Profiler June 2013

JUNE 2013

WESTERN CANADA’S OILFIELD SERVICE AND SUPPLY MARKET AUTHORITY

STATE OF THE

INDUSTRY ISSUE

Reaching out to the world With petroleum production rising,

Canadian industry looks to all points on the compass to move product to market

PlusTight oil plays have enjoyed explosive growth, but that growth will moderate as plays develop

Gas prices rebound in winter of 2013, but the question is, what lies ahead?

Bitumen bubble will keep prices discounted for a decade, but production will keep rising

is an innovative completion technology from Logan Completion Systems that is especially designed for produc-ers who are tackling multi-stage fracs. One-trip installation for faster completion times and frac valves with fully removable ball seats post-fracturing — without milling or drilling — reduces well costs, improves production, and maximizes your profits. The key feature of the MultiStim System is the use of the full-bore inner diameter which allows conventional tools to be run after the seats are removed. Cementing, or plugging and perforating operations are not required. MultiStim is suited to extended reach horizontal wells. Sleeves can be selectively opened and closed post-fracturing to allow customized stimulation, testing or production management of the entire wellbore for the life of the well. The MultiStim Fracture Isolation Liner System and MultiStim Cup Frac Tool System (a straddle cup system) are suitable for acid, proppant or energized fracturing operations in all types of formations. Contact us for complete details.

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3

6 reaching out to the world

With petroleum production rising, Canadian industry looks to all points on the compass to move product to market

12 tight oil matures Tight oil plays have enjoyed explosive growth, but that

growth will moderate as plays develop

18 turnaround time Gas prices rebound in winter of 2013, but the question is,

what lies ahead?

22 on hold Bitumen bubble will keep prices discounted for a decade,

but production will keep rising

3

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Cover illustration by Paul Zwolak

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Plug-and-perf and ball-actuated sleeves are brute force frac methods that bullhead fluids and sand down the casing with no feedback about formation response, no recourse in the event of a screen-out, and no way to manage water and chemicals usage. Both methods limit the number of stages and usually require post-completion drill-out of composite plugs or ball seats. The Multistage Unlimited system overcomes those limitations and drawbacks using coiled tubing as a work string and circulation path to the frac zone.

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P R O F I L e R M A G A Z I n e . C O M 3

Oilfield purchasing technology is changing rapidly

In Canada’s Western Canadian Sedimentary

Basin, explorers and producers are changing

the way they work. In many plays, their

focus is on repeatable, factory-like approaches

to drilling, completion and tie-in of new wells,

and to the service and operation of existing

wells. More and more, they are focused on effi-

ciency and cost control.

Engineers, planners, managers and buy-

ers are using new approaches and technolo-

gies to make sure they purchase services and

supplies at the lowest possible cost. Just as

important, they are making sure that services

and supplies are delivered when they are need-

ed. Time is money in the oilfield, and they’re fo-

cused on saving both.

To save time and money, a buyer needs to

have more than one option—they need choices

in products and vendors.

They may have information on some vendors

in their accounting, enterprise resource plan-

ning and compliance systems. That’s usually not

enough—they must extend their search for sup-

pliers, so they need other sources.

However, finding what a buyer needs in Can-

ada’s oilfield is a complex process. The service

and supply industry is made up of over 3,000

companies, and they are constantly changing.

Mergers and acquisitions and company start-

ups and closures happen frequently. Vendors

change the products and services they offer,

and move their head offices or open and close

branch locations.

Luckily, the Canadian Oilfield Service and

Supply Database (COSSD) is constantly up-

dated, so a buyer can count on it to find what

they need. They can use the COSSD for free,

and it’s available in six ways: website, smart-

phone, iPad, Garmin GPS, digital edition and print.

Whether in an office or in the field, it’s proving

to be a buyer’s best source for vendor informa-

tion—that’s why its usage is growing so rapidly. In

2012, over 53,000 people used its print or digital

edition. The fastest growth is in digital usage—in

2012, over 118,000 used it through the website,

smartphone, iPad and Garmin GPS. That’s more

than 170,000 in total.

COSSD is also proving to be a vendor’s

best choice for connecting to their customers.

Buyers are now using COSSD.com on their

web browsers and iPhone, BlackBerry or

Android smartphones. They can search a ven-

dor’s company profile, product catalogue, dis-

play advertisements, categories of service and

locations. They’re also able to use its proximi-

ty search features to find a service or product

close to a town, city or even their smartphone’s

current location.

An analysis of 1,000 companies who visited

COSSD.com in the second to third quarter

of 2012 showed that many were primary

buyers—explorers and producers such

as Encana Corporation or Talisman Energy

Inc., and pipeline operators like TransCanada

Corporation. Many more are secondary buy-

ers—service and supply companies such

as Weatherford Canada Partnership and

Halliburton.

If you’re a buyer, visit COSSD.com to learn

how this database can help you. If you’re a ven-

dor, use the COSSD to ensure 170,000 or more

buyers can find you.

Become part of this fast-growing buyer/

seller community—email Christopher Kuntz

at [email protected] or call

403.516.3492.

Purchasing patterns are changing in Canada’s oil and gas industry, and buyers are using technology to access more and better information. The COSSD, a new database of service and supply companies, is helping them con-trol costs and maximize productivity. In 2012, more than 170,000 people used it.

June 30, 2009 June 30, 2010 June 30, 2011 June 30, 2012 December 31, 2012

140,000

120,000

100,000

80,000

60,000

40,000

20,000

0

iPad (downloads)Smartphone (unique visitors)Website (unique visitors) Garmin GPS (downloads)

LefT: Digital usage of the COSSD has grown substantially since 2009. ABOVe: Many of Canada’s leading explorers and producers use COSSD.com—as do many other primary and secondary purchasers of oilfield services and supplies.

Company type Per cent of total visits

Primary purchasersExploration & ProductionEngineeringPipelineConstruction

Refining & Petrochemicals/ Gas Processing

Total—primary purchasers 22Secondary purchasersService & SupplyTransportationManufacturing & FabricationElectrical, Instrumentation & ControlHealth, Safety & EnvironmentalTotal—secondary purchasers 21Occasional purchasersLegal, Financial & InvestmentGovernment, Agencies & Consulates

Universities, Research Institutions & Public Libraries

OtherTotal—occasional purchasers 57From a sample of 1,000 companies who visited COSSD.com in Q2-Q3 2012.

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Marketing excess Canadian oil and gas production used to be an easy job, with a hungry market of 300 million Americans south of the border willing to take everything Canada could produce.

But it appears those days are over.A massive surge in tight natural gas production in the United States has decimated

Canadian exports, and a growing number of analysts are predicting the United States will be self-suf� cient by the end of the decade.

The same extended reach horizontal drilling and multistage fracturing technology that set off the natural gas production explosion has also resulted in a tight oil explosion south of the border and, when combined with growing exploration success in the Gulf of Mexico, could add as much as 2.5 million barrels per day of incremental production over the next few years.

This growing tight oil production, combined with expanded oilsands production, has created bottlenecks in the North American pipeline infrastructure, resulting in huge discounts on Canadian oil.

Both the government and the industry have � oundered in � nding a solution to the oil and gas market access challenge, creating what is now a crisis situation.

And it appears this crisis could easily last for the next � ve years as political and regulatory burdens are worked through.

The good news is all options are on the table in � nding ways to new markets.On the oil front, Canadian Association of Petroleum Producers vice-president for markets

and � scal policy Greg Stringham says despite growing production south of the border, the United States will still need to import six million to seven million barrels per day for the foreseeable future.

“And our role as Canada is really to be the preferred supplier into those markets and, in particular, the demand is connecting our growth in heavy oil to that supply of re� ners in the U.S. Gulf Coast who already have that capacity already built and in place,” he said.

Stringham said other options include the Gateway Pipeline to the West Coast and pipelines to the East Coast of Canada and the United States.

The Alberta government is now looking north to see if it can bypass the West Coast to reach international markets. It has hired consultants to look at shipping up the Mackenzie Valley to the Beaufort Sea. It is also investigating rail shipments to Alaska, where the oil would then be loaded on tankers bound for Asia.

With natural gas, all eyes are looking westward toward Kitimat, B.C., as the centre for lique� ed natural gas (LNG) exports. New proposals for export terminals keep piling up, but until construction starts, the industry remains at a standstill.

With a decision on the Keystone XL Pipeline expected this year, along with investment decisions on two LNG export facilities expected in 2013, there may � nally be some action after � ve years of discussion on how to reach new markets.

Unfortunately, tens of billions of dollars—if not hundreds of billions—in potential revenues will be lost in the meantime.

All options on the table

Darrell [email protected]

PUBLISHER

Maurya Sokolon | [email protected]

EDITORIAL

EditorDarrell Stonehouse | [email protected]

Editorial Assistance ManagerMarisa Sawchuk | [email protected]

Editorial AssistanceShawna Blumenschein, Matthew Stepanic

CREATIVE

Print, Prepress & Production ManagerMichael Gaffney | [email protected]

Creative Services ManagerTamara Polloway-Webb | [email protected]

Creative LeadCathlene Ozubko

Graphic DesignerJanelle Johnson

SALES

Sales Manager—AdvertisingMonte Sumner | [email protected]

SalesBrian Friesen, Tony Poblete

For advertising inquiries please contact [email protected]

Ad Traf� c Coordinator—MagazinesDenise MacKay | [email protected]

DIRECTORS

CEOBill Whitelaw | [email protected]

President Rob Pentney | [email protected]

Director of Sales & Marketing Maurya Sokolon | [email protected]

Director of Events & ConferencesIan MacGillivray | [email protected]

Director of The Daily Oil BulletinStephen Marsters | [email protected]

Director of Digital StrategiesGord Lindenberg | [email protected]

Director of ContentChaz Osburn | [email protected]

Director of ProductionAudrey Sprinkle | [email protected]

Director of FinanceKen Zacharias, CMA | [email protected]

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Profiler is owned by JuneWarren-Nickle’s Energy Group. GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2013 JuneWarren-Nickle’s Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240. Postage paid in Edmonton, Alberta, Canada.

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P R O F I L E R M A G A Z I N E . C O M 5

EDITOR’S NOTE

6 J u n e 2 0 1 3

Canada’s petroleum industry is all revved up with no place to go.Oil production continues climbing as new oilsands operations come on stream and tight oil plays

add incremental production. Production is expected to double to around 5.7 million barrels per day over the next decade. But challenges in building new pipelines have created bottlenecks in the system, resulting in huge discounts on Canadian oil.

The advent of extended reach horizontal drilling and multistage fracturing has created a 100-year supply of natural gas, at a time when traditional markets in the united States are plugged with their own tight gas boom.

The industry is now beginning the hard work of connecting to new markets for its growing oil and gas reserves, but it will take time before supplies begin flowing overseas.

In a recently released report, petroleum analyst Wood Mackenzie Limited says in the short term the start-up of the Southern Access and Pony express pipelines in 2014 will provide some relief for oil producers currently seeing major discounts on production. enbridge Inc.’s Southern Access expansion will open up new markets for western Canadian and north Dakota light crude oils, taking some stress off the Cushing hub in Oklahoma. The Pony express will provide a similar service.

Longer term, construction of the Keystone XL and Gateway pipelines will be needed to move Canadian crude to market. However, both projects are at an early stage and significant challenges, both operationally and politically, lie ahead.

“u.S. approval of the Keystone XL northern leg is still pending, and a continued delay will result in Keystone XL’s southern leg acting as a clearing mechanism for light oil from Cushing until the northern leg is approved and constructed,” said Skip York, principal analyst in Wood Mackenzie’s oils research team. Wood Mackenzie expects the northern leg ultimately will go forward, although the approval decision remains politically charged so the timing could slide, he said.

With petroleum production rising, Canadian industry looks to all points on the compass to move product to market

Reaching out to the world

By Daily Oil Bulletin staff

Illustration by Paul Zwolak


Cover Feature

Wood Mackenzie doesn’t see material infrastructure relief until the start-up of projects such as Southern Access and Pony express in 2014. The companies without a natural hedge via an accessible downstream position are the most affected and may seek out rail as an alternative option, according to Wood Mackenzie.

“Canadian prices will remain highly susceptible to refinery and pipeline outages or interruptions,” said York.

“even post-2014, we forecast a tight view as production from existing and sanctioned oilsands projects ramp up,” he added.

The strong supply outlook from u.S. tight oil plays warrants a diversification for Canadian crudes away from the traditional u.S. Midwest export market, said Wood Mackenzie. It noted that projects are moving forward in varying stages to transport western Canadian barrels to coastal markets, where stronger Brent-linked prices can be realized.

Keystone XL would add 830,000 barrels per day of capacity to the u.S. Gulf Coast, with some of that capacity allocated to Bakken volumes. enbridge’s Line 9 reversal to Montreal is not expected online until 2014, and planned projects through British Columbia are not expected to start up until 2018 at the earliest, with political, environmental and First nation opposition as substantial obstacles.

Supply growth over the next four years also is expected to outpace pipeline capacity in western Canada, the u.S. Rockies and the u.S. Bakken. even if all planned pipeline projects such as Keystone XL and northern Gateway were to proceed, incremental rail shipment volumes of

approximately 600,000 barrels per day, up from existing or planned crude transportation by rail of approximately one million barrels per day, would still be required. Rail capacity would need to increase to approximately 2.5 million barrels per day to keep up with production growth if the pipelines aren’t built.

At a recent industry event, Greg Stringham, vice-president of oilsands and markets for the Canadian Association of Petroleum Producers (CAPP), said the oil transportation issue isn’t just a problem for oilsands producers.

He pointed out current production from north American tight light oil plays, including the Bakken, has soared to 750,000 barrels per day in two years and could be one million barrels per day by the end of this year.

“That’s equivalent to five mining projects or 25 in situ phases—in two years from start to production,” said Stringham.

That dramatic growth in light oil has resulted in competition for pipeline and, more recently, rail capacity. And all that new crude, except for the eagle Ford in Texas, will rely on the same pipelines heavy oil producers were counting on to move their crude to market, he said.

Despite the growth in the united States in light oil, there will still be a demand for six million to seven million barrels per day of imported oil, according to Stringham. “And our role as Canada is really to be the preferred supplier into those markets, and in particular the demand is connecting our growth in heavy oil to that supply of refiners in the u.S. Gulf Coast who already have that capacity already built and in place.”

8 J u n e 2 0 1 3

Cover Feature

In an effort to match growing heavy crude supply with the growing demand, the industry is targeting three areas: the eastern seaboard in both Canada and the united States, the u.S. Gulf Coast and California, and then offshore north America in China and India.

The most recent push is toward the east coast, in which north American crude would begin to replace about 680,000 barrels per day of crude currently imported by Quebec refineries. Projects include enbridge’s Line 9 re-reversal between Sarnia, Ont., and Montreal and the proposed conversion of a TransCanada Corporation natural gas pipeline to oil service in the same market with a potential extension to new Brunswick, where Irving Oil Ltd. has a large refinery that has been able to process some Venezuelan heavy oil. More importantly, that would provide access to a deepwater port where very large crude carriers (VLCCs) could come in and open up that market, he said. “That’s where the Indians have been talking to us about the opportunity of potentially bringing that oil into their refineries.”

On the Gulf Coast, CAPP is optimistic about new projects with a potential capacity of 1.3 million to 1.4 million barrels per day that will help ease the oil bottle-neck at Cushing, Okla., which has resulted in a disconnect between world oil prices and north America landlocked prices. The 700,000-barrel-per-day southern leg of Keystone XL from Cushing to the Gulf Coast should be in operation in the third quarter of this year, along with the potential doubling of the Seaway line at the beginning of 2014, said Stringham.

On the west coast, enbridge’s proposed 525,000- barrel-per-day northern Gateway pipeline to Kitimat,

B.C., is nearing the end of its regulatory process and will have a decision by the end of this year, while

Kinder Morgan Canada Inc. will be applying for an expanded 830,000-barrel-per-day Trans Mountain Pipeline to Vancouver for export to Asian markets.

In the long run, because of the forecast growth in heavy oil supply, it will not be an either-or situation for additional pipeline capacity, he said. While the order and timing may change, all three markets eventually will be

required, according to Stringham.CAPP also has been looking closely at rail for

the movement of crude oil. First quarter 2013 shipments are estimated at 120,000 barrels per day,

with some forecasts of up to 200,000 barrels per day by the end of this year. An example of that is in the Bakken where nearly 500,000 barrels per day is being shipped by rail, he said.

Orders are going in for railcars, while loading and unloading terminals, which have been the bottleneck for shipments, now are being built, said Stringham. And railcar orders are not only for those to move tight and light oil, but a significant number of orders are for steam-wrapped railcars to move heavy oil, which also require steaming facilities to unload them.

“There are some things that need to be built but, in the short term, the rail and the track are in place and so the companies have been promoting this as a short-term remedy together with pipelines,” he said. “They are not there to replace pipelines.”

The Alberta government is scouting out possible new ways to get crude oil and refined products to market in the wake of mounting public opposition to crude oil pipelines, says the province’s energy Minister Ken Hughes.

Most recently, the government hired Canatec Associates International Ltd., a Calgary consultant experienced in northern development, to do some research on the potential for an oil pipeline from the Central Mackenzie Valley to a tidewater at Tuktoyaktuk, n.W.T., on the Beaufort Sea, Hughes said. From there, it could be loaded onto tankers for shipment to Asia. There is already an enbridge pipeline that transports oil from norman Wells, n.W.T., to Zama City, Alta., he pointed out.

In 2014, the northwest Territories will have full control over its resources and the government knows there are companies that are currently active in exploration, he said. Husky energy Inc., ConocoPhillips Canada and MGM energy Corp., in a joint venture with Shell Canada Limited, were all active in the Central Mackenzie Valley area this past winter. The northwest Territories

In an effort to match growing heavy crude supply

with the growing demand, the industry is targeting three areas:

the eastern seaboard in both Canada and the united States,

the u.S. Gulf Coast and California, and then offshore

north America in China and India.


Cover Feature

government is in the same situation as Alberta, which is looking at ways to get its

products to market, according to Hughes.However, while the Tuktoyaktuk harbour is relatively

deep, the Beaufort is a shallow sea and the approaches are in shallow water, according to Doug Matthews, an energy consultant who worked with governments in the north for 25 years. In order to be able to ship out large volumes of crude, either considerable dredging or the construction of a 20-kilometre pipeline to deeper waters where large tankers could anchor for loading would be required. “It could be done but the cost would be very high, but if there is no alternative,” he said.

“If one were a prospective n.W.T. producer, it would be a good news story because then you could get your oil onto this Alberta-funded pipe and that, would be great,” said Matthews. “But having said that I think the technical challenges are pretty big and the political challenges are big; we don’t build pipelines with ease in the northwest Territories.”

The Alberta government has also just begun preliminary research on another proposal: a railway that could transport products from the oilsands to the existing marine oil terminal at Valdez, Alaska, said Hughes.

The Alaska route is not the only northern proposal under consideration. Hughes said the government is still looking at the Port of Churchill on Hudson Bay as a potential outlet for diesel fuel produced in Alberta and moved to Churchill by rail—once the province has a surplus. Communities in northern Canada would be the likely market for the diesel fuel from the north West Redwater Partnership. The 50/50 joint venture between north West upgrading Inc. and Canadian natural Resources Limited is building a refinery in Alberta’s Industrial Heartland that will convert 50,000 barrels per day of bitumen into diesel fuel. The long-term plan is to expand to 150,000 barrels per day, in three 50,000- barrel-per-day stages.

“All of these are sort of ‘Let’s do some research, let’s get the response back as early as we can and see if it’s worthy of more research,’” he said.

lNG export system takiNG shapeevery year, almost nine trillion cubic feet of natural gas with a value of $150 billion is super-cooled and shipped in tankers to Asian markets.

Getting a piece of that giant liquefied natural gas (LnG) market will ultimately determine whether western Canada’s natural gas industry continues to expand or stagnates. And right now the odds are around even on whether the five biggest LnG export terminals planned will be built, according to the experts.

The size of the prize is huge, according to Ziff energy Group. LnG exports to Asia could easily build up to 10 billion cubic feet per day within five years of the first export terminal opening, edward Kallio, the firm’s director of gas consulting, said at a recent Ziff-sponsored breakfast in Calgary.

“We could get over 20 billion cubic feet a day of total western Canadian gas output pretty quickly if several of the proposed West Coast LnG export projects are realized, which is really good news for our basin. Drill bits will have to start turning to come up with this gas,” said Kallio.

Western Canadian gas output has plunged to about 13 billion cubic feet per day and will probably fall closer to 12 billion cubic feet per day next year, Ziff energy expects.

“Our gas is being shut out of the u.S. market and even the eastern Canadian market,” Kallio said, referring to the inability of western Canadian gas to compete with cheap output from shale plays such as the Marcellus in the northeastern united States.

“Marcellus is going to get up to 15, maybe 20 billion cubic feet a day by 2020,” Kallio said. “They don’t need our gas.”

When western Canada was producing 17 billion cubic feet per day, about 10 billion cubic feet per day of that was shipped south of the border. exports to the united States have now plummeted to roughly five billion cubic feet per day and are headed to three or four billion cubic feet per day, or even lower, Kallio said. Asian exports could make up for that lost market.

But to make that happen, industry needs to act fast in getting West Coast LnG export terminals up and running, according to Gerry Goobie, principal with Gas Processing Management Inc.

“We really have to raise our game to participate in this LnG business,” Goobie told the Canadian energy Research Institute natural gas conference. “If we’re going to be successful, we’ve got to get our product to market cheaper than the next guy.”

“If we take forever in the regulatory process to get through this, then LnG exports won’t happen and the whole gas development in western Canada won’t happen, and that would be a big calamity. I’m not saying this will occur, but we really have to focus on getting it done,” he said. “There is a window of opportunity and we’ve got to get after it because that window is not going to remain open forever.”

Some have suggested that Canada only has until the end of this decade to build up its LnG industry or face

10 J u n e 2 0 1 3

being overtaken by other countries looking to cash in on booming demand for fuel throughout Asia.

Gary Weilinger, vice-president of strategic development and external affairs with Spectra energy Corp., echoed the fact that the timing of these projects in British Columbia is critical.

Last year, Spectra signed a project-development agreement with BG Group plc to jointly develop plans for a new natural gas transportation system from northeastern British Columbia to serve BG Group’s potential LnG export facility in Prince Rupert, B.C., on the province’s northwest-ern coast.

“If we think the world LnG markets are just waiting patiently for western Canadian LnG projects, then we’re mistaken,” he said. “This is a very competitive space with potential projects in Russia, Africa, the Middle east and Australia.”

Jim Prentice, senior executive vice-president and vice-chairman of CIBC, noted at a recent B.C. LnG conference that the challenge with gas is similar to oil in that there is a growing urgency to tap new markets.

“Industry revenues are down sharply,” noted the former federal cabinet minister in an evening address to the conference. “Government revenues have been adversely affected. The impact on western Canadian producers has been devastating. And with key plays in the u.S. expected to result in even higher production south of the border, the threat to—and impact on—Canadian gas producers is likely to continue.

“We’ve entered a critical period. We face the imperative to match up Canada’s resources with the needs of the Asian marketplace. We must access new and growing markets if we want to reinvigorate this important industry,” he added. “We therefore need to do the hard work of reorienting ourselves to serve the demand of tomorrow—and we need to get on with it, because there are others who are equally determined to get into those markets.”

He noted that the critical element in the LnG industry is—and always will be—contractual dependability.

“The world has a lot of natural gas,” Prentice said. “What it doesn’t have is an ample supply of reliable, dependable nation states that are capable of fulfilling their contractual obligations over a 50-year period without potential interruption due to political, legal or territorial conflict.

“But let’s be clear. Getting into liquefied natural gas represents a big financial bet,” he added. “The stakes are high and the challenges are formidable. This is no slam dunk. We need to be confident and aggressive, but we must also ensure that we resolve and bring across the finish line a number of key outstanding issues.”

First, Prentice said, a royalty regime must be defined in such a way that it promotes the establishment of an LnG industry in Canada and helps ensure its long-term survival and success.

“In a highly competitive global industry, it doesn’t take much to marginalize returns to the point that

other jurisdictions begin to look more attractive,” he said. “This month, the

B.C. government indicated that it foresees some $100 billion in

tax and royalty revenue coming to it from LnG over the next 30 years. In tough economic times, it’s human nature to celebrate potential good news.”

But, he warned that the key driver of any project of this scale should be the

overall benefits to the local, provincial and national

economies, not simply the potential taxation base.

“The imperative in LnG must be to ensure that the taxes we place on this

important burgeoning industry don’t have the effect of stymieing or undermining its creation and its growth,” Prentice said.

He added that there needs to be sufficient skilled labour to build the proposed LnG facilities and pipelines under tight timelines.

“Australia, whose industry is more mature than ours, has already experienced significant delays caused by a shortage of qualified workers,” Prentice noted.

Also, he said that the federal government needs to adopt a proactive role on coastal management.

“Ottawa has sole jurisdiction over our territorial waters, so it must take the lead in developing a management regime that will take into account the rewards as well as the environmental risks of increased West Coast tanker traffic,” Prentice said. “We need to better understand and move to address the competitive challenge that may be posed by the united States. The Americans represent a different market offering. They are not necessarily committed to a long-term future as a natural gas exporter, and they are prepared to sell at floating market prices.”

Capp estimates first quarter 2013

rail shipments at

120,000barrels per day,

with some forecasts of up to

200,000barrels per day

by the end of this year.


Cover Feature

JTight oil matures

Tight oil plays have enjoyed explosive growth, but that growth will moderate as plays develop


Just how important have tight oil plays been in the resurgence of western Canada’s light oil business?

In 2011, the Cardium play in Alberta accounted for 12 per cent of all production additions in the Western Canadian Sedimentary Basin, and the Bakken in Saskatchewan added another seven per cent, according to a report by new York–based ITG Investment Research that looked at data from more than 300,000 wells.

But don’t expect that pace to continue, says ITG. The study forecasts that rig-based oil production, which includes the Alberta Cardium and Saskatchewan Bakken, will slow to a compound annual growth rate of 3.3 per cent to 2020, down from 8.8 per cent in 2011-12. Assuming no increase in the number of oil-directed rigs, production is projected to grow by approximately 370,000 barrels per day by 2020.

Tight light oil plays have driven growth in Saskatchewan’s total oil production for the last five years. In 2012, the province averaged a record 474,000 barrels per day, up 50,000 barrels per day from 10 years ago and more than triple its output from 30 years ago.

Saskatchewan’s three main tight oil plays—the Bakken, Shaunavon, and Viking—are currently producing about 115,000 barrels of oil per day, driven by horizontal drilling and multistage fracturing.

The Bakken is currently producing around 70,000 barrels per day, up from less than 1,000 barrels per day a decade ago.

ed Dancsok, assistant deputy minister of petroleum and natural gas with Saskatchewan’s Ministry of the economy, says production growth from the Bakken has slowed but continues expanding by five to 10 per cent annually.

“I think overall the trend is still upwards on the [Saskatchewan] Bakken—just at a more measured pace,” says Dancsok.

The other Saskatchewan tight oil plays that have emerged in recent years are the Viking and the Lower Shaunavon.

total saskatchewan production

1982

20022012

average474,000

barrels per dayaverage424,000

barrels per day

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12 J u n e 2 0 1 3

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In 2008, about 6,000 vertical oil wells were producing only about 9,000 barrels per day from the Viking formation in Saskatchewan. exiting 2012, there were more than 7,800 wells—including 1,800 new horizontal wells—producing 27,350 barrels per day.

At the end of last year, production from Saskatchewan’s Lower Shaunavon formation had soared to 17,350 barrels per day from 820 wells, up from only about 200 barrels per day from 20 vertical wells in 2007.

With 4.6 billion barrels in place and only four per cent recovered, Bakken operators are moving to secondary recovery methods to add to their reserve base.

“There’s a lot of work on waterfl ood pilots going on right now in Viewfi eld, led by Crescent Point [energy Corp.],” Don Rawson, managing director of institutional equity

research for AltaCorp Capital Inc. says. “Separately, PetroBakken is testing gas injection as an alternative way to fl ood it and increase recoveries. Those developments are being very closely watched.”

neil Smith, chief operating offi cer for Crescent Point, says his company is working with the Saskatchewan government on unitization of four separate units side by side, which he is optimistic will occur in 2013.

“Once we’re unitized, we can implement a waterfl ood.”

According to Smith, at eight wells per section, the company’s current Bakken recovery is about 19 per cent, primary. However, waterfl ooding will increase recovery to over 30 per cent.

“In the near term, you’re probably going to see 1.5 [billion] to two billion barrels under fl ood in the core area; it’s in that order of magnitude and we have a ways to go.”

To date, Crescent Point has converted 45–46 wells to injection, and the company is looking to convert another 20 in 2013. Smith

says the Bakken play is tight rock, which traditionally has not been considered economically fl oodable, but Crescent Point pioneered using fractured horizontal oil wells as the injectors.

“We’ve proved that it works, we’ve proved that it’s repeatable economically across the play, and now with unitization, we’re planning to go commercial across the fi eld.”

Dancsok says secondary recovery methods are starting with a few pilot projects currently, but as companies gain information, he expects to see those pilots turn into full commercial projects.

“So we’ll see that adding to the growth.”Once Crescent Point’s team of geophysi-

cists fi gured out how to crack the rock in

BC AB SK MBBakken/Three Forks/Torquay

Cardium

Duvernay

Montney/Doig

Pekisko

Lower Shaunavon

Beaverhill Lake/Swan Hills/Slave Point Carbonate

Viking

Wellsites


FEATURE

from tight formations and then use those techniques in other tight plays such as the Shaunavon and Viking.

“We see emerging successes there, and we’re pretty hopeful for our future as the boom continues in the province.”

The horizontal drilling and multistage fracturing techniques developed in the Bakken have turned the giant Cardium formation in Alberta into Canada’s biggest tight light oil play.

Oil production from horizontal wells in Alberta’s Cardium formation has skyrocketed to about 80,000 barrels per day in only four years, reports Peters & Co. Limited.

Horizontal Cardium wells were producing less than 2,000 barrels of oil per day at the start of 2009, Peters says in a recent seven-page Cardium oil update. (The total estimated oil production from the Cardium formation is about 115,000 barrels per day.)

One of the largest oil reservoirs in western Canada, the Cardium formation has been drilled with vertical wells for decades but was considered a mature play until the success of multi-frac horizontal wells sparked significant new investment.

Thanks to the advances in drilling and completion technologies, the Cardium has become the equivalent of Alberta’s Bakken—a tight oil play that has helped

reverse a decades-long decline in the province’s light oil production.

nearly 2,000 wells have been drilled across the vast Cardium fairway, spanning about 500 kilometres between Lochend in the south and Wapiti in the northwest, Peters says.

“unconventional horizontal drilling in the Cardium ranks as one of the most targeted light oil plays in the Western Canada Sedimentary Basin, with about 580 wells drilled and about 715 wells brought on stream in 2012,” Peters reports.

The current Cardium total of nearly 2,000 horizontal wells is up from fewer than 70 horizontal wells on production at the start of 2009.

Over the past 12 months, about 40 operators have drilled a combined total of about 450 horizontal Cardium wells. Peters says the top three horizontal drillers in the Cardium in that period were PetroBakken energy Ltd. (60), Bonterra energy Corp. (which acquired Spartan Oil Corp.) (53) and Whitecap Resources Inc. (41).

The leading operators to license Cardium wells in the past year were PetroBakken (93), Bonterra (85) and Vermilion energy Inc. (70).

Of the nearly 2,000 horizontal Cardium wells drilled to date, about 1,700 are outside the main conventional conglomerate play in the Pembina field, Peters says.

the Saskatchewan Bakken to make oil production economical, Smith says, the company took that technique and employed it in other formations with similar types of tight rock.

The company was one of the first movers into southwestern Saskatchewan into the Shaunavon formation. “We knew it was there with lower permeability, medium gravity and lower recovery...big oil in place.

“So, we initially got in and bought four or five sections of land, tried our techniques and said, ‘Yep, with a little bit of modification, this is going to work.’”

Smith says Crescent Point now owns about 90 per cent of an oil play with about 4.2 billion barrels in place. It currently has 10 major oil opportunities, eight of which were discovered since 2005 with techniques developed in the Bakken.

“It’s been extremely important, the advances in fracture stimulating horizontal oil wells. We really have built a 90 per cent oil-weighted, unique company based on that technology.”

Among the many benefits of Bakken production in Saskatchewan, Dancsok says, is that it has allowed companies to

innovate and perfect the means of producing

Viking formation in saskatchewan

2008

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new areas where horizontal Cardium wells are being drilled include Wapiti, Kakwa and Kaybob in the northwest, and Stolberg, Willesden Green, Ferrier and Harmattan east on the southern portion of the core Pembina fairway, the investment firm says.

It emphasized that well productivities vary among operators, and well productivities and costs vary by area.

Peters highlights four emerging areas that have shown increased levels of horizontal drilling activity and good results in 2012—Kaybob, Willesden

Green, Ferrier and Stolberg. Ferrier and Willesden Green were productive for Cardium oil in conventional conglomerate reservoirs, while the new horizontal wells have targeted the undeveloped “halo” sandstone reservoirs. Kaybob and Stolberg are newer areas for Cardium oil.

When Peters published its first unconven-tional Cardium play report in early 2010, its type curves in the east Pembina, West Pembina and Garrington areas were based on only about 20 multi-frac horizontal wells with limited production history.

now, with about 1,200 wells in these areas, Peters’ estimated ultimate recovery per well has been reduced by four per cent for

east Pembina and Garrington, but increased by 11 per cent for West Pembina.

“Our revised type curves result in half-cycle rates of return in the range of 35 per cent (Garrington) to 66 per cent (Harmattan east), with a payout period of between 1.7 to three years,” Peters reports.

A number of other tight oil plays in Alberta are in earlier stages of development.

The Slave Point, Swan Hills carbonate play in northern Alberta has seen significant production growth. There was zero produc-tion in 2009, but by the end of last year 14,000 barrels per day were flowing from horizontal wells in the play. Over 300 wells targeting the carbonate play were drilled last year.

The Montney oil play in northwestern Alberta has seen similar growth. Horizontal production in the play surpassed 6,000 barrels per day early last year from zero in 2009.

In central Alberta, DeeThree exploration Ltd. is in the early stages of developing a Belly River play. In April, DeeThree announced an exploration well in the play flowed for four days up the 11.4-centimetre frac string at an average rate of 1,770 barrels per day of 44 oAPI reservoir oil, 1.6 million cubic feet per day of natural gas with the final rate of 1,580 barrels per day of oil, and 1.8 million cubic feet per day of natural gas.

Thanks to the advances in drilling and completion technologies, the Cardium has become the equivalent of Alberta’s Bakken—a tight oil play that has helped reverse a decades-long decline in the province’s light oil production.

The 100 per cent DeeThree-owned well was drilled to a planned total depth with a horizontal lateral of about 2,000 metres in upper Belly

River sand. The horizontal lateral was fracture stimulated, placing 550 tonnes of sand over 19 stages using an energized water-based system. The well is shut-in for pressure work, and the company began operations to tie the well into the existing pipeline and facility infrastructure.

DeeThree has drilled 18 Belly River horizontal wells in its Brazeau property, where it has more than 70 sections of high working interest Belly River lands widely spread throughout the land base.

The company has proven significant productivity in six different distinct intervals within the Belly River zone. Further, produc-tion results have continued to improve due to DeeThree’s rapidly increasing geotechnical understanding of the Belly River zone and improving drilling and completion techniques. DeeThree has now initiated a resource evaluation over its Brazeau Belly River lands.

The company’s Brazeau drilling inventory continues to increase, and DeeThree now has over 100 horizontal drilling locations in inventory on its Belly River land base as a result of the success of its horizontal drilling program and the well control provided by historical vertical wells.

saskatchewan’s

Bakken is currently

producing around

70,000 barrels per day

up from less than

1,000 barrels per day

a decade ago


Feature

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n the summer of 2012, there was talk that natural gas would be worthless going into the winter heating season, with producers giving the commodity away.

That didn’t pan out. Instead, the price has steadily climbed as a drop in gas-targeted drilling across north America, combined with a colder-than-expected winter in the eastern united States, improved the supply and demand balance. As of May, the Canadian price has climbed to $4.30 per million British thermal units.

Going forward, expect this trend to continue, Andrew Botterill, senior manager of Deloitte LLP’s resource evaluation and advisory practice, says as the firm releases its quarterly Canadian domestic oil and gas forecast.

Botterill says he is “cautiously optimistic” about future prices.

“Although there is less data in the long-term portion of the price forecast, it is still a very good barometer for long-term optimism,” he says.

Withdrawals through this past winter have reduced storage volumes to closer to the five-year average, resulting in a slightly higher near-term natural gas price, Botterill notes.

“With major u.S. markets expected to move toward natural gas for power generation, long-haul trucking and fuel for rail transport, we believe we may see a gradual rise in the natural gas price,” he says. “The establishment of LnG export terminals, now being discussed, would also help to give the currently depressed natural gas price a longer-term boost.”

Deloitte is forecasting an AeCO real price of C$3.35 per thousand cubic feet in 2013, up 15 cents from the company’s last forecast in December. Gas prices are forecast to rise to $3.70 per thousand cubic feet for 2014 and $5.20 per thousand cubic feet in real dollars by 2021.

The forecast nYMeX price is uS$3.65 per thousand cubic feet in 2013, rising to $4 per thousand cubic feet in 2014 and $5.50 by 2021.

Turnaround

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Deloitte’s forecast commentary also includes an adjustment in the pricing ratios for natural gas liquids (nGLs), which Botterill points out are imperative for the economic drilling, development and exploitation of certain north American shale gas plays.

Historically, the price forecast looked at five-year weighted averages, but given the rapid drop in propane prices and a more gradual increase in pentanes plus prices, Deloitte felt a little bit more comfortable going forward using more of the average over the past 12 months, he says.

As a result, Deloitte has decreased its propane price forecast for 2013 and 2014 to 40 per cent of edmonton Par oil from 55 per cent, while forecasting a pentanes plus price 115 per cent that of edmonton Par oil to reflect the increasing oilsands demand for pentanes plus as a diluent. Pentanes plus, in fact, is the only nGL of which Canada imports significant volumes, and it is expected to continue imports because of the strong oilsands demand.

The forecast price of butane remains unchanged at 85 per cent of edmonton Par oil, based on the weighted average of the last five years.

With the continued growth in propane production, companies are beginning to look at ways to increase the market for propane with more export terminals and moving propane in different directions within north America and potentially offshore. Propane also is being studied as a solvent in miscible floods, in the oilsands and in other enhanced recovery methods, Botterill says.

“Some of those projects are a year out, others are two or three years out so we have our forecast lower in the short term then dropping back to more of a five-year average [55 per cent] beyond that.”

Butane price differentials remain virtually unchanged for the forecast period.

According to Botterill, the erosion in propane prices is not due to the fact that there is more propane in the growing nGL volumes from north American shale gas, but to a lack of demand for the product.

“Propane production remains relatively unchanged at 28 per cent of total nGLs in the market; it’s just that pentanes and butanes have found a demand that has grown with those nGLs,” he says.

“In contrast, propane—which is used for heating or as a fuel—hasn’t been able to find a way to increase demand at the same rate as those increased volumes are coming on.” Last winter, for example, there was a low demand, which meant that a lot of it went into storage.

The price differential for butane, though, has been consistent over the past five years, which suggests that growth in both supply and demand has been relatively in sync, he says. Butane is typically used for gasoline blending and can be used in the creation of petrochemicals and solvents.

As for future trends, although the Duvernay resource play is still in its infancy, “it has the potential to be a very desirable target at today’s market prices and could affect the dynamic of pentanes plus imports for years to come,” Botterill predicts.

new York–based ITG Investment Research, in its new report called No More Guessing: Canada, sees Canadian gas production rising as prices improve. ITG estimates that marketable gas production will increase to

“ With major u.S. markets expected to move toward natural gas for power generation, long-haul trucking and fuel for rail transport, we believe we may see a gradual rise in the natural gas price.”

— Andrew Botterill, senior manager of resource evaluation and advisory practice, Deloitte LLP

Gas prices rebound in winter of 2013,

but the question is, what lies ahead?


Turnaround time


Feature

approximately 16 billion cubic feet per day (approximately 19 billion cubic feet per day

of raw gas) by 2025. The ITG forecast is based on a ramp-up in the Montney and the Horn River Basin in response to liquefi ed natural gas (LnG) facility feedstock requirements. In addition, the

study assumes success in the Duvernay with 42 rigs running there by 2016. If the

number of rigs remains fl at at 2012 levels, forecast gas production would decline by approximately

3.2 billion cubic feet per day by 2025, resulting in a slight decline in western Canadian gas production.

Last year, western Canadian gas production fell to 16 billion cubic feet per day from approximately

20 billion cubic feet per day in 2007, as natural gas additions of approximately 300 million cubic feet per day have not

kept pace with a natural decline of between 17 per cent and 20 per cent, the

report notes. In the past six years, monthly gas production additions averaged approximately

300 million cubic feet per day.Of the incremental production, gas from liquids-rich

plays such as the Deep Basin, Duvernay and associated gas accounted for 56 per cent of gas additions at the end of last year and are expected to account for 55 per cent of new production by 2020.

About 36 per cent of gas additions in 2012 came from the top 10 gas producers in western Canada, implying a more diverse set of operators than oily producers, notes ITG.

Assuming success in the Duvernay, nGL production is expected to rise to approximately 420,000 barrels per day, up from approximately 300,000 barrels per day last year.

Although the Duvernay looks encouraging, due to the early stage of development it is not without risk, the ITG study cautions, forecasting only modest growth in gas and nGL production without the Duvernay. Marketable gas volumes would drop by approximately two billon cubic feet per day in 2025 to approximately 14 billion cubic feet per day, while forecast nGL output would drop by approxi-mately 92,000 barrels per day to approximately 328,000 barrels per day. In addition, ITG’s estimate of the half-cycle gas supply cost would increase to approximately $4 per thousand cubic feet nYMeX in 2015.

The Canadian natural Gas Initiative (CnGI) has an even more optimistic long-term outlook.

north America’s newfound abundance of natural gas “could well be accompanied by demand growth far in excess of any other primary energy source,” says a new report by the CnGI.

“By 2035, natural gas could displace coal as the world’s second most important primary energy source,” says the report. It predicts crude oil and refi ned petroleum products will still take top spot.

“This demand growth will mainly be refl ected in power generation, but there are other important growth sectors as well. Worldwide, gas will likely grow in importance as a transportation fuel, especially in heavy-duty road transport (about one-quarter of transport fuel demand in north America) and marine transport (one of the most serious sources of air pollution in and near port cities),” says the 52-page report. IL

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“In north America, there is evidence of what is being called an ‘industrial renaissance’ as low fuel and feedstock prices induce a revival of industries that are heavily energy-dependent or reliant on hydrocarbon feedstocks.”

However, it cautions this scenario is “far from a sure thing.” Opposition to gas production activities, transporta-tion infrastructure and new gas-fired power plants “may well lead to some of these new resources never being developed,” the report says.

A big potential application could be in specific seg-ments of the transportation sector.

“In the transportation market, it is still early days for natural gas vehicles, but there has been a recent rapid development of heavy-duty vehicle pilot tests using LnG trucks in several north American markets. Heavy-duty trucks and buses running on natural gas reduce greenhouse gas emissions by an estimated 15 to 30 per cent compared to diesel trucks and buses,” the report says.

“The opportunity to expand these pilot tests to return-to-base fleets is the next step in the growth of the natural gas vehicle market. And the prospect for longer-term applications in passenger vehicle markets is starting to be discussed. The u.S. Department of energy recently launched a project to develop a low-cost home refuelling unit for natural gas vehicles.”

Looking ahead, the report says the robustness of the supply picture offers an opportunity to look at more and more emerging applications for gas.

In transportation, the immediate opportunities have been identified and are beginning to be pursued; the

“ As natural gas is used in greater volumes as the result of its affordability and attractiveness as a fuel of choice, the fuelling infrastructure necessary to respond to increased demand is expected to evolve over time, making natural gas more widely available as a fuel option.”

— The Canadian natural Gas Initiative

report notes the infrastructure necessary to enable greater use of natural gas is still evolving, as Canada currently has fewer than 100 compressed and LnG fuelling stations across the country, more than half of which are private fleet refuelling stations.

“However, as natural gas is used in greater volumes as the result of its affordability and attractiveness as a fuel of choice, the fuelling infrastructure necessary to respond to increased demand is expected to evolve over time, making natural gas more widely available as a fuel option,” the report says. “In addition, private sector investments in liquefaction facilities to supply liquefied natural gas into the heavy-truck market can also be leveraged to supply fuel for off-road applications such as marine, rail and heavy off-road trucks.”

In power generation, as the challenges around siting large facilities in densely populated areas become even greater, the idea of more decentralized generation through highly efficient and small combined heat and power units is being looked at more closely, the report says.

“In addition, efforts to incorporate new fuels like biomass, or to expand thermal grids—both popular in many jurisdictions—turn in large part on having natural gas as the foundation fuel. And emerging ideas like power to gas, whereby the gas grid becomes the means to turn intermittent renewables into reliable supply, are starting to be tested.”

While these are emerging applications, “the technolo-gies involved are not hypothetical,” the report points out. “The opportunities require investment and innovation, but the possibilities are real—all the more so in the face of affordable natural gas.” IL

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Canadian crude prices are expected to remain volatile for the rest of this decade as production from sanctioned oilsands projects ramps up,

says Volatile Canadian Crude Oil Prices—A Growing

Challenge, a recent report by research fi rm Wood Mackenzie Limited.

And despite new infrastructure, export capacity will remain tight as production from both the oilsands and north Dakota’s Bakken continues to increase, according to the report.

“While temporary pipeline issues have recently eased the sharp decline of Canadian crude prices, we expect prices to remain volatile for the rest of the decade,” Mark Oberstoetter, upstream research analyst for Wood Mackenzie, said. At times, Western Canadian Select (WCS) has traded at as much as uS$40 per barrel below West Texas Intermediate (WTI), although the differential has since narrowed to under $20 per barrel, he said.

The Wood Mackenzie report attributed the continuing price volatility to the fact that certain Canadian oilsands projects remain attractive even with current weak bitumen prices.

“We can get a fi rm grasp on what the pie looks like in the near term, but what’s more the question mark is that capacity needs to grow, and when and how does that

Bitumen bubble will keep prices discounted for a decade,

but production will keep risingBy Daily Oil Bulletin staff

On hold

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FEATURE

grow is really what’s going to drive the price,” Oberstoetter said. “In short, inadequate market access results in a supply glut even under a more depressed bitumen price outlook.”

non-upgraded bitumen production will grow by 540,000 barrels by 2015 and, of this, 72 per cent will be from sanctioned projects that break even below $60 per barrel, according to Wood Mackenzie. Much of the remaining growth comes from the ramp-up of existing projects already in production.

Of the 37 future projects or phases included in Wood Mackenzie’s oilsands outlook, 29 break even at a WTI price of under $60 based on a January 2013 discount date. Most of these projects are already sanctioned and have incurred signifi cant sunk costs.

“What our analysis shows is that point-forward economics for the vast majority of oilsands projects planned to start up between now and 2015 are attract-ive,” said Oberstoetter. “The SAGD [steam assisted gravity drainage] projects typically have better break-evens than their mining project counterparts,” he said. “In particular, the projects we are looking at coming on in the 2014-2015 timeframe actually have quite a bit of sunk costs already spent, so you would get very different results if you were to calculate break-evens on the date of fi rst spend compared to point forward as of today,” Oberstoetter said.

Wood Mackenzie concluded that based on point-forward economics, “these SAGD projects really stack up, so we are not expecting any of those to kind of lose out,” he said.

If the assumed bitumen differential were to widen to 50 per cent from 40 per cent of WTI, Wood Mackenzie said a larger number of projects would become marginal.

“even so, 26 projects would continue to break even at a WTI price below $70 per barrel under this scenario—the majority of growth would still be supported by healthy point-forward economics,” said Oberstoetter.

On the other hand, the break-even points of new unsanctioned projects are not so compelling and many are currently at risk, he suggested. Wood Mackenzie believes that these unsanctioned projects are the most likely to be delayed.

Deloitte LLP’s resource evaluation and advisory practice senior manager Andrew Botterill also expects oil prices to remain fl at.

An oversupply of oil in the united States, continued oil drilling, and a lack of infrastructure and export permits are likely to result in little change in prices over the long term, says Botterill.

“With no signifi cant export solutions on the horizon, we don’t expect to see much long-term change in oil futures

pricing,” Botterill said as the fi rm released its quarterly Canadian domestic oil and gas forecast.

While in the last 12 months long-term WTI futures prices were in the uS$90 to uS$95 per barrel range, they have softened and are now closer to uS$85 per barrel, Botterill said. “So while we are seeing quite robust pricing, there is the thought of where are all these volumes coming from and where are they going to go in the long term.”

There’s also the question of whether demand on the oil side will grow along with these prices, he said.

However, after previously lowering its real forecast for long-term oil prices to $85 per barrel, the Deloitte team has increased its 2013 and 2014 price forecast by $2 per barrel in response to near-term upward price movements. The WTI longer-term outlook, though, remains relatively unchanged at $88 per barrel in real dollars for 2015 and 2016, settling back to $85 per barrel from 2017 through 2021.

In the fi rst quarter of this year, the differential between WTI and edmonton Par oil has been around $7 per barrel due to the Canadian volumes of oil being backed out from the united States market due to pipeline constraints, and Deloitte is forecasting a differential of $5 per barrel for 2013 and 2014. That is expected to return to the historical WTI to edmonton par differential of $2 per barrel in 2015 with further rail transport and major pipeline reconfi gurations and optimizations.

An oversupply of oil in the united States, continued oil drilling, and a lack of infrastructure and export

permits are likely to result in little change in prices

over the long term.

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FEATURE

Wellbore integrity has not always been considered an important topic by many

in oil and gas, but it has been gaining prom-inence lately. Doull Site Assessments Ltd. (DSA) has been assisting customers with issues in this area since 1988.

The Alberta-based wellsite inspection services fi rm provides wellbore integrity detection, sampling and monitoring solutions for oil and gas customers in western Canada at every stage of a well’s life cycle, from new drills, through production, to wells scheduled for abandonment and abandoned wells.

Regarded as an industry leader in gas migration and surface casing vent fl ow testing, monitoring, sampling and analysis, DSA has pioneered new gas migration test methods that improve effi ciency, accuracy and clarity of results for customers.

With new technological advancements and growing public awareness of the potential issues posed by old wells, the industry is now paying more attention to the cost of well abandonments and how to effectively attempt remediation on a well with integrity issues.

“Costs are dictating you do it right the fi rst time,” says DSA President Kerry Doull. “There are a number of cases where wells weren’t abandoned properly. Those have shown up in follow-up testing and/or landowner complaints. They [well licensees] consequently have had to re-enter the well and repair it correctly.” Increasingly, licensees are looking for quality service and reliable data. That has been the company’s, and Kerry’s, focus for years.

Innovation is vital at DSA, which has taken conventional testing methods to a more defi nitive, effi cient and ultimately more cost-effective level. Their methods have changed the standard of what is expected when it comes to gas migration and surface casing testing.

“We focus on putting new ideas into practice before others, and will continue to do that,” Kerry says.

DSA’s Operations Manager Ryan Doull remarks, “Our test method for wellbore integrity testing is more accurate than traditional testing methods. It’s a more effi cient method with a higher level of detail, so they [DSA’s customers] have better information to make their decisions with.”

A family-run business, DSA is headquar-tered in the Lloydminster area. And like a

family, the business has expanded, adding locations in Bonnyville, Red Deer, Airdrie and an offi ce in Calgary. DSA services Alberta, Saskatchewan and B.C. while pushing past their current operational borders.

Kerry isn’t one to tell you unless asked, but his growing company is celebrating its 10th year in business as DSA, and Kerry is not green to the industry. His oilfi eld experience goes back to the 1970s, when he performed seismic work in the Arctic. He also worked as a B-pressure welder into the 1990s while providing wellbore integrity testing services to customers as Doull Soilgas Specialty before DSA’s incorporation in 2003. Over the years, he has refi ned his company’s techniques and methods, to the point where he is consulted by regulatory bodies such as the energy Resources Conservation Board in Alberta and Saskatchewan’s Ministry of energy and Resources, in addition to the customers that DSA regularly assists on best practices for detection, monitoring and sampling.

DSA’s patent-pending gas migration test method was fi rst introduced in 2010, and soon proved effective in identifying signs of gas migration, even in areas where surface contamination, weather and other factors often hamper traditional test methods. When used in combination with DSA’s other tools, procedures and experience, and in collabora-tion with technical partners, their customers receive a concise answer on a wellbore’s gas migration status and a good sense of direction on the source of the issue.

DSA is continually developing new technology to become a more effi cient service provider. An example of this is the VentMeter™, a new tool that is seeing success. It is a remote monitoring unit that provides consistent, calibrated, real-time surface casing data. VentMeter™ helps ensure customers have the data to back their decisions, with a safer and more informed strategic intervention or abandonment process—since obtaining the best data possible ensures that a leak can be stopped in a timely, cost-effective manner, reducing overall remediation costs.

DSA prides itself on providing a high level of customer service. The team members make themselves available whenever customers need their assistance.

“We have a really good staff,” Ryan says of DSA’s fi eld technicians and administrative team. “The things that have helped us grow through the years have been a really

InnOVATInG WeLLBORe InTeGRITY eVALuATIOn

doUll site assessmeNts ltd.

“ We focus on putting new ideas into practice.”— Kerry Doull, DSA President

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Doull is the industry leader in gas migration and surface casing vent fl ow testing, monitoring and analysis.

Doull provides wellbore integrity detection, sampling and monitoring solutions.

SERVICES

· Gas Migration Testing/Monitoring/Sampling

· Surface Casing Testing/Monitoring/Sampling

· Urban Well Testing/Monitoring/Sampling

· Oilsands Wellbore Integrity Testing

· Remote/Northern Access Well Testing

· Wellbore Fluid Level Surveys

· VentMeter™ Services

DOULL SITE ASSESSMENTS LTD.PRESIDENT: Kerry Doull

Toll-Free: 855.500.VenT (8368)

T: 780.847.2567

F: 780.847.3277

E: [email protected]

www.doullsite.com

www.ventmeter.com

conscientious, competent and innovative staff, good customers and relationships, and strong industry alliances with good technical partners.” One of DSA’s main technical partners is Hifi engineering Inc. of Calgary, a co-founder of the VentMeter™. Kerry and Ryan agree that all of those pieces will be fundamental to DSA as it continues to grow both in Canada and abroad.

Ryan adds, “We enjoy the challenges that this sector of the industry presents.”

Kerry is quick to point out the importance of the customer connections and industry associations DSA has cultivated, and how enjoyable it is to see their clients and partners succeed. “We are really fortunate to work with the people we do work for. It’s a good relationship.”


EnTReC Corporation is a leading provider of heavy-haul and heavy-lift services across

western Canada, with service offerings encom-passing heavy-haul transportation, crane ser-vices, and engineering logistics and support.

enTReC serves the oil and gas, construc-tion, petrochemical, mining and power generation industries. enTReC’s extensive fl eet includes 160 cranes, 550 multi-wheeled trailers, 160 tractors and approximately 375 lines of specialized platform trailers.

“We have the fl eet, the scale and the engaged employees to deliver customer service safely,” says President and Chief Operating Offi cer John Stevens. “That scale allows us to execute much larger projects, which is important from a customer perspective.”

enTReC, which holds an enviable competi-tive position in a strong industry, is strategically

located across western Canada and north Dakota, with 11 locations throughout northwestern Alberta, northern B.C., and Dickinson, north Dakota. The company provides complete service coverage over Alberta, northern B.C. and the north Dakota Bakken region, with the ability to haul throughout Saskatchewan and Manitoba as well as from the u.S.

enTReC is further strengthened by its widespread employee ownership. The company believes that success is driven by customer service and engaged employees. That is why enTReC’s management team focuses constantly on both.

“We believe it is a simple model that follows a circular process: a valid business depends on delivering great customer service, and customer service is achieved through engaged employees. Both are supported by safety,” says Stevens, noting that safety is one of enTReC’s core values.

This is truly a people-driven company, with a strong belief in employee ownership and in creating a workplace environment where every employee is involved in the company’s growth.

To this end, enTReC has worked steadily on developing a positive employee culture. The company also provides the right tools—including modern, well-designed and user-friendly equipment—and continues to enhance its training programs to facilitate employee progression.

enTReC believes that business success rests on a powerful but simple foundation: great customer service. Great customer service is a differentiator apparent to every stakeholder—and a clear competitive advantage. Great customer service is a founding principle of enTReC, and one that enTReC looks for in every candidate for acquisition.

What does service mean to the customer? For heavy-haul customers, the no. 1 criterion is delivering the goods to the site on time—even if that’s late on a Sunday night—and doing so safely. Customers of crane services place maximum value on safety, engineering support and the service provider’s responsive-ness to changes in the project’s scope.

Planning every detail ahead of time, and quoting accurately and completely, are important parts of the service package. A

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service provider with the range of equipment and locations to consider several possible haul routes or lifting approaches gains an edge in service effi ciency, work precision and cost-effectiveness. enTReC’s large, varied fl eet provides such an edge.

Customer service is easy to say, but a lot goes into achieving and maintaining excel-lence. The most important factor is having every employee motivated to excel, every hour of every day. Great equipment, modern internal processes and innovative systems all play important supporting roles. But it is the engaged employee who delivers great customer service.

Among enTReC’s continuous improvement initiatives is building an internal culture in which people care and perceive that they are cared about.

The management team believes in this, both as an intrinsic good and as a business principle, because achieving and maintaining great customer service rests on a workforce of engaged employees.

Customer service and safety win and retain customers. engaged employees deliver great service and work safely. This is a simple

model that, once operational, works in a virtuous cycle as one element strengthens and improves the next, and is in turn strengthened and improved.

employees are not only enTReC’s most valuable asset, they are also an essential element of its overall competitive advantage. enTReC offers industry-leading training programs to promote growth and development within the organization.

enTReC works to build and strengthen its culture of engaged employees through:

· employee share ownership, including restricted shares for key employees;

· Competitive compensation;

· Modern, well-maintained, user-friendly equipment;

· Thorough training;

· enTReC’s employee-centred safety program; and

· A fair and effective acquisition process that includes welcoming and integrating the employees of the acquired company, includ-ing recognition for past years of service.“We have the scale, and we have great

employees who deliver excellent customer service safely,” Stevens says.

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ENTREC CORPORATIONEXECUTIVE VICE-PRESIDENT, BUSINESS DEVELOPMENT AND MARKETING: Chris Good

Toll-Free: 1.888.962.1600

www.entrec.com


F lo-Back equipment Rental and Sales is dedicated to building and renting excep-

tional quality equipment, providing outstand-ing service, and maintaining high standards in quality control.

“We put our customers fi rst, with a focus on quick deliveries and operator-friendly packages,” says Flo-Back Vice-President, Mark Brown.

For Flo-Back customers, it all brings peace of mind. “We ensure quality equip-ment that is engineered and built safely,” says Brown’s business partner, Flo-Back President Scott Candler. “The integrity of the rental fleet is our top priority, maintained by an internal Integrity Management System developed by the partners. All equipment is ultrasonically tested after each rental to ensure that minimum wall thicknesses are

maintained, and to ensure the safety of our clients.”

Flo-Back equipment Rental and Sales opened its doors in 2010 in nisku, Alberta, after Brown and Candler saw a need for quality processing and testing equipment, rental and sales in the oil and gas industry. The company quickly grew to 30 units, including test separators, line heaters, fl ow line, wellhead packages and pressurized storage. Currently, Flo-Back has more than 70 units and is building another 25 units at its new fabrication facility in nisku.

Flo-Back FabricationAdded in 2012, Flo-Back’s fabrication division is an ABSA-certifi ed facility. In 2013, Flo-Back will be adding ASMe section VIII Div. I to its capabilities. equipment recently fabricated and packaged includes

testing and wellhead separators, line heaters, fl are stacks, fl ow line and fl are line, as well as inlet and group separators.

With 14 years of equipment design, fabrication and rental management experience, company co-founder Mark Brown looks after the design and build process, from concept to rollout. Working with clients one-on-one allows him to ensure the client’s specific operational needs are at the forefront of each design. Custom projects, such as the twin-fired 4MMBTu trailered line heaters, showcase the firm’s ability to think outside the box and design equipment for today’s completions. Flo-Back’s newly designed 6”x 60’ flare stack with two 3” auxiliaries is another example of great design. Flo-Back is capable of designing and building your largest testing

Flo-BaCk eQUipmeNt reNtal aNd sales

High-quality processing and testing equipment drives Flo-Back’s rapid growthC

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FLO-BACK EQUIPMENT RENTAL AND SALESVICE-PRESIDENT: Mark Brown

T: 780.955.3561

E: profi ler@fl o-back.com

www.� o-back.com

packages, while placing great value on customer service.

“We have an oilfi eld equipment engineer-ing background and our own design capabilities, so we can handle it all from start to fi nish, from the concept design to fi nished product, all under one roof,” Brown says.

Flo-Back Rental and Fabrication: Your Short- and Long-Term Equipment SolutionBy leveraging Flo-Back’s rental fl eet of more than 70 units while you build, you can get into production immediately, while Flo-Back builds to your specifi c needs. Flo-Back’s rental units are sized to be used in as wide a variety of situations as possible, so they will suit many different scenarios. While the fl eet unit might be oversized for your needs, it will do the job while Flo-Back builds to your exact specifi ca-tions. This allows the client to get into

production and cash fl ow sooner. As an added bonus, purchase credits earned in this scenario can be used against the purchase price of the new piece of equipment.

Whether you need additional equipment for a specifi c job, or you want production equipment fabricated to your exact specifi cations, Flo-Back is your short- and long-term equipment solution.

Currently located in nisku, Alberta, Flo-Back plans to open additional locations in the next 18 months in Grande Prairie, Alberta; southern Saskatchewan; and north Dakota.

“We have an extremely aggressive growth plan that will see us grow to several hundred units in the next three years,” Candler says.

Whether you are renting or purchasing, you can be assured that Flo-Back equipment will be of exceptional quality. Your work-force’s safety is their number one priority.

“ We have an extremely aggressive growth plan that will see us grow to several hundred units in the next three years.”

— Scott Calder, Flo-Back President


W ith its new Brutally Tough™ tanks, you could say Gem Steel edmonton Ltd. is

thinking inside the box. The Alberta fabricator’s recently launched rectangular, aboveground steel tanks can store up to 100,000 litres of fuel, water, recovered waste or other liquids.

Brutally Tough™ (tested and certifi ed to uLC-601-07) tanks are poised to challenge round, horizontal containers that, until now, have pretty much been standard issue when it came to small-to-mid-sized tanks used in various resource locations. Gem Steel Owner and President Brad Gemmer is confi dent that

the Brutally Tough™ tanks will live up to their name from an integrity standpoint, as well as when it comes to ease of handling, transpor-tation and durability, particularly when used in harsh and remote surroundings.

In business for 30 years, Gem Steel has long specialized in building large, permanent fi eld-erected storage tanks at many resource development sites. Its huge tanks—100,000-barrel (20,000,000-litre) and larger—form a signifi cant part of the northern resource landscape from Alaska to Baffi n Island and are associated with all of the major mine

names such as echo Bay - Lupin, Diavik, ekati and Snap Lake.

While travelling in the north, Gemmer became aware of the widespread use of smaller, horizontal liquid-containment tanks. even though his company also built a few of these cylindrical tanks, the steel-fabrication veteran felt that, for the most part, such vessels had many shortcomings and especially lacked robustness. Generally, the tanks were not well suited for harsh environ-ments, such as remote exploration camps, or the need for frequent relocations.

Gem steel edmoNtoN ltd.Gem Steel’s Brutally Tough™ tanks show the shape of things to come in safe and sound storage of liquids

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At a given site, the round, horizontal tanks commonly had temporary and semi-permanent uses. It was not unusual for such tanks to be moved. Whether coming or going, in the north, cranes were seldom available and that would pose a challenge to the move. Improvised, ragtag lifting alternatives—dozers, forklifts, loaders—often were pressed into action, which would often take a toll on the tanks.

Furthermore, the rounded, horizontal tanks needed to rest on a secure base—preferably a concrete slab. Since concrete is not usually available, the bases at remote sites were often improvised, and seldom adequate. In addition, the bases, which were usually constructed in the winter, changed when they began to thaw, so that the formerly supported tank no longer had proper support.

“I saw a real defi ciency in what was available as no one was making tanks with the rigour to be moved multiple times and positioned on less than ideal support,” Gemmer explains. Gradually, he moved toward squaring the circle, including developing the special equipment to corrugate large, heavy-steel sheets.

The fi rst version of the Brutally Tough™ tank, which has a patent pending, rolled out from Gem Steel’s southeast edmonton fabrication yard in March. Besides its rectangular shape, what sets the Brutally Tough™ tanks apart from their cylindrical competition are their 1/4” corrugated-steel walls.

Corrugation not only gives Brutally Tough™ added strength but means less weight and a better weight-to-capacity ratio than its

competition. The 70,000-litre special order, Hercules-transportable version of the Brutally Tough™ tank weighs 19 tons. The reduced weight and the rectangular shape suit the 70,000-litre version for shipment on Hercules aircraft.

The shape also facilitates hauling by truck. In fact, Brutally Tough™ tanks, although much stronger, look very much like intermodal shipping containers transported by sea and rail, or hauled by semi-trailer truck. Brutally Tough™ tanks’ rigid design will not bend or twist while transported or lifted, and is of similar strength to a railroad bridge.

With its fl at bottom, Brutally Tough™ tank needs no fancy base preparation, just fl at, level ground. Positioning the tank isn’t that different from placing a container on the ground.

“Moving a rectangle is a breeze, position-ing it is a breeze and handling [it] can easily be done by virtually any piece of equipment available,” says Gemmer.

Brutally Tough™ tanks are available in sizes starting at 10x10 feet, 20,000-litre and up to the largest, 10x50 feet (with 100,000-litre capacity). Single-wall and contained (double-walled) versions of the uLC-S601-07 certifi ed tanks are available. The double tank offers added reliability against leakage, an especially important feature legislated in most locations in Canada.

The rectangular confi guration facilitates access via two man-ways on the fl at top, which makes it easier to inspect the interior for corrosion or to apply coatings and linings. The

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GEM STEEL EDMONTON LTD.PRESIDENT: Brad Gemmer

T: 780.449.000


9060 - 24 St. n.W. edmonton, AB T6P 1X8

www.gemsteel.com

fl at surface also provides an effective platform for valves, gauges and dispensing systems, which can be installed or serviced without the need for special fall-arrest devices.

Gemmer takes satisfaction in having “produced a pretty tough tank that will relieve users of worries about just about every aspect of managing storage of fuel and other liquids.”

“ Moving a rectangle is a breeze, positioning it is a breeze and handling [it] can easily be done by virtually any piece of equipment available.”

— Brad Gemmer, Gem Steel Owner and President


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NCS OILFIELD SERVICES CANADA INC.19,909 sleeves installed

2,952 wells completed

44,804 frac stages placed

50 stages completed in a single trip

1,503 sandouts circulated out without tripping

18,250 ft. (5,563m) longest TMD treated

SALES MANAGER: Lyle Laun

T: 403.969.6474


www.ncsfrac.com

A s operators wrestle with greatly expanded capital requirements and

operational challenges, while facing the concerns of stakeholder groups, public opin-ion, and political wrangling at almost every level of government, it can be diffi cult for the industry to stay focused on what mat-ters most: the safe, effective, and effi cient recovery of energy resources. It is to this mission that nCS Oilfi eld Services has dedi-cated itself, and it is making a difference by offering the oil and gas industry unique and reliable tools to allow optimal resource exploitation, rather than a one-method-fi ts-all approach. nCS offers a choice of completion tools and techniques, borne from a concern for what is most appropriate for the reser-voir, the wellbore, and the environment.

Since its inception, nCS has performed thousands of frac treatments in wells that incorporated a cemented casing string. That style of completion offers producers wellbore integrity assurance, and facilitates the pinpoint placement of hydraulic fractures to optimize reserves recovery. But all formations are not the same. In formations where an open-hole completion is most appropriate, nCS now combines its Multistage unlimited™ Frac Sleeves with open-hole packers. While offering similar speed and effi ciencies as ball drop systems, the use of a CTu-deployed BHA provides defi nitive information regarding the effectiveness of the open-hole packers in containing each individual wellbore interval. This information can be invaluable in benchmarking well performance, and in understanding what portions of the reservoir might not be adequately stimu-lated. Priceless information, without any additional costs—all collected during normal wellsite operations, with no extra equipment, and no wasted time. And—as with all nCS systems to date—the wellbore is left full drift, with no balls, plugs or seats to drill up or to restrict production.

nCS continues to develop and market new technologies that bring its customers added value. The nCS Airlock™ system, which facilitates the running of long horizontal completions, is a great example of how increased reliability can be used to reduce

both risk and total well costs. Similarly, as a refi nement of the nCS Multistage unlimited system, the nCS Half-Straddle method provides operators with signifi cant time and fl uid savings. The company will also unveil a new line of frac sleeves in 2013 with enhanced features, increased pressure and torque ratings, and a closable port option to provide long-term production assurance. Additional BHA refi nements will soon be introduced to further reduce completion costs, while maintaining the reliability and performance the Mongoose™ BHA has come to be known for.

“It’s a unique way of doing multistage fracs that nobody else has matched for speed or reliability,” says nCS Marketing Services Manager Don Francis.

nCS completions technology combines the advantages of coiled tubing and proprietary tool designs to provide greater access to the pay zone, at lower costs than any other multistage completion method. This gives customers a powerful set of advantages not available with any other system, including the ability to monitor real-time pressure at the frac zone, better fl uid management, quick recovery from screen outs, and no drill out required.

nCS technical staff provide expert support to customers, who can design completions that suit the reservoir, and not the limitations of the completion assembly.

“It’s really the technical leadership in multistage fracturing, which compares very favourably with other alternative methods,” Francis says.

Beaumont—a private e&P company developing assets in southwest Saskatchewan, using horizontal well and multistage completion technology—deployed nCS’s Frac Sleeve and Multistage Frac Isolation equipment in its Q1-2013 Drilling/Completion program, “with overwhelming operational success. The evolution of nCS’s multistage tool technology and the specifi c improvements made to its bottom hole assembly have made nCS a leading service provider in this space,” says Beaumont Manager, Drilling & Completions, Justin Crawford. “The system provides industry with a simple and mechanically sound frac

delivery tool, with minimal operational risk.” nCS has proven to be a progressive company that continues to evolve its multistage completion technology to satisfy industry’s ongoing quest for improved rate of return, through the capital-effi cient develop-ment of its assets, Crawford says.

Curtis Swain is a Completions Superintendent at a Calgary-based oil and gas producer that has been using nCS’s Multistage unlimited™ technology for the past two years.

“The main benefi t we have seen from using nCS is that our completion times have decreased by close to 40 per cent, resulting in less fresh water being used and reduced completion costs,” Swain says. “We used to pump 900 m3 of fresh water, and now we are down to pumping around 400 m3, which is great for trying to reduce our environmental footprint. In addition, nCS has been able to meet all of our needs by adding new technology on a regular basis. I love sitting down with these guys and discussing new strategies for completions or refracs.... They never seem to stay happy with the latest technique because they lead the market.”

NCs oilField serViCes CaNada iNC.The dawning of the oil and gas industry’s new Age is reshaping the future of the world’s energy supply

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Fracceleration!

Plug-and-perf and ball-actuated sleeves are brute force frac methods that bullhead fluids and sand down the casing with no feedback about formation response, no recourse in the event of a screen-out, and no way to manage water and chemicals usage. Both methods limit the number of stages and usually require post-completion drill-out of composite plugs or ball seats. The Multistage Unlimited system overcomes those limitations and drawbacks using coiled tubing as a work string and circulation path to the frac zone.

Fast frac isolation, mechanical sleeve shiftThe work string operates the Multistage Unlimited resettable frac plug, a dual-function tool that 1) isolates frac zones and 2) grips and shifts the sleeves. With no pump-down plugs and sleeve-shifting balls, time between fracs is only about 5 minutes. Large-volume, high-rate fracs are pumped down

the coiled tubing/casing annulus; smaller, low-rate fracs can be pumped through the coiled tubing.

Circulation path adds capabilitiesThe circulation capability allows operators to:• monitor actual frac-zone pressure for better control of sand

placement • reduce water and chemicals requirements up to 50%• recover quickly from screenouts by circulating excess sand

out of the well• use sand-jet perforating to add stages in blank casing,

without tripping out of the holeIt all adds up to unlimited stages and spacing, streamlined frac operations, better frac control, lower-cost completions, less environmental impact, and no drillouts. Call, email, or visit our website for more information.

Resettable frac isolation on coiled tubing + Grip/ShiftTM sleeves

ncsfrac.com

Canada: 403.969.6474

US: 281.453.2222

[email protected]

The unique resettable frac plug grips and shifts the sliding sleeve and isolates the frac zone.

Frac ports

©2012, NCS Energy Services, Inc. All rights reserved. Multistage Unlimited, Grip/Shift and “Leave nothing behind.”are trademarks of NCS Energy Services, Inc. Patents pending.

Fast FaCts

PENTA COMPLETIONS SUPPLY & SERVICES LTD.


www.pentarods.com

Penta Completions Supply & Services spe-cializes in sucker rod–pumping diffi cult oil

wells, providing complete rod pumping optimi-zation, design and services to companies in western Canada and around the world.

Founded in 1987, the edmonton-based fi rm had the good fortune from its very beginning to work with rod pumping design and analysis pioneers Dr. Sam Gibbs and Mr. Ken nolan.

Originally focused on fi breglass sucker rods, Penta has since expanded into a complete rod pumping optimization and services organization as directional and horizontal drilling have increased well-design complexity. “We’ve earned an international reputation for helping producers design and install anything from a conventional pumping confi guration, to a highly specialized rod string,” says Penta Completions president Tom Dennehy.

Penta provides analysis and optimization recommendations from fl uid level and dynamometer testing, along with a full line of steel and fi breglass sucker rods, sinker bars, and related accessories. Its services also include long-term monitoring and optimization through cellular-accessed pump-off control-lers. Penta specialists will supervise installs to ensure optimal performance and life cycles in rod-pumped oil wells.

“What we bring to the table is rod pumping expertise,” says Penta contract engineer Fred Morrow. “The things that we do will increase the life of the downhole pump, limit pumping

unit repairs, and increase the average time to failure from months to years. We’ve gone in and optimized rod pumping to where the mean time to failure has been increased by magnitudes. We’ve got wells where we’ve run three to four years with no rod or tubing failures. Twenty minutes of conversation before the well is drilled can literally save hundreds of thousands of dollars in mainten-ance, years down the road. By designing the wellbore path with production concerns taken into consideration, changes in the wellbore path can increase a well’s economic life by many years.”

Says Bob Wanner, who handles business development for Penta: “We like to be involved with the oil company from the conception of their drilling plan through to the actual completion and follow-up monitoring. We’ve been lucky enough to have a close relationship with our clients that allows us to stay in contact after the well is put on production to monitor how actual pumping conditions compare to the design.”

Kerry Olsen, Laska energy president and Lakeview energy vice president operations, has turned to Penta Completions for more than 20 years for well optimization on pumping installations. Penta’s “prompt service, technical expertise, pumping equipment, and attention to detail have been an invaluable asset to the companies I have been associated with,” says Olsen, who seeks Penta’s assistance to ensure he achieves minimum operating costs along with maximum production. “The commitment that Penta’s representative Bob Wanner and his staff have provided to obtain maximum economically obtainable production rates is exemplary.”

Don Finley, Baccalieu energy vice president operations, has also worked with Wanner and Penta Completions for more than 20 years. “I have always found their knowledge, reliability, accuracy, and level of service to be top-notch,” says Finley, who thinks that Penta’s longevity is a direct refl ection of the quality of its work and service. Penta “proposes real‐world installations that let me optimize equipment design and capital costs over the life of the well.”

These are just some of the reasons that Penta Completions is fl ourishing. In addition to doing work across western Canada, Penta has expanded internationally, serving customers in China, the u.K., new Zealand, and France.

“Over the last couple of years, we’ve been getting calls from all over the world looking for the services we provide,” says Penta Completions sales manager Jeff Wanner. “A lot of the easy oil is gone, and you’re seeing the rest of world now having to go after their challenging production. Canada in general, and Penta in particular, has been focusing on that challenging production since day one.”

Penta’s longstanding expertise in well automation and effi cient power usage has opened many doors. For instance, at the invitation of SaskPower, Penta is participating in an industrial energy optimization program focused on optimizing power usage in the Saskatchewan oilfi eld, and is working as a liaison between the power provider and the province’s energy industry. “Similar to the international requests we’ve been seeing, it’s another side of Penta’s business that has been a focus for the company’s entire history,” Jeff Wanner says.

A commitment to providing better service and always going a step further is at the heart of what Penta is all about. “There is a little more time and effort involved with every well we work on. It’s paying attention to the little details. It’s staying true to our beliefs. It’s putting the right product into the right application, and designing the right system to optimize the long-term production of the well.”

peNta CompletioNs sUpply & serViCes ltd.

Prompt service, technical expertise, pumping equipment and attention to detail set Penta Completions apart

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Edmonton

9543 - 56 AvenueEdmonton, AlbertaT6E 0B2Phone: (780) 436-6644Fax: (780) 435-4565E-Mail: [email protected]

Calgary

610, 910 - 7 Ave SWCalgary, AlbertaT2P 3N8Phone: (403) 262-1688Fax: (403) 234-0108E-Mail: [email protected]

EstEvan

P.O. Box 667Estevan, SaskatchewanS4A 2A6Phone: (306) 634-7399Fax: (306) 634-6989E-Mail: [email protected]

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P iston Well Services Inc. of Red Deer, Alberta, has introduced to the market a new

high-pressure snubbing unit that sets a higher standard of technology for western Canada.

A fully guided tube rig, Piston’s hydraulic workover snubbing Rig 9 is the fi rst of its kind in Canada, offering unusually effective service production rates for this size of iron. Fully capable of 10K snubbing (10,000 psi surface pressure), Rig 9 was developed in association with a major operator, and it has recently passed a full year of safe and effective high-pressure service.

Piston, which owns Rig 9, was responsible for the rig package design, full project management, and commissioning. The company developed this unit to drill long-reach horizontal wells fractured with propane. The stringent design and specifi cation process included extensive critical service and environmental evaluations, full engineer-ing certifi cation, and the inclusion of many of the latest concepts and components available to the snubbing industry. The unit also includes several of Piston’s signature design features, which increase snubbing production rates.

This self-contained drilling tool is expand-able for outfi tting for routine full-pressure 20K snubbing work and can handle the extra size and length of larger tie-back strings. Compatible with the requirements of the international marketplace, Rig 9 is currently outfi tted as a true 10K snubbing rig, with ample margins for safety and upgrading. It has been sized and outfi tted to work in western Canada in wells rich in light oil and condensate. This rig is big iron, but its footprint is small, with pad-friendly rig-up and no soil disturbance. Rig 9 includes a guided tube structure, counterbalanced winch elevating system with built-in tubing handling mast, two-stage hydraulic ram system, proprietary valving, powerful dual rotary drilling motors, and a redundant BOP stack. The result is a piece of state-of-the-art equipment with impressive service and safety margins, and the production rates of any 5K rigless snubbing unit.

Guided tube snubbing rigs support the tubing string within telescoping spools for the full 12-foot stroke. The rig can always safely

pistoN well serViCes iNC.

new snubbing technology for horizontal wells

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Fast FaCts

PISTOn WeLL SeRVICeS InC.MARKETING MANAGER: Bob Babcock

T: 403.309.4429

C: 403.519.6401

F: 403.309.4349

Toll-Free: 1.877.309.4429


www.pistonwell.com

take a full 12-foot stroke from the fi rst joint to the last stroke. This design feature and a compatible BOP stack allow future rigs to be delivered and outfi tted to any standard required by an operator, from 10K to 20K pressure capacities.

This safety feature allows for a routine 10K or greater pressure snubbing service that

complements the safety and loss manage-ment strategies of today’s operators. This is the next evolution in hydraulic workover equipment for Canadian fi elds such as the Duvernay, Montney, and Horn River, and is a natural response to the increasing effective-ness of horizontal fracturing technology. As these fi elds are brought into production, this technology will grow with the fi eld require-ments of the future. It will also meet any expected specifi cations or legislation yet to be introduced. This design assures fi eld managers and forecasters that snubbing equipment already exists to match their future requirements.

Rig 9 uses Piston’s unique self-contained 60-foot gin pole for crane-free snubbing

services, eliminating crowding at the wellhead. Together with Piston’s signature tubing-handling system using counter-balanced winches, the rig handles a wide selection of production strings, including large-diameter tie-back strings—assuring a level of completions and drilling service production rates that compete favourably with coiled tubing service.

This technology was originally designed by Piston through service experience gained on 32 high-pressure well pads in Colorado (four-by-eight grids with multi-service activity at all times).

Piston’s rig uses a dual-staged hydraulic ram structure. The two-leg stage allows 12-foot stroke high-service production rates, while the four-leg stage delivers the strength for high-pressure snubbing service. The push force is rated at 170,000 pounds, while pull force is rated at 285,000 pounds. The balanced dual hydraulic motor rotary drive is capable of 140 rpm and 6,600 ft./lbs. of torque. The proprietary custom hydraulic valving creates a true big iron snubbing unit with compact unit smoothness and produc-tion capabilities. The state-of-the-art BOP stack is Cameron manufactured—not an offshore BOP clone—and includes the necessary work fl oors for rapid tooling changes and a sensible amount of redun-dancy. The standard design is outfi tted with a shear ram and an extra lower pipe ram to mitigate potential problems with washouts.

An important benefi t of this design is the effectiveness of its drilling functions—the result is that only a single major service provider is needed for completions. The self-contained drilling capability is included in the rig, with no added rig-up charges or time allowances required. Thanks to the snubbing rig’s self-contained dual hydraulic-driven rotary system, there is no need for coil drilling service, top drives, or mud motors.

Piston’s snubbing rig is an excellent choice in tooling and equipment for all servicing in long-reach horizontal work. The ability to combine strong push-and-pull efforts while rotating work strings with authority makes heel-to-toe removal of multi-interval porting or bridge plugs very effective. This rig solves any concerns about getting stuck in the horizontal

wellbore, fi shing parted tubing, or low push-force authority to the toe. The strong manipulation in both axes of tubing move-ment combined with a tough work string results in faster, more cost-effective operations. Tried and true drilling methods and rig pump cleaning eliminate expensive repeat sweep-back trips while drilling with coil—a major cost savings offered by snubbing completions.

Piston is an active, innovative snubbing contractor with a long history of creating unique designs. Its fl eet capacity starts at a 1.5K rig assist that fi ts any single rig, 5K hydraulic workover rigs, and a full-capacity 10K rig. Piston’s comprehensive QHSe department is constantly developing loss-management strategies, and its management team prides itself on delivering complex fi eld-specifi c projects on time.

Piston’s Rig 9 is available today, and the company is now considering a second spec unit. Please contact Piston for details on using Rig 9 for fi eld evaluation, general servicing, or for assistance in solving your unique needs with Piston’s outstanding new snubbing technology.


The ultimate goal of Victory Pressure Services (VPS) is to protect lives, while focusing on

oil spill and blowout prevention. At VPS, we pro-vide our services to ensure these goals are met.

VPS is a safety-oriented pressure testing and pumping company. We utilize highly trained and experienced staff and manage-ment to provide the best service to our customers. We operate out of north and central Alberta as well as northwestern Saskatchewan. Since opening our doors, we have experienced a lot of growth and have expanded our business to accommodate our customers. Our goals for the future aim to continue this responsible and accountable growth, and to grow relationships with more customers and communities.

VPS offers a variety of services, including B.O.P., pipeline, frac string, facility pressure testing and formation integrity testing, as well as downhole tool and packer setting and low-rate cement squeezes. These services are performed by our highly trained staff, who are backed up by a management team with over 50 years of experience in the oilfi eld. Many of the services we provide are intended to facilitate a safe work environ-ment and to ensure the protection of our nation’s natural resources.

Pressure testing of B.O.P.s is an example of one of these services. By making sure the accumulator within a B.O.P. functions properly and that the valves close and hold while under pressure, we ensure that if a blowout does occur, the B.O.P. system will be able to control it and seal the well.

Another service we provide to ensure the safety of not only employees, but also communities, is pipeline and facility pressure testing. If a pipeline ruptures it

can cause a lot of damage to the environ-ment and cost a lot in environmental reclamation after the accident. By ensuring the integrity of pipelines—either in a facility such as a water treatment plant, or on large national pipeline systems—through the regular testing of these systems, the possibility of having these accidents is greatly reduced.

VPS is headquartered in edmonton, Alberta, offering services in the regions of Fort McMurray, Grande Prairie, Lac La Biche, Slave Lake, Whitecourt, and now Cold Lake, Lloydminster, and Peace River. We listen to our customers and accommodate their needs. If a customer requires something for our job, we can quickly adjust our equipment from one of our mechanical or machining departments operating out of edmonton and Grande Prairie. If the customer requires services outside of one of our main regions, we provide services out of the nearest competitor’s location.

Also helping us to provide better service are our new high-rate, high-pressure units, which can pump as fast as 700 litres a minute at pressures of up to 70,000 kPa. These units are very well suited for high volume pipeline pressure testing or setting downhole tools. Backed up by our fl eet of ten 5,000lb lightweight four-wheel drive units with digital displays, we can go anywhere to put the pressure on for you.

We are growing in leaps and bounds at VPS, keeping things tight and accountable along the way. This means we are making sure that all our operators are trained well, and that our equipment is in good repair and ready for when your call comes in.

Since VPS was established one year ago, we have opened a shop and offi ce in Grande Prairie, opened our mechanical and machin-ing departments, and increased our fl eet size by two 5,000lb units and two high-rate, high-pressure units.

In the coming year, VPS will continue focusing on the safety and satisfaction of our customers. In order to serve them better, we will be opening another shop and offi ce in Slave Lake, and developing a data center to provide easier access for our customers to view job information.

ViCtory pressUre serViCes

Victory Pressure Services is putting the pressure on

Fast FaCts

VICTORY PRESSURE SERVICEST: 780.298.TeST (8378)

Toll-Free: 1.855.955.TeST (8378)


www.victorypressure.com

Address: 12029 - 106 St.

edmonton, Alberta T5G 2R5

Locations: edmonton, Fort McMurray, Grande Prairie, Lac La Biche, Slave Lake, Whitecourt, Cold Lake, Lloydminster, and Peace River, Alberta.

CEO: Craig Crawford

T: 780.803.8882


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Profiler June 2013