Diesel Displacement for Mines - LNG, Small Nuclear, Green Hydrogen and Small Hydroll

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Diesel Displacement for Mines - LNG, SMALL HYDRO, GREEN HYDROGEN AND NUCLEAR

by MELODIE MICHEL Reporter, Energy and Mines

When it comes to reducing diesel consumption by mines, there are many things to consider. Do you use diesel to power the mine, in your fleet, in your processing? Where is your site and what access do you have to renewable energy? What’s your budget and mine life? While solar, wind and storage solutions are gaining steam, other options can also help mines achieve a more sustainable energy mix, or even increase their renewable penetration.

Some, like liquefied natural gas (LNG) or hydroelectricity, have been around for decades, and are now being modernized or improved to better suit the need of mining clients. Others, such as green hydrogen or small modular reactors (SMRs), are in their infancy, but hold enormous promise among large industry.

LNG - An easy and efficient switch (for most)

While still a fossil fuel, LNG is cleaner than diesel; in conventional cars, the US Department of Energy estimates that LNG produces about 10% less GHG emissions than gasoline. In mining trucks, Energir has noted a GHG reduction of up to 25% for vehicles switching from diesel to LNG. Energir supplies Stornoway Diamond with natural gas to power the Renard Mine in Quebec, and there, the LNG solution, combined with a heat recovery scheme, helped the site achieve GHG reductions in the order of 42%. LNG An easy and efficient switch (for most)

Using LNG instead of diesel also tends to bring financial benefits, since LNG’s pricing structure is not as vulnerable as diesel to commodity price volatility. Guillaume Brossard, LNG business development director at Energir, explains why: “Almost all of the elements of pricing in LNG are fixed, except for the commodity itself that accounts for about 25% of the total price. If the molecule fluctuates a little bit, you almost won’t see it on your final price. On the other hand, if you use diesel, the commodity accounts for 75% of the total price, and it is much more volatile.”

This allows for better budgeting and the maximization of the mine’s financial viability which, in an industry as cyclical as mining, is a real plus. However, in order to calculate LNG pricing, one must think about how the natural gas will get to the site. If the mine is located close enough to a pipeline, connecting to it will be the best options. In other cases, the natural gas is usually delivered by road.

Champion Iron Mines has reduced GHG emissions by about 30,000 tonnes over the past two years, through energy efficiency projects, including a transition from fuel oil to electricity for steam generation using an electrode steam boiler, the commissioning of a 3.5 km long conveyor for crushed ore material transportation (offsetting the equivalent of two 240-ton haul trucks) and increasing the tailings pumping capacity to reduce handling and hauling operations using diesel-powered heavy equipment. Now, the company is looking to go further in displacing fuel oil and diesel, and LNG is one of the options being considered. Alexandre Belleau, general manager of projects and innovation at Champion, points out that the firm could partner with others in the region to bring LNG transportation costs down. “Pricing is really a matter of volume,” he says. “Assuming that we’re the only ones in the region to use LNG, right now the price would be fairly similar to fuel oil and diesel, but as soon as other companies start to use it in our region, it would probably be around 30% cheaper.”

This is because Champion’s mine is located in Quebec, a province with central production and distribution of LNG. That’s not always the case, and even then, getting the gas to remote places can be tricky: Brossard explains that in the far North of Quebec, where road access may not exist, LNG would have to be transported by boat, which can be challenging both in terms of cost and logistics.

But even with easy access to the LNG itself, there can still be obstacles to fuel switching. In the case of Champion, most of the diesel used on site is consumed by the fleet, and while trucks can run on LNG, they require adjustments — and these are not always available. “Right now the main challenge in using LNG for haul trucks is that the technology to do the retrofitting is limited. Caterpillar has a kit for our trucks, but only for a specific series, which is currently phasing out as it’s reaching its end of life. There is one other market option but that generates some technical support concerns, and would also void the warranty that we have with Caterpillar,” says Belleau.

So while the company continues to look for fuel alternatives for its fleet, it is focusing more on the retrofitting of its remaining diesel boilers. “We could swap 100% of our diesel consumption for heating to LNG, resulting in about 30% reductions in GHG. We’re looking at this right now,” he adds.

Overall, LNG is a solid option for diesel displacement: it’s widely available and brings environmental and financial benefits. And with current investment into renewable natural gas (a type of biogas) picking up pace, mines fitted with LNG equipment could soon be well positioned to switch to 100% carbon-neutral fuel.

Summary

GHG REDUCTION: 10% to 40% (with efficiency improvements)

FEASIBILITY: High

EQUIPMENT NEEDED: Retrofitting kits (available on certain trucks); LNG storage tanks; gas generators for power

SAFETY CONSIDERATIONS: Cryogenic, little training required

FINANCIAL VIABILITY: Proven

Green Hydrogen - Standardization and milestone pilots

There’s been a lot of hype around hydrogen fuel cells in recent years: tier one miners such as BHP and Rio Tinto are investing in research and development, electrolyzer prices are going down, and some governments are actively trying to define standards and regulations for its use as a replacement fuel in trucks. Natural Resources Canada (NRCan) is one such government body, producing guidelines and studies, and organizing tests to determine the conditions under which hydrogen fuel cells can be the safest and most productive.

Dr. Marc Bétournay, principal research scientist at NRCan, says his work has been focused mainly on underground applications, since they require more safety and ventilation provisions than on the surface. Since the start of the 2000s, he and his team have set up various mining consortia with names such as Newmont Goldcorp, Barrick, Glencore, Vale, IAMGold and Anglo American, to set up pilot projects and refine Canada’s standardization efforts. Based on this work, NRCan is now involved in developing the mining portion of the Canadian Hydrogen Installation Code (CHIC), a national standard first published in 2007 to regulate surface hydrogen infrastructure. The updated version of the CHIC with the mining portion will come out in about two years, marking a turn in hydrogen standardization efforts.

Recent research suggests that hydrogen is on the brink of becoming an affordable solution

Canada is also working with Australia, South Africa, Chile and other mining countries to make sure the regulations developed in each one of them are com- patible with the others. “It’s going to be tough to have the same regulations from country to country but the essentials will be there and we’re working very hard to make sure all countries will have similar mining regulations with respect to hy- drogen,” Dr. Bétournay says.

Once the industry scales up, renewable hydrogen could be produced from wind or solar power for the same price as natural gas in most of Europe and Asia

So what are the benefits of using hydrogen instead of diesel, and why are government and industry working so hard to make it commercially viable? There are three types of hydrogen: brown or grey (made from natural gas, therefore emitting CO2), blue (also made of natural gas but with carbon sequestration and reuse at the production site), and green (which uses renewable electricity as a base). Out of these, green hydrogen is the most attractive, since it is 100% clean, but it is also the most expensive to produce, with the International Energy Agency estimating its price around US$3.90 and US$5.50 per kg (compared to around US$1.70 a kg for brown hydrogen).

However, recent research suggests that hydrogen is on the brink of becoming an affordable solution: in an August 2019 report, Bloomberg New Energy Finance (BNEF) predicted an 80% drop in its cost of production by 2030. “Once the industry scales up, renewable hy- drogen could be produced from wind or solar power for the same price as natural gas in most of Europe and Asia. These production costs would make green gas affordable and puts the prospects for a truly clean economy in sight,” Kobad Bhavnagri, BNEF’s head of special projects, says in the report.

Already, green hydrogen is increasingly being considered as part of the energy mix for large greenfield mines: Glencore started pro- ducing it about three years ago from the excess energy provided by wind turbines at the Raglan mine. Now, the second part of the pro- ject is underway: according to Dr. Bétournay, who has worked with Glencore on the initiative, Hydrogenics is going to build a hydrogen refuelling station on surface at the mine, and the 50-tonne hauling trucks will be retrofitted with hydrogen fuel cells to transport ore from the mill to the port some 200 km away.

Hydrogen fuel cell provider Ballard is also working with “a major mining company” to build a mining truck transporting material from the extraction site to the processing site. “The idea is to install renewable energy all around the mine, wind and solar, which will meet the entire mining operation’s energy demand,” explains Nicolas Pocard, director of marketing. “If you want to meet peak demand, you have to oversize your renewable production, and as a result you get a lot of stranded renewable energy, which you can convert into hydrogen on site and turn it into zero-emission fuel which can be used on the mining vehicles.” The first truck will be in operation by the second half of 2020, and if successful, the scheme will then be rolled out to the whole fleet.

For now, green hydrogen as a replacement for diesel in mobile equipment is only a solution for mines with a long life and ample renewable energy capacity. Pocard says a holistic approach is needed. “If you just want to do vehicles, that’s not going to be cost-effective, unless you have a hydrogen industry nearby. The right approach is to figure out what is the role of hydrogen in your operation, and how you can integrate it into your overall energy systems,” he adds.

SUMMARY

GHG REDUCTION: 100% (for green hydrogen)

FEASIBILITY: Dependent on renewable capacity or access to centralized production

EQUIPMENT NEEDED: Hydrogen storage tanks, retrofitting available on hybrid trucks

SAFETY CONSIDERATIONS: Highly flammable, air flow critical to safety

FINANCIAL VIABILITY: Improving rapidly

SMALL HYDRO : From flowing rivers to dirty water

Water is a well-known power source: in many parts of the world, the utility grid is fuelled by electric dams. But for remote mines, there is a less invasive solution: small hydro. It consists of turbines that can be installed on almost any body of water near the mine, providing reliable renewable power. Compared to solar or wind power, hydroelectricity generation is more stable and can be used for baseload, though seasonality is a factor.

Mining energy consultancy THEnergy is currently working with two German universities on the SmartH2O Energy Project in Peru, where the feasibility of small hydro solutions to displace diesel in remote mines is being tested. Managing Director Thomas Hillig explains that while hydropower has typically been installed on rivers in the past, the technology is evolving.

“The project is about applications that have never been used before, so for groundwater, process water, water that is in the pit. The system could also be used as an alternative for storage. We’re looking at the technical aspects of that.”

In 2018, Gilkes installed a hydropower system at Anglo Gold’s Sadiola Mine in Mali. It is made of a containerized turbine that replaces the function of a pressure-reducing valve, extracting energy from the raw water supplied to the mine and village. Because of its small size and ability to be packed into a shipping container, the system was mostly built before being installed on site, reducing installation time. “That was a very small project, around 150 kW,” says Gilkes head of sales Andy Eaton. “They put it in because they were pumping water from a reservoir some 100 km away. They realized they could put a small hydro unit on the end of it, and that’s what we did.” He adds that in this case, water quality does not matter, because the turbine installed can handle sand and filthy water. This means that in the future, mines could even use their tailings to produce electricity.

It’s actually more expensive than solar per kW capacity, but then you get more stable generation

“The tailings are more rocks than actual water, but again, we believe that the Turgo Impulse machine would be a good solution for that. In order to bring it to market, we would need to trial it, put it on a mine and see how it works, so we need to do a partnership with somebody to move forward with it,” Eaton says.

Compared to large hydro schemes, small hydro doesn’t require big construction work or human displacement. While each site is specific, Eaton notes that payback varies between two and seven years, and can displace diesel completely throughout the mine life.

In fact, the long-lasting character of small hydro could even be seen as an obstacle by miners: “With the limited lifetime of the mine, there can be a bigger conflict than for solar or wind power, that’s the downside. But there’s already a good business case today. It’s actually more expensive than solar per kW capacity, but then you get more stable generation,” Hillig points out.

Of course, a thorough environmental assessment must be conducted, and hydropower is more site-specific and may require more planning than other renewable options. But it could be a worthwhile investment, replacing diesel as the baseload power provider and even presenting storage capacity.

Hydroelectricity has suffered a drop in interest in the past few decades, but as miners start to focus more and more on holistic and sustainable energy generation, small hydro schemes could become instrumental in the journey to zero-emission power.

SUMMARY

GHG REDUCTION: 100%

FEASIBILITY: Highly dependent on location

EQUIPMENT NEEDED: Hydropower turbines

SAFETY CONSIDERATIONS: Low risk

FINANCIAL VIABILITY: Proven

SMRs: Modularity and reliability

The last diesel replacement option this article will explore brings back a clean but somewhat controversial type of energy to the table: nuclear. Small modular reactors go from 5 MW to 300 MW in size, more than three times smaller than regular nuclear reactors, and a lot of hopes are pinned on them. In Canada, NRCan has developed an SMR roadmap to help these systems reach commercialization.

Diane Cameron, director of NRCan’s nuclear energy division, explains that there are three key reasons for the strong interest in SMR applications as diesel replacement for remote communities and mines. The first is cost: “The analysis indicates that SMRs could provide a 20 to 60% cost reduction compared to diesel,” she says. The second is logistics: “Diesel supply chains are very complex and prone to disruption. Some SMR units can come pre-fuelled for 20 years and function like a battery. At the end of its life, you remove it for decommissioning at a central location by nuclear experts and you plug in a new one. The promise of much simpler logistics would provide greater energy security,” she adds. And of course, there is the fact that SMRs produce zero GHG emissions. This solution’s biggest strengths are its reliability and modularity. “Nuclear reactors supply very reliable generation output as well as stability in pricing with a fixed-cost model with an offtake contract, allowing for certainty around costs. With the modular aspect of it, if you realize that in the end, you need to add to the size of your electricity production, you could put in a second module. And if at the end, you have figured out a way to extend the life of your mine and need power for longer, again, you could bring in another module,” says Eric McGoey, Ontario Power Generation (OPG) director of remote generation development.

OPG has partnered with SMR developer Global First Power to construct and operate a commercial demonstration unit at Canadian Nuclear Laboratories’ Chalk River site in Ontario. The proposed 5 MW electrical, 15 MW thermal reactor will serve as a model for the future — to demonstrate the viability of the technical and commercial application of the Micro Modular Reactor (MMR) design. Additionally, it will be the first time an SMR has gone through the environmental assessment and licensing processes in Canada.

Further West, a small town in Manitoba is also working on a commercial demonstration site for SMRs. Pinawa is the site of the former Whiteshell nuclear laboratory, which is being decommissioned but still holds a nuclear licence. “This gives us a huge advantage in hosting one or more demonstration reactors at our site,” says Mayor

Blair Skinner. “Remote communities and mining companies are interested in the possibility for an SMR to provide the power they need, but they don’t want to be the first to have one. There needs to be a working demonstration to show that the technology is safe and reliable, that the estimated costs are as forecast, and that it’s able to follow the load: those kinds of issues need to be tested in real life, and that’s where we come in,” he adds.

Part of the promise of SMRs is that they can integrate with renewables: the models in development are being designed to integrate as seamlessly as possible with variable renewables, such as solar. When the solar panels are generating electricity, the reactor could slow down, and when it gets dark at night it can increase power to compensate. “Because there’s been so much investment in wind and solar around the world, this is a strong advantage, because not only will these investments not be wasted, but they will actually be maximized as SMRs would compensate their variability. And the more power you produce with solar and wind, the longer you extend the life of the fuel in the reactor, so it’s a win-win,” says Skinner, adding that wind and solar providers in Manitoba are interested in partnering in the Pinawa project.

According to Cameron, mining executives are extremely interested in the solution; in fact, many have indicated that they would already buy it now if it were available. But while SMRs have been used for decades in military applications, commercial interest is recent and requires more testing and fine-tuning, which is why demonstration plants such as Chalk River or Pinawa are crucial. And even though they are rare, high-profile nuclear accidents such as Chernobyl or Fukushima may increase the need for community engagement — though a recent poll conducted by Abacus Data shows that public acceptance is high, at least in Canada: only 13% of the people surveyed expressed opposition to them being used as a replacement for fossil fuels.

SMRs are a potential game-changer in the world’s clean energy transition, but it is likely to take another five to ten years to see the first commercial units deployed on mine sites. Stay tuned.

Summary

GHG REDUCTION: 100%

FEASIBILITY: High

EQUIPMENT NEEDED: Small modular reactor

SAFETY CONSIDERATIONS: Safety training required, decommissioning and waste disposal critical

FINANCIAL VIABILITY: Yet to be determined, but expected to be high