as positive from the perspective of recovering resources, Hill said, as, based on geology and information the company has collected, it believes the project will tap a potential oil reservoir worthy of pursuit. “They would rather the geology said it was outside the city, but unfortunately it doesn’t, and what we’re planning on is recovering from where we think there is the greatest chance of success.” Hill said Goldenkey continues to want to talk with the city and anyone else in Lethbridge who has concerns. He said the company has been processing statements of concerns regarding the project, and delaying the Alberta Energy Regulator application allows for a “wholesome response.”

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SASKATCHEWAN WELL ACTIVITY MAR/13

MAR/14

Wells licensed



342

MAR/13

MAR/14

Wells spudded



176

MAR/13

MAR/14



262

Rigs released

Source: Daily Oil Bulletin

S.K. Saskatchewan

Gear Energy sets production record

Photo: Joey Podlubny

Gear Energy Ltd. achieved record production for the fourth quarter of 2013 by averaging 4,642 barrels of oil equivalent per day. Annual production for 2013 was 4,079 barrels per day. Gear executed an active drilling program in 2013, with a total of 47 (42 net) wells drilled at a 98 per cent success rate, including drilling into three new formations: Maidstone Cummings, Wildmere Cummings and Vermilion Sparky. The company said that all of these new plays have been proven successful and have added material undeveloped inventory. Gear will focus on testing several new low-risk plays in 2014 to further build future inventory. Four horizontal wells were drilled in Gear’s new core area in Maidstone Cummings during the fourth quarter, completing a nine-well program executed throughout 2013. All nine wells were on production at year-end and were contributing approximately 700 barrels per day, compared to no production from this area in 2012.

Gear said that the results from these wells strongly support further development in the area, and, as such, approximately 12 horizontal and up to four vertical wells are currently planned in 2014. Two horizontal wells were drilled in Gear’s second new core area in Wildmere Cummings, with initial average 30-day rates of 90 barrels per day. As a result of improved completion techniques, these rates are 30 per cent higher than the two Wildmere Cummings wells completed earlier in the year. This new core area makes up 65 potential wells out of total company drilling inventory of 230 locations. Gear’s current 2014 capital plan includes drilling approximately seven horizontal wells into this area. With the bullish outlook on heavy oil pricing, Gear has decided to accelerate its 2014 capital program by adding a third drilling rig in the first quarter. This more aggressive drilling schedule has resulted in a shift in the company’s production profi le for 2014. As with prior

Gear Energy drilled 42 net wells in 2013, with production reaching 5,000 barrels per day at year-end.

years, production volumes in the first quarter are forecast to be lower than the previous quarter as a result of the drilling operations. Current production is approximately 4,500 barrels per day, 500 barrels per day lower than the company’s December exit rate. The temporary decline in production is a direct result of drilling multi-well pad sites that take longer to initially produce (but provide both increased capital and operating efficiency), shut-in of several high-producing wells to accommodate adjacent drilling, railing interruptions and extreme winter weather. Gear said it is anticipating material advances on its enhanced oil recovery programs in 2014. The two pilot projects in the Wildmere Lloydminster pool continue successfully, with no early breakthrough and backpressure increasing on the injectors for both the waterflood and polymer pilot project. The simulation model and field results to date indicate a defi nitive response is to be expected very early in 2014. Within the Maidstone Cummings pool, an off set operator has recently seen significant early response from water injection into section 23-047-23W3. These results are encouraging and add confidence to Gear’s plans for potential waterflood implementation in both the Maidstone Cummings and Wildmere Cummings plays. T he compa ny hopes to a n nounce its plans later in 2014, with $5 million c u r rent ly budgeted for i n it ia l commercialization. Gear noted that it is benefiting approximately $4 per barrel by selling its production via rail. At times, the company has to inventory some of its oil production based on available sales transportation. During the first quarter, rail transportation has been constrained due to both weather and rail network disruptions. As a O I L & G A S I N Q U I R E R • M AY 20 14

33


Saskatchewan

result, Gear has been building oil inventory levels during this quarter. As the weather begins to improve, the company expects the constraints on shipping oil by rail to diminish, facilitating increased sales production and reducing inventories to normal levels.

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M AY 20 14 • O I L & G A S I N Q U I R E R

— DAILY OIL BULLETIN

Crescent Point’s waterfloods get first reserve recognition By Paul Wells

For the first time, “improved recovery” reserves have been independently recognized in the early stages of Crescent Point Energy Corp.’s Viewfield Bakken waterflood program. “The highlight is that we received technical reserve revision in the core of the Viewfield Bakken play attributable to the waterfloods for the first time, which I think is significant,” president and chief executive officer Scott Saxberg told the company’s 2013 year-end conference call. “In addition, we had a large technical revision due to results from the latest generation of cemented liner completion technology. This independent assessment speaks to the success we’ve seen in the waterflooding and cemented liners,” he added. “In the future, we expect to see similar reserve increases in the Shaunavon and in our other core plays as we continue to refine our technologies and implement them.” The company’s independent reserve evaluators, Sproule Associates Limited, assigned the company’s waterflood patterns in the play an incremental three per cent recovery factor from the previous primary recoverable reserve levels, which equates to a 16 per cent increase in estimated ultimate recoveries. This is consistent with the independent engineering firm’s study earlier in the year that found ultimate long-term recovery factors of up to 30 per cent are achievable in these areas. Overall, Crescent Point increased provedplus-probable reserves by nine per cent to 663.76 million barrels of oil equivalent


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at year-end 2013, weighted 91 per cent to light and medium crude oil and liquids, while proved reserves increased by eight per cent to 432.77 million barrels. This represents annual reser ves per share growth of four per cent for proved-plusprobable reserves and three per cent for proved reserves. “We are very pleased with our waterflood programs and cemented liner completions, which continue to drive costs down, reduce the amount of water we use, lower initial decline rates, lower overall corporate decline rates and increase recoveries,” said chief operating officer Neil Smith. “I’d really like to emphasize the significance of having qualified, independent engineers recognize our waterflood reserves for the very fi rst time. This is evidence that our waterfloods work without question.” In the Viewfield Bakken inner core area, estimated ultimate recoveries assigned by the company’s independent reserve evaluators increased by approximately 25 per cent per well on average due to the application of current cemented liner technology, which provides more efficient fracture stimulation results, more controlled access to the reservoir and lower decline rates. In general, these estimated ultimate recovery increases have raised the value of the Bakken inner core area by approximately 35 per cent. In 2013, Crescent Point added 93.6 million barrels of oil equivalent of provedplu s - p r o b a bl e r e s e r v e s , e xc lu d i n g reserves added through acquisitions. This includes approximately 83 million barrels in its core Bakken/Torquay, Shaunavon and Uinta Basin resource plays, and represents the 12th consecutive year of strong positive technical and development reserves additions.

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O I L & G A S I N Q U I R E R • M AY 20 14

35


Saskatchewan

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Spartan Energy Corp. has completed the business combination with Renegade Petroleum Ltd. and outlined its capital spending plans for the year. On March 31, the arrangement was approved at the special meeting of Renegade shareholders by 97.11 per cent of the votes cast. The arrangement was also approved by the Alberta Court of Queen’s Bench on the same day. Spartan’s business plan is to focus on light oil opportunities in western Canada, employing a targeted acquisition and consolidation strategy, complemented by development and exploration drilling. The company’s goal is to assemble a high-quality asset base that exhibits strong cash flow netbacks, attractive capital efficiencies and manageable corporate declines. In 2014, Spartan’s focus will be on spending within cash flow to deliver production per share growth of between 15 and 20 per cent, while maintaining a corporate decline rate below 30 per cent. The company will also work to optimize operations following the acquisition of Renegade. The company has identified numerous opportunities to reduce operating and administrative expenses, which will translate into improved netbacks and cash flow. It will also continue to target acquisitions that increase production and cash flow per share while expanding the asset portfolio. The board of directors has approved a $74-million capital program for 2014, which will be funded entirely through internally generated cash flow. The budget will be reviewed and potentially revised on a quarterly basis, depending on results and commodity prices. The company expects to spend a total of $66 million in 2014 to drill 58 (53 net) wells. The remaining $8 million will be spent on land, seismic and maintenance expenditures. During the first quarter of 2014, the company drilled three (2.67 net) Detrital oil wells in central Alberta on the company’s Alexander property. The focus of Spartan’s remaining 2014 capital program will be on the company’s Mississippian assets in southeastern Saskatchewan and, to a lesser extent, on the Viking prospects in the Dodsland area of west-central Saskatchewan. Spartan expects to drill up to 44 (40 net) horizontal wells in southeastern Saskatchewan targeting the Frobisher and Midale formations. For budgeting purposes, Spartan is using a first-month average production rate of 60 barrels per day for the Frobisher and a first-month average production rate of 96 barrels per day for the Midale. In the Viking, the company expects to drill 11 (10.5 net) horizontal wells. The budget does not include any capital spent by Renegade prior to the eff ective date of the arrangement, as this amount is included in the company’s estimate of net debt. During the fi rst quarter of 2014, Renegade executed on a capital budget of approximately $20 million, drilling six (5.3 net) horizontal wells in southeastern Saskatchewan and 10 (9.5 net) Viking horizontal wells in west-central Saskatchewan. Renegade’s cash flow for the fi rst quarter is estimated to be approximately $20 million. Spartan expects its 2014 budget to yield full-year average production of 5,100 barrels of oil equivalent per day (93 per cent oil and liquids) and exit production of 7,300 barrels per day (94 per cent oil and liquids). — DAILY OIL BULLETIN

36

M AY 20 14 • O I L & G A S I N Q U I R E R


Saskatchewan

Bakken target of latest land sale By Richard Macedo

A swath of exploration licences in the area around 004-27W2 and 004-30W2 that combined for $26.81 million helped to power Saskatchewan’s April sale, which produced $47.94 million in revenue. After just two sales so far in 2014, the province has already eclipsed the $67.37 million collected for all of 2013. The industry acquired 72,819 hectares this week at an average of $658.30 per hectare. Year-to date, the province has attracted $98.62 million in bonus bids on 100,727 hectares at an average price of $979.13. Of particular interest in this sale was a cluster of exploration licences between Assiniboia and Rockglen. Drilling in the early 1950s proved the presence of Bakken oil in the area, but the technology did not exist to develop the resource, the government noted.

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“ With interest in [the Bakken] rekindled after 50 years, we are hopeful that the technological advances can be applied to produce significant amounts of oil.” — Tim McMillan, energy and resources minister, Government of Saskatchewan

“With interest in this area rekindled after 50 years, we are hopeful that the technological advances made in the interim can be applied to produce significant amounts of oil,” Energy and Resources Minister Tim McMillan said. “Industry has again voted with their pocketbooks that Saskatchewan is a great place to invest and drill for oil.” While the western edge of the Viewfield Bakken sand pool is 160 kilometres east of the exploration licences that sold south of Assiniboia, there is a smattering of successful Bakken wells between Viewfield and the Roncott area, just a few miles east of the exploration licences that sold, noted Paul Mahnic, director of the Petroleum Tenure Branch in Saskatchewan. “Regarding the zone of interest for these exploration licences, it is reasonable to expect that the Bakken is the main zone of interest, but there is the potential for shallower Mississippian plays in the area as well as the deeper Red River, and multiple targets always help when determining the economics of drilling a well,” he said.

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O I L & G A S I N Q U I R E R • M AY 20 14

37


Cover Feature

Enhanced recovery gains ground in tight oil, heavy oil and conventional plays

Call it the “great flood of 2014.” Across the Western Canadian Sedimentary Basin, producing wells are being converted to water injectors as operators develop waterflood schemes to stem declines and increase ultimate recovery in tight oil plays. In conventional and heavy oil plays, operators are pumping polymers, hydrocarbons and other chemicals downhole to improve recoveries and to benefit from higher oil prices. And in labs across the Prairies, scientists are working on a variety of new methods using everything from microbes to radio frequencies to free trapped oil. At stake are tens of billions of barrels of oil left behind when primary production is exhausted. Waterfloods the future of tight oil Waterfloods are nothing new in western

38

M AY 20 14 • O I L & G A S I N Q U I R E R

Canada. At last count, there were almost 1,000 such schemes operating in Alberta, with more than 200 schemes active in Saskatchewan. What is new is the application of waterfloods in tight oil plays where horizontal wells with multistage fracturing have been used on primary production. Peters & Co. Limited analysts outlined waterflooding’s value in tight oil plays in a 17-page Waterflood Primer published last fall. The analysts said a successful flood could increase recovery to between 30 and 45 per cent of the original oil in place, up from between fi ve and 15 per cent on primary production. Peters & Co. said the average increase in oil recovery from waterflooding is about 30 per cent. And adding those reserves comes on the cheap, Peters & Co. said. Average costs come in at $5–$10 per barrel, as most wells and surface facilities are already in

place in existing fields. All that is usually needed are injection, pumping and treatment facilities. In tight oil plays with billions of barrels of oil in place, waterflood recoveries could amount to hundreds of millions of barrels, something not lost on Crescent Point Energy Corp. “We now have waterflood programs or pilots in all of our plays,” Crescent Point chief operating officer Neil Smith told analysts late last year. “Based on their ongoing success, we have plans to expand our program in the Viewfield Bakken resource play to apply for a first waterflood in the Manitoba Bakken play, and to apply for a second unit, which would be adjacent to our first in the Lower Shaunavon. We continue to monitor results from our first shared waterflood in the Beaverhill Lake light oil resource play and expect to begin injecting

Photo: Logray-2008/Thinkstock

By Darrell Stonehouse


Cover Feature

water in the second Crescent Point pilot during the first half of 2014.” In the Bakken, Crescent Point has completed two studies looking at potential recoveries through waterfloods, with both indicating a recovery factor of 30 per cent. “I think to put it into scale, when we say over 30 per cent recovery, we’re talking hundreds of millions of barrels of incremental reserve outs with very minimal capital cost associated with that,” says Crescent Point president and chief executive officer Scott Saxberg. Smith, however, cautioned that reserve evaluator recognition of this increase in recovery factor won’t happen overnight. Instead, as the company drills more wells, adds more injectors and gets more production history on its floods, reserve evaluators will recognize the increased recovery. He expects it will go up a few percentage points each year. “You’re not going to see us go from 19 per cent [primary recovery] to 30 per cent in one year,” he explained. Penn West Petroleum Ltd. currently operates around 135 active waterflood schemes. Its current focus is on the tight area of the Cardium play, where it is testing the waterflood response in horizontal wells. In the final quarter of 2013, the company began flooding on a pilot project on an eight-well pad at Willesden Green, with four horizontal injection wells supporting four horizontal producers. A second Cardium waterflood pilot in the Willesden Green area was constructed in the fourth quarter and commenced water injection in January 2014. In addition, Penn West commenced construction of a waterflood project in its Medicine River glauconite play designed to support horizontal production wells with the conversion of legacy vertical producing wells to water injection wells, and was scheduled to commence injection in the first quarter of 2014. Penn West also has two pilot projects underway in the Slave Point carbonate. In the Viking play, Penn West received approval for the conversion of 11 horizontal

producing wells to water injection wells at Avon Hills. This represents the first of three phases of waterflood implementation planned for the Avon Hills field over 2014 and 2015. Facility and pipeline construction for Phase 1 is planned for the third quarter of 2014, with injection expected to commence in late 2014. Phases 2 and 3 are scheduled for 2015. Beaumont Energy Inc. has implemented a large waterflood with 38 water-injection wells and four horizontal producers over five sections of land in the Viking play at Kerrobert. Its Kerrobert asset, purchased in 2012, includes about 1,000 vertical wells and associated facilities. While some might see 1,000 vertical wells as an abandonment liability, Beaumont president and chief executive officer Robert Chaisson and his team saw opportunity. The plan from the outset was to do a waterflood. So with 1,000 vertical wells already perforated and fracture stimulated in the Viking, Beaumont won’t have to drill any water injectors for a long time. The other big attraction for privately held Beaumont was that a waterflood with 80 vertical wells had operated on 3.5 sections of the property from roughly 1986 to 1999, when water injection ended and the area reverted back to primary production. “So we got 27 years of data to look at to see how that waterflood performed in there. And when we looked at that, we knew right away that the waterflood had worked,” said Chaisson. The Viking at Dodsland, just south of Kerrobert, has been waterflooded for nearly half a century. “So that was why we bought the Kerrobert property— because we knew you could waterflood it.” Currently Beaumont is converting eight wells per section to water injection, but it can do more if necessary. Chaisson said there are at least 16 vertical wells on nearly every section, and some sections have about 30. Beaumont drills a horizontal producer down the middle of the injection lines on each section. The company has already drilled four horizontal producers in the old

waterflood area, which it expanded to five sections from the original 3.5 sections. The company is monitoring the performance of these wells. The goal is to waterflood another eight sections in 2014, and then do between eight and 10 sections per year. Currently the plan is to start injecting water a year before the horizontal producers are drilled, giving the reservoir time to re-pressurize.

Alberta conventional oil pools with EOR potential EOR type Waterflood

Number of pools 4,500

Vertical solvent flood

200

Horizontal solvent flood

734

Combined solvent flood

382

Sandstone solvent flood

1,701

ASP flood

1,396

Polymer flood

935

Cyclic steam flood

196

Steam flood

214

SAGD

196

In situ combustion

1,434

Source: Alberta Energy Regulator

Given that Beaumont has more than 70 sections at Kerrobert, this project will keep the company busy for a long time. Chaisson said it costs $1 million per section to convert eight vertical wells to water injection and to install new water injection pipelines. It costs about $900,000 to drill, complete and equip the horizontal wells. The big prize is in boosting ultimate recoveries. The recovery factor on primary production is only about five per cent, but Beaumont believes waterflooding can raise

O I L & G A S I N Q U I R E R • M AY 20 14

39


Cover Feature

it to about 20 per cent, based on the performance of nearby Viking pools that have been waterflooded for decades. With original oil in place of 600 million barrels, a 20 per cent recovery factor equates to 120 million barrels of light sweet crude, of which only 20 million have been produced. Chaisson says, “We’ve got 100 million barrels left to get out of this thing.”

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M AY 20 14 • O I L & G A S I N Q U I R E R

Solvents, polymers driving conventional EOR Solvent- and polymer-based floods could increase Alberta conventional oil recovery by as much as two billion barrels, more than doubling current reserves, according to a study by the Energy Resources Conservation Board, now the Alberta Energy Regulator, released in the spring of 2013. Titled Identification of Enhanced Oil Recovery Potential in Alberta, the study was done by Calgary-based engineering firm Sproule Associates Limited, with Chris Galas, a partner at Sproule and manager of reservoir studies, acting as lead. Galas presented the results of the study at GeoConvention 2013 last May. The study screened 11,000 oil pools in Alberta and identified 3,000 pools that have solvent-flood potential and 1,400 pools with alkaline surfactant polymer or polymer potential. It estimates solvent flooding or miscible flooding—the terms are used synonymously— could increase oil recovery by between 546 million barrels and 1.8 billion barrels. And the report estimates chemical flooding—polymer and alkaline surfactant polymer f looding— could increase oil recovery by between 294 million and 634 million barrels more than could be produced by conventional waterflooding. So the total additional oil that could be recovered by both processes in Alberta is estimated at between 840 million and roughly 2.4 billion barrels. The two enhanced oil recovery processes examined in detail were miscible flooding and chemical flooding. Miscible floods inject a solvent such as an enriched gas or CO2 into the reservoir. The gas goes into solution with the oil, causing it to swell, so more oil is displaced from the pore spaces. The solvent also increases reservoir pressure and reduces viscosity— all of which increase oil recovery. Chemical flooding refers to waterfloods where the sweep efficiency is enhanced by adding a polymer, or thickening agent, to injected water, so the viscosity of the


Cover Feature

injected fluid more closely matches the viscosity of the heavy oil in the reservoir. Alkali and surfactant may also be used with the polymer. Surfactant reduces the interfacial tension between the oil and water. In plain language, it is a detergent that washes the oil off the rock. However, surfactants are relatively expensive. The study estimates the amount of oil that could be recovered by each process, but doesn’t assess the economics. “There’s a certain benefit to that because prices vary so much. Trying to put economics in at any particular time means that your results are limited to that time frame,” Galas says. Canadian Natural Resources Limited operates around 100 waterfloods in western Canada. It is now advancing polymer flooding as a means to capture even more incremental oil. The company has seven years’ experience operating a polymer flood at Pelican Lake and is now using that experience to add value to other heavy oil fields. “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 underway with waterf looding progress being made at Lone Rock, South Epping and Salt Lake,” said Scott Stauth, Canadian Natural’s senior vice-president of North American operations, in a presentation last summer. He was referring to three properties in the greater Lloydminster area of Saskatchewan. At South West Epping, the company also recently sanctioned as a polymer-flood pilot, according to a slide in Stauth’s presentation. “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. 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 and another in light oil, according to a presentation by Lyle Stevens, executive vicepresident of Canadian conventional. The pilot in medium-gravity crude will be an alkaline surfactant polymer flood at Grand Forks in southern Alberta. The pilot in light crude will test a technology called nanosphere polymer in a mature reservoir at Nipisi in north-central Alberta. All three were expected to be operational in late 2013 or early 2014, said Stevens.

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Cover Feature

“The success of the polymer flood is very obvious.” — Lyle Stevens, executive vice-president, Canadian conventional, Canadian Natural Resources Limited

Stevens said Canadian Natural’s incremental capital cost of polymer flooding at Pelican Lake 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 watertreating 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. “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 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.” The next wave in EOR While Canadian Natural develops its polymer-flooding expertise, Innovation

Saskatchewan is looking for the next wave of enhanced recovery technology. Its board of directors recently approved $1.9 million in funding to develop new enhanced oil recovery technology for heavy oil fields. One of the projects will investigate the use of radio frequency heating. It works by volumetrically exciting bipolar molecules and instantaneously heating a volume. This technology holds promise for reservoir heating due to both its instantaneous properties and its ability to reach out many metres. A second project will look at microbially generated biosurfactants. The project will focus on the stimulation of naturally o c c u r r i n g bio s u r f ac t a nt-pr o duc i n g microbes, and testing of those biosurfactants in heavy oil reservoirs to enhance oil recovery in the Lloydminster area. The project is the fi rst within an iterative prog ram of developing a biosurfactant approach to heavy oil enhanced recovery. This project is ex-pected to isolate and identify biosurfactant-producing microbes indigenous to the reservoir from samples taken from a range of wells in the reservoir, and to conduct trials to optimize nutrient mixtures to maximize indigenous production of surfactants. It will also investigate effectiveness of using surfacegrown biosurfactants and determine the impact of introducing a foreign bacteria or non-indigenously produced biosurfactant into the reservoir. It will also bench test the effectiveness of using biosurfactants in model reservoir conditions and deliver the best surfactants for use in field tests.

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M AY 20 14 • O I L & G A S I N Q U I R E R


FFeeaattuurree

WINDS OF CHANGE Emerging oil plays breathe new life into southern Alberta oilpatch

I

n 2010, it looked like southern Alberta was set for a tight oil drilling boom as explorers scooped up land prospective for the Alberta Bakken Formation. Around $270 million was spent acquiring land in the play, with a number of exploratory wells spuded and anticipation running high. Four years later, after plenty of ups and downs, explorers continue to work to unravel the Alberta Bakken system. And it appears a few have found sweet spots in the play, giving southern operators a base to build on. But the Alberta Bakken is only part of the story in southern Alberta. Work also continues in the Pekisko tight oil play, where waterflood efforts are underway to maximize recovery. And an emerging Mannville oil play is adding to opportunities in the region.

The Alberta Bakken DeeThree Exploration Ltd. has by far enjoyed the greatest success in the Alberta Bakken. DeeThree has 200 gross sections of land in the Bakken fairway and has discovered an oil pool in the play running 14 miles long and four miles wide, covering more than 56 sections of land. The pool, located in the Upper Bakken, is in the Ferguson area near Lethbridge, Alta. As of year-end 2013, the company had drilled 28 horizontal wells in the play and reported production of around 4,000 barrels per day of light oil. Its current type curve for the play puts well costs at $3.5 million, recoverable reserves at 400,000 barrels, payout at a little over a year and a rate of return at 146 per cent, making it one of the more profitable tight oil plays in Alberta. The company reported 2013 year-end proved-plus-probable Bakken reserves of 19.2 million barrels, up 80 per cent from the previous year. It has 32 undeveloped drilling locations on its developed lands and plans on drilling 18 wells this year. In the first quarter, DeeThree drilled two horizontals into the Bakken and one gas injection well. Two rigs will drill seven to eight Alberta Bakken wells in the second quarter. The gas re-injection well was drilled to further expand the company’s ongoing gas re-injection enhanced oil recovery

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M AY 20 14 • O I L & G A S I N Q U I R E R

scheme project. Its fi rst pilot with one injector has continued to exceed its expectations for increasing ultimate recovery in off setting wells, and, as a result, DeeThree has now drilled a total of three gas re-injectors in different areas of its extensive Bakken pool. The company is expecting to increase recovery by as much as 30 per cent using the enhanced oil recovery technique. TORC Oil & Gas Ltd. is also showing some early success in unravelling the mysteries of the Bakken system at its Monarch play, which is comprised of 150 net sections of land. In 2013, TORC focused on exploring its light oil resource at Monarch while modifying drilling and completion techniques to progress toward area development. During the fourth quarter of 2013, TORC drilled two wells, including one exploration well (04-20) and one development well (14-01). For the full year 2013, TORC drilled three exploration wells at Monarch and one development well. Although early in the evaluation process, initial production results from the company’s 04-20 exploration well, which was drilled, completed and tested in the fourth quarter and brought on production in February 2014, have been encouraging. TORC has identified an area in the heart of the Monarch play that will be the focus of the company’s initial development efforts. TORC’s 14-01 well, the first development well into the play, was completed in the first quarter of 2014 and is currently awaiting tie-in. Based on well performance and initial flowback data, Sproule Associates Limited has assigned proved-plus-probable reserves per well ranging from 300,000 to 425,000 barrels (100 per cent light oil) in TORC’s initial development focus area. In addition to completing the 14-01 development well, TORC’s 2014 plans at Monarch include drilling three additional development wells. The initial development project is focused on demonstrating repeatability of results, enhancement of recovery factors and cost reductions to further enhance the economics of the play. The company has identified 77 drilling locations in its current development area. LGX Oil + Gas Inc. is also finding early success on its Bakken acreage. LGX has around 110,000 acres covering the Bakken

Photo: Digital Vision./Thinkstock

By Darrell Stonehouse


Feature

Alberta Bakken horizontal well production Company DeeThree Exploration

Operated wells

Oil (bbls/d)

22

2,693

TORC Oil & Gas

8

584

Connaught Oil & Gas

4

186

Crescent Point

Pekisko  oil wells Direction Operator

Directional

Horizontal

Vertical

Total

Cenovus Energy Inc.

18

11

7

36

Coda Petroleum Inc.

0

2

0

2

Crew Energy Inc.

1

6

2

9

21

2

0

23

17

149

Kainai Energy

2

120

Gryphon Petroleum

3

46

Husky Energy Inc.

2

2

1

5

3

13

Spyglass Resources Corp.

0

2

0

2

59

3,791

West Valley Energy Corp.

0

1

0

1

42

26

10

78

Nexen Energy Total

Note: Estimate of Q3/2013 production Sources: Scotiabank; Daily Oil Bulletin; SEDAR

Encana Corporation

Total

Source: Daily Oil Bulletin

oil system. It drilled two wells into the Big Valley Three Forks Formation during 2013, both in the fourth quarter. The company drilled its 14-02 well, which was fracture stimulated, to a depth of 1,150 metres horizontally from a vertical stratigraphic test. Put on production in late January, the well averaged in excess of 530 barrels per day of light oil for the first 30 days of production. The well currently produces about 470 barrels per day of oil at a 13 per cent water cut and with high fluid levels. LGX has 100 per cent working interest in the well prior to 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’s 10-15 vertical stratigraphic well encountered 13 metres of gross pay in Big Valley, which confirms the company’s 3-D seismic interpretation. Well logs and core samples indicate good porosity and permeability, and the core had good oil saturations and geochemical evaluation showing high total organic carbon and early oil maturation. LGX kicked off and drilled the well to an intermediate casing point in the reservoir for future re-entry to drill a horizontal leg. A similar reservoir was encountered in the build section.

Pekisko/Mannville plays taking off Both the Pekisko and Mannville heavy oil plays are also emerging from obscurity in southern Alberta. Crew Energy Inc. was one of the pioneers of the Pekisko play, with 290,000 net acres in the Princess area of southern Alberta. It is now focused on maintaining production in the Pekisko play, with 11 waterfloods underway. Its exploration focus has turned to the Mannville play. Crew’s Princess production averaged 4,738 barrels per day in the fourth quarter, driven by recent Mannville drilling activity. In 2014, Crew will focus on Mannville development at Princess, with plans to drill 16 horizontal wells targeting both the Sunburst and Detrital formations, as the relative economics of Mannville development are superior to Pekisko development, given the more attractive Crown royalty scheme. In the first quarter, the company drilled six (six net) horizontal wells at Princess targeting the Mannville play.

Crew will continue to optimize performance of the Pekisko waterfloods by converting an additional four wells to water injection. Hemisphere Energy Corporation is also targeting the Mannville and Pekisko plays. Its first horizontal well on its Atlee Buffalo property, drilled in January, targeted the oil-bearing glauconitic sandstones within the Mannville Group. It has been on production for over 30 days at an average pumping rate of approximately 100 barrels of oil per day, with a two per cent water cut and minor associated gas. With the consistent low water cut Hemisphere has been able to tank treat the oil production and truck directly to sales, the company says. The initial production results of the Atlee Buffalo horizontal well are better than expected and very encouraging as Hemisphere continues to finalize additional drilling locations and development plans, it says. A second horizontal well in Atlee Buffalo was planned for March, but due to warm-weather conditions, the well has been rescheduled to be part of a multi-well drilling program after spring breakup. Hemisphere acquired the Atlee Buffalo property in November 2013, with the plan to increase oil recovery from existing pools using horizontal wells and future pressure maintenance. Hemisphere has 100 per cent working interest in nine contiguous sections of land covering two significant glauconitic oil pools, where up to 75 drilling locations have been identified. Cenovus Energy Inc. is the king of southeastern Alberta, with around three million acres of land in the region. In 2013, it drilled around 102 wells in the area, targeting both heavy oil at Suffield and tight plays north of Brooks. It drilled 36 wells targeting the Pekisko in 2013, according to Daily Oil Bulletin records. Cenovus plans to spend between $540 million and $590 million on its conventional oil assets in 2014, a 22 per cent decrease when compared with the previous year, as part of the company’s continued efforts to align capital investment with expected cash flow in 2014.

O I L & G A S I N Q U I R E R • M AY 20 14

45


advertisers' index Allmand Bros Inc . . . . . . . . . . . . . . . . . . . . . . . . . 35

Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 41

Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Annugas Compression Consulting Ltd . . . . . . . . 24

EV Canada Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Phoenix Fence . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Bear Slashing Inc . . . . . . . . . . . .outside back cover

FMC Ford Motor Co Canada . . . . . . . . . . . . . . . . . 8

Platinum Energy Services ULC. . .inside front cover

Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 27

Gibson Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Brother’s Specialized Coating Systems Ltd . . . . 42

Hughson Trucking Inc. . . . . . . . . . . . . . . . . . . . . . 28

Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . 27

Kenwood Electronics Canada Inc . . . . . . . . . . . . . 4

CanElson Drilling Inc . . . . . . . . . . . . . . . . . . . . . . 32

Maxxam Analytics . . . . . . . . . . . . . . . . . . . . . . . . 35

Chase Operator Training . . . . . . . . . . . . . . . . . . . 22

Meridian Manufacturing . . . . . . . . . . . . . . . . . . . 10

Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 26

Dentec Safety Specialists Inc . . . . . . . . . . . . . . . 20

NAIT Corporate and International Training. . . . .40

dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

NCSG Crane & Heavy Haul Services . . . . . . . . . . 19

Dow AgroSciences Canada Inc . . . . . . . . . . . . . . 12

Northgate Industries Ltd. . . . . . . . . . . . . . . . . . . 22

TRTech . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Dragon Products Ltd . . . . . . . . . . . . . . . . . . . . . . .11

Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . 19

Veyance Technologies Inc . . . . . . inside back cover

Eclipse Rentals Inc. . . . . . . . . . . . . . . . . . . . . . . . 36

Pembina Controls Inc. . . . . . . . . . . . . . . . . . . . . . . 6

V J Pamensky Canada Inc. . . . . . . . . . . . . . . . . . . . 7

46

M AY 20 14 • O I L & G A S I N Q U I R E R

Pumps & Pressure Inc . . . . . . . . . . . . . . . . . 23 & 32 RedGuard. . . . . . . . . . . . . . . . . . . . . . . . . . . 14 & 28 RIVEER. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Rush-Overland Manufacturing . . . . . . . . . . . . . . 20 Saskatchewan Research Council (SRC). . . . . . . . 43 Site Energy Services . . . . . . . . . . . . . . . . . . . . . . 23 Tervita . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15


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Oil & Gas Inquirer May 2014