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Home My WebLink About20023293.tiff STATE OF COLORADO Bill Owens,Governor Jane E. Norton,Executive Director ,c c6<o0 Dedicated to protecting and improving the health and environment of the people of Colorado rye�Mq. 0 4300 Cherry Creek Dr.S. Laboratory and Radiation Services Division * 4 Denver,Colorado 80246-1530 8100 Lowry Blvd. **�'"'•"'%*" Phone(303)692-2000 Denver,Colorado 80230-6928 te7e TDD Line(303)691-7700 (303)692-3090 Colorado Department Located in Glendale,Colorado of Public Health httpd/www.cdphe.state.co.us and Environment March 5,2002 U.S.EPA-Region 8 U.S.Forest Service Attn.:Ms.Meredith Bond Attn.: Ms. Laura Hudnell 999 18th St Ste 500 P.O.Box 25127 8P2-AR LAKEWOOD CO 80225 DENVER CO 80202 National Park Service-Air Resources Division a pe .:aate..y,s,Weld County Attn.: Mr.Don Codding w "r , P.O.Box 25287 GREELEY DENVER CO 80225-0287 Please make the enclosed PSD application available for public review. Re:Rocky Mountain Energy Center,LLC—Hudson Power Generation Facility Ladies/Gentlemen: Rocky Mountain Energy Center,LLC has submitted a PSD application. Enclosed herewith is a copy of the application. If you have any questions on this,please feel free to contact me at 303-692-3198. Please send in your comments at your earliest convenience. rely, Ram N.Seetharam • Professional Engineer Construction Permits Unit Stationary Sources Program Air Pollution Control Division • APCD-SS-B1 • ,;ZOO;;Z-3a93 j is(41/c ; etc) AL /5/<2? I • • � r . .. t APPLICATION FOR PREVENTION OF SIGNIFICANT DETERIORATION For the Rocky Mountain Energy Center Submitted by Rocky Mountain Energy Center, LLC 26 W. Dry Creek Circle, Suite 600 Littleton, Colorado 80120 Prepared by: RTP Environmental Associates, Inc. 2925 Puesta del Sol Santa Barbara, California 93105 (805) 569-6555 • RTP ENVIRONMENTAL RTa ASSOCIATES, INC. -~ AIR • WATER • SOLID WASTE ENVIRONMENTAL CONSULTANTS I • • • APPLICATION FOR PREVENTION OF SIGNIFICANT DETERIORATION For the: Rocky Mountain Energy Center • Submitted by: Rocky Mountain Energy Center, LLC 26 W. Dry Creek Circle, Suite 600 Littleton, Colorado 80120 Prepared by: RTP Environmental Associates, Inc. 2925 Puesta del Sol Santa Barbara, California 93105 (805) 569-6555 March 4, 2002 S • Table of Contents Page 1.0 Introduction 1-1 1.1 Project Schedule 1-2 1.2 Application Organization 1-2 2.0 Proposed Project Description 2-1 2.1 Proposed Project 2-1 2.1.1 Combustion Turbine/Heat Recovery Steam Generator 2-1 2.1.2 Cooling Tower 2-2 2.1.3 Steam Condensing Turbine 2-3 2.1.4 Ancillary Equipment 2-3 2.1.4.1 Emergency Backup Generator 2-3 2.1.4.2 Fire Pump 2-3 2.1.4.3 Auxiliary Boiler 2-3 2.1.4.4 Ammonia Storage 2-4 • 2.2 Fuels 2-4 2.3 Project Emissions 2-4 2.3.1 Criteria Pollutant Emissions 2-5 2.3.2 Noncriteria Pollutant Emissions 2-10 3.0 Regulatory Analysis 3-1 3.1 Prevention of Significant Deterioration (PSD) 3-1 3.2 Emission Standards 3-1 3.2.1 New Source Performance Standards 3-1 3.2.1.1 Subpart GG 3-2 3.2.1.2 Subpart Da 3-3 3.2.2 Title 4 (Acid Rain) Provisions 3-3 4.0 Regional and Site Description 4-1 4.1 Project Location 4-1 4.2 Population and Land Use 4-1 • • • • 4.3 Existing Climate 4-1 4.4 Existing Air Quality 4-3 4.5 Existing Soils and Vegetation 4-3 5.0 Analysis of BACT for NOR, PM lo, CO, VOC and SO, 5-1 5.1 BACT Analysis for the Combined Cycle Units 5-3 5.1.1 Analysis of Control Requirements for Nitrogen Oxides 5-3 5.1.2 Evaluation of Achieved in Practice 5-15 5.1.2.1 Achieved in Practice Criteria Evaluation for SCR 5-16 5.1.2.2 Achieved in Practice Criteria Evaluation for SCONOx 5-18 5.1.3 Evaluation of Ammonia Emissions 5-24 5.1.4 Analysis of Control Requirements for Carbon Monoxide 5-31 5.1.5 Analysis of Control Requirements for PM10 5-35 5.1.6 Analysis of Control Requirements for VOC 5-40 5.1.7 Analysis of Control Requirements for SO, 5-42 5.2 BACT Analysis for the Cooling Tower 5-43 . 5.3 BACT Analysis for the Auxiliary Boiler 5-44 5.3.1 Analysis of Control Requirements for Nitrogen Oxides 5-44 5.3.2 Analysis of Control Requirements for Carbon Monoxide 5-50 5.3.3 Analysis of Control Requirements for PM10 5-52 5.3.4 Analysis of Control Requirements for VOC 5-53 5.3.5 Analysis of Control Requirements for SO, 5-55 5.4 BACT Analysis for the Emergency Generator and Fire Pump 5-55 6.0 Emissions Inventory 6-1 7.0 Air Quality Modeling Analysis 7-1 7.1 Overview of the Modeling Process 7-1 7.2 Goals of the Air Quality Modeling Analysis 7-1 7.3 Existing Meteorological and Air Quality Data 7-3 7.4 Site Representation 7-4 7.5 Background Concentration 7-7 • ii • 7.6 Auer Land Use Analysis 7-8 7.7 Air Quality Dispersion Models 7-8 7.7.1 Simple, Complex, and Intermediate Terrain Impacts 7-9 7.7.2 Ambient Ratio Method 7-11 7.7.3 Good Engineering Practice Stack Height and Downwash 7-11 7.7.3.1 Good Engineering Practice Stack Height 7-11 7.7.4 Receptor Selection 7-14 7.8 Load Screening 7-18 7.9 Significant Impact Analysis 7-19 7.10 PSD Increment Consumption Analysis 7-19 7.11 Comparison of Impacts to NAAQS and CAAQS 7-20 7.12 Pre-and Post-Construction Air Quality Monitoring Requirements 7-20 7.13 Additional Impacts Analysis 7-20 7.14 Class I & Sensitive Class II Area Impacts 7-21 7.14.1 CALPUFF Dispersion Model 7-22 • 7.14.2 CALPOST Model Options 7-25 7.14.2.1 Nitrogen Deposition on Soils 7-25 7.14.2.2 Nitrogen Deposition on Sensitive Lakes 7-25 7.14.3 Visibility Analysis 7-26 7.15 Increment Consumption and Cumulative Impacts 7-27 8.0 Air Quality Impact Analysis 8-1 8.1 Load Screening Analysis 8-1 8.2 Refined Air Quality Impact Analysis 8-3 8.3 Turbine Startup 8-7 8.4 Preconstruction Monitoring 8-8 8.5 Results of the Ambient Air Quality Modeling Analyses 8-9 8.6 PSD Increment Consumption 8-9 8.7 Impacts to Class I Area, Integral Vistas, and Sensitive Lakes Analysis 8-12 8.7.1 Results of Distant Field Visibility Modeling 8-16 • iii • • . 8.7.2 Effects to Sensitive Lakes 8-19 8.8 Impacts on Class II Areas 8-21 8.8.1 Potential Stack Emission Effects on Soil and Vegetation 8-21 9.0 Socioeconomic and Growth Impacts 9-1 9.1 Socioeconomic Impacts 9-1 9.2 Growth Inducing Impacts 9-1 10.0 Summary and Conclusions 10-1 References Appendix A APENs Appendix B Emissions Calculations and Data Sheets Appendix C Concentration Isopleth Maps Appendix D Modeling input/output files on CD FIGURES Figure 2-1: Rocky Mountain Energy Center Project Location(end of Section 2.0) • Figure 7-1: Denver Stapleton International Airport Wind Rose Figure 7-2: Building, Structures, and Stacks Included In Building Downwash Analysis Figure 7-3: RMEC Coarse Grid Receptors Figure 7-4: RMEC Downwash/Fenceline Receptors Figure 7-5 RMEC Fine Grid Receptors TABLES Table 2-1: Typical Chemical Characteristics & Heating Value of Natural Gas Table 2-2: Maximum Sort Term Pollutant Emission Rates Each Gas Turbine Table 2-3: Max Pollutant Emission Rates Each Turbine with Duct Burner/Power Augmentation Table 2-4: Maximum Pollutant Emission Rates Auxiliary Boiler Table 2-5: Maximum Pollutant Emission Rates Emergency Generator Set(1984 Hp) Table 2-6: Maximum Pollutant Emission Rates Fire Pump Engine(182 Hp) Table 2-7: Maximum Device Heat Input Rates(HHV) (MMBtu) • iv • • • Table 2-8: Maximum Facility Startup Emission Rates Table 2-9: Emissions from New Equipment Table 2-10: Noncriteria Pollutant Emissions for the RMEC Table 4-1: Background Air Quality Values Table 4-2: Summary of Soil Types Found at Power Plant and Wellfield Areas Table 5-1: NOX Control Technologies Ranked by Effectiveness Table 5-2: Comparison of SCR and SCONOx Removal Technologies Table 5-3: NOx Control Technologies Ranked by Ammonia Emissions Table 5-4A: SCR Costs (Per Gas Turbine/HRSG) Table 5-4B: SCONOx Cost and Incremental Cost(Per Gas Turbine/HRSG) Table 5-4C: SCONOx Incremental Cost(Per Gas Turbine/HRSG) Table 5-4 Notes: SCONOx Cost Effectiveness Analysis Table 5-5: Summary of CO BACT Evaluation Results Table 5-6: Oxidation Catalyst Costs (per Gas Turbine/HRSG) Table 5-7: NOX Control Technologies Ranked by Effectiveness • Table 7-1: Building Dimensions for RMEC Air Quality Modeling Table 8-1: Load Screening Results for RMEC (Turbines) Table 8-2: Load Screening Results for RMEC (Emergency Equipment) Table 8-3: ISCST3 Model Input Data: Source Characteristics for Refined Modeling Table 8-4: Emission Rates Stack Parameters for Modeling Analysis for Startup Emission Impacts Table 8-5: APCD PSD Preconstruction Monitoring Exemption Levels Table 8-6: Modeled Maximum Project Impacts Table 8-7: Comparison of Emissions Increase with PSD Significance Emission Levels Table 8-8: APCD PSD Levels of Significance Table 8-9: Comparison of Maximum Modeled Impacts and PSD Significance Table 8-10: Evaluation of Preconstruction Monitoring Requirements Table 8-11: Class I & Sensitive Class II Areas and Integral Vistas Evaluated Table 8-12: Land Use Parameters Table 8-13: Receptor Rings Used in the CALPUFF Modeling • v • • • Table 8-14: Model-Predicted Class I Area PSD Increment Consumption Table 8-15: Model-Predicted change in Light Extinction Table 8-16: CALPOST Output for Rocky Mountain Nat'l Park Visibility Analysis Table 8-17: Nitrogen and Sulfur Deposition Rates Table 8-18: CALPUFF Predicted Nitrogen Deposition Rates for Rocky Mountain.Nat'l Park Table 8-19: ANC Calculations for Sensitive Lakes • • vi • 1.0 INTRODUCTION Rocky Mountain Energy Center,LLC (RMEC)is proposing to build a new power generating facility near the town of Hudson, Colorado. The project will be called the Rocky Mountain Energy Center (RMEC).The plant site is located just east of the town of Hudson and is bounded by CR 49 to the west, CR 16 to the north,and CR 51 to the east. The site location in Universal Transverse Mercator(UTM) coordinates is 534491 meters Basting, 4437767 meters northing. Figure 1 shows the general site location of the power plant. The power plant site is currently zoned agricultural with a Use by Special Review Permit and is located adjacent to an existing commercial/industrial area of the town of Hudson to the west and agricultural land uses with scattered residences to the east and west. The RMEC will have the capacity to generate a nominal 600 megawatts(MW)of electrical power with a peak capacity up to 630 MW. The facility is expected to be a major source of oxides of nitrogen (NO,),carbon monoxide(CO),particulate matter with an aerodynamic diameter of 10 microns,or less (PM10),and volatile organic compounds(VOCs).Emissions of sulfur dioxide(SO2)are expected to be • minor. Following Colorado State Regulation No.3,Part B IV.D.3 and 40 CFR Part 52,these emission rates will trigger the requirements of the Prevention of Significant Deterioration(PSD)permit program. The proposed Project comprises construction of two(2)Westinghouse 501F combustion turbine(CT) units, two (2) heat recovery steam generators (HRSG), a thirteen (13) cell cooling tower, one (1) condensing steam turbine generator(CSTG),a 129 MMBtu/hr(HHV)natural gas fired auxiliary boiler, and a diesel fueled emergency generator and fire pump. Except for the emergency equipment, the facility will be fueled exclusively by natural gas. Each HRSG will have the capacity to fire up to 659 MMBtu/hr(HHV)of natural gas. Each of the two(2)combustion turbines will incorporate dry low- NOx combustion systems that will limit NO,emissions to 25 ppmv. Each HRSG will incorporate low NOx burners and Selective Catalytic Reduction(SCR)system to further control NOx down to 3.0 ppm,,. Each turbine/HRSG combination will also incorporate a CO catalyst that will limit CO emissions to 9 ppm,,. The auxiliary boiler will incorporate low NOx burners to limit emissions of NOx to 30 ppmv. Steam produced in the HRSGs will be used to drive the CSTG,which can produce additional electric • generation. 1-1 • • 1.1 Project Schedule The project will be constructed in the following phases: • Permitting and Management Approval • Engineering and Procurement • Construction • Startup/Testing • Commercial Operation RMEC understands that this is a very aggressive schedule. To support an expeditious approval,RMEC will provide technical support to the staff by making technical staff available on an as-needed basis from the following companies: Siemens Westinghouse --- Combustion Turbine Technology Calpine --- Overall Project Design RTP Environmental --- Environmental Technology and Air Quality Analysis The Permitting and Contract Negotiation in support of the Project was initiated in January 2001. This • Air Permit Application is being submitted in February 2002.Key milestones for the permit application will be the completeness determination for this application,and the issuance of the construction permit. The Engineering and Procurement phase of the Project was initiated in September 2001 with preliminary engineering. The detailed engineering will start in February 2002 and be completed in March 2003. Procurement(order, fabrication,and delivery)will be completed by October 2003. The Construction phase of the Project is scheduled to begin in July 2002 and to be completed in February 2004. The Start-up phase of the Project is scheduled to be completed within 2 months. The Commercial Operation phase,when full Project availability is achieved,is anticipated to occur within 60 days after completion of construction. 1.2 Application Organization This application is organized into 10 sections and 2 appendices: • 1-2 • • • Section 1.0 Introduction provides a basic introduction to the proposed Project and the organization of this document. Section 2.0 Project Description describes the proposed new facilities and associated equipment. Section 3.0 Regulatory Analysis contains discussions of the applicability of new source review(NSR)rules,and new source performance standards (NSPS). This section also discusses the applicability of tribal,state and local air quality regulations. Section 4.0 Regional and Site Description contains information pertaining to the proposed Project including geographic information; site location and topographic indicating the locations of existing and proposed facilities and units. • Section 5.0 Analysis of Best Available Control Technologies for NOx, PM10, CO, VOC and SO2 presents the analysis of control requirements conducted to determine best available control technology (BACT) for the Project, including a review of the EPA's RACT/BACT/LAER information service (RBLIS) database and a review of applicable NOR, PMia, VOC, and CO control technologies. Section 6.0 Emissions Inventory presents pollutant specific emission rates and stack parameters of each proposed new source and the basis for the values presented. • 1-3 • r • Section 7.0 Air Quality Modeling Analysis describes the air quality dispersion modeling analysis conducted to demonstrate that the impacts associated with the Project will not adversely impact existing air quality or exceed the available increment(s). This section includes a discussion of model selection, methodology, and inputs, as well as results of the analysis. Section 8.0 Air Quality Impact Analysis describes the assessment of the impacts of air, ground, and water pollution on soils, vegetation, and visibility caused from the Project and any Project-associated growth. Impacts to Class I areas were also assessed as part of this section. Section 9.0 Socioeconomic and Growth Impacts describes the impacts of the project on local infrastructure and economics. . Section 10.0 Summary and Conclusions Appendix A contains APENS for each piece of combustion equipment. Appendix B contains emission calculation information and data sheets. Appendix C presents concentration isopleth maps, details of the modeling methodology used to determine ambient air concentrations. Appendix D contains the modeling input/output files on Compact Disk. This document was prepared for RMEC by RTP Environmental Associates,Inc.(RTP). The primary project contact for the PSD Permit Application is: • 1-4 • Gregory Darvin RTP Environmental Associates, Inc. 2925 Puesta del Sol Santa Barbara, CA 93105 (805) 569-6555 Questions pertaining to this document should be directed to Gregory Darvin. • 1-5 • 2.0 PROPOSED PROJECT DESCRIPTION The energy facility will consist of two(2)Westinghouse 501 F natural gas combustion turbines(CT), two (2) 659 MMBtu/hr supplementary fired heat recovery steam generators (HRSG) each equipped with duct burners(DB), one (1) condensing steam turbine generator (CSTG), a thirteen (13) cell cooling tower, a diesel emergency backup generator, and a diesel fired fire pump. The CTs will be operated in a combined cycle configuration. The combustion turbines and duct burners will be fueled exclusively by natural gas. As shown, steam produced by the three HRSGs will be directed to the CSTG. The RMEC facility will have a gross electric generating capacity of up to 630 MW. Electricity generated by the combustion turbines and the CSTG will be distributed to the local utility electric power grid. A diesel fuel-fired 2084 horsepower(1545 kW)emergency backup generator will also be used to maintain power to the facility during utility outages. A small(182 horsepower)diesel fuel-fired fire pump will also be located on site and will be deployed only in case of a fire at the facility. The emergency generator and fire pump will be periodically tested at least one hour per week. A plot plan is included at the end of this section.Equipment not shown in detail on the plot plan but included in the project is the electrical switchyard and electrical equipment such as transformers,transmission lines, • and switchyard interconnections, and other miscellaneous equipment and facilities. 2.1 Proposed Project This section presents additional details regarding the combustion turbines/heat recovery steam generators, cooling tower, and condensing steam turbine, as well as equipment configuration and operation. 2.1.1 Combustion Turbine/Heat Recovery Steam Generator The two(2)new CTs will be Siemens Westinghouse 501 FD gas turbines equipped with dry low-NOx combustion systems. The heat input rating for each CT at ISO conditions is approximately 1785 MMBtu/hr(I II IV). The hot CT exhaust will be ducted to its associated HRSG,where the exhaust heat will be used to generate up to 2,300 psia steam for electric power generation via the CSTG. Auxiliary or supplemental duct firing is included as a part of each CT/HRSG. The rated heat input capacity of each duct burner is 659 MMBtu/hr(HHV). Auxiliary duct firing will be used to increase • electric power production during periods of peak electric demand. Based on preliminary design 2-1 • • • information,the total steam production from each HRSG is estimated at 1,600,000 and 760,000 lbs/hr for operation with and without duct firing, respectively, with the CTs operating at average ambient conditions. A selective catalytic reduction(SCR)system and CO catalyst is being proposed to control emissions from the combustion turbines and duct burners. The plot plan at the end of this section presents the basic configuration diagram of the CT/HRSGs. 2.1.2 Cooling Tower A cooling water system will provide cooling to condense the steam coming from the steam turbine. The cooling water system will use a 13 cell, induced draft cooling tower with a circulating water flowrate of 174,268 gpm, operating at up to 10 cycles of concentration. The water that is circulated through the cooling tower is considered non-contact cooling water. A high efficiency mist eliminator with a typical drift rate of 0.001 percent of the water circulation rate is being proposed to limit emissions of PM1o. Cooling tower PKo emissions were calculated based on the total dissolved solids in the circulating • water and the drift rate. EPA's AP-421 provides available particulate emission factors for wet cooling towers. AP-42 states that "a conservatively high PKo emission factor can be obtained by (a) multiplying the total liquid drift factor by the TDS fraction in the circulating water,and(b)assuming that once the water evaporates, all remaining solid particles are within the PKo range." (Italics per EPA). As this overestimates the total PM 10 formation,it was assumed that fifty percent of the total PM would be in the form of PMto• If TDS data for the cooling tower are not available,a source-specific TDS content can be estimated by obtaining the TDS for the make-up water and multiplying it by the cooling tower cycles of concentration. [The cycles of concentration is the ratio of a measured parameter for the cooling tower water(such as conductivity,calcium,chlorides,or phosphate)to that parameter for the make-up water.] Using AP-42 guidance,the total particulate emissions(PM)(after the pure water has evaporated)can be expressed as: • 2-2 • • PM= Water Circulation Rate x Drift Rate x TDS [1] Then,in the calculation of PMio,fifty percent of total PM was assumed to be PM10. For the proposed project,the cooling tower with a water circulation rate of 174,268 gallons per minute(gpm),drift rate of 0.001%,and TDS of 10,000 ppmw produces an emission rate of 8.71 lb/hr. On an annual basis,this is equivalent to 38.15 tpy. However, as stated above, only a very small fraction is actually PM10. Therefore, hourly PM10 from the cooling tower is 4.35 lb/hr, while on an annual basis, this is equivalent to 19.07 tpy. 2.1.3 Steam Condensing Turbine A new condensing steam turbine/electric generator rated at 508 MW is included as part of the proposed project. Steam produced by the HRSGs will be used to drive the CSTG. 2.1.4 Ancillary Equipment In addition to the above devices,the following ancillary equipment will also be located at the existing facility: • 2.1.4.1 Emergency Backup Generator A 1984 horsepower(1545 kW)diesel fuel-fired generator will be used to provide power to the facility during utility outages. This unit will only operate when both(2)CTs are not operating and there is no power available from the grid and during periods of periodic testing. 21.4.2 Fire Pump One (1) 180 hp diesel fuel-fired fire pump will only be used in the event of fire and there is no power available from the grid,and during periods of periodic testing. 2.1.4.3 Auxiliary Boiler One (1) 129 MMBtu/hr(HHV) auxiliary boiler is proposed for the project. The auxiliary boiler will only be used when one or more of the CT/HRSGs are not operating. The purpose of the auxiliary boiler is to maintain a temperature in the steam condensing turbine and HRSGs and vacuum in the condenser,thus allowing the facility to be started quickly. 2-3 • 2.1.4.4 Ammonia Storage Two anhydrous ammonia tanks with a maximum capacity of 12,000 gallons each will be located on site. 2.2 Fuels The combustion turbines and duct burners will be fired exclusively with natural gas. Table 2-1 presents the natural gas properties used as the basis for this application. Table 2-1: Typical Chemical Characteristics and Heating Value of Natural Gas Constituent Mole Nitrogen 0.857 CO2 1.98 Methane 89.6 Ethane 5.857 Propane 1.14 1110 n-Butane 0.19 Isobutane 0.146 n-Pentane 0.042 Isopentane 0.057 n-Hexane 0.057 BTU/SCF 1057 2.3 Project Emissions Natural gas combustion results in the formation of NO,,SO2,VOC,PM40,and CO.Because natural gas is a clean burning fuel,there will be minimal formation of combustion PMio and SO2.The combustion turbines will be equipped with dry low-NO,combustors that minimize the formation of NO„and CO. To further reduce NO,emissions, selective catalytic reduction(SCR)control systems will be utilized. Similarly,the duct burners and auxiliary boiler will also be equipped with a low-NO„burner design that minimizes NQ formation. A CO catalyst will be incorporated into the turbine/HRSG in order to further reduce emissions of carbon monoxide. • 2-4 • Various noncriteria pollutants will also be emitted by the facility, including ammonia(NH3), which is used as a reactant by the SCR system to control NOx,and sulfate(or secondary particulate matter)due to the oxidation of the SO2 emitted by the facility.Emissions of all of the criteria and noncriteria pollutants have been characterized and quantified in this application. 2.3.1 Criteria Pollutant Emissions The emissions sources at the RMEC include two gas turbines with heat recovery steam generators equipped with supplemental burners(duct burners), and a wet, mechanical-draft cooling tower,plus minor auxiliary equipment(emergency generator and fire pump engine). The actual operation of the turbines will range between 70 percent and 100 percent of their maximum rated output. Supplemental firing will be provided by the duct burners as needed to achieve the required power generation level. Steam injection into the combustion turbines (power augmentation, or PAG) will also be used to increase power output under certain conditions. Emission control systems will be fully operational during all operations except during startups and shutdowns. Maximum annual emissions are based on operation of the RMEC at maximum firing rates and envelope the expected maximum number of • startups that may occur in a year. Each turbine startup will result in transient emission rates until steady-state operation for the gas turbine and emission control systems is achieved. Ambient air quality impact analyses for the site have been conducted to satisfy the Air Pollution Control Division(APCD)requirements for criteria pollutants(NO2, CO,VOC,PM10,and SO2)on a pollutant-specific basis. It should be noted that the operational scenarios having the highest emissions rates do not necessarily produce the highest ambient impacts. The gas turbine,duct burner,and auxiliary boiler emission rates have been estimated from vendor data, RMEC design criteria, and established emission calculation procedures. The emission rates for the combustion turbines alone,the combustion turbines with duct burners and power augmentation,the auxiliary boiler,and the IC engines are shown in the following tables 2-2 through 2-6. • 2-5 • Table 2-2. Maximum Short Term Pollutant Emission Rates—Each Gas Turbine'. Pollutant ppmvd @ 15% O2 lb/MMBtu` lb/hr NOx 3.0b 0.0134 24.0 CO 9.00b 0.0241 43.0 VOC 2.00 0.0025 4.5` PM,od - 0.0062 11.0 SO2e 0.120 0.0007 1.3 Basis: 'Emission rates shown reflect the highest value with no power augmentation, and no duct burners at any operating load except startup and shutdown. bRMEC design criteria. `Pounds per hour provided by vendor; ppm and lb/MMBtu calculated from lb/hr. d100 percent of particulate matter emissions assumed to be emitted as PM,°; PM,()emissions include both front and back half as those terms are used in USEPA Method 5. 'Based on maximum fuel sulfur content of 0.25 grains/100 SCF. • Table 2-3. Maximum Short Term Pollutant Emission Rates—Each Turbine With Duct Burner And Power Augmentation. Pollutant ppmvd @ 15% O2 lb/MMBtu` lb/hr NO„ 3.0a 0.0108 25.0 CO 9.0a 0.0199 46.0 VOC 2.0 0.0025 5.86 PM1o` - 0.0076 17.6 SO2d 0.12 0.0006 1.4 Basis: aRMEC design criteria. "Pounds per hour provided by vendor; ppm and lb/MMBtu calculated from lb/hr. `100 percent of particulate matter emissions assumed to be emitted as PM1o; PM,()emissions include both front and back half as those terms are used in USEPA Method 5. °Based on maximum fuel sulfur content of 0.25 grains/100 SCF. S 2-6 • Table 2-4: Maximum Pollutant Emission Rates Auxiliary Boiler' Pollutant ppmvd @ 3% 02 lb/MMBtu lb/hr NO„ 30b 0.0380 4.9 CO 50e 0.0388 5.0 VOC 10n 0.0047 0.6 pm led N/A 0.0186 2.4 SO2' 0.359e 0.0007 0.09 Notes: 'Emission rates shown reflect the highest value at any operating load, excluding startup b Vendor guarantee. °MEC specification. °100 percent of particulate matter emissions were assumed to be emitted as PM10; Ph/lio emissions include both front anc back half as those terms are used in USEPA Method 5. °Based on maximum fuel sulfur content of 0.25 grains/100 SCF Table 2-5. Maximum Pollutant Emission Rates—Emergency Generator Set(1984 Hp). Pollutant g/bhp-hr lb/hr tons/yr NO„ 6.9 31.7 0.75 CO 8.5 39.05 0.9 VOC 1.0 4.59 0.115 PMI° 0.40 1.84 0.044 SO2 Neg 0.654 0.0163 Notes: Emission rates shown reflect the highest value at any operating load per vendor guarantee. Tons/yr based on max operation hours of 30 minute tests at 50% load and 200 tests/yr. 100 percent of particulate matter emissions were assumed to be emitted as PM10; PM10 emissions include both front and back half as those terms are used in USEPA Method 5. EPA AP-42, Table 3.2- 2. SO2 emissions based on maximum fuel sulfur content of 0.05%wt. • 2-7 • • Table 2-6. Maximum Pollutant Emission Rates—Fire Pump Engine (182 Hp). Pollutant g/bhp-hr lb/hr tons/yr NO, 5.89 2.36 0.236 CO 3.55 1.42 0.142 POC 0.73 0.29 0.0290 PM10 0.25 0.10 0.010 SO2 neg 0.063 0.0063 Notes: Emission rates shown reflect the highest value at any operating load per vendor guarantee. Tons/yr based on max operation of 200 hrs/yr. 100 percent of particulate matter emissions were assumed to be emitted as PM1o; PM10 emissions include both front and back half as those terms are used in USEPA Method 5. SO2 based on maximum fuel sulfur content of 0.05%wt. The maximum firing rates,daily and annual fuel consumption rates,and operating restrictions define the allowable operations that determine the maximum potential hourly and annual emissions for each pollutant. These allowable operations are typically referred to as'the operating envelope"for a facility. The maximum heat input rates(fuel consumption rates)for the gas turbines,and gas turbines with duct burners, and the IC engines are shown in Table 2-7. i Table 2-7. Maximum Device Heat Input Rates (HHV) (MMbtu). Gas Turbines w/ Gas Turbines w/o Emergency Emergency Fire Period Duct Burners' Duct Burners" Generator Set Pump Per Hour 2311 1785 -6.51d -1.26 Per Year` 10,630,600 6,611,640 --1301d -252 Notes: a Based on maximum heat input for full load operation at 90 deg. F plus duct burner with power augmentation. Based on maximum heat input for full load turbine operation at 3 deg. F. `Daily and annual heat input rates are highly variable due to the wide capability of the turbines and duct burners to operate at various loads on a daily and annual basis. d Emergency generator limited to 30 minute tests. Natural gas @ 1057 btu/scf(HHV), #2 diesel fuel @ 137,000 btu/gal (EPA AP-42), see App A, Table A-9 for approximate fuel use calculations. Maximum emission rates expected to occur during a startup or shutdown are shown in Table 2-8.PM10 and SO2 emissions have not been included in this table because emissions of these pollutants will be • 2-8 • • • lower during a startup period than during base load facility operation. Up to 456 turbine startup hours are expected to occur on an annual basis. This includes 52 cold starts, which are a three-hour event, and 300 warm starts,which are 1-hour events. Thus,the short-term and annual emissions profile for each turbine/I-IRSG include these cold/warm starts and were included in the modeling analysis. Table 2-8. Maximum Facility Startup Emission Rates'. NOx CO POC Cold Start, lb/hour 80 838 16 Cold Start, lb/startb 240 2,514 48 Hot Start, lbs/start° 80 902 16 'Estimated based on vendor data and source test data. See Appendix B °Maximum of three hours per cold start. `Maximum of one hour per hot start. The analysis of maximum facility emission levels was based on the pollutant emission factors shown in Tables 2-2, 2-3, and 2-4; the RMEC operating envelope shown in Table 2-5; and the RMEC startup • emission rates shown in Table 2-6. The annual emissions for the turbines were calculated based on a turbine capacity factor of 100 percent, with 456 hours in startup mode. For some pollutants, turbine emissions vary based on ambient temperatures. Annual emissions have been calculated assuming an average ambient temperature of 50 degrees Fahrenheit for 5,360 hours. It was assumed that up to 4,600 hours of duct burner and power augmentation would occur and this is typically associated with high temperature conditions. In addition,up to 456 turbine start hours (52 cold starts and 300 warm starts) were included in the annual emissions profile. Base mode operation(no power augmentation and duct burner operation)would occur for 5,360 hours per year. The maximum annual and hourly emissions for RMEC are shown in Table 2-9. Detailed emission calculations appear in Appendix B. Emissions from the cooling tower were calculated from the maximum cooling water TDS level and assumed 8,760 hours of operation. Auxiliary boiler emissions characteristics are also shown in Appendix B. i 2-9 • r • Table 2-9: Emissions From New Equipment' Maximum Hourly Emissions NO„ SO2 CO VOC PMto (lb/hr) Turbines and Duct Burners" 105.0 2.7 948.0 21.8 28.6 Cooling Tower - - - - 8.71 Auxiliary Boiler 4.9 0.09 5.0 0.6 2.4 Emergency Generator` 7.55 0.163 9.3 1.15 0.44 Fire Pump Engine` 2.36 0.063 1.42 0.29 0.1 Total Project (lb/hrd) 117.45 2.95 962.3 23.55 40.15 Maximum Annual Emissions, (tpy) Turbines and Duct Burners" 240.40 11.80 782.2 50.6 126.8 Cooling Tower - - - - 38.15 Auxiliary Boiler 4.7 0.05 2.75 0.570 2.28 Emergency Generator 0.75 0.0163 0.9 0.115 0.0437 Fire Pump Engine 0.236 0.0063 0.142 0.0290 0.010 Total Project(tons/yrd) 246.1 11.9 785.9 51.3 167.3 Notes: • 'See Appendix B for calculations. "Includes startup emissions. `Emergency generator and Diesel fire pump engine will not be tested on the same day or same hour. °Numbers may not add directly due to rounding 2.3.2 Noncriteria Pollutant Emissions Noncriteria pollutants are compounds that have been identified as pollutants that pose a significant health hazard. Nine of these pollutants are regulated under the federal New Source Review program; they are lead,asbestos,beryllium,mercury,fluorides,sulfuric acid mist,hydrogen sulfide,total reduced sulfur,and reduced sulfur compounds.' In addition to these nine compounds,the federal Clean Air Act lists 189 substances as potential hazardous air pollutants(Clean Air Act Sec. 112(b)(1)). The APCD has also published a list of compounds it defines as potential non-criteria reportable air pollutant emissions. Any pollutant that may be emitted from RMEC and is on the federal New Source Review list,the federal Clean Air Act list,and/or the APCD non-criteria air pollutant list has been included in • 'These pollutants are regulated under federal and state air quality programs 2-10 • • • the emissions inventory. Emission factors were determined by reviewing the available technical data, determining the products of combustion, and/or using material balance calculations. Non-criteria pollutant emission factors were taken from data compiled from the California Air Toxics Emission Factors(CATEF) database. The non-criteria pollutants that may be emitted from RMEC,and their respective emission factors,are shown in Table 2-10. Appendix B also provides the detailed emission calculations for non-criteria pollutants. Table 2-10. Noncriteria Pollutant Emissions For The RMEC. Emission Factor Emissions Pollutant (lb/MMscf) lb/hr ton/yr Gas Turbines with Duct Burners (each): Acetaldehyde 6.86x10.2 0.15 0.56 Acrolein 6.43x10"3 0.01 0.05 Ammonia a 30.90 114.96 Benzene 1.36x10.2 0.03 0.11 • 1,3-Butadiene 1.27x104 2.78E-04 1.04E-03 Ethylbenzene 1.79x10-2 0.04 0.15 Formaldehyde 1.10x10-' 0.24 0.90 Hexane 2.59x10-' 0.57 2.11 Naphthalene 1.66x10"3 3.63E-03 1.35E-02 Polycyclic Aromatics 2.23x10"3 1.44E-03 5.38E-03 Propylene 7.70x10-' 1.68 6.28 Propylene Oxide 4.78x10-2 0.10 0.39 Toluene 7.10x10.2 0.16 0.58 Xylene 2.61x10.2 0.06 0.21 8Ammonia emissions calculated from ammonia slip rate. See Appendix B• 2-11 • ".„:„1, ' J f t . I r � 1 , i - I Greeley fejr ,' <';,y Well Field i" _ "4 f tl J 4 r 1 F -/qyy � ® sn A� 4 �� I Riervnllen e f m b otPt r =f I i Frn I *II''' L 6 n '' ''',---:- Mlon I 1 ,' . tilt3 rPlattevllle �,N:+Li,% .l t I I I ' • W I i.., al ,I � H ''' 1 r` `r N i /. Ni . , l_ 7 I• j tr—I ' c _ x, 1.. i — /. , { IX j , l r I : .1 v: r l ,-� 1 _ I is I _____ P i p _ I 00 r� • 1 et`` Fort' ®_ 1 I II. ,, �` '"I/ I, ry v Luplon�I i 1 lit rj V a - _a 6 1 ) r 11 i; 4 .c� � 11 LL A 3 i! 1-'4 • Legend E Fes Rocky Mountain a`i"1ip Energy Center - . .$ Gas Pipeline 0 1 2 3 Miles Water Pipeline Project Location Source: uSGS 1:100.000 Greeley Topographic DRG. Figure 2-1 di i Cb �I 4 / _: ,I, t;I d dill L 43) CD I 4 i Il VI I � r m L Jid ii C W � I 'II ( ttl .' lx nova ■� _. _.. �� Ii titC i IHj, ii i II it h, ��i _ rota EYL it _hlo_ �' '—. of � 1 I,F E J 1' g irti m L 1 L • 3.0 REGULATORY ANALYSIS This section presents the identification of applicable regulations that will affect the proposed facility, with respect to air quality issues. The regulation is briefly explained and the compliance methods proposed to be used by the facility are delineated. Because the proposed project will be located within the State of Colorado,the Colorado Department of Public Health and Environment,Air Pollution Control Division(APCD)has the regulatory jurisdiction. 3.1 Prevention of Significant Deterioration(PSD) If a source emits, or has the potential to emit,more than 100 tons per year of any pollutant subject to regulation under the Clean Air Act(CAA),and if it can be classified as one of the 28 specific source types listed in 40 CFR Part 52.21, then the source is considered to be a major source [40 CFR Part 52.21(b)(23)(i)] subject to PSD review. PSD review applies to sources located in an attainment area (an area considered by the regulatory authority as meeting ambient air quality standards)or in an area designated as unclassifiable. EPA Region VIII and the APCD have designated Weld County as being • in attainment for all regulated pollutants. Therefore, the proposed project is subject to PSD review. In addition,the EPA has classified natural gas-fired combined cycle electrical generating facilities as fossil fuel fired steam electric plants. The project is therefore,subject to the 100 ton per year emission level threshold at which PSD review is required. As shown in Section 2, the projected annual emissions of NO,„CO,and PM10 exceed 100 tons per year.Emissions of VOCs are also subject to PSD review as they exceed the 40 ton per year major modification threshold. Emission of SO2 are not subject to the requirements of PSD as the potential to emit of this pollutant is less than the major source thresholds. 3.2 Emissions Standards 3.2.1 New Source Performance Standards EPA has established performance standards for a number of air pollution sources in 40 CFR Part 60. These"new source performance standards"(NSPS)usually represent a minimum level of control that • 3-1 • is required on a new source.NSPS Subparts GG and Da address emissions from combustion turbines and fossil fuel fired boilers,respectively, and would apply to the project. 3.2.1.1 Subpart GG EPA regulates stationary gas turbines in 40 CFR Part 60, Chapter 1 subpart GG. The final rule for the so-called"New Source Performance Standards" (NSPS)was promulgated September 10, 1979. Turbines associated with RMEC would be considered "electric utility stationary gas turbines" because more than one-third of their potential electric output capacity will be supplied to a utility power distribution system. The NSPS for turbines in this classification limit nitrogen oxide emissions based on heat input according to the formula: NOx (% by volume, dry @ 15% O2)=0.0075 * (14.4/y)+F where: • y is the heat rate in kilo-Joules per watt-hour, and • • F is an emission allowance for fuel-bound nitrogen Each of the two Westinghouse combustion turbines would consume 1,785 MMBtu/hr(HHV)when burning natural gas to generate 177 MW(base load)at 50°F.NSPS NOx limits based on these factors and the preceding equation are 159 ppm for the Westinghouse turbines. Because proposed NOx emissions are 3 ppm when burning gas, the proposed turbine NOx emissions would be well below NSPS limits. The NSPS limit sulfur dioxide emissions to 150 ppm, and prohibit the use of fuel containing more than 0.8 percent sulfur (by weight). NSPS also require continuous monitoring of fuel and water consumption and daily measurements of the sulfur and nitrogen content of natural gas provided by pipeline. Because SO2 emissions would be less than 1 ppm when burning gas and the proposed turbine SO2 emissions would be well below NSPS limits, compliance with this standard will be achieved. • 3-2 • 3.2.1.2 Subpart Da Subpart Da applies to electric utility steam generating units with heat input from fuels combusted exceeding 250 MMBtu/hr. Subpart Da would apply to the heat recovery steam generator (HRSG) when the duct burners are operating because the heat input would be approximately 659 MMBtu/hr (HHV). The duct burners would only be fired with natural gas,so only those sections of Subpart Da governing emissions with natural gas firing would apply to RMEC. Subpart Da limits particulate matter emissions to 0.03 lb/MMBtu and SO2 and NON emissions to 0.20 lb/MMBtu. The HRSG will be equipped with duct burners that produce 0.015 lb/MMBtu PM10,0.08 lb/MMBtu NON,and 0.0002 lb/MMBtu SO2. Because the proposed emission rates reflect BACT (which is usually more stringent than NSPS limits), the emission rates proposed for RMEC are far below those allowed by NSPS. Consistent with NSPS requirements, RMEC will also notify APCD of the anticipated initial startup date, the actual startup date, any changes in the facility that affect emissions, compliance sources tests, and certification tests for continuous emission monitors. RMEC also will maintain records of startups • and shutdowns,malfunctions of control equipment or periods of excess emissions if they occur,and periods when continuous emission monitoring equipment is inoperative. 3.2.2 Title 4 (Acid Rain)Provisions Title 4 of the Clean Air Act Amendments of 1990 provide a strategy for reducing national emissions of nitrogen and sulfur oxides as part of a comprehensive plan for reducing acid deposition. Part 75 requires any gas turbine larger than 25 MW that provides more than one-third of its potential electric output capacity to a utility power distribution system to monitor flow rate,oxygen,and nitrogen and sulfur oxides. RMEC would be subject to these regulations. Monitoring may take the form of continuous emission monitors or calculations based on fuel sulfur monitoring or similar techniques. The requirements for continuous emission monitors are similar to those required under NSPS except that CEMs for sources subject to Part 75 must meet more stringent accuracy limits during annual relative accuracy test audits. 3-3 • 4.0 REGIONAL AND SITE DESCRIPTION This section describes the project location,the land use and population of the surrounding area,the existing climate,air quality, soils, and vegetation. 4.1 Project Location Figure 4-1 illustrates the location of the proposed Rocky Mountain Energy Center. The facility lies approximately 47 km northeast of downtown Denver(assuming the center of the Denver downtown area is at the intersection of Broadway and Colfax) off of Interstate 76, 18 km north of the Denver International Airport complex, and 38 km south of Greeley, Colorado. Based on data derived from existing USGS maps, the facility will be located inside the boundaries of Weld County. The circle encompassing the facility has a 3 km radius; the relevance of this is discussed in the Auer Land Use Analysis section. The RMEC will be located at UTM coordinates 534491 meters easting,4437767 meters northing. The facility elevation is 1508 meters above mean sea level (MSL). • 4.2 Population and Land Use The population of Weld County,per updates to the 2000 census is approximately 180,936 individuals. The county covers an area of 3,992 square miles, resulting in a population density of 45.3 persons/square mile. Much of the land use in Weld County is based upon agriculture. 4.3 Existing Climate The climate of the project area prevails over much of the central Rocky Mountain region,without the extremely cold mornings of the high elevations during winter,or the hot afternoons of summer at lower altitudes. Extremely warm or cold weather in Denver is usually of short duration. Situated long distances from any moisture source,and separated from the Pacific Ocean by several high mountain barriers,the area enjoys low relative humidity, light precipitation, and abundant sunshine. I 4-1 • Air masses from four different sources influence the area weather. These include arctic air from Canada and Alaska, warm moist air from the Gulf of Mexico, warm dry air from Mexico and the southwestern deserts, and Pacific air modified by its passage over mountains to the west. In winter,the high altitude and mountains to the west combine to moderate temperatures in the area. Invasions of cold air from the north, intensified by the high altitude can be abrupt and severe. However,most of the cold air masses that spread southward out of Canada never reach the altitude of the project area, but move off over the lower plains to the east. Surges of air from the west are moderated in their decent down the east face of the Rockies,and reach the project area in the form of chinook winds that often raise temperatures into the 60s, even in midwinter. In the spring,polar air often collides with war moist air from the Gulf of Mexico and these collisions result in frequent, rapid and drastic weather changes. Spring is the cloudiest windiest, and wettest season in the project area. Much of the precipitation falls as snow,especially in March and Early April. Stormy periods are interspersed with stretches of mild,sunny weather that quickly melt previous snow • cover. Summer precipitation falls mainly from scattered thunderstorms during the afternoon and evening. Mornings are usually clear and sunny with clouds forming during early afternoon to cut off the sunshine at what would otherwise be the hottest part of the day. Severe thunderstorms,with large hail and heavy rain occasionally occur in the area,but these conditions are more common on the plains to the east. Autumn is the most pleasant season. Few thunderstorms occur and invasions of cold are infrequent. As a result,there is more sunshine and less severe weather than at any other time of the year. Based on observations in Denver for the 1951-1980 period,the average first occurrence of 32 degree Fahrenheit in the fall is October 8 and the average last occurrence in the spring is May 3. • 4-2 • 4.4 Existing Air Quality RTP contacted Ms. Nancy Chick of the Colorado Air Pollution Control Division to obtain representative background concentrations of criteria pollutants. The following data was provided. Table 4-1: Background Air Quality Values Averaging Pollutant Period Concentration Ranking Data Source CO 1-hour 10 ppm Second Maximum DIA 8-hour 5 ppm Second Maximum 1995-1996 NO2 Annual 0.016 ppm Mean RMA 1992-1996 O3 1-hour 0.098 ppm Second Maximum RMA 1992-1996 PM10 24-hour 101 ug/m3 Second Maximum Thermo Carbonics Annual 33 ug/m3 Arithmetic Mean 1991-1992 As shown above, air quality in the region is in attainment for all pollutants and for all averaging • periods. 4.5 Existing Soils and Vegetation The location and properties of the soil types in the project area were identified from maps of the area prepared by the U.S.Soil Conservation Service(now called Natural Resources Conservation Service). These soil maps and properties were obtained from the Soil Survey of Weld County, Colorado - Southern Part(U.S.Department of Agriculture, 1980). Weld County has the highest number of prime farmland acres in Colorado(365,000 acres). No impacts will occur to prime farmland from the RMEC project, as all reasonable efforts were made to avoid prime farmland in siting the facilities. Out of a total of 633 acres of existing agricultural land,approximately 88 acres(including about 15 acres for temporary construction laydown and parking) will be impacted by the power plant facility. The temporary construction laydown area will be reclaimed.Impacts will be mitigated through preservation of existing agricultural uses on the remainder of the parcel.No prime farmland will be impacted. Table 4-2 summarizes the soil types in the project area. • 4-3 • Table 4-2: Summary of Soil Types Found at Power Plant and Welifield Areas Restrictions Roads Shallow Sm.Comm. and Soil Type Descriptions Prime Excavation Bldgs. Streets RMEC Power Plant 10—Bankard sandy This is a deep,somewhat excessively drained soil N S S S loam 0-3%slopes on floodplains*at elevations of 4,450-5,000 feet. Permeability is moderately rapid.Available water capacity is low.This soil is used as pasture and limited cropping. 15—Colby loam This is a steep well-drained soil on uplands at Y SI SI M 1-3%slopes elevations of 4,850-5,050 feet. Permeability is moderate.Available water capacity is high.Surface runoff is medium,and erosion hazard is moderate. In irrigated areas,this soil is suited to all crops commonly grown in the area. In nonirrigated areas this soil is soil is suited to winter wheat,barley,and sorghum.Windbreaks and environmental plantings of trees and shrubs are generally well suited to this soil. 18—Colby Adena These gently to moderately sloping soils are N SI M M loams 3-9%slopes located on plains, hills and ridges at elevations of 4,750-4,900 feet.The Colby soil is deep and well- • drained with moderate permeability, high water capacity, rapid runoff,and high erosion hazard. The Adena soils are deep and well-drained with slow permeability,high water capacity, medium runoff,and moderate erosion hazard. 47—Olney fine sandy This is a deep and well-drained soil located on Y SI M M loam 1-3%slopes plains at elevations of 4,600-5,200 feet.The permeability and available water capacity are moderate permeability, high water capacity. Surface runoff is medium,and erosion hazard is low. In irrigated areas,this soil is suited to all crops commonly grown in the area. In nonirrigated areas this soil is soil is suited to winter wheat,barley, and sorghum.Windbreaks and environmental plantings of trees and shrubs are generally well suited to this soil. 60—Shingle-Renohill This gently to moderately sloping soil complex is N S S S complex 3-9%slopes located on plains, hills and ridges at elevations of 4,600-4,750 feet.The permeability is slow to moderate and available water capacity ranges from low to moderate.Surface runoff is medium to rapid, and erosion hazard is moderate.This soil is used as rangeland and wildlife habitat. 79—Weld loam 1-3% This is a deep,well drained soil on smooth plains Y SI M M slopes at elevations of 4,850-5,000 feet. Permeability is slow.Available water capacity is high. Surface runoff is slow,and erosion hazard is low.In • irrigated areas,this soil is suited to all crops 4-4 • • • Table 4-2: Summary of Soil Types Found at Power Plant and Wellfield Areas Restrictions Roads Shallow Sm.Comm. and Soil Type Descriptions Prime Excavation Bldgs. Streets commonly grown in the area.The soil is well suited to winter wheat, barley,and sorghum.Windbreaks and environmental plantings of trees and shrubs are generally well suited to this soil. Well Field 1 —Altvan loam 0-1% Steep,well-drained soil on terraces at elevations of Y S M M slopes 4,500-4,900 feet. Permeability and available water capacity are moderate.Surface Runoff is slow and erosion hazard is low.This soil is used almost entirely for irrigated crops.Windbreaks and environmental plantings of trees and shrubs are generally well suited to this soil. 3—Aquolls and These are deep poorly drained soils that formed in N S S S Aquents,gravelly recent alluvium on bottomlands and floodplains*. substratum These soils are used for rangeland and wildlife habitat. 68—Ustic This is a deep,excessively drained soil on terrace N S M M Torriorthents breaks and enscarpments at elevations of 4,450- moderately steep 5,100 feet.Permeability is rapid.Available water capacity is low.Surface runoff is medium,and erosion hazard is moderate.This soil is used as • pasture and poorly suited to wildlife habitat. 'Although these soils are typically found in wetlands and floodplains,the RMEC and wellfield will not affect jurisdictional wetlands and are not located in a floodplain overlay area. Restrictions: SI—Slight M—Moderate S-Severe Weld County's economy is heavily dependent on agriculture. Crops produced in the county include onions,sugar beets,pinto beans,potatoes,corn,alfalfa,wheat,carrots,barley,and sorghum,in addition to other specialty crops.Many of the feed crops are used locally by the livestock industry.For example, most of the corn grown in the area,both silage and grain,is used for feed at commercial feedlots,farm feedlots,and dairies.Significant numbers of sheep,swine,and turkeys also use the feed crops from the area. Croplands in the agricultural district also provide natural open space areas. • 4-5 • • None of these soils or vegetation types have been identified as having any particular sensitivity to air pollutants such as those emitted from the proposed facility or anticipated to be emitted from the proposed facilities. In addition,the secondary air quality standards are designed to be protective of cash crops,but are not designed to be protective of sensitive plant and animal species. The Environmental Coordinator for the Colorado National Heritage Program(Beth Hunter)was contacted to identify any such species in the project area. No sensitive species were identified. • • 4-6 • • 5.0 ANALYSIS OF BEST AVAILABLE CONTROL TECHNOLOGY FOR NOx, • CO,PM10,VOC,and SO2 The Project was evaluated under federal PSD provisions in 40 CFR Part 52.21 and Regulation 3 of the APCD rules,and it was concluded that the new combined cycle units and auxiliary boiler are subject to PSD review requirements for NO2,CO,PM/PMio,and VOC. SO2 is not subject to PSD as the source is a minor one with regards to this pollutant. However, the plant will apply BACT to SO2. The applicable air quality permitting requirements in the APCD regulations are delineated by air quality areas which correspond to established attainment and non-attainment areas within the county. The Weld county region is a PSD area for all pollutants per Regulation 3,consequently,the project must incorporate controls that are designed to meet Best Available Control Technology (BACT) requirements. This section presents the BACT analyses,with proposed emission controls and limits for the project's new emission units. The emissions units covered by the BACT control technology review are the two combustion turbines and associated duct burners,the 13-cell mechanical draft evaporative cooling tower,and the auxiliary boiler. BACT is defined in the regulations as follows: • ...an emissions limitation (including a visible emission standard) based on the maximum degree of reduction for each pollutant subject to regulation under the Clean Air Act which would be emitted from any proposed stationary source or modification which the Control Officer, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such source or modification through application of production processes or available methods,systems,and techniques,including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant. In no event shall application of best available control technology result in emissions of any pollutant which would exceed the emissions allowed by any applicable standard under 40 CFR Parts 60 and 61. If the Control Officer determines that technological or economic limitations on the application of measurement methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a design, equipment, work practice, operational standard, or combination thereof, may be prescribed instead to satisfy the requirement for the application of best available control technology. Such standard shall, to the degree possible, set forth the emissions reduction achievable by implementation of such design,equipment,work practice or operation,and shall provide for compliance by means which achieve equivalent results. • 5-1 • EPA recommends using a "top-down" approach for determining BACT. This approach essentially ranks potential control technologies in order of effectiveness and ensures that the best technically and economically feasible option is chosen. As described in EPA's New Source Review Workshop Manual, draft,October 1990,the general methodology of this approach is as follows: 1. Identify potential control technologies,including combinations of control technologies, for each pollutant subject to PSD review. 2. Evaluate each control technology for technical feasibility;eliminate those determined to be technically infeasible. 3. Rank the remaining technically feasible control technologies in order of control effectiveness. 4. Assume the highest-ranking technically feasible control represents BACT,unless it can be shown to result in adverse environmental,energy, or economic impacts. 5. Select BACT. EPA's RACT/BACT/LAER Clearinghouse (RBLC) is considered a principal reference for identifying potential control technologies and emission rates used in past permitting of similar sources. The database was queried for entries since January 1990 involving combustion turbines and duct burners, cooling towers, and boilers. The emission rates proposed in this permit application apply with and without duct firing. Also,the duct burners and combustion turbines have a common release point and the duct burners will never operate independent of the turbines, thus, the BACT analyses are conducted for the combined emission rates of the combustion turbines and duct burners. The emission rates proposed are consistent with the entries in the RBLC for past BACT evaluations, especially those for sources with similar MMBtu/hr and MW ratings. The "top-down" procedure is followed for the BACT analyses for the pollutants evaluated in this analysis,with a focus on identifying emission limitations or control technologies that are achieved in practice and technically feasible. The sections following present the BACT analyses and proposed NOx, CO,PM/PM10,VOC,and SO2 limits and controls. Section 5.1 presents the BACT analysis for the combined cycle units and Section 5.2 contains the PM 10 analysis for the cooling tower. Finally,the • 5-2 • BACT analysis for the auxiliary boiler is provided in Section 5.3 5.1 BACT Analysis for the Combined Cycle Units 5.1.1 Analysis of Control Requirements for Nitrogen Oxides 1. Identify Potential Control Technologies The baseline NO, emission rates for this analysis are considered to be 75 ppmvd @ 15% O2 for the combustion turbines and 0.20 lb/MMBtu for the duct burners, based on the applicable New Source Performance Standards (40 CFR Part 60, Subparts Da and GG). These emission rates provide a comparison for the evaluation of control effectiveness and feasibility. The maximum degree of control, which results in the lowest NON emission rate,is a combination of dry low-NON combustors(DLN)for the turbines and low-NON burners (LNB) for the duct burners in conjunction with either selective catalytic reduction(SCR) or SCONOx. The formation of NON from the combustion of fossil fuels can be attributed to two basic mechanisms— fuel NON and thermal NON. Fuel NON results from the oxidation of organically bound nitrogen in the • fuel during the combustion process,and generally increases with increasing nitrogen content of the fuel. Because natural gas contains only small amounts of nitrogen, little fuel NON is formed during combustion. The vast majority of the NON produced during the combustion of natural gas is from thermal NON, which results from a high-temperature reaction between nitrogen and oxygen in the combustion air. The generation of thermal NO,is a function of combustion chamber design and the turbine operating parameters,including flame temperature,residence time(i.e.,the amount of time the hot gas mixture is exposed to a given flame temperature),combustion pressure,and fuel/air ratios at the primary combustion zone. The rate of thermal NO,formation is an exponential function of the flame temperature. The reduction of NON emissions can be achieved by combustion controls and post-combustion flue gas treatment. Combustion modifications for turbines include both wet and dry combustion controls. Wet and dry combustion controls act to reduce the formation of NO„during the combustion process,while post-combustion controls remove NON from the exhaust stream after it is generated. Thus,potential • NO,control technologies for the combustion turbines and duct burners include the following: 5-3 • r • Wet combustion controls • Water injection • Steam injection Dry combustion controls • Dry low-NOx combustor design(with low-NOx burners for the duct burners) • Other combustion modifications • Catalytic combustors(e.g.,XONON) Post-combustion controls • Selective catalytic reduction(SCR) • Selective non-catalytic reduction(SNCR) • Non-selective catalytic reduction(NSCR) . • SCONOx 2. Evaluate Control Technologies for Technical Feasibility The performance and technical feasibility of each"category"ofNOx controls listed above are discussed separately. Wet and dry combustion modifications as they are applicable to combustion turbines are discussed first (duct burner controls are achieved with the use of low-NOx burners). A detailed discussion of post-combustion controls, which can control emissions from both the combustion turbines and duct burners, follows. Wet Combustion Controls—Water and Steam Injection Injecting water or steam directly into the turbine combustor are common NQ control techniques for combustion turbines. The principle behind wet injection techniques is to lower the flame temperature in the combustor,which reduces the formation of thermal NOx. Specifically,water or steam is injected into the primary combustion chamber to provide a heat sink that lowers the peak flame temperature of • combustion. Because water acts as a better heat sink than steam(due to temperature and latent heat of 5-4 • vaporization), more steam is required to achieve an equivalent level of NO„reduction. The injected water or steam exits the turbine as part of the exhaust. The performance of wet controls is primarily dependent on the water- or steam-to-fuel ratio, with NO„emissions decreasing as the water-or steam-to-fuel ratio increases. Additional factors affecting the level of control are the combustor geometry and the design and location of the injection nozzle(s). In order to maximize NO,,reductions, there must be a homogeneous mixture of water droplets and fuel in the combustor. This homogeneous mixture is only achieved through the proper atomization and injection of the water within the turbine combustor region. Typically,for gas-fired turbines,steam injection can reduce NO„emissions to levels of 15 to 25 ppmv @ 15%02. Emission rates for water injection are higher due to the inability to achieve a homogeneous mix of water and fuel in the combustor and are usually around 25 to 45 ppmv @ 15% 02. Although the quenching effect of the water or steam lowers the peak flame temperature and thus reduces NO,, emissions, it can also increase CO and hydrocarbon emissions, decrease combustion • efficiency, and increase maintenance requirements. Due to incomplete combustion, CO and hydrocarbon emissions can increase as the water- or steam-to-fuel ratio increases. The reduction in efficiency also can increase with increasing water-or steam-to-fuel ratios and is typically greater for water injection(due to the heat of vaporization). For some turbines,due to the injection of water or steam into the combustor, increased wear and erosion in the hot section of the turbine can result in increased maintenance and downtime. Water and steam injection have been used on gas-fired turbines in all size ranges for many years. Where both systems are available, steam availability at the site and other economic factors usually determine which system is used. These NO„ control technologies are widely available and are technologically feasible. Dry Combustion Controls Dry combustion controls reduce NO„ emissions without wet injection systems. Combustion • modifications to reduce NO„formation include lean combustion,reduced combustor residence time, 5-5 • lean premixed combustion, and two-stage rich/lean combustion. Lean combustion uses additional excess air(greater than stoichiometric air-to-fuel ratio)to cool the flame and thus reduce thermal NOx formation. Reduced combustor residence times are achieved by introducing dilution air between the combustor and the turbine hot section. The rate of thermal NOx formation is reduced because the combustion gases are at higher temperatures for a shorter time. The idea behind lean premixed combustion is to premix the fuel and air prior to combustion in order to provide a homogeneous air/fuel mixture, which acts to reduce the combustion temperatures, and thus thermal NON. Rich/lean combustion uses a fuel-rich primary stage,quenching,and then a fuel-lean secondary stage to reduce NOx formation,however,this type of control is currently not very common. Currently,the most widely used combustion controls are dry low-NO„(DLN)combustors,which use lean premixed combustion to reduce the formation of thermal NOx. Prior to the development of premix based dry-low NOx combustors, fuel and air were injected separately into the turbine's combustor section where oxygen in the combustion air needed to support the combustion process diffused to the flame front located at the combustor's fuel burner. Simply put, the combustion • occurred in a diffusion flame similar to that of a Bunsen burner. The result of this approach was a range of fuel-to-air ratios over which combustion occurred and a corresponding range of flame temperatures. The dry-low NOx combustion process works to reduce the amount of thermal NOx that is formed by lowering the overall flame temperature within the turbine combustor by premixing the fuel and air at controlled stoichiometric ratios prior to combustion. DLN combustion is effective in achieving NOx emission levels comparable to the levels achieved using wet injection without the need for large volumes of purified water or steam. An increase in CO emissions can result from lower NOx emission rates (in the range of 9 ppmv). However, negligible increases in CO are associated with controlled NOx emission rates around 25 ppmv (the level for the proposed turbines before subsequent control). Thus, the increases in CO and VOC emissions that result from wet injection are not a factor with such DLN systems. Several turbine vendors have developed DLN systems for their turbines, therefore this technology is considered technically feasible. • 5-6 • • Catalytic combustors use a catalytic reactor bed mounted within the combustor to bum a very lean fuel- air mixture. This technology has been commercially demonstrated under the trade name XONON in a 1.5 MW natural gas-fired turbine in Santa Clara,California. Commercial availability of the technology for a 200 MW GE Frame 7 natural gas-fired turbine was recently announced. The technology has also been announced as commercially available for some models of small turbines (around 10 MW or lower). The combustor used in the Santa Clara demonstration engine is generally comparable in size to that used in GE Frame 7F engines. The technology has not been announced commercially for the engines proposed for this project, thus a commercial quotation for the use of XONON is not commercially available from the supplier,Catalytica Corporation. No turbine vendor,other than General Electric,has indicated the commercial availability of catalytic combustion systems at the present time. Consequently,catalytic combustion controls are not considered commercially available for this project and are not discussed further. • Post-Combustion Controls • Selective Catalytic Reduction (SCR) The SCR process is a post-combustion control technology in which injected ammonia reacts with NOx in the presence of a catalyst to form water and nitrogen. The catalyst's active surface is usually a noble metal, base metal (titanium or vanadium) oxide, or a zeolite-based material. The geometric configuration of the catalyst body is designed for maximum surface area and minimum back-pressure on the turbine. An ammonia injection grid is located upstream of the catalyst body and is designed to disperse ammonia uniformly throughout the exhaust flow before it enters the catalyst unit. The desired level of NOx emission reduction is a function of the catalyst volume and ammonia-to-NOx(NH3/NOx) ratio. For a given catalyst volume,higher N-13/NOx ratios can be used to achieve higher NOx emission reductions,but can result in undesired increased levels of unreacted NI-I3 (called ammonia slip). The SCR catalyst is subject to deactivation by a number of mechanisms. Loss of catalyst activity can occur from thermal degradation if the catalyst is exposed to excessive temperatures over a prolonged • period of time. Catalyst deactivation can also occur due to chemical poisoning. Principal poisons 5-7 • • include compounds of arsenic,sulfur,potassium,sodium,and calcium. In applications where natural gas is fired, a catalyst life of 5 to 6 years has been demonstrated. SCR has been demonstrated effective at numerous installations throughout the United States. Typically, SCR is used in conjunction with other wet or dry NO„ combustion controls (e.g., DLN). Because SCR is a post-combustion control, emissions from both turbines and duct burners can be controlled. SCR requires the consumption of a reagent (ammonia or urea) and requires periodic catalyst replacement. Estimated levels of NO„control are in excess of 90%. • Selective Non-catalytic Reduction(SNCR) SNCR is another post-combustion technology where NO„is reduced by injecting ammonia or urea into a high-temperature region, without the influence of a catalyst. The SNCR technology requires gas temperatures in the range of 1200°to 2000°F.The exhaust temperature for the proposed turbines ranges from 1033° to 1135°F, which is below the minimum SNCR operating temperature. Thus, some method of exhaust gas reheat,such as additional fuel combustion,would be required to achieve exhaust • temperatures compatible with SNCR operations. SNCR is most commonly used with boilers,and there are no entries in the RBLC indicating the use of SNCR for turbines. SNCR is considered technologically infeasible for this project due to the temperature considerations. However, even if SNCR were technically feasible,it would not be able to achieve NOx reductions comparable to SCR. • Nonselective Catalytic Reduction (NSCR) NSCR uses a catalyst without injected reagents to reduce NO„ emissions in an exhaust gas stream. Typically, NSCR is used in automobile exhaust and rich-bum stationary IC engines, and employs a platinum/rhodium catalyst. NSCR is effective only in a stoichiometric or fuel-rich environment where the combustion gas is nearly depleted of oxygen,and this condition does not occur in turbine exhaust where the oxygen concentrations are typically between 14 and 16%. Consequently, NSCR is not technologically feasible for this project. • SCONOx • The SCONOx system uses a proprietary potassium carbonate coated oxidation catalyst to remove both 5-8 • NOx and CO. SCONOx is a relatively new system produced by Goal Line Environmental Technologies that began commercial operation in California at the Federal Plant owned by the Sunlaw Cogeneration Partners in December 1996. According to a press release from December 1999,for gas turbine installations larger than 100 MW, ABB Alstom Power is Goal Line's exclusive licensee for SCONOx. The combustion turbine at the Federal facility is a GE LM-2500 that is approximately 23 MW in size, roughly one-eighth the size of each of the two combustion turbines proposed for this project. The application of the SCONOx system at the Federal Plant is the second-generation of the technology. The first generation was a pilot unit application that operated for ten months at another nearly identical GE LM-2500 based facility,the Growers facility,also owned by Sunlaw Cogeneration Partners. The SCONOx catalyst used at the pilot facility was transported to the Federal facility when the pilot unit was taken out of service. Two power plant projects in California proposed by PG&E Generating Company have recently . proposed the use of SCONOx for NOx control,although both projects included switching to SCR as a contingency in their permit applications. The La Paloma Generating Project is a merchant plant that originally proposed using SCONOx on one out of its four turbines,although recently the decision was made to apply SCR to all four turbines. In addition, the technology's co-developer, Sunlaw, has proposed to use the technology in conjunction with ABB gas turbines at the Nueva Azalea site in Southern California. The SCONOx system does not use a reagent such as ammonia but instead utilizes natural gas as the basis for a proprietary catalyst regeneration process. The NO present in the flue gas is reduced in a two- step process. First, NO is oxidized to NO2 and adsorbed onto the catalyst. For the second step, a regenerative gas is passed across the catalyst periodically. This gas desorbs the NO2 from the catalyst in a reducing atmosphere of hydrogen(H2)which results in the formation of N2 and water(H2O)as the desorption products. For the regeneration/desorption step to occur there must be no oxygen (O2) present during this step. The CO present in the flue gas is oxidized to CO2 as part of the SCONOx • process. 5-9 • • • In order for the SCONOx technology to work properly,inlet/outlet dampers must continuously isolate one quarter of the catalyst blocks for regeneration. The SCONOx potassium carbonate layer has a limited adsorption capability and requires regeneration about once every 15 minutes in normal service. Each regeneration cycle requires approximately 3 to 5 minutes. The regenerative gas is passed through the isolated portion of the catalyst while the remaining catalyst is left open to the flue gas flow. After the isolated portion is regenerated,the next set of dampers must close and isolate the next section of catalyst for regeneration. This cycle is continuously repeated. Assuming a four(4)section catalyst,and regeneration times of 15 minutes per section,results in approximately 35,000 regeneration cycles per year. At the Federal Plant the regenerative gas is produced from natural gas by processing it through a separate skid mounted processing unit. The resulting regenerative gas is approximately 3 percent nitrogen, 1.5 percent CO2, and 4 percent H2,with steam making up the balance. Steam is used to: (1) dilute the regenerative gas hydrogen concentration below the lower explosive level;(2)act as a carrier • gas;(3)promote the purging of the catalyst bed of the oxygen containing flue gas;and(4)promote even distribution of the regeneration gas throughout the catalyst bed. Goal Line has tested several methods for producing regeneration gas, including a one step method where steam,natural gas,and air are reacted at 900°F using an autothermal process. This process failed to produce consistent results and was abandoned. Goal Line has stated that in future applications,the regeneration gas will be generated in the HRSG at a temperature of approximately 600 °F. This modified system to produce regeneration gas has not been tested on any commercial applications and as such is not demonstrated in practice. Because the active regenerant gas is hydrogen, the regeneration process must be performed in an atmosphere of low oxygen to prevent dilution of the hydrogen. In practice,the oxygen present in the exhaust gas of combustion turbines is excluded from the catalyst bed by dividing the catalyst bed into a number of individual cells or compartments that are equipped with front and rear dampers that are • closed at the beginning of each regeneration cycle. Obtaining a good seal with the dampers is key to: 5-10 • • (1) preventing oxygen in the flue gas from disrupting the regeneration process, and (2) evenly distributing the regeneration gases across the catalyst. Complete regeneration of the SCONOx catalyst system is dependent upon the proper functioning and sealing of these sets of dampers approximately four times each hour. Incomplete regeneration of the catalyst results in decreased system performance which in-turn results in increased NOx emissions. Based on an article by Goal Line(Campbell et al,February 1997),probably the most important cause of reduced performance in the pilot unit was poor distribution of regeneration gas over the catalyst. As a result, several design changes were incorporated into the system located at the Federal Plant. The SCONOx catalyst is very susceptible to fouling by very small amounts of sulfur in the flue gas. Sulfur causes the catalyst to loose activity. The impact of sulfur is minimized by a sulfur absorption catalyst, called SCOSOx, located upstream of the SCONOx catalyst. First, the SO2 is oxidized and absorbed on to the catalyst. The SO3 is then desorbed from the catalyst as part of the SCONOx regeneration process. The resulting byproduct of the regeneration is either H2S(for systems located in • the HRSG where the flue gas temperature is below 450°F at the catalyst)or SO2(for systems located in the HRSG where the flue gas temperature is above 450 °F). In the case where H2S is formed,it is converted back to SO2 using an additional subsystem and directed into the exhaust downstream of the catalyst. In the case where SO2 is the byproduct,it is directed into the turbine exhaust downstream of the catalyst. For a new construction project,the system would be placed in the HRSG at a point where SO2 would be the primary product of the SCOSOx system. According to Goal Line/ABB,the catalyst requires periodic washing at least annually. The"washing" consists of removing the catalyst modules from the unit and submerging each module in a vessel containing potassium carbonate. Thus, the adsorbent portion of the SCONOx process must be revitalized or replaced at least annually. For units the size of the proposed turbines, total required "wash"time could be on the order of seven(7)days per turbine per wash cycle(including the time to allow safe entry to the HRSG). There are three options available for carrying out this washing: S 5-11 • • To shut down the unit for approximately one week to clean the catalyst. Shut down includes a two day cooling period prior to personnel entering the HRSG. Unbuttoning and entry into the HRSG. Dismantling of the catalyst support structure to allow the catalyst to be removed. Removal and dipping of the catalyst and then placement back into the HRSG. The actual logistics and design requirements of accomplishing this task on a unit the sizes of the proposed units are not yet known. In addition, this approach has the disadvantage of eliminating the ability to produce power during the outage. • Removal of the unit while on-line and replacement with clean catalyst while the other catalyst is washed. This approach is impractical in light of the need to assure that all damper seals maintain 100% integrity during the removal. The logistics associated with performing this operation on an application with units the size of the proposed units is also several fold more complicated because of the need to maintain tight damper seals where one side is at operating temperature and the other is at ambient in order to allow worker access. Several safety issues would also have to be overcome. This approach also requires that a spare catalyst set be purchased and stored. Thus, additional storage facilities would also be required. • Bring the catalyst off-line only long enough to permit removal of the used catalyst and replacement with a spare catalyst set. The removed catalyst is then washed and prepared for placement back in service at the next wash outage. Any of the above operations will require several days to shutdown and cool the HRSG and • SCOSOx/SCONOx sections to the point that the catalyst can be handled safely. Then each catalyst section will have to be removed, washed, dried, and put back in the HRSG before the units can startup again. Commercially quoted NO,‘ emission rates for the SCONOx system range from 2.0 ppm on a 3-hour average basis, representing a 78% reduction, to 1.0 ppm with no averaging period specified (96% reduction). Because it has only been applied at two relatively small combustion turbine facilities,there are several long-term operational concerns that exist with the SCONOx system. Although technical concerns exist,the SCONOx system will be considered technologically feasible for the purposes of this analysis. Thus,based on the information in this section,the following NQ control technologies are technologically feasible for the proposed project: • Water injection • Steam injection • • Dry low-NQ combustors(low-NO„burners for the duct burners) 5-12 • • • • Selective Catalytic Reduction(SCR) • SCONOx 3. Rank Technically Feasible Control Technologies by Control Effectiveness The technically feasible control technologies listed above are ranked by NO„control effectiveness in the traditional"top-down"format in Table 5-1. Table 5-1: NO„Control Technologies Ranked by Effectiveness NO„ NO,Control Technically Emissions Environmental Energy Alternative Available? Feasible? (@ 15% O2) Impact Impacts Selective >90% Decreased Catalytic Yes Yes reduction Ammonia slip Efficiency Reduction' 1 —3.0 ppm >90% Reduced CO; Potential Decreased • SCONOx Yes" Yes` reduction 1 —2.5 ppm reduction in Efficiency VOC Dry Yes Yes 9-25 ppm Low- Reduced NO,� Increased CONOC Efficiency Combustors Steam Increased Increased Injection Yes Yes 15 —25 ppm CONOC Efficiency Water Yes Yes 25-42 ppm Increased Decreased Injection CONOC Efficiency a Typically used in conjunction with wet or dry combustion controls. b The availability of commercial guarantees for utility-scale projects is not clear. This technology has been used on two small(5 MW and 23 MW)gas turbines;it has not been demonstrated on utility-scale gas turbines. 4. Evaluate Most Effective Controls for BACT For large gas turbines such as those proposed,water and steam injection have been largely superseded by dry low-NO„combustors,due to the superior emission control performance and increased efficiency. The proposed project plans to use dry low-NO, combustors for the combustion turbines, thus no 5-13 • further discussion of water injection, steam injection, or dry low-NO, combustors is necessary. The duct burners will be equipped with low-NO„burners, which also represents a high level of emission control performance. The level of NO„control for SCR and SCONOx is essentially equivalent. However,the SCONOx process is much more complex both chemically as well as mechanically than the SCR technology. The principal differences between the two technologies are associated with whether the low emission levels proposed have been achieved in practice,the cost-effectiveness in achieving these levels,and secondary environmental impacts. Table 5-2 compares the two processes. The SCR catalyst needs to be located in the appropriate section of the HRSG and maintained at the proper temperature. An SCR system also requires ammonia to be injected upstream of the catalyst with good mixing and even distribution. By comparison, the SCONOx process is much more complex in that the catalyst requires continuous regeneration,not just the presence of a reducing agent in the flue gas. Unlike SCR,the regeneration • process for SCONOx requires a separate process to generate the regeneration gas and the catalyst must be separated from the flow of hot flue gas for the regeneration process to occur. Thus,the need for the isolation louvers and the ability to frequently remove the SCONOx catalyst for washing. Each SCONOx catalyst block also has inlet and outlet piping for the regeneration gas. In order to control flow of the regeneration gases, each inlet and outlet pipe has a set of electronically actuated valves. As such,each catalyst section has several actuators and valves that need to properly function and be maintained. In contrast, the SCR ammonia distribution system requires one automatic ammonia flow control valve and a set of manually adjusted valves used as part of the initial tuning of the ammonia injection grid. As a result, relative to the well-demonstrated application of SCR to natural gas-fired sources,the SCONOx processes will have a lower availability and higher operating and maintenance costs for the following reasons: • The mechanically complex nature of the isolation louvers; • The mechanically complex regeneration gas valving system;and, . • The added catalyst regeneration/replacement step (potassium carbonate solution washing). 5-14 • • • Table 5-2: Comparison of SCR and SCONOx Removal Technologies SCR SCOSOx/SCONOx Process Parameters NOx SO2 NOx NOx Reduction Removal Oxidation Reduction Catalyst Yes Yes Yes Yes Reducing agent& Yes Yes No Yes equipment Mechanical seals No Yes Yes Yes Catalyst regeneration/ At least replacement 5 years 5 years 5 years annually By products/wastes Potassium NH3 slip H2S or SO2 None solution 5.1.2 Evaluation of Achieved in Practice Guidance from APCD is not available to determine if a control has been achieved in practice(AIP). • However, the South Coast Air Quality Management District(SCAQMD) has established criteria for determining when control technologies should be considered AIP for the purposes of BACT evaluations. SCAQMD's BACT Scientific Review Committee has recently reviewed a proposed clarification of those criteria,which include the following elements: Commercial Availability: At least one vendor must offer this equipment for regular or full-scale operation in the United States. A performance warranty or guaranty must be available with the purchase of the control technology,as well as parts and service. Reliability: All control technologies must have been installed and operated reliably for at least six months. If the operator did not require the basic equipment to operate daily,then the equipment must have at least 183 cumulative days of operation. During this period,the basic equipment must have operated (1) at a minimum of 50%design capacity; or(2) in a manner that is typical of the equipment in order to provide an expectation of continued reliability of the control technology. • 5-15 • Effectiveness: The control technology must be verified to perform effectively over the range of operation expected for that type of equipment. If the control technology will be allowed to operate at lesser effectiveness during certain modes of operation,then those modes of operation must be identified. The verification shall be based on a performance test or tests,when possible,or other performance data. Technology Transfer: BACT is based on what is AIP for a category or class of source. However, USEPA guidelines require that technology that is determined to be AIP for one category of source be considered for transfer to other source categories. There are two types of potentially transferable control technologies: (1)exhaust(backend)controls,and(2)process controls and modifications. For the first type,technology transfer must be considered between source categories that produce similar exhaust streams. For the second type, technology transfer must be considered between source categories with similar processes. 5.1.2.1 Achieved in Practice Criteria Evaluation for SCR • SCR has been achieved in practice at a multitude of gas turbine installations throughout the world. This technology has also been demonstrated on large gas turbines through stack testing and continuous emissions monitoring systems (CEMS) at numerous facilities. SCR technology has been making continued advances over the past few years, although there are not that many facilities in operation designed to meet low NO„permit limits of 3 ppm or less(most are in the permitting or construction phase). There are numerous facilities operating at higher NO„ concentrations and experience from these facilities has allowed manufacturers to gain a better understanding of operations to optimize NO, reduction, sizing of catalyst systems,reagent distribution, and process and control systems. Some SCR system operational data is available on EPA's Acid Rain web site for sources required to submit emissions information. One such source is the Sacramento Power Authority-Campbell Soup cogeneration plant in Sacramento,California. CEMS data for this source indicate NQ emissions that are in compliance with its 3.0 ppm limit on a continuous basis,in fact,the actual NO„levels from the 120 MW Siemens V84.2 turbine are approximately 2.5 ppm (3-hour average). This facility has • experienced a few excursions due to the gas turbine switching from pre-mix,or low-NO),mode, into 5-16 • diffusion mode, which have resulted in emissions above 3 ppm. As a result, the permit has been modified to accommodate up to ten hours per year of excursions above the 3 ppm permit limit under certain conditions. This site is an example of the knowledge gained from existing comparable sources operating with SCR (something that is not truly available with SCONOx). The experience at the SPA-Campbell Soup site demonstrates that lower emission levels are achievable on a continuous basis. However, it also indicates that the ability of the SCR system to track NOR emissions changes upstream of the catalyst is further challenged at progressively lower concentrations. Another factor that is important to mention is the ability of measurement systems to accurately measure very low NOR levels. SCAQMD for instance has indicated that current NOR measurement methods for stationary sources are accurate to ±1 ppm (Protocol for Rule 2012). This presents problems at permit levels of 5 ppm and lower for NOR, although this challenge will be a factor for either SCR or SCONOx. The following is an evaluation of the proposed AIP criteria as applied to the achievement of extremely • low NOR levels using SCR technology to control both turbine and duct burner emissions. Commercial Availability: There are numerous manufacturers of SCR catalyst systems and standard commercial guarantees are available. Guaranteed NOR levels in the range of 2-5 ppm for turbines are commonly available. Reliability: There are numerous similar installations operating with SCR control systems throughout the United States. This technology has been available for years and has demonstrated the ability to meet low NOR emission rates. The SPA-Campbell Soup facility provides an example of a source achieving NOR levels complying with a 3 ppm permit limit during routine operations over time. There has not been evidence of adverse effects on overall plant operations and reliability from SCR system operating at these levels. • 5-17 • • • Effectiveness: SCR technology has been demonstrated to achieve NOx levels below 3 ppm. CEMS data for the SPA-Campbell Soup site is available for several years and demonstrates compliance with a NO. permit level of 3 ppm. Due to system design (SCR inlet NO. levels in excess of those for which the SCR system was designed that caused tripping from pre-mix to diffusion mode), short-term excursions have resulted in NO. concentrations above 3 ppm. However, these excursions have not been associated with diminished effectiveness of the SCR system. Consequently, as with most control systems designed to reduce emissions to very low levels, the application of SCR should reflect the potential for infrequent NO,, excursions under specified conditions. Technology Transfer: SCR has been demonstrated on numerous similar installations, and is therefore not a situation of technology transfer. From the above discussion,SCR technology is considered to be achieved in practice. The technology is capable of achieving NO,, levels of 3 ppm and below. The current BACT guidelines used by EPA • Region DC indicate that NOx levels of 2.5 ppm to 3.0 ppm on a 3-hour average basis are considered BACT for utility-scale gas turbines (without supplemental firing). The achievement of NO. concentrations below these levels,on either a short term or long term basis,have not been demonstrated in practice. Thus,the proposed NO.emission rate for the combustion turbines and duct burners of 3.0 ppm on a 3-hour average basis with the application of SCR meets BACT. 5.1.2.2 Achieved in Practice Criteria Evaluation for SCONOx The SCONOx system has only been applied at two relatively small combustion turbine facilities (5 MW and 23 MW). As a result,there are several long-term operational concerns that exist with the SCONOx system. The SCONOx isolation louvers are moving parts in the flue gas stream that will require more frequent maintenance than any SCR components. In fact, no other combustion turbine systems or boilers have damper systems that require frequent operation from a fully open to a fully closed position. • 5-18 • Louver and damper systems are subject to mechanical and thermal stresses and strains that result from changes in temperatures associated with startup and shutdown as well as normal fluctuations in operating temperatures during load changes or changes in steam demand. These thermal/mechanical stresses result in operating and maintenance problems that are magnified with increases in scale. It should be noted that the change in placement/position of the SCONOx from the Federal facility location where the operating temperature is 320°F to the Goal Line stated preferred,undemonstrated, location where the operating temperature will be 550 to 650°F will increase the challenges associated with maintaining good seals during regeneration. Another issue of concern is long-term catalyst availability and pricing. The SCONOx catalyst is a proprietary catalyst produced and available through only Goal Line/ABB,unlike SCR catalysts that are available through multiple suppliers that guarantee competitive pricing and availability. While Goal Line/ABB guarantees a catalyst life of three years, this catalyst life has not yet been commercially demonstrated over multiple applications,since only a single unit has been operated over that length of time. It is important to note that although SCR catalyst is now well demonstrated,during the first three • years of operation on the initial five(5)combustion turbine applications in the U.S.there were over five (5)catalyst change outs. Also,vendor guarantees are only good for replacement of the catalyst. The guarantee does not: • Pay for lost revenues associated with downtime; • Pay for the cost of any penalties resulting from any exceedence of a permit limit; • Pay for the cost of removing SCOSOx/SCONOx and replacing it with an SCR system; and, • Ensure that the catalyst will be replaced until the system works. Subsequent catalyst replacements are at the vendor's discretion and it is left to the vendor discretion to abandon a particular application at any time. MI of these risks and their associated costs would be borne by the proposed project. • 5-19 • • • In a recent application submitted for another Calpine facility, which is also in EPA Region IX, an analysis of available CEMS data for the SCONOx system at the Federal facility was conducted(please refer to the supplemental BACT analysis for Metcalf Energy Center). For the period covering July through December 1997,review of the available SCONOx data indicated that up to 12 exceedences per year could be expected for a 3.0 ppm,3-hour average limit,even when exceedences related to startups and shutdowns were excluded. According to the analysis,for a combined cycle gas turbine with a limit of 2.0 ppm on a 3-hour average basis(the BACT/LAER levels recommended by several agencies),the 1997 SCONOx data from the Federal site indicate that this limit would be exceeded 44 times per year (excluding exceedences associated with startups and shutdowns). Data was also obtained for the Federal facility from the period of April 1 through December 31, 1999. The more recent data are also consistent with the earlier data. According to the analysis,there were approximately 2,500 valid 1-hour average periods in the data set,excluding startups,shutdowns,and CEMS maintenance. For a 3.0 ppm limit based on a 3-hour averaging period, there were 20 exceedences(for the period April- December). • The analyses conducted show that the SCONOx system at the Federal facility is not capable of maintaining low NO.levels of 3.0 ppm or less on a continuous basis. Moreover,the more recent data do not indicate improved performance over time. In addition to performance-related concerns about the SCONOx system, there are several specific concerns regarding applying the SCONOx system to this project. Applying the system on a unit that is six times larger than its previous first time hill-scale application would require a major redesign of the dampers. The dampers at the Federal Plant are 10 feet wide. The HRSG for this project would be approximately 32 feet wide. A width that is 3.5 times greater than that previously demonstrated results in concerns about designing dampers that provide an adequate seal when fully opened and closed during the numerous regeneration cycles required(i.e.,as many as 35,000 times per year). This concern is heightened for an application • at temperatures greater than those at the Federal Plant(i.e.,650°F versus 320°F). In addition,potential 5-20 • • • interferences between damper actuators and the regeneration gas injection system would need to be resolved, as well as issues on attaining and maintaining cross flow distribution of regeneration gas across a 35 foot catalyst section. In an independent evaluation of SCONOx conducted by Stone & Webster, Independent Technical Review—SCONOx Technology and Design Review,from February 2000,it is reported that the initial operation of the SCONOx system at the second installation — the Genetics Institute facility in Massachusetts - resulted in a rapid loss of performance due to poor operation of the regeneration system. The problem was traced to mechanical deficiencies, such as seal and gasket leakage, and numerous corrective actions were necessary. Further changes to the overall system included adding an external reformer and adding a sulfur filter to remove sulfur from the gas that feeds the external reformer. Moreover,Stone&Webster reports that a number of damper/seal design changes have been proposed by ABB based on results from testing of the system. The following is an evaluation of the proposed AIP criteria as applied to the achievement of extremely • low NQ levels using SCONOx technology. Commercial availability: SCONOx is available through only one vendor and has been applied to a very limited number of projects. In a press release, Goal Line/ABB indicate that commercial performance guarantees will be provided for SCONOx upon request. Although,due to the lack of information in the public domain,there are still questions regarding whether SCONOx technology is presently available with standard commercial guarantees for NQ levels as low as 2.0 ppm. Another concern is whether the guarantee will be passed on by the HRSG vendors. Also,will the system be able to achieve 3 ppm controlling both the turbine and duct burner emissions,especially on a system with a large number of duct burners Thus,numerous questions exist regarding the availability of a commercial guarantee for SCONOx. There are also numerous questions regarding scale-up of a SCONOx system to units of the size proposed for this project,consequently,problems associated with installation and operation have to • be anticipated. As previously mentioned,even if a commercial guarantee is available, it does not 5-21 • • cover the loss of revenue associated with downtime and the potential need to replace the SCONOx system with an SCR system if the required emission level cannot be achieved. Reliability: Due to the fact that the SCONOx system has not been installed and operated for an extended period of time on a utility-scale turbine,serious questions exist regarding the reliability of the system on such an installation. As the CEMS data from the Federal facility indicate,there has not been a demonstration of the SCONOx system's ability to meet NOx levels of 3 ppm or lower over an extended period of time without numerous exceedences. There have also been numerous design changes since the original SCONOx installation at the Federal plant. As witnessed in the Stone& Webster report,there have been problems at the Genetics Institute facility that have also required redesign. Consequently, the system that would be applied to a utility-scale application would also likely require design changes,thus,the reliability of the SCONO,system is substantially unknown. Effectiveness: The analysis contained in the MEC application demonstrates that the effectiveness • of the SCONOx system to meet a 3 ppm limit on a consistent basis without exceedences is in question. Also,there have been numerous design changes associated with the SCONOx system and as such it is uncertain as to whether the actual system that would be installed on a larger,utility- scale turbine has been subjected to performance testing. From the available data, if SCONOx technology were to be used to achieve extremely low NQ levels,it would be necessary to include permit conditions that would allow for the potentially frequent NO„ excursions under certain conditions. Technology Transfer: SCONOx technology has been found to be capable of achieving extremely low NOx levels by SCAQMD and EPA (although the data from the Federal facility does not support this conclusion for an extended period of time,at least not without numerous exceedences). The SCONOx system has not been installed on a utility-scale turbine for an extended period of time, and serious technical concerns have been enumerated in this application regarding such a scale-up of the technology. While it is not fair to regard this as technology transfer,it is fair to say S 5-22 • that SCR has been installed on many more similar installations and is a more demonstrated technology. In summary,the evaluation concludes that the SCONOx process is not commercially demonstrated on larger, utility-scale turbines and the economic risks to the project versus SCR are considerable. This is because the moderate temperature SCONOx process (post-HRSG location) has not been commercially demonstrated on units the size of the proposed project, and the high temperature SCONOx process(mid-HRSG location)proposed by the developers for large turbines has not been commercially demonstrated on any size unit. The significant technical/economic risks are a result of the following: • No commercial demonstration of the SCONOx catalyst operation/regeneration at the mid-HRSG location proposed by the developers for large combustion turbine units like the proposed units; • No commercial demonstration of the regeneration gas system proposed by the developers for large combustion turbine units like the proposed units; • No commercial demonstration of a much larger more complex damper system needed 411, to apply the SCONOx technology to very large CT/HRSG systems(concerns here are related to size, complexity, and placement of a damper system into a higher temperature position of the HRSG(i.e., 650 °F versus 350 °F)); and, • The additional complexity of the SCONOx technology when compared to SCR. This additional complexity will result in lower project availability and could impact revenue generation. 5. Select BACT Based on the analysis presented,either SCR or SCONOx is generally considered capable of achieving NOx levels of 3.0 ppm for combustion turbines. Technical concerns are associated with the use of SCONOx however. BACT for NO„is considered to be the use of either SCR or SCONOx systems in conjunction with dry low-NO„combustors to achieve NOx levels for the combustion turbines of 3.0 ppm on a 3-hour average basis. The proposed project will have duct burners in the HRSG(low-NOx design),consequently,the proposed BACT rate needs to be higher to take this supplemental firing into account. Consequently, a NO„ level of 3.0 ppm on a 3-hour average basis is proposed, which is consistent with the lowest emission rates contained in the RBLC. Due to the technical concerns related • 5-23 • to the use of SCONOx and the increased cost,the project proposes the use of SCR technology to meet this emission rate. Thus,the proposal is consistent with the BACT requirements for NON. 5.1.3 Evaluation of Ammonia Emissions Although secondary emissions associated with the operation of an air pollution control device are typically excluded from BACT requirements,ammonia slip is often discussed in association with SCR. The following section discusses ammonia emissions as a result of the choice of control system and is presented in an analogous format to that for NOR. An economic analysis is also provided to show that the benefit of no ammonia emissions associated with SCONOx does not outweigh the cost of using this technology. 1. Identify Potential Control Technologies Ammonia emissions result from the use of ammonia-based NON control technologies(e.g.,SCR). As presented previously, the reduction of NON emissions can be achieved by wet and dry combustion . controls and post-combustion flue gas treatment. Combustion controls act to reduce the formation of NON during the combustion process, while post-combustion controls remove NON from the exhaust stream after it is generated. Potential NON control technologies as identified for combustion turbines and duct burners include the following: Wet combustion controls • Water injection • Steam injection Dry combustion controls • Dry low-NON combustor design(with low-NOx burners for the duct burners) • Other combustion modifications • Catalytic combustors(e.g., XONON) • 5-24 • Post-combustion controls • Selective catalytic reduction(SCR) • Selective non-catalytic reduction(SNCR) • Non-selective catalytic reduction(NSCR) • SCONOx Two of these NQ control technologies result in ammonia emissions, SCR and SNCR. 2. Evaluate Control Technologies for Technically Feasibility Based on the previous discussion, the following NQ control technologies are considered technologically feasible for the proposed project: • Water injection • Steam injection • • Dry Low-NOx Combustors • Selective Catalytic Reduction • SCONOx Of these technically feasible control alternatives,only SCR results in ammonia emissions. 3. Rank Technically Feasible Control Technologies by Control Effectiveness Table 5-3 presents the technically feasible control technologies ranked by potential ammonia emissions. S 5-25 • • • Table 5-3: NO,Control Technologies Ranked by Ammonia Emissions Ammonia NO‘Control Technically Emissions Alternative Available? Feasible? (@ 15% 02) Selective Catalytic Yes Yes 5-10 ppm Reductions SCONOx Yes" Yes` 0 ppm Dry Low-NO„ Yes Yes 0 ppm Combustors Steam Injection Yes Yes 0 ppm Water Injection Yes Yes 0 ppm a Typically used in conjunction with wet or dry combustion controls. " The availability of commercial guarantees for utility-scale projects is not clear. ` This technology has been used on two small (5 MW and 23 MW) gas turbines; it has not been demonstrated on utility-scale gas turbines. 4. Evaluate Most Effective Controls for BACT • The proposed turbines will be equipped with dry low-NO„combustors,which have largely superceded water and steam injection due to improved performance. Thus,water injection, steam injection,and dry low-NO„ combustors are not discussed further. SCR and SCONOx are assumed to be able to achieve equivalent NO„ reductions. SCONOx does not result in ammonia emissions, while SCR results in ammonia"slip"in the range of 5-10 ppm. Ammonia slip generally results from a gradual decline in catalyst activity over time. This requires increasing the amount of ammonia injected in order to maintain NO,concentrations at or below the design rate. Ammonia slip levels are usually specified for an associated NQ concentration and represent the maximum amount of ammonia emissions expected. At the initial catalyst installation ammonia slip is typically quite low, such as 1-2 ppm, and as the catalyst performance declines over time it begins to approach the guarantee level. • 5-26 • • • Ammonia is not included on the Federal list of hazardous air pollutants. Although with the recent increase in power plant projects, especially those using combustion turbines and SCR controls, ammonia slip requirements are usually included as a permit term. For instance,the Northeast States for Coordinated Air Use Management(NESCAUM)has recommended an ammonia emissions limit of 10 ppmv,unless this limit is shown to be inappropriate. In order to determine what ammonia slip levels have been included in recent permitting a query of the RBLC database for ammonia was conducted. The RBLC was searched for natural gas internal combustion(process type code 15.004) and also for the keyword turbine. Twenty-four entries were found with ammonia limits since January 1990. Some entries only had limits in terms of lb/hr or lb/MMBtu. In order to have a normalized frame of reference only those entries with ppm limits were considered. The range of permitted ammonia limits is 10 to 30 ppm. The applicant is aware of some projects that have been permitted with very low ammonia slip rates, however, these were either associated with higher NO„levels or the facilities are not in operation yet,so the rate is not considered demonstrated in practice. • 5. Select BACT The project has proposed an ammonia slip rate of 10 ppm,which is consistent with information from the RBLC. As mentioned previously,this is the maximum level of ammonia emissions that is expected to occur only at the end of the catalyst life. Lower ammonia slip rates have been permitted,however, the applicant is not aware of any sources in operation with extremely low NO„levels(on the order of 2.0 ppm for combustion turbines)and lower ammonia slip rates. As discussed previously, SCR is proposed as the control technology to meet the NQ limit of 3.0 ppm (on a 3-hour average basis) for the turbines and duct burners, due to technical concerns and costs associated SCONOx. However, the SCONOx technology does not have associated ammonia emissions. Therefore,a further evaluation of the cost-effectiveness of this technology was performed with regards to the incremental cost assigned to the benefit of eliminating ammonia slip. The use of 5-27 • • • SCONOx is assumed to eliminate all ammonia emissions,which would be a reduction of 123.2 tons per year. Assuming a conservative cost-effectiveness value of$5,000/ton,SCONOx would be cost-effective for the reduction of ammonia emissions if the annual incremental cost,as compared with SCR,is less than $637,500 per year. This amount is calculated by multiplying the reduction in ammonia emissions(in TPY)by the cost-effectiveness value of$5,000/ton,as follows: 135.3 tpy * $5,000/ton= $676,500 year Tables 5-4A through 5-4C present the cost-effectiveness analysis. As shown in Table 5-4A,the total annualized costs for SCR (per turbine/HRSG) are $1.38 million. Table 5-4B presents the total annualized costs for SCONOx, which are $4.6 million. Table 5-4C presents the annual incremental cost. Thus,the annual incremental cost of SCONOx is$3.22 million per year per turbine,or over$9 million per year for the facility. Consequently,SCONOx is not cost-effective when compared to SCR. • The applicant proposes to use SCR technology to meet a NQ level of 3.0 ppm on a 3-hour average basis for the combustion turbines and duct burners with an ammonia slip level of 10 ppm. This proposal is consistent with BACT requirements and with emission rates found in EPA's RBLC database. Table 5-4A: SCR CostsjPer Gas Turbine/HRSG) Description of Cost Cost Factor Cost($) Notes Direct Capital Costs(DC): Purchased Equip.Cost(PE): Basic Equipment: Auxiliary Equipment:HRSG tube/fin modifications Instnunentation: SCR controls Ammonia storage system: Taxes and freight:: PE Total: $1,750,000 I Direct Install.Costs(DI) • Foundation&supports: 0.08 PE $140,000 2 5-28 • • • Table 5-4A: SCR Costs(Per Gas Turbine/HRSG) Description of Cost Cost Factor Cost($) Notes Handling and erection(included in PE cost): — $0 I Electrical(included in PE cost): _ $0 1 Piping(included in PE cost): $0 1 Insulation(included in PE cost): $0 1 Painting(included in PE cost): $0 1 DI Total: $140,000 Site Preparation for ammonia tanks(included in PE cost): $0 1 DC Total(PE+DI): $1,890,000 Indirect Cost(IC): Engineering: 0.10 PE $175,000 2 __ Construction and field expenses: , 0.05 PE $87,500 2 Contractor fees: 0.10 PE $175,000 2 _ Start-up: 0.02 PE $35,000 2 _ Performance testing:_ 0.01 PE $17,500 2 Contingencies: 0.05 PE $87,500 1 IC Total: $577,500 _ Less:Capital cost of initial catalyst charge _ -$630,000 Total Capital Investment(TCI=DC+IC) $1,837,500 • Direct Annual Costs(DAC) 0.5 hr/SCR per shift hr/yr:4,380 Operating Costs(O): sched.(hr/day):24 day/wk: 7 _ wk/yr: 52 Operator: hr/shift: 1.0 operator pay:($/hr) 39.20 $42,806 2 Supervisor: 15%of operator $6,421 2 Maintenance Costs(M): 0.5 hr/SCR per shift Labor: hr/shift: 1.0 labor pay($/hr): 39.20 _ $42,806 2 Material: %of labor cost: 100% $42,806 2 Utility Costs: Perf loss: (kwh/unit):0.0 SCONOx losses are shown as incremental to SCR losses 1 Electricity cost: ($/kwh):losses $0 Ammonia: based on 325 lbs/hr of 28%wt aqueous ammonia $626,340 1,4 $440/ton _ Catalyst replace: based on 3 year catalyst $210,000 I Catalyst dispose: based on 2,750 square foot catalyst,3 yr life $13,750 1 Total DAC: $15/ft $984,930 Indirect Annual Costs(IAC): Overhead: 60%of O&M $80,904 2 Administrative 0.02 TCI $36,750 2 Insurance: 0.01 TCI $18,375 2 _ Property tax: 0.01 TCI $18,375 2 Total IAC: $154,404 Total Annual Cost(DAC+AC) $1,139,334 _ Capital Recovery(CR): _— al _ Capital recovery: interest rate(%): 10 period(years): 15 0.1315 $124,583 2 5-29 • • STable 5-4A: SCR Costs(Per Gas Turbine/HRSG) Description of Cost Cost Factor Cost($) Notes Total Annualized Costs: $1,380,917 Table 5-4B SCONOx Cost and Incremental Cost(per gas turbine/HRSG) Direct Capital Costs Notes: Capital(less cost of initial catalyst change) $3,900,000 3,5 Installation $1,700,000 3 Indirect Capital Costs Engineering $200,000 3 Contingency $250,000 3 Other - Total Capital Investment _ $6,050,000 Direct Annual Costs Maintenance $250,000 3 Ammonia - 3 S Natural Gas:2.2 MMBtu/hr 4$3,77/MMbtu $72,655 _ 1,7 Pressure Drop $226,000 3 Catalyst Replacement(based on 3-yr catalyst life) $3,033,333 5,6 Catalyst Disposal $0 Total Direct Annual Costs $3,581,989 Indirect Annual Costs _ Overhead _ - 3 Administrative,Tax&Insurance $225,000 TOTAL ANNUAL COST $3,806,989 Capital Recovery Factor 0.1315 2 Capital Recovery $795,416 TOTAL ANNUALIZED COSTS $4,602,405 Table 5-4C SCONOx Incremental Cost(per gas turbine/HRSG) Notes: SCONOx Annualized Costs $4,602,405 SCR Annualized Costs $1,380,917 Incremental Annualized Costs $3,221,488 5-30 • • Table 5-4 Notes SCONOx Cost Effectiveness Analysis Note No. Source 1 Based on information from Calpine and Bechtel Power Corporation. 2 From EPA/OAQPS Control Cost Manual. EPA-450/3-90-006, January 1990 3 From April 12,2000 letter from ABB Alstom Power to Matt Haber EPA Region IX(SCONOx — capital cost of$13,000,000) 4 Based on aqueous ammonia cost per$440/ton. 5 Based on information from May 8, 2000"Testimony of J. Phyllis Fox, Ph.D. on Behalf of the California Unions for Reliable Energy on Air Quality Impacts of Elk Hills Power Project', cost of replacement catalyst for SCONOx is 70%of initial capital investment. 6 Based on information from May 5, 2000 letter from ABB Alstom Power to Bibb and Associates indicating that SCONOx catalyst life is guaranteed for a 3-year period. 7 Personal communication,ABB Environmental 1/18/00 5.1.4 Analysis of Control Requirements for Carbon Monoxide 1. Identify Potential Control Technologies Carbon monoxide(CO)is a product of incomplete combustion. CO formation is limited by ensuring complete and efficient combustion of the fuel in the combustion turbine. High combustion • temperatures, adequate excess air, and good air/fuel mixing during combustion minimize CO emissions. Measures taken to minimize the formation ofNOx during combustion may inhibit complete combustion, which could increase CO emissions. Lowering combustion temperatures through premixed fuel combustion can be counterproductive with regard to CO emissions. However,improved air/fuel mixing inherent in newer combustor designs and control systems limits the impact of fuel staging on CO emissions. The applicable NSPS does not contain requirements for CO,thus,there is no real baseline emission rate. Based on a review of the information provided in the RBLC database and knowledge related to the control of CO emissions from combustion sources,the following CO control approaches were identified: • CO oxidation catalyst • SCONOx • Good combustion control 5-31 • 2. Evaluate Control Technologies for Technical Feasibility Oxidation catalysts have previously been applied to natural gas-fired combustion turbines located in CO nonattainment areas, and there are numerous suppliers of oxidation catalyst systems. The catalyst lowers the activation energy for the oxidation of CO to CO2 so that CO in the exhaust gas is converted to CO2. For units that include duct firing,the placement of the catalyst is defined by the need to protect it from temperatures in excess of 1100 degrees F. Because the removal efficiency of CO is fairly constant above approximately 550 degrees F, there is only minimal impact to the catalyst's performance associated with placing it further back in the HRSG. This technology has been applied to natural gas-fired combustion turbines of all sizes,and as such,is considered a demonstrated technology. CO removal efficiencies of up to 90 percent are typical.The oxidation catalyst is typically a precious metal catalyst. As the basis of control used to evaluate BACT for this application, 90 percent removal is used. • The SCONOx process previously discussed as part of the NOx BACT analysis is used to control both NOx and CO. The SCONOx system provides for control of CO emissions to levels comparable to that of a conventional oxidizing catalyst. As part of the NOx BACT discussion,it was noted that SCONOx is currently being applied to a 25 MW sized combustion turbine operating at the Federal Plant. Based on available literature describing the Federal Plant's operation, a 90 percent removal efficiency is evaluated. Technical concerns were identified in association with application of the technology on a larger combustion turbine,however,this technology will be considered technically feasible for this analysis. Good combustion control, as the name infers, is based upon maintaining good mixing, a proper fuel/air ratio, and adequate time at the required combustion temperature. This technology is technically feasible and is the most commonly used technology to control CO emissions. Good combustion control is considered the baseline control technology for CO emissions. Thus, an evaluation is provided for the two most stringent technically feasible control technologies, an oxidation catalyst and SCONOx, for energy, environmental, and economic impacts. I 5-32 • r • 3. Rank Technically Feasible Control Technologies by Control Effectiveness Both an oxidation catalyst and SCONOx are considered in this analysis. Control efficiencies for both controls are 90 percent. Consequently,the following analysis compares these two controls as being equally effective for CO control. 4. Evaluate Most Effective Controls for BACT The addition of a CO oxidation catalyst to reduce outlet emissions to 9 ppmv(including duct burner firing)was evaluated. This requires a control efficiency of 90 percent which is achievable in practice and can be guaranteed. For SCONOx,a 90 percent removal was also evaluated as potential BACT. The BACT evaluation that follows considered the energy,environmental,and economic impacts of the potential BACT levels evaluated. Energy Impacts: There is a pressure drop associated with each of the add-on controls that were evaluated. This pressure drop results in a backpressure on the combustion turbine, which in turn • increases the heat rate(i.e.,decreases the turbine's efficiency). The end result is an energy impact in the form of additional fuel to make the same amount of electricty. Based on vendor information the increased backpressure on the turbine associated with oxidation catalyst systems is 1.5 inch w.c. Although, the backpressure for a SCONOx system is likely greater, a similar backpressure of 1.5 inch w.c. is used for this analysis. Each inch w.c. of backpressure on the turbine results in a 0.15%increase in the heat rate(i.e.,Btu/kwh). As a result,there is an increased fuel requirement to generate the same amount of power output. This penalty is included as an annual cost. It should also be noted that the additional fuel firing also results in additional emissions of some pollutants. Environmental Impacts: The spent oxidation catalyst is comprised of precious metals that are not considered toxic. This allows the catalyst to be handled and disposed of following normal waste procedures. Because of its precious metal content,the catalyst is often recycled by the manufacturer to recover the metals. The SCONOx system providers also take back the catalyst for reconditioning. The effective power reduction due to the pressure drop across the two add-on control technologies increases the emission rate of other criteria pollutants, such as NOx,on a per unit of power output. • 5-33 • • • The use of natural gas in the catalyst regeneration process for SCONOx will result in release of some natural gas (methane) to the atmosphere due to leakage and venting. As noted above, the SCONOx catalyst also must be regenerated using a 4-step potassium carbonate bath and water rinses. Each module will generate approximately 1,500 gallons of wastewater per step. A SCONOx installation for the Project is expected to require the use of 40-60 modules. Even assuming the low end of only 40 modules,there would be approximately 720,000 gallons of wastewater produced each year for the three turbines(i.e.,4 x 1,500 x 40 x 3). Production of the regeneration gas requires additional water to generate the steam needed for the process. Such a significant increase in water consumption and waste discharge associated with SCONOx is a considerable concern for the project. Another concern associated with SCONOx,as discussed in further detail in the NO„BACT section, is that an installation of the system in the hot section of the HRSG has not been demonstrated to the satisfaction of the HRSG suppliers. HRSG suppliers are not yet willing to offer performance guarantees for their equipment if the SCONOX system is installed in the hot section of the HRSG. • Economic Impacts: A summary of the capital and annual costs associated with the installation of an oxidation catalyst and SCONOx are presented in Table 5-5. The detailed cost analysis for the oxidation catalyst is shown in Table 5-6. Please refer to Table 5-4B for the SCONOx cost analysis. The cost of the oxidation catalyst system includes the catalyst, catalyst housing, HRSG modifications, and balance of plant equipment. Capital costs are based on scaled estimates from previous budgetary quotations from equipment manufacturers and other engineering estimates. It should be noted that the previous estimates were for systems of nearly the same size. As shown,the per turbine/HRSG total installed capital cost for the oxidation catalyst system is $1,954,050. The total installed capital cost for the SCONOx system is $6,050,000. The annual operating costs associated with the two alternative approaches are also presented in Table 5-5. The annual operating costs include catalyst replacement,energy impacts due to increased fuel usage, operating personnel, and maintenance. Throughout the life of the facility, the catalyst • will require periodic replacement. Catalyst manufacturers are currently willing to guarantee a 5-34 • • • three-year catalyst life. Maintenance consists of the routine catalyst replacement costs. Labor for the operation and maintenance of the combustion control system is considered a part of the facilities normal operating expenses. The estimated annual operating cost associated with the oxidation catalyst and SCONOx systems are $733,356 and $3,806,989, respectively. Table 5-5. Summary of CO BACT Evaluation Results* Control Capital Cost Annual Cost Annualized Cost Oxidation Catalyst $1,954,050 $733,356 $990,314 SCONOx $6,050,000 $3,806,989 $4,602,405 * All costs are presented on a per gas turbine/HRSG basis • 5. Select BACT Based on the above discussion, both control technologies evaluated for CO control, an oxidation catalyst and SCONOx, are considered technically feasible and provide comparable reduction efficiencies. Even though the proposed project is located in an attainment area, and controls beyond combustion controls have not typically been required in attainment areas,the project is proposing the use of an oxidation catalyst to meet BACT requirements of 9 ppm. The use of an oxidation catalyst versus SCONOx is supported by the technical questions associated with SCONOx and the large difference in cost. 5.1.5 Analysis of Control Requirements for PMio PMio is a Clean Air Act regulated pollutant defined as particulate matter equal to or less than a nominal aerodynamic particle diameter of 10 microns. Particulate matter is typically described as filterable and condensable PM. The following discussion explains the formation of both for combustion sources. 5-35 r • • Table 5-6. Oxidation Catalyst Costs (per_gas turbine/HRSG) Description of Cost Cost Factor Cost Direct Capital Costs(DC): Purchased Equipment Cost(PE): Catalyst Catalyst Reactor(HRSG mod.) Control/Instrumentation Taxes and Freight PE Total: $1,405,000 Direct Installation Costs(DI): Foundation&Supports 0.08 PE $112,400 Handling and erection(included in PE cost) Electrical(included in PE cost) Insulation(included in PE cost) Painting(included in PE cost) Dl Total: $112,400 DC Total(PE+DI): $1,517,400 Indirect Costs(IC): Engineering: 0.10 PE $140,500 Construction and field expenses: 0.05 PE $70,250 Contractor fees: 0.10 PE $140,500 Start-up: 0.02 PE $28,100 Performance testing: 0.01 PE $14,050 • Contingencies: 0.05 PE $70,250 IC Total: $436,650 _ Total Capital Investment(TCI=DC+IC) $1,954,050 _ Direct Annual Costs(DAC): Operating Costs: Operator Same as SCR $42,806 Supervisor 15%of Operator $6,421 Maintenance Costs: Labor Same as SCR $42,806 Materials 100%of labor $42,806 Utility Costs Catalyst replacement $378,500 Power consumption(backpressure) $60,950 Total DAC $574,289 Indirect Annual Costs(IAC): Overhead 60%of O&M $80,904 Administration 0.02 TCI $39,081 Insurance 0.01 TO $19,541 Property tax 0.01 TCI $19,541 Total IAC _ $159,067 Total Annual Cost(DAC+ IAC) $733,356 Capital Recovery Interest rate: 10% Period: 15 years 0.1315 $256,958 Total Annualized Costs _ $990,314 5-36 • For combustion sources, there are three potential sources of filterable PM 10 emissions: mineral matter found in the fuel,solids or dust in the ambient air used for combustion,and unburned carbon or soot formed by imcomplete combustion of the fuel. There is no source of mineral matter for natural gas-fired combustion sources,such as the proposed turbines and duct burners. In addition,as a precautionary measure to protect the high speed rotating equipment with a combustion turbine,the inlet combustion air is filtered prior to compression and use as combustion air. Also, the potential for soot formation in natural gas-fired turbines and duct burners is very low because of the excess air combustion conditions under which the fuel is burned. As a result, there is no real source of filterable PKo originating from either the turbine or duct burners. There are two sources of condensable PM10 for combustion sources: condensable organics that are the result of incomplete combustion and sulfuric acid mist that is found as sulfuric acid dihydrate (H2SO4.2H2O). For natural gas-fired sources,there should be no condensable organics originating from the source because the main components of natural gas (i.e., methane and ethane) are not condensable at the temperatures found in a Method 202 ice bath (the EPA reference method for • measuring condensable PM). Thus, any condensed organics are from the ambient air. The most likely source of condensable PKo from natural gas-fired combustion sources is sulfuric acid dihydrate,which results when sulfur in the fuel and in the ambient air is combusted and then cools. Appendix M of 40 CFR Part 51 recommends that EPA Reference Methods 201 or 201A be used to measure in-stack emissions of PMio. As part of Appendix M,EPA also recognizes that condensible emissions not collected by an in-stack method are also PM10 and that these emissions contribute to ambient PM10 levels. As a result,to establish source specific contributions of PM10,EPA suggests that PMIo measurements include both condensable particulate matter emissions and emissions measured by the in-stack methods. The use of EPA Reference Method 202 is recommended for determining the portion of condensable PM emissions that are PM10 from stationary sources. The Method 201/201A and Method 202 portions of the sample are referred to as the filterable and condensable portions, because the PM] emissions form a source represent the sum of these two measurements. Only the most recent NSR permits issued for turbines require the measurement of 5-37 • • both the filterable and condensable portions. Most combustion turbine permits only require measurement of the filterable PM10. Thus, comparison of the proposed PKo emission rate to emission rates in the RBLC can be tricky,because the lower rates may represent only the filterable PKo portion, and not be directly comparable. Based upon the above discussion, the amount of both filterable and condensable PMio emissions from the natural gas-fired combustion turbines and duct burners should be very small relative to the total exhaust flow. However, the vendor guaranteed base load PMio emission rates are 11 lb/hr (0.0062 lb PM io/MMBtu)for the turbines and 0.010 lb PM10/MMBtu(6.6 lb/hr)for the duct burners. Vendor data on expected PM,() emission rates are designed to allow for the high level of test error inherent in sampling for an extremely small quantity of PM10 in a very large exhaust flow. In order to reduce the amount of variability/error, longer sampling times than are normally used by stack testers during compliance testing are required. Permit data from EPA's RBLC database beginning with January 1990 were searched for PM and iPM,o BACT decisions and corresponding limits. In particular,data listed for similarly sized natural gas-fired installations were reviewed in detail. Based on a review of the information provided in the RBLC database,a knowledge of combustion source PM and PM,()controls,and taking into account technology transfer from other combustion sources, the following PMI() control approaches were identified: • Add-on control technologies including: electrostatic precipitators, baghouses or fabric collectors, and venturi or packed bed scrubbers; • Combustion turbine lubrication oil exhaust vent coalescers; • Combustion turbine inlet air evaporative coolers; • Use of clean(i.e., low ash) and low sulfur fuels such as distillate oil or natural gas; and • Combustion controls and practices designed to minimize the production of soot. Add-on controls are used to control particulate emissions from solid fuel(i.e.,coal,coke,or waste) and residual oil-fired boilers because of the relatively high level of mineral matter(i.e.,ash)in these fuels. There are no known applications of add-on controls for the purpose of controlling PM from • distillate oil or natural gas-fired units,because these fuels have little if no ash that would contribute 5-38 • to the formation of PM or PM10. In addition, PM emissions from add-on control devices are typically higher than from uncontrolled natural gas-fired combustion units. Therefore,add-on PKo controls do not make practical sense and are not considered feasible for natural gas-fired turbines and duct burners. Two CT sites located in California were identified as having LAER-based permit PKo limits and controls that included natural gas-firing, an air inlet filter cooler, and lube oil vent controls. The permit for one of the sites required the lube oil vent to be routed to the exhaust stream of the turbine, and the other site's permit required installation of an oil mist coalescer on the vent. Contact with a permit engineer at San Joaquin Valley Unified Air Pollution Control District indicated that the district requires the installation of oil mist coalescers designed to achieve a 95%removal efficiency of the oil mist. Inclusion of oil mist coalescers are usually standard practice on large frame turbines, such as the ones proposed. Vendor information indicates that venting the controlled stream to the turbine's exhaust would not be a form of control,but of dilution. For these reasons,the practice of routing the coalescer treated lube oil mist vent to the turbine exhaust is not considered further in this • analysis. The proposed combustion turbines will include inlet air filters, which are required as part of the design to protect the rotating equipment. Inlet air coolers are included on units located in arid regions where high ambient tmeperatures combined with low relative humidity can sometimes preclude the ability to fire the turbine at full load. To overcome this, an inlet air cooler is placed downstream of the inlet air filters and upstream of the compressor air intake. Combustion air is drawn across a wetted surface (similar to a home humidifier screen) or fogging nozzles spray moisure directly into the inlet air. As a result of these processes,the inlet air is cooled and picks up moisture. These devices clean the ambient air upstream of the source, rather than controlling the emissions generated by the source. Therefore, these devices are not considered further in this analysis. The proposed combustion turbines and duct burners are natural gas-fired. They are also equipped • with state-of-the-art combustion controls to ensure maximum fuel efficiency. As a result, the 5-39 • conversion of fuel carbon to CO2 will be maximized and the production of carbonaceous particulates minimized. In conclusion,because the combustion turbines and duct burners will fire clean burning natural gas, and their combustion controls will be state-of-the-art, add-on controls are not considered feasible. Particulate emissions from the proposed combined cycle units will be controlled via proper combustor design, operation, and maintenance. With respect to combustion controls,there are no significant economic, energy, or environmental impacts. Review of the RBLC database indicates PM/PM 10 limits in the range of 0.0023 -0.06 lb/MMBtu. The PKo emission rate for the proposed combined cycle units is toward the lower end of the range,approximately 0.01 lb/MMBtu. As noted before, it is difficult to make a direct comparison to the results in the RBLC because it is unclear as to whether the emission rate contained in the database includes both condensable and filterable PM. 5.1.6 Analysis of Control Requirements for VOC This section presents the BACT analysis for the proposed units having a potential to emit VOC(i.e.,the • combustion turbines and duct burners). The water circulated through the cooling tower will be noncontact cooling water and no water treatment chemicals containing VOC will be used. Consequently,the cooling tower does not have the potential to emit VOC and therefore has not been evaluated in this analysis. The proposed combustion turbines and duct burners are natural gas-fired combustion units. The VOC emissions from natural gas-fired combustion sources are the result of two possible formation pathways: incomplete combustion, and recombination of the products of incomplete combustion. Complete combustion is a function of three key variables:time,temperature,and turbulence. Once the combustion process begins,there must be enough time at the required combustion temperature to complete the process, and during combustion there must also be enough turbulence or mixing to ensure that the fuel gets enough oxygen from the combustion air. Combustion systems with poor control of the fuel to air ratio,poor mixing,and/or insufficient time at • combustion temperatures have higher VOC emissions than those with good controls. The proposed 5-40 • • • turbines and duct burners incorporate state-of-the-art combustion technology,and both are designed to achieve high combustion efficiencies. As a result,the proposed combustion equipment has very low expected VOC emission rates. The two most prevalent components of natural gas, methane (--92% by vol.) and ethane (-5% by vol.), are not defined as VOCs. The remaining portions of natural gas are propane and trace quantities of higher molecular weight hydrocarbons,all of which are nearly 100%combusted. The high energy efficiency of turbines and duct burners and low fraction of VOCs in natural gas result in a very low VOC emissions rate for the proposed new units. Additionally, the recombination of products of incomplete combustion is unlikely in well controlled turbine/duct burner systems because the conditions required for recombination are not present. Based on a review of the information provided in the RBLC database and knowledge related to the control of VOC emissions from combustion sources, and taking into account technology transfer from other combustion sources, the following VOC control approaches were identified: • • Thermal oxidation, • Catalytic oxidation, and • Good combustion design and operation. Thermal oxidizers are used for combustion systems where VOC rates are high, such as waste incinerators. The thermal oxidizers for these types of sources are in the form of secondary combustion chambers and afterburners and are inherent to the combustion system's design. The VOC emissions from these types of sources are much higher because they combust fuels that are heterogeneous in nature and as a result it is difficult,if not impossible,to maintain the uniform time, temperature, and turbulence needed to ensure complete combustion. Thermal oxidation systems work by raising the VOC containing stream to the combustion temperature to allow the combustion process sufficient time to reach completion. The controlled VOC rates from these systems are still higher than those being proposed for this project without VOC control. Also, because thermal oxidizers combust fuel, a significant amount of NOx emission can be generated. As such,thermal • oxidizers are not considered further in this anlaysis. 5-41 • Oxidation catalysts have traditionally been applied to the control of CO emissions from clean fuel fired combustion sources located in CO nonattainment areas. As discussed previously, this technology uses precious metal based catalysts to promote the oxidation of CO and unburned hydocarbon (of which a portion is VOC) to CO2. The amount of VOC conversion is compound specific and a function of the available oxygen and operating temperature. Good combustion design and operation is the primary approach used to control VOC emissions from combustion sources. The VOC controls, inherent in the design and operation of a unit, include the use of clean fuels such as natural gas,and advanced process controls to ensure complete combustion and the best fuel efficiency. The proposed turbines and duct burners will be 100%natural gas-fired and each unit is designed with state-of-the-art combustion controls to maximize conversion of the natural gas to CO2, and minimize the production of VOC and CO. An oxidation catalyst is being proposed to control CO emissions, and such systems also achieve • VOC reduction. Thus,the highest ranking,technically feasible control technology is being proposed for VOC control. The proposed VOC emission rate is 2.0 ppmv, which is consistent with values from the RBLC, and represents BACT for VOC. 5.1.7 Analysis of Control Requirements for SO, The new combustion turbines and duct burners will be designed and operated to minimize emissions and will be fired solely with natural gas, which is inherently low in sulfur. Sulfur dioxide is formed during combustion due to the oxidation of the sulfur in the fuel. Add-on control devices (e.g., scrubbers)are typically used to control emissions from combustion sources firing higher sulfur fuels, such as coal. Flue gas desulfurization is not appropriate for use with low sulfur fuel, and is not considered for this project,because the realizable emission reduction is far too small for this option to be cost-effective. The use of natural gas is proposed as BACT for SO2. As discussed under the NSPS section, SO2 • emissions will be below the regulatory limits required by Subpart GG(there are no SO2 requirements in 5-42 • Subpart Db for natural gas fired units). Also, from the RBLC there is no precedent for use of post- combustion control of SO2 on combined cycle units. 5.2 BACT Analysis for the Cooling Tower Emissions of PM10 from cooling towers result from solid material,both dissolved and suspended,in the cooling water. Particulates are emitted when small droplets of cooling water,called drift,escape from the tower and evaporate. The dissolved and suspended materials in the drift become airborne particles when the water around them evaporates. PM to emissions from cooling towers are usually estimated by using the design drift rate and the solids concentration in the cooling water directed to the tower. Measurement of the emissions from a cooling tower is impractical,because of difficulties in obtaining a representative sample. There is currently no EPA Reference Method for sampling the exhaust from forced draft cooling towers.PM/drift testing at cooling towers is currently performed by using the Cooling Technology Institute test method ATC-140 (June 1994). I This section presents the PM10 BACT analysis for evaporative cooling towers similar to the tower proposed for this project. Evaporative cooling towers are designed to cool process cooling water by contacting the water with air, and evaporating some of the water. Thus, these units use the latent heat of water vaporization to exchange heat between the process and the air passing through the tower. This type of cooling tower typically contains a wetted medium to promote evaporation, by providing a large surface area and/or by creating many water drops with a large cumulative surface area. Some of the liquid water may be entrained in the air stream and be carried out of the tower. The concentration of total dissolved solids(TDS)in different cooling waters varies widely and is site dependent. For this project,because the water is noncontact cooling water the amount of TDS is not a result of the process it is cooling. Instead,it is a function of the cooling water source. For a given solids concentration,PM10 emissions from cooling towers depend on the amount of water that drifts from the tower. The amount of drift from evaporative cooling towers,usually expressed as a percent • of circulating water flow, is called total liquid drift. Total liquid drift is controlled by drift 5-43 • • • eliminators installed in the tower cells. Drift eliminators work by passing the cooling tower exhaust through mesh type media resulting in the inertial separation of water droplets (mist) from the air stream. The RBLC database was queried for entries since 1985 containing information on cooling towers with permit limits for PM and PM 10 . The search revealed that all cooling towers were equipped with drift eliminators with a total liquid drift of 0.001 to 0.004%of flow. There was no information that compliance had been verified via source testing at any of the operating cooling towers with PM or PMio limits. Also,no add-on PKo control technologies were identified. The proposed cooling tower for this project will be equipped with a high efficiency drift eliminator, rated for a maximum total liquid drift of 0.001%,expressed as a percent of total cooling water flow. The search of the RBLC database shows that all cooling towers with PM or PMI° limits use drift eliminators for PM/PM10 control. The proposed BACT limit of 0.001%total liquid drift is consistent with BACT requirements for PMto• • 5.3 BACT Analysis for the Auxilliary Boiler 5.3.1 Analysis of Control Requirements for Nitrogen Oxides 1. Identify Potential Control Technologies The baseline NQ emission rate for this analysis is considered to be 0.10 lb/MMBtu for the boiler, based on the applicable New Source Performance Standards (40 CFR Part 60, Subpart Db). This emission rate provides a comparison for the evaluation of control effectiveness and feasibility. Note that as an auxiliary boiler,the operation of the boiler will be limited to 1,900 hours/year. As with other combustion sources,NO„emissions from boilers can be reduced by combustion controls and post-combustion flue gas treatment. Combustion controls include low-NO„ burners and other combustion modifications,which act to reduce the formation of NQ during the combustion process. Post-combustion controls remove NO„ from the exhaust stream after it is generated. Potential NO„ control technologies for the boiler include the following: S 5-44 • • • • Low-NO,burners(LNB) • Flue gas recirculation(FGR) • LNB and FGR • Fuel specification—natural gas • Good combustion and design • Water/steam injection • SCONOx • Selective catalytic reduction(SCR) • Selective non-catalytic reduction(SNCR) 2. Evaluate Control Technologies for Technical Feasibility The performance and technical feasibility of the NO„controls listed above are discussed separately. Combustion controls are discussed first, and a discussion of the post-combustion control SCR and SNCR follows. The proposed boiler will be fired with only natural gas and be well-maintained and • operated with good combustion practices,thus these control options are not discussed separately below. • Low-NO,Burners Low-NO, burners (LNB) have been developed over the last few decades by applying combustion modifications to "conventional" burners. Low-NO„ burners are very common and there are many variations available from numerous manufacturers. A LNB is a packaged assembly that uses staged combustion techniques to reduce the formation of thermal NO,. The purposes of LNB are to reduce the amount of oxygen in critical NO,formation zones,to modify the introduction of air and fuel so that the rate of mixing is slowed,and to reduce the amount of fuel burned at the peak flame temperature.There are two basic types of LNB,air-stage and fuel-staged. Both types of LNB achieve the above objectives, thus,emissions are reduced when compared with conventional burners. • 5-45 • • • Flue Gas Recirculation As the name implies,with FGR a portion of the flue gas is recirculated and mixed with the combustion air supply. For new boiler installations,this is usually accomplished with a larger forced draft fan,as compared to that required without FGR. The objective of FGR is to lower the amount of oxygen available to react with nitrogen and reduce the flame temperature,both of which reduce the formation of NO,. One drawback to FGR is that efficiency is somewhat reduced due to the additional power requirements of the larger fan. The addition of FGR to a LNB assembly can result in further reductions in thermal NQ formation. • Water/steam injection As with turbines,injection of water or steam causes the combustion temperature to be lowered,which reduces the formation of thermal NOx. The performance of wet controls is primarily dependent on the water- or steam-to-fuel ratio, with NOx emissions decreasing as the water- or steam-to-fuel ratio • increases. Additional factors affecting the level of control are the combustor geometry and the design and location of the injection nozzle(s). Although the quenching effect of the water or steam lowers the peak flame temperature and thus reduces NQ emissions, it can also increase CO and hydrocarbon emissions,decrease combustion efficiency,and increase maintenance requirements due to incomplete combustion The reduction in efficiency also can increase with increasing water-or steam-to-fuel ratios and is typically greater for water injection(due to the heat of vaporization). • SCONOx for Boilers SCONOx for boilers,as with SCONOx for turbines,involves a catalyst system produced by Goal Line Environmental Technologies. The South Coast AQMD lists an entry in its BACT determinations for "other technologies"(i.e.,those that do not qualify as LAER)from April 2000 for SCONOx applied to a boiler. The application is on a 4.2 MMBtu/hr boiler at the Margaretis Textile Service (MTS Inc.) facility in Santa Ana, California. This boiler is much smaller than the boiler proposed in this • 5-46 • • • application. The entry states that this is the first application of SCONOx on a boiler and that the emission level is not considered achieved in practice. Estimated start-up for the boiler was May 2000. In the turbine NO„BACT section of this application a discussion was presented of the criteria used by the South Coast AQMD for determining whether a control is achieved in practice. Commercial availability requires that a commercial guarantee is available from the vendor. Given that this technology has only recently been applied to one source,the availability of a commercial guarantee for a much larger boiler is seriously in question. Also,the reliability of SCONOx on a larger boiler has not been demonstrated,and the estimated start-up of the only application on a much smaller boiler was just in May of last year. Thus,sufficient data to evaluate the reliability of SCONOx has not been generated. Also,the effectiveness of SCONOx on a large boiler has not been demonstrated. As a result of these factors,this control is not considered technically feasible for the proposed boiler. • Selective Catalytic Reduction • Selective catalytic reduction is a post-combustion flue gas treatment in which NO„ is reduced to nitrogen and water by injecting ammonia in the presence of a catalyst. The ammonia can be used in either the anhydrous or aqueous form. An ammonia injection grid is located upstream of the catalyst body and is designed to disperse ammonia uniformly throughout the exhaust flow before it enters the catalyst unit. The SCR catalyst is subject to deactivation by a number of mechanisms. Loss of catalyst activity can occur from thermal degradation,if the catalyst is exposed to excessive temperatures over a prolonged period of time,or from chemical poisoning. SCR has been used extensively on combustion turbines and to a somewhat lesser extent with boilers. The desired level of NO„control is a function of the catalyst volume and ammonia-to-NO.(NH3/NO.) ratio. For a given catalyst volume,higher NH3/NO,ratios can be used to achieve higher NO.emission reductions,but can result in undesirable increased levels of unreacted ammonia,called ammonia slip. • 5-47 • • • • Selective Non-catalytic Reduction SNCR is another post-combustion technology where NO„is reduced by injecting ammonia or urea into a high-temperature region, without the influence of a catalyst. The SNCR technology requires gas temperatures in the range of 1200 °F to 2000 °F,and the exhaust temperature for the proposed boiler will be less than 400 °F, which is below the minimum SNCR operating temperature. Thus, some method of exhaust gas reheat,such as additional fuel combustion,would be required to achieve exhaust temperatures compatible with SNCR operations. Based on the information in this section, the following NO,, control technologies are considered technologically feasible for the proposed boiler: • Low-NQ burners(LNB) • Flue gas recirculation (FGR) • LNB with FGR • • Water/steam injection • Selective Catalytic Reduction(SCR) • Selective Non-catalytic Reduction(SNCR). 3. Rank Technically Feasible Control Technologies by Control Effectiveness The technically feasible control technologies listed above are ranked by NO„control effectiveness in the traditional"top-down"format in Table 5-7. I 5-48 • • • Table 5-7: NOx Control Technologies Ranked by Effectiveness NOx Emission NOx Control Technically Reduction Alternative Available? Feasible? (%) SCR Yes Yes 80-90 LNB with FGR Yes Yes 60-85 Water/steam Yes Yes 50-70 injection LNB Yes Yes 40-90 FGR Yes Yes 40-70 SNCR Yes Yes 35-80 4. Evaluate Most Effective Controls for BACT For boilers such as the one proposed, low-NON burners (LNBs) have become standard. As the proposed auxiliary boiler will only operate 1,900 hours/year, the applicant is proposing to use Coen • low-NON burners as BACT. The applicant has chosen the highest level of control, thus, the other control technologies are not discussed further. The proposed emission rate is 30 ppmvd @ 3%O2. 5. Select BACT The applicant has chosen to apply low-NON burners for the proposed auxiliary boiler. From the"top- down" analysis, this represents on of the highest level of control for NON. This level of control is consistent with the control technologies listed in the RBLC, and in some cases exceeds the level of control for some recently permitted boilers. There is one entry in the RBLC for General Dyeing and Finishing(CA-0934)that lists 5 ppmvd @ 3%O2,however the contact for the district indicated that the proposed ultra low-NOx burner had operational problems and that the project was cancelled. A completely different boiler and burner are being used,which are designed to meet 30 ppmvd @ 3%O2. • 5-49 • 5.3.2 Analysis of Control Requirements for Carbon Monoxide 1. Identify Potential Control Technologies Carbon monoxide(CO)is a product of incomplete combustion. As with a turbine,CO formation in a boiler is limited by ensuring complete and efficient combustion of the fuel. High combustion temperatures, adequate excess air, and good air/fuel mixing during combustion minimize CO emissions. Measures taken to minimize the formation of NOx during combustion may inhibit complete combustion, which could increase CO emissions. Lowering combustion temperatures through premixed fuel combustion can be counterproductive with regard to CO emissions. However,improved air/fuel mixing inherent in newer burner designs and control systems limits the impact of fuel staging on CO emissions. The applicable NSPS does not contain requirements for CO,thus,there is no real baseline emission rate. Based on a review of the information provided in the RBLC database and knowledge related to the control of CO emissions from combustion sources,the following CO control approaches were • identified: • CO oxidation catalyst • SCONOx • Low NOx burners • Good combustion control The EPA RACT/BACT/LAER Clearinghouse (EPA-RBLC 2001) were reviewed to identify prior determinations for natural gas fired boilers. A review of the EPA BACT/LAER Clearinghouse information indicates that the most stringent CO emission level for a boiler is 0.018 lb/MMBtu for two 150 MMBtu/hr natural gas fired boilers in operation at the Basic American Foods Energy-American.I Cogeneration Plant in California. The facility has two water-tube boilers(model NS-F-85,Nebraska Boiler Company)that fire natural gas with No. 2 fuel oil used for stand by purposes. The emission limit for firing No.2 fuel oil is 0.019 lb/MMBtu. CO emissions for this facility are limited through the use of an oxidation catalyst. It should be noted that the Basic American Foods Energy project is located in a nonattainment area for CO and ozone. Champion International also lists a CO emission limit of • 0.018 lb/MMBtu for an 89 MMBtu/hour boiler;however,after checking with the issuing agency it was 5-50 • • • confirmed that the emission limit is actually 0.18 lb/MMBtu and is incorrectly listed in the BACT/LAER Clearinghouse database. The University of California Irvine Medical Center is operating a 48.6 MMBtu/hr natural gas-fired boiler with an emission limit of 50 ppmvd CO. These emissions are achieved by reducing CO emissions using good combustion controls and Alzeta ultra low NOx burners(ULNB). 2. Evaluate Control Technologies for Technical Feasibility Oxidation catalysts have previously been applied to natural gas-fired boilers located in CO nonattainment areas,although not to the same extent as turbines. The catalyst lowers the activation energy for the oxidation of CO to CO2 so that CO in the exhaust gas is converted to CO2. There are numerous suppliers of oxidation catalyst systems, and as such this technology has been applied to natural gas-fired boilers of all sizes and is considered a demonstrated technology. The SCONOx process for boilers was previously discussed as part of the NOx BACT analysis;it is • used to control both NON and CO. As part of that discussion,it was noted that SCONOx for boilers has only recently been applied to a 4.2 MMBtu/hr boiler operating at the MTS Inc plant. This control technology has not been achieved in practice and is not considered technically feasible for the proposed boiler. As discussed in the previous section for NON, recent advances in burner design have resulted in low NOx burner system that can achieve very low NOx emissions,as well as reduce CO emissions. Two such low NOx burners such(LNBs) are the Coen LNB and the Alzeta ULNB. The both the Coen and Alzeta burners can achieve CO emission levels of 50 ppmvd @ 3 percent O2 (0.039 lb/MMBtu) without the use of flue gas recirculation. Both the LNB systems described are considered technically feasible for control of CO emissions from the auxiliary boiler service proposed for the RMEC and are further evaluated in this BACT analysis. S 5-51 • Good combustion control, as the name infers, is based upon maintaining good mixing, a proper fuel/air ratio, and adequate time at the required combustion temperature. This technology is technically feasible and is the most commonly used technology to control CO emissions. In fact, combustion control/design is the most stringent control technology listed in the RBLC for boilers. 3. Rank Technically Feasible Control Technologies by Control Effectiveness The two technically feasible control technologies for CO are the LNBs and good combustion controls. Good combustion control is generally considered the baseline control technology for CO emissions. Thus,use of LNBs,which is inerent in the desing of the burner assembly, is considered the most stringent level of control for CO. 4. Evaluate Most Effective Controls for BACT For boilers such as the one proposed,good combustion practices/design are considered standard.Thus, the additional use of the Coen LNBs provides the highest level of emission control. The proposed • auxiliary boiler will only operate 1,900 hours/year, however, the applicant is proposing to use an oxidation catalyst. As a result,the applicant has chosen the most stringent control technology. 5. Select BACT The applicant has chosen to apply use Coen LNBs for the proposed auxiliary boiler. From the"top- down"analysis,this represents the highest level of control for CO. This level of control exceeds the level of control technologies listed in the RBLC for boilers. The proposed emission rate of 50 ppmvd @ 3%O2 is also consistent with the lowest rates given in the RBLC. 5.3.3 Analysis of Control Requirements for PMm PKo is a Clean Air Act regulated pollutant defined as particulate matter equal to or less than a nominal aerodynamic particle diameter of 10 microns. Particulate matter is typically described as filterable and condensable PM. As presented in the turbine section,the amount of both filterable and condensable • PKo emissions from natural gas-fired combustion sources should be very small relative to the total 5-52 • exhaust flow. In addition, PM emissions from add-on control devices are typically higher than from uncontrolled natural gas-fired combustion units. Therefore, add-on PMio controls do not make practical sense and are not considered feasible for utility natural gas-fired boilers. Permit data from EPA's RBLC database beginning with January 1990 were searched for PM and PMio BACT decisions and corresponding limits. In particular,data listed for similarly sized natural gas-fired boilers were reviewed in detail. Review of the RBLC database indicates PM/PM10 limits in the range of 0.001 -5 lb/MMBtu. The PM to emission rate for the proposed boiler is toward the lower end of the range,at approximately 0.019 lb/MMBtu. As noted before,it is difficult to make a direct comparison to the results in the RBLC because it is unclear as to whether the emission rate contained in the database includes both condensable and filterable PM. In conclusion, because the proposed boiler will fire clean burning natural gas, and its combustion controls will be state-of-the-art,add-on controls are not considered feasible. Particulate emissions from the proposed unit will be controlled via proper design, operation, and maintenance. With respect to • combustion controls,there are no significant economic,energy, or environmental impacts. 5.3.4 Analysis of Control Requirements for VOC This section presents the BACT analysis for the proposed natural gas-fired boiler. The VOC emissions from natural gas-fired combustion sources are the result of two possible formation pathways: incomplete combustion,and recombination of the products of incomplete combustion. The proposed boiler incorporates state-of-the-art combustion technology and is designed to achieve high combustion efficiencies. Additionally,the recombination of products of incomplete combustion is unlikely in well- controlled boilers because the conditions required for recombination are not present. As a result,the proposed boiler has a very low expected VOC emission rate. Based on a review of the information provided in the RBLC database and knowledge related to the control of VOC emissions from combustion sources,and taking into account technology transfer from other combustion sources,the following VOC control approaches were identified: • 5-53 • • Thermal oxidation, • Catalytic oxidation, and • Good combustion design and operation. Thermal oxidizers are used for combustion systems where VOC rates are high, such as waste incinerators. The thermal oxidizers for these types of sources are in the form of secondary combustion chambers and afterburners and are inherent to the combustion system's design. The VOC emissions from these types of sources are much higher because they combust fuels that are heterogeneous in nature and as a result it is difficult, if not impossible, to maintain the uniform time,temperature, and turbulence needed to ensure complete combustion. Thermal oxidation systems work by raising the VOC containing stream to the combustion temperature to allow the combustion process sufficient time to reach completion. The controlled VOC rates from these systems are still higher than those being proposed for this project without VOC control. Also, because thermal oxidizers combust fuel, a significant amount of NOx emission can be generated. As such,thermal oxidizers are not considered further in this anlaysis. • Oxidation catalysts have traditionally been applied to the control of CO emissions from clean fuel fired combustion sources located in CO nonattainment areas. As discussed previously,this technology uses precious metal based catalysts to promote the oxidation of CO and unburned hydocarbon(of which a portion is VOC)to CO2. The amount of VOC conversion is compound specific and a function of the available oxygen and operating temperature. Good combustion design and operation is the primary approach used to control VOC emissions from combustion sources. The VOC controls,inherent in the design and operation of a unit,include the use of clean fuels such as natural gas, and advanced process controls to ensure complete combustion and the best fuel efficiency. The proposed boiler will be 100%natural gas-fired and is designed with state- of-the-art combustion controls to maximize conversion of the natural gas to CO2, and minimize the production of VOC and CO. • 5-54 • • • Good combustion design and operation is being proposed to control VOC emissions. The proposed VOC emission rate is 10 ppmvd @ 3%O2,which is equivalent to 0.0047 lb/MMBtu. This emission rate is consistent with values from the RBLC for similar-sized boilers and represents BACT for VOC. 5.3.5 Analysis of Control Requirements for SO2 The new boiler will be designed and operated to minimize emissions and will be fired solely with natural gas,which is inherently low in sulfur. Sulfur dioxide is formed during combustion due to the oxidation of the sulfur in the fuel. Add-on control devices(e.g.,scrubbers)are typically used to control emissions from combustion sources firing higher sulfur fuels,such as coal. Flue gas desulfurization is not appropriate for use with low sulfur fuel, and is not considered for this project, because the achievable emission reduction is far too small for this option to be cost-effective. Also,the proposed emission rate of 0.0007 lb/MMBtu is consistent with the lowest emission rates listed in the RBLC. 5.4 BACT Analysis for the Emergency Generator and Fire Pump The objective of this section is to identify BACT for NOx, CO, PM10, and VOC emissions from the . diesel-fired emergency generator and fire-pump proposed for the RMEC. The emergency generator will be operated for no more than 200 hours per year and will use low-sulfur diesel fuel with a sulfur content of less than 0.05 percent. The emergency generator will normally be operated at 50 percent load for no more than 30 minutes per test (up to 200 tests per year) for routine maintenance and to ensure proper operation. The emergency fire-pump will also be tested up to 200 hours per year and will use low-sulfur diesel fuel with a sulfur content of less than 0.05 percent. A review of the BACT/LAER Clearinghouse databases indicates that the most stringent NOx emissions limit for a diesel-fired internal combustion engine is use of SCR with a control efficiency of 94 percent. Most of the BACT determinations in the RBLC for diesel-fired internal combustion engines used for emergency purposes(generators or fire pumps)were proper operation and maintenance and/or limits on the hours of operation. Emission Reduction Methods And Technical Feasibility Post combustion controls such as SCR or catalysts are a post-combustion method of control of • 5-55 • • • emissions. This option represents the lowest achievable emission rate for the diesel engine. However, these technologies are not considered to be a cost-effective emissions control device for the diesel engines on this Project,due to the emergency status of the emergency diesel generator and fire-pump, which would not be in operation for a significant percentage of the year. Additionally,during normal operation for engine testing purposes, the post-combustions controls would not be at a sufficient temperature to control emissions due to the limited period of operation(1 hour). Therefore,these types of controls will not be considered further in this analysis. Fuel injection and timing retardation delays the start of fuel injection in order to reduce the engines maximum combustion pressure, thereby, lowering the combustion temperature. Typically, fuel injection timing on this size unit and service is retarded by three to four degrees. The maximum amount of retardation possible is controlled by such factors as piston,cylinder,and manifold shape and materials, expected unit life, and the impact of modifying the combustion process on other pollutant emissions. Retarding the fuel injection timing can reduce NOx emissions by 20 to 30 percent, depending upon unit service, size and design. However, the diesel engine combustion efficiency • decreases with an increase in timing retardation and the emissions of other pollutants such as CO and VOC and particulate matter subsequently increase. Additionally, use of timing retard or other combustion controls can adversely affect engine start up and reliability. Due to potential increases in pollutants other than NQ and reliability,timing retardation is not considered feasible for emergency diesel-fired engines. Selection BACT BACT for NOxemissions from the diesel-fired emergency generator and fire-pump is proposed as use of low sulfur fuel,proper operation and maintenance,and restricted hours of operation(200 hours per year). • 5-56 • • • 6.0 EMISSIONS INVENTORY Because of the variability in ambient temperature and the need for power augmentation,the emissions and associated stack parameters will vary. Seven different operating scenarios were identified as described below. 1. base load during cold ambient temperatures (3 °F) 2. 70 percent load during average ambient temperatures(50 °F) 3. 70 percent load during hot ambient temperatures (90 °F) 4. maximum firing with power augmentation during high ambient temperatures(90 °F) 5. maximum firing without power augmentation during high ambient temperatures(90 °F) 6. maximum firing without power augmentation during high ambient temperature (102°F) 7. maximum firing without power augmentation during average ambient temperature (50°F) Nominal load refers to a nominal net plant output of 600 MW with inlet fogging and duct firing. Additional steam is created through the use of a 659 MMBtu/hr(HHV basis)duct burner. The turbine • stack parameters that produced the maximum impacts in the screening analysis were used in the full impact analysis to calculate the impacts for each pollutant and each averaging period. In addition, impacts from turbine startup were also modeled. Section 8 discusses the results of this load screening assessment. As part of the PSD permit application,a full impact analysis is conducted for those pollutants that are above the significant impact level(s). The impact analysis includes a demonstration that the proposed project will not cause or contribute to an exceedance of the NAAQS and PSD increments for the subject pollutant. All increment consuming sources within the largest significant impact area,plus 50 kilometers(screening area)were included in the analysis for comparison with the increment. For the NAAQS analysis, all sources within 50 kilometers of the largest SIL were included in the modeling assessment in addition to adding in background monitored concentration data,collected in the project area. For the NAAQS,this will produce extremely conservative results. • 6-1 • 7.0 AIR QUALITY MODELING ANALYSIS 7.1 Overview of the Modeling Process The air quality modeling included with the PSD application has followed the Colorado Department of Public Health and Environment,Air Pollution Control Division(APCD)requirements as outlined in the "Compilation of Air Quality Modeling Guidance for Permits". As such, a modeling protocol submitted to and approved by the APCD. The protocol is included with this application. The protocol followed modeling guidance provided by the U.S.Environmental Protection Agency(USEPA)in their "Guideline on Air Quality Models" (including supplements), the National Park Service's "Permit Application Guidance for New Air Pollution Sources"(Bunyak, 1993),the Federal Land Managers' "Air Quality Related Values Workgroup (FLAG) Phase I Report" (December 2000), and the "Interagency Workgroup on Air Quality Modeling(IWAQM)Phase 2 Recommendations"(1998)as well as the APCD modeling guidance found in the"Compilation of Air Quality Modeling Guidance for Permits", dated December 31, 1998, with recent updates, and APCD guidance on Long-Range Transport Model Selection and Application(May 21, 1999). • 7.2 Goals of the Air Quality Modeling Analysis The objective of the modeling was to assess the potential air quality impacts from the RMEC over a geographic area of interest where potentially significant impacts may occur. Modeling of ozone(O3) was not performed,as no suitable atmospheric dispersion model exists for this pollutant. Impacts from operation of the facility were compared to the following: Air Quality Criteria NO2 PM1p CO PSD Modeling Significant Impact Analysis ✓ ✓ ✓ PSD Monitoring Significant Concentration Analysis ✓ ✓ ✓ PSD Increment Analysis(Class I and Class II) V V Ambient Air Quality Standards (NAAQS and CAAQS) ✓ ✓ V Class I and Class II Visibility/Regional Haze Analysis V ✓ Analysis of Impacts to Soils, Vegetation, and Water V • Class I Area Acid Deposition Analysis V 7-1 • The facility is subject to air quality PSD requirements for NOx, CO, PM10, and VOC, as potential facility emissions exceed the significant emission rates for those pollutants.For each pollutant subject to PSD review,the air quality analysis must consider the amount of PSD increment that is available to the new or modified source, as well as the potential amount of increment that the new or modified source is expected to consume. Since there are no PSD increments for CO or O3,only NO2 and PM 10 were considered in the increment analysis.The PSD increments in Class I and Class II areas are 2.5 and 25 micrograms per cubic meter(ug/m3) for annual NO2 concentrations; 8 and 30 ug/m3 for 24-hour PKo concentrations; and,4 and 17 ug/m3 for annual PKo concentrations,respectively. The project site is not designated as nonattainment for any pollutant. However, the Denver PKo nonattainment area is within 50 kilometers of the project site. Therefore, dispersion modeling was performed to determine if the RMEC would impact this nonattainment area. The significance ambient concentrations for Class I areas and the significance levels for Class II areas • are listed in the following table. Proposed Significant Ambient Concentrations for Class I Areas Annual 24-Hour 3-Hour NO2 0.1 ug/m3 PM10 0.2 ug/m3 0.3 ug/m3 SO2 0.1 ug/m3 0.2 ug/m3 1.0 ug/m3 Significance Levels for PSD for Class II Areas Annual 24-Hour 3-Hour NO2 1 ug/m3 PMio 1 ug/m3 5 ug/m3 SO2 1 ug/m3 5 ug/m3 25 ug/m3 S 7-2 • • • 7.3 Existing Meteorological and Air Quality Data Pre-application assessment modeling conducted with the CALPUFF model utilized the five(5)years of existing meteorological data derived from Stapleton Airport(Denver)for 1986 through 1990.The data was obtained from the APCD staff and was already in extended CD144 format. The PCRAMMET meteorological preprocessor,as recommended by the IWAQM Phase 2 Report,was used to process the surface,precipitation,and upper air data. PCRAMMET requires complete data sets of the following variables: wind speed, wind direction, temperature, ceiling height,opaque cloud cover or total cloud cover, surface pressure, relative humidity, and precipitation type. The five years of upper air data includes twice-daily mixing heights. Missing surface and upper air data were screened to identify missing or spurious values,and then edited to eliminate gaps or erroneous values.Surface data such as wind speed,wind direction,and temperature data periods of five hours or less were supplemented by interpolation between the last good hour and the next valid hour of data.Missing data periods of six hours or more were replaced with data from the • previous hour(s)from the previous day(s),as discussed with John Vimont of the National Park Service. Missing mixing height data for three days or less was replaced by an interpolated value using data from previous day and next valid mixing height. Missing mixing height data for periods greater than three days was replaced with seasonal morning/afternoon mixing heights,calculated from the valid data for that year and season. PCRAMMET was run with wet deposition options as required in the Phase 2 Report. As such, the following domain averaged variables are required and were based on values expected in the modeling region: • Precipitation data • Minimum Obukhov length=2 meters • Anemometer height=6.1 meters • Roughness length=0.5 meters • Noon time albedo=6 • 7-3 • • • • Bowen ratio =0.0 • Fraction of net radiation absorbed by ground=0.150 Five years of data were preprocessed with PCRAMMET,which was then used as input into CALPUFF. Air quality data for the project region were derived from the APCD published annual reports and/or the AIRS database for the Northern Front Range AQCR.Data for the most recent available 3 years will be were.The APCD was consulted on the appropriate values for background for any pollutants for which data is not available or current. 7.4 Site Representation USEPA defines the term "on-site meteorological data"to mean data that would be representative of atmospheric dispersion conditions at the source and at locations where the source may have a significant impact on air quality. Specifically,the meteorological data requirement originates in the • Clean Air Act at Section 165(e)(I).Section 165(e)(1)defines on-site meteorology as the collection"of the ambient air quality at the proposed site and in areas which may be affected by emissions from such facility for each pollutant subject to regulation under [the Act] which will be emitted from such facility." This definition and USEPA's guidance on the use of on-site monitoring data, is also outlined in the "On-Site Meteorological Program Guidance for Regulatory Modeling Applications" (1987). The representativeness of the data is dependent upon(a)the proximity of the meteorological monitoring site to the area under consideration,(b)the complexity of the topography of the area,(c)the exposure of the meteorological sensors, and (d)the period of time during which the data are collected. As discussed below, the Stapleton Airport data satisfies the definition of on-site data. The attached windroses of Stapleton Airport data from the APCD indicate a consistent wind pattern with a predominant wind direction from the south. This flow is indicative of the influence of the South Platte River drainage. • 74 • • • The terrain surrounding the proposed facility is illustrated in the topographical map attached at the end of Section 7.0. The facility is located within the South Platte River drainage in Weld County. Weld County is predominantly grassland and irrigated farmlands.Elevations in the project region vary due to the low rolling prairie type terrain. The elevation of the project site is approximately 5000 feet amsl. The terrain rises gradually to the south,as illustrated by the elevation contour lines and the north-south orientation of the small streams,which originate to the south of the facility. The frequency of wind direction and speed is illustrated in Figure 7-1. Winds are predominately from the south and north,as typical of flows along the South Platte River Valley. The same orientation of wind flows is also expected at the proposed project area. Additionally,the meteorological boundary layer characteristics of surface roughness length, albedo, and Bowen ratio are expected to be similar between the two sites.Elevations between the two sites are within a few hundred feet of each other,so ambient temperatures are also expected to be similar. S S 7-5 • • • WI.ROW Na nbaen AMU.uvfinesiwnu en INI L AWL CC le • • • *ST • ,e, wive 4MT [WiM5 _� awe renne Hoch Line nrnr.nv,nowt •wa-'vw um %a rc e.W e.0 f.Y Nneb a a1LLET0� Pi0refigetTE.111. Linn". 'I" ILk'aM.ruin '.Lifer anniea!- 'It! Figure 7-1: Denver Stapleton International Airport Wind Rose • 7-6 • Representativeness has also been defined in the "Workshop on the Representativeness of Meteorological Observations"(Nappo et al., 1982)as"the extent to which a set of measurements taken in a space-time domain reflects the actual conditions in the same or different space-time domain taken on a scale appropriate for a specific application."Judgments of representativeness should be made only when sites are climatologically similar, as the project site and Stapleton Airport station clearly are. Representativeness has also been defined in the PSD Monitoring Guideline as data that characterizes the air quality for the general area in which the proposed project would construct and operate.The same large-scale topographic features that influence the Stapleton Airport station also influence the proposed project site in the same manner.As stated earlier,the met data set was obtained from and approved for use by the APCD,and has been used in other modeling studies in the regional areas east of the Rocky Mountains within Colorado.RTP assumed that the representativeness of the met data is based upon the APCD analysis of the following parameters: • Aspect ratio of terrain, • Slope of terrain, • • Ratio of terrain height to stack/plume height, and • Correlation of terrain features to prevailing meteorological conditions. 7.5 Background Concentration RTP contacted Ms. Nancy Chick of the Colorado Air Pollution Control Division to obtain representative background concentrations of criteria pollutants. The following data was provided. Averaging Pollutant Period Concentration Ranking Data Source CO 1-hour 10 ppm Second Maximum DIA 8-hour 5 ppm Second Maximum 1995-1996 NO2 Annual 0.016 ppm Mean RMA 1992-1996 O3 1-hour 0.098 ppm Second Maximum RMA 1992-1996 PM10 24-hour 101 ug/m3 Second Maximum Thermo Carbonics . Annual 33 ug/m3 Arithmetic Mean 1991-1992 7-7 • • • For pollutants with maximum modeled ground-level impacts greater than USEPA-defned significance levels, modeled concentrations will be added to these representative background concentrations to determine compliance with the AAQS. 7.6 Auer Land Use Analysis The areas surrounding the project site can be characterized as predominantly rural. Areas within a three km radius of the project are predominately undeveloped prairie or farmland with small areas of residential development,mostly in the immediate vicinity of the small town of Hudson,Colorado. In accordance with the Auer land use classification methodology (USEPA "Guideline on Air Quality Models"),land use within the area circumscribed by a three km radius around the modified facility is greater than 50 percent rural. Therefore, in the modeling analyses supporting the permitting of the facility, rural coefficients were assigned. 7.7 Air Quality Dispersion Models • Several USEPA dispersion models are proposed for use to quantify pollutant impacts on the surrounding environment based on the emission sources'operating parameters and their locations.The models used for the air quality analysis included the Building Profile Input Program (BPIP, current version 95086), the Industrial Source Complex - Short Term Version 3 (ISCST3, current version 00101), CTSCREEN (current version 94111), the long-range CALPUFF model (run in screening mode),and the VISCREEN visibility model(current version 88341). These models,along with options for their use and how they are used, are discussed below. These models were used for: • Comparison of Impacts to PSD Significant Ambient Impact Levels • Comparison of Impacts to Monitoring Significance Thresholds • PSD Class I and Class II Increment Consumption • Compliance with NAAQS and CAAQS • The impacts to Air Quality Related Values in Class I and Class II Areas • 7-8 • 7.7.1 Simple,Complex,and Intermediate Terrain Impacts For modeling the project in simple, complex, and intermediate terrain, the ISCST3 model (version 00101)was used with the hourly meteorological data from Stapleton Airport for 1986 through 1990. The ISCST3 model is a steady-state,multiple-source,Gaussian dispersion model designed for use with stack emission sources situated in terrain where ground-level elevations can exceed the stack heights of the emission sources. The ISCST3 model requires hourly meteorological data consisting of wind vector,wind speed,temperature,stability class,and mixing height.The model assumes that there is no variability in meteorological parameters over a 1-hour time period, hence the term steady-state. The ISCST3 model allows input of multiple sources and source groupings eliminating the need for multiple model runs.Complex phenomena such as building-induced plume downwash are treated in the ISCST3 model. The ISCST3 model was selected due in part to the lack of varying terrain surrounding the project site and is one of several models that are recommended by the USEPA for such evaluations.The ISCST3 model is capable of calculating pollutant concentrations in intermediate terrain.Intermediate terrain is • defined as terrain between stack top and final plume height. In calculating pollutant concentrations in intermediate terrain,the model will select the higher of the simple and complex terrain calculations on an hour-by-hour, source-by-source and receptor-by-receptor basis. In addition,the ISCST3 model is preferred for this application because it incorporates algorithms for the simulation of aerodynamic downwash induced by buildings.These effects are of importance because many of the emission points may be below Good Engineering Practice(GEP) stack height. Technical options selected for the ISCST3 model are listed below. Use of these options follow the USEPA's(1986, 1987, 1990,and 1994)modeling guidance,APCD modeling guidance,and/or sound scientific practice. An explanation of these options and the rationale for their selection is provided below: • Default option (includes final plume rise except for building wake downwash, stack-tip downwash except for Schulman-Scire [SS] downwash, buoyancy-induced dispersion 7-9 • except for SS downwash, default wind profile exponents, default temperature gradients, and calm processing via EPA policy); • Anemometer height= 10 m; • Rural dispersion parameters; and • ELEVated receptor terrain heights option. The ISCST3 default options will be used as recommended by the Colorado guidance.The final plume rise option does not consider the possible effects of gradual plume rise on ambient concentrations during the rising phase of the plume downwind transport. Gradual plume rise is recommended by USEPA (1986, 1987, 1990, 1994) when there is significant terrain close to the stacks. The only significant terrain feature noted would be the Rocky Mountain foothills region,which lies due west of the site approximately 30-34 miles. Buoyancy-induced dispersion, which accounts for the buoyant growth of a plume caused by entrainment of ambient air, will be included in the modeling per USEPA/APCD guidance and because of the relatively warm exit temperature and subsequent buoyant nature of the exhaust plumes. Stack-tip downwash,which adjusts the effective stack height downward • following the methods of Briggs(1972)for cases where the stack exit velocity is less than 1.5 times the wind speed at stack top, was selected as per USEPA/APCD guidance. As previously mentioned, based on the land use classification procedure of Auer (1978), land use within the area circumscribed by a three km radius around the proposed facility is greater than 50 percent rural. Therefore, in the modeling analyses supporting the permitting of the facility, rural coefficients were assigned. The calm processing option allows the user to direct the program to exclude hours with persistent calm winds in the calculation of concentrations for each averaging period. This option is generally recommended by the USEPA(1986, 1987, 1990, 1994)for regulatory applications.The ISCST3 model recognizes a calm wind condition as a wind speed less than or equal to 1 meter per second and a wind direction equal to that of the previous hour (a wind speed of 0 m/sec is used in the ASCII meteorological data file). The calm processing option in the ISCST3 model will then exclude these • hours from the calculation of concentrations. 7-10 • • • 7.7.2 Ambient Ratio Method NOx to NO2 chemical transformations evaluations,such as the ARM procedure will not be used,except as follows.No chemical transformations were used when comparing NOx impacts to the NO2 modeling significance levels. Chemical transformations may be used if the proposed source has a significant impact and a cumulative impact analysis is required to show compliance with the NO2 PSD increments or AAQS.For receptors less than 50 km from the proposed source the ARM default value of 0.75 will be used to convert NOx to NO2.For receptors greater than 50 km from the source,we understand that the APCD will still allow use of the ARM default value provided that the NOx impact values were derived from ISC3 in flat terrain mode. As an alternative,RTP supplemented the ISC3 analysis with evaluations derived from CALPUFF Screen per IWAQM Phase 2 Report. 7.7.3 Good Engineering Practice Stack Height and Downwash 7.7.3.1 Good Engineering Practice Stack Height Evaluation Buildings or structures located close to emission sources may cause downwash of the exhaust plumes • resulting in very high pollutant concentrations close to the emission source. The potential for downwash effects was evaluated to assess if close-in ambient air impacts have the potential to exceed applicable ambient air quality standards. Evaluation of building downwash on adjacent stacks was performed to ensure that stack source heights were not at or below Good Engineering Practice(GEP) heights. The formula for GEP height estimation is the following: Hs= Hb+ 1.50Lb where, Hs-GEP stack height, Hb-Building height, Lb-The lesser building dimension of the height, length, or width. Based on an evaluation of the HRSG stacks and the corresponding facility structures,it was determined that GEP stack height calculations were necessary. S 7-11 • • • To determine whether or not a structure potentially affects pollutant dispersion from a nearby emission source, EPA provides specific guidance. The guidance states that, if a structure is located within a certain distance from the emission source (stack), downwash effects on the dispersion of stack emissions must be considered. The distance criteria are the following: - The emission source is within five times the lesser of the structure height or width when the source is downwind of the structure. - The emission source is within two times the lesser of the structure height or width when the source is upwind of the structure. The emission source is within one and one-half the lesser of the structure height or width when the emission source is adjacent to a structure,regardless of the wind flow trajectory. Based on an examination of the facility plot plan and proposed stack heights,it was determined that the stacks would not be GEP heights design. Thus, an assessment of potential impacts from downwash was made. Figure 7-2 illustrates the location of the emission stacks and the structures used in the downwash analysis.The coordinates of these structures were identified from the computerized facility . plot plan. The building dimensions used in the modeling analysis are listed in Table 7-1. Table 7-1: Building Dimensions for RMEC Air Quality Modeling Building Name Building Ht(m) Building Width(m) Building Length(m) Cooling Tower 10.67 14.6 219 Administration Bldg 12.19 27.4 46 CT Chem Bldg 3.66 6 9.4 HRSG(1-2) 28.04 12.2 32 Air Intakes(1-2) 24.38 13 13 Combustion Turbine(1-2) 8.23 11 11 Water Tanks(1-2) 10.36 10 10 Demin Tank(1) 12.19 8 8 Steam Turbine(1) 14.33 8 11 The stack locations,stack heights,and building locations and dimensions were input to EPA's Building Profile Input Program(BPIP). BPIP is divided into two parts. The first part is designed to determine and report on whether or not a stack follows GEP guidance and is being subjected to wake effects from a structure or structures. The second part performs the"equivalent building dimension"calculations only if a stack is being influenced by structure wake effects. The program's output was input directly into the ISCST3 model input runstream. 7-12 • Figure 7-2 Building, Structures,and Stacks Included In Building Downwash Analysis 4438100-I 4438050 , 1- 4438000 4437950 4437900-III . 4437850 4437800-II i. ripI 4437750- • ' I LI I•I 4437700 • •I L • U! - • 4437650 • I• • 44376001 I• • I• 4437550 • - I 534400r 534450 534500 534550 534600 534650 534700 534750 534800 534850 534900 534950 • 7-13 • 7.7.4 Receptor Selection Receptor and source base elevations were determined from USGS Digital Elevation Model(DEM)data using the 7%-minute format (i.e., 30 meter spacing between grid nodes). The DEM data files were obtained from either the USGS. The receptor files are included on compact disk(CD). Cartesian coordinate receptor grids will be used to provide adequate spatial coverage surrounding the project area for assessing ground-level pollution concentrations, to identify the extent of significant impacts,and to identify maximum impact locations.Grid spacing will conform to the APCD guidance. A three-dimensional receptor grid extending 15 km from the emission sources was used to identify pollutant concentrations. The grid was defined as follows: • Coarse grid spacing at 450 meters • Refined grid spacing at 30 meters • Fenceline grid spacing at 30 meters • • Downwash grid spacing at 30 meters Elevations were determined from 7.5 minute USGS Digital Elevation Model(DEM)data which has 30 meter spaced grid points. Figure 7-3 illustrates the coarse grid receptor spacing. Figure 7-4 depicts the fenceline and downwash grids used, while figure 7-5 shows the refined grid spacing about the maximum impact location(s). 7-14 • Figure 7-3 ROCKY MOUNTAIN ENERGY CENTER Coarse Grid (450-meter spaced) Receptors yyy I 14 I , F4r++ + ++ +I*\+ 4 4_+++ + +-+++ + ++ ++ 4 'It(4'-Ft + + {I\-;+ 4{M41 + + + ,Y + + + 4 +°+ + + ++ 4 + + + + 4 + + 4 + + + 1.+ + + +J4J+ + -'1 +•/#`\ 4 4454000 ti + + +.+ a + + + +\,+ + + 4 + + +4+# + 4 + > + 4 +`*+ 4hf+-T'.4 + -'-4's +fr • +4 +.+ + + + + + +4,+ + + + + + +'++ + + + + r +I+ 4,,₹ + Nay + + + + + + + + t+ \•: + ++ + + + + +"4,+ + + + +/+ 1.44+ ++ + +e 4 + 4 + + + +-4 + + +* 4; 14 4+ 4 + +++ + ++ +A + + 4++++*PY.+++ ++ + + ++b(+ + + ,4.. + + +j1+' - 4452000 + + + + + 4++,+ + +.+ + + ++I+ + ++ + + + + + + + 1A++ + + +; _ + + p'.+-+ + + + + -qr + + + ++ + + + + + 4+ 4 + + - + ++ A-₹!,}, ++ t + + + + +�+ + + + + + + + + + + + +.+ + + + ? 4 + + + + + + + + ift + +.+j`1+ 4 + +.++ 4 + + +4 + + + + + ++ +i4 + ++ + 4 + + 4 + ++ + + + + 4 + 4 #4 -j+ + k}+ 'r • + 4450000 + + 4.t. 4++.+4�+ + +.t+.. '4.+ ++ + +.*4_.+4-4-4+44 + +.rs�a+mot + +'+ + + + +-4e+ 4-+ + + + + ++ +P + + + + + + + + + + + ++.+ 4 + + + + + + + + + + 4- + +4,+ + + + 4 4 + + + +f+ + ++ 4- + + + + + + + + + + l+ + + + 4 + + + + +4gd+�+ + + + ++ +M + + + + 4 + + + ++ + + +"+ f + + + + +I + -4 4448000 + + ++ + + + + + + + + + + +4 + ++ 4 + 4 + + + + + +' + + +\+ + + +f + 1 `+ + + t'+ + + + + + ++I+ +�44 + ++ +e# + + + +""+ + + + + + + + 44+ +i + 4 + + + + + + + +.+ + + - + + + + +:4 +i+ 4 + + + 4 + 4 + ++ + + + 4 + +++4 + ,+ + +++ +4 + + +`* + + + +. + +i+ 4 + + 4 + + + + s'4 + + + 4+'+ + + * + + � + + 43- 4 + + + + + + + + -4+ +Iy+ + + + + +^z49 + + + + + + +* 49+4Y + + + 4446000 + + + 4 + + + +4 + + 4 + + + + +l« + + + + + + + + p + + + + + + + + +\t '''+ + + + tr'+ + . + +,+ + + 4 �4 + +5+ +\+ ++ 11- + + + + + i.a + + + + + + t+ + + +l+ 4f+ +.4 + t.- + + + + + 4, + + + } 4 + +.+ +II+ + , + + ++ + + f+ ++ + + +y}+�+ + + ,,4r+ 41+ + il• +, µ +' +-+1 + + + +-+ 411+ +\+ + + + ++ 4+-+-+ + +�,'/C�'. + + ++ ; +,+ t �^+` 4444000 + 4 . +.1- + + + + + + +,+ 4.,+,t 44+Hr+,w+ X41+ "*1 W 44+ 1"+ + + + + +.+ t W ' + ++ + + + + ++ ,+ + + + t[ + E + + +•v? + + + + +* + + + + +I+ + +�+ + +-+�+ '+�+.\+ 4 + + 4+-* + + + + + 4 t +\+ + + a + + + + + + + + + + + t + + + i,+ + 4,+ + + +4 +.+ + 4/ + + ♦,- 4 4 + v + + + + +-4 ♦ + + + +-+ + + + + +—4 + + + + + + + + ++ + + Fs+ CD 4442000-.44 + +.+ + r i + + + +i+ ++ + + + + 4 y/+ + + + +.+ + + + +,+ + + + I C , ++ ++-1 +# + + +-s-4 +'+ +t�ji + + ++ + + + + + + +,+•'+ + + t1- -44-- 41 9+ + + 4 + + + 4440000 + - - ( ,i ti '— O } + + + + + .+ +» + 14 + + i + ++ + + 4 +h + + + + + 9 �4�+ 4 �+ - + 2,$''t+++ + + , + +f, � } 2 4438000 I+ + ,y+ 4+4 +-b.+ +' + +_±.,4 ,44. + 4 -1 � , 4,+ + + +-+ 4 ,r +` + -L_+ +.+,t +48 + + •: D + ++' + + + + -44_+ + + + 1 •„ 1 } + ✓j + 4 �,+ , C YY + +•+ '4 + J. 4436000 +_ ' + + +" + + a + SIN j�+l , r \+ + + il +� - 4 CCC111 I r +%- + i + + •'i + + +' `+ + + + ! . + + + y7 + + + + +tl+`�+ •. 4 + + Y-+w + + + + + . + + +f + + 7 /4 + + + + + + + + c.+ + +�'"+ '4 + + + 4 tt 4434000 y>r�'• 4 + f++ +i +g -+ + ++ + + 4 r.+ +4-,+ -$+ 4 + +-+-+ 4 # Y +-,+ + + + + + � + T + + + + + + + + + + +f+.+ + +1+ + 4 4 t F�� 14 + + +-+ + + +-+ 4432000 + +'.t{ .,� + + +- +L+ d 4 + + + + +‘1 +`4-+ + + + + + +,+. r 4 + • + + + I 444+ 4+ 4 + + + +o+ + + +'.++ + + ,4w> 4 • I +4 +"4-+ ,4 + + + + + +. + + + + + + + 4 + + + • + + +,44 + + 4 - + + + 4 4430000 + + y + + + + + +. +r*+ + + + +'+ + + ++ + , - 'I+ +^j 4-y ��,,��..({{(��Y�+ + s ++4+*-+k + + + + + + + + �+ + 4 + + + + + + +4 4 4+µ e4'°„,;,,, i�'' 4 + *, 4 +'+-++ + 4 +°F + I+ ++ ++ f+ + + + + 4 + + +, 4 4428000 . }" - _--__1I- + + F 4 525000 530000 535000 540000 UTM Easting (meters) TN Sources: Base Map: Greeley 1:100,000 Metric Map DEM Data: Hudson, Keensburg, Klug Ranch, and 0 4000 8000 Milton Reservoir 1:24,000 DEM Files(30-meter) Scale: 1"=4000 meters • 7-15 • Figure 7-4 ROCKY MOUNTAIN ENERGY CENTER Downwash/Fenceline (30-meter spaced) Receptors 4438800 �+ +++++ +++++++++.}}�/++f4441+ i+ � ++++++++++41+4+++++++ +++i+ +++ :+++++i,++ ▪ :44+ + +i++++4F+++ + +++#Y + ++ ++ +++++++++++++44+ 4+,�• 4}+++ + ++++++++++} } + ++ + ++ +++++++++++++41-0-+ + ++ +++ + ++ +}i+++++ ₹++ +++++++ ++++ 4+4#4+4++4+4+ +4,t ₹+ ++ 4+ 4438600 /�' %++++4+ 1 ++++ +" + ++++++++++++++++t++i++#+�#+/+4 + +++ +{}++ '. +++++++ 1 ++++ + + +++++++#+++++++++++++++ ++ +++++++ ++ +4 , ++++++ +++++ + +++++++++++++++++++++++++41+ +++ at ++++ ++++++ + - + - +++++++ +++++++++++++++++Mt} +++ +} +# ��' ++ ++.+,+¢+ ++ ' ++ +444+44 fi+t+++++++4#++#+++.++ ++ 4 +t+ ',.. + ++++ ++ . + 4+++++{ -44444+444--4Z+++++ 4+ ++ +T-7 4438400' + Vpt!� ++ +'"�+-++++++ ++ + ++++++ ++ ++++++++++++++++4+ ++++ + +4+ +++'Yf +4+ ++++4.}++ +++ 1t+++++++ +++ + +++++++ +++}4}+++ + ..44{ +++ '++4+++++4+ ++++++++ +++i 4+-}+++44+4++ ++++ ++++++}4y++++f+ +++-1 ++++ +++++++++ ++++++++t+++ ++ +++ ++ +++++ ++++c-+++++++_� 4+ ++++ +++++++++ ++++++++I+++ ++t+++1+++ +++4+ ++++++++++++ +F+ '. _ ++++ +++++yf +++++++++++ + + +++ }+ + +++++++ - +++++++++++w to 4438200 +++++++++y++ + 1 +++++,++ +++ +4+ + + #++ +++ + ++++i+++++++ +++++++4+4 ++++ ++++++ + 1 ++++++il++++ ++++, + ++1-_+F ++ +++++++++4++ ++4+44++ L +++++ ++++44 + ++++ +++{+++'V++4��f ++4+ +N 4+ ++++++++++++ +++44++ ++++ ++++7,+ ++++++++-4.-.41++++j/#� +`+i +�+ +++ 4+++++4+++++ +1+ + +i I +++++ +++++++ ++4-41C. ++ + ++ + ++++ ++++ 4+4++++4+44 .4,4 + ++++++++++++µ4 „ ++ +++++ ++ , 4++4++44++ +++44Y ++, E I +++++4++++++++++++*+ ' +++++++4+H ' 1 , % 44++++++++4+ +++44++ E 4438000 +++++++++++t#�11 +44+ ++++++++++ e / +4444444444 ++4++++ +++++++ + ♦rf f 4+++ ++4++++4+ 0 I +++4 +++++++4++} ++++++++++++ +1 ++4++ ++++++1, / ++++ ++++++++ \� +++++++++++++1\ ++++++ +++++c ; ` N ++++++-N4+++++4.+ ff'�''t�\\ +++++++++++++ �. +++++++ ++++++ ) \ I & /}++4 ++4+++ �i. CD ". ++++++++++++++ ' +++44++4+++++ i I I f ++ A ++ ++44++ ++++++++}++++4 {++4+++++++ 1 111 +++ +++++4+44,4 + l 4437800 ++++++++++++++▪ + + +' +,+++++++++++++ , ),i +++++4++++++++}4}++++ _ +++++++ 4.++++ ++ ++++++++ +J ++++ +++.+444+ t +++i+}.f+y+++�}}+ ++ ' +++++++<+. "i ++++ + ++++++4++ +4+4y 4+4++++ +4+' +4+4+4, + (_ 'ti I I +4+ '}++ +++++44* O +-+ +d+i++++++++ ++++4+{+++++"++ +++ +++ +4 ++4+++++ - Z4437600 ++++++++++++4+ '+++++++-+++t+ +++ 4++ ++++ �4: +++++++4+44+44 + +++++++Y++'h V� +++ 4++ ++++4+4+ + ++4+4+4+4+44++ ++ ++++++++.4% '\ +++ +++ ++++++4+ ++` ++4+4+4+4+4+4+ +++�k++++++1' i �y +44 +++ +44+44+4 +4 4+4+4+4+4+4+4+ +4+4+ +4+ +�}y + +44 ++ +++++ ++++ +#+++ ++4+4+4 ++Is , • +4+4+++#+4++#+ ++'++4++ +4#+ 4}4 ++' 4+++ +44+ +4+4++ ++44+4+ ++ '. +++++++++}++ + }}}4+4++ +++# i .' #+ ++++} 4#+ i+{#+4+ +4++}+4 4437400 I ++4+++++++++' + +++++++r,+++ +++ +++++ +4+ ++++++++}+ +++ ` + ++ ++ +14 r ++++++,+++++ +++ +f+++++++}4Y# +4+' Tl' +++++++++#++++ ++++++4++++r+ 4, ++++++i\#++++ ++ +##+++ ++++++44++ . ++++++4+4##+++ +4+4+4++++ 4-4++ 11++4++++4+4+4+ #++ +++++ ++#+++}+4++ . k++++4+4+4++++ ++++++4443,444444I ++++++ ++++ +++ +++ +++++++++444-4-1 4437200 +JN:il++,14414 +++++++++++ +++++ _< +++++ ++++ +++ ++++ ++++++-++-44+ 4++++++++++ +++++ tE+t +++; N+ + ++++ ++++ +++ +++ ++++ +++f++ +++++4+++++ ++++ ty+ .+d -% ++ +f'i��++++ +++++ ++++ +++ +++ +++f++ --1+ #+++++++ ++ +++ t.t + , +y4+ }f++++ +++++ ++++ +++ +++ +44++/' ++ ..4y +b ++ ++++++r1+++++ ++++ ++++ +++ ++t++, }} ,1 +}+r++4 +++++ +++++ +++ ++++ 4#+ 4437000 + ++++++++ r 4 + 4 /4+F++++ ++++4++++++ ++++ ++++ ++++++4 0 +}+ + + 4• +4+4#+++ +++++h+4+4+4 444 ++++ +++f4+1 +++++++++++1 4 l4, # � 14'++++++ +++++�+++++++ #++ +++++++Y#+ I ++++++++++ � +t 1Fl +'t + + +n+'+++++++ +++++++++++4+ ++++ +++ ++4r 1+{F+ ++++++++++'W+ Y+ 4 Ftt. + ++++i#+++ 4++++4+++++i +++ +++ + i ++4+4444+ +4 + +4 W #4,++'+'++ + +++ ++++ 4++++++ +#++}+#+4+f + i ++++++++ l+++ +{�.++# + + + ++}₹Tl #+ +++++ 4+4+4+ ++#+ +++#+ + , 4436800 +44+44++4444t4+4f% ++ ' +++t•. 4,+44+4+++ +4+4.4++ +++#++++++4+4 +++#+++ +++ }+4+j-+#+ 533600 534000 534400 534800 535200 535600 UTM Easting (meters) m� Sources: V Base Map: Keensburg 1:24,000 Topo Map IIIIII 0 400 800 DEM Data: Keensburg 1:24,000 DEM File (30-meter) Scale: 1"=400 meters • 7-16 • • • Figure 7-5 ROCKY MOUNTAIN ENERGY CENTER Fine Grid (90-meter spaced) Receptors {+. +++++,+t++-++r49-A4t-4 ++ +t+++++++++F++. I4++++�}++++++ +4 `+ r+, -t + 44410004+++{++++++++++++++++` +-+ ++ ++'+.++++++++a,++++ +++++. +++++++++ ++ t+' ++ ++++5+4++++s++a+++++++ 44+ ++++ + ₹ +++++ �++++ ++++++'�++++++++++ - + . + +. r+++ ++++++++++++++ ++++} +++++++ ++++++f i*�-f ++++P-++-++++++ ++ + + +. ++++ +++r it++.r.r+.+++ +++++-}, a +++++++.j Fr+3A++ +{4. + i 4440500 ++++ ++++++++++++ qq++-«—++-+ ++. +++++ + +++ ++,++++++++++k++++ +++ + }+++ ++++++++++++ q+++++k+ +++++++++++++ \t++++++++++.++++ ++++ ++ + ++++++++++++ +M+++f++ ++ ++++++A++++++ +\+ +++++++++{+++ +++++++ +++tl++++t++++++ 4+++-ft+ +++ ++++++i.{++++ ++44444-t+'r++++++t+tt-}}+ ++++++++ +++ ++ +++++++ +*++t++ +++ ++++++++mot+++ ++"+ +++ ++++++`t� ++++++++ +++ + +++++ ++ +f-++4+++. +++ +++++++++++ +++,$:„..t+ -r++ ++++++w+++++++. 4440000 --'++ +< Ems - ,t++' _ - -+++ +++++ ++ t+ +++ f++++ ++++++++' + +++++i -+++ ++++�..fr'++++++ +++ t3•S +'+,+++ ++++++++c,+ '+++ ' _ r r'rn--rrr t++ +++++ +++j++++ ++'-,-.++ +++++++++'+,� + ��+'� +++-E + + ++++++ ++++++++f.+++++++ ++++.+ +++++++ _f + l++V,+++Y+ > t ++ 4439500 ++ + +++• +++++++++++++++ +++++++ ++ - �� I�" +++++�++++,++++ I. * + }++- + ++++q'+�+x+++++ +++++'+++ lrt' ++++++ +++#+++ ++ ++++ t++ ++ - + ++++++++++++++ + + ./ + +++..t+++++ ++++A++ ++++ -'k++'�! }+++ + +—TT-+++++4++++++++++ -�w ++++ ++++,++++++ ++++P.+ ++++++ - }+++ ++ + .+++++++++++++++++ +j++++ +++++++++++,+++++A. ++++++++�I +++++ ++++++a++++++++ +++++4t++ :++++++++++ ++++++ +++++++I r. 4439000 -t -+ a F++ +.+r+++s++++++` - Cl) ++ +++ + ++++.+++ +'e+++++++++- ++++t++++++ +++++ ++k f++++j L +++++++++ -+++ + ++++ / ++++\++++++iF++++ +++ .,++++ +++++++++ ++++ •+ +++++ , /, - ++++++.+++++?.++++ •++++#P�++I +�+ +++++++++ ++++ +++++++ .. ++++++}+++++'''[[[+++- +++++ ++<1 tU }++++++++ -++++ ++++++ •. \. A ++++++{+++++ +++- +++++'t + E 4438500 }++++++++++ -++++ . + 'r - ++++++ +++++ +++ ++++++\++ ++++++++ -++++++ ,#+++++++++++ +++- +++++++.,+ +++++ -++++++++ / �I l +4--4„-+++ +++++.-4,4t.t +++++++# ...{� + +++ +++++++ t ' 3 1 +++t+ ++++++ +++++ CD +++++ +++ ++++++ -_ ++++µ +++++ y+++++++! C 443800O+++++ ++ ++++ . ,�� + + ' ( ,++++++..+, +++++i+*++++++.. N++++++y+ ++ ++++++ ++++++ +4 +++y++++' t ♦I++++++ + +- -+'+- +++++++ J +4t+++++ +• • f'+^F_+++ +++ ++++++ ++++++++ ++rs • ++ + +++}-+A+ ++++ Z ++4++++ // +++++++++ ' _, -+p: + +- ++�'+++, 4437$00 +q++++ +++++++++ ij ![$5 + + ++'1- ++r 411 m t.+-t_++++i-t,.t.._�___ l > +4-444. t. .++++++++++ Ir�fant� it +) + • + ++++++++. ++++++++++++ ++##++++++ ++++,a-vF� I— 4437000 : ++++++++++++ +++,+ ++++.. N + +++ + ++, + ++++++++++++r +++I++ r.+++++ f\++ i+ .++++++++++++t+ + .++++++++�++++ yf'Re4/vo +++++++ ++ + ++++++++ ++++++++++++++++++ ++++++ ,« t + ++aLv+.+++++++ +.+++ ++-;++++' • t 4436500 S`+++++-+m<++++++++1+++++++ +++++t+Vt+t-++++++ ++k++ yl+r +++ ++ + j +++k++y'+++`N++++++++++++++++ ++ ++++++++r++++++ +-+J++ t++++, +A+++++, + + + +++++++++++++,+++++ +++++++++++ + +++++++++++++ +++ A++++k. ++�+++ + y' +te} nt++++}+.,+++++++++++++++ +++-++++r,.t++++++ + 4+.;21 ++ +Jt++ + +4+52 ++++++ +++++++++++++ ++I++++ ++++++f + ++++++ ++ {+ + + .± 4436000 + +g�+ ++r+++ +++++++++++++ +"(1""4"t+++,” +.+++++ ++ + ++++, + + +ttr* 11+++++++++++++ ++ +++ ++ +++�+ '+'+=t+++::::.+(4411+ ++++++++ ++ h + rY, t t }"f . . . +++++++ ++++++++++• + ,+ + ++ ++++al+++t+ ++"t+++++++++tv h ++Y.+ +++ +++++++++++++++++ ++4+ ++t+ •++++.t+ + ++?+++++++++++ + {+r+i 4435500 +++++ +++++++++++++++++ ++ + '(+++4`++++J.. ,++ a++++++++++++r k I + ++++a+ +++++++++++++++++ ++ +}+++N++++++ +44 +, +/+' }+ ++++++ +++++++++++++++++ ++ ++ +++++a++++ �qq.'�+«'I'++fit++++++++++ +WW+{++r., ++ ++++++ ++++++++ 4 +++++ ++ 4+ i+++I ++++ 4+{+, + ++++++ +++ ++1y+++ 4435000 ++t+++++- +}++++++++ 4,+++ +++++++ rft4+ 4+++* + +++++++++ ++++++++; +++t+++++ ++++++++++ ++ + 531500 532000 532500 533000 533500 534000 534500 535000 535500 536000 536500 537000 537500 UTM Easting (meters) TN Sources: Base Map: Greeley 1:100,000 Metric Map �00 2000 DEM Data: Keensburg 1:24,000 DEM File(30-meter) Scale: 1"= 1000 meters all 7-17 • • • 7.8 Load Screening Pollutant emissions to the atmosphere from the proposed facility will occur from combustion of natural gas in each of two identical combustion turbines. In addition,the HRSGs have the capacity to duct fire natural gas. Emission rates were provided by RMEC and are based on vendor data and additional conservative assumptions of turbine and HRSG performance. Turbine/HRSG emissions and stack parameters, such as flow rate and exit temperature, exhibit some variation with ambient temperature and operating load. In order to calculate the worst-case air quality impacts, a screening analysis(i.e., load screening)was performed to evaluate each operating scenario(based on operating load with and without HRSG firing and atmospheric conditions)to predict the worst-case facility configuration on a pollutant-specific basis. In the modeling analysis,maximum impacts will be predicted for maximum(100%)and reduced load conditions.In addition,different ambient temperatures will be evaluated for each load condition.Each of these conditions has unique performance characteristics which affect plume dispersion and thus predicted impacts. This analysis is most relevant to analyses for short term impacts. Annual impacts • will be evaluated based on expected turbine performance at an ambient temperature representative of the project site. The temperatures and humidity levels selected for the short-term screening analyses will closely reflect the range of possible sites.The results of this screening analysis were used to select the worst-case operational scenarios for the modeling analyses in order to provide maximum operating flexibility. Refined modeling for the permit application was based on these worst-case scenarios. The screening modeling used to determine the worst-case operating condition(i.e.,configuration which produces maximum facility impacts) will use five years of NWS meteorological data and a nested receptor grid as described above to determine the worst-case source configuration. This worst-case operating condition was then carried forward in the remaining air quality analyses.No further modeling was performed for those operating conditions that did not result in worst-case impacts. i 7-18 • • • 7.9 Significant Impact Analysis The NSR Workshop Manual contains an extensive listing of significant impact levels(SILs)that must be evaluated as part of the air quality modeling effort. It should be clearly noted that Class I SILs do not necessarily refer to or apply to ambient air quality impacts. In many instances,these SILs merely establish action thresholds within the permitting process. i.e.,a source may have impacts less than the significant impact levels and still be considered significant for a Class I area.For example,the 1 ug/m3 (24-hour average)SIL applied to sources located within 100 km of a Class I area is not used to establish the significance of the sources' impacts, but rather to determine if the proposed sources' emissions would be considered"major"for purposes of PSD review and thus,require an increment analysis. An analysis of impacts to Class I AQRVs is automatically made, regardless of the significance levels. Such distinctions are clearly noted in the impact section. Initially, only the proposed project sources were modeled to determine maximum ground-level concentrations of criteria pollutants. Impacts were determined for I-hour and 8-hour CO averaging periods,24-hour and annual averaging times for PM to,and annual average concentrations for NO2.The 4111 results of these modeling runs were used to identify the extent of significance areas for NO2,PM10,and CO. The radius of impact was determined from the receptor furthest from the facility which was above sig ificance. This maximum distance was then used for all subsequent analysis. 7.10 PSD Increment Consumption Analysis Increment consumption of PM10 and NO2 were evaluated if impacts from the facility are above PSD modeling significance levels. As discussed in Section 8, all modeled impacts were less than significance levels. Thus,no increment modeling was performed. If modeled impacts triggered an increment analysis, the resulting concentrations would then be compared to the appropriate PSD increments to assess compliance. Additionally,the impact from the proposed new source alone will be compared with 75% of the PSD increment to demonstrate compliance with the State standard (Regulation No. 3, Part B §VII.A.5.a)for 75%increment consumption restriction for major sources. • 7-19 7.11 Comparison of Impacts to NAAQS and CAAQS To assess compliance with the AAQS,the impacts resulting from the proposed project will be added to background levels of pollutants described earlier if the modeled impacts from RMEC are above significance levels. The applicant will also rely upon guidance provided in the APCD's Technical Guidance Series: Air Quality Modeling - Emission Inventories for Nearby and Other Background Sources(September 30, 1997).Where the background data does not contain specific,recently permitted sources, these sources will be modeled and included in the cumulative analysis. Appropriate background sources to be modeled will be determined in consultation with the APCD. For example, background sources with significant concentration gradients should be included in the analysis. The total pollutant concentrations(modeled project and background source plus background)will then be compared to the AAQS to assess compliance. 7.12 Pre-and Post-Construction Air Quality Monitoring Requirements The model-predicted maximum impact for each pollutant emitted in significant amounts (i.e., that exceed the PSD significant emission rate)from the proposed facility were compared with the PSD pre- • construction monitoring significance levels (i.e., NO2, PM10, and CO). If these values are exceeded, then the applicant will discuss with APCD the need for pre-construction monitoring data. APCD has already indicated the lack of recent monitoring data from the project area that would be suitable for meeting any PSD pre-construction monitoring requirements as may be triggered. The applicant understands that the decision to require post-construction monitoring is not discretionary as suggested by federal regulations.Further,the applicant understands that the APCD can only exempt a source from post-construction monitoring if the source's impact or the existing background concentration is below the applicable monitoring de minus level. 7.13 Additional Impacts Analysis The additional impacts analysis is an assessment of the impacts of air,ground,and water pollution on soils,vegetation,and visibility caused by any increase in emissions of any regulated pollutant from the modification under review,and from associated growth.There are four parts of the additional impacts analysis: 1)growth,2)ambient air quality impact analysis,3)soils,water,and vegetation analysis,and 7-20 • 4)visibility impairment.This analysis will follow EPA's guidance provided in the New Source Review Workshop Manual(October 1990 draft),with the addition of Colorado-specific issues. The growth analysis will quantify the number of new employees,the availability of housing in the area, and associated commercial and industrial growth, and construction related activities and mobile sources. Because the number of new employees is not envisioned to be large enough to result in a quantifiable increase in emissions from residential,commercial,or industrial growth(e.g.,less than 25 new employees),the applicant expects only to have to prepare an emission inventory of fugitive dust generated from the construction activities. An inventory of soils, vegetation, and water in the significant impact area was performed. Impacts outside this area were assumed to be insignificant. The analysis of water is a Colorado-specific requirement. All vegetation with any commercial or recreational value within the significant impact area was. Similarly,water resources in the significant impact area were identified.Nitrogen loading on these water resources was quantified and compared with available reference levels. S A visibility impairment analysis was conducted for scenic and/or important views as identified by the APCD.Ms.Colleen Campbell of the APCD was contacted to identify these views.Only Pawnee Buttes was identified for this analysis.Pawnee Buttes is approximately 103 km north-northeast of the project site.A light extinction analysis was performed for this location using the same methods as in the Class I visibility analysis(i.e.,CALPUFF in a screening mode).No background or reference concentration was provided for this view.Therefore,the percent change in light extinction was not quantified. Only the light extinction attributed to the facility under worst-case conditions was quantified. 7.14 Class I and Sensitive Class II Area Impacts The facility is proposed to be located approximately 82 km east-southeast of Rocky Mountain National Park, and 116 km southeast of the Rawah Wilderness, which are Class I areas. Rocky Mountain National Park is administered by the National Park Service (NPS). The Rawah Wilderness Area is administered by the US Forest Service(USES). A complete Class 1 Area analysis consistent with the • PSD program will be conducted for these areas. 7-21 • The nearest Class II area with Class I area PSD SO2 protection is the Florissant Fossil Beds in Florissant,Colorado,which lies 142 km south-southwest of the project site.Since the facility will not emit SO2 at levels above the PSD significant emission rate, modeling for SO2 impacts within the Florissant Fossil Beds was not performed. A visibility analysis was conducted for Pawnee Buttes, as discussed previously. An analysis of regional haze and acid deposition was conducted for sensitive Class II areas. The modeling followed guidance as provided by the Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report and the Federal Land Managers' Air Quality Related Values Workgroup (FLAG) Phase I report (December 2000). The Federal Land Managers (FLMs) were contacted with regards to this project and copies of the modeling protocol were sent to the FLMs as well. 7.14.1 CALPUFF Dispersion Model . The screening mode of the CALPUFF modeling system requires hourly,single station meteorological data as input, both surface and upper air. Based on the guidance contained in the IWAQM Phase 2 Summary Report,CALPUFF was used in a screening mode,which requires five years of single station meteorology. The five years of surface and upper air data used in the ISCST3 analyses were used (Stapleton Airport for 1986-1990). The PCRAMMET meteorological preprocessor,as recommended by the IWAQM Phase 2 Report,was used to process the data. However,since the CALPUFF modeling system also requires precipitation, surface pressure,relative humidity,and precipitation type,the five years of SCRAM surface data was supplemented with precipitation,surface pressure,relative humidity,and precipitation type data from the NCDC SAMSON/HUSWO CD-ROMs datasets. Based on the SCRAM datasets,the amount of missing supplemental data was minimum. If missing data do occur,they were filled in using USEPA guidance ("Procedures for Substituting Values for Missing NWS Meteorological Data for Use in Regulatory Air Quality Models,"Dennis Atkinson and Russell F. Lee,July 7, 1992). • 7-22 • • • PCRAMMET was run with wet deposition options as required in the Phase 2 Report. As such, the following domain averaged variables are required and are based on values expected in the modeling region: • Include Precipitation data • Minimum Obukhov length=2 meters • Roughness length=0.3 meters • Noon time albedo=0.12 • Bowen ratio= 5.0 • Fraction of net radiation absorbed by ground=0.150 CALPUFF also requires domain averaged background O3 and ammonia(NH3)concentrations for the Mesopuff II chemistry algorithm. For O3,the background concentration of 60 ppb was used. For NH3, a domain average value of 44 ppb was selected based on APCD Guidance on Long-Range Transport Model Selection and Application(May 21, 1999). • Site specific model options include rural dispersion coefficients,default wind speed profile exponents, and default vertical potential temperature gradient. A brief summary of the options used in the modeling analysis are listed below: • Number of X grid cells=2 • Number of Y grid cells=2 • Grid spacing= 175 km • Number of vertical layers= 2 • Cell face heights=0, 5000 • Terrain adjustment method=partial plume path adjustment • No puff splitting allowed • Chemical mechanism= Mesopuff II scheme • Dispersion= PG dispersion coefficients • 7-23 • • PG sigmay and sigmay not adjusted for roughness • Plume modeled as puff, not slug • Land Use=agricultural with irrigation—model default surface roughness length and leaf area index • Dry and wet deposition for individual chemical species as follows: Chemical Species Dry Deposited Wet Deposited SO2 gas phase ✓ SO4 particle phase V NOx gas phase HNO3 gas phase ✓ NO3 particle phase ✓ PMio None • The computational grid was extended 50 km beyond the furthest receptor point.For each Class I area, receptors were be placed in three polar receptor rings that extended 45 degrees on either side of each Class I area. The receptors were spaced at one-degree intervals along each arc-length. The closest receptor ring was placed at a distance where it extends through the portion of the Class I area located closest to the proposed project. The middle receptor ring was placed at a distance where it extends through the central portion of the Class I area.The farthest receptor ring was placed at a distance where it extended through the most distant portion of the Class I area.A single elevation value is assigned to all receptors on a given ring.The selected elevation value is based on the average elevation of the arcs that extended through the Class I area being modeled. Following the IWAQM screening method,the maximum concentration for each pollutant,for each distance averaging time modeled is selected for comparison with the appropriate AQRV. • 7-24 • • • 7.14.2 CALPOST Model Options The following options will be selected for use in the post processing control file. • Method 6: Compute Extinction from speciated PM measurements and user specified RH factors. • Monthly RH factors based upon seasonal values reported in FLAG Phase I guidance document • Maximum RH= 95% • Modeled species for visibility: sulfate, nitrate, and fine particulate (PM1o). 7.14.2.1 Nitrogen Deposition on Soils Nitrogen deposition on soils were quantified using the options in CALPUFF to calculate and output the wet and dry flux expressed in units of g/m'/s of the pollutant modeled(e.g.,NO2,HNO3,and NO3)and converted to kg/ha/yr of nitrogen. Project-only deposition rates were quantified. • 7.14.2.2 Nitrogen Deposition on Sensitive Lakes The U.S.Forest Service was contacted to discuss which sensitive Class II areas they would require to have an air quality related values assessed, and to identify which sensitive bodies of water would be evaluated for impacts (October 7, 2001 conversation with Laura Hudnell, USFS—Rocky Mountain Regional Office). The table below presents a list of the USFS Class I and sensitive Class II areas of interest to the USFS, along with the sensitive bodies of water. The change in acid neutralization capacity(ANC)was calculated for these bodies of water following the USFS Screening Methodology for Calculating ANC Change to High Elevation Lakes(1999).The input parameters for this calculation were provided by the USFS and are listed here for reference. 7-25 111 • • Class I and Class II Sensitive Bodies of Water Watershed Annual Wilderness Distance Sensitive ANC Area Precip Area Class (kin) Lake (Meq/l) (hectares) (m) Rawah 1 116 Island 41.2 Indian Peaks II 85 Blue 21.9 268 0.635 No Name 24.5 49 1.016 Mt. Evans II 100 Upper 52.1 107 1.016 Middle BearTrack 7.14.3 Visibility Analysis Visibility impacts, through the calculation of light extinction, will be assessed using CALPUFF. CALPUFF is the IWAQM and FLAG recommended model for long-range transport. Since all Class I areas are greater than 50 km from the project site,a coherent plume analysis using VISCREEN will not be performed for the Class I areas. However, VISCREEN will be used in accordance with APCD . guidance documents to assess Class II visibility impacts in general terms, if necessary. The methodology used to calculate the change in light extinction due to the proposed project followed the FLAG Phase I guidance(December 2000).Briefly,this method involves:calculating the reference level(also referred to as the natural background level),then calculating the single-source contribution (i.e.,the contribution due to the proposed facility),and calculating the change in extinction.Reference levels were calculated by quantifying the hygroscopic component,non-hygroscopic component,and Rayleigh Scattering component.The hygroscopic component refers to the component of light extinction caused by sulfate and nitrates as a function of relative humidity.The non-hygroscopic component refers to those pollutants whose light extinction properties do not change as a function of relative humidity (e.g.,organic carbon,soil,coarse particulate,and elemental carbon).Site-specific reference levels and /(RH)values used were obtained from the FLMs,in the absence of their publication in the FLAG Phase I guidance.CALPUFF calculates the natural background level;that value was used in the comparative analysis. • 7-26 • The contribution to light extinction from the facility itself was then quantified and compared with the 5%de minimis level.If the contribution from the proposed project does not exceed 5%light extinction, then no further visibility analysis will be conducted. However, should the contribution from the proposed source exceed 5%, a cumulative analysis may be warranted,depending upon the frequency and magnitude of such an occurrence. The FLMs will be contacted in such an event to discuss such a situation. 7.15 Increment Consumption and Cumulative Impacts Increment consumption and cumulative impacts of NO2 and PM1O will be assessed in the Class I areas within 150 km if single source impacts are above the Class I significance levels. For the cumulative impacts analysis,the same emission inventory used to assess increment consumption from cumulative impacts in Class II areas will be used in the Class I analysis. I S 7-27 1 • • File contains oversized map See Original File r • 8.0 AIR QUALITY IMPACT ANALYSES This section describes the impacts as calculated from the air quality dispersion modeling described in Section 7.0. All other input and output files are contained on the enclosed CD-ROM disk. All modeling analyses were performed using the techniques and methods as outlined in the modeling protocol submitted and approved by APCD. All sources, excluding emergency equipment, were modeled in the analysis for comparisons with significance levels, increments and NAAQS. This included the turbines, HRSGs, auxiliary boiler, cooling tower, fire pump and emergency generator. Turbine startup emissions were also used in the analysis for 1-hour, 3-hour, 8-hour, 24-hour, and annual averaging periods. Only one turbine is expected to be in startup during a 1-hour time period. 8.1 Load Screening Analyses Modeling was performed with 7 distinct load conditions(as described previously)in order to determine the operating condition that will result in the highest modeled concentrations. The results of the load . screening analysis are listed below in Table 8-1. ISCST3 with five years of hourly meteorology was used in the load screening assessment. The maximum modeled concentrations are listed in bold in Table 8-1. Therefore, all additional modeling analyses were performed using the various cases that produced the maximum impact for each pollutant for each averaging period. The emissions used in the modeling assessment also included startup conditions for comparison to both short-term and annual averaging periods. • 8-1 Table 8-1: Load Screening Results for RMEC • Emissions,Modeling Characteristics,and Screening Results for Turbines Case D E N GP F B J Ambient Dry Bulb Temperature deg F 90 102 90 50 50 3 90 100% 100% 100% no 100% 70% no 100%no 70% no Conditions w/DB and w/DB and DB/PA w/DB and PA and DB and PA and no PA no PA no PA no DB no PA DB Unitized Modeling Results for 1 g/s/turb D E N GP F B J Stack Height meters 53.340 53.340 53.340 53.340 53.340 53.340 53.340 Stack Diameter meters 5.639 5.639 5.639 5.639 5.639 5.639 5.639 Stack Temperature Kelvin 343.0 344.7 343.0 341.3 346.9 349.7 346.9 Stack Velocity M/s 20.422 18.898 19.202 19.812 16.459 21.641 16.459 1-hour ug/m3 5.98197 6.41023 6.37597 6.24452 7.21032 5.37619 3-hour ug/m3 3.40614 3.69412 3.66722 3.57575 4.23287 3.02419 Same as 8-hour ug/m3 1.81796 2.09750 1.94631 1.89989 2.46301 1.45653 Case F 24-hour ug/m3 0.67372 0.80393 0.72206 0.70461 0.94904 0.57687 Annual ug/m3 0.02076 0.02183 0.02207 0.02199 0.02900 0.01768 Pollutant Modeling Results D E N GP F B J • NOR, as NO2,Maximum g/stturb 3.150 2.898 3.024 3.024 1.638 2.394 1.512 SO2, Annual Average g/s/turb 0.176 0.164 0.164 0.176 0.088 0.139 0.088 CO g/s/turb 5.796 5.292 5.418 5.544 3.024 4.410 2.898 PM10(excludes H2SO4 mist) g/s/turb 2.230 2.155 2.167 2.155 1.386 1.386 1.386 NOR, as NO2,Annual ug/m3 0.065 0.063 0.067 0.066 0.048 0.042 0.044 SO2, 3-hour Average ug/m3 0.6008 0.6051 0.6007 0.6308 0.3733 0.4192 0.3733 SO2, 24-hour Average ug/m3 0.1188 0.1317 0.1183 0.1243 0.0837 0.0800 0.0837 SO2, Annual Average ug/m3 0.0037 0.0036 0.0036 0.0039 0.0026 0.0025 0.0026 CO, 1-hour Average ug/m3 34.671 33.923 34.545 34.620 21.804 23.709 20.896 CO, 8-hour Average ug/m3 10.537 11.100 10.545 10.533 7.448 6.423 7.138 PM10,24-hour Average ug/m3 1.503 1.732 1.565 1.518 1.315 0.800 1.315 PM10,Annual Average ug/m3 0.046 0.047 0.048 0.047 0.040 0.025 0.040 In addition to the load screening analysis for the turbine, a screening analysis was also performed for both the fire pump and emergency generator. The screening analysis was necessary to determine which • engine would produce the highest impacts,as neither engine will operate during the same hour or the 8-2 • same day. The highest emissions do not always produce the highest impact(s). High impacts are often the product of stack height,downwash,and location. The results of the screening analysis are listed in Table 8-2. As can be seen in this table,the emergency generator produces the highest concentration on a short-term basis. For annual impacts,both the fire pump and emergency generator were included in the modeling analysis. PMIo was modeled for all combustion sources along with the cooling tower. The cooling tower emissions of PMIG were calculated based on the total dissolved solids in the circulating water and the drift rate. In the document titled Effects of Pathogenic and Toxic Materials Transported Via Cooling Device Drift— Volume 1 Technical Report (EPA 1979),it is indicated that only a portion of cooling tower drift(31.3%)is governed by atmospheric dispersion. The majority of the drift falls out close to the tower as water droplets. Therefore,in modeling the PM to emissions from the cooling tower,it was assumed that 50%of the PM would be in the form of PM i0 8.2 Refined Air Quality Impact Analysis • The operating conditions and emission rates used to model RMEC are summarized in Table 8-3. As discussed above,the turbine stack parameters for the cases that produced the maximum impacts were used in modeling the impacts for each pollutant and averaging period. The complete modeling input for each pollutant and averaging period is shown in Appendix B. The model receptor grids were derived from three-second DEM data. Initially,a 450-meter coarse grid was extended to ten(10)kilometers from RMEC in all directions. A 30 meter resolution downwash receptor grid was used within approximately 0.5 km of the site. Thirty-meter refined receptor grids were used in areas where the coarse grid analyses indicated modeled maxima for each site plan would be located. Receptors for the refined modeling analysis were from USGS DEM data for four 7.5-minute quadrangles. The nested receptor grids contained a total of approximately 11692 receptors. • 8-3 Table 8-2: Maximum Modeled Results and SIA for RMEC • Emissions,Modeling Characteristics,and Screening Results for Emergency Generator and Fire Pump Emergency Generator NOx SOx(1) CO PM,a Emissions g/bhp-hr(2) 6.90 n/a 8.50 0.40 lb/hr(4) 7.545 0.1634 9.295 0.437 (testing at 50%load,30 min/hr 24 hrs/day(4)) g/s(1-hour) 0.951 0.0206 1.171 0.055 g/s(3-hour) 0.00686 g/s(8-hour) 0.14639 g/s(24-hour)(5) 0.00086 0.00230 Tpy(3) 0.754 0.0163 0.929 0.0437 (200 tests/yr(3)) g/s(annual)(5) 0.0217 0.00047 0.00126 (453.6 gib conversion factor) Impacts gig/m3) Unitized Impacts(for 1 glsisource) µg/mm3 UTM-x(m) UTM-y(m)rYMMDDHH 1-hour ug/m3 1455 31.5 1792.4 84.3 1530.47534 534630 4437510 90070921 3-hour ug/m3 3.50 510.51804 534630 4437510 90070921 8-hour ug/m3 45.84 313.15793 534590 4437512 90061608 24-hour ug/m3 0.184 0.492 241.17467 534590 4437512 88010624 Annual ug/m3 #n/a #n/a #n/a #n/a illStack Height 20 feet 6.096 meters Exhaust Temperature 820 °F 710.9 °K Stack Diameter 8 inches 0.203 meters Exhaust Flow 6670.6 cfrn 3.148 m3/sec Exhaust Velocity 318.5 ft/sec 97.079 m/s Manufacturer Caterpillar Model 3512B Output(Bph) (nominal) 1,984 Output(Bhp)(testing) 992 Fuel cons, gals/hr(nominal) 95 Fuel cons, gals/hr(testing) 24 • 84 Table 8-2: Maximum Modeled Results and SIA for RMEC . Emissions,Modeling Characteristics,and Screening Results for Emergency Generator and Fire Pump Fire Pump Engine NOx SOx ell CO PM,s Emissions g/bhp-hr(2) 589 n/a 3.55 0.25 lb/hr(4) 2.363 0.0633 1.424 0.100309(testing at 100%load,60 min/hr 24 hrs/day(4)) g/s(1-hour) 0.298 7.98E-03 0.1795 0.0126 g/s(3-hour) 2.66E-03 g/s(8-hour) 0.02243 g/s(24-hour)(5) 3.32E-04 0.00053 Tpy(3) 0.236 0.006 0.142 0.010 (200 tests/yr(3)/ g/s(annual)(5) 0.0068 1.82E-04 0.00410 0.00029 Impacts(µg/m3) - Unitized Impacts(for 1 Ws/source) pg/m3 UTM-x(m) UTM-y(m)WWMMDDHH 1-hour uglm3 567 15.2 341.6 24.1 1903.17578 534800 4437512 90070921 3-hour ug/m3 1.69 510.51804 534800 4437512 90070921 8-hour ug/m3 10.62 313.15793 534710 4437512 90061608 24-hour ug/m3 0.051 0.080 241.17467 534710 4437512 88010624 Annual ug/m3 #nla #nla #n/a #nla Stack Height 23 feet 7.010 meters Exhaust Temperature 890 °F 749.8 °K Stack Diameter 6 inches 0.152 meters Exhaust Flow 745 cfm 0.35 m3/sec Exhaust Velocity 63 ftlsec 19.202 m/s Manufacturer Cummins Model 6BTA Output(Bph)(nominal) 182 Output(Bhp) (testing) 182 Fuel cons, gals/hr(nominal) 9.2 Fuel cons, gals/hr(testing) 9.2 Notes: (1) Based on Diesel: 0.05%sulfur,0.825 Spec.Gray. (2) Emission factors based on vendor information. (3)Based on 200 tests of 30 minutes each(100 hrs/year) (4)lb/hr emissions reduced by 50%(since each test is 30 minutes) (5)Since operations not limited for daily(24-hr)period, modeled average g/s emissions for these two periods NOT multiplied by 3 to compensate for 8 am-4pm testing. i 8-5 Table 8-3. ISCST3 Model Input Data: Source Characteristics For Refined Modeling • (Emissions In Pounds Per Hour). Unit NOx SO2 CO PM:o One-Hour Average: Turbine/Duct Burner l N/A N/A 46 N/A Turbine/Duct Burner 2 N/A N/A 46 N/A Auxiliary Boiler N/A N/A 5 N/A Emergency Generator - - 9.295 N/A Fire Pump N/A N/A (1) N/A Cooling Tower(13 cells) N/A N/A N/A N/A Three-Hour Average: Turbine/Duct Burner 1 N/A 1.4 N/A N/A Turbine/Duct Burner 2 N/A 1.4 N/A N/A Auxiliary Boiler 0.09 Emergency Generator N/A 5.45E-02 N/A N/A • Fire Pump N/A (1) N/A N/A Cooling Tower(13 cells) N/A N/A N/A N/A Eight-Hour Average: Turbine/Duct Burner 1 N/A N/A 367.00 N/A Turbine/Duct Burner 2 N/A N/A 367.00 N/A Auxiliary Boiler 5 Emergency Generator N/A N/A 1.162 N/A Fire Pump N/A N/A (1) N/A Cooling Tower(13 cells) N/A N/A N/A N/A 24-Hour Average: Turbine/Duct Burner 1 32.1667 1.4 N/A 17.6 Turbine/Duct Burner 2 30.75 1.4 N/A 17.6 Auxiliary Boiler N/A 0.09 N/A 2.4 Emergency Generator N/A 6.81E-03 N/A 1.82E-02 III 8-6 • • Table 8-3. ISCST3 Model Input Data: Source Characteristics For Refined Modeling • (Emissions In Pounds Per Hour). Unit NO, SO2 CO PM10 Fire Pump N/A (1) N/A (1) Cooling Tower(13 cells) N/A N/A N/A 3.35E-01 Annual Average: Turbine/Duct Burner 1 25 1.4 N/A 17.6 Turbine/Duct Burner 2 25 1.4 N/A 17.6 Auxiliary Boiler 1.063 0.0195 N/A 0.5205 Emergency Generator 1.72E-01 3.73E-03 N/A 9.98E-03 Fire Pump 5.39E-02 1.45E-03 N/A 2.29E-03 Cooling Tower(13 cells) N/A N/A N/A 3.35E-01 Note: t Emergency generator and fire pump will not operate during same 24-hour period. Note: 2. Higher concentration from screening assessment used for each pollutant and averaging period. • 8.3 Turbine Startup Facility impacts were also modeled during the startup of one turbine to evaluate short-term impacts(1 hour and 8-hour CO)under startup conditions. Emission rates used for this scenario were based on an engineering analysis of available data,which included source test data from startups of the gas turbine at a similar Calpine facility in California (LCEF). A summary of the data evaluated in developing these emission rates was shown in Appendix B. Turbine exhaust parameters for the minimum operating load point (70 percent) were used to characterize turbine exhaust during startup. Startup impacts were evaluated for both the one-and 8-hour averaging periods using ISCST3. Emission rates and stack parameters used in the startup modeling analysis are shown in Table 8-4. • 8-7 • • Table 8-4. Emission Rates And Stack Parameters Used In Modeling Analysis For Startup Emissions Impacts. Parameter Value Turbine stack 347.0 deg. K temperature Turbine exhaust velocity 16.46 m/s One-hour average impacts NQ emission rate N/A SO2 emission rate N/A CO emission rate 113.65 g/s PKo emission rate N/A Eight-hour average impacts NOx emission rate N/A SO2 emission rate N/A CO emission rate 46.24 g/s PMI°emission rate N/A 8.4 Preconstruction Monitoring • To ensure that the impacts from RMEC will not cause or contribute to a violation of an ambient air quality standard or an exceedance of a PSD increment,an analysis of the existing air quality in the area of RMEC is necessary. Colorado APCD rules require preconstruction ambient air quality monitoring data for the purposes of establishing background pollutant concentrations in the impact area. However, a facility may be exempted from this requirement if the predicted air quality impacts of the facility do not exceed the de minimis levels listed in Table 8-5. Table 8-5. APCD PSD Preconstruction Monitoring Exemption Levels Pollutant Avenging Period De minimis Level CO 8-hr average 575 µg/m3 PMto 24-hr average 10 µg/m3 NO2 Annual average 14 µg/m3 SO2 24-hr average 13 µg/m3 A facility may, with the APCD approval, rely on air quality monitoring data collected at existing monitoring stations to satisfy the requirement for preconstruction monitoring. In such a case, in accordance with the USEPA PSD guideline,the last three years of ambient monitoring data may be • 8-8 • used if they are representative of the area's air quality where the maximum impacts occur due to the proposed source. 8.5 Results of the Ambient Air Quality Modeling Analyses The maximum facility impacts calculated from each of the modeling analyses described above are summarized in Table 8-6 below. Table 8-6. Modeled Maximum Project Impacts Turbines Cooling Total Pollutant Averaging Turbine Only Towers Impact 3 Time (Kim) (µg/m3) (µgJm3)a Startup (µgiro ) NO2 Annualb 0.069 0.490 N/A SO2 3-hour Max 0.629 3.500 N/A 3-hour H2H 0.429 2.769 N/A 24-hour Max 0.142 0.187 N/A 24-hour H2H 0.117 0.150 N/A Annual 0.0039 0.0108 N/A CO 1-hour Max 34.7` 1790.2 1790.2 • 1-hour H2H 28.8° 1417.3 1417.3 8-hour Max 97.0 100.8 N/Ad 8-hour H2H 65.3 66.6 N/Ad PMioa 24-hour 1.78 4.59 4.68e N/A 24-hour H2H 1.46 2.17 4.08e N/A Annualb 0.049 0.129 0.191` N/A Notes: aTurbines, auxiliary boiler, cooling towers (PM10), and emergency generator and/firewater pump Annual NOx impacts does not consider ambient ratio method. `Turbine impacts alone are 593.0 and 402.5 ug/m3(Max and H2H)for one turbine in startup and one turbine in normal operation. °Impacts at left for normal operation which includes emissions for three hours of turbine startup conditions. e24-hour maximum and H2H and maximum annual PM,')impacts without cooling towers are 2.75, 2.45, and 0.062 ug/m3, respectively. 8.6 PSD Increment Consumption The Prevention of Significant Deterioration(PSD)program was established to allow emission increases (increments of consumption)that do not result in significant deterioration of ambient air quality in areas 8-9 • . where criteria pollutants have not exceeded the National Ambient Air Quality Standards(NAAQS). For the purposes of determining applicability of the PSD program requirements, the following regulatory procedure is used. RMEC emissions are evaluated to determine whether the potential increase in emissions will be significant. Because this facility is a new major facility,the level of emissions that requires an analysis of ambient impacts is determined on a pollutant-specific basis. The emissions increases are those that will result from the proposed new equipment. For new facilities that include large gas turbines with fired HRSGs, USEPA considers a potential increase of 100 tons per year of any of the criteria pollutants to be significant. In this specific case,RMEC is considered a new major source. Potential emissions increases are compared with the levels considered significant for new sources in Table 8-7. Table 8-7. Comparison Of Emissions Increase With PSD Significance Emissions Levels Pollutant Emissions Significant Emission Levels Significant? (tons per year) (tons per year) NO„ 246.0 40 yes • SO2 11.9 40 no VOC 51.4 40 yes CO 786.0 100 yes PMloa 167.2 15 yes alncluding cooling tower. If an ambient impact analysis is required,the analysis is first used to determine if the impact levels are significant. The determination of significance is based on whether the impacts exceed established significance levels,shown in Table 8-8. If the significance levels are not exceeded,no further analysis is required. • 8-10 Table 8-8. APCD PSD Levels Of Significance • Significant Impact Maximum Allowable Pollutant Averaging Time Levels Increments NO2 Annual 1 µg/m3 25 µg/m' SO2 3-hour 25 µg/m3 512 µg/m3 24-Hour 5 µg/m3 91 µg/m3 Annual I µg/m3 20 µg/m3 CO 1-Hour 2000 µg/m3 N/A 8-Hour 500 µg/m3 N/A PM10 24-Hour 5 µg/m3 30 µg/m3 Annual 1 µg/m3 17 µg/m3 If the significance levels are exceeded, an analysis is required to demonstrate that the allowable increments will not be exceeded,on a pollutant-specific basis. Increments are the maximum increases in concentration that are allowed to occur above the baseline concentration. These PSD increments are also shown in Table 8-8. • Table 8-7 shows that RMEC will be a major new source of NO;CO, PKo and VOC. Emissions of SO2 are less than the major source thresholds. The maximum modeled impacts from RMEC are compared with the significance levels in Table 8-9 below. These comparisons show that RMEC does not exceed the significance levels for any pollutant for any averaging time. Thus,no multi-source modeling analyses were performed. Table 8-9. Comparison Of Maximum Modeled Impacts& PSD Significance Thresholds Maximum Significance Pollutant Averaging Time Modeled Threshold Significant? Impacts (µg/m3) (µg/m) NO2 Annual 0.490 1 no SO2 3-Hour 0.629 25 no 24-Hour 0.142 5 no Annual 0.0039 I no CO 1-Hour 1790.2 2000 no 8-Hour 100.8 500 no • 8-11 Table 8-9. Comparison Of Maximum Modeled Impacts & PSD Significance Thresholds • Maximum Significance Pollutant Averaging Time Modeled Threshold Significant? Impacts (µg/m3) (µg/m3) PM1pa 24-Hour 4.68 5 no Annual 0.191 1 no alncluding cooling tower and emergency equipment Preconstruction monitoring is not required because the maximum impacts did not exceed de minimis levels, as shown in Table 8-10. Table 8-10. Evaluation Of Preconstruction Monitoring Requirements Averaging Exemption Concentration Maximum Modeled Monitoring Pollutant Time (Pg./ Concentration Concentration(µg/m3) Required? NO„ Annual 14 0.490 no SO2 24-hr 13 0.187 no CO 8-hr 575 100.8 no PMloa 24-hr 10 4.68 no Including cooling tower and emergency equipment. 8.7 Impacts to Class I Area, Integral Vistas and Sensitive Lakes Analysis An analysis of air quality impacts in nearby Class I and sensitive Class H areas and Integral Vistas was conducted for the Rocky Mountain Energy Center. Table 8-11 presents the areas analyzed,the land classification,the responsible Federal Land Manager(FLM), nearest distance to the project, and the type of analysis conducted. The list of areas and types of analysis evaluated was identified in cooperation with the FLMs. Table 8-11. Class I & Sensitive Class II Areas and Integral Vistas Evaluated Federal Nearest Area Classification Land Distance to Analysis Manager Project(km) Rocky Mountain Class I NPS 76.3 Regional Haze National Park Acid Deposition Class I Increments and Standards • Rawah Wilderness Class I USFS 118.1 Regional Haze 8-12 • • Table 8-11. Class I & Sensitive Class II Areas and Integral Vistas Evaluated Federal Nearest Area Classification Land Distance to Analysis Manager Project(km) Island Lake Sensitive Lake 132.5 Acid Deposition Class I Increments and Standards Indian Peaks Wilderness Class II USFS ANC Blue Lake Sensitive Lake 87.3 No Name Lake Sensitive Lake 93.7 Mt. Evans Wilderness Class 11 USFS ANC Upper Bear Tracks Lake Sensitive Lake 104.0 Pawnee Buttes Integral Vista USFS 81.0 Regional Haze Because all distances are greater than 50 km from the project site,CALPUFF model(version 5.5 Level 010730 1)/CALPOST (version 5.2 991104D) were used to quantify impacts. The CALPUFF/CALPOST modeling system was run in a screening mode. The analyses followed methods established and agreed upon in the modeling protocol (October 5, • 2001)and subsequent comments provided by the Colorado Air Pollution Control Division(November 27,2001). These documents are included as attachments to this report for convenience of the reviewer. However,the following changes were made to the CALPUFF input files,which differ slightly from the submitted protocol. The grid spacing was changed to 190.1 km rather than the 175 km spacing stated in the protocol due to closer examination of some of the distances to the subject areas. Also, only 1 vertical layer was used due to the homogeneous nature of the meteorological wind field used in the screening model; the protocol inadvertently stated 2 vertical layers would be used. The cell face heights remain unchanged. Additionally,the land use parameters of surface roughness length(Zo)and leaf index were changed, following guidance provided by Ms. Doris Jung of CDPHE APCD. Using a topographic map which also shows various land use types(e.g.,forest,urban,etc.)the fractional amount of each land use type was determined along the direct path from the project to the subject Class I or Class II area. The • weighted-mean value surface roughness length and leaf index was then calculated for each area and 8-13 • • • assigned in the CALPUFF input file. Table 8-12 presents the fractional land use type and value determined from the analysis. Table 8-12. Land Use Parameters Class I or II Area Land Fraction Zo(m) Leaf Index Use Rocky Mountain Forest 0.34 1 7 National Park. Ag. Ir. 0.57 0.25 3 Urban 0.09 1 0.2 Weighted Average 0.57 4.11 Rawah Wilderness Forest 0.5 1 7 and Island Lake Ag Ir. 0.5 0.25 3 Weighted Average 0.63 5.0 Blue Lake& Forest 0.36 1 7 No Name Lake Ag. Ir. 0.42 0.25 3 (Indian Peaks Urban 0.22 1 0.2 Wilderness) Weighted Average 0.69 3.82 Upper Bear Tracks Forest 0.34 1 7 Lake(Mt. Evans Ag. Ir. 0.52 0.25 3 Wilderness) Urban 0.14 1 0.2 • Weighted Average 0.61 3.97 Pawnee Buttes Ag Ir. 0.5 0.25 3 Range 0.5 0.05 0.5 Weighted Average 0.15 1.75 Three receptor rings were created for each of the Class I areas, one ring representing the nearest, middle, and farthest distances from the project location. Each receptor ring consists of 360 equally spaced receptors per ring at an elevation equal to that mean elevation of the transecting arc in the Class I area. Table 8-13 presents the distances and elevations of the receptor rings for each Class I area. Distances may vary within a few kilometers of those distances presented in the modeling protocol,upon reevaluation and new plant coordinates. Elevations for sensitive lakes were provided by Ms. Laura Hudnell of the USFS. Table 8-13: Receptor Rings Used in the CALPUFF Modeling Area Distance to Elevation(m) Receptor Ring (m) • Rocky Mountain National 76.3 2743 8-14 Table 8-13: Receptor Rings Used in the CALPUFF Modeling • Area Distance to Elevation (m) Receptor Ring (m) Park 95.0 3200 113.6 3810 Rawah Wilderness 118.1 3048 129.1 3200 140.1 3200 Island Lake(Rawah W.) 132.5 3392 Indian Peaks Wilderness Blue Lake 87.3 3447 No Name Lake 93.7 3608 Mt. Evans Wilderness Upper Bear Tracks Lake 104.0 3536 Pawnee Buttes 81.0 1524 Following the IWAQM screening method, the maximum concentration for each pollutant, for each distance averaging time modeled was selected for comparison with the appropriate AQRV. • Results of Class I PSD Increment Consumption Analysis are presented in Table 8-14. The NO2 values conservatively assume 100%conversion of NO„to NO2. The maximum-model predicted impact is presented and compared with the allowable PSD Class I increments. In addition,the results are also compared with the FLM's proposed PSD Class I area modeling significance levels. In all cases,the model-predicted impacts are below both the modeling significance levels and the PSD increments. Table 8-14. Model-Predicted Class I Area PSD Increment Consumption (All concentrations are presented in units of ug/m3) Maximum Proposed Class I Area Pollutant Averaging Model- Class I PSD Class I PSD Period Predicted Increment Modeling Impact Level Significance Levels Rocky NO2 Annual 0.03 2.5 0.1 Mountain SO2 3-hour 0.0004 25 1.0 National 24-hour 0.01 5 0.2 Park Annual 0.002 2 0.1 PMI0 24-hour 0.20 8 0.3 Annual 0.031 4 0.2 • 8-15 Table 8-14. Model-Predicted Class I Area PSD Increment Consumption(All concentrations are presented in units of ug/m3) Maximum Proposed Class I Area Pollutant Averaging Model- Class I PSD Class I PSD Period Predicted Increment Modeling Impact Level Significance Levels Rawah NO2 Annual 0.0095 2.5 0.1 Wilderness SO2 3-hour 0.04 25 1.0 Area 24-hour 0.01 5 0.2 Annual 0.002 2 0.1 PM1p 24-hour 0.11 8 0.3 Annual 0.015 4 0.2 8.7.1 Results of Distant Field Visibility Modeling The maximum model-predicted light extinction, background light extinction, and percent change in light extinction at each Class I area and Pawnee Buttes Scenic View are presented in Table 8-15. The background values for the Class I areas(i.e.,Rocky Mountain National Park and Rawah Wilderness Area)were obtained from the December 2000 FLAG document. The background value for Pawnee • Buttes was based upon the same values of hygroscopic and soil components as Rocky Mountain National Park.The maximum predicted change in light extinction at Rawah Wilderness and at Pawnee Buttes is less than or equal to 5%. Therefore,no further analysis is required for these locations. The maximum predicted change in light extinction at Rocky Mountain National Park was just slightly greater than 5%,with a predicted value of 5.092%. Inspection of the model output,presented in Table 8-16,revealed that there were four receptors with model-predicted change in light extinction exceeding 5%on one day out of the five years analyzed and these four receptors lie due north of the project area. Rocky Mountain National Park is located west of the facility between 265°and 305°. If one were to consider only receptors located within±45°of the Park boundary(i.e.,between 220°and 350°)then the maximum model-predicted change in light extinction is 4.303%. Hence, using the "shrunken arc" refinement,the project is not predicted to exceed the FLM's thresholds for concern for regional haze within Rocky Mountain National Park. i 8-16 • • Table 8-15: Model-Predicted Change in Light Extinction 4111 Class I Area or Scenic Model- Background % Change in View Predicted Bert Be:t Bert Rocky Mountain 0.815 16.000 5.092 National Park (Shrunken Arc) (0.689) (16.000) (4.303) Rawah Wilderness 0.555 16.000 3.471 Pawnee Buttes 0.467 16.000 2.919 Table 8-16. CALPOST Output for Rocky Mountain National Park Visibility Analysis TOP-10 24 HOUR AVERAGE EXTINCTION VALUES BEXT BEXT YEAR DAY TIME RECEPTOR TYPE B SN BACKGND %CHNG DELTA DV RH-FAC 1990 361 0000 ( 0, 2) D 16.815 16.000 5.092 0.497 2.500 1990 361 0000 ( 0, 1) D 16.814 16.000 5.090 0.496 2.500 1990 361 0000 ( 0, 3) D 16.808 16.000 5.052 0.493 2.500 1990 361 0000 ( 0, 360) D 16.807 16.000 5.045 0.492 2.500 1990 361 0000 ( 0, 4) D 16.796 16.000 4. 972 0.485 2.500 1990 361 0000 ( 0, 359) D 16.795 16.000 4.966 0.485 2.500 1990 361 0000 ( 0, 358) D 16.777 16.000 4.858 0.474 2.500 • 1990 361 0000 ( 0, 5) D 16.777 16.000 4.856 0.474 2.500 1986 339 0000 ( 0, 5) D 16.773 16.000 4 .833 0.472 2.500 1986 339 0000 ( 0, 4) D 16.773 16.000 4.832 0.472 2.500 Acid Deposition Estimates of atmospheric deposition were obtained from CALPUFF,which calculated the wet and dry fluxes of NOR,HNO3,NO3,SO2 and SO4 from the proposed project. The POSTUTIL processor was used in conjunction with CALPOST to obtain total deposition rates of nitrogen and sulfur. POSTUTIL incorporates user-defined scaling factors,to convert from individual nitrogen- and sulfur-containing species to total nitrogen and sulfur. The scaling factors in Calpost account for the appropriate unit conversions between POSTUTIL output and user-desired unit(g/m2-sec to kg/ha-yr). Deposition rates were calculated for the Class I areas and the sensitive lakes. Table 8-17 presents the maximum model-predicted nitrogen and sulfur deposition rates for the Class I areas and Pawnee Buttes. Model-predicted deposition rates for the sensitive lakes are presented in Table 8-18,and discussed in • the next section. 8-17 • • • The FLM's have established screening thresholds for nitrogen and sulfur deposition in the Western United States at 0.005 kg-ha/yr. Project-specific impacts demonstrated to be less than the screening thresholds are not considered a significant Class I areas. The model-predicted impacts of nitrogen and sulfur for the Rawah Wilderness and Pawnee Buttes are less than the FLM's screening criteria, and therefore are not considered a significant threat of acid deposition. Table 8-17. Nitrogen and Sulfur Deposition Rates Area Total Nitrogen Total Sulfur FLM Deposition Deposition Screening (kg/ha-yr) (kg/ha-yr) Threshold (kg/ha-yr) Rocky Mountain 0.0052 0.0007 0.005 National Park (Shrunken arc) (0.0035) Rawah Wilderness 0.0023 0.0004 0.005 Pawnee Buttes 0.0025 0.0004 0.005 Similar to the light extinction analysis, the maximum model-predicted nitrogen deposition rate for Rocky Mountain National Park is slightly over the 0.005 kg/ha-yr threshold(if the value was rounded to three decimal places,it would be equal to threshold value).Inspection of the model output,presented in Table 8-18,revealed that there were six receptors with model-predicted changes in light extinction exceeding 5%. These all occurred on one day out of the five years analyzed and were all predicted at receptors located due north of the project area. Using the same"shrunken arc"technique as used in the light extinction analysis,i.e.,considering only receptors located within±45°of the Park boundary,then the maximum model-predicted nitrogen deposition is 0.0035 kg/ha-yr. Hence,using this refinement, the project is not predicted to exceed the FLM's screening threshold for acid deposition within Rocky Mountain National Park. • 8-18 Table 8-18 CALPUFF-Predicted Nitrogen Deposition Rates-Rocky Mountain National Park • N TF TOP-10 8760 HOUR AVERAGE W+D DEPOSITION VALUES (g/m2/s) YEAR DAY TIME(HHMM) RECEPTOR TYPE W+D DEPOSITION 1990 365 0000 ( 0, 8) D 5.2213E-03 1990 365 0000 ( 0, 7) D 5.2091E-03 1990 365 0000 ( 0, 9) 0 5.1843E-03 1990 365 0000 ( 0, 6) D 5.1505E-03 1990 365 0000 ( 0, 10) D 5.0966E-03 1990 365 0000 ( 0, 5) D 5.0575E-03 1990 365 0000 ( 0, 11) D 4 .9643E-03 1990 365 0000 ( 0, 4) D 4. 9338E-03 1987 1 0000 ( 0, 5) D 4.8292E-03 1987 1 0000 ( 0, 6) D 4.8238E-03 8.7.2 Effects to Sensitive Lakes . Lakes and streams differ in their sensitivity to atmospheric deposition of acidifying compounds. Several factors affect lake sensitivity including bedrock geology,soil and vegetation type,hydrologic characteristics,lake chemistry and biology,and precipitation volume. Areas with sensitive lakes and streams are commonly located using maps of bedrock geology. Seepage lakes, lakes which have no visible outlet,are likely to be affected by precipitation,while drainage lakes are likely to be influenced by watershed base cation supply. Seepage lakes will be more sensitive to acidification with all other things being equal.The lake water combines many watershed factors that may be difficult to estimate or measure in the field and thus provides a convenient measure of sensitivity. One of many water chemistry parameters may be used to assess sensitivity. In pristine areas receiving little or no acid deposition, acid neutralizing capacity (ANC) provides a good measure of sensitivity to acidic deposition(U.S. Forest Service, 1989). Acid neutralizing capacity is a measure of the ability of water to neutralize acid inputs. Lakes with a high ANC can maintain a neutral pH even with some acidification whereas lakes with a low ANC will not maintain a neutral pH with acidic deposition. ANC is expressed in units of microequivalents per liter(ueq/1). Lakes with an ANC value below 25 are considered extremely sensitive. S 8-19 Four lakes were identified as"sensitive"by the USFS. These are Island Lake in the Rawah Wilderness, • Blue Lake and No Name Lake in the Indian Peaks Wilderness and Upper Bear Tracks Lake in the Mt. Evans Wilderness. At the request of the U.S. Department of Agriculture, Forest Service Rocky Mountain Region (personal communication with Ms. Laura Hudnell), a screening level analysis for deposition induced changes in lake alkalinity was conducted to determine the effects of the Rocky Mountain Energy Center on a specific watersheds in the Rawah, Indian Peaks and Mount Evans Wilderness Areas. The screening level analysis used to assess the pH and alkalinity change followed a technique presented by the USDA Forest Service,Rocky Mountain Region(January 2000). This technique,recommended by the Forest Service, quantitatively estimates the change in pH on a sensitive water body (i.e., mountain lake)by incorporating predicted deposition rates of total nitrogen and sulfur. Unfortunately, the screening methodology does not provide screening thresholds against which to compare the results of the analysis. Therefore, only the results are presented with no indication of whether these are acceptable changes in ANC. In absence of an acceptable threshold, one could also compare the deposition rates with the FLAG guidance screening thresholds of 0.005 kg/ha-yr. • The maximum annual deposition rate of nitrogen and sulfur was calculated by the CALPUFF modeling system in the same manner as deposition rates were calculated for the Class I areas. However,only one receptor ring was placed at the distance corresponding to the sensitive lake being analyzed. Receptors were placed at each 1°arc along the receptor ring for a total of 360 receptors. Watershed-specific input parameters were provided by Ms. Laura Hudnell of the USFS (personal communication). Table 8-19. ANC Calculations for Sensitive Lakes No Name Upper Bear Tracks Island Lake Blue Lake Lake Lake Input Data N dep(kg/ha-yr) 1.67E-03 3.98E-03 3.47E-03 2.84E-03 S dep(kg/ha-yr) 2.81E-04 5.75E-04 5.11E-04 4.33E-04 Watershed area(ha) 71 268 49 107 Precip(meters) 0.762 0.635 1.016 1.016 Baseline ANC (Meq/1) 41.2 21.9 24.5 52.1 Intermediate Values ANC (o) 14934 24971 8172 37948 Hs 1.757E-06 3.59E-06 3.19E-06 2.71E-06 Hn 1.195E-05 2.84E-05 2.48E-05 2.03E-05 H (dep) 10 86 14 25 • % ANC change 0.07 0.34 0.17 0.06 8-20 • Table 8-19 presents the results of the ANC screening calculations. In all cases the predicted change in ANC is less than 1%. The results are considered conservative for several reasons. First,the deposition rates calculated by CALPUFF in a screening mode were not specific to wind direction,the maximum predicted value within the receptor ring was used. Second,the generation of ANC is in the watershed catchment is assumed constant over time. Third,all atmospheric deposition of sulfates and nitrates into the catchment is assumed to enter the lake and neutralize an equivalent amount of ANC. Fourth,the monitored baseline acid neutralizing capacity of the lake represents baseline acid neutralization capacity of the water in the catchment area. These assumptions are intended to be conservative,as they do not incorporate aquatic ecosystem biogeochemistry. 8.8 Impacts on Class II Areas The proposed source impact area lies within the confines of the Weld County,which is a Class II area, and is currently attainment for all pollutants. Since lead is not emitted from the combustion of natural gas fuels no further discussion on this pollutant is necessary. The modeled source impacts as delineated above were less than the SILs for all pollutants for all averaging periods. As secondary air quality standards are designed to protect agricultural interest, the impacts to soils and vegetation would be . insignificant as the impacts are less than the air quality standards. 8.8.1 Potential Stack Emission Effects on Soil and Vegetation Emissions from the turbine/HRSG stacks and cooling tower drift will not significantly affect vegetation and soils surrounding the RMEC project area. The following paragraphs present the results of an analysis of the turbine/HRSG stack and cooling tower emissions for the RMEC project. The purpose of this analysis is to evaluate the potential detrimental effects that the projected turbine/HRSG stack and cooling tower emissions from the RMEC plant site will have on surrounding vegetation. Potential pollutant stack emissions included in this analysis include carbon monoxide (CO), inhalable particulates(PM10),and oxides of nitrogen and sulfur(NOx and SO2). No pollutant emissions are predicted to result in concentrations exceeding the U.S. Environmental Protection Agency (USEPA) prevention of significant deterioration (PSD) significant impact levels, for either short-term or annual averaging periods for CO, PMio, ,NOx, and SO2. • 8-21 • Carbon Monoxide • Plants metabolize and produce carbon monoxide (CO). Few studies on thresholds for detrimental effects on vegetation have been conducted. Most available studies use very high CO concentrations (above 100 ppm). Soil microorganisms probably acts as a buffering system and sink for CO. There are no known detrimental effects on plants due to CO concentrations of 10,000 to 230,000 µg/m3(USEPA 1979). Zimmerman et al. (1989)exposed a variety of plant species to CO at concentrations of 115,000 µg/m3 to 11,500,000 µg/m3 from 4 to 23 days. While practically no growth retardation was noted in plants exposed at the lower level,retarded stem elongation and leaf deformation were observed at the higher concentrations. Pea and bean seedlings also exhibited abnormal leaf formation after exposure to CO at 27,000 µg/m3 for several days(USEPA 1979). Comparatively low levels of CO in the soil have been shown to inhibit nitrogen fixation. Concentrations of 113,000 µg/m3 have been shown to reduce nitrogen fixation, while 572,000 to . 1,142,000 µg/m3 result in nearly complete inhibition(USEPA 1979). Maximum predicted 1-hour and 8-hour CO emissions have been calculated from RMEC. All impacts from CO are well below 113,000 ug/m3,even when including a background concentration. Therefore, predicted CO emission levels from the RMEC are not expected to result in adverse effects on vegetation. Sulfur Dioxide and Nitrogen Oxides SO2 and NO,,are the major airborne pollutants of concern for the RMEC project. The extent of their effect on soils and vegetation would be directly related to a variety of factors, including wind speed, direction and frequency,air temperature,humidity,the geomorphology of the area,and the location of the proposed project in relation to sensitive plant communities in the zone of impact Sulfur dioxide tends to convert to sulfite and sulfate during chemical transformation in soils. • Interpretation of the results of investigations published to date has engendered considerable controversy 8-22 i • • due to the complexity of terrestrial ecosystems. However, the effects of acidified precipitation containing sulfate(SO4)on terrestrial ecosystems have been investigated with respect to alteration of soil chemistry as it relates to vegetation health. High levels of SO4 may reduce soil pH, thereby decreasing the availability of certain essential nutrients and increasing the concentrations of soluble aluminum, which reduces plant growth. In soils where nitrate-nitrogen is not limiting plant growth,excess nitrate may percolate through the soil column,carrying base cations and exerting an acidifying effect. Increased atmospheric contributions of nitrate may influence vegetation in a species-specific way, with some species taking advantage of its fertilizing characteristics while others(such as those occurring in nitrogen-limited soils)are adversely affected. Sulfur is a major plant nutrient and can be directly absorbed into the soil. Therefore,an increase in SO2 in the soil(particularly at levels below threshold limits)would not have an adverse effect on vegetation. SO2 can affect vegetation directly(as a gas)or indirectly by means of its principal reaction product,SO4 • (e.g., acidification of soils). In addition, a third mechanism of impact is the formation of acid mist. Direct effects of injury can be manifested as foliar necrosis, decreased rates of growth or yield, predisposition to disease, and reduced reproductive capacity. Environmental factors,such as temperature,light,humidity,and wind speed,influence both the rate of gas absorption and the plant physiological response to absorbed quantities. The higher the humidity, the higher the absorption of gases. Exposure duration and frequency are also important factors that determine the extent of injuries. Guidelines for air emission impact assessment provided in the technical literature are diverse and threshold dosages required to cause injury are extremely variable. This is due to the variety of factors affecting plant responses to phytotoxic gases. Consequently,in cases where emissions are below lower threshold limits, decreased yields can result in the absence of visible injury(Sprugel et al. 1980)and long-term impacts should be addressed. • 8-23 • • • Among the different published attempts to define SO2 thresholds for vegetation effects,two represent worst-case situations. Loucks et al. (1980) presented threshold ranges between 131 µg/m3 and 262 it SO2, and McLaughlin(1981) suggested values of 1310 µg/m3 SO2 for the 1-hour average and 786 µg/m3 for the 3-hour average. According to the dose-injury curve for SO2-sensitive plant species provided by the USFWS(1978),the lowest 3-hour concentration expected to cause injury to plants is approximately 390 µg/m3,which is significantly lower than the projected concentrations from RMEC. However,these predicted values are applicable only when plants are growing under the most sensitive environmental conditions and stage of maturity. Thresholds for chronic plant injury by SO2 have been estimated at about 130 µg/m3 on an annual average(USFWS 1978). The maximum annual average concentration modeled for this project 0.0039µg/m3)is far below the USFWS threshold for chronic exposure,and the worst-case projected 3- hour maximum of about 0.629 µg/m3 is substantially below the McLaughlin protection level of 786 µg/m3. Consequently,the projected concentration of SO2 is not expected to cause visible foliar injury or significant adverse chronic effects. • Nitrogen dioxide is potentially phytotoxic, but generally at exposures considerably higher than those resulting from most industrial emissions. Exposures for several weeks at concentrations of 280 to 490 µg/m3 can cause decreases in dry weight and leaf area,but 1-hour exposures of at least 18,000 µg/m3 are required to cause leaf damage. The modeled maximum RMEC emissions of NO2 impacts of 0.490 µg/m3 are far below these threshold limits (219.0 µg/m3 or 0.1169 ppm). This indicates that NOx emissions from the RMEC,when considered in the absence of other air pollutants,would not adversely affect vegetation. Airborne Particulates Particulate emissions will be controlled by inlet air filtration and use of natural gas. The deposition of airborne particulates (PM1o) can affect vegetation through either physical or chemical mechanisms. Physical mechanisms include the blocking of stomata so that normal gas exchange is impaired,as well as potential effects on leaf adsorption and reflectance of solar radiation. Information on physical effects • is scarce, presumably in part because such effects are slight or not obvious except under extreme 8-24 • • situations(Lodge et al. 1981). Studies performed by Lerman and Darley(1975)found that particulate • deposition rates of 365 g/m2/year caused damage to fir trees,but rates of 274 g/m2/year and 400-600 g/m2/year did not damage vegetation at other sites. The maximum annual predicted concentration for PM io from RMEC is 0.191 µg/m3. Assuming a deposition velocity of 2 cm/sec(worst-case deposition velocity,as recommended by the California Air Resources Board [CARB]),this concentration converts to an annual deposition rate of 0.12 g/m2/year, which is several orders of magnitude below that which is expected to result in injury to vegetation(i.e., 365 g/m2/year). The primary chemical mechanism for airborne particulates to cause injury to vegetation is by trace element toxicity. Many factors may influence the effects of trace elements on vegetation, including temperature, precipitation, soil type, and plant species (USFWS 1978). Trace elements adsorbed to particulates emitted from power plant emissions reach the soil through direct deposition,the washing of plant surfaces by rainfall,and the decomposition of leaf litter. Ultimately,the potential toxicity of trace • elements that reach the root zone through leaching will be dependent on whether the element is in a form readily available to plants. This availability is controlled in part by the soil cation exchange capacity,which is determined by soil texture,organic matter content,and kind of clay present. Soil pH is also an important influence on cation exchange capacity; in acidic soils, the more mobile, lower valence forms of trace metals usually predominate over less mobile,higher valence forms. The soils located in the RMEC project area will have a lower potential for trace element toxicity due to the comparatively high soil pH commonly found in these soils. Perhaps the most important consideration in determining toxicity of trace elements to plants relates to existing concentrations in the soil. Several studies have been conducted relating endogenous trace element concentrations to the effects on biota of emissions from model power plants (Dvorak et al. 1977,Dvorak and Pentecost et al. 1977,Vaughan et al. 1975). These studies revealed that the predicted levels of particulate deposition for the area surrounding the model plant resulted in additions of trace elements to the soil over the operating life of the plant which were, in most cases,less than 10 percent • of the total existing levels. Therefore,uptake by vegetation could not increase dramatically unless the 8-25 • • forms of deposited trace elements were considerably more available than normal elements present in • the soil. Pahwa and Shipley(1979)exposed vegetation(corn,tobacco,and soybeans)to varying salt deposition rates to simulate drift from cooling towers that use saltwater(20-25 parts per thousand)circulation. Salt stress symptoms on the most sensitive crop plants (soybeans) were barely perceptible at a deposition rate of 0.12 g/m2/year(Pawha and Shipley 1979). Using an assumption that 100 percent of the airborne particulates from RMEC produce salts in the cooling tower drift,the calculated deposition rate of 0.09 g/m2/year is more than one order of magnitude below the deposition rate that was shown to cause barely perceptible vegetation stress from salt mist. This highly conservative estimate of deposition and the fact that the RMEC cooling towers will use fresh water makes this evaluation much overstated. Therefore, cooling tower drift is not expected to have any impact on vegetation in surrounding habitats within the maximum impact radius for the RMEC cooling tower drift and further. • 8-26 9.0 SOCIOECONOMIC AND GROWTH IMPACTS • One of the required public services is the need for a reliable electricity supply.The proposed project is just one part of a complex mix of electrical generation sources that will provide electrical power to the region in both the short and long term. 9.1 Socioeconomic Impacts Presently, the proposed project does foresee the need to hire construction and operations personnel. This hiring level is insignificant. As a result, the project, once completed, will not cause any new impacts as a result of hiring or relocating personnel. Construction contractors and workers will likely be obtained from the local area.All of the construction specialties required by the proposed project are readily available in the greater Denver Metropolitan area. As the project is built,there will be from time to time,a small influx of engineering and technical staff to oversee certain aspects of equipment placement and testing. These individuals will not require permanent housing and will instead make use of the numerous hotel and motel facilities in the project • area.As a result,the socioeconomic impacts of the project will be insignificant when compared to the other aspects of economic growth in and around the area.The project will increase the payroll value for the construction categories,but should have an insignificant affect on all other economic categories. 9.2 Growth Inducing Impacts The proposed project,which will result in an additional 600 MW of electrical power on the power grid, is in and of itself not a growth inducing impact.As stated above,the increases in population growth and demand for services,both public and private,in the Denver area is occurring at a phenomenal rate. The power plant,as proposed,is not the cause of the growth,but rather is a response to the growth and need for electrical power in the area. Independently owned and operated power plants such as that proposed by Calpine have an excellent track record of reliability and stability.These types of plants,which use clean fuels,such as natural gas, state of the art combustion technologies, such as gas turbines, and environmental control systems to minimize emissions to the air, water, and land surface, will continue to provide the public with reasonably priced electricity for many years into the future. 9-1 • 10.0 SUMMARY AND CONCLUSIONS The data and supporting analyses provided in this document demonstrate the following: • All applicable requirements of the Colorado APCD and EPA are satisfied. • Emissions from the proposed modification will not cause or contribute to an exceedance of any state or federal AAQS or PSD increment. • Emissions will be controlled using Best Available Control Technology(BACT). • Emissions will not cause detrimental effects to vegetation or soils. • Air Quality Related Values, including visibility, will be protected at all Class I areas and sensitive Class I areas. • The project will not cause significant population growth in the area. • The air quality analyses set forth in this document were conducted in accordance with EPA guidelines and included all of the Colorado APCD requirements. Based on the results of these analyses, it is concluded that the Rocky Mountain Energy Center will not pose an adverse threat to the maintenance of the local or regional AAQS, or to the health and welfare of the general public. 10-1 • REFERENCES Colorado APCD Regulations. Air Monitoring Network NAMS/SLAMS Review Reports for 1996, 1997, 1998,Colorado APCD,July 1997,July 1998, July 1999. Weather America-Detailed Climatological Data, TV Publications Inc., 1996. Weather of U.S. Cities,R.A. Wood, 5th Ed., Gale Research, ITP Information Group. Climates of the United States,Volume II:Western States,NOAA,U.S. Dept. of Commerce. Comparative Climatic Data for the United States,NOAA,U.S. Dept. of Commerce,April 1985. U.S.Bureau of the Census,Population Division,Statistical Information Section,Population Estimates Program,7-1-98. U.S. Fish and Wildlife Service, Division of Endangered Species, Listed Species Under FWS Jurisdiction as of 12-31-97 by State and Territory. • Soils and Men, U.S. Dept of Agriculture, Yearbook 1938. Western Economic Research, Census Tract Map Service, Colorado Census Tract Map, Map #C23, 1994. New Source Review Workshop Manual, USEPA, OAQPS, October 1990. Permit Application Guidance for New Air Pollution Sources,John Bunyak,National Park Service,Air Quality Div.,NRR-NPS/NRAQD/NRR-93/09,March 1993. IWAQM-Phase I Report: Interim Recommendation for Modeling Long Range Transport and Impacts on Regional Visibility,USEPA-OAQPS, EPA 454/R-93-015,4/93. Clean Air Status and Trends Network(Castnet) at http://www.epa.gov/ardpublc/acidrain/castnet IWAQM-Phase II Report: Summary Report and Recommendations for Modeling Long Range Transport Impacts, USEPA-OAQPS, EPA 454/R-98-019, 12/98. Draft Guideline on Air Dispersion Modeling,APCD, Revised,January 1998. OAQPS Cost Control Manual,4th Ed.,USEPA-OAQPS, EPA 450/3-90-006,January 1990. • • • . Alternative Control Techniques Document-NO„ Emissions from Stationary Gas Turbines, USEPA- OAQPS, EPA 453/R-93-007, January 1993. Guidance for Power Plant Siting and BACT,CARB-CEC, Stationary Source Div.,June 1999. Stationary Combustion Turbine Database, Alpha-Gamma Technologies Inc., Database Report and Summary to EPA/OAQPS-ESD Combustion Group, February 1999. Cooling Tower Drift:Its Measurement,Control,and Environmental Effects,G.K.Wistrom,et al.,CTI Annual Meeting,January 1973. • • 0 Appendix A APENs • M l.,i 6cP- j.- O ,EH ° s ¢ � }a. IIa. c Q r Q P. d = d in a > S ° y i c°. ¢ a cii o E N 9 '2 F v a v Q Q 7 0 m ° b0 0- rn � o V •c o a r c v x 2 a y g c >0 r W 2 E v at Od.Er Q .. o oo _ P7 G N a P7 M .t.).0 N x w 0 cia .. c W N G 4. E' W[y m F- 3 ._ o p m < c° ,a.E �0. a�'Ac',,?, U A : 0. V1 © c v Y = = c yu` vo et.v. 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T O G u v r. t L w y v J N A a) •C 4 ° O .E P 5 ts 9 R 0 1j �. 6 �.'1 W 'O �. ]a L _ • Appendix B Emissions Calculations and Data Sheets • 0 0 d ooro 'A 4' C, � NN CD n • 0 d 0 LL 0 00+ v N N r 0 Ea N N N N Z ` W n \N a g IO 3', 0 0 N v m N N CD O O o 0 .- 0 .- 0 0- O UI 6 N 0 N c r N c- O ^ N 6 0 N CO T N vr-0 P O Z O CO 0 O O v In LL (J co co O Odi Odi N N O O N 0 N OO N W O+ CCO r b a ' p ; O 0ro'_nn ^ , N a zN - a a 0 W CJ O ° 0 2 co W 0 P ID O CO CO d , N n m d 0 N w N 0 O U' ° N N m O .- v O+ O CC CI N 0 m O 2 0 0 - N co f n v N Z - 0 0 N on 0-2 0 Z N f 00 O o N 0 n O N N CO N N d co N O J CO 0 0 0 N N v ` M Q 0 N ry O 6 6 O 0 ` CO n v v N a 7 z Cl_ n o m O o 0 LL en CO o o m - o N in N N n n m o o n N e In ry 00 - nm_me Nn o n- o qo NNO N - Co Z 0 W "- CVO LL w O 0 N NO N m N 0 N N n o CO 0 b O0i or 0, m d O«N IV Ur' N N rim-N f (Ni CO 4- n - n n N d E6 3 o • 0 a 0 O 0 n O 0 O0+ N Oi d 0 m N N ' O ['I N N m ti 0 N co 0 m 0 d N m N " NN. W 0 a WvOOd D" - "O 0 z .O U 0 0 N 0 N N 0oP N U1 N ONi N 0 0 o M Oa In OOi 0 0 4 o m 0 n co. _ `; a N Ili z a n 4 O 0°00 LL O 0 o o 0 m m 0 N 0 0 CO CO N °i m °� 0 M 15 2E] O O in - LL 0 CO ' 0 n ' 0 m ,- co � `° 0 NN N m N _n6 ° `a N z" o 0 N v LL ` p0 m N 0 N CO • N 0 N N 0 0 O CO N O CO a LL (3m ry toMN0 0 3 T 0 ! O 0 0 0 N ` c- n P 0 Co N z N 0cn v 22 II; U 2 72 0 d N . 0 N O N N N '_ N v0 -` w W o o LL N o o N ro d N CO N 0 .{4 00f 0 ` O00Nm ON NN n nom N 0. E CC f N -;o cEE N OC N N ` _ Z o N N O Z N P d P 0 a E E E N O - m E y 0 g r o _ 0 3 r a - c co c ra T.,L: ii nLL 3m LL v S 5 S roam 0 - m m m o a t c N r m ° v 3 v Y 3 E r 3 r E r E E ., En E n E r E n r 3 m m 3 3 _ - 0 y 0 E c e o o m o m E a 0 m a n n n n n „.0c a n ry n 2 e° c a .2 ._ U a W 3 0 >1 U o^ 0 - 0 a .E o t "m ° - fag ° C o o o f n x -t `-n 3 _ n t ; v E 'N LL ry 2F2 o > 0 0 > m E - m illi a ` d O— a >2 3 E- a E z ? u"i h a a 5 w a W carK 'O^Cln n> E N �LL VZo o_ OZ °:Ca o 0 p z ° o ° o = 8 oE ( T Q E 2 O U _ 2 W u� .� n U' N o `. 0 a o H O O N p V j t v O w_ uE m 2 co o v ` mi- - l- '"W - 0 o E N Q oo 4 2220 E 0 U Tin. a ¢ Clw' ¢ w O Pa' o '._ b o o m2222 "2-23 " "t c m o 0 0 0 O N N n n_ c x o o „ c w v n E . . . . . w 2f< E ov °' 2 000022000000 ma x E- m '° C w °' r o re wU,, wQQOULLLLIiLLo2iwwwm W ZZOOJD» 00 wNNaa w az0O3 w co W UJ wQU L O .. .. - c O • • a • , _, ,, 000666 Z ZL o d a .P U O -„t. „,„ O66 G L N N Y N O c , N000000 L 2 m c '`� O L m N N O o' ^ Z VI L o O - •- L U '� P m O O O O O L ..� O ^G - O U 9 3mmccoc > c oN N L M e v m H .. .. 66 O m m' U X > 0 o O O o m 0 6., r. n .. 666 > 2 y m N P06 m n O m pi L' o x° .E 0 0 Om _ �,0000000 a� o m rv - z• Zp c' m 000 - 0 H n n noo N o o O O L - p occ ° L N `,U K. t2 I vl .Q GL N L NN h N N F' c O P a a T m z O J 50 . 777o . `° L N L - q ` } m M. L GO. O S m o v' z F 9 y z u v „ _ A b , 000000 "0H6 m 0 c c V d T '^ H - O O O ~ 3 S 6 E L o a W — _ _ Z > L L �� co00o OX '� o � '� o . c m �.. ^ N N c a a L g N a. :44 0 3 6L Y U O E V y L E U F m O O O O O O 5 L n 00 00 �' N O O \ fi 66 4 C t2 G O m a m a 22 q . O O �' N O m - d 6 .O N N 4 O O O 01 c ' G n a T H - L G _ °L 0• o R T > c o > s i 5 D a v a p ' v m m d a o $ ' E G H N 6 c5 `, N Z � nea .". , oc � a E Ex' L ul LJ u. 0 > E 2 s m „ r o c o 0 , m ? i c i m N a P L: 0 fi 5 , a c G= M = . G a a Q O G 0[ ❑ G 22 G ct OC .. U X °c 3 3 m° t' L c c 3 3 m �_ d o E .:N'.:ri 0 tcE - L'r ci > fim a ' . a '.5caL 'E ss na4 a 'E fi a E m v c o E E > > ^q c - E E 3 0 5 F 2 S HHECUUU H H HGU H • • • Notes for Table B-1 Calculation of Maximum Hourly, Daily and Annual Emissions Calculation of Maximum Hourly Emissions a. Turbines/HRSGs As hourly NON, CO and VOC emissions from the turbines are higher during startup than during full load operation, highest hourly emissions occur while one turbine is in startup mode. Except for startup, maximum hourly emissions from the turbines occur while operating at full load and 90 deg F with power augmentation and duct firing. Emissions under this operating mode are higher than under part load or low temperature operations as the duct burner operates only at full load and high temperature conditions. Emissions under full and part load conditions at maximum and minimum site temperature conditions are shown in Table B-2. Only one turbine at a time will be in startup mode. Therefore highest hourly emissions from the turbines will occur when one turbine is starting up and the other is operating at full load with power augmentation and duct firing. b. Auxiliary Boiler The maximum hourly emissions assume operation at 129 MMBtu/hr. Maximum 24-hour • emissions assumes 24 hours of operation at 129 MMBtu/hr. Annual emissions assume 1900 hours per year. c. Emergency Generator and Fire Pump The emergency generator and the fire pump will not operate simultaneously. Maximum hourly NON,SO2,CO and PM10 emissions will occur while the emergency generator is operating. Emissions from these units are shown in Table B-1. d. Cooling Tower Maximum hourly emissions occur while the cooling tower is operating at full capacity. See Table B-3. Calculation of Maximum Daily Emissions a. Turbines/HRSGs As discussed above for the hourly emissions calculations,hourly NON,CO and POC emissions are highest during startup. The operating conditions having the next highest hourly emissions are full load operation at 90 degF with power augmentation and duct firing,followed by full load operation at 50 degF with duct burning,but no power augmentation. Duct burner operation will not exceed 16 hours a day. Therefore maximum daily turbine emissions will occur on a day when each turbine has one hot and one cold start,operates at full load with power augmentation and duct firing for 16 hours, and • operates at full load without power augmentation and duct burning for the rest of the day. RMEC/APPENDIXB • • • Again, both turbines will not be in startup mode simultaneously; there will be a two-hour period between starting the first and second turbines. b. Auxiliary Boiler Maximum 24-hour emissions assume 24 hours of operation at 129 MMBtu/hr. c. Emergency Generator and Fire Pump The emergency generator and fire pump will operate a maximum of one hour per day for testing,and the two units will not be tested on the same day. Therefore maximum daily emissions correspond to one hour of operation of the unit that has the higher emissions (emergency generator). d. Cooling Tower Maximum daily cooling tower emissions will occur while the cooling tower is in operation for 24 hours. Maximum Annual Emissions a. Turbines/HRSGs Each turbine is assumed to have a maximum of 52 cold starts (156 hours) and 300 hot starts (300 hours) each year. Duct firing will be limited to the equivalent of 4600 full load hours per year per turbine. Therefore the calculation of maximum annual emissions from each • turbine is based on the following assumptions: 156 hours of cold start operation 300 hours of hot start operation 4600 hours of operation with power augmentation and duct firing 3704 hours of operation at full load, 90 degF b. Auxiliary Boiler Annual emissions assume 1900 hours per year. c. Emergency Generator and Fire Pump The emergency generator will be tested up to 200 times per year, each test lasting 30 minutes. The fire pump will be tested a maximum of 200 times per year,each test lasting up to 1-hour. Annual emissions are based on this yearly operation. • RMECJAPPENDIXB « ! \ \ - \ /a . / } / a / 9a \ / 28 ° a ± - --d822E - 72 99 ! ; 92 o : ; ; ; _ ; 8 } } } \ N} \\ : 2 § / § § % 3rt If) LO / � ( » 2 „ : 2 : \ ) } 7 )§ { } r / ! rcc ! o 2 „ 2 §cn O / ! § § / ! tt \ \ \ \ \ j 2 tal 9 ° §@I % b x i ) 7 } 4 ] ! o < t ± : 110 \ \ \ 7 } Vim : « ! 0 r. \ } ( / } } • tP / ± c ? ER \ � \ / = = z § � = 2j Table B-3 Calculation of Cooling Tower Emissions Cooling Tower Flow Characteristics: (from Bechtel, 4/27/01) Water Flow Rate, 10E6 lbm/hr 87.10 Water Flow Rate, gal/min 174,268 Drift Rate, % 0.001 Drift, lbm water/hr 870.99 PM10 Emissions based on TDS Level TDS level, ppm 10000 PM10, lb/hr 8.710 PM10, tpy 38.15 PM10 Emissions for Modeling PM10 Emissions per cell, g/s 4.22E-02 i s Table B-4 Emission Rates and Stack Parameters for Modeling • Emission Rates,g/s Exhaust Stack Temp,deg Velocity, Diam,m K m/s NOx SO2 CO PM10 Averaging Period: One hour Turbine 1/HRSG 5.6388 343.0 20.4 n/a n/a 5.796 n/a Turbine 2/HRSG 5.6388 343.0 20.4 n/a n/a 5.796 n/a Auxiliary Boiler 1.0668 435.8 25.9 n/a n/a 0.630 n/a Em Generator 0.2032 710.8 97.1 (1) (1) 1.171 n/a Fire Pump 0.1524 749.7 19.2 n/a n/a (1) n/a Cooling Tower(each cell) 11.3291 298.9 9.4 n/a n/a n/a n/a Averaging Period: Three hours Turbine 1/HRSG 5.6388 341.3 19.8 n/a 0.176 n/a n/a Turbine 2/HRSG 5.6388 341.3 19.8 n/a 0.176 n/a n/a Auxiliary Boiler 1.0668 435.8 25.9 n/a 1.134E-02 n/a n/a Em Generator 0.2032 710.8 97.1 n/a 6.863E-03 n/a n/a Fire Pump 0.1524 749.7 19.2 n/a (1) n/a n/a Cooling Tower(each cell) 11.3291 298.9 9.4 n/a n/a n/a n/a Averaging Period: Eight hours 0 Turbine 1/HRSG 5.6388 344.7 18.9 n/a n/a 46.242 n/a Turbine 2/HRSG 5.6388 344.7 18.9 n/a n/a 46.242 n/a Auxiliary Boiler 1.0668 435.8 25.9 n/a n/a 6.300E-01 Em Generator 0.2032 710.8 97.1 n/a n/a 1.464E-01 n/a Fire Pump 0.1524 749.7 19.2 n/a n/a (1) n/a Cooling Tower (each cell) 11.3291 298.9 9.4 n/a n/a n/a n/a Averaging Period: 24 hours Turbine 1/HRSG 5.6388 344.7 18.9 4.053 0.176 n/a 2.218 Turbine 2/HRSG 5.6388 344.7 18.9 3.875 0.176 n/a 2.218 Auxiliary Boiler 1.0668 435.8 25.9 n/a 1.134E-02 n/a 3.024E-01 Em Generator 0.2032 710.8 97.1 n/a 8.579E-04 n/a 2.294E-03 Fire Pump 0.1524 749.7 19.2 n/a (1) n/a (1) Cooling Tower (each cell) 11.3291 298.9 9.4 n/a n/a n/a 4.221E-02 Averaging Period: Annual Turbine 1/HRSG 5.6388 341.3 19.8 3.150 0.176 n/a 2.218 Turbine 2/HRSG 5.6388 341.3 19.8 3.150 0.176 n/a 2.218 Auxiliary Boiler 1.0668 435.8 25.9 1.339E-01 2.457E-03 n/a 6.558E-02 Em Generator 0.2032 710.8 97.1 2.170E-02 4.701E-04 n/a 1.257E-03 Fire Pump 0.1524 749.7 19.2 6.798E-03 1.821E-04 n/a 2.885E-04 Cooling Tower(each cell) 11.3291 298.9 9.4 n/a n/a n/a 4.221E-02 0 Note: 1. Emergency generator and fire pump will not operate during the same 24-hour period. Higher concentration from screening assessement used for each pollutant and averaging period. • Table B-5 Ammonia Emissions Calculations Calculation of ammonia emissions from the gas turbines and duct burners is based on the proposed ammonia slip limit of 10 ppmvd. Gas Turbines Data supplied by Calpine pertaining to the operational scenarios for the gas turbines and duct burners indicates the following with respect to ammonia emissions for each gas turbine. Table B-5 Ammonia Emissions Scenario Emissions Maximum hourly,Case D 30.9 lbs/hr W/Duct Burners, Pwr Aug, at 50 deg F . Maximum annual,based on proposed 124.8 tons/yr Annual operating scenario. Annualized hourly emissions,at 28.48 lbs/hr 8760 hrs/yr i RMEC/APPENDIXB • v C G v a. EC C ct w v I. C C O R 'J (,) a Tii Cr U � m p ° 3 a o4-i h-1>, Cr v _ - w a) u � c v vi E., 'G O. r" .D a` G G M N o G [V n a) 47,34 .a �. co LnrnN I Ln coa. I Icmr- ON t° r" is Cr >, Ln O �; rl W rl rn ri W W Ln d" .o N o 4 2 c ao < .i '---- oo4ocp. ' . I a000 U � a p LL] O r--, rti ui < N C) _ v G E~ �' et ° 0 Ln >, • G 0 C G 01 Ge o ❑ a U t 0 .>G >, '� "O .00 m cr N. W rn N. �? W W 71: In N. N. c w O Li) R m rep O .�-� O .c O In N C. N c<i ry .5 v v p G Q W .o 0o M G - G w 7 Q" ° •o V c cn et 0 G grr M M E •� OOWON in W LU .Dr , O iIIU 'E ! .x o . oogo °K° 0002 � o0o Oo E Eo rttE O N tom. x W 'fl N M N O O A. E CS O R 'i. p E O F. �", ry e,co O-i GO ,�, N M N N r-i r-i M r-+ N N N v G G Z G ' V O O 0 0 0 0 0 0 0 0 0 0 0 .O 0 �' O O et V '-. O y i i i i i i i i i i i i i '� TS U G r� 4+ LULULULULULULULULULULULULU > aJ x aJ �G. ai >, i �-. r rr M N .�D .OD hO. .O tft C) tCZ T5 CCC 0 y w LL" \ .D .D r-i 4 r-i ,- Ni 4 .D N 4 h Ni P'l w Fa R Fa C. 0 Q G G 4 `. M '- O Z c v 4.4 o C � -0 0C >. C o O CV i6 O ,L ( :� N vCa O N O (NI U O, v G •G v a G et v G G 0 O. :� 'O O G �' v v 'S v G v • v G a` E ;a °1 a) G , ,c m >, >, a G N co rtt is v U v o G v x O O o N [-" U g < < < PO r-i W [� X Z C. C�-i G E- X Z N G CC • • • Table B-7 Calculation of Toxics for Auxiliary Boiler Emission Rates Emission Maximum Factor, Hourly Annual lb/MMscf Emissions, Emissions, Chemical (1) lb/hr ton/yr Propylene 5.30E-0I 6.47E-02 6.14E-02 Acetaldehyde 9.0E-04 I.10E-04 1.04E-04 Acrolein 8.00E-04 9.76E-05 9.28E-05 Benzene 1.70E-03 2.07E-04 1.97E-04 Ethylbenzene 2.00E-03 2.44E-04 2.32E-04 Formaldehyde 3.50E-03 4.27E-04 4.06E-04 Hexane 1.3E-03 1.59E-04 1.51E-04 Naphthalene 3.00E-04 3.66E-05 3.48E-05 PAHs 1.00E-04 1.22E-05 1.16E-05 Toluene 7.8E-03 9.52E-04 9.04E-04 Xylene 5.8E-03 7.08E-04 6.72E-04 Total HAPs 6.43E-02 Notes: (1) Emission factors from Ventura County APCD. • • • • Table IS-8 Liquid Fuel IC Engine Air Toxics Emissions Calculations • Fuel Type: Diesel Max Hrs/Day: Gal/Hr: 95 Max Hrs/Yr: 100 Mgal/Yr: 0.095 Mgal/Yr: 9.5 EF Substance lbs/Mgal lbs/hr lbs/yr tons/yr Acenaphtene 6.71E-04 6.37E-05 6.37E-03 3.19E-06 Acenapthylene 1.02E-03 9.69E-05 9.69E-03 4.85E-06 Anthracene 2.23E-04 2.12E-05 2.12E-03 1.06E-06 Benzo-a-anthracene 9.60E-05 9.12E-06 9.12E-04 4.56E-07 BaP 7.90E-05 7.51E-06 7.51E-04 3.75E-07 Benzo-a-fluoranthene 1.12E-04 1.06E-05 1.06E-03 5.32E-07 Benzo-ghi-perylene 9.00E-05 8.55E-06 8.55E-04 4.28E-07 Benzo-k-fluoranthene 7.83E-05 7.44E-06 7.44E-04 3.72E-07 Chrysene 1.30E-04 1.24E-05 1.24E-03 6.18E-07 Dibenz-ah-anthracene 8.20E-05 7.79E-06 7.79E-04 3.90E-07 Fluoranthene 3.30E-04 3.14E-05 3.14E-03 1.57E-06 Fluorene 9.65E-04 9.17E-05 9.17E-03 4.58E-06 Indeno-123cd-pyrene 8.45E-05 8.03E-06 8.03E-04 4.01E-07 Naphthalene 1.60E-02 I.52E-03 1.52E-01 7.60E-05 Phenanthrene 3.54E-03 3.36E-04 3.36E-02 1.68E-05 Pyrene 2.64E-04 2.51E-05 2.51E-03 1.25E-06 Ethylbenzene 6.76E-03 6.42E-04 6.42E-02 3.21E-05 13 Butadiene 0.0E+00 0.0E+00 0.0E+00 0.0E+00 III Acetaldehyde 3.47E-03 3.30E-04 3.30E-02 1.65E-05 Acrolein 1.07E-03 1.02E-04 I.02E-02 5.08E-06 Benzene 1.81E-01 1.72E-02 1.72E+00 8.60E-04 Formaldehyde 5.10E-02 4.85E-03 4.85E-01 2.42E-04 Propylene 3.41E-01 3.24E-02 3.24E+00 1.62E-03 Toluene 6.10E-02 5.80E-03 5.80E-01 2.90E-04 Xylenes 2.10E-02 2.00E-03 2.00E-01 9.98E-05 Hexane 1.39E-03 1.32E-04 1.32E-02 6.60E-06 Arsenic I.60E-03 1.52E-04 1.52E-02 7.60E-06 Beryllium 0.0E+00 0.0E+00 0.0E+00 0.0E+00 Cadmium 1.50E-03 1.43E-04 1.43E-02 7.13E-06 Hex Chromium 1.00E-04 9.50E-06 9.50E-04 4.75E-07 Copper 4.10E-03 3.90E-04 3.90E-02 1.95E-05 Lead 8.30E-03 7.89E-04 7.89E-02 3.94E-05 Manganese 3.10E-03 2.95E-04 2.95E-02 1.47E-05 Mercury 2.00E-03 1.90E-04 1.90E-02 9.50E-06 Nickel 3.90E-03 3.71E-04 3.71E-02 1.85E-05 Selenium 2.20E-03 2.09E-04 2.09E-02 1.05E-05 Zinc 2.24E-02 2.13E-03 2.13E-01 1.06E-04 Diesel PM 8.3E+00 7.87E-01 7.9E+01 3.93E-02 EFs:CARB-CATEF Database(mean values for source type and category) Metals EFs from VCAPCD, 1/8/96 i Table B-9 • Liquid Fuel IC Engine Air Toxics Emissions Calculations Fuel Type: Diesel Max Hrs/Day: 1 Gal/Hr: 9.2 Max Hrs/Yr: 200 Mgal/Hr: 0.0092 Mgal/Yr: 1.84 EF Substance lbs/Mgal lbs/hr lbs/yr tons/yr Acenaphtene 6.71E-04 6.17E-06 1.23E-03 6.17E-07 Acenapthylene 1.02E-03 9.38E-06 1.88E-03 9.38E-07 Anthracene 2.23E-04 2.05E-06 4.10E-04 2.05E-07 Benzo-a-anthracene 9.60E-05 8.83E-07 1.77E-04 8.83E-08 BaP 7.90E-05 7.27E-07 1.45E-04 7.27E-08 Benzo-a-fluoranthene 1.12E-04 1.03E-06 2.06E-04 1.03E-07 Benzo-ghi-perylene 9.00E-05 8.28E-07 1.66E-04 8.28E-08 Benzo-k-fluoranthene 7.83E-05 7.20E-07 1.44E-04 7.20E-08 Chrysene 1.30E-04 1.20E-06 2.39E-04 1.20E-07 Dibenz-ah-anthracene 8.20E-05 7.54E-07 1.51E-04 7.54E-08 Fluoranthene 3.30E-04 3.04E-06 6.07E-04 3.04E-07 Fluorene 9.65E-04 8.88E-06 1.78E-03 8.88E-07 Indeno-123cd-pyrene 8.45E-05 7.77E-07 1.55E-04 7.77E-08 Naphthalene 1.60E-02 1.47E-04 2.94E-02 1.47E-05 Phenanthrene 3.54E-03 3.26E-05 6.51E-03 3.26E-06 Pyrene 2.64E-04 2.43E-06 4.86E-04 2.43E-07 Ethylbenzene 6.76E-03 6.22E-05 1.24E-02 6.22E-06 13 Butadiene 0.0E+00 0.0E+00 0.0E+00 0.0E+00 • Acetaldehyde 3.47E-03 3.19E-05 6.38E-03 3.19E-06 Acrolein I.07E-03 9.84E-06 1.97E-03 9.84E-07 Benzene 1.81E-01 1.67E-03 3.33E-01 1.67E-04 Formaldehyde 5.10E-02 4.69E-04 9.38E-02 4.69E-05 Propylene 3.41E-01 3.14E-03 6.27E-01 3.14E-04 Toluene 6.10E-02 5.61E-04 1.12E-01 5.61E-05 Xylenes 2.10E-02 1.93E-04 3.86E-02 1.93E-05 Hexane 1.39E-03 1.28E-05 2.56E-03 1.28E-06 Arsenic 1.60E-03 1.47E-05 2.94E-03 I.47E-06 Beryllium 0.0E+00 0.0E+00 0.0E+00 0.0E+00 Cadmium 1.50E-03 1.38E-05 2.76E-03 1.38E-06 Hex Chromium 1.00E-04 9.20E-07 1.84E-04 9.20E-08 Copper 4.10E-03 3.77E-05 7.54E-03 3.77E-06 Lead 8.30E-03 7.64E-05 1.53E-02 7.64E-06 Manganese 3.10E-03 2.85E-05 5.70E-03 2.85E-06 Mercury 2.00E-03 1.84E-05 3.68E-03 1.84E-06 Nickel 3.90E-03 3.59E-05 7.18E-03 3.59E-06 Selenium 2.20E-03 2.02E-05 4.05E-03 2.02E-06 Zinc 2.24E-02 2.06E-04 4.12E-02 2.06E-05 Diesel PM 8.3E+00 7.62E-02 1.5E+01 7.62E-03 EFs:CARB-CATEF Database(mean values for source type and category) Metals EFs from VCAPCD, 1/8/96 • • • 0 Appendix C Concentration Isopleth Maps • • • • • Emissions, Modeling Characteristics, and Screening Results for Turbines Case D E N GP F B J Ambient Dry Bulb Temperature deg F 90 102 90 50 50 3 90 100% 100% 100% no 100% 70% no 100% no 70% no Conditions w/DB and w/DB and w/DB and PA and DB and PA and no PA no PA DB/ PA no PA no DB no PA DB Unitized Modeling Results for 1 g/s/turb D E N GP F B J Stack Height meters 53.340 53.340 53.340 53.340 53.340 53.340 53.340 Stack Diameter meters 5.639 5.639 5.639 5.639 5.639 5.639 5.639 Stack Temperature Kelvins 343.0 344.7 343.0 341.3 346.9 349.7 346.9 Stack Velocity m/s 20.422 18.898 19.202 19.812 16.459 21.641 16.459 1-hour ug/m3 5.98197 6.41023 6.37597 6.24452 7.21032 5.37619 3-hour ug/m3 3.40614 3.69412 3.66722 3.57575 4.23287 3.02419 Same as 8-hour ug/m3 1.81796 2.09750 1.94631 1.89989 2.46301 1.45653 Case F 24-hour ug/m3 0.67372 0.80393 0.72206 0.70461 0.94904 0.57687 Annual ug/m3 0.02076 0.02183 0.02207 0.02199 0.02900 0.01768 Pollutant Modeling Results D E N GP F B J NOR, as NO2,Maximum g/s/turb 3.150 2.898 3.024 3.024 1.638 2.394 1.512 SO2, Annual Average g/s/turb 0.176 0.164 0.164 0.176 0.088 0.139 0.088 CO g/s/turb 5.796 5.292 5.418 5.544 3.024 4.410 2.898 PM10 (excludes H2SO4 mist) g/s/turb 2.230 2.155 2.167 2.155 1.386 1.386 1.386 NOR, as NO2,Annual ug/m3 0.065 0.063 0.067 0.066 0.048 0.042 0.044 • SO2, 3-hour Average ug/m3 0.6008 0.6051 0.6007 0.6308 0.3733 0.4192 0.3733 SO2, 24-hour Average ug/m3 0.1188 0.1317 0.1183 0.1243 0.0837 0.0800 0.0837 SO2, Annual Average ug/m3 0.0037 0.0036 0.0036 0.0039 0.0026 0.0025 0.0026 CO, 1-hour Average ug/m3 34.671 33.923 34.545 34.620 21.804 23.709 20.896 CO, 8-hour Average ug/m3 10.537 11.100 10,545 10.533 7.448 6.423 7.138 PM10, 24-hour Average ug/m3 1.503 1.732 1.565 1.518 1.315 0.800 1.315 PM10 Annual Average ug/m3 0.046 0.047 0.048 0.047 0.040 0.025 0.040 • • mmcnm (n m mmcnmcn 3 m x x x d '0 3 d d D 3 S S n D N (/ D) co - D) x- a)) CO. C• O OF. 0 S 0 O .w. 0 d co S _ O o f pj co (.9_ co y < a d m C c0 c0 0 _a 3 (D (D Cy 0 0 3 co h 0 0 0 0 O N cow (D IO co » in Z 'o DN m w -s3 N 'Ts iii- Zr) N co Oo. `< 0 Da no. w -. 3 N.O^ A CP Q Q Q 0 O 'A S S Co C 'A W W Q Q .� j S �' J ,w.. `G i300- W '� i 7 (I 0w C O O O O C O 0 S S S J C O O O O C O S V)00 S y) D) C C i d w C O O O " N O C -, S C O O O S " C CC C J — C C C. N C N v v 0 a 0 7 0 A CO N - ._. .... .i— n • O C. O J 0 O J 70 Z p) �' O O. �' y W O •ON N W U Z m Z d Ocn N J 0 cn tD O d (n O Q. co O. c%. O. - 0 D m co m 0 CD W 00 O CO OCO D to A (n C71 A O x 0 a 0. 3 O j 0 O) A (D N W a co c) 0 J A q (D " 0- 0 co N O1 0 co O -, o co. O n 0 -33 n 3• a N - W N J O (n n J cD O O O 0 0 0 (n N a' m 0 o S co m 3 O uo � _, 'wN ON ao owb O m 3 co 9° Z + cat". oho 'oo � 5 x0 S 7 cn N N -1 0 m Z 0 m (P m o m m m O) d.x- () m co is is O O) ^) °) (� O to m O w N CP cn 0 3 N Q .. D co N '0 O O O O W D A v w T o O) A cD 0 o C N CU A A W W 7 O D OT O0 0 a 0 0 0 as o m a O 3 0 0" 00 0 o w o0 o w0 � wo � rn to CD A ^)• LT,� O fn (D a co 3 0 N 0 • a Ol A0 a m A a A 0 a 0 0V A O O o CO cD W -, 0 O 0 0 O W (n (D cocoCO O) (0 fD p 0 ono 0 o N N N W 0 0 W CD Zm � 0 ETT ° = 3 w3 CD 3 0 000 0 � v m �) 3 co 3 u m oho oo0m =. 0 �< (D 7 N �_ C y CO O Z_ .0 a o O o 0 00 " Z_ A O A O O w A 3 (0 N C N O l D O r 0 m a isW0 U1 0 D W N v WO 0 "-1 O 0 Zi A O O ] (D W CO 0 . d v 0 d (0 co C tn o o H w H cn C FD: D w O• N 5. O (0 d �. C y cn c cn -. ( a .N.. O M < D• co fn o Co N C 0 0) W O (O W O C 0 w w 5 W d ccnn o � 00 o ^ O) O N 0 0 •' m A n 0 o a 3" y � 3 d o- w z- m 3 • O d - 9 a co 3 (O—D g, C n a A < a �A (C o d 3 V 0 w < 0 < v 1171003 — C m m O O 0- O ^ G 0 Ej 0 0 On V W O C 7 CD 0 n j 3t IQ " W C 0.' m -a te a � CD (� r". z N co is con N' O o C sc.,- C cD C Z a W O O cp N 0 0 » c a C 7 Co ;') (^) ' 3 0 00 __ N D V N N a 3 0 0 0 __ N co • y 0 O W W O- coon w Co c o o m O O W W m U1 W W C d 3 0 oo NW 0 VW "" 3 S S C W A A 3 CO (D "O (O c0 'O - ry N O N —. a 0 N N C A C n N N.-.j —I ° 41 < j 0 3 cn cn cn cn � w ss- w o ww w w3 -- = fl d 7 O J J CO CO^ N-c0 cn cn an O)^ O co =O 0 0 a -. X003 0) o �- D—) 00003 C0. 3 = O 0 0 0 O H. 3 co 0 co C y a) c N O o a A A a H cn �. A a a A -I O — C w Aw W is C C w w w W C 3 0 a cn V 0 3 N- NNN3"' NNOO---- rr N CO CO -, w cD CO (D CO < N N W CO Q] C CO 0 0 0 -< is N CO V1 C) CC0000K 0 00i N N D 3 0 0 0 v A Co - 0 0 0 o m 0 o O a O co co I 0' N 0 N) N I N a Co S m a Co ' _ i • • Emission Rates and Stack Parameters for Refined Modeling • Emission Rates,g/s Exhaust Stack Temp,deg Velocity, Diam,m K m/s NOx SO2 CO PM10 Averaging Period: One hour Turbine 1/HRSG 5.6388 343.0 20.4 n/a n/a 5.796 n/a Turbine 2/HRSG 5.6388 343.0 20.4 n/a n/a 5.796 n/a Auxiliary Boiler 1.0668 435.8 25.9 n/a n/a 0.630 n/a Em Generator 0.2032 710.8 97.1 (1) (1) 1.171 n/a Fire Pump 0.1524 749.7 19.2 n/a n/a (1) n/a Cooling Tower(each cell) 11.3291 298.9 9.4 n/a n/a n/a n/a Averaging Period: Three hours Turbine 1/HRSG 5.6388 341.3 19.8 n/a 0.176 n/a n/a Turbine 2/HRSG 5.6388 341.3 19.8 n/a 0.176 n/a n/a Auxiliary Boiler 1.0668 435.8 25.9 n/a 1.134E-02 n/a n/a Em Generator 0.2032 710.8 97.1 n/a 6.863E-03 n/a n/a Fire Pump 0.1524 749.7 19.2 n/a (1) n/a n/a Cooling Tower (each cell) 11.3291 298.9 9.4 n/a n/a n/a n/a Averaging Period: Eight hours Turbine 1/HRSG 5.6388 344.7 18.9 n/a n/a 46.242 n/a 0 Turbine 2/HRSG 5.6388 344.7 18.9 n/a n/a 46.242 n/a Auxiliary Boiler 1.0668 435.8 25.9 n/a n/a 6.300E-01 Em Generator 0.2032 710.8 97.1 n/a n/a 1.464E-01 n/a Fire Pump 0.1524 749.7 19.2 n/a n/a (1) n/a Cooling Tower(each cell) 11.3291 298.9 9.4 n/a n/a n/a n/a Averaging Period: 24 hours Turbine 1/HRSG 5.6388 344.7 18.9 4.053 0.176 n/a 2.218 Turbine 2/HRSG 5.6388 344.7 18.9 3.875 0.176 n/a 2.218 Auxiliary Boiler 1.0668 435.8 25.9 n/a 1.134E-02 n/a 3.024E-01 Em Generator 0.2032 710.8 97.1 n/a 8.579E-04 n/a 2.294E-03 Fire Pump 0.1524 749.7 19.2 n/a (1) n/a (1) Cooling Tower(each cell) 11.3291 298.9 9.4 n/a n/a n/a 4.221E-02 Averaging Period: Annual Turbine 1/HRSG 5.6388 341.3 19.8 3.150 0.176 n/a 2.218 Turbine 2/HRSG 5.6388 341.3 19.8 3.150 0.176 n/a 2.218 Auxillary Boiler 1.0668 435.8 25.9 1.339E-01 2.457E-03 n/a 6.558E-02 Em Generator 0.2032 710.8 97.1 2.170E-02 4.701E-04 n/a 1.257E-03 Fire Pump 0.1524 749.7 19.2 6.798E-03 1.821E-04 n/a 2.885E-04 Cooling Tower(each cell) 11.3291 298.9 9.4 n/a n/a n/a 4.221E-02 • Note: 1. Emergency generator and fire pump will not operate during the same 24-hour period. Higher concentration from screening assessement used for each pollutant and averaging period. • - • ROCKY MOUNTAIN ENERGY CENTER Maximum 1 -hour CO Concentrations (ug/m3) 4443000 H - . - � I it 4442000 / /\`�� + a 2 5 l ,f 0 , 4441000rill. • So t �\ �1 'b J 4440000 y ti' - `c�1c �• / rO"' .�i Fr , — r �� / • �_ { 4439000 '-' ti ��:C E h i c.�r--- 0 4438000 � � //C6 �, �? \ • Z J 2 ? f 5� _ i, ie . IT? -- 4437000 I \ Q•NI 4436000 �lA i 4%12 2 �' !• ' udsan .q 1 i R: 4435000 rI' ... - " ., �, `. • • \ , S0 _ �o 4434000 - 1349- 50 - 4433000 ' 530000 531000 532000 533000 534000 535000 536000 537000 538000 539000 UTM Easting (m) • * Overall Maximum 1-hour Scale: 1" = 1500 meters \ CO Concentration = 1790 ug/m3 0 2000 4000 • ROCKY MOUNTAIN ENERGY CENTER Maximum 8-hour CO Concentrations (ug/m3) 4443000 / i � 4442000 I 411 cd O 1J .c.Ctee.,%7,D / I 7SS1 4441000 is O 7576 / �\ i, 4440000 IL t 9 / p III)._--- 20 - 4439000 — ^°• E p m 20 ea IIIIII o - 1 15 c n ` _ j . 0�. \ 11 • 0 4438000 r S . 1 , ., 15 1-..-L.,.‘_ �/` `` k , rT 'S� = 4437000 \ i f \ °LS:c `, _ N y• rnise4436000 fhv� _ 4' 1 r n 'ThC e io;) • 7 \ ‘,..,,, N,I I \ 4-,Judson 0 4435000 �r�_ i 1 [-I,) - `3015 \i 4434000 7 72 o io 15a9c i. n )4433000 ' _. i ' _. 530000 531000 532000 533000 534000 535000 536000 537000 538000 539000 UTM Easting (m) • * Overall Maximum 8-hour Scale: 1" = 1500 meters CO Concentration = 101 ug/m3 0 2000 4000 • ROCKY MOUNTAIN ENERGY CENTER Maximum Annual NOx Concentrations (ug/m3) 4443000 I , I I 4442000 / / o� o FI / 1 // ) 0,04 4441000 k,_ ! 1 • 57 S 4440000 k . -� 4439000 --- ---C - ¢rj i oo .----/ E • 4438000 � 0 z ` Y• 1• 4437000 i \`, 0 r _� 0 O 4436000 a - 6 I 7572 �./ 4 / s . ,4- ! 'i 4tludson • O V 0 4(4 �,pS v � , 4435000 1- r� i v' { _ 1 ., t 4434000 o� ,� �, 5a9- �_ , / n 4433000 = 530000 531000 532000 533000 534000 535000 536000 537000 538000 539000 UTM Easting (m) • Overall Maximum Annual Scale: 1" = 1500 meters \ NOx Concentration = 0.5 ug/m3 0 2000 4000 • ROCKY MOUNTAIN ENERGY CENTER Maximum 24-hour PM10 Concentrations (ug/m3) 4443000 — , Litoij eu ` I 4442000 / 7.43s•. T - „D ear O + .o // 0:65 , 4441000 , p5 , "�p.35 J(1,� S '1 1516' J V . a 4440000 0k; — • •- . O. — • - — r is co 4439000 --.___- j r O" �r ,, .� • r 4438000 i g O 4437000 \ / r f s 4. \ (---r- . 4436000 4 + /\, I _ , 12 �- r -' mi' I1-Judso " O 7-75 0. 4435000 1 _I � a� �� 4434000 o -6 6 4433000 . 1 i { ''.2.: 530000 531000 532000 533000 534000 535000 536000 537000 538000 539000 UTM Easting (m) • * Overall Maximum 24-hour Scale: 1" = 1500 meters \ PM10 Concentration = 4.7 ug/m3 0 2000 4000 • • • ROCKY MOUNTAIN ENERGY CENTER Maximum Annual PM10 Concentrations (ug/m3) 4443000 I , t ,/ -- 4442000 I i ...,./ p , b0 r . 4441000 ' `kr --__ r ,57 0 4440000 V (1taiigj sr o =�y__ ._ -- � d. 4439000 - - � � •. ? • FF; :• 002 r 4438000 �: �� • o �, 4437000 �� /�N, -q S •1 -c --.� U� p �� 4436000 - \, 5a z C3 l 14 ny -Jut on v '1. D Off\ 4435000 i1 i 1 4434000 _ o o 9 w 0 4433 000 I 1 r 530000 531000 532000 533000 534000 535000 536000 537000 538000 539000 UTM Easting (m) • Overall Maximum Annual Scale: 1" = 1500 meters \ * PM10 Concentration = 0.19 ug/m3 0 2000 4000 • ROCKY MOUNTAIN ENERGY CENTER Maximum 3-hour SO2 Concentrations (ug/m3) 4443000 I V 4 4442000 lO _ / O . - o ripI 0 . _ 44410004 1N , O 7 6 li 4440000 99 _ �' `m - ^y ^�. . . - 4439000 - • ,` • •_ 1 • • r „r 4438000 �. .� F • t .. LILY'-'►�/ ^h •.!/nom _ •� n'• ^• / • •• F 4437000 ! /� y tl_ • S 1 .29 hYY� c 4436000 a rt . • 4 PIB • - ^• " Y -ate N r 4435000 +-t_ o , • 0.2 O o N 4434000 O O .� 13¢9' N-10,15 0.2 4433000 ' x 530000 531000 532000 533000 534000 535000 536000 537000 538000 539000 UTM Easting (m) • * Overall Maximum 3-hour Scale: 1" = 1500 meters \ SO2 Concentration = 3.5 ug/m3 0 2000 4000 ! • • ROCKY MOUNTAIN ENERGY CENTER Maximum 24-hour SO2 Concentrations (ug/m3) 4443000 1 %4•01,:c - -r---- V 7 6/ r 4442000 I 7110 a o \ O pp. /' ^�\ // � pp O 4441000 , i"_ = ./- o 4440000 ' " i v :1 - _ • . . _ 4439000 f I. ' ice , • f ti E 1" .p •- \ 0.0 0r 4438000 �� 1� + :,ter` pb� z • DO 4437000 4436000 \OO6, ` thilison , \ , 4435000 i _ o' 4434000 i S. c N o o. yfl9- , / S Sv 4433000 J 530000 531000 532000 533000 534000 535000 536000 537000 538000 539000 UTM Easting (m) • Overall Maximum 24 hour Scale: 1" = 1500 meters SO2 Concentration = 0.19 ug/m3 0 2000 4000 • • • ROCKY MOUNTAIN ENERGY CENTER Maximum Annual SO2 Concentrations (ug/m3) 4443000 / iAre, r- 4442000 I / ! No ' SO I I f ( w S 4441000 - % o0 $ , b / i r J v% 4440000 e `\ — i l ov 4439000 — } {' fit.)crA ? ` s�i apr I X02 l , t 4438000 i C� .� Q �Q D 4437000 I �1 oo, , e .'' :`:o r OO`1' /. 4436000 s r' h► r -t' Vi `pudson N f1:-\<- -r . , , r' 1 oo o �' ; G o p 4435000 r� 0.r o ( F�f,•r- o n \ , 4434000 / O O O 3e9- 4433000 ' In T: II , 530000 531000 532000 533000 534000 535000 536000 537000 538000 539000 UTM Easting (m) • Overall Maximum Annual Scale: 1" = 1500 meters \ SO2 Concentration = 0.01 ug/m3 0 2000 4000 r • • Appendix D Modeling Input/Output Files on CD • • 1 • File contains CD of Modeling Input/Output Files See Original File Hello