Profiler April 2011

APRIL 2011

BRITISH COLUMBIA ISSUE

Horn River Basin

Montney

Kitimat LNG

b.c.

northeast

Producers are develoPing standardized, rePeatable Procedures to efficiently harvest trillions of cubic feet from b.c.’s montney and horn river basin Plays

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Producers are developing standardized, repeatable procedures to efficiently harvest trillions of cubic feet from British Columbia’s Montney and Horn River Basin plays

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GAS FactorIes F Factor actor Producers are develoPing standardized, rePeatable Procedures to efficiently harvest trillions of cubic feet from british columbia’s montney and horn river basin Plays

By Mike Byfield est Texas Intermediate crude currently trades near $100 per barrel while natural gas fetches about US$25 per barrel of oil equivalent, assuming a gas price of $4 per thousand cubic feet (mcf). This degree of disparity between the two fuels is unprecedented in modern times, and today’s low gas prices show little sign of ending. As producers switch their drilling to liquid targets, Alberta’s shallow gas and coalbed methane developments have shrunk drastically. In northeastern British Columbia, however, the Horn River Basin and Montney gas plays continue to move strongly forward.

“We know that gas prices are creating at least a short-term challenge to producers and we appreciate the fact that most companies continue to take a long-term approach to the region,” says Steve Thomson, minister of natural resource operations. (The KelownaMission MLA was also energy minister until a cabinet shuffle in March.) Thomson credits several factors for his province’s ability to continue drawing billions of investment dollars into natural gas:

• A mammoth unconventional gas resource trapped in shale and tight rock • Revolutionary technological innovation and strict operating discipline • Stable, long-term strategies from both the B.C. government and producers • A well-timed $4-billion project to export liquefied natural gas (LNG) into Asian markets, where prices hovered above US$10 per mcf last year.

B.C.’s conventional gas resource (methane trapped in reservoir rocks with good porosity and permeability) is estimated at 91 trillion cubic feet (tcf), which includes 19.2 tcf of recoverable reserves. Over the past decade, those figures have been dwarfed by the province’s mushrooming unconventional gas resource potential. The B.C. Energy Ministry estimates shale gas in place at 1,000 tcf, tight gas in place at 300 tcf and coalbed methane in place at 100 tcf.

“Our total production last year was 1.1 tcf, the second highest among Canadian provinces [after Alberta],” notes Christopher

Adams, an oil and gas specialist with B.C. Energy’s geosciences and natural gas development branch.

The Canadian Society for Unconventional Gas (CSUG) estimates that the Horn River Basin, a Devonian-age shale formation north of Fort Nelson, B.C., has 500 tcf of gas in place. To the east sits the less-explored Cordova Embayment, whose gas in place is pegged tentatively at 200 tcf. At an even earlier stage of development but highly prospective is the Liard Basin, lying west of the Horn River Basin. Further south sprawls the B.C. portion of the Triassic-age Montney formation (shale plus fine-grained siltstones and sandstones), with gas in place estimated at 450 tcf across 3.8 million acres.

MONTNEY FORMATION Montney producers can reportedly earn attractive returns at the current gas price of $4 per mcf. Crown land sales in the play peaked in 2008 at $1.32 billion. “Montney development has proceeded more quickly

PHOTO: APACHE CANADA

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PHOTOS: (LEFT) APACHE CANADA. (RIGHT) CHRISTINA RyAN, INEz PHOTOGRAPHy

than the northern prospects because the area around Dawson Creek, Fort St. John and Chetwynd is more accessible by road. A lot of infrastructure [processing plants and pipelines] was already in place due to earlier conventional gas development,” says CSUG president Mike Dawson. In addition, Montney drillers can hunt for more porous “sweet spots” and liquids-rich gas while Horn River gas is dry. (Gas liquids sells at prices comparable to crude oil.)

The Montney play was pioneered by ARC Resources Ltd. in 2003. The Calgary-based producer’s 2010 capital program included $283 million in Montney spending. ARC (which converted from a royalty trust in January) recently reported total proved plus probable reserves of 1.4 tcf equivalent (gas plus liquids), up by a dramatic 68 per cent in just 12 months. An independent evaluation estimated conservatively that its recoverable reserves in the Montney are at least 2 tcf equivalent. Gas in place is pegged at more than 10 tcf.

ARC’s 2011 capital budget calls for spending of $98 million at Dawson including the drilling of one step-out vertical well along with the drilling of 13 horizontal wells and completion of its Phase 2 gas plant. In the West Montney district, which includes Sunrise, Septimus and Sundown, $25 million is scheduled for investment this year in drilling two horizontal wells and related work.

In August 2010, ARC added the Parkland field to its Montney portfolio with the $652-million acquisition of Storm Exploration

Inc., another early champion in the play. In 2011, the company plans to spend $67 million on drilling 11 horizontal wells, two vertical delineation wells, and additional compression aimed at increasing liquids production. Also in 2011, ARC plans to drill four vertical wells and two horizontal wells in 2011 at Attachie, currently a non-productive area northwest of the Dawson field. At Ante Creek, $55 million is allocated to drill 14 horizontal and two vertical wells, plus $30 million to build a 30 million cubic feet (mmcf) per day gas plant.

Encana Corporation has been the most active contender in the Montney, establishing 70 tcf of gas in place on the trend. In February, PetroChina Company Limited (through an international subsidiary) agreed to pay $5.4 billion for a 50 per cent interest in Encana’s Cutbank Ridge assets. These lands—about 635,000 net acres straddling the B.C. and Alberta boundary—include most of Encana’s Montney properties.

As of 2010, PetroChina was the world’s most valuable publicly traded corporation and the first ever to reach a market capitalization of $1 trillion. The firm’s half-share of the Cutbank Ridge joint venture represents proved reserves of about 1 tcf equivalent with current production of about 255 mmcf equivalent per day. The planned joint-venture infrastructure, on a 100 per cent basis, includes about 700 mmcf per day of processing capacity, about 3,400 kilometres of pipelines and the Hythe natural gas storage facility.

Mark Taylor, Encana’s Horn River team lead, says tight spacing is key to the resource hub concept.

After Encana, Shell Canada Limited has drilled the most wells in the B.C. Montney (see chart on page 11). Shell established its position in the play through Crown land sales and a $5.9-billion takeover of Duvernay Oil Corp. in 2008. It currently holds 243,000 hectares of prime prospects in the fairway with an estimated gas in place of 8 tcf. Although the company declined to comment on this winter’s program, it drilled more than 30 wells during 2009-10 in the Sunset and Groundbirch areas, with depths of 2,200-3,000 metres.

In late 2009, Shell’s production totalled 100 mmcf per day from Sunset-Groundbirch. “We think we could approach [500 mmcf per day at Groundbirch] by 2014,” Philippe Gauthier, Shell’s manager of onshore Canadian exploration, told a B.C. gas conference last year. “As with any unconventional gas project, the pace of production growth will be related to drilling capital. We’ve drilled so far about three per cent of the wells that we think we’ll need to develop that asset, and only one per cent of the volumes have been produced.”

The Montney play has not yet been fully delineated. Exploration is trending to the west and north where the formation gets shalier. At Farrell Creek, for example, Talisman Energy Inc. drilled 21 wells in 2010. In Greater Cypress and Greater Groundbirch, the company continued its piloting program, drilling 16 wells. In December, Talisman agreed to sell a 50 per cent interest in its Farrell Creek project to South Africa’s Sasol Limited for about $1 billion, including $250 million cash and a commitment to fund future capital in the amount of $800 million.

Last September, Pengrowth Energy Corporation (another former trust) jumped into the Montney with the acquisition of Monterey Exploration Ltd. through a $366-million share swap. “The key area is Groundbirch for us,” Pengrowth’s Montney vice-president Diane Shirra told the Daily Oil Bulletin. “We’re in a key part of the Groundbirch area. We’re west of some of the bigger players...but we think we’re in a key part of the reservoir.” Pengrowth’s first Montney gas facility came on stream in December, adding 4,800 barrels of oil equivalent to its production. With five wells tied in, Pengrowth says its Groundbirch inventory includes 212 additional potential drilling locations.

B.C. Energy reports that Montney production has reached 918 mmcf per day in 2010, up by nearly 100 per cent from 472 mmcf per

Liard Basin

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Cordova Embayment Horn River Basin

Fort Nelson

Montney 97 Play Region 29

Alberta

British Columbia

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Fort St. John

Hudson’s Hope

49 Dawson Creek

50 KM

B.C.’s Montney formation came on stream before the Horn River Basin, North America’s most remote commercial gas source.

day in 2009. The increase is all the more welcome since exploration activity is almost stagnant in the province’s traditional conventional fields while producers in the Horn River Basin are only now emerging from what Adams calls the “advanced experiment” stage.

HORN RIVER BASIN The crucial technologies for developing shale gas reservoirs have been long-reach horizontal drilling coupled to multistage hydraulic fracturing that enables gas to flow through otherwise impermeable rock. Also critical is drilling multiple wellbores from a single pad. Mark Taylor, Encana’s Horn River development team lead, comments, “Geographically, we’re further from major markets than any other shale gas development in North America. We can only make the play work through continuous reductions in costs. To achieve that goal, we’ve integrated our technologies into a single conceptual model that we call the resource play hub.”

Taylor, a mechanical engineer (University of Saskatchewan, 1986), has worked with an

“assembly-line” approach to field operations since similar tools to multiple-stage fracs first appeared in Alberta’s coalbed methane and shallow gas plays. “We were drilling 1,000 wells per year back then. Always we looked for easily repeatable procedures that could be standardized across the program,” he says. “Measurement is essential to management. A standard operating model enables you to track your results precisely.

That way, you can accurately assess the cost benefits achieved by incremental improvements to your technologies and procedures.”

Encana learned to punch vertical shallow wells into the Prairies within eight hours, then shift a rig rapidly to the next wellsite. To exploit multiple seams in a coalbed, techniques were created to quickly perform a sequence of nitrogen stimulations up a vertical wellbore.

Then geosteering tools were created, enabling drillers to accurately navigate horizontally along a thin limestone layer or coal seam, following its undulations when necessary. Next came efficient technologies for creating sequential fracs along a horizontal wellbore.

“Improved efficiencies can be achieved through longer wellbores, more fracs per wellbore and more wells per drill pad,” Taylor explains. Encana now drills 16 wellbores from one pad, each with a horizontal reach as long as 3,000 metres.

The company plans to perform as many as 30 fracs per wellbore. Assuming each frac is equivalent to a single vertical well into the formation, a single pad can host production equivalent to 480 vertical wells. Not bad for a patch of terrain measuring 250 by 300 metres.

Horn River fracs rank among the world’s largest, conducted far from supplies of virtually every kind. The remote location—very close to the Northwest Territories—intensifies the importance of topflight logistics and operational skills in controlling cost. Encana is at the forefront of employing high-performance, skid-mounted, fit-for-purpose drilling rigs, conducting 24/7 hydraulic fracturing operations, leveraging economies of scale with bulk deliveries of sand and steel casing, and developing specialized technical staff for its “gas manufacturing” process.

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PHOTO: ENvIRONMENTAL REFUELLING SySTEMS INC.

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Completion operations in the Horn River Basin—this is a Nexen Inc. wellsite at Dilly Creek—rank among the world’s largest.

Encana is partnered with Apache Canada Ltd. in a portion of its Horn River Basin, pooling more than 400,000 acres.

Financially, all proceeds are shared equally in the joint venture. Instead of electing one operator, however, Encana and Apache both operate their own projects, setting up a highly unusual competition. To date, the producers have been leapfrogging each other’s results on successive pads. “Our 63-K pad this summer did better than their 70-K pad last winter, but they may beat us again this spring,” Taylor says. “Kevin Screen, my counterpart at Apache, and I agree that the rivalry between our teams

actually provides our project with a unique advantage.”

For its 70-K well pad, Apache Canada set up for overlapping fracturing, coiled tubing and wireline operations on its 16 wellbores. Ideally, all of the wells should be ready to frac at all times, thus minimizing the need for crews to sit idle. “We had to have customized wellhead equipment, wellhead enclosures, a robust frac manifold, et cetera, around the wellheads,” says Karl DeMong, Apache Canada’s completions and well services manager. “What that meant was that we spent a fair amount of time with our suppliers designing and building particular types of equipment for this.”

Apache’s innovative manifold system enabled it to double block and bleed among its tightly spaced wellheads (which sit 10 feet apart, which alone is an industry-leading achievement). “We had the ability to close two valves and bleed off in between, so that you could be sure you wouldn’t be exposed to an unplanned pressure event. So our average—the average amount of wells that were being worked on at a given time—was probably two and a half, and it was often three or four,” DeMong says. “[Including deployment of microseismic geophones], the maximum amount of wells that we were doing operations downhole on would have been six.

PROFILER 9

And later in the program, we had tied some of the wells to flow back while we were continually working on the balance of them.”

Drilling multiple wells from one pad allows Apache and Encana to work at a steady pace (i.e. no frenzied activity peaks), improve its safety record, and reduce environmental disturbance. “We moved a rig onto our Two Island Lake site in October 2008 and haven’t missed a drilling day since then. Apache’s done that as well,” Taylor reports. “The one activity with the highest potential for a serious incident facing workers in the oilpatch is driving, and we’ve minimized the need to drive. When drilling, it’s rigging up and down.

We’ll drill as many as 48,000 metres of horizontal length in the shale on a pad without laying down the derrick once.”

Drilling multiple wells from one pad drastically reduces surface disturbance due to fewer drill sites and gathering lines. That reduction pleases First Nations whose members hunt and trap in the area. The smaller footprint’s benefits are self-evident for landowner relations in more densely populated areas like central Alberta. However, intense hydraulic fracturing does require large volumes of water. For instance, Apache pumped 500 million litres of water for its 70-K pad completions. Even in freshwater-rich British Columbia, that level of consumption triggered concerns.

In response, Apache and Encana have tapped into the Debolt reservoir. This aquifer, which lies 500-1,100 metres below the surface, holds saline water with total dissolved solids content ranging from 15,000-40,000 milligrams per litre, and a hydrogen sulphide concentration of 65 milligrams per litre. The water is unfit for most common uses. However, the formation is well-suited for supplying water for fracturing operations and for disposal of spent fracturing fluids or produced water. In two years, the partners developed an integrated water treatment and distribution system that allows for the full recovery and reuse of fracture stimulation fluids.

Last June, the Debolt Water Plant went into operation. The facility, the first of its kind, functions as a closed system, with water being reinjected into the deep aquifer for future reuse. The water is naturally warm (35 degrees Celsius), which reduces energy consumption. Its hydrogen sulphide scavenging method does not require heat treatment, eliminating venting and flaring while further enhancing energy efficiency.

This year, the plant is expected to produce over 90 per cent of the water required for hydraulic fracturing in the play.

As a measure of the industry’s progress in human terms, Taylor compares the Horn River operation to his earlier drilling experience in the Jean Marie formation, a gas-bearing limestone that’s also north of Fort Nelson.

“The drilling season back then was about three months. To get the work done within that window, we had to move in 20 rigs every year. Half of the crews had never drilled a

Jean Marie well before,” the Encana team leader says. “Level-loaded drilling on a year-round basis at Horn River means that our people become a lot more efficient. The lifestyle is also more attractive. We provide high-quality camps—gyms, movies, Internet and great food. Our Calgary-based managers actually like to spend time up there.”

Technical innovation and skilled deployment have enabled Encana to slash its average cost per individual frac to less than $450,000. That figure is 60 per cent lower than its initial performance during 2008 in the Horn River Basin. “We’ll continue to see double-digit improvements in our cost per frac,” Taylor predicts. “Given a gas price of $4 [per mcf], we can continue to develop this basin. Our financial return here should be comparable to our company’s shale gas plays in the U.S., an important factor since we have to compete internally for development capital.”

Encana’s senior management thinks its resource hub concept remains in its infancy, with major advances still in the works.

Among those concepts is a ported casing system that would enable fraccing without the need to install segment-isolating plugs along the wellbore. The casing ports would be operated via electric or hydraulic controls. If successful, this new completion tool could eliminate the need to drill out 28 or more plugs per wellbore in the Horn River Basin. Taylor comments, “We’ve got a dozen technological concepts like that in mind to reduce costs further.”

EOG Resources Inc. is also reporting encouraging results from its Horn River properties, where its shale gas resource is estimated at 9 tcf. The company holds 157,500 acres in the play. Mark Papa, EOG’s chairman and chief executive officer, told analysts in February that the Houstonheadquartered producer recently completed several wells that had been drilled the previous winter. One well tested with a peak rate of 22 mmcf per day and flowed at a rate of over 18 mmcf per day for 15 days, Papa said, adding that it appears to be EOG’s best well to date, with estimated reserves of 17 billion cubic feet.

Even so, EOG has announced that it will minimize its investment in the region this year in favour of directing more capital toward oil and liquids targets elsewhere. The Horn River Basin Producers Group consists of 11

10 PROFILER

SOURCE: CANADIAN SOCIETy FOR UNCONvENTIONAL GAS

Original Gas in Place Estimates for Shale Gas Regions in British Columbia (tcf)

B.C. Doig 120

B.C. Montney 450 Tight Gas/Shale Gas Play

Horn River Basin 500

Cordova Embayment 200

companies: Apache, ConocoPhillips, Devon Energy Corporation, Encana, EOG, Imperial Oil Limited, Nexen Inc., Pengrowth, Quicksilver Resources Inc., Stone Mountain Resources Ltd. and Suncor Energy Inc. “Some producers appear to be slowing down their activity due to low gas prices, others are not. Although we’re not in a position to forecast spending for 2011, activity levels remain healthy,” says B.C. Energy’s Adams.

It’s difficult to report precise production figures for Horn River, Adams says, in part because some wells still qualify for confidentiality status. “A year ago, we were looking at 70-80 mmcf per day,” the oil and gas specialist reports. “The total is definitely now above 100 mmcf per day, and a reasonable estimate would be 150-160 mmcf. As development continues and the basin generates more provincial royalties, this play will become important to all British Columbians.”

FUTURE PROSPECTS British Columbia’s other shale plays remain in the experimental stage, according to the energy ministry. Penn West Petroleum Ltd., Nexen and Canadian Natural Resources Limited are probing the Cordova Embayment. In August, Mitsubishi Corporation and Penn West announced a 50/50 joint venture to develop Cordova shale and conventional gas in the Wildboy area.

Under the deal, the Japanese industrial giant is committing to spend $850 million on lands contributed to the partnership by Penn West.

So far, the company has drilled five Cordova wells, more than any other operator. Jason Fleury, Penn West’s manager of investor

relations, says one of those wells has been on stream since March 2009, the other since March of 2010. Production from the individual wells isn’t being disclosed, but Fleury says the two wells have combined production of between 4 mmcf and 5 mmcf per day.

The Liard Basin and Fold Belt saw land sale bonuses of $110.4 million at British Columbia’s Crown land auction in June. In the Sandy and Patry areas, where Apache has drilled, 14 licences were sold. In the northern Liard, Transeuro Energy Corp. is evaluating conventional and shale formations, with three wells on production but no drilling in 2010.

Adams says the Muskwa horizon is the main shale gas target in both the Horn River and Liard basins but sits deeper in the Liard, likely around 2,000 or 3,000 metres. “Horn River more or less started the same way where you initially saw some pretty hefty land sales,” Adams suggests.

“Once producers get the technology down in the Horn River [Basin], it can shift over to the Liard. It’s hard to say whether it’s two years off or five years off. It could be within that time frame that we see more development.”

“There are a lot of greenfield opportunities in British Columbia,” comments Dawson.

B.C. Energy credits 9.5 tcf of resource potential in the Nechako Basin west of Prince George and 6.5 tcf further north in the Bowser Basin. Shell holds Bowser acreage but appears inactive there at this point. Coalbed methane resource potential is pegged at about 90 tcf province-wide, including 60 tcf in northeastern B.C.’s Peace River coal deposits.

“None of B.C.’s greenfield prospects are likely to be developed any time soon, given the abundance of shale gas across North America,” the CSUG president says.

“Continental natural gas supply has reached the point where it should be considered a foundational fuel. Industry and government need to dramatically expand its consumption by motor vehicles and other large-scale applications, replacing crude oil and coal where appropriate.”

While virtually everyone involved accepts the enormous resource potential in shale deposits, a continental debate continues over how much

gas will be actually emerge from the ground at affordable prices. Due to very different geology among shale reservoirs, recovery rates may vary widely. The more pessimistic analysts suggest 10 per cent may be a reasonable average. B.C. Energy, on the other hand, currently projects 20-40 per cent recovery of gas in place for the Montney formation, and perhaps 20 per cent from the Horn River Basin.

Taylor is more optimistic, forecasting a recovery rate in the range of 35-40 per cent for Encana’s Horn River Basin reservoirs. “As we accumulate more production history, our independent evaluators have consistently raised their recoverable reserve estimates for this play,” says the team lead. “With more drilling, we’ll make progress in determining how many wellbores and fracs are optimal for recovering the most gas at the lowest economic cost.”

KITIMAT LNG PROJECT While North American gas prices wallow, strong international demand has spurred higher prices for LNG. Its primary uses are electric power generation and petrochemical feedstock.

Apache and EOG would like to pipe Horn River Basin shale gas to the West Coast at Bish Cove near Kitimat. There, the gas would be cooled, liquefied and loaded onto tankers.

Kitimat LNG, a partnership 51 per cent owned by Apache and 49 per cent by EOG, would construct a $3-billion liquefaction plant. Initial LNG processing capacity would be five million tonnes per year, scheduled for start-up in 2015. A further $1 billion would be needed for pipeline capacity linking the new plant to Spectra Energy’s West Coast gas transmission system. The operation would process 468 billion cubic feet of gas per year.

Kitimat offers an ice-free deepwater harbour in an industrialized location, with no dredging or breakwater required. The Canadian port sits closer to Asia Pacific markets than rival gas producers in the Middle East. Kitimat LNG says tanker movements in and out of the port would total five to seven per month. Until now, Canada has never exported LNG. The National Energy Board has scheduled a hearing for July 7 to review Kitimat LNG’s application for a 20-year export licence.

Kitimat LNG will be conducting front-end engineering and design (FEED) this year. Once it’s completed, Apache and EOG will make a final investment decision whether to proceed with the project. Main construction is

PROFILER 11

expected to start in early 2012, with commercial operations projected to begin in 2015. The FEED study will also explore the feasibility and timing of constructing a second LNG train (also five million tonnes per year) at the Kitimat plant.

The proposed location recently received overwhelming support in a Haisla First Nation vote. The Indian Reserve No. 6 on Bish Cove has been legally designated as an industrial park by the federal government.

Kitimat LNG has agreed to provide the Haisla community with economic growth,

Top 35 Montney Operators Since 2003 (Montney and Doig Targets)

training opportunities, employment, and community and social benefits.

ENERGY SERVICES BC Oil and gas service firms based in northeastern British Columbia are having a good business year, according to Energy Services BC (ESBC). “Some people are busier than others, but overall it’s going well for most,” says Laurie Dolan, the trade association’s executive director for Fort Nelson. Art Jarvis, the ESBC’s southern area manager, reports similar conditions in Fort St. John and Dawson Creek.

Wells Rig Released

Encana Corp.

352

Shell Canada Ltd.

235

ARC Resources Ltd.

212

Murphy Oil Company Ltd.

123

Progress Energy Ltd.

121

Terra Energy Corp.

67

Canadian Natural Resources Ltd.

67

Talisman Energy Inc.

62

ConocoPhillips Canada Resources Corp.

62

Baytex Energy Ltd.

31

SOURCE: BC OIL & GAS COMMISSION

Crew Energy Inc.

29

Devon Canada Corp.

23

Suncor Energy Inc.

22

BP Canada Energy Company

22

Tourmaline Oil Corp.

20

Huron Energy Corp.

18

Painted Pony Petroleum Ltd.

17

Penn West Petroleum Ltd.

16

Pengrowth Corp.

14

Altia Energy Ltd.

12

Crescent Point Energy Ltd.

12

Great Plains Exploration Inc.

11

Canbriam Energy Ltd.

11

Bonavista Petroleum Ltd.

10

Northpoint Energy Ltd.

8

Aduro Resources Ltd.

7

Crocotta Energy Inc.

7

Paramount Resources Ltd.

7

Trident Exploration Corp.

7

Artek Exploration Ltd.

6

Enermark Inc.

6

UGR Blair Creek Ltd.

5

Chinook Energy Inc.

5

Husky Oil Operations Ltd.

5

Hudson’s Hope Gas Ltd.

5

ESBC has worked with the Horn River Basin Producers Group to maximize use of local suppliers and workers. “In principle, the companies agree with that goal. They know that it’s more affordable in the long run to build up a powerful local workforce and service capability, and the same policies generate community support for the industry. However, implementing those good intentions remains a challenge.

Despite some definite improvements over the past couple of years, we still have a ways to go,” Dolan says.

The lifelong northern resident is encouraged by Horn River producers locating an increasing number of managers in Fort Nelson. “Some of these executives are from Calgary, others come directly from the States with the accents to prove it.

Their being here makes it much easier for our members to network and identify contract opportunities,” Dolan comments.

“Also, those managers can advise local companies on what’s coming down the road and help them make informed decisions concerning expansion and new equipment.”

ESBC acknowledges that northeastern B.C. companies often lack the resources to handle major projects as prime contractors.

“For instance, Encana has hired Ledcor for the gas plant that’s now under construction at Cabin [Gas Plant] and that’s fine with us,” Dolan says. “Unfortunately, the primes have tended to bring in outside subcontractors even when local companies could readily do the work. In February, we had a good meeting about this problem with the producers group. In future, we hope to see prime contractors respect the community buy-and-hire policies that have been adopted by the producers themselves.”

The Horn River Basin Producers Group has agreed to transfer management of the annual Energy Expo to ESBC. “Last year, the show had 72 booths, and I think we could have sold 200,” Dolan says. “Next fall, we’ll hold the event in Fort Nelson’s new recreation centre, which is a much larger facility. The Horn River Basin is getting known around the world. This week, our office was contacted by a fuel company based in Dubai, and that’s not unusual. We welcome everyone—but please locate here, hire here, pay taxes here, be a real neighbour.”

Departure Energ

DEPARTURE 12 PROFILER

DEPARTURE ENERGY SERVICES

The Most Directional Drilling Experience, the Best Technology, and the Best Operational Advice

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ompanies drilling in today’s complex shale plays like the Montney want the ver y best in operational advice and technologies to meet their directional drilling ser vice requirements.

That’s why big intermediates and others operating in the Montney have been turning to Depar ture Energ y Ser vices Inc. for their directional drilling ser vice needs. “Over the last three years, we’ve provided directional drilling on more than 150 wells,” says Brian (Angus) Gregor, president of Depar ture.

the first horizontal wells in the Persian (aka Arabian) Gulf, an MWD operations manager who developed the first wireless EMWD sur face system, and a COO who helped develop magnetic guidance tools and shor t- radius re - entr y systems.

It’s a team that can draw from 200-plus years of directional drilling experience and is led by a CEO whose pioneering work resulted in 37 U.S. and Canadian patents.

Departure’s combination of an engineering approach to problem-solving, experience, the best and latest technologies, and

that work closely with each other—and clients—to provide consulting and operational services, without the layers of management and specialists sometimes associated with bigger service companies.

“Integration of services typically means better value for the client,” says Bond.

Clients also benefit from Departure’s innovative, proprietary downhole tools and proactive engineering approach.

For example, its newly introduced mud motors have been designed and built to accommodate today’s higher-output power sections.

No other directional drilling company offers the collection of experience and skill that Departure has been fortunate to secure.

Depar ture’s suite of proprietar y downhole tools is geared to remove the guesswork from directional drilling program planning and execution.

Cer tainly, as long-reach horizontal wells assume an increasingly impor tant role in shale gas and other plays, the challenges are not going away. “That’s why we do a lot of wells where our clients have encountered some difficulty. The kind of analysis and solutions we are able to provide involves specialized engineering capability,” says Larr y Comeau, chairman and CEO at Depar ture.

Depar ture’s engineered approach to well design means that it takes into account actual conditions, like the litholog y of the Western Canadian Sedimentar y Basin (WCSB), and ensures that it can accommodate future well inter vention criteria. “We do torque and drag design, and modif y design for pump placements. We design for the whole life cycle of the well,” says Bruce Bond, Depar ture’s sales and marketing manager.

Depar ture’s clients benefit from a tightly integrated team of specialists

Departure’s G-force vertical drilling system has been proven to reduce overall drilling time by as much as 30 per cent for many operators. That’s another reason a growing number of operators in the WCSB, including ARC Resources, Trident Energy, and others in the Montney, have turned to Departure for directional drilling services.

It’s technology like this that enabled a Departure driller to drill a “pacesetter” well in record time in the Montney last fall.

FAST FACTS

“As a result of growing demand from large intermediates, Departure has increased its job capability by about 30 per cent,” says Dan Robson, Departure’s director of strategic development.

The firm recently completed an expansion of its Leduc assembly, maintenance, and repair facility. It has boosted staf f levels and expanded its operations management team. This has included the hiring of another two experienced directional drilling coordinators, Bill Dmy triw and Dar yl Tremblay. Each has more than 15 years of directional drilling experience.

Depar ture has also added an electro magnetic measurement while drilling (EMWD) tool to its suite of specialized and proprietar y downhole equipment.

“This improves the depth capacity of wells we can drill. It’s being used in the Cardium. The technology has been used ver y successfully in the U.S. with depths to 12,200 feet,” says Gregor.

The core of Depar ture’s streng th is an experienced 10 -person management team that includes directional drilling specialists who have been drilling horizontal wells since 1985 and drilled

COMPANY NAME: Departure Energy Services

PRESIDENT/FOUNDER: Brian (Angus) Gregor

T: 877.233.3940 E: inquiry@departureenergy.ca WEBSITE: www.departureenergy.com

Energy Services

You’ll profit from our experience – from start to finish – throughout the life of Your well this is the point of Departure

contact us today to start writing your chapter. calgarY sales office :

877.233.3940 toll free, 403.266.3940 local | www.departureenergy.com

leDuc operations:

780.980.3900

Macquarie Capita

MAcquA MAcqu Arie 14 PROFILER

MACQUARIE CAPITAL ADVISORS

The leading advisor to the oil and gas industry worldwide

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clients in negotiations through intimate knowledge of recent and relevant data points.

Macquarie has advised on over C$3.3 billion in shale gas mergers, acquisitions and divestitures processes and has raised approximately C$600 million through the public capital markets for shale-focused producers since 2007.

Clients who can benefit from Macquarie’s services include oil and gas companies and oilfield service firms. With a comprehensive global and Canadian equities platform, Macquarie is the ninth-largest equities research house in the world, covering in excess of 200 oil and gas stocks and approximately 2,400 stocks globally and has a Canadian retail distribution platform through Macquarie Private Wealth.

“Complementing our advisory franchise, Macquarie’s fixed income, currencies and commodities (FICC) group has a similarly leading presence in North America, particularly in oil and gas marketing and hedging. Macquarie is the No. 4 marketer of natural gas in North America and the No. 1 non-producer marketer of natural gas,” Mr. vetters added.

Macquarie Capital is part of Macquarie Group Limited (ASX:MQG; ADR:MQBKy), a global provider of banking, financial, advisory, investment and funds management services.

Founded in 1969, Macquarie has approximately 15,400 employees operating in 28 countries around the world. At September 30, 2010, Macquarie had US$324 billion of assets under management.

FAST FACTS

s one of the largest resources-focused financial institutions in the world, Macquarie Capital provides the full spectrum of corporate advisory and capital markets services, including mergers and acquisitions (M&A), acquisitions and divestitures (A&D), equity and debt capital solutions, and capital management and structuring advice. With an active and growing presence in North America for over a decade, Macquarie has significant local and global resources dedicated to the oil and gas industry worldwide.

Macquarie Capital’s specialization along sector lines enables a deep understanding of client businesses and the issues and challenges they face. Natural resources (comprising oil and gas, and metals and mining) is one of six core industries that Macquarie focuses on. Over the past four years, Macquarie has expanded its oil and gas banking platform both organically and through strategic acquisition. The acquisitions of Orion Securities in 2007 and Tristone Capital in 2009 provided Macquarie with industry-leading capabilities in the oil and gas sector, particularly in equity finance, M&A and A&D. Macquarie’s A&D team is comprised of approximately 40 technical professionals— engineers, geologists, geophysicists and petroleum economists—located in Calgary, Houston, London and Buenos Aires. This specialized group provides a true subsurface understanding of client assets.

In Canada, Macquarie Capital has had significant transactional volume across assets in the Western Canada Sedimentary Basin, with

approximately 100 M&A transactions worth more than $35 billion in the last three years. year-to-date in 2011, Macquarie Capital is ranked No. 1 in Canada for lead mandates and is recognized as having superior market intelligence to the financeability of domestic and international projects.

“Macquarie’s leading market share in transactions provides us with added insight and more detailed current information regarding the valuation of oil and gas assets,” said David vetters, Macquarie Capital’s Head of Canadian Oil & Gas. Macquarie Capital’s oil and gas professionals are located in 28 cities around the world, providing truly global access and client coverage in key energy hubs.

“We are No. 1 in Canada with respect to oil and gas equity capital markets, and have world class expertise with respect to our mergers, acquisitions and divestitures product. We are a leading participant, with the ability to provide full capital market solutions to clients across their capital structures,” Mr. vetters added.

Macquarie’s Calgary team of 26 professionals is headed by Mr. vetters. As a key location in the energy sector, Macquarie’s Global Head of Oil & Gas, Dan Cristall, is also based in Calgary, demonstrating the importance of—and Macquarie’s commitment to—the Canadian market.

Over the last few years, there has been a tremendous evolution in shale gas in northeastern B.C., ranging from exploration and development to production and joint ventures with international entities, furthering the development of these world-class assets in a low gas price environment. Investor demand remains significant, particularly where there is a strong associated liquids component produced with the gas.

“The only real hurdle to the development of these assets is the availability of capital and the low current and near-term forecasted natural gas prices in North America,” Mr. vetters said.

Macquarie has a depth of experience advising on shale gas transactions involving northeastern B.C. unconventional gas, and this experience uniquely positions Macquarie to evaluate valuation and expertly represent its

COMPANY NAME: Macquarie Capital Advisors

WEBSITE: www.macquarie.com/ca

KEY CONTACTS: Dan Cristall Head of Global Oil & Gas T: 403.218.6660 E: dan.cristall@macquarie.com David vetters Head of Canadian Oil & Gas

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M t A t h d

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T: 403.539.8524 E: david.vetters@macquarie.com

Macqua of Macq Canada

e Capital Advisors

Deep expertise, proven experience

A proven track record of delivering for energy clients Macquarie Group has been an active participant in the North American energy sector for over a decade.

And with one of the largest dedicated oil and gas teams of any global financial institution, Macquarie has the global reach and depth of resources to deliver results.

From comprehensive advisory and capital markets capabilities to specialized A&D expertise, Macquarie offers a full spectrum of services to energy sector clients. Talk to Macquarie to find out how we can put our resources to work in helping you make the most of yours.

www.macquarie.com/ca

Macquarie Capital Markets Canada Ltd. is not an authorised deposit-taking institution for the purposes of the Banking Act 1959 (Commonwealth of Australia) and its obligations do not represent deposits or other liabilities of Macquarie Bank Limited ABN 46 008 583 542 (MBL). MBL does not guarantee or otherwise provide assurance in respect of the obligations of Macquarie Capital Markets Canada Ltd. Macquarie Capital Markets Canada Ltd. is a member of IIROC and CIPF. Š 2011 Macquarie Group

Nexen In

NEXEN 16 PROFILER

NEXEN

Responsible Shale Gas Development

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want to do is find a partnership that will help enhance development of this asset over the next 40 years—which is the timeframe you’ve got to think about given how much gas has been discovered up there.”

Nexen invested more than $450 million in 2010 advancing its shale gas strategies in northeastern B.C. This investment included land acquisitions and advancing operations at the company’s Horn River location. The company drilled an eight-well pad with an average of 18 fracs per well and completed these wells at an industry-leading pace of 3.5 fracs per day with a 100% success rate. Nexen is currently completing a nine-well pad drilling program and planning an 18-well pad that would begin drilling in the second half of 2011.

Testing and drilling at Nexen’s Horn River properties has confirmed a promising reservoir and allowed the company to steadily drive down production costs. Nexen currently expects to make a 10% return with gas prices as low as US$4.00 to US$4.50/Mcf NyMEX. This success has given Nexen confidence to pursue shale gas development elsewhere, including Colombia.

In addition to low production costs, British Columbia’s shale gas developers enjoy several competitive advantages. The operations are ideally located to supply gas to power Alberta’s rapidly expanding oil sands industry. It’s also one of the few shale gas plays in North America where a liquefied natural gas export link is a viable option. yet another advantage has to do with land tenure. With minimal drilling, Nexen has secured tenure on the majority of its Horn River lands for 10 years. With tenure secured, the company is able to control the pace of field development during periods of low gas prices.

“Shale gas complements our corporate oil and gas portfolio, which includes a number of long-cycle, capital-intensive projects,” says Romanow. “It provides us with natural gas exposure and relatively short-cycle projects where we can match the pace of drilling to forecasted economic conditions.”

Romanow stresses that as Nexen’s shale gas production expands, the company will maintain the highest standards of safety, environmental stewardship and community

engagement. One key vehicle is the Horn River Basin Producers Group, comprised of Nexen and 10 other companies working in the area.

Founded in 2007, the Producers Group companies work together to mitigate environmental impacts and identify economic and social benefits for local residents. For example, area operators are sharing roadways and other infrastructure to reduce land disturbance. At the same time, they are stepping up efforts to use local labour and services.

The companies are also working to keep the lines of communication open with First Nations and other stakeholders to ensure community concerns are clearly understood and resolved in a timely fashion.

“We recognize that responsible development is how we earn our licence to operate,” says Romanow. “And we plan to be operating in the shale gas fields of northeast British Columbia for many years to come.”

FAST FACTS

y exploring and developing in some of the world’s richest oil and gas basins, Calgary-based Nexen Inc. has become an energy leader with a global reach that encompasses parts of Europe, the Middle East, offshore West Africa and North and South America. In addition to significant interests in conventional oil and gas and Canada’s oil sands, Nexen is quickly becoming a key player in what is a game-changer for the global natural gas industry—namely shale gas.

Nexen has accumulated more than 300,000 acres of high-quality, low-cost shale gas lands in northeast British Columbia—one of the most prospective gas fields in North America. “Even though this industry is still in its infancy, shale gas could represent as much as 20% of Nexen’s production and cash flow in as little as five years’ time,” said Marvin Romanow, Nexen’s President and Chief Executive Officer.

Shale gas is natural gas trapped in small spaces of shale rock formations. The resource’s vast potential has been known for some time, but accessing it proved challenging. New horizontal drilling and fracturing technologies changed all that.

Horizontal wells allow for more contact with the reservoir; by injecting high-pressure water and sand, it’s then possible to fracture the rock, creating pathways for the gas to flow.

Nexen began operating in the Horn River Basin, near Fort Nelson, B.C., in 2007. The company more than doubled its land holdings in the area in 2010 by acquiring additional acreage in the Cordova field, to the east of Horn River, and a new position in the Liard Basin, to the west of Horn River. The Horn River and Cordova lands contain between 4 trillion and 15 trillion cubic feet of recoverable contingent resource, while the Liard lands contain between 5 trillion and 23 trillion cubic feet of prospective resource (all resource estimates determined by a third party).

While Nexen has a 100% operating interest in all of the properties, it recently hired the Bank of America to seek out proposals for a joint venture partner interested in acquiring a working interest in Nexen’s Horn River and Cordova lands. This would enable Nexen, which plans to remain the operator, to accelerate development. Observes Romanow: “What we

COMPANY NAME: Nexen

PRESIDENT:

A O

R

Marvin Romanow

T: 403.699.4000 F: 403.699.5800 WEBSITE: www.nexeninc.com

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Nexen Th

exen Inc

Nexen shale gas rig at Horn River, BC

ALL FORMS OF ENERGY Responsibly Developed.

By exploring and developing some of the most globally significant oil and gas basins, Nexen Inc. delivers energy to the world. For Nexen, all kinds of energy are key to our success. Our resource base – conventional oil and gas, oil sands and shale gas – is as diverse as our geographic reach – Canada, the North Sea, the Middle East, the Gulf of Mexico and West Africa.

We’re proud of our reputation for responsible energy development and have received national and international awards recognizing our high standards in community leadership, social responsibility, environmental management and safety.

That’s Nexen’s way.

www.nexeninc.com

Nexen The Profiler s13662.indd 1

3/9/2011 9:55:06 AM

Northwes 18 PROFILER

NORTHWESTEL N ORTHWESTEL Connecting Northerners with the world for more than 60 years

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leading telecommunications and telephone provider in northern Canada, Northwestel has played a huge role in transforming communications in the North by offering innovative technologies and ensuring that its customers are as connected as possible.

With its operations headquarters in yellowknife and corporate headquarters in Whitehorse, Northwestel is a communications and entertainment leader that delivers a broad range of telecommunications solutions and television services to a population of 120,000 northern Canadians in 96 communities throughout the yukon, Northwest Territories, Nunavut, northern British Columbia and northern Alberta. All of the company’s approximately 550 employees live and work in communities across the North.

“We are the professionals at remote communication solutions. When it’s 40 or 50 below in the Horn River Basin, you want a network that continues to work, and we deliver,” says Mark Rollefson, Northwestel Account Executive B.C.

WATERWAyS COMMUNICATIONS LIMITED PARTNERSHIP Waterways Communications is the result of a new partnership between Northwestel and

CORPORATE DATA AND INTERNET SOLUTIONS Northwestel can provide connectivity outside of its operating area to southern locations or even cross-border. For instance, the company provides corporate data and Internet solutions from remote sites in the Horn River Basin to offices in downtown Calgary or Houston, Texas. “We connect you completely, from north to south,” Rollefson says.

“Our solutions are the most reliable communications solutions out there. When you’ve got hundreds or thousands of people working remotely, having a communications link that is reliable is extremely important.”

REMOTE LOCATION SERvICE The installation of the Ootla tower last year, in the centre of the Horn River Basin, allows Northwestel to offer services to customers within a 70-kilometer range of the tower (further with multiple hop radios). This is a significant infrastructure investment that will greatly enhance service for customers.

Northwestel also offers microwave transport and fibre transport in outlying areas of the Horn River Basin, “which means there is no location in the Horn River Basin we cannot reach,” Rollefson says.

“Northwestel has millions of dollars’ worth of infrastructure that can be leveraged to provide service to customers in extremely remote locations along the Liard Highway toward the NWT and south all the way down the Alaska Highway.”

Much of the company’s infrastructure is so remote that Northwestel uses multiple diesel generators to keep services running on its network. “It’s good for customers, who can utilize our network and don’t have to build it themselves,” Rollefson says, noting that Northwestel is always upgrading its services and providing new services. “We are one of the most progressive telecommunications companies in Canada when it comes to our customers being able to access the Internet and other services.”

COMMITTED TO THE COMMUNITy Northwestel demonstrates its commitment to the community on an ongoing basis, and in the past two years has invested more than $50,000 into the Fort Nelson community, including: Fort Nelson Minor Hockey, Fort Nelson First Nations Petitot Gathering, Fort Nelson Aboriginal Day, Fort Nelson Seniors’ Bus, Fort Nelson Trade Show, Fort Nelson Library and Fort Nelson Hospital.

FAST FACTS

FIRST IN THE NORTH The company that eventually became Northwestel was a major contributor to early telecommunications milestones in the North. In 1947, the federal government contracted Canadian National Telegraphs (CNT) to operate the telephone network installed during the construction of the Alaska Highway. In the following decades, CNT brought new or improved local and long-distance telephone service to a much larger area, including the Northwest Territories and northern B.C. Northwestel was incorporated in 1979, after CNT became a wholly owned subsidiary of Canadian National (CN). Northwestel’s tradition of excellence resulted in its sale to Bell Canada Enterprises (BCE) in 1988. With the acquisition of Bell Canada’s eastern Arctic operations four years later, Northwestel became the sole telecommunications supplier north of the 60th parallel. Ownership of Northwestel was transferred from BCE to Bell Canada in 1999.

Fort Nelson First Nation (FNFN), which is situated seven kilometres south of the Town of Fort Nelson. This joint venture, formed to serve the Horn River Basin in northern B.C., combines Northwestel’s technical telecommunications expertise and FNFN’s local area expertise. It’s a unique relationship that encourages local involvement and provides long-term economic benefits for the people of FNFN. It ensures that “a fair share of the economic benefits from natural resource industries remain in the region and benefit the people who have lived here for generations,” says FNFN Chief Kathi Dickie.

Waterways was formed to serve resource companies operating in the Horn River Basin with a full suite of reliable, cost-efficient communications products and services, including voice, Internet and data solutions, using both satellite and microwave technology.

IP-Connect is a custom-built IP-based network connection that extends Northwestel services (Business Gateway, v-Connect, E-WAN and voice services) outside of its usual service area using the company’s high-capacity, carrier-grade digital transport facilities. These facilities are backed up by Northwestel’s network monitoring system and highly skilled technicians.

COMPANY NAME: Northwestel

ACCOUNT EXECUTIVE: Mark Rollefson

T: 250.774.4710 E: mrollefson@nwtel.ca WEBSITE: www.nwtel.ca

orthwestel

Network powered

by Northwestel.

Network powered by

Network powered

by Northwestel.

Raven 20 PROFILER

raven oilfield rentals RAVEN OILFIELD RENTALS A Big Company with a Small Company Atmosphere

R

aven Oilfield Rentals has served the oilfield industry in northeastern B.C. and northwestern Alberta with pride for nearly a quarter-century.

Based in Fort St. John, B.C., Raven Oilfield Rentals provides rental equipment and access matting to the region’s oilfield industry in its entirety—drilling, completions, construction, pipeline and production. A private company that was founded in

garbage bins with sizes that include 16-yard, 30-yard and 40-yard; as well as environmental garbage bins with a separate compartment for special waste, which it is fully licensed to transport and one of the first to be able to do so. Raven also offers mobile equipment such as loaders, skid steers and packers for various other jobs that need to be done.

Like the rest of the industry, Raven has been dealing with the challenge of low gas prices and the uncertainty over what will happen with prices in the future. “One of the major things we’ve been doing is that we’ve been trying to stay as diverse as possible while staying committed to core areas of service, safety and the quality equipment that have taken us to where we are now,” McNee says.

As for the future, he believes, “it’s only going to get better. It’s been slow for the last couple of years for some people, including us at times. But as long as we’ve stayed working hard for our customers and pushing to find new customers, we haven’t been as affected as some in getting work. The future looks fairly bright, especially the way the oil and gas industry is going with shale gas, with companies spending money on facilities, infrastructure and land.”

Raven Oilfield Rentals is committed to providing the highest levels of customer satisfaction and client support.

FAST FACTS

1988, Raven is now one of the area’s largest distributors of exploration, production, construction and pipeline rental equipment. you’ll find that Raven Oilfield Rentals brings many advantages to the table. “For one, our experience—we’ve been doing this for a number of years now and are right in the heart of the oil and gas industry,” says sales representative Kevin McNee. “Being locally owned and operated is a huge positive for us.

We’ve dealt with the conditions, the terrain and the people from around here for almost 25 years. If you have any questions that need answering, you can always phone, or you simply stop in. Our owner has an office here and the general manager has an office here.

We feel we are a big company with a small company atmosphere—it’s more family-orientated.”

Raven Oilfield Rentals offers drilling rentals, tank rentals, garbage bins, generators, rig mats and access mats that it has grown largely in the past few years.

The company is now starting to go bigger and better with the access matting, which is mainly used for roads and leases during the spring breakup season. “It’s all relatively new for everybody over the last few years, with everything changing,” says McNee. “With shale gas in B.C., it’s mainly large pad work, multi-well pads and year-round, so the requirement for mats has been quite substantial. We already were relatively big into the matting and we’re now gearing ourselves up for more, as more and more companies are starting up projects.”

Raven Oilfield Rentals manufactures all of its own mats in Fort St. John, using a mat-building machine that the company built itself. “We’re the only mat manufacturing facility right in the heart of the B.C. oil and gas industry.”

Raven builds a variety of mats using fir, oak and a combination of oak and fir if the customer so desires. Raven focuses on providing the best quality mats possible, as quickly as possible, completing large quantities in a short time.

In terms of general equipment, “with the tanks, generators and everything we have, we’ve been doing it for long enough that we understand the needs of our clients, the types of equipment they are looking for and are able to modify the equipment to the programs they are looking to do. One of the benefits to using Raven is that we do have our 6,000-square-foot, CWB-Certified welding shop where we can do any modifications to any equipment—whatever they see fit.”

Raven rents out a wide range of equipment, including shale tanks, floc tanks, 400-barrel tanks, flare tanks, premix tanks, sewer tanks, fuel tanks, tank farms, generators, invert vacuum units, rig mats and light towers. It has various styles of

COMPANY NAME: Raven Oilfield Rentals

T: 250.787.8474 F: 250.787.3097 E: info@ravenoilfield.com WEBSITE: www.ravenoilfield.com

Raven

RENTAL

EQUIPMENT

One of B.C.’s largest distributors of exploration,

production, construction, and pipeline equipment

Schlumberger Can

Unconventional Plays, SCHLUMBERGER Unconventional Solutions 22 PROFILER

SCHLUMBERGER

Rock and ReseRvoiR chaRacteRization wellbore and full-reservoir geomechanical Reservoir quality and completion quality are the behavior. This technology continues to be developed keys to successful shale gas and oil operations through the Schlumberger geomechanics today. Exploration and production (E&P) research and engineering programs at company companies working in shale reservoirs require an facilities around the world. With a well-defined, understanding of the interactions between rock fit-for-purpose mechanical earth model (MEM), fabric, in-situ pressures, temperature, and other Schlumberger geomechanics technology brings conditions—and geomechanics is key to this value to a client’s asset. In the presence of rock understanding. “Probably one of the biggest anisotropy (of which there are many forms) and challenges in any shale play is to find out what heterogeneity, geomechanics can elegantly model type of rock you’re dealing with, because the this complex setting. From its participation in lessons learned in one shale play don’t shale geomechanics projects throughout North necessarily translate directly to another shale America, the Schlumberger geomechanics team play,” says Stan Cena, business development has established efficient, effective processes for manager, Schlumberger TerraTek. “For our clients, building these MEMs, incorporating all types of Schlumberger has the ability to characterize that oilfield data and using the results to add value to rock in terms of both reservoir quality and projects. A dynamic, predictive MEM is the key to completion quality. To maximize well production, obtaining the maximum value from this technology. we need to understand not only the quality of the rock, but also how to place and complete the wellbore in order to minimize uncertainty. What we’re interested in understanding is how big a hammer you need to break that rock.” The Schlumberger geomechanics team, the world’s leading provider of integrated geomechanics technology and services, uses all available data to manage such challenges—to identify, predict, Shale gas, shale oil, coalbed methane, or tight gas reservoirs—for 30 years, and prevent costly events and to manage a Schlumberger Data & Consulting Services (DCS) has delivered economic results shale reservoir optimally.

We know what unconventional means for E&P operators in every key unconventional play.

access to expeRts Schlumberger DCS gives you access to the industry’s foremost shale experts in E&P reservoir characterization and interpretation, multidisciplinary reservoir and production solutions, geomechanics studies, and field development. Schlumberger works collaboratively with your team to help you develop successful business decisions for your well, your reservoir, and your company.

FAST FACTS

solutions foR geomechanical challenges Our experts unconventional reservoirs require unconventional solutions.

Despite yearsknow of geomechanical analysis, integRated data and woRkflows many E&P companies targeting unconvenShale heterogeneity, We apply industry-leading expertise and proprietary workflows toboth thevertically unique and laterally, tional shale reservoirs continue to experience requires a wide range of measurements to be properties of unconventional plays. Collaborating with your team, we offer problems induced by drilling, completion, or understood. To realize field-wide success, the multidiscipline technologies, coupling geophysics, geology, engineering, and production. However, the field of geomechanintegrated Schlumberger geomechanics approach economics at any scale—regional, prospect, field, singlemore well. ics involves much more than analysis of helpsor deliver predictable, repeatable, and stress. The orientation or magnitude of reliable results. Data is readily integrated into Our dedicated DCS has petrotechnical team is yourexploration comprehensive resource. stresses and strains little significance workflows, resulting in faster without framing such measurements in the decision-making processes and shorter www.slb.com/ug context of the shale itself. And as we know, operational timelines. By focusing on variability shale is highly variable. Other problems are across the field, not just on individual wells, the caused, in part, by oversimplified characterizaSchlumberger geomechanics team can identify Global Expertise tion of rock behavior, and by limited modeling the best targets and develop the most effective Innovative Technology and analysis capabilities compounded by a lack field development plans for better allocation of Measurable impact of comprehensive rock property data. valuable resources. Because shale heterogeneity As a leading supplier of geomechanics increases the complexity of the data analysis, technology, we provide the unconventional shale Schlumberger works closely with its customers gas and oil industry with solutions to challenging through workshops and seminars to ensure that

the geoscience, drilling, and completions teams have a thorough understanding of the rock.

Integration of core, log, seismic, drilling, and completion data is critical to the development of these shale reservoirs. These integrated data have many applications in terms of modeling— from operational summaries using the DrillMAP* drilling planning and management tool to fracture stimulation design from Petrel* geological modeling to ECLIPSE* reservoir simulation. Schlumberger Data & Consulting Services (DCS) has the science, expertise, and experience to leverage complex data to any level that customers require. “It’s the integration of all these technologies that is key to understanding the complex nature of shale rock and unconventional tight gas rock,” says Schlumberger Canada account manager Sean Gough. “We work with our clients to enable them to make better business decisions.”

companY name: Schlumberger

Business development manageR: Stan Cena canada account manageR: Sean Gough

t: 403.509.4000 f: 403.509.4021 weBsite: www.slb.com/geomechanics

*Mark of Schlumberger. Measurable Impact is a mark of Schlumberger. © 2011 Schlumberger. 11-DC-0044

*Mark of Schlumberger. Measurable Impact is a mark of Schlumberger. © 2011 Schlumberger. 11-DC-0044

Shale reservoir geomechanics for predicting and explaining an unprecedented range of reservoir behaviors.

ger Canada Limited

*Mark of Schlumberger. Measurable Impact is a mark of Schlumberger. © 2011 Schlumberger. 11-DC-0044

Unconventional Plays, Unconventional Solutions

We know what unconventional means Shale gas, shale oil, coalbed methane, or tight gas reservoirs—for 30 years, Schlumberger Data & Consulting Services (DCS) has delivered economic results for E&P operators in every key unconventional play.

Our experts know unconventional reservoirs require unconventional solutions.

We apply industry-leading expertise and proprietary workflows to the unique properties of unconventional plays. Collaborating with your team, we offer multidiscipline technologies, coupling geophysics, geology, engineering, and economics at any scale—regional, prospect, field, or single well.

Our dedicated DCS petrotechnical team is your comprehensive resource. www.slb.com/ug Global Expertise Innovative Technology Measurable impact

VE BRAN

V.E. BRANDL

24 PROFILER

V.E. BRANDL LTD.

A family-owned business that has been delivering quality service, equipment and earth-moving expertise to the oilfield construction industry in northeastern B.C., northwestern Alberta and yukon for the past five decades.

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The company works hard to stay on top of industry trends. With shale gas development, the energy industry has changed the way it operates and v.E. Brandl has changed with it. For instance, multi-well pads are now common. With many multi-well pads measuring 250 metres by 200 metres or larger, it is no longer efficient to move the material with dozers, as was the norm in the past—so v.E. Brandl has added six Caterpillar 627 motor scrapers to its fleet, as the company has found these to be the most cost-effective way to move material these distances.

Looking forward, v.E. Brandl sees a long-term future for shale gas in northeastern B.C., and the company is looking forward to serving the energy industry for many years to come.

FAST FACTS

ased in Fort St. John, B.C., v.E. Brandl has been serving the industry since 1961, building access roads, plant and well sites, cutting seismic lines, clearing pipeline rights-of-way, and providing all other types of earth-moving services. In the past few years, the company has worked as far south as Grande Cache and as far north as the fields surrounding Fort Nelson. A respected name in the industry, v.E. Brandl has built an outstanding reputation over the years, priding itself not only on the quality of its work, but also on its integrity and concern for employee safety and the environment. Founded by vic Brandl, whose sons Barry, Ron and Kevin are now running the company, v.E. Brandl is celebrating its 50th anniversary this year.

“We take pride in everything we do. We try to give our clients good value and we do it honestly, the way our father did things in the past,” says Director Ron Brandl, who looks after sales and is based in Calgary. v.E. Brandl has approximately 100 employees, many of them long term, and its supervisors and operators bring a wealth of experience to the job. “Our biggest asset is our employees. Whenever we work with new clients, they seem pretty impressed with the quality of our work,” Ron Brandl says.

In addition to its people, v.E. Brandl’s large fleet of modern equipment is another major asset, with different brands and sizes, and the ability to handle a wide range of projects. In order to prevent downtime on job sites, v.E. Brandl maintains its fleet of equipment according to one of the most thorough maintenance programs in the

industry in one of the largest, most modern shops in the business. v.E. Brandl also prides itself on its commitment to safety. In its recent annual Certificate of Recognition (COR) audit, the company scored 94 per cent—three per cent higher than last year—despite the fact that COR criteria have now been changed to be even more rigorous than before. While many companies’ COR results are coming in lower this year, v.E. Brandl continues to improve.

“We were really happy about that,” says v.E. Brandl vice President, Barry Brandl, noting that the company is constantly fine-tuning its equipment in order to make it safer. “We’ve been really innovative in modifying our equipment so that it’s easier for operators to get on and off our crew trucks, because that’s been one of the major causes of slips and trips.”

One of the problems, particularly with high-drive Caterpillars, is that there is nowhere to stand while fuelling. v.E. Brandl has modified its service truck decks with a flip-out platform that workers can stand on, so they don’t have to crawl on top of the cat to fuel up. The company has also installed guardrails at the back of its trucks to ensure that operators use the proper steps when climbing in and out of their service trucks, along with adding steps and handholds to all of its equipment in addition to the ones provided by the manufacturer. v.E. Brandl also seeks to ensure employee safety inside its vehicles. In response to concerns and documented cases of people being injured by being struck by objects inside a vehicle, v.E. Brandl had a local plastics company build containers which are attached to the back seat of its crewcabs using the existing seatbelts along with bolts on the floor, which allow for objects such as lunch boxes and thermoses to be secured during travel. v.E. Brandl has installed vehicle monitoring in all of its service trucks, which allows it to track vehicle speed and locations.

COMPANY NAME: v.E. Brandl Ltd.

FOUNDER: vic Brandl

DIRECTOR: Ron Brandl T: 403.835.2916

VICE PRESIDENT: Barry Brandl

T: 250.785.2916 E: info@vebrandl.com WEBSITE: www.vebrandl.com

BRANDL

Head Office Fort St. John 11112 – 269 Road Fort St. John, BC

Regional Office Grande Prairie 11301 – 89 Avenue Grande Prairie, AB

Earth-moving & Oilfield Construction

V.E. Brandl Ltd. welcomes inquiries regarding

well sites, plant sites, roads, cleanups, seismic programs and any other heavy equipment needs.

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