NOVEMBER 2012
resource
revolution
PM40069240
New technologies start a new cycle of oil exploration and development in western Canada
Operators expand tight oil potential in existing plays while pushing formation boundaries
The oilsands and tight oil get all the coverage, but conventional heavy oil remains an economic powerhouse
New tight oil plays moving quickly towards commercialization
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4 Resource revolution Operators expand tight oil potential in existing plays while pushing formation boundaries
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Heavy profits The oilsands and tight oil get all the coverage, but conventional heavy oil remains an economic powerhouse
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Future attraction New tight oil plays moving quickly towards commercialization
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Cover illustration by Anthony Tremmaglia PROFILERMAGAZINE.COM
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Operators expand tight oil potential in existing plays while pushing formation boundaries
resource
revolution By Darrell Stonehouse
Illustration by Anthony Tremmaglia
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N OV E M B E R 2 0 1 2
Cover Feature
F
ive years into the tight oil boom in western Canada, operators continue proving up their potential acreage while adding low-cost reserves through infill drilling and waterflooding in existing developments.
Work also continues on fine-tuning horizontal drilling and multistage fracturing technologies to maximize production and ultimate resource recovery. Just how much has the tight oil boom driven by multistage fracturing and horizontal drilling impacted western Canadian producers? The answer lies with two of the industry’s great success stories, Penn West Exploration and Crescent Point Energy Corp. Two years ago, less than two per cent of Penn West’s production came from wellbores using horizontal multi-frac technology, company president and chief executive officer Murray Nunns told the company’s second-quarter conference call. “By the end of this year, we anticipate 30 per cent of our production will come from horizontal multi-frac wells. These new light oil wells deliver significantly higher rates of returns in the long run. The value of this technology has added to our asset base and will only continue to grow in the future.” Bakken/Shaunavon Plays For Crescent Point, the company has drilled over 2,000 horizontal wells with multistage fracture treatments on its acreage across western Canada. Current production now hovers close to 100,000 barrels equivalent per day. Crescent Point is the biggest player in Saskatchewan’s tight oil developments, controlling over 1,100 net sections of land in the Bakken resource play and more than 800 net sections in the Shaunavon resource play. At the company’s annual meeting in June, president and chief executive officer Scott Saxberg said Crescent Point can double its reserves just through infill drilling at its Shaunavon and Viewfield properties. Crescent Point’s current proved-plus-probable reserves total 496.8 million barrels of oil equivalent. This includes year-end 2011 reserves adjusted for 2012 acquisitions and dispositions. Referring to the company’s total asset base, he said: “We believe right now—just through infill drilling and some waterflooding on existing assets—we have the potential to add over a billion barrels of reserves, above and beyond our current base,” Saxberg said. He said the company has $16 billion worth of development inventory and more than 7,500 future drilling locations—“all defined by 3-D seismic, geology and engineering.” Crescent Point—which is 91 per cent oil-weighted—is forecasting average 2012 production of 88,500 barrels equivalent a day, but has already surpassed that forecast. The company’s first-quarter output averaged a record 90,285 barrels a day.
In the first quarter, the tight-oil producer bagged $1.3 billion worth of acquisitions, and is forecasting 2012 exit production of 97,500 barrels a day. Crescent Point has a 2012 capital budget of $1.25 billion and plans to drill 408 net wells this year. The company expects to increase production to about 132,500 barrels a day over the next five years. That includes raising output from its Saskatchewan Bakken area to 74,000 barrels a day from about 60,000 barrels a day in the first quarter. Shaunavon production would shoot up to 35,000 barrels a day over the next five years, from 18,500 barrels a day in the first quarter. Saxberg noted the plan to grow to 132,500 barrels a day in five years doesn’t include any Bakken or Shaunavon waterflooding impact, and it doesn’t include any additional acquisitions or increased output due to future technology improvements. On the technology front, Crescent Point has fine-tuned its completions program to optimize production and ultimate recovery from its Saskatchewan wells. During its second-quarter report, company chief financial officer Greg Tisdale told analysts that Crescent Point has moved away from the 16-stage open-hole fracture treatments originally used to develop both the Bakken and Lower Shaunavon, to a 25-stage treatment using cemented liners. “Our 25-stage cemented liner wells are outperforming any of our previous completions and have lower initial declines,” he said. Industry success with multistage fracking in the Bakken in southeastern Saskatchewan now has some operators testing the technology in the Midale formation. While no results have been released, a number of operators have drilled test wells. Swan Hills/Slave Point Plays Moving into Alberta, the Swan Hills area has been a drilling hotspot as explorers begin developing tight oil plays in the Beaverhill Lake and Slave Lake tight formations. P R O F I L E R M A G A Z I N E . C O M
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Cover Feature
Penn West has been focused on the northern Alberta tight oil plays for much of 2012 with stellar results, chief operating officer and executive vice-president Hilary Foulkes reported to shareholders in the company’s second-quarter update. Penn West has moved to drilling dual lateral wells in the play to cut costs. “Results at Swan Hills are exceptional,” Foulkes said. “At East Swan Hills, we drilled seven wells this year. A recent completed dual-lateral horizontal well is particularly noteworthy. The first leg of the well had peak rates of 1,500 barrels equivalent per day and produced more than 24,000 barrels over a 24-day period. That makes the finger-math easy. The second leg tested peak rates of over 800 barrels a day. Our sixth of 15 wells has had peak rates of 1,950 barrels equivalent per day. This well has averaged over 650 barrels a day in the first month of production. Five other wells completed in 2012 are either producing at or above curve expectations currently. Planning is underway to increase our gas-handling capacity in 2013 to support an ongoing program in East Swan Hills. “In the Slave Point play, the Sawn Lake area continues to impress us,” Foulkes added. “We have a major facility upgrade which is expected to be on stream in the fourth quarter of this year, and this will allow us the capacity to accelerate activity, as we have a significant inventory in Sawn Lake supported by our very large land position. Our aggressive program in Otter is delivering as expected, and we are seeing successful gains and efficiencies with our most recent dual-lateral, drilled in two-thirds of the time we projected. This equates to a cost savings of $1 million.” Slave Point production has climbed to over 5,000 barrels equivalent per day. Cardium Play Penn West also continues spending in the Cardium. Penn West is the largest player in the Cardium trend with approximately 665,000 net acres. The company has added approximately 10,000 barrels equivalent per day, net of related declines, from its horizontal drilling and multistage fracturing programs over the last few years. Penn West is focused primarily in the Willesden Green, Alder Flats and West Pembina areas where the company says results have been strong and predictable. Penn West is in the development stage in the Cardium and is focused on cutting costs. The company reports efficiencies are improving across the Cardium play as it moves to a higher proportion of water-based fracture treatments, as drill times continue to shorten, and as cycle times on multi-well pads improve. Bonavista Energy Corporation is another major player in the Cardium, with 300 net sections of land. Bonavista drilled eight horizontal light oil wells targeting the Cardium during the second quarter. The company focused its efforts on prospective acreage at Harmattan where five horizontal wells were drilled. Like Penn West, Bonavista is in full-development mode, using slickwater fracture treatments and pad drilling to cuts costs. It reported a reduction of 10 per cent in costs in the second quarter. Bonavista has drilled 68 wells since commencing a horizontal Cardium development program, resulting in increased average-initialproduction rates and estimated recoverable reserves per well. Its inventory of 120 horizontal locations remains stable despite drilling activity to date, as the company continues to delineate its 300-netsection Cardium land base. 6
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TriOil Resources Ltd. is another Cardium producer. It continues experimenting with drilling and completion technologies to maximize production from the play. In 2011, the company focused on highdensity slickwater completion programs designed to improve reservoir breakdown, provide more effective fractures deeper into the reservoir, improve production performance and reserve capture, and reduce costs. The 20-stage fracture completions delivered 30-day initial production ranging from 125 to 190 barrels per day. In 2012, TriOil has upped the ante, drilling longer horizontals and implementing a new multistage fracturing program on its Lochend Cardium lands.
The hybrid fracturing design uses slickwater for the first half of the job, then uses gelled water for the remainder to give the frac better sand-carrying ability on long horizontals. “TriOil continues to optimize drilling techniques and completion designs,” company president and chief executive officer Russell Tripp reported in an October update. “Our last seven horizontal wells have all been drilled monobore with invert mud systems. Drilling times have been reduced by an average of four days. TriOil recently implemented hybrid fracs on two Lochend area wells with encouraging early results, and plans to apply these modified frac designs to future development drilling operations within the pool.” The hybrid fracturing design uses slickwater for the first half of the job, then uses gelled water for the remainder to give the frac better sand-carrying ability on long horizontals. TriOil successfully participated in the drilling of the first long-reach horizontal oil well (over 2,800 metres open in the Cardium A) in the Lochend region and completed the well with a 40-stage hybrid frac during the third quarter. After milling out the ball seats/sand blockages in the heel of the wellbore, the well tested at an average of approximately 630 barrels of oil per day over an eight-day production test period. The operator plans to bring the well on production in late October and produce the well for a few months to determine productivity from the milled-out heel section of the horizontal leg, prior to drilling out the toe section and bringing the entire wellbore on production. “We are encouraged by the early results of this well and plan to drill two additional long-reach horizontal wells in the first half of 2013,” Tripp reported. “With the effective utilization of multi-well pads, monobore drilling technologies, hybrid frac designs and long-reach horizontals at Lochend, we expect that production rates, recoveries and capital efficiencies will continue to improve.” Viking tight oil play Exploration and development also continues in the Viking tight oil play straddling the Alberta-Saskatchewan border.
Photos: Joey Podlubny
Cover Feature
Penn West has a significant position in the Viking oil plays with approximately 750,000 net acres, including large, core positions at Avon Hills and Dodsland, Sask. On the Alberta side, production results from the gassy-oil wells drilled in the first quarter continue to be encouraging, reports the company. Plans for the third quarter include eight additional wells and the expansion of the company’s gas-handling infrastructure to support its 2013 drilling programs. There are also a number of junior companies active in the Viking. Raging River Exploration Inc. is increasing spending in the play based on success in the first half of the year. The company has approved a $15-million increase in its 2012 capital budget, to $82 million from $67 million. The company will add 10–12 net horizontal wells to its program, for a total of 41–43 net wells. The revised capital budget also contemplates pre-drilling a number of 2013 locations, assuming that operating conditions remain favourable. The revised capital budget provides $44 million for drilling and completions, $4 million for land, seismic and facilities, and $34 million for acquisitions. Based upon field estimates, third-quarter production exceeded expectations with average production of 2,100 barrels of oil equivalent per day (97 per cent oil). Average daily production for the period from April through December 2012 is expected to be 2,150 barrels per day (97 per cent oil). The increased forecast, the third this year, represents a 26 per cent increase from initial guidance of 1,700 barrels per day without increased capital expenditures. The 10–12 incremental net wells are expected to have a material impact on exit production, which is now expected to be 2,800–2,900 barrels equivalent per day (97 per cent oil). This third increase in exit guidance represents a 30 per cent increase from initial guidance of 2,200 barrels per per day without increased capital expenditures. The company drilled a total of 37 (28.8 net) wells during the third quarter including 36 horizontal Viking oil wells at a 100 per cent success rate and one vertical stratigraphic test well. A total of 17 (16 net) wells were placed on production in the third quarter and 19 (11.8 net) wells were waiting to be brought on stream in October. The optimized drilling and completion techniques continue to provide consistent, improved production results. Average 45-day production rates for the 17 new wells placed on stream during the third quarter have exceeded 50 barrels per day of oil. This is consistent with the results of the first 13 wells drilled with this technique earlier this year. Drilling and completion costs have continued to trend lower. The average drilling and completion cost in the third quarter was $800,000, leading to total per well on stream costs of $925,000. Novus Energy Inc. is also a significant player in the Viking. In addition to the 124 net sections of Viking rights the company holds in the Dodsland area of Saskatchewan, Novus recently amassed 46 net sections of Crown lands prospective for Viking oil in the Provost area of Alberta, on trend with its existing Dodsland assets. The acquired land is proximate to historical vertical Viking oil production and recent successful horizontal drilling activity on both sides of the AlbertaSaskatchewan border targeting Viking oil. Novus believes the assembled acreage meaningfully increases the company’s future drilling and development inventory. Drilling on these lands is planned for early 2013.
During the second quarter of 2012, Novus drilled 13 wells, all of which were Viking horizontal oil wells in the greater Dodsland area. Eight wells (eight net) were completed by June 30. For the first half of 2012, Novus drilled 26 wells, all of which were Viking horizontal oil wells in the greater Dodsland area. Sixteen wells (16 net) were completed by June 30. Novus has completed the installation of the main infrastructure in the Flaxcombe area by adding 11,000 metres of emulsion lines that tie into the main transmission line feeding its facility. Thirty-six wells currently have gas conservation and are tied in, with new wells tied in as they are completed. Load water recovered is being handled by the company-owned disposal facility. Produced water coming into the main facility is injected into a second well tied into the plant, while sales gas flows to a sales line, making it an enclosed system. Additionally, upgrades have been completed at the main facility. It is now fully enclosed and electrified with two treaters and treating capacity exceeding 13,000 barrels per day. The facility also has 11,000 barrels of storage. The company has 625 net high-quality risked Viking oil drilling locations on its 124 net sections of land in Dodsland, based on an eight-well-per-section drilling density. This already-significant opportunity base does not reflect the ability to down-space from eight to 16 wells per section, or the future potential to waterflood the reservoir. Novus believes that the development of the Viking resource is in its early stages and that there is further significant upside to recovery factors by applying secondary-recovery methods. The 625 Viking locations do not include potential locations on the company’s recently acquired Alberta Viking lands. P R O F I L E R M A G A Z I N E . C O M
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The oilsands and tight oil get all the coverage, but conventional heavy oil remains an economic powerhouse By Darrell Stonehouse
heavy profit$
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Feature
has the
highest return
on capital in our overall inventory and generates significant
free
cash flow.
— Steve Laut, president, Canadian Natural Resources Limited “In the second quarter, we have adjusted our steaming strategy slightly, steaming new pads longer and injecting more steam volumes. As a result, our recovery per cycle will increase and our steam to oil ratio on a cycle basis will decrease,” he noted. “This has impacted production slightly for 2012, as we will not bring these new pads on to the production portion of this cycle as early as first planned. Production guidance for the year has not changed. Primrose pads are some of the lowest-cost production capacity additions in the industry, as are Canadian Natural’s operating costs, which are targeted to come in at $9 a barrel in 2012, making Canadian Natural’s thermal in situ heavy oil production very profitable, if not the most profitable in Canada.” Laut said CNRL believes that while today heavy oil is profitable, the future looks even brighter. “We are very bullish on heavy oil pricing,” he said. “The blowout on heavy oil differential seen in the first quarter is almost entirely due to planned and unplanned refinery or heavy oil refinery capacity. As this capacity came back online, we saw a dramatic narrowing of heavy oil differentials in May and June. As a result, second-quarter differentials averaged about 24 per cent of WTI, well within our long-term estimate of 22 per cent to 25 per cent. We do, however, expect to see occasional anomalies in heavy oil differentials in 2012, as the refineries go down for planned and unplanned maintenance.”
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2012 record drilling program has been increased by Our
54 wells to 872 wells in 2012.
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PHOTO: Joey Podlubny
“ Primary heavy oil “
H
eavy oil is the workhorse of western Canada’s petroleum industry. It isn’t glamorous, but consistently provides profits and cash flow for operators with the landbase and know-how to exploit it. Canadian Natural Resources Limited (CNRL) is one such operator, and is in the process of adding to its already-large heavy production base. “Primary heavy oil has the highest return on capital in our overall inventory and generates significant free cash flow,” company president Steve Laut told shareholders at CNRL’s second-quarter update. Laut said CNRL has increased spending on the company’s primary heavy oil properties on the Alberta-Saskatchewan border, as a result of its current profitability. “Our 2012 record drilling program has been increased by 54 wells to 872 wells in 2012,” he noted. “With increased drilling and the success of our program, we now expect production growth to be 20 per cent in 2012, or roughly 124,000 barrels a day.” CNRL has a number of growth projects underway to add to heavy oil volumes. Laut said development is well underway at the company’s Woodenhouse play, which has already added significant new production. “Currently, we are producing 9,300 barrels a day, well ahead of expectations, and exit rates for the year are targeted at roughly 12,000 barrels a day,” Laut noted. “We’ve drilled 50 wells so far this year, have 32 completed, with 17 wells left to drill in 2012. Production rates have been excellent at 170 barrels a day per well. We have over 200 drilling locations left to drill at Woodenhouse, to add to our significant and extensive 8,000-well inventory of heavy oil locations, ensuring significant heavy oil–production growth in the future.” Laut said CNRL continues making progress in growing production at Pelican Lake as well. “We continue to effectively implement the polymer flood across a pool, and we’re now seeing good polymer response from essentially all portions of the pool,” he explained. “We will drill another 72 wells at Pelican in 2012 and continue the expansion of the facilities to handle the increased Pelican Lake and Woodenhouse production. Pelican Lake production will grow four per cent year-over-year, but more importantly, the polymer-driven production profile delivers very lowdeclining production and significantly adds to our long-life, low-decline asset base.” CNRL also continues building momentum at its thermal heavy oil developments at Primrose. “At Primrose, we continue to effectively deliver production volumes at the lowest operating costs in the industry,” said Laut. “In the 2012 Primrose development plan, we are developing five pads at Primrose East that will add 20,000 barrels a day in 2012 and ramp up to 30,000 barrels a day in 2013. At Primrose South, we’re developing three pads that will add roughly 15,000 barrels a day in 2012, and ramp up to 20,000 barrels a day in 2013, both at a cost of $13,000 flowing barrel.” Laut added that CNRL continues learning as it develops its Primrose resource.
— Steve Laut, president, Canadian Natural Resources Limited
P R O F I L E R M A G A Z I N E . C O M
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Beginning next year, CNRL expects heavy oil economics to improve significantly. “With 300,000 barrels per day of heavy oil conversion capacity slated to come on stream from the end of 2012 to the first half of 2013, these issues will disappear and actually put downward pressure on heavy oil differentials,” said Laut. “Add to this, the strong likelihood that the Keystone XL pipeline will be approved allowing North American heavy barrels to displace to roughly 2.4 million barrels of heavy oil imports into the Gulf Coast, as well as provide blending opportunities to displace medium oil imports, heavy oil pricing looks very strong going forward.”
year-end reserves of about 83 million barrels, our reserve life index about 11 years.” Aylesworth said the key to Baytex’s success at Lloydminster has been using appropriate technologies to access the reservoir. “We have been developing in the Lloyd area using a multiple of different techniques, vertical wells, horizontal wells, SAGD, foam injection; it’s not a very homogenous area,” he explained. “We use whatever technique is appropriate for the particular reservoir, but we look at the Lloydminster area as, as I said, the cash cow for the company. We don’t expect it to grow materially but there is
How good? “We believe we’re about to enter an outstanding era for heavy oil, and in particular for thermal or in situ heavy oil, an era where, for the first time, most if not all the key factors are in our favour,” said Laut. “Increasing demand for heavy oil, strong heavy oil pricing, low gas prices which drive thermal in situ heavy oil operating costs lower, and lower premiums for diluents with increased supply of liquid diluent from liquidsrich drilling, all adding to the further strength of economics for heavy oil. “As a reminder, Canadian Natural has 8.5 billion barrels of heavy oil resources to develop, and 8,000 primary heavy oil locations in inventory,” he added. Like CNRL, Baytex Energy Corp. is also high on the potential of heavy oil. Speaking at a Barclay’s Capital conference this fall, Baytex chief financial officer Derek Aylesworth described the company’s heavy oil operations around Lloydminster as “the bread and butter of historic development for Baytex.” “The story with Lloydminster is traditional heavy oil,” said Aylesworth. “Heavy oil is typically at relatively shallow depths, and when you drill a single vertical well you can intercept multiple pay zones. The multiple pay zones result in lower finding and development cost because you’ll produce out the most prolific zone first, plug it, move to the next zone and recomplete to produce from the next zone. Those recompletions have been historically able to add reserves at $1 or $2 or possibly $3 per barrel—very, very low-cost recompletions and reserve adds. At Lloyd, we are currently producing about 20,000 barrels a day of heavy oil,
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still unidentified seven years of drilling inventory in front of us. That drilling inventory has grown by about 75 per cent over the last five years that I’ve been at Baytex.” Like CNRL, Baytex views heavy oil as a cash flow– generating machine. “Capital efficiency ratios are very, very good at Lloydminster,” he explained. “We’ve been adding production at $11,000 per flowing barrel with finding and development cost of around $12 a barrel. At current WTI pricing we’re in the 200 per cent to 300 per cent Internal Rate of Return [IRR] for Lloydminster.” Aylesworth said a study done by Scotia Bank is looking at the profitability of all resource plays in North America. Lloydminster heavy oil ranked fifth in the study. Aylesworth said while current heavy oil pricing is volatile, longer term they expect it to become more stable. “Notwithstanding today’s volatility, we very, very much believe that when the U.S. pipeline system is built out and things like the Keystone line are in place, heavy oil pricing is going to be in a very, very, very strong position,” he explained. “So the main product that we’re producing is looking for a price improvement in a not-too-distant future. I think by the time we get Keystone online, you’re going to have a very, very positive pricing picture because we’re accessing the Gulf Coast, using the Maya to Western Canadian Select [WCS] pricing marker. Maya is the Mexican heavy oil blend. It’s a very similar quality to WCS. Today Maya is getting about $20 a barrel premium to WCS. When you adjust for transportation, it’s probably about $10 to $12 premium. So there’s an arbitrage there that’s likely going to be closed when we get access to the Gulf Coast refining region.”
PHOTO: Joey Podlubny
Heavy oil producers are increasingly turning to thermal recovery methods to increase production.
FEATURE
Future attraction
New tight oil plays moving quickly towards commercialization By Darrell Stonehouse
PHOTO: JOEy PODLuBNy
C
anada’s tight oil revolution began five years ago in the Bakken in southeastern Saskatchewan. It spread quickly to other tight formations including the Cardium, Lower Shaunavon, Viking and Swan Hills carbonates. While these established plays are in various stages of development, they aren’t the end of the story. A number of new tight plays are under exploration and early results look promising. alBerta Bakken Play The Alberta Bakken is one such play. The target of a land rush two years ago, explorers are now drilling up prospects and developing strategies to tap what could be
billions of barrels of resource. Early results have been mixed, but optimism that the play crossing the Alberta and Manitoba border could be huge remains. DeeThree Exploration Ltd. is a junior producer reporting early success tapping the Alberta Bakken. The company is focused on the Exshaw formation in the Lethbridge area, with two rigs drilling the play. DeeThree holds 200,000 acres in the Lethbridge area prospective for the Sunburst and Bakken. In the second quarter, DeeThree drilled four wells into the Exshaw. One of the company’s two most recently completed wells tested at 808 barrels of oil equivalent a day over nine days, the other at 630 barrels a day over eight days. PROFILERMAGAZINE.COM
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“ The sixth location drilled this year was a step-out that is significant as the first well drilled by DeeThree on the Crown lands that comprise part of its Exshaw properties. Based on the success of this well, the company acquired an additional 22 sections of offsetting Crown land in the second quarter, and DeeThree now has 39 sections of Crown land that it believes to be highly prospective for Exshaw potential in addition to its extensive freehold land in the area. The 2012 drilling program has successfully tested the upper Exshaw formation over an eight-mile east-west by three-mile north-south fairway. DeeThree intends to further test the limits of the known Exshaw oil pool through the second half of the year by drilling an additional eight Exshaw wells. To accommodate anticipated additional production increases from its Exshaw drilling program, the company is currently installing an amine plant to handle CO2 from solution gas. Also, it is designing and procuring equipment for a second 4,000-barrel-per-day expandable oil facility, which is to be operational by year-end. Murphy Oil Corp. is also reporting success in the Alberta Bakken. “In southern Alberta, we continue to see positive results from our first well completed in the Three Forks zone, with production rates of 280 barrels a day of light oil, and the well has now produced over 200 days,” Roger W. Jenkins, president of Murphy Exploration & Production Company, told shareholders at the company’s second-quarter conference call. “Our second Three Forks well has now been on production for more than 70 days and is 12
N ovember 2 0 1 2
producing near 100 barrels a day. The third well has been selected and will be drilled in the fourth quarter of this year. As we gain better understanding of the Three Forks reservoir and refine our completion techniques, we expect to continue seeing positive results in this play.” Montney tight oil play The Montney tight oil play in northwestern Alberta is also gaining traction as a number of explorers report strong initial production rates from early wells. Trilogy Energy Corp. is the pioneer in the Montney oil play. In the fourth quarter of 2010, Trilogy completed drilling operations on its first horizontal Montney oil well at 16-1-64-18W5. The well was completed using a 15-stage fracture stimulation. Following recovery of the completion load fluid, the 16-1 well flowed crude oil at 1,800 barrels of oil per day. Over the first 30 producing days, this well produced an average of 569 barrels per day. A follow-up well to delineate the pool was drilled with a lateral 1,158 metres in length and completed with a 15-stage fracture stimulation. The well produced 1,600 barrels of oil in the first 24 hours of production. Based on the success of these two horizontal Montney oil wells, Trilogy acquired 28 sections of land in this area. With a 100 per cent working interest in 41 sections of land in this area, Trilogy believes it holds substantially all of the petroleum and natural gas rights associated with this Montney oil pool. Starting in mid-August 2011, four drilling rigs were used to execute an 18-well horizontal drilling program during the third and fourth quarters. Drilling operations were
originally forecast to take 30–35 days; actual drilling times were reduced to 20–25 days per well, based on continuous improvement of the drilling practices throughout the program. Faster drilling times have reduced drilling costs and accelerated the need for additional production and processing equipment. As a result, wells were produced in such a way as to maximize oil production and reduce effective royalty rates while the new facilities and equipment were being constructed. Trilogy’s capital spending on the Kaybob Montney oil pool in 2011 was approximately $175 million. During the first quarter of 2012, Trilogy drilled eight wells to further develop the Montney oil pool at Kaybob, bringing the total to 31 wells that have been drilled into the pool. As many as 20 wells were on production during the month of March when production averaged approximately 9,000 barrels per day of crude oil. It also began expanding the play into the Fox Creek area. Trilogy has followed up on the success of the first two Montney oil wells in the Fox Creek pool by drilling a third well at 16-1-63-19W5, which was spudded on March 22 and rig released on April 8. The well was drilled to a measured depth of 3,838 metres including a 1,749-metre horizontal lateral in the Montney formation. The 16-1 well was cased with a liner assembly, which will allow a 24-stage fracture stimulation following spring breakup. The second well that was drilled from an existing surface lease at 4-14-63-19W5 to a bottomhole location at 102/13-10-63-19W5 was completed with a 21-stage fracture stimulation on Dec. 19, 2011.
Photo: Joey Podlubny
In southern Alberta, we our first well completed production rates of 280 has now produced over
Feature
continue to see positive results from in the Three Forks zone, with barrels a day of light oil, and the well 200 days.
”
— Roger W. Jenkins, president, Murphy Exploration & Production Company
Only one well was drilled into the Montney oil play in the second quarter as the company caught up on infrastructure to handle growing production. It plans 10 wells for the remainder of 2012, and is planning an aggressive program for 2013. Canol Shale Oil Play Further north, the Canol shale oil play is in the embryonic stage of development. MGM Energy Corp. has filed a regulatory application to drill a horizontal well with multiple fractures targeting the Canol shale oil play in the Central Mackenzie Valley this coming winter. The Northwest Territories–focused junior already has approval from the Sahtu Land and Water Board for a vertical well with a number of near wellbore fracs on Exploration Block 466, company president Henry Sykes told the Peters & Co. Limited energy conference in Toronto. However, if it receives approval for the horizontal well in a timely manner, MGM will drill that instead, with Shell Canada Limited picking up the total cost as part of a farm-in agreement, he said. If not, MGM will proceed with the vertical well and once approval is received it will drill the horizontal well, which must be fractured, as the second well in the farm-out agreement. Sykes said his company is “very, very excited” about the level of activity planned for the area this winter, as well as about its own interest in the play. “It’s a significant amount of activity given that this play wasn’t on the radar screen two years ago,” he said.
Last winter, Husky Energy Inc. drilled two vertical wells at its Slater River project in the area and completed a 220-square-kilometre 3-D seismic program over its two exploration blocks adjacent to MGM’s. Husky has indicated that this winter it is planning to further evaluate the first two wells and to build an all-weather road. “That’s important because all-weather roads are very, very expensive and that indicates some level of commitment to the play,” said Sykes. Construction and maintenance for MGM’s temporary roads and the wellsite will cost between $10 million and $13 million this winter, he noted. “These are not inexpensive roads by any standard.” Although Husky has not released any information on its wells, which can remain confidential until 2014, the Canol play is one of two major oil resource plays—the other is the Muskwa at Rainbow, Alta.—that “could move the needle” for the company, Rob Symonds, senior vice-president, western Canada production, told another session at the Peters conference. ConocoPhillips Canada has consulted community groups about plans to drill up to three vertical wells on its exploration blocks east of Husky’s but has not yet filed an application, Sykes said. With its acquisition of a 50 per cent interest in the two other exploration licences that MGM acquired in 2011 with a partner, Shell is now MGM’s partner in all the licences. MGM also has an agreement that Shell cannot put it on notice for at least the next two years without its consent until it has some results from these plays, said Sykes.
MGM, which holds a total of 338,400 (180,075 net) hectares in the Central Mackenzie Valley, has been involved in the area for a number of years and always assumed it was a shale natural gas play, said Sykes. “When we drilled our Windy Island well, a conventional oil play with Devon Canada Corp. in 2010, the well came in dry,” he said. “As we did more and more of the work we came to realize that what we had originally thought was a shale gas play was really more of a shale oil play.” The Canol play runs about 200 miles from north of Norman Wells to south of Norman Wells, becoming gasier to the west. “We think it compares very, very favourably with proven resource plays,” said Sykes. Although Husky was the first to target the Canol play in drilling its two wells, probably dozens of wells had been drilled through the play targeting conventional target plays, he said. MGM has reviewed seismic, logs and cores of those wells available through the National Energy Board and has mapped the play. “There is sufficient organic richness to be good-to-excellent source rock,” and the play runs right through MGM’s blocks, Sykes said. The Canol is very consistent at 75–90 metres in thickness over most of the active play part of MGM lands. The underlying Bluefish shale is more variable with a thickness of 15–30 metres. The kerogen maturity is in the liquids window over most of the MGM blocks, said the MGM president. The existing Enbridge Inc. oil pipeline from Norman Wells with significant excess capacity also contributes to the attractiveness of the resource play, the conference heard. P R O F I L E R M A G A Z I N E . C O M
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COMPANY PROFILE
FIRST MERCHANTS CAPITAL INC. Speaking out for the Energy Industry
as a consultant in the energy “industry, this is a very SeriouS issue for me that could have a very negative financial impact on me, as well as thousands of other Calgary consultants and other families. we really need to understand the implications and
”
how we can deal with it.
— Brad Gaulin, P.Eng, MBA., consultant
a
warning to all energy industry consultants: new taxation legislation could have substantial tax consequences for you. Many professionals and consultants provide their services through a consulting corporation, which can provide them with valuable benefits. However, a consulting corporation may be considered a Personal Services Business (PSB) if, among other things, the person providing services on behalf of the consulting corporation can reasonably be regarded as an incorporated employee. Recent changes to the Income Tax Act have significantly increased the cost of being considered a PSB. Consultants working in the oil and gas industry will be directly impacted by these changes. If a consulting corporation is deemed to be a PSB, it will lose most of the benefits of doing business through a corporation, and will be subject to a significantly higher corporate tax rate after October 31, 2011. “The new legislation can have an immediate and costly impact on energy industry consultants. It can cost them money—
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N OV E M B E R 2 0 1 2
potentially a lot of money,” says Dale Leicht, President of First Merchants Capital Inc., a private investment banking company that has worked with a group of Calgary tax lawyers to develop a plan to effectively reduce or eliminate the consequences this tax legislation could have on you. “When looking at this problem, our tax lawyers have found a solution,” Leicht says. “With proper planning, it’s possible to reduce the impact this tax change has on you. We have the solution, and have designed a structure in the spirit of the Income Tax Act.” Many tax-planning ideas are created by tax lawyers as a result of a specific transaction. Many people could benefit from tax planning, but tax lawyers typically do not market these solutions to the general public. First Merchants Capital Inc. has access to these lawyers and is pleased to arrange an introduction. “Several years ago in my normal course of corporate finance transactions, I began encountering the genius that exists within the profession of tax lawyers,” Leicht says. “The vast majority of business owners and consultants are simply not aware of the
creative power of these tax minds. I personally enjoy introducing business owners to these fine lawyers who they would otherwise never know or meet. “In order for us to offer any tax advice, it must comply with the Income Tax Act and hold up to CRA scrutiny,” Leicht says, noting that advanced rulings are often in place. Please call Dale Leicht for your complimentary consultation with one of our tax lawyers.
FAST FACTS FIRST MERCHANTS CAPITAL INC. PRESIDENT: Dale Leicht T: 403.266.8080 C: 403.651.8763 E: dleicht@telusmail.net
WEBSITE: www.psbcts.com www.firstmerchantscapitalinc.com
Attention Oil & Gas Consultants
New legislation will drastically increase the tax liability of incorporated consultants and other professionals. Your tax rate could increase to over 57%. There is a limited opportunity to protect yourself from this punitive tax increase.
Visit Our Website to Download a Free Summary www.FirstMerchantsCapitalInc.com or call Dale Leicht at 403.266.8080
COMPANY PROFILE
NCS OILFIELD SERVICES CANADA INC. multistage unlimited™ Leave Nothing Behind
n
CS Oilfield Services prides itself on helping operators realize the goal that has become the company’s mantra: “Leave Nothing Behind.” “When we finish with the wellbore, it’s open, unobstructed and ready for production,” says NCS Sales Manager Eric Schmelzl, P.Eng. “Perhaps more importantly, by placing the stimulation treatments precisely where operators want them, they can be assured of recovering the full potential of the asset, and leave nothing behind when they are done.” NCS Oilfield Services began working in western Canada in 2008 with a unique downhole tool that allowed operators to perforate and fracture multiple stages in a single trip. With the evolution of horizontal wellbores, NCS successfully refined their BHA and jetting processes so that operators could continue to apply abrasive cutting for reservoir access in the horizontal well environment. Today, although the jet-cutting method is still widely used, frac equipment shortages and rising costs mean that accelerating the speed at which operators execute their treatments is of paramount importance. This brought about the introduction of NCS Multistage unlimited™ frac sleeves, which have allowed operators to accelerate the speed with which they can complete their stimulation treatments. NCS frac sleeves eliminate the need 16
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to employ abrasive cutting, saving on both time and fluid requirements, while retaining the option to jet cut whenever desired. The NCS multistage frac sleeve stimulation method often results in higher production rates when compared to other “non-pinpoint” stimulation techniques. “Wells are getting longer and hotter—some of these horizontal wells are getting to be two miles long, so our technology is focused on being able to get tools down to those depths and [being] able to effectively place fractures,” says NCS Oilfield Services Chief Technology Officer Don Getzlaf, P.Eng. “Our motto has always been ‘Leave nothing behind,’ which requires optimizing wellbore performance over its entire life—that’s always been our goal. We leave the wellbore full diameter so that at any time in the future, operators can go in there and if there is bypassed pay, it can be isolated and re-stimulated. Maintaining the capability to manage the asset over its entire life has always been one of our primary system design goals.” From a technical standpoint, NCS does a great deal of custom design work. “If customers want something specific, we’ll listen to their concerns and be able to design the tool or part that meets those concerns,” Getzlaf says. “We are very quick and very responsive. When we designed the frac
sleeves, we went from a napkin sketch to first deployment in just 59 days. That’s a remarkably fast response to meet a specific customer need.” NCS technology also allows customers to re-perforate between existing producing intervals and re-stimulate, or potentially squeeze off existing intervals as needed. “It gives operators far more options to manage the wellbore and the reservoir,” Getzlaf says. Industry is being tasked to lower costs by doing more work in less time and to use fewer resources in accomplishing that goal. To that end, NCS recently introduced the Half-Straddle™ system—a marriage between frac sleeves and fracturing through coil. The technique results in a significant reduction in the amount of fluids required to execute a multistage stimulation program, in some cases by up to 50%. The challenge was to develop a method that would allow quick transition from fracturing down the inside of the coiled tubing, to jetting down the CTu, then back to fracturing again. The NCS Half Straddle™ BHA allows the use of the jet cutter whenever required, and then quickly returns to fracturing operations. “The exciting thing is that even though we use significantly less water, the formation receives exactly the same frac treatment as before, without compromising on-the-job design,” Schmelzl says. “With reduced fluid volumes, there is a reduction of costly frac chemicals, and it also reduces the amount of time the frac crew is on location. The Half-Straddle™ method often allows the annulus to remain entirely free of sand, which in the long run reduces both operational risk and costs. “Our clients are very excited by the fact they require less fluid to haul, less fluid to heat, less tankage and fewer chemicals on location,” Schmelzl says, noting there is also less fluid to dispose of after the frac treatment is completed. “We are especially pleased by reducing the amount of time required to perform the frac treatments. When we can do that, we are improving every aspect of the total well completion costs.” Cost reductions and environmental benefits aside, one of the most important factors in any completion methodology is the assurance that reserves are not bypassed. The frac stage spacing needs to be uniformly draining the reservoir so that all portions of the reservoir are in approximately the same stage of depletion when the well’s economic limit is reached. The flexibility of
placing frac stages anywhere in the wellbore is retained by including the abrasive jet cutter, even on wells where sleeves are installed. NCS was the first to develop a BHA that’s tolerant enough in a high-sand environment to allow this style of multistage fracturing. Since 2009, NCS’s Mongoose BHA has performed more than 33,000 frac treatments across western Canada. NCS Oilfield Services is continually refining and modifying the BHA design and components with the goal of enhancing the number of stages that can be achieved on a single trip, and extending the service to deeper, hotter well environments. To date, the company has completed more than 40 stages on one trip into a wellbore, and successfully placed fracs at over 5,500 metres TMD. NCS’s largest treatment to date resulted in 3.4 million pounds of proppant placed in a single treatment, and the BHA has demonstrated exceptional reliability: 94.8% of the 1,342 sand-offs experienced to date have been circulated clean with no requirement for BHA disconnects and minimal service interruptions. The boundaries of the method are being continuously extended as new BHA refinements and techniques are tested and deployed, and operational results continue to improve. Operators are coming to the realization that the long-term viability of their investment is enhanced by having a cemented wellbore. “We believe the open-hole methodologies have good application in highly fractured,
NCS Frac Sleeve components awaiting assembly. Custom-built components allow NCS to meet specialized customer needs with speed and agility.
dendritic formations, and our sleeve methodology is applicable in those reservoirs as well,” Schmelzl says. “But in reservoirs that generate simple, planar fractures, we continue to see operators leaving behind the
“
our clients are very excited by the fact they require
less fluid to haul, less fluid to heat, less tankage and
”
fewer chemicals on location.
— Eric Schmelzl, Canadian sales and engineering manager, NCS Oilfield Services Canada Inc. old plug-and-perf and cluster-perf methods in favour of pinpoint stimulation methods that guarantee the placement of a known number of fractures, in specific, predetermined locations. The proof is in the production—not just initial production rates, but the total recovered reserves over the life of the well.” All NCS staff bring an extensive background in hydraulic fracturing, coiled tubing and downhole tools to the job, with more than 175 years of combined experience among company management. “We bring to the table unique solutions to customer challenges. We have the expertise; we move quickly and deal with our clients with a ‘small-company’ feel, which is an environment we treasure.” Looking forward, one of NCS’s goals is to continue expanding globally. The company continues to support operations in Australia and China, and is actively expanding into the u.S. and several other international markets.
FAST FACTS NCS OILFIELD SERVICES CANADA INC. Over 33,000 frac stages pumped Over 715,000,000 lbs of proppant successfully placed Sand-off recovery rate: 94.8% Offices in Calgary AB, and Houston TX CANADIAN SALES & ENGINEERING MANAGER: Eric Schmelzl T: 403.862.0870 WEBSITE: www.NCSfrac.com
PROFILERMAGAZINE.COM
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COMPANY PROFILE
STEP ENERGY SERVICES – One Year Later Since being profiled only one year ago, STEP Energy Services is redefining coiled tubing, fluid pumping and nitrogen services in Western Canada
J
ust 18 months ago, STEP Energy Services set out to be the premier coiled tubing, fluid pumping and nitrogen service provider in the Western Canadian Sedimentary Basin. “I believe we’ve made significant progress towards that goal already,” says STEP chief operating officer, Steve Glanville. “Bringing together highly specialized, purpose-built coiled tubing and fluid pumping equipment with the most talented professionals in western Canada has put STEP on the radar of some of the industry’s largest E&P companies.” Founded in March 2011, STEP’s business model is focused on the market demand for increased reel capacities to effectively service the growing number of technically advanced horizontal wells, which now account for over 60 per cent of wells drilled in western Canada. STEP’s coiled tubing mast units are custom fabricated to accommodate 4,500 meters of 73 mm and 5,200 meters of 66.7 mm coiled tubing, respectively. By providing this innovative equipment to oil and gas producers, STEP’s clients are increasing their production efficiencies and are setting new benchmarks for operations. STEP is headquartered in Calgary, Alberta, and currently has a fleet of four purpose-built, deep-capacity coiled tubing units, nine twin fluid pumps, 10 nitrogen pumps and five nitrogen bulker units. STEP’s current capital expansion program will continue as it targets a total of 12 coiled tubing spreads, which will be fully operational in the second half of 2013. The company’s first pumping job took place in December 2011 and its first coiled tubing project in July 2012. “Our job execution and service-quality standards have been exceptionally high,” says Glanville. “We’ve built a client base of over 45 energy producers with land holdings in B.C., Alberta and Saskatchewan, including Shell and Penn West—and have delivered a level of client service not seen before in the oilfield industry.”
maJor mileStoneS in 2012 STEP completed its first coiled tubing operation for Shell in northern B.C. “The execution was flawless—everything went as planned,” says Glanville. From July to 18
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“
it’s great to see a
company that is built around safety, trust, execution and possibilities, taking the initiative to build fit-for-purpose equipment for the challenging horizontal wells that have become so prevalent in our industry. they have addressed the challenges of long, deep horizontal wells and have built a first-class team to run built-for-purpose equipment that helps the producer deal with the milling difficulties in these long reach wells. they are a quality operation and did
”
a very good job.
— Trevor Schable, Well Servicing Superintendent, Penn West Exploration
September, STEP completed an intensive project for Penn West Exploration in Cordova, involving the mill out of composite bridge plugs and ball seats with continuous 24-hour operations. “Once again, the project was executed perfectly, with minimal nonproductive time, zero safety infractions, and we were able to increase efficiencies from the previous project Penn West had serviced by another provider,” Glanville says. On this project, STEP ran one of the largest coiled tubing strings in Canada from a diameter perspective, with an overall diameter of 73 mm, in depths of 4,500 meters.
In mid-September, STEP acquired Kamber Nitrogen Services Ltd., a privately owned coiled tubing and nitrogen pumping company based in Fort St. John, B.C. This acquisition aligns with STEP’s vision of combining technically advanced, purposebuilt coiled tubing units, and associated pumping and support equipment, with the industry’s most experienced operations professionals. President Bailey Epp comments, “Kamber has built a respected business in northeastern B.C. and we believe that the integration of their operations, equipment and people into our growth plans is a great strategic move.” STEP now employs over 160 people in its three locations, including the head office in Calgary, the original service center in Blackfalds, Alberta, and the new center in Fort St. John, B.C. The acquisition of Kamber—an early entrant into the deep coil, fluid and nitrogen pumping business—has positioned STEP to better serve clients in northeastern B.C. “With Kamber’s
“
SteP is a competitive,
performance-oriented company with the right core values in safety and efficiency. their team of professionals have helped deliver our pursuit of goal Zero in an environment that looks for opportunities to create value for their customers. they have great people and solid equipment to service our
”
needs in the montney.
— Luke Schauerte, C&WI Superintendent, Groundbirch, Shell Canada Limited
well-established nitrogen business, and our expertise and coiled tubing knowledge, we plan to increase our penetration into the Montney and Horn River Basin and deliver exceptional service to the energy producers who are active in the area,” Epp says.
unit to the industry, in order to increase efficiencies on pad drilling locations. “Rig-up and rig-down time will be substantially decreased, and we will be able to accomplish this with safety as our number one priority.”
a SteP aBove Future ProJeCtS STEP’s equipment has been well received in the field and the company continues to be very busy. “With our engineering department and depth of operating experience, we have been able to explore opportunities and integrate our expertise in challenging well profiles with complete engineered programs. We have created solutions for our clients that have not previously existed,” Glanville says. “Our growth strategy is extremely aggressive and by mid-2013, we will have a significant fleet of state-of-the-art coiled tubing units in the field ready to service our growing client base,” adds Glanville. In February, STEP plans to deploy another newly designed coiled tubing
In a very short time, STEP has built a reputation as a company that provides an Exceptional Client Experience (internally, employees have coined this phrase “The ECE”). But STEP believes the key to this client-focused culture begins with the success of its employees. STEP Energy Services is proud of the progressive work environment it provides its team of professionals; it is a culture in which growth and personal development are expected rather than suggested, a platform for employees to embrace new challenges and to think outside of the traditional bounds of oil and gas service. “From an employee perspective, we have built a unique culture that engages all professionals, and have been
able to attract the very best in the industry,” explains Glanville. “Our STEP family is the company’s best asset and gives us our competitive advantage. It is the reason why we have enjoyed such incredible success over the last 18 months and how we will continue to raise the bar for coiled tubing and fluid pumping services.”
FAST FACTS STEP ENERGY SERVICES T: 403-457-1772 E: info@stepenergyservices.com Blackfalds Dispatch: 1-855-480-7837 Fort St. John: 1-888-785-1515 www.stepenergyservices.com
PROFILERMAGAZINE.COM
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COMPANY PROFILE
TOG SYSTEMS LTD. Expanded fleet key for busy season
WE HAVE INCREASED OUR
“Being able to offer a wide range of options is a priority and having these towers
FLEET SIGNIFICANTLY AND WE
now means that we can service more of our valuable customers,” says CEO
ARE NOW ONE OF THE LARGEST
Diane Nordhagen. In past years, companies were not able to meet the demand
PORTABLE TOWER PROVIDERS
for this technology, but that won’t be a problem any longer. For being only 10
IN WESTERN CANADA.
years young, this Alberta-based remote oilfield telecommunications company has begun to make its footprint in the oilfield telecommunications market. Their plans are only to get bigger and better.
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TOG is committed to providing the best in communications equipment and customer service. The extensive list of rental products includes TOG’s microwave network, oilfield satellite systems, wireless rig phones, computer packages, cellular boosters, radios, satellite televisions and more. TOG also supplies Internet services through satellite, cellular or their own microwave link. WE INVEST IN PEOPLE AND WHEN WE
Look up. Way up…and over. You will need a wide lens to capture the eleven new portable towers that TOG Systems Ltd. has just added to its fleet. The towers are a rapid deploy with zero ground disturbance and leave a smaller footprint onsite, which are all very important factors when time and weather often aren’t on your side. Customers can now extend their own networks or add to TOG’s private network in only a matter of days or weeks, compared to several months with a standard tower with pilings. The towers also allow the addition of a variety of equipment, including an independent power source, cellular repeaters, radio repeaters and microwave links for an all-in-one complete solution. The result is an effective and reliable communication product and there’s plenty to share. TOG’s headquarters is located near Grande Prairie in the heart of the Alberta oil country, and they service customers across Alberta, British Columbia and Saskatchewan.
THE PEOPLE FACTOR Employees are one of TOG’s most important assets. The company attracts the best in the field because of its reputation for extensive training, priority on workplace safety and its commitment to providing the best quality of life possible for all employees. These full-time service positions are a hot commodity and TOG prides itself on its great team and the excellent service they provide to customers. “The training and support system that TOG has in place allows me to safely, efficiently and confidently face the unique challenges that arise on location. TOG recognizes the need for a healthy work/life
balance and my family greatly appreciates the time we are able to have together thanks to this,” states Micah Fricke, TOG Technician. “We really nurture long-term relationships both within our company and with our customers,” Nordhagen says, noting this is a key part of TOG’s philosophy.
STAYING ON THE LEADING EDGE Research and development is what really sets TOG apart from its competitors. TOG’s philosophy is to continually expand products and services, and to work with partners to create and develop the best products to meet the continually changing business needs of their customers. “We take the time to innovate and we are committed to investing in the future of this industry. All of our clients have unique needs and when presented with a new challenge, we go out and search the globe for products—and if doesn’t exist, well, we then create it,” Nordhagen says. Partnering with manufacturers and other companies to create new products helps TOG to stay on the leading edge of the oilfield telecommunications world and keep its customers happy. THE FUTURE IS BRIGHT TOG Systems has big plans for the industry and is excited about their future. As a private company, it can adapt to an ever-changing market by making decisions and moving on them quickly. With its extensive line of equipment, its multiple brands in every product category and its commitment to exceptional customer service, TOG is positioned to take the lead in this competitive industry.
RECEIVE FEEDBACK FROM CUSTOMERS ABOUT OUR EXCEPTIONAL STAFF AND SERVICE, WE CONSIDER THE JOB WELL DONE.
T E L E C O M M U N I C AT I O N S O I L & G A S
FAST FACTS TOG SYSTEMS LTD. T: 780.356.3965 E: info@togsystems.ca
WEBSITE: www.togsystems.ca
PROFILERMAGAZINE.COM
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COMPANY PROFILE
TUNDRA PROCESS SOLUTIONS LTD. World-class suppliers to the industrial and commercial processors
t
undra Process Solutions provides worldclass products and services for industrial and commercial process applications across Western Canada. Established in 1999 by President Dan Peet, Tundra now employs more than 100 workers, with offices in Calgary, Edmonton, Red Deer, Fort McMurray, Grande Prairie, Lloydminster, Saskatoon, and Swift Current. “We have really focused on becoming a full solutions provider, with many different products for different areas of the oil and gas industry,” Peet says. “We not only have boiler, water treatment, instrumentation, and valve products for plants, but also provide motors, VFD drives, and much more. We’ve become experts at packaging skids, and buildings as well, to make it easier for the customer to go to one source for so many of their projects requirements. We’ve now also ventured into the upstream market with our Artificial Lift Division, which will provide a complete suite of products to meet all the needs of artificial lift.” Sure Stroke intelligent lift™ System Tundra manufactures this innovative surface-mounted artificial lift system for oil and gas that is lighter, lower cost, more energy-efficient, and has greater lifting capacity and performance compared to conventional lift systems. In late 2011, Tundra acquired DynaPump, a company based out of California. After rebranding DynaPump as SSi Lift™, Tundra took over its manufacturing process and moved it to Calgary, redesigning and improving the entire unit. “As a result, performance has gone up, overall costs have decreased, and manufacturing and support are world-class and local,” Peet says. “What this product does is revolutionize the way that you produce a well—this is a game changer.”
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The SSi Lift™ technology offers advanced rod manipulation like no other. “It’s a very efficient design. With our technology, we are able to reduce downhole wear to prolong the life of downhole equipment through a much longer stroke, soft turnarounds, and more fluid production per stroke,” Peet says. Power savings are approximately 30 per cent over a conventional pumpjack, and 70 per cent over an electric submersible pump. Tundra offers a variety of units ranging from 240-inch stroke to 360-inch stroke, with lift capacities of up to 80,000 pounds and a variety of horsepower options from 15 hp through to 125 hp. These units operate using hydraulics with a nitrogen counterbalance, which allows the user to change directions on the fly, change stroke length in seconds, and change speed at the touch of a button. “We can very quickly change virtually any parameter of our system in seconds through our touch screen, as our unit is PLC-based with a built-in variable frequency drive.” Improvements to the pump design include an upgraded Toshiba motor and drive featuring the latest VS1 variable frequency drive technology, which increases turndown and comes with a three-year warranty on the motor and drive. Each unit comes with a web-based interface. “Virtually any parameter of our unit can be seen remotely through the SCADALynx system, as well as adjusted,” Peet says. “This allows for much easier operation and a better interface. Almost anyone within the organization can log on to see all the details of the well, to check the current pump status, load graphs, surface cards, downhole cards, pressures, or wellsite parameters.” A built-in pump-off controller has the ability to automatically increase and decrease speed based on pump conditions.
The unit comes standard with jog control to move the unit up and down, inch by inch, in any position. This allows the operator, if need be, to tap the pump by manually jogging the unit down past the regular stroke, and it can be done and put back online in seconds. The unique hydraulic system—a bi-directional electric motor and hydraulic pump—spins in one direction for the upstroke and in the other direction for the downstroke, maximizing reliability. “Our unit is proven to work very well in horizontal deviated wells. We are able to outperform conventional pumpjacks on initial production, as well as provide a much higher turndown, producing a wider flow range. We are able to produce the well for the entire life cycle of the well.” The unit is built on a skid, so it can be placed directly on the ground, and is now a lighter weight than before, with a smaller footprint. The unit slides back on a rail system, so there is no need for a crane or picker truck when well servicing. Installation is rapid, with the capacity to install two units per day. “We’re excited about this venture, because it brings us into oil and gas markets worldwide through international distributors and direct sales personnel,” Peet says. “It puts Canadian technology and manufacturing on the international stage, as it has so many times before. This replaces old conventional beam pumpjack technology and offers so many advantages over just about everything. This is truly something that we believe five years from now will be the de facto standard in the oil and gas industry, in Canada and beyond.” Tundra also provides rental, financing, and leasing options for its equipment, combined with award-winning technical service and support. “Our goal is to ensure we meet clients’ demands by having significant inventory in a variety of locations,” Peet says.
“
our unit is proven to
work very well in horizontal deviated wells. we are able to outperform conventional pumpjacks on initial production, as well as provide a much higher turndown, producing a wider flow range. we are able to produce the well for the entire life cycle of
”
the well.
— Dan Peet, president, Tundra Process Solutions Ltd.
FAST FACTS TUNDRA PROCESS SOLUTIONS LTD. PRESIDENT: Dan Peet T: 403.255.5222 Toll-Free: 1.800.265.1166 E: info@tundrasolutions.ca
WEBSITE: www.tundrasolutions.ca
PROFILERMAGAZINE.COM
23
THE
FOR FRAC SAND HANDLING & STORAGE.
REDUCE your FOOTPRINT
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Easy to set up Up to 240 ton capacity Custom patented detachable trailer Patented stabilizer system Optional solar panel system
www.fbindustriesinc.com info@fbindustriesinc.com 204-325-7337