JANUARY 2010 � $6.00
Keeping readers regionally informed
OutlOOk Canadian Publication Mail Product Agreement #40069240
2010
HOping FOr better tiMes
Gimme shelter
Fabric buildings evolve into a global architecture
Piping carbon dioxide
Alberta pledges $495M to move CO2 for enhanced oil recovery
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Table of Contents
Keeping readers regionally informed
F E A T U R E S
12
Outlook 2010
18
Gimme shelter
35
Piping Carbon Dioxide
by Graham Chandler
2010 looks like a better year for the oilpatch than 2009
by Mike Byfield
Fabric-over-frame matures as a building technology that’s well-suited to the resource sector
by Paul Wells
Alberta government pledges $495M for CO2 pipeline project
With all the uncertainty about the economy, look for our Recession to Recovery logo for coverage on how companies are handling the downturn, preparing for the rebound, and, in some cases, even thriving. 4
January 2010 • OIL & GAS INQUIRER
Table of Contents
R E G I O N A L
27
N E W S
British Columbia
39
• Nexen sees oilsands as natural market for Horn River gas
to impede profitability
• TAQA North plans to drill three Horn
• CIBC analyst expects better industry
River wells this winter
31
Northwestern Alberta/Foothills
conditions in 2010
43
• Orleans completes two Montney gas
Northeastern Alberta
acquisition binge with TriAxon deal
45
• Suncor restarts third and fourth stages
Northern Frontier • Greenland’s retreating ice fuels
of its Firebag SAGD project
35
Saskatchewan • Crescent Point continues its
wells on western Kaybob lands
33
Southern Alberta • Ensign says over-capacity continues
dreams of hidden resource wealth
Central Alberta
47
Central Canada
• Imperial signs oilsands service
• CSA unveils North America’s first
agreement with Keyera • A JM urges Alberta gas royalty reforms
pipeline security standard
49
International • Enerplus plans to invest $100M in Marcellus shale play • Vast gets ready to drill in Kurdistan
I N
E VE R Y
I S S U E
10 Statistics at a Glance
53 Tools of the Trade
Completions data, spot gas prices, gas
North Rig hydraulic catwalks replace
storage, drilling activity, and more
the traditional ramps used to drag tools from the ground up to the rig floor.
51 On The Job Jeff Schryver is an oil and gas fisherman, one of the elite field workers who are
54
Political Cartoon
called in when tools or pipe get stuck downhole.
Cover Design: Ken Bessie
OIL & GAS INQUIRER • January 2010
5
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Editor’s Note Vol. 22 No. 1 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com
Mike Byfield | mbyfield@junewarren-nickles.com
Fabric architecture
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Who would have expected the Canadian Prairies—sparsely populated, resource-dependent, far from tidewater—to play a lead role in creating an entire new building technology with global implications? Yet one Calgary-based manufacturer—Sprung Instant Structures—has done just that. In this issue, Oil & Gas Inquirer “covers” (pun intended) fabric architecture. Within one lifetime, Sprung has developed permanent structures made with fabric skins and aluminum frames. Highly competent western rivals have quickly emerged, pushing forward the technology. Usually on short notice, this new construction sector can deliver low-rise buildings for almost any purpose: industrial, agricultural, residential, commercial, recreational, or religious. Building erection is strikingly quick, durability measures in decades, the fabric can be readily replaced when worn, labour availability has been excellent, and prices are attractive. Exceptional natural lighting characterizes fabric architecture. Flexibility is another strength. If necessary, big or small buildings can be dismantled and transported without sacrificing structural integrity. (Try moving a “mobile” home a few times and watch what happens.) As building technologies evolve in electronics, heating, plumbing, and so on, fabric structures appear convenient for incorporating new interior systems. Why not build an entire fabric community? Capital cost would only decline as economies of scale kicked in, and technically the challenge seems feasible. For instance, a self-standing overhead crane can be installed in a fabric industrial shop. It’s true that most people accustomed to wood and brick houses would resist any shift to homes with a tent profile. But add trees and gardens, and hopefully inject real flair into the decor of the exterior fabric, and the new neighbourhoods could at least equal the aesthetic appeal of today’s suburbs. Of course, cultural evolution normally proceeds at a generational pace. Fabric town planning will take time to claim its share of attention. But humanity is struggling to provide billions of presently poor people with a decent standard of living and touches of elegance. Over the 21st century, perhaps we won’t be able to resist the advantages of fabric architecture.
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The Chinese challenge
If you know an admirable person to profile in
China’s manufacturing companies now offer
On The Job—he or she may be a veteran or
a comprehensive range of onshore drilling
apprentice, field or shop, wise or a little crazy—
Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.
rigs, pumps, and other oilfield equipment.
please give me a call at (780) 944-9333, or
In February, Oil & Gas Inquirer will examine
email mbyfield@junewarren-nickles.com.
how domestic manufacturers compete and
In fact, feel free to sound off about any
cooperate with Chinese firms.
concern at all—that’s a personal invitation.
OIL & GAS INQUIRER • January 2010
9
Stats
FAST NUMBERS
US
AT A GLANCE
$30 billion
US
Price paid by Exxon Mobil for shale gas producer XTO Energy Inc.
$300 million
2011-2012 spending cut proposed by Wyoming governor, a 10 per cent reduction due to low natural gas prices
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
Dec 2008 Jan 2009 Feb 2009
496 156 116
1,793 606 899
200 96 120
2,489 858 1,135
Dec 2008 Jan 2009 Feb 2009
917 248 269
2,380 813 1,060
173 70 113
137 47 36
3,607 1,178 1,478
Mar 2009 Apr 2009 May 2009
321 111 71
979 344 187
317 140 53
1,617 595 311
Mar 2009 Apr 2009 May 2009
433 111 71
1,121 342 187
165 61 46
86 12 35
1,805 526 339
Jun 2009 Jul 2009 Aug 2009
36 79 101
143 178 212
42 77 80
221 334 393
Jun 2009 July 2009 Aug 2009
177 79 250
211 31 267
45 6 36
27 3 37
460 119 590
Sept 2009 Oct 2009 Nov 2009
146 132 169
155 160 212
78 77 116
379 369 497
Sept 2009 Oct 2009 Nov 2009
146 331 382
155 196 244
45 32 68
9 12 10
355 571 704
Wells Drilled In British Columbia
Wells Drilled In Saskatchewan
Source: B.C. Oil and Gas Commission
Cumulative to December 4, 2009 Source: Saskatchewan Energy & Resources
MONTH
WELLS D R I L L E D
CUMULATIVE *
Dec 2008 Jan 2009 Feb 2009
79 125 117
919 125 242
Mar 2009 Apr 2009 May 2009
75 33 26
317 350 376
Jun 2009 Jul 2009 Aug 2009
19 34 36
395 429 465
Sept 2009 Oct 2009 Nov 2009
38 29 39
503 532 571
* from year to date
OIL
GAS
OTHER
DRY
TOTAL
403 78 42 57
5 30 183 0
33 7 5 23
22 38 9 47
463 153 239 127
35 34 71 586
0 0 0 0
0 0 0 2
0 0 0 0
35 34 71 588
438 112 113 643
5 30 183 0
33 7 5 25
22 38 9 47
498 187 310 715
Vertical Wells
Lloydminster Kindersley Swift Current Estevan Horizontal Wells
Lloydminster Kindersley Swift Current Estevan Total Wells
Lloydminster Kindersley Swift Current Estevan
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January 2010 • OIL & GAS INQUIRER
S P O T P R I C E S at AECO trading hub in Alberta
GAS STOR AGE
Source: Natural Gas Exchange Inc.
Source: U.S. Energy Information Administration 4.00
5.5
$5.35/GJ Total vol.: 2,002 TJ Transactions: 190
4.5
3.5
in the United States
Nov 18
Nov 25
Dec 2
Dec 9
3.75 3.57 Tcf Year ago: 3.49 Tcf 5-year avg: 3.41 Tcf 3.50
Dec 16
Nov 13
Nov 20
Nov 27
Dec 4
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada December 14, 2009 Source: Rig Locator
Alberta November 2009 Source: Daily Oil Bulletin
ACTIVE
DOWN
TOTAL
(Per cent of total)
Western Canada Alberta
ACTIVE
283
296
579
49%
53
58
111
48%
5
5
10
50%
Saskatchewan
77
57
134
57%
WC Totals
418
416
834
50%
0
2
2
0%
British Columbia
Manitoba
Northwest Territories
OIL WELLS
Alberta
GAS WELLS
Nov 09
Nov 08
Nov 09
Nov 08
Northwestern Alberta
23
53
46
173
Northeastern Alberta
31
51
0
12
Central Alberta
93
154
32
207
Southern Alberta
22
20
134
683
TOTAL
169
278
212
1075
Service Rig Count by Province/Territory
Drilling Activity: CBM & Bitumen
Western Canada December 14, 2009 Source: Rig Locator
Alberta November 2009 Source: Daily Oil Bulletin
ACTIVE
DOWN
TOTAL
ACTIVE
Western Canada Alberta
406
741
45%
British Columbia
17
23
40
43%
Manitoba
8
1
9
89%
Saskatchewan
112
74
186
60%
WC Totals
472
504
976
48%
1
1
2
50%
Northwest Territories
COALBED METHANE
Alberta 335
Dec 11
BITUMEN WELLS
Nov 09
Nov 08
Nov 09
Nov 08
Northwestern Alberta
1
8
6
15
Northeastern Alberta
0
0
31
42
Central Alberta
13
93
50
77
Southern Alberta
15
171
0
0
TOTAL
29
272
87
134
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OIL & GAS INQUIRER • January 2010
11
Outlook 2010
2010 looks like a better year for the oilpatch than 2009 by Graham Chandler
L
ast year proved to be a debacle for most oil and gas industry forecasters. The Canadian Association of Oilwell Drilling Contractors (CAODC) initially predicted a well count of 14,325 wells for 2009. The Petroleum Services Association of Canada (PSAC) was even more optimistic at 16,750 wells. The Canadian Association of Petroleum Producers (CAPP) initially estimated 14,700. As the global recession slashed energy consumption and prices throughout 2009, the associations repeatedly found themselves forced to reduce their well estimates. The actual well count for 2009 will likely be little more than 8,000 wells, more than a 50 per cent plunge from 17,043 wells in 2008. That grim performance was most accurately forecast by Ziff Energy Group, which initially estimated the 2009 well count at 8,000 to 11,000. Within that range, Ziff VP Bill Gwozd leaned toward the more pessimistic figure as early as November 2008. For 2010, the Calgarybased consulting firm—whose thorough evaluations of gas markets are wellrespected in Houston and New York as well as its hometown—ranks among the most optimistic analysts. Driving last year’s activity decline were natural gas prices that plunged to 12
January 2010 • OIL & GAS INQUIRER
the range of C$3 per thousand cubic feet (Mcf) for months. The Alberta gas price (AECO) is currently about C$4, while NYMEX hovers around US$5 per Mcf— still too low to drive much of a recovery in drilling. For 2010, however, Ziff believes NYMEX gas prices will average US$6 to US$7 this year. “At $6.50, field activity will likely be more robust than it has been in 2009,” Gwozd suggests. Further strengthening the outlook, he adds, are crude oil prices that have already reached activity-generating levels. T he veteran analyst hesitates to forecast a well count for 2010 because drilling and completion technologies are in a period of extraordinary f lux. “What’s a well? When you drill a dozen horizontal wellbores from a single pad, you’re in a very different situation than punching shallow gas wells on the prairie,” Gwozd says. “The well count will remain a significant metric because every well needs a wellhead, tubulars, and so forth. However, the well count by itself is no longer a reliable metric for forecasting production changes from year to year.” On the demand side, Ziff foresees a continent-wide industrial recovery pushing up natural gas sales over the coming year, notably for power generation.
But Cam Gingrich, the group’s manager of gas services, notes that higher gas prices will also make coal more competitive. Based on normal weather, Gingrich says, “We see a small increase [in demand], but not a massive one.” The analyst does not expect potential climate change laws and regulations to have much effect on gas demand before 2012, if then. “A lot of the legislation is languishing,” he says. Gwozd anticipates a continuing decline in Canadian gas sales to the United States. “Exports were just a shade over 10 Bcf [billion cubic feet] per day in 2005,” he says, “By 2010 we see exports down to around 8 Bcf per day. And by 2015, we expect that to tilt down towards 7 and by 2020, 6 or 7 Bcf per day.” In part, the Ziff VP believes oilsands producers will be sopping up more gas. “These giant ‘vacuum cleaners’ currently take 1.1 Bcf per day and that will rise to almost 3 by 2020,” he says, “weighted towards the in situ projects.” Another factor, in his view, is declining gas productive capacity in the Western Canadian Sedimentary Basin. PSAC does not share Ziff’s belief that times will improve much in 2010 over 2009. Roger Soucy, its president, says the association anticipates about 8,000 wells this year. The annual total includes 5,095
wells in Alberta (down by 5 per cent from 2009), 630 in British Columbia (up by 7 per cent), and 1,935 wells in oil-prone Saskatchewan (an increase of 10 per cent over 2009). PSAC is basing its 2010 forecast on average natural gas prices of C$5 per Mcf (AECO) and crude oil prices of US$72 per barrel (West Texas Intermediate). “We all know that oil and gas activity is predicated on price,” Soucy says. “In 2010, oil prices will be adequate to sustain conventional oil activity. As a result, we are forecasting an increase in drilling in oil[-prone] areas like Saskatchewan and northeast Alberta. Gas pricing, on the other hand, remains relatively low and we are not expecting any significant gas price turnaround in 2010. That, combined with industry’s focus on shale gas drilling, has led us to forecast a 30 per cent drop in the conventional shallow gas drilling area of southeast Alberta. “We’re forecasting that [western Canada] will potentially see more oil wells than gas wells drilled in Canada in 2010.” Soucy continues. “And that’s not because we’ve all of a sudden got an abundance of oil plays, it’s just the lack of natural gas pricing levels to generate interest to drill for natural gas.” He also acknowledges that gas prices remain “a wild card.” Oil drilling has not outpaced
gas since the Turner Valley and Leduc plays, back in the heyday of Alberta’s conventional crude discoveries. Besides its lack of conventional oil exploration targets, Alberta continues to suffer due to its provincial royalty structure. Murray Edwards, vice-chairman of Canadian Natural Resources Limited, reflected widespread industry sentiment when he recently told Toronto’s Globe and Mail: “Without cuts to royalties, which were raised early this year, capital will continue to flow into Saskatchewan oil properties and British Columbia gas assets—but not to Alberta.” The National Energy Board, in its annual winter outlook, forecasts an average crude oil price between US$75 and US$80 per barrel through the winter 2009–10, while natural gas is forecast at $4 to $5.50 per Mcf for the period. The CAODC estimates the 2010 well count at 8,523, based on US$70 per barrel WTI and C$5.50 per Mcf. The fourth quarter of 2010 is expected to be the strongest, according to the CAODC. CAPP more optimistically pegs western Canadian drilling for this year at 9,500 wells. Healthy crude values will stimulate oilsands activity, although some bitumen operators remain unconvinced. In its latest oilsands forecast, the Canadian OIL & GAS INQUIRER • January 2010
13
Photo: Trinidad Drilling Ltd.
Feature
The Canadian Association of Petroleum Producers thinks capital spending will be $40 billion in 2010.
Energy Research Institute (CERI) notes: “While announcements have been made by Imperial Oil that they are staying course and proceeding with the Kearl oilsands projects, other major producers such as Royal Dutch Shell and Total have raised concerns that current oil prices are insufficient to justify new oilsands projects.” CERI adds that “as the developed world moves forwards with its economic recovery and the BRIC nations [Brazil, Russia, India, and China] return to high levels of growth, it does not take much of an imagination to see [WTI] oil prices pushing north of US$80 to US$90 per barrel.” In its 2009 World Energy Outlook, the International Energy Agency (IEA) says crude oil consumption in the developed world is likely to remain nearly flat, with a projected annual increase of 1 per cent for the next two decades. However, the IEA suggests that India’s oil demand is likely to rise by 3.9 per cent annually until 2030, and China’s by 3.5 per cent. The U.S. Energy Information Administration estimates world oil consumption will rebound in 2010, climbing by 1.1 million barrels per day compared with 2009. 14
January 2010 • OIL & GAS INQUIRER
For Canada’s gas services sector, the hot spot this year will be the world-class shale and tight rock prospects in northeastern British Columbia. In the Horn River Basin and Montney plays, producers seem willing to drill no matter what the current natural gas price happens to be. Soucy says the shale plays will fuel demand for horizontal services, “which involves everything from the drilling rig down through to the motors that drive the process at the bit end of the operation.” Simon Mauger, a technology specialist with Ziff, foresees the potential for an immense supply impact over time from horizontal drilling, multi-stage fracs, and the use of micro-seismic to assess and improve frac techniques. “These technologies have increased in influence over the past four years,” Mauger says. But the immediate effect of these tools on gas supply and prices remains uncertain, he warns. That’s because most of North America’s shale plays, including Horn River, remain at a relatively early stage of development. A crucial concern with shale gas wells is the potential rate of production decline. “There are indications already that decline
rates are in that 65 per cent range in the first year, 35 in the second, 25 in the third, and 10 to 20 thereafter. These declines can be quite brutal,” Gwozd says. “So if a well starts off at 18 million, it may be down to 6 [million] after a year then 3.5 [million]—that’s significant.” The Ziff VP has not forgotten the Ladyfern play, also in northeastern British Columbia, which unfolded in 2001. Within two years, production rocketed to about 700 million cubic feet per day. Today those wells are producing a total of 25 million cubic feet per day. In recent months, some American producers have been promoting the concept of shale gas providing a century of national supply. “When they called it a 100-year supply, that is all the gas in the ground—original gas in place,” explains Gwozd. “What we need to show is at what rate it can be produced until the end of the field. The 100-year number is simplistic, but we concur that shale will comprise nominally 18 Bcf by 2020— that’s triple what it is now.” PSAC’s Soucy concurs on the unconfirmed production rates for shale. “There is a debate going on,” he says. “Some
Feature Photo: Trinidad Drlling Ltd.
We’ve got you covered
A Trinidad rig drills in B.C.
1 ➡
2 ➡
analysts have been saying the depletion rates are very high, which is being challenged by Devon and some of the bigger companies. In my opinion, we need more time to see what actually does happen. At this point, it’s a function of waiting to see what does prove out and whether shales will be the saviour for natural gas in North America.” Even so, multiple fracing in shales is definitely driving demand for more pumping horsepower, and not only in the United States and Canada. “In line with recent trends, we expect pressure pumping to enjoy one of the highest growth rates in the service industry,” writes Jan Cerny, a research analyst for oilfield services at Macquarie Capital Markets Canada. “We estimate that over the next 12 to 18 months, about one million horsepower [mhp] of pressure-pumping capacity will be retired or relocated from North America to international markets.” This should reduce North American pressurepumping capacity 13 per cent to 5.7 mhp by late next year, with 5 mhp located in the United States and 0.75 mhp in Canada, he calculates.
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Feature Cerny forecasts that pumping horsepower demand will soar by about 36 per cent over the next 12 months, raising pressure-pumping equipment utilization from 48 per cent currently to roughly 68 per cent by the second half of 2010 and close to 79 per cent by the second half of 2011. Pressure-pumping prices have stabilized recently. However, the Macquarie analyst predicts they will start rising again, picking up momentum in the last half of 2010 and becoming very strong in 2011. Capital spending by producers is a crucial factor for oil and gas service companies. As of early December, the
Daily Oil Bulletin reported that only 20 Canadian producers had reported their initial capital budgets for 2010. Although many companies are hesitating before placing next year’s investment bets, the spending trend to date has been modestly higher. The 20 producers announced capital projections of $17.3 billion for 2010, $609 million more than the same companies expected to spend in 2009. According to the Daily Oil Bulletin, most of the mid-size and junior producer budgets that have been announced for 2010 indicate spending hikes of 20 to 30 per cent over 2009. A few—such as Anderson
Energy Ltd., Iteration Energy Ltd., and Arsenal Energy Inc.—have more aggressive increases planned for next year due to extreme cuts to their 2009 expenditures. CAPP, whose members are mostly large and medium-size producers, predicts that the industry’s capital spending will jump from $34 billion in 2009 to $40 billion this year. (The equivalent figure for 2008 was $54 billion.) “Our update now is kind of with cautious optimism…which is really driven mostly by a recovering level of oil prices,” says Greg Stringham, CAPP’s VP of oilsands and markets.
Penn West applies horizontal multi-frac technology to oilfields
Photo: Brian Zinchuk, Pipeline News
Staged hydraulic fracturing of horizontal wellbores, already progressed from 90 per cent vertical wells to 80 per cent the dominant technology in natural gas, appears poised to horizontal multi-stage frac wells. claim a big a role in oilfields. Among Canada’s leaders in this In Saskatchewan, Penn West is seeing consistent results at emerging strategy is Penn West Energy Trust. This year, the Leitchville with horizontal wells that initially produce 100 to 130 Calgary-based producer hopes to increase production and barrel per day range. Total production per well should average recoverable reserves from its light oil properties at Waskada, 125,000 barrels and possibly up to 150,000 barrels per well in Dodsland, Pembina, and Leitchville. total, according to Bob Shepherd, senior In 2010, the trust plans a capitalVP of exploration and development. The spending program between $800 miltrust is also very encouraged by what it lion and $900 million, according to is seeing in eastern Alberta shallow gas Murray Nunns, its president and COO. with the use of horizontal wells. That activity will be weighted more Bill Andrew, Penn West’s CEO, towards the second half of the year, says his team is quickly moving elsesays Nunns, adding, “We want to a bit where with the Leitchville concept. At more results in terms of our light oil Waskada, Man., where it has a large plays before we really put the pedal land position, he says initial tests indidown on the capital side.” cate “we are certainly in the guts of the Penn West will focus on six nearoil trend” and the trust will be following term oil projects, five of them oil, which up quickly with horizontal wells. are in the first and second phases of test“The biggest change will be once ing and refining multi-frac horizontal we get into the groove will be Pembina field techniques. Nunns says these pro[Cardium],” Andrew says. “Penn West has a land base that goes through jects will account for 50 to 60 per cent of capital spending with 200 to 225 wells Garrington, up to Sylvan Lake and in 2010, weighted 80 per cent to oil. Willesden Green, up to Strachan on the The trust’s third-quarter producwest side of the Pembina field” where it tion averaged 178,124 barrels of oil plans to drill this winter. The trust also equivalent per day in 2009, down plans to be active this winter in northfrom 180,601 barrels of oil equivalent central Alberta in the Swan Hills/ per day in the third quarter of 2008. Mitsue area and further north into the Penn West drilled a total of 36 net Nipisi and Otter areas using the same wells, including 29 horizontal multitype of technology on infill wells and on some of the smaller, tighter plays and stage frac wells, with a success rate of 100 per cent in the third quarter. with good results to date. Penn West’s drilling programs have This rig is working in Manitoba. — DAILY OIL BULLETIN
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January 2010 • OIL & GAS INQUIRER
Photo: Trinidad Drilling Ltd.
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JAp a nr uila r2 y 0 0290 1• 0 O •I L O&I LG &A SG AI NS QI U N IQRUE IRR E R
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Gimme shelter
Fabric-over-frame matures as a building technology that’s well-suited to the resource sector by Mike Byfield
From simple canvas tents, fabric-covered structures have evolved to the point where they can challenge conventional construction for almost any type of low-rise building. Churches and casinos, military bases and manufacturing plants, zoos and hospitals—all of these facilities and more have been made in western Canada, then shipped around the world. In the oil and gas sector, fabric buildings attract customers due to their attractive capital cost, portability, speed of construction, ease of maintenance, and surprising durability. As the industry expands, its products and players are becoming more varied.
The Sprung head office, located south of Calgary, illustrates the growing sophistication of the company's building technology.
O I L O&I LG &A SG AI NS QI U N IQRUE IRR E• R J a • nAp u arril y 200 10 9
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Cover-All mushrooms into North America’s largest fabric-and-steel building manufacturer In October, Cover-All Building Systems, Inc. shipped its 35,000th building, all formed with fabric stretched over a steel frame. The longest of these buildings, at 1,700 feet, houses a dairy in Kazakhstan, and much bigger structures are in the proposal stage. These milestones have been achieved by a company launched just 18 years ago by the founder, Richard Quiring, who “wanted to expand his hog operation and didn’t want to put up a Quonset hut, so he came up with his own alternative,”
the steel framework can last, but upwards of 50 years is a reasonable estimate unless the structure is being used to store a corrosive substance like highway road salt.” Foundation options include concrete piles, floating blocks, concrete or steel walls, and earth anchors. “The primary use of our buildings is cold storage, protecting vehicles and other goods against sun, rain, and other weather,” the engineering VP says. “Also, many customers use our structures as
In terms of width, a Cover-All building can have a clear span (i.e. without interior columns) as great as 300 feet, although 180 feet is the standard maximum.
20
January 2010 • OIL & GAS INQUIRER
maintenance shops, which can be heated. Our own manufacturing facilities in Saskatoon are housed in Cover-All buildings, which we heat to 20 degrees Celsius in the winter. Because we use an overhead radiant heating system, we don’t have to heat the entire volume of structure.” When heating is required, a lining is attached to the inner chords (beams) of the steel trusses. The outer and inner skins plus the air trapped between them yields an insulation value of about R5. The liner can also be insulated to provide any insulated rating.
Photo: Cover-All Building Systems, Inc.
says Mark Antonini, VP of engineering for Saskatoon-based Cover-All. At a casual glance, fabric may seem a tad flimsy for serious construction. To counter that misconception, Cover-All staged a lifting demonstration in August. A 6,200-pound pickup truck was driven onto a 12 by 24 foot panel of DuraWeave. The woven polyethylene fabric had been stretched within a tubular steel frame. While cameras rolled, six forklifts hoisted the truck atop the DuraWeave. Antonini had reason to be pleased with the performance—that pickup belongs to Cover-All’s president, Nathan Stobbe. In terms of width, a Cover-All building can have a clear span (i.e. without interior columns) as great as 300 feet, although 180 feet is the standard maximum. The fabric is a patented double-stack weave, guaranteed for 15 years, but capable of lasting longer. With a series of 10,000pound winches and zero-stretch belting and/or cables, covers stay tight and secure. Antonini says DuraWeave strongly resists punctures as well as ripping, and the tensioned membrane can be readily replaced when it does eventually wear out. Cover-All’s galvanized steel frameworks have a patented triple-coated corrosion barrier, and all welds are re-coated. A ntonini, who heads the company ’s product development and engineering teams, adds, “I really don’t know how long
The interior of fabric buildings often have an airy feel thanks to the combination of massive clear spans and natural light. “A translucent membrane passes enough sunlight into the structure to eliminate the need for artificial lighting during the day,” Antonini explains. Electricity bills are lower, of course, but there’s also a more intangible benefit. One farmer noticed that his cows, when offered a choice between a conventional barn and a Cover-All building, always headed for the naturally lit stalls. People, too, typically prefer to work near windows and other sources of sunlight. The company considers itself North America’s largest maker of steel-frame fabric buildings. It currently has about 400 personnel in Saskatoon and an additional 100 or so in corporate dealerships like Cover-All Alberta. Private dealerships around the world (including CoverAll North Inc., based in Grande Prairie, Alta.) bring its employment total up to 1,200. Cover-All has averaged doubledigit percentage revenue growth since its inception. Saskatchewan has been a very good place to manufacture over the years because of the solid and experienced workforce. Over the last few years, Cover-All has also brought in highly qualified immigrants to augment that workforce. The company, which sees further growth in its future, is monitoring expnasion opportunities in Europe and the United States.
Feature Photo: Cover-All Building Systems, Inc. Photo: Cover-All Building Systems, Inc.
Photo: All Weather Shelter
Fabric buildings can house virtually any industrial application, although the presence of corrosive substances will shorten a shelter's life significantly. OIL & GAS INQUIRER • January 2010
21
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All Weather Shelters engineers for the oilsands a non-standard footprint, or needs an unusual door, we’d take a little longer, but normally not much.” Roger Sims, Craig’s father, began All Weather in 1996. His son, a construction engineering graduate from the Northern Alberta Institute of Technology, specialized in putting up structural steel buildings before taking over the management of the family business. Typically, the Edmonton plant’s payroll stands at about 30, plus a couple of dozen additional workers employed on installation crews. “We’re not a large outfit but the company has plenty of experience. We’re fortunate that many of our employees have stayed with us for a long time,” Sims says. The All Weather director is blunt about one risk faced by anyone looking to buy a fabric building: “We see a fair amount of fly-by-night manufacturing in this sector. Someone sets up shop, sells at 15 to 20 per
cent less than responsible competitors, then disappears as their products begin to collapse,” Sims says. “One national retailer actually carried an imported line of poorquality consumer structures sold under the name All Weather. When a building collapses, our whole industry looks bad.” When a fabric structure collapses, the typical causes are wind or snow load. The National Building Code includes data on wind, snow, temperature, and seismic activity for every municipality in Canada. “Our sector has gone through a lot of change over the past five years because the building code was extended to include our class of products. We engineer a building so that it will withstand conditions where it will be set up,” Sims says. “Mickey Mouse operators are forced to comply with the code, which protects consumers, but non-compliant products are still around to some extent.”
Photo: Sprung Instant Structures
Craig Sims targets a specific sector: oi l sa nds. “ T he re sou rce i s on ou r front doorstep,” says the co-owner of Edmonton-based All Weather Shelters. “It’s a big industry with serious concerns about cost control and labour supply, and we can address those factors effectively.” Because oilsands producers sometimes operate internationally as well, All Weather has shipped its products as far as Asia and North Africa. Closer to home, the manufacturer has supplied equestrian and ice arenas, bus barns for the City of Edmonton, and a variety of other buildings. “If an oilsands producer encounters delays in construction of a conventional building, the ripple effect on related developments can be really expensive,” Sims says. “All Weather carries a lot of inventory, so we can usually supply a structure within a week. If a customer requires
Sprung's headquarters boasts architectural features like two-storey glazed windows, a basement gymnasium, and first-class insulation.
Sprung pioneers the world’s most advanced fabric structures While a dozen or more competitors sell fabric buildings in Canada, only one manufacturer has moved far beyond the traditional inventory of industrial storage, shops, and arenas. Just south of Calgary at Aldersyde, Sprung Instant Structures has created a world headquarters with no peer anywhere. The 150,000 square foot complex, erected two years ago, is engineered with an aluminum substructure and architectural membrane. Its facilities include two manufacturing wings, a mezzanine 22
January 2010 • OIL & GAS INQUIRER
administrative centre, a two-storey glass façade, a full gymnasium in the basement, and more. Sprung VP Jim Avery says his company has its eye on the resource sector, particularly the oilsands. “These projects, big or small, need shelter for personnel and equipment at an affordable price. At the same time, lifestyle quality has to be high if you want to attract and hold good people,” Avery says. “When the energy sector moves back into high
gear and Alberta again finds itself facing labour shortages, oilsands operators must minimize the need for skilled construction workers. They also have to move quickly while maintaining construction quality. We’ve positioned ourselves to meet all of those requirements.” For a Calgary outfit, Sprung’s local roots are extraordinarily deep. Started in 1887 by Philip Dorland Sprung, the company manufactured chuckwagon covers, teepees, and other tent-type shelters
Feature
Truss spacing is a critical factor in strengthening a building for local conditions. In Sims’ view, no single-chord steel framework can safely support any but the smallest structures. Sturdier trusses consist of two chords linked by a lattice of smaller steel webs. Besides strength, the double-chord truss provides airspace where All Weather can install fibreglass insulation if required, to a value as high as R20. What sort of changes does Sims see coming down the road? “I’ve seen fabric with solar cells built in. Wouldn’t it be great if a membrane-type building could provide its own power?” he replies. “Seriously, though, there’s no way of knowing where the technology will take us in future. I do think the sector will continue to expand as potential buyers become more aware of the benefits built into these products.”
for settlers and aboriginal bands. Philip Donald Sprung, the current president, is the founder’s great-grandson, and several other family members are active managers as well, including Avery’s wife. This pioneering firm has developed what amounts to a new architectural technology that reportedly works well in virtually every environment. Arctic Watch, the world’s most northerly lodge, sits less than 130 kilometres from the magnetic North Pole. Another Sprung structure, located in the Aleutian Islands, was engineered to meet sustained wind loads as high as 200 kilometres per hour. Restaurants and mass merchandisers appreciate the hip ‘wow’ factor and large skylights of Sprung structures. The distinctive Sprung building profile not only sheds snow well, but also earns praise from church worship leaders for its acoustic qualities. Casino operators by the dozen have opted for Sprung facilities. Calgary’s Edge School, which serves 300 student-athletes, reportedly saved millions by having Sprung construct its two hockey arenas and gymnasium. The company is also proud of a letter from former U.S. first lady Barbara Bush praising its work in speedily supplying hospitals for charity work in Rwanda. On short notice compared to conventional construction, Sprung can put together
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technology achieves greater strength and precision. One well-known testing laboratory in the U.K. told us that our structures are the most airtight they’ve ever tested.” T he c ompa ny ’s a lu m i nu m s ub structure allows precise placement of formaldehyde-free fibreglass blankets. Besides reducing the cost of heating and air conditioning, insulation acts as an effective barrier to vapour and sound.
“Our structures carry a higher initial price tag, but the owner can recover that expense over the building’s life through lower operating costs,” Avery says. “Even for a relatively short-term application, the insulation option usually makes financial sense. The customer that takes proper account of his structure’s full life cycle can benefit from superior reliability, comfort, and aesthetics at little or no additional cost.”
Photo: Sprung Instant Structures
a convention centre, restaurant, ski resort, golf club, bush camp, warehouse, mine processing facility, or other lowrise building. An installation crew can progress as quickly as 1,000 square feet per day. Innovation, flexibility, and especially reliability, according to Avery, lie at the heart of Sprung’s success. “No one wants their school to blow over,” he points out. “And don’t kid yourself, it can happen. I’ve seen two of our buildings standing on either side of a competitor’s product that had collapsed during a storm. We’ve spent a great deal of money designing reliable doors, windows, and other architectural features of many types. But most important of all is our unique integration of architectural membrane, the aluminum substructure, and insulation technology.” Sprung’s top-quality fabric consists of five layers, including Dupont Tedlar
"I’ve seen two of our buildings standing on either side of a competitor’s product that had collapsed during a storm." - Jim Avery, VP, Sprung Instant Structures
24
January 2010 • OIL & GAS INQUIRER
Photo: Sprung Instant Structures
colour film. The combination resists fire, ultraviolent rays, fire, fungus, solar heat buildup, and other ills. Eight colours are available. The light, bright material provides an excellent backdrop for company logos and other decoration. Where most rivals place their fabrics on top of a steel frame (i.e. no ribs are visible from the exterior), Sprung patented the stressed membrane structure: its membrane panels are placed under high tension within the framework. Another Sprung hallmark is aluminum, which is more expensive than steel but 66 per cent lighter, highly corrosionproof, and readily extruded into virtually any shape and size. “Extrusion allows for fitted and bolted connection points rather than welded connections frequently seen on steel,” Avery says. “Overall, our
Sprung hopes to see its structures used in the oilsands as offices, housing, and industrial workshops.
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Nexen sees oilsands as natural market for Horn River gas
Photo: Nexen Inc
by Paul Wells
Nexen says Horn River Basin producers must address mounting competition from U.S. shale gas plays.
As Alberta oilsands operators continue to increase production, Nexen Inc. believes British Columbia’s Horn River producers should supply their growing demand for natural gas through TransCanada Corporation’s North Central Corridor pipeline. “With the geographical location of Horn River, we feel it makes sense to come across and feed those volumes over to the oilsands,” said Michelle Rampersad, Nexen’s marketing manager for northeastern B.C. Producers in the Horn River Basin likely will need to find additional markets in response to surging North American shale gas production, Rampersad told a Canadian Institute conference in Calgary on Nov. 24. If the proposed Kitimat LNG (liquefied natural gas) facility, which would export Canadian gas to Asian markets, comes to fruition, Rampersad said the new outlet would also be “real game changer” for pricing of B.C. natural gas.
Kitimat is an export facility. Import LNG projects now face a much bleaker future, the conference heard. “In my view, LNG imports into the United States are actually not required. That is a very sad development, particularly for the companies that have spent billions of dollars building re-gasification plants in the U.S. Gulf Coast, along the Atlantic seaboard, and in Mexico to serve the U.S. market,” said Patricia Mohr, V P of economics and commodity market specialist with Scotiabank Group. Mohr said that American shale and tight gas development has also lowered the industry cost curve. Scotia Waterous’ estimates indicate t hat t he nat ural gas price required to cover break-even costs (operating, finding, and development costs and royalties/taxes, as well as a 10 per cent return on total capital employed, but excluding land costs) is
only US$3.19 to US$4.45 per million British thermal unit for the Marcellus, Haynesville, Barnett, Eagleford, and Fayetteville shales. Scotia Waterous believes that prices should rebound further into the first half of 2010, but only modestly. Mohr noted that horizontal drilling allows a more rapid response to higher prices than conventional drilling—“a factor also likely to check prices,” she said. Mohr is forecasting an average NYMEX price of US$5.50 per million British thermal unit in 2010, and in 2011, “I’ll keep the price right at the $5.50 mark, no higher.” If natural gas does reach the $6 per million British thermal unit mark for an extended period, Mohr said a flood of new supply will follow. “We think if prices move up to $6, the economics of these new shale developments in the U.S. means a tremendous amount of drilling…because they’re very economic, very lucrative at $6,” she said. “So, I think the industry’s cost curves have been lowered.” Rampersad said Nexen’s break-even mark for Horn River is dropping rapidly and has further upside. She said the project currently breaks even (with a 10 per cent internal rate of return) at US$5 to US$6 per thousand cubic feet and that the company continues to work toward reducing that figure further. Nexen’s Horn River program is progressing well with the drilling and completion of approximately 10 wells. “Our best guess is we have three to six Tcf [trillion cubic feet] of recoverable reserves. That’s not gas in place, that’s recoverable reserves,” Rampersad said. “We’ve also had extremely high initial production rates out of the wells. We’ve been very fortunate with that—as have other producers in the basin—upwards of one MMcf [million cubic feet] per day per frac.” — DAILY OIL BULLETIN
BRITISH COLUMBIA WELL ACTIVITY
NOV/08
NOV/09
WELL LICENCES
243
85
▼
NOV/08
NOV/09
WELLS SPUDDED
68
42
▼
NOV/08
NOV/09
WELLS DRILLED
61
37
▼
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • January 2010
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British Columbia
TAQA North plans to drill three Horn River wells this winter Anxious to see what its newly acquired exploration licences hold, TAQA North plans to drill three exploration shale natural gas wells in the Horn River Basin of northeastern British Columbia this winter, the company’s top official said on Nov. 11. Earlier this year, the subsidiary of the Abu Dhabi National Energy Company PJSC (TAQA) spent $63.3 million to acquire 13,000 hectares of land on two blocks north of Fort Nelson. In Canada, the Horn River basin and tight gas are among the many globa l orga n ic g row t h oppor t u n ities for the parent company as it shifts its focus away from growth by mergers and acquisitions, Carl Sheldon, the recently appointed general manager,
said in a conference call to discuss thirdquarter results. The company reported a profit of 278 million AED (Arab Emirates Dirham) for the three months ended Sept. 30, 2009, compared to 840 million for the 2008
Bratani (39,700 boe per day), and TAQA Energy (4,500 boe per day). TAQA North production was down five per cent from 93,000 boe per day in the 2008 period due to decreased capital investment as a result of lower natural
TAQA's global production was 132,600 barrels of oil equivalent per day in the third quarter of 2009, up from 110,500 boe for the same period in 2008. period. Total production was 132,600 barrels of oil equivalent (boe) per day, up from 110,500 boe per day in the third quarter of 2008. Output was split between TAQA North (88,400 boe per day), TAQA
gas prices. The average realized price was US$2.96 per thousand cubic feet, a reduction of 67 per cent from $9.03 per thousand cubic feet in the third quarter of 2008.
Spectra Energy’s $100-million, 95-kilometre South Peace Pipeline, which extends Spectra Energy’s existing raw gas gathering system in the rapidly developing Montney/ Doig/Cadomin plays in northeastern British Columbia, has been successfully placed into service. The 20-inch raw gas pipeline includes pipeline segments south and north of an existing 12-inch line. “The South Peace Pipeline project represents an important part of Spectra Energy’s significant expansion activities designed to meet the needs and timing of area producers and downstream customers,” says Duane
Rae, VP of field services for Spectra Energy Transmission West. “This pipeline, which has a capacity in excess of 220 million cubic feet per day, provides Montney producers in the emerging South Peace region with access to our vast Fort St. John area infrastructure, including our McMahon gas processing plant.” Over the past two years, Spectra also completed a turnaround of its processing facilities at the plant, which is now capable of operating at its full design capacity of 740 million cubic feet per day, Rae says.
Photo: Spectra Energy
Spectra South Peace Pipeline expansion comes on stream
McMahon can now process 740 MMcf/d.
Exxon, Imperial boost Horn River acreage at B.C. land sale British Columbia’s land sale for November brought just under $20 million into government coffers at $1,130 per hectare, which included a successful $6.5-million bid for a drilling licence in the Horn River Basin. That licence was scooped up jointly by ExxonMobil Canada Energy and Imperial Oil Limited. The companies picked up 1,597 hectares at an average price of $4,066 per hectare at 94-O-2, north of Fort Nelson. 28
January 2010 • OIL & GAS INQUIRER
“Imperial Oil and ExxonMobil did acquire on a 50-50 basis additional exploration acreage in the Horn River Basin,” said Laura Bishop, a company spokeswoman. “[It’s] close to the middle of what we currently own there, so this acquisition of the additional acreage is a logical follow-up to what we currently have. This brings our…acreage acquired by the companies since 2007 in the Horn River area to 309,000 acres.”
Five leases in the Montney play located at 82-19W6 went for just under $6 million with per-hectare average ranging from $1,574 to $8,662. The land sale brought the province’s year-to-date total bonus revenue to $720.6 million, thanks mostly to two large sales. It’s still off from $2.6 billion the province had collected to the same point last year. Per-hectare averages have also fallen to $2,110 from $3,692 last year.
British Columbia
CCS Corporation and Secure Energy Services have filed proposals to build secure landfills near Dawson Creek, betting on growing volumes of drilling waste from the Montney and Horn River gas plays. “We are in the heart of the new up-and-coming Montney gas play in B.C.,” says Todd Sauve, development manager for landfill services with Calgary-based CCS. “It ’s going to be a fairly significant play in B.C., and we wanted to be there for the customers,” Sauve adds. Secure landfills are fenced, lined facilities designed to accept wastes, such as contaminated soil, that are banned from municipal landfills. CCS currently operates two secure landfills in British Columbia. Some operators also haul waste to approved facilities in Alberta. CCS has filed a proposal to build a 65-hectare landfill 15 kilometres west of Dawson Creek, a hub for EnCana Corp. and other producers. CCS’s facility would have an expected life span of 25 to 40 years, with the first stage of the project estimated to cost $2 million. Secure Energy Services, based in Calgary, has filed a proposal for a 34-hectare, $7-million landfill five kilometres south of Tupper, just 1.5 kilometres west of the Alberta-B.C. boundary. “We’ve been approached by a number of producers in B.C.” says Corey Higham, Secure Energy’s business development manager. The company currently has no operations in British Columbia. The site for the facility is near the crest of a hill and slopes northward to Swan Lake, about five kilometres away. In submissions to the Environmental Assessment Office, area residents have raised concerns about the landfill’s potential impact on water, air quality, and property values. The B.C. Oil and Gas Commission highlighted the issue of proper garbage disposal earlier this year when it sent out a bulletin to oil and gas operators after being alerted that contaminated truck liners were being dumped in municipal landfills.
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29
2010
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Northwestern Alberta/Foothills
Photo: Orleans Energy Ltd.
Orleans completes two Montney gas wells on western Kaybob lands
Orleans Energy Ltd. has developed a large resource-style drilling inventory on its Kaybob lands.
Orleans Energy Ltd. has drilled and completed two (1.75 net working interest) horizontal Montney natural gas wells on its western Kaybob land block. The first well, a 100 per cent working interest well at 4-1560-19W5, was completed with multi-stage fracture technology as an 11-stage fracture stimulation with an aggregate 198 tons of proppant sand displaced along the 1,343metre horizontal leg. The 4-15 well recently flowed liquidsrich gas over an 89-hour extended flow test period at a final gross raw test rate of 5.6 million cubic feet per day or 933 barrels of oil equivalent (boe) per day, with a flowing well head tubing pressure of 1,450 pounds per square inch. The well was brought on stream on Nov. 21, 2009, and is currently producing at a similar “flush” rate to its final flow test rate. The second Kaybob well (75 per cent working interest) was completed and
stimulated with an 11-interval hydraulic fracture encompassing 209 total tons of proppant sand displaced along the 1,144metre horizontal leg. The well recently flowed gas over a 69-hour extended flow test period at a final gross raw test rate of approximately 5.5 million cubic feet per day, or 917 boe per day (687 boe per day net working interest), with a flowing wellhead tubing pressure of 1,420 pounds per square inch. The well is currently shut in for downhole pressure testing The company anticipated that this well would be tied in by mid-December. These two Kaybob wells represent the initial successful application of horizontal drilling and multi-stage completion techniques on those respective sections of land, which Orleans said validates the repeatable, scalable nature of its Triassic Montney natural gas resource play at Kaybob.
The company has regulatory approval to drill up to five horizontal wells per section across 25 (22.5 net working interest) of its 28 gross sections of land in Kaybob, creating a drilling inventory of up to 100 horizontal locations. Since beginning horizontal drilling in October 2007, Orleans has drilled a total of 16 (14.1 net working interest) Montney horizontal wells at Kaybob, with a success rate of 94 per cent. At Waskahigan, to the northwest of Kaybob in west-central Alberta, the company intended to commence field operations and spud a 100 per cent working interest Montney horizontal test (12-1763-23W5) on one of its 18 sections of contiguous land. The 12-17 well is programmed to be drilled with a total measured depth of 3,667 metres. Orleans has used its technical and geological experience garnered with its Kaybob Montney development success to assist in identifying and growing its Montney-prospective land base in the Waskahigan area. Pending exploration success, the Waskahigan area is expected to complement and significantly expand Orleans’ large drilling inventory. As a result of the flow-though share equity financing, which closed Nov. 12, the company increased its 2009 total capital expenditures budget to approximately $44 million. The revised capital program encompasses the drilling of a total of four (3.75 net) horizontal Montney wells at Kaybob and two horizontal wells involving its new Montney exploration prospect at Waskahigan. Despite the previously disclosed disposition of Orleans’ non-core Medicine River property the company’s year-end 2009 exit production rate target is projected to remain unchanged at approximately 4,600 boe per day, assuming the second Kaybob well is brought on stream by year-end as planned. — DAILY OIL BULLETIN
NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY
NOV/08
NOV/09
WELL LICENCES
296
276
▼
NOV/08
NOV/09
WELLS SPUDDED
220
213
▼
NOV/08
NOV/09
WELLS DRILLED
224
169
▼
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • January 2010
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January 2010 • OIL & GAS INQUIRER
Northeastern Alberta
Suncor restarts third and fourth stages of its Firebag SAGD project
Photo: Suncor Energy Inc.
by Lynda Harrison
Suncor CEO Rick George says its Firebag launch plan "officially restarts growth in the oilsands."
Fuelled with a capital budget of $5.5 billion for 2010, Suncor Energy Inc. is going ahead with Voyageur’s Firebag Stages 3 and 4 in situ project expansions this year, but its proposed Voyageur upgrader and Fort Hills mining project will remain on the shelf. “This actually officially restarts the growth in oilsands,” said Rick George, Suncor’s president and CEO, during a conference call on Nov. 13. The planned investment level for 2010 is below the budgets set by Suncor and Petro-Canada (before the merger) for 2009. The two companies had originally announced plans to spend over $9 billion in 2009, but that was reduced to $6.4 billion due to low commodity prices. George estimated Suncor and Petro-Canada would have spent a total of $8 billion in 2010 if they had remained separate. The majority of growth spending in 2010 will be directed toward the Firebag Stage 3,
which was about half complete before being deferred in early 2009. Suncor now expects the project to begin production in the second quarter of 2011, with volumes ramping up toward design capacity of approximately 68,000 barrels per day of bitumen. Spending on Firebag Stage 4, also with design capacity of 68,000 barrels per day, will support a target of first bitumen production in the fourth quarter of 2012. Suncor expects oilsands growth to generate a 15 per cent return with a West Texas Intermediate crude oil price of US$70, and the company plans to continue spending about $6 billion over the next two years, said George. It expects to exit 2010 with oilsands production of 350,000 barrels of oil per day and that oilsands output will increase at a rate of 10 to 12 per cent per year up to 2020. Captial spending plans for 2010 include growth capital of $900 million
on Firebag stage three, $50 million on Firebag Stage 4, $100 million on the Millennium naphtha unit, $390 million on international and East Coast Canada, and $60 million on other, totalling $1.5 billion. Sustaining capital spending will consist of about $750 million on oilsands base maintenance, $450 million on in situ maintenance (Firebag and McKay River), $200 million on its 12 per cent interest in Syncrude Canada Ltd., $360 million on a 40-day turnaround at Upgrader 2, $450 million on tailings reduction operations, $750 million on International and East Coast Canada, $250 million on natural gas, $670 million on refining and marketing, and $170 million on other for a total of just over $4 billion. George estimated the natural gas spending is far below what the separate companies would have spent. “While we’ve seen some improvement in crude oil prices and the overall economy, we believe that a conservative capital strategy remains the best approach for Suncor,” George stated. “We’re looking at a level of capital investment that is supportable entirely from free cash flow at midcycle crude oil prices.” That spending includes about $550 million to sustain production on the East Coast and North Sea and a little more than $300 million on growth in Syria and Libya, all of which were acquired in the Petro-Canada deal. Near-term differentials do not support the Voyageur upgrader, but George expects it will be “a great option for us down the road at some point,” he said. Suncor has spent $3 billion to date on the Voyageur upgrader. George told analysts it can be shelved for two or three years. It would consider taking on a partner for the project, which would take two and a half years to construct. — DAILY OIL BULLETIN
NORTHEASTERN ALBERTA WELL ACTIVITY
NOV/08
NOV/09
WELL LICENCES
95
114
▲
NOV/08
NOV/09
WELLS SPUDDED
78
85
▲
NOV/08
NOV/09
WELLS DRILLED
69
85
▲
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • January 2010
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January 2010 • OIL & GAS INQUIRER
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Alberta government pledges $495M for CO2 pipeline project
Photo: Enhance Energy Inc.
by Paul Wells
Energy Minister Mel Knight (left) and Premier Ed Stelmach with Enhance Energy president Susan Cole.
The Alberta government moved its carbon capture and storage (CCS) game plan forward in awarding $495 million in funding for the $600-million Alberta Carbon Trunk Line (ACTL). Beyond its capital budget, the pipeline’s operating cost is estimated at about $200 million over 10 years. On Nov. 24, the province announced that it has signed a letter of intent with En ha nce Energ y Inc. T he pipeline operator is partnering with North West Upgrading Inc. to build the 240-kilometre trunk line. CO2 will be piped from North West’s proposed new upgrader northeast of Edmonton to depleted oilfields near Clive, in central Alberta, where it will be used for enhanced oil recovery (EOR). The province’s portion of the funding, which will be paid over 15 years, is coming from its $2-billion carbon capture technology fund. The federal government is contributing $63 million towards the pipeline.
The full project also includes an additional $350 million in capital costs for CO2 capture by North West. “Upon completion, it will be the first pipeline in the province that will capture large volumes of carbon dioxide from
Construction of the pipeline is scheduled to start in 2011 and be in operation in 2012, initially transporting 5,100 tonnes per day of compressed CO2. The pipeline is expected to take 15 to 20 years to reach full capacity and at its peak will be capable of carrying up to 40,000 tonnes of CO2 per day. The initial supplies of CO2 will come from the Agrium Redwater fertilizer complex and, once it’s built, from the North West Upgrader in the Industrial Heartland near Fort Saskatchewan. A number of other refineries, upgraders, and chemical plants in the area could eventually access the pipeline, said Stelmach. “This new pipeline will significantly advance Alberta’s capacity for future carbon capture and storage projects,” the premier said. “The Alberta Carbon Trunk Line will be the backbone of CO2 transportation for Alberta. It will be built with long-term capacity in mind, so as more companies capture CO2, they will be able connect to the line.” In the future, Enhance foresees lateral lines running off the trunk line to other fields, and CO2 collection lines extended to both Fort McMurray and the coalfired power plants near Lake Wabamun. Stelmach noted that the oil produced via
" ...it will be the first pipeline in the province that will capture large volumes of carbon dioxide from one area and transport it to another." - Ed Stelmach, Premier, Alberta
one area and transport it to another,” Alberta Premier Ed Stelmach said in a conference call. “Once complete and operating at full capacity, the Alberta Carbon Trunk Line project will be able to store 14.6 million tonnes of CO2 per year. That’s equivalent to removing approximately 2.6 million cars from the road. And it will make this the largest CCS project in the world.”
EOR will be subject to royalties and taxes to both the province and freehold landowners over the life of the project. “It’s good news for the economy. Every barrel recovered using CCS means more revenues for Alberta, and that means more money in the provincial coffers for things like health care, education, and other programs and services,” Stelmach said. Enhance president Susan Cole added:
NOV/08
NOV/09
NOV/08
NOV/09
WELLS SPUDDED
320
255
WELLS DRILLED
332
251
CENTRAL ALBERTA WELL ACTIVITY
NOV/08
NOV/09
WELL LICENCES
368
229
▼
▼
▼
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • January 2010
35
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“Alberta will lead the world in CO2 management. The system will access one billion barrels of new oil production that will in turn generate $15 billion of royalties to the province.” Cole estimated that the price tag to build the pipeline would be about $600 million, with another $200 million for operating costs. She said the project is currently under regulatory review and unopposed by all 400 landowners along the proposed route. Just as the Alberta Gas Trunk Line built in the 1950s formed the backbone for a network of a natural gas collection lines that laid the foundation of a large and profitable gas export and petrochemical industry, the carbon trunk line is expected to perform a similar role for CCS in Alberta, said Cole. “It’s a CO2 distribution system that can collect CO2 and move it to mature oilfields and reservoirs that have the potential for
The combined $558 million in provincial and federal funding for the project means a vast chunk of the anticipated $600 million in construction costs will be covered and that the province’s contribution as a percentage of overall project costs exceeds that of two other CCS projects that were previously awarded funding under the provincial CCS program. Energy Minister Mel Knight admitted as much but said the backbone pipeline is essential if Alberta is to move forward and meet its goal of reducing greenhouse gas emissions by 200 megatonnes by 2050, of which 70 per cent of the reductions are expected to come from CCS. “This was not out of scope with the rest of things that we are doing. If you look at the federal involvement, we have on this one a bit higher content from the
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January 2010 • OIL & GAS INQUIRER
more oil recovery through CO2 flooding,” she said. “At full capacity, this is a 14.6 million tonnes of CO2 per year. There are only four other projects in the world that move anything greater than one million tonnes per year.” The pipeline will advance a joint Fairborne Energy Ltd. and Enhance CO2 flood project at Fairborne’s Clive field in central Alberta. Enhance will operate the pipeline and capture facilities. Fairborne will operate the EOR project at Clive, an oilfield that was discovered in the early 1950s and which has produced 70 million barrels of light oil to date from an estimated 166 million barrels of discovered petroleum initially in place. “The project is being designed to recover additional light oil from Nisku and Leduc reservoirs through CO2 injection and extend the producing life of the Clive field by up to another 20 years,” Fairborne said in a press release. “Internally evaluated best estimate of Fairborne’s working interest contingent resources associated with the CO2 flood is 24 million barrels of oil. Subject to the terms and conditions of a previously announced agreement with Enhance that includes payment of earning capital, Fairborne will retain 60 per cent of its current working interest and contingent resources.”
point of view of provincial money, but it is reasonable,” Knight said. “We think that what we’re on the verge of here is absolute global scale. When these projects open… this will put Alberta in the forefront with respect to this [CCS] technology.” In early 2009, the Canadian and Alberta governments announced their intent to award $865 million in funding for a carbon capture project at a Royal Dutch Shell PLC refinery near Edmonton. The Shell Quest project will capture and store 1.2 million tonnes of CO2 annually beginning in 2015 from Shell’s Scotford upgrader and expansion, near Fort Saskatchewan. The governments also pledged $774 million in funding for a similar system at a power-generation plant owned by TransAlta Corporation when a letter of intent was signed with TransAlta and its partners for Project Pioneer at the Keephills 3 plant west of Edmonton. The project will use leading-edge technology to capture CO2 , which will be used for EOR in nearby conventional oifields, or stored almost three kilometres underground. The project is expected to capture one million tonnes of CO2 annually beginning in 2015. — DAILY OIL BULLETIN
Central Alberta
Imperial signs oilsands service agreement with Keyera Keyera Facilities Income Fund has entered into a long-term agreement with Imperial Oil Resources Ventures Limited to provide diluent transportation, storage, and rail offload services in the Edmonton/Fort Saskatchewan area for Imperial’s Kearl oilsands project. This agreement will reportedly provide Keyera with secure, long-term, feefor-service revenues, beginning in late 2012, as well as the potential to generate significant incremental new business opportunities. Imperial will pay a perbarrel fee for the rail offload service. Under the terms of the agreement, Keyera will transport diluent by pipeline from supply sources in the Edmonton area to a diluent delivery pipeline north of Fort Saskatchewan for delivery to the Kearl site near Fort McMurray. Keyera will also provide diluent storage and rail offload services at its fully owned Alberta Diluent Terminal and the Edmonton Terminal, as well as at the Fort Saskatchewan Fractionation and Storage Facility it operates. Upon start-up of the 110,000 barrel per day first phase of the Kearl project, Keyera anticipates that operating cash flow from the agreement will initially be in the range of $10 million to $11 million annually,
growing to approximately $16 million as the second and third phases of the Kearl project come on stream. Under the agreement, Imperial will be provided with transport capacity within existing and new-build pipeline infrastructure to match its expected diluent requirements for its Kearl development. The transportation portion of the agreement has an initial term of 25 years. Keyera plans to invest $58 million to construct an 18-kilometre extension to the Fort Saskatchewan pipeline system north from the Fort Saskatchewan Fractionation and Storage Facility, a new pump station at the Edmonton Terminal, and a short pipeline connection to increase diluent supply into Keyera’s Edmonton Terminal. Imperial will pay an annual capital payment based on a portion of the new capital investment relating to its capacity commitment. In addition, Imperial will pay a per-barrel tariff for volumes it ships on the existing Fort Saskatchewan pipeline system. The capacity of the new facilities will exceed Imperial’s Kearl requirements and Keyera can use the remaining capacity to provide similar services to other oilsands customers.
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AJM urges Alberta gas royalty reforms AJM Petroleum Consultants warns that, without some decisive and proactive interventions to encourage natural gas production in Alberta, the potential for negative impact on the province’s economy is very real. Dave Russum, AJM’s VP of geoscience, points to specific conditions in Alberta—other than the current decline in the natural gas price—that may be accentuating Alberta’s drop in production. “Reduced production during a time of low gas prices is understandable,” says Russum. “But there’s been a general downward trend for more than ten years, regardless of price and number of wells drilled. And in each of the last two years, Alberta has been shedding production at an alarming rate of greater than 1 Bcf [billion cubic feet] per day. Current production is about 3.3 Bcf a
day, or 20 per cent below the peak production levels of the late 1990s.” Even if natural gas prices do climb, Russum says Alberta producers would then be hit with higher royalties as determined by changes to Alberta’s Royalty Program. Furthermore, while unconventional gas is showing promise in other jurisdictions, the dispersed nature of Alberta’s unconventional gas deposits and difficulties with extraction make Alberta plays less attractive than those promoted in other parts of the world. “Natural gas has been the strength of the Alberta economy for more than 30 years,” Russum says. We need to reassess natural gas royalties to ref lect the maturity of Alberta’s natural gas industry and the real costs and rewards of doing business here.”
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Ensign says over-capacity continues to impede profitability
Ensign expects its service rig fleet to achieve more than 40 per cent utlization this winter.
Ensign Energy Services is forecasting peak Canadian drilling rig utilization of between 50 and 60 per cent this winter, but the drilling contractor doesn’t expect much of an improvement in margins. “Competitors with interest payments to make are still bidding as price takers into the winter market,” Bob Geddes, president and COO, said in a conference call. The over-capacity is generally more pronounced in Canada than in the United States, where Ensign currently operates 80 drilling rigs and 18 service rigs, according to Geddes. In 1980, there were 5,000 drilling rigs in the United States, but today there are 2,000, he said. In contrast, “there were 500 rigs in Canada and now there are 880 and we are drilling wells two to three times faster.” Ensign’s 150 Canadian rigs account for just over 40 per cent of its total fleet of 350 rigs. The Calgary-based company
reported net earnings of $16.9 million for the third quarter of 2009, down 77 per cent from the same period in 2008. “The fundamental challenge still plaguing the Western Canadian Sedimentary Basin is too many rigs,” said Geddes. There currently are 880 drilling rigs in Canada capable of drilling close to 40,000 wellbores, said the Ensign COO. “With the peak in the 23,000 range a couple of years back and with the 2009 forecast at 9,000 wells, there is an overcapacity issue that must be rationalized for profitability to come back to the sector,” he cautioned. Geddes said there appears to be a reasonable market for higher technology drilling rigs geared towards unconventional plays. “The challenge is on the equity between what they are willing to pay and what you are willing to build it for,” he said. “Some operators get that….
Some won’t pay that differential, so that slows down the market a little bit.” Ensign operates a fleet of about 100 service rigs. Its customer base in heavy oil plays are keeping those units busy, but pricing has reportedly come under pressure. About 40 per cent of the Ensign fleet is currently in operation with some upturn expected this winter. In the third quarter of 2009, the company purchased 25 relatively new wireline units in Canada at “very attractive prices,” increasing the capacity of its fleet by about one-third, said Geddes. Ensign thinks it likely has the lowest cost operation of any its competitors now, as it has centralized many of its administrative duties. Although Ensign operates a welltesting business in both Canada and the United States, most of the business now is coming out of the U.S. Rockies and most recently the Marcellus shale in the eastern United States. The company sees growing opportunity for the 30 test units in the United States on top of the 50 test units it runs in Canada. Although margins are compressed, Geddes said, “we see no further pricing degradation at this time and somewhat a levelling off of business there.” In the United States, Ensign currently operates 80 drilling and 18 service rigs in the Rockies and California with utilization in the 50 per cent range, and “we appear to have the worst behind us,” Geddes said. In the oil-focused California market, activity has remained relatively steady, although pricing came under pressure over the summer. The company added three new proprietary automated drilling rigs on longterm contracts in the U.S. market in the third quarter. “Operators are willing to pay for the technology, which brings net well costs down,” said Geddes. — DAILY OIL BULLETIN
SOUTHERN ALBERTA WELL ACTIVITY
NOV/08
NOV/09
WELL LICENCES
459
395
▼
NOV/08
NOV/09
WELLS SPUDDED
599
239
▼
NOV/08
NOV/09
WELLS DRILLED
591
233
▼
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • January 2010
39
Southern Alberta
CIBC analyst expects better industry conditions in 2010 doing the last six months. Since the beginning of July, we’ve seen Canadian-based E&P companies raise over $8 billion in debt and equity capital,” he said. Fetterly said that in the near term, the majority of that capital will be allocated to debt reduction, debt retirement, and merger and acquisition opportunities, but “ultimately, we believe the E&P community is positioning to increase spending in 2010. “Fundamentally, what we see in the natural gas markets today supports a gas price of an average of about $6 [per thousand cubic feet at AECO] and a price that moves from the fives to the upper sixes over the course of 2010,” he said. Based on CIBC’s $6 per thousand cubic feet AECO natural gas forecast for 2010 and an average West Texas Intermediate crude price of $80 per barrel, Fetterly said CIBC is projecting capital spending to increase by about $10 billion in 2010 to $38.6 billion from estimated full-year 2009 spending of about $28.1 billion. CIBC is also forecasting the 2010 average active rig count will be 294 in a fleet size of 831 for an average utilization rate of 35.5 per cent, compared to an estimated
average active drilling rig count of 204 in a fleet of 826 and an average utilization rate of 23.9 per cent in 2009. Service rig activity will see a 43.9 per cent utilization rate from a fleet of 486 rigs in 2010, compared to 38.6 per cent and 428 respectively in 2009. — DAILY OIL BULLETIN Photo: Brian Zinchuk, Pipeline News
Spea k i ng at a Pet roleu m Ser v ices Association of Canada (PSAC) event on Nov. 5, 2009, an oilfield services analyst with CIBC World Markets Inc. said recent increases in drilling activity in the Western Canadian Sedimentary Basin should continue. Jeff Fetterly told the PSAC audience that the industry downturn may have bottomed out and a rebound is in the offing, albeit at a modest pace. “Ultimately, we believe the rig count improves from an average of less than 200 in the third quarter [of 2009] to about 250 in the fourth quarter to a little bit north of 300 in the [first quarter of 2010],” the analyst predicted. “It’s certainly very modest expectations from a historical context, but we believe the industry is starting to show some signs of momentum coming out of this downturn.” Fetterly noted that with debt and equity markets beginning to open up again, exploration and production companies are gearing up to increase capital spending in 2010, which is obviously positive news for the service sector. “The truly encouraging sign is what the E&P [exploration and production] community has been
CIBC estimates average drilling rig utilization rate at 35.5 per cent for 2010.
LE B I X E E FL B O T l l a a S t t i s o Y n n i A . . P . r I T e , quick s e c i r er p w o L
40
January 2010 • OIL & GAS INQUIRER
.
Southern Alberta
Cenovus plans to sell $1B worth of non-core assets Cenovus Energy Inc. hopes to sell about $1 billion worth of natural gas and noncore crude assets in the next two years, including $500 million in 2010, a conference call heard on Nov. 12, 2009. “We are going to be targeting about $1 billion in divestiture proceeds over the next two years,” said Brian Ferguson, designated president of Cenovus. Ferguson hopes that half of that amount will be sold during 2010. Cenovus is the spinoff of EnCana’s integrated oil business, including thermal oil and its 50 per cent upgrading/refining joint venture in the United States. The EnCana split was completed on Nov. 30. On the spending side, Ferguson said Cenovus has identified unspecified shortterm oil opportunities in the range of $50 million to $150 million. He said that the capital allocation will depend on free cash flow, which will significantly increase after the massive Wood River refinery expansion in Illinois is completed. “We intend to emphasize the oil opportunities inside Cenovus’s portfolio, and expect over the next three to five years [to be] two-thirds to three-quarters
oil-weighted,” Ferguson said. Cenovus will continue to be an oil-focused company, but Ferguson said it will retain enough of EnCana’s shallow gas assets to provide a price hedge for gas consumed at Cenovus’s thermal oil projects and refineries. Ferguson expects gas will always be a secondary business for Cenovus. “I certainly do not think of our growth opportunities other than those focused on our oil.” But he added that the shallow gas assets generate a tremendous amount of free cash flow. Cenovus will be a major gas consumer as well as a producer. At current bitumen production rates, the company’s refineries and steam assisted gravity drainage (SAGD) operations at Foster Creek/Christina Lake now consume about 100 million cubic feet per day of gas. As SAGD production expands, gas consumption is expected to grow to the 200 million to 250 million cubic feet per day range, Ferguson said. Before royalties are deducted, Foster Creek SAGD production is currently close to 100,000 barrels per day, while Christina Lake is around 15,000 barrels per day, said EnCana executive VP John Brannan. The
company expects the two projects to operate at about 93 per cent of capacity in 2010. “Our capacity at Foster Creek will be 120,000 barrels [per day], but we won’t reach that capacity until we have some patterns on blowdown,” Brannan said. He expects Foster Creek will enter 2010 with total productive capacity of roughly 95,000 to 100,000 barrels per day and to exit the year at about 106,000 to 110,000 barrels per day. Under Alberta’s royalty regime for projects in the province’s designated oilsands regions, Foster Creek is paying a favourable rate because capital costs haven’t yet been recouped. “Currently, before payout, at $65 oil, we’re paying about 2.2 per cent royalties on a gross basis,” Brannan said. (Half of Foster Creek/Christina Lake production is net to EnCana/Cenovus. Downstream partner ConocoPhillips owns the other half.) After payout—and at $65 oil—the royalty rate would skyrocket to 27.3 per cent on a net basis, Ferguson said. At current production rates and oil prices, Foster Creek could reach project payout by June 1. — DAILY OIL BULLETIN
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Crescent Point continues its acquisition binge with TriAxon deal
Crescent Point will apply its Saskatchewan Bakken expertise to the emerging Viking light oil play.
Crescent Point Energy Corp., which had already spent close to $1 billion on acquisitions in 2009, announced on Nov. 9 a further $250-million acquisition. The Calgary-based producer is buying TriAxon Resources Ltd., which holds oil-prone assets in Saskatchewan’s Viking and Bakken formations as well as the Pembina Cardium field in central Alberta. Crescent Point will acquire all of the issued and outstanding shares of TriAxon for consideration of 0.18 of a Crescent Point share for each TriAxon share plus the assumption of approximately $17.3 million of TriAxon net debt. TriAxon’s assets include more than 148 net sections of undeveloped land, including 63 net sections in the Viking light oil resource play in the Plato area of westcentral Saskatchewan. TriAxon also operates the Flat Lake Bakken play in which Crescent Point currently holds a working interest.
TriAxon is currently producing approximately 1,400 barrels of oil equivalent (boe) per day, of which approximately 130 boe per day and 170 boe per day are from the Viking resource play and the Flat Lake Bakken play, respectively, and 1,100 boe a day is from Alberta, which includes 560 boe per day from the Pembina Cardium play. In the second half of 2009, TriAxon successfully drilled two step-out exploration horizontal wells, one currently on production and one awaiting completion, which significantly increase Crescent Point’s estimates of the size of the Flat Lake Bakken pool. Crescent Point believes that this drilling success, combined with TriAxon’s large undeveloped Viking land base, provides the potential for significant production and reserves growth from these two plays. “Over the past few years, TriAxon has aggressively pursued high-quality plays with significant recovery factor upside,” said Scott
Saxberg, president and CEO of Crescent Point. “They have established leading positions in the Viking and Flat Lake Bakken plays in Saskatchewan. These assets complement Crescent Point’s existing Bakken assets very well and provide us with the opportunity to lever our tight oil expertise into a large land base in the emerging Viking tight oil play.” “Crescent Point shares our strategy of balanced growth through the combination of technology and large resource in place assets,” said Jeff Saponja, president and CEO of TriAxon. “ The boards of directors of Crescent Point and TriAxon both unanimously approved the arrangement.” The acquisition will bring net tax pools of $99 million to Crescent Point. Reserves being acquired are estimated at 12.4 million boe, proved-plus-probable, and 7.8 million proved, according to a Sproule Associates Limited evaluation as of June 30, 2009. Excluding undeveloped land value of $49 million, the estimated acquisition metrics are $142,643 per producing boe and $16.10 per boe of proved-plus-probable reserves ($25.60 per proved boe). Acquisitions and steady drilling in the Bakken and Lower Shaunavon boosted Crescent Point’s production in the third quarter to 46,322 boe, including 40,854 barrels of crude and natural gas liquids. Third-quarter revenue plunged to $45.4 million from $497.8 million for the same period in 2008. Crescent Point drilled 69 (48 net) oil wells and 2 (1 net) service wells in the third quarter of 2009, with a 100 per cent success rate. The figures include 46 (31 net) Bakken horizontal wells and 7 (4 net) Lower Shaunavon horizontal wells. The company also fracture stimulated 53 (43 net) Bakken horizontal wells. In August, Crescent Point spent $225 million to buy the Saskatchewan assets of Provident Energy Trust plus another $665 million to acquire Wave Energy Ltd. — DAILY OIL BULLETIN
SASKATCHEWAN WELL ACTIVITY
NOV/08
NOV/09
WELL LICENCES
349
256
▲
NOV/08
NOV/09
WELLS SPUDDED
356
216
▲
NOV/08
NOV/09
WELLS DRILLED
390
230
▲
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • January 2010
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January 2010 • OIL & GAS INQUIRER
11/13/2009 9:36:31 AM
Northern Frontier
Greenland’s retreating ice fuels dreams of hidden resource wealth
Greenland has iron, zinc, and other mineable mineral deposits, but its richest potential is petroleum.
Greenland’s frozen world is thawing along the edges, potentially exposing riches. The retreating ice could uncover potential oil and minerals, which, if successfully tapped, could dramatically change the fortunes of this semi-autonomous Danish territory of 57,000 people. The U.S. Geological Survey estimates there are more than 18 billion barrels of oil and gas beneath the Arctic waters between Greenland and Canada, and 31 billion barrels off Greenland’s east coast. “If we find those kind of quantities of oil and gas and the prices remain at current levels, then Greenland would be a very wealthy country, no doubt,” said Joern Skov Nielsen, the director of Greenland’s Bureau of Minerals and Petroleum. Finding hydrocarbons would be crucial to help Greenlanders realize their long-held dream of cutting the annual 3.4 billion kroner (US$680 million) subsidy from former colonial power Denmark that currently rules out full independence. Under a self-rule agreement that took effect in 2008, Greenland will use any revenue from oil and minerals to slash its annual grant from Denmark,
which currently accounts for one-third of its economy. Admittedly, it all still amounts to a big “if.” To date, no oil has been found in Greenlandic waters. Even if discoveries are made in new areas under exploration, the most optimistic estimates say commercial production is at least 10 to 15 years away because of the long time-scale involved when developing offshore oil and gas fields. Even so, local decision makers are getting prepared. Last year, the Greenland parliament approved the creation of a sovereign wealth fund similar to that which Norway uses for its surplus oil income. Any payoff from minerals would be smaller, but more immediate. The giant island is believed to be rich in base metals such as zinc and iron, precious stones like diamonds and rubies, and precious metals like gold and platinum. It’s also a potential hot spot for rare earth minerals used in electronic gadgets including cellphones and flat-screen TVs. The problem is 80 per cent of the island is covered by an ice sheet that is up to three kilometres thick, which means exploration is only possible in coastal
regions. Even there, conditions are far from ideal due to the long winter with frozen ports, 24-hour darkness, and temperatures regularly dropping below -30°C in the northern parts. However, as the climate slowly warms, more of Greenland is opening up for exploration. Nielsen said the retreat of Greenland’s massive inland ice sheet has uncovered new deposits of iron on the west coast near the capital, Nuuk. In northern Greenland, Britain’s Angel Mining PLC said a new deposit of zinc has been laid bare by a retreating glacier. The company plans to reopen an abandoned zinc mine in the area, and eventually link it to the new deposit, CEO Nick Hall said. Climate change has been “helpful rather than unhelpful” to miners in Greenland, he said, but added that the main stimulus for the mining activity “is that the world is hungry for resources.” Angel Mining already operates a gold mine in the south. An olivine mine just north of Nuuk also has started production. Many more are expected soon. The number of mineral exploration licences issued by Greenland’s local government surged from 17 in 2002 to 72 this year. Officials offer basic courses in geology to amateur mineral hunters, and started a more advanced mining education in Sisimiut in western Greenland in 2008. The goal is to prepare Greenland’s labour force for jobs in the mining industry. The only large-scale industry now on the island is fishing, which accounts for about 90 per cent of ex por t s. “Greenlanders are hunters and fishermen,” said Finn Ly nge, a retired Greenlandic diplomat. He said the mining and oil industries require job skills “for which Greenlanders are not apt at all.” He noted plans by Alcoa Inc. to build an aluminum smelter and two hydroelectric plants to power it in Maniitsoq, southwestern Greenland. Project leaders say the 600 workers needed for the construction phase would have to be recruited from Europe or China because Greenland doesn’t have that kind of labour. — ASSOCIATED PRESS OIL & GAS INQUIRER • January 2010
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January 2010 • OIL & GAS INQUIRER
Central Canada
CSA unveils North America’s first pipeline security standard by Paul Wells
The Canadian Standards Association developed its guidelines in response to terrorist attacks.
On Nov. 25, CSA Standards unveiled North America’s first oil and gas pipeline security standard to help prevent acts of vandalism and sabotage the continent’s sprawling transportation networks. The document developed by the Canadian Standards Association (CSA) is expected to be embraced enthusiastically by the pipeline sector. The new guidelines are not a knee-jerk reaction to recent bombings in northeastern British Columbia, according to the non-profit association. Rather, the initiative is a work in progress, established in 2005 partly in response to the 2001 terrorist attacks on the United States. “This standard is to help maintain the security of North American energy supply systems as well as provide worker safety. Attacks on pipelines and oil and gas facilities in western Canada underscore why this standard is a necessity. In just over a year, there have been six bomb attacks in the northern B.C. region alone,” CSA president Suzanne Kiraly said at a news conference at SAIT Polytechnic. “While not all security risks can be completely prevented, this standard provides a means of identifying, analyzing, and reducing risks through the security
risk management process, and it will help mitigate these risks,” Kiraly said. Ontario-based CSA Standards is a division of CSA Group, which also includes CSA International and OnSpeX, a provider of consumer product evaluation, inspection, and advisory services for retailers and manufacturers. Brenda Kenny, president of t he Canadian Energy Pipeline Association (CEPA) agreed. “[The] recent attacks on pipelines and facilities in and around the Dawson Creek area certainly demonstrate the need to implement consistent guidelines and to absolutely ensure the safety of local communities,” she said. The development of the standard was initiated by a 2005 amendment to the National Energy Board Act to include “securit y ” within the board’s mandate. The National Energy Board (NEB) approached CSA to develop a consensusbased standard that would outline the minimum expected requirements of a security management program. Kenny expects the majority of CEPA members to adhere to the new standards. “Attention to security, particularly post 9-11, is absolutely a fact of life we have
to live with,” she said. “It can ultimately help to save money and, while some companies may have an additional cost as they upgrade their management systems, in the long run it will be of great benefit.” Kiraly wouldn’t speculate what adopting and implementing the standards might cost. “I think it’s hard to put a dollar figure on it. Companies already have systems in place and the amount of work a company would do would be dependent on the size,” she said. “I think one of the concepts that’s important to remember is the implementation can actually save money,” the CSA president commented. “Instead of looking and doing their own research and relying on a number of consultants, this really provides them with a blueprint for a security system from start to finish that they can rely on and build on what they have already.” In order to help petroleum and natural gas companies evaluate and respond appropriately to security threats, CSA Standards has worked with security and industry professionals to prepare the standard, CSA Z246.1 Security Management for Petroleum and Natural Gas Industry System. Gaétan Caron, NEB chair, said the standard uses a risk management and performance-based approach to help identify and reduce threats to oil and gas industry assets. “The world we’re living in is changing; we all know that. Sometimes security events are inadvertent and sometimes they are deliberate,” he said. Caron said the standard assists in enabling pipeline owners and operators to establish governance, conduct planning, implement security operations (including detection and mitigation practices), and refine the security program through change management and audit processes. The standard applies to land-based pipeline systems for oil and gas, as well as liquefied gas production, storage and handling facilities, underground hydrocarbons storage, petrochemical installations, oil and gas treatment, production processing, storage operations, and related assets. — DAILY OIL BULLETIN OIL & GAS INQUIRER • January 2010
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Enerplus plans to invest $100M in Marcellus shale play Vast gets ready to drill in Kurdistan
Enerplus plans to participate in more early-stage growth resource plays like the American shales.
Pennsylvania’s Marcellus shale gas play will be a focus for Enerplus Resources Fund in 2010, the Calgary-based trust’s president and CEO said in a conference on Nov. 16. “We believe this asset will provide tremendous growth potential for Enerplus,” Gordon Kerr told analysts, describing the emerging play as one of the best in North America. Last summer, the trust acquired an average 21.5 per cent working interest in 116,000 net acres in the Marcellus shale region of the northeastern United States, mainly Pennsylvania. The US$411-million purchase from Chief Oil & Gas LLC gives the trust a solid position in the play, close to northeastern U.S. gas markets. Kerr estimated the Pennsylvania lands contain about 1.4 trillion cubic feet of bestestimate, contingent natural gas resources (net to Enerplus), and could add about 100 million cubic feet per day in the next few years. “This [asset] would almost double our 2P gas reserves currently booked,” he said, noting that over 2,400 drilling locations have been identified so far. While the trust plans to put more than $800 million into the Marcellus over the
next five years, the near-term would see about $40 million invested in the play by year-end 2009. Kerr estimated Enerplus could sink US$100 million or more into the play. During 2010, the trust plans to focus on oil projects on its Bakken lands and waterflood assets, while limiting gas activities mainly to the Marcellus and where it can benefit from the Alberta Drilling Royalty Credit (DRC) incentive. As the trust participates in more early-stage growth plays, it expects to increase its land and seismic expenditures in key areas. Enerplus is still active in shallow-gas resource play, but due to weak gas prices, it drilled only 12 wells in the third quarter, completing its Shackleton, Sask., program for the year. The trust has chosen not to tie in the wells until gas prices recover. However, it started drilling the first 9 of about 250 shallow gas wells in Alberta to take advantage of the province’s DRC incentive. The trust plans to use the DRC program primarily at Verger, Bantry, Hanna Ga rden, a nd P r i ncess Spec ia l A rea No. 2, Alta. — DAILY OIL BULLETIN
Vast Exploration Inc. plans to drill its first exploratory well on the Qara Dagh block in the Kurdistan region of Iraq in the first quarter of 2010. The consortium has completed the acquisition of 355 kilometres of a 2-D seismic program over the surface structure that dominates the block. The seismic data was subsequently processed, interpreted, and integrated with surface and regional geologic models. Three main prospects were identified along the Qara Dagh structure as three subsurface culminations that extend across multiple horizons. The primary prospective reservoirs have been identified as the main carbonate sequences in the Cretaceous as well as underlying Jurassic and Triassic sections. Based on the seismic data, three well locations were also identified. The central feature, the Qara Dagh dome, being the largest structure was selected for the drilling of the first exploratory well. It is planned that this well will be drilled to a depth of 4,000 metres and could encounter up to eight potential reservoirs. The first exploratory well is anticipated to be spudded in the first quarter of 2010. An invitation to tender has been issued to 12 drilling contractors. After technical and commercial evaluation, a company with existing operations in the region was selected to mobilize a 2,000-horsepower rig to the block for drilling of one firm well and three optional wells. Contracts for long-lead items have been awarded and wellsite construction is underway. Additionally, contracts for drilling support services have been tendered, evaluated, and finalized with various service companies operating in the region. The consortium is in the process of obtaining an independent 51 to 101 prospective resource estimate for the Qara Dagh block, which is expected to be completed in December. OIL & GAS INQUIRER • January 2010
49
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TATE
ZEUES
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Directions from Estevan Hwy 39 – 1 mile North or 1½ miles East of Estevan
MCMULLEN
SUNSET
H
MANNY
IOSEGUN
ANTE CREEK LITTLE SMOKY NORTH
CLYDEN
GLOVER
MAX
CHERPETA
SPUR
WIDEWATER
PETER
MOONEY
DECRENE
ADAMS
MITSUE
SWAN HILLS
FRANCIS
PARKER
NIPIN
AMADOU
MCMILLAN
LYLE
TOMATO
SMITH
HONDO
NIXON
ARMITAGE
WAPPAU
LOGAN
KIRBY
GRIST
IPIATIK
CALLING LAKE
BOUVIER
DEVENISH
GROUSE
DUNCAN
CANAL
MEYER
GAMBLER
BAPTISTE
RICHMOND
PHILOMENA
CHARRON
MILLS
FISHER
HEART LAKE
Ath
N New Truck Route
11
9
10
8
7
6
2 5
1
Estevan Town Limits – 1½ miles east to property
4 4
1
5
3 2
1 1
Hwy #39 – 1 mile north to property
For more information please contact Gary at 780-305-9255 1174365 Alberta Ltd. Operating as Gar-Lin Investments garymbr@telus.net
January 2010 • OIL & GAS INQUIRER
GRAHAM
HARDY
LEISMER
DRIFTPILE
DEVIL MCGOWAN
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CALAIS
3
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■ 16 lots for sale in Estevan, SK. ■ SW 29-2-7-W2 New Bypass Industrial Park New Truck ■ Re-zoned for commercial / Route opening in light industrial lots front of quarter ■ Lot sizes vary from in 2010 4.2 acres to 27 acres KELLY
GODIN
NIPISI
LITTLE HORS
GIROUXVILLE
TEEPEE
GRANOR
SHOAL
NEWBY
EAGLESHA
KAKUT
CLAIR
UTIKUMA LAKE
ROXANA
WINAGAMI
WEBSTER
HYTHE WEMBLEY BEAVERLODG E GRANDE PRAIRIE ALBRIGHT
GOODLOW
KIMIWAN
CINDY
PEORIA
SEAL
DAWSON
DAWN
M NORTH
BELLOY CULP
SADDLE HILLS
ATIKAMIK
HANGING STONE
HARMON VALLEY
TANGENT
SALESKI
SLAVE
GRIMSHAW
DUNVEGAN
SPIRIT RIVER
LA GLACE
SINCLAIR
NAMPA
GAGE
WHITELAW
CREEK RING
ROLLA
K
LOON
LEDDY
FAIRVIEW
PINGEL
HAMELIN
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VALHALLA GLACIER KNOPCIK
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EXPANSE
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WORSLEY
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THETLA ANDO A THETLA AN SOUTHDOA
5
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C ove r-A l l A l b e r t a 1.866.399.7569 • www.coverall.net COVER-ALL AND TITAN ARE REGISTERED TRADEMARKS OF COVER-ALL BUILDING SYSTEMS, INC. GATORSHIELD TUBING SUPPLIED BY ALLIED TUBE & CONDUIT
3.5 x 4.5 Publication: Oil & Gas Inquirer - Dec 1 • 1973-09/4c/150/mc
On the Job
onthe
JOB Careers in the Oilpatch
What is oil and gas well fishing? A fisherman recovers wireline tools, drill pipe, packers, tubing, and any other equipment left downhole or stuck during drilling and completion operations. Every major fishing company also has a pipe recovery service since that’s the first thing we have to do on a job. In the field, Hess can do the entire fishing operation starting with the pipe recovery/line truck and finishing it with the proper selection of fishing and rental tools. How did you get into fishing? Most fishermen have extensive experience working as rig hands themselves. I’m the exception to that rule. After graduating from high school in Swift Current, I qualified as a welder. I wound up with a company that installed and recovered downhole sand screens. On May 4, 1985, they didn’t have anyone available for a fishing job north of Taber, so I got sent. The work really suited me, and I eventually became Weatherford Canada’s manager of fishing services for Canada. Then I came to Hess. As Hess’s GM, do you still work in the field? Definitely. In this line of work, I don’t believe in non-producing management. No two fishing jobs are exactly alike. You stay on your toes all the time, and there’s no such thing as having too much experience.
Tammy Matthews
Why do you like fishing? Who wouldn’t want to jar loose tonnes of drill string or deploy bromine trifluoride cutters that slice through steel pipe in half of a second? For me, it’s the best job in the world; you have to be alert and on your toes all the time. Because an experienced fisherman is difficult to replace, veterans almost never get laid off. In Canada, there are about 85 guys who fish professionally. Most of us work for Weatherford, Baker Hughes, Command, or Hess. Although the companies compete, it’s a friendly business where a lot of people know each other.
Jeff Schryver Age: 44 Title: General manager and fisherman Company: Hess Fishing & Rentals LP
Age: 43 Training: Production accountant Title: General manager Companies: Petroline Rentals Ltd. and Barracuda Pilot Service
Have you done much work overseas? Yes. Besides the East Coast and a lot of American states, I’ve fished in Russia, China, Southeast Asia, and Scotland. Canadian fishermen are generally well-accepted around the world. Partly that’s because the West has many different types of geological formations—deep and over-pressured, shallow and low-pressure, heavy oil and bitumen, every degree of sour gas, coalbeds, shales, and tight rock. It’s unusual to find that variety within one region. Fishing here, you acquire a broad range of experience. Photo: Aaron Parker
Who should consider going into oil and gas fishing? Our customers hire more on the basis of expertise than price. No wellsite supervisor is likely to listen to someone with less than 15 years of experience in the patch, or at least 10. With fishing, as they say, either send out a guy with grey hair or don’t send anyone. But don’t worry—this business turns your hair grey pretty quick. OIL & GAS INQUIRER • January 2010
51
Coming marCh 2010
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January 2010 • OIL & GAS INQUIRER
oilpatchex.com
Tools of the Trade
TOOLS
OF THE TRADE A LOOK AT NEW TECHNOLOGIES
Who is North Rig Catwalk Technologies? North Rig Catwalk Technologies is an independent, privately owned manufacturing business headquartered in Cochrane, Alta. We design and build a comprehensive range of hydraulic catwalks for both drilling and service sectors. What is a hydraulic catwalk? A hydraulic catwalk is a hydraulically powered device which replaces the traditional long steel platform and ramp used to drag tubulars from the ground to the drilling floor using the tugger line. Hydraulic catwalks use a variety of methods to transport the tubulars from ground level to drilling floor. The lift-
North Rig hydraulic catwalk
up mechanism on a North Rig catwalk is securely attached to the V-door at all times and a deep trough holds tubulars securely. What are the competitive advantages of North Rig catwalks? We can tailor existing proven designs to clients’ customized requirements. Wireless controls mean the operators are kept away from the most hazardous part of the drilling operation—pipe handling. All the operations of the catwalk are hydraulically controlled, meaning rapid setup and teardown times, together with dependable, repeatable operability. There is a large, global appetite for the safety and efficiency advantages of this equipment in the industry. How long have your catwalks been in field service? The earliest equipment has been running in the field for over three years, operating in both extreme heat and cold climates and has performed in a stellar fashion. The safety record is impeccable. What future development does North Rig have in mind for this technology? By watching industry developments closely and responding to clients’ requirements, North Rig will continue to expand its product line, adding more mobile units for the service sector in the future.
Answered by Adrian Prudden, president of North Rig Catwalk Technologies
OIL & GAS INQUIRER • January 2010
53
Political Cartoon
Advertisers' Index 1174365 Alberta Ltd . . . . . . . . . . . . . . . . . . . . . . 50
Cover-All North Inc . . . . . . . . . . . . . . . . . . . . . . 38
Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . 34
AGI-Envirotank . . . . . . . . . . . . . . . . . . . . . . . . . 38
Crompton Western Canada Inc . . . . . . . . . . . . . 46
OilPro Oilfield Production Equipment Ltd . . . . . 26
All Weather Shelters Inc . . . . . . . . . . . . . . . . . . . . 7
Dean’s Pump Service Ltd . . . . . . . . . . . . . . . . . 44
Pembina Controls . . . . . . . . . . . . . . . . . . . . . . . 34
Allan R. Nelson Engineering (1997) Inc . . . . . . . . 32
DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Annugas Compression Consulting Ltd . . . . . . . . 17
Diversified Glycol Services Inc . . . . . . . . . . . . . 48
BC Resources Expo . . . . . . . . . . . . . . . . . . . . . . 42
Ecoquip Artificial Lift Ltd . . . . . . . . . . . . . . . . . 23
Petroleum Services Association of Canada . . . 30
Bear Slashing Ltd . . . . . . . . . . . . . . . . . . . . . . . . 34
Falvo Electrical Supply Ltd . . . . . . . . . . . . . . . . 36
Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . 37
Fit Right Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Bilton Welding and Manufacturing Ltd . . . . . . . 44
Flexpipe Systems . . . . . . . . . . . . . . . . . . . . . 40/41
Black Sivalls & Bryson (Canada) Ltd . . . . . . . . . 42
Glentel Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Brews Supply Ltd . . . . . . . . . . . . . . . . . . . . . . . . 25
Global Oil & Pipe Inc . . . . . . . . . . . . . . . . . . . . . 48
Brother’s Specialized Coating Systems Ltd . . . . 10
Hex-Hut Shelter Systems Ltd . . . . . . . . . . . . . . . 15
Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . 11
Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . 48
TARM Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . 32 Platinum Grover Int. Inc . . . . . . . Inside front cover Propak Systems Ltd. . . . . . . . . . . . . . . . . . . . . . . 3 Prostate Cancer Canada Network . . . . . . . . . . 52 RTS Services Inc . . . . . . . . . . . . . . . . . . . . . . . . 44 Systech Instrumentation Inc . . . . . . . . . . . . . . . 26
Caradan Chemicals Inc . . . . . . Outside back cover
LJ Welding & Machine . . . . . . . . . . . . . . . . . . . . . 5
Titan Logix Corp . . . . . . . . . . . . . . . . . . . . . . . . 46
CARES Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
LoTech Manufacturing Inc . . . . . . . . . . . . . . . . . 37
Trans Peace Construction (1987) Ltd. . . . . . . . . 46
Contain Enviro Services Ltd . . . Inside back cover
MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . 29
Triple D Technologies Inc . . . . . . . . . . . . . . . . . . 26
Cover-All Alberta . . . . . . . . . . . . . . . . . . . . . . . . 50
Northstar Energy Services Inc . . . . . . . . . . . . . . 6
Vertigo Theatre Society . . . . . . . . . . . . . . . . . . 52
54
January 2010 • OIL & GAS INQUIRER
Reduce H2S Scavenging Costs by 20-50%
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1404 - 8 Street T9E 7M1
780.955.3050
Drayton Valley, AB������������������������� 780�542�6832 Edson, AB ��������������������������������������� 780�728�4152 Grande Prairie, AB������������������������� 780�832�4527 Kindersley, SK ������������������������������� 306�460�5609 Stettler, AB ������������������������������������� 403�741�4271 Swift Current ���������������������������������� 306�750�1339 Wainwright, AB ������������������������������ 780�806�8227
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