Alberta’s royalty framework is a set of tools to determine and collect an appropriate government share of resource development.
While the royalty framework is primarily a way to collect revenue, government anticipates that the new modernized royalty framework will encourage innovation and efficiencies. This will allow more use of multiple wells on common pads, reducing the environmental footprint from well pads and access roads. It will also ensure wells are able to maximize the recovery of oil through additional recovery techniques, extending well life and end of life economics, which can help companies prepare for and use best abandonment practices.
To ensure environmental responsibility, the government has a set of tools, including the Alberta Energy Regulator (AER). AER is the provincial regulatory body responsible for regulating the life cycle of oil, oil sands, natural gas and coal projects. Environmental responsibility is managed mainly through regulation by the AER and the Alberta government.
Projects are regulated in all phases of their life cycles, including:
- application and construction
- water allocation and conservation
The AER reports on a number of environmental indicators. For more information, go to the AER website.
Environmental indicators will also be monitored and reported as part of reporting on the royalty framework. We can tell how the oil and gas sector is impacting the environment by tracking:
- greenhouse gas emissions
- the amount of water used for oil and gas extraction
- tailings ponds
- pipeline safety
More environmental indicators may be developed to reflect any changes from the Modernized Royalty Framework.
At a glance
- In 2014, oil sands greenhouse gas emissions per barrel were 31% below 1990 levels. Oil sands operations currently emit roughly 70 megatonnes (Mt) of emissions per year.
- Alberta’s oil and gas industry only uses a third of its total water allocation per year.
- The total area occupied by oil sands tailings ponds and associated structures (such as dikes) was 220 km2 at the end of 2013.
- Over the past 10 years, as the length of pipelines grew by 11%, the number of pipeline incidents dropped by 44%.
Greenhouse Gas Emissions
Normal business procedures have reduced greenhouse gas emissions by more than 61 million tonnes since 2007.
Figure 1. Energy related greenhouse gas emissions by province and territory
Figure 2. Alberta greenhouse gas emissions by sector
In 2014, oil sands greenhouse gas emissions per barrel were 31% below 1990 levels. Oil sands operations currently emit roughly 70 megatonnes (Mt) of emissions per year.
Alberta is placing an oil sands emissions limit of 100Mt per year and implementing a new carbon price on greenhouse gas emissions.
Alberta is also reducing methane gas emissions from oil and gas operations by 45%.
In 2014, methane emissions from Alberta’s oil and gas sector were 31.4 megatonnes of carbon dioxide equivalents. This accounted for 70% of provincial methane emissions and 25% of all emissions from the upstream oil and gas sector.
Government allocates water as part of the overall management of this valuable resource. Licences specify the maximum volume per year, if water is available and all other licence conditions are met. Government considers the range of possible demands and usage during the term of the licence; this means licensed allocations generally are higher than actual usage.
For example, a municipality’s water allocation may reflect future growth, and an irrigation district may reflect needs during a drought that isn't needed in average or wet years. This approach gives some flexibility to operate, while still giving government the means to assess and manage the resource. This is why water used by oil sands mines and in situ operations is usually far below the operator’s allocation.
Water Use Intensity (AER)
Water use intensity measures the amount of water (in barrels) needed to produce one barrel of oil equivalent (BOE). Over the past 5 years, oil sands mining had the highest nonsaline (fresh) water use intensity at 2.7 barrels per BOE. Enhanced oil recovery, in situ, and hydraulic fracturing used significantly less water, with average intensities of less than half a barrel (0.5) per BOE.
In most cases, this is based on the amount of new or “makeup” water (makes up water lost during processing). However, oil sands projects, in particular, recycle a high percentage of the water they use. Many applications, oil sands or otherwise, use saline (salty) groundwater from deep rock formations that is not potable. Waste water eventually is injected into deep rock formations.
No project or potential use uses all its water allocation. Some may be planned for use in future expansion, or is not used if the project operator successfully in recycles or finds sources of non-saline water.
Figure 3. Nonsaline water use intensity by extraction technology
Oil sands mining
Oil sands mining is the largest user of nonsaline water in the industry. That’s because large amounts of nonsaline water and groundwater are added to recycled water from tailings ponds to replace water that is lost during processing. Since the Athabasca River is near most oil sands mining operations, it is used as the primary nonsaline water source for makeup water.
Although the industry uses a small fraction of the Athabasca River’s annual average flow, the impacts of those water withdrawals are greater during low-flow periods. The Surface Water Quantity Management Framework establishes stringent water withdrawal limits for oil sands mining and ensures a cap on overall water withdrawals.
In 2016, oil sands mining used 186 million cubic metres of nonsaline water (26% of the nonsaline water allocated for oil sands mining) to produce 467 million BOE.
Our data shows that, in 2016, oil sands mining used 2.51 barrels of nonsaline water to produce one BOE. Since 2012, improvements in technology and processes improved nonsaline water use intensity by 12%.
Enhanced oil recovery
While oil sands mining uses the most nonsaline water overall, enhanced oil recovery (EOR) uses the most nonsaline water among non mining technologies. EOR requires water to be injected into a well to increase or maintain its pressure so that the remaining oil can be produced at nearby recovery wells.
In 2016, EOR used 14 million cubic metres of nonsaline water (14% of the water allocated for EOR) to produce 183 million BOE. A five-year trend shows that, as production from EOR decreased by 16%, nonsaline water use decreased by 25%.
In 2016, EOR used 0.49 barrels of nonsaline water to produce one BOE. Overall, EOR has shown a 15% improvement in its nonsaline water use intensity from 2012 to 2016.
In 2016, in situ oil sands projects used 16 million cubic metres of nonsaline water (21% of the water allocated for in situ oil sands projects) to produce 476 million BOE.
Since 2012, the amount of nonsaline water used for in situ development has decreased by 2%, as companies gradually improved recycling. For example, in 2016, companies recycled 86% of all water used, a 9% increase since 2012.
In 2016, in situ oil sands projects used 0.21 barrels of nonsaline water to produce one BOE. Overall, in situ development has shown a 37% improvement in its nonsaline water use intensity since 2012.
Hydraulic fracturing uses the least amount of nonsaline water among extraction technologies. In 2016, hydraulic fracturing companies used 7 million cubic metres of nonsaline water (11% of the water allocated for hydraulic fracturing) to produce over 355 million BOE. The amount of water used for hydraulic fracturing varies each year, depending on economic conditions and the number of wells that are drilled and fractured.
In 2016, hydraulic fracturing used 0.38 barrels of nonsaline water to produce one BOE. Overall, hydraulic fracturing has shown a 35% increase in its nonsaline water use intensity since 2013. Since hydraulic fracturing in horizontal wells is a relatively new use of the technology, water use intensity is expected to vary as operators test different strategies and methods to optimize production and minimize water use.
Alberta’s oil and gas industry currently uses about a third of its total water allocation per year. The industry continues to research and implement new technologies to reduce the amount of water needed to produce a barrel of oil or bitumen. Government policies and strategies, including those coming out of The Water Conversation, are also helping drive this forward.
For more information about Water Use Performance in oil and gas development go to AER's water use performance page.
Tailings are a by-product of the bitumen mining process. Tailings consist of water, silt, sand, clay, and residual bitumen and are stored in ponds above or below ground. Tailings are deposited in man-made tailings ponds surrounded by collection and monitoring systems.
Tailings ponds are essential to oil sands mining operations. They act both as holding areas, where most of the water needed for bitumen extraction can be recycled, and as settling basins for solids.
Fluid tailings have been linked to environmental risks from seepage, and to wildlife, land use and reclamation.
Table 2. Total tailings active area, pond water area and volume of fine fluid tailings
|Total Active Tailings Area including all tailings structures (km2)*||196||220||12%|
|Total Tailings Pond Water Area (km2)||83||88||6%|
|Total Volume of Fine Fluid Tailings (million m3)||922||976||6%|
Source: Alberta Environment and Parks
Figure 4. Estimated total area of oil sands tailings ponds
More information about tailings ponds surface area and volume is available on Alberta Environment and Parks' Oil Sands Information Portal.
Tailings pond regulations
The Alberta Energy Regulator (AER) has comprehensive rules, regulations and requirements in place for the safe design, construction, and operation of tailings ponds.
In March 2014, the AER assumed responsibility from Alberta Environment and Parks for regulating tailings ponds.
The AER has a strong regulatory process that includes regular inspections of oil sands tailings dams. It ensures that all regulated dams are designed, constructed, operated, maintained, and decommissioned safely.
Tailings Management Framework
The Tailings Management Framework provides objectives on how to manage existing and new fluid tailings volumes, and minimize accumulation. The framework ensured that fluid tailings are treated and reclaimed during the life of a project. Under the framework, all fluid tailings must be ready to be reclaimed within 10 years of the end of a mine’s life.
There are some things that the Tailings Management Framework does not address such as waterfowl protection, dam safety and emissions. These important issues are already addressed through regulatory requirements.
The Alberta Energy Regulator regulates more than 422,000 kilometres of oil and gas pipelines. It also provides inspection and incident response support for an additional 12,000 kilometres of pipelines regulated by the Alberta Utilities Commission. If an operator is unable to meet regulatory requirements there may be a risk to the public or the environment. All pipeline incidents, including those in which a pipeline is hit but does not leak, must be reported to the AER.
Pipeline incidents can be caused by:
- pipeline failures resulting from corrosion due to poor maintenance or construction practices
- equipment failure or material and welding defects
- environmental incidents, such as ground movement or flooding, or
- human interference, such as when a pipeline is hit by heavy equipment operations during ground disturbance or through vandalism
- High consequence
- Incidents that could have significant impact on the public, wildlife, or the environment, or that involve the release of a substance that affects a large area or waterbody.
- Medium consequence
- Incidents that could have a moderate impact on the public, wildlife, or the environment, and no impact on a flowing water body.
- Low consequence
- Incidents that involve the release of little to no substance with little to no impact on the public, wildlife, and the environment (but no impact on a water body).
Table 3. Annual pipeline incidents
|Number of high consequence pipeline incidents||45||35||53||53||32|
This decrease is largely due to more stringent requirements, increased focus on integrity issues, industry education, improvements to inspection programs, and a greater focus on pipeline safety.
High-consequence incidents accounted for 7% of all incidents in 2015/2016.
There was a 40% decrease in incidents in the 2015/16 fiscal year compared to the 2014/15 fiscal year.
When classifying the consequence rating of an incident, the AER considers liquid volume, because these have the potential to cause the greatest long-term social and environmental damage. Any incident that has a release volume above zero but lower than 0.1 cubic metres defaults to 0.1 cubic metres in the AER’s system. For example, if 0.06 cubic metres of product was released, the number would be rounded to 0.1 cubic metres.
Preventing pipeline failures
All pipeline incidents are preventable. The AER’s long term goal is zero incidents, and is taking cumulative steps to prevent all pipeline incidents and failures.
The AER requires companies to implement comprehensive integrity management programs to identify, manage, monitor and address potential hazards associated with each individual pipeline. The AER reviews a company’s safety and loss management system to ensure it has all necessary controls in place to help prevent pipeline incidents.
AER also conducts pipeline inspections to ensure operators are in compliance with regulations and proper leak detection strategies are in place. Inspections focus on identifying high-risks—such as preventation maintenance programs, pipelines that cross water courses and inactive pipelines. The AER also helps educate licensees on pipeline integrity issues and how to address them. If the AER identifies that a pipeline operation is—or is at risk of—causing unacceptable impacts, it can order an immediate pipeline suspension until the problems are corrected.
For more information on pipeline safety go to AER’s Website.