The revolution in unconventional technology has unlocked a new generation of oil and gas plays in Canada and around the world. Hundreds of formations are now being evaluated to determine if they are amenable to production using the specialized knowledge that has been developed in the past two decades for unconventional targets, from coalbed methane (CBM) to tight sands to shales.

Here, briefly, is a summary of what Hart Energy sees as the best of the best in the Canadian unconventional world.

Ordovician

Utica Shale (Appalachian Basin and St. Lawrence Lowlands, U.S. and Canada)

The Late Ordovician-age Utica Shale in the Appalachian Basin occurs some 610 m to 1,219 m (2,000 ft to 4,000 ft) below the younger Marcellus Shale in Ohio, and as much as 2,134 m (7,000 ft) beneath the Marcellus in central Pennsylvania. The Utica is shallowest in Ohio and beneath the Great Lakes; it outcrops in Quebec.

The thermally mature, organic-rich Utica has a high carbonate component. The Utica tends to be liquids-prone to the west, trending to wet gas and then dry gas to the east. It contains Type II kerogen, and core data indicates that total organic carbon (TOC) content is in the range of 3% to 4%.

Often grouped with the Utica in Ohio and a primary target for exploration, is the Point Pleasant. This unit is the lateral equivalent of the upper portion of the Trenton Limestone and grades into the overlying Utica shale. The Utica, including the Point Pleasant interval, ranges in thickness from zero m to 137 m (zero ft to 450 ft), generally thickening into the basin.

In Ohio, which is the most prospective area for the Appalachian Utica, the Ohio Geological Survey has calculated that recoverable reserves from the interval can range from 2 Bboe to 8.2 Bboe.

An October 2012 assessment released by the U.S. Geological Survey estimated that the Utica Shale contains a mean of 38 Tcf of technically recoverable natural gas, 940 MMbbl of oil and 208 MMbbl of NGL.

The Utica shale also occurs in Eastern Canada, in the St. Lawrence Lowlands of Quebec. Here, the shale has been extensively impacted by tectonic activity. The depth ranges from 914 m to more than 3,353 m (3,000 ft to more than 11,000 ft), and thickness ranges from 305 m to more than 914 m (1,000 to more than 3,000 ft). TOC values are 1% to 3%, and thermal maturity is high.

Most of Canada’s Utica Shale lies in the dry-gas window, according to the U.S. Energy Information Administration’s 2011 assessment of world shale. That study estimated gas in place (GIP) at 348 Bcf/sq km (134 Bcf/sq mile). For Canada’s portion of the Utica Shale, risked GIP gas is 155 Tcf, and technically recoverable gas is 31 Tcf.

Devonian

Horn River Group Shales (Horn River Basin, Canada)

Horn River shales are Middle Devonian in age, and they lie in the remote Horn River Basin in far northern British Columbia. The shales are generally divided in to two groups: the uppermost Muskwa and Otter Park, and the lower Klua and Evie shales. The two are separated by a tight, thick carbonate zone. Total shale thickness reaches 182 m (600 ft), and depths are 1,981 m to 2,743 m (6,500 ft to 9,000 ft).

The Horn River Shale contains 55% silica, and TOC ranges from 1% to 6%. The shales are thermally mature and entirely within the gas window, between 2.2% and 2.8 % Ro. They are also HP/HT, and the produced gas contains up to 12% CO2 and trace amounts of H2S.

The Horn River Group shales are prospective across an area of 3.2 million acres. They are considered to be one of the major shale-gas deposits of the world.

A commonly used estimate for GIP for the Horn River Shale is 500 Tcf, and that figure agrees well with the EIA. The latter agency estimates gas resources of 395 Bcf/sq km (152 Bcf/sq mile) in the Muskwa and Otter Park shales and 143 Bcf/sq km (55 Bcf/sq mile) in the Evie and Klua shales. Overall, the Horn River Shale holds 488 Tcf of risked GIP, and 165 Tcf is considered technically recoverable.

Bakken Shale (Williston Basin, U.S. and Canada)

The Bakken Shale has quickly become one of the most significant unconventional reservoirs in the world. It has a wide distribution: the formation occurs in eastern Montana, western North Dakota, southern Saskatchewan, and even extends into western Manitoba. It is Late Devonian-Early Mississippian in age, and consists of an upper and lower shale member and a mixed-lithology middle member, usually characterized as a silty dolomite or dolomitic siltstone.

The thickness of the Bakken varies across its extent, from a thin edge to more than 38 m (125 ft). The thickest area is just east of the Nesson Anticline, a structural feature that influenced both depositional patterns and hydrocarbon migration.

A majority of samples collected from the Bakken indicate a Type-I and II oil-prone kerogen (algal origin). The Bakken grades from thermally immature in the eastern portion of the Williston Basin to mature in the central and western portions of the basin. The middle member is the main producing reservoir. The Bakken petroleum system is self-sourced; in situ generation of hydrocarbons occurred in the oil kitchen. The formation is also regionally overpressured because of hydrocarbon generation.

The combo of a uniquely closed petroleum system, a high thermal gradient and volumetric expansion of the Upper and Lower Bakken kerogen into oil has resulted in high potential for creating in situ fractures parallel to bedding planes.

In 2008, the U.S. Geological Survey estimated that the Bakken in North Dakota and Montana had an estimated 3 Bbbl to 4.3 Bbbl of undiscovered, technically recoverable oil. Industry estimates in the intervening years have ranged far higher, and the USGS is currently working on an updated assessment.

Triassic

Montney Formation (Western Canada Sedimentary Basin, Canada)

The Early Triassic Montney Formation is tight gas-shale gas, hybrid reservoir that is found in northeastern British Columbia and also extends into western Alberta. Wherever the Montney occurs, it unconformably overlies either Permian or Carboniferous strata; above the Montney is the Middle Triassic Doig Formation, which also can be a drilling target.

The Montney is a complex play that has different lithologies, from near-shore, fine-grained sandstones and siltstones on its eastern side in west-central Alberta to deep-water, very-fine-grained siltstones and shales to the west in British Columbia. The formation has been a conventional producer in areas of high-quality reservoir, but today unconventional potential is being pursued in the lower-permeability facies in both the Upper and Lower Montney.

The Montney ranges in depth from 1,500 m to 3,500 m (4,921 ft to 11,482 ft), and pressures vary from normal to overpressured. Porosity ranges from 2% to 9%. TOC varies from 0.4% to 4%, and thermal maturity varies across the play from rich gas to dry gas.

For the Montney’s shale portion only, the EIA estimated risked in-place resources at 141 Tcf, and technically recoverable resource at 49 Tcf. Advanced Resources noted that it had separately assessed the Montney tight gas sand GIP resource at more than 500 Tcf. A study by MIT on the future of natural gas assigned 1,536 Tcf of risked GIP, and 230 Tcf of technically recoverable gas for the Montney.

Cardium Tight Sand (Western Canada Sedimentary Basin, Canada)

The Late Cretaceous-age Cardium Formation contains fine-grained sandstone, interbedded sandstone, and silt and shale, and in places isolated overlying conglomerates. It was deposited in environments ranging from coastal plain to shoreface to shallow shelf and offshore.

The Cardium occurs in western Alberta, and extends into eastern B.C. and northern Montana.

The Cardium forms a sizeable stratigraphic trap in its eastern shaleout, creating Canada’s largest conventional onshore oil field, dubbed Pembina. The producing region spans approximately 350 km by 100 km (217 miles by 60 miles), in an area west of Edmonton and north of Calgary.

The formation wedges toward the east, with a thickness greater than 165 m (541 ft) in the west and decreasing to a thickness less than 50 m (164 ft) in the east. It is found at depths of 1,200 m to 2,700 m (3,937 ft to 8,858 ft). Porosity ranges from 3% to 12%, and permeability from 0.1 to 50 millidarcy.

The Cardium spans the continuum from conventional to unconventional. It is a “halo” play and is included as an unconventional reservoir because the application of horizontal drilling and multistage fracturing technology has made previously uneconomic tight facies of the formation economic to produce.

The Cardium contains potential resources of 6 MMboe to 16 MMboe per section. An estimated 12 Bbbl to 17 Bbbl remain in place.