Profiler - Pride of the Prairies

November 2011

Saskatchewan ISSUE

pride of the prairies Stable regulatory and royalty regime, plentiful resources and technological innovation turn Saskatchewan into petroleum powerhouse

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Profiler November 2011 Pride of the prairies

6 president & ceo Bill Whitelaw

bwhitelaw@junewarren-nickles.com

interim group publisher Chaz Osburn

cosburn@junewarren-nickles.com

Stable regulatory and royalty regime, plentiful resources and technological innovation turn Saskatchewan into petroleum powerhouse

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The next step

Enhanced recovery designed to extend economic life of Saskatchewan’s oil resource plays

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Carving up the pie

Everyone wants a piece of Saskatchewan’s oilfield action

publisher

Maurya Sokolon

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editorial

Editor Darrell Stonehouse

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Editorial Assistance Manager Samantha Kapler skapler@junewarren-nickles.com

Editorial Assistance Kate Austin, Tracey Comeau, Brandi Haugen proofing@junewarren-nickles.com

Contributor Elsie Ross

creative

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The 21 billion barrel question

Finding ways to produce western Saskatchewan’s massive heavy oil resource remains a challenge

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Business as usual

Saskatchewan’s legacy oil plays still the foundation of production

Production, Prepress and Print Manager Michael Gaffney mgaffney@junewarren-nickles.com

Senior Publications Manager Audrey Sprinkle

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Art Director Ken Bessie

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Creative Services Manager Tamara Polloway-Webb

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Contributing Photographer Joey Podlubny

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Advertising Features 24

Cathedral Energy Services Ltd.

www.cathedralenergyservices.com

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Computer Modelling Group Ltd.

www.cmgl.ca

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Kudu Industries

www.kudupump.com

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Logan Completion Systems Inc.

www.logancompletionsystems.com

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Paradox Access Solutions Inc.

www.paradoxaccess.com

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Royal Well Servicing Ltd. SaskTel

www.sasktel.com

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Skyway Canada Limited

www.skywaycanada.ca

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SPT Group

www.sptgroup.com

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STEP Energy Services

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United Centrifuge Ltd.

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Inside front cover

Valtus Imagery Services

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CN Corporate Marketing

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Arrival Oil Tools Inc.

www.arrivaloiltools.com

Inside back cover

Gibson Energy Inc.

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Roke Technologies Ltd.

www.roke.ca

PROFILER

Photo: Joey Podlubny

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Pride

of the prairies

By Darrell Stonehouse

Stable regulatory and royalty regime, plentiful resources and technological innovation turn Saskatchewan into petroleum powerhouse

ark Saskatchewan as one province that weathered the economic storm of 2008 intact and emerged from the disaster at the top of its game.

From 2008-10, provincial exports rose by 48 per cent, compared with the three years earlier, to total over $70 billion. Mining and oil and gas exports climbed by 55 per cent during the period to $41 billion. Oil accounted for around $11 billion in sales in 2010 alone.

The oil sector now provides for almost 17 per cent of the province’s gross domestic product.

Credit for the growth in oil exports goes partly to the provincial government, who maintained regulatory and royalty regimes while neighbouring Alberta created political uncertainty with its royalty experiments. But technological advances have been the biggest driver

with oil explorers and service companies working together to free up billions of barrels of previously stranded resources in the province.

Speaking at the World Heavy Oil Conference in Edmonton earlier this year, Saskatchewan Energy and Resources Minister Bill Boyd said the province is committed to creating a strong investment climate for oil exploration and development.

“What you can expect in Saskatchewan, and can continue to expect in Saskatchewan, is a stable fiscal regime and a stable royalty regime,” said Boyd, adding the government understands companies make investment decisions based on the royalty regime and projected future prices. “I don’t think it’s a good thing for governments to come in partway through those investments and make changes that impact the bottom

existing and future technologies. Its current reserve base is around 1.2 billion barrels, but that is increasing rapidly with new technologies opening up three large resource plays with combined oil in place of around 12 billion barrels.

Saskatchewan’s oil renaissance began six years ago in southeastern Saskatchewan when a group of junior explorers began targeting the Bakken tight oil play.

Known of since about the 1950s, it took the advent of horizontal drilling and multistage fracturing to open up the estimated five billion barrels of oil in place to economic production.

PetroBakken Energy Ltd. was a pioneer in evolving the technical know-how to exploit light tight oil in the play. Company president and chief executive officer John Wright outlined how the technology used to produce the

“Saskatchewan understands the petroleum industry and how important it is to maintaining a prosperous economy,” says Gerry Angevine, Fraser Institute senior economist and co-author of the report. “Industry executives stress that long-term energy policy stability, low royalties and clear regulatory frameworks are their top priorities when choosing where to invest. Saskatchewan offers investors confidence in each of these areas.”

A stable political environment is one thing—having resources to invest in is another. Saskatchewan had initial oil in place of around 46 billion barrels with around 13 per cent of that believed recoverable with

Bakken has changed over the years in mid-September, at the Peters & Co. investment symposium.

Wright said PetroBakken first used extended reach horizontals in the play to expose as much of the reservoir as possible. Production in the wells came in at 10–30 barrels per day. These wells were followed by open-hole coiled tubing fracture treatments using cemented liners, which produced at around 100 barrels per day.

Then, about five years ago, came the multistage fracturing revolution, led by Calgary-based Packers Plus Energy Services Inc. The Packers Plus ball-drop system provided the ability to do multiple stimulations quickly

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Photo: Pipeline News

line. When it comes to royalties, we are going to be stable in the future.

“Industry has a lot of confidence in what is happening in Saskatchewan right now and we will certainly make sure we do everything we can to encourage that development,” he added.

The government is also focused on ensuring drilling applications are turned around as quickly as possible.

“We want to make sure that we have the ability in Saskatchewan to accept investment as quickly as possible and to see companies grow and succeed in our province as they have in the last number of years,” he said.

Saskatchewan’s royalty and regulatory regimes were recently recognized by oil executives and managers polled by the Fraser Institute as the best in Canada and 11th best in the world.

A BJ Services fracking crew at work in southeastern Saskatchewan. Long horizontal wells and multistage fracturing have made southern Saskatchewan a hotbed of activity.

PROFILER

Horizontal wells accounted for over half the oil wells drilled in Saskatchewan last year. Eight months into this year, horizontal drilling has climbed by almost 30 per cent.

Photo: Pipeline News

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and without multiple coiled tubing trips used with earlier technologies. Production per well in the Bakken quickly increased. The extended horizontal wells stretched up to 1,400 metres and early multistage treatments averaged seven or eight per well.

“With the technology of the time, there was no way to increase the fracturing intensity in the field so we started drilling shorter horizontals, but still doing eight fracs,” Wright said. “We were essentially getting 16 fracs in the same area we used to get eight.”

Wright said drilling the shorter 600-metre horizontals taught the company that the higher the frac intensity it

put into the reservoir, the more oil it could get out. As the multistage fracturing technology improved, PetroBakken returned to drilling longer horizontal legs, setting the record by doing the first 20-stage open-hole frac in the Bakken. Well production increased to up to 250 barrels per day.

The next step in the evolution of the Bakken was the introduction of bilateral wells. PetroBakken saw competitors drilling two long horizontal wells on each quarter section and began looking for a more economic way to cover the reservoir. It came up with a scheme to drill bilateral wells off of a single vertical well to cut

costs. The bilateral wells access the same resource as two separate horizontals, but cost $2.58 million to drill, while it costs $4 million to drill two wells.

In the last four years, PetroBakken and Crescent Point Energy Corp. have consolidated the Bakken play through corporate takeovers and land sales. Crescent Point has done an amazing 140 acquisitions in the Bakken and Lower Shaunavon.

Crescent Point president and chief executive officer Scott Saxberg told the recent Canadian Association of Petroleum Producers investment symposium that the company now has over 1,000 net sections of land in the Bakken and over 3,800 drilling locations. Saxberg said technology in the play continues evolving.

“In the last six months alone, we’ve gone from cemented liners using 10–20 stages with larger fracs to now dialing it in more and going with 25-stage, cemented liner smaller-sized fracs,” he explained.

“We’re penetrating more rock and seeing significant improvements in productivity.”

The change in technology is radically altering the province’s drilling sector. Saskatchewan set a record in drilling horizontal wells in 2010, with 1,531 wells drilled. That’s an 88 per cent increase over the figure for 2009 and a 13 per cent increase over the previous record set in 2008.

“Horizontal well drilling has now become the standard in the Canadian oil industry,” Energy and Resources Minister Boyd says. “Twenty years ago, it was experimental technology that our province pioneered, but now it represents more than 50 per cent of our total oil production.”

Horizontal wells accounted for 56 per cent of the 2,730 oil wells drilled in Saskatchewan in 2010. In the first eight months this year, 1,211 horizontal holes were sunk compared to 941 wells in the first eight months of 2010, an increase of 29 per cent.

Industry continues refining its stimulation technologies to increase fracture density and expand the boundaries of the Bakken play as well. Packers Plus released its QuickFRAC technology in May of this year.

The new technology is capable of fracturing 60 stages downhole while only pumping 15 treatments at surface.

Using limited entry diversion techniques and the company’s proprietary technology, the system allows a producer to fracture several isolated stages at one time through a process known as batch fracturing. Aside from cutting costs, the new technology increases fracture density in the reservoir.

PetroBakken also announced the first commercial application of CleanTech completion fluid in the Bakken in May. The new fluid allows better control of fracture treatments, enabling the company to avoid breaking out of the pay zone into water zones.

“It’s a process that allows us to carry a lot of sand in our fracture treatments into the reservoir, but we get to deliver it at very low rates and very low pressures—which avoids the breaking out of the formation,” says John Wright.

By maintaining the frac within the Bakken formation, the operator avoids breaking into other zones, which may cause water incursion.

“This allows us to increase the economic practicality of drilling at the peripheral edges of the Bakken play and expands our opportunities,” Wright says.

He says CleanTech is, “creating value where before we had written off the potential for the Bakken. And now we’re applying this technology to all of the wells in this region.”

One of the major concerns with the new extended reach horizontal drilling and multistage fracturing technology was that high decline rates would make wells uneconomic before recovering most of the potential reserves available. In May, Wright cited the 68 per cent increase in reserve bookings for the company’s first six Bakken wells as validation of its technology and play concepts.

Independent evaluators assigned 100,000 barrels of proved-plus-probable oil reserves per well to each of the original six horizontal Bakken wells drilled by the company in 2006. Bookings increased in 2007, 2009 and again last year, when evaluators estimated the ultimate recovery will be 168,000 barrels of oil per well.

“By the way, these are not in any way the best wells we drilled. They’re the first wells we drilled into the Bakken,” Wright says. “But over the last four years, the reserve assignments for these wells has increased 68 per cent without us doing anything to them—just by proving over time the validity of our technology.”

Of the 1.8 billion barrels of discovered petroleum initially in place on the company’s Bakken lands, only five per cent have been booked as proved-plusprobable reserves.

“We actually think there’s a potential for reserve booking of more than 25 per cent once you include the effect of our enhanced oil recovery programs,” Wright adds. “And that’s not only going to increase our ultimate reserves, but it will mitigate the decline rates.”

The Lower Shaunavon medium oil resource play in southwestern Saskatchewan followed the Bakken as the next major play targeted with the new technology. With more than four billion barrels of original oil in place, the pool is one of the largest oil pools ever discovered in western Canada. Again, Packers Plus played a key role in opening the play to commercial development. In 2008, an operator in the play used the StackFRAC system on 20 wells, fracturing 10 stages per well. The wells had initial production rates of up to 200–300 barrels per day, with typical 3-month initial production rates of 120–150 barrels per day. It was a 10-fold increase over fractured verticals, which achieved in the range of only 10–20 barrels per day in the Lower Shaunavon.

The strong results set off a land rush and flurry of corporate takeovers as explorers competed for a significant position in the play. Bakken pioneer Crescent Point came out on top with over 450 net sections in the play. Since then, it has been proving up that acreage and turning the massive resource into reserves.

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“The Lower Shaunavon is three years behind the Bakken,” says Crescent Point’s Saxberg. “What we’re basically doing is taking the technology and knowledge from the Bakken and applying it there.”

Saxberg says Crescent Point and other players like Cenovus Energy Inc. and Wild Stream Exploration Inc. have had great success in expanding the Lower Shaunavon play and adding to the resource base. Last year, Crescent Point drilled a series of step-out wells in the northern part of the play and added 150 million barrels of oil in place to its resource tally. Crescent Point and Cenovus found, by drilling in the heart of the play, that what was originally thought were two different fields were actually connected, adding another 150 million barrels.

Last year, Crescent Point drilled a series of step-out wells in the northern part of the play and added 150 million barrels of oil in place to its resource tally.

“In the southern part of the field, we rediscovered an area of the Upper Shaunavon, a tight oil play drilled vertically in the past,” he adds. “Ourselves and Wild Stream have been drilling the pool and we believe there are 700 million barrels of oil in place.

“That’s one billion barrels of oil in total for the three areas,” he adds. “Five or six years ago, this would have been the biggest oilfield discovered in 50 years, so it’s a pretty incredible amount of new oil.”

Crescent Point controls 90 per cent of the Shaunavon play. The company is currently focused on building infrastructure as it prepares to increase drilling in the region. It expects to drill 44 net wells in the Shaunavon area in 2011. It also expects to significantly increase drilling to around 100 wells next year following the completion of this year’s infrastructure projects.

The Viking tight oil play in the Dodsland/Kindersley area is the third of the major resource plays underway in Saskatchewan. Less prolific than the Bakken and Shaunavon plays, its lower drilling and completion costs are a significant attraction for developers, as is its four billion barrels of oil in place with only 12 per cent produced.

Junior producer Compass Petroleum Ltd. is working the Viking play.

“Our main focus has been in the Dodsland/Kindersley area,” says Bruce Beynon, vice-president of exploration.

“In Lucky Hills, we probably have about 21 net sections, largely 100 per cent working interest, on our land base.

In the last 13 months, the company has drilled about 25 Viking horizontal wells in the Lucky Hills area.”

Benyon says the Viking is shallow in this part of the basin.

“It’s a shaley reservoir; it occurs at about 700 metres vertical depth,” he says. “We tend to drill 1,500-metre monobore wells.

“We end up on average with about a 600-metre horizontal lateral section that we end up then fracking

and completing.” Beynon says, adding that, in this area, most of the analysis shows 36 or 38 degree API light oil.

“On the royalty side on Crown lands, Saskatchewan has a royalty incentive where royalties are 2.5 per cent on the first essentially 36,000 barrels of oil,” he notes.

“There are very high netbacks given the oil price, low royalties and very reasonable operating costs.”

Beynon adds that operators are able to drill multiple horizontal wells per section, with some having gone to 16 per section.

“We’re only at four wells per section now, but definitely looking at developing it on at least eight wells per section,” he said. “I think the first leg of activity has really stuck close to existing pools and now it’s starting to branch out. In parts of west-central Saskatchewan, there are townships that have only a couple of penetrations in the entire township. You’re still in a fairway where you’re going to have Viking sands. You are a bit more on the exploratory side, so is that sand going to be oil-saturated or could it be gas-saturated or could it be water-saturated?

“There’s a bit of an exploratory phase away from these main pools and obviously those exploratory lands are still available and probably going to be cheaper than land in the hearts of pools.”

Trent Stangl, vice-president of marketing and investor relations with Crescent Point, says the company has about 130 net sections, primarily in the Dodsland and Plato areas of Saskatchewan.

“Nothing this year yet, but we did about 16 wells last year,” he says of drilling activity. “This year, we’ve got a smaller program in our base budget.

“What we normally do coming out of breakup and into summer here is revisit where we are at in our budget, [examine] oil prices and activity levels, and then look to potentially expand our budget. One of the areas that would likely see some incremental activity then would be the Viking.”

The company has six wells planned for the second half of the year, but that could climb to as many as 20 or 30 if the budget is raised. The company has been using shorter-legged horizontals in the area.

“It really gets down to a capital cost play. If you can get your capital costs down low enough, then you can make a decent amount of money out here,” he says.

“The extra money you spend to try and get the extra length on the horizontals hurts your economics.

“When you look at the Dodsland area, there’s been production in that play for a long time. In this respect, it’s kind of like the Cardium where guys are stepping out towards the edges of the play where it’s been a little bit thinner, a little bit tighter and the economics haven’t been as strong, and they’re using the multistage fracking to unlock that value.

“A lot of what we’ve been doing has been addressing expiries and playing with different completion techniques to really understand where we get the best bang for our buck,” Stangl adds. “The issue really out here

Photo: Joey Podlubny

PROFILER

The Viking play at Dodsland is just taking off, with four billion barrels of oil originally in place.

Only 12 per cent has been produced.

for us is that these wells come on at 50–70 barrels a day, and so when you’re a 75,000-barrel-per-day company and you’re drilling 200-barrel-per-day wells in the Bakken and the Lower Shaunavon, it’s a lot tougher for this play to compete.”

Penn West Exploration is the major landholder in the play both in Saskatchewan and Alberta. Its Colorado Group Viking play features a vertical depth of 700 metres, horizontal length of 800 metres, with average fracs of 14 stages. The company drilled 94 horizontal Colorado (Viking) wells in 2010 and 38 wells were drilled in the first quarter this year.

Viking production includes a first-month average rate of 80 barrels of oil equivalent per day a well, the three-month average rate is 50, while the 12-month average is 40. Penn West operates a position of greater than 750,000 acres in the borderlands of southern Alberta and Saskatchewan. To date, the company has identified more than 1,000 light oil drilling locations and more than 1,500 mixed gas/oil locations on the Colorado (Viking) trend.

During the first quarter, Wild Stream drilled two net exploration step-out wells in the Dodsland area. The favourable results from this exploration program allowed the company to participate successfully in the April 2011 Crown land sale, resulting in the acquisition of 31 net sections around its successful exploration wells.

Still to come in the Viking are drilling plans from Devon Canada Ltd., which has a huge land base in the area. David Hager, executive vice-president of exploration and production, says the company drilled and completed two wells in the second quarter, one of which had initial production of 90 barrels of oil per day.

The company expects this play to be economic with well costs in the $1-million to $1.2-million-per-well range, initial production of approximately 40 barrels per day and estimated ultimate recovery of 50,000 barrels per well.

“While these results are encouraging, we’re still in the early stages of evaluating the potential on our 900,000 net acre position. If successful, we could have more than 1,000 Viking drilling locations,” Hager says.

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PHOTO: Joey Podlubny

Enhanced recovery designed to extend economic life of Saskatchewan’s oil resource plays

By Darrell Stonehouse

Hundreds of millions of barrels of new production could come on stream if enhanced recovery schemes prove effective in tight oil reservoirs.

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askatchewan’s new resource plays have breathed new life into the province’s oil industry. But the plays are not without their pitfalls, says John Wright, president and chief operating officer of PetroBakken Energy Ltd. “These wells are capital-intensive, require a lot of innovation, practice and execution,” he explains. “Still, at the end of the day, what they give you is a very high rate of initial production that declines exceptionally rapidly. But they provide a very long 20–30 year tail of production. After the first two years you basically have an annuity on your hands.”

Wright says the goal of enhanced recovery schemes in oil resource plays is to maintain field pressure to get maximum returns on that annuity.

“There’s nothing magic about this. This is lousy, crappy rock saturated with oil. It’s very, very low permeability and it’s very, very difficult to tease the oil out. Without these horizontal wells, there would be no production at all,” he explains. “The idea with any pressure maintenance scheme is to push oil out of the rock and leave the injector fluid behind. If you think of the field as a long-life annuity, what we’re trying to do is attenuate the decline and extend its economic life by increasing the recovery factor and the ultimate recovery of each well.”

There are a number of enhanced recovery schemes underway in Saskatchewan resource plays, and their success could mean hundreds

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of millions of barrels of new oil and decades of revenues for governments, shareholders and service providers.

While having years of drilling prospects ahead in the Bakken play in southeastern Saskatchewan, Wright says PetroBakken is already beginning to experiment with enhanced recovery in the play. The company has looked at a number of different methods, including waterfloods and CO2 floods, but has opted for natural gas injection.

PetroBakken has its first gas injection well on injection now with a total of five planned for this year, with $20 million allocated for enhanced oil recovery (EOR) pilots. If gas flooding works, PetroBakken has identified about 100 locations, probably about 20 a year over the next five years, which will result in about half of its Bakken production on EOR in that period.

“The beauty of this is that we are actually going to start injecting our own solution gas,” said Wright.

At today’s prices, natural gas is almost a waste product, so by putting “it in the ground, it becomes a storage project,” he said.

“Displacing oil out of the ground and ultimately producing that natural gas back on final depletion could be an optimal way to get the most value out of the Bakken, and we are pretty excited about the potential that this offers for us,” he said.

The company has 1.8 billion barrels of light oil in place in the tight Bakken formation. Only five per cent have been booked as proved-plusprobable reserves.

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“We actually think there’s a potential for reserve booking of more than 25 per cent once you include the effect of our enhanced oil recovery programs,” Wright told the company’s 2011 annual meeting.

PetroBakken chose the natural gas flood because the rock isn’t homogenous and traditional waterflooding wouldn’t work on significant portions of its Bakken lands, the company’s modelling showed.

The goal is to increase reservoir pressure, which falls as oil is extracted. In the areas targeted for natural gas enhanced recovery, the permeability is so low that it isn’t possible to inject water fast enough to offset production from nearby oil wells, said Rene LaPrade, PetroBakken’s senior vice-president of operations. Hence, there wouldn’t be sufficient re-pressuring of the reservoir to enhance oil recovery.

CO2 would work, a brief test indicated. In February 2010, PetroBakken shut in one of its Bakken wells for a very short CO2 injection and soak period. In the ensuing 14 months, two offsetting wells each recovered more than 6,000 barrels of additional oil, Wright said.

This test and reservoir modelling convinced PetroBakken that gas injection would enhance oil recovery. There are two reasons why the company is piloting dry natural gas injection rather than CO2.

The first is an abundant supply of cheap solution gas from the company’s own nearby gas plant. The second is existing facilities that can be used without worrying about corrosion. CO2 would change how the company could use its facilities, which in most cases are bare steel that would be highly susceptible to corrosion.

While PetroBakken is bullish on dry natural gas injection, the company isn’t ruling out the possibility of injecting water—or other fluids—for future projects in other areas of the Bakken.

In the Bakken, the company has allocated $20 million this year for five pilot projects to evaluate the effectiveness of injecting natural gas to increase ultimate oil recovery.

Methane injection began in March on the first pilot at a preliminary low rate of half a million cubic feet a day. The second injection well has been drilled and injection started this summer.

“We’ve got four more wells to drill through the end of this year. And so by early 2012, we should have five EOR projects going,” Wright said.

PetroBakken will use the pilots to test different concepts or well configurations. For example, in the second pilot—which will inject natural gas at a rate of about two million cubic feet per day—gas will be injected along the entire horizontal section of the injection well, so the flood front will hit the toe of each of four perpendicular producing wells.

“As gas breaks through at the toe of each well, we have the ability to simply plug off the toe area of the producing horizontal well and mitigate the cycling of the gas at that port,” LaPrade explained.

“The front would continue to move along the horizontal producing leg to the next port, where we would again plug that port off as the gas breaks through.”

The company hopes to make public some preliminary data from the first pilot by year’s end, and to release further results by mid-2012.

If the results are favourable, “I would expect there’d be a significant acceleration in pilots,” said LaPrade.

LaPrade cites a key economic driver behind the decision to use natural gas for EOR in the Bakken.

“We’re in a closed loop. In other words, in the areas we’re working in, we inject gas, we produce it back, it’s processed and then we can re-inject it again,” he said. “So it’s a cheap medium for us.”

So, having its own gas and the infrastructure to capture the gas after it’s produced with the oil so it can be re-injected is a key component of the economics.

“If you were working in a situation where you couldn’t capture the gas and have what I call closed-loop…then using gas as a medium wouldn’t work, in my mind. It would be too expensive,” LaPrade said.

Further enhancing the economics is the fact that the injected gas can be produced and sold when the commodity price improves.

“We can get paid for it now or we can get paid for it later,” Wright told the company’s annual meeting.

Bakken competitor Crescent Point Energy Corp. is testing more traditional waterflood techniques to enhance recovery both in southeastern Saskatchewan and at its Shaunavon play in the southwest.

“To us it is the next leap in technology and it moves us back into more conventional technologies,” Crescent Point president and chief executive officer Scott Saxberg says. “It’s a game-changer for how the Bakken will be developed and it will bring long-term value growth. It will basically, over time, lower decline rates in the field to the point we will be spending lower amounts of capital to maintain production levels and it will free up cash flow for other areas.”

Crescent Point began its Bakken waterflood pilot in 2008 and now has 17 injector wells up and running.

“We’ve seen a positive response from all injectors,” says Saxberg.

The economic impact of the waterflood on cash flow is huge, he adds. High decline rates on newly drilled wells means that to maintain production rates, Crescent Point would have to drill five wells for every injector, Saxberg says.

Typical wells in the Bakken come in at an average 200 barrels of oil per day and decline about 70–75 per cent in the first year before flattening out at 30–40 barrels per day. The two producers in Crescent Point’s first pilot were producing at 100–150 barrels per day this winter.

Greg Tisdale, chief financial officer of Crescent Point Energy, told a recent BMO Capital Markets conference that the company expects waterfloods will increase the recovery factor from 19 per cent to 30 per cent. Tisdale said Crescent Point expects the waterflood scheme will allow the company to increase recovery by around 307,000 barrels per well, and that this will transfer into increased economic value for the company.

“Three wells under primary production would be worth around $18 million,” he explained. “Under waterflood, the value of those wells would be $24.6 million.”

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PHOTO: Pipeline News

With the huge amounts of oil in place in the Bakken, the waterflood scheme could mean a massive increase in ultimate recovery as well.

Bakken producers expect between 17 per cent and 19 per cent recovery is achievable from primary technologies based on eight wells per section. Preliminary data from the waterflood suggests at least a 30 per cent recovery factor. The area that Crescent Point has initially targeted for waterflood has around 1.5 to two billion barrels in place. A 10 per cent increase in recovery factor means 150 million to 200 million barrels of potential incremental reserves, if pilot one is right.

A key to the success so far of the Bakken waterflood has been fracking the injector and producer wells to ensure water sweeps the oil from the rock.

Crescent Point also has three waterflood pilots underway in the Lower Shaunavon resource in southwestern Saskatchewan. Wave Energy began the first in 2008 before being bought by Crescent Point.

While developers test EOR techniques on new resource plays, work continues on CO2 floods as well. Cenovus reported production of 17,000 barrels per day in the second quarter at its Weyburn CO2 miscible flood project. The company is spending between $100 million

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An injector well at Apache Corp.’s carbon dioxide flood project in southeastern Saskatchewan.

The government is pushing for more carbon dioxide flooding in the province.

and $150 million this year and will begin rolling out six new CO2 patterns featuring 33 wells. The wells include five horizontal producing wells, 24 CO2 water-alternating-gas-injection wells, two water injectors and two observation wells. Cenovus is also building a natural gas liquids plant at Weyburn.

Nearby, Apache Corporation is also adding new facilities at its Midale CO2 miscible flood project. Apache is expanding its existing CO2 flood to cover the whole field and will run continuous 4-D to monitor the movement of the CO2.

“It has been very successful so far,” said Tim Wall, president of Apache Canada Ltd. An agreement could be reached by year’s end for Saskatchewan’s third commercial enhanced oil recovery project using CO2, the province’s energy minister said at a recent tight oil conference.

Saskatchewan, through its government-owned electric utility, SaskPower, committed funding to capture CO2 from one generating unit at its Boundary Dam coal-fired power plant near Estevan in southeastern Saskatchewan in April.

So far, one element required for an enhanced project to proceed has been lacking—an agreement with an oil producer to take the CO2. But that could change in the coming months, said Bill Boyd, Saskatchewan’s energy and resources minister.

“We’re in discussions with a number of oil companies about that very thing. In fact, I had a breakfast meeting this morning with one of them,” Boyd said at the Canadian Business Conferences’ tight oil conference in Calgary.

“They are very, very interested in enhanced oil recovery benefits of CO2 and the storage of it. It looks very, very positive. I think they’re into advanced discussions with SaskPower,” the minister said of the oil producers, which he didn’t name.

“We think that will conclude probably later this year perhaps. And for a project to come on stream, I think they’re looking at about late 2013, early 2014 for a very, very significant project,” Boyd said.

16 PROFILER

Everyone wants a piece of Saskatchewan’s oilfield action

T

By Darrell Stonehouse

he oil boom in Saskatchewan is attracting interest from outside service and supply companies looking to grow their operations into new markets.

In 2011 alone, three major transactions have taken place as service providers target Saskatchewan-based firms to get a foothold in the region.

In January, Calgary-based CanElson Drilling Inc. purchased Eagle Drilling Services Ltd. for around $61 million.

A private company, Eagle owned eight telescopic double drilling rigs working the Bakken play in southeastern Saskatchewan. In making the purchase, Randy Hawkings, CanElson’s president and chief executive officer, made clear the reason for the takeover was to get a piece of the Bakken pie.

“Eagle is one of the most respected contract drilling providers operating in southeast Saskatchewan and southwest Manitoba that has consistently realized higher-than-industry utilization levels and also has a reputation as an efficient and safe drilling contractor,” he says. “The acquisition adds an additional eight heavy-duty telescopic double rigs to CanElson’s existing rig fleet of 10, for a total of 18 drilling rigs operating in western Canada, which will strengthen CanElson’s presence and capitalize on increased market exploration and production opportunities in Saskatchewan, as well as Manitoba.”

Eagle’s drilling rig fleet had been focused on drilling in southeastern Saskatchewan, which has among the highest rates of drilling activity in western Canada. During 2010, Eagle operated at 71 per cent utilization compared to the average industry utilization of 40 per cent. Eagle drilled 152 wells last year, including 57 wells for Bakken producer Crescent Point Energy Corp. and 35 wells for PetroBakken Energy Ltd. In July, Three Star Trucking Ltd., an oilfield hauling company serving Bakken-area crude oil producers, was joined by a new partner—Provident Energy Ltd. Provident bought a two-thirds interest in Three Star for around $20 million. Again, the Bakken was the driving force behind the deal.

“The acquisition of this two-thirds interest in Three Star expands Provident’s logistics footprint in the Bakken area, one of the most exciting resource plays in North America, and creates a strong partnership with a highly regarded and growing player in the industry,” says president and chief executive officer Doug Haughey.

Three Star is a privately held enterprise based in Alida, Sask., operating in Saskatchewan, Manitoba and North Dakota, providing fee-for-service hauling of crude oil and related oilfield liquids for major Bakken-area producers. Three Star has a new and wellmaintained fleet of approximately 170 tractors and 160 trailers.

In September, Flint Energy Services Ltd. announced it was taking over Carson Energy Services Ltd. The purchase price to be paid at closing is comprised of $112 million in cash and 2.12 million Flint common shares, plus up to an additional $30-million earn-out spread over the next three years, subject to closing adjustments.

Carson, established in 1974 and based in Lampman, Sask., is one of the province’s largest private companies engaged in energy services with over 900 employees and operations in 14 locations, covering the major energy plays in Saskatchewan, Manitoba and eastern Alberta.

It offers pipeline construction, fabrication, civil and facility construction, oilfield maintenance, pipeline integrity, horizontal directional drilling, trucking and tubular management, environmental and safety sales and services.

Flint says that Carson’s well-respected safety performance, outstanding employees, strategic services and operations, and strong customer service will provide a platform for the company to expand its energy services reach in Saskatchewan and Manitoba.

As Flint’s Saskatchewan operations are based in three locations offering a limited suite of services, there will be little overlap or duplication in operations, it says.

Saskatchewan has seen significant growth in its oil and gas sector activity, making it an attractive area for expansion, particularly in heavy oil production near Lloydminster and in the Bakken oil play in southeastern Saskatchewan, says Flint.

Flint already has a presence in the U.S. part of the Bakken with locations in Minot, Williston and Stanley, N.D. The addition of Carson’s locations positions the company as the largest established and diversified service provider across this resource basin, Flint says.

In addition to the oil and gas industry, Flint says its experience with large and complex projects in the oilsands, combined with Carson’s local customer relationships, presents a new opportunity for Flint to expand its major projects construction and maintenance capabilities in the largest potash-production region in the world.

Flint anticipates that the acquisition will add over $220 million in annual revenues going forward. There are numerous incremental opportunities for both Flint and Carson to offer their existing services across the expanded operational footprint. Flint’s fluid haul, large construction projects, rig moving and maintenance services are some examples of services that can grow across the Carson operations, while Carson’s horizontal directional drilling and fabricating capacity can be offered through Flint’s existing operations.

“Flint sees this combination with Carson as a strategic opportunity for growth, tied to the increasing oil drilling and production activities we are seeing in Saskatchewan,” says Bill Lingard, president and chief executive officer of Flint.

Photo: Joey Podlubny

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18 PROFILER

The 21-billionbarrel question

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Finding ways to produce western Saskatchewan’s massive heavy oil resource remains a challenge

By Darrell Stonehouse

W

ith tight oil resource plays cranking up in the province, the next step in Saskatchewan becoming an energy superpower lies in fuelling a similar revolution in the heavy oil fields in the western reaches of the province, according to Saskatchewan Energy and Resources Minister Bill Boyd.

The government is looking at ways in which it can work with companies to encourage improved recovery rates for its heavy oil resources, Boyd told delegates at the World Heavy Oil Congress.

In the Lloydminster/Kindersley area in western Saskatchewan, there are an estimated 21 billion barrels of oil in place, with production averaging more than 200,000 barrels per day. However, recovery rates are less than 10 per cent. Boyd said this is something that needs to be addressed.

Saskatchewan’s Petroleum Technology Research Centre and the companies themselves are working on ways to increase those rates.

The government also wants to work with industry to recover as much of that heavy oil in place as possible, through the application of new and emerging technologies, and is looking at ways of assisting industry.

“There may be some things that we can do to help as a government, perhaps through taxation,” he said. “We are certainly prepared to take a look at all of those kinds of things.”

It’s likely that no one solution will answer the heavy oil challenge.

There are, however, a number of technologies including thermal recovery, vapour extraction, CO2 floods and even microbial enhanced recovery that can turn resources into reserves.

Baytex Energy Ltd. president and chief executive officer Anthony Marino told the Peters & Co. investment symposium in mid-September that there are currently a variety of production techniques in use in heavy oil fields. There’s cold vertical production with sand and cold horizontal production without sand, which Marino said is becoming quite common. Then there’s waterfloods using both cold and hot water, which have long been the preferred enhanced recovery techniques.

Marino said steam assisted gravity drainage (SAGD), used in Alberta’s oilsands industry, is gaining a foothold in heavy oil development and has room to grow.

Baytex purchased a SAGD operation at Kerrobert in 2009. At the time it was producing 1,000–1,500 barrels per day. Since then the company has drilled three new SAGD pairs.

Its initial SAGD well pair, which began production late in the third quarter of 2010, continues to exceed 1,000 barrels of oil per day at a cumulative steam to oil ratio of about 2.7.

Cumulative production from this well pair stands at 325,000 barrels after 10 months of production. Two additional SAGD well pairs were drilled during the second quarter. After June 30, one of the new well pairs was put on production at initial rates topping 1,000 barrels per day. Start up of the second new well pair is planned for later in the third quarter.

Baytex has identified at least nine further SAGD well pair locations at Kerrobert and plans to drill four additional stratigraphic test wells later this year to optimize the placement of these future well pairs. The company is also doing engineering and procurement work to increase the steam plant capacity in 2012.

Husky Energy Inc. plans on doubling its thermal heavy oil production in Saskatchewan to about 40,000 barrels per day in roughly five years, it reported in July.

“Our current thermal production is in the range of about 18,000– 20,000 barrels per day today,” Rob Peabody, Husky’s chief operating officer, told analysts after the company released second-quarter results. “With these projects coming on stream over the next five years, we’re looking to increase our thermal production into the range of about 40,000 barrels a day.”

Husky’s total heavy oil production is roughly 100,000 barrels per day, most of it from the Lloydminster area.

Peabody said the increase in thermal heavy oil output will be offset somewhat by declines in cold heavy oil production: “As we’re moving toward the edge of the reservoir with some of the cold heavy oil wells, F&D [finding and development] costs are rising. And by bringing on these thermal projects, we actually help drive our F&D costs back down.”

Husky expects its overall heavy oil output—thermal and cold combined—to grow at a compound annual rate of three to five per cent over the longer term, but the rate may vary on a year-to-year basis as new thermal projects are developed, says Asim Ghosh, Husky’s chief executive officer.

PHOTO: Joey Podlubny

20 PROFILER

Heavy oil producers are increasingly turning to SAGD in areas with thicker oil deposits.

Reviewing its thermal heavy oil construction progress, Husky says its 8,000-barrel-perday South Pikes Peak project is on target for first oil in mid-2012. South Pikes Peak was 67 per cent completed on June 30.

Husky continued its 3,000-barrel-per-day Paradise Hill development, which will use existing Bolney infrastructure. The project was 28 per cent complete on June 30 and is to be operational by the third quarter of 2012.

Construction of a single thermal pilot well pair at Rush Lake was completed in the second quarter with first production expected in the third quarter.

Husky says four more commercial thermal projects are in the early delineation and concept selection phase.

BlackPearl Resources Inc. is another conventional heavy oil producer looking at thermal technology to increase recovery. BlackPearl has an aggressive conventional drilling program underway at Onion Lake, drilling 63 wells in the second quarter and targeting 110 wells for the year. The company has 13 million barrels of established reserves in the play, with another 80 million barrels of contingent resource.

“In addition to conventional development, a portion of the Onion Lake lands are amenable to thermal development,” company president and chief executive officer John Festival said in releasing BlackPearl’s second-quarter results. “In fact, the majority of the contingent resource estimates for Onion Lake are based on thermal development in the area.”

The areas BlackPearl is targeting for SAGD development have net pay zones in excess of 15 metres, making the technology workable. It expects to recover 50–70 per cent of the resource in place, compared to around five to eight per cent through primary development.

BlackPearl is predicting steam to oil ratios in the 2.5–3.5 range, putting it in line with the top quartile of SAGD bitumen projects.

To assist in the transition from conventional to SAGD development, BlackPearl plans on “pre-spending” some capital by drilling the horizontal wells that will be used in the SAGD operations. This will ensure it is not drilling in areas that have been partially depleted or disturbed by conventional drilling. The company expects to drill up to 20 horizontal wells by the end of 2012.

“These wells will not be put on production until we begin SAGD development. We have recently filed an application with regulatory authorities for a 10,000-barrel-per-day commercial SAGD project in the area,” said Festival.

Nearby, Petrobank Energy and Resources Ltd. continues moving forward with commercial development of its thermal development using its toe to heel air injection (THAI) methodology.

Petrobank has spent much of the last two years working through the challenges of proving the THAI technology in shallower pay zones of Saskatchewan’s heavy oil fields. But the two pilot wells are now on track, reaching combined peak production of 355 barrels per day early this year, before declining to 40 barrels per day this summer, due to ongoing work at the facility.

“The produced oil has been consistently upgraded in situ by 4–7 degrees API, requiring less diluent to meet pipeline API quality,” said Chris Bloomer, Petrobank’s senior vice-president and chief operating officer, heavy oil, in March. We will focus on increasing production towards design capacity of 600 barrels per day, per well. Under normal operations, design capacity is expected to be achieved approximately one year after air injection has commenced.”

A 10-well commercial expansion at Kerrobert is well underway. In August, Bloomer said that eight of the 10 new well pairs are on air injection and in the initial production phase.

“The first expansion well pair was placed on air injection and production in the middle of May, with an additional four well pairs placed on air injection by the end of the second quarter,” he said.

The pre-ignition heating cycle (PIHC) for the remaining five well pairs began at the end of the second quarter, and currently three of these well pairs are on air injection, with the remainder expected to be on air injection by September. The company said its operating procedures continue to evolve.

“We have been able to reduce the duration of the PIHC from a planned eight weeks to approximately four weeks. Following the PIHC, the vertical wells commence air injection at low rates and the horizontal production wells are brought on production with a progressive cavity pump,” Bloomer said.

The initial clean-up fluids consist of water, including condensed water from the PIHC steam injection, and some native oil. As these

PROFILER

fluids are produced, the combustion gas volume increases, the temperature in the horizontal well begins to rise and the well begins to produce an oil and water emulsion at low rates. Wellbore temperatures will increase and combustion gas, along with some native oil and occasional upgraded THAI oil, will be produced.

“As we measure the combustion gas communication and rising wellbore temperatures, we will increase the air injection in stages to facilitate the combustion zone development,” Bloomer said.

Bloomer noted that the second quarter was a “period of transition” for the Kerrobert project.

“We completed the drilling of the expansion wells, began operations on the new wells and started dismantling the temporary facilities in anticipation of the new wells being tied into the new central processing facility [CPF],” he said.

Bloomer added that very wet weather delayed the company’s access to the CPF and wellsite until mid-July. Petrobank experienced “significant downtime” on the original Kerrobert wells due to pump changes, decommissioning of the original Kerrobert facilities and delayed tie-in to the new CPF. Petrobank continues expanding its land base at Kerrobert. In May it acquired 566 acres of petroleum rights on the Kerrobert trend adjacent to the 4,092 acres of land that it purchased in March. This is the third acquisition of land that it has made in six months on the same trend as Kerrobert, and it currently controls 11,517 net acres of land on the trend. To define the resource potential of its new lands, the company purchased three third-party 3-D seismic surveys and plans to drill two stratigraphic delineation wells.

Southern Pacific Resource Corp. is also using SAGD at its STP-Senlac Thermal Project located near Unity in southwestern Saskatchewan. Southern Pacific’s aim at Senlac is maintaining production levels on an annual basis between 4,000 and 5,000 barrels per day. This summer, the property achieved an average production rate of 4,829 barrels per day. This increased production level is primarily a result of the recent addition of Phase H, which

PHOTO: Joey Podlubny

In the Lloydminster/ Kindersley area in western Saskatchewan, there are an estimated 21 billion barrels of oil in place, with production averaging more than 200,000 barrels per day.

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Tighter well spacing is also adding to recovery rates.

consists of two SAGD well pairs placed on production in April 2011.

As part of its development strategy, Southern Pacific is now drilling and preparing Phase J for production. Phase J consists of three SAGD well pairs; these well pairs may not all be needed until later in the fiscal year and they will be layered into the facility as capacity permits.

With thermal recovery limited to thicker pay zones, the Saskatchewan government and industry have invested $40 million in the Joint Implementation Vapour Extraction project with a goal to develop, demonstrate and evaluate solvent vapour extraction processes for enhanced oil recovery from heavy oil reservoirs. The project ran from 2006-09, with three pilots at Husky, Nexen Inc., and Canadian Natural Resources Limited heavy oil fields in Saskatchewan.

Vapour extraction technology involves injecting solvent gases like methane and butane, or methane and propane, into reservoirs to reduce the viscosity or stickiness of heavy oil. Once the solvent dissolves into the oil and reduces the oil’s viscosity, it can drain and be pumped from a lower horizontal oil well. What makes it attractive is that it may be applicable to 80 per cent of heavy oil reservoirs in Saskatchewan, as well as in medium oil reservoirs in the southwestern area of the province. The potential recovery rate for heavy oil using vapour extraction is 20 per cent to 50 per cent, which is an average of two to five times the current heavy oil recovery rate.

While there are no commercial vapour solvent projects underway in Saskatchewan, experimentation continues. Husky operates two solvent enhanced oil recovery pilots at Edam and Mervin.

The company is also investigating the use of CO2 as a solvent.

Construction of two CO2 injection pilot sites at Lashburn and Tangleflags, as well as a CO2 capture and liquefaction plant at the Lloydminster Ethanol Plant, are under way. The captured emissions will be used in the ongoing piloting program.

Husky is also going further outside the mainstream in an effort to produce more heavy crude, with some success. A microbial enhanced oil recovery pilot in Wainwright, Alta., continued in 2010 with nine wells continuing to show a substantial response eight months after treatment. A second pilot in Devonia Lake has commenced with two cycles of treatments completed. The preliminary results show a 20 per cent increase in oil production, says Husky.

22 PROFILER

By Darrell Stonehouse

W

ith the Bakken tight oil play in southeastern Saskatchewan generating all the buzz, it is easy to forget that conventional oil plays still make up the bulk of the province’s production.

Of the nearly 425,000 barrels of oil per day produced in the province in 2010, only around 60,000 came from the Bakken. Other tight oil plays, like the Lower Shaunavon and the Viking play at Dodsland, add from 10,000 to 15,000 more barrels per day, according to recent estimates. The remainder, nearly 80 per cent, comes from legacy light, medium and heavy oil plays. And many of these fields have years of drilling ahead.

Southeastern Saskatchewan has been the backbone of the province’s conventional light oil industry since the Weyburn field was discovered in the early 1950s. Drilling in the area continues almost 60 years later as producers target known resources and test new play types.

Tight oil pioneer PetroBakken Energy Ltd. is one of the major players in the conventional Mississippian light oil play in southeastern Saskatchewan, with current production of around 5,000 barrels of oil and natural gas liquids per day. PetroBakken plans on spending $40 million in the area in 2011. It has drilled 17 wells this year, with another 25 planned. It has over 300 drilling locations identified, with around 950 undeveloped sections of land in the play for future growth.

Typical new wells in the Mississippian/Jurassic-age light oil pools generate initial production rates between 75 and 200 barrels of oil equivalent per well, says the company. Each well is expected to recover around 80,000 barrels of oil equivalent over its lifespan.

PetroBakken says the big advantage of the conventional play in southeastern Saskatchewan is that it is relatively low risk and provides long-life production, high netbacks and steady cash flows. The company sees opportunity in using horizontal wells to down-space within the play to add future production.

NAL Energy Corporation is another believer in southeastern Saskatchewan’s conventional oil resource. In September, NAL said it had four rigs operating, targeting Mississippian light oil. The majority of drilling in Saskatchewan has been focused in the greater Hoffer area where 48 (24 net) wells have been drilled since 2010. Of these 48 wells, 45 are currently on production and internal expectations are that production in the area will grow to over 1,800 barrels of oil per day (gross) by year-end from approximately 200 barrels of oil per day (gross) in 2010.

At Hoffer, results to date continue to validate a significant light oil resource in the area, the company says. Individual well outcomes at Hoffer have varied, with initial first-month production averages of 40–300 barrels per day.

In 2011, NAL’s drilling program has identified two new pool discoveries in the greater Hoffer area at Neptune and Oungre. These discoveries have validated the play’s potential and added significant additional Mississippian light oil drilling inventory for 2012 and beyond, says the company.

NAL has been testing different drilling techniques in its Hoffer program over the past 12 months. The Mississippian reservoir does not require fracture stimulation, but efforts are underway to increase production. The company has recently been using underbalanced drilling techniques on a number of wells, which have delivered enhanced initial production results. It has also been testing acid stimulation techniques in the play.

NAL continues to add to its land base in the area, with over 11 sections of land acquired adjacent to existing producing acreage.

Potential for continuity of the play across the acquired acreage is supported by mapping that reflects the stratigraphic nature of the play, the presence of bypassed pay in several wellbores and observations made from NAL’s proprietary 3-D seismic.

PROFILER

Drilling conventional resources continues despite the Bakken being the main target in the southeast.

Novus Energy Inc. recently acquired a 100 per cent working interest in approximately 55 net sections of land with rights in the Birdbear formation near Dodsland, adding to the 24 net sections of land with rights in this formation already owned by Novus.

“Successful Birdbear oil wells in the area are amongst the most economic in Canada due to high deliverability rates, large oil reserves and low drilling and completion costs,” says the company.

At only 750–950 metres deep, drilling and completing Birdbear wells averages around $1.3 million per well. Initial production rates at 30 days average around 100 barrels per day, and Novus expects each well to have 125,000 barrels of reserves.

NuVista Energy Ltd. is also high on the Birdbear and other heavy oil prospects in Saskatchewan. In 2010, NuVista’s primary focus was on the Birdbear, and that focus has continued this year.

In the fourth quarter of 2010, NuVista drilled four successful Birdbear horizontal oil wells at Zoller Lake. In the second quarter this year, it drilled two (1.5 net) successful Birdbear delineation wells, extending the Hallam pool to the south, following up on a successful extension well drilled in the first quarter of 2011.

It expects to drill 25–30 horizontal oil wells during the second half of the year. The focus of the drilling program will be on the development wells at Zoller Lake and Hallam, the development wells and further delineation wells at its southern extension of the Hallam pool and the testing of new Birdbear prospects. Five Birdbear wells were drilled in the second quarter following spring breakup and five wells have already been drilled in the third quarter.

Photo: Pipeline News

Construction of a central gathering, treating and water disposal facility at Hoffer is expected to be completed by year-end 2011.

Throughput capacity of the facility is designed to be 5,000 barrels per day of oil and water. Once commissioned, operating costs in the area are expected to drop to approximately $6 per barrel of oil equivalent (boe) from $10 per boe at present.

NAL says another important factor in driving interest in conventional oil exploration in southeastern Saskatchewan is the royalty rate on new pool discoveries. In Saskatchewan, royalties of 2.5 per cent are paid on the first 100,000 barrels of oil produced from each well.

Another former trust, Zargon Oil & Gas Ltd., is also active in southeastern Saskatchewan, as well as in Manitoba and North Dakota.

The Williston Basin area holds 53 per cent of Zargon’s proved and probable oil and liquids reserves and accounted for 51 per cent of oil and liquids production in 2010.

Zargon says it has a large inventory of Mississippian horizontal oil locations that will be the focus of drilling for the next three years. These wells will augment primary depletion schemes in some pools or will be drilled to optimize waterfloods.

Zargon’s 2010 drilling program targeted pool extensions in the Steelman and Manor (Frobisher-Alida) areas. In 2011, activity will also focus on Midale, Sask., targets at Weyburn and Elswick, in Saskatchewan, where reservoir studies show horizontal drainage wells will increase oil recoveries. Additionally, multi-frac horizontal wells are unlocking Mississippian and Bakken/Torquay opportunities at Daly, Man., and at Workman and Fertile, Sask.

As with most Saskatchewan producers, this spring and summer’s wet conditions and flooded surface leases resulted in a three-month delay, and drilling operations at Zargon did not resume until the middle of August. Only two horizontal wells at the Weyburn and Elswick properties have been drilled in the third quarter.

The majority of Zargon’s 2010 drilling program targeted very profitable Steelman-Frobisher locations that were characterized by very strong initial rates, which are associated with rapid declines prior to rate stabilization. In 2011, the company is targeting lower initial rate, but shallower-decline, Midale drainage wells.

Zargon’s eastern Williston Basin properties at Daly, Virden, Mackobee Coulee, Truro, Frys and Workman are characterized by thick, low-permeability Mississippian oil-bearing carbonate formations that are interpreted to be prospective for improved waterflood performance through the use of multi-frac horizontal drainage wells. This winter, as a follow-up to a successful Truro multi-frac horizontal well, Zargon is planning four horizontal multistage frac locations at Truro and Mackobee Coulee in North Dakota and Daly. Beyond 2012, it is anticipated that the majority of the Williston Basin locations will be multistage frac waterflood exploitation wells in the eastern properties. In aggregate, Zargon currently holds an 85 net well Williston Basin oil exploitation inventory.

Another growing new conventional heavy oil play is the Birdbear play in west-central Saskatchewan.

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24 PROFILER

CATHEDRAL ENERGY SERVICES LTD. CATHEDRAL ENERGY SERVICES LTD. Industry-leading drilling and completions technology drives Cathedral’s success athedral Energy Services Ltd. is committed to providing value-added services and solutions to customers in Saskatchewan and across North America. A leading international provider of innovative drilling and completions services in operation since 1998, Cathedral builds industry-leading technology and strong partnerships to maintain its competitive advantage.

“The cornerstone of our company is our people,” says Cathedral president and chief executive officer Mark Bentsen. “Our success is measured by the quality of our people, our innovative technology and the satisfaction of our customers.”

For Cathedral Energy Services Ltd., a publicly traded company listed on the Toronto Stock Exchange under the symbol CET, technology has led to its success in the market.

Headquartered in Calgary, Cathedral is one of the larger suppliers in the Saskatchewan market, where it is a significant provider of directional services in the Bakken play, and operates its own service facility in Estevan.

“That’s key because we’re not having to ship equipment back to our major repair facility in Nisku,” says Cathedral vice-president, John Ruzicki. “We’re able to service the market locally with our facility in Estevan.”

Technology is a key driver of growth at Cathedral, which has been gaining market share based on the strong performance of its electromagnetic (EM) measurement-whiledrilling (MWD) systems.

“One of the things that has created some of our success in Saskatchewan has been the use of the EM technology,” Ruzicki explains.

Currently, more than 90 per cent of the 1,500 wells drilled by Cathedral each year are drilled using EM technology.

Cathedral’s latest advancement in its EM technology is the FUSION MWD, the next generation of tool that has even greater flexibility. It’s a highly versatile tool you can use to build to suit the drilling requirement.

The FUSION-EM system incorporates all of the performance milestones from Cathedral’s previous systems—reliability, ruggedness and industry-leading depth achievements. This new, upgraded technology, which entered the market in the second quarter of 2011, merges diverse MWD elements into a unified whole.

Cathedral’s FUSION MWD System makes it simple to incorporate several MWD components and capabilities into a single system to provide superior communication, target trajectory navigation and accuracy. This system can withstand today’s very challenging drilling environments while at the same time maintaining data storage performance.

Cathedral designed this system to ensure ongoing customer satisfaction.

Cathedral’s FUSION MWD System advances MWD technology by combining the best of Cathedral’s existing MWD systems together with new technologies that enhance performance and provide operators with additional options not found on standard systems.

One of the added abilities of the new system is that it can provide both electromagnetic and positive mud pulse (P+) telemetry options. “It is now backed up by the ability to run dual telemetry transmission— enhancing or reducing drilling times through appropriate use of the FUSION system,” Ruzicki says. “It’s a versatile tool that you can use to build to the drilling requirements.”

The FUSION MWD System also offers LWD (logging while drilling) capabilities, including not only gamma ray, but also the latest in resistivity tool technology. It increases accuracy through upgraded directional and gamma sensor packages: •FUSION-P+ (positive pulse) system •FUSION-DT (dual telemetry) system •FUSION-LWD (logging while drilling) system

enhanced space will allow us to expand our remote drilling and remote MWD capabilities.”

Manufacturing, assembly and repair will all take place under one roof at Cathedral’s Calgary campus, where approximately 90 people will come together, including all support staff—management, accounting, safety, human resources, engineering, research and development, and well-planning personnel. The benefits of this move will include better communication between the various groups since they’ll all be working under one roof, Ruzicki notes.

Cathedral’s remote drilling services, for both directional drilling and MWD, and the command centre operations hub will all operate out of the new facility, which will serve as a 24-hour operation centre.

Cathedral’s Calgary-based Remote Drilling and Command Centre handles drilling multiple projects and horizontal and under-balanced wells, saving clients money and increasing safety by having fewer personnel on location and out on roadways.

•Gamma Ray Gamma Sensor •Focal Gamma: the FUSION focal gamma sensor •FUSION-RES (resistivity) In addition to FUSION, Cathedral is continuing to develop and bring new technologies to market.

This fall, Cathedral plans to consolidate its Calgary staff and operations into a new 80,000-square-foot campus, located off Blackfoot Trail Southeast in Calgary. “The facility enhances our capabilities to continue coordinating our development and utilization of new technology,” Bentsen says, pointing to the new building’s size and magnitude, as well as its increased manufacturing capabilities. “The

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COMPANY NAME: Cathedral Energy Services Ltd.

TOLL FREE: 866.276.8201

T: 403.265.2560 F: 403.262.4682 E-MAIL: info@cathedralenergyservices.com

WEBSITE: www.cathedralenergyservices.com

WD M n: a merging of diverse elements

FU.SIONinto a unified whole

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FUSION

MWD SYSTEMS

P+ EM Cathedral’s FUSION MWD System advances MWD technology by combining the best of our existing MWD systems with new technologies that enhance performance and provide operators with additional options not found on standard systems. The FUSION MWD System provides both electromagnetic P+ (“EM”) and positive pulse (“P+”) telemetry option, as well as logging while drilling (“LWD”) capabilities including not only gamma ray, but also the latest in resistivity tool technology.

NOW HIRING

DT Drilling + Completions

CathedralEnergyServices.com/careers

26 PROFILER

Computer ltd.

(Cmg) Computermodelling modellinggroup group ltd.

(Cmg) The enhanced oil recovery simulation specialists omputer Modelling Group Ltd. (CMG) is a Calgary-based software company that builds specialized reservoir simulation software for difficult hydrocarbon recovery processes. “We are the enhanced oil recovery simulation specialists. We are known for simulating unconventional hydrocarbons as well as thermal recovery of heavy oil,” says Dan Dexter, CMG vice-president, Canada and marketing.

The largest independent developers of reservoir simulation software, CMG provides highly practical solutions for oil and gas reservoir modelling, simulation and advanced oil recovery (EOR/IOR) processes—helping customers maximize recovery of their hydrocarbon assets.

CMG can play an important role in helping companies optimize production and ultimate recovery in oil shale regions such as the Bakken formation. “Historically, it’s been a real trial-and-error methodology for determining how closely to space wells, how to do fracs, and how to configure and complete wellbores in the Bakken. CMG has developed a solution for hydrocarbonbearing shales, both gas and oil, that makes the optimization of well placement, frac spacing and frac size very simple and efficient,” Dexter says.

Dexter compares the situation in the Bakken to what it was like in the Mannville Coal about five years ago, when coalbed methane was a hot prospect. “There was an awful lot of money spent doing experiments with the drill bit, rather than ‘experiments with a reservoir simulator’ to determine a small number of science-based, physically practical exploitation methods prior to going out to the field,” he notes.

For example, 300 vertical wells were drilled into the Mannville Coal before the first horizontal well was drilled. All but a few of the 300 vertical wells that were drilled are uneconomic—that’s a lot of money for a failed experiment. In comparison, just two weeks’ worth of reservoir simulation work allowed CMG to determine that vertical wells would not be economic, and that only some configurations of horizontal wells would be

economic. “We used publicly available data, but if you have specific reservoir information about your asset, we can narrow the range of uncertainty dramatically,” Dexter explains.

“Would you rather spend a million dollars or half a day in the library?”

Optimizing the exploitation of hydrocarbonbearing shales is a very similar process, he adds, noting that within the past five years, CMG has by far become the industry leader in shale gas simulation. As industry is now focusing on the Bakken oil shale, “we can apply the same shale simulation technology we have for tight and shale gas to tight and shale oil, and with that same type of result.

With the addition of tools to utilize microseismic data to enhance the accuracy of the reservoir simulation model, our clients are getting even better guidance. You go to the websites of the major Canadian Bakken players and you can see the ‘optimization’ that has been done in well spacing, and the number and size of fracs. What has taken them years and millions of dollars to determine with the drill bit and frac trucks, we can do in a month or so with our reservoir simulators.”

Simulation is not like it was in the old days where some questionable results emerged from the simulation engineers after six months or a year of work. There are three reasons for this: 1) Desktop computers are literally 10 million times faster than they were 25 years ago 2) Computers are very inexpensive and 3) Reservoir simulation software is far more sophisticated and has a great visual interface (WindowsTM) rather than stacks and stacks of printouts. These three things make this type of “experimentation” very cost-effective and provide tremendous value.

CMG began over 35 years ago with a grant from the Alberta government to try to determine how to recover the non-minable oilsands. Today, CMG is the unchallenged leader in the difficult hydrocarbon-recovery process simulation arena around the world.

Over the years, CMG has developed an international reputation as the go-to

simulation company for difficult-to-solve reservoir problems. “We’ve got half of our staff involved in R&D [research and development], and that makes us unique,” Dexter says. “It’s very unusual to have that much brain power pushing your company forward. That keeps us at the forefront of innovation for our customers.”

That’s why he sees continued unparalleled growth for CMG, in the near term and well into the future. “We’ve grown incredibly over the last 10 years because we’ve got the best technology for this field. Industry isn’t finding many new oilfields—but we know where there are hundreds of thousands of existing reservoirs. It’s just a science experiment as to how to extract it—and that’s where CMG comes in. It’s much better to do your science experiments on a computer, rather than doing them with a drill bit and a frac truck—it’s faster and cheaper, but most importantly, it explains why you get different results.”

CMG software is used internationally in virtually every oil-producing region of the world. “Our software is used because we have the best technology for the job. It all comes down to the physics, and you have to get it correct and complete,” Dexter says.

“No matter how complicated and difficult building the code is, we always do it right—there are no shortcuts.”

FASt FACtS

C

COMPANY NAME: Computer Modelling Group Ltd. (CMG)

T: 403.531.1300 F: 403.289.8502 E: cmgl@cmgl.ca WEBSITE: www.cmgl.ca

If you're optimizing tight oil projects with a drilling rig, you're leaving money on the table.

Use CMG Software to maximize your reservoir exploitation and determine optimal...

• number of wells, • well placement, • size and number of frac stages, • well configuration.

CMG. Unconventional Simulation.

Calgary: +1.403.531.1300 Houston: +1.281.872.8500 email: info@cmgl.ca web: www.cmgl.ca

28 PROFILER

KUDU InDUstrIes KUDU InDUstrIes

Technical excellence, highest standard of service make KUDU a market leader in artificial lift

UDU Industries is a Canadian manufacturer widely recognized for its Progressing Cavity Pumps (PCP), and related products and services. Headquartered in Calgary, KUDU was founded in 1989 by Robert and Ray Mills, whose dedication to quality, performance and technical excellence is the cornerstone of KUDU’s success.

Committed to advancing PCP technology, KUDU prides itself on delivering the highest standard of service in the field of artificial lift, and to optimizing production by providing safe, reliable products. The industry leader in developing elastomers for use in aggressive conditions and elevated temperatures, KUDU has engineered its PCP systems to handle the demands of heavy, medium and light oil, as well as for coalbed methane and dewatering applications. KUDU’s approximately 275 employees provide a global distribution network to clients in Canada, the United States, Russia, Romania, Kazakhstan, Oman and Australia.

KUDU has been active in southeastern Saskatchewan since the company’s early days. Now, KUDU is very busy serving clients all over Saskatchewan, many of whom are focusing west of the third meridian. “A lot of different zones are being developed in central Saskatchewan that haven’t been touched before, and the activity level is higher as a result,” says KUDU Canada new business development manager Ted Tryhuba. “We are now able to go into horizontal wells, right down to the liner, with new technology. We are the

formation-to-formation. It’s our guys having the experience to be able to do that successfully.”

“Top Tag is one of our latest innovations,” Tryhuba says. KUDU’s patented Top TagTM system is the first engineered Progressing Cavity Pump Top Tag, which locates the rotor inside the stator without using a bottom tag bar.

It reduces costs by allowing a paddled rotor to agitate the fluid within the casing, instead of being limited to the fluid entering the tag bar.

Using a Top Tag will decrease the number of burnt pumps due to plugged pump intake because the rotor continuously clears the stator intake, reducing rotor breakage since the rotor is never run in compression on the tag bar.

An excellent choice for producing highviscosity and sand cut wells, Top Tag increases pump run life, improves wellbore agitation, increases fillage and intake access, and is suitable for limited sump applications.

The exposed rotor in the annulus increases wellbore agitation and gas break out, and there is more mixing of sand and oil. Top Tag simplifies trouble-shooting and is reusable— it can easily be removed and installed on a replacement stator. It can be re-threaded, if required, and if worn, the Top Tag plate can be replaced instead of the entire collar.

In Saskatchewan, Top Tag has been used for heavy oil in the Lloydminster area, with 3,000 systems now installed. “It helps PCPs to easily handle a variety of conditions and it reduces restrictions,” Tryhuba says.

FAst FACts

K

leaders in elastomer development and light oil, which is challenging for PC pumps, as well as aromatics. We apply the right elastomer to a range of different grades of oil and well conditions. Our 204 elastomer has been run successfully in up to 45 degrees API oil. In the Estevan area, we are one of the only ones with this elastomer selection.”

While PCPs remain a cornerstone of KUDU’s business, through research and development the company has widened its product base. Among the most popular products is KUDU’s PCP Well Manager, an innovative system designed to maximize performance in PCP wells.

KUDU’s smart-well technology seeks out and detects hidden production points to ensure your well is always running at optimum levels. The PCP Well Manager provides the ability to pump more aggressively, for increased fluid production. The PCP Well Manager optimizes production by measuring flow rates, adjusting pump speed, and measuring torque. It logs data in real time and allows you to view and make changes remotely.

The PCP Well Manager eliminates fluid level monitoring problems and increases overall production by keeping the fluid at or near the pump. The system sustains optimum inflow by maintaining the lowest bottom hole pressure possible. Its ability to pump over capacity allows the system to quickly recover from downtime.

“We can control the wellbore better through our PCP Well Manager,” says KUDU area manager for Canada Darren George. “We can go deeper and we can go lighter for the same pump off control. We can pump oil up to 45 API successfully; that’s pretty huge…. A lot of what we have is application history and experience—being able to apply the right combination of products for optimum results.

It’s so vast. It’s well-to-well and

COMPANY NAME: KUDU Industries

MARKETING MANAGER: Jennifer McMurty

T: 403.203.9896 F: 403.279.2192 E-MAIL: jennifer_mcmurty@kudupump.com

WEBSITE: www.kudupump.com

PROFILER 3

At Your Service Helping you get the most from your well is KUDU’s top priority. Whether the concern is production, efficiency, troubleshooting or training, partnering with KUDU gets results. A custom well plan prepared by one of our PCP technical specialists ensures you get the best fit.

With over 20 patents using Progressing Cavity Pumps in the artificial lift field, KUDU offers the most innovative Progressing Cavity Pump options in the artificial lift industry. KUDU’s revolutionary Tough CoatTM rotors offer

superior abrasion resistance compared to standard chrome rotors. Our complete thermal package is capable of withstanding temperatures up to 350°C, perfect for SAGD and CSS. Not only does KUDU pump it up and take the heat, but we ensure you get the most from your well, everytime. www.kudupump.com

Alberta Export Award Winner for Oil and Gas Manufacturer Calgary Manufacturing Industry’s Best Employer for Medium Sized Manufacturers.

Bringing Solutions to Surface

30 PROFILER

LogancompLetion Logan compLetion systems systems inc.

inc.

Logan Completion Systems advances multistage fracturing technology ou can reduce your well costs, improve production and maximize your profits with MultiStim Fracture Isolation Systems, brought to you by Logan Completion Systems Inc. An innovative oil and gas service company active in Canada and the United States, Logan Completion Systems provides high-quality equipment and services to the unconventional oil and gas fracturing markets, along with a comprehensive line of completion products (including completion and well construction products). In addition to high-quality equipment, what sets Logan apart is its focus on ensuring 100 per cent customer satisfaction through the integrity and reliability of its people.

In 2010, Logan International acquired the Canadian firms Source Energy Tool Services Inc. and Complete Oil Tools Inc. In 2011, the two wholly owned subsidiaries merged. Logan Completion Systems, which is headquartered in Calgary, complements Logan Oil Tools and Dennis Tool Company in Logan International’s downhole tool segment, and enhances offerings to Logan International customers by combining product and service offerings to the Canadian market. multistim Fracture isolation system Logan Completion Systems’ proprietary multistage fracturing technology, used in horizontal wells in oil and gas plays, is unique in the marketplace, according to Logan president Andrew Buzinsky. Logan’s fracture isolation technology facilitates the removal of the balls and seats post-fracturing, leaving a fully open wellbore that increases production flow capacity and allows easier downhole intervention without the need for costly and debris-creating milling or drilling of seats.

Most of Logan’s competitors leave the seats in the well and produce the well with these restrictions remaining in place. “The problem is that you have a number of these ball seats restricting the full production potential of the reservoir,” Buzinsky notes.

“Our competitors recommend to clients that they destroy the ball seats by drilling them up, or, alternatively, to simply leave them in place.

But the problem in the drilling process is that

you convert all of those ball seats into debris that contaminates the wellbore and, in some cases, reduces the production rates achieved from the well.”

Logan Completions Systems’ MultiStim Fracture Isolation Systems have been particularly designed for multistage fracs, featuring valves with fully retrievable seats post-fracturing via threaded tubing—without milling or drilling. Rather than drilling up the balls and ball seats, MultiStim removes the ball seats from the sleeve and can either bring them back to the surface or leave them at the bottom of the wellbore. The advantages, Buzinsky says, are time savings and the reduction of debris created in the drilling process. “With our system, you have the option of removing the seats with fewer problems and quite a bit less debris. It really gives customers more options in how they want to produce their well.”

The technology, which has been used throughout western Canada, primarily in the Bakken and southwestern Saskatchewan, has been well-received in the 1.5 years since it was introduced to market. growth in saskatchewan Logan has been heavily involved in Saskatchewan for years through Source Energy Tool Services, which operated three stations in Saskatchewan in Estevan, Kindersley and Lloydminster. Logan continues to grow and develop these three stations in order to find new markets for its products and applications in these regions.

“Saskatchewan and the Bakken are a key part of our growth strategy,” Buzinsky says.

“With our product development group in the U.S. as well as a small engineering group in Canada, we continue to develop new products for these reservoirs, particularly ones in Saskatchewan.”

Target markets are located in plays that include the Williston Basin, the Bakken, Kindersley, Lloydminster and others. Logan operates locations across western Canada in Grande Prairie, Edmonton, Lloydminster, Bonnyville, Brooks, Red Deer, Kindersley and Estevan.

Part of Logan’s growth will also involve attracting and retaining new talent. “We’re getting more involved with communities so that people understand we are here to stay,” Buzinsky notes. “We’re also working very closely with educational institutions to develop career models for people—so they know we’re not just a stopping place in their career, and they can come here and find it as a home.”

Logan is currently looking for good people of all skills sets. The biggest challenge, according to Buzinsky, is going to be field staff. The company is seeking workers with experience with subsurface equipment and downhole tools.

“I think if we get past this little economic dark cloud in the next few months, things look pretty positive for the energy industry and for Logan,” Buzinsky says. “We have a very aggressive growth strategy for the company for the next two years and Saskatchewan is playing a key role in that.”

Logan focuses on being innovative as an organization, not only in its equipment design, but also in how it does business.

Logan’s core values are safety, quality, innovation, integrity and reliability, which the company focuses on to drive its growth strategy. By following its core values and focusing on 100 per cent customer satisfaction, the company believes it will achieve profitable growth well into the future.

Fast Facts

Y

COMPANY NAME: Logan Completion Systems Inc.

VICE-PrESIdENt, SALES ANd MArkEtINg: Todd Atkinson

tOLL FrEE: 1.888.4TOOLTEC

t: 403.930.6810 F: 403.930.6811 E: tatkinson@logan completionsystems.com

Source Energy Tool Services is now

Logan Completion Systems

MultiStim Fracture Isolation Systems

Multi-Stage Fracturing with Removable Ball Seats and Shiftable Sleeves Logan Completion Systems’ MultiStim Fracture Isolation System - an innovative multi-stage completion technology - is especially designed for producers who are tackling multi-stage fracs. The MultiStim Fracture Isolation System features one-trip installation for faster completion times and frac valves with fully retrievable seats post-fracturing via coiled or threaded tubing…without milling or drilling! Use of the full-bore inner diameter - the key feature of the MultiStim System - 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 of the entire wellbore. Fractures can be controlled from toe to heel for selective fracturing, testing, producing, and restimulating throughout the life of the well. The MultiStim Fracture Isolation Liner System and MultiStim Cup Frac Tool System (a straddle cup system) are suitable for use in sandstone, carbonate, shale, coal, and other naturally fractured formations.

Logan Completion Systems offers a comprehensive line of completion products: • Retrievable & Permanent Packers • Service Tools • Liner Hangers • Thermal Liner Hangers • Casing Patches • Flow Control • Open Hole Packers • Mud Motors • Custom Tool Design & Development

Reduce well costs, improve well production, and maximize your profits with MultiStim Fracture Isolation Systems. Contact us for more information.

635 8th Avenue Southwest, Suite 850 | Calgary, Canada T2P 3M3 | 403.930.6810 | Fax 403.930.6811 www.logancompletionsystems.com

32 PROFILER

PARADOX ACCESS SOLUTIONS INC. PARADOX ACCESS SOLUTIONS INC. Solving accessibility problems for industries across Western Canada

P

aradox Access Solutions Inc. was

by looking at a variety of alternative

ENgINEERED PIPELINE CROSSINgS

founded in 2004 by Marc Breault with a

materials. These include:

Paradox’s pipeline crossing equipment has been designed and built to service the

mandate to introduce new access technologies to mitigate industries’ environmental

Emtek Mats—an extremely strong

pipeline industry. Paradox’s pipeline

impact. Paradox provides solutions that are

engineered mat that is half the weight of

crossings have been engineered to support

cutting edge and cost-effective while

traditional three-ply oak mats. The

up to 120,000 pounds and can be hauled

maintaining stringent schedules.

manufacturing process minimizes

and put into position in one lift. This design

increased weight due to water absorption,

allows for crossing of pipelines which would

costs, starting out with rubber mats to

resulting in reduced transportation costs.

require open air or clay lift to mitigate

reduce trucking costs, which is the biggest

Emtek mats are also two times as strong

vibration or crushing of pipe in the ground.

expense in terms of any matting project.

as traditional three-ply oak mats. The

“We were looking for alternatives to wooden

engineered torsion rod system increases

NEOwEb®

mats, which can absorb up to 100% of their

strength and flexibility, reducing replace-

Through the process of researching and

weight in water, equating to higher freight

ment costs.

designing new matting materials, Paradox

The first challenge was to minimize project

obtained a product called Neoweb®. In 2009,

cost,” Breault explains.

ATR™ (All Terrain Road) mats have been

Paradox was awarded the exclusive Canadian

since its early inception as a start-up

designed for muskeg applications,

rights to Neoweb®, a cellular confinement

business offering access consulting. The

typically with engineered technology. The

system (geocells) based on Neoloy™

company now employs more than 60 people

ultimate portable working road mat

technology. Neoloy technology is a new

and operates depots throughout Alberta and

combining aerospace technology and

polymeric alloy with long-term durability that is

Saskatchewan. Paradox works with leading

composite engineering, ATR mats allow

setting the standard for durable, sustainable

institutions worldwide on product research

users to do a true load transfer without

soil reinforcement solutions. This new

and development.

shearing the muskeg.

generation of geocell is developed and

Paradox Access Solutions has evolved

manufactured by PRS, the world’s leading

Paradox provides comprehensive, Easily transportable Recycled Rubber Mats

supplier of cost-effective ground stabilization

assistance for access and environmental

are made from a newly developed matting

solutions, and the largest producer of 3-D

solutions through planning, designing,

material that provides minimal ground

cellular confinement systems. Neoweb®

engineering, installation and support—with

disturbances. Unlike wood mats, they do

improves the performance of infill materials,

the ultimate goal of total customer

not use nails, which can puncture truck

while increasing the bearing capacity of varying

satisfaction.

and equipment tires. Rubber mats are

road applications. Neoweb® offers high-

more durable and are non-slip, resulting in

performance and design life and is designed

Paradox provides a wide variety of access products to the customer. “We are extremely

a safer working environment. Ideally

proud of the products we offer,” Breault

practical for matting needs when using

says. “The quality, accessibility and

tracked equipment.

sustainability aspects are second to none.

To fully comprehend the scope of our

Bamboo Mats, imported from overseas,

product’s capability, it is beneficial to get a

are extremely strong and lightweight. They

basic understanding of each one.”

minimize water absorption, significantly reducing transportation costs. Bamboo

ENgINEERED mATTINg

has a higher tensile strength than steel.

Over the years, Paradox has worked hard at researching bamboo, rubber matting, crane

Rig Mats, constructed from steel and

mats and steel rig mats.

wood, have been designed for sturdiness,

Industry practices have changed dramatic-

with engineered lifting lugs. There are

ally in recent years as a result of environ-

different designs and wood materials

mental concerns. Because of this, Paradox

inserted into the rig mats. The wood

has seen a huge growth curve in the use of

products inserted into the mats can

matting in order to mitigate environmental

dramatically affect the quality

impact. Paradox continually challenges itself

and strength.

FAST FACTS

end-to-end consulting and customer

COMPANY NAME: Paradox Access Solutions Inc.

BUSINESS DEVELOPMENT: Jared Durand

TOLL FREE: 877.MUD.UGLY (683.8459)

T: 780.418.1955 F: 780.418.2259 E: info@paradoxaccess.com WEBSITE: www.paradoxaccess.com

PROFILER

“We only require the use of local infill material, Which minimizes our transportation costs substantially. this offers a huge cost and environmental savings.”

— Marc Breault, founder, Paradox Access Solutions Inc.

to meet the needs of today’s transportation and municipality infrastructure requirements.

“Neoweb® has been proven in Canada [meeting temperature extremes ranging from -70 degrees Celsius to +70 degrees Celsius] and is being well-received in the industry,” says Breault. Paradox has been working with this material for the past two years, first in Fort McMurray on heavy-haul roads and tailings ponds, and later as a replacement for matting required for teardrops, leases, road access and other applications. “Neoweb® can reduce the amount of material used to build roads—and make it even stronger than the traditional build,” Breault says, noting that Neoweb® has the ability to build heavy-haul roads designed to carry the weight of 797 heavy-haul trucks (which can carry 1.4 million pounds loaded).

Neoweb® is a cost-effective, economical and stable product that gives Paradox the ability to provide long-term solutions. “Neoweb® is the alternative solution for matting requirements,” asserts Breault—“because it minimizes the need for trucking. We can haul the equivalent of 40 Super B trailers of matting on one truck, reducing transportation costs substantially.

We are always researching and developing solutions to assist industry’s access challenges,” Breault says. “We are the access experts.”

33

34 PROFILER

ROyaL WELL SERVICING LTD. ROYAL WELL SERVICING LTD.

Flexibility makes Royal Well Servicing a customer choice ilwell service company Royal Well Servicing Ltd. has a proud 15-year track record of serving the Saskatchewan market.

Royal’s niche is in the heavy oil and shallow gas sectors of eastern and northern Alberta and west-central Saskatchewan. The company maintains all of the auxiliary equipment required to service heavy oil wells to a depth of 2,500 meters and shallow gas wells to pressures of up to 10,000 kilopascals. Royal’s customer base ranges from small, independent producers to major heavy oil producers in Alberta and Saskatchewan. The company carries out approximately 85 per cent of its operations in Saskatchewan with a satellite operation based out of Peace River, Alta., where the company is currently running two rigs.

“Our fleet has typically worked in northwestern Saskatchewan, as far east as North Battleford, south to Kindersley, north of Pierceland and across the border into northeastern Alberta. We see nothing but continued growth in this area, as well as expansion into areas which typically had very little oil activity until recently,” says Royal Well Servicing operations manager Dick Polinsky.

“What makes us unique is that we are of a significant size, yet still independently owned.

We are very flexible when it comes to meeting our clients’s needs.” This is a bonus to customers, he notes, because you only need to go through one or two people to get an answer. There is no board of directors to approve any changes in equipment or personnel, and so decisions are clear, local and typically prompt.

Incorporated as a private Saskatchewan company in 1997, Royal Well Servicing began oilwell service operations with two service rigs operating out of Turtleford, Sask. Company owner Ken Parohl purchased his first service rig in 1997, when there was a shortage of service rigs in the Lloydminster heavy oil sector. Parohl purchased the rigs in order to service oil wells that he owned at the time through Nahanni Oil & Gas—and he hasn’t looked back since.

Royal Well Servicing expanded its fleet to seven rigs in 1998 and became incorporated as an Albertan company that year. In 2001, Royal moved its head office to Lloydminster, Alta. By the end of 2006, the company expanded its fleet to 12 single tubing/double rod rigs. It’s now in the process of expanding further with a slant rig division of three state-of-the-art heavy oil slant service rigs, which the company expects to be fully operational by early to mid-2012.

Royal has worked to be environmentally friendly for the past several years. In 2004, the company began implementing a “green” philosophy by converting its rigs and auxiliary components engines to electronic, lowemission diesel power. All subsequent additions to the fleet have followed this philosophy.

At Royal, there is always room for expansion; the company is continually looking for an avenue to better meet clients’s needs.

“If that means adding to the fleet, we’ll do that,” Polinsky says. “We are constantly seeking new ways to accommodate our clients’s needs in relation to equipment, safety and environmental responsibility.”

Currently, Royal is looking to equip its service rigs with continuous rod injectors on all-wheel drive TMX units to better serve clients’s needs. It is one of only a handful of companies with an accelerator and continuous rod injectors.

One major challenge for Royal Well Servicing is meeting its ongoing goal of hiring and retaining first-class employees. In order to meet this goal, Royal has been using the Canadian government’s Temporary Foreign Worker Program, with outstanding results.

“It’s been a blessing—they’re great,” Polinsky says. (Royal’s core group of employees, consisting of drillers and rig managers, are long-term employees who have typically been with the company for up to 10 years or more.)

“Another major challenge has been to ensure that our work sites are absolutely safe for our employees, the public and the environment. To help accomplish this, our entire Health, Safety and Environmental

(HS&E) Program has been given a complete overhaul in the past six months, and we will continue to be proactive in the future.”

Royal is totally committed to safety. Since it operates across provincial boundaries, Royal Well Servicing maintains Workers’ Compensation Board (WCB) accounts in both Alberta and Saskatchewan, and has developed its HS&E program to comply with occupational health & safety regulations in both provinces.

Royal Well, which is a member of the Canadian Association of Oilwell Drilling Contractors, holds a current certificate of recognition in Alberta (Partners in Injury Reduction program), as well as a certificate of achievement from Worksafe Saskatchewan/ Saskatchewan WCB, and a certificate of accomplishment from Worksafe Saskatchewan/Saskatchewan WCB for its Return to Work Program. “All of our equipment is 100 per cent engineered and certified; all certifications and inspections are current. We follow industry-recommended practices to the letter.”

Royal Well Servicing is busy these days in both Saskatchewan and the Peace River region. “The growth up there is unreal too,” Polinsky says.

Royal’s Peace River operation can be reached by calling (780) 624-3448. You can obtain 24/7 dispatch options for Royal Well Servicing by calling (780) 808-2333.

FAST FACTS

O

COMPANY NAME: Royal Well Servicing Ltd.

OPERATIONS MANAGER: Dick Polinsky, C: 780.205.0742 E: dpolinsk@telus.net

FIELD SUPERINTENDENTS: Raymond Broadhead

C: 780.205.0741 E: r.broadhead@live.com Frankie Shewchuk

C: 780.205.4857 E: frankieshew@sasktel.net

lloydminSter:

780 808 2333

peace river:

780 624 3448

raymond Broadhead:

780 205 0741

SpecialiStS in heavy oil Servicing • 12 mobile vertical service rigs to 2500m • 3 mobile slant service rigs to 2500m • continuous rod injectors TMX and rig mounted • member CAODC and Alberta/Saskatchewan OH&S compliant

Frank Shewchuk:

780 205 4857

36 PROFILER

SASKTEL SASKTEL

The oil industry’s communications network

askatchewan Telecommunications Holding Corporation (SaskTel) is the leading full-service communications provider in Saskatchewan, operating one of the most extensive telecommunications networks in Canada.

“It is our intention to provide complete business solutions anywhere in the province, based on our customers’ business needs,” says SaskTel business solutions client technology manager, Richard Redekop. “Our network is built on redundant fibre optic rings through out the province. It is from that foundation that we have the ability to extend our network to remote areas with multiple technologies including wireless and DSL.” SaskTel has more than 1.4 million customer connections, including 568,000-plus wireless accesses, 528,000 wireline network accesses, 230,000 Internet accesses and 85,000 Max™ (TV) subscribers. SaskTel offers a wide range of communications products and services including data, Internet, entertainment, security, cellular, wireless data, directory services, co-location and hosted data centre services. In addition, SaskTel International offers software solutions and project consulting around the world.

SaskTel finds partners with core competencies that enhance its own, and over the years has developed strong business relationships with private enterprise, with the goal of building complete solutions for its customers.

These partners build on SaskTel’s network in order to reach the province’s most remote areas extending the SaskTel network even further. “A partnership that has benefitted the oilpatch in Saskatchewan is SaskTel’s business relationship with Comtech.

Comtech’s experience in the oilpatch with ‘last mile wireless technology’ and its ability to provide ‘turnkey’ SCADA [supervisory control and data acquisition] solutions, is a perfect fit.”

Basic telephony is a hosted service that SaskTel can provide at a very high level of availability. SaskTel also provides hosted

services with the infrastructure in place to host customer applications, as well as server and data centre infrastructure. Cloud services such as infrastructure and applications as a service are a couple of examples.

“Companies have come to us for those business needs. Managing networks, telecom systems and applications is not their core competency, that’s ours. These companies choose to have their scarce resources focused on their core business.”

Cloud services are a hot new technology trend that many companies want to be a part of. For SaskTel, “it makes sense that we would embark on providing cloud services, because cloud services rely so heavily on a good fibre-based wide area network [WAN],” Redekop explains.

“We have applications such as Hosted Microsoft Exchange and Hosted Contact Centre that we can provide for customers—or, we can provide infrastructure such as servers and storage where customers can take advantage of our hardened data centre facilities.”

It is also evident in the oilpatch that high availability of data and systems is becoming more important to efficient and profitable operations. “Our ability to help customers with business continuity and disaster recovery planning is another core competency,” Redekop says. “Having the network in place that we do, where we can provide network architecture strategies, results in the business continuity that customers require.

Better connectivity means less downtime and increased production.”

SaskTel works very hard to meet the needs of the oil and gas industry, which requires considerable bandwidth to meet all of its data and communication needs. “We believe that our network is the strength we can leverage for oil and gas companies,” Redekop says. “The more bandwidth we can

get to these companies in smaller, more remote areas, the better. That seems to be a very common need as more intelligent devices are placed further out in the field.

Again, better connectivity means less downtime and more production.”

To meet these challenges, SaskTel has made it a priority to build its fibre optic and wireless infrastructure, so that it reaches even further into remote areas. “We believe our network is fundamental for any opportunities or requirements an oil and gas company might have for their data and communications needs.”

Our oil and gas customers need to be able to take their in-office business applications and have them at their fingertips when they work in the field, which allows for increased productivity and reduced downtime. To meet this need, SaskTel has been working hard over the last couple of years to build up its latest 4G network. “We’ve given the oilpatch in Saskatchewan the highest priority in terms of coverage,” Redekop says.

And the network evolution continues.

Beginning in 2012, SaskTel will continue to build on the next phase of its wireless mobility capacity with its LTE (long-term evolution) platform, starting out in Saskatchewan’s highly populated areas, followed by roll-out to more remote areas, as time goes on. “LTE will augment this whole idea of more bandwidth being available to more remote locations—getting faster speeds out to the edges of the network.”

FAST FACTS

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COMPANY NAME: SaskTel

Client Technology Manager, SaskTel Business Solutions: Richard Redekop

T: 306.931.6049 F: 306.931.5818 E: richard.redekop@sasktel.com WEBSITE: www.sasktel.com

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Technology is changing at an exponential rate, each day giving us amazing new tools to make our lives easier, more efficient and more enjoyable. Integrating all these new technologies can be confusing, complicated and costly. SaskTel has the Experts you need to work with you every step of the way from planning to implementation. SaskTel makes it easy for you to stay up-to-date today, tomorrow and for as long as you need.

Contact your SaskTel Representative | 1-800-SASKTEL | sasktel.com

38 PROFILER

SkyHigH—A diviSion of Sk SkyHigH—A diviSion of SkywAy cAnAdA

Solutions you can trust: scaffold sales, rentals and service kyway Canada has been safely supporting its customers since 1967.

SkyHigh—a Division of Skyway Canada is a trusted provider of safe, cost-effective scaffold and shoring solutions across western Canada and Ontario. Skyway is a single-source solutions provider offering scaffolding, swing stage and shoring, engineering, design, erection and dismantling services, project management and control, and cost-control and billing systems. Tailored management solutions can be integrated with clients’s internal systems, ensuring accuracy, efficiency and timely reporting.

“Our approach is to develop the right solution for every project, to ensure safety, production efficiency, cost-effectiveness and on-time completion,” says Skyway Canada president and chief executive officer, Gary Carew. “What makes us unique is our experience and expertise in the design, engineering, delivery and maintenance of our systems. We have set the highest industry standards for safety and quality. We are a safe company—not just a company with a safety manual. Our vision for this company is to be the safest, smartest scaffolding company in Canada.”

The company, which is Canadian-owned and operated, has 165 full-time employees and 1,100 employees in the field, with Skyway branches in Toronto, Sarnia, Thunder Bay, Edmonton, Calgary, Bonnyville, Whitecourt and Grande Prairie, and SkyHigh branches in Saskatoon, Regina, Winnipeg, Brandon and Edmonton.

Skyway Canada was established in Toronto in 1967 in order to supply contractors and the commercial market in southern Ontario.

In 1996, Skyway expanded to Sarnia in order to better serve Ontario’s industrial market, and, in 1998, the company established itself in Alberta. In 2005, Skyway acquired SkyHigh Scaffold in order to expand its operations into northern Ontario, Saskatchewan and Manitoba. In Saskatchewan and Manitoba, the company now operates as SkyHigh—a Division of Skyway Canada. “SkyHigh Scaffold had built a good reputation with the SkyHigh name,” Carew explains, noting that these acquisitions have provided Skyway Canada with a strong market presence from Ontario through to Alberta.

SkyHigh is currently supplying all of the scaffold labour and all materials for the Consumers’ Co-operative Refineries Limited (CCRL) expansion in Regina. SkyHigh was chosen as the scaffold contractor of choice thanks to its Track-RITE system for managing cost, schedule and productivity, Carew says.

Skyway’s proprietary Track-RITE Project Control System keeps labour and equipment costs and worker productivity in plain view on a real-time basis, so expenses and project progress can be reviewed daily.

With Track-RITE, every scaffold build is uniquely identified and tracked in a database, so the customer maintains complete visibility over every aspect of the project. On repeat jobs, such as annual maintenance shutdowns, Track-RITE’s data mining capacity is particularly valuable. When the next scheduled event approaches, it’s easy to go back to the data to compare previous and actual estimates, and obtain solid information with which to plan the next project.

In Alberta, Skyway and SkyHigh are focusing on oilsands opportunities, and in Saskatchewan, on opportunities associated with potash mine expansions. “Oil-based opportunities are going to start to take off in Saskatchewan as well,” notes Skyway Canada vice-president, business development, Terry Haunn. “Saskatchewan is going to enjoy a very robust economy for the next three to four years.”

Because of this, SkyHigh is putting resources into place in Saskatchewan in order to better support industry and contractors.

As projects in Saskatchewan and Alberta heat up, one of the major challenges the company is now facing is the requirement for additional labour. It’s looking for workers to help support. “Bring the skills we need to the company and we’ll support you, empower you and help you grow your career,” Haunn says. “We want SkyHigh to be the place to work for scaffolders—we want people to come and develop a career here. We’re making SkyHigh a great place to work. We believe in open, honest communication, and we treat them well.”

SkyHigh is also seeking to recruit people from other provinces and countries as its manpower requirements increase.

In addition, the company has formed strategic alliances with a variety of other contractors in order to provide a complete range of services to large industrial plants.

SkyHigh/Skyway combines its services with mechanical and insulation contractors in order to form a comprehensive team.

Skyway’s Strategic Alliance Services bring together best-in-class organizations representing the complete breadth of industrial specialization, ensuring that a true single source solution is available to customers.

SkyHigh—a Division of Skyway Canada.

Solutions you can trust since 1967.

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COMPANY NAME: Skyway Canada Limited

VICE-PRESIDENT, BUSINESS DEVELOPMENT: Terry Haunn

T: 780.413.8007 F: 780.413.8012 E: terry.haunn@skywaycanada.ca WEBSITE: www.skywaycanada.ca

kywAy

40 PROFILER

SPT GROUP SPT GROUP

Streamlining workflow with SPT Group

PT Group provides a complete and unique platform for flow simulation technology and competence, with essential steady-state and dynamic software tools for optimizing oil and gas production systems, from design through to operations. In February 2010, Calgary-based Neotechnology Consultants (Neotec), a longstanding provider of leading global steadystate multiphase flow modelling software, was acquired by SPT Group of Norway, the world leader in dynamic flow modelling. The acquisition was intended to take full advantage of the close synergies between the two companies, says SPT Group senior vicepresident, steady-state, Steve Smith.

SPT Group, which is focused on dynamic multiphase flow simulation, provides software with a time-dependent element, which is a technical step beyond steady-state flow modelling. Now, the integrated company offers a unique blend of products and services.

“There is no other company that can offer the breadth of flow modelling and simulation that we can,” Smith says.

“As a result of this acquisition, SPT Group now has a Calgary office that offers a full suite of products, from steady-state through to dynamic,” adds Tena McCarthy, sales manager, Canada and Alaska. “Historically, we had only been offering steady-state solutions. We are now able to support the full dynamic portfolio, including services, to our client base.”

In addition to its Calgary office, SPT Group operates nearly a dozen offices globally, all of which have the capacity to deliver full steadystate to dynamic solutions, with both software and services.

“One of the benefits of bringing the two companies together is that we have opened up a much broader capacity in the Canadian market,” Smith says. In its other offices as well, SPT Group has extended its reach: it can now offer the software previously developed by Neotec, as well as the services that accompany them.

“Particularly in Canada, we see this as a strength. Our experience to date is that the onshore market has not yet widely adopted multiphase dynamic simulation, yet their systems

have the same production challenges that any offshore system will have.” For example, prior to implementing a pigging operation, transient simulation of a multiphase pipeline will allow a more detailed assessment of operational risk, debottlenecking, and system capacity constraints by providing an understanding of liquid holdup in the system and how that liquid travels through the system during pigging. Aside from the potential safety and capacity issues, this will also allow the user to define a more efficient pigging schedule. In addition, multiphase transient issues such as liquid loading, common in gas production wells, can be better understood, and production is optimized by using transient simulation to qualify and develop alternative operating scenarios.

SPT Group has dedicated considerable effort to focus on workflow in order to make life easier for the end user. It has built a workflow that allows direct communication from its steadystate PIPEFLO product into OLGA, SPT’s dynamic simulation tool for transient flow modelling. “By building this workflow, we’re trying to encourage industry to think in different terms than they might have done historically,” Smith says. “There is continuity from steadystate design and conceptual work, into the detailed design and operational considerations that can be handled with transient simulation.

As a result of the acquisition, we have been able to tighten the connection between our existing products and create new ones.”

One of SPT Group’s new products is PIPEFLO Dynamic, which pulls some of the traditional dynamic capabilities from OLGA into the steady-state workflow. Released last October, PIPEFLO Dynamic combines elements of both of these technologies to create something new and even more accessible.

In the post-Macondo era, Smith notes, there is a real focus on clearly understanding downhole safety issues and planning to avoid or address challenging situations. Similarly, contingency planning is taking on a new and greater urgency. SPT Group is focused on building the workflow necessary to support the requirement to address these considerations.

These solutions provide valuable input, primarily to the engineering design of planned operations, but also for effective planning regarding concerns with respect to safety and the environment. SPT Group products that can be used for such work include: Drillbench (dynamic drilling and well control), OLGA ABC (Advanced Blowout Control), WELLFLO (steady-state production and drilling), and OLGA for Wells (dynamic production simulation).

Much of the focus, post-acquisition, has been on streamlining workflow to make the best possible tools available to users, with as few challenges as possible. As a result, workflow efficiencies are greatly enhanced. “One of the greatest factors is the time savings in the model building that needs to be done by the user,” McCarthy says. “We have been told by clients that sometimes, when having to rebuild a model in a different tool (moving from steady-state to dynamic simulation), the effort can amount to man-months of additional work.

Being able to export files and share data will provide significant savings in time, and reduce the likelihood of errors being introduced when you are rebuilding models.”

SPT Group’s mission is to deliver unique solutions to increase the value of their clients’ oil and gas projects. “We are very solutionoriented,” Smith says. “Whatever challenges companies are facing with their flow systems, be it downhole in wells or in surface pipeline systems, we are here to work together to help them solve their problems.”

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COMPANY NAME: SPT Group

T: 403.277.6688 F: 403.277.6687 WEBSITE: www.sptgroup.com

Bridging the gap between Steady-State and Dynamic solutions World leaders in steady-state and dynamic modelling The highly skilled professionals of SPT Group have a common goal of bringing state-of-the-art competence and technology to our customers.

SPT Group Office

SPT Group is the world leader in steady-state and dynamic modelling for the oil and gas industry providing a range of software and consulting services within multiphase flow and reservoir engineering. We develop and market OLGA速, Drillbench速, MEPO速, OLGA速 Online, PIPEFLO, PIPEFLO Dynamic, WELLFLO and FORGAS; products and solutions that maximize value for engineering and operations through the entire field development lifecycle.

Providing practical expertise from our services group and bringing our technology into a dynamic on-line production support system plays significant roles in the SPT Group business model. This maintains the communication between software users and developers - conveying practical understanding of market demand.

For more information: +1 403 277 6688 info@sptgroup.com / www.sptgroup.com

SPT Group provides highly skilled professionals worldwide to support development and engineering services within multiphase flow and reservoir engineering.

42 PROFILER

STEP EnErgy SErvicES STEP EnErgy SErvicES

Pushing the coiled tubing envelope

TEP Energy Services is a privately owned, technically focused oilfield service company that provides specialized coiled tubing units and associated pumping and support equipment to service the deep horizontal well market in western Canada. “We have taken all the best ideas available today and incorporated them into the operating design for all of our new equipment. Our purpose-built equipment is superior to what is currently available from an operations standpoint, as well as from a safety perspective,” says STEP’s chief executive officer, Regan Davis.

Most coiled tubing service providers are part of larger service organizations. STEP, on the other hand, believes that by being a focused coiled tubing company, it will differentiate itself in the market. STEP combines advanced, purpose-built coiled tubing equipment with a team of industryleading professionals who are focused on delivering exceptional customer experiences.

Founded in March 2011 in Calgary, STEP delivers the expertise required to improve operational efficiencies and productivity in extended reach wellbore designs.

“The primary motivation for the creation of STEP Energy Services was a growing need in the market,” explains company president Bailey Epp, who founded the company together with Davis and Steve Glanville, STEP’s chief operating officer. “We recognized a void in the coiled tubing industry, specifically with changes in the type of wells that are being drilled and the level of service being offered to customers.” Glanville adds, “We had a unique opportunity to start a company which puts to use our expertise.

We have an extensive network of industry professionals wanting to join our team.

There is a genuine desire from these people to be a part of a new company which will redefine how oilfield service is delivered.

These people will be key to our success.”

The company got off the ground when Epp and Glanville, who have backgrounds in coiled tubing operations and engineering, were introduced to ARC Financial Corp. “We are pleased to have ARC Financial Corp. as our capital partner who share the same vision,” states Rob Sprinkhuysen, chief financial officer.

Custom-fabricated in Calgary, STEP’s equipment is fit-for-purpose, including the twin engine fluid pumpers which have been built to support larger coiled tubing or stand-alone pumping treatments with 24-hour, continuous operations. The company’s support services for coiled tubing operations include not only fluid pumping, but nitrogen pumping capabilities as well. “STEP is creating something that really hasn’t been seen before in western Canada in coiled tubing operations. Our equipment has a larger capacity in terms of the length and size of coiled tubing, allowing STEP to work at greater depths with improved efficiencies,” says Epp. During the company’s start-up, much of the initial focus revolved around designing and

FAST FAcTS

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COMPANY NAME: STEP Energy Services

TOll FrEE: 1.855.480.STEP (7837)

T: 403.457.1772 WEBSITE: www.stepenergyservices.com

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“What We ultimately Want to become is the preferred service provider in Western canada.”

— regan davis, chief executive officer, step energy services procuring the next generation of equipment required by industry. The energy quickly shifted toward its employees, who are the key components in the business. As Davis puts it, “We wanted to create a company that was truly different from an employee point of view. The business opportunity was obvious, but it is the ability to capture that opportunity with a truly engaged workforce that is exciting for all of us.

STEP is not revolutionizing the coiled tubing industry—we are evolving the coiled tubing service model. Ultimately, we believe our success will hinge on our people, our business model and the culture of the company.”

STEP’s people strategy is grounded in what STEP calls an ‘exceptional employee experience’ and building a STEP family around that philosophy, explains STEP’s human resources director, Aly Bandali. “It includes a career focus for the people that join our organization, which takes into consideration things like succession, career planning, mentoring and training in areas such as leadership, customer service and safety, as well as supervisor training,” Bandali says. “The overall focus is to engage our employees. We will have a culture where our employees have an authority level that

matches their responsibility level. Our employees will be expected to be accountable for their role in our business and we will empower them to do that.” One of STEP’s target markets is southern Saskatchewan.

“We envision a large part of our workforce being from this province” Davis adds.

“We are going to bring the right equipment to the wellsite and bring the workforce that’s going to give our clients the service that will exceed their overall expectations. What we ultimately want to become is the preferred service provider in western Canada,” states Davis in closing.

44 PROFILER

United CentrifUge Ltd. United CentrifUge Ltd.

Trustworthiness, reliability allow Weyburn-based equipment supplier to grow or Weyburn-based United Centrifuge Ltd., which specializes in oilfield equipment rentals, it’s all about providing the best quality equipment and the best service possible to customers.

Established in 2002 by president Wayne Ebel together with partners Tim Bowers and Ed Lantz, United Centrifuge began operations with five SS1000 centrifuges, operating out of a small shop in Midale, Sask.

To meet the needs of a rapidly expanding oilfield customer base and demand for its product lines, the company moved to Weyburn in 2004 where it opened a new office and repair facility in 2005. Now, just a few short years later, United Centrifuge is Saskatchewan’s largest privately owned and operated supplier of solids control and dewatering equipment, with 15 staff members serving Saskatchewan and Manitoba. The company is currently looking to expand to other locations as well.

United Centrifuge owns more than 100 pieces of equipment, including SS1000 centrifuges, SS2000 centrifuges, E-Z Load Systems, polymer injection tanks, pre-mix tanks, rig matting, cone tanks and shale bins.

The services it offers include dewatering, solids control, underbalanced drilling solids processing, pre-well and pre-project planning, on-site equipment installation and on-site supervision, technical assistance, troubleshooting and 24/7 emergency service. United Centrifuge prides itself on being the equipment provider for the Cenovus underbalanced drilling operation in the Weyburn Business Unit CO2 project.

United Centrifuge’s Weyburn repair facility is fully equipped to perform the minor servicing required for all of its equipment. All major repairs are sent to the manufacturer, United Oilfield Inc., in Airdrie, Alta.

Safety is a top priority at United Centrifuge, which hired a full-time safety supervisor in 2006. Safety is the foundation of the company’s operations and is intended to protect employees, clients, property, the public and the environment. The corporate motto, ‘Be Safety Smart from the Start’ is a

way of life for all staff, who have received up-to-date training in first aid, WHMIS, TDG, H2S, IRP16 and Confined Space.

The company, which is a member of the Saskatchewan Safety Council, HSE Registry Ltd., ISNetworld and ComplyWorks Ltd., received a safety Certificate of Recognition from Enform in 2006 and is registered for Safety Stand Down Week each year. United Centrifuge is also a member of the Petroleum

“We strive to provide the best quality equipment and the best service to our customers.”

— Wayne Ebel, president, United Centrifuge Ltd. Services Association of Canada (PSAC) and the Weyburn Oil Show Board. At the 2011 biannual oil show, United Centrifuge signed on as a member of PSAC’s Community Partners Program, a program designed to strengthen the oil and gas industry’s social license to operate, and focuses worker attention on local concerns related to oil and gas activity with regards to driving safety and environmental concerns.

For United Centrifuge, the key to success lies in its superior service, quality equipment and competitive pricing. Another plus is the strong working relationships the company has established with drilling engineers and contractors, and its excellent reputation for trustworthiness and reliability.

“We strive to provide the best quality equipment and the best service to our customers,” Ebel says.

In 2008, to better serve customers, United Centrifuge developed the E-Z Load Hydra-Lift tank system, which provides a complete dewatering tank system and centrifuge in just one load. The centrifuge can be raised or lowered by the hydraulic arms enclosed in the legs of the main platform. The system eliminates the use of a picker and reduces the number of loads from two to one. This is a

superior solution for a number of reasons, Ebel says—it addresses safety concerns while reducing costs for customers at the same time.

With its compact size, the E-Z Load tank system takes up less room on locations and helps customers save money on trucking costs.

In 2010, United Centrifuge was awarded the Weyburn Chamber of Commerce Weybex Award for community involvement, in recognition of the company’s enthusiastic support for a wide range of community projects.

“We are very proud to have won the Weybex Award. We think it is very important to do what we can to support the community, not only by way of financial support, but also volunteering time to different events” Ebel says.

The company’s main challenge right now is trying to find enough people to do all the work that’s coming through the door. “Labour is always an ongoing challenge,” Ebel notes.

“And with Alberta starting up, our labour pool has decreased. That’s one of our biggest challenges right now, trying to recruit new employees.”

The weather, too, has made things difficult for the oilpatch this past year, but despite the human resources and weather-related challenges, Ebel thinks the industry has a bright future in Saskatchewan. “I think the oilpatch will be good, as long as Mother Nature cooperates.”

COMPANY NAME:

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United Centrifuge Ltd.

SALES MANAgEr: Tim Bowers

SAfEtY SUPErviSOr: Morley Forsgren

t: 306.842.2378 (24 Hours and Emergencies)

f: 306.842.2403 E: unitedcentrifuge@sasktel.net WEbSitE: www.unitedcentrifuge.ca

24 Hour Service

Be Safety Smart From The Start

Solids Control And Dewatering Equipment • Centrifuge • Cone Tanks • Polymer Tanks • Shale Bins

• Dewatering Tanks • Premix Tanks • EZ Load Hydra Lift System 2010 Winner for Community Involvement

Enform C.O.R. Certified www.unitedcentrifuge.ca Phone: (306) 842-2378 Fax: (306) 842-2403 Email: unitedcentrifuge@sasktel.net Shop 1560, New City Garden Road, Weyburn, Saskatchewan S4H 2L5

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PROFILERMAGAZINE.COM

Gibson Energy – Part of Saskatchewan’s Past, Present and Future…

Although Gibson Energy, a premiere North American midstream oil and gas company for over 50 years, is headquartered in Calgary, its roots began (with its first 1953 invoice!) and continue to grow in Saskatchewan.

The brands of Gibson’s affiliates - including Moose Jaw Refinery, Bridge Creek Trucking, Johnstone Trucking and Canwest Propane -are very recognizable to both the business and the non-profit sectors in many Saskatchewan communities.

The Moose Jaw Refinery, which refines and markets a variety of petroleumderived products, including several grades of road asphalt and roofing flux, has been in the Gibson family of companies since 2002. In addition, the refinery produces drilling fluid and fracturing fluid for the oil & gas drilling industry, which are also distributed by truck and rail across North America.

With the recovery of oil prices and the development of shale gas, the demand for both fluids is expected to grow in the future.

Gibson Energy 1700, 440 - 2nd Avenue SW Calgary, Alberta T2P 5E9

www.gibsons.com

Accurately map reservoir properties and book more reserves with Quad Technology

Do something awesome. Think Quad. Get Results.

Sub Surface Evaluation Specialists

www.roke.ca