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A N o r t h A m e r i c A N L e A d e r i N e N v i r o N m e N tA L A N d e N e r g y s e r v i c e s Copyright Tervita Corporation 2012. EARTH MATTERS and the TERVITA logo are the trademarks of Tervita Corporation. All rights reserved.
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FEATURES
19
27
Idea Factory
The Global Brain Game
Finding solutions to global drilling and completion
Canadian energy industry borrows
challenges drives Canadian company growth
knowledge from around the world
By Darrell Stonehouse
By Darrell Stonehouse
G e n era l Ne w s
33 NEB forecasts gas deliverability decline
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REGIONAL NEWS
• River crossings • Underground intersects • Wetlands and water crossings
45
British Columbia
57
Artek expands on Inga condensate play
49
Northwestern Alberta Gas expenditures cut due to low prices
53
production on quickly By Lynda Harrison
Celtic predicts low gas prices will fuel demand
61
Northeastern Alberta Cenovus brings Christina Lake
Central Alberta Southern Alberta Producers testing southern Alberta Bakken/Exshaw tight oil plays By Richard Macedo
65
• Roadway and utility crossings • Slope and obstacle crossings • Harmful Alteration Disruption or Destruction (HADD) repairs to water crossing • Shore approaches and outfalls • Pipe ramming • Pipe bursting • Slip lining
Saskatchewan Fairborne sells Sinclair oil assets
T e c h n o l og y Ne w s
69
Tervita bringing in green service rig
IN EVERY ISSUE
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Stats at a Glance
78
Political Cartoon
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O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
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Imperial Oil is a trademark of Imperial Oil Limited, Imperial Oil, licensee. Mobil and the Pegasus design are trademarks of Exxon Mobil Corporation or one of its subsidiaries, Imperial Oil Licensee.
Editor’s Note
Darrell Stonehouse | dstonehouse@junewarren-nickles.com
Vol. 24 No. 5 editorial
Ending the
Editor
Darrell Stonehouse | dstonehouse@junewarren-nickles.com
Indian wars
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Another pipeline, another chapter in Canada’s ongoing Indian wars. This time it’s the Northern Gateway oil pipeline running from Alberta to the West Coast, with British Columbia First Nations claiming the pipeline crosses traditional lands so they should have a say in whether it is built. Echoes of the Mackenzie Valley natural gas pipeline all over again. First Nations objections to that pipeline have basically stalled it for a generation, along with the economic development it would bring with it. The stakes are equally high with the Northern Gateway and the recently announced expansion of the Trans Mountain oil pipeline, also being contemplated to carry oilsands crude to the coast for export. Tens of thousands of pay cheques and dividend cheques, along with billions of dollars in royalties and taxes, are on the line. It’s easy to blame the First Nations for standing in the way of progress when they protest industrial development like pipelines—easy, but wrong. The root of the problem, as usual, is government. The federal government has taken a paternalistic attitude toward the First Nations since the west was settled. Rather than allowing First Nations to integrate into the market economy, trading access to resources on their traditional lands for the revenues to pay their bills and build their businesses and communities, the federal government has injected itself as a middleman. It takes its cut from all economic activity in Canada, carving off a portion to fund First Nations. The disconnect between how this wealth is generated locally on traditional lands and how it is allocated by a far away government in Ottawa has created all sorts of economic disincentives for First Nations. After all, the money keeps flowing onto the reserves whether the wells are drilled, the mine is built, or the pipeline is constructed. At least until the tap runs dry. On the flip side, the local First Nation community assumes much of the direct environmental and social risks of industrial development, while not directly seeing a proportional amount of the financial rewards. It seems fairly obvious a realignment is necessary. Maybe rather than the current funding model, First Nations are paid a royalty as co-resource owners on development in their traditional territories. The key here would be to ensure it was a portion of current royalties rather than an add-on. With this new source of First Nations’ funding, federal government funding of reserves out of general revenues would be phased out. No more “Big Brother” giving them money and telling them how to spend it. Tying First Nations funding to local economic development would radically change negotiations between industry, First Nations and governments. It would align the interests of all three parties in making development happen. Would it end the Indian wars? Who knows? But it would be a damn sight better than what we have now.
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N E X T
I S S U E
July/August 2012 Tracking technological change in the Cardium and Beaverhill Lake/Slave Point tight oil plays. We also take a look at liquids-rich gas plays in west-central Alberta.
Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as "Letter to the Editor" if you want them published.
O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
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Stats AT A GLANCE
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
MONTH
OIL
GAS
OTHER
T O TA L
MONTH
OIL
GAS
D RY
618 428 298
509 197 97
46 12 15
81 183 88
1,254 820 498
728 1,531 904
Aug 2011 Sep 2011 Oct 2011
922 1,448 1,153
262 445 321
28 24 20
80 155 49
1,292 2,072 1,543
36 72 35
834 940 381
Nov 2011 Dec 2011 Jan 2012
1,170 988 419
331 359 190
27 27 15
42 115 31
1,570 1,489 655
50 55 127
718 717 671
Feb 2012 Mar 2012 Apr 2012
846 996 608
244 180 192
21 33 31
52 66 157
1,153 1,275 988
419 209 105
472 124 43
112 100 97
1,003 433 245
Aug 2011 Sep 2011 Oct 2011
452 1,028 626
183 357 259
93 146 19
Nov 2011 Dec 2011 Jan 2012
557 568 215
241 300 131
Feb 2012 Mar 2012 Apr 2012
491 515 403
177 147 141
Wells Drilled in British Columbia
Saskatchewan Completions
Source: B.C. Oil and Gas Commission
Source: Daily Oil Bulletin
WELLS DRILLED
C U M U L AT I V E *
MONTH
OIL
GAS
OTHER
TOTAL
Apr 2011 Jun 2011 Jul 2011
41 54 56
172 419 479
Apr 2011 Jun 2011 Jul 2011
183 217 185
11 25 5
11 89 3
205 331 193
Aug 2011 Sep 2011 Oct 2011
40 92 35
519 611 646
Aug 2011 Sep 2011 Oct 2011
413 352 457
2 4 29
13 29 46
428 385 532
Nov 2011 Dec 2011 Jan 2012
92 58 53
738 796 53
Nov 2011 Dec 2011 Jan 2012
524 332 142
4 4 10
32 61 8
560 397 160
Feb 2012 Mar 2012 Apr 2012
66 39 86
119 158 244
Feb 2012 Mar 2012 Apr 2012
296 414 172
6 0 0
20 40 49
322 454 221
*From year toto date * from year date
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T O TA L
Apr 2011 Jun 2011 Jul 2011
Apr 2011 Jun 2011 Jul 2011
MONTH
SERVICE
J UNE 2 0 1 2 • O I L & G A S I N Q U I R E R
FAST NUMBERS
50,000
13,500
Number of wells expected to be drilled in the United States in 2012 , says the Energy Information Administration.
Number of wells PSAC predicts for western Canada in 2012.
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada, May 11, 2012 Source: Rig Locator
Alberta, May 2012 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada
OIL WELLS
AC T I V E
Alberta
May 12
GAS WELLS May 11
May 12
May 11
Alberta
90
510
600
15%
Northwestern Alberta
155
149
114
179
British Columbia
22
32
54
41%
Northeastern Alberta
59
44
0
4
0
19
19
0%
160
201
13
91
13
106
119
11%
29
35
14
190
125
667
792
16%
403
429
141
464
Manitoba Saskatchewan WC Totals
Central Alberta Southern Alberta TOTAL
Service Rig Count by Province/Territory
Drilling Activity: CBM & Bitumen
Western Canada, May 11, 2012 Source: Rig Locator
Alberta, May 2012 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada Alberta
AC T I V E
C OA L B E D M E T H A N E
Alberta
May 12
May 11
BITUMEN WELLS May 12
May 11
305
454
759
40%
Northwestern Alberta
0
9
16
16
British Columbia
1
30
31
3%
Northeastern Alberta
0
0
57
44
Manitoba
1
14
15
7%
Central Alberta
1
39
54
76
Saskatchewan
105
96
201
52%
Southern Alberta
2
78
0
0
WC Totals
412
594
1,006
41%
TOTAL
3
126
127
136
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A IDEA D f cO Y factory Finding solutions to global drilling and completion challenges drives Canadian company growth By Darrell Stonehouse
Canada’s oilfield service and supply industry has been on a growth curve in the aftermath of a global financial meltdown that slowed exploration and development well into 2010. The extended-reach horizontal drilling and multistage fracturing revolution has spawned a wave of technological innovations by drilling services and completions outfits that are being quickly adopted by operators across North America. Canadian companies are now taking those innovations global. The rush in new tight formation drilling is now having trickle-down effects as manufacturers, production services and environmental companies follow the boom southward to the United States and around the globe.
O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
19
Feature
Drilling services The United States is the biggest market for drilling services in the world. In 2012, an expected 50,000 onshore wells will be drilled there, reaching the pre-economic bust levels from 2006 to 2008. The big difference is that the type of well being drilled has changed. Horizontal wells accounted for 16,100 of the over 42,000 wells drilled in the United States in 2011. This year around 18,600 horizontal bores are expected to be drilled. The preference for horizontal drilling in tight formations is driving well depths longer and longer. In 2006, drilling contractors punched 51,000 wells, with the total feet drilled coming in at 282 million. In 2011, 42,600 wells were drilled amounting to 328 million feet. Canadian drilling services contractor Precision Drilling Corporation has been a major benefactor of the growth in horizontal drilling tight formations in the United States. In 2011, Precision saw rig utilization grow by 17 per cent and day rates and margins increased by $3,586 and $2,715, respectively. The first quarter of 2012 has started out just as strong. Precision president and chief executive officer Kevin Neveu says demand for state-of-the-art drilling rigs for drilling horizontal wells is driving the company’s growth in the United States. “In the U.S. market we continue to experience strong demand for Precision’s Super Series rigs as customers recognize Precision’s high-performance, high-value services and capabilities to develop unconventional resources,” he told shareholders in Precision’s first-quarter report, adding that there is further growth to come.
“We are in discussions with several customers for new-build rigs to meet drilling challenges in unconventional oil–focused drilling plays such as West Texas Permian, the Mississippian Lime, the Bakken and the Niobrara.” But Neveu acknowledged that the U.S. market is changing as operators focus more on liquids and tight oil plays rather than the shale gas–driven boom of recent years. “The industry is experiencing regional activity and pricing softness in gas-driven markets. The decrease in gas-directed activity has been steep and swift with the U.S. gas–directed land rig count declining approximately 35 per cent or 315 rigs since October 2011,” he explained. “Precision has mitigated the impact by redeploying many of our rigs to oil targets; however, we do expect this regional gas–directed weakness to continue until the gas rig count reaches its bottom over the coming months. As a result of Precision’s rig redeployments over the past 16 months and new-build and upgrade rig deliveries, we have established stronger positions in the Bakken, Eagle Ford and horizontal Permian markets as well as some of the emerging oil and gas liquids plays. In the United States, Precision averaged 104 active drilling rigs, of which approximately 75 per cent were drilling for oil compared with approximately 55 per cent in the prior year comparable quarter. Precision’s current active count in the United States is 101 rigs.” Canada’s second-largest drilling company, Ensign Energy Services Inc., also continues growing in the U.S. market. In 2011, the company reported U.S. revenue of $727.7 million, an increase of
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J UNE 2 0 1 2 • O I L & G A S I N Q U I R E R
Feature
48 per cent from the $493 million recorded in 2010. The number of drilling days recorded by the company’s U.S. operations increased 37 per cent from the comparable period in the prior year, to 20,827 from 15,254 drilling days in 2010. Driving Ensign’s growth was the third-quarter purchase of Rowan Land Drilling and its fleet of 30 ADR-style drilling rigs. This acquisition significantly expanded Ensign’s operations into many of the resource plays of the southern United States. In addition, eight new ADR drilling rigs and 12 new well servicing rigs were added to the U.S. equipment fleet in 2011 as part of the company’s ongoing new-build program, combining to produce strong revenue growth in this segment. While Canadian drilling services companies have largely focused on the U.S. market, they are also targeting international growth. Precision is focused on growing operations in Central and South America, while working to gain a foothold in the Middle East. In late 2011, the company announced efforts were underway to develop drilling operations in Saudi Arabia, where it was sending three rigs. “This provides Precision with a revenue base and credible presence to continue our growth in the Arabian Gulf region,” Neveu said in November, adding the Saudi’s were in the market for a driller with experience drilling deep, high-pressure oil reservoirs. “Clearly, they’re anxious to get us in and see what we can do. We know we’ll do well. It’s an excellent market entry for us.”
In late April, Neveu said one rig was up and running in Saudi Arabia and the other two were expected to be drilling in May. Precision is also targeting growth in Central America. “We recently signed a long-term contract with an international service company in Mexico for three of our high-performance rigs; two to move from the U.S. and one rig to relocate from Colombia,” said Neveu. “Operations are scheduled to commence in the second quarter.” Ensign is also active internationally with rigs working in Latin America, Australia and the Middle East. In 2011, the company reported mixed results in its international operations. Increased operating activity in Latin America operations drove the improvement in revenue and activity in 2011 compared with 2010. Other regions experienced challenges outside of the company’s control, including disruptions of operations resulting from severe flooding in Australia and political unrest in parts of the Middle East and North Africa. Australian operations recovered in the second half of 2011; however, the company continues to focus on addressing challenges with respect to its Libyan operations that remain suspended since the civil unrest that started in the first quarter of 2011. Savanna Energy Services Corp. began its international expansion into Australia two years ago in an effort to find work for its hybrid drilling rigs built for Alberta’s shallow gas market. In January, the company reported its growth plan to expand into the coal seam–gas market in Australia, using its proprietary CT1500 hybrid drilling platform, as initial leverage was gaining momentum.
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O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
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Feature
“Savanna has achieved very positive market acceptance in Australia for its CT1500 to drill coal seam gas wells,” the company reported. “Savanna has, to date, delivered four CT1500 rigs, modified to meet Australian regulations. The first two of these rigs are currently working in the country under a five-year takeor-pay contract. The third and fourth rigs landed in Australia in January 2012. Both of these rigs will be field-ready in March 2012, with strong interest from several potential customers. Savanna is actively pursuing long-term contracts for these two rigs and is optimistic it will be able to do so given the level of interest expressed in the rigs to date.” These drilling rigs are in addition to the three high-spec workover rigs Savanna has already delivered, and which are working in the Bowen Basin. Savanna also expects to add one additional workover rig to Australia in mid-2012. Three of the four workover rigs are committed to long-term contracts while the fourth is currently working under a short-term contract. Canada’s rig manufacturers are also making their mark internationally. In early 2012, Red Deer, Alta.–based CARE Industries announced it had completed one of its most impressive drilling packages to date: Rig 120. Designed and manufactured for Tuscany International Drilling Inc., Rig 120 was delivered to Trinidad and Tobago, and it has been operational as of mid-November 2011. With over 27,000 hours of invested labour in this turnkey package, the use of three facilities, and a team of extremely dedicated
• • • • • • • • • • • • •
and committed employees, CARE manufactured its first Telescopic Double Drilling Rig to compete with the Pad Master Moving System. Equipped with 850 horsepower and a mast rated at 440,000 pounds, Rig 120 demonstrates CARE’s ability to offer a custom fabricated turnkey drilling rig package that was delivered on time and on budget, says the company. When fully operational, Rig 120 has the ability to physically move a million pounds from wellhead to wellhead through the use of the custom-designed Pad Master Moving System. The ability to move without removing the pipe from the mast on pad drilling work significantly reduces the cost and time spent on set-up and tear-down, greatly improving rig efficiency and overall operations.
Fracking outfits branch out Like with Canada’s drilling contractors, the country’s pressure pumpers and fracturing specialists are also growing in the giant U.S. market and branching out internationally. Calfrac Well Ser vices Ltd. is growing unconventional resource basin by unconventional resource basin in the United States. The company reported record revenue in 2011 as it followed operators from shale gas plays into tight liquids plays. “Record revenue and operating income were driven by an expanded presence in the Marcellus and Bakken resource plays, combined with a larger presence in the Niobrara oil shale play in the Rocky Mountain region,” said company president and chief executive officer Doug Ramsay.
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Three fracturing fleets are currently operating in that region’s Marcellus shale play. Early in the fourth quarter, Calfrac deployed a third fracturing fleet into the Bakken play of North Dakota. Near year-end Calfrac deployed an additional fracturing fleet into the emerging Niobrara oil shale play in northern Colorado and Wyoming. While the play is in the early stages of development, the company has taken a leadership position through its longstanding presence and established customer base. “The Marcellus shale play has evolved into one of the most economic natural gas–producing regions in the United States,” said Ramsay. “The company is completing the construction of a
play in Canada, this region was considered mature but has been revitalized using multistage fracturing techniques in horizontal wellbores. While still in the early stages of development, recent exploration successes by some of the company’s customers plus announcements of accelerated drilling by certain large area operators provide the basis for optimism.” Outside the United States, Calfrac continues growing in Russia, a long-time target for Canadian fracking and completion outfits. It is also focused on growth in Latin America. “The Russian well-servicing market is concentrated on the development of crude oil formations, which is expected to drive
“ Customer interest in horizontal completions and multistage fracturing is expected to increase in Russia during 2012.” new district facility in Smithfield, Pa., to service this play, which will provide the capacity to service not only the Marcellus but also a large part of the emerging liquids-rich Utica shale play. Calfrac recently completed its first significant project in the Utica play. “The third area of growth for Calfrac in the United States market is the emerging Niobrara oil shale play of northern Colorado and Wyoming,” said Ramsay. “Similar to the Cardium
— Dale Dusterhoft, president, Trican Well Services
improvement in the demand for the company’s services in Western Siberia,” said Ramsay. “In Mexico, completions activity continued to improve during the fourth quarter of 2011 as a focus towards greater onshore development was realized throughout the past year, reviving activity from the lows experienced in late 2010. Calfrac’s activities remain concentrated on oil-producing regions due to the current strong commodity price environment. Calfrac anticipates continuing to deploy innovative technologies into this
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market as it collaborates with its customers to enhance oil and natural gas production, and financial returns.” “The company remains encouraged by the development of a number of emerging unconventional oil and natural gas plays in Argentina which are expected to stimulate further oilfield activity over the longer term,” Ramsay added. “Similar to North America, horizontal drilling combined with multistage fracturing is anticipated to be integral to unlocking the large development potential of these reservoirs. In response to these market opportunities, Calfrac deployed additional cementing and coiled tubing equipment in 2011 and expects to commence fracturing operations in Argentina during 2012.” Calfrac also commenced cementing operations in Colombia late in the year and continues to increase the size of its operations in this emerging international market through the deployment of additional capital and expansion of its customer base. “Calfrac continues to execute its geographical diversification strategy of deploying its technology and brand into selected international markets,” said Ramsay.” The entry into Colombia is consistent with Calfrac’s international expansion strategy of using cementing or coiled tubing operations, which require a smaller initial capital investment, to provide an opportunity to build a market presence prior to the potential deployment of fracturing equipment. The company expects that the emerging Colombia market will provide significant opportunities for growth.” Trican Well Services Ltd. is also focused on diversifying internationally, with a focus on emerging U.S. unconventional plays. In the final quarter of 2011, Trican added a fracturing crew in the Eagleford shale play, and early in 2012 crews began operations in Oklahoma and the Permian Basin in Texas. Trican’s international operations are located in Russia, Kazakhstan, Algeria and Australia. In Russia, Trican is working hard to introduce the drilling and completion revolution in unconventional resources into the marketplace. Trican has established a research and development centre in Moscow as part of a long-term agreement with Gubkin Russian State University of Oil and Gas. The facility will focus on enhancing oil and gas production through the development of new technology for drilling and completion applications throughout Russia and surrounding areas. “Customer interest in horizontal completions and multistage fracturing is expected to increase in Russia during 2012. Several successful pilot projects were completed in 2011, and we expect this momentum to continue into 2012,” company president Dale Dusterhoft reported to shareholders in his annual review. “Our 2012 strategy in Australia will be to expand our cementing service line by building new customer relationships and offering high-quality service,” said Dusterhoft. “We expect to add to the current cementing fleet during 2012 as we continue to establish ourselves in the region.” Like Precision, Trican is also working to establish a foothold in Saudi Arabia. “In Saudi Arabia, we are working to establish our presence in the market and continue to expect to participate in pressure pumping tenders in 2012,” he said. “Revenue from this region is not expected to be significant during 2012, as we will focus on establishing customer relationships and a reputation as a high-quality service provider.”
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The Global
BrainGame Canadian energy industry borrows knowledge from around the world By Darrell Stonehouse
I
n an age of globalization, good ideas know no geographical or industrial boundaries. A lber t a’s oi l sa nds a re becoming major beneficiaries of this economic openness as multinational companies with huge research and development departments focus their attention on solving many of the technological and environmental challenges facing the industry.
...
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General Electric (GE) is one example of this trend. The global industrial conglomerate has established a joint technology development program with Suncor Energy Inc. to help Suncor meet its sustainability objectives, while increasing facility reliability and efficiency. James Cleland, GE’s regional leader of heavy oil solutions for the Americas, says the two companies have worked together on four or five different projects, with the majority focusing on water management. Cleland says GE provides Suncor with a deep pool of knowledge and technologies to meet its operational and sustainability challenges. GE has an operational location in Fort McMurray, Alta., along with a heavy oil research centre in Calgary, focused on providing solutions. “When you talk innovation, GE has over 22,000 patents,” Cleland notes. “We have over 40,000 technical people worldwide, with 2,600 dedicated to research. There are 1,000 PhDs among them.” “We’re well-positioned to package solutions—technology, products and services,” he explains. “We look at understanding the challenges facing the industry as it grows and evolves and at improving on its operational performance and its bottom line.” Suncor’s steam assisted gravity drainage operations have been one beneficiary of the partnership with GE. Suncor’s MacKay River and Firebag sites use a system developed by GE that recycles water in a closed system for steam generation, requiring minimal makeup water. Another effort at Suncor’s Edmonton refinery is also paying dividends. Approximately 50 per cent of water used at the refinery is
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recycled from the Gold Bar waste-water treatment plant, saving 1.6 million cubic metres of fresh water from the North Saskatchewan River. Cleland says the Edmonton refinery project is win-win for all parties involved. “It delivers Suncor more water while reducing sewage costs for the City of Edmonton,” he says. Suncor also participates in the Oil Sands Leadership Initiative (OSLI) collaborative network, along with ConocoPhillips Canada, Nexen Inc., Shell Canada Limited, Statoil Canada Ltd. and Total E&P Canada Ltd., addressing land stewardship, water management, technology breakthroughs and sustainable communities. Oilsands mines produce tailings—leftover material produced during the extraction process that separates bitumen from the sand. Working with GE’s Global Heavy Oil Centre of Excellence in Calgary and with GE’s Water & Process Technologies business, OSLI tested multiple processes to reclaim tailings water for reuse within oilsands operations as part of a larger Regional Water Management Solutions project. Reclaiming and treating “used” waste water from oilsands surface mining operations allows operators to reclaim and reuse water stored in tailing ponds, thereby reducing the amount of new water required as make-up water to generate steam at most in situ operations. Global consulting firm Deloitte & Touche believes that oilsands players are missing the boat by not looking outside the industry for potential answers to their productivity and sustainability challenges. In their report, Gaining ground in the sands 2012, the
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consultants say for too long the culture in the industry has prevented it from taking a broader worldview. “Producers with a strong conventional oil and gas orientation often embody corporate cultures that celebrate the industry’s roots in the early wildcatting days of petroleum exploration,” Deloitte notes. “This, however, is increasingly at odds with the demands of oilsands development today. Challenges such as environmental oversight, cost containment and social performance are not as effectively addressed in some of the older ways of doing business that promoted staunchly independent or even adversarial attitudes.” However, the report says this attitude is changing as oilsands operators look closely at issues such cost containment, waste reduction, and overall process reliability and efficiency. “Borrowing models and methods from the automobile and high-tech sectors specifically, more and more oilsands producers are implementing contemporary manufacturing approaches such as Lean Improvement and Six Sigma processes to bring about savings and efficiencies of no small significance,” Deloitte says. Adopting lean processes has reduced cycle times to first oil or gas by 30–50 per cent, reduced overall operational costs (including fabrication and construction) by 15–20 per cent, and eliminated non-productive activity (recruiting, training, housing and moving people) by more than 50 per cent, reports Deloitte. “We also see, however, where there is now opportunity for the industry to take these early steps with manufacturing models to the next level,” the company adds. “Specifically, we encourage w ider industr y collaboration and bestpractices sharing around all such continuous improvement
Suncor's Edmonton refinery. A partnership with GE has led to major improvements in water sustainability at the refinery.
and just-in-time processes that would take supplier relationship management well beyond individual supplier-producer t r a n s ac t ion s, a nd b e c ome c on si s te nt a nd i nteg r ate d practice across the entire industr y and supply chains.” The consultant report says oilsands developers can benefit
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from more than just processes used in other industries. It points out that it can also borrow technologies as well to cut costs. “For a sector enabled at the ground level almost entirely through technical capacity and technology, it is somewhat paradoxical that industry has not paid more attention to advanced technologies developed elsewhere in the world and/or in other sectors that carry potential benefits to oilsands operations–especially when many of these technologies can help mitigate labour crunches,” Deloitte notes. The consultants point to remote-sensing equipment or remotely controlled vehicles as technologies that could be game-changers. They add that such technologies could also enhance data flow and safety
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The partnership with GE has also led to improvements in water recycling at Suncor's SAGD operations.
The Dreaded CRA Tax Audit: tax tips for the self-employed
Does the CRA target small business owners and the self-employed?
I am being audited. What can I do to lessen the potential blow?
The CRA focuses on those groups who are more likely to omit or misrepresent information on their tax returns, one of whom is, according to the CRA, the self-employed.
1. Consult a tax lawyer. Yes, a tax lawyer is advising you to consult a lawyer. Nevertheless, the key to being audited without your tax bill doubling is to ensure the audit is conducted fairly - without intimidation. This is best achieved with the representation of a tax lawyer, who is trained to know the law and the CRA’s internal policies and, unlike other tax professionals, is trained to fight for your rights. 2. Be nice. No one likes being audited, but taking it out on the auditor will get you nowhere. 3. Be on guard. Avoid getting chatty and volunteering more information than necessary that can later be used against you. 4. Be organized. It may be tempting to dump a box full of financial records onto the auditor’s lap, this will only serve to motivate the agent to work harder to find omissions and mistakes in your return. Keeping your records organized will, at the very least, lend credibility to you as a responsible businessperson.
Is there anything I can do to avoid a tax audit? The following strategies can be used to reduce the number of red flags that may come up with your file, thereby reducing the likelihood of an audit: 1. File on time! Nothing places a red flag faster than a late tax return, so get your return in by the deadline. The same holds true for filing too early. 2. Be honest and consistent. The CRA has tools to investigate and gather information about your industry. If your numbers don’t fit the typical profile, then chances are you will be audited. Also, major changes in income, expenses or tax deductions from one year to the next will raise suspicion. 3. Avoid declaring business losses year after year. A reasonable amount of losses is fine; however, continuous business losses over a few consecutive years will alert the CRA. 4. Select your partners wisely. Any close association you make with other businesses or individuals who had or currently have problems with the CRA may result in a tax audit.
5. Inform yourself. Knowing your rights will help you be better prepared when facing an audit. The CRA publishes the Taxpayer’s Bill of Rights, and although some of these rights are not technically legal rights, it is still useful to know the principles behind which the CRA hopes to conduct their tax audits.
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General News
NEB forecasts gas deliverability decline NEB gas deliverability based on three price scenarios
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The National Energy Board is predicting natural gas deliverability will decline in the next few years as supply continues outstripping demand.
Canadian natural gas deliverability is expected to decline between now and 2014 as demand continues to grow, but still remains well ahead of supply, says a new National Energy Board (NEB) energy market assessment. In its study, Short-term Canadian Natural Gas Deliverability 2012-2014, the board sets out lower, mid-range and higher-price cases for natural gas based on varying market factors. In the middle-case scenario, the NEB expects the current oversupply of gas in North America to continue to drive Canadian and U.S. natural gas prices below 2011 prices of US$4 per million British thermal units (mmBtu). A lthough prices are expected to rise gradually to $4.50 per mmBtu in 2014 from $3.75 per mmBtu this year, producers would continue to reduce drilling, especially for dr y gas, as much of it would still be uneconomic, says the study. Natural gas drilling would occur where natural gas liquids content is high enough to make production economic.
The same case forecasts that Canadian gas prices would increase to C$3.69 per gigajoule in 2014 from $3.11 per gigajoule this year. With a decrease in overall gas drilling, Canadian daily production would decline to 13.2 billion cubic feet in 2014 from 14 billion cubic feet in 2013 and 14.5 billion cubic feet in 2012, while U.S. production growth would slow. (Western Canada accounts for 98 per cent of marketable gas production, with Nova Scotia and New Brunswick contributing most of the remaining volumes, while minor amounts come from Ontario, the Northwest Territories and the Yukon.) A gradual increase in demand for natural gas would reduce the supply, and prices would begin to rise and slowly increase, says the study. Increased oil-targeted drilling with associated and solution gas will contribute additional gas to overall production, but total gas deliverability will still be less than deliverability of 14.6 billion cubic feet per day in 2011, according to the NEB.
In t he mid-range pr ice case, Canadian natural gas deliverability will continue to be well above Canadian demand, although the rate of decline in overall deliverability would slow slightly due to higher-productivity wells coming on stream. Tight gas and shale gas activity is forecast to stabilize in 2012 with 229 wells drilled in the Montney and 39 in Horn River. Horn R iver deliverabilit y would decline to 522 million cubic feet per day in 2014 from 555 million cubic feet per day this year, while Montney deliverability would increase to 1.95 billion cubic feet per day from 1.62 billion cubic feet per day in the same period. In the mid-range case, the number of Canadian gas-intent wells drilled would decline to 1,384 in 2014 from 2,159 wells in 2012 and 1,755 wells in 2013. Last year, producers drilled an estimated 2,782 gas wells. At the same time, gas wells’ share of drill days is projected to decline to 20 per cent in 2014 from 25 per cent in 2013 and 30 per cent this year. In 2011, gas wells accounted for 37 per cent of drill days. Slowing gas-drilling activity and rising natural gas demand would begin to reduce the oversupply conditions and growth in Canadian natural gas demand, and would account for a greater proportion of the country’s available deliverability, reducing the net volumes available for export. Between 2012 and 2014, in the midrange case, total Canadian demand would increase by 600 million cubic feet per day to 9.8 billion cubic feet per day from 9.2 billion cubic feet in 2012. Forecast demand in 2013 is 9.4 billion cubic per day. In 2011, Canadian gas demand was 8.9 billion cubic feet per day. According to the study, the growth in demand between 2012 and 2014 would be led by western Canada, where demand would rise by 400 million cubic feet per day, due mainly to Alberta oilsands O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
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requirements. Eastern Canadian demand will grow more slowly, with an increase of 200 million cubic feet per day. In the lower price-case scenario, the NEB forecasts gas prices increasing to US$3 per mmBtu at Henry Hub from $2.50 in 2012 and $2.75 per mmBtu in 2013. Canadian prices are projected to rise to C$2.15 per gigajoule at AECO in
2014 from $1.86 this year and $1.98 per gigajoule in 2013. This case is based upon persistent oversupply with new drilling mainly targeting liquids-rich natural gas. Deliverability would decline steadily to 12 billion cubic feet per day in 2014. In the NEB’s higher case, current oversupply conditions would end by 2014, pushing up gas prices to US$6 per mmBtu
(C$5.22 per gigajoule at AECO), resulting in dry gas once again becoming economic. As increased drilling would only begin to have an effect later in the projection period, deliverability would continue to decline, but to a lesser extent (13.6 billon cubic feet per day in 2014 from 14.6 billion cubic feet per day in 2012). — Daily Oil Bulletin
Industry applauds effort to cut regulatory review red tape
Federal government efforts to streamline project applications for projects like major pipelines are being greeted optimistically by industry.
The oil and gas industry is happy with the federal government’s budget pledge to streamline the regulatory review process for major economic projects. The much-delayed Mackenzie Gas Project is often held up as the poster child for unnecessary laborious and timeconsuming reviews. With several other important energy projects on the table— 34
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namely Enbridge Inc.’s Northern Gateway, which would deliver crude overseas—the federal government’s move toward a “one project, one review” approach drew widespread industry praise. Brenda Kenny, president and chief executive officer of the Canadian Energy Pipeline Association (CEPA), says that her group strongly supports the move towards
a more effective, efficient and timely regulatory process. “A n i m p r o v e d p r o c e s s w o u l d allow environmental assessments to focus on major environmental concerns that could amount to a show stopper,” she says. “If [a] project is to proceed, specific environmental considerations should be addressed by environmental regulation, at a later stage. At that point, industry and other stakeholders’ resources could be allocated more efficiently.” CEPA supports the one-project, onereview approach with time certainty by the best-placed regulator in considering major pipeline projects. “In the case of most CEPA member compa n ies, it wou ld l i kely be t he National Energy Board,” she says. “The NEB has an in-depth k nowledge of safety, environmental and social factors linked to major pipeline projects, as well as the experience to balance local and national interests. In addition, we’re pleased to see that the federal budget is increasing resources to improve pipeline safety through better monitoring and auditing.” CEPA believes a streamlined approach will allow project proponents, regulators and stakeholders to focus on developing and implementing practical solutions that will make a real difference. “Our member companies typically spend between three to five per cent of their capital costs on environmental assessments and regulatory processes. This equates to
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By Richard Macedo
General News
approximately $30 million–$50 million, based on a $1-billion project,” Kenny says. “We support thorough reviews that focus on important environmental and social considerations. In doing so, we can deploy technical expertise and resources to address environmental and social issues, enhance best practices and develop new technologies.” The group also supports initiatives that will alleviate labour constraints in Canada. “CEPA intends to provide input to these initiatives to ensure that pipelinespecific issues are considered and incorporated in the federal government’s plan,” she says, in reference to the government’s intention to better align the Temporary Foreign Worker Program with labour market demand. Travis Davies, a spokesman with the Canadian Association of Petroleum Producers (CAPP), added that regulatory changes broadly outlined in the budget will improve Canada’s business climate and competitiveness without compromising industry’s commitment to responsible, sustainable development. “The government’s plan will improve the timeliness and efficiency of the decision making process while the regulatory scrutiny that Canadians expect remains intact,” he says. “We must move to more efficient processes, time-limited decision making and better coordination both within and among governments to eliminate regulatory overlap. Today’s announcement is a positive step and we look forward to the federal government continuing to advance its regulatory plan. That said, the environmental outcomes remain the same.” As for the Temporary Foreign Worker Program, Davies notes that one of the largest challenges Canada’s oil and gas industry and other sectors of the economy currently face is a looming shortage of skilled labour to support growth. “Current and growing workforce shortages are no longer cyclical in nature, and we are entering into a time of global, chronic and sustained skilled labour shortages, a situation that is expected to remain in the long term,” he says. “Canada’s oil and gas industry believes in hiring Canadians first, and supports training and measures to increase labour mobility within Canada. Given the numbers of skilled people needed, we also believe we must look
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beyond our borders and take steps to increase economic immigrants and temporary foreign workers.” The government is also phasing out the Atlantic Investment Tax Credit (AITC), and Davies notes that the measure builds on the federal government’s G20 commitment to reduce and/or eliminate subsidies for fossil fuels. “However, we do have concerns it is discriminatory towards the oil and gas industry insofar as the AITC will still be available for non-oil and -gas and non-mining activities,” he says. “CAPP and our members operating in Atlantic Canada will continue to address this issue with government.”
He adds that CAPP made a budget recommendation for a temporary accelerated deductibility for natural gas drilling and completion expenditures, aimed to aid the industry through a near-term challenging business environment. “Despite extensive consultations and support from the province of Alberta, the budget did not include this measure,” Davies says. “However, some of the enhancements in competitiveness of the regulatory system will benefit the natural gas industry, which continues to face considerable challenges in terms of commodity price.” Environmental groups, meanwhile, panned the government’s moves toward regulatory efficiency.
“The plan to weaken one of Canada’s foremost environmental laws outlined in today’s budget is nothing more than a gift to Big Oil,” said Gillian McEachern, Environmental Defence Canada deputy ca mpa ig n di rec tor, i n a prepa red statement. Jessica Clogg, executive director and senior counsel at the West Coast Environmental Law, adds that the budget announcements “make it clear that longstanding legal protections for the environment, including environmental reviews of major industrial projects like mines and oil pipelines, will soon be rolled back or eliminated.”
PSAC slightly lowers drilling forecast The Petroleum Services Association of Canada (PSAC) expects a slight increase in Canadian drilling activity levels for the year, but it’s lower than previously forecast, the industry group announced in its second-quarter update. The revised forecast for 2012 predicts a total of 13,150 wells will be drilled (rig released) across Canada, representing a two per cent increase in total wells drilled
conditions, including the European debt crisis. PSAC is basing its updated 2012 forecast on average natural gas prices of $1.90 per thousand cubic feet at AECO and a West Texas Intermediate crude oil price of US$100 per barrel. “There have been some conditions that have impacted expected drilling activity that were beyond our industry’s control,” Mark Salkeld, PSAC’s president, said in a
the prominent well type and technology, according to Salkeld. PSAC is forecasting that horizontal wells will account for more than half of all well types this year, a marked increase from the horizontal well count of 2007, which levelled out at only 13 per cent of total wells. On a provincial basis, PSAC is forecasting that 7,949 wells will be drilled in Alberta in 2012, down two per cent from
The days of 20,000-plus wells are likely not to return any time soon, due largely to the fact that operators are drilling longer and more complex wells. over 2011. The final tally for 2011 was 12,850 total wells drilled. The 2012 revised forecast represents a slight reduction of 200 wells from PSAC’s January update, which pegged activity for the year at 13,350 wells. The association attributes the decrease largely to the decline in natural gas drilling due to record-low natural gas prices. The overall forecast well reduction since November is based on declining gas prices, labour shortages, balmy weather at the outset of the year and world economic 36
J UNE 2 0 1 2 • O I L & G A S I N Q U I R E R
statement. “That said, productivity so far this year is high and activity is still on the uptick.” The days of 20,000-plus wells are likely not to return any time soon, due largely to the fact that operators are drilling longer and more complex wells that are accessing plays once thought unreachable or fully tapped, he added. The first quarter of 2012 saw the average well depth reach beyond 2,000 metres and that is a sure sign that the industry now operates very differently than only five years ago, when vertical wells were still
2011 final drilling numbers of 8,146. It anticipates that British Columbia will be hit hardest by low gas prices with a projected five per cent decline to 591 wells drilled from 620 in 2011. Saskatchewan and Manitoba—both predominately oil players—are expected to post positive increases this year and again set new records, with Saskatchewan experiencing a 13 per cent increase to 3,962 wells drilled, up from 3,492, and Manitoba a six per cent increase to 618 from 583 last year. — Daily Oil Bulletin
General News
First Nations a major obstacle to Northern Gateway Opposition from First Nations on British Columbia’s west coast remains a “significant obstacle” to the development of Enbridge’s proposed $5.5-billion Northern Gateway pipeline, says a senior Enbridge official. “We still see it as a material concern among coastal First Nations,” said John Carruthers, president of Enbridge Northern Gateway Pipelines, following an address to the Canadian Energy Research Institute (CERI) 2012 oil conference. “There’s a lot ahead of us in building support among the coastal First Nations.” In a panel discussion entitled Another Nat iona l Drea m — How to Ma ke It Happen, Carruthers said there is increasing interest among some First Nations in taking an equity interest in the project, although he would not reveal which of the 40 First Nations along the pipeline route from northern Alberta to Kitimat, B.C., have shown an interest. “We are offering $1 billion in opportunities,” he said. Carruthers was one of six speakers who fol lowed federa l Nat u ra l Resources Minister Joe Oliver’s keynote speech, Becoming a Responsible Energy Superpower, which was closed to the media. The minister also chose not to speak to the media directly, saying the fact that his address coincided with the day of a provincial election in Alberta made it inappropriate to do so. Those who heard his address said it was largely a repeat of past statements he has made about the need for Canada to fully develop its oil and gas and other resources in an environmentally acceptable manner. Oliver cited impediments to that development, including opposition by environmentalists and others to oilsands extraction, which he described as a “vocal minority” using “scare tactics” to stop or slow down oilsands expansion. Oliver defended his government’s recently announced plan to expedite the review process for major resource projects in Canada, placing a two-year time limit on the review of such projects by federal regulatory bodies. He denied the move was an attempt to reduce environmental
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standards in Canada, saying his government is spending $165 million to protect the environment, including stepped-up enforcement of pipeline and tanker safety. In a question-and-answer session after his address, Oliver touched on the opposition by aboriginals to resource development projects such as Northern Gateway, saying he has detected what he calls “intergenerational conf lict ” with some older First Nations residents opposing such projects and younger, unemployed residents wanting to see the development proceed. Enbridge’s Carruthers told those attending the conference that Northern Gateway, which would move 525,000 barrels of oil per day of oilsands crude daily to Kitimat and then to Asian markets, would provide a significant economic boost to Canada, generating $81 billion in overall tax revenue and $270 billion in economic benefits. It would also account for $48 billion in income to workers overall and create 558,000 person-years of employment. However, he cited the “strong concerns” from First Nations and others about the project, which he suggested stem mainly from the fact it will move oilsands crude, seen as more environmentally suspect than other fossil fuels. The company continues ongoing consultations with the 40 aboriginal communities living within 80 kilometres of the proposed pipeline route, said Carruthers. “They want to know what are the chances of a pipeline rupture and a spill,” he said. Those concerns were heightened by a major spill two years ago from an Enbridge pipeline in Michigan, which Carruthers described as a “very humbling experience” for the company. Enbridge and others have taken a number of measures to enhance pipeline safety, including choosing less-intrusive pipeline routes, using strong steels in the construction of pipelines and using sophisticated monitoring of pipelines, the conference heard. “We think we can design a pipeline through the coastal mountains of B.C. with the chance of a spill [being] once in 1,000 years,” said Carruthers. And he said the chances of a spill in the coastal waters would be very remote, adding that Enbridge has calculated the odds of a spill of any kind occurring in the waters of the West Coast from the tankers it will use occurring once in 350 years.
General News
The chances of a disastrous Exxon Valdez–type spill occurring, which would leave a serious slick behind, are one in 15,000 years, according to Carruthers. In the question-and-answer session that followed, he was asked whether total tanker traffic would be a concern if Northern Gateway and some of the six liquid natural gas (LNG) export terminals being planned for the coast go ahead. “Enbridge will load 220 tankers a year and the LNG terminals will involve less than that,” he said. ”In Norway, in a similar environment, there’s 10 times that tanker traffic.” — Daily Oil Bulletin
WCSB wells getting deeper Operators across Canada drilled 7.35 million metres of hole during the first quarter of 2012, up about nine per cent from 6.76 million metres that were rig released in the first quarter of 2011. The total number of wells rig released was off year-over-year, however, with 3,576 wells drilled during the first quarter, down 7.67 per cent from 3,873 wells drilled in the first three months of 2011. For the first time, the average depth/ length of wells in western and northern Canada during the first quarter rose to over 2,000 metres—hitting an average 2,054 metres, up close to 18 per cent from 1,744 metres a year ago. The number of wells drilled over the quarter was down in Alberta (17.33 per cent) and British Columbia (5.47 per cent) compared to a year ago, level in Manitoba (up 1.04 per cent) and up significantly in Saskatchewan (22.82 per cent). Saskatchewan’s three-month rig release tally rose to a high of 974 from 793 in last year’s first quarter, with metres drilled lifting to 1.57 million metres from 1.35 million metres last year. In Alberta, rig releases for the quarter declined to 2,213 from 2,677 a year earlier, although metres drilled rose 6.9 per cent (cont. on page 42)
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General News
to 4.73 million metres from 4.42 million metres in January to March 2011. Gas-focused British Columbia saw quarterly rig releases decline to 190 wells from 201 wells a year ago, while operators working in Manitoba drilled 195 wells over the first three months of 2012, about even with 193 wells drilled a year ago, but still a record. Metres drilled in British Columbia rose to 674,601 from 620,888 metres drilled in the first quarter of 2011, and Manitoba’s metres drilled climbed to 363,767 from 350,870 in the year-prior quarter.
Preliminary data suggest less than 15 per cent of the wells being drilled are resulting in gas wells this year, down from about 27 per cent last year, 44 per cent in the first quarter of 2010 and 69 per cent in 2009. Of the wells rig released in the first quarter in Alberta, 1,466 were licensed to drill for oil or bitumen, about even with last year’s 1,453 wells and up from 1,083 wells in 2010 and 390 wells in 2009. By contrast, gas and coalbed methane (CBM) wells in Alberta declined to 459
from 895 rig releases in the first quarter of 2011. In 2006, close to 5,000 gas and CBM wells were rig released during the first quarter. In Saskatchewan, 924 of the wells drilled were licensed to search for oil, while only eight were targeting natural gas. Operators in western and northern Canada rig released 6.16 million metres of development hole—another record— compared to 5.62 million metres a year ago. — Daily Oil Bulletin
Talisman Energy Inc.—which has agreed to sell about $1 billion in assets this year— says it will cut its 2012 capital budget by roughly $400 million as it curtails dry natural gas activity. During the rest of this year, Talisman expects to spend only about $200 million on dry gas activities in North America, primarily to maintain land and options for the future. In January, Talisman projected capital spending of just over $4 billion, a drop of roughly $500 million from 2011. The company now expects to spend $3.6 billion on this year’s exploration and development.
“I see no reason to continue spending money in dry gas shales when it doesn’t remunerate,” Talisman president and chief executive officer John Manzoni told the company’s first-quarter earnings conference call. During the quarter, the company also reported higher production, cash flow and revenue. Production was up with record sales in Southeast Asia and higher volumes in Colombia and North American shale. Liquids volumes in Southeast Asia and North America are up 35 per cent yearover-year.
Talisman is cutting spending on dry gas plays like the Marcellus in the northeast US.
Talisman reported good progress toward its asset disposal target of $1 billion– $2 billion. It completed the sale of a coal asset in the first quarter for $500 million and expects to complete the sale of its noncore Shaunavon and Whitecourt assets in the second quarter for $450 million. Under its initial $4-billion budget, the company would have operated three rigs in the Marcellus shale. Under the revised budget, it will run only one rig in the Marcellus, Manzoni said. In the Montney, by contrast, planned activit y is unaffected. In that play, Talisman is partnered with Sasol Limited, which is paying most of the cost. “Gas prices in North America continue to reflect the combination of oversupply and the unusually warm winter. Gas prices have remained below what we consider to be a necessary long-term equilibrium price,” Manzoni told analysts. “With the injection season now upon us, it’s quite possible that this gets even worse before it gets better—and we’ve adjusted our capital plans accordingly,” he continued. “There are some early voices of optimism that the coal switching, which has occurred over the last quarter, will play a role in accelerating a recovery,” Manzoni said. “But I don’t think anyone is expecting positive news until at least the end of this year, and we need to be ready for this to last well into 2013.” — Daily Oil Bulletin
42
J UNE 2 0 1 2 • O I L & G A S I N Q U I R E R
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British Columbia
Artek expands on Inga condensate play
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Artek continues showing great results on its Inga Doig condensate play, expanding the play to the north.
Artek Exploration Ltd. has successfully drilled and completed the first of seven horizontal wells (60 per cent working interest) planned for 2012 at its Doig natural gas and condensate pool in the Inga area of British Columbia. The well is the furthest north step-out to its previous horizontal Doig wells in the pool, which tested at an average rate of over 2,000 barrels of oil equivalent per day with approximately 1,600 barrels per day of condensate. After an 80-hour test that was conducted in-line and still cleaning up, the horizontal well was flowing at an average rate of 2,366 barrels equivalent per day, of which approximately 6.5 million cubic feet per day was natural gas (15 per cent load methane) and 1,283 barrels per day was condensate as measured at the company’s facility, for a total of approximately 2,200 barrels per day (58 per cent condensate)
net of load over the last five hours at a f lowing pressure of 1,172 pounds per square inch. The latest test, which is one of Artek’s best results to date, further supports the productivity and liquids potential of the reservoir at the north end of the pool, the company says. The well was drilled to a lateral distance of approximately 1,367 metres and was stimulated using a 14-stage hydrocarbon fracture program. The company is currently drilling out its second 2012 Doig horizontal at Inga, which it expects to be completed in May. Subsequent to breakup, the five remaining horizontal wells in Artek’s Inga gas/ condensate drilling program are planned to be drilled from June through November with all wells anticipated to be completed and on production by year-end. Also in the first quarter of 2012, the company drilled and completed two
additional horizontal wells in the Peace River Arch (PRA) area of Alberta, targeting intermediate-depth Triassic light oil. The first was completed using a 13-stage hydrocarbon fracture program, and after a 111-hour test period, the well was flowing at approximately 149 barrels equivalent per day (54 per cent light oil) and about 858 barrels of water per day. The second horizontal well was completed using an 11-stage water-based fracture program and after 96 hours, tested at approximately 180 barrels equivalent per day (64 per cent light oil) and approximately 810 barrels of water per day. Three horizontal wells on the PRA Triassic oil play have been drilled to date with the average test rate meeting management’s expectations at 246 barrels equivalent per day (130 barrels of oil per day and 725,000 cubic feet per day of rich natural gas) with approximately 1,300 barrels of water per day. The company disposes the water from the wells at its 100 per cent–operated water disposal facility and sends its rich natural gas to a third-party deep-cut facility where it realizes a further 40–50 barrels per million cubic feet of liquids-yield from its rich natural gas. Results to date, and company mapping, support an additional 22–30 horizontal locations targeting light Triassic oil in the Dunvegan to Cecil corridor of Alberta, where Artek has accumulated over 60 (57 net) sections of land. An additional horizontal well is planned on an undeveloped land block targeting Triassic oil in the PRA in the second half of the year. In addition, the company anticipates starting its four-well (1.6 net) development program targeting Glauconite oil at Leduc Woodbend this summer, which is anticipated to be complete in September. — Daily Oil Bulletin
BRITISH COLUMBIA WELL ACTIVITY
APR/11
APR/12
WELL LICENCES
78
29
▼
APR/11
APR/12
WELLS SPUDDED
40
23
▼
APR/11
APR/12
WELLS DRILLED
40
22
▼
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
45
British Columbia
Advantage slows Glacier development
46
J UNE 2 0 1 2 • O I L & G A S I N Q U I R E R
Advantage Oil & Gas is in a holding pattern at its Glacier Montney play, awaiting higher gas prices.
to ra mp up produc t ion c apac it y to 140 million cubic feet per day by completing modifications as planned in the Phase IV capital program. Interim guidance for the six months ending Jun. 30, 2012, includes average production of 22,800–23,400 barrels of oil equivalent per day, a royalty rate of eight to 10 per cent, operating expense of $5.70–$6 per barrels equivalent, and capital spending of $65 million–$75 million. The company said that additional capital budget and guidance details will be provided pending evaluation of future delineation plans for the liquids-rich Middle Montney formation in order to determine the natural gas and NGL production and reserves potential. This evaluation will include detailed analysis and interpretation of recent geological, engineering and completions data that the company obtained
from Middle Montney Phase IV wells. In addition, Advantage has one remaining Middle Montney well and two Lower Montney wells that are drilled and are awaiting completion, which the company anticipates undertaking after spring breakup. Advantage expects the results of this information and its evaluation to provide more information in regard to determining a systematic delineation plan for the balance of 2012 and beyond. The company recorded a net loss of $152.77 million in 2011, compared to net income of $40.92 million the previous year. The company experienced an increase in depreciation expense and a significant impairment that resulted in the net loss. Additionally, net income for 2010 was much higher, primarily due to significant gains on derivatives and asset dispositions. — Daily Oil Bulletin
Photo: Joey Podlubny
Advantage Oil & Gas Ltd. says it’s deferring the production ramp-up of Glacier Phase IV due to low natural gas prices. The company’s capital budget for the 12-month period ending Jun. 30, 2012, was set at $216 million, of which $200 million is focused on a Phase IV development program at Glacier with two key objectives: increase throughput capacity at Advantage’s Glacier gas plant from 100 million cubic feet per day to 140 million cubic feet by the second quarter of 2012, and further evaluate the Middle and Lower Montney formations. To date, the company has drilled 29 (28.5 net) Montney horizontal wells at Glacier as part of the Phase IV capital program and has recently started delineation in the Middle Montney, which has revealed the potential for natural gas liquids (NGL). Current behind-pipe volumes are estimated to be 37 million cubic feet per day, including wells that have been tested and existing wells that are currently restricted as a result of the 100-millioncubic-foot-per-day Glacier gas-plant capacity. An additional 14 Montney wells have been drilled and are awaiting completion. As a result of the prevailing low natural gas–pricing environment, production at Glacier will be maintained between 90 million and 100 million cubic feet per day until Advantage sees a sustained increase in natural gas pricing. The company will use its inventory of 29 (28.5 net) Montney wells that have been drilled to maintain targeted production rates at Glacier by producing and/ or completing these wells as required. Additionally, the company says that high industry-activity levels that have increased service and supply costs could subside during the latter part of 2012, which would benefit natural gas development economics. Advantage says that it’s prudent to maintain capital-spending discipline and financial flexibility in this current natural gas–price environment and that the current price of natural gas is unsustainable for generating sufficient full-cycle economic returns in the vast majority of North American natural gas plays, although an improvement in the price environment is anticipated. As a result, the company is positioning its Glacier gas plant with the capability
British Columbia
Kinder Morgan proceeding with Trans Mountain expansion A proposed $5-billion expansion of the Trans Mountain Pipeline System transporting an additional 550,000 barrels per day of crude oil from Alberta to the West Coast could be in operation by 2017, operator Kinder Morgan Energy Partners, L.P. said in late April. When completed, the proposed twinning will increase system capacity to 850,000 barrels per day from the current 300,000 barrels per day. In an open season, which closed April 10, a diverse group of existing and new shippers had submitted binding bids for 660,000 barrels per day of capacity, all for 20-year terms, it said. “We are extremely pleased with the strong commercial support that we received through the open season, which reinforces the appeal of our project and our approach,”
NEB and the federal government’s Major Projects Management Office to understand expectations and the process from their perspective, said Galarnyk. Kinder Morgan is still in the early stages of a community-engagement process with more in-depth consultation getting underway this summer. “We share respectful, open relationships with many communities and organizations interested in our business,” said Anderson. “We are committed to an 18–24-month inclusive, extensive and thorough engagement on all aspects of the project with local communities along the proposed route and marine corridor, including First Nations and aboriginal groups, environmental organizations and all other interested parties.”
on bigger ships coming in.” However, if the port were to decide to allow larger ships to come in, “we’d work with them to see how we could make that happen,” he added. Aframax vessels are 245 metres long with a deadweight of approximately 80,000 tonnes (average freight rate assessment). That’s about one-quarter the weight of the very large crude carriers that would transport crude to Asia from Enbridge Inc.’s proposed Northern Gateway terminal at Kitimat. This summer, Kinder Morgan anticipates filing a commercial tolling application with the NEB, seeking board approval on how it will charge its customers for transporting their product through the proposed expanded pipeline.
To the extent possible, the pipeline consisting of a combination of new 30- and 36-inchdiameter pipe will be built in the existing right-of-way between Edmonton and Burnaby, B.C.
said Ian Anderson, president of Kinder Morgan Canada Inc. “This strong commercial support shows the market’s enthusiasm for expanding market access for Canadian crude by expanding an existing system.” While the company had received commitments of about 600,000 barrels per day from its initial open season, a number of additional shippers came forward after the open season was extended for two weeks until April 10, said Andrew Galarnyk, director of external relations. Kinder Morgan anticipates filing a facilities application initiating a regulatory review with the National Energy Board (NEB) in 2014, he said. If the project is approved, construction is currently forecast to begin in 2016 with the proposed project operating by 2017. In addition to construction of a second pipeline, the preliminary scope of the proposed project includes adding new pump stations along the route, increasing the number of storage tanks at existing facilities and expanding the Westridge Marine Terminal in Port Metro Vancouver. Prior to submitting its application, Kinder Morgan will be meeting with the
Kinder Morgan will also consider providing financial support to local communities for environmental initiatives. In addition to extensive engagement, the company will conduct traditional land use, and environmental and socio-economic studies, and undertake detailed engineering and design studies. To the extent possible, the pipeline consisting of a combination of new 30and 36-inch-diameter pipe will be built in the existing right-of-way between Edmonton a nd Bur naby, B.C ., sa id Galarnyk. There may be areas, though, where Kinder Morgan may need to look at some rerouting because of urban and other types of development since the pipeline was built. Fr om Bu r n aby, c r ude cou ld b e shipped from the Westridge dock in Port Metro Vancouver to markets in Asia or California, or shipped by pipeline to refineries, including some in the U.S. Pacific Northwest. The Trans Mountain expansion will be based on Aframax ships, the largest ships currently using the port, Galarnyk said. “This is not necessarily dependent
“We want to make sure that the board understands how we are proposing to charge customers, based on this project, ” said Galarnyk. “Having the board review and approve that methodology…saves time in the end.” Mea nwh i le, joi nt r e v ie w pa ne l hearings are continuing on Enbridge’s p r op o s e d 52 5,0 0 0 - b a r r e l - p e r- d a y, $5.5-billion Northern Gateway crude line from Bruderheim, Alta., to Kitimat, and a 180,000-barrel-per-day diluent line that would carry imported diluent back to Edmonton. The project has faced intense opposition from First Nations, environmentalists and those involved in the fishing industry who are concerned about the effect of an oil spill on their livelihoods. At present, community hearings for oral statements have been scheduled into July 2012 with an NEB decision by the end of 2013. The federal government, though, has served notice that it wants to streamline the regulatory process for major resource projects, including Northern Gateway. — Daily Oil Bulletin O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
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Gas expenditures cut due to low prices
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Gas producers are turning off the taps and curtailing drilling activity in response to low gas prices.
Since their initial guidance in late 2011, several producers have announced plans to boost or lower their capital-spending plans for 2012, with a number of gasweighted operators announcing plans in the first quarter to curtail expenditures during a time of unprecedented low prices. Overall, for the close to 90 producers announcing capital budgets for 2012, spending plans have been revised downwards by about $53 million–$55.66 billion from initial plans of $55.72 billion. In late January, Tourmaline Oil Corp. said weak natural gas prices had forced it to reduce anticipated 2012 capital spending by $90 million. The company said that given the current natural gas–price environment, it has scaled back planned-2012 capital spending to $400 million, down from the originally planned $490 million.
The company announced in March that it had elected to reduce its 2012 capital program by an additional $25 million– $375 million. As these deferred expenditures are almost entirely facility and
Tourmaline has cut spending by $115 million in 2012. Progress has cut spending by $135 million. infrastructure investments, they will have no impact on the 2012 production forecast, which earlier was revised upwards to 50,000 barrels of oil equivalent per day from 47,000 barrels per day.
Nat u r a l g a s – we ig hte d P r og r e s s Energy Resources Corp. announced in February it was reducing its 2012 capital program to $365 million from the previously announced $465 million, due to low gas prices. At the same time the company said it would shut in about 10 per cent of its total gas production by April and delay the completion of selected wells. Under the new budget, approximately $330 million will be invested in the North Montney program, including $280 million on the company’s proprietary program and $50 million net (the gross budget of $341 million remains intact) on the North Montney Joint Venture (NMJV) properties. Progress will spend $35 million in the Deep Basin targeting its Dunvegan light oil play. Based on the reduced capital program of $365 million, Progress expects 2012 ex it produc t ion to be i n t he 53,000–55,000-barrel-equivalent-perday range. In November, Painted Pony Petroleum Ltd. announced plans to spend approximately $200 million during 2012, with a major portion of this capital allocated to the ongoing development of the Montney gas project in nor t heaster n British Columbia. Given the decline in North American natural gas prices, Painted Pony revised its 2012 capital program in mid-February to $120 million from the original guidance of $200 million, reducing both the overall amount of its capital program and slowing its investment in gas projects in northeastern British Columbia by $90 million. Should natural gas prices improve, the company may re-evaluate this plan. Celtic Exploration Ltd. said in its fourth-quarter and full-year 2011 release that it has reduced its 2012 capital expenditure budget by $55 million and now
NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY
APR/11
APR/12
WELL LICENCES
90
113
▲
APR/11
APR/12
WELLS SPUDDED
44
67
▲
APR/11
APR/12
WELLS DRILLED
100
94
O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
▼
49
Northwestern Alberta/Foothills
plans to spend $300 million. With the continued downward pressure on natural gas prices, due in part to the abnormally warm 2011-12 winter, Celtic said it has reallocated capital expenditures for the last three quarters of 2012. The company will be directing capital from the main gas-liquids lands in Resthaven to two oil pools in the area. As well, the Fir development will be postponed with capital instead being directed to additional Duvernay wells, a new Dunvegan oil play in Kaybob and a Bluesky oil pool in Kaybob. Redirecting the capital will have the effect of bringing the company’s oil and liquids ratio from the current 22 per cent of production up to 27 per cent by yearend, the company said. Bonavista Energy Corporation also plans to direct more of its 2012 budget to crude oil capital spending.
In light of the continued erosion in natural gas prices, the company announced last month it will adjust its 2012 capital budget downward, resulting in net expenditures of between $340 million and $360 million, down from its original guidance of between $400 million and $425 million. The revised program will incorporate an increase in crude oil–directed capital spending to approximately 45 per cent of total drilling expenditures, which is an increase from the company’s previous budget of 33 per cent. Other companies reducing 2012 budgets from original plans included Chinook Energy Inc. (down $25 million to a total of $165 million), Yangarra Resources Ltd. (down $15 million to a total of $35 million) and Insignia Energy Ltd. (down $5.50 million to a total of $16.5 million).
additional 5,000 barrels of oil and associated gas per day. During the remainder of 2012, Guide plans to drill an additional 24 (22 net) wells including 19 (19 net) wells in the Normandville/Girouxville Montney fairway. Plans also include the construction of a 5,000-barrel-per-day oil facility at Girouxville. Work is continuing on the company’s Duvernay prospect near Grande Prairie, Alta. It anticipates spudding the well in the third quarter of this year. Guide also repor ted t hat its $250-million credit facilities have been renewed. The credit facilities consist of a $225-million extendable 366-day revolving-term facility to May 28, 2013, and a $25-million non-revolving facility. The $25-million non-revolving facility is available subject to mutual approval of the banking syndicate and the company, including repayment terms. The current amount outstanding is approximately $192 million.
Shell Canada Limited has purchased a 1,820-acre (740 hectare) tract of land in northern Alberta to conserve boreal forest habitat near its Peace River oilsands operations. The conserved area, now called the Shell True North Forest, was privately owned land previously used for cattle grazing and hay production. Its purchase on behalf of Shell’s oilsands business will conserve an area almost twice the size of Stanley Park in British Columbia. “Shell has a land and reclamation strategy in place to guide environmental performance in our oilsands business and the Shell True North Forest is part of that continuous effort,” John Abbott, Shell’s executive vice-president, heavy oil, said in a news release. “As oilsands reclamation takes decades to complete, conserving land allows us to address the impacts of our land disturbance in the short term.” Land conservation plays a key role in managing biodiversity. The Shell True North Forest contains mixed woodlands, grasslands, wetlands and habitat along the Ksituan River, which runs through the property. The property has excellent road access and will allow for many different recreational opportunities such as hiking and birdwatching. The Shell True North Forest is 70 kilometres north of Grand Prairie, Alta., and lies less than one kilometre south of Moonshine Prov incial Park. T he land was secured through an arrangement with the A lberta Conser vation Association. Together, both parties will manage the area for biodiversity conservation and low-impact recreational use. “Over the next decade we plan to accelerate the pace of land reclamation at our mines and develop technologies to reduce future land disturbance,” said Abbott. “Including the Shell True North Forest, we’ve conserved land equivalent to nearly 14 per cent of our Jackpine and Muskeg River mines.”
— DAILY OIL BULLETIN
— DAILY OIL BULLETIN
— DAILY OIL BULLETIN
Guide curtails gas production In response to low natural gas prices, Guide Exploration Ltd. has shut in certain gas properties and will curtail production in other areas. These shut-ins will affect approximately six to nine million cubic feet per day, or approximately 10–15 per cent of Guide’s gas production. However, the majority of the company’s production is protected from the low gas–price environment, as it has hedges in place for the remainder of this year for approximately 31 million cubic feet per day of gas at an average price of $5.09 per thousand cubic feet at AECO. Exit production for the first quarter of 2012 was approximately 16,000 barrels of oil equivalent per day, including 5,600 barrels per day of oil and natural gas liquids (35 per cent liquids). Guide drilled a total of 14.2 net wells in the first quarter. Its major area of focus was Montney oil in the Normandville/Girouxville area where it added six net wells and upgraded its Normandville oil facility to handle an 50
J UNE 2 0 1 2 • O I L & G A S I N Q U I R E R
Shell to conserve 1,800 acres of forest in northern Alberta
Northwestern Alberta/Foothills
Strategic boosts production at Steen River
Photo: Photos.com/comstock
Strategic is focused on becoming a light oil producer in northwestern Alberta.
Strategic Oil & Gas Ltd. quadrupled production in the fourth quarter, due largely to drilling success at Steen River. During the year, the company added 1.59 million barrels of proved-plus-probable reserves through drilling and improved recovery. It converted 1.24 million barrels of oil from the probable category to the proven category with an increased oil weighting from 66 per cent to 83 per cent. The company increased total provedplus-probable reserves by 11 per cent to 5.27 million barrels equivalent (81 per cent oil) and total proved reserves by 24 per cent to 3.22 million barrels (83 per cent oil). The proved component of proved-plus-probable reserves increased from 53 per cent to 61 per cent over 2010. At Steen R iver in nor t hwester n Alberta, Strategic drilled and completed two wells in the first half and five wells in the second half of 2011. Sixty-day initial production rates on the two wells drilled in the first half of 2011 were 48 barrels of oil equivalent a day and 214 barrels of oil equivalent a day. Steen River wells drilled in the second half of 2011 had 60-day initial production rates ranging from 98 barrels a day to 335 barrels a day. Strategic’s Steen River capital program also included seismic, land
acquisition, all-weather road access and infrastructure development. At Maxhamish in northeastern British Columbia, Strategic and its operating partner, Legacy Oil + Gas Inc., completed an all-weather road and well pads in July 2011. Strategic said two wells were drilled and fracture stimulated at Maxhamish and initial production rates have been encouraging. The second well came on production in January 2012 and continues to recover load fluid. Strategic continues to be encouraged with the play, as the two horizontal wells drilled in 2010 have been producing at a stabilized rate of about 55 barrels equivalent a day per well after almost two years of production. Capital spending last year totalled $46 million, of which $37.5 million was for exploration and development and $8.49 million was spent on land and seismic. Seventy-two per cent of the total exploration and development capital was spent at Steen River and 27 per cent was spent at Maxhamish. Strategic’s two-year average finding, development and acquisition cost is $18.76 per barrel equivalent, excluding natural gas technical revisions. Strategic said it made great strides during 2011 in establishing itself as an efficient light oil operator in northern Alberta.
Increased light oil production at Steen River is expected to generate substantial cash f low, allowing the company to continue development of that operated property and its non-operated Maxhamish property. As previously announced, Strategic has a capital budget of $60 million that is expected to provide significant growth in 2012 oil output. The capital program includes $35 million for oil at Steen; the rest is for production optimization, land and seismic. Strategic’s drilling plan includes an estimated 20 (17 net) wells and is expected to provide 2012 average production of 2,400 barrels a day and to generate funds flow of $34 million–$38 million. Regarding 2012 Steen River activities, Strategic said it drilled nine wells in the first quarter of 2012. Two of the nine wells drilled in the first quarter are on production, with both doing more than 300 barrels a day. The remaining seven wells have been drilled and cased. Strategic intends to resume drilling in the third quarter and expects to drill up to five more wells this year. Additional work at Steen will include the acquisition of followup 2-D and 3-D seismic data, work on an all-weather road and the expansion of an oil-processing facility. At Maxhamish, plans for further drilling are proceeding. In 2011, an allweather road and a drilling pad were built to allow all-weather access and additional drilling. By January, the third and fourth wells were successfully drilled and stimulated and are now producing oil. T he pace of development at Maxhamish depends on Strategic’s operating partner, Legacy Oil + Gas. Strategic continues to work closely with Legacy to advance the project. Strategic expects to take part in the drilling program at Maxhamish starting in July. At A mber i n nor t her n A lber ta, Strategic last year acquired a large land position in an emerging oil play. Strategic has identified multiple prospective oil zones underlying its lands. Extensive road and pipeline infrastructure exists in the Amber area. Strategic plans to drill two exploratory horizontal wells starting in the third quarter. — DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
51
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Northeastern Alberta
Cenovus brings Christina Lake production on quickly By Lynda Harrison
range between six and 12 months for future phases at Christina Lake, rather than the historical 12–18 months,” John Brannan, executive vice-president and chief operating officer, said in a firstquarter conference call. “The project exceeded nameplate capacity of 58,000 barrels per day on February 19 and we are working hard to maximize production at those rates through the year.” Construction at Christina Lake phase D, which will add another 40,000 barrels per day, is more than 75 per cent complete and the project is on track for first production in the fourth quarter of this year, he said. Phase E is more than 40 per cent complete and first production is expected in the fourth quarter of 2013, he added. Bra n na n sa id Foster Creek a nd Christina Lake had a few minor power outages and required some unscheduled
maintenance during the first quarter that decreased production. A 17-day turnaround planned for the second quarter is expected to weaken volumes by 21,000 barrels per day on an annualized basis, or about 8,300 barrels per day net to Cenovus for the second quarter, he added. T he t wo pr oje c t s ’ f i r s t- qua r te r output was 82,000 barrels per day net to Cenovus, the company reported. Christina Lake has also received regulatory approval for Phases E, F and G, which are expected to increase production capacity to 218,000 gross barrels per day when complete. Cenov us has projects w it h total expected gross production of 400,000 barrels per day moving through the regulatory process. The company has identified 10 emerging projects and continues to assess its resources to prioritize development plans and support regulatory applications. T he r eg u l ator y appl ic at ion f or t he 130,0 0 0 -ba r rel-per- day (g ross) Narrows Lake project, jointly owned with ConocoPhillips Canada, is being reviewed by the regulators and Cenovus anticipates receiving approvals in the second quarter. The application includes the option of usi ng a combi nat ion of a SAGD and solvent-aided process. Prov ided approvals are received as anticipated, c on s t r uc t ion i s e x p e c t e d t o s t a r t later this year with initial production expected in 2016. The joint regulatory application and environmental impact assessment for a commercial SAGD project at Grand Rapids in the Greater Pelican Region is also being reviewed by the regulators. The company drilled a second well pair in the first quarter as part of the pilot project in the area, which began in 2010.
APR/11
APR/12
APR/11
APR/12
WELLS SPUDDED
73
101
WELLS DRILLED
71
108
Photo: Joey Podlubny
Total net production at Christina Lake averaged 24,700 barrels per day.
Flush with excitement over first-quarter production increases at its latest expansion at Christina Lake—attributed to its reservoir, its team and accelerated startup techniques— Cenovus Energy Inc. expects it can speed up future phases of the steam assisted gravity drainage (SAGD) oilsands project. The company reported a 23 per cent improvement in production from Foster Creek and Christina Lake during the f irst quar ter of this year compared to a year ago, and says it is thanks to “industry-leading” ramp-up at Christina Lake Phase C. Total net production at Christina Lake during the quarter averaged 24,700 barrels per day or about 85 per cent of nameplate capacity, with a steam to oil ratio (SOR) of two to one. “Based on this performance, we now expect ramp-up to full production to NORTHEASTERN ALBERTA WELL ACTIVITY
APR/11
APR/12
WELL LICENCES
98
83
▼
▲
▲
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
53
Northeastern Alberta
First production from the commercial project is anticipated in 2017, if approvals are received as expected. The company believes Grand Rapids has the potential to reach a production capacity of 180,000 barrels per day. The revised joint regulatory application and environmental impact assessment (EI A) for t he Telephone Lake
project in the Borealis Region is also being reviewed by the regulators. The application updates the expected production capacity to 90,000 barrels per day from the original 35,000-barrel-perday application that was filed in 2007. The company is continuing its search for a strategic transaction to support development of the project.
Cenovus continued to progress the Telephone Lake dewatering pilot project during the first quarter and expects to start water production and air injection in the second quarter of 2012. The pilot is designed to test the efficiency of removing the nonpotable water sitting on top of the bitumen in the reservoir, which is anticipated to reduce the SOR for the commercial project.
Nexen announces continued progress at Long Lake Nexen Inc. says it has reached two significant milestones in its plan to fill the Long Lake upgrader to its design capacity of 72,000 barrels per day of bitumen (60,000 barrels per day of premium synthetic crude, or PSC). It recently began steaming Pad 12 on the Long Lake lease and has received the necessary regulatory approvals to proceed with the development of Pads 14 and 15 at Long Lake and the Kinosis 1A area. The wells on these pads are in high-quality resource areas. “Achieving first steam at Pad 12 and securing approvals for the remainder of our wells are key steps in our strategy to increase bitumen production and fill the upgrader,” Kevin Reinhart, Nexen’s interim president and chief executive officer, said in a news release. “Obtaining regulatory approval allows us to commence drilling the wells this summer.” The company expects peak production of 11,000–17,000 barrels per day from the 18 wells on Pads 12 (currently steaming) and 13, and another 4,000–7,000 barrels per day from the 11 wells planned for Pads 14 and 15. With 29 wells planned for Kinosis 1A, expected peak rates are 15,000–25,000 barrels per day. Ne xe n sa id it s pla n to f i l l t he upgrader starts with increasing production from the existing 11 pads with estimated peak rates of between 30,000 and 44,000 barrels per day of bitumen from the 90 wells. The average bitumen production rate for the first quarter of 2012 was approximately 34,500 barrels per day, up 10 per cent from the prior quarter. Pad 11, its newest producing pad, 54
J UNE 2 0 1 2 • O I L & G A S I N Q U I R E R
Nexen's Long Lake SAGD development is slowly building production toward capacity.
continues to ramp up with recent rates of 5,700 barrels per day trending toward the upper end of the expected range of 4,000–8,000 barrels per day. Steaming on Pad 12 started in March as planned and production is expected to begin there this summer. Completion work is underway on Pad 13 and steam injection is expected to begin mid-year with bitumen production anticipated to start before the end of the year. Production from these pads is expected to ramp up to full rates over an 18–24-month period. Wit h reg u lator y approva ls now received, drilling is expected to commence on Pads 14, 15 and Kinosis 1A later this year. Steam injection is expected on Pads
14 and 15 in the second half of 2013, with Kinosis 1A following by mid-year 2014. Nexen said its winter 2011 core-hole program has confirmed the high quality of resource in each of these areas. It also allowed it to finalize the initial number of wells to be drilled in each area and to optimize the well layouts. For Pads 14 and 15, the optimum well con f ig urat ion ca lls for shor ter well lengths resulting in a lower production range on these pads. Nexen has a 65 per cent working interest in both Long Lake and Kinosis, while CNOOC Limited holds the remaining 35 per cent interest. — Daily Oil Bulletin
Northeastern Alberta
Value Creation announces SAGD project
Photos: Joey Podlubny
Value Creation expects to begin construction on its TriStar SAGD project in 2014.
Value Creation Inc. is proposing to build and operate a 75,000-barrel-perday SAGD project whose output will be converted using the company’s patented Accelerated Decontamination bitumenprocessi ng a nd pr i ma r y upg radi ng technology. Dubbed the Advanced TriStar project, it is the first development on privately held Value Creation’s TriStar leases in the Athabasca oilsands region in the Regional Municipality of Wood Buffalo. The central processing facility will be about 10 k ilometres northeast of Fort McMurray, Alta., on oilsands lease OSL 023, whic h compr ises sect ions 20–30 of township 89, range 8, west of the fourth meridian. The project will be developed in three phases, with construction anticipated to start in May 2014. Operations are expected to begin two years later and continue for 25 years. The first phase will produce 15,000 barrels per day of bitumen and be converted to 12,750 barrels per day of decontaminated crude oil (DCO), or premium oil. The second phase will increase output to 45,000 barrels per day of bitumen
converted to 38,250 barrels per day of DCO and the third phase will increase volumes to 75,000 barrels per day of bitumen converted to 63,750 barrels per day of DCO. TriStar’s DCO will be blended with diluent to produce a marketable, premium medium oil containing no asphaltenes, named Value Creation Medium crude oil, destined for Asia or the United States. Natural gas will be used for steam generation in the first phase, while the second and third phases will use asphaltenes removed during bitumen processing. The asphaltenes can either be used as an on-site fuel to generate steam or sold to international markets. The DCO can be shipped and sold as is, using trucks or rail cars, or it can be pipelined and marketed as a premium medium crude oil using 50 per cent less diluent than is currently needed for pipelining bitumen-only production as a diluted bitumen blend. When fully operational, TriStar will have about 300 well pairs and 40 well pads. A third-party supplier will provide power. Value Creation is currently assessing options for road access. Initial production will be transported by truck and thereafter by pipeline or rail.
According to Value Creation, its bitumenprocessing unit will physically separate out water and asphaltenes from the bitumen emulsion, resulting in a higher-value premium heavy oil (or DCO) and no air emissions. No surface water is to be used. The initial water source for the SAGD process will be non-potable saline water from a deepwater source and most of the produced water will be recovered, recycled and reused for steam injection. The first phase is expected to create more than 1,000 person-years of employment. An on-site camp is to house construction workers only. Value Creation expects to file the integrated application with the Energy Informatiom Administration (EIA) with regulatory agencies in the third quarter of 2012, and will distribute them to stakeholders for review. The company has prepared proposed terms of reference for its EIA and is inviting the public to review the document. Value Creation is also partnering with BP Canada Energy Group ULC, which will be the operator in the development of the Terre de Grace oilsands leases. — Daily Oil Bulletin O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
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Central Alberta
Celtic predicts low gas prices will fuel demand this year’s plans call for the drilling of eight Montney gas wells and three-net crude oil wells. The NGL yield on the Resthaven gas wells offset current low gas prices, Celtic executives said. The company is assuming an average gas price of about $2.35 per thousand cubic feet this year.
“ Gas royalties are probably what’s helping our economics the most.” — Sadiq Lalani, vice-president of finance and chief financial officer, Celtic Exploration
Photo: Joey Podlubny
With operators focused on tight oil plays and gas drilling at a standstill, Celtic believes gas prices may finally have reached bottom.
Executives at Celtic Exploration Ltd. are bullish on natural gas, arguing that the long-running low prices the industry has seen will serve to boost industrial demand for gas, helping to kick-start a price recovery. “I think we’ve turned the corner,” David Wilson, Celtic president and chief executive officer, told shareholders and executives at the company ’s annual meeting in Calgary. “The warm winter has pretty well made everyone stop drilling for gas,” he said. Citing a steep drop in the United States’ gas rig count, he noted some 650 rigs are now drilling for gas south of the border, down from 1,600 rigs in 2008. Earlier, another Celtic executive attributed the strength of the company’s gas economics to a few factors, including the five per cent gas royalty it’s currently paying, the natural gas
liquids (NGL) volumes many of its wells generate and a cost-allowance credit it’s receiving. Celtic is 75 per cent gas weighted. “[Gas] royalties are probably what’s helping our economics the most,” said Sadiq Lalani, vice-president of finance and chief financial officer. Early this year, Celtic cut its 2012 capital budget by $55 million, to $300 million, and the latter figure still stands, with about $234 million slated for drilling. In all, the plan is to drill 41 (30 net) wells, most in the Kaybob and Resthaven areas of west-central Alberta. The goal is to bring average volumes to 26,000 barrels of oil equivalent per day, and hit 29,000 barrels of oil equivalent per day by year-end. I n t he broader Rest haven a rea, where Celtic holds Montney rights on some 449,280 net acres (702 sections),
I n t h e K a y b o b a r e a , 13 w e l l s are planned, of which seven will be Cretaceous, while six are planned in the Duvernay formation. In the Fir area of Alberta, three wells are planned in the Montney, while in northeastern British Columbia three wells are planned for the Doig formation in the Inga region. Also Friday, Celtic said its lenders increased the company’s credit facilities to $335 million, up from $275 million. In the current low gas–price environment, the increase gives Celtic significant financial f lexibility to execute its 2012-13 capital expenditure programs, management said. Celtic estimates its 2012 year-end bank debt, net of working capital, will be about $162 million, which provides the company with roughly $173 million in unused and available bank credit at year-end. — Daily Oil Bulletin
CENTRAL ALBERTA WELL ACTIVITY
APR/11
APR/12
WELL LICENCES
142
102
▼
APR/11
APR/12
WELLS SPUDDED
89
80
▼
APR/11
APR/12
WELLS DRILLED
116
89
▼
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
57
Central Alberta
Crocotta reports Edson drilling success
58
J UNE 2 0 1 2 • O I L & G A S I N Q U I R E R
Crocotta is building liquids-rich gas production at its core area at Edson, Alta.
estimated at over 90 per cent and a payback of approximately 1.2 years. However, due to the strong Cardium oil drilling results in the first quarter, Crocotta’s drilling focus this summer will continue on the Cardium oil and it will resume Bluesky drilling in the late third or fourth quarters. In January 2012, Crocotta announced a Montney well at Dawson/Sunrise that tested approximately 14 million cubic feet per day plus 20 barrels per million cubic feet of NGLs. The company tied the well into the Westcoast system, but has opted not to produce it at this time due to low gas prices. Crocotta plans to extend its pipeline system and tie the well into the Alliance pipeline in late fall—pending better prices—to reduce operating costs and benefit from some of the NGLs that would otherwise not be extracted. Based on the type curve for the area and current strip pricing, a Montney horizontal well provides a rate of return of more than 40 per cent and a payback of approximately 2.3 years. C r o cot t a h a s ove r 75 (75 net) Mont ney locat ions in t he Dawson / Sunrise area that it plans to further develop next year. Of its other projects, the company has identified and assembled land (more than 40 net sections) on three additional
prospective “oil resource” projects that it anticipates to drill prior to year-end. C r o c ot t a’s l iq u id s c omp o s it ion includes approximately 47 per cent light oil and condensate, 18 per cent butane and 35 per cent propane. With the recent increased differential between West Texas Intermediate (WTI) and Edmonton par, Crocotta has tried to isolate as much of its condensate as possible to benefit from the higher condensate pricing. Previously, the company was blending a large portion of its condensate with light oil at Edson and receiving a premium price relative to Edmonton par. The company estimates its blend of oil and liquids will receive approximately 73 per cent of WTI pricing for the rest of the year after accounting for higherthan-historical differentials on light oil and propane. In 2011, Crocotta received approximately 80 per cent of WTI for its blend of oil and liquids. The company estimates net debt at the end of first-quarter 2012 to be approximately $45 million. It has a bank credit facility of $80 million and estimated cash f low of about $50 million based on current strip pricing. Current productive capacity is well ahead of budget expectations, including its 2012 exit-rate target of 8,500 barrels per day. — Daily Oil Bulletin
Photo: Joey Podlubny
Crocotta Energy Inc. invested approximately $28 million—primarily on drilling the Bluesky and Cardium at Edson, Alta., and the Montney at Dawson/Sunrise—in the first quarter and early in the second quarter of 2012. Output for first-quarter 2012 is estimated to be approximately 6,700 barrels equivalent per day (67 per cent gas; 33 per cent light oil and NGLs). Drilling in the Cardium and Montney during the fourth quarter of 2011 and first quarter of 2012 has significantly increased its development drilling inventory, the company reported in an update. In first-quarter 2012, Crocotta participated in a second Cardium horizontal well at Edson (40 per cent working interest), currently producing about 560 barrels of oil equivalent per day gross at 46 per cent oil and liquids at the end of its first two weeks of production. T his wel l is sig nif ica nt ly above Crocotta’s type curve for the area, which forecasts an initial production rate of 300 barrels per day. Its first Cardium horizontal well at Edson (40 per cent working interest) is producing 410 barrels equivalent per day gross (41 per cent liquids) after almost four months of production. The company has a contiguous block of 13.5 (8.8 net) sections that features those first two wells and plans to aggressively step-out drill to prove up the lands. Crocotta plans to drill six (3.3 net) wells to further prove up approximately 50 (32 net) unbooked Cardium locations on these sections during the second and third quarters of this year. During the first quarter of 2012, Crocotta completed an additional three (2.6 net) wells that continue to meet or exceed its t y pe cur ve for Bluesky wells (650 bar rels of oil equivalent per day). One (0.6 net) well is drilled and not completed and one (one net) is currently drilling. Crocotta expects to have them both on production in the third quarter. The company has an inventory of more than 40 net locations that has been largely proved up over the last two years. The Bluesky wells average 80–100 barrels of NGLs per million cubic feet of gas and, under current strip prices, have economics with internal rates of return
Central Alberta
Whitecap to double wells drilled Whitecap Resources Inc. plans to drill at least 120 wells this year and produce an average of 15,000–16,000 barrels of oil equivalent per day with development capital spending of $260 million, its annual general meeting heard last week. Last year, the company drilled 60 (48 net) wells, all successful, compared to 17 (11 net) wells drilled in 2010 The company anticipates exiting 2012 with output of 18,000–19,000 barrels equivalent per day—70 per cent of it oil, Grant Fagerheim, president and chief executive officer, told the meeting. In the first quarter of this year, Whitecap drilled 12 horizontal wells at Pembina in west-central Alberta and it plans to drill between 22 and 24 in the remainder of 2012, he said. It will initiate a waterflood pilot in the area during the third quarter to potentially recover another 12–14 per cent of the light oil, he said. In west-central Saskatchewan where the company is drilling for Viking oil in its Lucky Hills core area—and drilled 14
horizontal wells in the first quarter with 100 per cent success—the company anticipates drilling 28 horizontal wells during the remainder of 2012. Using prices of $98 WTI for oil and $2.25 per gigajoule for natural gas, Whitecap estimates cash flow this year of $216 million. Whitecap will continue this year with the strategy that has worked for the past
Whitecap Resources Inc. plans to drill at least 120 wells this year and produce an average of 15,000–16,000 barrels of oil equivalent per day. few years: targeting high-netback, light oil–growth assets with large oil resource in place where horizontal multistage fracture technology and secondary recovery methods can be applied to increase resource recovery, said Fagerheim.
Since its inception in 2009, Whitecap has added 5,900 barrels per day through acquisitions and 5,200 barrels per day through the drill bit, he said. “The company will continue to work on operational efficiencies at the field level, both at the capital and operating level, expand our assets through increased reser ves recovery through waterfloods and well density. Ultimately we believe long term this prov ides the best form of per-share, long-term growth, which ultimately will drive long-term share price appreciation,” said Fagerheim. Whitecap acquired Midway Energy Ltd. through an arrangement earlier this year. The company’s combined production is now 16,000 barrels equivalent per day (68 per cent oil and NGLs) and, as a result of the arrangement, the borrowing base of Whitecap’s syndicated credit facility has been increased from $250 million to $400 million, an increase of 60 per cent. — Daily Oil Bulletin
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Southern Alberta
Producers testing southern Alberta Bakken/Exshaw tight oil plays By Richard Macedo
“This is a play that we’ve put a lot of work into at Murphy,” Jon Noad, Murphy’s exploration manager, Canada, told a recent Canadian Energy Research Institute oil conference. He was discussing some of the new tight oil plays i n we ste r n C a n ada, i nc lud i ng t he Exshaw. “There are several other companies out there drilling. There’s probably been 25 wells drilled into this play in the last year at an individual cost of $7 million– $12 million a t hrow, so there’s a decent amount of investment into this reservoir. “There’s a variety of sediments here which you’re going to have to try and target with your horizontal well and your fractures, to try and produce. “The jury’s still a little bit out about the best way to drill into these rocks,” Noad added. “It’s a complicated story to get right. A lot of these wells, the reason
you’ll find that they’re non-commercial is not necessarily just to do with the geology, but to do with how they’ve been completed; what kind of pressure [has been] applied to try and break the rocks open, what they’ve used to hold them open and where they’ve targeted the wells.” Turning to other tight oil plays around the province, Noad said while they’re described as new, in reality they are newly accessed plays. Many of them have been known for generations. “As the wells have been drilled in western Canada, they’ve seen oil shows, but they’ve never been able to exploit them until the newer technologies of horizontal wells and fracking,” he told the conference. Many of western Canada’s tight oil plays are still in the early stages of development, Noad said. In addition to the Alberta Exshaw, they include the Muskwa, Nordegg, the Horn River Group shales in the Northwest Territories and the Beaverhill Lake play. “There’s a huge concentration [of these plays] in Alberta,” he said. “What’s really driving Alberta’s economy is plays like this. “Once you think you’ve exhausted a certain way of producing oil and gas, then the technology comes along to reinvent the wheel and [you] go back in and find more ways of producing commercial hydrocarbons.” Meanwhile, Rusty Braziel, president of RBN Energy LLC, added that the rise of crude production in Canada and the United States could help the continent become energy independent in a short period of time. “In other words, no Latin America crude, no Middle East crude, no Africa crude,” he told the conference. “We could, if we choose to be so, be energyindependent.”
APR/11
APR/12
APR/11
APR/12
WELLS SPUDDED
1
11
WELLS DRILLED
4
12
Photo: Joey Podlubny
Rig drilling near Waterton, Alta. Producers continue working to unravel the tight oil play in southern Alberta.
Horizontal drilling and hydraulic fracturing have opened up a plethora of tight oil plays in western Canada, including the Exshaw/Bakken in southern Alberta, where producers are still trying to get a handle on the best way to drill the rocks in that area. Several producers are currently active in the play including Bowood Energy Inc., Nexen Inc., Penn West Petroleum Ltd., Murphy Oil Company Ltd., Royal Dutch Shell plc, DeeThree Exploration Ltd., Crescent Point Energy Corp. and Legacy Oil + Gas Inc. In southern Alberta this year, Murphy has plans for two appraisal wells, according to a company presentation. The initial objective there was the Exshaw/Bakken. Six appraisal wells were drilled in 2011 with mixed results. One recent well tested the Three Forks, and the company said early results were promising. SOUTHERN ALBERTA WELL ACTIVITY
APR/11
APR/12
WELL LICENCES
51
27
▼
▲
▲
Source: Daily Oil Bulletin
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Southern Alberta
Is this possible before the end of this decade? “The answer is not only yes, but sooner still,” Braziel said. “By 2014, the combined production of the U.S. and Canada will be to where it was in 1973, the 1973 peak of the two countries’ production. “What happens after that…we’re into territory that we’ve never seen between
the two countries before. We’re into virgin territory in terms of how much crude production that we’re seeing. Of course, we know that has a lot of implications for logistics and for capacity constraints. “In terms of self-sufficiency, I define that as the point at which the combined waterborne crude imports of the U.S. and Canada go to zero. Or it’s offset by
a volumetrically equivalent export,” Braziel added. “We’re going to assume that some of the coastal refineries are going to have to still continue to bring in barrels simply because of logistical constraints,” he noted. “But…as long as there’s equivalent exports, then we ought to be flush with that.”
Japanese company invests C$602 million in Encana CBM development
Encana Corporation has reached an agreement with Toyota Tsusho Wheatland Inc., a subsidiary of Toyota Tsusho Corporation, which will see the Japanese company invest approximately C$602 million to acquire a 32.5 per cent royalty interest in natural gas production from a portion of Encana’s coalbed methane (CBM) resource play. The agreement includes production from a total of about 5,500 existing wells and potential future drilling locations in southern Alberta. “This investment from a global partner recognizes the significant value identified in Encana’s CBM lands, which rank 62
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among the company’s lowest-cost, lowestrisk assets and signifies another step as Encana pursues a range of opportunities to manage its portfolio and enhance the long-term value creation of its vast inventory,” said Randy Eresman, president and chief executive officer. The company’s CBM resources cover a great expanse that includes approximately 2.1 million net acres in the Horseshoe Canyon fairway. The vast majority of this acreage is fee lands, where Encana holds the mineral rights in perpetuity, and are estimated to contain significant amounts of recoverable natural gas. This relationship
with Toyota Tsusho offers strong synergies that have the potential to foster expanded business opportunities, he added. “Further, this agreement serves as a model for other investment opportunities, and supplies capital investment to preserve the value and efficient development of Encana’s shallow gas lands in Alberta that have contributed long-life production for more than five decades,” Eresman added. Encana has been selling midstream assets, inked a joint-venture deal and is looking for more. In early May, the natural gas producer said it was executing on its plan to leverage the exploration and development
Photo: Joey Podluby
Encana's Horseshoe Canyon production is among the lowest-cost natural gas assets in Alberta.
Southern Alberta
of certain of its oil and liquids-rich assets through partnership opportunities designed to maximize recognition of the value inherent in its large asset base. In February, the company completed the Cutbank Ridge partnership agreement with Mitsubishi Corporation. The company also sold off interests in the Cabin gas plant. In a press release, Toyota Tsusho said it regards North America as a strategic business region for building a natural gas value chain through transactions. It noted that growing supplies may “serve as a future LNG source for Japan in the near future.” The Japanese company added that unlike many CBM projects around the world, Horseshoe Canyon coals do not produce water and production can be developed without environmental concerns and costs related to dewatering of the coals prior to production. “In addition, Encana’s world-class experience and technical capabilities in CBM projects reduce business risks.” Under the agreement, Toyota Tsusho paid $100 million with the closing of the transaction and will invest approximately $502 million over seven years to acquire a 32.5 per cent royalty interest, before deductions, in production from approximately 4,000 existing wells and approximately 1,500 potential future drilling locations. These wells are located in an area covering about 480,000 net acres along the eastern edge of the Horseshoe Canyon fairway—an area that represents about 24 per cent of Encana’s total CBM net acreage. The existing wells on these lands are currently producing a total of about 120 million cubic feet equivalent per day of natural gas. The area contains approximately 480 billion cubic feet of proved-plusprobable reserves and 140 billion cubic feet of best-estimate economic contingent resources as of December 2011. Under the agreement, Encana will be operator, and Encana and Toyota Tsusho have established a management committee that will provide overall supervision and direction of development operations. “Our integrated CBM wells produce lowpressure, sweet natural gas that is essentially pure methane, and as a result is a cleaner energy source, producing the fewest emissions of any hydrocarbon—a natural gas resource capable of delivering longterm, affordable energy supplies to domestic and export markets,” Eresman said. — DAILY OIL BULLETIN
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Fairborne sells Sinclair oil assets
Photo: Joey Podlubny
Fairborne is selling 700 barrels per day of production to cut debt.
Currently in the midst of a strategic alternatives process, Fairborne Energy Ltd. announced in late April that it will unload its assets in the Greater Sinclair area of Saskatchewan and Manitoba for $80 million. The sale, to a private oil and gas company, includes approximately 700 barrels per day of oil production but excludes approximately 100 barrels per day in the Kingsford area of southeastern Saskatchewan. The company’s production, prior to the proposed disposition, is currently 15,300 barrels of oil equivalent per day, with an additional 1,000 barrels per day shut in at Wild River, due to low natural gas prices. Reserves attributed to the Greater Sinclair assets on a proved basis are 1.6 million barrels and on a proved-plus-probable basis are 3.1 million barrels, based on an assessment conducted by GLJ Petroleum Consultants
Ltd. Transaction metrics are $48.87 per barrel on a proved-reserve basis, $25.46 per barrel on a proved-plus-probable reserve basis and $114,286 on a flowingbarrel basis. Based on the April 13 closing price of the company’s shares of $1.84, transaction metrics include: a 290 per cent premium
Reserves attributed to the Greater Sinclair assets on a proved basis are 1.6 million barrels to its current enterprise value per flowing barrel valuation, based on production of 15,300 barrels per day; a 260 per cent premium to Fairborne’s current enterprise
value per proved-plus-probable reserves; and the divested assets represent four per cent of 2011 exit volumes, while proceeds represent 42 per cent of current market capitalization and 18 per cent of current enterprise value. Fairborne said the proceeds from the transaction will be applied to reduce debt. Combined with its Clive divestiture announced in January, which is expected to close near the end of the second quarter of 2012, the company anticipates net debt to be approximately $140 million post the closing of the two transactions, and the effect of the dispositions will be integrated into the annual borrowing base review process, which is currently underway by Fairborne’s bank syndicate. Meanwhile, in an operational update, the company said it had an active winterdrilling program that included three (2.7 net) horizontal Wilrich wells at Marlboro, one (0.75 net) Cardium horizontal well at Harlech and one net vertical well at Harlech. With the exception of one Wilrich horizontal well, which will be completed after spring breakup, all the wells are on production. The company’s second Cardium horizontal at Harlech (75 per cent working interest) has been on production for 30 days and has produced at an average rate of 1,000 barrels equivalent per day, which includes 165 barrels per day of condensate and 85 barrels per day of natural gas liquids. The well has had a very strong production profile and is currently producing at 925 barrels per day. Fairborne has identified a Cardium horizontal-drilling inventory on its existing Harlech land base of 300 net wells (three wells per section spacing) on this regionally extensive and consistent sandstone reservoir trend. — DAILY OIL BULLETIN
SASKATCHEWAN WELL ACTIVITY
APR/11
APR/12
WELL LICENCES
326
335
▲
APR/11
APR/12
WELLS SPUDDED
41
19
▼
APR/11
APR/12
WELLS DRILLED
43
29
▼
Source: Daily Oil Bulletin
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Saskatchewan
Novus builds oil production Novus Energy Inc.’s 2011 production increased 77 per cent to 1,971 barrels of oil equivalent per day, weighted 76 per cent towards oil and liquids, from 1,115 barrels per day the prior year. Fourth-quarter production increased 81 per cent to 2,845 barrels per day (83 per cent oil and liquids) from 1,571 barrels per day in the corresponding quarter
Novus may drill 320 wells at Flaxcombe.
of 2010. The company said the higher year-over-year production is largely a reflection of increased drilling activity that began in the latter half of 2010 and continued throughout 2011. Backstopped by increased production and strong crude oil prices, Novus’s funds flow from operations increased 607 per cent to $26.1 million from $3.69 million in 2010, while fourth-quarter 2011 funds flow climbed 392 per cent to $12.03 million from $2.44 million the prior year. T he compa ny noted it ac h ieved operating netbacks of $47.17 per barrel equivalent, up more than 100 per cent from $23.52 per barrels recorded in 2010. Operating netbacks in the fourth quarter of 2011 were a record $55.34 per barrel. Novus said its Viking production achieved impressive operating netbacks of $68.16 per barrel for the fourth quarter
of 2011. For the 12-month period of 2011, operating netbacks in the Viking were $63.02 per barrel. Novus drilled 59 wells (57.9 net) in 2011, with 52 wells (51.8 net) achieving a 100 per cent success rate targeting the Viking play in Dodsland, Sask. The company entered 2012 with an extensive light oil development drilling inventory of more than 600 net locations, which represent over eight years of development potential. This already-significant opportunity base does not reflect the ability to down-space from eight wells to 16 wells per section or the future potential to waterf lood the reser voir. Novus said it believes that the development of the Viking resource is in its early stages and that there is a further significant upside to recovery factors by applying secondary recovery methods. The company said that it will continue to actively drill its existing land base, and will remain focused on expanding its dominant presence within this large oil resource play. While Novus is pleased with the results it has achieved throughout the greater Dodsland area, the Flaxcombe region has emerged as an area that has exhibited consistent and reliable outperformance. In addition to delivering higher initialproduction rates, the region is exhibiting lower-than-typical decline rates. In the Flaxcombe region, Novus has identified two distinct Viking cycles that have been mapped over at least 10 contiguous sections. These 10 sections have the potential to add 80 future drilling locations for the company through the
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development of both cycles at eight-wellper-section spacing. Based on Novus’s success in the area and industry down-spacing trends, the company believes that it may be able to develop each cycle independently at 16-well-per-section spacing, which would provide the potential for drilling up to 320 wells in the Flaxcombe area. Novus has finished running an emulsion line from its core facility at Whiteside to the Flaxcombe field, and a total of 29 wells in the southern portion of the area have been tied in and have their gas production conserved. This line will be used to tie in all new wells drilled in the Flaxcombe area throughout 2012, and will serve to reduce both downtime and future operating costs. Based upon the stable production rates, highly economic netbacks, significant recoverable reserves, and lower drilling and completion costs in the Dodsland area the company has experienced to date, Novus said it plans on maintaining an aggressive drilling program on its current acreage and will continue its efforts to further consolidate and expand its position within the area through acquisitions. The 2012 capital budget of $81 million will have 88 per cent of the funds allocated to drilling and completions and is expected to result in 2012 average production of 3,300 barrels per day (84 per cent oil and liquids), which represents growth of 67 per cent over the 2011 average production rate. The forecasted 2012 exit production rate is 4,500 barrels per day, 85 per cent of which will be oil and liquids. — DAILY OIL BULLETIN
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Technology News
Tervita bringing in green service rig
Tervita is focused on making the service rig industry more safe and environmentally friendly.
Tervita Corporation, a leading North American environmental and energy services company, is shaping the future of the service rig industry by entering into an exclusive lease agreement with TTS Energy Canada Ltd. for the first rack-andpinion service rig on the continent. This innovative rig technology is safer and more environmentally friendly than
the last 30 years, there have been no real significant changes to service rigs. We feel the move to the rack-and-pinion technology will provide greater automation and the increased benefit to safety and the environment represents the future of the industry.” The patented rack-and-pinion technology allows the rig to push and pull.
part of our growth strategy is to develop and work with external partners to design and manufacture those solutions,” Gibson said. “TTS is excited to find a partner in Tervita to launch the rack-and-pinion technology to the service rig industry,” said Mark Skawronski, president, TTS Energy Canada. “We feel confident this
“ We feel confident this rig addresses most challenges that rig operators are faced with when
Photo: Tervita Corp.
working in a SAGD environment" traditional rigs. It requires fewer workers to operate while keeping those employees at a safer distance from the operation. The new rig has the f lexibility of being powered by diesel or electricity provided by one of the company’s steam assisted gravity drainage (SAGD) clients, who already generate power from on-site steam plants. “This is a pivotal moment for the service rig industry,” said John Gibson, Tervita president and chief executive officer. “In
Typically a rig requires up to five workers on site, but with the rig’s automation technology, only three employees are needed to keep the rig in service. This is a tremendous benefit to Tervita and its customers, considering the labour shortages the industry faces and the vital importance of worker safety, the company said. “Our customers are increasingly interested in using safer, environmentally responsible technologies, so a significant
— Mark Skawronski, president, TTS Energy Canada
rig addresses most challenges that rig operators are faced with when working in a SAGD environment, which will be the initial entry point for this rig. Tervita’s continued commitment to technology and innovation will help revolutionize the well-servicing industry.” TTS will begin manufacturing the SR-75-RP 75T rig shortly and service is expected to commence by the end of 2012. The new technology will be pioneered for and first used in Fort McMurray. O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
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Technology News
ESG Solutions introduces next generation microseismic recorder ESG Solutions, an industry leader in microseismic technology and services, has announced the North American release of its next generation Paladin microseismic recorder. The Paladin IV 32-bit digital seismic recorder is the backbone of ESG’s microseismic data acquisition systems, which monitor induced seismicity during underground and open-pit mining, oil and gas production and a variety of geotechnical applications. Building on nearly 20 years of industry experience, the Paladin IV reflects ESG’s innovation and leadership in the microseismic industry. Designed for versatile signal acquisition, this low-noise device records microseismic signals from a range of seismic sensors and transmits time-synchronized data via Ethernet to a central location for processing and analysis. The Paladin IV introduces plug-andplay functionality for improved ease of
use, and remote diagnostics capabilities keep tabs on sensor health, speeding up system maintenance. Coupled with webenabled global data streaming, powerful new on-board processing enables standalone units to perform advanced triggering and analysis without a PC, supporting a diverse suite of new remote monitoring applications. Microseismic monitoring uses the principles of earthquake seismology to listen to a rockmass during mining or oil and gas operations, delivering continuous, real-time feedback on how the rock is behaving in response to those operations. By operating as an early warning system for potential hazards caused by changing rock conditions, microseismic monitoring can help to mitigate risk and optimize design in underground and open-pit mines. In the oil and gas industry, a permanent, life-of-field approach is applied
to monitor enhanced oil recovery and unconventional reservoir stimulation to help optimize production, ensure reg ulator y compliance and address public concern. Founded in 1993, ESG Solutions is the leading provider of microseismic instrumentation and data acquisition, analysis and interpretation services for the mining, oil and gas, and geotechnical industries. As an independent provider of innovative microseismic solutions, ESG helps operators improve safet y, optimize production, reduce costs and mitigate risk associated with hydraulic fracturing, thermal enhanced oil recovery, underground and open-pit mining, natural gas and waste storage, carbon sequestration and geotechnical applications. ESG is based in Kingston, Ont., with offices in Calgary, Houston, Denver, Dubai, Amsterdam, Changsha and Beijing.
Solar-generated steam delivering for EOR projects GlassPoint Solar, Inc. announced that Anthony Kovscek, professor of Energy Resources Engineering at Stanford University, presented a new study of solar thermal enhanced oil recovery (EOR) at the Society of Petroleum Engineers (SPE) Western Regional Meeting, March 22.
steam versus conventional gas-fired steam and cogeneration alternatives. Using the San Joaquin Valley as a case study, Kovscek quantified the effectiveness of solar EOR through reservoir simulation, economic analysis and life cycle assessment of oil recovery operations.
GlassPoint ’s solar steam generators can supply up to 80 per cent of a project ’s annual steam needs, replacing natural gas. Kovscek, a renowned expert in thermal oil recovery, is lead author of the SPE paper, Solar-Generated Steam for Oil Recovery: Reservoir Simulation, Economic Analysis, and Life Cycle Assessment (SPE 153806). During the Reservoir Characterization session, Kovscek presented research results from the study which models 20 years of thermal EOR, comparing solar 70
J UNE 2 0 1 2 • O I L & G A S I N Q U I R E R
The study found that solar EOR delivered the highest profitability, lowest emissions and lowest economic risk of the modelled alternatives. GlassPoint commissioned t he world’s f irst commercial solar EOR project early last year in McKittrick, C a l i f., a t B e r r y P e t r o l e u m ’s 21Z lease. Designed specif ically for oilfield environments, GlassPoint’s solar
steam generators can supply up to 80 per cent of a project ’s annual steam needs, replacing natural gas. The company has projects in development in California and the Middle East. GlassPoint is the leading provider of solar steam generators to the oil and gas industry. When used for enhanced oil recovery, GlassPoint solar steam generators reduce natural gas consumption by up to 80 per cent, releasing large amounts of gas for use in higher-value applications. This is only possible because, unlike previous solar designs, GlassPoint steam generators deliver steam at a lower cost than steam produced by burning natural gas. GlassPoint’s steam generators are sealed for protection from the sand, dust, dirt and high humidity typical of oilfield environments throughout the world. GlassPoint is headquartered in Fremont, Calif., with offices in Bakersfield, Calif., Muscat, Oman and Shenzhen, China.
Technology News
ExxonMobil awards MultiZone Stimulation Technology licence to Weatherford ExxonMobil Upstream Research Company (URC) has announced the licensing of its award-winning Multi-Zone Stimulation Technolog y (MZST) well treatment process to a subsidiary of Weatherford International Ltd. The MZST process can be used to rapidly and reliably stimulate multiple zones in a single operation, yielding improved well economics.
“ As shale gas takes on growing significance, this technology will play a key role in improving the economics” — Sara Ortwein, president, URC
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The MZST process can be particularly beneficial for hydraulic fracturing operations in tight gas, shale gas and coal bed methane wells that target multiple reservoir zones, thick reservoir sections or long reservoir intervals where multiple stimulation treatments are required. “The MZST process is a proven technology for rapidly completing wells in tight reservoirs such as shale gas,” said URC president Sara Ortwein. “As shale gas takes on growing significance, this technology will play a key role in improving the economics of developing this unconventional resource.” T he MZST process w i l l enable Weatherford to optimize its stimulation operations by combining the deployment of perforating and hydraulic fracturing equipment simultaneously in the wellbore to enable “single-trip” multi-zone stimulations. The technology dramatically increases the number of zones that can be fractured per day compared to traditional fracturing and stimulation operations.
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Technology News
“We are always looking for proven technology to reduce completion costs without sacrificing safety or well integrity,” said Gary Flock, Weatherford vicepresident of pressure pumping. “The MZST process is an excellent fit with our existing portfolio of completion and well stimulation technologies and services, and will help us add value to our customers in the unconventional gas business.” The MZST process was developed by ExxonMobil URC, the upstream research
affiliate of Exxon Mobil Corporation. The technology was recognized with Platts Global Energy Award for Most Innovative Commercial Technology in 2005 and has been licensed to numerous service companies. Exxon Mobil Corporation is a leading global oil, natural gas and petrochemicals company with operations in nearly 200 countries and territories worldwide. ExxonMobil URC is charged with developing an industry-leading array of proprietary
technologies that support the corporation’s continued leadership position in exploration, development, production and gas commercialization. Weatherford is a Swiss-based, multinational oilfield service company. It is one of the largest global providers of innovative mechanical solutions, technology and services for the drilling and production sectors of the oil and gas industry. Weatherford operates in over 100 countries and employs over 60,000 people worldwide.
Marmit Plastics launches Top Fill Tank Adaptor Since 1990, Marmit Plastics Inc. has grown from a family business into an industry leader in innovation and unbeatable service. Based in Grande Prairie, Alta., Marmit Plastics manufactures single- and double-wall plastic chemical tanks, secondary containment basins, water tanks and other oilfield-related plastics products, as well as specializing in custom molding, polyurethane spray foam insulation and plastic welding. With a commitment to providing customers the
filling process for chemical tanks presented a safety hazard to workers climbing ladders in order to insert a hose and fill from the top. Even with the dangers of ladders in winter conditions set aside, splashing, fumes and static all played a part in creating an unsafe work environment for those filling their chemical tanks from the top. When product research turned up unsatisfactory results, Marmit began creating its own product for ground-level filling. Several tests and two
techniques from the filling process. The new design also features technology that eliminates splash filling, reduces the danger of static discharge in both plastic and steel tanks, and allows the fill line to be emptied by simply reversing the discharge pump. Since product launch, Marmit has retro-fitted both plastic and steel tanks throughout western Canada, and is creating a new standard for safety within the oil and gas industry.
Top Fill is designed as an innovative answer to safe tank filling—allowing chemical tanks to be filled from the ground level. best service and most reliable product, Marmit has made a name for themselves as an innovative industry leader within the oil and gas, rotational, molding and plastics industries. Marmit Plastics recently launched its newest patent-pending technology— the ‘Top Fill Tank Adaptor.’ True to its name, the Top Fill is designed as an innovative answer to safe tank filling—allowing chemical tanks to be filled from the ground level. I n 20 08, Ma r m it Pla st ic s wa s approached with a problem: the current 72
J UNE 2 0 1 2 • O I L & G A S I N Q U I R E R
years of design/development processes later, the end result became today’s Top Fill Tank Adaptor technology—a design that has revolutionized the task of delivering chemical products into plastic and steel tanks. The Top Fill Tank Adaptor’s design includes an inlet and vent all-in-one fitting, drop tube (stinger), load lin and valve. The design allows tanks to be filled to the same level consistently, from the ground—eliminating ladders and other commonly practiced, unsafe
In 2009, after the successful launch of the Top Fill Tank Adaptor, Marmit found a need to not only supply the product, but to also perform the installation in the field. Since then, numerous projects have been carried out doing installations for a number of the oil and gas industry’s largest corporations. To date, thousands of Top Fill Tank Adaptors have been installed throughout Alberta and British Columbia by Marmit Plastics’ experienced and welltrained crews.
Technology News
Ulterra designs over 75 drill bits in 2012 Ulterra Canada’s focus on finding the right bit for the job has driven their continued success helping operators drill faster, for less. Since January 2012, the polycrystalline diamond compact (PDC) drill bit company has increased their product line by over 75 modified designs. “Ulterra continues to build upon our successes by evolving our designs and growing our product offering. This allows us to create the optimal solution for the applications and formations being drilled.” says Craig Knull, vice-president and general manager of Ulterra Canada. These design evolutions have been particularly effective in the Viking formation in southwestern Saskatchewan, where the latest design of Ulterra’s U513S (UD513) PDC bit continues to outperform competitors. Drilling a horizontal well in Avon Hill, Ulterra’s 159-millemetre U513S drilled 1,462 metres at a rate of penetration (ROP) of 94.3 metres per hour, beating average offsets in the area by 30 per cent. The vertical, build and horizontal were all drilled with the same bottomhole assembly, reaching total depth without a trip out of the well. Drilling engineer Tom Cook with Penn West Exploration, who has drilled over 150 horizontal wells in the Dodsland/ Avon Hill area in Saskatchewan, had this to say about Ulterra’s bits: “The UD513 has been fast, cost-efficient and highly dependable; just what we looked for in a PDC bit.” “The latest improvements to our U513S and introduction of our U513M have shortened drilling time, ultimately reducing operator costs.” says Knull. Proven again in the Shaunavon field, a 222-millemetre U513S drilled 1,367 metres at an ROP of 111.6 metres per hour, saving the operator over eight hours in drilling time. Ulterra’s unique and diverse design philosophies produce more efficient designs while greatly expanding their bit design toolbox. Ulterra’s applications engineers and sales team work closely with their design groups to convey each customer’s needs and goals so the best design philosophy can be applied for each unique application. Ulterra was named “the fastest growing drill bit company” by Spears & Associates’ 2011 Oilfield Market Report, and continues to build momentum in 2012.
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O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
73
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BUSINESS
BUSINES INTELLIGENCE
Diverse factors drive surging chemical EOR interest in Canadian oilpatch
By Charles King, district account manager, TIORCO Inc.
Canadian EOR solutions
sweep efficiency in the reservoir. Polymer gel treatments are short-term
Interest in chemical enhanced oil recovery (EOR) has exploded around the world
injections of polymers and cross-linking agents that flow into fractures and
in recent years as an increasing number of fields reach maturity and rising oil
high-permeability thief zones where they harden and reduce the flow. This
prices improve the return on investment in this technology. The Canadian oil-
improved conformance diverts injected water into previously unswept low-
patch has emerged among the most aggressive at implementing chemical injec-
permeability layers.
tion as a means of boosting both secondary and tertiary recoveries.
Surfactant injection changes the “wettability” of the rock and reduces the
For more than three decades, TIORCO Inc. has been designing and carry-
interfacial tension between the injection water and the oil, freeing crude oil
ing out chemical EOR projects around the world, and we’ve seen the spike
from the pore throats of the formation. Surfactant effectiveness is signifi-
in Canadian activity first hand. In just the past five years, we have engaged
cantly improved in most reservoirs with simultaneous injection of alkali and
in one or more aspects of 15 chemical EOR projects in Canada, making it our
polymer. Injection of alkali depends on the type of formation, quality of water
most active market outside the United States. Additionally, Alberta Energy’s
and oil characteristics.
Innovative Energy Technologies Program (IETP) has funded at least 14 chemical EOR projects that are underway in this province alone.
Recent improvements in chemical formulation techniques have vastly expanded the number of reservoirs that are suitable for chemical EOR. The
We are witnessing multiple factors driving interest in this technology in
most important breakthrough has been the introduction of new polymer, cross-
Canada. First, of course, is the price of oil. Stable crude prices above $80 per barrel
linking and surfactant chemicals that remain stable at higher reservoir tem-
make EOR an extremely attractive investment—not just in Canada, but globally.
peratures and salinities. Unlike 20 years ago, today chemical floods are being
The second factor is the size of the prize in Canada. Low recovery rates for vis-
considered in reservoirs with temperatures exceeding 250 degrees Fahrenheit
cous oil in so many fields puts Canada’s typical remaining oil in place at well above
and salinities exceeding 200,000 total dissolved solids due to the improve-
50 per cent—even after waterflooding—which represents billions of dollars that
ments in the chemistries of surfactants and polymers.
can be tapped with the right technology as matched with reservoir conditions.
For polymer gel treatments, new methods of combining chemicals make
The third factor is the relatively large community of independent operators
it possible to place a gel at the precise location deep in the reservoir where it
in Canada with an entrepreneurial mindset. While the major multinational pro-
can perform most effectively at shutting down thief zones when it hardens.
ducers have focused on developing the oilsands regions, many independents
Surfactant formulations have also improved. Surfactants developed spe-
still work the more traditional fields. In our experience, these smaller operators
cifically for use in oil reservoirs can be injected at a fraction of the concentra-
tend to make faster decisions to try new technologies compared with their
tion—and cost—of the generic industrial surfactants used a few decades ago.
larger competitors. As a result, they move through the critical reservoir and
With today’s advanced chemical formulations, polymer floods and gel treat-
risk-analysis phases more rapidly and pull the trigger on field projects sooner
ments are boosting the recovery from waterflooding by five to 20 per cent.
than many of the big players.
Surfactant-polymer floods applied as a tertiary method can improve overall
A tradition of early adoption
production by 20–35 per cent. Another difference in the application of chemical EOR today is the level
The Canadian tradition of rapid adoption of new technologies in the oilpatch
of study that precedes a pilot injection. While phase behaviour tests, inter-
dates back to at least the 1980s. At TIORCO, we frequently get inquiries from
facial tension measurements and core floods remain cornerstones of the
operators that tried chemical EOR back then, before oil prices retreated,
process, computerized reservoir simulations enable operators to model a
and are taking a second look at the technology today. Most are pleased with
variety of chemical EOR formulations and injection scenarios on the com-
what they learn: chemical EOR today is far more efficient and cost-effective
puter. Bolstered by recent advances in computer processing speeds, these
than it was 20 or 30 years ago, primarily due to significant improvements in
applications can simulate reservoir conditions with great detail in three
reservoir simulation or modelling, and the introduction of customized EOR-
dimensions and model chemical flood results in a matter of hours.
specific chemicals, which can be used in smaller amounts. These technological
Not only do these high-fidelity 3-D models contribute to better under-
advances help improve overall project economics and help us better under-
standing of risk, prediction of reservoir response and project economics, and
stand the risk factors.
eventually overall project success, they also help weed out the reservoirs with
Although most chemical EOR injections now involve “designer molecules,” the
conditions that render them unsuitable for chemical EOR, saving time and
basic concept behind the technology has remained the same for all these years.
money in the process. Overall, the long routine of pre-pilot testing and analyses
Polymer floods involve continuous injection of partially hydrolyzed polyacryl-
that once took five to seven years before an actual field trial was launched now
amides or other polymers during waterfloods to increase the viscosity of the
takes an average of about two to three years—thanks primarily to advanced
injection fluid relative to the oil, causing mobilization of more oil and better
computer simulation. O I L & G A S I N Q U I R E R • J UNE 2 0 1 2
75
Prior to field trials, laboratory work today also focuses heavily on examining the quality of injection and produced waters. Because the presence of certain divalent minerals in the water directly influences the effectiveness of the chemicals and the concentrations in which they must be injected, understanding and developing an overall water strategy is critical. In alkali surfactant polymer (ASP) floods, for example, calcium and magnesium in high concentrations can react with the alkaline agent and cause scaling in the reservoir and wellbores. Predictive tools can be used to determine the potential damage or risk to the project. Based on this information, three possible alternatives can be modelled to determine which is more cost-effective before implementation: completely eliminate the alkali component, which may require a higher concentration of surfactant; install a water treatment plant to soften the water so the alkali can still be used without potential scaling issues; or implement an aggressive scale inhibition program along with the ASP project.
Canada’s unique advantages While the variety of internal and external factors noted above is driving chemical EOR adoption in Canada, several other unique advantages may be helping to guarantee a higher rate of success. Most notable is the existence of the Alberta Energy Resources Conservation Board in Calgary. Few, if any, countries or states have a similar organization that maintains meticulous records on the production performance of fields, reservoirs and formations dating decades back. Included in the archives are reports detailing the success—and failure—of every project implemented in Alberta. Access to this vital information gives EOR planners in that province an enormous head start in the pre-pilot analysis phase because it provides insights as to which technology may or may not work. Another advantage that is relatively unique to Canada is its long history of chemical EOR pilots and projects. Fields and formations that respond well to chemical injections are already well known. For example, the viscous crudes in north-central Alberta around Slave Lake and Pelican Lake suffer from the mobility and conformance problems that can be improved with polymer gels and chemical floods. Other formations including the Upper Mannville, Mannville and Upper Shaunavon have track records of success with ASP floods. Thirdly, Canada has a ready supply of EOR chemicals, most notably surfactants that are made either in the country or can be easily imported from the northern United States. Chemical availability is a crucial, but often overlooked, consideration in designing chemical EOR projects. Once a long-term flood has begun in a field, an interruption in chemical injection can set the project back and potentially hamper overall success.
Where EOR is heading in Canada? As noted at the outset, favourable oil prices are among the factors prompting operators to take a look at chemical EOR for increasing residual oil recovery from aging fields as a more attractive alternative for adding oil reserves than the drill bit. Based on experiences over the past few years, TIORCO operators are viewing these technologies in a different light that may signal a new trend in the oilpatch. Once applied late in secondary waterflooding or as a tertiary process, polymer and surfactant applications are increasingly being studied and applied earlier in the life of the field—with promising results. Already a specific trend in the favoured approached to EOR implementation is emerging. With so many fields suffering from conformance issues, more operators are investing in the relatively inexpensive polymer gel treatments earlier on in secondary recovery to get the most recovery from their waterflood. Only after the thief zones and perm streaks have been handled, the operators upgrade to full-scale polymer or surfactant-polymer flooding to improve overall contact of the formation. Fortunately, the track record of predicting the suitability of this approach for a specific formation has a much higher success rate today, thanks to advanced reservoir modelling and simulation capabilities. 76
J UNE 2 0 1 2 • O I L & G A S I N Q U I R E R
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advertisers' index ABB Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Advantage Valve Maintenance Ltd . . . . . . . . . 48 & 59 Allmand Bros Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 American Jereh International . . . . . inside back cover Annugas Compression Consulting Ltd . . . . . . . . . . . 12 ASAP Heating & Well Servicing Corp . . . . . . . . . . . . 22 Balon Corporation . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Barrett Tax Law . . . . . . . . . . . . . . . . . . . . . . . . . . . . .31 Bear Slashing Inc . . . . . . . . . . . . . . outside back cover Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . . . 32 Brent Gedak Welding . . . . . . . . . . . . . . . . . . . . . . . 48 Brews Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Brother’s Specialized Coating Systems Ltd . . . . . . . 17 Cameron Construction Services . . . . . . . . . . . . . . . 76 Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . . . . 24 Chevron Delo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 City of Grande Prairie . . . . . . . . . . . . . . . . . . . . . . . . 11 ClearStream Energy Services . . . . . . . . . . . . . . . . . . 4 Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . . . . . 30 Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Dean’s Pump Service Ltd . . . . . . . . . . . . . . . . . . . . . 59 DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Diversified Glycol Services Inc . . . . . . . . . . . . . . . . . 38
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J UNE 2 0 1 2 • O I L & G A S I N Q U I R E R
Dragon Products . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . . . . 63 Edmonton Exchanger & Manufacturing Ltd . . . . . . . 71 Expertec Van Systems Inc . . . . . . . . . . . . . . . . . . . . 16 Flexpipe Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 Gorman-Rupp of Canada Limited . . . . . . . . . . . . . . . 43 Hughson Trucking Inc . . . . . . . . . . . . . . . . . . . . . . . 68 Imperial Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . . . . . 74 Kubota Canada Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Lloydminster Heavy Oil Show . . . . . . . . . . . . . . . . . 52 Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Meridian Manufacturing . . . . . . . . . . . . . . . . . . . . . 21 Minimal Impact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 NETZSCH Canada Inc. . . . . . . . . . . . . . . . . . . . . . . . 38 Nexus Exhibits Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . 29 Norseman Structures . . . . . . . . . . . . . . . . . . . . . . . 60 Northgate Industries Ltd . . . . . . . . . . . . . . . . . . . . . 39 Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . . . 68 Ocean Fluids & Filtration . . . . . . . . . . . . . . . . . . . . . 64 Oil Lift Technology Inc . . . . . . . . . . . . . . . . . . . . . . . .77 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 Platinum Grover Int. Inc . . . . . . . . . . . . . . . . . . . . . . 25
Platinum Pumpjack Services Corp . . inside front cover Risley Equipment Inc . . . . . . . . . . . . . . . . . . . . . . . . 32 Sirius Instrumentation And Controls Inc . . . . . . . . . 56 Smart Completions Ltd . . . . . . . . . . . . . . . . . . . . . . 30 Southern Alberta Petroleum Show . . . . . . . . . . . . . 60 Sprung Instant Structures . . . . . . . . . . . . . . . . . . . . 37 Stewart Steel Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 Strad Energy Services . . . . . . . . . . . . . . . . . . . . . . 40 Systech Instrumentation Inc . . . . . . . . . . . . . . . . . . 64 Tank Gauging Systems . . . . . . . . . . . . . . . . . . . . . . 68 Tartan Controls Inc . . . . . . . . . . . . . . . . . . . . . . . . . . 31 TCA Marketing Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . 74 Tervita . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Trans Peace Construction (1987) Ltd . . . . . . . . . . . 48 ULTERRA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Vertigo Theatre Society . . . . . . . . . . . . . . . . . . . . . . 67 Veyance Technologies, Inc . . . . . . . . . . . . . . . . . . . . 35 Viking Pump of Canada Inc . . . . . . . . . . . . . . . . . . . . 20 Vortex Drilling Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . 64 Westeel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 ZCL Composites Inc . . . . . . . . . . . . . . . . . . . . . . . . . 28