September 2010 $6.00
In situ o ilsands projects g rowing provide volume a of much -needed work fo r servic e firms GoinG it alone Cenovus builds an in-house EPC team
Pat nelson Alberta’s image-cleaning lady
RestinG easieR Large or small, Canada’s flock of remote camp operators senses better times ahead
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Keeping readers regionally informed
F E A T U R E S
6
SEPTEMBER 2010 • OIL & GAS INQUIRER
12
Bitumen bonanza
16
Cenovus builds an in-house EPC team
18
Pat Nelson: Alberta’s image-cleaning lady
21
Resting easier
by Jim Bentein In situ oilsands projects provide a growing volume of much-needed work for service firms
by Jim Bentein
by Jim Bentein
by Nordahl Flakstad Large or small, Canada’s flock of remote camp operators senses better times ahead
Innovative Building Solutions Immediate & Cost Effective there is white here
R E G I O N A L
29
N E W S
British Columbia
51
• Peters surveys sand, water, production and costs at Horn River
US$3.25B
should come first
Northwestern Alberta • Government monitors odours after
• Total metres drilled in Q2 rise to nearly double the count in 2009
61
• Viking formation economics stack
• Two Alberta coal gasification projects
up well with other resource plays
Northeastern Alberta
players drive Bakken activity
69
• French multinational Total buys UTS
CO2 restrictions • Quebec has commercial oil prospect
• Total’s proposed Joslyn oilsands mine
Central Alberta
71
• Alberta government can feed new
MANUFACTURING
Eastern Canada • ExxonMobil files its development
• Lobby group urges more bitumen valueadded processing in Alberta
Central Canada • Canadian Senate report supports
Energy for $1.15B in cash faces opposition
ON-SITE BREAK ROOMS
• New technologies, prospects and
Cougar's controversial Australian project
43
Saskatchewan
complaints from Three Creeks area proceed despite alleged "hysteria" over
39
TRAINING FACILITIES
properties acquired from BP for
• Planning for B.C. gas plants
33
Southern Alberta • Apache expects to re-work
plan for the Hebron offshore project
73
International • Xtreme enters the Australian market
upgraders with its royalty bitumen
and redeploys its Mexican rigs
ADMINISTRATION
• Savanna updates Mexico operations
I N
10
E VE R Y
I S S U E
Statistics at a Glance
77
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Tools of the Trade
78
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Editor’s Note Vol. 22 No. 7 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com
Mike Byfield | mbyfield@junewarren-nickles.com
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This month’s cover feature looks at in situ oilsands operations. The sector is in good shape, both now and for the forseeable future. Steam assisted gravity drainage — a technology that originated entirely in Alberta — has provided us with a mighty economic pillar. For the future, new in situ methods are under development. The West’s well-being depends not only on applying technologies but also creating them. Years ago, while interviewing the president of a Texas-based junior producer, I mentioned that Americans had taught western Canadians the basics of oil and gas. Even earlier, they taught us how to raise cattle and dryland grain on the Great Plains. The oilman responded graciously that Alberta reminded him very much of his own state. I agreed but said there is one big difference. “What’s the difference?” asked the oilman, genuinely curious. I answered, “Nowadays, when it comes to producing oil, beef and grain, Albertans are better than Texans.” The resident of Fort Worth chuckled and commented, “Y’all really have learned a lot from Texas!” Teasing aside, Canadian oil and gas technology companies are better at engineering solutions than selling them. For a striking illustration of our strengths and limitations, look at Calgary’s Safety Boss and the Kuwaiti oil blowouts of 1991. During the first Gulf War, the retreating Iraqi army deliberately set hundreds of oil wells on fire. An Imax movie, the stunning “Fires of Kuwait,” featured Texans handling the largest non-military mobilization of men and materiel in history. The Canadian crews of Safety Boss had outperformed the Americans by a large margin, dousing and capping more wells than any other company. Even so, our achievements received no glory in that film, nor did Canada do anything else to publicize its superb contribution to averting an economic and environmental disaster. Despite the lack of blockbuster glitz, Safety Boss became one of the top four companies among the world’s wild well fighters on the strength of its competence in Kuwait. True, we could have had a much bigger promotional win, but it was still a victory. Perseverance pays. Even though we often have to start modestly, the Canadian oil and gas service sector must seize every marketing opportunity. In that spirit, JuneWarren-Nickle’s Energy Group has initiated an award called Technology Stars. For more details about this program, check out www.newtechnologystars.com, and take a look at the notice on page 76 of this issue. Then submit a nomination for your own Technology Star.
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Subscription Inquiries Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: junewarren–nickles.com 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
The next issue of Oil & Gas Inquirer will
If you know an admirable person to profile in
review Canada’s multi-billion-dollar pipeline
On The Job — he or she may be a veteran or
business, notably proposed bitumen lines in
apprentice, field or shop, wise or a little crazy —
British Columbia. We also look at the red tape
please give me a call at (780) 944-9333, or
that some oil and gas professionals believe is
email mbyfield@junewarren-nickles.com.
choking activity and jobs in Alberta.
In fact, feel free to sound off about any concern at all — that’s a personal invitation.
OIL & GAS INQUIRER • SEPTEMBER 2010
9
Stats
FAST NUMBERS
US
AT A GLANCE
$17
billion
US
BP’s reported loss for the second quarter of 2010, attributed to the British company’s oil blowout in the Gulf of Mexico on April 20.
$18
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
MONTH
OIL
GAS
OTHER
TOTAL
Aug 2009 Sept 2009 Oct 2009
101 146 132
212 155 160
80 78 77
Nov 2009 Dec 2009 Jan 2010
169 121 253
212 127 324
Feb 2010 Mar 2010 Apr 2010
144 264 198
May 2010 Jun 2010 Jul 2010
400 126 131
MONTH
OIL
GAS
DRY
SERVICE
TOTAL
393 379 369
Aug 2009 Sept 2009 Oct 2009
250 146 331
267 155 196
36 45 32
37 9 12
590 355 571
116 35 62
497 283 639
Nov 2009 Dec 2009 Jan 2010
382 283 429
244 138 343
68 34 55
10 13 13
704 468 840
308 579 418
114 198 6
566 1,041 622
Feb 2010 Mar 2010 Apr 2010
147 548 291
143 681 458
20 109 2
5 20 9
315 1,358 760
462 117 110
51 41 38
913 284 279
May 2010 Jun 2010 Jul 2010
490 295 193
511 153 9
39 40 16
19 16 4
1,059 504 222
Wells Drilled In British Columbia
Saskatchewan Completions
Source: B.C. Oil and Gas Commission
Source: Daily Oil Bulletin
MONTH
million
The reported termination payment (US$1.6 million) plus pension benefits of Tony Hayward, the BP CEO who has resigned over his handling of the Gulf of Mexico oil spill. Hayward spent 28 years with BP, including three years as its CEO.
WELLS D R I L L E D
CUMULATIVE *
Aug 2009 Sept 2009 Oct 2009
36 38 29
Nov 2009 Dec 2009 Jan 2010
MONTH
OIL
GAS
OTHER
TOTAL
465 503 532
Aug 2009 Sept 2009 Oct 2009
116 194 157
3 7 5
6 3 7
125 204 169
39 45 65
571 616 65
Nov 2009 Dec 2009 Jan 2010
171 139 153
11 11 18
10 9 6
192 159 177
Feb 2010 Mar 2010 Apr 2010
101 98 56
166 264 320
Feb 2010 Mar 2010 Apr 2010
169 223 92
58 32 10
4 8 3
231 263 105
May 2010 Jun 2010 Jul 2010
54 41 64
374 415 479
May 2010 Jun 2010 Jul 2010
86 149 220
7 7 7
3 11 0
96 167 227
*From year to date
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SEPTEMBER 2010 • OIL & GAS INQUIRER
SPECTACLE BLINDS *IN STOCk BLEED RINgS *IN STOCk PIg LAUNChERS/RECEIVERS wITh ‘A’ STAMP Y LATERAL *CRN REgISTERED ORIFICE PLATES
NEw 10 TON OVERhEAD CRANE 10,000 SQ. FT FABRICATION FACILITY
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GAS STOR AGE
Source: Natural Gas Exchange Inc.
Source: U.S. Energy Information Administration 3.25
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3.5
3.0
in the United States
3.00
2.75 Jul 19
Cdn$/GJ
Jul 26
Aug 2
Aug 9
3.01 Tcf Year ago: 3.2 Tcf 5-year avg: 2.82 Tcf
Aug 16
Jul 16
Tcf
Source: Natural Gas Exchange Inc.
Jul 23
Jul 30
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada August 17, 2010 Source: Rig Locator
Alberta July 2010 Source: Daily Oil Bulletin
ACTIVE
DOWN
TOTAL
ACTIVE (Per cent of total)
Western Canada Alberta
242
310
552
44%
British Columbia
48
53
101
48%
Manitoba
17
4
21
81%
Saskatchewan
75
53
128
59%
382
420
802
48%
0
1
1
0%
WC Totals Northwest Territories
Aug 6
OIL WELLS
Alberta
GAS WELLS
Jul 10
Jul 09
Jul 10
Jul 09
Northwestern Alberta
27
15
74
49
Northeastern Alberta
22
9
0
1
Central Alberta
59
44
12
21
Southern Alberta
23
12
15
119
TOTAL
131
80
101
169
Service Rig Count by Province/Territory
Drilling Activity: CBM & Bitumen
Western Canada July 13, 2010 Source: Rig Locator
Alberta June 2010 Source: Daily Oil Bulletin
ACTIVE
DOWN
TOTAL
ACTIVE
Western Canada Alberta
320
655
51%
British Columbia
16
14
30
53%
Manitoba
15
1
16
94%
Saskatchewan
127
65
192
66%
WC Totals
493
400
893
55%
0
2
2
0%
Quebec
COALBED METHANE
Alberta 335
Aug 13
Source: U.S. Energy Information Administration
BITUMEN WELLS
Jun 10
Jun 09
Jun 10
Jun 09
Northwestern Alberta
1
10
3
8
Northeastern Alberta
0
0
22
9
Central Alberta
0
6
9
21
Southern Alberta
3
26
0
0
TOTAL
4
42
34
38
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OIL & GAS INQUIRER • SEPTEMBER 2010
11
bonanza In situ oilsands projects provide a growing volume of much-needed work for service firms by Jim Bentein
W
ith natural gas prices looking weak for years to come, the petroleum service sector is looking to the oilsands. Larger operators like Precision Drilling Corp. and Nabors Canada Ltd. say in situ oilsands projects already represent 10–15 per cent of their total workload, and they expect that portion to increase as steam assisted gravity drainage (SAGD) projects ramp up. The In Situ Oil Sands Alliance (IOSA) refers to non-mining bitumen activity as “drillable oilsands” because producers rely on many of the same services that are used in the conventional sector. Don Herring, president of the Canadian Association of Oilwell Drilling Contractors (CAODC), says in situ appeals to drillers because it’s less seasonal than conventional activity. A steady workload makes it easier to retain workers. Herring, whose association represents 45 drilling contractors (their fleets total 804 rigs) and 72 service rig operators (1,079 rigs), says in situ development is also attractive due to its reliance on walking rigs. These mobile units drill multiple horizontal wellbores from a single pad, then move readily to the next pad. The CAODC hasn’t yet polled its members to find out how many are involved in the oilsands and what percentage of their business is concentrated there. “Clearly, it will become more important for our members,” Herring predicts. In situ oil work, along with horizontal shale gas wells completed with multi-stage fracs, is already generating black ink for Calfrac Well Services Ltd., Trican Well Service Ltd., Xtreme Coil Drilling Corp. and other service companies that specialize in directional drilling and pressure pumping. 12
SEPTEMBER 2010 • OIL & GAS INQUIRER
Last year, Precision Drilling was the most active land driller in North America. Kevin Neveu, its president and CEO, says the “factory-style rigs” used for heavy oil and in situ drilling are among the most economical units to build, costing about $10 million each. “Our performance with SAGD wells is well known to our customers,” Neveu comments. “[SAGD] is not seasonal and it’s long-term. It’s a consistent, repeatable business.” Precision owns 351 contract drilling rigs, including 202 in Canada, as well as 200 service rigs overall. In July, the company had 90 active rigs in Canada, with 20 drilling for in situ and heavy oil customers. Meanwhile, 30 rigs that are well-suited for shallow gas, have sat idle for two years and continue to do so. Gas prices below $5 per thousand cubic feet transformed 2009 into the worst year in a decade for Canada’s oil and gas service sector. Nabors Industries Ltd. is counting on oilsands and shale gas to help pull it out of a funk that saw the company post a loss of US$85.5 million in 2009, versus a profit of US$475 million in 2008. “Canada is financially our worst-performing unit, but still there are reasons for optimism,” says Gene Isenberg, Nabors chairman and CEO. The company uses programmable alternate current electrical rigs for oilsands drilling, which Bruce describes as state-of-the-art because of their mobility. They cost about $20 million each and can also be used in the shale gas plays. Joe Bruce, Canadian division president for Nabors, reports that 14 of its 85 rigs were working in British Columbia’s Horn River and Montney shale gas plays this winter. “We have two rigs contracted [in the oilsands] now, and we are going to be building two more fit-for-purpose rigs for that area in the next
This summer, Precision Drilling had 90 active rigs in Canada, with 20 rigs working on in situ and heavy oil projects. Photo: Cenovus Energy Inc.
year or two,” Bruce reports. “We’re bidding on quite a few projects now in the oilsands.” Akita Drilling Ltd. is also shifting its focus to heavy oil, in situ oil and shale gas. Karl Ruud, president and CEO of the Calgarybased firm, told its annual meeting in May that in situ pad drilling means rigs don’t have to rely on roads or favourable surface conditions to move from one wellsite to another. These rigs essentially run 300-plus days a year, and in many cases almost every day of the year,” Ruud says. “We’ve got a lot of equipment [in the in situ areas] and a lot of equipment means better margins.” Akita has five pad rigs working for in situ clients and a sixth unit is under construction. In addition, Ruud says other rigs were
“In the past, 70 per cent of the drilling in Alberta was gas-based.… This year, it will be 60 per cent oil-based and 40 per cent gas-based.” — Roger Soucy, Former President, Petroleum Services Association of Canada
drilling oilsands evaluation wells this past winter. “Energy giants are investing in this area,” he adds. “Barring abnormal environment [-related] or government interference, that’s going to serve Akita very well.” Flint Energy Services Ltd. focuses on bitumen producers in both the mining and drillable oilsands sectors. “While work and revenues in [the facility infrastructure division] will slow down in 2010
compared to the last few years, several new major oilsands projects have been sanctioned, which the company is targeting to add to its backlog for 2011 and 2012,” says Bill Lingard, Flint’s president and CEO. “With the announcement of resumption of work on Suncor Energy’s Firebag 3 project, the decision to proceed by ConocoPhillips on their Surmont SAGD project, and approval of Husky Energy Inc.’s Sunrise SAGD project, the next phases of oilsands production growth have been confirmed. As a result, the tendering of construction work by the company is being actively pursued at this time.” In 2009, Flint reported revenues of $1.88 billion, down by $438 million from the previous year. But its facility infrastructure segment actually saw a $7.1-million increase in revenue, to $592.5 million, thanks to continued work on Royal Dutch Shell’s Albian Sands project, at Suncor’s Firebag project and at projects being built by Statoil Canada Ltd. Flint also targets oilsands customers for its maintenance services segment, including a 50 per cent owned subsidiary called FT Services. This segment’s revenue for 2009 decreased by a modest 7.9 per cent during 2009 over 2008, to $280 million. The Calgarybased firm has 8,000 employees in North America. Its facility infrastructure division has chopped its payroll to about 2,000, down by about 1,000 workers since 2008. The maintenance services segment (including FT Services) currently employs 1,800. Few analysts expect conventional shallow gas activity to recover quickly, primarily because unconventional shale gas can be developed at lower cost. “In the past, 70 per cent of the drilling in Alberta was gas-based,” says Roger Soucy, the recentlyretired president of the Petroleum Services Association of Canada (PSAC). “This year, it will be 60 per cent oil-based and 40 per cent gas-based.” OIL & GAS INQUIRER • SEPTEMBER 2010
13
A full range of power and force measurement transducers, protection relays, needle and manifold valves, pressure switches, diaphragm seals and thermometers.
Mike Mazar, an oilfield services analyst with BMO Capital Markets, says a simple well count can be a misleading indicator by itself. “We may see half as many wells drilled this year as in 2008,” Mazar acknowledges. “But those wells take 40 per cent longer to drill [due to long-reach horizontal drilling and completions], so we may only be down 20 per cent [in total activity for 2010]. The companies that are involved in directional drilling and operate highspec, high-horsepower rigs are all very busy, as are the companies involved in the oilsands.” Photo: Cenovus Energy Inc.
Many gas-dependent juniors are in trouble. The Small Explorers and Producers Association of Canada (SEPAC) reports that it has lost 100 members over the last three years, from 450 down to 350. Contributing to that decline has been the credit crunch brought on by the recession. Even so, SEPAC executive director Gary Leach says the soft natural gas market has played the most destructive role among the Calgary-based association’s membership. “Low gas prices have accelerated a shift of the sector to other opportunities, such as shale gas, legacy oilfields and the oilsands,” he comments. In future, Leach forecasts, junior producers will have to be bigger and better-capitalized than in the past. A handful of SEPAC members are already involved in the oilsands sector. For instance, Connacher Oil and Gas Ltd. will be producing 17,000 barrels per day from SAGD wells later this year, and the company plans a major expansion beyond that. The sector is becoming more accessible to juniors thanks to the advent of new technologies and other factors that allow drillable oilsands prospects to be developed in a series of phases rather than as one massive project. Can the overall service sector recover fully through unconventional oil and gas work? Soucy counsels caution, noting that the Canadian industry has the equipment capacity to handle an annual well count of 25,000 to 30,000. PSAC recently raised its forecast for drilling activity for 2010 to 11,250 wells, an improvement from 8,350 in 2009. The association bases its estimate on an average West Texas Intermediate oil price of US$82 per barrel and gas at $4.25 per thousand cubic feet. Soucy suggests that 200 to 300 shallow gas-suited drilling rigs may remain permanently idle.
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14
SEPTEMBER 2010 • OIL & GAS INQUIRER
Photo: Cenovus Energy Inc.
Cenovus builds an in-house EPC team
Phased construction matches well with a continuous improvement strategy.
C
enovus Energy Inc. is providing its own engineering, procurement and construction (EPC) for four major oilsands projects in northeastern Alberta. It’s a different strategy — producers usually sign contracts with EPC specialists like Flint Energy Services Ltd. — but Cenovus has big plans. “We’re going from two projects now to six in the next couple of years,” says Rob Templeton, the Calgaryheadquartered company’s supply chain manager. “But we feel we can manage that growth with the same group we have now.” Cenovus was spun off last year by Encana Corp. as an oil-focused producer. The company operates steam assisted gravity drainage (SAGD) projects at Foster Creek, located north of Cold Lake, and at Christina Lake, near Lac La Biche. Expansions are underway for both projects. In addition, Cenovus plans new SAGD projects — Narrows Lake, north of Athabasca, and Grand Rapids, west of Fort McMurray. Altogether, this slate of work ranks as one of the most ambitious in the industry. In total, the projects are expected to take the company to 350,000 barrels per day of net production in the next decade. (It is partnered with ConocoPhillips in some of the projects.) By 2015, Cenovus would like to have government approval for projects that would expand its daily output to 500,000 barrels per day. Only one other company has managed construction of a major oilsands project with an in-house team: Canadian Natural Resources Ltd. took that approach with its Horizon oilsands mining project. “They’re the only ones that are doing it,” said Guy Cocquyt, a market analyst with Flint. “It takes a completely different skill set and a lot of investment and time. At the end of the day, most companies want to focus on producing bitumen and not on the construction side.” The EPC team at Cenovus currently includes 60 employees in Calgary and another 40 or so at Christina Lake and Foster Creek. “There have been very significant cost savings for the company,” says Templeton, although the extent of the saving has not been made public. The capital project schedule complements developing an in-house EPC capability. “We use a repetitive package approach,” the supply chain manager explains. “The phases are 30,000 barrels [per day] each, so we can utilize a cookie-cutter approach. By limiting the size, we can better manage the construction.” Also consistent with the cookie-cutter strategy is the fact that all of the projects utilize SAGD recovery, a technology whose ongoing evolution is well-understood by Cenovus. The supply chain group can also 16
SEPTEMBER 2010 • OIL & GAS INQUIRER
oversee construction of several phases at a time, which Templeton says will be necessary as the company ramps up its expansion. Cenovus has its own yard at Nisku, outside of Edmonton, where workers manufacture modules of key equipment. This approach, which is standard for the industry, reduces the number of high-cost employment in the field. The company also uses an open-shop approach to find workers, rather than working directly with trade unions. Templeton accepts that the company’s rapid expansion schedule “will test the management skills” of his group. He’s worked for 30 years in the energy industry, chiefly in the equipment procurement area. To date, the veteran manager says, “There have been no quality issues. For instance, we had to do zero re-drilling after we completed the last project [at Foster Creek, now producing about 100,000 barrels daily].” Independent analysts have praised the company’s performance of Foster Creek and Christina Lake. For instance, the CanOils oilsands service recently rated a number of in situ project operators. The most important factor in industry ratings of this type is the steam to oil ratio (SOR) required to extract the underground bitumen. In January, according to CanOils, Christina Lake had Alberta’s best SOR, producing one barrel of crude with just two barrels of steam. Foster Creek ranked second with an SOR of 2.4 to 1. By contrast, the Long Lake project operated by Nexen Inc. had an SOR of 5.2 to 1 and Tucker Lake, an operation of Husky Energy Inc., had an SOR of 7.7 to 1. Encana, Templeton's previous employer, also uses the supply chain management approach. At Cenovus, this department has
“There have been no quality issues. …[W]e had to do zero re-drilling after we completed the last project." — Rob Templeton, Supply Chain Manager, Cenovus Energy Inc.
both a project group and an operations group, with the latter scheduled to expand its staff as new phases come on stream. The company is guarded about what information it provides to other oilsands operators. “We want to keep our good secrets to ourselves,” Templeton says with a smile. The staged construction approach fits well with the Cenovus philosophy of “continuous improvement,” since changes can be implemented as new phases are reached. The company has a continuous improvement group of 12 employees. “We interact with them on a frequent basis,” Templeton says. Cenovus prefers having a number of oilfield service companies working on its sites, rather than one or two with a large number of employees. Templeton says that policy has yielded savings, but “the busier we get, the more we may have to alter that approach.” When construction peaks, he anticipates to have at least 1,000 contractor staff. In addition, Cenovus itself will grow. Its current staff of about 3,500 should increase to 5,500 by 2019.
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Photo: In Situ Oil Sands Alliance
Pat Nelson, vice-chair of the In Situ Oil Sands Alliance, is a former Alberta energy minister.
Alberta’s image-cleaning lady
L
ast year, to help promote trust in the oilsands industry across shouldn’t,” Nelson comments. “The future is on the in situ North America, six producers formed the In Situ Oil Sands side — there are 143,000 square kilometres of oilsands, and Alliance (IOSA). Its most aggressive public voice is its vice-chair only two per cent of that can be mined from the surface.” Pat Nelson (formerly known as Pat Black), who previously headed In situ production is close to surpassing mined bitumen output. In situ operators, according to provincial statistics, Alberta’s energy and finance ministries under former premier Ralph pumped more than 540,000 barrels per day in the first quarKlein. “Our members have 20 billion of reserves in total,” Nelson ter of this year, while volumes from mines dipped to about says. “They’re all working every day to reduce emissions and improve their environmental performance.” IOSA’s members are 576,000 barrels per day (from 639,600 barrels daily last year). The Canadian Association of Petroleum Producers forecasts Laricina Energy, Petrobank Energy and Resources Ltd., Osum Oil that oilsands production could Sands Corp, MEG Energy Group, total 3.5 million barrels daily by Athabasca Oil Sands Corp. and Connacher Oil and Gas Ltd. All 2025, with much of that growth either have in situ projects undercoming from in situ wells. way or have projects in the planIOSA emphasizes that its ning stages. But Nelson’s oilsands technologies do not require controversy-generating mine experience predates them all, beginning in the 1970s when the tailings ponds, nor do their drillformer Conservative MLA was ing pads disturb much of the still in her 20s. surface forest. Even so, Nelson is Her f irst senior job was quick to defend the mining operwith Great Canadian Oil Sands ations as well. “Whenever I see — Pat Nelson, Vice-Chair, In Situ Oil Sands Alliance Ltd., which was a subsidiary reports about the supposedly bad of Philadelphia-based Sun Oil environmental performance of Company at the time. The company built the first oilsands mine the industry, I want to ask critics, ‘Have you seen the buffalo?’” she near Fort McMurray, Alta., in 1967, producing 30,000 barsays. Buffalo now graze on land reclaimed by Syncrude Canada rels per day. “I was part of the management team that created Ltd. The oilsands mining sector has always included full reclamaSuncor Energy [which bought the Sun Oil assets in Canada],” tion of all lands and ponds in its long-term plans. says the former financial controller. “I was there when the Nelson sees oilsands development as Canada’s economic Mildred Lake mine was relatively new. It was a dream for me. ace. “I think it’s a dream come true, that it will be the economic The oilsands for me was the ninth wonder of the world.” IOSA driver of the country,” she comments. The Canadian Energy members use underground recovery technologies like steam Research Institute agrees. Last year, the Calgary-based think assisted gravity drainage, cyclic steam stimulation, toe to heel tank released a study that assesses new oilsands investment at air injection, combustion overhead gravity drainage (which $218 billion over the next 25 years. In that case, the net result includes air with the injected steam) and vapour extraction will be 465,000 jobs in Canada, $306 billion in federal and prov(where solvents are injected into reservoir in place of steam). incial government revenues, and $1.7 trillion in incremental “Canadians take this new technology for granted and they gross domestic product.
“Whenever I see reports about the supposedly bad environmental performance of the industry, I want to ask critics, ‘Have you seen the buffalo?’”
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SEPTEMBER 2010 • OIL & GAS INQUIRER
Danatec – celebrating 25 Years 1985 - 2010
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Danatec educational services is celebrating 25 years of providing quality workplace health and safety compliance solutions to clients across canada. Incorporated in 1985, Danatec is a family-run publishing and information delivery company focused on producing Occupational Health and Safety (OH&S) materials used by individuals, safety trainers, as well as by large companies to train staff internally. Headquartered in Calgary, with offices in every major city across the country, Danatec’s emphasis on family values has contributed to its enduring success. “We are very family-oriented,” says Danatec Vice President Alina Martin, daughter of Danatec’s President, Ronald J.E. Martin. “We’re fortunate to have a knowledgeable, hard-working team of employees, agents and distributors who know the business and care about our customers.” Danatec published its first books in 1985 under contract to Transport Canada. Over the years, the company has updated its Transportation of Dangerous Goods Instructor’s Manual and corresponding Transportation of Dangerous Goods (TDG) Handbooks several times, setting the mark for dangerous goods publications across Canada. Danatec’s TDG Self-Teach training program is its No. 1 bestseller, and in the past several years the company has won many prestigious awards for its publications, training materials and online solutions, which cover a wide range of workplace safety topics. Danatec produces more than 25 products, and it is also the longest-standing company in Canada doing online OH&S training. This year, the Calgary firm broke $1 million in revenues in its e-learning business, “which is astronomical,” Alina Martin says. “The growth curve has been enormous.” Danatec’s primary product lines are its awardwinning publications and training materials in the areas of TDG and Workplace Hazardous Materials Information System (WHMIS), which feature self-teach training materials, instructor packages, handbooks, regulations, posters and videos. Danatec’s TDG online
training program won the Hermes Platinum Award last year, and its WHMIS program has won 12 awards in the past three years. Recently, Danatec has also begun to sell other materials, such as placards, labels and additional DVDs. It is also expanding its product line with several new innovative products. This fall, it is launching its first application for the iPhone and iPad. The new Danatec TDG Handbook app, available on iTunes, is the first of its kind in the industry. It’s a convenient way to access a summary of the material covered in Danatec’s award-winning TDG training programs. Also new this fall is DanatecTV, which is a platform for electronic video delivery that allows users to view all of Danatec’s safety training videos on the Internet using just a username and password. Danatec is offering DanatecTV in a live streaming format that an instructor can easily show on a laptop in a classroom setting. DanatecTV runs on an annual subscription, giving users the ability to choose the videos they want to view. Also new this fall from Danatec is a first-of-its-kind online training program for TDG: Class 7 Radioactive Training. Danatec is proud of its unequalled reputation for reliability, practicality and quality in everything the company does. “My father gave Danatec its foundation; I will give it its future,” Martin says. “We are in a perfect position to grow. We are adding new product lines and experiencing true growth outside our traditional product lines. We are changing, because the industry is changing. We are heavy on technology, because that’s the way the industry is pushing us.”
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Photo: PTI Group Inc.
Big camps like PTI’s Athabasca Lodge serve for years, then move without leaving behind a ghost town.
Resting easier Large or small, Canada’s flock of remote camp operators senses better times ahead
by Nordahl Flakstad
C
anada’s fur-trading voyageurs slept under their big birchbark canoes, the first form of mobile shelter for paid workers along Canada’s frontiers. Later, to accommodate roughnecks, miners and loggers in the early period of resource development, bunkhouses, cookhouses and privies were skidded or barged to farf lung worksites. Today’s remote housing is incomparably more luxurious, and it's still highly mobile. Complete with satellite TV and Internet access, recreation and fitness centres, and private washrooms — sometimes even a driving
range and fast food outlet — contemporary camps must act as recruiting tools to help attract workers. Many remote camps can hardly be described as “temporary.” In fact, some stay in place for years; they only move once a major project is completed or when the resource that prompted their arrival is depleted. Other smaller camp configurations — say, rig camps — are likely to be moved more frequently. Mobile camps, whether big or small, may depart from a resource site without leaving behind the ghostly imprint of an abandoned singleindustry town.
Companies involved with remote camp operations follow various business models. Some supply-inclusive packages covering accommodation, catering, water/sanitation services, camp management and related logistics. Others offer just some services. Sometimes companies that deliver other services, say oil and gas completion, decide to diversify by adding mobile worksite divisions. In other instances, a firm that began with catering might branch out to include housing and related camp services. Atco Ltd. has a long association with worksite accommodation. Thanks to O I L & G A S I N Q U I R E R • S eptember EPTEMBER 2010
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Photo: Peak Energy Services Trust
It may not be home, but a modern camp bedroom is clean, efficient and online.
ASL also stands ready to meet more modest requests, as it did in June by announcing it will build a 50-person work camp for Eni Petroleum Co. on Alaska’s North Slope. This follows ASL’s completion last fall of a 78-person camp for the Pogo gold mine, southeast of Fairbanks, Alaska. ASL’s reach extends beyond resources developments, including furnishing logistical support to the military in Canada and other countries. The company has mobile structure manufacturing facilities in North America, South America, Australia and the Middle East. Other companies also are making their mark in the camp market. Take Calgary’s Black Diamond Group Limited, whose largest camp — located near Encana’s Christina Lake, Canadian Natural Resources Limited’s
Photo: Peak Energy Services Trust
Atco’s diversification, the Atco name now may bring to mind gas and electricity. But, Atco traces its origins and name to Alberta Trailer Company and the trailer rental and sales firm founded by the Southern family more than six decades ago. Through Atco Structures & Logistics (ASL), the Atco Group remains very much a leading Canadian and international supplier of workforce housing, modular facilities, catering services, construction site support services, including related logistics operations management. For instance, a few years back, when Shell was building its Athabasca Oil Sands Project Upstream Expansion No. 1, north of Fort McMurray, Alta., it turned to Atco to supply and install Albian Village, designed to accommodate 2,460. Covering 115,000 square feet, it features a gymnasium, running track, workout facility, lounge, lecture hall, dining area and elevated corridors.
Peak Energy’s camp service is turnkey, from set-up through operation to take-apart, for up to 600 workers. 22
SEPTEMBER 2010 • OIL & GAS INQUIRER
(CNRL’s) Kirby Lake and Devon Energy’s ’s Jackfish operations in the Fort McMurray area — has 1,000 beds. Elsewhere, Black Diamond houses from 500 to 1,000 at camps in northern Alberta, northeastern British Columbia, southeastern Saskatchewan and Alaska. In total, Black Diamond camps have more than 6,000 beds. With a workforce of 250 to 300 in its camp management and logistics division, Black Diamond does not directly provide catering but will oversee the contracting of food services. (Black Diamond’s Boxx Modular division provides temporary mobile structures that tend to be moved more frequently to provide work and storage space.) ESS Canada is a div ision of the Compass Group, the world’s largest catering and support group. In Canada, ESS accommodates 10,500 residents in remote
PTI Group Inc. bills itself as one of North America’s largest fully integrated suppliers of remote site services. With 15,000-plus beds, it offers more accommodation than Canada’s largest regular hotelier.
camps at 75 locations. Most facilities are long-term, but some of its camps run on a more seasonal or transient nature. In business for over 30 years, PTI Group Inc. bills itself as one of North America’s largest fully integrated suppliers of remote site services. With 15,000plus beds, it offers more accommodation than Canada’s largest regular hotelier, and depending on the season employs from has anywhere from 2,500 to 3,000. About half of PTI’s beds are located through smaller, leased out facilities (rig camps and dormitories) with space for 25 to 500. The remaining beds are in PTI’s 22 owned and operated “open camps” (described in more detail elsewhere in this article). Beyond North America, PTI serves clients in the Middle East, Asia, South America and Europe — the Edmontonbased firm has even supplied waste water services as far away as the Antarctic.
K e n M ac L ea n , P T I ’s m a rket i ng director, explains: “While most of our competitors provide only the facility or only the catering services, PTI provides our customers with a fully integrated offering. PTI provides facility design, engineering, modular manufacturing, site construction, and installation. Once in place, we also operate the facilities with catering, housekeeping, laundry services and facility maintenance. We also provide all site services including power generation, communications, and water and waste water treatment.” Besides delivering a full range of drilling, completions and productionrelated ser vices, Peak Energy Services, a Calgary-headquartered trust, also runs a camp and catering division. Like PTI, it accommodates field crews, including full-ser vice on-site catering, housekeeping, water supply and waste management. It particularly delivers these services to the oil and gas sector from Manitoba, west to British Columbia and into the North west Territories.
Peak Energy camps can accommodate from 6 to 600 workers. (At present, the largest one houses 280.) The company can supply a full turnkey service consisting of set-up, take-apart and onsite management. The accommodation mix includes single- and double-occupancy drill-style camps, single occupancy drill camps and dorm-style layouts configured to
activity. As a result, subject to ebbs and flows in drilling, total staff within its camp and catering division ranges from 80 to 380. Mitch McLeod, a senior account manager with the camp and catering division, believes that being part of a larger group results in synergies and that the drillingrelated services provides an advantage in marketing and market awareness. For example, Peak Energy’s other divisions
Results of a 2009 survey by the Oil Sands Developers Group indicated a total of 22,728 workers were staying at 78 camps, lodges and motels, mostly north of Fort McMurray. meet customer needs. It also rents out complete complexes that include recreation halls and fully outfitted workout centres, along with power generation, water storage and patented wastewater treatment systems capable of serving from 6 to 2,500 people. Accommodating drilling crews represent a sizable portion of Peak Energy’s
already have service centres in Wyoming and near shale gas activity in Pennsylvania, both of which McLeod considers potential markets for camps. Like several other operators, Peak Energy does not build its own units but will install specific features, such as fitness or special kitchen equipment to meet customers’ needs.
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SEPTEMBER 2010 • OIL & GAS INQUIRER
Photo: Atco Structures & Logistics
Atco and PTI Group are industry heavyweights, constructing, setting up and operating remote camps.
In recent years, the Fort McMurray area has accounted for an important percentage of overall Canadian work-camp occupancy. Results of a 2009 survey by the Oil Sands Developers Group indicated a total of 22,728 workers were staying at 78 camps, lodges and motels, mostly north of Fort McMurray (a number that would be somewhat higher than the total just for mobile camps). It compares with 27,752
in mid-2008, when CNRL’s upgrader and bitumen mine were under construction north of Fort MacKay, Alta. That survey also occurred before the 2008 economic crisis and the subsequent halting or postponement of numerous oilsands projects. (Comparable figures for 2010 were not available at the time of writing.) Cutbacks in conventional oil and gas drilling also depressed remote-camp
utilization. This summer’s increase in activity is swinging the pendulum back for camp operators. So much so that Peak Energy’s McLeod foresees a possible return to pre-slowdown utilization levels by early 2011. However, he cautions that while that upswing may mean more bodies in bunks, it won’t necessarily translate in to revenue increases as petroleum producers cope with lower prices, particularly for gas.
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OIL & GAS INQUIRER • SEPTEMBER 2010
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“Indications are that utilization rates are returning to where they were two or three years ago. But there’s going to be lots of price pressure, with rates comparable to what they were as far back as 2003,” suggests McLeod. Black Diamond president and CEO Trevor Haynes shares an optimistic outlook on utilization rates and observes, “There continues to be a strong demand for camp accommodation. The only trend that we are seeing to date is the lack of equipment availability, particularly in the regions of the oilsands development and deep shale basins.” Erin Meehan, president of ESS Canada, sees “an increasing demand for camp accommodation. We are adding capacity across Canada in partnership with our clients. It is too early in the recovery for real trends to emerge, but the overall market is showing favourable conditions.” In the past, work camps often would serve one project or a single company. Those staying at the camp usually worked for either the contracting company or its subcontractors. Increasingly, however, operators are moving toward “open camps,” which are run much more like remote, temporary hotels. At a given time, workers from
various employers may stay at the camp — for shorter or longer periods — while working on a project in that vicinity. For example, in the Fort McMurray area, Black Diamond’s Sunday Creek Lodge near Conklin is an open facility. Open camps also are popular in northeastern British Columbia, where drilling on shale gas plays tend to take place in a restricted time period and can entail a succession of different drilling contractors. Such open camps or temporary hotels especially make sense if travel distances to permanent accommodation in regional communities are lengthy and the longerterm economics don’t justify setting up permanent hotels close to field operations. Earlier this year, to serve workers involved with shale gas in the Horn River Basin, PTI added the PTI Geetla Lodge, a 52–single occupancy facility northeast of Fort Nelson, British Columbia. PTI has also moved into the Bakken tight oil play by opening of the 98-room lodge 14 kilometres north of Waskada, Man. Also applying the open-camp concept is the recently announced 202-room Atco Lodge in Estevan, Sask., a full-service camp
where, besides accommodation, guests also receive three meals a day. Mobility has definite advantages in a shifting market like the oilpatch. “All of our open-camp facilities are modular and can be relocated as demand for service fluctuates in a region over time,” says PTI’s MacLean. “This gives us the ability to be nimble and locate our properties where our customers need us most.” A further emerging trend has seen mobile-accommodation providers team up with First Nations. Noting that it already has 35 aboriginal business partnerships in Canada, ESS’s Meehan describes these joint ventures as “very much part of our business model and certainly our preferred method.” Meanwhile, Black Diamond has established an exclusive partnership with the Fort Nelson First Nation in northeastern British Columbia. CEO Haynes comments, “We will continue to explore joint ventures with other First Nations groups where there are beneficial two-way relat ionship oppor t unit ies for our company and the communities in which we operate.”
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SEPTEMBER 2010 • OIL & GAS INQUIRER
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Peters surveys sand, water, production and costs at Horn River
Photo: Trinidad Drilling Ltd.
by Richard Macedo
Peters & Co. estimates that Horn River production could reach five billion cubic feet per day by 2020.
Issues regarding access to equipment and sand and water supply could become constraints for development in the Horn River Basin, given the remoteness of the activity and large fracturing job requirements, suggests a report by Peters & Co. Limited. Production potential from on the emerging shale gas play is estimated as high as five billion cubic feet per day by 2020. That figure is on an estimate of roughly 290 wells drilled annually over a 10-year period, developing roughly 24 trillion cubic feet of natural gas resource. These wells would need 7.1 fracturing crews and hydraulic horsepower (HHP) of 282,240, which would take up 24 per cent of the Western Canadian Sedimentary Basin (WCSB) fracturing capacity. In a higher case scenario of 400 wells, 10.1 fracturing rig crews would be required and 403,200 HHP or 35 per cent of the fracturing capacity in the WCSB.
At 150 wells — the low-case scenario in the report — 3.8 crews would be needed for an HHP of 151,200 or 13 per cent of the capacity. “Ultimately, we believe that the pressure pumpers will continue to build equipment if they are able to secure long-term
well can be as high as 180,000 cubic metres, according to Peters. “To put this in perspective, an Olympic-sized swimming pool contains 2,500 cubic metres of water, so the drilling of 100 Horn River wells annually potentially requires 7,200 Olympic-sized swimming pools. Obviously, these consumption levels of fresh water are not sustainable.” The report said that to source water, operators are drilling water source wells into the Debolt formation, reducing surface water usage. But Debolt formation water is sour and must be treated before being pumped. Additionally, the Debolt is not prevalent in all areas of the Horn River Basin, which will result in some operators having permanently higher cost structures due to the cost of transporting water. “It is also worthwhile noting that for fracture stimulations, water needs to be heated, which, during the winter, presents an enormous cost to operators,” the report said. “Therefore, we expect that the trend towards summer fracturing programs will continue.” In terms of sand, the base case Horn River well assumes 12 fracture stimulations per well with some of the more active operators increasing the number of stimulated intervals to 20 per well.
“… [F]or fracture stimulations [in winter], water needs to be heated… [at] enormous cost to operators. Therefore, we expect that the trend towards summer fracturing programs will continue." — Peters & Co. report
commitments with...producers in the area, thereby alleviating the potential horsepower constraints as operators attempt to secure equipment for steady programs,” the report states. The volume of fresh water consumed in fracture stimulating one Horn River
With each stage requiring roughly 200 tonnes of sand, volumes are substantial with about 2,400 tonnes required per well (12 stages) or roughly 4,000 tonnes per well (20 stages). One of the prime factors driving the competitive metrics of the Horn River
JUL/09
JUL/10
JUL/09
JUL/10
WELLS SPUDDED
34
46
WELLS DRILLED
26
58
BRITISH COLUMBIA WELL ACTIVITY
JUL/09
JUL/10
WELL LICENCES
34
48
▲
▲
▲
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • SEPTEMBER 2010
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British Columbia Basin is the province’s net profit royalty. This reduces the break-even costs in the basin to US$4.86 per thousand cubic feet, down from US$6.11 per thousand cubic feet. Various studies have indicated a potential gas in place of between 400 trillion cubic feet and 700 trillion cubic feet for the “Horn River package” in the Horn River Basin and Cordova Embayment, with recoverable estimates ranging from 105 trillion to 240 trillion cubic feet. These estimates would make it the third-largest accumulation in North America following the Marcellus and the Haynesville shales. The Peters & Co. report noted that advances in drilling and completion practices have helped improve the economics of Horn River development. The estimated risked rate of return is 20 per cent using $5.50 per thousand cubic feet NYMEX pricing, which is in line with the median of 22 per cent for other unconventional natural gas plays in North America. To date, industry has largely been focused on t he Musk wa- Ot ter Park formation, which on its own provides robust rates of return. Recent activity has some operators testing the Klua/ Evie formation, which could result in
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SEPTEMBER 2010 • OIL & GAS INQUIRER
an increase in the overall recoverable resource estimates. Apache Corporation drilled the first vertical well into the Horn River in 2005 and since then, there have been a total of 137 horizontal wells drilled and 56 vertical wells drilled and completed in the basin. There are also an additional 92 and 25 horizontal and vertical licences in the basin that remain undrilled. “[Through] technological improvements and adopting concepts from other areas, other operators, service providers and optimizing our approach, we’ve decreased our costs to about $550,000 per frac interval and are completing as many as 22 stages per well,” says Randy Eresman, president and CEO of Encana Corp. “The next evolution of our pad design is...based on 20 wells from a single pad location and completing up to 26 fracs per well.” An increasing number of fracture stimulation events per well can have a positive impact on rates of return, especially if economies of scale can be realized. At US$5.50 per thousand cubic feet, the rate of return increases from 20 per cent to 35 per cent if the number of fracture stimulations per wellbore is successfully increased
to 20 stages from the standard assumption of 12 stages per well, the report says. Based on current assumptions, fracturing costs currently account for 50 per cent of total well costs and are expected to remain one of the largest cost components for operators in the basin. The primary reason for these significant costs is that the availability of equipment that is capable of performing these types of jobs is limited, according to Peters. Overall, the most active operators at Horn River have been Encana, Apache and EOG Resources Inc. which have drilled 37, 36 and 35 horizontal wells, respectively, followed by Nexen Inc. which has drilled 17 horizontal wells. About 230 wells were drilled over the past five years with $1.9 billion spent on land acquisitions in the area over the past three years. Based on the risked 10-year capital forecast, the capital spending per year would be roughly $3.6 billion totalling roughly $36 billion over the 10-year period for 2,900 wells. This estimate excludes additional spending requirements on land, seismic, infrastructure and facilities, which would have a material impact on overall expenditure levels. — DAILY OIL BULLETIN
British Columbia
Planning for B.C. gas plants should come first Midstream executives speaking in Calgary agreed that successful development of shale and tight gas plays in northeastern British Columbia requires careful planning for the area’s natural gas processing needs. “The challenge for industry is to develop the processing infrastructure in a manner that facilitates...efficiency,” David Smith, executive VP at Keyera Facilities Income Fund told TD Newcrest’s Unconventional Oil & Gas Forum on July 15. “Our hope...is that producers will build facilities to be scalable, as Aux Sable Canada and Crew Energy Inc. have done, because ultimately, you want the most efficient network for the long term, not just for the next few years,” Smith said. “Generally, that means larger facilities and larger gathering systems.” Ideally, planning for northeastern British Columbia would avoid the situation in Alberta, where about 725 gas processing plants are currently working at roughly 50 per cent utilization rates, Smith said. The total number of plants is down, reflecting consolidation in recent years. Cooperation among midstream companies like Keyera, AltaGas Income Trust and Spectra Energy Midstream alone won’t solve the problem, since oil and gas producers are in charge of how their gasprocessing needs are met. “The producers are the ones that drive the boat,” Smith said. “They’re developing the resource and determining whether processing facilities are built by them or third parties. It’s really the producers that make those decisions. My only hope is that when they [do], they take a long-term view in terms of the design of those facilities and the development plan.” Ot hers on t he con ference’s gasprocessing panel addressed the pace of
development of gas-processing plants. Stephen White, president and CEO of Fort Chicago Energy Partners, noted that consolidation of gas plants tends to occur in older fields, not new ones like British Columbia’s Horn River Basin. “It’s based on the age of the field. If you’re dealing in an older area where production has peaked, it’s only natural that you see consolidation, but in new areas, exactly the opposite is going to happen. You’ll see smaller plants gets built, and over time, they’ll be expanded into bigger plants,” he said.
“The challenge for industry is to make sure that competition doesn’t lead to over-investment in underutilized facilities.” — David Smith, Executive VP, Keyera Facilities Income Fund
On a practical level, he said northeastern B.C. producers that are still pursuing Montney or Horn River Basin exploration programs are not going to commit to building plants that produce 200 million or 300 million cubic feet per day, since they have little sense of firm production volumes over time. Processing capacity also concerns pipeline carriers, like TransCanada
read more online at energizealberta.com Where energy, the economy, and the environment intersect.
Corporation, which will deliver the gas to end-use markets. “In the shale plays, we’ve seen producers coming along with wells with initial production of 10 million cubic feet per day or more. It doesn’t take many of those to fill up a small plant,” noted Dave Murray, manager of the company’s Commercial Supply West division. He reported seeing more large-scale gas plants proposed recently for shale basins than in the past. Others speaking at a recent session noted that some producers have a policy of wanting to own and operate their own processing plants, allowing scope for future expansion unrestricted by partners. Yet, not all producers want to be married to a gas plant. “I think you’ll see different strategies,” said Smith. “Producers like Encana Corporation are more comfortable with third-party sourcing to facilities infrastructure. Talisman Energy Inc. likes to control [it] themselves. That kind of tension is a good thing, like competition. The challenge for industry is to make sure that competition doesn’t lead to over- investment in underutilized facilities.” In the interests of efficiency, Smith called for the design of plants for the long term, which will often mean building fewer large-scale facilities with larger capture areas. Despite high decline rates in many shale plays, he said gas plant development plans can be arranged so that new wells brought on supplement declining production from older wells. “If you have a longterm program, I think it can be managed in a way that keeps the [processing] infrastructure reasonably full, well-utilized and efficient. But it means planning and it means a longer-term view.” — DAILY OIL BULLETIn
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31
The Geldart Group
Northwestern Alberta/Foothills
Government monitors odours after complaints from Three Creeks area
Although regulators say smelly emissions did not reach danger thresholds, producers have cut venting.
A government report has found that Alberta air quality objectives were not exceeded after odour complaints from residents in the Three Creeks area near Peace River, Alta. Even so, steps to reduce fugitive emissions will continue, as will air quality monitoring. The report traced the stink to an unfortunate mixture of odourous compounds. Hydrocarbon-type odour complaints from the Three Creeks area were received by the Energy Resources Conservation Board (ERCB) and Alberta Environment. Odours were noted when the wind speed was low, according to results of a study conducted earlier this year. “Before this study was done, about 56 per cent of the produced gas was being vented in the area,” said Randall Barrett, a regional env ironmental manager. “Industries have agreed to implement processes…to capture all but two per cent
of that gas. When we return in October of this year, we want to collect samples and just see [if] we’re seeing differences from this reduction [in] the background and community and at the source sites.” The study showed that concentrations detected for samples taken during odour events were substantially higher than concentrations detected at background sites. One hour average total volatile organic compound, or VOC, (excluding methane) concentrations from samples collected during odour events ranged from 41 to 521 parts per billion. In contrast, at the background sites, this concentration ranged from 2 to 13 parts per billion. Concentrations for individual VOCs were compared to known odour thresholds. The odour threshold for hexanol (green grassy odour) was exceeded twice and the threshold for nonanal (rosy citrus smell) was exceeded once. The report said that odour
was also perceived during the collection of community samples where threshold values were not exceeded. Odour threshold resulting from a mixture of compounds can be lower than the threshold for individual compounds. Light hydrocarbons were found to contribute the most to concentrations detected in the collected samples. VOCs containing sulphur are typically associated with strong odours from upstream oil and gas operations. However, these compounds were not detected in any of the samples collected, nor were the established Alberta Ambient Air Quality Objectives exceeded for any substance. VOCs commonly found within the community samples were also found at most of the potential industrial emission sites. Although a direct link between source and community samples could not be made, “given the distribution and proximity of the sample sites, meteorological conditions and analysis results, community samples were likely impacted by emissions from oil and gas emission production,” the report said. “Air quality objectives are what we put as the line of safe air quality,” said Barrett. “[But] we consider quality of life also a health impact. So, the idea that people are having trouble sleeping or are waking up with headaches from the fumes that they’re smelling is a health concern for us.” Mov ing for ward, t he ERCB and Alberta Environment will be doing an overall odour management plan. Further monitoring and inspections will also be conducted. “Alberta Environment is also setting up a stationary air monitoring unit,” Barrett said. “We’re also going to be returning in October to collect more air samples in the same way we’ve done for the study we presented for the February to May samples.” — DAILY OIL BULLETIN
NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY
JUL/09
JUL/10
WELL LICENCES
130
210
▲
JUL/08
JUL/09
WELLS SPUDDED
90
170
▲
JUL/08
JUL/09
WELLS DRILLED
72
144
▲
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • SEPTEMBER 2010
33
Northwestern Alberta/Foothills
Two Alberta coal gasification projects proceed despite alleged "hysteria" over Cougar's controversial Australian project The CEO of a Calgary-based company that is slated to receive $285 million from the Alberta government to develop a deep coal gasification project says problems an Australian company has run into with a similar project, where an alleged underground water contamination caused the government to shut down a pilot project, will not be repeated with its $1-billion plant. “We’ve been waiting for people to ask us this question [about whether the planned Swan Hills Synfuels project faces a similar potential],” said CEO Martin Lambert. “We are developing a very, very different project.” The Australian underground coal gasification (UCG) pilot project, located about 220 kilometres northwest of Brisbane, was shut down on July 16 and a government employee with Queensland’s Department of Environment and Resource Management (DERM) was suspended for not reporting earlier on underground water contamination problems with the plant.
DERM ordered the project developer, Cougar Energy Ltd., to shut down the plant after toxic chemicals were found in drinking water from bores near the plant site. It said it learned there were traces of the cancer-causing chemical benzene and the toxic chemical toluene found in bores near the site. The UGC technology Cougar is using was developed by a Canadian company, Montreal-based Ergo Exergy Technologies Inc., with whom Cougar has a licensing agreement. The pilot project was to be the beginning phase of the planned 400 megawatt Kingaroy Power Station. In addition, the company is planning to develop a second UGC project in Queensland and another, along with a partner, in the Victoria, Australia area. Ergo Exergy’s technology has also been licensed by Houston-based Laurus Energ y Inc., which, like Swan Hills Synfuels, is proposing an Alberta project (in the Drayton Valley area) to use in situ
coal gasification to produce synthetic gas (syngas) which would be sold to a power plant owner. Carbon dioxide (CO2 ) captured from both projects would be sold for enhanced oil recovery (EOR). Two other developers of proposed commercial in situ coal projects in Australia, Linc Energy and Carbon Energy, which also operate pilot projects in the state, met in July with Stephen Robertson, the state’s Minister of Natural Resources, Mines and Energy and were told the incident at the Cougar site raises concerns about the whole sector. “I indicated…that the government remained committed to undertaking a formal environmental evaluation of the Underground Coal Gasification process at each site in Queensland, and our independent scientific expert panel will be undertaking a complete review of all trials,” Robertson said. B ot h t he pr op o se d Sw a n H i l l s Synfuels project and the Laurus project
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Northwestern Alberta/Foothills are being reviewed by Alberta regulatory officials. The Laurus project, a phased project that the company says would eventually be large enough to fuel a 300 megawatt power plant, has not received any government funding. The Alberta government announced last December that it had signed a letter of intent with Swan Hills Synfuels to provide funding for the proposed Swan Hills project. It was one of four projects that received
A se n ior of f ic i a l w it h A lb e r t a Innovates, who was involved in a review of the Swan Hills Synfuels technology but who did not want his name to be used, said he’s “absolutely confident” the company’s technology presents no danger of groundwater contamination or other serious environmental problems. The company plans to develop the commercial-sized Sagitawah Power Project starting in 2012. The plant, which would
“The media has crucified the government for mismanagement of environmental issues and that has created a hysterical situation.” — Dr. Michael Blinderman, CEO, Ergo Exergy Technologies Inc.
funding commitments from its $2-billion Carbon Capture and Storage Fund. The company developed a demonstration project of its in situ gasification process, based on a technolog y developed at the California-based Lawrence Livermore National Laboratory in the 1960s and 1970s. That $9-million project, still operating, was funded by the former Alberta Energy Research Institute (now Alberta Innovates).
be in service by 2015, would operate for 40 years and produce more than 17 million gigajoules of syngas annually. The key components of the project are the in situ gasification facility, associated pipelines and a syngas processing plant, similar to a conventional natural gas processing plant, and a power plant, to be located near Whitecourt, Alta., which would tap the syngas. In addition, the company would capture CO2 and it would be transported by
pipeline to oilfields in the Swan Hills area for use in EOR projects. It is estimated that the project would capture 1.3 million tonnes of CO2 emissions a year and could help replace other energy sources with high emissions. Lambert, the CEO of Swan Hills Sy nfuels, said he was aware of the Kingaroy plant shutdown in Australia but isn’t concerned about it affecting prospects for his company’s plant development. “Our project operates at such depths that we are isolated from groundwater contaminants,” said Lambert, a former CEO of Calgarybased international law firm Bennett Jones LLP. He said the high pressure used in its process is also a factor, as are other aspects of its process. “We’re looking at a project that gasifies coal at a depth of 1,400 metres,” he said. “The majority of UGC projects in the world operate at depths of 100–400 metres, where groundwater contamination is an issue.” He said t he K ingaroy project in Australia is operating at 300 metres, while other UGC projects in Queensland operate at 600 to 700 metres. Lambert said the advancement of horizontal
OIL & GAS INQUIRER • SEPTEMBER 2010
35
Northwestern Alberta/Foothills drilling technology in the oil and gas industry makes the Swan Hills project possible. “We couldn’t have done this 10 or 12 years ago,” he said. “What has made it possible are the horizontal drilling advances.” Simon Maev, senior VP in charge of project development for Laurus Energy, the other company proposing an in situ coal project in Alberta, along with one in Alaska and several in Texas, said the independent firm that tested underground water samples at the Kingaroy site in Australia made a mistake and the government will have to withdraw its objections. “It ’s virtually impossible for contaminants to enter the groundwater [with the Ergo Exergy process],” said Maev. “They [the carcinogen and other toxic chemicals] could have been in the soil.” He said drilling for the project is deep enough so that the wellbores won’t intersect with underground aquifers. Also, the technology is designed to eliminate the threat. “The process is conducted in such a way that gasification pressure in the gasifier is always slightly less than the hydrostatic pressure of fluid in the coal seam and surrounding strata. This creates a pressure gradient directed towards the gasifier,” he said. “As a result, no flow from the gasifier into the surroundings is allowed, thereby preventing the loss of valuable product gas
and averting contamination of the underground environment.” Dr. Michael Blinderman, CEO of Ergo Exergy, after he returned from an emergency trip to Australia, blamed the Cougar plant shutdown on “hysterical media coverage” and state politicians who overreacted to initial water sampling tests that were incorrect. “The media has crucified the government for mismanagement of environmental issues and that has created a hysterical situation,” he told the Daily Oil Bulletin. Blinderman said the independent lab that had reported the abnormally high levels of benzene and toluene issued a subsequent letter on July 17 admitting it had erred and amounts of both were negligible. “There was no contamination, zero,” he said. However, by then it was too late, since the issue had been raised in the state legislature by a member of parliament known to be opposed to the coal gasification projects. Meanwhile, the Cougar project has been suspended since April, when the larger readings of the chemicals was first reported “so they haven’t been doing anything that would create contamination.” Blinderman said Cougar, which now faces serious financial problems and has had its shares suspended from trading on the Australian stock exchange, has appealed to the government to lift its ban on operating the project. “My understanding is the government doesn’t know what to do,” he said.
“They created the problem themselves. Now the company [Cougar] faces uncertainty and is in dire straits and there is a cloud over the whole underground coal gasification industry.” Laurus CEO Rebecca McDonald said the company still believes in the Ergo Exergy technology and is planning to go ahead with its Tomahawk project in Alberta and with other in situ coal projects, calling the Australian incident “much ado about nothing.” She said the company has selected a site and is waiting for government approval of a demonstration project. “We have two billion tonnes of coal at our site in Alberta,” she said. Laurus hopes to team up with a power plant developer. Aside from the Australian projects, there are other in situ coal gasification projects underway, including a pilot plant in South Africa that is using Ergo Exergy’s technology. Lambert said it’s vital for underground coal gasification technology to be developed, since it would unlock vast hydrocarbon reserves. “The Alberta Geological Survey has estimated there is 600 billion tonnes of coal in the Mannville zone alone [which covers about one-quarter of Alberta],” he said. “The energy in the Mannville is more than two times all of the energy in the oilsands.” — DAILY OIL BULLETIN
Pembina Pipeline will proceed with its Nipisi and Mitsue projects Project construction is expected to proceed immediately on t wo Pembina Pipeline Corporation crude oil and condensate pipeline projects to serve heavy oil producers in north-central Alberta. Pembina has received Energy Resources Conservation Board approval to build and operate the projects, which are estimated to cost a combined total of $440 million. The Nipisi Pipeline will run from the Nipisi Terminal, north of Slave Lake, to Pembina’s Judy Creek pump station, south of Swan Hills. From there, the new system will connect to an existing Pembina pipeline to deliver product to the Edmonton area. The pipeline is expected to require approximately 190 kilometres of new construction. The pipeline is designed so that it can ultimately be expanded to approximately 200,000 barrels per day. 36
SEPTEMBER 2010 • OIL & GAS INQUIRER
The Mitsue Pipeline will transport condensate from Whitecourt to producers operating north of Slave Lake. The pipeline is designed to accommodate an ultimate expansion to 45,000 barrels per day. The Mitsue Pipeline is expected to require approx imately 135 k i lo metres of new pipeline and the use of approximately 120 kilometres of existing pipelines. The regulatory approvals were granted without a hearing, as all stakeholder objections were resolved through the consultation process. Both projects, which rely on a combination of new and existing pipe, are scheduled to be placed into service in mid-2011. Pembina has executed long-term transportation services agreements, which will govern operations on the Nipisi and Mitsue Pipelines once they have been completed.
Fou nd i ng c u stomer s, Ca nad ia n Natural Resources Ltd. and Cenovus Energy Inc. have, subject to certain conditions, contracted 80 per cent of the Nipisi Pipeline’s initial capacity of 100,000 barrels per day and 50 per cent of the 20,000-barrel-per-day capacity on the Mitsue Pipeline. Pembina Marketing Ltd., a subsidiary of Pembina Pipeline Corporation, has contracted for the balance of available capacity. Piping fabrication for the pump stations commenced in July and the pump station construction was expected to begin in August. Right-of-way clearing is anticipated to begin in September in preparation for pipeline construction, which is planned to start in early December. Approximately 800 to 1,000 temporary positions are expected to be created during construction. — DAILY OIL BULLETIN
Northwestern Alberta/Foothills
NuVista Energy Ltd. has reported successful production testing of its first Wapiti Montney horizontal well. The well was drilled at 9-22-68-8W6 in the first quarter of 2010 and was completed in late June with multi-stage water-based fracture stimulations over 11 intervals. The final test rate for the well, over an eight-hour period, was 10 million cubic feet per day of burnable formation gas at a 1,100-poundsper-square-inch wellhead with flowing pressures increasing during the test. The well was also producing approximately 250 barrels per day of free condensate. Analysis of the gas stream suggests the formation gas is also liquids-rich, bringing total anticipated liquid yields from the well to approximately 50 barrels per million cubic feet (including the free condensate). The tie-in of this well is currently underway. The hydrogen sulphide concentration in the gas stream during the production test was 4.5 per cent. A second Montney horizontal well at 13-33-65-6W6 commenced drilling in early July. This well is located approximately 20 miles away from the first well and is designed to establish productive capability on the company’s second contiguous Montney acreage position to the south. NuVista has a total of 167 gross sections on the Montney trend in its Wapiti operating area with an average working interest of 94 per cent and each of its northern and southern Montney land blocks contain 60–70 contiguous sections of prospective lands. Based upon the success of the first Wapiti Montney horizontal well, the producer said it expects to begin drilling two additional delineation horizontal wells on the northern Montney block in late 2010. The extended production tests and the results of the delineation horizontal wells will then be used to begin planning for a NuVista operated sour gas processing facility scheduled to be on stream prior to the end of 2012. NuVista recently drilled its first operated Cardium horizontal well in Wapiti and has initiated drilling of its second operated Cardium horizontal well. — DAILY OIL BULLETIN
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Northeastern Alberta
French multinational Total buys UTS Energy for $1.15B in cash
Photo: Joey Podlubny
by Lynda Harrison
Total, with stakes in four oilsands projects, is becoming a well-known name across oilsands country.
Total E&P Canada Ltd., a subsidiary of Paris-headquartered Total SA, will pay a cash amount of $1.15 billion to acquire UTS Energy Corporation along with its principal asset, a 20 per cent interest in the Fort Hills oilsands mine. With its remaining assets, UTS is transforming itself into a new company, SilverBirch Energy Corporation. Parallel to this transaction, Total is considering divesting some of its interest in the proposed Joslyn mine, while retaining its role as operator, with the objective of an approximately 50 per cent stake. It currently owns 75 per cent of the project. Based in France, Total will now have an interest in the Fort Hills mining project, the Joslyn mine project, a 50 per cent ownership in the Surmont SAGD project where Phase 2 is scheduled for start-up in 2015, and a 50 per cent interest in the Northern Lights project
f ol low i n g it s 2 0 0 8 ac qu i s it ion of Synenco Energy Inc. Total attempted a hostile takeover of UTS last year and relations were always professional and cordial but the price wasn’t right, said Will Roach, UTS president and CEO on July 7. “The idea was great and we understood that,” he added. This time, UTS’s board of directors has unanimously approved the Total offer, which works out to about 65 cents per barrel of bitumen in place. The Fort Hills project is operated by Suncor Energy Inc. with a 60 per cent interest, the remaining 20 per cent held by Teck. Fort Hills has an estimated 3.4 billion barrels of bitumen. An open-pit mining project will be developed in two phases. The first phase of approximately 160,000 barrels per day has already obtained the necessary administrative approvals to launch the development in the near future with a
target production start-up, as expected by Total, in 2015-2016. “Yet again, I think that we’ve…reset the clock with a proven team to hopefully recreate the success we’ve enjoyed in UTS,” Roach said. SilverBirch, whose assets will include a 50 per cent interest, along with Teck Resources Ltd., in both the Frontier and Equinox oilsands mining projects, will be seeded with around $50 million, he said. A pre-feasibility study (design basis memorandum) is on schedule for completion by year-end 2010. Roach said a regulatory application combining both projects, is to be ready for submission in the first quarter of 2011. “This is a relatively low-capital intensive exercise, taking you to the point where the project is a shovel-ready project and as we’ve shown with Fort Hills, you can create a lot of value by taking projects through to that stage,” said Roach. Approval is anticipated in 2014, to be followed by four years of engineering, procurement and construction, and start-up, with production of 80,000 barrels per day in 2018 rising eventually to 290,000 barrels per day at full production. Last year, UTS purchased a new 100 per cent-owned lease, a new discovery in leases 418/271, where it has conducted geophysical testing this year and it plans to drill about 50 holes in the first quarter of 2011. The company estimates it has between 10 and 15 prospective sections on the land. “We’re not sure whether this is going to be a shallow in situ or a deep mine,” said Roach. “That’s one of the things that has to be determined by drilling. We think there is probably an overburden of around plus or minus 100 metres on these lands and we’re pretty optimistic there’s oilsands there. Our challenge will be to get the right recovery mechanism.” — DAILY OIL BULLETIN
NORTHEASTERN ALBERTA WELL ACTIVITY
JUL/09
JUL/10
WELL LICENCES
33
80
▲
JUL/09
JUL/10
WELLS SPUDDED
41
91
▲
JUL/09
JUL/10
WELLS DRILLED
46
94
▲
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • SEPTEMBER 2010
39
Northeastern Alberta
Total’s proposed Joslyn oilsands mine faces opposition A joint review panel (JRP) will review Total E&P Joslyn Ltd.’s application for a proposed oilsands mine at a public hearing in Fort McMurray, Alta., starting Sept. 21 and running through Oct. 8. The Regional Municipality of Wood Buffalo (RMWB is the local government) has indicated it intends to oppose the project at the hearing. The municipal council said it “cannot support any additional approvals until significant steps have been taken to implement a comprehensive framework for the fair and responsible development of the oilsands region.” In its comments to the panel secretariat submitted in May, the RMWB said it believes the project is not in the public’s interest at this time and requested the application be denied. The hearing is to provide individuals and organizations with the opportunity to learn more about the project and its consequences and for them to provide their views to the panel. An additional third week of proceedings will likely be held in Edmonton.
The JRP for the Joslyn North Mine project is an independent body, mandated by the minister of the environment and the chairman of the Alberta Energy Resources Conservation Board (ERCB) to assess the environmental effects of the proposed project and review the application. Total E&P Joslyn, a subsidiary of Total E&P Canada Ltd., is the operator of the Joslyn lease, with a 75 per cent participating interest. The application seeks to construct an open pit, truck and shovel mine; two trains of froth production and treatment; a cogeneration plant; one external tailings location; and other related infrastructure to support the operation (water intake, water pipeline, water storage construction and operations of camps and roads). The proposed project site is about 70 kilometres north of Fort McMurray on oi lsa nds leases 7280 060T24, 7404110452 and 7405070799. Designed to produce 100,000 barrels per day of bitumen, the project, if approved, could
begin construction in 2011-2012, with mining expected to occur from 2017 to 2037. In addition to that of the RMWB, submissions have also been received from organizations such as its neighbour, Canadian Natural Resources Limited (CNRL); the non-status and status First Nations living in the area; the Sierra Club of Canada, Oil Sands Environmental Coalition; Health Canada; Environment Canada; the Department of Fisheries and Oceans, Natural Resources Canada; Pa rk s Ca nada; A lber ta Sustainable Resource Development; and A lberta Health and Wellness. The RMWB submission says the project would pose risks to air quality due to emissions and resulting harm to human and wildlife health, potentially low water flows in the Athabasca River and pressures on municipal infrastructure, among other concerns. It said economic growth has placed tremendous strain upon infrastructure and the provision of services to residents, and while it fully
! n o k n u o y can ba Savings
40
SEPTEMBER 2010 • OIL & GAS INQUIRER
Northeastern Alberta
Alberta Health and Wellness recommends the joint review panel requests an enhanced risk assessment of the potential health impacts from the project on those living at the worker camp.
supports responsible development, such development should not and cannot be at the expense of long-term residents of the region. Alberta Health and Wellness recommends the JRP requests an enhanced risk assessment and evaluation of the potential health impacts from the project on those living at the worker camp which has been expanded to 4,000 workers from 2,000 workers. The Joslyn project also proposes an upgrader to be built in three phases. Phase 1 of the Total upgrader is anticipated to produce 150,000 barrels of light sweet synthetic crude oil. Phase 2 should increase total bitumen processing capacit y to over 245,000 barrels per day and the final phase, Phase 3, will take production to 295,000 barrels per day. The upgrader’s front-end engineering and design phase were completed at the end of 2009; regulatory approvals are anticipated in 2010. When Total submitted its application to the ERCB in December 2007, the estimated cost of the upgrader was between $7 billion and
$9 billion, with about two-thirds allocated to the first phase. T he mine’s tailings management plan includes multiple treatment processes for managing fluid fine tailings within the extraction process, combined with return f luid and pond management techniques aimed at reducing fluid storage requirements during operation while increasing fine tailings deposit strengths by exposing treated fine tailings beaches. Proponents said the tailings plan has numerous beneficial features including minimal fluid fine tailings inventories during life of mine operation, an in-plant thickener for hot water re-use and recovery, and increased flexibility to vary fines treatment processes to manage operation realities. The company had been expected to make a final investment decision on the Joslyn North mine this year but deferred a decision in the face of escalating costs. JeanMichel Gires, Total Canada’s president, has said the decision will now likely come by the end of 2011 after the project clears regulatory hurdles. — DAILY OIL BULLETIN
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41
Central Alberta
Lobby group urges more bitumen value-added processing in Alberta
Photo: Joey Podlubny
by Elsie Ross
A new lobbying alliance says Calgary as well as Edmonton will lose many jobs due to bitumen exports.
Alberta’s Industrial Heartland Association (IHA), along with supporters from the petrochemical industry, local municipal ities and employee groups, has launched a campaign to build support for more valueadded oilsands products. The first step is encouraging more upgrading in the province, said Don Rigney, mayor of Sturgeon County and chair of IHA. “The time to act is now,” Rigney said. “All this is about skilled, full-time, long-term jobs, pensions and benefits. That’s what will build us to the future, and we are losing that.” A new website — refineitwherewe mineit.ca — provides information on how value-added is important to Albertans. Exports of raw bitumen are far outstripping the increase in the upgrading by almost 10 to 1, Rigney said. “We’ve seen exports of close to a million barrels [per day] of raw bitumen announced with ver y little, if any, upgrading,”
the campaign chair said, adding that Alberta currently refines the lowest percentage of its oil production of any jurisdiction in North America. There also is concern in the petrochemical industry in Alberta about a shortage of natural gas liquids for feedstock, according to Rigney. With increased
Resources Conservation Board forecasts that by 2019 only 50 per cent of total bitumen production will be upgraded locally, down from 60.6 per cent in 2009. “It is a significant loss,” said Rigney. If the oilsands create $25 billion annually in GDP [gross domestic product], then upgrading to synthetic crude oil can create a further $25 billion, while further processing to petrochemical feedstock could add yet another $25 billion, he said. The IHA comprises the largest petroleum and petrochemical-refining complex in Canada with municipalities including Edmonton, Fort Saskatchewan and the counties of Sturgeon, Strathcona and Lamont. The group has allied itself with people who have been working on Royal Dutch Shell’s Scotford upgrader expansion. “As it winds down, they are laying off 7,000 very skilled workers who have been working on these upgraders for years in various phases from Shell and Syncrude Canada Ltd.,” Rigney said. While a number of upgraders were once proposed in the Edmonton area, companies have pulled back in the face of unattractive economics. At present, the only upgrader on the horizon is North West Upgrading’s proposed 150,000-barrel-perday project, which would be built in three stages in the Industrial Heartland.
While a number of upgraders were once proposed in the Edmonton area, companies have pulled back in the face of unattractive economics. upgrading capacity, the next step could be further processing to produce petro chemical feedstock. Although the Alberta government’s stated goal is to ensure that two-thirds of oilsands production is upgraded in Alberta, in its latest report, the Energy
The impact of the cancellation of upgrading projects isn’t limited to northern Alberta, according to Rigney. “All the engin eering, all the design work, all the highend stuff, thousands of hours, comes out of Calgary and Calgary risks losing becoming a world centre of excellence for this,” he said.
JUL/09
JUL/10
JUL/09
JUL/10
WELLS SPUDDED
117
219
WELLS DRILLED
112
204
CENTRAL ALBERTA WELL ACTIVITY
JUL/09
JUL/10
WELL LICENCES
152
272
▲
▲
▲
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • SEPTEMBER 2010
43
Central Alberta For Richard Wassill, chair of the Building Trades of Alberta executive board, though, the campaign is about more than upgrading bitumen. “It is about getting people back to work, diversifying the economy by adding value to the province’s natural resources, eliminating the boom and bust cycles associated with an economy that relies on the export of its raw commodities and maintaining Alberta’s commun ities and quality of life,” he said. Upgrading two-thirds of Alberta’s bitumen at home will create thousands of jobs, added Stephen Kushner, president of the Merit Contractors Association. “That’s why we need to renew our commitment to the value-added supply chain policy to attract the investment before it’s too late.” — DAILY OIL BULLETIN
Alberta Sulphur Terminals nears final approval for new sulphur plant Sulphur producers in northern Alberta could have a processing facility nearby as early as next year if Alberta Sulphur Terminals (AST) receives the remaining approvals for a proposed $30-m illion sulphur-f or m i ng pla nt i n A lber ta’s Industrial Heartland near Bruderheim. “We’re just completing all the conditions from our approval from the Natural Resources Conservation Board [NRCB] and once that’s done we’re negotiating with the County of Lamont a development agreement,” said Robert Mann, director of sulphur services for the proponent, Hazco Environmental Services. The first application was filed in 2005, but the facility has faced public opposition ever since. Most recently, Lamont County opposed the project in 2008. A year ago, the NRCB asked AST to detail how it would minimize and manage potential impacts in addition to its commitments to address safety, community impact and environmental mitigation. AST was also required to revise its emergency-response plan to the satis faction of the NRCB before construction commences. 44
SEPTEMBER 2010 • OIL & GAS INQUIRER
Central Alberta AST has submitted all the required information. Once final approvals are received, all that remains is to finalize contracts with customers and construction can start, said Mann, adding that he could not provide an exact date. He said the company has agreed on an operating approval in draft form from Alberta Environment. The facility will potentially provide ser vice for oil and gas production and refining operations from Fort Saskatchewan, For t McMur ray and Lloydminster, taking the by-product of oil and gas upgrading and refining, and processing it into high-quality sulphur pastilles for export. Producers have committed an adequate supply of feedstock for the new facility. It’s scheduled to manufacture 3,000 tonnes per day of sulphur pastilles, with short-term, on-site storage. The unapproved Phase 2 is based on 6,000 tonnes per day “sometime maybe in the future,” Mann said in Calgary. The facility is designed to store 45,000 tonnes in Phase 1 while Phase 2 is designed to store 90,000 tonnes. The plant will have rail capacity for 120-car trains, which don’t currently exist, but AST anticipates they will in the future, he said. The proposed site is serviced by Canadian Pacific and Canadian National railways as well as major highways. “For the sulphur industry, being logistically challenged as we are in Alberta, that has a huge impact on the project itself,” Mann told the
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PennWell Corporation conference on oilsands heavy oil technologies in late July. Sulphur producers are receiv ing positive netbacks and, though the prices have f luctuated, market for sulphur is “still fairly strong,” Mann said. “We don’t market sulphur; we’re just collecting it, forming it and shipping it out to Vancouver. We’re just a service provider.” He estimated Hazco has spent about $6 million on the project to date, including the land purchase. — DAILY OIL BULLETIN OIL & GAS INQUIRER • SEPTEMBER 2010
45
Central Alberta
Alberta government can feed new upgraders with its royalty bitumen Alberta Energy Minister Ron Liepert says the provincial cabinet has given the okay for detailed talks about supplying royalty bitumen to a proposed multi-billion-dollar bitumen upgrader planned by North West Upgrading Inc. A contract could be signed before the end of the year. “We have agreed on a term sheet, and it has been approved, so now we will proceed with negotiations,” Liepert said. “This bodes well for the future of the project.” The provincial government intends to use its royalty-in-kind bitumen to encourage value-added upgrading in Alberta. By the end of the decade, the government could have up to 400,000 barrels of bitumen per day. Liepert said the North West project could act as a template for future upgraders. “There are a couple of others that might be interested in a similar arrangement,” he said. In his view, the key is the province’s Bitumen Royalty In Kind (BRIK) program, which gives the government the option of
receiving future royalties from producers in dollars or in bitumen with the same value. “If you project it out, we will reach a point where by 2020 the province could be handling 300,000 to 400,000 barrels a day of bitumen,” Liepert said. “If you think about that, it means there could be 10 similar projects [to the North West one] just to handle the BRIK production.”
enormous economic engine no different than the birth of the petrochemical industry in Alberta,” he said. The project would create 8,000 peak construction jobs and hundreds of permanent high-value jobs. MacGregor said the BRIK program will eventually mean the provincial government will have “an enormous quantity of bitumen that has to be processed”
The injection of CO2 into older reservoirs could lead to the recovery of hundreds of millions of barrels of oil. Ian MacGregor, chairman of Calgarybased North West, said the provincial government stands to generate billions of dollars in taxes and royalties as a result of the project, and he believes it paves the way for other similar projects. “It’s an
with oilsands projects that have reached payout status eventually having to contribute as much as 25 per cent of their volumes. The taxpayers of Alberta have much more to gain by encouraging the de velopment of integrated upgrading-CO 2
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SEPTEMBER 2010 • OIL & GAS INQUIRER
Central Alberta extraction projects than by seeing the bitumen shipped outside of the province, according to North West. The injection of CO 2 into older reservoirs could lead to the recovery of hundreds of millions of barrels of oil, which could lead to the province collecting more in royalties. In addition, North West will pay millions of dollars in taxes, as will its employees. MacGregor said skeptics who question whether the standalone upgrader is viable and who argue that it makes more economic sense to ship bitumen south to the United States for upgrading and refining miss a key point concerning the province’s strategy as a royalty bitumen producer. “Every large [commercial] bitumen producer is integrated,” he noted. “Some producers have done it through partnerships with companies that have refining capacity already and some have built their own facilities [in Alberta]. But, the point is, no large bitumen producer can afford not to be integrated.” I n a d d i t i o n , t h e N o r t h We s t upgrader/refinery is being engineered to generate and capture CO 2 of the high purity and low cost needed for enhanced
oil recovery (EOR). MacGregor argued that EOR oil production could yield billions in additional revenue for Albertans. North West would be the first standalone bitumen upgrader built in Alberta. It would also be a refinery, producing diesel, butane and other by-products. Existing oilsands mining projects such as Syncrude Canada Ltd.’s Fort McMurray–area plant, Suncor Energy Inc.’s plant and Royal Dutch Shell Plc’s Athabasca Oil Sands Project all include an upgrading component. However, the recent trend has been towards producers developing bitumenonly projects, partly because of the high cost of building upgraders in Alberta and partly because of narrow price differentials between light and heavier oils, which weaken upgrading profits. The North West upgrader would proceed in three phases, eventually processing as much as 150,000 barrels per day. Engineering work on the first 50,000-barrelper-day phase has already begun and should be completed by later this year or early 2011. The capital costs to build the project are about five per cent higher than for a conventional upgrader refinery, said MacGregor.
However, operating costs for the project would be lower and it could generate more revenue, thanks to sales of CO2 , diesel and other value-added products. North West is partnered on a 50-50 basis with Canadian Natural Resources Ltd., which has committed to send about 25,000 barrels daily to the upgrader. But a key source of future supply would come from the provincial government’s BRIK program. North West has said it isn’t seeking government funding for the project, but needs to secure a source of bitumen from the BRIK program. “If we can secure a long-term contract with the province to handle a portion of its BRIK bitumen, the company could complete its financing arrangements and proceed with construction immediately,” MacGregor said. North West has already purchased about $300 million worth of equipment and materials for the upgrader, he said, adding that he believes it will be ready to choose a contractor for the project by the end of the year. — DAILY OIL BULLETIN
Duvernay shale appears to drive massive Alberta Crown land sale Alberta collected $452.2 million from a land sale on July 7 in what appears to be a rush to grab land prospective for Duvernay shale gas. After anemic land sale revenues in 2009, the provincial government has already surpassed its originally projected land sale amount for its entire 2010–11 fiscal year, which ends in March 2011. The government had expected land sale revenue to reach $630 million for
2010–11, but with the latest sale, the figure has already hit $835.7 million so far in the fiscal year, which began on April 1. “There are many factors [for the high bonus],” said Bob McManus, a government spokesman, when asked if the recent royalty changes had any affect. “Commodity prices, economic conditions, royalty regime, resource availability and land access...impact a company’s decision to participate in a land sale.”
The Duvernay has been a source of increasing producer interest. According to an analysis of the land sale posting by Canadian Discovery Ltd., Fox Creek represented approximately 28 per cent of the land rights posted for the July 7 sale. The position of the lands within the West Shale Basin and the rights posted indicated the sale was focused on the Duvernay shale gas play. “It’s our belief it was posted for the Duvernay,” said Neil Watson,
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Central Alberta consulting services director with Canadian Discovery. “They [the parcels] are well situated for development of a play in the Duvernay. If you look at the rights that were posted, the one common denominator is that the Duvernay rights are included. There are other zones, obviously, but...when you zero in and look at the rocks themselves, it def initely appears to be a Duvernay posting.” The July auction sold 210,563 hectares (ha) at an average price of $2,147/ha. This pushed the province’s year-to-date total revenue to just under $1.3 billion on 1.61 million ha, an average of $796.72/ha. It’s a sign that producer confidence is rebounding in the province since natural gas prices remain weak. To this point last year, $119.7 million had rolled into government coffers on 816,287 ha for an average price of only $146.68/ha. The sale featured seven licences that combined for a total bonus of $336.7 million. Scott Land & Lease Ltd. tendered the bonus high of $63.6 million for an 8,192 ha licence parcel. The broker paid an average of $7,765/ha for several sections at 62-18W5 and 62-19W5. Gregg Scott, president of Scott Land & Lease, said the company invested
$326 million or 72 per cent of the entire $452-million sale between its four land sale companies, Scott Land, Canadian Coastal Resources Ltd., Plunkett Resources Ltd. and Windfall Resources Ltd. “I think the royalty changes are a contributing factor, no question,” Scott said. “Lower royalties equate to higher land sale bonuses, and at the rate we are going in Alberta this year, land sale revenues and revenues generated by related
61-24W5, 62-23W5, 62-24W5, 63-23W5 and 63-24W5. Windfall Resources produced the perhectare high of $10,315, paying $42.3 million for a 4,096 ha licence at 61-19W5 and 61-20W5. Windfall was also a successful picking up an 8,192 ha licence for $63.55 million. The parcel, which drew an average of $7,757/ha, included several sections at 61-21W5, 61-22W5, 62-21W5 and 62-22W5.
The sale featured seven licences that combined for a total bonus of $336.7 million. field activities could easily offset any reduction in royalties. There is growing confidence that companies can earn a fair rate of return in Alberta. A lot of land expired over the last two years, so I believe we will see some pretty active land sales going forward.” Canadian Coastal plunked dow n $63.51 million at an average of $7,753/ ha for a n 8,192 ha l icence, wh ic h included several sections at 61-23W5,
Daily Oil Bullet in records show Daylight Energy Ltd. rig released a horizontal well targeting gas in April in the Fox Creek area at surface location 3-262-17W5 with the Montney formation as the projected zone. On June 23, Trilogy Resources Ltd. was issued a licence at surface location 5-6-62-62-17W5 in the Fox Creek area, with oil as the objective and the Gething formation the projected zone. — DAILY OIL BULLETIN
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Southern Alberta
Apache expects to re-work properties acquired from BP for US$3.25B by James Mahony
Apache has a long history of bumping up production from property packages divested by bigger firms.
Apache Corporation has a reputation for extracting new production and reserves from assets that have been bought from other companies. Its Canadian arm will promptly tackle properties purchased for about US$3.25 billion from BP Plc on July 20. In a preliminary estimate, Apache said its new properties would require $300 million in capital spending this year, but that figure may be revised with further evaluation. The deal brings to Apache BP Canadian production of 6,529 barrels of liquids and 240 million cubic feet (MMcf) per day of natural gas (first-half 2010 production) plus estimated reserves of 224 million barrels of oil equivalent (boe). In 2010, Apache Canada’s first half production was 16,313 barrels of oil and natural gas liquids plus 326.6 MMcf per day of gas. Steve Farris, Apache’s chairman and CEO, described many of BP’s North
American properties as underworked. “Apache has really made a living off of sales packages from the majors,” he said. “For the first time in our history, we have an opportunity to take a major out of three core areas that are going businesses. An old cliché is that the place to find reserves
In Canada, the acquired properties include the Noel tight gas project, a proposed coalbed methane (CBM) project at Mist Mountain in southeastern British Columbia and a producing CBM play at Ojay in northeastern British Columbia. In Alberta, Apache has bought properties at Chinchaga, Wapiti, Fox Creek, Edson and Marten Hills. Kaybob and Harmattan dovetail with Apache’s existing assets and overall, the large acreage portfolio offers potential for applications of new horizontal drilling with multi-frac stimulation, Apache said. “Our regions have not had a big opportunity to look at what we’ve put together, but we’ll be doing that over the next several weeks, and coming up with a plan for each of these core areas,” Farris said. “In Canada, we have an awful lot of vintage wells.” Following a detailed review, Apache expects to put a rationalization package of non-core properties up for sale. Not part of the sale deal were BP Canada’s oilsands assets (including a 50 per cent stake in Husky Energy Inc.’s Sunrise project), a 50 per cent stake in the Kirby oilsands project and a 75 per cent interest in the Terre de Grace oilsands project. Also excluded from the deal were
“In Canada, we have an awful lot of vintage wells.” — Steve Farris, Chairman and CEO, Apache
is in mature areas, and this is right in our wheelhouse.” The Canadian assets form part of Apache’s US$7-billion acquisition from the British giant, which needs cash to deal with the devastating blowout of its offshore well in the Gulf of Mexico. The BP sale includes oil and gas properties in the United States and in Egypt’s Western Desert.
the company’s Kirby and Leismer natural gas fields in Alberta, its Mackenzie Delta assets in the Northwest Territories and its North American gas trading business. Apache paid about $80,000 per net flowing barrel for the complete package, after allowing for land values, according to Peters & Co. Limited. The proposed deal also includes select midstream assets in
JUL/09
JUL/10
JUL/09
JUL/10
WELLS SPUDDED
133
252
WELLS DRILLED
125
248
SOUTHERN ALBERTA WELL ACTIVITY
JUL/09
JUL/10
WELL LICENCES
127
197
▲
▲
▲
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • SEPTEMBER 2010
51
Southern Alberta western Canada, including eight mostly operated gas-processing plants, along with 2,933 miles of pipelines and flow lines. At one time in the late 1990s, BP was the largest producer of Canadian gas (at around one billion cubic feet of production per day, gross) following its acquisition of Amoco Canada Petroleum Ltd. Its drilling activity in subsequent years was limited. Based on 2009 year-end data, it ranked 14th overall with net production of 263 MMcf per day from Canada. Apache Canada, with the BP assets, should climb in the ranks to become the
sixth-largest Canadian gas producer, based on 2009 numbers. Apache’s total reserves worldwide increase to nearly three billion boe and its worldwide production will rise to about 769,000 boe per day from 686,000 boe per day. In terms of land, the deal will add 2.4 million acres to Apache’s acreage across the three regions concerned, including 1.3 million acres in western Canada. “We have about 4.3 million acres [in western Canada]. If you add BP’s 1.3 million acres, you’ve got 5.6 million acres in one of the most prolific gas basins in the world,”
Farris said. “Our production goes up to about 117,000 boe per day and reserves are over 750 million boe.” The Apache chairman highlighted BP’s Montney tight gas play at Noel in northeastern British Columbia, noting BP had invested about $600 million in infrastructure in the field, setting the stage for raising production to about 100 MMcf per day from the current 42 MMcf per day. “Our job will be not only to get to 100 MMcf per day, but to accelerate that,” Farris stated. — DAILY OIL BULLETIN
Total metres drilled in Q2 rise to nearly double the count in 2009 Operators nearly doubled the amount of metres drilled in the second quarter of this year compared to same three months in 2009, while the well count rose by a more modest 55 per cent to 1,197 holes. The rapid move to horizontal wells resulted in 2.49 million metres drilled from April to
June, a 95 per cent surge from 1.28 million metres a year earlier. While well counts remain significantly below most years in the past decade, on a metres-drilled basis, the second quarter of 2010 was back to levels experienced in 2008 and 2007, albeit
“LEADING THE
still below the 4.1 million to 4.4 million metres finished in the gas boom years of 2005 and 2006. Companies drilled only 127 wells in British Columbia from April to June, which amounted to 10.6 per cent of all 1,197 wells drilled in Canada. However,
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SEPTEMBER 2010 • OIL & GAS INQUIRER
STEVE WILLIAMS COO, SUNCOR
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Southern Alberta the B.C. wells accounted for 502,544 metres of hole, over 20 per cent of the industry total and up 275,907 metres from the second quarter of 2009. This year’s second-quarter B.C. metres surpassed even the record drilling years in the province. I n ea ster n Sa sk atc hewa n, com panies finished 177 wells and 421,729 metres during the second quarter, up from 106 wells and 233,548 metres last year. The recent peak year for the region was 2008 when industry drilled over 587,000 metres.
of the new century. The peak year was 2006 when 13.2 million metres of hole were drilled. In western and northern Canada, companies finished 4,796 wells to the end of June, up from 3,731 wells a year earlier, but still the second-lowest well count since the year 2000. The average well depth of 1,756 metres, however, is the highest since the Daily Oil Bulletin began tracking metres drilled in 1988. Compared to last year, the two regions showing the greatest increase in drilling in the first half were Alberta’s foothills front
The peak year was 2006 when 13.2 million metres of hole were drilled. I n t h e f i r s t h a l f of t h i s y e a r, Canadian operators drilled 8.43 million metres, 54 per cent more than last year’s 5.3 million but 8.7 per cent below the 2008 total of 9.24 million. That represents a better-than-average year when compared to the 1990s in Canada, but is below average for the first decade
(up 700,107 metres to 1.87 million) and eastern Saskatchewan (up 608,912 metres to 1.14 million). For the month of June, activity was reduced somewhat by wet weather, and operators only finished 592 wells, although 702 new wells were spudded. The rig-release count for June compares to
463 wells drilled in June 2009, while the spud count is up from 512 a year ago. In t he f irst si x mont hs of 2010, Alberta operators drilled 3,219 wells, ab out 20 p e r ce nt more t h a n t he 2,672 wells finished a year earlier. Saskatchewan producers rig released 1,0 42 we l l s ve r su s 626 la st yea r. Manitoba operators finished 161 wells, more than double the 69 drilled in the first half of 2009. Despite the pickup in the second quarter, B.C. drilling was flat with 368 wells this year versus 361 a year ago. Many of the wells drilled this year are still under confidential status, but of those wells with a reported status, over 50 per cent are listed as oil wells, which would make 2010 the oiliest year for Canadian drilling since 1997. In Alberta, 1,484 of the wells drilled to the end of June had oil or bitumen as an object ive — as high as in the boom years for drilling — compared to 597 for the same six months last year. In Saskatchewan, 934 first-half wells had oil as an object ive while only 81 were targeting natu ral gas. — DAILY OIL BULLETIN
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53
Southern Alberta
Drilling contractor days surge by 61 per cent in the first half Precision Drilling Corporation increased its market share and was the most active driller in the first half of this year, which saw a surprisingly strong increase in contractor drilling days compared to a year ago. Rig Locator records show 45,192 operating days for Canada’s drilling contractors to the end of June this year, up 61 per cent from only 28,059 days a year ago when the industry was in the midst of a major slump. This year’s 45,192 operating days compares well to the 42,504 days booked in the first half of 2008 and the 47,122 days recorded in the same period of 2007 but remains well below the boom period total in 2006, when operating days reached 68,692. And as there remains a surplus of available drilling rigs in Canada, day rates this year are not at levels experienced prior to 2009. Excluding test and observation wells, Precision drilled 1,252 wells in the first half, accounting for 26.02 per cent of all wells drilled in Canada, up from a 24.6 per cent market share a year earlier. Part of that was due to its largest producer client, Canadian Natural Resources Limited, being busier this year. Precision also ranked first in wells drilled in Canada’s three largest fossil fuel–producing provinces, leading the way in Alberta (1,005 wells), Saskatchewan (248 wells) and British Columbia (80 wells). The leading contractor in Manitoba was Trinidad Drilling Ltd. which finished 48 wells in the first six months of 2010. Including all test and observation wells, Precision drilled 1,371 wells to the end of June, while second-place Ensign Energy Services Inc. finished 1,122 wells.
Savanna Energy Services Corp. ranked third with 827 wells drilled, including over 200 observation/evaluation holes. Excluding observation/evaluation wells, Savanna drilled 563 wells and had a market share of 11.7 per cent, down from 763 wells and a market share of close to 20 per cent a year earlier. Encana Corporation was Savanna’s biggest customer and it is investing heavily in the United States this year. Despite drilling fewer conventional wells this year, demand for Savanna’s deeper-capacity rigs has been strong and operating days doubled to 4,245 days in the first half. Ensign was the second most active contractor in Alberta (825 wells) and
Average drilling days in western Canada remained at historically high levels in the first six months of 2010.
Saskatchewan (222 wells), while in British Columbia, second place went to Nabors Drilling, which finished 74 wells in that province during the first half. Average drilling days in western Canada remained at historically high levels in the first six months of 2010 due to the preponderance of horizontal wells and the absence of shallow gas drilling, but overall average days dipped slightly from
last year due to improved drilling times in British Columbia. On average, it took 10.94 days to drill a well in western Canada, including 10.03 days in Alberta, 9.4 days in Saskatchewan and 24.6 days in British Columbia . Alberta and Saskatchewan drilling times were slightly longer than last year, while British Columbia’s drilling days fell from an average of 27.02 days per well in the first six months of 2009. As usual, smaller contractors dom inated the top spots on metres drilled per rig and average wells drilled per rig owned. Eagle Drilling Services Ltd. (six rigs) and Cedar Creek Drilling Ltd. each managed to drill over 25,000 metres per rig in the first half. Technicoil Corporation’s five rigs in Canada drilled the most wells per rig (26.6) during the period. Similarly, rig utilization was highest at Cedar Creek, which had a 63 per cent utilization rate, slightly ahead of Lasso Drilling Corporation’s 60 per cent utilization rate for its two rigs. Only three drilling contractors had fewer operating days in the first half of this year compared to last year. Jomax Drilling (1988) Ltd. had the largest decline, off 277 days to 727 operating days, according to Rig Locator records. (Operating days exclude all test and observation wells.) The largest gains were at Ensign (up 3,058 operating days) and Precision (up 2,732 operating days). Ensign had a particularly strong second quarter with operating days more than doubling from last year to 3,381 days, a gain of 2,145 days from the second quarter of 2009. — DAILY OIL BULLETIN
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Western Energy Services acquires Impact Drilling for $19.4M Western Energ y Ser v ices Cor p. has agreed to buy Impact Drilling Ltd. in a deal valued at about $19.4 million. Western Energy is making the acquisition through its wholly owned subsidiary Horizon Drilling Inc. Impact is a private company whose assets include three Range 3 top-drive
eight drilling rigs in the field, and all of the rigs will be included in the acquisition, but four of them will be placed in inventory. Western Energy anticipates that it will upgrade these drilling rigs to increase their horizontal depth capability to match the comparable drilling rigs in the Western Energy drilling fleet.
Western Energy has commenced the construction of a top-drive telescopic double drilling rig with hoisting and pumping capabilities to drill long-reach horizontal wells. telescopic single drilling rigs, one topdrive single drilling rig and various ancillary drilling equipment. All four drilling rigs have top drives and pipe-handling systems and are capable of drilling horizontal wells. Impact’s rigs drilled 19 wells in the first six months of this year. Rig Locator records show the company currently has
Western Energy said its acquisition of Impact will increase its exposure to nonconventional resource plays while reducing general and administrative expenses on a per-rig basis. Western Energy’s fleet utilization rate was 46 per cent in the second quarter of 2010 compared to an industry average of 20 per cent. Rig Locator records show Horizon drilled 66
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wells in Canada during the first six months of 2010. Western Energy has commenced the construction of a top-drive telescopic double drilling rig with hoisting and pumping capabilities to drill long-reach horizontal wells. The rig is expected to be commissioned during the first quarter of 2011 and will be financed through operating cash flow and Western Energy’s available lines of credit. Upon closing of the acquisition, Western Energy will have a fleet of 15 drilling rigs in service that are, on average, less than four years old, cost on average $6.8 million per rig. Impact’s rigs are designed and engineered similar to Western Energy’s current comparable rigs. Western Energy CEO Dale Tremblay noted that, following the purchase, his company “will achieve the status of being one of the top 10 largest oil and gas well drilling contractors in Canada.” — DAILY OIL BULLETIN
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TransForce acquires assets of EnQuest Energy Services EnQuest Energ y Ser vices Corp. has agreed to sell substantially all of its assets for US$32 million to TransForce Inc., a Montreal-based trucking and logistics firm. On the block were Speedy Heavy Hauling, Inc., Summit Crane & Rigging, Inc., Northern Truck & Crane, Inc. and Tubular Transportation Inc. The buyer is Hemphill Trucking, an American subsidiary of TransForce. The asset sale was announced in June, followed by an equity arrangement in July. Calgary-based EnQuest operated extensively in the United States and Canada. Its energ y-related ser v ices included transportation, rig moving, crane services, specialized heavy hauling, oilfield equipment rentals, retailer of new and refurbished oil country tubular goods and pipe storage.
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SEPTEMBER 2010 • OIL & GAS INQUIRER
Proceeds for the asset sale will be used for the payment of the creditors of EnQuest and its subsidiaries, for the payment of transaction costs, for the costs of rectifying certain regulatory defaults of EnQuest and for the remaining operating costs of EnQuest. Following completion of the arrangement agreement, EnQuest will cease operations in its primary business of rig moving. Hemphill Trucking will be integrated with the new companies, operating as Hemphill-Speedy, headquartered in Grand Junction, Col. “The acquisition of the EnQuest assets substantially enhances TransForce’s competitive position in the
Southern Alberta
U.S. energy services industry where our coverage will now include Arkansas, Colorado, Montana, Nor t h Dakota, Pennsylvania and Wyoming and where we will be well poised to benefit from the impending recovery in the industry,” said Alain Bedard, chairman, president and CEO of TransForce. “With the strong support of EnQuest investors, we look forward to working with the 220 employees of Speedy as we further build on our U.S. infrastructure and management team,” Bedard said in a statement. — DAILY OIL BULLETIN
A record 1,993 horizontal wells were drilled in the first half of this year with three out of four western Canadian provinces at record highs for the period. The total of 1,993 horizontal wells rig released represents a 141 per cent surge from 825 wells a year ago and tops the previous first-half record of 1,216 horizontal wells drilled to the end of June in 2008.
Alberta, Saskatchewan and Manitoba are setting new highs for horizontal drilling this year. Alberta, Saskatchewan and Manitoba are setting new highs for horizontal drilling this year, while B.C. activity is far ahead of last year but below the previous first-half record of 312 horizontal holes in 2004. Operators rig released 1,013 new horizontal wells in Alberta to the end of June compared to only 382 a year earlie r. In Saskatchewan, 607 wells were drilled, up from 230 last year, while Manitoba shows 124 horizontal wells drilled in the first half compared to 57 last year. B.C. operators finished drilling 248 wells in the first half, up from 156 horizontal wells last year.
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— DAILY OIL BULLETIN OIL & GAS INQUIRER • SEPTEMBER 2010
57
Southern Alberta
Despite higher revenue, Precision reports a net loss due to high financing costs Precision Drilling Corporation is crediting an increase in rig utilization days in Canada and the United States for revenue that rose 25 per cent in the second quarter. However, $52 million in financing charges and a $26 million in foreign exchange loss dragged down profits, contributing to a net loss in the quarter. Precision converted to a corporation in June, but paid no dividends in the second quarter, nor any cash distributions in the first. The mix of drilling rigs working under term contracts rather than well-to-well contracts put downward pressure on pricing during the quarter, the company said. However, contract drilling revenue rose 22 per cent in the period, while revenue in the company’s Canadian-based completion and production business rose 47 per cent over the second-quarter figure of 2009. Day rates on its tier 2 and 3 rigs have improved, said Kevin Neveu, Precision’s president and CEO. However, Neveu commented that it takes several quarters after an “activity trough” for rates and margins to improve. “We believe we are at or near that bottom now,” he said in a written statement. “With unconventional horizontal oil drilling techniques being applied to conventional oil reservoirs in Canada, we believe that the remainder of 2010 activity levels will exceed those in 2009.” Thanks largely to spring breakup, an average 40 drilling rigs worked in Canada in the second quarter, with 90 operating in the United States and Mexico, for a total average of 130 rigs working. That’s down from an average of 193 rigs working in the first quarter of 2010 and 79 rigs in the second quarter of 2009.
In its contract drilling business, Precision has 351 drilling rigs, including 200 in Canada, 148 in the United States and 3 internationally, along with 85 drilling rig camps. Precision’s completion and production business operates 200 service rigs, 20 snubbing units, 79 water treatment units and a broad mix of rental equipment. In the three months ended June 30, 2010, Precision’s net loss was $66.55 million, down from earnings of $57.48 million in last year’s period. Revenue in the quarter rose to $261.83 million from $209.60 million in the earlier period. Capital spending fell to $21.68 million from $29.17 million in last year’s quarter. The $52 million in the quarter’s finance charges included a non-cash charge of $24 million. In the six months ended June 30, 2010, the company’s net loss was $5 million, down from net earnings of $115 million in the 2009 period. Revenue in the first half slipped to $635 million from $658 million in the first half of 2009, due to lower pricing, partially offset by higher activity, the company said.
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Higher activity levels in 2010 were offset by lower drilling revenue per day in the company’s operating areas, management said. First-half results include a foreign exchange loss of $6 million, compared to a $42-million gain on foreign exchange in last year’s first half. Capital expenditures in this year’s first half were $29.17 million, down from $165.25 million in the 2009 period. This year’s spending included $8 million on expansionary capital and $21 million on upgrades to existing assets. In the first six months of 2009, 14 newly built Super Series drilling rigs were added to the fleet under long-term customer contracts, 7 in Canada and 7 in the United States, management said. Precision has added seven rigs to its 2010 new rig-build program, bringing the total to nine rigs, including two announced in the first quarter. Five of the rigs are Super Singles, with three to be deployed in Canada and two in the United States. The remaining four rigs are Super Triples, also expected to work in the United States. — DAILY OIL BULLETIN
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Viking formation economics stack up well with other resource plays
Photo: Reece Energy Exploration Corp.
by Paul Wells
Reece Energy, since acquired by Penn West, drilled the first multi-frac horizontal wells at Dodsland.
Drilling results indicate that Saskatchewan has another promising tight oil play in the Viking formation. Similar to the Alberta Cardium, the Viking is a formation developed in the 1950s that now stands to be rejuvenated thanks to horizontal multistage frac techniques. “What we’re seeing is increased land sale activity there,” says Saskatchewan Energy Minister Bill Boyd. “It’s our sense that the Viking formation could be a very, very strong play for us given the fact it’s shallower production and it’s getting very good results. Activity in the Kindersley through Lloydminster area is picking up very [well].” In the April land sale, the KindersleyKerrobert area produced the secondhighest bonus revenue at $25 million. The top price paid for a single lease was $3.95 million for a 647-hectare parcel situated partially within the Avon Hill
Viking Sand (oil) pool six kilometres northeast of Kindersley. So far in 2010, the Kindersley-Kerrobert area has raised $31.6 million in land sale bids, up from $3.68 million in 2009. The Viking is one of the largest established conventional light-oil accumulations in western Canada, second only
expanding known oil in place both vertically and aerially, with revised estimates for oil in place growing to more than five billion barrels. “With one of the lowest recover y factors among established oil pools, at approximately four per cent, significant remaining oil in place is waiting to be harvested through advances in technology,” the Macquarie report said. Reece Energy Exploration Corp. kickstarted the Viking resurgence when, in late 2007, it became the first company to begin drilling horizontals into the formation with multi-stage fracs, making the Viking one of the earlier western Canadian oil pools outside of the Bakken to have multi-stage fracs applied to it. Reece was subsequently acquired by Penn West Energy Trust in 2009, and the trust has since become one of the most active drillers in the area, exploiting its significant land position at Dodsland. Outside of west-central Saskatchewan, industry has also had recent success at Redwater, Alta. While this is a much smaller-scale play, the Macquarie report said operators have recently achieved very good results from horizontal Viking drilling (200–300 barrels of oil equivalent per day from multilaterals), with generally better initial rates and shallower
"With one of the lowest recovery factors among established oil pools, at approximately four per cent, significant remaining oil in place is waiting to be harvested through advances in technology." — Macquarie Capital Markets Canada report
to the Cardium in Alberta. According to a Macquarie Capital Markets Canada report, application of horizontal drilling with multi-stage fracturing is tapping into previously uneconomic rock and
declines than witnessed in Saskatchewan so far. Ed Dancsok, assistant deputy minister of Saskatchewan’s Minist r y of Energy and Resources, says the Viking
JUL/09
JUL/10
JUL/09
JUL/10
WELLS SPUDDED
190
287
WELLS DRILLED
195
295
SASKATCHEWAN WELL ACTIVITY
JUL/09
JUL/10
WELL LICENCES
162
292
▲
▲
▲
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • SEPTEMBER 2010
61
Photo: Brian Zinchuk, Pipeline News
Saskatchewan
Due to historical production, well control in the Viking play is excellent, which reduces risk.
in his province appears to have the legs to live up to the growing, albeit modest, hype. “It’s certainly gaining traction. As for numbers, we’re starting to get into something that’s worth talking about,” he com ments, adding t hat t he play should be able to hold its own with the Bakken and Lower Shaunavon, at least when comparing the economics of the various plays.
“I think for bottom-line potential, it sure does,” Dancsok says. “It’s much cheaper to drill the Viking horizontal wells, and companies are finding better and better ways to lower their upfront costs for drilling these wells. It’s fairly shallow. It’s the shallowest oil target we have in the province and as a result with the lower front-end costs, it’s making their rates of return and netbacks very, very attractive.”
Dancsok says that the latest provincial figures (to the end of March) show the growing trend toward horizontal development in the formation. He said that about 110 producing wells in the Viking have combined output of approximately 2,400 barrels per day, or around 22 barrels per day each on average. W hile those are not eye-opening numbers, when compared to the output of vertical wells, it’s a vast improvement. “When you look at the vertical wells producing in the Viking, I think we’re down to about 1.5 barrels per day, so it’s certainly a much better picture as far as that is concerned,” Dancsok says. “There’s going to be high spots or sweet spots that make some of that more attractive.” Year-to-date, 20 vertical wells have been drilled in the Kindersley area compared to 19 in the first six months of last year. In contrast, 103 horizontal wells have been drilled so far this year compared to only one horizontal well at this time last year. “That’s a huge jump,” says Dancsok. “Now we’re seeing that about 85 per cent of the wells being drilled in that area are now horizontals and they form the lion’s share of the activity.”
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SEPTEMBER 2010 • OIL & GAS INQUIRER
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Saskatchewan Leon K night, an oil and gas analyst with Macquarie, says that while the wells are less prolific than in other plays such as the Bakken, the cost structure associated with the Viking provides good upside for producers. “The Viking is much shallower than other emerging plays, at only approximately 700 metres. Although lower pressure delivers less prolific rates relative to some other light oil plays, costs are also much lower and will be a key factor in improving returns on the play,” he says. Knight notes that well costs have steadily declined to about $1.2 million from the range of $1.5 million to $2 million per well a year ago. And he expects that as industry familiarizes itself with the nuances of the play, those costs may be further reduced to around $1 million per well by this time next year. “This is an important consideration for smaller players, making them less likely to be derailed by a few unsuccessful wells right out of the gate,” the analyst says. He noted that Redwater in Alberta is also currently drawing significant attention, with multilateral horizontals achieving initial production (IP) rates of 200–300 barrels of oil equivalent per day.
Single-laterals at Redwater are also achieving attractive IP rates of 70–100 barrels of oil equivalent per day as producers are seemingly on the brink of unlocking the technology that is delivering very attractive returns. According to a Scotia Capital Oil and Gas Resource Play Spotlight released last year, the Saskatchewan government’s original oil in place estimate for the Viking in that province of about two billion barrels is not reflective of what the formation holds given recent techno logical advancements. “[It’s] considerably less than our estimate of six billion barrels primarily, we believe, because the government considered only the upper sandstones in its estimate. The key to unlocking increased oil in place, we believe, lies in accessing the tighter, siltier rock that underlies the cleaner sandstones,” the Scotia Capital report said. Given the firm’s estimate of oil in place, it said the Viking play in southwestern Saskatchewan is second only to the Cardium “in terms of magnitude among emerging tight oil plays.” Similar to the Cardium, the Viking has also already been well delineated because
of extensive vertical drilling, Scotia Capital noted. “We also see potential for significant expansion of the play...with estimated IRRs [internal rates of return] of 57 per cent and breakevens of US$34 per barrel, Viking economics edge out the Shaunavon, and come in slightly behind the Bakken and Cardium plays,” the report said. “With much improvement in completion techniques still to be had, we think the best results in the play are likely yet to come.” In its report, Macquarie said significant land positions are held by larger players, such as Penn West, Husk y Energy Inc., Baytex Energy Trust and more recently Crescent Point Energy Corp., through several acquisitions. Smaller players have also estab lished sizable positions both within some smaller producing pools (including Redwater) and along the boundaries of existing pools — areas made prospective by horizontal technology. Key smallcap, publicly listed players with notable land positions include WestFire Energy Ltd., Novus Energy Inc., Wild Stream Exploration Inc. and Sure Energy Inc. — DAILY OIL BULLETIN
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OIL & GAS INQUIRER • SEPTEMBER 2010
63
Saskatchewan
New technologies, prospects and players drive Bakken activity This year, Crescent Point Energy Corp. plans to drill 191 net Bakken wells and has a total budget of $750 million for the tight oil play in southeastern Saskatchewan. PetroBakken Energy Ltd. plans to drill 100 net wells. While the 2010 well count isn’t expected to match the record 714 rig releases in 2008 (when West Texas Intermediate crude oil rocketed to nearly US$150 per barrel), the play is still going strong. Technology for exploiting the resource continues to evolve. To complete the wells, Crescent Point is using cemented liners while PetroBakken continues to use packer-style completions. PetroBakken is now drilling mostly dual-leg horizontal wells. Crescent Point is piloting multiple waterfloods. Certainly production has shot up. According to the province’s tally, Bakken oil production averaged 61,000 barrels per day in the first half of this year, up from 54,500 barrels per day in 2009, 41,800 barrels per day in 2008, 13,500 barrels per day in 2007, 5,100 barrels per day in 2006, 1,600 barrels per day in 2005 and 750 barrels per day in 2004.
Some 1,737 wells have been drilled into the southeast Saskatchewan Bakken from 2004 to mid-2010, the province’s statistics show. In an April research report, Macquarie Capital Markets Canada Ltd. said the Bakken Viewfield fairway is arguably one of the fastest-growing light oil plays in North America. While much of the available land has been snapped up around Viewfield, new areas are emerging in Canada’s first tight oil play. Also, a few big producers are giving the Bakken a serious look, and there have been some significant land acquisitions. When Enerplus Resources Fund set its $117-million Bakken development budget this year, most of it was earmarked for Montana and North Dakota. But purchase of acreage in the Freda Lake/Neptune area at a Crown land sale in late April means the trust now has 100 per cent working interest in 170,000 net acres of Canadian Bakken-prospective lands and will likely increase its spending there. “We’re excited by it — it’s a meaningful position for us,” said Garth Doll,
Enerplus’s manager of investor relations. The trust expects to divulge more details on its development plans for the region in the coming months. NAL Oil & Gas Trust has about 75 sections of Bakken acreage south of Viewfield, and also holds the Bakken rights in 245 sections of undeveloped lands near Hoffer, which is just north of the North Dakota border. The trust, which is Mississippian-focused in Saskatchewan, doesn’t plan to drill any wells in the area south of Viewfield this year, but will likely drill one or two Bakken wells in the Hoffer area in 2011, says NAL president Andrew Wiswell. He said the trust will continue to monitor the area south of Viewfield to see what nearby competitors are doing. All of NAL’s acreage in that area is held by production. NAL is focusing most of its 2010 spending on its signature play in the Cardium at Garrington in central Alberta and on Mississippian (non-Bakken) light oil in southeastern Saskatchewan. In recent months, a much bigger player has quietly made its public debut in the
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SEPTEMBER 2010 • OIL & GAS INQUIRER
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Saskatchewan Bakken. Cenovus Energy Inc., the spinoff of Encana Corporation’s oil assets, has been buying Bakken lands in the Roncott area, west of Viewfield. Cenovus has 57 undeveloped sections of land at Roncott, where it has drilled two horizontal and three stratigraphic wells. It has about 140 more undeveloped sections of Bakken lands in the Viewfield and Estevan areas, where it has drilled four horizontal and three stratigraphic wells. The company plans to drill six Bakken wells this year, three of which have already been drilled. About six had been drilled prior to 2010. Cenovus president and CEO Brian Ferguson says that the evaluation of those lands is still in the “very early phases” and no decision has been made. “We do have a couple of areas that we have actually farmed out where other companies are drilling wells,” Ferguson says. “And there’s, for example, a 30-well commitment by one other company...which has a 24-month window for which they’ve got approvals.” A recent surge in activity outside the Bakken core is providing entry opportunities for new players and enhancing the play’s growth potential. Much of this activity is targeting known accumulations
of Bakken oil that haven’t been heavily exploited in the past because of relatively high water production, said Glenna Jones, VP of energy equities at Ross Smith Energy Group Ltd. Activity is occurring near the Saskatchewan/North Dakota border in areas such as Tableland and Taylorton. A key player at Taylorton, which is near Estevan, is Legacy Oil + Gas Ltd. Created last year from the recapitalization of Glamis Resources Ltd., Legacy has 25,850 net acres in the Taylorton Bakken with an average working interest
drilling would be in the Bakken, where the company has more than 275 gross well locations. On June 15, Legacy increased its capital budget to $130 million from $117 million. In some areas, Legacy is targeting multi-zone opportunities, including the Torquay, another tight, light oil formation, which in some places underlies the Bakken. Meanwhile, acreage continues to become available within the Bakken core as lands frozen for native land claims have become available for posting. In a recent investor presentation,
According to the province’s tally, Bakken oil production averaged 61,000 barrels per day in the first half of this year, up from 54,500 barrels per day in 2009. of 77 per cent. Legacy is headed by Trent Yanko, an engineer and former president of Mission Oil & Gas Inc., a Bakken pioneer that grew from 500 barrels of oil equivalent a day to more than 7,000 barrels of oil equivalent per day in two years before being sold to Crescent Point for $670 million in February 2007. After Legacy’s annual meeting in May, Yanko said 60–65 per cent of the company’s
Crescent Point stressed it still has a land budget and continues to increase its core Bakken acreage. The Macquarie report on emerging oil plays said the original oil in place in the southeast Saskatchewan Bakken is estimated at five billion barrels — four billion at Viewfield and the rest in smaller accumulations such as Taylorton and Flat Lake. — DAILY OIL BULLETIN
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65
Saskatchewan
Novus completes Viking horizontals and closes Dodsland acquisition Novus Energy Inc. says it recently successfully completed the drilling its initial 16 horizontal Viking oil wells in the Dodsland area of Saskatchewan. To date, 14 of these wells have been fracture stimulated and 2 wells are awaiting completion. The company wholly owns all of the wells. Of the 14 wells that have been completed, 5 have been producing for a period of in excess of 30 days, 6 have recently been brought on stream, and the remaining 3 are being equipped and will be placed on production in the near future. Novus has used several completion methods in its wells including hydrocarbon, cross-linked water, native crude oil and energized foam fracs. The company has now determined that on the majority of its future drilling operations in the Dodsland area, it will drill approximately 600-metre horizontal lateral legs using monobore technology with completion operations employing 11–15 stage energized foam fracs of 13–14 tonnes of sand per stage. Novus has drilled, cased and completed the majority of its wells in this fashion for approximate capital costs of $950,000. The five wells that have been on production
for over 30 days are currently averaging approximately 72 barrels of oil per day per well. Novus said it is extremely encouraged by the initial results it has seen in its current phase of operations in the Dodsland area. The company exited the second quarter of 2010 producing approximately 1,100 barrels of oil per day comprised of 52 per cent oil and liquids, with the majority of the company’s recent production growth coming from the Viking light oil play. During the second quarter of 2009, the company’s average corporate production level was 327 barrels of oil per day, with 24 per cent of the production being oil and liquids. Novus said it expects the oil weighting of its corporate production to continue to increase as new wells in the Dodsland area are brought on stream. Novus anticipates drilling a minimum of 20 wells in the second half of the year in the Dodsland area and is currently surveying 60 drilling locations. To accommodate the increased production the company expects in the area, two new facilities to treat oil and conserve gas will be constructed. The company is in the advanced stages of planning and has sourced all the necessary equipment for these
facilities. Applications will be submitted shortly, and both facilities are expected to be operational in the third quarter of this year. Novus also announced that it has closed an acquisition of assets within its core area of Dodsland. Under the terms of a purchase and sale agreement effective July 1, 2010, between Novus as purchaser and two private companies as vendors, Novus acquired 4,240 net acres (approximately 6.5 net sections) of prospective land in the Viking oil resource play for the consideration of $675,000. The purchase price for the acquired lands was entirely payable through the issuance of 794,119 common shares of Novus, at a deemed issue price of $0.85 per common share. The company said it has identified 10 net horizontal drilling locations targeting the Viking formation on the acreage acquired. Novus now has approximately 49,300 net acres (77 net sections) of land in the Dodsland area, and a drilling inventory of 240 net horizontal Viking oil drilling locations, which represents an inventory of six years, assuming a drilling density of four wells per section. — DAILY OIL BULLETIN
Oilsands Quest reports resource estimates Oilsands Quest Inc. has released independent resource estimates for its Wallace Creek, Axe Lake, Raven Ridge and Eagle’s Nest properties. “The results of the drilling program at Wallace Creek are encouraging and imply an area with high prospectivity,” said Sue MacKenzie, COO at Oilsands Quest. “We look forward to drilling and delineating more resources in the remainder of Wallace Creek.”
Best-estimate bitumen resources for Wallace Creek were listed as 302 million barrels of discovered resource and 98 million barrels of contingent resources. The resource estimates for the Axe Lake, Raven Ridge and Eagle’s Nest properties were also updated, but have not changed significantly from the previous evaluation. McDaniel & Associates Consultants Ltd. prepared the estimates at the request of Oilsands Quest.
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At A xe Lake, Oilsands Quest has drilled 320 exploration core holes and 45 development and monitoring wells. The McDaniel resource estimate remains relatively unchanged from the previous evaluation for the Axe Lake project with a best-estimate discovered resource of 1.86 billion barrels and a contingent resource of 152 million barrels. — DAILY OIL BULLETIN
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SEPTEMBER 2010 • OIL & GAS INQUIRER
Central Canada
Canadian Senate report supports CO2 restrictions
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Quebec has commercial oil prospect
Rising CO 2 emissions from sources like the oilsands are being examined by a Senate energy committee.
In July, the upper house of Canada’s Parliament released an interim report on Canada’s energy future in which it calls for a broad-based, national discussion on energy. Entitled “Attention Canada! Preparing for our Energy Future,” the Senate report wraps up nine months of testimony before its Standing Committee on Energy, the Environment and Natural Resources. In that time, the group heard from witnesses in the energy sector, think tanks and other stakeholders. While making few recommendations, the report sums up recent dialogue on major energy issues facing Canadians, including Ottawa’s strategy on climate change, the future of fossil fuels and the prospects for nuclear energy and renewables, among other energy sources. The 75-page report looked briefly at how action or delay on climate change in the United States would affect Canada’s options. The Stephen Harper government has said it would not move ahead on the subject until the United States shows its hand, either by passing cap-and-trade laws or by taking a regulatory approach to climate change. In June 2009, the U.S.
House of Representatives passed a bill with cap-and-trade provisions, which has since become mired in the U.S. Senate. In their report, Canada’s senators said many witnesses appearing before them agreed on the need for a national carbon tax to tackle the rise of greenhouse gas emissions. “The committee found near unanimity among witnesses... that supported carbon-pricing as the most efficient way to reduce emissions,” the report said. “Given the choice, most witnesses favoured carbon taxes over cap-and-trade, but both are market-based approaches for pricing carbon and both can be levied at different stages [in] the fossil fuel supply chain.” The recent Senate report said any carbon tax should be national in scope: “Carbon pricing should be applied broadly and uniformly throughout the economy and across Canada.” The committee is looking forward to future testimony from a broader group of Canadians. Under the current plan, the committee would issue its final report in June 2011. — DAILY OIL BULLETIN
Petrolia Inc. and Junex Inc. say their Haldimand property in Quebec’s Gaspe Peninsula is a commercial prospect. An evaluation of the nine-square-kilometre portion selected for assessment showed a best estimate of the petroleum initially in place of 69.7 million barrels with the contingent (potentially recoverable) resources amount to 7.7 million barrels. The low estimate was 21.9 million barrels of oil in place with contingent oil resources of 1.9 million barrels. The Haldimand evaluation was prepared by Sproule Associates Limited. Andre Proulx, president of Petrolia, said its estimates are very encouraging, since the survey covers only the nine-squarek ilometre area represented by the Haldimand property, whereas the structure extends beyond its border. From a commercial standpoint this volume of recoverable petroleum could potentially support a viable production operation, the company added. Petrolia has a 65 per cent interest in the Haldimand property and Junex holds 35 per cent. The presence of such an amount of recoverable petroleum in this structure alone raises the possibility of other significant discoveries in the Gaspe region, where Petrolia holds a number of permits that are prospective for the discovery of petroleum, Proulx said. Petrolia has signed a principal agreement with France’s SCDM Energie, through its Canadian subsidiary, Investcan Energy Corp. In return for its investment of $15 million, Investcan Energy will be acquiring 50 per cent of Petrolia’s interest in the Haldimand discovery and in the 13 surrounding licences. The costs to develop the Haldimand field will be shared equally between the partners. Petrolia will act as operator during the exploration phase, and Investcan Energy will act as operator in the production phase. OIL & GAS INQUIRER • SEPTEMBER 2010
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SEPTEMBER 2010 • OIL & GAS INQUIRER
East Coast
Illustration: ExxonMobil Canada Properties
ExxonMobil files its development plan for the Hebron offshore project
Hebron would be the fourth stand-alone offshore development project on Newfoundland’s Grand Banks.
The Canada-Newfoundland and Labrador Offshore Petroleum Board (CNLOPB) is seeking comments from the public on the draft Comprehensive Study Report (CSR) for the Hebron offshore development project prepared under the Canadian Environmental Assessment Act. ExxonMobil Canada Properties is proposing the project on behalf of the Hebron project proponents, which also include Chevron Canada Limited, Petro-Canada Hebron Partnership, Statoil Canada Ltd. and Nalcor Energy Oil and Gas Inc. The draft CSR concludes that the project will not have significant residual environmental effects on items such as air quality, fish and fish habitat, marine birds and animals, species at risk, and sensitive or special areas. “The only potential for significant residual adverse environmental impacts as a result of the Hebron project is in association with a worst-case accidental event,” according to the report. “In such an unlikely event, significant adverse en-vironmental impacts have been predicted for marine birds and the sensitive or special areas located in the near-shore env ironment,” it says.
“Emphasis on both pollution prevention and effective response planning will further reduce the potential for these unlikely significant environmental effects to occur,” says the report. The Canadian Environmental Assessment Agency will provide an opportunity for public comment on the final CSR at a later date. Hebron will be the fourth stand-alone development project on the Grand Banks and the sixth offshore petroleum project when the two tie-back projects to the Hibernia and White Rose facilities are included. The Hebron platform will be situated approximately nine kilometres north of the Terra Nova field, 32 kilometres southeast of the Hibernia development and 46 kilometres southwest of White Rose. T he operators are commit ted to achieving first oil prior to the end of 2017, but best efforts are being made to optimize the project schedule and achieve an earlier first-oil date (before the end of 2016). The intent is to develop the project using a concrete gravitybased structure (GBS), which will be constructed at Bull Arm, Newfoundland beginning in 2012. The structure will be
designed for an in-service life of 50 years or more. The GBS will accommodate well slots with J-tubes for potential future subsea tieback of nearby resources. It will have a single main shaft supporting the topsides and will encompass all wells to be drilled from the platform. The GBS concept will be further refined/finalized during the front-end engineering design and detailed design stages. The structure will be designed to store approximately 180,000 to 230,000 cubic metres of crude oil in multiple storage compartments. In anticipation of potential future development of resources within drilling reach, it will be designed to include 52 well slots. An offshore loading system (OLS), similar to an upgraded system design proposed for the Hibernia OLS, will be installed to offload crude oil from the platform to tankers. The initial depletion plan consists of developing oil resources from the Ben Nevis, Hibernia and Jeanne d’Arc H and B reservoirs within the Hebron field, and storing any temporary surplus of produced gas in either the Ben Nevis reservoir of the Hebron field or in the Ben Nevis reservoir of the West Ben Nevis field. The forecasted cumulative oil recovery for the base development after 30 years of producing life is approximately 100 million cubic metres (629 million barrels) from an anticipated 41 wells. The CNLOPB estimates that the Hebron field contains 581 million barrels of recoverable oil and it estimates that the Ben Nevis and West Ben Nevis discoveries contain an additional 150 million barrels of oil, 429 billion cubic feet of natural gas and 30 million barrels of natural gas liquids. The Ben Nevis pool within the Hebron field is the core of the Hebron project and is anticipated to produce approximately 80 per cent of Hebron’s crude oil. However, reservoir quality is expected to be lower than that of some other producing fields in the Jeanne d’Arc Basin and the 19- to 25-degree API crude presents production challenges since the viscosity can be approximately 10 to 20 times higher than that of water, says the CSR. — DAILY OIL BULLETIN OIL & GAS INQUIRER • SEPTEMBER 2010
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Xtreme enters the Australian market and redeploys its Mexican rigs
Photo: Xtreme Coil Drilling Corp.
Savanna updates Mexico operations
Xtreme’s new partner says its coiled tubing rigs will cut coal seam drilling costs by up to half.
Xtreme Coil Drilling Corp. has entered the Australian drilling market by establishing a joint-venture company with AJ Lucas Group Limited. The joint-venture company, Lucas-Xtreme Drilling Pty Ltd., is owned 50 per cent by AJ Lucas Coal Technologies (a wholly owned subsidiary of Lucas) and 50 per cent by Xtreme (Luxembourg) SA (a wholly owned subsidiary of Xtreme Coil). AJ Lucas is the largest provider of drilling services to the Australian coal and coal seam gas industries. “We are particularly pleased to have partnered with them to introduce and apply our coiled tubing drilling methods to Australia,” says Xtreme Coil chairman Tom Wood. “We believe Xtreme Coil is able to drill wells much faster and at a substantially lower cost than is possible with traditional drilling methods using jointed pipe.” Xtreme Coil and Lucas will provide Coil Over Top Drive drilling rig equipment and related ser vices. The new joint-venture company will focus on developing business with proprietary, built-forpurpose equipment designed specifically for the Australian market using several Xtreme Coil patents and patent-pending
processes to respond to coal seam gas drilling projects and other opportunities as they arise throughout Australia. A llan Campbell, chairman of A J Lucas said that through the partnership it expects a new rig, especially designed for Australian conditions, to deliver wells to clients at as little as half the current cost due to the significant reduction in drilling and moving time. Meanwhile, Xtreme is continuing its plan to redeploy drilling rigs from Mexico’s Chicontepec region to the United States. On June 30, Xtreme Coil Mexico filed suit against Weatherford International Ltd. for breach of contract under 10 service agreements executed in 2009 to provide drilling rigs for work in Mexico. The lawsuit was filed in the District Court of Harris County, Texas, and seeks recovery for damages the company believes are payable under the terms of the contracts in excess of US$60 million. In recent weeks, Xtreme has moved two Coil Over Top Drive drilling rigs from Mexico’s Chicontepec region to McAllen, Texas, to prepare them for work in the Rocky Mountain region of the United States. — DAILY OIL BULLETIN
Savanna Energ y Ser vices Corp. has received formal notification from its customer, a global integrated oilfield services company, regarding its four-rig drilling contract in Chicontepec, Mexico. Savanna’s customer has advised that it has received operator notification that the pace of drilling, and potentially the absolute number of wells to be drilled, under the contract pursuant to which Savanna’s customer has been operating, has been reduced. The customer has advised Savanna that it will be releasing two of the drilling rigs upon completion of their current locations. As a result of this reduction, the customer will demobilize the two released rigs, at its cost, to McAllen, Texas, as soon as possible. The remaining two rigs will remain in service pursuant to the same terms as the original contract. Savanna has initiated efforts to transfer the released rigs to other operating areas in North America and anticipates that the rigs will be quickly redeployed. Given the depth capacity and efficiency of these 1200 hp AC rigs, Savanna expects limited downtime on this equipment; however, the rigs are currently uncommitted. Savanna will continue to monitor expected activity levels in respect to the remaining two rigs in Mexico, and will assess their utilization, current and long term, with its customer on an ongoing basis. However, the operating situation in Mexico remains very unsettled. Up until two years ago, western Canada was Savanna’s core operating area, with more than 80 per cent of revenue from Alberta; now that figure is below 50 per cent and it is continuing to diversify its revenue base. In a $220-million (Australian dollars), five-year deal signed last year, Savanna will send two hybrid drilling rigs from its Canadian fleet to Australia along with two workover rigs for deployment in a coalbed methane to liquefied natural gas project in Queensland in the third or fourth quarter of this year. OIL & GAS INQUIRER • SEPTEMBER 2010
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into their existing operations. Over half of my work is for oil and gas
of them difficult to identify and some carrying harmful voltage. The customer
companies. I deal with control systems of all kinds, pretty much anything
is often in a hurry, especially when we’re troubleshooting. Certain precautions
that requires electric power. I’m attached to our sales division. Eaton also
must be considered when operations can’t be shut down, but we naturally try to
has service division that provides after-sales service on a longer-term basis.
avoid the expense involved in pulling a high-volume industrial process offline.
What does your job involve on a day-to-day basis?
Can you describe an interesting troubleshooting assignment?
I spend about 20 per cent of my time in the field, the rest in the office. Overall,
Names must be kept confidential, but I vividly remember working at a
about 85 per cent of my hours are spent working on VFDs [variable frequency
temporary oilsands pilot plant in northern Alberta. The pilot test involved a
drives] that control the speed of AC motors. Almost any processing facility
device inside a large separation tank. The plant hadn’t been winterized, so
will use VFDs. Integrating our VFDs into the two most popular controllers are
testing had to be finished before freeze-up, which was approaching quickly.
DCS [distributed control system] and PLC [programmable logic controller],
The control network kept crashing and we just could not identify why. After
but there are other kinds of controllers as well, and many manufacturers.
a temporary solution was identified, the company agreed to shut down its
For installations, a lot of my work involves integrating the protocols that
operation for 30 minutes — not a minute longer. Another technologist and I
control the different devices. There are many different protocols, many of
managed to install a second DeviceNet network in 22 minutes. After the pilot
them proprietary to specific manufacturers. Getting them to work together
test was finished, we finally did pin down the problem. Another manufacturer
can be tricky. When it comes to troubleshooting, the most common culprit is
had made an error in its firmware, a real ghost. Despite the stress, though, I
installation cabling. For example, someone may have placed a power cable
really enjoyed that job. OIL & GAS INQUIRER • SEPTEMBER 2010
75
The first patent for a spring-loaded mousetrap was issued in 1894. Since then, more than 4,400 patents for “better” mousetraps have been granted in the U.S. alone. Did you build a better mousetrap? Want to be recognized for the products, inventions, gadgets, or gizmos you’ve created?
Introducing the first ever Technology Stars competition in Canada! New Technology Magazine and Oil & Gas Inquirer have teamed up to recognize innovative stars in the oil and gas industry. If you’ve developed an interesting or groundbreaking new product, either in your grandmother’s basement or in a high-tech lab, we’re looking for you!
Nominate yourself or a buddy. Go online to find out more!
www.newtechnologystars.com Get your nomInatIons In now! CompetItIon Closes oCtober 15, 2010. to be elIGIble, a Company must operate In Canada, wIth Its produCt or servICe deployed here.
TOOLS
OF THE TRADE A LOOK AT NEW TECHNOLOGIES
One 4 Haul Mobile Structure
Who is Bear Den 4 Haul? Bear Den 4 Haul, a new division of Bear Slashing Ltd., is the official distributor of the Trans4mer Mobile Structure for One 4 Haul Trans4mer Ltd. Bear Den 4 Haul’s territory extends from Manitoba to the Pacific to the Arctic Ocean. Bear Den 4 Haul is responsible for servicing the clients’ needs during the warranty period and throughout the service life of the structure. What is the One 4 Haul Mobile Structure? The One 4 Haul Mobile Structure is a solid walled building that is pulled from location to location by a regular semi-truck. In transport mode, the dimensions of the self-contained trailer are 16 feet wide by 65 feet long by 14 feet high. The structure opens up to a building that is 30 feet wide by 40 feet long by 20 feet high. The structure is temperature-controlled and is built to support 65,000 pounds of snow load. It is insulated to a R20 factor, better than most homes. It comes with a four-ton overhead crane that transits the full 40-foot length of the building. The floor can support 90,000-pound loads. Beneath the floor is a double-walled, insulated, heated, 1,500-gallon holding tank to contain any fluids. On both ends of the structure are 14 by 16 feet steel overhead doors, which allow drive-through access and egress. It has its own power source, a 50kilowatt three-phase diesel generator to provide power for tools, lights and heat. What are the competitive advantages of the One 4 Haul Mobile Structure? This structure is unique. The advantages to this unit are: • Mobility: Set up and tear down in about one hour. It is able to transport 30 tons of equipment, spare parts and tools while configured for transport. • E nvironmentally friendly: Spill-containment tank in the floor prevents cross-contamination and damage to the environment due to spills. • Versatility: The structure has many uses, including a repair shop, wash bay, warehouse, office space, classroom and much more. • Safe, well-lit, temperature-controlled workspace in remote locations that will reduce turnaround times on equipment downtime. • A mong the many options are a four-ton overhead crane, wash bay kit, hoist of 15,000 pounds, water recycling unit and more.
Photos: One 4 Haul Trans4mer Ltd.
What future development plans do One 4 Haul and Bear Den 4 Haul have for the mobile structure? The primary markets are the oil and gas industry, as well as road builders and construction projects that have to move on a regular basis. One 4 Haul Trans4mer and Bear Den 4 Haul are currently concentrating their efforts in Canada but will be aiming at the U.S. market in a short period of time. Within the next year or so, the Mobile Structure will be introduced overseas. There are different new versions of the Trans4mer mobile unit in the forecast: the national defence and the high-end car racing are two of the main focuses for development. This sturdy structure can serve any purpose that requires selfcontained heat, power and plumbing, from workshop to wash bay. Answered by Ken Lengyel, Sales Manager, Bear Den 4 Haul
OIL & GAS INQUIRER • SEPTEMBER 2010
77
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SEPTEMBER 2010 • OIL & GAS INQUIRER
DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Diversified Glycol Services Inc . . . . . . . . . . . . . . 70 dmg world media . . . . . . . . . . . . . . . . . . . . . 34 & 63 Edmonton Exchanger & Manufacturing Ltd . . . . 45 EITI Electrical Industry Training Institute . . . . . . 60 Falvo Electrical Supply Ltd . . . . . . . . . . . . . . . . . . 72 Flexpipe Systems . . . . . . . . . . . . . . . . . . . . . 40 & 41 Gaugetech Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 General Motors of Canada Ltd . . . . . . . . . . . . . . 49 Imperial Oil Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Joint Economic Development Initiative . . . . . . . . 30 Kubota Canada Ltd . . . . . . . . . . . . . . . . . . . . . . . 35 Last Chance Trucking (1995) Ltd . . . . . . . . . . . . . . 47 LJ Welding & Machine . . . . . . . . . . . . . . . . . . . . . . 57 Lockhart Oilfield Services Ltd . . . . . . . . . . . . . . . 31 LoTech Manufacturing Inc . . . . . . . . . . . . . . . . . . . 72 Maxon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 MCI Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Mechanix Wear Canada . . . . . . . . . . . . . . . . . . . . 20 MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . . 37 NAIT Corporate and International Training . . . . . 46 Northstar Energy Services Inc . . . . . . . . . . . . . . . 4 OilPro Oilfield Production Equipment Ltd . . . . . . 72 Oomph Events . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 Opsco Energy Industries Ltd . . . . . . . . . . . . . . . . 74
Pembina Controls Inc . . . . . . . . . . . . . . . . . . . . . . 48 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 59 Phoenix Heli-Flight . . . . . . . . . . . . . . . . . . . . . . . 26 Platinum Energy Services Corp . . . . . . . . . . . . . . 17 Platinum Grover Int. Inc . . . . . . . outside back cover PrintWest Communications . . . . . . . . . . . . . . . . 62 Propak Systems Ltd . . . . . . . . . . . . . . . . . . . . . . . . 3 Prostate Cancer Canada Network . . . . . . . . . . . 65 Radafab Oilfield & Industrial Supply Inc . . . . . . . . 10 Silverado Oilfield Ventures Ltd . . . . . . . . . . . . . . . 72 Sprung Instant Structures . . . . . . . . . . . . . . . . . . . 7 Suncor Energy Inc . . . . . . . . . . . . . . . . . . . . . . . . 53 Systech Instrumentation Inc . . . . . . . . . . . . . . . . 67 Tank Gauging Systems . . . . . . . . . . . . . . . . . . . . . 74 TARM Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 TCA Marketing Ltd . . . . . . . . . . . . . . . . . . . . . . . . 67 Thames River Chemical . . . . . . . . . . . . . . . . . . . . . 15 The Geldart Group . . . . . . . . . . . . . . . . . . . . . . . . 32 Trans Peace Construction (1987) Ltd . . . . . . . . . . 64 Vertigo Theatre Society . . . . . . . . . . . . . . . . . . . 64 V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . 67 Westeel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 ZCL Composites Inc . . . . . . . . . . . . . . . . . . . . . . . 28
41/2” to 72” O.D. Pipe .205” to 1” Wall Thk. Cut/Weld to Length Servicing Canada and USA
Platinum Grover “The Piling Connection”