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Power Engineering

The Ins and Outs of SO2 Control

06/01/2012

ByLindsayMorris, Associate Editor

Sulfur dioxide (SO2) emissions have long been an area of concern for the U.S. Environmental Protection Agency(EPA)

and, therefore, the power producers it regulates.

Anumber of regulations are set to target SO2 emissions, including the Cross State Air Pollution Rule (CSAPR) and the

SO2 National Ambient AirQualityStandards (NAAQS). In addition, SO2 is important to consider when preparing for the Mercuryand Air Toxics Standard (MATS), as it is a surrogate for acid gas hazardous air pollutants (HAPs).

An METinstallation of a CFB-FGD

Scrubber at a 250 MWcoal plant. Photo

courtesyMET

With so manyregulations in the mix, it seems as though SO2 is an all-encompassing concern in the scope of emissions

control. If a utilitycan get a solid control on SO2, other air toxins will be controlled, said AndrewByers, associate vice

president of Black &Veatch Environmental Services.

"When you look at all the different things that can be addressed with SO2 controls, it casts a wide net over a lot of EPAair

qualityissues."

According to the EPA, power plants are responsible for 66 percent ofworldwide SO2 emissions,with the majority—more

than 98 percent —coming from coal-fired power plants. Wet flue-gas desulfurization (FGD), dryFGD, drysorbent injection

(DSI) and other technologies have been responsible for cutting SO2 emissions by57 percent between 1980 and 2008,

according to the Edison Electric Institute. But there is still work to be done and utilities need to be aware of the many

regulations likelyto affect their plants' financial and operational decisions.

Inter-state SO2

CSAPRrequires a total of 27 states to reduce annual SO2 and nitrogen oxide (NOX) emissions from power plants. CSAPRwas stayed bya federal court in December but maybe re-released this summer. More than three dozen lawsuits

have been filed againstCSAPR, accusing the rule of being one of the "most costly, burdensome and arbitrary"rules ever

issued under the Clean Air Act.

Since the stay, EPAhas released minor changes to the rule. The Final Revisions Rule revises state SO2 and NOx

budgets for Florida, Louisiana, Michigan, Mississippi,Nebraska,NewJersey,NewYork, Texas and Wisconsin, and new

set-asides for Arkansas and Texas. The rule also revises unit-level allocations for Alabama, Indiana, Kansas, Kentucky, Ohio and Tennessee to better account for utilityconsent decrees. The rule also amends the assurance penaltyprovisions

for all states within the programs so theystart in 2014 instead of 2012.

An METinstallation of a wet scrubber at a 250 MWcoal plant. Photo

courtesyMET

"Bydelaying the assurance penaltyprovisions, EPAis providing utilities with slightlymore time to relyon emission trading

as a compliance strategyand more time to install emission controls," said Todd Palmer, partner at Michael Best &

Friedrich LLP. Trading of SO2 and NOxcredits between states is expected to make compliance more feasible.

Along with CSAPRitself being challenged, these minor changes to the rule have also been challenged, Palmer said.

An oral argument over CSAPRwas held on April 13 in Washington D.C. before a federal court."The panel seemed most

concerned that EPA's methodologyfor developing state emission budgets, specificallywhether EPAis forcing states to

reduce their emissions beyond what is otherwise necessaryto mitigate the state's contribution to downwind air pollution

concentrations," Palmer said.

It is expected that the courtwill reach a decision on CSAPRsometime this summer,which could be followed by

substantive changes to the rule bythe EPA.

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By2014, combined with other final state and EPAactions,CSAPRwill reduce SO2 emissions by73 percent and NOx

emissions by54 percent from 2005 levels in the CSAPRregion, according to the EPA.

Byers said it is understood that trading under CSAPRwill provide "a bit of cushion where operators can add SO2 control

on the back end."Given the levels that maybe imposed under the rule, it maybe more beneficial to add SO2 control on

the back end and bank or sell credits back into the market, Byers said.

SO2 NAAQS: The One-hour Challenge

The SO2 NAAQSare another concern for utilities. The Clean Air Act requires EPAto set national air qualitystandards for

SO2 and five other emissions types.On June 2, 2010, the primarySO2 NAAQSwas revised to set the SO2 standard at 75

parts per billion (ppb),which is attained when the three-year average of the 99th percentile of one-hour dailymaximum

concentrations does not exceed 75 ppb.

The one-hour measurement of SO2 raises a newset of challenges for utilities, especiallycompared to the previous

standard,which allowed no more than 140 ppb over 24 hours. In contrast, manyother EPAstandards have concentration measurements taken over a span of eight hours, one dayor even one year. For SO2 NAAQS, EPAargues that long-term

measurements of SO2 produce too much fluctuation."While national SO2 air qualitylevels have improved, EPAremains

concerned about short-term peak SO2 concentrations," EPAsaid on its web site.

"The one-hour compliance is a big concern," said Solvair business manager Michael Wood."When such a short time windowexists, it makes a lot of over-design needed in order to assure there are no out of compliance events."

The concern over short-term exposure has also prompted EPAto change data reporting requirements to include reporting

the highest five-minute average from each hour. While there is no limit on the five-minute average, the reporting is being

done to collect additional data so EPAcan further studythe health impacts of short-term exposure to high concentrations

of SO2 based on official data from their monitoring network.

Consequently, short-term SO2 concentrations have become a focal point for utilities. Adding to the newchallenge is the

fact that a measurement can be conducted during a plant's start-up or shut-down at the Agency's discretion, Byers said.

"UsuallySO2 control isn't operating at its fullest efficiencyduring start-up or shut-down," Byers said."Therefore, there might be more SO2 released during start up or shut down."

For example, a typical SO2 control system might reduce SO2 by98 percent, Byers said.However, during start-up or shutdown, the technologymight operate at onlyhalf the efficiency.

As a result of the new measurements, EPAis "expecting an increase in the number of non-attainment areas," said Barney Racine, software development manager atHoneywell Process Solutions. SO2 NAAQSis a five-year program, so itwill

take time to "trickle down to the individual facilities."

Racine said that SO2 NAAQSwill likelyhave a positive impact on scrubber technologydemand. After one-hour ambient measurements are collected, EPAcan focus on identifying which facilities nearbymaybe contributing to an exceedance of

the standard,which ultimatelymayresult in requirements for still more emissions control installations.

"If a plant emits a lot of SO2 during start-up and it affects the non-attainment status, that means someone who doesn't

have a scrubber on nowbut has high SO2 emissions during start-up and shut-down mayneed to install scrubber

technology."

MATS: SO2 as Surrogate

One of the biggest overarching concerns for power generators is the recentlyfinalized Mercuryand Air Toxics Standard, EPA's first mandate in U.S. historyto limit mercuryemissions from coal-fired units. The rule will also curtail a number of

hazardous air pollutants (HAPs), including lead, arsenic, hydrogen chloride, hydrogen fluoride and dioxins/furans. MATS

control will require the power industryto reach compliance by2015. Since SO2 is a surrogate for HAPs, MATScould also

introduce or reinforce a push toward SO2 control installation.

MATSis EPA's replacement for the Clean Air MercuryRule (CAMR), an interstate cap-and-trade program issued in 2005. EPAestimates that MATSwill reduce mercuryemissions from covered power plants by91 percent, acid gas emissions by

91 percent and SO2 emissions by55 percent.

While MATSdoes not limit SO2 emissions directly, it provides an alternative wherein plants can meet an SO2 standard in

place of the hydrogen chloride (HCl) limit. Plants can opt to meet the 0.2 lbs. of SO2 per million Btu instead of installing HCl monitoring technology.

In other words, there will be some allowances in MATSfor plants that have alreadyinstalled or are installing SO2 control,

said Byers.

BART

Best Available Retrofit Technology(BART) guidelines under the Clean Air VisibilityRule will also take a toll on SO2

emissions (as well as NOx, ammonia and certain volatile organic compounds), affecting facilities built or reconstructed

between Aug. 7, 1962, and Aug. 7, 1977, that have the potential to emit more than 250 tons a year of emissions and fall

into one of 26 different categories, including power plants. The EPA's presumptive BARTemission limit for SO2 is 0.15

lb/mmBtu, or 95 percent removal.

Hitachi's wet scrubber technologywas recentlyinstalled at the 1,005 MW

Coffeen power station, operated byAmeren, near Coffeen, Ill. Photo

courtesyHitachi

After an extensive lawsuit against the Regional Haze rule, Public Service Co. ofOklahoma (PSO) recentlydecided to retire

two of its coal-fired units atNortheastern Station inOolagah,Okla.Under an agreementwith the EPA, Sierra Club and the

state, PSOhas agreed to meet specified emissions rates at both Northeastern coal units, install certain emissions

control equipment on one of the Northeastern coal units in 2015 and retire the other unit in 2016. The coal unitwith the

emissions controls would be retired in the 2025 to 2026 timeframe. The agreement also will result in PSOwithdrawing its

lawsuit against the EPAregarding the Regional Haze rule.

Control Technologies

Two basic methods exist for controlling SO2 emissions from coal-fired power plants: switching to a lower sulfur fuel or

implementing SO2 control technologies. Switching to a lower sulfur coal can be a fairlysimple undertaking.Certain coal

types inherentlylowin sulfur, such as sub-bituminous coal from the PRBof Montana and Wyoming, can sometimes bring SO2 emissions within acceptable limits.However, some plants cannot burn 100 percent PRBcoal without substantial modifications to the boiler or fuel-handling systems. In these cases, PRBcoal can be blended with a bituminous coal to

reduce emissions.

If a facilityis unable to burn a lower sulfur coal or needs to achieve lower SO2 levels than is possible through a fuel

switch, emissions reductions technologyshould be implemented. When it comes to SO2 control technologies, a number

of products have been on the market for decades, including dryscrubber,wet scrubbers and drysorbent injection (DSI).

In the case of a typical wet scrubber, flue gas coming from the boiler is saturated with a slurrycontaining limestone

reagent. This type of SO2 control is characterized byhigh capital cost, lowoperating cost and high performance.

Dryscrubber processes inject particles of alkaline sorbent into the flue gas, producing a drysolid by-product. The flue gas

leaving the absorber is not saturated in this process.Dryscrubber costs have gone down in recent years due to technical

innovations.Dryscrubber systems can be grouped into three categories: spraydryers, circulating spraydryers and dry

injection systems. The circulating dryscrubber (CDS) technologyoperates at similar temperatures, but is based on

separatelyfeeding dryhydrated lime and water into a fluidized bed reactor.Here the SO2 removal takes place in a bed of moistened powder.

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DSI involves injecting a reagent in drypowdered form (hydrated lime, sodium bicarbonate or trona) into the flue gas

upstream of existing particulate control equipment.DSI is praised for its simplicityand lowcapital costs, but is limited in

performance and requires reagent injection rates above stoichiometrythat are often necessaryfor removal efficiencies.

Hitachi recentlycompleted a scrubber installation at the Amerenoperated Coffeen power plant in Illinois. Photo courtesyHitachi

Jonas Klingspor, vice president of business development and marketing for URS, said one potential concern for using DSI systems with trona is the disposal of the product."Unless you have a double-lined, capped landfill, the water soluble

byproduct maybe a serious concern."

Solvair is one of the manycompanies on the market currentlyoffering DSI solutions."DSI is a lowcapital cost system

which is attractive to utilities," said Wood.

Hitachi, on the other hand, is predicting a big demand for circulating dryscrubbers, said RobertNicolo, director of air

qualityfor Hitachi Power Systems America.Nicolo said EPAregulations such as the Cooling Water Intake Structures Rule

(316(b)) and Coal Combustion Residuals will partiallydetermine whether a utilitydecides to retrofit using wet or dry

scrubbers.

Hitachi's newest product, the Enhanced All-Dry(EAD) scrubber technology, is being jointlydeveloped with Solios Environnement Inc. The technologyis actuallythe original circulating semi-dryscrubber technologythatwas developed by Solios in the ‘80s.Hitachi is applying the EADscrubber with a modular approach that enables enhanced scrubber

capacity, virtuallyunlimited turndown and enhanced system layout flexibility. The technologyalso boasts lowcapital cost,

lowwater consumption and drybyproducts. In addition to SO2 removal, the technologyalso captures HCl, mercuryand

particulate matter from flue gas.

MarsulexEnvironmental Technologies (MET) has seen interest in its Circulating Fluid Bed dryscrubber, or CFB-FGD, said AmyEvans, director of technology.CFB-FGDprovides high levels of SO2,HCl and SO3 emission control byinjecting

hydrated lime in the presence ofwater. The decoupling of the lime and water injection provides SO2 removal upwards of

98 percent.High lime utilization is achieved byrecycling the majorityof bed material collected in the downstream fabric

filter back into the fluid bed. In addition to the dryscrubbing technologies, METalso offers a wet scrubber, but the company

has seen more interest in the drytechnology, Evans said.

Out with the Old...or Not?

Manyolder coal-fired power plants alreadyhave some sort of SO2 control installed, but in light of the stringent newEPA

requirements, theyare looking to either upgrade the technologyor install an entirelynewsystem.

METis one of manycompanies currentlyconducting wet scrubber upgrades. Mike Walsh, vice president of engineering,

said that for scrubbers that are about 30 years old, an upgrade can cost significantlyless than a newsystem.However, he

said, manyolder scrubbers actuallyentail multiple vessels,whereas modern scrubber models onlyentail onlyone vessel

per boiler."The reliabilityand overall design have improved dramaticallyover the last 25 years," Walsh said.

Arecentlycompleted FGDupgrade byURS. Photo courtesyURS

URS,which has conducted more than 52,000 MWworth of scrubber upgrades, is currentlyundergoing a number of such

projects. Klingspor said a scrubber upgrade is typicallyabout one-third or less the cost of a newscrubber.

URSis nowin the middle of an expansive upgrade project atHoosier Energy's 1,000 MWMerom Generating Station. The

upgrade will increase the plant's SO2 removal from 90 percent to 98 percentwhile lowering the FGDsystem pressure

drop, Klingspor said.

AURSupgrade was recentlycompleted at South Mississippi Electric Power Association's R.D. Morrow, Sr.Generating Plant."We were able to upgrade the scrubber so that the plant SO2 removal was increased from about 50 percent to 98

percent SO2 removal without installing newscrubbers," Klingspor said.

While hundreds of upgrade or retrofit options exist, most utilities are still hesitant to dive full-in to a control plan for SO2

prior to the final, undisputed release ofCSAPR."Alot of utilities are making plans, but no one is going to kick off a project

until theysee a final rule," Walsh said.

Fortunately, the final version of the rule is expected to be less stringent than the proposed version,which could allowfor a wider selection of options. Klingspor said that in light of the onslaught of EPAregulations,URShas seen a fewproject

upgrade cancellations for smaller, older plants that have been retired instead of upgraded."Utilities are still facing

uncertainty. With gas prices below$2 [at time of interview], manyare being shut down or idled."

For now, utilities must choose whether upgrading or installing a newtechnologyis right for them.Regulatorycompliance

is not onlyessential for SO2 emissions, but also for the multitude of other emissions types addressed through EPA

regulations.However, in the midst of a season in which drastic changes are required, SO2 and other control options are

readilyavailable to address everycompliance issue.

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