FGD and DeNOx
NEWSLETTER

 

August 2020
No. 508

 

Table of Contents

 

COAL – U.S.

COAL – WORLD

GAS TURBINES

WASTE-TO-ENERGY

BIOMASS

CO2

 BUSINESS

________________________________________

 

 

COAL – U.S.

 

Air Plan Approval; MS; Bart SIP and Regional Haze Progress Report

 

The Environmental Protection Agency (EPA) is proposing to approve, through parallel processing, a draft Mississippi State Implementation Plan (SIP) revision, submitted through a letter dated April 23, 2020, addressing best available retrofit technology (BART) determinations for 14 electric generating units (EGUs) (“draft BART SIP”). These EGUs were initially addressed in EPA's prior limited approval and limited disapproval actions on Mississippi's regional haze SIP because of deficiencies arising from the State's reliance on the Clean Air Interstate Rule (CAIR) to satisfy certain regional haze requirements. EPA proposes to approve the draft BART SIP and finds that it corrects the deficiencies that led to the limited approval and limited disapproval of the State's regional haze SIP; to withdraw the limited disapproval of the regional haze SIP; and to replace the prior limited approval with a full approval of the regional haze SIP as meeting all regional haze requirements of the Clean Air Act (CAA or Act) for the first implementation period.

Federal Register / Vol. 85, No. 150 / Tuesday, August 4, 2020 / Proposed Rules


U.S. Regulator Proposes Extension to Coal Ash Compliance Deadline

 

The Environmental Protection Agency (EPA), which is responsible for regulation of the 400 coal ash pits in the US, has proposed allowing further extensions for the operation of unlined pits. In 2015, EPA introduced regulations for management of coal ash dams for the first time and set a 2019 deadline for the capping or closure of unlined dams. Following the election of President Trump in 2016, the EPA sought to weaken the regulation. However, a legal appeal against the changes was successful, prompting the agency to craft a revised regulation. The new regulation introduces loopholes that allow some dams to continue to accept waste until 2028 and potentially stay open until 2038. Earthjustice has flagged a legal challenge against the new regulation is likely.

 

EPA Eyes Cleanup of Coal Ash Threatening Indiana Dunes

 

The U.S. Environmental Protection Agency is seeking the public’s feedback on a proposed cleanup of coal ash buried along Lake Michigan that the agency believes is threatening wildlife at the Indiana Dunes National Park.

 

The EPA has drafted a cleanup plan for the eastern part of Northern Indiana Public Service Co.’s (NIPSCO) former Bailly Generating Station in Chesterton. The deadline for public comments is August 19.

 

EPA officials believe coal ash buried around the former coal-fired power plant is seeping through groundwater and threatening plants and wildlife at the national park. The 15,000-acre (6070-hectare) park along Lake Michigan’s southern shore is located about 50 miles (80 kilometers) southeast of Chicago and contains one of the nation’s most biodiverse ecosystems.

 

The Bailly Generating Station closed in 2018, but the EPA said NIPSCO buried coal ash — a by-product of coal burned to produce electricity — there in the 1960s and 1970s about 25 feet (7.6 meters) underground.

 

The agency believes that ash is seeping into underground water, which is “carrying the underground contamination into the park,” the Post-Tribune reported.

 

Coal ash is known to contain many toxic metals, but boron is the primary contaminant the EPA is worried about. The agency said the metal is harming plants but is present at levels “too low to harm people.”

 

The EPA’s plan calls for 100,000 cubic yards (76,455 cubic meters) of dry coal ash/soil to be dug up and hauled off-site for disposal. Another 85,000 cubic yards (64,987 cubic meters) of “wet” ash below the water table would be solidified to prevent contaminants from migrating to the groundwater or surface water, the agency said.

 

Ozone Transport Commission; Recommendation That EPA Require Daily Limits for Emissions of Nitrogen Oxides from Certain Sources In Pennsylvania

 

The Environmental Protection Agency (EPA) is announcing that on June 8, 2020, the Ozone Transport Commission (OTC) submitted a recommendation to EPA for additional control measures at certain coal-fired electricity generating units (EGUs) in Pennsylvania. Specifically, the OTC has recommended that EPA require Pennsylvania to revise the Pennsylvania State Implementation Plan (SIP) to include additional control measures which would establish daily nitrogen oxides (NOX) emission limits for all coal-fired EGUs with already-installed selective catalytic reduction (SCR) or selective non-catalytic reduction (SNCR) control technology to ensure that these technologies are optimized to minimize NOX emissions each day of the ozone season. EPA is also announcing a public hearing on the recommendation as discussed under DATES below. EPA is commencing a review of the recommendation to determine whether to approve, disapprove, or partially approve and partially disapprove it. Prior to the public hearing, EPA plans to publish another document in the Federal Register providing further discussion of the recommendation and the framework the Agency intends to apply in reaching a decision.

 

DATES:  EPA will hold a virtual public hearing within 90 days of the OTC recommendation or by September 4, 2020. Further information on the date and time of the virtual public hearing will be available at https://www.epa.gov/​interstate-air-pollution-transport/​ozone-transport-commission-otc-section-184c-petition.

 

Air Plan Approval; Indiana; Revisions to NOx SIP Call and CAIR Rules

 

The Environmental Protection Agency (EPA) is approving under the Clean Air Act (CAA) a request from the Indiana Dept. of Environmental Management (IDEM) to revise the Indiana State Implementation Plan (SIP) to incorporate the following: a new rule concerning nitrogen oxide (NOx) emissions for the ozone season from electric generating units (EGUs) and large non-EGUs; revisions concerning NOx emission rate limits for specific source categories; the repeal of the NOx Budget Trading Program; and the repeal of the Clean Air Interstate Rule (CAIR) NOx ozone season trading program. this SIP revision will ensure continued compliance by EGUs and large non-EGUs with the requirements of NOx SIP call.

 

Federal Register / Vol. 85, No. 143 / Friday, July 24, 2020 / Rules and Regulations

 

 

COAL – WORLD

 

Coal Capacity Declined in First Half of 2020

Global coal power capacity declined by 21,200 megawatts (MW) in the first half of 2020 with the largest changes being the closure of 8300 MW in European Union countries and 5400 MW in the U.S., according to a new report by Global Energy Monitor. Over the same period 18,300 MW of new capacity was commissioned, of which 11,600 MW was in China, resulting in a 2900 MW net decline over the period. Between 2010 and 2019 new coal plant capacity has increased on average by 25,000 MW every six months. At present 189,800 MW of coal power capacity is still under construction. In the first half of 2020 China accounted for 90 percent of the 59,400 MW of newly proposed capacity and 86 percent of the 15,000 MW of new construction. With China’s existing coal plants already running at just 50 percent utilization rate, the completion of plants already under construction will add to the financial stress on utilities and waste scarce capital.

Bangladesh Could Cancel 28 GW of Planned Coal-fired Capacity

 

Bangladesh’s Minister of Power, Energy and Mineral Resources, Nasrul Hamid, surprised energy watchers recently when he said the country is planning to “review” all but three of 29 planned coal-fired power plants.

 

“We are keeping the three coal-fired power plants that are under construction. At present, we are aiming for 40- to 41-GW of total generation capacity, where only 5-GW is coal based,” said Minister Hamid during a webinar run by the Centre for Policy Dialogue. “We are reviewing how we can move from coal-based power plants.”

 

Bangladesh has one of the largest coal power pipelines in the world, a total of 29 power plants amounting to 33.2-GW of capacity, according to a 2019 study by an Australian organization that tracks fossil fuel investment. If the minister’s comments become government policy, up to 26 power plants accounting for 28-GW of capacity could be put under review. That’s 90 percent of the coal pipeline.

 

“It would dramatically swing the nation’s power development away from coal,” said Simon Nicholas, Energy Finance Analyst with the Institute for Energy Economics and Financial Analysis (IEEFA).

 

“Coal power is no more a cheap option and it’s becoming more expensive for imported coal. Hence, the government is reconsidering its earlier plan on coal-power generation in its energy mix,” Mohammad Hossain, director general of the ministry’s research body, Power Cell, commented in the webinar, echoing Minister Hamid’s suggestion to review coal-fired power plans.

 

The costs of renewables have been undercutting coal for years and recent price crashes in oil and gas mean that these two fossil fuels are now also price competitive with coal. Bangladesh’s coal power dream would also be highly dependent on imports of both equipment and coal, an expense and a liability in the age of Covid-19-induced lockdowns and supply chain disruptions.

 

In addition, Bangladesh’s Power Development Board must also pay costly subsidies to operators of underutilized power plants in the form of “capacity payments”. With a coal power utilization rate of just 43 percent, from 2018-19 the government reportedly burned US$1.1 billion in payments to power plant operators. One third of the energy ministry’s budget has been allocated to capacity payments for idle power plants in the 2020-2021 financial year.

 

With the IMF predicting that GDP growth in Bangladesh could slip to just 2 percent this year, compared to a pre-COVID forecast of 7.4 percent, power demand is expected to be lower, meaning capacity payments will continue to rise unless steps are taken to revise plans for new capacity. Power Cell’s Hossain also acknowledged in the webinar that the government will need to review the country’s power system masterplan considering the radically changed outlook for the economy and power demand.

 

The 29 coal-fired power plants currently in Bangladesh’s pipeline are at varying stages of development. The three that Minister Hamid suggested will continue as planned—Rampal, Matarbari and Payra — have entered construction and are nearing completion. Their financiers include Chinese, Japanese and Indian export credit and international cooperation agencies. Other projects have signed engineering, procurement and construction (EPC) deals, equity investment deals or are only at the stage of memoranda of understanding.

 

Chinese companies dominate both the EPC and equity investment market in Bangladesh. According to information on EPC contracts gathered by Market Forces, Chinese construction companies are involved in up to 16.5-GW worth of EPC contracts. Japanese companies, the second largest EPC contractors in Bangladesh, are involved in just 2.4-GW of coal power capacity. According to Greenpeace figures, up to 98 percent of proposed Bangladeshi coal power plants with Chinese involvement also include equity investment.

 

Coal power was seen as a solid investment that could deliver stable returns from operating plants. But Minister Hamid’s comments last month will be of concern to investors and contractors. EPC companies could lose out on a lot of business in one of their most promising markets, although they may be eligible for partial compensation under force majeure and other insurance clauses. Equity investments in coal plants that do not reach the commissioning stage will also suffer losses.

 

Insurers will also feel the ripple effects, according to Wang Yan, an independent researcher in environmental, social and governance performance of companies. The minister’s comments “are like a red light” to these companies, warning them that “coal power plants are not a comfortable and profitable deal anymore”, she said.

 

The companies who have signed the most EPC deals for coal-fired power plants in Bangladesh include Power China, China Energy Engineering Corporation, and First Northeast Electric Power.

 

Though of a much larger scale than elsewhere, Bangladesh’s potential pivot from coal is not an isolated incident this year. In June, the 700-MW Qasim coal power project in Pakistan was cancelled, in large part due to lack of demand. A number of Vietnam’s coal power projects, long plagued with financing and construction start problems, are also looking increasingly unfeasible in the post-COVID world. In a consultation session held earlier this month, Vietnam’s Energy Institute suggested that the country’s next decade-long power plan due to come into force next year could see up to 9.5-GW of planned coal capacity cancelled and 7.5-GW postponed until at least 2030, about half of the country’s total planned coal power.

 

IEEFA’s Simon Nicholas notes that these shifts on the demand side also raise huge uncertainties for the region’s number one coal exporter, Indonesia, which has been banking on growth markets in Bangladesh, Vietnam and Pakistan as the Chinese and Indian markets shrink.

 

The review of coal power may not be all good news for the climate though. Firstly, three large coal-fired power plants, amounting to 5-GW of capacity, will still be connected to the grid, increasing Bangladesh’s carbon emissions and requiring costly capacity payments.

 

Secondly, as indicated by Minister Hamid in the Centre for Policy Dialogue webinar, the government is likely to turn from coal to liquid natural gas (LNG), a fossil fuel that is more or less equal to coal in terms of greenhouse gas emissions when accounted for on a whole-lifecycle basis. Given current overcapacity in the power sector, LNG plants would also likely lie idle and be a drain on the ministry’s budget.

 

Some Bangladeshi researchers and advocacy groups, such as Transparency International Bangladesh and Waterkeepers Bangladesh, are pushing for an alternative power sector development path that would radically expand renewables.

 

There is some interest in developing renewables in the country and from foreign investors. Last month, Power China signed an EPC contract to develop 500 MW of solar and wind energy in Bangladesh, the largest ever addition of renewable capacity in the country. However, on paper the government remains cautious about renewables expansion, with their 2016 forecast signaling a negligible role for renewables through to 2041.

 

Minister Hamid’s comments at the end of June, echoed by several high-level energy officials, may signal a huge shake-up in the Bangladeshi energy sector. For now, though, the government needs to be clearer about how it is “reviewing” coal power plans, how many of the 29 plants may be on the chopping board, and what it proposes to do instead.

 

EPC companies that may see proposed coal projects in Bangladesh held up or even cancelled

 

Plant

EPC company 1

EPC Company 2

Capacity (GW)

Banshkhali / Chittagong

PowerChina

SEPCO III Electric Power Construction Corporation

1.2

Barisal

Shanghai Electric Power Construction Co., Ltd. – EPC

Dongfang (& UK company)

0.7

Gazaria

General Electric

Guangdong Electric Power Design Institute (China Energy Engineering Group CEEC or Energy China)

0.7

Mirsarai

Zhejiang Jindun Pressure Vessel Co. Ltd. (Jindun Group)

 

1.3

Patuakhali power station (BCPCL) (Phase 2 of Payra Power Station)

First Northeast Electric Power Engineering Company (NEPC) (Northeast No 1 Electric Power Construction Co in some sources)

China National Energy Engineering and Construction Co Ltd. (CECC) (subsidiary of China National Machinery Import and Export Corp (CMC))

1.3

Patuakhali power station (RPCL/NORINCO) Phase 1

China Wanbao Engineering Co., Ltd (China North Industries Co., Ltd NORINCO)

China Huadian Science and Technology Group Co., Ltd.,

1.3

Phulbari Coal Project (GCM-China Gezhouba)

China Gezhouba Group International Engineering (subsidiary of Energy China, CEEC) (China Energy Engineering Group Co., Ltd.)

PowerChina

2

Phulbari Coal Project (GCM-Sinohydro/PowerChina)

PowerChina

 

2

 

Source: China Dialogue, compiled using project-level data provided by Market Forces cross-checked with Minister Hamid’s comments

Only 27% of Indian FGD Contracts Awarded

Only 1 percent of the total coal-fired power plant capacity, which is required to comply with the emission standards under the current phasing plan have installed the mandatory flue gas desulfurizers (FGD), an equipment to control toxic sulfur dioxide emissions.

Of the total 169.7 GW coal capacity in the country, plants with only 27 percent capacity have awarded bids for FGD implementation. Around 72 percent capacity haven’t even awarded the bids.

India APC Program Faces Further Delays

Given a host of challenges, the government’s 2022 deadline for installation of FGD units at 166 GW coal-based capacities is likely to be missed.

The agenda for installing pollution reducing equipment at coal-based power plants, already facing challenges, has to reckon with an apparent disruption of the supply chain following the ban on import of power equipment from China. Taken together with the reluctance of lenders to inject more capital in the stress-ridden sector and the uncertainty over its impact on power tariffs, this means the Centre’s 2022 deadline for installing flue gas desulfurization (FGD) units in plants with a capacity of 1,65,942 MW is likely to be missed.

In fact, about 75 percent of these plants are yet to award contracts for the purpose though it takes about 30 months to commission such a project, which reduces sulfur dioxide emissions. About 14,000-MW capacity power plants around the NCR have already missed the first deadline of December 2019. As per the mandate, 22,310-MW power capacities are required to set up FGD units in 2020, 62,297-MW, in 2021, and 65,455-MW, in 2022.

Industry associations have requested the Prime Minister’s Office to constitute a committee to review the timelines, after assessing the requirements and the bottlenecks. The Supreme Court recently refused to allow a blanket extension of deadlines for FGD installation to power plants undergoing the corporate insolvency process.

Lack of clarity on the tariff hikes which would be allowed in lieu of equipment installation is another hurdle. While the power ministry has clarified that FGD installation would be treated under the ‘change in law’ provision, implying the expenses would be passed on, discoms, are challenging the tariff hikes approved by the Central Electricity Regulatory Commission (CERC). “Without confirmation from discoms, financing institutions are unwilling to finance FGDs, as there is uncertainty over cost recovery,” says Vipul Tuli, Chairman of FICCI Power Committee.

As per initial estimates, the cost of FGD installation is Rs 27-45 lakh per MW and would necessitate a rise of Rs 0.62-0.93/unit in power tariff. However, several power plants have pointed out to the CERC that the actual costs are higher. CLP India’s 1,320 MW Jhajjar power plant, a unit of the Hong Kong-based CLP Holdings, is currently the only private station to have commissioned such equipment.

The ban on Chinese equipment is also delaying the FGD tendering process, as even local companies manufacturing the machines are dependent on imports. According to sources, about 30 percent of FGD components have to be imported, with most of these coming from China. “A shift of 2-3 years in timelines would provide an opportunity to implement the ‘Atmanirbhar Bharat’ agenda by creating an order book of about Rs 48,000 crore for the domestic industry,” says Ashok Khurana, Director General of the Association of Power Producers.

There are also activists who believe that spending on costly FGDs would add to environmental problems. To curb sulfur dioxide emissions, FGD units would end up producing a similar quantity of carbon dioxide and also lead to an increase in mining activity, as limestone is required to run the units, they say. Seeking a review of the plan, the Veterans Forum for Transparency in Public Life has pointed out to the National Green Tribunal (NGT) that these units would also produce more than 10 MT of chemical gypsum, the disposal of which would be an added burden for power plants. The NGT has asked the NGO to approach the Central Pollution Control Board (CPCB) with its plea.

While the CPCB has imposed a fine on power plants not complying with FGD deadlines, some industry watchers feel the penalties, in the range of 0.12-3.28 percent of the energy cost of plants, are not a significant deterrent. “The penalty is notional at best,” says Karthik Ganesan, fellow at the Council on Energy Environment and Water. “Until there is a clear directive from the Centre, power producers are unlikely to take the issue of compliance seriously,” he feels.

South Korea's Ruling Party Proposes Bill to Ban Overseas Coal Finance

Twenty-one parliamentarians from South Korea’s ruling Democratic Party have proposed a bill banning investments in overseas coal power projects. The bill explicitly proposes banning KEPCO, the Korea Export-Import Bank, Korea Development Bank and Korea Trade Insurance Corp. from involvement in overseas coal-fired power plants. The legislators have also written to all four public agencies calling for a review of all coal projects currently being promoted and considered. Assemblyman Seong-Hwan Kim said that if the agencies did not voluntarily announce they were suspending support for overseas coal projects then the legislation should be passed. South Korea is one of the top investors in international coal-fired power plants behind China and Japan.

GE Combines Software and Services to Improve Dominican Republic’s Power Reliability

GE announced it is providing the Corporación Dominicana de Empresas Eléctricas Estatales (CDEEE) with a combined software and services package at the Central Termoeléctrica Punta Catalina (CTPC) power plant. This includes a Multi-Year Agreement (MYA) to provide maintenance and repair services for the plant’s existing steam turbine generators, combined with GE software to help CDEEE operate the plant reliably and achieve optimal performance. The combination of digital services makes it GE’s most comprehensive digital deal in Latin America with first-of-its-kind software implementation currently underway.

“With CTPC’s essential role in providing one-third of the Dominican Republic’s total generation capacity, we are counting on GE’s maintenance services and digital capabilities to help us generate reliable, affordable electricity for years to come,” said Jaime Aristy-Escuder, General Manager, CTPC. “We are proud to partner with GE on the island’s largest digital steam plant with first-of-its-kind software implementation which is complemented with on-site support by GE experts with Advisory Services on operations and maintenance on the plant.”

As an island nation, the Dominican Republic can face weather and other challenges in its quest to deliver continuous electricity for its 10.8 million residents. The 752-megawatt CTPC power plant plays an essential role in maintaining reliable power and supporting a stable grid as the country strives to increase its use of renewable energy by 25 percent between 2015 and 2025.

“We look forward to supporting CDEEE/CTPC and helping them deliver reliable and affordable power for the Dominican Republic,” said Michael Keroulle, President & CEO, GE Steam Power. “As a longtime service provider for the steam power industry with more than 200 multi-year agreements in place, GE is committed to helping our customers improve their profitability and competitiveness, while at the same time providing essential power to those who need it most.”  

As the Dominican Republic’s most comprehensive digital steam plant, CTPC will showcase GE’s broad range of software to help CDEEE operate the CTPC plant reliably and achieve better performance over its lifetime. This will include the world’s first-ever implementation of GE’s Plant Efficiency Advisor to help CDEEE monitor and identify the plant’s performance gaps, as well as the Caribbean’s first implementation of Boiler Optimization and Mill Optimization software to help increase efficiency and reduce NOx emissions over the plant’s lifetime. 

“By investing in GE’s innovative hardware, software and services capabilities, CDEEE/CTPC will be able to offer better value for its customers while demonstrating its commitment to innovation,” said Pat Byrne, CEO of GE Digital. “GE’s partnership with CDEEE at the CTPC plant further proves that software is becoming mission critical in helping industries solve their toughest challenges.”

Through its Predix Asset Performance Management (APM) digital technology, GE will help the CDEEE/CTPC team remotely monitor the site’s equipment to help detect operational issues before they occur as a means of avoiding unplanned downtime from operation. In addition, an Operations Performance Management (OPM) suite will help the site run more efficiently, translating to lower fuel costs and longer operating life for its equipment.

Additionally, to avoid unplanned downtime and optimize performance, CTPC will implement Digital Twin blueprints — software representations of critical assets — across both units to detect equipment failures before they happen. Based on AI / Machine Learning and network modeling, GE’s Digital Twins will help CDEEE recognize faster time-to-value through increased reliability, reduced risk, lower maintenance costs and improved production. Assets are monitored in real-time from GE’s Monitoring and Diagnostics Center in Atlanta, Georgia where teams of industry experts currently oversee more than 1.2 million digital twins worldwide.

GE Power Bags Orders Worth Rs 850 Crore to Set Up Air Quality Systems

GE Power India stated it has multiple orders worth Rs 850.69 crore (USD 112.57 million) to implement air quality control systems technology in India.  

The company will supply these air quality control systems (AQCS) solutions to NTPC, Hindalco Industries and UP Rajya Vidyut Utpadan Nigam Ltd. a GE Power India statement said.

 According to the statement, it will supply the AQCS to Hindalco Industries Ltd for their Aditya Aluminum Plant Lapanga in Sambalpur, Odisha. The project is expected to be commissioned by 2021.  

This technology will give a number of benefits as it facilitates sulfur dioxide (SO2) removal with lower water consumption, smaller footprint, utilization of existing stack, lesser lifecycle cost and lesser implementation time, the statement said.

It will also supply ACQS to its Feroze Gandhi Unchahar Thermal Power Project Stage-I, II & III in Rae Bareli, Uttar Pradesh. This order is expected to be completed by February 2023.

Another order is to supply ACQS to UP Rajya Vidyut Utpadan Nigam (UPRVUNL), which will be setting up a combustion system modification of the boilers along with advanced firing system equipment to meet the nitrogen oxide (NOx) emission norms for their Harduaganj, Parichha and Anpara plants.  

The order is a first for combustion modification for NOx control by any state utility in India, the company said.  

"The commitment being shown by the Government of India to reduce the overall levels of SOx and NOx is very encouraging. The solutions from its AQCS portfolio will help to lower levels of SOx and NOx n emissions and will serve to improve the overall quality of air," said Prashant Jain, Managing Director of GE Power India Ltd.  

GE Power India Ltd is a listed legal entity of GE Steam Power business in India and one of the leading players in the Indian power generation equipment market.

Hitachi Completes Merger of Its JV Business Unit With Power India

Hitachi has completed the merger of its joint venture power business unit with ABB Power Grids, known as Power India, a statement said.

The merger follows the completion of the global merger of the energy business vertical of the Swiss major with the Japanese conglomerate. The merged entity is known as Hitachi ABB Power Grids globally.

While Hitachi owns 80.1 percent stake in the new joint venture, which has a combined business of $ 10 billion, ABB holds the balance, the companies said in a joint statement.

Following this, Hitachi will directly be responsible for the management and operation of Power India or ABB Power Products and Systems India, which comprises part of Hitachi ABB Power Grids and is listed on the BSE and NSE (as Power India).

The merger also involves moving the assets of Asea Brown Boveri's or ABB's shareholding in ABB Power Products & Systems India.

ABB Power Products & Systems India was incorporated in February 2019 and was listed in March 2020 and an open offer is underway to buy back its publicly held shares.

The open offer was launched on March 30, 2020. Power India is traded on the exchanges and will continue to be a public company post-open offer.

Globally the new company is known as Hitachi ABB Power Grids with $10 billion in annual sales, and the new entity began commercial operations, the companies said.

The companies said the merger ensures that the complementary portfolios and technology strengths will enable continuity, enhance customer value and bring growth opportunities.

"In accordance with the agreement signed on December 17, 2018, Hitachi and ABB today completed all required procedures for the formation of Hitachi ABB Power Grids in the 80.1:19.99 joint venture respectively, creating a new global power leader”, the statement said, adding the new entity is headquartered in Zurich, Switzerland.

The new entity will have a larger scope in areas such as mobility, smart cities, industry, energy storage and data centers, besides providing financial muscle to support ambitious projects and enabling access to Japan, the third largest economy in the world.

“Combining our respective technology strengths will bring us new market opportunities and enable us to deliver greater customer value,” said N. Venu, managing director of Hitachi ABB Power Grids India.

After the global merger, Hitachi acquired the indirect control over the power grids business of ABB and, on closing, Hitachi will directly be responsible for the management and operation of APPSIL now.

Last December Hitachi and ABB had agreed to merge at an enterprise value of USS 11 billion. The Japanese major had paid $ 6.85 billion to the Swiss major for 80.1 percent stake. Hitachi will acquire the remaining 19.9 percent stake of Hitachi ABB Power Grids to make it a wholly owned subsidiary after 2023.

India No Longer Importing Power Plant Equipment From China

India has decided to shut the door on power equipment imports from countries like China, which feature in its Prior Reference Category (PRC) list.

While supporting the move, industry executives also warn that it will lead to delays in complying with emission-reduction norms. Over three-quarters of India's thermal power plants (TPP) are likely to miss the December 31, 2020, deadline, since most emission-reducing gear is sourced from China, the Association of Power Producers observed.

India's power sector has been dependent on its northern neighbor for a large variety of equipment so far, especially in the solar and emissions-control segments. According to Power Minister RK Singh, India imported nearly Rs 71,000 crore worth of power sector equipment in fiscal year 2018-19, of which China alone contributed Rs 21,000 crore.

"This is something we cannot tolerate... (from) a country (that) transgressing into our territory.... we will not take anything from China and Pakistan," Singh said while speaking at a virtual conference with state power ministers.

"We will not give permission for imports from Prior Reference Countries," he added.

The PRC list currently comprises several countries from which threats to Indian interests may originate, such as China, Pakistan, Iraq, Afghanistan, and Sudan.

Singh also asked his state-level counterparts to stop any procurement orders from China for power distribution companies under their control. A constant concern with such imported equipment—highly advanced electronics goods, in particular—is that they may contain software which could be weaponized by enemy actors.

"There could be malware or trojan horse in those, which they can activate remotely," Singh warned.

The Ministry of Power has already passed relevant orders to ensure that roadblocks to such imports are in place. In an order dated July 2, the ministry made the import of equipment from PRC countries will "require prior permission of the Government of India."

Even if such imports are allowed in special cases, officials say, the order also mandates that all such gear will be tested in India to weed out any embedded cyber threats. "The protocol for testing in certified and designated laboratories shall be approved by the Ministry of Power," it added.

Since the power supply network is "sensitive and critical infrastructure," officials said the ministry has decided to weed out vulnerabilities which mainly arise from "possibilities of cyberattacks" through embedded malware.

The Finance Ministry had also raised import barriers in the solar segment by imposing a new basics customs duty on solar modules and panels.

Apex industry body Association of Power Producers (APP), while hailing the move, is seeking an extension in deadlines for compliance with emissions norms.

All thermal power plants (TPP) are mandated to upgrade their emissions controls systems with flue gas de-sulfurization (FGD) units and electrostatic precipitators (ESP) before December 31, 2022. As per the phase plan, 37.61 GW of TPP capacity should have installed FGDs by December 2020, of which 1.7 GW have managed to do so far. The COVID-19 pandemic has also thrown a spanner in the works. 

 In a letter to power minister Singh, APP director-general Ashok Khurana wrote that the ban on using Chinese equipment will impact the installation of pollution-control devices in power plants. Industry executives say that only about 20-30 percent of such components are made locally, with 70-80 percent imported from China.

At present, a large majority of TPPs haven’t even awarded tenders for these works yet, APP noted.

"It is evident that as many as 77 percent of the total TPP units for whom FGD is planned have not yet awarded the EPC contracts. These are highly likely to miss their timelines. Around 36 GW of TPPs will miss their target deadline of December 31, 2020, thereby further loading the already strained FGD supply chain," Khurana wrote.

The APP is consequently seeking an extension of the timelines for compliance. “A push back by 2-3 years would provide an excellent opportunity for implementing... “Atmanirbhar Bharat” by opening a manufacturing order book of Rs 48,000 crore for the domestic industry," he said, since tenders have still not been awarded for capacity worth 120.72 GW.

Philippines Adding 4,000 MW of Capacity by 2022

The Dept. of Energy (DOE) said the country will have an additional 4078 megawatts (MW) from committed power projects until 2022, the last two years of the Duterte administration.

 

In its accomplishment report released in late July, the DOE said the bulk of the new capacity or around 2518 MW will come online this year and 1560 MW will be ready by 2022.

 

In terms of sources, the majority of the additional power sources will come from coal-fired power plants with a total of committed capacity of 2,521 MW from 2020 to 2022. 

 

This is followed by oil with 415 MW new capacity, natural gas with an additional 650 MW, biomass with 252 MW, and solar with 240 MW.

 

The DOE said the administration has pursued energy security for the country to support the needs of the growing economy.

 

In 2019, the country’s installed capacity reached 25,531 MW, growing by 19 percent from 21,423 MW in 2016. 

 

This means power projects approved between 2016 and 2019 added 4,106 MW of installed capacity.

 

On the other hand, dependable capacity also increased to 22,736 MW in 2019 from 19,097 in 2016.

 

“Renewable-based plants recorded a share of 29 percent or 7399 MW in the country’s total installed capacity in 2019. Among the RE-based power plants, hydropower and geothermal has the largest shares at 15.8 percent or 3760 MW and 8.1 percent or 1928 MW, respectively,” DOE said.

DOE underscored that the government’s policies for pursuing clean and green energy made the Philippines have the highest share of renewable energy (RE) in its primary energy supply.

With RE accounting for 32.8 percent of the country’s energy supply mix in 2019, the Philippines has met early its commitment to Asean Plan of Action on Energy Cooperation to raise RE share in the energy mix by 23 percent by 2025.

Meanwhile, DOE said that from 2019 until June 2020, 133 certificates of energy projects of national significance were issued with investments amounting to PHP386.86 billion.

These projects are also expected to generate additional jobs of 13,419 upon full operation. (PNA)

Most Indian Coal Plants Stall on Pollution Control

The Centre for Research on Energy and Clean Air (CREA) estimates coal-fired power plants comprising less than one percent of India’s 169,700 MW of coal capacity have been fitted with flue gas desulfurization (FGD) units. CREA estimates only 24 percent of coal-fired power plant capacity is covered by contracts for the installation of units to cut sulfur dioxide emissions. Seventy-two percent of coal-fired power plant capacity is not yet covered by contracts to install FGD units despite the new pollution standards first being adopted in late 2015.

Vietnam Coal Imports Surge

Vietnam’s coal imports in the first half of this year surged by more than 50 percent to a record high, government data showed, mostly to feed the country’s growing number of coal-fired power plants.

Coal imports in the January-June period rose 53.8 percent from a year earlier to 31.57 million tons, the Customs Dept. said in a statement.

Vietnam turned from a net coal exporter to a net importer about five years ago and has become more reliant on imported coal for its electricity production, though the government is seeking to reduce its coal reliance and boost renewables.

Coal-fired power plants now account for around 35 percent of Vietnam’s installed power generation capacity, a ratio that will stay unchanged for the next five years, according to the Ministry of Industry and Trade’s institute of energy.

Its coal imports in the first half of this year, mostly from Indonesia, Australia and Russia, exceeded the domestic coal production of 25.27 million tons during the same period, according to government data.

Last year’s coal imports nearly doubled to 43.77 million tons. The ministry last year said Vietnam would face severe power shortages from 2021 as construction of new plants lags demand. Electricity consumption is expected to exceed supply by 6.6 billion kWh in 2021, and 15 billion kWh in 2023.

Recently, Vietnam’s state oil firm PetroVietnam said it will stop developing new coal-fired power plants and wants to venture into renewable energy sources, as domestic crude oil production has peaked at most of its offshore oil fields.

Vietnam’s Power Development Plan 8 to Provide Vision for Power Supply Up to 2045

Vietnam’s government faces crucial choices as it draws up a new national energy plan for 2021-2030. Due to be published this summer, the Power Development Plan 8 will provide a vision for power supply up to 2045. Experts are hoping that Vietnam will use the plan to further its position as a renewables leader in Southeast Asia and provide clarity on the role of coal in meeting the country’s rapidly rising demand for electricity.

It has become a regional solar leader in the past couple of years. Its installed capacity reached 5.5 gigawatts (GW) last year, accounting for 44 percent of Southeast Asia’s solar capacity, according to Reuters. It has already reached a solar power target it had set for 2025.

There is great potential for the development of wind power as well, with the minister of industry and trade, Tran Tuan Anh, stating in June that Vietnam plans to increase wind power by 7,000 MW to 11,630 MW by 2023 due to delays and opposition to coal-fired power plants.

However, electricity from fossil fuels still accounts for 62 percent of Vietnam’s total installed power capacity, according to a 2018 study from the Beijing-based Global Environmental Institute (GEI).

Under the government’s current power development plan, released in 2016, this is expected to drop to 53 percent by 2030. But the finance and construction of new power plants is nevertheless ongoing, much of it with the support of major Chinese banks and companies.

 

china coal in vietnam

 

Rising demand

The new power development plan is expected to emphasize the further development of renewables. Though officials have said little in public and the government faces hard choices. Demand for electricity is growing faster than supply, as both industrial and residential usage continue to rise. Thermal power will continue to play a large role.

“China is a top investor in both coal and renewable energy globally,” says Nguyen Trac Duc, a Project Coordinator at Green Innovation and Development Centre (GreenID), an environmental NGO in Hanoi.

With Chinese funding likely either way, it is up to the Vietnamese government to “seize the opportunity to mobilize financial resources for renewable energy development,” says Duc.

“This is an opportunity for Vietnam to act.” Furthermore, the push to use coal to close the energy gap has stalled.

According to WWF Vietnam, there are currently 68 coal-fired power plants in some stage of planning or development nationwide. But many of these projects are delayed.

An August 2019 article by Market Forces, an Australian organization that tracks fossil fuel investment, found that 57 percent of planned coal power capacity is delayed while, of those projects, 93 percent of the projects financed through the build-operate-transfer (BOT) model have been postponed. All told, investors in Vietnamese coal power projects face a cumulative delay of 100 years.

Why the wait?

Market Forces lists three main causes for these delays: corruption; issues with engineering, procurement and construction (EPC) contractors; and local opposition. The Long Phu 1 and Thai Binh 2 plants, for example have run into problems because of corruption charges against the former chairman of PetroVietnam, the state-owned oil giant. Both of them, along with the Nghi Son 2 project, have also been slowed by financial struggles among their investors.

Local opposition and environmental concerns have delayed work elsewhere, such as in the Mekong Delta province of Long An and in Khanh Hoa province on the south-central coast, where residents have raised concerns about the environmental impact. Resettlement has also proved difficult, as residents and officials tussle over land compensation fees.

Another major contributing factor in these delays is the global movement away from coal power. South Korea, Japan and China have long been the three biggest investors in thermal power in Vietnam. For example, in April, the governor of the Japan Bank for International Cooperation (JBIC), a major investor in overseas coal-fired power plants, said the institution would stop accepting loan applications for these projects, though it remains unclear whether this is a set policy shift.

Peng Ren, Program Manager at the Global Environmental Institute (GEI), says a debate is underway in China too. “There are discussions among Chinese industries to be aware of the risks of continuing to invest in coal in other countries.”

“But you have to think about new developments in the global pandemic, and the country has released an economic recovery package, and we’re really concerned about fossil fuels or coal being one of the tools to stimulate the economy,” he adds. 

GAS TURBINES

AAF High Efficiency Intake Filters Used on BP Clair Platform

“When it comes to protecting gas turbines from offshore air, and all that is contained within, air filtration systems play a critical role, operating on the front line of defense” says Graeme Turnbull of AAF International. Currently, around 85 percent of offshore gas turbines are protected by small high velocity filtration systems that use low efficiency filter bags. These only provide protection against coarse particles and fail to capture sub-micron particles offshore. It is worth noting that the air quality at platform level is significantly different to sea level. At the height of an offshore platform the majority of particles in the air are sub-micron in size. The vast majority of particles of this size will pass through high velocity filter bags; in fact, only 5 percent will be captured. This can lead to lost production revenue, unplanned gas turbine shutdowns, reduced component and engine life, premature engine failure, and low turbine compression efficiency and high CO2 emissions; especially unwanted given today’s current market dynamics and the low price of oil. By contrast, high efficiency particulate air filter (EPA) 12 technology captures 99.95 percent of sub-micron particles. This protects and enhances the performance of expensive gas turbine components.

As operators have become aware of the benefits of EPA E12 air intake filtration, there has been a push to upgrade existing high velocity units installed offshore. However, traditional EPA E12 filtration technologies — with much larger equipment envelopes — have necessitated that the air intake housing is replaced in its entirety. This increases foundation loads and incurs significant costs and down time. However, there is another route, using a new EPA E12 system which provides all the associated benefits of EPA E12 air filtration, but can be quickly and seamlessly installed within the existing high velocity air intake filtration system.

BP’s Clair platform operates three Titan 130 gas turbines (GTs 1, 2 and 3) employed in power generation application to provide power to the asset. Each gas turbine was experiencing compressor blade fouling, corrosion and erosion, as well as turbine section hot gas path corrosion. Operationally, this resulted in poor engine reliability, reduced availability and premature engine overhaul and/or replacement; all of which severely impeded the long-term strategic planning for the platform for both production and maintenance.

Eventually, the poor filtration provided by the high velocity bag system resulted in a catastrophic failure of GT2 after 12,000 operating hours, which equated to only one-third of the engine design life. The root cause of the failure being inlet guide vane seizure and in turn compressor section imbalance and ultimately blade liberation. This resulted in irreparable damage and a new replacement engine was required, incurring unplanned long-term shutdown and significant unbudgeted costs.

BP was aware that AAF International was in the final stages of developing a new EPA E12 high velocity filtration solution. Critically this new design could be installed within an existing high velocity housing with no penalty in differential pressure (dP), therefore negating the need for a larger housing replacement. Because of this failure on GT2, BP was expediting the GT original equipment manufacturer (OEM) for fast-track delivery of a replacement engine and approached AAF to determine if this new technology (N-hance) could be urgently deployed in a field trial as a technology collaboration initiative.

Thanks to a longstanding relationship between the two companies, BP was able and confident to pilot AAF’s N-hance technology. The N-hance filters and conversion parts were delivered to the operator within five weeks and commissioned along with the new GT2 engine on the Clair platform in February 2017.

The pilot delivered excellent results. There was an increase in engine availability resulting from a reduction in unplanned downtime and shortened shutdown periods. There was also a decrease in CO2 emissions improving sustainability, as well as retained power output (compressor efficiency) and heat rate. Critically, BP has also eliminated the risk of potential GT failure due to corrosion at just one-third of design life.

Commenting on the project, BP’s asset team said: “The upgrade project has enabled improved reliability, cost savings and will feed into the reformation of outdated air filtration standards as well as playing a part in helping to achieve offshore asset efficiency of 90 percent.”

EPA E12 air filtration is currently available within low velocity systems and already in use on assets owned by super majors. However, few operators are aware that EPA E12 filtration is now supported within high velocity systems. This is partially due to the fact there needs to be significantly more support for the widespread adoption of the technology used on the Clair platform. This includes the adoption of EPA E12:EN1822 standards within OEM offshore turbine specifications to extend the life of all new gas turbines operating in the offshore environment and provide the operator with the added benefit of a small and lightweight filter housing in comparison to the traditional low velocity large E12 filter housings. Operators also have their part to play and need to question why they are repeatedly offered low efficiency filter bags for high velocity systems. The accepted norms of poor air filtration in offshore environments can be redefined, and operators can benefit from the improved technology.

Immediately, the result will be to eliminate frequent water washing of the gas turbine, increasing production efficiency while at the same time providing a longer operational life of the gas turbine. Furthermore, a sustained effort is needed to communicate the evolution in filtration performance and demonstrate the findings, which support the use of new proven EPA E12 technologies.

Graeme summarizes in an Offshore article with “Collectively if adopted by the offshore oil and gas industry, these measures trigger a new “front end” approach to gas turbine reliability and availability, which is beginning to gain momentum in some areas of the sector. With cost control and environmental improvements, such as CO₂ reduction now more critical than ever, taking the necessary steps to address current technology adoption should be delayed no further.

”You can view the full article at https://www.offshore-mag.com/business-briefs/equipment-engineering/article/14176563/air-filtration-system-helps-improve-gas-turbine-performance-on-bps-clair-platform.

Gas Turbine lnlet Filters for LNG Plants

Gas turbine inlet filters for LNG plants were analyzed in a recent Diesel and Gas Turbine Worlwide by Peter McGuigan, Global LNG Market Manager for the Parker Gas Turbine Filtration Division.

Land-based refrigerant compressor stations for the liquefaction of methane are always located near coastlines to facilitate onward tanker transport of the LNG. This means gas turbines will be exposed to dust, moisture, salt and many other airborne contaminants, all of which will put gas turbine operations in jeopardy if not addressed 

“Gas turbines ingest enormous amount of air, and the operators realize that any salts or hydrocarbons, any nasty stuff getting into their gas turbines will significantly impact operations. And then they connect the dots in terms of lost potential, lost revenue,” McGuigan said. “And they’re very, very risk averse as a result.”

With the colossal volumes of air passing through a gas turbine air inlet, having the correct inlet filtration system in place is vital for ensuring ongoing reliable operations. To handle these various, contaminants, protect the turbines and avoid shutdown on the basis of either pressure loss (DP) increase or degradation in output, LNG filtration systems typically have multiple stages. Ensuring the right stages of filters are selected has a huge impact on the overall process availability, reliability and profitability. A filtration system that is correctly designed and engineered to meet the real-world conditions of the gas turbine installation can mean shutdowns are limited to scheduled maintenance periods only. Choosing the wrong system, however, can have major financial repercussions. For LNG applications, the turbine needs to be protected from the corrosion, erosion and fouling which would be caused by salt and particulate getting downstream, with a primary focus on keeping the turbine operating reliably and predictably over long periods of time.

The inlet filtration system for an LNG process turbine can have three, four or even five unique stages, providing an ability to change filters online without the need to shut down the turbine. The first few (prefilter) stages are designed to remove larger particles and extend the life of the later (high efficiency) stages. As prefilters can typically be changed out without taking the turbine offline, designs that facilitate quick change out need to be incorporated. The final filtration stage should use high efficiency hydrophobic media, typically rated F9 (EN779) to E12 (EN1822) to achieve optimum results. Options to use an extended 24-in. deep final filter (compared with traditional 12- in. to 17-in. vCell filter depths), provides for extended filter service life if required. Another area for consideration in correct filter selection is the type of high efficiency media used. Levels of moisture are obviously going to be high in offshore and coastal environments, and small moisture droplets can quickly block thin ePTFE membranes. Sudden blockages equate to sudden and unpredictable pressure spikes (the ‘hockey stick’ effect), which can result in complete turbine (and therefore plant) shutdown.

Microfiber glass media, however, offers the same efficiency but is around 10 times thicker, making it more resistant to blockage and more predictable in its performance, with slow, gradual, pressure increases as contaminant is captured. To avoid unplanned maintenance activities, filters should be designed for long life. Prefilters should require changing no more than around once per year. Second-stage filters once every two years, and third- or fourth-stage filters around just once every three to four years. If a filtration system requires more regular maintenance, a review of its design and the choice of filter grades used is recommended.

Filter system designers are continually developing and improving technology to enhance performance in challenging offshore and onshore installations. When considering the result of an unexpected shutdown, investment in the right filtration solution offers operators lightening quick return on investment.

McGuigan said operators tend to understand the importance of filtration but aren’t always able to keep abreast of developments and new technologies.

“They absolutely get right from the outset, every single one of these LNG operators get the quality of air entering the gas turbine is one of the things that, if they don’t adequately control, they’re in big trouble,” McGuigan said. “But a lot of them aren’t aware of the latest technologies. So that’s my job to educate and tell them what’s new and what extra incremental benefits new technologies can bring to their operations.

“What I’m feeling, and my genuine belief is that LNG operators want more than just the filter, they want the expertise, the recommendations, the new product development, all the kind of stuff that goes with a customer-operations focused, leading-edge company.” The full article can be viewed at https://dieselgasturbine.com/clearing-the-air-at-lng-processing-facilities/.

AFRY Awarded Contract for Thailand Power Plants 

B. Grimm Power, one of South East Asia’s largest private power producers, have awarded AFRY with an Owner’s Engineer services assignment for six gas-fired cogeneration power plant projects in Rayong, Chonburi & Ang Thong provinces in Thailand. Construction of the first project started in May and the remaining projects will start before the end of the year.

The six projects are located across four site locations serving industrial power and heat customers in Laem Chanang, Amata City, Asia Rayong and World Food Valley Industrial Estates. A total of 14 gas turbines, 14 HRSGs, 7 steam turbines and balance of plant equipment will be installed, with a combined electrical output of approximately 1000 MW.

AFRY's assignment includes assistance in project management, design review, site supervision services, quality assurance and control and commissioning super vision. The overall duration for AFRY's services is about three years. 

WASTE-TO-ENERGY

MHIEC Receives Order to Refurbish Core Equipment of the Kushiro Wide-Area Federation WtE Plant in Kushiro, Hokkaido

Mitsubishi Heavy Industries Environmental & Chemical Engineering Co., Ltd. (MHIEC), a Group company of Mitsubishi Heavy Industries, Ltd. (MHI), has received an order from the Kushiro Wide-Area Federation, comprising the city of Kushiro and five other Hokkaido municipalities, for repair and improvement of core equipment at the Kushiro Wide-Area Federation Waste-to-Energy (WtE) Plant in Takayama, Kushiro. The facility has a total waste treatment capacity of 240 tons per day (tpd). MHIEC will refurbish and improve the fluidized bed type gasification and ash melting furnace (1) and related equipment, extending the working life of the facility and enhancing its energy efficiency. The contract is valued at 3,993 million Japanese yen. Completion is scheduled for September 2023.

The Kushiro Wide-Area Federation was established in 2002 under the provisions of the revised Local Autonomy Act. It currently manages the incineration of waste for the municipalities of Kushiro-shi, Kushiro-cho, Akkeshi-cho, Teshikaga-cho, Tsurui-mura, and Shiranuka-cho. The WtE plant was designed and built by MHI. It was completed in March 2006 and began operations in April that year. Kushiro Eco-Creation Co., Ltd., in which MHIEC holds a 90 percent stake, provides operations and maintenance work under a 15-year, long-term comprehensive contract. The plant comprises two lines of fluidized bed type gasification and ash melting furnace and related equipment, each with capacity of 120 tpd. It has an electricity generating capacity of 4.6 megawatts (MW).

The core facilities renovation contract comprises the renewal of superannuated key components of the facility, including the waste receiving and feeding equipment, gasification and ash melting furnace, waste heat boiler, and flue gas treatment system. The renovation will introduce high-efficiency motors and invertors to increase energy efficiency, as well as hybrid bag filters with dioxin decomposition functionality (2), and a low-temperature catalyst for the denitrification equipment to increase the heat recovery rate. These measures will reduce CO2 emissions by around 15 percent annually, helping to curb global warming. This is the first order for repair and improvement of core equipment MHIEC has received for a WtE plant for which it has a long-term comprehensive contract for operations and maintenance by MHIEC Group.

Renovation of WtE plants is increasing as operators aim to extend the service life of facilities and reduce their environmental impact. The Japanese national government also established a related subsidy system (3) in fiscal 2010, further accelerating this trend.

MHIEC took over MHI's environmental protection business in 2008, incorporating its accumulated technological development capabilities in environmental protection systems, and its broad expertise in the construction and operation of waste management facilities both in Japan and overseas. Based on this strong track record, MHIEC is well-positioned to provide comprehensive solutions, from plant construction to operation.

Going forward, on the strength of this record and boosted by this latest contract, MHIEC will pursue additional renovation projects to enhance the energy efficiency and stable operation of existing plants, and actively offer solutions to lower operation and maintenance expenses and other lifecycle costs.

(1) The fluidized bed type gasification and ash melting furnace utilizes a pre-process fluidized bed gasification furnace for thermal cracking (carbonization) under low-oxygen conditions of waste into inflammable gas and unburned hydrocarbons. These gases and unburned hydrocarbons are fed into the post-process combustion melting furnace and immediately combusted, with the vitrified molten slag becoming a reduced, recycled material. This system is a practical application of a next-generation incinerator developed in response to the increasingly serious dioxin and environmental issues of the 1990s.

(2) Hybrid bag filters, in addition to removing toxic substances, have coatings of a catalyst on the bag filter fibers that provide additional functionality to decompose gaseous dioxins and nitrogen oxide (NOx). See the following website for details. (Japanese) https://www.mhiec.co.jp/jp/products/recycle/city/hbf/index.html

3) This program, administered by Japan's Ministry of the Environment, is centered on improvements to existing facilities for more effective use, and as a measure to address climate change in the waste sector. Municipal governments seeking to extend the working life of their MSW facilities and implement climate change measures are eligible for subsidies on projects that reduce CO2 emissions (promoting the introduction of leading-edge facilities), or grants for establishing a sound material-cycle society, equivalent to one-half or one-third of project costs.

MHIEC Receives Order to Refurbish the Minato WtE Plant in Tokyo

Mitsubishi Heavy Industries Environmental & Chemical Engineering Co., Ltd. (MHIEC), a Group company of Mitsubishi Heavy Industries, Ltd. (MHI), has received an order from Clean Authority of TOKYO for facility renovation to extend the service life of its Minato Waste-to-Energy (WtE) Plant. The facility has a total waste treatment capacity of 900 tons per day (tpd). MHIEC will refurbish and improve the stoker type incinerators (1) and related equipment, extending the service life of the facility, and enhancing its energy efficiency. The contract is valued at 7.6 billion Japanese yen, with completion scheduled for January 2023 (three-year project). MHIEC received a similar order from Clean Authority of TOKYO in fiscal 2016 to extend the service life of its Ariake WtE Plant, which was completed in fiscal 2019. This order succeeds in that previous project.

Clean Authority of TOKYO was established in fiscal 2000 to handle waste treatment for Tokyo's 23 wards. Located in the Chiyoda Ward main government building, the organization manages 21 plants throughout the city, including facilities undergoing renovation. The Minato WtE Plant was designed and built by MHI and completed in January 1999. The WtE facility comprises three stoker type incinerators and related equipment, each with capacity of 300 tpd, and can generate up to 22 megawatts (MW) of electricity.

The plant facility renovation contract to extend service life covers refurbishment of superannuated main equipment, including the refuse feeder and incinerator furnace, along with equipment for ash treatment, bag filter, scrubber, boilers, power generators, and steam condensers, as well as electric instrumentation and water supply systems. The adoption of nickel base alloy cladding technology to counter boiler tube thinning, upgrading of main equipment for steam turbines and power generators, and improved combustion with control technologies utilizing infrared (IR) sensors, will allow for long-term stable incineration and operation. The facility will also utilize high-efficiency motors and inverters for electric components to increase energy efficiency. These measures will reduce CO2 emissions by around 4 percent annually, helping to curb global warming.

Renovation of WtE plants is increasing as operators aim to extend the service life of facilities and reduce their environmental impact. The Japanese national government also established a related subsidy system (2) in fiscal 2010, further accelerating this trend.

MHIEC succeeded MHI's environmental protection business in 2008, incorporating its accumulated technological development capabilities in environmental protection systems, and its broad expertise in the construction and operation of waste management facilities both in Japan and overseas. Based on this strong track record, MHIEC is well-positioned to provide comprehensive solutions, from plant construction to operation.

Going forward, on the strength of this record and boosted by this latest contract, MHIEC will pursue additional renovation projects to enhance the energy efficiency and stable operation of existing plants, and actively offer solutions to lower operation and maintenance expenses and other lifecycle costs.

(1) A stoker furnace is the main type of WtE plant. Waste is combusted as it moves along on a fire grate made of heat-resistant castings.

(2) This program, administered by Japan's Ministry of the Environment, is centered on improvements to existing facilities for more effective use, and as a measure to mitigate climate change in the waste sector. Municipal governments seeking to extend the working life of their MSW facilities and implement climate change measures are eligible for subsidies on projects that reduce CO2 emissions (promoting the introduction of leading-edge facilities), or grants for establishing a sound material-cycle society, equivalent to one-half or one-third of project costs.

Fourth Wheelabrator Technologies Waste-to-Energy Facility in the UK Sees Total Capacity Delivered Reach 2.4 Million Tons (2.2 Million Tonnes)

Wheelabrator Kemsley, a new waste-to-energy facility at Kemsley in Kent, England, enters full commercial operation following a successful commissioning phase throughout early 2020.

Wheelabrator Kemsley is now operational as a combined heat and power facility and will generate up to 49.9 MW (gross)/44 MW (net) of sustainable, baseload electricity to power UK homes and businesses. The facility will process up to 606,000 tons (550,000 tonnes) of non-recyclable waste from across Kent and the South East. The facility is pending planning approval for additional waste capacity and electrical output.

The facility will play a major role in reducing waste sent to landfill or for European export, saving carbon emissions when compared with sending the waste to landfill and making better use of non-recyclable material in the UK through the energy recovery process. It will also provide valuable steam heat – up to 77.4 tons (70 tonnes) per hour – to DS Smith's adjacent Kemsley Paper Mill, helping to diversify its energy requirements.

Wheelabrator Technologies, the largest pure play waste-to-energy platform and fourth-largest waste-to-energy business in the UK, will process 2.4 million tons (2.2 million tonnes) of non-recyclable household and commercial waste each year, in turn generating 1.1 net MWh of baseload energy, enough to power around 500,000 UK homes and businesses. The portfolio of four strategically located assets includes:

Wheelabrator Kemsley was built by EPC contractor CNIM, and in the four years of construction more than 800 jobs were created, including 46 full-time operational roles, and significant inward investment across the region was generated as a result of construction. With a strong focus on safety, there have been more than four million manhours without a single lost-time incident and commissioning during early 2020 was completed carefully in line with UK Government COVID-19 safety and social distancing guidance.

Robert Boucher, President and CEO at Wheelabrator Technologies, said: "To be able to complete construction, hot commissioning, grid synchronization and steam export to DS Smith during the COVID-19 pandemic is a fantastic accomplishment and a testament to the commitment of our team and our partners to work safely and Make a Difference. Takeover at Kemsley is the result of many years of commitment, hard work and strong partnerships with DS Smith, our customers and the communities we operate within."

Colin McIntyre, CEO of DS Smith's Paper and Recycling divisions said, "Harvesting steam from Wheelabrator Technologies facility for our paper mill at Kemsley is a key part of our energy strategy. As the largest mill for recycled paper in the UK, processing almost 1.1 million tons (1 million tonnes) of paper for recycling a year, achieving the right energy mix is vital. With the facility fully operationally, it will supply us with a third of the steam required to run our paper making operations.

"We are delighted with our strategic energy partnership with Wheelabrator, a partnership which enables a carbon reduction of 86,000 tons (78,000 tonnes) per year and contributes to one of our nine ambitious long-term sustainability targets — to reduce our CO2 e emissions by 30 percent per ton of production by 2030." 

BIOMASS

Bioenergy with Carbon Capture and Storage Will Be An Essential Part of the Energy System

Drax is leading the way in using Bioenergy with Carbon Capture and Storage (BECCS) to address climate change. McIlvaine has written several news releases on this subject.

Opportunistic Biomass - CCS Program is the Route chosen by the UK and Japan

Climate Change and the Quality of Life

The Opportunistic Antidote to the Climate Change Doomsday Scenario

The effort is now centered on obtaining the public support and investment. The following information is taken from the Drax website.

The Committee on Climate Change (CCC) says negative emissions are essential for the UK to offset difficult-to-decarbonize sectors of the economy and meet its net zero target. This may include direct air capture (DAC) and other negative emissions technologies, as well as BECCS.

BECCS power generation uses biomass grown in sustainably managed forests as fuel to generate electricity. As these forests absorb CO2 from the atmosphere while growing, they offset the amount of CO2 released by the fuel when used, making the whole power production process carbon neutral. Adding carbon capture and storage to this process results in removing more CO2 from the atmosphere than is emitted, making it carbon negative.

Pine trees grown for planting in the forests of the U.S. South where more carbon is stored, and more wood inventory is grown each year than fiber is extracted for wood products such as biomass pellets.

This means BECCS can be used to abate, or offset, emissions from other parts of the economy that might remain even as it decarbonizes. A report by The Energy Systems Catapult, modelling different approaches for the UK to reach net zero by or before 2050, suggests carbon-intensive industries such as aviation and agriculture will always produce residual emissions.

The need to counteract the remaining emissions of industries such as these make negative emissions an essential part of reaching net zero. While the report suggests that direct air carbon capture and storage (DACCS) will also play an important role in bringing CO2 levels down, it will take time for the technology to be developed and deployed at the scale needed.

Meanwhile, carbon capture use and storage (CCUS) technology is already deployed at scale in Norway, the US, Australia and Canada. These processes for capturing and storing carbon are applicable to biomass power generation, such as at Drax Power Station, which means BECCS is ready to deploy at scale from a technology perspective today.

The CCC’s “Hydrogen in a low-carbon economy report” highlights the needs for carbon zero alternatives to fossil fuels — in particular, hydrogen or H2.

When combusted, hydrogen only produces heat and water vapor, while the ability to store it for long periods makes it a cleaner replacement to the natural gas used in heating today. Hydrogen can also be stored as a liquid, which, coupled with its high energy density makes it a carbon zero alternative to petrol and diesel in heavy transport.

There are various ways BECCS can assist the creation of a hydrogen economy. Most promising is the use of biomass to produce hydrogen through a method known as gasification. In this process solid organic material is heated to more than 700°C but prevented from combusting. This causes the material to break down into gases: hydrogen and carbon monoxide (CO). The CO then reacts with water to form CO2 and more H2.

While CO2 is also produced as part of the process, biomass material absorbs CO2 while it grows, making the overall process carbon neutral. However, by deploying carbon capture here, the hydrogen production can also be made carbon negative.

BECCS can more indirectly become an enabler of hydrogen production. The Zero Carbon Humber partnership envisages Drax Power Station as the anchor project for CCUS infrastructure in the region, allowing for the production of ‘blue’ hydrogen. Blue hydrogen is produced using natural gas, a fossil fuel. However, the resulting carbon emissions could be captured. The CO2 would then be transported and stored using the same system of pipelines and a natural aquifer under the North Sea as used by BECCS facilities at Drax.

This way of clustering BECCS power and hydrogen production would also allow other industries such as manufactures, steel mills and refineries, to decarbonize.

One of the challenges in transforming the energy system and wider economy to net zero is accounting for the cost of the transition.

The Energy Systems Catapult’s analysis found that it could be kept as low as 1-2 percent of GDP, while a report by the National Infrastructure Commission (NIC) projects that deploying BECCS would have little impact on the total cost of the power system if deployed for its negative emissions potential.

The NIC’s modeling found, when taking into consideration the costs and generation capacity of different sources, BECCS would likely be run as a baseload source of power in a net zero future. This would maximize its negative emissions potential.

This means BECCS units would run frequently and for long periods, uninterrupted by changes in the weather, rather than jumping into action to account for peaks in demand. This, coupled with its ability to abate emissions, means BECCS — alongside intermittent renewables such as wind and solar — could provide the UK with zero carbon electricity at a significantly lower cost than that of constructing a new fleet of nuclear power stations.

The report also goes on to say that a fleet of hydrogen-fueled power stations could also be used to generate flexible back-up electricity, which therefore could be substantially cheaper than relying on a fleet of new baseload nuclear plants.

However, for this to work effectively, decisions need to be made sooner rather than later as to what approach the UK takes to shape the energy system before 2050.

A joint Royal Society and Royal Academy of Engineering Greenhouse Gas Removal report, includes research into BECCS, DACCS and other forms of negative emissions in its list of key actions for the UK to reach net zero. It also calls for the UK to capitalize on its access to natural aquifers and former oil and gas wells for CO2 storage in locations such as the North Sea, as well as its engineering expertise, to establish the infrastructure needed for CO2 transport and storage.

However, this will require policies and funding structures that make it economical. A report by Vivid Economics for the Department for Business, Energy and Industrial Strategy (BEIS) highlights that—just as incentives have made wind and solar viable and integral parts of the UK’s energy mix — BECCS and other technologies, need the same clear, long-term strategy to enable companies to make secure investments and innovate.

Beyond just decarbonizing the UK, a report by the Intergovernmental Panel on Climate Change (IPCC) highlights that BECCS could be of even more importance globally. Differing scales of BECCS deployment are illustrated in its scenarios where global warming is kept to within 1.5o C levels of pre-industrial levels, as per the Paris Climate agreement

BECCS has the potential to play a vital role in power generation, creating a hydrogen economy and offsetting other emissions. As it continues to progress, it is becoming increasingly effective and cost efficient, offering a key component of a net zero UK.

CO2

Fluor Awarded Front-End Engineering and Design Contract for California Resources Corporation Carbon Capture Project

Fluor Corp. announced that it was awarded a front-end engineering and design (FEED) contract for California Resources Corp.’s (CRC) carbon capture and sequestration project, Cal Capture, at the 550-megawatt, natural gas-powered Elk Hills Power Plant in Tupman, CA. The FEED is being AAfunded by the U.S. Department of Energy (DOE) through collaboration with the Electric Power Research Institute (EPRI) as part of a larger initiative to advance carbon capture technology development 

“Fluor’s commitment to helping clients achieve their clean energy goals continues with this recent award from CRC,” said Mark Fields, group president of Fluor’s Energy & Chemicals business. “We are honored to be selected by CRC to help them design and permit California’s first carbon capture and sequestration system.”

Fluor’s scope of work is as the licensor providing engineering services for the plant’s licensed process unit and required utility systems using its proprietary Econamine FG PlusSM carbon capture technology, which is an energy-efficient and cost-effective process for the removal of carbon dioxide from flue gas streams. The process will incorporate Fluor’s advanced solvent formulation together with a number of patented energy savings features. The execution of the project is a collaborative effort between EPRI, CRC and Fluor. The DOE award was made to EPRI, which has led the interface with the DOE. CRC is providing the project oversight and defining the basis of the FEED.

“CRC has four 2030 sustainability goals that align with those of the State of California. Our carbon goal is to design and permit a carbon dioxide (CO2) capture and storage system – the Cal Capture project — at our Elk Hills Power Plant with associated CO2 injection for enhanced recovery and sequestration at the adjacent Elk Hills oil field,” said Shawn Kerns, CRC Executive Vice President of Operations and Engineering. “The Cal Capture project offers multiple benefits including substantial emissions reductions, substantial positive economic impacts across the California economy and the development of a key technology needed worldwide to meet future energy transition targets.”

8 Rivers Capital Wins Seven Department of Energy Carbon Capture Grants Worth Over $30 Million to Develop World-Leading Technologies for Low-to-Negative Carbon Power

8 Rivers Capital, LLC, was awarded seven US Department of Energy (DOE) grants worth over $30 Million to further develop its world-leading carbon capture technologies for flexible clean electricity that allows customers to achieve their net-zero ambitions. These projects will advance the Allam-Fetvedt Cycle, Lime Direct Air Capture, and the Carbon8 technologies invented by 8 Rivers, and continue 8 Rivers' 10 years of innovative leadership in advancing the global energy transition towards a net-zero carbon economy.

8 Rivers is partnering with global leaders in carbon capture to deliver this multi-million-dollar suite of projects:

Bill Brown CEO at 8 Rivers Capital, said, "By making clean cheaper than dirty, the 8 Rivers technology platform creates the economics that allows the world to achieve net-zero emissions by 2050.  Our mission is social at its very core:  the world can only achieve its climate goals if we drive the cost of electricity down to a level that every human being can afford. We are grateful for the opportunity to work on seven projects with our world-class partners at GE, MIT, NREL, PSI, SWRI, and UNOTech, advancing the DOE's goals for carbon capture and the world's goals for hitting net-zero emissions."

8 Rivers will be the Principal Investigator on two grants and provide its world leading carbon capture expertise to the five other projects. The DOE's Advanced Projects Research Agency for Energy (ARPA-E) is supporting four of these innovative projects through its new Flexible Carbon Capture and Storage program, which aims to develop carbon capture technologies that can be responsive to grid conditions with large amounts of solar and wind. The two syngas projects will be funded through DOE's Critical Components for Coal FIRST Power Plants grant program.

8 Rivers sees a large global demand for its portfolio of low- and negative-carbon technologies. 8 Rivers' technologies for oxy combustion, retrofit carbon capture, and direct air capture (either through machines or, better yet, through working with nature's own processes) provides a necessary and enabling complement to solar and wind power, while helping the world to reach even deeper decarbonization targets at the lowest cost. In its recent 1.5 degrees report, the IPCC recognized that carbon capture is essential for the world to reach net-zero emissions by 2050.

ExxonMobil Collaborates on Discovery of New Material to Enhance Carbon Capture Technology

Scientists from ExxonMobil, University of California, Berkeley and Lawrence Berkeley National Laboratory have discovered a new material that could capture more than 90 percent of CO2 emitted from industrial sources, such as natural gas-fired power plants, using low-temperature steam, requiring less energy for the overall carbon capture process.

Laboratory tests indicate the patent-pending materials, known as tetraamine-functionalized metal organic frameworks, capture carbon dioxide emissions up to six times more effectively than conventional amine-based carbon capture technology. Using less energy to capture and remove carbon, the material has the potential to reduce the cost of the technology and eventually support commercial applications.

By manipulating the structure of the metal organic framework material, the team of scientists and students demonstrated the ability to condense a surface area the size of a football field, into just one gram of mass — about the same as a paperclip — that acts as a sponge for CO2. Results of the research were published today (July 24) in the international peer-reviewed journal, Science.

“This innovative hybrid porous material has so far proven to be more effective, requires less heating and cooling, and captures more CO2 than current materials,” said Vijay Swarup, Vice President of Research and Development at ExxonMobil Research and Engineering Co.

“Through collaborations with strong academic institutions and national labs like UC Berkeley and the Lawrence Berkeley National Laboratory, we are developing a portfolio of lower-emissions energy solutions. This provides yet another example of one of the many new materials ExxonMobil is researching to reduce CO2 in the production of energy,” said Swarup.

ExxonMobil’s team, led by Senior Research Associate Simon Weston, along with UC Berkeley’s professor Jeffrey Long and his team of faculty and students have been working collaboratively for eight years to develop this potential carbon capture solution that demonstrates stability in the presence of water vapor, without oxidation, allowing carbon dioxide to be captured from various sources, under a number of conditions.

Additional research and development will be needed to progress this technology to a larger scale pilot and ultimately to industrial scale.

The research successfully demonstrated that these hybrid porous metal-organic materials are highly selective and could capture more than 90 percent of the CO2 emitted from industrial sources. The materials have much greater capacity for capturing carbon dioxide and can be regenerated for repeated use by using low-temperature steam, requiring less energy for the overall carbon capture process.

“This exciting advance for carbon capture technology is an outstanding example of how scientists with diverse expertise from universities, national labs, and industry can come together to solve fundamental research challenges,” said Jeffrey Long, Professor of Chemistry and Chemical and Biomolecular Engineering at University of California, Berkeley and faculty senior scientist at Lawrence Berkeley National Laboratory. “We are grateful to have had such long-term research support from ExxonMobil, without which this discovery would not have been possible. I hope this success will serve to encourage further partnerships between industry and academic research labs.”

ExxonMobil is the world leader in carbon capture, capturing more carbon dioxide than any other company since 1970 and working on a portfolio of carbon capture technologies in collaboration with others. Since 2000, ExxonMobil has invested approximately $10 billion in projects to research, develop and deploy lower-emission energy solutions. The company continues to expand collaborative efforts with more than 80 universities, five energy centers and multiple private sector partners around the world to explore next-generation energy technologies.

The researchers on the technology as written in Science include Simon Weston and Joseph Falkowski from ExxonMobil; Eugene Kim, Henry Jiang, Alexander Forse, Jeffrey Martell, Phillip Milner from the University of California, Berkeley; and Rebecca Siegelman, Jung-Hoon Lee, Jeffrey Neaton, Jeffrey Reimer, Jeffrey Long from the University of California, Berkeley and Lawrence Berkeley National Laboratory.  

BUSINESS

Emerson and MHPS Collaborate on Power Industry Digital Transformation

Emerson and Mitsubishi Hitachi Power Systems Americas are joining forces again to develop digital technologies, software and services to help utility customers drive operational excellence in North America. The companies will collaborate on digital solutions to optimize performance and reliability, enable predictive and AI-driven maintenance strategies, and automate operational decision-making.

The collaboration will build on the expertise of Emerson and MHPS to enhance the performance and reliability of power plants operating with MHPS gas or steam turbines.

Emerson’s Ovation™ automation technologies, software and solutions portfolio for power generation is highly regarded in the industry, controlling thousands of plants across the globe. Its embedded digital twin enables power plants to identify and implement new operating efficiencies, improve safety, decrease unscheduled maintenance and train workers.

As a leading global provider of power generation and energy storage solutions, MHPS is driving the development of next-generation power plants and digital solutions that deliver higher efficiencies to reduce carbon emissions and the highest levels of reliability to lower maintenance costs. Its industry-known MHPS-TOMONI™ digital solutions platform provides real-time adaptive control and actionable knowledge to optimize plant performance and significantly improve reliability.

“Emerson has worked collaboratively with MHPS for over a decade to bring the best experts, technologies and services to the power generation industry,” said Bob Yeager, President of Emerson’s power and water solutions business. “This next chapter will focus on identifying and delivering the best digital transformation strategies and technologies that will drive operational performance for our customers and create cleaner, more reliable power for consumers.”

The two companies will explore these and other advanced technologies: advanced sensing; thermal, process and equipment modeling and diagnostics; advanced control; analytics; pattern recognition; remote monitoring; digital twin; automated workflows; and AI-driven predictive maintenance.

One of the companies’ collaborations is to build and deploy the next generation of total plant simulation for the Intermountain Power Plant Renewal project. “This collaboration leverages Emerson’s digital twin technology, MHPS’ high-fidelity gas turbine and steam turbine models, and advanced analytics. The simulation solution will seamlessly receive data and operate in parallel with the plant’s integrated control systems and other enterprise platforms to support commissioning and training,” said Marco Sanchez, Vice President of Intelligent Solutions at MHPS.

Paul Browning, president and CEO of MHPS Americas and chief regional officer for Europe, Africa, the Middle East and the Americas, said, “MHPS looks forward to this next stage of collaboration with Emerson as we continue developing digital solutions that will enable our customers to provide affordable and reliable electricity, maximize profitability of existing and future power plants, and combat climate change. Together with Emerson and our customers, we will achieve a Change in Power.”

CECO Holding Its Own In Tough Market

CECO Environmental Corp., reported its financial results for the 2nd quarter and first six months of 2020.

Todd Gleason, CECO's Chief Executive Officer, commented, "During the 2nd quarter, the CECO team delivered focused execution and solid customer service while adjusting for the disruptions associated with the wide-spread COVID-19 pandemic. The company enacted proactive measures to reduce costs in anticipation of the market declines, which maintained strong profitability and margin rates while streamlining operations for future quarters. Additionally, we executed the EIS acquisition, which advances our industrial solutions portfolio and positions us for growth in the European industrial markets.

Mr. Gleason added, "As I come to the end of my first month with the company, I have enjoyed connecting with our talented team members, and immersing myself in how we will collectively create more value — for our customers, employees, and shareholders. I am excited to be on the CECO team and look forward to driving new growth and sustainable business processes as we build upon our strong foundation."

Power-Gen Postponed Until March 30 Next Year

As a consequence of the ongoing impact of the COVID-19 (coronavirus) pandemic, POWER-GEN International and DISTRIBUTECH International, will be postponed to March 30-April 1, 2021. In light of both governmental direction and general public health advisories delivering POWER-GEN International and DISTRIBUTECH International will not be possible at this time with the ongoing impact of the COVID-19 pandemic and the government issued guidelines for large gatherings.

“This has been a difficult decision but the health and safety of our attendees, exhibitors, speakers, employees and the wider public is of paramount importance to us. We must comply with the strict public health guidelines and directives. Unfortunately, the implementation of these government regulations make it impractical to run a large-scale event.  We have also reached out to our power generation and transmission & distribution communities and listened to their input around uncertainty and concerns for gathering this coming winter. We are confident that postponing POWER-GEN International and DISTRIBUTECH International to spring 2021 will ensure a successful and safe delivery of the events,” said Desiree Hanson, Executive Vice President, Clarion Events.

The postponed events will open further opportunity for helping energy professionals navigate through the complex energy transition by conveniently co-locating POWER-GEN International, the world’s largest power generation event, with DISTRIBUTECH International, the leading annual transmission & distribution event. The co-location will result in bringing the energy industry together for these two powerhouse events happening next to each other, under one roof. While these events will remain separate, holding them alongside each other will allow attendees to conveniently access both exhibition halls and educational offerings. In addition, it will provide further opportunities to connect these two audiences for networking, bringing them together to shape the future of energy and experience the energy movement.

As previously announced, POWER-GEN International 2021 will also be home to the newly created Leadership Summit. The two-and-a-half-day executive level summit will address the challenges facing the power generation and transmission & distribution sectors. Speakers and panelists will represent utilities, EPCs, OEMs, regulators, investors and more. They will discuss the industry’s ambitious journey to 2050, in which historically central station-based generation represents a smaller percentage of capacity, as it’s joined by renewable energy and other forms of distributed generation, including energy storage. Experts across the ecosystem, seeking solutions to prominent challenges in pursuit of a balanced and sustainable energy mix, will have the opportunity to contribute their thoughts in high-level debates with domestic and international peers.

Between now and March, POWER-GEN International and DISTRIBUTECH International, in partnership with their media partners Power Engineering and POWERGRID International, will launch two new platforms to provide timely and informative content year-round, the POWER-GEN+ Series and DISTRIBUTECH+ Series. These live Series will bring together the energy community through virtual experiences for those looking for perspective and discussion on current and future issues affecting the generation and transmission & distribution markets.

“While we believe in the power of face-to-face events and what they deliver; our focus is on what our customers need now, as well as in the future, and how we can deliver experiences to best meet those needs. Our team is talking with our customers and working on a variety of opportunities that will meet the needs of power industry professionals engaged in each of the energy markets we serve. These opportunities include virtual experiences, timely content and educational sessions, peer-to-peer networking, vendor product and service demonstrations and matchmaking assistance between decision-makers and sellers,” said Hanson.

Additional information on the POWER-GEN+ Series can be found at: www.powergen.com/plus. Additional information on the DISTRIBUTECH+ Series can be found at: www.distributech.com/plus.

“Given the uncertainties we all face due to the COVID-19 pandemic, this move, and the alignment of POWER-GEN with DISTRIBUTECH, makes great sense,” said Lisa Johnson, CEO of Seminole Electric Cooperative, based in Tampa, FL. “I look forward to the broad and robust participation these events are known for across our industry, as well as our discussion centered on ‘Destination 2050’.”

Wallstein Group Takes Over the Filter Business From Balcke-Dürr GmbH

The Wallstein Group continues its steady growth course and takes over Balcke-Dürr Polska retrospectively as of January 1, 2020 as part of a share deal. The company, headquartered in Warsaw, generated sales of around €30 million in 2019 with approximately 60 employees. It is a leading global supplier of filter systems for conventional power plants and industrial applications and will continue to operate under the new name "Wallstein Rothemühle" with the current management team.

Mutares acquired Balcke-Dürr Polska from the American SPX Corp. as part of the takeover of the Balcke-Dürr Group in 2016. As a global center of competence for fine dust separation, the company was able to more than double its overall performance and almost quadruple its profitability. With its excellent e-filter technology, it contributes in particular to lowering the dust emission values of large power plants and other large combustion plants below the stricter limits in the EU and Asia.

With the acquisition of this highly specialized company, the Wallstein Group is specifically expanding its product portfolio in energy and environmental technology with electrostatic precipitators, fabric and hybrid filters, thereby ideally supplementing its existing range of heat exchangers and heat utilization systems for flue gas flows. In the future, it will also be able to offer its customers air preheaters and gas heaters in the Ljungström design.

The synergies of the takeover will further strengthen the Wallstein Group not only in Germany but also in Eastern Europe as one of its most important core markets, where highly qualified engineers work out innovative solutions for local and international customers. The consequent expansion of the international presence remains in focus, after the Wallstein Group founded a joint venture in China in 2012 and has successfully developed it into the regional market leader.

The integration into the Wallstein Group will open up a multitude of new application possibilities to the excellent technical know-how of the Polish company. The management of the Wallstein Group expects to be able to use their new company as a perfect platform to improve the market access to Eastern Europe of the business area E- and maintenance technology. It is planned that in future the innovative services of Wallstein Service Polska for cleaning and maintenance of electrical systems will be offered locally under the roof of Wallstein Rothemühle.

Wallstein group: Wallstein is a family-owned group of companies founded more than 30 years ago, which operates in three business areas. The area of energy and environmental technology supplies heat utilization systems for flue gas cleaning systems as well as gas scrubber systems for production plants. The area of pharmaceutical and medical technology designs, manufactures and assembles plant components made of stainless steel. The electrical and maintenance technology division builds charging infrastructure for e-mobility and provides services for electrical systems and facilities. With around 300 employees in several companies, including a joint venture in China, the Wallstein Group generates annual sales of around EUR 90 million.

IEA Believes Carbon Capture Has an Important Role

Meeting climate and energy goals requires a fundamental and accelerated transformation of power systems globally. Decision makers collectively must support a rapid shift to low-carbon generation while meeting strong growth in power demand, driven by increased energy access in developing economies and electrification of end-use sectors. Carbon capture, utilization and storage (or “CCUS”) technologies can play an important role in this transformation in three ways:

First, retrofitting carbon capture technologies is an important solution to avoid the “lock-in” of emissions from the vast fleet of existing fossil-fueled power plants while also providing plant owners with an asset protection strategy for recent investments. This is of particular relevance in Asia, where the average age of coal-fired power plants is just 12 years.

Second, increasing variable renewable generation requires dispatchable energy for flexibility and resource adequacy. Batteries and other forms of energy storage are being further developed and deployed, but carbon capture, utilization and storage technologies are also part of the portfolio of low-carbon technologies able to meet the growing need for flexibility (to manage both short-term and seasonal variations). These strategies offer a technological hedge against innovation uncertainty in the power system transformation.

Third, through its combination with bioenergy, carbon capture technologies can enable negative-emission power plants, which may be critical for offsetting emissions in harder-to-abate sectors and to support “net-zero” climate goals. Today, only two large-scale CCUS facilities are operating in the power sector. But experience from these first-of-a-kind plants highlights the potential to reduce costs significantly and improve technology with further research, development and deployment. Policy makers are urged to provide targeted policy support, including capital grants, public procurement and tax credits, to kick-start near-term investment in CCUS-equipped power plants.

IEA draws the following conclusions:

Carbon capture, utilization and storage technologies have important roles to play in decarbonizing global power systems, which today are dominated by fossil fuels, and in supporting the transition to net-zero emissions.

Owners of existing plants as well as those under construction can retrofit carbon capture technologies to protect their assets and avoid the potential “lock in” of emissions, in particular in Asia with a large and relatively young fleet of existing fossil-fueled plants.

System operators can benefit from CCUS-equipped power plants, which help integrate growing shares of renewables into the power system by providing short- and long-term flexibility.

Combining these technologies with bioenergy enables negative-emission power plants that can offset emissions in harder-to-abate sectors and support “net-zero” climate goals.

Significant cost reductions and technology improvements have already been achieved for these technologies, with further improvements anticipated through research, development and deployment.

Targeted policy measures, like the 45Q and 48A tax credits in the United States, will be critical to realize the potential of carbon capture technologies in power generation.

 

 

 

    FGD and DeNOx Newsletter No. 508