FGD and DeNOx NEWSLETTER

· Georgia Power, Electric Power Research Institute Open Ash Beneficial Use Center

· Effluent Limitations Guidelines and Standards Proposed for the Steam Electric Power Generating Point Source Category

· U.S. EPA Will Reinstate Power Wastewater Limits For Coal-Fired Power Plants

· Alabama Power Expects to Spend $3.3 Billion Over The Next Several Years to Close its Coal Ash Ponds

· B&W Continues Asia-Pacific Growth With $11 Million in Power Plant Emissions Control Contracts

· Andritz to Supply Another Flue Gas Desulfurization Plant to Tata Projects Limited For The Thermal Power Plant in Jojobera India

· Valmet to Supply a Boiler Upgrade and a Flue Gas Cleaning System to Stora Enso’s Anjala-Ingerois Sites in Finland

· Air Products Chooses Haldor Topsoe’s SynCOR Technology For World-Scale Blue Hydrogen Energy Complex in Canada

Georgia Power, Electric Power Research Institute Open Ash Beneficial Use Center

Georgia Power, in collaboration with the Electric Power Research Institute (EPRI) and Southern Company, marked the opening earlier this year of the first Ash Beneficial Use Center (ABUC). The ABUC will host pilot projects and lead continued testing of technologies to develop useful products potentially further from recycled coal combustion products (CCPs) such as coal ash.

This facility is located at Georgia Power's Plant Bowen and will allow for testing of pilot project technologies to increase the beneficial use of coal ash. Activities that will take place at this center include reviewing ways to optimize coal ash characteristics to better fit commercial applications, speeding and facilitating development of emerging beneficial-use technologies, understanding performance of re-use products, and developing realistic cost profiles.

"As a part of our ash pond closure efforts, Georgia Power is always looking for opportunities to use coal ash that are not only beneficial to our customers, but for our communities and environment," said Dr. Mark Berry, vice president of environmental and natural resources for Georgia Power. "The Ash Beneficial Use Center is paving the way for the latest coal ash technologies. We hope to see closed ash ponds and landfills become resources as new and improved uses are developed and proven through this center."

Today, Georgia Power already recycles more than 85 percent of all ash and gypsum, including more than 95 percent of fly ash, it produces from current operations for various beneficial reuses such as concrete production as well as other construction products.

"Developing cost-effective technologies to recycle coal ash is an important aspect of the clean energy transition," said Neva Espinoza, EPRI vice president of energy supply and low-carbon resources. "This unique research center provides an opportunity for utilities, researchers, and vendors to collaborate and advance technologies from benchtop to commercial operation."

By promoting advancements in beneficial use processes and technologies, this center will ultimately provide economic and environmental benefits by bringing cost-effective technologies to market and increasing the potential value of ash and other CCPs stored in landfills or ash ponds. This will result in long-term economic and environmental benefits to customers through the increased beneficial use of CCPs.

Research and larger-scale engineering tests and demonstrations are necessary to further develop advanced processes and beneficial use technologies that could increase the opportunities for CCP use. Since current CCPs are primarily supplied by operating power plants, this center aims to develop new technologies or processes that expand beneficial use applications and potential markets.

Mitchell Reuse Project
At Georgia Power's Plant Mitchell, an ash beneficial use project, is removing approximately two million tons of stored coal ash from the existing ash ponds at the retired coal plant for use in Portland cement manufacturing. The project at Plant Mitchell marks the first time that stored ash from existing ash ponds at sites in Georgia is being excavated for beneficial use as part of an ash pond closure project. Georgia Power continues to look for additional opportunities similar to Plant Mitchell to beneficiate CCPs at other plant as we proceed with ash pond closures.

Under orders from President Biden, EPA has taken its first overt step to revisit one of the Trump administration’s most bitterly contested air quality rollbacks.

While agency officials are not discussing the contents of a proposed rule sent yesterday to the White House budget office for a routine review, it is expected to restore the legal basis for landmark limits on emissions of mercury and other hazardous pollutants from coal-fired power plants.

Last year, the Trump administration scrapped the determination that it was “appropriate and necessary” to regulate those emissions, arguing that the underlying cost-benefit analysis was seriously flawed (Greenwire, April 17, 2020). While the administration’s decision had no immediate practical impact, it was opposed with particular intensity by environmental and public health groups that feared it would open the door to revoking the actual emissions limits for a class of high-polluting facilities.

Among the foes was Joe Goffman, who is now acting head of EPA’s air office. In a 2019 critique, written while he was still running Harvard University’s energy and environmental law program, Goffman accused the Trump administration of relying on a “blinkered and torturous legal interpretation” of the Clean Air Act to justify its move. In a January executive order issued on his first day in office, Biden instructed EPA to relook at the rollback and come up with a proposal by this month.

Mercury, a neurotoxin, is particularly dangerous to babies and small children. Also opposing the Trump-era move was the power industry, which had largely complied with what are formally known as the Mercury and Air Toxics Standards. The industry, however, backed an accompanying EPA decision last year to leave the original 2012 emission standards unchanged following a legally required review.

In a June interview with E&E News, Goffman indicated that the Biden administration was instead exploring the option of tightening them (Greenwire, June 7). It’s unclear whether the proposed rule sent yesterday to the White House contains any such provision. Goffman Thursday referred emailed questions to EPA’s press office, where a staffer declined to comment because the draft rule is under review. EPA has not publicly set a timetable for completion of the final rule.

As critics predicted, the revocation of the appropriate and necessary determination last year was soon followed by a lawsuit from a Colorado-based coal company seeking to scrap the actual standards as well. Proceedings in that suit are currently on hold at the U.S. Court of Appeals for the District of Columbia Circuit, along with others from environmental groups that variously challenge the Trump administration’s decision and seek to strengthen the standards.

Among the attorneys initially involved in the legal scrimmaging was Tomas Carbonell, who was then with the Environmental Defense Fund but joined EPA in January as deputy assistant administrator for stationary sources in the air office. In his current job, Carbonell is recused from matters related to the MATS litigation, according to a March ethics filing obtained by E&E News through the Freedom of Information Act.

Effluent Limitations Guidelines and Standards Proposed for the Steam Electric Power Generating Point Source Category

In accordance with President Biden's Executive Order Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis (January 25, 2021), the U.S. Environmental Protection Agency (EPA) announced its decision to undertake a rulemaking that will propose to revise the Steam Electric Power Generating Effluent Limitations Guidelines and Standards. As part of the rulemaking process, EPA will determine whether more stringent limitations and standards are appropriate and consistent with the technology-forcing statutory scheme and the goals of the Clean Water Act. EPA intends to sign the notice of proposed rulemaking for public comment in the Fall of 2022.

A digital mining company has an agreement to purchase a second power plant in Pennsylvania, as the group increases its coal refuse reclamation operations in the state to provide energy for its bitcoin mining operations.

Stronghold Digital Mining, a bitcoin (BTC) miner headquartered in Kennerdell, Pennsylvania, on Aug. 3 said its purchase of the Panther Creek Plant, located on 33 acres in Nesquehoning, in Carbon County, adds 80 MW of generation capacity to its portfolio, which also includes the 85-MW Scrubgrass plant. Scrubgrass is located on 650 acres in Scrubgrass Township, in Venango County.

Stronghold, founded earlier this year, uses the power plants to convert coal refuse into power that is used to mine bitcoin, an energy-intensive process. Coal refuse is classified by Pennsylvania as a Tier II alternative energy resource, akin to large-scale hydropower. Coal refuse over the years has been left in piles near coal operations; today, circulating fluidized bed technology allows for emissions-controlled conversion of coal refuse into energy.

West Virginia’s only remaining coal refuse–fueled facility, the 80-MW Grant Town Power Project, is a 2021 Top Plant winner for powering on, despite challenges, to remediate 530,000 tons of coal refuse annually while reclaiming roughly 30 acres of land per year.

The Environmental Protection Agency (EPA) is set to establish more stringent standards on water pollution from coal-fired power plants. The EPA, on July 26, announced it would reinstate Obama-era regulations that were rolled back by the Trump administration.

An EPA official on Monday said the new rule would impact about 100 coal-fired power plants. The agency said it would begin the rule-making process to reduce pollution, including toxic metals such as mercury, arsenic, and selenium, though changes could take a few years to go into effect—meaning the current standards, which include dozens of environmental regulations that were weakened by the Trump EPA—will remain in place.

Monday’s action in particular addresses a rule finalized on Aug. 31 of last year, when the EPA moved to limit the number of power generation facilities that could incur costs for failing to comply with limits on pollution. Last year’s action revised a 2015 rule, when for the first time the EPA issued an order that set federal limits on the levels of toxic metals in wastewater that could be discharged from power plants.

The EPA on Monday said it intends to issue a proposed rule for public comment in the fall of 2022, with an eye toward finalizing the rule by late 2023 or early 2024.

Alabama Power Expects to Spend $3.3 Billion Over The Next Several Years to Close its Coal Ash Ponds

Last year Alabama Power estimated those cleanup costs to be around $2.8 billion, but the company’s assistant comptroller, Wendy Hoomes, told state regulators last week during a public hearing that the new estimate is $3.3 billion.

Last year, Alabama Power increased customer rates by about 3%, citing coal ash clean-up costs as a driving factor. Next year’s 2 percent increase, which takes effect in January, is not tied to coal ash or environmental compliance costs, but other infrastructure costs.

Hoomes said the company expects to spend around $1.6 billion on coal ash over the next five years. The full closure process will take much longer. She said new studies on one of the ponds led to the higher estimates, as the company found increased ash volume and additional infrastructure would be needed.

Mike Godfrey, Alabama Power’s general manager for environmental affairs, told the Alabama Public Service Commission last week that it will take another 7-12 years to close the ponds, with an additional 30 years of groundwater monitoring required after closure.

For decades, coal-fired power plants in Alabama and elsewhere used wet ponds to dispose of the ash left over after burning coal, which contained potentially harmful substances such as mercury, cadmium, arsenic, selenium, and other heavy metals.

That ash was flushed from the plants into massive impoundments, usually on the banks of a river. The solid particles would settle to the bottom of the ponds, and water would discharge into the river.

Recent studies have shown high levels of groundwater contamination near these ash ponds and since 2018, Alabama Power has been fined $1.25 million for groundwater pollution violations related to its coal ash ponds.

Now, to comply with stricter regulations implemented by the U.S. Environmental Protection Agency in 2015, utilities are essentially forced to close these ponds and transition to dry handling and disposal of coal ash, which Alabama Power has already done. That means no more ash is going into these ponds.

Alabama Power has opted for the cover-in-place option to close its existing ash ponds, which can be hundreds of acres in size and contain millions of tons of wet coal ash slurry. The estimated cost includes de-watering the ponds, compacting the remaining coal ash into a smaller area and covering it with a synthetic liner, topsoil and vegetation or a synthetic turf, much like a modern landfill.

The closure in place option will not excavate the ash and install a liner underneath the material. The barrier atop the ash mound is designed to prevent rainwater from seeping into the ash and carrying contaminants to the groundwater below. The levels of toxins in the groundwater should naturally decrease over time.

Critics say the ash will continue to pollute groundwater, citing engineering reports showing that many ash ponds are close to groundwater sources. They have argued that moving the ash to a lined landfill, away from rivers is safer because it will eliminate groundwater contamination and the risk of a catastrophic spill or dam collapse, like the one that occurred at a TVA plant in Kingston, Tennessee. in 2008.

All of Alabama Power’s existing coal-fired plants have converted to dry ash handling and the company has begun dewatering the massive lagoons filled with 50 years or more of coal ash.

Alabama Power still has not received formal approval from the Alabama Department of Environmental Management (ADEM) for its closure plans at all ponds but is proceeding with efforts to de-water the ash ponds, which would be required regardless of the specific closure plans.

ADEM has issued draft permits for the permanent closures at Plant Miller in Jefferson County, Plant Greene County and Plant Gadsden in Etowah County. Alabama Power held public meetings and ADEM held public hearings at those plants for the public to weigh in on the proposed permits.

Godfrey said Alabama Power is waiting on ADEM to issue draft permits for ponds at its other facilities -- Plant Barry in Mobile County, Plant Gaston in Shelby County and Plant Gorgas in Walker County.

Alabama Power Company completed cover-in-place closure operations of its coal ash pond at Plant Gadsden in 2018.

The ash pond at Plant Gadsden is already closed, with the pond de-watered, consolidated and capped with a synthetic liner. Only ongoing monitoring operations remain.

Coal ash can be used safely to create products like concrete, wallboard, bricks, or roofing materials. Godfrey said Alabama Power has been able to sell more of its product than expected to other companies.

Alabama Power sold about 85 percent of its new ash generated in 2019 and expects a similar number for 2020, he said. He also said it is easier to sell ash that is new and handled dry than ash that has been sitting in a pond for years.

“[Dry handling] really helps in the marketability of the ash, and that’s been part of the increase in percentage that we’re able to beneficially reuse,” Godfrey said.

Hoomes said that Alabama Power expected to take in about $3 million a year from selling gypsum to vendors, but the increased sales have been around in the range of $5-7 million.

San Miguel Corporation (SMC) has confirmed it has dropped plans for three coal plant projects with a combined capacity of 1200 MW. In a July 1 letter to the Center for Energy, Ecology and Development, the Philippines Department of Energy stated it had dropped the 300 MW expansion of the Malita plant, the proposed 600 MW Merbau plant and the 300 MW Ozamiz plants from its list of potential projects “due to non-submission of the required monthly power project updates”. SMC has now confirmed it has abandoned the projects. The company also opted not to proceed with Central Luzon Premiere Power Corporation’s 1340 MW coal project and Lumiere Energy Technologies 710 MW station in Pagbilao, Quezon.

B&W Continues Asia-Pacific Growth With $11 Million in Power Plant Emissions Control Contracts

Babcock & Wilcox announced that it has entered into two contracts to design and supply advanced technologies to achieve reduced emissions and generate cleaner energy at a power plant in Asia. The total value of the contracts is more than $11 million.

B&W will upgrade the plant’s existing combustion equipment, supplying a B&W AireJet® low-NO_x (nitrogen oxides) combustion system and other equipment to improve the unit’s emissions and efficiency.

“As we continue to expand our business in the Asia-Pacific region, as well as other regions globally, we’re seeing an increasing number of significant opportunities to help customers reduce emissions from thermal plants,” said B&W Chief Operating Officer Jimmy Morgan. “The emphasis on clean energy technologies is global and growing, and customers in Asia and elsewhere are moving quickly to protect the environment as they generate energy efficiently and economically.”

As part of B&W’s strategy to expand its international presence, it established its Asia-Pacific regional headquarters, located in Perth, Australia, in 2020 to pursue opportunities in Asia. This expansion will enable B&W to deliver its ClimateBright™ technology platform and grow its B&W Environmental, B&W Renewable and B&W Thermal businesses to meet the demand for clean energy, decarbonization, renewable waste-to-energy, biomass, and environmental technologies, as well as services for utility and industrial customers.

Zulkifli Zaini, the President Director of Indonesia’s state-owned utility PLN, has told an online forum the utility has decided not to phase out the country’s coal fleet any earlier than the 2056 end date included in its current power plan. This contradicts earlier suggestions PLN would bring forward the retirement of coal units. Zulkifli floated the prospect it could keep operating coal plants beyond 2050 by embracing carbon capture and storage (CCS) if the costs come down. “If at that time, for example in 2050, carbon capture technology is very cheap, then let's just operate coal power plants. It’s okay … We could operate [the power plants] at very low costs.” There is currently only one CCS unit operating on a coal unit, but this has proven expensive and unreliable.

ISGEC Heavy Engineering Ltd has successfully secured a big order for wet limestone flue gas desulfurization (FGD) system and flue gas conditioning (FGC) system package from Odisha Power Generation Corporation (OPGC) for its 2x660 MW TPPIB Thermal Power Station at Banharpalli, Jharsuguda (Odisha).

OPGC is a state government-owned company, which operates advanced thermal power plants. Bagging an order from such an esteemed company makes it a prestigious one.

ISGEC will be working on design, engineering, procurement, fabrication, construction, installation, commissioning, startup, and testing of FGD-FGC package. And to do this, it will be utilizing state-of-the-art technology, which it has due to the ‘collaboration and technology transfer’ agreement with Babcock Power Environmental Inc. (USA).

The company's stock is on the top gainers' list today on BSE and has also, made a fresh 52-week high of Rs 824.40, surging almost 17 percent in a single trading session from its previous day's close of Rs 704.

ISGEC is a multi-national company, engaged mainly in manufacturing and project businesses. It has customers and projects across 91 countries and is in the business for the last 88 years. The company has a strategic technological association with many global leading firms and numerous joint ventures as well. It ranks 220 in the Fortune India 500 listing and 236 in ET 500 listing.

Andritz to Supply Another Flue Gas Desulfurization Plant to Tata Projects Limited For The Thermal Power Plant in Jojobera India

International technology Group Andritz has received another order from Tata Projects Limited, India, to supply the process engineering for a complete flue gas desulphurization (FGD) plant, comprising basic engineering and the detailed engineering for the absorber internals and equipment as well as other core components for the Jojobera power plant (output: 4 x 120 MW), near Jamshedpur, East Singhbum District, Jharkhand State, India. Start-up is scheduled for the first half of 2023.

For desulfurization purposes, the exhaust gas is washed in counter-current flow with a limestone suspension, reducing the content of SO₂ and other acidic components to concentrations in line with the current environmental requirements. With further oxidation, process gypsum can be produced that is either landfilled or sold to the construction industry.

Andritz has comprehensive experience with FGD technologies and many successful references around the world. This project is another important step towards establishing Andritz’s flue gas treatment technology on the Indian market.

Drax Group has cut the carbon emissions from its power generation by over 90% in less than a decade, the company reported in its half-year results.

With this reduction, Drax has become one of Europe’s lowest-carbon intensity power generators, moving it closer to achieving its ambition to be carbon negative by 2030.

Formerly the largest coal power station in Western Europe, Drax has this year ended commercial coal generation, sold its existing gas assets and is now a 100% renewable power generator. It has already been a big year for Drax, which secured additional biomass production capacity and reduced costs through the acquisition of Canadian biomass producer, Pinnacle Renewable Energy.

Drax’s adjusted EBITDA from continuing and discontinued operations were up by £7 million (€8.2 million) to £186 million (€218 million) in the first half of 2021, compared to £179 million (€210 million) in the same period in 2020. The company said it was pleased to announce a 10% increase in its dividend and that it remains committed to creating long-term value for its stakeholders.

The firm has also made ‘significant progress’ in the development of bioenergy with carbon capture and storage (BECCS) in the first half of 2021, with plans to deploy the world’s largest carbon capture project at its facility in North Yorkshire. Deploying BECCS at Drax would enable the company to make an even greater contribution to carbon reductions in the coming decade while creating jobs and supporting the UK’s green transition.

“Cutting Drax’s carbon emissions by more than 90% in under a decade is a unique achievement and is transformational, both for our business and the environment,” said Will Gardiner, Drax Group CEO.

“Replacing fossil fuels with clean power from renewables like sustainable biomass and hydro has enabled the UK’s electricity system to decarbonize faster than any other major economy, but industry needs to go further than just reducing emissions to permanently removing CO₂ from the atmosphere, if the UK is to achieve its ambitious climate targets.

“By deploying BECCS, Drax will be leading the way in permanently removing millions of tonnes of CO₂ while generating renewable power and supporting clean growth and thousands of jobs in the 2020s.

“BECCS is the only technology available now which can deliver the negative emissions the world needs to meet the climate commitments set out in Paris in 2015 while also generating the reliable renewable electricity the world needs.”
In the first half of the year, Drax progressed its plans for BECCS, choosing Mitsubishi Heavy Industries as its technology partner and kick-starting the planning process to develop BECCS at Drax this decade.

The company also started to explore overseas BECCS opportunities with Bechtel, including in North America, and next-generation BECCS technologies with Phoenix BioPower, creating further opportunities for the UK to export this technology that will be needed globally.

Subject to ‘the right government support’, the first BECCS unit at Drax Power Station could be operational in 2027, with a second in 2030, permanently removing at least eight million tons of CO₂ from the atmosphere annually.

Valmet to Supply a Boiler Upgrade and a Flue Gas Cleaning System to Stora Enso’s Anjala-Ingerois Sites in Finland

Valmet will supply a boiler upgrade and a flue gas cleaning system to Stora Enso’s Anjala-Ingerois sites in Finland. The goal of the investment is to reduce the emissions and to ensure flexible use of different fuel mixtures in heat production, as well as to achieve better boiler performance and higher boiler efficiency.

The order is included in Valmet’s orders received of the second quarter 2021. The value of this kind of boiler rebuild is typically around EUR 15-20 million. The boiler outage is scheduled for the third quarter of 2022, but the installation work of the new baghouse filter will be done mainly before the shutdown. The project’s focus has been in finding ways to minimize the boiler shutdown time.

Valmet’s delivery includes an upgrade to an existing biomass and solid recovered fuel (SRF) fired BFB boiler, with a thermal power of 110 MWth. Maintenance type of replacements will be part of the work. The air emission control system modification includes an efficient new baghouse filter with additive feeding.

Valmet is OEM of this Stora Enso Anjala BFB boiler. During the years Valmet has done lots of boiler related works at SE Anjalankoski mill. Original PC boiler has been delivered by Tampella (one of Valmet´s predecessors) in 1971 and it was converted to biomass fired BFB in 1995. In 2008 the boiler was modified to increase the share of SRF as a fuel. Steam values are 38.5 kg/s, 480°C and 70 bar(g). New BHF will be Valmet´s own design.

Flue gas from the boiler (230 000 Nm³/h at MCR) will be conveyed to a baghouse filter (BHF), which will replace the current ESP. In the baghouse filter and in the existing flue gas scrubber the flue gas emissions will be reduced to the required level. The purpose of the baghouse filter (BHF) is to separate fly ash and other particles from the flue gas stream by filtration through fabric filter bags. In order to reduce acid gases (SO₂, HCl and HF), hydrated lime is injected into the flue gas duct upstream of the filter. Activated carbon is injected into the flue gas duct upstream of the filter to control the emissions of gaseous heavy metals, dioxins, and furans.

The BHF consists of six separable compartments. Each BHF compartment is supplied with an inlet damper on the untreated flue gas side, and an outlet damper on the cleaned gas side. During operation, any filter compartment can be shut down and isolated individually for maintenance work inside the compartment.

Suction pressure generated by the I.D. fan draws the flue gases from the boiler back pass into the baghouse filter. The flue gas flows through the vertically installed filter bags leaving fly ash, dust, and additives on the outer surface of the bags. The cleaned gas then flows upwards inside the filter bags into the clean gas side of the filter and finally to the existing scrubber.

NO_x emissions in the boiler will be reduced by using urea injection system (Selective Non-Catalytic NO_x Reduction, SNCR). The NO_x reduction system consists of urea receiving, storing and injection to the boiler.

A director of the Ministry of Energy and Mineral Resources, Chrisnawan Anditya, said the burning of biomass in coal plants will be made mandatory as a measure to reduce the country’s power sector coal consumption. Chrisnawan said the government is currently drafting a regulation that would apply to the government-owned utility PLN as well as independent power producers. PLN estimates biomass co-firing at its largest 52 coal units could reduce coal consumption by 9 million tons per year. PLN first began trialing co-firing at its coal plants in 2018. However, the Institute for Energy Economics and Financial Analysis has doubts about the economic viability of using waste from the palm oil industry given palm kernel shells are currently exported to Japan and Korea for more than double the cost of coal.

Following a major research and testing program into all aspects of biomass combustion, RJM has developed and is now marketing its own range of burners specifically configured for biomass and co-firing applications.

As a result, RJM is increasingly seen by the sector as the “go to” consultant for generators seeking to evaluate their options in terms of migration to co-firing or full plant conversion to biomass combustion.

RJM's expertise in the biomass sector has brought together in-house engineers working in the USA and UK, together with research teams at Brigham Young University (USA) and Aalborg University (Denmark).

As part of the R&D process, RJM engineers designed and manufactured a scaled-down RJM biomass burner that was tested extensively on a range of biomass fuels at different sizes and velocities on a special rig, in controlled conditions. Combustion data recorded during these tests has now been incorporated into RJM's own CFD biomass model — one of the most sophisticated biomass combustion modelling software programs in the industry — to further increase predictive performance at customer sites.

Globally, biomass supplies approximately two percent of the world’s electricity. In Europe, it’s share is higher at six percent. In the UK alone, however, biomass accounted for 11 percent of power generation last year.

In the UK, National Grid ESO’s Future Energy Scenarios show biomass is expected to play an increased role in the country’s energy future. The report notes that those scenarios show that deployment of BECCS means annual carbon emissions from electricity generation could be negative by as soon as 2030. By the mid-2030s, BECCS could be removing 40 million metric tons per year of carbon dioxide from the atmosphere, according to the report. That is comparable to total annual emissions in 2020.

The UK Association for Renewable Energy and Clean Technology (REA) issued a statement on the report, noting the UK’s record on bioenergy offers the world a pathway to net zero emissions. “Sustainable biomass has been key to the UK’s decarbonization success so far and has supported the expansion of variable renewables like wind and solar,” said Nina Skorupska, CEO of the REA. “Negative emissions through bioenergy with carbon capture and storage will be vital to achieving our net zero targets and will be delivered by building on the UK’s world-leading biomass sectors and adhering to strict science-led sustainability governance.

“We look forward to the publication of an update this summer on the upcoming Biomass Strategy, which we hope will provide a clear direction for the further development of the bioenergy sector over the coming years,” she added.

Iain Staffell, lead author of Electric Insights, said, “The versatility of sustainable biomass for electricity generation is an overlooked success story in the UK. It has helped the UK to rapidly decarbonize its power sector and looks set to continue to deliver key strategic benefits through bioenergy with carbon capture and storage and the potential for negative emissions.”

At the state level, at least 12 states have also issued public policies to encourage the production and enhancement of a sustainable energy matrix, including bioenergy, providing financial, credit and tax incentives for such activities. In some states, this incentive is also given through specific public policies related to the production of biomass to generate bioenergy from the use of reforested areas — as in Piauí, Rio Grande do Sul and Rondônia — or within the scope of public policies connected to climate change, as in Rondônia and Mato Grosso do Sul states. The states of São Paulo, Santa Catarina, Rio Grande do Sul, Paraná and Goiás have created specific policies to encourage the production of biogas and biomethane, in order to enhance the generation of energy from biomass.

In addition to such public policies, other state regulations grant special conditions for environmental licensing of activities related to bioenergy generation.

FutureMetrics LLC on May 3 released a new white paper that emphasizes the carbon-negative potential of deploying carbon capture and storage (CCS) technology at pulverized coal (PC) power stations that are modified to use sustainably produced wood pellet fuel.

In the white paper, William Strauss, president of FutureMetrics, stresses that while CCS used in conjunction with fossil-fueled power generation is appealing, the best CCS can achieve with fossil fuels is near carbon neutrality. Pairing CCS with fossil-fueled power generation offers no net reduction in atmospheric carbon dioxide. While carbon neutral is good, carbon negative is better, he said.

“If part of an effective strategy for mitigating climate change is to develop ways to optimally subtract CO₂ permanently from the atmosphere, then one of the most efficient and economical ways to achieve that goal is to repurpose selected PC power stations,” Strauss wrote.

“Think of the station’s primary purpose as being a negative CO₂ pump with a by-product of grid-level constant and reliable electricity,” Strauss continued. “This combination results in a highly cost-effective carbon-negative-plus-power solution. This is only possible with the use of upgraded solid fuel suitable for PC power stations made from renewing biomass: i.e., wood pellets.”

The white paper includes a discussion of working forests and the production of sustainable wood pellet fuel and explains how many countries are already using pellet fuel in place of coal in PC power stations to lower net carbon dioxide emissions.

FutureMetrics has also developed a dashboard that complements the new white paper. Both the new white paper and the accompanying dashboard are available on the FutureMetrics website.

Drax Group plc released the results of a new study on April 12 that shows its planned bioenergy with carbon capture and storage (BECCS) projects will save the UK more than £4.5 billion ($6.18 billion) over the next decade as the country works to meet its climate goals.

The study, commissioned by Drax and completed by energy consultancy Baringa, evaluates the impact of deploying BECCS at scale as part of achieving the country’s climate change targets.

The report released by Baringa explains that Drax is considering the potential retrofit of two of its existing 630-megawatt (MW) biomass units with CCS. Each unit could deliver up to 4 million tons per year of negative emissions. A final investment decision on the BECCS projects will be required in 2024 to allow the first of these units to come online in 2027.

For the study, Baringa considered the role of negative emissions in reaching the UK’s net-zero goals, the role of BECC-power given the competing abatement options, and the role of the Drax projects as part of a broader need for BECCS-power.

According to the report, the capital cost of adding carbon capture at Drax’s facility is significantly lower than building a new BECCS facility. Converting the existing biomass units to BECCS at the facility would also secure the long-term future of the site, according to Baringa’s report. A carbon payment and power contract for difference (CfD) would underpin the necessary investment at the Drax site and enable the capture of 8 million metric tons of carbon dioxide per year. That volume of carbon capture would be a significant contribution to the 20 to 40 metric tons of carbon dioxide capture per year required by 2050 to meet the U.K.’s goals, the group said in the report.

The report calls the Drax-BECSS project a “no regrets” option, and notes that achieving net-zero will be significantly more expensive without BECCS-power. “Conversion of Drax’s existing biomass units can pave the way to a substantial program of new build BECCS and other negative emissions technologies, such as biomass gasification to produce hydrogen with negative emissions, with the optimum pathway being refined as technologies mature and costs evolve,” said Baringa in the report. “Drax BECCS can also provide an important ‘anchor project’ for development of the CO2 Transmission & Storage infrastructure as part of the Humber CCS cluster. Additionally, Drax’s consistent demand for biomass can aid in the development of sustainable biomass supply chains.”

Historically used to help make fertilizer and chemicals, hydrogen is increasingly being pushed for a much broader range of uses, including for trucks, planes, ships, household heating and as a way to store renewable power.

“Today, hydrogen is used as a feedstock primarily…the growth of the hydrogen market is all about it becoming an energy source,” said Louise Jacobsen Plutt, BP’s senior vice president of hydrogen and carbon capture and storage.

BP is exploring the use of hydrogen to replace natural gas in industries such as steel, cement, and chemicals, and also as a substitute for diesel in trucks. Overall, BP forecasts hydrogen could account for about 16% of the world’s energy consumption by 2050—if net zero carbon-emissions goals are to be achieved—up from less than 1% today.

Like other major oil companies, BP thinks its existing expertise—it already produces hydrogen at refineries—and infrastructure could help it win a sizable market share. Last year the company said it planned to use wind power to produce hydrogen for a refinery in Germany, hoping to demonstrate the technology at a large scale.

However, BP doesn’t expect green hydrogen to be a material part of its business until the 2030s, and it has yet to make a final investment decision on any new hydrogen projects. It will take time to create a market and bring down the cost, Ms. Jacobsen Plutt said, “Because it is so nascent, it is more expensive.”

Shell also is grappling with high costs. This month, the company started up what it said is Europe’s largest green hydrogen plant, to supply its Rhineland refinery in Germany. But that hydrogen is between five and seven times more expensive than the fossil-fuel-based product it predominantly uses.

“You’re not in the money yet,” said Paul Bogers, Shell’s vice president of hydrogen. “For green hydrogen, the core belief is that you almost have to get to a world where the electrons are free.”

Industry executives say green hydrogen is expensive because of the cost of the electricity needed to make it, as well as the cost of the electrolyzer—the system used to split water into hydrogen and oxygen.

Shell hopes it can reduce costs by building hydrogen projects in strategic locations alongside customers’ plants, like at ArcelorMittal SA’s steel mill in the German port of Hamburg, where it can also add hydrogen refueling for trucks.

The industry is also getting government support. The European Union paid half the roughly $23 million cost of Shell’s Rhineland project and has earmarked funding for hydrogen as part of its pandemic recovery program.

Air Products Chooses Haldor Topsoe’s SynCOR Technology For World-Scale Blue Hydrogen Energy Complex in Canada

Air Products has selected Haldor Topsoe’s low-carbon SynCOR technology for a world-scale net-zero hydrogen energy complex in Canada. Topsoe’s SynCOR technology will enable capture of more than 95% of CO₂ emissions from the production of blue hydrogen from natural gas for the recently announced Air Products facility to be built in Edmonton, Alberta, Canada. The captured CO₂ will be stored underground.

Hydrogen-fueled electricity will power the plant and offset the remaining five percent of emissions at the site. The clean energy complex will help refining and petrochemical customers served by the Air Products Heartland Hydrogen Pipeline to reduce their carbon intensity. The complex will also produce liquid hydrogen for merchant sales and as a clean fuel in the transportation sector.

This industry-proven and advanced technology produces hydrogen at large scale with low emissions and energy consumption. Canada’s clean energy diversification strategy has marked hydrogen as a key enabler for Canada to achieve its goal of carbon neutrality by 2050. Expected to come onstream in 2024, the SynCOR-based hydrogen facility will effectively support that goal.

Topsoe offers a complete range of market-leading hydrogen production technologies, including electrolysis technology to produce green hydrogen.

The hydrogen complex is part of Air Products’ ambition to reach more than 1,500 tons of hydrogen production per day and achieve more than three million tons per year of CO2 capture in Alberta alone.

Babcock & Wilcox and the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL) have signed an Intellectual Property Option Agreement that gives B&W field-limited exclusive rights to negotiate a licensing agreement that would allow it to market an advanced, particle-based thermal energy storage technology currently in development.

B&W is part of NREL’s Duration Addition to electricity Storage (DAYS) Advanced Research Projects Agency-Energy (ARPA-E) team, which is developing an innovative electric particle heater, pressurized fluidized-bed heat exchanger, a long-term thermal energy storage system that stores energy up to 100 hours, and other technologies to allow power producers to store solar or wind energy to generate continuous, reliable, grid-scale power.

B&W’s proven and established pressurized fluidized-bed boiler technology is an ideal choice for advancing this technology to commercial operations.

“High-capacity, long-term energy storage is essential for renewable energy sources such as solar and wind power to become widespread, baseload power options,” said B&W Chairman and Chief Executive Officer Kenny Young. “B&W’s fluidized-bed heat exchanger will be able to generate up to 135 megawatts of power for up to 100 hours (four days) from stored clean thermal energy with zero CO2 emissions. By facilitating long-term storage of zero-carbon, renewable energy, this technology enables power producers to deliver power to the grid 24-hours a day, including during periods of peak demand, or when solar or wind are not optimal conditions.”

“We see tremendous global commercial applications for our fluidized-bed heat exchanger and are pleased to have the opportunity to negotiate a licensing agreement with NREL and expand B&W’s technology for use in new, innovative energy storage platforms,” Young said.

B&W and NREL are also engaged in discussions to develop a prototype heat exchanger that can be scaled-up for a pilot demonstration as part of NREL’s Economic Long-Duration Electricity Storage Using Low-Cost Thermal Energy Storage and a High-Efficiency Power Cycle (ENDURING) project.

In effect the system temporarily stores the energy normally supplied directly by the steam turbine. It uses technology already used in many coal-fired plants.

Since the process leverages technology already being supplied by B&W, the question arises as to whether existing plants with fluid bed combustors could be utilized and converted to the storage concept.

B&W is very experienced with biomass combustion including waste to energy plants. So the question arises as to whether the storage technology could be incorporated in these plants.

There is work being done on biomass gasification and its use in gas turbines. Could this technology be used with the storage option? If this were combined with CCS, you would have a carbon negative power source with storage capacity.

“Flowserve delivered solid second quarter results, including year-over-year bookings growth of nearly 18 percent, driven by the continued activity in our shorter cycle MRO and aftermarket services,” said Scott Rowe, Flowserve’s president, and chief executive officer. “The ongoing progress of our Flowserve 2.0 transformation initiative has delivered results, including a strong sequential increase in Adjusted EPS and incremental margin improvement. Following last year’s disruptive impact of the pandemic and volatile commodity prices, we believe Flowserve is set to build upon the growing momentum in our operations and end-markets.”

Rowe concluded, “Our early cycle markets have clearly begun to recover, and we have confidence that we are approaching an inflection point for larger project opportunities. In addition to the improving outlook in our core energy and chemical markets, we continue to believe that Flowserve is well-positioned to benefit from the expected increase in energy transition and decarbonization investments across our served end-markets. The combination of stronger bookings coupled with our operational progress lays the foundation for escalating earnings growth in the second half of 2021.”

	Revised Target Range	Prior Target Range
Revenues	Down 2.0% to 4.0%	Down 3.0% to 5.0%
Adjusted Earnings Per Share	$1.45 - $1.65	$1.40 - $1.60
Adjusted Tax Rate	21%-23%	22%-24%

Fuel Tech Awarded Air Pollution Control Orders Totaling $4.5 Million

Fuel Tech, Inc., a technology company providing advanced engineering solutions for the optimization of combustion systems, emissions control, and water treatment in utility and industrial applications, announced the receipt of multiple air pollution control (APC) contracts from customers in Korea, North America, and Europe. These awards have an aggregate value of approximately $4.5 million.

The company also announced the completion of two on-site US demonstrations of its DGI™ Dissolved Gas Infusion water treatment technology.

An order from Korea was received for Selective Catalytic Reduction (SCR) technology including an ULTRA^® system, that will be installed on a natural gas-fired combined cycle plant in the Pacific Rim. SCR technology uses a catalyst along with urea or ammonia as the reagent to provide high levels of nitrogen oxide (NO_x) reduction. Fuel Tech’s ULTRA process provides for the safe and cost-effective, on-site, conversion of urea to ammonia for use as a reagent where SCR is used to reduce NO_x, eliminating the hazards associated with the transport, storage, and handling of anhydrous or aqueous ammonia. This is the second unit on which they have installed the SCR and ULTRA technologies at the same site. Deliveries are expected to be completed in the second quarter of 2022.

An order was received in Europe for catalyst replacement for an existing Fuel Tech SCR system. Delivery is scheduled for the third quarter of 2021.

In North America, a contract was received for a NOxOUT^® Selective Non-Catalytic Reduction (SNCR) system for a biomass-fired unit. Fuel Tech’s SNCR technology is a proven solution for utility and industrial combustion unit owners looking to comply with more stringent NO_x control requirements. Work is expected to be completed by the fourth quarter of 2021.

Vincent J. Arnone, President and Chief Executive Officer, commented, “We are pleased to announce these contract awards and we have begun to see activity in our markets increase with the improved economic outlook as the effects of the COVID-19 pandemic subside. The order from Korea demonstrates Fuel Tech’s on-going commitment and our long-term partnership approach to meet the environmental compliance needs of utility plant operators implementing our advanced technology solutions.”

Fuel Tech also announced the completion of two demonstration contracts in the US where DGI technology provided a source of dissolved oxygen for wastewater treatment plants evaluating the use of advanced aeration in addition to their existing treatment processes to accommodate periods of high wastewater treatment demand.

Mr. Arnone concluded, “We are excited to announce the incremental demonstrations of our DGI wastewater treatment technology as we look to expand the use of DGI to meet customer needs in a variety of market segments. We continue to develop DGI as a potential cost-effective retrofit technology for sites with physical or capital constraints.”

Researchers from Georgia Tech’s School of Civil and Environmental Engineering have discovered a way to extract rare-earth elements—essential ingredients for nearly all modern electronics—from the ash left behind at coal-burning power plants using a non-toxic ionic liquid.

In a paper published in ACS’s Environmental Science and Technology on June 23, the Georgia Tech researchers showed that by applying an ionic liquid directly to solid coal fly ash, rare-earth elements can be successfully removed in a safe process that creates little waste. The study is co-led by Ching-Hua Huang, a professor of environmental engineering and Ph.D. candidate Laura Stoy.

Huang and her research team have discovered a new method that utilizes an ionic liquid that is reusable and environmentally benign. Ionic liquids have only gained traction for use in metallurgy over the last decade, and this research represents the first time that ionic liquids have been directly applied to solid coal ash.

“This methodology is a significant paradigm shift away from the digestion of coal ash by strong acids or bases typical in other REE recovery methods,” Huang said. “This new approach is safer industrially and is more environmentally sustainable with the recyclability of the ionic liquid.”

Ozone is used in conjunction with wet scrubbers in refining for SO₂ and NO_x control. The approach has been to inject ozone in the hot gas ahead of the scrubber but research for marine vessels suggests a single stage combination may be best.

The stringent international regulations on marine emission abatement have exerted a huge push on the development of marine desulfurization and denitrification technologies. However, for the traditional vessels driven by large two-stroke diesel engines, simultaneous removal of NO_x and SO₂ is still a big challenge at present. Here, a one-stage ozone oxidation combined with in-situ wet scrubbing for simultaneous removal of NO and SO₂ is proposed. A series of experiments were performed based on a bench-scale reaction system. The results showed that in-situ wet scrubbing could effectively decrease flue gas temperature, and then suppress the thermal decomposition of ozone, which was beneficial for improved oxidant utilization. Meanwhile, the in-situ combination of ozone injection and wet scrubbing was in favor of improving the selectivity oxidation of NO over SO₂ by ozone, which was possibly due to the high aqueous solubility of SO₂ in water. Aiming to reduce the electric power consumption by an ozone generating system, O₃/NO molar ratio was kept as low as possible. A complete removal of SO₂ and a high NO_x removal efficiency could be achieved through the introduction of other oxidative additives in scrubbing solution.

Another paper focused on coal-fired boilers with the ozone sodium hydroxide scrubber combination.

GE Power India (GEPIL) reported healthy revenue growth at 27% YoY to Rs9.3bn in Q4FY21 led by strong FGD order execution. The company has a robust executable orderbook of Rs54bn (~1.5x TTM sales) and the order pipeline for FGD too is promising, as the majority of state and private utilities are yet to tender. The withdrawal of parent from large coal utility projects opens up opportunities for GEPIL to focus on long-term value creation by ramping up the high-margin, high-RoCE services business. Factoring-in near term stress on margins due to commodity price inflation and covid second wave, one analyst marginally cut FY22E earnings by 1.3% but raise the same for FY23E by 6.2% supported by better cashflows. Given the recent acquisition to expand the services portfolio and increase its contribution, it maintains BUY on the stock with a revised SoTP valuation of Rs407 (earlier: Rs352).

- Healthy growth in services orderbook: Company witnessed 75% growth in the service order intake during FY21 and this is likely to support strong growth in this segment going forward. The acquisition of 50% stake in NTPC GE Power Services Private Ltd (NGSL) presents an opportunity to leverage NTPC's third-party O&M.

- High commodity prices and unfavorable mix impact margins: The overall raw material cost proportion in sales increased 100bps YoY and 120bps QoQ impacting the overall margins. The higher mix of low-margin FGD is also depressing the overall margins. The recent VRS and gradual increase in service business is likely to support overall margins in the medium to long term perspective.

- Cashflows likely to be stronger FY22E onwards: the analyst factors-in a major uptick in FGD execution for FY22E, which it believes will lead FGD revenues to their peak. Majority ordering will be from NTPC though ~145GW of ordering towards FGD is pending finalization (predominantly from state electricity boards and private sector). Execution of the current orderbook will impact near term working capital, however, cashflows to improve from FY22E onwards. This would be post completion of high working capital intensive NTPC FGD orders and increase in mix of services.

Currently, ~Rs20bn of domestic coal plants are serviced by Chinese companies; however, given the government's reservations towards China, the analyst believes majority of these contracts are likely to move to non-Chinese players. The analyst believe, this will help improve GEPIL and Siemens' market shares (the two companies are the major third-party service solution providers).