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

IAC will be a DSUA Participant

Dry Scrubbing Discussions at the Cement Conference in St. Louis

Cement Dry Scrubber Systems

DSI Systems for Cement Plant Mercury and Acid Gas Reduction

Komline Sanderson has Unique Dry Scrubber Atomizer

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

Dadri Coal-fired Plant is installing DSI

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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 through 12, 2019 in Kansas City, MO.  The third 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!

Important conference dates:

• July 15, 2019 – Call for Abstracts Closes
• August 1, 2019 – Author Notifications Sent
• August 15, 2019 – Final Presentations Due

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 SDE^TM 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 SDE^TM 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.

You can register for the conference at the following link and you can reach out to the association president, Gerald Hunt, with any questions (gerald.hunt@lhoist.com):    http://www.cvent.com/events/2019-dry-scrubber-users-conference/event-summary-a5a83248aab04179bd8355b529d6334b.aspx 

IAC will be a DSUA participant

IAC is located in Kansas City and will be supporting the conference in multiple ways. With their test rigs to determine location and amount of required reagent IAC is interfacing with suppliers, end users and consultants.  When you click on IAC in the McIlvaine corporate search you find

The newsletter coverage of the Wagner test site shows the value of test rigs which IAC has available.  The capital cost of DSI is very low. The reagent cost can be high. It is important to accurately predict reagent costs before choosing DSI, dry scrubbing or wet scrubbing with the lower cost limestone.

Constellation Energy’s 340-MW Wagner Unit 3 with SCR, tubular air preheater and cold side ESP and 130-MW Unit 2 with Ljungstrom air preheater and cold side ESP participated in Solvay Chemicals testing of Trona and sodium bicarbonate injection for SO2, SO3, NOx and mercury reduction. Industrial Accessories Company (IAC) provided the rigs, injection lances and test management. The required SO2 removal rate was 30 to 50 percent. Both units use activated carbon (PAC) injection for mercury control. The units fire CAPP coal (0.83 percent sulfur) or a blend of CAPP and PRB. Youngen Kong and Stan Carpenter of Solvay Chemicals, Salil Bose and Matthew McMillian of Constellation Energy, and Pramodh Nijhawan of IAC reported at Power-Gen International 2009 that Trona was able to meet the SO2 removal targets for various fuel types at feed rates between 1.1 and 2 NSR. A higher SO2 removal rate was obtained with sodium bicarbonate. ESP performance was enhanced by Trona (with no PAC injection) and NSR 1.1, which reduces SO2 by 29 percent. Around 10 percent NOx was also removed (a bonus) with both sorbents. For Unit 2, mercury removal increased from 82 to 90 percent with Trona injection alone (NSR 1.1). For Unit 3, up to 80 percent of the mercury was removed by PAC without Trona. Over 90 percent mercury removal was realized by PAC with Trona injection (NSR=0.1). The positive effect of sodium bicarbonate on mercury removal was also demonstrated and is comparable to Trona.

One of the goals is to publish generalized cost data relative to the capital cost of the various scrubbing technologies along with costs for various reagents to obtain the lowest total cost of ownership validation (LTCOV).  At the height of the FGD market McIlvaine was working closely with all the lime companies and had agreed upon rules of thumb such as lime consumption per MW for low sulfur coal for 90% efficiency and average capacity factors. Sargent & Lundy provided some good comparative analyses through a contract with NLA. McIlvaine utilized all this information in a contract with Austin Energy who made a case for dry scrubbing for one of the units owned by a partnership which included them.

Dry scrubbing discussions at the Cement Conference in St. Louis

The 61st Annual IEEE-IAS/PCA Cement Industry Technical Conference was held in the St, Louis Convention Center, April 28-May 2, 2019. This is the largest conference in the cement industry and  included presentations of the latest technology covering a variety of topics important to the industry. One of the speakers, Robert McCaffery of Global Cement, addressed the lower consumption of cement per capita in developed countries. This is one of many reasons that information about dry scrubber technology needs to be global.

This same speech was given in Belgium where there is a focus on CO₂ reduction.  A country  such as Belgium has less CO₂ emissions per capita as a result of lower cement consumption.

McIlvaine has interviewed exhibitors in the past and posted this coverage plus other cement industry analyses and articles in a free site.  These articles and interviews can be viewed at
http://www.mcilvainecompany.com/Decision_Tree/subscriber/Tree/UnivDB/appl3.asp?ref1=806&ref2=0&ref3=0&ref4=0&ref5=0&ref6=0

IAC, who was one of the conference exhibitors, supplied a turnkey system for the Drake Cement plant in Arizona.

1.      Imported ingredients: Alumina and iron are imported as minor processing additions.

2.      Mining and crushing: Limestone (calcium) and silica are mined from the quarry and conveyed to the plant.

3.      Raw material storage: Limestone (calcium), iron, silica and alumina are stored in large silos.

4.      Blending: All raw ingredients are blended in proportion to prepare for grinding.

5.      Raw grinding: Raw ingredients are ground to fineness of baby powder and further blended into a homogeneous mixture.

6.      Heating and cooling: The ground mixture is fed into the kiln through a tall preheating tower, where it is heated and rapidly cooled to create clinker.

7.      Clinker storage: Clinker is stored in a large dome and silo waiting to be ground into cement.

8.       

9.      Finish grinding: Clinker is ground into the fine gray powder recognized as cement, adding a small amount of gypsum to control the time of setting.

10.  Cement storage and shipping: Finished cement is stored in a silo awaiting loading into trucks or rail cars.

IAC provided Design/Build services. The plant site sits on 300 acres in Drake, AZ. The facility includes complete raw materials receiving and storage, clinker production, rail loading and storage silos, coal fuel processing, and fugitive dust collection. The Design/Build contract was valued at $49.7 million. As part of the project, IAC supplied over 1,500 metric tons of structural steel, 34 different specially designed IAC OEM baghouses, energy saving IAC OEM air-to-air heater exchanger, conveyors, rotary valves, fans, and process control dampers for emission control at the plant.

Cement Dry Scrubber Systems

Votorantim Cimentos’ St Marys Cement plant and quarry in Bowmanville, east of Toronto, installed  a new, more efficient raw mill and a new scrubber to further reduce emissions in 2018. The company worked with FLSmidth to reduce its SO₂ emissions by producing its own hydrated lime, which is used as a cost-effective alkali to treat flue gas emissions from the cement plant. 

Hanson implemented  a £25 million (€29.06 million) 7-year project at Ribblesdale cement works in Clitheroe, Lancashire, North West England to improve production efficiency and emissions.  £11 million was spent on improvements and maintenance to enable the plant to meet new dust emission regulations. This is the biggest investment program since the 1990s and includes a £2 million replacement of the filters on two cement grinding plants. A £6.5 million, replacement of the wet gas scrubber was initiated. The plant was the first UK cement plant to install a scrubber in 1998.

DSI Systems for Cement Plant Mercury and Acid Gas Reduction

DSI and ACI systems usually consist of storage (either silo storage or bulk bag, i.e. ‘super sack’), after which the product is metered into an air stream and conveyed via dilute-phase into the process gas stream, upstream of a particulate collection device. However, while often considered a low capital solution relative to other acid gas scrubbing technologies, the greatest capital associated with DSI and ACI is the initial equipment procurement and installation. For applications where Hg control is either intermittent or low injection rates are needed, a blended hydrated lime (HL) and powdered activated carbon (PAC) sorbent allows for a single feed system to be used. For example, Lhoist North America’s blended HL-PAC product enables concurrent acid gas and Hg control, using a single sorbent injection system (instead of installing and maintaining two nearly identical systems), to inject the sorbents simultaneously as a pre-blended, homogeneous product. Lhoist North America produces customized enhanced hydrated lime blends (branded Sorbacal^® SP and SPS) with brominated PAC. These are produced either in bag or bulk, in 5% PAC (weight by weight) blend increments up to 30%.

While a single, blended sorbent for Hg and acid gas can decrease overall system CAPEX by reducing the need to a single system, careful attention should be paid to optimizing the quantity of sorbent required to achieve compliance.

Before equipment design and selection phases (or after system commissioning, if this was overlooked during design), plants should consider the following:

• Optimal injection location (which depends on target pollutants).
• Sorbent type.
• Sorbent application/distribution within the gas stream.

Sorbent trials with temporary DSI systems are highly recommended before the system design and selection phases. Alternatively, it is possible to evaluate alternative injection locations after a DSI system has been installed. Sorbent trials should include the measurement of dose-response curves (i.e. parametric) at several different locations within the plant, to identify the most efficient injection strategy.

https://www.worldcement.com/special-reports/06032019/optimising-dry-sorbent-injection/

Komline-Sanderson has Unique Dry Scrubber Atomizer

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:

§  Air Pollution Control (APC)

§  Dry Flue Gas Desulfurization (FGD) on coal-fired boilers

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

§  Evaporation of wet scrubber effluents at hazardous waste facilities

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

o    Inorganic salts

o    Tungsten carbide

o    Catalyst carriers

o    Silicas

o    Kaolin & clay products

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

Illinois power plants have significant amounts of dry FGD and DSI.  A task force 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 provide an understandable estimate of the actual costs to a 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 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

http://www.ilga.gov/reports/ReportsSubmitted/173RSGAEmail366RSGAAttachFINAL%20FGD%20Task%20Force%20Report%20and%20Appendix%20(printing).pdf

Dadri Coal-fired Plant is installing DSI

The National Thermal Power Corporation (NTPC)’s Dadri Power Plant is opting for a Dry Sorbent Injection (DSI) system for controlling sulphur 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 6,00,000 Nm³/hr, with sulphur 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

use Sodium Bicarbonate as reagent

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 desulphurization (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.

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.

http://www.indiaenvironmentportal.org.in/files/file/Off-Target---Status-of-Power-Stations-Report.pdf