FGD and DeNOx
NEWSLETTER       

February 2011
No. 394

FGD

Serbian 2x350-MW Kostolac B to Add FGD

The Chinese company China National Machinery and Equipment Import & Export (CMEC) and the Kostolac thermal power station signed a deal for the first stage of the 2x350-MW Kostolac B project, worth US$344 million. Serbia Minister Skundric said that the deal includes rehabbing the first and second blocks of the Kostolac B power plant, the purchase of FGD equipment and construction of infrastructure. Elektroprivreda Srbije Director Dragomir Markovic pointed out that China Eximbank is expected to approve a loan for the realization of the project in the next two to three months.

Work to Resume on Two FGD Units at Clifty Creek

Construction will resume in May at the Clifty Creek power plant, where the building of scrubbers was halted two years ago because of the economy. “We are thrilled to be in a position to restart construction of the scrubbers at Clifty Creek,” said Scott N. Smith, vice president and assistant to the president of Ohio Valley Electric Corp-Indiana-Kentucky Electric Corp., (OVEC-IKEC) which owns the power plant. The construction of the two scrubbers was about 35 percent complete when work stopped. Each of the units will treat the flue gas from three of the plant’s six generating units and is expected to be completed in 2013.

OVEC-IKEC also is building scrubbers at the Kyger Creek Plant in Cheshire, OH. A design flaw was found at Kyger Creek, and some of the parts had to be replaced with redesigned parts. “For us, really it was fortunate that we suspended construction when we did because it gave us the opportunity to correct this design flaw,” Steven Smith, Clifty Creek plant manager, said. One of the two stainless steel tanks at Clifty Creek had the flawed design in components, so they will be replaced by the redesigned parts, he said.

DTE Monroe Gets Further Approval for Environmental Upgrades

The Michigan Department of Natural Resources and Environment gave DTE Energy the green light to invest more than $1 billion more in FGD and SCR equipment at its Monroe Power Plant. When completed sometime in 2014, the project is expected to cut an estimated 49.2 million pounds of NO_x, 7.5 million pounds of particulate matter, 215.9 million pounds of SO₂ and 1400 pounds of lead. In addition to the pollution control equipment, changes to the boilers include increasing the use of sub-bituminous coal and adding the combustion of petroleum coke; upgrading the coal-handling systems; installing petroleum coke-handling systems, installing limestone- and gypsum-handling systems, and installing diesel fuel-fired quench pumps. Two of the plant’s four boilers already have been outfitted with the pollution control systems and work continues on the others.

Lawsuit Over Implementation of 1 – hour SO₂ Standard

EPA is urging a federal appeals court to reject North Dakota’s request to stay implementation of EPA’s novel approach for determining whether states are attaining its SO₂ National Ambient Air Quality Standard (NAAQS). EPA, states, public health groups and others filed briefs with the U.S. Court of Appeals for the District of Columbia Circuit in Montana Sulphur & Chemical Company v. EPA, which consolidates a slew of lawsuits filed over the agency’s decision earlier in 2010 to tighten its SO₂ standard On June 22, EPA finalized its rule creating a new 1-hour standard at a level of 75 ppb.

As part of the litigation, on October 8, North Dakota filed a motion requesting a stay of the new 1-hour SO₂ standard that had a June 2, 2011 deadline by which all states must provide EPA with recommendations for whether each area within its jurisdiction is in or out of attainment in the new NAAQS.

North Dakota says the final rule establishes a new implementation approach that requires states to use the results of “conservative” computer modeling rather than actual air quality data in making attainment recommendations. North Dakota says EPA has not fully “articulated” how to run the modeling, and says the models “almost always” lead to more areas being designed as nonattainment or unclassifiable because they overstate emissions. But EPA counters that it has no final plans for how to make attainment designations and that a lawsuit on that issue is premature.

TVA Kingston Must Replace Liner at Leaky Gypsum Pond

Two years after the Tennessee Valley Authority’s coal ash spill, environmental officials have ordered a synthetic liner be installed in a leaky gypsum storage pond at the same coal-powered plant, Kingston. The gypsum pond seepage is not related to the TVA’s ongoing $1.2-billion cleanup of the 5.4 million cubic yards of ash spilled two years ago into the river and the surrounding landscape.  Tennessee Dept. of Environment and Conservation spokeswoman Tisha Calabrese-Benton said that in addition to TVA interrupting use of the storage pond until it is fixed, the utility must provide a “detailed corrective action plan.”

A TVA statement said the pond built in 2006 covers an area of about 50 acres and has a capacity to hold about 5.7 million cubic yards of gypsum but has been used only a short time and contains about 22,000 cubic yards of gypsum. She said the gypsum “had settled in the far end of the pond away from the leak.” TVA spokeswoman Barbara Martocci said there was not yet any estimate on the cost of the synthetic liner or a timetable to get it installed. She said the existing liner — a 3-foot-thick layer of clay and a layer of bentonite — was required when the gypsum pond was built.

SCAQMD Reduces SO_x Emissions from 11 Facilities

The South Coast Air Quality Management District (SCAQMD) has approved three measures that will reduce SO₂ emissions from oil refineries, lead emissions from battery recyclers and cumulative air toxics risk from a number of sources across the Southland. SCAQMD is the air pollution control agency for Orange County and major portions of Los Angeles, San Bernardino and Riverside counties, CA.

Amendments to Regulation XX – SO_x RECLAIM will reduce emissions from six oil refineries, two sulfuric acid plants, a petroleum coke facility, a glass manufacturer and a cement plant. These facilities emit 93 percent of the total SO_x emissions in the RECLAIM program. These revisions will help the area come into attainment for PM_2.5.

Adopted changes to the RECLAIM program include:

· Cumulative reductions of 5.7 tons per day of SO_x emissions from the 11 facilities by 2019, to be phased in between 2013 and 2019;

· New lower levels for Best Available Control Technologies (BACT); and

· New set-aside credit accounts that could be available to facilities if market credit prices spike above the $50,000 per ton threshold.

KBR Acquires Roberts & Schaefer

Engineering and construction company KBR, Inc. has acquired Chicago-based Roberts & Schaefer Co., a subsidiary of Elgin National Industries. The purchase price is $280 million plus preliminary networking capital of $12 million with final adjustment after closing. Roberts & Schaefer is an engineering, procurement and construction services company specializing in bulk material handling and processing systems. The company provides services to customers in the mining and minerals, power, industrial, refining, aggregates, and precious and base metals industries.

Jeffrey Energy Center FGD Upgrade

Over a period of 18 months (Spring 2008 through Spring 2009), Westar’s 3 x 800 MW Jeffrey Energy Center upgraded the existing FGD systems to remove greater than 95 percent of the SO₂. Burns & McDonnell was contracted to provide detailed engineering, procurement and construction management services for the project. In addition to upgrading the absorbers by way of new internals, new slurry recycling pumps and conversion to forced oxidation, the scope of the project also included upgrading the existing ID fans, new ductwork from the ID fan outlet through to the stack breaching, and conversion to accommodate “wet stack” mode of operation and forced oxidation. The project also included the addition of new limestone preparation and feed systems, new gypsum dewatering and a new FGD blowdown treatment system. The approximate cost of the project was $435 million, reported Kristin Collier of Burns & McDonnell and Stuart Bailey of Westar Energy at Power-Gen 2010.

Upgrades included:

· The internals of each module were replaced in their entirety. All new module internals were of Alloy 2205 construction. The existing spray headers were replaced in kind, with two levels of spray. Headers were constructed of Alloy 2205 internal to the module and fiberglass-reinforced plastic (FRP) external to the module. A contact tray was added to improve the liquid/gas (L/G) contact and reduce the slurry spray requirement. Wall rings were installed to prevent gas sneakage and to direct sprays back toward the center of the towers.
 

· The original mist eliminators and retractable lance wash system were replaced with high efficiency mist eliminators and a fixed grid wash system. The new mist eliminators have a velocity limit of about 22 feet per second (fps), as compared to the original system’s limit of 10 fps.
 

· Each module has a dedicated reaction tank. As a result of degradation over time, all tanks were replaced. The new tanks are carbon steel with ceramic tile lining the walls and floor. The new tank roof was constructed of 316L stainless steel.
 

· The upgraded system includes one spray pump per spray level, or two per module. Each pump is rated at 20,5000 gpm.
 

· Due to increased pressure drop across the absorber modules, the ID fans needed to be upgraded. New rotors and variable inlet vanes were installed in the existing fan housings. New 8900-hp motors were also installed as part of the upgrade.
 

· The required limestone grind for the revised FGD system is 95 percent passing 325 mesh. To accomplish this, two new 48 tph ball mills were installed, one running, one spare. The new ball mills were sized so that grinding for a 24-hour-period could be accomplished in one 8-hour shift. Two new limestone slurry storage tanks and new forwarding system, pumps and slurry piping loop were included as part of the upgrade.
 

· Hydrocyclones, one cluster per module, were added for primary dewatering. Three 55 tons/hr vacuum filters were installed as part of the upgrade, two operating, one spare, sized so that a day’s worth (24 hours) of spent slurry can be dewatered in 12 hours.

After the outage for Unit 3, the scrubber was not achieving the desired SO₂ removal efficiency. Several attempts were made to increase removal by way of altering operating parameters such as pH, stoichiometry and reaction tank density with limited success. The final solution was to increase the pressure drop, and therefore liquid/gas contact time, across the contact tray by reducing the open area from 40 to 30 percent. Figure 1 (see insert) shows emissions from Unit 3.

After the upgrade there were vents of foaming from the reaction tanks. The probable cause was bridging between fine particulates. To counteract the foaming, the limestone slurry storage tanks were dosed with an anti-foaming agent as a plant-wide solution. A purge valve on the hydrocyclone overflow, now opened to remove fines from individual reaction tanks when required, substantially reduces foaming events.

When the secondary dewatering system was first operated, there was a persistent failure to produce filter cake. The filter cloth was blinding after a couple of revolutions of the drum. The blinding was not permanent — the filter could be shut down and the cloth cleaned, which ruled out significant amounts of flyash as a fouling source. The fines layer (secondary peak at 10 micron or less) was attributed to a high level of inerts in the limestone. The limestone supply was changed to a source with fewer inerts and performance of the vacuum filters dramatically improved. A permanent chemical feed system was installed to accommodate upset conditions.

Chiyoda FGD Installed at 147-MW Asnaes 2 in 23 Months

Dong Energy completed a Chiyoda wet limestone CT-121 FGD system on 147 MW Asnaes Unit 2. This system was designed to also, with only minor modifications, be able to treat effluent from a possible future upgrade of Asnaes Unit 4 to 400 MW. Separate from the scope of the FGD supply, a new booster fan was installed upstream of the FGD, along with modification of the stack with an FRP liner for wet operation. The 700-MW Unit 5 FGD slurry preparation system and dewatering systems were integrated with the new Unit 2 FGD. This project was completed in 23 months.

Elm Road Emissions Tested Well Below Permit Levels

One 615-MW supercritical unit at Elm Road, part of We Energies Oak Creek Power Plant (OCPP), was commissioned in 2010. Unit 2 came online in early 2011. Tom Metcalfe, project director for the Elm Road Units at OCPP and Vice President of We Power LLC, said, “Unit 1’s emission tests were completed in January 2010, and the results are considered world class. Actual emissions of particulates, SO₂ and the other regulated emissions were tested to be considerably lower than required by the project’s air permit. In the case of SO₂, carbon monoxide, and many other regulated substances, the emission rates were a fraction of required permit levels.” Both units burn Eastern coal and have SCR, baghouse, FGD, and wet ESP.

NO_x

FIP for San Juan Proposes SCR by 2013

A Federal Implementation Plan has been proposed under the Clean Air Act for Public Service Co. of NM’s 1,800 MW coal-fired San Juan Generating Station. The plant’s operators will be required to install BACT that is expected to reduce emissions of NO_x by approximately 83 percent. This could be achieved through installation of SCR or similar technology on all four coal-fired generating units at the power plant. EPA proposes that the plant have three years to add the pollution controls.

Colorado Proposing SNCR for Craig

Tri-State Generation & Transmission’s coal-fired power plant in Craig, CO may soon be receiving new emission control technology as part of Colorado’s plan for regional haze compliance. Tri-State supports the state’s proposal which would likely put in place SNCR technology to reduce NO_x by 15 percent. The project would have a start-up cost of about $40 million with an annual operating price tag of about $10 million, Tri-State spokesman Brad Jones said.

Vogt Power to Supply HRSG/SCR for El Centro Repower

Vogt Power International, Inc. will supply the Heat Recovery Steam Generators (HRSG) to Siemens Energy, Inc. for Imperial Irrigation District’s El Centro Power Plant in California. Phase Two of the El Centro Unit 3 Repower Project will convert the power plant from a conventional steam cycle system to a combined cycle system, increasing its generating capacity from 44 to 144 MW. The existing equipment will be replaced with two Siemens SGT-800 combustion turbine generators, two Vogt Power auxiliary-fired, two pressure level HRSGs, with CO and SCR systems, and a Siemens SST-600 steam turbine generator.

RasGas Retrofits GE DLN Combustion Control at LNG Complex

RasGas Company Limited (RasGas), one of the world’s largest producers of Liquefied Natural Gas (LNG), is applying GE’s Dry Low NO_x (DLN) combustion technology to reduce gas turbine emissions at its LNG complex in Ras Laffan Industrial City in Qatar. “The technology retrofits for our first six GE gas turbines achieved the reduction of NO_x emission levels by more than half, which go beyond the country’s current regulatory requirements,” said Hamad Rashid Al Mohannadi, RasGas Managing Director.

Ozone Attainment for NH and WI Areas

The EPA is proposing to determine that the Boston-Manchester-Portsmouth, NH moderate 1997 8-hour ozone nonattainment area has attained the 1997 8-hour National Ambient Air Quality Standard (NAAQS) for ozone.

EPA is also making determinations that the Milwaukee-Racine and Sheboygan, WI areas have attained the 1997 8-hour ozone NAAQS.

TurboSonic to Supply DeNOx in Europe

TurboSonic Technologies, Inc. has been awarded a contract by Wahlco, Inc. for balance of plant supply for a NO_x control project at a European coal-fired power plant.

Consent Decree with Murphy Oil Includes SCR for FCCU

The Environmental Protection Agency (EPA) and the U.S. Justice Dept. announced a settlement with Murphy Oil USA. Murphy Oil USA has agreed to pay a $1.25-million civil penalty to resolve violations of the Clean Air Act at its petroleum refineries in Meraux, LA and Superior, WI. As part of the settlement, the company will spend more than $142 million to install new and upgraded pollution control equipment at the refineries. Murphy allegedly violated the New Source Review (NSR), Prevention of Significant Deterioration (PSD), New Source Performance Standards (NSPS) and the National Emission Standards for Hazardous Air Pollutants (NESHAP) provisions in the Clean Air Act (CAA) with regard to the facilities emissions of SO₂, NO_x, VOCs and benzene.

The consent decree requires fluidized catalytic cracking units (FCCUs) and heaters and boilers by September 30, 2012 to limit NO_x emissions to no more than 20 ppm on a 365-day rolling average basis and 40 ppm on a 7-day rolling average basis at the Meraux refinery. The Superior refinery will implement a program to demonstrate the lowest emissions achievable using NO_x-reducing catalyst additives in conjunction with other operational requirements to minimize NO_x emissions. The final NO_x emissions limit at the Superior refinery will be no higher than 40 ppm on a 365-day rolling average and 80 ppm on a 7-day rolling average basis. The consent decree will require the installation of SCR, Ultra Low NO_x Burners, or equivalent technology that is designed to achieve an emission rate of 0.040 lb NO_x/MMBtu on heaters and boilers greater than 40 MMBtu/hr at each refinery.

ROFA and Rotamix at Elektrownia Opole

Nalco Mobotec’s Rotating Opposed Fired Air (ROFA^®) and Rotamix^® and extensive windbox modifications were installed at PGE’s Elektrownia Opole Unit 3 in Poland to reduce NO_x emission.  The RAFAKO BP-1150 boiler is a 380-MW tangentially-fired tower boiler. The installation included three steps:  (1) An operational, mechanical and performance review of the existing firing system, leading to tangential windbox modification and upgrade, (2) the existing SOFA system was replaced by Nalco Mobotec’s ROFA system, and (3) a Rotamix SNCR system was installed, introducing urea into the upper furnace.

In 2016, Polish NO_x emissions regulations are to drop to 200 mg/Nm³ (at 6 percent O₂) under the large combustion plant directive (LCPD). Due to the large number of boilers in Poland that must be below 200 mg/Nm³, many are installing equipment early. In 2008, PGE Elektrownia Opole procured the Mobotec System.

Elektrownia Opole mandated that the installation could not degrade plant performance with specifications on CO, flyash LOI, slag ash LOI, ammonia slip, ammonia in ash, ammonia in gypsum, ambient noise, availability, boiler efficiency, wastage, steam flow, steam temperature, and consumption of urea, water, electricity and compressed air.

To maximize SNCR efficiency, it is important to minimize CO in the upper furnace. Improved fuel/air mixing in the burner zone facilities CO burnout. Nalco Mobotec felt that having automated secondary air (SA) nozzle tilt control for superheat (SH) and reheat (RH) temperature along with the existing attemperation system was beneficial for the project. Drives were added to control the tilts for all three independent vertical burners groups. The CCOFA ports were replaced with new higher velocity nozzles and were also provided manual control for both tilt (vertical) and yaw (horizontal). Also, the lower secondary air nozzles in each corner were modified with a Lower Furnace CO Control (LFCC) system. As part of the windbox modifications, the SA nozzles located between pairs of burners were replaced with new nozzles to increase exit velocity and windbox pressure control.

The windbox SA flow dampers were also modified to provide operation with increased air biasing control. The downstream dampers were modified and entry loss optimized by adding a venture-shaped entry. A portion of the secondary flow control dampers (all but coal nozzle secondary air feed) were equipped with modulated actuators to improve control of flow and windbox pressure across load. RV Industries designed and supplied the tangential-firing system components, including installations and startup support.

The Rotamix system consists of an air delivery system and a liquid (urea and water) delivery system. The air delivery system contains a small ambient-air fan and ductwork similar to the ROFA system, but smaller in size. There are several levels of Rotamix ports; including ports between gaps in the radiant wall superheater bands and ports in the upper furnace between SH platens. Urea can also be injected through the ROFA nozzles. The upper furnace injection ports have injection angle adjustment capability. In addition to the diluted urea, Rotamix humidification water is delivered to any injection device that is in service. The humidification water system adds additional control and tuning capability to the Rotamix system as urea injection concentrations can be manipulated to compensate for furnace flow anomalies.

Brian Higgins, Baiyun Gong, Ed Pozzobon and Guisu Liu of Nalco Mobotec; Edward Kinal, Jan Pilipionek and Miroslaw Pietrzyk of Elektrownia Opole and Robert Zmuda, Peter Hajewski and Wlodzimierz Blasiak of Nalco Mobotec Polska reported at Power-Gen 2010 that the combined effect of burner modification and the ROFA and Rotamix systems resulted in:

(1) NO_x emission below 200 mg/Nm³, averaging 168 mg/Nm³ (52 to 66 percent reduction).

(2) Demonstrated ability to handle significant fuel variability.

(3) Improved combustion due to mixing introduced by the ROFA system. O₂ is reduced in the furnace, lowering NO_x and improving boiler efficiency.

(4) LOI for flyash averaged 3.5 percent, which is below the limit for continued flyash sales.

(5) LOI for slag ash averaged 7.3 percent, which is high, but will be managed through tuning.

(6) CO emissions were held to an average value of only 41 mg/Nm³ over the ten days testing.

(7) Ammonia slip from the SNCR system was held to 3.1 ppm on average and below 5 ppm for full load conditions.

(8) Ammonia in ash averaged 35 mg/kg (below the 50 mg/kg limit).

(9) Ammonia in gypsum averaged 8.6 mg/kg (below the 10 mg/kg limit).

(10) The FD and ID fan power usage dropped by a total of 830 kW, or 10 percent. This savings nearly made up for the entire power usage required for the ROFA fan. The net power increase post-ROFA installation was two percent of the total parasitic fan load and less than 0.05 percent of the produced power.

McIlvaine Definitions for Catalyst Maintenance

McIlvaine is working on precise definitions as part of the Decisive Classification area of our free website. The goal is to precisely organize and classify the world’s information and to make it easily understood in any language. On October 21 in a McIlvaine webinar on catalysts there was tentative agreement reached on the differentiation between catalyst cleaning, rejuvenation and regeneration. Coalogix provided the definitions given in Figure 2 (see insert) and these are now part of the Decisive Classification area.

EPA Postpones Issuing New Ozone NAAQS

EPA filed a motion with the United States Court of Appeals for the District of Columbia Circuit on December 8, 2010 to delay issuing the revised National Ambient Air Quality Standard (NAAQS) for Ozone until July 29, 2011. In January 2010 EPA issued a new proposal to tighten the ozone standard to within the 60-70 ppb range. EPA accepted public comment until March 22, 2010. In the motion, Regina McCarthy, Office of Air and Radiation Assistant Administrator, says, “In the process of evaluating the scientific evidence and other information before her, the Administrator recently determined that seeking addition advice from the Clean Air Act Scientific Advisory Committee (CASAC) may prove useful and important in helping her draw conclusions about the scientific and other technical information.” EPP intends to prepare a set of questions for CASAC in December 2010 and Jan. 2011. EPA expects that CASAC will hold a public meeting in February 2011. EPA intends to then issue a final decision by July 29, 2011.  

Hg

Mercury Control and Measurement —Hot Topic October 14

There is going to be a short time-period for utilities to react and then comply with the anticipated Utility MACT Rule. Five experts provided insights at McIlvaine’s October  14 Hot Topic Hour on the challenges regarding mercury control and measurement to meet the anticipated requirements.

Jean Bustard of ADA-ES provided some interesting graphs showing that most coal has raw mercury in the 3-7 lbs/tBtu range. So if the limit is 0.5 lbs/tBtu, there will be an efficiency requirement between 80-95 percent for most units. Activated carbon can be injected ahead of a baghouse but also can be used ahead of a precipitator-scrubber combination. Here the activated carbon injection (ACI) would provide a safety factor if the scrubber cannot by itself meet the limits. The capital cost of the ACI system is low, so it is a good investment even if it is seldom used.

Jean believes that there could be as many as 600 coal-fired power plants, 500 industrial boilers and 90 cement plants which presently do not use ACI but will need to start using it in the next four years. In the peak years of 2013 and 2014 as many as 300 systems/yr will be purchased. This could create a shortage of equipment and labor. Jean says that the total procurement cycle for ACI is more than one year.

Ron Landreth of Albemarle provided details on the PPL Corette Station in Montana. A commercial ACI system using cement-friendly sorbent is allowing the power plant to sell its flyash while meeting a mercury limit of 0.9 lbs/tBtu. C-PAC consists only of pulverized activated carbon and Bromine. There are no other additives. Ron stressed the importance of this due to pending guidelines which would prohibit supplemental additives.

Chris Martin and John Pavlish of EERC explained the complex mechanisms by which activated carbon is successfully removing mercury. Some specific nitrogen compounds play a role in converting elemental mercury to the oxidized form. Mercury capture is primarily site limited in the capture of the first 30 percent. Transition effects are important in raising the efficiency to 50 percent. Higher efficiency is “reactant-limited.” As a result of the variables the performance of the ACI/precipitator combination will vary greatly from plant to plant. Therefore pilot or full scale testing is beneficial.

John Foster of SPE-Amerex extrapolated from the experience on incinerators and industrial boilers to predict the equipment needs for Utility MACT.  He believes that any of the scrubber types will be able to meet the 3 ppm HCl requirement. Ninety-five percent mercury capture can be achieved but in the case of incinerators there is a high HCl content and therefore little elemental mercury. SPE-Amerex is injecting activated carbon after the counter flow reactor but ahead of the baghouse. The company installed an ACI unit on a utility in Green Bay, Wisconsin last year. The 120-MW unit is achieving 77 percent mercury removal at 6 lbs/MMACF. The injection is upstream of a precipitator.

Bobby Chen of Shaw discussed the potential of EMA, which relies on hydrogen bromide instead of calcium bromide. This compound is proving capable of oxidizing more than 90 percent of the elemental mercury and therefore allowing scrubbers to achieve high mercury removal. Annual consumption for a 350-MW unit at full load and injection rates of 3 to 10 gph would cost between $200,000 and $400,000. The compound could be used as the only chemical or to reduce the amount of activated carbon required.

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