For the purpose of CO2 storage, the geology of Ontario can be divided into three generalized rock types (Figs. 1 and 2). The lowermost and oldest rocks consist of Precambrian rocks of the Canadian Shield ,which underlie most of the North American continent and formed more than 1 billion years ago. Overlying the Canadian Shield to the north and to the south are younger sedimentary rocks. These range from 540 to 360 million years in age and were deposited in sedimentary basins when Ontario was flooded by shallow tropical seas. The final uppermost layer consists of thin deposits of largely unconsolidated sediment or “drift” deposited during the last million years, largely as a result of glaciation.
The rocks of the Canadian Shield consist of either igneous rocks (cooled directly from magma) or metamorphic rocks (igneous or sedimentary rocks that have undergone intense deformation due to pressure and heat). Except where they have been fractured, these rocks have low porosity and permeability and are thus generally unsuitable for CO2 storage. The unconsolidated sediments of the uppermost layer have good porosity and permeability, however, these sediments are open to the atmosphere, are major sources of potable groundwater and are very thin. This leaves Paleozoic rocks for consideration. These occur in the far north and in southern Ontario (Fig.1)
Four major sedimentary basins occur within Ontario (Fig. 1). In northern Ontario, sedimentary rocks occur within the Moose River and Hudson Bay basins. These basins tend to be too shallow for carbon storage, reaching depths of approximately 500 m in the Moose River Basin and 1000 m in the Hudson Bay Basin. They are also remote from large point sources of CO2 emissions and thus are presently impractical for consideration as candidates for geological sequestration. In southern Ontario, thick accumulations of sedimentary rocks are present in the Michigan and Appalachian basins. Rocks within these basins were originally horizontal, but have subsequently tilted and deformed forming a northeast-trending ridge known as the Algonquin Arch (Fig. 3). Because of this, the thickness of the rocks increases westerly into the Michigan Basin and southerly into the Appalachian Basin, reaching a maximum thickness of about 1400 m beneath Lake Erie and at the southern tip of Lake Huron, and much greater thicknesses beneath the neighbouring U.S. states (Fig.8, 9). Extensive development of porosity and permeability is evidenced by the presence of oil and gas reservoirs and regional saline water aquifers in these basins.
The sedimentary rocks within the Michigan and Appalachian basins are distinguished by geologic age and further subdivided into formations that can be mapped in the subsurface (Fig. 4). The oldest and lowermost rocks are of Cambrian age and consist mainly of sandstones. Younger sandstone, shale, limestone and dolostone rocks of Ordovician, Silurian and Devonian age overlie the Cambrian rocks.
The feasibility and potential for geological sequestration of CO2 in Ontario is directly related to geology since in the absence of suitable geologic features all other technical criteria are irrelevant. Thus the following analysis summarizes the potential for geological storage of CO2 and identifies possible options for further study. Options considered are coal beds and organic shales, oil and gas reservoirs, saline aquifers and salt caverns.
While injection of CO2 into deep coal seams to enhance the production of coal bed methane is being tested in other parts of North America, no deep coal seams are present in Ontario. This option is not considered further in this analysis.
In Kentucky, Devonian-aged, low permeability, organic gas-rich shales are being studied as a potential site for CO2 storage (Nuttall et al. 2005). Devonian shales within Ontario are too shallow (200 m and less) to provide an adequate pressure and temperature regime for the storage of CO2. Organic-rich shales at the base of the Blue Mountain Formation (Fig.4) locally occur at depths greater than 800 metres but their suitability for CO2 storage has not been studied.
Accumulations of oil and gas occur in porous and permeable rock and are known as reservoirs or pools. The key features of a good reservoir are high porosity and permeability to allow the hydrocarbons to migrate and pool in the rock and the presence of an impermeable layer above the porous rocks to form a trap or seal. Without the latter, due to its buoyancy relative to water, any oil or gas in the rock would migrate upwards towards the surface. The same holds true for CO2 in the subsurface as it is also buoyant in water (at shallow depths). Due to their porosity and permeability sandstones and dolostones tend to be the best reservoir rocks while limestones and shales tend to act as a seal. The same geological characteristics that form good oil and gas reservoirs also make them excellent candidates for storage of CO2.
Oil and gas reservoirs in Ontario are found at a variety of depths and in different rock types. Common reservoirs include Cambrian sandstones (at depths of 800-1200 m), Ordovician carbonates (900-800 m), Silurian carbonates (500-700 m and 350-450 m), and Devonian carbonates (110-140 m) all of which occur in southwestern Ontario. To date neither oil or natural gas have been discovered in the Hudson Bay and Moose River basins or in eastern Ontario. A total of 262 oil and gas pools occur in southern Ontario with cumulative production of 1.3 trillion cubic feet of natural gas and 85 million barrels of oil (Carter et al, 2006)(Fig. 5).
Studies for the potential storage of CO2 in depleted oil and gas reservoirs in Ontario or for use of CO2 for enhanced oil recovery have not been completed. Shafeen et al. (2004a) considered that the shallow depth of the reservoirs, large number of unplugged wells and limited pore volume renders this option unfeasible in Ontario. Individual reservoirs may prove to be technically suitable but would require further study to confirm
Injection of CO2 into salt caverns is being considered for both permanent and temporary storage in major salt-producing formations in other parts of the world. Salt is impermeable to supercritical CO2 and therefore provides an ideal trapping mechanism for the gas (Dusseault et al. 2001). Ontario produces large quantities of salt from solution mining operations and has a number of abandoned caverns where salt extraction no longer occurs. Unfortunately, the Salina Group from which the salt is produced occurs at too shallow a depth to provide the necessary conditions for storage of large quantities of CO2. Depth to salt beds beneath Lake Huron is unknown but if deep enough there may be potential for construction of salt caverns for storage beneath the lake.
When a porous rock contains water instead of oil or gas it is known as an aquifer. Two types of aquifers can be distinguished in southern Ontario; deep saline aquifers in the Paleozoic bedrock and fresh water aquifers in the unconsolidated sediments (glacial drift) overlying the Paleozoic and Precambrian bedrock and locally in near-surface Paleozoic bedrock. Fresh water aquifers are shallow, recharged by meteoric waters, and are sources of drinking water in Ontario and therefore are not candidates for CO2 storage. Saline aquifers occur within the sedimentary bedrock in the basins of southern Ontario and Hudson Bay, generally at depths greater than a few tens of metres or wherever the bedrock is covered by thick accumulations of glacial drift. Saline aquifers are usually isolated from fresh water aquifers. While all porous rocks in the subsurface of southern Ontario are filled with water (or locally with hydrocarbons) only a few of these form porous layers thick enough or regionally extensive enough to comprise significant aquifers. Waters within these deep aquifers contain elevated concentrations of salt and/or sulphur and are generally not suitable for drinking, irrigation or other domestic purposes. Therefore, injection of CO2 should not pose a risk for future use and in fact CO2 is naturally present in groundwater (Ballentine et al. 2001, Hutcheon and Abercrombie 1990).
Shafeen et al (2004a) assessed saline aquifers within all the sedimentary basins of Ontario to determine the best candidates for CO2 storage. Paleozoic sedimentary rocks in the Hudson Bay and Moose River basins and in eastern Ontario were deemed either too shallow to provide the conditions for CO2 storage or too distant from large point sources of CO2 to make them viable options. Only saline aquifers in the Michigan and Appalachian basins in southern Ontario were considered suitable.
Within the Michigan and Appalachian basins the Upper Cambrian age Mt. Simon Formation is considered the best candidate for CO2 storage. Most of the other sedimentary formations are too shallow. The Mt. Simon Formation (Fig 6) is a saline aquifer consisting of regionally extensive, porous sandstone underlying large parts of southern Ontario and the neighbouring U.S. states. It occurs close to point sources of CO2 generation and an established pipeline infrastructure. The formation thickens to the west under Lake Huron and into Michigan as part of the Michigan Basin and to the south under Lake Erie and the adjacent states within the Appalachian Basin and pinches out over the top of the Algonquin Arch. The formation is overlain by dolomitic and sandy shales of the Shadow Lake Formation and non-porous limestones of the Gull River Formation which serves as a cap rock (Fig. 4, 6). The Shadow Lake Formation is overlain by an additional 600 or more metres of non-porous Ordovician limestones and shales, which form an excellent barrier to upward movement of fluids (Fig. 4).
Shafeen et al. (2004a) divided the available storage within the Mt. Simon Formation into two zones on either side of the Algonquin Arch, which separates the Michigan and Appalachian Basins (Fig. 1). Their northern zone (6,250 km2) consists of the southern half of Lake Huron and the northern part of Lambton county. The southern zone (9,525 km2) extends into Lake Erie and includes parts of Essex, Lake St. Clair, Kent, Elgin and Haldimand-Norfolk counties. Calculated storage capacities are based on the lateral extent of the formation, estimates or assumptions of formation thickness, porosity, and permeability, and assumptions about potential CO2 saturation within these two areas.
Shafeen et al. (2004a) estimate that the Mt. Simon Formation saline aquifer could be capable of storing 289 million tonnes (Mt) of CO2 in the northern zone and 442 Mt in the southern zone. These calculations were based on an assumed average porosity of 10% with an assumed average thickness of 31 m. No detailed thickness maps were prepared and no drill core or cuttings were examined. The capacity estimates are also based on estimates/assumptions of the salinity of the formation (which controls the CO2 solubility) and of the achievable sweep efficiency (effectiveness of the injected CO2 contacting the pore space of the aquifer). The estimates of storage capacity are very sensitive to the assumed values for porosity, permeability, sweep efficiency, and solubility. In the southern storage zone, for example, increasing the porosity from 10 to 25% results in 1104 Mt storage capacity while decreasing it to 5% reduces the capacity to 220 Mt. The greatest increase in storage capacity can be realized by increasing the sweep efficiency. This may be possible with multiple injection locations and better technology. However, better characterization of the Cambrian reservoirs is clearly needed to accurately estimate the potential for long-term storage of CO2 in order to justify the large capital expenditures necessary for CO2 capture.