MAY 2010 � $6.00
AUTOMATING HORN RIVER
To cut shale gas costs and gain reservoir insights, Apache pours millions into wellsite automation
280
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280 200 130
85
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Working Overseas Canadian oil and gas specialists are on the job from Argentina to Azerbaijan
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Table of Contents
Keeping readers regionally informed
F E A T U R E S
12
Automating Horn River by Mike Byfield To cut shale gas costs and gain reservoir insights, Apache Canada's Karl DeMong and his completions team are pouring millions into automation
20 35
Working overseas by Jim Bentein Canadian oil and gas specialists like Shane Proteau are on the job from Argentina to Azerbaijan. These days, many overseas assignments involve teaching the job as well as performing it.
The hunt intensifies for a break through oilsands solvent by Pat Roche N-Solv, Imperial Oil, Cenovus, and Suncor are each seeking a solvent capable of dramatically reducing natural gas consumption in steam-driven bitumen recovery
As the economy strengthens, look for stories with the Recession to Recovery logo to help you through uncertain times. And be sure to check out junewarren-nickles.com/r2r for Recession to Recovery stories from all JuneWarren-Nickle’s publications. 6
M ay 2010 • O I L & G A S I N Q U I R E R
Table of Contents
R E G I O N A L
27
N E W S
British Columbia
45
• B.C. First Nations coalition opposes Enbridge oilsands pipeline
activity all surge in early 2010
• Fort Nelson North gas plant application
• Ensign launches a build program
proceeds without NEB hearing
31
Northwestern Alberta
despite lower revenues for 2009
51
• Early drilling results in Wilrich play
Northeastern Alberta
outlines drilling plans
53
• The hunt intensifies for a breakthrough
Central Alberta
project gets delayed until 2013
55
• Industry responds positively to Alberta’s
Central Canada • Conference Board forecasts higher
retreat on royalty rates
profits for the gas industry
• Bellatrix Exploration updates its Cardium drilling results
Northern Frontier • Decision on Mackenzie pipeline
oilsands solvent
41
Saskatchewan • PetroBakken pegs FD&A cost and
encouraging
35
Southern Alberta • Well count, metres drilled, and rig
• Feds penalize Chinese OCTG imports
57
International • Xtreme Coil lands a Saudi contract but suffers a setback in Mexico • BlackWatch announces foreign acquisition
I N
10
E VE R Y
I S S U E
Statistics at a Glance
61
59
On the Job • For years, Graham Fletcher has been providing Internet services far and wide. Now he’s fighting the feds to get more than 260 small communities linked to the Alberta Supernet
Tools of the Trade • Departure Energy Services Inc. manufactures the G-Force TM Vertical Guidance Drilling System, which will maintain a wellbore in a vertical attitude while rotating at any rate of penetration
• Completions data, spot gas prices, gas storage, drilling activity, and more
62
Political Cartoon
Cover Design: Aaron Parker
O I L & G A S I N Q U I R E R • M ay 2010
7
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Editor’s Note Vol. 22 No. 5 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com
Mike Byfield | mbyfield@junewarren-nickles.com
Your mom had a point
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During the early 1990s, a Canadian rig manager went to work in Texas. Some of his company’s drilling rigs were manned by Tex-Mex workers, but no American toolpush wanted to run those crews. (All of the supervisory staff was Caucasian.) “I wound up being assigned to the Mexicans, and I really enjoyed working with them,” this fellow told me. Why didn’t the American managers want to deal with Hispanic crews? How did the Canuck get along with them? For a petroleum specialist working overseas—the subject of a feature story in this issue of Oil & Gas Inquirer—those are useful questions. My acquaintance answered with a story, reportedly true. A gringo toolpush was backing up in his rig’s parking lot and accidentally struck a car belonging to one of his Tex-Mex roughnecks. Surveying the damage, the rig manager saw that he’d made a minor dent in a vehicle that was already covered in dents and rust. Thinking no harm had been done, the man jumped back in his pickup and went about his business. A few evenings later, that toolpush was drinking in a bar. Several of his crew members were in the same bar. Suddenly, without any warning at all, the car owner attacked the supervisor with a knife. Fortunately, others intervened and no one was seriously hurt. But that sort of unpredictable incident made Texan rig managers leery of Tex-Mex roughnecks. So why did the rig hand attack his boss over a trivial dent? Because his boss had not apologized, the Tex-Mex roughneck had brooded about the apparent lack of respect. Given time and alcohol, his smouldering over the perceived insult mutated into a violent thirst for revenge. When the Canadian toolpush arrived in Texas, he knew nothing about the local culture, either white or Latino. Even so, my acquaintance would have apologized to that roughneck for denting his car. Canadians, after all, are famously polite. Due in part to his ingrained personal courtesy, the rig manager got along fine with the Tex-Mex crews. Texas has its own good manners. Another friend of mine, a young woman in medical school, worked one summer for NASA is Houston. On returning to Calgary, she informed me that Texan men are exquisitely polite to women, and more so to older ladies. She adored them. In many foreign nations, courtesy is a more valuable social tool than back-slapping friendliness. Although I’ve never had a foreign job in the patch (unless Wyoming is considered foreign), I have travelled to, taught, and been employed in quite a few other countries. In my experience, showing respect rarely hurts and usually helps. Oilpatchers working overseas today are teachers more often than not. Their tasks typically include training local citizens to perform the same job. No doubt there are dozens of tricks to the foreign petroleum trade. Courtesy alone certainly doesn’t guarantee success. Even so, bear in mind that your mom was right: Always be polite. Otherwise, you just might get knifed.
Oil & Gas Inquirer is owned by JuneWarren-Nickle’s Energy Group and is published monthly. GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2010 1072125 Glacier Media Inc. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240. Postage Paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 800 - 12 Concorde Place, Toronto, ON M3C 4J2 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.
N E X T
I S S U E
Global champions
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With the Global Petroleum Show in Calgary,
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Oil & Gas Inquirer asks successful exporters
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please give me a call at (780) 784-4251, or
foreign sales. Also, the magazine takes a look at
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the activity outlook in northwestern Alberta.
In fact, feel free to sound off about any concern at all—that’s a personal invitation.
O I L & G A S I N Q U I R E R • M AY 2 0 1 0
9
Stats
FAST NUMBERS
$10
AT A GLANCE
C$5
million
Average cost to drill and complete a natural gas well in Quebec, which could drop by 50 per cent due to greater activity and rig availability
per Mcf
Price at which Quebec natural gas is commercially viable, equivalent to C$4 in Alberta due to lower pipeline costs
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
MONTH
OIL
GAS
OTHER
TOTAL
MONTH
OIL
GAS
DRY
SERVICE
TOTAL
Apr 2009 May 2009 Jun 2009
111 71 36
344 187 143
140 53 42
595 311 221
Apr 2009 May 2009 Jun 2009
111 71 177
342 187 211
61 46 45
12 35 27
526 339 460
Jul 2009 Aug 2009 Sept 2009
79 101 146
178 212 155
77 80 78
334 393 379
July 2009 Aug 2009 Sept 2009
79 250 146
31 267 155
6 36 45
3 37 9
119 590 355
Oct 2009 Nov 2009 Dec 2009
132 169 121
160 212 127
77 116 35
369 497 283
Oct 2009 Nov 2009 Dec 2009
331 382 283
196 244 138
32 68 34
12 10 13
571 704 468
Jan 2010 Feb 2010 Mar 2010
253 144 264
324 308 579
62 114 198
639 566 1,041
Jan 2010 Feb 2010 Mar 2010
429 147 548
343 143 681
55 20 109
13 5 20
840 315 1,358
Wells Drilled In British Columbia
Wells Drilled In Saskatchewan
Source: B.C. Oil and Gas Commission
Cumulative to April 1, 2010 Source: Saskatchewan Energy & Resources
MONTH
WELLS D R I L L E D
CUMULATIVE *
Apr 2009 May 2009 Jun 2009
33 26 19
350 376 395
Jul 2009 Aug 2009 Sept 2009
34 36 38
429 465 503
Oct 2009 Nov 2009 Dec 2009
29 39 45
532 571 616
Jan 2010 Feb 2010 Mar 2010
65 98 71
65 163 234
*From year to date
OIL
GAS
OTHER
D RY
T O TA L
Vertical Wells
Lloydminster Kindersley Swift Current Estevan
151 5 14 28
7 1 54 0
5 1 1 8
5 5 3 28
168 12 72 64
16 59 28 244
0 0 0 0
0 0 0 6
0 0 1 0
16 59 29 250
167 64 42 272
7 1 54 0
5 1 1 14
5 5 4 28
184 71 101 314
Horizontal Wells
Lloydminster Kindersley Swift Current Estevan Total Wells
Lloydminster Kindersley Swift Current Estevan
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M AY 2 0 1 0 • O I L & G A S I N Q U I R E R
S P O T P R I C E S at AECO trading hub in Alberta
GAS STOR AGE
Source: Natural Gas Exchange Inc.
Source: U.S. Energy Information Administration $3.75/GJ Total vol.: 1,664 TJ Transactions: 182
4.0
2.00
1.76 Tcf Year ago: 1.69 Tcf 5-year avg: 1.51 Tcf
1.75
3.5
3.0
in the United States
Mar 17
Cdn$/GJ
Mar 24
Mar 31
Apr 7
1.50
Apr 14
Mar 12
Tcf
Source: Natural Gas Exchange Inc.
Mar 19
Mar 26
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada April 13, 2010 Source: Rig Locator
Alberta March 2010 Source: Daily Oil Bulletin
ACTIVE
DOWN
TOTAL
ACTIVE (Per cent of total)
Western Canada Alberta
72
479
551
13%
British Columbia
54
56
110
49%
0
15
15
0%
13
110
123
11%
139
660
799
17%
0
1
1
0%
Manitoba Saskatchewan WC Totals Northwest Territories
Apr 2
OIL WELLS
Alberta
GAS WELLS
Mar 10
Mar 09
Mar 10
Mar 09
Northwestern Alberta
46
50
170
375
Northeastern Alberta
65
88
8
14
Central Alberta
124
145
76
196
Southern Alberta
29
41
325
377
264
324
579
962
TOTAL
Service Rig Count by Province/Territory
Drilling Activity: CBM & Bitumen
Western Canada April 13, 2010 Source: Rig Locator
Alberta March 2010 Source: Daily Oil Bulletin
ACTIVE
DOWN
TOTAL
ACTIVE
Western Canada Alberta
437
674
35%
British Columbia
8
24
32
25%
Manitoba
2
7
9
22%
Saskatchewan
81
105
186
44%
328
573
901
36%
0
2
2
0%
WC Totals Quebec
COALBED METHANE
Alberta 237
Apr 9
Source: U.S. Energy Information Administration
BITUMEN WELLS
Mar 10
Mar 09
Mar 10
Mar 09
Northwestern Alberta
11
4
3
6
Northeastern Alberta
0
1
61
81
Central Alberta
33
84
60
48
Southern Alberta
30
98
0
0
TOTAL
74
187
124
135
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O I L & G A S I N Q U I R E R • M AY 2 0 1 0
11
Blank Page for duplexing
Photo: Jack Cusano
Feature
Karl DeMong, completions manager at Apache Canada Ltd. 12
M AY 2 0 1 0 • O I L & G A S I N Q U I R E R
by Mike Byfield
A
unique partnership and rivalry has sprung up in the Horn River Basin of northeastern British Columbia. In 2007, Apache Canada Ltd. and Encana Corporation formed a 50/50 partnership in the then-emerging shale gas play, pooling more than 400,000 acres. Unlike other oilpatch joint ventures where one operator is elected, in this joint venture, each producer operates its own sites. In 2009, Encana drilled 19 wells and Apache drilled 23. Financially, both companies share equally in all of those wells. Operationally, however, their teams compete with and ultimately learn from each other. “There’s a big learning curve involved in figuring out how to economically develop a huge shale gas resource like Horn River. Our guys do their absolute best to get better results than Encana, and naturally they do the same,” says Karl DeMong, completions manager for
Apache Canada. “It’s pretty intense, like good hockey. In our game, however, everyone wins. Each company tries out its own innovations and we both get the benefit of learning what works best. ” Until March, DeMong headed Apache’s well completion team for the Horn River. Multi-stage horizontal well completions in northeastern British Columbia are massive operations, involving about 280 workers on site, split in two shifts. Also on site are some of the largest fleets—pressure pumpers, wireline trucks, cranes, coiled tubing service rigs, and other vehicles—ever assembled on site in Canada’s oilpatch. Frac proppant, chemicals, and other material needs are equally enormous. “When you’re pumping water at the rate of 100 barrels per minute, you don’t want empty surge tanks,” DeMong says. Between January 7 and March 18, Apache pumped about 500 million litres of water at Horn River, with 95 per cent being brought in O I L & G A S I N Q U I R E R • M AY 2 0 1 0
13
Feature
Photo: Apache Canada Ltd.
“on the fly” during the fracs. By the end of March, DeMong’s crew conducted 193 frac intervals (or stages) and placed 33,000 tons of sand. Although the company has not released budget figures, DeMong’s team is spending tens of millions. An Apache Horn River frac interval typically takes five to six hours. Supervision of a Horn River frac comes from three points: 1) t he pumping company’s horsepower control centre on site, 2) A pache’s frac command centre on site, and 3) t he frac control headquarters in Apache Canada’s head office in Calgary. The torrent of data that’s essential to tight coordination between these centres moves via satellite within two seconds. Each centre has its specific duties. The frac command centre, for example, directs the actual fracture pumping operation and monitors safety, and can shut down the entire operation for safety reasons at any time. The Calgary team usually mandates pressure and flow rates during the frac. Horn River, just south of the Northwest Territories, ranks as the most geographically remote commercial-scale gas field now producing in North America. Apache and Encana will be competing with gas from big shale plays in the United States that sit far closer to market. To bring costs down, DeMong recognized two challenges. First, more work had to be performed in less time by fewer people. Second, the company had to learn the complexities of reservoir fracturing in this basin. On both counts, the team leader turned to innovative automation. A mechanical engineer from the University of Saskatchewan, DeMong credits his personal enthusiasm for technical challenges to
Apache spaces its wellhead manifolds as close as 10 feet apart.
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M AY 2 0 1 0 • O I L & G A S I N Q U I R E R
Toll Free 1-888-511-0554 11/13/2009 9:36:31 AM
Feature
his father Leroy, a labourer who severely fractured both arms at age 19. “Dad had one artificial limb and limited rotation in his remaining wrist,” the 41-year-old Calgarian recalls. “Every day, we kids watched him figure out innovative ways to shovel grain, hoist bales, and perform other tasks that would be routine for most people.” A high school stint at Saskatchewan’s famed Athol Murray College of Notre Dame taught DeMong another lesson: “As a philosophy, ‘everything matters’ beats the hell out of ‘nothing matters.’” After the 180-pound teenager enrolled at the University of Saskatchewan, he packed on an additional 60
Horn River, just south of the Northwest Territories, ranks as the most geographically remote commercial-scale gas field now producing in North America. pounds of muscle (from “two years of 20 hours of pumping iron per week, no steroids”), then served as an offensive lineman on the football team. His first job came from PanCanadian Petroleum. “I didn’t realize it until later, but they hired me mostly because I was big. In those days, the field supervisors [who’d risen from the ranks] tended to pick on the young engineers from headquarters. They’d ball your engineering program up and throw the paper in the wastebasket, saying they’d always done it their way,” DeMong says. The neophyte won over these hard cases by integrating their operational understanding in his engineering programs.
He subsequently worked for both senior producers (Wascana Energy Inc., Nexen Inc.) and juniors (Calahoo Petroleum Ltd., Intensity Resources Ltd.). In 1998, Sperry-Sun Drilling Services posted the Canadian to Dubai, eventually promoting him to manager of global multilateral operations. “I’m basically a downhole tools guy with experience tying together multiple wellbores below the surface on high-value well pads. Initially, this involved challenging all the engineering done on the project,” DeMong says. In 2006, the experienced manager became an independent consultant, gravitating toward Apache Canada (who later brought him on staff). DeMong encourages high-energy discussions that he calls “happy yelling,” prompting his staff members to debate divergent opinions in the search for solutions. “You can tell by the smiles that the team is really enjoying tackling these challenges,” he says. At Horn River, Apache drilled its 70-K pad with 16 wells, divided into two pods of eight wells apiece for working purposes. The 52-L pad has 14 wells, while 34-L is scheduled to have 22. “Pressure pumping [for fracs] is the critical path item in the whole operation,” DeMong says. “People were doing one thing at a time in sequence and it wasn’t efficient.” To help prepare a better work program, the engineer brought his supervisors to head office for four months. “I regard their 200 years of field experience as gold and we definitely tap into that,” he comments. A key component of his technical strategy focused on automating the fracture manifold (an assembly of actuated and manual valves plus piping) that sits astride each wellhead. “The frac supervisor
O I L & G A S I N Q U I R E R • M AY 2 0 1 0
15
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Feature
A full range of power and force measurement transducers, protection relays, needle and manifold valves, pressure switches, diaphragm seals and thermometers.
Photo: Jack Cusano
[on site] swings the valves and keeps the pump program on track during the frac interval,” DeMong explains. “Simultaneously, the pumpdown supervisor can do work on the other pod like placing the plug and perforating gun or pulling out of the hole. Due to automation, we’re reducing cycle times and doing it safely.” Through redesigning its fracture manifolds, Apache has shrunk wellhead spacing to an industry-leading 10 feet. Smaller manifold shelters and shorter trunk lines are easier to maintain and cost less, while rig-up cranes can do their tasks with fewer movements, reducing risk and expense further. The smaller overall footprint for each pad harmonizes with the environmental concerns of regulators, First Nations, other neighbours, and the industry itself. Responsible use of water is another priority for all stakeholders. “We are in the process of moving over to employing non-potable [formation] water for our fracturing,” DeMong says. “This will enable us to avoid using surface water supplies.” During a fracturing operation, Apache’s completion specialists can watch pumping pressures along with proppant concentrations and flow rates in real time on screens in the frac-control headquarters. This technology is the norm among major producers in Horn River. Uniquely, however, Apache’s specialists can access another 18 screens of data from SCADA (supervisory control and data acquisition) sensors placed on wellsite equipment at Horn River. This automation gear is transferable to a new pad when the drilling and completion operation moves on. Critical performance and safety information is available at the team’s fingertips to support decision making.
Apache VP Rob Spitzer helps harmonize two different corporate cultures.
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O I L & G A S I N Q U I R E R • M AY 2 0 1 0
17
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“We have real-time information and a historical record of every pressure event, valve position, temperature, and other data that’s generated during frac intervals,” DeMong says. “This information enables us to diagnose successes and problems as they occur. This is the most demanding project that Apache’s SCADA specialists have ever worked on. Our guys are really excited; they keep offering us new ways to do more.”
Earlier in this decade, Calgary-headquartered Encana stunned its industry peers by investing billions in marginal resource acreage, effectively betting the company on prospects previously considered almost worthless.
On a conventional oil or gas well, most of the budget is spent on drilling the well and installing production facilities. For shale gas projects, however, completions comprise the majority of the capital cost. DeMong hopes that the use of SCADA will improve the efficiency of the hydraulic fracture operations, which absorb billions of dollars on an annual basis. To date, Apache has invested over $10 million in new automation technology at Horn River, including about $1 million for SCADA.
Apache acknowledges that it’s a risky ploy, and its partner may not be willing to help fund the investment. “We have strong management support to go ahead with the innovations, even if we had to do it on our own,” DeMong says. He credits John Crum, Apache’s Co-COO for North America, and Tim Wall, president of Apache Canada, for that decision. Apache has long specialized in wringing more oil and gas from known reservoirs through engineering advances. This is a natural progression to wringing gas out of previously unproducable rock in the Horn River Shale. Not that Encana lacks boldness. Earlier in this decade, the Calgary-headquartered producer stunned its industry peers by investing billions in marginal resource acreage, effectively betting the company on prospects previously considered almost worthless. Other independents followed that lead. Now Exxon Mobil Corporation and Royal Dutch Shell are investing heavily in North American tight gas, a strong signal that the gamble is paying off. “Encana has a completely different culture than us,” the Apache Canada completions manager comments. Fortunately, he says, the partners’ expertise tends to be complementary. The two producers meet for a regular weekly project review and constantly share data. Rob Spitzer, Apache’s VP of new ventures, helps the teams lever off each other’s strengths rather than bicker over operational differences. Spitzer’s steady fence mending pays off. “It is really Rob’s positive attitude toward the partnership that helps make this all work,” says DeMong, adding that the dual operator configuration “creates a stronger project. We were the first two companies to grasp the potential of the Horn River Basin, and Encana has a great team. Almost as good as us—hey, I’m just kidding, right?”
YOU’RE PROUD OF YOUR SKILLS AND KNOW-HOW. You want to work where you can be proud of your employer too. At Suncor Energy, we aim to earn your respect by providing you with the tools and support that enable you to do quality work.
Ready to be proud of your workplace?
Put yourself in our picture. When you join Suncor, you enter a working environment where how you get the job done is as important as the goals you achieve. You’ll be part of a company that’s guided by strong values and beliefs; that demands a high standard for safety, integrity, responsibility and always strives to exceed expectations – real reasons to take pride in saying, “I work for Suncor.”
Put yourself in our picture by applying at www.suncor.com/careers © 2010 NAS (Media: delete copyright notice) 18 M AY 2 0 1 0 • O I L & G A S I N Q U I R E R
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WORKING OVERSEAS
Grande Prairie's Shane Proteau on site in the Caspian Sea (above), a Nexen facility in the Yemeni desert (right), and a jungle wellsite in
Photo: Nexen Inc.
Papua New Guinea (opposite page).
20
M aY 2010 • O I L & G A S I N Q U I R E R
Feature
Canadian oil and gas specialists are on the job from Argentina to Azerbaijan by Jim Bentein
S
hane Proteau began working overseas out of economic necessity. The 32-year-old resident of Grande Prairie, Alta., has five children, aged 2 to 14. When northwestern Alberta’s gas patch crashed two years ago, his alternatives were unemployment or a foreign assignment. Fortunately, as a completions specialist with Halliburton Completion Tools, he soon landed a job in the West African country of Cameroon. “You make more money if you’re busy year-round in Canada, but the downturn really slowed us down,” Proteau says. Halliburton’s rotation schedule called for 35 days out of country and 35 days at home. “I’m fortunate because I have an understanding wife and understanding kids,” says the eight-year industry veteran.
Photo: InterOil Corporation
Eve n work i ng i n C a n ada , he ’d spent plenty of nights in hotel rooms. “I’ve never been one for an office job. Halliburton covers a big area from our Grande Prairie office,” Proteau says. “I go to Zama City, Red Earth, and Norman Wells. We’ve had guys who went to Alaska. I put an average of 15,000 kilometres a month on my truck.” After Cameroon, his next assignment was Azerbaijan, a central Asian nation that previously belonged to the Soviet Union. Proteau happened to speak some Russian, learned from a former girlfriend, which came in handy. “The coordinator there is from Canada, and he and I get along,” he comments. The oilfield specialist is also a history buff who enjoys reading about his foreign locations.
O I L & G A S I N Q U I R E R • M ay 2010
21
Feature
Halliburton offers its overseas rotational workers online training in language and culture, outlining local social customs, and religious beliefs. Even so, Proteau found himself shaken emotionally by the drastic poverty of Cameroon. “I was def i n itely not prepa red for Africa.” In his experience, foreign jobs are often technically interesting, but the dangers are greater than in Canada. “A helicopter could crash and there’s some political risk, too,” he says. All in all, though, this Albertan has enjoyed being an expatriate worker. In important respects, Duane Mather did not relish his time as an expat worker about 40 years ago. In that era, entire families normally went overseas. While his wife and three children lived in Tehran, Mather himself worked 300 kilometres from the Iranian capital. “We had problems finding schools for the kids and there were medical and other family issues,” recalls the president of Nabors Canada, a division of Nabors Industries Ltd. Too many of his colleagues wound up divorced. Mather worked in half a dozen countries and eventually ran the
international operations of Nabors, the world’s largest land drilling contractor. His division operated across 25 nations around the globe. To ease the burden on families, the Albertan initiated the modern oil and gas pattern of rotating expat workers in and out of country on a schedule that typically spans 28 to 35 days out with an equal time at home. O verseas operators also rely far more heavily now on homegrown talent in their foreign operations. For the most part, Nabors only has senior employees, suc h as e x per ienced r ig ma nagers or drillers, working on rotation. “In exploration, where you don’t have much margin for error, we have more expats,” Mather says. Employing locally normally saves money in salaries and travel, and creating local employment wins political approval. Tom Boleantu, president of T he Expatriate Group Inc., provides financial and lifestyle advice to 2,000 Canadian clients who work outside their own country. “I’m a geologist by training and I worked overseas from 1961 to 1968 [in Morocco, Iran, and elsewhere],” the Calgarian says.
He launched his present business during the 1980s, when troubles in the domestic petroleum sector drove many Canucks to foreign lands. The financial rewards can be excellent, Boleantu says. For instance, Saudi Aramco currently plans to add 1,000 expat employees to its staff. Its pay scales tend to be more attractive than similar jobs in the Canadian energy sector. In addition, the Saudi Arabian national oil company provides subsidized housing and other generous benefits, a practice that some other overseas employers also offer. Then there are tax advantages, particularly for Canadians who live elsewhere. T h i s c ategor y c a n i nc lude rotational employees who make their permanent home outside Canada. For instance, an expat may work in several nations but reside in Mexico when off duty. If a Canadian proves to the Canada Revenue Agency that he no longer resides in this country, no personal income taxes are owed in this country. Foreign countries often have lower tax rates, and some governments do not collect taxes from foreign residents.
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Saxon Energy Services Inc. knows all about expatriate and foreign-based workers. The Calgary company operates 54 drilling rigs and 11 workover rigs in seven countries, but none in Canada. Schlumberger, the global oil and gas services giant, holds a 49 per cent interest in the operation, whose staff totals 1,850. The vast majority are local employees, a pattern that increasingly prevails in the world’s oil and gas industry. Kathy Marasco, Sazon’s VP of human resources, says its Canadian and American specialists working overseas act primarily as a “training pool” for their future local replacements. “We have 90 employees who rotate from their Canadian homes,” she says. “We also have a small group, perhaps 15 or 20 senior people, including country managers or controller positions, who are resident expats.” At the moment, the majority of those senior executives work in Mexico. The well-paid contracts are typically for two to three years. After that, Saxon plans to have Mexicans in most of those positions. The warm climate is a bonus for Canadians accustomed to working outside in long,
Nexen's Ashif Noorani found that rotating overseas actually gave him more quality time with his son.
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Ne xen’s produc t ion i n t he A rab country has expanded to 56,000 barrels a day since it began operating there in 1993. It’s partnered with the Yemeni state oil company. Today, 90 per cent of its field staff and most of its managers in Yemen are local citizens. Cann prefers to send Canadians who’ve already worked overseas. “That isn’t to say we wouldn’t hire people without foreign experience,” he says, “but in that case we look for people with cultural sensitivity and flexibility.” Employees are carefully groomed for a foreign assignment, especially in Yemen, Africa, and Colombia. “We give them a security briefing so they know what they’re getting into,” Cann says. “We also give them a two-day intercultural session.” For Yemen, that briefing includes Muslim practices, such as daily prayer routines. Nexen also offers a “pre-decision trip” to the country of assignment for the staffer and his family. Once the job begins, the company pairs the newly assigned rotational or expat worker with someone who already has
Photo: Xtreme Coil Drilling Corp.
cold winters. “We encourage them to take classroom language training [which the company pays for],” Marasco says. Paul Beswick, a 38-year-old rig manager with Saxon, spent the last two years rotating between Calgary and Mexico. He’s now switched to Pennsylvania, where Saxon is drilling in the Marcellus shale gas play. The father of two boys, aged 14 and 15, plans to continue this way of life as long as possible. “Working in Alberta is feast or famine,” he says. “Now there’s structure in my life. It’s nice to know I’ll have 28 days in the field and 28 days at home. And I’m seeing the world on someone else’s dime.” Nexen Inc., a Calgary producer with 4,200 employees, operates in Yemen, West Africa, Colombia, the North Sea, and the Gulf of Mexico. The company has 61 expatriate employees and 120 who are on rotation to Yemen (down from 300 at the peak). “We hire people who can mentor, so that ultimately the Yemenis can take over their roles,” says Jeff Cann, a senior recruiter who worked in Yemen.
Western Canadian oil and gas service companies and workers have found work in Mexico. 24
M aY 2010 • O I L & G A S I N Q U I R E R
experience working there. The pay is attractive. “You receive an uplift to your base salary and a daily living premium,” Cann says. “It’s a fairly significant number.” Ashif Noorani has worked for Nexen as a systems analyst for 18 years, half of them in Yemen. As a single man, the Calgarian was happy to accept an initial expatriate position in Yemen. After getting married and having a son, he switched to a 35-day rotation between 2003 and 2009. “It’s hard when you’re away that long,” says the 45-year-old father. On the plus side, “I found I could spend more quality time with my son.” The biggest advantage of expat and rotational work is financial, according to the Nexen systems specialist. In Yemen, his work camp lifestyle included free room and board plus amenities like laundry, satellite television, and Internet services, all free of charge. Although he maintained Canadian residency rather than opting for full expatriate status, his income tax rate fell to 10 per cent. Noorani, who’s now working in Calgary, says he would gladly accept another foreign assignment.
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British Columbia
Photo: Kinder Morgan, Inc.
B.C. First Nations coalition opposes Enbridge oilsands pipeline
Despite past pipeline successes, opponents say Enbridge’s oil export plan creates environmental risks.
Dozens of orcas, hundreds of thousands of seabirds, and millions of salmon were wiped out when the Exxon Valdez oil tanker spilled 40 million litres of crude oil into Alaskan waters. Twenty-one years later, a coalition of British Columbia First Nations says such a disastrous oil spill can never be allowed to happen again, and declared it will do whatever it takes to stop a proposed pipeline from the Alberta tar sands to the B.C. coast. More than 150 First Nations, businesses, environmental organizations, and prominent Canadians have signed on to the campaign to stop the pipeline proposed by Calgary-based Enbridge Inc. The majority of the landscape to be covered is traditional B.C. First Nations land. The Coastal First Nations, who are heading the declaration, are an alliance of communities on B.C.’s north and central coast, including the islands of Haida Gwaii.
The Northern Gateway Project would see two 1,170-kilometre pipelines stretching from the tar sands near Edmonton to the northern B.C. coast town of Kitimat. Crude would flow, crossing more than 1,000 streams and rivers, mountain ranges, avalanche-prone terrain, and rainforest ecosystems before being loaded onto upwards of 150 tankers annually for export. “We all believe the Enbridge Gateway pipeline project is a threat to the very existence of our culture and our way of life,” Art Sterritt, executive director of the Coastal First Nations, said on March 23. “There are some who believe the Enbridge project is a done deal. It isn’t. It would be both unwise and irresponsible for Enbridge to ignore us or our constitutionally protected rights and title in British Columbia.” Enbridge is in the final stages of a regulatory application to the National Energy Board. The company has touted
the benefits of the project, saying more than 4,000 construction jobs and thousands more indirect jobs would be created, while generating hundreds of millions in tax revenue for both provinces. The company has said ships have safely carried petrochemicals out of the Kitimat port for 25 years, and they will, in fact, make safety improvements. Oil and gas have long been piped over the Rockies without incident. In an email, Enbridge said it must still undergo a “comprehensive and rigorous regulatory review process to ensure the project is in the interest of the Canadian public.” But Sterritt said after five years of scientific research and community consultations, the groups that have signed onto the campaign believe “no good” can come from the project. “We don’t... make this declaration blindly or lightly, we make it from an informed position,” said Gerald Amos, a director of Coastal First Nations. Amos said a blockade on the water is possible if the project goes ahead. Along with 28 B.C. First Nations, the Union of B.C. Indian Chiefs and some aboriginal groups from Alberta, environmental groups including the David Suzuki Foundation, and the Pembina Institute also signed on to the campaign. Environmentalist Vicky Husband said she believes two additional pipelines would allow an increase in production in the Alberta tar sands of up to 30 per cent. “If we actually believe in taking steps to deal with climate change, the tar sands need to be phased out,” she said. Premier Gordon Campbell said the project will not proceed if it’s deemed too dangerous for the environment. He said the government wants to build an economic future for B.C. First Nations, “in a way that meets all of our environmental standards.” —CANADIAN PRESS
BRITISH COLUMBIA WELL ACTIVITY
MAR/09
MAR/10
WELL LICENCES
68
75
▲
MAR/09
MAR/10
WELLS SPUDDED
27
73
▲
MAR/09
MAR/10
WELLS DRILLED
59
92
▲
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • M ay 2010
27
British Columbia
Fort Nelson North gas plant application proceeds without NEB hearing The National Energy Board is continuing to review an application from Westcoast Energy Inc. (Spectra Energy Transmission) for a new plant to process Horn River natural gas after cancelling a public hearing on it. In a letter to Westcoast, the board said that when it asked for comments on the proposed cancellation, it received one letter of support and no objections. The Dene Tha’ First Nation, which initially had requested the hearing later withdrew its request. Westcoast had emphasized the need for an expeditious regulatory process for the proposed Fort Nelson North processing facility as “time is of the essence.” The project schedule requires that tree and brush clearing work for the 250 million cubic feet-per-day facility adjacent to Westcoast’s Cabin Lake booster
station be completed this spring prior to the restricted activity period for migratory bird nesting, from May 1 to July 31. The proposed facility 75 kilometres northeast of Fort Nelson is underpinned by long-term expansion service agreements that provide for a targeted in-service
2012 and, subject to certain adjustments, they increase to the 250 MMcf per day maximum inlet design of the plant. Sales gas from the proposed facility will flow east on the Alberta system. Encana received regulatory approval for its proposed Cabin gas plant approximately
The facility is supported by a number of producers with gas rights in the Horn River basin. date of May 1, 2012. “While manageable, the project schedule is tight and requires diligent construction management by Westcoast and its vendors and contractors,” said the company. The expansion service agreements provide for initial contract volumes of 55 MMcf per day of raw gas beginning in May
6.7 kilometres from the proposed Fort Nelson North processing facility. It will have an initial processing capacity of 400 MMcf per day and a final capacity of 800 MMcf per day when fully developed in 2013. The facility is supported by a number of producers with gas rights in the Horn River basin. —DAILY OIL BULLETIN
B.C. puts up a further $120M through infrastructure royalty program The British Columbia government has put up $120 million in the latest installment of cash through its infrastructure royalty-credit program. The ministry is now accepting requests for applications from companies to participate in the 2010 program. Energy Minister Blair Lekstrom expects the program will continue to draw strong interest. “We expect to [receive many applications],” Lekstrom said. “These are always good incentives to try and get new infrastructure put in place, access new plays or parts of plays that aren’t as economical as some of the others.”
Since 2004, the B.C. royalty-credit program has allocated more than $485 million in infrastructure royalty credits to natural gas and petroleum companies operating in the province, resulting in 71 new road-based projects and 83 new pipeline projects. This represents new total capital investment in B.C. of almost $1 billion. The province gets an approximate return on investment of $2.50 for every dollar invested, it was estimated, which is revenue that would not have been collected otherwise. The program is designed to reflect the competitive challenges of
enabling year-round activity and providing infrastructure that allows natural gas activity that would otherwise not take place. Companies can apply to the ministry with proposed road or pipeline infrastructure projects and compete for these royalty credits. As in previous years, all projects applying for credits under the infrastructure royalty credit program will undergo an evaluation and ranking process and only those that ensure the highest economic benefits for B.C. will be approved. —DAILY OIL BULLETIN
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Northwestern Alberta/Foothills
Early drilling results in the Wilrich play are encouraging
Photo: Brian Zinchuk, Pipeline News
by Paul Wells
Alberta royalty reforms helped spark drilling success this winter in the Wilrich tight gas formation.
In 2009, Fairborne Energy Ltd. pioneered horizontal drilling in the Wilrich formation, an emerging resource play in the Marlboro/ Pine Creek area. Three horizontal probes (1.6 net to the company) into the tight sand reservoir all tested between five million and six million cubic feet (MMcf) per day. This year, Fairborne contracted two rigs during the first quarter to drill three Wilrich horizontals in the Marlboro area. Throughout 2009, Fairborne added to its land base in the Marlboro area—midway between Edmonton and Grande Prairie, Alta.—and now controls 37 (28 net) sections that are prospective for Wilrich. With current plans to drill up to three wells per section, the company estimates its potential drilling inventory at 107 wells. Steve VanSickle, Fairborne’s president and CEO, notes that its Wilrich wells benefit greatly from provincial drilling and royalty incentives because the formation
lies at a depth just below 2,500 metres. “You do get the maximum benefit from a depth standpoint and then you really get a significant benefit from going horizontal from there, so it really does make a material difference on the economics of those wells,” he says. “The horizontal wells cost approximately $5.4 million to drill and complete, and they benefit from all three components of the Alberta government royalty incentives that include 0.5 Bcf [billion cubic feet] of production at five per cent royalty and approximately $4.4 million in deep gas credits and drilling incentives,” VanSickle says. Aside from the drilling and royalty incentives, the Fairborne CEO praises the provincial government for recently expanding areas in the Deep Basin where automatic downspacing is allowed. “We used to have to apply for that [to the
Energy Resources Conservation Board] but now it’s encompassed in the changes announced and we’re quite appreciative of that,” he comments. VanSick le says the company has improved its drilling and fracturing techniques, enabling its latest well to average 4.6 MMcf per day over 60 days, a 25 per cent improvement over its first well’s production. Two of the three Wilrich wells (2.3 net) scheduled by Fairborne for the first half of this year will be drilled from a single pad. Completion operations will commence after both wells have been drilled. Although this approach will delay the start-up of production relative to drilling and completing single wells, the “cost efficiencies will significantly enhance already robust economics,” VanSickle says. The oldest Wilrich horizontals have been on production for less than 290 days, still too soon to project their ultimate recovery. “Initial indications are those wells are quite economic in today’s price environment and that we are generating double-digit rates of return with these wells in this commodity price environment,” VanSickle says. His company’s capital budget includes seven horizontals. Darren Gee, president and CEO of Peyto Energy Trust, plans to ramp up drilling this year in several emerging Deep Basin tight gas plays, most notably the Wilrich, Notikewin, and Bluesky reservoirs. In its Nosehill project area in Greater Sundance, Peyto has Wilrich rights on 125 sections. Gee says a number of past vertical producers proved the potential of the Wilrich play. “The average vertical well comes on the first month at about 1 MMcf per day and quickly declines down to about 200 Mcf [thousand cubic feet] per day,” he says. Initial results from the application of horizontal drilling and multi-stage frac treatments have been encouraging. “The first
NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY
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WELL LICENCES
51
127
▲
MAR/09
MAR/10
WELLS SPUDDED
30
116
▲
MAR/09
MAR/10
WELLS DRILLED
97
204
▲
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • M ay 2010
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well [drilled during the third quarter of 2009], as we slowly opened it up over time, we got it up to about 4 MMcf per day. Then in the next few months it declined to about 2.5 MMcf per day,” he says. Although horizontal wells cost about $5 million compared to about $1 million for a vertical, Gee says horizontal drilling increased original gas in place three
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“Daylight has the flexibility to re-allocate capital depending on the commodity price outlook for oil versus natural gas, and certain of our liquids-rich natural...." – Steve Nielsen, CFO, Daylight Resources Trust
to five times per well, initial production rates were three to four times higher, and estimated ultimate recovery was improved four to six times. Rate of return for the horizontals was between 87 and 113 per cent in the low- and high-case models respectively, compared to 33 per cent for vertical wells. The trust plans to drill five or six Wilrich horizontals this year, “which doesn’t sound like a lot relative to the inventory, but it’s still $25 million to $30 million [at about $5 million per well],” Gee says. “If they continue to perform as well as we expect and as we’ve seen in some of the early results, we’re going to continue to probably ramp up our activity there a little more and try to drill even more wells there in 2011.” Steve Nielsen, Daylight Resources Trust’s CFO, says his company will spend $300 million ($275 million net of drilling credits) on its 2010 capital program to drill approximately 60 to 80 locations. In the Deep Basin at Elmworth and Wapiti, Daylight will commit 25 to 30 per cent of that capital to drilling for Cadomin and Nikanassin gas. A similar amount of capital has been allocated to Daylight’s west central Alberta properties of Pine Creek, Kaybob, and the like, where the trust will drill for Wilrich natural gas, Bluesky liquids-rich natural gas, Cardium liquids-rich natural gas and light oil and Notikewin natural gas. “Daylight has the flexibility to re-allocate capital depending on the commodity price outlook for oil versus natural gas, and certain of our liquids-rich natural gas targets provide desirable exposure to both commodities,” Nielsen says. “With our significant resource plays in inventory, we are looking
forward to a very active 2010 drilling program to bring these opportunities on to production and recognized in our reserves.” At its emerging Wilrich play, Daylight has participated in three horizontal multistage fractured wells in the zone. Wells came on production between 3 and 5 MMcf per day and first well production to date has produced about 600 MMcf in six months. Daylight has over 24 net sections of lands with Wilrich rights in the area and Neilsen notes that similar developments have used between two and three wells per section. In 2010, the trust plans to drill six to eight Wilrich/Cardium/Notikewin horizontal gas wells and a similar number of multi-zone vertical gas wells in the area. Lyle Michaluk, CFO for Open Range Energy Corp., says his company has begun to identify potential sweet spots that would be “attackable” on a horizontal basis in its core Ansell/Sundance area. The firm drilled its first horizontal at Ansell/Sundance during the first quarter of 2009. Targeting the Bluesky formation, the well was completed in July with a total of six fracture stages and production averaged about 2 MMcf per day for the first six months. Open Range followed that well up with its initial foray into the Notikewin, where it punched a well in December that was drilled to a total measured depth of 4,100 metres, including a 1,250-metre horizontal leg. That well was cased by mid-January and flowed at initial cleanup production rates of up to 5.4 MMcf per day after 60 hours. Open Range’s first-half 2010 capital program is $30 million. The company plans to drill three (2.6 net) horizontal and two wholly owned multi-zone vertical Deep Basin wells at Ansell/Sundance as well as one (0.4 net) horizontal Cardium oil well at Pembina. At its still untapped Wilrich horizontal play, Michaluk says the company has identified 15 horizontal locations after reviewing the results of the initial wells punched into the zone by other operators in the Marlboro area just north of Ansell/ Sundance. Open Range plans to drill its first Wilrich horizontal later this year. “In the past year, seeing some of the success the guys to the north of us have had in the Wilrich has really got us encouraged as to the potential of this horizontal drilling in our area, and we’re going to do a Wilrich horizontal sometime in the second half—that’s our plan in the shorter term,” Michaluk says. — DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • M AY 2 0 1 0
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Northeastern Alberta
The hunt intensifies for a breakthrough oilsands solvent by Pat Roche
MAR/09
MAR/10
MAR/09
MAR/10
WELLS SPUDDED
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WELLS DRILLED
64
105
Photo: Joey Podlubny
John Nenniger, CEO of N-Solv Corporation, says the poor SOR progress stands in stark contrast with strong gains in other sectors such as computer technology during the same period. “Outcomes like this, in a competitive business environment, are very unusual,” he comments. “There is a heck of a lot of money just going up in smoke.” Discovering a superior alternative could be worth billions of dollars a year, benefiting bitumen producers, federal and provincial taxpayers, and other oilsands stakeholders. In a bid to command a share of that massive prize, N-Solv is promoting its own solution. Like SAGD, N-Solv uses two parallel horizontal wells—an injector wellbore is placed above a bitumen collector wellbore. Instead of injecting steam to heat the in situ bitumen, however, N-Solv would inject propane vapour into the reservoir.
Nenniger, a chemical engineer who earned his doctorate at the Massachusetts Institute of Technology, believes N-Solv’s process would be twice as profitable as SAGD. Bitumen output from comparable reservoirs could be tripled, fuel cost could plunge by 90 per cent, and the oil would be higher quality. As a major bonus, eliminating water usage and reduced carbon dioxide emissions would help allay environmental concerns. The Calgary-based company is tackling a technical challenge that has defeated plenty of contenders, some of them highly qualified. Hopeful inventors have been patenting solvent-based bitumen extraction processes since the mid-1970s without a game-changing breakthrough. The only current commercial-scale application of solvents in bitumen recovery occurs at the Cold Lake project operated by Imperial Oil Limited in northeastern Alberta. Imperial is Canada’s largest steamassisted bitumen producer. Its in situ production relies mainly on cyclic steam stimulation (CSS), not SAGD. CSS involves injecting steam into a well, then recovering the heated bitumen within the same wellbore. The company is testing a technology called LASER, which stands for liquid addition to steam for enhancing recovery. LASER adds a small amount of solvent— in this case, natural gas condensate, or diluent—to the steam that’s being injected into mature CSS wells. Imperial began piloting LASER on one well pad at Cold Lake in 2002 and the first production cycle was completed in 2004. While the company isn’t disclosing results, it has expanded LASER to 10 well pads over the past two years. (Each pad has roughly 20 wells.) Cenovus Energy Inc. is another operator experimenting with solvent technology. The company, which was created last fall from the oil operations of Encana Cor porat ion, i s Ca nada’s biggest
Imperial has expanded NGL solvent injection to 200 CSS wells at Cold Lake over the past two years.
When steam assisted gravity drainage (SAGD) was first piloted in the 1980s, one project achieved a steam to oil ratio (SOR) of 2.4—meaning 2.4 barrels of water were converted to steam for every barrel of bitumen produced. Today’s commercial SAGD projects have not achieved significantly better SORs, and many are worse. Granted, that early SOR was a small pilot test with 25-metre well spacing, one-quarter of the usual commercial spacing for SAGD well pairs. Even so, why hasn’t more progress been made? It’s a crucial question. For in situ bitumen operations (as opposed to strip mining at surface), steam stimulation remains the overwhelmingly dominant technology. Extracting Alberta bitumen consumes roughly one billion cubic feet of natural gas per day, much of it to boil water to produce steam. By 2020, that daily gas consumption is forecast to triple to a staggering three billion cubic feet. NORTHEASTERN ALBERTA WELL ACTIVITY
MAR/09
MAR/10
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189
112
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Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • M ay 2010
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made when the company decides whether to proceed with the project. Cenovus and Imperial are both adding solvent to steam. Imperial has tried solvent-only processes but then reverted to steam usage due to the high cost of solvent, the fact that not all of the solvent could be recovered with the bitumen, and the complexity of pure solvent processes compared to steam. Even so, Imperial’s steam-plus-solvent operation at Cold Lake involves significant losses of high-cost
diluent into the formation, and the process is far from simple. The best-known previous attempts at using solvent without steam focused on a process called vapour extraction, or VAPEX. This technology utilizes solvent vapour at dew-point conditions. After several unsuccessful pilots, industry interest waned. Nenniger argues that N-Solv’s patented pure solvent technology will succeed where VAPEX failed for two key reasons: Photo: Joey Podlubny
SAGD producer. Cenovus is currently doing a third field pilot test of its solventaided process (SAP). This technique adds a small amount of solvent—butane— to the steam injected into SAGD wells. Cenovus says the butane greatly reduces its steam requirements. Natural gas is expensive. Even though Cenov us has achieved steam to oil ratios that are second to none, its SAGD operations consume about 100 million cubic feet per day of gas. As production expands, the company expects consumption to reach the range of 200 million to 250 million cubic feet. Its previous two SAP pilot tests took place at Christina Lake in northeastern Alberta and Senlac in southwestern Saskatchewan. Cenovus says the third SAP pilot, again at Christina Lake, is going well. The heavy crude producer is now considering commercial use of SAP at its proposed Narrows Lake project on a lease near Christina Lake. The company plans to outline two options—SAP and straight SAGD—when it files its Narrows Lake regulatory application later this year. Once the regulatory process is finished, a decision on whether to use SAP will be
Cenovus is piloting two more butane solvent injection projects.
? ion t c u prod r u o ffect y a e d o e r n d r i o s l c t e e p e a i l p t e l fford to a u o y Can
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Ma AY Y 2010 • OIL & GAS INQUIRER
Northeastern Alberta
1. N -Solv’s process removes methane that is naturally present in raw bitumen. Nenniger says methane greatly impedes the effect of solvent and thus impedes bitumen production. 2. N -Solv uses the heat from the condensing solvent vapour to heat the in situ bitumen. The company says this relatively low-cost form of heating is sufficient to achieve an eight-fold increase in bitumen flow if a suitable solvent is present. The second point lies at the heart of N-Solv’s technology. “You don’t need to increase the temperature by 230 [degrees Celsius] to mobilize the oil and get it flowing. With solvent, 20 or 30 degrees of temperature rise is sufficient to achieve SAGD-type production rates,” argues Nenniger. He believes a 500-metre well pair in 20 metres of pay could achieve production of 440 barrels per day using N-Solv’s technology, compared to 50 barrels with SAGD. In a SAGD horizontal well pair, the injected steam creates a heated zone referred to as a “chamber” between the two wellbores. Conceptually, only liquids should exit that chamber (flowing downward due to gravity). Steam and solvent
vapour should remain trapped rather than escaping into the formation or to surface. To help achieve that result, the production well is placed low in the chamber— and submerged under a pool of liquid—to ensure only liquids are produced to surface. The problem, according to Nenniger, is that methane—which is relatively insoluble in oil—is also trapped in the steam chamber. The more methane accumulates in the chamber, the less room there is for steam or solvent. “In our experiments, one per cent methane contamination in our solvent reduced the extraction rate by a factor of four,” he reports. Like N-Solv, VAPEX involves propane vapour injection into the reservoir. As part of the VAPEX dew-point recipe, however, between two and four cubic metres of methane were co-injected for every cubic metre of propane vapour. Nenniger postulates that the methane filled the chamber, leaving little room for propane. His conclusion: all of the VAPEX field projects “were doomed to fail right from the beginning.” Conceptually, N-Solv eliminates this problem by continuously removing methane from the propane before it is recycled back into the chamber.
N-Solv also hopes to address the pressure problem faced by SAGD and CSS. Many steam-assisted projects operate at pressures far above the original reservoir conditions. That pressure helps force steam into the bitumen. However, Nenniger warns, high pressure can also induce loss of steam and bitumen to thief zones or lean zones, and steam may even break through to the surface. An extreme example of SAGD pressures compromising overburden integrity occurred in May 2006 when the caprock was breached at Total E&P Canada Ltd.’s Joslyn project in northeastern Alberta. The resulting explosion hurled rocks hundreds of metres into the air and left a huge crater in the ground. After a regulatory investigation that lasted nearly four years, Total recently decided to abandon the Joslyn SAGD project. N-Solv’s low-pressure injection would resolve such issues. Beyond its extensive lab work, the company has drilled three exploratory wells at the underground test facility (UTF) site in northeastern Alberta. Nenniger feels the facility at Dover can provide a convincing benchmark comparison since SAGD was originally piloted at that
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O I L & G A S I N Q U I R E R • M ay 2010
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Northeastern Alberta
site (originally developed by the provincial government). “We want to validate the technological assumptions at a scale that’s relevant to a commercial development,” he says. Several heavy hitters are backing N-Solv. Enbridge Inc. invested $15 million. Hatch Ltd., a global engineering firm based in Ontario, invested $15 million and supplied
Neil Edmunds is VP of enhanced oil recovery at privately held Laricina Energy Ltd., a well-financed oilsands lease holder that doesn’t yet have any production. Edmunds was process development coordinator at the Dover UTF for Alberta Oil Sands Technology and Research Authority during the early SAGD work.
“We think solvent additives are the lowest-hanging fruit in terms of making a material improvement in the performance without a huge change in the engineering.” – Neil Edmunds, VP of Enhanced Oil Recovery, Laricina Energy Ltd.
engineering talent. (Hatch patented a solvent vapour extraction process for bitumen in the 1970s and continued to do research and development work through the 80s.) Nenniger says Suncor Inc. made an in-kind contribution of $25 million in providing the Dover site for a field pilot. Sustainable Development Technology Canada, which funds development of clean technologies, invested $9 million on behalf of the federal government. Meanwhile, a thermal oil veteran who worked on several SAGD projects is planning two steam-solvent field tests.
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Laricina hopes to start an 1,800-barrelper-day pilot at Saleski—which is about 80 kilometres northeast of Wabasca in northern Alberta and 100 kilometres southwest of Fort McMurray—before year’s end. The target at Saleski is the Grosmont, a karsted, bitumen-bearing carbonate formation that has never been produced commercially. Hard on the heels of the Saleski pilot, Laricina hopes to do a 5,000-barrel-perday demonstration project at Germain, about 130 kilometres southwest of Fort McMurray and 40 kilometres northeast of Wabasca. The main target at Germain
is the Grand Rapids, a conventional oilsands formation that has had little attention compared to the McMurray formation (which accounts for most of Alberta’s current bitumen output). Laricina’s projects are designed to add solvents (such as propane or butane) to injected steam, a process it calls solventcyclic SAGD. The idea is the solvent would run ahead of the steam front, providing more oil recovery from a bigger volume than steam alone. “We think solvent additives are the lowest-hanging fruit in terms of making a material improvement in the performance without a huge change in the engineering,” Edmunds says. Laricina’s twist is the use of genetic algorithms. This technique harnesses the computational power of computers to mimic nature’s process of natural selection to find the most robust solution to a problem. The company will use genetic algorithms to find the optimum proportions of steam and one or more solvents. In his long research career, Edmunds has long operated on a basic principle: It’s probably easier to find new technology suitable to the reservoir than reshape the reservoir to existing technology. — DAILY OIL BULLETIN
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Central Alberta
Industry responds positively to Alberta’s retreat on royalty rates
Photo: Government of Alberta
by Paul Wells
Premier Ed Stelmach, seen here, says the province will take a smaller slice of a growing revenue pie.
The A lberta government rolled out changes to its royalty regime on March 11, a move that oil and gas industry leaders said was a strong move toward mending fences that were damaged by the New Royalty Framework (NRF) announced in 2007. Premier Ed Stelmach and Energy Minister Ron Liepert unveiled the results of the province’s long-awaited Competitiveness Review at Calgary’s McDougall Centre. Royalty changes include the reduction in the maximum royalty rate on conventional natural gas wells to 36 per cent from 50 per cent, while the maximum rate for conventional oil wells would decrease to 40 per cent from 50 per cent. The province will also permanently entrench a temporary incentive it introduced last year that reduces the royalty on new natural gas and conventional oil wells to five per cent for one year
(to a maximum 50,000 barrels of oil equivalent or 500 million cubic feet equivalent). The government said the permanent incentive takes effect immediately, while the new royalty curves
Stelmach also said the province will launch a cross-ministry task force that will look to simplify a cumbersome regulatory system. The task force has been directed to report back within 90 days on regulatory advancements, changes to support innovative technologies, and how to proceed with a comprehensive review of the regulatory system. Also, the Energy Resources Conservation Board will develop new processes around well spacing and confidentiality of date. The province estimates that with the changes, oil and gas companies will increase cash flow reinvestment by two percentage points. A two percentage increase will be worth about $700 million a year, the government said. “One of the things that we’ve committed to industry is that we wanted to provide certainty and stability, and we’ve done that,” Liepert said. The government said that the new rules will reduce its overall royalty take by at least $828 million over the next three years, but it expects to make back roughly half that amount in increased land sales and corporate taxes. “We believe that…by the third year of our
"…by the third year of our fiscal plan, activity, and spinoff from activity will offset any revenue losses projected." - Ron Liepert , Energy Minister
will be finalized by May 31 and made effective on Jan. 1, 2011. The proposed measures are designed to re-stimulate investment in Alberta’s oilpatch, but they will also see the government’s royalty share shrink. “The best way to look at this and the best way I can describe it is that the piece of the pie may be smaller, but we’re growing a much larger pie,” Stelmach said.
fiscal plan, activity, and spinoff from activity will [help] offset any revenue losses projected,” Liepert said. Gary Leach, executive director of the Small Explorers and Producers Association of Canada, viewed the changes in a positive light, noting that the junior sector had been hit particularly hard by the NRF, as well as the fallout from the credit crisis and global recession. “We’re pleased
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CENTRAL ALBERTA WELL ACTIVITY
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Source: Daily Oil Bulletin
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Central Alberta
to see that the low front-end royalty is entrenched because that’s a really critical requirement when you’re investing risk capital. You get return on that capital sooner,” he said. “We’re also pleased to see that the government’s given us some certainty on where the upper end of the royalties are going to be capped because that’s a return on your investment, and the smaller oil and gas companies are trying to attract investment into A lberta. I think it’s really important to be able to say to investors, ‘Here’s some certainty on what that will be.” Dave C ol lye r, pr e side nt of t he Canadian A ssociation of Pet roleum Producers, was also pleased. “I think they got a lot of it right. Certainly on the fiscal side there was some significant movements that are consistent with the kinds of things we’ve been talking about for some time,” he said. “And I think they also very tangibly recognized this is more than fiscal terms—it’s regulator y framework, it ’s technolog y and
innovation, it’s about how to talk about the industry collectively.” Collyer added that he’s encouraged that all aspects of competitiveness are being addressed, in particular the government’s commitment to address regulatory competitiveness in a timely manner. “A better regulatory framework will provide greater certainty for industry while continuing to deliver responsible environmental performance.” Both Collyer and Leach agreed that the province has opened the door to an improved relationship with industry, which was highly critical of the NRF and showed its dissatisfaction with that royalty regime by diverting investment out of Alberta to neighbouring jurisdictions. “I don’t think you restore credibility and trust overnight. That’s a process and that’s going to take a little while,” Collyer said. “But I would say that both the substance of what’s been announced and t he tone w it h which it ’s being announced are both very positive steps in that direction.”
Leach agreed that the province has taken a positive step, saying the development of Alberta’s petroleum resources should be a “partnership” between industry and government. “From what I’ve heard today and talking to a number of companies in the industry and the financial community, I think the sentiment is this has gone a long way toward restoring a level of trust with the government, and I also think both sides acknowledge they need to keep the door open in terms of dialogue,” he said. Although changes announced in the Competitiveness Review bode well for industry, Leach said there are still some outstanding issues that need to be ironed out, most notably establishing the parameters for when the high-end royalties kick in. “We’ve got quite a bit of work to do around drawing those curves. The details around where those curves will be drawn between the low front-end and the upper is still a piece of business we have to work out with the government in the next couple of months,” he said. — DAILY OIL BULLETIN
Bellatrix Exploration updates its Cardium drilling results Bellatrix Exploration Ltd. reports that its most recently operated Cardium well at Willesden Green (0.71 net) was successfully stimulated utilizing the multi-stage fracturing technique. After all of the load oil was recovered, the well was flowing at 735 barrels of oil per day and a natural gas rate of 1.05 million cubic feet per day for a combined production rate of 910 barrels of oil equivalent per day. To date in the first quarter of 2010, Bellatrix says it has drilled and completed 11 gross wells (6.01 net) and the company is currently drilling one gross well (0.85 net) at Ferrier (Notikewin horizontal) and one gross well (one net) at West Pembina (Cardium horizontal). On the Cardium play in westcentral Alberta, the company is drilling its seventh gross well (5.46 net). These wells were drilled and are being drilled at Willesden Green, Lodgepole, West Pembina, and Norbuck. At Lodgepole, the company’s second wholly owned well was drilled and completed, and placed on stream in midFebruary at an initial production rate 42
M AY 2 0 1 0 • O I L & G A S I N Q U I R E R
of 375 barrels of oil equivalent a day. The company is currently drilling a wholly owned well at West Pembina, which it anticipated being tied in before spring breakup. A second well (0.5 net) has been completed and is currently recovering load fluid. Bellatrix has a total ownership in 133 gross sections (81 net) in the west-central Alberta Cardium oil play.
On the Notikewin play in the Ferrier area, Bellatrix has drilled and completed a wholly owned multi-staged horizontal well. The well was placed on production in February at an approximate initial rate of 3.5 million cubic feet per day with 35 barrels of liquids per million cubic feet. A second Notikewin horizontal well (0.85 net) is currently
At Lodgepole, the company’s second well was placed on stream at an initial production rate of 375 BOE a day. At Norbuck, the company has drilled a total of three Cardium wells on its 2.5 gross sections (1.15 net). Production from two wells has lowered reported initial production rates each of 100 barrels of oil equivalent per day. Bellatrix said these lower rates are believed to be a factor of the more distal setting at Norbuck, where thinner net oil pays and lower permeabilities are more common.
drilling in the Ferrier area. The timing for the completion and tie-in will be dependent on road restrictions during spring breakup. In addition to this activity, Bellatrix participated in drilling four gross (0.55 net) nonoperated McLaren oil wells in the Lindberg area. These wells have been completed and are currently being put on production. — DAILY OIL BULLETIN
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Southern Alberta
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Well count, metres drilled, and rig activity all surge in early 2010
Alberta employed 366 drilling rigs for the first two months, up 34 per cent from a year earlier.
Operators drilled 35 per cent more wells in February than a year earlier, while metres drilled surged 54 per cent with more wells being drilled horizontally. Daily Oil Bulletin (DOB) records show 1,491 new wells were rig released in Canada during February compared to 1,106 for the same month last year, but still far fewer than in 2008 when industry drilled 3,952 wells. In fact, metres drilled in February (2.29 million) were only down 11 per cent from February 2008 and were 54 per cent above the 1.49 million metres of hole drilled in the second month of 2009. Part of the rise in metres drilled this year has been due to horizontal drilling in tight formations. DOB records show 440 horizontal wells rig released last month, up from 191 a year ago. In the first two months of 2010, operators rig released 2,772 new wells, up by 420 wells or 9.5 per cent from the same two months in 2009. Metres
drilled reached 4.25 million to the end of February this year, 31 per cent above the total for January and February 2009. Operators drilled 462 new wells in Saskatchewan over the first two months of 2010, up nearly 40 per cent from a year earlier. In Manitoba, 88 wells have been drilled versus 38 to the end of February
chasing natural gas deposits (according to licence data). Wells targeting natural gas in Alberta were down more than two-thirds from the peak of gas drilling in 2006. Rig activity also surged by 31 per cent during the first two months of 2010. A DOB survey for the first week of March found 232 more rigs at work than in the same week last year. The 547 active rigs represented 68 per cent of the available fleet of 806 rigs. A year ago, Canada’s oilpatch was hit hard by plunging commodity prices and the credit crisis that began in the fall of 2008. Only 232 of Canada’s drilling rigs were at work in the first week of March 2009, which represented 37 per cent of the available fleet of 853 rigs. Through the first two months of 2010, the Rig Locator showed an average of 543 active units, up from 416 in the first two months last year. Provinces with good oil prospects got a solid start this year. Saskatchewan and Manitoba almost doubled their rig counts from a year ago with 75 active in the former province through the first two months of 2010 (versus 39 last year) and 12 at work in the second province (up from six in 2009). Alberta employed 366 drilling rigs for the first two months, up 34 per cent from a year earlier but still well below the 455 active in the winter of 2008 and the 475
Operators drilled 462 new wells in Saskatchewan over the first two months of 2010, up nearly 40 per cent from a year earlier. 2009. Alberta operators finished work on 2,067 new wells, about eight per cent more than last year’s 1,911 wells. British Columbia operators only drilled 150 wells, down 39 per cent from 246 wells a year earlier. Of all the wells rig released in Alberta and Saskatchewan in the January-February period, 1,180 were targeting crude oil or bitumen formations, while 1,177 were
rigs at work in the first two months of 2007. The 2006 peak year saw 542 active rigs. While British Columbia’s rig count was down to an average of 89 units so far in 2010 from 96 employed a year ago, it was fairly consistent with rig counts for the past three years, although well below the 2004 peak of 155 active rigs.
MAR/09
MAR/10
MAR/09
MAR/10
WELLS SPUDDED
55
27
WELLS DRILLED
65
40
— DAILY OIL BULLETIN
SOUTHERN ALBERTA WELL ACTIVITY
MAR/09
MAR/10
WELL LICENCES
182
128
▼
▼
▼
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • M ay 2010
45
Southern Alberta
Ensign launches a build program despite lower revenues for 2009 Ensign Energy Services Inc. has begun a new build program that will result in six new proprietary ADR-1500s (automated drilling rigs) for delivery starting in early 2011. While no specific regions have been targeted for these new builds, Ensign said the rigs will likely be contracted for natural gas shale plays within North America before construction is completed. The expansion is proceeding though Savanna’s fourth-quarter net income was down 69 per cent to $22.64 million in 2009 from $73.83 million for the same period in 2008 due to lower levels of demand for oilfield services and reduced margins resulting from a general oversupply of oilfield service equipment, particularly in North America. Net income for 2009 fell by 52 per cent to $125.44 million from $259.96 million a year earlier. Despite the market turbulence experienced in Canada and throughout the world in 2009, Ensign said it continued to achieve acceptable operating margins of 31.3 per cent for the year compared with 32.8 per cent in 2008. Its geographic diversification and strong balance sheet
allowed the firm to take advantage of opportunities to continue to grow in 2009. The 14 ADR and seven well servicing–rig new-build program that began in 2008 was completed in December 2009. In Canada, Ensign recorded revenue of $112.4 million in the fourth quarter of 2009, a 38 per cent decrease from $180.2 million recorded in the fourth quarter of 2008. Canadian revenue was $425.9 million for the year, down 43 per cent from $743 million recorded in 2008. Canada accounted for 40 per cent of the company’s revenue in the quarter (39 per cent in 2008) and for 37 per cent of its revenue for the year, down from 44 per cent in 2008. Drilling rig utilization in Canada in the fourth quarter was 28.8 per cent versus 33.8 per cent in 2008, while rig utilization for the year averaged 20.3 per cent compared to 36.5 per cent the previous year. Ensign’s 112 well servicing rigs/units averaged a 29.8 per cent utilization rate in the fourth quarter (31.3 per cent in 2008) and 26.5 per cent for the year (33.7 per cent in 2008).
The number of drilling days recorded by the company’s U.S. segment in the fourth quarter of 2009 was down 45 per cent while drilling days for 2009 decreased by 51 per cent. Late in 2009, Ensign began operating in the unconventional shale gas plays of Haynesville and Marcellus with one rig in each area. A second rig began operating in the Haynesville area in the first quarter of 2010. Ensign’s international operations struggled in a few key areas during the second half of 2009, as it worked through a significant reduction in operating activity in Africa and Latin America. These negative events were partially offset by the expansion of the company’s international drilling rig fleet in 2009. During 2009, the company completed the international component of its newbuild program that resulted in six new ADR drilling rigs successfully deployed into the international market. Additionally, it transferred four ADR rigs from its Canadian fleet to its international operation to capitalize on additional opportunities in existing markets, although the financial contributions of
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M aY 2010 • O I L & G A S I N Q U I R E R
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Southern Alberta
these transfers will not be realized until the first half of 2010. Ensign said its Canadian operations have had a decent start to 2010, with winter utilization being slightly better than expected, particularly for the deeper drilling rig classes. However, financial contributions from Canada in 2010 are expected to be reduced from the prior year as margins for the winter drilling season reflect revenue rates associated with the lower levels of demand for oilfield services that persisted through much of 2009. The company’s U.S. operations also started the 2010 fiscal year better than expected, bolstered by the positive impact from the addition of seven ADR drilling rigs and two new well servicing rigs added to the fleet. Additionally, Ensign was able to modestly improve its margins on operating equipment in the face of better-thanexpected levels of demand for certain equipment classes. While the margins remain below peak levels attained within the last couple of years, the slight improvements indicate the level of customer acceptance and demand for the company’s newer high-technology drilling rig fleet. — DAILY OIL BULLETIN
Trican acquiring U.S. assets Trican Well Service Ltd. has agreed to pay $46 million for the assets of a private U.S.based company that provides stimulation services used in the development and completion of oil and gas wells in Oklahoma, Texas, and Arkansas. The acquired assets, which were put into service mid-2008, consist of 56,250
Trican said it intends to integrate the acquired equipment into its current U.S. fleet and operate out of the acquired base in Shawnee, Oklahoma, providing another base from which to service customers active in the Woodford shale. Despite some very challenging market conditions for most of 2009, Trican said its
Despite some very challenging market conditions for most of 2009, Trican said its U.S. operation positioned itself well in some of the most active shale plays. horsepower (hp) fracturing capacity and the necessary ancillary equipment to operate two fracturing crews. In addition, the company acquired two acidizing pumpers and ancillary equipment, and an established base of operations in Shawnee, Oklahoma, which includes some rail assets. This transaction brings Trican’s worldwide fracturing fleet to 515,850 hp and will increase the U.S. fleet to 267,750 hp. Based on the allocation of the cash consideration and assumed debt to the fracturing assets acquired, Trican estimates the cost of the acquisition to be approximately $773 per unit of hp.
U.S. operation positioned itself well in some of the most active shale plays. Activity has recently rebounded in these regions, which has had a positive impact on equipment utilization and operating margins. This additional equipment will help Trican meet the increasing demand for services from its customers. Trican said it is committed to growing its geographic presence and service offering in the United States, and believes that this acquisition will make a significant contribution to this long-term strategy. Currently, demand for its services in the United States is robust. — DAILY OIL BULLETIN
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Southern Alberta
Alberta is well on the way to surpass its 2009 Crown land bonus revenue dollar terms, “so I think the trend is healthy and shows growing optimism about future investment trends in Alberta. It is certainly possible that uncertainty over the details of the government’s policy response on royalties was a bit of a brake [for] some bidders,” he said. Britt Resources Ltd. tendered the bonus high of $21.4 million for a 4,096 ha licence parcel in the Deep Basin west
Land & Lease Ltd. The broker acquired the rights to a 64-hectare parcel for $2.3 million in the northwestern quarter of section 16 at 50-11W5. The second parcel, totalling 128 ha, went for $4.6 million for the eastern half of section one at 51-12W5. Daily Oil Bulletin records show Vero Energy Inc. rig released an oil well on March 1 in the Westpem area at surface location 4-16-50-12W5 with the Cardium
"It is certainly possible that uncertainty over the details of the government’s policy response on royalties was a bit of a brake [for] some bidders." – Gary Leach, Executive Director, Small Explorers and Producers Association of Canada
of Edson. The broker paid an average of $5,226/ha for a total of nine tracts and several sections at 53-18W5, 53-19W5, 54-18W5, and 54-19W5. The area has been heavily drilled by industry. The per-hectare high in the sale was $36,239, which was produced on two separate lease parcels picked up by Scott
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Alberta’s land sale auction on March 10 generated $167.6 million in bonus bids, the highest after four sales this year, as producers continued to post and purchase lands containing tight formations that are now considered economic to produce with new drilling and completion technologies. Year-to-date, the government has raised $378.6 million from 2010 land sales on 628,714 hectares (ha) for an average price of $602.18/ha, already past the halfway point to equalling the full calendar year total for 2009 of $741.6 million. To the same point in 2009, the province had collected $52.9 million on 443,774 ha for an average of $119.26/ha. The March 10 auction sold 323,661 ha of Crown rights for an average of $517.71. During the first sale of March last year, the province brought in just $10.6 million on 110,870 ha at an average of $95.40. Gary Leach, executive director of the Small Explorers and Producers Association of Canada, pointed out that each land sale in 2010 has been progressively larger in
formation listed as the terminating zone. The well had a total depth of 3,150 metres and was drilled horizontally. Also during the sale, seven parcels at 45-5W5, which combined for a total bonus of $12.6 million, each produced per-hectare averages of $15,162. — DAILY OIL BULLETIN
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Savanna more than doubles its 2010 capital budget to $97M Savanna Energy Services Corp. is expanding its capital program in 2010 in the light of improving prospects, international expansion, and its improved financial position. Late last year, the company outlined a $46-million capital program. Including maintenance capital and an expansion focused on Australia, the company’s 2010 capital commitment is now approximately $97.3 million. Savanna plans to expand its fleet of ultra-heavy double drilling rigs by two, retrofit a further two hybrid drilling rigs for deployment to Australia, and enhance the conventional depth capacity of two of its hybrid rigs to enable them to drill to depths exceeding 3,000 metres. While none of these rigs is currently contracted, management said it’s confident that they will be prior to delivery. The company will also add an additional flush-by unit to its well servicing fleet. In addition to these commitments, Savanna also aims to further expand its portable top drive fleet by four, to upgrade the capacity of two shallow conventional double drilling rigs for deployment from
Canada to the United States, and to marginally increase its rental fleet. In 2009, the company reported a lower net loss of $27.9 million compared to a $280.6-million loss the previous year. Savanna’s challenges mirrored those of the industry in 2009. With about 80 per cent of its drilling rigs and 90 per
rig from its Canadian operations to North Dakota in the fourth quarter of 2009, increasing the total U.S. drilling rig fleet to 17 rigs. During the fourth quarter, Savanna concluded a joint technology–development agreement with a private, government, and operator-backed technology
In 2009, the company reported a lower net loss of $27.9 million compared to a $280.6-million loss the previous year. cent of its well servicing fleet based in Canada during the year, the company was negatively affected by the industry conditions in Canada to a greater extent than those with broader geographic operations. Savanna, however, is on a diversification strategy. In December 2009, the company entered into a five-year contract to initially deploy two hybrid drilling rigs from its Canadian fleet and two builtfor-purpose service rigs to Queensland, Australia. Savanna also moved a drilling
group directed at the development and expansion of coil-drilling capabilities in directional and horizontal wells, focused primarily in the United States. On a year-to-date basis, Savanna operated an average fleet of 100 net rigs compared to 2008, when the average deployed drilling fleet was 96 net rigs. Since the first quarter of last year, Savanna has taken measures to reduce operating costs to more closely align these costs with the decreased operating activity. — DAILY OIL BULLETIN
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O I L & G A S I N Q U I R E R • M ay 2010
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Gibson Energy—part of Saskatchewan’s past, present and future…
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lthough Gibson Energy, a premier North American midstream oil and gas company for over 50 years, is headquartered in Calgary, its roots began and continue to grow in Saskatchewan. In fact, Gibson’s first sale in 1953 was for 365 barrels of crude oil that was loaded onto two tank cars in Gull Lake, Saskatchewan, headed for the Suncor Edmonton refinery (then known as British American). Today, the company moves millions of barrels of energy products to market through an infrastructure of facilities, terminals, pipelines, tank storage and a fleet of over 1,400 truck transportation units. The yellow Gibson trucks, or “moving billboards” as they like to call them, have long been a familiar sight on Saskatchewan’s highways. The brands of Gibson’s affiliates—including Moose Jaw Refinery, Bridge Creek Trucking, Johnstone Trucking and Canwest Propane—are also very recognizable to both the business and the non-profit sectors in many communities. In addition to Gibson’s reputation as an employer of choice, its longstanding practice of being socially responsible and giving back to the communities in which it operates has been acknowledged and appreciated by the University of Saskatchewan, the Moose Jaw Multiplex, the Lloydminster Fire Department, the Gull Lake Recreation Complex and many other service organizations. The Moose Jaw Refinery, which refines and markets a variety of petroleum-derived products, including several grades of road asphalt and roofing flux, has been in the Gibson family of companies since 2002. The refinery, when first purchased, operated six to seven months of the year. Because of Gibson’s capital investment, today the facility runs year-round. Gibson is a significant purchaser of crude oil in the Shaunavon, Gull Lake, Kerrobert and Lloydminster areas, which provide feedstock to the refinery. Under Gibson’s management, several new products have been developed and sold, both in Canada and the United States. These markets are served by a fleet
of 750 railcars as well as truck transportation units supplied by Gibson. Being in close proximity to both CP and CNR rail lines at Moose Jaw allows for efficient deliveries to customers. In addition, the refinery produces drilling fluid and fracturing fluid for the oil and gas drilling industry, which are also distributed by truck and rail across North America. With the recovery of oil prices and the development of shale gas, the demand for both fluids is expected to grow in the future. The acquisition of Bridge Creek Trucking in the spring of 2009 provided two truck unloading terminals located just outside of Gull Lake. Oil received into these terminals is delivered into the South Saskatchewan Pipeline System. Another affiliate, Johnstone Trucking, primarily transports crude oil and operates a well service business out of southeastern Saskatchewan and Manitoba, with over 50 units in these areas. Johnstone recently added a new office and shop complex to its base in Frobisher, and has additional facilities and trucks in Estevan, as well as trucks based out of Arcola, Saskatchewan. This was a strategic acquisition for Gibson, as Johnstone is located in the fast-developing Bakken oil play. Canwest, the propane marketing/distribution arm of Gibson, provides innovative propane solutions to customers throughout Saskatchewan. Its services are used by a wide variety of sectors (industrial, commercial, residential, etc.) and industries. Gibson’s Saskatchewan footprint was also enhanced with the 2009 purchase of a 39% ownership interest in Deepwell Energy. As Gibson’s Saskatchewan-born-and-raised President Stew Hanlon stated when the two companies initiated an alliance, “Our strategic relationship will
enable Gibson to optimize crude oil marketing opportunities with Deepwell’s facilities, capitalize on Gibson’s trucking fleet to move additional volumes of oil and water and increase Gibson’s presence in the Bakken play region.” Another intrinsic contributor to Gibson’s business in Saskatchewan is the marketing department. The marketing function touches almost every component of the oil and gas industry. The department: ■ purchases crude oil from the producer’s wellhead to supply oil to many Gibson terminals and the Moose Jaw Refinery ■ buys crude for transport on a Gibson truck or pipeline and ships the oil on various crude oil pipelines to refineries across Canada and the United States ■ sells the drilling and fracturing fluids so producer/ drillers can drill and complete new wellhead production ■ buys and sells natural gas liquids. One could say that marketing is the grease between the wheels of the Gibson machine that offers a wide array of products and services to Saskatchewan’s upstream and downstream oil and gas industry. Gibson excels at bundling its services—marketing, transportation, distribution and processing of energy products—for the specific demands of customers. The company intends to reinforce its enviable reputation in Saskatchewan, as a responsible employer and as a corporate citizen. In Mr. Hanlon’s words: “We’re proud to be an integral part of the Saskatchewan economy today as well as the growth and success we all expect to see throughout the province for decades to come.” ■
www.GibSonS.com
Saskatchewan
Photo: Brian Zinchuk, Pipeline News
PetroBakken pegs FD&A cost and outlines drilling plans
PetroBakken plans to build two more major oil batteries and expand its existing Midale gas plant.
PetroBakken Energy Ltd. calculates its proved-plus-probable reser ve cost at $32.11 per barrel of oil equivalent (boe), rolling in its finding, development, and acquisition expenses along with reserve revisions and future development charges. Its proved-plus-probable reserves at the end of 2009 totalled 143.6 million barrels. On Aug. 4, 2009, Petrobank and TriStar Oil and Gas Ltd. agreed to combine assets into a Saskatchewan-focused producer named PetroBakken Energy Ltd. The new company is a 64 per cent owned subsidiary of Petrobank Energy and Resources Ltd. The net present value of its reserves was estimated at $3.7 billion (before tax, discounted at 10 per cent) at the end of 2009. PetroBakken suffered a negative revision of 4.8 million boe to its proved-plus-probable reserves when Sproule Associates Limited applied its reserve assessment standards and
methodology to a portion of TriStar’s assets in southeastern Saskatchewan. PetroBakken said its enhanced bilateral drilling approach in the Bakken tight oil formation has demonstrated its ability to increase primary recoveries from the reservoir and expand the economic limits of this resource play. The ongoing modifications and improvements to fracture stimulation techniques result in fractures that are statistically less likely to break out of zone, resulting in wells with lower water cuts in areas where the bounding shale zones to the Bakken are thinner. Since July 2009, PetroBakken has been implementing the use of long bilateral horizontal wells with 51 bilateral horizontal wells now on production. Bilateral horizontal wells have generated on average greater than a 50 per cent increase in productivity compared to offset single-leg Bakken horizontal wells.
PetroBakken noted that its January 2010 production averaged 43,600 boe per day, after the disposition in December 2009 of approximately 2,000 boe per day. The company said it expects further dispositions of non-core producing assets in the first quarter of 2010 totalling 3,800 boe per day. Including assets sold prior to year end, the company anticipates selling a total of 5,800 boe per day for gross proceeds of approximately $315 million. PetroBakken’s 2009 average production was 26,333 boe per day. In the fourth quarter, PetroBakken production averaged 45,621 boe per day. In December 2009, company production averaged 45,900 boe per day, of which 38,200 boe per day were produced from core properties in southeastern Saskatchewan and British Columbia. PetroBakken drilled 157 gross wells (152 oil wells, three gas wells, and two dry and abandoned wells) and 117.3 net wells (113.3 oil, 2.5 gas, and 1.5 dry and abandoned) in 2009. All of these oil wells were in southeastern Saskatchewan, while all of these gas wells were in the Monias and Horn River unconventional gas plays in northeastern British Columbia. PetroBakken currently has 12 rigs drilling in southeastern Saskatchewan, 10 rigs working in the Bakken, and two rigs in its conventional Mississippian plays. The company plans to build two more major oil batteries and expand the existing Midale gas plant from 8 million to 13 million cubic feet per day to handle the additional solution gas volumes. Following spring breakup, the company’s 2010 drilling program will be realigned to take advantage of an expanded drilling inventory in the Cardium play of Alberta. Current plans anticipate an 8 to 10 rig program in the Bakken and conventional plays of southeastern Saskatchewan and six drilling rigs operating in the Cardium. — DAILY OIL BULLETIN
SASKATCHEWAN WELL ACTIVITY
MAR/09
MAR/10
WELL LICENCES
157
287
▲
MAR/09
MAR/10
WELLS SPUDDED
47
142
▲
MAR/09
MAR/10
WELLS DRILLED
68
197
▲
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • M ay 2010
51
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M AY 2 0 1 0 • O I L & G A S I N Q U I R E R
Northern Frontier
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Decision on Mackenzie pipeline project gets delayed until 2013
First proposed in the 1970s, the Mackenzie Valley pipeline project still faces a long road ahead.
The proponents of a proposed Mackenzie natural gas pipeline will not decide whether the project should proceed for nearly four years—and then it would be another five years before gas would be flowing. In that case, the earliest possible start-up date for the proposed Mackenzie natural gas project is late in 2018, four years later than the 2014 possible onstream date forecast three years ago. “This revised start-up timing reflects regulatory delays, lack of a fiscal agreement, project re-staffing requirements, and seasonal constraints,” Imperial Oil Resources Ventures Limited says in a filing with the National Energy Board (NEB). “Timely action by all parties, including the proponents, governments and regulators, will be essential to achieve this schedule.” The NEB is to hear final arguments on the Mackenzie project April 12–24 in the Northwest Territories. In its filing, Imperial says the proponents believe that by late 2013 they could be in a position to decide whether to proceed with the project. Assuming they decide to proceed, facilities and site work would begin in mid-2014 with commissioning and start-up in the first quarter of 2018.
This schedule is based on the assumption that by Sep. 1, 2010, the board has approved the principal project and sufficient progress has been made on fiscal terms, says Imperial. These requirements will allow for a decision to be made in September of this year to re-staff the project team and re-start the activities required to enable the proponents to decide whether to proceed. The NEB had directed the project proponents, Imperial, the Mackenzie Valley Aboriginal Pipeline Limited Partnership, ConocoPhillips Canada (North) Limited, Shell Canada Limited, and ExxonMobil Canada Properties, to file an updated project schedule, as well as on markets and economic feasibility. In an update for the board, Imperial said that there have been confidential discussions between the federal government and the project proponents on the subject of fiscal terms for the project. “However, more progress is needed to allow for a re-staffing of the project team and for resuming engineering, permitting, and fieldwork,” it said. As for regulatory-related activities, Imperial noted the Joint Review Panel concluded its hearings in late 2007 and
issued its report Dec. 30, 2009. The company said it has obtained an improved understanding of the regulatory review and approval process associated with permits required for construction and operations activities. Benefits and access agreements also have been negotiated, ratified, and executed with aboriginal groups in all regions except the Deh Cho, where further negotiations are planned, said Imperial. Imperial said it has no new evidence to file for the Mackenzie Valley pipeline regarding long-term gas supply, contractual commitments, and project financing. However, in relation to gas markets, it filed an updated gas market demand and supply analysis for Canada and the U.S. Lower 48. The study by Angevine Economic Consulting Ltd. concluded that market conditions in Canada and the Lower 48 states would allow gas from the Mackenzie Delta to be absorbed if the pipeline project is constructed to be in service by 2018. The northern gas would be needed because natural gas consumption will continue to grow, spurred by the increasing demand for power generation and for industrial purposes, especially for oilsands bitumen production and upgrading, the study found. The Angevine study forecasts that total gas demand in Canada and the Lower 48 states will climb to 92.81 billion cubic feet (Bcf) per day by 2030, up from 73.35 Bcf per day this year. In Canada, Alberta oilsands’ demand for gas is forecast to rise to 2.01 Bcf per day by 2030, from 800 million cubic feet per day in 2010, while gas-fired power generation demand would increase to 2.48 Bcf per day, of which 1.42 Bcf per day would be in Alberta. The study acknowledges that the growth of shale gas in both Canada and the United States will help to meet total domestic requirements. “However, even with the delivery of gas to the North American pipeline grid via pipelines from the Mackenzie Delta and Alaska, LNG [liquefied natural gas] imports will still be needed to balance supply and demand,” it says. — DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • M ay 2010
53
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54
M AY 2 0 1 0 • O I L & G A S I N Q U I R E R
We’ll help make sense of the areas where energy, the economy, and the environment intersect.
Central Canada
Conference Board forecasts higher profits for the gas industry
Photo: Brian Zinchuk, Pipeline News
Feds penalize Chinese OCTG imports
Gas industry costs are expected to rise this year, but not as rapidly as natural gas revenues.
Higher average natural gas prices this year will more than offset falling production in Canada’s natural gas industry, according to the Conference Board of Canada. “Although prices have nearly doubled in less than six months, drilling activity remains sluggish as Canada continues to ride out the remaining effects of the recession,” says Todd Crawford, an economist with the Ottawa-based think tank. Natural gas prices are expected to average $5.44 per thousand cubic feet at AECO, up 36 per cent from last year’s low, but down from the 2008 average as high inventories continue to weigh on the effects of any growth in North American demand, says the board in its report, Canadian Industrial Outlook: Canada’s Gas Extraction Industry—Winter 2010. Prices will continue to rise throughout the forecast period to $9.30 per thousand cubic feet by 2014 due to a rising demand for a relatively clean and inexpensive source of fuel along with falling North American supply, which should help keep inventories in balance, the report predicts. After falling by nearly 65 per cent last year, profits in Canada’s gas extraction
industry are forecast to more than double to nearly $5.9 billion in 2010 as revenues rebound by more than 20 per cent. “Profits responded quickly to low prices in 2009, falling 65 per cent to $2.1 billion,” says the report. “The result would have been even worse were it not for the industry’s ability to curtail investment spending and cut costs in a timely manner.” While costs will also rise this year, they are not expected to expand as rapidly as revenues due to continued weak investment for at least one more year. Costs, though, will nearly double over the full forecast period, limiting the average annual growth in profits to under 10 per cent between 2010 and 2014. The Conference Board of Canada completed the forecast before the Alberta government released the outcome of its Competitiveness Review. Although changes to Alberta’s royalty framework are expected to have little effect on this year’s forecast, the reduction in royalties proposed by the government offers some upside potential to the forecast starting in 2011, says the board. — DAILY OIL BULLETIN
The dumping by China of subsidized well casing and tubing has harmed Canada’s domestic industry, Ottawa’s senior trade tribunal said on March 23. As a result, the Canadian International Trade Tribunal (CITT) said the Canada Border Services Agency (CBSA) will collect anti-dumping and countervailing duties on the goods. The exception will be pup-joints up to 12 feet long, which will not be affected by the finding. In February, the CBSA ruled that the oil country tubular goods (OCTG) in question had been dumped and subsidized, but it was up to the CITT to decide to what degree, if any, those actions had injured Canada’s domestic industry. As it turned out, while the CITT decided Canada’s domestic industry was injured by Chinese casing and tubing imports, it ruled that the industry was not harmed by the dumping and subsidizing of Chinese coupling stock, another class of OCTG. Last November, the CBSA began collecting preliminary duties on Chinese casing and tubing, on the grounds that it had earlier made a finding of dumping and subsidization of the goods in Canada by China. Duties will not be collected on imports of coupling stock from China. The most recent ruling affects casing and tubing with an outside diameter from 2 3/8 inches to 13 3/8 inches (60.3 to 339.7 millimetres), meeting American Petroleum Institute specification 5CT or equivalent, in all grades, but excluding drill pipe and seamless casing up to 11 3/4 inches (298.5 millimetres) outer diameter. The complainants in the case before the CITT were Canadian makers or importers of steel, including Evraz Inc. NA Canada of Regina; Lakeside Steel Corporation of Welland, Ontario; and Tenaris Canada (including Prudential Steel Inc., Tenaris Global Services (Canada) Inc., and Tenaris Algoma Tubes) of Calgary. O I L & G A S I N Q U I R E R • M ay 2010
55
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M AY 2 0 1 0 • O I L & G A S I N Q U I R E R
Stay Informed. Stay Connected.
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International
Xtreme Coil lands a Saudi contract but suffers a setback in Mexico
Photo: Xtreme Coil Drilling Corp.
BlackWatch announces foreign deal
Xtreme has 10 idle CT rigs in Mexico at least for now due to the operator’s budget constraints.
X t r e m e C oi l D r i l l i n g C or p. s a y s Christensen Saudi Arabia Limited, an affiliate of Baker Hughes Incorporated, has awarded the two-year contract to Xtreme (Luxembourg) S.A., a wholly owned subsidiary. The contract requires two fit-for-purpose drilling rigs to perform underbalanced coiled-tubing drilling on re-entry wells in the natural gas fields located in southern Saudi Arabia. The first of the two rigs under contract is expected to commence drilling early in the second quarter. The project involves re-entering existing wells and drilling horizontally into untapped reservoirs that are critical to overall reserves recovery. The target wells are deep and technically challenging, have multi-lateral well profiles, and require underbalanced drilling. Rod Uchytil, Xtreme Coil’s president and CEO, noted that his company customized its most recent drilling rig design, the XTC 200DTR(PLUS), specifically for the technical requirements and challenges presented by this project. The first XTC drilling rig arrived in Saudi Arabia in December 2009 and is preparing to move to the first location. Customization to the
second rig is in the final stages and it’s expected to begin operations toward the end of the second quarter. In mid-March, Xtreme also announced a collaboration with Suhayl Bin Abdul Mohsin A l Shoaibi & Sons Holding Company Limited. This business collaboration will promote and provide Xtreme contract drilling services and products in the Kingdom of Saudi Arabia and Algeria. On March 19, Xtreme said that it learned there is no remaining budget for contract work on the Chicontepec oil project in Mexico. As a result, the operator (Pemex) doesn’t expect to drill the total number of wells initially planned for the project. That information came from a customer, which Xtreme didn’t name but described as a “global integrated oilfield services company.” Xtreme’s Mexican subsidiary provided the services company with 10 drilling rigs for work on the project. It is now “evaluating how this situation might affect future rig activity to determine the appropriate next steps regarding operations in Mexico.” — DAILY OIL BULLETIN
BlackWatch Energy Services Corp. has announced an agreement to acquire two drilling rigs in its new Middle East and North Africa (MENA) region, along with an option to acquire up to an additional three drilling rigs in the region, a related acquisition facility, and the appointment of senior management personnel. The company has entered into an agreement to acquire two drilling rigs, related equipment, associated contracts, and operating infrastructure in Libya for a purchase price of US$21 million. The drilling rigs are 1,000-horsepower triples with a depth capacity of up to 4,000 metres, constructed in 2008. This agreement is subject to closing conditions typical for acquisitions of this type, including the transfer of drilling service contracts with the national oil company with a remaining term of two years. Management expects the Libyan acquisition will close in April and anticipates financing will be provided by an acquisition facility as well as incremental senior bank facility capacity. Libya had been targeted by management as a key market in the MENA region. The vendor of the assets operates the most significant oilfield well-service business in the region, aside from the large multinational service companies. “ T h i s m a rk s t he ne x t s te p i n BlackWatch’s corporate strategy to expand our geographic reach outside of North America,” said John King, the Calgarybased company’s president and CEO. “This is a unique opportunity for BlackWatch to initiate our business in the region and to leverage key relationships from our past.” BlackWatch has also executed a binding memorandum of understanding with the vendor of the Libyan assets to provide BlackWatch with an option to purchase up to three additional drilling rigs located in the MENA region. O I L & G A S I N Q U I R E R • M ay 2010
57
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M AY 2 0 1 0 • O I L & G A S I N Q U I R E R
onthe
JOB Careers in the Oilpatch
Graham Fletcher Age: 59 Title: President
Company: The Internet Centre Inc. Location: Edmonton
What do you do? In 1994, I launched the Internet Centre as Alberta’s first commercial Internet service. We’ve accomplished quite a lot, working with the Government of Alberta to roll out both Alberta Supernet connections and high-definition (HD) televideo conferencing for taxpayersponsored literacy and volunteer groups. For the first time, there’s now a truly affordable solution for HD video transmission over a standard Internet connection. With a large-screen monitor, you can see and hear in more detail than you’d experience in a regular meeting. The camera can easily and quickly pan onto a whiteboard, or right into the pupils of someone’s eyes. Also, you can simultaneously sync people and computers onto the same monitor. What significance does HD video conferencing have for the oilpatch? It’s a breakthrough technolog y for staff meetings and consulting of all kinds, for group training, for distance education courses, for certain types of medical emergencies, even for workers who want to enjoy close contact with their families. On screen, you see every facial expression, every gesture—you can sense everything but smell. The savings in travel time and expense often pay for the equipment very quickly. Because transmission is over the Internet, there is no per-minute charge for the actual calls.
In the past, video conferencing has been either expensive or low-definition—what’s the cost for HD technology now? A company that needs to handle multiple calls concurrently on one screen—for instance, a meeting that includes people from seven locations—will pay about $8,000 for a 50-inch flat screen monitor, an HD camera, and related equipment at each location. We’re now moving to 48 concurrent calls. A home model with fewer bells and whistles sells for well under $2,000, and it still provides full HD quality. I think we’ll see this gear for sale in the big electronics retail stores in a year or so. What are the limitations of this technology? People who live beyond fibre optic transmission networks still have fewer options. In remote areas, some oil companies are installing towers and radios that can handle high data transmission volumes. Today’s consumer-grade Internet radios still don’t have enough capacity for HD video conferencing. Also, a recent regulatory ruling means that Telus can legally deny access to its existing copper telephone lines. In more than 260 communities, that “unloaded copper” represents the only economical link between the customer’s home or of fice and the Alber ta Supernet [a fibre-optic net work that spans the province]. Amazingly, the federal ruling applies only to the four western provinces, not to Ontario and Quebec. Our company is asking the federal government to reverse this decision from Industry Canada. We’d like to provide affordable video conferencing services now that Telus doesn’t offer to smaller communities. O I L & G A S I N Q U I R E R • M ay 2010
59
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M AY 2 0 1 0 • O I L & G A S I N Q U I R E R
Tools of the Trade
TOOLS
OF THE TRADE A LOOK AT NEW TECHNOLOGIES
Departure Energy Services Who is Departure Energy Services Inc.? Departure is a customer-focused, mid-sized directional drilling and MWD [measurement-while-drilling] service provider working in western Canada, the northwestern United States, and the Middle East. The company is owned and operated by a group of highly experienced directional drilling, MWD professionals who are dedicated to introducing innovative technology to the industry. Departure owns all of its own directional drilling equipment, most of which is designed and manufactured in house by Departure Energy in Alberta. The company is headquartered in Leduc, Alta., with offices in Calgary, Casper, Wyoming, and Dubai. What is the G-Force TM Vertical Guidance Drilling System? G-Force is a vertical drilling system that utilizes a uniquely stabilized downhole motor and a conventional positive pulse MWD tool. The assembly is configured to simulate a rotary pendulum assembly. The tool will maintain the wellbore in a vertical attitude while rotating at any rate of penetration. If the well deviates for any reason—for example, excessive formation dip angles— the tool may be oriented to guide the well back to vertical. This system can be run with on-site supervision supplied by Departure or remotely operated.
What are the competitive advantages of this product? The G-Force system is designed to run on most any well in western Canada in a cost-effective manner. The tool drills extremely high-quality, full-gauge wellbore that is free of “high-frequency wellbore spiralling” commonly caused by rotating bent housing mud motors. The tool can be configured with any power section to harmonize bit/PDM combinations aimed at optimizing ROP [rate of penetration] performance for the intervals being drilled. The stabilized system significantly reduces wellbore tortuosity and improves performance and longevity of PDC bits. The tool eliminates “fanning” often required to maintain verticality and the resultant smooth wellbore improves trip times, hole cleaning, and log responses. Run cost for this tool is low compared to the closed-loop vertical drilling systems (that is, rotary steerable tools) available today. The lost-in-hole cost is also very low due to the fact the MWD tool can be configured to be retrievable. What are your future plans for the G-Force TM Vertical Guidance Drilling System? The system is presently available in 156 mm, 159 mm, 171 mm, 200 mm, 222 mm, and 311 mm. Departure Energy Services has built 20 G-Force Systems to date, and is in the process of launching the tool into the northwestern United States and the Middle East. The company expects to double the G-Force fleet size by the end of 2010. The system has just completed its 100th well in Canada. The newly manufactured 311 mm G-Force tool has generated considerable interest from operators in western Canada and the Middle East for deep vertical well applications, and the company expects to design and manufacture a 444 mm G-Force system before the end of the year, to be deployed to the Middle East.
Answered by Bruce Bond, sales and marketing manager of Departure Energy Services.
O I L & G A S I N Q U I R E R • M ay 2010
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Political Cartoon
Advertisers' Index 1174365 Alberta Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . 58 AGI-Envirotank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 All Weather Shelters Inc . . . . . . . . . . . . . . . . . . . . . . 33 Annugas Compression Consulting Ltd . . . . . . . . . . 25 BC Resources Expo . . . . . . . . . . . . . . . . . . . . . . . . . 49 Bear Slashing Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . . . 44 Bilton Welding and Manufacturing Ltd . . . . . . . . . 44 Brews Supply Ltd . . . . . . . . . . . . . . . . . . . . . . . 26 & 40 Brother’s Specialized Coating Systems Ltd . . . . . 54 Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . . . . . 11 CARES Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 CG Industrial Specialties Ltd. . . . . . . . . . . . . . . . . . 39 Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . . . . . 60 Contain Enviro Services Ltd . . . . . Inside Back Cover Continental Electric Motor Services Ltd . . . . . . . . 29 Crompton Western Canada Inc . . . . . . . . . . . . . . . . .17 DaimlerChrysler Canada Inc . . . . . Inside Front Cover Dean’s Pump Service Ltd . . . . . . . . . . . . . . . . . . . . . 44 DFI Corporation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
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M AY 2 0 1 0 • O I L & G A S I N Q U I R E R
Diversified Glycol Services Inc . . . . . . . . . . . . . . . . . 32 dmg world media . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Ecoquip Artificial Lift Ltd . . . . . . . . . . . . . . . . . . . . . 43 Falvo Electrical Supply Ltd . . . . . . . . . . . . . . . . . . . 43 Flexpipe Systems . . . . . . . . . . . . . . . . . . . . . . . . . 36-37 Gibson Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 Hex-Hut Shelter Systems Ltd . . . . . . . . . . . . . . . . . . 16 Joint Economic Development Initiative . . . . . . . . . . 15 Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . . . . 48 Kubota Canada Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 LJ Welding & Machine . . . . . . . . . . . . . . . . . . . . . . . . . 7 Lloydminster Heavy Oil Show . . . . . . . . . . . . . . . . . 34 LoTech Manufacturing Inc . . . . . . . . . . . . . . . . . . . . 43 Maxon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 MDI Industrial Sales Inc . . . . . . . . . . . . . . . . . . . . . . . 52 MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . . . 48 NAIT Corporate and International Training . . . . . . 52 Northstar Energy Services Inc . . . . . . . . . . . . . . . . . 4 OilPro Oilfield Production Equipment Ltd . . . . . . . 28 Oil Sands and Heavy Oil Technologies . . . . . . . . . . 30
Pembina Controls Inc . . . . . . . . . . . . . . . . . . . . . . . . . 52 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 PrintWest Communications . . . . . . . . . . . . . . . . . . 46 Production Control Services . . . . . . . . . . . . . . . . . . 19 Propak Systems Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Prostate Cancer Canada Network . . . . . . . . . . . . . 58 Pumps & Pressure Inc . . . . . . . . . . . . . . . . . . . . . . . . 23 RTS Services Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Suncor Energy Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Systech Instrumentation Inc . . . . . . . . . . . . . . . . . . 10 TARM Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Trans Peace Construction (1987) Ltd . . . . . . . . . . . . 22 Tundra Boiler & Instrumentation Ltd . . . . . . . . . . Outside Back Cover Vertigo Theatre Society . . . . . . . . . . . . . . . . . . . . . 60 World Energy Congress . . . . . . . . . . . . . . . . . . . . . . 58
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