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Tight oil plays give conventional oil industry new lease on life

PATCHES OF OPPORTUNITY Despite low prices, Alberta gas producers find profitable niches

NEXT-YEAR COUNTRY Land sales provide clue to next Alberta exploration hot spots

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Tight oil plays give conventional oil industry new lease on life


Patches of opportunity

Despite low prices, Alberta natural gas producers find profitable niches


Next-year country

Land sales provide clue to next Alberta exploration hot spots

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Tight oil plays give conventional oil industry new lease on life

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By Darrell Stonehouse


he sun has slowly been seting on Alberta’s conventional oil industry for the last 40 years. Oil production has declined from a peak of 1.43 million barrels a day in 1973 to a trough of around 460,000 barrels per day in 2010. Reserves are being depleted. But things are about to change for the better, according to Alberta Energy Minister Ron Liepert. Pointing to increased implementation of long horizontal wells and multistage fracturing in tight oil plays across the province and new royalty incentives to encourage drilling, Liepert recently told the Daily Oil Bulletin that the government expects incremental growth in the conventional oil output going forward. “For the first time in several years, output is projected to increase and we will now see the industry getting into a growth period,” he noted, before declining to put a figure on how much new oil will be produced. “Nobody can make an accurate prediction, as a great deal

will depend on new technology. Under the royalty changes we made last year, incentives were given for horizontal drilling and multistage fracking, the results of which are now visible. What was deemed as depleted resources is currently highly prospective, with significant chances of being brought out of the ground.” Alberta Energy estimates the province had around 61 billion barrels of original oil in place. Of that, between 25 and 30 per cent has been produced. Remaining established reserves are 1.5 billion barrels. While the provincial government is gun-shy in putting a figure on how much new oil will be added to that reserve base and how much new production will result through the use of the new drilling and completion technologies, industry is much more forward with opinions. Murray Nunns, president and chief executive officer for Penn West Exploration Ltd., says the tight oil revolution that began in the Bakken play in Saskatchewan and gradually moved westward into Alberta marks the dawning of a

new day for the conventional oil production in the Western Canadian Sedimentary Basin. “The basin is undergoing a renaissance, make no mistake about it,” Nunns told delegates at the Canadian Association of Petroleum Producers’ investment symposium in mid-June. “There’s been 100 billion barrels of conventional oil found in Canada and only ­ 20 billion barrels have been taken out through vertical technologies,” he explained. “If you eliminate the carbonate and reef plays [that have higher recovery percentages], only 10–12 per cent has been recovered. With the same reservoirs in the U.S., there is 25–35 per cent recovered. We believe with there’s five to 10 per cent we can recover with primary horizontal technology, and another five to 10 per cent with enhanced recovery using horizontal technology.” In Alberta, the new technology is being used in an increasing number of oil plays. The most advanced plays are the Cardium in


west-central Alberta, the Beaverhill Lake Carbonates near Swan Hills, the Viking in east-central Alberta and at Redwater north of Edmonton, in the Pekisko at Princess in southern Alberta, and at Judy Creek in northwestern Alberta. Emerging plays include the Alberta Bakken in the southern reaches of the province, and in oil windows in the Duvernay and Montney shale.

play. Currently, around 25 per cent of Penn West’s wells have been grouped on pads. By year-end, Nunns said that number is expected to be 75 per cent. “In the appraisal phase costs are 20–30 per cent higher than in development,” he explained. “We’re now in the phase where we are pad drilling with four to eight wells per pad. This limits rig moves, tie-ins, construction costs.” Junior producer Bellatrix Exploration Ltd. is also targeting the Pembina Cardium. Bellatrix boasts 86 net sections of land in the play with 320 drilling locations. Company president Ray Smith tracked the technological evolution of the Pembina play at the company’s annual meeting in late May. “The Cardium is a play that’s been a slow developer. When people first got involved in the

Draining the Cardium Coaxing crude oil out of the ground from the Cardium formation underlying the Pembina oilfield has always been a matter of brute force. The Pembina #1 discovery well, drilled by Socony-Mobil in the winter of 1953, required a fracture treatment consisting of diesel fuel and 3,000 pounds of sand pumped at 1,800 pounds per square inch of pressure to get oil flowing to the wellbore in commercial quantities. Almost 60 years later, oil explorers are still at it, cracking sandstone as deep as 9,400 feet beneath the surface in the hopes of striking pay. Only now the wells drilled are horizontal and stretch as far as a mile through the reservoir. Massive fracture treatments consist of 20 tons of sand—more than 12

days, and they’re levelling out at 150 barrels a day after six months.” At West Pembina, where the rock is tighter, Bellatrix has found that slickwater fracture treatments are more effective. “In each one of the fracture areas, we create an additional 10 or 15 sub-fractures as we’re stimulating the well...and as a result, I think our company has posted the best results that I’ve seen in the Cardium so far this year,” Smith said. Bellatrix has drilled 34 operated wells in the area—13 fracked with oil and the remaining 21 fracked with water. Smith displayed charts comparing Bellatrix horizontal Cardium oil production results after water fracs to the results of the original oil fracs. After six months the water-fracked wells were producing about 130–140 barrels

“When we run that against our finding and development costs and lease operating costs and an $80 flat oil price, we’re looking at a rate of return of 500 per cent.”

times as much as was pumped down hole in the Pembina #1— mixed with specialized fluids. And as many as 20 stages are fracture stimulated one after another along the horizontal leg using on average 10,000 horsepower of pumping might. The size of the prize is huge. The Alberta Energy Resources Conservation Board says the Cardium had 10 billion barrels of original oil in place with around 1.7 billion barrels produced. However, those numbers were derived from historical records from vertical drilling in the play. Penn West estimates the Cardium could contain as much as 15 billion barrels of oil, and expects 20–30 per cent of that oil could ultimately be recovered. In the Pembina Cardium, Penn West has identified more than 2,500 potential drilling locations on around 665,000 net acres of land. Nunns said the company has completed appraisal of its lands in the play, and is now moving to full development. Wells in the play are being drilled with average horizontal legs of 1,400 metres and completed with around 20 fracture stages. Fracture loads average 20 tonnes per treatment. Nunns said the next big economic driver in the Cardium is doing more pad drilling in the

— Ray Smith, President, Bellatrix Exploration Ltd.

Cardium it was basically shorter horizontals, fracked with oil and we slowly started to experiment and optimize to make it better and better,” Smith said. Bellatrix was one of the first to use water-based fracturing fluids, starting last May after drilling 13 oil wells, Smith said. Bellatrix uses two different kinds of water fracks—slickwater and with foam water. “One of the reasons we believe we’re getting significantly better results with water fracking is we don’t put in additional constituents in the fracking fluid that will precipitate out against the formation. Some of the gelling agents in oil-based completion fluids precipitate out and we think that causes an impermeability barrier along the frac face in most cases,” he explained. In one area of Bellatrix’s Cardium pool at Willesden Green, the company uses a foam water frac. “It creates a very long frac face that you can pack with sand to give it maximum conductivity,” Smith said. “In doing that particular frac, we’re finding great results. Those wells are coming on in the 500-barrel-per-day range and are doing 300–350 barrels a day after 30

a day—almost double the rate of the oil-fracked wells, which were levelling out at about 70 barrels a day. Technological advances allowing producers to access more reserves per well, combined with a five per cent royalty holiday for horizontal oil wells, make the Pembina highly profitable, said Smith. “Overall, our reserve adjudicator has given us, on all of the wells we’ve drilled, an average of 186,000 barrels of oil. When we run that against our finding and development costs and lease operating costs and an $80 flat oil price, we’re looking at a rate of return of 500 per cent,” Smith explained. “Those are stellar economics. One reason why they’re so much better than most people’s is this is legacy land. We haven’t spent ­ $2 million or $3 million per section in buying the land.” Return to Swan Hills The Beaverhill Lake carbonate play in the Swan Hills north of Edmonton is another hot tight oil play in central Alberta. Home Oil Company originally discovered the North Swan Hills field



in 1956. Amoco Corporation and Gulf Oil drilling a total of 17 short lateral-length annual meeting in early June. “And when you’re Corporation discovered the South Swan Hills horizontal wells using new pad drilling looking at new technology—that is the unit in 1959. Combined, the two fields had techniques and increasing the number of horizontal multistage frac technology being around four billion barrels of oil in place. fracture stimulation stages from an average of used on this play—you have to admit that Again, Penn West is a leader in the play, Arcan has spearheaded the development of six to 10 stages. with 200,000 net acres of land and 500 As of March 31, 11 of these wells were in this play.” drilling locations identified. The company is various stages of completion. Seven of the 11 Arcan is spending $135 million this year, of developing the play using 1,400-metre wells have achieved average maximum initial which $44.2 million was spent in the first horizontals with 15-stage acid fracture production rates of 300 barrels per day while quarter. The company plans to drill 20–25 treatments. the remaining four wells are cleaning up after multi-frac horizontal wells at Ethel as well as Nunns described the carbonate play as a fracture stimulation. The six uncompleted wells construction of a pipeline and waterflood long extended platform. Historically, explorers were expected to be completed after the infrastructure. Enhanced oil recovery plans for have targeted reefs on the platform with great conclusion of spring breakup. water injection at Ethel are underway. success. However, sometimes they would “At that same time, we will put three rigs The technology needed to access the tight “screw up and miss the target, but they would back to work in the field and continue that oil in the carbonate play is advancing, Gilmet still find a little bit of oil.” program throughout the remainder of this told shareholders. Nunns said those missed wells are what year,” said J.C. Ridens, executive viceProducers are using a 14-stage fracture explorers are currently targeting in the president and chief operating officer. stimulation program with a retrievable carbonate play. The wells drilled in Evi are all short laterals multi-fracturing tool that allows full wellbore “They’re going out to the averaging about 1,800 feet in platform and following the old length and were stimulated on vertical wells,” he explained. average with 10 frac stages “I expect the juniors will “Not all the old vertical wells had compared to six frac stages oil shows—some were tight—so used in 2010 for that same probably sell off before drilling how much of the platform is length lateral. prospective is unknown.” “The Canadian business unit all the known vertical parts Nunns added with well costs was the first company to drill at $4 million per well, it’s going horizontal Slave Point carbonate of the platform.” to take deep pockets to test the wells in this area, which extent of the tight carbonate provides valuable data for our — Murray Nunns, President and Chief Executive Officer, Penn West Exploration Ltd. play over the long term. continuing drilling program.” “I expect the juniors will The typical Evi well is forecast probably sell off before drilling to cost $2.3 million to drill and all the known vertical parts of the platform,” he complete. The company has 242 future wells access later if needed. More and more acid is explained. “But there is a much bigger prize identified, Ridens said. being pumped in each fracture stage to open up out there. We’re looking at 500 locations that more reservoir. Operators are now injecting as are follow-ups to verticals, and then beyond Cracking the Pekisko much as 1,200 cubic metres of acid per stage. that we’re looking at how you explore the rest The Pekisko fairway runs from southwest The acid treatment is custom designed for the of the platform.” Saskatchewan through Alberta to northeast formation rock. Jet pumps are being used to Penn West reported average rates on the British Columbia and encompasses 210 oil enhance cleanup after the fracture stimulation first 12 wells that it drilled were almost 200 pools. Around 14 per cent of the original to mitigate any formation damage. And barrels per day and several wells were in the 3.8 billion barrels of oil have been produced. multi-well pads are being used to cut costs. 250-barrel-per-day range after three months. The two current major areas of activity are at Gilmet said Arcan has about 600 million The company has drilled a total of more than Princess in southern Alberta and at Judy Creek barrels of original oil in place on its Swan Hills 20 wells into the play to date. in west-central Alberta. lands. The company is investing heavily in Junior producer Arcan Resources Ltd. is Crew Energy Inc. is the dominant player at waterflood facilities to coax as much of that oil another dominant player in the Beaverhill Lake Princess, with over one million net acres to the surface as possible. Gilmet said that he play, with 150 net sections of land and 400 under its control and more than 2,300 expects recoveries of 40 per cent with horizontal targets identified. Its main target is drilling and recompletion locations identified. waterflooding. And further ahead, he pointed the Ethel oil pool on the eastern side of the It has almost 600 square miles of 3-D to a competitor’s pilot test of CO2-enhanced oil Swan Hills field. seismic coverage on the play as well, which recovery that showed the recovery factor could is being developed with a mix of vertical and Since beginning its horizontal program at be increased to 60 per cent. horizontal wells. Swan Hills in late 2009, Arcan has drilled 27 During the first quarter, Crew drilled 20 horizontal wells into the Beaverhill Lake Slave Point carbonates horizontal wells, 14 vertical exploration wells Canadian Forest Oil Ltd. holds roughly 48,000 carbonate, with two wells on the go in the and two (two net) water disposal wells at gross and 41,000 net acres in the Evi light oil second quarter. Princess. The company placed seven play in north-central Alberta. During the first “None of our competitors have drilled horizontal and three vertical wells on producquarter, Forest resumed operations in the Evi anywhere near this number of wells,” Arcan tion, with strong results. area with a three rig development program, president Ed Gilmet said at the company’s

Two wells near Alderson reported production of 420 and 425 barrels of oil equivalent (93 per cent oil). Eleven wells placed on production in December 2010 continue to produce on average 189 barrels of oil per day four months after being placed on production. Current production at Princess is approximately 6,200 barrels per day with an estimated 2,800 barrels per day shut in due to restricted access or awaiting tie-in. For the remainder of 2011, Crew plans to drill 51 horizontal, 20 vertical and 15 water disposal wells in the Princess area. At Judy Creek, Second Wave Petroleum Inc. has a best estimate of around one billion barrels of oil in place on its 88,000 acres of Pekisko lands. It has 700 unrisked drilling locations. The company is currently delineating the Pekisko resource and moving forward with development plans. Like in the Beaverhill Lake play, which Second Wave is also developing with a partner at Judy Creek, acid fracture treatments are being used to develop the Pekisko. The company is using 10–15 stage fracture using 60–100 cubic metres of hydrochloric acid per stage. It is using 100-metre spacing between fracture treatments. Well costs in the play average $2.35 million, with around 155,000 barrels of medium-weight oil expected to be recovered per well. Piercing the Viking A fourth major play taking shape in central Alberta is in the Colorado Group in the eastern reaches of the province. The play started in the Dodsland area of Saskatchewan where Penn West began applying horizontal drilling and multistage fracturing to the Viking formation. “We’re in full-scale development there,” Nunns said. “But the more curious part of the play is to the east and we have 500,000 acres there.” Nunns said Penn West initially thought the Colorado group was gas-prone, making it less desirable given the current price environment. “On closer examination, we found there is a mix of gas and oily gas throughout the area,” he explained. “We drilled 25 test wells last year and what we identified out there is a series of oil accumulations we want to now follow up on.” Nunns said production from the initial wells is higher than in the Viking around Dodsland. “We see it as something for the future,” he added. Private explorer Cutpick Energy Inc. has around 333 net sections of land targeting the

Photo: Aaron Parker


Old oilfields have become hot targets due to new technology.

Viking near Halkirk in east-central Alberta. The company plans on spending $150 million on drilling 70 net horizontal-development Viking wells this year. Since March 2010, the company has drilled 45 net Viking horizontal wells, 41 oil wells and four gas wells at a 100 per cent success rate. Its March estimated production

equivalent a day for the first-month average,” said Bob Chaisson, president and chief executive officer. “Our one-year out average rate is about 35–38 barrels of oil equivalent per day so we’re about 30 per cent higher than, say, Dodsland. “It’s a little bit tighter than it is in Dodsland. In Dodsland you’re looking at four to six metres

“We drilled 27 horizontal Viking wells [in east-central alberta] last year and in 2011 we expect to drill 70 horizontal wells.” — Pep Lough, Vice-President of Finance and Chief Financial Officer, Cutpick Energy Inc.

was about 4,000 barrels per day, 58 per cent oil and liquids. “We drilled 27 horizontal Viking wells there last year and in 2011 we expect to drill 70 horizontal wells,” said Pep Lough, vice-president of finance and chief financial officer, adding that virtually all capital spending will be in the Halkirk area. Cutpick’s Viking oil fairway features high-quality 35-degree API sweet oil. So far this year, the company has drilled 18 wells in the area and fracked 14. “We’re drilling 1,100-metre wells...but they’re coming on at 150 barrels of oil

of pay and about 18–20 per cent porosity. Where we are, we’re looking at 14–16 metres of pay and about 12–14 per cent porosity,” he added. “There is liquids-rich gas, but we are focusing only on the oil.” Chaisson said the company may drill a couple of gas wells this year to establish liquids rates and to test the general performance of the wells. “In September of ’09 we did our first deal in here,” he said. “What we didn’t want to do was go in and drill a horizontal well here as soon as we had that first deal because as soon as you drill that first one, everyone is all over you.”


Photo: Joey Podlubny

Patches of opportunity


Despite low prices, Alberta natural gas producers find profitable niches By Darrell Stonehouse


all it a cascading disaster. First came Ed Stelmach’s royalty maladjustment, making Alberta’s natural gas industry uncompetitive with booming British Columbia. Then came the Great Recession of 2008, decimating gas demand and resulting in a deep dive in natural gas prices. And, finally, the shale gas boom in the United States, ensuring plentiful supplies south of the border and destroying export markets. The last three years have been anything but kind to Alberta’s natural gas producers. But despite the hard blows, patches of opportun­ ities remain. And many explorers are positioning themselves for gradual market improvements in the future. The Deep Basin of west-central Alberta is one area where gas producers remain profitable despite current markets. Aided by natural gas liquids (NGLs) production and royalty incentives, drilling is still going full speed ahead in the region. The Deep Basin is being targeted in two distinct play types. The first is exploiting the stacked zones of the Cretaceous sands using vertical wells. Drilling the stacked play took off when the provincial government allowed commingling of production from different zones in the Deep Basin following the lead of the B.C. government, making many former uneconomic zones profitable. A number of companies are now taking advantage of commingling. Fairborne Energy Ltd. has 222 sections of land at Harlech, with 80 wells producing. The typical vertical wells drilled in the area target the stacked Viking, Notikewin and Gething formations.

“The nice thing about Harlech is the free condensate and NGL,” said company president Steven VanSickle at a recent FirstEnergy conference. “With more than half of the revenue from NGL and condensate, the effective gas price is about $8 per thousand cubic feet.” The second method for exploiting Deep Basin gas is to use horizontal drilling and multistage fracturing to exploit thicker pay zones. Fairborne drilled the first horizontal well into the Wilrich zone, and it continues developing the play using horizontal technologies. “The results continue to get better and the frac technique is continuing to be modified and we are now doing about 12 fracs per well,” said VanSickle. New wells in the play are delivering over five million cubic feet per day and 15 barrels per million cubic feet of liquids. The Wilrich zone offers an estimated ultimate recovery of 700,000 barrels of oil equivalent per well. In the Nikanassin zone of the Deep Basin, a Lone Pine Resources Inc. (formerly Canadian Forest Oil Ltd.) well in the play tested at 32 million cubic feet per day with initial production (one month) of 20 million cubic feet per day and cumulative production of 7.3 billion cubic feet after 16 months. The well, however, hit a sweet spot and is not considered a tight gas well. Lone Pine holds about 214,000 gross and 127,000 net acres in the resource play. The area provides access to a minimum of 10 different stacked pay-producing intervals, many of which can be completed with production commingled in a single wellbore.

During the first quarter, Lone Pine completed four vertical wells that had average initial 24-hour production rates of nine million cubic feet of gas equivalent per day. The results from these four wells bring Lone Pine’s average 24-hour initial production rates from its Nikanassin resource program to 11 million cubic feet per day. Lone Pine has identified specific zones for which it initiated a horizontal drilling program to isolate completions in the most productive intervals. The company’s first horizontal test had a 24-hour initial production rate of 6.4 million cubic feet per day from a single interval. This first horizontal well was drilled with a 2,200-foot lateral and completed with seven fracture stimulation stages. The well was not drilled to planned specifications of a 4,000foot lateral and 12 fracture stimulation stages due to slower-than-expected drilling rates and operational time constraints. Lone Pine intends to evaluate and monitor the horizontal well performance and plans to conduct additional horizontal operations in the second half of 2011. Because of the Alberta government’s deep gas royalty holiday, there is effectively five years of royalty-free production in the Nikanassin. With operating costs of 40 cents per thousand cubic feet, including processing, the play can be profitable with a gas price as low as $2.20 per thousand cubic feet. While the play can be developed vertically, operators are attempting horizontal wells with the use of new technology. In the Kaybob area of the Deep Basin, Paramount Resources Ltd. is also finding success applying horizontal drilling and

12 PROFILER multistage fracture treatments. Early in 2010, Paramount drilled two horizontal wells in the Dunvegan and one in the Falher. The Dunvegan well came on at eight million cubic feet per day to 10 million cubic feet per day and is still doing five million cubic feet per day a year later. The Falher well came on at 12 million cubic feet per day and has flattened out at six million cubic feet per day after nine months. Based on those results, Paramount accelerated its drilling program. In the Musreau/Kakwa area, it drilled two horizontal wells in the Falher that tested 10 million cubic feet per day to 12 million cubic feet per day that are now on stream. It also tested another formation, the Cadotte, with the well coming on at nearly seven million cubic per day, opening up what Paramount believes is hundreds more locations within the same pool. Encana Corporation is also active in the Deep Basin on its 488,000 acres it calls Big Horn. The company expects production

saving bringing supply costs down to $3 per million British thermal units. Explorers are also actively targeting the Montney/Doig shale play in the Peace River Arch. Intermediate producer Birchcliff Energy Ltd. has nearly 500,000 undeveloped acres in the region. In the first quarter of 2011, Birchcliff drilled five (3.8 net) horizontal wells utilizing multistage fracture stimulation techniques in the Montney/Doig. To date, Birchcliff has drilled and cased eight (5.9 net) wells, of which five (3.8 net) have been completed and are on production. It currently has one rig working in the Pouce Coupe area of Alberta. “The rapid advancements in horizontal drilling and multistage fracture stimulation of these horizontal wells have resulted in significant improvements in production and reserve capture for many different plays throughout North America,” Birchcliff president and chief operating officer Jeff Tonken told

“As our knowledge grows with respect to both operational technology and characteristics of these reservoirs, we expect our results to continue to improve.” — Jeff Tonken, President and Chief Executive Officer, Birchcliff Energy Ltd.

to average 255 million cubic feet per day this year and plans to drill 70 wells. Like other producers, it is moving to drilling long horizontals with more fracture stages in the thick areas of the stacked zones to increase production. Encana is also focused on improving liquids recovery in the play. It expects incremental production increases of 60 to 70 barrels per million cubic feet as it introduces a deep cut strategy to remove the liquids content. Mike Graham, president of Encana’s Canadian division, told the Canadian Association of Petroleum Producers investor symposium in June the company expects to increase the price it receives by 20 per cent by accessing the liquids. Outside the Deep Basin, Encana continues development of the Horseshoe Canyon coalbed methane (CBM) play. It plans on drilling 450 wells in the play this year, and has an inventory of 15,000 locations. Graham said in the Horseshoe Canyon the company is shifting to a pad drilling format with four wells per pad. It is hoping for a 30 per cent per well

shareholders in reporting the company’s first-quarter results. “Birchcliff believes that the Montney/Doig play continues to experience some of the best results of the application of this technology due to its unique reservoir characteristics.” Birchcliff classifies the Montney/Doig as a hybrid resource play that has approximately 300 metres of gas-saturated rock that is both tight silt and sand reservoir rock inter-layered with shale gas source rock. “The horizontal wells are designed to maximize the contributions from the different elements of this complex reservoir,” said Tonken. “As our knowledge grows with respect to both operational technology and characteristics of these reservoirs, we expect our results to continue to improve.” Birchcliff has in excess of 300 net sections of land on the play and believes that it has more than 1,000 potential Montney/Doig horizontal natural gas drilling locations on its lands. Two Alberta gas resource plays that once looked promising, the Colorado shale and the

Mannville CBM plays, have been put on the backburner due to low prices. With nearly 400 trillion cubic feet of gas in place, the Mannville was seen as Alberta’s next big thing following the success of the Horseshoe Canyon. But so far only Nexen Inc. at Corbett Creek has established commercial production. At the Canadian Energy Research Institute’s 2011 gas conference late this spring, Simon Mauger, Ziff Energy Group’s director of gas supply and economics, said the biggest problem in the Mannville is the cost of dewatering the coals and handling that water. This isn’t a technology challenge, he added. “We’re experts in handling water for oil and gas operations. For every barrel of oil we produce, we actually produce nine barrels of water,” he explained. “So handling water isn’t that big a deal in terms of the technology. It just costs money.” Until those dewatering costs can be lowered, Mannville CBM will generally remain uneconomic, he said, adding that the cost of producing CBM from the Mannville is high compared to the dry, shallow Horseshoe Canyon coals of central Alberta. “The Horseshoe Canyon is probably the cheapest CBM in North America because it is dry gas,” he said. Another problem is that much of the Mannville gas is in very thin coal seams—in some cases one to three feet thick, he said. While drilling is technically possible in thin pay zones, costs start to escalate significantly. While the Mannville’s gas in place is huge, Mauger said thick pay sections make up a relatively small percentage of those coal seams. “We expect more wells to be drilled in the Horseshoe Canyon, and even a few in the Mannville—particularly where the Mannville has less water in it,” said Mauger. “But we do not see the Mannville as becoming economic relative to the shale gas opportunities in North America.” The Colorado Group shales—which were pursued by at least a couple of junior explorers in Alberta and Saskatchewan—are shallow with thin pay zones, said Ed Kallio, Ziff Energy’s director of gas consulting. But the biggest problem with the Colorado shales may be that the rocks don’t fracture very well. Key to a shale’s commercial potential is its ability to be fracture stimulated so economic volumes of gas can flow. To fracture effectively, rock needs to be brittle, but the Colorado shale is “kind of spongy” and just absorbs the energy, said Kallio.

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All the fracs you need, exactly where you want them, in a fast, nonstop completion sequence No actuating balls, no pumpdown plugs, no perforating Frac ports

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The system requires no pump-down plugs, actuating balls, or perforating tools. Here’s how simple it is: • Run the casing with a Multistage Unlimited sliding sleeve in the string wherever you plan to frac. You can either cement or run swellable packers to seal the annulus. • Run the Multistage Unlimited frac-isolation assembly on coiled tubing to the lowest sliding sleeve. • Set the resettable bridge plug inside the sliding sleeve and shift the sleeve with string weight and annular pressure. • With the bridge plug sealing below the open frac ports, pump the frac down the casing/coiled tubing annulus. Monitor frac pressure at the surface via the coiled tubing. • When the frac is away, pull up to open the equalizing valve and unset the bridge plug. Move to the next sleeve and repeat. In about 5 minutes, you’re ready to frac again.

Add stages on the fly You can add a stage where there is no sliding sleeve by using the integral jet-perforating sub. The added stage is frac-ready in less than 40 minutes.

When the frac-isolation assembly is pulled from the well after the last frac, you have an unrestricted wellbore all the way to the toe, with nothing to retrieve or drill out. The Multistage Unlimited system cuts water requirements by eliminating pump-down components, by circulating leading-edge fluids down instead of bullheading them, and by reducing casing volume by the volume of the coiled tubing.

Ultra-reliable operation The Multistage Unlimited system is easier to operate and more reliable than any other multistage equipment: • All-mechanical operation. An automatic j-slot sets and unsets the bridge plug with up-and-down string motion. • The resettable bridge plug has been used for more than 10,000 stages and has been cycled more than 40 times during a single completion operation. • With its sand-friendly design, the system is impervious to malfunctions caused by contamination. • Sand-outs can be quickly reversed out. The Multistage Unlimited system is currently available for 41⁄2in (114 mm) and 51⁄2-in (140 mm) casing. Call us or visit our website for more information.

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409.925.7160 (U.S. Sales)

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©2011, NCS Energy Services, Inc. All rights reserved. Multistage Unlimited and “Leave nothing behind.” are trademarks of NCS Energy Services, Inc. Patents pending.


Photo: Joey Podlubny

Land sales provide clue to next Alberta exploration hot spots By Darrell Stonehouse


he numbers tell the story. In 2010, explorers spent around $2.4 billion for access to 3.9 million hectares of land at Alberta land sales, the second-highest payout on record. Half way into 2011, the province has already collected $1.87 billion from bids, including $843 million from a single record sale June 1. Driving the land rush is explorer interest in capturing prospective acreage in tight oil plays and emerging shale plays. Land bought in 2010 is already being drilled and early reports are positive.

Alberta Bakken Since April of 2010, explorers have spent over $180 million building land positions in the Alberta Bakken. They are now drilling in the play, but are holding their cards close to their chests. Through Crown land sales, freehold leasing programs and the acquisition of a private company, Crescent Point Energy Corp. amassed more than one million net acres in the play in 2010. The company is in the midst of exploring the land base, with plans to spend $31 million drilling 14 net wells in southern Alberta this year.

Crescent Point president and chief executive officer Scott Saxberg isn’t releasing any information on the company’s drilling program so far. “We are in the midst of an exploration program out there, so it’s very competitive. We’ve got competitors out there that are buying land that we’re competing with, so we don’t disclose those numbers,” Saxberg said at the company’s annual general meeting in relation to three exploration wells drilled in the play during the second half of 2010.


“We’d love to, but because of competition we don’t.... We’re early days on production. The production on the first couple of wells is public; you can go to the records there,” he added. “What we’ve described to people is to take whatever conclusions you like out of those results because we’re not going to talk to them until we move to a development program out there and we can ensure our shareholders and people what our game plan is out there. “We’re in our first phase of development, so it’s super early days,” Saxberg said. “The way I describe it’s the first period of the hockey game, we’ve had three shifts and got a couple of shots on net...and we don’t know what the score of the game is going to be and we don’t know who is going to win it.” Murphy Oil Corporation is a little more forthcoming with results. Murphy has drilled and completed two Exshaw shale appraisal wells in a six-well program in the Alberta Bakken. “At this early stage, from what we have seen, it’s encouraging but it’s not an Eagle Ford [Texas],” David Wood, president and chief executive officer, said in a conference call to discuss first-quarter 2011 results. The wells are currently being evaluated, and while it’s still early, “we are pleased the wells have flowed within our expectations,” he said.

“We will continue to add acreage in this new play as it fits within our understanding.” Because Murphy Oil plans to pick up additional land, Wood declined to provide more information about the wells. “If we can get wells that are better than 200 barrels a day to start, then I would regard that as being good and I would say that the first two wells would get into that bucket,” said Wood. “What we need to do is see some performance from those wells from initial flow and then put a pump on and see how they produce.” And while he would like to add more acreage, “I am not so sure I would add the acreage in the places that I was going to want to add the acreage prior to the well results.” For Wood, the keys in looking at the play are the presence of water and the kind of reservoir pressure. Water is going to be patchy with some parts of the play having it and some not while some areas will have more over-pressure that would mean Murphy should expect better rates, he said. Montney tight oil In February, Trilogy Energy Corp. spent $36 million to capture Montney oil rights in the Kaybob region of northwestern Alberta. In May, the company announced it was boosting its capital budget to accelerate

development of the play. The company is spending $138 million developing Montney oil in 2011. In addition to the land, the budget includes $20 million for four wells drilled in the first quarter, $70 million for 14 wells to be drilled in the third and fourth quarters, and $12 million in facility capital, Jim Riddell, chief executive officer, told Trilogy’s annual general meeting in May. “We are quite excited about it,” he said. Trilogy estimates that each of these wells may produce reserves of 200,000­– 300,000 barrels. In October of last year, Trilogy drilled the 16-01-64-18W5 horizontal well at the south end of the Montney pool and it tested 1,800 barrels per day of oil and 2.3 million cubic feet per day of associated gas. Encouraged by the result, the company then posted the land between what it already owned and drilled a second well in the area. The 03-21-64-18W5 well, completed the day before the land sale, flowed nearly 6,000 barrels of new oil and fluid in the first 24 hours. The well tested 3,000 barrels per day of oil and 1.9 million cubic feet per day of associated gas. Since then, Trilogy has drilled three more wells into the pool, including two off the original 16-01 pad. The 03-21 well is now on


Photo: Joey Podlubny

production and in the first month it produced a little over 30,000 barrels of oil. Trilogy has a total of about 40 sections of land all within what it believes to be the oil pool and holds it all essentially 100 per cent, he said. The company also owns a lot of the batteries, roads and pipelines in the area capable of producing its new oil. Duvernay sparks major interest Industry has spent over $1 billion on Duvernay land in the last 18 months, including the June 1 record land sale. Few companies, however, have released drilling results. Trilogy is also pursuing deep Duvernay shale gas in the Kaybob area, drilling two of a small number of exploration wells in the play. The company believes the pore space is filled with different hydrocarbons depending upon the location. The southwest corner of the play is likely drier gas with an oil-saturated reservoir moving to the northeast and a gas condensate in between. Trilogy has concentrated on the gas condensate area and believes it has as much as 100 net sections of land in that area. It also has another 125 sections to the northeast. “If it does work and we are right, we could have hundreds and hundreds of locations to drill,” said Riddell. Trilogy reported preliminary results for its second horizontal well targeting the Duvernay in the Kaybob area in April. Trilogy managed the drilling and completion operations for the well as part of a joint venture with Celtic Exploration Ltd. and Yoho Resources Inc. Each partner has a one-third working interest in 30 gross sections of land in the area. The well was drilled to a total depth of 4,866 metres with a horizontal lateral extending 1,400 metres within the Duvernay shale. The well was drilled and cased over 50 days at a cost of approximately $6.5 million for the drilling operation. Completion operations began March 8 and were concluded in late April. The well was fracture stimulated in 31 perforated intervals in 12 separate stages along the length of the horizontal wellbore. In total, approximately 2,300 tonnes of sand and 138,600 barrels of slick water were used to stimulate the well. The well was completed using a staged plug

and perf horizontal completion technique, incorporating perforation clusters (two and three per stage) to stimulate the well. Following the fracture stimulation, the plugs were drilled out to permit the well to be evaluated without obstruction in the horizontal portion of the well. Completion costs for the well have totalled approximately $11 million. However, Trilogy expects to see substantial cost savings on subsequent wells as the well was the first to use the plug and perf completion methodology in the Duvernay. The well has been tied in since April 10 in order to reduce flared emissions during the completion and evaluation period. The well was flowing up seven-inch casing at approximately 1,250 barrels of oil equivalent per day, consisting of 5.2 million cubic feet per day of sweet natural gas and an estimated 390 barrels per day of natural gas liquids, including 180 barrels per day of 56-degree API condensate and 1,450 barrels per day of water. Producers are beginning to find ways to complete the Duvernay shale economically. Is the Nordegg next? The Nordegg formation came on to the resource play radar in March of last year when Anglo Canadian Oil Corp. fluid and a propane frac. It is now looking at a bought 269 sections in the play in northwestwater-based frac and possibly using foam ern Alberta. based on either nitrogen or CO2. Further interest came when the company Anglo Canadian has since purchased received a best estimate of over six billion aeromagnetic and gravity studies as well as barrels in place on its lands from AJM seismic data and Canadian Discovery’s Petroleum Consultants in June. Nordegg tight oil study. Anglo Canadian has drilled a horizontal well Using all this data, the company will try to on the northern portion of its lands and a find sweet spots on its Nordegg acreage. In vertical test on its western properties. Both addition to its fully owned lands, Anglo has a were fracture stimulated and produced small pooling/farm-in agreement with Quatro non-commercial volumes of about 25- to Resources Inc. covering several sections in 26-degree API gravity oil. the Ante Creek North area where both the “But we did learn a lot,” said Anglo Canadian Nordegg and the Montney are oil-prone. president James Ehret. For example, cores Anglo plans to operate the drilling of two from the wells will help the company develop a Nordegg wells this summer. The success of more efficient fracture stimulation. On its first those wells will determine future drilling plans, two wells the company tested a gel-based frac Ehret said.

MAKING CONNECTIONS For more than 50 years, Pembina Pipeline Corporation has provided reliable energy transportation and services to western Canada’s energy infrastructure sector. In addition to our conventional crude oil and nGL transportation service, Pembina provides transportation support to alberta’s oil sands and heavy oil industry; serves customers through an expanding network of terminals, storage facilities and hub services; and offers natural gas gathering and processing facilities.

Conventional Crude Oil Pembina has been transporting crude oil for our customers in the Cardium formation since the mid-1950s and is ideally positioned to continue servicing expanded production in the region for many years to come. We see significant long-term opportunities in the ongoing development of this vast resource and are taking a proactive approach by strengthening service options to producers in the area.

makInG ConneCtIons – It’s What We do. If you’re interested in being connected with Pembina, or are looking for more information, give us a call at: 1-888-428-3222 or visit us online at:

Reliable | Trusted | Responsible Committed to being the operator, employer, partner, neighbour and investment of choice in western Canada’s energy infrastructure sector.




Making information work for you—that’s the power of engineering information management


Engineering information management (EIM) enables owner-operators and EPCs to easily collaborate on information and data—leading to more efficient capital project management, quicker handover and commissioning. AVEVA NET (pictured here) is a proven EIM solution that’s helping the industry make more informed business decisions while reducing risk and enhancing the bottom line.

completion. In fact, the company has refined and streamlined its handover process to the point where it now can be done on a continuous basis in mere minutes! The EPC has also incorporated its document and change management into a centralized data hub, giving all parts of the global organization secure access to project data in a wide variety of formats. In each case, and in many others, an AVEVA EIM solution makes information work for the client, not the other way around. How? AVEVA’s EIM solutions eliminate information silos. Gain complete and timely access to

“It’s not InformatIon overload. It’s fIlter faIlure.” — Clay Shirky, author on the social and economic effect of Internet technologies

critical information. Better manage and use your data. With AVEVA’s EIM solutions, you’ll have the right information filter for the job. AVEVA provides strategies to make information work for you. See our accompanying ad or visit


lant owner-operators and engineering, procurement and construction companies (EPCs) don’t want to waste time and money organizing, sifting, sorting and combing through information. They need key data about a plant or project available at a mouse click to make the right decision the first time. They need a better information filter. AVEVA’s engineering information management (EIM) solutions resolve this vexing problem using a collaborative process that combines precise asset lifecycle management, experienced business consulting and innovative software. AVEVA’s EIM solutions provide decision-makers with a powerful, accurate information filter that empowers them to cost-effectively run assets or successfully complete projects on time and on budget. For example, AVEVA assisted a large Australian independent energy producer to better manage new and legacy data for its facilities using a Web-based asset lifecycle management solution. The company saw immediate benefits, including the reuse of engineering data and designs, better information quality, reduced unplanned shutdown risk, and improved handover and archival of abandoned or sold assets. According to one report, this producer has calculated that, over a 10-year period, it expects to enjoy a return on investment with an internal rate of return of 84%. On the engineering, procurement and construction side, AVEVA improved a major global EPC’s project processes. The firm can now more intelligently manage information from initial project design to handover and


DESCRIPTION: AVEVA provides the world’s oil & gas industry with comprehensive design, construction and asset management solutions for onshore and offshore facilities.

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Joined up thinking

A plant is made up of a million decisions, big and small. It’s a complex flow of people, resources, designs and schedules. Success requires collaboration and a complete understanding of strategic activities and events. With AVEVA information integrity, all project data can be exploited and shared at every stage of the asset’s life, joining up the details to show the big picture. The results are accurate and efficient project performance and asset operations that are always under control, reducing risk, time and cost. With a global sales and service network in more than 40 countries, AVEVA is a leader in engineering design and information management solutions for the process and power plant industries.

Choosing AVEVA will be one of the best decisions you ever make.



CalfraC CAlFrAC WellWell ServiCeS ServiCeS lTd.


Leader in providing efficient, environmentally friendly completions in new resource plays


the resource base. “A lot of these areas are heterogeneous rock, so you can’t offer off-the-shelf solutions,” Medvedic notes. “Having the ability to work together with our customer base to closely nurture strong relationships allows Calfrac to develop custom-based solutions for our customers’ specific requirements.” As the industry has evolved more and more to the unconventional side of the business, the service aspect has become more critical. Five years ago, for example, completion costs were only 10–15 per cent of overall well costs; now, however, completion costs make up anywhere from 30–50 per cent of total well costs. The Cardium is one play that has seen a significant increase in the length of horizontal legs. By extension, the number of frac stages per horizontal leg has also increased dramatically, leading to greater service intensity per well. “The completion side of the business has really become a focal point in the success or failure of many of these unconventional projects. What that has done has been to forge some very strong relationships with our customer base and Calfrac’s engineering teams in developing custom solutions,” Medvedic says. “The other important aspect is a real focus on the deployment of ‘green chemistry’ [environmentally friendly fluid systems]. We have deployed 12 different systems in the last 18 months in both Canada and the U.S., which continue to improve the environmental footprint.” Calfrac’s CleanTech™ fracturing fluid system, for example, is a patented cleantechnology fluid that maximizes proppant placement while minimizing water usage and formation damage. “Overwhelmingly positive feedback has spread like wildfire throughout the industry, and as a result, the number of CleanTechTM jobs that we pump is increasing on a daily basis,” says Chad Leier, Canadian Division Sales & Marketing Manager. “We are seeing the highest demand for this system in the Bakken, the Viking, and the Cardium. Production results really tell the tale about whether a fluid system is successful or not—fortunately, our customers are achieving

greater results than ever imagined in these unconventional plays. “At Calfrac, we partner with our customers to provide environmentally friendly, costeffective solutions. Calfrac’s continual focus on chemistry, specifically green chemistry, is a huge part of our business, as we believe that industry is going to continue the trend toward the tighter, more unconventional reserves.” Calfrac uses many different fluid systems that have been tailored to each formation’s specific geology. Both SlickWater and SlikProTM, Calfrac’s slick oil systems, were designed for formations with less permeability. For more permeable formations, the company uses foamed and cross-linked water systems, as well as a number of hydrocarbonbased fluid solutions. Execution in these resource plays relies on the latest equipment and technology; equally important are well-trained, well-qualified people, plus good health, safety and environment programs, the right commodities, and logistics. Since its inception in 1999, Calfrac has enjoyed a proven track record in each of these areas. “We are still in the very early stages of oil development in Western Canada incorporating this technology. We believe there will be many applications to this, and that it will continue to become more and more efficient through the passage of time and the improvement of technology,” Medvedic says.


alfrac Well Services is a leading oilfield service provider positioned in some of the world’s most exciting energy basins. Active in Canada, the U.S., Russia, Mexico, Argentina, and most recently Colombia, Calgaryheadquartered Calfrac is a pressure pumping firm whose primary service line is fracturing, although the company offers coiled tubing and cementing services as well. The move towards unconventional resources—initially targeting tight gas and shale gas opportunities through horizontal drilling and multi-stage fracturing technology— is the biggest change that Calfrac has seen in recent years. “Over the last three to five years, we have been very focused on shale opportunities in North America,” notes Calfrac Senior Vice-President, Corporate Development, Tom Medvedic. “Recently there is significant momentum directed toward the oil part of the business. We are very much seeing diversification from a commodity perspective, and the same technologies used in shale gas are now being applied to the oil-producing formations.” This trend is not exclusive to the oil shales, he adds. “Plays such as the Cardium and Viking formations and the Permian Basin in the U.S., which have been producing for decades and were thought to be in terminal decline as far as conventional production goes, have been completely revitalized through the use of horizontal drilling and multi-stage fracking.” Oil and gas companies are now looking at many of their reservoirs through a different lens and asking where else they can apply this technology to existing plays, with the hopes of repeatability through the experiences of some of the other plays. “It’s a fairly sizable shift in the business,” Medvedic says, noting that the move toward the oil part of the business has highlighted a renewed focus on chemistry— “the products we pump downhole. It has really brought companies that are strong in chemical development—which has been a hallmark for Calfrac and its dedicated laboratory facility in northeast Calgary—to the forefront in these developing oil plays.” Calfrac has established strong relationships with customers, working with them jointly to provide custom-tailored solutions for

COMPANY NAME: Calfrac Well Services Ltd.


T: 403.218.8180 F: 403.508.1545 E: WEBSITE:


All in a day’s work. From the Horn River, Montney and Deep Basin in Canada to the Marcellus and Fayetteville basins in the United States, Calfrac has an outstanding track record in unconventional gas plays. This is an everyday reality because of our specialized pumping equipment, a state-of-the-art research and development facility, our highly advanced crews which are involved from advance planning to on-site supervision, and in thanks to our relationships with suppliers for reliable sand storage and delivery. Safety is also topmost priority, as made evident by our high safety performance. We’ve proven ourselves on project after project in some of the toughest shale and tight sands basins anywhere – one of the reasons Calfrac was awarded the Shell Upstream 2009 Supplier of the Year Award for the Americas


We’re breaking new ground... every day. For more information, contact: Gary Rokosh P.Eng. Vice-President, Sales, Marketing & Engineering 403-218-7483 Chad Leier P.Eng. Manager, Sales & Marketing 403-218-8180



CanGas saves customers money, providing natural gas on the go


CanGas is also focusing on high gas-to-oil ratio penalty wells. CanGas can conserve the gas so producers can bring shut-in wells back on stream and get their oil to market. A significant benefit to CanGas’ business is the reduction of greenhouse gases. Providing an alternative to the venting of natural gas has a significant impact in reducing greenhouse gas emissions and other air pollutants in the atmosphere since methane is approximately 20 times more damaging than carbon dioxide. The company also provides compressed natural gas transport service for the displacement of diesel, propane and other liquid fuels. “Due to the low price of natural gas, there is an economic benefit for consumers,” Fraser explains. “We are utilizing that market opportunity to assist producers and companies generating power or running equipment to reduce their fuel costs.” The company’s focus on fuel displacement has been with drilling rigs, which burn significant diesel on a daily basis, so the economics are very compelling to convert to dual fuel, according to CanGas Operations Manager Gary Hyer. “We would displace approximately 50 per cent of the diesel consumed on a rig with compressed natural gas,” Hyer says, noting that in terms of energy content, the cost of natural gas is approximately one-seventh the cost of diesel. CanGas will offer customers a turnkey solution overseeing the supply and delivery of gas, including depressurization equipment, to provide the gas at the pressure and flow rate required. In its first drilling rig conversion project scheduled for this fall, CanGas plans to deliver natural gas via truck to Encana drilling locations in southern Alberta. The other application that CanGas is focusing on is delivering natural gas for power generation at temporary sites or other oilfield applications where power is required. At oilfield camps for example, which are often located near the drilling sites, natural gas can be used for power generation, heating and cooking. Compared to diesel or propane, the cost savings are 40 to 50 per cent. In addition, CanGas offers portability of the supply of natural gas. “It enables the client to get up and running relatively quickly. Even if

they plan to install a pipeline in the future, they can see the savings much sooner than they would otherwise,” Fraser says. CanGas is always looking for innovative new technologies to improve the efficiency of its gas transportation systems. “With the continued rise in oil prices, we see that the switch to replace oil with alternative fuels such as natural gas will only increase,” Fraser says. “We are constantly coming across new applications and because of the growth of drilling in the Bakken and other plays with high-value hydrocarbons throughout western Canada and the United States, we see a huge opportunity for expansion in the collection of these valuable gases that are currently being wasted. Our motto is, ‘Saving gas is saving cash.’”


anGas Solutions Ltd. is a North American leader in the development and use of containerized natural gas transportation systems. The Calgary-based company provides an alternative to pipelines for conserving solution gas from oil wells and delivers compressed natural gas to displace diesel and other liquid fuels. CanGas specializes in conserving and monetizing natural gas being flared or vented at oil wells or facilities not tied into gathering systems. The equipment is portable and can be used at existing sites or at new sites prior to tie-in. CanGas provides a complete service solution to transport the natural gas from where it’s being flared, to where it can generate a profit for the producer. CanGas installs its patent-pending loading equipment on a well site to collect and compress the gas into trailers for transport to a pipeline connection or gas plant. CanGas will either transport the producer’s gas and charge a transportation fee or take ownership of the gas at the well head. “We focus on natural gas that contains high-margin hydrocarbons such as propane, butane and pentanes plus—because that’s what makes the economics more attractive. The revenue from the liquids in the gas is typically much greater than the revenue for the gas,” says CanGas President and CEO Greg Loewen. The process was introduced in January 2011 on a project with PetroBakken Energy Ltd. in southeastern Saskatchewan. It involved placing equipment at one of their well sites and delivering gas to a PetroBakken pipeline located approximately 80 km away. “We have been very focused on the Bakken oil production area because of the lack of gas-gathering infrastructure in that area and because of the quality of the solution gas—typically sweet with high-value hydrocarbons,” explains Don Fraser, CanGas Vice President of Business Development. “We have proven our process and are currently expanding our equipment fleet to other companies and to more well sites in Saskatchewan.” CanGas plans to expand further into the Bakken in North Dakota and Montana over the next six months.

COMPANY NAME: CanGas Solutions Ltd.


T: 403.452.7789 F: 403.452.7189 E: WEBSITE:

Can Gas Solutions Ltd. 2010, 444 5th Ave SW, Calgary, AB, T2P 2T8 Ph. 403-452-7789




For the most experience and the best operational advice and technology, Departure Energy Services has no equal


developed techniques and modified its equipment in order to operate in the most effective, efficient way possible. “Because we own our own downhole motors, we’ve done the engineering in terms of building fixed bent housings for the motors, to aid in the build rate issues in the Cardium. We have full engineering control over the tools.” Due to formations that are not laid down really flat, the other major issue with these wells is that energy service firms must be able to work with geologists very closely in order to track the formation as best they can. Departure’s people understand this—and other issues—very well. “We believe in drilling problem-free wells,” Robson stresses. “We have a tremendous amount of experience, and we do all of our upfront planning and engineering prior to drilling. We make a plan, we follow the plan and we work closely with the operator to make sure the plan is executed and a problem-free well is delivered at the end of the project. We strongly believe in the engineering aspect of well planning— we don’t plan wells without reviewing the torque and drag aspects and reviewing anti-collision and proper well placement in the reservoir.” Departure’s core group of owners bring a tremendous amount of experience from all over the world to each and every job. Since the basics of horizontal drilling are the same worldwide, Departure can easily apply these basics when drilling wells in both the Cardium and in the Viking, where the company runs rigs on a daily basis. “We modify to suit the area, but the basics are all the same,” Robson notes. To date, Departure has drilled 100-plus wells in the Cardium for 10 different customers. Fields drilled include Brazeau, Caroline, Crossfield, Crystal, Ferrier, Lochend, Minnehik, Pembina, Willesden Green and Wilson Creek. The Viking—another very active formation— is completely different from the Cardium. “The wells are shallower, they are faster and they require following the basics and dealing with in-field situations we have every day.” Departure has drilled 45-plus horizontal wells in the Viking formation to date, for nine different operators.

“Resource plays like the Cardium and the Viking are a huge part of the future of our business, and horizontal drilling technology and multi-stage fracing technology are making all of this possible by increasing the production from known reservoirs,” says Robson, who thinks the future outlook for Departure is very strong. The company, which is growing in both Canada and the U.S., is focusing all of its investment in North America. Departure Energy Services prides itself on providing premium quality directional drilling equipment and services, and partnering with customers to deliver exceptional value. “What we tell people is that when you call this office, you will find a partner in one phone call—you don’t have to go through two or three levels of management,” Robson says. “The partners run the business and we are always available.”


aunched five years ago, the Alberta-based energy service firm offers high-quality consulting services, advice and technology with a heavy-hitting 10-person management team that includes the directional drilling specialists who drilled the first horizontal wells in the Persian Gulf, a measurement-whiledrilling operations manager who developed the first environmental measurement while drilling surface system, and a COO who helped develop magnetic guidance tools and short-radius re-entry systems. This is a team that can draw from its 200-plus years of directional drilling experience, led by a CEO whose pioneering work resulted in 37 U.S. and Canadian patents. Headquartered in Leduc and with a sales office in Calgary, Departure Energy Services combines an engineering approach to problem solving, bringing to the job its proven experience, the best and newest technologies, and a suite of proprietary downhole tools designed to remove the uncertainties from directional drilling program planning and execution. “That’s why we do a lot of wells where our producer clients have encountered some difficulty. The kind of analysis and solutions we provide involves specialized engineering capability,” explains Departure chairman and CEO Larry Comeau. Clients benefit from Departure’s closely integrated team of specialists, who work hard to provide consulting and operational services without the management layers sometimes associated with larger service firms. “This helps guarantee that planning and execution are very well coordinated,” says Departure director of strategic development, Dan Robson, who drilled his first horizontal well in 1985. “We’ve got a tremendous amount of experience in the industry, especially in horizontal drilling. We’ve been at it for a long time.” Departure does a great deal of work in the Cardium, where drilling horizontal wells is “not cookie cutter—because there are issues to get the well drilled, especially through the build,” Robson explains. “In the Cardium, it’s getting the build. It isn’t standard—you have to work at it.” To this end, Departure has

COMPANY NAME: Departure Energy Services Inc.


T: 403.266.3940 EMAIL:



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Alberta’s frac fluid heating specialists


client, Worobec notes—“so if one heater was to go down for any reason, you would still have the majority of the heaters running. “ICS Group can deliver the appropriate heating package tailored to your specific job requirements. You are never going to lose your heat.” ICS Group also offers generators with built-in redundancy as part of the package. ICS’s immersion heat exchange system keeps fluids at a consistent temperature, even in extreme weather conditions. Last year, as just one example, ICS kept a 3200 M3 above-ground tank heated at a constant temperature, even as the thermometer dropped to -50 C with the wind chill. Frac Fluid Temperature Control from ICS Why should you use the ICS Solution? Precise, reliable temperature management ensures consistent up-time and service. ICS Group’s innovative temperature control applications for oil and gas fracturing fluids will keep your frac fluid at a consistent temperature and always frac-ready. With ICS immersion heating systems, you will control the temperature from start to finish; Achieve and maintain frac fluid temperature within a specified or pre-determined range; No need for getting the off-site heater back to re-heat. Prevent On-Site Delays No longer will your frac fluid temperature be compromised if a heating unit goes down; Multiple heating units in an ICS package provide risk management by built-in redundancy. Cost Savings Built-in redundancy eliminates the cost of back-up or stand-by heater units; ICS systems convert fuel burned to output BTUs more efficiently than other heaters; Atmospherically vented/non-pressurized units eliminate the need for on-site certified steam technicians. Fuel Flexibility Heaters operate on diesel, propane or natural gas.

Proven Reliability and Responsive Service ICS backs up its equipment with a 10-year track record of 24/7 reliability, particularly in remote locations and extreme winter conditions; Remote monitoring provides notification of any temperature interruptions; Technical and service support available 24/7 and can include on-site personnel. Frac Site Applications Frac fluid heating: Above-ground vessels; In-ground pits; 400-barrel tanks—including fire, water and tanks farms; Freeze protection for water supply lines, valves, pumps and instruments; Air heat for hoardings and buildings. “As specialists, we go beyond equipment rental,” Worobec says. “We offer value-added services, project analysis, start-to-finish site climate control, remote monitoring, and gas fitters on staff.” To help customers learn more about their equipment and process of heating frac fluid, ICS Group offers clients a Lunch and Learn technical talk, at no charge. Please call for details. For information on how to make your site 100% frac fluid ready, call Wes Worobec at (780) 904.7209 or email:


CS Group keeps your tank fluids flowing, even in the most extreme conditions. “We are a solutions provider. We listen, design and deliver,” says Wes Worobec, Partner, Oil and Gas Energy Solutions with ICS Group, a Canadian company that provides Complete Portable Climate Control for completions and production operations. For a decade, ICS Group started out supplying Portable Climate Control to construction sites, industrial, restoration and event industries. Today, the company has branched out in the oil and gas industry, providing Frac Fluid Temperature Control. The ICS Immersion heating system provides precise temperature control for frac fluids in above-ground tanks and pits. ICS also manages temperature in firewater tanks. ICS is developing a circulation heating system with a target delivery date of fall 2011, which will enable the simultaneous heating of a 400-barrel tank farm. “We are on site for the entire duration of the fracing operation, constantly maintaining fluid temperature,” Worobec says. Thanks to the ICS heating system, customers have full control of fluid temperatures from start to finish. “They don’t have to rely on anybody else. This enables constant temperature management of the fluid, regardless of any on-site delays.” ICS heating systems also offer fuel flexibility. “Using our solution, you can run on natural gas, propane or diesel in any location.” With every system, 24/7 phone technical support is included. ICS also offers a full turnkey package providing 100% on-site service. Having a flexible service offering is key, as clients may have different needs. ICS can also provide long distance water-line freeze prevention, keeping pipes and valves from freezing by wrapping them with hoses or its Climate Change Tarp System. “We can do one or two kilometers, easy,” Worobec says. ICS can also provide air heat to prevent the hoardings, buildings or valves from freezing. Redundancy is another major benefit to what ICS Group offers. “We double up—we have built-in redundancy on heating and generators. Multiple heating units in an ICS package provide risk management to the


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YOUR FRAC FLUIDS – READY WHEN YOU ARE The ICS inline immersion system keeps your frac fluid at an exact temperature, even in extreme weather conditions. Our unique multi-unit configuration ensures consistent and reliable temperature control so there is no need for traditional reheat processes. Alberta’s heating specialists for over 10 years – trust ICS to ensure your frac fluids are ready when you are. To find out how to make your site 100% frac fluid-ready, call Wes at 780-904-7209 or email PRECISE CONTROL FOR: Above ground tanks


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Innovative products, personal integrity drive growth of Rocky Mountain House–based supply outfit


with the idea of the free-standing rig floor to give workers a platform to do their well intervention work. An engineer was hired to help with design, and in 2010 a prototype was working in the field. “After we built the first one we revamped it and made it even better,” he explains. “We now have half a dozen of them.” This unit is engineered and certified for 2,000 pounds working weight on the floor. It will drop from five feet and raise to 12 feet, and comes with an intermediate floor if needed. “I’ve seen other units out there that need a two-ton truck to haul,” says Casorso. “We can haul ours with a half-ton.” Another innovative offering is the Envirobin. The Envirobin is a combination unit that eliminates the need for separate storage and hauling of well site waste materials. “Right now we’re going through the motions with the ERCB to become a transfer station,” says Casorso. “When it’s done we will be an approved recycling facility for the upstream oil and gas industry.” Yet another innovation is what Casorso is currently calling “the Hot Tub.” The Hot Tub is an electrically heated, insulted floc tank designed to keep fluids thawed during winter drilling operations in the oil sands. The tank is heated using radiant heat on the outside, leaving the inside of the tank open so it can be cleaned using a regular vacuum truck. Casorso believes the Hot Tub will be in demand in all extreme working conditions. The Hot Tub, along with all of Oil Boss’ generators, comes equipped with GPS. With the Hot Tub, this means operators can measure both the temperature outside and

inside the tank remotely, and make the proper adjustments. With the generator fleet, this means operators can remotely monitor things like oil pressure and fuel levels. They can then ensure fuel is delivered when needed, and plan for times like Christmas when crews may not be on site. A second key to Oil Boss’ success is Casorso’s commitment to his customers. “We’re a private family-owned business,” he explains. “We’re straight shooters and look after the guys who look after us. We’ll lose a dollar now to make a dollar tomorrow and we’re not happy when we leave a job until everyone is happy.” This commitment to the customer has served Oil Boss well. In 2008, when the industry went into a tailspin, the company prospered. “It was the worst downturn in 80 years and we had our best year ever,” he notes.


uccess in the oilfield rental business means having products that are in demand. Over the last decade, Gerry Casorso has grown Oil Boss Rentals Inc. from a small hotshot company into a thriving general oilfield rental outfit servicing all of Alberta by having the right kinds of equipment on offer at the right time. Backed by his personal pledge to “look after the guys that look after us,” Casorso plans on continuing growing Oil Boss’ market share and product offerings into the future. Casorso started the private oilfield service company as Casorso Industries in 2001. The company was rebranded as Oil Boss after acquiring two other service and supply companies in 2010. As Oil Boss has grown, it has continually added to its product lines. “We started out as a hotshot company and then gradually moved into the environmental side of things,” he explains. “We concentrated on the completion and production side of things. Our organization is now moving into the drilling side.” Oil Boss continues providing oilfield hauling/ hot shot services with a fleet of vehicles ranging from half tons to tandem axle picker trucks. Over the years it has added a rental fleet of office trailers, elevated work platforms and portable catwalks, light towers, generators, chemical injection units, heaters, rig mats, along with environmental equipment to contain hazardous fluids at well sites. Its free-standing rig floor is one of the company’s innovative new offerings. Two years ago, Casorso says he saw the growing trend of rigless completions emerging as fracture technology changed. He came up

COMPANY NAME: Oil Boss Rentals Inc.


T: 403.844.3031 E: WEBSITE:

• Wellsites

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• Light Towers

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With Portable Toilets

Floc Tank With Lid




PARADOX ACCESS SOLUTIONS INC. PARADOX ACCESS SOLUTIONS INC. Solving accessibility problems for industries within Alberta


Paradox using Neoweb to complete its first municipal road rebuild through a swamp. “Neoweb can reduce the amount of material used to build traditional roads and construct roads where, traditionally, roads could not be built,” Breault says, noting that Paradox has designed and engineered heavy-haul roads to carry the weight of 797 heavy-haul trucks, which can carry 1.4 million pounds loaded. Neoweb offers economic and environmental sustainability, with significant advantages that include: Increased soil-bearing capacity; Reduced thickness of aggregate, structural pavement and asphalt layers; Reduced construction costs for paved and unpaved roads in weak soil; Money savings through the use of local and ungraded granular materials for infill, including soil, quarry waste, sand and recycled construction waste; and Reduced long-term maintenance costs. “Neoweb is the future of access 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.” In addition, “We only require the use of local infill material, which minimizes our transportation costs substantially. This offers a huge cost and environmental savings.” Neoweb is setting the standard with a new generation of durable, sustainable soil

reinforcement solutions. With an engineered lifespan of up to 50 years, Neoweb is rated from -70°C all the way up to +70°C. The design of this material compliments the climate here in western Canada, opening the window of business all year long. Neoweb is a cost-effective, economical and stable product that gives Paradox the ability to provide long-term solutions. ENgINEERED PIPELINE CROSSINgS Paradox’s pipeline crossing equipment has been designed and built to service the pipeline industry. Paradox’s pipeline crossings


aradox Access Solutions Inc. was founded in 2004 by Marc Breault with a mandate to introduce new access technologies to mitigate industries’ environmental impact. Paradox provides solutions that are cuttingedge and cost-effective while maintaining stringent schedules. The first challenge was to minimize project costs, starting out with rubber mats to reduce trucking costs, which is the biggest expense of any matting project. “We were looking for alternatives to wooden mats, which can absorb up to 100% of their weight in water, equating to higher freight cost.” Breault explains. Through the process of research, designing and development of new matting materials, Paradox found a product called Neoweb™. In 2009 Paradox was awarded the exclusive Canadian rights to Neoweb. This material is a cellular confinement system (geocells), based on Neoloy technology. This material is a new polymeric alloy with very long-term durability that is setting the standard for durable, sustainable soil reinforcement solutions. This new generation of geocell is developed and manufactured by PRS, the world’s largest producer of three-dimensional cellular confinement systems. Neoweb creates a composite honeycomb structure with a confinement system that maintains compaction and improves the performance of infill materials to provide long-term soil reinforcement and increased structural strength. Neoweb is high-performing and can be designed and engineered to meet the needs of today’s transportation and municipality infrastructure requirements. “Neoweb has been proven in Canada and is well received in [the] industry,” says Breault. Paradox has been utilizing Neoweb material for the past two years, first in the Fort McMurray area of Alberta and later in Drayton Valley, Alberta, as an alternative for access matting requirements for teardrops, leases, road access, and many other applications. Alberta Transportation has recently begun its approval process for Neoweb road construction, with

COMPANY NAME: Paradox Access Solutions Inc.


TOLL FREE: 877.MUD.UGLY (683.8459)

T: 780.418.1955 F: 780.418.2259 E: WEBSITE:


“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.

have been engineered to support up to 120,000 pounds, and can be hauled and put into position in one lift. This proprietary engineered design eliminates the need for steel rig mats and/or a clay cap to mitigate crushing of underground utilities. Paradox has evolved since its inception as a start-up business offering access consulting. The company now employs more than 60 people and operates depots throughout Alberta and Saskatchewan. Paradox works with leading institutions worldwide on product research and development. Paradox provides comprehensive, end-to-end consulting and customer assistance for access and environmental solutions through planning, designing, engineering, installation and support—with the ultimate goal of total customer satisfaction. “We are always researching and developing solutions to assist industry’s access challenges,” Breault says. “We are the access experts.”


Petroskills llC peTroSkiLLS LLC

Competent workers across the entire oil and gas value chain are essential


s oil and gas workers age and retire, the need to grow new talent has never been more pressing. A systematic approach, such as a competency system, to growing oil and gas workers is critical for all oil and gas industry organizations. “A competency system is any methodical process that sequences an individual or group of individuals through a graduated process,” says PetroSkills LLC vice-president Lloyd Elder, who is based in Edmonton. “It starts at simple awareness and moves towards mastery of a defined body of knowledge and experience under a given discipline.” A successful competency system can be defined as a managed set of methods that effectively, efficiently and consistently produce the human assets that are adequately skilled to meet the varied and unique job requirements encountered in the oil and gas value chain upstream, midstream and downstream. Four pillars create the foundation for every successful competency system: The Competency Framework Management Software Learning Content and Resources The Competency Process Set and Champion

Learning ConTenT and reSourCeS Learning Content and Resources—which is oil and gas subject matter—can include books, policies, procedures, case studies, video libraries, interviews, simulations, instruction, expertise and all knowledge repositories that help shorten the time in moving an individual from unaware and unskilled to knowledgeable and skilled. The CompeTenCy proCeSS SeT and Champion Only when a competency system can be successfully sustained can it render continuous value. A competency system survives and flourishes when it is linked to strategy, held in high regard by the organization’s senior leadership, and underpinned by a repeatable process. Process nurtures the competency system. People who champion competency systems are people who take on this responsibility. peTroSkiLLS Can heLp PetroSkills is the world’s leading industryled alliance of petroleum training management providers. PetroSkills also delivers outstanding solutions in employee performance and competency assurance systems, building and delivering complete competency systems, and helping develop competent engineers, technicians, and other oil and gas industry professionals through detailed performance tools and consulting. In 2001, the PetroSkills alliance launched a new age in petroleum learning. Today, PetroSkills is the leader for oil and gas training and is a unique competency-based training-program provider under the unique

alliance organization. Content is based on detailed skill and competency maps developed with member companies. Each discipline is detailed through these competency skill maps to ensure that professionals receive the skills they need at their individual level, which will put them on the right track for advancement. Practicality is what sets PetroSkills apart. Its competency-focused learning delivers the individual skills and technology requirements of operating companies and industry professionals. “Our goal is to help build competent engineers and technicians that can immediately apply the skills they learned within PetroSkills programs to create value within their companies,” Elder says. PetroSkills provides world-class sessions on topics ranging from Exploration & Production and Surface Facilities to Operations & Maintenance and HSE. PetroSkills makes it easier with one-stop convenience to meet all of your training needs. In addition, PetroSkills’ software technology can help training managers target, manage, track and report on employee petroleum training. If you have any sort of oil and gas training issues, PetroSkills is a company you should be calling.


The CompeTenCy Framework Competency frameworks must be inextricably linked to an organization’s strategic plan. In 1996, Kaplan and Norton wrote The Balanced Scorecard. They described the “Vertical Vector,” an organizational linkage bridging return on capital employed to customer satisfaction elements, success with customers to quality processes, and quality processes to an organization’s ability to learn and innovate. The primary point: the financial success of any company is simply an outcome of customers being served with excellent process. Further, these wellexecuted processes are grown from training and skilling programs.

managemenT SoFTware Competency systems cross multiple disciplines, process arenas, tasks, levels, assessments, content linkages, calendaring and planning facets, as well as required reporting and measurement tools. Competency systems require technology in the form of automated software and a robust database to crunch the sheer volume of individual, group, departmental and corporate summative data.


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T: 780.462.6365 F: 780.450.0186 WEBSITE:


With a competency intelligence system that offers both knowledge and capability assurance, TRACCESS CI gives you the power to develop a highly skilled workforce—and most importantly, safety and assurance for your company. Change the way your company manages your employee’s skills. Ask for a demo today:


ProphetRMS ProphetRMS

The future of well servicing looks bright


prove the effectiveness of ProphetRMS under Canadian conditions. To complete the study, one­third of a large group of service rigs operating under the same conditions were equipped with ProphetRMS with the remaining two­thirds acting as the control group. The performance of the control rigs, and the 10 monitored trial rigs, were both tracked for one year prior to the commencement of the monitoring trial to establish a baseline. During the year prior to the trial, the performance of the control rigs and the monitored trial rigs operated within 0.24 per cent of each other. During the one­year monitoring trial, the monitored rigs experienced an average reduction in job times of 6.84 per cent. Baird says the improvement in performance was driven largely by an increase in accountability with workers ensuring they were doing the job right. “The rigs with ProphetRMS were more efficient instantly,” he explains, pointing to a 2.83 per cent reduction in job times in the first month. The monitoring trial rigs’ performance improved further over the duration of the trial with the monitored rigs experiencing an average reduction in job times of 6.84 per cent over the year. Making this more remarkable is that there were no formal process changes or other actions taken to improve efficiencies. “The improvement has been attributed to increased accountability and better informa­ tion. There was better communication from the field to the office and the crews at the rig have better information,” says Baird. Aitichison says the company is currently focusing its marketing efforts on heavy oil and tight oil in western Canada because of the high levels of well interventions common in such plays. “We know we can get 20 per cent improvement here,” he comments. “A lack of resources is keeping producers awake at

night. They can’t get enough rigs due to a lack of trained personnel. The idea of ProphetRMS is to help make the rigs and crew more efficient. If you have 17 rigs working and you need 20, a 15 per cent improvement in efficiency over time will allow the 17 rigs to do the work of 20.” ProphetRMS builds a stronger relationship between the service companies and the operators. By identifying potential areas for improvement, the service company, site supervisor, and operator can work together to address the issues and increase productivity. Ultimately, the goal is to reduce costs, risks, and liability, increase safety and efficiency, and bring lost revenue back on­line. “Re­interventions put the producer behind on an already full schedule of bringing other off­line wells back on,” he explains. “With less rework, there’s more first time work.” “Quality of work is also a significant problem,” he adds. “Sometimes there are production failures and they don’t know why. If you can’t measure what’s happening, you can’t improve operations. That’s where we come in.” Increasing the quality of the production string can help reduce the overall


ervice rig optimization provides faster service, better quality, and safer well completions and interventions while building accountability and increasing communica­ tions between the field and office. By reducing total intervention job time, crews can service more wells and get more assets producing with the same number of service rigs. With service rig crews and equipment in short supply, rig operators and the oil and gas producers who employ them need ways to meet targets while utilizing the currently available resources. Enter Advanced Measurements Inc.’s ProphetRMS remote monitoring system. ProphetRMS is a well servicing optimiza­ tion tool that identifies inefficiencies, improves quality, and promotes safety in well servicing operations. The system automatic­ ally monitors and collects data on specific operational parameters at the well site using sensors incorporated throughout the rig. Using rig­to­Internet technology combined with sophisticated data analysis and reporting, the data gathered is streamed to all stakeholders and saved, allowing them to see the conditions and activities in the field. “You can monitor all activities when they are running in­hole and are able to monitor the quality of the production string put in place,” says Steve Baird, senior product manager for ProphetRMS. There are currently 300 similar systems in place on service rigs in the U.S. Jeff Aitichison, Advanced Measurements’ vice president for business development, says, and this has resulted in improving the average well intervention times by as much as 20 per cent. Advanced Measurements recently began introducing the system in western Canada and is now building industry support. It has partnered with a major heavy oil producer in the Lloydminster area on a two­year study to


DIRECTOR OF SALES: Steve Chand’oiseau

T: 403.571.7273 ext. 312 F: 403.571.7279 E: WEBSITE:


costs of operating the well, and this will result in a longer well lifespan and higher profits. “With ProphetRMS, you know what happened and that creates visibility and awareness. That’s the key to accountability,” notes Baird. He cites, as an example, rod makeup quality improving due to being able to ensure crews were following proper procedures, resulting in a 40 per cent reduction in rod failures. Aitichison says ProphetRMS provides other benefits as well. Another benefit the system provides is a record of the activity on the well. If the oil company or the crew is uncertain whether a task was completed properly, they can go in and look at the data instead of potentially repeating work. The historical record can also answer any disputes concern­ ing whether a task was performed correctly. “It provides verifiable information after­the­ fact so there is no ‘he said, she said’ debate,” he explains. “It provides real evidence.” Baird says ProphetRMS can also play a role in verifying if safety procedures are being followed. “It can be used for safety monitoring. You can identify if a safety meeting was held before a critical operation, that kind of thing,” he explains. “It also monitors blowout preventor pressure tests, and can identify activities like tripping too fast, or racing, and help crews safely run in rods and tubing.”

Aitichison adds that the system can be used to help train new workers on how to do work safely. “It can be used to help orient them on the rig and understand when they are doing something wrong or unsafe,” he explains. “It’s an opportunity to bring people up to speed fast.” As ProphetRMS is used on more and more wells, producers will have the historical data to create standard operating procedures for their organizations to get the biggest bang for their well servicing dollars. “Over time, we can develop average job times in an area and the company can compare their own times against the average benchmarks in the industry,” he uses as one example. “The draw of checking your own data against others is quite appealing.” With skilled worker shortages a chronic problem in the service sector, Aitchison says improving efficiency and quality will be the key to the future and the ProphetRMS system is the answer to that question. “In western Canada we expect to see greater and greater adoption as more producers realize the benefits of ProphetRMS. Depending on the involvement level the producer chooses, they will see a minimum benefit that pays for the system. Higher levels of involvement will yield greater and greater benefits. Everyone believes this will become the industry standard.”

ProphetRMS Reduces Well Failures

ProphetRMS Minimizes Offline Production

ProphetRMS Keeps You in the Loop on Rig Activity

ProphetRMS Promotes and Monitors Safe Behavior


Sproule ASSociAteS Sproule ASSoCiATeS limiTed


Sproule offers a total package for optimizing unconventional oil and gas play economics


see results on a 24/7 basis, thus improving communication with the client as well as reducing time and cost.” MacLeod says the company is now leveraging this knowledge and experience in emerging resource plays in western Canada. Sproule’s experience working in western Canada and worldwide puts it in a unique position to understand the emerging plays, he notes. Sproule was one of the pioneers in recognizing the potential of coalbed methane in Alberta and was also early in seeing the shale gas and tight oil boom in western Canada. “In the Bakken oil play we are doing work for virtually all the companies on the Canadian side and work on the U.S. side for some clients,” says MacLeod, as one example of its experience. “We’ve worked with clients to take the play from its infancy with vertical development through horizontal development with multistage fracturing to waterfloods. We have built a complete technical story and analysis of the results of different company’s activities in the Bakken. We’ve done the same in the Montney, Viking and Cardium. We’ve looked at the plays and studied them on a regional basis. When working with a client, we can bring a macro and micro perspective that can be hugely beneficial. We can give them a better quality analysis in less time with less cost and can support the analysis with data.” Sproule’s experience internationally adds to this knowledge base. “One thing that sets Sproule apart is that we are a truly worldwide consultancy. Our people are exposed to reservoirs around the world,” MacLeod explains. “When it comes to unconventional plays, we have a wide range of experience not just in Canada, but in the U.S. and internationally.” This wide-ranging experience allows Sproule to look at analogues for emerging western Canadian plays in other regions to better understand the new plays. MacLeod says one of the key things to understand about the new resource plays is that they are heterogeneous, meaning some

areas in the play will be more prospective than others. “Our technical analysis goes back 60 years in some of these reservoirs,” he explains. “What’s challenging is to understand what is the most productive part of the reservoirs and to understand the optimal full development strategy for these reservoirs over time.” John Chipperfield, senior vice-president at Sproule, notes that companies are continuing to experiment with different evaluation technologies and that Sproule has recently established the position of Manager of New Plays and Technology to ensure that the company understands both the technologies and what their economic impact may be. MacLeod says this evolution in technologies, combined with the geological variability in the resource plays, makes having solid information to create the right development plan crucial. “In some plays, if you do just a statistical analysis, the average result makes a given well economical,” he explains. “But you don’t want to be drilling in areas that bring the average down. You may be better off waiting for the next technological revolution before drilling in those areas. “At the end of the day, we work with clients to find the ultimate development strategy,” he adds. “And that is the one that offers the best return on capital employed.”


nderstanding the economic potential of emerging resource plays in western Canada is a complex challenge facing oil and gas explorers, investors, governments and others with a stake in the industry. The emerging plays represent massive resources measured in trillions of cubic feet of gas and billions of barrels of oil. But they are trapped in heterogeneous reservoirs located across huge geographic areas, making in-place volumes and ultimate recovery levels highly uncertain. And with technologies like horizontal drilling and multistage fracturing in a state of continuous evolution, recognizing how much of that resource can be optimally converted to reserves is a moving target. Enter Sproule Associates Limited and its various technical teams that focus either on geography (Canada, U.S. or international), unconventional technology or project management. Sproule is a global full-service consultancy providing everything from resource and reserve assessments to mergers and acquisitions to field-development and economic-optimization studies to clients around the world. Over the last 60 years, Sproule has completed more than 20,000 studies for around 5,000 clients, ranging from small firms to multinationals. Our fully integrated subsurface teams provide geoscience, geo-modeling, reservoir engineering, reservoir simulation, project planning, economics and regulatory services. “We’re ranked in the top five consultancies by most majors worldwide and are number one or two in some areas,” says Sproule president Keith MacLeod. “When you work with Sproule you get consistent high-quality analysis that you can count on. And you can count on the staff to be there next year and the year after that because we’ve developed a model that encourages low turnover. We’ve also developed one of the best peer review processes in the world, whereby an assessment goes through five levels of review to ensure it is high quality. Sproule utilizes commercially available software tools and a web-based model that allows our clients to

COMPANY NAME: Sproule Associates Limited

TOLL FREE: 1.877.777.6135 T: 403.294.5500 F: 403.294.5590 WEBSITE:

Sproule is a diversified, worldwide petroleum consulting firm. We have been in business for 60 years and have experience in all aspects of the energy sector throughout North America and the World.

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Profiler September 2011  

Alberta Sunrise - Tight oil plays give conventional oil industry new lease on life.

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