Neil Camarta just can’t seem to stay retired. After 35 years in the oil industry, including stints at Shell and Suncor, the chemical engineer from Edson, Alta. is now in what he calls the ‘crackpot business,’ taking risks on maverick new technologies. His current project is Western Hydrogen, a company that recently launched the world’s first pilot-scale molten salt reactor for turning carbonaceous feedstocks — including petroleum coke, asphalt, natural gas and even biomass — into high-pressure hydrogen, ready for use in oil sands upgrading or electricity generation. ACCN spoke to Camarta about what drives him to keep innovating.

Can you briefly describe your career?

I’m an Alberta boy; I grew up on a farm, went to the University of Alberta and joined Shell in 1975. I worked there for 30 years, both at home and overseas. In my final 10 years, I got Shell’s oil sands business up and running, including the development of the Scotford upgrader, which was specifically built to handle Alberta bitumen. We caught the oil price rise just beautifully, and I retired from Shell in 2005. But I got tired of retirement, so joined Petro-Canada and worked on their oil sands for a couple of years. Then came the big merger with Suncor, and its president Rick George asked me to ride herd on the gas business. I retired again in 2010, so I’m a serial retiree.

This time around I’ve hooked up with Guy Turcotte, and together we became venture capitalists looking for new technologies. That means we are in the crackpot business; you have to kiss a lot of frogs before you find a prince. When we find something worthwhile, we help the people that own the technology to make it commercial, and that’s what we’re doing with Western Hydrogen.

You’ve said, “producing hydrogen is one of the most expensive and carbon-intensive parts of the oil sands business.” How so?

To turn that heavy black stuff — which is full of sulphur, heavy metals and various acids — into something you can pump down a pipeline, you have to upgrade it. You can do this by heating it up to crack the big molecules into little ones, or you use what’s called hydro-conversion, which is a catalyst-based process. Either way, you use a lot of hydrogen, about 1,000 standard cubic feet per barrel of bitumen converted.

Most hydrogen is made in steam-methane reformers that use water and natural gas as their feedstocks. The efficiency of these plants is not great, which is fine as long as the price of natural gas is low, but if the gas price goes up, then that hurts. It’s one of the biggest input costs when you’re running an upgrading business.

Tell us about your alternative, molten salt-based process.

This was developed by the folks at the United States Department of Energy lab in Idaho, who are experts in reactor design. We fill our reactor with molten sodium salts: sodium hydroxide and sodium carbonate. Then, we heat it up to 1,000 C and pressurize it up to 2,000 pounds per square inch.

When we inject our hydrocarbon feedstock plus water into this reactor, a looping reaction takes place. First, sodium carbonate reacts with the hydrocarbon plus water to form elemental sodium ions, plus carbon dioxide and hydrogen. Then, the sodium ions react with water to form more hydrogen plus sodium hydroxide. Finally, the sodium hydroxide plus the carbon and more water re-forms the sodium carbonate. So it’s a big looping reaction, in which the molten sodium salts act as a catalyst — they’re not consumed.

The upshot is that if you put in any hydrocarbon — whether it’s a fossil fuel like petroleum coke, coal and natural gas, or renewable feedstocks like glycerol, algae or wood chips — the looping reactions convert it plus water into hydrogen and carbon dioxide (CO2).

Traditional gasification — burning hydrocarbons in a low-oxygen environment — can accomplish the same transformation. What’s the advantage of your system?

All the gasifiers I know use oxygen plants, because they don’t want to waste energy heating up the nitrogen in the air that comes along for the ride. In these systems, 18 to 30 per cent of the capital cost is tied up in the oxygen plant. We don’t need oxygen, so that gets one big piece of hardware off the table, and also saves a lot on utility costs.

The second thing is that we produce our hydrogen at high pressure. Hydrogen takes a lot of energy to compress, but you typically need to have it at around 1,000 pounds of pressure to be useful. So again, we save on costs by not needing a compressor. The elegance of our system is that everything happens in one reactor, so it’s much more energy-efficient than a conventional gasifier. If you go back and talk about steam-methane reformers, those use air in the burners used to heat the catalyst, which requires blowers, etc. And you still need to compress the hydrogen up to 1,000 pounds. In general, our system has fewer pots and pans.

Your system doesn’t produce­ pure hydrogen­, but rather a mixture of H2 and CO2. How do you separate these streams?

We have a quench stream which cools off the reactor gases, and that carries away some CO2. As for the rest, there are a couple of options. One is to use pressure swing adsorption, which involves microporous minerals that selectively adsorb CO2. Another is to use a cryogenic process to liquefy the CO2 and separate it from the H2. We looked at both these options, and either way it comes out to be a lot cheaper when the gases start at high pressure. We’re also looking at ionic transport membranes that separate hydrogen from other gases, and they run really well at high temperatures too. If it works, it would be a real breakthrough, and would help us get rid of a lot more pots and pans. But that’s still an open question; and we’ll find out in the next year.

Molten salt gasification has been known for decades­; what did you do differently­?

The chall­enge was the reactor design. You need the right metallurgy to contain the molten sodium salts at high pressure and high temperature. The other key element is that we just have one reactor, which means you don’t have to pump molten salts around, which would be hard to do. Really it’s the expertise developed by the people in Idaho — the metallurgy and the mechanical design — that make the difference.

The pilot plant build by Western Hydrogen in Fort Saskatchewan, Alta. contains the world’s first large-scale molten salt reactor for the production of hydrogen, a key ingredient in oil sands upgrading. The feedstock can be any carbonaceous material, from asphalt and petroleum coke to waste glycerol or other biomass. Photo credit: Katherine Camarta

Tell us about the pilot plant you’ve just built.

We built it for two reasons. Firstly, we wanted to prove the technology, to get all the proper data and to try different feedstocks. We’re running it on asphalt because it’s cheap, you can put it in a tank and pump it, and it’s a good proxy for a heavy, carbonaceous feedstock. If you can run on asphalt, you can probably run on anything.

Secondly, it acts as a showcase. Oil sands people are “show me” people, and the best way to get rid of a crackpot is to ask them to build a pilot plant; a lot of them never do. We’ve put ourselves right between refinery row and upgrader alley — in Fort Saskatchewan, just east of Edmonton. There are a lot of pots and pans out there, including the upgrader I built for Shell, so it’ll be pretty hard to avoid us.

It’s going to take us a year or two to try out different feedstocks and get the kind of practical information that engineers need to design a demonstration plant. I see moving toward that kind of scale-up within five years.

How is all this funded?

I think we’re up to about $10 million now. Most of that comes from myself and my partner Guy Turcotte. The rest — about $4.5 million — comes from the Canadian government, specifically from Sustainable Development Technology Canada (SDTC.)

How confident are you in your ability to compete with traditional ways of making hydrogen, like steam-methane reforming?

If you’re running on something like asphalt or petroleum coke, it’s hard to compete against steam methane reformers running on natural gas that costs only two dollars per gigajoule. But if gas prices rise to five or six dollars, we could make hydrogen at the same cost using petroleum coke.

Our other advantage is that we can switch. We’d have to add a different front end, and we’ll be proving that in the pilot scale, but we can run on natural gas if that’s the cheaper option. What will attract oil sands people is not just that we can make hydrogen, but we can make it with different feedstocks and react to market forces. With a steam-methane reformer, once you’ve sunk that capital, you’d better pray the gas price stays low for the life of the plant.

What if it doesn’t work out? Are there other applications­ for your technology?

This started because we know that the oil sands are a hydrogen-intensive business, but there are other markets. If you use renewable feedstocks and run the hydrogen in a solid oxide fuel cell, you could very elegantly make carbon-neutral electricity. There seems to be some market pull for this, for example on the back of the biodiesel industry. For every 10 barrels of biodiesel you make, you make about a barrel of glycerol as a byproduct. There’s only a limited market for glycerol, and if you look at the amount coming out of places like Germany you start to realize that it’s a perfect renewable feedstock for our machine. We don’t even need to scale it up: a plant the size of the one we just built could make the equivalent of three megawatts of power. If the pull is still there in a few years, I could see us chasing that market too.

You could have had an easy and comfortable retirement; why did you decide to take a risk on this project?

I’ve worked in big oil for 35 years; I’ve taken lots of risks, and I’ve got the scars to show for it. I’ve had a lot of fun, but at the end of the day I’m a chemical engineer, and I like to build stuff. In a way it’s just getting back to basics, but it’s also a chance to try the one thing I haven’t done, which is this entrepreneurial bit. When you get your own money into trying to find a cheaper and cleaner way to develop the oil sands, and proving that this technology can change the game, that’s very exciting.