The technologies involved in blue hydrogen – produced from natural gas or coal with carbon capture, utilization and storage— are not new, but renewed interest in possible projects is leading analysts and academics to take closer looks at the environmental impacts through emissions modeling.
As with any kind of modeling, the assumptions used can vary considerably, leading to vastly different conclusions.
One recent such study by Robert Howarth of Cornell University and Mark Jacobson of Stanford University has attracted a lot of attention by asserting that blue hydrogen is worse for the environment than burning gas in heating applications. Their study — “How Green is Blue Hydrogen? — was published Aug. 12.
“Far from being low carbon, greenhouse gas emissions from the production of blue hydrogen are quite high, particularly due to the release of fugitive methane,” the report said.
However, in applying different assumptions to its own analysis, S&P Global Platts Analytics found merits in the blue hydrogen case, especially when considering applications other than direct heating.
Platts Analytics modeling, published Aug. 17 as part of its Future Energy Outlook special report series, found blue hydrogen to have a smaller emissions profile than gas when combusted for heating, resulting from more optimistic assumptions regarding methane intensity rates, CCUS technology performance and steam methane reforming plant efficiency.
The two studies’ assumptions differ in two key ways: how to fully measure methane emissions from gas and whether to prioritize what has been or what could be in terms of carbon capture and process efficiencies.
Methane emissions
For blue hydrogen that uses gas as its feedstock, the methane intensity of that gas is a primary variable in assessing overall emissions.
Although shorter-lived than carbon dioxide, methane is a potent greenhouse gas that is as much as 84 times as efficient at trapping radiation as carbon dioxide in a 20-year time frame, according to the Intergovernmental Panel on Climate Change.
In comments to S&P Global Platts, Jacobson emphasized the more intense, shorter-lived impact of methane emissions on the atmosphere.
“Methane and black carbon immediately warm the Earth, enhancing wild fires, hurricanes, droughts, floods, agricultural loss, heat stress, heat stroke, and air pollution,” Jacobson said in an email.
Beyond its use as a feedstock, gas is also a common choice to power steam methane reforming units, given the steady supply already flowing to the facility. The SMR process’ technical requirements discourage non-combustion options, according to Platts Analytics hydrogen analyst Brian Murphy.
“Natural gas, already a feedstock to the plant, is typically the cheapest option to provide the heat needed by the SMR reactions,” Murphy said. “This heat makes up the majority of the energy consumed by the plant.”
The Howarth and Jacobson analysis assumed an average lifecycle methane intensity of 3.5% for gas, on the high end of estimates that typically run closer to 1.4% to 2.7%. However, Jacobson clarified to Platts that the methane intensity number used in their blue hydrogen emissions model may not be an apples-to-apples comparison with most methane intensity numbers in the literature.
“Our numbers are not leakage rates and not just at the well, but lifecycle methane emission rates from well-to-end use and also after the well has been retired,” Jacobson said. “These include emissions (intentional and accidental releases) and leaks at the well, losses of methane between the well and end use, (which includes leaks from well to processing station, in processing station, and from processing station to end use at H2 plant).”
Platts Analytics’ model was primarily drawn from literature estimates of emissions, with an emphasis that methane intensities vary widely depending on the production basin, producer and transport distance.
“Countries with access to low-leak sources of natural gas, which has been exploring policy options to include blue hydrogen, appear well-positioned to achieve significant emissions reductions from the widespread adoption of CCS in hydrogen production,” according to the Platts Analytics report.
SMR, CCUS efficiencies
Efficiency rates for SMR plants and of CCUS systems are also primary assumptions in modeling the environmental footprint of blue hydrogen, with Platts Analytics modeling assuming higher efficiency rates for both than the Howarth and Jacobson study.
The Platts Analytics assumption of a 90% carbon capture rate was shaped by the Platts’ hydrogen price model and data from the International Energy Agency and International Renewable Energy Agency.
Jacobson asserted that his and Howarth’s assumed rates were already more optimistic than existing precedents.
“With respect to capture efficient rates, [Platts Analytics] fails to acknowledge that our 85% capture rate of SMR emissions is actually higher than reality,” he said. “Shell’s SMR capture plant in Alberta has an annual average capture rate of 79% (as cited in our paper).”
Part of Platts Analytics’ and others’ rosier view reflects an expectation that time and technology improvements will yield better efficiency outcomes.
Hydrogen from gas has historically been produced using SMR technology, which uses steam to separate hydrogen from the gas, but auto-thermal reforming technology has been touted as offering a higher rate of carbon capture at a lower cost.
Blue hydrogen in decarbonization
Looking at blue hydrogen in the larger decarbonization context, direct heating may not be the most efficient use case for blue hydrogen, or the best application to weigh its relative merits.
Instead, sectors where abatement is difficult, such as aviation or shipping, might present a better comparison for evaluating the technology’s potential benefits in comparison to existing fuels. Similarly, industrial uses for hydrogen, such as a feedstock for oil refining or ammonia production, could see their emissions footprints decrease by switching to blue hydrogen.
With lifecycle methane intensity a major concern for blue hydrogen, producing hydrogen with non-fossil gas could be a solution, according to a recent article published in the journal Energy Research & Social Science.
“In order to leverage the existing infrastructure for fossil hydrogen, replacement with biomass feedstocks (fuel crops, biomass waste streams, and biomass-derived fuels), other waste streams (MSW, de-watered effluent sludge), and co-processing are possible decarbonization interventions,” the report said.
Alternatives also include using renewable natural gas, or biomethane gathered from waste, such as dairy manure or landfills, and processed to pipeline-grade specifications. Another potential replacement for fossil gas is industrial waste streams such as effluent from gas that has high sulfur content, such as that found in areas of the Haynesville and Eagle Ford shales.
Ultimately, blue hydrogen might serve as a transitional process as the world moves toward zero-emissions production methods.
“While blue hydrogen is not a universal solution, in the short to medium term it can mitigate emissions from hard-to-decarbonize sectors as green hydrogen technologies scale up,” Murphy said.
Source: Platts