January 2018

Canadian Shales: More wells in ‘18, but full recovery remains elusive

The winter drilling season in the diverse shale plays scattered throughout the western Canada sedimentary basin (WCSB), is shaping up to be the busiest in three years.
Jim Redden / Contributing Editor

The winter drilling season in the diverse shale plays scattered throughout the western Canada sedimentary basin (WCSB), is shaping up to be the busiest in three years. Yet, market accessibility tied to nagging regulatory issues and anomalous gas price volatility combine to stymie a full-blown recovery.

Headwinds aside, the Petroleum Services Association of Canada (PSAC) expects the legion of largely Calgary-based independents to drill 7,900 wells this year, representing a modest 4%-to-5% increase over the estimated 7,550 wells drilled in 2017. The forecast new-well count is the highest since 2015, but remains some 30% below the 2014 tidemark, according to the PSAC. The Canadian Association of Oil Drilling Contractors (CAODC), however, reported 196 active rigs the week of Dec. 18, all but three of which are drilling ahead in Alberta, low-cost Saskatchewan and British Columbia, compared to a 212-rig average during December 2016.

“The small uptick in activity we realized in the first quarter of 2017 has carried on through the year. Budgets set with initial optimism for a gradual climb in prices by year-end continue with their plans, as drilling and completion efficiencies improve,” PSAC President Mark Salkeld said upon the Oct. 31 release of the 2018 forecast. “Due to pressure to stay low, costs for services continue to be suppressed, affording better margins for producers.”

Despite lingering takeaway woes, exacerbated in October by the regulatory-engendered cancellation of TransCanada’s 2,795-mi Energy East Pipeline, non-oil sands production trended slightly upward in 2017. A breakdown of National Energy Board (NEB) data has leading WCSB producers Alberta, Saskatchewan, British Columbia and Manitoba averaging cumulative light oil and equivalent production of just under 573,090 boed as of Dec.16, compared to a 2016 average of roughly 565,674 boed.

Conversely, year-over-year gas production was virtually flat, as Canadian producers face increasing competition from their U.S. contemporaries and unprecedented swings in AECO (Alberta Energy Co.) benchmark prices. A dissection of NEB data shows the primary WCSB gas hubs of Alberta, Saskatchewan and British Columbia together delivering monthly average production of approximately 15,397 MMcfd as of Dec. 4, compared to around 15,032 MMcfd in 2016.

Darren Gee, president and CEO of Peyto Exploration & Development Corp, said the exceptional volatility in gas prices which, at one point, forced the company to curtail 3,000 boed of production, even swung to the red side of the ledger. “We have never seen daily natural gas prices that went negative before. During the third quarter, AECO daily prices (measured in gigajoules) ranged from a high of $2.50/gigajoule down to a low of minus $2.20. That’s just massive swings and we have never seen that before,” he said.


Liquids-rich Alberta appears on track to meet the 2018 PSAC forecast of 3,998 new wells—a 152-well jump over 2017—where, at last count, 147 rigs were exploring multiple targets, including the wetter windows of the mature Montney shale, the underlying Duvernay (newly reinforced as Canada’s largest tight oil resource) and the Cardium shale/sandstone sequence. The Cardium extends from its Alberta Deep basin epicenter into the Montney fairway of British Columbia, where 730 new wells are expected to be constructed this year, up from the 612 new drills projected for 2017.

Saskatchewan is expected to follow closely behind Alberta with 2,931 new drills in 2018, an annual increase of around 84 wells. The latest CAODC tally had 30 rigs at work in the province, where numerous prospects include the economical and geologically uncomplicated Viewfield Bakken, the Torquay (Three Forks) shale, the dual-bench Shaunavon light oil resource play, and the shallow west-central Saskatchewan portion of the Viking formation. Elsewhere, with only three rigs drilling ahead, activity in Manitoba is expected to remain flat at around 230 wells.

The cautious optimism broadly reflected in a sampling of operators’ 2018 guidance does not extend to the pure dry gas horizons. Owing to the price volatility, spending is expected to be flat to reduced this year, as traditional dry gas producers focus more on condensate, which continues to trade at a premium relative to the U.S.

Boosted by the fast-track completion of three processing plants last year, premier Montney condensate producer Encana Corp. recorded October production of 147,000 boed, up 32% over the previous quarter. “On the back of strong well productivity gains and the recent successful start-up of all three Montney plants, we now expect to grow our core asset production by 30%, to roughly 305,000 to 310,000 boed,” President and CEO Doug Suttles told investors on Nov. 8.

At year-end, Encana and joint venture partner Mitsubishi Corp. were running seven rigs with plans to drill 70 to 80 wells in its nearly 600,000-net-acre position, concentrated largely in the liquids-prone Montney window, in northeast British Columbia and northwest Alberta.

Encana also enhanced its position as the leading Duvernay producer, with record third-quarter production of more than 24,000 boed, Fig. 1. Operating under a joint venture with a subsidiary of PetroChina Ltd, Encana averaged two rigs in 2017 and planned to drill seven to nine Duvernay wells across its roughly 343,000-net-acre leasehold. Illustrating the improving economics of Duvernay wells, drilling and completion costs for 8,850-ft lateral wells in Encana’s condensate-rich Simonette South asset averaged $8.2 million/well.

Pure play operator Painted Pony Energy Ltd. expected to wrap up 2017 with the drilling of 50 wells and the completion of 55 net Montney wells in the 201,009 net acres (314 sections) it controls in northeast British Columbia. The operator projected 2017 production to average 43,500 boed to 46,000 boed, up from the 23,204 boed produced in 2016.

Painted Pony drilled and completed 16 net wells in the third quarter, including six Upper Montney wells on the 17-G pad in the Blair fairway, marking the first time the company had sequentially completed as many wells on a single pad.

Blackbird Energy Inc. is steadily transitioning from delineation to development of its core Pipestone/Elmworth Montney condensate-rich asset, where FY 2017 production averaged 1,609 boed. Blackbird drilled 10 and completed seven gross wells during the year, as it continues to evaluate the productivity of the Upper and Middle Montney. The recent acquisition of 3.5 net sections increased the company’s net position in the Alberta Pipestone/Elmworth corridor to 112.4 sections.


Based on 2017 average commodity prices and reduced well costs, an updated NEB economic resource assessment released in November has the central Alberta Duvernay shale holding 1 Bbbl of oil, about a third of its total marketable reserves. The latest assessment also showed an economical gas resource of 12 Tcf and natural gas liquids (NGL) of 1.4 Bbbl, bolstering the Duvernay as among the hottest in-country plays.

While providing no specifics, Chevron Canada Ltd. created a stir in early November, when it announced plans for a significant drilling program, initially targeting 55,000 net acres in the Duvernay East Kaybob section. Chevron, which holds a 70% operating interest in approximately 228,000 net acres in the Duvernay, said the venture follows a three-year appraisal program. “This is a very significant business opportunity for Chevron Canada and our very first foray into development in the liquids-rich Duvernay,” spokesman Leif Sollid told Reuters on Nov. 6.

Chevron and Shell, which controls sizeable land positions in both the Duvernay and the dry gas Montney horizon in northeast British Columbia, are among the few international oil companies (IOC) still holding shale interests in Canada. International players, including Shell, collectively liquidated nearly $23 billion of mainly Alberta oil-sands assets last year, according to Reuters. No information on Shell’s near-term unconventional activity has been made available.

With three rigs and one frac crew, another remaining U.S. operator, Murphy Oil Corp., closed out 2017 with the drilling of 16 Kaybob Duvernay wells, with 11 wells put on line within its 230,000-gross-acre leasehold. Third-quarter Duvernay production averaged just over 3,700 boed, a 32% increase over the first three months of 2017. In the latter part of 2017, Murphy also completed a five-well pad in its Tupper Montney asset in Alberta, with average lateral lengths exceeding 10,000 ft. The pad, which included a pace-setting 11,000-ft lateral well, was slated to go on stream in the just-ended fourth quarter. Year-end Tupper Montney production was estimated at 223 MMcfd, up from the 208 MMcfd average in the third quarter.

Junior player Raging River Exploration Inc. drilled and completed its first Duvernay well in the third quarter of 2017, after freshly amassing a 236,000-acre (370 sections) leasehold and expanding beyond its established Saskatchewan Viking core, Fig. 2. The debut evaluation well was drilled to an MD of just over 15,003 ft, including a nearly 7,218-ft, 43-stage horizontal section, completed in the Upper Duvernay. Raging River plans to drill no less than six Duvernay evaluation wells in 2018.

The Duvernay inauguration capped what Raging River described as the most active quarter in the company’s history, which included the drilling of 124.8 net horizontal wells in its commanding 460-section Viking position. The company, which plans to add a fourth Viking-directed rig in January, expected to exit 2017 with production of 22,750 boed (93% oil).


Cenovus Energy Inc. wasted little time ramping up activity within the roughly 3 million net acres in the Deep basin, acquired from ConocoPhillips last year. The company planned to exit 2017 with seven rigs and the drilling of 28 wells in the newly integrated assets straddling the British Columbia and Alberta border, where third-quarter production averaged 115,301 boed, Fig 3.

ConocoPhillips, meanwhile, continued to beef up a foothold elsewhere in Canada’s unconventional sector, quietly expanding its liquids-rich Blueberry-Montney position in northeast British Columbia. In what it described as a “case study in low-cost resource acquisition,” ConocoPhillips, over the past five years, has increased its holdings from 14,000 to 106,000 net acres, more recently snatching up core acreage for $1,000/acre.

Now in the appraisal phase, ConocoPhillips will begin drilling a 12-well pad early this year to test stacking and spacing. The company closed out 2017 with the drilling and completion of two wells, which it said produced at “double the average 30-day rates of competitor wells across the play.”

With control of 1.9 million acres, Tourmaline Oil Corp. holds a commanding position in the Deep basin, where it mainly targets the Cardium, but has significant exposure to the gas-rich Spirit River group of tight sandstones. Trourmaline, which also holds positions in the Peace River High and Northeast British Columbia (NEBC) Montney gas/condensate complexes, reached its year-end production target on Dec. 1, with the asset trio delivering a cumulative 270,000 boed. The Deep Basin Falher D three-well pad contributed some 2,600 bpd to the accelerated liquids growth, joining an earlier 2017 Cardium discovery that had delivered 3.4 Bcf of gas and 102,000 bbl of condensate after 315 days on line.

The company also drilled and/or completed 11 Lower Montney horizontal wells in the Peace River, which are slated to be in production by early 2018. The initial well on the first four-well Lower Montney pad is producing at a 1,888-boed clip. In the NEBC Montney, the company drilled and completed two pads in its Gundy asset, comprising an aggregate 16 wells, with a third 11-well pad awaiting stimulation at year-end. Tourmaline operated a 14-rig fleet throughout the fourth quarter and plans to average 12 rigs across its three plays this year.

Despite the gas price volatility, Peyto completed one of its busiest three-month periods, drilling 44 Deep basin wells in the third quarter, spread evenly across its Sundance, Ansell and Brazeau assets. Peyto’s new-well inventory included 42 horizontal and two vertical Cardium wells. Operating nine rigs, Peyto expected to exit 2017 with production between 115,000 and 120,000 boed.

After notching company record production of 20,992 boed in the third quarter, Torc Oil & Gas Ltd. increased 2017 exit guidance to 22,500 boed, with projected 2018 production to average 23,000 boed. Along with roughly 50 net sections prospective for the Torquay in southeast Saskatchewan, Torc holds more than 95 net sections in Alberta’s Cardium light oil trend, where it drilled 7.7 net (9 gross) wells in the first nine months of 2017. In 2018, TORC expects to drill 10.5 net (12 gross) Cardium wells.

In Saskatchewan, Torc finished the year with the drilling of 10 net (13 gross) horizontal Torquay wells, with plans to drill 13.5 net (17 gross) wells in 2018. During the fourth quarter, Torc also drilled 4.6 net (6 gross) unconventional wells in Saskatchewan’s emerging Midale light oil play, which the operator plans to further delineate this year with 11 net (12 gross) new wells. Torc’s Torquay and Midale wells typically comprise 1-mi laterals with 30-stage completions. 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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