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a better In sItu oIlsands producers test new technologIes to cut costs and access new resources
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oIl companIes clImb aboard potentIal alternatIve to pIpelInes
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F E A T U R E S
14
A better blueprint
23
In the crosshairs
By Darrell Stonehouse
In situ oilsands producers test new technologies to cut costs, access new resources
By Darrell Stonehouse and Elsie Ross
Safety and environmental concerns put pipeline operators under public scrutiny just as major expansions needed
29 8
September 2011 • OIL & GAS INQUIRER
riding the rails By Lynda Harrison
Oil companies climb aboard potential alternative to pipelines
there is white here
R EGI O N A L
35
N E W S
British Columbia
65
• New Cutbank Ridge joint venture coming, says Encana By Elsie Ross
43
By Pat Roche
69
cooperation
Central Alberta • Cardium's liquids-rich gas potential
71
Central Canada • Ottawa will defend oilsands,
TRAINING FACILITIES
says Oliver
73
East Coast • Offshore Boards update guidelines By James Mahony
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International • Xtreme contracts four XDR 500
starting to emerge
MWR CAMPS
drilling rigs
By Paul Wells
59
Northern Frontier exploration at Eagle Plain
By James Mahony
53
MAINTENANCE FACILITIES
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Northeastern Alberta • Oilsands monitoring plan requires
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Editor’s Note Vol. 23 No. 7 President & ceo bill Whitelaw | bwhitelaw@junewarren-nickles.com GrouP Publisher Agnes Zalewski | azalewski@junewarren-nickles.com AssociAte Publisher Chaz Osburn | cosburn@junewarren-nickles.com editoriAl director Stephen marsters | smarsters@junewarren-nickles.com
darrell stonehouse | dstonehouse@junewarren-nickles.com
editoriAl
The next oilsands wave
EDITOR
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Could Canada surpass Saudi Arabia as the global gas tank? This question isn’t as preposterous as it sounds. With existing oilsands producers developing enhanced recovery technologies to capture more already developed resources and efforts underway to exploit the 400 billion barrels of bitumen trapped in the Grosmont carbonates of northern Alberta, Canada is slowly moving tens of billions of barrels closer to the reserves category, as this month’s cover story indicates. One example of enhanced recovery in the oilsands includes wedge wells that capture leftbehind resources in between existing horizontal well pairs. Cenovus Energy Inc., which pioneered the infill drilling technology, says they are increasing recovery by up to 10 per cent at its Foster Creek and Christina Lake developments. Another enhanced recovery technique is solvent-aided thermal recovery. Imperial Oil is using its version of the technology, called LASER, at its Cold Lake cyclic steam stimulation project. It reports recovery increases of as much as 35 per cent from pads using the technology. With the massive resource in place, these incremental gains in recovery could translate into major reserve additions as they become more commonplace. But an even bigger breakthrough is in the early stages at Saleski where Laricina Energy Ltd. is beginning to produce from its Grosmont carbonate project. Company president and chief executive officer Glen Schmidt says the Grosmont carbonate play is the biggest prize left in the industry. “The ERCB [Energy Resources Conservation Board] describes the Grosmont as a resource with more than 400 billion barrels in place. Applying a recovery factor of only 25 per cent to those volumes could add over 100 billion barrels to the current 175 billion barrels recognized as recoverable bitumen to total over 275 billion barrels, making Canada number one in terms of oil supply in the world,” he told shareholders at the company’s annual meeting. “Saleski is more than just Laricina’s first development—it is breaking ground at a world scale.” But having a world-scale resource in place and developing the technologies to exploit it is only part of the story. To make the hundreds of billions of dollars in investment needed to fully exploit the oilsands, Canada needs access to global markets. Inside you will find a review of the efforts to build the infrastructure to access global markets and the resistance they are encountering. Both the Keystone XL pipeline to the U.S. Gulf Coast and the Gateway Pipeline accessing Asian markets via the Canadian west coast will be needed if the oilsands are to grow to their full potential. But both lines are facing stiff opposition as environmentalists target pipeline companies as a secondary means of attacking oilsands development itself. Another alternative to moving product to market is also taking shape—railway. A number of companies are already shipping production to market using North America’s extensive railway network and rail companies are working hard to gain market share. Ultimately, millions of barrels per day could be shipped by rail, and in this month’s issue we review the economic argument in favour of shipping bitumen above ground.
NE X T
I S S U E
In the October issue we take a look at resource plays in northeastern British Columbia and how explorers and developers are honing their game plans in the face of low gas prices. We also take a look at the oilfield hauling sector and how the boom in multistage fracturing, using millions
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.
of tons of sand and millions of gallons of water, is affecting the trucking industry. OIL & GAS INQUIRER • September 2011
11
Stats
AT A GLANCE Alberta Completions
WCSb Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
MONTH
OIL
GAS
OTHER
TOTAL
MONTH
OIL
GAS
DRY
SERVICE
TOTAL
Jul 2010 Aug 2010 Sept 2010
131 168 357
110 135 638
38 43 59
279 346 1,054
Jul 2010 Aug 2010 Sept 2010
193 452 617
9 156 790
16 40 45
4 15 23
222 663 1,475
Oct 2010 Nov 2010 Dec 2010
404 579 676
460 847 403
46 169 294
909 1,595 1,373
Oct 2010 Nov 2010 Dec 2010
678 868 1,061
581 989 559
39 75 78
18 165 238
1,316 2,097 1,936
Jan 2011 Feb 2011 mar 2011
226 353 650
145 294 974
82 127 222
413 774 1,846
Jan 2011 Feb 2011 mar 2011
409 723 1,069
201 378 1,081
33 38 64
17 99 164
660 1,238 2,378
Apr 2011 Jun 2011 Jul 2011
419 209 105
472 124 43
112 100 97
1,003 433 245
Apr 2011 Jun 2011 Jul 2011
618 428 298
509 197 97
46 12 15
81 183 88
1,254 818 490
Wells Drilled In british Columbia
Saskatchewan Completions
Source: B.C. Oil and Gas Commission
Source: Daily Oil Bulletin
MONTH
WELLS D R I L L E D
CUMULATIVE *
MONTH
OIL
GAS
OTHER
TOTAL
Jul 2010 Aug 2010 Sept 2010
65 45 40
481 526 566
Jul 2010 Aug 2010 Sept 2010
220 198 197
7 12 5
0 7 6
227 217 208
Oct 2010 Nov 2010 Dec 2010
42 43 49
608 651 700
Oct 2010 Nov 2010 Dec 2010
201 217 340
12 3 2
11 64 11
224 284 353
Jan 2011 Feb 2011 mar 2011
62 69 55
62 131 186
Jan 2011 Feb 2011 mar 2011
136 321 316
4 6 8
3 7 4
143 334 328
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
*From year to date * from year to date
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September 2011 • OIL & GAS INQUIRER
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FAST NUMBERS
2,556
1,492
Number of oil wells completed in Alberta in the first seven months of 2011, up 67 per cent from last year.
Number of oil wells completed in Saskatchewan in the first seven months of 2011, up 37 per cent over last year.
Drilling rig Count by province/territory
Drilling Activity: Oil & Gas
Western Canada August 15, 2011 Source: Rig Locator
Alberta July 2011 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
AC T I V E (Per cent of total)
Western Canada Alberta
346
211
557
62%
british Columbia
57
31
88
65%
manitoba
12
-
12
100%
Saskatchewan
112
40
152
74%
WC totals
527
282
809
65%
Northwest territories
0
0
0
0%
OIL WELLS
Alberta
GAS WELLS
July 11
July 10
July 11
July 10
Northwestern Alberta
21
27
28
74
Northeastern Alberta
8
23
0
0
Central Alberta
65
59
10
21
Southern Alberta
11
23
5
16
105
132
43
111
tOtAL
Service rig Count by province/territory
Drilling Activity: Cbm & bitumen
Western Canada August 15, 2011 Source: Rig Locator
Alberta July 2011 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
AC T I V E
Western Canada
COALBED METHANE
Alberta
Alberta
391
292
683
57%
british Columbia
13
15
28
46%
manitoba
13
4
17
76%
Saskatchewan
150
47
197
76%
WC totals
567
358
925
61%
Northwest territories
0
0
0
0%
BITUMEN WELLS
July 11
July 10
July 11
July 10
Northwestern Alberta
0
1
1
5
Northeastern Alberta
0
0
7
23
Central Alberta
2
0
27
8
Southern Alberta
1
4
0
0
tOtAL
3
5
35
36
OIL & GAS INQUIRER • September 2011
13
Photo: Joey Podlubny
FEAturE
Steam generators at a SAGD operation. Much of current innovation is aimed at reducing steam use and cutting energy costs.
14
September 2011 • OIL & GAS INQUIRER
FEAturE
A better by DArrell StonehouSe
W
Photo: Joey Podlubny
ith 80 per cent of Alberta’s 171 billion barrels of oilsands reserves too deep to mine, finding means to bring that trapped resource to the surface economically has been the goal of wave after wave of technical innovators for generations. Breakthroughs have come in fits and starts, with cyclic steam stimulation and steam assisted gravity drainage (SAGD) the major technological leaps making nearly 140 billion barrels of bitumen commercially accessible. But another innovation push is now underway, promising to add reserves from the existing in situ resource base and possibly add tens of billions of new reserves from the 400 billion barrels of bitumen trapped in the carbonates of northern Alberta. Imperial Oil Limited has been the pioneer in making the in situ oilsands industry a reality. In 1966, it developed and patented cyclic steam stimulation, a process it used to develop its Cold Lake oilsands holdings. In 1982, it patented SAGD, opening up more of the oilsands to development. These two technologies underpin current in situ operations in the province. Imperial continues to innovate to turn more of its existing bitumen resource base into reserves, Bruce March, Imperial
Wedge wells target left-behind bitumen between horizontal well pairs on drilling pads.
OIL & GAS INQUIRER • September 2011
15
FEAturE
“[ W ]e anticipate that our teams will be able to commercialize at least one new technology each year for the next several years.” — brian Ferguson, president and Chief executive Officer, Cenovus energy Inc.
Photo: Joey Podlubny
Oil’s chairman, president and chief executive officer, recently told shareholders at the company’s investor days. Imperial’s Cold Lake operations have produced more than one billion barrels of bitumen, with decades of production ahead as new technologies unlock incremental reserves at existing operations and the company expands into untapped areas. “When we started at Cold Lake 30 years ago, we expected recoveries of between 10 and 15 per cent and through the use of technologies and our operating experience and expertise, we’ve got that up to 50 per cent now,” March said. With some of its new technologies, Imperial is headed to 60 per cent in the next decade, analysts heard. “The interesting thing about the oilsands is that we have been able to find ways to get more of this resource up using selective technologies that really work with cost scales that are market competitive,” he said. “Our company will continue to have Cold Lake to be really the benchmark of our whole company.” There are still an estimated 700 million to 800 million barrels of undeveloped resources at Cold Lake, said Glenn Scott, senior vice-president of resources. To improve in situ recovery from existing wells, it is evaluating new steam flooding techniques for late-life wells in which it will drill new steam-only injector wells and continue to produce from existing wells. In older development areas, this will encourage the flow of steam from the new injector well toward producing wells, accessing bitumen that cannot be reached with the single injector and producing well, contributing significantly to the higher recoveries. Imperial has commercialized LASER technology in which solvent is added along with steam in mid-life wells to improve recovery with no additional steam input. Over about two cycles, recovery is up about 35 per cent compared to a typical cyclic steam stimulation well. Scott said the company is also piloting technologies that will allow it to develop in situ resources that don’t readily lend themselves to existing technologies. At Cold Lake, it is piloting solventassisted SAGD where solvent is added to lower-pressure steam and the mix is injected into the formation. It is also preparing to pilot a solvent process targeting more challenging reservoirs where heat can easily be lost out of the formation, making thermal recovery technologies ineffective. This technology could potentially eliminate the use of steam altogether, reducing water use and significantly reducing greenhouse gas intensity. Cenovus Energy Inc. has also been a pioneer in commercializing in situ oilsands recovery technology as part of Encana. In 2001, its Foster Creek operation became the industry’s first commercial SAGD operation. It is also the largest, with 180 wells producing around 115,000 barrels of bitumen per day. Cenovus also has a second commercial operation at Christina Lake with 19 wells producing 18,000 barrels per day. Like Imperial Oil, Cenovus continues adapting new technologies to increase reserves and recovery. “Our commitment to technology and innovation is a key part of our execution strategy,” Cenovus president and chief executive officer Brian Ferguson told analysts in presenting the company’s 10-year plan in June. “At any one time, our teams are working on about 60 technologies designed to improve efficiency, reduce environmental impact and lower costs. We currently have 10 pilot
Solvent-aided SAGD aims to increase recovery while reducing energy usage.
projects planned or underway and we anticipate that our teams will be able to commercialize at least one new technology each year for the next several years.” One Cenovus innovation is the use of wedge wells to recover bitumen left in the space between two SAGD well pairs drilled from the same pad. A wedge well is a single horizontal well drilled between the two well pairs that allows for pumping that oil to the surface. Cenovus has drilled 51 wedge wells at Foster Creek with production averaging between 600 and 800 barrels per day OIL & GAS INQUIRER • September 2011
17
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FEAturE
per well in the 35 wells on production. It plans on drilling 10 more wedge wells in 2011. At Christina Lake, it has drilled four wedge wells with three on production at 300–400 barrels per day. The wedge wells have a steam to oil ratio of less than 0.1, making the oil produced very profitable. Cenovus expects to increase recovery by as much as 10 per cent from existing operations using wedge well technology. Cenovus is also testing the use of solvents to improve in situ thermal recovery. Its system is called Solvent Aided Process (SAP)
we recovered about 75 per cent of the oil in less than 24 hours. This shows you something about the quality of the rock and how easily it releases the hydrocarbons,” Svarte said. “So, if you can extract the oil by heating it to 140 Celsius, instead of 240 Celsius, it’s a huge saving in energy needs.” During the TAGD test, AOSC inserted mineral-insulated cable into the wellbores and turned the heaters on to heat the reservoir for six to 10 months. Svarte said the company expects to turn the lower well into a producer this fall or early winter.
“If successful, [thermal assisted gravity drainage] could be the key to producing bitumen carbonate reefs globally.” — Sveinung Svarte, president and Chief executive Officer, Athabasca Oil Sand Corp. (AOSC)
Photo: Joey Podlubny
and uses butane as the solvent to free up more bitumen. The company has run two SAP pilots, at Senlac and Christina Lake, along with an isolated test of the technology at Christina Lake that began in 2009. Compared with SAGD, the Cenovus pilot projects had a 30 per cent production rate improvement and added 15 per cent to total oil recovery. It comes with an upfront increase of 30 per cent in initial capital costs, which is recovered by a three per cent reduction in annual fuel use, a 10 per cent decrease in annual sustaining capital and a five to 10 per cent reduction in non-fuel operating costs. Overall, Cenovus says SAP could add $1 per barrel to netbacks. Cenovus is also testing combustion technology in the Wabasha and Clearwater formations. In the Wabiskaw in the Foster Creek area, it launched an air injection pilot that demonstrated the technology can heat underlying bitumen to drain down to horizontal producing wells. In the Clearwater, Cenovus plans on piloting a technology called Gas Cap Air Injection for Thermal Oil Recovery (GAITOR) in 2012–13. Athabasca Oil Sand Corp. (AOSC) is also pushing the technological envelope, testing thermal assisted gravity drainage (TAGD) at its Dover West Leduc carbonate play, president and chief executive officer Sveinung Svarte said during the company’s firstquarter conference call. TAGD is a lower-energy form of SAGD. AOSC’s winter drilling program included two horizontal wells to test heat-conductive behaviour using TAGD with four associated observation wells. “The reason why we looked at [TAGD] is we took samples from this very good rock and heated it up in labs and, already at about 140 degrees Celsius, which is 90 degrees lower than normal SAGD,
thermal assisted gravity drainage (tAGD) means using lower temperatures to heat bitumen, thus cutting costs.
“If successful, TAGD could be the key to producing bitumen carbonate reefs globally,” he said. “These types of reservoirs could be heated at lower temperatures, thus needing less energy and potentially saving significant operating costs.” Svarte said the company also injected quantities of steam into the highly fractured reservoir and observed that a good steam chamber was formed. He said the initial conclusion is that SAGD remains a viable option to heat the bitumen in this formation, which management believes is good news. In addition to further steam tests, Svarte said the company anticipates applying for a TAGD pilot of up to 12,000 barrels per day in late 2011 with a view to obtaining regulatory approval in late 2012 or early 2013. Construction would commence shortly thereafter with start-up in late 2013 or early 2014. Laricina Energy Ltd. made headlines in late December of last year when it announced first steam at its Saleski Grosmont Carbonate Oil Sands Pilot, an industry first. OIL & GAS INQUIRER • September 2011
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The Saleski Pilot is designed to test Laricina’s version of solvent-aided thermal recovery, a process it calls solventcyclic SAGD or SC-SAGD. In addition, the Saleski Pilot will help Laricina confirm the Grosmont as an economic formation for SAGD, test specific well design and well placement to exploit the dual zone carbonate opportunity of the C and D zones in the formation, and assist in establishing production performance cur ves for both SAGD and SC-SAGD for the Grosmont. Company president and chief executive officer Glen Schmidt says the Grosmont carbonate play is the biggest prize left in the oilsands. “ T he ERCB [Energ y Resources Conser vation Board] describes the Grosmont as a resource with more than 400 billion barrels in place. Applying a recovery factor of only 25 per cent to those volumes could add over 100 billion barrels to the current 175 billion barrels recognized as recoverable bitumen to total over 275 billion barrels, making Canada number one in terms of oil supply in the world,” he told shareholders at the company’s annual meeting. “Saleski is more than just Laricina’s first development—it is breaking ground at a world scale.” Schmidt says the carbonate play is not only attractive because of the bitumen in place. It also has the geological attributes needed to be produced economically. “Not only does the Grosmont have scale, it also has quality,” he explained. “The pay thicknesses can exceed 50 metres and the porosity can average nearly 25 per cent, which is a very large number for a carbonate and also critical to thermal oil recovery. You make money heating oil, not rock, and low-porosity carbonates do not meet the quality of the Grosmont.” Schmidt said so far the pilot is performing as expected. “We are pleased with our successes each step of the way, starting with our development of the drilling methods to completion and first recorded production in the Grosmont,” he noted. “The first phase of any in situ project is the start-up. This is the phase where the objective is to heat two parallel horizontal wells as effectively as possible in order to mobilize the bitumen and create a steam chamber when the bitumen is produced. At Saleski we have been able to advance to production very efficiently with less energy than a typical McMurray SAGD project. In other words, compared to the typical McMurray,
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we’ve been able to convert to production with less energy driven by the quality of the reservoir and the ability of the formation to produce oil. “We can and have drilled horizontal wells within the Grosmont successfully,” he added. “Our completions, in terms of their ability to manage any solid production from the formation, have been successful to date. The pump designs, the facility and certainly the details of operations, all important foundational steps, have been successful to date.” Schmidt said the addition of solvent to the SAGD process is just an extension of the enhanced oil recovery techniques being used in conventional oilfields. “Why solvent?” he asked. “Solvent has features in enhanced recovery that we’ve seen many times: it leaves less oil behind, it changes the architecture of the steam chamber and it increases the rate of production.” Laricina is also testing its patented Passive Heat-Assisted Recovery Method, or PHARM, at Saleski. PHARM uses heat emanating from one steam chamber to recover bitumen from an adjacent zone. “A notable application of PHARM will be in the Grosmont formation where we plan to enhance the basic SAGD well architecture by managing the heat conducted between formations and thus optimize recovery,” said Schmidt. “We will be examining other opportunities and formations within in situ recovery where the adjacent formations will benefit from the integration of the exploitation schemes with the movement of heat between adjacent zones.” While advancing its solvent-aided thermal recovery technique and PHARM, the company is also looking to the future. In 2010, Laricina filed jointly with Harris Corporation—a communications firm—a patent application for the process and use of radio frequency heating called Enhanced Solvent E xtraction Incor porating Electromagnetic Heating. T he partnership established with Harris includes Suncor Energy Inc. and Nexen Inc. “This joint program offers the potential advancements for the application of augmenting or replacing steam w it h solvent w it hin t he SAGD architect ure,” said Schmidt. “To support this program we received a $16million grant from CCEMC [Climate Change and Emissions Management Corporation], the Alberta Agency focused on technology to reduce carbon emissions.”
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Photo: TransCanada Corp.
in the
crosshAirs SAFety AND eNvIrONmeNtAL CONCerNS put pIpeLINe OperAtOrS uNDer pubLIC SCrutINy JuSt AS mAJOr expANSIONS NeeDeD by Darrell Stonehouse and elsie ross
r
ising oilsands production, combined with a need to develop new markets for natural gas, is leading to a new wave of proposed pipeline construction in Canada and the United States. A spate of pipeline leaks and fierce opposition to the export infrastructure from environmentalists and First Nations, however, are making it difficult to move forward on any of the projects. Oilsands production in northeastern Alberta is expected to reach three million barrels per day by 2020, according to the latest Canadian Association of Petroleum Producers forecast. Total Canadian crude oil production is predicted to reach 4.2 million barrels per day.
That is, if the country can find markets for the growing production. As it stands, Canadian oil and growing production from the Bakken play in North Dakota and Montana is creating a massive bottleneck at Cushing, Okla. In mid-July, that bottleneck resulted in West Texas Intermediate crude trading at a $22-per-barrel discount compared to world prices. With Canada currently producing 2.5 million barrels per day, this discount is costing $55 million per day. The natural gas industry is also facing issues in finding markets for production. The shale gas revolution in the United States has severely limited demand south of the border, just at the time when the revolution has taken hold here in Canada.
New export markets are needed for the industry to grow. There are a number of proposed pipeline megaprojects to move growing oilsands production to market. The furthest ahead is TransCanada Corporation’s Keystone XL Project. The 2,673-kilometre, 36-inch crude oil pipeline would begin at Hardisty, Alta., and extend southeast through Saskatchewan, Montana, South Dakota and Nebraska, incorporating a portion of the existing Keystone pipeline through Nebraska and Kansas before continuing to Texas. It would allow for 500,000 barrels per day to be shipped to markets on the Gulf Coast. The U.S. government has been dragging its feet on making a decision on whether OIL & GAS INQUIRER • September 2011
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it should go forward. Initial opposition to the line came from environmentalists and landowners worried about the environmental impacts of the oilsands and concerns about the effects a leak would have on the Ogallala aquifer, a massive shallow underground reservoir that provides water for much of the U.S. breadbasket. But with Enbridge Inc.’s major oil leak from a pipeline in Minnesota last year, and a spate of smaller leaks on the existing Keystone
deliver imported condensate to Alberta for use in the oilsands. Enbridge president and chief executive officer Pat Daniel said at a recent speech to the Empire Club in Toronto that there are distinct disadvantages to relying solely on U.S. markets for the country’s oil exports. He said with only one market, Canadian producers are price takers. “The United States likes—perhaps even prefers—Canadian oil. It is secure
“CANADA’S WeSt COASt IS tHe GAteWAy tO HALF tHe GLObe’S GeOGrApHy AND NeArLy HALF OF tHe WOrLD’S pOpuLAtION.” — pat Daniel, president and Chief executive Officer, enbridge Inc.
line, the debate has now shifted to focus on whether bitumen from the oilsands carries greater risk for pipeline safety. In July, U.S. congressman Henr y Waxman asked regulators to examine whether oilsands crude is more corrosive to pipelines than traditional sources, making them more likely to spring leaks. Speaking to the Energy and Commerce committee, Waxman said he was concerned pipeline safety regulations didn’t ref lect the changing composition of crude imports. “I’m concerned that the industry is changing, but the safety regulations are not keeping up with the changes,” he said. “That could be a recipe for disaster down the road.” A nt hony Sw i f t of t he Nat u r a l Resources Defense Council echoed Waxman’s comments. “It is in the public’s best interest for our pipeline safety for regulators to evaluate the risks that high volumes of heavy, corrosive and abrasive crude, such as diluted bitumen, will have on the U.S. pipeline,” Swift said at the committee meeting. Enbridge is also meeting stiff opposit ion for it s Nor t her n Gateway Project. The proposed $5.5-billion project would deliver 525,000 barrels per day of oilsands production to the port of Kitimat, B.C., where it would be loaded into large crude tankers bound for Asian markets. A parallel pipeline would 24
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and reliable,” said Daniel. “But they have other options. A world of global energy options. We don’t.” Building the pipeline would give Ca nadia n i ndust r y new opt ions by opening up global markets to Canadian supply, he said. “Canada’s west coast is the gateway to half the globe’s geography and nearly half of the world’s population,” he said. “It is an essential driver of our future economic success.” Enbridge is making a strong economic argument in favour of Northern Gateway. According to independent estimates, over the duration of 30 years the project will add $270 billion to Canada’s gross domestic product—about one-fifth of Canada’s total economic output in one year. “It is literally a transformative injection of new economic opportunity to Canadians for a generation,” said Daniel. But opposition to Northern Gateway is equally strong. Many First Nations along the pipeline route have banded together with environmental groups in a well-organized campaign attacking Enbridge. Both the federal Liberal and New Democrat parties support a ban on tanker traffic in coastal waters, which would kill the project as well. Daniel said those opposing the line need a dose of reality. “The project will proceed only if we can rise above the mounting clamour of a coalition of hard-line activists and their political
allies committed to saying no to proposed projects and initiatives rather than seeking balanced, sustainable development and supporting continued prosperity for our entire country,” he said. “We say no to nuclear, we say no to coal, we say no to oil, we say no to fracturing wells to recover natural gas, but we say yes to light switches, cooked food, school buses and gas pedals.” T he Ca nad ia n E nerg y P ip e l i ne Association (CEPA) says the greater environmental and regulatory demands being put on industry are making it very difficult to move new projects forward. “This is an inflection point in our history,” Brenda Kenny, president and chief executive officer of CEPA, told the Insight Information Ltd. North American pipeline forum. “When you look at regulatory options, aboriginal consultation, environmental stewardship, I think that 10 years from now we will either be living in a world that is collaborative, effective and progressive or a world that is defensive, litigious and very much more painful to manoeuvre in, either as a company or as a consumer.” CEPA members transport virtually all of the crude oil and natural gas produced and used in Canada and that fact has not gone unnoticed by some of the opponents of oil and gas, whether they are motivated by a vision of off-oil and zero emission energy or by a mistrust of large corporate undertakings, said Kenny. “We need to win the day on avoiding getting flipped into a defensive culture of fear,” she said. “We need to be responsible, direct and clear that we are the ones who hold the keys to the best possible solutions and it’s time that we stepped up and demonstrated that that’s what we’re about.” In her presentation, Kenny said the environmental assessment is migrating from a planning tool and an effective way to vet projects at a reasonable level up to a “very elaborate, detailed gut-wrenching level of investment.” Companies have told her that, while they once budgeted about one per cent of the capital cost of a project to go through environmental assessment, that is now closer to five per cent, she said. With more than $100 billion in major resource projects on the books in Canada over the next five or six years, that would amount to $5 billion on environmental assessment. The pipeline sector will be doing appropriate and detailed investments
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Photo: Joey Podlubny
toward environmental protection, but $3 billion of that estimated total cost could be better spent on good environmental monitoring and regional environmental assessments, the tracking of populations such as woodland caribou and strategies for boreal forests, she suggested. “We need to take a much more holistic, integrated approach to these things and these are absolutely central to business risk,” said Kenny. Kenny said environmental groups are currently hoping to put enough roadblocks in front of projects that eventually they become unviable. “You’ve got a window of opportunity for a major development and if you miss that window you’ve got a problem. NGOs [non-government organizations] know that and that’s their strategy. It’s stall and delay to kill; you don’t have to kill it outright,” she explained. The forum also heard a discussion of how pipeline companies can best approach the issue of aboriginal consultation on major projects. “When we engage aboriginal communities, we do so from a position of
the idea that shipping bitumen could erode pipelines quicker is the latest argument being used against the Keystone XL project.
respect, genuine interest and humility, recognizing that they are the local experts,” said Jody Whitney, manager of aboriginal consultation and regulatory compliance for Enbridge Pipelines. “Enbridge takes nothing for granted,” she said. “We appreciate that, as project proponents, we are involving aboriginal communities in a process that they themselves have not initiated.” Companies need to be prepared to provide resources for that process, be willing to compromise and expect positive outcomes for both the project and the aboriginal community, she said.
In her presentation, Whitney outlined how Enbridge, as part of its recent mainline expansion program, had initiated what she described as difficult discussions with the Birdtail Dakota Sioux, a nontreaty First Nation in southern Manitoba. “They were not initially receptive to our proposal and in fact were extremely distrusting of corporate Calgary, and in this particular case of Enbridge, where we were proposing a major project through their territory,” she said. However, through its willingness to provide resources and support of the community's interest and willingness to compromise
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on process, Enbridge eventually earned the community’s trust, said Whitney. In retrospect, fundamental to the company’s success was gaining an understanding through its research of who the true decision makers were in the community, she said. “It was in fact not until we gained the trust of the elders who subsequently directed chief and council to proceed in exploratory discussions with us that we made any successful inroads.” Enbridge looks to First Nations near its projects to guide the company on how it might provide sustainable and meaningful benefits in their communities. One initiative at Birdtail that Enbridge is especially proud of is the seed money it provided to a band-operated store, said Whitney. The initiative was not only sustainable, but it addressed a critical local need, she said. The most important thing the company has learned over several years of experience in aboriginal engagement is that cookie-cutter approaches do not work, said Whitney. “One size does not fit all. Recognize local community protocols and design
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s u it able a nd i n nov at ive c on s u lt ation programs to meet unique needs and interests.” It also is important for companies to conduct due diligence and research at the earliest opportunity to understand the aboriginal claimants’ treaty and aboriginal rights in the area, said Heather Treacy, a partner at Fraser Milner Casgrain LLP. If there are rights, consultation should take place as early as possible in the planning stages and, if concerns are raised, the company should try to understand those and develop a relationship with the aboriginal group. Providing accurate information to the potentially affected group as early as possible will assist it in identifying any of its rights. It’s also important to ask the aboriginal group about their interests in the area, as there may be information about traditional land-use studies that will assist. “In some instances, it may be appropriate to provide financial contributions towards expert assistance for the aboriginal group to understand the nature of the project.” While governments are responsible for consultation with aboriginal groups,
their failure to do so also has consequences for pipeline companies if there is an order to carry out additional consultation, she said. In another area, companies will be expected to deal with issues such as migratory birds and critical habitat when it comes to pipeline construction, said Dean Mutrie, vice-president of major projects for TERA Environmental Consultants. For example, on its Alberta Clipper crude oil pipeline across the Saskatchewan prairies, Enbridge Pipelines spent more than $1 million studying a particular species of bird, he noted. A later study found that while the birds would avoid nesting on the pipeline right-of-way, actual construction did not affect the net survival rate within the setback distance. Critical habitat is another big issue that still needs to be determined and a major issue will be boreal caribou, as they cover half of northern Canada, said Mutrie. Companies can also work with aboriginal communities to integrate aboriginal traditional knowledge and traditional land use into their environmental assessments, he said.
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riding
thee rails
OiL COMPANiES CLiMb AbOArD POtENtiAL ALtErNAtivE tO PiPELiNES Photo: Gerald Ford
by Lynda Harrison
M
oving crude oil by rail is nothing new. It’s how the commodity was transported until the late 1800s before John D. Rockefeller came up with the idea of pipelines as an alternative, and today is still carried this way in parts of the world where pipelines don’t exist. Now several Canadian companies have started using rail as an alternative to pipelines and proponents say it’s catching on. “It’s kind of going crazy,” said Glen Perry, president of Altex Energy Ltd., which has partnered with Canadian National Railway Company (CN) to promote the concept of moving bitumen by rail to create new markets for the hydrocarbon. Canadian Pacific Railway is also getting a piece of the oil transportation pie. The market has opened up “a fair bit” and interest in receiving bitumen where Canadian pipeline access cur rently doesn’t exist has been expressed “from all over the place, really,” said Perry. Buyers such as refiners and asphalt plants in places such as California, Texas,
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Photo: Gerald Ford
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Around 5,000 barrels per day are currently being shipped by rail out of Alberta.
Louisiana and the east coast have made proposals, he said. Interest has grown in the past six months, he continued. It’s gone from producers saying they’ll review the proposal to asking, “Can you do it tomorrow?” he said. Perry estimated seven or eight companies are now moving their heavy oil by rail, five of them moving bitumen, but he would not disclose their names due to confidentiality agreements. He guessed about 5,000 barrels per day of western Canadian production is currently being shipped by rail. “You keep bringing on supply and you don’t build takeaway, it’s inevitable what happens,” said Perry. “It’s just happened a lot quicker than we thought it was going to happen, maybe as a result of all the pipeline problems. We can’t even take away as much oil as we thought we could.” CN’s three terminals are not built for heavy oil, so custom loading and unloading facilities are needed in Peace River, Fort McMurray and the Cold Lake/ Lloydminster area of Alberta. But their construction is proceeding slowly, he said, and no shovels have hit the ground yet. Connacher Oil and Gas L imited has been transporting diluted bitumen (dilbit) by rail since the first quarter of this year to expand its markets and raise the price of its production, Pete Sametz,
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Connacher’s president and chief operating officer, said. Sametz said rail companies have been responsive to the company’s needs. “It’s another option. It’s developing and it’s something to watch.” “Dilbit by rail is still in its early stages, but we are trying to develop markets for essentially moving raw bitumen to parts of North America and/or the coast that can take advantage of it,” said Sametz. “We’d rather have our dilbit priced not on WCS [Western Canadian Select] but more related to the world oil price. Given that the pipelines have had apportionment and it’s caused differentials to widen or be landlocked so we can’t get the stuff out as easily as we could, then we would like to get our pricing as close to the refinery gate as possible based on some other marker than just the WCS.” Possible markets for Canadian heavy crude oil and bitumen are the U.S. Gulf Coast (USGC), the California coast and the U.S. Midwest. Moving heavy crude and bitumen to the USGC makes a lot of sense now because that area’s refineries could use it to replace its current, dwindling sources from Venezuela and Mexico, said Sametz. Connacher had been using rail to transport asphalt to markets from its refinery in Montana. “Rail can get you just about anywhere,” Sametz said. “It’s like the Harry Potter stairway. You get on the stairs at one end and they move to wherever you need to go. That’s the beauty of the railway. You get on at one end here, with your bitumen or dilbit, and then you can end up
in different places depending on what are the best markets.” Currently producing around 15,000 barrels of oil equivalent per day, mostly from near Fort McMurray, Connacher’s volumes are not yet such that a pipeline makes economic sense so production has been trucked. Its long-term strategy is to use truck, rail and eventually pipeline, said Sametz. Rock Energy Inc. chief executive officer Allen Bey told a recent industry conference his company is sending 500 barrels a day of oil directly to USGC refiners from its rail-loading facilities in Lloydminster. The company leased 30 rail cars to gain access to a wider range of markets for its Lloydminster heavy oil and is adding as much as $6–$7 a barrel to the netbacks, Bey said. CN has the rail while Altex is handling everything else: the terminals, loading and unloading, and putting producers and refiners together, explained Perry. Altex looks after all the rail cars, Randy Meyer, CN’s senior manager of business development, told the Canadian Institute’s North A merican Pipeline Symposium in June. “You pay a toll for that, that’s it, that’s all and you deliver your oil to a terminal.” According to CN, it has been moving diluent, pipe, aggregate, steel, cement, sulphur and petroleum coke into and out of the oil-producing regions of western Canada and now it is prepared to transport from 1,000–200,000 barrels of bitumen per day from Alberta’s oilsands to the USGC, the U.S. Midwest or eastern and western Canada. Warren Chandler, regional manager of CN western Canada public and government affairs, said CN has been testing concepts to move crude from western Canada to various markets in the United States. Since October 2010, it has been providing truck-to-rail transportation for Bakken crude oil, used as diluent for bitumen, at Wilmar, Sask. From October 2010 to June 2011, CN has moved more than 1,900 cars of freight from the Bakken formation—more than 60 single cars of petroleum crude in large blocks loaded directly from truck to rail, said Chandler. Rail cars can carry between 550 and 680 barrels depending on the product and rail type. Pure bitumen in an insulated coal car, for example, has capacity for 550 barrels.
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“When the type of oil that needs to go to a market changes, pipelines are dedicated to a certain type of oil and you’re kind of committed….” — randy meyer, Senior manager of business Development, Canadian National railway Company
CN has direct access to the Louisiana Gulf Coast, and, through the company’s rail interline partners or barge, can access the Texas Gulf Coast. Oilsands projects are all within about a 100-kilometre radius of the end of CN’s network just east of Fort McMurray’s Linton yard at the end of Highway 69. The yard is currently being used to truck in commodities such as sulphur and petroleum coke, and to truck out products like heavy components for construction. Trains have capacity for about 60,000 barrels of bitumen and do not need to
run full. Shippers only pay for what they use when they use it. According to CN, five trains can take the equivalent of a 400,000-barrel-per-day pipeline. Meyer promoted rail as a complementary option to pipelines and part of a portfolio approach to market access. “When the type of oil that needs to go to a market changes, pipelines are dedicated to a certain type of oil and you’re kind of committed, but rail is segregated each way so you don’t have to worry about whichever oil you want to deliver,” Meyer told the conference.
The network provides connections from Fort McMurray–area oilsands to upgraders in Alberta’s Industrial Heartland near Edmonton and to the port in Prince Rupert, B.C., where production can be shipped to Asian destinations such as Hong Kong, Shanghai and Tokyo. Rail can get bitumen f rom Fort McMurray to the USGC in 10 days versus 50 or 60 days via pipeline, he said. Shipped by rail, bitumen does not have to be diluted, he added. “In fact, it’s better if you don’t because there’s no point. Not having to dilute bitumen with diluent makes transport safer because, in the case of a break or crack, it won’t escape into the environment. At ambient temperature it doesn’t flow,” said Meyer. Rail shipments of bitumen use existing infrastructure, avoiding the necessity of getting permits and approvals that proposed pipelines such as Northern Gateway and Keystone XL are going through, he said. Rail also offers less risk, as much of the capital has already been spent and
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already in Prince Rupert; we’re already at the west coast.” He said CN is moving intermodal containers from Prince Rupert into Chicago in 100 hours. “We can move product very fast if it’s in that type of unit train service.” Enron Oil and Gas Resources is moving about 70,000 barrels per day by way of about three or four trains per week through Saskatchewan, said Meyer, adding that North Dakota Bakken producers are trucking north up to CN’s facility. PADD III (USGC), the largest refining location in the United States, contains between one million and 1.5 million barrels a day of coking capacity within a 50-mile radius of CN’s facilities where the company’s trains interchange with connecting carriers, said Meyer. “It’s kind of amusing when I read in the paper that there’s this angst and gnashing of teeth about Keystone and I’m going, ‘My goodness, we’re already there.’ We can go there and we are. We are shipping product there,” he told the conference. CN is also serving PADD V. “No surprise, right? Because that’s where the money is, that’s where the value is. That’s where the differentials support us. And we’re even now talking about going into as far as PADD I—the U.S. east coast—so it’s quite something,” said Meyer. CN is continuing to test the reloading of condensate, he said. “That’s the nice thing about rail, is you can reload your condensate in the same car…. So you can bring it back, and when you bring it back, not even Southern Lights [pipeline] can compete with our tolls.”
Even if railcars return empty, rail is still less expensive than pipelines, he said. “We did a study where we took the Association of American Railroads’ published rates, which averaged out all the traffic that moves and all its products. That average…is about 16 per cent less than pipeline costs.” Asked about public opposition to transporting oil by rail, Meyer said, “We started moving condensate through Kitimat and there wasn’t a peep. Now, if you’re going to move crude and you’re going to advertise that I’m not naïve enough to say that you’re not going to have opposition, but the opposition then comes to that port and that tankage area that you’re going to have to build and in the case of Prince Rupert, that’s a federal port which has a whole different regulatory regime than anywhere else, but you narrow your scope. You’re not going through a bunch of bands and such to get there. We can get there and increase our traffic with no problem.” He said each train can carry about 10,000 tonnes or about 55,000 barrels a train. “If you’re looking at 10 trains a day, which is one every two hours, that’s about 550,000 barrels a day. That’s a lot. You can put a lot of traffic on there. And don’t forget, a barrel on rail is not a barrel on pipeline because a barrel nominally is a 30–70 blend of oil and diluent, right? …We r u n a b o u t 135 trains a day in wester n Canada. CN runs 90 trains a day just of coal so these things are easily possible.”
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it does not require 20-year take-or-pay commitments or $10-billion investments. Infrastructure commitments would likely consist of $5-million or $10-million terminals, he said. A scalable transportation option, rail lowers the risk of project development, he said. Steam assisted gravity drainage producers run the risk of having fields that don’t perform to expectations while having already built pipelines. That risk does not exist with the rail system. “You scale into what you need.” Rail also offers security, he said. If something goes wrong with a pipeline and there is an interruption, producers have no alternative mode of shipment. Meyer suggested they use rail as part of their portfolio by having some component of their production moved on rail so that they can “dial it up or dial it down depending on market demand.” CN is moving more than one million tonnes of petroleum coke from upgraders and about 250,000 tonnes of sulphur out of its Alberta terminal to the port of Prince Rupert in British Columbia and as far south as Florida. Meyer indicated a slide depicting CN’s coal terminal at Prince Rupert, which receives coal trains carrying the volumetric equivalent of 750,000 barrels per day of coal, and the nearby road/rail corridor. Also near the terminal is the site of a future potash terminal. “This is going to accommodate up to nine high-speed, high-throughput tracks and you can actually put tanks right in here,” said Meyer. “We can connect. We’re
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The TELUS World of Science—Calgary is in the process of building and outfitting our new science centre. This series of articles explores the things that we’re learning along the way as we develop new kinds of experiences with our visitors. Pilot Testing/Prototyping and the Value of Trying stuff out early and often. By Julie Bowen, Vice President, Content Part 1 of 2 “To invent, you need a good imagination and a pile of junk.” ~ Thomas Alva Edison Your boss comes to you one day and asks you to come up with a new series of products— for a new client group with whom your company has very little experience and very little street cred. Or another scenario that might be closer to home: your kid asks you to help them come up with an idea for a killer science fair project that involves building a gadget to automatically measure the growth rate of plants. What do you do other than wonder how up-to-date your resume might be? Try to steer your kid to a more ‘manageable’ project—like comparing the different types of mould that grow on bread? Even better, how about passing this one on to your spouse? What if instead of the (inevitable) panic, you thought about this as an opportunity to take a risk—after all you really don’t have a lot to lose. Your boss is unlikely to fire you for not coming up with something that the organization has no background in—and remember that negative results are totally acceptable in the pursuit of science or science fair projects. (You could always hedge your bets and have that bread mould experiment happening at the same time.) So how do you start? Try unleashing your inner ‘experimenter’. IDEO (a design firm with an international reputation) has analyzed its successful approach to designing products, processes and services, and describes not only techniques and tools, but also the types of people, roles or personas that are critical to the development of innovation. One of these roles is the ‘experimenter’— “someone who loves to play, to try different ideas and approaches.”1 IDEO further defines the experimenter as “someone who makes
ideas tangible—dashing off sketches, cobbling together creations of duct tape and foam core, shooting quick videos to give personality and shape to a new service concept.”1 Before you decide that’s a role for someone else, be assured that anyone can do this. It’s really a question of mindset. Jeff Dyer and Hal Gregersen in their new book The Innovator’s DNA suggest that “good experimenters understand that although questioning, observing and networking provide data about the past (what was) and the present (what is), experimenting is best suited for generating data on what might work in the future. In other words, it’s the best way to answer our “what-if” questions as we search for new solutions.”2 Well that’s the theory, now back to the problem (or opportunity) at hand. Assume that you’ve come up with a bunch of ideas for what to do (brainstormed with a team or looked to other fields for ideas that could translate to your industry)—the question is what to do next. One of the more powerful tools to tackle new product or new service development is pilot testing—the quick construction of an idea to spark discussion or to provide something tangible to test or experiment with. Some would call this prototyping—our experience has encouraged us to have a stage before prototyping. Prototypes have been traditionally seen as more solidified ideas, constructed to handle more rigorous testing where technical, interface or design issues are being addressed. Prototyping, for us, is the step after you know what ideas to pursue. How do you pilot test? It’s really up to you and what you’re trying to find out. But after years of pilot testing and thousands of pilot tests later (we’ve pilot tested every exhibit that will be in the new science centre and had a whole lot that didn’t make the cut), we’ve found that the characteristics, or rules if you prefer, of successful pilot testing can be summarized as: Build it fast and cheap—cardboard, duct tape, foam core, hot glue and a good pile of
junk are the best resources for this kind of activity for a couple of reasons. It’s hard to get precious about an idea that is built out of junk, that can be changed quickly and that doesn’t have a huge investment of time. Use pilots to test out a theory, an idea or to clarify a conversation. Words will only go so far in the development of something—by bringing the idea into a physical manifestation, the conversation changes from vague statements like “that would never work” to “oh that’s what you meant” or “if we moved this over here that would do this.” Consider this 3-dimensional brainstorming. Watch for Part 2 in next month’s edition!
End notes: 1
Kelley, Tom. 2005. The Ten Faces of Innovation. Doubleday. 276 pages.
2
Gregersen, Hal and Dyer, Jeff. 2011. The Innovator’s DNA: Mastering the Five Skills of Disruptive Innovators. Harvard Business Review Press. 304 pages.
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British Columbia
New Cutbank ridge joint venture coming, says encana
Photo: Joey Podlubny
By Elsie Ross
Encana is targeting its drilling to liquid-rich areas of its resource plays.
Encana Corporation has received strong interest from new potential joint-venture partners in its Cutbank Ridge natural gas properties after it was unable to reach a final deal with a unit of PetroChina Company Limited, Encana’s top official said in early July. The interest is indicative of the high quality of these assets in Alberta and British Columbia, Randy Eresman, president and chief executive officer, told analysts in a conference call to discuss second-quarter results. Despite the lack of an agreement, “the process we undertook has gone a long way to demonstrate the tremendous value that we created in Cutbank Ridge,” he said. PetroChina would have paid $5.4 billion in a 50/50 joint venture that included both land and infrastructure, but this time around Encana will be offering a variety of joint venture opportunities for portions
of the undeveloped resources at Cutbank Ridge while retaining the producing assets. Eresman anticipates a deal around the end of this year. Encana plans to sell the Cutbank pipeline and processing assets to a midstream company, which could be as early as October, he said. In the second quarter, successful drilling programs translated into a nine per cent increase in production to approximately 1.51 billion cubic feet equivalent per day from 1.41 billion cubic feet last year, said Mike Graham, president of the Canadian division. Year-to-date, production is up 13 per cent to 1.51 billion cubic feet equivalent per day from 1.33 billion cubic feet in the second quarter of last year. The Cutbank Ridge resource play performed exceptionally well in the quarter with production up 20 per cent to an average of 535 million cubic feet equivalent
per day, driven by production across the Montney formation despite the wet weather in the Peace Country, he said. During the quarter, Encana saw promising results from wells drilled across its Cutbank Ridge lands, he said. It successfully completed its second Steeprock Doig horizontal well with an initial production rate of 18 million cubic feet per day and plans to drill two additional wells in the formation in the second half of this year. Encana also commissioned a two-well pad in the Montney where the condensate-togas ratio exceeded its type curve expectations by 25 per cent on average. Initial production rates from the wells were 3.5 million cubic feet per day and 4.1 million cubic feet per day, with condensate levels of 40 barrels and 90 barrels per million cubic feet, respectively. At Horn River, Encana began completion operations on the north half of the D1-d pad and by the end of the quarter had completed about 60 per cent of its planned stimulation. Its partner, Apache Canada Ltd., completed stimulations on the 34-L pad, pumping 162 stimulations into the nine wells on the pad. So far, the wells are performing at, or above, expectations. For the five Muskwa wells, the 30-day initial production rate per completion interval was about 12 million cubic feet per day per well, while the four Evi wells had an average 30-day initial production rate of 10 million cubic feet per day, about three times better than the previous Evi wells. The company is also seeing excellent performance from its Jean Marie play where it has maintained flat production with only a two-rig program, said Graham. Its dual multi-lateral wells are producing about 20 per cent more than single wells and cost only about 10 per cent more, while the triple multi-lateral wells are producing 40 per cent more gas for 20 per cent more capital.
brItISH COLumbIA WeLL ACtIvIty WELL LiCENCES
JUL/10
JUL/11
48
66
▲
WELLS SPuDDED
JUL/10
JUL/11
47
48
▲
WELLS DriLLED
JUL/10
JUL/11
60
51
▼
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • September 2011
35
British Columbia
Higher prices needed to spur gas drilling Higher natural gas prices are needed for producers to achieve solid rates of return, while incremental technological improvements are expected to help lower costs and enhance recoveries in the field, industry executives said during a conference on unconventional resources in July. Responding to a question about an outlook for natural gas prices at the TD Securities Unconventional Energy Conference, John Dielwart, chief executive officer of ARC Resources Ltd., said that it’s plain to see a “wall” of natural gas will be developed. “There’s a tremendous amount of gas out there, there’s no question about that,” he said. “But when you really look at all the plays, the amount of the gas that works at $4 is a very small subset.” Plays like the Horn River Basin and deeper, tighter Montney that don’t have associated liquids are going to require higher prices to be economic. “We’re not of the view that today’s gas prices of $4–$4.50 are sustainable for the long term,” Dielwart added. “But it is
important for our industry to find alternative markets, whether it’s gas-to-oil…or LNG [liquefied natural gas] projects [that] can get a new market or finding new markets in North America.” The industry needs higher prices to develop available resources, he said, adding that doesn’t necessarily mean $7–$10 gas. “Once you get to $6 you have a pretty robust business,” Dielwart noted. “A lot of information you’ll see will talk about breakeven costs of $3.50–$4. Well, nobody’s in this business to break even. And if you’re breaking even at the project level, you’re not making money at the corporate level. “Our view is that you really do need to be generating…30–40 per cent-plus rates of return in the field to generate adequate returns, full-cycle, in the corporation. When we see all these low numbers on break-even costs in the field, those are not indicative of the prices that the industry needs to sustain a business.” Derek Evans, president and chief executive officer of Pengrowth Energy
Corporation, said one element that could keep gas prices down for the next 18–24 months is the number of joint ventures that have been signed. “They have a completely different subset of economics associated with them,” he said. “The second thing I would point to is the focus on liquids-rich gas. That is a completely different set of economics. Until we work through those types of pieces, we’re still going to have a supply imbalance. On the long term, I’ve talked about the importance of LNG, not only in terms of gas prices, but we’ve got to move away from a North American island-based economy for natural gas. It’s absolutely critical that if we want to participate in the Asian markets that we have the ability to supply them off the west coast of Canada.” That must happen quickly because of competition from Australia, he added. There are several competitors for the Kitimat LNG plant in that country. “The biggest single thing that we can do to relieve the North American
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British Columbia
“You’re constantly trying to get top technology improvements but at the same time save costs. We probably now do 20 per cent of our fracs on a 24-hour basis." — michael Culbert, president and Chief executive Officer, progress energy resources Corp.
pressure is the development of export LNG,” Evans said. Mike Wood, vice-president of Canadian shale for Talisman Energy Inc., noted that companies in the United States are still drilling to hold acreage. “Once the acreage is held, I believe you’ll start seeing the rigs laid down and that will take the pressure off supply,” he said. Meanwhile, other producers at the conference touched on the evolution of technology and how that will help drive down costs while improving recoveries. Keith MacPhail, president and chief executive officer of Bonavista Energy Corporation, noted that technology continues to evolve.
“Longer laterals, multi-leg laterals are certainly coming into play pretty quickly,” he said. “Given the stacked nature of the Deep Basin, typically the single lateral only accesses one zone.” He added that completion fluid technology is also continuing to evolve, which will help enhance recoveries or lower costs. David Anderson, president and chief executive officer of Lone Pine Resources Inc., added that due to horsepower costs of the slickwater systems, there could be some more coil tubing–based completions. “We’ve had very good success on our Evi program on an oil basis of shaving pretty much a day off the completions by using coil tubing, getting horsepower down, keeping costs a little more at bay.”
Michael Culbert, president and chief executive officer of Progress Energy Resources Corp., said moves that can help reduce costs include reducing the amount of fluid or sand being pumped. “You’re constantly trying to get top technolog y improvements but at the same time save costs,” he said, noting t he economies of scale achieved by using pad operations. “We probably now do 20 per cent of our fracs on a 24-hour basis. “If we could increase the number that are done on a 24-hour basis, that’s going to help [on] the cost side. Obviously there’s manpower pressure [associated with these operations].” — DAILY OIL BULLETIN
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OIL & GAS INQUIRER • September 2011
37
British Columbia
trans mountain facing opposition from environmental groups Canadian oilsands producers looking to the Trans Mountain Pipeline ULC system and Port Metro Vancouver for access to new Asian markets are running into similar objections as those voiced by opponents to Enbridge Inc.’s proposed Northern Gateway project from Alberta to Kitimat, B.C. Trans Mountain, which is seeking regulatory approval to offer crude oil firm transportation service to its Westridge marine terminal in Burnaby, B.C., is facing opposition from a raft of environmental and community groups. In letters to the National Energy Board (NEB), the groups cite concerns about increased tanker traffic off the west coast, the risk of oil spills, the effect of tanker traffic on marine life and the lack of public consultation. The NEB also has received a letter from MEG Energy Corp., which recommends that the application be denied. The oilsands operator says that while it agrees with the importance of developing access to new markets that require water-borne
solutions, it does not believe the proposals in the application are the best way to support these objectives. Removing capacity from common carriage is not appropriate when the other means to provide additional certainty to shippers have not been canvassed, it says. Trans Mountain says it f iled its application in response to its shippers’ requests and growing market demand for firm service to Westridge in order to access and continue development of existing and new offshore markets. Since 2003, capacity for the 300,000-barrelper-day pipeline has been allocated bet ween uncommitted land shippers and uncommitted Westridge shippers. Nominations for dock capacity are currently allocated on a monthly basis using a “bid-premium” method. Trans Mountain wants to reallocate 27,000 barrels per day of land capacity to the Westridge dock for a total of 79,000 barrels per day of capacity and reinvest the firm service fees it receives in capital activities and preliminary activities supporting
pipeline expansions. In an open season last year, dock shippers signed up for 54,000 barrels per day of firm service in 10-year contracts with an average fee of $1.50 per barrel in addition to the pipeline toll. Kinder Morgan Canada Inc., which operates Trans Mountain, has suggested that NEB approval of the application could be the catalyst for future expansions that could increase pipeline capacity to 700,000 barrels per day through phased expansions. In a letter to the NEB, the Raincoast Conservation Foundation says these incremental applications and expansions would effectively quadruple the number of tankers travelling through the Georgia Strait and Gulf Islands. “The implications of these expansions will be significant, particularly in the event of a tanker spill, collision or other mishap,” it says. “In this application, British Columbians are being asked to bear these additional risks with virtually no public engagement.” The Islands Trust, a federation of local governments, notes in its letter of
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per day to Westridge with shipments of up to 143,000 barrels per day, it notes. The tanker route through the Gulf Islands and Georgia Strait also overlays large sections of the legally designated critical habitat of southern resident killer whales, which are listed as “endangered” under Canada’s federal Species at Risk legislation, according to the Raincoast Conservation
Photo: Joey Podlubny
comment that there currently appear to be no regulatory limits on the volumes that Trans Mountain can deliver to the Westridge terminal, and that the only limits on tanker- or oil-barge traffic are Trans Mountain’s capacity and the Port Metro Vancouver’s operating limits for Second Narrows. Last year, Trans Mountain shipped an average of 80,000 barrels of oil
Foundation. Increased tanker traffic not only increases the risk of a catastrophic spill, but also presents concerns about physical and acoustic disturbance, it says. The NEB also has received letters of support for the Trans Mountain application from shippers who have signed up for firm service. PetroChina International (America) Inc. says that it committed to firm capacity on the pipeline, which it sees as the first step in developing longterm relationships with Canadian oil suppliers. The subsidiary of PetroChina International Company Limited said it also wants to gain firm access to transportation that can be used to increase crude oil supply to the Pacific Basin. Cenovus Energy Inc. says it believes that having firm service to the Westridge dock will assist it in diversifying the markets to which it sells its growing oil production. Certainty of access to transportation capacity will enable it to supply customers on a regular and predictable basis, facilitating the development of long-term relationships with markets accessible from the west coast, it says. — DAILY OIL BULLETIN
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39
British Columbia
Advantage approves $216m budget, Glacier expansion Advantage Oil & Gas Ltd. has approved a $216-million capital budget for the next year, of which $200 million is allocated to its Glacier project. The Phase 4 development program at Glacier has two key objectives: increase throughput capacity at the Glacier gas plant to 140 million cubic feet per day from 100 million cubic feet per day by the second quarter of 2012 and drill a sufficient number of wells to fill the plant ($155 million), and further evaluate the Middle and Lower Montney formations ($45 million), where the company believes significant potential for resource and reserve growth exists. In conjunction with the anticipated production increase at Glacier, corporate production is forecast to grow 24 per cent to a first-half 2012 exit rate of approximately 29,000 barrels of oil equivalent a day, at which time Glacier will represent about 80 per cent of total production. Since 2008, drilling results at Glacier have increased the quality and magnitude of the company’s Montney natural gas
• • • • • • • • • • •
resource, which is contained in approximately 290 metres of formation in the three major gas layers (and numerous sublayers) of the Upper, Middle and Lower Montney, said Advantage. A total of 60 net Montney horizontal wells (51.3 net Upper Montney and 8.7 net Lower Montney) have been drilled on the company’s 80 net section land block, which the company said offers significant opportunity to further delineate and develop each of the Montney layers. Following a review of drilling results to date, Advantage believes its Montney well inventory could be between 900 and 1,150 horizontal wells. Advantage’s capital program will be funded primarily out of cash flow, un-drawn credit facilities and potential divestments of conventional assets. The company said drilling results during its Phase 3 program (June 2010 to June 2011) exceeded expectations and confirmed the continuation of high-quality Upper Montney reservoir characteristics in the northeastern and southeastern areas of its land block.
The last 32 Upper Montney wells have demonstrated an average 30-day initial production rate in excess of five million cubic feet a day, which is a 56 per cent improvement over the initial 12 wells, Advantage said. This improvement has resulted from improved completion technology combined with a better understanding of the Upper Montney geology. A total of 51.3 net wells have been drilled in the Upper Montney, which translates to a well density of 0.6 wells per section on the company’s land block. Advantage estimates the threshold well economics to drill an Upper Montney well to be approximately $3 per thousand cubic feet. In the Lower Montney, Advantage has drilled a total of 12 (8.7 net) horizontal wells since 2008 including four (four net) wells as part of its Phase 3 program. The company said Lower Montney wells to date have demonstrated 30-day initial production rates up to 3.8 million cubic feet per day but exhibit relatively shallow declines, which indicate significant reserve potential. — DAILY OIL BULLETIN
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Northwestern Alberta/Foothills
Nordegg interest grows
Photo: Joey Podlubny
By Pat Roche
the Nordegg is the latest formation being targeted by new fracturing technology.
Western Canada’s list of emerging oil plays is steadily expanding as producers broaden their use of the horizontal multi-frac technology that has dramatically increased production from tight formations such as the Bak ken and the Cardium. During remarks to his company’s annual meeting in July, Bill Andrew, chief executive officer of Penn West Petroleum Ltd., very briefly commented that the latest oil horizon to get industry attention is the Nordegg. Penn West declined to comment further on the Nordegg, citing competitive reasons for not discussing emerging exploration opportunities. The potential for a Nordegg tight oil play was flagged when an emerging junior explorer, Anglo Canadian Oil Corp., bought 269 sections of Nordegg lands in Alberta Crown sales in March 2010.
A nglo asked A J M Pet roleum Consultants to do an estimate of in-place Nordegg oil on its lands between townships 66 to 79 and ranges 20W5 to 04W6. Last June AJM completed the study of in-place Nordegg oil on Anglo Canadian’s
exploration target. Only about a half-dozen wells have been completed for oil production from this rock, said Dave Hume, a geologist and director of multi-client studies at Canadian Discovery Ltd., which completed a Nordegg tight oil study early this year. Hume said some vertical wells in the Ante Creek area have had cumulative production of about half a million barrels a day. In its evaluation of Anglo Canadian’s lands, AJM cited a 1988 well, 04-11-6325W5, which unsuccessfully targeted the Leduc and was then completed in t he Nordegg, ult imately producing 198,011 barrels of oil with a low water cut. Another well, 15-05-66-24W5, was unsuccessful as a Montney test in 1987. It was completed in the Nordegg and produced more than 266,000 barrels of oil with a negligible water cut. In conclusion, AJM recommended Anglo Canadian drill a series of vertical wells to acquire modern log data and rock data before deciding horizontal well placement in each of the four areas. “Prolonged testing of horizontal wells will help to determine the economic potential of these opportunities,” the AJM study said. “Once these issues are better understood, AJM will be able to better
Investment firms are enthusiastic about what they call Nordegg “shale oil” potential. 172,000 acres at Rycroft, Kakut, Sturgeon Lake and Ante Creek North, all in northwestern Alberta. A J M estimated that the Nordegg oil in place on those lands ranged from 4.93 billion barrels to 8.51 billion barrels with a best estimate of 6.48 billion barrels. It was too early to estimate recoverable resource. The Nordegg shale has long been known as a source rock but has rarely been an
determine whether it is appropriate to assign resources and reserves.” Anglo Canadian drilled a horizontal well (Shane 07-11-77-03W6) on the northern portion of its lands and a vertical test (Sturgeon Lake 05-10-68-22W5) on its western properties. Both were fracture stimulated and produced small non-commercial volumes of about 25- to 26-degree API gravity oil. “But we did learn a lot,” said Anglo Canadian president Jim Ehret. For
NOrtHWeSterN ALbertA/FOOtHILLS WeLL ACtIvIty WELL LiCENCES
JUL/10
JUL/11
210
254
▲
WELLS SPuDDED
JUL/10
JUL/11
170
212
▲
WELLS DriLLED
JUL/10
JUL/11
156
144
▼
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • September 2011
43
Northwestern Alberta/Foothills
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example, cores from the wells will help the company develop a more efficient fracture stimulation. Anglo Canadian has since purchased aeromagnetic and gravity studies as well as seismic data and Canadian Discovery’s Nordegg tight oil study. Using all of this data, the company will try to find sweet spots on its Nordegg acreage. In addition to its fully owned lands, Anglo has a pooling/farm-in agreement with Quatro Resources Inc. covering several sections in the Ante Creek North area where both the Nordegg and the Montney are oil prone. Anglo plans to operate the drilling of two Nordegg wells this summer. The success of those wells will determine future drilling plans, Ehret said. Investment firms are enthusiastic about what they call Nordegg “shale oil” potential. In a report last October on emerging Canadian “shale oil” plays, Macquarie Equities Research said the reser voir characteristics of the Nordegg compare favourably to other resource plays in western Canada. Because of the Nordegg’s rich organic content, oil in place is estimated at 18 million to 24 million barrels per section— “which is one of the highest among the plays we evaluate,” the Macquarie report said. In a short paper last March on the Nordegg, Peters & Co. Limited said: “Existing data reveals that the Nordegg has many attractive qualities, not the least of which is a potentially large amount of oil in place.”
Another plus, Peters noted, is the area has historically had lots of oil and gas development and hence has good infrastructure and access to services. (Peters is referring to what it calls Greater Simonette—a nine-by-15-township area from about 60-17W5 to 69-05W6.) Galleon Energy Inc. has 150 sections of land in the Kakut and Worsley areas that are in the Nordegg oil fairway, said Jim Iverson, Galleon’s vice-president of exploration. The company hasn’t drilled specifically for Nordegg oil yet, but it has recompleted some old wells—the results of which are still confidential—and done some core studies, said Iverson. Galleon plans to drill a horizontal well, but not in the near term. “There are some key oil producers at Ante Creek, which is in township 67, range 25. And then our acreage starts in 71. That’s about 30 miles north,” said Iverson. He expects the play to start in the Simonette area and evolve northward into the Kakut area. Canadian Discovery’s Hume said the industry still has to “crack the code” on the Nordegg. “They know the oil is there. They know the oil can move because we’ve seen some good shows and some good wells,” he said. But the challenge is to figure out how to drill and frac the wells to get economic production rates. “My gut [feeling] is that there are a lot of people looking at this,” Hume said, “and they’re sort of close to the stage where they’re going to crack the code on the Nordegg.”
blackpearl provides mooney update BlackPearl Resources Inc. has commissioned its polymer facilities for phase one of its alkali surfactant polymer (ASP) flood at the company’s Mooney project. The company has started injecting soft water into the reservoir and has added polymer and other chemicals. It is anticipated that it will take six to 12 months of injection before there will be meaningful increases in oil production, BlackPearl said. The first phase of the ASP f lood included construction of water- and chemical-handling facilities, as well as
converting 22 (out of a total of 49 wells) existing oil-producing wells into polymer injection wells. The Mooney operation suffered delays and shut-in production in May due to forest fires in the area, and most recently wet weather caused some delays with respect to construction and start-up of the polymer project. During the second half of 2011, BlackPearl plans to drill up to seven wells at Mooney—three vertical stratigraphic wells and four horizontal producers that are needed to complete the
Northwestern Alberta/Foothills
injection/production pattern within Phase 1 of the ASP flood. At the company’s pilot steam assisted grav it y drainage (SAGD) project at Blackrod in the Athabasca oilsands, steam injection began in May and is in the initial warm-up phase where steam is injected into both of the horizontal wells. After the warm-up phase (two to four months), the lower well will be converted into a producer to establish the SAGD process. BlackPearl is continuing to work on the regulator y application for a 40,000-barrel-per-day first phase of commercial development at Blackrod. The application is expected to be filed during the first half of 2012. Ultimate production potential for Blackrod is over 70,000 barrels per day. Meanwhile, at Onion Lake, 76 wells have been drilled in the first six months of the year. While spring weather has hampered production operations in the second quarter, all new drills should contribute to third-quarter production. BlackPearl expects to drill a total of 100–120 wells at Onion Lake in 2011. The company has not established the timing for SAGD development at Onion Lake; however, it plans to pre-drill some of the horizontal wells before it completes conventional development to reduce the risk of reservoir damage caused by lost circulation from drilling through partially depleted zones. “Operationally, two of our primary objectives for 2011 were to complete con st r uc t ion a nd com mence stea m injection at Blackrod and to initiate commercial development of a polymer f lood at Mooney,” John Festival, president of BlackPearl, said in a news release. “I am very pleased that we have met these objectives and I look forward to positive results from both of these projects over the next several months. Conventional development at Onion Lake is ongoing as planned and we have started preparing for thermal development in the area. “Oil production growth has been hampered during the first half of 2011 due to lack of rig availability, wet weather and the forest fires in northern Alberta this spring; however, we still expect to reach our production target of 11,000 barrels per day by the end of the year.”
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45
Northwestern Alberta/Foothills
Shoreline buying peace river Arch production Shoreline Energy Corp. has entered into agreements to acquire three private oil and gas companies for a total purchase price of $34.58 million for production and reserves, undeveloped land, seismic and facilities. The acquisition adds an estimated 640 barrels of oil equivalent per day of production, 57,000 net acres of land, as well as reserves of 1.55 million barrels of oil equivalent on a total proved basis and 2.49 million barrels of oil equivalent on a proved-plus-probable basis. Shoreline said the acquisition provides a strong and diverse platform to continue its consolidation program in the Peach River Arch area, while concurrently shifting its liquids and natural gas mix closer to a 50/50 weighting by providing a large inventory of organic projects from which to grow reserves and production. T he t r a n sac t ion s w i l l i nc rea se Shoreline’s production by 78 per cent to 1,400–1,450 barrels of oil equivalent per day. The deal adds more than 30 vertical and horizontal drilling locations targeting light and medium grade oil. It also includes between 20 and 30 low-risk optimization projects, with relatively low capital requirements. In addition, Shoreline said the transaction involves a portfolio of over 40
potential natural gas drilling opportunities, including high-impact Doig and Montney liquids-rich natural gas, as well as the addition of two 100 per cent working interest and operated gas processing facilities. Assuming completion of the transactions, Shoreline’s capital budget over the remainder of 2011 and through 2012 will focus on developing light oil from the Charlie Lake formation from Shoreline’s land holdings in the Progress, Pouce Coupe and Bonanza areas at depths of between 1,450 and 1,650 metres; developing medium grade oil from the Gething and Cadomin formations on over 10,000 net acres of land in the Hines Creek area at target depths of 1,000 metres; drilling its first highimpact wells, targeting both oil and natural gas in the Doig and Montney for mations; continuing to optimize existing production assets through wellbore recompletions, restarts and facility optimization; acquiring new 2-D and 3-D seismic data in three project areas through a combination of new acquisition and purchase of available industry trade data; and drilling initial test well or wells on a high-impact Viking resource oil play in the Redwater area of central Alberta. — DAILY OIL BULLETIN
Artek reports success at Sinclair/Glacier
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September 2011 • OIL & GAS INQUIRER
As a follow-up to its 2010 horizontal Montney gas discovery, Artek Exploration Ltd. says it has successfully completed its second horizontal Montney gas well (50 per cent production working interest) in the Sinclair/Glacier area of Alberta. The well was drilled to a total measured depth of 4,400 metres in the first quarter of this year and subsequently completed after breakup with 10 out of a planned 14-stage fracture stimulation program using nitrogen foam frac technology. A f te r a 216 -hou r c lea n-up te st period, and a 22-hour single point flow test, the well flowed at a restricted rate of 6.7 million cubic feet per day (10 per cent nitrogen) at a flowing pressure
of 1,065 pounds per square inch (7,342 kilopascals). The company said it is pleased with the test results and has released testers due to road and lease conditions. Subject to third-par t y timing, management expected the well to be on production by the end of August. Meanwhile, in the Inga area of British Columbia, the company has spudded the first of three consecutive horizontal wells following up on its liquids-rich Doig discoveries that tested approximately 1,895 barrels of oil equivalent per day (1,100 barrels per day condensate) and 2,040 barrels per day (1,400 barrels per day condensate) in January and March of this year.
Northwestern Alberta/Foothills
The first well is a farm-in on thirdparty lands that will allow the company to earn three sections of land adjacent to Artek’s earlier operations. The well is targeted to reach a total measured depth of approximately 2,600 metres (including an approximately 700-metre horizontal lateral) and was expected to be completed in early August. The second and third horizontal wells of the summer program are expected to be drilled back to back in August and September and completed consecutively in October, and are planned for a total
Creating Value for our Customers
Artek's first horizontal well at 06-03-88-23W6 is anticipated to be brought back on at restricted rates over the next several weeks as facility capacity allows. measured depth of 3,000 metres including approximately 1,300–1,400-metre horizontal laterals. Artek’s existing producing wells at Inga were temporarily shut in through June for a scheduled plant turnaround at the Sprectra McMahon facility. Since being brought back on after the turnaround, Artek’s horizontal well at 05-1188-23W6 has been using the current full capacity of the company’s facility and producing at an average restricted rate of approximately 1,510 barrels per day, of which approximately 695 barrels per day (46 per cent) were natural gas liquids. The company’s first horizontal well at 06-03-88-23W6 is anticipated to be brought back on at restricted rates over the next several weeks as facility capacity allows. Facility expansion operations are underway at Inga and the company expects to be able to process up to 16 million cubic feet per day of natural gas and associated liquids through its Inga-operated facility by the fourth quarter of 2011. In the immediate area, Artek holds interests in approximately 25 (15 net) sections of land, almost all of which it operates, and has an additional three sections under option through the farm-in commitment well that it is currently drilling.
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Northeastern Alberta
Oilsands monitoring plan requires cooperation
Photo: Joey Podlubny
By James Mahony
the federal government wants to see improved monitoring of air and water in the oilsands region.
The federal government has released an integrated environmental monitoring plan for Alberta’s oilsands. “The oilsands represent a significant, long-term economic advantage for the people of Alberta and all Canadians. We must ensure that this resource is developed in a way that protects our air, our water and biodiversity for generations to come,” federal Environment Minister Peter Kent said in releasing the plan in July. “With our partners and all Canadians, we want a world-class monitoring system to protect the economic future of our industry, while we ensure environmentally sustainable production in the best way we can.” At the same time, because jurisdiction over environmental issues is shared between Ottawa and the provinces, Kent acknowledged the plan means “cooperation
is imperative to ensure that every aspect of oilsands development gets the scrutiny it deserves.” T he a n nou ncement represented Phase 2 of a broader plan and follows the release in March of Phase 1, known as the Lower Athabasca Water Quality Monitor ing Plan, which af fects t he Lower Athabasca River, source of water for several oilsands plants. Phase 2 of the plan expands the Athabasca plan, both in the area covered and in the comprehensiveness of coverage. Overall, the integrated monitoring plan is a series of technical documents that prescribe which environmental factors should be monitored, where, when and how. The plan’s second phase broadens monitoring to include not just water, as in Phase 1, but also air quality, wildlife
monitoring and biodiversity. Phase 2 also provides for improved measurement of environmental effects downstream and downwind of the oilsands, in northern Alberta, Saskatchewan, the Northwest Territories and Manitoba. T he mon itor i ng pl a n c ome s i n response to earlier adv ice f rom the Federal Oilsands Advisory Panel, which reported last December to the federal environment minister, noting key shortcomings in current oilsands monitoring, and outlining what would be needed for Canada to achieve a “world-class” environmental monitoring plan. A key philosophy of the new plan is that the frequency of sampling and the geographic extent of coverage are linked to what the plan’s drafters call “decision triggers.” In effect, this means monitoring can be enhanced if certain changes are detected at a given site, while alternatively, it can be reduced if repeated sampling reveals no significant changes occurring. Part of the need for the plan is future growth in the oilsands. Like the industry, Ottawa expects Alberta’s oilsands production to grow sharply in the long term, to roughly three million barrels per day in 2020 from just over 1.5 million barrels a day currently. Along with that production growth will come an increased need for more comprehensive environmental monitoring. Elizabeth Dowdeswell, who chaired the peer review process for Ottawa’s monitoring plan, underscored the critical importance of implementation in a statement. “If i mplementat ion is approached with a similar level of ambition and scientific discipline, according to the principles enunciated, the panel is of the view that the potential to have a world-class environmental monitoring system for this region will be realized.”
NOrtHeASterN ALbertA WeLL ACtIvIty WELL LiCENCES
JUL/10
JUL/11
80
109
▲
WELLS SPuDDED
JUL/10
JUL/11
92
123
▲
WELLS DriLLED
JUL/10
JUL/11
69
129
▲
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • September 2011
49
Northeastern Alberta
partnerships, modularization key to keeping oilsands developments on target The increasing trend towards building oilsands projects in modules along with collaboration among oil and gas industry players are among the differences that will be evident between the previous building boom and the next growth phase, an industry conference heard in July. Collaboration in the oilsands industry is improving dramatically, said Rick George, president and chief operating officer of Suncor Energy Inc., citing as an example Suncor’s partnership with Total E&P Canada. Several panellists at t he annual TD Securities Unconventional Energy Conference in Calgary said they were seeking partnerships. They included Connacher Oil and Gas Limited, Ivanhoe Energy and Athabasca Oil Sands Corp., wh ic h i s developi ng oi l sa nds pro jects in partnership with PetroChina Company Limited. “We are going to create more partnerships, probably this year,” said Sveinung
Svarte, Athabasca’s president and chief executive officer. Suncor and Total are together building the Fort Hills and Joslyn North mines and the Voyageur upgrader. “As our industry grows, those kinds of partnerships and joint ventures, I think, are going to be more common,” said George. “Clearly, part of this is economic and part of it is around risk reduction in terms of sharing the risks of these capital-intensive projects. But it also will mean more rapid change and development that is more socially and environmentally sustainable.” Just three years ago three major companies—Suncor, Petro-Canada and Total—were independently pursuing their own mines and an upgrader, but now the partners have an opportunity to better manage that growth and minimize impacts, said George. This will take a significant amount of pressure out of the system, said Bart
Demosky, Suncor’s chief financial officer. Suncor plans to build its projects in modules, to measure the pace of development and focus on costs and quality rather than schedule, said Demosky. For example, the company will have far fewer people on site at peak construction and this will lead to better productivity, he said. Instead of those three companies competing on engineering, construction materials, labour and equipment—which drove up costs during the previous oilsands construction boom—collaboration will smooth out the peaks and valleys in demand for materials and labour, the conference heard. John Langille, v ice-chair man of Canadian Natural Resources Limited a nd a not her con ference pa nel l i st, thanked Demosky. “You did take some of the pressure out by basically acquiring Petro-Canada and through your joint venture with Total, and presumably you’re not going to
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Northeastern Alberta
necessarily compete against yourselves,” he said. “We should have a bit better, level playing field. I think when you look at the whole landscape of mining today there’s really not a lot of new projects that can all of a sudden get up and running and I think you’re going to see a lot
Cenovus runs its own fabrication yard at Nisku, Alta., which it is expanding by 50 per cent and where it has “pretty muc h a ma nu fac t u r i ng approac h,” he said. The company built 144 modules there for Phase C of Christina Lake.
John Brannan, chief operating officer of Cenovus Energy Inc., told the conference that building its projects in 30,000-to-40,000-barrel-per-day increments has helped it lower costs and schedule spending. more disciplined approach from the producers overall as we go forward.” John Brannan, chief operating officer of Cenovus Energy Inc., told the conference that building its projects in 30,000-to-40,000barrel-per-day increments has helped it lower costs and schedule spending. The company’s capital efficiencies are less than $23,000 per flowing barrel, said Brannan.
“When we got to the field and hooked it up, we had one flange that needed to be rotated a little bit and one pipe that was out of alignment, on 144 connections, so by doing things right at the fabrication yard you’re really reducing your overall time and installation costs in the field.” Chris Seasons, president of Devon Canada Corporation, agreed with Brannan
and added industry has room to improve on using what it has already built. Plants average about 60 per cent of design capacity, he said. “You’ve already invested capital in those facilities. Fill them up and make a profit from them.” Devon lear ned dur ing const r uction of Jackfish 1 to internalize project management and to create repeatable designs, he added. Another difference between the oilsands growth spurt of 2005–08 and the current one is that Suncor and other companies are now more focused on modular design, allowing more flexibility in construction schedules and better ability to handle materials on site, said George. Also, the industry is not seeing the same pressure on material costs—at least not yet—because there isn’t the same amount of refineries being built in the United States. Projects around the world, including in the Gulf of Mexico, have slowed down, he said. “I’m not saying you can relax; you can never relax on this issue, but it does feel slightly different to me than the last cycle,” he said.
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OIL & GAS INQUIRER • September 2011
51
Central Alberta
Cardium’s liquids-rich gas potential starting to emerge
Photo: Aaron Parker
By Paul Wells
the Cardium is more than a tight oil play as producers in the Deep basin are beginning to exploit its liquids potential.
While the extensive Cardium play is a wellpublicized target for light oil-related exploitation, some companies are taking the road less travelled and chasing liquids-rich gas pursuits that they say offer comparable economics to crude programs in the formation. Peyto Exploration & Development Corp. has an active Cardium liquidsrich gas program underway this year and president and chief executive officer Darren Gee says that, despite getting lost amid the industry rush to exploit the light crude in the play, the liquids component of the Cardium stacks up well and the economics are healthy. “There’s so much focus on the Cardium oil it seems, and so very little focus on the Cardium liquids-rich gas. On a netback basis and on a barrel-of-oil-equivalent basis, we’re getting more productive wells in the gas fairway at lower royalty rates and just as good a netback, if not better,” Gee said.
He noted that the Cardium gas fairway is more than 4,000 square miles and the company’s internal estimates peg the original gas in place at about 65 trillion cubic feet, of which only two trillion to three trillion cubic feet has been developed to date. Peyto’s Cardium rights span 400 square miles (gross) and the company has developed about one trillion cubic feet to date through vertical wells only. While it has punched numerous vertical wells into the gas fairway over the last dozen years, Peyto only drilled its first horizontal well in late 2009. The company has since completed about 20 in total with encouraging results, especially when it comes to liquids content, which through horizontal drilling has averaged around 90 barrels per million cubic feet versus between 40 and 45 barrels through vertical wells. About 70 per cent of liquids recovered are
condensate, while propane and butane each comprise about 15 per cent. In its own economic comparison of vertical versus horizontal wells drilled into the Cardium gas fairway, Peyto said that the average vertical during the last five years cost about $1.7 million to drill. Its first-month production of 410,000 cubic feet per day declined to 260,000 cubic feet per day after 12 months. The first-year average production was 325,000 cubic feet per day. With the lower natural gas liquids content, and using a $4 natural gas price, the internal rate of return (IRR) was 23 per cent, payout was 3.6 years and NPV10 was about $800,000. The company’s targeted average horizontal well cost is $5.05 million to drill, complete and tie in. First-month production was anticipated to be 3.2 million cubic feet per day, which was expected to decline to one million cubic feet after 12 months and average 1.7 million cubic feet per day during the first year. At $4 gas, IRR was predicted to be 46 per cent, payout was 1.8 years and NPV10 was $4.1 million. However, Gee noted that the average Cardium horizontal is coming in slightly less than the company’s targets. “But we’re working to improve upon that,” he said. “Generally, the results have been pretty good—a little bit lower, maybe, than what we thought and simulated when we were running some simulation work on the horizontals. “But the liquids component does boost the equivalency of the gas we’re getting. So, to normalize this to a dry gas well, if you use 20-to-one on the condensate or even 30-to-one where it is today, then all of a sudden a three-million-cubic-feet-per-day well becomes a five-million-cubic-feet-perday well on a dollar-equivalency basis. So these are pretty potent wells, no question.” Although Peyto has initially produced higher liquids content with horizontal
CeNtrAL ALbertA WeLL ACtIvIty WELL LiCENCES
JUL/10
JUL/11
270
311
▲
WELLS SPuDDED
JUL/10
JUL/11
220
264
▲
WELLS DriLLED
JUL/10
JUL/11
211
252
▲
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • September 2011
53
Central Alberta
wells, Gee said the company has a “suspicion” that the initial flush will trend down and mimic the rates of past vertical wells. “We’re seeing much higher liquids recovery initially, but we think it is just because of the fact we’ve got all this stimulation near the bore area, and there’s a little more contact with the reservoir and we’re getting a little more flush liquids coming out. Ultimately, these horizontals will stabilize in the 40- to 45-barrels-permillion-cubic-feet [range], too,” he said. “It’s still positive as we’re getting a lot of cash back sooner and getting payout quicker, and all of those things contribute to the economics.” Peyto’s Cardium horizontal project has tested variable rock quality, reservoir pressure and completion design across
the Cardium gas trend, from the Cutbank area in the northwest to the southeast portion of the trend at Sundance and down to Ansell. Gee said that because of the inherent complexity and variability of the Cardium formation, knowing and understanding the geology is “critical.” “We’ve specifically high-graded the Cardium fairway and picked away at what we think to be the best quality reservoir in the lands that we have purchased or the farm-ins that we’ve done and the lands that we control today. Those are little drilling islands that we’ve high-graded for reservoir quality and we believe to be some of the best spots to develop. “That being said, I don’t know that we can just say we can throw down four wells
in every section that we own. We’re still high-grading even beyond that to pick the very best parts of the reservoir. And to be honest, it’s just not delineated enough to know for certain where the best parts are,” Gee explained. “We don’t just go carpet bombing the play like some people might do in some of these shale plays. We have to be a little more selective where we drill and where we target.” Gee said the company plans to spend in the neighbourhood of about $100 million on its Cardium liquids-rich gas program in 2011, which means about 20 wells will be drilled. “So we should see a meaningful amount of new production and new development going on this year,” he said.
Conventional resource plays progressing, says Connacher Connacher Oil and Gas Limited says it continues to make progress at its two light gravity crude oil resource plays in central Alberta, while it has doubled its exposure to a multi-zone liquids-rich natural gas resource play at Latornell in the Deep Basin. At Twining, a third Pekisko well has been placed on stream, at attractive, albeit temporary, facility-restricted rates, the company said. Three additional wells have been licensed on the play, with one rig dedicated to a continuous drilling program during the balance of 2011. Wit h t he licensing of t he company’s first horizontal well at Penhold, Connacher has now identified the Lower Cretaceous Viking formation as its second central-Alberta resource play.
New facilities, infrastructure, reserves and production have also been acquired at Penhold, complementing its 100 per cent working interest in approximately 40 sections (25,600 acres) of primarily Crown rights in the region. A rig has been contracted to drill at least two Viking horizontal wells by yearend 2011. The company also expanded its land base in the Latornell area by an additional 9.25 sections or 5,920 net acres. The assets were acquired from a private company that had joint ventured with Connacher on a portion of lands already held in the region. With the completion of the transaction, Connacher now owns and operates a 100 per cent working interest in 38
sections (24,320 acres) in this Deep Basin resource play, including Duvernay rights under 28 sections or 17,920 acres. The area has multi-zone, liquids-rich natural gas potential from the Dunvegan to the Duvernay, including the Wilrich, with possible Nordegg crude oil potential also recognized, the company said. Numerous undrilled vertical and horizontal drilling opportunities have been identified. At Twining, in the general Three Hills region of central Alberta, Connacher owns 38 sections along the Pekisko fairway. The company recently began production from the third of three wells drilled earlier in the year, located to provide an initial range of information on the play.
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Central Alberta
Completion of the 06-23-31-25W4 well had been delayed by extremely wet weather and similar surface conditions, which precluded access to the well location. The well has now been on stream and on pump at restricted rates since June 19. It has produced at peak rates to date of 300 barrels of oil equivalent per day and peak crude oil rates to date of 250 barrels a day during this period of temporary facilityconstrained production.
To begin Phase II of the drilling program at Twining, Connacher recently licensed three new horizontal Pekisko wells, including 01-23, 02-23 and 01-24, all in Township 31, Range 25 W4M. The company has a dedicated rig that will continue to drill these and further follow-up locations through the first quarter of 2012. The Penhold area is south of Red Deer, approximately 40 miles northwest of Twining and is located adjacent to the Queen Elizabeth II Highway.
The company has just licensed its first Viking multifrac horizontal location at 16-13-36-05W5 and expects to begin drilling upon rig arrival, with its primary objective being light gravity 40-degree API Viking crude oil. Connacher believes it has the potential for approximately 80 locations on its 100 per cent working interest lands, covering approximately 40 sections (25,600 acres) of Crown and freehold rights in the region. — DAILY OIL BULLETIN
Photo: Aaron Parker
penn West reaches out to rural stakeholders through 4-H partnership By Joseph Caouette People fear what they don’t understand— a fact that has been brought home to Alberta’s oil and gas industry through years of tumultuous stakeholder relations over issues ranging from royalty compensation to environmental concerns. But Penn West Exploration Ltd. is looking to change that through a partnership with 4-H and the Canadian Petroleum Discovery Centre (CPDC) in Devon, Alta. On a sunny day early in August, the company sponsored a 4-H tour of the centre, where club members learned about the history and science of oil and gas in Alberta. It was the third year for the tour, and it remains an eye-opening experience for the children involved, explains Nicole Collard, public affairs specialist for Penn West. “They were really keen to learn more about what’s in their backyard,” she says.
Most of the 4-H members, aged between 12 and 15, come from rural backgrounds and have encountered the oil and gas industry at some point in their lives. Naturally, they’re curious to learn about the pipes and pumpjacks they’ve seen on their own farms. “They asked so many technical questions. Where do the workers work? Where do they stay? How do they get there?” explains Collard. “It wasn’t just the job, but the lifestyle. “They were thinking big picture.” CPDC offered the children a chance to view that big picture from a variety of angles. Volunteers—some of whom are retired oilfield workers with decades of experience—provided tours of the many historical exhibits, while other educators took the children through hands-on activities that touched on everything from petrochemicals to pipelines.
According to CPDC president Daniel Claypool, it’s all part of the centre’s ongoing mission to introduce the industry to Alberta stakeholders of all ages. “A lot of people don’t know anything about the oil industry and a lot of people think we’re the black devils out there that screw up the environment,” he says. “If people understand a little more about the oil and gas industry when they’re going to drill on your place, sometimes it makes it easier.”
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55
Central Alberta
Arcan touts successful beaverhill Lake wells Arcan Resources Ltd. says it has achieved excellent 30-day initial production rates from two new Ethel wells at 01-04-6808W5 and at 05-35-67-08W5—singleleg horizontal wells in the Swan Hills Beaverhill Lake play. The wells were drilled from the padsite at 05-34-67-08W5 and were completed using 14 separate, 100-cubic-metre hydrochloric-acid fracture stimulation treatments. Over its first 30 days of production, the 01-04 well averaged approximately 732 barrels of oil equivalent per day of 40-degree API light sweet oil with approximately five per cent associated solution gas and cumulative production of 21,946 barrels of oil equivalent. The 05-35 well averaged approximately 681 barrels of oil equivalent per day of 40-degree API light sweet oil with approximately five per cent associated sweet solution gas and cumulative production of 20,437 barrels in the first 30 days.
56
September 2011 • OIL & GAS INQUIRER
Both wells are in the Ethel area and do not have the benefit of pressure support from the anticipated fourth-quarter waterflood implementation. Arcan said the 01-04 and 05-35 wells reflect a change in stimulation volume size from the previous 600-cubic-metre stimulation to a heightened 1,400-cubic-metre hydrochloric-acid stimulation. Both wells were drilled from the same pad-site as Arcan’s second horizontal well, 10-27-67-08W5, which came on stream in May. The 10-27 well produced approximately 11,650 barrels of oil equivalent over the first 30 days, 36,300 barrels over the first six months and has had cumulative production of approximately 53,000 barrels on primary recovery in the first 14 months. Arcan estimates that the 01-04 and 05-35 wells each cost $4.4 million to drill, complete and equip. Both wells are expected to reach payout at approximately 60,000 barrels
of production (assuming $100 per barrel Edmonton light sweet oil price). Presently, Arcan has two drilling rigs operating and has recently spudded its 36th horizontal well. Of t he compa ny ’s 36 hor izonta l wells, 15 were fractured in 2010, 12 were fractured in 2011, seven are awaiting fracture completions and two are presently drilling. A rcan’s 2011 dr illing focus continues to be in t he Et hel area (100 per cent working interest), where the company has applied for approval for a waterflood as well as a pipeline to connect the Ethel area wells to its existing infrastructure. T he company has also identified numerous horizontal re-entr y candidates, whereby it can apply new horizontal technology to wells that were drilled prior to Arcan’s ownership and the advent of multistage fracturing. — DAILY OIL BULLETIN
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Southern Alberta
Skilled labour, some services in short supply
Photo: Joey Podlubny
By Pat Roche
Service companies are beginning to feel the pinch as activity heats up.
Availability of labour and services continues to be an issue in both the oilsands and non-oilsands sectors of western Canada’s oil and gas industry. Speakers at TD Securities’ Unconventional Energy Conference in Calgary said securing qualified workers and some equipment continues to be a challenge across much of the industry. “Overall, getting rigs isn’t a problem. Getting labour…sometimes is a problem,” said Murray Nunns, president and chief operating officer of Penn West Petroleum Ltd. “Fundamentally, that’s where the cracks started to show around the business in the winter this year,” Nunns said. “We anticipate…that will be a continuing pressure. But as long as shale gas stays on the sidelines, we’re probably all in pretty good shape.” Speaking during a question-andanswer session, Nunns indicated Penn
West has adequate access to pressurepumping equipment. “Oil tends to take a lot less fracture stimulation equipment than shale gas. So we haven’t had the pressure the shale gas players have in the U.S.,” he said.
“Fracturing is a tougher story, especially in North Dakota.” — tony marino, president and Chief executive Officer, baytex energy Corp.
However, Nunns added it probably helps if an operator has a large program. “If you’re a junior running a smaller program, it’s probably a lot tougher to access equipment.” Replying to the same question about the availability of labour and equipment,
Gord Kerr, president and chief executive officer of Enerplus Corporation, said North Dakota has “probably one of the highest rig activity levels they’ve seen in their history. I think there’s probably about 160– 170 rigs running currently.” In North Dakota, Enerplus is chasing light oil in tight formations such as the Bakken. In such a market, long-term programs are important. “For example, we’ve got two rigs under long-term contract. We’ve got a frac services arrangement as well,” Kerr said of Enerplus’s North Dakota operations. On the U.S. shale gas front, low natural gas prices haven’t slowed activity as much as might be expected, Kerr said. “We’re involved in the Marcellus shale gas play out in Pennsylvania. And the economics there for gas are probably some of the best in terms of the returns that you will see,” he said. “Having said that, we’re all looking for a better gas price environment.” Longer-term labour will be a challenge in North America because of the high proportion of older workers, particularly in the oilpatch, Kerr continued, but added that opportunities will continue to attract talent to the industry. “If you build it, they will come.” Tony Marino, president and chief executive officer of Baytex Energy Corp., agreed with other speakers on the importance of long-term service contracts, noting Baytex has about five or six long-term rig contracts. “I don’t really see a problem with having enough drilling rigs for either U.S. or Canadian operations. “Fracturing is a tougher story, especially in North Dakota,” Marino said, adding that Baytex was in “relatively good shape” but still experiences delays and has to group wells together to attract services. Heavy rain and flooding have restricted activity in southern Saskatchewan and North Dakota.
SOutHerN ALbertA WeLL ACtIvIty WELL LiCENCES
JUL/10
JUL/11
197
167
▼
WELLS SPuDDED
JUL/10
JUL/11
256
124
▼
WELLS DriLLED
JUL/10
JUL/11
250
117
▼
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • September 2011
59
Southern Alberta
“The backlogs probably have grown during this wet period. So it may be a little bit slower than even it had been with respect to [getting equipment for] fracturing,” Marino suggested. So far, Enerplus has the services it needs for the North Dakota Bakken, but Kerr also expects equipment availability to be tighter during the latter part of the year as operators scramble to catch up. “The rainfall has far exceeded the averages. And it’s just made getting into wellsites, water hauling, water disposal just a challenge,” Kerr said. “So it’s going to get a little tighter.” As for the availability of fracturing equipment, Marino says a solution may be in the offing. One global service company is building 80,000 horsepower a month of fracturing equipment, the Baytex chief executive officer said. “That’s just one service provider. So I do think a lot of fracturing capacity will be created,” Marino told the conference. “And it would be my hope anyway—and probably my expectation—that this growth in the frac fleet will be able to meet Canada.”
Alberta government supports six experimental projects Six projects submitted by five companies will receive royalty reductions totalling up to $27.5 million under the fourth and fifth rounds of the Alberta government’s Innovative Energy Technologies Program (IETP). L a r i c i n a E n e r g y L t d ., E n c a n a Corporation, Penn West Petroleum Ltd., Cenovus Energy Inc. and Pengrowth Energy Corporation submitted the projects. They address a variety of research interests, such as advancing production technologies to produce bitumen in reservoirs that are not yet commercial, developing a better understanding of coalbed methane production, and expanding new enhanced oil and gas recovery technologies into previously inaccessible oil and gas deposits. IETP represents a $200-million commitment by the Alberta government to provide royalty relief to specific pilot and demonstration projects that use
innovative technologies to increase recoveries from existing reserves and encourage responsible development of oil, natural gas and in situ oilsands reserves. The most recent grants are in addition to the $134.3 million already allocated to 31 projects. With the successful completion of rounds four and five, the IETP is now open for another round of applications (Round 6). Applications will be accepted until September 30 with the expectation that successful applicants will be notified by the end of the year. Successful applicants in the program are provided with a royalty adjustment of up to a maximum of 30 per cent of approved project costs. Industry must provide the remaining 70 per cent or more of total project costs. T he largest f unding approva l is $10 million to Laricina as it moves from the laboratory to a field project with
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September 2011 • OIL & GAS INQUIRER
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the objective of demonstrating steam assisted gravity drainage (SAGD) bitumen recovery in the Grosmont carbonate reservoir based on the results of a previous IETP pilot. While SAGD has been demonstrated as a successful production method within the McMurray reservoirs, the application of SAGD to a carbonate environment presents different challenges and remains untested. E nc a n a w i l l r e c e i ve a tot a l of $7.95 million for two projects, one in Round 4 and one in Round 5. In the Round 4 project, which has approved funding of $2.95 million, the company is undertaking two high well-density/ reservoir-continuity projects, each with 25 Horseshoe Canyon coalbed methane wells. These projects east of Calgar y will improve the understanding of natural gas recovery from coal beds in relation to the distance between wells or well spacing, and variation in the geology of the coal beds. In Round 5, Encana has received $5 million under IETP for a project in the Bighorn area near Grande Cache
that will develop a method to understand zonal natural gas production performance in the Deep Basin, leading to increased production from marginal zones and the gas reser ves from the Bighorn area. Penn West has been approved for $5.65 million for a project southwest of Drayton Valley to explore horizontal multistage fracturing for improved waterf lood recovery from low-permeability sandstones. While industry has demonstrated success with applying horizontal multistage fracture technology in Cardium pools, the company has designed a pilot test to extend these trials into lowpermeability, low-waterflood recovery areas of the Pembina Cardium pool. Using vertical well technology, the recovery to date from the estimated original oil in place is 12 per cent. Multistage fracture technologies and flooding programs could lead to an ultimate recovery of 16 per cent of the original oil in place. In the Cold Lake region, Cenovus has demonstrated in a previous IETP project that, in a confined area, air can successfully
be injected into a reservoir and through low-temperature combustion, increase reservoir pressure, displace natural gas and generate heat into the underlying bitumen. The Round 5 project, with an approved amount of $2.43 million, is expected to expand this knowledge and technology by providing information about the distance from an injector that reservoir pressure can be maintained, and how the underlying bitumen can be produced through a horizontal well. Pengrowth will receive $1.51 million for an associative-polymer pilot flood project at Bodo East, south of Lloydminster. There is growing interest in chemical floods as a way to enhance oil recovery. In this project, Pengrowth will be using a brine tolerant “associative polymer.” Current primary and waterflood recovery has achieved only four per cent recovery of the original oil in place and the expectation is that incremental oil recovery using polymers could be improved by two to three per cent over waterflooding. Polymer use is also expected to reduce water requirements. — DAILY OIL BULLETIN
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OIL & GAS INQUIRER • September 2011
61
Southern Alberta
Devon testing over 10 new plays in Canada Devon Corporation plans to spend an additional US$200 million on drilling in Canada this year as part of its companywide capital budget increase of $1 billion, the company reported in July. Devon will test more than 10 new plays in Canada this year, John Richels, president and chief executive officer, told a webcast. The company did not disclose all 10 play types but highlighted three of them: the Viking at Kindersley, Sask., for light oil (19 wells and 1,000–2,000 potential locations), the Cardium for light oil (18 wells, prospective in the Deep Basin and at Ferrier) and Lower Cretaceous zones for liquids-rich gas (18 wells). The latter includes the Cadomin play and has 1,000 to 2,000 potential locations. The company had originally budgeted to drill 13 wells in the Viking at Kindersley. In the Cardium, it will drill about 11 wells in the Ferrier area and about seven in the Deep Basin, where it sees the potential of 40 million to 170 million barrels of production.
Recovery per well in the Viking is estimated at 50,000 barrels. “It could be bigger than that if it starts working well,” said Dave Hager, executive vice-president of exploration and development. There are not a lot of results to report to date, but Devon will provide a resource update later this year, he said. “We’re really just starting to scratch the surface significantly…evaluating the oil and liquids potential in the Western Canadian Sedimentary Basin,” said Hager. Devon also announced a new in situ oilsands asset entitled Jackfish East, about four kilometres east of Jackfish 1, which is expected to produce about 150 million barrels before royalties (130 million barrels net). The company believes reservoir quality is similar to previous phases, with minimal bottom water. The company estimates potential production of about 20,000 barrels per day (17,000 barrels per day net)—considerably smaller than previous phases. Devon has been exploring the asset for the past couple of years and is about 90 per cent complete in its delineation.
At Jackfish 1, an additional well pad was brought on in February for a current total of 35 wells on production, the webcast heard. Now producing about 1,000 barrels per day, which is more than expected, Jackfish 2 started steaming this spring and first sales were made in June. Richels said Jackfish 2 was constructed 19 per cent under budget on a Canadian-dollar basis and gave credit to the construction management. The foreign exchange, however, “ate away” at those savings, he said. Peak production is still expected in late 2012. A regulatory application was filed for Jackfish 3 in the third quarter of 2010 and approval is hoped for later this year. Major equipment has been ordered and costs are “coming in quite nicely,” the webcast heard. Adjacent to Jackfish, winter appraisal drilling was done at the Pike joint venture with BP—50/50 with Devon as operator— and the company continues to see five steam assisted gravity drainage phases. — DAILY OIL BULLETIN
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62
September 2011 • OIL & GAS INQUIRER
Southern Alberta
erCb approves Cenovus wells at CFb Suffield Cenovus Energy Inc. has received Energy Resources Conservation Board (ERCB) approval for licences to drill 47 shallow sweet gas infill wells about eight kilometres northeast of Ralston, Alta., on Canadian Forces Base (CFB) Suffield. However, the board acknowledged in its decision that it will still be up to the federal government, which opposed the non-routine licence application, to grant surface access to Cenovus. ERCB licences are a pre-condition to obtaining access to CFB Suffield. In 2010, t he Suf f ield base commander allowed the company to drill three wells the board had approved in 2009 following an application submitted by predecessor company, Encana Corporation. The ERCB approval for the 47 well licences following a written hearing came despite an objection from the minister of national defence, the Canadian Forces and the department of national defence. They expressed concerns about the density of the wells exceeding 16 surface
disturbances per section (DPS) at the proposed locations, the impact of the wells on the military and on defence research activities at Suffield, and Cenovus’s reliance on outdated environmental sitespecific information when assessing the cumulative effects of the proposed wells. Canada expressed concern about the effects of the growing oil and gas footprint at CFB Suffield. It said that cumulative environmental effects would result in decreases in range health and native species abundance and diversity because of habitat loss, increased fragmentation, and impacts on wetlands and species at risk. Canada was of the view that CFB Suffield is of national significance as a refuge for prairie wildlife, providing habitat for federally and provincially listed species at risk. The limit of 16 DPS was, in part, intended to reduce the risk of irreversible environmental effects. T he ERCB, however, said it was unable to test the information Canada had provided as it chose not to actively participate in the hearing.
Cenovus submitted that there is no evidence before the board that disturbance associated with the proposed wells would exceed the carrying capacity of CFB Suffield or result in any significant cumulative effects. The company noted that there is no requirement under provincial or federal regulation for a cumulative-effects study of the subject applications. Cenovus further submitted that the cumulative-effects assessment that it is relying on for the subject applications was directly applicable and relevant because it included an assessment of virtually the entire CFB Suffield. In its decision, the board found that the proposed wells are in the public interest having regard to the social, economic and environmental effects of the project, including its potential impact on the military activity and the environment at CFB Suffield. The additional wells are required to enable Cenovus to maximize recovery of gas reserves, according to the ERCB. — DAILY OIL BULLETIN
DO N E LO WNT W CA OW TIO N N
Speakers include:
Juan Morera,, Lead, Terminals Engineering & Tank Specialist (Consultant), TransCanada Pipelines Paul Paynter, Calgary Economic Development
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John Cornell, API tank trainer
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Gregg Manzione, Nationwide Consulting Company
Tank Storage Canada brings together terminal operators, traders, oil majors, regulators and equipment suppliers to discuss market trends, expansion projects and future outlooks for the storage sector. For more information and registration www.tankstorageevents.com/tscanada
Murray Heap, Compliance Promotion Officer, Environment Canada Adrian Pellen, Vice president, Aon Reed Stenhouse Alan Crossley, Partner, Osprey Capital Partners
Please note that speakers may be subject to confirmation and alteration. All information correct at time of going to press.
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Novus drilling up Dodsland
Despite wet weather, Novus continues drilling at its viking project at Dodsland.
Nov us Energ y Inc. announced it is half way through its 2011 Viking oil drilling program, and has now successfully drilled 26 Viking oil wells in the Dodsland area of Saskatchewan, with 20 of these wells completed. Seventeen of the wells that have been completed have been placed on production, with the remainder to follow. Novus said it is pleased with the initial rates the first wells have demonstrated to date. Drilling and completion costs in the Dodsland area continue to meet the company’s budgeted figures of $850,000 per well. With two drilling rigs running, Novus plans to drill a total of 52 net Viking oil wells in the Dodsland area by the end of the third quarter, and complete a total of 46 wells, assuming normal summer weather, by the end of September. The remaining wells will be completed early in the fourth quarter of the year.
Total estimated field-level corporate production as of July 18 was approximately 2,120 barrels of oil equivalent per day. Novus expects production will continue to increase steadily through the balance of the third quarter as additional wells are drilled and placed on production. The company said it is comfortable that, given the progression of its drilling plans and results to date, it will meet its previously announced exit rate guidance of 3,000 barrels per day. The company’s anticipated exit rate represents a near doubling of production from the 1,544 barrels per day the company reported in the first quarter of 2011. Novus said it remains excited about its Flaxcombe sub-area in the Dodsland region. The company has determined that these previously undrilled lands are characterized by two distinct cycles in the Viking formation.
In 2011, the company has now drilled two horizontal wells targeting the lower cycle and one horizontal well targeting the upper formation. Virgin pressures realized on these wells were in excess of 7,500 kilopascals, which are amongst the highest pressures the company has recorded in any of its Viking wells drilled to date. These three wells have now all been producing for in excess of 30 days, and have demonstrated estimated field-level average production rates per well of 74 barrels per day for the last 30-day period. Novus has mapped over 10 sections of its lands where both cycles are present and expects this area to significantly add to its existing drilling inventory of 592 net Viking oil locations, and reserves and production growth as development of the two distinct Viking cycles progresses. Production from the recently drilled wells has exceeded expectations, Novus said, and is supportive of the longer-term potential the company believes the area exhibits. With recent land acquisitions in the Dodsland area, Novus now controls 115.25 net sections of Viking rights and has identified 592 net Viking oil drilling locations. In addition, the company recently acquired a 100 per cent working interest in approximately 55 net sections of land with rights in the oil-bearing Birdbear formation in the Dodsland area, which complements the 24 net sections of land with rights in the formation already owned by Novus. Successful Birdbear oil wells in the area are amongst the most economic in Canada due to high deliverability rates, large oil reserves and low drilling and completion costs, Novus said. The company will be dedicating some of this year’s capital expenditure program towards the shooting of 3-D seismic and the potential drilling of a number of Birdbear locations. — DAILY OIL BULLETIN
SASKAtCHeWAN WeLL ACtIvIty WELL LiCENCES
JUL/10
JUL/11
292
325
▲
WELLS SPuDDED
JUL/10
JUL/11
294
394
▲
WELLS DriLLED
JUL/10
JUL/11
291
370
▲
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • September 2011
65
Saskatchewan
petro One discovers new oil pool
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Petro One Energy Corp. reports that the first hole of its first summer drill program has led to the discovery of a previously unknown light oil pool on the company’s 100 per centowned J5 property in Saskatchewan. The conventional vertical well demonstrated a flow rate of 60.57 barrels of light oil to surface in 7.75 hours from the Viking sand at a depth of 736.5 metres, without stimulation, swabbing or pumping.
indicated by the high-resolution seismic program shot by Petro One last spring. The productivity of the Petro One Milton 10A-15-30-27W3 well is explained by a highly porous and permeable basal channel facies that cuts across the main thick Viking sand fairway. As a result of discovery, the company said an expanded exploration and development drilling program of up to 17 additional wells has been
“The discovery of a new oil pool with our first drill hole has exceeded the company’s expectations." — peter bryant, president, petro One energy Corp.
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September 2011 • OIL & GAS INQUIRER
Flowing pressure in the tubing measured at surface was stable at 1,000 kilopascals throughout the flow period, the company said. The well has been shut in pending installation of a separator and adequate tanks, at which time it will be placed in full production. With oil flowing to the surface on its own, and excellent reservoir pressures, a pump is not necessary, Petro One said. Once the well is on stream, the results of a 48-hour production test and fluid analyses will be announced. The company said a final core analysis completed by Core Labs confirmed excellent porosity up to 23.5 per cent and unusually high permeability up to 3,980 millidarcys over the perforated interval. The new oil pool is contained within a Viking sand corridor on the J5 property
planned on J5 to exploit the full potential of the newly identified reservoir. “The discovery of a new oil pool with our first drill hole has exceeded the company’s expectations and establishes the ability of our technical team,” said Petro One president Peter Bryant. “This will serve as a solid foundation to build on.” P roduc t ion fac i l it ie s a re bei ng installed to bring the well on stream and a reserve upgrade is planned to be released in the immediate future, the company said. Detailed core and fluid analyses and petrographic and reservoir engineering studies are in progress to optimize development and production of the newly discovered oilfield. Preparations are also underway for summer drill programs on other Petro One properties with strong light oil potential. — DAILY OIL BULLETIN
Southern pacific Senlac production sets record The performance of Southern Pacific Resource Corp.’s STP-Senlac thermal project in Saskatchewan and strong oil prices combined to drive the company to record fiscal fourth-quarter production and gross revenue. Total production averaged 4,915 barrels of oil equivalent per day for the fourth quarter ended June 30, 2011, compared to 3,663 barrels per day in the third quarter. Two steam assisted gravity drainage (SAGD) well pairs brought on stream at
STP-Senlac in April (Phase H) have performed as expected. Preparations are being made to drill the next three SAGD well pairs (Phase J) this fall. These wells will be set up and placed on standby, ready to be activated as required once capacity in the plant becomes available. Southern Pacific’s development plan is to maintain STP-Senlac production at between 4,000 and 5,000 barrels per day for the next 10–14 years. — DAILY OIL BULLETIN
Saskatchewan
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“The acquisition of this two-thirds interest in Three Star expands Provident’s logistics footprint in the Bakken area, one of the most exciting resource plays in North America, and creates a strong partnership with a highly regarded and growing player in the industry,” Doug Haughey, president and chief executive officer of Provident, said in a news release. Privately held Three Star is based in Alida, Sask. It operates in Saskatchewan, Manitoba and North Dakota, providing fee-for-service hauling of crude oil and related oilfield liquids for major Bakkenarea producers. Three Star has a new and wellmaintained fleet of approximately 170 tractors and 160 trailers, Provident said. In addition to building a strong presence in crude oil hauling, the transaction will also provide Provident the opportunity to further expand its natural gas liquids and diluent logistics service businesses. Provident will retain the option to purchase the remaining minority interest in Three Star after three years from the closing date, anticipated on or before Oct. 1, 2011. The acquisition will be immediately accretive to both cash flow and earnings on a per-share basis, Provident said.
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st
Provident Energy Ltd. has reached an agreement to purchase a two-thirds interest in the equity of Three Star Trucking Ltd., a Saskatchewan-based oilfield hauling company serving Bakken-area crude oil producers. The transaction is valued at approximately $20 million, comprised of about $8 million in cash, 945,000 Provident shares, and approximately $4 million of assumed bank debt and working capital.
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Northern Frontier
Photo: Gerald Ford
New rail link could carry oilsands to Alaska
First Nations support shipping oilsands to Alaska by rail.
G Seven Generations Ltd. (G7G) is proposing a new railway to carry oil from the Alberta oilsands to the existing marine oil terminal at Valdez, Alaska. The company revealed its proposal at the International Indigenous Summit on Energy and Mining in Niagara Falls, Ont. “Studies have already demonstrated that a rail link to Alaska is a viable alternative to
the oil pipelines currently being planned through British Columbia,” said G7G director Matt Vickers. “This approach is timely because it promises significant economic benefits while avoiding many of the environmental risks associated with current pipeline proposals. “Diversifying markets for Canadian oil is an important challenge, but we need to
achieve this goal in the most environmentally and socially responsible way possible,” Vickers added. A key advantage of G7G’s rail link proposal is its use of the existing marine oil terminal in Valdez, which is facing a declining supply of oil from Alaska’s North Slope. One option of the proposed 2,000-plus kilometre railway would run northwest from Fort McMurray, Alta., to join the Alyeska Pipeline (part of the Trans-Alaska Pipeline System, which carries oil to the Valdez oil terminal) at Delta Junction, Alaska. The project’s first phase is estimated to cost $12 billion or more. British Columbians’ opposition to oil tanker traffic on British Columbia’s north coast is very strong and should not fall on deaf ears, said G7G. “Valdez has seen oil tanker traffic since the 1970s and this proposal would simply mean replacing the declining supply of Alaska crude with a new supply of Alberta crude. We believe this approach has a greater chance of obtaining social licence from local communities than other competing scenarios.” G7G said the Alberta-Alaska rail link has already received leadership support from First Nations in the Yukon and British Columbia, and leadership tribal support from the Alaska tribes along the proposed railway route.
CNOOC funding Northern Cross exploration at eagle plain Northern Cross (Yukon) Limited announced that an affiliate of CNOOC International Limited, a subsidiary of CNOOC Limited, one of the largest independent oil and gas exploration and production companies in the world, has made an investment in Northern Cross. The investment will allow privately owned Northern Cross to fulfill work commitments under its current exploration permits located at Eagle Plain. These work commitments are intended to further assess the oil and gas resource
potential in the Eagle Plain area of northern Yukon. In addition to providing funding for early-stage exploration and development, Northern Cross said CNOOC Limited offers significant operational expertise that will be helpful to the successful execution of its business plan. Northern Cross said it is hopeful that the initial investment in exploration activities at Eagle Plain will lead to the development of energy resources to
meet the growing demand in Yukon and export markets. The investment in Yukon’s oil and gas resources is expected to create employment, diversify the sources of primary energy for Yukon to include natural gas, contribute to energy self-sufficiency in Yukon and support infrastructure development—all of which are key aspects of the Energy Strategy For Yukon that was announced in early 2009 by the Government of Yukon. — DAILY OIL BULLETIN
OIL & GAS INQUIRER • September 2011
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Central Canada
Photo: Joey Podlubny
Ottawa will defend oilsands, says Oliver
Canadian Natural resources Minister Joe Oliver says the federal government will defend the oilsands.
Ca nada’s newly appoi nted nat u ra l resources minister has promised that his government will work with industry to ensure sustainable oilsands development while defending the province and its interests against those who attack it. “We recognize that there are environmental challenges associated with developing the oilsands,” Joe Oliver said in a luncheon speech to the Calgary Chamber of Commerce. “Our government will work with Alberta’s oil industry to advance and enhance practices of good stewardship and sustainability,” he said. “But, we will equally defend the province and its interests against those who attack Alberta’s industry and who seek to freeze its growth and cut its access to foreign markets.” While the future of the Canadian economy and the country’s national security are inextricably linked to energy in all provinces, the oilsands are one of the prime sources of energy strength, said Oliver, a Toronto MP and former investment dealer. The oilsands are a key driver in virtually every sector of the Canadian economy, including equipment manufacturing,
construction, engineering and financial services, according to the minister. “So we need to correct a popular misconception that the oilsands are just about Alberta,” he said. “They are about Canada’s economic future.” In his speech, Oliver said he believes a shared vision on energy is crucial to Canada’s long-term future as a global energy superpower. At the energy ministers’ conference in Kananaskis, he worked on that shared vision with provincial and territorial ministers. “Collaboration respects the uniqueness of each jurisdiction, but positions us much better to harness our energy potential, grow our status as a clean energy supplier, and create jobs and prosperity for Canadians,” he said. “Such a vision does not imply federal command and control.” The Conservative government has always been committed to respecting provincial jurisdiction and any and all initiatives will be pursued jointly with its provincial and territorial partners, said Oliver. He also warned that this won’t be a quick process. “It will take time to develop and time to ensure that the interests of all the regions of our vast country are represented.”
The federal government will also respect the principles that the energy sector must be market-oriented and governed by “effective, efficient and transparent” regulatory systems, and plans improvements in the regulatory and environmental assessment process, said the minister. The ultimate goal is simple: one project, one review. “Streamlining regulatory reviews will not weaken our environmental protection regime but strengthen it and provide Canadian industry with more predictable timelines,” said Oliver. Canada is also well-positioned to be a global leader in clean electricity, Chamber members heard. But it also must continue to develop markets both domestically and abroad for the future use of wind, solar, geothermal, marine and biomass energy sources, he said. “Tapping international markets to become a global energy superpower, whether that is natural gas, renewable power or oil, is key to Canada’s economic future,” said Oliver. “And we are wellpositioned to grow our energy markets as a politically stable, competitive and reliable energy producer.” However, to achieve its full potential, Canada needs to make major investments in oil and natural gas infrastructure, he continued. “We have to get our resources to market, to increase production and to help meet the world’s need for reliable sources of energy.” According to Oliver, the United States will have to import more Canadian oil and energy if it is to achieve increased energy security. TransCanada Corporation’s proposed 500,000-barrel-per-day Keystone X L pipeline from Alberta to Texas will help provide energy security for Canada and the United States in a safe and environmentally responsible way, permanently enhancing North American energy security and market stability, he suggested. The project, which requires a presidential permit from the U.S. State Department, has been facing mounting opposition from environmental groups. The department has promised it will make a decision by the end of this year. OIL & GAS INQUIRER • September 2011
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East Coast
Offshore boards update guidelines
Photo: Joey Podlubny
By James Mahony
New offshore guidelines focus on safety.
T he Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) has co-published with the Canada Nova Scotia Offshore Petroleum Board drilling and production guidelines governing the offshore. These guidelines address each of the 91 sections of the Newfoundland Offshore Petroleum Drilling and Production Regulations, and speak to a full range of topics associated with drilling and production projects. The guidelines were initially issued on Dec. 31, 2009, in draft form, for use on a one-year trial basis. Based on feedback received from various stakeholders and experience with their use, a number of improvements were made and the guidelines were re-published on May 31, 2011. The updates took into consideration the special oversight measures implemented for deep water operations, as well as a review of initiatives taken in other jurisdictions. Max Ruelokke, chair and chief executive officer of the C-NLOPB, said the changes to the guidelines are part of an ongoing process of improvement to the board’s regulatory oversight of offshore oil and gas activities.
“Consistent with the key principles of performance-based regulations, the need to update guidance on an ongoing basis is necessary to keep pace with industry best practices and evolving technology,” he said. In the view of the dynamic nature of the matters addressed in the drilling and production guidelines, a process to initiate another round of updates will commence later this summer. In the next round, the board said it will take into account its review of the Offshore Helicopter Safety Inquiry Implementation Team Advisory documents, the provincial government’s review of Offshore Oil-spill Prevention and Remediation Requirements and Practices in Newfoundland, as well as the board’s review of the National Commission on the BP Deepwater Horizon incident offshore the Gulf of Mexico. Input from stakeholders, including industry, the workforce and outside experts, will be sought as part of this process. The most recent updates and improvements to the Drilling and Production Guidelines include clarification of management system expectations in section 5.3, and new guidance additions to
sections 5.7 and 5.8 on “document control” and “change control process” to clarify expectations in how management systems documentation should be controlled. Redundant guidance regarding flow systems and metering was removed and, instead, the “Measurement Guidelines” were referenced. Redundant guidance regarding well data acquisition requirements was also removed and, instead, the “Data Acquisition Guidelines” were referenced. Comprehensive guidance was added to section 6 with respect to contingency planning to address relief well drilling, flight following and vessel tracking, resource sharing and mutual aid agreements, oil spill preparedness, precautionary downmanning, search and rescue, a dedicated Search and Rescue helicopter, exercises and drills, communication equipment and facilities, medical support and subsea oil spill containment equipment. Guidance was also added to section 6 with respect to the public release of contingency plans, specifically the need to arrange any personal information in the plan in a manner that facilitates its redaction. This will aid in the public release of these plans as is provided in the legislation. The revision also added guidance to section 10.5, clarifying that an “Approval to Alter the Condition of a Well” is required for chemical treatment programs that could affect the completion of a well. And it added guidance to section 16.2 with respect to how a resource management plan is to be updated as part of the annual production report. Guidance was added to section 26.0 respecting considerations for “sour” environments. The board also added guidance with regards to the arming of backup systems and the need for two blind shear rams in the blowout preventor (BOP) stack, and it issued further guidance to section 37.8 with respect to requirements for backup BOP systems with particular expectations for remotely operated vehicle intervention capability. As a result of publishing these new guidelines in final form, the C-NLOPB’s Guidelines Respecting Drilling Programs have been rescinded. OIL & GAS INQUIRER • September 2011
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xtreme contracts four xDr 500 drilling rigs Delivery of the first new rig is planned for the first quarter of 2012, with one rig planned for delivery in each of the following three quarters. In total, Xtreme expects the four new rigs will cost approximately $65 million to $70 million to construct over the next 15
Photo: Joey Podlubny
In total, Xtreme expects the four new rigs will cost approximately $65 million to $70 million to construct over the next 15 months.
Coiled tubing rigs are gaining popularity internationally.
Xtreme Coil Drilling Corp. announced the award of long-term contracts to a large exploration and production company to build and operate four new XDR 500 drilling rigs with the start of operations staged throughout 2012. In total, the current value of the four new drilling contracts is more than $100 million and each rig will operate under a three-year contract. The company said its growth strategy involves expanding the fleet of advanced
technology rigs, especially larger rigs featuring deeper drilling capabilit y. Xtreme said the announcement demonstrates significant market confidence resulting from its strong performance in the Greater Denver-Julesberg Basin since it initiated operations in that region in 2007. Initially, the company anticipates that the four new drilling rigs will operate in the Niobrara resource play in the Rocky Mountain region of the United States.
months. Construction of the first of these four rigs is already underway. Including the four new XDR 500 drilling rigs, Xtreme Coil has committed to adding eight XDR 500 drilling rigs to the fleet since the introduction of this model in October 2010. Currently, one rig is operating in the Bakken in North Dakota and one is in the Eagle Ford in Texas. Two previously announced XDR 500 rigs are nearing completion. â&#x20AC;&#x201D; DAILY OIL BULLETIN
trican enters Australia market Trican Well Service Ltd. has purchased Viking Energy Pty Ltd. and its subsidiaries, a privately owned enterprise based in Brisbane, Queensland, that provides cementing and environmental services in eastern Australia. Under the terms of the purchase, Trican acquired 100 per cent of the shares and units of Viking Energy through its wholly owned Australian subsidiary.
Viking Energy operates four cement pumpers, along with associated ancillary equipment and fluid logistics equipment. The acquisition of Viking Energy provides Trican with a strategic entry point into the growing Australian market, it said. The company believes the acquisition provides a solid partnership with the existing Viking management team and
allows Trican to quickly introduce its hightechnology cementing, coiled tubing and well stimulation products to the Australian and surrounding markets. Trican and Viking ultimately intend to provide specialized pressure pumping solutions. The company said significant growth is expected in the Australian coal seam and shale gas plays. OIL & GAS INQUIRER â&#x20AC;˘ September 2011
75
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OF THE TRADE A LOOK AT NEW TECHNOLOGIES
STEP Energy Services’ new deep horizontal coiled tubing units
blueprint of one of StEP’s new deep horizontal coiled tubing units
steP energy services is a new coiled tubing service company offering completion and well intervention services to the deep horizontal well market.
Why did you start the company now and what geographic
to six units into four, the overall lease footprint is reduced. STEP’s specialized
region are you targeting?
mast unit eliminates the use of a crane to support the injector, minimizing the
Coiled tubing is an effective method used to increase reservoir per-
risk of critical lift operations, thereby improving employee safety on a pro-
formance in well completions and well intervention projects, however,
ject work site. Being able to source a complete suite of coiled tubing services
existing coiled tubing units are not designed to safely service wellbores in
will minimize clients’ logistical concerns and increases job efficiencies. These
the deep horizontal market.
features allow STEP Energy Services to address the individual needs of its customers and enhance the quality of the company’s client-focused services.
Coiled tubing experts Bailey Epp and Steve Glanville recognized this void and joined with Regan Davis, an experienced oilfield industry professional, and
What makes your equipment unique and how will it
ARC Financial Corp., the company’s capital partner, to form a new business
compete in the marketplace?
to fulfill this niche.
The horizontal well activity in the WCSB has steadily increased over the last five years and the industry is reaching well depths beyond the current
Recent industry focus to concentrate service and capital to fracturing
equipment capabilities. This has created an opportunity for STEP Energy
resources has left the coiled tubing industry ill-equipped to provide the sup-
Services to enter into the space with its specialized fleet of coiled tubing
port required to maintain balance amongst the related services.
(CT) equipment.
STEP Energy Services will focus its efforts on the Western Canada
Both STEP’s CT equipment and pumping equipment represent not only some
Sedimentary Basin (WCSB), specifically within the active resource plays such
of the highest capacity oilfield service equipment in the industry, but also the
as the Horn River, Montney, Cardium, Alberta Bakken and Saskatchewan
most fit-for-purpose equipment in the industry. Step Energy Services’ next
Bakken. STEP will target those operations which are currently utilizing hori-
generation [of] mast coiled tubing equipment will be the largest of its kind in
zontal drilling techniques and areas which may benefit from improved pipe
the WCSB. The CT equipment will have the depth capabilities of over 6,000
length capacity, pipe size and under-supported pumping operations.
metres and will have the largest mast height in the industry. The twin pumping support equipment is uniquely designed to supply additional horsepower
how many units and associated equipment will you initially be
required, as well as they provide complete redundancy during continuous
deploying in the field and what services will you be providing?
24-hour operation, which minimizes undesirable downtime.
STEP Energy Services’ aggressive capital build program will bring a large fleet of mast coiled tubing units with supporting twin fluid pumping units and
STEP Energy Services will combine the most efficient, purpose-built CT and
nitrogen pumping units to the market beginning in the fourth quarter of 2011.
pumping equipment in the industry, along with a service-oriented team of
STEP’s skilled and competent personnel with this equipment will provide
experienced personnel to deliver exceptional customer experiences.
clients with customized solutions and exceptional client experiences. The company’s modern equipment and professional expertise will deliver improved operational efficiencies and productivity in extended reach wellbore designs. By utilizing a mast unit design, which combines the capabilities of up
Answered by bailey epp, steP energy services’ president, and steve Glanville, steP’s chief operating officer.
OIL & GAS INQUIRER • September 2011
77
Advertisers' Index Allan R. Nelson Engineering (1997) Inc . . . . . . . . . 64 Annugas Compression Consulting Ltd . . . . . . . . 42 Applus RTD Canada . . . . . . . . . . . . . . . . . . . . . . . .31 ASAP Heating & Well Servicing Corp . . . . . . . . . 40 Bear Slashing Inc . . . . . . . . . . . . . inside back cover Beaver Plastics Ltd . . . . . . . . . . . . . . . . . . . . . . . 70 Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 74 Black Sivalls & Bryson (Canada) Ltd . . . . . . . . . . 54 Brews Supply Ltd. . . . . . . . . . . . . . . . . . . . . . . . . 34 Brother’s Specialized Coating Systems Ltd . . . . 55 CADE Canadian Association of Drilling Engineers . . . . . . . . . . . . . . . . . . . . . 68 Cameron Construction Services . . . . . . . . . . . . . 58 Canadian Assocation of Petroleum Producers (CAPP) . . . . . . . . . . . . . . . . . . . . . . . 57 Canadian Standards Association . . . . . . . . . . . . 25 Canwell Enviro-Industries Ltd . . . . . . . . . . . . . . . .12 CARES Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 CH2M Hill Canada Ltd . . . . . . . . . . . . . . . . . . . . . .41 Chevron Delo . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . . 76 Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Dean’s Pump Service Ltd . . . . . . . . . . . . . . . . . . . 66 DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10
78
September 2011 • OIL & GAS INQUIRER
Diversified Glycol Services Inc . . . . . . . . . . Draeger . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dragon Products . . . . . . . . . . . . . . . . . . . . . Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . Edmonton Exchanger & Manufacturing Ltd EITI Electrical Industry Training Institute . . Enviro Vault Canada Ltd . . . . . . . . . . . . . . . Falvo Electrical Supply Ltd . . . . . . . . . . . . . FDI Acoustics Inc . . . . . . . . . . . . . . . . . . . . . Flexpipe Systems . . . . . . . . . . . . . . . . . . . . Horseshoe Media Events. . . . . . . . . . . . . . . Infosat Communications LP . . . . . . . . . . . . Joule Technical Sales Inc . . . . . . . . . . . . . . . kenwood Electronics Canada Inc . . . . . . . . kubota Canada Ltd . . . . . . . . . . . . . . . . . . . LJ Welding & Machine . . . . . . . . . . . . . . . . . London Business Conferences . . . . . . . . . . LoTech Manufacturing Inc . . . . . . . . . . . . . . MCI Solutions . . . . . . . . . . . . . . . . . . . . . . . MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . NAIT Corporate and International Training. NDT Systems & Services (Canada) Inc . . . . Nexus Exhibits Ltd. . . . . . . . . . . . . . . . . . . . Northstar. . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . 74 ..... 5 . . . . .16 . . . . 76 . . . . 47 . . . . 64 . . . . 48 . . . . 72 . . . . 66 37 & 39 . . . . 63 . . . . 45 . . . . 74 . . . . 6-7 . . . . .21 . . . . 46 . . . . 56 . . . . 72 . . . . 70 . . . . 72 . . . . .51 . . . . 22 . . . . 44 .....4
Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . 58 Opsco Energy Industries Ltd . . . . . . . . . . . . . . . . 76 Pembina Controls Inc. . . . . . . . . . . . . . . . . . . . . . 58 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 64 Phoenix Heli-Flight . . . . . . . . . . . . . . . . . . . . . . . 50 Platinum Energy Services Corp . . . inside front cover Platinum Grover Int. Inc . . . . . . . outside back cover Propak Systems Ltd . . . . . . . . . . . . . . . . . . . . . . . 3 PTI Group Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 Radafab Oilfield & Industrial Supply Inc . . . . . . . 32 SMS Equipment Inc . . . . . . . . . . . . . . . . . . . . . . . .61 Sprung Instant Structures. . . . . . . . . . . . . . . . . . . 9 Strad Energy Services. . . . . . . . . . . . . . . . . . . . . 27 TELUS World of Science . . . . . . . . . . . . . . . . . . . 33 Tigercat Industries Inc. . . . . . . . . . . . . . . . . . . . . 60 Trans Peace Construction (1987) Ltd. . . . . . . . . . 68 Tundra Process Solutions Ltd . . . . . . . . . . . . . . . .18 V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . .13 Waydex Services LP . . . . . . . . . . . . . . . . . . . . . . 38 Working In Limited. . . . . . . . . . . . . . . . . . . . . . . . 68 Xtreme Hot Oil & Pressure Services Inc . . . . . . . 36