As the United States strives to meet its goal of zero-carbon electricity generation by 2035, energy providers are rapidly increasing renewable resources such as solar and wind power. But because these technologies only produce electrons when the sun is shining and the wind is blowing, they need backup by other energy sources, especially during seasons of high electricity demand.
Currently, factories burning fossil fuels, mainly natural gas, are filling the gaps.
“As we move towards increasingly renewable penetration, this intermittency will have a greater impact on the power system,” says Emre Gençer, researcher at the MIT Energy Initiative (MITEI). In fact, network operators will increasingly have recourse to “peak” power stations based on fossil fuels which compensate for the intermittence of the sources of variable renewable energy (VRE) such as the sun and the wind. “If we want to achieve zero carbon electricity, we have to replace all sources that emit greenhouse gases,” says Gençer.
Low- and zero-carbon alternatives to cutting-edge greenhouse gas-emitting power plants are being developed, such as lithium-ion battery networks and hydrogen power generation. But each of these evolving technologies comes with its own set of advantages and constraints, and it has proven difficult to frame the debate on these options in a way that is useful for policymakers, investors and committed utilities. in the transition to clean energy.
Now Gençer and Drake D. Hernandez SM ’21 have come up with a model that can pinpoint the pros and cons of these alternatives to the tip plant with greater precision. Their hybrid technology and economic analysis, based on a detailed inventory of California’s electricity system, was published online last month in Applied Energy. While their work focuses on the most cost-effective solutions to replace advanced power plants, it also contains information intended to contribute to the larger conversation about transforming energy systems.
“The key takeaway from our study is that hydrogen power generation may be the most economical option compared to lithium-ion batteries, even today, when the costs of production, transmission and hydrogen storage is very high, ”says Hernandez, who worked on the study while a graduate research assistant for MITEI. Gençer adds: “If there is a place for hydrogen in the cases we have analyzed, this suggests that there is a promising role for hydrogen to play in the energy transition.
Add up the fees
California serves as a stellar paradigm for a rapidly evolving electrical system. The state gets more than 20% of its electricity from solar power and about 7% from wind, and more ERVs will be coming online quickly. This means that its peak power plants already play a central role, going into operation every evening when the sun goes down or when events such as heat waves increase electricity use for days on end.
“We looked at all of the state-of-the-art factories in California,” says Gençer. “We wanted to know the cost of electricity if we replaced them with hydrogen turbines or lithium-ion batteries. The researchers used a basic measure called the discounted cost of electricity (LCOE) as a way to compare the costs of different technologies with each other. LCOE measures the average total cost of building and operating a particular power generation asset per unit of total electricity produced over the assumed life of that asset.
Choosing 2019 as the baseline study year, the team looked at the costs of running peak natural gas-fired plants, which they defined as plants running 15% of the year in response to shortcomings in the intermittent renewable electricity. In addition, they determined the amount of carbon dioxide released by these factories and the cost of reducing those emissions. Most of this information was publicly available.
Pricing for replacing peak power plants with massive sets of lithium-ion batteries was also relatively straightforward: “There is no technical limitation to lithium-ion, so you can build as many as you want. ; but they are very expensive in terms of footprint for the energy storage and mining required to manufacture them, ”explains Gençer.
But then came the hardest part: fixing the costs of producing electricity from hydrogen. “The hardest part is finding cost assumptions for new technologies,” Hernandez explains. “You can’t do it through a literature review, so we’ve had a lot of conversations with equipment manufacturers and plant operators. “
The team envisioned two different forms of hydrogen fuel to replace natural gas, one produced by electrolyser facilities that convert water and electricity into hydrogen, and another that reformats natural gas, producing hydrogen and carbon waste that can be captured to reduce emissions. They also analyzed the numbers on upgrading natural gas plants to burn hydrogen rather than building entirely new ones. Their model includes identifying probable locations statewide and the expense involved in constructing those facilities.
The researchers spent months compiling a giant dataset before embarking on the analysis task. The results of their modeling were clear: “Hydrogen may be a more cost-effective alternative to lithium-ion batteries for peak operations on a power grid,” explains Hernandez. Further, notes Gençer, “Although some technologies work best in particular locations, we have found that, on average, reformation of hydrogen rather than electrolytic hydrogen has proven to be the cheapest option for this. replace peak power plants. “
A tool for energy investors
When he started this project, Gençer admits that he “had no hope” that hydrogen would replace natural gas in peak power plants. “It was a bit shocking to see in our different scenarios that there was a place for hydrogen.” This is because the overall price of converting a fossil fuel power plant to a hydrogen power plant is very high, and such conversions are unlikely to take place until more sectors of the economy adopt. not hydrogen, whether as a fuel for transportation or for various manufacturing and industrial purposes.
A nascent hydrogen production infrastructure exists, mainly in the production of ammonia for fertilizers. But huge investments will be needed to expand this framework to meet network-wide needs driven by targeted incentives. “With all the climate solutions proposed today, we will need a carbon tax or carbon pricing; otherwise, no one will switch to new technologies, ”says Gençer.
Researchers believe studies like theirs could help major energy players make more informed decisions. To this end, they integrated their analysis into SESAME, a lifecycle and techno-economic assessment tool for a range of energy systems developed by researchers at MIT. Users can take advantage of this sophisticated modeling environment to compare the energy storage costs and emissions of different technologies, for example, or to determine whether it is cost effective to replace a natural gas-fired plant with one that is powered by one. to hydrogen.
“As utilities, industry and investors seek to decarbonize and achieve zero emissions targets, they must weigh the costs of investing in low carbon technologies today against the potential impacts of climate change in the future, ”said Hernandez, who is currently a senior partner in energy practice at Charles River Associates. Hydrogen, he believes, will become increasingly competitive as its production costs decline and markets expand.
A member of the soon-to-be-released MITEI Future of Storage study group, Gençer knows that hydrogen alone will not pave the way for a carbon-free future. But, he says, “Our research shows that we need to seriously consider hydrogen in the energy transition, start thinking about the key areas where hydrogen should be used and start making the massive investments needed.”
Funding for this research was provided by MITEI’s Low-Carbon Energy Centers and Future of Storage study.
Publication referenced in the article:
Drake D. Hernandez and Emre Gençer. Technical-economic analysis of the seasonal balancing of the Californian electricity system: hydrogen batteries vs lithium-ion batteries. Publication Accepted June 20, 2021, Available online July 6, 2021.
This article was written by MIT Energy Initiative. It was originally published here.