1 

## Evaluation of Wet FGD Technologies to Meet Requirements for Post CO 2 

## Removal of Flue Gas Streams
Paper # 49 Kevin Smith, William Boot h, Stephane Crevecoeur - Dravo Technology, 3600 Neville Road, Pittsburgh, PA 15225
ABSTRACT
The possibility of CO 2 emission reductions from existing coal fired power plants being mandated is causing electric utilities to begin studyi ng their options. One option to reduce CO 2 emission that is being considered is the use of regenerativ e sorbents (including amine) to scrub flue gas. One of several requirements to be met for pow er plant flue gas to be processed by amine scrubbing is for SO 2 concentration to be le ss than 10-ppmv (~20-mg/Nm3). This paper discusses the results of a comparative st udy of typical wet FGD methods us ed to achieve extremely low emissions of SO 2 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 cha nge legislation seeks to reduce emissions of greenhouse gases (GHG), most notably CO 2 , by as much as 80% by 2050. Regardless of whether or not CO 2 emissions will be limited to this degr ee 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 CO 2 emissions from existing scrubbed and unscrubbed coal fired power plants. With utilities finding it more difficult to obtain permits to construct new more efficient co al based power plants such as supercritical boilers or IGCC, they are forced to consider ex tending the life of existi ng plants. Although not necessarily the motivation for their study, the US DOE investigated this scenario with a technical and economic study to capture CO 2 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 SO 2 from 104 (~270-mg/Nm 3 ) to 6.5-ppmv (~17-mg/Nm 3 ). 1 The additional SO 2 scrubbing would be necessary for an advanced amine CO 2 scrubbing system to be installed. Whether extending the life of existing plants or building new ones; it is becoming more evident that reducing CO 2 emissions will have to be factored into how US utilities do business in the future. 

### CARBON CAPTURE AND SEQUESTR ATION (CCS) AND FLUE GAS REQUIREMENTS

Based on the amount of discussion and research that is currently unde rway, carbon capture and sequestration techniques appear to be the near term solution for CO 2 emission reduction from coal fired power plants. Among many carbon captu re 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 possibilities 2 . A major consideration for either technique is the requirement for nearly all SO 2 (and NOx) to be removed from fl ue gas prior to being treated2 with MEA or chilled ammonia. Amine scrubbing requires an inlet flue gas SO 2 concentration to be less than 10-ppmv 3 (~20-mg/Nm3) or in a range from 3 (~8-mg/Nm3) to 15-ppmv 4 (~25- mg/Nm3). Several sources, while not specifically specifying a maximum SO 2 inlet concentration for chilled ammonia scrubbing of SO 2 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 SO 2 by first chilling the flue gas that has already been through conventional treatment to below 20°C us ing water to condense any residual gaseous contaminants like SO 2 and SO 3 before entering the CO 2 scrubber. However not all CO 2 scrubber technologies operate at this low temper ature, so other methods of removing SO 2 should be considered. The study presente d in this article will assume that maximum possible SO 2 removal is required for any downstream CO 2 removal process. With this assumption comes the realization that post combustion CO 2 removal processes will dictate SO 2 emissions rather than governmental regulations.


### SO 2 

### REMOVAL – FUNCTION OF COAL TYPE
Wet FGD is likely to be the most reliable means to achieve the high degree of SO 2 removal that will be required to accommodate CO 2 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 ga s 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 expres sed in weight percent or mass SO 2 per unit energy common for the power industry. Untreated flue gas SO 2 concentration listed in th e last two columns of Table 1 were estimated from coal analyses and com bustion calculations and normalized to 6-volume % oxygen concentration.


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

FGD Inlet @ 6- vol% O 2
Fuel Type Sulfur wt.% lbSO 2 /mmBTU kg-SO 2 /10 6
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 84923 Clearly varying sulfur and heating value of each coal type results in different amounts of SO 2 that has to be removed from flue gas to achieve less than 10-ppmv SO 2 . (Conversion from ppmv to mg/Nm 3 is not straight forward but for this exer cise it will be assumed that 10-ppmv equals 20-mg/Nm 3 although this is not strictly accurate.) Fi gure 1 illustrates this clearly by indicating required SO 2 removal efficiency in terms of percentage and Number of Transfer Units (NTU). NTU is a particularly usef ul means of expressing SO 2 removal efficiency as it conveys the amount of mass transfer “work” th at is required for a scrubber to achieve a desired level of SO 2 emission. NTU is calculated from percen t removal using the following equation:
) 100 / % 1 ln( 2 SO NTU

− − =

. An incremental increase of 1 NTU represents an equal amount of work to provide the necessary mass transfer to achieve a diminishing increase in SO 2 removal efficiency as shown in Table 2. Therefore increasing SO 2 removal efficiency from 95% to 99.3% (a 4.3 percentage point increase) requires double th e effort of raising SO 2 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 tran sfer exists to achieve a desired SO 2 removal efficiency is the energy to operate recycle pum ps and induced draft fans. The mass transfer medium is usually a combination of liquid droplets from spray head ers, sieve trays or other flue gas flow straightening devices. Mass transfer can also be aide d by using alkalinity enhancing chemicals such as Mg(OH) 2 or DBA. 

### Table 2 - Relationship of % SO 2 

### Removal to NTU

% SO 2 

### 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 underst ood, Figure 1 shows that regardless of the type of fuel and its sulfur content, in order to achieve SO 2 concentration of less than 10-ppmv (~20-mg/Nm 3 ) scrubbers will require a greater number of transf er units than is typi cally used to scrub SO 2 today.4 Figure 1 - SO 2 Removal Required For Scrubbed Flue Gas SO 2 to be <10-ppmv

97.5

98 98.5

99 99.5 100

012345
Fuel S-wt%SO2Removal%

3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0SO2Removal NTU

SO2 Removal % SO2 Removal NTU Brown & Lignite

PRB S. Africa Illinois Basin East US
Bituminous



### WET FGD TECHNOLOGY DEVELOPM ENTS TO ACHIEVE ULTRA-SO 2 

### REMOVAL Limestone Forced Oxidation (LSFO) FGD

Wet limestone FGD scrubber vendors are aware of the need to achieve ever greater SO 2 removal efficiency and have both modi fied a number of existing LS FO scrubbers and designed new scrubbers to achieve up to 98% removal efficien cy. 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 installati on projects that include next generation or ultra high SO 2 removal scrubbers.5 

### Table 3 - LSFO FGD High SO 2 

### Removal Systems (multiply L/G by 0.1334 for l/m 3 )

Michigan South Central Power Agency - Endicott 7 Vectren – Culley Station 8 Trimble County 9 Meliti Echlada 10 K. C. Coleman 11

SO 2 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

SO 2 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

SO 2 -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 stati ons are existing LSFO FGD units that were modified by their original designers to improve SO 2 removal efficiency. Coleman Station and Meliti Echlada, a power plant locat ed in Greece, represent new stat e-of-the-art FGD installations designed for higher than typical SO 2 loading of the flue gas. The SO 2 removal efficiencies mentioned in Table 3 were reported as the highe st achieved during testin g but do not represent the design condition or a performance guarantee.

SO 2 removal performance enhancements that are me ntioned in the references include increased number of spray headers, multiple perforated tr ays, 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 refere nces and making some assumptions about boiler operation, the values for SO 2 flowrate, scrubber recycle rate, SO 2 scrubbed per 1000 gallons of recycl e slurry, and equivale nt L/G were calculated by the writer. Babcock & Wilcox provides a useful parameter – SO 2 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 SO 2 . Babcock & Wilcox mentions that a va lue of 5 is typical for the modified Endicott LSFO scrubber. This parameter decrease s in value (regardless of sulfur loading in the flue gas) as actual L/G increases to improve SO 2 removal efficiency and increases if enhancements like those listed in Table 3 are employed 6

. While impressive improvement in SO 2 removal efficiency is reported for all the cases in Table 3, calculations using the informa tion on hand indicate that SO 2 concentration in the flue gas exiting these absorber systems remain significantly abov e 10-ppmv. To achieve flue gas with less than 10-ppmv SO 2 a removal efficiency of 99.8% or 6.2 NT U is required. With an understanding of the relationship between NTU and SO 2 removal efficiency and the da ta presented in Table 3, one should be able to estimate how much further ab sorbers need to be improved to exceed the SO 2 concentration threshold of 10-ppmv. One way to do this is to plot SO 2 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-ft 3 (3.34 to 4-l/m 3 ). This analogy was also assigned to each of the other absorber enhancem ents (liquid distributi on rings, baffles and dual direction nozzles) and added to the reported L/G to arrive at the Equi valent L/G values in the last row of Table 3. Figure 3 is a plot of Effectiv e 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% SO 2 removal efficiency) an equiva lent L/G of approximately 280 Figure 2 - L/G eff vs. NTU for Current High Efficiency LSFO Absorbers



### 0 1 2 3 4 5 6 7 8

100 150 200 250 300
Equivalent L/GSO2Removal (NTU)

Endicott Culley Trimble County Meliti Echlada Coleman7 gal/1000-ft 3 (37.5 l/m 3 ) is determined. It is important to remember again that equivalent L/G here equals any combination of recycled slurry and absorber e nhancement; i.e. tray, baffle, dual direction nozzle or liquid distri bution rings, each assumed to be equivalent to L/G of 25 gal/1000-ft 3 (3.344-l/m 3 ). 

### Magnesium Enhanced Lime (MEL) FGD
While MEL FGD has always been thought to ha ve the capability to achieve ultra-high SO 2 removal efficiency, there is little published da ta indicating a removal efficiency of 99.8%. Using published articles about vari ous MEL FGD facilities an approach similar to that used for LSFO can be taken to determine what improveme nt in absorber design may be required for MEL absorbers to achieve SO 2 concentration below 10-ppmv (~20-mg/Nm 3 ). Table 4 lists several retrofit and new MEL FGD pr ojects that were installed in the mid 1990’s and typically burn mid to high sulfur fuels ra nging from 3 to 4.5-wt% sulfur. There is no documentation of any SO 2 removal enhancement other than pe rforated 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 SO 2 flowrate, scrubber recycle rate, SO 2 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/m 3 )

Lowman 12 Gavin 13 Zimmer 14 Henderson 15 Harrison 16 Pleasants Unmodified 17

SO 2 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

SO 2 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

SO 2 -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

† SO 2 removal efficiency is only for flue gas that is not bypassed around the scrubbing system.8 As with the LSFO data, equi valent L/G is plotted vs. SO 2 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-ft 3 (9.9-l/m 3 ).



### IMPLICATIONS FOR EXISTING AND NEW FGD INSTALLATIONS
Both LSFO and MEL FGD results indicate signif icant changes in absorb er design and operation will be required to achieve less than 10-ppmv (~20-mg/Nm 3 ) SO 2 in flue gas that is to be processed for CO 2 removal. Scrubbing “harder” will mean higher L/G combined with use of multiple scrubbing enhancements that have been di scussed and in turn will mean taller absorbers and more energy expended. Although Dravo Tec hnology is familiar with the basic concepts of FGD design and engineering, Dr avo Technology is not in th e 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 fu ture absorber design to be as emission limits become even more stringent. It is possible using published information and application of basic engineering sk ills 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 wh ere three different co al sulfur cases are presented. The fuels considered for this study include Powder River Ba sin (PRB) at 0.6-wt% S, Appalachian coal at 1.3-wt% Sulfur and Appalach ian coal having 3-wt% Sulfur. These fuels are identical to those used by Sargent & Lundy in their economic evaluation of MEL and LSFO FGD processes 18

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

0 1 2 3 4 5 6 7 8

40 50 60 70 80 Equivalent L/GSO2Removal (NTU)

Lowman Gavin Zimmer Henderson Harrison Pleasants unmodified9 Design assumptions for all cases are a nominal 500-MW single unit supplying flue gas to a single absorber module. Scrubber flue gas veloc ity was nominally set to 12-fps (3.7-m/s) and a single sieve tray is the only fl ue gas contacting enhancement device employed for all cases. The mass rate of SO 2 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 indi vidual pumps of 36,000 GPM (8176-m 3 /h) while the Appalachian coal cases used individu al pumps of 50,000 GPM (11,360-m 3 /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 re sulted 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 re sulting 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 SO 2 removal efficiency was required to achieve a scrubbed flue gas that had less than 10-ppmv (~20-mg/Nm 3 ) SO 2 . For PRB, low sulfur Appalachian and high sulfur Appalachian coals those SO 2 removal efficiencies were respectively, 99% (3.9 NT U), 99.6% (5.5 NTU) and 99.8% ( 6.2 NTU). Also estimated is electric power consumption to move flue ga s and air through the abso rber and recirculate absorber slurry. The re sults are found in Figure 4.10 Figure 4 - Absorber dimensions and Operating Conditions for High SO 2 Removal Efficiency All top SO 2 absorber vendors undoubtedly have more sophisticated techniques to design absorbers for ultra SO 2 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 SO 2 removal moves from high to ultra high efficiency, the trends rather thanDimensionsMEL LSFO MEL LSFO MEL LSFO MEL LSFO MEL LSFO MEL LSFOA - 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 Headers2333 3 3 3 5 3 5 3 8No. of Trays1111 1 1 1 1 1 1 1 1L/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)SO2lb/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 Headers1222 2 2 2 4 2 4 2 7Recycle 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)SO2Removal EfficiencyNTUEquivalent 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/OxidationEnergy Consumption (kW-h)3,5245,1563,8725,4553,8356,1454,62910,1145,11710,5626,30818,371Reagent PreparationEnergy Consumption (kWh)7491,1207491,1317831,1007831,1138541,1008541,11998% SO2Removal 99.8% SO2RemovalAppalachian Coal 3% sulfur99% SO2RemovalAppalachian Coal - 1.3% sulfur98% SO2Removal 99.6% SO2Removal3.91 6.213.91 4.61 3.91 4.8398% SO2RemovalPRB Coal11 absolute numbers indicated in Figure 4 should be the focus. Projecting the design of an ultra high SO 2 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 pe riphery 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 SO 2 where previously dry scrubbing would be sufficient to achieve up to 98% SO 2 removal. For bituminous coals, absorber size increases in over all 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 me dium sulfur bituminous coals, FGD parasitic load for LSFO exceeds 4% while for MEL parasitic load approaches 2%.


### CONCLUSION
All post combustion CO 2 removal processes, with the possibl e exception of the chilled ammonia process, require SO 2 to be less than 10-ppmv (~20-mg/Nm 3 ) in order to slow the degeneration of the CO 2 reagent. Power plants with existing FGD systems will have to modify their processes to achieve ultra high SO 2 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% SO 2 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. 

### REFERENCES

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### KEY WORDS

CO 2 capture, ultra SO 2 removal, magnesium-enhanced lime, LSFO, FGD