October 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500 

## Appendix A

NO x 

## BART Review for the Mohave Generating Station

# NOx BART REVIEW

For

MOHAVE

GENERATING STATION

UNITS 1&2 CLARK COUNTY, NEVADA

Date Issued: July 28, 2008Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential 7/28/08
©2008 Babcock Power Inc. All Rights Reserved This document was prepared solely for use by, and s olely for the benefit of Navasota Energy for the purpose of supporting the BART analysis for the Mohave Generating Station. Any other recipient of this document uses it without th e permission of Riley Power and thereby releases Riley Power from liability of any kind. R iley Power has taken certain steps to evaluate possible changes to the Mohave Generating Station, but the information herein is not intended as a design, nor even a basis for design. Riley Power expressly disclaims any warranty, expressed or implied, with respect to use of the information or concepts disclosed in this document for any purpose other than that set o ut in the underlying contract between Riley Power and Navasota Energy.Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential -A- 7/25/08
©2008 Babcock Power Inc. All Rights Reserved 

## APPENDIX A:

Babcock Power Inc. NOx BART Review for the Mohave Generating StationMohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-1 7/25/08
©2008 Babcock Power Inc. All Rights Reserved 1.0 EXECUTIVE SUMMARY

1.1 OBJECTIVE

Evaluate the Mohave Generating Station options to r educe NOx emissions. The predicted NOx values in this report will be use d for the preparation of the

BART evaluation.

1.2 FINDINGS

The evaluation of the boiler emissions profiles in this report are based on the future predicted operating conditions as shown in T able A-1.

Table A-1 – Predicted Operating Conditions

Natural Gas Firing Predicted operation Natural Gas Firing

Max. operation
Fuel Flow Rate 7,163,100 SCFH 7,635,659 SCFH

Fuel HHV 1032 Btu/ft3 1032 Btu/ft3 Heat Input (per boiler) M Btu/hr 7,392.3 7,880.0

Flue Gas Flow (from combustion) Lb/hr 6,049,300 6,448,300

Air Heater Leakage (12%) Lb/hr 725,916 773,796
Flue Gas Flow to Stack Lb/hr 6,775,216 7222,096 FG Temp. Leaving AH oF 252 252 FG Temp. Leaving AH K 395.4 395.4 FG Density (@ temp above) Lb/ft3 0.053 0.053

Flue Gas Flow Rate (to stack per boiler) ACFM 2,130,570 2,271,100

Total Flue Gas Flow Rate (to stack – both boilers) ACFM 4,261,140 4,542,200

Stack Height ft (m) 500 (152.4) Base Site Elevation ft (m) 712 (217) Stack Diameter ft (m) 32.5 (9.91) Flow Area ft2 (m2) 829.6 (77.1) Flue Gas Exit Velocity ft/s (m/s) 85.6 (26.1) 91.3 (27.8)

Utility boilers firing fossil fuels have generally employed two techniques for reducing NOx emissions including modifications to t he combustion system and the use of chemical reagents. These methods of NOx control can be used in combination to help further reduce NOx emissions . Each of the differentMohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-2 7/25/08
©2008 Babcock Power Inc. All Rights Reserved

emissions controls has inherent advantages and disa dvantages that can be compared and evaluated. The three areas that are us ually compared and evaluated include: level of NOx reduction, initial “Capital” costs, and annual operating costs.

Modifications to the combustion system are designed to reduce the temperature of the combustion zone thereby reducing the thermal NOx. Typical modifications to the combustion system incl ude:

o Low excess air operation

 The typical excess air design range for natural gas is 8-12%.

 Operating at lower excess airs works to reduce the flame temperatures thereby reducing thermal NOx.

 Low excess air operation can be done in conjunction with low NOx burner modifications and is typically achieved through testing and tuning of the combustion system

 Low excess air levels can result in an increase in CO emissions

o Operating with Burners out of service

 Operating with burners out of service is a method o f staging the combustion zone with out overfire air ports.

 This method controls thermal NOx by reducing flame

temperatures.

 Minimal capitol cost to upgrade the combustion cont rol

system.

o Low NOx burners

 Reduces the NOx emissions by controlling the mixing of fuel and air during combustion.

 Low NOx burners reduce flame temperatures thereby r educing the production of thermal NOx

 Low NOx burners can be used with Overfire air to ac hieve further staging of the combustion zone and further NOx

reduction.

 Low NOx burners can also be used in conjunction wit h Flue

Gas Recirculation.

 Low NOx burners alone are the base case for NOx emi ssions.

o Overfire air

 Overfire air ports divert some of the combustion ai r away from the burners (primary combustion zone) to lower the combustion temperatures and therefore NOx emissions

 Overfire air ports are typically located above the top row of

burners.

 This technology can be used with other NOx control techniques such as Low NOx burners and Flue Gas

Recirculation.Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-3 7/25/08
©2008 Babcock Power Inc. All Rights Reserved  Minimal impact on boiler performance and operation (i.e. minimal increase in CO emissions and opacity)

 Modifications include the addition of ductwork, air registers, airflow measurement, and boiler wall openings.

o Flue gas recirculation

 Flue gas from the outlet of the boiler is mixed wit h the

combustion air to the burners.

 Reduces the combustion temperatures to achieve a re duction in

NOx.

 Increases the flue gas flow through the convective pass of the boiler thereby increasing heat transfer.

 Retrofitting the boiler with this system involves n ew fans, ductwork and dampers, control system, flow measurem ent and a mixing device.

 Increase in plant operating cost as a result of the FGR fan motor power absorption.

The second method of NOx control is performed after combustion has taken place and NOx molecules have been formed. NOx reduc tion in this case is achieved by the use of chemical reaction between th e NOx in the flue gas and

ammonia. There are two methods that are used to ini tiate the chemical

reaction:

o Selective Non-Catalytic Reduction (SNCR)

 Ammonia or Urea is injected into the flue gas to ac t as the chemical reagent in the reaction with NOx.

 The ammonia or urea is injected in the area were th e flue gas is in the temperature range of 1600oF to 2200oF.

 NOx reduction levels is dependent on injection poin t, residence time within the temperature range, and mixing effic iency.

 NOx reductions are limited on the Mohave Boilers du e to

• Already low levels of NOx

• Physical size of the boiler

• CO levels entering the SNCR zone

• Temperature profiles in the boiler

• Low residence times

 Ammonia slip of 6 ppmv dry corrected to 3% oxygen

 Modifications include:

• A reagent transfer, storage and pumping station

• Reagent transport system (Pumps, flow meters, heate rs)

• Control system

• Injection equipment including furnace penetrations

o Selective Catalytic Reduction (SCR)

 Lower reaction temperatures then SNCR (600 – 800 oF )

 The reaction takes place in a bed of catalyst.Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-4 7/25/08
©2008 Babcock Power Inc. All Rights Reserved  Can be designed as either a stand alone reactor ves sel or for natural gas part of the ductwork (in-duct SCR)

 NOx emissions reduction of 90% with an ammonia slip of 2

ppm.

 The addition of a SCR system involves the following modifications and additional equipment:

• Reagent (ammonia or urea) transfer, storage and pumping station

• Reagent injection grid and mixing devices

• SCR system controls for reagent flow, temperature, boiler load, NOx emissions monitoring and control, and system safety

• Reactor and catalyst

• Structural considerations for both the reactor and boiler

proper

• FD and ID fan upgrades including their electrical

system

• Boiler system upgrades (e.g., implosion study)

• Economizer modifications if necessary to achieve proper reactor temperatures over the boiler load ra nge

A summary of the BART technology and cost review ar e presented in Table A-2. A detailed discussion of NOx formation and control op tions is provided in the next

section.

Table A-2 MGS BART Technology Options Summary

NOx

Emissions

(lb/MMBtu) Capital

Costs (10 6 $) Operating

Costs (10 6 $/yr) Ammonia

Slip (ppm)*

LNB + OFA 0.10 8 0 -

LNB+OFA+FGR 0.07 75-150 4 -

LNB+OFA+SNCR 0.08 60 7.5 6

LNB+OFA+SCR (in-line) 0.03 105 – 180 12 2

LNB+OFA+SCR (stand alone) 0.01 200 12 2

*ppmv dry corrected to 3% oxygenMohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-5 7/25/08
©2008 Babcock Power Inc. All Rights Reserved 2.0 DISCUSSION OF NOx FORMATION AND AVAILABLE CONTR OLS

2.1 NOx FORMATION

Oxides of nitrogen (NOx) are formed during the comb ustion process of natural gas

via three distinct mechanisms. The first mechanism , called “thermal” NOx, refers to the NOx that is formed through the oxidation of nit rogen that is present in the air and is supplied to complete the combustion process. Th ermal NOx typically represents virtually all of the NOx generated during natural g as combustion. The second mechanism, called “fuel” NOx, refers to the NOx tha t is formed through the oxidation of the nitrogen that is chemically bound in the fuel itself. There is no “fuel” NOx produced during natural gas combustion. The third and final mechanism, “prompt” NOx, refers to the NOx that is formed with in the flame front from hydrocarbon fragments that react with molecular nit rogen. Prompt NOx represents a very small amount (approximately 2 – 10 ppm 1 ) of the total NOx emissions generated during fuel oil combustion. A review of basic NOx emissions formation during the combustion process is important in understanding ho w NOx control technologies described in this report act in reducing NOx emissi ons, their impact on unit operation.

This would then allow in the selection of “best ava ilable retrofit technology” (BART).

“Thermal” NOx formation has been adequately describ ed by the Zeldovich mechanism and it is dependent on temperature, local fuel and oxygen concentrations and residence time at the reaction temperature. Mo lecular nitrogen present in the air that is supplied to complete combustion is a fairly inert material, that under high temperatures (typically >2800 °F) it dissociates an d reacts with oxygen to form mainly nitric oxide (NO) and small quantities (<5%) of nitrogen dioxide (NO 2 ). The

Zeldovich mechanism indicates that the rate of “the rmal” NOx formation is exponentially proportional to temperature of the re action and proportional to the local oxygen concentration.

“Fuel” NOx is formed by the direct oxidation of the nitrogen that is organically bound in the fuel. It can represent a significant (~ 50%) of the total NOx that is formed and emitted during fuel oil combustion even though a small portion of the fuel bound nitrogen is converted to NOx. Its rate of formation is not dependent on temperature but rather on the oxygen concentration during the early stages of combustion but less so to combustion temperatures.

Since the Mohave units will be converted to natural gas resulting in all of the NOx emissions produced are due to “thermal” NOx.

1 All ppm numbers referred in this report are by vol ume, dry and corrected to 3% oxygenMohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-6 7/25/08
©2008 Babcock Power Inc. All Rights Reserved

2.2 NOx EMISSIONS CONTROL There are basically two techniques that have been u sed in reducing and controlling NOx emissions generated by utility boil ers combusting fossil

fuels:

• Modifications to the combustion process

• Use of chemical reagents to reduce NOx to molecular nitrogen

Both of these general techniques by themselves or i n combination have been used throughout the industry with various degrees of suc cess to achieve reductions in

NOx emissions.

2.2.1 Modifications to the Combustion Process/Optim ization

Over the past forty years it has been shown that mo difying or “retrofitting” the combustion process through the reduction of oxy gen concentrations during the initial stages of natural gas combustion , thereby reducing the temperatures of combustion, and/or reducing the amo unt of oxygen that is present have resulted in significant reductions in NOx emissions from utility boilers. These modifications to the combustion pro cess have included changes to the unit’s operation such as low excess air, burners out of service (BOOS) and general optimization of the combustion s ystem settings or the installation of equipment such as low NOx burners ( LNB) and overfire air (OFA) ports.

The Mohave units are tangentially fired supercritic al boilers originally designed to fire pulverized coal, natural gas or a combination of both to achieve full load. Typical emissions from these un its averaged 0.4 – 0.5 lbs/MBtu fired at full load boiler operation on coa l.

2.2.1.1 Low Excess Air Operation Operating natural gas fired utility boilers at Low Excess Air (LEA) levels is an operational change that has been shown to provide some improvement in NOx reductions. This operation prov ides for a reduction in the amount of available oxygen to the combustion zone lowering the overall NOx formation stoichiometry an d combustion temperatures. A natural gas fired boiler would typ ically operate at excess air levels of 8 –12%. This level of operati ng excess air is anticipated for the Mohave units. Further reducing operating excess air levels could have negative emission and operati ng impact by increasing the amount of combustible losses (e.g., CO and particulates). It is anticipated that the proposed excess air level of 8 –Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-7 7/25/08
©2008 Babcock Power Inc. All Rights Reserved 12% provides for the best compromise in terms of em issions and unit performance.

This method of NOx control can be used in conjuncti on with other combustion modifications such as low NOx burners, o verfire air and flue gas recirculation. An excess air level of 8-12 % is recommended for the design of the fuel burning equipment and af ter modifications are made the unit may be able to further reduce NOx emissions by lowering excess air levels. Testing and tuning of t he combustion system is typically performed when lowering the exc ess air. This is

done while the boiler is on-line so that the overal l unit performance (i.e. steam temperatures and CO emissions) can be m onitored while changes are being made.

2.2.1.2 Burners-Out-of-Service Burners-out-of-service (BOOS) is an inexpensive and proven means of achieving staged combustion (i.e., the reduction of burner zone stoichiometry) and subsequent reduction in NOx emis sions, without the use of overfire air ports. Staged combustion i nvolves the generation of fuel-rich zone during the initial sta ges of the fuel combustion that reduces the oxygen concentration an d flame temperatures. The remainder of air necessary to co mplete combustion is added downstream through overfire (OFA) ports in another section of the furnace (i.e., the “second stage”) resulting in an overall

reduction of NOx emissions. BOOS eliminate the nee d of capital and installation expenditures of OFA ports. Figure A-1 provides a graphical indication of the BOOS concept.Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-8 7/25/08
©2008 Babcock Power Inc. All Rights Reserved Figure A-1 - Typical Burner out of Service (BOOS) a rrangement

BOOS operation is accomplished by eliminating fuel flow to selected burner and only providing air through them. Fuel f low to remaining burners is increased to maintain the heat input req uired to produce the fuel rich atmosphere required for reducing NOx emis sions. The BOOS takes the place of OFA ports and assists in co mpleting the combustion. This technique has been used extensive ly through out the U.S. on heavy oil and gas fired units over the past 30+ years due to its simplicity and low cost and has resulted in signifi cant (25 – 50%) NOx reductions. Typically the numbers of burners remov ed from operation in the unit is 20 –25% of the total. Generally rem oving burners from service in the upper rows of the burner array resul ts in the lowest NOx

emission levels.

The advantage of the BOOS technique is that it offe rs significant NOx emissions reductions, at minimal capital costs, it can be implemented in a short period of time and it is applicable to a ll types of utility boilers. Large site-to-site variations in the effe ctiveness of the BOOS technique have been encountered depending on the un it’s design, and burner arrangement (the larger number of burners th e larger the NOx reduction achieved and design flexibility allowed).

BOOS can be implemented to existing utility boilers without significant modifications to the existing combustio n equipment or to the boiler in general. Typically the modifications required would be to upgrade the boiler control system and combustion in strumentation and increasing fuel flow to the reduced number of opera ting burners.Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-9 7/25/08
©2008 Babcock Power Inc. All Rights Reserved The current Mohave units having been designed for p ulverized coal and natural gas firing lend themselves to BOOS sinc e the existing burner corner (tangential) openings are oversized f or natural gas. The proposed conversion of the units calls for the use of the excess space as overfire (OFA) ports for NOx emissions control.

2.2.1.3 Low NOx Burners (LNB) Low NOx burners (LNB) are designed to reduce NOx em issions by controlling the mixing of fuel and air during the i nitial stages of combustion. The basic concept that forms the basis of the LNB design is to delay the mixing of the fuel and air during t he initial stages of the combustion process. This delay is achieved through the physical separation of some of the air from the fuel, or thr ough aerodynamic means by imparting swirl to the air, or both. The production of NOx is

minimized under these conditions since the availabi lity (concentration) of oxygen to react with the liberated organically b ound nitrogen is minimized (see Figure A-2).

Figure A-2 - Typical Low NOx Burner Concept

The Mohave units are tangentially – fired boilers t hat are characterized by their inherent lower NOx emissions when compared to wall – fired boilers. Tangentially – fired boilers introduce th e fuel and air at the corners of the combustion chamber (furnace) in an a lternating manner. As a result the mixing of fuel and air is delayed r esulting in lower temperatures and hence lower NOx emissions. It has been shown that the most effective way of reducing emissions in the se units is to design OFA ports that further delay the introduction of ai r in the combustion process further reducing NOx emissions. This is pr oposed approach

for the Mohave units.Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-10 7/25/08
©2008 Babcock Power Inc. All Rights Reserved 2.2.1.4 Overfire Air (OFA) Overfire air (OFA) involves the use of air injectio n ports above the main combustion (burner) zone in the upper furnace to divert a portion of the combustion air away from the initial combust ion zone (burners). Figure A-3 shows a typical OFA system for a utility boiler.

Figure A-3 - Typical OFA system for a wall-fired ut ility boiler

The quantity of air that is diverted to the OFA por ts typically varies from 5 to 25% with the primary objective being to r educe oxygen concentrations and temperatures in the primary comb ustion zone thereby reducing NOx emissions. The air injected t hrough the OFA ports assists in completing combustion. This techn ology has been applied to control NOx emissions to power boilers o ver the past 35+ years with success. The technology can be used in combination with other NOx control techniques such as low NOx burner s (LNB), flue gas recirculation (FGR) on several units in the US with success and is applicable to all utility boilers with its effect o n NOx reductions being additive. Its success and applicability depends on boiler design (i.e., available boiler height to install the OFA ports an d complete combustion) and available space to route the combus tion air necessary for the OFA ports.

The NOx reduction that has been achieved with OFA p orts has ranged between 10 to 30% with some units as high as 40% fr om uncontrolled levels. Typical boiler modifications include the a ddition of new boilerMohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-11 7/25/08
©2008 Babcock Power Inc. All Rights Reserved wall openings, and an air register assembly to cont rol mixing and flow of the OFA with the furnace gasses. Ductwork that delivers the air from its main supply to the OFA ports is also requi red along with the necessary structural supports and thermal expansion joints. Flow

measurement and control of the air flow to each OFA ports may also be required such that OFA flow can be optimized to maximize NOx emissions reductions with minimal impact on boiler performance and operation (i.e., increased combustibles and opacity ).

The Mohave units will be equipped with OFA ports to provide the

maximum NOx emissions reduction via retrofit techno logy resulting in anticipated NOx emissions of 0.1 lbs/MBtu when firi ng natural gas at

boiler full load.

2.2.1.5 Flue Gas Recirculation (FGR) Flue gas recirculation (FGR) refers to the mixing o f the combustion products (flue gas) with combustion air to reduce N Ox emissions. FGR lowers oxygen concentration during the initial stages of combustion along with combustion temperature reduci ng NOx emissions. Since flue gas is inert (consists mainl y of nitrogen, carbon dioxide and water vapor) it is important that the o xygen concentration of combustion air/flue gas mixture is kept above 17 % (as compared to air of 21%) in order to ensure that sufficient oxyg en for the combustion of natural gas is available. Failure to do so could result in unsafe operating conditions.

The flue gas is typically taken from the outlet of the boiler upstream of

the air heater and is then mixed with hot combustio n air exiting the air heater (see Figure A-4 for typical approaches to FG R).Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-12 7/25/08
©2008 Babcock Power Inc. All Rights Reserved Figure A-4 - Typical utility boiler FGR system

For utility boiler applications the mixture is then transported to the burners (windbox) through the existing combustion a ir ductwork. To reduce the cost of application “induced” FGR has al so been used. During this approach flue gas from the stack is tra nsported to the inlet of the forced draft (FD Fan) using the induction fo rce of the FD fan itself (see Figure A-5).

Figure A-5 - Typical Induced FGR system (20)Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-13 7/25/08
©2008 Babcock Power Inc. All Rights Reserved This approach is less expensive since it does not r equire a dedicated FGR fan and mixing device, however is limited to th e capability of the existing FD Fan and ductwork.

FGR has been in use for over 30 years on boilers fi ring natural gas as one of the main techniques in reducing NOx emission s. It has been and can be retrofitted to most utility heavy boiler s although an engineering study would need to be performed to est ablish its compatibility with existing boiler and burner desig ns. The study

should at a minimum establish burner air/FGR flow r equirements, air ductwork size and velocities, boiler convective sec tion heat transfer impact, existing fan (forced and induced) capacity, and furnace pressure limits.

The NOx reduction levels achieved though the use of FGR in heavy oil combustion are primarily dependent on: (1) FGR flow rate, (2) excess air levels, (3) burner stoichiometry, and (4 ) burner/furnace heat release rate. In general FGR is effective in reduc ing the levels of “thermal” NOx produced due to its dilution effect o n the combustion and its reduction of combustion temperatures. Typi cally the NOx

reductions that are achieved with the use of FGR ra nge on the order of

20 – 50% from uncontrolled levels.

To retrofit FGR in a natural gas fired boiler one w ould need to establish first if the unit has an existing FGR sys tem for controlling steam temperatures. If the boiler is equipped with an existing FGR system the capability of the existing FGR fan would need to be evaluated to establish if it can provide the necess ary flows and pressures required for NOx control FGR system. If the existing fan is not adequate (typically existing FGR fans are not c apable) it needs to either be upgraded or replaced and the existing mot or electrical system be upgraded. If the unit does not have an existing FGR fan a new fan along with the necessary equipment (transformer, sw itchgear, etc.) will need to be purchased and installed, along with the necessary ductwork from the boiler (extraction point), to the fan and then to the combustion air duct. Mixing devices to thoroughly mix the gas with the air and gas flowing measuring devices will also need to be supplied. It is not advisable to mix FGR with the OFA, so if the unit is already equipped with OFA a “fresh” air system n eeds to be maintained to supply the OFA.

FGR can have some significant impacts on boiler ope ration and its implementation needs to follow a careful study. Si nce it dilutes the oxygen content of the combustion air careful consid eration should beMohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-14 7/25/08
©2008 Babcock Power Inc. All Rights Reserved given to flame (combustion) stability. This is typ ically done by limiting the amount of FGR that is mixed with the c ombustion air to the mixture minimum oxygen content of 17%.

The addition of FGR increases the total mass flow o f the flue gases passing the boiler’s convective heat transfer surfa ces (i.e., superheater, reheater, and economizer). This results in increas ed heat transfer and hence in increased steam and heating surface metal temperatures leading to premature failures. This increase in fl ow is most critical during boiler full load operation while at lower lo ads the increased FGR flow could be helpful in meeting steam temperat ure requirements. Careful operation will be required t o minimize furnace vibrations that are the result of flame instability and the emissions of combustibles (CO), opacity and particulates that co uld result from the application of FGR.

The capital costs of FGR systems are estimated to b e in the range of $35 - $50 2 /kW, however if significant upgrades to existing eq uipment are required such as modifications of heating surfa ces, FGR fan replacement, boiler structural and controls upgrade s, these costs could be significantly higher. “Induced” FGR implementat ion has significantly lower costs (<$40/kW) due to the elim ination of the FGR dedicated fan and its ancillary equipment and contr ols, along with a significant reduction in FGR ductwork.

A review of the Mohave units indicates that the app licability of FGR recirculation would provide some reduction in NOx e missions (from 0.1 to 0.075 lbs/MBtu) however at a high cost of re trofit. Specifically the following modifications to the unit will be req uired:

• Installation of two FGR recirculation fans per unit

• Installation of required switchgear for the fan mot ors

• Flue gas and air mixing devices

• Removal/addition of convective section surface

• Upgrade of furnace materials

• Modifications to unit’s control system

• Addition of “fresh” air system for the OFA ports

The addition of the FGR system would represent incr eased operating costs due to the power required to operate the FGR fans as well as

increased unit maintenance. The addition of an “in duced” FGR

2 The costs included in this report have been adjuste d to reflect 2004 costs in US $, however over the p ast four years there have been unprecedented increases in the price of steel, and materials in generalMohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-15 7/25/08
©2008 Babcock Power Inc. All Rights Reserved system was also evaluated, and it was deemed not to be cost effective since the Mohave units are pressurized. The IFGR s ystem to be applied at the Mohave units would require their con version to balanced draft necessitating the addition of Induce d Draft (ID) fans

and re-enforcement of the units to withstand the si gnificant increase in negative pressure from the current design.

2.2.2 Post – Combustion NOx Emissions Control

NOx emissions can be controlled following their gen eration from the combustion of fossil fuels through the use of chemi cal reagents such as ammonia or urea. There are two major commercial ly available processes that can be used using this basic princip le:

 Selective Non – Catalytic Reduction (SNCR)

 Selective Catalytic Reduction (SCR)

In both of these processes the following chemical r eaction forms the

basis for the reduction of NOx:

2NH 3 + 2NO + 1/2 O 2  2N 2 + 3H 2 O (1)

Urea has also been used as an ammonia (NH 3 ) substitute with the overall NOx reduction reaction being:

(NH 2 ) 2 CO + 2NO + 1/2 O 2  2H 2 O + CO 2 + 2N 2 (2)

The basic difference between these process (SNCR an d SCR) is that in the SCR process reaction (1) is used and is assiste d through the use of a catalyst.

2.2.2.1 Selective Non – Catalytic Reduction (SNCR) The Selective Non – Catalytic Reduction (SNCR) proc ess is accomplished within the boiler and typically uses a mmonia (NH 3 ) or urea [(NH 2 ) 2 CO] as the chemical reagent. Either of those reage nts can be injected directly into the flue gas to react and reduce NOx according to reactions (1) or (2) above. The optim um reaction temperature for either reaction is in the range of 1600 to 2200 °F. This is a critical process parameter in that injection a t higher temperatures
(>2200 ° F) would result in the conversion of ammonia or ure a to NOx while injection at lower temperatures (<1600 ° F) would result in the reagent remaining un-reacted (increased quantities of ammonia slip).Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-16 7/25/08
©2008 Babcock Power Inc. All Rights Reserved Urea based SNCR uses an aqueous solution of urea (t ypically 30 – 50% by weight) while the ammonia process uses eithe r anhydrous or aqueous solution. The injection location of the re agent is important and should be given careful consideration. To allo w for better mixing and for variation of flue gas temperatures as a res ult of boiler load variations multiple injection ports and levels have been used in commercial applications of the SNCR process. The m ajority of experience with SNCR systems is with urea based sys tems. A typical utility SNCR system is shown in Figure A-6.

Figure A-6 - Typical SNCR system for utility boiler application

The temperature of flue gas at the point of reagent injection and the available residence time within the optimum reactio n temperature window along with mixing efficiency are the key ing redients in achieving maximum NOx reductions with the SNCR proc ess. The SNCR process can be retrofit to most if not all res idual oil fired utility

boilers however the NOx reductions achieved are ver y site specificMohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-17 7/25/08
©2008 Babcock Power Inc. All Rights Reserved since they are highly dependent on the temperature and residence time profiles of the individual boiler. It is therefore recommended that a study is performed to establish the residence times of the flue gases in the reaction temperature window, the location of th e temperature window, ease of access for installation of the reag ent injection ports at that temperature window, and the ability to achieve rapid and complete mixing of the reagent within that temperat ure window.

Typical boiler modifications and equipment required for retrofitting SNCR to a natural gas boiler include:

 Urea or ammonia loading and storage station includi ng safety equipment for the prevention of spills and reagent escape

 Reagent transport equipment, including pumps, flow meters, controls, heaters and carrying medium (e.g., air) i f required

 Reagent injection equipment (e.g., lances), install ation of furnace penetrations at the appropriate location

 Process control system to control injection rates a s a function of boiler load and NOx emissions levels required

A SNCR process schematic is shown in Figure A-7.

Figure A-7 - SNCR process schematicMohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-18 7/25/08
©2008 Babcock Power Inc. All Rights Reserved Typical capital costs of the SNCR process range fro m $20 to $40/kW. The cost of the reagents is a major operating expen se with the cost of ammonia and urea being tied to the cost of natural gas. Typical operating and maintenance (O&M) costs range from $1 to $5/kW-yr, while annualized technology costs are $3 - $30/kW.

An analysis of the Mohave units indicates that NOx emissions reductions using NSCR will be only on the order of 15 – 25% in addition to those achieved with OFA. The primary reasons for these l ow reductions are:

• Low NOx levels flowing into the SNCR control zone

• The unit’s physical size

• CO levels entering the SNCR

• Temperature levels present in the boiler

• Low available residence times in the appropriate te mperature window

2.2.2.2 Selective Catalytic Reduction (SCR) The Selective Catalytic Reduction (SCR) process inv olves the following two chemical reactions:

2NH 3 + 2NO + 1/2O 2  2N 2 + 3H 2 O (3)

4NH 3 + 2NO 2 + O 2  3N 2 + 6H 2 O (4)

Ammonia (NH 3 ) is injected and mixed with the products of combustion (flue gases) and reacts with NOx over a bed of catalyst producing molecular nitrogen and water vapor. The use of catalyst lowers the reaction temperature from the typical 16 00 – 2100 °F to a

600 – 800 °F. Since over 95% of the NOx contained in the flue gases consists of NO reaction (3) above is the predominan t reaction. Approximately one mole of ammonia (17 lbs by weight ) to one mole of NO (30 lbs by weight) is required to produce NOx emissions reductions of 90% at an ammonia slip (un-reacted) l evel of 2 ppm. The ammonia reagent is typically anhydrous or aqueo us ammonia or derived through the thermal hydrolysis of urea.

SCR catalysts generally consist of a base material such as titanium oxide (TiO 2 ) or a zeolite. The primary ingredient is vanadium pentoxide (V 2 O 5 ) including some other metals such as molybdenum, cobalt, tungsten, chromium, iron, nickel and chromi um. Structurally here are three basic types of catalysts:

o Honeycomb

o PlateMohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-19 7/25/08
©2008 Babcock Power Inc. All Rights Reserved o Corrugated

All three have been used in residual oil applicatio ns however the most commonly used has been the honeycomb. Catalyst is specified according to the NOx removal rate required, hours o f life, ammonia “slip”, space velocity, and pitch (e.g., the size o f each honeycomb). Typical pitch for heavy oil applications ranges bet ween 3.5 to 7 mm depending on the ash content of the fuel. The volu me of catalyst required depends on the operating temperature, NOx removal required, and gas flow (i.e., boiler size).

The vessel (reactor) where the reducing reaction ta kes place contains the catalyst and is typically located between the b oiler outlet and the air heater due to the NOx reduction reaction temper ature requirements (see Figure A-8).

Figure A-8 - Typical aqueous ammonia SCR system for utility boiler with separate reactor

In some applications where there is no available sp ace the SCR system

has been located close to the boiler stack downstre am of the air heater and other air pollution control devices. In those cases the flue gas needs to be reheated to achieve proper reaction tem peratures. The benefits of this approach is lower construction cos ts, reduced size of catalyst (clean flue gas), however increased operat ing costs due to the reheating of the flue gas and the increased capital costs (purchase ofMohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-20 7/25/08
©2008 Babcock Power Inc. All Rights Reserved gas – to – gas heat exchanger) make the overall cos ts of this design higher.

For natural gas applications the reactor can be a s eparate vessel or it can be part of the ductwork or as is commonly calle d “in-line” (see Figure A-9).

In-line SCR systems are typically applied to residu al oil and gas fired units. Due to the lower velocities (approximately half to one-third of typical flue gas velocities) required for the NOx r eduction reaction to take place in the catalyst laden reactor the existi ng ductwork is replaced with larger size.

Figure A-9 - In-line SCR system for natural gas-fir ed boiler

application

The addition of a SCR system is a major project, re quiring careful study and typically involves the following modifica tions and

additions:

o Reagent (ammonia or urea) transfer, storage and pum ping

station

o Reagent injection grid and mixing devicesMohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-21 7/25/08
©2008 Babcock Power Inc. All Rights Reserved o SCR system controls for reagent flow, temperature, boiler load, NOx emissions monitoring and control, and system sa fety

o Reactor and catalyst

o Structural considerations for both the reactor and boiler proper

o FD and ID fan upgrades including their electrical s ystem

o Boiler system upgrades (e.g., implosion study)

o Economizer modifications if necessary to achieve pr oper reactor temperatures over the boiler load range

A typical ammonia storage and supply system schemat ic for utility boiler application is shown in Figure A-10.

Figure A-10 - Typical ammonia storage and supply sy stem

The capital costs of the application of SCR to a na tural gas unit range from $70 to $120/kW depending on unit size, availab le space, and SCR design (separate versus “in-line” reactor). In -line SCR is less expensive. O&M costs average about $8/kW-yr while overall technology annualized costs average about $12/kW.

SCR systems have been applied extensively throughou t Japan, Europe and the U.S. In the U.S. approximately 100 GW of e lectric generation has been equipped with SCR systems and of those app roximately 6 GW are oil and natural gas fired units (mainly gas fired in California). The NOx removal efficiency has been averaging 85% t o 90% for all those units with levels as low as 10 ppm for gas fi red utility boilers.Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-22 7/25/08
©2008 Babcock Power Inc. All Rights Reserved The installation of SCR on a natural gas fired boil er would increase overall system pressure drop (approximately 6 – 8 i nches w.c.) resulting in increased fan power consumption and lo ss of overall plant efficiency.

The application of an in-line SCR system at the Moh ave units would require the following systems:

• Ammonia, or aqueous ammonia or urea storage and sup ply

system

• Modification to the boiler’s flue system (between e conomizer outlet and air heater inlet) to provide catalyst sp ace

• Catalyst

• Addition of mixing devices and reagent injection sy stem

• Control system additions and modifications

• Conversion of the unit to balanced draft

• Installation of ID fan(s) and necessary switchgear

It is estimated that the cost of in-line SCR additi on at the Mohave units will be in the order of $130 - $150 million. The cost of the conversion to balanced draft would increase the pro ject cost by an additional $30 - $50 million.Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-23 7/25/08
©2008 Babcock Power Inc. All Rights Reserved 3.0 WORK CITED

1. “North American Combustion Handbook” Volumes I & II, North American Manufacturing Company, Cleveland, OH, 2001 2. Afonso, R.F., et. al., “Salem Harbor 4/ Brayton Point 4: NOx Reduction Testing on Oil-Fired Boilers”, Presented at the EPRI NOx Co ntrols for Utility Boilers Workshop, 1992 3. “Module 6: Air Pollutants & Control Techniques - - Nitrogen Oxides” http://www.epa.gov/eogapti1/module6/nitrogen/contro l/control.htm#combust 4. Bisonett, G.L., et. al., “Comparative Assessment of NOx Reduction Techniques for Gas- and Oil-Fired Utility Boilers”, Proceeding s: 1991 Joint Symposium on Stationary NOx Control, EPRI Report GS-7447, Vol. 2 , 1991 5. “Alternative Control Techniques Document – NOx E missions from Utility Boilers”, US EPA Office of Air Quality Planning and Standards, EPA-453/R-94-
023, 1994 6. Hayden, J., et. al., “Advanced Overfire Air Retr ofit for Summer Ozone Compliance” http://www.fwc.com/publications/tech_papers/powgen/ pdfs/2403235.pdf 7. Kerho, S.E., et. Al., “Reduced NOx, Particulate and Opacity on the Kahe unit 6 Low NOx Burner System”, Proceedings: 1991 Joint Sym posium on Stationary NOx Control, EPRI Report GS-7447, Vol. 2, 1991 8. Frederick, N., et. al., “NOx Control on a Budget : Induced Flue Gas Recirculation”, Power Engineering, July 2003 9. Witkamp, J.G., et. al., “Demonstration of Advanc ed, Low NOx Combustion Techniques at the Gas/Oil – Fired Flevo Power Stati on unit 1” Proceedings:1991 Joint Symposium on Stationary NOx Control, EPRI Rep ort GS-7447, Vol. 2,

1991 10. Mormile, D.J., et. al., “NOx Inventory and Retr ofit Assessment”, Proceedings: 1987 Symposium on Stationary Combustion Nitrogen Ox ides Control, EPRI Report CS-5361, Vol. 2, 1987 11. McDannell, M.D., et. al., “Low NOx Levels Achie ved by Improved Combustion Modification on two 480 MW Gas – Fired Boilers”, Pr oceedings: 1991 Joint Symposium on Stationary Combustion NOx Control, EPR I Report GS-7447, Vol.
2, 1991 12. Horn, K., et. al., “Low NOx Combustion Modifica tions on a 300 MW Gas – and Oil – Fired Utility Steam Generator”, Proceedings P owerGen 1997, Dallas, TX 13. Srivastava, et. al., “Menu of NOx Emission Cont rol Options for Coal-Fired Electric Utility Boilers”, presented at the 2003 A& WMA Conference, San Diego,
CA, 2003 14. Bayard de Volo, N., et. al., NOx Reduction and Operational Performance of two Full – Scale Utility Gas/Oil Burner Retrofit Instal lations”, Proceedings: 1991 Joint Symposium on Stationary Combustion NOx Contro l”, EPRI Report GS7477, Vol. 2, 1991Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-24 7/25/08
©2008 Babcock Power Inc. All Rights Reserved 15. Yee, J.L.B., et. al., “Retrofit of an Advanced Low – NOx Combustion System at Hawaiian Electric’s Oil – Fired Kahe Generating Sta tion”, Proceedings: 1989 Symposium on Stationary Nitrogen Oxide Control, EPR I Report GS – 6423, Vol.
2, 1989 16. DeMichelle, G., et. al., “Application of Reburn ing Technologies for NOx Emissions Control on Tangentially, Oil – Fired Boil ers”, Presented at the EPRI NOx Controls for Utility Boilers Workshop, July 199 2 17. Nylander, J. H., et. al., “Demonstration of an Automated Urea Injection System at Encina Unit 2”, Proceedings: 1989 Symposium on Stat ionary Nitrogen Oxide Control”, EPRI Report GS-6324, Vol. 2, 1989 18. Abele, A. R., et. al., “Performance of Urea NOx Reduction Systems on Utility Boilers, Proceedings: 1991 Joint Symposium on Stati onary Combustion Nox Control, EPRI Report GS-7447, Vol. 2, 1991 19. “Flue Gas Recirculation Background” http://www.etecinc.net/index.cfm?area=ip&ip_page=ip &cat_id=4 20. Staudt, J., “Status Report on NO X Control Technologies and Cost Effectiveness for Utility Boilers”, Northeast States for Coordina ted Air Use Management,
Boston, MA, 1998 21. “Module 6: Air Pollutants & Control Techniques - - Nitrogen Oxides” http://www.epa.gov/eogapti1/module6/nitrogen/contro l/control.htm#noncat 22. Mussati, D.C., et. al., “Chapter 1 – Selective Non-catalytic Reduction (SNCR)”, EPA/452/B-02-001, October 2000 23. “Module 6: Air Pollutants & Control Techniques - - Nitrogen Oxides” http://www.epa.gov/eogapti1/module6/nitrogen/contro l/control.htm#cat 24. McLaughlin, B.R., et. al., “Selective Catalytic Reduction (SCR) Retrofit at San Diego Gas & Electric Company South Bay Generating S tation”, Presented at EPRI-DOE-EPA Combined Utility Air Pollutant Control Symposium, August

1997 25. Perry, J.H. editor, “Chemical Engineer’s Handbo ok”, Fourth Edition, 1969

26. 

### “Air Pollution Control Technology Fact Sheet – Sele ctive Non-Catalytic Reduction (SNCR)”, EPA-452/F-03-031

27. 

### “Air Pollution Control Technology Fact Sheet – Sele ctive Catalytic

Reduction” EPA-452/F-03-032

28. 

### Arai, M., “Flue Gas Recirculation for Low NOx Combu stion System”, Proceedings of 2000 International Joint Power Gener ation Conference, Miami FL, July 2000
29. “EPA Air Pollution Control Cost Manual”, Sixth Edition, EPA Report

EPA/452/B-02-001 30. Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units – Final Report to Congress”, EPA R eport EPA-453/R-98-004a, February 1998 31. Hunt, T., et. al., “Integrated Dry NOx/SO 2 Emissions Control System”, Final Report, Volume 1: Public Design, DOE Contract No. D E-FC-91PC90550,

November 1997Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential A-25 7/25/08
©2008 Babcock Power Inc. All Rights Reserved 32. Chu, P., et. al., “Power Plant Evaluation of th e Effect of SCR Technology on Mercury”, Presented at the Combined Power Plant Air Pollutant Mega Symposium, May 2003October 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500 

## Appendix B

Guidance on CALMET SettingsJuly 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500 National Park Service guidance on CALMET settingsJuly 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500 Excerpts from recent EPA Region IX guidance on BART modeling for Navajo Nation EGUs

1) CALMET settings

“After discussion with Federal Land Managers represent atives, we request the following changes to input switches for the CALMET meteorological processor:

• NOOBS = 0, to use both surface and upper observations;

• IEXTRP = -4, to extrapolate surface wind observations to the upper layers using similarity theory, and ignore layer 1 from the upper air soundings;

• ITPROG = 1, to use surface station temperature and the MM5 for upper air.

These settings are more appropriate for BART dete rmination modeling, as opposed to ‘subject to BART’ modeling that the WRAP modeling protocol addressed.”

2) Ammonia background

“We withdraw the request for additional reprocessing using a 1 ppb ammonia background concentration, as we believe the background values already used are appropriate.”October 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500 

## Appendix C

Factors Influencing NO
x 

## Emissions Effects on VisibilityJuly 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500 Secondary pollutants such as nitrates and sulfates are si gnificant contributors to the visibility extinction in Class I areas. The CALPUFF model was used to determine the effect of these pollutants on Class I areas, associated with the candidate BART control options . CALPUFF uses the E PA-approved MESOPUFF II

chemical reaction mechanism to convert SO 2 and NO

x emissions to secondary sulfates and nitrates. The discussion below describes how the secondary pollutants ar e formed and the factors affecting their formation.

Formation of Sulfates

The rate of transformation of gaseous SO 2 to ammonium sulfate (NH 4 ) 2 SO 4 aerosol is dependent upon solar radiation, ambient ozone concentration , atmospheric stability, and relative humidity, as shown in Figure C-1 (taken from the CALPUFF users guide, 2000). Ho mogeneous gas phase reaction is the dominant SO 2 oxidation pathway during clear, dry conditions (Calvert et al., 1978). CALPUFF assumes that the sulfate reacts preferentially with ammonia (NH 3 ) to form ammonium sulfate and that any remaining ammonia is available to form ammonium nitrate (NH 4 NO 3 ).

Figure C-1 MESOPUFF II SO 2 Oxidation

Formation of Nitrates

The oxidation of NO

x to nitric acid (HNO 3 ) depends on the NO

x concentration, ambient ozone concentration, and atmospheric stability. Some of the nitric acid is then combined with available ammonia in the atmosphere to form ammonium nitrate aerosol in an equilibrium state that is a function of temperature, relative humidity, and ambient ammonia concentration, as shown in Figure C-2 (from the CALPUFF users guide).

Figure C-2 MESOPUFF II NO

x Oxidation

In CALPUFF, total nitrate (TNO 3 =HNO 3 + NO 3 ) is partitioned into each species according to the equilibrium relationship between gaseous HNO 3 and NO 3 aerosol. This equilibrium is a function of ambient temperature and relative humidity. Moreover, the formation of ni trate strongly depends on avai lability and amount of NH 3 toJuly 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500 form ammonium nitrate , as shown in Figure C-3 (from CALPUFF courses given by TRC). The figure on the left shows that with 1 ppb of available ammonia and fixed temperature and humidity (for example, 275 deg K and 80% humidity), only 50% of the total nitrate forms particulate matter. When the available ammonia is increased to 2 ppb, as shown in the figure on the right, as much as 80% of the total ni trate is in the particulate form. Figure C-3 also shows that colder temperatures and higher relative humidity significantly favor nitrate formation and vice versa. A summary of the condi tions affecting nitrate formation are listed below:

• Colder temperature and higher relative humidity cr eate favorable conditions to form nitrate particulate matter, and therefore more a mmonium nitrate is formed;

• Warm temperatures and lower relative humidity create less favorable conditions to form nitrate particulate matter, and therefore less ammonium nitrate is formed;

• Sulfate preferentially scavenges ammonia over nitr ates. In areas where sulfate concentrations are high and ambient ammonia concentrations are low, there is less ammonia available to react with nitrate, and therefore less a mmonium nitrate is formed.

Figure C-3 NO 3 /HNO 3 Equilibrium Dependency on Temperature and Humidity

Ambient Ammonia Background Concentrations

CALPUFF modeling of the baseline and BART control options emissions was conducted with the following sets of background ammonia values. The actual ammonia values used for each of the eleven Class I areas

are listed in Table C-1.

• Class I areas located in areas of higher ammonia emission sources (shown in Figure B-4) and with mild winters are modeled with ammonia background of 1 ppb all year, in accordance with the WRAP BART protocol. These Class I areas are: Jos hua Tree W, San Gorgonio W, Agua Tibia W, San Jacinto W, Domeland W, and Cucamonga W. Th e ammonia background of 1 ppb is used to model the baseline, BART option 3 (LNB/OGA /FGR) and option 5 (LNB/OFA) emissions.

• Class I areas located in the region of sparse ammonia emission sources (shown in Figure B-4) and

with more substantial winter seasons are model ed with monthly variable ammonia background that have been approved for multiple PSD projects by the Federal Land Managers. The monthly ammonia background values are 0.2 ppb in January-February and December; 0.5 ppb in March-April and October-November; and 1 ppb in May-September). The Class I areas assigned these background values are Grand Canyon NP, Zion NP, Sycamore Canyon W, Pine Mountain W, and Mazatzal W.July 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500 The ammonia background values mentioned above were recently approved by the Federal Land managers for the nearby Toquop Energy Project (T EP) PSD permit application (northwest of Mesquite, Nevada) and also previously for the De sert Rock Energy Facility PSD permit application (Navajo Nation, New Mexico). These backg round ammonia values are based upon direct measurements (some in the Grand Canyon) as well as seasonal considerati ons. In general, it is important to note that the likely over-prediction by CA LPUFF of nitrates in winter as noted by Morris et al. (2005) can be partially addressed by usi ng a monthly variation of background ammonia concentrations. The default value of 1.0 ppb for arid lands as referenced in the IWAQM Phase 2 document (1998) is valid at 20°C, but the sa me document cites a strong dependence with ambient temperature, with variations of a factor of 3-4. This same dependence is seen at the CASTNET monitor at Bondville, Illinois (see page 5 at http://www.ladco.org/tech/ monitoring/docs_gifs/NH3proposal-revised3.pdf ). In addition, a study of light-affecting particles in southwest Wyoming indicated that nitrates were over-predicted by a factor of 3 for a constant ammonia concentration of 1.0 ppb, and by a factor of 2 for an ammonia concentration of 0.5 ppb (see

slide 57 at http://www.air.dnr.state.ga.us /airpermit/psd/dockets/longleaf /facilitydocs/050711_CALPUFF_eval.pdf ). Since there are no large sources of ammonia due to ag ricultural activities th e Class I areas in Arizona and Utah, it is appropriate to introduce a monthly varying ammonia background concentration to the CALPUFF modeling. These ammonia background c oncentrations without change (ignoring additional ammonia from the plant itself) for all BART options except for SNCR operation.

• Excess ammonia emissions associ ated with SCR as well as SNCR operations were modeled with

CALPUFF to determine the 8 th highest 24-hour ammonia conc entration averaged over three meteorological years in all Class I areas. Predict ed ammonia concentrations were less than 10% of the background ammonia concentrations at all Class I areas except for the Grand Canyon NP (winter months only ) for SNCR operation, so only the winter season background concentrations at the Grand Canyon were adjusted upward by 0.04 ppb (only fo r SNCR operation) to account for the additional ammonia due to plant emissions, as shown in T able C-1. The POSTUTIL program (CALPUFF postprocessor) was used to re-compute regional haze imp acts with the adjusted ammonia background at Grand Canyon.

As discussed above, the formation of nitrate is highly s ensitive to availability of ammonia to form ammonium

nitrate. Ammonium nitrate is a visibility-degrading pollutant. For the purpose of evaluating NO

x emissions control options, the ambient ammonia background concent rations at the Grand Canyon were refined to factor

in excess ammonia emission increases associated with SNCR operations. The installation of SCR creates slightly higher levels of primary sulfate emissions (H 2 SO 4 ) that were also accounted for in the CALPUFF modeling.July 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500 Table C-1 Ambient Ammonia Background Concentrations

Class I Area January – February March – April May – September October –

November December Modeling Option

0.2 0.5 1 0.5 0.2 baseline, 1-3, 5 Grand Canyon NP 0.24 0.5 1 0.5 0.24 4

Zion NP 0.2 0.5 1 0. 5 0.2 baseline, 1-5 Sycamore Canyon W 0.2 0.5 1 0.5 0.2 baseline, 1-5

Pine Mountain W 0.2 0.5 1 0.5 0.2 baseline, 1-5
Mazatzal W 0.2 0.5 1 0.5 0.2 baseline, 1-5
Domeland W 1 1 1 1 1 baseline, 1-5
Joshua Tree W 1 1 1 1 1 baseline, 1-5 San Gorgonio W 1 1 1 1 1 baseline, 1-5
Agua Tibia W 1 1 1 1 1 baseline, 1-5
San Jacinto W 1 1 1 1 1 baseline, 1-5 Cucamonga W 1 1 1 1 1 baseline, 1-5

Figure C-4 Ammonia Emissions DensityOctober 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500 

## Appendix D

Re-Calculating CALPOST Visibility Outputs with the New IMPROVE AlgorithmJuly 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500July 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500July 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500July 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500July 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500July 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500July 2008BART Determination for MGS: Natural Gas Firing06200-034--500July 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500July 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500July 2008BART Determination for MGS: Natural Gas Firing06200-034--500July 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500July 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500October 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500 

## Appendix E

CALPUFF Modeling Results and Gr aphic Charts using the New IMPROVE EquationJuly 2008BART Determination for MGS: Natural Gas Firing06200-034--500Table E-1 Regional Haze Results of Modeled BART Options for Each Met YearJuly 2008BART Determination for MGS: Natural Gas Firing06200-034--500Table E-1 Regional Haze Results of Modeled BART Options for Each Met YearJuly 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure E-1 8thHighest Visibility Impactdue to BART Option 18th Highest Regional Haze Impacts due to LNB+OFA+SCR (Stand Alone) Controls0.00.10.20.30.40.50.6Grand CanyonNPJoshua TreeNMZion NP SycamoreCanyon WAgua Tibia W Cucamonga W San GorgonioWSan Jacinto W Mazatzal W Pine MountainWDomeland WClass I Area

8th Highest deciviewMet Year 2001Met Year 2002Met Year 2003Met Year Ave 2001-2003July 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure E-2 8thHighest Visibility Impactdue to BART Option 28th Highest Regional Haze Impacts due to LNB+OFA+SCR (In-Line) Controls0.00.10.20.30.40.50.6Grand CanyonNPJoshua TreeNMZion NP SycamoreCanyon WAgua Tibia W Cucamonga W San GorgonioWSan Jacinto W Mazatzal W Pine MountainWDomeland WClass I Area

8th Highest deciviewMet Year 2001Met Year 2002Met Year 2003Met Year Ave 2001-2003July 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure E-3 8thHighest Visibility Impactdue to BART Option 38th Highest Regional Haze Impacts due to LNB+OFA+FGR Controls0.00.10.20.30.40.50.6Grand CanyonNPJoshua TreeNMZion NP SycamoreCanyon WAgua Tibia W Cucamonga W San GorgonioWSan Jacinto W Mazatzal W Pine MountainWDomeland WClass I Area

8th Highest deciviewMet Year 2001Met Year 2002Met Year 2003Met Year Ave 2001-2003July 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure E-4 8thHighest Visibility Impactdue to BART Option 48th Highest Regional Haze Impacts due to LNB+OFA+SNCR Controls0.00.10.20.30.40.50.6Grand CanyonNPJoshua TreeNMZion NP SycamoreCanyon WAgua Tibia W Cucamonga W San GorgonioWSan Jacinto W Mazatzal W Pine MountainWDomeland WClass I Area

8th Highest deciviewMet Year 2001Met Year 2002Met Year 2003Met Year Ave 2001-2003July 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure E-5 8thHighest Visibility Impactdue to BART Option 58th Highest Regional Haze Impacts due to LNB+OFA Controls0.00.10.20.30.40.50.6Grand CanyonNPJoshua TreeNMZion NP SycamoreCanyon WAgua Tibia W Cucamonga W San GorgonioWSan Jacinto W Mazatzal W Pine MountainWDomeland WClass I Area

8th Highest deciviewMet Year 2001Met Year 2002Met Year 2003Met Year Ave 2001-2003October 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500 

## Appendix F

CALPUFF Modeling Results and Gr aphic Charts using the Old IMPROVE EquationJuly 2008BART Determination for MGS: Natural Gas Firing06200-034--500TableF-1 Regional Haze Impacts Due to Baseline EmissionsJuly 2008BART Determination for MGS: Natural Gas Firing06200-034--500FigureF-1 8thHighest Regional Haze Impacts for Each Modeled Year Due to Baseline Emissions8th Highest Regional Haze Impacts due to Baseline Emissions0.00.51.01.52.02.53.03.54.04.5Grand CanyonNPJoshua TreeNMZion NP SycamoreCanyon WAgua Tibia W Cucamonga W San GorgonioWSan Jacinto W Mazatzal W Pine MountainWDomeland WClass I Area

8th Highest deciviewMet Year 2001Met Year 2002Met Year 2003Met Year Ave 2001-2003July 2008BART Determination for MGS: Natural Gas Firing06200-034--500Table F-2Regional Haze Results of Modeled BART Options for Each Met YearJuly 2008BART Determination for MGS: Natural Gas Firing06200-034--500Table F-2Regional Haze Results of Modeled BART Options for Each Met YearJuly 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure F-2 8thHighest Visibility Impactdue to BART Option 18th Highest Regional Haze Impacts due to LNB+OFA+SCR (Stand Alone) Controls0.00.10.20.30.40.50.60.70.8Grand CanyonNPJoshua TreeNMZion NP SycamoreCanyon WAgua Tibia W Cucamonga W San GorgonioWSan Jacinto W Mazatzal W Pine MountainWDomeland WClass I Area

8th Highest deciviewMet Year 2001Met Year 2002Met Year 2003Met Year Ave 2001-2003July 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure F-3 8thHighest Visibility Impactdue to BART Option 28th Highest Regional Haze Impacts due to LNB+OFA+SCR (In-Line) Controls0.00.10.20.30.40.50.60.70.8Grand CanyonNPJoshua TreeNMZion NP SycamoreCanyon WAgua Tibia W Cucamonga W San GorgonioWSan Jacinto W Mazatzal W Pine MountainWDomeland WClass I Area

8th Highest deciviewMet Year 2001Met Year 2002Met Year 2003Met Year Ave 2001-2003July 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure F-4 8thHighest Visibility Impactdue to BART Option 38th Highest Regional Haze Impacts due to LNB+OFA+FGR Controls0.00.10.20.30.40.50.60.70.8Grand CanyonNPJoshua TreeNMZion NP SycamoreCanyon WAgua Tibia W Cucamonga W San GorgonioWSan Jacinto W Mazatzal W Pine MountainWDomeland WClass I Area

8th Highest deciviewMet Year 2001Met Year 2002Met Year 2003Met Year Ave 2001-2003July 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure F-5 8thHighest Visibility Impactdue to BART Option 48th Highest Regional Haze Impacts due to LNB+OFA+SNCR Controls0.00.10.20.30.40.50.60.70.8Grand CanyonNPJoshua TreeNMZion NP SycamoreCanyon WAgua Tibia W Cucamonga W San GorgonioWSan Jacinto W Mazatzal W Pine MountainWDomeland WClass I Area

8th Highest deciviewMet Year 2001Met Year 2002Met Year 2003Met Year Ave 2001-2003July 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure F-6 8thHighest Visibility Impactdue to BART Option 58th Highest Regional Haze Impacts due to LNB+OFA Controls0.00.10.20.30.40.50.60.70.8Grand CanyonNPJoshua TreeNMZion NP SycamoreCanyon WAgua Tibia W Cucamonga W San GorgonioWSan Jacinto W Mazatzal W Pine MountainWDomeland WClass I Area

8th Highest deciviewMet Year 2001Met Year 2002Met Year 2003Met Year Ave 2001-2003July 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure F-7 8thHighest Visibility Impact due Five BART NOx Control Options8th Highest Regional Haze Impacts dueto Five BART NOx Controls Options0.00.10.20.30.40.50.60.7Grand CanyonNPJoshua TreeNMZion NP SycamoreCanyon WAgua Tibia W Cucamonga W San GorgonioWSan Jacinto W Mazatzal W Pine MountainWDomeland WClass I Area

2001-03 Ave 8th Highest dvLNB+OFA+SCR (Stand Alone)LNB+OFA+SCR (In-Line)LNB+OFA+FGRLNB+OFA+SNCRLNB+OFAJuly 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure F-8 Total Number of Days Removed Above 0.5 delta-dv Relative to the Baseline Case1505145714731483150102004006008001000120014001600LNB+OFA+SCR (StandAlone)LNB+OFA+SCR (In-Line) LNB+OFA+FGR LNB+OFA+SNCR LNB+OFA

# of Days RemovedJuly 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure F-9 Number of Days Removed at Each Class I Area Above 0.5 delta-dv Relative to the Baseline Case249238232222213 213 213 213121 121 121120287 287 287285116 116 116 1165165015045085152522131212871160100200300400500600LNB+OFA+SCR (StandAlone)LNB+OFA+SCR (InLine)LNB+OFA+FGR LNB+OFA+SNCR LNB+OFA

# of Days RemovedGrand Canyon NJoshua Tree NMZion NPSycamore Canyon W5 Other CA Class I Area2 Other AZ Class I AreaJuly 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure F-10 Annual Cost of NOx Controls vs. Visibility Improvements at the Closest Class I Areas010203040500.00.51.01.52.02.53.03.54.02001-2003 Average 8th Highest delta-dv

Cost at 12% Interest Rate (MM$/year)Grand Canyon NPJoshua Tree NPBaselineLNB+OFA+SNCRLNB+OFALNB+OFA+FGRLNB+OFA+SCRIn-LineLNB+OFA+SCRStand-AloneJuly 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure F-11 Annual Cost of NOx Controls vs. Visibility Improvements at the Other California Class I Areas010203040500.00.20.40.60.81.01.21.42001-2003 Average 8th Highest delta-dv

Cost at 12% Interest Rate (MM$/year)Agua Tibia WCucamonga WSan Gorgonio WSan Jacinto WDomeland WBaselineLNB+OFA+SNCRLNB+OFALNB+OFA+FGRLNB+OFA+SCRIn-LineLNB+OFA+SCRStand-AloneJuly 2008BART Determination for MGS: Natural Gas Firing06200-034--500Figure F-12 Annual Cost of NOx Controls vs. Visibility Improvements at the Other Non-California Class I Areas010203040500.00.20.40.60.81.01.21.41.62001-2003 Average 8th Highest delta-dv

Cost at 12% Interest Rate (MM$/year)Sycamore Canyon WMazatzal WPine Mountain WZion NPBaselineLNB+OFA+SNCRLNB+OFALNB+OFA+FGRLNB+OFA+SCRIn-LineLNB+OFA+SCRStand-AloneOctober 2008 BART Determination for MGS: Natural Gas Firing

06200-034--500 

## Appendix G

Projected NO x 

## Emissions on Natural Gas Over Mohave’s Future Operating Range Based on 2005 Actual Reporting for the Mohave Generating Station

# ANTICIPATED NOX EMISSIONS

OVER THE OPERATING RANGE

BASED ON 2005 ACTUAL REPORTING

FOR

MOHAVE GENERATING STATION

Date Issued: October 8, 2008Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential 7/21/08
©2008 Babcock Power Inc. All Rights Reserved This document was prepared solely for use by, and s olely for the benefit of Navasota Energy. Any other recipient of this document uses it withou t the permission of Riley Power and thereby releases Riley Power from liability of any kind. R iley Power has taken certain steps to evaluate possible changes to the Mohave Generating Station, but the information herein is not intended as a design, nor even a basis for design. Riley Power expressly disclaims any warranty, expressed or implied, with respect to use of the information or concepts disclosed in this document for any purpose other than that set o ut in the underlying contract between Riley Power and Navasota Energy.Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential -G- 10/8/08
©2008 Babcock Power Inc. All Rights Reserved 

## APPENDIX G:

Anticipated NOx Emissions Over the Operating Range Based on 2005 Actual Reporting

For Mohave Generating StationMohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential G-1 10/8/08
©2008 Babcock Power Inc. All Rights Reserved 1. NOx Emissions

An analysis was performed comparing NOx in lb/MBtu versus lb/hr NOx, at various boiler loads. To do this the hourly EPA NOx data f or 2005 Quarter 1 thru 4 was downloaded, this data is indicated as the blue data points on Figure 1 & 2 below. In order to mimic the same operating conditions while firing gas we applied a multiplier to the coal firing NOx data from 2005 to make the f ull load NOx average 0.10 lb/MBtu. Table 5 and Figures 1 & 2, show that ther e are load conditions where the unit would operate above the 0.10 lb/MBtu value. T his is especially important for a unit that will be cycling as the average may be ske wed by these transient operating

conditions.

Table 5 Example Case Analysis Comparing lb/MBtu and lb/hr NO

x Emissions

Figure 1 Mohave Unit 1 - NOx (lb/hr) vs Heat Input

EPA NOx Database 2005 Q1-4

0.00 500.00 1000.00 1500.00 2000.00 2500.00 3000.00 3500.00 4000.00

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000

Heat Input, MBtu/hrNOx, lb/hr

Gas Firing (Projected) Coal Firing (Actual 2005) Load, MW Heat Input, MBtu/hr NOx, lb/MBtu NOx, lb/hr

750 7500 0.1 750

500 5000 0.15 750

250 2500 0.07 175

<100 1000 0.2 200Mohave Generating Station U 1&2 Clark County, NV

Proprietary and Confidential G-2 10/8/08
©2008 Babcock Power Inc. All Rights Reserved Figure 2 Mohave Unit 1 - NOx vs Heat Input

EPA NOx Database 2005 Q1-4

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000

Heat Input, MBtu/hrNOx, lb/MBtu

Gas Firing (Projected) Coal Firing (Actual 2005)