Insights & Analysis

March 31, 2022

Maximizing the Potential of Blue Hydrogen in Alberta

Hydrogen is expected to play a key role in future global energy systems as most of the world moves toward a net-zero 2050. While renewable electricity will feature prominently in our low-carbon future, it is not a viable energy source for all sectors. Some of our heaviest emitting sectors—heavy transport, heavy industry, and space heating in cold climates—must find a zero-emission chemical fuel alternative to circumvent green electricity’s storage and intermittency challenges. This is where hydrogen comes in.

Countries around the world are increasingly embracing the potential hydrogen offers as a clean energy carrier. Canada was an early adopter of a national hydrogen strategy, releasing its strategic plan in December 2020. And nearly a year later, Alberta published its highly anticipated hydrogen roadmap in November 2021.

Alberta’s hydrogen roadmap stands out among comparable strategies for its strong emphasis on blue hydrogen—hydrogen gas produced from fossil fuels coupled with carbon capture, utilization, and storage (CCUS) technology. Alberta is strategically positioned to become a leader in blue hydrogen production because of its unique industrial and geological profile. This province has the resources, technology, infrastructure, and expertise to produce blue hydrogen in a cost-effective manner. And hydrogen offers Alberta a way to manage the energy transition by transforming its energy sector into a lower-carbon one.

There are as many as nine different "colours" of hydrogen. In this piece, @BizCouncilAB examines blue hydrogen, and the opportunities for Alberta in this space. Click to Share

But lately, blue hydrogen has been criticized as a way to greenwash the fossil fuel industry, and a recent controversial study claimed that blue hydrogen is worse than natural gas when it comes to emissions. Proponents of blue hydrogen are eager to lump blue and green hydrogen (produced by electrolysis powered by renewable electricity) together as equivalent and interchangeable ‘clean’ and ‘low-emissions’ options. By doing so, the emissions intensity of blue hydrogen is obscured and downplayed.

As industry and governments make decisions about low-carbon technologies, we must remain aspirational in our goals yet realistic in how we can achieve them. In this analysis, we examine (a) if blue hydrogen is a low-carbon energy carrier and (b) opportunities to reduce the emissions intensity of blue hydrogen.

But before we address those questions, a brief, high-level explanation of the different colours of hydrogen.

A primer on the hydrogen rainbow

As indicated earlier, hydrogen comes in a rainbow of colours. While it is actually a colourless gas, hydrogen is often classified according to a colour taxonomy to indicate how it is produced, what energy sources are used, and how clean it is. There are as many as nine different “colours” of hydrogen, but the three key ones are depicted below.

Grey hydrogen is produced using fossil fuels, and steam methane reforming (SMR) of natural gas is the dominant production method. SMR is a well-established industrial process that has been used to produce hydrogen for oil refining and fertilizer production for decades. SMR uses natural gas as a feedstock and as a fuel to generate steam. The steam converts the methane in the natural gas feedstock to hydrogen and carbon dioxide (CO2). The CO2 is subsequently released into the atmosphere. As such, grey hydrogen isn’t considered a clean or low-carbon hydrogen. Natural gas + SMR accounts for nearly 60% of global hydrogen production.

At present, blue hydrogen is simply the above process coupled with CCUS to reduce carbon intensity at the point of production. Natural gas + SMR + CCUS generates 0.7% of global hydrogen production.

Green hydrogen is produced using electrolysis powered by renewable electricity to separate water into hydrogen and oxygen. Green hydrogen is virtually emissions-free and accounts for a tiny share of global production at 0.03%.

A closer look at the emissions from blue hydrogen

While hydrogen emits zero CO2 emissions when burned, the blue hydrogen production pathway is not fully net-zero, even with added CCUS. Therefore, to fully consider the climate footprint of blue hydrogen, the entire lifecycle—from production to consumption—must be considered.

GHG emissions from blue hydrogen can be separated into four distinct parts:

  1. The upstream emissions from producing and transporting the natural gas feedstock;
  2. The SMR process where methane is converted to CO2 and hydrogen;
  3. The energy used to generate the heat and pressure required to drive the SMR process; and
  4. The energy used to power the CCUS equipment.

There is little consensus on the emissions impact of blue hydrogen. Over the past year, several studies have quantified the carbon intensity of blue hydrogen and delivered vastly different results. Much of the inconsistency stems from assumptions in the calculations.

Lifecycle assessments (LCAs) of blue hydrogen contain several different assumptions: the rate of upstream methane leakages, the global warming potential of methane, carbon capture rates, and the carbon intensity of the electricity supply, among others. Because there are only a few commercial blue hydrogen facilities in operation, raw data is limited, and calculations must rely on assumptions ranging from the observable data to the theoretical maximum potential of the technology.  

The emissions reduction potential of blue hydrogen is paramount to its future in a low-carbon world. In other words, blue hydrogen must offer emissions reductions to make sense as a pathway forward. To this end, let’s investigate the two lines of inquiry we posed earlier.

Is blue hydrogen a low-carbon energy carrier?

To answer this first question, the Alberta context is critical. Blue hydrogen emissions are sensitive to the industrial, geological, and technological features of the production environment. As such, emissions can vary from province-to-province and even from facility-to-facility. For example, the emissions from the electricity used in blue hydrogen production are tied to the composition of the local grid. And Alberta’s electricity grid is primarily driven by natural gas; fossil fuels account for 91% of electricity generated in the province.

Researchers at the University of Alberta recently investigated the emissions intensity of blue hydrogen, using Alberta as a case study. They found that blue hydrogen, as it is currently produced, emits 28% fewer GHG emissions than grey hydrogen. The Pembina Institute came to a similar conclusion in its analysis of Shell’s Quest Project in Alberta. Blue hydrogen, produced by Shell, emits 34% fewer GHG emissions than grey hydrogen. And other studies, using European and American examples, find emissions savings between 9-40%.

Therefore, we can be relatively assured that blue hydrogen, produced in Alberta, presents potential to be a low-carbon fuel for the future.

Opportunities to reduce emissions from blue hydrogen

Next, we examine the conditions that optimize the decarbonization potential of blue hydrogen. While there are many ways to reduce the emissions intensity of blue hydrogen, the three largest opportunities are discussed below.

1. Address upstream emissions

Upstream emissions come from the natural gas supply chain where methane gas (the primary component of natural gas) is vented or leaked throughout the extraction, processing, transportation, and distribution of the natural gas feedstock.

Methane is an incredibly potent GHG. Its warming effect is 25-times and 86-times greater than carbon dioxide over 100 and 20 years, respectively. And it is a significant contributor to the emissions intensity of blue hydrogen—accounting for at least 20% of total emissions (based on current production methods). For these reasons, the impact of upstream methane emissions cannot be ignored. 

Alberta’s methane leakage rate was calculated to be 1% based on Canada’s national inventory estimates. While this is a comparatively low leakage rage, recent field analyses have determined that Alberta’s methane emissions are 50-60% higher than official inventory estimates. Thus, LCAs of blue hydrogen underestimate the contribution of upstream emissions to blue hydrogen’s overall emissions impact.

Fortunately, work is already underway to address these emissions. In 2018, the federal government published regulations to reduce methane emissions from the oil and gas sector by 40-45% of 2012 levels by 2025, and a 2020 report from the Government of Alberta indicates that the province is on track to meet that goal. Furthermore, the pathways for reducing methane emission are well known, commercially available, and economical. Many abatement options are low-cost or even negative cost–meaning reducing emissions could result in overall cost savings.

Better quantifying and minimizing upstream methane emissions from the natural gas sector are essential to low-carbon blue hydrogen production.

2. Optimize the hydrogen production process

The hydrogen production process, where SMR separates hydrogen from natural gas, is the most emissions-intensive component of the blue hydrogen lifecycle. As such, this is an important process on which to focus emissions reduction efforts.

During the SMR process, CO2 is released in two different locations. About 60% of the CO2 is contained in the process gas (from which hydrogen is obtained), and the remaining 40% of CO2 is contained in the flue gas (created from burning natural gas to power SMR). Currently, SMR facilities only capture carbon from the process gas stream while the carbon in the flue gas remains unabated.

There are two options to address these flue gas emissions. One obvious option is to apply carbon capture to the flue gases. However, this may not be the most appealing option. Carbon dioxide is more concentrated in the process gas stream and more dilute in flue gas, leading to comparatively low carbon capture efficiency when applied to the latter. Furthermore, running additional CCUS units will necessitate additional energy expenditure (often from burning natural gas), negating some emissions reductions. Finally, given the cost of CCUS investments, it may not be financially worthwhile to invest in these efforts if the net capture rates are too low.

The second option to mitigate flue gas emissions is to change the hydrogen production technology. Autothermal reforming (ATR) is an established industrial process that is increasingly being considered as an alternative to SMR in blue hydrogen production. While ATR and SMR produce similar carbon dioxide levels during the chemical reaction, the resulting carbon emissions are entirely contained within the process gas stream. This negates the flue gas problem and results in a higher concentration of CO2 in the process gas, meaning carbon capture can operate more efficiently and at a lower cost.

Researchers at the University of Alberta found that blue hydrogen produced with ATR has the lowest lifecycle emissions—52% fewer emissions than SMR with one carbon capture unit and 41% fewer emissions than SMR with two carbon capture units.

3. Increase the carbon capture rate

The final key determinant of the carbon intensity of blue hydrogen is the capture rate of the installed CCUS technologies. The rate of carbon capture can vary widely according to many factors including: the efficiency of the carbon capture unit, the composition of the natural gas feedstock, and the plant configuration among others.

Alberta only has two commercial CCUS plants, and these blue hydrogen facilities have demonstrated relatively low carbon capture rates—around 50%. This inefficiency is partly because they only capture CO2 from the process gas—leaving 40% of emissions unabated. The plant’s design also contributes to the low capture rate. These existing facilities are refineries and ammonia plants, where blue hydrogen is not the end product, and they were retrofitted to incorporate CCUS. Thus, they are not representative of what could be feasible in a new, purpose-built blue hydrogen production facility.

Achieving a high capture rate (over 90%) is necessary for the resulting blue hydrogen to be considered low-carbon. Capture rates of 90% have been proven in small demonstration projects but have yet to be achieved in large-scale commercial plants.

Unfortunately, CCUS is not without challenges. The technology is capital intensive and requires significant energy to operate, which in turn increases upstream emissions. And achieving high capture rates is expensive and may not be economical without a much higher carbon price. 

Conclusion

Understanding and optimizing the conditions under which blue hydrogen is a low-carbon energy carrier is critical to its compatibility with a low-carbon economy. Minimizing methane leaks from the natural gas supply chain and capturing more emissions from the hydrogen production process could reduce blue hydrogen’s emissions by more than 50%.

As hydrogen requires significant, long-term investments and structural changes to the energy system, policymakers need to have honest conversations about blue hydrogen’s potential to meet decarbonization objectives.  



Emma Dizon, Policy Analyst

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