OCTOBER 2011 � $6.00
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s upplie s s a g e l .C. sha With B g, producers o st in explod new market ing explor ice pressure pr relieve
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On the rebound
Heavy haulers profit from increase in field activity
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2011 PRODUCTS
Keeping readers regionally informed
F E A T U R E S
STER
LLOYDMIN
OCTOBER
2011
heaits on The
+
push thermal Producers means to recovery as vy oil recover hea
hers Penny pinc ss all about Heavy oil succe less for getting more
central ent Opportunity means differ Heavy oil play ent companies things to differ
A regional
supplement
to
LUMBIA
BRITISH CO NOVEMBER
2010
6
Oc t o b e r 2 0 1 1 • O I L & G A S I N Q U I R E R
12
Gas for sale
19
On the rebound
By Darrell Stonehouse With northeastern B.C. shale gas supplies exploding, producers are exploring new markets to relieve price pressure
By Darrell Stonehouse Oilfield haulers profiting from upswing in field activity
The Heart of Heavy Oil Technology is driving improved recovery in Lloydminster's heavy oil fields. This is driving growth plans for existing players and attracting new investment.
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• Petrobank pushes forward with
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By Paul Wells
By Lynda Harrison
Northeastern Alberta
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By Elsie Ross
Central Alberta
East Coast • Environmental review planned for Old
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International • EOG sand mine could save $400M
By Richard Macedo
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• Keystone XL leaps
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Editor’s Note Vol. 23 No. 8 President & ceo Bill Whitelaw | bwhitelaw@junewarren-nickles.com interim Publisher Chaz Osburn | cosburn@junewarren-nickles.com EDITORIAL Editor
Darrell Stonehouse | dstonehouse@junewarren-nickles.com
Darrell Stonehouse | dstonehouse@junewarren-nickles.com
ASSISTANT Editor
Joseph Caouette | jcaouette@junewarren-nickles.com
The great gas glut
Editorial Assistance Manager
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Laura Blackwood, Brandi Haugen, Marisa Kurlovich proofing@junewarren-nickles.com Contributors
Lynda Harrison, Richard Macedo, James Mahony, Pat Roche, Elsie Ross, Paul Wells Creative Print, Prepress & Production Manager
Michael Gaffney | mgaffney@junewarren-nickles.com SENIOR Publications Manager
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It’s hard to believe, but just three short years ago natural gas was trading at over $13 per million British thermal units on U.S. commodity exchanges. Today, the price is mired in the $4 range, and few analysts are predicting a rebound in the near term. The global market meltdown in 2008 and resulting destruction in demand is partially to blame for the price collapse. But predicted massive increases in supply are the key factor driving prices over the cliff. Drilling extended-reach horizontal wells from multi-well pads and fracturing as many as 25 intervals per horizontal leg has altered the supply dynamic. The new market perception is that shale and tight gas resource represents a 100-year supply, and that supply can quickly be brought into production when needed. There are some doubters when it comes to the unconventional gas revolution. They point to the steep decline rates reported in many shale developments as evidence that wells may not recover as much resource as many believe before becoming too uneconomic to operate. There are also concerns much of the contingent resources being reported by explorers are outside the sweet spots in the plays that can be economically produced with current technologies, greatly limiting how much of the resource will ultimately be produced. These voices of caution, of course, are being drowned out by the chorus of optimists who envision a cornucopia of new supply being used to replace coal in power generation and diesel fuel in heavy transport, while exporting the surplus to Asian markets. The good news is gas producers win either way in the long run. If, as the new shale and tight gas plays mature, predicted ultimate recovery doesn’t pan out, prices are going to climb as perceived supply comes back into alignment with demand. If the gas is there at the volumes predicted and can be produced in a competitive fashion, it is likely demand from the power, transportation and export market will eventually suck up supply and bring the market back into balance. Natural gas producers in northeastern British Columbia, where the Canadian industry is furthest along in developing unconventional gas, fall into the optimist camp. In this month’s issue, we look at how they are growing gas supply out of the Montney and Horn River plays, and review their efforts to build new markets for the gas. We also look at how the technological revolution allowing the exploitation of unconventional gas and tight oil has impacted the trucking industry. The massive fracs needed to unlock tight resources require huge volumes of sand and water, making bulk material and fluid-handling growth industries. Also in this month's issue we launch a new column called Business Intelligence. In this installment, MNP oilfield service leader Dustin Sundby advises service providers how to take a more balanced approach to managing their businesses.
Subscription Inquiries Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: junewarren-nickles.com Oil & Gas Inquirer is owned by JuneWarren-Nickle’s Energy Group and is published monthly. GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2011 1080554 Glacier Media Inc. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240. Postage Paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 800 - 12 Concorde Place, Toronto, ON M3C 4J2 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.
N E X T
I S S U E
November edition In the November Oil & Gas Inquirer, we review activity in the North Dakota Bakken play and efforts to extend the play further westward into Montana. We also take a look at artificial lift and how lift technologies are changing to improve
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.
reliability and economics.
O I L & G A S I N Q U I R E R • Oc t o b e r 2 0 1 1
9
Stats
AT A GLANCE Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
MONTH
OIL
GAS
OTHER
TOTAL
MONTH
OIL
GAS
DRY
SERVICE
TOTAL
Aug 2010 Sept 2010 Oct 2010
168 357 404
135 638 460
43 59 46
346 1,054 909
Aug 2010 Sept 2010 Oct 2010
452 617 678
156 790 581
40 45 39
15 23 18
663 1,475 1,316
Nov 2010 Dec 2010 Jan 2011
579 676 226
847 403 145
169 294 82
1,595 1,373 413
Nov 2010 Dec 2010 Jan 2011
868 1,061 409
989 559 201
75 78 33
165 238 17
2,097 1,936 660
Feb 2011 Mar 2011 Apr 2011
353 650 419
294 974 472
127 222 112
774 1,846 1,003
Feb 2011 Mar 2011 Apr 2011
723 1,069 618
378 1,081 509
38 64 46
99 164 81
1,238 2,378 1,254
Jun 2011 Jul 2011 Aug 2011
209 105 452
124 43 183
100 97 93
433 245 728
Jun 2011 Jul 2011 Aug 2011
428 298 922
197 97 262
12 15 28
183 88 80
818 490 1292
Wells Drilled In British Columbia
Saskatchewan Completions
Source: B.C. Oil and Gas Commission
Source: Daily Oil Bulletin
MONTH
WELLS D R I L L E D
CUMULATIVE *
MONTH
OIL
GAS
OTHER
TOTAL
Aug 2010 Sept 2010 Oct 2010
45 40 42
526 566 608
Aug 2010 Sept 2010 Oct 2010
198 197 201
12 5 12
7 6 11
217 208 224
Nov 2010 Dec 2010 Jan 2011
43 49 62
651 700 62
Nov 2010 Dec 2010 Jan 2011
217 340 136
3 2 4
64 11 3
284 353 143
Feb 2011 Mar 2011 Apr 2011
69 55 41
131 186 172
Feb 2011 Mar 2011 Apr 2011
321 316 183
6 8 11
7 4 11
334 328 205
Jun 2011 Jul 2011 Aug 2011
54 56 40
419 479 519
Jun 2011 Jul 2011 Aug 2011
217 185 413
25 5 2
89 3 13
331 193 428
*From year to date * from year to date
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FAST NUMBERS
112 million 53% barrels of oil per day needed by 2035, says Energy Information Administration.
amount world energy demand will increase by 2035, says Energy Information Administration.
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada September 15, 2011 Source: Rig Locator
Alberta August 2011 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
AC T I V E (Per cent of total)
Western Canada Alberta
373
186
559
67%
British Columbia
53
28
81
65%
Manitoba
18
1
19
95%
Saskatchewan
116
33
149
78%
WC Totals
560
248
808
69%
Northwest Territories
0
0
0
0%
OIL WELLS
Alberta
GAS WELLS
August 11
August 10
August 11
August 10
Northwestern Alberta
87
27
109
70
Northeastern Alberta
57
14
14
0
263
112
27
18
45
18
33
47
452
171
183
135
Central Alberta Southern Alberta TOTAL
Service Rig Count by Province/Territory
Drilling Activity: CBM & Bitumen
Western Canada August 15, 2011 Source: Rig Locator
Alberta August 2011 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
AC T I V E
Western Canada
COALBED METHANE
Alberta
Alberta
416
239
655
64%
British Columbia
11
17
28
39%
Manitoba
13
7
20
65%
Saskatchewan
158
41
199
79%
WC Totals
598
304
902
66%
Northwest Territories
2
0
2
100%
BITUMEN WELLS
August 11
August 10
August 11
August 10
Northwestern Alberta
0
2
4
3
Northeastern Alberta
0
0
57
14
Central Alberta
0
1
102
52
Southern Alberta
3
1
1
0
TOTAL
3
4
164
69
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Feature
Gas FOR
12
Oc t o b e r 2 0 1 1 • O I L & G A S I N Q U I R E R
Photo: Joey Podlubny
The arrival of extended-reach horizontals and multistage fracturing has created a glut of gas in northeastern British Columbia.
Feature
sale With northeastern B.C. shale gas
supplies exploding, producers are exploring new markets to relieve price pressure By Darrell Stonehouse
T
he land rush for shale gas and tight gas rights in northeastern British Columbia is finished. Over the last five years, explorers spent an average of $1.2 billion annually staking claim to prospective acreages from south of Dawson Creek, B.C., all the way to the border of the Northwest Territories. At the peak of the rush in 2008, $2.7 billion was invested chasing mostly the Montney and Horn River plays. So far in 2011, explorers have spent only $71 million in land sales with half the year over. With much of the prospective shale and tight gas acreages spoken for, the work of turning the resource into reserves is underway. Explorers are fine-tuning drilling and completion strategies and testing the new technologies on different play types. And their success is adding to a natural gas supply glut that is depressing prices across North America, leading to efforts to create new markets for what could be over 100 years of recoverable reserves. The Montney The Montney was the first of the unconventional gas targets to catch fire in northeastern British Columbia after ARC Resources Ltd. drilled its initial horizontal well at Dawson in the Deep Basin in 2005. Since then, explorers have been expanding the Montney both geographically and geologically, but Dawson remains a hot spot. ARC Resources’ chief executive officer John Dielwart said at the company’s annual meeting that the Dawson play is “the best of the best acreage” in the Montney. “At today’s prices—if they stayed flat at this level forever— we’d still get a 40 per cent rate of return on every dollar we spend. And that’s a full-cycle rate of return,” Dielwart said. ARC has an estimated 3.8 trillion cubic feet of discovered gas initially in place at Dawson and is currently producing over 160 million cubic feet per day. In all, the company has an estimated 10.1 trillion cubic feet of discovered gas initially in place on its northeastern B.C. Montney lands excluding its Attaché and Tower properties where the
resource potential hasn’t been assessed. Only 1.38 trillion cubic feet have been booked as proved-plus-probable reserves. “So about a 14 per cent recovery factor. We certainly expect to get much beyond that,” Dielwart said. Another Montney hot spot in the Deep Basin is the Farrell Creek area of British Columbia driven by the joint venture between Talisman Energy Inc. and Sasol Ltd. At Farrell Creek, Talisman drilled eight wells in the first quarter. Gross production averaged 56 million cubic feet per day, more than double the same quarter last year. Talisman closed a $1.05-billion transaction with Sasol and formed a 50/50 partnership to develop Farrell Creek earlier this year. Sasol also agreed to pay $1.05 billion for a 50 per cent working interest in Talisman’s Cypress A Montney properties. The companies also started a study on the feasibility of a gas-to-liquids (GTL) facility in western Canada. “Farrell Creek is our most mature area,” said Mike Wood, vicepresident of Canadian shale with Talisman, at a recent conference. “We started drilling there in 2009 with a piloting program and started full development in 2010. Currently we have 10 rigs running there. “At this time, we’re going to focus just on the Farrell Creek assets for the next three to four years and that’s where we’ll keep the rigs going. In 2015, we’ll start the development phase in Cypress A.” Sasol, he added, brought its knowledge and history of GTL technology to the table. “That’s quite a unique opportunity for us,” Wood said, citing the feasibility study. “The results of that study we plan to have finished by the second half of next year.” The GTL option is important to maximize value, he added. With oil trading at around 20–25 times the price of natural gas and Canadian gas searching for market alternatives, the case for a GTL project looks compelling. Edward Kallio, director of gas consulting with Ziff Energy Group, agrees that the joint venture partnership was helping to drive some of the activity at Farrell Creek. “I would be very surprised if it wasn’t,” he says. “The Montney is the lowest-cost play in the WCSB [Western Canadian Sedimentary Basin]. Full-cycle costs, excluding liquids, are in the low $4 range, including rate-of-return, so this gas is marginally economic to develop against current gas prices, unlike other higher-cost plays, including shallow gas, coalbed methane and other conventional WCSB plays. That’s why activity is ramping up here and declining elsewhere.” The wells in Farrell Creek area are producing from three zones: the Upper Phosphate (Doig), which is a pure shale play, and the Upper and Lower Montney, which are siltstone reservoirs. Progress Energy Resources Corp. is pushing the Montney play northward. Development has traditionally occurred closer to the B.C./Alberta boundary, but over the past few years Progress has been amassing a significant land position north of this around Town-Kobes-Altares-Caribou. “We really think about this as a fairway,” says Greg Kist, the company’s vice-president of investor relations and marketing. “There’s a real, distinct fairway here where the productivity, the over-pressure regime, the rock properties and all that are practically identical through this whole fairway.” A report by Cormark Securities Inc. says that Progress now stands as the largest holder of Montney rights with nearly O I L & G A S I N Q U I R E R • Oc t o b e r 2 0 1 1
13
L
Feature
g -
. s a
y o
e n n r d p
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900,000 net acres of land focused in northeastern British Columbia. It moved into the region early, originally drilling for the Halfway and Debolt gas formations. “We have, over the course of the last 10 years, continued to build a position up in this neck of the woods,” Kist says. “The way we primarily play the game is we want to hold all the rights in the stratigraphic column. That’s the way you can be successful because as time and technology works, it opens up those additional layers. That’s what we do and how we play the game in this whole area.” Jim Stannard, the company’s vice-president of engineering, notes that previous industry activity essentially stopped at the Peace River and didn’t move much further. “What’s really evolved over the past 18 months has been a rapid ramp-up of activity north of the Peace River and really extended the commercial fairway, if you will, more than doubled the size of it,” he said. “That’s a big part of the story.” A major advantage of the northern Montney is that it is liquidsrich, which aids economics at today’s low natural gas prices. “The data is pretty sparse right now on gas analysis information, so it’s a little bit difficult for us to tell, but it looks like it’s 1 ½ to two times the liquids yields that they’re seeing in the Pouce Coupe area,” says Doug Ashton, vice-president of engineering with AJM Petroleum Consultants. “In there, they’re seeing five to 10 barrels per million cubic feet, so in the north area there’s probably more like 15 to 20 barrels per million.”
Progress is using a pod model in the north Montney. The company will drill a total of 35 horizontal wells this year and is ramping up five pods into various stages. “Instead of very concentrated development like Talisman Energy Inc.’s doing at Farrell, we’re taking a bit more of a small production pod approach,” Stannard notes. “The idea for a pod is to take an area we think is prospective and develop that up to 50 million cubic feet a day. Our idea is to get multiple of these pods on.” The reason is it allows the company to achieve economies of scale in a concentrated area and to develop a number of areas on its land base. The Cormark report says that in 2010, Progress grew provedplus-probable Montney reserves 386 per cent to roughly 600 billion cubic feet equivalent on 156 net booked wells, which is 4.4 billion cubic feet per well on average. With more than 7,500 potential Montney locations, less than two per cent of the company’s Montney inventory has been booked to date. Horn River Drilling in the Horn River shale gas play slowed in the winter of 2011 as low gas prices made the prolific but remote resource uneconomic. But explorers continue working to prove up the play and build the infrastructure needed to monetize what the National Energy Board estimates is nearly 90 trillion cubic feet of recoverable gas in the region. Quicksilver Resources Inc. has now drilled a total of eight horizontal wells into the Muskwa and Klua formations of the Horn River, of which four wells have started production. Only two additional
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14
Oc t o b e r 2 0 1 1 • O I L & G A S I N Q U I R E R
wells are required to validate virtually all of Quicksilver’s exploratory licences and convert these licences, covering approximately 130,000 net acres, into 10-year development leases. In addition, the company has drilled its first horizontal well into the shallower Exshaw oil formation and expects to have it completed soon. Quicksilver initiated midstream operations at Horn River in May. The company completed the construction and compression for a 20-mile, 20-inch gathering line, which will serve as the spine of Quicksilver’s transportation from its Horn River acreage. Completion of this line allows the company to flow gas from its four completed gas wells at unrestricted rates of more than 30 million cubic per day and minimize transportation costs. Horn River volumes averaged approximately 40 million cubic feet per day during the second quarter for Nexen Inc. A nine-well pad was drilled in record time, with one well drilled in only 14 days. Nexen also began fracking and completions on the wells during the quarter. Production from the pad is expected to be on stream in the fourth quarter but will be limited to existing facility capacity of about 50 million cubic feet per day. This capacity increases to 175 million cubic per day in late 2012 to coincide with the start-up of production from its 18-well pad. Encana Corporation and Apache Corporation spent much of the second quarter of 2011 doing completion work on wells targeting the Muskwa and Evie shale that were drilled earlier in the winter, Mike Graham, Encana’s Canadian division president and executive vice-president, reported in late July.
Image: Apache Corporation
Feature
Artist's rendering of the Kitimat LNG export terminal.
“So far, the wells are performing at or above our expectations. For the five Muskwa wells, the 30-day average initial production rate per completion interval was 15 per cent higher than our expectations—or about 12 million cubic feet per day per well. The four Evie wells had an average 30-day initial production rate of 10 million cubic feet equivalent per day, which is about three times better than the previous Evie wells,” said Graham. Finding new markets Despite the drilling successes in northeastern British Columbia, producers say higher prices are needed in the longer term to
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Feature
make developing the massive resource in the area economic. And for that to happen, new markets are needed urgently. “There’s a tremendous amount of gas out there, there’s no question about that,” ARC Resources’ Dielwart recently told the TD Capital Unconventional Energy Conference. “But when you really look at all the plays, the amount of the gas that works at $4 is a very small subset.” Plays like the Horn River Basin and deeper, tighter Montney wells that don’t have associated liquids are going to require higher prices, he said. “We’re not of the view that today’s gas prices of $4–$4.50 are sustainable for the long term,” Dielwart added. “But it is important for our industry to find alternative markets, whether it’s gas-to-oil or LNG [liquefied natural gas] projects or finding new markets in North America.” The industry needs higher prices to develop available resources, he said, but that doesn’t necessarily mean $7–$10 gas. “Once you get to $6, you have a pretty robust business,” Dielwart noted. There are a number of efforts underway to increase demand and therefore prices for B.C. gas. Apache, Encana and EOG Resources, Inc. are working toward the development of the Kitimat LNG export terminal. Talisman and partner Sasol are investigating the construction of a GTL complex. And, more recently, Progress Energy Resources announced a partnership with Malaysian state oil company PETRONAS to develop and export LNG from its Montney shale gas resource. “What we were looking for when we went into this joint venture process is not only somebody to work with us on the upstream development of the north[ern] Montney but it was also to look for new markets,” Progress Energy’s president and chief executive officer Michael Culbert told the Canadian Association of Petroleum Producers investment symposium. “So joining forces with PETRONAS puts us in a very enviable position in that we’re now linked with one of the largest LNG producers across the world.” Culbert said with plans for various LNG export terminals being proposed officials with both the federal and provincial governments would be wise to consider joint regulatory proceedings for multiple projects. “If you look at Southeast Asia’s demand, we could handle multiple [LNG] projects off the West Coast…. This can be a wellorchestrated process, where we benefit from using the right-of-way
“ If you look at Southeast Asia’s demand, we could handle multiple [liquefied natural gas] projects off the West Coast…." — Michael Culbert, President and Chief Executive Officer, Progress Energy Resources
once. If construction is all done at the same time, at least you’re going down the same right-of-way,” Culbert said. “And if you’re looking where the projects are situated, whether it be Kitimat or Prince Rupert, there’s a lot that can be done in directing by the federal and provincial governments.” While gas producers look overseas for potential markets, pipeline connections to the Alberta grid are coming on stream or are under construction to feed another potential market— the oilsands. Ziff Energy Group expects natural gas consumption in the Alberta oilsands will grow to about three billion cubic feet a day in 2020 from about 1.1 billion cubic feet a day currently, says vicepresident Bill Gwozd. To put that increase in perspective, he says it would be very roughly the equivalent of a second Alliance pipeline. Gas demand for the oilsands sector will account for four per cent of the total North American gas demand in 2020 if projects Ziff expects to go ahead are completed. That would be up from an estimate of roughly 1.5 per cent of North America’s average gas demand today. If all announced projects proceeded and reached design cap acity, the oilsands sector would need more than seven billion cubic feet of gas a day by 2020, according to Ziff’s tally. “However, in our realistic case, we think it’s closer to three billion cubic feet by 2020,” Gwozd says of Ziff’s forecast for oilsands gas needs. But if the industry is aggressive “and the stars align, you could actually have a lot more gas requirement for the oilsands,” he notes.
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Feature
On the
rebound Photo: Joey Podlubny
Oilfield haulers profiting from upswing in field activity
By Darrell Stonehouse
W
estern Canada’s oilfield trucking business is seeing a slow t u r na rou nd i n it s for t u nes as oil and gas drilling recovers, new drilling and completion technologies increase the amount of materials used on drill sites, and new production from tight oil and natural gas liquids (NGL) finds its way to market. But consolidation in the heavy hauling business continues as service providers attempt to vertically integrate operations to capture more revenues. According to the Petroleum Services Association of Canada, 13,325 wells will be drilled in 2011, an increase of 10 per cent over 2010. This followed a 35 per cent increase in wells drilled in 2010 compared to 2009 as industry recovered from the
global economic meltdown of 2008. The recovery has begun to translate into revenues for western Canada’s heavy haulers. Diver si f ied t r uc k i ng g ia nt a nd Canada’s largest oilfield hauler, Mullen Group Ltd., reported an increase of revenues of almost 36 per cent in the second quarter compared with a year earlier. A significant portion of Mullen Group’s operations involves moving heavy equipment, drilling rigs and drilling supplies such as oilfield fluids, tubulars and drilling mud, according to the company. Mullen Group president and co–chief executive officer Stephen Lockwood credits the record results directly to higher oil prices. “Revenue gains were strongest in the oilfield services segment with most operating entities benefitting from improved industry
conditions. Despite unusual wet weather conditions in southeastern Saskatchewan, overall drilling activity in western Canada improved in the current quarter as compared to the prior year, and activity related to oilsands development and infrastructure projects remained robust,” he says. The unconventional oil and tight gas revolution is having a mixed effect on the trucking industry. While raw well numbers are increasing, they are far from prerecession levels, and the advent of pad drilling using long horizontal wells means fewer rig moves and less work for heavy trucks. In the Horn River of northeastern British Columbia, natural gas producer Encana Corporation estimates it can drill the equivalent of 64 vertical wells using long horizontal wells from one drill pad. O I L & G A S I N Q U I R E R • Oc t o b e r 2 0 1 1
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Unconventional oil and gas drilling, combined with increasing liquids production, is increasing demand for fluid handling.
of this business. Flint Energy Services Ltd. expanded its geographic reach in response to the shale gas boom by buying a U.S. hauler in late 2010. The $36-million purchase included property and equipment in five locations in the United States: three in East Texas, one in Louisiana and one in Oklahoma. Flint began with fluid hauling services in Vernal, Utah, and recently expanded into the Marcellus shale gas basin, moving underutilized equipment from western Canada to its new Williamsport, Pa., location. With the addition of the five new locations, approximately 170 new employees and 450 pieces of equipment, Flint is now one of the largest oilfield haulers in the U.S. shale basins. In addition, the acquisition provides equipment, personnel and management for a new location that Flint is constructing in Williston, N.D., to provide oilfield hauling services in the active Bakken shale oil play in North Dakota. This brings the total to eight locations for Flint’s U.S. oilfield services business segment.
“Prior to 2010, we had very limited oilfield hauling operations in the United States, and this move, together with our earlier expansions, will make Flint a market leader,” said Flint president and chief executive officer W. J. Lingard in announcing the purchase. Flint isn’t the only traditional western Canadian hauler to expand into the United States. In May of 2010, midstream and trucking enterprise Gibson Energy Ltd. purchased Taylor Companies LLC. Headquartered in Mesquite, Texas, Taylor was the largest independent forhire crude oil transportation and logistics business in the United States. Its oper ations included more than 340 specialized tractor-trailer units handling 49 million barrels of crude oil annually, 71 pipeline injection stations, and a crude oil and NGL marketing business. Taylor has operations in most major crude oilproducing states in the United States. The extended-reach horizontal drilling and multistage fracking revolution is also being used to increase supplies
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“Our drilling rig relocation business has underperformed for the past eight quarters due to the decline in drilling rig activity and change in drilling technologies,” said Mullen in its second-quarter report. “We have streamlined this business to reflect current market realities, consolidated terminals and are now positioned to capitalize as drilling activity improves.” Outside of the rig relocation sector, however, the advent of drilling long horizontals and multistage fracturing from drilling pads is driving growth as truckers haul equipment, sand and water to wellsites. While no estimates are available in Canada, The Department of E nv i ron menta l Conser vat ion i n Pennsylvania estimates it can take as many as 10,000 trips to drill, fracture and complete an eight-well pad in the Marcellus shale. Here is the breakdown: • Drill pad and road construction equipment: 10–45 truckloads • Drilling rig: 60 truckloads • D rilling fluid and materials: 200–400 truckloads • Drilling equipment (casing, etc.): 200– 400 truckloads • Completion rig: 30 truckloads • Completion fluids and materials: 80–160 truckloads • Completion equipment (pipe, wellhead): 10 truckloads • Hydraulic fracture equipment: 300–400 truckloads • Hydraulic fracture water: 3,200–4,800 tanker trucks • Hydraulic fracture sand: 160–200 truckloads • F lowback water removal: 1,600–2,400 tanker trucks Major Canadian trucking companies are competing continent-wide for a share
Feature
of conventional oil and to coax more NGL out of tight gas plays. The increase in liq uids production is creating even greater demand for tanker trucks and attracting new entrants into the market. One example is midstream company Provident Energy Ltd., which recently bought a southeastern Saskatchewanbased trucking company in an effort to squeeze further value out of the NGL value chain while capturing new revenues from hauling light oil. Early this summer, Provident reached an agreement to purchase a two-thirds interest in the equity of Three Star Trucking Ltd., a Saskatchewan-based oilfield hauling company serving Bakkenarea crude oil producers. The transaction is valued at approximately $20 million and comprised of about $8 million in cash, 945,000 Provident shares, and approximately $4 million of assumed bank debt and working capital. “The acquisition of this two-thirds interest in Three Star expands Provident’s logistics footprint in the Bakken area, one of the most exciting resource plays in North America, and creates a strong
partnership with a highly regarded and growing player in the industry,” Doug Haughey, president and chief executive officer of Provident, says. Privately held Three Star is based in Alida, Sask. It operates in Saskatchewan, Manitoba and North Dakota, providing fee-for-service hauling of crude oil and related oilfield liquids for major Bakkenarea producers. Three Star has a new and well-maintained fleet of approximately 170 tractors and 160 trailers, Provident says. In addition to building a strong presence in crude oil hauling, the transaction will also provide Provident the opportunity to further expand its natural gas liquids and diluent logistics service businesses, said the company. Following the news it had purchased Three Star, Provident announced it is constructing a $10-million truck-unloading terminal located at Cromer, Man. The terminal, plus associated storage, will have an initial capacity of approximately 2,000 barrels per day of NGL production from the Bakken area. The NGL from this terminal will be injected into the Enbridge
Inc. mainline for transport to Sarnia, Ont. Provident has entered into a supply agreement with PetroBakken Energy Ltd. to underpin the terminal project and, as supply in the area grows, Provident will be able to expand its terminal on a very costeffective basis. “The Cromer terminal project is a key initiative that was an important part of our Three Star Trucking Ltd. acquisition strategy, is underpinned with producer supply agreements, augments our Empress East NGL supply and will be immediately accretive to EBITDA [earnings before interest, taxes, depreciation and amortization],” says Haughey. Provident anticipates the project will begin receiving volumes in the first quarter of 2012. Consolidation of smaller trucking companies continues in western Canada as smaller mom-and-pop outfits get eaten by the big companies with access to capital. In 2010, Mullen Group made five acquisitions of smaller transport companies. It started 2011 by acquiring Panda Tank & Vac Truck Services Inc. Panda is an oilfield fluid transportation company headquartered in Grande Prairie, Alta.
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British Columbia
More northeastern B.C. pipeline capacity planned
Photo: Joey Podlubny
By Elsie Ross
With gas production climbing in B.C. and northwestern Alberta, a number of new pipeline expansions are underway.
Wit h constr uction cur rent ly underway on its Horn River Mainline to tap the massive shale gas supplies in the Montney Formation and the Horn River Basin in northeastern British Columbia, NOVA Gas Transmission Ltd. (NGTL) is gearing up for further major expansions into the area. T h i s f a l l , t he Nat ion a l E ne r g y Board (NEB) will hold a hearing on the proposed $324-million Northwest Ma i n l i ne E x pa n sion, wh ic h wou ld increase transportation capacity in the Upper Peace River area of northeastern British Columbia and northwestern Alberta to 1.26 billion cubic feet per day by Apr. 1, 2013. If approved, the project would provide additional access to markets for the massive shale gas resources from the Horn River and Cordova Embayment in northeastern British Columbia as well as for
conventional gas production in the remote corners of northwestern Alberta. The expansion is designed to address the shortfall between the existing system capability of 775 million cubic feet per day in the Upper Peace River area and total
productive capability for the area to ensure the selected facilities are appropriately sized to meet forecast flow requirements and to minimize the long-term owning and operating costs, inclusive of fuel. The annual average productive capability of the Upper Peace River area is forecast to increase to 3.8 billion cubic feet per day by 2026. The NEB will hold a hearing this fall on the proposed project, which will expand TransCanada’s Alberta system by a total of approximately 111 kilometres of new right-of-way in three locations. Of the total, 104 kilometres will be alongside the existing right-of-way. The Northwest Mainline expansion includes the Horn River Mainline (Kyklo Creek section), which provides additional capacity for Horn River shale gas. It consists of approximately 29.1 kilometres of 42-inch pipe and related facilities beginning at the Sierra gas plant in British Columbia at the southern end of the Horn River mainline. It runs parallel to the Ekwan pipeline, which NGTL acquired as part of the Horn River pipeline project approved by the board earlier this year. T he Nor t hwe s t M a i n l i ne L o op (Timberwolf section) provides additional
The National Energy Board will hold a hearing this fall on the proposed project, which will expand TransCanada’s Alberta system by a total of approximately 111 kilometres of new right-of-way in three locations. contractual commitments of 1.25 billion cubic feet per day by November 2013, says NGTL. In designing the expansion, the TransCanada Corporation subsidiary says it also took into account the forecast
capacity for shale gas from the Cordova Embayment and conventional gas in the far northwestern corner of Alberta and northeastern British Columbia in addition to Horn River shale gas. The project consists of approx i mately
AUG/10
AUG/11
AUG/10
AUG/11
WELLS SPUDDED
46
54
WELLS DRILLED
44
48
BRITISH COLUMBIA WELL ACTIVITY
AUG/10
AUG/11
WELL LICENCES
47
128
▲
▲
▲
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • Oc t o b e r 2 0 1 1
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British Columbia
49.7 kilometres of 48-inch pipe and related facilities beginning approximately 30 k ilomet res sout hwest of Rainbow Lake, Alta., at 03-109-12W6 on the Northwest Mainline south to a point at 06-104-12W6, adjacent to the Snowfall Creek Meter Station, where it will tie in to the Northwest Mainline. The Tanghe Creek Lateral Loop (Cranberry section) consists of approximately 32.4 kilometres of 48-inch pipe and related facilities beginning approximately 104 kilometres northwest of Manning, Alta., on the Tanghe Creek Lateral Loop at 13-96-05W6 adjacent to the Chinchaga Meter Station. It is contiguous with, and will tie into, the 20-inch Tanghe Creek Lateral Loop. In the third quarter of this year, NGTL also expects to submit an application for the proposed Northwest Mainline-Komie North Extension, which would include a section 75 kilometres northeast of Fort Nelson, B.C., to serve customers in the Horn River Basin with an in-service date of April 2014. The project would also include the Horn River Mainline Loop (Townsoitoi
Creek section), the Northwest Mainline L o op ( P y r a m id s e c t ion) a nd t he Chinchaga Loop. The proposed Horn River Mainline (Komie North section) is expected to be approximately 100 kilometres of up to 36-inch-diameter pipeline, according to information on TransCanada’s website. The pipeline would parallel existing infrastructure for approximately 60 per cent of the route. Starting at the proposed Fortune Creek Meter Station (66-A-94-0-15) at the producer’s facility, the pipeline would follow a southeastern direction to a tie-in point on the Horn River Mainline (Cabin section), approximately 700 metres downstream of the Cabin Meter Station (64-J-94-P-4). The proposed Horn River Mainline Loop (Townsoitoi Creek section) is expected to be approximately 27 kilometres of 42-inch-diameter pipeline. The pipeline would parallel the existing Ekwan pipeline from 97-F-94-I-10 to a mainline block valve in 81-E-94-I-09. The route is approximately 60 kilometres northwest of Rainbow Lake.
The project was originally expected to loop approximately 55 kilometres of the existing Ekwan pipeline; however, commercial discussions indicate that the most easterly 27 kilometres of pipeline, now known as the Horn River Mainline Loop (Little Hay Creek section), may not be required to be in service in April 2014 and will not be applied for within the application, says the company. T he Nor t hwe s t M a i n l i ne L o op (Pyramid section) is expected to be approximately 29 kilometres of 48-inchdiameter pipeline that would parallel the existing Northwest Mainline from a tie-in point at 06-104-12W6 to a tie-in point at 01-101-13W6 near the existing Foulwater Creek Meter Station. The proposed pipeline route is approximately 65 kilometres southwest of Rainbow Lake. The proposed Chinchaga Loop is expected to be approximately 33 kilometres of 48-inch-diameter pipeline running parallel to the existing Chinchaga Lateral system from 13-96-05W6 to a tie-in point at 26-94-02W6. The proposed pipeline route is approximately 50 kilometres northwest of Manning, Alta.
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Apache says investment decision on Kitimat could come in early 2012 Apache Corporation chief executive officer Steven Farris says that a final investment decision on the Kitimat liquefied natural gas (LNG) export facility could be made by the first quarter of 2012. The LNG plant near Kitimat, B.C., is planned by Apache, EOG Resources, Inc. and Encana Corporation. An oral hearing into the export licence for the facility recently wrapped up and a decision by the National Energy Board is pending. “Due to the timing of front-end engineering and design work, we are now targeting a final investment decision in the first quarter of 2012,” Farris said. “We remain committed to a target date for first production in late 2015. Kitimat LNG is a landmark step, not just for Apache, but for the industry.” Apache’s Canadian production climbed in the second quarter to 126,526 barrels of oil equivalent per day (net after royalties) from 73,159 barrels the previous year. Yearto-date daily Canadian output also rose to
127,443 barrels of oil equivalent from 70,753 barrels during the same period last year. “We operated three rigs in Canada during the quarter and participated in 12 wells that reached total depth,” Farris added. “In the third quarter, we are
said. “Some of the offset players are drilling and making…good wells. We’ve got a huge acreage position in there and are starting to drill some wells in there.” In terms of Canadian dispositions, roughly $200 million closed in the second
“The Kaybob area has got some zones that have got some real potential.” — Steven Farris, Chief Executive Officer, Apache Corporation
currently projecting approximately 1,800 barrels of oil per day in unscheduled production disruptions due to pipeline downtime and ongoing flooding in some areas.” The company announced an increase earlier this year in Canadian capital spending and outlined some of its depth in oil and liquids plays at an investor day. “The Kaybob area has got some zones that have got some real potential,” Farris
quarter. A similar package is expected to close in the third quarter, but no details were given. Natural gas liquids (NGL) production in Canada shot up to 5,998 barrels per day in the second quarter from 1,996 barrels the previous year. For the six-month period, daily NGL production climbed to 6,270 barrels from 1,866 barrels during the same stretch of 2010.
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Northwestern Alberta/Foothills
Petrobank pushes forward with Dawson oilsands project
Photo: Joey Podlubny
By Paul Wells
Petrobank will be using its patented toe to heel air injection system on two well pairs at Dawson.
Petrobank Energy and Resources Ltd. is pushing forward its Dawson oilsands pro ject in the Peace River area. During the company’s second-quarter conference call, chief operating officer Chris Bloomer said that the often-delayed Dawson demonstration project is set to proceed and that drilling is anticipated to start in the fourth quarter of 2011. He said that Petrobank received final Energy Resources Conservation Board (ERCB) and Alberta Environment (AENV) approval for the Dawson demonstration project during the fourth quarter of 2010. The project will consist of two toe to heel air injection (THAI) well pairs plus associated surface facilities. “We expect that one well pair will be drilled during 2011 and the second will be drilled in 2012,” Bloomer said. “In the second quarter of 2011, we drilled two stratigraphic evaluation wells, which
confirmed the geophysical interpretation of the reservoir.” The company is currently decommissioning the surface facilities from its first two wells at the Kerrobert THAI project and will begin moving the facilities to the Dawson project in the third quarter of 2011. Civil work has begun and it is expected that drilling will begin soon. “Drilling activities for the remainder of 2011 will include completing an observation well as an air injector, as well as drilling a water disposal well, an observation well and one horizontal production well,” Bloomer said. He noted that the pre-ignition heating cycle (PIHC) is planned to start in the fourth quarter of 2011, and air injection is expected to start before year-end. The environmental assessment and regulatory application associated with the Dawson 10,000-barrel-per-day expansion
project are underway with the application to the ERCB and AENV scheduled to be submitted during the fourth quarter of 2011. “We ex pect t hat t he reg ulator y review cycle could take up to 18 months,” Bloomer said. Bloomer said Petrobank’s Kerrobert THAI project operations are underway with eight of the 10 new well pairs on air injection and in the initial production phase. “The first expansion well pair was placed on air injection and production in the middle of May, with an additional four well pairs placed on air injection by the end of the second quarter,” he said. The PIHC for the remaining five well pairs began at the end of the second quarter and currently three of these well pairs are on air injection, with the remainder expected to be on air injection by September. The company said its operating procedures continue to evolve. “We have been able to reduce the duration of the PIHC from a planned eight weeks to approximately four weeks. Following the PIHC, the vertical wells commence air injection at low rates and the horizontal production wells are brought on production with a progressive cavity pump,” Bloomer said. The initial cleanup fluids consist of water, including condensed water from the PIHC steam injection and some native oil. As these fluids are produced, the combustion gas volume increases, the temperature in the horizontal well begins to rise and the well begins to produce an oil and water emulsion at low rates. Wellbore temperatures will increase and combustion gas, along with some native oil and occasional upgraded THAI oil, will be produced. “As we measure the combustion gas communication and rising wellbore temperatures, we will increase the air injection in stages to facilitate the combustion zone development,” Bloomer said.
NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY
AUG/10
AUG/11
WELL LICENCES
236
312
▲
AUG/10
AUG/11
WELLS SPUDDED
178
270
▲
AUG/10
AUG/11
WELLS DRILLED
157
217
▲
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • Oc t o b e r 2 0 1 1
29
Northwestern Alberta/Foothills
Athabasca Oil Sands hits Nordegg oil Athabasca Oil Sands Corp. has drilled and completed three wells in the Deep Basin and says its strategy of targeting areas where the Nordegg Formation has reached high thermal maturity, increasing the possibility of yielding lighter oil, initially seems successful. The 13-14-063-20W5 well, located just off Highway 43 in the Kaybob area of northwestern Alberta, produced 41-degree-API oil. The well was drilled with a lateral length of 1,200 metres, equipped with an open-hole (ball-drop) liner system, and was completed with a 15-stage slickwater fracture treatment. The well flow tested for five days, with final restricted flow rates of approximately 500 barrels of oil equivalent per day—400 barrels of oil and 700,000 cubic feet of natural gas. The well flowed with an oil cut of 65–75 per cent (25–35 per cent stimulation fluid) at approximately 290 pounds per square inch (psi) flowing tubing pressure. Athabasca purposely limited the initial flowback rate from the shale following the fracture treatment under the belief this would
• • • • • • • • • • • • •
help to prevent movement and embedment of the proppant in the near wellbore region and prevent closure of the fracture network. The well is currently suspended, having reached its maximum permitted flare volumes. “We believe that the results from this well, which demonstrate that the Nordegg Formation is capable in certain favourable locations of yielding high-API oil and with high production rates, if repeatable could become a game changer for the Nordegg Formation exploitation,” wrote Sveinung Svarte, president and chief executive officer, in a release. Athabasca initiated its horizontal well evaluation drilling program in the first quarter of 2011 in the southern portion of its Deep Basin lands, near Fox Creek, Alta. Given that the Montney section in this area is also highly prospective and immediately underlies the Nordegg Formation, a second well was drilled from this pad site into the Montney formation with the goal of proving productivity from both zones, said the company.
The Montney horizontal well was drilled in parallel to the Nordegg wellbore, with a lateral offset of approximately 170 metres. The horizontal section was 1,196 metres in length, equipped with a similar liner system to the Nordegg well, and was completed with a 15-stage gelled water fracture treatment. The well was flow tested for six days, with final flow rates of approximately 250 barrels of oil equivalent per day (75 barrels of oil and 1.1 million cubic feet of gas per day). The oil cut was 25 per cent and continued to rise throughout the flow test. Only 30 per cent of the stimulation fluids have been recovered to date. “Although not surprised based on results from offsetting wells drilled by other operators, Athabasca is very encouraged by these Montney results, especially considering the non-optimal fracture treatment, which took a total of five days due to a combination of equipment failure and inclement weather,” wrote Svarte.
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Oc t o b e r 2 0 1 1 • O I L & G A S I N Q U I R E R
Northwestern Alberta/Foothills
The densit y of the oil from the Montney zone measured 37 degrees API and showed a total mass fraction of sulphur approximately 30 per cent higher than that measured in the Nordegg well. Interference testing was conducted during the flow period between the wells with downhole recorders, followed by an extended buildup on both formations, convincing Athabasca that these two wellbores are producing from separate reservoirs. The company has constructed a multiwell battery and short gas pipeline for these two wells, and hopes to bring them both on production soon. Athabasca’s Waskahigan (03-22-6223W5) well also targeted the Nordegg Formation. The lateral section was 1,228 metres in length, equipped with an openhole liner system similar to the other wells, and was completed with a 15-stage slickwater fracture treatment in late March 2011. The 30-day initial production rate for the well was 78 barrels of oil per day, with rates restricted to maintain a bottomhole pressure above 1,100 psi. — DAILY OIL BULLETIN
Lone Pine ups liquids production at Evi By Paul Wells In its first reporting period as a public compa ny, Forest Oi l Cor porat ion’s Canadian spinoff Lone Pine Resources Inc. increased its liquids content during the second quarter of 2011 while advancing its Slave Point play at Evi, Alta. The company averaged 17,061 barrels of oil equivalent per day, of which crude oil and liquids volumes of 3,561 barrels per day increased by more than 50 per cent from the first quarter of 2011. Lone Pine says that its commodity mix increased to 19 per cent liquids in the second quarter of 2011 from 14 per cent in the first quarter of 2011. “Despite ma ny operat iona l a nd weather-related challenges that faced much of the oil and gas industry in our core areas, we were able to execute our business plan with little disruption and negative effects,” president and chief executive officer David Anderson says. Lone Pine reported 100 per cent drilling success rate year-to-date in 2011 from 17 light oil wells at Evi and four (3.5
net) natural gas wells in the Nikanassin resource play at the Narraway field. Anderson said the company continued to improve well performance in the Evi light oil play. Results from the first 11 horizontal wells completed prior to spring breakup under the new fracture stimulation program had average initial peak production rates of 305 barrels per day per well and 30-day average rates of 206 barrels per day. “From a productivity perspective, we are very encouraged with the improved results we achieved at Evi through the application of a modified completions technique in the first half of the year,” Anderson said during the company’s second-quarter conference call. “Through increasing the number of frac stages placed in our horizontal wells from six stages in 2010 to the 10 stages in the current year’s program, we have seen an increase of 65 per cent in our well productivity.”
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Northwestern Alberta/Foothills
Anderson noted that despite applying more fracs, the average well cost has remained relatively flat. “The enhanced completion techniques have come with very small increases to the average well costs as increased costs of fracking have been offset by operational
to drill 25 horizontal wells at Evi in the second half of 2011. As at June 30, 2011, the company holds approximately 50,400 (43,500 net) acres in the Evi light oil play. Anderson said that Lone Pine will continue to focus on the Slave Point at Evi
“We believe our Evi asset base is one of the best-in-class light oil assets you will find.” — David Anderson, President and Chief Executive Officer, Lone Pine Resources Inc.
efficiencies on the drilling and completions side,” he said. “We are currently budgeting a total cost per well of $2.5 million to drill, complete and tie in for the remainder of our 2011 drilling program.” Activity levels in the area ramped up in early July following spring breakup and the company is currently completing six horizontal wells drilled in the first half of the year. Two rigs are currently drilling and a third rig is planned to be added later in the third quarter. Lone Pine plans
in the second half of the year to further advance the play and continue to shift the company’s commodity weighting towards high-margin light oil. “We believe our Evi asset base is one of the best-in-class light oil assets you will find,” he said. I n t he f i r st ha l f of 2011, L one Pine completed four vertical wells in the Nikanassin resource play in the Narraway/Ojay area with an average initial 24-hour production rate of nine
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million cubic feet per day. Additionally, the company drilled its first horizontal test that had a 24-hour initial production rate of 6.4 million cubic feet per day from a single interval. This first horizontal well was drilled with a 2,200-foot lateral and completed with seven fracture stimulation stages. The well was not drilled to planned specifications of a 4,000-foot lateral and 14 fracture stimulation stages due to slowerthan-expected drilling rates and operational time constraints. Lone Pine said it is encouraged by the first horizontal well result, which has a stabilized 90-day average production rate of approximately 3.2 million cubic feet per day, and intends to further its near-term horizontal efforts primarily through identified re-entry candidates. The company plans to drill three (three net) wells targeting the Nikanassin in the second half of the year and is currently completing two (1.5 net) wells that were drilled prior to spring breakup. As of June 30, 2011, Lone Pine holds approximately 202,100 (128,800 net) acres in the Nikanassin resource play.
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Oc t o b e r 2 0 1 1 • O I L & G A S I N Q U I R E R
Northeastern Alberta
Keystone XL leaps environmental hurdle
Photo: TransCanada Corp.
By Elsie Ross
The Keystone XL project to carry oilsands production to the Gulf Coast is a step closer to reality after the U.S. State Department found no environmental reason to block construction of the line.
TransCanada Corporation says it is pleased that the U.S. State Department’s Final Environmental Impact Statement (FEIS) for the Keystone XL crude oil pipeline has reaffirmed the environmental integrity of the project. “The Final Environmental Impact Statement reaffirms the findings of the two previous environmental impact statements that the Keystone XL pipeline will have no significant impact on the environ ment,” Russ Girling, TransCanada’s president and chief executive officer, says. “[The] Final Environmental Impact Statement continues to demonstrate the focus on safety and the environment that has gone into the development of this critical North American pipeline.” If construction of the pipeline begins early in 2012, Keystone XL is expected to be operational in 2013.
The nine-volume FEIS is more than 1,000 pages in length. Keystone XL has gone through an exhaustive 36-month review, including numerous public meetings, multiple public comment periods, submitting and review of thousands of
determined that incorporation of the 57 special conditions that TransCanada has agreed to would result in a project with a degree of safety greater than any typically constructed domestic oil pipeline system under current regulations, and a degree of safety along the entire length of the pipeline system similar to that required in high-consequence areas. In the final FEIS, the Department of State (DOS) also said it recognizes the public’s concern for the Northern High Plains aquifer system, which includes the Ogallala aquifer formation and the Sand Hills aquifer unit. The Northern High Plains aquifer system supplies 78 per cent of the public water supply and 83 per cent of irrigation water in Nebraska, and approximately 30 per cent of water used in the United States for irrigation and agriculture. Of particular concern is the part of the aquifer that lies below the Sand Hills region where the aquifer is at or near the surface. However, “in no spill incident scenario would the entire Northern High Plains aquifer system be adversely affected,” says the FEIS. Extensive studies of a previous spill in Minnesota similar to the Northern High Plains system suggest that impacts to shallow groundwater from a spill of a
Of particular concern is the part of the aquifer that lies below the Sand Hills region where the aquifer is at or near the surface. pages of information and responses to hundreds of detailed questions. The FEIS addresses concerns raised by the public during the review process. The department says that in consultation with the Pipeline and Hazardous Materials Safety Administration (PHMSA), it has
similar volume in the Sand Hills region would affect a limited area of the aquifer around the spill site. DOS assessed the potential impacts of the proposed project on many aquifer systems. The aquifer analysis included the identification of potable groundwater in
AUG/10
AUG/11
AUG/10
AUG/11
WELLS SPUDDED
70
123
WELLS DRILLED
76
128
NORTHEASTERN ALBERTA WELL ACTIVITY
AUG/10
AUG/11
WELL LICENCES
44
32
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▲
Source: Daily Oil Bulletin
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Northeastern Alberta
water wells within one mile of the proposed centreline of the pipeline. More than 200 public water supply wells, most of which are in Texas, are within one mile of the proposed centreline, and 40 private water wells are within 100 feet of the centrel ine. The pipeline route does not cross any sole-source aquifers or aquifers serving as the principal source of drinking water for an area. Diluted bitumen and synthetic crude oil, the two types of crude oil that would be transported by the proposed pro ject, would both initially float on water if spilled, and the lighter aromatic fractions of the crude oil would evaporate over time and water-soluble components could enter the groundwater, says the FEIS. Studies of oil spills from underground storage tanks indicate that potential surface and groundwater impacts are typically limited
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Oc t o b e r 2 0 1 1 • O I L & G A S I N Q U I R E R
before returning the pipeline to operation. In that incident, most of the oil was contained within the pump station, but 210 gallons discharged from the pump station to adjacent land. The land affected was treated in place in compliance with North Dakota Department of Health land treatment guidelines. Keystone conducted an assessment of the ma ximum potential pipeline spill volume from a complete pipeline structural failure, estimating that the maximum spill volume would be approximately 2.8 million gallons, which would be possible along less than 1.7 miles of the proposed pipeline route due to topographic conditions. For approximately 50 per cent of the proposed pipeline route (approximately 842 miles), the maximum spill volume would be approximately 672,000 gallons.
One spill was 21,000 gallons and occurred when a fitting failed at the Ludden, N.D., pump station.
to several hundred feet or less from a spill site, it says. For larger spills, the released oil would likely migrate from the release site. However, DOS analysis of previous large pipeline oil spills suggests that the depth and distance that the oil would migrate would likely be limited unless it reaches an active river, stream, a steeply sloped area or another migration pathway such as a drainage ditch. The existing Keystone Oil Pipeline System has experienced 14 spills since it began operation in June 2010. The spills occurred at fittings and seals at pump or valve stations and did not involve the actual pipeline. Twelve of the spills remained entirely within the confines of the pump and valve stations. Of those spills, seven were 10 gallons or less, four were 100 gallons or less and two were between 400 and 500 gallons. One spill was 21,000 gallons and occurred when a fitting failed at the Ludden, N.D., pump station. As a result, PHMSA issued a corrective-action order halting pipeline operation and requiring Keystone to consult with the agency
In response to suggestions t hat Keystone XL will not be needed, the FEIS says the demand for crude oil in the Gulf Coast area is projected to increase and refinery runs are projected to grow over the next 10 years, even under a lowdemand outlook. It also pointed out that Gulf refineries will need to find alternative sources of crude as production is declining from three of the four countries that currently supply crude. If Keystone XL is not built and operated, Gulf Coast refineries could obtain Canadian crude oil transported through other new pipelines or by rail or truck transport, says the FEIS. Many of the sources outside of North America are in regions that are experiencing declining production or are not secure and reliable sources of crude oil, including the Middle East, Africa, Mexico and South America, it says. “As a result of these considerations, DOS does not regard the no-action alternative [Keystone is not built] to be preferable to the proposed project.” If Keystone XL does not proceed, Canadian producers would seek alternative transportation systems to move oil
Northeastern Alberta
to markets other than the United States, it says. None of the pipeline systems considered would be capable of transporting Canadian crude oil to Gulf Coast delivery points in the volumes required to meet Keystone’s commitments for transporting 380,000 barrels per day to delivery points in Texas. The trucking alternative would add substantial congestion to highways in all states along the route selected, particularly at and near the border crossing and in the vicinity of the delivery points. At those locations it is likely that there would be significant impacts to the existing transportation systems, says the FEIS. Trucking would also result in substantially higher greenhouse gas emissions and a higher risk of accidents than transport by pipeline. Development of a rail system to transport the volume of crude oil that would be transported by the proposed project would likely produce less impact from construction than would the proposed project because it could be done using existing tracks. However, it would result in greater safety concerns and greater impacts during operation, including higher energy use and greenhouse emissions, greater noise impacts, and greater direct and indirect effects on many more communities than the proposed project. “As a result of these considerations, system alternatives were considered either not reasonable or not environmentally preferable,” says the FEIS. The release of the FEIS launches a 90-day consultation period to determine if the proposed project is in the national interest. This broader evaluation of the application extends beyond env i ron menta l i mpac t, ta k i ng i nto account economic, energy security, foreign policy and other relevant issues. During this time the DOS will consult with, at least, the eight agencies identified in the executive order to obtain their views. The department will also solicit public comments, both online and in public meetings, in the six states the proposed project would cross and in Washington, D.C. The Department of State says it is still on track to make a determination by the end of this year. “Above all else, the department is committed to maintaining the integrity of a transparent, impartial and rigorous process,” it adds.
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O I L & G A S I N Q U I R E R • Oc t o b e r 2 0 1 1
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Central Alberta
Peyto boosts capital budget By Richard Macedo
AUG/10
AUG/11
AUG/10
AUG/11
WELLS SPUDDED
248
339
WELLS DRILLED
250
336
Photo: Aaron Parker
“It’s those mid-rights, is really where we hunt.” He added that the company came off one of its best years from a land acquisition standpoint last year. “We acquired about 100 sections of land,” Booth said. “Most of those postings were by our own design, tailored to our drilling activity, our successful horizontal wells. That has provided us with current activity. “I would not want to be acquiring those rights in this day and age because we’ve seen in the Deep Basin that these rights are getting multiple more cost per acre. One, we own them, and two, we bought them at the best price,” he added. “We’re going to continue to go to land sales, evaluate those and even do deals, but it will be in a measured way.” Post breakup activity has resumed to a high level despite some weather-related
delays experienced through late June and early July. Daily production has recently reached the 37,000-barrel-of-oil-equivalentper-day targeted exit rate for 2011. Wells drilled in 2011 have contributed over 13,000 barrels per day of this amount, up from the second-quarter exit level of 11,000 barrels per day. To date, 42 (36.1 net) wells have been spudded this year and 38 (32.4 net) new wells have been brought on stream. Peyto has five rigs currently drilling, four in the greater Sundance area and one in the company’s northern Cardium lands. Peyto successfully executed on its plan to drill through breakup in the second quarter, taking advantage of multi-well drill pads to eliminate rig moves as the melting frost caused roads to be too soft for travel. As a result, the company continued to grow its production and funds from operations during a challenging period that saw much of the industry shut down activity and even shut in production. Peyto has now drilled over 85 horizontal multistage fractured gas wells in the Deep Basin. Overall, production results for the 2011 wells continue to meet or exceed company expectations with initial threemonth and six-month sustained production rates exhibiting similar averages to the 2010 group of wells. In total, Peyto has 17 horizontal producers that now have over 12 months of production history. At the end of their first year, six were Cardium wells still producing an average of 190 barrels of oil equivalent per day, seven were Wilrich wells at an average of 280 and four were Notikewin wells at an average of 285 barrels of oil equivalent per day. Some of Peyto’s first multistage fractured horizontal wells are now approaching two years of producing life and are showing strong continued performance in support of their assigned ultimate recoveries.
Drilling west of Edmonton. Producers like Peyto are upping budgets as new technology improves economics.
Peyto Exploration & Development Corp.’s board of directors has approved the expansion of the 2011 capital program to between $350 million and $375 million, assuming market conditions remain favourable. The company had previously announced a budget of between $300 million and $325 million. “Management believes the economic moat that surrounds Peyto’s business fortress is wider and deeper than ever,” the company stated in its second-quarter results. Overall production in the quarter climbed by 55 per cent year-over-year to 34,443 barrels of oil equivalent per day. “The key from a technical standpoint is to ensure that we capture the oil and gas rights in the Cretaceous,” Glenn Booth, vice-president of land, said during a conference call. “Whether it’s down to the Bluesky-Bullhead, or down to the Spirit River, that’s the challenge. CENTRAL ALBERTA WELL ACTIVITY
AUG/10
AUG/11
WELL LICENCES
273
347
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Source: Daily Oil Bulletin
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Central Alberta
Daylight adds Duvernay Shale acreage Add Daylight Energy Ltd. to the list of companies that have bought land in the emerging Duvernay shale play. So far this year, Daylight has spent roughly $100 million at Crown land sales, focused mainly on building a position in the Duvernay, the company reported in August. Duvernay purchases include several contiguous blocks in the company’s Pembina core area in Alberta. The company has also bought Duvernay rights in the Kaybob area, and now has in all about 130,000 net acres of Duvernay rights in the province. It plans to initiate a four-well pilot project in the first quarter of 2012, with an initial three wells planned in Pembina and one in the Kaybob area. The company said its $100-million investment in land is in addition to its previously announced $350-million capital program for 2011. Talisman Energy Inc. announced it is also building a position in the Duvernay. Duvernay potential dominated Alberta’s
June 1 Crown land sale with huge investments for land in west-central Alberta northwest of Red Deer. Encana Corporation confirmed in August that it was also a buyer. In the second quarter, Daylight’s average production fell 13 per cent, to 36,814 barrels of oil equivalent per day from 42,273 barrels per day in the second quarter of 2011,
advancing its Nikanassin and Cadomin natural gas resource play at Elmworth, Alta. Adverse weather delayed the completion of some wells and the resumption of operations after spring breakup. Apart from the Duvernay rights already mentioned, Daylight also acquired lands adjacent to its liquids-rich resource plays at Wapiti and Medicine Lodge.
Adverse weather delayed the completion of some wells and the resumption of operations after spring breakup. reflecting the sale of Daylight’s heavy oil properties and natural gas volumes that fell about six per cent from second-quarter 2010 output. Light oil volumes in the second quarter fell 19 per cent. Daylight drilled three (two net) wells in the second quarter, also completing wells in its Cardium light oil resource play at Pembina, its liquids-rich gas Montney play at Wapiti and Rock Creek at Pembina, and
Also in the second quarter, Daylight sold two properties for about $43.5 million, representing 1,600 barrels of oil equivalent per day of production (roughly 90 per cent gas). During the quarter, average daily production was made up of 140.61 million cubic feet per day of gas, 9,883 barrels per day of light oil and 3,496 barrels per day of natural gas liquids. — DAILY OIL BULLETIN
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Oc t o b e r 2 0 1 1 • O I L & G A S I N Q U I R E R
&
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S E RV I C ES
Central Alberta
Cardium lifts Bonterra production Bonterra Energy Corp. lifted production in the first half of 2011 to an average of 6,361 barrels of oil equivalent per day, representing an increase of 18 per cent compared to the same period last year. T he company ’s capital expenditures during the first six months totalled $26.22 million, net of drilling credits. The costs related to the drilling and completion of six (five net) Pembina and Willesden Green Cardium wells, the completion and tie-in of four wells drilled in the fourth quarter of 2010, constructing infrastructure to reduce operating costs and preliminary work for future drilling. Bonterra said the second-quarter capi tal program and production was negatively impacted by a number of uncontrollable factors including a longerthan-average spring breakup, shut-in production due to flooding, forest fires, pipeline issues and a scheduled plant B.C. properties. Despite this difficult operating environment, Bonterra says it was able to hold production levels flat quarter-over-quarter.
Due to these factors, however, the majority of the company’s drilling activity has been planned for the second half of the year. The company is currently executing its second-half capital program with two drilling rigs employed. The capital expenditure program for the full year is estimated at $50 million to $60 million, and Bonterra currently anticipates drilling more than 10 operated Cardium horizontal wells in the third and fourth quarters. With a back-end loaded drilling program, production is anticipated to increase in the latter part of the year and the company continues to forecast 2011 full-year production guidance at 6,200–6,500 barrels of oil equivalent per day. Bonterra has focused primarily in drilling Cardium horizontal wells outside of the main Cardium fields. Beginning in the third quarter of 2010, Bonterra has participated in successfully drilling seven gross non-operated horizontal Berrymoor Cardium unit wells (15 per cent working interest) in the main
Pembina pool. Bonterra said results to date have been extremely encouraging with the majority of these wells outperforming expectations. It added that the Berrymoor, Alta., wells are some of the best performing wells in the Pembina Cardium field. The company said it has begun to realize capital expenditure savings with the use of foam water fracs on some of its recently drilled horizontal wells. This new technology is applicable in some areas of the Cardium field and there are significant capital cost savings in the range of $300,000–$400,000 per well. Bonterra has used the technology on two wells drilled so far this year and is pleased with the results, noting no initial negative results from using foam water versus the more traditional oilbased fracs. The company said it will continue to assess whether foam-water fracs are preferable on an individual well basis and apply the technology where best suited. — DAILY OIL BULLETIN
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Central Alberta
Delphi posts record production
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Oc t o b e r 2 0 1 1 • O I L & G A S I N Q U I R E R
Delphi Energy Corp. says its operating costs continued to fall in the second quarter of 2011 as it focused spending and achieved growth in its core areas of Bigstone, Hythe and Wapiti/Gold Creek, all areas in Alberta with an operating cost structure of less than $6 per barrel of oil equivalent. Operating costs in the second quarter of 2011 were $6.63 per barrel of oil equivalent—a 17 per cent decrease over the $7.95 per barrel of 2010. For the six months ended June 30, 2011, operating costs were 19 per cent lower than the comparative period of 2010. The decrease is also attributed to lower field operating costs and last year’s disposition of eastcentral Alberta properties. Capital activity in the second quarter primarily included the completion of several projects from the first quarter and the start of the program for the second half of the year with two horizontal wells in Hythe and one multi-zone vertical well in Wapiti drilled and rig released. Start-up of the program was delayed due to weather, although the company did complete drilling three wells before the end of the quarter. In light of continued low natural gas prices, Delphi focused on light oil and liquids-rich gas. The company drilled 16 wells in the first half of 2011. Drilling included two (1.5 net) liquids-rich gas wells and one (one net) oil well in the second quarter of 2011, and 10 (8.7 net) liquids-rich gas wells and six (4.2 net) oil wells in the first half of this year. All were met with 100 per cent success. It drilled a total of three wells (2.5 net) within its core areas of Wapiti and Hythe, including one (one net) horizontal well targeting light oil in the Doe Creek Formation at Hythe. The second horizontal well drilled targeted gas in the Falher Formation where the company has identified 60–70 followup locations. At Wapiti, one vertical well (0.5 net) was drilled and cased during the second quarter. Completion operations have started on all three wells, despite ongoing wet weather conditions that continue to cause delays. About eight (6.2 net) vertical wells targeting liquids-rich gas in the Nikanassin
Central Alberta
and up-hole Cretaceous intervals will be drilled at Wapiti during the second half. Delphi continues to advance its plan to improve the efficiency of the existing natural gas liquids (NGL) recovery system at its processing facility at Hythe, expected to be running in the first quarter of 2012. This is anticipated to boost NGL production in the area to 20–25 barrels per million cubic feet of gas from the current five barrels. At Bigstone, industry activity and positive results offsetting the company’s Montney acreage (27 net sections) support acceleration of its drilling plans in the area. It is anticipated the first horizontal well targeting liquids-rich gas will spud in October.
Delphi achieved record output in the second quarter of 2011 with average volumes of 8,906 barrels of oil equivalent per day. Pressure Vessels By The company achieved record output in the second quarter with average volumes of 8,906 barrels of oil equivalent per day, an increase of 11 per cent compared to the second quarter of 2010. Liquids volumes grew by 65 per cent, changing the production mix to approximately 30 per cent crude oil and natural gas liquids. Oil output in the second quarter was 25 per cent higher than the comparative period last year, the increase due to horizontal drilling targeting Cardium light oil at Bigstone and Doe Creek light oil at Hythe. NG L out p ut w a s 145 p e r c e nt higher for the quarter primarily due to increased production in the Wapiti/Gold Creek area where the company has been drilling multi-zone vertical wells with the Nikanassin Formation as the primary target. Delphi has moved three drilling rigs into its operating areas in the Deep Basin of northwestern Alberta to kick off its second-half 2011 capital program, to drill about 12 (9.2 net) wells. — DAILY OIL BULLETIN
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Southern Alberta
Dollars keep flowing at Alberta land sales By Richard Macedo
AUG/10
AUG/11
AUG/10
AUG/11
WELLS SPUDDED
285
113
WELLS DRILLED
287
124
Photo: Joey Podlubny
Duvernay. This is where nearly all the spending happened, with 12 different licences in the general area drawing total bonus bids of $416.2 million. The top price paid was for a 7,680-hectare licence, which included several sections in the area around 61-16W5. Scott Land & Lease Ltd. picked up the parcel for a bonus of $123.67 million, paying an average of $16,103 per hectare, also the land sale high. This is a record for a single petroleum and natural gas (P&NG) parcel (excluding oilsands). The next highest was the $106.5 million paid for a single parcel at the record $843-million sale earlier this year. In terms of rankings, the total sale of $463.73 million in P&NG rights only (not including oilsands) stands as the third highest of all time. Ray Kwan, an analyst with Macquarie Securities, said the parcels that garnered the large bonus bids are likely prospective for the Duvernay.
“Targeting both the oil and liquids-rich gas window of the play,” he said. Macquarie recently released a report on the Duvernay. The report said that activity in the Duvernay shales has largely been a science experiment to this point with only a handful of wells recently drilled into the play. In total, Macquarie counted around 24 wells that have been licensed or drilled to date, consisting of 15 vertical delineation/test wells and nine horizontals. The two most notable are Celtic Exploration Ltd., Trilogy Energy Corp. and Yoho Resources Inc.’s horizontals (33.3 per cent working interest each) at Kaybob. The first horizontal tested at 2.1 million cubic feet per day of sweet natural gas and roughly 75 barrels per million cubic feet of natural gas liquids and condensate with only six of the 13 planned stages fracked because of a rupture in the liner, while the second horizontal tested at 5.2 million cubic feet per day plus 390 barrels per day of liquids. Of the 24 wells drilled or licensed, t here are t wo ver ticals ( Yoho and Arriva Energy Inc.) and two horizontals (ConocoPhillips Company) licensed in the greater Pembina region. For the remainder of the year and throughout 2012, another 20-plus vertical/ horizontal wells are expected to be drilled. Notable players that have indicated Duvernay programs include Encana Corporation at two wells, Talisman Energy Inc. at two to four wells, Chevron Corporation at five to 10 wells, Daylight Energy Ltd. at four wells and Husky Energy Inc. at two wells. In addition, Celtic/Trilogy/Yoho, Birchcliff Energy Ltd., PetroBakken Energy Ltd., Sonde Resources Corp., Bellatrix Exploration Ltd., Bonavista Energy Corporation and Longview Oil Corp. each plan to drill at least one pilot well in the fourth quarter of 2011 or the first quarter of 2012 to help appraise the prospectivity of the play, the report stated.
The Duvernay shale play is driving land sales in Alberta.
The Alberta government has surpassed its bonus revenue from all of last year after a sale of $464.06 million rolled into government coffers at August’s auction, moving the year-to-date total into the all-time second place with eight sales left in 2011. With this latest total, the province has collected $2.73 billion in bonus revenue on 3.09 million hectares so far in 2011, already displacing last year’s $2.41-billion total for second place. For the full calendar year in 2010, Alberta sold a total of 3.98 million hectares. The top spot is held by the 2006 tally when the government attracted $3.4 billion thanks to heavy spending for oilsands acreage. The recent land sale generated an average price of $1,615.83 with 287,198 hectares sold. A solid block of land that was sold in northern Alberta in the Fox Creek area, northwest of Edmonton, appeared to be related to continuing interest in the SOUTHERN ALBERTA WELL ACTIVITY
AUG/10
AUG/11
WELL LICENCES
213
110
▼
▼
▼
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • Oc t o b e r 2 0 1 1
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Southern Alberta
Alberta natural gas needed for oilsands, says Ziff Ziff Energy Group expects natural gas consumption in the Alberta oilsands will grow to about three billion cubic feet a day in 2020 from about 1.1 billion cubic feet a day currently, said vice-president Bill Gwozd. To put that increase in perspective, he says it would be very roughly the equivalent of a second Alliance pipeline. Gwozd said that Ziff gas analyst Julia Sagidova analyzed more than 60 existing, under-construction, approved and proposed oilsands developments. Ziff Energy used this information to forecast growth in gas demand by major oilsands operators through this decade. “Gas demand for the oilsands sector will account for four per cent of the total North America gas demand in 2020,” Sagidova said in a press release. That would be up from an estimate of roughly 1.5 per cent of North America’s average gas demand today. Gwozd expects bitumen output from the province’s oilsands regions will reach
between 3.5 million and four million barrels a day by 2020, up from 1.4 million barrels a day now. Gwozd is confident bitumen output can rise to this level by 2020 —even though many of the reservoirs in question haven’t been developed yet. He said the forecast assumes some proposed projects won’t proceed by 2020, others won’t reach their design capacity and production will sometimes be interrupted by events such as fires. But if all announced projects proceeded and reached design capacity, the oilsands sector would need more than seven billion cubic feet of gas a day by 2020, according to Ziff’s tally. “However, in our realistic case, we think it’s closer to three billion cubic feet by 2020,” Gwozd said of Ziff’s forecast for oilsands gas needs. But if the industr y is aggressive “and the stars align, you could actually have a lot more gas requirement for the oilsands,” he noted.
Gwozd said oilsands mining projects use about 500 cubic feet of gas to produce a barrel of bitumen, while thermal in situ projects use around 1,000 cubic feet. Neither figure includes gas used in bitumen upgrading, but Gwozd said that upgrading consumption is relatively modest—increasing total oilsands gas needs by roughly 10 per cent. In its forecast, Ziff Energy assumes the amount of gas burned to produce a barrel of bitumen will decrease over the decade with technology advances. So will western Canada be able to produce enough gas to satisfy oilsands as well as other requirements? In 2008, Ziff Energy suggested that without shale gas and other tight gas supplies coming on stream, Alberta’s gas exports could start to approach zero by 2030. This, the consultancy had warned, could begin to jeopardize the viability of future in situ oilsands projects. While Ziff Energy has never agreed with the currently popular notion that
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Oc t o b e r 2 0 1 1 • O I L & G A S I N Q U I R E R
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getting the proper netback to drill for this expensive gas that requires expensive transportation,” said Gwozd. However, lower shipments to the East could be offset by the potential rise of what Gwozd calls unconventional markets in western Canada, which might include LNG exports from the West Coast, a gas-to-liquids (GTL) plant or other potential uses for western Canadian gas. Gwozd puts oilsands gas consumption in this category. He regards the use of gas for oilsands production as, in effect, a GTL conversion that capitalizes on high oil prices. “Using the six-to-one ratio for gas-tooil equivalency, if you take the gas price at $4 per thousand cubic feet and multiply it by six, you get $24 for a barrel. And you’re not getting $24 for oil, you’re getting $84 a barrel,” Gwozd said recently. Wit h t he t ra n spor tat ion cost of shipping western Canadian gas east expected to rise, growing gas demand in the oilsands sector is “fantastic ” news for the region’s gas producers, Gwozd said.
Photo: Joey Podlubny
North America will have a surplus of gas for many years, the consultancy believes the continent will have enough gas to meet most of its needs with liquefied natural gas (LNG) imports making up the difference. However, Ziff expects volumes shipped on long-haul pipelines to the East to taper off. “This incremental gas demand for gas in the oilsands, along with the slight tilt down in supply, means that longhaul pipes don’t have access to the same amount of gas supply as they had a few years ago,” Gwozd said. And as volumes on these pipelines fall, per-unit tolls would rise as costs are shared by fewer shippers or shipments. This would further reduce the incentive to drill in western Canada, where producers are already at a competitive disadvantage compared to producers in places like Texas that are closer to major markets and can drill all year. So higher pipeline tolls could further erode the economic viability of some of western Canada’s gas supply and “further drive producers away because they’re not
Thermal oilsands projects use 1,000 cubic feet of gas per barrel of bitumen.
O I L & G A S I N Q U I R E R • Oc t o b e r 2 0 1 1
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Southern Alberta
Alberta oil well completions at 30-year high Operators continued to pursue oil develop ment across western Canada in July, pushing the seven-month tally for oil well completions to another high. Development completions for oil in the four western provinces soared to 3,727 wells in the January–July period, close to 62 per cent of total development completions and up from 2,434 development oil wells in last year’s comparable time frame. With strong crude prices and stagnant gas prices, July marked eighth straight month (beginning December 2010) that operators completed more oil development wells than gas development wells. Exploratory oil completions in western Canada are also at a high. During the first seven months of the year, exploratory oil completions rose to 554, up from 407 in the first seven months of 2010. St i l l, t he p ercent age of e x ploratory wells being completed in western
Canada continues to decline, at only 17 per cent of the wells to date this year.
With strong crude prices and stagnant gas prices, July marked eighth straight month (beginning December 2010) that operators completed more oil development wells than gas development wells. Industry and governments reported that 8,120 wells were completed across the country from January to July, up 33 per cent from 6,102 completions in the comparable period last year.
This year’s total includes 4,285 oil wells, 2,755 gas wells, 827 service wells and 253 dry holes. In A lber ta, oil wel l complet ions excluding experimental wells to the end of July rose to 2,556, up 67 per cent from 1,533 wells since last year. It’s the highest number of oil well completions in 30 years of records compiled by the Daily Oil Bulletin. Saskatchewan’s oil well completions during the first seven months of the year climbed 37 per cent to 1,492—up from 1,091 last year—and there were 194 oil well completions in Manitoba compared with 204 from Januar y to July in 2010. For the month of July, 500 wells were completed across Canada. T he tally included 300 oil wells and 97 gas wells. A total of 13.3 million metres of hole have been completed year-to-date, with 890,000 metres completed in July. — DAILY OIL BULLETIN
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Oil plays drive Calfrac to record quarter Calfrac Well Services Ltd. booked record net income and revenue in the second quarter, despite a lengthy spring breakup and poor weather that limited the amount of work possible. Management attributed the quarter’s record figures to high levels of pressure pumping in unconventional oil and nat ural gas plays in both the United States and western Canada. Much of the company’s activity in the quarter was focused on established and emerging oil-producing plays, such as the Cardium, Viking and the Alberta Bakken formations. The company expects these plays will continue to diversify its Canadian operations. Calfrac says it would boost this year’s capital program by $59 million, to $382 million, of which $38 million is expected to be spent in 2012. Most of the increase will go to building a fracturing fleet and support equipment to service a minimum-commitment contract in North Dakota’s Bakken oil shale play, while some
of the funds are deposits on 2012 pumping equipment. This year’s capital program is advancing, and most of the equipment was expected to be delivered in the latter part of 2011, the company said. In the second quarter, the company completed several projects in the Montney
active in the Deep Basin and Montney. In the United States, the company has signed a multi-year agreement to provide two fracturing fleets to a producer active in North Dakota’s Bakken play as well as a long-term right-of-first-refusal contract with a producer in the Marcellus shale gas play.
Late in the second quarter, Calfrac deployed a large fracturing crew in the Horn River Basin to begin 2011 activity. Formation, which continues to evolve into one of the most economic natural gas plays in North America, management says. Many of the projects use multi-well pads and 24-hour operations. Calfrac has signed several new contracts to provide pressure pumping in Canada and the United States. In Canada, the company has a long-term, minimumcommitment contract with a producer
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Also during the quarter, Calfrac sent a Canadian fracturing crew to North Dakota to maximize Canadian equipment utilization during spring breakup. Several pro jects were completed, and the company will continue to evaluate the merits of such opportunities in the future to mitigate the impact of spring breakup in Canada. Late in the second quarter, Calfrac deployed a large fracturing crew in the
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47
Southern Alberta
Horn River Basin to begin 2011 activity. The projects are expected to be complete by the end of the third quarter. Calfrac’s 2011 activity in the Horn River Basin will be higher than in 2010, and the play is expected to provide a growth platform for several years. At the end of the second quarter, Calfrac had 224,000 hydraulic horsepower (HHP) in Canada and expects to be running 330,000 HHP by yearend. In the United States, the company plans to have 430,000–440,000 HHP by year-end, making its total North American pressure-pumping f leet 760,000–780,000 HHP at year-end. Calfrac will begin work in Colombia in this year’s second half. Thanks to a stable political and economic environment, the country appears poised for strong future growth, management says. The expansion will provide further diversification for the company and another platform for growth in Latin America. By year-end, Calfrac expects to begin fracturing in Argentina. — DAILY OIL BULLETIN
Wells continue going deeper The average length of rig-released wells in Canada continues to increase, reflecting the shift by industry to use horizontal drilling to exploit reservoirs. A record 5,204 of the permits issued to the end of July this year were for horizontal holes, 50 per cent of the total. In 2008, almost 16 per cent of the well authorizations were for horizontal holes. During the first seven months of the year, a total of 11.51 million metres of development and exploratory hole were drilled in western and northern Canada, with average well length increasing to 1,792 metres in the January–July period, up from 1,746 metres in the comparable period of 2010 and an average of 1,428 metres in 2009. A decade ago, in 2001, the average stood at 1,055 metres. The total meterage for rig-released wells for the January–June period is up 12 per cent over last year’s comparable period—11.51 million metres in 2011 versus 10.27 million metres in 2010.
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In a move to develop oil wells while prices are high, however, operators have shifted to drilling development wells. In 2011’s first seven months, 9.74 million metres of development hole were rig released in western and northern Canada, up 18 per cent over 8.24 million metres last year. But exploratory meterage has declined about 13 per cent year-over-year to 1.77 million metres in the January–July period from 2.03 million metres last year. During the month of July, the average well length increased to 1,809 metres from 1,732 metres in July 2010 and 1,500 metres in July 2009. A total of 1.72 million metres of development hole were rig released in western and northern Canada in July, up 12 per cent from 1.53 million metres in the year-prior period. Explorator y mete r age dec l i ned 37 p e r ce nt to 227,282 metres from 361,084 metres in July 2010. — DAILY OIL BULLETIN
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Saskatchewan
Manitoba land sales strong but Saskatchewan down By Richard Macedo
AUG/10
AUG/11
AUG/10
AUG/11
WELLS SPUDDED
274
432
WELLS DRILLED
279
481
Photo: Joey Podlubny
in the Pierson, Man., area at surface location 01-22-02-28W1, with the Triassic System listed as the total depth zone and a planned depth of 1,576 metres. EOG is a busy operator in the area. BASM Land & Resources Ltd.’s bid generated the highest price per hectare for a parcel located in the Waskada, Man., area. The firm paid $15,999 per hectare for a 16-hectare parcel at legal subdivision 10 of section 32 at 01-25WP. The broker paid a total bonus of $255,999 for the lease. This was the third of four sales scheduled for 2011. The next sale will be held on November 9. Meanwhile, Saskatchewan also held a land sale recently, which generated $21.75 million in bonus bids for the province, the lowest at a single land sale this year. A total of 31,258 hectares exchanged hands
at the land sale, at an average of $695.78 per hectare. Total bonus bids this year now stand at $214.88 million on 420,747 hectares at an average of $510.70. To the same point last year, the province had taken in $371.63 million in bonus bids as 316,505 hectares were sold at an average price of $1,174. Despite August numbers declining from the previous three sales, Energy and Resources Minister Bill Boyd was pleased with the overall result. “We were expecting a smaller sale after two years of intense land acquisition by our oil industry,” Boyd said in a statement. “The sale numbers demonstrate continuing and sustained interest in our oilpatch, but I believe what we’re also seeing now is an evaluation by companies of the properties they currently have, plus a budgetary focus on coordinating drilling programs in areas that had been affected by the wet conditions this year. “Dr illing continues to be a head of last year, w it h a record number of rigs working in the province. And clearly the industry has confidence in Saskatchewan, as evidenced by our province’s number one investment ranking for Canada in the Fraser Institute’s 2011 Global Petroleum Survey.” Earlier in August there were 116 active rigs in Saskatchewan, the highest rig count on record. T he Wey bu r n-E ste v a n a r ea of Saskatchewan received the most bids recently with sales of $11 million. The Lloydminster, Sask., area was next at $5.7 million, followed by the Swift Current, Sask., area at $2.8 million and Kindersley-Kerrobert brought in $2.2 million. The top purchaser of acreage in the province was Prairie Land & Investment Services Ltd., which spent $3.95 million to acquire 14 lease parcels.
The Bakken remains the hot spot in Saskatchewan while tight oil drilling is driving a land boom in Manitoba.
Manitoba is within touching distance of its record land sale year in 2010 after having collected bonus bids of $10.1 million so far in 2011 with one auction left. Year-to-date, the provincial government has sold 17,798 hectares at an average of $567.60 per hectare. Last year, Manitoba collected just over $12 million in bonus revenue, a record. This week’s land sale added $2.83 million to provincial coffers on 1,952 hectares at an average price of $1,450. Canadian Coastal Resources Ltd. tendered the bonus high at a recent sale of $320,000 for a 128-hectare lease parcel, for the northern half of section 29 at 02-28WP. The parcel’s average price was $2,500 per hectare. Daily Oil Bulletin records show that EOG Resources Canada Inc. licensed a new field wildcat oil well at the end of June SASKATCHEWAN WELL ACTIVITY
AUG/10
AUG/11
WELL LICENCES
350
425
▲
▲
▲
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • Oc t o b e r 2 0 1 1
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Saskatchewan
Crescent Point heads south of the border Saskatchewan Bak ken oil producer Crescent Point Energy Corp. has acquired approximately 750 barrels of oil equivalent per day of Bakken light oil production and more than 78 net sections of land in North Dakota through two strategic acquisitions. The company believes the land to be prospective for the Bakken and Three Forks zones. The majority of the land is in a highly prospective area of the Bakken that is adjacent to existing Crescent Point properties, further consolidating the com pany’s land position in North Dakota. Combi ned considerat ion for t he acquisit ions was approx imately $164 million of cash. Key attributes of the acquisitions include more than 78 net sections of land, of which the majority are operated; average land acquisition cost of approximately $2,500 per acre, net of value for production; and more than 140 net internally identified low-risk
drilling locations in the Bakken and Three Forks zones. Pro forma the acquisitions, Crescent Point now has more than 165 net sections of lower-r isk land w it hin t he main productive areas of the North Dakota Bakken. The company has internally ident i f ied approx i mately 26 0 net lowrisk drilling locations on these lands. Currently, Crescent Point’s production in the United States is approximately 1,000 barrels per day. To date in 2011, the company has participated in the drilling of 16 (2.2 net) non-operated North Dakota Bakken/ Three Forks horizontal oil wells and has drilled its first operated North Dakota Ba k ken hor izonta l oi l wel l, wh ic h the company expected to complete in September. In addition, the company has entered into a two-year agreement with a leading U.S. fracture stimulation company with operations in North Dakota to
secure access to equipment and services for the company’s expanded development plans in 2012. The agreement is effective in 2012 and will provide the company with full access to fracture stimulation equipment to complete wells and put production on in a timely manner. In total, the company now expects to drill 10 net wells in North Dakota in 2011, up from previous plans of three net wells. A s a resu lt of t he acquisit ion s, Crescent Point is upwardly revising its 2011 capital expenditure plans and production guidance. Capital expenditures are expected to increase by $50 million to $1.05 billion, with 100 per cent of the increase allocated to development capital on the acquired assets. Crescent Point is also upwardly revising its 2011 exit production rate to more than 77,500 barrels of oil equivalent per day from 76,500 barrels per day. — DAILY OIL BULLETIN
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Oc t o b e r 2 0 1 1 • O I L & G A S I N Q U I R E R
Saskatchewan
Devon targets Saskatchewan Viking, other Canadian plays Devon Energy Corporation is pursuing a wide range of exploration opportunities across North America, including in western Canada, where it’s conducting oil and liquids-rich exploration drilling. “Given the recent advances in drilling and completion technolog y and the stacked pay nature of these basins, we’re pursuing more than 20 oil and liquids-rich plays that have emerged in these two basins alone,” said John R ichels, president and chief executive officer, referring to the Western C a n ad i a n S e d i me nt a r y B a s i n a nd Permian Basin during a second-quarter conference call. T he company ’s overall Canadian production in the second quarter fell to 199,200 barrels of oil equivalent per day from about 206,700 barrels during the same period last year. David Hager, executive vice-president of exploration and production, said that Devon has a significant exploration effort in Canada targeting the Deep
Basin where it has Cardium and Lower Cretaceous drilling programs underway as well as a Cardium program in the Ferrier area and a Viking program in Saskatchewan. “Although wet weather has delayed a portion of our Canadian exploration program, we still expect to complete our 2011 program,” he noted. “At our Viking light oil play in Saskatchewan, we did complete two wells in the second quarter, one of which had initial production of 90 barrels of oil per day.” The company expects this play to be economic with well costs in the $1-millionto $1.2-million-per-well range, initial production of approximately 40 barrels per day and estimated ultimate recovery of 50,000 barrels. “While these results are encouraging, we’re still in the early stages of evaluating the potential on our 900,000-netacre position. If successful, we could have more than 1,000 Viking drilling locations,” Hager said.
We Ask The Right Questions
He added that during the second quarter, Jackfish 1 production averaged 31,000 barrels per day, net of royalties. At Jackfish 2, the company began injecting steam in the second quarter. “All four pads are currently in the circulation phase of the process,” he said. “This is the initial stage where steam is injected into both the injector and producer wells to begin warming t he reser voir. Later t his mont h [September], three of the pads w ill move into t he par tial SAGD [steam assisted gravity drainage] phase and production will continue to ramp up.” Hager added that Devon exited the quarter producing about 1,000 barrels per day, net of royalties, at Jackfish 2. “At Pike, with data from nearly 400 wells and some 60 square miles of seismic, our SAGD team has begun engineering work on a 105,000-barrel-per-day facility for Pike 1,” he said. “This would be essentially three Jackfish-sized facilities from a single plant site.”
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Central Canada
Enbridge looks to move oilsands into eastern Canada
Photo: Joey Podlubny
By Lynda Harrison
The Monarch pipeline targeting the U.S. Gulf Coast is still under consideration at Enbridge.
Enbridge Inc. says it is seriously considering providing new pipeline access for light crude oil to the East Coast via a reversal of Line 9 and building more capacity out of Alberta’s oilsands region around 2015 or 2016 to pick up incremental volumes from new projects. “The Line 9 reversal is one of the projects that is front and centre with us right now,” Patrick Daniel, president and chief executive officer, told a secondquarter results conference call. The plan would require a reversal of flow on its pipeline, which can carry up to 240,000 barrels a day to Sarnia, Ont., from Montreal. The company had proposed a simila r idea in 20 08, t he $350 -m i l lion Trailbreaker project, which would have shipped crude on Line 9 and reversed a P or t l a n d - M ont r e a l p ip e l i n e . A t Portland, Ore., the crude would have been loaded onto tankers and shipped to the Gulf Coast. Enbridge is considering both shortand long-term Line 9 potential, said Daniel. The short-term proposal to move crude oil into Ontario on Line 9A towards
Nanticoke, Ont., and a longer-term, full reversal of Line 9 to move crude off the East Coast and into refineries on the East Coast are “getting some very close work and examination,” said Daniel. They both look highly prospective, he said.
differential. We’re concerned that there’s going to be a significant synthetic differential that develops as well if we don’t broaden that market.” During the second quarter, Enbridge continued to advance a number of growth projects including existing liquids pipelines projects in the oilsands region. Construction is continuing on projects including the Christina Lake lateral, Woodland pipeline, Wood Buffalo pipeline, Waupisoo pipeline and Athabasca pipeline expansion. Enbridge is still considering building the Monarch pipeline, whose northern portion would be a combination of using existing capacity and building a pipeline south of Cushing, Olka., to the U.S. Gulf Coast by late 2013. No presidential permit is required since they would all exist within the United States, callers heard. T he reg ulator y rev iew of t he Northern Gateway Project took a step forward in the second quarter with the release by the Joint Review Panel of the hearing order setting out the schedule for the hearing process. “We’re pleased with the scope of the public hearings, which clearly meets the widely expressed desire for a full and open review of the project,” said Daniel.
" We’re concerned that there’s going to be a significant synthetic differential that develops as well if we don’t broaden that market.” — Patrick Daniel, President and Chief Executive Officer, Enbridge Inc.
“As the market continues to push Canadian crude further east, those projects become even more likely. That push east, of course, comes from the fact that we’ve got a lot of heavy crude cracking capacity going into the Midwest, which takes away some of the light processing capacity and means that it’s very important for Canadian producers to be able to broaden out the market. As you know, many times in the past we’ve focused on the huge light-heavy
Enbridge currently estimates that Northern Gateway could be in service by 2017 at the earliest, at an estimated cost of $5.5 billion. Expenditures to date, which relate primarily to the regulatory process, are approximately $200 million, including $100 million in funding secured from western Canadian producers and Pacific Rim refiners toward the costs of seeking the necessary regulatory approvals for the project. O I L & G A S I N Q U I R E R • Oc t o b e r 2 0 1 1
55
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East Coast
Environmental review planned for Old Harry project in Gulf of St. Lawrence
Map: Corridor Resources
By James Mahony
The Old Harry prospect, located in the Gulf of St. Lawrence, could contain over a billion barrels of oil.
Responding to a request from Ottawa, the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) has agreed to oversee a two-pronged environmental assessment of a plan to drill on Newfoundland’s Old Harry prospect. Following a written request from federal Minister of the Environment Peter Kent, the board has endorsed what will be two separate, parallel processes to review the environmental aspects of a proposal to drill submitted earlier this year by Corridor Resources Inc. In February, Corridor submitted plans to the C-NLOPB to drill its first offshore exploratory well off Cape Anguille (Old Harry) between 2012 and early 2014. Old Harry is on the Newfoundland side of the Gulf of St. Lawrence and part of Exploration Licence (EL) 1105. Corridor’s application triggered an environmental assessment process. In June, the C-NLOPB said public comments in response to Corridor’s proposal were greater than any it had received on the environmental aspects of an exploration project in its 26-year history. In a letter to minister Kent, C-NLOPB board chair and
chief executive officer Max Ruelokke said he “believes this warrants reference to a mediator or review panel.” In response, Kent requested a twopronged approach for environmental assessment of Corridor’s proposal, asking
planning for t wo separate processes that are independent, but informed by one another.” In setting the stage for the twopronged process, the board is striking a working group to oversee the updating of the SEA, which will begin with development of a scoping document. Public consultation will be integral to the SEA process, and the board said it would ensure that such consultation will be part of the review process. The C-NLOPB will also engage an independent reviewer to conduct extensive public consultations for the screening of Corridor Resources’ proposal to drill on EL 1105. The board said it is finalizing both the scoping document for the screening and terms of reference for the public review. In the past, any thought of drilling on Old Harry was complicated by the fact that the area straddles the offshore border between Newfoundland and Quebec in the Gulf of St. Lawrence. Until recently, proposals to drill there would have raised potential jurisdictional issues between the two provinces. In March, however, the federal government and Quebec signed an agreement for
Public consultation will be integral to the Strategic Environment Assessment process, and the board said it would ensure that such consultation will be part of the review process. the board to address public concerns by updating its 2007 Strategic Environment A ssessment (SE A) for t he Wester n Newfoundland Offshore Area, which includes Old Harry. As well, the minister asked that the environmental assessment continue as a screening “with extensive public consultation.” In response to minister Kent’s letter, Ruelokke said the board had agreed to the minister’s requests. “We have begun
the development of oil and gas resources in the Gulf of St. Lawrence. While the agreement does not advance Corridor’s specific proposal, it reduces what would almost certainly have been an obstacle to oil and gas development in the area. Roughly 30 kilometres long and 12 wide, the geological structure underlying Old Harry is considered one of the largest, undrilled geological structures in eastern Canada. O I L & G A S I N Q U I R E R • Oc t o b e r 2 0 1 1
57
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International
EOG sand mine could save $400M
Photo: Joey Podlubny
By Pat Roche
Prices for frac sand have skyrocketed due to demand from tight oil and shale gas plays.
EOG Resources, Inc. could save as much as $400 million during development of its resource plays by supplying its own proppant sand for fracture stimulations. With the proliferation of tight oil and natural gas plays in North America in recent years, prices of frac sand have skyrocketed. In response, Houston-based EOG is developing its own sand mine in Chippewa County of northwestern Wisconsin. If EOG uses that sand with dedicated frac fleets on plays such as the Eagle Ford and the Barnett, “we could probably be looking at savings of around $400 million—just on the sand part,” an EOG executive told the company’s second-quarter earnings conference. “Then we have the benefit of the dedicated frac fleets and the improved efficiency there. We have these contracted similar to how we have drilling rigs contracted to us,” the call heard. In the southeastern United States, the company is also developing its own rail facilities. Most oil is pipelined, but some companies have found that rail can sometimes be a profitable alternative as it ramps up its liquids output.
EOG expects to increase its total 2011 crude oil and condensate production by a dramatic 52 per cent over 2010. “Our second-quarter domestic realized oil price versus the West Texas Intermediate benchmark was slightly better than similarly situated oil producers. This is primarily because of our Bakken crude-by-rail system and having a dedicated truck fleet to service the Eagle Ford,” said Mark Papa, EOG’s chairman and chief executive officer. EOG expects to have the capability next year to rail most of its Bakken and some of its Eagle Ford production to Louisiana instead of the key crude distribution hub at Cushing, Okla. “Last week we signed an agreement for a 70,000-barrel-a-day train off-loading facility to be built in St. James, Louisiana. The EOG-owned facility is expected to be in service late in the first quarter of 2012,” Papa told analysts. Reuters reports that EOG and shipper NuStar Energy LP signed a deal to build a rail off-loading facility in Louisiana to receive oil from U.S. shale plays such as the Eagle Ford in southern Texas.
“With our rail system next year we’ll have the f lexibility to move crude to EOG-owned facilities at either Cushing or Louisiana,” Papa said. Given that oil and natural gas liquids are “quite profitable” while dry natural gas is “at best marginally profitable,” Papa said he is “just befuddled” as to why some companies continue to pursue the latter commodity—“which is pushing more gas into an already over-supplied market”—and why some analysts give credit for such growth. “Why anybody in the industry pays the slightest attention to natural gas growth in North America is beyond me,” Papa told his company’s conference call. “We continue to have a one- to threeyear cautionary view regarding North American gas prices,” he said. EOG believes gas prices will improve by 2014 as gas-powered electricity demand increases. “For this reason we have no interest in growing 2011 North American gas volumes at current price levels,” Papa said. EOG is drilling dry gas only where necessary to secure acreage. Due to lower gas production, the company’s second-quarter output in Canada fell to 32,667 barrels of oil equivalent a day during the second quarter from 41,500 barrels a day in the corresponding 2010 period. The company said its gas production fell due to asset divestitures and the reallocation of capital to liquids-rich plays. In the longer term in Canada, EOG hopes to take advantage of overseas gas prices, which are tied to oil prices. The company is partnered with Encana Corporation and Apache Corporation to develop a liquefied natural gas project at the British Columbia deepwater port of Kitimat. “You’ve likely already heard Kitimat project status updates from Encana and Apache and we concur with their status comments. Like them, we’re excited about the project—but it’s not yet a done deal,” Papa said. “The project is contingent upon the cost-estimate study and the ability to lock in long-term oil-index off-take contracts.” O I L & G A S I N Q U I R E R • Oc t o b e r 2 0 1 1
59
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NEW
BUSINESS INTELLIGENCE A Balanced Strategic Approach to Management Dustin Sundby, Oilfield Service Leader, MNP
Most successful oilfield service companies understand that effective
Operations
strategic management and planning is a key factor of business success.
When it comes to understanding operations, one of the most important
Industry conditions have improved since 2008 and 2009, but oilfield ser-
factors is to have a good grasp on the cost of production and ways to
vice companies are now faced with labour and equipment shortages—and
improve productivity, efficiency and quality. Understanding what your
a cloud looms due to worldwide economic instability. Taking a balanced
break-even points are will also allow you to make better business decisions.
approach to ensure you are prepared to overcome obstacles and meet your business goals allows your oilfield service company to contend with
People
this changing landscape.
People are possibly the most important aspect of your business. Recruit, train,
The Balanced Strategic Approach to Management is a full strategic plan-
mentor and reward are the pillars to proper people management, and all four
ning and management system that allows oilfield service companies to align
are extremely important in today’s environment. If these pillars don’t exist in an
business activities with vision and strategy. Rather than analyzing financial
oilfield services company, the “tone from the top” needs to change. Otherwise,
data alone, the Balanced Strategic Approach to Management takes opera-
your company will not be able to adapt to the changing labour landscape.
tional, marketing and developmental inputs into account to provide a more comprehensive view of the company.
A significant percentage of owners of oilfield service companies are nearing retirement. It is imperative for them to recognize that now is the time to invest
There are four main components to consider in the Balanced Strategic
in their people, because a company that has an owner who doesn’t delegate
Approach to Management: customers, operations, people and finance.
responsibilities is a company that isn’t nearly as attractive to a buyer as one
Within each of these components, there are areas to consider and questions
with a proper management structure and a performance management system.
to ask. The components are equally important and do not need to be completed in any particular order.
Finance Once the other three components of the Balanced Strategic Approach to
Customers
Management are working successfully, the financial component will also
The recent industry rebound has had significant impact on the customer
begin to improve. It is also helpful to develop a planning process based on
component. Lack of equipment and manpower means that oilfield service
your financial statements to improve the financial fluency of the entire
companies need to be more proactive in allocating these limited resources.
management team. Often, financial measures are lagging indicators, so
Unlike in 2008 and 2009, where finding work was a concern, the issue is
a scenario analysis should be conducted to help determine the effec-
now “picking your horse” to ensure that your customer is in it for the long
tiveness of your business. This analysis should focus upon liquidity, debt
haul and has the financial means to get there. It is simple, sound business
coverage and profitability. Without question, cash is king, but today it is
advice to try and attract customers that you want to work with instead of
more so because credit hasn’t returned to pre-2008 levels and as a result,
just waiting for the phone to ring.
necessary steps should be taken to ensure cash flow is being managed
Equally important, oilfield service companies should strive to become
very carefully.
“partners” versus having the traditional supplier/customer relationship.
Applying the Balanced Strategic Approach to Management is not a major
This gives oilfield service companies input into the services provided to
undertaking. The most common obstacle is getting started. Once you have
each customer. Lastly, the old adage of “loving your customer to death”
prioritized the areas in which you want to improve and begun taking steps to
holds true, as there is a limited number of “A” customers and the competi-
make the required changes, you will find your oilfield services company much
tion is never far behind.
better prepared to compete and succeed.
For more information on this topic, please contact Dustin Sundby, Oilfield Service Leader, MNP, at 1-877-500-0779.
O I L & G A S I N Q U I R E R • Oc t o b e r 2 0 1 1
61
Advertisers' Index Allan R. Nelson Engineering (1997) Inc . . . . . . . . 53 Annugas Compression Consulting Ltd . . . . . . . . 36 ASAP Heating & Well Servicing Corp . . . . . . . . . 30 Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . 31 Beaver Plastics Ltd . . . . . . . . . . . . . . . . . . . . . . . 53 Bilton Welding and Manufacturing Ltd . . . . . . . 54 Black Sivalls & Bryson (Canada) Ltd . . . . . . . . . . 20 Brother’s Specialized Coating Systems Ltd . . . . 16 Brownlee LLP . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 CADE Canadian Association of Drilling Engineers . . . . . . . . . . . . . . . . . . . . 50 Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . . 10 Canadian Heavy Oil Association . . . . . . . . . . . . . 47 Canadian Standards Association . . . . . . . . . . . . 42 CARES Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 City of Grande Prairie . . . . . . . . . . . . . . . . . . . . . . 18 Clean Harbors . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Contain Enviro Services Ltd . . . . inside back cover Dean’s Pump Service Ltd . . . . . . . . . . . . . . . . . . 54 DFI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
62
Oc t o b e r 2 0 1 1 • O I L & G A S I N Q U I R E R
Diversified Glycol Services Inc . . . . . . . . . . . . . . 40
MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 40
Docktor Oilfield Transport Corp outside back cover
Northgate Industries Ltd . . . . . . . . . . . . . . . . . . . 41
Dragon Products . . . . . . . . . . . . . . . . . . . . . . . . . 28
Northstar . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 35
Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . 42
EITI Electrical Industry Training Institute . . . . . . 39
Ocean Fluids & Filtration . . . . . . . . . . . . . . . . . . 49
Falvo Electrical Supply Ltd . . . . . . . . . . . . . . . . . 49 Fort Nelson & the NRRM . . . . . . . . . . . . . . . . . . . 14 General Motors of Canada Ltd . . . . . . . . . . . . . . 22 Guard-All Structures . . . . . . . . . . . . . . . . . . . . . 45 Hughson Trucking Inc . . . . . . . . . . . . . . . . . . . . . 25 Imperial Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Joule Technical Sales Inc . . . . . . . . . . . . . . . . . . . 56 Kenwood Electronics Canada Inc . . . . . . . . . . 26-27 LJ Welding & Machine . . . . . . . . . . . . . . . . . . . . . 34
Oil Lift Technology Inc . . . . . . . . . . . . . . . . . . . . 49 OilPro Oilfield Production Equipment Ltd . . . . . 54 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 46 Platinum Grover Int. Inc . . . . . . . inside front cover Propak Systems Ltd . . . . . . . . . . . . . . . . . . . . . . . 3 Risley Equipment Inc . . . . . . . . . . . . . . . . . . . . . 58 Suncor Energy Inc . . . . . . . . . . . . . . . . . . . . . . . . . 21 Systech Instrumentation Inc . . . . . . . . . . . . . . . 50 TCA Marketing Ltd . . . . . . . . . . . . . . . . . . . . . . . . 7
LoTech Manufacturing Inc . . . . . . . . . . . . . . . . . 54
Trans Peace Construction (1987) Ltd . . . . . . . . . 46
MCI Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . 11
Meridian Mfg Group . . . . . . . . . . . . . . . . . . . . . . . 15
Waydex Services LP . . . . . . . . . . . . . . . . . . . . . . 24
Mitra Industries . . . . . . . . . . . . . . . . . . . . . . . . . 44
Wellhead Distributors Int’l Ltd . . . . . . . . . . . . . . . 5
441678 Contain Enviro Services Ltd full page 路 fp IBC
DOCKTOR OILFIELD TRANSPORT CORP
GENERAL OILFIELD HEAVY HAUL COMPLETION PACKAGE MOVES TANKS & TANK FARM MOVES CRANE & PICKER SERVICE Pickers to 45 ton Winch Tractors Tri-Drive Winches Bed Trucks to 400” Texas Beds to 280” 12-16-24 Wheel Trailers Highboys / Trombones Doubledrops Hydraulic Tank Cradles 40-48 Wheel Combos
COMPLETE OILFIELD SERVICE
Drayton Valley 780.514.7898 Edson 780.728.0089 w w w. d o c k t o r t r a n s p o r t . c o m