Mine power system options of tomorrow are being shaped by the energy cost, availability and zero-carbon issues of today
By Russell A. Carter, Contributing Editor
High-quality, reliable electricity is a prime prerequisite for efficient mining. A site running on dependable but “dirty” power risks financial and physical-asset harm from degraded equipment performance, while an active mine that unexpectedly loses power essentially becomes a de facto ore storage facility until power is restored, while incurring production losses, equipment damage, cleanup costs, lower worker productivity and safety along with other related problems.
In the most efficient mines, energy costs typically can amount to anywhere from 10% to 30% of overall costs, but the price of energy inefficiency can be much higher. A mine that obtains electrical power from a source that pollutes, or pays too much for the power it needs, or uses power uneconomically, is short-circuiting its chances for success.
Although securing the lowest cost of electricity service while ensuring system reliability has always been a concern for mineral producers in remote or undeveloped areas, economic trends are now bringing even operations located in highly industrialized regions face-to-face with the same problem. For example, in late September, Mats Gustavsson, vice president for energy at Boliden, told the Bloomberg news service that the industry is looking at significant energy price increases. “Contracts will have to be renewed sooner or later. However they are written, you will eventually get hurt because of the situation in the market.
“Volatility is here to stay,” Gustavsson said. “What’s dangerous is that the lowest price is increasing all the time. So if you want to hedge yourself, you will pay a much higher price.” Boliden operates Europe’s largest zinc mine in Ireland, where EirGrid, the state-owned electric power transmission operator, recently warned of a generation shortfall that could lead to blackouts, according to Bloomberg.
And in mid-October, zinc/lead producer Nyrstar announced it was cutting production by up to 50% at its zinc smelters in Belgium, France and the Netherlands due to rising power prices. The company cited significant increases in the cost of electricity in recent weeks, and “the cost burden of carbon emitted by the electricity sector, which is passed on to industrial and domestic customers,” stating that it is no longer economically feasible to operate plants at full capacity.
Industry anxiety about price uncertainty is heightened by the prospect of increased competition for existing power services. The traditional gold standard for electric power service to mines and plants has been connection to a national or regional distribution grid, but what happens when too many customers vie for the finite supply of grid power to a certain area?
That was the problem facing gold producers in the Eastern Goldfields area of Western Australia. Grid capacity was at its limit as power to the area was restricted to a single 220-kV line that services the region. There was no additional capacity available to support the large energy loads required without compromising everyone else already connected to the network, according to Western Power, the region’s electric utility.
Instead of building a new, expensive 650-km-long transmission line to the region, Western Power developed an innovative approach for utilizing the available capacity on the network: the Eastern Goldfields Load Permissive Scheme (ELPS).
Announced in March 2021, the ELPS scheme provides an alternative energy supply by distributing the capacity when it’s available and then curtailing the supply when it is not. Now, when required, customers are automatically notified that they need to reduce their ELPS load within a set time. It’s claimed to be a mostly autonomous process managed out of the utility’s Network Control Center.
“As Western Power hasn’t been able to connect these large loads in the region, this has led to some miners going completely off grid. Others have made do with some power from the grid with the balance provided by expensive diesel generation costing approximately $1.3 million per MW, per year,” explained Pat Costello, ELPS program manager.
“Our forecasts show the ELPS service will still provide a high availability rate for our ELPS customers, without impacting existing customers in the Eastern Goldfields,” Costello said.
The scheme provides an option for larger customers to access power that ordinarily would not be available through traditional network solutions. Customers will have some upfront connection costs; however, according to the company, the potential for future savings is attractive, potentially removing the need for expensive on-site generation.
ELPS, said Western Power, includes configurable parameters to help enable connection to different customer installations. “We monitor scheme performance, have an operating protocol for each site, and have a dedicated network operations engineer and customer relationship consultant to oversee the service.
Where grid power is accessible, the savings gained from connecting to it in place of site-generated power can be significant. For example, Northern Vertex Mining Corp. recently completed a 6.9-mile electrical powerline project for its Moss gold and silver mine in Arizona. The mine is now linked to the Mojave Electric power grid, and the company said it is beginning to realize benefits that include reducing electrical costs from approximately $0.31 per kilowatt-hour (kwh) to a grid system cost $0.08/kwh. The move also eliminated the operational and maintenance cost of operating the diesel gensets, representing a savings of $15 million to $20 million over the life of mine.
Solar, Wind Plant Projects Gain Speed, Size
The cost, reliability, maintenance and environmental aspects of solar and other renewable power sources for microgrid applications are attractive to mining customers — and the numbers seem to become more appealing with every new solar project announcement. The declining cost of battery storage further strengthens the case for solar or wind power. During a recent webinar presented by Rolls Royce/MTU, Andrew Jones, sales director for microgrids, pointed to predictions of strong future growth in energy storage installations heading toward 2050, with an accompanying significant drop in battery prices (see graph below).
Mine-linked renewable-energy plants are coming online at an increasingly quicker pace — and getting larger. For example, Gold Fields Ltd. announced in May that it’s moving ahead with construction of a 40-MW solar plant at the South Deep mine in South Africa that will generate more than 20% of the average electricity consumption of the mine. Located on the mine’s property, it will comprise 116,000 solar panels and cover a 118-ha area roughly the size of 200 soccer fields.
The company estimated that the use of self-generated, renewable energy from the R660-million plant will translate into savings of around R120 million on the cost of electricity annually.
BHP is planning to build two solar farms and a battery storage system to help power the Mount Keith and Leinster operations in Western Australia, allowing the company to reduce its emissions from electricity use at the two sites by 12%, based on FY2020 levels.
The Northern Goldfields solar project will include a 27.4-MW solar farm at Mount Keith and a 10.7-MW solar farm and 10.1-MW battery at Leinster, displacing power currently supplied by diesel and gas turbine generation. This, according to BHP, will result in an estimated reduction of 540,000 mt of C02e over the first 10 years of operation.
Rio Tinto approved construction of a new solar farm and battery storage at Weipa in Queensland, which will reportedly more than triple the local electricity network’s solar generation capacity and help provide cleaner power to Rio Tinto’s operations.
Under the plans, power station operator EDL has been contracted to build, own and run a 4-MW solar plant and 4 MW/4MWh of battery storage at Weipa.
Rio Tinto also recently signed a power purchasing agreement for a new renewable energy plant to power the operations of its QMM ilmenite mine in Fort Dauphin, Southern Madagascar. The plant, to be built, owned and operated by independent power producer, CrossBoundary Energy (CBE), over a 20-year period, will consist of an 8-MW solar facility and a 12-MW wind energy facility along with a lithium-ion battery energy storage system of up to 8.25-MW reserve capacity.
The optics of moving away from total reliance on fossil-fueled power generation can serve to validate a company’s stated decarbonization goals. Again, the numbers are notable: A 1-MW solar plant typically produces 2,000 MWh annually, theoretically displacing up to half a million liters of diesel fuel. In a mixed-source power scheme increasingly typical of many mine setups, the fuel-cost savings provided by a solar plant can be bolstered by the ability to run conventional power plants at less than peak capacity, with associated maintenance cost reductions. Here’s an example:
In Mali, B2Gold’s Fekola gold mine completed construction of a 27-ha, 30-MW solar plant in June. Approximately 25% of the solar field came online on January and solar production reached 75% of full installed capacity by the end of March when the plant was turned over to the Fekola operations team. According to the company, solar power production with only 75% installed capacity exceeded daily baseline targets for the full project, with several days of fuel cost savings of more than $32,000 versus a goal of $25,000 per day, and replacement of up to 20% of the total daily power compared to a baseline goal of 18%.
The company said the mine’s existing heavy fuel oil (HFO) and diesel power plants have an installed capacity of 64 MW while Fekola’s expanded mill facilities require only approximately 40 MW for continuous operations. Consequently, the solar plant isn’t necessary to sustain the higher process plant production rate, but is expected to reduce Fekola’s operating costs and emissions by decreasing power plant fuel consumption and maintenance costs. When the solar project is fully commissioned, it is projected to reduce HFO consumption by more than 13 million liters per year and lower carbon dioxide emissions by 39,000 metric tons per year.
In December 2020, gold miner Newmont’s CEO, Tom Palmer, said the company plans to invest $500 million over the next five years, at a rate of $100 million per year, to study and implement solar, wind and energy storage technologies throughout its operations as it moves toward reducing its carbon emissions by 30% over the next decade, before reaching net zero emissions by 2050. According to Palmer, Newmont is currently looking at solar and wind installations, micro-grid technology and energy efficient equipment for its Peñaquisito mine in Mexico and Ahafo mine in Ghana, as well as at other locations.
And, Sungrow recently announced the signing of a contract to supply equipment to German EPC juwi for a 36-MW off-grid solar farm and 7.5-MW battery energy storage system at the Sukari gold mine operated by Centamin in Egypt. The installation will include a 1,500-V 6.25-MW PV inverter and highly integrated energy storage system with lithium iron phosphate (LFP) batteries, according to Sungrow, a Chinese solar inverter developer and supplier.
Proof of Performance
Renewable sources aren’t holding all the cards, however. The unpredictability of solar and wind energy sources can adversely affect power availability and grid stability, and they must prove they’re capable of meeting grid performance requirements that diesel-powered generation mastered many years ago, such as frequency and voltage control, adequate spinning reserve, peak shaving, load leveling and load sharing between units.
Diesel-powered genset suppliers can make a strong pitch for including internal combustion engines in a microgrid setup, citing advantages such as:
• A smaller physical footprint than current renewable-system choices;
• Instant power when needed;
• Redundancy, avoiding dependency on just one source of power;
• Much lower particulate and NOx emissions from Tier 4 diesels than previous engine technologies.
However, although hydrocarbon fuels have long provided dependable energy for industrial heat, power and mobility, it seems reasonably likely that the industry’s drive to decarbonization will be fueled by a non-carbon molecule — hydrogen. In fact, during a recent webinar sponsored by Canadian law firm Fasken, Bob Oliver, CEO of H2GO Canada, said after talking with economists that had studied various energy scenarios, he determined there’s “no pathway to zero (carbon} without hydrogen and fuel cell technology.”
“The marginal cost of emitting carbon into the atmosphere is rising exponentially, so we need carbon-free sources of energy — and that brings us to hydrogen, Oliver said. “Twenty years ago, hydrogen technology wasn’t ready for prime time.”
That has changed, according to Oliver, noting that currently there already are as many as 40,000 hydrogen-fueled forklifts operating at logistics centers across North America. He predicted that if appropriate hydrogen distribution chains are set in place, the current high price of hydrogen will fall to a level that can compete with conventional hydrocarbon fuel sources.
According to Oliver, mine operators need to take the prospect of turning to hydrogen power seriously: “When heavy industry is confronted with the prospect of taking their carbon intensity to zero or near zero, the viable pathways begin to collapse pretty quickly to just a few options.”
His advice to the mining industry: “First, you electrify everything that you can. And for processes that can’t be electrified, hydrogen normally can fill the gap.”
With major mineral producers such as Anglo American, Rio Tinto, Antofagasta and Fortescue experimenting with various forms of green hydrogen generation and utilization, heavy-duty engine suppliers are also hedging their bets in anticipation of a changing energy-fuel mix to power mobile assets as well as stationary power operations.
Rolls-Royce, for example, recently said it is further developing its MTU gas engine portfolio for power generation and cogeneration to run on hydrogen as a fuel. Currently, gensets powered by MTU Series 500 and Series 4000 gas engines can be operated with a gas blending of 10% hydrogen. Beginning in 2022, operation with a hydrogen content of 25% will be possible, according to the company. Rolls-Royce will continuously market new MTU Series 500 and Series 4000 gas engines beginning in 2023 for use with up to 100% hydrogen and will offer on a design-to-order basis conversion kits to allow already installed gas engines in the field to run on 100% hydrogen.
Rolls-Royce also has expanded the recently acquired, Berlin-based Qinous GmbH into a Microgrid Competence Center. The company said that, as a center, it will see more group investment in its distributed energy systems business, which ranges from simple storage solutions to complex microgrids that intelligently combine battery storage with renewable energies, and with diesel or gas gensets, according to Andreas Schell, CEO, power systems division.
In early September, Caterpillar announced it will begin offering generator sets capable of operating on 100% hydrogen on a designed-to-order basis in the fourth quarter of 2021. Caterpillar also said it will launch commercially available power generation solutions from 400 kW to 4.5 MW in 2021 that can be configured to operate on natural gas blended with up to 25% hydrogen.
Caterpillar will begin offering the G3516H gas generator set specifically configured to use 100% hydrogen for fuel in late 2021. Initially available as demonstrator units in North America and Europe with initial deliveries in late 2022, the G3516H generator set will be available with a rating of 1250 kW for 50 or 60 Hz continuous, prime, and load management applications.
Caterpillar will also begin a staged roll-out of commercially available CG132B, CG170B, G3500H, G3500 with Fast Response, and CG260 gas generator sets configured to enable operation on natural gas blended with up to 25% hydrogen for continuous, prime, and load management applications in North America and Europe. Additionally, the company will offer retrofit kits that provide hydrogen blending capabilities up to 25% hydrogen for select generator sets built on these engine platforms. Production of new natural gas generator sets and retrofit kits capable of 25% hydrogen will begin in the fourth quarter of 2022.
Both Liebherr and Cummins are developing hydrogen-powered heavy-duty engines. Liebherr is working with Mahle Group’s Powertrain subsidiary, which provides engineering and consultancy services for the design, testing, development, calibration and integration of electrified powertrain systems and hybridized internal combustion engines. Liebherr recently reported that tests involving hydrogen-fueled model H966 and H964 engines delivered favorable results in terms of combustion speed, performance and emissions.
Cummins also has been testing a hydrogen-fueled internal combustion engine. Srikanth Padmanabhan, president of the company’s Engine Segment, said, “We are using all new engine platforms equipped with the latest technologies to improve power density, reduce friction and improve thermal efficiency, allowing us to avoid the typical performance limitations and efficiency compromises associated with converting diesel or natural gas engines over to hydrogen fuel.”
Nuclear power might not be the first concept to come to mind when compiling a list of alternative energy sources for mines, but it’s definitely on the radar screen of some operators and governmental organizations — particularly in Canada, where the federal government is actively promoting the study and use of small modular reactors (SMR), as their name implies, are designed to be modular and mostly factory-built, providing scalability to specific energy demands. SMR designs vary in electrical output from as high as 300 MWe per module for grid-connected reactors, down to 3 MWe per module (or even smaller for micro SMRs), which could be suited for remote or industrial applications.
In 2018, Natural Resources Canada, the government agency responsible for energy, minerals, metals and other resources, launched Canada’s SMR Roadmap, described as a pan-Canadian dialogue on SMRs with provinces, territories, utilities and stakeholders to chart a vision for the next wave of nuclear innovation in Canada.
According to the Roadmap’s official website, Canada has one of the world’s most promising domestic markets for SMRs. Conservative estimates place the potential value for SMRs in Canada at $5.3 billion between 2025 and 2040. Globally, the SMR market is much bigger, with a conservative estimated value of $150 billion between 2025 and 2040. This represents a large potential export market for Canada, which has already exported nuclear reactor technology to six other countries.
As part of the government’s ongoing interest in SMRs for mining applications, Canadian Nuclear Laboratories, which manages and operates Atomic Energy of Canada’s sites nationwide, recently released the results of a study that presents a favorable case for combining SMRs with conventional diesel generation to provide power at remote northern mine sites.
The study was conducted by a group of organizations that included CNL, MIRARCO, Ontario Power Generation and an unnamed mining partner. The goal was to determine vSMR (very small nuclear reactor) requirements — electricity and heat demand curves/seasonality, life of mine — from the perspective of a mining company that operates in the far North.
The team calculated the economic competitiveness of vSMR deployment under four scenarios: 1) diesel generators only; 2) vSMRs only; 3) vSMRs and diesel generators; and 4) vSMRs, diesel generators, wind turbines and battery energy storage. The energy system with vSMR and diesel generators was found to be the most economic. In this scenario, the vSMR provided baseload electricity to the mine site (approximately 90% of annual demand), while the diesel generators covered peak loads (approximately 10% of annual demand). The heat demand was met through a combination of diesel cogeneration (capturing waste heat) and nuclear heat; no diesel-fueled burners were required to meet heat demand. This scenario resulted in an 85% reduction in CO2 equivalent emissions compared to diesel only.
Although the vSMR-only scenario eliminated all CO2 equivalent emissions from energy production, it also resulted in a relatively high levelized cost of energy (LCOE), a measure of the average net present cost of electricity generation for a generating plant over its lifetime. This was in part due to the high CAPEX of the SMRs, the highly seasonal demand and the ramp up of production over several years, which resulted in unused capacity of the reactor during periods of low demand.
Initially, both solar panels and wind turbines were considered as potential sources of variable renewable energy. It was quickly determined that available solar energy in the region was a poor fit for energy demand at the mine site, since peak generation is expected to occur during seasons of low demand (i.e., summer). Therefore, only wind energy was considered. The addition of wind turbines in a scenario did reduce the CO2 equivalent emissions from energy generation; however, it required additional infrastructure (battery, reserve diesel capacity) to manage the variability of supply, which came at an additional cost.
Interest in SMRs extends beyond Canadian borders. In September KGHM, the Polish copper miner, signed a joint commitment with NuScale Power, a U.S.-based producer of SMRs, and PBE Molecule, a Polish consulting firm, to develop SMR technology.
Under the agreement, NuScale will support KGHM with the implementation of SMR technology to replace existing coal-based energy sources and provide power to the miner’s production plants. The venture involves development and construction of four SMRs, with the option of up to 12 (with installed capacity of around 1GW), which, according to KGHM, potentially could be the largest installation of its type in the world. Completion of the project is expected by the end of 2030.
KGHM’s strategy, aimed at achieving half of the company’s power needs by its own internal sources by 2030, also involves construction of PV plants on the grounds of its facilities and developing offshore wind farms in Poland.
Envisioning the Electrified Mine
The vision of what an electrified mine of the future will look like is not yet totally in focus, with industry supplier and producer segments often viewing the emerging image from different perspectives ranging from pragmatic approaches, such as Sandvik’s “rethink the machine, not the mine” philosophy for its electrified mining equipment, all the way to “start from clean sheet” initiatives sponsored by mineral producers, research organizations and other interested parties.
From Sandvik’s point of view, a critical issue in the electrification of mining is to optimize charging and energy use to ensure that battery-electric machines are as productive or more productive than their diesel-powered counterparts. Sandvik addresses that issue with its own self-swapping battery technology, which meets its productivity goals while easing and smoothing a mine’s power supply requirements throughout a typical shift.
“It is really going after the infrastructure impact of refueling,” said Brian Huff, vice president of technology and product line, battery and hybrid electric vehicles at Sandvik. “Swapping batteries means you can charge batteries at the same rate that you are using the energy, mitigating the peak power draws from the infrastructure, minimizing the amount of charging power that you need, and really optimizing all of your equipment.”
Electrification solutions from Epiroc, meanwhile, are aimed at supporting mining customers in their transition to battery-electric vehicles, including Batteries as a Service (BaaS) designed to eliminate the risks of owning batteries; and battery conversion kits. The recent acquisition of Meglab will strengthen its capacity to provide customers with the infrastructure required as mines transition to BEV, according to the company.
Clean-sheet studies, such as the Scalable and Adaptable Mining Challenge announced by OZ Minerals in partnership with Canada-based Inspire Resources and Unearthed — a community of startups, developers, and data scientists focused on making the energy and resources industry more efficient and sustainable, according to its website — are aimed at uncovering fresh thinking linked to the concept of flexible, modular mine design. The challenge is focused on finding solutions that could be deployed as part of an integrated mine design and includes a cohort of participating organizations such as Komatsu, Sepro Mineral Systems, juwi and others.
Katie Hulmes, general manager, transformation at OZ Minerals, explained: “Today’s mining projects favor economies of scale, resulting in large projects that are capital intensive with bespoke designs and little flexibility. Traditional project valuation processes don’t place a value on flexibility. We are looking to explore the concept of modularity as an enabler of flexibility and new models for project valuation, asset ownership, development and operation. We are curious to discover if flexible, modular architectures might unlock future assets that are currently uneconomic.”
Tools for Management
Whatever form future mining might take, it’s clear site electrification will significantly increase the importance of power management, and with more solar, wind, fuel cell and hybrid system facilities entering the mainstream, the need for real-time control and analysis provided by advanced digital technology will become increasingly essential for efficient, reliable microgrid operations. Adaptability to the variable power needs of a mine will be a crucial performance feature for microgrid controllers.
For example, Barrick Gold recently collaborated with Caterpillar dealer Tractafric to install 7.5 MW of battery energy storage capacity for a microgrid at the Kibali gold mine in the Democratic Republic of the Congo. The mine generates 45 MW of power from three hydroelectric power stations and 36 Cat 3512 diesel generator sets.
Tractafric’s solution deploys the battery energy storage and Cat bidirectional power inverters (BDP) to provide grid stability. Caterpillar said its grid stabilizer offsets the cyclical loading of the mine’s winding plant to reduce the spinning reserve requirement, which decreases annual diesel consumption by approximately 3 million liters and the associated carbon dioxide emissions by an estimated 8 kilotons.
The mine uses Cat’s Master Microgrid Controller to integrate output from the various power sources. According to Cat, its MMC can be configured to optimize overall performance based on user-defined criteria. The optimization can be based on a number of different parameters, such as minimizing fuel cost, optimizing engine operation, or maximizing system reliability. The system may also be configured to provide a minimum level of spinning reserve online to respond to sudden load transients. In a hybrid microgrid such as the Kibali setup, the MMC will determine the correct energy contribution from each of the distributed energy resources. Priority for distributed resource use can be changed from the MMC user interface.
Earlier this year, ABB launched ABB Ability eMine, a portfolio of solutions that it claims will help accelerate the move towards a zero-carbon mine. The company explained that eMine comprises a portfolio of electrification technologies, which makes the all-electric mine possible from mine to port and is integrated with digital applications and services to monitor and optimize energy usage. It can electrify any mining equipment across hoisting, grinding, hauling and material handling. Beginning in 2022, it will include ABB’s Ability eMine FastCharge, which provides high-power electric charging for haul trucks and is currently in pilot phase.
ABB said eMine provides integral design planning and thinking to maximize the value of electrification, helping to design the hauling process in the most optimized way with electrical solutions that match mine constraints and help meet production targets. ABB helps mine operators map their journey toward an all-electric mine from phasing out diesel to embedding a new mindset and new team skills. By fully integrating electrification and digital systems from the mine to the port, eMine further reduces overall costs and improves mine performance while significantly lowering environmental impact, according to the company.
Making the Switch
The needle on the industry’s power meter is moving swiftly in the direction of mine electrification, pointing to opportunities for decarbonization, reduced maintenance and underground ventilation requirements, and both short- and long-term financial benefits, such as a move to renewable energy technologies that allow phased installation and capacity growth, thus cutting upfront capital costs.
But a shift to adopt renewable energy sources is a one-way street. Due to investor and social pressure, there will likely be no viable fallback options to return to hydrocarbon-fueled power dependency if a company stumbles on the route to its committed decarbonization goals. A recent blog article authored by Jim Spenceley, senior vice president with Black & Veatch’s mining business, and Victoria Gosteva, strategy and business development director-mining, although aimed primarily at development of electrification of mobile equipment, actually illustrates the demanding road ahead for mine-wide electrification.
“Solutions will require innovative ways of collaborating and combining resources between miners, OEMs and EPCM integrators with diligent business case assessments, piloting programs, as well as significant mobile equipment and infrastructure investments. An approach involving staging RE and electrification energy infrastructure solutions in correlation with the mine and existing equipment life cycle, and scaling up pilot projects, while keeping an eye on the ultimate carbon reduction goals, will require the rigor and attention that mine development and management have not previously seen,” the authors warn.
Costs, Convergence and Concerns for Efficient Mine Power
In the absence of main-grid availability or reliability, or from a desire on the part of producers to control their own power distribution and costs, the industry’s embrace of microgrids and other nonconventional power schemes is gaining strength on an almost weekly basis. E&MJ asked Jason Hartley, senior vice president-customer success at Hitachi Energy (formerly Hitachi ABB Power Grids), to comment on some of the main issues and opportunities associated with localized power generation.
E&MJ: Are there economic justifications for a mining company to disconnect from the main grid in favor of local control of its power?
Hartley: I’ve been involved with operations that act as the regional power distributor on behalf of the government. Given the remoteness of many operations, localized control is often the only option. Outside of a forced-localized scenario, localized control can provide a number of benefits.
Mines with their own energy grid can improve resiliency, reduce reliance on diesel, and lower operating costs. Overall, microgrids can lead to higher uptimes, improve gross margins, and reduce CO2 emissions. Mine operators with their own grid can do this more easily than with other forms of energy management and optimization. Long-distance transmission and integration of renewables is difficult without microgrids, which requires in-house expertise.
Each mine has individual considerations for their energy source. The amount they can invest, their timeline and their location will drive some decisions around power, whether it’s localized or not. Larger mines tend to embrace generation more so than smaller ones as energy generation can be cost-prohibitive, especially considering cost fluctuations.
However, I suspect we’ll see a shift to localized over time as it helps mines take control to manage costs, improve reliability and reach their environmental targets.
Many mines face uptime challenges when they rely solely on the main grid. It’s usually a best practice for them to have their own generation backup. There’s also a potential profit from mines owning and running their own renewable generation as they can sell it back to the main grid.
E&MJ: If a mining company is interested in decarbonizing its operations and increasing electrification of its conventional assets, what are the main steps it needs to consider for an incremental transition to a hybrid power system?
Hartley: The steps to transition to a hybrid power system will depend heavily on the operation. For example, you need to start by considering what form of system to move to. For transportation within mines, you’ll need to consider battery electric vehicles, a trolley system, hydrogen fuel cells and more. The choice will depend in part on the mining method, whether an open-pit or underground operation. Open-pit mines are looking more at trolleys, while underground mining often looks at battery electric vehicles.
Mines also need to consider how to store the power and where. Then there are considerations for charging infrastructure and where to locate it to minimize impact on operations. You then need to factor in what amount of redundancy you want.
The list and considerations are extensive. Yet I do see hybrid — and microgrids — as the future of mines’ energy infrastructure. The opportunity is especially good for larger mines with a lot of land. They can develop solar or wind farms on their land and pair it with battery energy storage systems. Not only does this improve mines’ reliability and reduce their carbon footprint, the mine can also sell surplus capacity to the grid, lowering operating costs.
I do want to note that historically mines have had their own sources of native generation. Many mines want to be able to “island” off the main grid if necessary. However, mines run into problems with this when they haven’t modernized their energy and generation assets. Pollution controls might mean mines can’t operate all the time. There are also issues with grid stability if they haven’t updated the primary and secondary equipment and controls. It’s important to keep the microgrids modernized so that when mines need to fire up their own generators and try to island off, they can do so.
E&MJ: Are mining companies starting to recognize a need for convergence of their power sourcing and distribution schemes with their IT resources to assure maximum effectiveness and minimal risk?
Hartley: The merging of process control and generation assets to optimize is now key. IT makes that collaboration possible from pit to port. In particular, larger mining operations rely on a mix of energy resources, from batteries to renewable energy, and they need modern network management and SCADA system to integrate data flows and optimize operations.
The amount of data mines will need to process — especially as they leverage microgrids — will increase continuously. IT can capitalize on that data and help mining companies digitize and automate operations.