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CONTENTS
NOVEMBER.
www.sprung.com/oilgas
Sprung Structures
in the news
13
Rail terminal projects booming
regional news
21
37
British Columbia
Engineered fabric building solutions
Central Alberta
Project planned to account for
Penn West’s Cardium spending
natural gas liquids in B.C.
to double
27
43
Northwestern Alberta
Southern Alberta
Changes to completions could boost
Industry supports sage-grouse
Duvernay results, conference hears
protection order
33
47
Northeastern Alberta
Saskatchewan
Low gas prices mask inefficiency of
Low-cost waterflood may increase
SAGD process, study suggests
Viking recovery rate
Available immediately from inventory
features Cover Feature
52 Harvest time Southeastern Saskatchewan producers move to exploitation phase in the Bakken
56 Taking a breather After a decade of steady growth, activity in Manitoba’s oilpatch set to plateau in 2013
business intelligence
60
Modularization, combined with rail, making oilsands construction a national business
every issue
10 Stats at a Glance 62 Political Cartoon
1 800 528.9899 403 601.2292
Direct Dial: Cover design: Peter Markiw Photo: ©iStockphoto.com/Kuzma
info@sprung.com CALGARY • ALBERTA
OIL & GAS INQUIRER • NOVEMBER 2013
7
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Make it happen. U.S. owned and operated for over 50 years.
Editor’s Note Vol. 25 No. 9 EDITORIAL EDITOR
Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS
Godfrey Budd, Carter Haydu, Richard Macedo, Pat Roche, Elsie Ross, Paul Wells EDITORIAL ASSISTANCE MANAGER
Political science
Marisa Sawchuk | msawchuk@junewarren-nickles.com EDITORIAL ASSISTANCE
Tracey Comeau, Matthew Stepanic CREATIVE PRINT, PREPRESS & PRODUCTION MANAGER
Michael Gaffney | mgaffney@junewarren-nickles.com
In middle school, kids across Canada learn the
getting a social licence to operate and for the
Tamara Polloway-Webb | tpwebb@junewarren-nickles.com
scientific method. It is a simple six-step process:
public looking for answers to their environ-
CREATIVE LEAD
1. Ask a question.
mental concerns.
CREATIVE SERVICES MANAGER
Cathlene Ozubko GRAPHIC DESIGNER
2. Do background research.
Across the board, whether it’s the oilsands,
Peter Markiw
3. Construct a hypothesis.
fracking, pipelines or whatever, there is a battle
CREATIVE SERVICES
4. Test your hypothesis through experimentation.
over science. Competing studies come out on
5. Analyze your data and draw a conclusion
what seems a weekly basis, and often with com-
Janelle Johnson SALES
SALES MANAGER—ADVERTISING
Monte Sumner | msumner@junewarren-nickles.com SENIOR ACCOUNT EXECUTIVES
Nick Drinkwater, Tony Poblete, Diana Signorile SALES
Terry Nelson Browning, Brian Friesen, Rhonda Helmeczi, Sammy Isawode, Mike Ivanik, Nicole Kiefuik, David Ng, Sheri Starko
based on the data. 6. Report the results. Kids also learn that the scientific method
pletely opposite conclusions, depending on who paid for the work. An example of this is the debate over
not only proves hypotheses, but it also dis-
fracking, shale gas development and climate
proves them.
change in the United States. In 2012, a study
Climate scientists at the Intergovernmental
was released claiming shale gas development
For advertising inquiries please contact adrequests@junewarren-nickles.com
Panel on Climate Change (IPCC), however, seem
resulted in more greenhouse gas emissions than
AD TRAFFIC COORDINATOR—MAGAZINES
to have failed to learn all these lessons, says Dr.
burning coal due to methane venting at well-
Tim Ball, a retired professor from the University
sites. Anti-fracking activists waved the study
of Winnipeg.
around as evidence the shale gas revolution was
Lorraine Ostapovich | atc@junewarren-nickles.com DIRECTORS CEO
Bill Whitelaw | bwhitelaw@junewarren-nickles.com PRESIDENT
Following the recent release of the IPCC’s fifth
no solution to the country’s energy concerns.
Rob Pentney | rpentney@junewarren-nickles.com
climate change report in September, Ball pointed
Then, this year, a study from the University of
DIRECTOR OF SALES & MARKETING
out that IPCC models predicting future climate
Texas came out, with the opposite conclusion.
Maurya Sokolon | msokolon@junewarren-nickles.com DIRECTOR OF EVENTS & CONFERENCES
Ian MacGillivray | imacgillivray@junewarren-nickles.com
have all proven inaccurate. “For 17 years, global temperatures
The result is no one knows what to believe any more. And when confusion reigns, politics
have declined while CO2 levels continue to
take over and reality goes out the window. It
increase,” he says. “Arctic summer ice, sup-
becomes a contest of who can scream loudest
Gord Lindenberg | glindenberg@junewarren-nickles.com
posedly all gone by 2013, has recovered by 60
and most often, turning the decision-making
DIRECTOR OF CONTENT
per cent in one year. Severe weather has not
process into a popularity contest.
DIRECTOR OF THE DAILY OIL BULLETIN
Stephen Marsters | smarsters@junewarren-nickles.com DIRECTOR OF DIGITAL STRATEGIES
Chaz Osburn | cosburn@junewarren-nickles.com DIRECTOR OF PRODUCTION
Audrey Sprinkle | asprinkle@junewarren-nickles.com DIRECTOR OF FINANCE
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increased.” Yet, as temperatures have declined and all climate models have failed to predict
ing, another proposed solution, doesn’t work
this decline, the IPCC says it has gained
because many people have little faith (and
confidence that a climate disaster is coming
rightly so) in the government’s motives.
and man is to blame. That’s right, it drew a
GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2013 JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240. Postage paid in Edmonton, Alberta, Canada. If undeliverable, return to:
I don’t know what the answer is, but the
conclusion that contradicts the data from their
stakes couldn’t be higher. If the politics of the
experiments.
IPCC win out over its lack of science, a lot of
That’s not science—it’s politics. And the
people are going to suffer.
politicization of science is one of the biggest problems facing the energy industry in
Darrell Stonehouse Editor
Subscription Inquiries Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: junewarren-nickles.com
Peer review has often failed to prevent this “political science.” Government fund-
dstonehouse@junewarren-nickles.com
N E XT I S S U E December 2013
Circulation Department, 80 Valleybrook Dr, North York, ON M3B 2S9
Our annual exploration and production
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.
outlook for the Western Canadian Sedimentary Basin, plus an update on the progress of export oil pipeline plans and construction.
Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as ”Letter to the Editor” if you want them published.
OIL & GAS INQUIRER • NOVEMBER 2013
9
FAST NUMBERS
. million , barrels per day barrels per day Expected capacity of the Energy East Pipeline.
Capacity already under contract on the Energy East Pipeline.
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
M O NTH
OIL
GAS
OTHER
MONTH
T O TA L
OIL
GAS
D RY
SERVICE
T O TA L
Sep 2012
447
65
12
2
Sep 2012
813
75
9
11
90
Oct 2012
588
80
23
91
Oct 2012
1,121
105
10
33
1,29
Nov 2012
535
137
78
0
Nov 2012
930
214
15
91
1,20
Dec 2012
483
105
51
9
Dec 2012
802
164
17
71
1,0
Jan 2013
313
59
9
1
Jan 2013
542
87
7
9
899
161
17
83
1,11 1,29
Feb 2013
449
124
67
0
Feb 2013
Mar 2013
544
149
119
12
Mar 2013
949
198
21
127
581
146
18
127
75
0
Apr 2013
481
91
129
01
Apr 2013
Jun 2013
179
14
73
2
Jun 2013
273
56
1
Jul 2013
263
59
51
Jul 2013
671
103
15
51
0
Aug 2013
394
46
34
Aug 2013
817
72
1
39
929
Sep 2013
357
72
29
Sep 2013
735
113
1
30
9
Wells Drilled in British Columbia
Saskatchewan Completions
Source: B.C. Oil and Gas Commission
Source: Daily Oil Bulletin
MONTH
WELLS DRILLED
C U M U L AT I V E *
MONTH
OIL
GAS
OTHER
TOTAL
Sep 2012
11
465
Sep 2012
302
1
7
10
Oct 2012
28
493
Oct 2012
453
0
27
0
Nov 2012
78
571
Nov 2012
346
0
26
2
Dec 2012
65
636
Jan 2013
Dec 2012
282
1
34
1
31
31
Feb 2013
42
73
Jan 2013
174
0
5
19
Mar 2013
66
139
Feb 2013
358
0
31
9
Apr 2013
69
208
Mar 2013
323
0
19
2
Jun 2013
45
330
Apr 2013
88
1
5
9
Jul 2013
49
379
Jun 2013
80
0
2
2
Aug 2013
26
405
Jul 2013
358
1
13
2
Sep 2013
43
422
Aug 2013
362
1
6
9
Sep 2013
347
0
1
*From year-to-date
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STATS
AT A
GLANCE
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada, October 9, 2013 Source: Rig Locator
Alberta, October 2013 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada Alberta
AC T I V E
OIL WELLS
Alberta
GAS WELLS
Sep 1
Sep 12
Sep 1
Sep 12
261
320
1
45%
Northwestern Alberta
86
105
42
30
British Columbia
51
18
9
74%
Northeastern Alberta
67
89
0
1
Manitoba
13
10
2
57%
Central Alberta
168
225
4
9
Saskatchewan
81
61
12
57%
Southern Alberta
36
31
26
25
0
09
1
0%
TOTAL
0
2
WC TOTALS
Service Rig Count by Province/Territory
Drilling Activity: CBM & Bitumen
Western Canada, October 9, 2013 Source: Rig Locator
Alberta, October 2013 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada
Alberta
AC T I V E
C OA L B E D M E T H A N E
Alberta
BITUMEN WELLS
Sep 1
Sep 12
Sep 1
Sep 12
391
300
91
57%
Northwestern Alberta
0
0
7
20
8
16
2
33%
Northeastern Alberta
0
0
67
87
12
6
1
67%
Central Alberta
0
0
65
96
Saskatchewan
133
52
1
72%
Southern Alberta
3
11
0
0
WC TOTALS
91
9%
TOTAL
11
19
20
British Columbia
Manitoba
OIL & GAS INQUIRER • NOVEMBER 2013
11
IN THE
NEWS Issues affecting Canada’s E&P industry
booming
Rail terminal projects booming By Carter Haydu
The “big challenge” for the continued growth in crude-by-rail transportation out of western Canada is ensuring there is terminal capacity at both ends of the rail route, said an oilsands company executive. Fortunately, efforts are underway to increase loading and unloading terminal capacity for rail transport of Canadian crude, with a number of refineries building in fairly major infrastructure in order to access less-expensive crude not currently linked by pipeline, Edward Koshka, vicepresident of operations and marketing for E-T Energy Ltd., said. “Refi ners are sort of getting into this and saying they want to participate in it on the off-loading side,” he said, adding that terminal operators have also been increasing their investments to enable rail transport of crude. “On the loading side, I think there has been lots of new capacity built, but there is more capacity that has to come online in the next five years.”
Canadian terminal projects Company
Type
Location
Capacity
Start-up
Canexus Corporation
Terminal expansion
Bruderheim, Alta.
70,000 bbls per day
Q3 2013
Gibson Energy Inc. and U.S. Development Group, LLC
New terminal
Hardisty, Alta.
140,000 bbls per day
Q1 2014
Ceres Global Ag Corp.
New terminal
Northgate, Sask.
70,000 bbls per day
Q4 2013
Tundra Energy Marketing Limited
Terminal for Manitoba and North Dakota crude
Cromer, Man.
30,000 bbls per day x 2
August 2013/Q1 2014
Keyera Corp. and Kinder Morgan Energy Partners, L.P.
New terminal
Edmonton, Alta.
40,000 bbls per day
Q2 2014
TORQ Transloading Inc.
New terminal
Kerrobert, Sask.
168,000 bbls per day
Q3 2014
TORQ Transloading Inc.
Terminal expansion
Unity, Sask.
N/A
N/A
U.S. terminal projects Company
Type
Location
Capacity
Start-up
Tesoro Corporation
Crude-by-rail and marine off-loading
Vancouver, Wash.
120,000–280,000 bbls per day
2014 (pending Savage Companies construction permit approval)
Phillips 66 Company
Off-loading facility
Ferndale, Wash.
30,000 bbls per day
Q4 2014
BP p.l.c.
Off-loading facility
Blaine, Wash.
60,000 bbls per day
Spring 2014
Valero Energy Corporation
Off-loading facility
Benicia, Calif.
70,000 bbls per day
N/A
Valero Energy Corporation
Off-loading facility
Wilmington, Calif.
60,000 bbls per day
N/A
PBF Energy
Off-loading facility
Delaware City, Del.
80,000 bbls per day
Q4 2014
Canadian National Railway Company
Transloading
Mobile, Ala.
75,000 bbls per day
Early 2014
Genesis Energy, LP
Terminal expansion
Natchez, Miss.
43,000 bbls per day
Late 2013
NuStar Energy L.P.
Terminal expansion
St. James, LA.
N/A
N/A
Photo: Gerald Ford
Source: Daily Oil Bulletin
Rail could carry as much as 700,000 barrels per day if Canadian terminal projects go ahead as planned.
A recent ARC Financial Corp. report suggested that if all publicly announced Canadian projects occur as planned, by 2015 they would add more than 700,000 barrels per day of capacity compared to the 850,000 barrels per day capacity of the proposed Keystone XL Pipeline. According to Koshka, growth in the crude-by-rail sector should continue into the future, regardless if a major pipeline project such as Keystone XL increases the link between western Canadian producers and markets.
“Keystone answers a lot of the issues around access to the U.S. Gulf Coast, but it doesn’t do anything for California, Washington state, and it doesn’t do anything for the east coast of Canada and PADD 1 east coast of the United States. Those markets definitely want to have takeaway capacity opening up to them.” Koshka noted that rail transportation largely reduces the need for diluent in heavy crudes and bitumen, which definitely changes the economics associated with rail transportation versus pipelines. OIL & GAS INQUIRER • NOVEMBER 2013
13
In The News
“ What I think is most interesting is to look at the volumes the big oil companies are looking to move, so I think crude-byrail has a great future.” — Ken James, co-president and chief executive officer, Oak Point Energy Ltd.
“It makes it even that much more attractive to avoid the diluent-blending issue that you get into when you’re producing bitumen.” Rail and pipelines offer a cooperative approach to transporting crude for producers
trying to ramp up production and ship it into a particular market, said Ken James, co-president and chief executive officer at Oak Point Energy Ltd. “I think rail and pipelines have a lot of synergies where they’ll develop rail until a certain capacity and then build a pipeline to move those secured volumes,” James said, adding that he is both “surprised and not surprised” by how quickly rail has picked up over the past couple of years as an alternative to pipelines, given the current bottleneck situation. Koshka said he envisions rail increasing its reach as a means of transporting crude to market in the years ahead. For example, he sees an opportunity for rail to move crude to Canada’s West Coast for export options, provided there is available terminal capacity. “There is huge rail capacity in Prince Rupert that exists today, but it’s just that we don’t have the terminalling capacity up in Prince Rupert to be able to off-load large amounts of heavy crude. So I think that’s just a next logical step for rail to open up that whole market to Canadian producers.” Largely because it is easier to fi nance, crude-by-rail is particularly attractive to
smaller producers who might not want or be able to commit to long-term pipeline contracts, said Koshka. “Typically pipelines require you to have very strong balance sheets in order to have the credit-rating worthiness to commit to a pipeline, and that always makes it difficult for new and emerging producers versus companies that have those established cash flows.” Even if diluted crude or bitumen is shipped to refineries via pipeline, James said rail can play an important role in transporting that diluent back to the producers. “Of course, all the dilbit that gets shipped gets fractionated back out in the refineries, and it needs to return home.” James said the current trend of crudeby-rail was largely initiated by a lot of the juniors who had to get product to market but didn’t have access to pipelines. What surprises him today is the degree to which larger producers are fi nding cause to take advantage of the rail advantage as well. “What I think is most interesting is to look at the volumes the big oil companies are looking to move, so I think crude-byrail has a great future.”
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NOVEMBER 2013 • OIL & GAS INQUIRER
10/1/2013 4:10:21 PM
climbing
In The News
Horizontal drilling continues climbing A record 4,837 horizontal wells were drilled across Canada to the end of August, excluding experimental and test wells, representing a 6.5 per cent increase from 4,541 horizontal wells rig released during the first eight months of 2012. This year’s eight-month rig release count for horizontal wells is up 16.5 per cent from 4,150 such wells two years ago, and up 61 per cent from 3,002 horizontal wells for January to August 2010. Year-over-year, the horizontal well count is up in all four western provinces except for Manitoba, where drilling counts are off from last year. Operators across Canada rig released 1,142 wells in August, up almost six per cent from 1,078 wells drilled a year ago, with drilling rates up in Saskatchewan and British Columbia, but down in the other two western provinces. B.C. operators drilled 54 wells in August compared to 37 a year ago (up 46 per cent), while operators working in Saskatchewan rig released 411 wells last
month, up from 323 in August 2012 (up 27 per cent). In Alberta, operators drilled 611 wells last month compared to 632 in August 2012 (off three per cent). Operators in Manitoba drilled 64 wells in August compared to 85 a year ago (off 25 per cent). To the end of August, operators have drilled 6,971 wells across Canada, about
61 per cent Increase in horizontal drilling since 2010
even with the 6,958 wells rig released during the comparable period last year. Of the wells drilled, 727 still have no final status (oil, gas, dry or service). Of those with a status designation, about 79 per cent were reported as an oil well and only 11 per cent were listed as a gas well. While the number of rig releases was flat to the end of August, total metres drilled
rose to 14.2 million metres from 14.04 million metres in January to August 2012. Alberta rig released 4,242 wells over the first eight months, off one per cent from 4,288 a year ago, and total metres drilled dipped to 8.84 million metres from 8.98 million metres to the end of August last year. In Saskatchewan, eight-month rig releases were up four per cent to 2,004 from 1,927 a year ago. Metres drilled climbed to 3.28 million metres from 3.10 million metres over the first eight months of 2012. The rig release tally in British Columbia improved eight per cent to 345 after eight months, compared to 320 last year, while operators in the province drilled 1.35 million metres versus 1.17 million metres to the end of August 2012. Manitoba’s rig release count after eight months declined 10 per cent to 363 compared to 404 a year ago. A total of 684,514 metres were drilled to the end of August compared to 748,777 metres in January to August 2012. — DAILY OIL BULLETIN
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OIL & GAS INQUIRER • NOVEMBER 2013
15
In The News
cash cow
Energy East Pipeline a cash cow, says report By Elsie Ross
A report commissioned by TransCanada Corporation has found that its proposed $12-billion Energy East Pipeline from Alberta to Saint John, N.B., will benefit Canada as a whole in addition to the jobs, economic growth and increased tax revenue to the six provinces along the pipeline route. The analysis conducted by Deloitte & Touche LLP estimates that Energy East would generate $35 billion in additional gross domestic product for Canada during six years of development and construction, and over the first 40 years of its operation. The report also estimates more than 10,000 fulltime jobs will be directly supported during development and construction of the pipeline between 2013 and 2018, and another 1,000 full-time jobs will be directly supported by the pipeline once it begins service. Deloitte also found that Energy East will generate an additional $10 billion in tax revenues for all levels of government over th life of the project. Deloitte’s projections were generated using Statistics Canada’s
input-output model, which measures direct, indirect and induced economic effects of large industrial projects and activities in Canada. Last month, TransCanada confirmed that it would proceed with the 1.1-millionbarrel-per-day pipeline based on binding, long-term contracts from producers and refiners to ship approximately 900,000 barrels per day of crude oil from receipt points in Alberta and Saskatchewan to delivery points in Montreal, the Quebec City region and Saint John. The project involves conversion of a portion of the existing TransCanada Mainline to oil service as well as the construction of new pipeline. Energy East will access a marine terminal in Quebec and a terminal at Canaport in Saint John, where TransCanada and Irving Oil Limited have formed a joint venture to build, own and operate a new deepwater marine terminal. The study says that “the project would help support thousands of jobs and millions
It will take an increasing amount of natural gas to keep Saskatchewan’s economy fired up.
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of dollars in government tax revenues over the short- and long-term life of the project,” Russ Girling, president and chief executive officer of TransCanada, said in Fredericton, where the report was released. “Energy East will do all of this safely and reliably while still ensuring TransCanada meets the needs of our gas customers in eastern Canada and the northeastern United States,” he said. “We are committed to maximizing utilization and the benefits of our infrastructure for all of our customers, gas and oil, and are committed to ensuring sufficient capacity is available to meet all of their growing needs.” Girling said there has been enormous support and interest in the project since it fi rst floated the idea more than a year ago and since it announced it was proceeding. “I think that is because this project makes sense for all Canadians and this new study helps us understand why that is the case.” The project will create thousands of jobs across the country and bring new revenues
Saskatchewan continues to experience rapid economic growth year after year. Potash mines are multiplying across the Province, construction cranes are rising above our cities, and power plants are increasing their capacities. Each mine, industrial site, refinery, or office building needs a dependable supply of natural gas to power its expansion and future operation. TransGas is strategically positioned to provide safe and reliable natural gas transportation and storage services to support this unprecedented growth in Saskatchewan.
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In The News
and business opportunities to local communities, added Alex Pourbaix, president of energy and oil pipelines. “It will achieve all of this safely, with minimal environmental impact and all with private sector funds.” Since the beginning of the project, TransCanada has been out in the field and engaging with aboriginal and stakeholder groups, he said. Over the past several weeks it has held dozens of public open houses and meetings with landowners, community groups and government leaders across Canada to find out how it can make Energy East the “safest and most environmentally responsible pipeline possible,” said Pourbaix. TransCanada expects to proceed with the necessary regulatory applications for approvals to construct and operate the pipeline project and terminal facilities in early 2014. Energy East is anticipated to be in service by late 2017 for deliveries in Quebec and 2018 for deliveries to New Brunswick. The study was based on the initial capital budget of $11.3 billion, and the economic impact is based strictly on the effects arising from the development and construction
Highlights of Deloitte & Touche LLP’s analysis of the economic benefits of the Energy East Pipeline project include: GDP growth Energy East will generate an estimated $10 billion in additional gross domestic product for the Canadian economy during the six-year development and construction phase, and $25.3 billion during the 40-year operations phase examined in the study. Regular maintenance is expected to extend the operating life of the pipeline beyond 40 years. Job creation The six-year development and construction phase of the project will generate an estimated 10,000 direct full-time equivalent (FTE) jobs across the country: 2,300 during the development period (2013-15) and 7,700 during the construction period (2016-18). The 40-year operations phase is expected to sustain 1,000 fulltime jobs across Canada directly related to the pipeline’s operation. Thousands of indirect and induced jobs are also expected to be generated by the project in all provinces along the route. Approximately one-half of the jobs created in the development and construction phase
will be in the construction, engineering, architectural, and oil and gas support services industries, while approximately half of the jobs in the operations phase will be in the oil and natural gas pipelines and power generation and transmission industries. The Deloitte & Touche LLP study found that Quebec and Ontario will be the largest beneficiaries of the project with an estimated 2,217 direct, indirect and induced FTE jobs in Quebec during the development phase and another 7,319 during construction. In Ontario, the project would provide an estimated 1,882 jobs during development and 6,214 during construction. Tax revenues The development and construction phase is expected to generate an additional $3 billion in tax revenues for municipal, provincial and federal governments across Canada. The operations phase will result in $7.2 billion in added tax revenues. Source: Deloitte & Touche LLP
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In The News
of the project and then its operation, said Trevor Nakka, partner at Deloitte. It does not include the potential benefits that may arise due to possible impacts on oil pricing due to increased market access or benefits that eastern refineries may see due to their ability to access lower-cost feedstock compared to
the 700,000 barrels per day of high-priced crude they currently import. Nakka said the input-output model used in the study is widely regarded as being credible and Deloitte did not modify the estimates. “We find the estimates reasonable relative to the nature of the project,” he said.
“Many people would reasonably expect that spending $11.3 billion on development and construction of a major energy pipeline project along with incremental operating expenditures of $635 million would result in the creation of jobs, taxation and general economic benefits.”
competitors
Are Canada and the U.S. LNG competitors? By Richard Macedo
While Australia has been cited as the chief rival for Canada’s planned West Coast projects in the race to build liquefied natural gas (LNG) export capacity to supply Asia, the U.S. Gulf Coast is being increasingly viewed as a possible competitor as well. Are the two regions really competing for the same LNG customers? Possibly for the immediate future, but that’s not likely to persist in the long term, according to Peter Hansen, the chief executive officer of a planned project on the west coast of the United States named Oregon LNG. He was speaking at the Canada LNG Export Forum hosted by dmg events. In a broader sense, he acknowledged, though, that there is some competition between the countries. “Any time you are in the same business as somebody else, yeah, you’re competing with them,” he said. “But if you look at the competition for gas supplies, I think it’s probably fair to say that the basins are so different now and so delinked and far from each other that there’s plenty of gas for everybody, and I don’t think there will be a lot of robbing going on across basin boundaries.”
As far as financing these projects, “it seems to be the case that if you have a good project that has a sound foundation, there’s money out there...but if you have a questionable project that won’t be competitive long term, you might have an issue.” “Competing for the world’s LNG markets, we might be competing for the same markets, but in reality I don’t think we are,” he added. “Short term, it’s quite obvious that we have been competing.” “The Gulf Coast projects have taken markets in Asia,” Hansen said. “I think it’s really a matter of the Gulf Coast projects being Mr. Right Now, not necessarily Mr. Right.” For the long term, he cited shipping distances and costs as the “elephant in the room.” “When you look at the cost of coming out of the Gulf Coast versus the cost of coming out of the B.C. coast, there is no comparison,” Hansen said. “I think this is a longterm thing that will shake out over time.” He said Kitimat LNG, for example, is less than 4,000 nautical miles to Tokyo, roughly the same distance as from Oregon LNG. “Compare that to Sabine Pass—that’s 16,700-plus nautical miles. That’s a huge
difference and that’s obviously not going to change,” Hansen said. “A lot of people believe that the Panama Canal expansion will be the saviour of the Gulf Coast projects in Asia, but I’m not so sure that’s really the case.” One of the key unknowns is what the Canal fee will be, he noted. “I think the conclusion here is that we’re not really competing for the same customers. The West Coast projects should be very competitive in Asia. I don’t think the Gulf or the Atlantic coast projects are,” Hansen said, “just like we are probably not going to be very competitive in the Atlantic Basin.” Like another project in the state, Jordan Cove Energy Project, Oregon LNG is seeking to use western Canadian natural gas to supply its proposed project. The Oregon LNG facility will be located in Warrenton, Ore., at the mouth of the Columbia River. “I really see that Oregon LNG project as just another B.C. coast project,” Hansen said. “If you extend the B.C. coast down a little bit, it’s not that different from the B.C. projects. It can access the same gas in Canada—B.C. and Alberta—and of course we can also access the U.S. Rockies gas.”
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BRITISH COLUMBIA WELL ACTIVITY SEP/12
SEP/13
Wells licensed
24
SEP/12
SEP/13
Wells spudded
34
SEP/12
SEPw/13
33
Rigs released
▲
▲
British Columbia
▲
Source: Daily Oil Bulletin
Project planned to account for natural gas liquids in B.C. By Richard Macedo
Photo: Joey Podlubny
Non-profit Geoscience BC has a new project planned that will try to quantify the amount of gas liquids in the province’s formations. Carlos Salas, vice-president of oil and gas with Geoscience BC, told a Canadian Society for Unconventional Resources technical luncheon that the group has a few new initiatives, including trying to quantify gas liquids in northeastern British Columbia. Salas noted that in Alberta, when the price of natural gas declined, producers started chasing more valuable liquids-rich gas. In order to aid in the exploration and development of these resources in British Columbia, a collaborative study, funded by Geoscience BC, with Professor Marc Bustin from the University of British Columbia and the industry as partners, will look to quantify gas and natural gas liquids (NGLs) and flow characteristics in
unconventional reservoirs. The three-year study will help the industry better understand liquids-rich fairways and respective flow characteristics from different source rocks including the Exshaw, Doig, Montney, Nordegg and Wilrich formations in northeastern British Columbia. “To address this short-term problem in gas prices...we’re trying to map out NGL fairways and quantify how much is in there,” Salas said. Bustin said that the project will start when the funding is available, likely at the end of September, and will go for three years. Geoscience BC started in April 2005 with a $25-million grant from the provincial government. The organization received an additional $11.7 million in 2008 to support mineral geoscience in mountain pine beetle–affected areas and oil and gas geoscience in frontier areas of the province. In May 2011, Geoscience BC received
Liquids pipeline crossing the Peace River at Taylor in northeastern British Columbia. The government is trying to determine how much gas liquids there are in the province.
$12 million in new funding from the province to continue mineral and energy geoscience initiatives in British Columbia. Geoscience BC also has other projects on the go that involve water management. One that is just wrapping up in the Liard Basin should be ready for public release by December or early in 2014. “It will be looking at saline aquifers also in support of development drilling in that basin,” Salas said. Brad Hayes, president of Pet rel Robertson Consulting Ltd., said his fi rm is involved in this project.
“To address this short-term problem in gas prices...we’re trying to map out [natural gas liquids] fairways and quantify how much is in there.” — Carlos Salas, vice-president of oil and gas, Geoscience BC
“It is a regional study of deep saline aquifer potential to support shale gas development,” he said. “We have submitted a draft report to Geoscience BC and expect to release the final report this month. Geoscience BC will make the report public, but I’m not sure a release date has been determined.” Another project just starting in the Horn River Basin, Salas said, will examine the interaction between surface and groundwater and how that is affected by discontinuous permafrost, while another one involves putting together a water data management system. “It’s going to house all the hydrometric data,” Salas said, adding that it will include climate data, groundwater observation wells and water usage. “Using this tool, we’ll be able to actually have the actual water numbers, the actual usage in there,” he said. OIL & GAS INQUIRER • NOVEMBER 2013
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British Columbia
Chevron and Apache executives say export experience key to LNG market By Richard Macedo
Canada’s experience as an exporter of hydrocarbons bodes well for Chevron Corporation and Apache Corporation’s planned Kitimat liquefied natural gas (LNG) plant, executives for both companies said in September. Speaking at the Barclays CEO EnergyPower Conference, George Kirkland, Chevron’s vice-chairman and executive vicepresident of upstream, reinforced a point he made in August that the company wants at least 60–70 per cent of Kitimat LNG supply under long-term agreement before announcing a final investment decision on the project. He said front-end engineering and design work continues for the LNG plant, and activity in the Liard Basin is also ongoing to assess resources there that could supply the plant. “We feel the Horn River resources are very well defined, so it’s really Liard— which in our view, and I believe in our partner’s view, Apache—that is the bigger long-term opportunity,” he said. From a resource point of view—for the first two trains and more—Chevron has no concerns; the challenge is for Kitimat LNG to secure sufficient gas contracts to underwrite the project. “Preferentially for us, the contracts will be very much so tied to oil,” Kirkland 22
NOVEMBER 2013 • OIL & GAS INQUIRER
said. “We are not Henry Hub–related at all because we are someplace else in the world. We are trying to have buyers enter into the project as equity owners and that will give them, we think, actually much better protection than Henry Hub pricing. “Why do we say better? Every index that you’re marked off of, indexes go up but they also go down. If they go up and you’re a buyer, you really don’t have much protection, so there’s a risk there,” he said. The final investment decision is very much contingent on the marketing side, Steven Farris, chairman and chief executive officer of Apache, told the conference earlier in the morning. “Luckily I can now punt that ball to our partner Chevron because they are in charge of the marketing,” he said. “In terms of the competition with other projects, I will tell you I think that the amount of LNG in the United States that’s actually going to be taken off shore is going to be smaller than we anticipate. “Canada has been exporting natural gas for years and years...so they are much more attuned to export than the United States is. I’m not so concerned about competition in the U.S. Obviously, worldwide competition continues [to be] very strong. Certainly,
China needs a tremendous amount of LNG over the next several years.” Kirkland echoed the point of Canada’s experience as an exporter during his talk, when asked about competition from the United States. “We like Canada because Canada has been exporting gas for a long period of time; Canada exports oil,” he said. “Canada has a different focus on a willingness to export resources, so we have, we believe, greater surety from the political side in Canada than you do in the U.S. “The U.S. has not been since—you go back many, many decades—has not been an exporter, or a significant exporter, of any of our hydrocarbons.” In addition to the political concerns in America, he noted that manufacturing groups have come out against LNG exports. “We don’t—from a policy point of view— believe that’s right,” Kirkland said. “The U.S. needs to take advantage of this opportunity that they have in this big [gas] resource.” The company also likes Canada because of the quality of the resource and the ability to control it. “We can really control the gas to a much greater extent,” K irkland said. “From every perspective, we like that opportunity better.”
Photo: Joey Podlubny
Canada’s experience in exporting natural gas should help liquified natural gas terminals planned for the west coast become reality, say Chevron and Apache executives.
British Columbia
BG Group examining upstream options for planned LNG plant By Richard Macedo
BG Group plc is examining its upstream options to feed its planned Prince Rupert liquefied natural gas (LNG) plant, and has raised the possibility of sharing infrastructure such as pipelines to save on costs. Infl ationary pressures have wreaked havoc on some Australian LNG projects. With so many facilities being proposed at the same time, it overheats the competition for labour and materials. Late last year, for example, Chevron Corporation added $15 billion to the cost of the Gorgon LNG export complex, which is now estimated at $52 billion. In British Columbia, BG Group is planning a two-train, 14-million-tonne-perannum project with an option for a third train. A plant site has been secured on Ridley Island in the Prince Rupert area with a joint-venture pipeline planned with Spectra Energy Corp. The company is in discussion with potential customers and partners. The earliest date given for a final investment decision is 2016 with a possible start-up of 2020. During a capital markets day hosted by BG Group, Martin Houston, the chief operating officer and executive director, said upstream options are under review. “We’ve secured a very attractive site, perhaps the best site for the LNG plant, which covers approximately 300 acres on Ridley Island,” he said. “This site is industrially zoned, has deepwater access, has road and rail access and has existing infrastructure.” The company is “exploring options with some of the promoters of the other western Canada LNG projects to see if we can cooperate in the development of a shared pipeline, something we believe could deliver significant savings across two projects.” Houston added the company is frequently asked about its upstream aspirations since, he said, but it does not have an upstream position in Canada today. “Let me just say that we’re pursuing several supply options and would anticipate
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supply from owned resource and purchased from the market,” he said. There have been at least a dozen LNG projects announced for British Columbia, sparking fears it could create an overheated capital cost environment. “Certainly sharing pipeline is an enormous advantage; it’s the most difficult part of the western Canadian projects,” Houston said. “Getting the pipeline done is really the key to unlocking the opportunity. “In western Canada, it’s absolutely true that there are a large number of projects. There probably are five real projects that you can track,” he added. “We will be looking at modularization, something that’s worked to great advantage in Australia.... Secondly, we’ll be looking for contracts to protect us against labour inflation, cost inflation, and against the inflation of goods and services.”
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ARC Resources’ Dawson play globally competitive, says company By Pat Roche
Many industry pundits are fretting that western Canadian natural gas producers can’t compete with low-cost producers in the United States, but don’t tell that to ARC Resources Ltd. ARC’s Dawson Montney play generated more than $100 million in cash flow last year even though the AECO gas price averaged only $2.27 per gigajoule, said president and chief executive officer Myron Stadnyk. Starting around 2005, ARC’s pioneering work at Dawson launched the blockbuster Montney natural gas play in northeastern British Columbia. Today, ARC’s Dawson Montney play is a case study of how Canadian producers can achieve lucrative returns even at brutally low gas prices. “Dawson is a really nice case study because you can see the investment through to the cash flow,” Stadnyk said in a 24
NOVEMBER 2013 • OIL & GAS INQUIRER
British Columbia
presentation on enhancing the returns from “long-dated” resources at the Peters & Co. Limited 2013 Energy Conference in Toronto. For a couple of years while it was building production, ARC’s capital spending of about $150 million per year at Dawson significantly exceeded the cash flow the play was generating. But as new wells coming on stream formed an ever-shrinking percentage of the total wells on production, decline rates flattened out and less capital is now needed to maintain the current Dawson output of 165 million cubic feet per day. “In fact, we over-drilled a little bit there, so we hardly needed any reinvestment capital in 2012,” Stadnyk told the Peters conference in September.
“The reinvestment, now that the field has stabilized, is very modest. A 25 per cent reinvestment will allow us now to produce this field for many, many years and have
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free cash flow.” — Myron Stadnyk, president and chief executive officer, ARC Resources Ltd.
Pressure Vessels By “But kind of the punchline is if you look at 2012...AECO was $2.27 for the year, and we cash-flowed over $100 million at Dawson,” he said. Stadnyk said an increase of $1 per thousand cubic feet would add $60 million to the company’s cash flow. “It’s a key play,” he said of the Dawson Montney. “The reinvestment, now that the field has stabilized, is very modest. A 25 per cent reinvestment will allow us now to produce this field for many, many years and have free cash flow.” One reason ARC achieved such stellar economics at Dawson was that the field was originally developed on the assumption of four billion cubic feet of reserves per well. But with improved knowledge and better hydraulic fracturing, ARC now expects to recover seven billion cubic feet per well at Dawson. “If you look at $3 AECO...in Dawson you’re at a 45 per cent rate of return,” Stadnyk said.
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NORTHWESTERN ALBERTA WELL ACTIVITY SEP/12
SEP/13
Wells licensed
172
SEP/12
SEP/13
Wells spudded
193
SEP/12
SEP/13
174
Rigs released
▲
▲
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Source: Daily Oil Bulletin
N.W. Northwestern Alberta
Changes to completions could boost Duvernay results, conference hears By Elsie Ross
Photo: Aaron Parker
An early player in the Duvernay Formation says he expects wells will continue to improve on both an initial production and ultimate recovery basis. The improvements will likely result from operators moving to slightly longer laterals and smaller fracs with more stages, as in the Marcellus and Eagle Ford shale plays, Brian McLachlan, president and chief executive officer of Yoho Resources Inc., told the Peters & Co. Limited Energy Conference. Some of the majors here are already moving in that direction, he said. “I don’t think we have to go out two kilometres, but even adding two or three stages will make quite a difference to your IP [initial production] and it doesn’t cost that much more,” he said. In response to a question, McLachlan acknowledged that the Duvernay is not an easy formation to fracture, with some frac pressures in the 80,000-kilopascal range. “We had that problem early, but we think we have put in the right cocktail to overcome that problem,” he said.
Yoho wells in the Duvernay are costing around $11 million to drill, case and complete.
“In the last well pair, we were having problems in the fi rst couple of stages and we changed the type of food we were using, and we had no problems at all after that.” Some operators, said McLachlan, have been introducing gel into their system, which appears to breakdown the formation even better. Asked about the company’s choice of completion techniques, he said some of the early Yoho wells used the ball-anddrop system while others used perf-andplug. While partner Celtic Exploration Ltd. favoured a ball-drop system because it was familiar with it in the Montney, Yoho had a bit of a problem with it because “when things go wrong, they go very wrong,” said McLachlan. “I would think that as time goes on, when you are very comfortable with what you are doing, maybe the balldrop [system] makes sense.” The only downside that is being seen in the United States is that operators are going back into wells and refracturing them and “that is going to be awfully hard to do with a ball-drop system in there,” he said. “You need a perf-and-plug system.” The prize in the Duvernay is 100 billion to 120 billion cubic feet per section of gas in place with liquids-rich gas of 100–160 barrels per million cubic feet (65 per cent condensate), with expected average well recoveries of approximately one million barrels of oil equivalent. Based on the results of the early wells, payouts are 1.4–2.6 years. The company has 57 (21.75 net) sections of land, all of which are contained within the rich gas condensate window of the play.
Yoho will develop its lands with 1,500to 1,800-metre horizontal sections with full development likely of seven to eight wells per section. “We have demonstrated that pad drilling will reduce capital costs with the last two Yoho-operated wells at Tony Creek costing a little less than $11 million to drill, case and complete,” said McLachlan. The wells qualify for both the deep case royalty credit as well as the shale gas royalty break, which totals fi ve years of fi ve per cent royalty. Yoho estimates that 145– 150 additional net wells are required for full development. Estimated fourth-quarter production (Yoho has a September 30 year-end) is 2,400 barrels equivalent per day with an additional 300–400 barrels per day of Duvernay production behind pipe waiting for compression in December of this year. Field netbacks have nearly doubled in the past year to $21.04 per barrel equivalent from $13.69 per barrel per year earlier with the replacement of low netback drier gas with higher netback Duvernay production. The liquids-rich window of the Duvernay extends for 320 kilometres and is about 30 kilometres wide. As an early entrant into the play, Yoho focused its land acquisition efforts on the Kaybob area as that was the thickest Duvernay sediments with the best reservoir parameters it had seen along the entire trend from Smokey in the north through Kaybob into the Brazeau area. Yoho has drilled eight horizontal and two vertical wells to date, with eight horizontal wells currently producing. It currently has five operated horizontal wells drill-ready, which includes two well pads and a single horizontal well. Results have steadily improved since the first well was put on production in 2012. The first well, which was only partially completed due to a ruptured liner, has produced about 103,000 barrels of oil equivalent in 26 months and is currently OIL & GAS INQUIRER • NOVEMBER 2013
27
Northwestern Alberta
RMP Energy has booked about 440,000 barrels equivalent of reserves (390,000 barrels of light oil) at Ante Creek, which Ferguson suggested is a conservative figure. Even at that, finding and development costs are $8 per barrel and rates of return are more than 200 per cent, he said. A major problem has been constraints in gas conservation facilities in the area. RMP Energy is restricted to 3.5 million cubic feet per day at a third-party battery, which has limited it to producing two or three wells, said Ferguson. To increase gas conservation and to allow for the higher deliverability of light oil volumes to the Pembina Pipeline Corporation system, RMP Energy plans to spend $34 million on a major facility expansion and a 35-kilometre pipeline. The line will connect Ante Creek to Waskahigan, which has direct tie-in to third-party crude oil and associated solution-gas sales pipelines. The expanded battery will handle 23 million cubic feet per day of gas and 10,000 barrels per day of oil compared to the current design, which is sized for five
“Our biggest problem at Ante Creek is that we just don’t know how big it is. We have seen phenomenal well performance.” — John Ferguson, president and chief executive office, RMP Energy Inc.
million cubic feet per day of gas and 6,000 barrels per day of oil. Once the facility is in operation, RMP Energy expects total production of at least 9,000 barrels equivalent per day.
Construction will begin in November with an anticipated February 2014 completion date for the 100 per cent RMP Energy project, which includes an eight-inch gas pipeline with capacity of 20 million cubic feet per day and a six-inch oil pipeline that will be able to transport 10,000 barrels per day. T he nex t const ra i nt w i l l be t he 6,0 0 0 -ba r rel-per- day pipel i ne f rom Waskahigan into the Pembina system, said Ferguson. “Pembina is telling us they are going to expand their mainline, and that may encourage us to get that little trunkline expanded this winter.” If RMP Energy doesn’t proceed with the pipeline project, it will ship as much as it can down the pipe, alleviate its gas constraints and then start shipping oil out of the Ante Creek facility, which will have four loading bays. The company has 320 locations based on four wells per section and is drilling 15–16 wells per year. Current production is 6,800 barrels equivalent per day (54 per cent oil weighted).
OIL & GAS INQUIRER • NOVEMBER 2013
29
Northwestern Alberta
Trilogy targets Montney oil, Duvernay condensate Trilogy Energy Corp. recently finished completion operations on the step-out well Trilogy horizontal Kaybob 09-10-064-19W5 on the western side of the Kaybob Montney oil pool, and it also plans to participate for its 30 per cent working interest in two fourwell pads targeting Duvernay production. Trilogy fracture stimulated the 09-10 well on Sept. 16, 2013. The fracture stimulation included 27 stages along the horizontal length of roughly 2,018 metres. Over the duration of the production test, the well recovered all of the completion load fluid and is currently flowing at an average oil rate of 438 barrels per day, 900 thousand cubic feet per day of natural gas and 104 barrels per day of water, at tubing pressure of 2,200 kilopascals. Trilogy said it’s encouraged by these early results and believes that they support the potential that the pool extends beyond the previously identified boundaries. Additional work will be required to completely evaluate the reserves ultimately expected to be recovered from the pool and to confi rm that these results support continued expansion plans. Trilogy rig released the eastern step-out well located at 16-29-063-17W5 on Sept. 26, 2013, which was drilled to evaluate additional acreage on the eastern margin of the Kaybob Montney oil pool. The 16-29 well is expected to be completed and evaluated through October and November. With a successful completion, the well should be on production in the first quarter of 2014. In the third quarter of this year, Trilogy completed drilling operations on the Duvernay horizontal well located at 01-24-061-22W5 and moved the drilling rig to the next location at 13-33-057-18W5.
Both of these operations were drilled to maintain Trilogy’s Duvernay land position. Following the 13-33-057-18W5 drill, the rig will move to 16-28-058-018W5 to drill a vertical well that is expected to preserve a 14-section block. Also in the third quarter, Trilogy elected to participate for its 30 per cent working interest in a four-well pad operated by a third-party targeting the Duvernay formation. The average cost to drill and complete these wells, net of certain technical expenses, was approximately $12 million per well.
Trilogy has approximately 125 net sections of prospective lands in the volatile oil area and 75 net sections of land in what the company interprets to be the gas condensate area of the Duvernay play. The four lateral legs were each approximately 2,000 metres in length and were completed in approximately 100 fracture intervals in approximately 17 stages. The four wells were production tested in August at an average rate of 1,940 barrels equivalent per day per well (3.4 million cubic feet per day of natural gas and 1,366 barrels per day of condensate), yielding an average condensate gas ratio of approximately 400 barrels per million cubic feet. Each well was flow tested for approximately 53 hours with average flowing pressures between 13 and 24 megapascals. The four-well pad
is expected to be tied in during September and placed on production in late October. Trilogy also has plans to participate for its 30 per cent working interest in a second four-well pad located approximately two miles west of the fi rst multiwell pad. Drilling operations have been completed and completion operations began in October, with first production in December. The estimated cost to drill, complete, equip and tie in this pad is approximately $12 million per well. These two multi-well pads are located on the same joint interest land block where Trilogy and its partner drilled two wells in 2012. These two wells were brought on production in August 2013, producing for approximately 28 days before being shut in due to maintenance work at the Keyera Corp. Simonette gas plant. The two joint wells were flowing at restricted condensate (48–54 degrees API) rates of approximately 500 barrels each, with associated gas production. It is anticipated that these wells will be back on production when the maintenance work at the Simonette plant is completed at the end of September. Trilogy has approximately 125 net sections of prospective lands in the volatile oil area and 75 net sections of land in what the company interprets to be the gas condensate area of the play. With the additional capital spending related to this Duvernay activity and costs associated with previously unbudgeted activity, Trilogy will be reviewing its capital expenditure plans for the balance of the year and providing further guidance when its operating and financial results are released in November.
Regulator probing Peace River heavy oil odour concerns By Elsie Ross
The Alberta Energy Regulator (AER) has initiated its fi rst proceeding under the province’s Responsible Energy Development Act to investigate and make recommendations about odours and emissions associated with heavy oil operations in the Peace River area. 30
NOVEMBER 2013 • OIL & GAS INQUIRER
“There have been hundreds of complaints about odours over the last few years,” Bob Curran, manager of public affairs for AER, said. “We have been doing everything we can within the regulatory framework and, in fact, companies in that area have exceeded regulations,” he said.
“We just felt we weren’t getting a resolution and had exhausted all of our other regulatory avenues, so we felt initiating this kind of proceeding was the best way to go at this time.” Curran said the AER isn’t sure at this time what the proceeding will look like,
Northwestern Alberta
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although it could include a public hearing. The fi nal approach will depend on the feedback it receives from stakeholders at an organizational meeting that was to be held October 7 in Peace River, he said. The regulator is inviting comments about the proposed scope and process from interested parties including area residents, licensees,
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government departments and agencies, municipalities and subject matter experts. At that time, Peace River–area residents may provide preliminary comments about the nature and scope of their concerns about heavy oil operations in the area. “There are heavy oil operations in other parts of the province, and we haven’t had the same level of complaints,” said Curran. “It just seems to be, for whatever reason, in this one area of the province, whether it’s topographical Peace River Valley or inversions,” he said. “It’s obviously not just specific to the type of operation; there are other factors at play.”
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NORTHEASTERN ALBERTA WELL ACTIVITY SEP/12
SEP/13
Wells licensed
132
SEP/12
SEP/13
Wells spudded
115
▲
SEP/12
SEP/13
199
▲
Rigs released
▼
Northeastern Alberta
Source: Daily Oil Bulletin
Low gas prices mask inefficiency of SAGD process, study suggests By Pat Roche
From the standpoint of many of Alberta’s thermal bitumen producers, a recent study on the efficiency of steam assisted gravity drainage (SAGD) could be titled “Thank God for low natural gas prices.” The paper, published in August in the journal Fuel by University of Calgary (U of C) professors Ian Gates (department of chemical and petroleum engineering) and Steve Larter (department of geosciences), underscores the importance of developing better technologies for in situ bitumen extraction. “The analysis shows that although some SAGD operations are achieving good steam-to-oil ratios, many are not achieving thermally efficient operation, with cumulative steam-to-oil ratios (SOR) many times the theoretical value,” the paper concluded. “This results from combinations of geological realities, operator decisions and the limitations of the SAGD process.
“The results demonstrate that on an energy and carbon dioxide emissions basis, bitumen or bitumen-based energy recovery processes need to step well beyond the capabilities of current steam-based bitumen recovery processes, such as SAGD, if practical and sustainable energy balance and emissions scenarios are to be achieved from the in-situ oilsands operations.” The study looked purely at the energy value of a barrel of bitumen versus the amount of energy required to produce it, but didn’t assess current economics. With gas prices of less than $2 per gigajoule (AECO) coinciding with strong oil prices and a relatively healthy differential between heavy and light oil prices, it would be hard for thermal oil producers not to have good economics today. But history has shown oilsands producers can’t bank on such an enormous
spread between the price of the gas they burn to convert water to steam and the price they get for their bitumen. After analyzing the energy efficiency of SAGD, the U of C researchers wrote: “The results reveal that the overall net energy breakeven point is now equal to a production CSOR [cumulative SOR] of about 6.5.” CSOR refers to a project’s SOR from inception, not just for the most recent month or quarter. The CSOR is usually higher than the instantaneous SOR because the SOR typically falls as the reservoir heats up during the first few years of steam injection. Based on CSOR field data, the analysis found that many operations exceed a CSOR of 6.5 and thus are not net-energy generation processes, though they may still be economic with low gas prices and high oil prices. “With disconnected price markets for natural gas and bitumen, it is possible for bitumen recovery under these conditions to be economically viable today even though it makes no sense to pursue such an energy inefficient process when CSOR values are high,” the paper said.
Alberta steam to oil ratio 2013 Commercial schemes company
Field
Jan
BlackPearl Resources Inc. Cenovus Energy Inc. Southern Pacific Resource Corp. Husky Energy Inc. CNOOC Limited Royal Dutch Shell plc Japan Canada Oil Sands Limited Connacher Oil and Gas Limited Royal Dutch Shell plc Canadian Natural Resources Limited ConocoPhillips Canada Imperial Oil Limited Suncor Energy Inc. Statoil Canada Ltd. Baytex Energy Corp. Suncor Energy Inc. Devon Canada Corporation Cenovus Energy Inc. ConocoPhillips Canada MEG Engery Corp. Cenovus Energy Inc. Pengrowth Energy Corporation
Blackrod Grand Rapids STP-McKay Tucker Long Lake Peace River Hangingstone pilot Great Divide Orion Primrose & Wolf Lake Sumont pilot Cold Lake Firebag Leismer Cliffdale pilot MacKay River Jackfi sh Foster Creek Surmont Christina Lake Christina Lake Lindbergh pilot
6.68 -1.34 6.59 5.23 4.11 4.44 4.40 4.73 3.62 3.89 3.31 3.42 3.22 1.87 2.33 2.56 2.32 2.53 2.44 1.92 1.70
Feb
Mar
Apr
36.35 15.37 8.93 6.68 4.93 4.63 4.77 4.37 4.62 4.00 3.57 3.41 3.42 3.26 3.35 2.60 2.64 2.69 2.51 2.48 1.95 1.70
15.67 5.41 12.17 5.88 4.69 6.43 4.68 4.55 4.63 4.72 3.72 3.40 3.42 3.04 1.96 2.49 2.62 2.51 2.35 2.45 1.95 1.71
34.84 2.85 12.16 5.62 4.34 4.33 4.33 4.47 4.38 4.71 3.50 3.51 3.41 3.01 2.69 2.58 2.60 2.47 2.39 2.34 1.91 1.74
May 7.89 8.07 9.48 5.74 4.42 4.68 4.59 4.62 4.32 5.07 3.53 3.54 3.29 2.99 6.60 2.42 2.41 2.31 2.44 2.24 1.91 1.32
Jun 2.24 -7.17 5.79 5.12 5.79 4.68 4.41 4.26 2.66 3.56 3.77 3.53 3.40 4.41 2.74 2.30 2.32 2.24 2.28 1.59 1.45
Jul
Monthly average
3.40 15.30 12.44 8.83 7.04 8.33 5.48 5.97 4.95 4.81 2.91 4.70 4.47 4.57 4.46 4.47 4.33 4.47 2.30 3.87 3.51 3.61 3.96 3.56 3.34 3.40 3.90 3.26 1.89 3.25 2.62 2.54 2.38 2.50 2.39 2.39 2.25 2.39 2.26 2.36 1.98 1.80 1.67 1.61 Source: Alberta Energy Regulator
OIL & GAS INQUIRER • NOVEMBER 2013
33
Northeastern Alberta
The paper said the theoretical minimum amount of energy required to heat a cubic metre of Athabasca oilsands at a reservoir temperature of 10 degrees Celsius to a steam temperature of 200 degrees Celsius would be about 1.75 gigajoules. Unfortunately, the realities of the reservoir mean the actual amount of energy needed is much higher. The 1.75 gigajoules is only the amount of energy needed to heat a cubic metre of bitumen to 200 degrees Celsius from 10 degrees Celsius. However, hot steam injected into the reservoir heats not only the oilsands but also the overburden, non-productive rock and water in water-rich zones within the rock. Also, the theoretical or ideal SOR is typically lower than the actual SOR because oilsands reservoirs are geologically variable with interbedded sandstones and shales that present a complex, variably permeable medium that steam, oil and water must migrate through, the paper noted. “Actual oilsands reservoirs are completely different from the homogeneous sandstones with uniform fluids envisaged by the reservoir engineers that developed the early SAGD process. Geological heterogeneity impacts
the recovery process through permeability changes of the reservoir sandstones within the oil column and the shale or mudstone barriers and baffles that prevent or retard fluid flow, respectively,” the paper said. “The more laterally extensive the barrier, the longer it takes steam or production fluids to go around it and the longer it takes for mobilized oil to get to the production well. Also, non-productive reservoir within the oil column represents a heat sink which erodes the thermal effi ciency of the process. The main impact of fluid compositional heterogeneity is due to the effect of vertically and laterally varying oil phase viscosity.” And it isn’t all about good reservoir management or well placement. Some companies just have better acreage. “In general, the best-performing well pairs are from regions with better-quality reservoir which have thick, highly oilsaturated accumulations with few shale barriers and high vertical permeability throughout the reservoir,” the paper said. “Operator experience is clearly an important factor, but reservoir geology is king.”
Using SAGD field data, the researchers found the majority of well pairs are operating with a thermal efficiency of less than 40 per cent. “For those few well pairs operating above this limit, this is probably an artifact of interaction between proximal well
“Real SAGD [steam assisted gravity drainage] is about 30 per cent as efficient as ideal SAGD with many well pairs less efficient than this.” — Steve Larter and Ian Gates, University of Calgary researchers
pairs and implies that some well pairs are not operating independently and thus one may appear highly efficient whereas its neighbour does not. Well pairs operating between 30 per cent and 40 per cent efficiency are probably operating as thermally efficiently as can be expected,” the paper said, adding: “Real SAGD is about 30 per cent as efficient as ideal SAGD with many well pairs less efficient than this.”
Emerging oilsands players look to technology to trim costs By Elsie Ross
Innovation plays a key role in technology that can help drive down the costs of oilsands projects over time, an energy conference heard in September. “We are trying to get applications to a commercial stage quickly,” Glen Schmidt, president and chief executive officer of Laricina Energy Ltd., told the Peters & Co. Limited Energy Conference in Toronto. “Invention is always in the background in how we think, so it’s each step of the process: how do we reduce steam requirements, how do you get more efficient in start-up.” A company needs to understand the reservoir while “taking that bucket of tools and applying it,” he said. For example, Laricina is using screw pumps at its Grosmont carbonates project at Saleski and electric submersible pumps at its Grand 34
NOVEMBER 2013 • OIL & GAS INQUIRER
Rapids Germain project because of the reservoir characteristics. Steve Spence, president and chief executive officer of Osum Oil Sands Corp., Laricina’s 40 per cent partner at Saleski, said he’s a big believer in adapting and adopting technologies that have been tested or proven to some degree, “but taking them to the application that you are actually running.” That could include the addition of solvent to steam to reduce the overall steam to oil ratio, thereby enabling a reduction in facility or water-handling capacity, he said. Adapting and adopting technologies could also mean “taking modularity of construction that additional degree further than has been done so far, so you can take more construction work out of the field,” said Spence. “Those are the kinds of things
we focus on: what’s been done, what’s been done well and how can we take it that one extra step.” For Will Roach, president and chief executive officer of Cavalier Energy Inc., which is developing the Hoole project in the Grand Rapids Formation, a key technology would be improving steam distribution along the wellbore, thereby increasing the well length. “If you do that, you are going to save a substantial amount of money in the overall field development,” he said. “That’s one we pay quite a bit of attention to, watching what other people are doing.” That technology, Roach suggested, would apply quite early in the field development in the Grand Rapids because of the homogeneous nature of the reservoir. When it comes to project execution, the focus could include the highest degree
Northeastern Alberta
of engineering completeness before going to the field, said Howard Lutley, president and chief executive officer of SilverWillow Energy Corporation. By the end of this year, the company expects to file an application
for a 12,000-barrel-per-day in situ oilsands project at Audet. Lutley, whose group specializes in early-stage projects, also advises working with experienced engineering construction
teams that have done it a few times. That way, “you have high degree of assurance that partway through the project you’re not having to go to the market for another $100 million.”
Canadian Natural reports first steam at Kirby South Canadian Natural Resources Limited announced in September that fi rst steam injection was achieved at its 100 per cent owned and operated Kirby South steam assisted gravity drainage project. The Kirby South project was completed on budget, with a forecast addition of production at approximately $30,000 per flowing barrel, and ahead of the originally targeted steam-in date of November. Kirby South is targeted to grow to approximately 40,000 barrels per day of
production by the end of 2014 and is the first step in a staged expansion plan for the greater Kirby area, targeted to increase Kirby area production over time to approximately 140,000 barrels per day. Canadian Natural’s current overall thermal in situ development plan targets to increase facility capacity from current levels of approximately 170,000 barrels per day to approximately 510,000 barrels per day in staged increments over the next 15 years.
“The successful completion of construction and commissioning of the Kirby South project demonstrates the strength of our teams and our ability to effectively and safely execute on our projects,” Steve Laut, president of Canadian Natural, said. “Kirby South is the next piece in our long-term growth plan for our thermal in situ assets, increasing the size of our long life, low-decline asset base and enhancing our already strong ability to generate free cash flow in the near and long term.” — DAILY OIL BULLETIN
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35
CENTRAL ALBERTA WELL ACTIVITY SEP/12
SEP/13
Wells licensed
187
SEP/12
SEP/13
Wells spudded
268
SEP/12
SEP/13
272
Rigs released
C.A.B.
▲
▼
Central Alberta
▼
Source: Daily Oil Bulletin
Penn West’s Cardium spending to double By Pat Roche
Photo: Joey Podlubny
Penn West Petroleum Ltd. is roughly doubling its 2013 capital allocation for the Cardium and will double spending in the company’s flagship play again next year. The company cut its allocation for the Spearfish tight oil play at Waskada, Man.— where it has suspended drilling—by $87 million, said Dave Roberts, the former Marathon Oil Corporation chief operating officer who became Penn West’s president and chief executive officer in July. Penn West has reallocated $40 million of that amount to the Cardium and the remaining $47 million to the Viking tight oil play in Saskatchewan, Roberts told the Peters & Co. Limited 2013 Energy Conference in Toronto. The $40-million increase will push Penn West’s total 2013 Cardium spending to $70 million to $80 million, and “I expect that figure will be at least double next year,” Roberts said. Roberts’s appointment was part of a major overhaul at Penn West. The
company, which has been stymied by poor production growth and high costs, has made a string of management changes since late last year and eliminated about 500 jobs. Under the original 2013 capital plan, drafted under former chief executive officer Murray Nunns, 30 per cent—the single biggest allocation in the $900-million budget—would have gone into the comparatively small Manitoba play while the Cardium—where Penn West holds the industry’s top land position—would have gotten only 13 per cent. One of the criticisms of Penn West under its previous leadership was the relatively small amount of growth it achieved for the amount of capital deployed. “We have a long ways to go in this particular area,” Roberts said, but noted significant progress that has been made recently. In the Viking program, “we have some outstanding competitors around us that frankly make us look pretty bad. And
The reallocation of capital means Penn West will be spending up to $80 million in the Cardium in 2013.
really, in the fi rst 60 days we’ve studied them.... We have taken the lessons from some of those competitors, and we’ve taken our costs on an average well...in the Viking from $1.35 million to $1.1 million,” he said. He added: “I expect the same kind of cost reductions in the Cardium play.” While the Spearfish at Waskada continues to be a major part of Penn West’s portfolio, the current focus is on the Cardium, the Viking and the Slave Point carbonate light oil play in north-central Alberta. Penn West has a strong position with a “lot of running room” in the Slave Point, but that carbonate play is in its early days and “we’ve got to do better in terms of our well costs,” Roberts said. Most of Penn West’s 2013 Slave Point spending will be on waterfloods in the second half of the year, he said. The Viking, meanwhile, is “a great bridge asset for the next three to five years to get us to the future that we envision,” he said after noting it’s “not a company maker for Penn West because of our size.” That’s in contrast with his vision for the Cardium, where Penn West has 600,000 net acres. “This is a company that’s built around the Cardium.... If we can’t do the Cardium well, then Penn West doesn’t do well,” Roberts said. “And it’s one of the things that we’re going to focus in on—both improving our drilling costs, drilling longer wells, drilling better wells, and also, importantly, being serious about pressure maintenance on this reservoir from the beginning.” He expects Penn West to be busy in the Cardium for the foreseeable future: “This is the play where we think we can operate four to six rigs probably as long as the rest of my career here. And we’re going to work more effectively with our partners here to make sure we get the maximum out of both our operated and non-operated asset base.” OIL & GAS INQUIRER • NOVEMBER 2013
37
Central Alberta
Edson-area Wilrich cranking up By Carter Haydu
The Edson-area Wilrich is an important and growing part of the portfolios for at least two companies presenting at Peters & Co. Limited 2013 Energy Conference. Paul Wanklyn, president and chief executive officer at Cequence Energy Ltd., told the conference his company has about 31 sections of land in the Edson/ Ansell-area Wilrich play, where there has been “just a flurry of industry activity” recently, largely driven by Perpetual Energy Inc. He said his company’s recent 15-14 well delivered a 60-day initial-production rate of 5.9 million cubic feet per day, and all of Cequence’s lands in the area are proving quite prospective. The company is currently drilling its fi rst step-out well at the location at 14-19. “We brought in a partner, and they will be carrying us largely through the evaluation phase of this play, so we’re in a pretty good position to be carried along for a
38
NOVEMBER 2013 • OIL & GAS INQUIRER
number of wells as we evaluate the size and quality of this discovery.” Susan Riddell Rose, president and chief executive officer at Perpetual, said that one of the top priorities in 2013 for her company is positioning for growth in those Edson liquids-rich gas assets, hopefully building on stronger gas prices next year and beyond. “The Wilrich is our second key priority and the other area where we are investing aggressively for growth,” she said, adding at West Edson the company has increased compression capacity to 30 million cubic feet per day. “When we start up our stand-alone gas plant in late September or early October, we’ll actually see the wells we’re drilling now start to fill that infrastructure. We should cap out in December at the full capacity of the infrastructure—15 million cubic feet per day net to us. So West Edson economics are very attractive to us,
and we think there is a 200 per cent rate of return.” According to Wanklyn, Cequence will also be drilling the Wilrich at Simonette this autumn, after about two years without having drilled a well in that play in that particular field. “We had a couple of very good Wilrich wells early in our program, and we followed up to the north where the pressure is significantly lower. We had the luxury then of drilling Montney wells in the southern part of that block...and the geological information we’ve uncovered from the Montney drilling has really given us a lot of confidence to head back south and drill our next Wilrich step-out there. “We think we have about 20 sections that could be exploitable.” At Simonette, Cequence also owns about 87 net sections of Montney lands. The biggest shift Wanklyn said his company intends to make for that particular
Central Alberta
Montney location over the next two years is a switch to pad drilling, with the first fourwell pad at 07-29 currently underway. “So this is going to be a chance for us to see how low we can drive our costs and how efficient we can start to recycle capital,” he said, adding Cequence has a second rig drilling about eight kilometres southwest of the 07-29 pad. “We expect to keep those two rigs fairly busy through the course of the winter.” While gas assets remain important for Perpetual, Riddell Rose said the decadeold company has worked to transform itself from a shallow gas producer to one with more diverse opportunities for the past four years. “We’ve gone through a very significant transition and we have come out the other side of that with an asset base we think positions us well for growth in a resourcestyle type of fashion,” she said. “We’re very entrepreneurial in our approach and value oriented.” Riddell Rose said Perpetual began drilling fairly thin horizontal zones of heavy oil
in recent years, costing about $1 million per well and with limited foresight as to how those wells would translate into returns.
“[Drilling thin horizontal zones of heavy oil has] turned out to be fairly prolific, so we now have 12 pools in multiple formations, and 200 million barrels of oil represented in there.” — Susan Riddell Rose, president and chief executive officer, Perpetual Energy Inc.
“It’s turned out to be fairly prolific, so we now have 12 pools in multiple formations, and 200 million barrels of oil represented in there. Rates per well tend to be about 80 barrels per day, so very productive and concentrated activity,” she said,
adding the company’s top priority in 2013 is maximizing value from its Mannville heavy oil assets. “We’re excited about this area with what not only we can do today on primary development, but also what the enhanced oil recovery [EOR] potential is.” At its Upper Mannville ‘I2I’ Sparky pool is the company’s furthest-along EOR project, Riddell Rose said, adding the project should be on the initial stages of waterflooding by the end of 2013, and into a polymer flood by late 2014. “There’s a very significant upside, I think, with the EOR potential,” she said, adding that for the end of 2013, the company had booked about 2.1 million barrels of proved plus probable reser ves for this year among Perpetual’s largest pools (Sparky, Upper Mannville A, Upper Mannville B, Sparky O). However, with EOR she said the company expects to recover 16 million to 18 million barrels from these pools alone. “So there is lots of growth in terms of reserve booking down the road.”
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Central Alberta
Duvernay to drive Encana’s future liquids growth By Paul Wells
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Encana Corporation remains confident that its early-stage Duvernay play will be a key catalyst in the company’s efforts to increase its liquids weighting in the coming years. Speaking at the Peters & Co. Limited 2013 Energy Conference in Toronto, Encana’s vice-president of the northwestern business unit, Kevin Smith, said the company’s 50 per cent joint-venture Duvernay program with PetroChina Company Limited is a critical component to future growth plans. “This is an incredible asset. It’s very early days, but we’re very encouraged,” he said. “We expect that over the longer term, this asset will be contributing to Encana’s liquids growth and balancing our portfolio.” Smith said the joint-venture partners, who plan to spend about $4 billion in the Duvernay over the next four years, have just over nine million barells of oil equivalent of estimated petroleum in place, “which we estimate to be about 10 per cent of the resource in place in the commercial fairway” in the Duvernay. “That translates to about 1,600 gross well locations...across our resource asset base in the Duvernay. We’re working to defi ne the
“ We think these [the highest-return areas of the Duvernay] are the types of areas where once we get to more of a resource play hub development, it will strongly drive the growth as well as the liquids returns.” — Kevin Smith, vice-president of northwestern business, Encana Corporation
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sweet spots while continuously driving down our cost structure as we do so,” he said. “We want to make sure that what we’re doing is targeting the highest-return areas of the Duvernay for initial development.” Earlier this year, the company announced one of its Duvernay wells in the Simonette area came on with a restricted 30-day initial production rate of 1,400 barrels per day of condensate and four million cubic feet per day of natural gas. Smith noted that five months later, the well is still performing well. “We’ve produced that well for about five months now, and it’s currently producing through constrained infrastructure at 3.1 million cubic feet per day and 630 barrels per day of free condensate. So in the fi rst five months, we’ve produced cumulatively 0.36 billion cubic feet and over 100,000 barrels of free condensate,” he said. “We think these are the types of areas where once we get to more of a resource play hub development, it will strongly drive the growth as well as the liquids returns.” Smith and Encana firmly believe that the Duvernay will live up to its early hype. “The Duvernay reservoir is fairly continuous and contiguous in nature and demonstrates a lot of the same characteristics that compare very favourably with the leading shale plays in North America, especially the Eagle Ford liquids-rich play in Texas,” he said. “Over the next couple of years I believe we’ll see the potential of the Duvernay materialize as we’ve seen in the Marcellus and the Eagle Ford.”
Central Alberta
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Madalena Energy fast facts Paddle River core area: 200 gross sections 150 net sections Ostrocad: 57 net sections 50 horizontal locations 12-05 well: 547 boe/d test 08-05 well: 719 boe/d test 01-05 well: 307 boe/d IP30 Stacked Mannville (Notikewin and Wilrich): 130 net sections 100+ horizontal locations 06-27 well: 384 boe/d IP 30 (14 per cent liquids) Nordegg: 145 net sections 200 possible horizontal locations Duvernay: 100 net sections
Source: Madalena Energy Inc.
This horizontal well is currently shut-in, and operations to equip the well for production and tie in the solution gas to existing Madalena facilities are underway. The company anticipated that this horizontal well will be brought on stream in October. Madalena has a large land base of over 150 net sections in the Greater Paddle River area of which the company controls approximately 60 net sections of land across the Ostracod oil trend and has a significant inventory of drill-ready horizontal locations for Ostracod development. While Madalena is very encouraged by the initial results from this horizontal well, the flowback information disclosed above should be considered preliminary and is not indicative of the well’s long-term performance. Ongoing technical work and operational enhancements continue to improve the company’s understanding of the ultimate potential of its Ostracod oil play with further optimizations being made via the drilling and completions execution.
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SOUTHERN ALBERTA WELL ACTIVITY SEP/12
SEP/13
Wells licensed
88
SEP/12
SEP/13
Wells spudded
94
SEP/12
SEP/13
96
Rigs released
▼
▼
▼
Source: Daily Oil Bulletin
S.A.B. Southern Alberta
Industry supports sage-grouse protection order By Carter Haydu
Photo: Alberta Wilderness Federation
A federal commitment to protect the few greater sage-grouse left in southern Alberta and Saskatchewan has garnered both support and cautious optimism from industry and conservation groups concerned about the bird. “It’s the right thing to do, so let us get on with it,” Alex Ferguson, vice-president of policy and environment with the Canadian Association of Petroleum Producers, said. “We’re supportive of protecting those species—there is no question about that.” In September, Federal Environment Minister Leona Aglukkaq announced the government’s plan to introduce an emergency protection order for the greater sagegrouse at some point in the months ahead. According to the environment ministry, the greater sage-grouse depends on the unique prairie ecosystem of southeastern Alberta and southwestern Saskatchewan. Its population has declined by nearly 98 per cent since 1988, and there are less than 150 birds now remaining in Canada. The intent of the federal order is to impose obligatory restrictions designed to protect the sage-grouse and its habitat on provincial and federal Crown lands in Alberta and Saskatchewan. There will be no restrictions on activities on private land, nor
Fewer than 150 greater sage-grouse remain in Canada.
will there be restrictions regarding grazing on provincial or federal Crown lands. The order will be issued under the Species at Risk Act, which aims to prevent wildlife species from being extirpated or becoming extinct. The act also provides for the recovery of wildlife species that are extirpated, engendered or threatened as a result of human activity, as well as managing especially concerning species so as to prevent endangerment or threatening. Environment Canada media relations advisor Mark Johnson said the federal government began taking steps to protect the sage-grouse several years ago, but recent rapid declines in the population prompted the minister’s determination that the species faces an imminent threat, and therefore introducing an emergency order seemed like the logical next step in protecting the bird’s future in Canada. “An order would be designed to address the needs of the species while minimizing the potential impacts on Canadians whose livelihood depends on working the land,” he said, adding government officials are in the fi nal stages of drafting an order and ensuring all of the technical details are correct. He suggested publication of the order in the Canada Gazette should occur within the next few months. However, Cliff Wallis, vice-president of the Alberta Wilderness Association, says he is hopeful the emergency order will take effect sooner and will bring appropriate restrictions for the habitat. “So there would be no new industrial activities, no new sod-busting that would happen on those lands,” he said. “What happens to the existing oil and gas activity? I’m not sure.”
According to Wallis, there are practical means of ensuring responsible economic activity from industrial activity with limited impact on the endangered species, while pulling back activity that is harming the sage-grouse habitat. He said the petroleum industry can be receptive to the protection of endangered species, but he believes such receptiveness can also be compromised if there is not regulatory clarity that prevents the pressures of competition from encouraging one company to develop, thus encouraging all other companies to follow suit. Wallis said he hopes the upcoming order provides the transparent rules necessary for companies to do their part in protecting the species. “I certainly think the order should bring clarity and it should bring clarity quickly, because this is a crisis for the species in Canada. We’ve been at this for many years through the courts, and the federal government has certainly been late to the table.” Oil and gas production poses a particular problem for nearby sage-grouse, according to Wallis, because these prairie birds have not evolved the ability to handle structures on the landscape. He said: “Certainly structures do things like attract predators—ravens and nesting hawks—that may prey on the young, or the nests, or the [adult] birds themselves. [Petroleum] activity seems to cause issues, and so [sage-grouse] tend to shy away from those areas where you have activity. “The actual physical roads are sources for non-native plant invasion into their habitat, and so it starts to change the habitat, and they’re also travel pathways for predators and other species you don’t want in there.” Ferguson noted that restricted access to the resources on lands subject to the impending order is not just a matter impacting oil and gas producers, but any industry that might otherwise freely use these lands. OIL & GAS INQUIRER • NOVEMBER 2013
43
Southern Alberta
Government orders Crew Energy to shut down Suffield well The Alberta government has ordered an energy company to stop operating an oil well near Suffield and reclaim the site due to violations under the Public Lands Act. According to the province, Crew Energy Inc. constructed an active oil well in contravention of regulated setback limits that protect ferruginous hawk populations. Provincial legislation prohibits high-risk developments within 1,000 metres of active nests to minimize danger to the birds and their offspring. “Alberta’s enhanced approval process requires all companies to complete a wildlife survey prior to development—in this case, the survey was not comprehensive enough and did not identify the hawk nest on the site,” the government said. The company’s mineral surface lease at the site is cancelled. It must submit a plan to Alberta Environment and Sustainable Resource Development to restore the site to its original condition and submit a fi nal report when reclamation has been successfully completed.
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In response, Crew Energy confirmed it received an enforcement order, dated September 12, to restore and reclaim a surface lease in the Suffield area of Alberta. The lease is approximately 600 metres from a ferruginous hawk nest built on a man-made structure: a windmill. The regulated setback of an active nest is 1,000 metres. “Crew practices sustainability and recognizes the importance of cultural, wildlife and environmental protection,” the company stated. “In its pre-drilling assessments, Crew utilizes archaeologists, agrologists and biologists as environmental auditors to ensure that Crew meets or exceeds all regulations with respect to culture, wildlife and the environment.” The original assessment of the lease did not identify a hawk’s nest within the setback prior to the lease construction in January 2013, the company stated. Crew later identified that two hawks were nesting in the area and in the interest of protecting the hawk habitat, the company
In its pre-drilling assessments, Crew Energy utilizes archaeologists, agrologists and biologists as environmental auditors to ensure it meets or exceeds all regulations with respect to culture, wildlife and the environment.
said it shut in the well on July 24, 2013, when it was producing approximately 12 barrels of oil per day. “Crew plans to diligently work with the department on the protection of the ferruginous hawk habitat in the area.” — DAILY OIL BULLETIN
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NOVEMBER 2013 • OIL & GAS INQUIRER
Southern Alberta
Arsenal Energy finds success at Princess Arsenal Energy Inc. drilled four wells at Princess, one well at Chauvin, one (0.5 net) well in the Alberta Deep Basin and completed four (0.25 net) Bakken wells at Lindahl in North Dakota in 2013. At Princess, Arsenal Energy has drilled four wells, resulting in two oil wells, one gas well and one suspended well. The company drilled a vertical exploratory well testing a half-section structural closure identified on seismic. The well has been on production for approximately two weeks at 90 barrels per day. The company has identified six follow-up locations. Three Glauconite horizontals have been drilled. One tested at three million cubic feet per day of gas and the other two will be completed and tested prior to quarter-end. At Chauvin, Arsenal Energy drilled and completed its first Leduc horizontal well. It swab tested at 110 barrels of oil per day. Arsenal has identified six follow-up locations and drilled a similar prospect at Edgerton, Alta., in 2012. That well continues to produce
4,400 boe d /
Arsenal’s expected 2013 exit rate
at approximately 30 barrels per day. The company has identified 10 follow-up locations on that property. At Columbia in the Alberta Deep Basin, Arsenal has participated for a 50 per cent working interest in a horizontal exploration test of the Falher Formation. The well will be completed in the third quarter and is expected to be placed on production in the fourth quarter. Results will be released at that time. In North Dakota four (0.25 net) Bakken wells were fracked and placed on production at Lindahl. The wells are performing typically of other Bakken wells in that field. Arsenal has begun permitting work on two (1.7 net) Bakken wells at Stanley and one (0.65 net) Bakken well at Rennie Lake. It is anticipated that those wells will be drilled in early 2014. Arsenal is maintaining 2013 exit-rate guidance at 4,400 barrels equivalent per day, but is increasing cash-flow guidance for 2013 to $44 million due to higher realized oil prices. — DAILY OIL BULLETIN
OIL & GAS INQUIRER • NOVEMBER 2013
45
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SASKATCHEWAN WELL ACTIVITY SEP/12
SEP/13
Wells licensed
284
SEP/12
SEP/13
Wells spudded
368
SEP/12
SEP/13
364
Rigs released
▲
▲
Source: Daily Oil Bulletin
S.K. Saskatchewan
Low-cost waterflood may increase Viking recovery rate By Elsie Ross
Photo: Joey Podlubny
Privately held Beaumont Energy Inc. is looking to horizontal infill drilling and a reactivated waterflood to boost recovery rates at its Viking light oil pool at Kerrobert, Sask. The company believes it can increase the recovery rate of the pool to 20 per cent from three per cent, president and chief executive officer Bob Chaisson told the Peters & Co. Limited Energy Conference. “It’s a great little pool we’ve got our hands on,” he said. “It’s a 600-million-barrel pool that we feel has got a 120-million-barrel
prize [at a 20 per cent recovery factor] sitting there.” Accounting for cumulative production of 19 million barrels, Beaumont sees between 95 million and 125 million barrels of recoverable oil at a recovery factor of between 20 per cent and 25 per cent. Beaumont will spend $80.3 million this year on drilling 65 horizontal wells and spent another $5.1 million on the first phase of its waterflood, converting 38 vertical wells to injectors at $40,000 per well, the conference heard.
Like in the Bakken and Shaunavon plays, producers are now looking toward enhanced recovery techniques to pull more oil out of the Viking play.
Plans call for a total of 676 horizontal wells (440 producers and 236 injectors) to be drilled over the next eight to 10 years. Full development will also include 25 vertical producers and 343 vertical injectors. The company bought the 74.3 sections (70.4 net) for $110 million in December 2012 and has grown production to 2,500 barrels of oil equivalent per day (95 per cent liquids) from just under 700 barrels per day, he said. Forecast average production for the year is 1,700 barrels per day with an exit rate of between 3,300 and 3,500 barrels per day. “We will at the end of this year have every molecule on production—all the gas, all the NGLs [natural gas liquids] and all the gas tied into the existing facilities.” “We’ve got 676 horizontal wells to drill, and we’ve drilled a lot of horizontal wells,” he said. The core of the pool has infrastructure in place with 870 vertical wells already pipeline connected. There are two batteries in the middle of the pool that can handle 6,000 barrels per day and because the pool is directly tied into an Enbridge Inc. pipeline, Beaumont currently doesn’t need to truck any oil, although that could change as production rises. A major cost advantage is royalties averaging 1.6 per cent. Crown royalties are 2.5 per cent for the first 38,000 barrels of production while most of the remaining block is fee simple lands that Beaumont owns outright. Although there are another six sections of freehold land on which it would have to pay royalties, it hasn’t yet drilled on those lands. So far this year, Beaumont has drilled 40 horizontal wells with 35 on production. The hydraulic fracture crews are following right behind the drilling rigs, he said. It takes about 17 days from spud to on production. “We’ll drill two wells every eight days and fracture two wells the next week.” Beaumont also has driven down the total cost of its horizontal wells during OIL & GAS INQUIRER • NOVEMBER 2013
47
Saskatchewan
“It’s costing us one million bucks a section to double the recovery factor for what we were going to get on primary.” — Bob Chaisson, president and chief executive officer, Beaumont Energy Inc.
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the year from $1.05 million ($418,000 to drill) in the first quarter to $920,000 ($370,000 to drill) in the second quarter. The estimated cost for 2014 is $860,000, which includes lower equipment costs, the conference heard. The company bought a lot of equipment such as bigger pumpjacks and separators for the fi rst year of the horizontal wells’ production, and that will be moved to the drilling program for next year. The smaller pumpjacks from the vertical wells converted to injection wells will be put on the horizontal wells after they have been on production for about one year. Beaumont believes the program of converting vertical wells to injectors is repeatable “year after year after year,” said Chaisson. The five-section area includes a 3.5-section block with 80 wells that had been affected by a waterflood that was in operation for 14 years ending in 1999. There is a distinct difference in the recovery rates for those wells and the other 950 wells that were not on waterflood, he said. The company has a three-year development plan for its waterflood, which will use an oriented line-drive system. It will line up all its injector wells northeast-southwest and will drill its horizontals in the same direction. Another 65–90 horizontal wells will be drilled in 2014 with another 65–90 wells in 2015. Beaumont plans to inject water for a year before following up with a drilling program. “It’s costing us one million bucks a section to double the recovery factor for what we were going to get on primary,” said Chaisson. “The waterflood reserves are so cheap.”
NAL and WestMan target Manitoba’s Spearfish play
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NOVEMBER 2013 • OIL & GAS INQUIRER
NAL Resources Limited and WestMan Exploration Ltd. have entered into a farmout and equalization agreement focusing on developing the Spearfish-Amaranth light oil play in the Pierson and Waskada areas of Manitoba. Under the terms of the agreement, NAL will spend up to $17.5 million on drilling activities in two earning phases on WestMan’s southwestern Manitoba lands (approximately 39,000 net acres of mineral rights) through to Sept. 30, 2014. Drilling is expected to begin next month. NAL and WestMan have identified the potential for more than 500 low-cost, multi-well drilling locations on WestMan’s existing land base. NAL has committed $10 million to prove up the play and earn a 30 per cent working interest in all mineral rights, facilities and existing production of WestMan, with an option to spend another $7.5 million to earn another 30 per cent for a total of 60 per cent of all of WestMan’s mineral rights, facilities and existing production.
Saskatchewan
Upon success of the initial drilling program, NAL expects to grow and maintain production in the new core area to more than 3,000 barrels per day by 2017. “This is an excellent opportunity to add value and growth to our company and we look forward to working with WestMan on this project,” Kevin Stashin, president and chief executive officer of NAL, said. NAL is a private oil and gas company, with sales of approximately 18,000 barrels equivalent per day, from its core areas of southern Saskatchewan, central and northwestern Alberta. NAL is an indirect subsidiary of Manulife Financial Corporation.
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Drilling success in southeast drives Renegade growth Recent drilling success has helped Renegade Petroleum Ltd. achieve current production of approximately 7,550 barrels equivalent per day (95 per cent light oil), based on field estimates. The company’s average output for the second quarter was 7,111 barrels per day. Renegade now has initial results on six (4.1 net) wells that were drilled post breakup in southeastern Saskatchewan with a 100 per cent success rate. Of these wells, five (3.6 net) are located in the Queensdale area targeting the Frobisher-Alida formation and one (0.5 net) well is in the Crystal Hills area targeting the Souris Valley Formation. Four of the six gross wells have production history in excess of 30 days, with an average 30-day initial-production rate of 241 barrels per day. The average drill, complete and equipping cost for the six gross wells was approximately $1.2 million each. In addition, Renegade has drilled, and is in the process of bringing onto production, one (0.97 net) well in the North Cantal area and one (0.75 net) well in the Gainsborough area.
Renegade Petroleum Saskatchewan fast facts Williston Basin 199 net sections 242 booked drilling locations 133 unbooked potential drilling locations Current production: 5,171 boe/d Target formations: Souris Valley, Tilston, Frobisher, Alida Viking 16 gross sections 81 booked drilling locations Current production: 3,351 boe/d
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49
Saskatchewan
The company also plans to drill its fi rst well in the Silverton area in early October. Renegade remains active in southeastern Saskatchewan and will have one rig operating in the area throughout the remainder of the year. In the Viking play in west-central Saskatchewan, Renegade completed the drilling of its 14-well (13.5 net) summer program with a 100 per cent success rate and has been staging the completions throughout the late summer and early fall. All wells have now been completed and are in various stages of post-fracture stimulation, cleanup and being brought on production. Results from the company’s Viking program are consistent with management’s expectations in respect of both production rates and all-in costs. Renegade has assembled a large inventory of light oil–focused drilling locations and currently holds in excess of 190,000 undeveloped acres across its asset base. — DAILY OIL BULLETIN
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NOVEMBER 2013 • OIL & GAS INQUIRER
A five-well oil drilling program in Pierson, Man., targeting the Spearfish Formation was completed early in the third quarter on schedule and under budget, Questerre Energy Corporation has reported. The wells were drilled as short radius horizontals and completed with 16-stage fractures per well. Over the first three days, the five wells produced at gross rates of more than 1,000 barrels of oil per day (350 barrels per day net to Questerre). Including these “Our light oil netbacks wells, the company’s production were in excess of $85 is currently in excess of 1,000 per barrel in July.” barrels per day. The drilling program, adja— Michael Binnion, president cent to existing production in and chief executive officer, Questerre Energy Corporation Antler, Sask., followed the drilling of two successful wells in the fourth quarter of 2012. Questerre holds a 35 per cent interest in all the wells. “We are very pleased with the initial performance of these oil wells,” Michael Binnion, president and chief executive officer of Questerre, said. “Our light oil netbacks were in excess of $85 per barrel in July. At current production rates, our operating cash flow before overheads is now over $2 million per month.” Questerre said it is leveraging its expertise gained through early exposure to shale and other non-conventional reservoirs. It has base production and reserves in the tight oil Bakken-Torquay of southeastern Saskatchewan and is bringing on production from its lands in the heart of the high-liquids Montney shale fairway. — DAILY OIL BULLETIN
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ince drilling in the Bakken Formation in southeastern Saskatchewan took off in 2007, nearly 2,700 wells have been sunk in the play. At year-end 2012, operators were coaxing around 72,000 barrels per day out of the tight rock. But drilling has plateaued in the play, as companies work to fine-tune completion techniques and implement enhanced recovery schemes to stem the huge declines common in tight oil plays. In 2012 operators completed 341 wells, with 356 wells completed in 2011, 517 wells in 2010, 432 wells in 2009, 728 wells completed in 2008 and 300 wells completed in 2007. While drilling has slowed in the play, there is still a lot of oil in place that will provide opportunities for many years to come as technological improvements continue to expand the geographical area where it is profitable, says Don Rawson, managing director of institutional equity research with AltaCorp Capital Inc. The primary region of development has been largely
52
NOVEMBER 2013 • OIL & GAS INQUIRER
defined, although the edges of the play have grown over time, as improving technology helps make it economic in some of the areas on the fringe. Trent Stangl, vice-president of marketing and investor relations for Crescent Point Energy Corp., agrees with this assessment. Crescent Point is the largest operator in the Bakken, with current production averaging around 60,000 barrels equivalent per day. St a ng l told a n aud ie nc e at EnerCom’s Oil & Gas Conference in August that Crescent Point is still in the early stages of development, having drilled a total of 1,300 wells into the tight rock since entering the Bakken in 2007. “We still have over 2,900 more wells to drill,” he said, including around 1,900 new drilling locations and around 1,000 infill wells. Crescent Point’s strategy in the Bakken and its other tight oil plays is simple, said Stangl. First, capture as much original oil in place as possible. “Then, increase the recovery factor doing simple things like infill drilling,
By Darrell Stonehouse, with notes from Daily Oil Bulletin staff
waterflood optimization and improved technology,” he explained. Crescent Point has 4.6 billion barrels in place in the Bakken, satisfying the company’s first requirement. Given this huge resource, Stangl said even small increases in recovery translate into huge additional reserves. The company has currently recovered 2.3 per cent of the 4.6 billion barrels of oil in place. It expects to recover 17–19 per cent of the oil in place using primary recovery techniques. From there, it expects to recover up to 30 per cent using waterfloods. “That’s better than a 50 per cent improvement,” said Stangl. Improved completions technologies have been the primary driver in increasing oil recovery to date, he explained. “We’ve seen massive technological change completions in this play, going from eight-stage surgi-fracs to eightto 16-stage mechanical or Packers Plus [Energy Services Inc.] fracs to today doing 25- to 30-stage cemented liner completions, and we continue to push
Photo: © iStockphoto.com/Kuzma
TIME
Southeastern Saskatchewan producers move to exploitation phase in the Bakken
Cover Feature
Annual southeastern Bakken oil production and producing well count
,
Total production: 118,100,000 bbl
,
Production in 2004: 760 bbl/day
,
Production in December 2012: 71,300 bbl/day
,
Well count
Oil production (million barrels)
,
Oil produced
Well count
Oil production (thousand barrels per day)
Southeastern Saskatchewan oil production
Light oil (Bakken)
Light oil (Excluding Bakken)
Medium oil
Sep `
May `
Jan `
Sep `
May `
Jan `
Sep `
Jan `
May `
Sep `
Jan `
May `
Sep `
Jan `
May `
Sep `
May `
Jan `
Month
Total Mississippian oil production
Total OilProduction: 426 million M3 Total oil production: Total Production Wells: 25 024 436 million cubic metres
Ratcliffe Midale
Total production wells: 25,024
Frobisher FrobisherAlida Alida
Alida-TilstonSouris Valley
Tilston
Souris Valley
Alida-Lower Watrous
Bakken
Year
Million cubic metres
new technologies,” he said, adding that as a result, “our EUR [estimated ultimate recovery] has gone from 75,000 barrels per well in 2009 to 225,000 barrels today.” Stangl said infill drilling is the cheapest way to add production and reserves, and is a major focus of the company. The next step in the strategy is putting as much of its Bakken acreage as possible under waterflood, he said. Crescent Point began testing waterfloods in 2007 with one injection well and two producers. It now has over 50 injectors impacting 100 producing wells and over 5,000 barrels per day of production. It is now working to unitize four areas of the Viewfield Bakken play in an effort to increase recovery and stem the high decline rates common in tight oil plays. Early in the third quarter, the Saskatchewan government gave the technical approval for the fi rst of the four proposed unitizations. “It allows us to continue moving forward, “ said Stangl. Ultimately, if the four unitizations are approved, Crescent Point expects to have 200 sections of land covering over one billion barrels of oil in place on waterflood. If successful, it expects to recover up to 300 million barrels from the four areas targeted. Legacy Oil + Gas Inc. is also using waterfloods on its Bakken properties at Heward and Taylorton, as well as on its Three Forks–Spearfish play in Manitoba. “The secondary recovery component is big, meaningful and it’s going to make it so much easier to manage this business,” said Trent Yanko, president and chief executive officer of Legacy, at a recent Peters & Co. Limited conference in September. Yanko estimated Legacy’s corporate decline rate at 32 per cent in 2012. “A waterflood gets us off the treadmill and changes the corporate decline,” he explained. “It either flattens it, or we’ve actually seen production increase on our waterflood pilots. It also generates free cash flow. With current oil pricing in 2013, we’re on track to spend cash flow and still grow by 20 per cent this year. We’ve been pushing waterfloods because they not only add reserves, enhancing your recovery factor, but they add value.” As Legacy has started pilot projects using waterfloods, it has seen 260–370 per cent
Source: Government of Saskatchewan
OIL & GAS INQUIRER • NOVEMBER 2013
53
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NOVEMBER 2013 • OIL & GAS INQUIRER
increases in production from the pilot areas, Yanko said. “If we can only f latten our production declines, every thousand barrels a day we have under waterf lood reduces our corporate decline by about 1.5 per cent,” he added. “It doesn’t take a lot to start turning things around. For us, it’s worthwhile, k nowing that no matter what you’re doing for the fluid, the pressure maintenance is having an impact, and having it quickly.” “We’re not having to face massive fill-ups, waiting years for a production response, like you would in a conventional, more depleted field. That’s why we’re getting after it as quickly as we can,” he said. Lightstream Resources Ltd., formerly PetroBakken Energy Ltd., is also in harvest mode in the Bakken. Lightstream has current production of around 17,000 barrels per day in the play. It has over 900 locations still to drill on a land position with an estimated 1.7 billion barrels of oil in place. The company has recovered around five per cent of the initial oil in place on its developed land. It expects to ultimately recover around 15 per cent using primary recovery methods. From there, it is developing natural gas flooding to capture more of the massive oil resource in place. “It’s early days in our natural gas flooding,” company president and chief executive officer John Wright told the Peters & Co. conference. “So far, we’ve just had the impact from our main commercialscale flood at Creelman, [Sask.]. It’s probably bumped up our production there by 150 barrels a day—effectively doubled production.” Lightstream began injecting gas into the Bakken at Creelman in southeastern Saskatchewan in February 2012. Earlier this year, the company said it would move to expand the flood to nine sections. Oil production in the field peaked at roughly 1,350 barrels per day sometime in 2008, according to the company’s website. Comparing natural gas flooding to CO2 flooding at places like Weyburn, Sask., Wright said oil production from Weyburn is currently declining at about two per cent per year, while undergoing a massive CO2 flood. “I think that ’s what we’d hope to ultimately see in our gas flooding, as well. To get the decline rates down to low single digits and significantly extend the reserve life,” he said.
Cover Feature
L ight st rea m bel ieves i f t he natural gas f looding is successful, it could lift recover y factors in the Bakken to higher than 25 per cent, or to more than 425 million barrels. Outside the Bakken, activity also remains strong in conventional oil plays in sout heaster n Saskatchewan. T he Mississippian play remains a driving force in the province’s oil output, averaging around 120,000 barrels per day in 2012. Lightstream accounted for around 5,600 barrels per day of that production. It has around 350 locations identified for further development. Strong initial production rates and low- cost d r i l l i ng a nd complet ion s, according to Lightstream, drive the economics of the Mississippian play. Initial 30-day production rates average around 100 barrels of oil per day. Costs to drill, complete, equip and tie in wells come in at around $1.4 million compared to around $2.9 million in the Bakken. Mississippian wells have ultimate recovery of around 78,000 barrels. Legacy is also active in the Mississippian, operating two play types. In its conventional operations it has over 350 locations targeting the Souris Valley, Tilston, Alida, Frobisher and Midale zones. In the Steelman/Pinto area, Legacy is taking a unique approach to the Midale, using horizontals with multistage fracturing technology on the conventional reservoir. So far the results speak for themselves. In the fall of 2012, two wells drilled in the play had initial 30-day production rates of 665 and 897 barrels equivalent per day. In the fi rst quarter of 2013, 10 additional wells were brought on stream with average production of 245 barrels per day for the first month for each well. Three successful wells were put on production in the second quarter of 2013. Average 30-day initial production rates from these wells were 260 barrels per day per well. With the commissioning of the new Steelman battery and tie-in of the wells, area production of 3,500 barrels per day was achieved in April 2013, Yanko reported to shareholders. “Two years ago, production from the Steelman area was approximately 350 barrels equivalent per day,” he added. The unconventional wells come in at a total cost of $2.25 million, with estimated ultimate recovery of around 125,000 barrels per well.
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www.ecoquip.ca OIL & GAS INQUIRER • NOVEMBER 2013
55
Feature
breather Taking a
After a decade of steady growth, activity in Manitoba’s oilpatch set to plateau in 2013
Photo: Joey Podluby; Illustration: liravega/photos.com
By Godfrey Budd
56
NOVEMBER 2013 • OIL & GAS INQUIRER
Feature
T
he Town of Virden (population 3,114) on the TransCanada Highway in the southwestern corner of Manitoba has a diversified economy that includes agriculture and chemical manufacturing, but most of the exponential growth the town has seen in the last few years has been due to the region’s oilpatch activity. There has been a spurt in housing starts, with a new subdivision developed by the town selling all its units within a year. Since about 2006, the population has been growing at an average of three per cent per year. Of late, Virden has been encountering some of the challenges seen elsewhere when a region’s energy sector experiences a sharp upswing in activity—not enough rental accommodation to meet demand as more people find work in the local oilpatch and a labour shortage in the hospitality sector. “A lot of oil-related service companies have been moving in and the town’s industrial park is now filled pretty much, except for a couple of lots,” says Ed Brethour, the economic development manager for the Town of Virden. The town has been taking various measures to cope with the demand, and may consider extending the town’s boundary. But a new subdivision, Brethour points out, takes two to three years from initial planning to putting lots on the market, and increasing the water supply can take five to 10 years. “Virden has many similar problems of any boom town. We’re trying to do all that’s needed in a tight fiscal envelope. Before this, we had some aging infrastructure, and now we have to catch up,” he says. In the meantime, people commute from neighbouring small towns, but some are travelling to work every day in or near Virden from as far away as Brandon, Man., a 150-kilometre round trip. More than 90 per cent of oilpatch activity in southwestern Manitoba is focused on two main areas. One is southwest of Virden with drilling into the Torquay and Bakken formations in the Daly Sinclair Field. Further south, closer to the town of Waskada, Man., operators have been drilling into the Lower Amaranth in the Waskada and Pierson fields.
The fi rst producing well of the entire Williston Basin was a discovery well in the Daly Field in 1951, according to the Manitoba Geological Survey. This was in the Lodgepole, a Mississippian formation above the Bakken. Overall, crude oil production increases in Manitoba have been on a tear since 2004-05, when the provincial total jumped from 637,000 barrels for 2004 to 812,000 in 2005. By 2008, production had climbed to 1.37 million barrels. In the 2009-12 period, production continued upward, from 1.52 million barrels to 3.05 million barrels, reflecting the robust levels of patch activity during those years. In 2009, 296 drilling licences were issued with 260 new wells drilled. In the following years, those numbers were, respectively, 632 and 510 for 2010, 672 and 578 for 2011, and 720 and 616 for 2012, according to figures from Manitoba Innovation, Energy and Mines. As one might expect, a high percentage of new wells are horizontal—207 (260 total) in 2009, 436 in 2010, 536 in 2011 and 570 in 2012. The metrics so far for 2013, however, are pointing in the other direction. As of September 23, drilling licences totalled 369 compared to 511 for the same period in 2012. Some 60 licences had been cancelled by September 23, compared to 27 for all of last year. A total of 398 wells have been drilled to date this year with 377 horizontals. By September 24 last year, a total of 453 wells had been drilled with 421 horizontals. Another significant metric has also been pointing south this year. Like Saskatchewan’s, Manitoba’s land sale revenue in 2013 continues to lag well behind last year’s. “Year-to-date, the province has attracted $1.64 million in bonus revenue for 3,503.62 hectares at an average price of $468.36, well off last year’s pace of $11.13 million in bonus bids paid to acquire 17,049.18 hectares at an average of $652.73,” as a story in the August 16 edition of the Daily Oil Bulletin noted following the third of the province’s four land sales for the year. The next sale is November 13.
OIL & GAS INQUIRER • NOVEMBER 2013
57
Feature
Manitoba’s oilpatch at a glance Drilling licences issued
2009
2010
2011
2012
296
632
672
720
New wells drilled
260
510
578
616
New wells on production
256
211
465
600
Horizontal wells drilled
207
436
536
570
Metres drilled
482,963
946,576
1,068,753
1,156,002
Wells capable of production (Dec.)
3,065
3,298
3,666
4,289
Wells producing (Dec.)
2,747
2,951
3,231
3,742
Avg. oil production (m3 per day)
4,166
5,133
6,492
8,218
Value oil sold ($)
632,000,000
879,386,554
1,366,288,850
1,600,018,360
Lease sale bonuses ($)
5,415,777
11,023,396
13,162,503
11,293,295
Expenditures ($ million)
485
894
1,228
1,448
Source: Government of Manitoba
Manitoba’s August 14 oil lease sale added $487,333.01 to provincial revenues. Rockwell Resources Inc., which so far has not shown up on the Innovation, Energy and Mines Petroleum Branch annual list of Manitoba’s top 25 producers, paid the highest price per hectare for a parcel located in the Manson area. One factor behind the drop in the province’s land sale revenues is simply that availability of choice parcels is perhaps not what it used to be, despite the $289,120 paid by Rockwell for a 64-hectare parcel in the August sale. Unlike in Alberta, where most of the petroleumrich lands belong to the Crown, in Manitoba, about 80 per cent of the desirable leases are privately owned. The government owns the remaining 20 per cent. “The figures that are reporting declining lease sales are government figures, and 20 per cent represents a modest slice of the pie.
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Sales are down partly as we don’t have much left,” says Keith Lowdon, director of the Petroleum Branch at Innovation, Energy and Mines. Also, some of the desirable acreage that does remain, he says, could be earmarked for wildlife habitat protection or pegged for potash development. Either scenario would present an obstacle to petroleum exploration and development. “It’s too early to say what effect this will have on the production curve. But there are quite a few leases in place that are already producing, and that are now being redeveloped with horizontal multistage fracking, so leasing might might not have an impact on production for some time,” Lowdon says. Nonetheless, 2013 could mark the first crude oil production decline for the province in a decade—but only a slight one. “We expect production this year to be close to last year’s,” Lowdon says.
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NOVEMBER 2013 • OIL & GAS INQUIRER
Feature
If production does in fact drop or flatline this year, two factors stand out as potentially pivotal. The first is that Penn West Petroleum Ltd., in 2012 the third biggest producer, accounting for 14.3 per cent of provincial production, behind only EOG Resources Canada Inc., at 15.4 per cent of production, and Tundra Oil & Gas Partnership with 40.4 per cent, has sharply curtailed activity in Manitoba since the spring. The other element that has been putting a crimp into oilpatch work this year has been the weather. A few days after Alberta’s summer solstice deluge and flooding, heavy rains hit southern Manitoba and homes were flooded in Virden. But earlier, the weather had been more than a little inconvenient. As soon as it was time for road bans to be lifted in some areas, it rained again. “It just got so wet the roads never dried out,” Brethour says. Lowdon also speculates that the Calgary flooding that closed offices for days or even weeks in some cases in the city’s downtown may have put the brakes on decisions to go ahead with projects in Manitoba. With the exception of Tundra, which is privately owned by the Richardson family of Winnipeg, most of the companies operating in Manitoba’s oilpatch are based in Calgary. Despite the relatively small size of its oilpatch in the southwestern corner of Manitoba, some of its infrastructure is old enough to raise concerns about pipeline integrity and the risk of oil spills. Several of the bigger operators have responded by announcing upgrades and new lines and, since 2010, hundreds of kilometres of pipeline have been built or proposed for the region. The absence of gas pipe infrastructure in some areas is also an issue, as associated gas from oil wells has to be flared. But, increasingly, this is being remedied. Lowdon says that a gas line is to be built next year so EOG will be able to send gas to a plant across the border in Saskatchewan. Although infrastructure projects pick up some of the slack, the service sector has metrics on the slowdown this year. “No one seems to be as busy as last year. We were typically running with about 12 utilized service rigs out of Virden. Now, about seven to nine are being utilized. And the hours are a little lower per rig,” says Pat Sinclair, an area manager with Precision Well Servicing. He adds that weather is still an issue, saying that rain has affected operations in southern Saskatchewan as well. Some in the service sector are finding activity levels very much the same as last year. “There’s been lots of work acidizing older wells, but fewer completions and we’ve seen fewer drilling rigs. Our work has been mostly in the Virden area. There’s been about the same level of activity as last year,” says Riley Brown, a supervisor with Prowell Stimulation Service Ltd. As the Manitoba oilpatch has boomed, bigger service sector outfits have moved in. They have made their presence felt, but not just by adding to the competition. Local outfits, some of them decades old, have sold to bigger players based outside the region. Randy Browning, with a couple of partners, had run Keystone Oilfield Services Ltd. for about 35 years before selling to Apex Distribution, where he is now a manager. Timing appears to have worked well for another long-time local businessman. Dennis Sparks, now retired, acquired a small service firm in Virden in 1996. Before selling to Carson Energy Services Ltd. in 2011, it grew from four to 45 employees over the 15 years. “We saw steady growth for the whole 15 years,” says Sparks. Based on the values of oil sold, the oil industry grew from $107 million to $1.4 billion over those years. The industry was worth $1.6 billion in 2012, according to Manitoba government petroleum statistics.
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59
The latest regional business news
Business
Intelligence Modularization, combined with rail, making oilsands construction a national business By Carter Haydu
Modular construction not only increases the link between oilsands operations and manufacturing sectors outside of Alberta, but it also allows for improved quality control, efficiencies through standardization, and a way to increase the buy-in central Canadians feel toward western Canada’s petroleum industry. This trend should improve as well, industry experts suggest, as rail becomes better equipped at moving large, prefabricated components across the country. Ken James, co-president and chief executive officer at Oak Point Energy Ltd., says his company has developed a full modular facility design, in which modular components are fabricated in Ontario and transported to the company’s oilsands site via rail. “So we’re barging the modules to Thunder Bay and then we can bring over-14foot-wide modules from Thunder Bay on rail all the way to Fort McMurray,” he says. “It is actually the easiest rail route and largest load route on rail, because you don’t have any mountains or major rivers to cross—it is flat prairie.” According to James, using rail to transport module components for use in the oilsands enables producers to access services from other jurisdictions outside of manufacturing-limited Alberta. “When I look at the oil and gas industry and I look at the oil price today, I say this should be a market that has runaway investments in Alberta. Unfortunately, we depend totally on the service sector of Alberta to expand growth. Of course, that means we are restrained by the availability for those service-sector resources.” The use of the railways enables
With modularization, major components of the facilities can be built off site, transported by rail and then installed.
oilsands companies to access labour and fabrication capability beyond Alberta’s borders and into Ontario and Quebec, he says. “Rail is the effective
modularization of some of these bigger components, so you can bring in fully
way of transporting those finished goods back into Alberta.”
manufactured products from the east and into Alberta. Today, though, the
Manufacturers & Exporters, says that some of the components that could be travelling to northern Alberta from manufacturing sectors cannot be transported easily due to current logistics. “I think one of the things that we have been pushing government and the pri-
really big stuff isn’t really able to get in because the rail lines out of Ontario just can’t really support the larger components.” According to Wilson, the sort of large, modular components companies are trying to bring to the oilsands have to be moved by rail as they are typically too large for highway transportation.
vate sector with CN [Canadian National Railway Company] and CP [Canadian
Although CN has not yet begun moving modules from manufacturing
Pacific] is to make sure the infrastructure is better in place to support the
areas to the oilsands, director of communications and public affairs Mark
60
NOVEMBER 2013 • OIL & GAS INQUIRER
Photo: Joey Podlubny
Mathew Wilson, vice-president of national policy for Canadian
Business Intelligence
Hallman says the company has been working with a number of petro-
is a lot of manufacturing expertise within Canada—largely in Ontario and
chemical companies and other stakeholders on the future rail shipment of
Quebec—to build these components.
modules to support projects in Alberta. “The modules are expected to be fabricated at North American facilities as well as imported from Asia,” he says. “CN has been actively engaged
“The more we can capture that value in Canada, the better it is for Alberta’s economy, Canada’s economy and Canadian manufacturing as a whole.”
in providing shipping options and technical assistance for the potential
While the two predominantly manufacturing provinces in central
shipment of rail modules. It is expected that rail shipments will commence
Canada are well-suited to benefit from greater modular construction for
in 2014.”
the oilsands, Wilson says the oilsands manufacturing supply chain draws
A lot of manufacturing for the oilsands currently is occurring within Alberta, says Wilson. However, he believes that over time there will be a
component parts from a multitude of regions, which in turn means the fabrication of these modules benefits Canadians across the country.
need for increased manufacturing capacity for the oilsands, which requires
“The modular components, wherever they’re assembled, you’re still
more modular construction from other manufacturing areas and increased
going to be pulling those components and bits and pieces from different
transportation infrastructure to accommodate the loads.
jurisdictions. Every province has an economic benefit from those types of
According to James, the biggest benefit of using rail to access central
purchases, and the supply reach is right across the country.”
Canada’s manufacturing sector for large modular components to be used
Wilson says the oilsands project is already a national project, and every-
in the oilsands is that it strengthens the buy-in by Ontarians, Quebecers and
thing his organization attempts to do to get more companies from across
other Canadians to the Alberta oilsands.
Canada involved in oilsands manufacturing aims to fortify that sense of
“It’s expanded economic benefit for the country.... If there are manufacturing jobs from central Canada where a lot of voters come from, then that expands the benefit.” He adds: “As an industry, I think we need to expand the benefits to beyond Alberta’s borders to eliminate the resistance, and rail has a pretty critical role in linking those two centres.” Wilson says the trend toward construction of prefabricated modular
national investment in the oilsands industry. “We have a lot of expertise and skill in Canada, and we think it can be a real and true benefit to the economy long term. The trick is, when you’re investing in oilsands for Canada, the goal for Canada should be figuring out how much of the value we can capture on the Canadian side of the marketplace. “How do we take the best advantage of it to build the economy long term, and not just pull the natural resources out of the ground to ship it elsewhere?”
components for use in the oilsands has been increasing for the past seven
While he recognizes that prefabricated modular components for the oil-
to eight years and he sees it continuing to do so into the foreseeable future.
sands also will be manufactured outside Canada, Wilson says the Canadian
“As investment in the oilsands continues to ramp up—and it still is grow-
manufacturing sector needs to position itself to create the proper business
ing year-over-year—there are more and more opportunities for manufac-
conditions to ensure manufacturing in Canada can compete and win bids for
turers to that sector, and there is more demand from the investors to make
oilsands projects.
sure equipment is delivered on time and on budget. They’re looking for sup-
“Certainly, large investors in the oilsands or any other natural resources
pliers for these things within Alberta, across Canada and globally, and that
project will be looking globally for their supply chains and try to take advan-
demand isn’t going to decrease.”
tage of those supply chains around the world. None of this is for sure for
Those prefabricated components represent high-value and high-technology pieces of equipment for the manufacturers to build, Wilson notes, and there
Canada, and our job as industry and government is to see how much advantage we can take of what is there.”
OIL & GAS INQUIRER • NOVEMBER 2013
61
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Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . 24
Flexpipe Systems . . . . . . . . . . . . . . . . . . . . . . . . .51
Platinum Grover Int. Inc . . . . . . . . . . . . . . . . . . . . .19
Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 59
FlexSteel Pipeline Technologies Inc . . . . . . . . . . . 6
Brother’s Specialized Coating Systems Ltd . . . . 35
Foremost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12
Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . .41
Human Resources Institute of Alberta (HRIA) . . . 46
CanElson Drilling Inc . . . . . . . . . . . . . . . . . . . . . . 46
Imperial Oil . . . . . . . . . . . . . . . . . . inside back cover
CG Industrial Specialties Ltd. . . . . . . . . . . . . . . . 32
Imperial Oil Fleet Services . . . . . . . . . . . . . . . . . . 4
Chevron Delo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Manulift EMI Ltee . . . . . . . . . . . . . . . . . . . . . . . . 23
Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
MaXfield Inc . . . . . . . . . . . . . . . outside back cover
TransGas Limited . . . . . . . . . . . . . . . . . . . . . . . . . 16
Dean’s Pump Service Ltd . . . . . . . . . . . . . . . . . . 49
Maxxam Analytics . . . . . . . . . . . . . . . . . . . . . . . . 25
Tundra Process Solutions Ltd . . . . . . . . . . . . . . . 20
Di-Corp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Meridian Manufacturing . . . . . . . . . . . . . . . . . . . . 15
Unified Valve Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Pumps & Pressure Inc . . . . . . . . . . . . . . . . . 41 & 44 Schneider Electric . . . . . . . . . . . . . . . . . . . . . . . . 26 Shaw Communications . . . . . . . . . . . . . . . . . . . . . 5 Sprung Structures Ltd . . . . . . . . . . . . . . . . . . . . . . 7 TOG Systems-Telecom Oil + Gas . . . . . . . . . . . . . .31
dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
Millennium Directional Service Ltd . . . . . . . . . . . 29
United Centrifuge Ltd . . . . . . . . . . . . . . . . . . . . . 54
Do All Industries Ltd . . . . . . . . . . . . . . . . . . . . . . 50
MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 48
V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . 11
Dragon Products Ltd . . . . . . . . . . . . . . . . . . . . . . . 8
MRC Global Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
Vortex Drilling Ltd . . . . . . . . . . . . . . . . . . . . . . . . 38
DSI Thru-Tubing Inc . . . . . . . . . . . . . . . . . . . . . . . .18
Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . 50
West Country Oilfield Services & Weed Control . . . 35
Eclipse Rentals Inc . . . . . . . . . . . . . . . . . . . . . . . 49
Pembina Controls Inc . . . . . . . . . . . . . . . . . . . . . . 10
Westeel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 55
Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Western Manufacturing . . . . . . . . . . . . . . . . . . . 40
62
NOVEMBER 2013 • OIL & GAS INQUIRER
When it comes to pumping productivity, we know the drill.
Whether your oil or gas exploration and production takes you offshore or onshore, if your machinery stops pumping, so does your productivity. That’s why we go deep to support you with exceptional industry expertise and technical service, global supply capability and proven oil-analysis programs. Combine these services with our groundbreaking lubricants, which have earned approvals from leading equipment builders, and it’s clear that we don’t just make industry run — we make it fly. Visit mobilindustrial.com for more.
© 2013 Exxon Mobil Corporation. All trademarks used herein are trademarks or registered trademarks of Exxon Mobil Corporation or one of its subsidiaries. Image courtesy of Baker Hughes.
TOG ETHE R WE CAN
For over 10 years MaXfield has quietly been gaining the expertise and experience to handle your next project. From custom vessels to structural steel, piping and modular packaged equipment; MaXfield is now your one stop shop for industrial fabrication.
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