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ALL REVVED UP,
READY TO GO Western Canada’s petroleum industry spins its wheels waiting for market access
Inside A province-by-province, play-by-play guide to western Canada’s petroleum industry
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g The What goes into an average extended-reach horizontal of Contents gas Well With multistage-fracture treatment? oadsTableshale JUNE 2014
lopment (first well, all water delivered by truck)
lts in a multi-well pad in the Marcellus shale play in New York City.
All revved up, ready to go 95
drill pad construction
Western Canada’s petroleum industry spins its wheels waiting for market access for growing reserves
COVER PHOTO: ©ISTOCKPHOTO.COM/SSTOP
hydraulic fracturing equipment british columbia fracturing
average number of workers per well
More in the tank New discoveries, improved drilling and completion technology, and enhanced recovery drive oil production growth in Saskatchewan going forward
Waiting for the light to change
number of different oilsands occupations involved in drilling one well Workhorse
Service & Supply
Total one-way loaded Fuel-injected trips per well
Alberta boasts a vast geology of petroleum-soaked rock. Producing it and finding markets for it are the challenges for generations to come.
Operators begin drilling British Columbia’s giant shale gas resource to prove up reserves in advance of LNG exports
Produced water disposal
final pad preparation
Light oil the focus of service and supply sector until LNG projects get green lit or shale oil exploration pays off
Disecting a shale gas well
Oilsands spending to keep chugging along
Tracking the truckloads of materials it takes to drill and complete a shale gas well
sources: all consulting; government of new York 8
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www.lynxcreek.ca 98 NCS Oilfield Services Canada Inc www.ncsfrac.com
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84 Clean Solutions Inc www.cleansolutionsinc.ca 86 Cummins Western Canada www.westerncanada.cummins.com
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16 Terrapro Group of Companies 1 www.terraprogroup.com 18 Thru Tubing Solutions 1 www.thrutubing.com
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29 Kel-Gor Limited www.kelgor.com 20 Meter-Man Flow Products www.meter-man.ca 49
Northwest Machine & Welding (1994) Ltd
50 Paddle Plastics Ltd www.paddleplastics.com P.C. Oilfield Construction Supplies Ltd www.pcoilfield.com 31
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57 Piston Well Services Inc www.pistonwell.com
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27 Skinner Bros Contracting Ltd www.skinnerbros.com 49 Springburn Oilfield Services Ltd www.springburn.biz 19
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47 Target Safety Services Ltd www.targetsafety.ca obc (WWL) Weaver Welding Ltd www.weaverwelding.ca 67 Western Fiberglass Pipe Sales Ltd www.westernfiberglass.net
P R O F I L E R M A G A Z I N E . C O M
Editor’s Note PuBLISHER Maurya Sokolon | firstname.lastname@example.org EDITORIAL Editor Darrell Stonehouse | email@example.com Contributing Writer Jacqueline Louie Editorial Assistance Manager Tracey Comeau | firstname.lastname@example.org
estern Canada has been blessed with a storehouse of petroleum resources. Trapped in the oilsands of Alberta are 1.8 trillion barrels of bitumen, with almost 10 per cent, or 170 billion barrels, recoverable with current technologies. Add to that a conventional heavy oil resource of around 30 billion barrels and a best estimate of 30 billion barrels of tight oil in the early stages of development. Add to that another 462 billion barrels of oil estimated to be trapped in shale deposits yet untapped. Natural gas? The Montney Formation alone has 449 trillion cubic feet of marketable resource, says the National Energy Board (NEB), enough to meet Canada’s requirements for 145 years. The NEB mid-range estimate for the Horn River is 78 trillion cubic feet of natural gas. And these numbers could be dwarfed by shale plays in early development in Alberta. The Alberta government currently pegs the Duvernay shale resource at 443 trillion cubic feet, the Muskwa shale at 419 trillion cubic feet, the Nordegg at 148 trillion cubic feet and the Wilrich at 246 trillion cubic feet, for a total of 1,256 trillion cubic feet of gas in place. This is a world-class resource endowment by any measure. But without new markets, it will remain in the ground. On the oil side of the ledger, the situation is dire. Without the Keystone XL Pipeline to the U.S. Gulf Coast, the Northern Gateway Pipeline and Trans Mountain expansion to Canada’s west coast, and the Energy East Pipeline to Canada’s east coast, western Canadian oil is trapped, says Ed Kallio, director of gas consulting for Ziff Energy, a division of HSB Solomon Associates LLC. And that will have major impacts across the industry. “If we don’t get any of that, then we are in trouble,” he says. “We stay around three million barrels a day, and that’s where we top out. Differentials crater, and you can’t add more oilsands production or even incremental tight oil production.” Natural gas demand would also be affected because current oilsands demand for gas is about 1.3 billion to 1.4 billion cubic feet per day. “By 2020, with this view [the oil pipelines built], we are going to three billion cubic feet per day. If we don’t get this, we top out at 1.3 [billion to] 1.4 billion cubic feet per day on the gas demand side,” says Kallio. Developing the huge natural gas resource, however, depends on more than the oilsands. It will also require liquefied natural gas (LNG) export markets. The NEB estimates, if oil pipelines and LNG export terminals are built, western Canada could be producing 17 billion cubic feet of gas by 2025, up from 12.9 billion cubic feet in 2013. Without the market expansion, it predicts gas production will decline to 8.6 billion cubic feet per day. That’s what’s at stake in the current political battle over new pipelines and export facilities—the future of the industry in western Canada. What is needed at this critical point is the political will to push through projects over the noise created by a loud minority of the Canadian population. We need a leader, and we need it now.
Darrell Stonehouse email@example.com
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Alken Basin Drilling Ltd. Complete Water & Drilling Services The oilfield requires experienced and well-trained drilling technicians to deliver on time—every time. With over 30 years’ experience, Alken Basin Drilling can provide well operators everything from specific services to comprehensive turnkey packages designed to reduce the overall cost of completion.
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ALL REVVED UP,
Western Canada’s petroleum industry spins its wheels waiting for market access for growing reserves By Darrell Stonehouse, with notes from Daily Oil Bulletin staff
The resource tank is topped off and the exploration and production machine is tuned up, but western Canada’s petroleum industry is stuck in second gear until new markets are found for its expanding production potential. While a cold winter across North America offered short-term price relief for natural gas producers, the stubborn supply glut created by the advent of horizontal drilling and multistage fracturing in shale gas and tight gas reservoirs remains. Until liquefied natural gas (LNG) terminals can be built to export some 12
of the massive supply build-ups in northeastern British Columbia and western Alberta, gas markets will remain tight. Wet gas with associated condensate production used for diluent in oilsands transportation is the one bright spot in the natural gas sector. Analysts predict this market will continue to grow as bitumen production increases. This past winter also provided improved markets for oil producers as a number of pipeline projects, rail terminals and refinery upgrades came on stream. Unfortunately, unplanned refinery outages created volatility in the marketplace, keeping the differential between Western Canadian Select and West Texas Intermediate as high as $30 per barrel in December before dropping to around $21 per barrel in January. And despite current stability in the differential, supply will soon catch up to the increased take-away capacity, and like with natural gas, access to new markets will be needed quickly for the industry to grow. For service and supply companies, all this translates into a flat (or barely growing) market until export facilities are built.
his winter has been a welcome respite for natural gas producers, Terry Anderson, senior vice-president and chief operating officer at ARC Resources Ltd., told the CIBC 17th Annual Energy Conference in early April. “It has been a great winter for being cold,” he said. “Personally, I did not want the cold, but from the gas-price perspective, it has been great in that it has driven down the inventories, and we are quite bullish on gas prices in the short term.” The numbers back Anderson’s story. NYMEX prices were up 23 per cent in the first quarter of 2014 compared to the final quarter of 2013. AECO prices were up over 50 per cent compared to the previous quarter and up 75 per cent compared to the first quarter of last year. Regarding macro-demand, Anderson said gas-fired power generation continues to increase year-over-year, the United States continues to export more gas to Mexico and development of LNG projects gives him confi dence in the expansion of that industry. He is, however, still cautious. “Demand seems to be stronger, but we have to be balanced,” he said. “We realize
PHOTO: JOEY PODLUBNY
ready to go
BETTER MARKETS THIS WINTER BUY PRODUCERS SOME BREATHING ROOM
GLj PETROLEUM CONSULTANTS ltd. NATURAL GAS PRICE FORECAST Effective Jan. 1, 2014 Midwest price at Chicago
NYMEX Henry Hub near-month contract (US$/mmBtu)
2012 2013 (e) 2014 2015 2016 2017 2018 2019 2020
Constant 2014 $ 2.89 3.75 4.25 4.41 4.57 4.71 4.85 4.98 5.00
Alberta Plant Gate
AECO/ NIT spot
Then-current Then-current Then-current 2.83 3.71 4.25 4.50 4.75 5.00 5.25 5.50 5.63
2.92 3.84 4.35 4.60 4.85 5.10 5.35 5.60 5.73
2.44 3.24 4.03 4.26 4.50 4.74 4.97 5.21 5.33
Spot Constant 2014 $ 2.29 3.02 3.81 3.97 4.11 4.25 4.39 4.51 4.53
Then-current 2.24 2.99 3.81 4.04 4.28 4.51 4.75 4.98 5.11
2.25 2.98 3.81 4.04 4.28 4.51 4.75 4.98 5.11
1.65 2.63 3.18 3.43 3.68 3.93 4.19 4.44 4.57
2.38 3.14 3.88 4.11 4.35 4.59 4.82 5.06 5.18
2.26 2.91 3.68 3.91 4.15 4.38 4.62 4.86 4.98
Light crude oil
Medium crude oil
2.77 3.70 4.20 4.45 4.70 4.95 5.20 5.45 5.58
Unless otherwise stated, the gas price reference point is the receipt point on the applicable provincial gas transmission system known as the plant gate. The plant gate price represents the price before raw gas gathering and processing charges are deducted.
GLJ PETROLEUM CONSULTANTS LTD. CRUDE OIL PRICE FORECAST Effective Jan. 1, 2014 ICE Brent nearmonth futures contract
NYMEX WTI near-month futures contract (US$/bbl)
2012 2013 (e) 2014 2015 2016 2017 2018 2019 2020
Crude oil at Cushing, Okla. Constant 2014 $ Then-current 96.59 94.21 98.85 97.88 97.50 97.50 95.59 97.50 93.71 97.50 91.88 97.50 90.07 97.50 88.31 97.50 87.50 98.54
Light, sweet crude oil (C$/bbl)
Bow River crude oil (C$/bbl)
Crude oil (40°API, 0.3%S) Stream quality FOB North Sea at Edmonton at Hardisty Then-current Then-current Then-current 111.71 86.60 74.42 108.76 93.33 76.25 107.50 92.76 77.46 107.50 97.37 81.30 105.00 100.00 83.50 102.50 100.00 83.50 102.50 100.00 83.50 102.50 100.00 83.50 102.50 100.77 84.14
Heavy crude oil
Stream quality at Hardisty Then-current 73.13 74.91 75.60 79.36 81.50 81.50 81.50 81.50 82.13
Proxy (12°API) (35°API, 1.2%S) (29°API, 2.0%S) at Hardisty at Cromer at Cromer Then-current Then-current Then-current 63.64 84.51 81.38 65.07 92.29 88.05 65.72 90.91 86.27 70.03 95.42 90.55 72.85 98.00 93.00 72.85 98.00 93.00 72.85 98.00 93.00 72.85 98.00 93.00 73.42 98.75 93.71
Historical futures contract price is an average of the daily settlement price of the near-month contract over the calendar month.
GLJ PETROLEUM CONSULTANTS ltd. ALBERTA NATURAL GAS LIQUIDS PRICE FORECAST Effective Jan. 1, 2014 (Then-current dollars) Spec ethane
--13.26 14.08 14.89 15.71 16.53 17.34 17.77
29.04 38.49 57.83 58.42 60.00 60.00 60.00 60.00 60.46
2012 2013 2014 2015 2016 2017 2018 2019 2020
that when you talk about the supply, the Marcellus has that ability to grow production and build-out some of that infrastructure. And so we’re balanced, and we see that with supply in the Lower 48, they can build up some of that production.” Even in Alberta, he said, natural gas demand is strong, measuring up to six billion
Edmonton butane (C$/bbl)
66.70 68.65 73.22 75.95 78.00 78.00 78.00 78.00 78.60
Edmonton pentanes plus (C$/bbl)
100.84 104.40 105.20 107.11 107.00 107.00 107.00 107.00 107.82
cubic feet per day, which bodes well for the price producers can get for that commodity. “I think, as a general theme, if you look overall, gas prices are in the $4–$5-perthousand-cubic-feet range over the next while here, and that is where we see things, he said. Although natural gas prices are showing improvements, Anderson said ARC would
remain disciplined with its capital spending in the short term. “We’ve had our budget planned out, and we are very big into planning out our budget and trying to stick to that, as it helps with capital cost efficiencies,” he said. John Williams, president and chief oper ating officer at Trilogy Energy Corp., said it has only been a few months that gas prices have been relatively high, and he does not think people are changing their capital spending programs in accordance with higher gas prices until they see long-term pricing improvements. However, he said, it is very nice to see added cash flow on the balance sheet. “I think companies in the short term will just put it in the bank. It probably takes about six months for people to reallocate capital wisely. For example, most companies would have a minor amount of prospects surveyed and ready to go, but I don’t think they could turn around and wisely invest in a 50 per cent increase in drilling activity.” P R O F I L E R M A G A Z I N E . C O M
Will the tight oil boom continue? The advent of tight oil development in western Canada has kept the conventional service and supply industry afloat in a sea of uncertainty created by the decline of natural gas drilling due to the shale gas boom in the United States. The number of oil wells drilled across western Canada has climbed from 3,219 wells in 2009 to 8,117 wells completed in 2013, according to Daily Oil Bulletin statistics. Tight oil production from horizontal wells averaged over 300,000 barrels per day in 2013. The Canadian Association of Petroleum Producers (CAPP) expects tight oil exploration and development to continue through to at least 2030. In CAPP’s 2013 oil forecast, it expects conventional crude oil production from western Canada to reach 1.4 million barrels per day by 2030, a 300,000-barrel-per-day increase from its 2012 forecast. “The impact of steep declines expected from mature oilfields is expected to be entirely offset from horizontal wells,” says CAPP. “Horizontal drilling has doubled, or even tripled, the percentage of the resource that industry expects to be recovered from the reservoir.” Alberta is expected to see its production increase from 556,000 barrels per day in 2012 to 813,000 barrels per day by 2030. But CAPP believes this number could go up. “With only a few years of production data from horizontal wells, it’s too early to establish the ultimate flow rates for wells drilled using the newer technology,” the association says. “However, if the early performance is any indication, CAPP’s current forecast outlook may be conservative.” Another wild card in the Alberta forecast is the six shale formations in Alberta with an estimated 462 billion barrels of resource in place. CAPP cautions that, while this number is huge, typically less than five per cent of the resource in place is recoverable. But this would still mean as much as 20 billion barrels of potential new reserves. CAPP expects Saskatchewan production to increase by around 20,000 barrels per day by 2030.
WCSB TIGHT OIL PLAY 2013 HORIZONTAL PRODUCTION Play
Viking Beaverhill Lake Lower Shaunavon Alberta Bakken Saskatchewan/ Manitoba Bakken Amaranth Montney Slave Point Cardium Total
Operated wells 2,282 582 733 59
41,014 19,099 17,268 3,791
1,000 538 315 1,941 10,959
15,859 33,293 9,511 74,802 296,699
All production is estimated based on Q2/2013 data. Sources: Scotiabank Playbook; Daily Oil Bulletin; SEDAR
But Williams said higher prices might encourage companies to sell production rather than banking it for next winter. “We’re pretty bullish on long-term natural gas prices,” he said, adding that with the “tail of the curve declining,” he does not think there is much motivation for people to put gas into storage to draw out later in the year. “Until we see positive pricing in 2015 and beyond, I don’t think people are going to inject. So it is going to create a long-term shortfall in natural gas,” he said. While the spot price of natural gas was off nearly 38 per cent from February, the monthly 14
J une 2 0 1 4
COMMERCIAL TIGHT OIL PLAY RESOURCE POTENTIAL Resource in place
Recovered to date
Swan Hills (BHL)
Source: CIBC World Markets
AECO average of $4.89 per gigajoule in March was still the highest in more than four years. Oil producers can also look toward some short-term stability in prices, according to FirstEnergy Capital Corp. In late March the analysts reported that heavy to light oil differentials seem to have leveled off in the $20– $25-per-barrel range. “We believe the North American crude market is gradually becoming less encumbered by infrastructure issues,” FirstEnergy noted. “There may still be some seasonal swings up and down, but we think that infrastructuredriven price blow-outs may be starting to become a thing of the past.”
Huge U.S. production upswing radically altering North American marketplace hile the past winter marked an uptick for western Canadian producers, the structural problems backing up the Canadian industry remain. U.S. natural gas and oil supplies continue climbing, meaning the huge market to the south will no longer soak up all of western Canada’s excess production. In fact, on the natural gas front, U.S. production is already pushing out Western Canadian Sedimentary Basin production from domestic markets in eastern Canada. In April, the U.S. Energy Information Administration (EIA) updated its 2014 natural gas production outlook, and it’s not good news. The EIA predicted 2014 natural gas production would jump by 2.11 billion cubic feet per day, or three per cent, to 72.29 billion cubic per day. This represents the fourth straight annual production record, and in 2015, production is forecast at 73.34 billion cubic feet per day. The EIA said the colder than normal winter drew U.S. gas inventories down to 822 billion cubic feet at the end of March, the lowest in 11 years. But it predicts a record injection season will follow over the spring and summer of 2.6 trillion cubic feet, which will rebuild gas in storage to 3.422 trillion cubic feet by the end of October. U.S. oil production and reserves also continue rising at record rates. In mid-April, oil production hit 8.3 million barrels per day, its highest level since 1988. And the EIA is projecting continued production growth for at least the next 15 years. Where are things headed? In the EIA’s 2014 outlook, crude oil production will rise to 9.6 million barrels per day before 2020 in its reference case, a production level not seen since 1970. Tight oil production growth accounts for 81 per cent of this increase and sees its share of national crude oil production grow from 35 per cent in 2012 to 50 per cent in 2019. In its high resource case, U.S. crude oil production reaches 11.3 million barrels per day in 2019 and 13.3 million barrels per day in the mid-2030s. The EIA expects imports to fall to 25 per cent of U.S. oil consumption by 2020 in its reference case. In its high-resource case, net U.S. oil imports will continue to decline
U.S. CRUDE OIL PRODUCTION FORECAST (Three SUPPLY CASES) 2013 2014 2015 2016 2017 2018 2019 2020 2025 2030 2040
AEO14 Reference 7.72 8.53 9.04 9.54 9.56 9.58 9.61 9.55 9.00 8.30 7.48
AEO14 High Resource 7.87 8.92 9.84 10.31 10.80 11.10 11.30 11.41 12.51 12.85 13.22
AEO14 Low Resource 7.57 8.45 8.81 9.18 9.10 9.07 9.03 8.85 7.98 7.05 6.61
The total unproved technically recoverable crude oil resources are 401 billion barrels in the High Oil and Gas Resource case and 180 billion barrels in the Low Oil and Gas Resource case, compared to 209 billion barrels in the Reference case. Source: EIA’s Annual Energy Outlook 2014
U.S. NATURAL GAS SUPPLY/IMPORTS FORECAST (REFERENCE CASE) (TRILLION CUBIC FEET) Supply, disposition and prices Dry gas production Supplemental natural gas Pipeline Net imports Liquefied natural gas Total supply Production
2013 24.19 0.06 1.22 0.12 25.59
2014 24.28 0.07 1.21 0.14 25.69
2015 24.63 0.06 1.05 0.04 25.78
2016 25.68 0.06 0.92 -0.16 26.50
2017 26.38 0.06 0.64 -0.61 26.47
2018 27.20 0.06 0.45 -1.11 26.61
2019 28.19 0.06 0.22 -1.62 26.85
2020 29.09 0.06 0.00 -1.93 27.23
2025 31.86 0.06 -0.84 -2.57 28.52
2030 34.43 0.06 -1.57 -3.37 29.56
Source: EIA’s Annual Energy Outlook 2014
NATIONAL ENERGY BOARD wcsb NATURAL GAS PRODUCTION OUTLOOK (THREE SCENARIOS) (BILLION CUBIC FEET PER DAY) Reference Low High
2009 14.7 14.7 14.7
2013 12.9 12.8 12.9
2014 12.2 11.8 12.3
2015 11.6 11.0 11.9
2016 11.2 10.2 11.9
2017 11.0 9.6 12.1
2018 11.0 9.1 12.5
2019 11.2 8.7 13.1
2020 11.5 8.4 13.7
2025 13.3 8.6 17.0
2030 15.2 9.4 19.5
2035 17.4 11.2 21.8
Source: NEB’s Canada’s Energy Future 2013
NATIONAL ENERGY BOARD CANADIAN OIL PRODUCTION FORECAST (REFERENCE CASE) (MILLION BARRELS PER DAY) Conventional light Conventional heavy C 5+ Field condensate Mined bitumen In situ bitumen Upgraded bitumen Total
2013 0.94 0.49 0.13 0.02 1.06 1.02 1.02 3.66
2014 0.90 0.51 0.12 0.02 1.12 1.15 1.06 3.83
2015 0.94 0.52 0.11 0.02 1.13 1.30 1.09 4.02
2016 0.93 0.52 0.11 0.02 1.18 1.49 1.14 4.25
2017 0.93 0.50 0.10 0.02 1.25 1.64 1.18 4.44
2018 0.97 0.48 0.09 0.02 1.31 1.74 1.27 4.62
2019 0.94 0.46 0.09 0.02 1.35 1.86 1.33 4.71
2020 0.87 0.43 0.09 0.02 1.44 1.98 1.35 4.82
2025 0.82 0.35 0.09 0.01 1.70 2.49 1.44 5.45
2030 0.60 0.29 0.09 0.01 1.80 2.88 1.55 5.68
2035 0.46 0.26 0.10 0.01 1.80 3.21 1.59 5.84
Source: NEB’s Canada’s Energy Future 2013
through the mid-2030s and remain at or near zero between 2035 and 2040. Canadian natural gas markets are already seeing the damage wrought by the shale gas boom south of the border. Pipeline operators provide a clear example. A new assessment released in April by the National Energy Board (NEB) shows the rise of the Marcellus shale in the northeastern United States has been the main culprit in killing demand for western Canadian gas. Marcellus shale production has climbed from 2.1 billion cubic feet per day in 2008 to 12.3 billion cubic feet per day in 2013. This has resulted in a reversal of gas flows in the Tennessee Gas Pipeline that connects with TransCanada Corporation’s mainline system at Niagara Falls, Ont. In 2008, 600 million
cubic feet per day of western Canadian gas was exported into the United States through the Niagara Falls export point. In 2013, 400 million cubic feet per day of Marcellus gas was imported into Ontario from the same terminal, meaning western Canadian producers have lost around one billion cubic feet of market share at this terminal alone. Significant new pipeline capacity bringing U.S. shale gas to traditionally western Canadian markets has added to the woe. The six-billion-cubic-feet-per-day mainline is now running at 29 per cent of capacity, down from 45 per cent in 2011 and 34 per cent in 2012. Western Canadian gas production has been devastated as a result. In 2008, when the Marcellus build-out began, the region was
producing 15.7 billion cubic feet per day. Last year, it had declined to 12.9 billion cubic feet per day, a drop of 2.8 billion cubic feet per day. The natural gas drilling industry has also been hammered. In 2008, 9,767 gas wells were drilled. Only 1,332 were drilled last year. While gas pipelines run empty, oil pipelines face a different problem, says the NEB. Increased oilsands production, combined with tight oil growth, has existing pipelines full. “Rapid growth in western Canadian oilsands and U.S. tight oil production created a surplus of oil in the mid-continent since 2011, exacerbated by limited pipeline cap acity to coastal markets,” says the NEB, adding that, although oil pipeline capacity out of western Canada has recently been added, constraints on connecting pipelines and P R O F I L E R M A G A Z I N E . C O M
capacity reductions on major lines continued limiting the capacity in 2013. One example of this exists on Enbridge Inc.’s Mainline Enbridge and Lakehead systems that, combined, are designed to export about 2.5 million barrels per day. Unfortunately, constraints on sections of the U.S. system have reduced the actual crude oil capacity out of western Canada to Superior, Wis., to about 1.9 million barrels per day, says the study. In 2012, throughput averaged 1.8 million barrels per day, and that decreased slightly in the first half of 2013 to 1.77 million barrels per day. Western Canada has seen a rapid rise in oil production since 2008, with production climbing by one million barrels per day to 3.4 million barrels per day in 2013. The NEB expects that number to climb by more than one million barrels per day by 2020 to 4.5 million barrels per day. That is if oil producers can connect to new markets, Patricia Nelson, vice-chair for the In Situ Oil Sands Alliance, said at a Canadian Institute Conference late last year. Not only must all current pipeline projects connecting the oilsands to new markets be approved and completed in a timely fashion, but new ones must be added to the list as well, and quickly, or the impact on Canada’s economy could be dire, she said. “We are getting to a point where we have to have this go forward fast. It’s not optional anymore,” said Nelson. She said oilsands exports must expand into the global arena, and they must do it soon, because while she does not foresee exports to the United States shrinking, there is not much room for growth in that market anymore either. “If you can’t get to market, there’s no point in producing, and I don’t know what you’re going to do with the product. So we’re in a serious situation,” she said. 16
maSSiVE nEw potEntial SuppliES add to markEting prESSurES hile western Canada’s petroleum industry struggles to find markets for its existing production potential, a possible bonanza of new conventional oil and gas is on the horizon. In late 2013, the NEB, along with the Alberta and B.C. governments, released a study on the potential of the Montney play straddling the border of Alberta and British Columbia. The study found there is approximately 450 trillion cubic feet of marketable natural gas, 14.5 billion barrels of marketable natural gas liquids (NGLs) and 1.125 billion barrels of marketable oil in the play. “At current consumption rates, the Montney gas resource would meet Canadian needs for 145 years,” says Gaétan Caron, the NEB’s chair and chief executive officer. “The report clearly shows that Canadian energy markets will be well supplied with natural gas far into the future.” And that’s only part of the story. A previous NEB study of the Horn River shale play in northeastern British Columbia found another 48 trillion cubic feet of marketable gas in that play. And then comes the recent Alberta Energy Regulator (AER) study into the scope of the province’s shale and siltstone resource base. The AER study found a mind-boggling total resource in place of 3,424 trillion
cubic feet of natural gas, 58.6 billion barrels of natural gas liquids (NGLs) and 423.6 billion barrels of oil in shale and siltstone formations in Alberta. The Duvernay, the furthest play into commercial development, has an estimated 443 trillion cubic feet of natural gas, 11.3 billion barrels of NGLs and 61.7 billion barrels of oil. Dean Rokosh, section leader of energy resource appraisal for the geology and environmental sciences branch at the AER, described it as a world-class resource with very high numbers, and he expects those numbers to increase as researchers learn more about it. “I do want to stress that we tried to be reasonable in everything we did. We didn’t want anything to be hype here.” The Muskwa has an estimated 419 trillion cubic feet of gas, 14.8 billion barrels of NGLs and 115.1 billion barrels of oil. Husky Energy Inc. drilled around 10 wells into this play in 2013 and is in the early stages of testing out technologies to develop it. The Basal Banff/Exshaw has an estimated 35 trillion cubic feet of gas, 92 million barrels of NGLs and 24.8 billion barrels of oil. To a large degree, the Exshaw is listed as preliminary because of the middle unit, which has highly variable lithology, said Rokosh. He added, “If anything, we’ll have to go back to this and try to establish the relationship between those various lithologies and porosity.”
PHOTO: JOEy PODLUBNy
Pipeline construction is needed now to sustain growth in oil production.
The Nordegg has an estimated 148 trillion cubic feet of gas, 1.4 billion barrels of NGLs and 37.8 billion barrels of oil resources in place, while the Wilrich, which is also under development, has 246 trillion cubic feet of gas, 2.1 billion barrels of NGLs and 47.9 billion barrels of oil. The remaining resource is Alberta’s share of the Montney. And Rokosh says there is more to come. “This is not an end—this is a beginning for us,” he said of the report, stressing that researchers were extremely conservative when estimating the formations’ shale resource. “Those numbers will get bigger and probably be substantially larger.” Add to this the 1.8 billion barrels of bitumen in northeastern Alberta, the 30 billion barrels in tight oil plays across western Canada, the 30 billion barrels of heavy oil resource and the more than 40 trillion cubic feet of conventional gas reserves. Western Canada could, conceivably, be the largest petroleum tank in the world. It just needs to find customers who want it.
LNG to the rescue? ust how bad will western Canadian gas markets get without new markets? In the NEB’s low case, where no new gas markets are found, production declines to 8.4 billion cubic feet per day by 2020, almost half of its peak in 2006. Industry is hoping LNG exports can help avoid this scenario. In its best-case scenario, where new markets are found for western Canadian gas, the NEB forecasts production rising to almost 14 billion cubic feet per day by 2020 and continuing to climb to 20 billion cubic feet per day by 2030. The NEB has approved eight LNG export licences, with four more working their way through the regulatory process. While some groundwork is under way at one facility, no licences have been given the green light by their ownership. While the analyst community does not know when LNG projects will start exporting natural gas off the west coast of British Columbia, Anthony Petrucci, vice-president and midcap oil and gas analyst at Canaccord Genuity, said there is already material capital
B.C. LNG PLANT PROPOSALS Proponents
Nexen Energy ULC, INPEX Corporation, JGC Exploration Canada LNG Partners, Haisla Nation Chevron Canada Limited, Apache Canada Ltd. Krishnan Suthanthiran Shell Canada Energy, Korea Gas Corporation, Mitsubishi Corporation, PetroChina Company Limited PETRONAS, Japan Petroleum Exploration Co., Ltd. BG Group Altagas Ltd., Idemitsu Kosan Co., Ltd. ExxonMobil Canada, Imperial Oil Limited Woodfibre Natural Gas Limited Total
3.12 0.24 1.28 2.64
Facility Aurora LNG B.C. LNG Kitimat LNG Kitsault Energy LNG Canada Pacific Northwest LNG Prince Rupert LNG Triton LNG WCC LNG Woodfibre LNG
3.23 2.74 2.91 0.31 4.00 0.29 20.76
Source: Clean Energy Capitalists
being spent from groups on some of the proposed projects, and that spending will only increase over the next few years. “We’ve had some groups come out and talk about their final investment decisions for either later this year or into next, and this is where they will actually decide whether to go ahead, and we will have a much better sense of timing for when these projects might start,” he said at Cannacord’s Spring Energy Outlook. He added that of the two or three projects most likely to start exporting, those groups are suggesting exports by 2017-18, although analysts more often suggest 2020. Of the many proposed projects, Petrucci said it appears the Kitimat LNG, Pacific NorthWest LNG and LNG Canada projects are the most likely to be completed first. However, he said, even if only two or three projects go through in the next few years, it will still have a tremendous impact for natural gas producers. “If all the proposed projects in B.C. were to go ahead, we would get to about 12 billion cubic feet per day of incremental demand to fill all those plants,” he noted. “But we only think two or three will go ahead and probably scale up over time. Let’s say those start off at five billion cubic feet per day, well, current production is about 13 [billion] to 14 billion cubic feet per day. So this is clearly a material piece of the pie.” Chevron Corporation, the operator of the proposed Kitimat LNG export terminal, says a “meeting of the minds” on pricing between LNG buyers and sellers is needed to ensure export projects get built. Speaking at the company’s annual security analyst meeting in New York City, John
Watson, chair and chief executive officer, said there’s “a lot of tension right now” in the gas market between buyers and sellers. “It’s easy to explain why. We’re seeing very low natural gas prices in the U.S.,” he said. “Whether it’s customers in Japan or in Europe, they have to compete with American businesses, and they’re seeing the advantage of low-cost gas, and they want some of it, both for their businesses and for their consumers.” Because of this, the buyers are trying to push prices down. “That’s a natural thing for them to do,” Watson said. “Our view has been for a long time that for the Asian market, oil-linked pricing made more sense.” “We think the realities of costs are such that it’s going to take stronger prices,” he added. “If you look at some of the very low price expectations that have been cited in the media, our projects won’t go ahead with those prices, whether in Kitimat or Australia.” “It’s going to take a meeting of the minds by customers and suppliers,” Watson said. “Right now, I don’t think that we are marketlimited in selling LNG, we’re supply-limited and that’s why you’re seeing spot prices above crude parity right now. I think it’s important that the industry and customers find that meeting of the minds so that our industry can continue to meet the energy needs that are out there by the 29-some countries that are now importing LNG.” For the Kitimat project, spending is being directed at engineering, site work and appraisal work in the Liard Basin, says George Kirkland, Chevron vice-chair and executive vice-president of upstream. P R O F I L E R M A G A Z I N E . C O M
“We need to do more assessment work in Liard, and we need to be ready to move if we have gas sale agreements made,” he notes. “We expect we’ve still got another year of assessment work on Liard, and once again, we’ve got to have gas sales contracts. We’re not going to expose the big money, post an FID [final investment decision] period, until we have gas-sale contracts in hand.” The company has said it wants at least 60–70 per cent of Kitimat LNG supply under long-term agreement before announcing a FID on the project. Other companies are taking a more waitand-see attitude toward LNG exports. Imperial Oil Limited’s decision on whether to build a B.C. LNG export plant is still several years away, top executives said in April. “We believe it will take several more years before we will find ourselves in a position to determine whether an LNG opportunity on the west coast of Canada can, or would, be an attractive opportunity we would pursue,” Paul Masschelin, Imperial’s senior vice-president of finance and administration, told the company’s investor conference in New York.
Although Imperial and its parent company, Exxon Mobil Corporation, have received a natural gas export permit for such a venture, the companies are in the “very early evaluation stages of a potential LNG project,” Masschelin said. “By nature, LNG projects are very complex,” he said, noting that the companies are pursuing all the elements “in parallel”—including the gas resource, a fiscal and regulatory regime, pipelines, liquefaction facilities, seagoing tankers, re-gas facilities and markets. Speaking to reporters on a conference call afterward, Rich Kruger, Imperial’s chair, pres ident and chief executive officer, drove home the same point. Asked why Imperial believes the export opportunity will still exist in several years, Kruger said: “More than anything, we look at and want to ensure the quality and the value of a project. And we won’t rush aspects of it because we’re afraid we might miss out. It has to be a quality project.” All aspects have to fit together, he said, “not the least of which is a fiscal and regulatory regime.”
He stressed that “whatever time it happens to take is what it will take. And if there’s value and a place in the market, then it’ll be a project. And if there’s not, it won’t go.”
All options on the table for oil exports ransCanada Corporation’s start-up Gulf Coast Pipeline and expansions at Enbridge’s Seaway and Flanagan South pipelines are helping to link western Canadian oil production to new markets in 2014 and also levelling off volatility in oil pricing. Growth in rail transportation is also creating marketing options, with current rail-loading capacity in western Canada estimated at between 300,000 and 400,000 barrels per day, up from about 150,000 barrels per day one year ago. But a lot more needs to be done if western Canada expects to continue growing supply, Robert Mason, managing director at TD Securities Inc., told the audience at Insight
EXPORT OIL PIPELINES (RECENTLY BUILT OR PROPOSED) Project
Completed projects Keystone Phase 1
Keystone Phase 2 (Cushing extension)
TransCanada Corporation Enterprise Products Partners, L.P./Enbridge Inc. Enterprise Products Partners, L.P./Enbridge Inc. Enbridge Inc. Enbridge Inc. TransCanada Corporation
Seaway Reversal Phase 1 Seaway Reversal Phase 2 Spearhead North Expansion (Line 62) Line 9A Reversal Gulf Coast (Keystone XL southern leg)
Steele City, Neb.
Steele City, Neb., and Wood River and Patoka, Ill. Cushing, Okla.
Flanagan, Ill. Sarnia, Ont. Cushing, Okla.
Griffith, Ind. Westover, Ont. Nederland, Texas
105,000 240,000 700,000
Late 2013 Late 2013 January 2014
Approved/under construction Seaway twinning/looping Flanagan South Clipper (Line 67) Phase I Batching improvements
Enterprise Products Partners, L.P./Enbridge Inc. Enbridge Inc. Enbridge Inc. Enbridge Inc.
Flanagan, Ill. Hardisty, Alta. --
Cushing, Okla. Superior, Wis. --
600,000 120,000 ?
Mid-2014 Mid-2014 --
Enbridge Inc. Enbridge Inc. Energy Transfer Partners, L.P. Enbridge Inc. TransCanada Corporation Enbridge Inc. Enbridge Inc. Enbridge Inc.
Superior, Wis. Westover, Ont. Johnsonville, Ill. Superior, Wis. Hardisty, Alta. Hardisty, Alta. Beaverlodge, N.D. Clearbrook, Minn.
Flanagan, Ill. Montreal, Que. St. James, La. Flanagan, Ill. Steele City, Neb. Superior, Wis. Clearbrook, Minn. Superior, Wis. Montreal and Quebec City, Que., and Saint John, N.B. Burnaby, B.C. Kitimat, B.C.
160,000 300,000 420,000 640,000 830,000 230,000 225,000 375,000
Mid-2014 Q4/2014 Mid-2015 H2/2015 2015 2015 2016 2016
Proposed Line 61 (southern access) Expansion Phase 1 Line 9B Reversal & Expansion Eastern Gulf Crude Access Line 61 (southern access) Expansion Phase 2 Keystone XL Clipper (Line 67) Phase II Sandpiper (N.D.-Minn.) Sandpiper (Minn.-Wis.) Energy East
Trans Mountain twinning Northern Gateway
Kinder Morgan Canada Enbridge Inc.
Edmonton, Alta. Edmonton, Alta.
*Completion dates shown are as currently targeted. Sources: Peters & Co. Limited; company reports
J une 2 0 1 4
Information’s 11th Annual Canadian Oil Sands Summit. Limited market access to export western Canadian crude, both light and heavy, is the most important issue facing the industry and possibly the country, said Mason. It has resulted in extremely large price discounts for Canadian crudes in the past three years and had a “very significant” impact on the overall Canadian economy of between $20 billion and $30 billion in lost revenues in 2012 and 2013, he said. “That’s not just revenues to companies but revenues to tax dollars and royalties to various levels of government. When you add that up, that equals roughly 1.2–1.8 per cent of Canada’s gross domestic product, to put it in context.” With the U.S. government once again delaying its decision on the Keystone XL Pipeline in mid-April, the importance of linking to markets in eastern Canada and overseas is becoming even more crucial. John Van der Put, vice-president of eastern oil pipeline projects at TransCanada, said that even if U.S. President Barack Obama approves Keystone XL, it would only meet the demand of producers up until 2017. “We need to move forward with all the major pipeline projects that are currently under development, such as Enbridge Inc.’s Northern Gateway project, such as Kinder Morgan Inc.’s expansion of it Trans Mountain Pipeline, and of course the Energy East Pipeline that we are proposing,” Van der Put told a recent Canadian Institute conference. “We also expect that we will need other pipeline projects, beyond the ones I’ve just mentioned, in order to provide the infrastructure needed to get oil to market and to realize the tremendous benefits associated with that resource,” he added. According to Van der Put, Energy East would benefit refineries in Quebec and New Brunswick by providing them with access to less costly domestic crude. It also would benefit western Canadian producers by providing a significant amount of incremental capacity to new markets. He said the entire country’s economy benefits from the proposed pipeline project. “This project will mean a $10-billion addition to the country’s fiscal revenues through the first 40 years of the pipelines operations,” he said, adding that the Energy East Pipeline would also provide access to international markets such as India. Van der Put told the conference that TransCanada would file its application with the NEB in mid-2014, with physical work
on the pipeline project expected to occur in 2016. In the meantime, he said, communicating with all Canadians about to the value of the project is an increasingly vital task for the company. With U.S. markets for western Canadian gas production in steep decline, repurposing pipelines like the TranCanada mainline to export crude oil as proposed in the Energy East project may provide a partial solution to marketing issues, according to Ed Kallio, director, gas consulting, Ziff Energy, a division of HSB Solomon Associates, LLC.
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Kallio told the Canadian Energy Research Institute conference in March that current natural gas capacity out of the Western Canadian Sedimentary Basin is 15.7 billion cubic feet per day, and Ziff Energy is forecasting that it will decline to just over five billion cubic feet per day by 2020 as a projected 19 billion cubic feet per day of Marcellus and Utica production displaces western Canadian gas. At the same time, western Canadian oil production is forecast to increase to about 5.1 million barrels per day in 2022, and Ziff
“ But if there are problems with the rail, if there are problems with the Energy East conversion, if we don’t get Keystone, Trans Mountain, if we don’t get any of that, then we are in trouble. We stay around three million barrels a day, and that’s where we top out.” — Ed Kallio, director, gas consulting, Ziff Energy
Energy sees another one million barrels per day after that. “We need more oil pipe; we certainly don’t need more gas pipe,” he said. Between now and 2020, there will be a need for roughly an additional two million barrels per day of oil export capacity, said Kallio. TransCanada’s proposed 1.1-million-barrel-perday Energy East project—which will convert
unused gas pipeline to oil service and build new pipe—coupled with one million barrels per day of planned new rail capacity should handle the incremental two million barrels per day of western Canadian crude forecast to come on production by 2020, he said. “But if there are problems with the rail, if there are problems with the Energy East conversion, if we don’t get Keystone, Trans Mountain, if we don’t get any of that, then we are in trouble,” Kallio said. “We stay around three million barrels a day, and that’s where we top out,” he said. “Differentials crater, and you can’t add more oilsands production or even incremental tight oil production.” Natural gas demand would also be affected because current oilsands demand for gas is about 1.3 billion to 1.4 billion barrels per day, the conference was told. “By 2020, with this view, we are going to three billion cubic feet per day. If we don’t get this, we top out at 1.3 [billion], 1.4 billion cubic feet per day on the gas demand side.” In terms of providing new oil market access, Energy East “is a great proposition for shippers,” with a toll of roughly $4–$5 per barrel from the Alberta-Saskatchewan border to tidewater, based on a 36-inch diameter pipeline, said Kallio. The Ontario Energy Board is reviewing the project’s effect on consumers and has contracted Ziff Energy to do the market analysis. The project is also a way to take some of the assets off the gas books and transfer them onto the oil books, which also benefits the gas shippers on the TransCanada system, he suggested. Another western Canadian candidate for repurposing is the Alliance Pipeline, a bullet
line that transports liquids-rich gas from northeastern British Columbia to the Chicago area where liquids are extracted at the Aux Sable Liquid Products Inc. plant, Kallio suggested. Ziff Energy is forecasting that Alliance volumes will decline to 870 million cubic feet per day from the current 1.5 billion cubic feet per day. “We see the Alliance system as potentially having problems down the road,” he said, noting that in 2010, less than 10 per cent of the shippers on the line opted to re-contract in 2015 when their contracts are set to expire. “We could see repurposing to oil, we could see them stripping liquids out, potentially around Edmonton, and turning it into a dry gas line.” Kallio said that, while he’s sure Alliance has looked at conversion to an oil pipeline, if it were to cross the border, it would require a U.S. Presidential permit, and there is no assurance that it would get one in light of what Keystone XL has faced. However, Alliance hasn’t yet had to back out Canadian gas, Tim Stauft, president and chief executive officer of Aux Sable, later said. It could either do so or expand capacity in the Bakken, he said. The growth in liquids in the Marcellus and Utica has actually helped Aux Sable fill out its fractionation as a lot of what is produced is mixed streams, and a lot of the fractionation is typically done elsewhere, Stauft told the conference. There currently are several NGL pipelines bringing mix to the U.S. Gulf Coast, and they likely will draw more and more Marcellus NGLs south rather than west, helping Aux Sable maintain its competitiveness in the Midwest in terms of selling a spec product, he said.
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Columbia BritishBritish Columbia
UP Operators begin drilling British Columbia’s giant shale gas resource to prove up reserves in advance of LNG exports By Darrell Stonehouse, with notes from Daily Oil Bulletin staff
Photo: joey podlubny
ortheastern British Columbia has gas to burn. The advent of horizontal drilling and multistage fracturing has opened up a massive shale gas resource to development. The Montney hybrid shale-siltstone play alone contains almost 2,000 trillion cubic feet of gas. Add to that an estimated 500 trillion cubic feet in the Horn River, and an equal or greater amount in the Liard Basin, and the scope of the resource at play in northeastern British Columbia becomes beyond comprehension. But efforts are underway to understand how much of this resource is recoverable. A National Energy Board (NEB) study expects between 200 trillion cubic feet to 364 trillion cubic feet of marketable gas could be developed in the B.C. Montney. An earlier study puts the figure from the Horn River at 48 trillion cubic feet. The Liard Basin is too early in development, but it is expected to equal or surpass the Horn River. Drillers have been busy proving their ability to produce this gas. In the BC Oil and Gas Commission’s latest reserves report covering
until the end of 2012, reserves reached their highest level in history in the province at 40.2 trillion cubic feet. It was the 12th year running with reserve additions. The Montney represents 33 per cent or 13.4 trillion cubic feet of the province’s remaining recoverable gas reserves. In 2012, 600 billion cubic feet was produced from the play, accounting for 40 per cent of total gas production in the province. The Horn River Basin represents 28 per cent or 11.1 trillion cubic feet of the province’s recoverable gas reserves. In 2012, 100 billion cubic feet was produced from the Muskwa–Otter Park and Evie formations within the Horn River, accounting for 11 per cent of total production in the province. The Liard Basin is a new unconventional resource in northeastern British Columbia, with 104 billion cubic feet booked in 2012, based on production from three existing wells—two vertical and one horizontal. With promising initial results and a prospective area of one million hectares, the Liard Basin is a potentially large future gas-producing region, the report states.
With one of the world’s great gas resources underlying the province, the B.C. government is hoping liquefied natural gas (LNG) exports will turbocharge its economy in the coming decades, bringing in between $130 billion and $260 billion in government revenues over 30 years, according to its figures. The figures, based on studies from independ ent consultants, are premised on the construction of two large and three smaller-scale LNG export facilities. The estimates include direct taxes paid by the LNG facilities and the royalties received by the provincial government from natural gas extraction needed to support those facilities. They also include additional revenues through personal income taxes from new jobs the industry creates. These estimates do not include additional potential revenues from other increased B.C. economic activity generated as a result of the LNG opportunity. There are currently 10 proposed LNG export terminals in the province. While none have been given the go-ahead by their owners, there are signs drilling is beginning to ramp up to ensure supply is ready when the shovels finally hit the ground. P R O F I L E R M A G A Z I N E . C O M
"I nitially, during the ramp-up, land grab and production testing, it could be as many as 40 rigs per billion cubic feet, but as the business matures, it comes down to 25 rigs per billion cubic feet, which will likely all be new-build pad rigs, capable of drilling all year round." — Kevin Neveu, chief executive officer, Precision Drilling Corporation, on LNG's effects on drilling contractors
B.C. 2013 TOP OPERATORS
B.C. NATURAL GAS PRODUCTION BY PLAY (2013 AVERAGE PRODUCTION)
% of total production
Progress Energy Canada Ltd.
Source: B.C. Ministry of Natural Gas Development
RESOURCE POTENTIAL FOR MAJOR B.C. TIGHT GAS PLAYS Total gas resource (tcf)
Deep Basin Cardium/Dunvegan
Royal Dutch Shell plc
ARC Resources Ltd.
Talisman Energy Inc.
Canadian Natural Resources Limited Deep Basin (Cadomin)
Encana Corporation Conventional
Harvest Operations Corp.
Tourmaline Oil Corp.
Crew Energy Inc.
Devon Canada Corporation
Imperial Oil Resources Limited
Painted Pony Petroleum Ltd.
Storm Resources Ltd.
Murphy Oil Company Ltd.
Canbriam Energy Inc.
Artek Exploration Ltd.
Apache Canada Ltd.
Black Swan Energy Ltd.
Quicksilver Resources Canada Inc.
Source: Daily Oil Bulletin
B.C. LAND SALES
Source: B.C. Ministry of Natural Gas Development
june 2 0 1 4
Average price/ hectare
$1,886.60 Source: Daily Oil Bulletin
ULTIMATE POTENTIAL FOR MONTNEY UNCONVENTIONAL PETROLEUM IN BRITISH COLUMBIA Hydrocarbon type
Natural gas (trillion cubic feet) NGLs (million barrels) Oil (million barrels)
Resource in place
Source: National Energy Board
Photo: nexen energy ulc
Montney leading race to supply LNG exports Progress Energy Canada Ltd., a subsidiary of Malaysia’s PETRONAS, is leading the pack when it comes to proving up its massive Montney resource in anticipation of LNG exports. While PETRONAS won’t decide until the end of this year whether to export LNG from Canada, the company is already pumping billions of dollars into the Canadian economy. Last year, Progress drilled 608,391 metres of hole, the sixth-highest total in the country. During the past winter, Progress operated about 28 rigs, making it one of the busiest drillers in the country and a big reason why British Columbia’s oilpatch has been busy so far in 2014. Progress typically ran 25 or 26 rigs on its North Montney project in northeastern British Columbia through the past winter. Even though the number of rigs the company was running dropped to 12 due to spring breakup, it is still the third-busiest driller in the country. In an interview with the Daily Oil Bulletin, Progress president and chief executive officer Michael Culbert discussed why he believes PETRONAS’s proposed West Coast LNG Project has an edge over more than a dozen competing projects. He also talked about what has to happen for the project to proceed and what that would mean in spending and activity through the decade and beyond. Just this year alone, Progress plans capital spending of $2 billion, Culbert said. That doesn’t include acquisitions such as the $1.5-billion purchase of Talisman Energy Inc.’s interest in two North Montney partnerships in the Farrell Creek and Cypress areas of northeastern British Columbia. That purchase closed in March of this year. Progress is currently in appraisal mode, drilling to establish 15 trillion cubic feet of proved-plus-probable reserves by year-end
2014 when PETRONAS will decide whether to proceed with an LNG project. Fifteen trillion cubic feet would provide a natural gas liquefaction plant with two billion cubic feet per day of natural gas feedstock for 20 years. The North Montney lands will feed the first two trains of the proposed LNG project, called Pacific NorthWest LNG. Progress is already more than halfway toward its 15-trillion-cubic-foot goal. In 2013, the company tripled the provedplus-probable reserves at its North Montney project to more than eight trillion cubic feet. Culbert said all the gas that is being drilled is being brought on production, involving a huge midstream investment by Progress and third parties. He said 850 kilometres of gathering lines are to be built this year. Numerous
compressor stations are to be built or expanded. A new gas plant is currently being commissioned in the Caribou area with initial capacity of 100 million cubic feet per day. In the third quarter of 2012, its last full quarter as an independent company, Progress reported average production of 43,045 barrels equivalent per day. Culbert said the company is now managing output of about 100,000 barrels equivalent per day, including production owned by minority interest holders in its North Montney project. “That includes about 12,000 barrels equivalent a day from Alberta. And it includes the Talisman acquisition, which was about 12,000 barrels equivalent a day. The rest is coming out of the North Montney,” he said.
A drill pad in the Horn River Basin.
P R O F I L E R M A G A Z I N E . C O M
june 2 0 1 4
Artist's rendering of the proposed Kitimat LNG facility.
"S o when you look at this in the scope of a 25-year project–five years ramping up and then 20 years maintaining–it's a very large capital commitment." — Michael Culbert, president and chief executive officer, Progress Energy Canada Ltd., on its LNG plans
In other words, PETRONAS will take 50 per cent of the LNG shipped from the Prince Rupert, B.C., area, the three partners will take 23 per cent, and PETRONAS is seeking partners for the remaining 27 per cent. “So we’re kind of in that 73 per cent sold mode at this point in time—which puts us well advanced of the other projects that are still looking for market,” said Culbert, who believes this wellhead-to-burner-tip integration gives the project a strategic advantage. “That, in my opinion, gives us greater certainty for a positive final investment decision because of the fact that we’ve got all aspects of it covered. We’ve got the resource, we’ve got the pipeline, we’ve got the LNG expertise, and we’ve got the market.” The Progress president is confident additional partners will be secured as the year progresses. “We’ve got active discussions underway as we speak,” he said. So will the pace slacken once Progress has proved up 15 trillion cubic feet of proved-plusprobable reserves by year-end 2014?
Not at all, said Culbert. “We really see ourselves, once a positive final investment decision is made, maintaining this pace… from 2015 throughout 2019, even 2020, to increase our production up to two billion cubic feet a day.” That would mean running roughly 28 rigs pretty much year-round, with the exception of spring breakup, for about the next five years. Matching the drilling intensity would be the pace of midstream construction as the company ramps up its capacity to process and transport two billion cubic feet per day. Once the LNG facility is operating and the first shipments are exported, facility construction will be significantly reduced, but Progress will still drill about half as many wells each year just to offset natural declines, Culbert said. “So when you look at this in the scope of a 25-year project—five years ramping up and then 20 years maintaining—it’s a very large capital commitment.” If the LNG project goes ahead, Progress expects to spend an average of $2 billion to
illustration: Apache Corporation
The transportation and processing agreements Progress has in place, combined with capacity the company is building itself, will meet short- and medium-term needs. “But sooner or later—sometime during 2015—we’ll maximize the available current capacity,” Culbert said. To handle longer-term growth, Progress has secured agreement from TransCanada Corporation to both extend its NOVA Gas Transmission Ltd. system into the North Montney region, and also to build an 850to 900-kilometre pipeline to deliver North Montney gas to the Prince Rupert area on the coast. This obviously depends on PETRONAS’s LNG plans proceeding. The project has already received export approval from the NEB and the federal government. To get the best cost estimates and design recommendations for the LNG project, PETRONAS hired three different engineering companies or joint ventures to do three competing front-end engineering and design (FEED) studies. That will be followed, in late summer or fall, by the selection process for the engineering, procurement and construction contractor. Pacific NorthWest is currently going through an environmental assessment with the federal and B.C. governments for the proposed LNG facilities. So as Progress proves up the reserves, TransCanada is going through its engineering and environmental process and Pacific NorthWest LNG is doing its regulatory and engineering studies. All are to be finished in the fourth quarter in time for a year-end final investment decision. PETRONAS wants to reduce its stake in the whole project to about 50 per cent. It is roughly halfway there after securing three partners to take a total of 23 per cent. Japan Petroleum Exploration Co., Ltd. of Japan and Indian Oil Corporation of India will each take a 10 per cent stake, and PetroleumBRUNEI of Brunei, which borders Malaysia, agreed to take three per cent. Those three partners bought into the North Montney assets (but not Progress) and Pacific NorthWest LNG. “So they’re actually taking title to the land and production facilities, et cetera.... And then on the LNG project, they’re coming in as shareholders or limited partners of Pacific NorthWest LNG,” Culbert explained. “And then each one will take their pro rata share of LNG to their own markets. So not only are we creat ing partners for the investment, but we’re also creating partners on the marketing side.”
$2.5 billion per year for the next five years until LNG shipments begin. First exports are slated for late 2018 or early 2019. The LNG facilities—including the liquefaction, storage and offloading—are expected to cost between $9 billion and $11 billion. Culbert said TransCanada would spend about $5 billion on its pipeline connecting the North Montney to the West Coast and another $1.5 billion to extend its NOVA gas transmission system. Direct spending—excluding the massive economic spinoff—is expected to total $36 billion. That includes PETRONAS’s acquisition of Progress, the LNG facilities, pipelines and drilling until LNG exports begin, Culbert said. But he cautioned that within any organization there is competition for capital, and many things have to come together for a positive final investment decision to be made. PETRONAS needs full clarity on matters such as the cost, construction and manufacturing, labour constraints and, obviously, the fiscal regime, which includes everything from royalties to carbon taxes to the B.C. government’s proposed LNG tax. “There’s no doubt that all this information is required before we can make that final investment decision. So we’re working hard as we go through the engineering and the regulatory side of things to make sure we have the best understanding available,” Culbert said. “And I give credit to the B.C. government that they know the timeline and they know that proponents of these projects have a window of opportunity, so time is of the essence.”
tHE montnEy monEy-makErS While Progress drills in preparation for LNG exports, other Montney operators are focused on turning a profit now. This includes Montney pioneer ARC Resources Ltd. ARC began drilling into the Montney in 2005 at Glacier just north of Dawson Creek, B.C. The Dawson Creek play is model of how development has taken shape in the Montney. “Dawson is a really nice case study because you can see the investment through to the cash flow,” ARC president and chief executive officer Myron Stadnyk told the Peters & Co. Limited’s 2013 energy conference in Toronto. While ARC was building production at Dawson, it spent around $150 million per year, significantly exceeding the cash flow the play was generating. But as decline rates
flattened and producing wells began accumulating, less new drilling was needed to keep production at ARC’s target of 165 million cubic feet per day. “In fact, we over-drilled a little bit there, so we hardly needed any reinvestment capital in 2012,” Stadnyk said. “But kind of the punchline is if you look at 2012…AECO was $2.27 for the year and we cash flowed over $100 million at Dawson,” he said. Stadnyk said an increase of $1 per thousand cubic feet of gas would add $60 million to the company’s cash flow.
“It’s a key play,” he said of the Dawson Montney. “The reinvestment, now that the field has stabilized, is very modest. A 25 per cent reinvestment will allow us now to produce this field for many, many years and have free cash flow. “If you look at $3 AECO at Dawson, you’re at a 45 per cent rate of return,” Stadnyk said. With Dawson generating cash flow, ARC is now focusing on its other Montney assets. ARC has approved a 2014 capital budget of $915 million, the largest in its history—and a seven per cent increase from this year’s $860 million budget.
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MONTNEY 2013 HORIZONTAL GAS PRODUCTION (BRITISH COLUMBIA & ALBERTA)
TOP 20 MONTNEY ACREAGE HOLDERS Net acreage
Operator Canadian Natural Resources Limited PETRONAS (Progress Energy Canada Ltd.)
Alta. and B.C.
Shell Canada Limited
Alta. and B.C.
ARC Resources Ltd.
Alta. and B.C.
Murphy Oil Company Ltd.
ARC Resources Ltd.
Alta. and B.C.
Birchcliff Energy Ltd.
Talisman Energy Inc.
Crew Energy Inc.
Tourmaline Oil Corp.
Talisman Energy Inc.
B.C. (sold to PETRONAS)
Birchcliff Energy Ltd.
Murphy Oil Corporation
Advantage Oil & Gas Ltd.
Tourmaline Oil Corp.
Canadian Natural Resources Limited
Korea Gas Corporation
Paramount Resources Ltd.
Alta. and B.C.
Progress Energy Canada Ltd.
Painted Pony Petroleum Ltd.
XTO Energy Inc.
Alta. and B.C.
Long Run Exploration Ltd.
Trilogy Resources Ltd.
Painted Pony Petroluem Ltd.
Canbriam Energy Inc.
NuVista Energy Ltd.
Crew Energy Inc.
Chinook Energy Inc.
Alta. and B.C.
Sinopec Daylight Energy Ltd.
Advantage Oil & Gas Ltd.
Cequence Energy Ltd.
Delphi Energy Corp.
Canbriam Energy Inc.
NuVista Energy Ltd.
Seven Generations Energy Ltd.
Trilogy Energy Corp.
TAQA North Ltd.
UGR Blair Creek Ltd.
Cequence Energy Ltd.
RMP Energy Inc.
Kelt Exploration Ltd.
Alta. and B.C.
Artek Exploration Ltd.
Lightstream Resources Ltd.
Pengrowth Energy Corporation
Sinopec Daylight Energy Ltd.
Bonavista Energy Corporation
Canada Energy Partners Inc.
Perpetual Energy Inc.
Insignia Energy Ltd.
Crocotta Energy Inc.
Yoho Resources Inc.
Aduro Resources Ltd.
Spyglass Resources Corp.
Donnybrook Energy Inc.
Apache Corporation Shell Canada Limited
Source: Daily Oil Bulletin
june 2 0 1 4
Sources: Scotiabank Playbook; Daily Oil Bulletin; SEDAR
ARC will spend $54 million on drilling and development activities in 2014 for nine gross operated horizontal natural gas wells at Dawson. The 2014 drilling program at Dawson will maintain production at current maximum facility capacity levels through 2014 and into 2015. ARC began commissioning a new gasprocessing and liquids-handling facility at its Parkland/Tower Montney liquids play in the fourth quarter of 2013. The new facility is the first phase of an approved 120-millioncubic-feet-per-day gas-processing and liquids-足 handling facility in the area. Total capacity from the first phase is expected to be approximately 60 million cubic feet per day of natural gas and 8,000 barrels per day of liquids (5,000 barrels per day of oil
and 3,000 barrels per day of natural gas liquids); however, actual liquids production will depend upon the ratio of Parkland and Tower wells feeding into the facilities. The Parkland/Tower region will see considerable activity and production growth in 2014 as the new gas-processing and liquidshandling facility is brought on stream. ARC invested significant capital in 2013 to “predrill” wells leading up to the start-up of the new facility. It expects to bring two eight-well pads on production at Tower, and 13 wells on four pads on production at Parkland when the new facility is brought on stream. In addition to the production increase resulting from the 2013 capital program, ARC will execute a $190-million capital program at Parkland/Tower in 2014 to drill 13 liquids-rich natural gas wells at Parkland and 17 oil wells at Tower to fill the newly constructed facility through 2014. ARC has been piloting production at Sunrise since the third quarter of 2011, with production coming from three layers in the Montney and processing capacity through third-party facilities. With the continued strong performance of the wells and the current outlook for commodity prices, it decided to pursue development plans starting in the fourth quarter of 2013. ARC has signed an agreement with a third party to increase natural gas processing commitments to 60 million cubic feet per day beginning in 2014. ARC’s 2014 capital program of $120 million includes the drilling of 14 gross operated natural gas wells and spending on associated infrastructure at Sunrise in 2014. Sunrise production is expected to grow to 60 million cubic feet per day from 20 million cubic per day throughout the course of 2014, averaging approximately 35 million feet per day in 2014. Painted Pony Petroleum Ltd. is also revving up Montney production. Its current production is around 15,000 barrels equivalent per day, almost double its 2013 average production. But this only marks the beginning for the junior producer, which has 120,000 net acres in the Montney. Painted Pony plans on spending $138 million in 2014, drilling 17 wells. Typical well costs come in at $7.2 million and feature a 1.6-kilometre horizontal leg and as many as 22 frac stages. In early April, Painted Pony president and chief executive officer Patrick Ward said the company plans to grow production to 100,000 barrels equivalent per day over the next five years. Michael Dembicki of TD Securities believes this is do-able.
“We believe the company has the access to capital to grow this asset to over 500 million cubic feet per day in the next several years with the potential to be over one billion cubic feet per day within the next 10 years,” he reported in an investment note. Deep Basin giant Tourmaline Oil Corp. is also moving forward with massive Montney development plans in British Columbia. Tourmaline operated two rigs in its Montney gas and condensate complex over the winter and plans to continue with drilling oper ations using the rigs through the remainder
of 2014. The company expects to drill 35 Montney horizontal wells in the area before the end of the year. The company’s A5-5 and D5-5 condensaterich lower Montney discovery wells from late 2013 have 30-day initial production (IP) rates of 6.3 million cubic feet per day and 5.6 million cubic feet per day, respectively. “We are very pleased with the first two horizontals into this zone, and what is particularly encouraging are the relatively high gas rates, which over the life will be critical to maintain those sorts of production numbers,” says
P R O F I L E R M A G A Z I N E . C O M
company president and chief executive officer Michael Rose. “We did add a significant amount of land in December. We already have a lot of land in there, and I would say we need to drill some more wells to see if it is a major new horizon or whether that is a little more local, but we’re very encouraged by what we have seen. “There is more exploration and production information required, but it’s looking good so far on that front,” he says. Tourmaline currently produces 30,000 barrels equivalent per day from the Montney. It has identified around 550 horizontal drilling locations.
Horn River, Liard Basin LNG ramp-up slowly gathers momentum The land sales tell the story of the rising and falling fortunes in the Horn River shale play north of Fort Nelson, B.C. In 2008, $1.1 billion was spent accumulating acreage in the play. In 2011, land-sale bonuses totalled $2.9 billion. In 2012, only $23,000 was spent on land. Last year? Nothing. Drilling in the play peaked in 2010 when 99 wells were drilled. By 2012, the well count had fallen to 90. In 2013, the only wells being drilled in the play were focused on land retention. But all indications are the Horn River and Liard basins could see a turnaround as early as next year as operators begin the ramp-up for LNG exports. Chevron Corporation, 50 per cent owner and operator of the Kitimat LNG Project, reported in January that work continues at both its Kitimat, B.C., terminal site and upstream on the project. “We’re doing site clearance now. One of the things we’ve learned on big land-based projects is get your infrastructure in order and housing and things of that sort, so that’s what we’re doing,” Chevron chair and chief executive John Watson said in a conference call discussing 2013 fourth-quarter and yearend results. “We’re pacing this project very carefully, as you would expect. “What we have said is that our final investment decision will be entirely a function of gas contracts that allow us to develop the opportunity and provide energy to Asian markets at a fair price,” he added. “It’s no secret that there’s a lot in the media on that subject right now. We’re actively working with gas customers today.” Watson pointed out LNG projects are expensive and so “robust pricing” is needed. 30
june 2 0 1 4
With that said, Watson said Chevron and Apache Corporation will continue to work to prove they have the reserves to feed the project. In Canada, he said, the company is focused on two main shale plays, the first being the Duvernay play in Alberta. “The second, of course, is the Horn River and the Liard Basin, which has gas to support the Kitimat project. There will be additional drilling in the Liard this year to delineate those holdings,” he explained. Chevron and Apache are focusing on the Liard play after Apache drilled a massive well in the play in late 2012. Apache’s D-34-K horizontal well had a vertical depth of 12,600 feet, a lateral length of 2,900 feet with six frac stages. The 30-day IP rate was 21.3 million cubic feet per day, 3.6 million cubic per day per frac and estimated ultimate recovery is 17.9 billion cubic feet. Apache estimates it has as much as 43 trillion cubic feet lying under its acreage in the Liard Basin. During the second quarter of 2013, the Kitimat Upstream Partnership maintained production and continued active drilling resulting in two tenure wells, both in Liard. “One of the aforementioned wells, with offset wells, is estimated to have over 500 billion cubic feet per section, the highest estimated original gas in place per section of any Apache well to date,” the company reports.
A 102-square-mile 3-D seismic program was also completed in Horn River and will be reprocessed and interpreted. If the Kitimat LNG Project goes ahead, the Canadian Energy Research Institute (CERI) expects a drilling boom north of Fort Nelson. In 2012, CERI released its Pacific Access report, which outlined the economic benefits of sending Horn River gas to Asia. The report expects drilling to peak at 103 wells per year during the ramp-up for Phase One of the project, and to peak at 175 wells to supply Phase Two of the project. From there, it expects annual well count to range from 107 to 61 wells as the project plays out over the next 20 years.
Service companies prepare for coming LNG development Behind the scenes, service companies are making plans as operators give them lead time for when drilling will pick up in the Horn River and Liard plays. Trican Well Service Ltd. expects growth in late 2014 and beyond as the industry prepares for anticipated facilities to allow Canadian natural gas exports. “We are having very high-level discussions with a few customers on LNG-related development in the Horn River that would start in late
HORN RIVER ACREAGE HOLDERS AND WELLS DRILLED (2003-13)
Operator Encana Corporation
Apache Canada Ltd.
Nexen Energy ULC
EOG Resources Canada, Inc.
Devon Canada Corporation
Imperial Oil Limited
Quicksilver Resources Canada Inc.
Spoke Resources Ltd. Ramshorn Canada Investments Limited ConocoPhillips Canada Storm Resources Ltd. Husky Oil Operations Limited
Pengrowth Energy Corporation
Suncor Energy Inc.
Current as of May 2013. Source: B.C. Ministry of Natural Gas Development
2014 or early 2015 and be, kind of, three years’ worth of term,” Dale Dusterhoft, chief executive officer, told Trican’s fourth-quarter conference call. He noted the company is still only having “conceptual discussions” with customers, though, as there are still highlevel decisions to be made on LNG projects. “There are no tenders out specifi c to frac equipment on that, but there are customers preparing some of their thoughts about how they are going to deliver gas to these facilities should there be a go-ahead with regards to a decision on capital decisions for them.” Drillers are also hopeful 2015 could be the start of the ramp-up. In July, Precision Drilling Corporation chief executive officer Kevin Neveu said LNG exports
are likely five to six years away, but much will happen before first gas, and he outlined some of the gaps that need to be closed before West Coast LNG becomes a reality. “you can’t get a natural gas contract without an export permit and an export facility,” he said. “The terminal facilities have been approved by government, and tree-clearing and foundation work is beginning, but you can’t have an export project without a pipeline. We think the first pipeline approvals will happen in 2014. Following that will be gas contracts, and we think investment will ramp up in 2015.” As for just how “deep” West Coast LNG will be, it depends on how much gas is ultimately exported, he said. “I think the likely range is three [billion] to eight billion cubic feet per day,” he said.
Depending on the stage of development, he said, LNG drilling could demand from 25 to 40 drilling rigs for every billion cubic feet per day of export volume. “Initially, during the ramp-up, land grab and production testing, it could be as many as 40 rigs per billion cubic feet, but as the business matures, it comes down to 25 rigs per billion cubic feet, which will likely all be new-build pad rigs, capable of drilling all year round,” he said. For Precision, meeting LNG drilling demand represents a “huge shift,” since its rigs typically work about 250 days per year, he said. yet, under the scenario he explained, Precision’s rigs serving LNG development could be drilling as many as 350 days per year.
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Fuelinjected Alberta boasts a vast geology of petroleum-soaked rock. Producing it and finding markets for it are the challenges for generations to come. By Darrell Stonehouse, with notes from the Daily Oil Bulletin staff
J une 2 0 1 4
The numbers tell the storyâ€”there are 3,424 trillion cubic feet of natural gas, 58.6 billion barrels of natural gas liquids (NGLs) and 423.6 billion barrels of oil in shale or siltstone formations in Alberta. Add to that the 1.8 trillion barrels of bitumen trapped in the provinceâ€™s three oilsands deposits. And the 20 billion barrels of oil trapped in tight formations and around 300 trillion cubic feet of tight gas. And around 43 trillion cubic feet of natural gas reserves in conventional formations. Almost the entire subsurface of Alberta is fuel-injected. The challenge is finding ways to economically turn these resources into reserves and finding markets to soak up the production. On the technology front, the tool
box for producing unconventional oil and gas and bitumen is mature and continues advancing. But without markets, the future remains uncertain. Until four years ago, Albertaâ€™s conventional oil industry was running on fumes. Production had declined from a peak of over 1.4 million barrels per day in 1973 to 460,000 barrels per day in 2010. But since then, a variety of tight oil projects have come on stream across the province. In 2012, conventional production climbed by 14 per cent to 556,000 barrels per day. With new tight oil plays being added, the National Energy Board (NEB) expects production to continue rising until at least 2017. But with 423.6 billion barrels of oil trapped in Alberta shale just beginning to be developed, that number could grow well into the future. Natural gas production peaked in 2001 at 13.8 billion cubic feet per day, according to the NEB. Since then it has declined to 9.1 billion cubic feet per day in 2013 as U.S. gas has replaced it in traditional markets. The only new wells that remain profitable in the province are those with high deliverability and high liquids content. Despite a resource base promising centuries of production, without new markets, gas production is expected to continue declining in the province, according to the NEB. The forecast for the oilsands is much more rosy. Production crossed the two-millionbarrel-per-day mark in 2014. It is expected to reach five million barrels per day by 2030, according to the NEB, again with the caveat that new markets must be found for this production to happen. Despite market concerns, efforts continue to prove up reserves in a variety of plays across the province. The first round of tight oil plays in the Cardium, the Slave Point/ Beaverhill Lake carbonate complex, the Montney, the Pekisko and the Viking are in the development stages, while new plays at Charlie Lake, the Belly River, the Peace River Arch and the Alberta Bakken continue being evaluated. On the horizon are true shale plays in the Duvernay, the Muskwa and the Second White Specks, which could blow the whole basin open. And demand for liquids to fuel the petrochemical industry and for diluent for shipping bitumen provide a floor until gas demand returns. Operators are finding growing liquids supplies in the Deep Basin and across central Alberta, with new play types taking hold.
Photo: Joey Podlubny
ALBERTA TOP OPERATORS 2013 Wells drilled Operator Canadian Natural Resources Limited Husky Energy Inc. Cenovus Energy Inc. Encana Corporation Devon Canada Corporation Imperial Oil Resources Limited Suncor Energy Inc. ConocoPhillips Canada Long Run Exploration Ltd. Apache Canada Ltd. MEG Energy Corp. Peyto Exploration and Development Corp. Bonavista Energy Corporation CNOOC Limited Pengrowth Energy Corporation Baytex Energy Corp. Royal Dutch Shell plc ARC Resources Ltd. Penn West Petroleum Ltd. Vermilion Energy Inc. MacKay Operating Corp. Bellatrix Exploration Ltd. Talisman Energy Inc. Trilogy Energy Corp. Trident Exploration Corp.
Oil 975 397 321 74 189 186 68 67 128 77 61 1 54 26 87 75 23 79 55 48 24 39 19 41 --
Gas 6 34 2 267 15 3 -35 1 41 -102 46 -1 3 39 --8 -15 34 12 50
Dry 1 1 12 2 4 2 -1 2 1 -1 -2 2 -8 -1 ---1 ---
Service 54 58 148 -38 14 88 43 --46 --70 5 10 12 -2 -32 -----
Total 1,036 490 483 343 246 205 156 146 131 119 107 104 100 98 95 88 82 79 58 56 56 54 54 53 50 Source: Daily Oil Bulletin
ALBERTA LAND SALES
“Based on the level of success we have experienced, we are preparing to ramp up the pace in this area. We currently have 136 locations in the hopper. And with continuing success and increased technical focus, the activity contained in our five-year plan will range from 300 to 500 wells.”
2009 2010 2011 2012 2013
1,842,058 3,983,622 4,606,952 3,158,488 2,277,948
Average price/ hectare $402.63 $606.13 $790.33 $354.85 $306.56
Bonus $741,673,011.00 $2,414,581,311.83 $3,641,012,381.26 $1,120,780,950.83 $698,321,632.93
Source: Daily Oil Bulletin
Land Sales by Region 2012
— Jeff Wilson, executive exploration adviser, Canadian Natural Resources Limited, commenting on the company’s northwestern Alberta drilling efforts
Plains Northern Foothills Oilsands
779,768 2,132,749 170,659 30,512
Average price/ hectare $288.12 $385.33 $372.83 $326.06
2013 Hectares 508,757 1,480,821 154,739 133,630
Average price/ hectare $191.64 $362.29 $294.45 $140.46 Source: Daily Oil Bulletin
ESTIMATE OF ALBERTA SHALE AND SILTSTONE HYDROCARBON RESOURCE Unit
Natural gas liquids (billion bbls)
Duvernay P50 Duvernay P90–P10 Muskwa P50 Muskwa P90–P10 Montney P50 Montney P90–P10 Basal Banff/Exshaw P50 (preliminary data) Basal Banff/Exshaw P90-P10 North Nordegg P50 (preliminary data) North Nordegg P90–P10 Wilrich P50 (preliminary data) Wilrich P90–P10 Total P50 (medium estimate) resource endowment
443 353–540 419 289–527 2,133 1,630–2,828 35 16–70 148 70–281 246 115–568 3,424
11.3 7.5–16.3 14.8 6.0–26.3 28.9 11.7–54.4 0.092 0.034–0.217 1.4 0.487–3.5 2.1 0.689–4.449 58.6
61.7 44.1–82.9 115.1 74.8–159.9 136.3 78.6–220.5 24.8 9.0–44.9 37.8 19.9–66.4 47.9 20.2–172.3 423.6
*The percentage of adsorbed gas represents the portion of natural gas that is stored as adsorbed gas.
Source: Alberta Geological Survey
P R O F I L E R M A G A Z I N E . C O M
The Peace River Arch, with its stacked formations, has long been the target of natural gas producers. But with natural gas markets in turmoil, operators are now picking apart the various formations, targeting tight oil sweet spots that offer better returns. The plains area in the far northern reaches of the province, a heritage oil play stretching back decades, is also being targeted as operators move from developing Rainbow Lake oil to testing the potential of the massive Muskwa shale formation. Canadian Natural Resources Limited reported in June that it is in the midst of accessing the 1.4 million acres of land it controls in northwestern Alberta. It has increased oil output from the region by 90 per cent and exited 2013 with more then 20,000 barrels per day of production. During the past two years Canadian Natural has been testing several tight oil plays in the area, which boasts 14 formations with horizontal initial production (IP) rates exceeding 100 barrels per day. So far the company has concentrated on the Montney, the Halfway and the Dunvegan formations. “Since 2011, we have drilled 56 successful wells and have first-month average initial production rates that range from 285 to 455 barrels equivalent per day and average estimated ultimate recoveries that range from 294,000 to 460,000 barrels equivalent per well,” says Jeff Wilson, executive exploration adviser at Canadian Natural. Canadian Natural says its tight oil drilling and completion costs range between $3.9 million and $5.25 million per well. “Based on the level of success we have experienced, we are preparing to ramp up the pace in this area,” Wilson says. “We currently have 136 locations in the hopper. And with continuing success and increased technical focus, the activity contained in our five-year plan will range from 300 to 500 wells.” He attributes the production growth to drilling success, field optimizations and well workovers. Wilson says the Grande Prairie, Alta., team reduced drilling and completion costs by using pad drilling as much as possible, by changing drilling fluids and by increasing the proportion of saline source water used for completions. “We have made improvements in our completion technology and optimized our frac fluids. By drilling longer laterals, optimizing frac 34
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sizes and using tighter frac spacing, we have achieved higher production,” he says. While Canadian Natural tests a variety of formations in northwestern Alberta, a number of other companies are focused on the Montney tight oil play in the region. Encana Corporation announced in late 2013 that it had completed its fifth multi-well oil pad at Gordondale. Oil and liquids production on its Montney lands has climbed from 2,900 barrels per day in 2012 to average 8,700 barrels per day in 2013. The company hopes to exit 2014 at 20,000 barrels per day, and it plans on investing between $800 million and $900 million in the play next year. Long Run Exploration Ltd. was a pioneer in developing the Montney oil play. In the Peace River, Alta., area, the company drilled a total of 50 net successful horizontal Montney oil wells at Normandville, Alta., and Girouxville, Alta., in
SLAVE POINT 2013 HORIZONTAL OIL PRODUCTION Company Penn West Petroleum Ltd. Pinecrest Energy Inc. Lone Pine Resources Inc. Harvest Operations Corp. Baytex Energy Corp. Dolomite Energy Inc. Arsenal Energy Inc. Devon Canada Corporation Border Petroleum Corp. Total
60 73 92 66 10 6 3 1 4 315
3,383 2,941 1,556 1,308 178 121 11 7 6 9,511
Sources: Scotiabank Playbook; Daily Oil Bulletin; SEDAR
BEAVERHILL LAKE 2013 HORIZONTAL WELL PRODUCTION Company Coral Hill Energy Ltd. Apache Canada Ltd. Arcan Resources Ltd. Penn West Petroleum Ltd. Pengrowth Energy Corporation Crescent Point Energy Corp. Lightstream Resources Ltd. Second Wave Petroleum Inc. Devon Canada Corporation ARC Resources Ltd. Total
54 140 96 79 140 18 6 7 19 23 582
5,065 3,702 3,605 2,588 1,913 891 805 191 180 159 19,099
Sources: Scotiabank Playbook; Daily Oil Bulletin; SEDAR
2013. Forecast 2014 capital spending in the Montney is expected to total $120 million and include drilling approximately 44 net wells. The Charlie Lake Formation is also emerging as a significant oil play in northwestern Alberta. Tourmaline Oil Corp. spent $53 million in 2013 consolidating land on this new regional oil play and an aggregate 514 sections was acquired on the trend. The
company believes that the regional pool could ultimately yield over 500 million barrels of oil equivalent. The producer said it controls over 75 per cent of the prospective trend as currently mapped. The company drilled approximately 35 new wells in 2013, and about 45 are planned for 2014. Tourmaline said Charlie Lake is a significant resource-style play, but not as large as the Montney. The average cost to drill and
Photo: A aron Parker
Tight oil targets take flight in northwestern Alberta, while shale oil experimentation continues
A Penn West well being drilled on a pad near Drayton Valley.
complete is $3.6 million. The company has identified 1,200 drilling locations in the play. Birchcliff Energy Ltd. has been working the Charlie Lake play and expanding its operations at the Worsley field since acquiring it in 2007. This year, $29.2 million will be spent on eight Worsley/Charlie Lake horizontal oil wells. The company holds 181,541 net acres that are prospective for the Charlie Lake light oil resource play.
“We believe the Charlie Lake PLAY has significant growth potential on land we currently own.” — Jeff Tonken, president and chief executive officer, Birchcliff Energy Ltd.
“Our main pool holding over 400 million barrels of oil in place is in Worsley, Alta. Our land is mostly large blocks of 100 per cent owned, contiguous blocks, which helps with repeatability, pad drilling and the construction of infrastructure,” says Jeff Tonken, president and chief executive officer at Birchcliff. “We believe the play has significant growth potential on land we currently own.” He adds that the play stretches across the Peace River Arch and has become popular because of the economics and the opportunity of growth due to the application of
horizontal drilling and fracturing, which is enabling further resources to be unlocked. “New technology, horizontal wells, completion techniques and resulting recoveries, together with higher light oil prices, have driven this play,” Tonken said. “This formation is only found in the Peace River Arch, so it will be limited to northwestern Alberta.” Drill and completion costs, on average, are roughly $2.5 million per well, Birchcliff says. Husky Energy Inc. is also ramping up oil production in the northwest at its Rainbow Lake operations. Husky has around 10,000 barrels per day of conventional light production at Rainbow Lake. It is also targeting the Muskwa shale play, along with the Slater River play in the Northwest Territories. Husky has about 400,000 net acres (more than 600 net sections) at Rainbow Lake with estimated total petroleum in place of 20 million to 30 million barrels equivalent per section. There are approximately 2,500 locations at four wells per section. In 2012, activity included 14 wells drilled and four completions. Drilling performance is improving dramatically with well designs and the remaining challenge is to optimize completions, Rob Symonds, senior vice-president, western Canada production, told the Peters & Co. Limited investment conference in Toronto last September. The company drilled 10 horizontal wells into the Muskwa in 2013. At Slater River, Husky holds approximately 300,000 acres (450 plus net sections). The estimated total petroleum initially in place is 20 million to 90 million barrels equivalent per section. The company has approximately 2,500 locations at six wells per section.
“It’s still very early days on those plays,” Symonds said, before adding, “In both these plays, the rocks are equivalent to the Duvernay. We believe that we are in a fairway for oil and for liquids-rich gas, given the size of our land total.” Activity is also robust in the northern carbonate plays, including the Slave Point and Beaverhill Lake plays. Penn West Petroleum Ltd. is a major player in the Slave Point play. During his year-end address to analysts, Penn West president and chief executive officer Dave Roberts said the Slave Point carbonate play is one of three core areas for development that the company identified during its restructuring over the last year. It now has a five-year plan in place, with the focus during the next two years on evaluating its over one billion barrels of oil resource base and testing different drilling and completion technologies. “We plan to transition to more development drilling in the Slave Point in years three through five,” he said. “With success here, we would expect this asset to become a real driver of value for Penn West in the future.” Penn West’s senior vice-president of development Mark Fitzgerald says the company is unravelling what it takes to produce the Slave Point effectively. “We tested two longer-reach laterals in the order of 2,200–2,400 metres,” he explains. “We think these will open up significant inventory for us outside the core area of the play.” Penn West expects to spend $143 million in the Slave Point, drilling 21 horizontal wells. That number is expected to increase substantially in the next five years. P R O F I L E R M A G A Z I N E . C O M
CARDIUM 2013 HORIZONTAL OIL WELL PRODUCTION Producers put pedal to the metal on tight oil and gas liquids development in central Alberta
The Cardium in west-central Alberta is the province’s premier tight oil play, producing over 75,000 barrels per day from horizontal wells in 2013. Dollars are expected to pour into the Cardium in 2014 and beyond. Penn West expects development capital spending on the Cardium to climb to $800 million per year by 2018. “Clearly the Cardium is the heart of the company, and we envision increased capital spending in the play, reaching $800 million invested per year there within five years,” president Dave Roberts told a conference call announcing the company’s 2014 spending plans. To put the $800-million figure in perspective, Penn West’s entire 2014 exploration and development capital spending is expected to be $900 million, of which $269 million is earmarked for the Cardium. “We believe the oil resource positions we have in our control in the Cardium and Slave Point are unrivalled in western Canada. And together with other high-return, oil-weighted assets like the Viking, it allows us to focus activity and capital to create sustainable platforms for success for years to come,” Roberts said in laying out the company’s five-year plan. Penn West believes it can grow its oil production at a compound annual growth rate of more than 12 per cent. “Of our capital program for development activities that approaches $5 billion in aggregate over the five-year period through 2018, roughly 90 per cent of the spend will be directed to the Cardium, Slave Point and Viking areas with over 50 per cent of total spent on the Cardium,” Roberts said. Roberts said Penn West’s Cardium well costs and cycle times are improving, and it is posting “solid” recoveries per well on primary production. Historically, the Cardium has been waterflooded successfully using vertical wells, and now “proven results from the use of horizontals are leading to further recovery improvement,” he added. Penn West is the leading landholder in the Cardium with 600,000 net acres. “This would be a feature play in any portfolio,” Roberts said of the Cardium. “We have hundreds of well opportunities at 30-plus per cent rates of return at moderate price assumptions. The Cardium is indeed a company maker.”
Company Lightstream Resources Ltd. Vermilion Energy Inc. Bonterra Energy Corp. Sinopec Daylight Energy Ltd. Whitecap Resources Inc. ARC Resources Ltd. Pengrowth Energy Corporation Penn West Petroleum Ltd. TORC Oil & Gas Ltd. Manitok Energy Inc. Baccalieu Energy Inc. Bellatrix Exploration Ltd. Bonavista Energy Corporation Angle Energy Inc.* ExxonMobil Canada Imperial Oil Limited ConocoPhillips Canada Anderson Energy Ltd. Total *Acquired by Bellatrix Exploration Ltd.
292 134 164 145 190 136 132 245 75 10 44 93 51 47 32 19 60 72 1,941
13,990 7,946 6,000 5,190 5,155 5,029 4,874 4,540 2,752 2,567 2,560 2,479 2,360 2,328 1,906 1,870 1,866 1,390 74,802
Sources: Scotiabank Playbook; Daily Oil Bulletin; SEDAR
CARDIUM 2013 OIL WELLS Direction Operator Anderson Energy Ltd. Angle Energy Inc. ARC Resources Ltd. Baccalieu Energy Inc. Baytex Energy Corp. Bellatrix Exploration Ltd. Birchill Exploration Limited Partnership Bonavista Energy Corporation Bonterra Energy Corp. Canadian Natural Resources Limited ConocoPhillips Canada Crew Energy Inc. Crocotta Energy Inc. Devon Canada Corporation Eclipse Resources Ltd. Exoro Energy Inc. ExxonMobil Canada/ExxonMobil Resources Co. Hitic Energy Ltd. Husky Energy Inc. Hyperion Exploration Corp. Imperial Oil Resources Limited Journey Energy Inc. Kingsmere Resources Ltd. Legacy Oil + Gas Inc. Lightstream Resources Ltd. Manitok Energy Inc. Marquee Energy Ltd. Mosaic Energy Ltd. OMERS Energy Inc. Pengrowth Energy Corporation Penn West Petroleum Ltd. PetroBakken Energy Ltd. Regent Resources Ltd. Sinopec Daylight Energy Ltd. Suncor Energy Inc. Talisman Energy Inc. Tamarack Acquisition Corp. Tamarack Valley Energy Ltd. TAQA North Ltd. TimberRock Energy Corp. TORC Oil & Gas Ltd. Tournament Exploration Ltd. TriOil Resources Ltd. Vermilion Energy Inc. Westbrick Energy Ltd. Whitecap Resources Inc. Yangarra Resources Ltd. Total
Directional -------1 ---------------------2 -----------------3
Horizontal 5 26 40 13 2 38 3 19 34 1 8 1 15 10 1 1 28 7 12 2 19 8 3 1 24 13 1 2 1 63 25 31 4 22 2 1 6 2 1 3 25 9 2 49 3 27 11 624
Total 5 26 40 13 2 38 3 20 34 1 8 1 15 10 1 1 28 7 12 2 19 8 3 1 24 13 1 2 1 65 25 31 4 22 2 1 6 2 1 3 25 9 2 49 3 27 11 627
Source: JuneWarren-Nickle’s Energy Group
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Vermilion Energy Inc. shares this optimism about the play, after reporting strong results in 2013. “We remained focused on the continued development of our successful Cardium light oil play, growing related production to more than 9,300 barrels equivalent per day in the fourth quarter,” president and chief executive officer Lorenzo Donadeo told the company’s 2013 year-end conference call. “We have considerable inventory to progress the play toward targeted production levels of 12,000– 14,000 barrels equivalent per day over the next few years.”
“We believe the oil resource positions we have in our control in the Cardium and Slave Point are unrivalled in Western Canada.” — Dave Roberts, president and chief executive officer, Penn West Petroleum Ltd. Cardium well performance remains predictable, reflective of the high-quality, consistent nature of the reservoir underlying the company’s land position in the West Pembina region. Since entering the play in 2009, Vermilion has brought online a total of 223 (158.9 net) Cardium wells. This year, the company expects to drill 30 net wells into the play. Entering 2014, the company has an inventory of nearly 200 net economic one-mile equivalent wells remaining to be drilled. Donadeo said that Vermilion continues to review a significant inventory of more than 120 additional locations that may become economic as the company expands the use of extended reach horizontal wells (greater than one mile in length) and further optimize completion technology and well design. “We have also initiated a water-injection pilot to test applicability of waterflooding to this reservoir as a means to increase potential recoveries. During 2014, we anticipate drilling more than 30 net Cardium wells,” Donadeo said. Bellatrix Exploration Ltd. is also spending heavily on its Cardium land base. The company, which recently took over Angle Energy Inc. and tapped into a major investment partnership, expects to drill 115 gross Cardium oil wells in 2014. Bellatrix has developed an inventory of 742 net remaining Cardium locations.
Kaybob firing on all cylinders
Whether targeting oil or NGLs, Kaybob, laying on the eastern outskirts of the Deep Basin, is one of the hot spots of both exploration and development. While the Montney oil play at Kaybob is dwarfed by its natural gas and gas liquids plays, it is a cash-generating machine. Peters & Co. ranked the Montney oil play at Kaybob as having the second highest rate of return of all resource plays in North America in September 2013. Trilogy Energy Corp. is the dominant operator in the play, with 50 net sections of land overlying around 500 million barrels of oil. At year-end 2013, Trilogy had drilled around 75 wells targeting Montney oil, with current production of around 8,500 barrels per day, plus around 21 million cubic feet of gas per day. Trilogy is developing the play using milelong horizontal laterals, with 22 fracs per well. The cost to drill, complete and tie in comes in at around $4 million per well. Trilogy expects to spend around $135 million in 2014 to drill 30 Montney oil wells and build-out some infrastructure. Longer term, it expects production to climb to 12,000 barrels per day, plus 30 million cubic feet per day
of gas. It has 400 identified horizontal drilling targets in the play. The Kaybob area accounted for approximately 94 per cent of Trilogy’s production and 97 per cent of its capital expenditures in 2013 and will continue to be the focus of the company’s 2014 spending plans and forecasted growth. Trilogy produced 32,384 barrels of oil equivalent in the Kaybob area in 2013. In Kaybob, Trilogy’s 2013 capital expenditures totalled approximately $388 million. Trilogy drilled 78 (54.7 net) wells in the area during the year, of which 77 (53.7 net) wells were drilled horizontally. The Montney oil play is being extended from the Kaybob core area south to Ante Creek as well. ARC Resources Ltd. is leading this charge. With the execution of pad drilling programs, ARC’s Ante Creek production was relatively flat for the first eight months of 2013, but fourth-quarter output rose significantly to 16,200 barrels equivalent per day (55 per cent oil and NGLs) as 11 new wells were brought on stream. ARC plans to spend $200 million to drill 40 gross operated horizontal Montney oil wells at Ante Creek in 2014 and will continue to delineate this large, prospective land base. ARC expects 2014 production at Ante Creek
MONTNEY 2013 OIL WELLS Direction Operator ARC Resources Ltd. Athabasca Oil Corporation Barrick Energy Inc. Birchcliff Energy Ltd. Canadian International Oil Corp. Canadian Natural Resources Limited Capio Exploration Ltd. Cenovus Energy Inc. Chinook Energy Inc. Encana Corporation Exshaw Oil Corp. Harvest Operations Corp. High North Resources Ltd. Inception Exploration Ltd. Kelt Exploration Ltd. Long Run Exploration Ltd. Longview Oil Corp. NAL Resources Limited Penn West Petroleum Ltd. PetroBakken Energy Ltd. Petrus Resources Ltd. Peyto Exploration and Development Corp. Progress Energy Canada Ltd. RMP Energy Inc. Sinopec Daylight Energy Ltd. Spry Energy Ltd. Surge Energy Inc. Trilogy Energy Corp. Whitecap Resources Inc. Total
Directional -----1 --1 -----------2 -1 ------5
Horizontal 50 12 1 1 3 12 3 3 -22 3 1 3 1 3 53 1 2 1 1 1 1 -16 1 1 1 34 3 234
Total 50 12 1 1 3 13 3 3 1 22 3 1 3 1 3 53 1 2 1 1 3 1 1 16 1 1 1 34 3 239
Source: Daily Oil Bulletin
P R O F I L E R M A G A Z I N E . C O M
MONTNEY 2013 HORIZONTAL OIL PRODUCTION Company Trilogy Resources Ltd. Long Run Exploration Ltd. ARC Resources Ltd. Canadian Natural Resources Limited RMP Energy Inc. Spyglass Resources Corp. Whitecap Resources Inc. Athabasca Oil Corporation NAL Resources Limited Capio Exploration Ltd. Encana Corporation Devon Canada Corporation Canadian International Oil Corp. Penn West Petroleum Ltd. Storm Resources Ltd. Harvest Operations Corp. Kelt Exploration Ltd. Petrus Resources Ltd. Total
60 74 67 63 33 91 16 30 20 6 10 15 5 8 15 6 2 17 538
8,927 4,443 3,265 3,157 2,990 2,462 1,147 1,136 1,053 1,037 903 560 549 370 354 347 300 293 33,293
Sources: Scotiabank Playbook; Daily Oil Bulletin; SEDAR
to average more than 15,000 barrels per day (50 per cent crude oil and NGLs). Paramount Resources Ltd. is in the midst of a major infrastructure build-out in
its Kaybob core area, with the goal of turning its Montney gas and liquids play in the region into an engine of growth well into the future.
Kaybob Duvernay hotspot
he Kaybob area is also the early leader in the race to develop the potentially massive Duvernay shale play. Royal Dutch Shell plc says it’s had positive early results in the Duvernay shale, where it holds roughly 360,000 net acres in the Kaybob and Pembina areas. It has over 1,100 potential drilling locations “on what we’ve already de-risked in the Kaybob area,” said Marvin Odum, the upstream Americas director for Shell, during an investor day in early 2014. “Shell’s equity in this area is about 95 per cent. “We’re doing well here with 38 wells drilled in 2013, and we recently achieved over 10,000 barrels equivalent a day of production for Shell.” Trilogy Energy Corp. has also been a pioneer in the Duvernay, but the company believes it will be a while before operators know just how good the economics are on the play. “We know they are good.... We just don’t know how good,” John Williams, president and chief operating officer for Trilogy, told the BMO Capital Markets 11th Annual Unconventional Resources Conference in January. “Before you start allocating all your money into the Duvernay, you have to reduce that risk.” “Today the longest producing wells—the 03-13[-060-20W5] wells— have produced just over one billion cubic feet of gas in about two and a half years,” he said. “So I think it is premature to actually be able to say this well is going to be a 250 per cent rate-of-return project.” In order to calculate the long-term economics, an operator really needs to know what production in the second and third years looks like and what will happen to the liquids yield in that period of time, said Williams. For example, Trilogy’s longest producing well in its Montney oil play has been on production for 34 months, he said. “It has taken us two or three years to figure it out to know what those true economics are worth.” 38
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Up until the end of 2013, Paramount had an ownership in infrastructure that enabled it to produce up to about 15,000 barrels equivalent per day, James Riddell, president and chief operating officer, told the recent CIBC 17th Annual Whistler Institutional Investors Conference in Whistler, B.C. At Musreau, Paramount has been developing a wholly-owned 200-million-cubic-feet-per-day (raw gas) deep cut plant with a net sales gas capacity of 50,000 barrels equivalent per day and has expanded the condensate stabilizer by 15,000 barrels per day, as it realized the high liquids content in the gas. The company expected to have first sales in March. It has about 300 million cubic feet per day of behind-pipe deliverability from 61 (47.9 net) wells drilled and completed over the last two or three years, said Riddell. The 200 million cubic feet per day of raw gas to the plant will result in 154 million cubic feet per day of sales gas that will produce 30,280 barrels per day of NGLs, including
Williams said the industry has made a lot of progress in learning about the Duvernay resource play in the last two and a half years. Well costs that initially were $15 million to $20 million have come down to $12 million as part of a multi-well pad. About 100 wells have been drilled and about 50 are producing, and “the results to date have been very, very positive,” he said. “We didn’t know what to expect, but it has exceeded our expectations in well economics, the rate of return.” In the second half of this year, Trilogy plans to spend about $100 million on its Duvernay program as part of its focus on land retention over the next two years. It has roughly 200 sections of Duvernay land, with 75 in the condensate window and 125 in the volatile oil window. The company is currently working on what a template type curve would look like in the various liquids fields of the play, said Williams. A number of wells in the 50–100-barrel-per-million-cubic-feet window have been on stream for one to one and a half years, and that will enable it to start generating that information. However, farther north, where liquids yields are in the 200–400barrel-per-million-cubic-feet range, the industry doesn’t yet have the production history. “As an industry, we are all waiting for the same thing,” said Williams. About 12–15 months ago, there was a step-change in completion techniques with the arrival of the majors such as Encana, Chevron Corporation and Shell in the Duvernay, said Williams. The number of hydraulic fractures increased to 60–100 per well from 25–30. The completion technology is the game changer, he suggested. “We have gone from the Packers Plus [Energy Services Inc.] ball-drop system doing fracs every 75 metres down to roughly every 20–25 metres,” said Williams. “Ultimately, it is about stimulating the rock and increasing your ultimate recoverable reserves.” To date, Trilogy has participated in 27 wells and has access to information on another 25–30 wells through confidential data exchange agreements, exchanging like data for like data.
11,200 barrels per day of stabilized condensate, he said. The build-out to a total of more than 80,000 barrels equivalent per day of sales capacity in the Kaybob operating unit by the beginning of 2015 will be gradual as Paramount adds the expanded condensate stabilizer and amine unit at Musreau, the conference heard. The company also has a 20 per cent ownership in the Pembina Pipeline Corporation Resthaven/Smoky deep-cut expansion to be in operation this year. Paramount has contracted for deethanization capacity at the Keyera Corp. plant at Fort Saskatchewan, Alta., which will be in operation later this year. The company believes it has de-risked all its 335 sections of land (approximately 225,000 net acres) of Montney rights in the Kaybob area, which gives it an inventory of thousands of sections to drill, said Riddell. Estimated discovered gas initially in place is more than 70 billion cubic feet per section,
with a total of 23 trillion cubic feet of gas plus NGLs across the land, he said. Typical wells are in the 10-million-cubic-feet-per-day range. In the third quarter of 2013, a four-well pad in an area with a very high liquids ratio (up to 300 barrels per million cubic feet) tested a combined 34 million cubic feet per day plus NGLs. “That would be in the realm of a 10,000barrel-per-day condensate deliverability initially out of that pad site,” said Riddell. Paramount has a 2014 exploration and development and strategic investments capital budget of $650 million, excluding land acquisitions and capitalized interest. Paramount’s sales volumes are expected to reach approximately 50,000 barrels equivalent per day in 2014 and increase to roughly 70,000 barrels per day in 2015, depending upon the availability of downstream thirdparty de-ethanization capacity. Apache Corporation is targeting the liquidsrich Bluesky Formation in the Kaybob area, which will see the lion’s share of its Canadian
drilling activity this year. The company has drilled 41 horizontal wells to date and plans to punch 44 more into the play in 2014. “In the Bluesky, we’ve been able to generate really good results, and we’re now producing over 5,000 barrels equivalent a day from those 41 wells,” Apache’s executive vice-president and chief operation officer, North America, John Christmann says. “It’s liquids-rich gas at 55 barrels per million on the yield, and we’re really planning to double activity there in 2014.” Christmann says Bluesky wells have “outstanding economics on a fairly conservative type curve.” He says wells cost about $5.5 million to drill and complete; the wells have an estimated ultimate recovery (EUR) of 585,000 barrels and generate a rate of return of 36 per cent at $4.50 per million British thermal units NYMEX. “The Bluesky is a tremendous program. We’ve got almost 2,000 locations identified, and we’re going to be active there,” he adds.
Photo: Penn West Petroleum Ltd.
Fracking crews at work this winter.
However, in some cases, the company will also be studying public data as a number of Duvernay wells—the earliest in the next generation of completion technology—are coming off confidential status this year, he said. “For us, expanding outside that core area and looking at some of the fringe wells and seeing how economic the Duvernay looks when it is down to 20 metres thick or 30 metres thick will be important.” Over the past 18 months, operators have spent an estimated $2 billion on Duvernay drilling opportunities, and Trilogy expects a similar level of capital spending in 2014. As the industry ramps up activity in the play, there’s the potential for increased competition for drilling rigs and pumping equipment, he said. “Drilling 100 wells a year shouldn’t be a problem, but when we start drilling 500 wells a year, I think that’s when we are looking at the competition for services, making sure we have the right rigs and the right number of rigs to do the job.” However, if the service companies know that Duvernay players will be stepping up activity in 2015 or 2016, it gives them a chance to move equipment into the area or to build pumping equipment, said Williams.
ACTIVE DUVERNAY LANDHOLDERS (net sections)
Athabasca Oil Corporation Encana Corporation/ PetroChina Company Limited Trilogy Energy Corp.
Shell Canada Limited
Yoho Resources Inc.
Husky Energy Inc.
EOG Resources, Inc.
Talisman Energy Inc.
Bounty Developments Ltd.
*Total acreage in both north and south Duvernay. Sources: BMO Capital Markets; Keyera Corp.; JuneWarren-Nickle's Energy Group
P R O F I L E R M A G A Z I N E . C O M
Drilling crew at work near Swan Hills.
The Deep Basin, with its stacked, petroleuminfused formations, offers high deliverability and liquids-rich targets for operators with the technical know-how to economically produce its massive resource. Tourmaline appears to have cracked the code. Tourmaline has around 1,950 gross sections (1.1 million acres) in the Deep Basin, the largest land position in the play. It has identified over 3,200 vertical drilling locations in the play, along with around 3,750 horizontal locations. Current production is 65,000 barrels of oil equivalent per day, making it the second largest producer in the Deep Basin. And with around 305 million barrels of oil equivalent of reserves, it has a lot of growing room. Tourmaline intends to operate 12 drilling rigs in the Alberta Deep Basin through the balance of 2014, after the fleet shutting-in during spring breakup. So far in 2014, the company has drilled 17 new Wilrich horizontals, with plans for a full-year total of 55 new Wilrich horizontals to be tied into Tourmaline facilities. Tourmaline says its winter program yielded five new high-deliverability Wilrich horizontals in the Smoky, Horse and Berland areas, including the Smoky 04-01-059-02W6 well, which has a 30-day average IP rate of 22.2 million cubic feet per day.
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Cretaceous Notikewin results have continued to exceed internal economic template expectations, management says. The 30-day average IP rate from the Wild River 12-28-056-24W5 horizontal is 20.9 million cubic feet per day. The company is expanding its Musreau gas plant by 50 million to 55 million cubic feet per day, with start-up in the third quarter. The company is also participating in a plant expansion at West Edson. Tourmaline expects to reach the 500-million-cubic-feet-per-day
production milestone in the Deep Basin in either late 2014 or early 2015. Peyto Exploration and Development Corp. has been a pure Deep Basin operator since its inception 15 years ago. It currently has 75,000 barrels equivalent per day of production, with 468 million barrels equivalent of proven and probable reserves on its 425,000-acre land base. It has over 1,700 booked and unbooked horizontal drilling locations. â€œFifteen years is an incredible milestone for any company in the Canadian oil and gas
DEEP BASIN 2013 HORIZONTAL & VERTICAL NATURAL GAS AND LIQUIDS PRODUCTION Company ConocoPhillips Canada Peyto Exploration and Development Corp. Canadian Natural Resources Limited Encana Corporation Tourmaline Oil Corp. Devon Canada Corporation Bonavista Energy Corporation Husky Energy Inc. TAQA North Ltd. Shell Canada Limited Talisman Energy Inc. Apache Canada Ltd. Suncor Energy Inc. Paramount Resources Ltd. Sinopec Daylight Energy Ltd. Penn West Petroleum Ltd. Harvest Operations Corp. Bellatrix Exploration Ltd. Trilogy Resources Ltd. NuVista Energy Ltd. Total
4,061 992 2,529 456 413 1,387 1,570 944 1,287 506 843 828 293 202 324 902 350 143 532 122 18,684
793 35 350 60 127 568 597 90 283 28 182 193 37 33 416 314 148 96 208 9 4,567
665.7 377.0 362.0 282.0 255.0 260.5 212.0 206.5 185.0 182.0 163.0 153.0 113.0 98.0 75.0 64.5 62.0 59.3 50.0 35.0 3,860.5
111,735 62,866 60,728 47,021 42,533 43,989 35,932 34,501 31,151 30,311 27,321 25,680 18,805 16,403 12,903 11,066 10,438 9,991 8,505 5,810 647,689
Sources: Scotiabank Playbook; Daily Oil Bulletin; SEDAR
Photo: A aron Parker
High deliverability wells drive Deep Basin drilling
Cardium 2013 Gas WElls Operator Arriva Energy Inc.
Bellatrix Exploration Ltd.
Birchill Exploration Limited Partnership
Carrick Petroleum Inc.
Crew Energy Inc.
Husky Energy Inc.
Petrus Resources Ltd. Peyto Exploration and Development Corp. Total
1 10 38
Source: Daily Oil Bulletin
industry,” Peyto president and chief executive officer Darren Gee said in March when announcing the company’s year-end earnings. “There’s not many companies that still exist today that existed back when we began in 1998, or if they do, they’re in a completely different form from what they started out as. Peyto is exactly the same as when we started. We have the same strategy, we’re working in the same areas, our goals are identical to the day we started—which I think makes us very unique in the industry,” Gee said.
“The real romance for Bonavista comes out of the Ansell area where we have got 45 sections of land and have drilled only two wells.”
replaced 450 per cent of annual production with new proved-plus-probable reserves at an FD&A cost of $11.16 per barrel. The figures include increases in future development capital of $87.9 million and $508.7 million respectively. The company anticipates investing $575 million to $625 million this year, drilling approximately 110–122 gross wells and adding between 32,000 and 36,000 barrels equivalent per day of new production by the end of the year. The Ansell area of the Deep Basin is proving to be a hot spot with a number of
operators targeting the liquids-rich Wilrich Formation in the area. Husky raised production by 60 per cent from 2010 to 2013 at its Ansell operations. The company is currently producing 14,000 barrels equivalent at the play. Husky president and chief executive officer Asim Ghosh describes the Ansell play as “the biggest star” in the company’s unconventional resource plays. Husky plans to spend $300 million at Ansell in 2014, double what it spent last year, in an effort to double production.
C O M B U S T I O N I N C.
After 20 years as managing director of his own production operating company, Brian Hauer launched Commander Combustion in order to provide incinerator rentals to the Western Canadian & US Oilfield. The fleet has now expanded to include flare stacks, knockouts & generators. Commander Combustion provides quality service on a personal level. Brian Hauer
— Jason Skehar, president and chief executive officer, Bonavista Energy Corporation In 2013, Peyto invested a record $578 million into drilling and completing 99 new gas wells, building two new gas plants at Oldman and Brazeau River, expanding a third plant at Swanson, acquiring 49 sections of new multizone rights and buying 170 square miles of 3-D seismic. For every well drilled, two new drilling locations were recognized in Peyto’s reserve report, the company said. First-quarter drilling in 2014 continues to be robust. Peyto is currently running a ninerig program extending across the Greater Sundance area, through Ansell and down to the Brazeau River. The program is targeting the Bluesky, Wilrich, Falher, Notikewin and Cardium formations. Peyto replaced 230 per cent of annual production in 2013 with new proved reserves at a finding, development and acquisition (FD&A) cost of $13.39 per barrel equivalent. It also
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“That’s four rigs running constantly,” says company chief operating officer Rob Peabody. Bonavista Energy Corporation plans to spend $66 million drilling 11 Wilrich wells at Ansell in 2014. Bonavista has also committed to building a 30-kilometre pipeline capable of delivering 100 million cubic feet of natural gas out of the area per day, said its top executive. The 10-inch pipeline would transport the gas out of the area to a processing facility with 100 million cubic feet per day of surplus gas, Jason Skehar, president and chief executive officer, told the CIBC Institutional Investor Conference. In addition, Bonavista will “bolt on” a 30-million-cubic-feet-per-day compressor station on the bottom end as the first phase of plans for the area, he said. “That will give us an opportunity to bring the five of six wells that we drill in the first quarter on stream throughout the summer in order for us to plan another active winter next year,” said Skehar. Since entering the Wilrich in 2012, Bonavista has acquired 75 sections of land and has 120 drilling locations. The Marlboro area at the northern end of the Deep Basin is well delineated and more of a development play, he said. “The real romance for Bonavista comes out of the Ansell area where we have got 45 sections of land and have drilled only two wells,” he said. “The results that we experienced in the last half of 2013 are going to propel this play into the spotlight for Bonavista—maybe not so much in 2014, but beyond that as we get some infrastructure built out into the south portion.” The first two Wilrich wells at Ansell had initial test rates of 10 million to 15 million cubic feet per day but came on production at curtailed rates of six million to seven million cubic feet per day through a nonoperated low pressure gathering system, according to Skehar. Well costs are a bit higher mainly because the area is more remote and deeper, he said. It spent about $7 million to drill its first well and $6 million on the second. “We anticipate that with a bit more of a scalable program, we will get close to $5 million per well over the next 12–18 months,” he said. Bonavista is also targeting the Bluesky Formation in the Deep Basin. Spending plans for 2014 provide $21 million for eight wells in the Bluesky as the company continues to develop an inventory of locations, drilling 10 wells per year for the next three to four years. 42
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West-central Alberta targeted for liquids-rich gas
Outside the Deep Basin, Bonavista is targeting liquids-rich gas in the Glauconite and Ellerslie formations. The Glauconite Formation in west-central Alberta will be the major source of growth in the next couple of years, with spending of $150 million to $200 million per year in 2014 and 2015 and an anticipated doubling of production by the second half of 2015 from the current 17,000 barrels per day, according to Skehar. This year, plans call for spending $161 million to drill 58 (gross) Glauconite wells where Bonavista has 400 horizontal locations and has already drilled 186 horizontal wells. Also in west-central Alberta, Bonavista has budgeted $44 million to drill 11 gross wells in the liquids-rich (90 barrels per million cubic feet) Ellerslie, which Skehar described as the “most undervalued, probably unappreciated play in the company.” It only recently began drilling horizontal Ellerslie wells after drilling vertical wells for a decade, and “we had some tremendous results in 2013,” he said. Bonavista drilled five horizontal wells in the latter part of the year, and “if we continue on with that success rate in 2014, I am convinced that the Ellerslie will overtake the Glauconite in terms of capital allocation within the next couple of years.” Over the past five years, Bonavista has increased its landholdings in two core areas— west-central Alberta and the Deep Basin of Alberta—by 160 per cent to 2.13 million
In 2013, Vermilion drilled 3.7 net wells targeting Mannville liquids-rich gas in the West Pembina area. Drilling results to date have exceeded initial expectations, Vermilion’s president and chief executive officer Lorenzo Donadeo told shareholders in March. Average production rates per well over the first six months have come in at 2.4 million cubic feet per day of sales gas and 310 barrels per day of liquids, of which 80 per cent is condensate.
“O ur Duvernay rights generally underlie our Cardium oil and Mannville condensate-rich gas rights, which creates the potential for infrastructure, operational and timing advantages.” — Lorenzo Donadeo, president and chief executive officer, Vermilion Energy Inc.
In 2014, Vermilion plans on drilling 5.7 net Mannville wells and expects drilling activity to increase in future years as it continues to develop the play and expand its inventory of prospects. It has 318 net sections of Mannville rights, with 37 drilling locations identified and 50 prospective drilling locations.
GLJ PETROLEUM CONSULTANTS LTD. ALBERTA NGL PRICE FORECAST Effective Jan. 1, 2014 (Then-current dollars) Year
Edmonton butane (C$/bbl)
Edmonton pentanes plus
2012 2013 2014 2015 2016 2017 2018 2019 2020
--13.26 14.08 14.89 15.71 16.53 17.34 17.77
29.04 38.49 57.83 58.42 60.00 60.00 60.00 60.00 60.46
66.70 68.65 73.22 75.95 78.00 78.00 78.00 78.00 78.60
100.84 104.40 105.20 107.11 107.00 107.00 107.00 107.00 107.82
acres in 2013 from 815,000 acres in 2009. Approximately 70–80 per cent of its current production and reserves exist in those two core areas. The company has a drilling inventory of 1,650 locations, of which 1,465 (89 per cent) are horizontal wells and 80 per cent are in the two core areas. Both Vermilion and Bellatrix are also developing liquids-rich gas in west-central Alberta along with their Cardium tight oil plays.
Bellatrix is approaching its Pembina acreage as a stacked resource play similar to the Deep Basin. Aside from targeting Cardium tight oil, it is also focusing on eight other formations. In the Lower Mannville, the company has 100 net drilling locations identified and has already drilled 31 Ellerslie wells. Wells are producing around 200 barrels of liquids per million cubic feet of gas.
The Duvernay is providing additional targets for west-central Alberta acreage holders.
B Photo: Joey Podlubny
South Duvernay showing strong liquids shows
Both Vermilion and Bellatrix also have significant South Duvernay acreage in westcentral Alberta. Donadeo said that Vermilion is appraising its position in the Duvernay, where the company has amassed 317 net sections at the relatively low cost of approximately $76 million ($375 per acre). “Our position comprises three largely contiguous blocks in the Edson, Drayton Valley and Niton [Junction, Alta.,] areas. To date, we have drilled three vertical stratigraphic test wells and are currently drilling our first horizontal well,” he said. “The first horizontal test is in the downdip part of our Edson block, where condensate yields are expected to be lower than the average in our overall land position. We selected this location because of its proximity to one of our vertical stratigraphic test wells, allowing us to conduct micro-seismic monitoring while we frac the horizontal well after breakup.” The company anticipates that the horizontal well production results and fracture geometries from the micro-seismic data will assist it in optimizing completions on future horizontal wells.
ACTIVE DUVERNAY LANDHOLDERS South Duvernay Encana Corporation/PetroChina Company Limited Shell Canada Limited Talisman Energy Inc. Sinopec Daylight Energy Ltd. ConocoPhillips Company Vermilion Energy Inc. Enerplus Corp. Bonavista Energy Corporation Canadian Natural Resources Limited
578* n/a 303 203 n/a 321 133 400 623
24 8 6 5 5 3 3 1 2
*Total acreage in both north and south Duvernay. Sources: BMO Capital Markets; Keyera Corp.; JuneWarren-Nickle’s Energy Group
“We are confident we will be able to project the results to higher condensate yield drilling locations as we move to the northeast in our acreage position, which encompasses the entire breadth of the condensate-rich window,” Donadeo said. “Our Duvernay rights generally underlie our Cardium oil and Mannville condensate-rich gas rights, which creates the potential for infrastructure, operational and timing advantages if we progress to full development of the Duvernay resource play,” he added. Talisman Energy Inc. says that early results in the Duvernay are encouraging, and the company will continue to seek a joint-venture partner in an effort to accelerate the pace of developing the play.
“We will figure out ways to reduce the cost of drilling these wells and improve overall production rates, but I think the very positive outcome of the work we have done so far is we have confirmed that we are in some very attractive acreage in the south,” Talisman’s president and chief executive officer Hal Kvisle told the company’s fourth-quarter conference call. “We have got some good spots in the north, and some parts of our northern acreage are gas-focused, and we are currently appraising some of that gas acreage with a view to running it through our capacity at the deep-cut plant and recovering significant natural gas liquids from that,” he added. “So, I think the key theme of our Duvernay position is one of liquids—very significant amounts P R O F I L E R M A G A Z I N E . C O M
Oilsands demand for gas and condensate a growing market
lberta gas producers can thank oilsands producers for providing a growing domestic market for natural gas production and for growing demand for condensate as pipeline diluent making wet gas production highly profitable. Oilsands natural gas demand has been climbing a steep cliff since 2000, when only 650 million cubic feet per day were used by the industry, according to Alberta Energy Regulator (AER) figures. By 2013, the oilsands were burning 2.62 billion cubic feet per day, a four-fold increase. The AER predicts that by 2020, around 4.25 billion cubic feet per day of natural gas will be needed. Thermal oilsands operations have been the driving force behind growing demand. In 2000, only 260 million cubic feet per day were being used to generate steam for in situ operations. By 2013, that number reached 1.1 billion cubic feet per day. The AER expects thermal operations to consume two billion cubic feet of gas by 2020. Demand for condensate by oilsands operators is growing at an even faster rate. Producers who don’t have upgraders use condensate to dilute their bitumen and heavy oil so it can move through pipelines. The transportation of non-upgraded bitumen from the oilsands con tinues to increase dramatically, driving up condensate consumption. Calgary-based Peters & Co. estimates the six biggest condensate consumers in the oilsands are Cenovus, Imperial Oil Limited, Devon Energy Corporation, Canadian Natural, MEG Energy Corp. and Suncor Energy Inc. If Husky and PetroChina Company Limited were included, condensate consumption by just those operators will nearly double to more than 500,000 barrels per day by 2017 and to 700,000 barrels per day by 2020, Peters & Co. says. Husky’s Sunrise steam assisted gravity drainage project is to come on stream in the second half of this year, while PetroChina is slated to bring on its MacKay/Dover production. This doesn’t include demand from a large number of smaller bitumen and heavy oil producers. Also, Peters & Co. doesn’t expect much near-term diluent recovery from bitumen pipelined to rail ter minals, and it predicts condensate storage capacity in the Edmonton/ Fort Saskatchewan area will remain tight. In total, Peters & Co. estimates condensate demand from all oilsands producers and conventional heavy oil operators will exceed 350,000 barrels per day this year. The investment firm says the build-out of pipelines and other infrastructure in northern Alberta will accommodate consumption of more than one million barrels per day of condensate in the oilsands.
OIlsands operators will need 350,000 barrels per day of condensate in 2014.
While demand for condensate skyrockets, in recent years production in western Canada has been declining, but the trend has reversed as prices climbed with rising demand for bitumen transportation. Peters & Co. had previously predicted condensate production in western Canada, which has reached 150,000 barrels per day, would grow to 200,000 barrels per day by 2020. But given the stronger recent production results from several liquidsrich plays, Peters & Co. has now also included a more optimistic highend production estimate of about 300,000 barrels per day by 2020. This high-end scenario assumes more production from the Montney and Duvernay formations.
OILSANDS PROJECTED NATURAL GAS USE Process gas for mining/ upgrading
Produced gas for in situ recovery
11.80 12.40 13.01 13.06 13.17 13.34 13.74 14.21 14.56 14.91
15.09 16.24 16.89 17.27 17.70 18.06 18.64 19.39 19.89 20.21
6.05 6.19 6.50 6.75 7.20 7.83 8.35 8.82 9.25 9.62
Purchased gas for in situ recovery
Purchased Process gas for gas for electricity electricity cogeneration cogeneration
Purchased gas for mining/ upgrading
Process gas for mining/ upgrading
Produced gas for in situ recovery
0.42 0.44 0.46 0.46 0.47 0.47 0.49 0.50 0.52 0.53
0.54 0.58 0.60 0.61 0.63 0.64 0.66 0.69 0.71 0.72
0.21 0.22 0.23 0.24 0.26 0.28 0.30 0.31 0.33 0.34
22.46 24.32 28.03 31.81 36.94 41.88 45.23 47.75 50.68 53.28
Purchased gas for in situ recovery
Purchased Process gas for gas for electricity electricity cogeneration cogeneration
15.05 15.52 17.23 19.47 22.54 24.87 25.20 26.49 26.57 26.57
3.38 3.39 3.39 3.38 3.39 3.40 3.40 3.39 3.41 3.41
0.80 0.86 0.99 1.13 1.31 1.49 1.61 1.69 1.80 1.89
0.53 0.55 0.61 0.69 0.80 0.88 0.89 0.94 0.94 0.94
0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12
Source: Alberta Energy Regulator
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Photo: Joey Podlubny
Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Purchased gas for mining/ upgrading
Photo: Joey Podlubny
Gas plants are going to need retrofitting to deal with the high liquids content of the Duvernay.
of condensate in the southern part and significant amounts of natural gas liquids in the northern part, as well as one block we called Waskahegan, which is particularly attractive in the north and surrounded by some pretty attractive wells drilled by our competitors.” The company currently holds interests in 347,000 net acres of land in the Duvernay. Talisman has drilled eight appraisal wells to date in the play and continues to evaluate its extensive acreage position. The two most recent wells drilled in the South Duvernay had seven-day average rates of 2.2 million cubic feet per day of gas and 550 barrels per day of condensate. Although these are early-stage results, Kvisle said they show the promise of Talisman’s Duvernay assets in the southern portion of the play. “The two wells that we announced are in the southern part of our Duvernay position and...we are quite excited by the liquids potential, and one of the purposes of releasing this information was to indicate that we are in a significantly liquids-rich part of the Duvernay,” he said. This year, the company plans to drill six wells as it continues to appraise its extensive land position. Talisman will drill its first multi-well pad in the southern part of the play and will begin a process to secure a strategic partner. Kvisle noted that a big challenge in making the Duvernay an “outstanding play” is going to be on the cost-control side. “We know we can improve the production rates through some longer horizontals and more hydraulic fracturing stages.... We are working with other industry players and with service companies, and I am pretty confident
we will be there on good technical answers in the Duvernay,” he said. “The real challenge, given the depth of the Duvernay, is to figure out all the different ways we can reduce the drilling-cycle time to really bring down the drill cost and then to reduce the very high fracturing cost.” At this point, Kvisle won’t speculate on what EUR from the wells might be. “The good news is that the Duvernay has got great liquids content, and it’s a relatively high-pressure reservoir—those are two factors that we think are pretty important as far as EURs, but we don’t want to get ahead of ourselves,” he said. Talisman is also in the midst of proving up a Wilrich play in the Edson area. In the fourth quarter, Talisman brought on stream three wells with 30-day average sales ranging from 5.6 million to 5.9 million cubic feet per day with 170–525 barrels per day of liquids. Kvisle said the company is fortunate that it is coming into the Wilrich play with a large legacy land position held by deeper production in the Greater Edson area. “From what we have seen so far, we have got some land that’s pretty well located. But because most of our land is held by production, we are able to enjoy the luxury of watching other people and how they go about developing their lands so that we can enter the capital phase of it with as much knowledge as possible about how to do it in a cost-controlled way. So that’s the approach we are taking,” Kvisle said. This year, the company will continue to appraise the Wilrich Formation through a ninewell drilling program.
Emerging shale plays could be game changers
The Duvernay is the furthest along of central Alberta’s shale plays, but it isn’t the only show in town. A number of explorers have been testing the Second White Specks shale, including Yangarra Resources Ltd. Yangarra has been “very keen” on shale plays and has done a lot of work on the Second White Specks Formation in the oil window, accumulating 45 (29 net) sections of land, says company president and chief executive officer Jim Evaskevich. However, the company is finding that “it is not easy to crack the nut on this particular play,” a thick shale lying below the Cardium and just above the Viking. “We think we are a lot closer.”
“T he good news is that the Duvernay has got great liquids content and it’s a relatively high-pressure reservoir.” — Hal Kvisle, president and chief executive officer, Talisman Energy Inc.
The Second White Specks has an estimated 10 million to 20 million barrels of original oil in place per section and considerable oil has been produced over the past 30 years, Evaskevich says. With three horizontal wells and two vertical wells in the play, “we’ve drilled more of them than anybody else to our knowledge,” Evaskevich says. With the Second White Specks now generating $250,000–$300,000 per month in revenue, it is content to pay down the capital it has put into the play, while seeing what other producers in the area are doing, he adds. Yangarra has one horizontal well that has six stages ready to fracture, but it still has to decide when to finish the job as the well is making “an awfully good profit just the way it is.” Yangarra believes it needs to revise its frac process and knows what it wants to try next, but “it’s pretty easy just to sit back when you are generating that much income out of there,” Evaskevich says. “We want to get closer to having the house’s money.” P R O F I L E R M A G A Z I N E . C O M
Drilling operations in southern Alberta.
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New oil plays provide hope in southern Alberta
In 2010, it looked like southern Alberta was set for a tight oil drilling boom as explorers scooped up land prospective for the Alberta Bakken Formation. Around $270 million was spent acquiring land in the play, with a number of exploratory wells spud and anticipation running high. Four years, after plenty of ups and downs, explorers continue working to unravel the Alberta Bakken system. And it appears a few have found sweet spots in the play, giving southern operators a base to build on. But the Alberta Bakken is only part of the story in southern Alberta. Work also continues in the Pekisko tight oil play, where waterflood efforts are under way to maximize recovery.
And an emerging Mannville oil play is adding to opportunities in the region. DeeThree Exploration Limited has, by far, enjoyed the greatest success in the Alberta Bakken. DeeThree has 200 gross sections of land in the Bakken fairway and has discovered an oil
Alberta Bakken Horizontal Well Production Company DeeThree Exploration Ltd. TORC Oil & Gas Ltd. Connaught Oil & Gas Ltd. Crescent Point Energy Corp. Kainai Energy Corp. Gryphon Petroleum Corp. Nexen Energy ULC Total
Operated wells 22 8 4 17 2 3 3 59
2,693 584 186 149 120 46 13 3,791
Sources: Scotiabank Playbook; Daily Oil Bulletin; SEDAR
PEKISKO 2013 OIL WELLS Direction Operator Cenovus Energy Inc. Coda Petroleum Inc. Crew Energy Inc. Encana Corporation Husky Energy Inc. Spyglass Resources Corp. West Valley Energy Corp. Total
Directional 18 -1 21 2 --42
Horizontal 11 2 6 2 2 2 1 26
Vertical 7 -2 -1 --10
Total 36 2 9 23 5 2 1 78
Source: Daily Oil Bulletin
Photo: Joey Podlubny
While in the company’s view, “ultimately this is going to be a big play, it’s going to take some time,” shareholders were told. DeeThree Exploration Ltd. is more advanced with its Belly River oil play in central Alberta. DeeThree has been working on developing its Belly River assets since 2011. “We basically pioneered the Belly River play. Nobody else was drilling in the Belly River play. Today, we’ve got, I think, 338 future well locations on the whole block, and I do believe that number is going up to north of 500,” DeeThree’s president and chief executive officer Martin Cheyne says. “It’s probably the biggest oil pool that I’ve ever been associated with,” he adds. “I think we’ve got somewhere between 600 million and 700 million barrels of oil in place here, and there’s only been 14 million barrels taken out.” He believes the Brazeau Belly River pool will prove to be one of Alberta’s blockbuster conventional light oil reservoirs. “Nobody believed us how good this asset was,” Cheyne recalls. “And to be honest with you, the market still doesn’t realize how big this Belly River sand package is. I mean, we’re making baby steps. We’ve been on the road a lot this year. Guys are starting to realize how good this play really is. We keep putting press releases out of 1,000-barrel-aday-plus wells.”
pool in the play running 14 miles long and four miles wide, covering more than 56 sections of land. The pool, located in the Upper Bakken, is in the Ferguson area near Lethbridge, Alta. As of year-end 2013, the company had drilled 28 horizontal wells in the play and reported production of around 4,000 barrels per day of light oil. Its current type curve for the play puts well costs at $3.5 million, recoverable reserves at 400,000 barrels, payout at a little over a year, and a rate of return at 146 per cent, making it one of the more profitable tight oil plays in Alberta. The company reported 2013 year-end proved-plus-probable Bakken reserves of 19.2 million barrels, up 80 per cent from the
“ THE BELLy RivER PLAy iS PROBABLy THE BiggEST OiL POOL THAT i’vE EvER BEEN ASSOCiATED wiTH. i THiNK wE’vE gOT SOMEwHERE BETwEEN 600 MiLLiON AND 700 MiLLiON BARRELS OF OiL iN PLACE HERE.” — Martin Cheyne, president and chief executive officer, DeeThree Exploration Ltd. previous year. It has 32 undeveloped drilling locations on its developed lands and plans on drilling 20 wells this year. Cheyne says that early on in the Bakken play, DeeThree was one out of six or seven different companies that was having any success at all in the Alberta Bakken. “So we had a hard time convincing people to believe it,” Cheyne says. Early last year, DeeThree drilled a well on the northern part of its southern Alberta Bakken lands. “The market had gone so cold on the Alberta Bakken because of all the terrible results. We didn’t even tell anyone we were drilling this well,” says Cheyne. “We didn’t want to tell anyone because we probably would have got shot by our institutional investors. So we licensed it for a Sunburst well. We got 13 metres of pay on that well. It had better pay, better porosity, and it was much thicker than we had thought.” The well tested at about 600 barrels of oil equivalent per day. “Still, nobody believed how great this play was—because it was DeeThree. And if Murphy
Oil Company Ltd. couldn’t figure it out, and Crescent Point Energy Corp. couldn’t figure it out, DeeThree couldn’t figure it out,” he says. “So we drilled five more wells. Nobody believed us.” Once DeeThree drilled its step-out well seven miles to the west and still had a large pay zone, “then we knew we had something really, really big,” Cheyne recalls. The company has now drilled 20 wells in the area with test rates now coming in at 600–950 barrels per day of 30 degree API oil. he says the best well, to date, exceeded 1,300 barrels per day on a flow test.
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TORC Oil & Gas Ltd. is also showing some early success in unravelling the mysteries of the Bakken system at its Monarch play, which is comprised of 150 net sections of land. In 2013, TORC focused on exploring its light oil resource at Monarch while modifying drilling and completion techniques to progress toward area development. During the fourth quarter of 2013, TORC drilled two wells, including one exploration well (04-20) and one development well (14-01). For the full year 2013, TORC drilled three exploration wells at Monarch and one development well.
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Drilling in west-central Alberta.
J une 2 0 1 4
Pekisko and Mannville plays taking off
Both the Pekisko and Mannville heavy oil plays are also emerging from obscurity in southern Alberta. Crew Energy Inc. was one of the pioneers of the Pekisko play, with 290,000 net acres in the Princess area of southern Alberta. It is now focused on maintaining production in the Pekisko with 11 waterfloods under way. Its exploration focus has now turned to the Mannville play. Crew Energy’s Princess production averaged 4,738 barrels per day in the fourth quarter, driven by recent Mannville drilling activity. In 2014, Crew Energy will focus on Mannville development at Princess, with plans to drill 16 horizontal wells targeting both the Sunburst and Detrital formations, as the relative economics of Mannville development are superior to Pekisko development given the more attractive Crown royalty scheme. In the first quarter, the company drilled six (six net) horizontal wells at Princess targeting the Mannville. Crew Energy will continue to optimize performance of the Pekisko waterfloods by converting an additional four wells to water injection. Hemisphere Energy Corporation is also targeting the Mannville and Pekisko. Its first horizontal well on its Atlee Buffalo property, drilled in January, targeted the oilbearing Glauconitic sandstones within the Mannville Group. It has been on production for over 30 days at an average pumping rate of approximately 100 barrels of oil per
day with a two per cent water cut and minor associated gas. With the consistent low water cut, Hemisphere has been able to tank-treat the oil production and truck directly to sales, the company says. The initial production results of the Atlee Buffalo horizontal well are better than expected and very encouraging as Hemisphere continues to finalize additional drilling locations and development plans, it says. A second horizontal well in Atlee Buffalo was planned for March, but due to warm weather conditions, the well has been rescheduled to be part of a multi-well drilling program after spring breakup. Hemisphere acquired the Atlee Buffalo property in November 2013, with the plan to increase oil recovery from existing pools using horizontal wells and future pressure maintenance. Hemisphere has 100 per cent working interest in nine contiguous sections of land covering two significant Glauconitic oil pools, where up to 75 drilling locations have been identified. Cenovus Energy Inc. is the king of southeastern Alberta, with around three million acres of land in the region. In 2013, it drilled around 102 wells in the area, targeting both heavy oil at Suffield, Alta., and tight plays north of Brooks, Alta. It drilled 36 wells targeting the Pekisko in 2013, according to Daily Oil Bulletin records. Cenovus plans to spend between $540 million and $590 million on its conventional oil assets in 2014, a 22 per cent decrease when compared with the previous year as part of the company’s continued efforts to align capital investment with expected cash flow in 2014.
Photo: A aron Parker
Although early in the evaluation process, initial production results from the company’s 04-20 exploration well, which was drilled, completed and tested in the fourth quarter and brought on production in February 2014, have been encouraging. TORC has identified an area in the heart of the Monarch play that will be the focus of the company’s initial development efforts. TORC’s 14-01 well, the first development well into the play, was completed in the first quarter of 2014 and is currently awaiting tie-in. Based on well performance and initial flowback data, Sproule Associates Limited has assigned provenplus-probable reserves per well ranging from 300,000 to 425,000 barrels (100 per cent light oil) in TORC’s initial development focus area. In addition to completing the 14-01 development well, TORC’s plans at Monarch in 2014 include drilling three additional development wells. The initial development project is focused on demonstrating the repeatability of results, the enhancement of recovery factors and the reduction of costs to further enhance the economics of the play. The company has identified 77 drilling locations in its current development area. LGX Oil+Gas Inc. is also finding early success on its Bakken acreage. LGX has around 110,000 acres covering the Bakken oil system. It drilled two wells into the Big Valley (Three Forks) Formation during 2013, both in the fourth quarter. The company drilled its 14-02 well, which was fracture stimulated, to a depth of 1,150 metres horizontally from a vertical stratigraphic test. Put on production in late January, the well averaged in excess of 530 barrels of light oil per day for the first 30 days of production. The well currently produces about 470 barrels per day of oil at a 13 per cent water cut and with high fluid levels. LGX has 100 per cent working interest in the well prior to recovery of 200 per cent of the drilling, completion, equipping and tie-in costs, at which point its interest will revert to 80 per cent. The company’s 10–15 vertical stratigraphic wells encountered 13 metres of gross pay in Big Valley, which confirms the company’s 3-D seismic interpretation. Well logs and core samples indicate good porosity and permeability, and the core had good oil saturations and geochemical evaluation showing high total organic carbon and early oil maturation. LGX kicked off and drilled the well to an intermediate casing point in the reservoir for future re-entry to drill a horizontal leg. A similar reservoir was encountered in the build section.
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Workhorse Oilsands spending to keep chugging along
Photo: joey podlubny
By Darrell Stonehouse, with notes from Daily Oil Bulletin staff
lberta 2014 oilsands capital expenditures should equal last year’s as operators continue to ramp up production, despite the current challenges of tight pipeline capacity. The Canadian Association of Petroleum Producers is projecting another strong year, with expenditures in line with 2013 spending of about $25 billion, says Martyn Griggs, manager of oilsands. “We don’t see a major uptick or a major downtick either,” he says. “In any other industry, they would be stunned with that level of investment.” The oilsands has bounced back strongly since 2009, when expenditures of $18 billion reflected a significant pullback in response to the global economic downturn, Griggs notes. Production forecasts for the oilsands also remain rosy, even with worries about market access. Despite the rapid growth of tight oil in the United States, the oilsands will continue to be an important component of U.S. oil supply, according to a report by international energy analysts at IHS CERA written in October 2013.
Entitled Critical Questions for the Canadian Oil Sands, the report says that even with tight oil growth, the United States will still need more than five million barrels per day of net crude oil imports over the next two decades, and Canada will be key to helping meet this demand. Oilsands and tight oil are complementary, not competitive, with light tight oil and heavy oilsands crude targeting different refinery markets in the United States. Canada is one of four countries included in what IHS CERA has called the “axis of oil supply growth.” The other three are the United States, Brazil and Iraq. The consultancy expects western Canadian crude oil output to rise to 5.9 million barrels per day by 2030 from three million barrels per day in 2012. Considering other anticipated sources of growth, the oilsands could account for 16 per cent of all new production globally until 2030, it says. This assumes that oilsands production grows by 2.6 million barrels per day between 2012 and 2030 (not including diluents added to oilsands for shipping) and that over the P R O F I L E R M A G A Z I N E . C O M
2014’s big spenders Canadian Natural Resources Limited and Suncor Energy Inc. will be the two biggest spenders this year. Canadian Natural has forecast capital expenditures of $4.68 billion, of which up to $3.55 billion has been allocated to its Horizon mining operation and $1.13 billion to thermal in situ projects. Planned spending at Horizon includes up to $1.58 billion for Phase 2B and up to $770 million for Phase 3. In situ allocations include $600 million for Primrose 52
June 2 0 1 4
Directional drilling at Imperial Oil’s Cold Lake oilsands operations.
ALBERTA CRUDE BITUMEN PRODUCTION FORECAST Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Surface mining (103 m3/d)
170.4 186.1 206.9 231.8 259.4 287.3 308.9 324.5 338.7 350.8
172.5 180.3 186.9 194.1 202.3 216.5 224.6 232.8 246.5 254.6
1,072.3 1,171.1 1,302.0 1,458.7 1,632.4 1,808.0 1,943.9 2,042.0 2,131.4 2,207.5
1,085.5 1,134.3 1,176.1 1,221.3 1,273.1 1,362.5 1,413.2 1,465.0 1,551.4 1,602.2
Source: Alberta Energy Regulator
and future projects and $450 million for Kirby North Phase 1. For its part, Suncor has budgeted $4.45 billion for its oilsands operations including $1.35 billion for advancing the Fort Hills mine joint venture with Total E&P Canada Ltd. and Teck Resources Limited. The mine will produce up to 73,000 barrels per day of bitumen as early as the first quarter of 2017. Husky Energy Inc. plans to spend $400 million for its 60,000-barrel-per-day (30,000-barrel-per-day net) Sunrise thermal in situ project. First oil should come on production in late 2014. The estimated total cost of the project is $2.8 billion. Syncrude Canada Ltd.’s total budget for 2014 is $2.76 billion. The majority will be directed to its major projects, the Mildred Lake mine train replacement ($965 million) and the centrifuge tailings management project ($812 million). The Mildred Lake mine train replacement project is targeted to be in service in the
fourth quarter of 2014, with the tailings management project expected to be in operation in the first half of 2015. For Canadian Oil Sands Limited (COS), which indirectly owns a 36.74 per cent interest in the Syncrude joint venture, the majority of its $1.01-billion expenditure for 2014 will be the Mildred Lake mine train replacement (COS’s share is $355 million) and the centrifuge tailings management project (COS’s share is $298 million). Cenovus Energy Inc. and ConocoPhillips Canada plan to spend a combined total of $1.64 billion at their Christina Lake joint venture, $1.52 billion at Foster Creek and $460 million at the new Narrows Lake project. All 50/50 joint ventures are in situ projects. On its own, Cenovus has budgeted an additional $160 million for in situ emerging oilsands assets. Total E&P Canada will spend $2 billion in the oilsands this year with the vast majority ($1.24 billion) allocated to the Fort Hills
Photo: joey podlubny
same period, global production grows by over 16 million barrels per day. Although markets for the oilsands are expected to diversify gradually, a large part of new oilsands supply through 2030 is expected to go to the United States—as virtually all of the production does today. By 2030, the United States could import more than four million barrels per day of oilsands crudes from Canada. Between 2012 and 2030, western Canadian supply is projected to grow by 2.9 million barrels per day. Assuming that the Trans Mountain expansion and the Northern Gateway and Energy East pipelines are constructed by 2030, there is the potential for 1.9 million barrels per day of new western Canadian supply to be exported to other markets, says IHS CERA. This assumes that some oil transported by these pipelines will still be exported to the United States, by tanker or barge. By the end of this year, Canadian oilsands production will be roughly equivalent to about two-thirds of estimated global spare production capacity for 2013, it says. The study’s authors expect 2020 global spare production capacity to average about 4.3 million barrels per day, which is higher than the two million to three million barrels per day in recent years. The International Energy Agency (IEA) also expects oilsands production to continue rising. In its most recent outlook, the IEA predicts Canadian oil production will grow steadily until 2035, with rising output from oilsands and light tight oil more than making up for a slow decline in conventional crude oil. In total, output rises by 62 per cent, from 3.8 million barrels per day in 2012 to 6.1 million barrels per day in 2035. The oilsands will produce 4.3 million barrels per day by 2035, with their share of overall oil production rising from just under half to 70 per cent.
OILSANDS PROJECTS UNDER CONSTRUCTION Operator
Project Sawn Lake Hangingstone MacKay River
Demonstration Phase 1 Phase 1 Reliability Tranche 2
Sawn Lake Halfway Creek Birchwood
Peace River South Athabasca North Athabasca
Andora Energy Corporation Athabasca Oil Corporation Brion Energy Corporation Canadian Natural Resources Limited Canadian Natural Resources Limited Canadian Natural Resources Limited Canadian Natural Resources Limited Cenovus Energy Inc. Cenovus Energy Inc. Cenovus Energy Inc. Cenovus Energy Inc. Cenovus Energy Inc. CNOOC Limited ConocoPhillips Canada Devon Canada Corporation Harvest Operations Corp. Husky Energy Inc. Imperial Oil Limited Imperial Oil Limited Japan Canada Oil Sands Limited MEG Energy Corp. North West Upgrading Inc.
Redwater Upgrader Phase 1
Pengrowth Energy Corporation
Production start 25 2014 563 2015 1,300 2015
Christina Lake Foster Creek Foster Creek Foster Creek Narrows Lake Long Lake Surmont Jackfish BlackGold Sunrise Cold Lake Kearl
Phase F Phase F Phase G Phase H Phase A Kinosis (K1A) Phase 2 Phase 3 Phase 1 Phase 1 Phase 14–16 Phase 2
Christina Lake Foster Creek Foster Creek Foster Creek Conklin Cheecham Hangingstone Conklin Conklin Steepbank Cold Lake Fort McKay
South Athabasca South Athabasca South Athabasca South Athabasca South Athabasca South Athabasca South Athabasca South Athabasca South Athabasca North Athabasca Cold Lake North Athabasca
SAGD SAGD SAGD Mining/ upgrading Mining/ upgrading Mining/ upgrading Mining/ upgrading SAGD SAGD SAGD SAGD SAP SAGD SAGD SAGD SAGD SAGD CSS Mining
Christina Lake Sturgeon County
South Athabasca Industrial Heartland
Carmon Creek Phase 1 Phase 1
Royal Dutch Shell plc
Suncor Energy Inc.
UC UC UC
1,400 12,000 35,000
UC UC UC UC UC UC UC UC UC UC UC UC
50,000 45,000 40,000 40,000 45,000 40,000 109,000 35,000 10,000 60,000 40,000 110,000
-2,000 --1,600 -2,490 1,400 460 2,800 2,000 8,900
2016 2014 2015 2016 2017 -2015 2014 2014 2014 2014 2015
Sources: Alberta Energy Regulator; corporate disclosures
mine project. The company is also working on Surmont Phase 2, a joint-venture in situ project with 50/50 partner ConocoPhillips. MEG Energy Corp. plans capital spending of $1.8 billion in 2014. Spending will include the implementation of Phase 2 of its RISER production enhancement initiative and the ramp-up of Christina Lake Phase 2B. The budget includes investment in a major brownfield expansion within Phase 2B, which the company anticipates will raise its overall production to 115,000–125,000 barrels per day by early 2017. MEG has also budgeted $125 million in 2014 for a field pilot test of its proprietary HI-Q technology. This “pipeline-spec-upgrading” process is designed to lower the viscosity of the company’s bitumen sufficiently for pipelining without diluent. At the Athabasca Oil Sands Project joint venture operated by Royal Dutch Shell plc, planned capital spending is $1.47 billion. (Shell’s share is $882 million.) Teck Resources has a capital budget of $995 million, with $850 million for its share of the Fort Hills mining project. It has allocated an additional $105 million for its proposed new
Frontier mine, a 240,000-barrel-per-day project about 110 kilometres north of Fort McMurray. Devon Canada Corporation capital expendi tures of $900 million for thermal in situ oilsands projects will include completing construction of the Jackfish 3 in situ project. Athabasca Oil Corporation plans to spend $328 million on the Hangingstone in situ project. The figure includes $225 million for the project itself, with first steam expected near the end of this year; $58 million on Hangingstone regional infrastructure and production support; and $45 million for regional activities and to advance the regulatory approval for a Hangingstone expansion. The company has also allocated another $20 million for other in situ projects. At Lindbergh, Pengrowth Energy Corporation has budgeted $365 million for the completion of its 12,500-barrel-per-day in situ project. First steam is expected in the fourth quarter of 2014, with first oil in early 2015. Harvest Operations Corp., a wholly owned subsidiary of Korea National Oil Corporation, will spend $131 million as it continues work on its BlackGold project, a 10,000-barrel-perday in situ project.
Connacher Oil and Gas Limited has a $58-million capital budget. The $50 million allocated for growth will include nine new infill wells at Pod One and continued engineering work on its proprietary SAGD+ at Algar, along with a mini steam expansion at Pod One. Baytex Energy Corp. will spend about $24 million on thermal projects.
Industry focused on costs Alberta’s in situ oilsands production used to be high-cost marginal barrels, meaning projects went on the shelf when oil prices declined. Not anymore. In situ production now competes favourably with oil plays across North America, according to two recent studies, and that means new developments are moving ahead with greater certainty. In one recent study, Scotiabank found in situ oilsands projects had break-even costs of US$63.50 per barrel, with existing mines coming in at $60–$65 per barrel. A Bank of Montreal study showed similar results, finding in situ oilsands operations had break-evens of about $65 per barrel. P R O F I L E R M A G A Z I N E . C O M
With a number of projects in the early stages of development, Cenovus Energy says even if oil prices fall to as low as $75 per barrel, those projects can survive thanks to supply costs of just $35–$45 per barrel West Texas Intermediate. At those prices, the company’s Foster Creek and Christina Lake steam assisted gravity drainage (SAGD) projects rake in a nine per cent return, Al Reid, senior vice-president of Christina Lake, told the BMO Capital Markets Unconventional Resource Conference. “Both Foster Creek and Christina Lake have plans to expand to 300,000 barrels a day, but we think we could keep going,” said Reid. “You always make that decision at the time you have to make it, but our capital efficiencies and our supply costs should allow us to continue to go through some ups and downs in crude oil prices.” He said capital cost efficiency at Narrows Lake, Cenovus’s next major oilsands development, is expected to be about $30,000 per flowing barrel based on infrastructure needed for the greenfield project, such as constructing fuel gas lines, supplying electricity and bringing in a diluent supply for the solventaided process (SAP). Narrows Lake is expected to be the industry’s first project to demonstrate SAP, using butane, on a commercial scale. The first phase of the project is expected to have a production capacity of 45,000 barrels per day gross, with first oil expected in 2017. Telephone Lake, another planned SAGD project, will require even more infrastructure, so it might have higher costs, while yet another proposed project, Grand Rapids, will benefit from existing infrastructure in the Greater Pelican area, he said. Last year, the company drilled a second well at the Grand Rapids pilot project and will provide an update on the outcome in the second quarter, said Reid. A regulatory application and environmental impact assessment for a 180,000-barrel-per-day commercial project at Grand Rapids has been submitted. Cenovus had hoped for regulatory approval by the end of 2013. Cenovus has seen inflation moderate over the past two or three quarters, Reid told analysts. “We are hearing anecdotally from some of our suppliers that they have shop space available right now, so that’s a good thing; that’s a good indicator. I think probably the biggest thing we’ve seen is that some of the long-lead items are a little longer lead than they have been in the past, but again, we’re starting to see some of that shop space free up,” he added. 54
J une 2 0 1 4
ALBERTA STEAM to OIL RatioS 2014 Commercial schemes Company
Grizzly Oil Sands ULC Laricina Energy Ltd. Canadian Natural Resources Limited Husky Energy Inc. Royal Dutch Shell plc BlackPearl Resources Inc. Canadian Natural Resources Limited Southern Pacific Resource Corp. CNOOC Limited Japan Canada Oil Sands Limited ConocoPhillips Canada Connacher Oil and Gas Limited Imperial Oil Limited Royal Dutch Shell plc Baytex Energy Corp. Cenovus Energy Inc. Statoil Canada Ltd. Suncor Energy Inc. Suncor Energy Inc. Cenovus Energy Inc. MEG Energy Corp. Devon Canada Corporation ConocoPhillips Canada Pengrowth Energy Corporation Cenovus Energy Inc. Murphy Oil Company Ltd.
Algar Lake Germain Kirby South Tucker Peace River/Carmon Creek Blackrod Primrose & Wolf Lake STP-McKay Long Lake Hangingstone pilot Surmont pilot Great Divide Cold Lake Orion Cliffdale pilot Grand Rapids Leismer Firebag MacKay River Foster Creek Christina Lake Jackfish Surmont Lindbergh pilot Christina Lake Seal/Cadotte pilot
-117.02 15.45 6.13 6.42 7.18 5.99 5.32 4.62 4.46 4.26 4.15 3.70 3.61 3.23 3.89 3.13 2.99 2.79 2.63 2.61 2.53 2.53 2.11 1.87 1.23
180.44 69.80 10.49 6.55 5.72 3.91 4.97 4.56 4.68 4.71 4.83 3.91 3.75 3.28 3.56 2.64 3.17 3.05 2.62 2.75 2.52 2.48 2.35 2.13 1.86 --
Monthly average 180.44 93.41 12.97 6.34 6.07 5.55 5.48 4.94 4.65 4.59 4.55 4.03 3.73 3.45 3.40 3.27 3.15 3.02 2.71 2.69 2.57 2.51 2.44 2.12 1.87 1.23
Source: Alberta Energy Regulator
Despite the industry’s current success at managing costs, more will be needed in the future, according to one industry representative. It is absolutely necessary to reduce in situ oilsands projects’ steam to oil ratios (SORs) to be as low as possible, because not doing so risks their development, as it is a key factor in costs, Shabir Premji, chief financial officer of Grandstar Resources Limited and entrepreneur, told the In Situ Oil Sands SOR Reduction Initiative 2013 in Calgary. SOR affects initial capital costs, sustaining capital expenditures, energy use and, by extension, the sensitivity of energy costs and the project discount rates, said Premji. Premji is a partner in Caribou LLC, an advisory firm that provides strategic and tactical advice for chief executive officers and their boards, and is a consultant to several international companies interested in acquiring oil and gas assets in Canada and the United States. Challenges in the coming years, such as continuing heavy-to-light price differentials and increasingly sensitive supply costs, can be mitigated by lowering oilsands projects’
SORs, said Premji, former executive chair and founder of Alberta Oilsands Inc. “It is all about getting the maximum production and the maximum amount of resource in place at the lowest cost possible. Industry is beginning to crack the two SOR mark and is beginning to increase recovery of resource in place to the 70 or 80 per cent level,” he said. “This obviously will have large net positive effects on a producer’s bottom line.” Premji said the lowest SOR in the industry is 2.1, at Cenovus Energy’s Christina Lake in situ oilsands project. The highest published SOR is 11 and the average is four. Pointing to Cenovus as an example, he said a project’s SOR can be reduced through recycling, upgrading, producing from wedge wells, the use of solvents “where steam almost becomes a mere propellant or the solvent delivery agent,” and nano-catalytic processing upgrading. The all-important understanding of the reservoir itself is a huge factor in reducing a pro ject’s SOR, he added. The world expects—even demands and will impose—a carbon tax on the oil and gas industry, and a lower SOR means lower greenhouse gas emissions and lower carbon taxes to pay, he said.
Natural gas and electricity prices are expected to remain constrained but still present a risk, said Premji. To withstand market changes, operators must reduce costs, increase recoveries and reduce environmental risks, said Premji. “Remember that natural gas assets are a natural hedge and will not always remain cheap. Diversify your markets, plan for better and more cost-effective transportation. Use hedges to provide stability and consider owning upgrading assets,” he said. “Attention to these operational factors will contribute to reducing your company’s risk and sensitivity to an adverse business climate in whatever form it may present itself.” Starting in 2015, oilsands projects will require input costs of $50 billion annually, so initially their capital expenditures budgets will rise, but then sustaining budgets will take over and SOR reduction should massively mitigate these costs, said Premji. Conservatively, over 50 per cent of supply costs are directly SOR-based and therefore controllable by SOR management, he said. Management must make SOR reduction a priority, as there is a clear relationship between reduced SORs and input costs, he told the forum.
would be required for successful expansion of oilsands developments. “The bottom line is we need to go to market,” she said, adding the rail industry must contend with public safety concerns that have come about following the explosion at Lac-Mégantic, Que. She said the future success of crude by rail depends on tight regulations for the processing and handling of crude carried on the tracks. “It’s like any other mode of transportation— there has to be a safety check on every bit of it as it goes forward.”
canadian SuppliErS HopE to bEnEFit From oilSandS growtH The growth in oilfield equipment and machinery manufacturing targeting the oilsands in recent years has made Edmonton into a global centre of advanced steel manufacturing technologies, with the area supporting the largest concentration of automated steel fabrication equipment in the world, according to Paul Collins, founder and chief executive officer of Collins Industries Ltd. and one of the driving forces behind the Alberta Steel Manufacturers (ASM).
markEt accESS main iSSuE Facing induStry Cutting costs is one thing in the oilsands. Finding market for production is another. Not only must all current pipeline projects connecting the oilsands to new markets be approved and completed in a timely fashion, but new ones must be added to the list as well— and quickly—or the impact on Canada’s economy could be dire, according to Patricia Nelson, vice-chair of the In Situ Oil Sands Alliance. “We are getting to a point where we have to have this go forward fast. It’s not optional anymore,” Nelson told a Canadian Institute conference early this winter. She said oilsands exports must expand into the global arena, and they must do it soon, because while she does not foresee exports to the United States shrinking, there is not much room for growth in that market anymore, either. “If you can’t get to market, there’s no point in producing, and I don’t know what you’re going to do with the product. So we’re in a serious situation.” Nelson added it is not an either-or scenario when considering pipelines and crude by rail. She said both modes, as well as trucking,
ALL THE SMALL PARTS AND BIG PLAYERS ARE FOUND ON Utilize an ever-expanding database of Canadian oilfield service and supply companies (and a powerful set of search filters) to access 11,000 companies in over 1,300 categories.
Canadian manufacturers are capturing only 20 per cent of oilsands capital spending, says CME.
Based on what we know about the state of interprovincial supply chains, the types of manufacturing inputs required by oilsands producers and the rate of new projects coming online, there is a significant opportunity for Canadian manufacturers to capitalize on a rapidly growing market demand here at home.
— Jayson Myers, president and chief executive officer, Canadian Manufacturers & Exporters
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as $905 billion through the end of 2030. Maintenance, repair and operations expenditures, meanwhile, could total another $912 billion. “Based on what we know about the state of interprovincial supply chains, the types of manufacturing inputs required by oilsands producers and the rate of new projects coming online, there is a significant opportunity for Canadian manufacturers to capitalize on a rapidly growing market demand here at home,” says Myers. “They can’t, however, sit back and wait. Manufacturers need to plan, invest and retool—and governments at all levels must provide the policies and support needed to make that happen.” Provided interprovincial trade capacity increases at the correct rate, the projected range of opportunities for Canadian manufacturers supplying oilsands operations between 2012 and 2030 will be between $211 billion and $387 billion, says CME. To put this growth into perspective, if the high end of the projection is accurate, this would result in oilsands-related manufacturing being equal to 75 per cent of current annual Canadian industrial production. CME has a list of things that need to happen to make this a reality. They include: • Creating an oilsands supply chain working group to be established with senior leaders from project owners, engineering, procurement and construction contractors (EPCs), and manufacturers that can focus on major bottlenecks in the supply chain, and identifying common threats to growth (such as labour shortages) and the role that each party can play in improving overall performance; • Creating detailed how-to guides for manufacturers from both project owners and
EPCs on the expected actions to be undertaken to participate in oilsands supply chains; • Establishing an oilsands supply chain resource office to help manufacturers learn about specific procurement opportunities and how to efficiently engage and navigate supply chains; and • Developing common supply chain prequalification standards and centralizing a process for pre-qualifying manufacturers and their specific products and services. To strengthen the investment climate and make the supply chain more efficient, the business environment across Canada must be improved, with a specific focus on manufacturing competitiveness and productivity, says CME. With globally integrated supply chains and the ability to supply customers around the world, creating a competitive business climate is critical to attracting investment for value-added innovative goods and services. CME recommends: • Improving the quantity and quality of the available labour pool; • Supporting manufacturing investments in production, productivity, innovation and commercialization through globally competitive direct-support mechanisms and through competitive tax regimes; • Reforming and modernizing the regulatory system to lower operating costs and speed decision making; and • Strengthening supporting infrastructure that is essential to manufacturing competitiveness, including the cost and reliability of energy and the connecting trade networks, especially east-west railway corridors.
Photo: joey podlubny
The ASM is a partnership between the Alberta Pressure Vessel Manufacturers’ Association, the Canadian Institute of Steel Construction, the Alberta division of Canadian Manufacturers & Exporters (CME) and the economic competitiveness division at Alberta Innovation and Advanced Education. The members first got together in late 2010 and concluded that fabricated steel was being sourced from offshore for oilsands developments for the wrong reasons, and that more collaboration among supply chain stakeholders within Canada would boost innovation and efficiency in the sector, resulting in more work for domestic producers. What’s at stake is huge, according to a new report from CME, Canada’s largest trade and industry association. The study found Canadian manufacturers are currently capturing around 20 per cent of oilsands capital expenditures. Of that share, two-thirds stayed within Alberta, while 14 per cent went to Ontario-based companies, nine per cent to the other Prairie provinces, six per cent to Quebec, four per cent to British Columbia and one per cent to Atlantic Canada. “Above all else, this data shows the close correlation between oilsands development and its positive impact on both Canadian manufacturing and the economy as a whole,” explains CME president and chief executive officer Jayson Myers. “But it also underscores the ongoing challenges and bottlenecks that threaten the ability of manufacturers outside Alberta to benefit from oilsands expansion. A big one is simply pipeline capacity. Companies won’t invest if they can’t reliably ship out product.” CME estimates nominal capital investment in the oilsands could climb as high
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New discoveries, improved drilling and completion technology, and enhanced recovery drive oil production growth in Saskatchewan going forward
askatchewanâ€™s oil industry has enjoyed a good run the last five years, as new production from tight oil plays augmented existing light production in the southern regions of the province and heavy production from the Lloydminster area. New production records were set in 2013, in some categories surpassing benchmarks established only the year before. The province produced an average 487,400 barrels of oil per day in 2013, up from the previous record of 472,500 barrels per day set in 2012. Saskatchewan also reported record horizontal drilling activity with a total of 2,433 horizontal oil wells drilled in 2013, surpassing the 2,036 horizontal oil wells drilled in 2012. 58
A total of 3,371 oil wells were drilled in 2013, the third-best year ever for oil well drilling. The figure ranks behind only 2011 (3,528 oil wells) and 1997 (3,608 oil wells). And the Saskatchewan government expects the good times to continue, forecasting production of over 513,000 barrels of oil per day in 2014. In January, the Petroleum Services Association of Canada predicted that 3,229 wells will be drilled in the province, an increase of one per cent over its October 2013 forecast. That number is likely to climb going forward. The Lloydminster and the KindersleyKerrobert areas accounted for almost twothirds of all drilling in 2013 as operators targeted the Viking tight oil play and heavy
oil. With Lloydminster heavy oil being the third most profitable play in North America, according to a number of analysts, expect it to remain a preferred target in 2014. The low drilling and completion costs in the Viking mean large numbers of wells will be drilled in the play again in 2014. Drilling will also remain robust in southeastern Saskatchewan in the Bakken and conventional Mississippian plays. And the Shaunavon play will also see development drilling on large pool discoveries from 2012 and 2013. Driving the steady growth in the Saskatchewan industry is a mix of new exploration and discoveries in the southeastern and southwestern parts of the province,
PHOTO: JOEY PODLUBNY
By Darrell Stonehouse, with notes from Daily Oil Bulletin staff
Saskatchewan oil production by play (December 2012) Play Bakken Viking Shaunavon Mannville Mississippian Ratcliffe Total
Production (bbls/d) 90,903 32,680 30,840 177,548 118,096 16,419 466,486
% of total production 19.5 6.8 6.6 38.2 25.3 3.4 99.8
Source: Government of Saskatchewan
Saskatchewan top operators 2013 Husky Energy Inc. Crescent Point Energy Corp. Northern Blizzard Resources Inc. Teine Energy Ltd. Raging River Exploration Inc. Canadian Natural Resources Limited NAL Resources Limited ISH Energy Ltd. Baytex Energy Corp. Penn West Petroleum Ltd. Legacy Oil + Gas Inc. Novus Energy Inc. Beaumont Energy Inc. Polar Star Canadian Oil and Gas, Inc. Home Quarter Resources Ltd. Spur Resources Ltd. Twin Butte Energy Ltd. Renegade Petroleum Ltd. Lightstream Resources Ltd. Whitecap Resources Inc. Rife Resources Ltd. Rock Energy Inc. CanEra Energy Corp. Federated Co-operatives Limited BlackPearl Resources Inc.
Oil 360 399 242 180 160 111 92 88 87 81 75 74 67 64 54 51 46 47 45 47 43 41 39 37 37
Gas -1 -------1 ----1 -----------
Dry 7 5 1 1 ------1 -----3 2 1 --1 1 ---
Service 71 4 7 --2 --1 -------1 -2 -1 1 -1 --
Total 438 409 250 181 160 113 92 88 88 82 76 74 67 64 55 51 50 49 48 47 44 43 40 38 37
Source: Daily Oil Bulletin
Saskatchewan land sales Year 2010 2011 2012 2013
Hectares 453,495 504,395 200,124 111,340
Bonus $462,805,857.62 $248,773,044.49 $104,682,885.05 $67,373,283.05
Average price/hectare $1,020.53 $493.21 $523.09 $605.12 Source: Daily Oil Bulletin
Land sales by region 2012 Average price/ Hectares hectare SE Saskatchewan 57,364 $789.86 Swift Current 19,806 $469.65 Kindersley/Kerrobert 44,963 $439.79 Lloydminster 36,352 $587.04 Region
2013 Average price/ Hectares hectare 33,800 $1,009.94 12,386 $377.91 25,477 $221.79 24,301 $659.65
Bakken 2013 oil wells 1346645 Alberta Ltd. Allstar Energy Limited Barnwell of Canada, Limited Baytex Energy Corp. CanEra Energy Corp. Crescent Point Energy Corp. DeeThree Exploration Ltd. Elkhorn Resources Inc. Epsilon Energy Ltd. Fenway Exploration Ltd. Freehold Royalties Ltd. Husky Energy Inc. Legacy Oil + Gas Inc. Lightstream Resources Ltd. Midale Petroleums Ltd. PetroBakken Energy Ltd. Questerre Energy Corporation Red River Oil Inc. Rife Resources Ltd. Silver Spur Resources Ltd. TriAxon Oil Corp. Tundra Oil & Gas Partnership Villanova Oil Corp. Total
Building out the Bakken
en years into development of the Bakken tight light oil play in southeastern Saskatchewan, operators continue
Total 1 1 1 1 9 211 15 4 1 1 1 8 25 6 1 16 2 17 3 1 2 3 1 331
Source: JuneWarren-Nickle’s Energy Group
Bakken horizontal well production Company Crescent Point Energy Corp. Lightstream Resources Ltd. Tundra Oil & Gas Partnership Legacy Oil + Gas Inc. Husky Energy Inc. CanEra Energy Corp. Williston Hunter Canada Inc. Red River Oil Inc. Penn West Petroleum Ltd. Painted Pony Petroleum Ltd. Cenovus Energy Inc. Questerre Energy Corporation Fort Calgary Resources Ltd. Elkhorn Resources Inc.* Rife Resources Ltd. Aldon Oils Ltd. T. Bird Oil Ltd. High Rock Energy Ltd. Total
Operated wells 1,341 867 541 193 43 58 45 77 72 90 27 56 27 13 19 18 11 11 3,509
Oil (bbls/d) 42,038 14,528 11,820 3,340 2,063 1,323 1,148 1,087 919 894 648 575 450 432 311 180 176 130 82,062
*Now Vermilion Energy Inc.
Source: Daily Oil Bulletin
improved drilling and completion technologies making production more economic, and a rush of enhanced recovery schemes designed to capture huge volumes of previously trapped resources.
Direction Directional Horizontal Vertical -1 ---1 1 --1 ---9 -1 210 --15 --4 --1 ---1 -1 --8 --25 --6 -1 ---16 --2 --17 --3 --1 --2 --3 --1 -4 325 2
pushing its boundaries, adding new lands to the south and east of the heart of the play at Viewfield. With well performance data piling up, optimal drilling and completion techniques to capture as much oil as possible are being finetuned. And experimentation in secondary recovery techniques, like waterfloods, has moved from the pilot phase to commercialization. A large February land sale shows explorers still believe there is untapped potential in the Bakken. Over $47 million was spent in the Estevan-Weyburn area as explorers look
Sources: Scotiabank Playbook; Daily Oil Bulletin; SEDAR
to expand the play along the SaskatchewanU.S. border. “An arm of Bakken development in North Dakota has worked its way up against the international border and is mirrored on the Saskatchewan side with significant drilling activity that is making its way northward, while just 25 kilometres to the northeast of these exploration licences lies the southwest edge of the Viewfield Bakken play,” says Paul Mahnic, director of the Petroleum Tenure Branch of the Government of Saskatchewan. P R O F I L E R M A G A Z I N E . C O M
Manitoba sees drilling slowdown This winter has been a bad one for Manitoba’s tight oil plays. On a year-over-year comparison, drilling declined by 43 per cent in the first quarter of 2014. Producers drilled 127 wells in the quarter versus 222 wells a year ago, while metres drilled decreased to 237,879 from 409,893 last year, according to Daily Oil Bulletin numbers. In January, PSAC announced it is forecasting that 480 wells will be drilled in the province, down from peak drilling of 616 wells in 2012. And in March, Penn West, a major leaseholder in Manitoba, announced it was taking a significant reserve write-down on its assets in its Waskada play. During the quarter, the company recorded non-cash impairment charges of $742 million related to property, plant and equipment and a goodwill writedown of $48 million, Clayton Paradis, manager of investor relations, said at the company’s year-end report to analysts. “These writedowns are related to lower-thanestimated reserve recoveries in Manitoba and limited planned capital allocations in certain natural gas–weighted properties,” he said. “We had a type curve reduction on a per-well basis down into the 40,000 barrel equivalent range in Waskada which was lower than we had carried previously,” added Penn West president and chief executive officer Dave Roberts. The company also increased its well spacing in the Waskada tight oil field in Manitoba as it became “a little bit more educated about the drawdown power of the horizontal wells that we’re putting out there. And so we’ve just reflected the reality of what the reservoir is giving us out there,” Roberts told the call. Waskada reserve bookings occurred before Roberts and the current management took over in mid-2013. In choosing the core areas to focus on, the new management had already decided Waskada wasn’t a focus area. “Having said that, Waskada remains an area—even at 40,000 barrels a well and our ability to drill these wells at close to $1 million now—that still provides outstanding economics,” Roberts said. “We had to recognize the realities, but in no means are we disappointed with the asset in aggregate.” Despite these setbacks, there remain many bright spots in the Manitoba industry, and it appears existing operators are in it for the long haul, while a number of fast-growing new operators are entering the province. Tundra Oil & Gas Partnership is Manitoba’s largest oil producer, exceeding 25,000 barrels per day in southwestern Manitoba and southeastern Saskatchewan. Tundra commenced operations in 1980 and is a wholly owned subsidiary of James Richardson & Sons Limited, a private, family-owned company. Early this year, Tundra announced it was piloting a nitrogen-based EOR program in Manitoba in an effort to capture more reserves in an area
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Manitoba 2013 top operators Tundra Oil & Gas Partnership EOG Resources Canada, Inc. Penn West Petroleum Ltd. Red Beds Resources Limited Corex Resources Ltd. ARC Resources Ltd. Legacy Oil + Gas Inc. Crescent Point Energy Corp. Elcano Exploration Inc. Canadian Natural Resources Limited Fort Calgary Resources Ltd. Corval Energy Ltd. Red River Oil Inc. Interwest Enterprises Ltd. Melita Resources Ltd. Paradise Petroleum Ltd. NAL Resources Limited Kinwest 2008 Energy Inc. Black Gold Energy Ltd. 618555 Saskatchewan Ltd. Other operators Total
Oil 157 102 63 26 24 22 19 19 14 14 12 12 9 5 6 4 3 3 3 3 10 530
Dry 3 ---------1 --2 -------6
Service 1 --------------------1
Total 161 102 63 26 24 22 19 19 14 14 13 12 9 7 6 4 3 3 3 3 10 537
Source: Daily Oil Bulletin
where primary recovery has become Amaranth horizontal well production exhausted. Operated Oil Company Tundra continues to grow and (bbls/d) wells expand, and it currently has an opporEOG Resources Canada Inc. 407 6,336 Penn West Petroleum Ltd. 277 5,475 tunity for an exploitation engineer in Legacy Oil + Gas Inc. 93 1,390 its Calgary office. Red Beds Resources Limited 43 944 Legacy Oil + Gas drilled 44 (34.8 ARC Resources Ltd. 79 784 net) wells in the Spearfish play in Canadian Natural Resources Limited 52 530 Manitoba and North Dakota in 2013. Surge Energy Inc. 22 137 The company used a modified frac Melita Resources Ltd. 4 134 Atikwa Resources Inc. 8 62 fluid on the last two wells in Pierson, 618555 Saskatchewan Ltd. 7 30 Man., which achieved 30-day IPAs of WestMan Exploration Ltd. 6 28 160 barrels equivalent per day per Renegade Petroleum Ltd.* 2 9 well, with average water cuts of 25 per Total 1,000 15,859 cent, representing significant improve*Now Spartan Energy Corp.; estimated as of end of Q3/2013. ments over historical results. Sources: Scotiabank Play Book; Daily Oil Bulletin; SEDAR Legacy plans on spending $60 million total of 60 per cent of all of WestMan’s mineral in the Spearfish in 2014. It is also looking at waterrights, facilities and existing production. flooding to capture more resource from the play. Upon the success of the initial drilling proNew investment dollars are also flowing into gram, NAL expects to grow and maintain proManitoba. Last September NAL Resources duction in the new core area to more than 3,000 Management Limited and WestMan Exploration barrels per day by 2017. Ltd. entered into a farmout and equalization agreement focusing on developing the Spearfish“This is an excellent opportunity to add value and Amaranth light oil play in the Pierson and growth to our company, and we look forward to workWaskada areas of Manitoba. ing with WestMan on this project,” Kevin Stashin, Under the terms of the agreement, NAL will president and chief executive officer of NAL, said. spend up to $17.5 million on drilling activities in Fast-growing Surge Energy also entered two earning phases on WestMan’s southwestern the Manitoba oilpatch in October, spending Manitoba lands (approximately 39,000 net acres $135 million to aquire assets near Manson, of mineral rights) through to Sept. 30, 2014. Man. The company says there are 76 million NAL and WestMan have identified the potenbarrels of oil in place on the properties, with a tial for more than 500 low-cost, multi-well drilling current recovery factor of less than one per cent. locations on WestMan’s existing land base. NAL Surge has identified 24 net drilling locations on has committed $10 million to prove up the play the play, but the real reason for the acquisition and earn a 30 per cent working interest in all was its waterflood potential. mineral rights, facilities and existing production Surge expects to recover at least 13 per cent of WestMan, with an option to spend another of the estimated 76 million barrels in place, or $7.5 million to earn another 30 per cent for a around 10 million barrels.
“Combined with a smattering of Bakken wells in the gap between Viewfield and North Dakota, it’s no wonder these lands attracted significant attention this sale.” “It is also encouraging that these lands were sold as exploration licences with a twoyear term,” he adds. “These disposition-types are drill to earn, which forces accelerated development when compared to five-year leases.” The April land sale, with almost $48 million in bonus bids, indicates explorers believe the boundaries of the Bakken can be expanded even further. Of particular interest in this sale was a cluster of exploration licences between Assiniboia, Sask., and Rockglen, Sask. Drilling in the early 1950s proved the presence of Bakken oil in the area, but the technology did not exist to develop the resource, the government noted. While the western edge of the Viewfield Bakken Sand Pool is 160 kilometres east of the exploration licences that sold south of Assiniboia, there is a smattering of successful Bakken wells between Viewfield and the Roncott area, just a few miles east of the exploration licences that sold in the recent sale, notes Mahnic. “Regarding the zone of interest for these exploration licences, it is reasonable to expect that the Bakken is the main zone of interest, but there is the potential for shallower Mississippian plays in the area, as well as the deeper Red River, and multiple targets always help when determining the economics of drilling a well.” In addition to the oil shows in the Bakken core and oil cut mud recovered from the Bakken in two wells drilled and tested in the 1950s, the area has seen limited exploration activity over the past five years, with a few leases and exploration licences being sold and a couple of exploration wells drilled that tested the Bakken without success. “Just west of these exploration licences is an active special exploratory permit that was acquired in the August 2012 land sale for a work commitment bid, and the ministry has been actively promoting this area at industry trade shows and conferences, so it’s not really a surprise that these lands were requested for this sale,” Mahnic said. The exploration licences are issued for two-year terms and have a drill-to-earn-leases requirement, so the province should know shortly whether the Bakken is commercial with today’s technology. Crescent Point Energy Corp. is one of the key players in expanding the boundaries of
the Bakken, as shown by its Flat Lake play straddling the Saskatchewan, North Dakota and Montana borders. “We’re pretty excited about that play, and it will be a pretty significant production growth area for us,” Neil Smith, Crescent Point’s chief operating officer, told analysts in late 2013. “I think, putting it in context, we were zero production a couple of years ago, and we’re now at almost 5,000 barrels a day in that area. It is about a one-billonbarrel oil pool to us at this stage—multizone Bakken and Three Forks—so it’s very exciting for us.” Smith said the Canadian side of the Flat Lake play is very economic to drill, making it an immediate target for development. Crescent Point had been drilling two-mile-long horizontals at Flat Lake, with as many as 72 fracs per well, on both sides of the border. All-in costs on the Canadian side have come in as low as $4.5 million per well, “versus $9 million to $10 million in North
Flat Lake area, where the company has more than 220 net sections of core-area Torquay land and 400 low-risk Torquay drilling locations on the Canadian side of the border. To date, the company has drilled 36 (35.2 net) horizontal wells targeting the Torquay Formation, growing net production from zero to approximately 5,100 barrels equivalent per day in just 12 months. “We’re very excited about the results we’ve seen in the Torquay so far,” Crescent Point’s president and chief executive officer Scott Saxberg said in a statement. “These are high rate-of-return wells at low capital costs relative to North Dakota that complement the Bakken production from our core Flat Lake area. To put it in context, this play has the potential to be the equivalent size of our Viewfield Bakken play.” In 2013, the company added proved-plusprobable reserves of 11.2 million barrels equivalent at Flat Lake in the Torquay and Bakken formations combined.
“We’re very excited about the results we’ve seen in the Torquay so far. These are high rate-of-return wells at low capital costs relative to North Dakota that complement the Bakken production from our core Flat Lake area. To put it in context, this play has the potential to be the equivalent size of our Viewfield Bakken play.” — Scott Saxberg, president and chief executive officer, Crescent Point Energy Corp.
Dakota, literally a mile away across the border,” said Smith. But the economic story gets better. “We’ve actually switched back to one-mile horizontals because of the royalty holiday and the depth related to that,” said Smith. “We get a bigger royalty holiday per well on the mile horizontals, and the economics are much better because of it. We have a huge advantage because of that in that area. We are very excited about that play and the development of that play, and we’re building a gas plant, building our infrastructure there, and we’ll expand the capital program.” In April, Crescent Point announced it had made a significant Torquay discovery in its core Flat Lake area of southeastern Saskatchewan, which is an extension of its Three Forks resource play in North Dakota. Over the past 12 months, Crescent Point has delineated the Torquay discovery in the
At year-end 2013, the company’s independ ent reserve engineers booked estimated ultimate recoveries on producing Torquay wells as high as 275,000 barrels per mile-long well. Crescent Point’s internal 275,000 barrels per mile-long type well, which has a $3.35-million capital cost, generates rates of return of approximately 300 per cent and payouts of approximately seven months. In 2014, Crescent Point expects to spend approximately $200 million of its 2014 budget in Flat Lake, including drilling approximately 48 net wells. In addition to its core Flat Lake Torquay land position, over the past 18 months Crescent Point has continued to accumulate a significant exploratory land position of more than 400 net sections in the southern part of southeastern Saskatchewan, targeting the Torquay and Bakken formations. These lands are in addition to the delineated core-area lands.
P R O F I L E R M A G A Z I N E . C O M
The company has drilled six wells testing the Torquay zone on these exploratory lands to date and has plans to drill five more wells over the coming six months. In late April, it added to this Torquay base with the $1.1-billion takeover of CanEra Energy Corp. CanEra has 260 sections of land prospective for the Torquay, along with 10,000 barrels per day of production.
improVEd complEtionS tEcHnologiES cutting dEclinES, improVing rEcoVEry in bakkEn
t its Viewfield Bakken play, Crescent Point remains focused on fine-tuning its completions technology. The company has been using cemented liners with 25 fracturing stages exclusively in the play for the last year with excellent results, said Smith. “About three years ago, we moved from the packer system to cemented liners,” Smith explained. “Basically what it does is allow you more precision as to where you place the frac. And it allows you to go back into wells and do as many fracs as you want. So we started out with eight stages with a cemented liner and then we went to 16-stage cemented liner, then to 20, then to 25. We adjusted the amount of sand, the amount of water used, and did the correlation between productivity and reserves and cost. And we’ve seen a tremendous uptick in that. “Also what has occurred, which we didn’t actually really expect, was that we got higher IPs [initial production rates] and lower declines because we are opening up more 62
rock,” he added. “And opening up more rock opens up more matrix porosity within the rock, which then allows more oil to flow and flow at lower pressure change, which then allows for the flattening of the production curves. We’ve seen that across all of the plays that we’ve implemented this in. And to give you an example, I think the math on the Bakken is something like after 12 months instead of 50 barrels a day, it’s at 100 barrels a day. It’s a pretty tremendous outperformance relative to the older 16-stage completion technique.” Smith said he believes the cemented liner system works better because it has fewer failed frac stages. “A lot of it is simply that in the 16-stage packer system technique, you maybe got 10–12 of the fracs that worked. So what we see is that there is a low percentage of fracs that work in that kind of methodology, and you wind up refracking the same frac in that case. And so you don’t get the good productivity,” he explained. The cemented liner completions technology has also cut costs, largely due to less water handling, says Crescent Point chief financial officer Greg Tisdale. “When you complete a well, just to give you a simple example, instead of using 2,000 cubes [cubic metres] of water, we use 1,000 cubes. So there is less tank storage, less power to pump that fluid in. Then, when you flow it back, you’re disposing of less water. All of that goes into your capital cost.” Tisdale says the cemented liner completions save about $100,000 per well on waterhandling costs.
EnHancEd rEcoVEry Slowly puSHing ultimatE rEcoVEry HigHEr in tHE bakkEn
aterfloods are nothing new in Saskatchewan. At last count, there were more than 200 schemes active in the province. What is new is the application of waterfloods in tight oil plays where horizontal wells with multistage fracturing have been used on primary production. Peters & Co. Limited analysts outlined waterflooding’s value in tight oil plays in a 17-page Waterflood Primer published in fall 2013. The analysts said a successful flood could increase recovery to between 30 and 45 per cent of the original oil in place, up from between five and 15 per cent on primary production. Peters & Co. said the average increase in oil recovery from waterflooding is about 30 per cent.
PHOTO: PIPELINE NEWS
Improved drilling and completions technologies are adding reserves in the Bakken.
“Our completion guides are really focused in on reducing the amount of fluid,” he adds, pointing out that often in the industry you hear about operators doubling their fluid, doubling their sand, doubling everything— and so their costs are going up. “We’re trying to look at it from the opposite direction and mitigate costs and reduce costs but get better performance. That’s what we’ve seen. And so, we’re pretty excited about that side of it. There [are] further ways to reduce those costs. So that’s really over the last year to two years what’s happened is any of the inflationary costs that you would have seen in capital programs, we’ve mitigated just by changing and optimizing our completion technique.” Legacy Oil + Gas Inc. is also a believer in cemented liners, company president and chief executive officer Trent yanko said in late March. “Over three and a half years ago, we started using cemented liners in the Bakken,” he said. “We recognized the potential of the improvement in being able to control the frac, how those fracs initiate and the profile of them back at that time. We have moved to cemented liners, using them in the Three Forks, Spearfish, Bakken and in a lot of our different areas, and we have been at the forefront of that.” “Also, we have been at the forefront of using slower pumping rates and less tonnage,” he added. “Three-and-a-half to four years ago, we recognized that as a potential for cost savings, but also a performance enhancer in these plays.”
PHOTO: PIPELINE NEWS
And adding those reserves comes on the cheap, Peters & Co. said. Average costs come in at $5–$10 per barrel as most wells and surface facilities are already in place in existing fields. All that is usually needed are injection, pumping and treatment facilities. In tight oil plays like the Bakken, with billions of barrels of oil in place, waterflood recoveries could amount to hundreds of millions of barrels, something not lost on Crescent Point. “We now have waterflood programs or pilots in all of our plays,” Smith told analysts late last year. In the Bakken, Crescent Point recently completed two studies looking at potential recoveries through waterfloods. “We’ve had two kinds of indications that we are going to see in reserves, a true waterflood, reserve assignment,” he said. “Number one was a lot of the simulation work that we’ve done previously indicating a 30 per cent–plus type of recovery factor beyond the 17–19 per cent from primary recovery. The other thing is I wanted to get some old-school type of waterflood classic analyses using some of the classic material balance techniques. So we brought in an expert from our independent engineers just to confirm a lot of the work that we did. This is a guy that’s got 30, 40 years’ engineering experience. He’s gone through, and his confirmation in areas where we had enough history of waterfloods is that, yeah, we should be seeing north of 30 per cent recovery factor.” “Everything that we’ve done during the last three, four years is showing that this is a pool that is going to be waterfloodable with strong economic returns,” he added. “And it’s really exciting. We haven’t seen this type of development probably as engineers in a generation.” Smith, however, cautioned that reserve evaluator recognition of this increase in recovery factor won’t happen overnight. Instead, as the company drills more wells, adds more injectors and gets more production history on its floods, reserve evaluators will recognize the increased recovery. He expects it will go up a few percentage points each year. “you’re not going to see us go from 19 per cent [primary recovery] to 30 per cent in one year,” he explained. What’s the size of the prize? “I think to put it into scale, when we say over 30 per cent recovery, we’re talking hundreds of millions of barrels of incremental reserve outs with very minimal capital cost associated with that,” said Saxberg.
The expanding Bakken play promises work for service and supply companies.
rEViSiting old playS in SoutHEaStErn SaSkatcHEwan
hile the Bakken has got all the headlines in southeastern Saskatchewan in recent years, conventional oil targets are also gaining in interest as operators apply new drilling and completions technologies to those plays. Mississippian conventional development accounted for over 118,000 barrels per day of production in 2012, more than its more famous neighbour, the Bakken, which produced around 91,000 barrels per day. Much of the play is under low decline rate enhanced recovery technologies, but explorers continue finding new pools and new methods to extract additional resources. Legacy Oil + Gas has been a leader in this effort, starting in the Midale play. “Midale has been a big performer for us right across the board. We saw very good reserve additions in the Midale in 2013,” says yanko. “This is a play that basically didn’t exist—the multistage frac Midale play—three years ago. We applied our technology and our knowledge base from our other plays, went into this area in Pinto and then to Steelman back to Taylorton, with new pool discoveries at Pinto East, Alameda South and beyond. So we’re not just extending existing pools, we are finding new pools. We are cumulating more land that we picked up some 3-D seismic on, and we have changed our well count here quite dramatically.”
yanko said Legacy now has a drilling inventory of over 335 Midale locations. It drilled 33 (28.8 net) wells in 2013 into the Midale, which included several step-out and delineation wells over a wide area. Legacy also drilled 29 (24.8 net) conventional wells in southeastern Saskatchewan in the Tilston, Souris, Alida and Frobisher zones, where it has around 330 drilling locations. And it drilled six (5.4 net) wells at Frys and Antler in the Torquay Formation, where it has identifi ed 116 drilling locations. Vermilion Energy Inc. recently joined Legacy in targeted conventional opportunities in southeastern Saskatchewan with its takeover of private oil company Elkhorn Resources Inc. in March. Elkhorn’s assets included approximately 57,000 net acres of land and 3,750 barrels of oil per day of production during 2014. The assets are located in the Northgate area. “We have currently identified approximately 175 (152 net) potential drilling locations targeting the Midale, Frobisher, Bakken, and Three Forks/Torquay formations,” the company said in making the purchase. “We have been evaluating prod ucing entry opportunities into this prolific area for an extended period of time but had not previously been able to structure a transaction that met the stringent requirements of our dividend growth model. Specifically, the assets exhibit PROFILERMAGAZINE.COM
Viking oil wells 2013 (Both Saskatchewan & Alberta) Operator 3 Martini Ventures Inc. Anegada Energy Corp. Apache Canada Ltd. Beaumont Energy Inc. Bonavista Energy Corporation Canadian Oil & Gas International Inc. Canuck North Resources Ltd. Cardinal Energy Ltd. Crescent Point Energy Corp. Devon Canada Corporation Encana Corporation Flagstone Energy Inc. Fort Calgary Resources Ltd. Home Quarter Resources Ltd. Husky Energy Inc. Indepth Energy Inc. Invicta Energy Corp. ISH Energy Ltd. Long Run Exploration Ltd. Mancal Energy Inc. Mosaic Energy Ltd. Muirfield Resources Ltd. NAL Resources Limited Novus Energy Inc. OMERS Energy Inc. Penn West Petroleum Ltd. Polar Star Canadian Oil and Gas, Inc. Raging River Exploration Inc. Renegade Petroleum Ltd. Rock Energy Inc. Sekur Energy Management Corp. Spur Resources Ltd. Spyglass Resources Corp. Sun Century Petroleum Corporation Tamarack Acquisition Corp. Tamarack Valley Energy Ltd. Teine Energy Ltd. Westdrum Energy Ltd. Whitecap Resources Inc. Total
Directional --------------1 -1 1 ---------1 ----------1 5
Direction Horizontal Vertical 1 -2 -22 -67 1 15 -1 -3 -3 -40 -5 -4 -6 -1 -53 -49 -1 -9 -86 -60 -7 -6 -3 -81 -77 -1 -75 -66 -166 -32 -10 -4 -44 1 5 -1 -5 -3 -178 -1 -42 -1,235 2
Total 1 2 22 68 15 1 3 3 40 5 4 6 1 53 50 1 10 87 60 7 6 3 81 77 1 75 66 167 32 10 4 45 5 1 5 3 178 1 43 1,242
Source: Daily Oil Bulletin
the three hallmark characteristics of our sustainable growth-and-income model: high margins, low base decline rates and strong capital investment efficiencies on future development.” The Elkhorn assets are geographically complementary to lands Vermilion has been leasing that target Mississippian development in southwestern Manitoba.
Turning the Viking into a pin cushion
he Viking oil play centred around Dodsland in southwestern Saskatchewan is the most active play in the province, based on the number of wells drilled. With low costs to drill, complete and tie in new wells, expect that to continue in 2014. Private company Teine Energy Ltd. is a dominant operator in the Dodsland Viking 64
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play. Teine has more than 500 net sections of land in the Viking, with 170 sections prospective for oil. It has identified 2,700 drilling locations in the play, after having drilled 400 horizontal wells. Teine expects to spend around $260 million in the Viking in 2014 and exit the year with 15,000 barrels per day of production. Raging River Exploration Inc. is also solely focused on the Saskatchewan Viking. At yearend 2014, Raging River reported Viking production of around 9,000 barrels per day, up from 4,000 barrels the previous year. Over the year, it spent $272.5 million in total, including $168.1 million on development activities and $104.4 million on property acquisitions. Raging River drilled 209 (172.5 net) horizontal Viking wells at a 100 per cent success rate. Total net land holdings increased 50 per cent to 164,000 acres in the Dodsland area. During 2013, Raging River invested $272.5 million including $155.3 million on
Viking 2013 horizontal oil production Company Teine Energy Ltd. Penn West Petroleum Ltd. Whitecap Resources Inc. Raging River Exploration Inc. Long Run Exploration Ltd. Novus Energy Inc.* Crescent Point Energy Corp. Renegade Petroleum Ltd.** NAL Resources Limited Husky Energy Inc. Mancal Energy Inc. Polar Star Oil and Gas Inc. Devon NEC Corporation Home Quarter Resources Ltd. ISH Energy Ltd. Baytex Energy Corp. Tamarack Valley Energy Ltd. Apache Canada Ltd. Total
Operated Oil (bbls/d) wells 329 5,379 275 4,574 199 3,929 154 3,697 165 3,414 182 2,975 198 2,337 137 2,332 104 2,169 143 2,156 55 1,514 73 1,240 43 1,101 44 963 70 889 35 850 42 800 34 695 2,282 41,014
*Taken over by Yanchang Petroleum International Limited. **Now Spartan Energy Corp. Sources: Scotiabank Playbook; Daily Oil Bulletin; SEDAR
drilling and completions, $104.4 million on property acquisitions, $8.5 million on production facilities, and $265,000 on geological and geophysical costs. This year looks like a repeat of the last. In March, Raging River raised its 2014 capital budget to $235 million from $215 million as a result of continued strong production and an additional 12-well commitment associated with a Viking farm-in with another producer. This results in increased 2014 average production guidance to 9,800 barrels per day from 9,500 barrels per day and an increase to the company’s exit guidance rate to 11,700 from 11,000 barrels per day. During the first quarter of 2014, Raging River drilled 75 (65.7 net) wells resulting in 72 (62.7 net) Viking horizontal oil wells, and 28 (26 net) undrilled sections were tested. As at Dec. 31, 2013, Raging River had tested 106 of 215 net sections of prospective land. As of March 15, that has expanded to 132 net tested sections with the intention to test at least another 35 sections by year-end. The company has identified more than 2,200 horizontal drilling locations, not counting the recent farm-in lands. Penn West Petroleum Ltd. is one of the pion eers of the Viking play. After reorganizing itself in late 2013, the company plans on continuing its investment in the play. Penn West plans on spending $150 million drilling 104 horizontal wells in 2014. It drilled 59 wells in 2013. The company has seen drilling and completion costs decline from around $1.1 million
per well in 2011 to around $800,000 per well in 2013. By 2018, it expects to be producing 10,000 barrels per day from the Viking. Mark Fitzgerald, senior vice-president of development for Penn West, told the Daily Oil Bulletin last summer that the company believes the Viking is one of the best resource plays in western Canada. “We very consistently characterize the Viking as one of the four core resource plays that we have,” he said. “It has great netbacks, it’s very economic, it’s highly predictable for us, and it is an area that we anticipate we will continue to develop and continue to drill.” Fitzgerald said that his company has been involved in the Viking for several years, growing that investment with the Petrofund Energy Trust merger and the acquisition of Canetic Resources Trust. “The economics and the deliverability, and I guess, ultimately, the estimated ultimate recovery associated per well has changed dramatically, and of course, that has changed the attractiveness and the economics across the whole play,” Fitzgerald said. “We’ve seen people move from a maximum of eight wells per section to testing 16 wells per section, which again is increasing potential recoveries across the area,” he added. Along with increasing its number of wells per section, Fitzgerald said, Penn West also sees further development of waterflooding as critical for the company’s long-term growth in the formation. In the Viking, Fitzgerald said, there is always the opportunity for greater production efficiency, which has been happening more and more with such techniques as high use of the immiscible production nitrogen in the company’s completion procedures. He said it might cost a bit more, but it also results in more output from the wells. “I also think there is a real opportunity over time to optimize just the entire producing area of the Viking. It is lower pressure, it’s sensitive to gathering system pressures and back pressures on the wells, and I think for us, part of the opportunity continues to be in reducing pressures across the system in order to maximize the ability of these wells to deliver,” he said. While other formations along the western portion of Saskatchewan tend to produce a bit heavier oil, Fitzgerald said the Viking is a bit lighter, which results in higher netbacks, making it “the play to be in” for that region. Private producer Beaumont Energy Inc. has jumped right into enhanced recovery on its Viking properties.
Beaumont Energy has implemented a large waterflood with 38 water injection wells and four horizontal producers over five sections of land in the Viking play at Kerrobert. Its Kerrobert asset, purchased in 2012, includes about 1,000 vertical wells and associated facilities. While some might see 1,000 vertical wells as an abandonment liability, Beaumont Energy’s president and chief executive officer Bob Chaisson and his team saw opportunity. The plan from the outset was to do a waterflood. So with 1,000 vertical wells already
perforated and fracture-stimulated in the Viking, Beaumont Energy won’t have to drill any water injectors for a long time. The other big attraction for privately held Beaumont Energy was that a waterflood with 80 vertical wells had operated on 3.5 sections of the property from roughly 1986 to 1999, when water injection ended, and the area reverted back to primary production. “So we got 27 years of data to look at to see how that waterflood performed in there. And when we looked at that, we knew right away that the waterflood had worked,” said
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Chaisson. The Viking at Dodsland, just south of Kerrobert, has been waterflooded for nearly half a century. “So that was why we bought the Kerrobert property—because we knew you could waterflood it.” Currently Beaumont Energy is converting eight wells per section to water injection, but it can do more if necessary. Chaisson said there are at least 16 vertical wells on nearly every section, and some sections have about 30. Beaumont Energy drills a horizontal producer down the middle of the injection lines on each section. The company has already drilled four horizontal producers in the old waterflood area, which it expanded to five sections from the original 3.5 sections. The company is monitoring the performance of these wells. The goal is to waterflood another eight sections in 2014, and then do between eight and 10 sections per year. The plan is to start injecting water one year before the horizontal producers are drilled, giving the reservoir time to re-pressurize. Given that Beaumont has more than 70 sections at Kerrobert, this project will keep the company busy for a long time. Chaisson said it costs $1 million per section to convert eight vertical wells to water injection and to install new water injection pipelines. It costs about $900,000 to drill, complete and equip the horizontal wells. The big prize is in boosting ultimate recoveries. The recovery factor on primary production is only about five per cent, but Beaumont Energy believes waterflooding can raise it to about 20 per cent, based on the performance of nearby Viking pools that have been waterflooded for decades. With original oil in place of 600 million barrels, a 20 per cent recovery factor equates to 120 million barrels of sweet light crude, of which only 20 million have been produced. “We’ve got 100 million barrels left to get out of this thing,” Chaisson said.
Still finding oil in the Shaunavon
rescent Point has long dominated the Shaunavon oil play in southwestern Saskatchewan, controlling as much as 90 per cent of the acreage in the play. But it now has company after Surge Energy Inc. entered the play after buying assets from Cenovus Energy Inc. In early 2014, Surge reported exploration success in the Upper Shaunavon horizon, drilling a new pool discovery at 16-36-005-20W3. 66
J une 2 0 1 4
The horizontal well encountered 1,175 metres of reservoir section and was completed with 21 frac stages. This discovery well is currently producing over 300 barrels of oil per day. The success of this well confirms Surge’s 3-D seismic interpretation of the Upper Shaunavon interval over its lands. Surge now maps over 125 million barrels of oil in place in the Upper Shaunavon Formation, with the potential for more than 64 additional drilling locations (four wells per section). Surge also successfully drilled four (three net) Lower Shaunavon wells in southwestern Saskatchewan, during the first quarter
In 2013, Crescent Point had a record year of activity in the Upper Shaunavon resource play, drilling 26.5 net Upper Shaunavon horizontal wells. It plans to drill 27 net horizontal wells in the Upper Shaunavon resource play in 2014. The company plans to apply techniques developed in the Viewfield Bakken resource play to the Shaunavon resource play drilling program, including using 25-stage cemented liner completions with lower tonnage on each drill. The company has more than 1,800 locations remaining in the play. Crescent Point had its most active quarter for waterflood activity in the Lower Shaunavon
Lower Shaunavon 2013 oil wells Operator Crescent Point Energy Corp. Federated Co-operatives Limited Fire Sky Energy Inc. Husky Energy Inc. Jarrod Oils Ltd. Red River Oil Inc. Surge Energy Inc. Taku Gas Limited Total
Direction Directional Horizontal Vertical -49 --8 ---2 1 9 -2 -2 -1 --2 ---2 3 69 6
Total 49 8 2 10 4 1 2 2 78
Source: Daily Oil Bulletin
Lower Shaunavon 2013 horizontal oil production Company Crescent Point Energy Corp. Surge Energy Inc. Husky Energy Inc. Federated Co-operatives Limited ARC Resources Ltd. Grizzly Resources Ltd. Ki Exploration Inc. Regent Resources Ltd. TSO Energy Corporation Spyglass Resources Corp. Total
Operated wells 558 139 21 6 3 1 1 1 2 1 733
Oil (bbls/d) 13,014 3,538 487 87 78 22 18 12 9 3 17,268
Sources: Scotiabank Playbook; Daily Oil Bulletin; SEDAR
of 2014, with excellent type curve results. In addition, the company has observed significant re-pressuring of the Lower Shaunavon Formation on both of the company’s four- and eight-well-per-section waterflood pilots, as a result of the injection started in the fourth quarter of 2013. Production from wells that had been shut in (in order to re-pressure the reservoir) was restarted at the end of March. Surge maps over 220 million barrels of original oil in place in the Lower Shaunavon Formation, with a 1.96 per cent recovery factor to date. Surge has over 215 net Lower Shaunavon drilling locations in southwestern Saskatchewan and full waterflood upside. Not to be outdone, Crescent Point is continuing its development in the play at full-throttle.
resource play during the fourth quarter of 2013, converting a total of seven producing wells into water injection wells. In total, the company currently has eight water injection wells operating in the Leitchville North Shaunavon voluntary unit #1 and 10 water injection wells operating in the second development area, all in the Lower Shaunavon zone. Current waterflood-affected production in the first unit is more than 2,600 barrels per day and waterflood-affected production in the second development area is more than 600 barrels per day. Crescent Point plans to double the number of water injection wells in the play by year-end 2014, as the company continues to be pleased with production performance in both its Lower and Upper Shaunavon waterflood projects.
HEaVy oil tHE baSE oF SaSkatcHEwan production
combination of low finding and development costs, low operating costs and favourable pricing has made conventional heavy oil production a cash flow– generating machine for Saskatchewan producers for the last three years. Operators expect the good times to continue in 2014 as improving pipeline access and more refinery capacity support tighter heavy oil to West Texas Intermediate differentials going forward. Just how profitable is conventional heavy oil production? In Peters & Co.’s September 2013, ranking of North American resource plays, vertical heavy oil wells at Lloydminster, on the Alberta-Saskatchewan border, were the third most profitable play, providing a 125 per cent rate of return. Horizontal wells at Lloydminster ranked seventh of 45 plays, providing an over 100 per cent rate of return. Saskatchewan produced 258,000 barrels per day of heavy oil in 2013, more than half of its total production. But how that oil is being produced is undergoing a significant change, Baytex Energy Corp. chief financial officer Derek Aylesworth said at a conference in November. Aylesworth said that, while vertical wells still drive production in the area, horizontal drilling is gaining a foothold as technology improves. “A vertical well in the Lloydminster area quite often intercepts multiple pay zones. you produce the most prolific zone first,
plug it, and then move to the next zone and recomplete it. Those recompletions add production reserves at very, very low costs. Finding and development costs in the Lloyd area using vertical development are about $11.25 per barrel,” he said. “We’ve just started to branch out and use horizontal development in the Lloydminster area,” he added. “The Lloydminster area historically wasn’t thought to be very conducive for horizontal because a lot of the pay zones are quite thin. With the improvements in horizontal drilling technologies, we now can place horizontal wells in an area as thin as a two-metre pay zone, and we’ve been able to do that quite successfully. We’re adding reserves there at about $13.50 per barrel and about $12,000 of fl owing day barrel.” Husky Energy Inc. is also increasingly using horizontal wells to target thinner pay zones. Husky chief operating officer Robert Peabody said at the company’s 2014 capital spending presentation that the company plans on drilling 140 horizontal cold production wells this year. “Cold horizontal production is expected to exceed 10,000 barrels per day,” he added. In unconventional shale reservoirs, drilling horizontal wells cost millions of dollars. But because the Lloydminster heavy oil fields are shallow and horizontal legs average only around 500 metres, costs are much cheaper. This allows smaller companies to use the technology effectively. An example of this is Twin Butte Energy Ltd. Twin Butte has amassed a horizontal drilling inventory of more than 100 heavy oil
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targets in the Lloydminster area. It reports costs of around $950,000 to drill, complete and tie-in each horizontal well. Initial well production for the first 90 days comes in at 80 barrels per day, with expected ultimate recovery of 80,000 barrels. The average cost of adding a barrel of reserves comes in at $11.88 per barrel.
EnHancEd rEcoVEry puSHing HEaVy oil production
usky is also focused on advancing its steam-driven plays in Saskatchewan’s heavy oil playground. “Thermal production has emerged as the central driver behind our expected steady growth in heavy oil production in 2014 and beyond,” Peabody said, adding that the reason for this is it is more profitable than thermal oilsands production. “year-to-date operating costs from all our heavy oil thermal projects now on production are a little under $10 a barrel,” Peabody said, referring to 2013 numbers. “Combine that with low finding and development costs in the $10–$15-per-barrel range and a premium product price about $10 per barrel more than you’d get for a typical Fort McMurray bitumen barrel, and you can see why these projects generate very strong returns.” Husky is producing 37,000 barrels per day from its thermal operations in the Lloydminster region and is on track to grow this production by another 50 per cent to 55,000 barrels per day by 2017.
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Service & Supply
Waiting for the light to change
By Darrell Stonehouse, with notes from Daily Oil Bulletin staff
he arrival of horizontal drilling and multiÂstage fracturing technologies has transformed western Canadaâ€™s oilfield service industry in the last half-decade. The drilling fleet has been repurposed as older rigs, designed to target shallow gas wells or deeper vertical wells, have been scrapped in favour of new fitfor-purpose units capable of drilling extended-reach horizontal wells and moving quickly on multi-well pads. The horizontal well count has climbed from 2,431 wells in 2009 to 7,728 wells in 2013, according to the Daily Oil Bulletin. Well servicing outfits have upped pressure-pumping horsepower tremendously to meet the demands for massive, high-volume fracture stimulations. New tools have been deÂveloped to allow increasing numbers of fracture stages to be completed efficiently and effectively along horizontal well bores with as many as 60 stages now being completed along a single horizontal leg.
Photo: joey podlubny
Light oil the focus of service and supply sector until LNG projects get green lit or shale oil exploration pays off
A host of other suppliers, ranging from frac sand and proppant suppliers to water treatment suppliers, have been in rapid growth mode to accommodate operator demand. Production companies have also benefited from the technology boom as low gas prices
“There is no question that the Western Canadian Sedimentary Basin is turning over to long-reach horizontal drilling, and there is an overcapacity of shallow and mid-sized rigs and undercapacity of deeper rigs.” — Bob Geddes, president and chief operating officer, Ensign Energy Services Inc.
have led to operators focusing on tight oil projects. Oil well drilling in western Canada has climbed from a low of 3,219 wells in 2009 to 8,117 wells completed in 2013, according to Daily Oil Bulletin statistics. The increase in wells targeting natural gas liquids is also setting off a boom in midstream construction as operators look to separate out liquids to maximize returns. As new technologies have come on stream and operators have gained experience drilling and fracturing wells, productivity has been on the rise. Members of the Canadian Association of Oilwell Drilling Contractors (CAODC) reported 102,469 operating days in 2013, down eight per cent from 2012 numbers. Yet, in that time period, they managed to drill 22.56 million metres, up from 21.71 million metres the previous year. It took CAODC members an average 9.2 days to drill a well during the 12-month period compared to 10.2 days in 2012. Fracking crews have also become much more efficient. The use of limited slickwater fracs in the Montney play has cut completions costs by 22 per cent for Encana Corporation,
while upping initial, unrestrained production by as much as 50 per cent. In the Bakken play, the use of cemented liners and 25 stage fracs has cut completion costs by as much as $400,000 per well for Crescent Point Energy Corp. The massive build-out of new technologies and resulting improvements in drilling and completions efficiencies, however, hasn’t been all good news. Service companies are now facing an oversupply problem across western Canada, resulting in stagnant or declining prices in the short term. But in the longer term, continued tight oil development and the potential drilling rampup leading to liquefied natural gas (LNG) exports could quickly return the sector to growth mode. And with shale oil development possible on the immediate horizon in the Duvernay and the Muskwa formations, things could change in a hurry.
Oversupply leads to stagnant drilling day rates, but fleet turnover continues Western Canada’s drilling contractors continue repurposing their drilling fleets, while working through a flat drilling market. Shallow and mid-size rig heavy Ensign Energy Services Inc. reported decreased revenue and earnings in 2013 as it continued to transition its fleet to meet industry’s demand for larger, next generation horizontal rigs. The company said that financial results were also affected by overall reduced demand for North American oilfield services in 2013 when compared to 2012. Although Ensign generated the second highest revenue in its history ($2.1 billion for the year ended Dec. 31, 2013), it was down five per cent from $2.2 billion recorded in the prior year. Fourth-quarter revenue was essentially flat at $536.04 million for 2013 versus $530.11 million in the same quarter the year prior. Bob Geddes, president and chief operating officer of Ensign, told a conference call that the company’s current and future build programs will focus on transitioning the fleet to meet the growing demand. “There is no question that the Western Canadian Sedimentary Basin [WCSB] is turning over to long-reach horizontal drilling, and
there is an overcapacity of shallow and midsized rigs and undercapacity of deeper rigs,” he said. “Understanding this shift, the Ensign fleet in Canada, which has been over-weighted in the shallow/mid category, is transitioning its 120-rig fleet to a mid-to-deep focus.” In 2013, Ensign added two new automated drill rigs (ADRs) to its fleet. Ensign has decommissioned 15 shallow Canadian rigs this winter, and its build program will deliver 12 new state-of-the-art drilling rigs this year. Four will be deployed in Canada, six in the United States and two in the company’s international segment. Geddes said the company continues to build new ADRs and upgrade existing drilling rigs to meet the increasing technical demands of its customers. “In Canada, Ensign is continuing to transition from shallow drilling to deeper drilling, building new ADRs and upgrading existing drilling rigs for deeper resource plays in the northwest part of the WCSB,” he said. Ensign recorded revenue of $661.01 million in Canada for the year ended Dec. 31, 2013, a 15 per cent decrease from $774.44 million recorded in 2012. Unfavourable price differentials for Canadian commodities and continued industry uncertainty weakened demand for the company’s Canadian oilfield services in 2013 compared to 2012. Canadian drilling recorded 14,183 oper ating days in 2013, a 23 per cent decrease from 18,398 operating days in the previous year. Canadian well servicing hours decreased by 14 per cent in the year ended Dec. 31, 2013, from the prior year. CanElson Drilling Inc., like Ensign, is expanding its new rig build in the face of a flat marketplace. In March, it increased its capital budget from $52.4 million to $95.5 million, counting the new builds as well as $20.1 million in capital spending being carried forward to this year from last. CanElson reported declining earnings in 2013, due to “subdued North American land drilling markets, resulting in lower industry land drilling activity,” the company said in its fourth-quarter report. In turn, lower activity put pressure on the company’s drilling rig revenue rates, management said. In 2013, CanElson’s Canadian utilization rate was 53 per cent, or 1.2 times the industry average (2012: 1.3). P R O F I L E R M A G A Z I N E . C O M
CANADIAN DRILLING STATISTICS (2012-13) 2012 Number of drilling rigs
Number of wells drilled
Average days per well
Metres drilled (thousands)
Average metres per well
Rig operating days Rig utilization
Average metres per day Rig revenue/utilization per day
WCSB HORIZONTAL WELL COUNT Year 2009 2010 2011 2012 2013
Alberta 1,135 2,515 3,980 4,172 4,271
Saskatchewan 806 1,532 1,999 2,029 2,430
British Columbia 278 535 535 444 527
Manitoba 202 531 531 567 497
Source: Daily Oil Bulletin
Source: Precision Drilling Corporation
As for the company’s expanded 2014 capital program, it will include two additional rig builds, an AC telescoping double rig, and a new innovative and proprietary AC triple drilling rig, the company said. Of this year’s $95.5-million budget, management provided a rough breakdown of spending. Roughly $51.6 million is allocated to the completion of two rigs (#44 and #103) and the construction of two additional telescoping double rigs (#45 and #49). About $15.5 million will go to the construction of rig #104, which is designed as an innovative and proprietary AC triple capable of moving quickly and being rigged up without using cranes. Also part of the budget, roughly $26.1 million will go to equipment upgrades, spares, maintenance capital and shop upgrades, the company said, while some $2.3 million is allocated to various compressed natural gas– related projects for CanGas Solutions Inc. In the fourth quarter, CanElson bought Highkelly Drilling Ltd., a private Canadian drilling company, for $44.1 million, resulting in the ownership of two new AC triple drilling rigs operating in the Montney natural gas liquids–rich resource play in northeastern British Columbia, as well as a third identical drilling rig that is under construction, management said. Precision Drilling Corporation also boosted this year’s capital budget up to $634 million from $515 million announced earlier this year. Of the total $634 million, management expects $597 million to go to the company’s contract drilling division and $37 million to go to its completion and production services business. Before the increase, $478 million had been destined for contract drilling, while the amount for completion and production services was the same. Precision’s expansion capital plan includes the completion of 12 new-build drilling rigs, 72
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11 of which were previously announced. This year, the company plans to deliver six newbuild rigs to Canada, two new-builds to the United States, three to international sites and one that will only be completed when a firm contract is in hand. Additional expansion capital will go to equipment for completion and production services and long-lead items, management said. Having termed Canada the “most challenged” of the drilling markets in which they operate, Nabors Industries Ltd. executives cited the potential that proposed LNG developments in British Columbia hold for the future. “There are a number of potential projects targeting Canadian natural gas liquids that continue to generate interest in the northwest part of the Western Canadian Sedimentary Basin,” Anthony Petrello, Nabors’ chair, pres ident and chief executive officer, told invest ors in a conference call, citing the Montney and Duvernay plays in particular, but also the Horn River Basin, as likely beneficiaries of future LNG development. At the same time, Nabors executives acknowledged that the Canadian drilling segment remains among the company’s most challenged, in terms of return on investment. “Profit margins fell to $11,478 in 2013 from $14,389 per rig per day in 2012,” Petrello said. “We remain optimistic that large-scale LNG developments will pull through rig demand, although I will caution you that timing is uncertain, and our thinking is 2015 at the earliest.” The company’s Canadian drilling division posted 32.5 rig years in the fourth quarter, down from 36.3 rig years in the 2012 period, while 2013 saw Nabors’ Canadian branch record 29.9 rig years, down from 34.8 rig years in 2012 (one rig operating 182.5 days in a 365-day year represents 0.5 rig years).
Price declines sting pressure pumpers, but optimism reigns for this summer A number of Canadian pressure pumpers say undisciplined pricing by a couple of competitors upset the pricing-versus-cost dynamic in their industry during the first quarter of 2014 as a stubborn oversupply of equipment continues plaguing the sector. The current low-price, high-cost environment, which is negatively affecting pressure pumpers in western Canada, will continue in the short term; however, the situation is not sustainable, and a market correction is likely to occur this summer. Some companies in the sector are pointing fingers at a small number of competitors who have low-balled work bids to the point that the level of overall pricing for pressure pumpers has been degraded. Although Canyon Services Group Inc. experienced increased activity in the fourth quarter of last year and the first quarter of 2014, it was not matched with improved customer pricing as competition continued to erode pricing as competitors jockeyed to add market share in anticipation of expected improved industry activity levels this year. In particular, in the fourth quarter of 2013, due to competition from other pumping providers, Canyon had little choice but to accept very low pricing in order to defend its market share with certain key customers. “There are companies out there bidding for work at cost. It’s not sustainable. It disrupts the market for everybody else who is trying to run a profitable business,” said Joe Peskunowicz, Canyon’s executive vicepresident, corporate. While he said there’s been a “modest” uptake in pricing of late, the company is still feeling the effects, especially in light of rising costs.
Service & Supply
Canadian Fracturing Requirements By Play Play
Fracturing HHP required
Oil plays Cardium
Deep Basin Horizontal
Deep Basin Vertical
75–150 cubic metres
Sources: Canyon Technical Services Ltd.; Calfrac Well Services Ltd.
“The undisciplined pricing by a couple of competitors, coupled with the U.S. [frac] sand exchange rate [sand is sourced from the United States and paid for in U.S. currency] and fuel and labour costs, which have both gone up, has made it difficult. We managed to get some recovery in the latter half of the first quarter on the exchange rate and fuel, and the fourth quarter was the bottom in pricing as far as we’re concerned.” Fernando Aguilar, president and chief executive officer of Calfrac Well Services Ltd., agreed that a few low bidders upset the pricing-versus-cost dynamic. He noted that it’s not only U.S. competitors undercutting pricing, but also some of the smaller Canadian competitors that he believes, “in desperation,” were trying to nail down work toward the end of the year at little to no margin. “They came with lower pricing. In fact, we had an example where one of our key customers tendered the work, and a smaller competitor came with a 43 per cent price differential. Even though this customer is very high in terms of quality and safety, they couldn’t defend that operational position when you have a competitor that claimed to do the work for 43 per cent less,” Aguilar told a recent CIBC investor conference in Toronto. “We can guarantee that competitor is going to lose money in an operation like that. At the same time, some American competitors were trying to get work. They lowered their price as well. That happened in November. That’s why, when the industry
talks about price increases, we don’t feel pricing is going to go up very quickly because you still have people who are willing to do the work for lower pricing.” Dana Benner, managing director of institutional equity research and head of research, oilfield services, with AltaCorp Capital Inc., says that price cutting by some service companies late last year has carried over and contributed to the lower-pricing reality pressure pumpers are contending with early in 2014. “As it related to the fourth quarter, I think there was hope among fracturing companies that there would be enough work heading into the winter that the price cutting would be finished. But there didn’t seem to be a lot of visibility on how extensive the programs of producers would be, both drilling and fracturing, in the first quarter and in the final quarter of 2013,” Benner says. “A lot of times you’ve got a good feel for how strong the winter season is going to be, and that helps you set a floor on pricing, or you try to push through pricing increases, but there seemed to be a lack of clarity on the strength of the winter,” he adds. “And I think amidst that lack of clarity, there were at least one or two fracturing companies that came in and took some incremental work at lower prices and companies that wanted to maintain their market share chose to match that pricing, even if it wasn’t across the board, for some of the work.” Scott Treadwell, vice-president of equity research for oil and gas services at TD
Securities, agrees that price cutting late last year has had an impact. “The issue was there was some aggressive pricing by some American and some Canadian guys in the space and it led to a bit of a shuffling of the deck,” he says, noting that some exploration and production (E&P) companies simply went to the lowest-cost service provider rather than sticking with longer-standing business relationships with a pressure pumper. Petroleum Services Association of Canada president and chief executive officer Mark Salkeld says the current cost and pricing environment is indicative of the cyclical nature the service sector has historically grappled with. Sometimes the service providers hold the cards, other times it’s their customers that deal from strength. “The pressure is on. As much as we love our relationship with producers and maybe signing long-term deals like three- to five-year contracts or for so many wells—there’s all sorts of different strategies—it’s always like, who’s holding the gun now?” he says. “This winter was busy, and there was awhile there that it seemed the fracturing/ pumping services market was a little bit overloaded with equipment. But a couple of outfits have shut down Canadian operations or they’ve taken equipment down to the U.S. where it’s busier and there’s better demand,” he added. “The market kind of balances itself out. It’s just the plain old principle of economics—supply and demand.” “I think everyone sort of expects to see a five per cent price increase as we go into P R O F I L E R M A G A Z I N E . C O M
National energy board HIGH CASE NATURAL GAS DRILLING FORECAST (WELLS PER YEAR) Western Canada
Shale Coalbed methane
Source: NEB’s Canada’s Energy Future 2013
summer and then something else near the end of the year when labour costs start to move up and if foreign exchange and sand is still a bit of an issue,” says Treadwell. “Then you could see guys kind of pre-empting winter tightness with another price increase.” Trican Well Service Ltd. chief executive officer Dale Dusterhoft notes that the first quarter of 2014 was actually very busy for the company—in fact, it had to turn down work. It was pricing and cost issues that dragged down the company’s performance and he plans to try to remedy that situation by putting through price increases in the second quarter that will take hold this summer. “We’ve got cost increases from the supply side, the U.S. dollar and fuel prices. Thirdparty hauling is up pretty substantially and job
sizes are up, which adds some costs to our third-party hauling,” he says. “So all these cost increases are there. So we’re now at a point where we have to start moving our pricing. We’re in a situation where we believe we can do that, and if we’re going to improve our Canadian margins, we’re going to have to do this,” Dusterhoft adds. While customers likely won’t be enamoured with the prospect of higher pricing, Dusterhoft says that as long as Trican can make a strong and credible case that some of the increase in cost needs to be recovered through pricing, mutually beneficial arrangements can be made. “Going to our clients with price increases usually works well as long as we can demonstrate cost increases. We have to go in and
say, ‘Well, here’s what the U.S. dollar did, here’s what fuel did, here’s what labour did, and all those kinds of things,” Dusterhoft says. “If we can go in and demonstrate that, normally we get a pretty receptive audience. They get testy if we’re trying to margin-grab, but if we’re trying to recover costs, most of the time that goes okay.” But that’s not always the case, he adds. “There are some other customers that won’t care. They want the cheapest, no matter what. It wouldn’t be very many, but there are lots of different customers out there,” Dusterhoft says. “But if I look at our ability to raise prices going forward, I feel pretty good about it. We’ve normally been able to do that. So if we put a price book increase in place this spring, we should be able to get that
Will the Duvernay set off a midstream building boom?
he emerging Duvernay shale play will create opportunities for a wide range of new infrastructure, including condensate stabil ization, once producers figure out what is needed, an institutional investors conference heard late last year. “You need facilities to take the gas out of the condensate and stabilize that condensate,” Mick Dilger, president and chief executive officer of Pembina Pipeline Corporation, told the CIBC conference in Whistler, B.C. In addition to a condensate stabilization unit, whose cost would depend upon the type of commodity mix in the gas stream, a gas plant would be required to handle the liquids-rich natural gas coming off the condensate, he said. However, many of the existing gas plants are not suitable for the type of liquids-rich product that is being produced, said Dilger. David Smith, president and chief operating officer of Keyera Corp., suggested at the conference that there is a “little bit of a question” about the composition and volumes of condensate as well as condensate handling and stabilization requirements. “Producers still need more time to evaluate the productivity and sustainability of those wells and to figure out what they really need from an infrastructure point of view.”
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According to Smith, the infrastructure required in the Duvernay also depends on the geographic area. “In the Simonette area, there’s no question there is a need for more infrastructure,” he said. The company is in the process of building more condensate handling capacity as well as more raw gas gathering and processing capacity, the conference heard. In the southern part of the Duvernay, in the Rimbey and Willesden Green area, there is a lot of existing gas processing capacity, but a fair bit of debottlenecking is required in order to accommodate some of the growing condensate production from the area, said Smith. The nine or 10 Keyera plants in the area have an estimated 100 million to 200 million cubic per day of available capacity, subject to some debottle necking work on the gathering systems, he said. “We really like the situation we have at Rimbey,” said Smith. “I think we are going to be in a position to be able to meet the needs of the producers as they develop.” The Rimbey plant, which has been operating for more than 20 years, is one of the oldest, largest and most complex facilities in the western Canadian basin, analysts heard. It also has tremendous
Service & Supply
Photo: Nexen Energy Ulc
A multi-well drilling pad in the Horn River.
through in a staged matter—it’s not going to happen overnight.” While he expects pricing to languish in the short-term, AltaCorp’s Benner believes a hike will occur. And not just for fracturing outfits. “I think prices will ultimately end up sticking, and it won’t just be in fracturing. I think you’ll see day rates start to move up on the drilling side and a number of other areas,” he says. “Again, the context is they’ve been falling for some time, and there has to be a point where
they trough and start to move higher amidst a rosier environment for E&P companies. That’s just sharing of the benefits that comes with sharing of the pain,” Benner adds.
Service rig slowdown may be about to change Despite the surge in oil well drilling in recent years, service rig utilization, which normally
flexibility in terms of its capabilities for liquids—liquids extraction and fractionation and rail, truck and pipeline connections, he said. Once Keyera completes the turbo expander project (a 400-millioncubic-feet-per-day deep-cut facility), it will be able to extract virtually all of the liquids in the gas. It will also be able to incrementally expand the plant’s inlet capacity without a significant amount of additional capital because it will still have the lean oil system available. For its part, Pembina has been busy planning new pipelines in the Duvernay. “The Duvernay is new enough that a producer doesn’t know whether they are going to get liquids-rich gas, crude or condensate,” said Dilger. However, that won’t be an issue for shippers on Pembina’s proposed Phase III expansion because there will be three distinct pipelines in the core Fox Creek, Alta., to the Edmonton corridor, he said. “They can decide later, and we will be able to accommodate them no matter what product type it is.” The $2-billion expansion project is expected to be in service between late 2016 and mid-2017, subject to environmental and regulatory approvals. According to Dilger, although a new 20-inch pipeline would have accommodated the initial demand, Pembina opted for a 24-inch
follows an uptick in drilling, hasn’t kept pace. But that seems to be changing. Now the challenge is finding workers to man the rigs, says Savanna Energy Services Corp. president and chief executive officer Ken Mullen. “The ultimate insult is we have been challenged with very low utilization for quite a while, and utilization has picked up in the first quarter of 2014, but most of the people who come to work on the rigs realize it may be time-limited,” Mullen said in March. “As a result, it has been very difficult to attract crews, so we have actually had to turn away work—and I am sure others are in the same boat—just because we cannot get qualified personnel who would come back and work on those rigs. That is part of the challenge it is going to take to rebuild this business. We have to get to a point where the labour force feels comfortable that it is a sustainable job with an activity level that will put groceries on the table, before they will come back.” Unfortunately, he said, to increase the labour force’s confidence regarding those service rigs, those rigs need to be used more in the field. “It is a difficult business, and it is going to take a while to rebuild the operating capacity in that business,” he said. According to Mullen, through acquisitions a couple years ago, Savanna made a bet on the
pipeline for the project because its producer customers were saying “that’s the start.” The expected initial capacity in the core area is 320,000 barrels per day with an ultimate capacity of 500,000 barrels per day. “It’s a vast resource, possibly, and as much as we have overbuilt our project, if it does turn out to be a million-barrel-a-day play...then I think there is going to be a lot more infrastructure required.” The Duvernay will also need fractionation capacity, he said. “We were surprised when we did RFS II [73,000 barrels per day] that it was filled by three customers, and there were other customers we couldn’t provide service for,” he said. “We build a certain kind of fractionator, and we want to do that over and over; we didn’t want to redesign our whole process.” In addition to Pembina’s Redwater project, new fractionation cap acity includes Keyera’s 30,000-barrel-per-day de-ethanizer and its 35,000-barrel-per-day fractionator, both at Fort Saskatchewan, Alta. If the Duvernay and Montney continue to develop, Dilger said he has no doubt that a third Pembina fractionator will be needed; the only question is the timing. “If our Phase III starts up in the 2017-18 time frame, I think there is a reasonable chance that a fractionator will be signed up before that time frame.” P R O F I L E R M A G A Z I N E . C O M
Canadian workover market, but whether it is due to better completion techniques with liquids-driven drilling in western Canada or some other factor, his company has not yet experienced “the turn” where the service rigs would be in high demand. “What is interesting is that we have seen that uptake in North Dakota, but I think, in fairness, the concentration of drilling and rapid maturing of that basin has probably contributed to the drive in activity levels. Our premise is that it is coming to Canada,” he said. “Obviously our bet was too soon, but we still believe the fundamentals of working over oil assets have not changed, and in fact, the deviated nature of the wells ultimately will require a great deal of maintenance.” The emergence of a growing workover market in western Canada can be seen in the Bakken, where Lightstream Resources Ltd. spent $30 million in 2013. It plans on spending a similar amount this year and will be expanding operations in the Cardium in Alberta as well.
Will shale plays build on tight oil base? Tight oil plays across western Canada have been keeping the service and supply industry afloat for the last five years. And with existing development drilling and a number of recent discoveries, this will continue in the short term. In existing tight oil plays, major developers continue investing heavily. Examples include Penn West Petroleum Ltd. in the Cardium play in central Alberta. Penn West is spending 76
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around $280 million in the Cardium in 2014, but by 2018, it expects to be spending $800 million. It expects to spend $5 billion on the Cardium, Slave Point and Viking plays over the next five years. New tight oil plays are also being developed. Tourmaline Oil Corp.’s Charlie Lake play has an estimated 500 million barrels of oil in place, with 1,200 drilling locations. Birchcliff Energy Ltd. says it has 400 million barrels in place on its land at Worsley. Then there’s Crescent Point’s April announcement that it is in the early stages of developing a Bakken/Three Forks tight oil play in the Flat Lake area, where it has already identified 400 drilling locations on top of the 7,100 drilling locations it has on its tight oil landbase. All of these tight plays, however, could be just a fragment of the potential of shale development, should it prove commercial in the Duvernay play of west-central Alberta and in the Muskwa play in northwestern Alberta. The industry is in the early stages of figuring out just how big the Duvernay development could be. Canadian oilfield service firms could easily support the drilling of 200 wells per year in the Duvernay, but full development will require a significant expansion of the existing equipment fleet, Tyler Elgar, engineering manager for the Canadian division of Calfrac Well Services Ltd. said at a presentation in Calgary. According to the most recent estimates, roughly 125–200 horizontal wells are expected to be drilled into the emerging Alberta shale play this year, up from about 105 last year and 51 in 2012. Elgar said the 2014 projection is now lower than initial
forecasts for the year, due mainly to inad equate take-away capacity in the greater Kaybob region and insufficient facilities to maximize the high yields of natural gas liquids. “It’s our understanding that these are perceived to be short-term issues at this point,” Elgar told a Daily Oil Bulletin Speaker Series breakfast, sponsored by NCS Energy Services Inc. “But really, you must start thinking beyond the 200 wells a year. If we start talking 300, 400, 500—which many have pegged to be the number for full development of the Duvernay—we need to consider what challenges face us.” “We’re going to be talking about large multi-well pads—eight, 16, maybe 24-plus wells on a pad. It’s certainly going to be 24-hour operations,” he said. “The estimate we’ve seen on the hydraulic horsepower demand to facilitate this is 300,000-plus. We’ve seen some estimates encroaching on 400,000.” To put this into perspective, Elgar said that’s roughly 20 per cent of the capacity that exists in Canada today. “This will require significant collaboration and preplanning. I say that because to the best of our knowledge, nobody has really committed the capital yet to build the crews to support this work,” he said. “I think we’re all in the background, trying to get an appreciation for where this play is going, so we can be ready when the workload is there. And keep in mind, a crew of this size to do this style of work is roughly a 12- to 18-month build time.” Development of the Duvernay could also face constraints if other plays heat up.
Photo: joey podlubny
Fracking outfits will be busy if the Duvernay shale play takes off.
Service & Supply
As the prospect of LNG looms closer, relatively dormant dry gas plays such as the Liard and the Horn River are likely to become busier, he said, adding that improved North American gas prices could also slow the pace of Duvernay development by competing for the same service-sector resources. While the number of horizontal and deviated wells drilled in western Canada was fairly flat in 2012 and 2013 at about 9,000 per year, “we see a sizable estimated uptick in 2014 to put us somewhere over 10,000,” he said, noting that the metres drilled has been increasing. He added, “We’re going to be competing for resources against the Montney, the Cardium, the Deep Basin and other successful plays in this area.” Also, the drilling of wells with longer lat erals and tighter spacing will tie up more services that would otherwise be available for the Duvernay. Elgar pointed out that success in the Duvernay could generate its own challenges. As drilling in the play ramps up, demand for services in the Duvernay itself could hamper the pace of development. Within the Duvernay in the near term, there are infrastructure constraints such as limited take-away capacity and processing capability. As well, the industry needs to better understand play economics. Capital costs have been declining and efficiency has been improving. “And once we better understand some of the long-term production, we will be well on our way to getting a better handle on the return on investment,” he said. Also, the rules of the game haven’t solid ified yet. Elgar noted that the Alberta Energy Regulator is creating a new regulatory framework for unconventional play development in the province. While much of the initial Duvernay drilling was on single-well pads, full development mode would obviously involve multi-well pads. “On a per-pad basis, we’re talking perhaps eight wells” with 15 frac stages per well— each stage using 150 tonnes of proppant and 2,000 cubic metres of fluid, he said. That would work out to 120 fracs, 18,000 tonnes of proppant and 240,000 cubic metres of fluid for an eight-well pad. With the ability to conduct roughly four fracs in a 24-hour period, it would take roughly 30 days to get through 120 fracs, pumping 600 tonnes of proppant and 8,000 cubic metres of fluid per day. “The highlight here is, logistically, this poses a significant challenge, though one that we
“If we start talking 300, 400, 500 [wells per year]—which many have pegged to be the number for full development of the Duvernay—we need to consider what challenges face us.” — Tyler Elgar, engineering manager, Canadian division, Calfrac Well Services Ltd.
have the ability to overcome,” Elgar said, referring to the service sector in western Canada. Some of the challenges facing the Duvernay are similar to those that were overcome in commercializing the Horn River shale gas play. “The learnings from there are certainly applicable as we look at developing the Duvernay,” he said. “It wasn’t very long before we overcame these challenges and development in the Horn River Basin has been very successful because of that.”
LNG exports provide long-term future opportunity If early indications prove true, the ramp-up leading up to LNG exports off the west coast, combined with long-term development drilling to keep the plants full, could create a major boom for the industry. In July, Precision Drilling Corporation pres ident and chief executive officer Kevin Neveu said LNG exports are likely five to six years away, but it will be a big push for service companies if it happens. Neveu said he expects around three billion to eight billion cubic feet per day of gas to be exported. He said, depending on the stage of development, this will mean between 25 and 40 rigs for each billion cubic feet of export volume, or between 200 and 320 rigs if the higher number becomes reality.
“Initially, during the ramp-up, land grab and production-testing, it could be as many as 40 rigs per billion cubic feet, but as the business matures, it comes down to 25 rigs per billion cubic feet, which will likely all be new-build, pad rigs capable of drilling all year round.” Ben Parfitt, resource policy analyst for the Canadian Centre for Policy Alternatives, expects the drilling boom in northeastern British Columbia to be even more intense. In a recent webinar for the POLIS Water Sustainability Project, Parfitt says that if four major LNG plants happen, the province’s annual production will rise to 4.6 trillion cubic feet from current levels of about 1.2 trillion cubic feet. The four plants will require $70 billion in investment. Parfitt said the construction of one LNG plant would raise drilling in British Columbia from about 460 wells annually to 941 wells. If four plants are built, 1,300 wells per year will be needed during the ramp-up, with 1,539 wells per year needed to keep the plants running for the next 20 years. In all, Parfitt said 37,718 wells would be drilled in the province by 2040 to supply the plants. LNG expectations of the B.C. government are unlikely to occur at the scale envisioned by the province, and the approval of current and expected projects poses potential national energy security risks, says a recently released report by a former Geological Survey of Canada scientist. David Hughes, president of Global Sustainability Research Inc. and author of BC LNG: A Reality Check, doesn’t believe the industry has the capacity to handle all the LNG projects currently approved by the National Energy Board (NEB). The NEB has approved export projects totalling 14.6 billion cubic feet of natural gas per day. The fact is, meeting those approvals requires drilling almost 50,000 new wells in the next 27 years—double all wells drilled in British Columbia since the 1950s, says Hughes in his report. Further, the report suggests, due to steep production declines associated with shale and tight gas, drilling rates of over 3,000 new wells per year would be required to ramp up production to export levels, and there would have to be 2,000 wells per year to maintain that production. Hughes says that he finds it unlikely that there will be seven LNG projects completed in B.C., as was approved by the NEB, and he finds it far more likely that the province could expect to see just one or two such terminals. P R O F I L E R M A G A Z I N E . C O M
Advantage Valve Maintenance The production tester’s best friend
he search for the perfect vendor, in any industry, can be a challenge. Oil and gas service, supply and rental companies know all too well that you must offer outstanding service and go the extra mile every time. Successful habits of visionary companies include delivering outstanding service on a consistent basis, with products that meet or exceed all expectations. Advantage Valve Maintenance is one of those visionary companies that consistently exceeds every expectation. “Our customers know the level of service they can expect from us every time they do business with us,” says owner Brooks McDermott, who founded the Alberta-based company in 1999. “We are available for our customers 24 hours, 7 days a week. We have built an outstanding reputation in the industry as being highly recommended by consistently delivering exceptional service.” Advantage Valve Maintenance specializes in maintenance on oilfield valves and other equipment for oilfield production testers in western Canada. While based in Grande Prairie, Alta., a recent expansion into Sylvan Lake, Alta., with a brand new facility allows them the ability to service customers throughout Alberta, B.C. and Saskatchewan. “We have the resources to react quickly and respond to our clients’ needs,” says Brooks. With a hands-on, value-driven management philosophy, Advantage Valve Maintenance has been able to grow its business through valued relationships and referral business. Advantage Valve Maintenance also has a rental division, Advantage Valve Rentals, which supplies production testing companies with manifolds, emergency shutdown devices (ESDs) and other equipment. Maintenance and rentals are available at both locations and are a big part of their business. Having original equipment manufacturer support is critical to a business, and Advantage Valve is supported by many of the manufacturers it works with on a continuous basis. “We are OEM-trained and hold distributorships with a number of the manufacturers 78
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ALBERTA WELLTEST INCINERATORS LTD. Guaranteeing you superior results
lberta Welltest Incinerators (AWI) provides industry-leading incineration technology that is dedicated to reducing the environmental impact of oil and gas–related production test flaring. AWI’s low-emission burner technology provides a significant edge over conventional flares and enclosed flaring equipment, along with competitive rental rates, 24-hour service and an intense focus on client satisfaction. AWI’s industry-leading incineration technology is highly effective and efficient, converting 99.99 per cent of methane to CO2 and H2O. The system disperses combustion products thanks to its high operating temperatures, increased stack velocities and a forced draft system. Designed specifically for well completion applications with patents pending, AWI’s equipment is “the most efficient and effective on the market for that purpose,” says AWI vice-president Dan Guenette. “It is the only incineration equipment in the industry specifically designed for well completions and well-testing applications—that’s really the big thing. We designed it specifically for doing that job, and it works very well.” Based in Whitecourt, Alberta, AWI works primarily in Alberta, British Columbia and Saskatchewan. Founded in 2004, the company has three full-time workers responsible for operations, sales and business development as well as administration. AWI’s employees are “top-notch people,” says Guenette, who believes it is AWI’s people who make the company the success that it is, as much as its equipment. AWI represents the best available technology to handle the effects of high-volume flaring associated with well testing, improving combustion with high internal temperature retention and reducing noise pollution. The AWI dual continuous ignition pilot system provides optimum fuel and air mixing energy, ensuring extremely high combustion effi ciency. The AWI equipment runs quietly and efficiently, emitting no odour, no smoke,
no visible flame and no heat radiation at ground level. AWI’s control system includes a forced draft multi-point vortex burner, automated air delivery system, dual pilot continuous ignition system, and continuous temperature measurement and recording. Instantaneous online temperature monitoring and recording take place through the on-board communications module. Clients can access temperature data with a password, and monitor realtime temperatures and well-test progression from any computer with Internet access. The simple automated control system is user-friendly, with a rapid set-up. The equipment is skid-mounted for ease of loading, transportation and installation. Installation is completed in just 20 minutes, with no guy wires and zero ground disturbance. Compared to conventional and enclosed flaring, AWI technology offers: • Combustion efficiency of 99.99 per cent, resulting in improved air quality and reduced greenhouse gas emissions; • Stable, consistent combustion in an enclosed, lined chamber unaffected by wind; • A freestanding unit with zero ground disturbance, no smoke, no visible flame and no odour; • No heat radiation at ground level, resulting in improved protection of personnel, equipment, and Arctic/tundra and other sensitive environments; • Oversized load permits and pilot trucks are not required with AWI’s equipment, which measures 40 feet long by 11.5 feet wide and weighs 16,500 kilograms;
• Uses significantly less enrichment fuel than a flare to efficiently incinerate lowheat-content gases (H2S) with 99.99 per cent combustion efficiency; • Compliant with Alberta Energy Regulator (AER) Directive 60. The equipment is approved to incinerate sour gas above five per cent, as per AER Directive 60 requirements. The system features a 40-foot exit elevation, dual continuous pilots, continuous temperature monitoring and recording, and the ability to maintain a temperature of 600 degrees Celsius for H2S incineration, reducing or eliminating additional fuel requirements. Oil and gas producers choose AWI over conventional and enclosed flaring primarily when: • Working within close proximity to neighbours and stakeholders (farmers, ranchers, residential and urban areas, cottage country); • Completing wells while ensuring “tight hole” status when necessary; • Ground disturbance and ground temperature radiation advantages are necessary in environmentally sensitive areas; and • There’s a presence of H2S in the well gas stream. AWI has also recently added a line of Low Flow Incinerator technology, designed for the lower flow rate, sweet gas applications, pipeline blowdowns, production facility temporary applications, etc. This equipment is trailermounted for ease of transportation and easy to operate with reliable solar-powered controls for LPG Pilot Ignition and Monitoring. It’s no surprise that AWI has been consistently gaining market share, year after year.
Guenette sees a very bright future for AWI. “We’ve got strong market share in western Canada, and have taken the technology into the U.S. In January 2012 we opened an office in Denver for our new subsidiary, American Welltest Incinerators Inc. We are very excited about that.” The AWI equipment is efficient, hassle-free and easy to operate. Just one button. Turn it on. Walk away.
FAST FACTS ALBERTA WELLTEST INCINERATORS LTD./ AMERICAN WELLTEST INCINERATORS INC. PRESIDENT/VICE-PRESIDENT: Don Guenette/Dan Guenette YEAR INCEPTED: 2004 NUMBER OF EMPLOYEES: 3 BUSINESS CATEGORY: Oil and gas industry equipment rentals ADDRESS: PO Box 447, Whitecourt, AB Toll-Free: 1.888.778.0960
SALES: Rick Henders T: 403.816.7116 E: Rick@awincinerators.com
BHD TuBuLAR LTD. The right pipe—on time, all the time
HD Tubular’s overriding goal is to provide the right pipe and related products—on time, all the time. An industrial pipe distribution company for the oil, gas and mining industries in Canada and the United States, BHD Tubular distributes a wide range of pipe and related products to meet the industry’s midstream, upstream and downstream requirements with an office and 15 acres of pipe yard strategically located in Edmonton and a new 16-acre pipe yard in Tofield, Alta. These two locations allow BHD Tubular to service projects of any size. “Service to our customers is number one and always has been. That is the backbone of our company,” says BHD Tubular business development and marketing manager Bryan Toles. Established in 1998 by president Ken Hesse as a division of the BHD Group, the tubular division became a separate entity in 2012, with rebranding taking place in 2013. For BHD Tubular, partnership with its customers and other business partners is essential to its success. “Partnership is a big thing to us. It’s really important to be a good partner with your customer, and it’s equally important to be a good partner with the people you buy from,”
Toles says. “Partnerships with our vendors are very strong, enabling us to buy better.” BHD Tubular, which recently became certified to ISO 9001:2008, provides quality pipe products that are regularly stocked and does custom pipe orders as well. BHD Tubular’s product specialists and application experts are available to provide skilled product demonstrations and training for customers across Canada and the United States. As a privately held, Canadian-owned company, BHD Tubular stocks a wide range of hard-to-find pipe sizes and grades, in order to better meet clients’ needs. BHD Tubular’s knowledgeable staff are happy to source out any product the company does not stock. In addition to seamless line pipes, BHD also offers a product line for upstream use: Oil Country Tubular Goods (OCTG). This includes API-5CT/D10 Casing and Tubing down hole tubulars, Specialty Cr-Mo and Stainless Steels, Proprietary (Premium) Connections, and ERW/ SAW/UOE large OD line pipes for transmission of gas, diluent, tailing, steam, emulsion application and more. With this, BHD has the capability to cover the entire range of energy steel piping products for the oil and gas, power and refinery industries.
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For BHD Tubular, being privately held and Canadian-owned brings many advantages, Toles says. “We feel that has a lot of benefits to it—mostly to do with where we work, with quality of life, and having happy employees.” BHD Tubular’s goal for its staff is maintaining a safe, productive and healthy workplace and attracting and retaining excellent employees. “It’s a really good place to work,” Toles says, noting that happy people do better jobs. In a major renovation last summer, the company added a workout facility in order to promote employee wellness and healthy living. As part of this health-centred approach, a personal trainer comes in to work with employees twice a week. Through innovation and service excellence, BHD Tubular is dedicated to being your ‘Supplier of Choice.’
FAST FACTS BHD TUBULAR LTD. T: 780.434.6824 Toll Free: 1.888.939.6824
B HD Tu bu lar C:81 M:53 Y:00 K:00
C:17 M:13 Y:13 K:00
A Leading Steel Pipe Product Distributor Serving The Canadian Oil & Gas Industry For Over 15 Years
Sizes: 1/8" to 48" Wall Thickness: .125" wall to XXH Stocking bare metal finish, YJ coated, FBE coated, galvanized, pickled and oiled, or blasted and primed NOW OFFERING: Oil Country Tubular Goods (OCTG) • API-5CT Tubing & Casing K55/J55/L80/T95/C90/C110/ P110/Q125 • Alberta Directive-010 Compliance Casing • 13 Chrome Specialty Stainless Steel • Proprietary/Premium Connections • API-5DP & IRP Drill Pipes
ASTM/ASME API5L CSA Z245.1 ASTM/ASME API5L
SA106 B/C SA333 1/6 Grade B/X42/X52 All Grades SA53 B Grade B through X80 PSL1 & PSL2
1-888-939-6824 Ph: (780) 434-6824
Fax: (780) 436-7961 ♦ 6903-72 Avenue, Edmonton, AB T6B 3A5
CLEAN SOLuTIONS INC. Raising the standards of quality control
lean Solutions Inc. specializes in cleaning equipment used in the oilfield transportation, pumping and storage industries throughout Alberta and beyond. Whether it’s steam-cleaning a tanker truck, flushing out a storage tank or pressure-testing coil tubing equipment, the professionals at Clean Solutions have the expertise to get the job done right. Established in Red Deer, Alta., in 2004, Clean Solutions was created to provide an environmentally secure location where oilfield pumping industry equipment could be flushed and cleaned. It has since expanded to offer flushing and cleaning services for all types of tankers and tank trucks, as well as for storage tanks and other equipment requiring the handling and disposal of hazardous waste.
The company handles and disposes of both waste and effluent, to ensure there is no contamination of sewer systems or land. Clean Solutions serves oilfield haulers from across Alberta, as well as cross-country highway haulers and tank truck customers from the United States, who come to Clean Solutions’ 20,000-square-foot facility in Red Deer to get cleaned out. Clean Solutions also handles coil tubing equipment, doing flushing, pressure testing and servicing. The company is open seven days a week and is conveniently located close to the Queen Elizabeth Highway II and Highway 11A in Red Deer. For Clean Solutions, it’s all about quality control. “When companies come to us to clean out their equipment, they dramatically reduce any
potential for cross contamination in their next job by maintaining high quality control in the jobs that they do,” says Clean Solutions general manager Blair Nielsen. “It’s risk management, by taking that extra precaution to make sure their equipment is clean. It just reduces that risk.” For customers, it’s also part of doing their due diligence, he adds, noting that Clean Solutions provides a certificate as part of the invoice for every cleaning job it does. “We are continually striving to meet any challenges the industry has,” Nielsen says. “We are willing to adapt and meet those needs as different equipment and products come up that need to be cleaned. We are always striving to find new solutions and more efficient ways of doing what we’re doing, and we’re open to expanding with new options and products.” Looking forward, Nielsen is optimistic about the future. As environmental awareness has increased dramatically in recent years, people are becoming much more concerned about handling waste properly and ensuring that all equipment is clean and safe to handle. For Clean Solutions, business has continued to get busier as awareness of its services increases over time. Clean Solutions has built a reputation for integrity and honesty in all that it does, and its customer base is continuing to grow. “Integrity and honesty are a very big part of our culture here,” Nielsen says.
FAST FACTS CLEAN SOLUTIONS INC. GENERAL MANAGER: Blair Nielsen 7915 Edgar Industrial Way Red Deer, Alberta T4P 3R2 T: 403.340.0131 F: 403.340.0160 E: email@example.com
Cleaning Facility for: Tank Trucks • Storage Tanks • Pumping Equipment Oilfield Equipment • Using GAMAJET® Cleaning Systems 7915 Edgar Industrial Way, Red Deer, AB T4P 3R2
CuMMINS WESTERN CANADA: RENTAL POWER SOLuTIONS Western Canada’s power-generation powerhouse
“in this business, we have to be available to react fast to emergency power requests and provide our customers with the best temporary power solutions.
— Richard Greenways, rental support manager, Cummins
ummins Western Canada provides complete temporary power solutions for oil and gas, construction and many other industries. Rental Power is an important part of the power generation business at Cummins Western Canada, which offers a complete line of dependable Cummins generators for prime power and standby power applications. Cummins Western Canada—the exclusive distributor of Cummins engine and power generation equipment products in western Canada—has been in the generator rental business for the past quarter century, providing customers with rental power solutions including Cummins diesel and natural gas generator sets and related electrical equipment and services. Services offered include delivery and set up of equipment, generator maintenance and fuel management. The rental equipment that Cummins provides is designed for safety and reliability, with western Canadian heavy duty industrial applications in mind. Equipment is CSAapproved, sound-attenuated, and designed for fluid containment, with Transport Canada– approved fuel tanks. Cummins Western Canada strongly believes in listening to its customers’ needs. “In this business, we have to be available to react fast to emergency power requests and provide our customers with the best temporary power
solutions. We have to be responsive to our customers’ needs,” says Cummins rental support manager Richard Greenways. Cummins Western Canada operates from an integrated network of 15 locations, with the majority of rental activity taking place from the Edmonton, Fort McMurray and Grande Prairie locations. With 24/7 service support, Cummins is committed to providing an exceptional customer experience and does so in a number of ways: “No. 1—our staff. We have a great team of dedicated people.” Cummins Western Canada’s experienced staff have the expertise to meet your needs. “In addition to our dedicated rental staff, we draw from a large number of Cummins technicians with specialized training for power generation applications,” Greenways explains. “We also draw from the wide experience of our engineering support team and our Health, Safety and Environment (HSE) group. We’ve made some great strides to grow that support and structure within the company. It’s always been there, but now it’s stronger than ever.” Additionally, as part of an extensive network of North American Cummins Distributors, Cummins Western Canada has access to a very large asset base of rental power equipment, which can assist the company in an emergency or when responding to large customer requests. Cummins, the world’s largest
independent manufacturer of diesel engines, is a global leader in power generation and diesel emissions technologies. Cummins Western Canada’s rental generator fleet takes advantage of Cummins emissions technologies to provide industry-leading emissions reductions technology in the products it offers. Cummins Western Canada’s Rental Business is set for growth. “We have a great team of professionals on staff and quality, dependable rental equipment,” Greenways says. “We strive to meet our customers’ needs, every time.” From start to finish, you can depend on Cummins Western Canada to provide for all your rental power needs.
FAST FACTS CUMMINS WESTERN CANADA: RENTAL POWER SOLUTIONS RENTAL SUPPORT MANAGER: Richard Greenways E: firstname.lastname@example.org
SERVICE ASSET MANAGER: Greg Killam E: email@example.com Toll-Free: 1.855.797.7368
RENTAL POWER SOLUTIONS You can depend on Cummins
for your complete rental power solution, including: • Cummins powered generator sets up to 2000 kW • Customized electrical distribution, transformers and power cables • Mobile double wall fuel tanks • 24/7 service support from 15 locations across Western Canada • Complete multi-megawatt generating installations with 24/7 site operation
On site, on demand, on time. 1-855-PWR-RENT (1-855-797-7368)
FLO-BACK EQuIPMENT RENTAL AND SALES High-quality processing and testing equipment drives Flo-Back’s rapid growth
lo-Back Equipment Rental and Sales is dedicated to building and renting exceptional quality equipment, providing outstanding service and maintaining high standards in quality control. “We put our customers first, with a focus on quick deliveries and operator-friendly packages,” says Flo-Back Vice-President Mark Brown. For Flo-Back customers, it all brings peace of mind. “We ensure quality equipment that is engineered and built safely,” says Brown’s business partner, Flo-Back President Scott Candler. “The integrity of the rental fleet is our top priority, maintained by an internal Integrity Management System developed by the partners. All equipment is ultrasonically tested after
each rental to ensure that minimum wall thicknesses are maintained and to ensure the safety of our clients.” Flow-Back Equipment Rental and Sales opened its doors in 2010 in Nisku, Alberta, after Brown and Candler saw a need for quality processing and testing equipment, rental and sales in the oil and gas industry. The company quickly grew to 30 units, including test separators, line heaters, flow line, wellhead packages and pressurized storage. Currently, Flo-Back has more than 70 units and is building another 25 units at its new fabrication facility in Nisku. Flo-back Fabrication Added in 2012, Flo-Back’s fabrication division is an ABSA-certifi ed facility.
Equipment recently fabricated and packaged includes testing and wellhead separators, line heaters, fl are stacks, fl ow line and fl are line, as well as inlet and group separators. With 15 years of equipment design, fabrication and rental management experience, company co-founder Mark Brown looks after the design and build process, from concept to rollout. Working with clients one-on-one allows him to ensure the client’s specific operational needs are at the forefront of each design. Custom projects, such as the twin-fired 4-MMBTU trailered line heaters, showcase the firm’s ability to think outside the box and design equipment for today’s completions. Flo-Back’s newly designed 6" x 60' flare stack with two 3" auxiliaries is
“the integrity of the rental fleet is our top priority.” — Scott Candler, president, Flo-Back
another example of great design. Flo-Back can design and build your largest testing packages, while placing great value on customer service. “We have an oilfield equipment engineering background and our own design capabilities, so we can handle it all, from the concept design to finished product, all under one roof,” Brown says. Flo-back rental and Fabrication: your Shortand long-term Equipment Solution By leveraging Flo-Back’s rental fl eet while you build, you can get into production immediately, while Flo-Back builds to your exact specifi cations. Flo-Back’s rental units are sized to be used in as wide a variety of situations as possible. This allows
the client to get into production and cash fl ow sooner. As an added bonus, purchase credits earned in this scenario can be used against the purchase price of the new equipment. Whether you need additional equipment for a specifi c job, or production equipment fabricated to your exact specifi cations, Flo-Back is your short- and long-term equipment solution. In addition to its Nisku base, Flo-Back plans to open locations in the next 18 months in Grande Prairie, Alberta, southern Saskatchewan and North Dakota. Whether you are renting or purchasing, you can be assured that Flo-Back equipment will be of exceptional quality. your workforce’s safety is their number one priority.
FAST FACTS FLO-BACK EQUIPMENT RENTAL AND SALES VICE-PRESIDENT: Mark Brown T: 780.955.3561 E: firstname.lastname@example.org
IHS Global Canada Unconventional reserves estimation with IHS Harmony ™
raditionally, reserves have been evaluated using Arps decline curves, assuming boundary-dominated flow. In conventional oil or gas well analysis, this meant a hyperbolic exponent (b-value), ranging from 0 to 1, could accurately forecast a well’s future production. As we have moved towards tighter unconventional play production, the assumption of boundary-dominated flow for the majority of the production history is no longer valid. The practice of empirically curve-fitting a single segment decline, however, still continues. The evaluator simply uses a higher b-value to fit the production data. These higher exponents produce much longer forecasts that are then truncated to exponential decline at a terminal decline rate. Typically, a single value for a terminal decline rate will be used for an entire field that does not necessarily have any theoretical basis or consideration of well spacing. When faced with limited well production data in an unconventional field, creating a type well (i.e. expected average well performance) is standard practice. Similarities in reservoir pressure, geology and fluid composition are honoured, but this methodology does not account for any volumetric limitation and ignores the observed variability in reservoir description and its resulting impact on production. With the traditional assumptions of Arps decline no longer being met, it should not come as a surprise that the results obtained through this analysis lead to more significant errors. IHS Harmony™, with IHS RTA, offers a modern approach to reserves evaluation that is more reliable for unconventional resource applications. The approach incorporates rate transient analysis (RTA) and advanced modeling to obtain a better fundamental understanding of the physical influences on long-term productivity—thereby providing more reliable forecasts. Our approach The method used in RTA’s unconventional model focuses on analyzing the reservoir signal or flow regime, understanding the recovery mechanism and quantifying the contacted inplace volume. This is combined with knowledge of the completion and well spacing to determine an expected ultimate recovery (EUR) based on a physical model.
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Analysis at a glance:
The flow regime is investigated using a squareroot time plot. Observation of a straight line suggests transient linear flow with departure from this line indicating a transition in flow regime or boundary-dominated flow. For wells in transient flow, the flowing material balance is used in identifying a minimum hydrocarbon volume in place (i.e. the contacted volume-todate). These two analysis methods provide the framework for developing an analytical model that can be used to history match performance data, validating the reservoir description and providing its associated EUR. Additional models with alternate reservoir descriptions can then be considered to capture the uncertainty in fracture network and reservoir geometries to bracket the possible outcomes in the production forecast. Relating the analysis back to decline, values of b and Dt are implicit to the analysis based
on a combination of operating, completion and reservoir characteristics. The relationship between b and Dt and the reservoir model is shown in the diagram below. The detailed analysis of over 200 wells in the Eagle Ford, 40 wells in the Bakken and 50 wells in the Montney has been conducted with the above process in IHS Harmony™. Additionally, this method has guided the analysis of hundreds of other wells in consulting projects, workshops and client support. While there has been significant variability in well performance between plays (and between wells within the same play), this approach has proven to be broadly applicable and customizable to the specific well performance observed. Applying this methodology across large numbers of wells has allowed bulk well performance parameter comparisons that would not be otherwise possible; results which have influenced change to field development and well operations of some of the most rapidly developing unconventional plays in North America. Summary Accepted reserve evaluation and reporting practices have not progressed to keep pace with unconventional reservoir development technology. The practice of understating the uncertainty and neglecting reservoir characteristics is resulting in unrealistic reserves estimation. The additional cost of a more detailed well analysis is becoming more manageable due to advancements in software and the increasing availability of high-quality well data. This upfront investment is paying off through improved reservoir characterization earlier in the life of the well, better understanding of well/completion performance and ultimately increasing the reliability of production forecasting.
Powerful and intuitive analysis tools for evaluating unconventional liquids-rich plays Characterize and optimize the performance of your oil and gas–condensate wells using IHS Harmony’s specialized analysis tools and type curve matching methods.
History match and forecast oil well performance using quick and powerful gridded numerical reservoir models.
Evaluate, manage and report forecasts for reserves using industry-leading decline curve analysis tools.
Update existing wells directly from Enerdeq and Well Data (Canada) databases and import new wells from Enerdeq.
Download a free trial today at ihs.com/harmony
JEWEL ENERGY SERVICE INC. Coiled tubing in the cloud-based tool provides real-time data to customers
ewel Energy Service Inc. prides itself on its reputation for excellence in getting the job done right the very first time. “We believe our approach to engineering, planning, equipment and technology selection is the key to success,” says Vern Mathison, who handles Western Region Sales for the Alberta-based coiled tubing and pressure pumping services company. Established in 2011, Jewel Energy Service is based in Red Deer, Alberta, with an operations base in Carlyle, Saskatchewan, and a sales office in Calgary. With six heavy duty trailer coil tubing rigs, four pump units and five pickers, Jewel Energy Service is active across the Western Canadian Sedimentary Basin, ranging from southwest Manitoba to deep basin Alberta. Jewel Energy Service’s equipment is brand new and built in Canada, and the company has a full health and safety program in place, with an emphasis first and foremost on quality, health, safety and environment. Jewel Energy Service works hard to expand the capabilities of coil tubing by continuing to introduce new technologies to the market and doing things “smarter.” Every job starts by working closely with the customer in order to understand and mitigate risks and come up with the best possible solution. “Together we agree how we are going to implement the solution in order to give the best possible result for the customer,” Mathison says. “By collaborating with the customer throughout the whole process, everyone is involved in the execution of the developed plan.” The customer can see exactly what’s going on at the rig in real time, thanks to Jewel Energy Service’s cloud-based tool, “Coil Tubing in the cloud,” which provides real-time field data over the Internet. “The customer can join with the rig on our consoles to view what’s going on,” Mathison explains. Through every step of the process, Jewel Energy Service provides expert oversight to support its operations 24-7. A coil manager based in Red Deer and the Carlyle sales/ operations manager oversee all operations in the field and are available to offer advice and solutions whenever required.
Jewel Energy Service is continually doing research, seeking out better methods of performing workovers, fracturing wells and looking for new methods, materials and products in order to complete the job more efficiently. Jewel Energy Service, which now has approximately 30 employees, makes it a priority to hire experienced deep coil personnel to run its units. “We hire experienced deep coil tubing personnel to reduce the risk and make sure the customer is comfortable with what we’re planning on doing,” Mathison says. Looking forward, it appears the market is demanding more coil tubing intervention operations, and Jewel Energy Service believes it is well positioned to capitalize on these opportunities. “We want to be the company of choice, recognized as a leader in technology, and to be the first call for customers.” At the Global Petroleum Show, Jewel Energy Service will have one of its coil tubing units on display at the outdoor exhibit of one of its manufacturers.
FAST FACTS JEWEL ENERGY SERVICE INC. WESTERN REGION SALES: Vern Mathison E: email@example.com
EASTERN REGION SALES AND OPERATIONS Ryan Benjamin E: firstname.lastname@example.org
TECHNICAL SALES: Ben Atkin E: email@example.com Toll-free: 1.855.347.7793
Visit Jewel Energy Service at booth #3356. 92
Coil Tubing Units
Pump Truck Specifications
Coil Tubing Unit Specifications
■ 70 Mpa, 600 HP, 3 1/2 x 6 Triplex ■ 40 to 550 lpm @ 35 MPa ■ 2 - 4.5 m3 mixing tanks, 1 - 1.5 m3 flush tank ■ 2012 Western Star DD15, Allison OFS transmission ■ Control cab inside of the 68” Strata sleepers
■ 60, 80 & 100k injectors ■ 38.1 mm to 73 mm coil tubing strings ■ Medium & HD trailer units ■ Reel trailer ■ 4 1/16" and 5 1/8" 10K Quad BOP’s ■ Medco and Cerberus/Orion systems
Applications ■ Well injection ■ Cased-hole testing ■ Workover pumping ■ Mud displacement ■ Wireline pumpdowns ■ Pumping down coil tubing
Pickers Picker Specifications ■ 1-30 m articulating boom 30 tonne ■ 2-30 m boom 35 tonne ■ 2-30 m boom 45 tonne
Applications ■ Clean-up and removal of fracturing and produced sand, scale and wax ■ Cement and stimulation fluid placement ■ Drilling in vertical or horizontal wells ■ Milling and under-reaming operations ■ Velocity string installment ■ Placement and retrieval of production plugs, packers and retainers ■ Casing and tubing scrapers, junk baskets and gauge rings ■ Perforating with E-line strings and pressure activated ■ Logging with E-line strings ■ Fracturing
P.O. Box 584, Red Deer, AB T4N 5G1 Phone:
Fax: 403-347-7728 Email: firstname.lastname@example.org
Learn-Rite Courses Inc. Protect your site—Learn-Rite
earn-Rite Courses provides industry safety training courses focusing on the oil and gas industry, with classroom facilities located in Grande Prairie and Wabasca. Learn-Rite offers a full slate of courses needed in the oilfield, from Enform’s H2S Alive (offered every day) and St. John Ambulance’s Standard First Aid to PST in a classroom setting. Other courses offered include General Oilfield Driver Improvement (GODI), Commercial Driver Hours of Service & Fatigue Management, and Confined Space Entry and Basic Rescue. Learn-Rite now employs two Enform-certified Detection and Control of Flammable Substances instructors. Learn-Rite’s Ground Disturbance Standard 201 Supervisors course is 94
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accredited by the Alberta Common Ground Alliance and is one of the first to be accredited by the ABCGA. Learn-Rite is very proud of that achievement, since Learn-Rite’s ultimate goal is to provide the best-quality instruction and training courses possible. Learn-Rite’s owners Penny and Doug Currie have, since purchasing the company five years ago, built a new 10,000-square-foot building, which has six spacious, bright classrooms and a mobile confined space trailer, which enables the company to take its Confined Space course to the company’s site. Learn-Rite is always interested in hearing from the industry as to what training is required, and then it develops high-quality courses to meet this demand. It just recently
introduced a course on Vacuum Truck Safety procedures that was developed by one of its contractors, who has had many years of experience operating a vac truck. “Most of our instructors all have oilfield experience behind them, and they are very knowledgeable,” Penny Currie says. “If somebody comes and says ‘We need a course about this,’ I’ve got the guys who can develop it.” Students say the classes are fun and enjoyable, and have high praise for their instructors. “We’re almost like a family here,” Currie notes. “Every one of the instructors cares about what they’re teaching, and they care about the students. If an individual has problems with, say, reading or writing, our
instructors will take the time to get them through the course.” Learn-Rite does its best to accommodate everyone’s needs and schedules. And it does not cancel classes because of a lack of enrolment. “These are guys who book a day off from work and are taking time away from their schedule to make the class, so they are going to have their class,” Currie says. She emphasizes that Learn-Rite’s courses are just the start of the safety training process for course participants. “It is the employer’s responsibility to carry on with training that is site-specific. It is their responsibility to make sure their employees are competent.” Learn-Rite Courses is all about helping workers be safe. “One of the biggest things about us is it’s not all about making money,” Currie says. “We care about the people that come through these doors. We want everybody to come home safe at the end of the day.”
Learn-Rite Courses Inc. Protect your Site - ˝Learn - Rite˝
New Course Vacuum Truck Safe ty
Serving the Peace Region Since 1996 • CLASSES ARE NOT CANCELLED BECAUSE OF LACK OF STUDENT REGISTRATION • ALL BASIC SAFETY TICKETS IN ONE WEEK • DAILY H 2S ALIVE CLASS • WHMIS • TDG • MOBILE CONFINED SPACE TRAINING UNIT • ST JOHN STANDARD FIRST AID & BC LEVEL 1 (5 CLASSES/WEEK) • GROUND DISTURBANCE SUPERVISOR LEVEL 201 • ACCREDITED BY THE ALBERTA COMMON GROUND ALLIANCE • DETECTION & CONTROL • FALL PROTECTION • GODI • COMMERCIAL DRIVER HOURS OF SERVICE (LOGBOOK) & FATIGUE MANAGEMENT
10129-128 Ave Grande Prairie, AB T8V 1X9 PH: (780) 532-0353 Fax: (780) 532-5153
• PST - IN HOUSE (CLASSROOM) • ONSITE TRAINING AvAILABLE
toll Free: 1-888-532-0353
2746 Strawberry Lane Wabasca, AB PH: (780) 891-7223 Fax: (780) 891-3089 P R O F I L E R M A G A Z I N E . C O M
LYNX CREEK STEAMING & OILFIELD SERVICES LTD. If you’ve got a job to do in the Deep Basin, Lynx Creek is just a call away
ynx Creek Steaming and Oilfield Services has grown from the previous owners into a diversified multi-service company, providing everything from steaming, vac trucks and tanking services to road construction and maintenance. Lynx Creek serves the mining, forestry and oil and gas industries in the Hinton, Edson, Grande Cache and Jasper areas. “We offer a multitude of different services. If you’ve got a job to do, we are just one phone call away,” says Lynx Creek president and owner Mike Radley. Serving regional industries since 2006, Lynx Creek seeks to meet its clients’ diverse needs in all local industries. Lynx Creek’s dedicated staff of approximately 35 employees, all based out of Hinton, are experienced and trained operators who are committed to helping customers work more efficiently and profitably. The company operates year-round a variety of different services and equipment: • mobile steamer units • combination steamer/vac units • water/gravel/sand trucks • lowbeds and winch tractors • graders/excavators/dozers • hydro excavation units • portable toilet services “Our company’s goal is to meet or exceed customer expectations in all ways,
right from our highly qualifi ed, safety trained and orientated operators to our professional billing services. Lynx Creek is an innovative, family-owned company with grounded roots that cares about our staff and their families,” says Lynx Creek offi ce manager Trena Radley. Safety is an integral part of daily operations at Lynx Creek, whose goal is to protect employees, clients, property and the environment. Lynx Creek is COR certified and maintains top grade ISN, PICS and ComplyWorks memberships. As a growing company, it is always looking for new and innovative ways to meet customers’ changing needs and requirements. The company, which uses products that are better for the environment wherever possible, saw a need for an effective yet environmentally friendly way of cleaning. Enter dry ice blasting. Lynx Creek is the only company in west-central Alberta to provide dry ice blasting, which is a non-toxic byproduct of other industrial processes. “It is very clean, which is also important to our clients. There is no secondary waste,” Trena says, noting that Lynx Creek has the most up-to-date equipment to make its own fresh dry ice pellets used in the procedure. For more information, please visit the Lynx Creek website.
Dry ice blasting does not produce CO2 or add CO2 to the atmosphere. Dry ice blasting means that worker exposure to chemical cleaning agents is reduced or eliminated, and it inhibits mold and bacterial growth. An approved medium by the U.S. Environmental Protection Agency, the U.S. Department of Agriculture and the U.S. Food and Drug Administration, dry ice “is an environmentally safe form that is very similar to sand blasting, but with none of the environmental fallout,” Mike notes. “With sand blasting, you’ve got sand and contaminants to clean up after the fact. Dry ice is much cleaner. When you blast something with dry ice, all of the surface contaminants you are trying to remove come off, and the ice evaporates. Dry ice is definitely the way of the future.” For all of your oilfield services needs, Lynx Creek is ready to help. “We are always expanding, always looking for new and different ventures to take on,” Mike says.
FAST FACTS LYNX CREEK STEAMING & OILFIELD SERVICES LTD. T: 780.865.5039 E: email@example.com
• Hydro Excavating
• Rubber Tired Backhoe
• Complete Non-Destructive
• Water Trucks/Dump Trucks
• Water/Gravel/Sand Trucks
• Combination Steamer/Vacuum Units
• Mobile Steamer Units
• Plant Turnarounds
• Rig Cleaning Big or Small
• Rig Tank Cleaning
• Dry Ice Blasting
• Frac Line Cleaning
• Tank Trucks
• Spill Cleaning/Recovery • Compressor/LSD/Wellsite Shack Cleanup • Portable Toilet Services • Lowbeds & Winch Tractors • Oilfield Road & Lease Construction • Graders/Excavators/Dozers IN
H E A LT H
24 Hour Dispatch 780.865.0329
H E A LT H
Get ready to work.
Office: 780.865.5039 105 Willets Ave Hinton AB T7V 1Z1 Serving Hinton, Edson, Grande Cache & Areas
www.lynxcreek.ca Email: firstname.lastname@example.org
NCS Oilfield Services Tried, proven, and completely unique completions solutions
CS Oilfield Services has built a strong reputation for delivering quality products that work reliably in the field. “We listen to our clients and provide them with a completions solution to meet their specific challenges,” says Don Battenfelder, NCS president, Canadian Operations, noting that NCS has brought three new products to the market in the past year. “They are tried, proven, and completely unique.”
sleeve can prevent that problem and allow the proppant to be better stabilized before opening the interval for production at some later time. Closeable sleeves can also be used for the management of water or gas production or injection, without the need for chemical treatments or cement squeezes. This functionality facilitates low-cost and low-risk well interventions over the life of the wellbore and helps maximize EUR.
NCS Closeable Sleeves When operators perform a frac treatment, there is a risk that some of the proppant that was placed into the formation could flow back into the wellbore, especially if cross-flow is established between frac stages. A closeable
J une 2 0 1 4
The Instafrac™ sub allows users to switch between abrasive jet cutting and hydraulic fracturing operations in a matter of seconds—without having to circulate a ball down to isolate the frac port during jetting
operations. This makes it very fast and efficient to add new perforations at any desired location and then immediately fracture the new targeted interval through the CTU string. The Instafrac™ tool is also functional in either a conventional NCS Grip-Shift frac sleeve completion or in a straddle frac operation using the new NCS MultiStage Unlimited SpotFrac™ system. NCS BallShift™ Sleeve The NCS BallShift™ Sleeve includes all the efficiencies of a ball drop system, together with all the benefits of a cemented wellbore. In completions where coil tubing reach limits the completion length, NCS’s new BallShift™ Sleeve allows placement of up
to 24 frac stages beyond the maximum depth of coil tubing reach. The BallShift™ Sleeve offers the ability to complete extended reach wells in the most effective manner possible, without compromising the number of frac stages available to the completion designer. NCS is very focused on doing the right thing for the rock; in their view, the reservoir itself determines the most appropriate completion method that is chosen. As NCS chief operating officer Marty Stromquist puts it: “We enable our customers to stimulate the rock based on their knowledge of the reservoir and to apply the best possible completion for their specific application.”
NCS’s commitment to excellence has been widely recognized. The company has been winning awards for having the best completion technologies available. In 2013, NCS won the Southwest U.S. Oil and Gas Award for Well Completion Company of the year. More recently, NCS was recognized by Alberta Venture as one of Alberta’s 50 fastest-growing companies, and in April, NCS received the Rocky Mountain Preferred Technology Award for Excellence in Well Completion. Oil and gas operators are clearly beginning to recognize the value of a flexible and reliable completions system that provides them with the means to truly “leave nothing behind” in the quest to realize the full value of their hydrocarbon assets.
FAST FACTS NCS OILFIELD SERVICES VP STRATEGIC BUSINESS: Eric Schmelzl T: 403.720.3236 E: email@example.com
NEW AGE OILFIELD SERVICES INC. Safety, quality control, customer service and competitive pricing drive New Age success
rom design and manufacturing to installation, New Age Oilfield Services Inc. is a high-quality one-stop shop that bases its success on safety, quality control, customer service and competitive pricing. Providing excellent quality and service has been New Age’s goal since the company first opened its doors a decade ago. New Age was the first company in Alberta to specialize in Downhole Chemical Injection Systems in 2004. “Our company has since added many complementary products and services, all based on customer requests, and will continue doing so,” says New Age Founder and President Mark Rhodenizer. New Age is a highly versatile, high-level service provider. They supply and install Accurate Downhole Chemical Injection Systems and Downhole Instrumentation, offer spooling services for Electric Submersible Pumps and Fiber Optic and Control Lines, provide Oilfield Transport and Picker Services, and more. “In many cases, the versatility of New Age makes us the one-stop shop,” says New Age business development specialist Cedric Vincendeau. New Age has since grown into a premier service company for the oil and gas industry across Alberta, Saskatchewan and B.C., and
holds long-term multi-service contracts with five of the major SAGD operators in Canada. As Vincendeau puts it: “Our success is based on our performance and our ability to satisfy customers with our products and services. New Age has many years of expertise within its team; this gives us strengths in different areas of the oil and gas industry. With this experience, we are able to look into specific applications and provide cost-effective solutions for our customers.” New Age’s head office and field operations are based out of a new state-of-the-art 12,000-square-foot facility in the Leduc Industrial Park. The company also has a sales office and manufacturing facility in Calgary. New Age is proud to say they are privately held and a 100% Canadian-owned and -operated company. New Age carries a large product line of inventory to support on-time customer deliveries. They are the Canadian distributor for Draka/Pyrsmian Group—Capillary Lines, Tubing Encapsulated Cable and Encapsulated Capillary Tubing. New Age is also Alberta’s largest distributor for Cannon Services products (Cannon clamps), providing complete sales, servicing and refurbishment.
“Over the past 10 years, New Age has grown from just a name to a well-known and trusted organization,” Rhodenizer says. “This was achieved through dedication, hard work and goal setting. One of our goals was to make a difference in the industry by creating innovative products and by offering competitive pricing and excellent customer service. All of this could not have been done without our valuable employees, who believed in the company and shared the same vision. We will continue on this same path, as our level of commitment to our customers.”
FAST FACTS NEW AGE OILFIELD SERVICES INC. T: 780.986.0155 F: 780.986.3086 Toll-free: 1.888.986.0155 E: firstname.lastname@example.org
7508-42nd Street, Leduc, AB T9E 0R8 Office: 780-986-0155 Fax: 780-986-3086 Email: email@example.com
OILFIELD SERVICES INC.
On Call 24 Hours Toll Free
Services • Specializing in removal & installation of ESP cables, injection/capillary lines & related components • Computerized alloy selection program available to assist in proper line selection • Temperature logging & observation well deployments • High-flow purging and computerized pressure testing • ESP & injection line combination trucks available • ESP & injection line combination rental skids available • Orbital welding • Custom spooling & banding • Cannon clamp installation, resizing & reconditioning • Oilfield hauling up to 34,000 kgs • Picker truck services • Hotshots
Sales • Large inventory of Capillary Line IN STOCK, including: 1/4”, 3/8” & 1/2” 316L SS, Duplex 2205, 825 Incoloy Other alloys available upon request • Custom-machined Injection Subs • Downhole Chemical Injection Valves & Burst Discs • Swagelok fittings, valves, gauges & tooling • Stainless Steel, Monel and Carbon Steel banding • Massive Cannon Clamp inventory • Downhole Instrumentation
Get ready to work.
P R O F I L E R M A G A Z I N E . C O M 101
PARK DEROCHIE 58 years of growth in service and excellence
n 1956, Merle Derochie and Jim Park started up a commercial painting firm in Calgary; shortly thereafter, Merle recognized the opportunities in Industrial Field Coatings, which soon became Park Derochie’s primary focus. In 1973, Park Derochie added Industrial Fireproofing to their services and became a name the industry looked to for their coatings and fireproofing requirements. Under Merle’s stewardship, and with the addition of Jeff Granberg in 1997 and Mark Walker in 1999, Park Derochie expanded into metalizing, shop coatings, and stickbuilt shop fireproofing. With the addition of our shop/office facilities in Fort McMurray, Saskatchewan and B.C., Park Derochie has grown to be the largest shop/field coatings and fireproofing company in Canada. Driven by fulfilling client needs, Park Derochie expanded into Mechanical Insulation in 2005 and Scaffolding & Containment in 2010. Recent expansion includes PD Management & Services Inc. and PD Properties & Rentals Inc., which has the largest inventory of field equipment in the industry (approximately two to three times the amount of its nearest competitor). It’s a classic business success story: organic growth built on a reputation of honesty and integrity, growing at a sensible and sustainable pace, spotting opportunities along the way and being driven by fulfilling client needs. As the range of services expanded, so did the projects. In 2010, Park Derochie’s coatings division completed the $19-million Enbridge 102
Hardisty Tankage Project. This is the largest tank-coating project in Canada to date. One particular Fireproofing project had over 19,000 pieces of steel, weighing over 10,000 tons, from six different fabricators going to nine different locations. Associated logistics handling challenges led to more innovations to accommodate customers’ needs. “So we created an in-house IT team to develop a tracking system that would address those challenges,” says Granberg. This sophisticated piece-tracking database was the first of its kind in the industry, allowing tracking and coordination of individual piece marks using barcodes and scanners. Additionally, clients are provided with a web-based interface that enables them to conduct status and shipping inquiries. While most companies work with purchased software packages that have limitations, Park Derochie’s software development team has the ability to customize its proprietary software to meet the reporting requirements of the client. One such development is a Time & Billing system that provides clients with daily Labour, Equipment & Material (LEM) reports. An extended version of the LEMs can be simultaneously emailed to the client to provide running cost values as often as the client wishes. “This type of reporting is critical for clients maintaining schedule and budget,” says Granberg. As these features developed, so did the company’s internal culture, which grew on close attention to safety, quality control and award-winning community involvement;
contributing regularly to numerous sectors including school programs, youth sports, health foundations, charities and community programs. These have recently included $50,000 to the Saskatoon Children’s Hospital and $24,000 to the Brick Sports Central. Health, wellness and professional development of employees are integral parts of the culture too. The head office in Edmonton provides an on-site gym and cafeteria and offers the services of a registered dietician. Park Derochie promotes, encourages and financially supports continuous learning for all employees. There are a number of programs that, while most companies believe they are assets, do not encourage or assist their Foremen to actually take the courses. PD not only encourages enrolment in these programs when union halls do not provide the training, they will set up the courses and pay for them. Some examples are NCSO (National Construction Safety Officer), CAS (Coating Application Specialist), NACE (National Association of Corrosion Engineers) Certification programs, LSE (Leadership for Safety Excellence), First Aid and Lead Abatement. As a result of continuing efforts in education, training, quality and safety, Park Derochie has achieved SSPC QP 1, 2, 3 and 6 certifications. This makes PD the only Canadian company to hold all of these certifications. Park Derochie is proud of its unique corporate culture. It matches what the company was built and grew on: strong work ethic, commitment to customer satisfaction and development of a skilled, dedicated workforce. That culture will continue to build and lead the company forward. “We are always looking at ways we can improve and continue to look at expansion,” says Granberg.
FAST FACTS PARK DEROCHIE T: 780.478.4688 F: 780.475.9832 E: info@ParkDerochie.com
CANADA WIDE SERVICES ALBERTA
Abrasive Blasting UHP Water Jetting Industrial & Commercial Painting Tank Linings Pipe Coating Underground Pipe Metalizing Lead & Asbestos Abatement Polyurea & Polyurethane Corrosion Under Insulation (CUI) Secondary Containment All Types of Fireproofing Process Pipe & Equipment Insulation Urethane Foam Insulation Scaffolding Maintenance Services NACE Inspection & Consulting
Hydro Mining Petrochemical Oil & Gas Industry Pulp & Paper Process Plants Potash & Coal Mines Power Plants Bridge Structures Railcars Offshore Drilling Platforms
QUALITY & SAFETY: SSPC QP 1, QP 2, QP 3 & QP 6 Certified Gold Seal Certified (CCA) NACE Inspectors & Technologists on Staff Award-Winning Industry Leaders in Safety
PEREGRINE PRESSuRE TESTING LTD. Under pressure, under control
t Peregrine Pressure Testing, safety is the No. 1 priority. Incorporated in 2006, Peregrine provides services to the oil and gas industry throughout northern British Columbia, the Northwest Territories and northwestern Alberta. The company started out with five pumping units and has since grown that number to a fleet of 14 units running state-of-the-art equipment that Peregrine designs and builds itself. “We are a very progressive company that is looking to grow,” says Peregrine operations manager Bob Brown. With a main office in Fort St. John, B.C., and a shop in Fort Nelson, Peregrine operates a variety of units, with operating pressures to 105,000 kPa (15,000 PSI) and pump rates to 400 litres per minute. The company offers a wide range of pressure testing, including blowout prevention systems, plant and facility testing, pipelines, formation integrity tests, formation leak off tests, micro fracs and hydrology tests. All of Peregrine’s units come equipped with a full range of test subs, crossover subs, cup testers, flow meter, digital deadweight, standard gauges and Barton chart recorder for backup. Additionally, all units feature a state-of-the-art digital computerized charting and recording system, first developed by Peregrine in 2006. The computerized charting and recording system can record truck pressure, remote pressure, pumping rate, volume pumped and temperature, and operates together with a secondary backup charting system. “We store all the data at the office, so if there is ever a question down the road, we can pull all the data and show them by the second the items that were tested,” Brown says. “If there are well control issues, you have digital backup to show that tests were done to the correct pressures and timelines.” All data can be exported in Excel format. Simply clicking on the exported chart will provide you with the information you need. Peregrine—which is now expanding the work it does on the pipeline testing side—is experienced with pipe up to 36 inches. The company has done pipeline pressure work as far north as the Norman Wells area and as far south as Hope in southern B.C. 104
“we are a very progressive company that is looking to grow.” — Bob Brown, operations manager, Peregrine Pressure Testing
Additionally, “with all the LNG talk coming on board, the future looks very rosy—but we’ve got challenges like everybody else,” says Brown, who has more than 26 years of experience in the pressure testing industry. Staffing is an issue: finding, training and retaining good people. “For our business, it takes a lot longer to train somebody to do the type of work we do because it’s so specialized.” Peregrine offers an intensive employeetraining and mentoring program to staff members, many of whom have been with the company since day one. When hiring testing truck operators, Peregrine looks for people with an oilfield background, with all of the required oilfield tickets, drilling rig experience and previous pressure pumping experience. “Our guys work alone, so they have to be a take-charge kind of person,” Brown adds.
Peregrine offers a full benefits package and extremely competitive wages. Peregrine Pressure Testing, which carries full liability insurance, is COR certified and is registered with ISNetworld, ComplyWorks, and PICS, as well as with WorkSafeBC and the Alberta Workers’ Compensation Board.
FAST FACTS PEREGRINE PRESSURE TESTING LTD. OPERATIONS MANAGER: Bob Brown T: 250.787.8662 E: firstname.lastname@example.org
HigH Pressure/ HigH volume rates
to 275 lPm at 69,000 KPa
105,000 KPa BoP unit
90 lPm at 105,000 KPa Call us today at:
250.787.8662 Email: pptbob@tElus.nEt Fax: 250.787.8664 box 6622, Fort st. John, bC V1J 4J1
RAPID ROD SERVICE LTD. your oil production optimization specialists
the Texas market, where it’s working with a client to introduce continuous rod solutions to that region. As part of Rapid Rod’s continuing growth path the company will form part of an overall production optimization platform for Pelican Energy Partners LP, a private equity firm headquartered in Houston and specializing in oilfield service investments that has been the
“our job is to work
apid Rod Service Ltd. is a leading provider of artificial lift maintenance services in western Canada and in Texas. Founded in 2008, Rapid Rod Service is a Calgary-based private entrepreneurial company in the continuous rod service business. Highly responsive to customer needs, Rapid Rod serves customers across Alberta in Peace River, Drayton Valley, Red Deer, Brooks and Taber, in Carlyle, Sask., and in San Antonio, Texas. “We have a solid degree of technical expertise at the field level, and our whole focus is around providing a quick response to client needs,” says Rapid Rod CEO Lou Doiron. “What Rapid Rod does intentionally with our clients is focus on production optimization. Our job is to work with clients to find solutions to optimize oil production from their wells.” This can help companies reduce costs significantly through the choices they make, in terms of choosing the right products for the right application for their wells. When helping clients, Rapid Rod provides all of the standard solutions. At the same time, designing specific solutions for specific requirements makes up a larger part of what the company does.
“In our mind, every well is different and requires a specific assessment as to what the best application is to enhance production,” Doiron explains. “We don’t profess to come to you with packaged solutions. We prefer to cater a solution to every customer and every customer’s requirement.” To this end, Rapid Rod offers a great deal of flexibility in working with the customer to solve any problems that might occur. “It’s really the strategic conversations around the best application of the products and services that we offer.” Rapid Rod was founded in 2008 in Brooks, Alta., by two local entrepreneurs, Dean Halifax and Justin Clingman. Over the years, Rapid Rod has grown from one rig when it first opened its doors to 16 rigs today. While the ownership structure has changed, the company is still privately owned and is heavily focused on customer service. Currently, Rapid Rod is working on a large new well development with a major heavy oil producer in the Peace River Arch region. Rapid Rod is seeing significant growth this year and is starting to make significant investment in new rigs, with plans to add four rigs by the end of 2014. A large focus in terms of the company’s growth footprint is in Texas. Last December, Rapid Rod added one rig into
with clients to find solutions to optimize oil production from their wells.
— Lou Doiron, CEO, Rapid Rod Service majority owner of Rapid Rod since June 2013. Pelican Energy Partners—where Doiron is Vice President, Operations—is now focused on developing a suite of products and services through individual companies to build a production optimization business across North America. The goal is to provide a bundled suite of services to clients through associated individual companies that are keenly focused on their areas of expertise.
FAST FACTS RAPID ROD SERVICE LTD. CEO: Lou Doiron T: 403.861.7799 E: email@example.com
Complete Rod Service
Servicing Continuous & Conventional Sucker Rod Pump Changes • Pressure Work • Surface Equipment • Repair Broken Rods • Complete with Fishing Tools and Rod Tongs • Coiled Rod Sales
Welding Truck • Repair Broken Rod • Pin End • Elliptical Rod • Tapered Strings
Truck Mounted X-Cellerator All New Equipment • Slant Capable X-Cellerator Can Be Used with Service Rig or Flushby Run/Pull New and Used PROROD/COROD All Safety Programs in Place • 24 Hour Service
RICK’S OILFIELD HAuLING Success bred from experience
ick’s Oilfield Hauling specializes in the transportation of light and heavy crude, condensate, and produced and fresh water. Centrally located in Redwater, Alberta, Rick’s Oilfield Hauling was founded by Rick and Verna Badry nearly three and a half decades ago, in 1979. The privately owned company started out with one tandem axle tank truck, run by Rick, who spent a great deal of time away from home working on the rigs. The company’s first driver was Rick’s brother Dennis, who is still here, now holding the position of truck push. Today, with approximately 100 units, Rick’s Oilfield Hauling is a father-and-daughterrun business, with a dedicated team in the field, on site, in the shops and in the office. “Every staff member plays a role in the company’s success,” says vice president Robindawn Badry. The company fleet consists of approximately 70 Super B trailers, primarily used to transport heavy and light crudes, as well as condensates and diesel, servicing Alberta and Saskatchewan. Thirty other units include tandem trucks, pups, quads, tri-drives and tridem trailers, which mainly service the areas surrounding Redwater in field production emulsion and produced water hauls, service rigs, drilling rigs, frac jobs and forest fire protection services. Rick’s Oilfield Hauling runs and hires company units and drivers, as well as owner operators, for both local and highway positions. It has access to numerous transloading facilities, pipeline terminals and clean oil battery sites throughout the region. Rick’s Oilfield Hauling is known for its service. “Service is key in this industry,” Robindawn says, noting that everyone in the company’s management team has a trucking background. “We believe that success has a lot to do with experience.” And for Robindawn, who has big dreams for the company’s future, a tremendous gift was the experience she received from her dad, starting from the ground up.
Equipment is new, clean and well maintained. Rick’s Oilfield Hauling has a dedicated heavy duty mechanical staff and shop facility, as well as a fully staffed wash bay. “If there is one thing Rick likes, it’s clean equipment,”
A recently executed deal between Rick’s Oilfield Hauling and Christina River Dene Nation Council, a working-in-partnership program with Métis, has both parties looking forward to an exciting future.
says Robindawn. The company offers its truck and trailer wash services to owner-operators working here as well. “Professionalism shows though the quality of our services and the productivity of our people,” Robindawn notes. “Some of our employees have been with us for 30-plus years, which speaks volumes.” Rick’s Oilfield Hauling has significant growth plans for the future. “Obtaining and maintaining our COR, being part of the Partners in Compliance program, as well as being members of ISNetworld and ComplyWorks as we do our best to keep up with changing industry demands, is something we take great pride in,” Robindawn says. “It shows through our employees, dayto-day tasks and accomplishments. Safety should never be taken lightly.”
Rick’s Oilfield Hauling makes regular donations to the local community and surrounding areas, in particular to school programs, sporting teams, fundraising events, the Stollery Children’s Hospital Foundation and animal rescue societies.
FAST FACTS RICK’S OILFIELD HAULING PRESIDENT: Rick Badry E: firstname.lastname@example.org
VICE PRESIDENT: Robindawn Badry E: email@example.com T: (780) 942.2025
24-hour service specializing in the transportation of petroleum crude oil and condensate insulated and sour sealed trailers tandems, tridems, super bâ€™s, mud buggy, mud crawler serving Alberta & saskatchewan
AdministrAtion office 4606-51 Ave. East Redwater, AB T0A 2W0
dispAtch & sAfety Phone: 780-942-2932 Fax: 780-942-2035
Safety and Environment â€“ Our #1 concern.
IRP 16 Get ready to work.
WORK SAFE A L B E R TA
SPECIALIZED DESANDERS INC. Desanders stop sand before it stops you
ormerly known as Specialized Tech Inc., Specialized Desanders Inc. underwent recapitalization in September 2013 to obtain the financing required to rapidly grow its business. With more access to capital, the company is now carrying out an aggressive plan to double its fleet of high-pressure desanders within three years, while expanding into new markets including the U.S. The company, which changed its name to Specialized Desanders Inc. (SDI) in December 2013, is currently establishing its presence in the Marcellus Basin in the northeast U.S. SDI is exclusively focused on providing engineered solutions to remove particulate matter from high-pressure, multi-phase flow streams, primarily from gas and liquids-rich gas wells. “Our top priority, bar none, is safety,” says SDI Vice President Craig McDonald. All equipment is certified and ABSAregistered to ASME Section VIII, Div 1 and ASME B31.3 codes. Operators and owners can rest assured that for SDI, the safe operation of the pressure equipment takes priority over being the lowest-cost or lowest-bid provider. In more than 12 years of desander service, SDI has not had a pressure equipment failure. The trend to drilling long, horizontal wells requiring multiple frac stages has fuelled rapid growth in demand for SDI’s patented horizontal desanders. Clients’ targeting of liquids-rich shale deposits, which rely more on hydraulic fracturing processes, has been a big driver of the company’s recent growth.
Producing frac sand during well cleanup can damage surface equipment, and as the pressure decreases over time, the velocities of the gas-liquid mixtures actually increase, resulting in even more erosive fluid flows. From the earliest days of production, SDI desanders operate with negligible pressure drops to ensure safe operation of the surface facilities—while capturing the maximum amount of production during the well’s initial high productivity. These desanders have been designed to operate over wide flow rate ranges, meaning they can remain effective over a long period of time—yet their best effi ciency is at the earliest stage of production, when the flowing pressure is highest. Removing all particulates, even after a well has been cleaned up following a frac, protects downstream assets such as chokes and valves and reduces the repair and maintenance costs associated with high velocity flow streams. Founded by three energy sector veterans in 2001, SDI opened its doors in Three Hills, Alta., and later added an operations base near Grande Prairie, Alta., in order to better serve its clients. Today, SDI’s clients cover a large geographical area in the Western Canadian Sedimentary Basin, stretching from Calgary to Fort Liard in northeastern British Columbia. SDI continuously monitors the location of its equipment fleet using GPS tracking. Thanks to web-based monitoring, it can even
advise operators on when the desander requires servicing. From day one, the SDI founders wanted to provide clients with a fee-for-service business, for a fixed monthly charge covering all of the costs involved. This continues today with SDI’s pricing structure. Most, if not all, of the technical support, regulatory filing requirements, certifications and normal wear-andtear costs are covered in the monthly service fee. The only variable costs that customers pay are related to equipment transportation and tie-in. Don’t be surprised by sand flows—call for a desander today.
FAST FACTS SPECIALIZED DESANDERS INC. CALGARY T: 403.233.2040
THREE HILLS T: 403.443.5453
GRANDE PRAIRIE T: 780.897.8140 E: firstname.lastname@example.org
SPECIALIZED DESANDERS INC. Multiphase Desanding Services – since 2001 – SDI’s patented equipment is installed upstream of the customers’ surface equipment to remove sand from produced gas and liquids. The desanders allow gas wells to be flowed under sand producing conditions that would otherwise be damaging to production equipment! CALGARY OFFICE
#111 3355-114 Ave SE Calgary, Alberta T2Z 0K7 Bus: 403.233.2040 Fax: 403.279.6915
Grande Prairie 780.897.8140 Ft. St. John 250.793.5140 Three Hills 403.443.5453
SPECTRuM WIRELINE SERVICES LTD. your critical sour services specialists
pectrum Wireline is a complete provider of wireline services, including cased hole logging and perforating, pipe recovery and slickline. With quality equipment and highly experienced personnel, Spectrum Wireline specializes in critical sour services and is also price-competitive with customers’ sweet well needs. When you call on Spectrum Wireline, you’ll have a supervisor and crew who work on critical sour wells, each and every day. “What sets us apart is that we deal with these well conditions daily,” says technical sales manager Peter Knight. “This is what we do, and we do it very well. We have a lot of experience. Our field supervisors have a minimum of five years, and up to 35 years, of field experience.” Established in 2006 by President Tom Wearmouth and Vice President Jaycne
Bischoff, Spectrum Wireline provides slickline and a number of logging and perforating services, which can be performed with its standard or H2S lines. The company, which operates in central and southern Alberta, with bases in Pincher Creek, Airdrie and Blackfalds, prides itself on its strong safety record. Spectrum Wireline has gone three years for its main client without a lost-time injury. “It’s a good environment with good equipment,” Knight says, noting that all of the company’s pressure control gear is high corrosion resistant NACE standard. The company has just built a new cased hole combination unit with a 5/16-inch sweet line, a 7/32-inch sour line, and a 0.125-inch and a 0.150-inch GD-31 stainless line. “It’s an all-around truck,” Knight says, who notes that with this premium unit, Spectrum
Wireline can do very competitive work for all of its customers. Spectrum Wireline is continuing to add new and innovative services. Recently, the company acquired a radiation licence for cased hole analysis tools, providing open hole quality logs in a cased wellbore. Spectrum Wireline is now working with one of its vendors to develop an arming chamber, which will allow them to select fire tubing guns down to two inches and run explosives in tandem. Testing is taking place this spring. “Doing it like that, we can save a customer up to four to eight hours a day because they don’t have to trip pipe in and out of the hole,” Knight says. “They can leave their tubing in the well, and we can drop through the tubing and perforate the casing, minimizing abandonment costs.” Thanks to a satellite communications dish, Spectrum Wireline is able to stay in touch with customers whenever required, even in remote locations like the Foothills. Additionally, the company’s large database can transfer files of up to 200 gigabytes, which can be directly shared with clients at the click of a button. Spectrum Wireline is growing and is looking to build new locations in order to better serve its customers. The company is also looking for experienced people seeking an exciting career opportunity. This is an attractive place to work, according to Knight. “We’ve done a good job of retention—I think that says a lot.” It all makes for satisfied customers, which is Spectrum Wireline’s ultimate goal. “My main goal, after we’ve done the job, is to have people feel they’re getting good value out of it—that they’re getting the best value they’ve paid for,” Knight says.
FAST FACTS SPECTRUM WIRELINE SERVICES LTD. TECHNICAL SALES MANAGER: Peter Knight T: 403.948.5031 E: email@example.com
24 HR WIRELINE SERVICE • CASED HOLE LOGGING & PERFORATING
• SOUR SERVICE
• SLICKLINE SERVICES
• PIPE RECOVERY
• ABANDONMENT SERVICES
Get ready to work.
H E A LT H
H E A LT H
aIRdRIE Ph: 403-948-5031 | CalGaRY Ph: 403-988-9758 PINCHER CREEK Ph: 403-627-5922 | BlaCKfalds Ph: 403-948-5031
TAK RENTALS INC. Your oilfield jobsite rental equipment specialists
AK Rentals Inc. is an Alberta-based oilfield rental company offering complete rental solutions across Western Canada. Dedicated to providing exceptional service and the essential equipment rentals required for your projects, in just a few short years TAK has developed a solid reputation for providing quality equipment, on-time deliveries and customer satisfaction. Established by President Tyler Luca in 2011, TAK provides services across Alberta, Saskatchewan and British Columbia. With locations in Red Deer and Grande Prairie, TAK’s cost-effective solutions are always there when you need them, and the company’s fleet of the latest equipment is regularly maintained by trained mechanics. TAK handles all surface rentals, with just one call. “It’s very convenient and efficient,” says TAK Vice President Jamie Moench, a former owner of JET Rentals, who joined TAK
in 2012, along with Superintendent Shane Moench. In 2013, Shane Mercer came on board as the company’s fourth partner and General Manager. All four owners run the company and work in the field, doing everything from setting up shacks to hooking up sewer lines, water lines and communications. With owners working and running the company, you get personal service. TAK has pioneered some of the latest equipment in the oilfield and designed its power combo (PC) units to meet an increasing need. They’re young, they’re growing and their main goal is to help TAK customers cut down on costs and help the environment. Pc units include all rentals that would normally be done separately, combined onto one 60-foot skid or one 24-foot trailer. The Pc units, which have been designed to save both time and money, include two generators, garbage storage, light towers, cell tower,
bathrooms and emergency showers, fresh water, septic containment, diesel, methanol and gas storage tanks. T units (trailer combo), for smaller jobs, are mounted on 24-foot trailers with his and hers bathrooms, 20kw light towers, 1,000-litre diesel storage, garbage storage, a junk basket and mixed waste bins for recycling. TAK will come to your site and set up your lease with shacks, power combo units, sewer, water, communications and lighting; they do it all. TAK’s efficiency cuts down on trucking, which is one of the major expenses in the oilfield. They will also save you time, in terms of reduced administration and billing. Tak also provides water/septic containment/treatment units that come in a 30-foot skid or a 24-foot trailer and hold 1,700 gallons of fresh water and 2,000 gallons of septic containment or septic treatment units. They are one of the first to put the water and septic together in a unit to save the consumer in trucking and rental costs. Tak also rents generators (20kw to 150kw), fuel storage (500gal to 2,000gal) and five types of shacks (Eng/Eng, Eng/Geo, Command Centres, Office/Day shack and Roughneck shack). For your communications needs, TAK rents individual cell towers on a trailer mount, rig radios, rig phones, satellite communication and cell boosters. TAK will rent you everything you require on location—“everything but the rig.” It’s what they’re known for. TAK will put a package together for the whole lease, so you only have one bill. You just have to make one call for all your rental needs.
FAST FACTS TAK RENTALS INC. VICE PRESIDENT: Jamie Moench T: 403.872.7444 E: firstname.lastname@example.org
coming Soon 24 ft trailer Million BTU Hotsy Wet/Dry Steam for your boiler needs and pressure washing on site
EquipmEnt & SErvicES Supplying Everything You Need But The Rig
20' Job Shack Fuel Storage Units Light Towers
Power Storage Units
Communication Systems Cell Towers
Eng/Eng Command Centres
Water Sewer Units
Shacks • cell towers • Light towers • combo units Working platforms • matting • Generators • pipe racks tanks • pumps • Septic Systems • Sewage treatment Systems
And more! Red deeR • GRande PRaiRie 24/7 dispatch: 403.872.7444 Toll Free: 1.855.872.7720
TERRAPRO GROUP OF COMPANIES Products, people and pricing drive mat company’s success
erraPro Group of Companies is all about products, people and pricing. The “3 Ps” drive everything that TerraPro is about. Headquartered in Sherwood Park, Alta., TerraPro is a remote-access mat solutions company for the energy sector, handling rental, sales and logistics. TerraPro helps customers gain access and protect terrain through matting, with an inventory of 50,000 mats that continues to grow. TerraPro mobilizes mats, putting them on the ground to the customer’s specification, then picking them up when the customer’s job is complete. TerraPro has worked hard to become one of the largest mat providers in western Canada. The fast-growing company is known within the industry for its efforts to go above and beyond for its clients. TerraPro has received a number of major awards in recent years. In 2011, the company was named one of Canada’s top new companies (number 15) by PROFIT magazine; in 2012, it was named one of Canada’s fastest-growing companies (number 9), and again in 2013 (number 4), by PROFIT magazine. “A big part of our success has been because of our goal to hit it out of the park with our customers on every job and to
maintain that personal contact with them as we continue to grow,” says Blain Davis, TerraPro sales and publicity specialist. Founded in 2007, the goal of TerraPro founders, vice president Colin Schmidt and president and CEO Richard Kulhawe, has always been to be innovators within the industry. TerraPro was excited to launch a state-of-the-art mat cleaning and disinfecting facility in Sherwood Park this past year. “More and more of our clients are under strict environmental scrutiny, and our mat washing system washes and disinfects mats at a never-seen-before rate,” says Davis. The company also sells mats and tracks matting inventory for its customers. Many large companies also have their own mat inventory, and when thousands of mats are involved, tracking where they all are at any given moment can be a challenge. TerraPro has developed a mat-tracking computer program designed to track not only its own mat inventory, but also the inventories of its customers. With 60-plus pieces of equipment and 75 employees, and continuing to grow, TerraPro is now offering a new state-of-the-art high-density plastic composite mat. “It’s ideal for environmentally sensitive areas because it’s easy to clean and disinfect,” Davis says, noting that TerraPro is expanding its footprint with this product, into Indonesia and Australia. The company is now offering energy sector reclamation as well. TerraPro will mat a location for a customer. Then, once the customer has finished up with the site, TerraPro will come in, remove the matting and do the reclamation required to bring the land back to its natural state.
TerraPro’s main storage yard is located in Sherwood Park, with additional yards in Lodgepole, Edson, Rocky Mountain House, Fort McMurray, Slave Lake and Grande Prairie, Alta.; in Kerrobert, Sask.; and in Virden, Man. Recently, TerraPro also expanded its office in Whitecourt to better serve that area. “We’re excited about the future of TerraPro. The company has grown through the support of our valued customers, our dedicated employees and our commitment to be innovators within the energy sector—not only here in western Canada, but beyond.”
FAST FACTS TERRAPRO GROUP OF COMPANIES SALES & RENTAL INQUIRIES? Toll-free: 1.855.255.MATS E: email@example.com
Group of Companies
Where you need it....When you need it The BeST in the business at what they do
access matting / swamp mats / rig mats / matting sales / mat rentals / mat fleet management / matting services / 400 bbl tanks and sales rentals / composite matting / mobilization and demobe services / mat washing / mat transportation / oak mats / fir mats / hybrid mats
Edmonton / Calgary / roCky mountain housE / drayton vallEy Edson / whitECourt / grandE prairiE / fox CrEEk / Conklin / EstEvan
1.855.255.mats (6287) www.terraprogroup.com
Get ready to work.
THRU TUBING SOLUTIONS “We are a solutions company. A technically strong company. That’s what we pride ourselves on.”
hru Tubing Solutions (TTS) has been providing specialized downhole services and equipment to customers worldwide since 1997. Forged from the expertise of its seasoned field professionals and engineering staff, Thru Tubing Solutions has become the leading provider of thru tubing products and services in the industry today. With more than 20 locations and 500 employees strategically placed in major shale plays around the globe, TTS stands ready, day and night, with the specialized resources you need for downhole projects done right. The company’s operational head office for Canada is located in Red Deer, with offices in Calgary, Grande Prairie, Estevan, SK, and Fort Nelson, BC. TTS Drilling Solutions is located in Leduc which is a full-service facility providing xRV™ friction breaking tools and safety joints for the drilling industry. With the growth of horizontal drilling and completions, Thru Tubing Solutions is continually developing new technology to address the challenging demands these wells present, such as the xRV™ (x-Tended Reach Vibratory tool), the new HydraSet Jars for coil tubing fishing applications and the new F5 drilling 118
motor capable of high flow rates and maximum torque output. Serving the horizontal drilling market, TTS Drilling Solutions’ Casing xRV™ utilizes the same technology as the Drilling xRV™, which breaks the friction between the wellbore and drill pipe. The Casing xRV™ helps combat friction between the wellbore and casing or other completions being run in the horizontal leg and allows producers to successfully run their completions to TD.
TTS’s xRV™ technology allows coiled tubing and drilling rigs alike to reach deeper horizontal targets. “As producers continue to drill deeper wells with longer lateral sections, the challenge is to complete them successfully while mitigating the risk of casing buckling and helping to ensure the completion is not set in compression, so they can realize the maximum potential of the well,” says Rob Phillis, country manager for TTS Drilling and Thru Tubing Solutions. As the oil and gas landscape becomes increasingly demanding, TTS’s tools and services are meeting the challenge. “We are a solutions company. A technically strong company. That’s what we pride ourselves on,” says Phillis. “We are successful because of a group effort. If a customer has a problem, somebody in this company will have an idea that will work to solve it, and we’ll make it happen. The company listens to its employees and recognizes each one for what they bring to the table.” Phillis notes that Thru Tubing’s strength lies in its employees and the innovation that comes from their experience. “This is where our engineering group comes into play. They are a dedicated group whose main focus is improving and expanding our service offerings, and with the years of experience behind them, they are very successful at what they do.” The company’s continued strong growth, its worldwide drilling services division, and new developments in downhole tool technology are allowing Thru Tubing Solutions to expand its service offerings, as well as its ability to address the challenges of a rapidly changing oilfield.
THRU TUBING SOLUTIONS
TTS DRILLING SOLUTIONS
The XRV TM is a downhole vibratory tool which creates an oscillating axial force in the workstring. This oscillating force helps combat friction between the drillpipe and the wellbore which aids in moving the pipe in hole, reduces slip-stick, transfers weight to the BHA and improves tool face control during sliding. Improved sliding and tool face control during steering operations eliminates or decreases extra slide attempts ope saving time and improving overall ROP.
THE BEST TOOLS. THE BEST PEOPLE. THE BEST CHOICE.
DEMAND THE BEST.
DEMAND TTS. There’s only one name you can count on for downhole equipment and services that never let you down: Thru Tubing Solutions.
DON’T LET JUST ANYONE TAKE ON YOUR DOWNHOLE CHALLENGES. DEMAND TTS. WWW.THRUTUBING.COM
TRENDON Specializing in the design, manufacture and service of drill bits for Canada’s oil and gas industry
(L-R) Director of Sales Mike Keller, Director of Operations Dwayne Becker and President Robert Baldauf at Trendon’s head office in Calgary, AB.
leader in service excellence, Trendon’s focus has always been on creating a unique customer experience for the companies it serves. “Our focus is making sure that our sales, distribution and service model is customized as much as possible, for the unique drilling requirements of the Western Canada Sedimentary Basin,” says Trendon president Robert Baldauf. That model continues to evolve, based on the Trendon team’s several decades of industry experience. Initially focused on the gas drilling market when it first began operating over 10 years ago, Trendon moved into heavy oil and is now expanding further into SAGD exploration and development in the Fort McMurray area. “We’ve been able to evolve our market and business model by deeply understanding and adapting to the market’s unique requirements,” Baldauf says. “We’ve evolved drill bit design, technology and service into something that’s a little newer and unique.” To this end, Trendon has researched and developed a reverse circulation bit, a patentpending product, which has resulted in increased rates of penetration and faster completions for customers. Over the past two years, Trendon has refined its service model to reflect the unique issues that are part of the drilling marketplace. “It’s a just-in-time, 24-7 model,” Baldauf says. “That allows us to get to the
users very, very quickly. We have created a robust supply chain that ensures our suppliers are linked into what we’re doing, and we have an ample supply of product.” With 25 employees, Trendon operates four locations to service clients throughout Alberta and Saskatchewan, with distribution hubs in Lloydminster, Red Deer, Redcliff and Fort McMurray. The company boasts a lean management structure, with the president, director of operations and director of sales overseeing the company. The rest of the Trendon team works in service functions in both the field and in the shop. “Our field team and service teams have the training, tools and processes they need to ensure we manage and deliver our service model properly. They are the ones who are really responsible for making the service model work.” Safety is a key element of the service model at Trendon. Trendon meets the highest COR standards and other safety measures, dedicating significant time, effort and resources each year to ensure safety standards and certifications are in place. It’s no wonder that Trendon enjoys such a loyal customer base. In fact, the company has been doing business with many of the same customers for the past decade. “Because of our service model, we have the ability to service large clients, and also brand new, smaller clients who are just getting into the drilling game,” Baldauf says.
“With our position in the market established, our attention is on growth. We feel we have a solid base in the marketplace because of our commitment to service, safety and specialization. We have the ability to customize products and services for customers, in addition to our standard offerings.” “We think our market position is very strong. With the people we’ve put into place— on the management level and on the service side—we have every opportunity to be very successful over the next several years.”
DID YOU KNOW? With your needs and specifications in mind, Trendon designs, manufactures, sources and supplies a full range of PDC and tri-cone drill bits to support a range of drilling applications. Our expertise in every step of the service process ensures a quality product with exceptional attention to detail.
TRENDON T: 403.536.2772
WE ARE COMMITTED TO SAFETY AND SERVICE. IT’S THAT SIMPLE. trendon.ca
VALLEY MATS Providing rig mats at home and around the globe
lberta-based rig mat manufacturer Valley Mats prides itself on building high-quality steel-framed rig mats to meet customers’ exact needs. “The same pattern doesn’t fit everybody. We work with our clients to build what they need,” says Valley Mats president Johnny Wieler. “We always try to keep an inventory of the more standard-sized mats available for prompt shipment, but we do have the flexibility to produce whatever the customer requires.” In addition to manufacturing rig mats for the oil, gas and mining industries, Valley Mats also does custom fabrication, timbers and blocking. For one of its customers, a major oilfield camp manufacturer, Valley Mats also builds bunk skid units.
“We are very fussy with our quality. We make sure our quality is second to none.
— Johnny Wieler, president, Valley Mats
Valley Mats uses northern white spruce to fill all of the mats it builds. “The reason we do it is for strength,” Wieler explains. “Northern white spruce is one of the most highly recognized and highly sought after spruce on the market. Because it grows so far north, it’s very dense—it’s very high quality. “We do not use beetle-kill wood from B.C. Beetle-kill pine is cheaper, but we refuse to use it.” Valley Mats is owned by Wieler and his wife Joyce, who founded their company in 1999 as a lumber remanufacturing facility in La Crete, Alta., eight hours north of Edmonton and an hour south of High Level, Alta. After the Wielers lost their business in a fire in 2005, they rebuilt everything. The company diversified into the rig mat business in 2006, building exclusively for a major rig mat manufacturer, shipping mats as far away as Siberia. 122
In 2008, after the market crashed, Valley Mats got out of lumber remanufacturing for good. Now, its main market is rig mats. Valley Mats deals directly with end-users, selling to oil companies and other customers across Canada, the u.S., Mexico and overseas. Valley Mats can be found as far north as Alaska’s North Slope, to as far south as Australia. The company will handle projects both large and small: the smallest mat it has built was three by seven feet, and its largest project to date covered 6.5 acres. One of Valley Mats’ biggest selling points, Wieler notes, is that “we are very fussy with our quality. We make sure our quality is second to none, and we check that consistently. We have a good crew, and we are very competitive.” Valley Mats does more than mats: the company also works on a wide range of projects with Vertical Building Solutions, a Grande Prairie–based company that manufactures fabric and modular building structures. Valley Mats provides all of the matting and steel walls for Vertical Building’s fabric structures, prefabricating the mats and walls and shipping them to each site.
Valley Mats builds all of its mats indoors, in a heated environment, at an approximately20,000-square-foot production facility. “Safety is a very high priority at our shop,” Wieler says, noting that Valley Mats is certified with COR and the Canadian Welding Bureau, and is registered with ISNetworld. “We work very hard at making a good name for our product. I think the future looks very bright.”
FAST FACTS ASPEN VALLEY LUMBER LTD./VALLEY MATS T: 780.928.3880 Toll-free: 1.888.928.3880 E: firstname.lastname@example.org
VM Valley Mats
PRODUCTS & SERVICES Pipeline blocking Rig mats Camp mats Crane mats Concrete mats SPF timbers • Timbers available in sizes up to 20" x 20" x 20' • Will custom cut to customer’s specific needs
Custom fabrication & metalworking • Lathe – 22" swing x 78" bed • Milling machine • 100T press • Cutting: Plasma, Oxy/Acetylene, Bandsaw • Welding
Tell us what you require, and we can design and build to meet your specifications.
VENTURE PRODUCTION TESTING INC. Committed to safety, quality service and customer satisfaction
services and equipment offered include production testing, frac recovery, inline testing, line heaters, mobile separators, 40-, 60-, 90- and 120-foot flare stacks, incinerators, a web-based data system, and an electronic surface recorder.
enture Production Testing is committed to safety, quality service and customer satisfaction. Specializing in flush-by rigs and production testing, Venture Production Testing knows that customers want the best, and it’s committed to providing the best service possible to all of its customers. Venture Production Testing has two divisions: rod rigs and well testing. On the rig side, the company operates five rigs; on the well side, it has 10 well-testing packages. Centrally located in Red Deer, Alta., with a sales office in Calgary, Venture Production Testing has 60 employees, serving customers across Saskatchewan, Alberta and British Columbia. The company’s overriding goal is to help clients be more efficient and productive, while safeguarding personnel and the environment. Venture Production Testing, which can run on 75 per cent road bans, operates quality
new equipment that’s maintained on a regular basis. Services and equipment offered include production testing, frac recovery, inline testing, line heaters, mobile separators, 40-, 60-, 90- and 120-foot flare stacks, incinerators, a web-based data system, and an electronic surface recorder. The free-standing flare stacks, which can withstand 120-km-per-hour winds, cause zero ground disturbance. Hydraulic rams allow quick rig up, while the air/fuel igniter system eliminates the need for flare pens and minimizes fire hazard. Mobile separators are ideally suited for quick rig up, meeting customers’ varying needs, from completions to workovers and more. The company’s mobile incinerators reduce the emissions produced by hydrocarbon streams. These units are much more efficient than traditional flare stacks and greatly reduce environmental impact. Venture Production
Testing, which offers competitive rental rates and the ability to model hydrocarbon emissions for each application, works with customers to ensure there is minimal environmental impact on landowners. While Venture’s equipment is excellent, customer service is what really sets the company apart. In all that it does, Venture Production Testing prides itself on its safety commitment, which includes protecting people, equipment, materials and the environment.
FAST FACTS VENTURE PRODUCTION TESTING INC. PRESIDENT: Mark Crawford T: 403.343.8888
EQUIPMENT & SERVICES OFFERED • Production Testing
• Line Heaters
• Frac Recovery
• Flush-by Units
• Web-Based Data System
• Inline Testing
• 40, 60, 90, 120 Flare Stacks
• Electronic Surface Recorders
Red Deer, AB (Head Office) 24 Hour Office
(403) 343-8888 • Fax (403) 343-8900 www.ventureesi.ca
“Commitment to Safety, Quality Service & Customer Satisfaction”
WISE INTERVENTION SERVICES INC. Your wise choice for well interventions
“We really pride ourselves on establishing partnership-type relationships with our clients that are ongoing relationships where there is a mutual
ISE Intervention Services Inc. is driving to be the company that clients turn to for handling their downhole wellbore challenges. A high performance, results-driven well intervention services provider to the oil and gas industry in western Canada and northeastern u.S., WISE provides comprehensive well intervention service solutions designed to improve well intervention operations and optimize reservoir performance. WISE specializes in providing well/downhole service solutions by developing products, processes and services to work within the various stages of a well’s life cycle. WISE’s multiple small, highly experienced and specialized teams bring to the table the expertise that’s needed to effectively analyze, prepare and execute successful well intervention service applications. WISE develops products, processes and services to further advance well intervention, offering operators fit-for-purpose downhole solutions that serve as a toolbox for today’s complex wellbore intervention needs. Extended reach tools, milling tools, stimulation tools and coil tubing fishing tools—all are unique products with specialized features to increase quality and reliability, and address inherent downhole problems discovered over time. The fit-for-purpose component designs are suited to a wide range of well environments and ensure compatibility between completion and intervention BHA designs for effective low-risk downhole operations. WISE also provides fit-for-purpose technology designed for deeper, more technically
challenging wellbores. WISE’s ability to offer downhole products, integrated with high capacity coiled tubing conveyance solutions, supports a more efficient well intervention operation. WISE’s supply chain and industry network creates a collaborative partnership that extends outside of WISE itself and supports the company in its drive to deliver fi t-forpurpose solutions to the market. WISE’s revolutionary high capacity coiled tubing equipment—which has been designed to service today’s deeper, more complex wellbore designs—enables this, with capabilities of up to 25,000' (7,600m) of 2" tubing, and 20,500' (6,200m) of 2 3/8" tubing. It comes with conventional unit configuration for diverse operating functionality, and HR680 and HR6100 injector heads for reliability, high-performance operations and extended reach applications. WISE’s technological focus will yield new opportunities for E&P companies, allowing them to squeeze more out of their well assets. By extending a well’s useful life cycle, and improving the effectiveness of the completion process, E&P companies will be able to better exploit the commodity. They will need a smaller amount of land and less infrastructure and will produce fewer operating emissions. The end result is a reduced environmental impact while the resource is being recovered. Headquartered in Calgary and with operations in Red Deer, WISE is currently expanding
— Josh Thompson, president and CEO, WISE Intervention Services
to service more areas throughout North America. WISE is in growth mode and is looking forward to the start of LNG exports for the North American market. “We see a very active future for our company in those areas of the market,” says WISE president and CEO Josh Thompson. “We really pride ourselves on establishing partnership-type relationships with our clients that are ongoing relationships where there is a mutual benefit. We really strive to have that type of relationship with our clients and look forward to developing new relationships going forward.”
FAST FACTS WISE INTERVENTION SERVICES INC. SALES OFFICE: 1040, 540 5th Ave. SW Calgary, Alberta T2P 0M2 T: 587.538.0586 F: 587.538.0654 E: email@example.com
Need a well intervention solution?
Get Wise Today Deep-Ultra Deep Coiled Tubing Services Revolutionary coiled tubing equipment designed to service todayâ€™s complex wellbore designs. High capacity tubing capabilities of up to 25,000' (7,600m) of 2" tubing, 20,500' (6200m) of 2 3/8" tubing. Conventional unit configuration for diverse operating functionality. HR680 and HR6100 injector heads for reliability, high performance operations & extended reach applications. Regulation compliant 10K & 15K pressure control equipment and controls for safe functionality in all well conditions. On board work string management system for added safety features and cost reductions during operations.
High Pressure Stimulation Services Industry leading 10K pumping equipment for remedial pumping needs. Twin 600 HP triplex and 1000 HP quints for low to high rate / high pressure pumping needs for coiled tubing support, service rig support, snubbing support, multizone completion support and auxiliary frac pump support. Chemical add and mixing capabilities, data capture, data interface, simple controls, operator focused functionality, environmental regulation compliant.
Multi-Conveyance Downhole Services Intervention BHA equipment for coiled tubing or threaded pipe conveyance methods. A tool box designed for todayâ€™s complex wellbore intervention needs. Extended reach tools, milling tools, stimulation tools & coil tubing fishing tools. Unique products offering specialized features to increase quality, reliability and address inherent downhole problems discovered over time. Fit for purpose component designs for a range of well environments & compatibility between completion and intervention BHA designs for effective low risk downhole operations.
6779 65th Avenue Red Deer, Alberta T4P 1X5
1040, 540 5th Avenue SW Calgary, Alberta T2P 0M2
90 West Chestnut Street Washington County, Washington, PA 15301
Ph: (403) 340-8205
Ph: (587) 538-0586
Ph: (724) 225-5500
Fax: (403) 340-1046
Fax: (587) 538-0654
Fax: (724) 225-5511
Get ready to work.
w w w. w i s e i s i . c o m
Tracking the truckloads
What goes into an average extended-reach horizontal shale gas well with multistage-fracture treatment?
Early well-pad development (first well, all water delivered by truck) Based on average first well results in a multi-well pad in the Marcellus shale play in New York City.
Drill pad construction
Hydraulic fracturing equipment Fracturing water hauling
Final pad preparation
Produced water disposal
Total one-way loaded trips per well
Average number of workers per well
Number of different occupations involved in drilling one well
5 500 100 1,103
Sources: ALL Consulting; Government of New York
J u ne 2 0 1 4
YOUR SOURCE FOR: PUMPS Reciprocating, Centrifugal & Rotary ENGINES & MOTORS Natural Gas, Diesel, Gasoline & Electric HYDRAULIC SKID UNITS Available With Natural Gas, Diesel, or Electric JACKSHAFT SKIDS
Our service trucks are fully equipped for oilfield maintenance and our mobile and in house mechanics work on a 24/7 basis. We stock a fully supplied parts room. Call for information on whatever your needs may be, or if you have surplus goods in stock. We are always looking for buying opportunities to replenish our inventory. Together with you, our valued customers, we will keep Rotation growing. First and foremost of our goals shall be to provide complete and total satisfaction to our customers, in grateful recognition that this alone will spell success in all of our objectives, and further, to achieve a level of excellence in our products and services that will be seen as the standard that the industryâ€™s success will be gauged by.
Office: 306-823-4818 Fax: 306-823-4811 Visit our website at: www.rotationpower.com Email: firstname.lastname@example.org
19 9 4 - 2 014
Since 1994 Weaver Welding Ltd. has been providing pipeline and maintenance expertise to the oil and gas industry. Our view of business is simple: to provide high quality production efficiently, on time, and on budget, and maintain a safe, professional working environment based on mutual respect between employees, management, and clients. We look forward to serving you for the next 20 years!
Get ready to work.
W W W.W E AV E RW E L DI NG .C A