What is Waste-to-Energy (WTE)?
Ecologically Sound, Cost-Effective Energy
Waste to energy (WtE) is a vital part of a strong and sustainable waste management chain. Fully complementary to recycling, it is an economically and ecologically sound way to provide a renewable source for energy while diverting waste from landfills.
A WtE plant converts solid waste into electricity and/or heat – an ecological, cost-effective way of energy recovery.
A waste-to-energy (or energy-from-waste) plant converts municipal and industrial solid waste into electricity and/or heat for industrial processing and for district heating systems – an ecologically sound, cost-effective means of energy recovery. The energy plant works by burning waste at high temperatures and using the heat to make steam. The steam then drives a turbine that creates electricity.
Recover valuable resources
Energy from waste (EfW) isn’t just a trash disposal method. It’s a way to recover valuable resources. Today, it is possible to reuse 90% of the metals contained in the bottom ash. And the remaining clinker can be reused as road material.
The results and benefits are proven:
- Avoids methane emissions from landfills
- Offsets greenhouse gas (GHG) emissions from fossil fuel electrical production
- Recovers/recycles valuable resources, such as metals
- Produces clean, reliable base-loaded energy and steam
- Uses less land per megawatt than other renewable energy sources
- Sustainable and steady renewable fuel source (compared to wind and solar)
- Destroys chemical waste / conventional HAPs
- Results in low emission levels, typically well below permitted levels
- Catalytically destroys NOx, dioxins and furans using an SCR
High efficiency and low emissions
Waste to energy is one of the most robust and effective alternative energy options to reduce CO2 emissions and replace fossil fuels. Approximately 2/3 of household waste is categorized as biomass. Therefore, we can recover 2/3 as CO2-neutral energy and reduce our dependence on fossil fuels.
In Europe, 50 million tons of waste is converted into valuable energy through WtE technology, supplying 27 million Europeans with electricity. Still, 50% of municipal solid waste becomes landfill. This releases greenhouse gasses like methane. Our WtE technology eliminates these emissions.
Our goals are two-fold: to maximize production and efficiency to meet energy needs, and to reduce our environmental footprint.
Waste facts
Energy from Waste Generation – 1 tonne
Energy from Waste Plant Costing
This advanced moving grate technology can be tailored to suit a very large range of capacity per line from 6t/h to 50 t/h i.e. 50 to 400 kt/y per line, with thermal input now potentially exceeding 120 MWth/line. Concerning the plant as a whole, its total capacity is recommended to be at least 150 kt/y for scale effects for theinvestment amortization and 300 to 500 kt/y capacity is the most sensible.
In the past, EfW plants had a minimum of 2 or 3 lines to ensure a continuous service all year round. Nowadays, the high availability which
is obtained on this reliable technology (+92%) allows building plants with only one line with an optimized maintenance program.
Below some orders of magnitude for costs in Eastern Europe or similar based on:
Fuel: typical Residual Municipal Solid Waste •
No land costs (considered as provided free of charge by the Authority), and ground conditions allowing conventional foundations
Project development and Permitting costs to be added
“Standard” architectural requirements •
Emissions requirements in line with the Industrial Emissions Directive
BOT contract whereby the contractor finances the CAPEX and is paid back with tipping fee per tonne of waste over 25+ years.
Well established bankability of the project with payment guarantees limited currency risk.
Energy sales: electricity only at 40- 50€/MWhe
This estimate provides some reference data which should remain valid in principle in different countries. The OPEX figures (and to a lesser extent the CAPEX) could however be significantly lower in low-income countries.
The gate fee covers CAPEX and OPEX expenditures minus the revenues from the energy selling and material recycling.
This table shows the significance of the “scale effect” when developing larger plants.
| Plant Capacity kt / y | CAPEX in M (Euro) | OPEX Euro / t | Energy Rev Euro / t | Gate fee Euro / t |
| 150 | 150 | 40 – 50 | 20 – 30 | 80 – 100 |
| 500 | 300 | 30 – 40 | 20 – 30 | 50 – 80 |
Rather than the annual mass capacity, the “size” of an EfW plant for its design and its CAPEX amount are mainly fixed by the thermal power input of the plant, which is the product of its hourly capacity by the calorific value of the fuel.
For example, a facility designed to treat 10t/h of residual MSW with an LCV of 8MJ/kg will develop a thermal power of 8x10x1000/3600 = 22MWth.
It will cost and produce the same energy quantity as a facility designed to treat 8t/h of residual MSW with an LCV of 10MJ/kg with the same thermal power input of c.22MW.
This means that:
• The pre-treatment in order to increase the LCV up-stream the EfW is in general not viable (except for very low LCV to improve the self- combustion of the fuel)
• With an increase of the LCV for example from 8 to 10MJ/kg (+25%), the size of a facility with an hourly capacity of 10t/h will increase from c.22MWth to 28MWth (+25%), the CAPEX
will roughly cost 15% more, the OPEX will be roughly the same and the energy revenues will increase by 25%.
Can green hydrogen save a coal town and slow climate change?
A smokestack stands at a coal plant on Wednesday, June 22, 2022, in Delta, Utah. Developers in rural Utah who want to create big underground caverns to store hydrogen fuel won a $504 million loan guarantee this spring. They plan to convert the site of the plant completely to cleanly-made hydrogen by 2045. (AP Photo/Rick Bowmer)
DELTA, Utah (AP) – The coal plant is closing. In this tiny Utah town surrounded by cattle, alfalfa fields and scrub-lined desert highways, hundreds of workers over the next few years will be laid off – casualties of environmental regulations and competition from cheaper energy sources.
Yet across the street from the coal piles and furnace, beneath dusty fields, another transformation is underway that could play a pivotal role in providing clean energy and replace some of those jobs.
Here in the rural Utah desert, developers plan to create caverns in ancient salt dome formations underground where they hope to store hydrogen fuel at an unprecedented scale. The undertaking is one of several projects that could help determine how big a role hydrogen will play globally in providing reliable, around-the-clock, carbon-free energy in the future.
What sets the project apart from other renewable energy ventures is it’s about seasonal storage more than it’s about producing energy. The salt caves will function like gigantic underground batteries, where energy in the form of hydrogen gas can be stored for when it’s needed.
“The world is watching this project,” said Rob Webster, a co-founder of Magnum Development, one of the companies spearheading the effort. “These technologies haven’t been scaled up to the degree that they will be for this.”
In June, the U.S. Department of Energy announced a $504 million loan guarantee to help finance the “Advanced Clean Energy Storage” project – one of its first loans since President Joe Biden revived the Obama-era program known for making loans to Tesla and Solyndra. The support is intended to help convert the site of a 40-year-old coal plant to a facility that burns cleanly-made hydrogen by 2045.
Amid polarizing energy policy debates, the proposal is unique for winning support from a broad coalition that includes the Biden administration, Sen. Mitt Romney and the five other Republicans who make up Utah’s congressional delegation, rural county commissioners and power providers. Biden was set to announce new actions on climate change Wednesday during an event in Massachusetts at a former coal-fired power plant that is shifting to a renewable energy hub.
Renewable energy advocates see the Utah project as a potential way to ensure reliability as more of the electrical grid becomes powered by intermittent renewable energy in the years ahead.
In 2025, the initial fuel for the plant will be a mix of hydrogen and natural gas. It will thereafter transition to running entirely on hydrogen by 2045. Skeptics worry that could be a ploy to prolong the use of fossil fuels for two decades. Others say they support investing in clean, carbon-free hydrogen projects, but worry doing so may actually create demand for “blue” or “gray” hydrogen. Those are names given to hydrogen produced using natural gas.
“Convincing everyone to fill these same pipes and plants with hydrogen instead (of fossil fuels) is a brilliant move for the gas industry,” said Justin Mikula, a fellow focused on energy transition at New Consensus, a think tank.
Unlike carbon capture or gray hydrogen, the project will transition to ultimately not requiring fossil fuels. Chevron in June reversed its plans to invest in the project. Creighton Welch, a company spokesman, said in a statement that it didn’t reach the standards by which the oil and gas giant evaluates its investments in “lower carbon businesses.”
As utilities transition and increasingly rely on intermittent wind and solar, grid operators are confronting new problems, producing excess power in winter and spring and less than needed in summer. The supply-demand imbalance has given rise to fears about potential blackouts and sparked trepidation about weaning further off fossil fuel sources.
This project converts excess wind and solar power to a form that can be stored. Proponents of clean hydrogen hope they can bank energy during seasons when supply outpaces demand and use it when it’s needed in later seasons.
Here’s how it will work: solar and wind will power electrolyzers that split water molecules to create hydrogen. Energy experts call it “green hydrogen” because producing it emits no carbon. Initially, the plant will run on 30% hydrogen and 70% natural gas. It plans to transition to 100% hydrogen by 2045.
When consumers require more power than they can get from renewables, the hydrogen will be piped across the street to the site of the Intermountain Power Plant and burned to power turbines, similar to how coal is used today. That, in theory, makes it a reliable complement to renewables.
Many in rural Delta hope turning the town into a hydrogen epicenter will allow it to avoid the decline afflicting many towns near shuttered coal plants, including the Navajo Generating Station in Arizona.
But some worry using energy to convert energy – rather than sending it directly to consumers – is costlier than using renewables themselves or fossil fuels like coal.
Though Michael Ducker, Mitsubishi Power’s head of hydrogen infrastructure, acknowledges green hydrogen is costlier than wind, solar, coal or natural gas, he said hydrogen’s price tag shouldn’t be compared to other fuels, but instead to storage technologies like lithium-ion batteries.
For Intermountain Power Agency, the hydrogen plans are the culmination of years of discussions over how to adapt to efforts from the coal plant’s top client – liberal Los Angeles and its department of water and power – to transition away from fossil fuels. Now, resentment toward California is sweeping the Utah community as workers worry about the local impacts of the nation’s energy transition and what it means for their friends, families and careers.
“California can at times be a hiss and a byword around here,” city councilman Nicholas Killpack, one of Delta’s few Democrats, said. “What we I think all recognize is we have to do what the customer wants. Everyone, irrespective of their political opinion, recognizes California doesn’t want coal. Whether we want to sell it to them or not, they’re not going to buy it.”
The coal plant was built in the wake of the 1970s energy crisis primarily to provide energy to growing southern California cities, which purchase most of the coal power to this day. But battles over carbon emissions and the future of coal have pit the states against each other and prompted lawsuits. Laws in California to transition away from fossil fuels have sunk demand for coal and threatened to leave the plant without customers.
In Millard County, a Republican-leaning region where 38% of local property taxes come from the Intermountain Power Plant, two coal plant workers unseated incumbent county commissioners in last month’s Republican primary. The races saw campaign signs plastered throughout town and tapped into angst about the multimillion-dollar plans and how they may transform the job market and rural community’s character.
“People are fine with the concept and the idea of it being built,” Trevor Johnson, one of the GOP primary winners, said, looking from the coal plant’s parking lot toward where the hydrogen facility will be. “It’s just coal power is cheap and provides lots of good jobs. That’s where the hang-up is.”
Read MoreGreen hydrogen project receives $504 million DOE loan guarantee
A green hydrogen project in Utah has received a $504.4 million loan guarantee from the Department of Energy’s Loan Programs Office, the first guarantee awarded to a clean energy project in nearly a decade.
The Advanced Clean Energy Storage project will combine 220 MW of alkaline electrolysis with two 4.5-million-barrel salt caverns to store clean hydrogen.
The project is intended to capture excess renewable energy when it is most abundant, store it as hydrogen, and then deploy it as fuel for the Intermountain Power Agency’s IPP Renewed Project. The hydrogen-capable gas turbine combined cycle power plant would be incrementally fueled by 100% clean hydrogen by 2045.
The Advanced Clean Energy Storage project received a conditional commitment from LPO in April. This is the first time a green hydrogen project has received a loan guarantee from DOE.
The Utah project is planned to include retiring existing coal-fueled power generating units at the IPP site; installing new natural gas-fueled electricity generating units capable of utilizing hydrogen for 840 MW net generation output; modernizing IPP’s Southern Transmission System linking IPP to Southern California, and developing hydrogen production and long-term storage capabilities.
IPP would use renewable energy-powered electrolysis to split water into oxygen and hydrogen. The new natural gas generating units, expected to be supplied by Mitsubishi Power, would use 30% hydrogen fuel at start-up, transitioning to all hydrogen fuel by 2045 as technology improves. The Los Angeles Department of Water and Power would be the off-taker for electricity produced by the facility.
50-fold increase
Across all its programs, LPO has attracted more than 70 active applications for projects in 24 states totalling nearly $79 billion in requested loans and loan guarantees as of the end of May.
With the closing of this loan guarantee, LPO now has $2.5 billion in remaining loan guarantee authority for Innovative Clean Energy projects.
“Accelerating the commercial deployment of clean hydrogen as a zero-emission, long-term energy storage solution is the first step in harnessing its potential to decarbonize our economy, create good-paying clean energy jobs and enable more renewables to be added to the grid,” Energy Secretary Jennifer Granholm said.
Green hydrogen plays an important role in the Biden administration’s goal of reaching net-zero emissions by 2050.
DOE’s National Energy Technology Laboratory determined that U.S. clean hydrogen production and use must increase 50-fold by 2050 to meet the country’s decarbonization goals.
Report findings noted while many opportunities exist for hydrogen’s growth, government leadership would be critical in achieving decarbonization goals. This would include tax credits and incentives, research, development and demonstration funding.
The DOE’s Office of Energy Efficiency and Renewable Energy has announced its intent to issue a funding opportunity to analyze the potential for regional clean energy deployments, all in the name of reducing the cost of green hydrogen production from $5 per kilogram to $1 by 2030.
Additionally, President Biden’s FY 2022 budget request includes $400 million for hydrogen activities, compared to $285 million in FY 2021.
Green (or clean) hydrogen produced using renewable energy and electrolysis represents only 5% of the hydrogen produced in the U.S. due to its high cost. In comparison, the remaining 95% is produced using fossil fuels.
So-called “blue hydrogen” from natural gas incorporates carbon capture and storage. However, recent studies suggest the practice could produce even more carbon emissions in heat generation than natural gas alone.
Read MoreMondofin UK receives letter of intent from the Sindh Government to develop a 50MW Waste-to-Energy project in Karachi, Pakistan
Mondofin UK, through its local partner BRV, received on April 1 a signed letter of intent (LOI) to develop a Waste-to-Energy project with a capacity of up to 50 megawatts. The project expects to process 1,500 tonnes of waste per day with an estimated investment of $150 million US dollars. Mondofin UK will execute the project with Babcock and Wilcox and licensee CSET.
The Sindh Government entered into an agreement with Mondofin UK through its local partner BRV Renewable Energy (BRV) and Technology partner Babcock and Wilcox (B&W) for launching a Waste-to-Energy project to transform the residual municipal solid waste generated in Karachi into clean electricity. At the same ceremony, the Sindh Government issued LOI’s to three other consortia.
For these four projects, the Sindh Government will provide land near the landfill site in Karachi. Energy Minister Mr. Imtiaz Shaikh said “Investments of approximately 600 million US dollars is expected for these projects and of the 15,000 tonnes of waste that Karachi’s population generates on a daily basis, about 6,000 to 8,000 tonnes of waste will be processed by the WtE plants for the production of 150 megawatts of energy”. He also mentioned that this project, launched in accordance with the “Green Energy, Clean Karachi” initiative, will not only help process the garbage from Karachi in a sustainable way but will also help meet Pakistan’s renewable energy requirements.
Energy Minister Mr. Imtiaz Shaikh, Karachi administrator Mr. Barrister Murtaza Wahab, Managing Director of Sindh Solid Waste Management Board, Mr. Zuhair Channa, Consuls General of the United States and the United Arab Emirates, the Ambassador of The Netherlands, Mr. Wouter Plomp and representatives of Mondofin UK, Babcock and Wilcox, and BRV Renewable Energy attended the signing ceremony.
Karachi Project Next steps after LOI
The LOI issued by the Sindh Government sets a clear pathway of milestones towards financial close which will take approximately 18 months. It is clear that after the successful construction of many wind projects with a cumulative installed capacity of more than 1GW, Pakistan is ready to make next steps, by implementing WtE to further reduce its carbon footprint and secure reliable as well as sustainable baseload power.
To develop the facility, Mondofin UK will work with its partner Babcock and Wilcox (B&W) via its licensee Beijing China Sciences Runyu Environmental Protection Technology (CSET) to deploy the same expertise used to build the CIXI Zhongke facility, which is one of the most efficient and cleanest and automated in the world. The plant in China commissioned in 2007, can generate around 920kWh of electricity from each tonne of waste processes 2250 tonnes daily. In 2016, The Ministry of Housing and Urban-Rural Development In 2016, rated CIXI Zhongke facility as an “AA-level domestic waste incineration plant” by. Mondofin UK expects similar success from its Pakistan project.
Refuse Derived Fuel
What exactly is RDF? Is it a secondary product or a waste? And is it available on the open market as a cheap renewable fuel?
RDF is refuse-derived fuel and it is produced as an output from materials recycling facilities (MRFs). It is composed of treated residual waste that is not suitable for recycling.
Although the residual waste has been through a treatment process, the manufacture of RDF does not qualify as recovery and the RDF is still classified as waste. Unlike secondary fuels based on waste solvents, it does not have such a high calorific value as fossil fuels and cannot be used as a direct replacement for them. Instead, it is burned in energy from waste (EfW) plants. RDF is regulated in the same way as any other waste and can only be burned in an installation that complies with the requirements for waste incinerators, taken from the EU Industrial Emissions Directive.
Energy from waste can be classified as either disposal by incineration or recovery (code R1), based on whether its primary purpose is to produce energy or dispose of waste. The Waste Framework Directive distinguishes between disposal and recovery using a formula based on the efficiency of the plant. Defra explains this as follows.
The R1 formula calculates the energy efficiency of the municipal solid waste incinerator and expresses it as a factor. This is based on the total energy produced by the plant as a proportion of the energy of the fuel (both traditional fuels and waste) that is incinerated in the plant. It can only be considered recovery if the value of this factor is above a certain threshold. It is important to note that the calculated value arrived at via the R1 formula is not the same as power plant efficiency, which is typically expressed as a percentage.
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