April 2016

ShaleTech: Canadian Shales

A lot of pain, little gain seen in ‘16
Jim Redden / Contributing Editor
A rig at work on Blackbird Energy’s Montney Elmworth leasehold in Grande Prairie, Alberta. Image: Blackbird Energy.
A rig at work on Blackbird Energy’s Montney Elmworth leasehold in Grande Prairie, Alberta. Image: Blackbird Energy.

Unique to the Western Canada Sedimentary basin (WCSB), much of the drilling and completion activity typically goes on hiatus between April and May, as the winter thaw creates slushy and hazardous roadways, prohibiting the movement of rigs and equipment. For all practical purposes, the mostly home-grown shale players within the WCSB appear set to make the 2016 rendition of the seasonal Spring Break-up a nearly year-long affair.

“Today, the oil and gas services industry is facing one of the most difficult economic times in a generation,” said Mark Scholz, president of the Canadian Association of Oilwell Drilling Contractors (CAODC). “The active rig count for the western Canadian rig fleet is at the same level as experienced in 1983, one of the worst periods in our history.”

Scholz issued that dire observation on Nov. 18, less than two weeks before the traditional start of the winter drilling season. His comments accompanied the release of CAODC’s equally dismal 2016 forecast, which has operators in the notoriously high-cost WCSB drilling 4,728 wells this year, compared to 5,292 in 2015, and down 58% from the 11,226 wells constructed during the 2014 peak. “With 696 land rigs available in the Canadian industry by year-end (2015), forecasted 2016 activity will average a 22% rig utilization across industry, the lowest rig utilization rate ever recorded by the CAODC, and its data stretches back to 1977,” said Beaver Drilling CEO Brian Krausert, chairman of the CAODC forecasting committee.

Throughout the established and emerging shale plays scattered across the tightly regulated and takeaway-challenged WCSB provinces of British Columbia, Alberta, Saskatchewan and Manitoba, a considerable number of rigs, frac spreads and the like are destined for the sidelines, at least for much of the first half of 2016. Calfrac Well Services’ CEO Fernando Aguilar said in late February that 45% of the company’s Canadian frac equipment was idle. “Pricing has decreased a further 10% to 15% from the fourth quarter of 2015, with some competitors now bidding at below break-even levels,” he said.

Fig. 1. A ConocoPhillips rig on location in the Deep basin, where the Houston independent ranks as one of the leading producers. Image: ConocoPhillips.
Fig. 1. A ConocoPhillips rig on location in the Deep basin, where the Houston independent ranks as one of the leading producers. Image: ConocoPhillips.

“Normally, I would say it’s good to put a year like 2015 behind us, but unfortunately, the challenge as we enter 2016 has only intensified,” said Kevin Neveu, CEO of Precision Drilling, Canada’s largest contractor. Neveu said Precision’s winter-season rig count peaked at 65 in the third week of January, but had dropped to 57 active units as of Feb. 11, noting, however, that gas drilling in the multi-target Deep basin of west central Alberta “remains firm,” Fig. 1.

The Canadian Association of Petroleum Producers (CAPP) has a similarly pessimistic outlook, predicting that total capital expenditures will decline to $42 billion this year, from $48 billion in 2015. For perspective, the CAPP forecast includes the cost-intensive Alberta oil sands, which, alone, accounted for $33 billion of the total 2014 capital spend. Evidence of across-the-board budget slashing is reflected by Vermilion Energy, which has cut its 2016 Canadian spending 73% to $54 million, earmarked solely for lease retention and meeting non-operated well commitments. Vermilion holds a substantial land position in the West Pembina Cardium, as well as the geologically complex and higher-cost Duvernay shale play. Despite high returns, the deeper Duvernay also comes with comparatively higher break-even costs, putting it squarely in the economic crosshairs.


Obviously, the collective strategy for 2016 is conserving cash, concentrating on lower-cost plays and squeezing more out of developed assets, as exemplified in Crescent Point Energy’s aggressive waterflood EOR campaign within its Saskatchewan Bakken leasehold. In 2015, Crescent Point converted 33 wells from producers to injectors in its Viewfield Bakken play, with an additional 50 well conversions planned for 2016. According to the operator, “producing wells directly offsetting a water injection well are demonstrating half the decline rate and three times the estimated ultimate recoveries of wells not affected by waterflood.”

Nevertheless, National Energy Board (NEB) data show both tight oil and shale gas production trending downward in the four shale-centric WCSB provinces. Last year, the quartet delivered 663,623 boed of light oil, while 2016 production is expected to drop to roughly 598,633 boed, according to Canada’s chief regulator, which still expects tight oil to account for 25% of the country’s non-oil sands production this year. The same trend is seen with shale gas, which, the NEB predicts, will decline to an average 13,668 MMcfd from the roughly 14,694 MMcfd delivered in 2015. By 2035, the NEB expects shale to account for 90% of Canada’s natural
gas production.

While keeping their fingers crossed that potential infusions from the capital markets could flip the narrative and spark a third-quarter recovery of sorts, companies generally agree that the next few months will be especially painful. “It’s going to be a tough year for our industry,” said Tom Simons, CEO of Canadian Energy Services and Technology, which lays claim to more than 30% of the Canadian drilling fluid market. “March to June is going to be tough. Nobody is going to drill. Why would they?”

 Calgary’s Painted Pony Petroleum is the rare exception, with plans to actually increase the number of Montney wells drilled this year on its 139,049-net-acre leasehold in British Columbia. In a Feb. 12 investor update, the independent said it will drill 29 and complete 26 net wells this year, after drilling 15 and completing nine net wells in 2015. The company, for now, has increased its 2016 capital investment to C$197 million, earmarked entirely for British Columbia, compared to an estimated C$107 spent in 2015. The additional wells are expected to help increase year-end production to around 40,000 boed, up sharply from the 17,500 boed delivered in January.

Much of the impetus for the hike is the expected mid-year start-up of the AltaGas Townsend shallow-cut gas processing facility. Painted Pony and AltaGas have a strategic alliance to develop the facility, which is being designed to process and market up to 198 MMcfd of gas and NGLs. The facility was 70% complete by January.


Second only to the U.S. in shale production, Canada added to its estimated 3,424 Tcf of shale gas-in-place with the March release of an NEB assessment that has the remote Laird basin of British Columbia and the Northwest Territories holding 219 Tcf of marketable unconventional gas.That makes the largely undeveloped frontier play the world’s ninth-largest shale gas resource and Canada’s second largest behind the Montney of British Colombia and Alberta, the nation’s most established and lowest-cost unconventional play. The latest NEB assessment follows the 2012 multi-agency Laird Basin Hydrocarbon Project, which was orchestrated to evaluate the gas potential of the Middle Devonian and Carboniferous Besa River and Golata shales.

However, until prices improve appreciably, a significant chunk of those reserves are likely to remain in situ. The only meaningful development, of late, has been in conjunction with the 50/50 Chevron Canada and Woodside Petroleum Kitimat LNG JV, one of 22 LNG export facilities in various stages of development off British Columbia. Australia’s Woodside acquired its 50% interest in April 2015, which includes 320,000 acres of potential feedstock in both the Liard and adjacent Horn River basins.

The JV brought its first Liard basin well into production during fourth-quarter 2015. A second well also was completed during the quarter and is expected to be in production early this year, according to Woodside.


With condensate fetching a price advantage relative to the U.S., much of the activity in the Montney is moving to its more liquids-rich Alberta horizons. Calgary’s Blackbird Energy says current condensate production falls some 200,000 bpd short of Canada’s current demand of 350,000 bpd.

Blackbird created a buzz in late January with the release of initial production (IP) from a record-setting Middle Montney well within its 48,000-acre Elmworth leasehold near Grande Prairie, Alberta. Located in the liquids-rich fairway, the well flowed 1,768 boed, which the junior operator says puts it among the top tier of Montney producers. Notably, the well was completed in 70 stages with sliding sleeve technology, incorporating what is believed to be a record CO2 foam frac job. Canadian off-road cryogenic fluids provider, Ferus Inc., said 88,317 bbl of load fluid and 9,226 m3 of CO2, were pumped to distribute an average of 31.75 tons of proppant/stage.

Blackbird said the decision to test the Middle Montney was prompted largely by Encana having effectively delineated the Upper Montney in its adjacent leasehold. “After completing a very detailed analysis of the activity undertaken by Encana, my team determined that the drilling of an Upper Montney on the Western portion of our lands would be redundant. It was clear that the drilling that had been undertaken by Encana had clearly delineated two intervals in the Upper Montney,” President and CEO Garth Braun wrote in a February/March executive letter.

Fig. 2. An Encana Montney well site. The operator plans to run two rigs in the play in 2016. Image: Encana.
Fig. 2. An Encana Montney well site. The operator plans to run two rigs in the play in 2016. Image: Encana.

Following discoveries last year in both the Upper and Middle Montney benches, Blackbird says it has “significantly derisked” its acreage, while reducing total well costs to an average $7.5 million. Blackbird has not yet released any guidance for 2016 activity.

With 2016 planned capital expenditures down 55% over 2015, Encana, meanwhile, plans to run four rigs (Fig. 2), split evenly between its nearly 600,000-net-acre Montney leasehold and the estimated 343,000 net acres it holds in Alberta’s Duvernay play, where it operates under a JV with PetroChina subsidiary Brion Energy (formerly Phoenix Energy Holdings). Like Blackbird, Encana says its Montney activity is shifting mainly to the condensate-rich Alberta component, where it envisions a liquids production growth rate of more than 50% on a compound annual basis through 2018. Across the provincial border in British Columbia, Encana’s four-year-old JV with Mitsubishi Corp. in Cutbank Ridge will primarily focus on a drill-to-fill program, as the duo awaits the 2017 expansion of additional compression.

Encana says reducing well costs further will occupy much of its attention this year, citing a Montney drilling and completion target of $5.1 million/well, with typical lateral lengths of 9,000 ft. “An operating cost reduction taskforce was assembled in December, and it identified over 1,000 initiatives across the company to lower our lease operating expenses (LOE),” Executive V.P. and COO Mike McAllister said in the 2015 year-end earnings call. “For example, we targeted greater than 15% savings on our water management. This is primarily driven through an increased focus on recycled produced water across the entire company, while minimizing our trucking and disposal cost.”

Also in Alberta, Athabasca Oil is expected to close this quarter on the C$475 light-oil JV with Murphy Oil, announced on Jan. 27. The agreement gives Murphy a 30% interest in Athabasca’s 60,000-acre Montney Greater Placid assets, and 70% of the Calgary independent’s nearly 200,000-acre Duvernay Kaybob holdings.

At Placid, Athabasca completed a three-well Montney pad in September, following up on two successful wells drilled in the winter of 2014/2015. The wells were scheduled for completion in first-quarter 2016, with total costs estimated at $8 million/well. In addition, Athabasca says it will spend $18 million in first-quarter 2016 to complete and tie-in the pad, and by late April plans to have completed the inter-connect to the Kaybob infrastructure. December gross production from two high-graded Placid Montney intervals averaged 900 boed, while its Duvernay Kabob wells averaged 6,900 boed, with 58% liquids. Athabasca expects 2016 light oil production of 7,000–8,000 boed.


As with the Montney, the less service-intensive Canadian Bakken/Torquay (Three Forks) shale of Saskatchewan and Manitoba, and the Cardium shale/sandstone formation, extending from Alberta and into eastern British Columbia, are seen as plays where operators can get more bang for limited bucks.

Fig. 3. Data from a five-operator peer group shows Cardium break-even costs dropping nearly 30% between 2013 and 2015.
Fig. 3. Data from a five-operator peer group shows Cardium break-even costs dropping nearly 30% between 2013 and 2015.

The comparatively shallow Cardium has become particularly intriguing of late. Though a relative newcomer to horizontal multi-frac drilling and completions, the Cardium is the largest conventional oil reservoir in the WCSB and has since emerged as Canada’s “most important light oil play,” according to Rystad Energy Senior Analyst Sona Mlada, who cites average light oil content as high as 40%. Adding to its vitality in today’s environment is the nearly 30% reduction in wellhead break-even costs between 2013 and 2015, she said, Fig. 3. Rystad’s break-even analysis was derived from the results of a peer group comprising five operators, which in 2015 collectively drilled 50% of all Cardium wells.

Penn West Petroleum, for one, drilled 56 and completed 73 net wells in its 766-section Cardium-prospective Alberta leasehold last year, delivering average production of 28,000 boed. PennWest also controls 648 sections in the Greater Viking play of southwestern Saskatchewan, where the Calgary-based operator in 2015 drilled and completed 105 and 103 net wells, respectively, with average production of 19,500 boed. Though Greater Viking is a well-established play, where PennWest says it has lowered costs by implementing 12-stage, high-density completions, the per-bbl economics of the Cardium were more attractive. Cardium oil was delivered at an operating cost of $14.40/boe with an $18.00/boe netback, compared to Viking’s $16.50/boe and $18.50/boe respective operating costs and netback, according to Penn West.

After setting a reduced 2016 exploration and development budget of $50 million, Penn West in March sold its properties in the Slave Point area of northern Alberta for $148 million, leaving the Cardium and Vikings as its core assets. Penn West expects 2016 production to average 60,000–64,000 boed. “We have been clear that the future of Penn West is around the Viking and Cardium,” says President and CEO David E. Roberts. “Our results in these light oil plays continue to offer attractive rates of return with short payback periods, even at historically low commodity prices.”

Bonterra Energy, which holds 201 net sections largely concentrated in the Pembina Cardium area, drilled 20 gross operated wells in 2015, with 24 completed and tied into production. Bonterra averaged production of 12,656 boed in 2015, and has set a 2016 target of 12,500 boed. The operator has set its 2016 capital budget at roughly $40 million, compared to the just-under $59 million spent last year, but said the spending levels will be re-visited monthly.           

Tamarack Valley Energy, which operates in the Pembina, Wilson Creek, Garrington and Lochend Cardium fairway, averaged production of 8,700–9,700 boed in 2015, including a record average of 10,870 boed in the fourth quarter. Other than drilling three of four remaining farm-in commitments in the first half, Tamarack has not provided guidance on the wells that it intends to drill in 2016. The operator has set capital expenditures at $52 million to $57 million, and expects 2016 exit production of 9,600–9,700 boed.

Calgary’s Torc Oil & Gas drilled 10 Cardium wells on its 95-section leasehold in 2015, and says it will drill nine this year, citing “improved operational efficiencies and service cost reductions of up to 25%.” Cardium production of 5,500 boed in 2015 was up modestly over the 5,000 boed delivered year-over-year. In a related development, Torc completed two acreage acquisitions last year, adding more than 6,000 boed and doubling its southeastern Saskatchewan asset base, where it continues to delineate the Torquay resource play.

The fifth operator in the Rystad peer group, Whitecap Resources, was among the most active of the Cardium players last year with 21 gross wells, including 18 in its West Pembina acreage and three in southeastern Alberta. Whitecap completed its first-quarter 2016 drilling program with four gross Cardium wells in West Pembina and one Cardium well in Ferrier, Alberta. The company says drilling and completion costs averaged $1.7 million/well, 33% lower than original budget estimates. Whitecap said it also is initiating its first waterflood EOR project in the Cardium, with plans to begin injection, having drilled and completed a water injector in April. Like Penn West, Whitecap also has a sizeable presence in the low-cost Viking play, where last year it drilled 93 gross horizontal wells, with another 15 drilled in first-quarter 2016. wo-box_blue.gif 

About the Authors
Jim Redden
Contributing Editor
Jim Redden is a Houston-based consultant and a journalism graduate of Marshall University, has more than 40 years of experience as a writer, editor and corporate communicator, primarily on the upstream oil and gas industry.
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