Distilled Thoughts On Hydrogen

image credit: physicsworld.com

All my concerns about hydrogen #hopium, in one convenient place!

Hydrogen is being sold as if it were the “Swiss Army knife” of the energy transition. Useful for every energy purpose under the sun. Sadly, hydrogen is rather like THIS Swiss Army knife, the Wenger 16999 Giant. It costs $1400, weighs 7 pounds, and is a suboptimal tool for just about every purpose!

The Wenger 16999 Giant (the Wenger brand is discontinued- owned by Victorinox)

Why do you hate hydrogen so much? I DON’T HATE HYDROGEN! I think it’s a dumb thing to use as a fuel, or as a way to store electricity. That’s all.

I also think it’s part of a bait and switch scam being put forward by the fossil fuel industry. And what about the electrolyzer and fuelcell companies, the technical gas suppliers, natural gas utilities and the renewable electricity companies that are pushing hydrogen for energy uses? They’re just the fossil fuel industry’s “useful idiots” in this regard.

https://www.jadecove.com/research/hydrogenscam

If you prefer to listen rather than read, I appeared as a guest on the Redefining Energy Podcast, with hosts Laurent Segalen and Gerard Reid: episodes 19 and 44

https://redefining-energy.com/

…or my participation in a recent Reuters Renewables debate event, attended by about 3000

This article gives links to my articles which give my opinions about hydrogen in depth, with some links to articles by others which I’ve found helpful and accurate.

Hydrogen For Transport

Not for cars and light trucks. The idea seems appealing, but the devil is in the details if you look at this more than casually.

https://www.linkedin.com/pulse/hydrogen-fuelcell-vehicle-great-idea-theory-paul-martin/

When you look at two cars with the same range that you can actually buy, it turns out that my best case round-trip efficiency estimate- 37%- is too optimistic. The hydrogen fuelcell car uses 3.2x as much energy and costs over 5.4x as much per mile driven.

https://www.linkedin.com/pulse/mirai-fcev-vs-model-3-bev-paul-martin/

What about trucks? Ships? Trains? Aircraft?

For trucks- I agree with James Carter- they’re going EV. EVs will do the work from the short range end of the duty, and biofuels will take the longer range, remote/rural delivery market for logistical reasons. Hydrogen has no market left in the middle in my opinion.

Trains: same deal.

Aircraft? Forget about jet aircraft powered by hydrogen. We’ll use biofuels for them, or we’ll convert hydrogen and CO2 to e-fuels if we can’t find enough biofuels. And if we do that, we’ll cry buckets of tears over the cost, because inefficiency means high cost.

(Note that the figures provided by Transport and Environment over-state the efficiency of hydrogen and of the engines used in the e-fuels cases- but in jets, a turbofan is likely about as efficient as a fuelcell in terms of thermodynamic work per unit of fuel LHV fed. The point of the figure is to show the penalty you pay by converting hydrogen and CO2 to an e-fuel- the original T&E chart over-stated that efficiency significantly)

Ships? There’s no way in my view that the very bottom-feeders of the transport energy market- used to burning basically liquid coal (petroleum residuum-derived bunker fuel with 3.5% sulphur, laden with metals and belching out GHGs without a care in the world) are going to switch to hydrogen, much less ammonia, with its whopping 11-19% round-trip efficiency.

https://www.linkedin.com/pulse/ammonia-pneumonia-paul-martin/

Heating

Fundamentally, why do we burn things? To make heat, of course!

Right now, we burn things to make heat to make electricity. Hence, it is cheaper to heat things using whatever we’re burning to make electricity, than it is to use electricity. Even with a coefficient of performance for a heat pump, so we can pump 3 joules of heat for every joule of electricity we feed, it’s still cheaper to skip the electrical middleman and use the fuel directly, saving all that capital and all those energy losses.

https://www.linkedin.com/pulse/home-heating-electrification-paul-martin/

Accordingly, hydrogen- made from a fuel (methane), is not used as a fuel. Methane is the cheaper option, obviously!

In the future, we’re going to start with electricity made from wind, solar, geothermal etc. And thence, it will be cheaper to use electricity directly to make heat, rather than losing 30% bare minimum of our electricity to make a fuel (hydrogen) from it first. By cutting out the molecular middleman, we’ll save energy and capital. It will be cheaper to heat using electricity.

I know it’s backwards to the way you’re thinking now. But it’s not wrong.

Replacing comfort heating use of natural gas with hydrogen is fraught with difficulties.

(this is my peer reviewed article in Energy Science and Engineering on this topic in detail)

https://scijournals.onlinelibrary.wiley.com/doi/10.1002/ese3.1861

https://www.linkedin.com/pulse/hydrogen-replace-natural-gas-numbers-paul-martin/

Hydrogen takes 3x as much energy to move than natural gas, which takes about as much energy to move as electricity. But per unit exergy moved, electricity wins, hands down. Those thinking it’s easier to move hydrogen than electricity are fooling themselves. And those who think that re-using the natural gas grid just makes sense, despite the problems mentioned in my article above, are suffering from the sunk cost fallacy- and are buying a bill of goods from the fossil fuel industry. When the alternative is to go out of business, people imagine all sorts of things might make sense if it allows them to stay in business.

Hydrogen as Energy Storage

We’re going to need to store electricity from wind and solar- that is obvious.

We’re also going to need to store some energy in molecules, for those weeks in the winter when the solar panels are covered in snow, and a high pressure area has set in and wind has dropped to nothing.

It is, however, a non-sequitur to conclude that therefore we must make those molecules from electricity! It’s possible, but it is by no means the only option nor the most sensible one.

https://www.linkedin.com/pulse/hydrogen-from-renewable-electricity-our-future-paul-martin/

…But…Green Hydrogen is Going to Be So Cheap!

No, sorry folks, it isn’t.

The reality is, black hydrogen is much cheaper. And if you don’t carbon tax the hell out of black hydrogen, that’s what you’re going to get.

Replacing black hydrogen has to be our focus- our priority- for any green hydrogen we make. But sadly, blue (CCS) hydrogen is likely to be cheaper. Increasing carbon taxes are going to turn black hydrogen into muddy black-blue hydrogen, as the existing users of steam methane reformers (SMRs) gradually start to capture and bury the easy portion of the CO2 coming from their gas purification trains- the portion they’re simply dumping into the atmosphere for free at the moment.

https://onlinelibrary.wiley.com/doi/full/10.1002/ese3.956

There is no green hydrogen to speak of right now. Why not? Because nobody can afford it. It costs a multiple of the cost of blue hydrogen, which costs a multiple of the cost of black hydrogen.

The reality is, you can’t afford either the electricity, or the capital, to make green hydrogen. The limit cases are instructive: imagine you can get electricity for 2 cents per kWh- sounds great, right? H2 production all in is about 55 kWh/kg. That’s $1.10 per kg just to buy the electricity- nothing left for capital or other operating costs. And yet, that’s the current price in the US gulf coast, for wholesale hydrogen internal to an ammonia plant like this one- brand new, being constructed in Texas City- using Air Products’ largest black hydrogen SMR.

https://www.bizjournals.com/houston/news/2020/01/08/major-ammonia-plant-project-to-start-construction.html

At the other end, let’s imagine you get your electricity for free! But you only get it for free at 45% capacity factor- which by the way would be the entire output of an offshore wind park- about as good as you can possibly get for renewable electricity (solar here in Ontario for instance is only 16% capacity factor…)

If you had 1 MW worth of electrolyzer, you could make about 200 kg of H2 per day at 45% capacity factor. If you could sell it all for $1.50/kg, and you could do that for 20 yrs, and whoever gave you the money didn’t care about earning a return on their investment, you could pay about $2.1 million for your electrolyzer set-up- the electrolyzer, water treatment, storage tanks, buildings etc.- assuming you didn’t have any other operating costs (you will have). And…sadly…that’s about what an electrolyzer costs right now, installed. And no, your electrolyzer will not last more than 20 yrs either.

Will the capital costs get better? Sure! With scale, the electrolyzer will get cheaper per MW, as people start mass producing them. And as you make your project bigger, the cost of the associated stuff as a proportion of the total project cost will drop to- to an extent, not infinitely.

But the fundamental problem here is that a) electricity is never free b) cheap electricity is never available 24/7, so it always has a poor capacity factor and c) electrolyzers are not only not free, they are very expensive and only part of the cost of a hydrogen production facility.

Can you improve the capacity factor by using batteries? If you do, your cost per kWh increases a lot- and that dispatchable electricity in the battery is worth a lot more to the grid than you could possibly make by making hydrogen from it.

Can you improve the capacity factor by making your electrolyzer smaller than the capacity of your wind/solar park? Yes, but then the cost per kWh of your feed electricity increases because you’re using your wind/solar facility less efficiently, throwing away a bunch of its kWh. And I thought that concern over wasting that surplus electricity was the whole reason we were making hydrogen from it!?!?

John Poljak has done a good job running the numbers. And the numbers don’t lie. Getting hydrogen to the scale necessary to compete with blue much less black hydrogen is going to take tens to hundreds of billions of dollars of money that is better spent doing something which would actually decarbonize our economy.

https://www.linkedin.com/feed/update/urn:li:activity:6761296385645117440/

UPDATE: John’s most recent paper makes it even clearer- the claims being made by green hydrogen proponents of ultra-low costs per kg of H2 are “aspirational” and very hard to justify in the near term. They require a sequence of miracles to come true.

https://www.linkedin.com/feed/update/urn:li:activity:6826148496073207809/

Why Does This Make You So Angry, Paul?

We’ve known these things for a long time. Nothing has changed, really. Renewable electricity is more available, popular, and cheaper than ever. But nothing about hydrogen has changed. 120 megatonnes of the stuff was made last year, and 98.5% of it was made from fossils, without carbon capture. It’s a technical gas, used as a chemical reagent. It is not used as a fuel or energy carrier right now, at all. And that’s for good reasons associated with economics that come right from the basic thermodynamics.

What we have is interested parties muddying the waters, selling governments a bill of goods- and believe me, those parties intend to issue an invoice when that bill of goods has been sold! And that’s leading us toward an end that I think is absolutely the wrong way to go: it’s leading us toward a re-creation of the fossil fuel paradigm, selling us a fossil fuel with a thick obscuring coat of greenwash. That’s not in the interest of solving the crushing problem of anthropogenic global warming:

https://www.linkedin.com/pulse/global-warming-risk-arises-from-three-facts-paul-martin/

Where Does Hydrogen Make Sense?

We need to solve the decarbonization problem OF hydrogen, first. Hydrogen is a valuable (120 million tonne per year) commodity CHEMICAL – a valuable reducing agent and feedstock to innumerable processes- most notably ammonia as already mentioned. That’s a 40 million tonne market, essential for human life, almost entirely supplied by BLACK hydrogen right now. Fix those problems FIRST, before dreaming of having any excess to waste as an inefficient, ineffective heating or comfort fuel!!!

Here’s my version of @Michael Liebreich’s hydrogen merit order ladder. I’ve added coloured circles to the applications where I think there are better solutions THAN hydrogen. Only the ones in black make sense to me in terms of long-term decarbonization, assuming we solve the problem OF hydrogen by finding ways to afford to not make it from methane or coal with CO2 emissions to the atmosphere- virtually the only way we actually make hydrogen today.

If Not Hydrogen, Then What?

Here’s my suite of solutions. The only use I have for green hydrogen is as a replacement for black hydrogen- very important so we can keep eating.

https://www.linkedin.com/pulse/what-energy-solutions-paul-martin/

There are a few uses for H2 to replace difficult industrial applications too. Reducing iron ore to iron metal is one example- it is already a significant user of hydrogen and more projects are being planned and piloted as we speak. But there, hydrogen is not being used as a fuel per se- it is being used as a chemical reducing agent to replace carbon monoxide made from coal coke. The reaction between iron oxide and hydrogen is actually slightly endothermic. The heat can be supplied with electricity- in fact arc furnaces are already widely used to make steel from steel scrap.

In summary: the hydrogen economy is a bill of goods, being sold to you. You may not see the invoice for that bill of goods, but the fossil fuel industry has it ready and waiting for you, or your government, to pay it- once you’ve taken the green hydrogen bait.

DISCLAIMER: everything I say here, and in each of these articles, is my own opinion. I come by it honestly, after having worked with and made hydrogen and syngas for 30 yrs. If I’ve said something in error, please by all means correct me! Point out why what I’ve said is wrong, with references, and I’ll happily correct it. If you disagree with me, disagree with me in the comments and we’ll have a lively discussion- but go ad hominem and I’ll block you.

Green Hydrogen as a Fuel is a Zombie Meme Idea

TL&DR summary:  hydrogen as a fuel is a zombie idea.  Thermodynamics and the properties of the molecule ensure that it will never be alive in economic terms.  Hydrogen’s dirty present hasn’t meaningfully changed over the last 20 years, and hydrogen as a fuel isn’t a real decarbonization idea.  However, while it will never be alive, don’t be too hopeful- you can’t kill it.  It’s a meme.  It is the simpleminded answer you get when you ask the wrong questions about decarbonization.  And it’s too valuable as a predatory delay strategy to ever be truly abandoned.

I’ve seen a lot of claims in recent days, that the hydrogen as a fuel #hopium epidemic is showing signs of coming to an end.  That the hydrogen hyperbole bubble is popping.  That the hydrogen souffle, as Michael Liebreich calls it, is collapsing.  Governments and major businesses are starting to wake up and smell the rotten stench arising from the idea that decarbonization was as simple as substituting what gas flows in the natural gas pipelines, or swapping which fuel is used in vehicle and aircraft engines.  While these high profile cancellations and project collapses are all good, hopeful signs, this article serves as a warning.  Those who are hoping that the hydrogen hyperbole will rapidly shrink back to the nothing upon which it was based, are not being realistic. 

Hydrogen as a fuel isn’t a simple idea, or alternative among many, or tool in the toolbox etc.:  it’s a meme- an idea that spreads by imitation.  And while you can combat a meme, killing one outright is very difficult.

My previous writings have explained in detail that hydrogen is a massive commodity chemical, made the same way that it was 20 years ago:  99% of it is made from fossils such as natural gas and coal, with carbon capture nowhere in sight.  It is made where and when its unique properties as a chemical are required. Almost no hydrogen is made today by the deliberate electrolysis of water using dedicated new renewable electricity resources.  Hydrogen is rarely transported, and rarely burned as a fuel, unless it’s a byproduct without any other practical use nearby, or when it’s mixed with a bunch of low value gases to the point where its only value is its heat energy value.  The ~ 120 million tonnes of yearly world hydrogen production, both as a pure gas and as hydrogen in syngas, generates as much as 4% of world GHG emissions today- more than aviation, and almost as much as aviation and shipping combined.

Hydrogen is therefore a massive decarbonization problem, not a decarbonization solution to much of anything.

https://www.linkedin.com/pulse/hydrogen-from-renewable-electricity-our-future-paul-martin

The notion that we will use renewable electricity to make hydrogen for use as a fossil fuel substitute, however, remains popular in the public imagination.  Why is that?  Because the concept satisfies an important human need:  the need for familiarity.  We’ve spent 800,000 years as a species, burning stuff whenever we needed heat.  Very old ideas like that are almost woven into our DNA- they are very difficult to remove and re-think.

If you ask yourself the wrong question:  “We can’t burn fossils any more because of global warming.  What else can we burn?”, you often get hydrogen as a simpleminded answer.  Therein lies the mematic nature of

the “hydrogen as a fuel” concept.

This is very similar to a story told about the father of the periodic table, Dimitri Mendeleev.  People asked the great chemist, father of the periodic table, what he thought about burning petroleum as a heating fuel.  He said, “I suppose you could also keep warm by burning banknotes in the kitchen stove.”   Wasting hydrogen for low value uses for which it is poorly suited, is very much like burning petroleum- a precious, finite resource, of incredible value as a feedstock for making tens of thousands of materials and chemicals.  Even while we didn’t know for sure that the atmosphere wasn’t a free and limitless public sewer, Mendeleev saw the inherent waste in that decision.  And burning hydrogen- just like burning banknotes, or petroleum- is the “let them eat cake” of the energy transition.  It works as a concept only under the influence of #hopium about future prices, and OPM, i.e. “other people’s money”.

https://www.linkedin.com/pulse/refinery-future-thought-experiment-paul-martin-4pfoc

 For hydrogen, it’s even worse- because petroleum derived gasoline and diesel and jet fuel are highly effective fuels, even though they are burned in  comparatively inefficient engines.  The effectiveness- arising from the ease with which these energy dense liquids can be moved and stored- outweighed their inefficiency, at least until we understood global warming.  The need to collect or eliminate their combustion CO2 emissions, totally destroyed their effectiveness as transport fuels.

Sadly, hydrogen, when wasted as a fuel, is neither efficient nor effective.  And its properties, and its thermodynamics, ensure that it will never be either when it is wasted in that way.

https://www.linkedin.com/pulse/breakthrough-electrolyzer-efficiency-paul-martin

And no, it’s not getting as cheap as some seem to imagine.

https://www.linkedin.com/pulse/scaling-lesson-2-water-electrolysis-paul-martin

When you ask yourself the right question:  “We can’t burn fossils any more because of global warming.  How else can we make the energy services we need, without generating fossil GHG emissions?” , the answer to that question is rarely hydrogen!

Certainly not as a vehicle fuel.

https://www.linkedin.com/pulse/case-against-hydrogen-trucks-paul-martin-gq5mc

Not even as a fuel for “hard to decarbonize” vehicles like transoceanic ships and aircraft.  The ineffectiveness arising from hydrogen’s extremely low energy density per unit volume, even as an ultra-cryogenic liquid, kill those ideas dead- once you’ve spent a few minutes looking into the details.  So instead, we see people focusing on using hydrogen to make fuels from water-derived electrolytic hydrogen and CO2, or even worse, from nitrogen.  Trading even more efficiency in a vain attempt to gain some effectiveness.

Certainly also not as a heating fuel.

https://www.linkedin.com/pulse/why-hydrogen-blending-gas-network-bollocks-paul-martin-i5sdc

Not for homes and commercial spaces, where now about 60 independent studies have panned the idea as just what it is:  expensive nonsense, intended to keep us feeling happy about burning fossil gas for longer.

And not even for high temperature heating.  No, it still makes more sense to make heat from electricity directly, than indirectly through turning part of the energy in electricity into chemical energy in a fuel.  Not even for cement clinkering kilns.

https://www.linkedin.com/pulse/electric-heating-future-industrial-heat-paul-martin-8vvqc

https://www.linkedin.com/pulse/can-hydrogen-help-green-cement-production-paul-martin-aibwc

It’s literally as simple as my Drake meme:  if you’re thinking the hydrogen you’re making is green, if the local grid isn’t green, you’re wrong- even if your project is islanded.  Remember that even in the best case, “green” hydrogen isn’t totally free of GHG emissions.

https://www.linkedin.com/pulse/how-green-hydrogen-lifecycle-basis-paul-martin-pbhyc

And even if the local grid is green, the focus must remain on the decarbonization of the easy to decarbonize sectors via direct electrification.  That’s going to yield the biggest reductions in GHG emission per dollar spent.  Only once that obvious problem is solved, should we begin to concern ourselves with making green hydrogen to replace black hydrogen, in applications where its unique chemical properties are needed.

https://www.linkedin.com/pulse/where-does-green-hydrogen-fit-paul-martin-oc8ac

 

And only after that is accomplished, should we be concerning ourselves with building new applications for green hydrogen as a chemical- the direct reduction of iron being an obvious one.

https://www.linkedin.com/posts/paul-martin-195763b_what-is-green-steel-simple-its-a-misnomer-activity-7293288766910156802-BGpN

So:  what can we expect? 

We can expect more plans, targets and studies.  More public money wasted on what is fundamentally a dead end.  A gradual morphing of the idea of hydrogen as a decarbonization panacea, to a narrower focus on industrial decarbonization (industries who can be enticed to participate in the scam by subsidies).  The shrinking of the concept of hydrogen as a fuel for cars and light trucks, to one for heavy trucks and heavy equipment- where it will also, gradually, fail.  And away from home heating to industrial heating, where it will similarly fail, for the same reasons:  the cost per tonne of CO2e emissions averted is just way, way too high.  Project plans will continue to be delayed or cancelled, failing to find willing offtakers at realistic prices for the product.

But will the idea die?  No way.  It will remain for a long, long time. 

Because it serves a key, important purpose:  it delays real decarbonization action.  It keeps us happy to burn fossils, for longer, in hope that the propellor-headed engineers and scientists will invent us a decarbonization strategy that allows us to keep doing what we’re comfortable with, without extra cost or a need to change anything.  It provides a nice, simpleminded fuel substitution- off at some point comfortably in the future, so we can keep burning fossils for now.  And there will be plenty of charlatans, shysters, and snake oil salesepeople out there to sell the public and our politicians on this simpleminded notion.

Disclaimer:   this article was written by a human, and hence is subject to error.  Provide me with corrections with good references and I will gratefully correct my work.

However, if your principal concern is that I’ve taken a dump on your pet idea, please contact my employer, Spitfire Research Inc., who will be happy to tell you to piss off and write your own article.

Green Steel = Green Iron

Image credit: Google Gemini

What is “green steel”? Simple. It’s a misnomer.

Iron in nature is rarely found alone. We mine its oxides as iron ores. These oxides need to be chemically reduced (gaining electrons = reduction) to take the Fe+2 and Fe+3 ions in the iron oxides, to Fe metal. And the oxygen needs to lose electrons to somebody else more willing to take them than iron was- or to be forced to give them up.

The traditional way we do that reduction is by (largely) reacting the iron in the ore with carbon monoxide, to produce carbon dioxide and iron metal. This is done either starting with coke made from coal in a blast furnace, or with synthesis gas (CO +H2) made from fossil gas in a device called a “Direct Reduction of Iron ” (DRI) furnace.

Once you have the iron, you can add scrap steel and make steel from it. In the US, about 70% of steelmaking is done in electric arc furnaces, so “steelmaking” is already substantially electric (not so in China…). Yes, there are lots of other steps in making steel products- soaking pits, annealing furnaces etc.- that are fired by fossil fuels- but that’s largely because the atmosphere remains a free or very cheap public sewer for the CO2 that is produced.

When people say “green steel”, what they mean generally is replacing the CO + H2 in a DRI unit with nearly pure electrolytic H2, made from water using renewable or low GHG electricity. Some CO is still required, but dramatically less than in a normal DRI furnace. What is also needed is electric heat, provided by resistance heaters, to make up for the lost heat of reaction. The product is still iron, not steel.

So what people mean, when they say “green steel”, is really “green iron”.

There are molten oxide (very high temperature) and aqueous electrolytic approaches to making iron, under development. Neither are going to be commercially ready for at least the next ten years, if they ever succeed.

Right now, “green iron” is one of the few ways we have of substantially reducing GHG emissions from far and away the most popular structural metal used on earth. However, because “green” electrolytic hydrogen is structurally expensive, so is green iron. While exciting projects like Stegra in Sweden are underway, these projects need either customers willing to pay a great deal more per pound of steel for it to be “green”, or massive carbon taxes or emission bans to make existing “black’ steel expensive or otherwise push it out of the market.

That’s the key problem: everybody likes the idea of decarbonization, but everybody also wants somebody ELSE to pay for it. The policy measures to make the decarbonization of steel, and many other key high-emission sectors of our economy, into reliable investments for billions of dollars of private money, remain elusive. And no, you simply can’t fix that by subsidizing green H2 production.

Will Green Hydrogen Save the Cement Industry?

Image credit: Google Gemini

TL&DR summary:  hydrogen can be used in cement production as a natural gas replacement, but that doesn’t solve the entire CO2 emissions of cement production. There are other problems like the lack of hydrogen flame radiance, but the deal killer is the cost per tonne of CO2 emissions averted.  Hydrogen may have a role, but that role is not certain to be a major one.

Cement is the glue that reacts with water to hold concrete together.  Portland cement is made from a mixture of limestone (CaCO3), clay/shale (a complex mixture of silica-alumina minerals)  and iron oxides.  The process has two distinct steps:  calcining, where CO2 is driven off limestone (CaCO3) by heating it to form lime (CaO), and “clinkering”, where the complex mixture of calcium alumino-silicates is formed into lumps by partial melting at very high temperatures (1450 C).

About 60% of the CO2 generated by cement manufacture is the fossil CO2- quite literally fossil in this instance- liberated by calcining of limestone, which formerly was the shells of ancient sea life.  The balance, about 40%, is from fossil fuels used to provide the necessary high temperature heat.

As cement cures in a concrete mixture, over a period of about 100 years, some of the silicates in the cement “weather”, reacting with atmospheric CO2 to form carbonates again.  This process recovers about 15-17% of the cement-making process.  

https://www.sciencedirect.com/science/article/abs/pii/S0195925514000055

Overall, cement making is a massive fossil CO2 emitter, representing about 8% of world CO2 emissions.

Cement is a low cost commodity material which requires production at scale to be economic, and which also requires proximity to feedstocks and to markets to provide affordable logistics.  Only 1-2% of cement today is imported/exported- almost all cement production is local to the country where it is used.

Options for Emissions Reductions From Cement Use

Cement is over-used, because it is cheap.  Alternatives do exist, such as using more wood and other cellulosic materials in above-grade construction, the use of steel screw piles in place of concrete foundations etc.  But to be clear, concrete is extremely useful, particularly in the subsurface and in direct weathering applications.  We have little alternative but to find better ways to make and use cement.

Approaches other than substitution, fall into several categories:

Strength Enhancement/Cement Reduction

Certain concrete additives, alternative pozzolanic materials (things that substitute for cement), and special curing conditions (for products like precast concrete and concrete masonry units) can allow us to achieve the same strength while using less Portland cement.  However, one alternative pozzolanic material is fly ash from coal combustion, which also must end in a decarbonized future.

Alternatives to Limestone

Companies like Brimstone are developing processes by which the complex mixture of calcium silicates that make up Portland cement, can be made from silicate rather than carbonate minerals, potentially eliminating that ~40% of CO2 emissions associated with calcining.  However, these processes have a long technology development road ahead.  Furthermore, such processes may still require high temperature processing steps akin to “clinkering”, so the emissions from the fuels use thereof are a separate problem that still needs to be solved.

Carbon Capture and Storage

The CO2 emissions from cement production, particularly from calcining, are comparatively easily captured because the concentration of CO2 is higher in the flue gas stream than is found in a typical fossil fuel combustion system.  However, the fundamental problem with CCS is cost per tonne of CO2 for both capture and durable storage in the subsurface.  Furthermore, cement production tends to be centred around serving a local concrete consumption industry with the logistics of both raw materials supply and product distribution being important to the economics of the business.  Subsurface reservoirs suitable for CCS are not guaranteed to be anywhere near the sites of cement production, and distribution of CO2 to distant burial sites adds considerable cost and risk. 

Electrification of Calcining

Calcining is well within the temperature limits of electric heating, allowing a considerable reduction in the fuel-related emissions from cement production.  Electric calcining provides the additional benefit of a nearly pure CO2/steam stream which would make CO2 capture trivially easy- though not without cost, as compression and dehydration are required even for pure CO2.  The problem of the “S” part of the equation described above, obviously remains.

Clinkering is the Real Problem

While some development of plasma arc-based clinkering is underway, it is clear that the temperatures required inside a clinkering kiln are not easily electrified.

Clinkering is accomplished in rotary kilns, which are large rotating inclined steel tubes lined internally with refractory bricks.  The bricks serve as insulation against the high temperatures, allowing the steel to be cool enough that it retains the necessary strength.  Feed materials enter at one end, and a large radiant jet flame is emitted by fuel burners at the other end.  The radiation from the flame, and to a limited extent, convection from the hot flue gases, heat the bricks and the solid feed material.  As the kiln rotates, solid material advances along the tube, comes in contact with heated bricks, and gradually forms balls of semi-melted material which exit as finished “clinker”.

Note that it’s not mere high temperature heat that’s required here, but intense infrared radiation. And that radiation must be emitted inside the brick-lined kiln.

Coal is the perfect material for clinkering kiln firing because a powdered coal flame emits extremely strong radiation.  Natural gas can be substituted, but is less preferred despite its lower GHG emissions due to reduced flame radiance.  Various strategies have been used to enhance the flame radiance and reduce fuel cost or generate additional sources of revenue.  Oxygen addition to enhance flame temperature in natural gas fired kilns is one option.  Another, used in both coal and gas fired kilns, is the addition of waste materials, including tires, hazardous liquid organic wastes,  agricultural wastes and liquid sewage, and refuse-derived fuel (RDF), such that the cement kiln doubles duty as a waste incinerator.

Electricity Can’t Do it- Therefore Hydrogen?

Hydrogen certainly can be used as a fuel in cement clinkering kilns.  However, the list of problems is considerable.

Hydrogen flames are even less radiant than natural gas flames, requiring the addition of even more waste or alternative fuels to increase radiance.  Adding char or cellulosic biomass (wood flour) is one option that is fairly low in GHG emissions.  But any refuse derived fuel will have a net calorific value that is largely fossil in origin, i.e. coming largely from plastics and synthetic materials made from fossil materials.  The use of such fuels therefore increases fossil CO2 intensity, reducing the GHG emission benefits of using hydrogen.

Hydrogen’s cost per joule is very high relative to other fuels.  Whereas wholesale natural gas in the US might be $3.50/MMBTU, (1 MMBTU = roughly 1 GJ), even “black” hydrogen made from natural gas without CO2 capture at a wholesale cost of  $1.50/kg is $11/MMBTU- obviously considerably more expensive than the fuel it replaces.  Green hydrogen is considerably more expensive than black hydrogen, with current production costs in the $6-$9/kg range.  And even at future dreamland costs of green hydrogen of $3/kg, even assuming zero CO2e emissions from green hydrogen production (an ideal not achievable in practice) the displacement of natural gas with such hydrogen has a cost of about $350/tonne CO2 emissions averted.  Green hydrogen is a very expensive decarbonization strategy when it is used as a fuel- even when used for very high temperature heating applications where direct electrification seem impractical.

Clinkering is a continuous process, and the equipment must be kept hot to avoid damage from thermal cycling.  Operating periods of 18 months between shutdowns is not uncommon.  Hence, any green hydrogen production used, must have considerable storage to ensure continuous supply.  Intermittent operation of cement clinkering kilns will never be a technically feasible option. 

Conclusions- How Do We Decarbonize Cement Production?

This is one of the most difficult problems for us to solve on our journey to decarbonization.  A combination of many strategies will be required: 

  • Reduction of concrete use by substituting materials with better LCA performance
  • Reduction of cement use by making better concrete
  • Electric calcining, hopefully with carbon capture and storage- if we can afford it
  • Alternative pozzolanic materials (under development)
  • Using silicate instead of carbonate minerals (under development)
  • Substitution of coal and natural gas with biomass/biochar and biogas methane as cement kiln fuels
  • Electric clinkering via plasma arcs, if this can be commercialized
  • Hydrogen as a partial fuel- but only in places in the world where high capacity factor green electricity is available greatly in surplus to local electrical needs

One thing is certain:  cement and the concrete made from it, is a truly “hard to (totally) decarbonize sector”.  Cement is going to be a lot more expensive in a decarbonized future, regardless how we do it- especially so if hydrogen is our only way out.  And that begs the question:  is cement the appropriate focus for near-term investments in decarbonization?  Research and development- certainly.  But in my view, we shouldn’t allow excessive worry about how to decarbonize the last 5-10% of GHG emissions, divert our attention from how to eliminate the easy 90-95%.

Disclaimer:  this article has been written by a human, who is familiar with the issues involved but by no means a specialist in cement production.  If I’ve made an error in my text, please provide the correction with references and I’ll be happy to edit the article to better reflect reality.

If, however, I’ve taken a dump on your pet commercial idea, please contact my employer, Spitfire Research Inc., who will be happy to tell you to piss off and write your own article.

The ER-6: An Electrifying Conversion

UPDATED: 05/12/24

Those of you new to my articles may not know the beautiful and sad story of my previous conversion, my beloved Triumph E-Fire. Its told here in detail, from prehistory to its sad end…https://www.linkedin.com/pulse/e-fire-triumph-spitfire-ev-paul-martin/

This is the story of a resurrection- an electrifying conversion!

In spring of 2019 I bought a 1973 Triumph TR6. Referred to in a famous Top Gear episode as the blokiest bloke’s car ever built.

https://www.youtube.com/watch?v=4FageCtKA0gId

I always admired the TR6, but it was always out of my price range- and this one popped up at a price that was too attractive to pass up. The body and chrome were solid, more or less, and the frame had been restored by an amateur, but was solid enough. The engine was in great shape, though it had some issues as all 47 yr old cars do. It had a 4 speed manual transmission without the expensive, rare overdrive, which meant that the engine was spinning too fast at highway speeds, which didn’t bode well for long term longevity.

I struck a deal and drove the car home, with my wife in the chase car, our Prius C. And I took it right to my favorite British car mechanic. He might as well have just asked for my wallet at that point…But on the plus side, she who must be obeyed, who had only warmed to the E-Fire in the later days, liked this car straight away.

A couple grand’s worth of repairs later, I was wondering if the money pit had a bottom… I managed to get it out for one nice Toronto Triumph Club rally drive, and its 2.5 L straight six was happy to gobble up premium gasoline, make a satisfying roar and enough power to have no problems keeping up. But the car is under-geared- perfect for rally driving and roaring around the English countryside, but not much use on the highways in and out of Toronto. The thoughts of driving it up to the farm for the weekend were dashed- it would just cost too much for fuel, even if we could stand the stink of the untreated exhaust- 1973 was the last year before the emission controls really started in earnest.

The final straw was the transmissions decision to puke out its entire inventory of oil and then commit suicide, near summers end. I parked it, disgusted by the thought of having to pull that transmission to repair it. I just couldn’t bring myself to the task and expense of continuing what was likely the spending of good money after bad.

But then it struck me: I had a perfectly good electric drivetrain occupying a good fraction of my garage, salvaged from the E-Fire. Converting the car would likely be cheaper than fixing it…and I had managed, via a complaint to the Financial Services Commission of Ontario, to find an insurer who would insure a converted version. What was holding me back?

…that sweet engine…it just seemed such a shame to pull it!I tried to find someone to buy it, to no avail. So I took video of it running, starting, idling, running at high RPM, the oil pressure, the exhaust etc., and started making plans for a conversion in the winter when the car would need to be in the garage anyway.

Finally I broke down and pulled it. I started during the break between Christmas and New Years, carefully removing the engine and transmission and other bits for the benefit of other TR6 enthusiasts. (UPDATE: I sold the engine, and all the soft goods from the engine compartment, to TR6 enthusiasts. In fact the conversion cost me less in new materials than I received for these used parts. The conversion therefore, in a sense, “made money”…because I already had the electric drivetrain just sitting there, taking up space in my garage)

(we won’t be needing this horseshit any more!)

When I did the E-Fire project, my son was young enough to be interested. He’s now a strapping 17 yr old, an able 2nd pair of hands, but with interests that run to video games and entirely away from cars. So Id be alone on this one- but this time with the benefits of experience and 3.5 yrs of driving and maintaining the E-Fire behind me. I took the E-Fire project almost like a 2nd job, and was determined to take my time on this one, enjoying it more. And there was more to enjoy- because there was very little car cancer to try to cure this time, whereas the E-Fire was a case of multi-metastatic car cancer from top to bottom. I had burned through 2 full pounds of welding wire just doing repairs before I was done on that thing! The welder was basically unused on this project aside from making some brackets and battery boxes.

The TR6’s big cast iron engine is a heavy, huge beast, and removing it left a lot of room- but less efficient room than under the hood of the E-Fire as well as much less convenient to work on. The Spitfires hood takes the fenders with it like a mini E-type Jaguar, but the 6 has a conventional engine bay which was much less fun to work in.

The drivetrain fit was a pleasant surprise. I was able to use the same Toyota transmission and my AC50 3 phase induction motor, the mounting bracket and even the transitional driveshaft without modification. A small adapter plate was all that was required to connect the old driveshaft to the TR6 differential- a much heavier and more robust affair than that in the E-Fire, so hopefully more durable against the high forward and reverse torques of the electric drivetrain.

The basic configuration would be the same as last time: 33 rather than 32 LiFePO4 prismatic cells, each 180 Ah and about 1/2 kWh (for a total of about 19 kWh, and 106 V nominal, 119 V peak). The front pack was set a little lower than in the E-Fire, but further ahead than Id have liked. The geometry of old cars leaves you with poor choices sometimes, but since the batteries had come through the E-Fire crash without problems, I had some confidence that I’d be OK this time too. A small 4-cell pack was put a little further back for better weight distribution- and as a pack I could pull as an emergency 12V battery for house UPS if required. The complete rear pack from the E-Fire dropped right into the same place, replacing the old gas tank and its 80 pounds of gasoline, separated again from the driver by pressboard covered with vinyl. The chrome flip top filler cap was kept as bling- chrome in good condition is one of the appeals of these classic cars.

(Front pack wiring in progress- the little boards on top of the cells are BMS alarm trip modules which alarm on high or low voltage- essential protection equipment for expensive Li ion batteries)

The COVID 19 tragedy struck when I was in the middle of the project and had the side benefit of providing 7.5 hours every single week of time that I no longer had to waste driving to work and back on the GTAs notoriously congested highways. I put the time to good use!

(I call this yoga pose upward facing electrician)

Wiring went smoothly. The main conductors between the front and rear packs were re-used as were all the heavy 0 gauge jumpers which connected up the main DC power. I was able to re-use most of the wiring in my original junction box without modification. Basically all the work from the E-Fire conversion was useful on this project too- most of what I re-did, I did to improve the reliability of my crimping and the neatness of my work so the car looks prettier at car shows.

The dashboard had been ruined by a previous owners attempt at furniture refinishing. I had to thickness plane and re-veneer the dash, as well as changing the size of the gauge holes to fit my Intellitronix gauges. It took every clamp in my shop to glue this up, but the result is very pretty.

The configuration of the rest of the components was basically the same as in the E-Fire, and you can read about the details there. I basically had to buy only some wire, crimp connectors and wire ties for the build.

There were a few things I needed to change from the E-Fire. One was the Curtis “potbox”, a mechanical potentiometer used in golf carts and the like as an accelerator position sensor. These units are in theory rated for a million cycles, but in reality they get ragged and jerky after a year or two of driving as you wear a “flat spot” at common speed settings. I replaced it with a Honeywell hall effect sensor which I hope will have more longevity. The other was that the TR6 had engine vacuum assist for the hydraulic brakes, being a heavier and more solid car. I had to fit a vacuum storage vessel and a small 12V diaphragm pump to pull the necessary vacuum. The “power brakes” on the car are really provided by regenerative braking, still sensed by a potbox on the slop in the brake pedal just like on the E-Fire. That arrangement can be defeated by a switch on the dashboard for safety in wet weather, as it rearward biases the braking which can be dangerous on a rear-wheel drive car.

So far the ER-6 is a very enjoyable drive! It is quieter, more comfortable and much more stylish than the E-Fire, but without its sexy Michellotti curves- I do miss those. It’s noticeably heavier so the acceleration is less zippy, and I expect the watt-hours per mile energy efficiency to drop a bit. I wont be commuting in this one- surviving one total write-off collision in a roadster with my life, much less uninjured, is not something I want to risk trying a 2nd time.

UPDATE:  several years in, and the original 2014 battery pack from the E-Fire project was starting to show its age.  The cells have crept upward in internal resistance, which causes a BMS alarm every time you tromp heavily on the accelerator (which is, let’s face it, not something you’re going to avoid doing in an electric roadster!).  The plan is likely to replace the original pack with 280 Ah LFP prismatic cells, which are about the same base dimension but also shorter than the 180 Ah cells I bought in 2014.  The trick will be to find 2C rated 280 Ah prismatics from a Chinese supplier that I can trust to have trustworthy specs.  Most 280 Ah prismatics are rated for 0.5 C discharge with only 1 C discharge peak, as they are intended for solar applications.  Pulling 2C from these, even for 2 minutes, would not be a good thing for longevity. 

The original Elcon charger that I bought in 2014, also kicked the bucket.  Being unwilling to waste another $1000 on similarly unreliable crap, I decided to use a home-made Frankenstein charger as a stop-gap measure.  It consists of a variable autotransformer (Variac), a bridge rectifier, a fan to keep them both cool, and a solid state relay interlocked to the BMS to shut off the AC side when the BMS trips on high cell voltage on any cell.  It works perfectly fine, and cost a total of $100 to build.  Mind you, the power factor is absolutely terrible, but residential customers aren’t charged for power factor. 

Finally, the cell-top “mini BMS” boards are no longer made, and it’s been impossible to find more of them.  If I go with the 280 Ah bricks, I’ll be installing a new BMS which will give me more data.  I’ve been given one by a kind LinkedIn colleague, but it is an OEM device which requires software requiring a licensing key to program.  As Spitfire Research is doing well enough, I think I can overcome my native cheapness and buy something that I will have full access to program and to gather data from easily.  If there’s anybody out there in the EV conversion community that has a really great solution to suggest (yes, I’m already aware of the Ewert Orion BMS system, but it’s also already showing its age), I’m all ears!

Got to admit, since we bought our Model Y, the ER6 has sat around dejectedly in the driveway quite a lot.  An update of the battery pack to improve range by 50%, and replacement of my Frankenstein with a charger that is J1772 compatible, will make it a lot more practical. 

Can You Put Hydrogen in Natural Gas Pipelines? Ya, but…

Ya-but the rabbit, courtesy of Google Gemini

TL&DR Summary:  sure, you can re-use an existing gas pipeline to carry some quantity of hydrogen at some pressure, and do so safely.  How much pressure and under what circumstances and operating conditions, and how much energy can be delivered via that repurposed pipe, and whether or not this makes any economic or environmental sense in a decarbonized future- these are all questions that don’t have such a clear answer.  The devil’s in the details, and in some cases, he’s definitely not hiding there in complex matters- he’s plainly visible from a distance, in simple and well known issues.  The result is an object lesson in how someone can ask an engineer a “yes/no” question, and receive the answer “Yes, but…”, and then do the very human thing which is to hear only the word “yes” and more or less ignore the rest.

Why Do I Care?

I’m the principal author of a peer reviewed research review paper on the re-use of existing fossil natural gas infrastructure for pure hydrogen and hydrogen/fossil gas blends.  The paper is open access, and was published in Energy Science and Engineering, which is a high impact scientific journal.

https://scijournals.onlinelibrary.wiley.com/doi/10.1002/ese3.1861

My co-authors in that paper include several prominent scientists working for the Environmental Defense Fund in the US and Europe, and two of my co-founders of the Hydrogen Science Coalition, all of whom are qualified scientists and engineers in their own right.  Our paper looked at every aspect of the fossil gas production, transmission, distribution and end-use, and evaluated the feasibility and issues which come along with hydrogen-methane blends and with pure hydrogen, given that this option is being offered by the fossil natural gas industry as a beneficial re-use of their existing infrastructure.  Our paper sailed through peer review, in part because the major issues contained therein had already been extensively peer reviewed here on LinkedIn, which has in fact greater reach to people who, in my opinion, have the most practical knowledge about these issues:  engineers working in the private sector, as I still am and have been for over 30 years- people who, by and large, rarely have occasion to read the academic press.

https://www.linkedin.com/pulse/hydrogen-replace-natural-gas-numbers-paul-martin

To briefly summarize the results of our review, the main problems are in the gas transmission network- the long, high pressure pipelines which carry gas between countries and regions.  The distribution network could perhaps be re-used for pure hydrogen without damage to that network’s components, but every end use device on the network would need replacement or substantial retrofit first, and numerous other concerns such as hydrogen leakage and permeation leading to effective GHG emissions and a greater risk of fires and explosions, would need to be addressed.  The transmission pipes, on the other hand, were never designed to handle hydrogen, nor were their associated compressors, valves and the like.  The significant differences in properties between hydrogen and a typical natural gas which is mostly methane, make the transmission pipes vulnerable to damage, and the existing compressors fundamentally unsuitable for the new duty.

While our paper deliberately steers clear of the economics of using green hydrogen as a fossil gas replacement, when one does such an evaluation, it’s clear that the notion of hydrogen as a gas replacement is fraught, even in a dreamy future time when green hydrogen is very, very much cheaper than it is today. Why? The cost per tonne of CO2 emissions averted is just ridiculously high even if one assumed that the gas network itself didn’t need modification at all.  Any risks or costs we might undertake in the process of repurposing the gas network as part of a green hydrogen based GHG emission mitigation scheme are therefore without a valuable destination, and hence not worth the cost or risk involved.  Here’s my basic arithmetic proving that point:

https://www.linkedin.com/pulse/why-hydrogen-blending-gas-network-bollocks-paul-martin-i5sdc

Needless to say, some people in the gas transmission and distribution industry took issue with our conclusions.  One entity, the Dutch gas network operator Gasunie, an entity wholly owned by the State of the Netherlands, was particularly vocal in criticism of our work.  Gasunie had concluded in a public report titled “Hyway27”, that the transition of their existing transmission assets to carry pure hydrogen in the future was basically a “solved matter”, so they dismissed our paper publicly as “old news”.

https://www.gasunie.nl/en/expertise/hydrogen/hyway-27

A read of Gasunie’s Hyway27 final report is interesting.  It seems to me to be an object lesson to engineers in relation to how their work can be taken out of context by a motivated client.

At Section 4, the Hyway27 report reads as follows:

“This confirms that the wall thicknesses of existing pipelines, which are determined by the diameter of the pipeline, as well as the rated pressures and steel quality are adequate for hydrogen transmission as well at a similar rated pressure (Bilfinger Tebodin , 2019).”

The Hyway27 report goes on to imply in its summary that all that’s required to repurpose certain Dutch gas transmission pipelines for pure hydrogen is to clean the lines, replace some valves, and make a small adjustment in operating pressure.

Well that’s clear enough then, isn’t it?  Myself and my co-authors must have just gotten this whole issue wrong, because we didn’t bother to do a good enough search for references when writing our review! 

Bilfinger Tebodin 2019:  “Research Technical Aspects of Hydrogen – In Existing Pipelines for the Energy Transition”

When you look into it, you find that the Bilfinger Tebodin report referenced in support of that rather strident, conclusive statement, is not publicly available- or at least by means that my Google-fu was able to obtain.  Repeated requests to Gasunie for copies of that report, so its conclusions and qualifications could be interrogated, fell on deaf ears.  In other words, Gasunie’s position was more or less that “We know it’s all OK, on the basis of information that we’ve received but aren’t willing to share with you.  Trust us!”

But fortunately, I have about 30,000 followers here on LinkedIn, and a resourceful follower who shall remain anonymous, was able to obtain a Dutch .pdf of that report.  With some effort the report was translated to Word and then to English via Word’s auto-translate feature, as my Dutch is limited to a few choice cusswords.  However, because the report isn’t public, I’m not able to share the whole text with you to read it yourself.  If you really want to read it and draw your own conclusions, sadly you’ll likely need to make a Freedom of Information request to the Dutch Ministry of Infrastructure and Water Management, for whom the report was written by Bilfinger Tebodin, a large and well respected engineering consultancy.

Here are a few quotes from the report, with my thoughts:

“·         The design factors that have been applied over the years for high-pressure natural gas pipelines are in line with the design factors used for new hydrogen pipelines to be built. This means that the wall thicknesses used for the existing pipelines, corresponding to the relevant pipe diameters, design pressures and steel qualities, are suitable for the use of hydrogen at a comparable design pressure.”

When you read that bullet point in isolation, you might conclude (wrongly!) like Gasunie seems to have done, that the pipelines are in fact suitable for re-use “at similar pressure” with hydrogen.  But a knowledgeable reader understands that wall thickness checks for hoop stress are just one of several things that need to be satisfied for pipeline safety.

“·         The damage mechanism that deserves extra attention for hydrogen applications under natural gas design conditions is fatigue crack growth. For smaller pipes (≤ DN400) with a lower steel grade (Re~ 245 N/mm2), no excessive crack growth is expected, even for larger pressure changes (∆p~ 30% of the design pressure). These small existing pipelines do not need to be subjected to an extensive quantitative analysis if they are to be used for hydrogen gas applications.

For larger pipes (> DN400) with a higher steel grade (Re ≥ 415 N/mm2), smaller pressure changes ((∆p ≤ 10% of the design pressure) are also not expected to result in excessive crack growth. When larger pressure changes are expected, there is a real chance of fatigue crack growth (PM’s emphasis). In this case, a quantitative analysis will have to be performed, which may result in limitations in business operations in the form of lower operating pressures and/or pressure changes.”

For reference, DN400 (16″) pipe is pretty small as gas pipelines go, and Re (yield strength) of 245 N/mm2 (36 ksi) is mild steel– yeah, these lines are FINE with hydrogen!  While mild, low alloy carbon steels are commonly used in chemical plant piping for hydrogen at ambient temperatures, people don’t generally make long distance fossil gas high pressure transmission pipelines out of mild steel, and haven’t for a long, long while.

Real pipelines are going to be > DN400 and > 415 N/mm2 (60 ksi) yield for the most part.  And the issues with the acceleration of fatigue cracking and the loss of fracture toughness on exposure to molecular hydrogen is well documented and discussed thoroughly in our paper, and even more thoroughly in my article here in relation to extensive DVGW testing done on pipeline steels to examine this risk.

https://www.linkedin.com/pulse/german-gas-pipelines-fundamentally-suitable-carrying-hydrogen-martin

The softest, lowest yield strength gas transmission pipeline steels used in the modern era are generally made of something like API 5L grade X42, which is also commonly used in hydrogen pipelines.  X42 has a yield strength of 42 ksi, i.e.  somewhere between these figures, i.e. between mild steel at 36 ksi and a typical 60 ksi pipeline steel.  For the higher yield strength steels, the rules based portion of ASME B31.12, the code used for the design of hydrogen pipelines, would apply a “material performance factor Hf” of between 0.874 and 0.776, i.e. de-rating the design pressure of a pipe of given wall thickness to between 87.4% and 77.6% of what it would be allowed to have if it were carrying natural gas.  If the design pressure of the line is increased (above the 66 bar design pressure which seems to have been assumed in the case of the Gasunie lines), that Hf factor drops further- all the way down to 0.606 for 207 bar design pressure (gas pipelines with MAWP in excess of 150 bar exist in many places in the world).  And for harder steels- X80 for instance with its 80 ksi yield strength, ASME B31.12 requires an even further de-rating via an even lower Hf factor. There are also exposure factors which differ between B31.8 for gas pipelines and B31.12 for hydrogen pipelines, which, combined in the worst case with the Hf factor for high pressure high yield strength pipe material, can reduce the safe allowable working pressure of a gas pipeline to as little as 1/3 the design pressure it previously had for carrying fossil gas.    

The consequences of reducing design pressure are reduced operating pressure, which drops the useful capacity of the line to deliver energy to its customers, or reduces the energy efficiency by greatly increasing the energy consumption of compressors used to push the gas through the line at a now un-economic velocity.  The latter option is not just a waste of energy, albeit a fairly small amount of energy relative to the amount being delivered, it also represents extra cost for the installation of larger, more powerful, and also more frequent, compressor stations along the pipeline.

https://www.linkedin.com/pulse/reduced-pipeline-pressure-eats-energy-paul-martin-8n3zc

You’ll also note that they say that for larger lines of higher yield strength steels, pressure fluctuations need to be kept within 10%…and at 10% pressure fluctuation maximum, such a pipe would have near zero “line pack” i.e. it could store no meaningful amount of hydrogen useful to keep downstream users operating if supplies were interrupted.  Keeping the line within these limits would basically drop the capacity of the line dramatically, because any major user would be unable to turn on or off suddenly (when a turbine tripped for instance) without inducing an excessive pressure fluctuation unless they were drawing a very minor fraction of the gas flowing in that pipeline. 

The report goes on to say:

“Steels with a yield strength Re ≥ 415 N/mm2, tensile strength Rm ≥ 800 N/mm2 and/or a hardness of 22 HRC or 250HB are prone to fatigue crack growth in hydrogen gas applications.”

 They further say,

“. In particular, the DN600 and DN900 pipes show a rapid growth of the depth of the axial crack in the WBZ of the longitudinal seam, for pressure changes of 20 to 30% of the design pressure. In the worst case, fatigue crack growth rates exceed the acceptance criterion of 0.01 mm/cycle (see Figure 5) by a factor of 25.”

They recommend that the pipelines be inspected for fatigue cracks, a pressure fluctuation threshold be set to limit fatigue (in the conclusions they suggest a pressure fluctuation limit of 10%), and then the line should be tested for 1 -2 years with frequent examination to observe fatigue crack growth.  To me, that sounds like an experiment with potentially significant consequences to the public safety, so I’d want to be sure, were I a Dutch citizen, that such an experiment was first given very careful scrutiny by a qualified and disinterested 3rd party whose sole concern was the public safety and wellbeing.  That would go doubly for examination of the experiment and the interpretation of its results.

Comments of George Verberg, former CEO of Gasunie

An article in the Dutch science magazine De Ingenieur, about our work, came to the attention of George Verberg, the former CEO of Gasunie for 12 years.  George was initially convinced by the Hyway27 report’s support for the repurposing of existing gas networks, but our study made George review the previous work with somewhat more skepticism.  I encourage you to read (translating if necessary) his comments here:

https://www.linkedin.com/pulse/dag-li-genoten-die-belangstelling-hebben-voor-h2-en-het-verberg-kdhfe

A few important points that George makes are supported by our work and bear repeating here:

1)      He mentions that the gas network initial working pressure is 66 bar, which would be reduced to 50 bar “initially with hydrogen”.  That is almost exactly consistent with the Hf= 0.776 de-rating per B31.12, i.e. assuming that no other design factors need adjustment.  The required pressure de-rating would be greater in systems outside the Netherlands, where design pressures are higher and stronger, harder pipe materials are used, and where differing design factors are required between the two applicable codes.

2)      He goes on to mention the effect of the greater velocity required to deliver the same amount of heat energy to customers in the form of hydrogen relative to natural gas, combined with the pressure de-rating, would result in considerably reduced practical capacity for the lines.  And that if pressure fluctuations are required to be kept to within 10% to reduce the risk of fatigue cracking, it’s quite clear that the effective line pack would disappear, complicating pipeline operation.

3)       He mentions that the Hyway27 report is inconsistent with regard to discussing the  compressors.  Compressors are long delivery, expensive pieces of equipment, and it’s clear from the Hyway27 report and from numerous other references that replacement, not retrofitting, will be required.  Strangely, the cost of replacing compressors is not accounted for.  Furthermore, although it seems evident that Hyway27 would propose to deliver similar energy flows in the pipes (i.e. at 3x the velocity, to account for hydrogen’s lower heat content per unit volume), the fact that the compressors would necessarily be 3x as large and powerful has not been considered.  In fact when one designs piping, one generally selects a pipesize based on an economic velocity, which optimizes the cost of pipe materials and installation against the cost of compressors and energy to run them.  One doesn’t generally try to shove more gas through a line that is too small by installing bigger compressors.

4)      Hyway27 does conclude that valves need replacement, but George points out that the valve frequency is assumed to be one every 32 km instead of the present one every 7-10 km in the network.  The reduced frequency of isolation valves is in fact the exact opposite to what might be expected from a hazard analysis examining the relative hazards between hydrogen and fossil gas.

George calls for the public release of the Bilfinger Tebodin report, which I fully support.

Lessons to be Learned

Bilfinger Tebodin wrote a carefully worded and, on first review, technically accurate report.  When asked the question, “can the gas network be re-used for pure hydrogen?”, they answered as good engineers should do- not with a yes or no, but with a list of conditions and provisos under which a conclusion of any kind could be drawn, specifically in relation to the particular system they were asked to review.  Unfortunately, we engineers all eventually learn during our careers that our opinions, even when expressed carefully with all the necessary qualifications, can be taken out of context and used to draw broader conclusions than we’d intended. That seems to me to have been quite clearly the case here.  The good engineers answered “Yes, but…” and Gasunie stopped listening after hearing the only thing they wanted to hear- “Yes”.

It’s also very important to examine the references used to support claims – especially when claims are surprising or are of potentially significant public importance.  Readers of Gasunie’s Hyway27 final report may have been satisfied to see a report by a qualified engineering company given as evidence of their statements, but unless that report itself is publicly available, its conclusions and provisos can’t be interrogated- and hence the conclusion must remain suspect.

Finally, industry reports- especially when the industry in question is examining more or less whether they will have a value proposition of any kind in a decarbonized future- need to be taken with an appropriate measure of salt.  My suggestion is that the appropriate measure is rather more like an excavator bucketful than it is to a pinch!

Disclaimer:  this article has been written by a human, not a fluffy “ya-but” rabbit- and humans are known to make mistakes from time to time.  Show me where I’ve gone wrong, with good references (public ones that I can interrogate) and I will be happy to edit my work to correct it.

If, however, your principal objection to my work is that it dumps a pile of rabbit-pellets on your pet idea, i.e. your dreams of a future selling hydrogen rather than fossil methane door to door- then you are encouraged to take it up with my employer, Spitfire Research Inc., who will be very happy to tell you to hop off and write your own article.

Electric Heating- the Future of Industrial Heat

This article is a summary of my series of posts about electric heating:

https://www.linkedin.com/posts/paul-martin-195763b_for-the-next-while-im-going-to-make-periodic-activity-7230286694044852224-ntuR?utm_source=share&utm_medium=member_desktop

https://www.linkedin.com/posts/paul-martin-195763b_post-2-about-electric-heating-residential-activity-7230648442459447299-wdnK?utm_source=share&utm_medium=member_desktop

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Some people have it in their head that there’s no way to make heat other than via fire. The reality is more complex. The reason we use fire to make heat is that not only do we have an 800,000 year history doing just that, but also because if you can find burnable fossils lying about in the earth, and have a free atmosphere into which you can dump the effluent, burning stuff is the cheapest way to make heat- under most circumstances.

 Note that we make heat from electricity today, despite its higher cost, in lots of applications where fire doesn’t do the trick, i.e. fire is ineffective for some reason or another. And in a world where we make electricity largely from heat, i.e. by burning stuff, using electricity to make heat is pretty crazy- it would need to provide a rather huge effectiveness benefit to overcome all the inefficiencies of making a fuel, transmitting it, converting it to heat, then converting that heat to a (much) smaller portion of electricity which is then converted to…heat.

Those basic assumptions have changed though. If you don’t think they have, then please just go away, as you’ll bring nothing to the conversation.

In a decarbonized future we’ll be starting with electricity, largely from wind and solar, but perhaps also from nuclear or out of storage. And in that case, converting electricity partially to something to burn as a way to make heat, is similarly insane. We’ll do that only if we’re both very rich and very desperate.

Residential and Commercial Heating

People in northern climates need to heat their homes. This isn’t for mere “comfort”, it’s a necessity of life.

Most of us still heat with fire here in Ontario, myself included. That’s because historically, gas was so very cheap, especially relative to retail electricity. And most of us consider the resulting GHG emissions to be worrisome- even though residential heating represents shockingly only 5.5% of Canada’s GHG emissions on an annual basis. That’s not because our climate isn’t cold, or because we’re hyper-efficient with our heating. Rather, it’s because we generate vastly greater emissions in other sectors of our economy, especially in transport. That likely surprises people more than it surprised me back in 2019 when I first saw these figures.

I’ve taken the time to update my 2019 article about residential heating electrification, using my own Toronto home and its energy use and costs as the reference case for comparisons.

https://www.linkedin.com/pulse/home-heating-electrification-paul-martin

The 2018-based figures used in my 2019 analysis showed that heating electrification produced quite high costs per tonne of CO2e emissions averted, even taking rather high estimates of methane leakage into consideration at the 20 year global warming potential of 84x CO2. However, my updated analysis using 2022/2023 data indicates that you might even save money if you were smart about using an air-sourced heatpump in Toronto. That’s despite the fact that the 2023 carbon tax rate was only $65 CDN/tonne CO2e on natural gas- it’s $80/tonne in 2024, making the opportunity even more compelling.

The key technology here is heat pumping, which allows us to use electricity as exergy, i.e. thermodynamic work, rather than grinding it up into heat in a resistance heater. Heat pumps allow us to use 1 joule of electricity to pump, on a seasonal basis, perhaps as many as 3 joules of heat from the cold air outside, into our homes- or as many as 5 joules of heat from soil and groundwater if we have the money to afford drilling wells to access that heat. And before the Albertans and Saskquatches jump on me, I’d like to remind readers that 80% of Canadians a) live in urban rather than rural settings, and b) live within 100 miles of the US border. So while it will be harder to justify heat pumping in Edmonton, much less Fort McMurray, relative to warm-ish Toronto, it’s still an option within reach of most Canadians. My brother in Alberta proved that by doing it in his home, and I’m very proud that he beat me to it!

And no, hydrogen as a home or commercial heating strategy, isn’t going to be a thing, regardless how hard the natural gas industry pumps the idea to stay in business- or at least to pretend to have a future post decarbonization.



Industrial Heat Pumping:  Distillation

Somewhere between 40 and 60% of industrial heat is consumed below about 200 C. 

Much of that heat today is produced by burning fuels, often transferred by means of steam.  Steam is generated from combustion and sometimes from waste heat from other processes, just as a means to move heat around conveniently.

My future article about electric heating will provide more detail and some sketches to illustrate things more clearly, but for now, let’s look at a major use of industrial heat:  distillation.

Commercially, most distillations are continuous, not done in batch.  A liquid mixture is fed continuously to the middle of a distillation column, which has trays or packing which allow rising vapour to intimately contact with falling liquid.  A condenser at the top of the column, condenses some or all of the vapour and allows the liquid condensate to flow back down through the packing (referred to as reflux).  A re-boiler at the bottom of the column, generates vapour from the liquid which leaves the bottom of the column.  Compounds in the mixture separate by their “relative volatility”- which depends on lots of stuff, but the most important thing is their relative boiling points.  Higher boiling liquids tend to concentrate in the bottom of the column, and lower boilers near the top.  Liquid products can be taken off the column continuously at any point where the composition is what you want- off the condenser, off the reboiler, or off various points along the column.

Normally, the reboiler is fed a hot medium- steam, a hot liquid, or sometimes, flue gas from fuel burning.  And the condenser is cooled using a cooling medium- cooling water, air, or sometimes, another stream that needs to be heated up.  Nearly every joule fed to the reboiler, comes back out of the condenser- just at a lower temperature.

We can electrify distillation by the simpleminded method where we use a resistance heater in place of the reboiler, but that would be wasteful. 

We could instead use a normal refrigerant heat pump to pump heat from the condenser, back into the reboiler.  The smaller the temperature difference between the reboiler and the condenser, the easier it would be to pump heat from the condenser back to the reboiler, and the higher the coefficient of performance (the less electricity we’d need to pump the required amount of heat).

But if we are permitted, we could instead simply take the vapour off the top of the column and feed it to a compressor directly.  The vapour would leave the compressor “superheated”, and would enter the tubes of the reboiler where it would condense at a higher pressure, providing heat to boil the fluid in the reboiler.  This scheme, called “mechanical vapour recompression”, uses the process vapour as the refrigerant, which not only improves the coefficient of performance, but also eliminates at least one heat exchanger entirely.  There’s no separate condenser and reboiler any more- one unit does both jobs. A small liquid subcooler might be required to prevent the reflux or distillate from flashing as it exits the reflux drum, but this would have a very small duty relative to what the condenser previously had.

Medium Temperature Industrial Heating- 200 to 800 C – Resistance Heaters

A smaller fraction of industrial heating requires heat at higher temperatures, above 200 C, where heat pumping schemes are presently impractical.  These are harder to afford, because none of the approaches feasible in this temperature range are capable of converting 1 joule of electricity into more than 1 joule of the required heat.  Burning up pure exergy (electricity) to make heat is of course dead easy to do technically, but not easy to afford!

The conventional approach within this temperature range is to use resistance heaters, which are as simple as they sound:  electrical resistors which heat up when you pass a current through them.

In practice, resistance heaters for temperatures below 800 C (and in fact for temperatures above this range under certain conditions) all look more or less the same:  they consist of a coil of resistance wire made out of a high temperature metal alloy.  That coil of wire is either immersed directly in air or another gas (examples:  a hair dryer or toaster, or a ceramic kiln), or it is protected from the thing it’s heating by a sheath.

Bare wire heaters have the advantage of direct contact with the thing being heated, if that thing is a gas.  They can be very cheap indeed.  They can also be heated to very high temperature such that their heat transfer is via radiation (infrared light) more than convection- that’s what’s largely happening in your toaster for instance.  They also have the distinct disadvantage of…direct contact with the thing being heated.  This can lead to:

  • Corrosion, causing the wire to get thinner and hence higher in resistance, which causes it to get thinner…leading to an autocatalytic failure
  • Deposits may form on the wire, which can insulate the wire from the thing being heated, allowing the wire’s local temperature to rise high enough to cause a mechanical and then an electrical failure of the wire
  • Decomposition of the thing flowing by the wire, if it isn’t totally inert to the wire material, or if it is sensitive to over-temperature.  This can cause product degradation

They also suffer from very low surface area as you can imagine.   Since heat flow is proportional to the area of the hot thing, higher temperatures are required for a small thing to emit the same heat as a large thing.  Longer wires are therefore required if you want the wire temperature to be kept low- or, if you’re at such a high temperature already that any higher temperature will cause the wire to rapidly sag (creep) and fail.

They also obviously cannot be used to heat media that are themselves conductive to electricity- otherwise, the thing carrying the current will not be the wire, but the thing you’re trying to heat…Sometimes, this approach, called “ohmic heating”, i.e. passing the current directly through the thing you want to heat up, is used- but we’ll talk about that in another article.

 Immersion Heaters

In my previous post, I talked about bare wire heaters such as those used in a ceramic kiln or a toaster.  In this post I’ll talk about immersion heaters, which are the workhorse of electric heating in the process industry.

Every chemical engineer is familiar with the shell and tube heat exchanger.  A fluid, hot or cold, flows through a number of tubes that pass through a shell through which another fluid flows.  Heat is transferred through the tubes to the fluid in the shell, or vice versa.  There are numerous arrangements of S&T exchangers, each best suited to a particular set of use cases.

In principle, an electric immersion heater is just a shell and tube heat exchanger whose tubes have electrons rather than a hot fluid flowing through them.  The tubes heat up, and fluid passing by the tubes in the shell, receive this heat by convection and radiation.

Each tube consists of a wire heater inserted into a tube which is then packed generally with  magnesium oxide, which has the properties of inertness and decent thermal conductivity while having low electrical conductivity even at very high temperatures. 

The tube is generally then bent into a U shape like a hairpin, so that both ends of the wire (where the electrical connections are made) are at one end of the assembly.  The U shaped tubes are inserted through a flange to which they are either welded or brazed.   Heaters can have one or thousands of such Us on a common flange.  The result is that we now have basically a “BEU” heat exchanger bundle, except the bonnet is where the electrical connections are made.

The elements are then wired in the bonnet with bus bars, in combinations of series and parallel, to provide the required resistance at the supplied voltage to obtain the necessary heating power.

Each flanged heater is inserted into the end of a shell.  Generally, either one or two flanged heaters are used per shell. 

Unlike with S&T heat exchangers, there aren’t generally baffles along the tube bundle.  Flow through the shell is therefore not serpentine, but annular.  Why are baffles not used?  Because they tend to accumulate deposits or serve as corrosion initiation points, and lead to premature failure.

You can see the advantages of the approach:

  • The wires are protected from the flowing fluid by a metal tube, which can be made of whatever alloy is resistant to the flowing fluid
  • The wire is supported by the MgO insulation, so it can’t sag
  • The flange and tubes are designed for whatever pressure you need- we’ve had heaters made up to 2500# flange class

The major disadvantage of course is that now the wire has to get hot enough to heat the MgO sufficiently to heat the tube to the temperature needed to transfer the required heat.  And if your process temperature is very high, you might soon exceed the limits of the wire, even well supported by the MgO.

We’ve had immersion heaters of this design, built to heat gases up to 850 C continuously, and they have provided excellent service- because we knew what we were doing in designing, controlling and operating the system.  But at those temperatures, nobody can guarantee how long such a heater will last.  Failure is only a matter of time, though there is much you can do to prolong their life.

Very High Temperatures

As an engineer who spent most of his career designing equipment to push the limits of chemical process technology, one thing that I couldn’t miss is the fact that the safe allowable stress values for all metallic materials and alloys, basically drop off a cliff around 800 C, limiting their ability to be used to support things or resist pressure.  The reason for this is “creep”, the tendency of alloys to change their shape over time even under small amounts of stress.

We contend with this problem in industry in several ways.  One is to manipulate conditions so that the mean temperature of the metal is kept to a reasonable level by playing games with heat transfer resistances.  This is how an ordinary steel tube can be kept safe in a heat recovery steam generator, when one face of the tube is exposed to very hot gas or even to a flame. 

Another is to keep the supporting metal cool by using a refractory material on the hot side.  The refractory can be “hard”, to resist erosion and other wear and tear, or “insulating”, or a compromise. The cold side must remain exposed or in some cases, must be actively cooled.  

And a third, when we need to transfer heat at very high temperatures, is to use tubes made of superalloys and just realize that they will eventually fail due to creep and need replacement.  That’s the strategy used in steam reformers, where the tubes operate at temperatures well beyond the limits of the normal design codes for pressure equipment.  Failing tubes are literally pinched off inside the furnace while the unit continues to operate.

A key limiting factor for electric heating therefore is the strength of materials at high temperatures.  And there are several solutions:

  1. Use superalloys:  FeCrAl alloys (i.e. tradename Kanthal) are king here, but they are difficult to fabricate.  They are among the best, most durable choices for heating wires used inside heating elements, but it’s tough to make a whole heat exchanger out of FeCrAl
  2. Use refractory metals:  molybdenum is the frequently reached for material here, but it too has serious issues other than just its cost.  The elements, after the first heating, become brittle
  3. Use nonmetals:  heating elements can be made of silicon carbide, molybdenum disilicide, graphite and other nonmetallic materials.  Each of these has its own upper temperature limit, and a set of conditions which kill them

The last option is to switch to another method of electric heating- the subject of future posts.

Other Kinds of Electric Heating

I could write a book on the subject of electric heating, based on my couple decades of doing it for pilot and demonstration scale plants of all sorts.  But even I rarely read books any more, because by the time they’re published, things have already changed!  So if you really want my advice about these issues, you are best advised to visit www.spitfireresearch.com and find out about my consulting services.

We’ve talked about heat pumping and resistive heating at some length.  Now I’ll gloss over a number of other ways to use electricity to heat stuff, spread over a couple posts.

Induction:  conductive things like metals and graphite can be heated by inducing eddy current flow in them using a varying magnetic field.  This is commonly done to rapidly heat piece of metal to temperatures suitable for forging, for instance, but it can be applied to heating all sorts of things.  It has become a very popular replacement for gas for cooking, where it is greatly more energy efficient and lower in emissions.   There are some losses, because the conductor producing the magnetic field has its own ohmic losses and these need to be removed (often via cooling water)  The switchgear needed to generate the induction current also represents some losses- moreso than in resistive heaters.

Microwave and RF Heating:  microwaves and radio-frequency radiation can be used to excite certain molecules or parts thereof directly- particularly stretches and rotations of O-H bonds in water, sugars and the like, resulting in heat generation.  Heat transfer is therefore not from the surface inward, but from some depth both inward and outward, the depth depending on how strongly the radiation is absorbed.  It is sometimes possible to accomplish the desired result (a chemical transformation, drying etc.) without heating the bulk of the material to the same uniformly high temperature, resulting in very real energy savings relative to convective or conductive heating. 

Microwaves are fairly inefficient as electric heating goes, with about 20% of the fed energy being lost as heat in the apparatus.  Microwave emitters are also limited in maximum power to around 100 kW, requiring “numbering up” of smaller apparatus which can be a real drag on economics at scale.

Mechanical Heating:  viscous materials such as plastics, which have poor thermal conductivity and a limited maximum temperature making resistive heating a real problem, are frequently heated by vigorous mixing using an extruder.  In this case, work done on the material becomes frictional heat delivered to the bulk of the material.  That seems insane at first blush- producing heat by friction!  But remember, we’re starting here with work– converting it to heat in a resistor is no less crazy.

There are other methods of producing heat, sometimes of very high temperature, by doing work on a gas, producing shock waves etc.  These are so far experimental without full-scale demonstrations as far as I’m aware, but they may be useful for some gas-phase reactions currently heated using tubes in furnaces.

Replacing Fire

 The really hard applications for electric heating are applications where heat transfer through a conductive heat transfer surface won’t do the job.  That can happen because the conductive materials we might want to use are not strong enough at the high temperatures required.  An example is the interior of a cement clinkering kiln.  There, we use a rotating steel tube which is lined inside with refractory bricks, and we put a giant radiative fire in the centre.  Heat is transferred from the fire to the solids by radiation, from the flue gas to the solid by convection, and from the fire to the bricks above the solid which are then rotated into contact with the solid.  Such a flame needs to be powerfully radiant though, so hydrogen’s a poor choice.  In fact even gas isn’t perfect- glowing particles of burning coal dust are the best.

Fortunately, we aren’t out of tools in the electric heating toolbag.

We can in fact make “flames” with electricity and just about any gas, including air.  Flames are just chemically heated plasma- a soup of ions and electrons- which radiate light (from UV to IR inclusive, depending on temperature). We use electrically heated plasmas to weld, to cut metal, and to heat gases to very high temperatures.  Plasma arcs are complicated- they can be “cold” (i.e. corona discharge, used to make ozone from oxygen) or “thermal”.  They can be struck between electrodes, or generated (under vacuum) by microwave excitation etc. They can be steered and focused by magnetic fields.  They can be excited by AC or DC currents.  And the gas they turn into a plasma can be air, or it can be vapour from the electrodes or the thing being heated. 

Temperatures of 30,000 C can be achieved.  But of course many things determine whether or not a plasma arc is a practical way to heat your particular thing.   Very many, complex things…far beyond our scope here.

A example is the electric arc furnace (EAF).  About 70% of steel in the USA is made using EAFs.  A charge of scrap mixed with some fresh iron is fed into a refractory lined ladle, into which huge carbon electrodes are fed.  The electrodes carry current which contacts the scrap and heats it by resistance heating, but there is also a plasma arc struck between the electrodes and the steel- and each other.  The electrodes evaporate and react with water and oxygen which might be present in the scrap, so they are continuously consumed.  CO2 emissions therefore occur- but some of the carbon also ends up where it’s needed, in the iron, to make steel.  There are other applications of arc melting, including melting ceramics or steelmaking slag to spin ceramic fibres.

Finally, direct ohmic heating is sometimes possible under conditions that you wouldn’t at first think possible.  Molten glass, for instance, has sufficient ion mobility that it is electrically conductive.  Molybdenum electrodes inserted into the molten glass can be excited with AC currents to heat the molten glass to the required temperature for forming.  Ohmic heating doesn’t consume the electrodes- at least not so quickly that they need to be continuously fed- and doesn’t involve a plasma arc.

Electric Heating:  Final Thoughts

It’s clear that most people still have a burner box on their heads about electric heating particularly in industrial applications, which is no surprise as we humans have been burning stuff to make heat for about the past 800,000 years.

Let’s be clear:  with precious few exceptions, this isn’t about a lack of a technology, or a need for fire.  It’s about a lack of economic drivers- durable carbon taxes and emission bans.  Without those, fire is just cheaper, and electric heating is used only where it provides greater effectiveness, i.e. convenience or cleanliness or ease of control.  That’s electric heating today, in a nutshell. But that is not electric heating’s future!

It’s clear that residential and commercial heating is transitioning to heat pumps.  Whether hybrid heat pumps with a supplementary fuel source for the very coldest days are worth thinking about, depends on how cold it is where you live, and how clean your grid might be.

Industrial heating below 200 C, where most industrial heat joules are actually used, is similarly going to heat pumps- but the heat source won’t be ambient air or groundwater.  It’ll be waste heat from inside these facilities.  Two birds with one stone- this not only cuts GHG and toxic emissions from fuel combustion, but also greatly reduce waste heat emissions to rivers and lakes, and freshwater loss through evaporation in cooing towers.  We can stretch this to 300 C if we try hard enough!  And yes, you CAN make steam with a heatpump- if your cold reservoir is hot enough.

Conventional heat recovery schemes rely on taking heat from fire and letting it trickle down the temperature range, passing from stream to stream on the way down.  We’ll keep doing that for temperatures above 300 C, and will be encouraged to do more of it as the cost per joule of heat increases- as a switch away from fire to resistance or other high temperature heaters will necessarily do.   In the future, below about 300 C, we’ll likely recycle a lot more heat via heat pumping, which will stand current heat recovery practice on its head.

Higher temperature heating is economically harder because efficiency is “only” about 100%.  But we have lots of tools in our toolbox for industrial uses, even to temperatures simply impossible with fire.

We know how to heat stuff with electricity.  The only question is, will we be smart enough to do so?

Finally:  Hydrogen For Industrial Heating

There are a few places in industry where flames and/or hot flue gas are really needed.  While hydrogen might be an option for some of these applications, the lack of a radiant flame, the tendency of hydrogen combustion in air to make NOx (just as burning  anything else in air does), and the cost of hydrogen derived from electricity, make this an unlikely choice.  Biogas methane makes more sense, as do some other biofuels.  Most of the thinking around hydrogen as a natural gas replacement are just simpleminded fuel substitution thinking- the thermodynamic equivalent of “let them eat cake”.  And no, hydrogen blending into the natural gas network, isn’t going to be a thing either.  This article’s title is rude, but that’s for a reason- the idea really is bollocks.

https://www.linkedin.com/pulse/why-hydrogen-blending-gas-network-bollocks-paul-martin-i5sdc

Disclaimer: This article was written by a human, and humans are known to make mistakes from time to time.  If you find an error in what I’ve written, and can demonstrate that with good references, please make a comment and I’ll be happy to correct my work.

If however you don’t like what I’ve written because it takes a dump on your pet idea- hydrogen for heating for instance- then I encourage you to contact my employer, Spitfire Research Inc., which will be happy to tell you to piss off and write your own article.

Home Heating-Electrification?

UPDATE 17/08/2024:  major updated costs and analysis

Warning: this article contains a lot of numbers. Numbers that tell a story. If you don’t like numbers, stop reading and spare yourself arithmetic anxiety.

It should not be news to you that people in Canada need to heat their homes. Some of us also need air conditioning if we want to be able to sleep in hot, humid July and August.

Home heating- emissions from residential combustion sources, resulted in 41 MT of CO2 equivalent emissions in 2017, or about 5.5% of Canada’s national GHG emissions. (2022 figures were 39 MT and still about 5.5% of total CO2e).  In contrast, road transport represented 132 MT- about 17.5% of total GHG emissions (2022: 120 MT, about 17% of total). Public electricity and heat production, lumped together, are larger at 79 MT (2022:  56 MT). Oil and gas production and refining are larger still at 124 MT (2022:  123 MT). Home heating is actually a surprisingly small fraction of our national and per capita emissions, given our cold climate. Figures are from Table ES-2 in this reference:

https://www.canada.ca/en/environment-climate-change/services/climate-change/greenhouse-gas-emissions/sources-sinks-executive-summary-2019.html

(updated figures are from the 2024 executive summary which has figures for 2022.  Note, the basis of comparison in some cases seems to have shifted between the two dates.  Note also that fugitive emissions from fossil fuel production aren’t attributed to fossil fuel uses, but are listed as their own category likely because Canada is a major fossil energy exporter.  Attributing all those emissions to our own consumption would be an error, as would ignoring them entirely, but splitting them equitably is also troublesome so it appears that MECC chose not to even try.)

About 75% of Canadians- those of us living in Ontario, Quebec, Manitoba and British Columbia for instance- have access to an electrical grid which is extremely low in CO2 emissions. Ontario is highest in that group with 40 g CO2/kWh on average (the actual figure in 2018 was about 25 g CO2e/kWh for Ontario). All of those GHG emissions comes from the 6% of our grid power produced using natural gas. We burned our last coal for power in 2013. (2024 update:  our natural gas use is climbing in Ontario.  It represented 12.8% of our kWh in 2023.  Our grid intensity however is still only about 45 g CO2e/kWh, as the figure I used for 2018 was a high estimate.  https://www.ieso.ca/Learn/Ontario-Electricity-Grid/Supply-Mix-and-Generation). It’s an enviable situation that much of the world can only dream of achieving decades from now.

Most Canadians, who live in major or secondary urban centres, also have access to the natural gas distribution system. And those who do, almost exclusively use natural gas to heat their homes through long Canadian winters.

Why? One reason: price. Natural gas is, and has long been, the cheapest source of heat available to homeowners- as long as they are in a city or town on the natural gas grid.

Those who don’t- people who live in rural locations or a few provinces without natural gas distribution- have four choices: wood or wood pellets, propane, fuel oil or electricity. Wood is often used as either a primary or supplementary heat source in rural locations or for cottages and hunting camps, with back-up often provided by electric resistance baseboard heaters. Rural homeowners are otherwise left with expensive options: propane sells at a premium to natural gas, oil tends to be used only in very old houses which haven’t had their heating systems retrofitted yet, and although electrical resistance heaters are 100% efficient at converting work (electricity) to heat, they are very expensive to operate.

So natural gas heating is king in Canada. My own home is heated with a modulating condensing boiler with an annual fuel utilization efficiency (AFUE) of about 94%. . My domestic hot water is similarly produced by a flow-through modulating condensing water heater with an AFUE of 98%. AFUE is a measure of how much of the chemical potential energy of a fuel, measured by its HIGHER heating value (HHV), is converted into useful heat in the home. High AFUE appliances not only extract the heat from the combustion product gases, but also extract heat by condensing the water produced by combustion.

Natural gas is very cheap per unit of chemical potential energy. One cubic metre of natural gas has a typical HHV of 37 MJ – for comparison, that’s about 10.3 kWh. But it is important not to confuse heat energy (which the HHV of natural gas represents) with thermodynamic work- which electricity can be readily converted to, but heat cannot without very significant losses.

https://www.linkedin.com/pulse/primary-energy-fallacy-committest-thou-2nd-sin-paul-martin-nty3e

My house used 2677 m3 of natural gas in 2018, which cost including taxes $1184 CDN, or $0.42 per m3.  (2023:  2328 m3 costing $1580, or $0.69 per m3, including the carbon tax and HST and all fees) Of that, $271 were account fees and taxes on those fees, rather than the marginal cost of extra gas and its delivery.

Fed into my 94% AFUE boiler, that’s about 4.3 cents/kWh worth of useful heat, i.e. when compared to using electricity fed to an electric resistance heater which is 100% efficient (2023:  about 7 cents/kWh of heat delivered into the home.  For reference, that’s $19.40/GJ or $20.50/MMBTU- retail gas is a lot more expensive than wholesale gas.  For reference, the Gulf Coast Henry Hub price for wholesale gas was about $3 USD or $4 CDN/MMBTU.  Those who confuse wholesale with distributed retail prices- and that happens frequently for instance when people foolishly consider wasting hydrogen as a fuel- really do us all a great disservice!).

To look at it another way, for every m3 of gas I burn in my boiler, I get about 9.7 kWh worth of useful heat in my house. The average cost of electricity for us in 2018 in contrast was about 17 cents per kWh (2023:  15.5 cents per kWh, because in May 2023 we bought our Tesla Model Y and signed up for the ultra-low overnight rate program.  This program drops the cost per kWh to 2.8 cents plus 2.6 cents delivery, taxes and fees charged per kWh, between 11pm and 7am, i.e. 6.2 cents per additional kWh consumed in total).

In GHG emissions terms, combustion and upstream/transmission energy use result in emissions of about 1.9 kg CO2/m3. That means for every kWh of heat my 94% boiler puts into my house, carbon emissions are about 0.2 kg or 195 g. In comparison, Ontario’s electricity CO2 generation is about 40 g total per kWh. In direct CO2 emissions from source, that’s about 4.9 times what I’d emit from my house if I used electric resistance heaters instead.

If we were to add estimates of methane leakage in production and distribution per my other paper:

https://www.linkedin.com/pulse/natural-gas-better-than-coal-paul-martin

-of 2.5 to 5% of the methane fed, using the 20 yr 84x factor for methane’s GHG equivalence to CO2, that would increase my heating plant’s GHG emissions from 195 g of actual fossil CO2 emitted to between 343 and 491 g of CO2 equivalent per kWh. That’s between 8.6 and 12.3 times as much total CO2 (equiv) on the 20 yr time horizon as if I heated with electric resistance heaters. Environment Canada estimates fugitive emissions of GHGs from oil and natural gas production to be about 54 MT- more than the amount produced by all residential heating combined. They no doubt use the 100 yr 33x factor for methane vs CO2 in this estimate.

The house used 2677 m3 of natural gas last year. That’s all heating, domestic hot water and our cooktop and oven, but not the clothes dryer which is electric. My CO2 emissions were therefore 5.06 T of direct or 8.9 to 12.7 T of total CO2(equiv) including the 2.5 to 5% methane leakage factor. $1124 per year to meet all the heating needs of a roughly 2400 sq ft 2 storey house and a family of four. It’s a relatively efficient house, about half renovated 1920s and half modern, well-insulated addition with careful detailing. Better than average, not best in class.

For comparison, I commute 4 days per week, 122 km total per day. (2023:  ZERO- I no longer commute at all for work- yay!  My driving emissions related to work transport are now near zero as I meet with almost all of my consulting clients via teleconferencing).  My commute in my 5L/100 km Prius C amounts to some 3.4 T of CO2 emissions from source, plus the associated toxic emissions breathed by the people I drive by on my way to and from work. That’s for one person to earn a living. A substantial fraction of the direct GHG emissions to keep a family of four warm through a Canadian winter, despite this being the most efficient IC engine car you can currently buy in Canada that doesn’t also have a plug. (Sure- I could move closer to work- but my options there are putting my wife out of HER career, and also quite likely a divorce. Not a practical option I’m afraid!)

Also in comparison, we have high speed internet, a VoIP home phone plan, and three cellphone plans, all modest and none with cellular data. Telecom services cost our family a total of $1650 per year. Yes, telecom services are expensive in Canada due to lack of competition and low population density. But we pay about 1.4 times as much for telecommunications as we pay to heat our house, in part because in 2018 we paid nothing to dump CO2 and methane to the atmosphere. Is that a correct statement of our relative values?

Recently, Canada’s federal government implemented a minimum carbon tax standard for the country. Ontario had a working cap and trade system with Quebec and California, but our provincial government elected about a year ago, spent hundreds of millions to destroy that working system- only to have it replaced by the federal government’s tax. The tax, per my most recent bill, was 3.91 cents per m3, or $20 per tonne of direct CO2 emissions ($8.50 per tonne of total 20 yr equivalent emissions at the 5% leakage figure). That would have increased my 2018 bills by $105, or nearly 10%. (2023 update:  $0.11/m3 carbon tax, $85/tonne CO2, which increased my bills by $266)

My average electricity use costs me 17 cents per kWh- that’s the total of my 2018 bills divided by my home’s total kWh consumption. (2023 update: the average is now 15.5 cents as noted above)

Electricity in Ontario has time of use rates, so electricity is cheaper at night than during peak hours during the day. But if I were to use my average cost per kWh to run resistance heaters, my heating bill would have been $4420 last year (2023:  a little less than that, using the 2023 average cost including fees and taxes). My CO2 emissions would have dropped to about 1 tonne. That’s a $3300/yr increase in cost, to save 4 tonnes of real or up to 11.7 tonnes of CO2 equivalent emissions. A cost of between $820 and $280 per T of emissions averted.

Needless to say, we’d have noticed that extra cost- if we were to increase our heating costs by a factor of almost four!

(2024 update:  per the 2023 costs for gas and electricity we paid, the premium would still be considerable.  However, if we were strategic about the use of electric heating only between 11pm and 7am, we could save at least a small amount of money due to the ultralow overnight rates.  Electricity during that time range costs us only 2.8 cents per kWh plus 2.6 cents for delivery and regulatory fees, plus taxes, for a total of about 6.1 cents per kWh in marginal terms (i.e. for new kWh added, assuming that our existing uses of electricity bear the cost of the rest of the bill)- and then only between 11pm and 7am.  In marginal terms, that 6.1 cent/kWh fee is less than the ~7 cents per kWh we paid for gas including carbon tax and HST- but again, that is a bit of an apples to oranges comparison, because the cost of gas includes fees and taxes.  But when you add a heatpump…well, see below!)

Of course there are alternatives to resistance heaters! A heat pump can use work (electricity) to pump heat from a cold place (the air, or the subsurface). Air source heatpumps became briefly popular in Canada after the 1973 energy crisis, but fell rapidly out of favour again due to the poor durability and performance of the first generation units in extremely cold weather. Modern air-source heat pumps can generate a coefficient of performance (COP) of up to 2 at temperatures as low as -20 C. It rarely gets colder than -20 C in Toronto or Vancouver, but does in places like Calgary, Edmonton, Regina and even Montreal. Air source heat pumps are a modest cost increase over air conditioners, which happen to also be basically necessary in the warmer parts of Canada due to hot, humid summers.

Small Mitsubishi air source heat pump units deliver their full heating load at 21 C return air temperature and outdoor temperatures of -15 C. Coefficients of performance- the kW of heat pumped into the interior per kW of power used- range from about 1.5 at -25 C outdoor to about 3.4 at 5 C outdoor. An air-sourced heat pump unit returning a COP of 2.2 would have reduced my electric heating cost to $2010/yr. if I were to go all electric- again this is an approximation because the HP system wouldn’t heat my domestic hot water or fire my cooktop or oven. That is still almost twice what I paid for natural gas last year. There is therefore no payback to be had from installing an air-source heat pump, until carbon taxes become very substantial indeed.

2024 update:  amazing how things change, so quickly!  If we were to strategically use an air source heat pump just between 11pm and 7am, the ultralow overnight electricity rates combined with a coefficient of performance of more than 2.2- the seasonal average is definitely higher than that for a good heatpump- would definitely save us operating cost year round- not just in the “shoulder seasons” where we likely wouldn’t need the gas unit at all.  If we look at the marginal electricity price of 6.2 cents/kWh between 11pm and 7am, and apply a COP of 2.2, we’d effectively be paying only 2.8 cents per kWh for heat delivered into our home- that’s already way cheaper than gas.    Even using the entire average cost of electricity we currently pay (15.5 cents per kWh), ignoring the fact that we’d need heat more at night than during the day even in mid winter- 15.5/2.2 is itself even a little cheaper than gas! 

Since we would be smart about using the heatpump, and we would also keep our gas boiler as a backup system, a payback on a bidirectional air source heatpump to replace our existing air conditioning unit, just jumped up on the priority list of home investment tasks.  It’s still down well below replacing the garage roof- that’s happening this fall.  And as to the payback period…well, that depends on how long you figure our existing air conditioner system would last if we didn’t replace it, and whether or not we add a 2nd heatpump system to increase comfort as our house is currently only air conditioned on the top floor.

Another alternative is ground sourced heat pumps. In urban areas, groundsource heat pumps require vertical wells to be drilled as there is insufficient land for heat collection trenches to be effective. Drilling costs vary, as do the cost of the equipment and installation, but it is clear that the costs of a groundsource heat pump system are many times the cost of a conventional furnace and air conditioner which they replace. Ground source systems can have coefficients of performance ranging from 2.5 to 5 for heating, with the bonus being that the COPs for cooling are very high indeed- air conditioning basically becomes “free”.

As a best case, assuming a system with a heating COP of 5, my electric heating costs would drop to $882 per year, a savings of $241 per year versus my current cost for natural gas heating.  But $241 per year would never pay back the extra cost of that GSHP system. Real savings would be modestly larger because it would drop my cost for air conditioning. A rough estimate is that we spent a whopping $95 on air conditioning in 2018 as best I can estimate, by comparing our June, July, August and September electricity bills against our May and October bills- so not much to be saved there.

(2024 update:  no real change here.  Groundsource represents a huge increase in capex, and we have no plans to live in this house long enough to make it even worth considering)

Significant carbon taxes would be required to make this investment make economic sense to someone whose primary interest was saving money rather than the planet. And frankly, if we’re honest, our actions and decisions reveal that most of us don’t care much about either: we care far more about our own comfort and convenience.

Perhaps this analysis explains why my focus has been on the electrification of transport, rather than on heating. Savings in operational GHG emissions of 97% (94% relative to our Prius) and a halving of daily operating costs can be achieved simply by switching from IC engine to battery electric cars and light trucks. (2024 update:  whoa, that was an under-estimate!  Our model Y is currently costing us about $0.91/100 km to recharge on the ultralow overnight rates, including taxes.  That’s relative to a current cost for driving our Prius C, the most efficient gasoline car you can buy here without a plug, of $8.50/100 km (5 L/100 km, $1.70/L for gasoline retail.  We only use superchargers for about 8% of our kWh so far, so their cost (less than 10x what our home charging costs) is really irrelevant to us.  That’s almost a factor of ten reduction in operating cost, not a factor of two!)  The electrification of light personal transport is some of the lowest hanging fruit in the battle against global warming in my opinion. Heating, on the other hand, will definitely have to wait.

2024 update:  electric heating is, as noted, looking much more promising in Ontario due to the ultralow overnight rate program.  But of course such programs don’t exist everywhere!

Why do we have such a program?  Because nuclear and hydropower together make up over 78% of our electricity supply (2023 figure)- and these meet substantially all of our power needs at night.  Because most of Ontario’s hydropower is “run of river”, which is “use it or lose it”, rather than hydropower derived from dams which can store water and deliver power only during peak periods, hydro and nuclear in Ontario are very similar in that both of these power sources cost the same, more or less, whether you use the power or not.  In past we sold this power at a discount to nearby US states- but a wise piece of public policy now offers this power to ratepayers who choose to sign up for it. What you get in return is a very much higher rate between 4 and 9pm, Monday through Friday, when gas peakers are at the margin.  In our home we avoid using electricity during this time period, by for instance avoiding doing laundry, washing dishes, using the air conditioner or charging our EVs.  But if we heated the house electrically, that would be a harder ask in terms of comfort.

Disclaimer:  this article was written by a human, and humans are known to make mistakes from time to time.  Show me where I’ve gone wrong, with good references, and I’ll be happy to correct my mistake.

If however you don’t like what I’ve written because it takes a dump on your pet idea, then please contact my employer, Spitfire Research Inc., who will be happy to tell you to piss off and write your own article.

Ammonia- “Ship of Fuels”? or Fuel of Fools?

image credit: Microsoft Create

TL&DR:  ammonia is a toxic and corrosive gas, and using it as a fuel aboard ships fails the 1st principle of safety in design.  It is an insane idea, and those pushing this toxic idea should give their heads a serious shaking.

I am a chemical engineer with many decades of experience handling chemicals.  I’ve safely handled chemicals both in the laboratory and industrially, which sometimes made ammonia look like mother’s milk.  I have a healthy respect for chemicals, but I am not a chemophobe.  Even in light of that experience, the notion of using ammonia, an extremely toxic and corrosive gas, as a fuel- especially aboard ships- absolutely terrifies me.  And that fear is, in my opinion as a chemical engineer,  a very reasonable response to very real danger.

Ammonia is an extremely important commodity chemical.  It is not only the base of the entire nitrogen chemicals industry, but also the key technology which enables roughly half the humans and their food animals currently on earth, to be fed in the style and at the cost to which they’ve become accustomed.  We humans are only a small fraction of the carbon cycle on earth, though our continuous addition of fossil carbon to the atmosphere is already altering the climate.  But as far as the nitrogen cycle is concerned, we humans are already responsible for 50% of it by way of making ammonia and molecules like nitrates and urea that we make from ammonia.  About fifty percent of the nitrogen atoms in the proteins in our bodies, were human-produced ammonia at some time in the recent past.

https://www.linkedin.com/pulse/ammonia-pneumonia-paul-martin

Ammonia is also an extremely poisonous and corrosive gas.  Ammonia dissolves readily in water, breaking it apart in the process to form hydroxide ion (OH-) and ammonium ion (NH4+).  While we’ve all had experience with dilute ammonia used as a household cleaner, most of us haven’t played around with concentrated ammonium hydroxide.  I certainly have.  It is nearly as strong a base as sodium hydroxide (caustic soda or “lye”) that you might be familiar with.  And strong bases are very damaging to human tissues because they cause them to hydrolyze, i.e. to react with water and fall apart (hydro-lysis- breaking apart something with water).

Of course it doesn’t matter where the water is- the reaction is the same.  So if that water happens to be deep in your lung tissues, your eyes, nose, throat, ears…you get the picture, and that picture is horrifying.  It causes pulmonary edema- your lungs fill up with fluid (your own body fluids) and you start to drown.  It will turn your fatty tissues (including the lipid bilayers of your cells) into soap, hydrolyze and dehydrate your proteins, and cause your various body tissues exposed to it, to die.  There is no antidote that will reverse this for you after exposure.  Though victims exposed to small amounts of anhydrous ammonia definitely can survive, even short acute exposures can lead to permanent loss of lung function.

Ammonia is also a very potent environmental toxicant.  50% of certain aquatic organisms are killed by as little as 0.5 milligrams per litre (ppm) of ammonia.  Ammonia also reacts with other toxic species  in the atmosphere such as SOx and NOx (products of fuel combustion, the latter also formed by the combustion of ammonia or hydrogen in air) to produce ultra-small aerosols or particulate solids containing ammonium ion that are harmful to the lungs.  While ammonia itself is fairly rapidly scrubbed out of the atmosphere by rain and snow, ammonium ion aerosols can travel much longer distances, leading to transborder pollution.  Ammonia itself is a regulated air pollutant.

https://www.apis.ac.uk/overview/pollutants/overview_nh3.htm

Ammonia is also flammable.  It burns with difficulty and has a narrow range of concentrations in air where it is flammable.  While it does represent a fire/explosion risk, its toxic risks are much greater- rather like other flammable but toxic gases like H2S and carbon monoxide.

Ammonia, with a molecular weight of 17 g/mol, is less dense than air (with a molecular weight average of 29 g/mol)- but that’s only true if the ammonia and air are at the same temperature.  Whether ammonia is stored as a compressed gas or refrigerated liquid, releases during a leakage or pipe rupture event are always  cold, and hence tend to accumulate low to the ground until they spread out and mix with air sufficiently to warm up.  In this way it is very different than the hydrogen it is made from, which is both less dense than air and tends to heat up as it expands, accumulating near ceilings before it diffuses outward and mixes with the air.

Emergency response in the case of an anhydrous ammonia leak therefore has to contend not just with toxic effects, but corrosivity and flammability risks too.  Mere respirators are not sufficient to protect emergency response crews.  Pressurized chemical suits (Level A protection) are required, which must be supplied air from either SCBA tanks or a hose connected to a breathing air blower drawing air from a safe location.  Having worked in such a suit, I can tell you that it is not conducive to either speed of response, productivity, agility, or calm!

Making Ammonia

We make ammonia almost exclusively from hydrogen that we make by reforming of natural gas or coal.  GHG emissions associated with ammonia production are, to a first approximation, about equal to the current emissions from the entire shipping industry.  And a powerful and persistent greenhouse gas, nitrous oxide (N2O), is produced by soil organisms when we add ammonia-derived fertilizers to soils.  Nitrogen fertilizers, when over-applied, can also run off into watercourses, causing eutrophication (the blooming of algae and other species which can turn parts of lakes and even ocean areas like the Gulf of Mexico, anoxic and essentially lifeless).

While we could make ammonia from hydrogen made from water using renewable or low emission electricity, the cost is prohibitive.  Even black ammonia costs more per joule than fossil bunker oil fuels or fossil LNG, and green ammonia costs a multiple of what black ammonia costs.  And no, that’s not likely to change any time soon, either.

Wow, this is a troublesome molecule!  But it’s also an essential one.  A real dichotomy.

The (Simpleminded) Appeal of Ammonia as a Fuel

Ammonia does have several points of (very arguable) appeal, which explain why someone would even think for a moment about its use as a ship’s fuel.

The idea is that the ammonia would be made from electrolytic green hydrogen, made from renewable electricity and water.  And that burning it, whether directly or via first “cracking” it over a catalyst using heat (from somewhere) back into hydrogen and nitrogen, would have low GHG emissions.  There’s no carbon in ammonia itself, you see.  So that’s the big appeal.  Let’s ignore the extreme inefficiency of all those transformations- electricity to hydrogen, hydrogen to ammonia, ammonia transport and storage, and then ammonia in an engine back to mechanical energy- and their associated costs.

Furthermore, there are people imagining that they will have heaps of stranded renewable electricity that can be made in places where nobody who needs electricity lives even within reach of a practical HVDC cable.  And those people know they can’t ship electricity, and have contended with the fact that shipping hydrogen itself is also more or less an economic and practical impossibility. 

https://www.linkedin.com/pulse/myth-hydrogen-export-spitfire-research-inc

They therefore want to make ammonia, because the only other reagent needed (nitrogen) is 79% of the atmosphere so no problem to obtain.  However, they know nobody (not farmers, food customers or governments) will pay them the premium for green ammonia to use as a fertilizer, and that the fertilizer market is tied up by some large incumbent manufacturers who understandably don’t want new competition for their fossil-derived ammonia supply.   So new markets for that (imaginary future) green ammonia are desperately needed.  And shipping, which has no simple electrification alternative, seems a perfect place to use it.

Potential future market competitors for decarbonized ammonia as a shipping fuel include green methanol.  Methanol is toxic, but it’s a liquid at room temperature and hence far, far safer and more practical as a fuel.  However, not only will green methanol also be more expensive than the fossil fuels used today in ships, it will also likely cost quite a bit more per joule than green ammonia at scale.  The problem is that to make green methanol, you need a biogenic carbon source and green hydrogen.  Sites where wind + solar are also found with large amounts of waste biomass or, in the more expensive and energetically wasteful case, biogenic CO2, are fairly limited, and direct air capture (DAC) as a way to collect the necessary CO2 is just FUBAR.

https://www.linkedin.com/pulse/why-direct-air-capture-sucks-good-way-paul-martin

 The problem with green methanol therefore seems to be one of scale, leading to higher costs at scale.  Ammonia, in contrast, seems “scalable”.

Uses and Handling of Anhydrous Ammonia

Anhydrous ammonia once found heavy use as a refrigerant, even in home refrigerators, until safer molecules were invented- but it is still widely used as a refrigerant in certain applications, including ice rinks.  Anhydrous ammonia is also applied directly to soils by farmers in certain places, solely because it is cheaper than using ammonia derived compounds like urea or nitrates. 

Ammonia itself can be shipped as a pressurized liquid (17 bar at 45 C), a semi-refrigerated liquid (4-8 bar at ~ -10 C) or  as a fully refrigerated liquid (atmospheric pressure at -50 C).  Ships designed for other low pressure refrigerated or pressurized liquid gases like LPG (propane) are often used.  About 8% of world ammonia is transported as anhydrous ammonia currently by ship.

There is, however, a world of difference between carrying a cargo of a poisonous, corrosive gas aboard a cargo ship, or using it as a refrigerant, and using ammonia in any open system use such as feeding it to engines.  The hazard class of a fuels use, i.e an open versus a closed system use of a toxic gas, is orders of magnitude higher in my engineering assessment.

Bunkering and Fueling Ships With Ammonia

Storage of ship’s fuel is referred to as “bunkering”, a hangover term from the days when coal was stored aboard ships in literal “bunkers”.   To use a fuel for shipping, it must be transported from where it’s made, to ports, and then stored there in fairly large quantity.  When liquid fuels are used, barges containing fuel are often towed alongside ships by tugboats. 

 With heavy oil fuels, these operations are routine, in stark contrast to loading a compressed or refrigerated gas tanker with its cargo.  The latter is carried out in very limited locations specifically designed for that purpose, by highly trained staff.   It’s clear that a new set of hazards would arise not just from more numerous and larger stores of toxic gas, but also more routine handling of it by less trained staff than are currently called on for fuel handling.  All of these operations involve the risk of leakage, both routine and accidental.  And with a proliferation of containers of toxic gas in ports, terrorism also cannot be discounted as a very real risk.

Storage and Use Aboard Ship

Once the ship is loaded with its toxic fuel, that fuel would need to be stored, potentially moved around from tank to tank, and of course conveyed to the ship’s engines.  Ammonia is difficult to ignite, so a “pilot fuel” such as diesel fuel is often used along with the ammonia, meaning that the ship would actually have two fuels to manage, one of which will still have some GHG emissions potential.

Ammonia proponents will tell you that they will take every measure possible to engineer out the risks of using their toxic, corrosive gas as a fuel- aside from the obvious one, i.e. not doing it! They will also say that the certifying agencies responsible for insurance-related regulation of every system aboard a ship- companies like DNV, Bureau Veritas, Lloyds Register and the like, will never let unsafe ships go to sea.  They will make every line carrying the fuel to the engine, a piece of jacketed pipe as one for-instance.  That way, a pinhole in the inner liner will not cause a leak into the engine room.  But of course containment at every joint in that pipe along the way- every valve, every flange, every instrument etc.- will not have full double containment.  And no, you cannot eliminate all such connections from any piping system, ever. 

The best you can do is imagine some kind of emissions control or leakage monitoring system, interlocked to shut off the fuel supply, likely backed up with some high-rate ventilation system to keep breathing air safe and possibly a scrubber system to de-inventory leaking components to safely.  And it is important to remember that an engine is an open system- if the fuel is not ignited, it leaves via the exhaust.  When the fuel is toxic, the exhaust becomes toxic too.  To be clear, I don’t design ships or ship-board systems.  But I do design piping, and have worked on process units that were intended at some point to be operated aboard ship.  Even in my comparative ignorance relative to a ship’s engineer, I can see problems that are rather difficult to manage to a high level of certainty.

Of course the 1st principle of safety in design, is to eliminate hazards by substitution if safer alternatives exist, rather than trying to make a fundamentally unsafe choice “adequately safe” by means of engineered controls.  And that is, honestly, the only thing we should be thinking of here, if we care about the lives of sailors.  Remember, aboard ship, accidents tend to happen during storms- and there is literally nowhere to run in the case of an accident aboard ship.

Emissions from Ammonia Combustion

The primary notion here is that ammonia contains no CO2, so it will not generate CO2 as a GHG upon combustion.  That of course ignores GHG emissions from upstream manufacture (99% of world ammonia production is made from fossil natural gas-derived hydrogen, without carbon capture), and also ignores the rest of the combustion chemistry involved.  While the major products of burning ammonia are nitrogen and water, those are definitely not the only products.

Because ammonia is difficult to ignite, some “ammonia slip” would be expected. And since ammonia is both toxic and corrosive and a regulated air pollutant, a pollution abatement system would be required to ensure complete combustion.  This could take several forms.

Burning anything in air causes oxygen and nitrogen in the air to react with one another to form NOx, which consists of two toxic smog-forming species and N2O, nontoxic but a persistent GHG.  NOx formation is however made much worse if the fuel contains nitrogen itself, and even worse still if that fuel is almost entirely nitrogen by mass (14 of every 17 grams of ammonia is nitrogen). 

NOx is often controlled by means of a selective catalytic reduction (SCR) catalyst, where a reductant is fed to react with the NOx to produce nitrogen.  Of course if ammonia is the fuel, ammonia would be used as the reductant, and some of it would likely be “slipping” by the engine anyway.  However, the important thing to know about SCR systems is that while we could feed a nontoxic, non-GHG reductant in excess to allow the catalyst to drive NOx concentrations to near zero, no such reductant exists.  Ammonia must therefore be very carefully added to the flue gas being fed to the SCR, to precisely match the reduction demand.  The normal result will be that either some NOx will not be removed, or both NOx and ammonia will be released.  Both are regulated pollutants which cause environmental harm.

Engines also combust their lubricants over time, generating particulate emissions. And if a pilot fuel is used, its emissions must be counted too.

The notion therefore that ammonia is a “clean fuel”, is basically a greenwash.  And a recent MIT report, agrees with me on that:

https://news.mit.edu/2024/study-finds-health-risks-switching-ships-to-ammonia-fuel-0711

The study found that switching world shipping to ammonia fuel could cause as much as 600,000 additional premature deaths per year, largely from particulate matter generated by ammonia and NOx emissions.  Remember that shipping is already a massive source of fine particulate emissions from combustion, so this result is rather shocking.  The study recommends not only further work, but tighter air pollution regulations to address ammonia’s particular hazards.

Final Thoughts

Basically, this is all about money, and nothing more.  The very best thing you might say about ammonia is that it could be, at some future time, a cheaper alternative to methanol as a green shipping fuel, especially at scale.  It remains to be seen, however, if the extra costs of safe bunkering, safe fueling, and all the safety requirements aboard ship that might be acceptable to the likes of DNV etc., will add to the raw cost of the fuel.  It is not even clear to me that ammonia will end up cheaper than methanol once these provisions are in place.  Methanol handling is, relative to ammonia, more or less childsplay- although it does require more provisions and different systems than required for heavy bunker oils.

What is also certain to me is that if we foolishly choose to use a poison gas as a shipping fuel, despite the concept’s failure of the very first principle of safety in design, the result will be deaths and environmental damage that would otherwise have been entirely preventable.

History has rarely looked well on people who made the decision to knowingly put people’s lives at risks in order to save money, whether those people be employees or the general public.  Such crass cost-benefit analysis type thinking should have gone out of favour in the 1970s with the likes of the exploding Ford Pinto! 

(the Ford Pinto- note the ironic “reverse flames” paintjob.  To save installing a ~$10 part, Ford knowingly allowed a car where rear end collisions led frequently to gas tank ruptures and fires.  Lawsuits ate every bit of savings and nearly killed the company)

The imagined savings are usually blown out in the end by legal liability costs, even if you don’t value human lives intrinsically.  And let’s face it, we don’t all have the same values.  Some people aren’t troubled by the thought of others killed or injured in what they can write off as “accidents”.

As a professional engineer, it is my duty to hold the public safety as paramount.  And so it’s also my duty to inform the public when I see something that clearly will lead to needless loss of life.  It’s my hope that others with the same knowledge and experience with chemical handling will step up and speak out publicly about this.  Ammonia as a shipping fuel is yet another in a long list of bad ideas that are being put forward as decarbonization solutions whereas at best they are merely distractions and subsidy-harvesting schemes.  The difference here however is that not only is public money likely to be wasted on yet another dead end, this time it could also come with a body count.  I just can’t sit here silent about that.

Disclaimer:  this article was written by a human, and humans are known to make mistakes from time to time.  If you find a mistake, please bring it to my attention with good references and I will edit the article with gratitude.

If however your chief objection is that I’ve taken a dump on your pet idea, or one that you intend to use to make money for yourself or your company, please reach out to my employer Spitfire Research Inc., who will be happy to tell you to piss off and write your own article.

Where Does Green Hydrogen Fit?

Image credit: Google Gemini

If you know my writing even a little, you’ll know where I stand on this issue.  It’s as simple as my meme, but my many articles (especially this one) explain why, in detail.  Those articles come with analysis and references and the comments of many experts in the field as an informal peer review too.

https://www.linkedin.com/pulse/distilled-thoughts-hydrogen-paul-martin

So…where does green hydrogen fit?  The simple answer is that it fits a) where it can be made truly green b) for applications where we need the special properties of hydrogen as a molecule, for things which are durable in a decarbonized future.

Where can we make hydrogen that is truly green? Since it is an economic myth that we can make affordable hydrogen only from electricity that would otherwise be curtailed, and because the obvious highest value use for green electricity is to replace BLACK electricity (electricity made from fossils without carbon capture), it stands to reason that we can only make green hydrogen where and when the local grid is already as green as we can manage to make it in practical terms. Sadly, at present, that means only in places where the potential to make new green electricity greatly exceeds the ability of people within reach of an HVDC cable (i.e. within a few thousand kilometres by land or sea) to make use of that electricity. Everywhere else, that electricity’s highest value use for decarbonization isn’t to make hydrogen- it’s to use it to displace dirty electricity from the grid.

If we do make some green hydrogen that we think we can afford, it similarly isn’t really “green” unless we use that hydrogen for uses that require hydrogen, and which will survive in a decarbonized economy. Those applications are largely things we use dirty, fossil-derived, high CO2e emission hydrogen for today.  And that’s substantially all the hydrogen in the world today- 99%+ of it is made to the tune of over 120 million tonnes/yr, not to waste as a fuel, but we make it from fuels, with CO2 and methane and toxic combustion emissions going to the atmosphere as a result.  And by my estimation, the making of this fossil-derived hydrogen- and there’s nothing “gray” about it, it’s blacker than black in terms of emissions- has CO2 emissions greater than those of aviation and almost greater than those of both aviation and shipping combined.

Existing Uses of Hydrogen

The three major categories of hydrogen demand are ammonia, petroleum refining, and everything else.  Each of these consumes about 1/3 of world hydrogen production.  The figures for hydrogen production and consumption by sector, both pure and in syngas (mixtures with carbon monoxide or CO) are from the IEA via IRENA and are referenced here:

IRENA IEA H2 use vs time 2018

Ammonia

Ammonia is the toxic gas that is keeping half the humans and their food animals on earth, alive by feeding them.  A deeply ironic state of affairs, with huge emissions that we must reduce.

https://www.linkedin.com/pulse/ammonia-pneumonia-paul-martin

 We use about 40 million tonnes/yr of hydrogen, substantially all of it blacker than black, to make ammonia, which is the source of all our nitrogen fertilizers and also the base of the entire nitrogen chemicals industry on earth.  We make so much ammonia that we humans are fully half the nitrogen cycle on earth.  (Note that while we are, with scientific certainty, wrecking the stability of the climate by burning fossils and emitting fossil CO2 to the atmosphere, it is the cumulative effect of doing that over decades which is the problem- despite the fact that we humans and all our activities represent a small fraction of the annual carbon cycle on earth.) 

The emissions from ammonia production are not just from the CO2e-emissive process of making the hydrogen that we then react with nitrogen to make ammonia itself, but also from the N2O emissions (a very powerful and persistent GHG) which inevitably result when we apply ammonia, and nitrates and urea made from ammonia, to agricultural soils.  We need to improve agricultural practices to reduce those N2O emissions.  But we also can and must reduce how much CO2e is generated to make ammonia in the 1st place.  And we can do that if we’re smart, by using truly green hydrogen in place of black hydrogen.

So- why aren’t we doing that?  Why do we hear almost nothing about projects to make green ammonia to replace black ammonia for use in fertilizers?  Yes, there are a handful of such projects in the works, but most green ammonia projects (or dreams of future projects, which are much more common than real projects) are centred around bad ideas like burning ammonia in power plants, or as a ship’s fuel, or cracking ammonia with added heat at destination to make it back into H2 and N2 again.  Why is that?

One word, one reason:  subsidy.  Perverse and ill considered subsidies generate perverse incentives, and tempting people to use a poison gas as a ship’s fuel is in my view, pretty much the definition of a perverse outcome.

No farmer will voluntarily pay more for green ammonia when their competitors can produce the same crops to sell in the same the same markets with cheaper black ammonia.  And no, a future where green ammonia is cheaper than black ammonia, even with heavy carbon taxes in place but without subsidy involved, is not something that we can expect in the foreseeable future in my view.  While there is hope for something close to cost-competitive to come out of green ammonia projects in the very best locations in the world, the delivered cost will still be a multiple of the cost of black ammonia.  Carbon taxes and emission bans are key, and are much preferable to subsidy.

Petroleum Refining

Petroleum refining is at once the source and the consumer of about 1/3 of the world’s hydrogen.  And both will shrink to about 15-25% of current levels when we stop burning fossils on purpose as fuels.

Hydrogen is used in refineries to remove toxic sulphur and nitrogen species from petroleum cuts that we will later burn- a process known as “hydrotreating”.  The hydrogen ends up as H2S, which is subsequently reacted with oxygen and then broken down into sulphur and water.  Hydrogen is also used in “hydrocrackers”, which not only hydrotreat a petroleum feedstock, but also break large molecules into smaller ones.  When this kind of chain breakage happens, a carbon-carbon double bond is formed in one of the pieces, which is usually undesirable to the final product’s storage stability and usefulness as a fuel.  Hydrogen eases the breakage and also adds hydrogen across that C=C double bond, eliminating the stability problem.

Hydrogen is made in refining or petrochemicals operations such as “plat-forming”, a process by which straight chain hydrocarbons are cyclized and dehydrogenated to make aromatic rings like benzene, toluene etc.  Cracking of lighter molecules such as naphtha or ethane and propane  to make olefins (compounds like ethylene, propylene and butadiene with C=C double bonds, useful for making polymers) also produces hydrogen as a byproduct.

Yes, in a decarbonized future we will still refine petroleum- just 15-25% of what we currently do.  And no, there’s no need to make gasoline and diesel or anything else to burn, in that process.  Whether or not we’ll choose to afford to do what’s required, is another story.

https://www.linkedin.com/pulse/refinery-future-thought-experiment-paul-martin-4pfoc

In summary, petroleum refining will greatly shrink in hydrogen demand, and may end up being nearly self-sustaining in hydrogen in the end (or might consume a small amount of green hydrogen).  Replacing black hydrogen used in petroleum refining today is therefore not a high priority use for any green hydrogen we think we can afford.  We should instead keep the focus on eliminating the burning of petroleum and gas products as fuels.

Everything Else

The other 1/3 of current hydrogen uses is divided among many smaller use cases

Methanol

Methanol today is nearly exclusively made from synthesis gas (mixtures of CO and H2) made from natural gas or from gasifying coal.  In a decarbonized future, any methanol we think we may need to burn- as a decarbonized shipping fuel for instance- we can make either using biomass or using biogenic CO2, the former being much cheaper than the latter.  Both will need green hydrogen- the former because biomass is deficient in hydrogen, the latter because CO2 basically needs to have one of the two oxygens on it “burned off” by reacting it with H2 to produce water.  Green methanol production is a good use of green hydrogen- but we should not reach right away for e-methanol (ie. ultimately made from water, CO2 and electricity) as it will likely be considerably more expensive than bio-methanol with added green hydrogen.

Methanol is also currently used to make many other important chemicals and materials, which are rarely burned- such as formaldehyde, formic acid, acetic acid, certain important polymers, and many others.  Methanol is also used as a solvent and antifreeze agent.

 Direct Reduction of Iron (DRI)

A small percentage of current world iron production is made from iron ore not in a coal coke-fired blast furnace or basic oxygen furnace, but in a process by which syngas (made from natural gas) is reacted directly with iron ore to form iron metal, CO2 and water.  The process, known as direct reduction of iron (DRI) has been demonstrated to be possible using only a very small amount of CO, with almost all of the CO replaced with hydrogen.

It is extremely important to note that iron in DRI is used as a chemical reducing agent (a source of electrons), not as a fuel.  It is also important to note that “steelmaking” is already largely an electric process in the developed world.  For instance, 70% of steel in the USA is made using electric arc furnaces that are fed largely scrap steel plus some fresh iron.  That fresh iron could, in part or maybe even in total, be made by pure hydrogen DRI.

 Since the reaction between iron oxides and hydrogen is slightly endothermic, electric heating is also required (unlike when syngas is used).  The process of DRI using pure hydrogen has been demonstrated at scale by Hybrit and others, and represents the highest technology readiness level (TRL) way we currently have to nearly eliminate CO2 emissions from iron production.  Other options are under development, including molten iron oxide electrolysis and some aqueous electrochemical methods, but all are at a much lower TRL and are at least a decade from at-scale market relevance- if they ever make it to market.

DRI with pure hydrogen is a high value use of green hydrogen, and a potential growth area for hydrogen consumption in a decarbonized future – but only if we do it in locations where both ore and the potential to build new high capacity factor wind plus solar hybrid power sources (or, rarely, excess hydroelectricity) exist close to one another, and nobody nearby needs the electricity that could be sold instead.  Western Australia is a perfect example, but there may be many other such locations- perhaps including Labrador in Canada, and Sweden where H2 Green Steel is building a plant to do just this (using hydroelectricity).

I also see substitutions of iron for aluminum, magnesium, wood and other materials which are easier to decarbonize (i.e. at a lower cost per unit strength) than iron may be.

Other Hydrogen Uses as a Chemical

Hydrogen is used in many other chemical reactions, and as a reagent to prevent others from happening.  It is used to protect metals from oxidation inside furnaces for operations like sintering or bright annealing.  It is used to hydrogenate vegetable and animal oils.   It is used as a coolant in turbines and certain electrical equipment. And it is used in a host of reactions such as making halo-acids (HF, HCl, HBr), hydroformylations and many others.

What We Should NOT use Green Hydrogen For 

Hydrogen’s current use as a fuel is limited to a very small number of specialty uses such as the upper stages of rockets, vitreous quartz “glassblowing” etc.  Notional future uses such as fuelcell vehicle fueling or industrial heating, amount to a trivial fraction of current world hydrogen consumption.

Virtually all the hydrogen currently burned is burned for its energy content and as a waste disposal practice, because it is hydrogen mixed with other gases that are simply not worth the bother and expense of separating from one another.  Despite the recent “hydrogen economy” hyperbole, hydrogen is in fact one of the cheapest commodity chemicals on earth, relatively easily made from methane- a molecule which itself has basically no uses other than for the production of heat energy or syngas.  Hydrogen is really not worth that much- certainly not enough to make it worth sifting hydrogen from a complex gas mixture when there’s a nearby furnace hungry for fuel.  That may change in the future, but it’s unlikely to change much.

Green hydrogen’s role in heating, transport and energy storage is usually a response to the wrong question.  When you ask, “what else can I burn, aside from fossils”, hydrogen is a frequently offered, simpleminded answer. 

But when you ask the better question:  “We can’t burn fossils any more- how can we meet our needs for energy services, without generating fossil GHG emissions?”, the answer is almost never hydrogen.

Making hydrogen from electricity is a step backward in exergy terms- and no, that’s not a typo.  That step backwards has a huge cost associated with it.  One that, I’m sorry, for energy applications, you are very unlikely to ever fix.  You may cope with it out of desperation, breaking your wallet in the process, but that is not at all the same thing.

https://www.linkedin.com/pulse/breakthrough-electrolyzer-efficiency-paul-martin

Green hydrogen’s intrinsic exergy destruction is a feature of its foolish use as a fuel, not a bug.  It’s a systematic inefficiency that acts as a multiplier of all the upstream emissions associated with every unit of useful energy services you generate from hydrogen as a fuel- moving a car by a kilometre, or heating your home, or storing a unit of electrical energy, or what have you.  There are usually better ways- and usually, those ways use electricity more directly, without the exergy destruction resulting from needlessly involving a molecular middleman and its covalent chemical bond formation and breakage.

https://www.linkedin.com/pulse/how-green-hydrogen-lifecycle-basis-paul-martin-pbhyc

But we’re not done yet- hydrogen has the twin problem of being energy and especially exergy inefficient, but also being ineffective as a fuel.  It is difficult to move and store.  That kills hydrogen as a practical replacement for some applications which are also not suited to electrification, such as transoceanic shipping and aviation.  Those applications will need liquid fuels, and those liquid fuels will be much cheaper to provide as biofuels.  Green hydrogen’s role there will be limited to yield improvement, as we’ve already discussed in relation to methanol.

Finally, those few applications for high temperature industrial heating that truly need fire rather than just heat, are rarely a good fit for hydrogen due to its lack of an emissive flame.  Biofuels are a better solution for those applications too.

Evidence

Michael Liebreich has provided a very useful graphic which shows that the highest value uses of green electricity are via the “electrification pathway” in every case where hydrogen is considered as an alternative. And where electricity needs to be made greener, it is far more sensible and economic to do THAT, than it is to try to use that same electricity to produce green hydrogen- even to replace black hydrogen in uses durable post decarbonization. Hence, the famous Drake meme well and properly deserved modification. This point should go without saying, but needs to be said- loudly and often.

Conclusions

It really is as simple as the meme.  Green hydrogen should be reserved for applications requiring its special properties as a molecule, where its resulting emissions are absolutely without regret.  It should not be wasted as a fuel.  And anybody selling you the idea of using hydrogen as a fuel, is selling you a bill of goods- sometimes out of ignorance or poor analysis, but often as a result, at least in part, of the fact that they have an invoice waiting for you in their back pocket- and some of that invoice’s proceeds are headed to their own bank account.  That’s not always true, to be clear- there are some true believers in hydrogen as a fuel who literally have no money riding on it.   But it was true frequently enough that myself and a number of co-founders saw fit to build the Hydrogen Science Coalition, to provide insights about hydrogen’s true role in decarbonization, from a position of scientific and engineering knowledge, free of any significant financial interest one way or another.

Disclaimer:  this article was written by a human, and humans are known to make mistakes from time to time.  Let me know, with good references, where I’ve gone wrong, and I will correct my work with gratitude.

If however what you don’t like is that I’ve taken a dump on your pet idea, then please feel free to contact my employer Spitfire Research Inc., who will be most happy to tell you to piss off and write your own article.

Yes, Virginia, Solar Really is THAT Cheap!

TL&DR Summary:  yes, it really is that cheap.  It’s not bullshit.  It’s real.  And it’s going to power the world.   Well, not the whole world- but a very significant part of the world.

Those of you who read my articles will know that I have a small farm east of Toronto.  We’ve built a couple small cabins there, and repaired a dilapidated building to become my workshop.  There’s no well, no septic system, and no grid electrical supply.   No, we don’t live there full time- but it does serve as a useful test bed for an off-grid system regardless.

Our power solution is pretty simple:  we have solar, and in the few winter weeks where solar is interrupted by snow cover on the panels, we have a gasoline generator.  That generator runs more often just to make sure that it works when we need it, than it ever does to make power.

Each cabin has a single panel, a small charge controller, a 300 W inverter (good enough for lights, a fan in summer, and cellphone charging), and a battery- generally an 80 Ah marine lead-acid battery, because they are best suited to sitting full most of the time.  The breakdown of the cost of these systems is as follows:

(all costs in this article are in $CDN, not including taxes.  As of publishing, the $CDN is about $0.75 USD)

12V 100W panel:  $100 (Amazon) – you can get a more powerful 30V panel but then you need a better charge controller

PWM charge controller:  $10 (AliExpress) Want a MPPT unit that can handle a higher voltage panel?  Then you’re looking at $100

300 W 120 V inverter:  $30 (AliExpress)

Wire and connectors:  $50

80 Ah lead-acid marine battery:  $200 (Canadian Tire)

Why bother with these little systems at all?  Because the cabins are a long way from one another, and stringing wire through the woods is a pain in the butt, and ruins the aesthetic.  Trenching is even more of a pain, and would sever the roots of numerous trees if we did.  And a single panel and battery produces all the power we really need, with no ongoing operating costs other than some distilled water every once in a while to water the batteries.

You’ll note that the biggest cost in each of these systems is the battery.  While “lead is dead” for real solar applications that cycle frequently or deeply, lead-acid’s one strong point is applications needing to sit at 100% state of charge for long periods of time, where discharge is at a low drain rate (low currents, draining the battery over a period of 20 hours or more).   The capacity of lead acid batteries at high drain rates is very low due to the Peukert effect.  Lead-acid batteries love to sit full, and need to occasionally be agitated to prevent sulphation- that’s why they last so well as vehicle starter batteries. In stationary applications, agitation is normally done by means of a “balance” or “equalization” charge cycle, where overvoltage is applied and the cell electrolyte is agitated with the resulting hydrogen. 

If we ever need more power- to run power tools at one of the cabins for instance- we have a brick of four LFP prismatic cells with a 3000 W inverter mounted on top of it.  This is our “silent generator”, and I use it for all my mobile construction projects.  We recharge it using a DC/DC converter ($6, AliExpress) from the main pack in the workshop.

The workshop system is more complex, and more fully functional as a source of electricity.  It consists as follows:

Four nominal 300 watt panels:  I recently bought two 320 W Jinko panels for $135 each.  These are brand new, just the older model.  $0.42 CDN per watt of capacity…that’s insanely cheap.  Total $540 for 1.2 kW of nameplate capacity.

Mounting structure:  made of 2x4s sawn from fallen trees in our own forest. Previously, the other two panels were mounted on two ~ 4” diameter black locust trees that I had to fell because they were in the wrong place, which I just limbed, notched, and leaned up against the south side of the building (back during COVID when 2x4x8s were $10 each).  It looked ugly and worked just fine, but now I have a nicer support system which allows me to tilt the panels to different angles in summer and winter.   The structure cost me perhaps $10 worth of hardware and $10 worth of sawmill and chainsaw gasoline and tractor diesel and sawblade wear and tear combined, but if you bought the wood at Home Depot it might have cost $125 or so.  The exercise I received is not charged for, but saves a gym membership.

Charge controller:  EPEVER 40 A maximum power point tracking unit with buck stage, $200, Amazon.  These things are pretty brainless and still don’t have proper factory lithium ion settings, but you can make them work especially with a BMS. 

Batteries:  eight 280 Ah LFP prismatic cells:  $860 including delivery from China.  These cells are guaranteed for 6000 cycles, and are about 90% efficient, i.e. they return 9 out of every 10 kWh you feed them.  They come with the cell connectors to build a series pack.  I built a box for them out of leftover plywood.  The eight cells are arranged in series with a total nominal capacity of about 7 kWh.

Battery Management System:  depending on what you’re doing, these can cost between $20 and $200 for a suitable unit.  The 100 A 24V unit I am using at the farm cost $60 (AliExpress).  The BMS monitors individual cell voltages.  If any cell goes above 3.65 V, it shuts down charging.  If any cell goes below 2.5 V, it shuts down the inverter output.   The BMS also provides a shunt charging balance function to top-balance the cells, but with LFP such continual balancing is basically unnecessary.

Battery Status Gauge (“smart shunt”)- $60, Amazon  (not strictly required, but helpful to know your state of charge, which with LFP cells you simply cannot tell via voltage readings except below 10% and over 90%).  This device measures and displays currents into and out of the cells and keeps track of the battery state of charge.

Inverter:  3000 W peak (1500 W continuous) true sine wave unit, 24V nominal input $108 (AliExpress)

Miscellaneous:  wire, connectors, disconnects, terminals etc.:  perhaps $200 all in

Ignoring my labour (and why shouldn’t I- this was all good fun!)  that’s about $2000 for the whole shebang.  That’s not just solar, but also includes storage.  More than enough storage for our needs- but we’ll soon have even more, as I augment the existing pack with batteries taken out of my electric car conversion projects after 10 years of service.  At the lower C rate of a solar application, these LFP cells will likely last ANOTHER ten years.

Some of you will say, “Oh, isn’t it nice to be an engineer, to know how to do all this stuff?!”  Well, I’ve got one word for you:  YouTube.  Visit one of the numerous sites such as Off Grid Garage, and you’ll soon know what’s involved.  It ain’t rocket science, or brain surgery, much less rocket surgery!  As long as you stick with either lead-acid or LFP with a BMS, and stay at 48V or less, you’re going to be just fine.  And yes, you can pay more for simpler solutions- LFP batteries packaged with their own internal BMS for instance so you don’t have to trouble yourself over them any more than you would with a lead-acid battery.  You can always push the “easy button”- it just costs you a bit more.  Of course you could push the “more money than brains” button and buy a Tesla Powerwall, but I definitely wouldn’t recommend that!  That product is massively over-priced.  Think of it as the “Apple” of battery storage systems.

How much electricity can my workshop system produce in a year?  Well, the panels will generate about 1,300 kWh per year per kW of installed capacity, so about 1,560 kWh per year.  And yes, they generate a surprisingly large number of kWh in winter, despite the snow- tilted at the correct angle, they tend to shed snow surprisingly well.  But of course I won’t use all of those kWh, so it’s hard to make a proper cost comparison.  In summer, most of the kWh go to keeping a fridge and freezer cold while we’re not there- but it’s nice to have cold drinks and to not have to go into town every time you need something.  In winter, the system more or less does nothing when we’re not there. 

The important thing is this:  the system is sized for our winter needs.  In summer, we make excess kWh but they cost us nothing.  When the batteries are full, the charge controller or the BMS simply disconnects the panels.  The cost of curtailment is zero.

But when we’re there, that system does everything we might expect to do with a power line connected to the grid.  If we lived there full time, we’d likely go up to 10 kW of panels (because they are VERY cheap) and quadruple our battery storage too, going with higher output hybrid inverters etc. etc., but that would be more about convenience, reliability, and recharging our electric car, than about anything else.  That system would definitely be up to the job of running a heat pump for cooling and shoulder-season heating.  We’d still heat the place primarily with wood, because with 28 acres of woodlot, we could never burn all the deadfall.

Costs per kWh and Other Metrics 

You could perhaps add up 16.5 years worth of the panels’ production (daily cycling of the batteries to achieve the guaranteed 6000 cycles takes 16.5 years- the panels etc. should all last much longer than that) and do a ratio, i.e. $2000/(1,560 x 16.5) kWh = $0.08/kWh, but that would assume that I use every kWh I make.  

Remember, that includes storage.  That’s for fully functional solar power.

But a better comparison is this:  what else can you buy for $2000?

You can buy the installation of one (1) power pole.  And I’d need fourteen (14) poles installed to bring power to my site from the nearest utility pole.  That doesn’t include wire, or labour to install it.

You can buy 4.5 years worth of monthly account charges to have an account with the local electrical utility, whether you use any kWh or not…

Are you agreeing with me yet?

Solar power is just that cheap.  Solar plus batteries are of course even cheaper in Australia where capacity factor is such that each kW of panels generates 2.7 times as many kWh per year, and where snow cover on the panels is never a worry. 

And panel and battery prices are still falling- as are the prices of all the various bits of kit needed to build an off-grid or “behind the meter” system.  Sodium ion is just coming on stream now, and has the twin advantages of low materials cost (nothing in those batteries is anything other than earth abundant), and the ability to be shipped fully discharged, i.e. no hazardous goods shipping charges, which are a significant fraction of the cost of buying LFP cells today.

I can clearly see where this is going.  I’ve seen it for years now.  Can you?

Yes, I know that my own little system isn’t a pin for pin replacement for the grid connection you have to your house, condo, flat, or castle.  I know you “can’t” and really wouldn’t build a whole grid like this.  I know there are reliability needs that literally mean life or death, that must be satisfied.  I know every human in a developed country is now conditioned to think that power can be supplied in any quantity with no more thought than it takes to flip a switch.  I know that building a fully decarbonized energy system is going to take decades, and cost trillions, and require major changes to how consume energy and hence how they live.  But if you don’t see that solar is going to play a major role in energy supply in a decarbonized future, I’m sorry- you either haven’t thought about it carefully enough or you’re delusional.  Energy this cheap is just too good an opportunity to pass up.

Disclaimer:  this article was written by a human, about his own little experiments with solar power.  If I’ve made a mistake, as humans are wont to do from time to time, correct me and I’ll be grateful.

If however you don’t like what you’ve read because I’ve threatened your own pet idea, then you can contact Spitfire Research Inc. who will be more than happy to tell you to piss off and write your own article.