GER-4192 - Combustion Modification: An Economic ... · Reburn and AGR. The combustion process is divided into three zones. In the Burner Zone the main fuel is burned with combustion

GE Power Systems

CombustionModification – AnEconomic Alternativefor Boiler NOx Control

Blair A. FolsomThomas J. TysonGE Power SystemsSchenectady, NY

GER-4192

g

Contents

Abstract . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Regulatory Drivers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Reburn and Advanced Reburn. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Comparative Economics of SIP Call Compliance with Combustion Modification and SCR . 8

No NOx Trading Scenario – Control to 0.15 lb/10 6 Btu . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9NOx Trading Scenario. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Dense Pack Steam Turbine Uprate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Integrated System (AGR-DP) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18References. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20List of Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Combustion Modification – An Economic Alternative for Boiler NOx Control

GE Power Systems ■ GER-4192 ■ (04/01) i

GE Power Systems ■ GER-4192 ■ (04/01) ii


AbstractSeveral provisions of the Clean Air ActAmendments of 1990 will require “deep” NOxcontrol on a large number of large utility andindustrial boilers in the eastern United States.EPA’s final ruling on Section 126 petitions filedby several northeastern states (December 1999)and the more recent revival of the “NOx SIPCall” both include provisions for trading ofNOx credits and state-wide NOx budgets thatare based on emissions of 0.15 lb/106 Btu ofheat input.

Selective Catalytic Reduction (SCR) andCombustion Modification using Reburn orAdvanced Reburn are the only commerciallyviable alternatives capable of reducing NOx tothis level. Although the optimum cost effectiveapproach for any given unit will depend on sitespecific factors, the general trend is expected tobe towards SCR as the technology of choice forthe larger, higher baseline NOx units and forCombustion Modification (with Reburn orAdvanced Reburn) for smaller units or unitswith lower baseline NOx emissions.

Reburn is a commercially proven control tech-nology that can reduce NOx by as much as 60%by the staging of fuel and air within the furnace.The level of NOx reduction can be increased toover 70% by integrating a “trim” Selective Non-Catalytic Reduction system with the basicReburn system (the integrated system isreferred to as Advanced Reburn). Althoughboth Reburn and Advanced Reburn systems canutilize a wide range of fuels, natural gas gener-ally produces the deepest NOx control.

By integrating Advanced Reburn using naturalgas as the reburn fuel (Advanced Gas Reburn)with Dense Pack steam turbine technology,deep NOx control can be achieved along withadditional power generating capacity and heatrate improvement. The economics of this inte-grated approach are particularly attractive.

IntroductionThis paper presents an overview of compliancealternatives for U.S. coal-fired utility boilers fac-ing requirements for deep NOx control underTitle I (Attainment of National Ambient AirQuality Standards for ozone) of the Clean AirAct Amendments of 1990. The focus is on theperformance and economic tradeoffs betweenCombustion Modification, using Reburn andAdvanced Reburn, and Selective CatalyticReduction (SCR). The regulations and implica-tions for NOx reduction requirements are dis-cussed first. Then, the Reburn and AdvancedReburn technologies are presented includingdesign factors and performance experience oncoal-fired utility applications. The economictradeoffs between Combustion Modificationand SCR alternatives are then addressed forboth emissions trading and non-trading scenar-ios. Finally, the integration of Advanced GasReburn with GE’s Dense Pack steam turbinetechnology is discussed including an overviewof the technology and the economic benefitsfor deep NOx control applications.

Regulatory DriversThe NOx emissions from many U.S. coal-firedutility boilers must be reduced due to severalrecent and ongoing regulatory actions underthe Clean Air Act of 1990 designed to achieveattainment of the ambient air quality standardsfor ozone. In September 1998, the EPA issueda ruling regarding NOx emissions from a 22State region in the eastern U.S. that were con-tributing to ozone levels exceeding the nationalambient air quality during a five month summerperiod (the ozone season). The EPA establishedreduced NOx budgets for each state in theregion and required them to submit stateImplementation Plans (the “NOx SIP Call”)wherein NOx emissions would be reduced tomeet those NOx budgets. The NOx budgets


GE Power Systems ■ GER-4192 ■ (04/01) 1

were prepared assuming that NOx emissionsfrom utility power plants as a group would aver-age 0.15 lb/106 Btu (SIP Call NOx Level) in2007.

In May 1999, the U.S. Court of Appealsreviewed the SIP Call and indefinitely suspend-ed EPA’s implementation schedule. Morerecently (March 2000), the court removed thissuspension of the NOx SIP Call and confirmedits provisions but reduced the 22-state region to19 states.

In the midst of this NOx SIP Call activity, EPAalso implemented other provisions (Section126) of the Clean Air Act that require compara-ble ozone season emission reductions fromabout 400 industrial and utility plants within thesame region. There are also several other areasin the U.S. with local ambient ozone problems,such as Atlanta and Texas, that are implement-ing additional NOx control regulations.

These ozone season regulations typicallyinclude the potential for emissions tradingamong affected units. With emission trading, itis not necessary to control each unit to meet thespecific NOx emission limit. Plant owners havethe flexibility to over-control some units wheresite specific factors reduce the NOx control costand to use the extra NOx reduction (below theNOx emission limit) to offset higher NOx onother units where deep NOx control may beparticularly expensive.

While the final requirements and implementa-tion schedules may well be resolved in thecourts, it is clear that a large number of coal-fired utility boilers will need deep NOx emis-sion control to near the SIP Call NOx level inthe next few years to meet these ozone seasonNOx regulations.

Annual NOx emission control is requiredunder Title IV of the Clean Air Act of 1990 for

acid rain mitigation. The Title IV NOx reduc-tion requirements were established by EPAbased on the capabilities of “Low NOx BurnerTechnology” and are not as stringent as Title I.Table 1 lists the Title IV target NOx levels forboilers by firing configuration.

Firing

Configuration Title IV NOx (lb/106 Btu)

Tangential 0.40

Wall 0.46

Cell 0.68

Cyclone 0.86

Title IV allows intra-utility trading and requirescompliance in 2000 on an annual average basis.Since the compliance dates for the Title I NOxregulations discussed above are in the 2003-2005 time frame, plant owners must provideadditional control beyond the Title IV targetlevels over a 3-5 year period to meet the ozoneseason NOx regulations.

Figure 1 shows the NOx reduction required toachieve 0.15 and 0.20 lb/106 Btu as a functionof the initial NOx level, presumably the levelrequired for compliance with Title IV. Thenominal maximum NOx reduction capabilitiesof Reburn, Advanced Reburn and SelectiveCatalytic Reduction (SCR) are overlaid.

The NOx control capability of SCR can beadjusted by varying the volume of the catalystand/or rate of ammonia injection. NOx reduc-tions as high as 90% are achievable. This is suf-ficient to reduce baseline NOx from as high as1.50 lb/106 Btu to the SIP Call NOx Level andthus covers the full range of Title IV baselinelevels.



Table 1. Title IV target NOx levels

As will be discussed in Figure 1, CombustionModification via Reburn and Advanced Reburncan typically achieve NOx reductions of 60%and greater than 70%, respectively. This is suf-ficient to meet the SIP Call NOx Level frombaselines as high as 0.55 lb/106 Btu. Thus, tan-gential and wall-fired units operating at theTitle IV target levels of 0.40 and 0.46 lb/106

Btu, respectively, can use CombustionModification to meet the SIP Call NOx limit.

Also, cell burner units, where site specific fac-tors allow low NOx burners to control NOxbelow the Title IV target level to 0.55, may alsouse Combustion Modification.

Reburn and Advanced ReburnReburn and Advanced Reburn are combustionmodification NOx control technologies.Reburn integrates fuel and air staging tech-niques and has been applied commercially to abroad range of coal-fired utility boilers. Table 2shows GE EER’s experience to date.

Any hydrocarbon fuel can be used to providethe staged fuel for Reburn. Most Reburn instal-lations to date have utilized natural gas as theReburn fuel (Gas Reburn) since it provides thegreatest NOx reduction and lowest retrofit cost.With Gas Reburn, NOx emissions are typicallyreduced by about 60% [References 1-3].

Advanced Gas Reburn (AGR) is the integrationof Gas Reburn with injection of a nitrogen con-taining NOx reduction agent (N-Agent) such asurea or ammonia. This can be accomplished ina number of configurations which may beselected based on site specific conditions[References 4-7].



x

Figure 1. NOx reduction required to achieve SIP callNOx limit from Title IV target NOx levels

Table 2. GE EER reburn experience on utility boiler

NOx at Title 4 Compliance (lb/106 Btu)

Kodak Park 15

Figure 2 is a schematic representation of GasReburn and AGR. The combustion process isdivided into three zones. In the Burner Zonethe main fuel is burned with combustion air.Although no changes to the main burners arerequired, it is generally cost-effective to replacethe existing burners with low NOx burners ormodify them to achieve comparable low NOxperformance for additional NOx reduction.The main burners are turned down to accom-modate the subsequent injection of the Reburnfuel (natural gas for Gas Reburn) and are oper-ated at the lowest excess air commensurate withsatisfactory lower furnace performance consid-ering flame stability, flame shape, combustionefficiency and ash deposition. The reburn fuelis injected downstream of the flames. Thereburn fuel injection system is designed to pro-duce locally fuel rich zones operating at approx-imately 90% theoretical air (TA) which is opti-mum for NOx reduction. The NOx reductionincreases with the reburn fuel injection rate.For low injection rates, the reburn fuel is strati-fied to produce locally fuel rich zones. As thereburn fuel injection rate is increased, theselocally fuel rich zones eventually merge to coverthe entire furnace cross-section. Overfire air is

injected to complete the combustion of fuelfragments exiting the reburn zone. The overfireair injection system is designed for variableinjection to optimize mixing of the overfire airwith the furnace gases as the reburn fuel injec-tion rate is varied.

Advanced Gas Reburn adds a trim NOx reduc-tion via injection of a N-Agent. The N-Agent canbe injected in a number of configurationsincluding: downstream of the overfire air, withthe overfire air, and into the reburn zone. Sitespecific factors determine the optimum injec-tion configuration. Injection downstream of theoverfire is equivalent to the Selective Non-Catalytic Reduction (SNCR) process. This is acommercial process offered by several vendorsusing ammonia and urea as the N-Agents.

Reburn and Advanced Reburn can be appliedto boilers with all firing configurations. As anexample, Figure 3 shows the applicationAdvanced Gas Reburn to a front wall fired utili-ty boiler. The main burners can be convention-al or low NOx burners and the flames fromthese burners are in the Burner Zone. Thereburn fuel injectors are positioned on the fur-nace walls above the top row of main burners.



Figure 2. Schematic diagram of reburn and advanced reburn

The specific reburn fuel injection elevation isselected to be close to the burners where tem-perature is high, but displaced enough so thatthe combustion in the flames is essentially com-plete. GE EER utilizes second generation gasinjectors for Gas Reburn systems to convert thepressure in the natural gas supply line to highinjection velocity. The injector arrangement isoptimized based on site specific factors to pro-duce optimum mixing over the full operatingrange of the boiler and with variable natural gasinjection rates. This generally involves multipleinjectors grouped in several tubewall penetra-tions. The Reburn Zone extends from the gasinjectors to the overfire air ports which arehigher in the furnace.

The elevation of the overfire air ports is select-ed by balancing the need for residence time inthe Reburn Zone with completion of combus-tion prior to the convective pass. This generallyresults in positioning the overfire air ports nearthe nose of the furnace. GE EER uses a dualconcentric overfire air port design with variableswirl. This allows the overfire air injection veloc-ity to be varied independent of the injection

flow rate so that optimum mixing can be main-tained as the reburn gas injection rate (andhence overfire air injection rate) and load vary.The burnout zone is the region between theoverfire air ports and the convective pass.

Figure 3 shows N-Agent injectors above the over-fire air ports to complete the Advanced GasReburn process.

GE EER has developed a design methodologyfor applying Reburn and Advanced Reburn. Ituses physical flow and Computational FluidDynamic (CFD) modeling along with heattransfer and chemical kinetic codes in the con-text of GE EER’s extensive database on pilotand full-scale Reburn applications to optimizethe design for site specific factors.

Figure 4 shows the NOx reduction achieved withseveral commercial Reburn systems on coalfired utility boilers. These applications repre-sent a broad range of unit and fuel characteris-tics: wall, tangential and cyclone firing; coaland gas as the main and Reburn fuels; baselineNOx ranging from 0.13 to 2.0 lb/106 Btu; andunit capacities from 40 to 330 MW. (A 600 MWGas Reburn system is being installed in Spring2000.) The NOx reductions for all units in thefigure exceed 60% with some substantially high-er.

For maximum NOx reduction and minimumNH3 slip from the SNCR component, the N-Agent must be injected so that it is available forreaction with the furnace gases within a tem-perature window close to 1800°F. This typicallyrequires multiple N-Agent injection elevationsin the upper furnace and/or convective pass toaccommodate varying load and ash depositionpatterns over the sootblowing cycle. However, ifthe NOx reduction requirement is reduced, amuch simpler SNCR system can be employed.In conjunction with Elkraft Power Company ofDenmark, GE EER has applied this simplified



Reburn Fuel

Main Fuel

Combustion Air

Nitrogen Agent

Overfire Air

Reburn Fuel

Main Fuel

Combustion Air

Nitrogen Agent

Overfire Air

Figure 3. Advanced reburn on a wall-fired boiler

SNCR concept to a 285 MW utility boiler[Reference 8]. Figure 5 shows the NOx reduc-tion and ammonia (NH3) slip for injection ofurea through a single elevation for two loads.At 46% load, the urea is injected at near opti-mum temperature so that NOx reduction ismaximized with low NH3 slip. At full load, thesame injection location achieves less NOxreduction and NH3 slip is higher. The 30%

NOx reduction level corresponds to nitrogenstoichiometric ratio (NSR) of 0.5 to 0.7 andresults in NH3 slip well under 2 ppm. NH3 slipof 2 ppm or less avoids air heater plugging withhigh sulfur coals.

With AGR, the NOx reduction is produced bytwo components: Gas Reburn and SNCR. Thisprovides the opportunity to adjust the relativecontribution of the two components to opti-mize performance. Figure 6 illustrates thesetradeoffs for NOx reduction to the SIP CallNOx level for wall and tangentially fired unitsoperating with low NOx burners at the Title IVtarget levels of 0.46 and 0.40 lb/106 Btu, respec-tively. For example, for the wall fired unit NOxmust be reduced by 67% reduction to meet 0.15lb/106 Btu. This can be achieved with the GasReburn component at 53% reduction and theSNCR component at 30% reduction, respec-tively, both conservative levels for the respectivetechnologies. The modest NOx reduction fromthe Gas Reburn component allows the reburnfuel injection rate to be lowered which reducesoperating cost. The modest level of NOx reduc-tion from SNCR can be achieved with a much



Figure 4. NOx control results from GE EER reburn applications on utility boilers

Figure 5. NOx reduction and NH3 slip for SNCR on 285MW utility boiler

simpler system than the conventional highlytuned SNCR system and with reduced risk ofNH3 slip (and air heater plugging).

Figure 7 shows the cumulative NOx reductionachievable by layering combustion modificationNOx control technologies on a typical wall-firedboiler. Low NOx burners provide the initial50% reduction from 0.92 lb/106 Btu down tothe Title IV target level of 0.46 lb/106 Btu. GasReburn reduces NOx by an additional 53 to60% depending on the reburn fuel flow of 13 to16%, respectively. Adding SNCR (AGR) reducesNOx further to less than 0.15 lb/106 Btu. The0.12 lb/106 Btu point corresponds to 16%reburn fuel and 33% NOx reduction fromSNCR. The 0.15 lb/106 Btu point correspondsto 13% reburn fuel with 30% NOx reductionfrom SNCR. Figure 8 shows these same points ascircles on a plot of NOx vs. gas injection rate tobetter illustrate the tradeoffs.

The preceding discussion focused on AGR withthe N-Agent injection downstream of thereburn overfire air. A number of other config-urations are under development includinginjection with the overfire air, into the reburn

zone and multiple stages of N-Agent injection[References 6-7]. These alternate configurationsprovide retrofit flexibility and by optimizing thecoupling the N-Agent injection with the Reburnsystem, NOx reduction is synergisticallyenhanced.



Figure 6. Advanced Reburn tradeoffs for SIP Call compliance: Reburn and SNCR components

Figure 7. Cumulative NOx for layered combustionmodification technologies

Comparative Economics of SIP CallCompliance with CombustionModification and SCRA comparative economic analysis of Reburnand Advanced Reburn (using coal, oil and nat-ural gas as Reburn fuels) and overfire air (OFA)with SCR has been conducted. OFA was includ-ed with SCR since it results in a slightly lowernet NOx control cost compared to SCR alone

by reducing catalyst volume. Table 3 lists theparameters for each NOx control technology;the key parameters are highlighted below. Theratio of reburn NOx reduction to reburn fuelflow is the Reburn Efficiency Factor (REF).Based on EER's full scale experience, the REFwas approximated as 5.0 and 3.0 for less thanand greater than 30% NOx reduction, respec-tively. Maximum Reburn and Advanced ReburnNOx reductions were capped at 60 and 73%respectively corresponding to a maximum of33% NOx reduction from the SNCR compo-nent. For SCR, the catalyst cost and lifewas based on the work of Cichanowicz [Refer-ence 9].

The analysis utilized a modified Electric PowerResearch Institute (EPRI) TechnologyAssessment Guide methodology which has beenwidely used to compare the economics of emis-sion control alternatives. This involves deter-mining the total annual cost of NOx control in$/ton. The retrofit capital cost is estimated andthen distributed over the life of the equipmentas a series of constant annual costs. The firstyear operating cost is also estimated and con-verted to a series of annual costs accounting for



Figure 8. Effect of gas firing rate on reburn andadvanced reburn NOx

Table 3. NOx control technologies in economic analysis

Title IV Wall-FiredLow NOx Burner Baseline

inflation, etc. These two annual cost compo-nents are then added and divided by the annu-al NOx reduction to calculate the total cost ofNOx control in $/ton. Table 4 shows the eco-nomic factors and other parameters used in theanalysis.

Two scenarios were evaluated: No trading andfull inter-utility trading.

No NOx Trading Scenario – Control to 0.15 Lb/106 Btu This “no trading” scenario involves comparisonof the NOx control costs to meet 0.15 lb/106

Btu for each technology. The following vari-ables were evaluated. (See Table 5.)

Parameter Range Units

Baseline NOx 0.25 – 1.6 Lb/106 Btu

Boiler Capacity 50 - 1,300 MW

Reburn Fuel Cost 0.00 - 1.50 $/106 Btu over coal

SCR Installed Cost 40 - 80 $/kw for 300 MW

Figures 9 and 10 show the results for a 300 MWunit with NOx reduced from a variable initial

level to 0.15 lb/106 Btu. Figure 9 shows Reburnand Advanced Reburn using coal, oil and gas asthe reburn fuels with variable reburn fuel tocoal cost differential. Figure 10 shows the Figure9 Reburn and Advanced results as an outlineand adds OFA-SCR with variable SCR cost.

In Figure 9, the maximum NOx reduction forReburn has been set at 60%, a conservative level

based on full-scale utility boiler experience. ForAdvanced Reburn, the maximum NOx reduc-tion has been set at 73% which corresponds to33% reduction from the Reburn level. Based onthese reductions, to achieve 0.15 lb/106 Btu,the maximum initial NOx is 0.38 and 0.55lb/106 Btu, respectively. For all Reburn andAdvanced Reburn configurations, the cost ofNOx control decreases as the initial NOxincreases.

The reburn fuels include coal and oil with dif-ferential costs over coal of $0.00 and $0.50/106

Btu, respectively, and natural gas with differen-tial costs over coal of $1.00 and $1.50/106 Btu.For both Reburn and Advanced Reburn, thedifferential cost of the reburn fuel over themain coal fuel is the key variable influencing



Table 4. Economic analysis parameters Figure 9. NOx control cost for Reburn andAdvanced Reburn to 0.15 lb/106 Btu –effect of initial NOx

Table 5. NOx control costs per variable

the total cost of NOx reduction. For the initialNOx range where Reburn can be applied,Reburn is lower in cost than Advanced Reburnexcept at the highest reburn fuel cost differen-tial (natural gas at $1.50 /106 Btu). For higherinitial NOx, the NOx control cost of AdvancedReburn continues to decrease down into thesame $/ton range as Reburn.

In Figure 10, the full range of the Reburn andAdvanced Reburn results from Figure 9 areshown as an enclosed region. It should be notedthat this includes all reburn fuels with reburnfuel to coal cost differentials ranging from 0.00to $1.50/106 Btu. OFA-SCR results are shownfor SCR capital costs ranging from $40 to$80/KW. The center of the range ($60/KW)corresponds to a straightforward application(Nominal). The low end of the range($40/KW) corresponds to an advanced low costfuture SCR application. The high end of therange ($80/KW) represents an increase fromNominal but is by no means the maximum.Several utilities have recently been quoted SCRsystems at well over $100/KW. The NOx controlcosts for all of the SCR cases are higher than thehighest Reburn and Advanced Reburn results atthe same initial NOx. The differences are sub-

stantial. For example at an initial NOx of 0.40lb/106 Btu, the highest cost for AdvancedReburn is 68% of the cost for the Nominal SCRcase.

As with Reburn and Advanced Reburn, theNOx control cost for SCR decreases as the ini-tial NOx increases. Thus, for high initial NOx,such as from a cell or cyclone unit, the NOxcontrol cost for SCR drops into the $/ton rangefor Reburn and Advanced Reburn at lower ini-tial NOx.

All of the preceding results were for a 300 MWunit. Similar analyses were conducted for arange of unit capacities from 50 to 1300 MW.Since the capital cost of the OFA-SCR systems issubstantially greater than the Reburn andAdvanced Reburn systems, the capacity effect isgreater for OFA-SCR. At high capacity, the costsfor OFA-SCR approach those for Reburn andAdvanced Reburn.

In summary, for control to 0.15 lb/106 Btu, theselection of the lowest cost technology dependson the initial NOx. For initial NOx less thanabout 0.55 lb/106 Btu, Reburn and AdvancedReburn have lower cost than OFA-SCR. For ini-tial NOx greater than 0.55 lb/106 Btu, Reburnand Advanced Reburn cannot meet the require-ment and OFA-SCR must be used with $/toncost approaching or lower than those of Reburnand Advanced Reburn, especially for the largehigh baseline NOx units.

NOx Trading Scenario The preceding analysis showed that two keyboiler variables, initial NOx and boiler capacityhave significant effects on the NOx control costwith the cost decreasing as both initial NOx andboiler capacity increase. This suggests thepotential for reducing total NOx control cost byover-controlling on the large, high initialNOxunits (where $/ton costs are low) andunder controlling on the other units. It is



Figure 10. NOx control cost for all technologies to0.15 lb/106 Btu – effect of initial NOx

expected that the final ozone related NOx reg-ulations will allow emission trading similar tothe Title IV SO2 allowance trading system whereSO2 prices are established by market forces on a$/ton basis. Of course, there is potential formore complex trading structures which maylimit trading to specific geographical areas ormake a ton of NOx in one region equivalent toa different amount in another region.

The cost of NOx allowances available on theopen market has a significant impact on theselection of the lowest cost NOx controlapproach. An analysis has been conducted toevaluate the economic tradeoffs of such trad-ing. Table 6 lists the parameters used in theanalysis. The objective is to determine the low-est cost NOx control strategy for a 300 MW tan-gentially fired boiler operating at the Title IVNOx limit of 0.40 lb/106 Btu to reach 0.15lb/106 Btu via emission control and/or pur-chased allowances. Four alternatives are consid-ered:

■ Do Nothing. In this case the requiredNOx allowances are purchased on theopen market.

■ Gas Reburn. Gas Reburn can beapplied to reduce NOx by 60% to 0.16lb/106 Btu, just slightly above the 0.15lb/106 Btu level. This requirespurchasing a small amount of NOxemission allowances on the openmarket.

■ Advanced Reburn. Advanced Reburncan be applied to reduce NOx by 73%to 0.11 lb/106 Btu, which is below the0.15 lb/106 Btu level. The excess NOxreduction is sold as NOx allowanceson the open market.

■ SCR. An SCR system is installed toreduce NOx by 80% to 0.08 lb/106

Btu, well below the 0.15 lb/106 Btu

level. The excess NOx reduction issold as NOx allowances on the openmarket.

The results are shown in Figure 11 where thetotal annual cost of NOx control is plotted as afunction of the NOx allowance trading price foreach control approach. Lines which slopeupward as NOx emission allowance tradingprice increases correspond to under-controland vice versa.



Ann

ual N

O C

ontr

ol C

ost (

$10

/Yea

r)x

6

Figure 11. NOx control cost for trading, 300 MW wall-fired boiler, initial NOx 0.40 lb/106 Btu

Unit Capacity (MW) 300

Firing Configuration Tang.

Title 4 NOx lb/106 Btu 0.40Ozone Season Cap. Fac. (%) 65

SO2 Allow. Price (%/ton) 200

Life (Years) 15

Interest Rate (%) 8

Dollars Con.

Adv.Technology Reburn Reburn SCR

Capital Cost ($/kW) 10 22 50

NOx Reduction (%) 50 72 80

Reburn Fuel - Coal ($/106 Btu) 1.00 1.00

Catalyst Life (Years) 4

Table 6. Trading analysis parameters

For low NOx allowance trading price (less thanabout $1,900/ton), the lowest cost approach isto Do Nothing and simply purchase all requiredNOx allowances. At high NOx emissionallowance trading price (greater than about4,000 $/ton), the lowest cost approach is tomassively over-control with SCR and sell theextra NOx allowances at the high price. Forintermediate NOx emission allowance tradingprices ($1,900 to $4,000/ton) Reburn andAdvanced Reburn are the lowest cost approach-es. Thus the market price for NOx allowances isa key factor affecting both the selection of thelowest cost approach and the total cost of NOxcontrol.

An analysis has been conducted to estimate theNOx allowance market price in a free trade sce-nario. In such a scenario, each utility will con-duct its own analysis of applicable NOx controltechnologies, estimate risks and project a NOxallowance price. To simulate this, GE EER hasconducted a systematic analysis of all coal firedutility boilers in the SIP Call region. These unitswere grouped into categories based on their ini-tial NOx and capacity and an analysis similar tothat outlined above was conducted for eachcombination of initial NOx and capacity. Thelowest cost NOx control approach was identi-fied as a function of the NOx allowance tradingprice. Then, the NOx credit allowance price wasiterated while monitoring the total NOxallowances bought and sold. At low NOxallowance trading price, the purchases exceed-ed the sales and the NOx allowance tradingprice was iterated upwards. This process wascontinued until the amount of purchases andsales balanced. This analysis was then repeatedfor a range of parameters such as cost of reburnfuel, future cost reductions in SCR, etc.

The results showed that for a broad range of

parameters, the NOx allowances should tradein the range of $2,000 to $3,000/ton. Thus, inthe case presented above (300 MW tangentiallyfired unit), Reburn and Advanced Reburn willbe the technology of choice. The results alsoshowed that the NOx control market will beshared between Reburn, Advanced Reburn andSCR with the distribution depending on sitespecific factors. Generally, SCR is favored forlarge high baseline NOx units and Reburn andAdvanced Reburn are favored for units with ini-tial NOx typical of the dry bottom wall and tan-gentially fired units with penetration increasingas unit capacity decreases.

Dense Pack Steam Turbine UprateDense Pack is a retrofit steam turbine modifica-tion technology developed by GE PowerSystems to increase the efficiency and powergenerating capacity of utility steam turbines.Dense Pack is custom designed for each turbineto achieve the most efficient steam path in theexisting turbine section outer shell. This highefficiency steam path produces a lower heat rateand increased output for the same steam flow.The maintenance requirements of the steamturbine are also reduced due to decreasedbucket and nozzle solidity and reduced rotordiameters which reduce solid particle erosionwith internal repair/inspection intervalsextended to ten or more years.

Dense Pack is the latest evolution of GE steamturbine designs that began in 1903. Figure 12shows the improvement in high pressure steampath efficiency achieved over the last 40 years.High pressure section efficiency is now in the94–95% range. This improvement was the resultof a systematic analysis of steam turbine per-formance to identify the sources of inefficiencyfollowed by development of improvement forthe critical components.



Figure 13 shows the loss (irreversibility) compo-nents for a typical steam turbine (GE G3Turbine with 700 MW capacity). Except for theloss due to the condenser, the high pressure tur-bine section contributes the greatest irre-versibility and was the focus of the improve-ments. Figure 14 shows the efficiency losses with-in the high pressure section. Nozzle and bucketaerodynamic profile losses, secondary flow loss-es, and leakage losses account for roughly 80%to 90% of the total stage losses. Hence, toensure high-efficiency turbine designs, it is nec-essary to use highly efficient nozzle and bucketprofiles and to minimize leakage flows withoutsacrificing turbine reliability.

Dense Pack replaces steam turbine internal

components to provide the most efficient steampath that will fit within an existing outer turbineshell. In short, the Dense Pack replaces theexisting turbine stages with a larger number ofstages in the same space. A Dense Pack sectionreplacement includes the following eight basiccomponents and features:

1. New, high efficiency, high pressure orhigh pressure / intermediate pressureturbine rotor with increased numberof stages

2. Optimized steam path diameter

3. New, high efficiency diaphragms

4. New high efficiency first stage nozzlebox plate or nozzle diaphragm

5. Lower bucket and nozzle solidity(decreased number of buckets andnozzles per stage)

6. New inner shell(s)

7. New shaft packing, packing heads andsteam inlet ring assemblies

8. Improved shaft and bucket sealingcapability

The basis of Dense Pack design is the funda-mental thermodynamic principal that more tur-bine stages at smaller wheel diameters creates amore efficient steam path. Recent steam tur-bine technology advances now allow an



Figure 12. GE high pressure steam turbine efficiency improvement history

Figure 13. Irreversibilities in typical 700 MW steam turbine

Shaft Packing

Figure 14. Distribution of high pressure sectionsteam turbine losses

increased number of stages in the same span.Figure 15 compares a conventional turbine witha Dense Pack.

Each Dense Pack is custom designed for thespecific turbine and steam flow conditions. Ingeneral it is possible to recover all efficiency lossdue to aging and to increase the efficiencyabove the original as new steam turbine condi-tion. Since the high pressure section(s) is/arereplaced, there is potential to design DensePack to match the normal MCR steam condi-tions or alternate conditions. This includes thecase of interest here for integration with AGRwhere the Dense Pack is configured forincreased flow at the design point steam pres-

sure for increased power generating capacity.Depending on the capabilities of the boiler,generator and other components, it may be pos-sible to boost heat input by as much as 17%.Table 7 summarizes the baseline and Dense Packperformance where the Dense Pack is designedfor a more modest 12% flow increase.

When the turbine is operated at the normalMCR steam flow, turbine efficiency is increasedby 1.4% resulting in a commensurate 1.4%increase in power generating capacity. Whensteam flow is increased to 12% above MCR,steam turbine efficiency decreases slightly to a1.2% improvement over baseline resulting in a13.3% power generation increase. To avoidthrottling losses, in this example the boiler isoperated in sliding pressure service.

GE introduced Dense Pack in 1998. To date 13units have been sold totaling over 6,000 MW.The first units will enter commercial service in2000.

Integrated System (AGR-DP)By integrating AGR with Dense Pack (AGR-DP)designed for flow increase, NOx can be reducedto SIP Call levels, power generating capacity canbe increased, and heat rate can be decreased.This section discusses the performance of thisintegrated technology focusing on applicationto a 300 MW wall-fired boiler operating withNOx at the Title IV level of 0.46 lb/106 Btuwhere the Dense Pack is designed for a steamflow increase of 12%.



Figure 15. Comparison of high pressure steam tur-bines: baseline and Dense Pack

Table 7. Baseline and Dense Pack performance summary

Steam Flow Steam Turbine PowerSteam Turbine Enthalpy Efficiency GenerationConfiguration (% of MCR) (% of Baseline) (% of Baseline)

Baseline (as new) 100.0 100.0 100.0Dense Pack 100.0 101.4 101.4Dense Pack 112.0 101.2 113.3

The four equipment and operating scenarios(Cases) listed in Table 8 will be discussed:

Figure 16 shows the fuel flows and power gener-ation and Figure 17 shows the emissions for thefour conditions. Case A is the baseline MCRoperating condition where the turbine is oper-ating in the “as new” condition with no agingloses. Case B is AGR applied at MCR. Cases Cand D are AGR-DP; Case C is operation at MCRand Case D is operation with the 12% flowincrease. With AGR-DP, NOx, SO2 and particu-late emissions are less than baseline levels evenwith an increase in power generation by 13.3%.Note that the total fuel flow for AGR-DP reflects

the increase in steam flow plus a slight heat ratepenalty for AGR, primarily due to the increasedlatent heat loss of natural gas compared to coal.

One possible strategy for optimum use of AGR-DP is as follows. During the summer ozone sea-son when deep NOx control is required andpower sells for a premium, AGR-DP is operatedin case D with the AGR system in service andmaximum steam flow to the turbine. NOx isreduced to the SIP Call NOx level, SO2 and par-ticulate emissions are reduced slightly (sinceless coal is fired) and power generation isincreased 13.3% over MCR. For the rest of theyear, when the low NOx burners alone can meetthe NOx requirements and power prices arelower, the system is operated in Case C with theAGR system out of service and MCR steam flowto the turbine. Due to the efficiency increase,

power output is up by 1.4% firing 100% coaland emissions are at baseline.

An economic analysis has been conducted toillustrate the costs and benefits of this integrat-ed technology comparing three approaches toreducing NOx to the SIP Call NOx level:

■ The base turbine (as new) with SCR

■ The base turbine (as new) with AGR

■ AGR-DP

The AGR-DP configuration operates at peakflow in the summer and nominal flow for therest of the year as discussed above. The SCR andAGR cases without Dense Pack operate only atMCR.

The economic factors used in the analysis are



Turbine NOx Control Steam FlowCase Configuration Technology (% of MCR)

A Baseline (as new) Low NOx Burners 100%B Baseline (as new) Low NOx Burners + AGR 100%C Dense Pack Low NOx Burners + AGR 100%D Dense Pack Low NOx Burners + AGR 112%

Figure 16. Firing rates and power generation forvarious technologies

Table 8. Four equipment and operating cases

summarized in Table 9. The technology per-formance factors and capital costs are typicalvalues which will vary with site specific factors.The capital costs are expressed in terms of the$/KW of the original MCR capacity of the unit.Note that the capital cost for the Dense Pack of$30/KW of MCR capacity corresponds to$225/KW for the increased power generationcapacity (13.3%).

The results will be considered from three view-points:

■ Cost of NOx control where the profits

from the incremental power sales arecredited against the cost of NOxcontrol at market value

■ Cost of incremental power generationwhere the value of the NOx reductionis credited against the cost of powergeneration at market value

■ Payback analysis where the costs arecredited by both the incrementalpower sales and value of NOxreduction

Figure 18 shows the NOx control cost where the



Table 9. AGR-DP analysis parameters

Figure 17. Emissions for various technologies

incremental power is credited at $25/MWH.Compared to SCR, AGR reduces cost by 22%and AGR-DP reduces cost by 34%. The effect ofthe sale price of the incremental power is shownin Figure 19. Note that as the incremental powersale price increases, the effective cost of NOxreduction decreases. At $44/MWH, the cost ofNOx control drops to zero. This means that thesales of the incremental power at $44/MWHentirely pay for the capital cost (annual capitalcharges) of the AGR-DP system and the operat-ing cost of AGR

Figure 20 shows the cost of incremental powergeneration as a function of the value of theNOx reduction. The cost of power decreases as

the value of NOx reduction increases. It isexpected that the trading price of NOxallowances will be in the range of $2000-2500/ton when the market matures. This corre-sponds to incremental power generation costsof $14-20/MWH. This means that sale of theincremental power at a price greater than thisamount will be profit to the utility.

Finally, Figure 21 shows the payback for investingin the integrated AGR Dense Pack technology

based on variable values for NOx and powergeneration. The payback can be less than twoyears depending on the prices.



Figure 19. Effect of incremental power sale price on AGR-DP NOx control cost

Figure 20. Incremental power generation cost forAGR-DP

Sim

ple

Payb

ack

(Yea

rs)

Figure 21. Payback for AGR-DP

Figure 18. NOx control cost for various technolo-gies

Conclusion

Title IV will result in most units meeting theEPA target NOx levels using low NOx burnertechnology. For the additional NOx reductionrequired for SIP Call compliance, the primaryalternatives are Combustion Modification (withReburn and Advanced Reburn) and SelectiveCatalytic Reduction (SCR). If the final regula-tions or utility preference require that the 0.15lb/106 Btu level be achieved, SCR will be theonly technology for initial NOx greater thanabout 0.55 lb/106 Btu. However for lower initialNOx, including the 80% of the units which havedry bottom wall and tangentially fired boilers,Reburn or Advanced Reburn will substantiallyundercut the cost of SCR on the smaller units.Under a NOx trading scenario, the NOxallowance trading price will be the key factoraffecting both the selection of the lowest costNOx control technology and the total cost ofNOx control. A free trading scenario shouldresult in NOx allowances trading in the range of$2,000-3,000/ton.

The integrated AGR-DP system is a cost effectiveapproach for deep NOx control to meet ozone-related regulations with the added benefit of a

significant increase in power generation capaci-ty. During the summer the AGR system is inservice controlling NOx to the SIP Call level(0.15 lb/106 Btu) and power generation isincreased by over 13%. Other pollutants (SO2and particulates) are slightly reduced. For therest of the year, the AGR system is out of serviceand the boiler heat input is entirely from coal atthe normal full load heat input. Power isincreased by 1.4% with no change in emissionsfrom baseline. Thus, this approach ensures thatthere is no increase in annual emissions of anypollutant.

The overall economics of AGR-DP are quitefavorable to the utility: NOx is reduced at a costthat is low compared to projected NOxallowances, the incremental power generationcost is low compared to summer power salesprices and payback can be under two years.

It should be recognized that the NOx controllevels, steam turbine performance and costs dis-cussed in this paper are examples of the typicalvalues expected in commercial US utility appli-cations. Site specific factors may alter these fac-tors. A site specific study must be conducted toconfirm the design, performance factors andeconomics.



References

1. C. Latham, et. al., “NOx Control Using Combustion Modification Technologies,” presented atElectric Power 2000, Cincinnati, Ohio, April 2000.

2. B. A. Folsom, et. al., “Updated Experience Using Reburn Technology for Utility Boiler NOxEmissions Reduction,” presented at the EPRI-EPA-DOE Combined Utility Air Pollutant ControlSymposium, Atlanta, GA, August, 1999.

3. B. A. Folsom, et. al., “Field Experience -- Reburn NOx Control,” presented at the EPRI-DOE-EPACombined Utility Air Pollutant Control Symposium (The Mega Symposium), Washington DC,EPRI Report No. TR-108683-V1, 1997.

4. B. A. Folsom, et. al., “Advanced Gas Reburning Demonstration and Commercial Gas ReburningSystem Upgrade,” Pittsburgh Coal Conference, 1996.

5. B. A. Folsom, et. al., “Advanced Reburning with New Process Enhancements,” presented at theEPRI/EPA 1995 Joint Symposium on Stationary Combustion NOx Control, Kansas City, Missouri,1995.

6. V. Zamansky, et. al., “Combined Reburning/N-Agent Injection Systems for Over 90% NOxControl,” presented at the EPRI-DOE-EPA Combined Utility Air Pollutant Control Symposium(The Mega Symposium), Washington DC, EPRI Report No. TR-108683-V1, 1997.

7. V. Zamansky, et. al., “Enhanced NOx Control Via Gas Reburning With Injection of Additives inthe Reburning Zone,” presented at the International Gas Research Conference, San Diego,California, 1998.

8. M. Berg, et. al., “NOx Reduction by Urea Injection in a Coal Fired Utility Boiler,” NOxSymposium, 1993.

9. J. Cichanowicz, “SCR for Coal-Fired Boilers: A Survey of Recent Utility Cost Estimates,” present-ed at the EPRI-DOE-EPA Combined Utility Air Pollutant Control Symposium (The MegaSymposium), Washington DC, EPRI Report No. TR-108683-V1, 1997.



List of FiguresFigure 1. NOx reduction required to achieve SIP call NOx limit from Title IV target NOx levels

Figure 2. Schematic diagram of reburn and advanced reburn

Figure 3. Advanced reburn on a wall-fired boiler

Figure 4. NOx control results from GE EER reburn applications on utility boilers

Figure 5. NOx reduction and NH3 slip for SNCR on 285 MW utility boiler

Figure 6. Advanced Reburn tradeoffs for SIP Call compliance: Reburn and SNCR components

Figure 7. Cumulative NOx for layered combustion modification technologies

Figure 8. Effect of gas firing rate on reburn and advanced reburn NOxFigure 9. NOx control cost for Reburn and Advanced Reburn to 0.15 lb/106 Btu – effect

of initial NOxFigure 10. NOx control cost for all technologies to 0.15 lb/106 Btu – effect of initial NOxFigure 11. NOx control cost for trading, 300 MW wall-fired boiler, initial NOx 0.40 lb/106 Btu

Figure 12. GE high pressure steam turbine efficiency improvement history

Figure 13. Irreversibilities in typical 700 MW steam turbine

Figure 14. Distribution of high pressure section steam turbine losses

Figure 15. Comparison of high pressure steam turbines: baseline and Dense Pack

Figure 16. Firing rates and power generation for various technologies

Figure 17. Emissions for various technologies

Figure 18. NOx control cost for various technologies

Figure 19. Effect of incremental power sale price on AGR-DP NOx control cost

Figure 20. Incremental power generation cost for AGR-DP

Figure 21. Payback for AGR-DP

List of TablesTable 1. Title IV target NOx levels

Table 2. GE EER reburn experience on utility boiler

Table 3. NOx control technologies in economic analysis

Table 4. Economic analysis parameters

Table 5. NOx control costs per variable

Table 6. Trading analysis parameters

Table 7. Baseline and Dense Pack performance summary

Table 8. Four equipment and operating cases

Table 9. AGR-DP analysis parameters



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