Special Report: Canada looks to shales for boost to gas supply

Dec. 14, 2009
Natural gas from shale formations represents a potentially crucial source of supply growth in Canada, where production from conventional reservoirs is declining in a trend likely to continue.

Natural gas from shale formations represents a potentially crucial source of supply growth in Canada, where production from conventional reservoirs is declining in a trend likely to continue.

While two shale gas plays—in the Horn River basin straddling the boundary between northern British Columbia and Alberta and the Triassic Montney shale to the south—draw most of the current drilling, potential exists elsewhere in the country. In some of the newer plays, drilling has just begun.

Production of gas from shale isn't new to Canada. The National Energy Board, for example, points out that the Cretaceous Second White Speckled shale of southern Alberta and Saskatchewan has produced gas for decades. But that shale is fractured enough naturally to produce gas commercially through vertical wells without the sophisticated fracturing and horizontal wells essential to most of the burgeoning new shale developments of North America.

In the more challenging shales capturing new industry attention, Canadian development lags that of the US. Canadian Society for Unconventional Gas (CSUG) Pres. Michael Dawson, in a September presentation, arrayed North American shale gas plays along a scale of development progress. Among Canadian plays, only the hybrid Montney—in some areas a tight sand because of its high silt and silica content—had reached what he described as the commercial stage. The US plays he judged to be at that stage were the Marcellus, Barnett, Haynesville, Fayetteville, and Woodford shales.

Speaking at the National Bank Financial Energy Services Conference, Dawson assigned the Horn River basin play in part to the pilot production-testing phase, where it aligned with newer projects in the Marcellus shale, and in part to the pilot-project drilling stage, aligned with the Eagle Ford play in the US.

Shales in the Quebec lowlands, Nova Scotia, and New Brunswick, Dawson said, remain at a stage he described as early evaluation drilling.

As in the US, shales in Canada differ greatly—shale versus shale and location versus location within a single shale—and require tailored completions and various fracturing methods. According to Dawson, Canadian shale plays have economics less favorable than many of the unconventional gas plays of the US.

Crucial supply

But their development is crucial to Canadian gas supply.

In a November outlook, the Canadian Association of Petroleum Producers documented declines during the past several years in Canadian drilling and gas production in Alberta (Fig. 1). CAPP sees gas from tight formations and shales in British Columbia as the most important element of an expected recovery and eventual expansion of gas production through 2020 (Fig. 2).

Now, however, shale gas production isn't rising fast enough to offset declines from conventional reservoirs, where economics have soured.

"Massive value destruction is occurring for the shareholder, or unit holder, for each thousand cubic foot of gas produced today," said Paul Ziff, chief executive officer of Ziff Energy Group, in a June report.

His reason: Gas prices aren't high enough to cover the costs of replacing produced reserves in the conventional reservoirs of western Canada.

A 2008 study by his group showed that the reserves life of gas reserves in the region had declined from more than 20 years to less than 9 years, a level requiring 12%/year reserves replacement.

The gas price when he spoke was about $3/Mcf (Can.), which according to his analysis generated a loss of $3.40/Mcf after cash operating costs of $2.30/Mcf, 60¢/Mcf for general and administrative expenses and interest payments, and $3.50/Mcf for drilling, depletion, and amortization. Ziff estimated full-cycle costs for gas production at $8/Mcf.

"Core gas reserves are being sold/depleted at market prices that simply cannot be replaced by the cash generated," he said. "So producers' reserve base shrinks, and in the near future more equity or debt will need to be issued to fund replacing the gas produced today."

Unconventional gas—from tight formations, coalbeds, and shale—"is moderating the western Canada decline but not reversing it," Ziff said.

Well characteristics

The NEB assessed Canada's shale gas potential in a comprehensive review last month. It said total volumes of recoverable gas are expected to be 1-10 bcf from each horizontal well drilled into Canadian gas shales, with amounts likely to grow as technology improves.

Initial production rates from horizontal shale gas wells are high—generally 3-16 MMcfd. But production tends to decline rapidly in each well's first year before flatting into a gradual decline. Horizontal shale gas wells, NEB said, are expected to produce for more than a decade each.

Vertical wells in silica-rich gas shales have initial production rates around 1 MMcfd. In the shallow Middle Cretaceous Colorado shale, initial production rates are less than 100 Mcfd.

NEB said the average Canadian conventional gas well drilled and placed on production in 2007 initially flowed about 200 Mcfd.

In the Montney formation, horizontal wells cost $5-8 million each, while Horn River basin wells cost as much as $10 million. Wells in the Upper Ordovician Utica shale are expected to cost $5-9 million.

Vertical wells into shallow shales with gas of biogenic origin, such as the Colorado shale, cost less than $350,000 each.

Surface work

In British Columbia, gas production beyond what's expected to be reached within just a few years will require expansion of surface facilities. The NEB's November review highlighted several projects planned to relieve the bottlenecks.

Spectra Energy is considering expansion of its gas processing plant at Fort Nelson in the southern Horn River basin. About half the existing inlet capacity of 1 bcfd is in use at present; the expansion would add 250 Mcfd at facilities 40 km northeast of Fort Nelson at Cabin Lake.

EnCana Corp. has proposed construction in six stages of 2.4 bcfd of gas processing capacity at Cabin Lake.

The NEB report mentioned Spectra Energy's construction of 92.7 km of 20-in. pipeline extending the company's raw-gas gathering system in the Fort St. John area to an area south of its 680 MMcfd McMahon gas processing plant in Taylor, BC.

Also in British Columbia, NEB noted, Nova Gas Transmission Ltd. proposes a 1 bcfd pipeline extending the company's Alberta System into the shale gas producing area. Nova says the 77-km, 36-in. Groundbirch Mainline Project would run between points 12 km west of Gordondale, Alta., and 4 km northwest of Groundbirch, BC.

NEB said several years might pass before production of gas from shale warrants construction of large-scale short-haul pipeline capacity. It said expansion of major long-haul pipeline capacity from western capacity is less likely to be needed because of pipeline capacity becoming available as conventional production declines.

Prospective shale gas plays elsewhere in Canada are closer to existing pipelines.

The Utica play is near the Trans Quebec & Maritimes Pipeline serving Montreal and Quebec City with connections to pipelines serving the Northeast US. The system has spare capacity.

And the Horton Bluff shale play in New Brunswick and Nova Scotia is close to the Maritimes & Northeast Pipeline system.

Prospective shales

In its report, NEB described the main shale gas plays under development or study in Canada. It pointed out that the characteristics summarized in Table 1 come from various sources and present data it didn't try to verify.

The table indicates potential for 1 quadrillion tcf of gas in place, somewhat less than the total of estimates by the CSUG shown in Fig. 3. "How much of that gas can be recovered still needs to be confirmed," NEB said. "Initial estimates are about 20%."

Summaries of its shale descriptions follow.

• The Montney formation produces from conventional shallow-water shoreface sandstones on its eastern edge and from deepwater tight sands at the foot of the depositional ramp to the west. Hybrid gas potential exists in the Lower Montney, involving sandy, silty shales of the offshore transition and offshore-marine parts of the basin, and the Upper Montney, below the shoreface where silts buried the tight sands at the foot of the ramp.

Because the Montney is more than 300 m thick in places, operators are planning stacked horizontal wells, drilling and fracing laterals in both the Upper and Lower Montney.

Estimates for the Montney formation exclude the overlying Triassic Doig phosphate, which also has shale gas potential.

Citing British Columbian data, NEB said operators had spent $2.4 billion for Montney gas rights in government auctions in 2005-08, $1.3 billion in 2008 alone.

As of last July, NEB said, 234 horizontal wells were producing 376 MMcfd from the Montney shale, mostly from the Heritage pool of British Columbia.

Individual wells produce 3-5 MMcfd generally, occasionally more than 10 MMcfd, at start-up, followed by rapid declines. The wells usually have 7 to 9 and as many as 12 100-tonne carbon dioxide or water frac stages over 2-km horizontal legs.

• In the Horn River basin, shales rich in silica lie at the foot of the Devonian Slave Point carbonate platform, which has long produced gas from conventional reservoirs. Operators have drilled, hydraulically fractured, and placed on production about 20 horizontal Horn River wells.

Before starting their steep declines, wells in the area produce at start-up at rates as high as 16 MMcfd. Production data in the Horn River basin remain confidential.

Associated with the Horn River basin play and to the east is the Cordova embayment, which has an estimated 200 tcf of gas in place but remains at a much earlier stage of evaluation.

NEB said that as of May operators had spent more than $2 billion in British Columbia government auctions for resource rights in the Horn River basin and less than $40 million in the Cordova embayment.

• The Colorado Group comprises shaley strata deposited in southern Alberta and Saskatchewan in the Middle Cretaceous. It includes the Medicine Hat and Milk River shaley sandstones, which have produced gas for more than 100 years, and the Second White Speckled shale.

Colorado Group shale, like the Montney, is a hybrid, producing through thin sand beds and laminae. It's underpressured, sensitive to water, and therefore difficult to frac. Operators are testing the use of nitrogen and mixtures of propane and butane as frac fluid.

More than 3 MMcfd is flowing from "a few dozen" shallow vertical wells in the Wildmere area of Alberta, where the Colorado shale is about 200 m thick and has potential to produce from five intervals. Wells cost $350,000 each from drilling through connection with pipelines.

Noting the difficulty of estimation given the shale's great lateral extent and reservoir variability, NEB said the Colorado Group might hold at least 1 tcf of gas in place.

• The Utica shale was deposited in deep waters at the foot of the Trenton carbonate platform. Caught later in early Appalachian Mountain growth, it became faulted and folded to the southeast. It's the source rock for conventional oil reservoirs.

The Utica shale has higher concentrations of calcite, which is less brittle than the silica it displaces, than other Canadian gas shales. It contains biogenic gas in shallow areas and thermogenic gas at greater depths.

Vertical wells after fracing in the Utica shale are reported to have produced 1 MMcfd of gas. Three hydraulically fraced horizontal wells are reported to have tested 100-800 Mcfd of gas from medium-deep shales.

The overlying Lorraine shale might have potential but is richer in clay and therefore difficult to frac.

• In the Canadian Maritimes, the Horton Bluff Group contains lacustrine muds deposited during regional Early Mississippian subsidence.

The average silica content of the group's Frederick Brook shale is 38% in New Brunswick, but the clay content also is high at 42%. In Nova Scotia, the Frederick Brook member has an organic content of 10%, much higher than other Canadian gas shales.

Frederick Brook thickness may be greater than 150 m, NEB said, sometimes exceeding 1 km in New Brunswick. Flow testing is in progress. Although hydraulic fracing has been less successful than in western Canada, two vertical Frederick Brook wells in New Brunswick have flowed 150 Mcfd after small fracs.

Corridor Resources has estimated that the Frederick Brook shale of the Sussex and Elgin subbasins of southern New Brunswick holds 67 tcf of free gas in place. Ryder Scott Co. has estimated 69 tcf of gas in place on the Windsor Block in Nova Scotia. Samples in Nova Scotia indicate most of the gas is adsorbed onto clay and organic matter, requiring effective stimulation.

Apache Canada, a large Horn River basin participant, recently joined Corridor in the Frederick Brook play (OGJ Online, Dec. 8, 2009).

The future

The NEB said shale gas "may be a key component that will allow Canada to sustain its own domestic requirements for natural gas far into the 21st Century," supplemented, perhaps, by other resource plays such as coalbed methane and tight sandstones and carbonates and by future production from frontiers offshore and in the north.

Shale gas might even allow Canada to export LNG, NEB said, citing memorandums of understanding signed by Horn River basin operators Apache Corp. and EOG Resources to supply a proposed liquefaction plant in British Columbia.

But the play overall remains young. "Only the Montney and Horn River basin gas shales can be said to have 'proof of concept' through numerous production tests after horizontal drilling and hydraulic fracturing," NEB said. And only the Montney is producing at significant rates.

Economic uncertainties remain. And concerns have arisen about environmental effects, especially water requirements and carbon dioxide emissions, although proposals have come forward for carbon capture and sequestration projects.

Furthermore, the pace of development may be limited by supply of required resources, such as fresh water, fracture proppant, or drilling rigs.

The play is still in early stages. But the potential boost to Canadian gas supply is great.

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