Vent, Flare and Compression, Where the Engineering Actually Happens
The near-term abatement agenda is unglamorous and specific. It centres on eliminating routine venting, replacing gas-driven pneumatic devices with non-emitting alternatives, controlling emissions from glycol dehydrators, and making flare ignition reliable rather than assumed. The AER’s latest edition of Directive 060 introduces requirements that take effect at the start of the next decade, covering automatic or continuous ignition, flare stack maintenance, active flare monitoring, reporting of unlit flare gas, and methane controls for glycol dehydrators installed, replaced, or relocated after that date. Because the directive applies to gas-conveying pipeline installations, compressor stations and line heaters sit inside its scope, which is why retrofit planning is now a multi-year exercise rather than a single procurement. Electrification of compression is the larger structural move, replacing gas-fired drivers with electric ones; its constraint is rarely the machine, and almost always the grid connection, and the CER’s own outlook identifies rising electricity demand as one of the forces reshaping the Canadian energy system.
Carbon Dioxide and Hydrogen as Pipeline Cargo
The second decarbonization track turns pipelines into part of the abatement solution rather than a source of emissions. In Alberta, the AER oversees the full carbon capture and storage chain, from capture facilities and carbon dioxide pipelines to subsurface injection. Applications follow Directive 056, while Directive 065 covers reservoir and injection requirements, including monitoring, measurement and verification, and closure plans available for public review. Alberta’s open-access sequestration hub model allows multiple emitters to share transport and storage infrastructure, avoiding the need for separate systems. For midstream operators and investors, that shared-infrastructure model is central to making carbon dioxide gathering networks commercially viable.
Repurposing existing pipeline steel for hydrogen is more challenging and needs careful assessment. CSA Group research on the assessment of natural gas pipeline materials for hydrogen service sets out the central concern, which is hydrogen-induced degradation of carbon steels under service conditions, and notes that established standards still contain gaps between hydrogen and natural gas requirements. Natural Resources Canada’s codes and standards roadmap points to the same unresolved questions around permissible stress levels. The CER has also observed that no interprovincial or international hydrogen pipelines are currently operating in Canada, which means repurposing remains an engineering and commercial proposition rather than settled practice. Pipeline Infrastructure Canada 2027 sets out where methane abatement, compressor electrification, carbon dioxide transport and pipeline repurposing are truly bankable today, and where operators, technology providers and financiers are still working with incomplete standards.
