1 

Evaluation of Wet FGD Technologies to Meet Requirements 

for Post CO2 Removal of Flue Gas Streams 

Paper # 49 

Kevin Smith, William Booth, Stephane Crevecoeur - Dravo Technology, 3600 

Neville Road, Pittsburgh, PA 15225 

ABSTRACT 

The possibility of CO2 emission reductions from existing coal fired power plants being mandated 

is causing electric utilities to begin studying their options. One option to reduce CO2 emission 

that is being considered is the use of regenerative sorbents (including amine) to scrub flue gas. 

One of several requirements to be met for power plant flue gas to be processed by amine 

scrubbing is for SO2 concentration to be less than 10-ppmv (~20-mg/Nm3). This paper discusses 

the results of a comparative study of typical wet FGD methods used to achieve extremely low 

emissions of SO2 and other acid gases in flue gas. This study reveals the critical assumptions 

and inputs that are required to draw meaningful conclusions. 

INTRODUCTION 

The US Congress has begun discussing climate change legislation seeks to reduce emissions of 

greenhouse gases (GHG), most notably CO2, by as much as 80% by 2050. Regardless of 

whether or not CO2 emissions will be limited to this degree in what eventually becomes law, 

industry and especially US power producers will have very difficult decisions to make. Among 

the most difficult decision is determining what to do about reducing CO2 emissions from existing 

scrubbed and unscrubbed coal fired power plants. With utilities finding it more difficult to 

obtain permits to construct new more efficient coal based power plants such as supercritical 

boilers or IGCC, they are forced to consider extending the life of existing plants. Although not 

necessarily the motivation for their study, the US DOE investigated this scenario with a technical 

and economic study to capture CO2 in a conventional PC fired power plant. The study 

recognized and proposed that a 42-ft (12.8-m) diameter secondary scrubber would be required to 

take flue gas SO2 from 104 (~270-mg/Nm3

) to 6.5-ppmv (~17-mg/Nm3).1 The additional SO2

scrubbing would be necessary for an advanced amine CO2 scrubbing system to be installed. 

Whether extending the life of existing plants or building new ones; it is becoming more evident 

that reducing CO2 emissions will have to be factored into how US utilities do business in the 

future. 

CARBON CAPTURE AND SEQUESTRATION (CCS) AND FLUE GAS 

REQUIREMENTS 

Based on the amount of discussion and research that is currently underway, carbon capture and 

sequestration techniques appear to be the near term solution for CO2 emission reduction from 

coal fired power plants. Among many carbon capture technologies that are being developed; 

post combustion solvent scrubbing of flue gas using either chilled ammonia or 

Monoethanolamine (MEA) scrubbing, in spite of many drawbacks or development hurdles, are 

being discussed as likely near term possibilities2

. A major consideration for either technique is 

the requirement for nearly all SO2 (and NOx) to be removed from flue gas prior to being treated 
 2 

with MEA or chilled ammonia. Amine scrubbing requires an inlet flue gas SO2 concentration to 

be less than 10-ppmv3

 (~20-mg/Nm3) or in a range from 3 (~8-mg/Nm3) to 15-ppmv4 (~25-

mg/Nm3). Several sources, while not specifically specifying a maximum SO2 inlet concentration 

for chilled ammonia scrubbing of SO2 recommend that for any post combustion chemical 

absorption process emissions controls either be designed to achieve ultra-low SOx emissions or 

be designed to allow equipment to be upgraded to accomplish this in the future.5, 6 As described 

in Alstom Power Inc. U.S. Patent Application US 2008/0072762 A1, the chilled ammonia 

process removes remaining residual SO2 by first chilling the flue gas that has already been 

through conventional treatment to below 20°C using water to condense any residual gaseous 

contaminants like SO2 and SO3 before entering the CO2 scrubber. However not all CO2 scrubber 

technologies operate at this low temperature, so other methods of removing SO2 should be 

considered. The study presented in this article will assume that maximum possible SO2 removal 

is required for any downstream CO2 removal process. With this assumption comes the 

realization that post combustion CO2 removal processes will dictate SO2 emissions rather than 

governmental regulations. 

SO2 REMOVAL – FUNCTION OF COAL TYPE 

Wet FGD is likely to be the most reliable means to achieve the high degree of SO2 removal that 

will be required to accommodate CO2 capture using a chemical absorption process. The specific 

design of any particular type of wet scrubber regardless of reagent is dependant upon the likely 

fuel to be consumed and the resultant flue gas conditions. Table 1 lists several coals found 

around the world that are used in coal fired power plants. The first three columns list sulfur 

content of each fuel type expressed in weight percent or mass SO2 per unit energy common for 

the power industry. Untreated flue gas SO2 concentration listed in the last two columns of Table 

1 were estimated from coal analyses and combustion calculations and normalized to 6-volume % 

oxygen concentration. 

Table 1 - Common fuel sulfur content and resulting flue gas conditions 

FGD Inlet @ 6-

vol% O2

Fuel Type Sulfur 

wt.% 

lbSO2/mmBTU 

kg-SO2/106

kJ 

ppmv mg/Nm3 

PRB 0.34 0.77 0.33 371 973 

N. Dakota Lignite 0.70 2.26 0.97 1077 2824 

Brown Coal 0.73 2.03 0.87 971 2546 

SW USA Lignite 0.76 1.67 0.72 783 2052 

S. Africa Coal 1.35 2.09 0.90 1034 2709 

Illinois basin 2.54 4.22 1.81 2086 5466 

Eastern USA Bit. 4.17 6.59 2.83 3240 8492 
 3 

Clearly varying sulfur and heating value of each coal type results in different amounts of SO2

that has to be removed from flue gas to achieve less than 10-ppmv SO2. (Conversion from ppmv 

to mg/Nm3 is not straight forward but for this exercise it will be assumed that 10-ppmv equals 

20-mg/Nm3

 although this is not strictly accurate.) Figure 1 illustrates this clearly by indicating 

required SO2 removal efficiency in terms of percentage and Number of Transfer Units (NTU). 

NTU is a particularly useful means of expressing SO2 removal efficiency as it conveys the 

amount of mass transfer “work” that is required for a scrubber to achieve a desired level of SO2

emission. NTU is calculated from percent removal using the following equation: 

ln(1 %/100) 2 NTU = − − SO . 

An incremental increase of 1 NTU represents an equal amount of work to provide the necessary 

mass transfer to achieve a diminishing increase in SO2 removal efficiency as shown in Table 2. 

Therefore increasing SO2 removal efficiency from 95% to 99.3% (a 4.3 percentage point 

increase) requires double the effort of raising SO2 removal from 86.5% to 95% (an increase of 

8.5 percentage points). For wet scrubbers, the mechanical work required to push flue gas 

through a medium where sufficient mass transfer exists to achieve a desired SO2 removal 

efficiency is the energy to operate recycle pumps and induced draft fans. The mass transfer 

medium is usually a combination of liquid droplets from spray headers, sieve trays or other flue 

gas flow straightening devices. Mass transfer can also be aided by using alkalinity enhancing 

chemicals such as Mg(OH)2 or DBA. 

Table 2 - Relationship of % SO2 Removal to NTU 

% SO2 Removal Efficiency NTU 

63.2 1.0 

86.5 2.0 

95.0 3.0 

98.16 4.0 

99.33 5.0 

99.75 6.0 

99.91 7.0 

Once the concept of NTU is understood, Figure 1 shows that regardless of the type of fuel and its 

sulfur content, in order to achieve SO2 concentration of less than 10-ppmv (~20-mg/Nm3) 

scrubbers will require a greater number of transfer units than is typically used to scrub SO2

today. 
 4 

Figure 1 - SO2 Removal Required For Scrubbed Flue Gas SO2 to be <10-ppmv

97.5

98

98.5

99

99.5

100

012345

Fuel S-wt%

SO2 Removal 

%

3.5

4.0

4.5

5.0

5.5

6.0

6.5

7.0

SO2 Removal NTU

SO2 Removal %

SO2 Removal NTU

Brown & 

Lignite

PRB

S. Africa

Illinois 

Basin

East US 

Bituminous

WET FGD TECHNOLOGY DEVELOPMENTS TO ACHIEVE ULTRA-SO2

REMOVAL 

Limestone Forced Oxidation (LSFO) FGD 

Wet limestone FGD scrubber vendors are aware of the need to achieve ever greater SO2 removal 

efficiency and have both modified a number of existing LSFO scrubbers and designed new 

scrubbers to achieve up to 98% removal efficiency. This performance has been achieved using 

combinations of inlet flue gas straightening, dual trays, wall rings on the inside of the scrubber 

shell or baffles to force flue gas and liquid slurry toward the center of the scrubber, dual flow 

nozzles, and of course additional spray levels. 

Table 3 lists several wet LSFO FGD retrofit and new installation projects that include next 

generation or ultra high SO2 removal scrubbers. 
 5 

Table 3 - LSFO FGD High SO2 Removal Systems (multiply L/G by 0.1334 for l/m3) 

Michigan South Central Power Agency - Endicott7 Vectren – Culley 

Station8

Trimble 

County9

Meliti 

Echlada10

K. C. 

Coleman11

SO2 Removal 

% 97 98 95 93 90 89 99 98 99.2 99.2 99.3 

NTU 3.5 3.9 3.0 2.7 2.3 2.2 4.6 3.9 4.8 4.8 5.0 

Trays 2 2 2 2 1 2 - - - - 3 

Spray 

Headers 2 2 2 2 2 2 5 5 5 6 5 

Liquid 

distribution 

Rings 

N N N N N N N N N Y N 

Baffles N N N N N N Y Y Y N N 

Dual 

direction 

nozzles 

N N N N N N N N Y N N 

L/G 

(gallon/ACF) 107 87 95 80 85 87 170 136 140 218 150 

SO2 lb/h 4,204 3,944 4,204 3,996 3,310 4,204 29,160 27,574 35,748 32,550 21,732 

Recycle Rate 

(GPM) 19,400 15,600 14,400 14,600 15,500 17,100 180,000 144,000 220,000 237,200 208,000 

SO2-lb/kgallon 3.50 4.13 4.62 4.24 3.20 3.65 2.67 3.13 2.69 2.27 1.73 

Equivalent 

L/G 

(gallon/ACF) 

157 137 145 130 110 137 195 161 190 243 225 

Endicott, Culley and Trimble County power stations are existing LSFO FGD units that were 

modified by their original designers to improve SO2 removal efficiency. Coleman Station and 

Meliti Echlada, a power plant located in Greece, represent new state-of-the-art FGD installations 

designed for higher than typical SO2 loading of the flue gas. The SO2 removal efficiencies 

mentioned in Table 3 were reported as the highest achieved during testing but do not represent 

the design condition or a performance guarantee. 

SO2 removal performance enhancements that are mentioned in the references include increased 

number of spray headers, multiple perforated trays, liquid distribution rings, baffles and dual 

direction nozzles. These enhancements either increase mass transfer area of recycled liquid, 

insure an even distribution of flue gas across the scrubber module or both. L/G for each column 

is as reported in each reference. 
 6 

Using what flue gas information was provided in the respective references and making some 

assumptions about boiler operation, the values for SO2 flowrate, scrubber recycle rate, SO2

scrubbed per 1000 gallons of recycle slurry, and equivalent L/G were calculated by the writer. 

Babcock & Wilcox provides a useful parameter – SO2 scrubbed per 1000 gallons of recycle 

slurry - that helps give a sense of the minimum volume of recycle slurry necessary to capture the 

desired amount of SO2. Babcock & Wilcox mentions that a value of 5 is typical for the modified 

Endicott LSFO scrubber. This parameter decreases in value (regardless of sulfur loading in the 

flue gas) as actual L/G increases to improve SO2 removal efficiency and increases if 

enhancements like those listed in Table 3 are employed6

. 

While impressive improvement in SO2 removal efficiency is reported for all the cases in Table 3, 

calculations using the information on hand indicate that SO2 concentration in the flue gas exiting 

these absorber systems remain significantly above 10-ppmv. To achieve flue gas with less than 

10-ppmv SO2 a removal efficiency of 99.8% or 6.2 NTU is required. With an understanding of 

the relationship between NTU and SO2 removal efficiency and the data presented in Table 3, one 

should be able to estimate how much further absorbers need to be improved to exceed the SO2

concentration threshold of 10-ppmv. 

One way to do this is to plot SO2 removal as NTU vs. L/G, but a means of accounting for the 

enhancements listed in Table 3 is required. B&W states in reference 6 that the use of a single 

perforated tray is worth an L/G of 25 to 30 gal/1000-ft3 (3.34 to 4-l/m3). This analogy was also 

assigned to each of the other absorber enhancements (liquid distribution rings, baffles and dual 

direction nozzles) and added to the reported L/G to arrive at the Equivalent L/G values in the last 

row of Table 3. Figure 3 is a plot of Effective L/G vs. reported SO2 removal efficiency as NTU. 

With the exception of Meliti Echlada, all stations in Table 3 burn high sulfur bituminous coal so 

a least squares trend line can be drawn through the plotted data and extended. At where the trend 

line intersects 6.2 NTU (99.8% SO2 removal efficiency) an equivalent L/G of approximately 280 

Figure 2 - L/Geff vs. NTU for Current High Efficiency LSFO Absorbers

0

1

2

3

4

5

6

7

8

100 150 200 250 300

Equivalent L/G

SO2 Removal (NTU)

Endicott

Culley

Trimble County

Meliti Echlada

Coleman
 7 

gal/1000-ft3

 (37.5 l/m3) is determined. It is important to remember again that equivalent L/G 

here equals any combination of recycled slurry and absorber enhancement; i.e. tray, baffle, dual 

direction nozzle or liquid distribution rings, each assumed to be equivalent to L/G of 25 

gal/1000-ft3

 (3.344-l/m3). 

Magnesium Enhanced Lime (MEL) FGD 

While MEL FGD has always been thought to have the capability to achieve ultra-high SO2

removal efficiency, there is little published data indicating a removal efficiency of 99.8%. 

Using published articles about various MEL FGD facilities an approach similar to that used for 

LSFO can be taken to determine what improvement in absorber design may be required for MEL 

absorbers to achieve SO2 concentration below 10-ppmv (~20-mg/Nm3

). 

Table 4 lists several retrofit and new MEL FGD projects that were installed in the mid 1990’s 

and typically burn mid to high sulfur fuels ranging from 3 to 4.5-wt% sulfur. There is no 

documentation of any SO2 removal enhancement other than perforated trays being used in any 

MEL absorber. For any absorber designs having a perforated tray, 25 L/G was added to actual 

L/G to arrive at equivalent L/G listed in the last row of Table 3. As with the LSFO cases using 

what flue gas information was provided in the respective references and making some 

assumptions about boiler operation, the values for SO2 flowrate, scrubber recycle rate, SO2

scrubbed per 1000 gallons of recycle slurry, and equivalent L/G were calculated by the writer. 

Table 4 - MEL FGD Systems (multiply L/G by 0.1334 for l/m3)

 Lowman12 Gavin13 Zimmer14 Henderson15 Harrison16 Pleasants 

Unmodified17

SO2 Removal 

% 96.7 99.2 99.7 95 93 95 98 98† 

NTU 3.4 4.8 5.8 3.0 2.7 3.0 3.9 3.9 

Trays - - - 1 1 1 0 1 

L/G 

(gallon/ACF) 23 44.7 70 27 21 30 54 33 

SO2 lb/h 9,922 9,922 9,922 82,520 64,584 12,653 103,675 36,107 

Recycle Rate 

(GPM) 16,200 31,000 48,400 15,000 23,000 22,065 221,000 48,000 

SO2-lb/k-gallon 9.87 5.29 3.41 11.36 8.14 9.08 7.66 12.29 

 Equivalent L/G 

(gallon/ACF) 23 44.7 70 52 46 55 54 58 

†

 SO2 removal efficiency is only for flue gas that is not bypassed around the scrubbing system. 
 8 

As with the LSFO data, equivalent L/G is plotted vs. SO2 removal efficiency as NTU in Figure 3. 

A least squares trend line is extended beyond 6.2 NTU to estimate the required effective L/G of 

76-g/1000-ft3

 (9.9-l/m3). 

IMPLICATIONS FOR EXISTING AND NEW FGD INSTALLATIONS 

Both LSFO and MEL FGD results indicate significant changes in absorber design and operation 

will be required to achieve less than 10-ppmv (~20-mg/Nm3) SO2 in flue gas that is to be 

processed for CO2 removal. Scrubbing “harder” will mean higher L/G combined with use of 

multiple scrubbing enhancements that have been discussed and in turn will mean taller absorbers 

and more energy expended. Although Dravo Technology is familiar with the basic concepts of 

FGD design and engineering, Dravo Technology is not in the business of designing and 

engineering FGD absorber systems and users are advised to consult qualified engineering 

companies to address specific design and engineering issues. Our interest in this subject lies in 

the need to discuss intelligently with utilities what to expect future absorber design to be as 

emission limits become even more stringent. It is possible using published information and 

application of basic engineering skills to approximate the trend in absorber design. Therefore in 

order to appreciate the magnitude of changes to absorber design, an assessment of MEL and 

LSFO absorber designs a study was conducted where three different coal sulfur cases are 

presented. The fuels considered for this study include Powder River Basin (PRB) at 0.6-wt% S, 

Appalachian coal at 1.3-wt% Sulfur and Appalachian coal having 3-wt% Sulfur. These fuels are 

identical to those used by Sargent & Lundy in their economic evaluation of MEL and LSFO 

FGD processes18. 

Figure 3 - L/Geq vs. NTU for Existing MEL Absorbers 

0

1

2

3

4

5

6

7

8

40 50 60 70 80

Equivalent L/G

SO2 Removal (NTU)

Lowman

Gavin

Zimmer

Henderson

Harrison

Pleasants unmodified
 9 

Design assumptions for all cases are a nominal 500-MW single unit supplying flue gas to a 

single absorber module. Scrubber flue gas velocity was nominally set to 12-fps (3.7-m/s) and a 

single sieve tray is the only flue gas contacting enhancement device employed for all cases. The 

mass rate of SO2 entering the absorber was taken into account when deciding on the liquid to gas 

ratio for each case. Whenever possible the references cited in this paper were used for guidance. 

Materials of construction were not considered germane in this study. 

The LSFO PRB cases used individual pumps of 36,000 GPM (8176-m3

/h) while the Appalachian 

coal cases used individual pumps of 50,000 GPM (11,360-m3/h), reaction tanks were assumed to 

have a residence time of between 18 and 24 hours. All MEL FGD cases with the exception of 

PRB at 98% SO2 removal use two recycle spray headers which resulted in varying individual 

pumps capacities ranging from 20,000 to 40,000 GPM (4543 to 10,000 m3/h) and ex-situ 

oxidation is used to produce gypsum 

Using standard coal combustion calculations and knowledge of FGD chemical reactions, a 

material balance was created to determine resulting flue gas conditions from the three coals 

previously mentioned for a hypothetical 500-MW boiler. Using available information about 

LSFO and MEL absorber design and the results of Figures 2 and 3, MEL and LSFO scrubber 

designs were developed for both 98% removal efficiency and the SO2 removal efficiency was 

required to achieve a scrubbed flue gas that had less than 10-ppmv (~20-mg/Nm3

) SO2. For 

PRB, low sulfur Appalachian and high sulfur Appalachian coals those SO2 removal efficiencies 

were respectively, 99% (3.9 NTU), 99.6% (5.5 NTU) and 99.8% (6.2 NTU). Also estimated is 

electric power consumption to move flue gas and air through the absorber and recirculate 

absorber slurry. The results are found in Figure 4. 
 10 

Figure 4 - Absorber dimensions and Operating Conditions for High SO2 Removal Efficiency 

All top SO2 absorber vendors undoubtedly have more sophisticated techniques to design 

absorbers for ultra SO2 removal efficiency. The projected absorber size, L/G, energy consumed 

etc for each fuel type and FGD process in Figure 4 should be considered high estimates. With 

this in mind, as SO2 removal moves from high to ultra high efficiency, the trends rather than Dimensions MEL LSFO MEL LSFO MEL LSFO MEL LSFO MEL LSFO MEL LSFO A - ft. (m) 57 (17.4) 95 (29) 60 (18.3) 95 (29) 58 (17.7) 105 (32) 65 (19.9) 125 (38.1) 62 (18.9) 145 (44.2) 72 (22) 170 (51.8) B - ft. (m) 50 (15.3) 50 (15.2) 50 (15.3) 50 (15.2) 50 (15.3) 55 (16.8) 50 (15.3) 55 (16.8) 50 (15.3) 65 (19.8) 50 (15.3) 65 (19.8) C - ft. (m) n/a 20 (6.1) n/a 20 (6.1) n/a 30 (9.1) n/a 30 (9.1) n/a 50 (15.2) n/a 45 (13.7) D - ft. (m) n/a 50 (15.2) n/a 50 (15.2) n/a 50 (15.2) n/a 50 (15.2) n/a 50 (15.2) n/a 50 (15.2) E - ft. (m) n/a 75 (22.9) n/a 75 (22.9) n/a 75 (22.9) n/a 95 (29) n/a 95 (29) n/a 125 (38.1) No. of Spray Headers 2333 3 3 3 5 3 5 3 8 No. of Trays 1111 1 1 1 1 1 1 1 1 L/G gal/kacf (l/Nm3) 20 (3.06) 50 (483) 30 (4.6) 60 (579) 30 (4.52) 80 (759) 50 (7.53) 150 (1423) 40 (6.02) 130 (1234) 70 (10.54) 240 (2277) SO2 lb/h (kg/h) 7100 (3230) 7122 (3231) 7100 (3230) 7122 (3231) 9600 (4360) 9625 (4366) 9600 (4360) 9625 (4366) 23050 (10460) 23122 (10488) 23050 (10460) 23122 (10488) SO2-lb/k-gallon (kg/kl) 4 (0.48) 2 (0.19) 3 (0.32) 2 (0.16) 4 (0.46) 2 (0.18) 3 (0.28) 1 (0.1) 7 (0.83) 3 (0.26) 5 (0.49) 2 (0.14) Operating Spray Headers 1222 2 2 2 4 2 4 2 7 Recycle Rate - GPM (m3/h) 29230 (6640) 71976 (16346) 43850 (9960) 86378 (19617) 40400 (9180) 106677 (24227) 67330 (15290) 200044 (45430) 54060 (12280) 176766 (40144) 94600 (21490) 326485 (74145) Approx. Tower ∆P - inWC (torr) 10 (19) 11 (20.5) 11 (19) 11 (20.5) 11 (19) 12 (22.4) 11 (20) 15 (28) 11 (20) 14 (26.1) 12 (22) 19 (35.5) SO2 Removal Efficiency NTU Equivalent L/G Gal/kacf (l/Nm3) 45 (6.89) 75 (724) 55 (8.43) 85 (869) 55 (8.28) 105 (1139) 75 (10.67) 175 (2135) 65 (9.79) 155 (1850) 95 (14.94) 265 (3416) Absorber/Oxidation Energy Consumption (kW- h) 3,524 5,156 3,872 5,455 3,835 6,145 4,629 10,114 5,117 10,562 6,308 18,371

Reagent Preparation 

Energy Consumption (kWh) 749 1,120 749 1,131 783 1,100 783 1,113 854 1,100 854 1,119

98% SO2 Removal 99.8% SO2 Removal

Appalachian Coal 3% sulfur

99% SO2 Removal

Appalachian Coal - 1.3% sulfur

98% SO2 Removal 99.6% SO2 Removal

3.91 6.21 3.91 4.61 3.91 4.83

98% SO2 Removal

PRB Coal
 11 

absolute numbers indicated in Figure 4 should be the focus. Projecting the design of an ultra 

high SO2 removal absorber system, whether MEL or LSFO, from published information reveals 

that absorbers must be required to be even taller, have more spray levels, recirculate more slurry, 

employ multiple numbers of trays, baffles or periphery rings and consume more power than ever 

before. 

For PRB coals wet scrubbing is likely necessary in order to reliably achieve less than 10-ppmv 

SO2 where previously dry scrubbing would be sufficient to achieve up to 98% SO2 removal. For 

bituminous coals, absorber size increases in overall height by as much as 25% to accommodate 

as many as 9 spray headers for LSFO and 3 spray headers for MEL along with use of at least one 

tray or set of baffles can be expected. For medium sulfur bituminous coals, FGD parasitic load 

for LSFO exceeds 4% while for MEL parasitic load approaches 2%. 

CONCLUSION 

All post combustion CO2 removal processes, with the possible exception of the chilled ammonia 

process, require SO2 to be less than 10-ppmv (~20-mg/Nm3

) in order to slow the degeneration of 

the CO2 reagent. Power plants with existing FGD systems will have to modify their processes to 

achieve ultra high SO2 removal by either adding secondary absorbers or upgrading existing 

absorbers. Power plants that do not already have FGD will have to consider installing systems 

that achieve up to 99.8% SO2 removal efficiency. In order to achieve this level of performance 

the absorbers, whether MEL or LSFO, will have to be the largest and most expensive ever built 

with parasitic electric consumption ranging from 2% for MEL to over 4% for LSFO of the plants 

output. 

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 12 

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9

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15 “Henderson Station Two FGD System Retrofit Project”; F.W. Campbell & J.L. McIlroy-Burns & McDonnell 

Engineering Company, J.A. Garner-Henderson Municipal Power and Light, and R.L. Phillips-Big Rivers Electric 

Corporation; 1993 SO2 Symposium, Volume 1-Session 2 Phase 1 Designs; Boston MA; August 1993 

16 “Design and Startup of a High Efficiency, Dilute Phase Lime FGD System”; M. Walsh-General Electric 

Environmental Services, Inc, A.J. Cirillo-Raytheon Engineers & Constructors; 1995 SO2 Control Symposium, Book 

2 Session 48-Phase 1 Startups, Miami FL, March 28-31, 1995 

17 “Full Scale Comparison of a Venturi/Dual Flow Tray Scrubber versus Multiple Dual Flow Trays at a Reference 

Power Plant”; M. Hoydick-Wheelabrator Air Pollution Control; Las Vegas, Nevada; December 9-11, 2003 

18 “Economics of Lime and Limestone for Control of Sulfur Dioxide”; W. DePriest, R. P. Gaikwad – Sargent & 

Lundy LLC, Mega Symposium, Washington DC, May 19-22, 2003 

KEY WORDS

CO2 capture, ultra SO2 removal, magnesium-enhanced lime, LSFO, FGD