How about some clean, green hydrogen with that natural gas?

08 June 2021

Hydrogen and natural gas

As a fuel source, hydrogen and natural gas have a number of similarities including safety considerations, transportability and versatility. In addition, hydrogen is the lowest carbon fuel at the point of use.[1] As such, it is expected to be a significant contributor in the world's shift to a cleaner and greener economy, by diversifying the energy mix and helping to meet emission reduction targets. On this basis, hydrogen represents an excellent fuel alternative in a range of applications including transportation, power production and heating, both process heating (industrial) and space heating (residential and commercial).

With increasing interest in hydrogen as a fuel source, blending hydrogen with natural gas provides an opportunity to increase hydrogen demand while lowering carbon emissions and optimizing the use of existing fuel delivery infrastructure as the hydrogen market develops. This blended fuel can be used in many applications in place of pure natural gas. Currently, blend ratios of up to 20% hydrogen are being tested with limited impact on delivery infrastructure and end-use appliances.[2]

Benefits of hydrogen blending

Blending relatively small amounts of hydrogen into the existing natural gas pipeline networks would at most require minor changes to fuel delivery infrastructure and end-user appliances while providing a boost to hydrogen supply technologies. At the outset, this can be achieved without incurring the high investment costs and associated risks related to the development of dedicated hydrogen transmission and distribution infrastructure.[3] Benefits include:

  1. Emissions reduction: Even low levels of hydrogen blending would provide a reduction in greenhouse gas emissions. However, the carbon intensity of the blend depends on the feedstock and production method of the hydrogen. For example, it is estimated that a blend comprised of as little as 5% low carbon hydrogen could reduce greenhouse gas emissions by 2%.[4]
  2. Allows use of existing network of natural gas transmission and distribution pipelines: By carrying a blend of hydrogen and natural gas, Canada's existing natural gas transmission and distribution pipelines can be repurposed to expedite the growth of hydrogen use in Canada. Further, creating hydrogen by utilizing excess electricity and blending that hydrogen into natural gas pipelines will take advantage of the inherent storage capacity of the gas delivery network.[5]
  3. Reduction of upfront capital costs: Blending hydrogen into existing natural gas infrastructure would limit (or at least delay) the significant capital costs required to develop dedicated transmission and distribution infrastructure for hydrogen.[6] Making use of existing infrastructure would also avoid further delays and potentially reduce opposition related to new pipeline construction projects.[7]
  4. Demand creation: Blending provides the largest potential demand opportunity for hydrogen.[8] Increasing the demand for hydrogen would lead to an increased hydrogen supply that could significantly decrease the cost associated with hydrogen supply technologies.

Challenges with hydrogen blending

Despite the benefits of hydrogen blending, there are challenges that will need to be addressed, including:

  1. Pipeline compatibility: Depending on pipeline composition and operating conditions, exposure to hydrogen can embrittle some pipelines. While the newer steel and polyethylene used in natural gas distribution systems are not typically subject to embrittlement concerns, the steel used in older distribution infrastructure and natural gas transmission pipelines, together with the higher pressures in these transmission pipelines as compared to distribution systems, does make them susceptible. [9]
  2. Tolerance of end-use equipment: The hydrogen/natural gas blend ratio can only be as high as the capacity and tolerance of the end-use equipment connected to the grid. As such, the tolerance of the overall grid is limited by the end-use component with the lowest tolerance. This may be a particular challenge for finely tuned industrial processes that utilize natural gas as a feedstock. Evaluation of more conventional (residential and commercial) end-use appliances is ongoing.
  3. Energy density: At room temperature, hydrogen has roughly one-third the volumetric energy density of natural gas. As such, blending reduces the energy content of the blended gas. As hydrogen blending increases, the average calorific content of the blended gas falls, and thus an increased volume of blended gas must be consumed to meet the same energy needs.
  4. Capacity of pipelines: With three times the volume needed to supply the same amount of energy as natural gas, additional transmission and storage capacity across the network might ultimately be required depending on the extent of the growth of hydrogen. Possible options for overcoming this hurdle include compression, liquefaction or incorporation of the hydrogen into larger molecules more readily transported as liquids.[10] 
  5. Volume variability: Variability in the volume of hydrogen blended into the natural gas stream would have an adverse impact on the operation of equipment designed to accommodate only a narrow range of gas mixtures.
  6. Accounting: Tracking the volume of hydrogen injected into the grid and its carbon intensity is important. Such an accounting method – sometimes called a "guarantee of origin" – is essential if operators are to be paid a premium for supplying lower-carbon gas.
  7. Regulations and standards: Currently, blending standards have yet to be determined. Action to update and harmonize national regulations that set limits on allowed concentrations of hydrogen in natural gas streams would help facilitate blending.

Policy considerations

The cost to produce blue or green hydrogen is high relative to other fuel sources at present.  In light of this, even low levels of hydrogen blending requires policy support to stimulate demand from gas suppliers and encourage hydrogen equipment production and infrastructure use. Offering incentives, setting quotas, blend levels, and emission targets for hydrogen production, analogous to mechanisms for renewable electricity, could foster the practice of hydrogen blending thereby creating dependable supply and demand for hydrogen.[11]

Current examples of hydrogen blending projects

  1. Alberta – ATCO

In July 2020, ATCO announced its plan to build Canada's largest hydrogen blending facility, near Fort Saskatchewan, using hydrogen derived from domestically produced natural gas. This facility is expected to inject up to 5% hydrogen, by volume, into a section of Fort Saskatchewan's residential natural gas distribution network, lowering the carbon intensity of the natural gas stream for its customers. In addition, ATCO intends to eventually employ Alberta's existing carbon capture and sequestration infrastructure to store emissions associated with the production process. ATCO has been awarded $2.8 million in funding from Emission Reductions Alberta's (ERA) Natural Gas Challenge for the project.[12]

  1. Ontario – Enbridge Gas and Cummins

After receipt of regulatory approval from the Ontario Energy Board for facility construction, in November 2020, Enbridge Gas and Cummins announced a $5.2-million pilot project that will blend renewable hydrogen gas into a segregated loop of the existing Enbridge Gas natural gas distribution network. Enbridge Gas will use the project to study the use of hydrogen to decarbonize natural gas and thereby reduce greenhouse gas emissions. This hydrogen-gas blending unit will be constructed adjacent to the existing power-to-gas (P2G) electrolysis facility in Markham, built in 2018 with financial support from the Canadian government. This P2G facility was established under contract with Ontario's Independent Electricity System Operator (IESO) to provide regulation services to balance electricity supply and demand by converting surplus renewable electricity into hydrogen. The hydrogen is stored for conversion back into electricity through hydrogen fuel cells when needed by the grid, or blended into the existing natural gas stream when available.[13]

  1. British Columbia – FortisBC

In November 2020, FortisBC announced the investment of $500,000 to explore the delivery of hydrogen through its distribution network. In partnership with the University of British Columbia, the focus of the study will revolve around hydrogen blending, understanding the potential effects that hydrogen may have on the infrastructure and determining what blend and concentration levels are safe to deliver in FortisBC's system.[14]

  1. Québec – Evolugen and Gazifère

In February 2021, Evolugen and Gazifère (subsidiaries of Brookfield Renewable and Enbridge Gas, respectively) announced their plan to build one of Canada's largest green hydrogen injection facilities. The companies intend to construct and operate a water electrolysis hydrogen production plant adjacent to Evolugen's hydroelectric facilities in Gatineau. The hydroelectric facilities will power the electrolyzer plant, which will produce green hydrogen for injection into Gazifère's natural gas distribution network. An estimated capacity of 425,000 GJ of green hydrogen will be produced from the project, which is anticipated to reduce GHG emissions by approximately 15,000 metric tons per year.


To conclude, while hydrogen-only technologies, such as fuel cells and zero emission vehicles, have been the focus of many to date, the above examples indicate that blending hydrogen with natural gas and transporting it using existing gas delivery infrastructure can be an important stepping-stone in the development and growth of the hydrogen economy.


[1] Hydrogen Strategy for Canada – p.IX

[2] Hydrogen Strategy for Canada – p.41

[3] The Future of Hydrogen – p.182-183

[4] The Future of Hydrogen – p.183

[5] Hydrogen Strategy for Canada – p.41

[6] The Future of Hydrogen – p.71

[7] The Future of Hydrogen – p.184

[8] Hydrogen Strategy for Canada – p.62

[9] Hydrogen Strategy for Canada – p.60

[10] The Future of Hydrogen – p.70

[11] The Future of Hydrogen – p.184-185




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