Alberta’s emerging shale and/or siltstone formations could ultimately yield 423.6 billion barrels of oil, 58.6 billion barrels of liquids and 3.3 trillion cubic feet of natural gas, says a long-awaited report by the Alberta Energy Resources Conservation Board and the Alberta Geological Survey.
The report is designed to provide baseline data, information and understanding of the geology, distribution, reservoir characteristics and hydrocarbon resource potential of Alberta shales.
The calculations for the formations, including the Duvernay, Montney and Muskwa, put the deposits in the same league as some of the major U.S. shale plays as part of the radical industry shift from conventional operations to horizontal drilling and hydraulic fracturing.
Andrew Beaton, one of the report’s authors, said the numbers fall roughly into line with the Eagle Ford and Marcellus shales and approximate numbers reported so far by companies exploring the shale prospects in Alberta.
Potential beyond oil sands
The findings bolster the view that Alberta has immense hydrocarbon potential beyond its oil sands, rated as the world’s third-largest deposit at 170 billion barrels of proven reserves and an ultimate potential of 1.7 trillion barrels.
The Duvernay and Montney have already attracted strong investments from Encana, Chevron and Talisman Energy, with ExxonMobil joining the scramble in October by negotiating a C$2.6 billion takeover of Celtic Exploration, while a host of mostly state-owned Asian companies have stakes out minority positions.
The study says the Duvernay formation, which cuts across much of north-central Alberta, contains 61.7 billion barrels of oil, 11.3 billion barrels of liquids and 443 tcf of gas, while the Muskwa in northwestern Alberta has 115.1 billion barrels of oil, 14.8 billion barrels of liquids and 419 tcf of gas.
Western Alberta’s Montney — which also extends into a major exploration area in northeastern British Columbia — has estimated resources of 136.3 billion barrels of oil, 28.9 billion barrels of liquids and 2,211 tcf of gas.
However, the Montney is not strictly rated as a shale target because it is dominated by siltstone and has been included because it is a target for unconventional resources.
The findings also cover a preliminary assessment of the Colorado, Wilrich and Rierdon units as well as a summary of the Bantry shale unit.
Technical snapshot of Exshaw findings
The basal Banff/Exshaw resource assessment was limited to southern Alberta “due to data availability and current industry focus”, the report said.
In addition to sourcing conventional reservoirs the Exshaw shale is recognized as a major source rock for heavy oil and bitumen deposits in northern Alberta. The combined interval of the Exshaw formation and the basal shale of the Banff formation is stratigraphically equivalent to the Bakken formation in the Williston Basin, the study said.
Extending into northern and northwestern Montana, the play is often referred to as the southern Alberta Bakken or the southern Alberta Bakken basin by industry.
“For this project,” the findings noted, “the terms lower shale, middle unit, and upper shale correspond to the Exshaw shale (lower Bakken), the upper Exshaw (middle Bakken), and the lower Banff basal black shale (upper Bakken), respectively.”
The basal Banff/Exshaw has a large variation in primary lithologies. The upper and lower shales are dominated by dark grey to black, fissile, hard-to-soft, calcareous to noncalcareous, organic-rich shale.
The middle unit consists of various lithologies, including calcareous sandstone, argillaceous sandstone, dolomitic siltstone, calcareous siltstone, silty lime-mudstone, limestone, and dolostone.
The variation in primary lithologies, the report said, “may indicate that the Exshaw and basal Banff merit a more detailed stratigraphic study to determine erosional boundaries and confirm stratigraphic equivalence to the Bakken.”
In the study area, depth to the top the basal Banff/Exshaw ranges from 500 meters (1,640 feet) near the subcrop erosional edge to about 4000 meters (13,123 feet) along the deformed belt.
The upper and lower shales are both thin. The thickness of the lower shale ranges from 4 to 13 meters, or 13 to 43 feet. The upper shale is more difficult to correlate and has a smaller aerial extent than the lower shale. The upper shale ranges from <1 to 2.3 meters, or <3 to 7.6 feet, thick.
The gross isopach of the middle unit in southeastern Alberta ranges from zero to 40 meters, or zero to 131 feet, along a roughly northeast-to-southwest trend.
Four wells were selected for a cross-section that displays the stratigraphic relationship of the three units and the correlation to the Bakken.
A porosity-thickness, or Phi-h, map of the basal Banff/Exshaw was constructed for the study, using density-porosity logs calibrated to a grain density of 2.74 g/cm3 with no porosity cutoff and a >75 API gamma-ray–log cutoff.
The gamma-ray cutoff excluded any lithology, such as sandstone or limestone that was relatively free of argillaceous material.
The map shows high porosity-thickness values in the northeast near the erosional edge. Current hydrocarbon exploration is concentrated in the southwest corner of the study area.
The grain density used to determine porosity accounted for the presence of total organic carbon by converting TOC to kerogen and counting it as a mineral component. The methodology used works well, the findings said, when the TOC content range spans only a few weight per cent.
“The TOC content of the upper and lower shale, however, is quite variable which may cause significant error in the calculation of the porous volume of shale in our methodology,” the report said. “For the present resource estimation, we chose not to include the porous volume of the shale. A well-by-well evaluation of the data is necessary to achieve a reliable estimate of shale porosity. However, because the upper and lower shales are quite thin, the resource estimate may not change dramatically by this exclusion.”
The resource estimate for the basal Banff/Exshaw “is based on the adsorbed gas content of the upper and lower shales, as well as the porous volume of the middle unit, which is the primary production unit in the Bakken play in the Williston Basin.”
The TOC content ranges from 0.1 to 16.9 weight percent in the findings, based on 75 samples from 13 wells. The
TOC content of the middle unit is generally <1.0 wt. % in the southern area.
“There is some indication that the northern area may contain a higher content of TOC,” the report said. “The thermal maturity of the basal Banff/Exshaw source rocks, based on vitrinite reflectance data, exhibits increased maturity to the southwest, corresponding to an increased depth below the surface.”
Using Dean Stark analysis and helium pycnometry on select samples, the laboratory calculated water saturation.
“The distribution of values for the basal Banff and Exshaw formations in the southern area shows dominance in the range of about 10 percent to 50 percent, which we used as P90 and P10 constraints in our resource evaluation,” the report said.
Constraints not considered
The report cautioned that the numbers represent “endowment of hydrocarbons” and that geological and engineering constraints along with economic, social and environmental considerations will eventually determine the volumes that can be recovered.
Co-author Dean Rokosh said the operators will be in the best position to say which plays are economic.
“It’s still a learning stage in every one of these formations,” he said.
Data and information produced by the study may help in the evaluation, exploration and development of the resources and can be used by industry to help identify shale gas prospects, plan effective drilling and completions strategies and guide land acquisition decisions.
In Alberta, 15 formations have the potential for shale and/or siltstone-hosted hydrocarbons, which may represent a valuable resource for the province, the report says.
Estimates for the total amount of gas in Alberta shale vary from 80 tcf to 100 tcf, pointing to the “great potential size of the resource, which can contribute to economic benefits and energy security for Alberta.”
The Energy Resources Conservation Board launched its study of shale- and siltstone-hosted hydrocarbons in 2006, initially focusing on shale gas in the formations which had attracted industry interest, such as the Colorado shales and the Banff/Exshaw.
As the study moved ahead, the ERCB found that many of the formations it was analyzing also contained significant quantities of natural gas liquids and oil, prompting it to expand the assessment.
In total, 3,385 samples were analyzed, including duplicates and standards for quality control.
Samples were collected from 65 outcrops and core samples were taken from 316 wells. Of the total samples collected, 2,746 were from core, 440 were from outcrops and 199 were standards and duplicates. Some of the data generated by the ERCB’s resource appraisal group will be presented in future digital databases.
Read the full report at http://www.ags.gov.ab.ca/publications/OFR/PDF/OFR_2012_06.pdf
—Gary Park
