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Incorporated in 2009, Logan Industries is the parent company of eight diverse businesses servicing a broad range of industries. Each of our unique divisions adds value and provides synergy to the others, enabling us to deliver superior quality within tighter timelines and at a higher level of service. From initial drafts and custom machining to the final fabrication, we are capable of completing your project “in-house” from start to finish. We are 100% employee owned. From our machinists, technicians and welders to our salesmen and management 90% of all of our employees are shareholders themselves. Logan Industries’ highly motivated workforce doesn’t need to be asked to go the extra mile. We exceed your expectations and deliver on what we promise. Our goal is that the pride we take in our workmanship will speak for itself.
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• Provides custom hydraulic services for the oil & gas industry. • Agricultural and transportation • Fully equipped welding and industries fabrication facility. • Commercial vehicle inspections • Production equipment MAIN LINE: 403.362.8881 Gary Meador 403.633-1795 • Drilling and service rig Richard Deunk 403.793.0080 fabrication gary.meador@logan-ind.ca • Hydraulic Catwalks and Pipe richard.deunk@logan-ind.ca Handlers
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• Commercial vehicle service and repair • Mobile oil service rigs repair • Commercial engine and transmission repairs. • Commercial vehicle inspection
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• Largest gas well optimization company in AB & BC. • Regulatory testing: ERCB, OGC. • Custom engineering, plunger equipment • Sales, installation & maintenance • Pumping well optimization & analysis
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Keeping readers regionally informed
FEATURES
10
Cover Feature
Will natural gas recover?
Less money
1
Conventional capital spending to decline in 2013, says TD
Demand is up, supply is moderating, but roadblocks remain before gas markets move up significantly
By Pat Roche
By Daily Oil Bulletin staff
Next-year country
21
Bumps in the road
2
Oil producers have mixed views about 2013 prospects
Pipeline export constraints will continue curbing oil industry enthusiasm in 2013
By Darrell Stonehouse
By Daily Oil Bulletin staff
GENERAL NEWS
29
Asian refineries moving to heavier crudes By Carter Haydu
45 Central Alberta
Red tape threatens B.C. LNG strategy,
EOR pipeline work continues as
says Fraser Institute report
Northwest Upgrader sanctioned
By Richard Macedo
By Pat Roche
37 Northwestern Alberta
49 Southern Alberta
Rent-based royalties more efficient, says
Paramount doing massive build-out
tax experts
of processing capacity in Montney
By James Mahony
By Pat Roche
41 Northeastern Alberta
from all the staff at
SMART DEADWEIGHT AND PRESSURE HOUND PRODUCTS PORTABLE CUSTOM DATA ACQUISITION SYSTEMS PRESSURE AND FLOW CALIBRATION TRACEABLE TO NATIONAL STANDARDS INSTRUMENT RENTALS SYSTECH HAS RELOCATED TO THE FOLLOWING ADDRESS TO BETTER SERVE OUR CUSTOMERS
REGIONAL NEWS
33 British Columbia
Merry Christmas
51 Saskatchewan
Cenovus output rockets
Legacy builds up Manitoba,
By Lynda Harrison
North Dakota production
#3, 4351 104th Ave. SE Calgary, AB. T2C 5C6 Phone: (403) 291-3535 Fax: (403) 291-3585
1-888-SYSTECH www.systechinst.com
BUSINESS INTELLIGENCE
53
Hand-held devices support oil and gas field production services
IN EVERY ISSUE
Stats at a Glance
54 Political Cartoon
DECEMBER 2012 $6.00
?
RECOVE R DemanD is uP, suPPly is moDerating, meaning 2013 coulD mark a turnarounD in north american gas markets
Producers are closely watching gas production in the U.S. in the hopes of higher prices this winter
Plus:
A look AheAd At the oil mArket for 2013 An updAte on the greAt oil export pipeline sAgA
PM4006924
8
Cover design by: Peter Markiw
OIL & GAS INQUIRER • DECEMBER 2012
5
advertisement
Taking your Oil and Gas Services Company South of the Border A co-ordinated approach can reduce your tax footprint. New opportunities in the U.S. are attracting Canada’s oil and gas services companies. Businesses of all sizes are sending employees and equipment to areas like the Bakken play in North Dakota and Marcellus in Pennsylvania, contributing expertise to make a profit. But with opportunity comes challenges, and cross-border taxation is one issue that must be planned for and managed. “Cross-border taxation is extremely complex. There are a number of considerations that must be addressed before you begin operating in the U.S. or your company and employees run a very real risk of paying higher taxes than necessary,” explains Jason Kingshott, CA, Oilfield Services Leader in Alberta, MNP. U.S. corporate tax rates are higher than Canadian rates. In addition, each state has its own tax regime. Working with a firm like MNP to understand the intricacies of U.S. and international tax, as well as the impacts on your specific industry, is critical when determining how you want to structure your business and the kind of tax footprint you want to have. For small, independent contractors who want to head south and get in on the action, one of the biggest issues is whether the Canadian company or the individual employee shareholder may inadvertently become subject to U.S. federal or state income taxation. In particular, some relatively new rules introduced in the tax treaty can, in certain circumstances, lead to both the contractor and the Canadian company becoming subject to U.S. taxes.
“The decision must be made by evaluating the situation in light of various standards related to the kind of activity that will be conducted in the U.S. and whether you are looking at federal or state tax law,” explains James Meadow, CA, CPA (NC), LL.M, International Tax Partner at MNP. Larger companies sending numerous employees across the border need to plan ahead and manage exposure to U.S. income taxes at the federal and state levels from a company perspective. Meadow also recommends that they understand the possible implications for their Canadian employees. Payroll is another consideration. If a certain level of activity is reached, the company will wind up with a U.S. payroll with Canadian employees, which introduces another level of complexity. And, sending equipment adds a new dimension that will play a role in deciding whether to operate as a Canadian company or set up a subsidiary. MNP can help oilfield services companies make the decision about how best to enter the U.S. or another country, considering your tax strategy as a whole so that both Canadian and international tax obligations are factored in. “The goal is to maximize after-tax profit. A good strategy can save significant dollars,” says Kingshott. If you’re operating in the U.S. or considering an international expansion, find out how MNP’s cross-border approach can benefit you. Contact Jason Kingshott, CA, MNP Oilfield Services Leader, Alberta, at 403.537.7615 or jason.kingshott@mnp.ca.
Editor’s Note
Vol. 24 No. 10 EDITORIAL
The great upheaval
EDITOR
Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS
Lynda Harrison, Darin Hauck, Carter Haydu, Richard Macedo, James Mahony, Pat Roche EDITORIAL ASSISTANCE MANAGER
Samantha Sterling | ssterling@junewarren-nickles.com EDITORIAL ASSISTANCE
Darrell Stonehouse | dstonehouse@junewarren-nickles.com
Brandi Haugen, Marisa Sawchuk, Matthew Stepanic CREATIVE PRINT, PREPRESS & PRODUCTION MANAGER
Michael Gaffney | mgaffney@junewarren-nickles.com CREATIVE SERVICES MANAGER
Tamara Polloway-Webb | tpwebb@junewarren-nickles.com CREATIVE LEAD
Cathlene Ozubko GRAPHIC DESIGNER
Peter Markiw
CREATIVE SERVICES
Christina Borowiecki production@junewarren-nickles.com SALES SALES MANAGER—ADVERTISING
Maurya Sokolon | msokolon@junewarren-nickles.com SENIOR ACCOUNT EXECUTIVE
Diana Signorile SALES
Nick Drinkwater, Sammy Isawode, Mike Ivanik, Rhonda Helmeczi, Nicole Kiefuik, David Ng, Tony Poblete, Sheri Starko For advertising inquiries please contact adrequests@junewarren-nickles.com AD TRAFFIC COORDINATOR—MAGAZINES
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Stephen Marsters | smarsters@junewarren-nickles.com DIRECTOR OF DIGITAL STRATEGIES
Gord Lindenberg | glindenberg@junewarren-nickles.com DIRECTOR OF CONTENT
Chaz Osburn | cosburn@junewarren-nickles.com DIRECTOR OF PRODUCTION
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The arrival of multistage fracturing and extended-reach horizontal drilling is radically altering North American energy markets. And it appears the Canadian oil and gas industry is going to have to almost completely reorient itself in the coming decades if it is to stay viable. On the natural gas front, analysts are predicting the United States will be selfsufficient by the end of the decade. There are some analysts that say the country is already there. What does this mean for Canada? It means that it needs to find a new home for five billion to six billion cubic feet of natural gas per day if it hopes to maintain production, according to Haywood Securities Inc. senior oil and gas analyst Robert Cooper. With oil, the trajectory is similar, but will play out over a longer period of time. The International Energy Agency is predicting the United States will be a net exporter of oil by 2030 and self-sufficient by 2035. While many doubt this forecast, one need only look at the growth in tight oil plays across the United States to see just how quickly production is growing. In September, North Dakota production climbed almost 30,000 barrels per day, bringing average daily production to 730,000 barrels per day. Output has doubled since February 2011 and has been growing at a rate of over three per cent per month for the last eight months. In other words, it has added almost three 150,000-barrel-per-day integrated oilsands mines in the last two years. The Eagleford play in Texas is enjoying similar growth. In July 2011, the Eagleford produced an average of 120,000 barrels of oil per day. In July 2012, it produced over 310,000 barrels per day. And both these fields are in the early stages of development, but are already growing national supply. In the first quarter of 2012, U.S. production crossed the six-millionbarrels-per-day level, the first time it has reached that quantity since 1998. Seeing these numbers, it becomes readily apparent that the days of our neighbour to the south taking all the oil and gas Canada can produce are over. The Canadian industry is facing a great upheaval, and needs to reorient itself to focus on international markets with growing demand. Here is the bottom line. Without liquefied natural gas export facilities and oil pipelines built to the West Coast, Canada’s industry is dead in the water. Right now, the Government of British Columbia is in the catbird seat. If it plays its cards right, the province could see an energy infrastructure boom that will carry its economy for a generation. But if it fails, all Canadians will be left poorer. On another note, in next month’s issue of Oil & Gas Inquirer, big changes are coming. We are undergoing a redesign to make our publication easier to read and to allow us to pack more information into each issue. Hopefully, you will enjoy our new look.
Subscription Inquiries Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: junewarren–nickles.com GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2012 JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240. Postage Paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 80 Valleybrook Dr, North York, ON M3B 2S9 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.
NE X T
I S S U E
January/February 2013 A review of oil, natural gas liquids and natural gas exploration and development in northwestern Alberta. Plus, a look at waterfloods and CO2-enhanced recovery schemes across tight oil plays.
Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as "Letter to the Editor" if you want them published.
OIL & GAS INQUIRER • DECEMBER 2012
7
STATS AT A GLANCE
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin OIL
GAS
D RY
Oct 2011 Nov 2011 Dec 2011
1,153 1,170 988
321 331 359
1 1 1
Jan 2012 Feb 2012 Mar 2012
419 846 996
127 37 95
1 2
Apr 2012 Jun 2012 Jul 2012
63 12 23
1 2 1
Aug 2012 Sep 2012 Oct 2012
OIL
GAS
Oct 2011 Nov 2011 Dec 2011
626 557 568
259 241 300
19 36 72
0 0
Jan 2012 Feb 2012 Mar 2012
215 491 515
131 177 147
35 50 55
Apr 2012 Jun 2012 Jul 2012
403 205 348
141 12 46
Aug 2012 Sep 2012 Oct 2012
380 447 588
98 65 80
OTHER
T O TA L
SERVICE
T O TA L
20 27 27
49 42 115
1,543 1,570 1,489
190 244 180
15 21 33
31 52 66
655 1,153 1,275
608 376 660
192 25 92
31 40 16
157 8 105
988 449 873
682 813 1,121
148 75 105
9 9 10
67 11 33
986 908 1,269
Wells Drilled in British Columbia
Saskatchewan Completions
Source: B C Oil and Gas Commission
Source: Daily Oil Bulletin
MONTH
WELLS DRILLED
C U M U L AT I V E *
MONTH
OIL
GAS
OTHER
TOTAL
Oct 2011 Nov 2011 Dec 2011
35 92 58
646 738 796
Oct 2011 Nov 2011 Dec 2011
457 524 332
29 4 4
46 32 61
2 0
Jan 2012 Feb 2012 Mar 2012
53 66 39
53 119 158
Jan 2012 Feb 2012 Mar 2012
142 296 414
10 6 0
8 20 40
10 22
Apr 2012 Jun 2012 Jul 2012
86 13 57
244 334 401
Apr 2012 Jun 2012 Jul 2012
172 144 232
0 0 0
49 10 16
221 1 2
Aug 2012 Sep 2012 Oct 2012
53 11 28
454 465 493
Aug 2012 Sep 2012 Oct 2012
296 302 453
4 1 0
9 7 27
0 10 0
*From year to-date * from year to date
8
MONTH
MONTH
DECEMBER 2012 • OIL & GAS INQUIRER
FAST NUMBERS
,
.
trillion cubic feet
Amount of gas in Alberta shale formations according to the Alberta Geological Survey's median estimate.
billion barrels
Amount of oil in Alberta shale formations according to the Alberta Geological Survey's median estimate.
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada, November 12, 2012 Source: Rig Locator
Alberta, November 12, 2012 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada Alberta
AC T I V E
OIL WELLS
Alberta
Oct 12
GAS WELLS Oct 11
Oct 12
Oct 11
267
313
0
46%
Northwestern Alberta
138
148
34
82
British Columbia
39
15
73%
Northeastern Alberta
111
89
0
1
Manitoba
11
11
22
55%
Central Alberta
294
328
6
63
Saskatchewan
82
59
11
58%
Southern Alberta
45
56
40
110
0%
TOTAL
621
0
256
WC TOTALS
Service Rig Count by Province/Territory
Drilling Activity: CBM & Bitumen
Western Canada, November 12, 2012 Source: Rig Locator
Alberta, November 12, 2012 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada Alberta
AC T I V E
C OA L B E D M E T H A N E
Alberta
Oct 12
BITUMEN WELLS
Oct 11
Oct 12
Oct 11
447
305
2
59%
Northwestern Alberta
0
0
21
11
10
19
2
34%
Northeastern Alberta
0
0
111
89
8
9
1
47%
Central Alberta
0
29
117
142
Saskatchewan
158
51
209
76%
Southern Alberta
9
59
0
0
WC TOTALS
2
1,00
2%
TOTAL
88
2
242
British Columbia
Manitoba
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OIL & GAS INQUIRER • DECEMBER 2012
9
FEATURE
?
RECOVE R DEMAND IS UP, SUPPLY IS MODERATING, BUT ROADBLOCKS REMAIN BEFORE GAS MARKETS MOVE UP SIGNIFICANTLY
10
DECEMBER 2012 • OIL & GAS INQUIRER
Photo: Joey Podlubny
By Daily Oil Bulletin staff
FEATURE
T
he year 2012 was another bad one for Canadian natural gas producers as huge shale gas supplies and a stalled U.S. economy curbing demand growth combined to continue depressing prices far below historical norms. Natural gas drilling continued its steep decline with around 2,500 wells drilled in western Canada. Production has been shut in across North America in response to the persistent low prices. The question going into 2013 is: When will natural gas prices recover?
And the answer is that it depends on whom you talk to. Canadian natural gas giant Encana Corporation believes gas prices will rebound somewhat in 2013, company president and chief executive officer Randy Eresman told shareholders at Encana’s third-quarter conference call. In early 2012, Encana shut in about 500 million cubic feet per day of production in response to low prices. Eresman said the decision to cut production was made after gas prices dropped below US$2.50 per million British thermal units. The
company brought that gas back on stream in August. With the forward curve reaching about $4 for 2013, “we thought it prudent to bring those volumes back on,” he said. Eresman said Encana sees a number of sources for optimism going into the winter heating season. On the demand side, he said gas use is growing in the power sector as it replaces coal. “Relative to 2008 levels, we estimate that approximately eight billion cubic feet per day of natural gas demand has been
OIL & GAS INQUIRER • DECEMBER 2012
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DECEMBER 2012 • OIL & GAS INQUIRER
gained from coal-to-gas displacement,” he said. Eresman said this has contributed significantly to reducing the North American storage surplus from about 927 billion cubic feet at the end of the winter to about 250 billion cubic feet going into the winter. “While demand from displacement may recede to some degree as natural gas prices rise, we expect to see a yearover-year increase in weather-sensitive demands with a return to more normal winter weather,” he said. On the supply side, Eresman noted that North American gas production has plateaued year-over-year, with declines in more mature or conventional basins largely offsetting growth from new plays. “This year, we’ve seen more than a 50 per cent drop in gas-directed rig counts in North America. And while rig completion efficiencies have improved relative to a few years ago, if this reduced rig– count trend continues, there should be an impact on 2013 natural gas production levels,” he said. CIBC World Markets Inc. institutional equity research executive director Andrew Potter is in line with Encana’s view for 2013. Speaking at the annual CFA Society Calgary Oil & Gas Forecast Breakfast, Potter said with current U.S. rig counts the production there will stall at about 65 billion cubic feet a day. At the same time, he said, Canadian deliverability to the United States is expected to decline by about 0.5 billion cubic feet a day by next year. “You can’t have declining supply and increasing demand and expect the prices to stay static. At some point, the prices have to go high enough to prompt more gas drilling, or see demand destruction,” he said. Potter said he sees gas prices in the $4 range, assuming there is a normal winter next year, as demand is the limiting factor for the commodity. However, while some might think a modest increase in demand would result in a return to drilling, Potter noted there is currently a lack of rig infrastructure allowing for simply increasing production. To reallocate capital back to dry gas means dry gas developers must compete with tight oil and liquids-rich plays, he noted. “And the reality is most of them don’t compete until you see a gas price in the $5–$6-per-thousand-cubic-feet range. So we think producers are going to be a lot
Feature more hesitant moving back to dry gas than a lot of people in the market do,” he added. Other major natural gas analysts aren’t so sure 2013 will mark a turnaround in the market. Credit Suisse Group says it expects a pause in recent price climbs due to five mitigating factors. The first factor is that production from the Haynesville shale play is coming in higher than analysts expected. Rigs have been leaving the Haynesville in droves as low prices have made the play borderline
“ This year, we’ve seen more than a 50 per cent drop in gas-directed rig counts in North America.”
Photo: Joey Podlubny
— Randy Eresman, Encana president and chief executive officer
economic. Only 19 rigs were operating there over the summer. Yet production continues rising. Credit Suisse expected July production of 5.9 billion cubic feet per day from the Haynesville but it came in 20 per cent higher at 7.1 billion cubic feet. The second reason Credit Suisse expects prices to stall is that the industry has become so efficient it takes fewer rigs and completions crews to add to already-huge supplies. “On a year-over-year basis, the natural gas rig count has declined by 54 per cent, yet production is yet to crack,” the analysts point out. “One of the key factors why production has been so stubborn is the impact of drilling efficiencies. In the Barnett Shale, the industry has averaged 2.70 completions per month, which represents a 17 per cent improvement in efficiencies relative to 2011. This is an astonishing 29 per cent improvement relative to 2010, when the industry completed 2.1 monthly Barnett wells per rig. The same trends are evident in other key dry gas basins.” New pipelines from the Marcellus shale play in the northeastern United States will also bring additional supplies to market. Credit Suisse says there are 1,000 uncompleted wells in the Marcellus play in Pennsylvania awaiting take-away capacity. Around 500 million cubic feet
Encana turned the taps back on 500 million cubic feet of gas it had shut in early in 2012. It is expecting prices to rise modestly in 2013.
per day of capacity is expected to be on stream this winter. A current oversupply of ethane is also adding to supply woes. Around 300 million cubic feet per day of ethane are being left in the gas stream in the United States, says Credit Suisse. The final concern Credit Suisse has that will limit natural gas price growth is an expected drop in demand from power producers. “Electric utility demand in 2012 has been off the charts, averaging 5.7 billion cubic feet per day, or 29 per cent above 2011 levels,” it notes. “Using historical correlations between coal-generation market share and gas prices, we estimate the potential impacts to switching at different price
points in the first half of 2013. We estimate natural gas could lose 2.4 billion–5.1 billion cubic feet per day of market share to coal at gas prices between $3.50 and $4.50 per thousand cubic feet. At the current futures strip of $3.95 per thousand cubic feet, we estimate gas could lose 3.75 billion cubic feet of market share to coal in 2013.” Haywood Securities Inc. senior oil and gas analyst Robert Cooper told the CFA breakfast the gas industry is better positioned going into this winter than any time in the last four years. But in the longer term, the Canadian industry needs to reinvent itself. In the short term, Cooper said the natural gas storage situation has improved greatly this year. OIL & GAS INQUIRER • DECEMBER 2012
13
Canada needs to fi nd markets for fi ve billion to six billion cubic feet of natural gas demand as U.S. production climbs.
“The withdrawals last winter are quite a bit higher than normal, and conversely, as we got into the summer the injections were quite a bit lower,” he noted, meaning prices should be better. Cooper also expects the decline in rigs targeting gas in the United States to continue, further dropping supply. Longer term, he believes the Canadian industry needs to transform itself as the United States moves towards natural gas independence. “What’s going to happen here—probably within this decade—Canadian natural gas producers are going to have to find another source of demand,” he said. If Canadian natural gas suppliers want to continue being competitive in an increasingly energy-independent American market, Cooper said there will need to be a change, and that change will likely come in the form of production for liquefied natural gas export. “We need to replace probably five [billion] to six billion cubic feet a day of natural gas demand going to the U.S. with an export going to the West Coast. That shift is not going to happen in the next year, but it’s probably going to happen in the next five years,” he noted.
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DECEMBER 2012 • OIL & GAS INQUIRER
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Photo: Joey Podlubny
FEATURE
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FEATURE
$$$ lessmoney Conventional capital spending to decline in 2013, says TD By Pat Roche
C
apital spending in the western Canadian oilpatch will likely pull back a little bit in 2013 despite a slight increase in natural gas prices recently, a senior analyst predicts. However, oilsands investment will continue to increase, reflecting “both the economics and the long lead times,” said Roger Serin, managing director of energy research at TD Securities. In predicting capital spending trends, Serin declined to forecast a specific number. Serin expects oilsands capex to rise by about 10 per cent in 2013 compared to projected-2012 spending. That compares with an estimated 20–25 per cent rise in oilsands spending this year over 2011. The TD analyst’s forecast was delivered to a standing-room-only crowd during the Petroleum Services Association of Canada (PSAC)’s 2013 outlook conference at the TELUS Convention Centre in Calgary. “On a conventional [non-oilsands] basis, we think spending will fall by five to 10 per cent in 2013 after about a 10–15 per cent drop this year. If anything, we’re probably conservative on that number,” he said. Serin is bearish about gas prices because U.S. production remains stable amid a steep drop in the U.S. gas-drilling rig count, and because some of the U.S. shale gas production—the equivalent of western Canada’s entire output—is now spilling into Canada, displacing Canadian gas.
He expects the NYMEX gas price to remain below US$4 per million British thermal units for some time. He noted the Alberta AECO price is roughly 50 cents lower than the NYMEX price. Canada is a big net exporter of gas; the United States has historically been a big net importer, but the balance is changing. Serin said exports to the United States used to make up as much as 65 per cent of Canada’s gas production. It’s now about 55 per cent. “And I’m going to tell you [that] over the next couple of years, it’s going to fall even more because Marcellus production [from the U.S. northeast] is not only going to grow for northeast U.S., but we recently started importing Marcellus gas into Canada to the tune of half a [billion cubic feet] a day, and that will probably grow to north of one [billion cubic feet] a day,” he said. In other words, Canada, a net exporting country, is becoming a significant gas importer—bad news for Canadian producers. To put the one-billion-cubic-foot-a-day invasion of U.S. gas into Canada into perspective, Serin noted Canada’s total output, including what’s consumed domestically, is only about 14.5 billion cubic feet to 15 billion cubic feet a day. So having half a billion cubic feet to one billion cubic feet a day of U.S. gas production flooding into Ontario is not a good thing, he said with understatement. OIL & GAS INQUIRER • DECEMBER 2012
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FEATURE
This underscores the urgency of planned exports of Canadian gas to Asia, he said, stressing the need for everyone—including governments—to work toward that goal. “LNG [liquefied natural gas] matters, even if you’re not with a company that’s exporting LNG,” he said. “And the reason it matters is it will significantly drive activity in the [Western Canadian Sedimentary] Basin. And unless we get an export opportunity for natural gas—whether to new markets in the U.S. or…Japan, Korea, China in the form of LNG—we’re going to be awash in natural gas, in my view, for some time. “And that will keep natural gas prices suppressed. Period. Full stop. So I don’t think gas prices will go much above US$4. I think netbacks for LNG will be $4–$5 on long-term contracts. So I think there’s a lot of work to be done to get LNG projects approved.” He said the good news for Canada’s non-oilsands sector is the return of the supermajors. He cited the recent announcement that Exxon Mobil Corporation has agreed to acquire Celtic Exploration Ltd. “The supermajors are back and with well costs in the Duvernay between $10 million and $15 million, it’s a good thing, in my view, that they are,” he said. Serin expects significant capital spending in the Montney liquidsrich gas play, the Cardium tight oil play and the emerging Duvernay liquids-weighted shale play. “The Montney in northeast B.C. and straddling into west-central Alberta will be a key part, in my view, of LNG exports, and, in fact, has the opportunity to largely, if not completely, displace Horn River demands for natural gas being exported,” he predicted. In the Duvernay, the industry has spent about $4.5 billion to acquire land in the past couple of years. “Generally, when you buy the land, you drill it,” said Serin, who expects Duvernay capital spending to exceed $1 billion in 2013. 18
DECEMBER 2012 • OIL & GAS INQUIRER
In its 2013 Canadian Drilling Activity Forecast, PSAC predicts the number of wells rig released in Canada will edge up slightly to 11,400 from an expected final tally of 11,250 this year. However, the modest increase in the forecast well count belies a significant increase in drilling and completions spending in recent years, as wellbores have become longer and more complex. “The forecast for 2013 of 11,400 wells—it’s expected the total measured depth of those wells will be 22 million metres, which is about the same as was drilled in 2008 with 17,000 wells,” said Mike Edmonds, past chair of PSAC’s board of directors and president of Import Tool Corp. Ltd. “It looks like in the coming year, horizontal wells are going to be about 70 per cent of the wells drilled. They take longer to drill and complete, [and] utilize the newest technology and equipment,” Edmonds said. He noted the technology advancements are allowing for directional drilling at deeper depths than ever before. New technology is also opening up new plays once considered to be out of reach. PSAC expects 87 per cent of the wells drilled will be oil wells. “We’re projecting that gas wells will only be drilled as needed,” said PSAC president Mark Salkeld, citing low gas prices and high storage levels going into winter. Low gas prices are a major reason for PSAC’s somewhat conservative 2013 forecast, and for the lower-than-expected drilling activity this year, said Lucas Mezzano, PSAC’s chair and sales manager with Tenaris Global Services (Canada) Inc. “Restricted access to new customers overseas will continue to be an issue our industry faces,” Mezzano added. “Access to cash flow and capital spending programs of our customers will also contribute to drilling-activity trends in the new year.”
Photos: Joey Podlubny
Capital spending in the oilsands is expected to rise 10 per cent. In the conventional industry, expenditures are expected to decline by fi ve to 10 per cent.
FEATURE
Y R T N U CO e mixed v a h s r e c u
Oil prod By Darrell
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due to planned and unplanned refinery or heavy oil refinery capacity. As this capacity came back online, we saw a dramatic narrowing of heavy oil differentials in May and June. As a result, second-quarter differentials averaged about 24 per cent of West Texas Intermediate (WTI), well within our long-term estimate of 22 per cent to 25 per cent. We do, however, expect to see occasional anomalies in heavy oil differentials in 2012, as the refineries go down for planned and unplanned maintenance.” Beginning next year, CNRL expects h e a v y oi l e c on om ic s t o i mp r o v e significantly.
“With 300,000 barrels per day of heavy oil conversion capacity slated to come on stream from the end of 2012 to the first half of 2013, these issues will disappear and actually put downward pressure on heav y oil differentials,” said Laut. “Add to this the strong likelihood that the Keystone XL pipeline will be approved, allowing North American heavy barrels to displace the roughly 2.4 million barrels of heavy oil imports into the Gulf Coast, as well as provide blending opportunities to displace medium oil imports, heavy oil pricing looks very strong going forward.”
Photo: Gerald Ford
estern Canada’s oil and oilsands producers have a range of opinions on how 2013 will play out, as some see the current export bottleneck easing, while others see clouds on the horizon. Canadian Natural Resources Limited (CNRL) is on the side of the optimists, particularly when it comes to heavy oil. “We are very bullish on heavy oil pricing,” CNRL president Steve Laut said in his second-quarter report to shareholders. “The blowout on heavy oil differentials seen in the first quarter is almost entirely
OIL & GAS INQUIRER • DECEMBER 2012
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$10–$12 premium. So there’s an arbitrage there that’s likely going to be closed when we get access to the Gulf Coast refining region.” Putting a damper on the enthusiasm, however, is tight oil growth in the many basins across the United States. In 2011, U.S. oil production climbed by around 450,000 barrels per day. That number is expected to climb to 900,000 barrels per day this year. Looking out, some analysts are predicting production to climb 500,000–750,000 barrels per day in each of the next three years. This growth in tight oil production, combined with a lack of pipeline takeaway capacity to off shore markets, has at least one major oilsands producer taking a close look at future growth plans. In October, Suncor Energy Inc. said it was reviewing its plans for its Voyager Upgrader and Fort Hills mine and would likely delay the projects. “The production timeline for Fort Hills is likely to be delayed by about a year, to 2017,” Steve Williams, Suncor president and chief executive officer, said during a thirdquarter conference call. “At the same time, Voyageur economics appear challenged in light of the projected ramp-up in tight oil production in the North American market.” Volumes of tight oil entering the market are effectively increasing the amount of light sweet crude, said Williams. “An upgrader just takes advantage of the margin between light crude and heavy crude, and so it squeezes the margin on an upgrader,” he told callers. “We are in the process of fully assessing what the mid- and long-term consequences of that change in the market are, and our belief is that it does put the Voyageur economics under more pressure than when we initially conceived the project.”
Heavy oil producers believe access to the U.S. Gulf Coast will add about $10–$12 per barrel to western Canadian production.
How strong? “We believe we’re about to enter an outstanding era for heavy oil—and in particular for thermal or in situ heavy oil—an era where, for the first time, most if not all the key factors are in our favour,” said Laut. “Increasing demand for heavy oil, strong heavy oil pricing, low gas prices which drive thermal in situ heavy oil operating costs lower and lower premiums for diluents with increased supply of liquid diluent from liquids-rich drilling, all adding to the further strength of economics for heavy oil.” Bay te x E nerg y Cor p. v iews it s Lloydminster heavy oil as a cash flow– generating machine. “Capital efficiency ratios are very, very good at Lloydminster,” Baytex chief financial officer Derek Aylesworth told a Barclays Capital conference this fall. “We’ve been adding production at $11,000 per flowing barrel, with finding and development costs of around $12 a barrel. At current WTI pricing we’re in the 200 per cent to 300 per cent internal rate of return for Lloydminster.”
Aylesworth said a study done by Scotiabank, looking at the profitability of all resource plays in North America, ranked Lloydminster heav y oil fifth. Aylesworth added while current heavy oil pricing is volatile, longer term, they expect it to become more stable. “Notwithstanding today’s volatility, we very, very much believe that when the U.S. pipeline system is built out and things like the Keystone line are in place, heavy oil pricing is going to be in a very, very, very strong position,” he explained. “So the main product that we’re producing is looking for a price improvement in a nottoo-distant future. I think by the time we get Keystone online, you’re going to have a very, very positive pricing picture because we’re accessing the Gulf Coast, using the Maya to Western Canadian Select [WCS] pricing marker. Maya is the Mexican heavy oil blend. It’s a very similar quality to WCS. Today, Maya is getting about $20 a barrel premium to WCS. When you adjust for transportation, it’s probably about
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Feature
Bumps
in the road Pipeline export constraints will continue curbing oil industry enthusiasm in 2013 By Daily Oil Bulletin staff
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anada’s oilsands operators and conventional oil producers are ready, willing and able to ramp up production. Plans are in place to potentially grow bitumen production by up to 350,000 barrels per day annually over the next decade. Conventional producers will likely drill upwards of 8,000 wells in 2012, and a similar number next year, according to the Petroleum Services Association of Canada’s 2013 forecast. But for the growth to continue, all the proposed export pipeline capacity and more will need to be built, and soon, according to CIBC World Markets institutional equity research executive director Andrew Potter. “Even if you build every single pipe that’s on the table right now... you’re still short pipeline capacity,” he noted. Unfortunately, Potter told a recent gathering in Calgary, the outlook for new pipelines is worse than it has ever been. While he expects Keystone XL to be approved at some point, he does not expect a West Coast pipeline to be built this decade. Further, he expects there to be political challenges in converting portions of TransCanada Corporation’s underused natural gas pipeline in eastern Canada to oil service. Standard & Poor’s (S&P) Rating Services shares this view. In a new report, S&P says increasing oil production in the Western Canadian Sedimentary Basin needs to find a home, and regulatory delays in approving new pipelines are putting this future growth at risk. During a midstream briefing in Calgary, Gerry Hannochko, a director with S&P, noted that in terms of pipeline projects, there are
over C$15 billion in projects in the queue to increase capacity by nearly two million barrels per day, including Alberta Clipper, Keystone XL, the Trans Mountain expansion and the Northern Gateway pipeline. “Production is coming, you’re going to need a home for it, and there’s simply not enough take-away capacity in the basin right now,” he said. But, he pointed out, the regulatory/environmental risks may slow approvals. “We’ve seen two major projects already been delayed with XL and Northern Gateway,” Hannochko said. “We’ve seen costs increase, with Gateway assuming about C$500 million for enhanced safety, and Keystone XL having additional costs rerouting away from the Sandhills in Nebraska.” Passing of the omnibus bill by Ottawa may speed the regulatory process, he added, but noted there’s now increased public scrutiny of pipeline projects. “We think that the overall trend here is going to be longer approval timelines...in spite of efforts to try to streamline these,” he said. Ian Anderson, president of Kinder Morgan Canada, said one key to moving pipeline projects forward is to work to understand and mitigate concerns in communities along pipeline routes. “National interest doesn’t matter a damn to that person who is sitting in Chilliwack [B.C.] whose yard is potentially going to be dug up for a new pipeline to go through,” he said during a keynote address to the Canadian Heavy Oil Association fall business conference. “It doesn’t matter a damn to that First Nation in the OIL & GAS INQUIRER • DECEMBER 2012
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North Thompson Valley [in British Columbia] who is questioning non-governmental organizations were providing to step in the the integrity of pipelines that cross the many streams and creeks way of pipeline projects, “it wasn’t very well-timed for us, and it that go through their traditional lands. was a little too public. “All it did was entrench further that local opposition,” “It’s got to get localized,” Anderson stressed. “It doesn’t mean the national interest doesn’t exist, it doesn’t mean it’s not critiAnderson said. “The local opposition got more reinforced, they got more committed to standing in the way of these projects cally important, but as a project proponent, as an industry, as a sector, it’s got to somehow get localized.” because they didn’t trust Ottawa, they didn’t believe the politiKinder Morgan is planning the expansion of its current cians. It made my job on the ground that much harder.” He added that improvements have been made to the regula1,150-kilometre Trans Mountain pipeline between Strathcona County near Edmonton and Burnaby, B.C. The proposed expantory process in Canada. In streamlining these regulatory systems, sion, if approved, would create a twinned pipeline that would however, a common criticism is that environmental standards will fall. Anderson disputed the latter point. increase the nominal capacity of the system to 750,000 barrels per day from 300,000 barrels per day. “We’re going to do every environmental study, we’re going to The company is planning to fi le the facilities application with do every outreach, we’re going to do every construction activity, the National Energy Board in late 2013. Filing the application monitoring...to the same standards as before or higher,” he said. will initiate a regulatory review What the federal governof the expansion facilities. If ment’s Bill C-38 did, for examthe regulatory application prople, was provide transparency cess is successful, construction and clar it y on t he reg ulaof the new pipeline could begin tory process: who should be as early as 2016. The expanded involved, who has an interest capacity would be ready for use in a project, what timelines in 2017. are going to be adhered to and “Today, we’re moving off of what parties should be working the West Coast down the Trans together instead of indepenMountain system, probably a dently to better advocate for their position, Anderson said. vessel a month which is making its way to China,” Anderson said. The bill was introduced by “When people talk about the Ottawa to modernize the fedfact that we need to access the eral regulatory system to estabmarket, the answer is we need to lish clear timelines, reduce access the market more.” duplication and regulatory burHe added that the planned dens, and focus resources on West Coast transportation projects Even if all proposed oil export pipelines are built there will still be a large projects where the potenare not a silver-bullet solution to tial environmental impacts are bott leneck gett ing exploding Canadian oil volumes to markets. move growing oilsands producthe greatest. tion to market. With respect to environmental issues of a pipeline proposal, he “I don’t think the West Coast proposals are the only projects said concerns seem to focus on upstream and downstream considerthat need to proceed; we need all of them right now,” he said. ations, tanker traffic in particular. “We need capacity to the Gulf Coast, whether that’s Keystone and “I never imagined when I was proposing a project expansion Seaway and other projects.” to the West Coast that I would, in fact, have to consult and engage Anderson outlined a number of different points that are key in Victoria, Sooke and Esquimalt,” Anderson said. “That’s part of to a project’s success. First, he stressed, the proposal must have the value chain, that’s part of the impacts that we’re seeing. commercial support. “[It’s] right through to the marine community.” “Industry needs to stand together and ensure that every project Reconciling positions between the environmental commuwe’re talking about and advancing is required,” he noted. nity and industry is important, he added. On First Nations issues, Also, projects need political support, although he said that Anderson said “there’s no textbook” on how to handle it. Alberta Premier Alison Redford and B.C. Premier Christy Clark “I can go from one band to the next band and it’s different,” he have not been a shining example of provincial alignment. On noted. Each can differ in terms of capacity, employment capabila visit to Calgary, Clark said that Enbridge Inc.’s proposed ity, and business development acumen and intention. Also, their Northern Gateway pipeline likely would not proceed if it did not views of the land and traditions, and the historical and generahave the support of British Columbia. tional reliance upon the land can differ as well. “Those things such as provincial alignment need to occur. “They are influenced by different factors than many of us have This infrastructure crosses boundaries,” Anderson said. “More to grown up with,” Anderson said. “You can’t crack that nut without the point, the political support needs to occur...at the right time, getting on the ground in the communities; talk to the chief, talk it has to be thoughtful, it has to be well-considered and it also has to the council, talk to the elders. Understand what’s driving them, to be without the rhetoric built in around it.” understand how they think, understand what it is they’re trying For example, while he agreed with federal Natural Resources to accomplish for their community and their people. I commit 20 Minister Joe Oliver’s concerns about funding that international per cent of my time to nothing but First Nations matters.” 26
DECEMBER 2012 • OIL & GAS INQUIRER
Photo: Joey Podlubny
FEATURE
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General News
Asian refineries moving to heavier crudes By Carter Haydu currently suffering from a lack of transportation capacity into more lucrative markets, such as the U.S. Gulf Coast with its large heavy crude refining capacity. The result, he said, is a disparity in what Alberta suppliers can expect for their oil. He said there’s a difference of about $20 per barrel between what Alberta crude can sell for and the price expected by other suppliers whose oil reaches the outer rim of the continent. That discount affects the amount of money that companies can invest back into the industry, as well as the tax dollars governments receive, Zahary pointed out.
“ I think if you tried to move a lot of western Canadian Canada's heavy oil production is a fit for Asian refiners, says John Zahary, president and chief
Photo: Joey Podlubny
executive officer of Sunshine Oilsands Ltd.
Asian markets and transportation infrastructure are the keys to the future of Canadian heavy crude, a rail and pipeline conference heard in late October. It is a mutually beneficial trading relationship: Canada has an oversupply of petroleum products, and is thus in a position to sell; East Asia has an undersupply of such commodities, and therefore needs to buy, speakers told the Crude Oil Markets, Rail & Pipeline Takeaway Summit. With Canada’s need to diversify its crude oil customer base and Asia’s need to diversify its oil supply source, the two jurisdictions will become increasingly linked as market partners in the years ahead, according to John Zahary, president and chief executive officer of Sunshine Oilsands Ltd., whose 10,000barrel-per-day first phase of its West Ells steam assisted gravity drainage (SAGD) project is currently under construction. “As we look at growing oil production, and we look at characteristics for markets for us to look at selling in, I think certainly Asia provides an ideal market for...diversifying and increasing sales over time,” he
said at the summit sponsored by Canadian Business Conferences. While Asian refineries, such as those in China and South Korea, are largely geared towards processing light crudes, Zahar y anticipates that Asia—as is currently the case in much of North America—will eventually make the transition into heavy crude refining, simply because more heavy crude than light will be available in the future. “I think if you tried to move a lot of western Canadian heavy crude into Asia right now, it would be difficult, but I think that market is changing, and I think it’s changing quite quickly as well.” However, as much as Canada’s international prospects for crude oil will diversify in the years ahead, Zahary said he sees one thing staying the same— Canada’s main customer. “I do believe, and will continue to believe, the natural market for western Canadian crude will continue to be U.S. demand over time.” Unfortunately, according to Zahary, western Canadian petroleum products are
heavy crude into Asia right now, it would be difficult.” — John Zahary, Sunshine Oilsands president and chief executive officer
“Western Canadian crude is currently suffering a discount, I believe, to the regional oversupply issue to the inland part of North America, because it doesn’t have the accesses to get it to the edge of the continent. But there are a number of ongoing projects underway that will help to alleviate that.” Zahary said that with increased rail transport and proposed pipeline projects, such as TransCanada Corporation’s Keystone XL and Enbridge Inc.’s Northern Gateway pipelines offering access to new markets, the price of western Canadian crude oil should come more in-line with what other oil-producing regions expect to receive for the same product. “All the projects I think are important, and all I think are constructive to help give this western Canadian crude production an opportunity to get world oil prices.” OIL & GAS INQUIRER • DECEMBER 2012
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General News
Governments in Canada have raised a total of $1.07 billion in land-sale revenue to the end of September, well off the pace set in 2011, thanks largely to a steep drop in Alberta. Over the first nine months of 2011, Canadian governments raised $3.41 billion from land sales, up from $3.04 billion in 2010, and the third-highest tally in the last 10 years. A total of $4.12 billion was raised over the same period in 2008, with $3.71 billion spent in 2006. Average land prices over the first three quarters of 2012 plunged to $295.78 per hectare, down from $846.79 over the same stretch a year ago. The amount of Crown land sold totalled 3.61 million hectares, down from 4.02 million over the first nine months of 2011. Alberta led the way in bonus bid revenue in the first three quarters of 2012, but is well back of last year’s torrid record-setting pace. The province collected a total of $872.66 million in bonus bids from January to September on 2.43 million hectares at an average of $357.98. At the same point in 2011, $3.06 billion in bonus bids had rolled into provincial coffers for 3.46 million hectares at an average of $884.50. The province ended up with a total of $3.64 billion in auction revenue for the full year of 2011, an all-time record. The huge bonus haul and high per-hectare averages paid last year were in large part due to heavy producer spending to tie up land in the Duvernay shale play. Despite the drop in 2012, overall relatively strong spending at land sales in Alberta demonstrates that the Western Canadian Sedimentary Basin still has considerable unconventional prospectivity
After two strong years of land sales, 2012 marked a pullback as explorers worked on proving up already purchased leases.
where explorers are willing to step out and apply modern drilling and completions technology to deeper and more remote areas, analysts say. Over in British Columbia—a mainly natural gas–producing jurisdiction—the province brought in $97.39 million over the nine months ending September 30, on 92,173 hectares at an average of $1,056.61. To the same point of 2011, a total of $123.19 million had rolled into provincial coffers for 121,165 hectares at an average of $1,016.71. Saskatchewan also saw fewer landsale dollars come in over the first nine months of 2012. Bonus bids fell to $78.93 million on 146,073 hectares at an average of $540.38. Over the same period of 2011, industry spent $214.88 million acquiring 420,747 hectares of Crown land at an average of $510.70. On the other side of the coin, in Manitoba, land-sale bonus revenue over the first nine months climbed to $11.13 million as 17,049 hectares exchanged hands at an average of $652.73. Over the same period last year, the province had collected $10.1 million on 17,798 hectares at an average of $567.60. The oil-prone province reached a record $13.14 million for all of 2011. Manitoba had one more sale left this year, scheduled on November 14, to break last year’s watermark. In addition to this, producers acquired a further 1.58 million hectares in workcommitment bids over the first nine months of the year. Total work commitment bids totalled $1.06 billion, mostly from Royal Dutch Shell plc’s $970 million for work bids in Nova Scotia, announced in January, on a total of 1.38 million hectares. — DAILY OIL BULLETIN
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DECEMBER 2012 • OIL & GAS INQUIRER
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Land sales plummet in the first nine months of 2012
General News
Nine-month licence count off 19 per cent from 2011
Permits are down 18 per cent in Alberta in the fi rst nine months of 2012. Saskatchewan permits are
Photo: Joey Podlubny
off 17 per cent, and B.C. permits are off 48 per cent.
Producers across Canada permitted 994 wells in September, bringing the ninemonth count to 10,915 licences. The January-to-September tally is off about 19 per cent from 13,440 well authorizations granted in the comparable period last year. This year’s nine-month total includes 6,037 horizontal wells (excluding experimental wells), or about 62 per cent of the total. Last year, to the end of September, operators had drilled 6,980 horizontal wells (again excluding experimental wells), or 58 per cent of the total. For September, Daily Oil Bulletin records show 595 licences approved in Alberta, 290 granted in Saskatchewan and 69 issued in Manitoba. British Columbia assigned 39
new licences during the month (21 were approved or input). The year-to-date permit count slumped 18 per cent in Alberta to 6,639, down from 8,093 last year, while Saskatchewan’s licence count for January to September declined 17 per cent to 3,249 well authorizations from 3,922 in the comparable period a year ago. In British Columbia, 483 licences have been assigned over the first nine months of the year, off 48 per cent from 924 permits last year. Manitoba is the only province to record an increase in well authorizations at the nine-month mark. Its tally is up 14 per cent to 528 licences from 463 in the January-toSeptember period last year.
To the end of September, records show 7,776 permits were approved in western Canada to drill for oil or bitumen, off 12 per cent from 8,820 licences last year, but still the second-highest tally during the past 10 years. Gas permitting over the first nine months of 2012 totalled 1,291 wells—a decade low—and was off 49 per cent from 2,531 permits last year. In 2005, 14,837 gas wells were licensed to the end of September. This year’s permit count also includes 778 oilsands evaluation wells, down from 1,113 permits issued to the end of September last year. Excluding experimental wells, Canadian Natural Resources Limited led producers by licensing 126 wells in September, including 90 bitumen wells. Second-place Husky Energy Inc. permitted 89 wells, including 67 oil wells. Cenovus Energy Inc. licensed 54 wells, Devon Canada Corporation approved 37 and Northern Blizzard Resources Inc. permitted 29 wells in September. At the three-quarter mark of the year, Canadian Natural is the only operator to crack the 1,000-permit mark. It licensed 1,087 wells (excluding experimental wells) during the January-to-September period, followed by Husky (690), Cenovus (521), Encana Corporation (317) and Crescent Point Energy Corp. (300). Encana licensed 176 gas wells and 75 coalbed methane wells through the first nine months of the year. Canadian Natural is the most active on the bitumen front, with 764 drilling authorizations from January to September, while Husky had 510 oil permits through the first nine months of 2012. — DAILY OIL BULLETIN
OIL & GAS INQUIRER • DECEMBER 2012
31
British Columbia
Red tape threatens B.C. LNG strategy, says Fraser Institute report By Richard Macedo
• Having the NEB conduct a generic hearing on issues in common with anticipated B.C. LNG export applications, such as environmental issues and the impact that such exports would have on British Columbian and Canadian natural gas prices and consumers; • Placing shorter, clearly defined limits on the time that regulators and elected officials may take to review energy project applications and reach decisions; • Involving federal and provincial government and First Nations organizations with industry representatives to identify and approve transportation corridors to be used for infrastructure development; • Requiring a single construction application where an export terminal, facility and new pipeline are being proposed by the same investors; and, • Establishing joint federal-provincial environmental reviews for projects that require approvals from both levels of government, or substitute provincial environmental
assessments that meet the requirements of the Canadian Environmental Assessment Act in place of a federal review. Gerry Angevine, Fraser Institute senior economist and co-author of the report, said that it would likely save money and time if all of the important aspects of an LNG project application (pipeline construction, gasliquefaction facility, marine terminal and shipping, export licence request and related environmental issues) could be addressed via a single regulatory process. “Then the proponent, having submitted a complete application, could plan on having a decision from the regulator in 18 months or less,” he noted. The report highlights examples of lengthy NEB approval hearings, separate environmental reviews conducted by both the federal and provincial governments, and requirements for project proponents to make separate applications for approval of natural gas pipelines and liquefaction facilities, even when both are part of the same project. Angevine noted that the federal government made an attempt earlier this year to streamline regulatory procedures through its responsible resource development plan, but he and his co-author contend that the allowed time frame for reviews remains too long and more could be done to reduce duplication. In the report’s development scenario, LNG exports reach 7.1 billion cubic feet per day by 2032. This assumes that the Kitimat LNG and the BC LNG Export Co-operative projects proceed. It also assumes that LNG Canada, proposed by Royal Dutch Shell plc, Korea Gas Corporation (KOGAS), Mitsubishi Corporation and PetroChina Company Limited, will be developed, along with two additional facilities that were labelled Project A and Project B. Meanwhile, proponents for the Kitimat LNG project proposed by Apache Canada Ltd., Encana Corporation and EOG Resources, Inc. are seeking, but have been
OCT/11 OCT/12
OCT/11 OCT/12
WELLS SPUDDED
49
WELLS DRILLED
49
Apache's Kitimat LNG project could get caught up in a federal and provincial regulatory maze,
Photo: Apache Corp.
according to the Fraser Institute.
The B.C. government’s aim of creating jobs and investment by exporting liquefied natural gas (LNG) to Asia could be at risk unless the existing overlapping regulatory process and environmental reviews can be further streamlined, says a new report by the Fraser Institute. The report, titled Laying the Groundwork for BC LNG Exports to Asia, examines the barriers and obstacles that could delay or inhibit the construction of natural gas pipelines, gasliquefaction facilities and marine terminals critical to building an LNG export industry. To reduce the barriers that could inhibit building a B.C. natural gas export industry, the report makes several policy recommendations, including: • Restricting the scope of the National Energy Board’s (NEB’s) mandate to matters necessary to protect the public interest, such as construction and operational standards and efficiency, property rights and claims, and environmental impacts; BRITISH COLUMBIA WELL ACTIVITY
OCT/11 OCT/12
WELL LICENCES
122
60
▼
39
▼
35
▼
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • DECEMBER 2012
33
British Columbia
unable to secure, an oil-indexed offtake agreement. Potential buyers of LNG may instead be aiming to index prices to lower North American gas prices, according to LNG analysts. The Fraser report touches on price risk in relation to the development of LNG export facilities. For example, it is possible that a significant spot market for LNG supplies could develop in the Asia Pacific region as its dependency on imported LNG grows, the report said. In this regard, though, because importers of gas supplies for power generation and for distribution
to urban centres as a thermal energy source require a high level of certainty about both supply and cost, it is likely that most LNG imports will continue to be subject to contractual arrangements negotiated between sellers and buyers for defined periods. Another possible problem is that—in their haste to secure positions in the attractive Asian LNG market before the current window of opportunity closes—developers of large-volume facilities may be tempted to undercut, and thereby squeeze out, competitors. In doing this, they may negotiate novel pricing arrangements.
This apparently occurred in the proposed Cheniere plant in the Gulf Coast, which reportedly has made deals priced off U.S. gas, which is much cheaper. If this practice were to become widespread, the report noted that it would make it difficult for other developers, like Kitimat LNG, to secure the oil-based pricing upon which their project plans are based. “This struggle for a piece of the action will not be easy,” Angevine said. “Perhaps what this means is that, eventually, only the big-volume players—such as BG and Shell—will be on the podium.”
Offshore presents big opportunity, says Fraser Institute study By Carter Haydu Provincial and federal governments could potentially see major revenue payouts if the federal government were to lift its 40-year informal moratorium on offshore oil exploration off the coast of British
Columbia, says a Fraser Institute study released in late October. “The study shows the benefits of allowing offshore oil in B.C. to greatly outweigh the costs,” said Joel Wood,
senior research economist at the public policy think tank and author of the study, Lifting the Moratorium: The Costs and Benefits of Off shore Oil Drilling in British Columbia.
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DECEMBER 2012 • OIL & GAS INQUIRER
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“The majority of these benefits are actually billions of dollars in government revenue for the provincial and federal governments, which could then be spent on health care, education or other government services.” Wood said his study doesn’t even account for indirect benefits from allowing offshore oil development, such as increased employment opportunities. The study estimates a net benefit of $9.6 billion from a single project offshore in the Queen Charlotte Basin, including the cleanup costs of any spills that might potentially occur. The baseline case assumes an oil price of $90 per barrel, similar to recent prices in Edmonton. A sensitivity analysis shows that the net benefits remain positive as long as the oil price is over $49 per barrel, said Wood. “It’s a pretty conservative estimate because if a world-class regulatory regime was put in place before it proceeded, those costs would be expected to be a lot lower,” he said, adding strong regulations on the industry would mean the net benefit would be even higher than his estimates suggest. The report estimates that there are 9.8 billion barrels of oil and 43.4 trillion cubic
feet of natural gas in the Tofino, Winona and Queen Charlotte Basins. The estimates are based on a Geological Survey of Canada report, as well as a government-commissioned report analyzing the potential benefits and costs of one offshore drilling project. “It’s not this catastrophic environmental scenario that would take place. We have examples from around the world; we have Newfoundland and the United Kingdom, and we have Norway, where these regimes have done offshore oil in a safe manner,” said Wood. However, Greenpeace Canada climate and energy campaign coordinator Keith Stewart suggests the potential risks from offshore drilling are simply too high, and therefore should be set aside in favour of other developments. “Lifting the moratorium would put at risk the more than 40,000 jobs in fisheries, forestry and tourism on the B.C. coast that depend on a healthy environment,” Stewart said. “Canada needs to invest in developing our wealth of renewable resources in a sustainable way, not seeking to squeeze out the last drop of oil from the tar sands or from beneath the ocean.”
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Northwestern Alberta/Foothills
Paramount doing massive build-out of processing capacity in Montney By Pat Roche
Paramount is building massive deep-cut capacity at Musreau and participating in a major expansion of
Photo: Joey Podlubny
the Resthaven plant’s deep-cut capacity.
Paramount Resources Ltd.’s processing capacity will total 73,000 barrels of oil equivalent per day, once projects at its Musreau and Resthaven properties in northwestern Alberta are completed. This would be a huge increase for Paramount, which reported average production of just under 22,000 barrels equivalent per day in the second quarter. Jim Riddell, Paramount’s president and chief operating officer, discussed the infrastructure growth during a presentation on the Montney play at a recent JuneWar ren-Nic k le’s Energ y Group Speaker Series event. Riddell is also chief executive officer of Trilogy Energy Corp. Both Paramount and Trilogy are heavily focused on the Montney. In Paramount’s case, Riddell discussed what the company is doing at its Resthaven/ Musreau/Smoky/Kakwa areas where it is pursuing liquids-rich Montney natural gas.
The company greatly expanded its presence after doing a propane frac on a vertical well, which resulted in initial production rates of between one million and two million cubic feet per day. “We’ve now acquired over 200 sections of land in this area and have another 100 sections of land to the north,” Riddell said. Horizontal wells drilled across the land base last year achieved initial rates ranging between seven million and 12 million cubic feet per day. Because it’s a new area, infrastructure has been a priority for Paramount. “Today, we have about 15,000 barrels equivalent a day of capacity available to us. We produce somewhere in the order of 12,000 or 13,000 barrels equivalent a day,” Riddell said. Paramount is building massive deepcut capacity at Musreau and participating
in a major expansion of the Resthaven plant’s deep-cut capacity. “So that’s going to give us an incremental additional capacity of another 57,000 barrels a day. We’ll have a total of 73,000 barrels a day. That’s a very big deal for Paramount—Paramount produces about 20,000–25,000 barrels a day today, and we’re going to see our production double or triple over the next few years,” he said. Meanwhile, the company is making sure it’s drilling enough wells to start filling up its new infrastructure when it comes on stream. “We have 20 or 30 wells now drilled or completed behind pipe waiting to come on stream, and will have an estimated first-month deliverability of 35,000 barrels equivalent a day at the end of Q2,” the Paramount president said. The company previously reported the Musreau deep-cut facility is to be commissioned in the second half of 2013. Production is expected to more than double once the deep-cut Musreau and Smoky facilities are fully operational in 2014. Regarding the grow th platforms for Paramount and its affiliate, Trilogy, Riddell said all the near-term growth opportunities for both companies are in the Montney. “I didn’t really consider us to be as much an exclusive Montney player as we really turned out to be,” he said. Trilogy began drilling horizontal wells into the Montney at its Presley, or Kaybob South, gas play. Since 2008, the company has continued to improve its application of technology and its well results. It began with one well per section and one frac per section. Then it increased to three wells per section and seven frac stages per well, for a total of 21 fracs per section. That increased to five wells per
NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY
OCT/11 OCT/12
WELL LICENCES
324
264
▼
OCT/11 OCT/12
WELLS SPUDDED
281
186
▼
OCT/11 OCT/12
WELLS DRILLED
297
174
▼
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • DECEMBER 2012
37
Northwestern Alberta/Foothills
section and roughly 20 fracs per wellbore— or about 100 fracs per section, resulting in much better recoveries and economics. Riddell said the gas wells Trilogy is now drilling are economic even with gas at $3.50 per million British thermal units. Like Paramount, Trilogy has been steadily adding infrastructure and continues to add compression and dehydration in the field. From a standing start in 2000, processing capacity has grown to about 85 million–90 million cubic feet per day. Wells cost roughly $5 million and produce about three billion cubic feet of gas at 30 barrels of natural gas liquids per million cubic feet. As gas prices crashed, Trilogy took its knowledge of how to develop horizontal gas wells in the Montney and applied it to oil, drilling about 21 Montney oil wells last year. The company has drilled about 10 so far this year and plans to drill 10 more before year’s end, for a total of roughly 40 for both years. “We have grown the [Montney oil] production from zero to 5,000 barrels a day through 2011, [to] probably around
38
DECEMBER 2012 • OIL & GAS INQUIRER
10,000 barrels a day by the time we’re done this year,” Riddell said. With solution gas added in, the total output from Trilogy’s Kaybob Montney oil development is expected to reach about 11,000 barrels per day this year. Including the acquisition of about 50 sections of land, Trilogy has spent about $300 million on its Kaybob Montney oil development and has already produced 2.5 million barrels, Riddell noted. He said the wells have “very steep” declines, coming on at 1,000–3,000 barrels per day or more, then flattening out at longterm rates of about 100 barrels per day. Trilogy believes it can recover 100 million barrels of Montney oil over 10 years and double its production to more than 20,000 barrels per day for a recovery factor of roughly 20 per cent. Commenting on lessons lear ned developing Montney gas and oil at both companies, Riddell said “location matters.” He said the quality of the Montney varies widely across the 350-by-50-mile fairway straddling the Alberta-B.C. border. “We have experience...principally in the southern part of the trend in the Alberta
side of the basin, [but also] in northeastern B.C. in some of the Paramount projects.” Well orientation also matters. Riddell acknowledged there are advantages in drilling the horizontal wells in a northwestsoutheast orientation—perpendicular to the principal stress—but said Trilogy and Paramount do otherwise to be able to drill more wells without compromising the results. “I think we have been a bit of a pioneer in not just drilling our wells northwestsoutheast,” he said. The companies are also a bit of a maverick in their choice of completion fluid for the Montney. Riddell said Paramount and Trilogy are among the few producers that frac “almost exclusively” with oil rather than cheaper completion fluids. While acknowledging producers prefer to put oil priced at nearly $100 per barrel into sales pipelines rather than down a wellbore, Riddell said using oil as a frac fluid “gives us, so far, a better well than we would otherwise get.” He said using oil to frac produces better well results and economics, which in the long run means lower costs.
Northwestern Alberta/Foothills
Photo: Joey Podlubny
Athabasca’s Kaybob light oil volumes jump
Athabasca has drilled eight wells in the Montney and Duvernay in the second quarter.
Thanks to successful drilling and a newly tied-in production facility at Kaybob West, Athabasca Oil Corporation reported 3,500 barrels per day of light oil volumes in the third quarter, up sharply from the roughly 800 barrels per day the company posted in this year’s second quarter. At that, the latest figure does not include about 7,000 barrels per day that the producer still has behind pipe. If all goes as planned, Athabasca’s light oil production should rise to 10,000–11,000 barrels per day by year-end, Sveinung Svarte, Athabasca president and chief executive officer, said in a conference call. In its light oil division, the third quarter was active from a drilling, completions and construction point of view, as Athabasca continued with construction of three batteries in its Kaybob West, Kaybob East and Saxon areas. In October, Athabasca commissioned the Kaybob West battery, bringing light oil volumes to over 3,500 barrels equivalent per day. The company said its Kaybob East battery will be commissioned in late
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November, and the Saxon battery in early December, setting the stage for Athabasca to reach year-end volumes of 10,000– 11,000 barrels per day. Also during the quarter, the company rig-released eight horizontal wells, all targeting unconventional reservoirs in the Montney and Duvernay formations, and completed 11 horizontal wells. All of the wells were successful and have met or exceeded the company’s type curve, management said. Also in the quarter, Athabasca drilled and completed a second horizontal Duvernay well at Saxon, Alberta (06-1062-23W5). The well was shut in to allow absorption of load f luid by the undersaturated formation and to enhance production. The well will be put on production when the Saxon battery is commissioned in December. Athabasca is working to reduce costs on its horizontal Montney wells from an average of about $4.5 million to about $3.7 million per well. — DAILY OIL BULLETIN
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Cenovus output rockets By Lynda Harrison
through the quarter to more than 63,000 barrels per day net, mainly due to improved well performance and plant optimization, said Ferguson. Throughout the quarter, production at Foster Creek consistently exceeded the project’s original design capacity by about five per cent, averaging more than 126,000 barrels per day (63,000 net). At Pelican Lake, volumes increased 16 per cent compared with the same quarter of 2011, averaging more than 23,500 barrels per day. Cenovus presents production volumes on a net-before-royalties basis. Steam to oil ratios (SOR) averaged about 1.9 at Christina Lake and about 2.1 at Foster Creek for a combined SOR of around two. “Cenovus has delivered another strong quarter highlighted by production growth across all of our oilsands operations, combined with refining results that affirm the
value of our integrated strategy,” Ferguson said. “This has all resulted in the strongest quarterly financial performance in our three-year history.” At Foster Creek and Christina Lake, supply costs are approximately $35–$45 per barrel. Supply costs are calculated as the long-term average West Texas Intermediate (WTI) oil price required to achieve a nine per cent after-tax return after all capital, operating and maintenance costs are considered. About 12 per cent of current production at Foster Creek comes from 48 wells using Cenovus’s patented Wedge Well technology. Ten additional wells using this technology are expected to have steam stimulation completed and be online before the end of 2012. Christina Lake is also beginning to see positive results from four wells using this technology, currently producing about 1,100 barrels per day. Operating costs at Christina Lake were $13.59 per barrel in the third quarter, a 41 per cent decrease from $23.01 per barrel in the same period a year earlier due to the significant increase in production. Operating costs at the project are expected to be lower than initially anticipated and the company has adjusted its fullyear guidance to $12.70 per barrel. Non-fuel operating costs at Christina Lake were $11.03 per barrel in the quarter, a 43 per cent decrease from $19.44 per barrel in the third quarter of 2011. Operating costs at Foster Creek averaged $11.50 per barrel in the third quarter, a four per cent increase from $11.11 per barrel in the same period last year. The increase is primarily due to higher staffing levels in preparation for the Phase F expansion and increased well workovers. The company expects operating costs at Foster Creek to average $12.05 per barrel for the full year, which is within the company’s original guidance range.
OCT/11 OCT/12
OCT/11 OCT/12
WELLS SPUDDED
107
WELLS DRILLED
102
Production volumes increased by 12 per cent at Foster Creek (pictured) and by more than threefold at
Photo: Joey Podlubny
Christina Lake.
Cenovus Energy Inc.’s third-quarter 2012 oilsands output improved 44 per cent over the same quarter a year ago to more than 95,000 barrels per day net, with the help of Christina Lake whose output soared more than threefold and Foster Creek whose volumes increased 12 per cent. According to Brian Ferguson, president and chief executive officer, the company is on track for “another great year, both operationally and financially.” Christina Lake production grew more than threefold in the third quarter compared with 2011, thanks to strong Phase C well performance and the start-up of Phase D in late July, approximately three months ahead of schedule, he said. The project’s output averaged more than 32,000 barrels per day net, reaching a singleday high of 43,500 barrels per day net. Foster Creek production averaged five per cent above current design capacity NORTHEASTERN ALBERTA WELL ACTIVITY
OCT/11 OCT/12
WELL LICENCES
69
181
▲
182
▲
195
▲
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • DECEMBER 2012
41
Northeastern Alberta
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Suncor’s Firebag production reaches design capacity Suncor Energy Inc.’s Firebag in situ oilsands project has reached full design capacity of nearly 120,000 barrels per day. First oil at Stage 3 of the steam assisted gravity drainage (SAGD) facility was brought online in August of last year, and with the application of infill well technology, the pace of production ramp-up exceeded previous expectations. Production at the Firebag complex averaged 113,000 barrels per day in the third quarter of 2012 with exit rates of approximately 120,000 barrels per day. Quarterly production was up over 100 per cent from last year’s third-quarter production of approximately 55,000 barrels per day.
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In addition, the Firebag Stage 4 facility was safely commissioned during the third quarter of this year and steaming of the wells has begun. First oil is expected by year-end, approximately three months ahead of the original schedule, and the project is approximately 10 per cent under the current budget estimate of $2 billion. “We’re seeing strong results from our disciplined focus on management of cost and quality—an excellent example of our commitment to create value for investors,” Steve Williams, Suncor president and chief executive officer, said in a news release. The expected total production from the Firebag complex will rise to approximately 180,000 barrels per day once Stage 4 reaches full planned capacity. There is significant integration between Firebag stages 1–4 allowing operational flexibility to optimize production, maintenance, reliability and costs. “The Firebag resource continues to provide among the most productive wells in the industry from one of the largest resource basins in the world,” he said. “Firebag is a high-quality asset and a crucial component of our oilsands portfolio.” — DAILY OIL BULLETIN
42
DECEMBER 2012 • OIL & GAS INQUIRER
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Flexpipe Systems, a subsidiary of ShawCor Ltd., is the industry leader in the manufacturing of flexible, composite pipe. Flexpipe Systems offers a full-service solution for clients’ needs, providing the most reliable pipeline material in the market, with a 17,000-km installation base of materials that extends over three continents. Installation of Flexpipe Systems’ prefabricated pipeline system—fast, efficient, safe and reliable—solves the technical and corrosion challenges that are present in steel infrastructure. “More and more, Canada is becoming a regulated environment. Companies can’t afford to have a line rupture from corrosion, so they are looking to composite materials such as those offered by Flexpipe Systems to solve the inherent corrosion issues involved in oil and gas production in the WCSB,” says Aethan Sakell, Flexpipe Systems Business Development Manager – Canada. “By making a shift to composite, you save capital upfront on installation and infrastructure costs, and reduce the ongoing costs of ownership.” With Flexpipe Systems, customers typically see upwards of 25 per cent savings in installation costs, according to Steven Gouthro, Flexpipe Systems Sales Manager – Canada. As an example, over two years ago, a large E&P company saved $2.5 million in operational costs by owning and operating 180 km of FlexPipe Linepipe. Flexpipe Systems’ suite of patented composite products includes: • FlexPipe Linepipe, a spooled, readymade pipeline system; • FlexPipe Linepipe High Temperature, capable of handling continuous service temperatures up to 180˚F (82˚C); • FlexCord Linepipe, suitable for systems with severe pressure pulsations with frequent on-off cycles. “With readily available and locally manufactured inventory, coupled with rapid installation, customers are seeing huge economic benefits,” Sakell says.
“Companies can get their production online faster, because you can build a composite gathering system using Flexpipe products in two-thirds of the time it would take you to build an equivalent steel system.” Flexpipe products require minimal equipment and manpower to install. With spool lengths of up to 1,100 metres, the pipeline system can be deployed with a highly reliable mechanical fitting system in as little as two hours. In addition, customers can expect a smaller environmental footprint and impact than traditional pipelining systems. Flexpipe Systems prides itself on the excellent engineering support it provides to customers. The Company’s applications engineering group reviews the operating parameters of each potential project to ensure successful operation over the life of the pipeline. “We are driving innovation in the industry,” Gouthro says. “We want to be the long-term, reliable solution.” “We want to be the industry leader in pipelining. Our goal is to be the solution both technically and commercially for our entire customers’ pipelining requirements,” Sakell says. “We’ve built higher pressure and higher temperature products based on changing customer demands; we’re now building larger diameter pipe. We will be able to handle the demands, not only for oil and gas, but every other industry that wants to look to us.” Going forward, the industry’s drivers of growth in western Canada will be tight oil, tight gas, in situ production and
enhanced oil recovery programs. Flexpipe Systems provides high-level engineered solutions for its clients—and wants to be the first place clients turn to for solutions. “Flexpipe Systems product lines and technology are the future of the pipeline industry, not only in North America, but globally,” says Sakell.
Contact: Steven Gouthro Sales Manager – Canada Flexpipe Systems
(403) 503.0548 E: sgouthro@flexpipesystems.com www.flexpipesystems.com
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Central Alberta
EOR pipeline work continues as Northwest Upgrader sanctioned By Pat Roche
spurring EOR in central Alberta’s mature oilfields, the Alberta Carbon Trunk Line (ACTL) will divert CO2 from the atmosphere as part of the province’s greenhouse gas emissions reduction strategy. Privately held Enhance plans to build a 240-kilometre, 16-inch-diameter pipeline capable of shipping 40,000 tonnes of CO 2 per day. The initial volume of about 5,000 tonnes of CO2 per day will come from the upgrader/refinery and an Agrium Inc. fertilizer plant, both northeast of Edmonton. The proposed pipeline will initially ship CO2 to a mature lightoil property at Clive in central Alberta, wh ic h E n ha nce ow n s joi nt ly w it h Fairborne Energy Ltd. Enhance and the Alberta government hope more oil producers will sign up to take CO2 once the pipeline is built, resulting in other EOR projects being announced.
About 800–1,600 tonnes per day of CO2 will come from Agrium. Enhance is depending on the planned upgrader/refinery to supply the rest of the pipeline’s initial 5,000 tonnes per day. Speaking at a Petroleum Technology Alliance Canada (PTAC) CO2 conference, Enhance president Susan Cole said detailed engineering for the Agrium carbon capture facility has been done. All of the major mechanical equipment has been procured and the on-site tie-in to Agrium plant completed. “We have purchased all the major mechanical equipment for the site; it has already started showing up. So we’ve made quite a bit of progress on the Agrium capture facility,” she said. “We decided to build that adjacent to the site. We were originally going to build it inside the Agrium facility, but it just made more sense to move it just to the edge. That project should be starting construction next year.” The Agrium capture facility will include dehydration equipment because the CO2 is wet. Otherwise, the Agrium stream is a highly pure form of CO2 needed for EOR. (Most industrial facilities—such as coalfired power plants—emit a highly diluted CO2 stream which is too costly to purify.) Enhance is currently doing detailed engineering for the CO2-capture facility at the upgrader/refinery and “we should be moving into procurement next year,” Cole said. As for the pipeline itself, surveying and construction plans should be complete by the end of this year, and specifications for the pipe have been finalized. “And the next step...is to just purchase the pipe, and that doesn’t take a very long time,” she added. “So we would be looking at construction for the pipeline probably in 2014.” The models for the Enhance project are the CO2-based EOR project, that has operated at Weyburn in southern Saskatchewan for more than a decade, and the Alberta Gas Trunk Line (AGTL).
OCT/11 OCT/12
OCT/11 OCT/12
WELLS SPUDDED
318
WELLS DRILLED
337
Agrium is supplying as much as 1600 tonnes per day of CO2 to the project, which will be used for
Photo: Joey Podlubny
EOR projects.
Work towards the pipeline meant to kickstart CO2-based enhanced oil recovery (EOR) in Alberta is continuing while the planned upgrader/refinery that will be the pipeline’s main supplier is expected to begin construction this spring. North West Redwater Partnership (NWR), a partnership between North West Upgrading Inc. and Canadian Natural Resources Limited, approved the construction of Phase 1 of the Sturgeon Refinery in November. The first 50,000-barrel-per-day phase of the bitumen refinery has a cost estimate of $5.7 billion and is expected to take approximately three years to build, with above ground construction starting in spring 2013. Meanwhile, Enhance Energy Inc., which was chosen by the Alberta government to build the pipeline and related CO2 capture facilities, is continuing preliminary work. Besides CENTRAL ALBERTA WELL ACTIVITY
OCT/11 OCT/12
WELL LICENCES
273
256
▼
215
▼
216
▼
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • DECEMBER 2012
45
Central Alberta
The AGTL was a natural gas pipeline system initiated by the Alberta government in the 1950s. In the early decades of Alberta’s oilpatch, natural gas was seen mostly as a hindrance to oil production and about a trillion cubic feet of gas was flared before the province’s Energy Resources Conservation Board was created to conserve the resource.
In a move that helped spur the development of Alberta’s natural gas industry, the government facilitated the creation of the AGTL to get the gas to the market. That initial trunk line grew into today’s massive province-wide natural gas pipeline system that is owned and operated by the private sector.
The thinking behind Enhance’s ACTL is similar. Today, roughly 70 per cent of Alberta’s light oil reserves are left in the ground after primary and secondary production end. Studies have indicated more than a billion barrels of additional light oil could be recovered from Alberta’s mature fields by injecting CO2.
Bellatrix expects to beat 2012 production estimate Despite light ning, hail and intense rain–caused power outages, as well as violent storms shorting out electrical panels and creating significant downtime in the processing portion of production, Bellatrix Exploration Ltd. expects to meet its previously announced 2012 average daily production guidance of 16,500 –17,000 barrels equivalent per day, and an exit rate of 19,000–19,500 barrels per day. However, average third-quarter sales volumes were negatively impacted by protracted spring breakup conditions, scheduled plant turnarounds, as well as a series of intense localized storms delaying third-quarter drilling, completion and tie-in programs. In a recently released third-quarter update, Bellatrix announced July-toSeptember sa les volumes averaged 15,503 ba r rel s equ iva lent per day (weighted 34 per cent to oil, condensate and natural gas liquids, and 66 per cent to natural gas). Production for October, based on field estimates, was 18,300 barrels per day (weighted 34 per cent to oil, condensate and natural gas liquids, and 66 per cent to natural gas). Field-production estimates for the end of October are 19,000 barrels per day, carr ying the same weighting as the month’s average. Bel lat r i x dr il led nine (7.71 net) wells consisting of seven (6.21 net) Cardium oil wells and t wo (1.5 net) liquids-rich Notikewin/Falher gas wells in the third quarter. During the first nine months of 2012, Bellatrix posted a 100 per cent success rate drilling and/or participating in 24 (20.15 net) wells, resulting in 18 (15.15 net) Cardium oil wells, two (two net) Cardium condensate-rich gas wells, one 46
DECEMBER 2012 • OIL & GAS INQUIRER
(one net) Duvernay gas well and three (two net) Notikewin/Falher liquids-rich gas wells. In the Brazeau area of west-central Alberta, the company recently completed a long-reach Cardium horizontal oil well (50 per cent work ing interest) to a total depth of 5,014 metres with a 2,767-metre horizontal leg. Average product ion volumes over t he init ia l 30 days of production, based on field
expenditure program of $180 million, which is anticipated to be finalized in the fourth quarter of 2012. Based on the timing of proposed ex pendit ures, dow ntime for anticipated plant turnarounds, resolution of infrastructure constraints and normal production declines, execution of the 2013 budget is a nt icipated to pro vide 2013 average daily production of approximately 20,000 –21,000 barrels
The company has developed an inventory of 644 net remaining Cardium locations and 354 net Notikewin/Falher locations. estimates, was 1,062 barrels equivalent per day—70 per cent oil and liquids with 30 per cent gas. During the fourth quarter of 2012, the company expects to drill an estim ated si x (4.85 net) C a rd iu m oi l wells that include a second long-reach Cardium horizontal well (programmed to drill to a total depth of 5,511 metres, including a horizontal length of 3,048 metres) in the Brazeau area. With reductions in industry activity levels, Bellatrix—through negotiation—has reduced its average cost base per well by 10 per cent and expects to carry these savings through the winter of 2012/13. The company is also moving to pad drilling wherever plausible to bring down the capital cost per well. Management is proposing a 2013 capital
equivalent per day, and an exit rate of approximately 21,500 –22,500 barrels equivalent per day. T he compa ny has developed a n inventory of 644 net remaining Cardium locations and 354 net Notikewin/Falher locations, representing a net remaining investment of $3.95 billion. As of September 30, Bellatrix has approximately 197,428 net undeveloped acres and, including all opportunities, has in excess of 1,525 net exploitation drilling opportunities identified, with capital requirements of $6.98 billion representing over 40 years of drilling inventory based on current annual cash f low. The company continues to focus on adding Cardium and Notikewin prospective lands. — DAILY OIL BULLETIN
Central Alberta
Wilrich “extremely economic” at $3.50 gas price, conference hears The Wilrich natural gas play would be “extremely economic” at an Alberta gas price of $3.50 per thousand cubic feet, but the shallower areas of the play are challenged at current prices. At t he Canadian Societ y for Unconventional Resources’ annual conference, geologist Dave Jenkinson and engineer Brian Hamm—both of McDaniel & Associates Consultants Ltd.—did a joint presentation on the findings of their recent study, titled “How Rich is the Wilrich?” The Wilrich reservoir is widely deposited in varying thicknesses and quality over an area spanning more than 200 miles in the Cretaceous-age Deep Basin fairway of northwestern Alberta. The study—which was limited to where there has been production from horizontal wells—included areas such as Kakwa, Resthaven, Sundance, Ansell, Simonette, Pine Creek and Edson. Based on more than 2,600 wells drilled to date, the McDaniel colleagues found early horizontal production results have been encouraging with the deep high-pressure areas of the reservoir significantly outperforming the shallower areas of the play. “It appears to be at this point the most important factor in these wells,” Hamm said of the correlation between reservoir depth and well performance. With natural gas liquids recoveries in the 10–30 barrels per million cubic feet of gas range, “half-cycle economics are pretty challenged for some of these plays right now at this gas price,” Hamm said. The AECO spot price has been well below $3 per gigajoule for many months. He said deep-cut liquids-extraction plants would defi nitely help the economics if producers foresee a “sustainable” gas price. But Hamm emphasized the amount of original gas in place is enormous and “there is a lot of gas out there that is extremely economic at $3.50.... So in a $3.50-per-thousand-cubic-feet world, I think you drill like crazy in this play.”
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Southern Alberta
Rent-based royalties more efficient, says tax expert By James Mahony
rate of return on capital. “A pure rent-based [royalty] will neither discourage nor encourage an investment or production decision, since it is neutral,” he said. The best kind of royalty system is a rentbased one, combined with a relatively “clean” corporate income tax, he said, describing Alberta’s current oilsands royalty structure as “the poster child for how to do an appropriate, rent-based tax.” The benefit of a rentbased royalty is that production costs are fully deductible under the system. Looking further afield, he did not have similar praise for royalty regimes in the other provinces studied, describing some as “amazingly complex.” Others are less competitive, while still others offer various kinds of differential treatment, depending on the kind of assets being evaluated. “Canada’s provinces tend to implement far too complex royalty systems, particularly Newfoundland and Nova Scotia, but also shale gas in B.C. [which uses a Nova Scotia– style system]. These are complex, very distortionary and very poor revenue collectors. They’re not really the appropriate approach for royalty design in the future.” In Nova Scotia, he said royalties are low largely due to the fast write-offs that
the province allows producers. Australia allows deductions for exploration to be carried forward at a generous rate, he said, arguing that’s the problem both with Nova Scotia’s and with British Columbia’s shale gas royalty as well. Yet, when it comes to royalties on conventional oil and gas, he said Alberta, British Columbia and Saskatchewan impose the highest fiscal burdens, since they use revenue-based royalty regimes in which royalties are based on a percentage of production revenue. In assessing the various jurisdictions, Mintz and Chen looked both at marginal tax rates and royalties in the province or country concerned. As western Canada’s conventional oil and gas production continues to decline, and more production is drawn from unconventional resources, whether shale gas or tight oil, he suggests the province should think a little more about a rentbased approach to royalties. “Alberta’s potentially got some significant tight oil and unconventional sources of gas, so if you’re going to introduce new royalty regimes, now is the time to start thinking about rent-based systems as opposed to the old conventional ones.” The problem with revenue-based royalties, he said, is that they tend to discourage investment at the margin, because they don’t allow for deduction of the production costs involved. In effect, revenuebased royalties take from the top line of what a company earns, he said. Among other things, the U of C royalty study concluded that the fiscal burden on the energy sector in Canada is higher than on the country’s other industrials sectors. “I’ve argued for a neutral corporate income tax across all business activities, that all industries should have the same tax burden on their investments,” Mintz said.
OCT/11 OCT/12
OCT/11 OCT/12
WELLS SPUDDED
156
WELLS DRILLED
163
A rent-based system makes more sense for tight oil and shale gas plays, says University of Calgary
Photo: Joey Podlubny
economist Jack Mintz.
As Canada turns increasingly to unconventional resources like tight oil and gas, provincial governments should consider moving from revenue-based to rent-based royalty regimes, tax expert and academic Jack Mintz said in Calgary in October. “For Alberta and other provinces looking at new types of finds, whether it’s New Brunswick shale gas or Alberta tight oil, in designing royalty systems, we should be looking at rent-based systems,” he said. Mintz was discussing a recently published study of oil and gas royalties authored by him and Duanjie Chen, a colleague at the University of Calgary’s (U of C) School of Public Policy. The study reviewed royalty regimes in five Canadian provinces, four U.S. jurisdictions, Australia, Brazil, Norway and the United Kingdom. Concluding that Canada falls roughly in the middle of the pack in terms of competitiveness and neutrality, Mintz said there was nonetheless a “great deal of disparity among the provinces.” He explained rent-based systems by referring to the concept of “economic rent”: the difference between the revenues a resource generates and the costs of production, including capital, labour costs and a SOUTHERN ALBERTA WELL ACTIVITY
OCT/11 OCT/12
WELL LICENCES
100
111
▲
101
▼
99
▼
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • DECEMBER 2012
49
Southern Alberta
Revenues were down for drilling contractors in the third quarter with activity down almost 30 per cent.
A weakened North American drilling market saw earnings for Precision Drilling Corporation slip nearly 53 per cent in the third quarter, while year-to-date profits were roughly flat. Nonetheless, the company will boost this year’s capital spending 5.3 per cent, to $921 million from a planned $875 million, due mainly to spending on rig upgrade contracts and two new well-servicing rig contracts. Precision president and chief executive officer Kevin Neveu chalked up the quarter’s weaker earnings to a recovery that never took hold. “The seasonal recovery in drilling activity never fully materialized, with Canadian industry drilling activity down 29 per cent from this time last year,” he said, noting the U.S. rig count is down 10 per cent from this time last year and seven percent below the beginning of the third quarter.” Across North America, despite healthy oil prices, demand from Precision’s customers slipped as producers moderated spending in the year’s second-half to stay within their capital budgets, Neveu added.
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In Canada, Precision’s drilling rig utilization days fell 26.4 per cent in the quarter, to 7,735 days from 10,505 days in last year’s period, while in the United States, utilization days dropped 14.5 per cent, to 8,305 days from 9,716 days in last year’s third quarter. In terms of well-servicing rigs, the contractor reported that service rig operating hours in the third quarter fell 15.5 per cent, to 72,766 hours from 86,146 hours in last year’s comparable period. As for metres drilled, Precision drilled 1,491 metres in Canada during the third quarter, down from 1,594 metres drilled in last year’s third quarter. Also in the third quarter, average revenue per day fell from the second quarter by US$35 and C$550 in the U.S. and Canadian operations, respectively. Declines in spot market pricing were the main reason for the decreases in the United States and Canada, while revenue from winter-related operations in the second quarter also contributed to the decrease in Canada. — DAILY OIL BULLETIN
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Saskatchewan
Legacy builds up Manitoba, North Dakota production
capability of a number of these Pierson wells would range from 120 to 280 barrels of oil equivalent per day—well in excess of the currently constrained rates. The company believes these achievements will lead to superior long-term performance, higher per-well reserve bookings and additional locations booked. Legacy has continued to improve capital efficiencies in the Spearfish play in Pierson. Through a combination of reduced day rates for both drilling and stimulation services and improved operations execution, wells drilled in Pierson over the first nine months of 2012 have drill, complete, equip and tie-in costs of less than $1.5 million. Wells drilled in the most recent quarter have all-in capital costs between $1.2 million and $1.3 million. Average number of drilling days has been reduced
from 10 days in 2011 to six to seven days in the most recent quarter. This excellent performance has been on long horizontal wells, which are typically drilled across an entire section. Operating costs continue to be reduced as additional wells are tied in to the central oil battery. Current operating costs in Pierson are down 35 per cent in the third quarter of 2012 from the third quarter of 2011. At Bottineau County, no new operated wells were brought on production in the quarter; however, the company anticipates having six (4.5 net) additional wells on production in the fourth quarter of 2012. The first two wells of this recent program have come on production at an average production rate of more than 150 barrels per day per well. Legacy has achieved these rates while constraining production to maximize ultimate recovery as all wells carry fluid levels. The company said that it has also continued to improve capital efficiencies in the Spearfish play in Bottineau County. Through a combination of reduced day rates for both drilling and stimulation services and improved operations execution, wells drilled in Bottineau County in the last half of 2012 have drill, complete, equip and tie-in costs of less than $1.6 million. Wells drilled in the most recent quarter have all-in capital costs between $1.4 million and $1.5 million on an all-in basis. Average number of drilling days has been reduced from 12 days in 2011 to seven to eight days in the most recent quarter. Similar to Pierson, this excellent performance has been on long horizontal wells that are typically drilled across an entire section. The total Spearfish play development drilling inventory of 440 net potential locations (88 per cent unbooked) is based on eight wells per section. Based on other operators’ results in the play, Legacy’s location count could
OCT/11 OCT/12
OCT/11 OCT/12
WELLS SPUDDED
354
WELLS DRILLED
368
Legacy took part in 18 wells in the Spearfish play in the third quarter, and continues to drive down
Photo: Pipeline News
drilling and completion costs.
Legacy Oil + Gas Inc. had an active third quarter with the drill bit, punching 46 (36.2 net) wells with a 100 per cent success rate. The total included 18 (14.6 net) horizontal wells in its Spearfish play at Pierson, Man., and Bottineau County, N.D. The company said it continues to be on track to meet its full-year production guidance. At Pierson, Legacy continued to deliver excellent production results in the Spearfish, compared to both the previous operator’s drilling and the type curve used in the 2011 year-end independent engineering report. Legacy has achieved these rates while constraining production to maximize ultimate recovery. The company said that all recent wells carry significant fluid levels, with some wells having fluid just below surface. Legacy estimates that initial productive SASKATCHEWAN WELL ACTIVITY
OCT/11 OCT/12
WELL LICENCES
375
329
▼
341
▼
350
▼
Source: Daily Oil Bulletin
OIL & GAS INQUIRER • DECEMBER 2012
51
Saskatchewan increase by 50 per cent through downspacing. In addition, the company is evaluating the waterflood potential in the play and anticipates recovery factors of up to 14 per cent, based on analogous pools. In its Bakken play at Star Valley, Legacy has applied its leading fracture stimulation design developed in Heward to this area with good success. Legacy brought 11 (7.8 net) wells on production since the start of the third quarter of 2012 and these wells have average 30-day initial rates of 200 barrels equivalent per day per well. As previously disclosed, the company believes the Bakken play boundaries have expanded and has increased its drilling location inventory to more than 50 net wells in Star Valley. At Taylorton, Sask., the company has continued to observe improved waterflood response in the original pilot area. The
91/12-29 horizontal well has seen its oil production rate increase to nearly 50 barrels per day, with a corresponding increase in fluid rate, fluid level and reduction in water cut. The pilot was expanded into section 28 in July 2012. Continuous improvement of drilling and completion practices has resulted in a reduction in capital costs in Taylorton, with drilling, completion, equip and tie-in costs for recent wells being 15 per cent less than historical costs. At Heward, the pilot waterflood project initiated in December 2011 continues to demonstrate waterflood response as the oil production rate in eight offsetting wells has increased since the start of the pilot. Individual well oil production rates are up 50–500 per cent from prior to initiation of the waterflood. Plans are underway for expansion of the pilot waterflood project in the latter part of 2012.
Legacy also remained active drilling conventional Mississippian horizontal wells throughout its southeastern Saskatchewan properties. These wells typically cost approximately $1 million to drill, complete, equip and tie in as they generally are not fracture stimulated and have excellent rates of return and quick payouts. At A lameda /Steelman, the company said its recent wells targeting the Frobisher and Midale have achieved “tremendous production results.” Five of the wells drilled in the third quarter of 2012 have average 30-day initial production rates of 440 barrels per day per well. The majority of these wells carry high fluid levels. The company has identified a significant number of follow-up locations in both areas. — DAILY OIL BULLETIN
Renegade grows through acquisitions As part of several transactions geared to remaking itself, Renegade Petroleum Ltd. plans to acquire a package of crude oil properties in southeastern Saskatchewan for about $405 million. The junior said it was taking steps to become a light oil based, income-plusgrowth company. As part of the plan, Renegade’s board has conditionally approved a monthly dividend of 0.0192 cents per share. If the Saskatchewan acquisition closes, Renegade will gain light oil assets that produce about 3,600 barrels equivalent per day from an unnamed senior producer.
The junior drilled 24 (20.2 net) wells in the quarter, including 14 (10.2 net) wells in southeastern Saskatchewan and 10 net wells in the Viking in west-central Saskatchewan. Renegade described the Saskatchewan properties as “low-decline, long-life, highnetback” light oil assets ideally suited to generate sufficient free cash flow to 52
DECEMBER 2012 • OIL & GAS INQUIRER
pay dividends after funding production growth, while retaining flexibility to pay down debt, raise the dividend and/or accelerate production growth. Management said the properties are high-working-interest (86 per cent), high operatorship (83 per cent), consisting of proved, developed producing reserves representing 81 per cent of total proved reserves and 57 per cent of total provedplus-probable reser ves. The package includes up to 219 square kilometres of 3-D seismic and up to 599 kilometres of 2-D seismic. The assets include infrastructure process facilities, water disposal and storage capacity within Renegade’s core southeastern Saskatchewan areas, providing synergies between Renegade’s assets and the new assets. Renegade said the assets include a “significant lowrisk development inventory of over an expected 240 [gross] low-risk development locations.” On a go-forward basis, Renegade will focus most of its 2013 capital program on two core areas in southeastern Saskatchewan, and on the Viking play in west-central Saskatchewan. Renegade also has a number of higher-growth properties in key plays such as the Slave Point
oil play, “which have significant economic value but are not ideally suited to an income-plus-growth model.” For these properties, the company said it is considering potential joint-venture partners. Renegade also updated investors on operations, noting it was “extremely active” in the third quarter on its southeastern and west-central Saskatchewan properties. In all, the junior drilled 24 (20.2 net) wells in the quarter, including 14 (10.2 net) wells in southeastern Saskatchewan and 10 net wells in the Viking in west-central Saskatchewan. During the quarter, the company boosted sales volumes to about 3,923 barrels per day (96 per cent light oil and natural gas liquids), a 38 per cent increase from 2,852 barrels per day reported in last year’s third quarter. A l so i n t h i s yea r ’s t h i rd qua rter, Renegade finished construction of its Redvers facility in southeastern Saskatchewan, which management said will allow for significant unoptimized production to come on stream in the fourth quarter. As well, the company demonstrated further improved production results from its Frobisher and Souris Valley trends, management said. — DAILY OIL BULLETIN
BUSINESS
BUSINES INTELLIGENCE
Hand-held devices support oil and gas field production services
By Darin Hauck, senior vice-president, energy and industrial services, Clean Harbors
Production support services are critical to efficient oil and gas field opera-
dispatched to the site, complete the job, fill out the worksheet on the hand-
tions The companies that provide these load-based services must be
held device, get the customer’s signature and electronically file it back to the
responsive to the work requests in order to help their customers avoid pro-
office for review, processing and billing
duction interruptions This kind of responsiveness demands a sophisticated
At Clean Harbors, we keep the dispatch function in our local offices so
support infrastructure because load-based jobs require a ton of documen-
that the local dispatchers know the customers and can give them an esti-
tation, from dispatch orders to invoices, that has to be accurate, timely and
mated time when the truck will arrive based on truck schedules, locations,
efficiently presented for processing
road conditions and other oilfield factors
Since oil and gas field operators generally request a high volume of small jobs, both operators and contractors must document the services and cap-
Benefits for Energy and Industrial Customers
ture administrative information, such as authority for expenditure (AFE)
This move toward mobile dispatch is all interesting from a work-process-
numbers and cost centres, so that the billing can be efficiently processed
control point of view, but what’s in it for customers? The main benefit of an
These high volumes present a perennial paperwork challenge As a result,
effective hand-held program is efficiency—both for the contractor and for
many production services contractors are turning to mobile hand-held tech-
its customers through the following functions:
nologies to electronically dispatch, monitor and close out work orders The
• Automated dispatch and reporting—Using a hand-held system, data can
objective is twofold: (1) eliminate errors and physical paperwork, and (2) rely
be accessed faster and quickly dispatched to the drivers in the field It also
on integrated electronic work order management and accounting systems
eliminates the need to decipher handwritten worksheets and rework tran-
Expect custom systems Whether using off-the-shelf technologies, such as iPads or rugged industrial
scription errors In addition, job completion information is submitted immediately if there is a cellular connection, so both contractor and customer can have earlier access to the record and an uninterrupted audit trail
hand-helds, the mobile technology used by production services contractors
• Accurate records—The combination of hand-held device, communica-
should be designed to address the specific needs of the energy and indus-
tions, management and printing capabilities provides timely, accurate and
trial sectors Minimum capabilities include:
legible documentation to ensure that work performed in the field is cap-
• GPS (way finding and locations tracking)
tured correctly, is properly authorized by the customer, and the data are
• Bar code scanner (equipment identification)
securely transferred directly into corporate systems Data entry errors
• Date/time stamp (on-site work verification)
are virtually eliminated through bar code scanning, drop-down menus for
• On-demand consumables tracking (pricing based on contract rates) • Camera (inspections and maintenance)
required customer-specific fields and other built-in controls • Improved compliance—The dispatcher is able to capture all customer-
• Customizable screens/reports
specific information, such as AFE and cost centre codes All information
• Customer-specific forms and data fields
is stored electronically and provides infield and administrative customer
• Electronic signature capture • Timecard reporting It also makes sense to have portable printers in the trucks to print out completion receipts for field personnel
staffs with reliable and consistent data for invoice and audit purposes • More flexibility—With the hand-held devices, personnel can make legible changes based on the work performed on site, capture the authorizing signature and transmit the updated data back to administrators in real time This level of efficiency can be expected from production services con-
System administration is important
tractors serving the energy and industrial sectors Contractors should
Regardless of the physical technology, effective mobile work order manage-
be ready to deploy mobile technologies, but they should also invest in the
ment requires a technical and administrative support system that starts
support infrastructure There’s an old information technology saying:
with well-trained dispatchers and field personnel, and extends through the
“Automating a bad process only leads to faster mistakes ” Make sure that
organization Phone and online requests should be accommodated, yet the
the administrative process is a solid base, and that the technology delivers
local dispatcher should remain responsible for capturing all of the informa-
results that will benefit your operations
tion upfront including customer-specific work order information, such as required AFE numbers and cost centre codes The work order can then be automatically sent over a cellular network to the designated hand-held mobile device The technician would then be
Darin Hauck, based in Provost, Alta., is Clean Harbors’ senior vice-president, energy and industrial services. He oversees production services in Canada and the United States.
OIL & GAS INQUIRER • DECEMBER 2012
53
advertisers' index Advantage Valve Maintenance Ltd . . . . . . . . . . . 34
Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . .12
Oil Lift Technology Inc . . . . . . . . . . . . . . . . . . . . . 48
Annugas Compression Consulting Ltd . . . . . . . . 20
Expertec Van Systems Inc . . . . . . . . . . . . . . . . . 48
Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . 38
Flexpipe Systems . . . . . . . . . . . . . . . . . . . . . . . . 43
Petro-Canada/Suncor . . . . . . . . . . . . . . . . . . . . . 35
Beijing Zhenwei Exhibition Co, Ltd . . . . . . . . . . . .19
FlexSteel Pipeline Technologies Inc . . . . . . . . . . . 3
Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 34
Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 28
General Motors of Canada Ltd . . . inside back cover
Bilton Welding and Manufacturing Ltd . . . . . . . . 24
Joint Utilities Safety Team . . . . . inside front cover
Brenntag Canada Inc . . . . . . . . . . . . . . . . . . . . . . 39
Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . . 44
Brother’s Specialized Coating Systems Ltd . . . . 24
Logan Industries Ltd . . . . . . . . . . . . . . . . . . . . . . . 4
Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . 22
MaXfield Inc . . . . . . . . . . . . . . . outside back cover
Platinum Grover Int. Inc . . . . . . . . . . . . . . . . . . . . . 15 Radafab Oilfield & Industrial Supply Inc . . . . . . . . 9 Risley Equipment Inc . . . . . . . . . . . . . . . . . . . . . . 42 Sirius Instrumentation And Controls Inc . . . . . . . 23 Systech Instrumentation Inc. . . . . . . . . . . . . . . . . 5 TransGas Limited . . . . . . . . . . . . . . . . . . . . . . . . 40
Canadian Standards Association . . . . . . . . . . . . . 8
Meridian Manufacturing . . . . . . . . . . . . . . . . . . . .14
ClearStream Energy Services . . . . . . . . . . . . . . . 32
MNP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6 & 48
Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . . 28
MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 50
Vertigo Theatre Society . . . . . . . . . . . . . . . . . . . 50
Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Northgate Industries Ltd . . . . . . . . . . . . . . . . . . 44
V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . .31
Diversified Glycol Services Inc . . . . . . . . . . . . . . 47
North Peace Communications . . . . . . . . . . . . . . . 27
West Country Oilfield Services & Weed Control . . . 30
Dragon Products . . . . . . . . . . . . . . . . . . . . . . . . . 36
NRG Process Solutions Ltd . . . . . . . . . . . . . . . . . 40
Westeel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
54
DECEMBER 2012 • OIL & GAS INQUIRER
Trans Peace Construction (1987) Ltd . . . . . . . . . . 39 U F A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
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