MUNICIPAL WASTE COMBUSTORS -- BACKGROUND INFORMATION FOR PROPOSED STANDARDS: COST PROCEDURES FINAL REPORT Prepared for: Michael G. Johnston U.S. Environmental Protection Agency Industrial Studies Branch (MD-13) Research Triangle Park, North Carolina 27711 Prepared by: Radian Corporation 3200 E. Chapel Hill Rd./Nelson Hwy. Post Office Box 13000 AUGUST 14, 1989 ------- DISCLAIMER This report has been reviewed by the Emission Standards Division of the Office of Air Quality Planning and Standards, EPA, and approved for publication. Mention of trade names or commercial products is not intended to constitute endorsement or recommendation for use. Copies of this report are available through the Library Services Office (MD-35), U.S. Environmental Protection Agency, Research Triangle Park NC 27711, or from National Technical Information Services, 5285 Port Royal Road, Springfield VA 22161. / ------- TABLE OF CONTENTS Secti on Page 1.0 INTRODUCTION 1-1 2.0 PROCEDURES FOR NEW PLANTS 2.1-1 2.1 COMBUSTORS AND BALANCE OF PLANT 2.1-1 2.1.1 Modular Units 2.1-2 2.1.1.1 Overview of Technology 2.1-2 2.1.1.2 Capital Cost Procedures 2.1-2 2.1.1.3 Operating Cost Procedures 2.1-4 2.1.2 Mass Burn Units 2.1-5 2.1.2.1 Overview of Technology 2.1-5 2.1.2.2 Capital Cost Procedures 2.1-6 2.1.2.3 Operating Cost Procedures 2.1-6 2.1.3 RDF Units 2.1-9 2.1.3.1 Overview of Technology 2.1-9 2.1.3.2 Capital Cost Procedures 2.1-11 2.1.3.3 Operating Cost Procedures 2.1-11 2.1.4 FBC Units 2.1-12 2.1.4.1 Overview of Technology 2.1-13 2.1.4.2 Capital Cost Procedures 2.1-13 2.1.4.3 Operating Cost Procedures 2.1-13 References 2.1-20 2.2 ELECTROSTATIC PRECIPITATORS 2.2-1 2.2.1 Overview of Technology 2.2-1 2.2.2 Capital Cost Procedures 2.2-1 2.2.2.1 Direct Costs 2.2-1 2.2.2.2 Indirect Costs and Other Costs 2.2-8 2.2.3 Operating Cost Procedures 2.2-12 References 2.2-14 iii ------- TABLE OF CONTENTS Secti on Page 2.3 DRV SORBENT INJECTION 2.3-1 2.3.1 Overview of Technology....- - 2.3-1 2.3.2 Capital Cost Procedures 2.3-2 2.3.3 Operating Cost Procedures 2.3-6 References 2.3-9 2.4 SPRAY DRYING WITH EFFICIENT PARTICULATE CONTROL 2.4-1 2.4.1 Overview of Technology 2.4-1 2.4.2 Capital Cost Procedures 2.4-1 2.4.2.1 Direct Costs 2.4-2 2.4.2.2 Indirect and Other Costs 2.4-5 2.4.3 Operating Cost Procedures 2.4-5 References 2.4-10 2.5 COMPLIANCE MONITORING 2.5-1 2.5.1 Overview of Technology 2.5-1 2.5.1.1 Continuous Opacity Monitoring 2.5-1 2.5.1.2 Continuous S02 Monitoring 2.5-1 2.5.1.3 Continuous HCt Monitoring 2.5-2 2.5.1.4 Diluent (O^/CO^ Monitoring) 2.5-3 2.5.2 Compliance Monitoring Costs 2.5-3 References 2.5-5 3.0 PROCEDURES FOR EXISTING PLANTS 3.1-1 3.1 OPERATION OF THE EXISTING COMBUSTORS 3.1-1 3.2 COMBUSTOR MODIFICATIONS 3.2-1 3.2.1 Introduction 3.2-1 3.2.2 Capital Cost Procedures 3.2-1 3.2.2.1 Stoker Rehabilitation 3.2-3 3.2.2.2 Refractory-Wall Furnace Reconfiguration 3.2-4 3.2.2.3 Fuel Feeding Modifications 3.2-4 3.2.2.4 Underfire Air Modifications 3.2-5 3.2.2.5 Overfire Air Modifications 3.2-7 3.2.2.5 Combustion Controls and Monitors 3.2-9 3.2.2.7 Auxiliary Fuel Burner Installation 3.2-10 iv ------- TABLE OF CONTENTS Section Page 3.2.2.8 Carbon Monoxide Profiling 3.2-11 3.2.2.9 Economizer for Flue Gas Temperature Control 3.2-11 3.2.3 Operating Cost Procedures 3.2-12 References 3.2-15 3.3 HUMIDIFICATION 3.3-1 3.3.1 Overview of Technology 3.3-1 3.3.2 Capital Cost Procedures 3.3-2 3.3.3 Operating Cost Procedures 3.3-3 References 3.3-6 3.4 PARTICULATE MATTER CONTROL RETROFIT 3.4-1 3.4.1 Installation of a New ESP 3.4-1 3.4.1.1 Capital Cost Procedures 3.4-1 3.4.1.2 Operating Cost Procedures 3.4-1 3.4.2 Increase in ESP Plate Area 3.4-2 3.4.2.1 Capital Cost Procedures 3.4-2 3.4.2.2 Operating Cost Procedures 3.4-2 3.4.3 ESP Rebuild 3.4-3 3.4.3.1 Capital Cost Procedures 3.4-3 3.4.3.2 Operating Cost Procedures 3.4-3 References 3.4-4 3.5 DRV SORBENT INJECTION RETROFIT 3.5-1 3.5.1 Overview of Technology 3.5-1 3.5.2 Capital Cost Procedures 3.5-1 3.5.3 Operating Cost Procedures 3.5-2 References 3.5-3 3.6 SPRAY DRYER RETROFIT 3.6-1 3.6.1 Overview of Technology 3.6-1 3.6.2 Capital Cost Procedures 3.6-1 3.6.3 Operating Cost Procedures 3.6-5 V ------- TABLE OF CONTENTS Section Page References 3.6-8 3.7 DETERMINATION OF RETROFIT FACTORS AND SCOPE ADDER COSTS 3.7-1 3.7.1 Retrofit Factors 3.7-1 3.7.2 Scope Adders 3.7-1 3.7.2.1 Ducting 3.7-1 3.7.2.2 Stacks 3.7-1 3.7.2.3 Demolition and Replacement 3.7-3 References 3.7-4 3.8 DOWNTIME COSTS FOR RETROFIT MODIFICATIONS 3.8-1 3.8.1 Procedures to Estimate Loss of Steam and Electricity Sales 3.8-1 3.8.1.1 Loss of Steam Sales 3.8-1 3.8.1.2 Loss of Electricity Sales 3.8-1 3.8.2 Procedures to Estimate Costs from Loss of Tipping Fees 3.8-3 References 3.8-4 Appendix A COST COMPARISON BETWEEN SPRAY DRYER/FABRIC FILTER AND SPRAY DRYER/ELECTROSTATIC PRECIPITATOR SYSTEMS A-l Appendix B DETAILED COST EQUATIONS B-l vi ------- LIST OF TABLES Tabl e Page 2.1-1 CAPITAL COSTS FOR MODULAR MWC's 2.1-3 2.1-2 CAPITAL COSTS FOR A 860 TON/DAY MASS BURN MWC WITH (WITHOUT) ELECTRICITY GENERATION 2.1-7 2.1-3 CAPITAL COSTS FOR A COARSE RDF FACILITY WITH ELECTRICITY GENERATION (CAPACITY = 850 TONS/DAY MSW, 800 TONS/DAY RDF) . 2.1-10 6.1-4 PROCEDURE FOR ESTIMATING CAPITAL COSTS FOR NEW FBC'S (DECEMBER 1987 DOLLARS) 2.1-14 2.1-5 ANNUAL OPERATING COST PROCEDURES FOR NEW FBC'S 2.1-15 2.1-6 PROCEDURE FOR ESTIMATING ANNUAL OPERATING COSTS FOR FBC'S (DECEMBER 1987 DOLLARS) 2.1-17 2.2-1 VENDOR QUOTES FOR ESP EQUIPMENT COSTS (IN 1000$ AUGUST 1986) 2.2-2 2.2-2 SPECIFIC COLLECTION AREA (SCA) REPORTED BY THE ESP MANUFACTURERS 2.2-5 2.2-3 AVERAGE SPECIFIC COLLECTION AREA (SCA) CALCULATED FROM THE MANUFACTURERS' DATA 2.2-6 2.2-4 COST PROCEDURES FOR ESTIMATING CAPITAL COSTS FOR ESP'S ON NEW PLANTS 2.2-11 2.2-5 COST PROCEDURES USED TO ESTIMATE ANNUAL OPERATING COSTS FOR ESP'S ON NEW UNITS 2.2-13 2.3-1 PROCEDURES FOR ESTIMATING CAPITAL COSTS FOR DRY SORBENT INJECTION 2.3-4 2.3-2 ANNUAL OPERATING COST PROCEDURES FOR DRY SORBENT INJECTION FOR NEW MWC's 2.3-7 2.3-3 ANNUAL OPERATING COST PROCEDURES FOR FABRIC FILTERS FOR NEW MWC's 2.3-8 2.4-1 VENDOR QUOTES FOR SPRAY DRYER/FABRIC FILTER TOTAL CAPITAL COSTS (IN 1,000$ AUGUST 1986) 2.4-3 2.4-2 CAPITAL COST PROCEDURES FOR SD/FF FOR NEW MWC's 2.4-6 vii ------- LIST OF TABLES Table Page 2.4-3 ANNUAL OPERATING COSTS PROCEDURES FOR SPRAY DRYER/FABRIC FILTER FOR NEW MWC's 2.4-7 2.5-1 CONTINUOUS MONITORING COST SUMMARY (DECEMBER 1987 DOLLARS) 2.5-4 3.2-1 O&M COST INPUTS (DECEMBER 1987 DOLLARS) 3.2-13 3.3-1 CAPITAL COST PROCEDURES FOR HUM IDIFI CAT I ON 3.3-4 3.3-2 OPERATING AND MAINTENANCE COSTS FOR HUM IDIFICATION 3.3-5 3.6-1 VENDOR QUOTES FOR SPRAY DRYER DIRECT CAPTIAL COSTS (in 1000$ August 1988) 3.6-2 3.6-2 CAPITAL COST PROCEDURES FOR SPRAY DRYERS 3.6-3 3.6-3 ANNUAL OPERATING COSTS PROCEDURES FOR STAND-ALONE SPRAY DRYERS FOR NEW MEW's 3.6-6 3.7-1 SITE ACCESS AND CONGESTION FACTORS FOR RETROFITTING APCD EQUIPMENT AT EXISTING PLANTS 3.7-2 3.8-1 DOWNTIME REQUIREMENTS IN MONTHS 3.8-2 viii ------- LIST OF FIGURES Figure Page 2.2-1 Correlation of ESP equipment costs (in August 1986 dollars) from ESP manufacturers and total plate area... 2.2-3 2.2-2 Relationship between ESP manufacturers' specific collection area and particulate matter removal 2.2-7 2.2-3 Correlation of ESP purchase equipment costs with total plate area for modular ESP's 2.2-9 2.2-4 Relationship between specific collection area and particulate matter removal for modular ESP's 2.2-10 2.4-1 Capital cost estimates of an SD/FF for a Model MB facility, and RDF facility 2.4-4 3.6-1 Correlation of SD direct capital costs (in August 1988 dollars) from the SD manufacturers and flue gas flowrate 3.6-4 ix ------- 1.0 INTRODUCTION This report documents the development of cost procedures for costing new and existing municipal waste combustor (MWC) facilities, associated heat recovery equipment, humidification equipment, air pollution control devices (APCD's) for the reduction of particulate matter (PM) and acid gas emissions, and continuous emission monitoring equipment. Costs presented in this report are divided into three major cost categories: Capital Costs; Operating and Maintenance (O&M) Costs; and Annualized Costs (total O&M cost plus capital - related annual charges). Each of these cost categories is further subdivided into individual cost elements. Capital cost elements include direct costs (purchase equipment and installation costs), indirect costs, and contingencies. Direct costs consist of the basic and auxiliary equipment, the labor and material required to install the equipment, plus site preparation and buildings costs. Indirect costs are those costs which are not attributable to specific equipment items such as engineering, construction and field expenses, contractor fees, and start-up and performance tests. Contingencies cover any unpredicted events and other unforeseen expenses that may arise. The O&M cost elements include direct and indirect costs. Direct O&M costs consist of operating and maintenance labor, fuel, utilities, materials and spare parts, supplies, waste disposal, and chemicals. These costs are dependent on the combustor capacity utilization. Indirect O&M costs, on the oiher hand, are totally independent of capacity utilization. These costs include plant and payroll overhead, real estate and local taxes, insurance, administrative charges, and replacement parts. 1-1 ------- Total annualized costs are the sum of the direct and indirect O&M costs and capital recovery costs. Capital recovery costs are determined by multiplying the total capital costs by the capital recovery factor, which is based on the assumed interest rate and economic equipment life. A 10 percent real interest rate and a 15-year equipment life are assumed for the combustors and control equipment in this report. This translates into a capital recovery factor of 13.15 percent. All costs are presented in December 1987 constant dollars. Chapter 2.0 of this report presents the costing procedures for new MWC plants. Included are procedures to estimate capital, operating and maintenance, and annualized costs for combustors, combustor-related equipment, flue gas temperature control, PM control using dry electrostatic precipitators (ESP's), acid gas control using either dry sorbent injection or spray dryers followed by a fabric filter for PM control, and continuous emission monitors (CEM's). Chapter 3.0 presents the costing procedures for existing MWC plants which include procedures used to estimate costs for operating existing combustors and for retrofitting emission controls. Emission controls evaluated include combustor modification, temperature control, PM control (rebuilding an existing ESP, adding plate area, or installing a new ESP), and acid gas controls using either dry sorbent injection or spray dryers with an existing ESP or a fabric filter for PM control. Appendix A compares the costs between spray dryer/fabric filter and spray dryer/electrostatic precipitator systems applied to new plants. The purpose of this comparison was to determine whether (1) the costs of these systems differ sufficiently to warrant separate costing procedures for each system and (2) a single procedure can be used. Appendix B presents the tables summarizing the cost procedures presented in this report. ------- COST COMPARISON BETWEEN SPRAY DRYER/FABRIC FILTERS (SO/FF) AND SPRAY DRYER/ELECTROSTATIC PRECIPITATOR (SD/ESP) SYSTEMS A.1 INTRODUCTION This appendix compares SD/FF and SD/ESP costs for two model mass-burn waterwall plants (a 250-tpd plant and a 3,000-tpd plant) at a PM outlet concentration of 0.01 gr/dscf. Costs presented in the appendix for SD/FF systems are based on cost procedures discussed in Section 2.4. Cost procedures presented in this appendix were used for SD/ESP. Lime requirements are based on a stoichiometric ratio of 1.5:1 for both systems. The objective of this comparison was to determine whether (1) the costs of these systems differ sufficiently to warrant separate costing procedures for each system and (2) a single procedure can be used. A.2 COST COMPARISON BETWEEN SD/ESP'S AND SD/FF Costs for SD/ESP's and SD/FF systems are estimated for two model mass-burn plants.1 Model plant 1 is a 250-tpd plant with two combustors, whereas model plant 3 is a 3,000-tpd plant with four combustors. These plants were selected to cover the size range of most MWC facilities. For both plants, the SD systems are assumed to achieve 90 percent HC1 and 70 percent SO^ removal and an outlet PM emissions of 0.01 gr/dscf at 12 percent C0ฃ. The following two sections discuss the approach taken in estimating costs for SD/ESP applied to these model plants and the results of the cost comparison. The costs for SD/FF systems are based on procedures presented in Section 2.4 at a stoichiometric ratio of 1.5:1. A.2.1 Approach Used to Estimate SD/ESP Costs Table A-l presents purchased equipment cost data for SD/ESP's provided by five manufacturers. The vendor quotations were based on design specifications for model mass-burn and refuse-derived fuel (RDF) plants. Because the costs in Table A-l contain significant scatter, the costs for vendors A and C were used to develop the capital cost procedure for SD/ESP's applied to mass-burn combustors. Both manufacturers are experienced in SD technology. Furthermore, the costs reported by both were consistent and generally were conservative compared to the other vendor's costs. Limited A-l ------- TABLE A-2. CAPITAL AND ANNUALIZED COSTS PROCEDURES FOR MASS BURN MWC'sa,b Capital Costs (dollars per ton/day of MSW processed) 1. Mass burn MWC without electrical generation: Unit Capital Costs - 50,420 (430/Size)0,39 2. Mass burn MWC with electrical generation: Unit Capital Costs = 60,700 (430/Size)0,39 3. Total Capital Costs = Unit Capital Cost * TPD Annualized Costs 1. Operating and Maintenance Costs excluding waste disposal: For mass burn refractory wall MWC, Costs = (15.7 - 0.00115 TPD) * Total Capital Costs/100 For mass burn waterwall MWC, Costs = (12.5 - 0.00115 TPD) * Total Capital Costs/100 r 2. Capital Recovery Costs - CRF * Total Capital Costs 3. Waste Disposal of Bottom Ash: Costs = 1_ * 10Qi~oW^ * tpd * HRS * WDC aCosts are estimated in December 1987 dollars. ^Size ป combustor MSW feed rate, tons/day TPD = plant MSW feed rate, tons/day HRS - hours of operation CRF - Capital recovery factor, 0.1315 based on 10 percent interest rate and 15-year economic 1ife WR = weight reduction MSW in the combustor percent WDC = waste disposal cost rate, dollars per ton (typically $25/ton) cApplies only to new plants. Capital recovery costs are not estimated for retrofit applications, since the capital costs are sunk. A-2 ------- cost data were available from vendor E at other outlet PM emission levels to substantiate the relative high equipment cost at 0.01 gr/dscf at 12 percent co2. Table A-2 presents the capital cost procedures for SD/ESP applied to mass-burn facilities only. A cost equation was developed relating purchased equipment costs in Table A-l at an outlet PM emission level of 0.01 gr/dscf at 12 percent CC.g with flue gas flowrate on a logarithmic basis. The resultant equipment cost equation updated to December 1987 dollars using the Chemical Engineering Plant Index is given below: Equipment Costs, 10^ $ = 5.896 Q0,535 where: Q - 125 percent of the actual flue gas flowrate, acfm. Both installation and indirect costs are 60 percent of the equipment costs. Assuming that the indirect costs are 33 percent of the direct costs, the direct cost equation for SD/ESP system shown in Table A-2 can be derived. Total direct cost equations for ductwork and the I.D. fan for SD/FF systems in Section 2.4 are used directly for SD/ESP systems. To be consistent with the SD/FF procedures in Section 2.4, costs for installation, indirect capital costs, and contingencies for SD/ESP are based on the same percentages used in the SD/FF procedures. Operating costs for SD/ESP were estimated using Table A-3. These operating costs are based on lower operating labor requirements (3 man-hours/ shift versus 4 man-hours/shift) and lower fan gas-side pressure drop requirements (5.5 inches versus 12.5 inches) than those for SD/FF. The gas-side pressure drop of 5.5 inches is based on a pressure drop of 5 inches across the SD and 0.5 inches across the ESP. Electricity costs are included for ESP energization. Additional costs are included for the SD/FF systems for bag replacement and compressed air. The same cost rates used to estimate SD/FF operating costs in Section 2.4 are used for estimating operating costs for SD/ESP systems in December 1987 dollars. A.2.2 Cost Comparison Results Tables A-4 and A-5 present costs for both SD/ESP and SD/FF systems applied to 250- and 3,000-tpd mass-burn plants, respectively. The capital A-3 ------- TABLE A-2. CAPITAL COST PROCEDURES FOR SD/ESP ON NEW MASS-BURN PLANTS Total Direct Costs (December 1987 dollars)3 Single SD/ESP Unit: Costs, 103S - 7.087 (Q)0'535 Ductwork: Costs, 103$ = 1.387 * L * Qฐ*S/1000 Fan: Costs, 103$ = 1.875 * Qฐ*96/1000 Multiple Units: Multiply the above costs by the number of units. Indirect Costs = 33% of total direct costs. Contingency - 20% of sum of direct and indirect costs. Total Capital Investment = Total Direct Costs + Indirect Costs + Contingency Costs. aQ ซ 125 percent of the actual flue gas flowrate, acfm L - Duct length, feet Cost procedures assume that-the total installed costs are 133 percent of the total direct capital costs. A-4 ------- TABLE A-3. ANNUAL OPERATING COSTS PROCEDURES FOR SD/ESP ON NEW MASS-BURN PLANTS Reference Operating Labor: 3 man-hours/shift; $12/man-hour 3, 4 Supervision: 15% of operation labor costs 4 Maintenance: Labor -- 2 man-hour/shift 3, 4 10% wage rate premium over operating labor wage Materials -- 2% of direct capital costs 3 Electricity: Electricity costs - $0.046/kwh ? ESP Energization -- 1.5 watts/ft plate area 5 Fan -- 5.5 inches of water pressure drop 6, 7 Atomizer Auxiliary Equipment -- 8 Kw ฆ= 6kw per 1,000 lbs/hr of slurry feed + 15kw Pump -- 20 feet of pumping height 9 10 psi discharge pressure 10 ft/sec velocity in pipe Water: Based on water flowrate required for 10 cooling flue gas to 300 F and water cost rate of $0.50/1000 gal Lime: Based on lime feed rate to the spray 11 dryer calculated by assuming a stoichiometric ratio of 1.5:1. Apply appropriate lime costs in $/ton ($70/ton) Solid Waste: Calculate solid waste disposal rate 12 collected by the ESP and the spray dryer and apply appropriate tipping fee in $/ton. (Assume $25/ton) A-5 ------- TABLE A-3. ANNUAL OPERATING COSTS PROCEDURES FOR SD/ESP ON NEW MASS-BURN PLANTS (Continued) Reference Overhead: 60% of the sum of all labor 13 costs (operating, supervisory, and maintenance) plus materials Taxes, Insurance, and Administrative Charges: 4% of total 13 capital costs Capital Recovery: 15-year life and 10% 14 interest rate A-6 ------- TABLE A-4. COSTS FOR SO/ESP'S AND SD/FF'S FOR A 250-TPD MASS-BURN PLANT Model Plant No. 1 250 tpd Mass-Burn Facility with 2 Combustors Outlet PM Emissions = 0.01 gr/dscf SD/FF SD/ESP Capital Cost fl.OOO $) Total Direct 3,270 3,730 Total Indirect 1,080 1,230 Contingency 870 993 Total Capital Costs 5,220 5,960 Operating Costs (1,000$) Direct Costs: Operating Labor 96 72 Supervision 14 11 Maintenance Labor 53 40 Materials 65 75 Electricity 62 51 Water 1 1 Lime 50 50 Waste Disposal 81 81 Bag Replacements 15 0 Compressed Air 8 0 Indirect Costs: Overhead 137 119 Taxes, Insurance. & Administration 209 238 Total Operating Costs 791 738 Annualized Costs Capital Recovery 687 783 Total Annualized Costs 1,480 1,520 aCosts are 1n December 1987 dollars. ------- TABLE A-5. COSTS FOR SD/ESP'S AND SD/FF'S FOR A 3,000-TPD MASS-BURN PLANT Model Plant No. 3 3,000 tpd Mass-Burn Facility with 4 Combustors Outlet PM emissions =ฆ 0.01 gr/dscf SD/FF SD/ESP Capital Cost (1,000 $) Total Direct Total Indirect Contingency Total Capital Costs 17,340 20,260 5,720 6,690 4.610 5.390 27,600 32,300 Operating Costs (1.000 S) Direct Costs: Operating Labor 192 144 Supervision 29 22 Maintenance Labor 106 106 Materials 347 405 Electricity 629 504 Water 12 12 Lime 594 594 Waste Disposal 975 975 Bag Replacements 184 0 Compressed Air 98 0 Indirect Costs: Overhead 404 406 Taxes. Insurance. & Administration 1.110 1.290 Total Operating Costs 4,680 4,460 Annualized Costs Capital Recovery 3.640 4.250 Total Annualized Costs 8,320 8,710 aCosts are in December 1987 dollars. A-8 ------- c.osts for SD/ESP systems are higher than those for SD/FF systems for both plants. This is because ESP capital costs are more sensitive to PM removal requirements than those for FF's. At the removal efficiencies required to achieve an outlet loading of 0.01 gr/dscf, the capital costs for a SD/ESP are roughly 15 percent higher than for a SD/FF. Tables A-4 and A-5 show that operating costs for SD/ESP and SD/FF systems are essentially the same. For both plants, capital-related operating costs are greater for an SD/ESP than for an SD/FF. The noncapital-related costs for an SD/ESP are lower. The magnitude of these cost differences are roughly equal, resulting in about the same operating costs for both SD systems. Because of lower capital costs, annualized costs for SD/FF systems are roughly 4 percent less than SD/ESP systems for both model plants. The results from this cost comparison, which showed the annualized costs for both systems are similar, agreed with those presented in another cost study prepared for the State of New York.^ A-9 ------- REFERENCES 1. U. S. Environmental Protection Agency. Municipal Waste Combustion Study: Costs of Flue Gas Cleaning Technologies, Research Triangle Park, NC. Publication No. EPA/530-SW-87-021e. June 1987. pp. 2-1 to 2-3. 2. Bowen, M.L. and M.S. Jennings (Radian Corporation). Cost of Sulfur Dioxide, Particulate Matter, and Nitrogen Oxide Controls in Fossil Fuel Fired Industrial Boilers. Prepared for the U. S. Environmental Protection Agency. Research Triangle Park, NC. Publication No. EPA-450/3-82-021. August 1982. p. 2-11. 3. Memorandum from Aul, E.F. et al., Radian Corporation, to Sedman, C.B., EPA. May 16, 1983. 30 p. Revised Cost Algorithms for Lime Spray Drying and Dual Alkali F6D Systems. 4. Vatavuk, W.M., and R.B. Neveril, Estimating Costs of Air Pollution Control Systems, Part II: Factors for Estimating Capital and Operating Costs, Chemical Engineering. November 3, 1980. pp. 157 to 162. 5. Neveril, R. B. (GARD, Inc.) Capital and Operating Costs of Selected Air Pollution Control Systems. Prepared for the U. S. Environmental Protection Agency. Research Triangle Park, NC. Publication No. EPA-750/5-80-002. p. 3-18. 6. U. S. Environmental Protection Agency. EAB Control Cost Manual. Research Triangle Park, NC. Publication No. EPA-450/5-87-001A. February 1987. p. 6-39. 7. Letter and attachment from Fiesinger, T., New York State Energy Research and Development Authority, to Johnston, M., EPA. January 27, 1987. Draft report on the economics of various pollution control alternatives for refuse-to-energy plants, p. 6-9. 8. Reference 7, p. 6-10. 9. Dickerman, J.C. and K. L. Johnson. (Radian Corporation) Technology Assessment Report for Industrial Boiler Applications: Flue Gas Desulfurlzation. Prepared for the U. S. Environmental Protection Agency. Washington, DC. Publication No. EPA-600/7-79-178i. November 1979. pp. 5-5 and 5-17. 10. Letter from Solt, J.C., Solar Turbines Incorporated, to Noble, E., EPA. October 19, 1984. Development cost for wet control for stationary gas turbines. 11. Chemical Marketing Reporter. Volume 233. Number 1. January 4, 1988. 12. Reference 6, p. 2-29. A-10 ------- 13. Reference 6, 14. Reference 2, 15. Reference 7, p. 2-31. pp. 2-17 and 2-18. pp. 6-1 to 6-17. A-ll ------- TABLE B-1. CAPITAL AND ANNUALIZED COST PROCEDURES FOR MODULAR MWC'sa'b Capital Costs 1. Modular MWC without heat recovery: Unit Capital Cost = $24,300 per ton/day of MSW processed 2. Modular MWC producing steam (without generating electricity): Unit Capital Cost = $32,500 per ton/day of MSW processed 3. Modular MWC generating electricity: Unit Capital Cost = $54,600 per ton/day of MSW processed 4. Total Capital Costs = Unit Capital Costs * TPD Annualized Costs^ 1. Operating and Maintenance Costs excluding waste disposal: For TPD < 150 and HRS < 6,000, Costs - (10 - 0.23 TPD + 0.006 HRS) * Total Capital Costs/100 Otherwise, Costs = (15.7 - 0.00115 TPD) * Total Capital Costs/100 2. Capital Recovery0: Costs ซ CRF * Total Capital Costs 3. Waste Disposal of Bottom Ash: Costs - i_ .(ioo^Wr) * TpD * HRS * WDC aCosts are estimated in December 1987 dollars. bTPD = plant MSW feed rate, tons/day HRS = hours of operation CRF - capital recovery factor, 0.1315 based on 10 percent interest rate and 15-year economic life WR ซ weight reduction of MSW in the combustor, percent WDC - waste disposal cost rate, dollars per ton (typically $25/ton) cApplies only to new plants. Capital recovery costs are not estimated for retrofit applications since the capital costs are sunk. B-l ------- TABLE B-2. CAPITAL AND ANNUALIZED COSTS PROCEDURES FOR MASS-BURN MWC'sa,b Capital Costs (dollars per ton/dav of NSW processed) 1. Mass-burn MWC without electrical generation: Unit Capital Costs = 50,420 (430/Size)0'39 2. Mass-burn MWC with electrical generation: Unit Capital Costs = 60,700 (430/Size)^"39 3. Total Capital Costs - Unit Capital Cost * TPD Annualized Costs 1. Operating and Maintenance Costs excluding waste disposal: For mass-burn refractory wall MWC, Costs = (15.7 - 0.00115 TPD) * Total Capital Costs/100 For mass-burn waterwall MWC, Costs - (12.5 - 0.00115 TPD) * Total Capital Costs/100 2. Capital Recovery0 Costs = CRF * Total Capital Costs 3. Waste Disposal of Bottom Ash: Costs = i_ * 100 "nWR * TPD * HRS * WDC 24 100 aCosts are estimated in December 1987 dollars. ^Size - combustor MSW feed rate, tons/day TPD = plant MSW feed rate, tons/day HRS ป hours of operation CRF = Capital recovery factor, 0.1315 based on 10 percent interest rate and 15-year economic 1ife WR = weight reduction MSW in the combustor percent WDC - waste disposal cost rate, dollars per ton (typically $25/ton) cApplies only to new plants. Capital recovery costs are not estimated for retrofit applications, since the capital costs are sunk. B-2 ------- TABLE B-3. CAPITAL AND ANNUALIZED COST PROCEDURES FOR RDF FACILITIES3'5 Capital Costs (dollars per ton/dav of RDF processed) 1. Coarse RD facility: Unit Capital Costs - 73,600 (400/Size)1^'^ 2. F1uff RDF faci1ity: Unit Capital Costs = 161,880 (315/Size)0-39 3. Total Capital Costs = Unit Capital Costs * TPD Annualized Costsc 1. Operating and Maintenance Costs excluding waste disposal: Costs - (12.5 - 0.00115 TPD) * Total Capital Costs/100 2. Capital Recovery0: Costs = CRF * Total Capital Costs 3. Waste Disposal of Bottom Ash: Costs = i_ * ^ฐฐ1'qWR^* TPD * HRS * WDC aCosts are estimated in December 1987 dollars. ^Size = combustor RDF feed rate, tons/day TPD ซ plant MSW feed rate, tons/day CRF = capital recovery factor, 0.1315 based on 10 percent interest rate and 15-year economic 1ife WR ป weight reduction of MSW in the combustor, percent HRS = hours of operation WDC - waste disposal cost rate, dollars per ton (typically 525/ton) cApplies only to new plants. Capital recovery costs are not estimated for retrofit applications since the capital costs are sunk. B-3 ------- TABLE B-4. PROCEDURE FOR ESTIMATING CAPITAL COSTS FOR NEW FBC'S (December 1987 dollars) Total Direct and Indirect Costs:a Costs, 103$ - 64,900 * TPD * (900/TPD)0'39 Process Contingency: 20% of total direct and indirect costs Total Capital FBC Costs: Total direct and indirect costs + process conti ngency aTPD = plant municipal waste feed rate, tons/day. B-4 ------- TABLE B-5. PROCEDURE FOR ESTIMATING ANNUAL OPERATING COSTS FOR FBC'S (December 1987 dollars) Combustor and Balance of Plant (excludes coarse RDF processing area): Operating labor (based on 10 man-years. 40 hours/week. S12/hrV: OL - 10 * 40 * 52 * 12 * (TPD/900) - 277.3 * TPD Supervision (based on 3 man-years/year. 40 hours/week. 30% wage rate premium over the operating labor wage): SPRV = 3 * 40 * 52 * 12 * 1.3 * (TPD/900) = 108.2 * TPD Maintenance labor (based on 3 man-years/year, 40 hours/week. 10% wage rate premium over the operating labor wage): ML - 3 * 40 * 52 * 12 * 1.1 * (TPD/900) = 91.5 * TPD Maintenance materials: 3% of the total capital costs Electricity (based on 3 MW power consumption, and electricity rate of S0.046/kwh): ELEC = 0.153 * TPD * HRS Limestone (based on S40/ton for limestone): LIMESTONE - 0.02 * LFEED * HRS * N Water (based on 3% blowdown rate and SO.05/1.000 gal): WC - 1.86 x 10"6 * STM * HRS Waste disposal (based on tipping fee of S25/hr): AD - 1.25 x 10"2 * N * HRS * WDR Overhead: 60% of the sum of all labor costs (operating, supervisory, and maintenance) plus 60% of maintenance materials costs Continued B-5 ------- TABLE B-5. (CONCLUDED). PROCEDURE FOR ESTIMATING ANNUAL OPERATING COSTS FOR FBC'S (December 1987 dollars) Coarse RDF Processing Area: Total Operating and Maintenance Costs (TOT O&M); TOT O&M = 4.4 x 10"4 * (12.5 - 0.00115 * TPD) * TDI Taxes. Insurance, and Administrative Charges: 4% of the total capital cost Capital Recovery (based on 15 year life and 10% interest rate): 13.15% of the total capital cost aOL * operating labor costs, $/yr SPRV =ฆ supervision costs, $/yr ML = maintenance labor costs, S/yr ELEC = electricity costs, $/yr HRS - hours of operation per year LIMESTONE - limestone costs, $/yr LFEED = limestone feed rate per unit, Ib/hr N = number of combustors WC ฆ water costs, $/yr STM = plant steam production, lb/hr AD = waste disposal costs, $/yr WDR = waste disposal rate per unit (bottom and fly ash collected), lb/hr TPD = plant municipal waste feed rate, tons/day TDI = total direct and indirect capital costs for FBC plant, $ B-6 ------- TABLE B-6. PROCEDURES FOR ESTIMATING CAPITAL. COSTS FOR ELECTROSTATIC PRECIPITATORS (ESP'S)a,D Design Equation for Mass-burn and RDF Facilities: SCA = -189.29 In H00 - PMEFF) 101.89 Design Equation for Modular Units: o Use above design equation for large modular units whose flue gas flowrate (Q) is greater than or equal to 30,000 acfm o For small modular units whose Q < 30,000 SCA = -285.7 In (100 - PMEFF) 79.6 Purchased Eouipment Costs ESP for Massburn and RDF plants and large modular plants0: Costs, 10J $ - (305.2 + 0.00738 * TPA) * RF * N ESP for small modular plants (Q < 30,000)c: Costs, 10J $ = 1.08 * (96.3 + 0.015 * TPA) RF * N ESP Rebuilds: , Costs, 10 $ = 0.42 * purchased equipment costs for a new ESP (RF - 1) Ductwork: 7 n c Costs, 10"1 $ - 0.7964 * N * RF * Q Costs, 103 $ = 1.077 * N * RF * Q0,96 Installation Direct Costs = 67% of purchased equipment costs for new ESP and ESP upgrades (i.e., addition of new plate area in existing ESP) = 33% of purchased equipment costs for ESP rebuilds only (conti nued) B-7 ------- TABLE B-6. (Continued) Indirect Costs - 54% of purchased equipment costs for mass-burn, RDF, and large modular units with new ESP and ESP upgrades = $14,000 for small modular units with new ESP and ESP upgrades = 24% of the purchased equipment costs for ESP rebuilds Contingency = 3% of purchased equipment costs Total Capital Costs * Purchased equipment costs + installation direct costs + indirect costs + contingency costs aCosts are estimated in December 1987 dollars. kpMEFF =ป particulate matter removal efficiency, percent SCA - specific collection area, ft /I,000 acfm Q = 125 percent of the actual flue gas flowrate per ESP unit, acfm TPA = total plate area, ft RF - retrofit factor obtained from Table B-16 N - number of ESP units L ซ duct length, feet cIncludes taxes and freight of eight percent of the ESP equipment costs. For retrofit applications requiring additional plate area of the existing ESP, TPA is the increase in the plate area. B-8 ------- TABLE B-7. PROCEDURE FOR ESTIHATING ANNUAL OPERATING COSTS FOR ESP'sa,b Operating Labor0 (Based on 1 manhour/shift. labor wage of >12/hr): OL = 1.5 * N * HRS Supervision0; 15X of the operating labor cost (OL) Maintenance Labor0 (Based on 0.5 manhour/shift. 10% wage rate premium over the operating labor wage): ML = 0.825 * N * HRS Maintenance Materials: 1X of the direct capital costs'* Electricity for 1.0. fan (Based on 0.5 inch pressure drop W.C. and electricity rate of t0.046/l(wh): FANELEC = 4.50 * tO ' * FLW * N HRS 2 _ n Electricity Consumed by ESP (Based on 1.5 watts/ft collection area and electricity rate of to.046/kwh): ESPELEC = 6.9 x 10 TPA * N * HRS Ash Disposal (Based on tipping fee of t25/ton): AD = 1.25 x 10 ^ * N * HRS * UDR Overhead: 60X of the sum of all labor costs (operating, supervisory, and maintenance) plus 60X of maintenance materials costs CO i vC Taxes. Insurance, and Administrative Charges: 4X of the total capital costs Capital Recovery (Based on 15 year life and 10X interest rate): 13.15X of the total capital costs ft For ESP rebuilds, the only annual costs are for an increase in waste disposal and capital recovery. All costs are estimated in December 1987 dollars. OL = operating labor costs, S/yr N = number of ESP units HRS = hours of operation ML = maintenance labor costs, S/yr FANELEC = electricity costs for 1.0. fan, S/yr ESPELEC = electricity costs for ESP, S/yr FLU = actual flue gas flourate per unit, acfm AD = ash disposal costs, S/yr UDR = waste disposal rate per unit, Ib/hr ฐLabor costs are estimated only for neu ESP's. The labor costs for ESP retrofits (including upgrades and rebuilds) are zero. ^Direct capital costs are the sum of purchase equipment costs and installation direct costs. ------- TABLE B-8. PROCEDURES FOR ESTIMATING CAPITAL COSTS FOR DRY SORBENT INJECTIONa,b Purchased Equipment Costs. 103 t Lime Storage Silo with Vibrator. Baghouse. and Flow Control Value (Based on 15-dav lime supply) torage volumes (V) less than or equt Costs = 1.05 (34.2 ~ 0.016V) RF torage volumes between 2,300 and 4,t Costs = 2.10 * (34.2 ~ 0.016V) RF o For storage volumes (V) less than or equal to 2,300 ft3 (one storage silo per plant). For storage volumes between 2,300 and 4,600 ft' (two storage silos per plant). o For storage volume greater than 4,600 ft3 (two storage silos per plant), Costs i 2.10 * (63 ~ 0.0038V) RF 2. Feed Bins o For duct sorbent injection (one feed bin per combustor), Costs = 0.0906 N RF (SF)0-6145 o For furnace sorbent injection (two feed bins per combustor), ^ Costs = 0.1812 * N RF (SF)0-6145 C 3. Gravimetric Feeders o For duct sorbent injection (one feeder per combustor), Costs = 1.024 (0.000289 SF ~ 9.293) * N RF o For furnace sorbent injection (two feeders per combustor). Costs = 2.048 (0.000289 SF ~ 9.293) N RF 4. Pneumatic Conveyor (Based on 400 Feet Length) Costs = 1.05 * (26.4 ~ 0.0073 SF ~ 0.4 [12.8 ~ 11.23 SF0-23]) N RF 5. Injection Ports o For duct sorbent injection (one injection port per combustor). Costs = 1.05 (22.2 ~ 0.0014 SF) * N * RF o For furnace sorbent injection (two injection ports per combustor). Costs = 2.10 * (22.2 ~ 0.0014 SF) * N * RF (cont i nued) ------- TABLE B-8. (Continued) 6. Reactor Vessel (optional for duct sorbent injection to increase flue gas and sorbent contact): Costs = 34 * (0 * 1.25/6,150)""'^ c 7. Fabric Filter Costs = 0.1482 * N RF q0-7043 8. Induced Draft Fan Costs = (1.167 * N * RF 0096)/1,000 9. Ductwork Costs = (0.8627 N * RF * L * Qฐ"5)/1,000 Installation Direct Costs = 30X of dry sorbent injection equipment costs ~ 72X of fabric filter and auxiliary equipment costs Indirect Costs = 33X of direct costs (equipment ~ installation costs) for dry sorbent injection ~ 42X of equipment cost for the fabric filter and auxiliary equipment Cont ingency = 50X of the sum of direct and indirect costs Total Capital Costs = Total Direct Costs + Indirect Costs + Contingency Costs sAll costs are estimated in December 1987 dollars. SF = lime feed rate per unit, Ib/hr Q = 125 percent of the actual flue gas flourat^ to the fabric filter per unit, acfm V = lime storage silo volume for the plant, ft N = number of units RF = Retrofit factor. For retrofit applications, use retrofit factor of 1.1 for sorbent injection equipment. Retrofit factors for fabric filter and auxiliary equipment are obtained from Table B-16. L = duct length, feet cFabric filters are used for new applications and for retrofit applications uhere no ESP exists. For plants uith existing ESP's, costs for upgrading the ESP are estimated from Table B-6. ------- TABLE B-9. PROCEDURES FOR ESTIMATING ANNUAL OPERATING COSTS FOR DRY SORBENT INJECTION3,6 Operating Labor (Based on 2 manhours/shift. wage of >12/hr): CL = 5.0 * M 1 HRS Supervision: 15X of the operating labor cost (OL) Maintenance Labor: (Based on 0.5 manhour/shift. IPX wage rate premium over the operating labor wage): ML = 0.825 * N * HRS Maintenance Materials: 5X of the direct capital costs of the sorbent injection equipment0 Electricity (Based on electricity rate of >0.046/ltwh): ELEC = 5.25 * 10 ' ' (251,850 ~ 52.56 * SF) * N HRS Lime: (Based on >80/ton for hydrated lime and acid gas stoichiometric ratio of 2:1): LIME = 0.04 * SF * N * HRS CD I > 1 Overhead: 60X of the sum of all labor costs (operating, supervisory, and maintenance) plus 6PX of maintenance materials costs Taxes. Insurance, and Administrative Charges: 4% of the total capital costs Capital Recovery (Based on 15 year life and IPX interest rate): 13.15X of the total capital costs aAll costs are estimated in December 1987 dollars. ^OL = operating labor costs, S/yr N = number of units HRS = hours of operation ML = maintenance labor costs, $/yr ELEC = dry sorbent injection electricity costs, $/yr SF = lime feed rate per unit, Ib/hr LIME = lime costs, $/yr CDirect capital costs are the sum of purchase equipment costs and installation direct costs. ------- TABLE B-10. PROCEDURES FOR ESTIMATING ANNUAL OPERATING COSTS FOR FABRIC FILTERS3,5 Operating Labor (Based on 2 manhours/shift. wage of S12/hr): OL =3.0 * N * HRS Supervi si on: 15X of the operating labor cost (OL) Maintenance Labor: (Based on 1 manhour/shift. IPX wage rate premium over the operating labor wage): ML = 1.65 * N * HRS Q Maintenance Materials: 5X of the direct capital costs of both the fabric filter and auxiliary equipment 2 Bag Replacement: (Based on >1.35/ft . gross air-to-cloth ratio of 3:1. 2 year bag life, and 10X interest rate): BAG = 0.2593 * 0 * N -L Electricity (Based on 12.5 inches U.C. pressure drop and electricity rate of >0.046/lcwh): ELEC = 1.12 x 10 FLU N * HRS Compressed Air (Based on 2 scfm of air/1.000 acfm flue gas and $0.17/1.000 scfm for compressed air): AIR = 2.01 x 10 * FLU * N * HRS cn Ash Disposal (Based on tipping fee of >25/ton): AD = 1.25 x 10 ^ ' N ' HRS * UDR ปป CO Overhead: 60X of the sum of all labor costs (operating, supervisory, and maintenance) plus 60X of maintenance materials costs Taxes. Insurance, and Administrative Charges: 4X of the total capital costs Capitol Recovery (Based on 15 year life and 10X interest rate): 13.15X of the total capital costs aAll costs are estimated in December 1987 dollars. ^OL = operating labor costs, $/yr N = number of units HRS = hours of operation ML = maintenance labor costs, S/yr BAG = bag replacement costs, S/yr 0 = 125 percent of the inlet flue gas flowrate per unit, acfm FLU = actual flue gas flowrate per unit, acfm ELEC = electricity costs, $/yr AIR = compressed air costs, $/yr UDR = ash disposal rate from fabric filter per unit, Ib/hr cDirect capital costs are the sum of the purchase equipment costs and installation direct costs. ------- TABLE B-ll. PROCEDURES FOR ESTIMATING CAPITAL COSTS OF STANDALONE SPRAY DRYER AND SPRAY DRYER/FABRIC FILTERS ' Direct Costs SD/FF Unitc: Costs, 103 $ - 8.053 * N * RF * (Q)0'517 Stand-Alone SD Unit: Costs, 103 $ = 8.428 * N * RF * (Q)0'460 Ductwork0: Costs, 103 $ = (1.3868 * N * RF * L * Qฐ-5)/l,000 FanC: Costs, 103 $ - (1.8754 * N * RF * Qฐ'96)/1,000 Indirect Costs = 33% of direct costs Contingency = 20% of sum of direct and indirect costs Total Capital Investment = Direct Costs + Indirect Costs + Contingency Costs aAll costs are estimated in December 1987 dollars. bQ = 125% of the actual flue gas flowrate, acfm N = number of units RF = retrofit factor obtained from Table B-16 L = Duct length per unit, feet cThe total installed costs are assumed to be 133 percent of the direct capital costs. B-14 ------- TABLE B-12. PROCEDURE FOR ESTIMATING ANNUAL OPERATING COSTS FOR STAND-ALONE SPRAY DRYERS AND SPRAY DRYER/FABRIC FILTERS ' Operating Labor for SD/FF (Based on 4 manhours/shift. labor wage of $12/hr): OL = 6.0 * N * HRS Operating Labor for SD (Based on 2 manhours/shift. labor wage of H2/hr): OL = 3.0 * N HRS Supervision: 15X of the operating labor cost (OL) Haintenance Labor for SD/FF: (Based on 2 manhcurs/shift. IPX wage rate premium over the operating labor wage): ML = 3.3 N * HRS Maintenance Labor for SD: (Based on 1 manhour/shift. 10X wage rate premium over the operating labor wage): ML = 1.7 N * HRS Haintenance Materials: 2X of the total direct capital costs Bag Replacement for SD/FF: (Based on t1.35/ft^. gross air-to-cloth ratio of 3:1. 2 year bag life, and 10X interest rate): BAG = 0.2593 0 * N > - L Electricity for I.D. Fan for SD/FF (Based on 12.5 inches W.C. pressure drop and electricity rate of t0.046/kwh): FANELEC = 1.12 x 10 FLW * N * HRS Electricity for I.D. Fan for SD (Based on 5.5 inches W.C. pressure drop and electricity rate of >0.0&6/kwh): FANELEC = 4.93 * 10 ^ * FLW N * HRS Electricity for Atomizer (Based on 6 ku per 1,000 Ib/hr of slurry feed + 15 kw and electricity rate of $0.046/kwh): ATELEC = 0.046 * (0.006 (SF ~ WTR) ~ 15) N HRS Electricity for Pump (Based on 20 feet of pumping height, , 10 psi discharge pressure. 10 ft/sec velocity in piping): PUMPELEC = 1.291 X 10 (SF ~ WTR) * N * HRS Compressed Air for SD/FF (Based on 2 scfm of air/1.000 acfm flue gas and >0.17/1.000 scfm for compressed air): AIR = 2.01 x 10 FLW N * HRS Water: (Based on Flue gas cooling to 300ฐF and $0.50/1.000 gal): WC = 6.00 x 10 ' * WTR * N * HRS Lime: (Based on $70/ton for quick lime): LIME = 0.035 * SF * N * HRS ------- TABLE B-12. (Continued) Ash Disposal for SD/FF (Based on tipping fee of t25/ton): AO = 1.25 x 10 * N * HRS * UOR Overhead: 60X of the sum of all labor costs (operating, supervisory, and maintenance) plus 60X of maintenance materials costs Taxes. Insurance, and Administrative Charges: AX of the total capital costs Capital Recovery (Based on 15 year life and IPX interest rate): 13.15X of the total capital costs aAll costs are estimated in December 1987 dollars. OL = operating labor costs, 4/yr N = number of units HRS = hours of operation HL = maintenance labor costs, S/yr BAG = bag replacement costs, S/yr Q = 125 percent of the actual flue gas flowrate to the fabric filter per unit, acfm FLU = actual flue gas flowrate to the fabric filter per unit, acfm SF = lime feed rate per unit, Ib/hr UTR = water rate per unit, Ib/hr FANELEC = electricity costs for the fan, $/yr ATELEC = electricity costs for the atomizer, i/yr PUHPELEC = electricity costs for the the pumps, $/yr AIR = compressed air costs, S/yr UC = water costs, S/yr LI HE = Iime costs, $/yr AO = ash disposal costs, t/yr UOR = waste disposal rate, Ib/hr ------- TABLE B-13. PROCEDURES FOR ESTIMATING CAPITAL COSTS FOR HUMIDIFICATIONa,b Purchased Equipment Costs, 103 $ 1. Humidification Chamber and Pumps: Costs = (0.438 * Q + 80,220) N * RF/1,000 2. Ductwork: Costs = (1.16 * L * Qฐ"5) * N * RF/1,000 Installation Direct Costs = 56% of Purchase Equipment Costs Indirect Costs = 32% of Purchase Equipment Costs Contingency = 3% of the Purchase Equipment Costs Total Capital Costs = Purchased Equipment Costs + Installation Direct Costs + Indirect Costs = 191% of Purchase Equipment Costs aAll costs are estimated in December 1987 dollars. = 125% of the actual flue gas flowrate, acfm L = duct length per unit, feet N = number of units RF = retrofit factor obtained from Table B-16 B -17 ------- TABLE B-14. PROCEDURE FOR ESTIMATING ANNUAL OPERATING COSTS FOR HUMIDIFICAT IONa *b Operating Labor (Based on 0.5 manhours/shift. labor wage of SIZ/hr); OL = 0.75 * N * HRS Suoervi sion: 15X of the operating labor cost (OL) Maintenance Labor: (Based on 0.5 manhour/shift. 10X wage premium over the operating labor wage): ML = 0.825 N * HRS Maintenance Materials: IX of the total capital cosVs Electricity for Pumpsc (Based on 20 feet of pumping height, 100 psi discharge . pressure. 10 ft/sec velocity in piping, and electrical rate of t0.046/kwh): ELEC = 7.3 X 10 N * HRS * UTR Mater (Based on SO.50/1.000 gal)C: UC = 6.0 x 10'5 * UTR * N * HRS Overhead: 60X of the sum of all labor costs (operating, supervisory, and maintenance) plus 60X of maintenance materials costs Taxes. Insurance, and Administrative Charges: 4X of the total capital costs Capital Recovery (Based on 15 year life and IPX interest rate): 13.15% of the total capital costs aA11 costs are estimated in December 1987 dollars. b0L = operating labor costs, $/yr N = number of units HRS = hours of operation ML = maintenance labor costs, S/yr UTR = water injection rate, Ib/hr ELEC = electricity costs, J/yr UC = water costs, S/yr CUTR = (Tin-Tout) * Os * (1-M01ST/100)/940 where Tin = inlet flue gas temperature, F Tout = outlet flue gas temperature, F Os = flue gas flow rate per unit, scfm MOIST = moisture content in flue gas, volume percent ------- TABLE B-15. CONTINUOUS MONITORING COST SUMMARY3 Pol 1utant compli ance options Method Capital costs ($1,000) Operating costs ($1,000/yr) Annuali zed costs ($1,000/yr) 61 8 16 67 10 19 140 74 92 19 15 18 31 4 8 256 103 137 61 8 16 67 10 19 140 74 92 19 15 18 286 107 145 PM only Opacity'5 Acid gas only SO- (inlet and outlet) HCt (inlet and outlet) o2/co Data Reduction System Total PM + acid gas Opacity13 SO? (inlet and outlet) HCt (inlet and outlet) e2ZCo2 Total aAll costs are reported in December 1987 dollars. For multiple control units, multiply these costs by the number of units. ^Includes costs for automatic data reduction system. cBased on 2 certifications/year and maintenance requirements of 0.5 man-hour/day for both opacity and 0-/C0- monitors and 1 man-hour/day for S05 and HC1 monitors. J t Annualized costs include annual operating costs and capital charges on equipment and installation costs. Capital charges are based on a 15-year equipment life at 10 percent interest rate. B-19 ------- TABLE B-16. SITE ACCESS AND CONGESTION FACTORS FOR RETROFITTING APCD EQUIPMENT AT EXISTING PLANTS Retrofit factor Congestion level Guidelines for selecting retrofit factor 1.02 Base case Interferences similar to a new plant with adequate crew work space. Free access for cranes. Area around combustor and stack adequate for standard layout of equipment. 1.08 Low Some aboveground interferences and work space limitations. Access for cranes limited to two sides. Equipment cannot be laid out in standard design. Some equipment must be elevated or located remotely. 1.25 Medium Limited space. Interference with existing structures or equipment which cannot be relocated. Special designs are necessary. Crane access limited to one side. Majority of equipment elevated or remotely located. 1.42 High Severely limited space and access. Crowded working conditions. Access for cranes blocked from all sides. B-20 ------- TABLE B-17. PROCEDURE FOR ESTIMATING SCOPE ADDER CAPITAL COSTS3'b Direct and Indirect Costs 1. New Ducting: Costs, 103 $ = 1.844 * L * N * RF * Q0,5 2. New I.D. Fan: Costs, 103 S ป 2.493 * N * RF * Q0"96 3. New Stacks (costs per stack): o For a lined acid resistant stack, Costs, 103 $ - [26.2 + 0.089 * H * (1 + 4.14 * D)] for D > 5 Costs, 103 $ = [26.2 + 0.080 * H * (1 + 4.33 * D)] for D < 5 o For a unlined stack, Costs, 103 5 ซ [26.2 + 0.0625 * H * (1 + 2.59 * D)] for D > 5 Costs, 103 $ - [26.2 + 0.087 * H * (1 + 2.2 * D)] for D < 5 Continaencv = 20% of the direct and indirect costs Total Capital Costs = Direct Costs + Indirect Costs + Contingency Costs aAll costs are estimated in December 1987 dollars. bL = duct length per unit, feet N = number of units RF = retrofit factor obtained from Table B-16 Q = 125% of the actual flue gas flowrate, acfm H = stack height, feet D =ป stack diameter, feet B-21 ------- TABLE B-18. DOWNTIME COST PROCEDURE3 Capital Costsb Loss of Tipping Fees: Costs, $ * WDC * HRS * (DT/12) Loss of Energy (Steam or Electricity): Costs, $ = IฃD * er * HRS * 0C * (DT/12) Annualized Costs (Capital Recovery)0 Costs, $ = CRF * Downtime Capital Costs aCosts are estimated in December 1987 dollars. Apply only to retrofit applications. ^WR = weight reduction of waste in the combustor, percent WDC = waste disposal cost rate, dollars per ton (typically $25/ton) TPD = plant waste feed rate, tons/day HRS - hours of operation DT - downtime, months ER - energy cost rate, dollars per ton ($24.84/ton for mass burn waterwall units, $36.16/ton for RDF units, and $19.52/ton for modular and mass burn refractory units with heat recovery) cCRF = capital recovery factor, 0.1315 based on 10 percent interest rate and 15-year economic life B-22 ------- 2.0 PROCEDURES FOR NEW PLANTS This section presents procedures for estimating costs of new MWC plants. The capital and annualized costs of a new plant include the combustors and associated equipment, air pollution control devices (APCD's), and continuous emission monitoring equipment. Section 2.1 presents the procedures for costing the MWC combustors and associated equipment (denoted as the balance of plant). Procedures for costing electrostatic precipitators (ESP's), dry sorbent injection (DSI), and spray drying (SD) are presented in Sections 2.2, 2.3, and 2.4, respectively. Section 2.5 presents compliance monitoring equipment costs for opacity, HC1, SO^, 0^, and CO2. 2.1 COMBUSTORS AND BALANCE OF PLANT This section presents procedures for estimating the combustor and associated equipment costs, excluding the air pollution control devices (APCD's), for four types of combustors: modular, mass burn, refuse-derived fuel (RDF), and fluidized bed combustion (FBC). The capital cost procedures for each combustor type with the exception of fluidized bed combustors were developed from data presented in Frost and Sullivan.1 The operating cost procedures were developed from responses to an information request which EPA sent to MWC operators under authority of Section 114 of the Clean Air Act. Capital and operating cost procedures for FBC's were developed from vendor data. Sections 2.1.1, 2.1.2, 2.1.3, and 2.1.4 present the cost procedures for modular, mass burn, RDF, and FBC facilities, respectively. Detailed cost data suitable for direct estimation of capital costs for MWC's of various types and sizes were not available. Therefore, the procedures presented in these sections are based on scaling the capital cost of typical size facilities of each combustor type. The capital costs estimated for these facilities were all based on Frost and Sullivan (with the exception of FBC's) to minimize inconsistencies in cost assumptions among combustor types. To facilitate use of these costs with those presented in subsequent sections of this report, the original combustor capital cost estimates were revised to exclude the cost of the APCD. Indirect cost estimations for general facilities and engineering fees are also based on Frost and Sullivan. 2.1-1 ------- Capital costs were updated from 1985 dollars in Frost and Sullivan to December 1987 dollars using the Chemical Engineering Plant Cost Index. 2.1.1 Modular Units 2.1.1.1 Overview of Technology. Modula~r combustors are prefabricated units which are generally used to combust unprocessed MSW. Individual combustor units typically range in size from 5 to 150 tons per day (tpd). Modular combustors are of two general designs, starved-air and excess-air. In typical starved-air combustors, MSW is ram-fed into a primary combustion chamber with a moving grate. Primary air is fed up through the grate at substoichiometric conditions. Volatile gases released from the heated MSW enter a secondary chamber where sufficient air and supplemental fuel, typically natural gas or oil, are supplied to complete combustion. Excess-air combustors provide air in excess of stoichiometric requirements in the primary combustion chamber. Additional air and supple- mental fuel may be added in a secondary chamber to assure complete combustion. Modular combustors which recover energy typically do so in waste heat boilers following the combustion chambers. The steam produced can be sold directly to users or used to generate electricity. 2.1.1.2 Capital Cost Procedures. The original modular combustors were relatively simple in design and had low capital costs. As a result of subsequent design changes, the capital costs of modular units have increased but are still relatively low compared to other MWC technologies on a "ton per day of MSW capacity" basis. However, thermal efficiencies are also lower, decreasing the cost advantage for facilities when designed primarily for heat recovery. Because of their modular design, little or no economy of scale 2 exists as a function of facility size. As shown in Table 2.1-1, capital costs were obtained for a 50 tpd modular facility without heat recovery and for a 100 tpd facility consisting of two modular starved-air combustors, one waste heat boiler (17,000 Ib/hr steam), and an optional 1.475 MW steam turbine. Costs for excess air modular units are expected to be similar. Based on the costs presented in this 2.1-2 ------- TABLE 2.1-1. CAPITAL COSTS FOR MODULAR MWC's3 Equipment Costs, 51,000's^ A. Without Heat Recovery Combustors (1 @ 50 tpd) 1,125 Total0 1,125 Engineering Fees 88 Total Capital Costs 1,210 Unit Capital Costs $24,300 per tpd of MSW processed B. With Electricity Generation (Without Electricity Generation)1^ Combustors (2 @ 50 tpd) 2,250 Waste Heat Boiler (1 @ 17,000 lb/hr) 770 Turbine/Generator (1 @ 1,475 kW) 2,050 (0) Total0 5,070 (3,020) Engineering Fees 390 (232) = = = s = s = = = = ^ = = = = = = = = = = = s = = s = s = = = s = s = s = = = s = = s = = = = = = = = = Total Capital Costs 5,460 (3,250) Unit Capital Costs $54,600 ($32,500) per tpd of MSW processed Reference 1, p. 128. ^December 1987 dollars. cRepresents total direct costs (sum of the equipment and installation costs) ^Ccsts in parenthesis represent modular MWC's producing steam without generating electricity. 2.1-3 ------- table, the following procedure can be used to estimate capital costs for modular faci1ities: Modular facilities without heat recovery ป $24,300 per tpd capacity Modular facilities producing steam - $32,500 per tpd capacity Modular facilities generating electricity = $54,600 per tpd capacity The heat recovery boiler and turbine/generator set effectively double the cost of the faci1ity. Because modular combustors are packaged units which require little site preparation or extra equipment, no separate costs were included for general facilities (foundations and building) or MSW or ash handling systems. 2.1.1.3 Operating Cost Procedures. Annual operating cost procedures were developed from analysis of cost data provided by five plants with modular combustors in their responses to the Section 114 questionnaire. All operating costs except for capital recovery and waste disposal costs were examined. The approach used in developing the operating cost procedures was to correlate the ratio of the operating to capital costs with facility capacity (tpd) and annual operating hours. The following best fit equation was derived for these facilities, all of which were rated below 150 tpd and were operating less than 6,000 hours per year: Ratio = 10 - 0.23 tpd + 0.006 hrs (1) where, Ratio = percentage of operating to capital plant costs tpd = facility waste feed rate, tons/day hrs = annual operating hours. For modular facilities outside these size or operating hour limits, the following equation can be used to estimate annual operating cost based on mass burn refractory wall facilities as discussed in Section 2.1.2.3: Ratio - 15.7 - 0.00115 tpd (2) It is assumed that the ratio of operating to capital costs for modular and mass burn refractory wall facilities are similar, since the design and equipment arrangements of both MWC types are similar (I.e., use of waste heat boilers for heat recovery). 2.1-4 ------- Capital recovery costs are calculated as 13.15 percent of the total capital costs, based on a 10 percent interest rate and 15 year economic life. Waste disposal costs are estimated by the following equation based on a $25/ton landfill tipping fee: 100 - RED (HRS) WDC = $25 * (100) * TPD * (24) (3) where, WDC = waste disposal costs, $/yr RED = weight reduction of MSW within the combustor, percent TPD * facility waste feed rate, tons/day HRS = annual operating hours. Therefore, the total annualized costs are obtained by summing the annual operating costs calculated from Equations 1 or 2, the capital recovery costs, and the waste disposal costs estimated from Equation 3. All costs are presented in December 1987 dollars. 2.1.2 Mass Burn Units 2.1.2.1 Overview of Technology. Mass burn combustors are field-erected units used to combust unprocessed municipal solid waste. Mass burn combustors range in unit size from 50 to 1,000 tons/day for a combustor unit and from 50 to several thousand tons/day for a facility. In a mass burn combustor, municipal waste is gravity- or ram-fed to a single combustion chamber. Several different grate designs can be used to move the waste through the. combustion chamber. Air is supplied in excess of stoichiometric requirements through the grates (underfire air) and into the combustion chamber above the grates (overfire air). Either waterwall or waste heat boilers are used for recovering heat. In units with waterwalls, boiler tubes are built into the walls of the com- bustion chamber. Additional heat recovery sections can include superheaters, economizers, and air preheaters. In units with waste heat boilers, the combustion chamber is refractory lined and steam is generated downstream of the combustion chamber. 2.1-5 ------- Electricity is generally produced on-site from steam. Some facilities sell both electricity and steam. Because of the large quantity of steam produced by large mass burn units, production and sale of only steam is unlikely unless a very large industrial facility with a consistent steam demand is nearby. Waterwall units are typically larger (100 to 1,000 tons/day per unit) than units with waste heat boilers (50 to 375 tons/day per unit). Most new units are of waterwall design. No units are projected to be built without heat recovery. 2.1.2.2 Capital Cost Procedures. As shown in Table 2.1-2, the estimated capital cost for a mass burn facility is $60,700 per tpd capacity. This cost is based on an 860 tpd facility consisting of two 430 tpd combustors with 174,000 lb/hr of steam capacity and a 20 MW turbine. For the same facility without a steam turbine, the estimated capital costs are 550,420 per tpd capacity. The capital costs for waterwall units and refractory units with waste heat boilers are assumed to be roughly equal. To account for the economy of scale of mass burn facilities, capital costs reported by Frost and Sullivan were correlated with facility size to yield the following scaling equation:3 C = 60,700 (430/size)0'39, with electrical generation (4) 0 35 C = 50,420 (430/size) ' , without electrical generation (5) where, C = new facility capital costs in December 1987 dollars per tpd size = size per combustor in tpd. Capital cost for a combustor is estimated using equations 4 or 5 to calculate cost on a dollar per tpd basis and then multiplying this cost by plant capacity in tons per day. 2.1.2.3 Operating Cost Procedures. Annual operating cost procedures were developed from analysis of cost data provided by six plants (4 of which were mass burn waterwall and 2 were RDF facilities) in their responses to the Section 114 questionnaire. The RDF facility operating cost data were 2.1-6 ------- TABLE 2.1-2. CAPITAL COSTS FOR A 860 TON/DAY MASS BURN . MWC WITH (WITHOUT) ELECTRICITY GENERATION3,0 Costs, J1,000c Equ i pment Purchase Cost Inst a Ilation Cost Total InstaI led Cost Uaterwall Combustors (2 3 430 ton/day) 6,742 3,519 10,261 Refuse Cranes (2) 1,245 498 1,743 weight Scales (2) 614 302 916 Fans and Ducts (2) 1,245 368 1,613 Ash Handling System 2,933 440 3,373 Dump Condenser (1) 778 547 1,325 Stacks (2) sao 365 1,245 Water Supply and Treatment 1,611 189 1,800 Piping System 3,127 975 4,102 Electrical 1,562 293 1,855 Instruments and Controls 2,073 195 2,268 Insulation and Paint 519 293 812 Cooling Tower (1) 3,105 440 3,545 Turbine/Generator (1 S 20 MW) 6,318 (0) 1,100 (0) 7,418 (0) Total Capital Costs General Facilities 32,752 (26,434) 9,524 (8,424) 42,276d (34,858)d F oundat ions 2,544 (2,053) 1,664 (1,472) 4,208 (3,525) Building and Structural 1 .487 C1,200) 172 (152) 1 .659 (1,352) Total General Facilities 4,031 (3,253) 1.836 (1,624) 5,867 (4,877) Engineering Fees -- 4,097 (3,624) 4,097 (3,624) Total Capital Costs 36,783 (29,687) 15,457 (13,672) 52,240 (43,359) Unit Capital Costs S60,700 (50,420) per tpd of HSW processed Reference 1, p. 113. bCosts in parentheses represent mass burn HUC's producing steam without generating electr i ci ty. cDecember 19B7 dollars. dReoresents total direct costs (sum of equipment and installation costs). 2.1-7 ------- analyzed along with the mass burn cost data because of limited data for mass burn plants and because both combustor types are constructed similarly (i.e., field erected) and will likely be operated for a similar number of hours per year. All operating costs except for capital recovery and waste disposal costs were examined. The approach used in developing the operating cost procedures was to correlate the ratio of the operating to capital costs with facility capacity (tpd) and operating hours. The following best-fit equation was derived for mass-burn waterwall facilities: Ratio = 12.5 - 0.00115 tpd (6) where, Ratio = percentage of operating to capital plant costs tpd = facility waste feed rate, tons/day. For mass burn refractory wall facilities, no equation could be derived due to the limited amount of cost data. However, by comparing the Section 114 data for waterwall and refractory wall facilities, the operating to capital cost percentages for refractory facilities were roughly 3 percent higher than those for mass-burn waterwall facilities. Therefore, to estimate the annual operating cost for mass-burn refractory wall facilities, the equation for mass-burn waterwall (Equation 4) was modified to give the following: Ratio ซ 15.7 - 0.00115 tpd. (7) Equations 6 and 7 are multiplied by equation 5 to estimate annual operating costs for mass burn waterwall and mass burn refractory wall facilities, respectively. Capital recovery costs for both types of mass burn facilities are calculated as 13.15 percent of the total capital costs, based on a 10 percent interest rate and 15 year economic life. Waste disposal costs are estimated by equation 3 presented for modular facilities (Section 2.1.1.3). Therefore, the total annualized costs are obtained by summing the annual operating costs calculated from equations 6 or 7, capital recovery costs, and waste disposal costs calculated from equation 3. 2.1-8 ------- 2.1.3 RDF Units 2.1.3.1 Overview of Technology. Refuse-derived fuel MWC's are field-erected units used to combust processed MSW. Individual RDF combustors typically combust 180 to 1,200 tons/day of RDF. Plant sizes range from 180 to several thousand tons/day of RDF. Refuse-derived fuel processing includes removal of noncombustible materials and shredding of the remaining material. The two types of RDF considered in this analysis include coarse RDF (cRDF) suitable for combusting in a specially designed RDF combustor and fluff RDF (fRDF) suitable for suspension firing in a utility or industrial boiler. Coarse RDF production generally includes primary shredding and ferrous metals recovery. The RDF material is reduced in size to 4 to 6 inches. A weight reduction due to metals recovery of approximately 6 percent is assumed; energy recovery is nearly 100 percent. Fluff RDF production usually includes crushing, initial trommel screening, and magnetic separation followed by primary shredding, air classification, and secondary shredding. This processing removes oversized combustibles and glass as well :as nonferrous metals and reduces the size to below 2 inches. The associated weight reduction is approximately 20 percent of the unprocessed MSW; energy recovery is roughly 97 percent. Production of both types of RDF includes a dust control system to prevent fugitive emissions of fine dust generated by RDF processing equipment. Existing RDF combustion is based almost entirely on use of cRDF in spreader strokers. In general with this technology, cRDF is thrown to the rear of the furnace by a dry-swept stoker. Fine particles are burned in suspension, and heavier materials fall to the grate and are combusted. A traveling grate moves the materials to the front of the furnace during which time combustion is completed. The heat from combustion is recovered using radiant waterwall and convective heat transfer. Electricity is generally generated on-site, especially with the larger units. Both electricity and steam may be sold. 2.1-9 ------- TABLE 2.1-3. CAPITAL COSTS FOR A COARSE RDF FACILITY WITH ELECTRICITY GENERATION (CAPACITY = 850 TONS/DAY MSW, 800 TONS/DAY RDF)a Costs, $1,000'sb Total Purchase Installation Installed Equipment Cost Cost Cost Waterwall Combustors (2 @ 400 ton/day) 5,085 2,544 7,629 Front End Loaders (9) 713 713 Primary Shredders (2) 1,016 508 1,524 Weigh Scales (2) 639 307 946 Magnetic Separation System (2) 205 68 273 Fans and Ducts (2) 993 273 1,266 Ash Handling System (2) 2,441 368 2,809 Dump Condenser (1) 916 670 1,586 Dust Control System 508 205 713 Stacks (2) 689 303 992 Water Supply and Treatment 1,985 225 2,210 Piping System 3,663 1,221 4,884 Electrical 1,657 375 2,032 Instruments and Controls 2,339 253 2,592 Insulation and Paint 539 307 846 Cooling Tower 3,586 506 4,092 Turbine/Generator (1 @ 24 MW) 7,627 1,345 8,972 Total Capital Costs 34,601 9,478 44,079C General Facilities Foundation 3,945 2,704 6,649 Building and Structural 3.283 388 3.671 Total General Facilities 7,228 3,092 10,320 Engineering Fees 4,512 4,512 Total Capital Costs 41,829 17,082 58,911 Unit Capital Costs 573,600 per tpd of RDF Reference 1, p. 117; ^December 1987 dollars. Represents total direct costs (sum of equipment and installation costs). 2.1-10 ------- Fluff RDF has been co-fired with coal in several existing utility and 4 industrial boilers. Of the total heat input, fRDF generally represents less than 10 percent. 2.1.3.2 Capital Cost Procedures. The cost procedures developed for RDF-fired MWC's are based on cRDF. As shown in Table 2.1-3, the estimated capital cost for a cRDF facility is 573,600 per tpd of cRDF capacity. This cost was based on a cRDF facility designed to process 850 tpd of MSW into 800 tpd of cRDF. The cRDF is combusted in two identical waterwall boilers to generate 203,000 lb/hr of steam for a 24 MW turbine. The major equipment items and associated materials and labor costs for the cRDF production/ combustion facility are presented in Table 2.1-3. Because no data are available from Frost and Sullivan for other cRDF facility sizes, it is assumed that the economy of scale of RDF facilities is the same as mass-burn facilities, since both mass-burn and RDF combustors are field-constructed. Similar indirect installation costs would be incurred for both MWC types. Therefore, the following equation can be used to estimate capital cost for cRDF facilities: C = 73,600 (400/size)0,39 (8) where, C = new cRDF facility capital costs in December 1987 dollars per ton of RDF size = size per combustor in tons RDF/day. 2.1.3.3 Operating Cost Procedures. Annual operating cost procedures were developed from analysis of cost data as discussed in Section 2.1.2.3. To estimate the annual operating costs except for capital recovery and waste disposal costs, equation 6 presented in Section 2.1.2.3 can be used. Capital recovery costs are calculated as 13.15 percent of the total capital costs, based on a 10 percent interest rate and 15 year economic life. Waste disposal costs are estimated using Equation 3 presented in Section 2.1.1.3. It should be noted that the annual cost procedures do not include estimates on sale of recoverable material such as metal and glass. 2.1-11 ------- 2.1.4 FBC Units 2.1.4.1 Overview of Technology. F1uidized-bed combustors are field-erected units used to combust RDF. Only three RDF-fired FBC plants are currently operating in the U. S. Existing and currently planned FBC's are designed to combust 195 to 500 tpd of RDF. Plant sizes range from 195 to 1,200 tpd of RDF.^ For costing purposes, it is assumed that a cRDF fuel processing facility is included in the design of the FBC facility. Two basic FBC designs exist: bubbling bed and circulating fluidized-bed. In a bubbling-bed combustor, the RDF burns in a turbulent bed of heated noncombustible material, such as limestone or sand. Typical bed temperatures are from 1,450 to 1,700ฐF. As with conventional combustors, primary combus- tion air is introduced underneath the bed, but at a flowrate high enough to suspend or "fluidize" the solid particles in the bed. Secondary combustion air is introduced through ports in the upper part of the combustor to complete the combustion process. If good mixing between air and combustible waste is achieved, the amount of excess air required for complete combustion is similar to conventional RDF combustors. In addition, by adding limestone to the bed, SO^ and HC1 can be removed from the flue gas to reduce acid gas emissions. Bed material entrained in the flue gas is typically removed by a cyclone in series with a fabric filter (FF) or an electrostatic precipitator (ESP). Circulating fluidized-bed combustors are similar to bubbling-bed combustors except that the superficial velocities within the bed are 3 to 5 times higher than in bubbling-bed combustors. As a result, a physically well-defined bed is not formed; instead, solid particles are entrained with the transport air/combustion gases. Most of the solids are captured by a cyclone, and are continuously recirculated into the combustor. The solids still in the flue gas are captured by a downstream FF or an ESP. Available information on the capital and operating costs of FBC's are insufficient to distinguish bubbling versus circulating bed designs. Therefore, a single set of cost procedures has been developed. 2.1-12 ------- 2.1.4.2 Capital Cost Procedures. Table 2.1-4 presents the capital cost procedure for FBC's. All costs are estimated in December 1987 dollars. The procedures do not include the costs for FF's or ESP's. The costs for ESP's and FF's can be estimated using procedures discussed in Sections 2.2 and 2.3 of this report, respectively. The direct and indirect cost equation shown in Table 2.1-4 is based on a vendor cost estimate for two combustors each rated at 450 tpd (i.e., total Q plant capacity of 900 tpd). The vendor cost estimate included: combustor vessel, natural gas preheat system, forced draft and induced draft fans, tramp removal system, boiler, fuel and limestone storage and metering, multiclone, instrumentation and control including a boiler management system, ductwork, freight, and engineering and start-up supervision. However, the cost estimate provided by the vendor did not include cRDF processing and other equipment associated with the combustors such as front-end loaders, primary shredders, weight scales, magnetic separators, stacks, cooling tower, water treatment and supply, and steam turbine. Because the other equipment would be the same for both cRDF and FBC facilities, costs for the balance of plant in Table 2.1-3 (adjusted by size to 900 tpd using the 0.6 power cost rule) were added to the vendor cost estimates to estimate the total direct g cost. Indirect costs for general facilities and engineering fees were based on percentages of the direct cost estimated by Table 2.1-3. To estimate the direct and indirect capital cost for other plant, sizes, it is assumed that the economy of scale of FBC facilities is the same as for mass-burn and RDF facilities (0.39). Similar indirect installation costs would be incurred for these boiler types. A 20-percent process contingency is added to account for the relatively limited application of FBC to MWC's.^ 2.1.4.3 Operating Cost Procedures. Table 2.1-5 presents the operating cost bases for FBC's. Table 2.1-6 presents operating cost equations derived from Table 2.1-5. The FBC operating procedures are divided into two process areas: combustor and the balance of plant, and cRDF processing. The direct operating cost bases for the combustor and balance of plant were based on information provided by one vendor for labor, electrical consumption, and water requirements. The maintenance materials costs were determined from cost data for coal-fired industrial FBC's.^ Lime costs are based on the 2.1-13 ------- TABLE 2.1-4. PROCEDURE FOR ESTIMATING CAPITAL COSTS FOR NEW FBC'S (December 1987 dollars) Total Direct and Indirect Costs:3 Costs, 103$ = 64,900 * TPD * (900/TPD)0*39 Process Contingency: 20% of total direct and indirect costs Total Capital FBC Costs: Total direct and indirect costs + process contingency aTPD = plant municipal waste feed rate, tons/day. 2.1-14 ------- TABLE 2.1-5. ANNUAL OPERATING COST PROCEDURES FOR NEW FBC'S References Combustors and Balance of Plant (except coarse RDF processing area) Operating Labor: Supervision: Maintenance Labor: 10 man-years/year, 40 hours/week, and $ 12/hr for a 900 tpd plant 3 man-years/year, 40 hours/week, and 30% premium over operating wage for a 900 tpd plant 3 man-years/year, 40 hours/week, and 10% premium over operating wage for a 900 tpd plant Maintenance Materials: 3% of the total capital costs Electricity: Limestone: Water: Waste Di sposal: Overhead: Taxes, Insurance, and Administrative: Capital Recovery of FBC Facility: 3 MW power consumption for a 900-tpd plant and electricity costs of S0.046/kwh $40/ton 3% blowdown rate calculated from steam production and $0.50/1,000 gal for water $25/ton tipping fee and 99% combustible material in RDF and spent sorbent collected 60% of the sum of all labor costs (operating, supervisory, and maintenance) plus 60% of the maintenance materials costs 4% of the sum of the total capital costs 15 year life and 10% interest rate 6, 12 6, 13 6, 14 11 6 15 6, 16 6, 17 18 18 19 Continued 2.1-15 ------- TABLE 2.1-5 (CONCLUDED). ANNUAL OPERATING COST PROCEDURES FOR NEW FBC'S References Coarse RDF Processing Area Total Operating and Maintenance: Taxes, Insurance, and Administrative: Capital Recovery of FBC Facility: 4.4% of the total direct and indirect capital costs * ratio of operating to capital costs from Equation 6 in Section 2.1.2 4% of the sum of the total capital costs 15 year life and 10% interest rate 1 18 19 2.1-16 ------- TABLE 2.1-6. PROCEDURE FOR ESTIMATING ANNUAL OPERATING COSTS FOR FBC'S (December 1987 dollars) Combustor and Balance of Plant (excludes coarse RDF processing area): Operating labor (based on 10 man-years. 40 hours/week. S12/hr): OL = 10 * 40 * 52 * 12 * (TPD/900) = 277.3 * TPD Supervision (based on 3 man-vears/vear, 40 hours/week. 30% wage rate premium over the operating labor wage): SPRV = 3 * 40 * 52 * 12 * 1.3 * (TPD/900) - 108.2 * TPD Maintenance labor (based on 3 man-vears/vear. 40 hours/week. 10% wage rate premium over the operating labor wage): ML - 3 * 40 * 52 * 12 * 1.1 * (TPD/900) = 91.5 * TPD Maintenance materials: 3% of the total capital costs m Electricity (based on 3 MW power consumption, and electricity rate of S0.046/kwhl: ELEC - 0.153 * TPD * HRS Limestone (based on S40/ton for limestone): LIMESTONE = 0.02 * LFEED * HRS * N Water (based on 3% blowdown rate and $0.05/1.000 gal): WC - 1.86 x 10~6 * STM * HRS Waste disposal (based on tipping fee of $25/hr): AD - 1.25 x 10"2 * N * HRS * WDR Overhead: 60% of the sum of all labor costs (operating, supervisory, and maintenance) plus 60% of maintenance materials costs Taxes. Insurance, and Administrative Charges: 4% of the total capital cost Capital Recovery (based on 15 year life and 10% interest rate): 13.15% of the total capital cost Continued 2.1-17 ------- TABLE 2.1-6 (CONCLUDED). PROCEDURE FOR ESTIMATING ANNUAL OPERATING COSTS FOR FBC'S (December 1987 dollars) Coarse RDF Processing Area: Total Operating and Maintenance Costs (TOT O&M): TOT O&M = 4.4 x 10"4 * (12.5 - 0.00115 * TPD) * TDI Taxes. Insurance, and Administrative Charges: 4% of the total capital cost Capital Recovery (based on 15 year life and 10% interest rate): 13.15% of the total capital cost OL = operating labor costs, $/yr SPRV - supervision costs, S/yr ML = maintenance labor costs, $/yr ELEC = electricity costs, $/yr HRS - hours of operation per year LIMESTONE ซ limestone costs, $/yr LFEED = limestone feed rate per unit, lb/hr N * number of combustors VJC = water costs, $/yr STM = plant steam production, lb/hr AD * waste disposal costs, $/yr WDR = waste disposal rate per unit (bottom and fly ash collected), lb/hr TPD = plant municipal waste feed rate, tons/day TDI = total direct and indirect capital costs for FBC plant, $ 2.1-18 ------- amount of limestone injected at a cost of $40/ton. This cost is based on a limestone freight-on-board cost of J20/ton and a transportation cost of S20/ton, assuming a handling rate of $0.04/ton-mile hauling distance and a 500-mile hauling distance. The cost for waste disposal is determined from the amount of solids removed by the FBC plus additional fly ash collected by the downstream particulate control device. All cost rates are based on December 1987 dollars. The operating labor wage is the average from those wages in the Department of Commerce Survey of Current Business for private nonagricultural payrolls and EPRI's Technical 20 21 Assessment Guide. ' Electricity rates are from the Energy Information 22 Administration, Monthly Energy Review. The annual operating cost procedures for RDF processing facilities in Section 2.1.3.3 were used to estimate the annual operating costs for the cRDF processing area. Operating costs for the cRDF processing area are estimated to be 4.4 percent of the product of total FBC capital cost and the ratio of operating-to-capital costs for RDF facilities from Equation 6 in Section 2.1.2.3. 2.1-19 ------- REFERENCES 1. Frost and Sullivan, Incorporated. As cited in Waste-Energy Boom Seen Through Century. Coal and Synfuel Technology. March 17, 1986. 259 p. 2. U. S. Environmental Protection Agency. Small Modular Incinerator Systems with Heat Recovery: A Technical Environmental, and Economic Evaluation-Executive Summary. Cincinnati, OH. Publication No. EPA/SW-797. 1979. p. 5. 3. Reference 1. p. 105. 4. Energy and Environmental Research Corporation. Refuse Derived Fuel Co-firing Technology Assessment. Prepared for the U. S. Environmental Protection Agency. Research Triangle Park, NC. September 1988. 5. Energy and Environmental Research Corporation. F1u i d i zed - Bed Combustor Technology Assessment. Prepared for the U. S. Environmental Protection Agency. Research Triangle Park, NC. September 1988. pp. 2-13 to 2-24. 6. Letter from Hansen, J. L., Energy Products of Idaho, to Martinez, J. A., Radian Corporation. December 1, 1988. Costs for bubbling fluidized-bed combustors applied to MWC's. 7. Letter from Ferm, B., Gotaverken Energy Systems, to Johnston, M. G., EPA. March 17, 1989. Costs for circulating fluidized-bed combustors applied to MWC's. 9 p. 8. Reference 6. 9. Garrett, D. E., Chemical Engineering Economics. New York, Van Nostrand Reinhold. 1989. p. 37. 10. Electric Power Research Institute. TAG - Technical Assessment Guide (Volume 1: Electricity Supply - 1986). Palo Alto, CA. EPRI Report No. P-4463-SR. December 1986. p. 3-3. 11. Young, C. W., et al. (GCA). Technical Assessment Report for Industrial Boiler Applications: Fluidized-bed Combustion. Prepared for the U. S. Environmental Protection Agency. Publication No. EPA-600/7-79-178e. November 1979. pp. 517-553. 12. Reference 10, p. B-4. 13. Neveril, R. B. (GARD, Inc.). Capital and Operating Costs of Selected Air Pollutant Control Systems. Prepared for the U. S. Environmental Protection Agency. Research Triangle Park, NC. Publication No. EPA-450/5-80-002. December 1978. p. 3-12. 2.1-20 ------- 14. Devitt, T., P. Spaite, and L. Gibbs (PEDCo Environmental). Population and Characteristics of Industrial/Commercial Boilers in the U.S. Prepared for the U. S. Environmental Protection Agency. Research Triangle Park, NC. Publication No. EPA-600/7-79-178a. August 1979. 462 p. 15. Jordan, R. J. The Feasibility of Wet Scrubbing for Treating Waste-to-Energy Flue Gas. Journal of Air Pollution Control Association (New York). 37:422-430. April 1987. 16. Letter from Solt, J. C., Solar Turbines Incorporated, to Noble, E., EPA. October 19, 1984. Development cost for wet control for stationary gas turbines. 17. U. S. Environmental Agency. EAB Control Cost Manual. Research Triangle Park, NC. Publication No. EPA-450/5-87-001 a. February 1987. p. 2-29. 18. Reference 17, p. 2-31. 19. Bowen, M. L. and M. S. Jennings (Radian Corporation). Cost of Sulfur Dioxide, Particulate Matter, and Nitrogen Oxide Controls in Fossil Fuel Fired Boilers. Prepared for the U. S. Environmental Protection Agency. Research Triangle Park, NC. Publication No. EPA-450/3-82-021. August 1982. pp. 2-17 and 2-18. 20. United States Department of Commerce. Survey of Current Business. Washington, DC. Volume 68. Number 6. June 1988. p. S-12. 21. Electric Power Research Institute. TAG'" Technical Assessment Guide (Volume 1: Electricity Supply - 1986). Palo Alto, CA. Publication No. EPRI P-4463-5R. December 1986. p. B-4. 22. Energy Information Administration. Monthly Energy Review: December 1987. Washington, D.C. Publication No. DOE/EIA-0035 (87/12). March 1988. p. 109. 2.1-21 ------- 2.2 ELECTROSTATIC PRECIPITATORS 2.2.1 Overview of Technology Electrostatic precipitators are used to control PM emissions from MWC's. In this process, flue gas flows between a series of high voltage discharge electrodes and grounded metal plates. Negatively charged ions formed by this high voltage field attach to particulate in the flue gas, causing the charged particles to migrate toward the grounded plates. Charged particles that collect on the grounded plates are periodically removed by rapping or washing. Key ESP design and operating characteristics influencing ESP performance are particulate size and resistivity, specific collection area (SCA, equal to the total surface area of the collection plates divided by the flue gas flow rate), and the number of ESP fields. When the plates are cleaned, some of the collected particulate is reentrained in the flue gas. To ensure good particulate collection efficiency during plate cleaning and electrical upsets, ESP's have several fields located in series along the direction of flue gas flow that can be energized and cleaned independently. Particles reentrained when the dust layer is removed from one field can be recollected in a downstream field. 2.2.2 Capital Cost Procedures 2.2.2.1 Direct costs. Information on direct equipment costs is available for ESP's at three PM control levels (0.01, 0.02, and 0.03 gr/dscf at 12 percent CO,) for mass-burn, modular, and RDF facilities ranging in size from 100 to 3,000 tpd total plant capacity. These cost estimates, based on data provided by eight manufacturers, are presented in Table 2.2-1. The equipment cost data were correlated with total plate area. Figure 2.2-1 illustrates the "best fit" equation for the data from all of the ESP vendors except for one. The data from manufacturer "D" in Table 2.2-1 at a flue gas flowrate of 245,230 acfm were not included in the analysis because the cost data varied significantly from the rest of the data (refer to the three solid data points in Figure 2.2-1). Data from manufacturers F and G in Table 2.2-1 were excluded in Figure 2.2-1, because flue gas flowrates for the large mass-burn units were not reported. The resultant "best fit" equation using this approach is: 2.2-1 ------- TABLE 2.2-1. VENDOR QUOTES FOR ESP EQUIPMENT COSTS (IN lOOOS AUGUST 1986)3 Furnace Flue gas f1owrates, Outlet PM emissions. ar/dscf Vendor type3 acfm 0.03 0.02 0.01 A MOD 54,105 240 250 310 A MOD 86,568 280 290 390 B MOD 86,568 325 325 325 C MB 24,523 253 423 440 D MB 24,523 410 450 570 E MB 76,000 NAb 640 NA C MB NA 503 828 980 D MB NA 1,470 1,640 2,310 F MB 245,230 1,313 NA 1,750 G MB 240,000 NA 1,813 2,188 B MB 190,031 475 475 545 H MB 126,687 567 576 617 H RDF 130,843 580 645 781 A RDF 130,843 780 880 890 H RDF 196,264 768 832 977 A RDF 196,264 910 970 980 aMOD = modular; MB- mass-burn, and RDF = refuse-derived fuel. ^NA = not available. 2.2-2 ------- w OO I OO o o 2.4 2.2 - 2 - 1.8 1.6 1.4 1.2 - 1 - 0.8 0.6 H 0.4 0.2 H tP Q o Hp p Figure 2. ~ ~ ~ ~ ~ ma ~ n Costs (10J$) = 270.1 * 0.00653 * TPA _i | ! | | i i r i i i 1 40 60 80 100 120 140 160 TOTAL PLATE AREA, 1000 ft2 Correlation of ESP equipment costs (in August 1986 dollars) from ESP manufacturers and total plate area. ------- Purchase equipment cost, 103 $ = 305.2 + 0.00738 * TPA, in (1) December 1987 dollars 2 where: TPA is the total plate area in ft calculated as the 2 product of the SCA in ft /1000 acfm and the flue gas flowrate in 1000 acfm. The flue gas flowrate is assumed to be 125 percent of the design flowrate to accommodate variations in feed waste composition and operating 2 conditions. Equation 1 was derived using the Chemical Engineering Plant Index to update the cost equation shown in Figure 2.2-1 to December 1987 dollars and including the cost for taxes and freight. Taxes and freight were estimated at 8 percent of the equipment cost.3 To estimate the required SCA for new units, the following approach was taken. Data on SCA's were provided by eight manufacturers, as shown in 4 Table 2.2-2. From this table, the average SCA was calculated for each PM removal efficiency, as shown in Table 2.2-3. The average SCA's from Table 2.2-3 were correlated with PM collection efficiency using the Deutsch-Anderson equation. The Deutsch-Anderson equation is frequently used to predict ESP performance.^ Using the form of the Deutsch-Anderson equation, the following equation is derived: PM collection efficiency, % = 100 - 101.89 * exp(-0.0112 * SCA) or SCA = -(89.29) * In [(100 - PM collection efficiency, %)/101.89] (2) 2 where SCA = specific collection area, ft /1000 acfm Figure 2.2-2 presents the "best fit" equation for the average SCA data. Both equations (Equations 1 and 2) reasonably fit the data. The 2 coefficients of determination (R ) were 0.86 for Equation 1 and 0.97 for Equation 2. Part of the scatter not explained by Equation 1 may be due to differences in equipment included in different vendor estimates. Equations 1 and 2 apply to field-erected ESP's with total plate areas 2 above 6,500 ft and flue gas flowrates above 30,000 acfm. ESP's applied to 2.2-4 ------- TABLE 2.2-2. SPECIFIC COLLECTION AREA (SCA) REPORTED BY THE ESP MANUFACTURERS Flue Gas Inlet PM Flowrate, Loading, SCA. ft /1000 acfm. for outlet loading of Manufacturer acfm gr/dscf 0.03 0.02 0.01 A 54,015 0.11 121 182.8 235.3 A 86,568 0.11 142 184.4 239.3 B 86,568 0.11 150 150 150 C 24,523 1.72 285.5 346.7 423.7 D 24,523 1.72 332.1 419.6 675.9 E 76,000 NA NA NA NA C 245,230 1.72 286 352.2 444.9 D 245,230 1.72 335.7 405.6 634 F NAa 1.72 325 375 450 G NA 1.72 360 400 500 B 190,031 1.72 258 258 314 1 NA 1.72 400 500 NA H 126,687 1.72 345 NA 392 H 130,843 4.63 408.6 NA 544.8 A 130,843 4.63 462.6b 480.8 573b H 196,264 4.63 404.5 NA 561.3 A 192,264 4.63 463b 527.9 595.1b aNA - not available. bThese values were not used to estimate averages SCA values reported in Table 2.2-3. ------- TABLE 2.2-3. AVERAGE SPECIFIC COLLECTION AREA (SCA) CALCULATED FROM THE MANUFACTURERS' DATA Inlet PM Loading, gr/dscf at 12% CO2 Outlet PM Loadi ng, gr/dscf at 12% C0ฃ PM Removal Efficiency, Precent ft2/1000'acfm 0.11 0.03 72.7 138 (3)a 0.11 0.02 81.8 172 (3) 0.11 0.01 90.9 208 (3) 1.72 0.03 98.3 332 (9) 1.72 0.02 98.8 397 (8) 1.72 0.01 99.4 500 (B) 4.63 0.03 99.4 406 (2) 4.63 0.02 99.6 504 (2) 4.63 0.01 99.8 553 (2) ^Number in parantheses indicates the number of data points used for the average. 2.2-6 ------- 100 98 96 94 92 90 88 86 84 82 80 78 76 74 72 PH reaoval. J-100-101.89 exp(-0.0112 SCA) 10 T 300 1 500 SCA. Fr/1000 *cfm Figure 2.2-2. Relationship between ESP manufacturers' specific collection area and particulate natter reaoval. ------- smaller modular combustor facilities generally are shop-assembled and are installed at the facility at a minimal cost. To estimate the costs of this type of ESP, cost data from one manufacturer were analyzed using the same approach as for field-erected ESP's.^ The "best fit" equation relating purchase equipment costs to total plate area (TPA) is: 3 Purchase equipment costs, 10 S = 96.3 + 0.015 * TPA, in December 1987 dollars (3) R2 = 0.86 Figure 2.2-3 presents the "best fit" equation for the data from this manufacturer. Costs received from another ESP manufacturer after Equation 3 was developed are similar to those used to develop Equation 3.^ To estimate the required SCA, the SCA calculated from the manufacturer cost data was correlated with PM collection efficiency using the Deutsch-Anderson equation: PM collection efficiency, % = 100 - 79.6 * exp (-0.0035 * SCA) or SCA = -(285.7) * 1 n[(100-PM collection efficiency, %)/79.6] (4) R2 = 0.90 Figure 2.2-4 presents the "best fit" equation for the SCA data. Table 2.2-4 summarizes the procedure for estimating total capital cost for ESP's using the above four equations. The SCA required to achieve a given PM collection efficiency is estimated using either equation 2 or 4. Purchased equipment costs for the ESP can then be obtained using either Equation 1 or 3. For the costs of additional ESP units, the costs of a single ESP are multiplied by the number of required units. Procedures for estimating the costs of ductwork and fan, and installation direct costs are O also presented in Table 2.4-4. 2.2.2.2 Indirect and Other Costs. The cost factors for estimating indirect costs for field-erected ESP's are based on those presented in 9 10 established EPA cost procedures. ' Because installation and engineering 2.2-8 ------- 290 280 270 260 250 240 230 220 210 200 190 160 170 160 150 140 130 D ~ ~r 2 T ~r 4 T (Thousands) Total Plate Area, SQ.FT. ~r 6 I 8 U Figure 2.2-3. Correlation of ESP purchase equipment costs with total plate area for modular ESP's. ------- 100 90 80 u ป- ซ o. . 70 m > i u S 60 50 40 300 500 700 900 100 SCA, Ft2/1000 acfm Figure 2.2-4. Relationship between specific collection area and particulate matter removal for modular ESP's. ------- TABLE 2.2-4. COST PROCEDURES FOR ESTIMATING CAPITAL COSTS FOR ESP'S ON NEW PLANTS3 Purchased Equipment Costs (December 1987 dollars): Single Field-erected ESP unitb: Costs, 103$ - 305.2 + 0.00738 * TPA TPA - SCA * Q/1000 PM efficiency % = 100-101.89 exp (-0.0112 * SCA) Single Shop-assembled ESP unitb,C: Costs, 103 - 96.3 + 0.015 * TPA PM efficiency % = 100-79.6 exp (-0.0035 * SCA) Multiple Units: Costs = N * Costs for single ESP unit Ductwork: Costs - 0.7964 * L * Q0,5 Fan: Costs = 1.077 * Q0'96 Installation Direct Costs = 67% of equipment costs . Indirect Costs = 54% of Purchase Equipment Costs for field-erected ESP's = 514,000 for shop-assembled ESP's Contingency = 3% of the Purchase Equipment Costs Total Capital Investment = Purchased Equipment Costs + Installation Direct Costs + Indirect Costs + Contingency TPA ป total plate area, ft ~ SCA = specific collection area, ft /1000 acfm Q = 125 percent of the calculated flue gas flowrate, acfm L = Duct length, ft N - Number of ESP units includes taxes and freight of 8 percent of the ESP equipment costs. cApplies only to modular combustors whose flue gas flowrate Q is less than 30,000 acfm. 2.2-11 ------- costs are less for a shop-assembled ESP than for a field-erected ESP, indirect costs for shop-assembled ESP's are based on the manufacturer's estimate of $14,000.^ Costs reported in August 1986 dollars were updated to December 1987 dollars using the Chemical Engineering Plant Cost Index for all equipment. 2.2.3 Operating Cost Procedures Table 2.2-5 presents the procedure for estimating annual operating costs for ESP's. The procedures and factors shown for estimating the various components of annual operating costs and the references for each are listed in Table 2.2-5. Operating costs are presented in December 1987 dollars. To the extent that data are available, cost rates are based on actual rates in December 1987 dollars. Operating labor wage rate is the average from those obtained from the U. S. Department of Commerce, in its Survey of Current Business for private non-agricultural payrolls and the EPRI's 12 13 Technical Assessment Guide. ' Electricity rates were obtained from the 14 Energy Information Administration, in its Monthly Energy Review. An ash disposal cost rate of S25/ton was used, since typical ash disposal rates (tipping fees) are between S20 and $30/ton.^ 2.2-12 ------- TABLE 2.2-5. COST PROCEDURES USED TO ESTIMATE ANNUAL OPERATING COSTS FOR ESP'S ON NEW UNITS Operating Labor: Supervi si on: Maintenance: Labor Materials Electricity: Ash Di sposal: Overhead: Taxes, Insurance, and Administrative Charges: Capital Recovery: I man-hour/shift 15% of operator labor costs 0.5 man-hour/shift, 10% wage rate premium over operating labor wage 1% of the total capital costs 2 1.5 watts/ft collection area 0.5 inch pressure drop W.C. $25/ton 60% of the sum of all labor costs (operating, supervisory, and maintenance) and 60% of the maintenance material. 4% of total capital costs 15 year life and 10% interest rate References 16 17 17, 18 17 19 20 21 22 22 15 aLabor requirement in the range reported by Reference 16 (from 1/2 to 2 man- hour/shi ft). 2.2-13 ------- REFERENCES 1. U.S. Environmental Protection Agency. Municipal Waste Combustion Study: Costs of Flue Gas Cleaning Technologies. Research Triangle Park, NC. Publication No. EPA/530-SW-87-021e. June 1987. 121 p. 2. Letter from Sedman, C.B., EPA, to Chang, J. Acurex Corporation. July 14, 1986. EPA guidelines for costing flue gas cleaning technologies for municipal waste combustion. 3. Turner, J.H., et al. Sizing and Costing of Electrostatic Precipitators, Part II: Costing Considerations. Air Pollution Control Association (New York). 38:715 - 726. Hay 1988. 4. Reference 1. 5. Radian Corporation. Background Information Document for Nonfossil Fuel Fired Boilers. Prepared for the U.S. Environmental Protection Agency. Research Triangle Park, NC. Publication No. EPA 450/3-82-007. March 1982. p. 4-31. 6. Letter and attachments from Martinez, J.A., Radian Corporation, to Graham, G., PPC Industries. June 20, 1988. Costs for electrostatic precipitators applied to small modular combustors. 7. Letter and attachments from Childress, J., United McG111 Corporation, to Martinez, J.A., Radian Corporation. July 28, 1988. Costs for electrostatic precipitators applied to small modular combustors. 8. Reference 3. 9. Reference 3. 10. U.S. Environmental Protection Agency. EAB Control Cost Manual. Research Triangle Park, NC. Publication No. EPA 450/5-87-001A. February 1987. p. 2-6. 11. Reference 6. 12. Electric Power Research Institute. TAG"' - Technical Assessment Guide (Volume 1: Electricity Supply - 1986). Palo Alto, CA. Publication No. EPRI P-4463-SR. December 1986. p. B-4. 13. United States Department of Commerce. Survey of Current Business. Washington, D.C. Volume 68. Number 6. June 1988. p. S-12. 14. Energy Information Administration. Monthly Energy Review: December 1987. Washington, D.C. Publication No. DOE/EIA-0035 (87/12). March 1988. p. 109. 2.2-14 ------- ]5. Reference 17, p. 3-16. 16. Vatavuk, W. M., and R. B. Neveril, "Estimating Costs of Air Pollution Control Systems, Part II: Factors for Estimating Capital and Operating Costs," Chemical Engineering. November 3, 1980. pp. 157-162. 17. Neveril, R. B., (GARD, Inc). Capital and Operating Costs of Selected Air Pollution Control Systems. Prepared for U.S. Environmental Protection Agency. Research Triangle Park, NC. Publication No. EPA 450/5-80-002. December 1978. p. 3-12. 18. Reference 17, p. 3-14. 19. Reference 17, p. 3-18. 20. Reference 17, p. 5-2. 21. Reference 10, p. 2-29. 22. Reference 10, p. 2-31. 2.2-15 ------- 2.3 DRY SORBENT INJECTION 2.3.1 Overview of Technology Dry sorbent injection is being examined as a control option for achieving moderate acid gas control and indirectly increasing dioxin control for MWC's. Two basic variations of this technology exist: furnace sorbent injection in which alkali sorbent is injected through the overfire air ports into the furnace, and duct sorbent injection in which the sorbent is injected into either a duct or a reactor vessel upstream of the particulate control system. Particulate control following sorbent injection can be accomplished by either an ESP or fabric filter. Sorbent injection technologies have been used commercially on MWC's in Europe and Japan since 1979.1 Japanese duct injection technology generally uses a high-temperature (approximately 500ฐF) ESP ฃor particulate matter collection. European duct injection technology incorporates a fabric filter (FF) for particulate control with typical FF inlet temperatures of 350ฐF. Furnace and duct sorbent injection systems have recently been installed and tested at several MWC's in the U. S. In addition, significant testing of furnace and duct injection applied to coal-fired systems for SOg control has occurred. However, data on the comparative performance and the cost of different sorbent injection approaches for MWC's are limited. The basic chemistry for acid gas control is the reaction of calcium or sodium sorbent with HC1 and SO^ to form chloride, sulfite, and sulfate salts. The degree of acid gas control is a function of sorbent feed rate, the extent of flue gas and sorbent mixing, the flue gas temperature, and the PM control device. For moderate levels of acid gas control, sorbent can be injected directly into the furnace or the flue gas duct. For higher levels of control, a separate reactor vessel can be used that is designed to enhance flue gas and sorbent mixing and provide additional reaction time. Flue gas hunidification with water sprays or additional heat recovery in an economizer or air preheater can be used to reduce flue gas temperature. Procedures for estimating the costs of flue gas temperature reduction using humidification are presented in Section 3.5. 2.3-1 ------- Based on similarities in equipment requirements, the capital costs for furnace and duct injection are expected to be generally similar. As a result, a "generic" cost procedure was developed to estimate the capital and operating costs for both types of sorbent injection. Major equipment associated with both technologies consists of a storage silo, a pneumatic feeding system for transferring sorbent from the storage silo to feed bins, feed bins with 2 gravimetric metering systems, and pneumatic sorbent injectors. For duct sorbent injection, a venturi or a reaction vessel with mixing baffles is provided to ensure adequate gas-to-sorbent mixing. For furnace sorbent injection, sorbent will be injected through the overfire air ports or separate injection ports in the combustor. For new systems, a FF is assumed for PM control because of its enhanced acid gas and dioxin removal capabilities compared to an ESP. Primary operating costs include labor, maintenance materials, electricity, and sorbent. Labor, maintenance material, and electricity cost are expected to be generally similar for both duct and furnace sorbent injection. Because of the greater amount of data on calcium-based sorbents, the cost procedures assume use of hydrated lime (Ca(OH)2) For furnace injection, limestone (CaCO^) or lime (CaO) can be used which may be less expensive. 2.3.2 Capital Cost Procedures The direct capital cost of sorbent injection equipment depends on the flue gas and sorbent flowrates. These two parameters, in turn, depend on MSW feed rate and composition, excess air levels, flue gas temperature, sorbent quality and utilization rate, and emission control requirements. Based on a simple material balance that assumes all of the sulfur and chlorine in the MSW are converted to S02 and HC1, sorbent throughput requirements can be calculated using the following equation: Llm(lb/hr)Rate " 74-] * (2,000/24) * TPD * [%S/32 + XC1/71] * CAG/PURITY where: TPD = tons per day of MSW, based on 125 percent of the design capacity to accommodate variations in feed waste composition and operating conditions , 2.3-2 ------- %S ป percent sulfur in the MSW, %C1 = percent chlorine in the MSW, CAG = calcium-to-acid gas molar ratio (i.e., stoichiometric ratio), and PURITY = weight percent of calcium in the lime. Based on available data for duct sorbent injection, a value of 2 for CAG is expected to achieve removal efficiencies of 80 percent for HC1 and 40 percent 4 for S09. For furnace sorbent injection, a CAG value of 2 is expected to ' 5 achieve 70 percent removal of HCl and 70 percent removal of SC^. PURITY is assumed to be 90 percent. Procedures for calculating direct capital costs for the individual major equipment items shown in Table 2.3-1 were derived from data in standard cost 6 7 8 estimating manuals and manufacturer estimates. ' ' Cost for a reactor vessel is based on a vaned, stainless steel tank with one second of flue gas q residence time. Installation costs are assumed to be 30 percent of the equipment costs.^ Indirect costs, also shown in Table 2.3-1, are calculated as a percentage of total direct costs. These indirect cost rates are the same as those used for estimating the indirect capital costs of a spray dryer/FF (presented in Section 2.4-1). The equations in Table 2.3-1 estimate costs in December 1987 dollars. The costs were escalated to December 1987 dollars using the Chemical Engineering Plant Cost Index for all equipment. Capital costs for pulse jet FF's with a net air-to-cloth ratio of 4:1 are estimated using equations for single units.^ Direct and indirect capital costs as a function of flue gas flowrate can be estimated from these equations. Installation and indirect costs for FF's are 72 and 42 percent of 12 the equipment cost, respectively. The flue gas flowrate is based on 125 percent of the design flowrate to accommodate variations in feed waste composition and operating conditions. The costs for FF and auxiliary equipment are in December 1987 dollars. Contingency is included to account for unforeseen costs (50 percent of the direct and indirect cost) during installation and start-up due to the relative lack of operating experience of dry sorbent injection systems applied to MWC's.^ Projected equipment life is 15 years. 2.3-3 ------- TABLE 2.3-1. PROCEDURES FOR ESTIMATING CAPITAL COSTS FOR DRY SORBENT INJECTION Purchased Equipment Costs. 103 $ 1. Lime Storage Silo with Vibrator. Baghouse. and Flow Control Value (Based on 15-dav lime supply) o For storage volumes (V) less than or equal to 2,300 ft' (one storage silo per plant). Costs = 1.05 * (34.2 ~ 0.016V) * RF o For storage volumes between 2,300 and 4,600 ft' (two storage silos per plant), Costs = 2.10 * (34.2 + 0.016V) * RF o For storage volume greater than 4,600 ft' (two storage silos per plant). Costs = 2.10 * (63 .+ 0.0038V) * RF 2. Feed Bins o For duct sorbent injection (one feed bin per combustor), Costs = 0.0906 * N * RF * (Sf)ฐ"6U5 o For furnace sorbent injection (two feed bins per combustor), Costs = 0.1812 * N * RF * (SF)ฐ"6U5 3. Gravimetric Feeders o For duct sorbent injection (one feeder per combustor). Costs = 1.024 * (0.000289 SF + 9.293) * N * RF o For furnace sorbent injection (two feeders per combustor). Costs = 2.048 * (0.000289 SF ~ 9.293) * N * RF 4. Pneumatic Conveyor (Based on 400 Feet Length) Costs = 1.05 * (26.4 + 0.0073 SF + 0.4 * [12.8 ~ 11.23 SF023]) N * RF 5. Injection Ports For duct sorbent injection (one injection port per combustor). Costs = 1.05 * (22.2 + 0.0014 SF) * N * RF o For furnace sorbent injection (two injection ports per combustor). Costs = 2.10 * (22.2 ~ 0.0014 SF) * N * RF ------- TABLE 2.3-1. (Continued) 6. Reactor Vessel (optional for duct sorbent injection to increase flue gas and sorbent contact): Costs = 34 * (0 * 1.25/6,150)"'^ ฃ 7. Fabric Filter Costs = 0.1482 ซ N * RF * Q0.7043 8. Induced Draft Fan Costs = (1.167 * N * RF * 0ฐ'96)/1,000 9. Ductwork Costs = (0.8627 * N * RF * L * 0ฐ"5)/1,000 Installation Direct Costs = 30% of dry sorbent injection equipment costs ~ 72% of fabric filter and auxiliary equipment costs Indirect Costs = 33% of direct costs (equipment ~ installation costs) for dry sorbent injection ~ 42% of equipment cost for the fabric filter and auxiliary equipment Co ฆ cn Cont i ngencv = 50X of the sum of direct and indirect costs Total Capital Costs = Total Direct Costs ~ Indirect Costs ~ Contingency Costs 8All costs are estimated in December 1987 dollars. bSF = lime feed rate per unit, Ib/hr Q = 125 percent of the actual flue gas flowrat^ to the fabric filter per unit, acfm V = lime storage silo volume for the plant, ft N = number of units RF = Retrofit factor. For retrofit applications, use retrofit factor of 1.1 for sorbent injection equipment. Retrofit factors for fabric filter and auxiliary equipment are obtained from Table A-14. For neu units, RF = 1.0. I = duct length, feet cFabric filters are used for new applications and for retrofit applications where no ESP exists. For plants with existing ESP's, costs for upgrading the ESP are estimated from Table B-4. ------- 2.3.3 Operating Cost Procedures Table 2.3-2 presents procedures for estimating operating costs for dry sorbent injection alone. Operating costs for humidification are presented in Section 3.5. The operating and maintenance labor requirements and maintenance materials for sorbent injection are based on typical values for coal-fired boilers. Electricity costs are based on electrical requirements to operate the pneumatic feed systems. Lime costs are based on the amount of lime injected. Equations for electricity and lime were taken from Reference 10. Table 2.3-3 presents procedures for estimating operating costs for FF's. The operating and maintenance labor requirements are based on those from established EPA procedures, with the exception of maintenance materials. Because maintenance material requirements for FF's can vary directly with the size of the unit, maintenance material costs are assumed to be calculated at five percent of the direct capital costs. This percentage is the same one used for dry sorbent injection to estimate maintenance material costs. The cost of bag replacement assumes a 2-year bag life, which is typical for FF's. A gross air-to-cloth ratio of 3:1 is used. Electricity to operate the I.D. fan is calculated using a total pressure drop of 12.5 inches of water, 7 inches of water across the FF and 5.5 inches for the additional ductwork and dry sorbent injection. The cost of compressed air for the pulse jet FF's is estimated from established EPA procedures. The costs for solids disposal are determined from the amount of solids collected by the FF and a tipping fee of $25/ton. All cost rates are based on December 1987 dollars. The operating labor wage is the average from those obtained from the Department of Commerce Survey of Current Business for private nonagricultural payrolls and EPRI's Technical Assessment Guide.Electricity rates will be obtained from the Energy Information Administration, Monthly Energy Review.^ Operating hours per year can be varied to meet model plant specifications. Indirect operating costs such as taxes, insurance, and administrative charges are based on percentages of the capital costs. Payroll and plant overhead are based on a percentage of the labor and material costs. 2.3-6 ------- TABLE 2.3-2. ANNUAL OPERATING COST PROCEDURES FOR DRY SORBENT INJECTION FOR NEW MWC's11 References Operating Labor: 2 manhour/shift 14 Supervision: 15% of operator labor costs 18 Maintenance Labor: 0.5 manhour/shi ft, 107. premium over operating labor wage 18, 19 Materials: 5% of total direct costs 20, 21 Electricity: (52.56 * (lime feed rate3) + 251,850) * (electricity costs) * (hours of operation/8,760) 22 L i me : 4.38 * (lime feed rate3) * (lime cost) * (hours of operation/8,760) 22 Overhead: 60% of the sum of all labor costs (operating, supervisory, and maintenance) plus maintenance material 23 Taxes, Insurance, and Administrative Charges: 4% of total capital costs 23 aLime feed rate in lb/hr is based on 100 percent capacity of waste processed. 2.3-7 ------- TABLE 2.3-3. ANNUAL OPERATING COST PROCEDURES FOR FABRIC FILTERS FOR NEW MWC's Operating Labor: Supervi sion: Maintenance Labor: Materi als: Bag Replacement: Electricity: Compressed Air: Sol id Waste: Overhead: Taxes, Insurance, and Administrative Charges: Capital Recovery: 2 manhour/shift 15% of operator labor costs 1 manhour/shift, 10% wage rate premium over operating labor wage 5% of direct capital costs $ 1.35/ft^ for teflon coated fiberglass; 2-year 1i fe Calculated based on fan requirements for inches of water pressure drop across FF 2 scfm/1,000 acfm flue gas Apply appropriate tipping fee in S/ton (Assume $25/ton) 50% of the sum of all labor costs (operating, supervisory, and maintenance) plus materials 4% of total capital costs 15-year life and 10% interest rate References 24 24 18, 24 20 25 26 27 28 23 23 29 2.3-8 ------- REFERENCES ]. Radian Corporation. Municipal Waste Combustors - Background Information for Proposed Standards: Post-Combustion Technology Performance. EPA-450/3-89- 27 c. August 1989. 2. Reference 1. 3. Letter from Sedman, C.B., EPA, to Chang, J., Acurex Corporation. July 14, 1986. EPA guidelines for costing flue gas cleaning technology for municipal waste combustion. 4. Reference 1. 5. Reference 1. 6. Callaspy, D.T. Dry Sorbent Emission Control Prototype Conceptual Design and Cost Study. Presented at the First Joint Symposium on Dry SO- and Simultaneous SO^/NO^ Control Technologies. November 1984. 7. Process Plant Construction Estimating Standards. The Richardson Rapid System. Volume 4. 1982. p. 100-45. 8. Stearns Catalytic Corporation. Economic Evaluation of Dry-Injection Flue Gas Desulfurization Technology. Prepared for Electric Power Research Institute. Palo Alto, CA. EPRI No. CS-4343. January 1986. Appendix A. 9. Garrett, D.E. Chemical Engineering Economics. Van Nostrand Reinhold, New York. 1989. p. 298. 10. Radian Corporation. Industrial Boiler Furnace Sorbent Injection Algorithm Developed. Prepared for U. S. Environmental Protection Agency. Research Triangle Park, NC. Contract No. 68-02-3994. May 1986. p. 10. 11. U. S. Environmental Protection Agency. Municipal Waste Combustion Study: Costs of Flue Gas Cleaning Technologies. Research Triangle Park, NC. Publication No. EPA/530-SW-87-021e. June 1987. p. 3-6. 12. Reference 10, pp. 9 and 10. 13. Electric Power Research Institute. TAG"-Technical Assessment Guide fVolume I: Electricity Supplv-1986). Palo Alto, CA. Publication No. EPRI P-4463-SR. December 1986. p. 3-3. 14. U. S. Environmental Protection Agency. EAB Control Cost Manual. Research Triangle Park, NC. Publication No. EPA-450/5-87-001A. February 1987. p. 5-42. 15. Reference 13, p. B-4. 2.3-9 ------- 16. United States Department of Commerce. Survey of Current Business. Washington, D.C. Volume 68. Number 6. June 1988. p. S-12. 17. Energy Information Administration. Monthly Energy Review: December 1987. Washington, D.C. Publication No. D0E/EIA-0035 (87/12). March 1988. p. 109. 18. Reference 10, p. 12. 19. Neveril, R.B., (GARD Inc.). Capital and Operating Costs of Selected Air Pollution Control Systems. Prepared for U. S. Environmental Protection Agency. Research Triangle Park, NC. Publication No. EPA 450/5-80-002. December 1978. p. 3-12. 20. Reference 10, p. 11. 21. Reference 8, p. 1-9. 22. Kaplan, N. et al. Control Cost Modeling for Sensitivity and Economic Comparison. Proceedings from the 1986 Joint Symposium on Dry SO- and Simultaneous SC^/NO Control Technologies, EPRI CS-4966, Volume z. 23. Reference 14, p. 2-31. 24. Reference 10, p. 2-31. 25. Reference 14, p. 5-39 and 26. Reference 20. 27. Reference 14, p. 5-45. 28. Reference 14, p. 2-29. 29. Reference 19, p. 3-16. 2.3-10 ------- 2.4 SPRAY DRYING WITH EFFICIENT PARTICULATE CONTROL 2.4.1 Overview of Technology Spray drying is designed to control SC^ and HC1 emissions. When used in combination with an efficient particulate control system, spray drying can also control CDD/CDF, PM, and metals emissions. In the spray drying process, lime slurry is injected into a spray dryer (SD) vessel. The water in the slurry evaporates to cool the flue gas, and the lime reacts with acid gases to form salts that can be removed by a PM control device. The simultaneous evaporation and reaction increases the moisture and particulate content in the flue gas. The particulate exiting the SD vessel contains fly ash plus calcium salts, water, and unreacted lime. Spray drying is commonly used in combination with either a fabric filter (FF) or an electrostatic precipitator (ESP) for PM control. Both combinations have been used for MWC's in the United States, although SD/FF systems are more common and may be more effective for CDD/CDF, PM, and metals control. Two basic designs of FF's are available:" reverse air and pulse jet. In a reverse air FF, flue gas flows through unsupported filter bags, leaving the particulate on the inside of the bags. The particulate builds up to form a particulate filter cake. Once an excessive pressure drop across the filter cake is reached, air is blown through the filter in the opposite direction, the filter bag collapses, and the filter cake falls off and is collected. In a pulse jet FF, flue gas flows through supported filter bags leaving particulate on the outside of the bags. To remove the built-up particulate filter cake, compressed air is introduced through the inside of the filter bag, the filter bag expands and the filter cake falls off and is collected. The cost procedures are based on pulse jet FF systems. 2.4.2 Capital Cost Procedures Vendor capital cost estimates for SD systems combined with either an ESP or a FF applied to three types of MWC's (mass-burn, modular, and RDF) were obtained for systems designed to achieve 90 percent HC1 and 70 percent SO, ^ i removal and PM emissions of 0.01, 0.02, and 0.03 gr/dscf at 12 percent CO^. A cost comparison of SD/FF and SD/ESP systems designed to achieve a PM emission rate of 0.01 gr/dscf at 12 percent COj is presented in Appendix A for 2.4-1 ------- two mass-burn facility capacity sizes (250 and 3,000 tons/day of MSW). This comparison indicates that, at this PM control level, costs for SD/FF and SD/ESP systems are very similar, with the annualized costs for SD/FF's being slightly lower than for SD/ESP's. Although cost procedures presented in this section focus on SD/FF systems, they are representative of costs for SD/ESP systems. Cost procedures for stand-alone SD systems (i.e., without a FF) are presented in Section 3.6. These procedures were developed based on the SD/FF data plus supplemental cost quotes from three SD manufacturers. These cost procedures are intended to assist in evaluating methods to retrofit SD systems at existing plants already equipped with efficient PM control devices. 2.4.2.1 Direct Costs. Direct costs for an SD/FF system include purchased equipment cost for an SD, FF, induced draft (1.0.) fan, and ducting. The SD components include a reaction vessel, atomizer, lime feed preparation equipment, and solids handling equipment. The SD is sized based on a stoichiometric ratio (moles of calcium per mole of both SC^ and HCl in the flue gas entering the spray dryer) of 1.5:1. The FF cost 1s based on a pulse-jet type unit operated at a net air-to-cloth ratio of 4:1 and a gross air-to-cloth ratio of 3:1. Costs for single SD/FF units were based on cost data provided by two manufacturers as shown in Table 2.4-1. The data from these two manufacturers were used to estimate installed capital costs of SD/FF systems for all furnace 2 types and are plotted as a function of flue gas flowrate in Figure 2.4-1. The costs are approximately the same for any combustor type at the same flowrate. There are two reasons for this. First, the cost of the FF is assumed to be sensitive only to flue gas flowrate and is unaffected by PM grain loading. Second, the inlet SO^ and HCl concentrations in the flue gas were assumed to be essentially the same for all facility types. Inlet SO2 and HCl concentrations primarily depend on the MSW composition (particularly sulfur and chlorine contents) and MSW heating value. The values for these three factors assumed for the three facility types result in approximately the same S02 and HCl concentrations. 2.4-2 ------- TABLE 2.4-1. VENDOR QUOTES FOR SPRAY DRYER/FABRIC FILTER TOTAL CAPITAL COSTS (IN $1,000 AUGUST 1986)a Flue gas Furnace flowrates, Outlet PM emissions, ar/dscf at 12% CO^c Vendor type acfm 0.030.02 "O.ol c MB 24,523 1,712 1,712 1,762 c MB 245,230 5,262 5,262 5,624 G MB 245,230 6,000 6,000 6,000 installed capital costs reported are the purchase costs for one unit multiplied by a 1.6 adjustment factor. Auxiliary equipment costs are not i ncluded. ^MB = mass-burn. c0utlet grain loading from fabric filters. tmg.017 secti on.2-4 2.4-3 ------- 100 i 8' tt I 10 Oulto Loading: 0.01 grttacf ฉ 0.09grMocf O.UgrMocf y*MA| - Mc r Figure 2.4-1. Capital cost estimates of an SD/FF for a model MB facility, and RDF facility.2 2.4-4 ------- Table 2.4-2 summarizes the capital cost procedures for single SD/FF units. These procedures are based on achieving a PM control level of 0.01 gr/dscf at 12 percent CO^-^ The equation was developed from Figure 2.4-1. From Table 2.4-2, the total direct costs can be estimated for single units by knowing the inlet flue gas flowrate and the length of ductwork needed. The flue gas flowrate is based on 125 percent of the design flowrate to accommodate variations in feed waste composition and operating conditions. To estimate the costs of multiple units, the direct costs of a single SD/FF unit including auxiliary equipment are multiplied by the number of units. 2.4.2.2 Indirect and Other Costs. To be consistent with established EPA methodology, the equations were adjusted to distinguish direct costs (i.e., purchased equipment and installation costs) from indirect capital costs (i.e., engineering costs, construction and field expenses, contractor fees, start-up and performance test costs). To separate these costs, indirect costs are assumed to be 33 percent of the direct capital costs.^ Contingency is assumed to be similar to that applied to fossil-fuel fired boilers.^ Interest during construction and working capital is not included for air pollution control devices.^ Costs are reported in December 1987 dollars. The Chemical Enqineerinq Plant Cost Index for all equipment was used to escalate costs from August 1986 dollars. 2.4.3 Operating Cost Procedures Table 2.4-3 presents the procedure for estimating operating costs. In general, the references in this table have been used in previous EPA cost analyses. The operating and maintenance labor requirements for SD/FF are based on those used in fossil fuel industrial boiler cost analyses and assume that operating and maintenance labor costs bases would be essentially the same for coal-fired industrial boilers and MWC facilities. However, the maintenance material cost for SD/FF systems applied to MWC facilities is usually lower than the cost for systems at coal-fired boiler facilities, since uncontrolled S02 emissions are much higher from coal-fired boilers. Because SO^ concentrations are lower at MWC facilities, less concentrated slurries can be 2.4-5 ------- TABLE 2.4-2. CAPITAL COST PROCEDURES FOR SD/FF FOR NEW MWC'S3 Total Direct Costs (December 1987 dollars) Single SD/FF Unitb: Costs, 103 S = 8.053 (Q)0,517 Ductworkb: Costs, 103 S = [1.3868 * L * Qฐ*5]/l,000 Fanb: Costs, 103 S = [1.8754 * Q0,96]/1,000 Multiple Units: Multiply the above costs by the number of units Indirect Costs - 33% of total direct costs Contingency = 20% of sum of direct and indirect costs Total Capital Costs = Total Direct Costs + Indirect Costs + Contingency Costs aQ * 125 percent of the actual flue gas flowrate, acfm L - Duct length, feet ^Assumes that the total installed costs are 133 percent of the direct capital costs. 2.4-6 ------- TABLE 2.4-3. ANNUAL OPERATING COSTS PROCEDURES FOR SPRAY DRYER/FABRIC FILTER FOR NEW MWC's3 Reference Operating Labor: 4 manhours/shift; $12/manhour 8, 9 Supervision: 15% of operating labor costs 10 Maintenance: Labor: 2 manhours/shift; 10% wage rate premium 9 over operating labor wage Materials: 2% of direct capital costs 11 Bag Replacement: p Bags: $ 1.35/ft for teflon-coated fiberglass; 12 2-year life for SD/FF; Bag replacement cost not included for SD only Electricity: Cost Rate = $0.046/kwh Fan: 12.5 inches of water pressure drop 13, 14 Atomizer: 6kW/l,000 lbs/hr of slurry feed + 15kW 15 Pump: 20 feet of pumping height 16 10 psi discharge pressure 10 ft/sec velocity in pipe Compressed Air: 2 scfm air/1,000 acfm flue gas; 17 $0.11/1,000 scfm of air Water: Calculate water flowrate required for cooling the flue gas to 300 F; water cost = $0.50/1000 gal 18 Lime: Based on lime feed rate calculated for a given 19 stoichiometric ratio; lime cost = $70/ton Solid Waste: Calculate solid waste collected by the spray 20 dryer and fabric filter using PES program and apply appropriate ash disposal fee in $/ton; Assume $25/ton (continued) 2.4-7 ------- TABLE 2.4-3. (Continued) Reference Overhead: 60% of the sum of all labor costs (operating, supervisory, and maintenance) plus materials 21 Taxes, Insurance, and Administrative Charges: 4% of total capital costs 21 Capital Recovery: 15-year life and 10% interest rate 22 aAll costs are in December 1987 dollars. 2.4-8 ------- used to achieve the same removal efficiency, which in turn result in less erosion of equipment and potential for plugging. Therefore, the maintenance 23 material cost was estimated at 2 percent of the direct capital cost. Estimating the material cost at 2 percent of the direct capital cost corresponds to 1.25 percent of the total capital costs. The costs of bag replacement assumes a 2-year bag life, which is a 24 typical bag-life for FF's. A gross air-to-cloth ratio of 3:1 is used. Electricity costs include electricity consumed by the I.D. fan, atomizer, and slurry pumps. Electricity consumed by the I.D. fan is calculated using a pressure drop of 12.5 inches of water across the SD/FF. Atomizer electrical 25 requirements are based on the amount of slurry feed. Slurry pumping requirements are estimated from assumed pumping height, discharge pressure, 26 and fluid velocity in pipe used in previous cost analysis. The costs for compressed air for pulse-jet FF's are estimated from the air usage rate of 2 27 scfm/1,000 acfm of flue gas. The stoichiometric ratio (moles of calcium per mole of SOj and HCl in the inlet flue gas) assumea is 2.5 to achieve 90 percent SOg and 97 percent HCl removals. All cost rates are based on December 1987 dollars. The operating labor wage rate used is the average from those in the Department of Commerce, Survey of Current Business for private nonagricultural payrolls and EPRI's Technical 28 29 Assessment Guide. ' Electricity rates are from the Energy Information Administration, Monthly Energy Review.^ The freight-on-board (FOB) costs for quick lime (calcium oxide, CaO), $45/ton bulk, are from the Chemical Marketing 31 Reporter; an additional cost of $25/ton is assumed for transportation, based on a hauling rate of $0.05/ton-mile and a 500-mile hauling distance. For estimating ash disposal costs, a tipping fee of $25/ton is used. For new plants, the operating costs will be based on the assumption of 8,000 hours of operation per year; however, operating costs can be calculated for any number of operating hours. 2.4-9 ------- REFERENCES 1. U. S. Environmental Protection Agency. Municipal Waste Combustion Study: Costs of Flue Gas Cleaning Technologies, Research Triangle Park, NC. Publication No. EPA/530-SW-87-021e. June 1987. 121 pp. 2. Reference 1, p. 4-10. 3. Reference 1. 4. Letter from Sedman, C.B., EPA, to Chang, J., Acurex Corporation. July 14, 1986. EPA guidelines for costing flue gas cleaning technology for municipal waste combustion. 5. Bowen, M.L. and M.S. Jennings. (Radian Corporation.) Cost of Sulfur Dioxide, Particulate Matter, and Nitrogen Oxide Controls in Fossil Fuel Fired Industrial Boilers. Prepared for the U. S. Environmental Protection Agency. Research Triangle Park, NC. Publication No. EPA-450/3-82-021. August 1982. p. 2-11. 6. Reference 4. 7. U. S. Environmental Protection Agency. EAB Control Cost Manual. Research Triangle Park, NC. Publication No. EPA-450/5-87-001A. February 1987. p. 2-6. 8. Memorandum from Aul, E.F., et al., Radian Corporation, to Sedman, C.B., EPA. May 16, 1983. 36 pp. Revised Cost Algorithms for Lime Spray Drying and Dual Alkali FGD Systems. 9. Neveril, R.B. (GARD, Inc). Capital and Operating Costs of Selected Air Pollution Control Systems. Prepared for the U. S. Environmental Protection Agency. Research Triangle Park, NC. Publication No. EPA-450/5-80-002. p. 3-12. 10. Reference 7, p. 5-43. 11. Electric Power Research Institute. TAG"*-Technical Assessment Guide (Volume 1: Electricity Supply-1986). Palo Alto, CA. Publication No. EPRI P-4463-SR. December 1986. p. 3-10. 12. Reference 7, p. 5-39 and 5-43. 13. Reference 7, p. 5-45. 14. Letter and attachment from Fiesinger, T., New York State, Energy Research and Development Authority, to Johnston, M., EPA. January 27, 1987. Draft report on the economics of various pollution control alternatives for refuse-to-energy plants, p. 6-9. 15. Reference 1, p. 4-23. 2.4-10 ------- 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Dickerman, J.C. and K.L. Johnson. (Radian Corporation.) Technology Assessment Report for Industrial Boiler Applications: Flue Gas Desulfurization. Prepared for the U.S. Environmental Protection Agency. Washington, DC. Publication No. EPA-600/7-79-178i. November 1979. pp. 5-5 and 5-17. Reference 7, pp. 5-46 and 5-52. Letter from Solt, J.C., Solar Turbines Incorporated, to Noble, E., EPA. October 19, 1984. Development cost for wet control for stationary gas turbines. Chemical Marketing Reporter. Volume 233. Number 1. January 4, 1988. Reference 7, p. 2-29. Reference 7, p. 2-31. Reference 5, pp. 2-17 and 2-18. Reference 17. Reference 12. Reference 1. Reference 18. Reference 19. Reference 11, p. B-4. United States Department of Commerce. Survey of Current Business. Washington, D.C. Volume 68. Number 6. June 1988. p. S-12. Energy Information Administration. Monthly Energy Review: December 1987. Washington, D.C. Publication No. D0E/EIA-0035 (87/12), March 1988. p. 109. Reference 21. 2.4-11 ------- 2.5 COMPLIANCE MONITORING Continuous emission monitoring (CEM) systems are used to determine compliance with emission limits for MWC facilities. The following sections describe monitoring systems for opacity, SO2, HC1, 0^ and CO^. Section 3.1 discusses the types of combustion control monitors required for good combustion practices. 2.5.1 Overview of Technology 2.5.1.1 Continuous Opacity Monitoring*. Stack opacity can be continuously measured using emission measurement systems based on the principle of transmissometry. Transmissometry measures the attenuation of visible light by particulate matter in stack effluent. Light from a lamp source is projected across the stack to a light sensor. The degree of attenuation (opacity) reflects the amount of light adsorbed and scattered by the particulate matter in the effluent. The EPA regulations (Appendix B of 40 CFR Part 60) require the opacity monitoring system to operate for a minimum of 168 hours within certain performance specifications without unscheduled maintenance, repair, or adjustment. The regulations set forth minimum performance criteria for the following system parameters: calibration error (<3 percent), 24 hour zero drift (<2 percent), 24 hour calibration drift (<2 percent), and response time (10 seconds maximum). During or before installation, it is necessary to calibrate, zero, and span using calibration filters and to perform all alignments. To validate accuracy, as required in 60.13(d), instruments automatically perform simulated zero and span calibration checks at selectable intervals (usually daily). It is also usually necessary to have an air purge system to prevent accumulation of particulate from condensing on the optical surfaces. Maintenance is typically required on an as-needed basis (usually weekly). This involves cleaning all filters, checking the optical alignment and the air purge system, and recalibrating the instrument. 2 2.5.1.2 Continuous SO^ Monitoring . Continuous monitoring of SOj emissions is typically accomplished by irradiating a given volume of sample air by ultraviolet (UV) or infrared (IR) light and measuring either the 2.5-1 ------- energy absorbed or the resulting fluorescence of the SO2 molecules. Commercially available units differ in design and method, but in general it is necessary to: (]) collimate the light from the original source to provide a narrow band; (2) prepare the sample for analysis; and (3) increase the signal-to-noise ratio of the final signal via phase-sensitive detection, second derivative spectroscopic measurement, or other techniques. All SO^ monitoring systems required under NSPS must have complete zero and span calibration checks performed daily. If not, a weekly manual check is recommended. About every month, it is necessary to clean, service, and readjust the instrument. The actual maintenance schedule needed depends on the instrument and the site of application. Instruments utilizing filters, chillers, sample dryers, or support gases typically require more maintenance. Continuous monitoring systems must be installed at sampling locations where representative measurements can be made of the total emissions from the affected facility, or can be corrected so as to be representative. The SC>2 monitoring system must be capable of operating for a 168-hour minimum within certain performance specifications without unscheduled maintenance, repairs or adjustments. The regulations (Appendix B of 40 CFR Part 60) set forth minimum performance criteria for the following system parameters: accuracy (<20 percent) and 24-hour calibration drift (2.5 percent of span). The calibration drift is determined using calibration gases (i.e., gases of known concentrations), gas cells, or optical filters. The relative accuracy is determined by measuring pollution concentrations with EPA reference methods while concurrently operating the continuous monitoring system. 2.5.1.3 Continuous HC1 Monitoring. The EPA has not published performance specifications for HC1 monitors, but is currently evaluating the reliability, accuracy, and reproducibility of various monitoring systems. The outcome of this evaluation will determine which monitoring systems will serve as the basis for any ensuing EPA performance specifications for continuous HC1 monitors. In brief, four types of extractive monitors are being evaluated and are available commercially. The first type is a wet chemical batch process.^ A sample of the flue gas passes through an automatic bubbler system, and the HCl-laden liquor is sprayed against a specific ion electrode. The second type 2.5-2 ------- 4 is a nondispersive infrared (NDIR) analyzer. This instrument determines the HC1 concentration of the sample flue gas by ratioing the peak heights of the flue gas and reference gas. Both types of monitors are certified for CEM applications in West Germany. 5 The third type uses a tape sampler. A sample of gas is exposed to a chemically impregnated tape. The HC1 in the flue gas reacts with the chemical on the tape leaving the tape stained. The instrument determines the HC1 concentration by measuring the reduction in transmissivity of the tape. The last type of monitoring system is based on continuous spectrophotometry.^ A sample of flue gas is contacted with a thiocyanate reagent stream in a column. The reagent leaving the column, which contains adsorbed HC1, is fed to the spectrophotometer to obtain an HC1 signal. These two types are not certified for CEM applications in West Germany. 2.5.1.4 Diluent (Op/CO,, Monitoring).^ Diluent monitors are an integral part of an SO^ or HC1 continuous monitoring system. Diluent concentrations (Og or CC>2 on a percent basis) are required to convert actual concentrations of SO2 or HC1 to concentrations at either 7 percent or 12 percent Continuous monitoring of 0^ is based on the paramagnetic properties of O2 molecules and their response to nonhomogeneous magnetic fields or by oxide cell differential voltages. Monitoring CC^ is accomplished through infrared absorption methods. 2.5.2 Compliance Monitoring Costs Table 2.5-1 summarizes the continuous monitoring costs associated with PM only, acid gas only, and PM and acid gas controls combined. Except for HC1 and operating costs for SOj and monitors, the monitoring costs are the same as those used by EPA in developing NSPS for both small and industrial steam 0 generation units. Costs for HC1 monitors and operating costs for a combined 8 9 SO2/O2 monitor are based on recent information. ' The capital costs were updated to December 1987 dollars using the Chemical Engineering Plant Cost Index for all equipment, while the operating costs were updated to the same time bases using the Bureau of Labor Statistics' Producer Price Index for all Industrial commodities. An automatic data reduction system is included in all options shown in Table 2.5-1. 2.5-3 ------- TABLE 2.5-1. CONTINUOUS MONITORING COST SUMMARY (December 1987 Dollars) ' Pollutant Method Capi tal Costs ($1,000) Operating Costs . ($1,000/yr) Annuali zed Costs ($1,000/yr) 61 8 16 67 10 19 140 74 92 19 15 18 31 4 8 256 103 137 61 8 16 67 10 19 140 74 92 19 _IS 18 286 107 145 PM Opacity3 Acid Gas SO, (inlet and outlet) HCt (inlet and outlet) 0,/CO- Data Reduction System Total PM + Acid Gas Opacity3 S0? (inlet and outlet) HCt (inlet and outlet) 02^2 Total 3Includes costs for automatic data reduction system. ^Based on 2 certifications/year and maintenance requirements of 0.5 man-hour/ day for opacity and 0-/C0- monitors and I man-hour/day for SO- and HC1 monitors. Annualized costs include annual operating costs and capital charges on equipment and installation costs. Capital charges are based on a 15-year equipment life at 10 percent interest rate. 2.5-4 ------- REFERENCES 1. Radian Corporation. Industrial Boiler NSPS Issue Papers' Issue Paper No. 7 Compliance Monitoring Costs. Prepared for the U.S. Environmental Protection Agency. Research Triangle Park, N.C. September 1980. pp. A3 and A-4. 2. Reference 1. pp. A-l and A-2. 3. Letter and attachments from Rigo, H.G., Rigo and Rigo Associates, Incorporated, to Russo, G.P., Connecticut Resources Recovery Authority. November 18, 1986. p. 1. Draft position papers on technical questions concerning Connecticut waste-to-energy projects. 4. Reference 3. 5. Reference 3. p. 2. 6. Reference 5. 7. Reference 1. pp. A-3 and A-4. 8. Kiser, J.V., "More on Continuous Emissions Monitoring", Waste Age. June 1988. p. 124. 9. Memorandum from Peeler, J., Entropy Environmentalists, Inc., to Riley, G., EPA. June 1, 1988. Review of Draft MWC Compliance Monitoring Document. 10. Radian Corporation. Industrial Boiler SCL Cost Report. Prepared for the U.S. Environmental Protection Agency. Research Triangle Park, N.C. Publication No. EPA-450/3-85-013. November 1984. p. 2-23. 11. Reference 1. p. 3. 2.5-5 ------- 3.0 PROCEDURES FOR EXISTING PLANTS This section presents procedures for estimating costs for existing municipal waste combustion (MWC) plants. Most procedures presented in this section rely on those procedures discussed for new plants. However, additional procedures are developed which are unique to existing plants such as costs for combustion modifications to the combustors, flue gas cooling using humidification, and downtime associated with either the installation of the air pollution control device (APCD) or modifications to the combustor. This section also provides a methodology to assess the higher costs of installing APCD's at existing plants, compared to new plants, using retrofit factors. Section 3.1 presents procedures for estimating costs for operating the existing combustor. Procedures for estimating costs of combustion modifications are presented in Section 3.2. Section 3.3 provides the procedure for estimating costs for flue gas temperature control using humidification. Sections 3.4, 3.5, and 3.6 discuss estimation of costs for particulate matter control, dry sorbent injection, and spray drying, respectively. Section 3.7 present the methodology to determine retrofit factors and additional site-specific costs. Downtime costs associated with the installation of an APCD or modifications to the combustor at an existing plant are discussed in Section 3.8. 3.1 OPERATION OF THE EXISTING COMBUSTORS No capital costs are estimated for the combustors and other equipment associated with the balance of plant, because these costs are sunk and are independent of the costs for retrofitting additional APCD's. Therefore, only the operating costs of the combustors and the balance of the plant are considered. Operating costs procedures for new combustors and the balance of plant are presented in Section 2.1 and are assumed to be the same for existing plants. For existing plants, capital recovery costs are not included in the total operating costs. 3.1-1 ------- 3.2 COMBUSTOR MODIFICATIONS 3.2.1 Introduction This section describes the methodology and assumptions used to estimate capital and annual costs associated with combustor modifications needed to 1 2 ensure good combustion for MWC's. ' The organization of this chapter is as fol1ows: Section 3.2.2 discusses the approach used to estimate capital costs for each of the combustion modifications, including all assumptions. An example calculation is provided for each retrofit. Section 3.2.3 provides a methodology for estimating annual costs for MWC plants. The Chemical Engineering Plant Cost Indices are used to convert costs to December 1987 dollars. 3.2.2 Capital Cost Procedures Capital cost estimates were calculated for each retrofit component and expressed as a direct, installed cost, unless otherwise noted. When uninstalled equipment costs are provided, an installation factor is applied: Direct Capital Cost (DCC) = 1.45(Equipment Cost) The installation factor applies to delivered equipment in a solids processing pi ant. ^ Capital costs that may vary based on unit size must be scaled using factors. For example, the cost of a modification, C, at a unit of a given size is scaled for a unit of different size by the following equation: Cj - C2 (TPDj/TPD^" where: Cj = scaled capital cost of equipment at unit #1; C^ - capital cost of equipment at unit #2; 3.2-1 ------- TPDj = capacity (tons per day) of unit #1; and TPD2 = capacity (tons per day) of unit #2. The exponent n varies according to the retrofit application. It is assumed that the volumetric heat release (Btu/ft^-hr) is constant for similar combustor types (i.e., mass-burn waterwall, RDF-fired, etc.). Therefore, for a given design, unit firing capacity (tons per day) scales directly with furnace volume. Consequently, a change in a given design feature will vary as the cube root of each resulting change in dimension modifications, and the exponent is 0.667. In the case of retrofitting a row of overfire air nozzles, where a one-dimensional change is required (along the width of the combustor), the exponent is 0.333. Perry's Chemical Engineers' Handbook also applies 4 typical exponents for various pieces of equipment. The exponent values range from 0.30 to 1.00 depending on the specific equipment. As noted in Perry's Chemical Engineer's Handbook, use of exponents to estimate costs results in a slightly higher probable error (10 to 50 percent) than study estimates (up to 30 percent). Indirect capital costs (ICC) and contingencies must be applied to the direct capital costs (DCC) estimates.^ Indirect capital costs, which include general facilities and engineering and home office costs, etc., are calculated as 30 percent of DCC: ICC - 0.30(DCC). A single contingency is applied to the DCC: Contingency - 0.20(DCC). The 20 percent contingency factor is applied in all cases except when a retrofit is judged to be especially difficult, such as with stoker (grate) 3.2-2 ------- replacement; a contingency factor of 30 percent is used in this case. The total plant capital cost (TPC) is calculated as follows: TPC = DCC + ICC + Contingency. The following subsections describe the costing methodology for specific retrofit elements, including: Stoker rehabilitation, Refractory-wall furnace reconfiguration, Fuel feeding modifications, Underfire air modifications, Overfire air modifications, Monitoring/control modifications, Auxiliary fuel burner installation, and Economizer installations for flue gas temperature reduction. 3.2.2.1 Stoker Rehabilitation This modification includes demolition and replacement of existing stoker, drives, siftings hopper, siftings conveyor, and structural steel. It is also assumed that a new stoker is equipped with a ram feeder. Chesner reports direct capital costs for stoker rehabilitation for four 250-tpd units to be $4,160,000 (in December 1984 dollars) based on quotes from two stoker equipment suppliers. Assume single unit cost for 250-tpd unit is $1,040,000. Apply CEP index: 12/84 - 324.3 12/87 - 332.5 Unit Cost - 1,040,000 (332.5/324.3) = $1,066,000. Apply scaling factor and account for number of units: DCC = 1,066,000 (TPD/250),677(number of units). 3.2-3 ------- Example: Estimate the direct capital cost of replacing traveling grates with new reciprocating grates in two 375-tpd units: DCC = 1,066,000 (375/250) 677 (2) = $2,797,000. 3.2.2.2 Refractorv-Wal1 Furnace Reconfiguration This modification includes material and labor for reconstructing the combustion chambers and refractory-lined flues, including structural steel and refractory brickwork. It is assumed that new overfire air nozzles and sampling ports are included in the new furnace design. Chesner reports direct capital costs for furnace reconfiguration for four 250-tpd units to be $6,072,000 (12/84 dollars). Assume single unit cost for a 250-tpd unit is $1,518,000. ป Apply CEP index: 12/84 - 324.3 12/87 - 332.5 Unit Cost = $1,518,000(332.5/324.3) = $1,556,000. ป Apply scaling factor: DCC = 1,556,000(TPD/250),667(number of units). Example: Estimate the direct capital cost of reconstructing two 120-tpd refractory wall combustors: DCC - 1,556,000(120/250)*667(2) = $1,903,000. 3.2.2.3 Fuel Feeding Modifications Ram Feeder - This modification includes material and labor, including the hydraulic system, for a new ram feeder, plus any necessary modifications to the feed chute. Nashville Thermal reports 1979 direct capital (installed) costs of ram feedecs (one dual ram for each of two 360-tpd units) to be $360,000/ ft Assume that the unit cost is $180,000 for dual rams and $90,000 for single ram. (Single rams can be used for grates with widths up to 8 feet.) 3.2-4 ------- Apply CEP Index: 1979 (yearly average) - 247.6 12/87 - 332.5 DCC - 90,000(332.5/247.6) = $121,000 per ram feeder. Example: Estimate the direct capital cost of retrofitting one ram on each of two 120-tpd units with 8-foot wide grates: DCC - $121,000(2) - $242,000. RDF Metered Feeder - This modification includes installing metered feeding modules, consisting of two hoppers, one ram feeder, and one variable-speed drive conveyor per module. 8 Equipment cost = $150,000 per module. Apply installation factor to obtain direct capital cost: DCC = $150,000(1.45) = $217,500 per module. Example: Estimate the direct cost of retrofitting metered feeding modules on two 300-tpd RDF-fired facilities. Assume two distributors per unit and one module per distributor: DCC = $217,500(2 modules/unit)(2 units) - $870,000. 3.2.2.4 Underfire Air Modifications Segmented Underfire Air Supplies - This modification includes installing segmented, separately controllable underfire air plenums. Laval in estimated the direct capital cost of five new underfire air plenums to be $153,000 Canadian (2/85) for the Quebec City Incinerator. Assume cost for one plenum = $153,000/5 = $30,600. Convert to U.S. dollars:^ $Canadian = 1.35 ($U.S.) $U.S. - 30,600/1.35 - $22,700 (2/85 dollars). Apply CEP Index: 2/85 - 325.4 12/87 - 332.5 3.2-5 ------- (22,700)(332.5/325.4) = 23,200. Apply scaling factor: (Quebec City'is a 250-tpd unit.) DCC - 23,200(TPD/250),6^7(h)(number of units), where h = number of plenums. Example: Estimate the direct capital cost of installing a single underfire air plenum to the drying grate section of two 120-tpd uni ts: DCC - 23,200(120/25),667(1)(2) - $28,400. Underfire Air Preheat - This modification includes a natural gas burner sized to provide sufficient heat input to raise combustion air temperatures from 68ฐF to 300ฐF. ซ Example: Determine the size and direct capital cost of an auxiliary fuel burner required to preheat underfire air supplied to the drying grate. Assume that the unit size is 250 tpd. 250 tpd(2000 lb/ton)(day/24 hr)(hr/60 min) = 347 lb/min MSW. Assume that the combustor operates at 150 percent excess air and that stoichiometric air requirements are 3.25 lb air/lb waste. Total air requirements are: (347 lb/min)(3.25 lb air/lb waste)(2.5) = 2820 lb air/min. Assume that 70 percent of total air is supplied as undergrate air, and 20 percent of undergrate air is supplied to the drying grate. (2,820 lb/min)(.70)(.20) = 395 lb/min at 68ฐF. Q = mcp T where: Q = heat input, m - 395 lb/min (mass flowrate), c ซ= 0.24 Btu/lb F (specific heat of air at standard p conditions), and T ป 300 - 68 - 232 F. Q = (395 lb/min)(0.24 Btu/lbฐF)(232ฐF)(60 min/hr) = 1.32 106 Btu/hr Use a 1.4 x 10^ Btu/hr burner. 3.2-6 ------- MITRE reports capitalficosts of burners ranging from capacity of 9.2 x 10 to 1.5 x 10 Btu/hr to be $1200 per burner. Apply CEP Index: 1981 (yearly average) - 297.0 12/87 - 332.5 1,200 (332.5/297.0) = 1340. Apply installation factor to obtain direct capital cost: DCC = 1,340(1.45) = $1,950 per burner. 3.2.2.5 Overfire Air Modifications Flow modeling/thermal analysis studies are required in most cases prior to modifying overfire air systems. Overfire air modifications made at refractory-wall MWC's and tube and tile waterwall MWC's will usually require only new ducting, dampers, and nozzles. New overf^-e air rows in (nenibrane-wall MWC's are assumed to require installation of new waterwall tube panels. 12 Flow Modeling/Thermal Analysis Studies - These analyses include flow visualization studies, mixing and dispersion measurements, and flow distribution studies on a built-to-scale physical model. In addition, mathematical modeling is included as part Df the thermal analysis. Cold flow modeling - $75,000 Thermal analysis - $50.000 Total $125,000 Ducting and Dampers - Ducting Capital Costs:^3 C - 1.1 (L)(Q)^'^, where L = Length (ft) and Q = 125 percent of the actual flue gas flowrate (acfm). ซ Example: Estimate direct capital costs of ductwork and dampers required to supply overfire air to two rows of nozzles. Assume a gas flowrate of 21,400 acfm. Assume that the overfire air system 3.2-7 ------- is designed to provide 40 percent of total air flow (8,560 acfm). At standard conditions, Q = 1.25(8,560) = 10,700 acfm. Assume ducting length requirements are 100 feet. C = 1.1(100)(10,700)- $11,400(equipment cost). Damper Capital Costs: Chemical Engineering. December 29, 1980 presents cost curves for rectangular dampers. Estimate costs of a damper to install in ducting. Assume that the damper is manually controlled and has a 1.5 ft cross-sectional area. The damper equipment cost is $400 (in December 1977 dollars). Apply CEP Index: 12/77 - 210.3 12/87 - 332.5 400(332.5/210.3) ซ= $600 per damper (equipment cost). Total equipment cost = Ducting costs + damper costs $11,400 + 600 = $12,000. Apply installation factor: Total DCC = 1.45(12,000) - $17,400. Insulation for Ducting - Capital costs for ducting insulation vary from 3.5 to 22 percent of direct capital costs for ducting. Selection of the appropriate factor is based on flue gas temperature.^ Example: Assume that ducting carries preheated air at a temperature of 300 F and that capital costs for the ducting are $20,000. Estimate direct capital costs of insulation. Perry's Chemical Engineers Handbook (Table 25-51) specifies a range of 3.5 to 6 percent of ducting costs over $17,000. Select 6 percent as conservative number. C - 20,000(0.06) = $1,200. Apply installation factor: DCC - 1.45(1,200) - $1,740. 3.2-8 ------- Membrane Wall Overfire Air Nozzle - Laval in reports direct capital costs for one row of nozzles installed at Quabec City Incinerator to be $40,000 (Canadian 2/85 dollars). Convert to U.S. dollars: $U.S. = SCanadian/l.35 SU.S. - 40,000/1.35 = 29,600 (2/85 dollars). Apply CEP Index: 2/85 - 325.4 12/87 - 332.5 DCC = 29,600(332.5/325.4) = $30,200 per row. Apply scaling factor: (Quebec City is a 250-tpd unit.) DCC = 30,200(TPD/250) '^(number of rows) (number of units). Example: Estimate direct capital costs for two new overfire air rows per unit for two 1000-tpd combustors: DCC = 30,200(1000/250)-333(2 rows/unit)(2 units) - $192,000. 3.2.2.6 Combustion Controls and Monitors Fully Automatic Combustion Controller - This modification includes all hardware and software required for converting a manual combustion control system to a fully automatic control (programmable logic controller). Direct capital costs for one unit are $200,000.^'^ฎ Additional units can be installed in control scheme using the same hardware. Incremental capital costs are restricted to those costs required for installation. Assume that the direct capital cost of an automatic controller for more than one combustor is: DCC - 200,000[1 + 0.45(N - 1)], where N = number of combustors, and installation factor = 45 percent of equipment costs. DCC - 200,000 + 90,000(3 - 1) - $380,000. 3.2-9 ------- Monitors - Display readouts and data loggers are included for each monitor. Air flow monitors are venturi flow meters with pressure transducers, ,19 Direct capital cost of in situ CO/t^ monitors - $45,000 19 Direct capital cost of in situ CO monitor - $22,000 Direct capital cost of air flow pressure monitors for underfire air plenums and overfire air headers - $1,500 per plenum or row of overfire air nozzles. Oxygen Trim Control - This modification includes installation of a control loop which adjusts underfire air flowrate and/or plenum distribution based on feedback signals from an 0ฃ analyzer. Hampton, VA plant manager reports direct capital costs to be $25,000 for two 100-tpd units. Assume that these costs are fixed, per unit costs: DCC = $12,500/combustor. 3.2.2.7 Auxiliary Fuel Burner Installation ซ Gas pipeline costs: DCC =ป $50,000 per 1/2 mile22. Auxiliary gas burners - Capital costs of dual-fuel burner packages, including blowers, igniters, safety panels, and controls, are available for the following burner sizes. An installation factor of 45 percent is applied to obtain direct capital costs. Burner size (Btu/hr) Equipment Cost Direct Capital Cost 10.5 $16,000 $23,200 30.0 $25,500 $37,000 45.0 $35,000 $50,800 60.0 $42,000 $60,900 Burner equipment costs for sizes other than those provided above should be extrapolated based on size, and the 45 percent installation factor should then be applied. Example: Estimate the capital cost of providing auxiliary fuel to a facility with three 300-tpd combustors. Assume the nearest source of gas is one mile away, and each combustor requires two burners, each rated at 35 x 10 Btu/hr. 3.2-10 ------- DCC of pipeline = $100,000 and Cost of one 35 x 10 Btu/hr burner = $31,400. Apply installation factor: DCC = 1.45(31,400) = $45,500. Total direct capital costs for burners = $45,500 and (2 burners/unit) (3 units) = $273,000. Total direct capital costs ซ 100,000 + 273,000 - $373,000. 3.2.2.8 Carbon Monoxide Profiling This activity includes two days labor for three men in the field plus travel and reporting. Sampling is assumed to include 0^, carbon monoxide (CO), and temperature measurements in a 16-point array under six variable air distribution settings. Carbon monoxide profiling is required on only one combustor when multiple units of identical design are in place: DCC = $10,000 (Reference 24). 3.2.2.9 Economizer for Flue Gas Temperature Control This modification includes a separate economizer module designed to reduce flue gas temperatures from 600ฐF to 450ฐF, along with the addition of ducting and a bypass damper. Equipment cost = $45,000 (1986 dollars) for an economizer-sized to handle flue gases from four 75-tpd units (300-tpd total). Apply CEP Index: 1986 - 318.4 12/87 - 332.5 45,000(332.5/318.4) = $47,000. Apply installation factor: DCC = $47,100(1.45) = $68,100. Apply scaling factor: DCC - 68,100(TPD/300),59. 3.2-11 ------- Example: Estimate the direct capital cost of installing one economizer for three 50-tpd units: DCC = 68,100(150/300)'59 = $45,200. 3.2.3 Operating Cost Procedures Total annual costs include annual operating and maintenance (O&M) costs and annualized capital costs. Table 3.2-1 presents a summary of inputs used to estimate annual costs. The costs provided for each plant are incremental 0&M costs. For example, if a plant is equipped with auxiliary fuel burners at baseline, it is assumed that the fuel is used for start-up and shutdown, and no incremental 0&M cost is applied to the plant for auxiliary fuel consumption. Plants without auxiliary burners in place will incur additional costs for fuel consumption. The following examples illustrate the calculation of annualized costs associated with combustion controls. Example: A mass-burn refractory-wall MWC consisting of three 250-tpd combustors must add auxiliary fuel burners and operate the burners during start-up and shutdown. The facility maintains a five per week operating schedule. Determine the size of burners required to provide 60 percent of rated thermal load and estimate natural gas consumption costs. Combustor _ (250 ton/davH2000 1b/tonH4500 Btu/lb) thermal load (24 hr/day) = 94 x 106 Btu/hr Assume for a refractory-wall facility that gas is fired for six hours during start-up and two hours during shutdown. Assume that the plant operates 50 weeks/year, and start-up/shutdown occurs weekly. Total gas use = (50 wk/yr)(6 + 2 hours)(56 x 10ฎ Btu/hr)(3 units) - 67.2 x 109 Btu/yr 3.2-12 ------- TABLE 3.2-1. O&M COST INPUTS (DECEMBER 1987 DOLLARS) Item Value Direct ODeratina Costs Operating Labor $12.00/hour Supervision 15 percent of operating labor Maintenance Labor 110 percent of operating labor (assume 1 hr/shift for maintenance of controls and moni tors) Maintenance Materials 100 percent of maintenance labor Natural Gcis $4.50 per 106 Btu Water $0.50 per 1000 gallons S teaii; $5.30 per 1000 lb Sol id Was e Disposal $25 per ton Indirect (Deratina Costs Overlive 60 percent of all labor costs (operating, supervisory, and maintenance) plus 60 percent maintenance materials Taxes, Insurance, and Administrative Charges 4 percent of total plant capital costs Capitcl Recovery 15 year life and 10 percent interest rate CRF - ^ (1 + i)" - 1 where i = interest rate and n = number of years CRF = J - .1315 (l.l)1* - 1 3.2-13 ------- Using a gas cost of $4.50/10^ Btu: C = (67.2 x 109 Btu/yr)(4.50/106 Btu) = $302,000/yr Example: Determine the annual costs for a combustion retrofit at the plant in the above example. Total plant capital costs are assumed to be 5500,000, including installation of CO and monitors. Direct Costs: Assume 1 hr/shift (3 hr/day) maintenance of monitors and controls. Maintenance Materials = (3 hr/day)(5 day/wk)(50 wk/yr)(S13.20/hr) - $10,000/yr, Maintenance Materials - $10,000/yr (100% of maintenance labor) Gas costs = $302,000/yr, and No additional operating labor is required. Total Direct Annual Costs = 10,000 + 10,000 + 302,000 - $322,000. Indirect Costs: Overhead = 0.6(maintenance labor + maintenance materials). Overhead = 0.6(20,000) ซ= $12,000. Taxes, Insurance and Administrative Charges = .04(total plant capital costs) - .04(500,000) - $20,000. Annualized capital = .1315(500,000) = $66,000 assuming 15 year facility life and 10 percent weighted cost of capital. Total Indirect Annual Cost = Overhead + Taxes, Insurance, and Administrative + Annualized Capital = $12,000 + $20,000 + $66,000 = $98,000. Total annual cost = Direct Cost + Indirect Cost - $322,000 + $98,000 = $420,000/yr. 3.2-14 ------- REFERENCES 1. Radian Corporation and Energy and Environmental Research Corporation. Municipal Waste Combustors - Background Information for Proposed Guidelines for Existing Facilities. Prepared for U. S. Environmental Protection Agency. Publication No. EPA-450/3-89-27e. August 1989. 2. EER. Municipal Waste Combustion Study: Combustion Control of MSW Combustors to Minimize Emission of Trace Organics. Prepared for U. S. Environmental Protection Agency. June 1987. Publication No. EPA/530-SW-021C. 3. Perry, Robert H. and Don Green. Perry's Chemical Engineers' Handbook (Sixth Edition). New York: McGraw-Hill, 1984, p. 25-70. 4. Reference 3, p. 25-69. 5. U. S. Environmental Protection Agency. EAB Control Cost Manual (Third Edition). Research Triangle Park, NC. Publication No. EPA-450/5-87-001A. February 1987. 6. Chesner Engineering and Black and Veatch Engineers. Energy Recovery from Existing Municipal Incinerators. New York State Energy Research and Development Authority (NYSERDA) Report No. 85-14. November 1984. p. 43-85. 7. Telecon. Conversation between J. Jackson, Nashville Thermal, and P. Schindler, EER, on April 6, 1988. 8. Telecon. Conversation between Tom Giaier, Detroit Stoker, and P. Schindler, EER, on May 13, 1988. 9. Lavalin. National Incinerator Testing and Evaluation Program (NITEPk Quebec Urban Community MSW Incinerator Program Planning. Part 2 Final Report. Prepared for Environment Canada. April 1985. 10. Wal1 Street Journal. Foreign Exchange. February 7-27, 1985. 11. MITRE Corporation. The Estimation of Hazardous Waste Incineration Costs. MTR-82W233. January 1983. p. 55. 12. EER in-house estimate provided by D. Moyeda. 13. U. S. Environmental Protection Agency. Municipal Waste Combustion Study: Costs of Flue Gas Cleaning Technologies. Research Triangle Park, NC. Publication No. EPA/530-SW-87-021e. June 1987. 14. Vatavuk, W. and R. Neveril. "Part IV - Estimating the Size and Cost of Ductwork." Chemical Engineering. December 29, 1980, p. 73. 15. Reference 1, Table 25-51, p. 25-70. 3.2-15 ------- 16. Reference 5, p. 7-3. 17. Reference 5, p. 7-3. 18. Telecon. Conversation between Rob Busby, Bailey Controls, and P. Schindler, EER, on May 17, 1988. 19. Compilation of vendor quotes obtained by S. Agrawal, EER, for EPA/OSWER. Documented in letter to Robert Holloway, EPA/OSWER. April 8, 1987. 20. Waukee Flo-meter Price List. Waukee Engineering Company Bulletin No. 1-1274-R8- Milwaukee, WI. April 1, 1987. 21. Information provided to EPA and EER during visit to NASA/Langley Waste to Steam Plant, Hampton, VA. July 6, 1988. 22. Telefax from Dan Hughes, Florida Gas Transmission Company, to W.S. Lanier, EER. April 12, 1988. 23. Vendor cost quotes provided to EER by Ed Flammang, North American Manufacturing Company, Cleveland, OH. August 11, 1988. 24. EER in-house estimate provided by 2. Frompovich. 25. Telecon. Conversation between Col. Frank Rutherford, Tuscaloosa Solid Waste Authority and P. Schindler, EER. May 26, 1988. 3.2-16 ------- 3.3 HUMIDIFICATION 3.3.1 Overview of Technology Humidification is used to cool the flue gas entering the particulate matter (PM) control device. Humidification can be used separately or in combination with dry sorbent injection. The primary objective of cooling is to reduce the temperature of the flue gas entering the PM control device to below that at which post-combustion formation of dioxin is suspected to occur (approximately 450ฐF). The quantity of water required is a function of the temperature, flowrate, and moisture content of the flue gas at the inlet to the humidification chamber and the temperature reduction required.^ Qw = (TrT0) * Qs * (1 -WTR/100)/940 (]) where: Q = water required for flue gas coolir^, lb/hr; w T. ฆ inlet flue gas temperature, F; Tq = outlet flue gas temperature, ฐF; Qs = flue gas flowrate, scfm; and WTR = moisture content of the inlet flue gas, volume percent. Flue gas temperatures at the combustor exit for refractory-wall combustors generally ranged from 1,400 to 1,600ฐF; for waterwall combustors, temperatures ranged from 400 to 600ฐF. For units already using quench towers for flue gas cooling (primarily refractory-wall systems without heat recovery), the water feed rate is increased to achieve the additional cooling. For units without an existing flue gas cooling system, a humidification chamber is installed. The humidification chamber diameter is sized for a flue gas velocity of 2 10 feet/second and a chamber length-to-diameter (L/D) ratio of 3 to 1. To minimize PM fallout and impingement of wetted solids on chamber walls, no baffles or other internals are used. Pressure nozzles are used for water atomization. A secondary effect of cooling the flue gas entering the PM control device is a reduction in flue gas volume (i.e., acfm) and a corresponding 3.3-1 ------- increase in the specific collection area (SCA) thereby enhancing the PM collection efficiency of the ESP. However, because MWC ESP's operate at temperatures above the temperature of maximum particle resistivity (300 to 400ฐF for most fly ashes), decreasing flue gas temperature may in some instances increase fly ash resistivity enough to create ESP back corona problems and impair PM collection efficiency. Because of the current lack of information on resistivity-temperature relationships for MWC fly ash, this analysis assumes that humidification does not alter particulate resistivity enough to cause ESP operating problems. As a result, the impact of humidification on ESP performance is estimated based solely on the change in SCA due to flue gas volume reduction. 3.3.2 Capital Cost Procedures Capital costs are estimated for existing facilities without an existing flue gas cooling system. Direct capital costs include the humidification (evaporative cooling) chamber including the vessel and supports, water spray system and controls, and duct modifications. Direct equipment cost for the humidification chamber are based on the flue gas 3 flowrate using the following equation: Equipment Costs ($) = 0.372 * Q + 67,980 (2) where: Q is 125 percent of the actual inlet flue gas flowrate (acfm) to accommodate variations in waste composition and operating 4 conditions. The costs estimated by equation 2 are in December 1987 dollars. Originally, the costs were in December 1977 dollars and were adjusted to December 1987 dollars using the Chemical Engineering Plant Cost Index for all equipment. The equipment costs are then adjusted for retrofit difficulty based on the procedures described 1n Section 3.7.1. Costs for instrumentation, taxes, freight, and installation are estimated using indirect cost factors for venturi scrubbers.^ The 3.3-2 ------- resultant procedure for estimating capital cost is summarized in Table 3.3-1. 3.3.3 Operating Cost Procedures Table 3.3-2 presents procedures for estimating operating and maintenance (O&M) costs for the humidification chamber. Because of the simple design and operating requirements of the system, O&M labor and maintenance materials are assumed to be at the low end of those presented in Reference 6 (i.e., using the wet scrubber labor and materials requirements). Other O&M costs include water and the electricity used by the pumps. All costs are based on December 1987 dollars. An operating labor wage of the $12/hr was used. This wage was the average of the labor wages reported by both the Department of Commerce Survey of Current Business for private nonagricultural payrolls and EPRI's 7 8 Technical Assessment Guide for utility power plants. ' The labor wage reported by EPRI in January 1985 dollars was updated to December 1987 dollars using the Bureau of Labor Statistics' Producer Price Cost Index for all industrial commodities, prior to averaging. An electricity cost of $0.046/kWh was obtained from the Energy Information Administration g Monthly Energy Review. Equipment life is assumed to be 15 years. 3.3-3 ------- TABLE 3.3-1 CAPITAL COST PROCEDURES FOR HUM ID1FICAT ION10'11 Equipment Costs (December 1987 dollars) 1. Humidification Chamber and Pumps:3 Cost, $ ฆ= 0.372 * q + 67,980 2. Ductwork Cost, $ = 0.981 * L * Q0,5 Retrofit Purchase Equipment Costs = 1.18 * Equipment Costs * Retrofit Factor (from Section 3.7) Installation Direct Costs = 0.56 * Purchased Cost Indirect Costs*3 * 0.35 * Purchased Cost Total Capital Costs = Purchased Equipment Costs + Installation Direct Costs + Indirect Costs = 1.91 * Purchased Costs aQ - 125 percent of the actual flue gas flowrate, acfm L - Duct length, feet. ''includes a contingency of 3 percent of the purchased costs. 3.3-4 ------- TABLE 3.3-2 OPERATING AND MAINTENANCE COSTS FOR HUMIDIFICAT ION Operating Labor: Supervision: Maintenance Labor: Maintenance Materials: Water: Electricity:3'^ Overhead: Taxes, Insurance, and Administrative Charges: Capital Recovery: 0.5 man-hours/shift; wages of S12/hr 15% of operating labor costs 0.5 man-hours/shift 10% wage premium over operating labor wages 1% of total capital investment 0.00012 * Q * (hours of operation) * (water cost1?, S/1000 gal) cost of SO.50/1000 gal -4 1.587 x 10 * Q * (hours of operation) * (electricity costs, S/kWh) cost of SO.046/kWh 60% of the sum of all labor costs (operating, supervisory, and maintenance) and maintenance materi als 4% of the total capital costs 15-year life and 10% interest rate References 6, 8 12 12 13 14 15 15 15 Q =* water injection rate, lb/hr, (from Equation 1 in Section 3.3.1). w 'Assume 20 feet of pumping height, 100 psi discharge pressure, and 10 ft/sec velocity in pipe. 3.3-5 ------- REFERENCES 1. PEI Associates, Inc. User's Manual for the Integrated Air Pollution Control System Cost and Performance Program (Version 2). Prepared for the U. S. Environmental Protection Agency. Research Triangle Park, NC. Contract No. 68-02-3995. April 1985. p. 4-16. 2. Neveril, R.S. (GARD Inc.) Capital and Operating Costs of Selected Air Pollution Control Systems. Prepared for U. S. Environmental Protection Agency. EPA-450/5-80-002. December 1978. p. 4-40. 3. Reference 2. p. 4-41. 4. Letter from Sedman, C.B., EPA, to Chang, J. Acurex Corporation. July 14, 1986. EPA guidelines for costing flue gas cleaning technologies for municipal waste combustor. 5. Reference 2. p. 3-11. 6. Reference 2. p. 3-14. 7. United States Department of Commerce. Survey of Current Business. Washington, D.C. Volume 68. Number 6. Jur^ 1988. p. S-12. 8. Electric Power Research Institute. TAG - Technical Assessment Guide (Volume 1: Electricity Supply - 1986). Palo Alto, CA. Publication No. EPRI P-4463-SR. December 1986. p. B-4. 9. Energy Information Administration. Monthly Energy Review: December 1987. Washington, D.C. Publication No. DOE/EIA-0035 (87/12). March 1988. p. 109. 10. Reference 2. p. 4-41. 11. U. S. Environmental Protection Agency. Municipal Waste Combustion Study: Costs of Flue Gas Cleaning Technologies. Research Triangle Park, NC. Publication No. EPA/530-SW87-021e. June 1987. 12. Reference 2. p. 3-12. 13. Reference 5. p. 4-23. 14. Letter from Solt, J.C., Solar Turbines Incorporated, to Noble, E., EPA. October 19, 1984. Development cost for wet control for stationary gas turbines. 15. U. S. Environmental Protection Agency. EAB Control Cost Manual. Research Triangle Park, NC. Publication No. EPA-450/5-87-001A. February 1987. p. 2-31. 3.3-6 ------- 3.4 PARTICULATE MATTER CONTROL RETROFIT This section discusses three electrostatic precipitator (ESP) control alternatives for reducing PM emissions from existing MWC facilities. These alternatives are: installation of a new ESP (discussed in Section 3.4.1), increasing the plate area of an existing ESP (Section 3.4.2), and rebuilding an existing ESP to improve performance (Section 3.4.3). 3.4.1 Installation of a New ESP The procedures for estimating ESP capital costs for new plants (described in Section 2.2.2) are applicable to the procedures used for existing plants. The existing plant cost procedures include site-specific retrofit factor and scope adders used to estimate the cost of demolition, replacement, relocation of existing equipment, new ducting, and stacks, if needed. 3.4.1.1 Capital Cost Procedures. The procedures developed for estimating the capital costs of ESP's for new plants (described in Section 2.2.4.1) are used to estimate the direct costs of major equipment, including the fans and ash handling. Estimated duct lengths are required to calculate duct costs for connecting the ESP to an existing plant. The estimated direct costs of new equipment and ducts are then multiplied by site-specific retrofit factors determined by the procedures described in Section 3.7.1. Total direct capital costs for retrofit are calculated as the sum of the adjusted equipment costs fclus any scope adders. Scope adders are additional significant costs for items, such as chimneys or demolition, that are required for an accurate estimate of the ESP retrofit. Determination of scope adder costs is described in Section 3.7.2. After the total direct capital costs have been estimated, the remainder of the capital cost procedure (for indirect and contingencies costs) is the same as for ESP's installed in new plants as described 1n Section 2.2.4.1. 3.4.1.2 Operating Cost Procedures. Operating costs for retrofit ESP's are estimated using the same procedures as those for new plants discussed in Section 2.2.4.2. The costs of taxes, insurance, and administrative charges are estimated as a fraction of the total retrofit capital costs. The proposed 3.4-1 ------- procedures also allow operating hours to be varied to reflect model plant specifications. 3.4.2 Increase in ESP Plate Area Additional ESP plate area is installed when the existing ESP is too small to achieve the desired PM control. Addition of plate area is accomplished by installing a new ESP in series with the existing ESP. This approach results in minimum facility downtime and will simplify cost estimation relative to the addition of plate area to the existing ESP. 3.4.2.1 Capital Cost Procedures. The procedures developed for estimating the capital costs of ESP's for new plants (described in Section 2.2.4.1) are used to estimate the direct costs of installing additional ESP plate area. First, the required particulate removal efficiency is calculated based on the PM emission limit desired and the inlet PM concentration. This removal efficiency is then used to calculate the required specific collection area (SCA) using either equation 2 or 4 presented in Section 2.2.4.1. Next, the SCA of the existing ESP is subtracted from the calculated SCA to determine the additional SCA required. The additional SCA required is used to calculate the additional plant area requirement and the direct costs of the second ESP using equations 1 or 3 in Section 2.2.4.1. The required duct length is estimated for each model plant based on the equipment configuration for that plant. The estimated direct costs of the new ESP and ducts are then multiplied by a site-specific retrofit factor determined according to the guidelines discussed in Section 3.7.1. Appropriate scope adders are costed based on procedures described in Section 3.7.2. After the total direct capital costs have been estimated, the remainder of the capital cost procedure (for indirect and contingency costs) are the same as for ESP's installed in new plants presented in Section 2.2.4.1. 3.4.2.2 Operating Cost Procedures. Operating costs for the second ESP are estimated using procedures for new plants discussed in Section 2.2.4.2. Only those costs associated with the second ESP are included. Because operating, supervision, and maintenance labor are available for the existing ESP, it is assumed that no additional labor requirements are necessary to operate and maintain the second ESP. 3.4-2 ------- 3.4.3 ESP Rebuild An ESP rebuild can be used with existing ESP's with PM removal efficiencies lower than those predicted in either Figures 2.2-2 or 2.2-4 for a new ESP with equivalent SCA. Rebuild of an ESP includes replacing worn or damaged internal components (plates, frame, and electrodes), upgrading controls and electrical systems for more effective energization, and flow modeling to evaluate gas distribution. The ESP rebuild does not include making design changes to the existing ESP, such as changes to the plate-electrode geometry or addition of collection area. 3.4.3.1 Capital Cost Procedures. The procedures developed for estimating the capital costs of ESP's for new plants (described in Section 2.3.4.1) are used to estimate the direct costs of ESP rebuild. Based on contacts with ESP vendors, a typical cost for rebuilding an existing ESP is roughly 30 percent of the total capital cost of a new ESP of equivalent size, 1 2 but can be as high as 50 percent of the new ESP cost. ' The recommended procedure for estimating the total capital costs for ESP rebuild is to use 30 percent of the cost for a new ESP. This factor assumes equipment costs of 42 percent of the cost of a new ESP plus installation and indirect equipment cost multipliers of 0.33 and 0.27, respectivelyThese indirect cost multipliers are lower than those used for new ESP's because: (1) new foundations, supports, piping, insulation, and painting are not required and (2) engineering and erection expenses are reduced relative to the costs for a new ESP. Site-specific retrofit factors are not used since the rebuild is performed within the existing ESP. 3.4.3.2 Operating Cost Procedures. The operating and maintenance costs after ESP rebuild are the same as before the rebuild with the exception of additional waste removal. The additional waste removal requirements are based on the incremental reduction of PM achieved after the ESP is rebuilt. 3.4-3 ------- REFERENCES 1. Telecon, Lamb, Linda, Radian Corporation, with Gawrelick, Gary, Research-Cottrell. February 18, 1988. Rebuild Costs for ESP's. 2. Telecon. Martinez, John, Radian Corporation, with Gawrelick, Gary, Research-Cottrell. April 11, 1988. Additional cost information on ESP rebuilds. 3. Turner J.H. et al. Electrostatic Precipitators (draft section). In: EAB Control Cost Manual, U. S. Environmental Protection Agency. Research Triangle Park, NC. Publication No. EPA-450/5-87-001A. February 1987. p. 6-56. 3.4-4 ------- 3.5 Dkr SORBENT INJECTION RETROFIT 3.5.1 Overview of Technology Cost procedures are presented in Section 2.3 for the injection of dry sorbent into the furnace or duct of a new plant. The major distinctions between the design of sorbent injection systems for most existing facilities versus new facilities are (1) the reuse of an existing ESP rather than a new fabric filter for PM control, and (2) the higher capital costs to reflect the difficulty of a site-specific retrofit. For existing facilities not equipped with an E:>P, new fabric filters can be used. Another retrofit option for duct sorbent injection at existing facilities is to :njact dry sorbent following an existing spray humidification chamber. In this option, the flue gas leaving the combustor is cooled by humidification to 350cF before it enters the ESP, or to 300ฐF in the case of a fabric filter. Dry sorbent is injected after the gas is humidified to minimize cake buildup in the duct. 3.5.2 Capital Cost Procedures The procedures developed for estimating the capital costs of dry sorbent injection for new plants are used to estimate the direct capital cost of major equipment and ductwork for retrofit installations. Because the major equipment components of dry sorbent injection (reagent storage and handling system) can be located in remote areas, difficulties associated with spacial constraints (i.e., access/congestion) and underground obstructions is generally minimal. Based on the application of dry sorbent injection to coal-fired utility boilers, the direct capital cost for new plants is increased by 10 percent to account for the estimated costs of modifying an existing duct in the case of duct sorbent injection, modifying an existing overfire air system in the case of furnace sorbent injection, or modifying an existing humidification chamber.^ The total direct capital costs for retrofit also include the cost of any scope adders such as additional ducting or existing equipment demolition that is required to accurately estimate dry sorbent injection retrofit costs at a specific site. Additional ductwork can be estimated using cost equations in Section 2.3. Scope adders are defined in Section 3.7.2. Determination of scope adder costs is also described in Section 3.7.2. 3.5-1 ------- After the total direct capital costs have been estimated, tire remainder of the capital cost procedure for estimating indirect capital costs and contingencies is the same as for dry sorbent injection at a new plant presented in Section 2.3.4.1. 3.5.3 Operating Cost Procedures Operating costs for retrofit dry sorbent injection installations are estimated using the same procedures discussed in Section 2.3.4.2 for new plants. Operating costs for existing plants are higher than for new plants of equivalent sizes because the maintenance expenses are affected by access and congestion difficulties. This increased cost is handled by calculating maintenance materials as a percentage of the total capital investment. The costs of taxes, insurance, and administrative charges are based on the total retrofit capital costs. 3.5-2 ------- REFERENCE 1. Radian Corporation. Retrofit Costs for S02 and NO Control Options at 50 Coal-Fired Plants (Draft Report). Preparea for the U. S. Environmental Protection Agency. Research Triangle Park, NC. Contract No. 68-02-4286. February 1988. 3.5-3 ------- 3.6 SPRAY DRYER RETROFIT 3.6.1 Overview of Technology Spray dryers (SD) combined with fabric filters (FF) can be retrofitted at existing plants where very high levels of CDD/CDF and acid gas control are required. Key technology considerations include reconfiguration of the ducting between the combustor outlet and stack, and the availability of space for installing sorbent handling equipment, SD vessel, FF, and ash disposal facilities. Stand-alone SD costs were developed for this study to evaluate the costs of retrofitting a new SD in front of an existing particulate control device. Cost procedures presented in Sections 3.6.2 and 3.6.3 can be applied to estimate SD retrofit costs at existing plants. In most cases, the existing particulate control device is an ESP. For cases where it is determined that additional plate area is required to handle the increase in fly ash loading to the ESP caused by the SD, costing procedures presented in Sections 2.2 and 3.4.2 for modifying ESP's to add plate area should be used. 3.6.2 Capital Cost Procedures The procedures developed for estimating the capital costs of SD/FF systems for new plants (described in Section 2.4.4) can be used to estimate the direct capital cost of major equipment and ducts for retrofit installations. Required duct lengths are used to estimate the duct costs for connecting the SD system to an existing plant. The estimated direct costs of new equipment and ducts are then multiplied by site-specific retrofit factors determined by the procedures in Section 3.7.1. Capital costs for stand-alone SD systems are based on quotes obtained from three manufacturers.1-3 These quotes, shown in Table 3.6-1, exclude the costs of any particulate control device. As discussed in Section 2.4, direct capital costs were correlated with flue gas flowrates. The direct capital cost equation in Table 3.6-2 for a single SD unit was developed from these 2 quotes. The correlation coefficient (R ) for this equation is 0.81. Figure 3.6-1 shows the relationship of both the predicted SD direct capital costs and the vendor costs with flue gas flowrate. The accuracy of the 3.6-1 ------- TABLE 3.6-1. VENDOR QUOTES FOR SPRAY DRYER DIRECT CAPITAL COSTS (in 1000$ August 1988) Vendor Combustor Type3 Combustor. Size, tpd Flue gas Flowrate, acfm Direct Capital Costs A KB/ WW 100 24,000 890 A MB/RC 250 49,000 1,225 A RDF 300 82,800 1,575 A MB/WW 750 210,000 2,725 A RDF 1,000 393,000 3,930 B MB/WW 100 24,000 850 B MB/RC 250 49,000 1,400 B RDF 300 82,800 900 B MB/WW 750 210,000 2,500 B RDF 500 196,500 2,150 C MB/WW 100 24,000 1,300 C MB/RC 250 49,000 2,170 C RDF 300 41,400 1,650 C MB/WW 750 210,000 3,430 c RDF 500 196,500 2,560 MB/WW = mass burn/waterwal1 MB/RC = mass burn/rotary combustor RDF = refuse-derived fuel ^tpd = tons burned per day 3.6-2 ------- TABLE 3.6-2. CAPITAL CCST PROCEDURES FOR SPRAY DRYERS3 Total Direct Costs (December 1987 dollars) Single SD Unit only: Costs, 103 $ = 8.428 (Q)0-460 * N * RF Ductwork^: Costs, 103 $ = [1.3868 * L * Qฐ'5]/1,000 * N * RF Fanb: Costs, 103 $ - [1.8754 * Qฐ'96]/1,000 * N * RF Multiple Units: Multiply the above costs by the number of units Indirect Costs = 33% of total direct costs Contingency = 20% of sum of direct and indirect costs Total Capital Costs =ป Total Direct Costs 1- Indirect Costs + Contingency Costs aQ = 125 percent of the actual flue gas flowrate. acfm L = Duct length, feet N = Number of units RF = Retrofit factor, dimensionless ^Assumes that the total installed costs are 133 percent of the direct capital costs. 3.6-3 ------- ~ u Vendor costs Predicted costs ~ \ i 1 1 1 1 ~i r 100 200 300 (Thousands) FLUE GAS FLOWRATE. ACFM Correlation of SO direct capital costs (in August 1988 dollars) from the SD Manufacturers and flue gas flowrate. ------- ฑiV percent. It should be noted that the costs shown in this figure are reported in Augjs1 1988 dollars and that the flue gas flowrate is the actual flue gas flowrate. The SD direct capital cost equation in Table 3.6-2 was oerivtd by c'd-escal at ing the predicted cost curve shown in Figure 3.6-1 to December 1987 cjlUrs using the Chemical Engineering Plant Index and by ccrrectirg fot :I.percent of the actual flue gas flowrate. Comparing the direc*. c.t;t.a 1 ei^ts for SD with those for SD/FF estimated using procedures in Se'!. 2.-L the SD '..osts are generally between 50 and 60 percent of the costs for a S!/m for f , v.? yas flowrates ranging from 25,000 to 400,000 acfm. These fiue flowrjlvr c.r, er the range of flowrates from small modular units to 1 ar^e RDf units, rcr F.SP reuse, the costs of additional plate area, if any, o:tir;;ated from pr?r<.-cures presented in Section 3.4.2 should be included. The required diiCt length is estimated for each model plant based on the r-r-cuosed air poll :::on control device (APCD) equipment configuration for that v-U'it. The direct costs of new equipment and ductwork are then tipl icd by s re-satcific retrofit factors described in Section 3.7.1. The U>t=i direct capital cost for retrofit is calculated as the sum of :he adjusted new ^quicment costs plus any scope adders. Scope adders incorporate additional capital costs for items such as chimneys or demolition thst ere required for SD retrofit. Determination of scope adder costs is described in Section 3.7.2. After the total direct capital cost has been estimated, the remainder of the capital costing procedure for indirect capital costs and contingencies is the same as for SQ-'FF installation at a new plant (see Section 2.4.2). 3.0.3 Operating Cost procedures. Operating costs for retrofit SD/FF installations are estimated using the saint procedure: as for new plants in Section 2.4.3. Table 3.6-3 presents the annual operating cost procedures for stand-alone SD's. Annual operating costs for the SD system alone exclude costs associated with the PM control device, such as bag replacement, compressed air, and solid waste costs. Operating labor, supervision, and maintenance labor costs for the SD alone are half those for a similar SD/FF system. Electricity costs for the I.D. fan are based on 5.5 inches of water pressure drop for an SD compared with 3.6-5 ------- TABLE 3.6-3. ANNUAL OPERATING COSTS PROCEDURES FOR STAND-ALONE SPRAY DRYERS FOR NEW MWC's3 Operating Labor: Supervision: Maintenance: Labor: Materials: Electricity: Fan: 2 man-hours/shift; $12/man-hour 15% of operating labor costs 1 man-hour/shift; 10% wage rate premium over operating labor wage 2% of direct capital costs Cost Rate = $0.046/kwh 5.5 inches of water pressure drop Reference 4, 5 6 5 7 4, 5 Atomizer: Pump: Water: Lime: Overhead: 6kW/l,000 lbs/hr of slurry feed + 15kW 20 feet of pumping height 10 psi discharge pressure 10 ft/sec velocity in pipe Calculate water flowrate reguired for cooling the flue gas to 300 F; water cost = $0.50/1000 gal Based on lime feed rate calculated by assuming a stoichiometric ratio of 1.5:1; lime cost = $70/ton 60% of the sum of all labor costs (operating, supervisory, and maintenance) plus materials 8 9 10 11 12 Taxes, Insurance, and Administrative Charges: 4% of total capital costs 12 Capital Recovery: 15-year life and 10% interest rate 13 All costs are in December 1987 dollars. 3.6-6 ------- 12.5 inc'ias of water pressure drop for a SD/FF. Operating costs for ESP reuse are estimated from procedures presented in Section 3.4.2 for additional ESP plate area. Operating costs for existing plants are higher than for new plants of equivalent size, since maintenance expenses will be affected by access and congestion difficulties. This increased cost is handled by calculating maintenance materials as a percentage of the total capital investment; The costs of taxes, insurance, and administrative charges are based on total retrofit capital costs. These procedures also allow operating hours to be varied to meet model plant specifications. 3.6-7 ------- REFERENCES 1. Letter and attachment from Weaver, E.H., Belco Pollution Control Corporation, to Johnston, M.G., EPA. September 28, 1988. Retrofitting of spray dryers to existing MWC's. 2. Letter and attachment from Buschmann, J.C., Flakt Incorporated-, to Johnston, M.G., EPA. October 27, 1988. Costs for spray dryers applied to MWC's. 3. Letter and attachment from Murphy, J.L., Wheelabrator Air Pollution Control, to Johnston, M.G., EPA. November 18, 1988. Costs for spray dryers applied to MWC's. 4. Memorandum from Aul, E.F., et al., Radian Corporation, to Sedman, C.B., EPA. May 16, 1983. 36 p. Revised Cost Algorithms for Lime Spray Drying and Dual Alkali FGD Systems. 5. Neveril, R.B. (GARD, Inc.). Capital and Operating Costs of Selected Air Pollution Control Systems. Prepared for the U. S. Environmental Protection Agency. Research Triangle Park, NC. Publication No. EPA-450/5-80-002. December 1978. p. 3-12. 6. U. S. Environmental Protection Agency. EAB Control Cost Manual. Research Triangle Park, NC. Publication No. EPA-450/5-87-001A. February 1987. p. 2-6. 7. Electric Power Research Institute. TAG^-Technical Assessment Guide (Volume 1: Electricity Supply-1986). Palo Alto, CA. Publication No. EPRI P-4463-SR. December 1986. P. 3-10. 8. Reference 1, p. 4-23. 9. Dickerman, J.C. and K.L. Johnson. (Radian Corporation.) Technology Assessment Report for Industrial Boiler Applications: Flue Gas Desulfurization. Prepared for the U. S. Environmental Protection Agency. Washington, DC. Publication No. EPA-600/7-79-178i. November 1979. pp. 5-5 and 5-17. 10. Letter from Solt, J.C., Solar Turbines Incorporated, to Noble, E., EPA. October 19, 1984. Development cost for wet control for stationary gas turbines. 11. Chemical Marketing Reporter. Volume 233. Number 1. January 4, 1988. 12. Reference 7, p. 2-29. 3.6-8 ------- 13. Bowen, M.L. and M.S. Jennir-~s. (Radian Corporation). Cost of Sulfur Dioxide, Particulate Matter, and Nitrogen Oxide Controls in Fossil Fuel Fired Industrial Boilers. Prepared for the U. S. Environmental Protection Agency. Research Triangle Park, NC. Publication No. EPA-450/3-82-021. August 1982. pp. 2-17 and 2-18. 3.6-9 ------- 3.7 DETERMINATION OF RETROFIT FACTORS AND SCOPE ADDER COSTS The costs of air pollution control device (APCD) installation at an existing plant are greater than at a new facility due to higher construction costs imposed by site access and congestion, longer duct runs caused by space limitations, 2nd the need to demolish and relocate some existing facilities. Procedures for estimating these costs at MWC's were adapted from procedures developed for the Electric Power Research Institute (EPRI) for retrofitting APCD's at existing electric generating plants.* These additional costs are divided into two types of adjustments: retrofit multipliers (discussed in Section 3.7.1) and scope adders (discussed in Section 3.7.2). 3.7.1 Retrofit Factors Site-specific retrofit factors can be estimated based on access and congestion problems associated with retrofitting APCD's at existing plants. Depending on the level of accessibility and congestion, one of four factors (ranging from 1.02 to 1.42) is recommended based on the guidelines shown in Table 3.7-1. The total direct costs of new APCD equipment excluding ductwork 2 are multiplied by this retrofit factor to estimate retrofit costs. 3.7.2 Scope Adders Scope adders are site-specific costs for additional ducting, chimneys, demolition, or any other major items that can be included in retrofit cost estimates in addition to the main control system equipment. Estimating procedures for some common scope adders are described here. 3.7.2.1 Ducting. Direct capital costs for ducts are estimated using the equation described in Section 2.2 for new plants. The duct costs are then multiplied by the retrofit factor from Section 3.7.1 to estimate the direct capital cost of ducts for existing plants. Depending on chimney and APCD tie-in difficulties at the model plant, the ductwork retrofit factor may be different than that chosen for the APCD. 3.7.2.2 Stacks. The installed capital cost of stacks 1s estimated from equations developed for industrial boilers.^ Total direct and Indirect capital cost data from one manufacturer were correlated into separate equations for lined and unlined stacks, and for stacks larger and smaller than 3.7-1 ------- TABLE 3.7-1. SITE ACCESS AND CONGESTION FACTORS FOR RETROFITTING APCD EQUIPMENT AT EXISTING PLANTS3 Retrofit factor Congestion level Guidelines for selecting retrofit factor 1.02 Br.re Case Interferences similar to a new plant with adequate crew work space. Free access for cranes. Area around combustor and stack adequate for standard layout of equipment. 1.08 Low Some aboveground interferences and work space limitations. Access for cranes limited to two sides. Equipment cannot be laid out in standard design. Some equipment must be elevated or located remotely. 1.25 Medium Limited space. Interference with existing structures or equipment which cannot be relocated. Special designs are necessary. Crane access limited to one side. Majority of equipment elevated or remotely located. 1.42 High Severely limited space and access. Crowded working conditions. Access for cranes blocked from all sides. Reference 4. 3.7-2 ------- 5 feet In diameter (stacks larger than 5 feet in diameter and 100 feet tall are normally tapered). For a lined acid-resistant stack, the equations for direct and indirect capital cost, updated to December 1987 dollars, are: Cost, 103 $ = [26.2 + 0.089 x (HJ x (1 + 4.14 D)] for D > 5 ft and Cost, 103 $ = [26.2 + 0.080 x (H) x (1 + 4.33 D)] for D < 5 ft For an unlined stack, the equations are: Cost, 103 $ ป [26.2 + 0.0625 x (H) x (1 + 2.59 D)] for D > 5 ft and Cost, 103 S - [26.2 + 0.087 x (HJ x (1 + 2.20 D)] for D < 5 ft, where H = stack height, ft and D ~ stack diameter, ft. To estimate the total capital costs, the direct and indirect costs are increased by 20 percent to account for contingency. 3.7.2.3 Demolition and Replacement. Costs for demolition of existing buildings required for installation of new APCD equipment are estimated according to EPRI guidelines.^ In general, demolition cost is estimated by multiplying the amount of material to be demolished or moved (i.e., square feet of building space) by an appropriate cost factor in Reference 5. These estimates are made on a plant-specific basis as needed. Costs for demolition or replacement of existing equipment such as ductwork, fans, and ESP's are assumed to be the same as the costs for installing the same equipment. 3.7-3 ------- REFERENCES 1. Stearns Catalytic Corporation. Retrofit FGD Cost-Estimating Guidelines. Prepared for Electric Power Research Institute. Palo Alto, CA. Publication No. CS-3696. October 1984. 2. Reference 1. pp. 4-1 to 4-3. 3. Bowen, M.L. and M.S. Jennings (Radian Corporation). Costs of Sulfur Dioxide, Particulate Matter, and Nitrogen Oxides Controls on Fossil Fuel-Fired Industrial Boilers. Prepared For the U. S. Environmental Protection Agency. Research Triangle Park, NC. Publication No. EPA-450/3-S2-021. August 1982. p. 2-11. 4. Reference 1. p. 5-4. 5. Reference 1. pp. 4-9 to 4-14. 3.7-4 ------- 3.8 DOWNTIME COSTS FOR RETROFIT MODIFICATIONS In many situations, the retrofit equipment cannot be installed during a normally scheduled maintenance shutdown and thus will result in additional downtime and loss of MWC revenues during retrofit. The loss of revenue is mainly from: (1) a loss of steam and/or electrical sales and (2) a loss of tipping fees from receiving MSW. It is assumed that the work force at the facility would be productive during the downtime period and that the cost of idle workers can be ignored. To estimate the downtime costs due to loss of revenue, the length of downtime required to install the APCD must be estimated. Table 3.8-1 presents ranges of unit downtimes required to apply combustion control and install various APCD's on existing MWC facilities. Once the downtime period is estimated, Sections 3.8.1 and 3.8.2 present the procedures used to estimate costs for the loss of steam and electrical sales and the loss of tipping fees, respectively. Costs attributed to the loss of revenue are treated as a one-time cost that is annualized over the useful life of the APCD. 3.8.1 Procedures to Estimate Loss of Steam and Electricity Sales 3.8.1.1 Loss of Steam Sales. To estimate the costs of loss of steam during downtime, the amount of steam that would have been generated during the downtime period is multiplied by a sales price for steam (typically in dollars per 1,000 lb of steam). A typical steam price in December 1987 dollars is $5.50/1,000 lb of steam.^ For example, the lost revenues from steam sales for a facility normally producing 10,000 lb/hr of steam are $1,320 per day (i.e., $5.50/1,000 lbs steam times 10,000 lbs steam/hr times 24 hours). 3.8.1.2 Loss of Electricity Sales. The cost of lost electricity sales is estimated by multiplying the amount of lost electricity generation by the electricity price. The electricity price is assumed to be the same as the electrical cost rate used in this report to estimate APCD electricity costs ($0.046/kWh in December 1987 dollars). Applying this procedure, the cost of lost electricity sales for a facility with a 1,000 kW capacity turbine is $1,100 per day (i.e., $0.046/kWh times 1,000 kW times 24 hours). 3.8-1 ------- TABLE 3.8-1. DOWNTIME REQUIREMENTS IN MONTHS' Combustor downtime (months) Combustion Modifications ESP-Rebuild ESP-Add plate area Retrofit Spray Dryer Retrofit Sorbent Injection Humidi fication 0.Z5-4 1-2 0.5-11 l' 0.5-1* 0.25-1 aReference 2. ^If there are significant space limitations, up to an additional 6 months could be required. 3.8-2 ------- 3.8.2 Prccsdures to Estimate Cofts from Loss of Tipping Fees Downtime costs associated with loss of tipping fees are estimated by multiplying an appropriate tipping fee (typically $25/ton) by the increase in tonnage of solid waste disposal. The increase in solid waste is the amount of feed that would have been reduced in the combustor plus the fly ash that would have been collected by the existing PM control device, if the combustor were operating during the downtime period. For example, if the weight of MSW fed to a 100 tpd combustor is reduced by 75 weight percent during combustion (including bottom ash and fly ash), the tonnage of solid waste to be disposed would increase from 25 tpd during combustor operation up to 100 tpd when the unit is shut down. The increase in solid waste disposal costs is approximately $1,880, based on a S25/ton tipping fee (i.e., $25/ton times 75 tons per day). 3.8-3 ------- REFERENCES Electric Power Research Institute. TAC-Technical Assessment Guide (Volume 1: Electricity Supply]986). Palo Alto, CA. EPRI No. P-4463-SR, December 1986. p. B-4. Memorandum from White, D.M. and J.T. Waddell, Radian Corporation, to R.E, Myers, EPA/1 SB. June 3, 1988. Time Requirements for Retrofit of Particulate Matter (PM), Acid Gas, and Temperature Control Technologies on Existing Municipal Waste Combustors (MWC's). 3.8-4 ------- TECHNICAL REPORT DATA fPlease read Jnsimcnons un ihe reverse bejore comptelingi 1. REPORT NO. EPA-450/3-89-27a 3. RECIPIENT'S /^CESSION fclO_ >6 90 lo 4 0 4 0 MS 4. title andsubtitle Municipal Waste Combustors - Background Information foi Proposed Standards: Cost Procedures S. REPORT DATE August 1989 6. PERFORMING ORGANIZATION CODE 7. AUTHOR(S) 8. PERFORMING ORGANIZATION REPORT NO. 9. performing organization name and address Orrice of Air Quality Planning and Standards U. S. Environmental Protection Agency Research Triangle Park, North Carolina 27711 IC. PROGRAM ELEMENT NC ii contract/grant no 68-02-4378 12. sponsoring agency name and aodress DAA for Air Quality Planning and Standards Office of Air and Radiation U.S. Environmental Protection Agency Research Triangle Park, North Carolina 27711 13. TYPE OF REPORT AND PERIOD COVERED F inal 14 SPONSORING AGENCY CODE 200/04 15 SUPPLEMENTARY NOTES 16. ABSTRACT Cost Procedures for the costing of new and existing municipal waste combustor facilities and associated equipment are presented. Cost procedures are developed for combustors, heat recovery equipment, humidification equipment, air pollution control devices for the reduction of particulate matter and acid gas emissions, and continuous emission monitoring equipment. Costs in this report are divided into capital costs, operating and maintenance costs, and annualized costs. Costs associated with retrofitting existing facilities are also presented. 17, KEY WORDS AND OOCUMENT ANALYSIS a. DESCRIPTORS b. 1 DENT1 F 1E RS/OPEN ENDED TERMS c. COSATI Field,'Croup Air Pollution Municipal Waste Combustors Incineration Pollution Control Costs Air Pollution Control 13B 18. DISTRIBUTION STATEMENT 19. SECURITY CLASS /This Report; Unclassified 21 NO. CP PAGES I * w 20. SECURITY CLASS ( This page / Unclassified 22. PRICE EPA Form 2220-1 (Rซป. 4-771 previous edition is obsolete ------- |