Utility E-Alert 1423

· Approval of Air Quality Implementation Plans; New York; Cross-State Air Pollution Rule

· IEA Blog previews Speech next Month on boosting efficiency of existing Coal Plants in China

· GE Secures $1.0B in Project Financing for Sharjah’s First Independent Combined Cycle Power Plant

· Argan, Inc.'s Wholly Owned Subsidiary Gemma Power Systems Enters into an EPC Contract and Receives a Limited Notice to Proceed for the Harrison County Power Project

· MHPS Receives Order for Two H-25 Gas Turbines for Major Chinese Paper Firm Lee & Man Paper Manufacturing Ltd.

· GE’s Total Plant Solutions Help Azito’s Power Plant Boost Efficiency, Output and Reliability in Ivory Coast

· Valmet receives a repeat Automation Order from GS EPS for Dangjin 4 Plant

· KBR awarded 20 Year Contract to deliver Major UK Nuclear Decommissioning Program

· Komline Sanderson’s unique Dry Scrubber Atomizer suitable for Three Different Applications

· Illinois Power Plants evaluating Wet Limestone, Dry Lime, and Ammonia Options

· Time to Register for the Dry Scrubber Users Group Conference in Kansas City

· Yokogawa delivers FGD Control System for Bosnian Coal-fired Power Plant

· Midwest Energy Emissions optimizes Mercury Capture with proprietary Sorbents and Holistic Approach

· A Columbian Plant fitted only with an ESP is achieving Low Mercury Emissions

· Innovation in the Combust, Flow and Treat Industry is a Product of Wisdom through Interconnection

The Environmental Protection Agency plans to change the way it calculates the health risks of air pollution, a shift that would make it easier to roll back air rules because it would result in far fewer predicted deaths from pollution, according to five people with knowledge of the agency’s plans.

The EP. had originally forecast that eliminating the Obama-era rule, the Clean Power Plan, and replacing it with a new measure would have resulted in an additional 1,400 premature deaths per year. The new analytical model would significantly reduce that number and would most likely be used by the Trump administration to defend further rollbacks of air pollution rules if it is formally adopted.

The proposed shift is the latest example of the Trump administration downgrading the estimates of environmental harm from pollution in regulations. The consensus in the industry is that fine particulate matter poses the most serious threat to people of all the pollutants due to both its quantity and its harm rating.

The Environmental Protection Agency (EPA) is finalizing approval of State Implementation Plan (SIP) revisions submitted by the State of Wyoming on April 5, 2018, addressing regional haze. The revisions modify the sulfur dioxide (SO₂) emissions reporting requirements for Laramie River Station Units 1 and 2. We are also finalizing revisions to the nitrogen oxides (NO_x) emission limits for Laramie River Units 1, 2 and 3 in the Federal Implementation Plan (FIP) for regional haze in Wyoming. The revisions to the Wyoming regional haze FIP also establish a SO₂ emission limit averaged annually across both Laramie River Station Units 1 and 2. These units are operated by, and owned in part by, Basin Electric Power Cooperative (Basin Electric).

Federal Register / Vol. 84, No. 97 / Monday, May 20, 2019 / Rules and Regulations

Approval of Air Quality Implementation Plans; New York; Cross-State Air Pollution Rule

The Environmental Protection Agency (EPA) is proposing to approve a revision to the New York State Implementation Plan (SIP) addressing requirements of the Cross-State Air Pollution Rule (CSAPR). Under the CSAPR, large electricity generating units in New York are subject to Federal Implementation Plans (FIPs) requiring the units to participate in CSAPR federal trading programs for ozone season emissions of nitrogen oxides (NO_x), annual emissions of NO_x, and annual emissions of sulfur dioxide (SO₂). This action proposes to approve into New York's SIP the State's regulations that replace the default allowance allocation provisions of the CSAPR federal trading programs for ozone season NO_x, annual NO_x, and annual SO₂ emissions. The approval is being issued as a direct final rule without a prior proposed rule because EPA views it as uncontroversial and does not anticipate adverse comment.

Federal Register / Vol. 84, No. 98 / Tuesday, May 21, 2019 / Rules and Regulations

Xcel Energy announced plans to retire its last two coal-fired power plants in the Upper Midwest a decade earlier than scheduled. The acceleration of the coal closures is another milestone in the company’s clean energy transition that includes expanding wind and solar, using cleaner natural gas and operating its carbon-free Monticello nuclear plant until at least 2040.

The plan outlines a path to make the transition while ensuring reliability and keeping costs low for customers. As part of this plan, the company has reached an agreement with a coalition of environmental and labor organizations on key elements of the plan relating to its coal, solar and natural gas plans.

These plans are part of the proposed Upper Midwest Energy Plan, which the company will submit for approval to the Minnesota Public Utilities Commission in July. If approved, the plan would lead to a more than 80% reduction in carbon emissions in the region by 2030, compared to 2005, a key stepping stone toward the company achieving its vision to provide customers 100% carbon-free electricity by 2050.

Key milestones in the company’s industry-leading clean energy transition include:

“This is a significant step forward as we are on track to reduce carbon emissions more than 80% by 2030 and transform the way we deliver energy to our customers,” said Chris Clark, president, Xcel Energy – Minnesota, North Dakota, South Dakota. “Accelerating the closure of our coal plants and leading this clean energy transition would not be possible without the dedication and support of our key stakeholders. We thank them for their work to put us on a path to deliver 100% carbon-free electricity by 2050.”

San Miguel Corp. (SMC) intends to continue developing clean coal-fired power plants, as well as pursue renewable energy projects and battery technology developments with room still to grow in its power portfolio. As of end-2018, SMC Global Power Holdings Inc. has an installed capacity of approximately 19 percent of the national grid, 25 percent of the Luzon grid and nine percent of the Mindanao grid, as stated in a regulatory filing.

Under the Electric Power Industry Reform Act of 2001 (EPIRA), no company can own, operate or control more than 30 percent of installed generating capacity (IGC) of a grid and 25 percent of the national IGC. SMC Global Power said it plans to expand its portfolio through strategic development of greenfield power projects and acquisition of existing power plants. In putting up new projects, it will not shut its door on coal-fired power plants, particularly clean coal technology, which “remains the most reliable and cost-efficient fuel source for greenfield power projects.” That’s why it will continue to pursue the 4×150-megawatt (MW) circulating fluidized bed coal-fired power plant in Mariveles, Bataan and the 600-MW coal-fired power plant in Pagbilao, Quezon.

These projects – under Mariveles Power Generation Corp. and Central Luzon Premiere Power Corp., respectively – were previously halted after acquiring the Masinloc coal-fired power plants in Zambales province in December 2017. The transaction closed in March 2018. The Bataan power plant was originally eyed for completion in 2020 and the Quezon power plant for commercial operations in 2021. The two power projects were also part of the controversial power supply agreements of Manila Electric Co. (Meralco), which were filed a day before the extended competitive selection process (CSP) deadline.

Currently, SMC Global is completing the 335-MW Unit 3 expansion of the Masinloc Power Plant – which it acquired from AES Philippines. It has tapped Posco Engineering & Construction, and Ventanas Philippine Construction as engineering, procurement and construction (EPC) contractors.

“Unit 3, which is envisaged as a brown-field/expansion project within the Masinloc Power Plant site, is substantially complete as of December 31, and is expected to commence commercial operations by 2Q of 2019,” it said. The SMC power unit is also completing the 160-MW Unit 4 of the Limay Greenfield Power Plant, which is expected to commence operations within the second quarter. Apart from coal, SMC Global Power is also focused on investing in battery energy storage systems (BESS) and renewable energy projects as part of its objective to operate in an environmentally-responsible manner while considering energy security and affordability.

IEA Blog previews Speech next Month on boosting efficiency of existing Coal Plants in China

The introduction of higher steam temperatures and pressures led first to operation at supercritical and then subsequently with ultrasupercritical conditions. To put this in context, the supercritical units could boost efficiencies from 39% to about 42% while ultrasupercritical units have achieved efficiencies that have steadily increased from just above 42% to about 49% (net, LHV basis), with developments and demonstrations underway to push these past the 50% mark. The current approach is to install plants that typically comprise 660 and more usually 1000 MWe ultrasupercritical (USC) units with state-of-the-art conventional pollutant control systems. These are commonly known as High Efficiency Low Emissions (HELE) plants. Currently in China, the national operational capacity of USC HELE power plants is some 224 GWe with a further 88 GWe under construction.

The overall coal power capacity is close to 1100 GWe and now comprises a mix of 300-<600 MWe subcritical units, 600 MWe supercritical and 660-1000 MWe USC units. A 300 MWe subcritical unit can at very best achieve 39% efficiency while a state of the art 1000 MWe USC unit can have an efficiency close to 49% (net, LHV basis). The Chinese Government has continued its strict approach to increasing efficiency. Depending on the technology mix within each power company fleet, this is likely to require an increase in the proportion of zero carbon emissions sources such as renewables and nuclear together with steps to increase the average emissions profile of the coal plants. The introduction of drivers to encourage closure of the older of the 300 MWe subcritical units together with moves to ensure all new plants are USC HELE units. These include the setting of regulations that require each power company to achieve a tough efficiency standard for its overall power fleet so limiting CO₂ emissions per unit of power generated.

In addition, the Chinese Government requires that by 2020 all the coal-fired power units should achieve an annual average UNE greater than 39.6% (LHV). This is designed to push the lower efficiency units off the grid. While the supercritical and ultrasupercritical units can readily achieve this target, for most subcritical units this will not be possible. Such subcritical units represent a significant part of the overall coal power fleet since their operational capacity is about 350 GWe, accounting for close to 35% of the total installed coal-fired power capacity. Typically, these units have typical steam parameters of 16.7MPa/538/538°C in the size range 300 MW-<600 MW. The heat rate of a typical subcritical turbine is greater than 8000kJ/kWh at THA (turbine heat acceptance) condition, which equates to an annual average unit net efficiency below 37% (LHV).

The ages of such subcritical power plants vary, with the newer units being less than fifteen years old, having been built just before the policy driven switch to supercritical and then USC options. There is an incentive to upgrade these units, to achieve cost effective higher efficiencies, since their expected operational lifetime could be some 40 years.

Professor Feng Weizhong, with his team from Shanghai Shenergy Power Technology Co., Ltd., has a well-regarded reputation for developing and implementing significant incremental improvements to the Waigaoqiao No. 3 coal-fired power plant in Shanghai. He has also designed innovative changes to the conventional turbine layout that are being introduced for demonstration in the early 2020s at the Pingshan Phase 2 project in Anhui Province. This comprises a 1350 MWe double reheat USC with adapted steam turbine layout that should achieve close to 50% net efficiency. The demonstration of this new technology variant will take place in the late 2020s.

Professor Feng has now turned his attention to providing the cost-effective high temperature retrofit for those existing 300/600 MWe subcritical coal-fired power units, which will result in a significant efficiency improvement that can be achieved at an acceptable investment level. His intention is to increase maximum temperature of the main and hot reheat steam from 538/538°C to 600/600°C, while keeping the steam pressure unchanged. It is estimated that the upgrade will enhance the unit’s power output efficiency to 42.9% for the 300 MWe units, and even higher for the 600 MWe ones, reduce its emissions by more than 10% and extend its overhaul interval from six to 12 years.

To turn these innovative technological ideas into engineering reality, Shanghai Shenergy Power Technology Co. Ltd. has signed a contract with China Resources Power for the demonstration of an upgrade of the 320 MWe subcritical coal-fired power plant at Xuzhou, Jiangsu Province, China. Alongside this, Siemens recently signed an agreement with Shanghai Shenergy Power Technology to implement a high-temperature subcritical upgrade for the 320 MWe steam turbine unit at the Xuzhou Power Plant. This will include adapting the control stage, incorporating advanced blade designs, plus ensuring additional steam extraction for the high-pressure pre-heater.

The basic design of the modified plant was completed by the end of September 2018, while construction drawings were essentially complete by the end of November 2018. The construction of the modified components was started during December 2018 and expected to be finished by the end of June 2019, with testing and performance demonstration scheduled later.

For those who wish to learn more about this exciting coal power development, Dr Li Li, a key member of Professor Feng Weizhong’s engineering team, will be providing an in-depth presentation on the Xuzhou upgrade project at the IEACCC CCT2019 Conference, which will take place in Houston, Texas, USA from June 4-7, 2019.

The “2019 International Forum on Clean Power Technology and Engineering & CHN Energy International Forum on Clean Energy”, jointly hosted by the Chinese Academy of Engineering, Chinese Society for Electrical Engineering and CHN Energy, was held in Beijing on May 16-17.

According to Wang Xiangxi, chairman of CHN Energy, CHN Energy has been earnestly upgrading its industrial structure and made great achievements in ultra-low emission coal and electricity, intelligent and efficient power generation, and coal-to-liquids projects in recent years. The group will work together with all parties to strengthen scientific and technological synergy and innovation, comprehensively promote the clean and efficient use of traditional energy and support the large-scale development of renewable and new energy.

“We will also speed up transforming China’s energy system into a cleaner, low-carbon, safe and efficient modern energy system, making new contributions to global energy change and clean power development,” Wang added.

Worley is eyeing opportunities in SA’s thermal coal sector, following the completion of the merger with a subsidiary of Jacobs Engineering in April. Australian-listed WorleyParsons bought US-based Jacobs’s energy, chemicals and resources business for $3.2 bn. The merged entity, Worley, provides professional project and asset services in energy, chemicals and resources and employs 57,600 people across 51 countries. Worley, which is one of the world’s largest project delivery firms, remains upbeat about the prospects of coal despite the negative sentiment towards the resource from a number of entities. Most recently Nedbank and Standard Bank decided not to fund coal mines.

“We are trying to work with clients [in the coal industry] to mine in the cleanest possible way because coal is under immense environmental pressure at the moment. Funders are making it far more difficult if you are not developing your project in a way that ensures the least amount of emissions,” said senior vice-president Denver Dreyer.

Dreyer, a former CEO of WorleyParsons RSA, is now responsible for mining, minerals and metals for Europe, Middle East and Africa in the merged company. Following the completion of the transaction, Worley has prioritized increasing its global footprint in minerals, metals and mining, Dreyer said.

Kosovo- and London-listed power firm ContourGlobal has chosen a consortium of General Electric subsidiaries to build and equip a new 500 MW coal-fired power plant in the Balkan country. Although sitting on more than 14 billion tons of proven lignite reserves, the fifth largest in the world, Kosovo is struggling with power shortages. The new plant is designed to meet nearly half of the country’s power demand.

“The selection of GE as Preferred Bidder puts Kosovo one step closer to achieving a successful outcome of the process that began long ago with the support of so many international institutions,” Kosovo’s economy minister Valdrin Lluka said in a statement. “Successful implementation of this project has the potential to reshape the overall economic perspective of the country,” he added.

The government sees coal-fired power plants (“clean coal”) as the second backbone of the power supply alongside the existing hydro power plants. The economy grew by more than 8% in 2017, and the Ghanaian government expects similar growth in 2018, driven by new oil and gas exploration that has gone into production. The medium-term prospects are positive despite existing risks (public debt). The completion of existing gas and coal-fired power plants will create additional capacity in the largely state-owned energy sector. At the same time, it is planned to further expand the use of renewable energy sources.

Alpiq has signed an agreement to sell its two coal-fired power plants to Sev.en Energy Group for nearly €280m ($307.15m). Under the terms of deal, Alpiq agreed to sell its Alpiq Generation (CZ) to Sev.en Zeta (CZ), which is a part of Sev.en Energy Group. Alpiq Generation owns and operates two coal-fired power plants, Kladno and Zlín, located in the Czech Republic.

The 516 MW Kladno coal-fired power plant, which was commissioned in 2000, has been wholly-owned by the Alpiq Group since 2002. The Zlín thermal power plant has an electrical capacity of 64 MW and a thermal capacity of 376 MW. It is equipped to deliver electrical energy, process heating and district heating. The power plant was acquired by Alpiq in 2005.

PPC, which is 51 percent state-owned, received six expressions of interest for the plants and a license to build a new one in northern Greece in March. Greece’s electricity utility Public Power Corp. (PPC) said the submission of binding bids, for three coal-fired power plants it is selling under a post-bailout agreement with its international lenders, has been pushed back to May 28. PPC received six expressions of interest for the plants and a license to build a new one in northern Greece in March. It relaunched the sale in April after a previous tender failed to attract satisfactory bids. Expressions of interest came from Beijing Guohua and Damco Energy, China Western Power Industrial, Sev.En Energy and Indoverse Coal Investments, Gek Terna, ElvalChalkor, as well as from Mytilineos Group.

The 300 megawatts (MW) Kam’mwamba Coal-fired Power Plant Project in Neno, with a lifespan of 30 years, is still alive and some studies are still underway. The Kam’mwamba Coal-fired Power Plant Project is being financed by a loan from the Export and Import (Exim) Bank of China to the tune of $667 million with Lilongwe required to provide $104 million as a commitment fee. Once fully operational, the plant would, among other things, help Malawi to diversify from using hydro power, which of late has proved to be challenging due to low water levels. According to a report from the Ministry of Energy, the plant would use coal from Moatize in Mozambique that will be transported by rail.

The project is expected to be implemented under the Engineering, Procurement and Construction (EPC) model.

One particular issue affecting the operating units at the Medupi and Kusile stations (which are being brought on line progressively) is ash handling, with embarrassingly large accumulations of ash. The supplier of the ash handling equipment, Clyde Bergemann, has ascribed the problems to poor operating practices by Eskom, pointing out that similar ash handling equipment has been operating well at Eskom’s Matla and Kriel plants. It has also been suggested that the quality of coal being used is much lower than the design level, due to Eskom’s continuing financial malaise and its need to save money.

As well as the Medupi and Kusile problems, Eskom has also experienced a general decline in generating plant performance. At January hearings by the South African energy regulator NERSA on Eskom’s request for a 15% rate increase over the next three years, Brad Ross-Jones, generation group manager, said there were numerous factors contributing to this decline.

“The root cause goes back to the late 90s when Eskom needed to make decisions on building new stations by 1999 at the latest, to meet demand by 2007 but was not allowed to. This meant that the final investment decision could only be taken in December 2006, which was too late,” Ross-Jones said.

“This was later exacerbated by delays in the construction of Medupi and Kusile. It should also be noted that one of the key reasons for the delays was an accelerated design period as a result of the late decision and the subsequent over-optimistic expectations on delivery dates,” he said.

This all led to inadequate capacity to meet demand meaning inadequate maintenance space to perform an ideal level of preventative maintenance, particularly mid-life refurbishments.

Eskom is operating an ageing generation fleet, notwithstanding the new power stations under construction, with more than half of its coal plants over 37 years old.

GE Secures $1.0B in Project Financing for Sharjah’s First Independent Combined Cycle Power Plant

Co-developers GE Energy Financial Services (“GE EFS”) and Japan’s Sumitomo Corporation along with Shikoku Electric Power Company and Sharjah Asset Management, the investment arm of the Government of Sharjah, have closed financing from leading private financial institutions and the Japan Bank for International Cooperation (“JBIC”), Japan’s export credit agency, for GE’s flagship 1.8 gigawatts (GW) power project, Hamriyah Independent Power Company, in Sharjah, United Arab Emirates (UAE). Securing financing for the Project will lead to the first independent combined cycle power project in the emirate of Sharjah, which is expected to be the most efficient power plant in the Middle East’s utilities sector on completion.

Together, a consortium of banks and JBIC will co-finance the Project for a total private-public co-financing amount of approximately $1.0B. GE EFS worked with multiple private financial institutions including Sumitomo Mitsui Banking Corporation, Sumitomo Mitsui Trust Bank Limited, Norinchukin Bank, Société Générale S.A., Standard Chartered Bank and KfW-IPEX to secure financing, which will be partly insured by Nippon Export and Investment Insurance (NEXI), a Japanese insurance corporation owned by the Japanese government.

Argan, Inc.'s Wholly Owned Subsidiary Gemma Power Systems Enters into an EPC Contract and Receives a Limited Notice to Proceed for the Harrison County Power Project

Argan, Inc. announced that its wholly owned subsidiary, Gemma Power Systems, recently entered into an engineering, procurement and construction services contract with ESC Harrison County Power, LLC to construct a 625 MW natural gas-fired power plant in Harrison County, West Virginia.

Harrison County Power Project is a combined-cycle facility composed of one General Electric 7HA.02 combustion turbine generator (CTG), connected to a heat recovery steam generator (HRSG). The HRSG will harness exhaust heat from the CTG to generate high-quality, superheated steam. The steam will drive a steam turbine (ST) to generate additional electricity in an environmentally friendly and efficient manner. The plant will also have an air-cooled condenser (ACC), which will dramatically reduce water usage to less than 3 percent of many similarly sized facilities. When operating, the plant will provide enough power for approximately 425,000 homes through the PJM interconnect (grid).

A limited notice to proceed has been issued to Gemma to continue project planning and engineering activities. Caithness Energy, LLC. (“Caithness”) partnered with Energy Solutions Consortium, LLC (“ESC”) to develop the project. Construction for the facility is scheduled to begin in the summer with completion scheduled in 2022.

MHPS Receives Order for Two H-25 Gas Turbines for Major Chinese Paper Firm Lee & Man Paper Manufacturing Ltd.

Mitsubishi Hitachi Power Systems, Ltd. (MHPS) has received an order for two H-25 gas turbines from Lee & Man Paper Manufacturing Ltd., a major Chinese paper manufacturing company, for a factory at its headquarters in Dongguan, Guangdong Province.

The units will be utilized as the core equipment of a natural gas-fired cogeneration system. This non-utility generation facility will have an output of 62 megawatts (MW) of electric power, as well as provide steam for the 150 tons per hour (t/h), during duct-firing, to the manufacturing process through a heat recovery boiler utilizing the exhaust from the gas turbine. Operations are scheduled to start in 2020.

As with the previous H-25 gas turbine project orders received from China, this order was placed through Harbin Guanghan Gas Turbine Co., Ltd. (HGGT), a member of China Shipbuilding Industry Group, a major producer of ships and marine machinery. Positive results from conventional projects led to this latest order.

The facility for this order is a co-generation, non-utility power plant comprising the H-25 gas turbines, heat recovery boilers, and auxiliary equipment. MHPS will supply the main and auxiliary machinery for the gas turbines through HGGT, and dispatch engineers to the site to oversee installation and provide guidance during commissioning.

GE Power announced an order for its HA gas turbine technology for the Indeck Niles Energy Center in Niles, Michigan.

GE will work through a contract with Kiewit Power Constructors, the engineering, construction and procurement (EPC) contractor on the project, to integrate two of GE’s 7HA.02 gas turbines into the approximately 1,000-megawatt power plant project. Indeck Niles—which will become one of the most efficient energy centers of its kind in Michigan—will be able to provide the equivalent electricity needed by 635,000 homes and businesses.

The developer of the project is Indeck Energy Services, Inc. The plant is owned 50 percent by Korea Southern Power Co. Ltd., 30 percent by Daelim Energy Co. Ltd. and 20 percent by Indeck Energy Services, Inc. and is scheduled to be completed in 2022. The construction of the plant is expected to create 500 union construction jobs and 21 full-time jobs for ongoing plant operations. The order also contains a GE steam turbine and generator, two heat recovery generators (HRSG), and a multi-year services agreement.

GE’s Total Plant Solutions Help Azito’s Power Plant Boost Efficiency, Output and Reliability in Ivory Coast

With a focus on improving power plant output, reliability, availability and operational performance as well as gaining data and insights for predictive maintenance of assets, Azito Energie S.A. announced that it has signed a contract with GE to deploy its Predix Asset Performance Management (APM) software for two GT13E2 gas turbines and two generators at the Azito III plant site, located in the Yopougon district of Ivory Coast. In addition, the companies announced the successful execution of GE’s MXL2 upgrade solution for the first GT13E2 gas turbine, which will increase the plant’s production by 15 megawatts (MWs), which is equivalent power for up to 120,000 homes. The upgrade on the second unit is set to be implemented later in the year. A first-of-its kind project in Sub Saharan Africa, this flagship upgrade combined with the digital solutions, is paving the way for additional total plant solutions across the region.

GE successfully executed the MXL2 upgrade on the first turbine, compressor and combustor modules without any loss time to injury and a workforce that was predominantly 95% local. Designed to be compatible with all installed GT13E2 units, the MXL2 upgrade combines GE’s latest technology developments and over 10 million operating hours of GT13E2 fleet experience. This upgrade allows operators to benefit from increased efficiency, improved power output, and significantly extended service intervals. This upgrade also helps extend the lifetime of the asset and improve availability of power with fewer C-inspections.

Under this contract, the APM software will provide real-time unified visibility into the health of assets critical to the customer —all in one place. It can predict and accurately diagnose issues with greater accuracy before they occur with the help of predictive analytics, while generating the root cause analysis of events and providing a framework for the resolution of identified issues.

Valmet receives a repeat Automation Order from GS EPS for Dangjin 4 Plant.

Valmet has received a repeat automation technology order from Asia's largest capacity biomass power plant owned by GS EPS Co., Ltd. Phase 2 of the Dangjin 4 Biomass Power Plant is currently under construction in the city of Dangjin, close to Seoul in South Korea.

The order was included in Valmet's fourth quarter 2018 orders received. The value of the order is not disclosed. The delivery will take place at the end of 2019. Installation and commissioning will start in February 2020. The order was placed by GS Engineering & Construction Co., Ltd. (GS E&C), the contractor responsible for the engineering, procurement and construction of the plant.

In 2014-2015, Valmet delivered automation for Phase 1 of the Dangjin 4 Biomass Power Plant. Similar to that, the new power plant will have a capacity of 105 MW and run 100% on wood chips. Once the new project is completed, the Dangjin unit will be the largest biomass power plant in Asia. With Valmet's automation technology, it will be able to further enhance its competitiveness in the power market, increase its electricity capacity and produce more renewable energy.

“Valmet's automation system is one of the best and most optimized solution for biomass-fired power plants. We have been successfully providing maintenance services for Phase 1 of the Dangjin 4 Biomass Power Plant, and our automation system has proven its flexible operation over the past years,' adds Wan Mo Yoon, Senior Sales Manager, Energy & Process Systems, Korea, Automation, Valmet

All product tests and the post-test overhauling of the first AP1000 canned motor main pump jointly produced by Shenyang Blower Works Group Nuclear Pump Co., Ltd. and Harbin Electric Power Equipment Co., Ltd. were successfully completed.

The test data shows that all the performance parameters of the main pump meet the requirements of the main pump design specification, and the overall overhauling indicators meet the relevant requirements.

The success of this main pump test indicates that domestic enterprises have been fully equipped with the capability of manufacturing localized AP1000 canned motor main pumps, which provides strong guarantee for the supply of the localized main pumps of CAP series power plants.

Main pump is one of the key components of NPPs and plays an important role in the safe and reliable operation of NPPs reactor system.

State Nuclear Power Technology Corporation (SNPTC) is in charge of the introduction and assimilation of AP1000 technology. So far, four AP1000 units (Sanmen No. 1 and No. 2 units, and Haiyang No. 1 and No. 2 units) of the self-reliant program of Gen III NP have all entered into the nuclear operation state. Sanmen No. 1 unit is expected to achieve commercial operation in the near future.

Wood has secured a new contract worth up to $1 billion to provide engineering design services to Sellafield Ltd over the next 20 years. The company has been selected as Design and Engineering Partner at the UK’s most complex nuclear site as part of the new Programme and Project Partners (PPP) procurement model. Sellafield Ltd has described PPP as a ‘game changer’ for the supply chain, creating long-term relationships with selected partners, developing closer working practices, and delivering projects faster without compromising safety standards.

Wood will provide the front-end design and engineering capability and services required to deliver a portfolio of major projects and site wide project delivery improvements. A key element of the Design and Engineering Partner’s role will be working with the other lot partners for Integration, Civils Construction and Process Construction to optimize design, constructability, and overall project delivery.

Working with Sellafield Ltd as fifth partner, the PPP lot partners will deliver multiple capital projects with a combined value of up to $6 billion across the Sellafield site.

Bob MacDonald, CEO of Wood’s Specialist Technical Solutions business, said: “This is a fantastic endorsement of Wood’s ability to meet the most complex nuclear decommissioning challenges. We already have a deep, shared history with Sellafield and this new appointment provides a platform for us to assist with safe and secure operation and clean-up over the next two decades. This award reflects a highly collaborative approach that we adopt to achieve shared outcomes with customers and partners. We are looking forward to working with Sellafield and our partners to maximize socio-economic benefits for local communities.”

KBR awarded 20 Year Contract to deliver Major UK Nuclear Decommissioning Program

KBR, Inc. has been selected by Sellafield Ltd. to act as one of its delivery partners on a major infrastructure program to manage the safe and secure decommissioning of the Sellafield nuclear site.

The Framework Contract under which call offs for work will be issued comprises reimbursable project and program management services in support of Sellafield Ltd.'s major construction projects and infrastructure development required in support of its decommissioning program. KBR revenue associated with this program is worth up to a value of £500 million.

Under the terms of the contract KBR will provide program and project management expertise and will deliver project specific delivery plans for all major projects at Sellafield during the contract term including mobilization of resources, coordinating logistical requirements and defining delivery strategies. KBR will also coordinate the development of an integrated management system and provide project controls, procurement management, estimating, quantity surveying, risk management, document controls and commercial services.

"This is a truly significant program of work and this win adds to KBR's expanding portfolio of program management contracts in the UK," said Stuart Bradie, KBR President and CEO. "As a pioneer of collaborative working and forging strong alliances, KBR is delighted to have been selected to partner with Sellafield on this enduring project, which will place us at the heart of the customer's delivery team."

As the integration partner KBR will collaborate with the client and three other Program and Project Partners (PPP) to form an integrated delivery team. All the partners will work with the supply chain to improve capability, enhance project delivery, support social value and local economic development and contribute to the UK industrial strategy and nuclear sector deal.

Thermax Group posted consolidated revenue of Rs. 5973 crore compared to Rs. 4486 crore in the previous year, up 33%. Profit after tax for the year was Rs. 325 crore (Rs. 231 crore). Consolidated earnings per Rs. 2/- share were Rs. 28.90 compared to Rs. 20.61 in 2017-18.

The profits are after an exceptional charge of Rs. 90 crore, principally related to the impairment of the goodwill in Danstoker and after a credit of Rs 94 crore deferred tax adjustment in Thermax Babcock & Wilcox Energy Solutions Private Limited (TBWES).

Consolidated order intake for the year was Rs. 5633 crore, 12% lower than Rs. 6380 crore in 2017-18. Last year’s figure comprised some sizeable orders including a single large export order of Rs. 1000 crore, a trend not witnessed during the current fiscal. Order backlog as on March 31, 2019, stood at Rs. 5370 crore, 6% lower than last year’s Rs. 5689 crore.

On a standalone basis, Thermax Limited had revenue of Rs. 3541 crore as compared to Rs. 2746 crore in the previous fiscal. The Boiler and Heater (B&H) business of the company has been considered as a discontinued operation as it is being transferred to the company’s wholly owned subsidiary, TBWES. The company’s profit after tax, including discontinued operation, is Rs. 275 crore as compared to last year’s Rs. 238 crore, a growth of 16%. The profit is after considering Rs. 48 crore (Rs.25 crore) of an exceptional item of expenditure on account of impairment loss on the company’s investments in JVs and subsidiaries. For 2018-19, Thermax Limited registered an order intake of Rs. 3325 crore (Rs. 3634 crore) and an order backlog of Rs. 2741 crore (Rs. 3074 crore).

On April 11, 2019, the company acquired the entire stake held by the joint venture partners, namely MUTARES HOLDING-24 AG, Germany and BALCKE-DUERR GmbH, Germany in Thermax SPX Energy Technologies Limited (TSPX). Subsequent to the acquisition, TSPX has now become a wholly owned subsidiary of Thermax Ltd.

Advanced Emissions Solutions, Inc. serves as the holding entity for a family of companies that provide emissions solutions to customers in the power generation and other industries.

ADA brings together ADA Carbon Solutions, a leading provider of power activated carbon (PAC) and ADA-ES, the providers of ADA^® M-Prove™. The company provides products and services to control mercury and other contaminants at coal-fired power generators and other industrial companies. A broad suite of complementary products control contaminants and helps customers meet their compliance objectives consistently and reliably.

CarbPure Technologies LLC, (CarbPure), formed in 2015 provides high-quality PAC and granular activated carbon suited for treatment of potable water and wastewater. Affiliate company, ADA Carbon Solutions, LLC manufactures the products for CarbPute.

Tinuum Group, LLC (Tinuum Group) is a 42.5% owned joint venture by ADA that provides patented Refined Coal (RC) technologies to enhance combustion of and reduce emissions of NO_x and mercury from coal-fired power plants.

First quarter revenue and cost of revenue were $19.3 million and $141.1 million, respectively, compared with $3.9 million and $0.6 million in the first quarter of 2018. The increase in revenues during the first quarter was almost entirely driven by the $14.5 million increase in consumables sales resulting from the contribution of the company’s PGI segment, which contains the newly acquired activated carbon assets.

First quarter earnings from equity method investments were $21.7 million, compared to $12.3 million for the first quarter of 2018. The significant increase was driven by additional RC facilities year over year as well as the impact of the adopted change in lease and revenue accounting standards by Tinuum.

KPS Capital Partners (KPS) announced May 16 that it has signed a definitive agreement to acquire Howden, from Colfax Corporation for an enterprise value of $1.80 billion, including $1.66 billion in cash consideration and $0.14 billion in assumed liabilities and minority interest, subject to customary closing adjustments.

Howden is a leading global provider of mission critical air and gas handling products and services to the industrial, power, oil & gas, and mining industries. Based in Glasgow, Scotland, Howden has a 160-year heritage as a world-class application engineering and manufacturing company with a presence in 32 countries. Howden manufactures highly engineered fans, compressors, heat exchangers, steam turbines, and other air and gas handling equipment, and provides service and support to customers around the world in highly diversified end-markets and geographies. The Company has over 5,300 employees, including over 650 industry-leading engineers and 22 manufacturing facilities in 12 countries.

Raquel Palmer, Co-Managing Partner of KPS, said, "We are thrilled to have the opportunity to own and support Howden as the Company continues its path of transformation and growth. Howden is a formidable company that benefits from many positive secular trends, including increasingly greater environmental standards, the need for energy conservation and the trend toward urbanization, especially in developing economies. Howden enjoys a leading market position, scale, a global manufacturing footprint, world-class design and engineering capabilities, and a portfolio of industry-leading products. We intend to capitalize on the Company's many attractive growth opportunities, including strategic acquisitions, and to support its already substantial investment in research and development, technology and new product development. We look forward to partnering with Howden's talented management team to achieve success as an independent company."

Ian Brander, Chief Executive Officer of Howden, said, "We are excited about our future as an independent company under KPS' ownership. KPS is an ideal partner, given its demonstrated track record of recognizing and growing world-class industrial companies. KPS' commitment to continuous improvement, its global network, access to capital and significant resources will enable us to continue to grow our business and provide our customers with market-leading products and solutions."

"We are very pleased that our Air and Gas Handling associates will be working with a strong partner whose vision is to invest and grow the business," said Matt Trerotola, President and Chief Executive Officer of Colfax Corporation. "I want to thank the team for their success in reshaping the business toward more profitable growth opportunities."

Completion of the transaction is expected in the second half of 2019 and is subject to customary closing conditions and approvals.

Komline Sanderson’s unique Dry Scrubber Atomizer suitable for Three Different Applications

Komline Sanderson has a unique rotary atomizer used for dry scrubbing but also for chemical and food production. Elimination of silos between industries should lead to improved atomizer designs.

Komline-Sanderson’s variable-speed Rotary Atomizers represent a dependable approach to atomization and spray drying. The compact, rugged, direct-drive, high-speed motor, utilizing only a few parts in one rotating assembly (no gear, pulley, gearbox or coupling), reduces the need for traditional mechanical maintenance. High quality, oil-mist lubricated precision bearings (ABEC-7), of ceramic-ball design, provide maximum reliability.

K-S has over 35 years of experience using rotary atomizers in the following applications:

· Dry Flue Gas Cleaning (FGC) on municipal and industrial waste combustors (incinerators)

· Spray Drying of miscellaneous chemical and mineral products for the production of dry, free-flowing powders, such as:

Illinois Power Plants evaluating Wet Limestone, Dry Lime, and Ammonia Options

Illinois power plants have significant amounts of dry FGD and DSI. A task forece was assembled in 2018 to evaluate options and impact on Illinois coal use. The conclusion was that ammonia scrubbing with byproducts be considered.

McIlvaine has been involved in ammonia scrubbing starting in 1962 when a pilot unit was installed at a TVA fertilizer research facility. MET has sold ammonia systems at several plants around the world. The price of ammonium sulfate by product can be as high as four times the raw ammonia cost. The high chlorine Illinois coals are an attractive fuel source for ammonium sulfate production.

The task force considered the technology of a Chinese-based supplier— Jiangnan Environmental Technology Inc. This supplier has 300 installations utilizing the technology. The one concern McIlvaine has is the potential for a blue plume of small particles. MET ultimately retrofitted a wet electrostatic precipitator to solve the blue plume problem.

The Flue Gas Desulfurization (“FGD”) Task Force Act (20 ILCS 5120) created the FGD Task Force “to increase the amount of Illinois Basin coal use in generation units,” and to “identify and evaluate the costs, benefits, and barriers of new and modified FGD, or other post-combustion sulfur dioxide emission control technologies, and other capital improvements, that would be necessary for generation units to comply with the sulfur dioxide National Ambient Air Quality Standards (NAAQS), while improving the ability of those generation units to meet the effluent limitation guidelines (ELGs) for wastewater discharges and enhancing the marketability of the generation units' FGD byproducts.”

There are also significant amounts of coal burned by industrial plants in Illinois.

The most relevant measures for the cost of SO₂ control by FGD are the costs in dollars per ton of SO₂ removed, and the annualized costs of installing and operating an FGD system. The dollars per ton of SO₂ removed figures are useful in comparison to prices for emission allowances. Annualized costs of controls include capital costs amortized over the life of the system and the operation and maintenance costs associated with the control and provide an understandable estimate of the actual costs to power plant operators. Estimates for costs have been taken from USEPA information, and the following estimates are based on a unit with a capacity of 500 megawatts.

Coal-fired units in Illinois range between 78 MW and 800 MW, but a 500 MW unit could be considered a unit of typical size in Illinois for the purposes of these estimates. Wet scrubbing system capital costs range from $50 to $125 million per unit controlled, and annualized costs range from $10 to $25 million annually. Control costs are in a range of $200 to $500 per ton of SO₂ removed. It should be noted that many power plants operate several generating units and total capital costs and annualized costs can be much higher than the estimate above for control of an entire power plant with multiple units.

Dry scrubbing system capital costs range from $20 to $75 million per unit controlled, and annualized costs are also range from $10 to $25 million annually. Control costs are in a range of $150 to $300 per ton of SO₂ removed. As with the cost estimates given for wet scrubbing systems, it should be noted that many power plants operate several generating units and total capital costs and annualized costs can be much higher than the estimate above for control of an entire power plant with multiple units.

DSI system capital costs range from $3 to $15 million, but as previously stated, control costs and annualized costs are heavily dependent upon factors specific to the power plant and their target control efficiency. Again, there are associated operating and maintenance costs.

At the October 10th meeting of the FGD Task Force, a presentation was made by representatives of Jiangnan Environmental Technology Inc. (“JET”), a company that reports it has been installing and operating ammonia-based FGD systems outside the U.S. According to JET, these ammonia-based FGD systems have many advantages over conventional limestone/lime wet scrubbers and can increase revenue at a power plant through the sale of the byproducts of the systems. JET representatives suggested that use of higher-sulfur Illinois coal in their systems was actually preferable to low-sulfur coal because it would produce more byproduct which is potentially saleable. According to JET, advantages of ammonia-based FGD systems include: SO₂ control efficiencies of 99% or greater; no wastewater or solid waste; lesser power consumption by the controls and thus lower operating costs; and profits through the sale of ammonia sulfate as a fertilizer. The company’s business model involves financial support for the cost incurred by EGU owner related to installation of the technology, for the costs associated with the packaging and sale of the fertilizer byproduct, and for operation of the control at the plant. JET posits this arrangement provides for essentially no-cost control of SO₂ emissions in addition to a share of the revenue to the plant from the sale of the byproduct. JET does not currently operate any ammonia-based FGD systems in the U.S., however, the company apparently has installed the technology in over 150 projects worldwide, and claims that the technology is mature and suitable for use in the U.S. Issues of concern for installation of this technology in the U.S. are the permitting difficulties presented by a third party control operator, potential additional emissions of ammonia and particulate matter, ensuring that there are indeed no issues requiring water permitting, and the issues involving accumulation of byproduct in the event it is not marketable.

From the information gathered for this report, the FGD Task Force acknowledges the challenges to sustaining and increasing the use of Illinois coal, and is encouraged by technological developments that could prove useful in achieving that goal. In the Illinois deregulated electricity market, the cost of constructing, operating, and maintaining FGD systems on independent generating units has been one of the biggest obstacles to the use of Illinois coal. While it would require further site-specific evaluation by EGU owners and operators, the ammonia-based FGD technology presented by JET could possibly overcome hurdles to Illinois coal usage. Currently, the investor-owned power plants in Illinois are owned by Vistra Energy and NRG Energy. Accordingly, the Task Force urges Vistra Energy and NRG Energy to seriously consider this technology for its Illinois power plants

The National Thermal Power Corporation (NTPC)’s Dadri Power Plant is opting for a Dry Sorbent Injection (DSI) system for controlling sulfur dioxide (SO₂) emissions and ensuring compliance with the 2015 environmental norms within the stipulated deadline.

The Dadri power station in the Dehli-NCR region had invited bids in March 2018 from interested manufacturers to install DSI technology. In the first phase, four power generation units with a capacity of 210 MW each will be targeted. The Invitation For Bids (IFB), currently running in its final stages, has laid out the technical criteria, wherein the bidder should have built at least one DSI system “in a pulverized coal-fired unit, having flue gas flow of not less than 6,000,000 Nm³/hr, with sulfur dioxide capture efficiency of at least 50%..... The….System should be using Sodium Bicarbonate as reagent and should have been in successful operation for a period not less than one (1) year prior to the date of Techno-Commercial bid opening.”

The scope of Dry Sorbent Injection (DSI) System Package for NCTPP, Dadri, Stage-I

(4x210 MW) for four (4) units of 210 MW shall cover design, engineering, manufacture, shop

fabrication, preassembly, shop testing/type testing at manufacturer’s works, packing,

transportation, unloading, handling and conservation of equipment at site, complete services

of construction including erection, supervision, pre-commissioning, commissioning and

performance testing of equipment under bidder’s scope of work of Dry Sorbent Injection

(DSI) System and its associated auxiliaries, including all associated Electrical, Control &

Instrumentation, Civil, Structural and Architecture works. Dry Sorbent Injection System shall

G Srikanth, an independent technical expert, believes that the technology choice is appropriate. “The lower capital cost and smaller construction and commissioning time make it ideal for smaller generation units that have stiff deadlines. Moreover, DSI actually improves the efficiency of electrostatic precipitator (ESP), thus reducing the emission levels of Particulate Matter (PM) further,” he said.

Operational costs due to reagents, however, remain a bone of contention. While some experts believe that the reagent in question is expensive, raising the operational costs, others are of the opinion that the higher cost is offset by the lesser quantity of reagent that will be needed in the process.

Notwithstanding the differences in opinions over cost of reagent, this is a significant development for the power sector, as the stations and technology manufacturers had been advocating for flue gas desulphurisation (FGD) as the only solution.

The Centre for Science and Environment (CSE), which has been at the forefront of advocating implementation of the 2015 environmental norms, had recommended that the smaller power generation units (less than 500 MW) should be adopting alternatives to the FGD system to achieve compliance with the prescribed standard. Against the 300 mg/Nm³ standard prescribed for 500 MW units, the smaller units have to meet 600 mg/Nm³. Interestingly, in a 2016 roundtable conducted by CSE, several representatives of the thermal power industry as well as technology suppliers had agreed to the utility of sorbent injection for the smaller units.

Moreover, sorbent injection is not a new technology. It is not entirely unknown to India. Sorbent injection with hydrated lime as the reagent has been in practice for a long time in the cement and steel industries in the country to control SO₂ emissions.

· Mill building for each unit for housing Mills, Unloading and Injection Blowers, Truck unloading Blowers, Dehumidifiers etc.

· Complete Electrical System including all motors, LT Switchgears, Transformers, Electrical

In December 2017, the Central Pollution Control Board (CPCB) sent Section 5 directions under Environment Protection Act to all coal-based power plants, affirming timelines for compliance mostly as per the CEA’s phasing plan, i.e. timelines were essentially extended to 2022. CPCB’s directions, however, made two changes to the CEA’s schedule: FGD installation was accelerated till December 2019 for plants based within a radius of 300 km of Delhi-NCR; timelines for upgrading Electrostatic Precipitator (ESP), which were not detailed in CEA’s plan, were given.

The power plant has been asked by the Central Pollution Control Board (CPCB) to comply with the environmental norms for coal-fired thermal power plants by December 31, 2019. The environment ministry has submitted the information that the plant will be compliant with the environmental norms by 2019 to the Supreme Court as part of the case on air pollution in Delhi, wherein pollution from coal-fired thermal power plants has been included for hearing among other issues.

Given the current status, about 8.5 GW, or about 65% of the overall installed capacity is on track to meet the deadlines given to it. Of this, 7 GW is supposed to be compliant, but there is no data to verify this; another 1.5 GW will comply by December 2019. The balance capacity will be unable to meet the 2019 compliance deadline.

Time to Register for the Dry Scrubber Users Group Conference in Kansas City

The annual Dry Scrubber Users Group will be held from September 10 through12, 2019 in Kansas City, MO. The 3rd annual pre-conference golf tournament and evening registration will take place on Monday, September 9, 2019. Participation in the conference can be achieved not only through registration but also through the sponsorship and exhibitor opportunities or by submitting abstracts for an opportunity to present at the conference!

The theme of this year’s conference is “Work Smarter, Not Harder.” We have all experienced the change in the power industry over the past few years coupled with a generation of engineers and operators that have or will be retiring as we usher in a new generation of young engineers and operators who will take the reins. As a result, the industry will have to continuously evolve to new technologies as well as new operating philosophies in order to minimize operating and maintenance costs while maximizing plant performance. While these constraints pose many problems this also presents opportunities for new solutions which is the essence of this year’s theme.

This year there will be three plant tours showcasing a variety of dry scrubber applications at the following location:

· Spray Dryer Absorber (SDA) Technology – Kansas City Power & Light’s Hawthorn Station Unit 5 which is a wall fired boiler burning PRB coal with a load range of 300 to 590 MWs. This site has a Babcock and Wilcox SDA as well as SCR system and UCC bottom ash submerged flight conveyor.

· Circulating Dry Scrubber (CDS) Technology – Kansas City Board of Public Utilities Nearman Creek Power Station Unit 1 is 256 MW Riley Stoker wall fired boiler burning PRB coal. This site has a dual train Babcock Power CDS along with a Babcock/Dustex pulse jet fabric filter. The site also has an SCR system, dual train Babcock/Chemo PAC injection system and UCC PAX dry bottom ash system.

· Spray Dryer Evaporator (SDE) Technology – Kansas City Power & Light’s Iatan Station Unit 2 is an 850 MW balanced draft super-critical unit with an air quality control system consisting of an SCR, pulse jet fabric filter, PAC injection system and wet flue gas desulfurization (WFGD) system. The plant was also retrofit with Alstom’s SDETM technology for elimination of the WFGD blowdown stream.

Alstom’s SDE™ technology is based on its SDA technology, which has been widely deployed since the mid-1970s to remove acid gases from utility flue gases. The SDETM technology takes a small slipstream of hot flue gas from boilers to evaporate the WFGD blowdown stream in lieu of sending it to a waste water treatment (WWT) system. Dissolved and suspended solids in the blowdown stream sent to the SDE are dried and collected by the existing downstream particulate collection device. Alstom’s SDE™ technology offers a true Zero Liquid Discharge (ZLD) solution that can be used on a stand-alone basis or in conjunction with other WWT technologies.

The SDE™ technology is considered cost-effective and relatively simple to operate. Since the WFGD blowdown stream is evaporated, this is true ZLD technology meaning that there is no waste water stream that must be permitted and monitored and is one potential solution that could be utilized to comply with the upcoming ELG rule.

One of the biggest advantages of attendance is the access to experienced industry experts not only from the U.S. but also international attendees. One such individual is Dr. Jianchun Wang (Joe) of Lonjing (www.lonjing.com). Joe has been an attendee as well as a speaker at a number of past Dry Scrubber User Group meetings. His company, also known as Longking, has supplied more dry scrubber systems than any other company.

FGD optimization requires a high level of sophisticated advanced process control using multiple techniques including model-based prediction, process value prediction, and enhanced regulatory control. When such an optimization system is implemented, the result is significant savings in energy use, reduced pump maintenance, longer pump life, and less limestone usage. This is the conclusion of Toshihiko Fujii of Yokogawa Electric Corp. writing in Power Magazine.

The optimization system typically consists of three functions: enhanced regulatory control, model-based prediction, and process value prediction. The system uses these three functions to continuously determine the minimum required number of recirculation pumps in operation, and to calculate the setpoint for the limestone slurry flow PID (proportional-integral-derivative) control loop.

Enhanced regulatory control governs the number of recirculation pumps in operation and calculates the slurry flow setpoint. It also calculates the optimal pH setpoint, using feed-forward control for some abnormal cases. Enhanced regulatory control also keeps track of the run time of each recirculation pump and uses this data to equalize the operating times of the pumps.

Yokogawa has delivered a control system for a flue gas desulfurization (FGD) system in Bosnia and Herzegovina, representing what the company said will be the first such system in the western Balkans.

The integrated production control system was installed at the 300 MW Ugljevik coal-fired power plant in the northeast of the country. It was delivered in August 2018 and is slated to come online in October 2019.

The brown coal-fired Ugljevik plant supplies around one-fourth of the power capacity for the Republica Srpska (Bosnian Serb Republic). Since brown coal has a high sulfur content, Yokogawa said, the emissions from Ugljevik's flue stack contain high levels of sulfur dioxide.

Installation of the flue gas desulfurization system is expected to improve the regional environment and help Bosnia and Herzegovina to meet the environmental standards required to join the European Union.

An approach to reduce the energy consumption of the flue gas desulfurization system for the hard coal-fired power station, Walsum 9 in Germany has been utilized. The FGD-system features two independent FGD-subsystems with five pumps each. This high number of operation modes makes it complex for the human operator to find optimal pump activation patterns, because each pump has an individual flow and also a specific power consumption. Furthermore, ongoing load demand changes as well as changing coal types with different sulfur contents make this challenging task even harder. To optimize the operation of the FGD-system, Steag implemented a clustering algorithm, which learns automatically from historical process data relationships between pump constellations, power consumption, reduction of sulfur emissions, plant load, and other factors.

The Source Testing Association conducted a survey regarding trends in portable instrumentation. The two most popular type of portable SO₂ analyzers were the Horiba NDIR (67% of respondents) and the Gasmet FTIR (44% of respondents). There were few notable trends by country, but every company from Italy who responded included the Horiba PG250/PG350 in their equipment list, with these models also proving popular in Finland. Germany, and the UK.

Dynegy’s 1,185 net MW coal-fired power plant in Baldwin, Illinois started operation in 1970. The bunkers for Units 1 and 2 are both about 186 feet long, 35 feet wide and 48 feet tall. Coal is fed into the top and then flows from the outlets into the coal feeders that transport it to the cyclones. Monitoring of the operation was done manually with safety and operational concerns. These were eliminated with Emerson’s Rosemount 5708 3D Solids Scanner, which provides continuous online volume measurement including visualization of the various peaks and valleys within vessels.
https://www.power-eng.com/articles/2019/02/measuring-the-level-in-coal-bunkers-at-illinois-power-plant.html

Four years after being awarded a contract by Fortum to upgrade safety-critical instrumentation and control (I&C) systems at the Loviisa nuclear power plant in Finland, Rolls-Royce has successfully completed installation and commissioning of new digital systems. The modernization project, ELSA, was implemented during outages over the period 2016 to 2018.

Fortum’s Loviisa plant is located on the southern coast of Finland. It has two Russian designed VVER-440 reactors, which have been in operation since 1977 and 1980, respectively.

While the major components of the plant are Russian, the I&C systems were mainly based on Siemens technologies (Simatic and Teleperm), for normal operation and safety related systems, and Russian technologies for reactor trip, rod control and neutron flux monitoring.

“We are very pleased that the implementation of the new safety systems was completed on time, within budget and according to high quality and required safety standards. Also, the nuclear specific challenge related to the complexity of licensing processes, was turned into a success factor throughout the excellent co-operation between Fortum, Rolls-Royce and all other stakeholders. This was achieved through an extensive pre-planning phase, proactive schedule management and continuous improvement during the project,” said Magnus Forsstrom, automation modernization project owner, Fortum.

GE Power India Limited has won an order worth Rs. 142 crore from NTPC for supply and installation of low NO_x combustion system for 10 GW of thermal power plant capacity across India. This is the first large scale project awarded by NTPC for installing low NO_x combustion technology at its thermal power plant fleet.

The low NO_x combustion system will be delivered in a phased manner over a period of over 30 months. The project involves in-combustion system modification of the boiler by staging the combustion air in the furnace to reduce the generation of fuel and thermal NO_x during the combustion process. This technology will help reduce 30-40 percent of NO_x emissions from these coal-fired boilers up to a level of less than 400 mg/Nm³ at 6 percent oxygen (O₂) content in flue gas on the dry gas basis at Induced Draft (ID) Fan outlet.

With more than 150 GW of coal-fired plants operating at the sub-critical level, India is the world’s second largest NO_x emitter, contributing close to 30 percent of annual NO_x emissions of the country’s industrial sector. With this order, GE Power has an opportunity to address this critical issue of emission from coal power plants.

Earlier in September 2018, GE was selected by NTPC and Tata Chemicals to upgrade two coal-fired boilers in India with low NO_x firing system in Dadri, Uttar Pradesh and Mithapur, Gujarat, which was the first standalone order for low NO_x firing system upgrade in any coal-fired utility and industrial boilers respectively in India.

With lots of new SCR and SNCR systems being installed in India, there is a need for both reagents and technical expertise. Yara has a long history in India due to its major role in the fertilizer industry.

Yara supplies the reagents for SNCR and SCR and can also supply complete systems. For each site, whether a power plant, a cement plant, or a waste incinerator, it can optimize the NO_x control system and reduce operating costs by:

· Maintenance, supply of spare parts, assessment of the SNCR and SCR system to improve its performance, safety audits.

· Advising and installing the correct storage system for your urea reagent needs, installing remote management of inventory by telemetry.

Although aqueous ammonia has perceived safety advantages, its cost is significantly higher than anhydrous ammonia.

· Aqueous ammonia has the double disadvantage of transporting and storing large quantities of water and evaporating that water prior to reaction in the SCR system.

· Vaporizing aqueous ammonia requires approximately 10 times the energy required to vaporize anhydrous ammonia.

· Finally, aqueous systems require liquid pumps and approximately 3-4 times the storage volume for an equivalent amount of reagent, resulting in additional capital costs.

· BHEL manufacturers both plate catalyst and honeycomb ceramic catalyst with three different designs.

Babcock Power Environmental Inc..has entered into a Technology Collaboration Agreement with BHEL. Babcock Power Environmental provides integrated products and services for air pollution control to power industries. BPE’s approach provides clients a single technology system for the removal of SO₂, NO_x, HCl, SO₃, Hg and fine particulates.

Babcock Power Environmental will provide Selective Catalytic Reduction (SCR) for De-NOx application to BHEL’s power equipment.

With over 48,000 MW of SCRs in operation in the US, Babcock Power brings many years of experience along with it.

Midwest Energy Emissions optimizes Mercury Capture with proprietary Sorbents and Holistic Approach

ME2C’s SEA^® Technology provides Total Mercury Control, providing solutions that are based on a thorough scientific understanding of actual and probable interactions involved in mercury capture in coal-fired flue gas. A complete understanding of the complexity of mercury–sorbent–flue gas interactions and chemisorption mechanisms allows for optimal control strategy and product formulation, resulting in the most effective mercury capture achievable. Combined with a thorough proprietary audit of the plant and its configuration and instrumentation, ME2C’s complete science and engineering approach for mercury–sorbent–flue gas interactions is well-understood, highly predictive, and critical to delivering Total Mercury Control.

A Columbian Plant fitted only with an ESP is achieving Low Mercury Emissions

Lesley Sloss of IEA visited the TermoPaipa unit 4, in Columbia to find out why a precipitator is achieving high mercury removal.

The reason why this coal/plant configuration achieved such a feat is a combination of a very clean coal and a boiler running just a little less efficiently than it should. Mercury in Colombian coal is low. Chlorine is moderate—helping to oxidize the mercury to make it “sticky” enough to attach to any fly ash materials, which have some form of sorbent characteristics … unburned carbon being the ideal surface. And so, a boiler running at a slightly lower efficiency than perhaps it should, producing 10-12% LOI (loss on ignition/unburned carbon) provides inherent sorbent, perfectly placed to capture the now oxidized mercury within the fly ash. As a result, 90% of the mercury is captured. Consistently.

For RWE’s lignite-fired power plants, the focus for mercury control is on an innovative entrained flow process and adsorption by activated lignite, called HOK^®, produced from Rhenish lignite. HOK^® is injected into the flue gas stream, adsorbs both elemental and oxidized mercury and is removed from the flue gas in the electrostatic precipitator together with the fly ash. This activity is described in Modern Power Systems by Knut Stahl, Dr. Peter Moser, Ferdinand Steffen, RWE Power AG, Essen, Germany.

With their existing flue gas treatment capabilities, RWE’s coal-fired power plants will safely comply with both the current and the upcoming German national mercury emission limits, which will become effective in 2019.

However, the introduction of EU-wide flue gas mercury emission limits via the BREF-LCP process, with a bandwidth of Hg < 1-4 μg/m³N for hard coal and Hg < 1-7 μg/m³N for lignite (annual average for existing large combustion plants >300 MWt), will again drastically tighten the framework conditions for the operation of RWE’s power plant fleet from 2021 onwards. Currently, no mercury control technique is commercially available to safely and reliably achieve emission levels below the upper limits of the bandwidth of 4 μg/m³N for hard coal and 7 μg/m³N for lignite in an industrially applicable and economically affordable way.

Based on experience and taking into consideration available technology options for Hg control in lignite-fired power plants, RWE has opted for activated carbon injection (ACI) in an entrained flow process. RWE’s affiliate Rheinbraun Brennstoff GmbH produces an activated lignite called HOK^® (“Herdofenkoks”), produced from Rhenish lignite via the so-called rotary hearth furnace process. The special properties of Rhenish lignite, coupled with the activation conditions in the production process, yield an activated carbon which has the capability for retention of a large number of pollutants due to its large specific surface area, its favorable pore radii distribution and its catalytic behaviour. HOK^® activated lignite has been commercially used for many years as an adsorption and filter agent for waste gas and effluent treatment in a vast range of applications, and several American power producers also use HOK^® in their ACI system.

With new EU regulations limiting mercury and SO₂ emissions due to come into force by 2021, executives at German power company Eins Energie in Sachsen (Saxony) knew it was time to make a change. Their coal-fired combined heat and power plant in Chemnitz was not due to be shut down for at least ten years and they needed to meet the new standards as soon as possible in the existing plant.

Roland Warner, CEO of Eins, explains: “The heat supply in Chemnitz is still largely based on lignite coal today. This type of generation produces mercury that has to be disposed of. We needed a way to comply with regulations and continue to operate our coal units in an environmentally friendly manner until they are shut down – not before 2029.

For the solution, the operators of the Chemnitz CHP plant turned to an innovative technology from W. L. Gore & Associates.

The GORE™ Mercury and SO₂ Control System has already been proven for four years in various US coal-fired power plants. The Chemnitz combined heat and power plant is pioneering the technology in Germany. After various test installations at other locations, it is also the first commercial use of the GMCS in Europe.

Innovation in the Combust, Flow and Treat Industry is a Product of Wisdom through Interconnection

A survey by McKinsey shows that 70 percent of senior executives believe that innovation should be a top driver of growth. According to the survey “Innovative cultures don’t magically descend from heaven. The top two motivators are strong leaders who encourage and protect innovation and top executives who actively manage and promote it. In fact, senior executives say their most common sin against innovation is talking it up but failing to act. The second is a failure to model innovation by encouraging behavior such as risk taking and a willingness to consider new ideas”.

Should Combust, Flow and Treat (CF) executives blame themselves for the failure of the industry to innovate or is it systemic? If customers cannot easily determine the lowest total cost of ownership of a CFT product, there is less incentive to create a better product. If the CFT industry is not interconnected in such a way that better product information will be properly assessed then innovation is stifled.

The holistic approach to innovation starts with fundamental issues such as what is the definition of “better”. The McIlvaine company has developed a unique metric to measure all harm and good Sustainability Universal Rating System. These fundamentals are the bottom of a pyramid which is supported by millions of details in organized systems. For example, what are the unique requirements for a slurry flow control valve in a dry FGD system?

The interconnection extends to the various media. Mcllvaine writes dozens of feature articles per month in magazines on materials, processes, pumps, valves, controls, chemicals etc. A new collaboration with International Filtration News features monthly “true cost analyses”. McIlvaine has more than 40 CFT reports, databases and other services which are valuable in pursuing innovation.

One of the most valuable recent initiatives is to forecast the market for each type of CFT product for each of the top 20,000 purchasers. The identification of the opportunity at BASF, Chevron, Sinopec is the first step toward developing better customer specific products. These detailed forecasts are the foundation for bottoms up collaboration among technologies, divisions and geographies.

This concept is explained in more detail in Most Profitable Market Program at www.mcilvainecompany.com

The capacity of installed coal-fired power plants will increase from 2 million MW to close to 2.3 million MW between 2018 and 2022. For some countries, such as Belgium, coal has been phased out. But, for others such as Bangladesh, there will be sixteen times as much coal-fired capacity in place in 2022 as in 2018.

Coal Plants by Country (MW) Installed Base
Country	2018	2019	2020	2021	2022	2023	2024
Albania	0	0	0	0	0	0	0
Argentina	350	350	350	350	350	350	350
Australia	24,442	24,442	24,442	24,442	24,442	24,442	24,442
Austria	635	635	635	635	635	635	635
Bangladesh	525	1,200	2,500	5,500	8,000	10,000	12,000
Belarus	0	0	0	0	0	0	0
Belgium	0	0	0	0	0	0	0
Bosnia & Herzegovina	2,073	2,073	2,073	2,073	2,073	3,000	4,000
Botswana	600	600	732	732	732	1,200	1,200
Brazil	2,804	2,804	2,804	2,804	2,804	3,400	3,400
Bulgaria	4,889	4,889	4,889	4,889	4,889	4,889	4,889
Cambodia	505	505	505	505	1,200	1,200	2,000

McIlvaine has published a new database for coal-fired power capacity additions through 2024 for every country of the world. This database is included in 42EI Utility Tracking System.

This Utility E-Alert is part of the Utility Tracking System. The system allows you to instantly retrieve project details, profiles of each coal-fired power plant worldwide, the right contacts at the OEM and A/E firms and summaries of all the scheduled FGD and SCR projects. You need a user name and password to access this system. If you have forgotten your user name or password or are not sure whether you are eligible to access this system please send email to editor@mcilvainecompany.com.

*** The Utility E-Alert is for the exclusive use of the registered subscriber to whom it is electronically delivered. Unauthorized distribution is prohibited. ***

· Argan, Inc.'s Wholly Owned Subsidiary Gemma Power Systems Enters into an EPC Contract and Receives a Limited Notice to Proceed for the Harrison County Power Project

· GE’s Total Plant Solutions Help Azito’s Power Plant Boost Efficiency, Output and Reliability in Ivory Coast

Argan, Inc.'s Wholly Owned Subsidiary Gemma Power Systems Enters into an EPC Contract and Receives a Limited Notice to Proceed for the Harrison County Power Project

GE’s Total Plant Solutions Help Azito’s Power Plant Boost Efficiency, Output and Reliability in Ivory Coast