Geology of Shale and Tight Resources
A product of the Energy and Mines Ministers’ Conference
Shale and tight resources are hydrocarbons (crude oil, natural gas and natural gas liquids) found in tight reservoirs – rocks with pores so small or poorly connected that the oil and natural gas cannot flow through them easily. Hydrocarbons found in these types of reservoirs are referred to as “tight gas” or “tight oil”. Shale is a common type of tight reservoir that is composed of extremely fine-grained, sedimentary rock and may contain oil or natural gas – referred to as “shale oil” or “shale gas”.
Like all hydrocarbons, they formed over millions of years, when organic material (plants and micro-organisms) was buried and subjected to increasing heat and pressure and slowly transformed to oil and natural gas. Some of these hydrocarbons escaped into adjacent rock layers that are relatively easy to extract because of their reservoirs’ high porosityFootnote 1 and permeabilityFootnote 2. However, the majority remained locked in tighter, lower permeability layers where they could not be extracted through conventional means.
Shale and tight resources are essentially the same kind of oil and natural gas as their conventional counterparts. They are “unconventional” simply because of the methods used in their extraction, and the types of reservoir from which they are produced.
The ability of a reservoir to produce hydrocarbons is related to both its porosity and permeability.
Reservoir rocks are like sponges in that they hold oil and natural gas in cavities (pores) present naturally in rocks. The percentage of pore volume within the rock is called the reservoir’s porosity.
In conventional reservoirs, pore space can vary from fairly large, visible openings to microscopic pores, and generally comprises less than 30 percent of rock volume. In tight reservoirs, porosity is commonly less than 10 percent.
However, regardless of the total porosity volume, if these pores are not efficiently connected one to the other, oil and natural gas cannot move and be extracted. This plumbing system is known as permeability and is as important as the porosity for reservoirs. The higher the permeability, the greater the amount of fluid that can flow through the rock.
Permeability is commonly measured in a unit called millidarcies. Conventional reservoirs may have permeability in the range of tens to hundreds of millidarcies. Tight reservoirs usually have permeability from 0.1 to 0.001 millidarcies, and shale reservoirs are even less permeable – in the 0.001 to 0.0001 millidarcies range. As a result, the average permeability of tight and shale reservoirs is usually too small to allow commercial production unless unconventional extraction techniques (horizontal drilling and hydraulic fracturing) are used.
In conventional reservoirs, hydrocarbons move easily through the formation until they are trapped against an impermeable rock – referred to as a “seal” or “cap” rock. This leads to localized pools of oil and natural gas that can be accessed with a vertical well drilled directly into the reservoir.
In tight reservoirs, hydrocarbons are often found within the same rocks in which they were generated. Otherwise, hydrocarbons in tight reservoirs can be found in the pore spaces and natural fractures of any tight rocks into which they migrated. Shale and tight resources tend to be widely distributed over extensive areas rather than concentrated in specific locations.
Conventional, Tight, and Shale Gas and Oil
Estimates of Canada’s shale and tight resources vary. Federal and provincial governments and regulators are in the process of developing a comprehensive and standardized approach to evaluate Canada’s shale and tight resources. Some industry claims of potential Canadian shale and tight resources still require independent verification by public geological assessments or commercial production.
Different types of estimates are used to measure the volume of available hydrocarbons. A key distinction is between “resources,” which may not yet be discovered or may not be economic to recover, and “reserves,” which are discovered by drilling and economic to recover. Estimates fluctuate due to changes in economic conditions, technology and available information. As more data become available, the accuracy of estimates will improve
The Canada Energy Regulator (CER, formerly the National Energy Board) estimates that Canada has 1,087 trillion cubic feet of remaining marketable gas resources, of which 750 trillion cubic feet is unconventional shale and tight gas. At the end of 2014, the CER estimated that Canada had approximately 171 billion barrels of remaining oil reserves, of which 97 percent is the oil sands and the rest is conventional and tight oil sources.
What are the different types of estimates of oil and gas resources?
- Oil/gas in place: The total volume of oil or natural gas that is contained within the reservoir. It does not indicate how much of that oil or natural gas is recoverable.
- Marketable oil/gas: Oil or natural gas that has been processed to remove impurities such as natural gas liquids and non-hydrocarbon by-products (e.g., CO2, H2S).
- Technically recoverable oil/gas: The volume of oil or natural gas that could be recovered from known reservoirs with current technology, regardless of economic conditions (e.g., prices, production costs).
- Economically recoverable oil/gas The volume of oil or natural gas that could be recovered from known reservoirs under foreseeable economic conditions (e.g., prices, production costs).
- Ultimate potential: The volume of proved reserves and technically recoverable marketable oil or gas inferred to exist from geological information but not yet discovered by drilling.
- Established reserves: The volume of technically and economically recoverable marketable oil or gas specifically proven by drilling, testing, or production, or estimated to exist with high certainty from geological or geophysical information.
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