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Updated June 2024

What are CCUS and CCS

Carbon capture, utilization, and storage (CCUS) refers to a range of technologies and processes that capture carbon dioxide (CO2) from industrial sources or directly from the atmosphere, and then utilized by injecting it into underground porous formations as part of CO2-enhanced oil recovery (CO2-EOR) or used to produce manufactured goods. CO2-EOR improves the production of residual oil and results in some CO2 becoming permanently stored (i.e., sequestered) within the formation. The CO2 can also be utilized through commercial processes, which permanently traps the CO2 into a higher-value product.

Carbon capture and storage (CCS) is similar to CCUS but excludes the utilization of CO2 and instead it is injected into subsurface formations (e.g., saline aquifers or depleted oil and gas reservoirs) for permanent storage.

Both CCUS and CCS technologies seek to reduce the amount of CO2 released into the atmosphere. Throughout the remainder of this chapter, CCUS will refer to both technologies unless specified otherwise.

The CCUS process (see diagram below) begins with capturing CO2, which can occur at the industrial emission source (power generation, hydrogen manufacturing, oil sands mine, etc.) or directly from the atmosphere using direct-air capture (DAC) technology. The captured CO2 is compressed and transported by pipeline or truck to its destination. The CO2 is either stored permanently underground (e.g., in saline formations) or used and stored by CO2-EOR. The Alberta Energy Regulator (AER) has been regulating CO2-EOR projects since the 1980s.

Carbon capture and storage processes

Captured CO2 may also be used as feedstock for a higher-valued product. Some non-oil industry applications include using CO2 in food and beverage production, metal fabrication, cooling, fire suppression, and plant growth stimulation in greenhouses. Some experimental and pilot applications are under development (i.e., cement, carbon nanotubes, CO2-to-liquid fuels).

Regulatory Framework for CCUS

Alberta is among the leading jurisdictions in CCUS policy and deployment of a regulatory framework. CCUS projects are covered by Alberta’s existing oil and gas legislation: Oil and Gas Conservation Act, Mines and Minerals Act, Surface Rights Act, Public Lands Act, Environmental Protection and Enhancement Act, and Water Act. Surface rights for CCUS projects are managed the same as oil and gas developments in the province. Pore space rights for CO2 are covered by the Mines and Mineral Act. Roles and responsibilities for Alberta’s CCUS regulatory framework are divided between Alberta Energy and Minerals, Alberta Environment and Protected Areas, and the AER.

Alberta Energy and Minerals roles include

  • development of policy and regulatory frameworks,
  • issuance of tenure rights for evaluation and sequestration of CO2, and
  • management of the Post-Closure Stewardship Fund.

Alberta Environment and Protected Areas responsibilities include

  • implementation of the Emissions Reduction and Energy Development Plan,
  • management of the TIER regulatory system that promotes CCUS through the generation of carbon credits, and
  • regulating CO2 capture facilities not connected to, or associated with, energy resource activity (e.g., chemical manufacturing plant).

As it pertains to CO2, the AER regulates

  • the energy-related facilities1 that capture CO2,
  • the pipelines that transport the CO2 within Alberta,
  • the subsurface injection activities, which include permanent sequestration and CO2-EOR projects, and
  • oversight of measurement, monitoring, and verification plans and closure plans.

Several AER directives provide technical requirements for CCUS projects including:

CO2 Sequestration in 2023

In 2023, there were 1.0 million tonnes of CO2 permanently sequestered by CCS (Figure S10.1). Since 2015, CCS injection facilities have permanently sequestered a cumulative total of 8.8 million tonnes of CO2.

There were 1.6 million tonnes of CO2 permanently sequestered by CO2-EOR in 2023 (Figure S10.1), an increase from the previous year due to higher production rates from associated carbon-emitting facilities. Since 2020, CO2-EOR facilities have permanently sequestered a cumulative total of 4.8 million tonnes of CO2.

Currently, the data for sequestration by CCS includes the Shell Quest CCS project, and sequestration by CO2-EOR includes Enhance Energy’s Clive Field CO2-EOR project. Sequestration values do not include CO2 permanently sequestered through acid gas disposal and other CO2-EOR projects.

Existing Projects

There are two large-scale CCUS projects in Alberta: Shell Quest and the Alberta Carbon Trunk Line (ACTL). Quest involves capturing CO2 from the hydrogen plant at the Scotford Upgrader and transporting it by pipeline to the injection site for sequestration in an underground saline formation (Basal Cambrian Sandstone unit). The ACTL relies on CO2 captured from hydrogen production at the Sturgeon Refinery and the Redwater Fertilizer Plant. The captured CO2 is used in the Clive Field at Enhance Energy’s CO2-EOR project.

Methodology

Sequestration Data

All historical data are as reported by the industry until the end of December and do not capture any subsequent amendments. The average density of the injected fluid is provided in the project annual reports and used to convert the reported volumes to the mass equivalent. The CCS sequestration volumes of CO2 are from Petrinex. The CO2-EOR injection volumes reported in Petrinex for the fluid injectors of the scheme are gross volumes, which include CO2 volumes supplied from capture sites and CO2 volumes that are recirculated through the active oil and gas producing wells in the pool (also recorded in Petrinex). The sequestered volume is then the recirculated CO2 volume subtracted from the gross injection volume. The 2023 data is preliminary since an estimate of the net CO2 tonnage injected was provided by the scheme holder and was used to back-calculate the average density of the injected fluid in the year. This result was used to estimate the sequestered volumes for the individual fluid injectors. 

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1 Energy infrastructure includes intraprovincial pipelines, wells, geothermal facilities (heat or power), gas or oil processing plants and facilities, in situ bitumen projects, bitumen upgraders, oil sands mines, and coal mines. It does not include interprovincial or international pipelines and electricity generation plants (except geothermal).