Re-inventing the service rig Technicoil’s Marv Clifton and Ben Nowell are adapting coiled tubing to multi-stage frac completions High-pressure outlook Pressure vessel manufacturers face still-slow oilsands activity and increasing foreign competition CARDIUM RUSH Penn West CEO Bill Andrew outlines a vast new tight oil play in central Alberta Canadian Publication Mail Product Agreement #40069240 MARCH 2010 ■ $6.00 Check out this story and more in the Red Deer Focus section inside
Transcript
Re-inventing the service rigTechnicoil’s Marv Clifton and Ben Nowell are adapting coiled tubing to multi-stage frac completions
High-pressure outlookPressure vessel manufacturers face still-slow oilsands activity and increasing foreign competition
CaRdium RusHPenn West CEO Bill andrew outlines a vast new tight oil play in central alberta
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Check out this story and more in the Red Deer Focus section inside
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6 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
Table of Contents
F E A T U R E S
re-inventing the service rigby Mike ByfieldTechnicoil’s Marv Clifton and Ben Nowell adapted
coiled tubing to multi-stage frac completions
12
A regional supplement toMarch 2010
RED DEER& CENTRAL ALBERTA
A regional supplement toMarch 2010
RED DEER& CENTRAL ALBERTA
A regional supplement toMarch 2010
RED DEER& CENTRAL ALBERTA
PLUS
TighT hoLeS
A secretive race is on to acquire
land and drilling insights in
Alberta’s Cardium formation
CardiUm rUSh
Penn West CEO Bill Andrew
outlines a vast new tight oil play
in central Alberta
Synergy faCiLiTaTor
KriSTa WaTerS redUCeS friCTion
beTWeen reSidenTS and The PaTChTalk is cheap(er)
high-pressure outlookby Graham ChandlerPressure vessel manufacturers worry about still-slow oilsands
activity and increasing foreign competition
18
Keeping readers regionally informed
Focus on Red Deerbegins after page 24
The Cardium tight oil play is sparking renewed field activity in Central
Alberta. Take a look at the players, and how stakeholders are striving to
remain neighbourly in an increasingly crowded corridor.
As the economy strengthens, look for stories with the Recession to Recovery logo to help you through uncertain times. And be sure to check out junewarren-nickles.com/r2r for Recession to Recovery stories from all JuneWarren-Nickle’s publications.
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R E G I O N A L N E W S
25 British Columbia• In 2010, EnCana will frac Horn River wells
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• Apache invests in $3B LNG terminal and
plans Canadian expansion
29 Northwestern Alberta/Foothills• Orion focuses its $85M capital budget
on Kaybob and Redwater
31 Northeastern Alberta• ConocoPhillips and Total proceed with
Surmont SAGD expansion
33 Central Alberta• Ron Liepert becomes Alberta’s energy
minister in a cabinet shuffle
• NAL’s $175M capital budget has a strong
focus on Cardium oil play
I N E V E R Y I S S U E
37 Southern Alberta• Some oilfield service companies see
stronger prices on the horizon
• PSAC raises its 2010 drilling forecast
by 1,000 wells
43 Saskatchewan• PetroBakken will apply its Sask
expertise to Alberta Cardium
45 Central Canada• Environmental policies that damage
the West hurt all of Canada
47 International• Three Canadian energy service
companies land overseas contracts
10 Statistics at a Glance• Completions data, spot gas prices, gas
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Table of Contents
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N E X T I S S U E
An oilpatch salute to womenVirtually everyone anticipates another shortage of energy services personnel when field activity rates rebound. Can women help make up that shortfall in significant numbers? Oil & Gas Inquirer profiles women who have made careers in this demanding sector.
Marv Clifton and Ben Nowell of Technicoil Corporation fit the classic patch profile—both originally blue-collar boys from the sticks who got their start labouring in the oilfield. Thanks to financial pressure and brilliant inspiration, these two Calgarians developed the coiled tubing service rig. Others soon came up with variations on the same theme, includ-ing Trailblazer and Xtreme Coil. Altogether, it’s a great extension of western Canada’s world-leading achievements with coiled tubing.
From land-based rig top drives to multi-stage fracs, the West has a strong record of innovation. Our economy will do fine as long as men like Nowell and Clifton have the opportunity to work effectively and create wealth. Unfortunately, that’s not the case today. This industry has not only been afflicted with an unstable royalty regime, but it’s seriously over-regulated.
The provincial government’s Competitiveness Review heard all about over-regula-tion when it met with the Canadian Association of Petroleum Producers and the Small Explorers and Producers Association of Canada. Although the sessions were not open to the media, I’m told that oilmen protested even more bitterly against the job-strangling snarl of regulations than royalty rates.
As this issue of Oil & Gas Inquirer goes to press, the Competitiveness Review was expected to release its report within a few weeks. Conducting that review are former Nexen VP Roger Thomas and Chris Fong, formerly with the Royal Bank of Canada. They’ll probably make the right recommendations. But will Premier Ed Stelmach and his team listen?
If recent public opinion polling is correct, most Albertans now question the wisdom of leaving the same political party in office for four decades. The white-hot core of that opposition is the petroleum industry. At this late stage, its distrust won’t evaporate even if the royalty structure is reformed properly.
However, slashing red tape quickly and decisively would restore some respect, maybe even gratitude, toward Stelmach within the province’s key industry. Regulatory stream-lining represents his best shot—if not his only shot—at retaining power.
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Subscription Inquiries Telephone: 1.866.543.7888 Email: [email protected] Online: junewarren–nickles.comOil & Gas Inquirer is owned by JuneWarren-Nickle’s Energy Group and is published monthly.
Made in CanadaThe 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.
If you know an admirable person to profile in On The Job—he or she may be a veteran or apprentice, field or shop, wise or a little crazy—please give me a call at (780) 944-9333, or email [email protected]. In fact, feel free to sound off about any concern at all—that’s a personal invitation.
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10 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
StatsAT A GLANCE Reserve replacement ratio achieved in 2009 by
Exxon Mobil Corporation, largely due to almost one billion BOE credited to LNG projects in Papua New Guinea and Australia.
133 per cent199,668Number of Albertans employed directly or indirectly due to natural gas activity in 2008, according to a new study from IHS Global Insight
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12 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
Feature
F rom 2002 to 2008, Technicoil Corporation built a fleet of coiled tubing rigs designed to work with
vertical shallow gas and coalbed methane wells. In 2007–08, however, the boom ended, slamming the shallow drilling sector hardest of all. In its determined thrusts to find new work, Technicoil did more than just survive—the Calgary-based firm has pioneered revolutionary changes to the service rig business.
Technicoil president Marvin Clifton and technical specialist Ben Nowell have adapted coiled tubing (CT) technology to a pair of new functions: first, rigless
completions of horizontal wells with multi-stage fracs and, second, running wireline in horizontal steam assisted gravity drainage (SAGD) wellbores. “For these tasks, we’ve shown that our masted CT units are faster, safer, and less intrusive than traditional service rigs,” Clifton comments.
Technicoil’s fleet consists of 17 masted CT service rigs (the largest fleet of coiled fracturing units anywhere), and 6 hybrid CT drilling rigs. In addition, the company purchased a fleet of nine conventional service rigs (eight singles and a double) in 2007, a diversification from exploration
and development into the more stable pro-duction side of the industry. The personnel roster stands above 250 and this winter the company is 30 per cent busier than it anticipated just a few months ago.
Sur v iva l has come at a pr ice. Technicoil’s share value has plunged from the $4 range in 2006 to $0.65 currently, and the company lost $2.9 million on revenue of $30.6 million for the first nine months of 2009 (the last period for which financial results are available). Like many service companies, the company can be grateful for low interest rates on its debt (today’s bank prime rate of 2 to 3 per cent
rE-INVENTING ThESErVIcE rIGTechnicoil’s Marv Clifton and Ben Nowell are adapting coiled tubing to multi-stage frac completions
O I L & G A S I N Q U I R E R • M a r c h 2 0 1 0 13
is a stark contrast to the oilpatch collapse of the early 1980s, when interest rates ran as high as 20 per cent).
While its conventional service rigs are operating at about the same rate as last year, Technicoil’s CT units are doing much better thanks to resource plays and SAGD activity. “I think the classic service rig will have its place in our industry for a long time to come, but it will be pushed more and more onto the production side,” Clifton predicts. “For well completions, I think CT service rigs will con-tinue to gain market share.”
The Technicoil CEO grew up in Taber, where his father worked in a sugar refinery.
Clifton first started in the patch working summers as a rig hand while earning his bachelor’s degree (sociology and psychol-ogy plus an education credential) at the University of Lethbridge. He taught school for two years in Vauxhall, Alberta, then decided to study commerce at Utah’s well-known Brigham Young University.
On joining Bow Island Drilling in 1974, the former teacher took to oil and gas like a duck to water. After rising to general man-ager of Atco Drilling, he moved to Cactus Drilling from 1980 to 1997, becoming president of that company. When Cactus was taken over, Clifton became senior VP
of operations in Precision Drilling’s well servicing arm.
Technicoil brought him on board at the end of 2002. The young company had already made a name for itself by building a dozen CT units that featured masts. A classic CT rig feeds its coiled tubing into the well by an injector head that’s suspended from an overhead crane. Technicoil found that suspending the injector head from a mast offers greater efficiency and safety.
Technicoil’s CT rigs were self-propelled body units (i.e. the front cab and engine form a single unit with the coiled tubing
Phot
o: T
echn
icoi
l Cor
pora
tion
Technicoil CEO Marvin Clifton (left) and technical specialist Ben Nowell designed CT service rigs for frac through coiled tubing in multi-frac horizontal well completions.
CT Drilling Rig
Photo: Jack Cusano
assembly). They offered mobility plus a small footprint on the farmlands where most shallow gas drilling takes place. The original concept had been to drill vertical wells with this innovative equipment, but it proved more suitable for “frac through coil” completion services. Halliburton contracted the entire fleet, then triggered a crisis by not renewing at the end of the contract term.
“At that point, Halliburton bought five of the units. I was hired as chief operating officer by Art Dumont [then Technicoil’s CEO] to get the rest of our equipment back to work,” Clifton says. About the same time, Technicoil took another stab at building CT shallow drilling rigs, com-pleting two more self-propelled units, this time incorporating top drives.
Fortunately, coalbed methane drilling was starting to take off in central Alberta’s Horseshoe Canyon formation. Each verti-cal CBM well requires a series of hydraul-ic fracs, performed precisely and quickly.
Calfrac Well Services Ltd., primarily a pres-sure pumping firm, breathed new life into Technicoil by subcontracting its uniquely configured “frac through coil” fleet.
Techncoil continued to innovate. Its CT self-propelled body units, although capable of moving across fields, were too heavy to qualify for highway permits. At that time, CBM wells tended to be much further apart than shallow gas wells, so the CT rigs had to be loaded onto 40-wheel trailers. In 2006, to implement a more cost-effective alternative, Dumont and Clifton hired a man who relishes mechani-cal challenges.
Ben Nowell has dedicated most of his working life to oil and gas completions. After finishing high school at Sandy Lake in the southwestern corner of Manitoba, he came to Alberta. “I’ve roughnecked, pushed tools, and built rigs as a project manager,” Nowell says. His first project at Technicoil was lopping the cab and engine
off each body unit, then replacing the drive train with a 24-wheel suspension. With the addition of a separate tractor, the firm had created a highly mobile, com-pact solution that could be hauled without expensive third-party truckers.
Technicoil has continued to evolve its CT rigs—a term that the company now uses in place of “frac through coil”. Since 2005, Nowell has supervised con-struction of 10 new CT service rigs, with the first unveiled at Calgary’s Global Petroleum Show in 2006. Trailers have become progressively longer, depth capacities greater.
Nowell also managed the creation of five hybrid drilling rigs (a reference to their use of both CT and jointed pipe), the last being completed in 2008. These top drive-equipped units, built by Foremost Industries LP in Calgary, can drill to 2,000 metres. “They are among the most modern and advanced coiled drilling rigs in the world,” Clifton says. During the boom, construction was often delayed by late deliveries and other difficulties that are typical during busy times.
But even before Technicoil’s “bleed-ing edge” fleet of CT service and drilling rigs was complete, the bottom fell off the
14 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
Feature
“They are among the most modern and advanced coiled drilling rigs in the world.”
–Marvin clifton, President, Technicoil
Technicoil’s innovative CT service rigs are based on technology that was originally intended for drilling shallow wells.
market due to declining natural gas prices. “CBM drilling peaked in 2006 and we were overbuilt for the western Canadian market,” Nowell says. Additionally, the relatively small service company didn’t have international exposure. Fortunately, the black economic cloud did have a silver lining, and a big one. Northeastern British Columbia’s Montney and Horn River Basin shale gas plays are so potent in terms of potential reserves that they’ve continu-ously moved forward.
Shale gas development is completely dependent on multi-stage fracturing of long horizontal wellbores. “Shell and a
Photo: Technicoil Corporation
O I L & G A S I N Q U I R E R • M a r c h 2 0 1 0 15
Feature
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16 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
“With each new resource play, we’ve been there right off the hop.”
– Marvin clifton, President, Technicoil
few other producers were already inter-ested in rigless completions,” Nowell says. “We recognized that our CT service rigs are well-suited to rigless completions. We can rig up and tear out more quickly than a conventional service rig. Like a snub-bing rig, we can enter a well under pres-sure. There, our competitive advantage is that fact that continuous coil means faster operations than jointed pipe, which snub-bing units use.”
At that stage, the challenge was con-vincing shale gas operators that coiled tubing could deliver reliable results. Their concerns included mast size (so a CT rig could accommodate a long enough tool string), reel size (which determines much coiled tubing is available for long wellbores), and the relatively small dog-house. “There are a lot of people on site when a shale gas well is being drilled and everyone wants to be at the centre
of the action,” Nowell says with a smile. “In fact, we easily made all of the adapta-tions necessary for shale gas completions. Our equipment also offers another impor-tant advantage: when a CT service rig has finished the job, it can hang off the coiled tubing as a production string. There are Montney wells that will never see a con-ventional service rig.”
Again working with Calfrac, Technicoil did its first shale gas work in the Montney on wells belonging to EnCana Corp. and Duvernay Oil Corp., which has since been acquired by Shell Canada. Today the com-pany has six CT service rigs in northeast-ern British Columbia. It’s also entered the Bakken tight oil development in southeast-ern Saskatchewan, and is now working in Alberta’s rapidly expanding Cardium tight oil initiatives. “With each new resource
Feature
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O I L & G A S I N Q U I R E R • M a r c h 2 0 1 0 17
play, we’ve been there right off the hop,” Clifton says.
At least 15 per cent of Technicoil’s rev-enue now comes from SAGD ranging in bitumen reservoirs. SAGD requires pairs of horizontal wellbores, one above the other. Steam reaches the bitumen through the injector well, warming the tarry crude so it drools downward into the production well. Hence the producer wellbore must be drilled in parallel with the injector well (typically the pair is about 15 metres apart) for thousands of metres.
Technicoil offers what it calls smart coil, an e-line inside coiled tubing. A CT service rig feeds e-line into the injector wellbore. A magnetic signal generated by the e-line guides the drilling rig as it drills the producer wellbore. There is a cheaper alternative: the e-line can be towed along the injector wellbore by a small tractor. However, Nowells points out, the tractor can be blocked by debris in wellbore, it can slip on bitumen in the raw hole, and it’s slow. “Because we push and pull from surface, our rigs can move the e-line more quickly and wellbore integrity won’t hold us up,” he says.
Operating eff iciencies being de- veloped by producers in northeast-ern British Columbia, particularly the Horn River Basin, will shift cash flows within the service sector, according to the Technicoil CEO. (Arthur Dumont retired in 2008 but remains a director.) Producers are drilling up to 16 wells from a single pad, with talk of 24 wells in the future. As a result, hundreds of fracs being performed on the same well-site, which remains in use for months at a time. “Obviously, you need a lot less con-struction and trucking if you consolidate so much drilling onto one pad,” Clifton says. “I think we’ll see a similar trend toward consolidation in other western Canadian resource plays over time.”
The Technicoil CEO’s long record as a senior executive has been critical to his company’s momentum. “Customers and our own directors respect his judgement. That confidence enables us to take more risks than usual,” Nowell says. Clifton himself does not foresee any slackening in the patch’s pace of change. “Working conditions, for example, are incomparably cleaner on a CT service rig than a tradi-tional service rig,” he says. “And the other day, I approved maternity leave for a male rig hand—we’re in a new world compared to just a few years ago.”
Feature
O I L & G A S I N Q U I R E R • M a r c h 2 0 1 0 1
Blank for Duplexing
18 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
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Alberta’s pressure vessel and heat exchanger manufacturers are major employers in Edmonton and Calgary.
O I L & G A S I N Q U I R E R • M a r c h 2 0 1 0 19
S ince January, Albertans concerned for t hei r economy have been encouraged by a spate of headlines:
“Oilsands roar back to life with move by Husky, BP”; “Oilsands rolling again”; and “Conoco, Total give boost to oilsands” do seem encouraging. Yet the 20 member companies of the Alberta Pressure Vessel Manufacturers’ Association (APVMA) aren’t ready to start cheering quite yet. Their concerns: oilsands construction plans remain smaller in scale than pre-vious years and foreign competition is intensifying.
The oilsands have long been the prin-cipal market for the province’s pressure vessel and heat exchanger manufactur-ers. “They are really the key here,” says APVMA chairman Riley Milford. “There are some coalbed methane and other natural gas developments, but there’s not as much infrastructure required for these projects—typically just pumping gas to plants where they have extra capacity.”
Oilsands producers, determined to control costs, are striving to avoid another traffic jam of massive construction con-tracts. “In 2007 and 2008, Alberta had several multi-billion-dollar oilsands pro-jects on the go,” Milford notes. “So what we’re seeing is a real shift away from that. Now, a lot of the majors are indicating that they are going to go with smaller pro-jects—breaking multi-billion-dollar pro-jects into three or four stages.”
Oilsands expansions have been hob-bled by lower crude prices and higher provincial royalties. The Edmonton region is home to about 60 per cent of Alberta’s capacity to manufacture pressure vessel and heat exchangers while the rest resides in Calgary. Both cities have been slammed by the oilsands downturn. Aker Solutions, for example, just closed a Calgary fabrica-tion shop that employed 75 or more people in better times. The multinational will continue to maintain a sizable engineer-ing and sales team in the city but will out-source its fabrication.
“When the government was decid-ing on the new royalty regime, we had lobbied them to really take a good look at what was best for Alberta as a whole, including our industry,” says Milford, the business development manager for Calgary-based Exchanger Industries. “We wanted to emphasize the subsequent effects that an excessive increase in roy-alties would have on our industry and the huge trickle-down impacts that would
Pressure vessel manufacturers worry about still-slow oilsands activity and increasing foreign competitionby Graham chandlerPhotography by Joey Podlubny
outlook HigH-preSSure
20 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
Feature
be felt by all Albertans.” The APVMA chair hopes the royalty impediments will soon be eased. That hope springs from a recent cabinet shuffle by Premier Ed Stelmach and his promise to re-examine the royalty structure.
The size of a pressure vessel often dictates where it gets built. A small unit would be pipe size, 12 inches in diam-eter and 6 feet long. A bigger vessel can be up to 32 feet in diameter and over 100 feet long. “One of those coke drums you’ve seen pictures of going from Edmonton to Fort McMurray weighed over one million pounds,” Milford says. “Edmonton vessel fabricators typically build the really big stuff.”
Alberta’s famed oilsands have drawn global attention, a factor welcomed by cost-conscious bitumen producers. “We have been seeing more and more for-eign competition in this market,” Milford says, adding that some of the upcoming oilsands projects will likely include inter-national components. The APVMA views quality as a key competitive advantage for its members. “We in Alberta have
very stringent requirements; every one of our units has to meet ABSA [Alberta Boilers Safety Association] approval—both a design review and inspection once it’s complete and hydro tested,” says the association’s chair.
“There have been cases of products from the Far East that have needed repair once they arrive here from not meeting Alberta regulations. But we are hear-ing that they have picked things up for the most part,” Milford says. In his view, foreign competition is now the greatest
challenge facing pressure vessel and heat exchanger manufacturers based in west-ern Canada.
“There’s all this work from South Korea coming here and we are being hurt by that,” says Bob Saari, the association’s manager.
APVMA members estimate that imports have already accounted for well over $50 million in business. “It’s frustrating to see trucks loaded with imported vessels and exchangers rolling by a plant gate that has a ‘Closed’ sign posted on it,” says one recently laid-off worker (who requested that his name be kept private).
The APVMA is deeply concerned that the competition be fair. Saari, who’s been involved in this industry for 23 years, is leading a government lobbying initiative. To develop a case, the association sent out
questionnaires to members asking what foreign companies are bidding in this market, what projects were involved, and the estimated cost differential offered by foreign fabrictors. “We also tried to factor in how much work Alberta fabricators lost
“It’s frustrating to see trucks loaded with imported vessels and exchangers rolling by a plant gate that has a ‘Closed’ sign posted on it.”
O I L & G A S I N Q U I R E R • M a r c h 2 0 1 0 21
Feature
[to date] to this competition,” the APVMA manager adds.
The industry group has explored the possibility of building an anti- dumping case against this class of imports. (Dumping is a term that refers to a com-pany selling a product in Canada for less than it fetches in its homeland.) Crafting a robust anti-dumping case is labourious as well as expensive, consuming six to twelve months. The APVMA’s Ottawa-based con-sultant “outlined the total process and said it would cost us at least $150,000 in legal costs,” says Saari. “We don’t have that kind of money,” especially since the actual price tag could well be significantly higher.
“Each one of our member companies would have to lay out: here’s what we sold in the past three years, here’s what we project for the next two years, here’s where we are being hurt by the competition, etc,” Saari explains. “Then the companies that are importing that equipment would have to defend their position. You would then have to go to Revenue Canada and prove to them that we have been injured. They would go to Korea and get them to open
22 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
their books to prove whether or not they have been subsidizing their industry. Once you gain all of this information, you then come back to Canada and have to appear before the CITT [Canadian International Trade Tribunal] and present the case again before they make a ruling.”
The APVMA has decided to try a lower-cost alternative. “We have written a paper on this proposing to put together a task force on how the industry is being hurt and to have something to show the
government—that would be our major lobbying effort now,” Saari says. “I have recommended a series of items that are going to the membership, after which I’m hoping we will be prepared to release it.”
On most issues, the association approaches governments indirectly. “Realistically, our lobbying efforts are
somewhat limited,” says Saari. “So we chose to get involved with some of the government-run bodies that impact our association.” To this end, one of its mem-bers chairs ABSA, which is the governing body for the rules and regulations for pres-sure vessel manufacture in the province. Another member chairs the Boilers and Pressure Vessel Council, which looks at technical issues.
“On the safety side, we have a member on the board of the Manufacturers’
Health & Safety Association, which we were a major part of founding in 1992,” says Saari. “And we have another member on CSA 51, a national committee on pressure vessel standards.” He feels this approach is better. “Instead of the staff person lobbying, we choose to place them on those organizations—it is more
efficient working from within rather than trying to lobby from outside.”
The APVMA would also like to pre-pare a SWOT analysis—strengths, weak-nesses, opportunities, and threats. “When we did a study a couple of years ago, one of the things we found was that our com-petitors in other countries, including the United States, don’t necessarily have to adhere to the same safety and reporting regulations that we have to comply with here in Canada,” Saari says. “They have different requirements where they are located. For instance, for pressure vessel design approvals we have to go through ABSA and in the U.S. [and elsewhere] that requirement is performed by an insurance company.”
Compounding the difficulties of for-eign competition for APVMA members is a new marketing hurdle. Many global engineering companies used to main-tain offices in Alberta, but times have changed. “These major [engineering] companies now have a central office, say in San Francisco, and they work on world mandates,” Saari explains. “They will shop the world for pricing on vari-ous products. Where you used to have
“Where you used to have good relationships with local engineering and purchasing staff, you are now dealing with outfits that are international in scope.”
–Bob Saari, Manager, alberta Pressure Vessel Manufacturers’ association
Feature
The Alberta Pressure Vessels Manufacturers’ Association alleges that Asian competitors are dumping product into the oilsands market.
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O I L & G A S I N Q U I R E R • M a r c h 2 0 1 0 23
good relationships with local engineering and purchasing staff, you are now deal-ing with outfits that are international in scope—it’s harder to create and maintain those relationships.”
Still, the APVMA sees positive signs for a turnaround in the sector, the most important being world oil pricing that has stabilized about US$70 per barrel for a period of months and less restrictive credit for resource companies. “We are hopeful that…this will give the producing com-munity a level of comfort that things have stabilized so that they can move forward with projects that had previously been put on hold or cancelled,” Milford says.
The association chair also thinks U.S. President Barack Obama’s recent green energy initiatives could open new busi-ness opportunities. “Solar, geothermal, and other green energy sources are touted as becoming more prevalent in the U.S. We are hoping that these emerging mar-kets will be open to Canadian supply,” Milford says. For the present, however, the APVMA’s crucial concerns are oilsands development, provincial royalty reform, and reasonable protection against dump-ing by Asian countries in this market.
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SUPPLEMENT TO OIL & GAS INQUIRER · MARCH 2010 RD3
RED DEER & CENTRal albERTa Focus
bOOm, bOOm, bOOmMike Byfield
lISTEN CaREFully and you’ll hear a drum beat—boom, boom,
boom—rolling across the parklands of central Alberta. The sound
is still gentle but it’s getting louder with every passing week. Like
southeastern Saskatchewan’s Bakken formation, the Cardium is
tight rock that’s yielding up its light crude through multi-stage
fracs in horizontal wells.
The Cardium boom won’t mature in a day. We’re looking at
a tech play, not a land rush triggered by an elephant discovery.
Activity wil l grow as producers gain experience with the best
ways to produce light oil from the formation. The same technology
promises plenty of future drilling and jobs in the Viking, the Peace
River Arch, and other formations across western Canada.
Spearheading the Cardium development is an improbable
leader—the subsidiary of a l ife insurance company. Trusts are
supposed to be low-risk operators. Yet NAL Oil & Gas Trust has
been probing tight sections of the Cardium for two years, report-
edly with growing success. The Calgary-based outfit, owned by
Manulife Financial Corporation, has core properties in south-
eastern Saskatchewan, central Alberta, and northeastern British
Columbia—all areas that are prone to resource plays.
Cautious folks will tell you that the Cardium game is stil l in
the first period, and that’s true. Conceivably, the play will fizzle or
sputter. But this prospect presents exactly the same type of tight-
rock engineering challenges that are already being licked from the
Barnett shale of Texas to British Columbia’s Horn River Basin.
Tight oil is big. Really big. Combined with coalbed methane and
shale gas, tight oil will drive decades of dril l ing activity in the
western basin, with plenty of that benefit going to central Alberta.
In fact, this region may well be on the brink of its richest period
to date.
TablE OF CONTENTS
cardium rush Penn West CEO Bill Andrew outlines a vast new tight oil play
in central Alberta
by Mike Byfield
TighT holes A secretive race is on to acquire land and drilling insights
in Alberta’s Cardium formation
by Paul Wells
Talk is cheap(er) Alberta’s growing synergy network reduces friction
between residents and the patch
by Mike Byfield974
CaRDIum RED DEER & CENTRal albERTa Focus
Penn West CEO Bill Andrew has amassed more than half of all mineral rights in the Cardium formation, where he anticipates future production totalling hundreds of thousands of barrels per day.
RD4 SUPPLEMENT TO OIL & GAS INQUIRER · MARCH 2010
Phot
o: C
hris
tina
Rya
n
ThE NEaR-DEaTh ExpERIENCE IS SlOwly ENDINg. Over the
past two years, provincial royalty changes and low natural gas prices
all but eliminated field activity in central Alberta beyond routine pro-
duction. Now an exploration frenzy is gradually building up, with a
flock of companies and crews targeting Cardium tight oil and other
emerging plays. At stake are billions of barrels of light crude.
Penn West Energy Trust owns the mineral rights to about half of
the entire Cardium geological formation in central Alberta. “The ERCB
of original oil in place for the Cardium, including 1.7 billion that have
already been produced,” says Bill Andrew, Penn West’s CEO. “In our
view, original oil in place could easily be 15 billion barrels and I’d say a
20 to 30 per cent recovery rate is a realistic prospect. So there’s poten-
tial there for production totalling tens of thousands of barrels per day.”
Andrew gives full credit for initiating the Cardium play to other
producers. “NAL, Nexstar, Bonterra, and others saw the opportunity
and moved quickly,” he says. In essence, the technology that unlocked
the Bakken tight oil play in southeastern Saskatchewan over the past
few years has been applied by a handful of other companies to tight
rock in Alberta. With Cardium estimates of oil in place running a
possible eight million barrels per section, the outlook is bringing the
junior sector back to life.
Penn West, now in the process of converting from trust to cor-
poration, is western Canada’s largest producer of light and medium
oil. These grades, which are significantly more valuable per barrel
than heavy oil, make up 44 per cent of its total output, which currently
stands at about 170,000 barrels of oil equivalent per day. The remain-
der is heavy oil (15 per cent) and natural gas (41 per cent). “Cardium
oil is light—36 or 37 degrees API—and sweet. This is first-class
crude,” Andrew says.
In his view, the trusts and other larger independent producers are
well-positioned to develop the play. “We have the resources to run pilot
projects and refine the best methods for producing from difficult res-
ervoirs,” the Penn West CEO explains. “Once they’ve built up produc-
tion to five or ten thousand barrels per day, many juniors are happy to
exit through a sale to a larger independent such as ourselves. They’re
explorers more than operators. The trusts, on the other hand, were
always intended to be operators who specialize in squeezing as much
oil and gas as possible from known fields.”
The native of Prince Edward Island, an engineer by profession,
joined Penn West in 1992 when its production was 500 barrels per
day. Previously, he’d worked for Shell Canada, Gulf Canada, Canadian
Occidental (now Nexen), Ocelot, and Opinac. Under his leadership, the
trust consolidated a massive position in central Alberta through acqui-
sitions from Petro-Canada, Cabre, Pan Canadian, Canadian Occidental,
BP Amoco, Petrofund, and Crescent Point. “We probably own 50 per cent
of Cardium play, perhaps more, and we’re still buying,” Andrew says.
His big-picture goal: to halt and possibly even reverse the long-term
decline in conventional oil production from the Western Canadian
Sedimentary Basin (WCSB). Daily output from the basin peaked in
1973 at 1.74 million barrels per day. In 2008, WCSB conventional oil
production stood at one million barrels per day, a 42 per cent drop.
Alberta’s output over the same 35 years plummeted by 65 per cent,
from 1.43 million barrels per day to 505,000.
A simple fact underpins Andrew’s optimism for the future: most
of the WCSB’s conventional oil is still in the ground. Petroleum
Technology Alliance Canada (an industry association) pegs the basin’s
original oil in place at 98 billion barrels, of which 77 billion remains
untapped. Unaided, only a certain amount of oil will flow into a well-
bore. Add flooding with water, lighter hydrocrabons, or CO2 and the
recovery percentage will rise. In Leduc pools and other reservoir
whose rock has excellent permeability and porosity, recovery rates can
reach as high as 60 to 70 per cent.
Formations with tighter rock and less permeability have yielded far
smaller shares of their oil in place. These reservoirs could not be effec-
tively tapped with vertical drilling and fracturing. “The combination of
horizontal drilling and multi-stage fracturing has dramatically improved
our capacity to economically produce from tighter rock,” Andrew says.
One measure of the importance and speed of this development: in 2007,
90 per cent of Penn West’s drilling investment went into vertical wells.
For 2010, horizontal operations should account for 90 per cent.
The Cardium formation is typical of the tighter oil prospects, with
just 17 per cent of its estimated original oil produced to date. The res-
ervoir consists of tight sandstone, with pay zones characteristically
about seven metres thick. Where the sand became intermingled with
chert gravel beds, porosity and permeability improves dramatically.
These “sweet spots” account for central Alberta’s prolific Cardium
fields, including Willesden Green, Garrington, Caroline, Carrot Creek,
Harmattan, and Keystone.
The granddaddy of them all, though, is the Pembina Cardium. This
sprawling oilfield near Drayton Valley has produced 1.3 billion barrels
since drilling began in 1953. In fact, Pembina briefly was the world’s
largest onshore oilfield, Andrew says, and it’s still considered one of
this continent’s top 10 conventional fields and the continent's largest
field by aerial extent. Penn West has nearly 900 net sections of land
in the west-central Alberta Cardium, producing 25,000 barrels of oil
equivalent per day from 2,400 net wells.
“As technology improves, we’ll see higher estimates of the origi-
nal oil in place for formations like the Cardium and higher recovery
rates,” Andrew says. He points out that Cardium production to
aNDREw
SUPPLEMENT TO OIL & GAS INQUIRER · MARCH 2010 RD5
CaRDIumRED DEER & CENTRal albERTa Focus
cardium rushby mike Byfield
Penn West CEO Bill Andrew outlines a vast new tight oil play in central Alberta
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date has been very concentrated within the permeable sweet spots.
For example, less than one per cent of the Pembina field’s total area
accounts for 250 million barrels produced to date. More than 400
million barrels have been pumped from less than 10 per cent of the
Pembina field. At Willesden Green, 10 per cent of the field’s area has
yielded 500 million barrels.
NAL and other innovators have focused their recent horizontal
drilling on tighter reservoir rock along the flanks of the historical
sweet spots at Pembina and elsewhere. Their successes indicate that
a far larger portion of the formation could very well become profitably
productive in the future. That’s an exciting prospect. From its heart
at Drayton Valley, the Cardium formation arcs south past Cochrane,
north beyond Edson, east as far as Calgary, and west to the Rocky
Mountains. In the area, the Cardium oil-bearing formation ranks as
the most extensive in North America. (Andrew says its only real peer
on this continent is the Viking formation of Alberta and Saskatchewan,
also now emerging as a hot tight oil prospect.)
Much of this immense, easily accessible prospect is well-known to
be oil-bearing. A typical Cardium vertical well in tight rock, fraced
once, flushes 30 barrels of oil per day, then declines to maybe seven
barrels over a couple of years. On the plus side, that low-rate produc-
tion continues for decades. Thousands of these stripper wells dot west-
ern Alberta. Although the Cardium was rarely a drilling target outside
of known oilfields, a producer who’d failed to score on a deeper pri-
mary target sometimes chose to frac and complete in the Cardium
zone, hoping to recover some of its costs.
A vertical well in the Cardium would typically cost about $1 mil-
lion to drill, according to Penn West. A horizontal well, fraced at eight
points along the wellbore, should generate oil production equiva-
lent to six to eight vertical wells yet costs only $3 million, including
completion and tie-in. That cost is expected to fall with greater expe-
rience. Even now, returns from Cardium tight reservoir projects are
promising. Although the province helps out with important royalty
breaks, producers warn that the program (currently temporary) needs
to be made permanent.
Andrew says the existing low-output vertical wells provide excel-
lent well control along with infrastructure like gathering pipeline
systems and access roads. “We’re in a strong position to get up the
operating curve once we learn how to produce from tight Cardium
rock,” he comments. Penn West’s capital expenditures budget, slated
to fall between $750 million to $900 million this year, includes 30 to
35 Cardium wells in west-central Alberta. That could rise, as could
the $100 million designated for the play this year.
Meanwhile, the trust is also focused on recovering additional
oil from the Pembina Cardium’s sweet spots, where 70 per cent of
the original crude typically remains in place. Here an operating
challenge is high water cuts in production due to extensive earlier
f loods in the historic field. Penn West is reportedly making prog-
ress with this work, although much of the results to date remain
confidential.
Beyond central Alberta, Penn West has tight oil initiatives at
Waskada in southwestern Manitoba, Dodsland in Saskatchewan (a
Viking play), and Swan Hills and Otter in northern Alberta.
Technological advances will continue to drive the industry,
Andrew predicts—like more frac stages per well, research into the
most effective proppants for fracs in specific reservoir conditions, and
so on. “The oil is there, we also know there’s a lot of gas left, and now
we’ve got the tools needed to produce it,” the Penn West CEO says. “I
think western Canada is entering its best-ever generation of energy
development.”
CaRDIum RED DEER & CENTRal albERTa Focus
RD6 SUPPLEMENT TO OIL & GAS INQUIRER · MARCH 2010
albERTa’S CaRDIum RESOuRCE play could see 200 or more hori-
zontal wells drilled this year. “The combination of the real extent of
the trend, extensive well control, known hydrocarbon-rich, water-free
system, and very encouraging initial test rates from a number of opera-
tors on a growing number of wells all point towards huge potential,”
said Kim Page, an analyst with Toronto-based Wellington West Capital
Markets Inc.
In a report, Wellington West said that while still early in the pro-
ductive history of the majority of Cardium horizontal multi-stage wells
drilled, it appears that these wells have initial production (IP) rates
in the 200 to 250 barrels of oil equivalent (boe) per day. They then
decline to the 100-boe-per-day range within six months, then produc-
tion drops further but stabilizes in the range of 70 to 80 boe per day
within a year.
“Based on our economic runs, Cardium horizontal wells have the
potential to rival Bakken wells in terms of expected rates of return,
reserve potential on a per-well basis, and ultimate potential for
resource development in and around existing fields,” Page said.
Companies that are active or hold large acreage positions within or
surrounding the Cardium field include ARC Energy Trust, Bonterra
Oil & Gas Ltd., Enerplus Resources Fund, NAL Oil & Gas Trust,
Midway Energy Ltd., Penn West Energy Trust, West Energy Ltd.,
Daylight Resources Trust, Angle Energy Inc., Result Energy Inc., and
Bellatrix Exploration Ltd. Other early entrants into the play such as
Berens Energy Ltd., Nexstar Energy Ltd., and Triaxon Resources Ltd.
have recently been acquired by other companies looking to increase
their position in the emerging play.
“If you plot the last two weeks of producers’ performance, you’ll see
that the Cardium producers have heavily outperformed their peers in
market performance,” said Cristina Lopez, an analyst with Macquarie
Capital Markets Canada. “Absolutely, this has been a play that has gar-
nered a lot of attention and will continue to do so.”
In a research paper, Macquarie credited NAL with advancing the
Cardium light oil play in Alberta after it witnessed the success multi-
stage horizontal drilling had in the Bakken and opted to try the same
technique on some of its Cardium acreage. “Although the use of multi-
stage horizontal drilling was believed to be amenable to other areas,
NAL Oil & Gas Trust was the first to experiment with the technology
in the Cardium [outside of a waterflood] during the fourth quarter of
2008,” the report said.
Following on NAL’s success at Garrington, Macquarie says develop-
ment of the Cardium has grown steadily in the past six months and is
“expected to explode in 2010” with an estimated 200-plus horizontal
multi-stage frac wells targeting the Cardium, up from an estimated 35
wells in 2009.
The Macquarie report said notable players that have indicated
Cardium oil programs in 2010 include Penn West at around 30 wells, ARC
at 32 wells with approximately half completed with multi-stage fracs,
NAL at 20 to 25 wells, Bonterra at approximately 25 wells, Bonavista
Energy Trust at around 20 wells, Daylight at between 15 and 20 wells,
West Energy at 24 wells, Bellatrix plans 5 to 10 wells, Angle up to 8 wells,
Vermilion Energy Trust 6 wells, and Baytex Energy Trust 5 wells.
[As of Dec. 15] there are 55 wells licensed in the Cardium and
we expect these licenses to pick up materially in the first quarter of
2010 as capital budgets are established and additional test results are
released,” Macquarie said in its report.
The Cardium in the smaller Garrington field is generally tighter
than at Pembina. The tight-rock reservoir characteristics make
Garrington an ideal candidate for experimentation with horizontal
stage fracs and in the fourth quarter of 2008, NAL initiated its first
four-well program at Garrington using multi-stage fracture comple-
tions and has become a pioneer in a play that is revitalizing the exten-
sive Cardium trend in west-central Alberta.
According to the Macquarie report, NAL initially used six- to eight-
stage 20-tonne oil based fractures on 1,000-metre-long horizontal legs.
While results were variable, one-month IP rates of 200 to 500 boe per
day were “very encouraging and underscored the massive potential
through re-entering the tight Cardium oil package.”
Macquarie said producers will soon begin experimenting with
slickwater fracs that will save an estimated $400,000 per well. The
report also notes that current completions are between 8 and 11 frac
intervals in horizontal wellbores ranging from 1,000 to 1,600 metres,
with frac sizes of approximately 20 to 30 tonnes.
John Dielwart, ARC Energy Trust’s CEO, said the trust is the
second-largest landholder in the Cardium behind Penn West Energy
Trust, it is only in the early stages of developing the light oil resource
play. For 2010, ARC has allocated $54 million to Pembina and plans to
drill 32 Cardium locations on operated lands. Over half of these wells
will be horizontal, multi-frac completions.
“The intention of that program is to test a multitude of different
opportunities, from very tight rock to horizontal wells in the sand-
stone, underneath the water-swept conglomerate,” Dielwart said. “We
think the opportunity is very substantial. We’ll be a big player in it….
You will hear a lot more from us in the coming year as we finish drill-
ing those wells.”— DAILY OIL BuLLETIN
SUPPLEMENT TO OIL & GAS INQUIRER · MARCH 2010 RD7
CaRDIumRED DEER & CENTRal albERTa Focus
Tight holesby paul Wells
A secretive race is on to acquire land and drilling insights in Alberta’s Cardium formation
SyNERgy RED DEER & CENTRal albERTa Focus
RD8 SUPPLEMENT TO OIL & GAS INQUIRER · MARCH 2010
Krista Waters, a professional facilitator, says face-to-face communication about energy-related issues is crucial to maintaining neighbourly relations.
and other details. Waters says the synergy process scales up and down
efficiently, from the widespread concerns of acreage owners around a rec-
reation lake to a parent concerned about rig hauls during school hours.
Waters grew up on a farm near Caroline and later worked as a news-
woman in Red Deer. The mother of three says residents’ expectations of
producers have evolved a great deal over the last few decades. “As resi-
dents become more informed, they do expect more and different things
from the industry. Industry has adapted and continues to improve at
informing the public about their operations and cooperating with their
concerns. Directional drilling has added a lot of flexibility for produc-
ers in terms of well location. It also helps that multiple wells can be
drilled from one pad, which reduces the footprint,” she comments.
At the neighbourhood level, natural gas laced with poisonous
hydrogen sulphide is arguably the mother of all environmental issues.
Waters says sour gas continues to generate controversy when deep,
high-volume wells are drilled in the foothills. “However, we’ve also
SyNERgyRED DEER & CENTRal albERTa Focus
SUPPLEMENT TO OIL & GAS INQUIRER · MARCH 2010 RD9
Talk is cheap(er)by mike Byfield
Alberta’s growing synergy network reduces friction between residents and the patch
SyNERgy RED DEER & CENTRal albERTa Focus
RD10 SUPPLEMENT TO OIL & GAS INQUIRER · MARCH 2010
had lot of sour gas production in the Rocky Mountain House-Caroline
region,” the facilitator states. “I’ve experienced cases where residents
have enough confidence in the regulations and the safety systems for
sour gas operations that companies can’t muster up interest to attend
an open house a proposed sour gas well.”
David Pryce is VP, operations for the Canadian Association of
Petroleum Producers (CAPP), which whole-heartedly supports the
synergy movement. “When an oil and gas company arrives at a land-
owner’s door, that family may have a sense of ‘Whoa, what’s up here,
this is new!’ That’s understandable—it’s a new situation for them. But
that family will soon discover that resources are available. More than
most Albertans realize our industry has made a huge effort in learning
to live with all stakeholders.”
Pryce handled the environmental and community aspects of the
Wolf Lake thermal bitumen project in the early 1980s, then went on to
head BP’s environmental group in Calgary. “Synergy amounts to work-
ing through disparate issues until a common position can be reached.
It’s a continuous process that adapts to new factors as they bubble up,”
says Pryce.
In his view, the Clean Air Strategic Alliance (CASA) was a piv-
otal development in Alberta’s homegrown synergy movement. The
non-profit association was established in 1994 as a new way to man-
age air quality issues, notably flaring of sulphur dioxide. CASA is a
multi-stakeholder partnership, composed of representatives selected
by industry, government, and non-government organizations.
CASA’s key decision-making tool is the Comprehensive Air Quality
Management System. CAMS integrates matters relating to health,
environment, energy, and the economy into decisions that affect air
quality. The board of directors, representing all stakeholders, deter-
mines what issues need to be addressed. As needed, organizing com-
mittees and projects teams are created to deal with specific problems.
With respect to flaring, Pryce launched a project team with an
environmental activist, the late Martha Kostuch. The team developed
a test that assesses the value of flared gas versus the cost of the equip-
ment needed to eliminate the emissions. “Martha was determined, but
she had the ability to see a situation from the perspective of others.
That willingness is the key to coming up with a workable fix. Over
time, we’ve reduced the flaring of solution gas at oil batteries by 72
per cent and we’re still making progress,” the CAPP VP says. “I believe
the flaring situation is now viewed as well-managed by pretty much
everyone involved.”
As CASA worked on a province-wide basis, synergy groups began
appearing at the district level through the 1990s. Alberta is home to
Judy Winter (left), a retired teacher, discusses energy with Krista Waters.
Phot
o: P
hoto
Mag
ic/L
inda
Dub
ois
SyNERgy
SUPPLEMENT TO OIL & GAS INQUIRER · MARCH 2010 RD11
at least 31 local synergy groups, from Taber to Peace River. In 2002,
CAPP and the Alberta Energy Resources Conservation Board (the
ERCB was called the Energy & Utilities Board at the time) sponsored
the first provincial synergy conference. For two days, 248 partici-
pants were coached in the art of mediating solutions within a dispa-
rate group.
Synergy Alberta, a provincial umbrella group, organizes annual
conferences and workshops. The non-profit organization also provides
some basic online resources. Even so, it’s still very much a locally
driven phenomenon. “CAPP simply does not have the resources to
participate in all of those local groups,” Pryce says. “The ball has to be
carried by producers who are active in a specific area, along with other
local stakeholders.”
Alberta’s ongoing development, which is most evident in the central
Edmonton-Calgary corridor, prompted the provincial government to
initiate the Land-use Framework (LUF) in 2008. The LUF is intended
to address combined or cumulative effects of all human activity,
including impacts on water supply, wildlife habitat, and many other
factors. In essence, Alberta has been chopped into seven regional divi-
sions, each of which will have its own detailed land-use plan.
Parallel examples are cities that are routinely zoned into areas that
are primarily used for single-family homes, higher-density residential
units, commercial, light industrial, and so forth. The LUF will define
the primary usage of lands within a division. For example, the land
on either side of the Calgary-Edmonton highway will be allocated for
transportation as a primary use, and property owners can plan their
own developments accordingly.
“I see our future land-use and water strategies being developed in a
synergistic fashion,” Pryce says. “Working together, stakeholders must
define the issues, consider the needs of all parties, and define a path
forward by favouring reasonable compromise.” Detailed land-use plans
are now being worked out for northeastern Alberta (oilsands coun-
try) and southern Saskatchewan, which embraces most of southern
Alberta. Completion is scheduled for this year.
This year, the province plans to initiate division planning for the
North Saskatchewan and Upper Athabasca. Red Deer, Upper Peace,
and Lower Peace will follow in 2011. Each division plan should be
completed by the following year, meaning all plans are slated to be in
place by 2012. Following what is likely to be many months (or years)
of discussion and debate, the final versions of these plans will have
the force of law.
LUF experts and other participants will be working closely with
the Alberta Water Council, a synergy initiative modelled on CASA.
CAPP plans to participate in each watershed group that’s formed by
the province-wide water council. “More than half of all oil production
in Alberta is assisted by steam or waterflooding,” Pryce says. “Water
is a critical resource. In planning its use, we must balance social, eco-
nomic, and environmental needs rather than being co-opted into see-
ing through a single lens.”
As far as Krista Waters is concerned, the synergy approach is work-
ing well so far. “Each year, the number of cases that go to the ERCB’s
ADR [alternative dispute resolution] or even the hearing process is
small compared to the number of well drills,” she says “Each hear-
ing is very expensive, takes a lot of time, and often has an outcome
that’s less than favourable for at least one of the involved parties. It’s in
everyone’s interest to reach sensible compromises wherever possible,
preferably early on, at the ‘kitchen-table’ stage of discussion.”
Delays and unpredictability make planning extremely difficult for
energy managers. And Alberta is already one of the world’s highest-
cost operating arenas for an oil and gas producer.
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O I L & G A S I N Q U I R E R • M a r c h 2 0 1 0 25
BrITISh cOLUMBIa WELL acTIVITY
JAN/09 JAN/10
WELL LICENCES 107 100 ▼
JAN/09 JAN/10
WELLS SPUDDED 161 101 ▼
JAN/09 JAN/10
WELLS DRILLED 130 61 ▼
Source: Daily Oil Bulletin
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In the Horn River Basin, EnCana plans to experiment different well spacing and other variables.
In 2010, Encana will frac horn river wells in as many as 23 stagesby Elsie Ross
This year, EnCana Corp. and Apache Canada will be targeting well completions in the Horn River Basin using an average of 19 fracturing stages per well, with some as high as 23. Kevin Smith, VP of EnCana’s Fort Nelson business unit, said, “There is a correlation between the number of stages pumped in a well and the actual perfor-mance of a well.”
Smith was addressing a Calgary conference sponsored by the Canadian Institute on Jan. 26. The two companies are 50-50 partners in the play. In 2009, they completed three 14-stage wells and one 12-stage well. In an earlier 10-stage well, the 30-day average rate was about nine million cubic feet per day.
EnCana is continuing to drill longer horizontal laterals to accommodate the increase in stages, although it has no plans to shorten the distance between stages within a wellbore. Developing
more acreage with a single wellbore is key and “very accretive” to the economics of the play, according to Smith.
In drilling more and longer wells on a single well pad, the company is also reducing its environmental footprint. “What we are heading into is a real game-changer as far as the develop-ment goes here,” Smith said. EnCana is
now drilling up to 16 wells on a single pad with the longest well drilled so far, achieving a total measured depth of 5,400 metres. “That gives us 2,200 to 2,400 metres of horizontal lateral which we are completing.”
With 16 wells and an average of 19 fracs per well, that will mean more than 300 fracs per well pad. Pumping 24 hours a day, it will take two to four months to complete a single pad. “Our frac company should be building permanent housing out here,” Smith joked. “It is going to be a very different application of their hard-ware.” That’s also where EnCana expects a lot of its efficiencies as it benefits from the 24-hour utilization of the service com-pany’s pumping equipment.
Since entering the Horn River basin in 2003, EnCana has drilled 50 gross wells with 13 gross wells on production at the end of 2009. This year, it expects to drill about 21 net wells, the company said earlier.
Up until this point, EnCana has con-sistently maintained a 40-acre spacing, but as it moves forward it is going to be testing a lot of different spacing variables, said Smith. It also will be employing dif-ferent job sizes, different sand tonnages, and using perforation clusters rather than single perf intervals as it experiments to find the optimum approach.
The production plot is notable in the similarity in character of the curves, the conference heard. “What that really tells me…is that we have something that is very homo-geneous, at least in our area of development,” he said. Results that EnCana has seen from around the basin support that belief.
Cooperation between producers in terms of infrastructure and sharing their development plans for the area has been an unusual aspect of the basin since Apache, EnCana, Nexen Inc., EOG Resources Canada Inc., and Devon Canada
“Our frac company should be building permanent housing out here.”–Kevin Smith, Vice-President, Encana’s Fort Nelson business unit
26 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
British Columbia
Apache Canada Ltd. has agreed to acquire 51 per cent of Kitimat LNG Inc.’s planned liquefied natural gas (LNG) export ter-minal in British Columbia. Apache also reserved 51 per cent of capacity in the ter-minal. “The growing supply of natural gas in the United States and Canada is trans-forming North American energy markets, and this increased resource has significant potential for global impact,” said G. Steven Farris, Apache Corporation’s chairman and CEO.
“Development of the Kitimat LNG project has the potential to open new markets in the Asia-Pacific region for gas from Apache’s Canadian operations, including the Horn River Basin in northeastern British Columbia, where our net estimated resource potential exceeds 10 trillion cubic feet of gas,” Farris said on Jan. 13.
T he proposed K it i mat projec t , located at Bish Cove near the Port of Kitimat about 652 kilometres north of Vancouver, has planned capacity of
about 700 million cubic feet of natural gas per day, or five million metric tons of LNG per year. Preliminary construc-tion cost estimates of C$3 billion will be refined at the conclusion of front-end engineering and design (FEED).
The project will employ an estimated 1,500 people during construction and 100 on a permanent basis. Kitimat LNG received its Provincial Environmental Certificate for the liquefaction terminal in December 2008 and the Federal Environmental Certificate in January 2009.
“The economic fundamentals remain strong for exporting natural gas from western Canada to international markets where natural gas is in demand, such as Asia,” said Alfred Sorenson, CEO of Galveston LNG Inc., parent company of Kitimat LNG Inc. “As natural gas supply and reserves continue to increase in North America, Kitimat LNG’s terminal will provide producers in Canada with secure access to key worldwide markets.”
Under the terms of the agreement, Apache will make an initial payment to the current owners of Kitimat LNG with additional consideration due upon achieve-ment of certain commercial and regulatory
apache invests in $3B LNG terminal and plans canadian expansion
Corporation started the Horn River Basin Producers’ Group, said Mike Simpson, Nexen’s manager of unconventional exploration. “Industry cooperation on surface issues and technology can benefit all stakeholders and minimize our footprint in spite of our traditional competitive nature of our industry,” Simpson said.
When it comes to unconventional resources, collaboration is the way of doing business simply because of the potential scale of development, the Nexen executive told the conference. “I don’t think we have a choice,” said Simpson. “We talk in town-ships, not in sections or quarter-sections, and your impact is so widespread that just by definition it involves a number of companies, and if we don’t collaborate on the surface issues for sure we are going to essentially hurt the credibility of industry.”
The producers’ group recognizes that surface issues are not an afterthought, he said. In planning, stakeholder con-cerns need to be built in right from the
beginning and the producers’ group has been doing that quite effectively, accord-ing to Simpson. The producers, for exam-ple, have worked together on shared roads that also include pipeline rights-of-way to reduce the overall environmental disturbance. Multi-well pads with hori-zontal wells also help in that objective.
EnCana has also been active in the tight gas Montney play where it has 730,000 net acres (1,100 sections) of land between Grande Prairie, Alberta and Dawson Creek, British Columbia, with an estimated 70 trillion cubic feet of gas in place. In 2009, EnCana drilled about 60 wells focusing on both the Upper and Lower Montney zones but took a different approach to completions, said Smith.
In the Upper Montney, it used Halliburton Corporation’s CobraMax frac-turing application to complete the wells, while in the Lower Montney it used open-hole swell packers primarily with energized fluids and then slick water. “We see some
really encouraging performance with an average of over four MMcf [million cubic feet] per day from the initial completion over a 30-day rate with some wells coming in at over 10 MMcf a day,” Smith said.
Similar to Horn River, EnCana is adding length and fracturing stages to increase and enhance the performance of the wells. Where there is both Upper and Lower Montney potential, the com-pany is drilling 8 to 10 wells per section to develop. “The tight curve performance is actually living up to actual data we are getting,” said Smith.
With this performance, from a large-scale perspective, the Montney is one of the strongest performing assets in EnCana’s portfolio with a rate of return approaching 50 per cent and a supply cost close to US$3 per thousand cubic feet. “We have come a long way,” he said. “In 2006, we were struggling to get a 12 per cent rate of return out of the Montney.”
— DAILY OIL BuLLETIN
Apache wants access to global markets from B.C. via LNG tankers.
O I L & G A S I N Q U I R E R • M a r c h 2 0 1 0 27
British Columbia
The B.C. government brought in nearly $13 million in revenue on the sale of 19 parcels in its first land auction of 2010. January’s sale saw 9,444 hectares sold for a total of $12.95 million, which worked out to an average of $1,371 per hectare. That’s an improvement from the same sale last year, which delivered $7.1 million to the province on 10,280 hectares for aver-age of $690.39 per hectare.
One lease in the Sunrise gas field area 20 kilometres northwest of Dawson Creek produced a per-hectare bid by Britt Resources Ltd. of over $20,687 per hectare, the land sale high. The broker paid over $5.3 million—nearly half the entire land sale—for the 259-hectare lease at 14-79-17W6. Producers in the area have been actively targeting the Montney
formation. EnCana Corporation has several wells licensed in the area.
Six leases in the Blair Creek area, roughly 115 kilometres north of Fort St. John, went for bids of between $1,088 and $4,249 per hectare, totalling over $4.7 million. Windfall Resources Ltd. plunked down $1.2 million for 283 hectares (4,248 per hectare) for units 74, 75, 84, and 85 at F-94-B-16.
Broker Canadian Coastal Resources Ltd. paid the same amount for units 94 and 95 at F-94-B-16 and units four and five at K-94-B-16. Daily Oil Bulletin records show that Painted Pony Petroleum Ltd. spudded a well in the Blair area on Jan. 19 at C-55-F-94-B-16 licensed to the Belloy formation. The well has a projected depth of 2,600 metres.
— DAILY OIL BuLLETIN
B.c. brings in nearly $13M in first land sale of 2010
milestones. Apache will fund the project’s FEED—to begin shortly—with a final investment decision expected in 2011.
First LNG shipments are projected for 2014. Apache will become operator of the project. Kitimat is designed to be linked to the pipeline system servicing western Canada’s natural gas producing regions via the proposed Pacific Trail Pipelines, a $1.1-billion 463-kilometre project origin-ating at Summit Lake, British Columbia.
Through its acquisition of a 51 per cent interest in the Kitimat project, Apache will acquire a 25.5 per cent interest in the pipeline, currently a 50-50 partner-ship between Galveston LNG and Pacific
Northern Gas Ltd. The proposed pipe-line has received both the federal and provincial governments’ environmental assessment approvals and has created an innovative arrangement to partner with the First Nations along the pipeline route.
With the development of the Marcellus shale play in Pennsylvania and the Horn River and other Canadian gas, North
America will have a surplus of gas, Tim Wall, president of Apache Canada, said in a conference call. “I do think it could ben-efit other markets by being able to export some of that surplus gas.”
Rosemar y Boulton, president of Kitimat LNG, said her company has addi-tional memorandums of understanding with other gas producers but is still look-ing for additional investors. “There cer-tainly is an opportunity for us to bring additional partners, on either capacity or equity, into the plant,” she said.
In December, Apache announced it will embark on evaluation of the commer-cial potential of gas development in New
Brunswick, in the Frederick Brook shale formation, and light oil development at the recent Caledonia oil discovery. The Houston-based producer and its joint- venture partner EnCana Corporation plan to have 27 horizontal gross wells on pro-duction in the Horn River Basin in north-eastern British Columbia by the end of the first half of 2010.
However, in interviews last month, officials at TransCanada Corporation, who are hoping to build their own pipe-line transporting gas from the Horn River basin into the Alberta system, expressed skepticism about the economics of the Kitimat LNG project.
A producer shipping gas to the West Coast would need a netback higher than $9.25 per thousand cubic feet, assum-ing a natural gas price at the wellhead of $5.25 per thousand cubic feet, $1 for pipeline transportation to Kitimat, and $3 for liquefaction, said Russ Girling, COO. In contrast, a shipper who wants to get Horn River gas to the Alberta Hub would pay a receipt charge of $0.25 per gigjoule for a minimum of three years. The Canadian mainline toll to the east-ern zone would add another $1.60 per gigajoule.
And while LNG proponents are eyeing prices such as $15 per mmBtu from Asian buyers for Canadian LNG, Hal Kvisle, TransCanada president and CEO, ques-tioned the assumption that LNG will continue to be priced off oil in a world where there is a surplus of LNG. “If I was a Japanese utility buyer, I would be saying, ‘Why should I do that [pay that price],’” he said. “The world has changed. There’s now lots of LNG out there and let’s see what the price of LNG is rather than tying it to oil.”
— DAILY OIL BuLLETIN
In December, Apache announced it will embark on evaluation of the commercial potential of gas development in New Brunswick, in the Frederick Brook shale formation, and light oil development at the recent Caledonia oil discovery.
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NOrThWESTErN aLBErTa/FOOThILLS WELL acTIVITY
Like other classic oilfields in Alberta, Redwater and Kaybob are triggering renewed interest.
Orion focuses its $85M capital budget on Kaybob and redwaterby James Mahony
Orion Oil & Gas Corp. plans a capital spend-ing program this year of $85 million, primar-ily directed toward its Kaybob and Redwater properties. The program, which began with a winter drilling program in November 2009, includes the drilling of 17 development wells at Kaybob and 18 development wells at Redwater, with the remainder to be spent on optimization, workover, and facilities programs at Orion’s Kaybob, Redwater, and Bigstone properties.
Current production from its proper-ties is approximately 2,650 barrels of oil equivalent (boe) per day with a mix of 55 per cent natural gas and 45 per cent light oil and natural gas liquids.
For 2010, Orion expects production to average between 4,050 boe per day and 4,900 boe per day with operating costs of between $10 and $12 per boe. Orion expects to generate approximately $60 million in cash flow in 2010. Beyond 2010,
production plans call for 5,000 to 7,000 boe per day. Once this level is reached, Orion anticipates that significant free cash flow will be available for redirection to other global projects.
Orion’s president and CEO is Gary Guidry, who recently served as CEO of Tanganyika Oil Company Ltd. until its acquisition by Sinopec International Petroleum Exploration and Production. In January, Orion Oil & Gas Corp. emerged as a publicly traded firm from a three-cornered amalgamation that included pri-vately held Orion Oil & Gas Ltd.
In January, Orion’s winter drilling program was reportedly on schedule, with six wells dril led and cased at K aybob a nd eight at Redwater i n November and December for a 100 per cent success rate. The combined results of these operations are expected to add 1,760 boe per day to 1,800 boe per day of
Northwestern Alberta/Foothills
JAN/09 JAN/10
WELL LICENCES 235 251 ▲
JAN/09 JAN/10
WELLS SPUDDED 251 304 ▲
JAN/09 JAN/10
WELLS DRILLED 251 304 ▲
Source: JuneWarren–Nickle’s Energy Group
production by the end of the first quarter of 2010.
The Kaybob property (91 per cent working interest) contains the Swan Hills natural gas condensate field, and repre-sents approximately 80 per cent of Orion’s production and reserve value. The property is completely covered with 3-D seismic and is well delineated. Orion has historically drilled eight wells on its Kaybob property with a 100 per cent success rate and all of these wells are on production.
In addition to the development wells at Kaybob, Orion plans to complete one major workover. The new wells are expected to add 200 boe per day to 300 boe per day of production and 500,000 boe of reserves per well. Well costs at Kaybob are estimated at $4 million per well to drill, complete, and tie-in, and all six wells have or are estimated to come in on or under budget.
The first well at 5-15-61-19W5 was drilled to 3,320 metres and was put on production Dec. 22, 2009, with a stabilized flow rate of 1.8 million cubic feet per day of raw gas. All six wells are expected to be on production by the end of the first quarter, adding sales of 1,200 to 1,800 boe per day.
At Redwater, (100 per cent working interest), Orion has 13 existing wells in the Ellerslie light oil formation with the planned 18 new wells (8 before breakup) expected to add 20 to 25 boe per day of production and 30,000 to 40,000 boe per day of reserves per well. Well costs at Redwater are estimated at $750,000 to drill, complete, and tie-in.
Orion is pursuing business develop-ment in Colombia, Argentina, and Peru—all areas in which Orion’s management team has significant experience and believes there are excellent opportunities to generate significant growth.
— DAILY OIL BuLLETIN
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30 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
O I L & G A S I N Q U I R E R • M a r c h 2 0 1 0 31
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NOrThEaSTErN aLBErTa WELL acTIVITY
The proposed Surmont expansion will create an estimated 2,500 jobs on site during construction.
conocoPhillips and Total proceed with Surmont SaGD expansionby Pat Roche
continuing to ramp up over the next few years,” Fox said of Phase 1 output.
S u r m o n t i s H o u s t o n - b a s e d ConocoPhillips’s only operated thermal oil project worldwide. However, the company is also a 50 per cent owner of the Foster Creek/Christina Lake SAGD project operated by Cenovus Energy Inc. In early January, Cenovus said Foster Creek/Christina Lake gross output is about 115,000 barrels of bitumen per day before royalties (50 per cent net to each company).
ConocoPhillips hopes to exit oilsands mining. Last fall, it announced it was putting its nine per cent stake in Syncrude Canada Ltd. on the auction block. All the company’s undeveloped bitumen leases would be pro-duced by drilling wells rather than mining.
“Surmont is an important part of our oilsands portfolio, and we’re pleased to announce its next phase of development,” said John Carrig, president and COO of ConocoPhillips. “The oilsands are an area of significant future oil production growth and are important for short- and long-term energy and economic security in North America.”
The company expects to spend $300 million in heavy oil technology research and development over the next few years to improve economic and environmental performance. “We believe that our oil-sands projects—and the conversion of crude oil produced from oilsands to fuel—can be conducted in an environmentally sustainable manner and that technology will play a significant role in managing the environmental footprint,” Carrig said.
Yves-L ouis Da r r ica r rère, presi-dent of exploration and production for Paris-headquartered Total, said: “The responsible development of Canada’s oil-sands—particularly with respect to the environment—will be crucial in providing a secure source of energy for the future.
— DAILY OIL BuLLETIN
ConocoPhillips Canada and Total S.A. have announced an 83,000-barrel-per-day expansion of their 50-50 thermal oil joint venture at Surmont in northeastern Alberta. Work to be done this year will include some Surmont 2 site clearing, ordering some long-lead equipment, and focusing on finalizing the engineering, said Matt Fox, president of ConocoPhillips.
ConocoPhillips did not release cost estimates for the project, located 63 kilo-metres southeast of Fort McMurray. Most of the construction work at Surmont would occur during 2011 through 2014. Fox said roughly 100 steam assisted grav-ity drainage (SAGD) well pairs will be drilled to achieve annual average output of 83,000 barrels of bitumen a day, which would be reached “a few years” after the project comes on stream.
“We expect we will start operations in 2014. And then first production will
be early in 2015 or late 2014,” Fox said on Jan. 19. Direct employment on site will climb to about 2,500 during construc-tion, with more jobs created indirectly in the manufacturing and service sectors in Alberta and elsewhere in Canada.
Phase 2 would raise total Surmont pro-duction to 110,000 barrels of bitumen a day. No Alberta upgrader is planned. Fox said production will continue to be sold on the open market or shipped to ConocoPhillips refineries in the United States.
Fox expects the steam-oil ratio from phases 1 and 2 will level off at around 2.5 to 1. Production from the project’s first phase—which flowed first oil in October 2007—was about 20,000 barrels per day exiting last year, Fox said. Phase 1 design capacity is 27,000 barrels per day, but with normal downtime and maintenance, actual output is expected to average about 23,000 barrels per day. “We anticipate we will be
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Alberta Energy Minister Ron Liepert hopes to improve his government’s rapport with the oil industry.
Central Alberta
JAN/09 JAN/10
WELL LICENCES 177 214 ▲
JAN/09 JAN/10
WELLS SPUDDED 192 271 ▲
JAN/09 JAN/10
WELLS DRILLED 192 251 ▲
Source: Daily Oil Bulletin
ron Liepert becomes alberta’s energy minister in a cabinet shuffleby Richard Macedo
of business, namely the competitiveness study, is nearing completion and we look forward to working with him to complete that project.”
“I believe he does have a general understanding of the industry issues,” added Roger Soucy, president of the Petroleum Services Association of Canada. “The primary issue he needs to shepherd at the moment is the Competitiveness Review which is coming to a conclusion.” The Canadian Association of Petroleum Producers (CAPP) added that the oil and gas industry competitiveness issue has a profound sense of urgency. “We look forward to seeing this process through with [Liepert],” said CAPP spokesman Travis Davies.
In a conference call, Stelmach said the fact that Liepert is based in Calgary should help improve communication with the industry. “The oil and gas industry, especially on the natural gas side, is going through significant structural changes,” the premier said. “We have to move the industry towards unconventional gas, shale gas. It requires new investment. We are partners, we are really partners with the industry. We own the resource, but they are the ones who put up all of the criti-cal dollars and those dollars, of course, are at risk unless you have a very good com-petitiveness position as a province.”
Many industry executives have com-mented in private that the Competitiveness Review has been conducted by personnel who appear to grasp the realities of the energy sector.
Danielle Smith, the leader of the upstart Wildrose Alliance, said Stelmach’s cabinet changes will not make a difference. “You can change the faces of the deck crew, but Albertans will only see real change when the Wildrose Alliance replaces this tired, rudderless government,” she said.
— DAILY OIL BuLLETIN
Calgary-West MLA Ron Liepert, after a controversy-ridden stint as health minis-ter, is Alberta’s new energy minister fol-lowing a cabinet shuffle by Premier Ed Stelmach on Jan. 13. Liepert takes over the portfolio at a critical time. The prov-ince is in the middle of an oil and gas com-petitiveness review after a tumultuous couple of years marked by a new royalty regime and a deep recession.
The new minister replaces Mel Knight, who has been shuff led to sustainable resource development after just over three years of handling the energy port-folio. Knight is a former oil and gas ser-vices entrepreneur from Grande Prairie, Alberta. Ted Morton, MLA for Foothills-Rocky View, is the new finance minister.
Industry organizations greeted the appointment of Liepert warmly but main-tain that there’s still some heavy lifting to get Alberta back on track competitively
with other jurisdictions. Gary Leach, exec-utive director of the Small Explorers and Producers Association of Canada, said the appointment makes sense due to Liepert representing Calgary, where most of the industry is headquartered.
“We believe strong economic policy guiding our provincial energy strategy will help accelerate Alberta’s recov-ery from this recession,” Leach said in a prepared statement. “The first step to achieving this goal is for government and industry to work together to complete the competitiveness review.
“SEPAC made a point of getting to know [Liepert] last year as part of a broader effort to make sure the concerns of our sector were on the table with senior ministers in the [Stelmach] government,” Leach told the Daily Oil Bulletin. “He will be on a steep learning curve, no doubt, but will benefit from the fact that a key piece
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Central Alberta
NAL Oil & Gas Trust plans a $175-million capital program this year and expects to drill 137 (67 net) wells, the most in its 14-year history. The 2010 program is focused 80 per cent on Cardium forma-tion oil development opportunities in Alberta and Mississippian oil projects in Saskatchewan, with some capital com-mitted to strategic natural gas drilling in Alberta and British Columbia.
“The trust plans to maintain its leader-ship position in the Cardium oil resource play in central Alberta, continue ongoing activity in the attractive Mississippian oil portfolio in southeast Saskatchewan, and invest in strategic gas opportunities on the trust’s expanded land portfolio,” NAL stated in a media release on Jan. 21.
In 2010, the trust is budgeting $140 mil-lion for drilling, completions, and tie-ins, $7 million for recompletions, $8 million for plants and facilities, and $10 million for land and seismic. Another $10 million is set aside for other items. The capital figure is $10 million in Alberta drilling credits.
Last year, the trust’s capital budget was $130 million, although its final spending
figures for 2009 haven’t been released. In 2010, NAL plans to spend about 35 per cent of its capital budget in the first quarter.
Highlights of the 2010 program include:* Cardium formation oil projects in central
Alberta will continue to be a focus at NAL’s existing Garrington/Westward Ho core area as well as delineating trend acreage to the south at Lochend (Cochrane) and to the north at Pine Creek.
* In Saskatchewan, a large inventory of con-ventional oil prospects on existing lands
coupled with new opportunities added in 2009 will lead to drilling 61 (30 net) hori-zontal wells. These wells are expected to add production and continue to delineate several existing Mississippian trends, adding new locations to future inventory.
* For gas, the trust plans to drill two more wells on the existing Kakwa Falher development program in Alberta and in northeastern British Columbia, NAL is planning to drill two Fireweed horizontal wells and the first Halfway horizontal at Trutch.
The 2010 capital program is forecast to deliver production volumes averaging between 29,500 and 30,500 barrels of oil equivalent (boe) per day. Incorporated in this guidance range is the planned divestiture of 500 boe per day. Production
in 2010 is forecast to be 50 per cent oil and natural gas liquids and 50 per cent gas.
Operating costs per boe in 2010 are expected to be consistent with 2009 levels due to lower power and third-party costs, offset somewhat by higher property taxes
NaL’s $175M capital budget has a strong focus on cardium oil play
The 2010 capital program is forecast to deliver production volumes averaging between 29,500 and 30,500 barrels of oil equivalent (boe) per day.
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Central Alberta
and utilities primarily in Saskatchewan. Operating costs are projected to fall between $11 and $11.50 per boe.
NAL said it will operate more than 90 per cent of its capital spending in 2010 and is not facing material land expiries. This provides significant flexibility for adjust-ing the timing and scale of the program in response to commodity prices and market conditions. As in 2009, NAL said its balance sheet strength and access to capital mar-kets position the trust to take advantage of value-adding acquisition opportunities.
Subject to final bank documentation being completed, the trust’s credit facility is expected to be increased to $550 mil-lion from $450 million as a result of the Breaker Energy Ltd. acquisition, which closed on Dec. 11, 2009.
The trust’s management said it con-tinues to assess alternatives for conver-sion to a corporation and reiterates that the company plans to maintain a yield-oriented business model after conversion. Conversion is expected to occur in late 2010 or early 2011 to maximize the tax shield for the trust model and protect its $1.2 billion of available tax pools.
— DAILY OIL BuLLETIN
Midway Energy Ltd. says it is “extremely pleased” with the initial results of its Cardium horizontal drilling program at Garrington, south of Red Deer. The company drilled three (2.7 net) operated Cardium horizontal wells in the fourth quarter of 2009 and participated in the drilling of one (22.5 per cent working inter-est) non-operated Cardium horizontal well.
Two of the operated wells were fractured in the fourth quarter of 2009 and the third was fraced in the first week of January 2010. All three wells reportedly showed similar res-ervoir characteristics and frac responses. The non-operated well is expected to be fraced mid-January.
Midway said all three of the operated wells have now been completed at an average cost of $1.15 million gross per well. Each of the three wells has been completed using dif-ferent multi-stage frac completion methods. Midway believes that completion methods will become the biggest area of achieving effi-ciencies in the future.
The first well has produced back the frac fluid and is producing formation oil (restricted
by pumpjack capacity) at an average rate of 300 barrels of oil equivalent per day for its first week of production. The well was drilled on an existing surface lease and tied into the company owned gathering system and pro-duction facility.
The second well has also been equipped and tied into Midway’s gathering system and is currently recovering frac fluid at a produc-tion rate similar to the first well. Upon produc-ing out its frac fluid, the well will be shut in for bottomhole pressure data. This well was expected to be producing formation oil by the last week of January.
The third Cardium well was fraced in early January and is currently flowing back its frac fluid. The well is showing similar produc-tion characteristics as the first two wells and it is expected that this well will be on produc-tion by the end of January after producing back its frac fluid.
Midway intends to drill an additional three Cardium horizontal wells in the first quarter of 2010.
— DAILY OIL BuLLETIN
Midway encouraged by cardium drilling results at Garrington
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O I L & G A S I N Q U I R E R • M a r c h 2 0 1 0 37
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SOUThErN aLBErTa WELL acTIVITY
Some managers report that oil and gas service prices have bottomed out and started to rise gradually.
Some oilfield service companies see stronger prices on the horizonby Elsie Ross
Southern Alberta
JAN/09 JAN/10
WELL LICENCES 349 242 ▼
JAN/09 JAN/10
WELLS SPUDDED 529 303 ▼
JAN/09 JAN/10
WELLS DRILLED 524 297 ▼
Source: JuneWarren–Nickle’s Energy Group
the company is taking only six-month and one-year contracts on the ADRs.
The companies indicated little interest in expanding their fleets with acquisitions at fire-sale prices. “We are more concerned about the type of rig,” said Geddes. “We have the ability to purchase and/or build rigs, so we are a lot pickier at what we are looking at these days because the value model has changed.”
Christopher Strong, CEO of Union Drilling Inc., agreed that “we are prob-ably at the bottom” in terms of pricing. His Texas-based firm is active in the Marcellus shale play in Pennsylvania, concurred. “There are a lot of distressed companies out there, and one would think this would be a good time to acquire distressed assets, but we have spent a good amount of time looking at different fleets…and there’s not a lot out there that is really attractive for the plays that have the most demand,” he said. “A lot of what’s for sale is that last hired, first fired type of equipment and that’s why it’s distressed.”
Last summer, Calfrac closed two sep-arate transactions, one in Canada and one in the United States, said Medvedic. “We were satisfied with the opportunity at that point in time, but don’t expect there is going to be a whole lot more opportunity in Canada,” he said, noting that approximately 85 per cent of the capacity in western Canada is held by five service companies.
There has been a major change in rig technology in the last three or four years, with features such as top drives, auto-mated handling, and self-moving pad rigs, and there will be little demand for older-style rigs, Geddes predicted. “There’s no question that box-on-box style 1,000- to 1,500-horsepower rigs are going to die,” he commented.
— DAILY OIL BuLLETIN
The worst of the downturn in oil and gas activity appears to be over, according to some service companies. “We just put a $500 [per day] increase across all rigs in the Rockies and we have been starting to move the price a little bit as the demand has been increasing,” Bob Geddes, presi-dent and COO of Ensign Energy Services, said on Jan. 12.
Geddes was addressing the BMO Capital Markets North American uncon-ventional resources conference in New York. Ensign has 30 proprietary auto-mated drilling rigs (ADRs) in the Rockies.
“We saw pricing kind of trough in Q2, saw stability coming in though Q3, and probably are seeing some recovery in Q4 and heading into Q1,” said Tom Medvedic, senior VP of corporate development for Calfrac Well Services.
However, Calfrac, primarily a pressure-pumping company, thinks it likely will be
mid-year before it sees significant price increases, Medvedic said. While Calfrac is currently extremely busy, it has locked in arrangements with its core customers for the next couple of quarters.
When it comes to recontracting rigs, Ensign has been able to hold rates on its ADRs “reasonably well,” although they are down a bit from new construction contracts, said Geddes. Ensign has con-structed 70 of the rigs, which require two fewer workers and offer greater efficiency and safety, according to the company.
“There is no question…that efficiency is well rewarded and does create real value so I think we will get back to those rates,” Geddes said. “Certainly, we are at those numbers on new discussions we are having currently with customers on new rigs through 2010.” While Ensign has operators who would like to sign three- and five-year contracts, right now
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38 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
Southern Alberta
In its f irst update to its 2010 dril l-ing forecast, the Petroleum Services Association of Canada (PSAC) is fore-casting a new total of 9,000 wells drilled (rig released) across Canada for 2010. That figure represents an increase of 1,000 wells (12 per cent) from the asso-ciation’s original 2010 forecast, released in early November 2009.
On a provincial basis for 2010, PSAC estimates 6,095 wells will be drilled in Alberta, an increase of four per cent over final 2009 drilling levels. All of the 1,000 wells added to this year’s forecast are attrib-uted to Alberta, where activity was origin-ally expected to be flat compared to 2009.
PSAC expects British Columbia to have 630 wells drilled in 2010, an increase of 10 per cent from last year. Saskatchewan’s drilling rate in 2010 will see an 11 per cent increase over 2009 to 1,935 wells, while drilling in Manitoba will increase 29 per cent to 300 wells.
I n t he la st wee k of Ja nua r y, JuneWarren-Nickle’s Energy Group’s Rig Locator publication showed nearly 70 per cent of the Canadian fleet active. While the
rig count was higher throughout January, the increased peaked in the final week with 558 units at work, 92 more than in the final week of January in 2009.
On Jan. 26, the Rig Locator found 378 units active in Alberta, 91 working in British Columbia, 74 in Saskatchewan,
13 in Manitoba, and 2 in northern Canada. That compares to 303 active in Alberta, 109 in British Columbia, 46 in Saskatchewan, 7 in Manitoba, and 1 in northern Canada in the final week of January 2008.
The 1,000-well increase for the 2010 forecast is primarily the result of strengthening prices for both crude oil and natural gas, the association said. PSAC is basing its updated 2010 forecast on average natural gas prices of C$5.50
per thousand cubic feet (AECO) and crude oil prices of US$74 per barrel for West Texas Intermediate.
“Industry is expecting commodity prices to strengthen further this year,” said Roger Soucy, president of PSAC. “Improved prices led to a spurt in drilling
activity in December 2009, and we expect stronger pricing to continue to impact drilling levels as we move through 2010.”
The final tally for 2009 was 8,450 wells drilled across Canada. “We are cau-tiously optimistic about 2010,” Soucy said. “The commodity pricing signals have been positive so far, but this may not be the quick and complete turnaround everyone is hoping for. The real test will come after spring breakup.”
— DAILY OIL BuLLETIN
PSac raises its 2010 drilling forecast by 1,000 wells
“ Improved prices led to a spurt in drilling activity in December 2009, and we expect stronger pricing to continue to impact drilling levels as we move through 2010.”
– roger Soucy, President, PSac
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O I L & G A S I N Q U I R E R • M a r c h 2 0 1 0 39
Southern Alberta
The Energy Resources Conservation Board (ERCB) has upheld an appeal by EnCana Corporation rescinding the High-Risk Enforcement Action 1 taken by board staff. The EnCana case involved a disagree-ment in interpretation between the company and ERCB staff over a missing bolt on a fire-tube inlet flange.
In the appeal decision issued in mid-January, the board ruled that the issuance of an enforcement action was “not appropriate” and suggested that discre-tion be used in assess-ing the adequacy of the equipment in similar situations.
Board staff determined during an inspection March 4, 2009, at an EnCana gas facility at 6-18-74-6W6 (near Sexsmith in northwestern Alberta) that a f lame arrester did not comply with the requirements and proce-dures for facilities because it was missing
a bolt and was less than 25 metres from a process vessel.
After unsuccessful appeals to both ERCB staf f and the board’s
Enforcement Advisor, EnCana appealed to the board on
the grounds that the reg-ulations referred to in the enforcement letter
did not support taking enforcement action in this
circumstance and the applied risk level was out of proportion to the
actual risk.EnCana argued that the regulation
cited is inadequate and inappropriate to support enforcement of a missing bolt on a fire-tube inlet flange. The flame-type equipment at issue was equipped with an adequate/workable flame arrester with all bolts in place, was not saturated with oil, appeared to be properly fitted and had a gasket in place, it said. The missing bolt was not associated with the flame arrester
itself, but is one of many components of the overall piece of equipment in question, according to EnCana.
It is common knowledge that a flame arrester is typically cylindrical in shape and generally finely packed with corru-gated metal too narrow for the passage of flame, the company added. The high-risk rating is based on an inadequate flame arrester but has been inappropri-ately applied to a different component of the flame-type equipment, and there is no mechanism within the regulations to adjust the risk level or apply any discre-tion, said the company.
To clearly establish the actual risk (which it believed was low), EnCana engaged a third-party engineering firm (DPH Focus), which determined that on this particular f lange design, an ade-quate seal would still be provided even if every second bolt (six bolts in total) were missing. It concluded there is a low risk of leakage as the result of a missing
Encana missing bolt does not justify harsh enforcement action, ErcB rulesby Elsie Ross
Southern Alberta
Ember Resources Inc. says it has entered into agreements that will significantly expand drilling and production activities in its core area of Acme, Alberta. Coalbed methane (CBM) drilling at Acme, operated by Ember, could exceed 140 gross wells over the next two years, the company said in mid-January.
Production from the area is expected to grow to 20 million cubic feet (MMcf) per day (11 MMcf per day net to Ember) from 7 MMcf per day (4.5 MMcf per day net), the company said. Ember and a major industry partner have pooled their interests in 12 sections of land in the Acme area, with Ember taking a 25 per cent stake. The pooled lands are on the Horseshoe Canyon CBM trend and include rights to the base of the Belly River sands.
Ember will operate all drilling and production operations. Production will be processed through facilities currently contracted by Ember and located at the Acme property. With the addition of these pooled lands, Ember has increased its inventory of locations in the area to 260 gross (75 net) locations.
Under the first phase of the agree-ment, Ember has committed to drilling 70 gross wells. In the second phase, Ember
will commit to drilling an additional 70 gross wells. By the end of the first quarter, Ember will have drilled 35 wells under the agreement. The balance of the first 70-well commitment is expected to be completed prior to the end of the year.
During the fourth quarter of 2009, Ember drilled 28 wells (20.5 net), all of which were cased as successful Horseshoe
Canyon CBM wells. Twenty wells (12.5 net) were drilled at Acme and eight (eight net) in the Bashaw area. To date, 16 of the wells (12.2 net) have been placed on production and the remainder should be onstream by the end of January.
In first quarter 2010, Ember said it is planning to drill 30 wells (17.4 net), all expected to be on stream prior to the end of March. Fifteen wells (4.9 net) are planned for Acme and 15 wells (12.5 net) are planned in the Bashaw area.
The fourth quarter of 2009 and first quarter of 2010 drilling programs are expected to grow Ember’s production from an average of 23.5 MMcf per day in the final quarter of last year to an average of 25 MMcf per day in the current quarter.
“We have been aggressively man-aging our business in the low gas pr ice env ironment by f inding new
opportunities to strengthen our opera-tions and our financial position. We have de-levered the balance sheet, expanded opportunities in a key area, and driven down our cost structure,” said Doug Dafoe, president and CEO. “2010 has started on a positive note with natural gas prices. If that trend continues, our Horseshoe Canyon resource play and extensive drilling inventory are ready to resume our historical growth profile.”
— DAILY OIL BuLLETIN
Ember ramps up its coalbed methane program at acme
bolt. The operations VP of the manufac-turer, Gas and Oil Production Equipment Ltd., also was of the view the missing bolt did not present a safety hazard, accord-ing to EnCana.
In their response, ERCB staff said that in their interpretation of the regulations an “adequate” flame arrester has all of the nuts, bolts, and gaskets designed by the manufacturer. The portion of the flame-type equipment from which the bolt is missing is an integral part of the unit as a whole and ERCB requirements explic-itly state that operators must ensure that flame arresters have all bolts, they said.
“The ERCB cannot reasonably be expected to test flame arresters that are missing bolts to determine their continued workability or level of safety risk before issuing an enforcement action,” said ERCB staff. “Such an approach is unworkable on a provincial basis, would inevitably lead to inconsistent enforcement processes, and [would] compromise public safety.”
The risk category assigned to a given deficiency is predetermined, and field staff have no discretion other than to issue the enforcement action prescribed if the facts show that the substantive requirement has not been met, they added.
EnCana’s interpretation was that the fire-tube inlet f lange is not part of the flame arrester and even if the ERCB found that it were, the flame arrester in question was adequate as supported by the third-party engineering assessment and the expert opinion of the equipment manufacturer. The company contended the regulation and its associate risk level were improperly and rigidly applied to a component other than what is commonly accepted as a flame arrester.
In granting the appeal, the board found that the issuance of the enforcement action was not appropriate and suggested that discretion be used in addressing the adequacy of the equipment in similar cir-cumstances.
In its decision, the board said it is not persuaded by the evidence before it that the flame arrester at issue was not in an adequate or workable state at the time of inspection. “In fact, the staff arguments focused not on the inadequacy of the flame arrester due to the missing bolt, but rather on the stated inspection parameters in the directive and the reasonableness and effi-ciency of inspecting and enforcing in this manner,” it said. “The board is concerned with such an approach.”
The primary goal of the ERCB’s inspec-tion and compliance and assurance program is to ensure that requirements are met with a focus on ensuring public safety in doing so, said the board. In this situation, the primary focus should be to ensure that the matter is remedied by an operator willing to do so as soon as possible. The board noted that the decision of the enforcement advisor said the operator took corrective action at the time of the inspection by replacing the missing bolt.
— DAILY OIL BuLLETIN
" We have de-levered the balance sheet, expanded opportunities in a key area, and driven down our cost structure.”
– Doug Dafoe, president and cEO, Ember resources Inc.
40 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
42 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
Saskatchewan
O I L & G A S I N Q U I R E R • M a r c h 2 0 1 0 43
SaSKaTchEWaN WELL acTIVITY
JAN/09 JAN /10
WELL LICENCES 144 271 ▲
JAN/09 JAN/10
WELLS SPUDDED 222 236 ▲
JAN/09 JAN/10
WELLS DRILLED 216 226 ▲
Source: Daily Oil Bulletin
PetroBakken plans to drill 141 wells (128 net) in the southeastern Saskatchewan Bakken play in 2010.
Phot
o: Jo
ey P
odlu
bny
PetroBakken will apply its Sask. expertise to alberta cardiumby Paul Wells
In January, PetroBakken Energy Ltd. acquired two junior producers for $816 million, with the intention of apply-ing lessons learned in southeastern Saskatchewan’s Bakken formation to Alberta’s tight-oil Cardium formation. “Why the Cardium play? It looks a lot like the Bakken but only thicker,” said Greg Smith, PetroBakken’s president and CEO.
On Jan. 28, his company announced the acquisition of Result Energy Inc. in a $480-million stock and cash deal. In early January, PetroBakken purchased another junior player, Berens Energy Ltd., in a deal valued at approximately $336 million. “We’ve drilled over 500 horizontal and multi-stage fracs [in the Saskatchewan Bakken] and we’re very competent at bringing that technology to most plays in western Canada,” Smith said.
The Bakken and Cardium geological formations both consist of oil-soaked
reservoir rock that often lacks permeability. Exploitation of these resources has only become economically possible in the last few years through the development of cost-efficient multi-stage reservoir fracturing along horizontal well bores.
Despite its Cardium ambitions, the PetroBakken CEO says the majority of his Calgary-based firm’s 2010 program will be focused on drilling 141 (128 net) wells in the Bakken resource play, supplemented by a further 121 (88 net) wells in its con-ventional light oil plays in southeastern Saskatchewan and Manitoba.
“Result has assembled a premier posi-tion in the Cardium light oil resource play through an aggressive strategy of land sale purchases, acquisitions, and farm-in opportunities,” said Brett Herman, Result ’s president and CEO. “The Cardium play holds tremendous potential, and we believe PetroBakken
provides our shareholders with an excel-lent vehicle for its development, as PetroBakken will use its access to capital, economies of scale, and technical experi-ence to accelerate the development of this significant resource play.”
After PetroBakken’s acquisitions of Result and Berens are in the books, the company will have access to over 225 gross (150 net) sections of land that are prospective for the Cardium exploitation. Its drilling inventory will then reportedly include over 400 net potential Cardium locations with the expectation of a higher figure through further evaluation of the lands.
The management teams of Result and PetroBakken have been merger-and- acquisition dance partners previously. In August 2009, PetroBakken itself was formed when Petrobank Energy and Resources Ltd. and TriStar Oil and Gas Ltd. agreed to merge certain assets. The new entity became the dominant player in southeastern Saskatchewan’s prolific Bakken light oil play.
Following that deal, the former TriStar management team took the reins of Calgary-based Result and quickly made a number of moves that positioned the junior producer as a player of note in the emerging Cardium trend. Among Result’s quick moves was the acquisition of Nexstar Energy and its stable of Cardium assets.
Result had a 2009 exit production of more than 750 barrels of oil equivalent (boe) per day. Its proved-plus-probable reserves totalled more than 2.9 million boe. Drilling on Result lands has recently commenced with plans to drill 10 (8 net) Cardium horizontal wells in the first quar-ter of 2010.
Based on field receipts for December, Berens currently has estimated production of 3,650 boe per day (78 per cent gas).
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44 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
O I L & G A S I N Q U I R E R • M a r c h 2 0 1 0 45
Central Canada
The oilsands carries a big chunk of the national economy, according to the Canada West Foundation.
Phot
o: Jo
ey P
odlu
bny
Environmental policies that damage the West hurt all of canadaby Pat Roche
Climate change policies that hurt western Canada’s oil and gas industry would also do widespread damage to the national economy, says a Canada West Foundation study. “Debate about how to reduce Canada’s greenhouse gas emissions has led some to argue that Canada’s oil and gas industry needs to be reined in or even shut down,” warns the 20-page report released on Jan. 28.
“This position is often accompanied by one or more dubious claims: the economic consequences will be minimal, the eco-nomic pain will be contained within west-ern Canada, and green investment and jobs will fill in the void left by a smaller oil and gas industry,” says the report.
The report—titled “Look Before You Leap”—isn’t suggesting environmen-tal goals be abandoned, but stresses the need to understand the full ramifications of measures that hurt western’s Canada’s hydrocarbon industry because the impact will extend into other regions and other industries across the country.
“Our concern was some of the stories and commentary coming out—particu-larly on the oilsands—sort of assumes that
if the industry is damaged, that damage is confined to Alberta,” commented Roger Gibbins, president of the Canada West Foundation. “However, the point we want to stress is that the strength of the western Canadian economy plays a significant role in supporting federal programming that
benefits Canadians living elsewhere in the country,” the report says.
Western Canada’s share of the national gross domestic product—the value of all goods and services produce—has already surpassed Ontario’s. “And if the manufac-turing base in Ontario continues to feel the pinch from a high Canadian dollar and
growing global competition in the years ahead, then the contribution of western Canada will become even more important as Ontario’s historical role as the fiscal linchpin in Confederation becomes diffi-cult to sustain.”
When it comes to climate policy, the oil and gas industry—and the oilsands in particular—has a big target on its back, the report says. “However, because the industry is a key driver of the western Canadian economy, which, in turn, is a key driver of the national economy, we should be wary of undermining its ability to play this role.”
The report says it’s safe to assume the number is much greater than the 130,000 direct jobs generated in oil and gas work. It would include accountants who do most of their work for small oilpatch cli-ents, steel mills in Ontario supplying oil-sands projects, and teachers and nurses in northern Alberta who likely wouldn’t be employed without hydrocarbon activ-ity in the area.
Capital spending in oil and gas exploration, extraction, and refining totalled $53.4 billion—31.3 per cent of total investment in western Canada—in 2007. Natural resource revenue accounted for 32.3 per cent of the Alberta government’s revenue in 2006–07, 19.3 per cent of Saskatchewan’s revenue and 11.3 per cent of British Columbia’s.
The report also cites more intangible benefits such as the fact that the mutual funds in most people’s RRSPs likely include oil and gas stocks. And it acknowl-edges that many thousands of central and Atlantic Canadians have found jobs in western Canada.
Resource revenue also underpins the federal equalization program, which cost Ottawa $14.2 billion in payments to six provinces in fiscal 2009–10. During the fiscal year ending this March 31, Alberta, British Columbia, and Saskatchewan receive no equalization payments. Ontario gets $347 million, or $27 per capita, while Québec gets $8.36 billion, or $1,067 per capita, the report says.
— DAILY OIL BuLLETIN
The report says oil and gas generates much more employment than the 130,000 jobs created directly within the industry.
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46 M a r c h 2 0 1 0 • O I L & G A S I N Q U I R E R
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International
Xtreme Coil, already working in Mexico (shown above), has now gained a toehold in the Middle East.
Phot
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Three canadian energy service companies land overseas contracts
Trican Well Service Ltd. reports that its Russian initiative is doing well, Wavefront Technology Solutions Inc. says Pemex (Mexico’s state-owned oil monopoly) has decided to expand its use of the company’s Powerwave well stimulation technology, and Xtreme Coil Drilling Corp. has won a toehold in the Middler Eastern market.
In 2010, Trican says it will be working for 7 of Russia’s top 10 oil companies and its two largest gas companies, servicing these contracts from its 9 operating bases in Russia and Kazakhstan. Based on the scope of work awarded, management expects that 2010 activity levels will exceed those of 2009 by approximately 10 to 15 per cent.
The company said it has been success-ful in winning work in the majority of the tenders in which it participated. Overall, pricing in the tender awards has modestly improved relative to 2009 pricing.
Based on current contract awards, man-agement expects high fracturing utilization for existing equipment. New equipment added from the 2010 capital program will also allow the company to pursue additional work throughout the year. Management also anticipates almost full utilization of its
coiled tubing fleets, including the sixth unit, which is expected to be in service during the second quarter of 2010. Cementing capacity continues to be underutilized, but the com-pany is still awaiting confirmation regard-ing the award of tenders submitted for some large cement projects.
Wavefront says the Activo Integral Poza Rica-Altamira (an oil production asset of Pemex) will undertake five single well stim-ulations using its Powerwave waterflood pulsing technology, beginning this winter. The approval for the well stimulations fol-lows the non-binding letter of intent signed in October 2009. The stimulations represent the continuation of an extensive Powerwave undertaking with Pemex.
“This is a very important step in the continuation of the relationship between Wavefront and Pemex,” Brett Davidson, Wavefront’s president and CEO. “Pemex has indicated to Wavefront that its longer term intent is to use Powerwave in the Chicontepec field to help Pemex recover reserves that would otherwise remain unrecoverable. We see this as a significant vote of confidence in the performance of Powerwave.”
Pemex has estimated that about seven per cent or 18 billion barrels of the 139 bil-lion barrels of original oil in place in the Chicontepec field is recoverable under cur-rent technology.
Wavefront also reported that the first of four Powerwave single well stimula-tions announced in December 2009 for the Samaria-Luna oil production asset of Pemex was successfully completed. Production results related to the stimu-lation work are pending. The remaining Powerwave stimulation work is imminent.
Xtreme announced its entry into the Middle Eastern drilling market after receipt of two letters of intent from a major diversified oilfield services company. Under terms of the letters, Xtreme Coil will agree to provide two newly designed Coil Over Top Drive XTC 200DTRPLUS drilling rigs customized for re-entry drill-ing projects in the Middle East.
Xtreme Coil completed the first of the two customizations and, subsequently, mobilized the first rig to the Middle East. The second rig was recently moved to Texas to undergo similar customization, which the company expects to complete within approximately three months. The customer will be responsible for mobiliza-tion expenses for both rigs.
Once executed, the long-term contracts related to the letters of intent are expected to require Xtreme Coil’s drilling rigs for two years and to include options for one-year extensions for each rig. The rigs will perform ultra-deep coiled tubing re-entry drilling using Xtreme Coil’s patent-pending XTC 200DTRPLUS rig design. The first rig is expected to commence operations in the first quarter and the second rig during second quarter of this year.
In connection with this new business, Xtreme Coil expects to create joint-venture companies for the Middle East and North Africa in which its wholly owned subsidiary, Xtreme (Luxembourg) S.A., will hold an 80 per cent interest. The new joint ventures may be used to provide certain Xtreme Coil contract drilling services and products in a number of international regions.
— DAILY OIL BuLLETIN
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On the Job
JOBonthe
CAREERS iN ThE OiLPATCh
What are business conditions like in the central Alberta oilpatch?For the past year, a great deal of my work has been insolvencies, mainly welding and fabrica-tion companies. In December, I handled an oil-field instrumentation shop in Drayton Valley, another insolvency. The more specialized big oilfield equipment, like drilling rigs, goes to the large auction outfits like Ritchie Brothers and kruse. we handle backhoes, crawlers, scrapers, trucks, and so on. You read that the economy is getting better, but I feel that is yet to be seen.
What drew you to auctioneering?As a boy, I enjoyed livestock auctions. My parents ranched near Cremona [northwest of Calgary] and my heart is still in agriculture. After high school, I apprenticed as a parts-man journeyman, spending 17 years with a Ford dealer in Red Deer, including 13 years wholesaling on the road. A partsman’s skills— cataloguing, sourcing, evaluations, selling, and so on—are exactly what’s needed to run an auction business.
how did you get your auction training?The Western College of Auctioneering in Billings, Montana, covered the basics well: bid calling, how to breathe, voice projection, and memory, along with handling merchan-dise from real estate to equipment. I started Montgomery Auction Services in 1988 work-ing it part-time for two years. At the time, automotive electronics and technology was getting big and many older mechanics chose to retire rather than learn the new technology. Auctioning off the assets of my former cus-tomers helped me get started. Today we are one of central Alberta’s leading multi-facet auction companies.
What advice would you give to someone with equipment to sell?Shop carefully for your auction company, and use a member of the Auctioneers Association
of Alberta. Reputation and integrity are more important than the amount of commission you are being charged. Advertising to the right buyers is key. It’s true that a multinational auc-tion company may attract more potential cus-tomers but will not necessarily translate into more money for your equipment. Buyers tend to pay less money for a piece of equipment if multiples of the same equipment is also on the block to choose from. Bidding reaches top dollar more often if there’s only one item avail-able. Also, be careful about minimum price guarantees or selling outright to the auction company. They are going to leave plenty of margin for error or selling price shortfalls. As I
said earlier, advertising is key, along with real-istic expectations for your equipment.
Where are auctions headed in the future?It’s not a big thing for our company, but online auctions will continue to grow as a percentage of the industry. An “online internet-only” auc-tion normally means the buyer pick will up the item from the consignor, which saves trans-portation, set up, and the need for an auction yard. It’s cost-efficient. Still, there will always be live auctions. People like to see the mer-chandise and meet each other. It’s a wonderful business full of variety—I look forward going to work each day.
Don Montgomery
Age: 53Training: OwnerCompany: Montgomery Auction Services Ltdlocation: Blackfalds, Albertaeducation: Journeyman partsman, accredited auctioneer—Western College of Auctioneering, certified personal property appraiser
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Tools of the Trade
A LOOK AT NEW TEChNOLOGiES
TOOLSOF ThE TRADE
SET solid expandable tubularsEnventure Global Technology
Answered by kevin Waddell, vP, Technology & Marketing for enventure global Technology, llC
Who is enventure global Technology, llC?Enventure Global Technology, LLC is the world’s leading provider of solid expandable technology solutions for the energy industry. Enventure was established in 1998 after proof-of-concept tests demonstrated the feasibil-ity of expanding oil country tubulars. We lead the industry in experience with more than 1,100 systems installed, one million feet of pipe expanded, and reli-ability of 97 per cent.
What is seT technology?SET solid expandable solutions involve the controlled expansion of solid steel tubulars in the downhole environment for enhanced drilling, production, completion, and remedial operations. SET technology utilizes a cold-working process that permanently deforms expandable casing. SET pipe, called EX-80, meets standards beyond those specified by the American Petroleum institute (APi) for oil and gas well use, but with pre-expansion properties similar to those of APi L-80 material. Enventure’s expandable systems utilize a solid cone to expand the casing from the bottom up.
What are the competitive advantages of seT technology?When SET systems are expanded downhole, Enventure’s solutions ensure maximum internal diameter (iD). in drilling operations, this translates to additional casing design options, reassurance of reaching total depth with the required completion size, and reductions in overall non-productive time.
Remediation with expandables is a reliable, one-time solution for parted con-
nections, corroded casing, and shutting off unwanted perforations. however,
we are constantly innovating how expandable technology is used to benefit
the industry, which means our SET system applications are ever-expanding.
From saving a multi-million-dollar exploratory well with a record 6,935-foot
liner, to remediating watered-out perforations in a 40-year-old well with a
