OIL&GAS November 2014 ~ $6.00
INQUIRER
SPECIAL
FEATURE
Concerns about water use in fracturing operations moving to Canada
Western Canada's Exploration & Production Authority
UNDER
SIEGE Caught in the crossfire in the climate change war, pipeline companies focus on safety, social licence to operate
PLUS:
Operators aggressively target Viking tight oil play, driven by low costs and high netbacks
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CORE Linepipe reduces manpower and logistics costs installing small-diameter pipe By Graham Chandler
W
hen Dana MacLean was looking for six-inch pipe for a waterflood manufacturer. “They were the brains behind all the products developed project, he wanted something non-corrosive that could handle there,” says Sakell. “Their names are on the patents.” They develsalty produced water at over 60°C. oped and tested CORE Linepipe products in coordination with C-FER “My philosophy has always been to not put steel in the ground if I Technologies, a world class pipeline testing laboratory, in response to an don’t have to,” says the construction supervisor at Perpetual Energy Inc. industry need. “We started commercially in July; that’s when we made “I’ve been using composite pipe for the past five years and was looking the decision we were ready to go after two years of R&D, lab testing and for something that had the durability and environmental friendli- multiple field trials.” ness of a composite pipeline but the strength and heat resistance of Importantly, the design entirely foregoes the need for welders or lina steel line.” er installers in the field. “It eliminates a lot of manpower, equipment Which is just what attracted him to select CORE Linepipe for its and logistics,” says Sakell. On average he says the daily bill on a right-ofCORE LinerTM product—a unique factory-built pipe-in-pipe corrosion- way is $1200 to $1500 per day per worker. “So we take six guys out of the resistant barrier system. It has outer steel pipe for structural integrity welding crew and four or five out of the liner installation crew—that’s and damage resistance and a plastic liner pipe for a reliable and durable taking ten people off a project.” corrosion-resistant barrier. In the field, welding is To MacLean, that’s a bonus. He likes not haveliminated, and coupling steel consists of a patenting to deal with welding. “It’s only as good as the “It fits the bill perfectly.” ed mechanism called ClickWeldTM that provides a welder you have that day,” he says. He anticipates —Dana MacLean, CORE Linepipe client strong, efficient method for joining the steel pipe savings of 20 to 25%. without compromising the internal plastic liner These are the sorts of clients CORE listens to. pipe. An integrated electro-fusion coupling joins and seals the plastic liner. “We are in the business of providing solutions to industry and right now Field installation is efficient. “We ship the pipe out virtually com- industry is leading our product development schedule,” says Sakell. It plete. The liner is installed inside the steel pipe, in our factory,” explains prompted their next product: CORE CoatTM, the only factory-applied internal spray coating system. It eliminates the higher risks and expense Aethan Sakell, CORE Linepipe’s Sales and Marketing Manager. “All we of in situ spray coatings. have to do is assemble it and energize the ClickWeldTM fittings.” That’s done with a field press device which is easily handled by two men. In the There’s more on the horizon. “Our current business plan is to offer field trials, “we were estimating 15 minutes per joint; it turned out four-inch to twelve-inch pipe by end 2015,” says Sakell. Higher pressure more like 7,” says Sakell. After the mechanical coupling of the steel pipe, and temperature ratings are in sight, and eventually they’ll be doing sour the plastic liner is electro-fused through embedded wires—eliminating service too. Longer-term, it’s more exotic plastics for electro-fusion and plastic beading common to standard butt fusing. maybe even a lined downhole casing. Like Sakell, the people behind the company and products came mostBut for now, MacLean is content with the CORE Liner system. ly from one leading high-pressure, corrosion-resistant composite pipe “It fits the bill perfectly.”
http://www.corelinepipe.com
CONTENTS
NOVEMBER.
in the news
13
Capital budgets continue climbing
regional news
19
British Columbia
Precision still an LNG believer
25
Northwestern Alberta
Delphi continues fine-tuning Montney completions
29
Northeastern Alberta
Cenovus reports first oil at Foster Creek Phase F
35
Central Alberta
41
Southern Alberta
Manitok updates operations at Entice
43
Saskatchewan
Spartan production up sixfold
Tourmaline expects massive production increase of 43,000 barrels equivalent in final quarter
features
Cover
FEATURE
48 Viking conquest Operators aggressively target Viking tight oil play, driven by low costs and high netbacks
every issue
10 62
Stats at a Glance
53 Under siege Caught in the crossfire in the climate change war, pipeline companies focus on safety, social licence to operate
58 Water worries Concerns about water use in fracturing operations are moving north, but Canada has a head start in managing the issue
Political Cartoon
Cover design: Peter Markiw Photo: ©iStock.com/VladKol
OIL & GAS INQUIRER • November 2014
7
POTENTIAL. WHEREVER YOU LOOK. EDC can help your business achieve its goals. Reduce the risk and seize the opportunities – wherever your markets may be. EDC can help with finance, insurance and bonding services that help you achieve your trade goals. EDC has representatives across Canada and in 16 cities internationally. Find out how we can help. Visit edc.ca/potential for details.
Editor’s Note Vol. 26 No. 11 EDITORIAL EDITOR
Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS
Lynda Harrison, Carter Haydu, Richard Macedo, Paul Wells
Crunch time in British Columbia
EDITORIAL ASSISTANCE MANAGER
Tracey Comeau | tcomeau@junewarren-nickles.com EDITORIAL ASSISTANCE
Kate Austin, Michael Doyle, Sarah Maludzinski, Sarah Miller CREATIVE CREATIVE SERVICES MANAGER
Tamara Polloway-Webb | tpwebb@junewarren-nickles.com PRODUCTION COORDINATOR
Janelle Johnson CREATIVE LEAD
Cathlene Ozubko GRAPHIC DESIGNER
Peter Markiw
CREATIVE SERVICES
Linnea Lapp production@junewarren-nickles.com SALES SENIOR ACCOUNT EXECUTIVES
Will British Columbia become a global natural gas
cial for future growth in the service and supply
Asian markets, or will the province see its huge
sector. Under Precision’s calculations, he esti-
gas resource stranded for at least a generation?
mated that roughly 20–25 rigs would be needed
The answer to this question will come over
Precision boss is hoping at least three projects
tax and regulatory framework and as potential
get approval, needing between six and eight bil-
LNG exporters tally up the numbers to see if gas
lion cubic feet of gas per day. This translates into
exports will be profitable.
demand for 100–200 rigs.
The stakes are huge for both parties.
SALES
The province is currently in debt to the
For advertising inquiries please contact adrequests@junewarren-nickles.com
per billion cubic feet of export capability. The
the next few months, as the province solidifies its
Nick Drinkwater, Tony Poblete, Diana Signorile Rhonda Helmeczi, Mike Ivanik, Nicole Kiefuik, James Pearce, Blair Van Camp
Neveu added that LNG exports are also cru-
powerhouse driven by LNG exports to hungry
tune of $60 billion and sees the LNG export
B.C. Premier Christy Clark is more optimistic. She is hoping for five export facilities to be built. But so far none have been approved, and
business as a means to rejuvenate its economy.
recent industry comments suggest LNG is far
The current Liberal government is hoping LNG
from a done deal. Imperial Oil recently said a
Lorraine Ostapovich | atc@junewarren-nickles.com
will generate as many as 100,000 new jobs and
DIRECTORS
decision on its LNG plans is “years away.”
add billions in new taxes and royalties to help
AD TRAFFIC COORDINATOR—MAGAZINES
CEO
“If there’s a market value and a place in the
Bill Whitelaw | bwhitelaw@junewarren-nickles.com
pay off the staggering debt. It is basically betting
market, then it will be a project. And if there’s
PRESIDENT
the future of the province on natural gas, as
not, it won’t go,” said Imperial president and
indicated in the throne speech opening the fall
chief executive officer Rich Kruger.
Rob Pentney | rpentney@junewarren-nickles.com DIRECTOR OF SALES & MARKETING
Maurya Sokolon | msokolon@junewarren-nickles.com DIRECTOR OF EVENTS & CONFERENCES
Ian MacGillivray | imacgillivray@junewarren-nickles.com DIRECTOR OF THE DAILY OIL BULLETIN
Stephen Marsters | smarsters@junewarren-nickles.com DIRECTOR OF DIGITAL STRATEGIES
Gord Lindenberg | glindenberg@junewarren-nickles.com DIRECTOR OF CONTENT
Chaz Osburn | cosburn@junewarren-nickles.com DIRECTOR OF PRODUCTION
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sitting of the legislature in October. “This is our turning point,” B.C. Lieutenant-
With Apache jumping ship, Chevron is also stalled out in its LNG plans, while Shell says it
Governor Judith Guichon said in reading the
won’t make a decision until 2016. PETRONAS
throne speech. “We must choose whether to
is expressing frustration with the slow pace
grow or to decline.”
of government progress in developing its LNG
The natural gas industry in the province fi nds itself in a similar situation. Speaking at the Barclays Energy Conference
framework, saying its project could be delayed for a decade if things don’t speed up. While the B.C. government remains confi-
in September, Precision Drilling president
dent of building an LNG export business, it is
and chief executive officer Kevin Neveu said
now much more subdued in its enthusiasm.
over $42 billion has been invested in Canada
“This is a chance, not a windfall,” Guichon
in the field in anticipation of LNG exports and
said in reading the throne speech. “It will not
another roughly $8 billion has been invested in
be simply given to us, but achieved after a lot of
infrastructure.
hard work.”
With traditional markets in the United
Let the work begin in earnest.
States saturated with gas for the foreseeable future, without LNG exports much of that
Darrell Stonehouse
investment will be written off.
Editor dstonehouse@junewarren-nickles.com
N EXT I S S U E December 2014 A look ahead at the economic, political and social issues that will shape the industry in 2015. Plus exploring emerging plays across the country and what it will take to get them developed.
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 2014
9
FAST NUMBERS
,
Wells drilled in the Viking play in 2013, according to Daily Oil Bulletin statistics.
,
barrels per day
Viking average production in 2013.
Alberta Completions
WCSb oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
M O NTH
T O TA L
MONTH
OIL
GAS
D RY
72
3
oct 2013
953
204
8
79
1,2
44
1
Nov 2013
852
218
9
62
1,11
52
Dec 2013
675
180
20
72
105
57
2
Jan 201
488
156
18
55
1
427
119
80
2
Feb 201
879
163
15
73
1,130
521
165
126
12
mar 201
924
218
23
118
1,23
504
142
17
68
32
OIL
GAS
oct 2013
528
153
Nov 2013
463
164
Dec 2013
298
137
Jan 201
280
Feb 201 mar 201
OTHER
SERVICE
Apr 201
418
94
62
Apr 201
may 201
188
54
63
30
may 201
259
77
10
59
0
Jun 201
240
94
45
3
Jun 201
411
154
9
44
1 3
Jul 201
245
52
70
3
Jul 201
562
86
24
71
Aug 201
257
63
69
3
Aug 201
657
77
29
81
20
Sep 201
389
154
85
2
Sep 201
861
188
28
76
1,13
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
oct 2013
52
474
oct 2013
380
0
15
3
Nov 2013
58
532
Nov 2013
339
0
27
3
Dec 2013
45
45
Dec 2013
321
0
39
30
Jan 201
49
94
Jan 201
181
0
13
1
Feb 201
46
150
mar 201
Feb 201
401
0
7
0
55
205
Apr 201
56
261
mar 201
349
0
14
33
may 201
41
302
Apr 201
79
0
23
102
Jun 201
62
364
may 201
20
0
1
21
Jul 201
35
399
Jun 201
163
0
7
10
Aug 201
19
418
Jul 201
290
0
21
311
Sep 201
36
454
Aug 201
338
0
26
3
Sep 201
408
0
19
2
*Year-to-date
OTHER
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T O TA L
November 2014 • OIL & GAS INQUIRER
TOTAL
STATS
AT A
GLANCE
Drilling rig Count by Province/Territory
Drilling Activity: oil & Gas
Western Canada, October 8, 2014 Source: Rig Locator
Alberta, September 2014 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 13
Sep 1
Sep 13
284
280
50%
Northwestern Alberta
108
86
99
42
british Columbia
47
17
73%
Northeastern Alberta
67
66
0
0
manitoba
13
10
23
57%
Central Alberta
178
169
46
4
Saskatchewan
86
69
1
55%
Southern Alberta
36
36
9
26
30
3
0
3%
ToTAL
3
3
1
2
WC ToTAL
Top Active Drillers in Canada
Drilling Activity: Cbm & bitumen
Western Canada, October 8, 2014 Source: Rig Locator
Alberta, September 2014 Source: Daily Oil Bulletin
O P E R AT O R
ACTIVE RIGS
DEV
C OA L B E D M E T H A N E
EXP
Canadian Natural resources Limited
23
21
1
Crescent Point energy Corp.
23
18
4
Progress energy Canada Ltd.
18
18
0
Tourmaline oil Corp.
17
13
3
Husky energy Inc.
15
11
4
ConocoPhillips Canada Limited
12
11
1
encana Corporation
11
9
2
Seven Generations energy Ltd.
11
8
2
Cenovus energy Inc.
10
8
1
Apache Canada Ltd.
9
5
4
Alberta
Sep 1
Sep 13
BITUMEN WELLS Sep 1
Sep 13
Northwestern Alberta
0
0
1
7
Northeastern Alberta
0
0
67
65
Central Alberta
2
0
75
65
Southern Alberta
6
4
0
0
ToTAL
13
13
OIL & GAS INQUIRER • November 2014
11
IN THE
NeWS Issues affecting Canada’s E&P industry
Capital budgets continue climbing
Producers are increasing 2014 capital spending by around $6.7 billion going into the winter drilling season.
Producer capital spending budgets will reach $63.37 billion in 2014 based on 86 producers that have announced their capital budgets, up from $56.71 billion outlined earlier, according to Daily Oil Bulletin estimates. The collective increase of $6.66 billion from initial spending plans is due to continued strength in commodity prices, as well as a spate of asset and company acquisitions over the past six months. A total of 51 producers have reported increases to their budgets from their initial plans set late last year or earlier in 2014. Eight companies including Suncor Energy Inc., which cut planned capital spending by $1 billion, have announced a decrease in spending from their original budgets. Suncor said its forecast capital reduction to $6.8 billion from $7.8 billion results from deferred spending on pre-sanction growth projects to optimize project economics, cancellation of sustaining capital
projects that are not critical for safe and reliable operations, delays in offshore exploratory drilling programs and suspension of activities in Libya. Canadian Oil Sands Limited initially set a budget of $1.1 billion in 2014 as its share of spending on a Syncrude project but reduced it to $928 million, reflecting a reduction in the Mildred Lake mine train replacement project cost estimate and adjustments to spending on regular maintenance capital projects. Canadian Natural Resources Limited has announced the largest increase as the result of acquisitions—up $4.23 billion to a total of midpoint of $11.93 billion. The company spent $3.13 billion to acquire Devon Canada’s conventional assets, excluding Horn River and its heavy oil properties. It forked out an additional US$475 million for Apache Corporation’s producing oil and primarily dry gas assets in the Deep Basin area (Ojay, Noel and Wapiti) in western Alberta and northeastern British Columbia.
Other companies that have raised their spending plans the most compared to initial budgets set for 2014 are Tourmaline Oil Corp. (up $450 million), Bellatrix Exploration Ltd. (up $370 million), Kelt Exploration Ltd. (up $328 million) and Baytex Exploration Ltd. (up $292.5 million). Tourmaline has increased its capital budget several times this year, most recently earlier this month with a $100 million increase to $1.35 billion to reflect the acceleration of the second Wild River facility expansion to 2014 from 2015 and the drilling of about 25 more wells in 2014 than originally planned in a 15-rig program. The company had increased spending earlier in the year by $100 million to $1.1 billion with the addition of one more rig in northeastern British Columbia, the Berland to Wild River pipeline lateral and acceleration of the Wild River plant expansion. Bellatrix also increased its capital budget twice during the year to $740 million (including $240 million as its share of joint venture projects) from the initial $370 million. Kelt’s capital spending increase to $428 million from an initial $100 million also ref lected an acquisition. It spent $165 million, including $107 million in cash, for a private Canadian oil and gas company with Montney crude oil and natural gas assets at Valhalla/La Glace, adjacent to the company’s core producing areas at Pouce Coupe and Spirit River in northwestern Alberta. Earlier the company had boosted capital spending by $120 million to $270 million (before $20 million in assumed dispositions), targeting increased drilling activity. The spending is expected to result in the drilling of 35 (27.5 net) wells during the year, with the largest increase in the Karr and the Pouce Coupe/Spirit River areas. — DAILY OIL BULLETIN
OIL & GAS INQUIRER • November 2014
13
In The News
Faster drilling depends on creativity, data collection and communication, conference told A willingness to innovate and experiment, keeping thorough data on what works, and communication between management and operators are valuable tools for companies striving toward improved rates of penetration (ROP) for horizontal drilling, a Calgary conference heard in September. “I think we kind of pigeonhole ourselves sometimes and just look at what we are doing in our own neighbourhoods and backyards,” Martin Rejman, drilling and completions engineer at Bellatrix Exploration Ltd., told those attending the Canadian Business Conferences Horizontal Drilling Canada 2014 conference. “There are 80 or more energy countries around the world where oil and gas is drilled for and produced, and so there are lots of examples out there we can look at, both onshore and offshore. We can grab ideas and bring them back.” He added, “Don’t be afraid to try and fail, because out of every third failure might be one or two successes.”
GIBSON ENERGY
Matthew Bloom, drilling engineer at Nexen Energy ULC, said one of the biggest ways his company increases the speed at which its drillbit breaks through the rock is simply by tracking lots of data. “When we see things are going well, and we notice certain parameters are working in limiting our slip stick or limiting our vibration and allowing us to smoothly drill, we note that, record that, and we make sure we keep doing that. It’s the biggest thing for longevity and continuity.” The reliability of downhole tools is a primary risk factor when companies are trying to achieve higher ROP, said Joseph Ekpe, senior drilling engineer at Chevron Corporation. He added it is also important for companies to have a “road map” in order to mitigate risks. “There has to be constant communication with the field and the office, monitoring the parameters downhole to show that what we are expecting is what
we are getting, and if there is something getting out of the norm, then it is quickly addressed.” Drilling fast, according to XTO Energy Canada senior drilling engineer Trevor Holding, is about rock, how the operator cleans hole and manages waste, and how the company treats operations as a fully integrated system. He said, “One way to do this is through relentless redesign. Find out what your performance parameter is and engineer that out of your system. It is as simple as that.” According to Holding, while generally more weight equals faster ROP, eventually there is a counterpoint where that is no longer the case, and stacking more weight will instead hinder operations. The goal is to have ROP continue to increase in a linear fashion as the weight on the bit is increased, he said. Some ways of achieving this include drilling with brines instead of muds to manage the chip hold down effect, redesigning bottomhole
w w w.g i b s o ns . co m
Gibson Energy is a growth-oriented, solutions-based, North American midstream energy service company with an integrated portfolio of businesses.
14
November 2014 • OIL & GAS INQUIRER
In The News
assemblies for vibration management purposes as well as making bits that constrain whirl. “Maybe we can’t clean the hole effectively, and so we need to understand what is constraining us from cleaning the hole more effectively. Do we need different mud properties? Do we need more flow rate? Do we need a smaller hole? Do we need a bigger rig?” According to Bloom, the use of near-bit inclination enables operators to learn how the bottomhole assembly reacts to a formation, and drill ahead with confidence while learning the subtleties of a downhole environment. He said: “Really, what near-bit inclination allows you to do is just get ahead of things, and instead of driving from the back of the bus, you can drive from the front.” When chasing a zone, Rejman said, geologists love near-bit technology because it enables predictions of which ways a reservoir is moving, which allows the drill bit to stay in the desired area much longer. “I wish that more sensors were brought up to the front and closer to the bit,” he said. “Unfortunately, due to limitations of technology and how much stuff we can
Canadian drilling statistics (2012-13) 2012
2013
Number of drilling rigs
822
819
Rig operating days
124,319
120,043
Rig utilization Number of wells drilled
42%
40%
10,753
10,903
Average days per well
11.6
11
Metres drilled (000s)
20,869
22,733
Average metres per well
1,941
2,085
Average metres per day
168
189
$21,030
$22,108
Rig revenue/utilization day
Source: Precision Drilling
pack in tools, we’ve reached the limitation for now, until we have a game-changing technology come out.” Important to managing ROP is understanding that improvements are never due to one factor, according to Ekpe. Appreciating its relationship to cost efficiency is equally important to ROP. “One of the things that is key here is being able to identify the performance qualifiers,” he said, adding that communication between the office and fieldworkers is important for analyzing data and making appropriate decisions. In the Horn River play in northeastern British Columbia, Bloom noted, Nexen tries to use the lightest mud weight possible,
which allows the gas to go through the managed pressure system when encountering the rare natural fracture, enabling increased efficiency in continuous drilling operations. “Teamwork, communication, innovation—every area is different, every well is different. It is dynamic, and so it comes down to analyzing the data, discussing the data and teamwork to increase ROP,” said Brent Eshleman, chief operating officer at Bellatrix. Where once the world thought it was running out of oil and gas resources, thanks in large part to horizontal drilling there is an abundant supply of energy resources, which is becoming increasingly true with ever-better methods,
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OIL & GAS INQUIRER • November 2014
15
In The News
Eshleman told the conference. “I actually don’t know of a zone where horizontal drilling has not improved productivity and reserves.” Horizontal wells currently account for more than 70 per cent of all wells drilled in
Canada, the conference heard, and that is expected to increase. “Continual improvement, working together and sharing ideas will continue to take this industry to new heights,” he
said. “The ability to continuously apply new technolog y is one of the keys to being both successful and a market leader in the future.” — DAILY OIL BULLETIN
Innovator encourages better use of fossil fuels by Lynda Harrison
Alberta needs a flue gas capture and CO2 commercialization centre—even a campus—where innovators and inventors can test out their hunches, kickstart innovation in important new areas and get more value out of the province’s hydrocarbons, a Calgary breakfast meeting heard in September. “We need to give people a place to prove [and] to de-risk technologies, so we can apply them back in a commercial space,” said Bob Mitchell, senior director of innovating for performance and sustainability in ConocoPhillips Canada’s oilsands business unit. “If we do, I really think the world will embrace this.” Some “really cool things” can be made from carbon-based materials, said Mitchell, who two years ago was recognized for his leadership in Alberta’s oilsands sector with an Emerald Award. “The imagination runs wild, and we have a real opportunity for Alberta to be in the lead in this world,” he said. “I think Alberta has the opportunity and, really, has the responsibility to be a hydrocarbon utilizer-producer that the world needs. We have a great responsibility, a great opportunity and we just have to think differently about what we’re doing and make better use of the natural endowments we’ve got.” Alberta could contribute the practice of diverting carbon from CO2 into the food chain and, eventually, use excess carbon in 3-D food printers, carbon-based materials for nanofi lters and aerogels for electrodialysis to desalinate water, he suggested. T he prov ince could also prov ide advanced carbon-based insulation and building materials, thereby creating new business opportunities and capitalizing on the chemical values of carbon and hydrogen, he told the Oilsands Review Speaker Series talk “New Revenue? Rethinking Fossil Fuels and Carbon Emissions.” “Emitting CO2 and other things into the atmosphere, whether you believe in climate change or not, that is a wasted product. We need to do industrial synergies. We need to fi nd ways to use those products instead 16
November 2014 • OIL & GAS INQUIRER
of just releasing them,” said Mitchell, co-founder of the Oil Sands Leadership Initiative, which has been rolled into the Canadian Oil Sands Innovation Alliance and the Sustainable Communities Initiative. “To do that, we need to embrace open innovation, captivate innovators, facilitate collaboration and help ideas become reality by bridging the technology valley of death.” It is up to the private sector to develop a carbon innovation campus; government is not going to take the lead on this, he said. While current uses of hydrocarbons include transportation fuels, home heating and electricity generation, higher-value uses in the future may be 3-D printing, graphene, ammonia and biofuel bicycles, the meeting heard. Graphene is a one-atom-thick miracle substance that’s stronger than steel and appears to be a super-conductor, he said. “It seems to be a promising, promising product.” He said “really smart people” are focused on energy efficiency and conservation; fuel-switching hydrocarbons to renewables, nuclear and fission; reducing the energy and CO2 intensity of energy production; and capture, long-term geologic storage and enhanced resource recovery. These have become mainstream, said Mitchell. But until recently, what haven’t been pursued are air capture and conversion, flue gas capture and CO2 conversion, and higher-value uses of hydrocarbons such as materials and clean fuels. There is more chemical value in hydrocarbons than there is thermal value, he noted. “We can divert carbon dioxide, from CO2 into the food chain, by putting it into fertilizers and composting, but if you get futuristic, we could be printing using carbon molecules to actually make food like a 3-D print,” said Mitchell. Recently a 3-D printed hamburger was created, although Mitchell said tasters pronounced it “not the best hamburger in the world.” Aerogels are the world’s lightest solid materials, composed of up to 99.98 per cent
air by volume. Transparent, super-insulating silica aerogels exhibit the lowest thermal conductivity of any known solid. Ultra-high-surface-area carbon aerogels power today’s fast-charging supercapacitors, and ultra-strong, bendable x-aerogels are the lowest-density structural materials ever developed. A Calgary company is using electrodialysis with aerogel filters to desalinate water, said Mitchell. Normally, desalination takes a lot of energy but this process is actually generating electricity, he said. “It’s a really promising technology. It was developed in the oilsands, but it could be applicable around the world.” Now, with advanced plastics and materials, lighter, stronger buildings might be able to deal with catastrophes such as earthquakes and hurricanes because carbon-based materials have the ability to sway better than steel and concrete do, he told the gathering. At a time when cleaner, reliable power is needed, Mitchell imagines including valueadding components in tailpipes and power plant smokestacks so that CO2 is not wasted and is instead turned into useful products. Hydrogen can be removed from hydrocarbons to make more hydrogen-rich fuels and other products so that the emissions are not contaminating the atmosphere and affecting people’s health, he said. “The big one here to me is, if we do a better job of this and make better use of our hydrocarbons, we reduce the need for conflict and tension over hydrocarbons because now everybody in the world can follow our example and find more livelihood out of what they’ve got,” he said. The world can switch from having its CO2 going into the atmosphere and land and acidifiying the oceans to one where it goes into products such as the BMW i3, which Mitchell said he has driven and is a “pretty neat,” mostly carbon-based electric vehicle, or an enclosed motorcycle that is currently in production. “It’s got a gyroscope, so it doesn’t tip over,” he said.
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Yield Strength (ksi)
65
58
62
59
Ultimate Tensile Strength (ksi)
82
76
78
74
Elongation (%)
34
30
31
29
CVNs @ -40°F (Ft-Lbs)
91
101
94
100
CVNs @ -60°F (Ft-Lbs)
82
77
79
83
Hardness (HV10)
219
1
200
Actual test result values from welding performed in the 3G position with a heat input of 64KJ/in.
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brITISH CoLUmbIA WeLL ACTIvITY SEP/13
SEP/14
Wells licensed
47
11
SEP/13
SEP/14
Wells spudded
56
SEP/13
SEP/14
50
Rigs released
▲
▲
▲
Source: Daily Oil Bulletin
B.C. British Columbia
Precision still an LNG believer by Paul Wells
Precision Drilling Corporation is the driller best positioned to take advantage of future Canadian LNG projects to the West Coast, the company’s president and chief executive officer told a conference in New York City in September. Speak ing at the Barclays Energ y Conference, Kevin Neveu added that he believes the first of many proposed LNG projects could be in line for a fi nal investment decision sooner rather than later. “Over $42 billion has been invested in Canada in the geology and roughly another $8 billion invested in infrastructure already. All of this is ahead of the first final investment decision by anybody,” he said. “So from a time-frame standpoint of what we’re looking for going forward is the royalty and tax environment in British Columbia to be stabilized, maybe as early as October but certainly no later than the fi rst half of 2015. We’ve had one
LNG could create demand for 100 –200 rigs, said Precision.
major operator already commit that if they receive this tax and royalty structure in place before the end of the year or early next year, they will push forward their funding approval as early as a month or two after that,” Neveu added. “So we could see the fi rst project approved as early as November and no later than Q2 2015. And then right behind that, we think there are two more projects to follow.” Under Precision’s calculations, Neveu estimated that roughly 20–25 rigs would be needed per billion cubic feet of export capability, meaning the opportunity is huge for drilling outfits. “So if my handicapping is right and three projects get approval, that could be between six and eight billion cubic feet a day of opportunity for 100–200 rigs in the industry for Canada, and we would certainly be targeting to get our share or more of that business,” he said. “For us it’s interesting in that likely most of these rigs will be new builds. If this is going to be pad-type drilling, these rigs don’t exist in Canada right now.” Neveu added that despite the lack of a final investment decision by any of the LNG project proponents, the drilling industry has been active in the plays that will provide the natural gas to be shipped via pipeline to the West Coast. “Currently today there are about 25 rigs that are running in Canada that are doing delineation work and early drilling work for the LNG projects. So it’s happening right now. Money is being spent, but fi nal investment decisions haven’t been made yet. We’re watching for that as early as November this year but no later than next year,” Neveu said. “We think that could bring a leg of new builds for Precision for 2015 through
2017, over a three- or four-year horizon,” he added. “We’re quite excited about this catalyst and watching this develop, but we’re also pleased with the investment so far to date and the willingness of our customers to put rigs to work on long-term contracts.” Neveu noted that strong government support for Canadian LNG projects is an indicator that the issues currently stalling final investment decisions for LNG projects could soon be ironed out. “There’s no question that Canada is hotto-trot on LNG, and we’ve got good support at several government levels. First of all, the province of B.C. has a relatively new administration that came in about a year ago, and they won this landslide election based on an LNG platform, so there’s strong provincial support,” he said. “The federal government has cleared the way for LNG development by approving over 20 billion cubic [feet] per day of exports [and] by providing preliminary environmental approvals for LNG facilities and [is] really trying to clear the path to facilitate development.”
Nexen working to revolutionize Horn river fracturing technology by Carter Haydu
Nexen energy ULC has broken a paradigm with what the company calls plugless fracturing, which data suggests could improve the efficiency and speed of operations in the Horn River Basin. “Ever since I have been in the business, I have been told that you have to set some physical isolation between the frac that OIL & GAS INQUIRER • November 2014
19
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you pumped and the frac you are about to pump,” Peter Chernik, program manager for northeastern British Columbia shale g a s, told a C a n ad i a n S o c iet y f or Unconventional Resources luncheon in September. “We have discovered in the Horn River that you do not need to do that.” Conventional plug-and-perf requires time, effort and risk, Chernik said, but Nexen has realized there exists a dynamic conversion process between the job done and the one about to occur that can reduce the time, eff ort and risk but produce results very similar to a successful plug-and-perf. “From a pumping perspective, one of the things we have learned is there is variability in every frac in terms of how it pumps, but the plugless jobs all fall within the range of conventional plug-and-perfs.” Cutting its execution time in the Horn River Basin by about 50 per cent over a four-year period and completing 18 wells two weeks faster than expected thanks to continuous operations, Nexen sees increasing efficiency as necessary due to the extremely tight economics associated with producing in that region. Chernik said, “Here is the reality: we have to compete in a very low gas price environment. Where we are, it is very dry and there are no liquids. The long and the short of it is that we must accomplish more for less, and we have to make our wells as productive as we can so we can do that.” On the topic of plugless fracturing, Chernik said that, aside from the benefit of saving money by avoiding drill issues associated with plug-and-perf, with plugless fracturing, operators avoid limitations to how far they can push horizontals, and there are other benefits such as the speed at which crews can conduct a job. “It leaves the well more fully open, and so if you want to do production logging, then it can be done.” The typical sequence Nexen employs while moving across its Horn River land position includes building roads and pads and drilling over a 10-month period, followed by three to five months of completions and finally long-term production over about 20 years, Chernik explained. “Our wells are getting longer, and we have the potential to get even further to reduce the number of pads that we require,” he said. Whereas the company
British Columbia
once required 20 well pads for 20 single wells, now the company can put 20 wells on a single pad, which reduces the degree of development necessary for a similar amount of production. “I think our disturbance will be onethird of what it used to be with the old single-well concept.” According to Chernik, it takes crews about 24 hours to rig release from one well and spud the next one. To further cut costs on its rigs, he noted, the company starts its engines on diesel and adds natural gas in front of the system, switching back to diesel when more power is required. “We have been running this for about four years, and there are significant savings in terms of fuel costs. It more than pays for itself.” Chernik said Nexen drills in a “fish hook” design, drilling away from the pad and then back underneath the pad, which allows the company to capture the 500metre strip under the pad. “The other thing that is happening is that we are getting much longer with our horizontals. We are typically now out to 2,600 metres, and we’re trying to push that out even further.” For fracturing, Nexen typically conducts slickwater fracs in the Horn River, with 200 tonnes per day of sand and 2,500 cubic metres of water per frac. “We use a lot of water in the Horn River,” Chernik said, adding the company has a licence allowing use of surface water during high-flow conditions, meaning it can only draw from this water source in spring and rainy periods. The company needs a means of storing the liquid, he said, which can be synergized with other components of operations. “Part of our development is roads and pads, and we need clay. So we end up with a whole series of borrow pits…. We fill these pits, and then we pull from them as we need to during our fracturing operations in the summertime.” Chernik told the luncheon audience that a company can only responsibly pull a certain amount of fresh water for fracturing purposes, and therefore Nexen is developing its use of saline water from the Debolt Formation, which has about five per cent hydrogen sulphide (H2S). “If you keep Debolt water above its bubble point, it remains stable, it’s clear
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British Columbia
and there are no iron sulphides in it. However, if you drop it below the bubble point, then things start to happen—you release H 2S, you release iron sulphides, you have plugging issues, et cetera.”
Therefore, Nexen developed a system where there are source wells for the Debolt water with pumps and pipelines keeping pressure above the bubble point so the water comes in for frac operations
and backflow is taken to disposal wells also in the Debolt Formation. “We end up using the Debolt as a huge underground container, both for source and disposal.”
Consolidation looming for LNG projects by richard macedo
Significant consolidation is expected for Canada’s West Coast LNG projects, of which 19 have been publicly proposed, an industry player said in September. While western Canada has a massive resource base and is favourably positioned, from a geographical perspective, to supply LNG to countries in southeastern Asia, it is fighting for market share on a global stage and must be competitive with other energy sources, noted Brian Tuffs, executive vicepresident of exploration and new ventures with Sinopec Canada. “The opportunities for Canadian LNG, we believe, are very real,” he said. “Clearly not all of the projects will go ahead. We anticipate that there will be significant consolidation between the projects between now and fi nal investment decisions, so we see the next 12–36 months as being very key. I think it’s important for everybody— whether it’s government, stakeholders, First Nations or the upstream industry here in Calgary—to recognize that Canada has to be competitive on a global stage. That’s going to be costs, that’s going to be regulatory, that’s going to be government.” In April, PETRONAS signed an agreement where Sinopec, through its affiliates, acquired a 15 per cent interest in Progress
Energy Canada Ltd.’s LNG-destined natural gas reserves in northeastern British Columbia and in the proposed Pacific NorthWest LNG export facility planned for the B.C. coast. As part of the transaction, Sinpoec has agreed to offtake 1.8 million tonnes of LNG per annum, which represents a pro rata 15 per cent of the LNG facility’s production, for a minimum period of 20 years. “We believe that the supply cost of the upstream will be a real differentiator in integrated LNG projects within western Canada,” Tuffs told the Canada LNG Export conference. “LNG and gas as a whole is a very important part of China’s national energy policy. “China is here to get energy, yes, but it’s also here to be able to do that in an economically responsible way,” he added. “The Chinese view is that Canadian LNG projects represent low risk in many facets—a stable political regime, a very good regulatory regime; however, it is relatively high cost.” Compared to a conventional LNG project, the upstream portion of the cost structure is very high for Canadian LNG projects that are backstopped by unconventional resources, Tuffs said. “Here we see about 60 per cent of the overall cost structure of an integrated LNG project being the upstream development
costs,” he said. “It means the margins are relatively small. “It’s our position that having an integrated approach—upstream, midstream, buyer—at the end of the day is the way that you will get the benefit of an unbundled price structure.” W h i le Tu f f s poi nted to wester n Canada’s planned LNG projects having a geographical advantage, “that doesn’t give us any right to be the exporter of choice.” Chen Weidong, chief energy researcher, CNOOC Energy Economics Institute, also noted that Canada is resource-rich and there’s low political risk. However, there are no exports yet, there are high labour costs and projects are progressing slowly. “We are looking for diversified supply,” he said. “Everybody knows we signed a contract with Russia in May this year.” China and Russia agreed to a US$400billion gas supply deal, securing the world’s top energy user a major source of cleaner fuel and opening up a new market for Moscow. “That contract will supply China 38 billion cubic metres per year,” Chen said. “By 2020…China will consume about 400 billion cubic metres of gas. By that time, the Russian contract will represent only 10 per cent of all consumption.”
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November 2014 • OIL & GAS INQUIRER
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NorTHWeSTerN ALberTA WeLL ACTIvITY SEP/13
SEP/14
Wells licensed
259
21
SEP/13
SEP/14
Wells spudded
203
20
SEP/13
SEP/14
212
13
Rigs released
▼
▲
▼
Source: Daily Oil Bulletin
N.W. Northwestern Alberta
Delphi continues fine-tuning montney completions Using a slickwater hybrid fracking technique in the Montney play in northwestern Alberta continues paying dividends for Delphi Energy. Delphi completed its tenth horizontal Montney well using a 30-stage slickwater hybrid completion technique at 16-15-06023W5, over the summer. The 16-15 well (75 per cent working interest) was drilled to a total depth of 5,903 metres with a horizontal lateral length of 2,949 metres and stimulated with a 30-stage slickwater hybrid completion. The well was produced on cleanup over a 10-day period, recovering approximately 22 per cent of the initial load frac water. The well was then shut in to equip and pipeline-connect the well for production. After running production tubing, the well produced, over the fi nal 24 hours, at an average rate of seven million cubic feet per day of raw gas and 311 barrels per day of wellhead condensate. Total production for the 16-15 well, over the fi nal 24 hour period, was approximately 1,598 barrels of oil equivalent per day including an estimated plant natural gas liquids yield of 36 barrels per million cubic feet of raw gas. Field condensate and plant natural gas liquids (NGLs) represented 35 per cent of the total production. The 16-15 has recently been placed on production through the company’s 100 per cent owned compression and dehydration facility. Delphi has completed drilling its sixth Montney horizontal well of 2014 at 03-26059-23W5 located in the central part of the East Bigstone block. The well was drilled to a total depth of 5,593 metres with a horizontal lateral length of 2,601 metres. Completion operations, consisting of a 30-stage slickwater hybrid fracture
Delphi has now drilled and completed 10 wells with a 30-stage hybrid slickwater fracturing process.
stimulation, are expected to commence in the next several weeks. Delphi has concluded facilities and pipeline construction to equip and tie in the company’s 12-17-059-22W5 well that was completed late in 2013. The 12-17 Montney horizontal well is the most southern well on the company’s East Bigstone block. The well is expected to be on stream around mid-September. As a result of a pipeline connection completed by Delphi this past winter to the SemCAMS K-west sour pipeline, Delphi is now delivering its Montney natural gas production to the SemCAMS operated Kaybob South 3 (K3) gas processing facility. Natural gas processing of the company’s Montney production at K3 is expected to result in improved field operating netbacks due to lower processing costs and improved propane recovery. — DAILY OIL BULLETIN
Strategic oil & Gas reports strong muskeg results
Strategic oil & Gas Limited’s Muskeg oil play in northwestern Alberta is delivering strong initial production rates, the company reported in September. Strategic announced that two recently completed Muskeg wells produced at a combined rate of 1,587 barrels equivalent per day (83 per cent oil). Two western Muskeg wells, 15-24 and 01-25 were recently brought on production and are free-flowing oil wells. Over the last three days of the production test, well 15-24 produced at an average daily rate of 848 barrels equivalent per day (81 per cent oil), and well 01-25 produced at an average daily rate of 614 barrels equivalent (88 per cent oil). The two wells have recovered approximately 30 per cent of the load fluid and are still cleaning up. An earlier well, Muskeg 11-24 has produced 29,000 barrels equivalent in the first 51 days with limited decline. Corporate production excluding the two new Muskeg wells is 3,500 barrels equivalent per day. The two new Muskeg wells (15-24, 01-25) have added flush production increasing current corporate production to over 4,600 barrels per day. Two northern Muskeg wells (02-26 and 14-23) have been drilled and completed, and a western Muskeg well (01-23) is currently being drilled. Strategic plans to drill up to six additional wells during the fourth quarter of 2014. Strategic continues to realize drilling efficiencies with the five wells drilled averaging 17 days per well. The company is executing on its cost reduction strategy with its most recent wells averaging $3.7 million. Strategic continues to target 25 per cent production growth with a continuous one-rig capital program, drilling up to 23 wells in 2015, and will provide more formal guidance once the annual budgeting process is complete. OIL & GAS INQUIRER • November 2014
25
Northwestern Alberta
blackbird building montney stronghold blackbird energy Inc. announced in September that through a series of land acquisitions it has acquired, and has entered into an initial agreement to acquire, 85 net sections of Montney prospective land. Eight of the sections are contiguous with the company’s existing Elmworth Montney project, bringing its total contiguous land
block in Elmworth to 36 net sections. The remaining 77 sections of this Montney prospective land acquisition are in East Wapiti, which is located northeast of Elmworth. Blackbird has completed an extensive geological review, and management is excited by the prospects and additional value that the land position presents, the company said.
Upon closing, Blackbird’s total Montney prospective land position will stand at 117 net sections. Eighty-one sections of the land to be acquired are subject to customary industry closing conditions, including execution of a definitive purchase and sale agreement. All acquisitions have been, or will be, funded from existing cash on hand.
Journey reports discovery at Windfall Journey energy Inc. says its Windfall 10-10060-14W5 (100 per cent working interest) horizontal well, completed over 18 intervals in the Beaverhill Lake Formation and production tested from August 9 to August 22, produced 5,416 barrels of 44-degree-API oil and 30.6 million cubic feet of raw gas during a 30-hour extended test. Final flow rates for the last 24 hours of the test were 320 barrels per day of oil, two million cubic feet per day of raw gas and
250 barrels per day of water at a flowing pressure of 300 psi. The produced raw gas was liquids-rich, and recoveries of approximately 50 barrels of natural gas liquids (NGLs) per million cubic feet of raw gas were calculated from the gas analysis. If processed through a facility, this test rate equates to approximately 700 barrels equivalent per day (60 per cent oil and NGLs).
Water c ut s fol lowed a dec l i n i ng trend and decreased throughout the test from 100 per cent to a final water cut of 44 per cent. The gas analysis showed 2.4 per cent CO2 and 0.9 per cent hydrogen sulphide (H2S). Given the H 2S concentration and the lack of acid gas processing on the north side of the Athabasca River, Journey is reviewing tie-in options for the well and a longterm development plan for the resource.
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November 2014 • OIL & GAS INQUIRER
Northwestern Alberta
Journey is reporting success in the Beaverhill Lake Formation.
As a result, the Windfall well is not included in Journey’s 2014 or 2015 production guidance. Further capital requirements and added volumes for Windfall will be determined once the development plan is
complete, and will be included in the company’s 2015 guidance. Drilling of the well will earn and validate 22 sections of land (100 per cent working interest) and the pool is thought to extend over the majority of these sections.
This play represents a potentially significant resource for the company, and there are no reserves currently attributed to the Windfall pool in Journey’s 2013 year-end reserve report, Journey wrote in a press release. The Windfall well cost $4.4 million to drill and complete. Journey expects reductions in drilling and completion costs with larger drilling programs as the field is developed. The company is executing the most active capital program in its history with multiplewell programs in Matziwin, Herronton, Pembina and Countess along with singlewell drills in Manola and Windfall. The program has had 100 per cent success, which is forecast to result in record exit production in excess of 11,200 barrels equivalent per day. August production was in excess of 11,000 barrels per day from field receipts, and the company continues to add new production over and above declines. Guidance for the third quarter remains on track at 10,600 barrels per day. — DAILY OIL BULLETIN
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27
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N.E.
NorTHeASTerN ALberTA WeLL ACTIvITY SEP/13
SEP/14
Wells licensed
93
20
SEP/13
SEP/14
Wells spudded
172
SEP/13
SEP/14
146
111
Rigs released
▲
▼
Northeastern Alberta
▼
Source: Daily Oil Bulletin
Cenovus reports first oil at Foster Creek Phase F Cenovus energy Inc. has achieved first oil production at its recently completed Foster Creek Phase F expansion earlier this month. Phase F is expected to add 30,000 barrels per day of capacity, with production ramping up over the next 12–18 months. By the end of this year, production from Phase F is expected to be approximately 5,000 barrels per day, the company said. Phases G and H are under construction and are each expected to add another 30,000 barrels per day with first production anticipated in late 2015 and 2016, respectively, bringing total expected gross production capacity at Foster Creek to 210,000 barrels per day. Following the completion of phases F, G and H, optimization work is expected to increase total capacity by another 15,000–35,000 barrels per day. Cenovus said it expects the F, G and H expansion and optimization projects can be completed with capital costs of between $35,000 and $38,000 per incremental barrel, better than the industry average. “In July, we indicated that capital costs for the F, G and H expansions were trending higher, and we committed to providing additional information,” said Brian Ferguson, Cenovus president and chief executive officer. “One of the key drivers of the cost increases is the impact of changes we made to the phases that we believe will result in better long-term plant reliability and production efficiency.”
Operations at Foster Creek, where Cenovus expects production to climb to 210,000 barrels per day by 2016.
Changes to the F, G and H expansions include improvements to the oil and water plant, safety systems, completion designs and the incorporation of recent regulatory changes. The revised cost estimate is based on actual costs for Phase F, which Cenovus has used to update cost estimates for phases G and H and optimization. The Foster Creek project has demonstrated consistent performance since a planned turnaround in late 2013, with production averaging between 90 per cent and 95 per cent of plant capacity. In July, production averaged 102,000 barrels per day as volumes were affected
Cenovus SAGD portfolio Foster Creek Christina Lake Narrows Lake Grand Rapids Telephone Lake Working interest (%) Potential size (000, bbls/gross) Design steam to oil ratio Net acres 2P reserves (billion barrels)
0
0
0
100
100
310
310
130
10
300+
2.1
1.
2.1
3.0–3.
2.1
0,00
2,00
13,0
,0
1,00
1.0
0.
0.1
0.0
Source: Cenovus Energy
by scheduled maintenance on the company’s cogeneration facility. August volumes averaged 119,000 barrels per day and September production continues to be strong. Cenovus estimates a planned partial turnaround later in the month will have minimal impact on production volumes. “Foster Creek is a cornerstone asset t hat continues to generate f ree cash flow and strong returns,” said Ferguson. “We believe the changes we’ve made to our latest expansion project will allow us to have more consistent performance as we work towards adding significant new production capacity over the next few years.” Cenovus anticipates Foster Creek’s steam to oil ratio (SOR), which measures how much steam is required to produce one barrel of oil, will range between 2.6 and 3.0 until all F, G and H phases are complete. At that point the SOR is expected to drop below 2.5. Foster Creek is operated by Cenovus and jointly owned with ConocoPhillips. — DAILY OIL BULLETIN OIL & GAS INQUIRER • November 2014
29
Northeastern Alberta
Statoil delays Corner project Citing rising costs and market access issues, Statoil Canada Ltd. says it has decided to postpone the previously planned Corner field development at the Kai Kos Dehseh project in the Athabasca oilsands. As a result of the Corner decision, the company expects to lay off about 70 employees. “Despite the improvements made in the Corner business case, we have decided not to go any further with the project at this stage,” Ståle Tungesvik, Statoil Canada country manager, said. “Costs for labour and materials have continued to rise in recent years and are working against the economics of new projects,” he said. “Market access issues also play a role, including limited pipeline access, which weighs on prices for Alberta oil, squeezing margins and making it difficult for sustainable financial returns.” The decision is in line with Statoil’s strategy to prioritize capital to the most
20,000
barrels per day Statoil Canada’s current oilsands production capacity
competitive projects in its global portfolio and is consistent with the company’s stepwise approach to the oilsands, Tungesvik said. Statoil entered Kai Kos Dehseh through the acquisition of North American Oil Sands Corporation in 2007 for $2.2 billion. In 2011, the Thai company PTTEP farmed into a 40 per cent interest in the project for US$2.28 billion in cash. Earlier this year, Statoil divided its oilsands leases with PTTEP to obtain 100 per cent ownership of the Leismer and Corner projects, while PTTEP took 100 per cent ownership of the Thornbury, Hangingstone and South Leismer areas. The decision has no implications for the Leismer SAGD development, which is in production and has an operating capacity of 20,000 barrels per day. In August, well pad five came on stream and work is ongoing on further infill drilling activity. — DAILY OIL BULLETIN
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November 2014 • OIL & GAS INQUIRER
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Northeastern Alberta
Sarnia-Lambton refinery could be boon for oilsands by Carter Haydu
A proposed $10-billion bitumen refinery in Ontario’s Sarnia-Lambton area would be a win for Alberta’s energy sector, Ontario’s petrochemical industry and the Canadian economy, said proponents of the 150,000-barrel-per-day project. “Eventually, we have to start adding value to our raw materials,” said Clem Bowman, founding chairman of the A lber ta Oi l Sa nds Tec h nolog y a nd Research Authority and a former research head at Imperial Oil Limited. “Almost all the new bitumen production that is planned is headed for Texas and is going to be refi ned outside of Canada. Someone must stop this process, and we think we have a group here that can show how this could be done differently for the benefit of Canada and Alberta.” The Canadian Academy of Engineering (CAE) selected a Sarnia-Lambton bitumen upgrading project as key for several practical reasons, including pipeline connectivity
to Alberta, seaway access for both eastern domestic and international markets, as well as the long-established, currently underutilized petrochemical expertise in Ontario’s “Chemical Valley,” Bowman said. “We must get some congruence from visionaries of both the public and private sectors to move this project along.” On August 28, at the Western SarniaLambton Research Park, proponents launched their plan for a $300,000 prefeasibility study into the project and asked for support from both the private and public sector. The study already received $150,000 from private backers, and Bowman said he is now pushing for the governments of Canada and Ontario to pitch in as well. “We need to get the other $150,000 from government. We could get that from the private sector also, but we need government to be involved and signal that it sees this as important for Canada. I would
be surprised if we were not able to get the additional $150,000 in the next two or three months. In fact, we have a full-court press out now on both the Ontario and federal governments.” Public participation is important, Bowman said, because all of the largest projects in Canada have come about through government and industry collaboration, with governments assuming at least some of the risks. Don Wood, associate with the Bowman Centre for Technology Commercialization, said that a major advantage of a SarniaLambton refinery project would be the access to nearly 2,000 skilled construction labourers who are available for work and would provide significant cost advantages on the labour front. He said the added jobs would be a boost to Ontario generally and the Sarnia-Lambton area specifically. “It would be at least a 5,000-person construction team for at least two years to
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31
Northeastern Alberta
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November 2014 • OIL & GAS INQUIRER
build. Plus, the refinery itself and the associated business management with the refi nery looks like it would provide jobs for about 1,000 people.” According to the CAE publication Canada: Becoming a Sustainable Energy Powerhouse, a Sarnia-Lambton bitumen upgrader refi nery would provide an acceptable return on investment if it produces gasoline, diesel and other value-added petroleum products in an area that is on the threshold of the massive U.S. Midwest energy market. Wood said, “This location is the centre of the North American market for both fuels and chemicals. We have half the population of North America within a day’s drive of this location, and there is a deficit of both gasoline and diesel fuel in the immediate area.” There is an opportunity to expand the nation’s petrochemical industry as well, Wood added, fi lling a hole left when ethylene plants switched to light feeds. While many people in Central Canada might be under the impression that bitumen is “dirty tar sands,” Bowmen said the fact is that bitumen is a crude oil with higher asphaltene content and a wide variety of unique chemical compounds with lots of aromatic ring structures—a big bonus for Ontario’s downstream sector. “These are precursors to a petrochemical industry, and so our whole concept is that what we are going to do here is not just another outlet for ‘dirty tar.’ We’re going to take the bitumen and do something unique with it. We’re looking at this as a petrochemical refi nery, and we are saying it is the fi rst refi nery that is designed and built to capture the unique properties of bitumen. “It has been known for many years that bitumen is a treasure house of chemicals that would be important for the chemical and pharmaceutical industries. It just needs a different kind of processing than what has been used before. We’re taking a new look at this, and we’re trying to present this as the next stage in the evolution of the oilsands. If we can make this click, then it will open up opportunities across Canada to feed international markets.” According to Bowman, many Alberta producers see an opportunity to extend their marketplace and diversify into a wider range of products with a Sarnia-Lambton refi nery. However, he noted, for multinational companies with refineries already in Texas, sentiments toward the proposed project have been cold because it does not fit into their immediate interests. “That’s the short-term economics for a single set of shareholders, and we’re talking about something that will be a long-term, longrange benefit for Canada,” he said, adding even the multinationals would come around to a more positive view of the project once it gets started. As for the pre-feasibility study, Wood said it is to occur in two parts—fi rst with identification of a major lead and major investor for the project, followed by a six- to nine-month preliminary look at the project as a whole. “After that, if it continues to look appealing enough to get us through the next gate, then it becomes a full-blown feasibility study that would take about 15–18 months and cost in the order of $50 million. That would then lead to sanctioning of the $10-billion project, which would take about two years to build.”
Northeastern Alberta
rail transport better for small projects by Carter Haydu
For smaller oilsands projects, rail transport is easily a better option than pipelines, a crude-by-rail conference heard in late September. Grizzly Oil Sands ULC, for example, focuses on smaller SAGD projects in the Alberta oilsands that lend themselves to crude-byrail as it is fairly difficult to justify the cost of pipeline connections for facilities that produce upwards of only 8,000 barrels per day, said Glen Perry, vice-president of marketing. “Probably to justify a pipeline of any distance you would require 20,000 to 30,000 barrels per day, and so essentially these plants are ideally suited for rail logistics — they’re small, they’re scalable, and so is rail,” he said. According to Perry, the costs of transporting heavy crude by rail or pipeline over a similar distance are comparable. “If you are looking at long-term alternatives, then there really is little difference between the cost of pipeline and the cost of rail,” he said.
“If you are looking at long-term alternatives, then there really is little difference between the cost of pipeline and the cost of rail.” — Glen Perry, vice-president, marketing, Grizzly oil Sands ULC
It costs about $26.50 per barrel to pipe diluted bitumen from Fort McMurray to the Gulf Coast, taking into account the cost of shipping the diluent with the crude, Perry told the Canadian Crude Markets & Rail Takeaway Summit. In comparison, railbit costs about $26 per barrel to move the same distance all things considered, he said, and producers do not have to deal with pipeline issues such as the requirement to sign up to long-term contracts. Rail also is beneficial in a rapidly-changing energy market because railways can link to multiple markets, whereas a pipeline goes only to a single destination, Perry pointed out. “The question is: Why would you build any new pipe for heavy oil?” Although the economics are better for moving Alberta’s heavy crude by rail, he noted, today in North America the majority of oil on railcars is actually light oil, which might make less economic sense but accommodates current pipeline limitations. “The light oil is moving by rail because pipe doesn’t exist or it has been delayed. Certainly out of the Bakken that is the conclusion. Although there certainly are a lot of proposals to build pipelines out of the Bakken, they have not been built yet,” Perry said. OIL & GAS INQUIRER • November 2014
33
CeNTrAL ALberTA WeLL ACTIvITY SEP/13
SEP/14
Wells licensed
246
212
SEP/13
SEP/14
Wells spudded
214
212
SEP/13
SEP/14
211
202
Rigs released
C.A.B.
▼
▼
Central Alberta
▼
Source: Daily Oil Bulletin
Tourmaline expects massive production increase of 43,000 barrels equivalent in final quarter Area/plant
2014 exit volume
2015 exit volume
MMCF/D
MMCF/D
Alberta Deep Basin Wild River
Musreau
Banshee/Edson
Smoky/Berland/Leland
Hinton/Anderson
Voyager/Harlech/Hanlon
Deep Basin total
Sunrise-Doe
Sundown
Northeastern B.C.
West Doe (Spectra)
Northeastern B.C. total
Peace River High Tourmaline Spirit River
Spectra Gord E/Fourth Ck
Peace River High total
Grand total
,
Tourmaline gas growth outlook (assumes 20 drilling rigs through exit 2015)
Tourmaline oil Corp. plans to add 43,000 barrels equivalent per day of new sustained production during the balance of 2014 through the completion and start-up of five new facility projects. The first of these projects, the compression and dehydration facilit y at Sundown, B.C., commenced production during the first week of September and will allow for 50 million cubic feet per day of incremental production during the fourth quarter. The Musreau, Alta., and Doe, B.C., 50-million-cubic-feet-per-day plant expansions are both on schedule to
Source: Tourmaline Oil & Gas
commence production during the first week of October. Construction of the Spirit River 03-10 sour gas injection plant will be completed by mid-October and start-up of the sour gas injection site and electrical power generation capability at the plant will be completed during the second half of October, with the plant achieving full production in early November. The Wild River 50-million-cubic-feetper-day plant expansion is currently under construction and remains on schedule for an early December start-up. The associated Berland-Wild River pipeline lateral will
be completed in October. This lateral will provide incremental natural gas volumes for the 100-million-cubic-feet-per-day Wild River plant expansion in 2015. These significant production additions during the last four months of the year will allow the company to achieve a fullyear 2014 average production guidance of 120,000 barrels equivalent per day and a 2014 exit volume of 150,000–155,000 barrels equivalent per day. Tourmaline continues to operate 20 drilling rigs and has drilled 68 new wells since spring breakup. Strong well results continued in all three core operated areas. The company drilled and completed 45 horizontal wells in the Alberta Deep Basin through to September 2014. Of the 33 wells that have 30 days of production history, 32 have exceeded the internal company 30-day IP template of five million cubic feet per day. The average 30-day IP of these 33 wells is 10.6 million cubic feet per day. The initial Triassic Doig horizontal at Sundown production tested at 15.2 million cubic feet per day at a flowing casing pressure of 14.5 MPa during a three day test. The company has a very large inventory of Doig horizontal locations in British Columbia that complement their existing Montney inventory. Tourmaline’s initial Dunvegan duplex vertical new pool wildcat in the Alberta Deep Basin production tested at 17.3 million cubic feet per day at a flowing pressure of 9.7 MPa during a three-day production test. Multiple step-out locations are planned on the original 3-D seismic defi ned feature and the company has captured additional identical 3-D defi ned features elsewhere in the Deep Basin. The Dunvegan duplex play is one of several OIL & GAS INQUIRER • November 2014
35
Central Alberta
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$1.35
billion
Tourmaline’s updated 2014 capital budget
high-potential new plays that the company is pursuing in the Deep Basin, complementing the enormous existing Cretaceous development drilling inventories. Tourmaline is the fi fth largest Triassic Montney producer in western Canada through ongoing development of the Sunrise-Dawson-Sundown area, where the company just completed drilling the 110th horizontal liquids-rich Montney well. The Sunrise-Dawson-Sundown complex, however, is only the first of four Montney areas that it plans to develop. Tourmaline has extensive land holdings and drilling inventories in the Montney play areas at KakwaResthaven, the emerging liquids-rich Montney play at Pouce-Coupe-Progress and the developing Montney area at BlueberryInga-Red Creek in British Columbia. The company plans multiple horizontal wells in these three emerging areas during the next 18 months to complement the ongoing activity at Sunrise-Dawson. On the Peace River High Charlie Lake oil complex, the 01-22 Earring well is producing at 570 barrels of oil per day after the first seven days of production. This is the third well at Earring, located at the northern end of the 70 mile long Charlie Lake pool. Tourmaline expects to have an additional 25 wells on production from the complex by year end. The company has increased f ullyear 2014 capital spending guidance by $100 million to $1.35 billion due to the acceleration of the second Wild River facility expansion from 2015 to 2014 and the drilling of approximately 25 more wells in 2014 than originally planned in the 15-rig program. This has resulted in an increase in 2015 preliminary production guidance from 159,000 to 164,500 barrels equivalent per day. — DAILY OIL BULLETIN
36
November 2014 • OIL & GAS INQUIRER
Central Alberta
Calfrac reports annular fracturing milestone in Cardium
IT’S ALL
V
Fracking
IN THE POND Above Ground Water Storage Systems
Calfrac Well Services reports it has successfully completed four high-rate annular sleeve slickwater fracs in the Cardium Formation since the start of 2014. The company said proper job designs and equipment selection have allowed for annular rates in excess of 7.5 cubic metres per minute, while maintaining service delivery and superior coiled tubing equipment performance in an extremely abrasive environment as the historical erosion velocity limits were surpassed. In addition, Calfrac has just completed a 15,000-psi high pressure annular frac in the Montney Formation using a specially designed two-inch HPHT high integrity coiled tubing string. “Engineering, technical and HSE planning enabled a successful execution of this treatment, which had sand perforating cutting pressures of approximately 12,000 psi and fracturing placement pressures of 11,000 psi, with a coiled tubing string in the wellbore,” the company said. Calfrac was scheduled for its second well in September.
Easy build and breakdown Storage up to 132,000 barrels n Well-engineered for transport n Lower transport and install costs n One truck delivery for most ponds n n
Calfrac reported annular rates of 7.5 cubic metres per minute. The company is one of the forefathers of the CoilJet technique, which uses coiled tubing for sand abrasive perforating, followed by fracturing via the coiled tubing and casing annulus. This has evolved into the annular sleeve systems that are heavily used in several key basins such as the Bakken, Viking, Cardium and Montney. “Calfrac has grown its market share in the integrated business by working closely with its completion counterparts to refine the processes, techniques, equipment and job design to generate incredible efficiencies. Specifically in the Viking Formation, Calfrac has obtained a 97 per cent success efficiency and has tripled its presence in the last year.”
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OIL & GAS INQUIRER • November 2014
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November 2014 • OIL & GAS INQUIRER
by richard macedo
Chevron Corporation is seeking a partner for its Duvernay shale gas play development, says the company’s chair and chief executive officer John Watson. “We have been looking for a partner in the Kaybob Duvernay area,” Watson said. “Our interest is 100 per cent virtually, and it’s quite normal for us to have a partner, so we have been looking to take on a partner as a normal…process of developing resources.” What type of partner comes into the project “remains to be seen.” Watson added the company is very excited about its Kaybob Duvernay acreage. “We’ve put together over 300,000 net acres; third parties have suggested that we have some of the choice acreage in that play,” he noted. “We’re commencing pad drilling now. We’ve got two rigs that are operating; we have an opportunity to ramp up to 10 rigs over the course of the next decade. It’s as good an opportunity as we have in our portfolio, based on what we’ve seen so far for liquidsrich plays.” The Chevron CEO was questioned about the state of the Kitimat LNG project. Its 50 per cent partner, Apache Corporation, announced earlier this year that it intends to completely sell its stake in the proposed multi-billion dollar project. Watson, who visited the Kitimat site in September, said there’s been good progress made on site clearance and clearing the pipeline right-of-way. “Chevron hasn’t stated an FID [final investment decision] date; we’ll make an FID when a number of condition precedents are met,” he noted. “Several of the items that have to be completed before we’ll take FID include having certainty on fiscal arrangements with the Government of British Columbia, [and] it includes having agreements with all First Nations. We’ve made good progress in that regard, but certainly First Nations peoples have their requirements.” Watson said there are agreements with 15 of 16 First Nations. “We’ve made progress with the 16th, and I expect we’ll be able to reach agreement. We’ve had good discussions. The key to that is to listen to their needs and expectations and create a situation where it’s a win for them, a win for us and a win for Canada.” The company is also working its way through necessary engineering and cost estimates. “We need gas contracts, and we need a partner because our current partner has decided to exit the project, and so when all those conditions are met, we’ll take FID.” Chevron officials have repeatedly said that the company is not going to go to FID on a project until it has 60–70 per cent of the gas sold. With regard to LNG generally, Watson said that worldwide, there’s been pressure on LNG projects. “We have a number of projects that are under construction in Australia and starting in North America. Right now the projects that are moving tend to be those that are on the Gulf Coast of the United States where they have an infrastructure advantage,” he noted. “There will need to be a meeting of the minds between gas
Central Alberta
purchasers and producers to make sure that the cost-price relationship is balanced so that projects can continue to move forward to bring the supplies to meet the growing demand.” In terms of securing gas contracts, Watson said the company continues to have regular contact and discussions with gas purchasers.
Study says new upgrader would be profitable A new upgrading refinery and petrochemical complex in Alberta is likely to be profitable and to generate favourable economic returns—so much so in fact that it would meet many of the criteria necessary to attract private sector investment, says a study commissioned by the Alberta Federation of Labour. The study, Upgrading Our Future: The Economics of In-Province Upgrading, found that the project would be economically viable at WTI prices of between $80 and $120 per barrel. “Based on existing capital cost estimates and arm’s-length purchases of feedstock at market prices, the project appears to be attractive with NPV (net present value) and IRR (internal rate of return) showing good returns under all three crude oil price cases,” says the report. The calculated IRR is 19 per cent at $80 per barrel, 22.6 per cent at $100 a barrel and 25.6 per cent at $120 per barrel. The base case assumes that the diluent return stream would be sold to oilsands producers at a market-related transfer price (WTI plus five per cent). The objective of the study was to examine the potential economics of in-province upgrading of Alberta oilsands and whether it’s something that should be looked at in more detail. The report, authored by Ed Osterwald, a senior partner with United Kingdombased Competition Economists Group (CEG), was released Monday at a forum in Edmonton. The AFL’s position is that the province should consider the idea of an upgrading and refinery complex and “give it its due,” Shannon Phillips, a policy analyst with the AFL, said in an interview. The federation believes that in-province upgrading is important only because it is something Albertans want but that they are at the mercy of fluctuating commodity prices that often result in cutbacks to health, education and other essential services, said Phillips. Osterwald told the forum that private companies would begin to be interested in developing a project with an IRR of 14 per cent. The new study updates a 2006 study by David Netzer, Consulting Chemical Engineer and Associates, commissioned by the government of Alberta under the Hydrocarbon Upgrading Task Force, a joint industry and government initiative. CEG used information from the earlier study to develop an operating cash flow model of the proposed project along with other factors such as CEG’s price forecasts, discount rate and projected fi xed and variable costs. On the basis that the project is commercially attractive and viable, the onus is likely to be on the Alberta government to move it forward, in the initial stages at the very least, says the report.
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SoUTHerN ALberTA WeLL ACTIvITY SEP/13
SEP/14
Wells licensed
47
SEP/13
SEP/14
Wells spudded
87
SEP/13
SEP/14
84
2
Rigs released
▲
▼
▼
Source: Daily Oil Bulletin
S.A.B. Southern Alberta
manitok updates operations at entice manitok has drilled a horizontal well at 03-28-022-25W4, testing the middle Basal Quartz (BQ) Formation in the southern end of the Entice field. This is the second well of a planned 10-well horizontal drilling program at Entice, where Manitok has a 100 per cent working interest. The well was completed using multistage fracturing technology. A 15-stage fracture completion was successfully executed, and the well began flowing on its own. During the production test, the well flowed for a total of 3.3 days at an average rate of 135 barrels per day of 30-degreeAPI oil and 420 thousand cubic feet per day of natural gas for a total rate of 205 barrels equivalent per day. The flowing pressures were stable throughout the production test. The cost to drill and complete the well was approximately $2.9 million. Manitok said these results proved there is a significant number of potential development drilling locations. The company has interpreted the depositional environment of the BQ pool as shallow marine sands, as opposed to channel sands. The formation has significant areal extent that is supported by log data, rock samples, seismic data and oil shows throughout the mapped area. There are five to seven immediate off set horizontal drilling locations, and Manitok believes the opportunity could cover approximately 10–12 sections of prospective land and would likely require four wells per section to optimize primary recovery. The 03-28-022-25W4 well is near the previously announced 15-32-022-25W4 Lithic Glauconitic well, which flowed for approximately six days at an average rate of 761 barrels equivalent per day, which included 328 barrels a day of 40-degreeAPI oil and 2.6 million cubic feet per day
of natural gas. The wells on both pads are expected to be tied in and on production in the fourth quarter of 2014. With the success of the first two wells of the program, Manitok said it now has 10–12 immediate offset horizontal well locations at the southern end of Entice, which could increase significantly in time as each trend is further developed. Manitok has also drilled the 03-09-02325W4 horizontal well in Entice, testing a
135
barrels per day
Results of three-day test on 15-stage completion Entice well
Manitok plans on drilling 10 horizontal wells with multistage completions at Entice.
lower BQ Formation in the southern end of the land base, and expects to begin the multistage fracture completion this fall. The drilling rig has moved to a Glauconite location, off setting the previously announced successful 15-32-022-25W4 Glauconite well. This rig will continue to drill wells in both the successful Glauconite and BQ new pool discoveries at the southern end of Entice until spring breakup in early 2015. Given the encouraging results to date at Entice, Manitok has mobilized a second rig to drill a
horizontal Glauconite well with similar log and seismic characteristics as the successful 15-32-022-25W4 well. This rig will follow up with other horizontal Glauconite and BQ wells in both the central and northern portions of the Entice land base, including a horizontal offset to the successful 06-16028-24W4 vertical BQ well. The second rig will test up to five different oil pools (two Glauconite pools and three BQ pools) before spring breakup in early 2015. — DAILY OIL BULLETIN OIL & GAS INQUIRER • November 2014
41
Southern Alberta
Strong summer drilling results push Hemisphere production As a result of the successful summer drilling program, Hemisphere Energy Corporation has achieved record corporate production, an average of 900 barrels per day (92 per cent oil) based on field estimates, during the first two weeks of September. The last three wells from the summer drilling program, drilled off the same
Within an 11-week period, Hemisphere drilled, completed, equipped and brought on st rea m f ive hor i zont a l wel l s i n Atlee Buffalo. Results from the company’s first six Atlee Buffalo wells show initial flush production rates 60 per cent higher than originally budgeted, with drilling costs from the summer drilling program 10 per cent below
nine-month payouts, $2.4 million net present values discounted at 10 per cent before tax and 175 per cent rates of return. Hemisphere’s first Atlee Buffalo well, which went on production in February 2014, has averaged $60-perbarrel netbacks through 2014. Since the company purchased the Atlee Buff alo property in November 2013, production has grown from 60 barrels equivalent
Hemisphere has identified 65 drilling locations at Atlee Buffalo. pad in Atlee Buffalo, have been on stream for approximately 30 days. During the first two weeks of September, each well averaged over 100 barrels of oil per day for a combined rate of 340 barrels of oil per day. During the summer, Hemisphere successfully completed the first five-well drilling campaign in its corporate history.
42
November 2014 • OIL & GAS INQUIRER
budget due to the use of multi-well pads and efficiencies of the larger-scale program. The economics associated with the Atlee Buff alo Glauconitic horizontal wells are robust. Hemisphere estimates ultimate recovery of 100,000 barrels equivalent per well. Based on an average drill, completion and tie-in cost of $1.15 million, the wells have
per day to current rates of over 520 barrels per day, and Hemisphere has identified up to 65 additional locations. Hemisphere has continued to consolidate its land position in Atlee Buffalo. During the summer, the company closed another acquisition that added 85 per cent working interest in 1,120 net acres of land adjacent to its existing land base.
SASKATCHeWAN WeLL ACTIvITY SEP/13
SEP/14
Wells licensed
330
3
SEP/13
SEP/14
Wells spudded
369
2
SEP/13
SEP/14
372
2
Rigs released
▲
▲
▲
Source: Daily Oil Bulletin
S.K. Saskatchewan
Spartan production up sixfold Spartan energy Corp. improved production 666 per cent during the second quarter of 2014, up to 6,396 barrels equivalent per day compared to 835 barrels per day during the same quarter in 2013, primarily as a result of acquiring Renegade Petroleum Ltd. earlier in 2014. The second quarter was quiet operationally due to the onset of breakup conditions in the field, said Spartan. The limited activity that the company did budget for in southeastern Saskatchewan was hampered by wet weather. Its development drilling program, which was expected to begin in early June, was delayed for about two weeks by rain. In late June, wet weather caused flooding in parts of southeastern Saskatchewan, which further delayed drilling and required Spartan to temporarily shut in approximately 700 barrels equivalent per day of production. Despite the weather-related challenges, the company managed to drill three (2.5 net)
development wells during the second quarter, all of which were awaiting completion at the end of the quarter. In addition, the company drilled two vertical wells in southeastern Saskatchewan, testing an exploration play. One well has been abandoned, and the other was cased for further evaluation. Conditions improved in the latter part of July, and Spartan now has two drilling rigs operating in southeastern Saskatchewan. “Although downtime and delays to our capital program experienced due to the rain and flooding in June and July are expected to impact average production levels in the third quarter, the company remains positioned to meet its stated 2014 average production rate of 5,700 barrels per day and exit production rate of 8,600 barrels per day,” the company said. Spartan delivered strong operating netbacks of $47.12 per barrel in the quarter, driven by a realized oil and liquids
Despite wet weather, Spartan continued development of its Saskatchewan leases in the second quarter.
price of $99.23 per barrel but offset by realized hedging losses of $12.49 per barrel. The company’s corporate netback was $41.86 per barrel, generating funds flow from operations in the quarter of over $24 million. Absent the impact of the hedges, which expire at the end of 2014, the company had an operating netback in excess of $59 per barrel in the quarter and cash flow of approximately $31.5 million. To date in the third quarter, Spartan has brought six new wells on production with two additional wells completed and waiting to be brought on stream. Spartan said it has amassed a sign i f ica nt la nd base i n sout heaster n Saskatchewan with an extensive inventory of drilling locations that position the company for future growth. With two drilling rigs now active in southeastern Saskatchewan, it is focused on executing its capital program for the remainder of the year. The company intends to operate two rigs in the area through the remainder of 2014 and add a third rig later in the year. It also intends to activate an additional rig late in the third quarter to drill the remainder of its 2014 Viking drilling program. Building on its second-quarter acquisitions that closed in early July, the company continued to consolidate its asset base in the third quarter. It has completed two additional asset acquisitions and has entered into an agreement for a third acquisition. Together, the acquired assets consist of around 130 barrels per day of production and 10 net sections of land in southeastern Saskatchewan for consideration of approximately $15.4 million. The acquisitions add approximately six net sections of land, directly off setting the company’s existing acreage in the Queensdale and Wordsworth areas, with 19 net identified drilling locations and approximately four net sections of land in the Souris Flats area. In addition, OIL & GAS INQUIRER • November 2014
43
Saskatchewan
Spartan has identified nine net locations that can now be drilled on its existing land base as a result of the acquisition of adjacent sections and facility infrastructure. Together with the company’s previously announced Midale acquisition, these acquisitions further consolidate Spartan’s core position in the Frobisher and Midale fairways in southeastern Saskatchewan, it said. In the Midale play, Spartan now has more than 47 net sections of land, including 20 net sections in the Pinto area, where off setting wells have delivered IP30
rates exceeding 250 barrels equivalent per day. Spartan has initially identified 75 net potential fracture-stimulated drilling locations on its Midale acreage. In addition, the company said, it has numerous conventional open-hole Midale locations across its land base. On July 7, 2014, Spartan completed two further asset acquisitions, which included undeveloped land, seismic and certain petroleum and natural gas properties in southeastern Saskatchewan, for a total cash consideration of approximately $115 million,
excluding transaction costs and closing adjustments. On Aug. 12, 2014, Spartan completed an acquisition that included undeveloped land, seismic and certain petroleum and natural gas properties in southeastern Saskatchewan for a total consideration of approximately $11 million, excluding transaction costs and closing adjustments. On Aug. 13, 2014, Spartan entered into an agreement to acquire undeveloped land and certain petroleum and natural gas properties in southeastern Saskatchewan for a total cash consideration of approximately $4.4 million.
CAPP’s new president former Saskatchewan energy minister Tim mcmillan, a former energy a nd resources minister in the Saskatchewan government, is the new president of the Canadian Association of Petroleum Producers (CAPP) effective Oct. 1, 2014. Currently minister of rural health in Saskatchewan, McMillan will become chief executive officer and president following the planned retirement of Dave Collyer at the end of this year, announced Glenn Scott, chair of CAPP. The new president has a strong connection to the energy industry over many years, including ownership of an oilfield services company.
“Tim McMillan brings extensive knowledge and experience in both the oil and gas industry and government,” Scott said. “He is well-positioned to lead CAPP’s activities in the policy and regulatory area, and in communications, both of which are extremely important to the continued success of our industry.” Scott said the CAPP selection committee considered a broad range of candidates as it conducted the search for a new CEO, ref lecting the scope and importance of the role. “We are confident that Tim McMillan has the skills,
experience and energy necessary to lead CAPP, particularly as we engage more broadly across Canada.” McMillan, who was fi rst elected as an MLA in 2007 and was re-elected in 2011, grew up on his family farm, 20 miles east of Lloydminster, where his family homesteaded more than 100 years ago. He attended the University of Victoria, where he received a degree in economics. After his schooling, McMillan travelled and worked abroad extensively. Prior to his election in 2007, McMillan operated an oilfield services company.
Disposal well surprises Tuscany with oil pay To the surprise of executives at Tuscany Energy Ltd., a water disposal well drilled at the company’s Macklin property in Saskatchewan struck nine metres of oil pay in the Dina Formation. The vertical step-out well was drilled to 1,011 metres as a potential Duperow water disposal well, although it was also oriented to test a potential extension of the adjacent Dina oilfield being developed by Tuscany. Dur-ing drilling, about nine metres of 33 per cent porous sandstone was encountered in the Dina, with log characteristics identical to wells producing in the same field, management said in a September news release. 44
November 2014 • OIL & GAS INQUIRER
14
Number of potential drilling locations as a result of the Dina heavy oil discovery Tuscany has a 100 per cent working interest in the well located at 07-33-03928W3, which will be completed as a disposal well in the next month, allowing the company to significantly boost its waterhandling capacity. That, in turn, will help to increase the company’s oil production
and allow the junior to tie in three wells that are currently shut in. Management said fi nding Dina oil pay in the new well is significant, since it could mean up to 14 more unbooked horizontal development drilling locations in the Dina and expand the Macklin pool to the north, all on Tuscany-controlled, 100 per cent working interest lands. In addition, Tuscany said it has completed its capital program, drilling five horizontal heavy oil wells. Management will update the market with estimated flow rates on the wells when they have been tested, the company said.
Saskatchewan
SaskPower launches carbon capture project What the project’s owner is calling the world’s first post-combustion, coal-fired carbon capture and storage (CCS) project was commissioned in early October in Saskatchewan. W hile prov incial power producer Sask Power star ted up the Boundar y Dam power plant in 1959, it recently rebuilt the plant’s aging Unit #3, adding carbon capture technology to allow the unit to produce 110 megawatts (MW) of power while cutting greenhouse gas (GHG) emissions by one million tonnes of carbon dioxide (CO2 ) per year, according to SaskPower figures. The re-tooled plant, just 10 miles north of the Canada-United States border, began capturing carbon dioxide in September and the gas will be injected into nearby oilfields for enhanced oil recovery (EOR) projects. In December 2012, Cenovus Energy Inc. and SaskPower signed a 10-year agreement for the purchase of the full volume — about 57 million cubic feet per day of carbon dioxide—from the coal-fi red power station. News of SaskPower’s CCS launch did not go unnoticed in Europe, where the Paris-based International Energy Agency (IEA) welcomed the launch, calling it a “historic milestone along the road to a low-carbon energy future.” In a written statement, Maria van der Hoeven, IEA executive director, said the launch represents a “momentous point in the history of CCS development, the family of technologies … that enable the capture of CO2 from fuel combustion or industrial processes, its transport via ships or pipelines, and its storage underground. “CCS is the only known technology that will enable us to continue to use fossil fuels and de-carbonize the energy sector,” she added. “As fossil fuel consumption is expected to continue for decades, deployment of CCS is essential.” She commended Canada for its role in making the SaskPower project a reality: “Getting Boundary Dam up and running is a great example of how Canada is a leader
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OIL & GAS INQUIRER • November 2014
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Saskatchewan
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Enhanced recovery will be needed to make the CCS scheme successful.
in CCS,” she said. “The experience from this project will be critically important. I wish the plant operator every success in showing the world that large-scale capture of CO2 from a power station is indeed not science fiction, but today’s reality.” The IEA believes CCS will play a central role in an ambitious, climate-friendly future energy scenario, accounting for one-sixth of required emissions reductions by 2050. IEA analysis has shown that without significant deployment of CCS, more than two-thirds of current proven fossil-fuel reserves cannot be commercialized before 2050 if the increase in global temperatures is to remain below two degrees Celsius, the agency said. According to a study published earlier this year, EOR in Saskatchewan would be key to the success of any large-scale CCS project. The study, ACCS Deployment Plan for Saskatchewan, by advocacy group ICO2N, said oil prices of at least $100 per bbl (WTI) make for an economic case to pursue EOR opportunities in western and southeastern Saskatchewan.
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Feature
VIKING CONQUEST
48
November 2014 • OIL & GAS INQUIRER
Feature
Operators aggressively target Viking tight oil play, driven by low costs and high netbacks By Darrell Stonehouse
Low drilling and completion costs, combined with high netbacks, have made the Viking tight oil play running from west-central Saskatchewan westward into central Alberta the busiest resource play in western Canada. In 2013, 1,235 wells were drilled into the play, with total production averaging over 40,000 barrels equivalent per day. At play is around four billion barrels of original oil in place, with only four per cent recovered since the Viking was first drilled in the 1950s. While wet weather this spring and summer slowed Viking development, the major operators in the play expect to catch up in the final two quarters of the year. Penn West Petroleum, one of the early entrants into the Viking, spent only $10 million in the second quarter of 2014, drilling eight wells. But company president and chief executive officer David Roberts said in his second quarter report to shareholders that the remainder of the year should be busy. “Our second half 2014 program is significant with 84 wells planned and approximately 75 wells scheduled to be on production by the end of the year,” Roberts said. “In southwestern Saskatchewan wet weather caused a minor delay in our Viking program where we have two rigs operating to execute our development program in the second half of 2014.” Roberts said Penn West has two major initiatives underway to grow reserves and cut costs in the Viking. The fi rst is a 16-wellper-section down-spacing program that is generating positive results. The company is testing down-spacing programs across the Viking. “As the largest acreage holder in the core of the Viking play, an expanded down-spacing program would significantly increase the existing 400–500 drilling locations we have estimated,” he said. Penn West also continues to drive down drilling and completion costs in the Viking. In 2011, it reported costs of $1.1 million per well, but by early 2014, that cost had declined to around $840,000.
OIL & GAS INQUIRER • November 2014
49
Feature
Viking 2013 horizontal oil production Company
Operated wells
Oil (bbls/d)
Teine Energy
329
5,379
Penn West Exploration
275
4,574
Whitecap Resources
199
3,929
Raging River Exploration
154
3,697
Long Run Exploration
165
3,414
Novus Energy*
182
2,975
Crescent Point Energy
198
2,337
Renegade Petroleum**
137
2,332
NAL Resources
104
2,169
Husky Energy
143
2,156
Mancal Energy
55
1,514
Polar Star Oil & Gas
73
1,240
Devon Nec Corp.
43
1,101
Home Quarter Resources
44
963
ISH Energy
70
889
Baytex Energy
35
850
Tamarack Valley Energy
42
800
Apache Canada
34
695
2,282
41,014
Total Raging River has identified over 2,400 Viking drilling locations.
* Now Yangchang Petroleum **Now Spartan Energy
“In our second half program, we also plan to reduce our cost per well to below $800,000 from what we believe to already be a best-in-class cost of $840,000,” he said. Penn West expects to spend around $140 million in the Viking in 2014, with around $130 million planned for 2015. Viking pure player Raging River Exploration continues driving up production while adding to its already significant land base. Raging River’s production for the second quarter of 2014 increased to 9,960 barrels equivalent per day from 4,620 barrels per day during the same period last year, an increase of 116 per cent. The year-over-year increase was attributable to a successful drilling program in 2013-14 combined with a property acquisition that closed late in the fourth quarter of 2013. Production levels moderated through breakup to lows of 9,600 barrels per day and have now begun to increase concurrent with capital activities, with production in excess of 10,500 barrels per day. The company reported record operating netbacks of $72.16 per barrel and very strong funds flow netbacks of $62.09 per barrel in the quarter. Raging River has completed a sequence of consolidated transactions of Viking light oil assets, primarily in its core area of Forgan, adding 12,000 net acres of land and an estimated 125 horizontal drilling locations. The company drilled a total of 22 net horizontal Viking wells, testing 14 undrilled sections of land in the second quarter. In all cases, the geological data was compelling with all wells cased and completed, it said. Third quarter to date, 23.9 additional net wells have been successfully drilled, testing 10 new sections. These wells
are currently in various stages of completion. The third quarter of 2014 is expected to be Raging River’s busiest quarter on record with 75–80 net wells expected to be drilled. At Forgan, six wells drilled in the first quarter of 2014 have all been on production for more than 120 days, with average rates of 40 barrels per day of oil. The company said that 16.2 net wells have been drilled since June with 10.9 net wells testing previously undrilled sections. These wells have successfully extended the boundaries of the proven economic edges of the play. The company added 15 net sections of land through the consolidation transactions. At Beadle, 17.8 net wells have been drilled since June 2014 at 100 per cent success. Raging River said that nine of the wells drilled since June have tested previously undrilled sections. Early time production results from these wells have been favourable, again extending the boundaries of the proven economic edges of the play. The 39 wells placed on production in the area in 2014 have shown 150-day average oil rates of 37 barrels per day, which is consistent with the 30 wells drilled in the area in 2013. At Plato, 16 wells placed on production in the first quarter of 2014 have shown six-month average oil rates of 50 barrels per day, which are the strongest wells drilled in the area to date. Speaking at the company’s annual meeting, president and chief executive officer Neil Roszell said Raging River drilled around 400 operated and non-operated wells into the Viking in 2012 and 2013. Roszell said average well costs are between $875,000 and $925,000, and cycle times are about 20 days per well.
50
November 2014 • OIL & GAS INQUIRER
Source: TD Securities Playbook
Feature
Viking 2013 oil wells (Saskatchewan and Alberta) DIRECTION Operator
“ We’re not scared to drill dry holes. That will happen over time.” — Neil Roszell, president and chief executive officer, Raging River Exploration
DIR
VERT
Total
3 Martini Ventures
1
1
Anegada Energy
2
2
Apache Canada
22
22
Beaumont Energy
67
Bonavista Energy
15
15
Canadian Oil & Gas International
1
1
Canuck North Resources
3
3
Cardinal Energy
3
3
40
40
Devon Canada
5
5
Encana Corporation
4
4
Flagstone Energy
6
6
Fort Calgary Resources
1
1
53
53
49
50
1
1
Crescent Point Energy
The company continues focusing on proving up the resource base on its lands before embarking on down-spacing, a strategy similar to Penn West. It currently has around 2,400 drilling locations, said Roszell. He said the company has 280 net sections of land—235 of which have been specifically targeted to be within the Viking light oil fairway. Of the 235 Viking sections, somewhere around 215 will have economic oil on them, and about 20 sections will drop off at some point, Roszell said. “We’re not scared to drill dry holes,” he said. “That will happen over time, and that number will move around.” Raging River also continues testing different completion technologies in the Viking. It is doing long-term trials in areas with low gas to oil ratios to see if more frac stages per well will drain more oil. It has gone from 15 stages to 18 stages with good results. It is now testing 21 stages. Raging River also has seven waterflood projects in early stages in the Viking. Crescent Point Energy is also growing in the Viking. In June, the company announced it was taking over Polar Star Oil & Gas for a price of $334 million. The Viking assets include all of Polar Star’s assets at Dodsland, Sask., and more than 2,800 barrels equivalent of high-netback production. The Viking acquisition consolidates Crescent Point’s existing Viking land position at Dodsland and increases its land position by 38 per cent to approximately 145 net sections. The assets include 258 net internally identified drilling locations, which increase Crescent Point’s drilling inventory in the Viking play at Dodsland by 70 per cent. Crescent Point Energy president and chief executive officer, Scott Saxberg said the high rates of return from the Viking are what drove the Polar Star acquisition. The Viking generates strong rates of return and pays out quickly, he explained. With forecast cash flow from the acquired assets of $87 million and estimated annual maintenance capital of $35 million, Crescent Point expects the assets to generate annualized free cash flow of approximately $52 million. “The Saskatchewan Viking play has very high netbacks of more than $85 per barrel,” said Saxberg.
HORZ
Home Quarter Resources 1
Husky Energy Indepth Energy
1
68
Invicta Energy
1
9
10
ISH Energy
1
86
87
60
60
Mancal Energy
7
7
Mosaic Energy
6
6
Muirfield Resources
3
3
NAL Resources
81
81
Novus Energy
77
77
Omers Energy
1
1
75
75
Long Run Exploration
Penn West Petroleum
66
66
166
167
Renegade Petroleum
32
32
Rock Energy
10
10
4
4
Polar Star Oil & Gas 1
Raging River Exploration
Sekur Energy Management
44
Spur Resources
1
45
Spyglass Resources
5
5
Sun Century Petroleum
1
1
Tamarack Acquisition
5
5
Tamarack Valley Energy
3
3
178
178
1
1 43
Teine Energy Westdrum Energy Whitecap Resources
1
42
Total
5
1,235
2
1,242
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • November 2014
51
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siEgE
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Caught in the crossfire in the climate change war, pipeline companies focus on safety, social licence to operate By Darrell Stonehouse
OIL & GAS INQUIRER • November 2014
53
Cover Feature
Pipeline companies are focused on ensuring pipeline safety and environmental performance to maintain their social
T
he Canadian pipeline industry finds itself in the crosshairs as environmentalists in Canada and the United States wage a proxy war targeting the industry as a means of stopping oilsands development, which the environmentalists believe is helping drive climate change. While the debate rages over whether new export pipelines will be built to the U.S. Gulf Coast and west and east coasts of Canada, pipeline operators are focused on making sure they are operating as safely as possible as a means to maintain their social licence to operate. Environmentalists have been leveraging concerns about pipeline safety as part of an effort to stem oilsands development. This strategy became clear in comments after the federal government announced earlier this year that federally regulated pipeline companies will be liable for up to $1 billion of costs and damages in the event of a spill. The announcement elicited this response from John Bennett, national program directorate, the Sierra Club Canada Foundation: “It’s putting on window dressing and nothing more,” he says. “The issue is climate change, the tailings ponds and tanker traffic at the end of the pipeline—all of which are not
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November 2014 • OIL & GAS INQUIRER
allowed to be considered when approving pipelines. As long as that is the case, then it doesn’t really matter what they say about pipelines.” The new regulations say pipeline companies will be held fully liable in all incidences, whether or not they are at fault or negligent. “This approach is called ‘absolute liability,’ and it will apply to all federally regulated pipelines up to $1 billion for companies operating major pipelines,” Canada’s Natural Resources Minister Greg Rickford said in announcing the new rules. The measures provide the National Energy Board (NEB) with the authority to order reimbursement of any cleanup costs incurred by governments, communities or individuals. The NEB will have the authority and resources to assume control of incident response if a company is unable or unwilling to do so. Including materials, construction methods and emergency response techniques, the measures also give the NEB the ability to provide guidance on the use of the best available technologies in federally regulated pipeline projects. Finally, the government will develop a strategy with industry and aboriginal communities in an effort
Photo: ©iStock.com/jacus
licence to operate.
Cover Feature
to increase the participation of First Nations in pipeline safety operations, including planning, monitoring, incident response and related employment and business opportunities. “We will also strive to ensure meaningful aboriginal participation in pipeline safety activities and modernizing the National Energy Board Act in the interests of ensuring our pipelines are safe for Canadians and safe for the environment,” Rickford said, adding the pipeline safety changes strengthen environmental protection, enhance aboriginal engagement and streamline the review process of major resource projects. Rickford emphasized the rules are not in response to any specific proposed pipeline project that would move Alberta crude to the West Coast. He said the new measures deal with future pipelines as well as existing ones. He noted the liability to be placed on companies is not arbitrary. “It is 200 times what we know to be the average cost of a spill. We think that puts Canada ahead of the world in two important regards. First of all, this is the first of its kind. Second of all, the multiplier on the average cost of a spill, remote and rare as that might be, puts us out in front of everybody.” The new liability rules come at a time when the industry is showing incremental progress in reducing spills. Reportable incidents on pipelines regulated by the NEB were down 28 per cent in 2013, declining to 97 incidents from 134 incidents in 2012, says a report from the board released in April. However, the number of reportable liquid releases (more than 1.5 cubic metres) increased in 2013 to nine from two the previous year although overall release volumes were significantly lower and have been declining since 2009. Eight of the nine releases that occurred last year remained on company property or the right-of-way. The NEB separates liquid releases into two categories based on volumes. The first is between 1.5 and 100 cubic metres, and the second is any release of more than 100 cubic metres. There has been no release of more than 100 cubic metres on NEB regulated pipelines since 2011, the report noted. Nearly all volumes released have been fully remediated except those where cleanup is ongoing, said the board, which expects companies to address all impacts associated with a release. The Canadian Energy Pipeline Association (CEPA) is working with its members to ensure this positive trend continues. In 2012, it announced its pipeline integrity and emergency response program called CEPA Integrity First. CEPA Integrity First is focused on advancing the performance of the Canadian energy pipeline industry in three broad categories: safety, environment and socio-economic. Earlier this year, CEPA’s board of directors approved the program’s first guidance documents
outlining industry best practices and requirements around pipeline integrity and emergency management. CEPA member companies will use the guidance documents to assess their current systems, processes and practices to identify areas for improvement. These documents will also act as a foundation for benchmarking and performance management, and once baseline metrics are established, will provide increased transparency to the public through industry-wide performance tracking and reporting. “We’re serious about CEPA Integrity First and what it stands for. The guidance documents represent only one component of a very robust program. Our members have all signed and committed to the Integrity First policy statement and principles and by doing so have resolved to hold each other accountable to drive toward their goal of zero incidents, improved stakeholder engagement and increased transparency around industry performance,” says Brenda Kenny, president and chief executive officer of CEPA. A guidance document for control room management is also currently being pilot tested with the expectation that it will be finalized later this year. Central to the success of the CEPA Integrity First program is the establishment of an external advisory panel (EAP). This panel consists of individuals from a variety of stakeholder groups including aboriginal peoples, environmental groups, academia, media and landowner groups. The EAP will have direct access to CEPA’s board of directors to provide advice and to assist in determining priorities for the Integrity First program as it continues to evolve. “CEPA Integrity First is not a response to current regulatory expectations but a formal approach to the future of our industry and its ongoing commitment to continuous improvement. This program was developed not because industry was asked to, but because we wanted to,” says Jim Donihee, CEPA’s chief operating officer, who is leading the evolution of the Integrity First program. “CEPA member companies are committed to working together to define and implement collective best practices and leading-edge technology to advance safety and help the industry continue its progress along a sustainable path. There is no competition when it comes to safety. It’s that simple.” “As an industry, we face the question of how we constantly demonstrate that we’re worthy of the trust of the Canadian public,” says Kenny. “Enhancing our reputation and credibility with Canadians depends on our ability to continuously improve and engage with stakeholders proactively and transparently. CEPA Integrity First is how we will accomplish these goals. It is the right thing for industry to do.” Individual pipeline companies are also collaborating to move pipeline integrity forward. Last December,
“this program was developed
NOt
because industry was
ASKED TO,
but
because we
wanted to.”
— Jim Donihee, chief operating officer, Canadian Energy Pipeline Association
OIL & GAS INQUIRER • November 2014
55
Cover Feature
Export Oil Pipelines (Recently built or proposed) PROJECT
THROUGHPUT COMPLETION CAPACITY DATE* (BBLS/D)
OWNER
FROM
TO
Keystone Phase 1
TransCanada Corporation
Hardisty, AB
Steele City, NE, and Wood River and Patoka, IL
435,000
June 2010
Keystone Phase 2 (Cushing Extension)
TransCanada Corporation
Steele City, NE
Cushing, OK
156,000
February 2011
Seaway Reversal Phase 1
Enterprise Products Partners LP/Enbridge Inc.
Cushing, OK
Freeport, TX
150,000
June 2012
Seaway Reversal Phase 2
Enterprise Products Partners LP/Enbridge Inc.
Cushing, OK
Freeport, TX
250,000
January 2013
Spearhead North Expansion (Line 62)
Enbridge Inc.
Flanagan, IL
Griffith, IN
105,000
Late 2013
Line 9A Reversal
Enbridge Inc.
Sarnia, ON
Westover, ON
240,000
Late 2013
TransCanada Corporation
Cushing, OK
Nederland, TX
700,000
January 2014
Enterprise Products Partners LP/Enbridge Inc.
Cushing, OK
Freeport, TX
450,000
H1/2014
Flanagan South
Enbridge Inc.
Flanagan, IL
Cushing, OK
600,000
Mid-2014
Clipper (Line 67) Phase 1
Enbridge Inc.
Hardisty, AB
Superior, WI
120,000
Mid-2014
Batching Improvements
Enbridge Inc.
--
--
--
--
Enbridge Inc.
Superior, WI
Flanagan, IL
160,000
Mid-2014
Completed projects
“enbridge
has
said repeatedly
as a
company that we don’t
compete
in the area of
safety.”
— Kirk Byrtus, vice-president, pipeline control, Enbridge Inc.
Gulf Coast (Keystone XL Southern Leg)
Approved/under construction Seaway Twinning/Looping
Proposed Line 61 (Southern Access) Expansion Phase 1 Line 9B Reversal & Expansion
Enbridge Inc.
Westover, ON
Montreal, QC
300,000
Q4/2014
Eastern Gulf Crude Access
Energy Transfer Partners LP
Johnsonville, IL
St. James, LA
420,000
Mid-2015
Line 61 (Southern Access) Expansion Phase 2
Enbridge Inc.
Superior, WI
Flanagan, IL
640,000
H2/2015
Keystone XL
TransCanada Corporation
Hardisty, AB
Steele City, NE
830,000
2015
Clipper (Line 67) Phase 2
Enbridge Inc.
Hardisty, AB
Superior, WI
230,000
2015
Sandpiper (ND-MN)
Enbridge Inc.
Beaverlodge, ND
Clearbrook, MN
225,000
2016
Sandpiper (MN-WI)
Enbridge Inc.
Clearbrook, MN
Superior, WI
375,000
2016
1,100,000
2017
Energy East
TransCanada Corporation
Hardisty, AB
Montreal and Quebec City, QC, and Saint John, NB
Trans Mountain Twinning
Kinder Morgan Canada
Edmonton, AB
Burnaby, BC
590,000
2017
Enbridge Inc.
Edmonton, AB
Kitimat, BC
525,000
n/a
Northern Gateway
*Completion dates shown are as currently targeted Source: Oilsands Review
Canadian pipeline giants Enbridge Inc. and TransCanada Corporation signed a joint industry partnership (JIP) agreement to conduct groundbreaking research in the area of leak detection. The partnership includes a funding commitment from both TransCanada and Enbridge to evaluate cutting-edge technologies to enhance external leak detection at an Edmonton research facility, using a state-of-the-art pipeline simulator developed by Enbridge and known as the External Leak Detection Experimental Research (ELDER) test apparatus. TransCanada and Enbridge will share equally in the new knowledge and advancements that can be applied directly to improve leak detection in their respective operations. “Enbridge has said repeatedly as a company that we don’t compete in the area of safety, and this partnership with
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November 2014 • OIL & GAS INQUIRER
TransCanada represents clear proof of that approach. Enbridge has invested considerable time and resources into building a world-class leak detection testing apparatus, but we believe that working together with committed partners to discover the best technology on the market is in everyone’s best interest,” says Enbridge’s Kirk Byrtus, vice-president of pipeline control. The ELDER apparatus is the first tool of its kind in the world of this scale and was purpose-built by Enbridge’s Pipeline Control Systems and Leak Detection (PCSLD) team, along with project research partner C-FER Technologies of Edmonton, to evaluate external leak detection technologies in a setting that very closely represents the actual conditions in which liquids pipelines are installed. This joint industry partnership represents a total funding commitment of $4 million, including $1.3 million from
Cover Feature
TransCanada, $1.6 million from Enbridge and $1.1 million from the Alberta Ministry of Innovation and Advanced Education. Enbridge had previously invested $3 million over a period of two years to develop and build the ELDER apparatus with C-FER Technologies. Engineers from Enbridge, TransCanada and C-FER Technologies will be performing a series of tests in 2014 on four external leak detection technologies—vapour-sensing tubes, fibre-optic distributed temperature sensing (DTS) systems, hydrocarbon-sensing cables and fibre-optic distributed acoustic sensing (DAS) systems—and discovering which technology is optimal for external leak detection on liquids pipelines. While the ELDER test apparatus was created to understand and examine the capabilities of external leak detection sensors, the scale and rigour of this project demonstrate the level of due diligence demanded by Enbridge and TransCanada before new technologies are applied to their operating environments. This joint industry partnership currently involves two players in TransCanada and Enbridge but remains an openended arrangement. Other pipeline operators and energy industry leaders are invited to participate as committed partners. Each organization that participates will see an immediate benefit from all engineering and test data collected since work began on the project. Pipeline companies are also collaborating to ensure that if spills do happen, their environmental issues will be mitigated. Member companies of CEPA conducted their fi rst ever joint emergency management exercise in Edmonton in late September. This exercise is the fi rst time CEPA member companies have tested their ability to collectively respond to an emergency situation. It is the result of the industry’s commitment to continuous improvement in the areas of safety and environmental protection, CEPA said. Last year, as part of the industry’s commitment to improve its strong record in pipeline safety, CEPA announced the Mutual Emergency Assistance Agreement (MEAA). This agreement formalizes an existing practice of companies lending critical resources to help each other in case of an emergency. While all pipeline operators must and do conduct their own emergency response drills, CEPA member companies have voluntarily chosen through the MEAA to formally work together and improve response capabilities by sharing resources and best practices during an emergency. “Today’s exercise shows we are committed to increased transparency and shared best practices,” said Kenny in announcing the exercise. “It also demonstrates there is no competition when it comes to safety. Any incident is everyone’s incident. It’s that simple.” The exercise highlights the efforts being made within the pipeline community to ensure there are comprehensive and well-tested plans in place to respond in the unlikely event of an incident, CEPA added. Lessons drawn from the exercise will be applied to ensure the industry becomes even safer and more responsive in the future.
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OIL & GAS INQUIRER • November 2014
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Feature
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Ca
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Wate wo ies L By
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Concerns about water use in fracturing operations are moving north, but Canada has a head start in managing the issue
U
nlike in the United States, the challenges of treating flowback water used in hydraulic fracturing have received little attention in Canada, but that won’t last, predicts one water handling company. “Water-related challenges faced by U.S. fracking operators are probably an early warning for Canadian producers,” says Owen Pinnell, president of Calgary and North Dakota–based White Owl Energy Services Inc. “Some of these challenges are going to arrive on our doorstep.” For one thing, restrictions on freshwater use are probably coming, Pinnell predicted at the recent Canadian Business Conferences initiative on tight oil and shale gas water treatment. 58
November 2014 • OIL & GAS INQUIRER
“Water shortages seen in the United States could become a Canadian story in decades to come, and the regulatory and technological developments to address these challenges, such as depleting water supplies, seem to be lagging behind the pace of shale oil and gas developments,” said Pinnell, who has been involved in water handling and disposal for more than 25 years. The benefits of frac water treatment and reuse—less use of fresh water, decreased waste-water disposal costs and fewer trucks on the roads, to name a few—are obvious, but how to get started is not, he said. Who should be treating reused water? Possibilities include producers setting up portable units on their frac pads, producer
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collaboration on central treating facilities and salt-water disposal well operators offering blended, treated water for reuse. There should be more effort placed on recycling and reusing water, and these will soon be part of well plans, he predicted. “Everyone’s talking about how fresh water is going to be regulated and there’s going to be all sorts of rules, and maybe that’s the case,” he said, adding the trend in Texas is for regulators to incentivize water reuse and recycling, not to mandate it. Most jurisdictions in Canada and North Dakota are moving towards some sort of water management plan in which companies catalogue water sources and uses, including the amount recycled and the final disposal option in a licensed salt-water disposal well. For water with high total dissolved solids (TDS), say greater than 1,000 parts per million, disposal wells are really the only option unless it is blended with fresh water, said Pinnell, former chair of Anterra Energy Inc. and founder of Newalta Corp. But disposal wells will not be a universal solution, he added. Water is permanently removed from the hydrologic cycle, and these wells are not feasible everywhere due to geology and regulations. “The public is suspicious about disposal wells and their potential to contaminate groundwater, but I just know from my experience having developed over 30 disposal facilities, that we’ve never had an incident where groundwater has been at risk if the well is completed properly. It’s not an issue,” said Pinnell. But there are valid concerns about frac fluid additives and the volumes of salt water, biocides, surfactants and other chemicals that are going down into the formation, and in some jurisdictions salt-water disposal wells are being blamed for earthquakes, he said. From a producer’s standpoint, the biggest issue around saltwater disposal wells is facility availability because huge volumes of water must be moved quickly during a fracturing operation, said Pinnell. According to Pinnell, the typical unconventional well needs more than 300 truck trips and between three million and six million gallons of water. Some producers in North Dakota are pipeline-connecting their wells to commercial salt-water disposal wells, he said. Most hydraulic fracturing operations use about 100,000 barrels (15,000 cubic metres) of water, and companies are paying between $1.50 and $6 per cubic metre for that water, while transportation—the bigger issue that most producers underestimate—costs between $30 and $50 per cubic metre, possibly more with waiting times, he said. “Typically there are waiting times both ways,” said Pinnell. “You’ve got picking up clean water, and you’re disposing of produced water or flowback, and I’ve heard of wait times as long as 20 hours in the Grande Prairie [Alta.] area, so wait times are a real issue.” Pinnell highlighted some of the trends in water use in the Bakken, Alberta and British Columbia. In the Bakken, the big issue is high TDS, while in Alberta, it’s the remoteness of the wells—both access to them and the lack of infrastructure. There aren’t enough disposal wells, so trucking and waiting times are huge issues, he said. According to Pinnell, Alberta is vulnerable to water shortages because of its location in the shadow of the Rockies. In addition, many rivers are fed by shrinking glaciers. Environment Canada
says water use is high relative to supply, and competition with agriculture is a concern. Reliance on brackish water is not the solution, he said. Some companies are using brackish water; however, they run the same risks as with flowback or produced water: compatibility with fracture-fluid chemistry, compatibility with the reservoir and environmental risks related to storage. In British Columbia, operators are contending with drought conditions in the north, First Nations’ and environmental groups’ considerations and the latter’s arguments in court that the B.C. Oil and Gas Commission’s repeated granting of short-term water-use approvals to oil and gas companies is unlawful, said Pinnell. While there is some frac water reuse in western Canada, it is not a trend, but he believes it is the long-term solution. “We just need to get started, even if we just reuse five or 10 per cent of the flowback. At least it’s a start, and we’ll get some experience with this approach. That’s already the case and pretty common in Texas and the Marcellus shale in Pennsylvania where they recycle a lot of their water and reuse it.” He said disposal well operators may need to consider changing their business model and providing a total water solution: supply, treat, reuse and dispose.
“ Oil and gas companies don’t have the expertise in-house to develop those sorts of systems and processes. I would suggest that it is up to the service industry to provide the solution.” — Owen Pinnell, president, White Owl Energy Services Inc. Companies tend to find short-term solutions for management and treatment of frac water or flowback, but the development of shale plays should be viewed in the long term, said Pinnell. “I think, as an industry, we need to move more towards a long-term approach as opposed to the short-term approach that we currently take, and that brings up the issues of centralized facilities,” he said. In the Bakken, he noted, there are still as many as 50,000 wells to be drilled, and over the next 25–30 years, there will probably still be very active development programs in North Dakota. “Currently, on the service side of the industry, we have saltwater disposal operators, and there are many of them in North Dakota. We have companies handling oilfield waste, which is the tank bottoms, drilling muds and the fluids that have solid contaminants.” In Canada, centralized oilfield waste management is fairly well represented in the services sector with upwards of 60 facilities, Pinnell said, but that is not the case in the United States. “As an industry, those are areas that we need to start looking at taking a more centralized approach to water management, which means being able to provide water for reuse in fracturing operations—taking flowback, taking produced water, maybe blending it with fresh water, and providing that as a water source for industry. OIL & GAS INQUIRER • November 2014
59
Feature
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“Oil and gas companies don’t have the expertise in-house to develop those sorts of systems and processes. I would suggest that it is up to the service industry to provide the solution,” he added. “I would be bold enough to say that, ultimately, that will be the solution, and you will find centralized water-handling and wastemanagement facilities handling flowback and frac water or produced water.” Jeff Green, vice-president of corporate and engineering services at Perpetual Energy Inc., says centralizing proximity between treatment plants, wells and storage facilities is not the only way to reduce operating costs. Also important, he noted, is recycling. “Whether you’re big or small, I think a company can have a goal of 100 per cent reuse,” Green says, adding the goal for Perpetual is to eventually reuse 100 per cent of its flowback fluids. Currently, he says, the company’s flowback-fluid reuse ratio is at approximately 75 per cent. According to Green, on-site treatment can be very beneficial for operators, as any movement of a fluid involves a degree of risk. “One thing that we’ve done is that we have gone to four-well pads for our drilling operations. Instead of having single-well pads or two two-well pads, we are containing more water on site. We’re using it all on site and then eventually moving it to the next four-well pad.” For Pinnell, the thought of a region forever losing water from the hydrological cycle as a result of fracturing operations is a legitimate concern for environmentalists and the public. He said individual companies and the industry as a whole should start working toward a “zero balance” in terms of disposing of water. To achieve this, he said, producers, service companies and regulators must work together toward a regional approach to handling frac water and flowback. Grabbing water from a municipality’s water-treatment plant, in the final stages of cleansing effluent and before releasing
Feature
it to a local river or lake body for dilution into the environment, is an opportunity worth considering for hydraulic fracturing operations, says Jeremy Hogg, water resource manager with White Water Management Ltd. It presents both a reliable and a less controversial source for fracturing than potable water. “It stands as a reliable backup for other plans, and in my opinion that is a really big deal,” he says, adding that a company could source water from such treatment plants as opposed to getting the fluid from nearby rivers or lakes, which would be where the municipality’s treated water would be headed anyways as a “controlled pollutant.” According to Hogg, the water available from such a facility is “recharged” every year, as municipalities still need to use a certain amount of water, which companies could factor into their water planning and applications for frac work. He notes that using this water source could enable companies to engage local citizens. “It includes the public in a water management plan—you have to talk with the town,” he says, adding integrating an impacted community in operations through use of their treated waste water could allow a window through which the public might learn more about operations and gain an appreciation for them. When looking at gaining long-term water withdrawal permits for fracturing, Hogg says companies must work with the hydrological cycle when trying to determine potential freshwater sources for operations. Notably, he adds, in spring there is lots of available surface water, but by autumn that water source has largely dried up. “One of the things you can do is water bank. During run-off season in May or June, in general, you could build borrow pits to use in fall or winter. That’s a fine plan. When you do that, include your idea in your plan for your program. Let the regulator know what you are doing. Just communicate.”
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OIL & GAS INQUIRER • November 2014
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advertisers' index Annugas Compression Consulting Ltd . . . . . . . . 34
Fruitland Manufacturing . . . . . . . . . . . . . . . . . . . 24
RedGuard . . . . . . . . . . . . . . . . . . . . . . . . . . 30 & 40
Ar-Tech Coating Ltd . . . . . . . . . . . . . . . . . . . . . . . .10
Gibson Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . .14
Rush-Overland Manufacturing . . . . . . . . . . . . . . 40
Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . 60
Globalstar Canada Satellite Co . . . . . . . . . . . . . . .61
Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 38
Government of Alberta, IIR . . . . . . . . . . . . . . . . . 52
Brother’s Specialized Coating Systems Ltd . . . . 22
Infinity Tubular . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
Canadian Heavy Oil Association . . . . . . . . . . . . . .31
Infosat Communications LP . . . . . . . . . . . . . . . . 57
CanElson Drilling Inc . . . . . . . . . . . . . . . . . . . . . . . 15
League Pipeline Services Ltd . . . . . . . . . . . . . . . 32
Testo, Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21
CG Industrial Specialties Ltd . . . . . . . . . . . . . . . . . 4
Mainland Machinery Ltd . . . . . . . . . . . . . . . . . . . 32
ThermaCell-The Schawbel Corporation . . . . . . . 33
Chase Operator Training . . . . . . . . . . . . . . . . . . . 60
Maxxam Analytics . . . . . . . . . . . . . . . . . . . . . . . . 45
TMK IPSCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Chevron Delo . . . . . . . . . . . . . . . . inside front cover
Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . 38
TOG Systems-Telecom Oil + Gas . . outside back cover
Core Linepipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
Phoenix Fence . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
Platinum Energy Services ULC . . . . . . . . . . . . . . 23
Dragon Products Ltd . . . . . . . . . . . . . . . . . . . . . . . 5
Platinum Grover Int. Inc . . . . . . . . . . . . . . . . . . . . . 17
Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 36
Pouce Coupe Industrial Park . . . . . . . . . . . . . . . . 20
Westeel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
Export Development Canada . . . . . . . . . . . . . . . . 8
Pumps & Pressure Inc . . . . . . . . . . . . . . . . . . . . . 26
ZCL Composites Inc . . . . . . . . . . . . . . . . . . . . . . . 27
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November 2014 • OIL & GAS INQUIRER
Select SAI Inc . . . . . . . . . . . . . . . . . . . . . . . . 18 & 28 Shaw Communications Inc . . . . . . inside back cover Site Energy Services . . . . . . . . . . . . . . . . . . . . . . 45
TransGas Limited . . . . . . . . . . . . . . . . . . . . . . . . . 52 Tundra Process Solutions Ltd . . . . . . . . . . . . . . . .12 V J Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . 11
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Just another day keeping the oil and gas industry in Western Canada seamlessly connected with a complete line of dependable, voice and data communications products and solutions – all backed by an equally dull, 100% service and equipment guarantee. Get the oil and gas industry in Western Canada’s most trusted communications provider working for you.
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For more information, visit our website: togsystems.ca
PHONE TOLL FREE EMAIL
780 356 3965 1 844 356 3965 info@togsystems.ca