Eric Newell knows the carbon dioxide issue inside and out.
Once the CEO of Syncrude Canada, a major part of an Alberta oil sands industry that is generating the largest amount of CO2 emissions in the province, he is presently the chair of the Climate Change and Emissions Management Corporation (CCEMC).
“It’s solely interested in funding projects that reduce greenhouse gas emissions and also adapting to climate change,” Newell said of CCEMC.
The company and its operations are closely tied to a piece of legislation enacted by the provincial government in 2007 known as the Specified Gas Emitters Regulation. That regulation focuses on large CO2 emitters that produce over 100,000 tonnes of the greenhouse gas per year and demands that they improve their energy efficiency by twelve per cent relative to a baseline level that was established in 2005.
“And that’s actually a very tough target because these are generally new plants where they’ve been working on energy efficiency for some time,” said Newell.
That target has to be met on an annual basis. If the company fails to do so, it can buy carbon offsets at auction under a system developed by Alberta Environment and Sustainable Resource Development (ESRD).
“Or you can choose to put $15 per tonne of CO2 equivalent that you’re short into a technology fund,” said Newell. “And that was the first time in North America that somebody put a price signal on carbon.”
It also provides the funds granted by CCEMC to projects tackling the climate change problem.
“They started collecting that in mid-2007 and, by the end of 2011, they’d collected $315 million,” Newell added.
“The interesting part of the model is, by legislation, that money can only be used to reduce greenhouse gas (GHG) emissions or adapt to climate change. It can’t go into government coffers.
“That’s very important when you’re doing research and development. Because you need sustainable funding.”
CCEMC had completed four rounds of funding grants when they realized that they were only hearing from large companies, not the small and medium enterprises.
“And yet that’s where often your entrepreneurial thinkers are,” said Newell. “And we do subscribe to the idea that a good idea can come from anywhere.”
Consequently, the most recent competition was exclusively for companies with 250 employees or less.
“And we got some really good, innovative ideas,” said Newell.
CCEMC had been told by those smaller companies that they didn’t require a great deal of money to move their ideas to the next phase, which meant that they could limit the grants to $500,000 per project and consequently provide funding for thirteen initiatives.
Three of those thirteen grant recipients that were announced on October 31 are concerned with capturing CO2.
One of those projects is Carbon Engineering’s direct air capture pilot plant where they would process atmospheric air to produce CO2 that can be used for enhanced oil recovery.
“You could move this device around wherever you’ve got a good source of air with carbon dioxide in [it],” said Newell.
“It would reduce the cost of that capture, which is the key.”
Sustainable Energy Solutions has a project involving cryogenic carbon capture and CO2 Solutions takes a page from the human body in its method of catching the GHG.
“They’re using a biological approach using an enzyme to reduce the cost of carbon capture from oil sands production,” said Newell.
“I love this example. It shows good lateral thinking,” he added.
“They feel they can reduce the cost of carbon capture by up to 40 per cent. And that’s the critical thing in carbon capture and storage, is the cost of the carbon capture. So, that would be very significant if they are successful.”
Glenn Kelly, president and CEO of CO2 Solutions, explained that their process simply builds on the “tried and true and pretty mature” method of absorbing the CO2 in a solvent in one column and subsequently stripping the CO2 from that solution in another column.
“It’s basically a closed system or a closed loop,” said Kelly.
“You’re pretty well just boiling it or heating it quite a bit to release pure CO2 off the top.”
Kelly said that that process stems from the decades-old practice of removing CO2 and other impurities from natural gas to bring it to pipeline quality. It is a very effective and efficient method at high pressure, but becomes very costly at regular atmospheric pressure.
“The bigger issue is the cost for … regenerating your solvents on the backside of the process,” said Kelly.
CO2 Solutions basically uses the same process.
“We don’t reinvent the wheel,” said Kelly.
“However,” he continued, “we use something called carbonic anhydrase, which is an enzyme. And carbonic anhydrase is present in all living organisms – you and I, bugs, animals, birds – and it manages CO2 in all living organisms.”
Carbonic anhydrase converts CO2 that is produced in the digestive tract into bicarbonate, which travels through the bloodstream to the lungs. The enzyme then converts the bicarbonate back into CO2 so it can be exhaled.
“Carbonic anhydrase is the most powerful catalyst for CO2 hydration,” said Kelly.
“We genetically modify [the enzyme] so we can use it in industrial processes,” he continued. “And then we use it in the solvents that are out there and have been used for solvent-based carbon capture.”
That system also utilizes the solvents that require less energy for regeneration.
“Efficient capture and a very energy efficient regeneration,” said Kelly. “Net effect of all that is you bring your cost to capture per tonne of CO2 down about 40 per cent compared to conventional technology.”
CFO and senior vice president of finance Thom Skinner explained that CO2 Solutions has been in existence for about ten years, but they have only been looking into applying their carbon capture technology to oil sands development over the past year or so, after previously focusing on emissions from coal-fired power plants and aluminum manufacturing facilities, two significant CO2 emitters.
The oil sands sector has shown interest in CO2 Solutions because burning natural gas to produce the steam used for steam assisted gravity drainage (SAGD) has made the industry the largest CO2 emitter in Alberta.
“It’s a $1.8 million project,” said Skinner.
Although the focus now is the oil sands, Skinner said that CO2 solutions is still interested in working with aluminum plants, as well as natural gas producers in the Horn River Basin shale gas play of northeast British Columbia where the resource has a high amount of CO2 that must be removed prior to piping the fuel to the consumer.
“It’s one thing to do it in the lab, but to do it in a pilot, you need the funds,” said Skinner. “And when you’re kind of a small cap company that runs with a couple of million bucks in the bank, you need the industrial partners to be able to take this forward.
“We’ll never get away from the fact that installing some form of CO2 capture is going to cost money. It won’t be free.”
Skinner suggested that there has to be incentives to capture CO2.
“If you can get the cost of capturing carbon down below what the carbon tax would be, than, economically, it would be more efficient for companies to invest in carbon capture technology than to pay the fine,” he said.
“Europe was very much into carbon credits and … carbon tax before the economy stumbled,” Skinner continued. “Australia has put in some very rigorous carbon legislation. They have a cap and trade system that’s going in. They have a carbon tax that’s in place now. They’re at the forefront. California has put in some of the strictest carbon capture regulations in North America, teaming up with a couple of other states and provinces – Quebec, British Columbia.”
Skinner noted that Canada is already topping CO2 emissions that had been forecast for 2020.
Additionally, energy demand is growing and fossil fuels continue to be the backbone of that industry.
“Wind is great. And nuclear is great,” said Skinner.
“But the only way to generate sufficient power to run the factories and to generate the electricity is going to be fossil fuel. And there’s no way around it. Because the demand is just increasing multifold.”
“I didn’t go from an energy executive to an environmentalist,” said Kelly. “I just think there’s an additional link in the energy supply chain that we’re going to have to be dealing with and that’s the management of the emissions of the use of fossil fuels. So, be it coal, natural gas or oil, we’re going to have to manage our carbon emissions. And I see that as the next big change in the energy industry.
“The management of our emissions.”
If the biggest obstacle is the cost of capturing CO2 at point sources such as oil sands operations or coal-fired power plants, one solution could be finding uses for the CO2 that is captured.
Those uses already exist.
“There’s a couple of different applications that Ferus provides for the use of CO2, one of which is hydraulic fracturing,” said Joe Ladouceur, vice president of external affairs and treasure at Ferus.
Liquid carbon dioxide is one of several fluids companies might pump into a natural gas well during fracturing.
“There’s different formations where liquid carbon dioxide has more of a beneficial impact,” Ladouceur continued. “Some companies will use it in combination with water or with nitrogen or just on their own. It really is a decision that’s made individually by the oil and gas companies as to which fluid they think is going to be the most effective in bringing up the gas or the oil and in making the well more valuable.”
Ferus obtains its CO2 from its production facilities in Alberta. The CO2 is typically from industrial processes such as natural gas processing.
“We’ll actually take that CO2 that you’re stripping out and, instead of you venting it to atmosphere or burning it, we will capture it,” Ladouceur explained.
“We’ll take a little pipeline off of your processing facility, we’ll capture it, we’ll put it through a cooling system, we liquefy it, and then we put it in trucks and we take it out and deliver it to the oil and gas community.”
A small portion of the CO2 that pumped into the well will stay in the ground, but the remainder returns to surface and can potentially be reused for hydraulic fracturing.
That might not make a significant impact in terms of mitigating climate change, but Ladouceur suggests that there are other environmental benefits to using CO2 in hydraulic fracturing.
“The primary alternative to using cryogenic fluids in a well is to frack with water,” said Ladouceur, noting the immense volumes of water that are being used to fracture natural gas wells in northeast B.C.
“You can use as much as 10 million gallons of water on a single well,” he said. “If you use a cryogenic with the water – CO2 or nitrogen – you can reduce that from 10 million gallons to 2 million gallons. So, that’s 8 million gallons of water that doesn’t come out of a stream, that doesn’t have to get disposed of.”
There are economic benefits as well.
“We have demonstrated to a number of our customers that the cost of CO2 or nitrogen is actually more economically beneficial in the long term … than actually purchasing water, coming up with a disposal system, trucking the water, having to reclaim the water,” said Ladouceur.
“Not only do you get the environmental benefit, but you will have cheaper cost in the long run because using cryogenics will actually give you more of your hydrocarbon product at the end of the process.
“After six months, you will be better off economically, because you’re going to be producing more gas and you’ll have less water disposal costs.”
Juergen Puetter doesn’t want to use CO2 to extract energy from the ground.
He wants to turn it into energy.
The president of Aeolis Wind and Blue Fuel Energy sees a tremendous future for methanol in a province that has a wealth of all the necessary ingredients: renewable energy in the form of hydro and wind; water from which hydrogen can be derived via electrolysis; and a huge supply of CO2 coming from natural gas processing plants.
That province is B.C.
“In the Horn River,” said Puetter, “ten [to] twelve per cent of the gas coming out of the ground is CO2. Companies like Spectra and others have big pipeline networks connecting the wells to processing plants where they remove the CO2 and the hydrogen sulphide and other impurities in the gas.
“The CO2 is emitted in very high concentrations … into the atmosphere from a point source.”
A stretch along the foothills between Hudson’s Hope and the Yukon border is the best wind energy resource in North America, according to Puetter.
The region also boasts two hydroelectric dams and a third one could be on the way in the not too distant future.
“With the Williston and the Peace Canyon Dam we’ve got close to 4,000 megawatts of generating capacity,” said Puetter.
Considering all these elements together, he had the idea to produce a liquid fuel from renewable energy – methanol.
“By using electricity, putting it in the water, essentially separating the hydrogen and oxygen from water, and then taking that hydrogen and combining it with CO2 over a catalyst, you make methanol,” Puetter explained.
“That technology is well known.”
However, the common practice as performed by companies like Methanex has been to convert natural gas into methanol.
“We also believe the same thing should be in B.C. and we’re working on that as well,” said Puetter.
“But we’ve now taken [it] a step further.”
Methanol can be used as a transportation fuel or transformed into gasoline over another catalyst.
“Then you have an ultra-low CO2, low sulphur, low benzene gasoline that you can just blend in the gas fuel pool,” said Puetter.
Ethanol derived from corn has been used to meet low carbon fuel standards, but that depends on having the right weather to produce a good crop, as well as be a complex issue in terms of the food versus fuel debate.
“It’s a very expensive process,” Puetter added. “It so far has only worked with government subsidies. And long-term, in our view, that’s not sustainable.
“You can make in B.C. a fuel that has much lower carbon content than ethanol.”
The fuel price would also stay low because the energy source would either by hydro or wind.
“Over time, the cost will go down,” said Puetter. “Because once you amortize a wind project or a hydro project, then it becomes heritage power. It becomes very cheap. So, over time, the cost of this fuel gets lower and lower, rather than higher.”
Puetter is planning to build a methanol plant of this kind in Fort St. John because of the access to renewable energy and CO2 in the region.
Also, when water is electrolyzed to produce hydrogen, a byproduct is oxygen that could be used in a conventional methanol plant that converts natural gas into the fuel.
According to Puetter, a plant that converts CO2 into methanol could produce 2,500 tonnes of oxygen per day.
“It would make sense to feed that renewable oxygen into an autothermal reformer that is fed by natural gas,” he continued.
Puetter said the North American methanol market could grow considerably with the Open Fuel Standard Act in the United States.
“There is a bill before congress in the U.S. to mandate that all cars manufactured in the U.S. starting in 2014 be able to burn any combination of ethanol, methanol or gasoline,” said Puetter.
Presently, vehicles allow for a small percentage of ethanol, but essentially run on a dedicated fuel.
“You can’t just mix and match as you want,” said Puetter.
“The Open Fuel Standard would cost about $100 or less per car and then you can put any combination in,” he added.
“Of course, the reason why that is so attractive for the US – different from Canada – is that by doing so the U.S. could become, literally overnight, independent of imports of oil into North America. Because there’s enough gas here and enough oil to basically fuel the entire transportation sector.
“We think there’s an incredible opportunity for B.C., because we have … a huge amount of gas.”
Methanol is also easy to transport to the consumer.
“It flows easily,” said Puetter. “It has very low viscosity. It’s basically like water.
“It’s much easier to transport – be it in pipeline or rail or truck – than gasoline or diesel or oil. Because if there’s a spill, it’s biodegradable. It’s not pressurized. It’s not explosive. It’s a really wonderful way forward.”
According to Puetter, the plant, if built, would take a 2,500 tonnes of CO2 out of the system every day, but would require almost as much energy as would be produced by BC Hydro’s controversial Site C hydroelectric project to do so.
“You would need hydro and wind power,” he reiterated.
Regardless, Puetter seems confident that his plan will come to fruition.
“We have done all the base engineering,” he said. “The technology review has been done by many outside sources. For example, the world’s largest engineering firm that builds these type of plants has [said] that what we’re proposing is entirely doable. They can built it and it works.”
The only obstacle is finding the right people to get behind the project, which is a bit of a problem considering the preoccupation with the promise of a liquefied natural gas (LNG) export industry rescuing the province’s natural gas industry from low commodity price and poor market access issues.
“This may be a much more reliable and actually financially more attractive alternative,” said Puetter, comparing methanol and LNG.
Blue Fuel Energy is trying to convince the oil and gas industry and the provincial government of the merits of the plan, suggesting that the government could take advantage of the royalty-in-kind concept to receive royalties in the form of natural gas rather than cash if it was involved in the operation of the plant
“If the price of gas goes up, the royalty goes up,” said Puetter. “So, the government is actually protected.
“I think it’s an incredible opportunity that’s staring us right in the face.”