mimimize nox emissions

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PETROCHEMICAL PLANT COSTS CONTROL VALVES BOXSCORE UPDATE

June 2001

Increase furnace output Raise control on CDU Plan a grassroots refinery

Reprinted from:



J. D. McAdams, and S. D. Reed, John Zink Co.,Tulsa, Oklahoma; and D. C. Itse, Christofferson

Engineering, Fremont, New Hampshire

A s local environmental agencies demand morestringent control of NOx emissions,companies are challenged to cost-effectively

bring combustion equipment into compliance.Because every facility has a unique mix of equipment and regulatory requirements, the mostcost-effective NOx control technology, or optionalcombinations of technologies, will be different foreach situation. In addition to NOx emissionsrequirements, operating companies must also beable to install this control equipment to meet

compliance deadlines, which can affect scheduledturnaround dates and durations.

For most situations, no single technology will pro-vide the most economic choice for all combustionequipment within an operating plant. By learning about all available options, HPI companies can dis-cover solutions that meet environmental mandateswhile minimizing capital outlays, operating costsand impact on turnaround schedules.

The following guidelines illustrate the availableeffective NOx control technologies. Important fac-tors included in this briefing are: method of oper-ation, positive and negative aspects for each device,

and NOx performance with combinations of sev-eral devices. Since capital costs for installation willbe site specific, the best estimates of the relativecapital and operating costs of each option are com-pared on a sample case for a 100 MMBtu/hr pro-cess heater. This sample heater is assumed to be ingood condition and configured to fire refinery-fuelgas (50% methane, 25% propane, 25% hydrogen)through natural-draft, up-fired, round-flame con-ventional burners with 3% excess oxygen using ambient temperature air—no air preheat (APH)—resulting in base NOx emissions of 100 ppm(0.131 lb/MMBtu, 57.4 tpy) for the unmodified case.

The cost effectiveness of each option is compared interms of U.S. $/t of NOx reduced, calculated by

dividing the tons/year of NOx reduction by the totalannual cost (TAC) in U.S. $/yr determined per the

U.S. Environmental Protections Agency’s (EPA)alternative control techniques (ACT) document1

and the information provided in this sample case.Since performance will also be situation specific,the economic effect of potential lost production dueto installation time is not considered.

Current low- and ultra-low NO x burners. Low-NOx burners can use air staging, fuel staging or inter-nal furnace gas recirculation to lower peak flametemperatures and directly reduce NOx emissionsfrom combustion. Current-generation low-NOx burn-ers have been available for over 20 years, with

improvements in design to decrease NOx emissions.In general, current-generation burners can achieveNOx emissions of 25–50 ppm on ambient air—depending on burner design and application. Thenewest low-NOx burners have been called ultra-lowdue to their enhanced NOx reduction.

For most cases, current-generation burners arethe simplest NOx-control technology option to install.Changing to low-NOx burners does not increaseplant-operating costs or decrease furnace efficiency.They are also able to reduce NOx emissions fromthe furnace without any corresponding increase inCO emissions, another important environmental

criterion. Because these installations require noother systems or additional equipment, operating companies have often considered current-genera-tion low- and ultra-low NOx burners as an “all inone solution” for NOx control. Even with thedecreased NOx emissions performance achieved overtime, the current low-NOx burners are not alwaysable to meet the most stringent regulations presentin some local areas.

When evaluating a low-NOx burner installationor retrofit, many practical matters must be consid-ered. Since the flame length of current-generationlow-NOx burners is typically longer than conven-

tional burners, it must be evaluated when retrofitting furnaces. The larger diameter of current low-NOx

Minimize NO x emissionscost-effectively

Use this tutorial to evaluate available control technologies and install

exactly what you need for current and future NOx reductions

Reprinted from HYDROCARBON PROCEDSSING magazine, June 2001 issue, pgs. 51-58. Used with permission.

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o c e s s O p t i m i z a t i o

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H e a t T r a n s f e r



burners may also require modifications to the airplenum, heater floor and/or refractory of the furnace toaccommodate their increased size.

Current low-NOx burners’ relative cost. Assume:1) ample room for installation under the furnace, 2)

that the only furnace modifications required are toenlarge the cutouts for the burners and 3) only minimalpiping changes are required to connect the gas to thenew burners. Table 1 lists the operating and capitalcosts for low-NOx burners.

FGR on conventional burners. Flue gas recircu-lation (FGR) into the combustion air stream of aburner has been used for many years as a NOx-reduc-tion technique on numerous different combustionapplications. Inert components in the flue gas (N2,CO2, H2O) dilute the oxygen concentration in the airstream and provide additional material in the com-

bustion zone that absorbs heat and lowers the flametemperature, thus decreasing NOx. The greateramount of flue gas recirculated, the lower the NOx

emissions from the burner.Using FGR only, NOx emissions on conventional

burners can be cut by 50–70%, achieving a level of 30 –50 ppm. If waste steam is added into the recir-culated flue gas, NOx can be reduced further to25–30 ppm. Adding FGR to a conventional burnerhas not been found to adversely affect the flameenvelope. Since flue gas is readily available at thefurnace, no cost is incurred for the diluent used inFGR technology.

FGR systems require installing ductwork from thestack to a fan and a forced-draft combustion air systemto supply the flue gas/air mixture to the burners.

Although FGR flow can sometimes be routed throughan existing forced-draft fan, that fan may requireupgrading to handle the additional capacity. Due toincreased velocities through the furnace, high recir-culation rates of FGR systems can shift the heat loadfrom the radiant to the convection section, depend-ing on the furnace design and firing rate. FGR canalso require a larger burner size to admit the recir-culated flue gas along with the combustion air to keepthe pressure drop across the burner low enough for

the fan capacity. Adding FGR to a furnace may requirecombustion air and FGR cold-flow physical modeling

or computational fluid dynamics (CFD) modeling toensure sufficient and uniform flow to all the burnersin the ductwork system.

FGR relative cost. Assume: 1) ample room for duct-work and fan installation and 2) that the new fan willsupply forced-draft air (no APH) and recirculated fluegas. Table 2 lists the operating and capital costs forFGR installations.

FGR and low-NO x burners. When a situationdemands NOx emissions below what current-genera-tion low-NOx burners alone can achieve, FGR can beused to further lower emissions from these burners.

Typical emissions for this combination are in the 15–25ppm range, depending if steam is added to the fluegas. As with conventional burners, adding FGR to low-NOx burners does not appear to adversely affect theirflame envelope.

Applying the two techniques in concert results inthe same potential disadvantages as utilizing eitherone or the other by itself. Combustion air and FGRcold-flow physical modeling or CFD modeling may berequired to ensure uniform flow to the burners in theFGR installation.

FGR and low-NOx burners combination rela-tive cost. Assume: 1) ample room for ductwork and

fan installation, 2) ample room for new burner instal-lation, 3) minimal piping modifications for burner

HYDROCARBON PROCESSING / JUNE 2001

Table 1. Costs (operating and capital) for low-NO x

burners

Capital cost estimateBurners (10 @ $5,000 each) $50,000Installation 80,000Total $130,000

Operating cost estimate, $/yrNo change

10-year net present cost (@8%) $130,000Total annual cost $14,300

NO x emissions performanceppm 25lb/MMBtu 0.033tpy 14.4tpy reduction from base 43.1$/t of NO x reduced $332

Table 2. Costs (capital and operating) for FGRapplications

Capital cost estimateForced draft and FGR ductwork $150,000New forced draft/FGR fan 50,000Forced draft/FGR fan installation 100,000

Total $300,000

Operating cost estimate, $/yr(Assumes no noticeable effect on furnace efficiency)

Power for FD/FGR fan, 30-hp motor, $0.06/kW-hr $12,00010-year net present cost @8% $380,532Total annual cost $45,000

NO x emissions performanceppm 30lb/MMBtu 0.039tpy 17.2tpy reduction from base 40.2$/t of NO x reduced $1,120

Fig. 1. Comparison of fuel dilution and FGR NOx reduction vs. fluegas flow (100 MMBtu/hr case).



installation and 4) that the new fan will supply forceddraft air (no APH) and recirculated flue gas. Table 3lists the capital and operating costs for the FGR and

low-NOx burner combination.

Fuel dilution on conventional burners. Fuel-dilution technology uses the mixing of recirculatedinert furnace flue gas or other inert componentswith the fuel of the burner before combustion. Theseinert components lower the heating value of the fueland decrease flame temperatures; thus reducing NOx emissions. Several pounds of flue gas per poundof fuel can be recirculated in fuel-dilution systems,with greater recirculation rates to produce lowerNOx. Waste steam or atomized water can also beinjected into the recirculation ductwork to further

lower NOx emissions.Like FGR systems, fuel-dilution systems also

require ductwork to carry the flue gas from the fur-nace stack to the burners. Since fuel dilution is moreeffective at reducing NOx than FGR (Fig. 1), fuel-dilu-tion systems require less flue gas for the same NOx

reduction, so that smaller, less expensive ducts canbe used. One patented method for implementing fueldilution does not require a fan or compressor to drivethe recirculation flow. With this method, the pressureenergy of the fuel is used as the motive force in aneductor to draw the furnace flue gas from the stackand mix it with the fuel before combustion in the

burner. Implementing this technology may not requirenew burners, but it does require that existing burnersbe converted with a retrofit kit that includes the fluegas eductor and new parts that allow the additionalflue gas to be passed through the burner along withthe fuel. Because the gas side of the burner now han-dles much more flow, fuel-dilution retrofit kits areoutfitted with larger gas port sizes that reduce thepotential for gas-tip fouling.

In field applications, fuel dilution on conventionalburners has achieved consistent NOx performancedown to 15–20 ppm—an 80–85% NOx reduction. Fur-ther reductions in NOx levels can be realized when

waste steam is introduced into the recirculation flow.Test results have shown that fuel dilution achieves

the greatest NOx reductions when applied to conven-tional burners.

The fuel-dilution method discussed above does notappear to affect the flame dimensions of existing burn-ers. Because no recirculation fan is required, there isalso no increase in plant operating cost. Since the burn-ers remain in place, fuel dilution provides a definiteadvantage in situations where it is too costly or imprac-

tical to replace the burners, or where there is no roomfor potentially larger low-NOx burners. In some situ-ations, a fuel-dilution system may be installed whilethe furnace continues to operate.

Once modified, burners typically require a smallamount of recirculation flow to maintain good flamequality. As with FGR, high-recirculation flowrates canpotentially impact the furnace efficiency or shift theload to the convection section. For greatest effective-ness, pressure-driven fuel-dilution systems should usea fuel pressure of 20 psig or more.

Fuel dilution relative cost. Assume: 1) ampleroom for ductwork and eductor installation around

the burners and furnace, 2) minimal piping modifi-cations for switching the fuel to the eductors and 3)


Table 3. Costs (capital and operating) for FGR andlow-NO x burner configuration

Capital cost estimateLow-NOx burners (from Table 1) $130,000Forced draft and FGR ductwok 150,000New forced draft/FGR fan 50,000Forced draft/FGR fan installation 100,000Total $430,000


Power for FD/FGR fan, 30-hp motor, $0.06/kWh $12,00010-year net present cost @8% $510,532Total annual cost $59,300

NO x emissions perfomanceppm 20lb/MMBtu 0.026tpy 11.5tpy reduction from base 45.9$/t of NO x reduced $1,291

Table 4. Costs (capital and operating) for fuel

diluton methodsCapital cost estimate

Burner retrofit kits (10 @ $4,000 each) $40,000Retrofit kit install (10 @ $2,000 each) 20,000Piping modifications (10 @ $1,000 each) 10,000Ductwork 150,000Total $220,000


No change10-year net present cost @8% $220,000Total annual cost $24,200

NO x emissions perfomanceppm 20lb/MMBtu 0.026

tpy 11.5tpy reduction from base 45.9$/t of NO x reduced $527

Fig. 2. Estimated capital costs for an SCR system on a 100 MMBtu/hr process heater.



ample room in the burner for a retrofit kit. Table 4lists the operating and capital costs for the fuel dilu-

tion method.

Selective catalytic reduction (SCR) systems withconventional burners. As opposed to the NOx-con-trol technology options previously discussed, SCR sys-tems do not reduce the amount of NOx produced in thefurnace, but rather remove it from the furnace flue-gas stream using a chemical reaction. Therefore, SCRscan be used with any burner. In the SCR, NOx is reactedwith ammonia (NH3) in the presence of a catalyst tobreak down NOx and change it back to N2. Some NH3

carries over from this reaction and can become an addi-tional furnace emission that must be monitored under

applicable environmental regulations.For the SCR to operate properly, the NOx-reduction

reaction must take place at the proper temperature.

Higher temperatures cause the NH3 to combust beforereacting, and lower temperatures can greatly reducethe destruction effectiveness of the reaction, requir-ing more catalyst and risking NH3 emissions. For thisreason, SCRs must be installed at the point on theheater where the flue gas is within the temperatureband required. On existing installations, this pointcan sometimes be in the middle of an existing convec-tion section, forcing a major heater reconfiguration.If an installation location with the proper flue gas tem-perature cannot be found, the operator may need touse a higher cost, low-temperature catalyst or provideadditional heat with a duct-burner system to bring

the flue gas up to the proper temperature beforeinstalling the SCR system.

A complete SCR system is complex and includes areactor housing for the catalyst and NH3 injection grid,storage and metering system. Also, an additionalinduced-draft capacity (either a new fan or retrofit of anexisting fan) to overcome pressure drop due to the newcatalyst bed and ductwork may be required. Uniformflow across the catalyst bed is critical, and CFD mod-eling may be necessary to ensure ±15% flow varianceacross the bed.

NOx destruction efficiencies for SCR systems can beanywhere from 50–97%. Ultimate NOx emissions as

low as 3 ppm, depending on burners and destructionpercent, are possible, making SCRs attractive for unitsthat must meet the most stringent NOx regulations.The cost (capital and operating) and the complexity of SCR systems, however, are high enough that SCRs areusually installed only on furnaces that cannot meettheir NOx permits by any other means. Figs. 2 and 3show the estimated installation and annual operating costs for SCR systems of varying destruction efficien-cies applied to a 100 MMBtu/hr process heater. Thesefigures assume a 400°F flue-gas inlet temperature, 10-ppm NH3 slip, and a 4-in. WC pressure drop across theSCR system components.

SCRs may sometimes be used to over-control NOxemissions on one operating unit, while others use low-


Fig. 3. Estimated annual operating costs for an SCR system on a 100MMBtu/hr process heater. Fig. 4. Typical performance range of various NOx control technologies.

Table 5. Costs (capital and operating) for an SCR

systemCapital cost estimate (installed)

Catalyst $236,000Reactor housing 173,000 Ammonia system 161,000 Ammonia injection grid 10,000Control system 34,000New ID fan (installed) 150,000Engineering 96,000Total $860,000

Operating cost estimate, $/yrCatalyst replacement (6-yr life) 40,000Power for ammonia skid, $0.06/kWh 14,000Power for new ID fan, 4-in. WC pressure, $0.06/kWh 10,000 Ammonia 4,000

Total $68,00010-year net present cost (@8%) $1,316,000Total annual cost $162,600


Source: Proprietary Christofferson Engineering Report to John Zink Company.© Christofferson Engineering, 2000. Used by permission.



NOx burners as their only control. Such a strategy maystill meet the plant’s “bubble” permit of overall NOx

emissions while reducing the plant-wide investmentin NOx-reduction technologies.

Al though SCRs can sometimes be ins tal leddirectly on the stack of existing furnaces, mostinstallations require furnace modifications (possi-bly inserting between convection sections) and alarge, available plot space. Plants that do not havespace near their furnaces for the large SCR equip-ment may need to duct several furnaces to a com-

mon SCR. If this common SCR goes out of service,the operation and emissions’ performance of severalheaters can be affected. NOx emissions may wellexceed regulatory limits during downtime and main-tenance if an SCR system is the only NOx-controltechnology used on a furnace.

The SCR catalyst bed can plug or foul over timedue to dust, metal scale, or degrading refractorythat passes through the furnace ductwork. Somechemicals found in refinery fuel gases, most notablysulfur, can also poison the SCR catalyst, reducing its life and degrading system performance until thecatalyst can be replaced. With growing demand for

SCR systems, the future availability of the SCR cat-alyst may well become an issue. The complex natureof an SCR system, and the interdependence of theductwork, catalyst bed, NH3-handling system, andfan increase the need for preventive maintenanceon the furnace and increase the potential forunscheduled maintenance incidents from equipmentfailures. Also, operators faced with tight deadlinesfor compliance must also consider the lead-time forSCR design, manufacture and installation, whichcan be several months since each application mustbe specifically engineered.

SCR system relative cost. Assume: 1) ample room

for ductwork and fan installation, 2) no heater recon-figuration and 3) 90% destruction eff iciency, 10-ppm

NOx emissions at SCR outlet w/10-ppm NH3 slip, 400°Fflue gas inlet temperature. Table 5 lists the operating and capital costs for an SCR unit—alone.

SCR with low-NO x burners. When a plant wishesto reduce the operating cost of an SCR system orminimize their dependence on the SCR system alone,a furnace can be equipped with both an SCR unitand low-NOx burners. Installing low-NOx burnersreduces the amount of NOx in the flue gas that theSCR must remove. Consequently, capital and oper-ational costs of the SCR system are greatly lowered.The two technologies, operating in concert, deliverthe best NOx performance achievable on the markettoday—2–15 ppm, depending on the burners anddestruction percent.

The optimum economic combination of these twoNOx-control technologies will be specific for each appli-


Fig. 5. NOx control equipment cost-effectiveness in $/t of NOxreduction.

Fig. 6. Cost and performance comparison of NOx reduction equip-ment (100 MMBtu/hr).

Table 6. Costs (capital and operating) for SCR andlow-NO x burner arrangement

Capital cost estimate (installed)Low-NOx burners (Table 1) $130,000Catalyst 186,000Reactor housing 138,000 Ammonia system 134,000 Ammonia injection grid 10,000Control system 34,000New ID fan (installed) 150,000Engineering 96,000Total $878,000

Operating cost estimate, $/yrCatalyst replacement (6-yr life) $31,000Power for ammonia skid, $0.06/kWh 14,000Power for new ID fan, 4-in. WC dP, $0.06/kWh 10,000 Ammonia 1,000Total $56,000

10-year net present cost (@8%) $1,254,000Total annual cost $152,580


Source: Proprietary Christofferson Engineering Report to John Zink Company.© Christofferson Engineering, 2000. Used by permission.



cation, but installing low-NOx burners with an SCRsystem can minimize NOx emissions even when theSCR system is out of service for maintenance or catalystreplacement. A combination SCR and low-NOx burnersystem can keep yearly totals of emissions low for alloperating conditions and reduce the dependence on

proper operation of the SCR system to maintain envi-ronmental compliance. This combination shares boththe advantages and disadvantages of low-NOx burn-ers and SCR systems.

SCR with low-NOx burners relative cost. Assume: 1) ample room for ductwork and fan installa-tion, 2) no heater reconfiguration for SCR, 3) 60%destruction efficiency, 25-ppm NOx from burners, 10-ppm NOx emissions at SCR outlet w/10-ppm NH3 slip,400°F flue-gas inlet temperature, 4) ample room forlow-NOx burners and 5) minimal piping modificationsfor burner installation. Table 6 lists the capital andoperating costs for the SCR and low-NOx burner com-

bination installation.

Next-generation low-NO x burners. The next gen-eration of low-NOx burners is being developed to achieveNOx emissions of 5–12 ppm in field applications. Someadvanced burners use a combination of lean-premixcombustion, fuel staging, and zoned internal furnacegas recirculation to achieve this emissions target. Atthese NOx levels, next-generation burners are able tocompete with SCR systems at considerably less capitaloutlay and operating expense.

Unlike current-generation low-NOx burners, theseburners that use lean-premix combustion can exhibit

flame lengths similar to conventional burners. Thelean-premix technique also allows a reduction inburner size and is comparable to conventional burn-ers; thus eliminating the need for an increased fur-nace cutout size on retrofits. These features makethese burners easier to retrofit into furnaces origi-nally designed for conventional burners. Some next-generation low-NOx burners are designed as “plug-and-play” units that f it within the tile throats of existing burners and have been installed on the runwith no furnace modification.

This technology has been successfully applied toradiant-wall and flat-flame wall-fired burners in com-

mercial applications and is currently being developedon round-flame process burners. Next-generation burn-

ers are undergoing continued development and engi-neering in a wide range of configurations and instal-lations as engineers and technicians approach fieldreplication of laboratory-produced NOx emission lev-els in the 8–15 ppm range.

New low-NOx burners may hold the promise of areturn to the simple installation and the “all in onesolution” of current-generation low-NOx burners.Next-generation low-NOx burner engineering andmanufacturing time is reduced to several weeks,

eliminating the long lead-time of SCR systems andthe potential extensive downtime required for SCRinstallation. As with current low-NOx burners, theinstallation of next-generation low-NOx burners nei-ther increases plant operating costs nor decreasesfurnace eff iciency.

Advanced lean-premix low-NOx burner rela-tive cost. Assume: 1) ample room for installation underthe furnace and 2) that there are only minimal piping changes required to connect the gas to the new burners.Table 7 lists the operating and capital costs for next-gen-eration lean-premix low-NOx burners.

NO x control options. Fig. 4 illustrates the range of NOx emission’s performance for the presented controltechnologies with ambient air temperature. The emis-sions levels used for the 100 MMBtu/hr process heatersample case are also shown on this graph. In Fig. 4,only next-generation low-NOx burners or SCR systems


Table 7. Costs (capital and operating) for next-generation low-NO x burners

Capital cost estimateBurners (10 @ $20,000 each) $200,000Installation 80,000Total $280,000

Operating cost estimate, $/yrNo change

10-yr net present cost (@8%) $280,000Total annual cost $30,800

NO x emission performancepm 12lb/MMBtu 0.016tpy 6.9tpy reduction from base 50.5$/t of NO x reduced $610

Jason McAdams is a technology development engineer at the John Zink Co., in Tulsa,Oklahoma. His responsibilities include evaluating new combustion technology and work- ing with designs for the next-generation low-NO x burners mentioned in this article. Prior to

coming to John Zink in 1999, Mr. McAdamsworked for more than five years as a project engineer and a reliability engineer for fired equipment at Koch Petroleum Group’s Corpus

Christi refining complex. At the refinery, he managed several projects involving fired heaters and combustion equipment and instituted a program to optimize the life-cycle cost of fired heaters.Mr. McAdams graduated summa cum laude with his BS degree in mechanical engineering from the University of Tulsa and is a member of the Tau Beta Pi Engineering Honor Society.

Scott D. Reed is the vice president sales and marketing, John Zink Co., Tulsa, Okla- homa. He has been with John Zink sinceobtaining his BS degree from Oklahoma StateUniversity in 1985. Currently, Mr. Reed serves as the vice president for customer origination, although he has experience in a variety of roles within the John Zink organization includ- ing product-line management, sales and ser-vice. As a key account manager, Mr. Reed works directly with customers to develop the most cost-effective low-NO x solutions.

Daniel C. Itse,PE, is president of ChristoffersonEngineering, Fremont, New Hampshire. He holds both BS and an MS degrees in chemical engineering from Worcester Polytechnic Institute. A noted developer of applications and technologies for controlling emissions from combustion systems, Mr. Itse has extensive experience in suc-cessful process stimulation. Current projects and past publications attest to the demand and respect

for his services to the process industries.



are able to meet some of the newest regulations thatrequire NOx emissions of less than 10 ppm.

Fig. 5 shows the cost effectiveness, measured in $/ tof NOx reduced, for each technology option, based onthe sample 100 MMBtu/ hr process-heater case. Fromthis figure, the NOx control options requiring only theinstallation of new burners or ductwork (current-gen-eration low-NOx burners, fuel dilution on conventionalburners and next-generation low-NOx burners) pro-vide the most cost-effective NOx control, with costs

ranging from $332 to $610/t of NOx reduced. FGR sys-tems, which require a fan for flue gas recirculation,make up the next tier of cost effectiveness with a rangeof $1,120 to $1,291/t of NOx reduced, depending on theemissions required.

SCR systems and combinations involving an SCRare the least cost-effective, with expenditures rang-ing from $2,954 to $3,148/ t of NOx reduced. How-ever, SCRs are able to achieve a lower NOx emissionlevel than most of the other options. Installing cur-rent-generation low-NOx burners in combinationwith an SCR system both decreases the overall NOx

produced and cuts the cost of NOx reduction by

$194/t. Since the SCR, low-NOx burner combinationprovides two controls on NOx production (both dur-ing and after combustion) and reduces operating costs, it can be an attractive option for operators

looking for the most cost-effective way to meet thetightest NOx regulations.

The 10-year net present cost at 8% of NOx controlequipment versus the emissions performance for theexample case is shown in Fig. 6. In this figure, itbecomes almost exponentially more expensive to controlNOx to lower levels. Again, the technologies that requireonly a burner change out or ductwork seem to have aneconomic advantage over those options requiring recir-culation fans or complicated SCR systems.

When evaluating any NOx reduction project, it isvital to f irst determine which control technologieswill be able to meet the emissions required for indi-vidual plant equipment. While realizing the valueof identifying the optimum solution for each case,many companies find that evaluating the perfor-mance and cost of every available technology can bea daunting task.

When faced with meeting an upcoming NOx regu-lation, operating companies should enlist an equip-ment supplier or engineering company with a widerange of combustion experience to aid in selecting thebest technology for each application.

LITERATURE CITED1 Alternative Control Techniques Document—NO x Emissions from Process Heaters (Revised):

EPA-453/R-93-034, September 1993.

F/1M/7-2001 Article copyright © 2001 by Gulf Publishing Company. All rights reserved. Printed in USA.

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