DRY FLUE GAS DESULFURIZATION TECHNOLOGY EVALUATION

PROJECT NUMBER 11311-000

PREPARED FOR

NATIONAL LIME ASSOCIATION

SEPTEMBER 2002

PREPARED BY

55 East Monroe Street

Chicago, IL 60603-5780 USA
LEGAL NOTICE 

This report was prepared by Sargent & Lundy LLC (Sargent & Lundy) expressly for National 

Lime Association. Neither Sargent & Lundy nor any person acting on its behalf (a) makes any 

warranty, express or implied, with respect to the use of any information or methods disclosed in 

this report or (b) assumes any liability with respect to the use of any information or methods 

disclosed in this report. 
DRY FLUE GAS DESULFURIZATION

TECHNOLOGY EVALUATION

PROJECT NUMBER 11311-000 

SEPTEMBER 26, 2002

NATIONAL LIME ASSOCIATION

 CONTENTS 

 

SECTION PAGE

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1. FLUE GAS DESULFURIZATION (FGD) DESCRIPTION......................................................... 1 

1.1 Process Chemistry ........................................................................................................................................................1 

1.2 Reagents and Waste Products.....................................................................................................................................1 

1.3 Commercial Status .......................................................................................................................................................2 

2. DRY FGD PROCESS ADVANTAGES AND DISADVANTAGES COMPARED TO WET 

FGD TECHNOLOGY.............................................................................................................................. 3 

2.1 Process Advantages......................................................................................................................................................3 

2.2 Process Disadvantages..................................................................................................................................................4 

3. DESIGN BASIS ................................................................................................................................. 5 

3.1 Specific Design Criteria – Dry FGD............................................................................................................................5 

3.2 System Design (Subsystems)........................................................................................................................................6 

3.2.1 Reagent Handling and Preparation ........................................................................................................................7 

3.2.2 SO2 Removal..........................................................................................................................................................7 

3.2.3 Baghouse................................................................................................................................................................8 

3.2.4 Flue Gas System/Stack ..........................................................................................................................................8 

3.2.5 Waste Handling .....................................................................................................................................................8 

3.2.6 General Support.....................................................................................................................................................8 

3.2.7 Miscellaneous ........................................................................................................................................................8 
DRY FLUE GAS DESULFURIZATION

TECHNOLOGY EVALUATION

PROJECT NUMBER 11311-000 

SEPTEMBER 26, 2002

NATIONAL LIME ASSOCIATION

 CONTENTS 

 

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4. IDENTIFICATION OF APPLICATION CONSTRAINTS........................................................ 11 

4.1 Unit/Absorber Size .....................................................................................................................................................11 

4.2 Coal Sulfur Content ...................................................................................................................................................11 

4.3 Performance Expectations.........................................................................................................................................11 

4.4 SO2 Reduction.............................................................................................................................................................12 

4.5 Reagent Utilization .....................................................................................................................................................12 

4.6 Waste/By-Product Quality.........................................................................................................................................13 

4.7 Energy Consumption..................................................................................................................................................13 

4.8 Retrofit Versus New Units.........................................................................................................................................13 

5. COSTS ANALYSIS......................................................................................................................... 14 

5.1 Capital Costs...............................................................................................................................................................14 

5.2 Operations and Maintenance Costs..........................................................................................................................15 

5.2.1 Fixed O&M Costs................................................................................................................................................15 

5.2.2 Variable O&M Costs...........................................................................................................................................16 

5.3 Levelized Costs............................................................................................................................................................16 
DRY FLUE GAS DESULFURIZATION

TECHNOLOGY EVALUATION

PROJECT NUMBER 11311-000 

SEPTEMBER 26, 2002

NATIONAL LIME ASSOCIATION

 

 EXHIBITS

NLA-DryFGD 

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NUMBER TITLE

5-1 Capital Cost Estimates for New Units 

5-2 Capital Cost Estimates for Retrofit Units 

5-3 Fixed and Variable O&M Cost Estimates for New Units 

5-4 Fixed and Variable O&M Cost Estimates for Retrofit Units 
DRY FLUE GAS DESULFURIZATION

TECHNOLOGY EVALUATION

PROJECT NUMBER 11311-000 

SEPTEMBER 26, 2002

NATIONAL LIME ASSOCIATION

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REPORT PREPARED, REVIEWED, AND APPROVED BY SARGENT & LUNDY LLC: 

Prepared by: September 26, 2002 

Raj Gaikwad Date

Technical Advisor

Reviewed by: Willard L. Boward September 26, 2002 

Technical Advisor Date

Approved by: September 26, 2002 

William DePriest Date

Project Director
DRY F PROJECT NUMBER 11311-000 LUE GAS DESULFURIZATION

TECHNOLOGY EVALUATION

SEPTEMBER 26, 2002

NATIONAL LIME ASSOCIATION

1. FLUE GAS DESULFURIZATION (FGD) DESCRIPTION

Lime-spray drying (LSD) is a dry scrubbing process that is generally used for low-sulfur coal. LSD FGD 

systems are typically located after the air preheaters, and the waste products are collected either in a baghouse 

or electrostatic precipitator. However, to achieve sulfer dioxide (SO2) reduction above 80% with good 

reagent use, the dry scrubber is generally followed by a baghouse. 

Flue gas is treated in an absorber by mixing the gas stream concurrently with atomized lime slurry droplets. 

The lime slurry is atomized through rotary cup spray atomizers or through dual fluid nozzles. Some of the 

water in the spray droplets evaporates, cooling the gas at the inlet from 300°C or higher to 160°F to 180°F, 

depending on the relationship between approach to saturation and removal efficiency. The droplets absorb 

SO2 from the gas and react the SO2 with the lime in the slurry. The desulfurized flue gas, along with reaction 

products, unreacted lime, and the fly ash passes out of the dry scrubber to the baghouse. 

1.1 PROCESS CHEMISTRY

The SO2 absorbed in the atomized slurry reacts with lime in the slurry to form calcium sulfite (CaSO3) in the 

following reaction: 

SO2 + CaO + 1/2 H2O ⇒ CaSO3• 1/2 H2O 

A part of the CaSO3 reacts with oxygen in the flue gas to form calcium sulfate (CaSO4): 

CaSO3 + 1⁄2O2 + 2H2O ⇒ CaSO4•2H2O 

1.2 REAGENTS AND WASTE PRODUCTS

Preparation of the lime slurry reagent involves slaking lime in a conventional lime slaker with a high 

efficiency grit removal and lime recovery system. The slaked lime is held in an agitated tank for use. The 

slurry reagent is fed to the absorber to replenish lime consumed in the reaction, and the feed rate is typically

controlled based on the removal efficiency required. 

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The waste product contains CaSO3, CaSO4, calcium hydroxide, and ash. 

1.3 COMMERCIAL STATUS

LSD FGD systems are in operation at many facilities, ranging in size from less than 10 MW to 500 MW 

(multiple modules are required for plants greater than 300 MW in capacity). For eastern bituminous coals, 

some FGD vendors have proposed modules for units sized up to 350 MW. Applications include commercial 

units with coal sulfur as high as 2.0%. LSD systems with rotary or dual fluid atomizers are available from a 

number of vendors including: 

• Alstom Environmental Systems 

• Babcock & Wilcox 

• Hamon Research Cottrell 

• Wheelabrator Air Pollution Control 

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2. DRY FGD PROCESS ADVANTAGES AND DISADVANTAGES COMPARED TO WET FGD 

TECHNOLOGY

2.1 PROCESS ADVANTAGES

The dry FGD process has the following advantages when compared to wet limestone FGD technology: 

1. The absorber vessel can be constructed of unlined carbon steel, as opposed to lined carbon 

steel or solid alloy construction for wet FGD. Typically, for units less than 300 MW, the 

capital cost is lower than for wet FGD. Typically, for units larger than 300 MW, multiple 

module requirements causes the dry FGD process to be more expensive than the wet FGD 

process. 

2. Pumping requirements and overall power consumption are lower than for wet FGD systems. 

3. Waste CaSO3, CaSO4, and calcium hydroxide are produced in a dry form and can be 

handled with conventional pneumatic fly ash handling equipment. 

4. The waste is stable for landfilling purposes and can be disposed of concurrently with fly ash. 

5. The dry FGD system uses less equipment than does the wet FGD system, resulting in fixed, 

lower operations and maintenance (O&M) labor requirements. 

6. The pressure drop across the absorber is typically lower than for wet FGD. 

7. High chloride levels improve (up to a point), rather than hinder, SO2 removal performance. 

8. Sulfur trioxide (SO3) in the vapor above approximately 300°F, which condenses to liquid 

sulfuric acid at a lower temperature (below acid dew point), is removed efficiently with a 

spray dryer-baghouse. Wet limestone scrubbers capture less than 25% to 40% of SO3 and 

would require the addition of a wet electrostatic precipitator to remove the balance or 

hydrated lime injection. The emission of sulfuric acid mist, if above a threshold value, may

result in a plume visible after the vapor plume dissipates. 

9. Flue gas following a spray dryer is unsaturated with water (30°F to 50°F above dew point), 

which reduces or eliminates a visible moisture plume. Wet limestone scrubbers produce flue 

gas that is saturated with water, which requires a gas-gas heat exchanger to reheat the flue gas 

to operate as dry stack. Due to the high costs associated with heating the flue gas, all recent 

wet FGD systems in the United States have used wet stack operations. 

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10. Dry FGD systems have the capability of capturing a high percentage of gaseous mercury in 

the flue gas if the mercury is in the oxidized form. Further, due to the nature of the filter cake 

present in the fabric filter associated with LSD, the LSD equipment with a fabric filter will 

tend to capture a higher percentage of oxidized mercury than would LSD equipment with an 

electrostatic precipitator. The major constituent that will influence the oxidation level of 

mercury in the flue gas has been identified as chlorine. Considering the typical level of 

chlorine in coals in the United States, we can expect that LSD systems applied to high 

chlorine bituminous coals will tend to capture a high percentage of the mercury present in the 

flue gas. Conversely, LSD systems applied to low-chlorine sub-bituminous coals and lignite 

will not capture a significant amount of the mercury in the flue gas. 

11. There is no liquid waste from a dry FGD system, while wet limestone systems produce a 

liquid waste stream. In some cases, a wastewater treatment plant must be installed to treat the 

liquid waste prior to disposal. The wastewater treatment plant produces a small volume of 

waste, rich in toxic metals (including mercury) that must be disposed of in a landfill. A dry

FGD system provides an outlet for process wastewater from other parts of the plant when 

processing residue for disposal. 

2.2 PROCESS DISADVANTAGES

The dry FGD process has the following disadvantages when compared to limestone wet FGD technology: 

1. The largest absorber module used in the industry is 250 MW to300 MW. Some suppliers of 

dry FGD systems have proposed absorbers as large as 350 MW for eastern bituminous coalfired units. For units sized at 500 MW, two modules will be required. This will also result in 

large inlet and outlet ductwork and damper combinations. 

2. The process uses a more expensive reagent (lime) than limestone-based FGD systems and the 

reagent has to be stored in a steel or concrete silo. 

3. Reagent utilization is lower than for wet limestone systems to achieve comparable SO2

removals. The lime stoichiometric ratio is higher than the limestone stoichiometric ratio (on 

the same basis) to achieve comparable SO2 removals. 

4. Dry FGD produces a large volume of waste, which does not have many uses due to its 

properties, i.e., permeability, soluble products, etc. Researchers may yet develop some

applications where the dry FGD waste can be used. Wet FGD can produce commercial-grade 

gypsum. 

5. Combined removal of fly ash and waste solids in the particulate collection system precludes 

commercial sale of fly ash if the unit is designed to remove FGD waste and fly ash together. 

In some cases, FGD could be backfit after the existing electrostatic precipitator, which would 

allow the sale of fly ash. 

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3. DESIGN BASIS

3.1 SPECIFIC DESIGN CRITERIA – DRY FGD 

Table 3.1-1 lists the specific design criteria. 

TABLE 3.1-1 

SPECIFIC DESIGN CRITERIA

Unit capacity 500 MW 500 MW 

Heat input to boiler, MBtu/hr 5,000 5,186

Fuel Low-sulfur - Appalachian Low-sulfur - Powder River 

Basin 

Fuel analysis, % wt.: 

Moisture 6.0 30.4

Ash 9.1 6.4

Carbon 72.6 47.8

Hydrogen 4.8 3.4

Nitrogen 1.4 0.7

Sulfur 1.3 0.6

Oxygen 4.7 10.8

Chlorine 0.1 0.03

High heating value, Btu/lb 13,100 8,335 

SO2 generation, lb/Mbtu 2.0 1.44 

Coal feed rate, tons/hr 191 311 

Flue gas flow at FGD inlet, macfm 1.79 1.97 

Flue gas temperature at FGD inlet, °F 280 280

Flue gas flow at FGD outlet, macfm 1.60 1.75 

Flue gas temperature at FGD outlet, 

°F 

160 165

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TABLE 3.1-1 

SPECIFIC DESIGN CRITERIA

SO2 reduction efficiency, % 94 93 

SO2 outlet, lb/MBtu 0.120 0.10 

Mercury concentration in coal, ppmd 0.06-0.10 0.08-0.12 

Table 3.1-2 summarizes the parameters used for the FGD comparison. 

TABLE 3.1-2 

PARAMETERS USED FOR FGD COMPARISON

Unit Capacity 500 MW 500 MW 

Heat input to boiler, MBtu/hr 5,000 5,186 

Fuel Low-sulfur - Appalachian Low-sulfur - Powder River 

Basin 

SO2 removal, % 94 93 

SO2 emission, lb/MBtu 0.12 0.10 

Byproduct Dry waste Dry waste 

Power consumption, % 0.65 new (without baghouse), 

1.1 for retrofit 

0.70 new (without baghouse), 

1.2 for retrofit 

Reagent High calcium lime High calcium lime 

Reagent cost, $/ton 60 60 

Reagent purity, % 93 93 

Reagent stoichiometry, moles of 

CaO/mole of inlet sulfur 

1.4 1.1

Load factor 80 80 

FGD system life, years 30 (new)/20 (retrofit) 30 (new)/20 (retrofit) 

Capital cost leveling factor, %/year 14.5 (new)/15.43 (retrofit) 14.5 (new)/15.43 (retrofit) 

Discount rate, % 8.75 8.75 

Inflation rate, % 2.5 2.5 

Operating cost levelization factor 1.30/1.22 1.30/1.22 

3.2 SYSTEM DESIGN (SUBSYSTEMS) 

The FGD system overall design consists of the following subsystems: 

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3.2.1 Reagent Handling and Preparation 

Lime is received by truck (or barge) and conveyed to storage. Lime is stored in a 14-day capacity bulk storage 

lime silo. The lime is pneumatically conveyed to a 16-hour capacity day bin. The lime day bin and a gravimetric 

feeder supplies the lime to a 150% slaking system. This will allow two shift operations for the unit operating 

continuously at 100% load. A conventional lime slaker with high-efficiency grit removal and lime recovery

system is used. Two 100% capacity slurry transfer pumps are used to provide high reliability to transfer the slurry

to the slurry tank. The process makeup water is added to the slaker to produce 20% solids slurry. The slurry is 

diluted on line, if required, prior to injection into an absorber. The slurry is fed to the absorber by a dedicated 

reagent feed pump (100% spare capacity provided). 

3.2.2 SO2 Removal 

Two absorbers, each treating 50% of the flue gas, are provided to achieve 93% to 94% SO2 removal efficiency in 

the absorber and baghouse. The absorber is a vertical, open chamber with concurrent contact between the flue gas 

and lime slurry. The slurry is injected into the tower at the top using a rotary atomizer to remove SO2. A spare 

rotary atomizer is provided. The hopper in the bottom of the carbon steel absorber also removes large particles 

that may drop in the absorber. The absorber will be operated at 30°F adiabatic approach to saturation temperature. 

In the past, a lower approach had been proposed. However, over the years, operational problems associated with 

the lower adiabatic approach to saturation temperature, due to wetting of the walls and large deposits in the 

absorber, were alleviated by designs with 30°F adiabatic approach to saturation temperature. 

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3.2.3 Baghouse 

A pulse-jet baghouse with air to cloth ratio of 3.5 ft/min is provided. The baghouse is provided with a spare 

compartment for off line cleaning to maintain the opacity at 10% or less. The waste will be pneumatically

conveyed to a waste storage silo with a 3-day storage capacity, which is in accordance with typical utility design. 

3.2.4 Flue Gas System/Stack 

The flue gas from the air preheater will be sent to the absorbers. The gases from the absorber will be sent to the 

baghouse to collect the waste products and the fly ash. The booster fan is sized to provide an additional 16”H2O 

(12" w.c. operating) pressure drop through the absorber and baghouse. The existing stack will be used for the 

retrofit case. 

3.2.5 Waste Handling 

The waste will be collected in the baghouse. A portion of the waste will be stored in a recycle storage silo, which 

will then be used to mix with lime slurry to increase the reagent utilization. Pug mills (2 x 100%) are provided to 

treat the dry FGD waste before it is loaded onto the trucks for disposal or sale. 

3.2.6 General Support 

The general support equipment includes the seal water system, instrument air compressor, makeup water system, 

and control room. 

3.2.7 Miscellaneous 

Equipment considered as miscellaneous includes onsite electrical power equipment, such as transformers and 

grounding, which is required to supply electrical power to the FGD system. 

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Table 3.2–1 lists the equipment used in each subsystem.

TABLE 3.2-1 

EQUIPMENT USED IN EACH SUBSYSTEM

Reagent Handling and Preparation 

Truck unloading system

Lime bulk storage steel silo (14 days’ storage) 

Lime live storage transport 

Lime day bin (16 hours’ storage) 

Slaker with screen (150% capacity) 

Lime slurry tank (16 hours’ storage) 

Lime slurry feed pump (2 x 100%) 

SO2 Removal System

Spray dryer (2 x 50%) 

Rotary atomizer (3 x 50% -2 operating and 1 spare) 

Spray dryer solid conveying 

Baghouse System 

Pulse jet baghouse (air to cloth ratio – 3.5 ft/min) 

Baghouse inlet ductwork 

Baghouse outlet ductwork 

Waste unloading system

Waste storage steel silo (3 days’ storage) 

Flue Gas System 

Booster induced draft fans (2 x 50%) 

Absorber inlet ductwork/dampers 

Absorber outlet ductwork/dampers 

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TABLE 3.2-1 

EQUIPMENT USED IN EACH SUBSYSTEM

Waste Handling and Recycle System 

Recycle waste storage bin (16 hours’ storage) 

Recycle waste conveying 

Recycle waste slurry tank 

Pug mills (2 x 100%) 

General Support System 

Slaking water tank 

Slaking water pumps (2 x 100%) 

Instrumentation/plant air compressors (2 x 50%) 

Miscellaneous 

Transformers/switchgear 

Electrical wiring, cables, etc. 

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4. IDENTIFICATION OFAPPLICATION CONSTRAINTS

Summarized below are the application constraints that we have identified. 

4.1 UNIT/ABSORBER SIZE

LSD FGD systems are in operation at many facilities, ranging in size from less than 10 MW to 500 MW. 

However, multiple modules are required for plants greater than 250 MW to300 MW in capacity. 

4.2 COAL SULFUR CONTENT

LSD FGD systems are applied mainly to low-sulfur coal. Most of these systems are applied to inlet SO2 less 

than 2.0 lb/MBtu. These systems are based on Powder River Basin and western bituminous coal. The 

systems installed on low-sulfur eastern bituminous coal have SO2 concentrations as high as 3.0 lb/MBtu. 

Sargent & Lundy’s database of dry FGD systems indicates that these systems are not installed on high-sulfur 

bituminous coals.

4.3 PERFORMANCE EXPECTATIONS

The first generation of dry FGD systems was designed to achieve 70% SO2 reduction efficiencies. This was 

done primarily to comply with the New Source Performance Standards (NSPS) for low-sulfur coals. 

However, further experience with Powder River Basin coal has prompted suppliers of dry FGD equipment to 

guarantee SO2 reduction efficiencies up to 94% or 0.10 lb/MBtu, whichever is achieved first. Applying this 

recent experience to the FGD system described in Table3.1-1, with the inlet SO2 from Powder River Basin 

fuel of 1.44 lb/MBtu, 94% reduction will result in an outlet emission of 0.086 lb/MBtu. This emission rate is 

less than 0.10 lb/Mbtu; hence, the SO2 outlet of 0.10 lb/MBtu becomes the standard, which results in an 

overall SO2 reduction efficiency of 93%. Figure 4.3-1 represents the maximum achievable SO2 reduction for 

a dry FGD system with baghouse as it relates to the sulfur content in the coal. Figure 4.3-1 is derived from

Sargent & Lundy’s in-house database on the technology performance, as obtained from various suppliers of 

FGD systems. 

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FIGURE 4.3-1 

RELATION BETWEEN INLET SO2 TO DRY FGD AND SO2 REDUCTION EFFICIENCY

F ig u r e 1: R e la tio n B e tw e e n In le t S O 2 t o D r y F G D a n d S O 2 R e d u c tio n E ffic ie n c y

7 0

7 5

8 0

8 5

9 0

9 5

1 0 0

0 0 .5 1 1 . 5 2 2 . 5 3 3

l b s S O 2 /m m B t u

% SO2 Reduction

.5

4.4 SO2 REDUCTION

Suppliers of FGD systems have guaranteed SO2 reduction efficiencies up to 94% or 0.10 lb/MBtu, whichever 

is achieved first, with a dry scrubber- baghouse combination. This limits the inlet SO2 level to 1.7 lb/MBtu. 

Suppliers of FGD systems were reluctant to provide Sargent & Lundy with higher removal guarantees, 

primarily due to the absence of any database. 

4.5 REAGENT UTILIZATION

The reagent utilization is limited due to the mass transfer limitations. Suppliers of FGD systems are using 

alkalinity in the waste by recycling the waste along with the active reagent. The alkalinity of Powder River 

Basin ash has resulted in good reagent utilization compared to acidic fly ashes from eastern bituminous coal. 

For example, to achieve a reduction efficiency of 90% SO2, a stoichiometric ratio of 1.1 could be used 

compared to 1.4 stoichiometric ratio for bituminous coals with waste recycling. The stoichiometric ratio for 

dry FGD is based on the inlet SO2 concentration. 

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4.6 WASTE/BY-PRODUCT QUALITY

The waste product contains CaSO3, CaSO4, calcium hydroxide, and ash. This material cannot be used in the 

cement industry or wallboard; however, there is potential for use as agricultural soil conditioning and for 

preparation of bricks or aggregates by mixing with other waste components such as fly ash. If there is 

currently significant income from the sale of fly ash, it may be prudent to install the dry FGD/baghouse 

combination after the existing particulate collector, such that the fly ash is segregated from the LSD waste and 

can continue to be sold. 

4.7 ENERGY CONSUMPTION

The major energy consumption is due to the pressure drop across the dry scrubber. Almost 60% to 70% of 

the energy required for FGD operation is due to an increase in draft (6-8” w.c., including inlet and outlet 

ductwork) and 25% to 35% of the energy required is for the atomizers. 

4.8 RETROFIT VERSUS NEW UNITS

The LSD system is installed between the air heater outlet and particulate collector. Most existing units have 

very short ductwork between the air heater outlet and electrostatic precipitator inlet. This makes it very

difficult to take the gas from the air heater outlet to the LSD equipment and return it to the electrostatic 

precipitator inlet. Also, most existing electrostatic precipitators are not designed to handle increased 

particulate loading resulting from the LSD waste products. This will require modifications to the existing 

electrostatic precipitator to accommodate collection of the additional particulate from the LSD. In addition, 

the electrostatic precipitator will capture only a small percentage of the SO2 (5% to 10%), placing a high 

burden on the LSD for SO2 removal. An added benefit of this LSD/FF combination is that the existing 

electrostatic precipitator can remain in service with the collected fly ash available for sale. 

Considering these issues associated with using an existing electrostatic precipitator for particulate and SO2

capture downstream of a retrofit LSD, employing a new fabric filter that can achieve 15% to 20% SO2 capture 

and that can accommodate the LSD particulate loading, may be a more attractive alternative.

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5. COSTS ANALYSIS

5.1 CAPITAL COSTS

Estimated capital costs for the dry FGD system were determined for new and retrofit applications, which 

includes the equipment, materials, structural, and electrical components associated with the retrofit 

installation of these technologies. 

The costs were developed using Sargent & Lundy’s database as well as price quotes obtained from

manufacturers for the equipment/work needed. 

The capital cost estimates provided herein are essentially “total plant cost,” and include the following: 

• Equipment and material 

• Direct field labor 

• Indirect field costs and engineering 

• Contingency

• Owner's cost 

• Allowance for funds during construction (AFUDC) 

• Initial inventory and Spare parts (1% of the process capital) 

• Startup and commissioning 

Finally, the capital cost estimates provided do not include taxes and property tax. License fees and royalties 

are not expected for the proposed control strategies. 

Salient features of each capital cost estimate prepared for FGD installations include: 

• Demolition of existing ductwork to provide access to the flue gas from the air heater outlet 

• Inlet and outlet ductwork to absorber and baghouse 

• 2 x 50% absorbers 

• Baghouse 

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• Induced draft fan modifications for retrofit application 

• Auxiliary power system upgrade (for retrofit) 

No range estimate was performed to assess the relative accuracy of this budgetary estimate. Based on 

experience, it is believed that the relative accuracy of the estimate is ±20%. 

Additionally, the underlying assumption, unless specifically stated otherwise, is that the contracting 

arrangement for the project is large, multiple lump sum work packages. If the client expects to execute the 

project on an engineer, procure, construct or turnkey basis, a separate risk allocation should be added to the 

estimate of 5% to 20% (1.05 or 1.2 multiplier) for this method of construction, with actual value dependent on 

the relative risk of labor, construction difficulty, etc. 

Exhibit 5–1 and Exhibit 5–2 present the capital costs for new units and retrofit units, respectively.

5.2 OPERATIONS AND MAINTENANCE COSTS

Exhibit 5–3 and Exhibit 5–4 present the estimated operations and maintenance (O&M) expenses associated 

with dry FGD systems. These costs include both fixed and variable operating costs, defined as follows: 

5.2.1 Fixed O&M Costs 

The fixed O&M costs determined for this study consist of sulfur oxides (SOX) emission control technology, 

O&M labor, maintenance material, and administrative labor. 

For purposes of this study, the installation of the FGD system has been anticipated to add an additional five 

operators to the current pool of operating labor for new units and eight operators for the retrofit application. It 

is assumed the plant layout for the retrofit application is not optimized, which would require more operating 

labor than for the new unit. 

Maintenance material and labor costs shown herein have been estimated based on technology operating 

experience in the United States and Europe. The maintenance cost includes periodic replacement of atomizers 

and maintenance material for various subsystems, and the labor required to perform the maintenance. 

NLA-DryFGD 

Project Number 11311-000 

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NATIONAL LIME ASSOCIATION

5.2.2 Variable O&M Costs 

Variable O&M costs determined for each technology include the cost of lime, waste disposal, bags and cages 

replacement, water, and power requirements. The cost of fly ash is not included in this study as it is assumed 

that even if the fly ash is currently disposed of or sold, the proposed configuration will not affect the current 

operation. For new unit operations, if the fly ash sale creates significant revenue, an electrostatic precipitator 

can be installed upstream of the dry FGD. This analysis assumes that the ash will be disposed of along with 

FGD waste for the new unit application and thus the only differential cost will be applicable to FGD waste. 

No added penalty for lost production has been included due to forced downtime to maintain the FGD systems 

because the availability (measure of random outage rates) of FGD systems is expected to be greater than 99%. 

 

Auxiliary power costs reflect the additional power requirements associated with the operation of the existing 

induced draft fans as well as the estimated power consumption for atomizers, compressor for baghouse, lime 

preparation system, and various electrical and control users typically needed for FGD operations. The owner 

will be responsible for the power cost of $30/MWH if the power is purchased from the open grid. This cost 

includes the replacement energy and capacity charges. 

Exhibit 5–3 and Exhibit 5–4 present the fixed and variable O&M costs for new and retrofit applications, 

respectively.

5.3 LEVELIZED COSTS

Levelized costs, also referred to as “life cycle costs,” take into account the impacts of capital costs and O&M 

costs during the operation of a plant over the period of analysis. The levelized fixed charge rate (impact due 

to capital cost) was calculated based on an assumption that a typical customer is a regulated utility. The 

levelized fixed charge rate includes depreciation of the property, return on capital (50% debt and 50% equity), 

income tax, property tax, and insurance. Based on 8.75% discount rate and 30-year or 20-year life 

expectancy for new or retrofit facilities, respectively, the levelized fixed charge rates are 14.50% (30-year 

NLA-DryFGD 

Project Number 11311-000 

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NATIONAL LIME ASSOCIATION

life) and 15.43% (20-years life). The levelized cost analysis was performed based on current dollars, as most 

regulated utilities base their analysis on current dollars. 

The levelized O&M cost factor takes into account the discount rate, escalation rate, and annuity rate. The 

levelized O&M cost factors were 1.30 for the 30-year period and 1.22 for the 20-year analysis. 

NLA-DryFGD 

Project Number 11311-000 

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PROJECT NUMBER 11311-000 

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NATIONAL LIME ASSOCIATION

NLA-DryFGD 

Project Number 11311-000 

EXHIBIT 5-1 

CAPITAL COST ESTIMATES FOR NEW UNITS USING 

PRB AND APPALACHIAN LOW SULFUR COALS

DRY FGD

PRB Coal Appalachian Low Sulfur

Subsystems Cost, US$ $/kW Cost, US$ $/kW

 Reagent Feed System 3,810,000 7.6 4,385,000 8.8

 SO2 Removal System 11,700,000 23.4 11,400,000 22.8

 Baghouse System 16,000,000 32.0 15,500,000 31.0

 Flue Gas System 6,550,000 13.1 6,300,000 12.6

 Waste Handling and recycle system 2,600,000 5.2 2,200,000 4.4

 General Support Equipment 550,000 1.1 550,000 1.1

 Miscellaneous Equipment 1,250,000 2.5 1,250,000 2.5

 TOTAL PROCESS CAPITAL (TPC) 42,460,000 85 41,585,000 83

 General Facilities (5% of TPC) 2,123,000 4.2 2,079,000 4.2

 Engineering and Construction Management 4,246,000 8.5 4,159,000 8.3

 Project Contingency (15%) 7,324,000 14.6 7,173,000 14.3

 TOTAL PLANT COST (TPC) 56,153,000 112.3 54,996,000 110.0

 Allowance for Funds (AFUDC - 3.2% of TPC) 1,797,000 3.6 1,760,000 3.5

 Owner's Cost (5% of TPC) 2,808,000 6.0 2,750,000 5.0

 TOTAL PLANT INVESTMENT (TPI) 60,758,000 121.9 59,506,000 118.5

 Inventory Capital (Spare, 1% of TPI) 608,000 1.2 595,000 1.2

 Initial Chemicals and Commissioning (2% of TPI) 1,215,000 2.4 1,190,000 2.4

 Royalties 0 0 0 0

 TOTAL CAPITAL REQUIREMENT (TCR) 62,581,000 126 61,291,000 122

Notes:

1.0 Accuracy of Estimate +-20%

2.0 Labor cost based on regular shift operation

3.0 ID fan and electrical cost is differential
DRY FLUE GAS DESULFURIZATION

TECHNOLOGY EVALUATION

PROJECT NUMBER 11311-000 

SEPTEMBER 26, 2002

NATIONAL LIME ASSOCIATION

NLA-DryFGD 

Project Number 11311-000 

EXHIBIT 5-2 

CAPITAL COST ESTIMATES FOR RETROFIT UNITS USING 

PRB AND APPALACHIAN LOW SULFUR COALS

DRY FGD

PRB Coal Appalachian Low Sulfur

Subsystems Cost, US$ $/kW Cost, US$ $/kW

 Reagent Feed System 4,645,000 9.3 5,338,000 10.7

 SO2 Removal System 15,100,000 30.2 14,500,000 29.0

 Baghouse System 19,000,000 38.0 17,000,000 34.0

 Flue Gas System 8,690,000 17.4 8,350,000 16.7

 Waste Handling and recycle system 3,400,000 6.8 2,800,000 5.6

 General Support Equipment 550,000 1.1 550,000 1.1

 Miscellaneous Equipment (Additional 4,250,000 8.5 4,250,000 8.5

 Transformer, Switchgear)

 TOTAL PROCESS CAPITAL (TPC) 55,635,000 111 52,788,000 106

 General Facilities (5% of TPC) 2,782,000 5.6 2,639,000 5.3

 Engineering and Construction Management 5,564,000 11.1 5,279,000 10.6

 Project Contingency (15%) 9,597,000 19.2 9,106,000 18.2

 TOTAL PLANT COST (TPC) 73,578,000 147.2 69,812,000 139.6

 Allowance for Funds (AFUDC - 3.2%) 2,354,000 4.7 2,233,984 4.5

 Owner's Cost (5% of TPC) 3,679,000 7.0 3,491,000 7.0

 TOTAL PLANT INVESTMENT (TPI) 79,611,000 158.9 75,536,984 151.1

 Inventory Capital (Spare, same as new) 608,000 1.2 595,000 1.2

 Initial Chemicals and Commissioning (same as new) 1,215,000 2.4 1,190,000 2.4

 Royalties 0 0 0 0

 TOTAL CAPITAL REQUIREMENT (TCR) 81,434,000 163 77,321,984 155

Notes:

1.0 Accuracy of Estimate +-20%

2.0 Labor cost based on regular shift operation

3.0 ID fan and electrical cost is for adequate modifications to ID fan/motor, additional

 tranformers and switchgears

4.0 Medium Retrofit Difficulty assumed
DRY FLUE GAS DESULFURIZATION

TECHNOLOGY EVALUATION

PROJECT NUMBER 11311-000 

SEPTEMBER 26, 2002

NATIONAL LIME ASSOCIATION

NLA-DryFGD 

Project Number 11311-000 

EXHIBIT 5-3 

FIXED AND VARIABLE O&M COST/LEVELIZED COSTS (NEW UNITS) 

D R Y F G D

In p u t fo r O & M C o s ts

P R B E a s te rn Low S

1 N u m ber of O pera to rs (40 hrs /w k ) 5 5

2 O pera tin g labor C o s t, $/h r 5 0 5 0

3 R eag ent P u rity , % 9 3 9 3

4 R eag ent S to ic h io m e try 1 .1 1 .4

5 R eag ent C o s t, $/to n 6 0 6 0

6 R eag ent R e q u ire m ent, t/h 3 .2 2 6 .5 9

7 S O 2 R e m o v a l E ffic ie n c y , % 9 3 9 4

8 S O 2 R e m o v ed, t/h 2 .8 9 4 .7 0

9 W a s te G enera ted - dry , t/h (w /o fly as h ) 7 .0 1 12.7 4

1 0 W a s te dis pos a l c o s t, $/to n 1 2 1 2

1 1 W a te r R e q u ire m ent, g p m 402 324

1 2 W a te r C o s t, $/1000 g a l 0 .7 5 0 .7 5

1 3 B a g Life , y ears 3 3

1 4 B a g C o s t, $/bag 8 0 8 0

1 5 C a g e Life , y ears 1 2 1 2

1 6 C a g e C o s t, $/c a g e 2 0 2 0

1 7 A u x . P o w e r R e q u ire m ent, M W 6 .0 5 .5

1 8 A u x . P o w e r C o s t, $ /M W H 3 0 3 0

1 9 Load F a c to r, % 8 0 8 0

P R B E a s te rn Low S u lfu r

F ixed O & M C o s ts

1 . O pera tin g Labor C o s t ($ /y r) $520,000 $520,000

2 . M a in tenanc e M a te ria ls C o s t ($ /y r) $1,019,000 $998,000

3 . M a in tenanc e La bor C o s t ($ /y r) $679,000 $665,000

4 . A d m in is tra tiv e and S upport Labor = $360,000 $356,000

 T o ta l Y e a rly F ix e d O & M C o s t = $2,578,000 $2,539,000

V a ria b le O p e ra tin g C o s ts

1 . R eag ent C o s ts = $1,354,000 $2,769,000

2 . W a s te D is pos a l C o s t fo r F G D S y s te m = $589,000 $1,071,000

(D ry b a s is )

3 . C redit fo r B y p roduc t = $ 0 $ 0

4 . B a g repla c e m ent= $375,000 $341,000

5 . C a g e repla c e m e n t= $23,000 $21,000

6 . W a te r C o s t= $127,000 $102,000

7 . A dditional P o w e r C o s ts * = $1,261,000 $1,156,000

 T o ta l Y e a rly V a ria b le O & M C o s t = 3 ,729,000 5 ,460,000

T O TAL Y E A R L Y FIX E D A N D V A R IA B L E O & M C O S 6 ,307,000 7 ,999,000

* In c ludes the pow e r re q u ire m ent fo r reag ent prepara tion and handlin g s y s te m , ID fan fo r 12 " w .c . pre s s u re drop,

pow e r fo r S O 2 C ontro l S y s te m (ro ta ry ato m iz e r), and p o w e r re q u ire m ent fo r bag hous e
DRY FLUE GAS DESULFURIZATION

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PROJECT NUMBER 11311-000 

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NATIONAL LIME ASSOCIATION

NLA-DryFGD 

Project Number 11311-000 

Levelized Costs 

Inputs for Levelized Costs

PRB Eastern Low S

1 FGD System Life, years 30 30

2 Capital Cost Levelization Factor 14.5 14.5

3 Discount rate, %/yr 8.75 8.75

4 Inflation Rate, % 2.5 2.5

5 Operating Cost Levelization Factor 1.30 1.30

Total Capital Cost, M$ 62.6 61.3

Levelized capital Cost, MM$/yr 9.07 8.89

Levelized O&M Cost, MM$/yr 8.20 10.40

Total Levelized Cost, MM$/yr 17.27 19.29

Total cents/kW-hr 0.49 0.55
DRY FLUE GAS DESULFURIZATION

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PROJECT NUMBER 11311-000 

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NATIONAL LIME ASSOCIATION

NLA-DryFGD 

Project Number 11311-000 

EXHIBIT 5-4 

FIXED AND VARIABLE O&M COST/LEVELIZED COSTS (RETROFIT UNITS) 

DRY F G D

In p u t fo r O & M C o s ts

P R B E a s te rn Low S

1 N u m ber o f O p e ra to rs (40 h rs /w k ) 8 8

2 O p e ra tin g la bor C o s t, $/h r 5 0 5 0

3 R e a g ent P u rity , % 9 3 9 3

4 R e a g ent S to ic h io m e try 1 .1 1 .4

5 R e a g ent C o s t, $/to n 6 0 6 0

6 R e a g ent R e q u ire m ent, t/h 3 .2 2 6 .5 9

7 S O 2 R e m o v a l E ffic ie n c y , % 9 3 9 4

8 S O 2 R e m o v e d , t/h 2 .8 9 4 .7 0

9 W a s te G e n e ra te d - d ry , t/h (w /o fly a s h ) 7 .0 1 1 2 .7 4

1 0 W a s te dis p o s a l c o s t, $ /to n 1 2 1 2

1 1 W a te r R e q u ire m e n t, g p m 4 0 2 3 2 4

1 2 W a te r C o s t, $ /1 000 g a l 0 .7 5 0 .7 5

1 3 B a g Life , y e a rs 3 3

1 4 B a g C o s t, $/bag 8 0 8 0

1 5 C age Life , y e a rs 1 2 1 2

1 6 C age C o s t, $/c a g e 2 0 2 0

1 7 A u x . P o w e r R equire m e n t, M W 6 .0 5 .5

1 8 A u x . Po w e r C o s t, $ /M W H 3 0 3 0

1 9 L o ad F a c to r, % 8 0 8 0

P R B E a s te rn Lo w S u lfu r

F ix e d O & M C o s ts

1 . O p e ra tin g Lab o r C o s t ($ /y r) $ 8 32,0 0 0 $ 832 ,0 0 0

2 . M a in te n anc e M a te ria ls C o s t ($ /y r) $ 1 ,0 19,0 0 0 $ 998 ,0 0 0

3 . M a in te n anc e Lab o r C o s t ($ /y r) $ 6 79,0 0 0 $ 665 ,0 0 0

4 . A d m in is tra tiv e an d S u ppo rt La bor = $ 4 53,0 0 0 $ 449 ,0 0 0

 Tota l Y e a rly Fix e d O & M C o s t = $ 2 ,9 83,0 0 0 $ 2 ,944 ,0 0 0

V a ria b le O p e r a tin g C o s ts

1 . R eag e n t C o s ts = $ 1 ,3 54,0 0 0 $ 2 ,769 ,0 0 0

2 . W a s te D is p o s a l C o s t fo r F G D S y s te m = $ 5 89,0 0 0 $ 1 ,071 ,0 0 0

(D ry b a s is )

3 . C redit fo r B y p rodu c t = $ 0 $ 0

4 . B a g re p la c e m e n t= $ 3 75,0 0 0 $ 341 ,0 0 0

5 . C a g e repla c e m e n t= $ 23,0 0 0 $21 ,0 0 0

6 . W a te r C o s t= $ 1 27,0 0 0 $ 102 ,0 0 0

7 . A d d itio n a l P o w e r C o s ts * = $ 1 ,2 61,0 0 0 $ 1 ,156 ,0 0 0

 T o ta l Y early V a ria b le O & M C o s t = 3 ,7 29,0 0 0 5 ,4 6 0 ,0 0 0

T O T A L Y E A R L Y FIX E D A N D V A R IA B L E O & M C O S 6 ,7 12,0 0 0 8 ,4 0 4 ,0 0 0

* In c lude s th e pow e r re q u ire m ent fo r re a g ent p re p a ra tion a n d han d lin g s y s te m , ID fa n fo r 12" w .c . p re s s u re d ro p ,

p o w e r fo r S O 2 C ontro l S y s te m (ro ta ry ato m iz e r), a nd po w e r re q u ire m e n t fo r bag h o u s e
DRY FLUE GAS DESULFURIZATION

TECHNOLOGY EVALUATION

PROJECT NUMBER 11311-000 

SEPTEMBER 26, 2002

NATIONAL LIME ASSOCIATION

NLA-DryFGD 

Project Number 11311-000 

Levelized Costs 

Inputs for Levelized Costs

PRB Eastern Low S

1 FGD System Life, years 20 20

2 Capital Cost Levelization Factor 15.43 15.43

3 Discount rate, %/yr 8.75 8.75

4 Inflation Rate, % 2.5 2.5

5 Operating Cost Levelization Factor 1.22 1.22

Total Capital Cost, M$ 81.4 77.3

Levelized capital Cost, MM$/yr 12.57 11.93

Levelized O&M Cost, MM$/yr 8.19 10.25

Total Levelized Cost, MM$/yr 20.75 22.18

Total cents/kW-hr 0.59 0.63