Technical Support Document

for the

Cost of Controls Calculations for the Texas Regional Haze Federal 

Implementation Plan

(Cost TSD)

Prepared and Reviewed by:

Joe Kordzi

November 2014
ii

 Table of Contents

1 Introduction........................................................................................................................... 1

2 Cost Analyses Methodology ................................................................................................. 2

3 Overview of DSI Cost Model Input Parameters................................................................ 3

3.1 Selection of DSI Cost Model Input Parameters........................................................... 4

3.2 DSI Cost Model Output............................................................................................... 11

3.3 Summary of DSI Cost Model Results......................................................................... 13

3.4 Discussion of DSI Cost Model Results........................................................................ 14

4 Overview of SDA Cost Model Input Parameters............................................................. 14

4.1 Selection of SDA Cost Model Input Parameters....................................................... 16

4.2 SDA Cost Model Output.............................................................................................. 18

4.3 Summary of SDA Cost Model Results........................................................................ 20

4.4 Summary of SDA Cost Model Results........................................................................ 20

5 Overview of Wet FGD Cost Model Input Parameters.................................................... 20

5.1 Selection of Wet FGD Cost Model Input Parameters............................................... 21

5.2 Wet FGD Cost Model Output..................................................................................... 22

5.3 Summary of Wet FGD Cost Model Results............................................................... 24

5.4 Summary of Wet FGD Cost Model Results............................................................... 24

6 Upgrading Existing Scrubber Efficiencies........................................................................ 25

6.1 Calculation of Existing Scrubber Efficiencies........................................................... 28

6.2 Historical Scrubber Designs and Upgrades............................................................... 31

6.3 Options for Upgrading SO2 Scrubbers ...................................................................... 38

6.3.1 Elimination of Scrubber Bypass.......................................................................... 40

6.3.2 Optimization of Liquid/Gas Ratio....................................................................... 44

6.3.3 Gas-Liquid Contact Improvements..................................................................... 44

6.3.4 Improving FGD Chemistry.................................................................................. 48

6.3.5 Use of Organic Acids to Improve Performance ................................................. 49

6.3.6 Related Capital Improvements............................................................................ 51

7 Scrubber Upgrade Analyses............................................................................................... 52

7.1 Section 114(a) Information Requests ......................................................................... 52

7.2 Approach to Scrubber Upgrade Cost Analyses......................................................... 53

7.3 Summary of Scrubber Upgrade Cost Results ........................................................... 55

7.3.1 San Miguel............................................................................................................. 56
iii

Tables

Table 1. Sources undergoing RP and LTS analyses 1

Table 2. Sample DSI Input Parameters 4

Table 3: Cost of Trona 9

Table 4. Sample DSI Output 12

Table 5. Summary of DSI Cost Model Results 13

Table 6. Sample SDA Input Parameters 15

Table 7. Elevation of Sources undergoing RP and LTS analyses 17

Table 8. Sample SDA Output 19

Table 9. Summary of SDA Cost Model Results 20

Table 10. Sample Wet FGD Input Parameters 21

Table 11. Sample Wet FGD Output 23

Table 12. Summary of Wet FGD Cost Model Results 24

Table 13. Capital cost and cost effectiveness of wet FGD versus SDA 24

Table 14. Efficiency of Units with existing SO2 scrubbers 30

Table 15. Comparison of theoretical to monitored SO2 emissions for unscrubbed units 30

Table 16. Summary of FGD information 33

Table 17. Selected information from Weilert and Meyer 34

Table 18. Existing Scrubber SO2 Removal Efficiencies 52

Table 19. Summary of Scrubber Upgrade Results 55

Table 20. Scrubber Improvements Performed at the San Miguel Facility 57

Table 21. San Miguel Sulfur Content and Btu Coal Value 57

Table 22. Summary of SO2 Emissions from the San Miguel Facility 60

Table 23. 2013 Monthly SO2 Emission Data for the San Miguel Facility 61

Figures

Figure 1. Typical Trona SO2 Removal Rates with ESP or Baghouse Installations 7

Figure 2. Effect of Bypass and Absorber Efficiency on SO2 Emitted 40

Figure 3. Aerial view of the San Miguel facility 56
Technical Support Document for the Cost of Controls Calculations for the 

Texas Regional Haze Federal Implementation Plan

1 Introduction

This TSD describes how we conducted cost analyses for retrofitting certain coal fired EGUs with 

Spray Dryer Absorbers (SDA, or dry scrubbers), Wet Flue Gas Desulfurization (wet FGD), Dry 

Sorbent Injection (DSI); and how we conducted cost analyses on upgrading certain existing wet 

FGD scrubbers. This work is a part of our review of the Texas and Oklahoma regional haze 

State Implementation Plans (SIPs).

In the process of developing our cost analyses, we consulted with Dr. Phyllis Fox, Ph.D., P.E., a 

consultant to RTI International under contract EP-W-11-029, Work Assignment No. 3-09. Dr. 

Fox contributed significantly to Section 6, concerning upgrading existing scrubbers. Dr. Fox 

also reviewed and provided comments on Sections 3, 4, and 5, concerning the cost analyses for 

SDA and wet FGD scrubber retrofits, and the cost analyses for DSI. Dr. Fox did not have access 

to any claimed Confidential Business Information for this work. 

We are conducting a SO2 cost analyses for the following facilities and units:

Table 1. Sources undergoing RP and LTS analyses

Facility Units Scrubbed? Bypass?

Big Brown 1, 2

Sandow 4 1 Y Y

Monticello 1, 2

Monticello 3 Y Y

Martin Lake 1, 2, 3 Y Y

Coleto Creek 1

Limestone 1, 2 Y Y

San Miguel 1 Y N

Tolk 1, 2

Welsh 1, 2, 3

W. A. Parish 5, 6, 7

W. A. Parish 8 Y Y

For those units without a scrubber, we calculate the costs for DSI, dry scrubbing, and wet 

scrubbing. For those units that are equipped with an underperforming scrubbing system, we 

calculate the costs of upgrading that scrubbing system. We also document the level of SO2

removal efficiencies we believe is appropriate, depending on the technology. 
2

We have constructed a master spreadsheet1that contains information concerning ownership, 

location, boiler type, environmental controls and other information that we draw upon 

throughout this appendix. This spreadsheet includes information contained within Texas’ 

computer-based State of Texas Air Retrieval System (STARS) database,2our CAMD emissions 

data,3 EIA Form 860,4and our National Electric Energy Data System (NEEDS) database 

associated with our Integrated Planning Model (IPM).5 We rely upon this information for our 

analysis, confirmed when possible through other public sources of information such as 

permitting files and trade journals.

2 Cost Analyses Methodology

In developing our cost estimates for the units in Table 1, we relied on the methods and principles 

contained within the EPA Air Pollution Control Cost Manual (the Control Cost Manual, or 

Manual).6 As we describe in our Oklahoma final action,7the Control Cost Manual uses the 

“overnight” method of cost estimation:

The Control Cost Manual uses the overnight method of cost estimation, widely 

used in the utility industry. The U.S. Energy Information Administration (EIA) 

defines ‘‘overnight cost’’ as ‘‘an estimate of the cost at which a plant could be 

constructed assuming that the entire process from planning through completion 

could be accomplished in a single day. This concept is useful to avoid any impact 

of financing issues and assumptions on estimated costs.’’ EIA presents all of its 

projected plant costs in terms of overnight costs. The overnight cost is the present 

value cost that would have to be paid as a lump sum up front to completely pay 

for a construction project. The overnight method is appropriate for BART 

determinations because it allows different pollution control equipment to be 

compared in a meaningful manner. Because ‘‘different controls have different 

expected useful lives and will result in different cash flows, the first step in 

comparing alternatives is to normalize their returns using the principle of the time 

value of money ... The process through which future cash flows are translated 

into current dollars is called present value analysis. When the cash flows involve 

income and expenses, it is also commonly referred to as net present value 

analysis. In either case, the calculation is the same: Adjust the value of future 

money to values based on the same point in time (generally year zero of the 

project), employing an appropriate interest (discount) rate and then add them 

together.’’ 

 

1

 This spreadsheet, entitled “TX Sources of Interest-new.xls,” is located in our docket.

2

 http://www.tceq.texas.gov/airquality/point-source-ei/psei.html

3

 http://ampd.epa.gov/ampd/

4

 http://www.eia.gov/electricity/data/eia860/

5

 http://www.epa.gov/airmarkt/progsregs/epa-ipm/BaseCasev410.html#needs

6

 EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002 available at 

http://www.epa.gov/ttncatc1/dir1/c_allchs.pdf.

7

 77 FR 81744.
3

We proceed in our SO2 costing analyses by examining the current SO2 emissions and the level of 

SO2 control, if any, for each of the units listed in Table 1. For the units in Table 1 without any 

SO2 control, with the exception of the PPG flat glass plant, we calculated the cost of installing 

DSI, a SDA scrubber, and a wet flue-gas desulfurization (FGD) scrubber. 

In order to estimate the costs for DSI, SDA scrubbers, and wet FGD scrubbers, we programmed 

the DSI, SDA and wet FGD cost algorithms, as employed in version 5.13 of our IPM model, 8

into three spreadsheets. These cost algorithms calculate the Total Project Cost (TPC), Fixed 

Operating and Maintenance (Fixed O&M) costs, and Variable Operating and Maintenance 

(Variable O&M) costs. We verified these spreadsheets by reproducing the costs estimated by 

Sargent & Lundy in the project reports. We further extended these cost algorithms to calculate 

the annualized costs per ton of SO2 removed ($/ton). We then performed DSI, SDA and wet 

FGD cost calculations for each unit listed in Table 1 that did not already have SO2 control. 

These spreadsheets are entitled, “DSI Cost IPM 5-13 TX Sources.xlsx,” “SDA Cost IPM 5-13 

TX Sources.xlsx,” and “Wet FGD Cost IPM 5-13 TX Sources.xlsx,” and are located in our 

Docket. We discuss the inputs and outputs for the DSI, SDA, and wet FGS cost models below. 

These cost models were based on costs escalated to 2012 dollars.9 Were we to escalate these 

costs to 2013 dollars, the capital costs would decrease by approximately 3%, because the CEPCI 

index for 2013 (567.3) is less than the index for 2012 (584.6). We have conservatively elected to 

leave the capital costs at their 2012 values. We present the results of our DSI, SDA, and wet 

FGD cost analyses in sections 3, 4, and 5. 

3 Overview of DSI Cost Model Input Parameters

Table 2, below, is a depiction of the input section of the DSI cost spreadsheet. Sample input 

parameters for the DSI cost calculation are represented by yellow highlighted cells. The input 

values designated “A” through “U” have the same meaning as those contained within the 

documentation for the IPM DSI cost algorithms (hereafter referred to as the “IPM DSI 

documentation”) referenced above. The last four input values, (i. e., Interest rate, Equipment 

Lifetime, Gross Load, and Baseline) were added by us in order to calculate the annualized costs 

per ton of SO2 removed ($/ton). Those cells that are not highlighted in yellow are interim 

calculations performed by the spreadsheet. 

 

8

 IPM Model – Updates to Cost and Performance for APC Technologies, Dry Sorbent Injection for SO2 Control 

Cost Development Methodology, Final March 2013, Project 12847-002, Systems Research and Applications 

Corporation, Prepared by Sargent & Lundy. Documentation for v.5.13: Chapter 5: Emission Control Technologies, 

Attachment 5-5: DSI Cost Methodology, downloaded from http://www.epa.gov/airmarkets/progsregs/epaipm/docs/v513/attachment5_5.pdf on 12-18-13.

IPM Model – Updates to Cost and Performance for APC Technologies, SDA FGD Cost Development Methodology, 

Final March 2013, Project 12847-002, Systems Research and Applications Corporation, Prepared by Sargent & 

Lundy. Documentation for v.5.13: Chapter 5: Emission Control Technologies, Attachment 5-2: SDA FGD Cost 

Methodology, downloaded from http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v513/attachment5_2.pdf.

IPM Model – Updates to Cost and Performance for APC Technologies, wet FGD Cost Development Methodology, 

Final March 2013, Project 12847-002, Systems Research and Applications Corporation, Prepared by Sargent & 

Lundy. Documentation for v.5.13: Chapter 5: Emission Control Technologies, Attachment 5-1: SDA FGD Cost 

Methodology, downloaded from http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v513/attachment5_1.pdf.

9

 Ibid., p.1: “The data was converted to 2012 dollars based on the Chemical Engineering Plant Index

(CEPI) data.”
4

Table 2. Sample DSI Input Parameters

3.1 Selection of DSI Cost Model Input Parameters

Below, we review the DSI Cost Model input values and discuss the procedures we employed in 

selecting them when constructing the costs for the individual DSI installations. For selected 

input parameters, we also discuss uncertainties in their values and how we dealt with them. Our 

overall goal was to select input parameters that would result in a cost that would be a reasonably 

conservative value. For example, we designed our cost model based on selecting maximum 

inputs from 2009 – 2013 for the inlet SO2 rate, the gross heat rate, the gross load, and the 

percentage lignite even if these values didn’t appear in the same year of data. We took this 
5

approach in order to ensure that the DSI system was designed to address any operating 

conditions the unit had experienced in the last five years.

Unit Size (Gross). This parameter is simply the unit size expressed in Megawatts (MW). 

Although our intent was to use gross and not net values, we are aware that MW values are often 

reported incorrectly, inconsistently, or the reported values are not specified as to whether they 

are gross or net values. We therefore invite comments on the accuracy of the values we have 

used.

Retrofit Factor. The retrofit factor represents a subjective estimation of the average retrofit 

difficulty. Because we are not aware of any significant retrofit issues at any of the facilities we 

evaluated, we adopted the default retrofit value of 1.0, which represents an average retrofit 

difficulty, for all the units we evaluated.

Gross Heat Rate. We calculated the gross heat rate by dividing the Heat Input (MMBtu) by the 

Gross Load (MW-h), downloaded from our Air Markets Program Data website,10 and 

multiplying the result by 1000W/kW to get (BTU/kWh). We chose the gross heat rate to be the 

maximum annual gross heat rate (Btu/kWh) value from 2009 – 2013 for each unit. 

SO2 Rate. The SO2 emission rate was calculated from monthly emission data.

11

 It was selected 

as the maximum monthly value from 2009 – 2013. As per the IPM DSI documentation, the SO2

emission rate has a built-in upper limit of 2.0 lbs/MMBtu. None of the units we evaluated were 

affected by this limit, although Big Brown’s maximum monthly SO2 emission rate was right at 

2.0 lbs/MMBtu.

Type of Coal. The cost algorithms allows the input of three types of coal: bituminous, lignite, 

and Powder River Basin (PRB) coal from Wyoming. Within the DSI cost algorithms, the type of 

coal is an input to an interim calculation (P), which is partly dependent on High Heat Value 

(HHV) of the coal. Also, the cost algorithms assume default values for the HHV of 11,000 

Btu/lb for bituminous coal, 8,400 Btu/lb for PRB, and 7,200 Btu/lb for lignite. The interim 

calculation, P, itself is an input to the variable O&M cost for waste disposal (VOMW). 

We note that the cost algorithms are somewhat sensitive to the selection of the type of coal. 

Therefore, a single coal selection is not appropriate for a few of the facilities for which we are 

costing DSI and scrubbers, which burn blends of Texas lignite and PRB coals (e.g., Big Brown 

Units 1, 2 and , Monticello Units 1, 2). In addition, regardless of whether a facility blends coal, 

we wished to allow the input of more accurate HHV coal values. Therefore, we adjusted the cost 

algorithms by (1) adding an option for a lignite-PRB coal blend, which if selected requires (2) 

the input of the percentage of lignite burned (remaining percentage is assumed to be PRB), plus 

(3) inputs for the HHV of the coals being burned. We select the maximum percent lignite value 

from 2009 – 2013. We use the three year average HHV values from 2009 – 2013, eliminating 

the maximum and minimum values. Our adjusted cost model accounts for this information in the 

calculation of the VOMW.

 

10

 http://ampd.epa.gov/ampd/

11

 Ibid.
6

Particulate Capture. The cost model allows for the input of either an Electrostatic Precipitator 

(ESP) or a Baghouse (BGH) as the particulate control device. As the IPM DSI documentation 

states, “Baghouses generally achieve greater SO2 removal efficiencies than ESPs by virtue of the 

filter cake on the bags, which allows for longer reaction time between the sorbent solids and the 

flue gas.”12 For those units that use an ESP along with a polishing baghouse, we assumed that 

the baghouse would have the capacity to handle the additional particulate matter from the trona 

by itself. Thus, we assumed the trona would be injected downstream of the ESP and upstream of 

the baghouse and we modeled the DSI cost on the basis of a baghouse. In all cases we assumed 

the existing particulate control device has the capacity to handle the additional load due to the 

addition of the trona. We invite comment from the affected facilities as to whether this 

assumption is valid.

Milled Trona. As discussed in the IPM DSI documentation, trona is the most commonly used 

sodium based sorbent material for DSI installations and the DSI cost algorithms assume trona. 

For a given mass, increasing the surface area of the trona has the effect of improving its ability to 

remove SO2 from the flue gas. One common method for increasing the surface area is to mill the 

trona to a particle size of 30 μm or smaller, using in-line mills. This usually results in slightly 

higher capital costs, but the overall cost effectiveness of milling the trona improves (lower 

$/ton), due to the reduction in trona required to achieve a given SO2 removal target. We 

assumed that trona would be milled in all cases.

We note, however, that other reagents have important advantages over the use of trona. 

Hydrated lime, for example, is less sensitive to the conditions of the pneumatic transport air, so 

less dehumidification or cooling is required for handling; the waste generated by lime injection is 

not soluble, so normal landfill disposal is feasible without encapsulation, lowering disposal costs; 

milling is not required; and hydrated lime is usually cheaper.

Removal Target. The removal target is the percentage reduction in SO2 desired from the SO2

rate discussed above. The IPM DSI documentation states, “When the sorbent is captured in an 

ESP, a 40 to 50% SO2 removal is typically achieved without an increase in particulate emissions. 

A higher efficiency (70 – 75%) is generally achieved with a baghouse.”13 Solvay Chemicals, 

Inc., a manufacturer of DSI sorbents, provides general performance information: 14

 

12

 IPM Model – Updates to Cost and Performance for APC Technologies, Dry Sorbent Injection for SO2 Control 

Cost Development Methodology, Final March 2013, Project 12847-002, Systems Research and Applications 

Corporation, Prepared by Sargent & Lundy, p.1.

13

 Ibid., p.2.

14

 “Dry Sorbent Injection of Sodium Sorbents,” presented at the LADCO Lake Michigan Air Directors Consortium, 

Emission Control and Measurement Technology for Industrial Sources Workshop, March 24, 2010. We note that a 

number of different DSI trona SO2 performance curves exist and our use of these curves is as a general reference 

only.
7

Figure 1. Typical Trona SO2 Removal Rates with ESP or Baghouse Installations

Figure 1 illustrates a number of important concepts concerning the performance potential of DSI:

 SO2 removal efficiencies for trona DSI installations perform better when a baghouse 

rather than an ESP particulate control device is employed. 

 The Normalized Stoichiometric Ratio (NSR), which is simply a measure of the actual 

usage needed compared to the theoretical need, governs the SO2 removal efficiency. In 

other words, for a given particulate control device, greater SO2 removal efficiencies 

require increasingly greater amounts of trona, with diminishing returns.

 A wide range of SO2 removal efficiency is possible for a given NSR and particulate

control device. We interpret this range to be in part dependent on site specific conditions.

We lack the site specific information, which we believe requires an individual performance test, 

in order to be able to accurately determine the maximum SO2 removal efficiency for the 

individual units listed in Table 1. We are aware that a number of the facilities in Table 1 have 

conducted such testing. However, although we have examined that testing, most of the facilities 

have claimed it as Confidential Business Information (CBI) and requested protection from public 

disclosure as provided by 40 C.F.R. Part 2.
8

However, we nevertheless must evaluate DSI as a viable, proven method of SO2 control. We 

must do the same for SO2 scrubbing, and in so doing, compare the visibility benefits and costs of 

each technology in order to propose which, if either technology, we should propose for 

installation due to the RP and/or LTS requirements. We therefore propose the following 

methodology:

 We will evaluate each unit at its maximum recommended DSI performance level, 

according to the IPM DSI documentation,15 assuming milled trona: 80% SO2 removal for 

an ESP installation and 90% SO2 removal for a baghouse installation. This level of 

control is within that of SO2 scrubbers, and thus allows a better comparison of the costs 

of DSI and scrubbers.

 However, (1) we do not know whether a given unit is actually capable of achieving these 

control levels and (2) we believe it is useful to evaluate lesser levels of DSI control (and 

correspondingly lower costs). We therefore also evaluate all the units at a DSI SO2

control level of 50%, which we believe is likely achievable for most units.

 We invite comments on whether particular units have performed DSI testing and have 

concluded they cannot achieve a SO2 reduction between 50% and 80/90%. For instance, 

Luminant states in its response to our Section 114(a) letter regarding its Big Brown and 

Monticello units:

Luminant commissioned the study of dry sorbent injection ("DSI") 

at these units in 2011. These studies determined that a very high 

feed rate (in the range of 20-30%) was required to achieve modest 

SO2 removal. Further, it was determined that other economic and 

operational factors make the use of DSI infeasible. For example, 

sorbent build-up was determined to cause degraded performance of 

the control equipment over time, as well as significant, repeat 

down time on a regular basis (i.e., every few days) to remove the 

buildup. In addition to the high cost of the sorbent required, the 

disposal and transport of the used sorbent (a Texas Class 1 waste) 

would result in significant additional cost. Thus, the use of DSI 

was determined infeasible from both an operational and economic 

point of view, and further evaluation has been discontinued.

As a consequence of this statement, which is discussed more fully in the CBI material 

Luminant has submitted, we have concluded that DSI is not a feasible alternative for the 

Luminant facilities.

Include Fly Ash Waste Rate in VOM. The cost model allows for the inclusion or exclusion of 

the fly ash in the Variable O&M costs for waste disposal via a drop down menu. As the IPM 

 

15

 IPM Model – Updates to Cost and Performance for APC Technologies, Dry Sorbent Injection for SO2 Control 

Cost Development Methodology, Final March 2013, Project 12847-002, Systems Research and Applications 

Corporation, Prepared by Sargent & Lundy, p. 7.
9

DSI documentation notes, when the sodium sorbent (e.g., trona) is captured in the same 

particulate control device as the fly ash, the resulting waste must be land filled. We are aware 

that a number of facilities sell their fly ash, and that the addition of trona may render that fly ash

unsalable. We chose this option in all cases. 

We note that a few of the units we analyzed use an ESP with a polishing baghouse. Such a 

configuration could allow for the injection of the trona between the ESP and the baghouse, thus 

allowing for excluding the fly ash from the VOM calculation. This would have the effect of 

significantly improving the cost effectiveness (reducing the $/ton). However, as the IPM DSI 

documentation notes, the disposal cost (discussed below) should be increased to account for the 

additional difficulty in handling the pure sodium waste product. This has the effect of 

diminishing the cost effectiveness (increasing the $/ton), and erasing much of the gain from 

excluding the fly ash waste rate from the VOM. We invite the affected facilities to inform us 

whether they would configure DSI in such a manner. 

Include Aux Power in VOM. The cost model allows for the inclusion or exclusion of the 

additional auxiliary power required for the DSI system to be included in the variable operating 

costs via a drop down menu. We chose to include this additional auxiliary power in all cases.

Trona Cost. The cost of trona is the largest portion of the variable operating costs. It is partly 

dependent on the delivery costs. The United States Geological Survey estimates the average 

2012 cost of soda ash to be $135/ton F.O.B at the mine or plant.16 Considering that trona must 

be delivered from Wyoming to Texas, we contacted Solvay, which is a supplier of Trona, in 

order to improve this estimate. We were able to get estimated trona costs and some of the 

estimated freight delivery costs.17 Trona was quoted as being $100 - $105/ton, so we selected 

$105/ton. For Big Brown and Welsh, we estimate the freight costs by using the Monticello 

quote, since all three facilities are in the same regional area of Texas. For Tolk, we estimate the 

freight cost as the largest value we were quoted, which is that for Coleto Creek.

Table 3: Cost of Trona

Facility Cost of Trona

($/ton)

Freight by Railroad

($/ton)

Total Cost

($/ton)

Big Brown $105 $76.25* $181.25

Coleto Creek $105 $89.55 $194.55

Monticello $105 $76.25 $181.25

W. A. Parish $105 $86.73 $191.73

Tolk $105 $89.55* $194.55

Welsh $105 $76.25* $181.25

* Estimated

 

16

 U.S. Department of the Interior U.S. Geological Survey Mineral Commodity Summaries 2013, p. 148. Available 

at http://minerals.usgs.gov/minerals/pubs/mcs/2013/mcs2013.pdf

17

 Email from Mike Wood to Joe Kordzi, 7-9-2014.
10

Waste Disposal Cost. The waste disposal cost is the second largest portion of the variable 

operating costs. The cost model suggests a cost of $50/ton if the trona waste and fly ash are 

comingled and disposed of together, and $100/ton, if the trona waste is not comingled with the 

fly ash and is disposed of separately. We assumed the trona waste and the fly ash were 

comingled and disposed of together for all cases, and therefore set this value to $50/ton. We 

note that the waste disposal cost is an area in which our cost model could be under predicting the 

true cost. Because adding trona to the fly ash increases the water solubility of the waste, an 

upgraded landfill may be required.18 We invite comments on this issue.

Aux Power Cost. Auxiliary power cost is the additional power required by the DSI control 

system. It is the smallest portion of the variable operating costs. We note from our examination 

of CBI material we received in response to our Section 114(a) requests that the true power cost 

for most if not all of the units we analyze is considerably less than this value. However, the cost 

model is fairly insensitive to the value used for the auxiliary power cost, and we assumed the 

default value of $0.06/kWh in all cases. 

Operating Labor Rate. The operating labor rate is the largest portion of the fixed operating and 

maintenance cost. We chose the default value of $60/hour for all cases.

Interest Rate. The interest rate is used in the calculation of the capital recovery factor, which itself 

is used in the calculation of the annualized capital costs. This input value is not a part of the IPM 

DSI cost algorithms and was added by us in order to calculate the cost effectiveness in $/ton. For 

cost analyses related to government regulations, an appropriate “social” interest (discount) rate 

should be used, unless site specific information is available. We calculated capital recoveries using 

3 percent and 7 percent interest rates in determining cost-effectiveness for the Regulatory Impact 

Analysis (RIA) for the BART Guidelines.19 Also, a 7 percent interest rate is recommended by 

Office of Management and Budget.20 

Equipment Lifetime. The Equipment lifetime is another factor used in the in the calculation of 

the capital recovery factor. This input value is not a part of the IPM DSI cost algorithms and was 

added by us in order to calculate the cost effectiveness in $/ton. It represents the actual or 

service life of the equipment in question. Because a DSI system is relatively simple and reliable, 

we have no reason to conclude that its service life would be any less than what we typically use 

for scrubber cost analyses. We therefore adopt that same value here, which is 30 years. 

Gross Load. The gross load (MW-h) was obtained from emissions data downloaded from our 

Air Markets Program Data website.21 It was selected as the maximum value from 2009 – 2013

 

18

 The Ins and Outs of SO2 Control, Lindsay Morris, Power Engineering, 6-1-2012. “Jonas Klingspor, vice 

president of business development and marketing for URS, said one potential concern for using DSI systems with 

trona is the disposal of the product. ‘Unless you have a double-lined, capped landfill, the water soluble byproduct 

may be a serious concern.’”

19

 Regulatory Impact Analysis for the Final Clean Air Visibility Rule or the Guidelines for Best Available Retrofit 

Technology (BART) Determinations Under the Regional Haze Regulations, EPA-0452/R-05-004 (June 2005).

20

 A 7.0 percent interest rate is recommended by Office of Management and Budget, Circular A-4, Regulatory 

Analysis, http://www.whitehouse.gov/omb/circulars-a004-a-4/.

21

 http://ampd.epa.gov/ampd/
11

in order to conservatively maximize the cost. This input value is not a part of the IPM DSI cost 

algorithms. It was added by us in order to convert the variable and operating costs, which the 

cost algorithms express in $/MW-h and $/kW-yr, respectively, into dollars which are 

subsequently used in calculating the cost effectiveness in dollars per ton of SO2 removed ($/ton). 

SO2 Emission Baseline. The SO2 emission baseline is calculated from emissions data 

downloaded from our Air Markets Program Data website.22 It was selected as the 2009 – 2013

five year average of the SO2 annual emissions, excluding the maximum and minimum values. 

This input value is not a part of the IPM DSI cost algorithms. It was added by us in order to 

calculate the annual SO2 emission reduction from the installation of DSI, which itself is an input 

to the cost effectiveness in $/ton. We concluded that using this kind of an average was a 

reasonable compromise between simply selecting the maximum value from 2009 – 2013, or

using the average of the values from 2009 – 2013.

3.2 DSI Cost Model Output

A sample of the IPM DSI cost model output is depicted below in Table 4. The cost algorithms 

calculate the Capital, Engineering and Construction Cost (CECC) and the fixed and variable 

operating costs (FOM and VOM, respectively). Following this, we add a calculation for the 

capital recovery factor, based on the interest rate and the Equipment lifetime, and use it to 

annualize the CECC. In so doing, we exclude any Allowance for Funds Used During 

Construction (AFUDC) and “owner’s costs.”23 To the annualized CECC, we add the FOM and 

VOM to arrive at the total annualized costs. Lastly, we divide this figure by the SO2 emissions 

reduction to calculate the cost effectiveness in $/ton.

 

22

 Ibid.

23

 We exclude any AFUDC and “owner’s costs” from regional haze control cost calculations, as they are disallowed 

by the “overnight” cost method used in the Control Cost Manual. In this case, however, AFUDC is assumed by the 

cost algorithms to be zero anyway, since a DSI project is expected to be completed within one year. 
12

Table 4. Sample DSI Output

Capital Cost Calculation

 BM ($) $18,348,000

 BM ($/kW) 37

Total Project Cost

 A1 $917,000

 A2 $917,000

 A3 $917,000

 CECC($) $21,099,000

 CECC($/kW) 42

 B1 $1,055,000

 TPC ($) $22,154,000

 TPC ($/kw) 44

 B2 $0

 TPC ($) $22,154,000

 TPC ($/kw) 44

Fixed O&M Cost

 FOMO ($/kW yr) 0.50

 FOMM ($/kW yr) 0.37

 FOMA ($/kW yr) 0.02

 FOM ($/kW yr) 0.89

Variable O&M

 VOMR ($/MWh) 5.55

 VOMW ($/MWh) 2.87

 VOMP ($/MWh) 0.39

 VOM ($/MWh) 8.82

Annualization

Capital, engineering and 

construction cost $21,099,000

Capital Recovery factor 0.0806

Annualized capital costs $1,700,293

Variable operating costs $35,260,822

Fixed operating costs $404,356

Total annualized costs $37,365,470

SO2 emissions reduction 

(tons) 15,000

$/ton 2,491

FOM*(Gross Load)*(1000kw/MW)*(8760 hours/year)

H/(100%)*(SO2 emission baseline)

Excludes owner's costs and AFUDC

VOM*(Gross Load)

Fixed O&M additional addministrative labor costs

Total Fixed O&M costs

Variable O&M costs for trona reagent

Variable O&M costs for waste disposal that includes both the sorbent and the fly ash waste not removed prior to the 

Variable O&M costs for additional auxillary power required (refer to Aux Power % above)

Total variable O&M costs

Fixed O&M maintenance material and labor costs

Total project cost without AFUDC

Total project cost per kW without AFUDC

AFUDC (zero for less than 1 year engineering and construction cycles)

Total project cost

Total project cost per kW

Fixed O&M additional operating labor costs. Based on two additional operators.

Base module cost per kW

Engineering and construction management costs

Labor adjustment for 6 x 10 hour shift premium, per diem, etc..

Contractor profit and fees

Capital, engineering and construction cost subtotal

Capital, engineering and construction cost subtotal per kW

Owners costs including "home office" costs (owner engineering, management, and procurement activities)

Explanation of Calculation

Includes: equipment, installation, buildings, foundations, electrical, and retrofit difficulty.

Base DSI module includes all equipment from unloading to injection. 
13

3.3 Summary of DSI Cost Model Results

Below in Table 5 is a summary of our DSI cost model results:

Table 5. Summary of DSI Cost Model Results
14

3.4 Discussion of DSI Cost Model Results

Some observations are apparent from the DSI cost model results displayed above:

 The vast majority of the total annualized cost of DSI is due to the variable operating cost, 

VOM. This is due to the relatively low capital cost of the equipment, and the relatively 

high cost of the trona.

 Unlike the cost effectiveness of scrubbers, which we will discuss below, for a given 

facility, the cost effectiveness of DSI worsens (higher $/ton) with increasing control 

levels. This is due to the inefficient use of the sorbent in DSI systems. Unlike scrubbers, 

in which the reaction of the reagent and the SO2 in the exhaust gas occurs within a large 

vessel (e.g., an absorber), which can be highly controlled, DSI lacks an absorber. Greater 

SO2 removal efficiencies require increasingly greater amounts of trona, with diminishing 

returns.

 For a given level of control, the cost effectiveness of DSI generally improves as the 

tonnage of SO2 removal increases.

4 Overview of SDA Cost Model Input Parameters

Table 6, below, is a depiction of the input section of the SDA cost spreadsheet. Sample input 

parameters for the SDA cost calculation are represented by the yellow highlighted cells. The 

input values designated “A” through “T” have the same meaning as those contained within the 

documentation for the IPM SDA cost algorithms (hereafter referred to as the “IPM SDA

documentation”) referenced above. The last four input values, (i. e., Interest rate, Equipment 

Lifetime, Gross Load, and Baseline) were added by us in order to calculate the annualized costs 

per ton of SO2 removed ($/ton). Those cells that are not highlighted in yellow are interim 

calculations performed by the spreadsheet. 
15

Table 6. Sample SDA Input Parameters
16

4.1 Selection of SDA Cost Model Input Parameters

Below, for those input values that are different than our DSI cost model, we review the SDA cost 

model input values and discuss the procedures we employed in selecting them when developing

the cost estimates for the individual SDA installations. 

Type of Coal: Unlike the DSI cost algorithms discussed above, the SDA cost algorithms are 

relatively insensitive to the type of coal. For instance, simply changing the type of coal from 

lignite to PRB for Big Brown Unit 1 results in an improvement in the cost effectiveness (lower 

$/ton) of less than 1%. Therefore, for those facilities that burn a mixture of lignite and PRB, we 

are simply assuming they burn lignite for the purposes of costing a SDA system.

Operating SO2 Removal. The operating SO2 removal is the percentage reduction in SO2 desired 

from the SO2 rate. The IPM SDA Documentation states: “The curve fit was set to represent 

proprietary in-house cost data of a "typical" SDA FGD retrofit for removal of 95% of the inlet 

sulfur. It should be noted that the lowest available SO2 emission guarantees, from the original 

equipment manufacturers of SDA FGD systems, are 0.06 lb/MMBtu.” As with our Oklahoma 

FIP,

24 we have assumed a level of control equal to 95%, unless that level of control would fall 

below an outlet SO2 level of 0.06 lb/MMBtu, in which case, we assume the percentage of control 

equal to 0.06 lbs/MMBtu.

Lime Cost. The cost of lime is the largest portion of the variable operating costs. At most dry 

scrubber facilities, the lime reagent is produced by onsite slaking of quicklime (calcium oxide) to 

produce a slurry of solid hydrated lime (calcium hydroxide) particles.25 Therefore, we assume in 

our cost model that quicklime is delivered to the facility where it is then slaked onsite, and that 

this cost is a part of the “base reagent preparation and waste recycle/handling” cost module.

26

 

The USGS estimates the average 2012 cost of quicklime to be $116/ton at the lime plant.27 

Although we do not have lime pricing available for Texas, lime is widely available within the 

State and we expect delivery charges to be minimal. Consequently, we consider the cost 

algorithm default cost for delivered lime of $125/ton to be reasonable, and we have adopted it for 

all cases. We invite the affected facilities to provide comment on this assumption.

Waste Disposal Cost. The waste disposal cost is the second largest portion of the variable 

operating costs. The cost model default is $30/ton and we have adopted it for all cases.

 

24

 As discussed previously in our TSD and elsewhere in this notice and the Supplemental RTC, control efficiencies 

reasonably achievable by dry scrubbing and wet scrubbing were determined to be 95% and 98% respectively. 76 FR 

81742.

25

 Primex Process Specialists. “Optimizing Scrubber Performance,” p. 3. Available at 

http://www.primexprocess.com/pdf/Paper_4.pdf

26

 IPM Model – Updates to Cost and Performance for APC Technologies, SDA FGD Cost Development 

Methodology, Final, March 2013. Sargent & Lundy, p. 3

27

 U.S. Department of the Interior U.S. Geological Survey Mineral Commodity Summaries 2013, p. 92. Available 

at http://minerals.usgs.gov/minerals/pubs/mcs/2013/mcs2013.pdf
17

Elevation Adjustment. The IPM SDA documentation states that the cost methodology is based 

on a unit located within 500 feet of sea level:28

The actual elevation of the site should be considered separately and factored into 

the cost due to the effects on the flue gas volume. The base absorber island and 

balance of plant costs are directly impacted by the site elevation. These two base 

cost modules should be increased based on the ratio of the atmospheric pressure 

between sea level and the unit location. As an example, a unit located 1 mile 

above sea level would have an approximate atmospheric pressure of 12.2 psia. 

Therefore, the base absorber island and balance of plant costs should be increased 

by: 

14.7 psia/12.2 psia = 1.2 multiplier to the base absorber island and balance of 

plant costs.

Although the cost algorithms call for this correction, no implementation was provided. 

Consequently, we included this atmospheric pressure adjustment in our SDA cost model by 

incorporating an atmospheric pressure change with elevation calculation provided by NASA.29 

In order to utilize this calculation, we constructed Table 7, below, which uses the average of the 

latitude and longitude of the stack locations. We entered these coordinates into an online 

service30 that returns the elevation above sea level.

Table 7. Elevation of Sources undergoing RP and LTS analyses

Latitude Longitude Elevation

Big Brown 31.8200 -96.0552 334.6

Coleto Creek 28.7108 -97.2139 108.3

San Miguel 28.7072 -98.4722 318.2

Martin Lake 32.2596 -94.5707 324.8

Monticello 33.0913 -95.0376 383.9

Limestone 31.4195 -96.2539 436.4

Sandow 4 30.5658 -97.0631 492.1

Tolk 34.1797 -102.5750 3753.3

W. A. Parish 29.4792 -95.6324 78.7

Welsh 33.0564 -94.8458 377.3

 

28

 IPM SDA documentation, p. 2.

29

 http://exploration.grc.nasa.gov/education/rocket/atmosmet.html. It should be noted that in addition to the NASA 

algorithm, this calculation requires converting the input feet to meters (multiplying elevation*0.3048) and K-Pa to 

psi (multiplying the calculation by 0.145038).

30

 http://www.earthtools.org/webservices.htm#height
18

As can be seen from Table 7, only the Tolk facility is located at an elevation that exceeds 500 

feet above sea level, and thus requires an elevation adjustment, which we included in our SDA 

cost model for this facility. This correction had the effect of worsening the cost effectiveness 

(increasing the $/ton) for Tolk by approximately 5%.

4.2 SDA Cost Model Output

A sample of the IPM SDA cost model output is depicted below in Table 8. As with our DSI cost 

model, the cost algorithms calculate the CECC and the FOM and VOM, and we add a calculation 

for the capital recovery factor, based on the interest rate and the Equipment lifetime, and use it to 

annualize the CECC. We exclude AFUDC and “owner’s costs.” To the annualized CECC, we 

add the FOM and VOM to arrive at the total annualized costs. Lastly, we divide this figure by 

the SO2 emissions reduction to calculate the cost effectiveness in $/ton.
19

Table 8. Sample SDA Output

Capital Cost Calculation

BMR($) 51,886,000

BMF($) 31,337,000

BMB($) 73,422,000

BMBA($) 73,422,000

BM($) 156,645,000

BM($/kW) 313

Total Project Cost

A1 15,665,000

A2 15,665,000

A3 15,665,000

CECC ($) 203,640,000

CECC($/kW) 407

B1 10,182,000

TPC' ($) 213,822,000

TPC' ($/kw) 428

B2 21,382,000

TPC ($) 235,204,000

TPC ($/kW) 470

Fixed O&M Cost

FOMO ($/kW-yr) 2.00

FOMM ($/kW-yr) 4.70

FOMA ($/kW-yr) 0.12

FOM ($/kW-yr) 6.81

Variable O&M Cost

VOMR ($/MWh) 1.81

VOMW ($/MWh) 0.96

VOMP ($/MWh) 0.81

VOMM ($/MWh) 0.06

VOM ($/MWh) 3.64

Annualization

 Capital, engineering and 

construction cost $203,640,000

Capital Recovery factor 0.0806

Annualized capital costs $16,410,615

Variable operating costs $15,645,084

Fixed operating costs $3,340,299

Total annualized costs $35,395,997

SO2 emissions reduction (tons) 29,061

$/ton 1,218

Explanation of Calculation 

Includes: Equipment, installation, buildings, foundations, electrical, and retrofit difficulty

Base module absorber island cost

Base module reagent preparation and waste recycle/handling cost

Base module balance of plant costs (including ID or booster fans, piping, ductwork, electrical, 

etc.)

Adjustment to base module balance of plant costs (including ID or booster fans, piping, 

ductwork, electrical, etc.), if elevation is greater than 500 feet. See page 2 of the S&L 

documentation.

Total Base module cost including retrofit factor

Base module cost per kW

Total project cost per kW without AFUDC

Engineering and Construction Mnagement costs

Labor adjustment for 6 x 10 hour shift premium, per diem, etc.

Contractor profit and fees. 

Capital, engineering and construction cost subtotal

Capital, engineering and construction cost subtotal per kW

Owner's costs including all "home office" costs (owner's engineering, management, and 

procurement activities)

Total project cost without AFUDC

AFUDC (Based on a 3 year engineering and construction cycle)

Total Project Cost (including AFUDC and owner's costs)

Total Project Cost per kW (including AFUDC and owner's costs)

Fixed O&M additional operating labor costs. Based on eight additional operators.

Fixed O&M costs for waste disposal

Fixed O&M additional administrative labor costs

Total Fixed O&M costs

Variable O&M costs for lime reagent

Variable O&M costs for waste disposal

Variable O&M costs for additional auxiliary power required including additional fan power 

(Refer to Aux Power % above)

Variable O&M costs for makeup water

Total Variable O&M Costs

J/(100%)*(SO2 emission baseline)

Excludes owner's costs and AFUDC

VOM*(Gross Load)

FOM*(Gross Load)*(1000kw/MW)*(8760 hours/year)
20

4.3 Summary of SDA Cost Model Results

Below in Table 9 is a summary of our SDA cost model results:

Table 9. Summary of SDA Cost Model Results

4.4 Summary of SDA Cost Model Results

Some observations are apparent from the SDA cost model results displayed above:

 In contrast to our DSI cost model results, a greater portion of the total annualized cost of 

SDA is due to the annualized capital costs and the annualized capital cost is greater than 

the total operating cost in most cases. However, the annualized capital costs and the 

operating costs are much closer in magnitude. 

 Unlike the cost effectiveness of DSI, the cost effectiveness of SDA improves (lower

$/ton) with increasing control levels. 

5 Overview of Wet FGD Cost Model Input Parameters

Table 10, below, is a depiction of the input section of the wet FGD cost spreadsheet. Sample 

input parameters for the wet FGD cost calculation are represented by the yellow highlighted

cells. The input values designated “A” through “T” have the same meaning as those contained 

within the documentation for the IPM wet FGD cost algorithms (hereafter referred to as the 

“IPM wet FGD documentation”) referenced above. The last four input values, (i. e., Interest 

rate, Equipment Lifetime, Gross Load, and Baseline) were added by us in order to calculate the 

annualized costs per ton of SO2 removed ($/ton). Those cells that are not highlighted in yellow 

are interim calculations performed by the spreadsheet. 
21

Table 10. Sample Wet FGD Input Parameters

5.1 Selection of Wet FGD Cost Model Input Parameters

Below, for those input values that are different than our SDA cost model, we review the wet 

FGD Cost Model input values and discuss the procedures we employed in selecting them when 

developing the cost estimates for the individual wet FGD installations.

Operating SO2 Removal. The operating SO2 removal is the percentage reduction in SO2 desired 

from the SO2 rate. The IPM wet FGD Documentation states: “The least squares curve fit of the 

data was defined as a "typical" wet FGD retrofit for removal of 98% of the inlet sulfur. It should 

be noted that the lowest available SO2 emission guarantees, from the original equipment 

manufacturers of wet FGD systems, are 0.04 lb/MMBtu.” As we established in our Oklahoma 
22

FIP,31 this level of control is achievable with wet FGD. We have therefore assumed a level of 

control equal to 98%, unless that level of control would fall below an outlet SO2 level of 0.04 

lb/MMBtu, in which case, we assume the percentage of control equal to 0.04 lbs/MMBtu.

Limestone Cost. Unlike the DSI and SDA cost algorithms, the wet FGD cost algorithms are 

fairly insensitive to the cost of the reagent – limestone. We note that the cost of limestone is 

partly dependent on the delivery cost, but limestone is widely available within Texas. 

Consequently, we consider the cost algorithm default cost for delivered lime of $30/ton to be 

reasonable, and we have adopted it for all cases.

Elevation Adjustment. Our wet FGD cost model incorporates the same elevation adjustment 

discussed above with regard to the SDA cost model. Again, only the Tolk facility required this 

adjustment, which we incorporated into our cost model for this facility. This correction had the 

effect of worsening the cost effectiveness for Tolk (increasing the $/ton) by approximately 6%.

Wastewater Treatment. The IPM wet FGD documentation states:

The evaluation includes a user selected option for a wastewater treatment facility. 

The base capital cost includes minor physical and chemical wastewater treatment. 

However, in the future more extensive wastewater handling may be required. 

Although an option for wastewater treatment is provided, no logic has been 

developed to accommodate the additional wastewater treatment costs.

Consequently, our cost model incorporates minor physical and chemical wastewater treatment. 

We invite comment from the affected facilities as to whether they believe more extensive 

wastewater treatment would be required for their facility, and if so, to provide an estimate of that 

cost.

5.2 Wet FGD Cost Model Output

A sample of the IPM wet FGD cost model output is depicted below in Table 11. As with our 

DSI and SDA cost models, the cost algorithms calculate the CECC and the FOM and VOM, and 

we add a calculation for the capital recovery factor, based on the interest rate and the Equipment 

lifetime, and use it to annualize the CECC. We exclude AFUDC and “owner’s costs.” To the 

annualized CECC, we add the FOM and VOM to arrive at the total annualized costs. Lastly, we 

divide this figure by the SO2 emissions reduction to calculate the cost effectiveness in $/ton.

 

31

 As discussed previously in our TSD and elsewhere in this notice and the Supplemental RTC, control efficiencies 

reasonably achievable by dry scrubbing and wet scrubbing were determined to be 95% and 98% respectively. 76 FR 

81742.
23

Table 11. Sample Wet FGD Output

Capital Cost Calculation

BMR($) 48,869,000

BMF($) 23,674,000

BMW($) 14,536,000 Base reagent 

BMB($) 89,730,000

BMBA($) 89,730,000

BM($) 176,809,000

BM($/kW) 354

Total Project Cost

A1 17,681,000

A2 17,681,000

A3 17,681,000

CECC ($) 229,852,000

CECC($/kW) 460

B1 11,493,000

TPC' ($) 241,345,000

TPC' ($/kw) 483

B2 24,135,000

TPC ($) 265,480,000

TPC ($/kW) 531

Fixed O&M Cost

FOMO ($/kW-yr) 3.00

FOMM ($/kW-yr) 5.30

FOMA ($/kW-yr) 0.15

FOM ($/kW-yr) 8.45

Variable O&M Cost

VOMR ($/MWh) 0.73

VOMW ($/MWh) 1.31

VOMP ($/MWh) 0.95

VOMM ($/MWh) 0.08

VOM ($/MWh) 3.07

Annualization

 Capital, engineering and 

construction cost $229,852,000

Capital Recovery factor 0.0806

Annualized capital costs $18,522,946

Variable operating costs $13,184,075

Fixed operating costs $4,144,689

Total annualized costs $35,851,710

SO2 emissions reduction (tons) 29,061

$/ton 1,234

J/(100%)*(SO2 emission baseline)

Excludes owner's costs and AFUDC

VOM*(Gross Load)

FOM*(Gross Load)*(1000kw/MW)*(8760 hours/year)

Variable O&M costs for makeup water

Total Variable O&M Costs

Variable O&M costs for additional auxiliary power required including additional fan power 

(Refer to Aux Power % above)

Fixed O&M additional operating labor costs. IF MW > 500, then 16 operators, else 12 operators

Fixed O&M additional maintenance material and labor costs

Fixed O&M additional administrative labor costs

Total Fixed O&M costs

Variable O&M costs for limestone reagent

Variable O&M costs for waste disposal

Owner's costs including all "home office" costs (owner's engineering, management, and 

procurement activities)

Total project cost without AFUDC

Total project cost per kW without AFUDC

AFUDC (Based on a 3 year engineering and construction cycle)

Total Project Cost (including AFUDC and owner's costs)

Total Project Cost per kW (including AFUDC and owner's costs)

Capital, engineering and construction cost subtotal per kW

Base balance of plant costs (including ID or booster fans, piping, ductwork, electrical, etc.)

Adjustment to base module balance of plant costs (including ID or booster fans, piping, 

ductwork, electrical, etc.), if elevation is greater than 500 feet. See page 2 of the S&L 

documentation.

Total Base module cost including retrofit factor

Base cost per kW

Engineering and Construction Mnagement costs

Labor adjustment for 6 x 10 hour shift premium, per diem, etc.

Contractor profit and fees. 

Capital, engineering and construction cost subtotal

Base reagent preparation and waste recycle/handling cost

Explanation of Calculation 

Includes: Equipment, installation, buildings, foundations, electrical, and retrofit difficulty

Base absorber island cost
24

5.3 Summary of Wet FGD Cost Model Results

Below in Table 12 is a summary of our wet FGD cost model results:

Table 12. Summary of Wet FGD Cost Model Results

5.4 Summary of Wet FGD Cost Model Results

Some observations are apparent from the wet FDG cost model results displayed above:

 As with our SDA cost model results, the majority of the total annualized cost of SDA is 

due to the annualized capital costs. However, the annualized capital costs is much greater 

than the operational costs. This is due to the slightly higher capital cost of the equipment 

and the lower cost of reagent (limestone versus lime), in relation to SDA.

 As with our SDA cost model, the cost effectiveness of wet FGD improves (lower $/ton) 

with increasing control levels. 

Table 13 compares the capital cost and cost effectiveness of both technologies:

Table 13. Capital cost and cost effectiveness of wet FGD versus SDA

Facility Unit

Capital Cost 

SDA

Capital Cost 

Wet FGD

% Difference 

Capital Cost 

Wet FGD 

over SDA

$/ton 

SDA

$/ton 

Wet

% 

Difference 

$/ton Wet 

FGD over 

SDA

Big Brown 1 $226,656,000 $256,032,000 12.96 $1,377 $1,255 -8.9

2 $229,544,000 $259,141,000 12.89 $1,373 $1,257 -8.5

Coleto Creek 1 $240,408,000 $262,435,000 9.16 $2,356 $2,278 -3.3

Monticello 1 $224,262,000 $250,804,000 11.84 $2,012 $1,937 -3.8

2 $227,409,000 $254,177,000 11.77 $2,254 $2,170 -3.7
25

Tolk 171B $218,306,000 $243,048,000 11.33 $3,178 $3,204 0.8

172B $226,957,000 $252,559,000 11.28 $2,998 $3,019 0.7

W A Parish WAP5 $240,112,000 $260,195,000 8.36 $2,441 $2,389 -2.2

WAP6 $248,503,000 $270,350,000 8.79 $2,401 $2,334 -2.8

WAP7 $211,443,000 $233,698,000 10.53 $2,559 $2,542 -0.7

Welsh 1 $201,549,000 $221,282,000 9.79 $3,489 $3,508 0.5

2 $202,108,000 $221,821,000 9.75 $3,438 $3,454 0.5

3 $204,177,000 $224,298,000 9.85 $3,368 $3,379 0.3

 The capital cost of wet FGD is higher than SDA by approximately 8 – 13%. However, 

wet FGD delivers a significant improvement in the cost effectiveness for a number of the 

units, increasing as the tonnage of SO2 removal increases This is mainly due to the 

greater level of control (98% maximum versus 95% maximum) of wet FGD over SDA, 

which tends to offset the additional cost of wet FGD. The exceptions to this are the Tolk 

and Welsh units, which burn 100% PRB coal. This is not unexpected as many EGUs that 

burn PRB coal and are equipped with SO2 scrubbers have installed SDA scrubbers.

6 Upgrading Existing Scrubber Efficiencies

In Sections 3, 4, and 5, above, for those facilities with no SO2 control, we contrasted the cost of 

DSI, SDA, and wet FGD. We then compared those costs to the visibility benefit from those 

controls from our visibility projection modeling, and we propose a RP and LTS determination. 

Here, we conduct similar analyses for those units listed in Table 1 with an existing SO2 scrubber

in order to determine if cost effective scrubber upgrades are available. Because all of the 

scrubber systems we evaluate are wet scrubbers, we limit our analyses of scrubber upgrades to 

wet scrubbers.

We proceed by first presenting information concerning the kinds of options generally available 

to facilities for upgrading their existing scrubbers. Following this, to the extent possible, we 

review all of the information we have at our disposal regarding the status of the existing 

scrubbers for each unit. This includes any upgrades the facility may have already installed. 

Although some of this information has been gleaned from public sources of information, much 

of it was collected as a result of our information collection effort. The companies that have 

supplied this information have asserted a Confidential Business Information (CBI) claim for 

much of it, as provided in 40 C.P.R. § 2.203(b). We therefore must redact any CBI information 

we utilize in our analyses, or otherwise disguise it so that it cannot be traced back to its specific 

source. Similar to our DSI, SDA, and wet FGD analyses we then contrast the cost of the various 

options for upgrading those scrubbers. Following this, we compare those costs to the visibility 

benefit from those controls from our visibility projection modeling, and propose a RP and LTS 

determination. 
26

We have long recognized that existing underperforming SO2 scrubbers are likely capable of 

being upgraded to much higher removal efficiencies. For example, we made this statement in 

the BART rule:32

For those BART-eligible EGUs with preexisting post-combustion SO2 controls 

achieving removal efficiencies of at least 50 percent, your BART determination 

should consider cost effective scrubber upgrades designed to improve the 

system’s overall SO2 removal efficiency. There are numerous scrubber 

enhancements available to upgrade the average removal efficiencies of all types 

of existing scrubber systems. We recommend that as you evaluate the definition 

of ‘‘upgrade,’’ you evaluate options that not only improve the design removal 

efficiency of the scrubber vessel itself, but also consider upgrades that can 

improve the overall SO2 removal efficiency of the scrubber system. Increasing a 

scrubber system’s reliability, and conversely decreasing its downtime, by way of 

optimizing operation procedures, improving maintenance practices, adjusting 

scrubber chemistry, and increasing auxiliary equipment redundancy, are all ways 

to improve average SO2 removal efficiencies. 

We recommend that as you evaluate the performance of existing wet scrubber 

systems, you consider some of the following upgrades, in no particular order, as 

potential scrubber upgrades that have been proven in the industry as cost effective 

means to increase overall SO2 removal of wet systems: 

(a) Elimination of Bypass Reheat; 

(b) Installation of Liquid Distribution Rings; 

(c) Installation of Perforated Trays; 

(d) Use of Organic Acid Additives; 

(e) Improve or Upgrade Scrubber Auxiliary System Equipment; 

(f) Redesign Spray Header or Nozzle Configuration.

We recommend that as you evaluate upgrade options for dry scrubber systems, 

you should consider the following cost effective upgrades, in no particular order: 

(a) Use of Performance Additives; 

(b) Use of more Reactive Sorbent; 

(c) Increase the Pulverization Level of Sorbent; 

(d) Engineering redesign of atomizer or slurry injection system. 

Industry has also recognized that the efficiency of existing SO2 scrubbers can and have been 

upgraded significantly and a number of companies offer scrubber upgrade services. For 

instance, URS makes this statement in its, “Assessment of Technology Options Available to 

Achieve Reductions of Hazardous Air Pollutants:”33

 

32 70 FR 39171.

33

 Lipinski, George, et al, Assessment of Technology Options Available to Achieve Reductions of Hazardous Air 

Pollutants, URS, April 5, 2011, p. A-5.
27

Upgrades have been performed on a large number of FGD units over the past 15 

years and have resulted in increased SO2 removal performance to levels ranging 

from 92 – 99%. These have ranged from minor modifications to the internal 

components of a given unit, to enhance gas-liquid contact, to conversion of some 

units from one FGD technology to another coupled with the addition or 

modification of various balance-of-plant equipment or processes.

It is typically much more cost effective to upgrade an existing FGD than to install a completely 

new scrubber.34 These existing scrubbers can be upgraded by applying new scrubbing 

technology35 to improve their removal efficiency, lower operating costs, and improve operations 

and reliability for much less than it would cost to replace them with a new scrubber. 

A scrubber can be upgraded by reusing as many structural components and equipment in the 

existing unit as possible, such as existing structural steel and absorber shells, ducts, pumps, and 

compressors. Scrubber upgrades have been completed on about 50 units in the last 15 years to 

enhance performance or lower overall operating costs.

As Staudt notes:36

There have been numerous examples of FGD upgrades over the last several years 

that have improved SO2 removal efficiencies. For example, the Fayette Station 

Unit 3, a 470 MW tangentially-fired coal unit in Texas, completed an upgrade to 

its 1988-vintage scrubber in 2010. The plant’s control efficiency was increased 

from about 84 percent to 99 percent, higher than the guaranteed SO2 removal 

efficiency of 95.5 percent. In Kentucky, E.On’s Trimble County Generating 

Station Unit 1, a 550 MW tangentially-fired coal boiler, completed a scrubber 

upgrade in 2006. Its scrubber, installed in the 1980s, was originally designed for 

90 percent removal efficiency. The scrubber system is now able to achieve over 

99 percent SO2 removal efficiency. In Indiana, NiSource upgraded the scrubbers 

at Schahfer Units 17 and 18 in 2009. The scrubber upgrades increased SO2

removal efficiency from 91 percent to 97 percent.

Other successful scrubber upgrades include the AEP/SWEPCO Pirkey Unit 1 in Texas,

37 the San 

Miguel Electric Cooperative Unit 1 in Texas,38 the Tuscon Electric Power Springerville Units 1 

 

34 Maller et al, p. 5.

35 See, e.g., Wolfgang Schuettenhelm and others, FGD Technology Developments in Europe and North America, 

Mega Symposium, 2001, http://www.babcockpower.com/pdf/rst-171.pdf.

36

 Staudt, James E., Control Technologies to Reduce Conventional and Hazardous Air Pollutants from Coal-Fired 

Power Plants Prepared For: Northeast States for Coordinated Air Use Management 89 South Street, Suite 602, 

Boston, MA 02111, March 31, 2011, p. 13.

37

 https://www.aeptexas.com/info/news/viewRelease.aspx?releaseID=146: “H. W. Pirkey Plant was equipped with 

an FGD system when it went into service in 1985. That system consistently removes nearly 80 percent of SO2. This 

original equipment will be upgraded to bring its removal rate into the 90-percent range;” Tax Relief For Pollution 

Control Property Applications Filed for Harrison County 11/1994 & 10/2003. Available at: 

http://www.tceq.state.tx.us/assets/public/assistance/graphics/Prop2/harrison.pdf

38

 San Miguel Electric Cooperative FGD Upgrade Program Update, URS Corporation, June 30, 2014. 
28

and 2 in Arizona;39 the Gibbons Creek facility in Texas, the San Juan Generating Station in New 

Mexico;

40 the Culley Generating Station Units 2 and 3 in Indiana;41 and the Trimble County 

Generating Station Unit 1 in Kentucky.42 These upgrades have increased SO2 removal to 92% to 

99%.

43

As we discussed in Section 5 in our wet scrubber retrofit cost calculations, a typical retrofitted

scrubber is capable of 98% removal, down to an effective lower limit of 0.04 lbs/MMBtu. 

However, we recognize that scrubber upgrades are highly individualistic, depending on the 

particular equipment in use at the facility. Furthermore, we recognize that a number of the 

facilities we analyze for scrubber upgrades burn either PRB coals or blends of coals containing a 

large percentage of PRB coals. Consequently, in our analyses, we assign a presumptive scrubber 

upgrade target of 95% SO2 removal, with the understanding that the ultimate individual 

efficiency will vary depending these factors.

6.1 Calculation of Existing Scrubber Efficiencies

In a typical situation in which we would propose that a pollution control device such as an SO2

scrubber be installed, we would have historical emissions data to use as a baseline. In such an 

instance, we would apply the control efficiency of the scrubber to the uncontrolled historical SO2

emissions, and be able to easily propose a controlled SO2 emission rate that would be appropriate 

following the installation of the scrubber. However, we face a more difficult task in analyzing 

the efficiency of existing SO2 scrubbers. 

As we discussed above, we are confident that any of these existing scrubbers can be upgraded to 

perform similarly to newly retrofitted scrubbers. If we are to approach the task of calculating the 

cost of upgrading these scrubbers in a way similar to that of proposing a new scrubber, we must 

first be able to specify an SO2 emission rate that would be appropriate following the installation 

of these scrubber upgrades. Because to our knowledge, none of these units monitors (via CEMS) 

their emissions before the exhaust gas traverses their existing scrubbers, we do not have CEMS 

 

39

 Farber, et al, Results of FGD Upgrade Projects On Low-Rank Coals, Presented at Electric Power 2007 

Conference and Exhibition EP-07 Session 12E2007. Covers upgrades to Pirkey Unit 1, San Miguel, and 

Springerville Units 1 and 2.

40

 Taylor, H., Nischt, W., San Juan Generating Station FGD Retrofit Project Update, Presented to: BR-1667 PowerGen International ’98, December 9-11, 1998, Orlando, Florida.

41

 Quitadamo, M., et al, SO2 Removal Enhancement to the Vectren Culley Generating Station Units 2&3 Wet Flue 

Gas Desulfurization System, Babcock Power Technical Publication, Presented at the ICAC Forum 05’, March 7-10, 

2005, Baltimore, Maryland.

42

 Erickson, Clayton, et al, Wet Flue Gas Desulfurization (WFGD) Upgrade at the Trimble County Generating 

Station Unit 1, Presented at MEGA Symposium, August 28-31, 2006, Baltimore, Maryland.

43 URS, 4/5/11, pp. A-5 to A-7; Babcock Power Environmental, Wet Flue Gas Desulfurization Scrubber Upgrades, 

2009; Erickson, C., et al, Wet Flue Gas Desulfurization (WFGD) Upgrade at the Trimble County Generating Station 

Unit 1, Mega Sumposium 2006; Quitadamo, M. et al, SO2 Removal Enhancement to the Vectren Culley Generating 

Station Units 2 & 3 Wet Flue Gas Desulfurization System, ICAC Forum 2005; Silva A., and Williams, P., WFGD 

Case Study – Maximizing SO2 Removal by Retrofit with Dual Tray Technology, Mega Symposium, 2006; Henry S. 

Taylor and Walter Nischt, San Juan Generating Station FGD Retrofit Project Update, PowerGen; Maller G., et al, 

Improving the Performance of Older FGD Systems; B&W, Wet Flue Gas Desulfurization (FGD) Systems Advanced 

Technology for Maximum SO2 Removal, 2007 (8,000 MW of non-B&W wet FGD system upgrades by replacing 

the original absorber internals with tray technology and forced-oxidation conversions).
29

baseline SO2 emissions. However, we do have coal quality data, which can be used to establish 

uncontrolled SO2 emissions.

We calculated the scrubber removal efficiency by utilizing the reported sulfur content and 

tonnages of the fuels burned and reported to EIA,

44 and the monitored SO2 scrubber outlet 

emissions reported to us.

45

 We did this by constructing a spreadsheet46, which among other 

things, divides the annual SO2 emissions by the theoretical uncontrolled SO2 emissions based on 

coal sulfur content to estimate the percentage of SO2 in the coal that is emitted by each of the 

scrubbed facilities in Table 1. We calculated the theoretical uncontrolled SO2 emissions from 

EIA reported coal sulfur data. This calculation is summarized below for a typical unit that burns 

both lignite and subbituminous coals:

(1) {

(

% S Lignite

100 X tons lignite X

2000lbs

ton )+(

% SUB

100 X tons SUB X

2000lbs

ton )

(

MMBtu

ton lignite X tons lignite+

MMBtu

ton SUB

X tons SUB)

} X (

2 lbs SO2

1 lb S

)

=

theoretical uncontrolled lbs SO2

MMBtu

or, alternatively expressed in tons:

(2) theoretical uncontrolled lbs SO2

MMBtu

X (

MMBtu

ton lignite

X tons lignite +

MMBtu

ton SUB

X tons SUB)

= theoretical uncontrolled tons SO2

and the scrubber efficiency is then:

(3) Scrubber efficiency = 1 − (

annual monitored tons SO2

theoretical uncontrolled tons SO2

)

In equations (1) and (2), the percentage and tonnage values are those reported by the facility to 

the EIA for each fuel type. In equation (3), the annual EPA reported tons of SO2 are those 

reported to us.

47

In the following table, we summarize our calculation of the SO2 removal efficiency for the 

existing scrubber systems:

 

44

 EIA Form 923. Available at http://www.eia.gov/electricity/data/eia923/

45

 EPA Air Markets and Programs Data. Available at http://ampd.epa.gov/ampd/

46

 See “Coal vs CEM data 2009-2013.xlsx,” tab “charts,” cell H12.

47

 EPA Air Markets and Programs Data. Available at http://ampd.epa.gov/ampd/
30

Table 14. Efficiency of Units with existing SO2 scrubbers

Facility Unit Scrubbed? Bypass?

2009-2013

Average SO2

Removal 

Efficiency (%)

Sandow 4 1 Y Y 75.7

Monticello 3 Y Y 60.0

Martin Lake 1 Y Y 69.2

Martin Lake 2 Y Y 71.9

Martin Lake 3 Y Y 69.8

Limestone 1 Y Y 78.1

Limestone 2 Y Y 77.0

San Miguel 1 Y N 94.0

W. A. Parish 8 Y Y 84.0

We were interested in gauging the accuracy and precision of our calculations of the theoretical 

uncontrolled SO2 emissions, so we compared it to the EPA reported SO2 emissions for units that 

do not have scrubbers. The following table presents that information:

Table 15. Comparison of theoretical to monitored SO2 emissions for unscrubbed units

Unit

2009-2013

average 

monitored 

SO2

emissions 

(tons)

2009-2013

average 

theoretical 

SO2

emissions 

(tons)

Percentage 

theoretical to 

monitored 

SO2 emissions 

(%)

Big Brown Unit 1 30,606.1 32,489.3 6.2

Big Brown Unit 2 30,638.8 32,048.5 4.6

Coleto Creek 16,665.1 18,771.5 12.6

Monticello Unit 1 16,434.9 18,288.8 11.3

Monticello Unit 2 15,458.0 17,805.3 15.2

Tolk Unit 171B 10,223.9 11,582.1 13.3

Tolk Unit 172B 10,889.4 11,395.4 4.6

W. A. Parish Unit 5 14,295.6 17,480.7 22.3

W. A. Parish Unit 6 15,376.5 17,404.9 13.2

W. A. Parish Unit 7 12,119.3 14,604.6 20.5

Welsh Unit 1 7,956.4 9,618.3 20.9

Welsh Unit 2 8,075.8 9,483.2 17.4

Welsh Unit 3 8,490.6 9,794.1 15.4

Average 13.6
31

This table shows that the actual SO2 emissions as measured by CEMS are about 13.6% lower 

than the SO2 estimated from coal quality data. The difference between these two numbers could 

be due to a number of factors, generally acknowledged in the literature, which include:

 Inadequate coal sampling including factors such as sample size, frequency, location (at 

the mine, train manifest, pile, blending hopper, silos, conveyor belts);

 Errors in reporting of the coal sulfur data, the heating value of the coals, and the amount 

of coal burned. We expect these errors to be compounded for units that blend coals.

 Our assumption that all coal sulfur will be oxidized to SO2 in equation (1) at the 

theoretical rate of 2 pounds SO2 for every pound of S. Some of the sulfur is in fact 

converted to other sulfur compounds such as SO3 that are not measured by the SO2

CEMS.48

 Potential effects of NOx and PM pollution control devices. SCRs, which are operating at 

the Parish units, convert a small amount of SO2 to SO3 as a consequence of the catalysts. 

Low SO3 conversion SCR catalysts are available, but we do not know if the Parish units 

employ them. ESPs and baghouses reduce sulfur by removing particulate matter with 

absorbed SO3. Further, the filter cake in a baghouse absorbs SO3.

49

 Losses of sulfur, such as pyrite, when the coal is pulverized or in bottom ash.

 Sulfur reported on an as-received basis rather than dry basis; the as-received sample 

includes moisture, which would dilute (or lower) the sulfur content.

Therefore, we acknowledge that both our calculations of current SO2 scrubber efficiency, and 

our calculations of tons of SO2 removed once a scrubber upgrade is performed (and hence our 

cost effectiveness calculations) will have some error. We discuss how we propose to treat this in 

our Federal Register Notice for our proposed action.

6.2 Historical Scrubber Designs and Upgrades

The scrubber systems we are evaluating were all installed in the late 1970s to mid-1980s as part 

of the initial design of the facilities. All employ wet limestone, and with one exception – San 

Miguel – have scrubber bypasses. Scrubbers of this vintage were typically designed to meet the 

1971 New Source Performance Standards (NSPS) for EGUs, which required new coal-fired 

boiler to meet a SO2 limit of 1.2lb/MMBtu; or the 1979 NSPS, which additionally required 70% 

control, not to exceed 0.6 lbs/MMBtu unless 90% control was achieved. 50 Compliance usually 

involved using multiple absorbers with spares.51

 

48

 Estimating Total Sulfuric Acid Emissions from Stationary Power Plants, Technical Update, EPRI, March 2012.

49

 R. Hardman, et al, Estimating Sulfuric Acid Aerosol Emissions from Coal-Fired Power Plants, U. S. Department 

of Energy-FETC Conference on Formation, Distribution, Impact, and Fate of Sulfur Trioxide in Utility Flue Gas 

Streams, March 1998; R. K., Srivastava, et al, Emission of Sulfur Trioxide from Coal-Fired Power Plants, J. Air 

Waste Manag Assoc. 2004 Jun;54(6):750-62.

50

 Flue Gas Desulfurization Inspection and Performance Evaluation Manual, EPA/625/ 1-85/019, October 1985, 

Sections 2.1.1.1 and 2.1.1; Farber, et al, p. 18. 

51

 Spare scrubber modules allow FGD systems to maintain full or partial operating capability when a primary 

module fails or is down for service. Early scrubber design commonly included spares due to poor operating 

experience and the NSPS “emergency condition” provision. See, e.g., William DePriest and Rajendra P. Gaikwad, 

Economics of Lime and Limestone for Control of Sulfur Dioxide, 2003. 
32

As Weilert notes,

52 “This is likely due to the requirement of the EPA’s new source performance 

standard (NSPS) for continuous compliance with a 30-day rolling average SO2 removal, and the 

provision that stipulates a spare absorber module as a prerequisite to operation during emergency 

conditions with a malfunctioning FGD system.” However, industry gradually recognized that 

module spares were not required due to advances in scrubber technology, and the proven 

reliability of single-module FGD systems.

53

 Thus, utilization of an existing spare FGD module 

at one of the facilities we are analyzing (Limestone) potentially represents a cost effective

opportunity to increase scrubbing capacity. The following tables summarize the FGD 

information we have available as a result of mandatory reporting to the EIA via Forms 860 and 

923, and from Weilert:

54

 

52

 Carl Weilert, FGD Systems Utilizing Single Absorber Modules: The Wave of the Future for New Utility Boilers, 

Burns & McDonnell Technical Paper.

53

 Bailly Generating Station Advanced Flue Gas Desulfurization System, Final Environmental Information Volume, 

April 1989; Carl Weilert, Ibid., p. 12: “The available data indicates that single-module FGD systems can be 

extremely reliable.”; Frazer, C., et al, Fayette Power Project Unit 3 FGD Upgrade: Design and Performance for 

More Cost-Effective SO2 Reduction, Babcox and Wilcox Technical Paper presented at the EPRI Mega Symposium 

2010, p. 3: “Ultimately, the options selected, and discussed above, offer the station the flexibility to permanently 

remove one of the absorbers from regular service.” Taylor et al, Control of SO2 emissions from power plants: A 

case of induced technological innovation in the U. S., Technological Forecasting & Social Change 72 (2005) 697 

718. ....” Page 715: “ ... according to a study of 111 FGD installations in 1986-1988 that declared that reliability 

was no longer an issue with FGD. With increased reliability, costly design options such as spare absorber modules 

were dropped in the 1990s.”; Schuettenhelm, W et al, FGD Technology Developments In Europe And North 

America, Babcock Technical Paper, Presented at the EPA-DOE-EPRI Mega Symposium Arlington Heights, Illinois, 

August 20-24, 2001, p. 3: “The F. B. Culley FGD (Vectren) system located near Evansville, Indiana ... was 

designed to remove 95% of the SO2 based on a 10 lb/MMBtu fuel. A unique feature of the project is that it uses one 

absorber to serve two generating units with no bypasses.”

54

 Weilert, C., and Meyer, E., Utility Design Trends, Power Engineering, 8-1-2010; personal communication.
33

Table 16. Summary of FGD information55

Facility Units

2011 EIA 860 2012 EIA 923

In-service

year

Sorbent 

Type 1

Sorbent 

Type 2 Bypass?

FGD 

Trains

FGD Trains 

at 100% 

Load

Design 

Removal 

Efficiency

(%)

Flue Gas 

Entering 

FGD (%)

Efficiency 

at Annual 

Operating 

Factor

Tested 

Efficiency 

at 100% 

Load

Date Latest 

Efficiency 

Test

Sandow 4 1 1981 LS DB Y 3 3 92 83 74.4 74.4 01/1984

Monticello 3 1978 LS DB Y 3 3 95 75 55 55 01/2007

Martin Lake 1 1977 LS DB Y 4 4 95 95 64.7 64.7 02/1991

Martin Lake 2 1978 LS DB Y 4 4 95 95 64.9 64.9 02/1991

Martin Lake 3 1979 LS DB Y 4 4 95 95 67.8 67.8 02/1991

Limestone 1 1985 LS DB Y 5 4 90 100 77.1 91.5 12/2011

Limestone 2 1986 LS DB Y 5 4 90 100 75.8 91.5 12/2011

San Miguel 1 1982 LS N 4 4 94.2 100 94.1 94.3 05/2010

W. A. Parish 8 1982 LS Y 3 3 85 82 81.9 73 01/1985

 

55

 We question the accuracy of some of this information reported to EIA. For instance, the Limestone facility reports that it has a bypass for its scrubbers, yet it reports 

that 100% of the flue gas enters the scrubber. Also, the Martin Lake facility reports that for Unit 1, 95% of its flue gas enters its FGD and that of that gas, the removal 

efficiency is 95%. This would result in an overall SO2 removal efficiency of 90.3% (0.95 X 0.95). However, our own calculations indicate an average removal 

efficiency of much less. We suspect the EIA scrubber efficiencies are a mixture of supplier guarantees (not counting bypassed flue gas) and actual estimates.
34

Table 17. Selected information from Weilert and Meyer

Facility 

Namea

FGD 

IDb Process Typea

Absorber 

Type Ib

Sorbent 

Typeb

Provision 

for Bypassb

Incorporation 

of Spare 

Moduleb Manufacturerb

Material of 

Construction

Oxidation 

Mode

Limestone 1 Wet Limestone SP LS Y Y AL NIe Forcede

Limestone 2 Wet Limestone SP LS Y Y AL NIe Forcede

Martin Lake 1 Wet Limestone TRm LS Y N HRC FRCSf NR

Martin Lake 2 Wet Limestone TRm LS Y N HRC FRCSf NR

Martin Lake 3 Wet Limestone TRm LS Y N HRC FRCSf NR

Monticello 3 Wet Limestone SP LS Y N MX FRCSf NR

San Miguel 1 Wet Limestone TRm LS N N BW SSm Inhibitede

Sandow 4 Wet Limestone SP LS Y N AL SSe NR

W A Parish 8 Wet Limestonef SP LS N56 N MX FRCSf NR

Notation from Weilert and Meyer

a This column is from the 2010 “Emissions” section of EPA’s Clean Air Markets Division “Data and Maps” website 

b This column is from 2008 EIA-860 data Schedules 6-G & 6-H

c This column is from 2008 EIA-860 data "Annual Electric Generator Report" Generator (Existing) File

d 2009 “Emissions” section of EPA’s Clean Air Markets Division “Data and Maps” website 

e Information is from respective vendor either from direct correspondence or from their website/publications

f DOE "Utility FGD Survey January - December 1989" Publication Number ORNL/M-2347

g 2008 “Emissions” section of EPA’s Clean Air Markets Division “Data and Maps” website 

h 2007 “Emissions” section of EPA’s Clean Air Markets Division “Data and Maps” website 

I 2008 EIA 860 data “Annual Electric Generator Report” Generator (Proposed) File

j Material information from Stebbins Manufacturing Installation List

k Upgrade by BPE according to BPE

l 2005 EIA 767 data Schedule 8 A & 8 B

 

56

 We note that the Weilert and Meyer data reports that the W A Parish facility does not have a scrubber bypass, yet the EIA data reports that the facility does have a 

bypass. Examination of aerial photos of Unit 8 seem to confirm the presence of ducting that would serve a bypass.
35

m Authors' correction based on personal knowledge

n Facility's Utility's website

o EPA's Steam Electric Power Generating Point Source Category: 2007/2008 Detailed Study Report (Online)

p Multiple FGD units are associated with one generator. The value reported is the nameplate capacity for the generator.

General Absorber Type Sorbent Type Material of Construction Unit Manufacturers

NA Not Applicable BR Jet Bubbling Reactor AF Alkaline fly ash CO Combination AD Allied 

NR Not Reported CD Circulating Dry Scrubber LA Lime and alkaline fly ash CS Carbon Steel AL Alstom 

DCFS Double Contact Flow 

Scrubber 

LF Limestone and alkaline fly 

ash 

FRCS Flakeglass Reinforced Resin AM American Air Filter 

DSI Dry Sorbent Injection LI Lime Lined Carbon Steel AP Airpol 

PA Packed LS Limestone FRP Fiberglass Reinforced Plastic AV Advatech 

SD Spray Dryer MO Magnesium oxide NI Nickel Alloy BPE Babcock Power 

Environmental 

SP Spray SA Soda ash RLCS Rubber Lined Carbon Steel BW Babcock and Wilcox 

TR Tray SC Sodium carbonate SS Stainless Steel CH Chiyoda 

VE Venturi SL Soda liquid TL Tile Lined FMC FMC 

HI Hitachi 

HRC Hamon Research Cottrell 

KE M W Kellogg 

MHI Mitsubishi Heavy 

Industries 

MX Marsulex 

SHU Saarberg Holter 

SI Siemens 

OT Other

The Instructions for EIA Form 860 indicate the following regarding the fields of interest to us:

Can flue gas bypass the flue gas desulfurization unit? Indicate whether the flue gas can bypass the FGD unit.

What is the total number of flue gas desulfurization unit scrubber trains or modules? Enter the total number of flue gas desulfurization unit 

scrubber trains or modules operated.

How many flue gas desulfurization unit scrubber trains or modules are operated at 100 percent load? Enter how many flue gas 

desulfurization unit scrubber trains or modules are operated at 100 percent load.
36

What is this unit’s design removal efficiency for sulfur dioxide when operating at 100 percent load? Report the design removal efficiency to 

nearest 0.1 percent by weight of gases removed from the flue gas when operating at 100 percent generator load.

The instructions for EIA Form 923 indicate the following regarding the fields of interest to us:

FGD or FGP Efficiency Rate at Annual Operation Factor (H, K): Enter removal efficiency, based on the annual operating 

factor. Annual operating factor, as given by the formula below, is defined as the product of design firing rate and hours of 

operation per year, divided by annual total fuel consumption, expressed as a percentage. If actual data are unavailable, 

provide estimates, based on equipment design performance specifications. 

Annual Operating Factor (AOF) = 

100 * Design Firing Rate (MMBtu/hr) * Hours of Operation (hr) / Total Fuel Consumption (MMBtu) 

Removal Efficiency at Annual Operating Factor = FGP Removal Efficiency * Average AOF

FGD or FGP Tested Efficiency Rate (at 100% Load) (I, L): Enter the tested efficiency of the FGD and/or FGP unit for each 

controlled pollutant. If not tested at 100% load, provide the load at which the test was conducted in a comment on Schedule 

9. If an efficiency test has not been conducted, leave field blank and provide a comment.

Test Date (J, M): Enter the date of the latest efficiency test for the FGD and/or FGP unit for each controlled pollutant. If no 

test was conducted, leave the test date blank.
37

These first generation FGD units were typified by multiple absorber modules, SO2 removal 

efficiencies between 75% and 90%, and the use of either natural or inhibited oxidation.57

However, as Staudt notes,58 “... limestone-forced oxidation (LSFO) wet scrubber technology is 

[now] the most widely used form of wet FGD and is more widely used on coal-fired power 

plants than every other form of FGD combined. State-of-the-art LSFO systems are capable of 

providing very high levels of SO2 removal – on the order of 98 percent or more.” These early 

units were often designed to operate with a dry stack, which was most often accomplished by 

bypassing a portion of the flue gas around the scrubber to maintain gas temperatures high enough 

to prevent condensation and the formation of H2SO4 which would erode an unprotected chimney. 

These older scrubbers represent a significant investment that can be optimized, improved, and/or 

upgraded to minimize the cost of reducing SO2 emissions. 

These early scrubbers typically employed two scrubbing zones, a venturi section with spray 

nozzles to enhance gas-liquid mixing and a second spray zone. The second zone sometimes 

included a tray or packing to enhance gas-liquid contact.59 They had many operational problems 

including poor reagent utilization, tray scale, ducting problems, and plugging of nozzles and 

demisters.60 Solids deposited on these devices, plugging them, reducing flow and increasing 

differential pressure, requiring weekly cleanings and driving up O&M costs. The resulting high

O&M costs led to replacement of packings and redesign.61

We know from our review of the facility’s responses to our information collection requests, 

described in Section 7.1, that many, if not all of these original scrubbers have been modified 

since their original installations to cure these and other problems. However, there is very little 

publicly available documentation. A number of key factors have pushed owners to upgrade their 

scrubbers, often absent any regulatory drivers including: 62

 Reduction in operating costs

 Reduction in maintenance costs

 Flexibility to burn higher sulfur coals

 Sale of byproduct (upgrade to forced oxidation allowing the sale of gypsum)

 Opportunity to generate excess emissions credits for sale,

 An increase in the SO2 emission credits price 20

 Reduction in auxiliary power consumption

 

57

 Farber, et al.

58

 Staudt, James E., Control Technologies to Reduce Conventional and Hazardous Air Pollutants from Coal-Fired 

Power Plants Prepared For: Northeast States for Coordinated Air Use Management 89 South Street, Suite 602, 

Boston, MA 02111, March 31, 2011. p. 10.

59

 Buecker, B., Important Concepts of Wet-Limestone Flue Gas Desulfurization Energy-Tech Magazine, October 

2008, http://www.energy-tech.com/article.cfm?id=21789; PEl Associates, 1985.

60

 See, e.g., NERC, Impact of FGD Systems. Availability Losses Experienced by Flue Gas Desulfurization, July 

1991, pp. 10, 27; Farber, et al, Ibid.

61

 Buecher, Brad. Ibid.

62

 Klingspor, J., Brown, G., Techniques for Improving FGD System Performance to Achieve Ultra-High SO2

Removal Efficiencies, URS Technical Paper; Frazer, C., et al, Ibid., p. 8: “The unit also has the option to burn 

lower-cost, high-sulfur coal, while still maintaining emissions limits;” NERC, Impact of FGD Systems. Availability 

Losses Experienced by Flue Gas Desulfurization, July 1991; Maller, G., et al; Taylor, H., Nischt, W., p. 5: “This 

conversion project was justified on the basis of O&M and power/fuel savings.”
38

 Solving process problems that cause high maintenance, reagent, and disposal costs

 Improving reliability (reducing scrubber-related outages)

 Ability to treat a higher volume of flue gas to improve scrubbing efficiency

Analyses of these upgrades reveals that they typically have performed better than guaranteed. 

Our examination of the facility’s responses to our information collection requests, lead us to 

conclude that some of these existing scrubbers are able to operate at higher removal efficiencies 

than they currently achieve due to changes in the factors that led to their upgrades. For example, 

our regulations have been delayed through litigation, SO2 allowance markets have not 

materialized or allowance costs have not risen as expected, changes in natural gas pricing, etc. 

Consequently, we suspect that absent a specific permit limit, other enforceable requirement, or 

market driver to operate at these higher scrubber efficiencies, some of these facilities may simply 

choose not to do so for economic reasons. For example, it has been suggested that some 

facilities owners turn off their scrubbers at peak demand to maximize profits.63

6.3 Options for Upgrading SO2 Scrubbers

The performance of older FGDs is often limited by poor reliability and poor design, resulting in 

lower SO2 removal efficiencies and higher operating and maintenance costs than newer FGD 

systems. The causes for poor performance include the following:64

 Bypassing a portion of the flow around the scrubbers

 Unbalanced flow between absorbers

 Poor gas distribution within the absorber

 Poor spray coverage within the absorber

 No droplet-to-droplet interaction within the absorber

 Sneakage along the sides of the absorber

 Poorly designed mist eliminator wash systems

 Inadequate scrubber chemistry

Existing FGD systems can be upgraded by applying new scrubbing technology65 and improved 

upon in many instances so that they can operate at performance and reliability levels similar to 

new systems for much less than it would cost to replace them with a new scrubber.

66

 As noted in 

the BART Rule, "upgrading an existing scrubber system is typically considered more cost 

 

63

 Wynne, H., et al, U.S. Utilities: Can Texas Comply with the Cross-State Air Pollution Rule? Yes, If Existing 

Scrubbers Are Turned On, Bernstein Research, July 20, 2011, p. 5: “This pattern suggests that generators have 

sought to avoid the reduction in net generation that results from operating the scrubbers (reflecting the parasitic load 

of the emissions control equipment) during hours when power prices are highest. Conversations with the investor 

relations departments of Energy Future Holdings and NRG Energy confirmed that, as long as continuous operation 

of SO2 scrubbers is not required to comply with currently prevailing SO2 emissions limits, generators will avoid 

operating the scrubbers so as to maximize net power output and revenues, and minimize variable operation and 

maintenance expense, including the cost of sorbents and water required for the operation of the SO2 scrubbers.”

64 Klingspor, J., Experience from 52,280 MWs of Wet Flue Gas Desulphurisation System Upgrades, VGD 

PowerTech, December 2012.

65

 Schuettenhelm, W et al; Maller, G., et al; Klingspor, J.,et al; Farber, P., et al; Klingspor, J., et al.

66

 Maller, G., et al, p. 13.
39

effective than constructing a new scrubber system."67 Dr. Jonas Klingspor, Vice President at 

URS, a firm that has conducted more than 52,000 MWs of scrubber upgrades, stated that, “a 

scrubber upgrade is typically about one-third or less than the cost of a new scrubber.” This is 

because a scrubber system can be upgraded by reusing many existing structural components and 

existing equipment, such as existing structural steel and absorber shells, ducting, pumps, and 

compressors. Other components can be modified or replaced with new technology. Also 

according to Klingspor:68

Most wet FGD systems, regardless of initial physical design or chemistry, can be 

upgraded to achieve above 99% SO2 removal efficiency and to operate 

uninterruptedly between scheduled outage cycles.

As described repeatedly in the scrubber upgrade references we provide, a scrubber system can be 

upgraded by reusing many existing structural components and existing equipment, such as 

existing structural steel and absorber shells, ducting, pumps, and compressors. There are many 

viable, cost-effective options to improve SO2 removal efficiency. These include: 69

 Removing any existing scrubber bypass;

 Eliminating sneakage of gases down the sides of the absorber bypassing the spray 

headers, by installing wall baffles or rings within the absorber;

 Improving liquid distribution by installing new spray headers, additional spray levels 

and/or more efficient nozzles to improve spray coverage in the absorber;

 Improving gas-liquid contact by adding trays within the absorber;

 Increasing the gas-to-liquid ratio by increasing recycle slurry pump flow by, for 

example, using all available scrubber modules, adding recirculation pump suction line 

screens or changing pump gear reducers to allow higher impeller speeds, thus 

producing greater slurry flow on pumps;

 Improving scrubber chemistry by reducing limestone grind size, eliminating 

limestone blinding, converting to inhibited or forced oxidation, optimizing pH, and 

using performance additives such as dibasic acid (DBA);

 Redesigning mist eliminators and mist eliminator wash system to handle higher 

velocities through the absorber;

 Repairing any damaged or worn parts, such as recycle pump impellors; and

 Removing any capacity constraints, such as in the dewatering system or induced draft 

fan.

 

67

 70 FR 39133.

68

 Klingspor, J., Experience from 52,280 MWs of Wet Flue Gas Desulphurisation System Upgrades, VGD 

PowerTech, December 2012.

69

 See for example: Klingspor, J., p. 106; Maller, G., et al; Klingspor, J. and Brown, G; Alstom, Wet Scrubber 

Upgrade Air Quality Control Systems, http://www.alstom.com/Global/Power/Resources/Documents/Brochures/wetscrubber-upgrade-datasheet.pdf;

Moretti, A., State-of-the-Art Upgrades to Existing Wet FGD Systems to Improve SO2 Removal, Reduce Operating 

Costs and Improve Reliability, Power-Gen Europe, June 3-5, 2014. 
40

We discuss these scrubber upgrade options in the sections that follow. These methods have been 

used on many vintage scrubbers in the last 20 years to enhance performance and/or to lower 

overall operating costs.70 

6.3.1 Elimination of Scrubber Bypass

As we note above, a flue gas bypass is used on all of the scrubber systems we are investigating 

for upgrades, except for the San Miguel unit. A bypass allows the facility to route all or a 

portion of the flue gas around the FGD system for flue gas reheat and/or to improve operating 

flexibility. Some utilities originally designed the FGD system to scrub only a percentage of the 

flue gas while others installed bypass capability as a means of providing continuous operating 

capability, using alternate method for flue gas reheat. Because a bypass can route a large volume 

of flue gas around the scrubber system, it can have a significant impact on the overall SO2

removal efficiency of the unit. Below is an example of this:

Figure 2. Effect of Bypass and Absorber Efficiency on SO2 Emitted

 

70

 
41

In the above example for a coal fired power plant that would emit 20,000 tons per year (tpy) if 

uncontrolled, the difference between no bypass and 20% bypass is significant. For example, if 

the absorbers are 96% efficient, a 20% bypass would mean that 3,840 tpy more is emitted over 

no bypass.

A wet FGD sprays a limestone-based slurry into the gas stream to remove SO2. This produces a 

gas stream that is saturated with water vapor at a temperature of 136-145 F for lignite and subbituminous coal. A wet scrubber cools the stack gas and adds moisture to it. The gases are

saturated and contain water droplets containing corrosive compounds such as sulfuric acid. If 

the temperature of the flue gas is blow the dew point, the moisture condenses in the exit ducts, 

stack walls, etc., corroding downstream equipment. Gasses emitted to the atmosphere can result 

in liquid fallout, visible steam plumes and plume touchdown, causing high ground-level SO2

concentrations.71 Thus, unless corrosive resistant materials are utilized, the temperature of the 

flue gases exiting the FGD system must be above the dew point to avoid condensation of flue gas 

and to maintain flue gas velocities in the exit ducts and stack.

At the time the subject scrubbers were installed, this was accomplished by heating the flue gas

exiting the FGD system by about 25 to 50°F72, so it was slightly above the saturation point. This 

increased the buoyancy of the plume, which reduced ground-level pollutant concentrations; 

reduced plume visibility by eliminating entrained moisture; and evaporated entrained water 

droplets, decreasing the potential for corrosion. Four methods were historically used to address 

this problem:73

 In-line reheat, in which the gas is passed through a heat exchanger located in the duct 

work (20%)

 Indirect hot air injection reheat (15%), in which air is heated in an external heat 

exchanger and then mixed with the exit flue gas

 Direct combustion reheat (14%), in which hot combustion gases are generated using fuel 

oil or natural gas and then mixed with the exit flue gas

 Bypassing a portion of the untreated flue gas around the scrubber and then mixing that 

hotter gas with the scrubbed flue gas (25%)

Bypassing flue gas was the lowest cost approach, followed by in-line reheat system.74 This is the 

option used by all of the scrubber systems we are analyzing, with the exception of San Miguel, 

which does not employ a bypass. This was most commonly accomplished by routing 5%-20% of 

the flue gas around the scrubbers.75 A bypass allows the facility to route all or a portion of the 

flue gas around the FGD system for flue gas reheat and/or to improve operating flexibility. 

Some utilities originally designed the FGD system to scrub only a percentage of the flue gas 

 

71

 Henzel, D., et al, Limestone FGD Scrubbers: Users Handbook, EPA-600/8-81-017, August 1981, p. 2-27.

72

 Froelich, D., Graves, G., Eliminating Reheat from Existing FGD Systems, A Design and Economic Evaluation, 

Journal of the Air Pollution Control Association, v. 3 7, no. 3, March 1987, pp. 314 - 321, p. 314

73

 Froelich, D., Graves, G, p. 315. Note percentages refer to FGD systems that used any type of stack gas reheat. 

Some FGD systems did not employ any stack gas reheat.

74

 Henzel, D., et al, p. 2-28.

75

 Klingspor, J., Brown, G., p. 8; Maller, G, p. 4.
42

while others installed bypass capability as a means of providing continuous operating capability, 

using alternate methods for flue gas reheat.

Many of these early scrubber systems had/have variable bypass capability, including Monticello 

Unit 3; Martin Lakes 1, 2, and 3; and Sandow 4.76 Variable bypass is used to adjust for different 

operating conditions, such as to maintain minimum stack temperature, adjust for variations in 

coal sulfur levels, and/or to maintain compliance with permits. Variable bypass was 

accomplished by adjusting the position of louver-type dampers on each scrubber tower, based on 

measurements of stack temperature, bypass fan parameters, and bypass damper position 

indicators. 

Partially bypassing the scrubber reduces the overall scrubbing efficiency, as not all of the flue 

gases are treated. Consequently, one way to improve SO2 removal efficiency is to eliminate the 

bypass and route 100% of the gases through the scrubber. When the bypass/reheat is eliminated, 

the amount of gas to be treated increases, the gas velocity decreases, and the gas density 

increases, resulting in system pressure losses of 5% to 10%, compared to dry operation.77

This requires that two technical issues be addressed.78 

First, the scrubber must have adequate capacity to handle the increased gas volume and be able 

to operate at higher flue gas velocities, which can cause problems with existing equipment such 

as the mist eliminators and stack. Scrubber capacity is generally not an issue if a scrubber 

system was designed with a spare absorber or spray level, which was common with many early 

scrubbers due to uncertainty about performance. This is probably not an issue for one of the 

subject Texas facilities (Limestone) as it was designed with multiple units plus a spare, which 

likely provides adequate capacity to handle bypassed gases. Absent a suitable spare, the existing 

scrubber may have to be modified to accommodate the higher flow, including replacement of the 

mist eliminators. 

Second, existing stacks on currently scrubbed units are designed for hot dry flue gases with a 

higher gas velocity (~100 ft/sec) in the liner than new wet stacks. The stack downstream of a 

wet scrubber without bypass or reheat is a “wet stack”, which exhausts saturated, scrubbed flue 

gas that contains droplets from mist-eliminator carryover. Thus, a new or modified mist 

eliminator and stack are usually required to accommodate the highly corrosive, saturated flue 

gas. The wet stacks must be designed using corrosion-resistant material and a gas velocity of 55 

to 75 ft/sec to prevent condensed moisture from being carried out the top of the stack.79 As 

mentioned above, when the bypass is eliminated, corrosive moisture condenses on downstream 

equipment that was not originally designed for these conditions, including scrubber outlet, ducts, 

bypass dampers, expansion joints, and the stack.

 

76

 Supplied June 17, 2014 by Luminant, in response to request for information under Section 114(a) of the CAA, 

dated May 20, 2014.6/17/14.

77 Revised Wet Stack Design Guide, Electric Power Research Institute (EPRI), 2012 Technical Report, Final Report, 

December 2012, p. 3-2.

78

 Maller, G., et al, p. 4.

79

 DePriest, W., Gaikwad, R., Economics of Lime and Limestone for Control of Sulfur Dioxide, p. 9; 

Wet Flue Gas Desulfurization Technology Evaluation, Project Number 11311-000, Prepared For National Lime 

Association, January 2003, Prepared by Sargent and Lundy, p. 25; EPRI 2012, Table 2-1.

Froelich, D., Graves. G., p. 317.
43

The cost of converting from dry to wet stack operation depends upon the existing materials used 

in these components. Moisture condensation within a stack designed for dry use can cause 

severe damage, as these stacks are typically lined with carbon steel or grouted brick. 

Considering the latter, moisture migration through the grout would corrode metal liner bands, 

weakening the stack and eventually resulting in stack failure. An acid-resistant brick liner may 

require no changes at all, while a carbon steel liner would require an alloy lining or other 

protection. Only the stack drainage system would likely have to be improved for acid brick lined 

stacks.80

The conversion of a dry stack to wet operation must address several issues that were not present 

when a bypass or reheat was used. Some of these issues include:81

 Stack liquid discharge;

 Plume downwash and icing;

 Corrosion/chemical attack;

 Stack height;

 Stack-liner geometry and material of construction;

 Liner-breach geometry;

 Stack liner geometry and material of construction;

 Gas velocity in the liner; and

 Liquid-collection devices and drainage.

A critical design consideration in converting a dry stack to wet operation is whether the existing 

liner and ductwork material can withstand the reduced temperatures and wet conditions of wet 

operation and whether the liner-gas velocity will result in droplet re-entrainment from the stack 

wall.82 These issues may be addressed by modifying the existing stack or replacing it with a new 

“wet” stack. Mist eliminators, designed to reduce liquid carryover and slurry to downstream 

ductwork and the stack, must often be modified when the bypass is eliminated to facilitate wet 

stack operation.83 These issues are further discussed in Section 7 concerning the costs of 

scrubber upgrades.

Relining a stack has become a common upgrade to power plants. As a general indicator of the

scale of stack lining projects, Johnson84 reports that 126 stack liner projects using Fiberglass 

Reinforced Plastic (FRP) kicked off in the 2004-2008, inclusive timeframe. This includes a 

number of facilities in Texas: Fayette Units 1 and 2, J.K. Spruce Unit 2, Sandow Unit 5, and Oak 

Grove Units 1 and 2. FRP competes with various steel alloys as a stack lining material and thus 

represents only a portion of the total stack lining projects.

 

80

 Maller, G., p. 4; See for example, http://www.hadek.com/project-reports/san-juan-power-station

81 EPRI, 2012. Ibid., p. 1-2.

82

 EPRI 2012, p.. 1-3.

83

 EPRI, Sec. 2.3.1.

84

 Johnson, T., et al, The Rapid Growth of Fiberglass Reinforced Plastic (FRP) in FGD Systems, 2011, Table 3.
44

As an alternative to relining an existing dry stack for conversion to wet operation, operators can 

choose to build a new stack. However, this the most costly of these options. 

6.3.2 Optimization of Liquid/Gas Ratio

The liquid-to-gas ratio (L/G ratio) is a sizing criterion for absorbers that compares the slurry 

recirculation rate to the flue gas flow rate. It is the ratio of the amount of limestone slurry 

expressed in gallons per minute to the amount of untreated flue gas in thousands (1000s) of 

actual standard cubic feet per minute (gpm/1000 acfm).85 Increasing the L/G increases the 

alkalinity available per pass, which increases the SO2 removal efficiency. The amount of flue 

gas is fixed by the boiler, so the L/G ratio is increased by increasing the amount of limestone 

slurry. This is typically varied by changing the number of operating recycle pumps.

In a conventional scrubber, the amount of slurry is increased by replacing an existing pump with 

a larger model, increasing the number of slurry recycle pumps and spray headers, upgrading the 

motors in existing recycle pumps, installing new gear reducers to allow the pumps to operate at 

higher impeller speed, or reducing the pump head by, for example, replacing high-pressure 

nozzles with low pressure nozzles.86

Sargent & Lundy notes87 in a wet FGD evaluation that included 2.0 and 4.72 lb/MMBtu SO2

coals, that most of the scrubbers installed in Phase 1 of the CAA title IV program (1995) were 

designed for and achieved 95% efficiency with L/Gs of 90-130 and inlet sulfur dioxide up to 8 

lb/MMBtu. Demonstrations and testing by the major FGD process developers, including 

Alstom, Mitsubishi, Babcock & Wilcox, and Wheelabrator, have shown that a 130 L/G is 

adequate to achieve 98% efficiency in a typical open-spray tower design on the 4.72 lb/MMBtu

inlet SO2 basis (high-sulfur coal case) of this work. This is further verified by recent guarantees 

offered by FGD vendors for new unit applications. 

6.3.3 Gas-Liquid Contact Improvements

SO2 removal in a wet scrubber is controlled by the amount of SO2 that can be absorbed per unit 

volume of recirculated slurry. SO2 absorption is limited by the amount of solid and liquid phase 

alkalinity provided in each gallon of slurry. The absorption is also a function of the contact time 

between slurry and SO2 as well as the absorber design, which determines the gas-slurry contact 

area. In a spray tower, the most common type of scrubber, flue gas typically enters horizontally 

and turns 90 degrees into a vertical open cylindrical vessel with multiple levels of spray headers. 

The flue gas is first cooled and saturated with slurry. The saturated flue gas then flows upward 

through the absorber spray zone, where slurry is sprayed countercurrent to the flue gas.

 

85

 Wet Flue Gas Desulfurization Technology Evaluation, Project Number 11311-000, Prepared For National Lime 

Association, January 2003, Prepared by Sargent & Lundy.

86

 Klingspor, J., Brown, G.

87 Wet Flue Gas Desulfurization Technology Evaluation, Project Number 11311-000, Prepared For National Lime 

Association, January 2003, Prepared by Sargent and Lundy, p. 10.
45

The scale models used to design early scrubbers largely ignored the interaction of flue gas and 

slurry. The impact of spray nozzles on flue gas distribution was poorly understood and often 

ignored. Thus, the effect of nozzle spray angle; spray coverage as a function of nozzle size, type, 

density and pressure; and the impact of wall sneakage were typically not modeled.88

Thus, maldistribution of flue gas across the cross section of the absorber is a common cause of 

poor performance in vintage scrubbers. This is caused by high velocity flue gas entering the 

absorber, which causes it to hug the walls of the absorber, bypassing the spray headers. This 

effect is commonly known as "gas sneakage" and can be minimized or eliminated through the 

installation of various mechanical devices.89 Gas sneakage also occurs around nozzles inside the 

absorber.

The skewed flow distribution in the absorber inlet often generates flue gas recirculation zones 

that cause buildup of solids. Similarly, a skewed flue gas distribution at the absorber outlet duct 

often leads to excess mist eliminator carryover, scaling of the absorber outlet duct, and stack rain 

issues.90 These factors place a limitation on the maximum removal efficiency that can be 

achieved for a given absorber. 

Poor recycle spray header design was another common problem in older FGD systems. The 

early designs used narrow-angle nozzles and a low nozzle density.91 This resulted in nonuniform and incomplete spray coverage. Spray towers use several levels of spray nozzles that 

scrub the flue gas as it moves upward through the absorption tray and spray zone. However, 

these spray levels are usually not sufficient by themselves to adequately distribute flue gas at the 

base of the spray zone.92 There are often significant holes in the spray coverage over the crosssectional area of the absorber due to a tendency in early scrubbers to use a small number of 

relatively large spray nozzles. This problem is especially significant along the walls of the 

absorber as gas flows tend to be higher there, or in the vicinity of internal support members. 

This results in poor gas-liquid contact because the gas tends to flow where the spray density and 

gas-side pressure drop are the lowest, contributing to gas sneakage. 

Incomplete spray coverage and gas sneakage can be eliminated by improving gas/liquid contact 

and thus the SO2 removal efficiency with the goal of achieving a uniform distribution of slurry 

and gases across the scrubber diameter. Thus, upgrades typically must address uneven flow 

distribution issues, poor gas-liquid contact, and poor mixing in the reaction tank. This can be 

achieved by improving flow distribution using turning vanes, perforated plates, and wall rings; 

improving gas liquid contact using devices such as sieve trays, improved spray nozzle layout, 

and double hollow cone nozzles; and chemistry modification, including performance additives 

and conversion to forced oxidation. The specific option depends upon a range of factors such as 

 

88 Klingspor, J., p. 101.

89 Klingspor, J., Brown, G.; Maller, G., et al.

90 Klingspor, J., p. 102.

91 Klingspor, J. 2012, p. 102 and Figures 2 and 3.

92

 See, for example, Wet Flue Gas Desulfurization (FGD) Systems Advanced Technology for Maximum SO2

Removal, Babcox and Wilcox, 2007, p. 6.
46

availability of space for a tray or packing and availability of fan power to overcome additional 

pressure drop.93

Wall Baffles

Wall baffles or liquid distribution rings are widely used to prevent gas sneakage down the sides 

of the absorber vessels. They are sloped downwards to re-inject wall slurry into the interior of 

the absorber where there is a greater chance of interaction with recycle spray droplets. They also 

promote more thorough mixing of flue gas, ensuring no areas of high SO2 concentration. These 

baffles are placed between spray levels. Wall baffles have been used in many scrubber upgrades, 

including both round and rectangular absorber towers as well as large and small towers. 94 These 

rings result in improved performance with no increase in power consumption or pressure drop.95

Trays

Perforated trays or counter flow trays can be used to improve the gas-liquid contact and 

distribution of flue gas across the tower. The gases rise through the absorber, contacting a froth 

of slurry on the tray. This provides increased SO2 removal by creating additional surface area 

obtained from liquid holdup on the tray. Trays uniformly distribute gas and create a bubbling 

zone that improves gas-liquid contact, yielding high SO2 removals at a lower overall L/G. 

Adequate space and improved structural support are required to add a tray to an existing open 

spray scrubber or an additional tray to an existing tray scrubber.96 

A tray is a much more efficient contact device than a slurry spray.97 This is because the tray 

creates more surface area between the slurry and the gas. The limestone dissolution on the tray 

can be as much as 50% of the dissolution in the entire absorber. The improvement in SO2

removal by adding a tray is very similar to adding liquid distribution rings or an additional spray 

level. A tray provides about the same removal efficiency as one spray header without requiring 

any of the cost and complexity of a recycle pump and spray header system.98 The benefits of the 

absorber tray compared to an additional spray level include:

 Reduced liquid to gas ratios

 Increased absorption for the same L/G

 More uniform gas distribution due to back-pressure from tray

 Fewer recirculating pumps

 

93 Klingspor, J., 2012; Klingspor, J., Brown, G.; Maller, G., et al; Moretti, A., State-of-the-Art Upgrades to Existing 

Wet FGD Systems to Improve SO2 Removal, Reduce Operating Costs and Improve Reliability, Power-Gen Europe, 

June 3-5, 2014.

94

 Maller, G., et al, Table 1 and pp. 4-5.

95

 Klingspor, J., Brown, G.

96

 Wet Flue Gas Desulfurization (FGD) Systems Advanced Technology for Maximum SO2 Removal, Babcox and 

Wilcox, 2007. 

Silva, A., et al, WFGD Case Study - Maximizing SO2 Removal by Retrofit with Dual Tray Technology, Presented 

to: EPRI-DOE-EPA-AWMA Combined Power Plant Air Pollutant Control Mega Symposium, August 28-31, 2006.

97

 Steam Its Generation and Use, The Babcox & Wilcox Company, Edition 41, 2005, p. 35-6.

98 Klingspor 2012, p. 104.
47

 Fewer spray headers

 Reduced pump maintenance

 Increased particulate removal

 Corrects gas distribution problems in the lower part of the absorber spray zone

 Protects the inlet duct from scaling

 Provides the lowest cost approach to a FGD upgrade

 Provides a maintenance platform that avoids draining the reaction tank to gain 

access to the spray headers and mist eliminators.99

A tray will significantly increase the gas-side pressure drop and thus requires adequate fan 

capacity. The exact amount is a function of design and operating conditions, but is typically on 

the order of 1.5 to 2.5 in-wc.100 However, the additional fan power required from the increased 

gas-side system pressure drop due to the tray is typically offset by a reduction in pumping power 

from the lower L/G (i.e., less slurry recycled) required to achieve a given SO2 removal.101 The 

savings in recycle pump power will offset the penalty of increased absorber pressure drop (i.e., 

pump versus fan power).102 For moderate SO2 removal improvements, a tray can allow the use 

of one less spray level and spray pump per absorber, reducing operating and maintenance 

costs.103

Trays are subject to plugging and scaling if scrubber chemistry is not controlled carefully, and 

trays are less attractive if absorber gas velocity is increased. However, they are desirable if space 

is limited, when efficient spray header designs are not present, and to correct skewed gas 

distribution profiles.104 More than one tray can be employed to optimize the gas-slurry contact. 

Babcock and Wilcox, for example, report that scrubber efficiency can be improved by adding a 

second tray.105 Adding a second tray increases contact time between SO2 and slurry, which 

increases SO2 removal efficiency.106

Spray Headers

The recycle spray header design of many older scrubbers results in incomplete spray coverage, 

especially near the walls where gas flows tend to be higher. These older designs have gaps or 

openings in the spray pattern that allow flue gas to bypass the spray zone without contacting the 

slurry. Many of these gaps are on the outside of the absorber, near the absorber walls and 

provide a direct path for the flue gas to bypass the slurry spray.107 This results in poor gas-liquid 

contact which limits maximum removal efficiency. 

 

99 Klingspor 2012, p. 104.

100 Maller, G., et al, Improving the Performance and Reliability of Older FGD Systems, Mega Symposium, August 

2010.

101 Moretti, A., 2014, p. 4.

102 Staehle, R., Upgrading Your Wet FGD System, Marsulex, October 2008.

103 Moretti, A., p. 4.

104

 Maller, G., et al, p. 3.

105

 Silva, A., et al.

106 Moretti, A., p. 5.

107 Moretti, A., p. 4, Fig. 4.
48

The spray headers can be replaced with a high-efficiency spray header that uses a high nozzle 

density and wide-angle nozzles. The older spray header designs also used a support system that 

was prone to breakage, resulting in header section failing and falling to the bottom of the 

absorber. Replacing the headers with a modern, self-supporting design reduces maintenance 

costs and outage time.108 A high efficiency spray header in combination with double hollow 

cone nozzles can substantially improve performance, on average proving about a 40% increase in 

performance.109

Many state-of-the-art nozzle designs are available to upgrade scrubber performance. Bidirectional nozzles can be installed regardless of the original design, which provide wider-angle 

spray cones to provide complete coverage of the spray zone and increased gas-liquid contact. 

Side-by-side double hollow cone spray nozzles can be used to improve droplet interaction 

(secondary atomization), thus enhancing removal performance.110

These types of changes ensure a high degree of gas-liquid contact with reduced chance for gas 

sneakage and can significantly improve SO2 removal efficiency and reduce O&M costs. New 

spray headers and/or new nozzles have been used in many scrubber upgrades,111 including 

Fayette Unit 3. 

6.3.4 Improving FGD Chemistry

SO2 removal can be increased by improving slurry reactivity. There are many ways to do this, 

including reducing limestone grind size, eliminating limestone blinding, converting to forced 

oxidation, optimizing operating pH and using performance additives, discussed elsewhere. The 

easiest way to increase SO2 removal efficiency in any scrubber is to increase the slurry pH. The 

SO2 removal typically responds very quickly to an increase in pH. An increase in slurry pH is 

typically achieved by increasing the reagent feed rate, which causes limestone utilization to

deteriorate. This deterioration can be offset by decreasing grind size, which allows operation at a 

higher pH while maintaining limestone utilization.112

Existing units that use natural or inhibited oxidation can be converted to forced oxidation. This 

process converts calcium sulfite to calcium sulfate and improves scrubber operating while 

providing a marketable gypsum byproduct.113

Limestone reagent fineness has a significant effect on limestone utilization, which in turn has a 

significant effect on FGD SO2 removal efficiency. The finer the grind, the higher the removal 

efficiency as the fineness of the limestone affects the rate at which it dissolves in the reaction 

 

108 Moretti, A., p. 5.

109 Klingspor, J., 2012, p. 103.

110 URS, Upgrade of Wet FGD Systems, Available at: http://urs-processtechnologies.com/wpcontent/uploads/2013/02/FGD-Upgrade-Final-2_2013.pdf. 

111

 See for example, Maller, G., et al, p. 3.

112

 Klingspor, J., Brown, G.

113

 Wet Flue Gas Desulfurization (FGD) Systems Advanced Technology for Maximum SO2 Removal, Babcox and 

Wilcox, 2007, p. 4.
49

tank.114 The general rule of thumb today is 95% passing a 325-mesh screen.115 Increasing the 

percentage that passes a 325-mesh screen increases the rate of limestone dissolution, which 

increases the removal efficiency. The majority of the subject FGD systems, those built before 

about 1995, were designed to produce limestone coarser than this optimum.116

Limestone reactivity is also important to scrubber operation. The chemical makeup of the 

limestone exerts a large influence on scrubber efficiency. In general, limestone with 94% or 

more calcium carbonate are very reactive, if properly ground. However, limestone with more 

than about 10% dolomite (MgCO3·CaCO3) are not desirable as the dolomite is rather nonreactive and tends to pass through the FGD untouched and thus does not participate in the 

chemical reactions that remove SO2.

117

 

6.3.5 Use of Organic Acids to Improve Performance

The use of organic acid additives, such as dibasic acid (DBA) and adipic acid, improves SO2

removal efficiency by reducing the L/G ratio. Additional benefits of organic acids like DBA 

(beyond enhanced SO2 removal efficiency) include reduced power consumption, lower spray 

pump flow, lower pressure drop, reduced limestone consumption, reduced overall operating 

costs, and reduced capital costs. They are also used as a backup, to allow a scrubber to be 

designed without a spare spray header and pump, and to allow increases in coal sulfur content.

The least expensive additives are organic acids that buffer the slurry liquor by acting as an acid 

or base to help dissolve limestone or to directly neutralize the sulfurous acid formed by the 

absorption of SO2.118 Dibasic acid (DBA) is the most economical acid. It is a mixture of 

succinic, glutaric and adipic acids and is a byproduct in the manufacture of nylon. They can be 

used continuously or to maintain high SO2 removal efficiencies if a recycle pump is taken out of 

service. They work by buffering the pH at the gas-liquid interface, thus reducing back pressure 

of SO2 and by lowering the liquid-film resistance to mass transfer. DBA and formate are the 

most commonly used additives due to cost.119

The incorporation of organic acids into an upgrade can significantly reduce the capital, 

operating, and maintenance cost of the scrubber. This occurs because organic acids increase 

limestone absorption and stabilize the pH, reducing the liquid-to-gas ratio while maintaining the 

required SO2 removal efficiency or increasing the removal efficiency for a given liquid-to-gas 

ratio. DBA has been reported to provide the equivalent of spraying an extra 20 gpm/1000 cfm of 

 

114

 Maller, G., Wet FGD Chemistry and Performance Factors, Presented at 2008 Power Gen Conference, December 

1, 2008, pdf 48.

115

 LG&E Services Company Contract No. 501654, Mill Creek FGD Performance Upgrade Study, Babcock Power 

Environmental, February 2011, p. 53.

116

 Seward, R., Brame, K., A Review of Methods for Increasing Limestone Reagent Fineness for Flue Gas 

Desulfurization, Proceedings Tenths Symposium on Flue Gas Desulfurization, Vol. 1, February 1987.

117

 Buecker, B., Important Concepts of Wet-Limestone Flue Gas Desulfurization Energy-Tech Magazine, October 

2008, http://www.energy-tech.com/article.cfm?id=21789; PEl Associates, 1985.

118 Moretti, A., p. 5.

119

 Klingspor, J., and Brown, G.
50

limestone slurry. Thus, increasing SO2 removal from 92% to 95% can either add 25% to the 

pump energy input or buy an organic chemical.120

Their benefit over ultra-fine grind limestone is that the effect is immediate. There is no turnover 

of a slurry tank prior to the organic acid impacting absorber performance. However, their 

disadvantages include additional operating cost, uncertainty in long-term supply and pricing of 

DBA byproducts, possible contamination of gypsum by-product, and increased wastewater 

treatment cost.121 

The U.S. Department of Energy and the Electric Power Research Institute conducted full-scale 

testing, process modeling, and economic evaluations of six utility flue gas desulfurization 

systems to evaluate low capital cost upgrades for achieving up to 98% SO2 removal efficiency in 

existing FGD systems. These studies mostly involved using performance additives in the FGD 

systems, but other low cost options were evaluated using an EPRI model. The tested units are: 

Big Bend,122 Merom,123 Pirkey,124 Gibson,125 Elrama, and Kintigh.126 These tests demonstrated 

the efficacy of organic acid additives. Many facilities add acid injection systems based on these 

and other test results, including (can we list the Texas units that use them?)

The addition of an organic acid system to an existing scrubber (that was not designed taking it 

into consideration) would increase the costs by a very small amount compared to the rest of a 

scrubber system. For instance, Invista reports the following based on modeling a 566 MW boiler 

using eastern bituminous high-sulfur coal (3% sulfur, 12,720 BTU/lb heating value) and 90% 

SO2-removal efficiency:127

Modeling shows that operational and maintenance costs of a wet limestone 

scrubber can be reduced by about 2% (about $200,000/year) when using DBA, 

including the cost of the DBA additive. The increased SO2 scrubbing efficiency 

using DBA translates into about a 15% reduction in limestone use, a 1% reduction 

in steam, a 1% reduction in solid waste disposal costs, and a reduction of about 

17% in power usage. Payback time, based on SO2 credit prices of $200/ton, for 

the capital required to retrofit an existing wet limestone scrubber for DBA 

addition (storage tank, pump, piping) ranges from 5 months to about two years, 

 

120 Invista DBA Will be Available to Improve FGD Efficiency, FGD & DeNOx Newsletter, No. 393, January 2011.

121

 Wet Flue Gas Desulfurization Technology Evaluation, Project Number 11311-000, Prepared For National Lime 

Association, January 2003, Prepared by Sargent and Lundy. p. 5.

122

 Radian Corp., Results of High Velocity Tests at Tampa Electric Company's Big Bend 4 FGD System, Topical 

Report, October 15, 1997.

123

 Radian Corp., High SO2 Removal Efficiency Testing, Topical Report, Evaluation of High Efficiency Test 

Results at Hoosier Energy's Merom Station, April 22, 1996.

124

 Radian Corp., High SO2 Removal Efficiency Testing, Topical Report, Results of DBA and Sodium Formate 

Additive Tests at Southwestern Electric Power Company's Pirkey Station, May 30, 1996.

125

 Radian Corp., High SO2 Removal Efficiency Testing, Topical Report, PSI Energy' s Gibson Station High SO2

Removal Efficiency Test Program, May 20, 1996.

126

 Radian Corp., High SO2 Removal Efficiency Testing, Topical Report, Results of Sodium Formate Additive Tests 

at New York State Electric & Gas Corporation’s Kintigh Station, February 14, 1997.

127

 The Role of Dibasic Acid (DBA) in Wet Limestone Flue Gas Desulfurization. Accessed from 

http://intermediates.invista.com/e-trolley/page_1035/, 7/7/2014.
51

depending on operating strategy (i.e. maintain SO2 efficiency and reduce 

operating costs vs. improve SO2 efficiency and profit from emission credits).

Consequently, the wastewater treatment system is the only item that might increase in capital and 

operating costs because organic acids increase the Basic Oxygen Demand (BOD) and Chemical 

Oxygen Demand (COD) of the wastewater, requiring biological treatment.128 Wastewater 

treatment is typically a small fraction of the total cost of a scrubber.

6.3.6 Related Capital Improvements

The improvements discussed above generally require modifications to other facility components 

including the following:

 A new or modified stack

 A new or modified absorber if the original FGD did not include a spare

 A new or modified limestone slurry preparation system

 A new or modified dewatering system

 Upgraded flue gas system

When SO2 removal is increased, the amount of wet FGD byproducts will increase. If the 

upgraded FGD system uses natural oxidation, the disposal pond may reach capacity. This 

usually requires conversion to forced oxidation to eliminate need for disposal ponds 

If limestone consumption is increased to improve SO2 removal, reagent preparation and 

dewatering systems may be undersized. In most cases, higher SO2 removal requires finer grind 

than delivered by older system. Thus, existing milling systems may have to be upgraded to 

handle the new quantity and grinding requirements.129

Older FGD systems used thickeners for primary dewatering and rotary drum filters for secondary 

dewatering. Thickeners are prone to maintenance problems. These thickeners are difficult to 

operate when an FGD is converted to forced oxidation due to rapid settling of gypsum, requiring 

replacement with hydroclones, which are used in modern FGD systems.130 

Older FGD systems used thickeners for primary dewatering and rotary drum filters for secondary 

dewatering. Thickeners are prone to maintenance problems. These thickeners are difficult to 

operate when an FGD is converted to forced oxidation due to rapid settling of gypsum, requiring 

replacement with hydroclones, which are used in modern FGD systems. The rotary drum filters 

 

128

 Riffe, M., et al, Wastewater Treatment for FGD Purge Streams, Paper # 33, Presented at the MEGA Symposium 

2008 Baltimore, MD, August 25 – 28, 2008; INVISTA DBA Dibasic Acid For Flue Gas Desulfurization November 

17, 2010.

129 Harper, G., Hagan, M.A., Dyer, P., and Breuer, W. J., Increasing Capacity of Existing Limestone Grinding 

Systems While Reducing Grind Size, Burns & McDonnell Technical Paper, 2006.

130

 Moretti, A., p. 8.
52

also may not have adequate capacity to handle increased SO2 removal. The capacity constraint 

can be addressed by increasing the amount of time per day that the rotary drum filter operates; 

replacing the rotary drum filter with new generation rotary drum technology; or replacing them 

with vacuum belt filters.131

7 Scrubber Upgrade Analyses

We have conducted a cost analysis for upgrading the scrubbers for those facilities listed in Table 

1 that currently employ a scrubber. As we discussed above in Section 6.1, we have calculated 

the SO2 removal efficiency of these scrubbers as follows:

Table 18. Existing Scrubber SO2 Removal Efficiencies

Facility Unit Bypass?

2009-2013

Average SO2

Removal 

Efficiency (%)

Sandow 4 1 Y 75.7

Monticello 3 Y 60.0

Martin Lake 1 Y 69.2

Martin Lake 2 Y 71.9

Martin Lake 3 Y 69.8

Limestone 1 Y 78.1

Limestone 2 Y 77.0

San Miguel 1 N 94.0

W. A. Parish 8 Y 84.0

7.1 Section 114(a) Information Requests

In order to assess the potential range of options available to upgrade the scrubbers in the facilities 

listed above, we must have an understanding of what upgrades may have already been 

performed. Most of this information is not available publically. Therefore, for each one of these 

units, except for San Miguel, we have requested information under authority granted to us under 

Section 114(a) of the Clean Air Act, which included the following:

a. State whether any of the scrubbers have a bypass.

b. If a unit’s scrubber has a bypass, describe whether the percentage of flow going to the 

scrubber is varied in practice by directly adjusting the bypass or if the bypass is fixed. 

State how and under what circumstances this is accomplished and monitored. 

c. For any scrubber with a bypass, provide the percentage flow that has bypassed the 

scrubber, based on a monthly average, for the years 2008 through 2013, inclusive.

 

131

 Moretti, A., pp. 10-11.
53

d. State the maximum SO2 removal efficiency of each EGU’s scrubber system, based on full 

EGU operating capacity, assuming the optimum amount of reagent usage (including 

dibasic acid or other organic acids), and the type of coal being burned. Either report this 

value assuming 100% of each coal type burned, or by the sulfur content of the coal being 

burned. In reporting this value, do not multiply the efficiency of the scrubber by the 

percentage of flow going to the scrubber – report only the efficiency of the scrubber.

e. State the maximum percentage of flow at maximum EGU operating capacity that can be 

directed to the scrubber and treated at the scrubber’s maximum efficiency. Either report 

this value assuming 100% of each coal type burned, or by the sulfur content of the coal 

being burned. 

f. Describe what improvements have been made to the efficiency of the scrubber system 

since its initial installation, including but not limited to reagent handling and milling, 

addition of dibasic acid or other organic acids, bypass elimination, absorber (e.g., trays, 

liquid distribution rings, sprayers, recycle pumps, etc), stack lining, etc.

i. Provide the capital costs for these projects and the dates when each upgrade was 

installed and became operational.

ii. Provide the percentage improvement in the scrubber system for each of these 

upgrades that were separately installed.

Because the San Miguel facility provided similar information in response to emails and 

telephone requests, we did not send them a request for information under Section 114(a). All of 

these units complied with our Section 114(a) requests, but most of the information provided was 

claimed as Confidential Business Information (CBI) under 40 C.F.R. Part 2, Subpart B. We 

were able to review and analyze that information to assist us in calculating the costs of upgrading 

the scrubbers for those units. However, because our analyses largely depends on that 

information and is thus CBI itself, we can only present a summary of it here. Since the San 

Miguel facility did not assert any CBI information, our assessment of its scrubber is presented 

here and the information that San Miguel’s provided is in our docket in full. 

7.2 Approach to Scrubber Upgrade Cost Analyses

Each of the units listed in Table 18 had contracted with engineering firms (sometimes multiple 

engineering firms) and conducted multiple SO2 scrubber upgrade cost analyses, which we were 

able to review as a result of our Section 114(a) requests. Many of these cost analyses were very 

detailed. Most of these analyses occurred in the 2004 – 2006 timeframe. They were done 

because the facilities had concluded that considering the price of SO2 allowances, upgrading 

their scrubbers would result in an annual cost savings as they could either stop buying SO2

allowances, or even sell excess SO2 allowances. In addition, in a number of cases, the 

companies had concluded that upgrading various pieces of equipment related to their SO2

absorbers that either required constant maintenance, or due to their poor initial design caused 

other problems, would additionally result in annual cost savings.
54

These scrubber upgrades concentrated on optimizing the unit’s total SO2 removal, with the 

primary goal being the elimination or minimization of the scrubber bypasses. In most cases, 

these cost analyses included the following:

 Additional induced draft fan capacity and upgrading of the electrical distribution system

to handle the additional load.

 Upgrading of the absorber(s) spray header to more efficient designs.

 Using all available slurry recycle pumps.

 Replacement of the mist eliminators with more efficient designs.

 Use of absorber trays or liquid distribution rings.

 Flow studies to identify flow maldistribution across multiple absorbers and the use of 

turning vanes (flow straightening baffles used in duct work) to correct this situation.

 Conversion to wet stack operation, which in most cases involved the demolition of the 

existing stack and the construction of a new wet stack.

In addition, some of the units’ cost analyses included either upgrading or the addition of new 

DBA systems and forced oxidation systems.

Many units completed some of this work, which usually involved the upgrading of absorber 

internals (e.g., spray headers, recycle pumps, trays, liquid distribution rings, etc.). Many also 

partially reduced their scrubber bypasses because upgrading their absorbers allowed them to cost 

effectively treat more flue gas. None, however, with the exception of San Miguel, totally 

eliminated their scrubber bypasses.

Our approach to analyzing the cost of a unit’s scrubber upgrade was the same in all cases except 

for San Miguel and consisted of the following basic steps:

 Conduct a literature search of published information from all available non-proprietary 

sources on any work conducted at the subject facility.

 Review the responses to our Section 114(a) request.

 Construct a timeline of all SO2 pollution control equipment installations or upgrades, 

noting what work had already been done so it could be eliminated from our cost analysis.

 Determine what additional equipment is necessary in order to eliminate the SO2 scrubber 

bypass and ensure that the unit’s overall SO2 removal efficiency is at least 95%.

 Use the company’s scrubber upgrade analyses to estimate the capital and operating costs 

of eliminating the SO2 scrubber bypass and ensure that the unit’s overall SO2 removal 

efficiency is at least 95%.

 Escalate the capital and operating costs to 2013 dollars.

 Annualize the capital and operating costs and calculate the cost effectiveness ($/ton) 

using the same methodology used in our DSI and scrubber retrofits in Sections 3, 4, and 

5, above.

 Weigh the cost of the scrubber upgrades against the visibility improvement at the affected 

Class I areas.

We discuss how we analyzed San Miguel for potential scrubber upgrades section 7.3.1 below.
55

7.3 Summary of Scrubber Upgrade Cost Results

With the exception of San Miguel, we are limited in what information we can include in this 

section, because in developing our scrubber cost estimates we used information that was claimed 

as CBI. This information was submitted in response to our Section 114(a) requests. We can 

therefore only present the following summary.

With the exception of San Miguel, we propose to find that for all the units we analyzed:

 The absorber system had either already been upgraded to perform at an SO2 removal 

efficiency of at least 95%, or it could be upgraded to perform at that level using proven 

equipment and techniques.

 The SO2 scrubber bypass could be eliminated, and the additional flue gas could be treated 

by the absorber system with at least a 95% removal efficiency.

 Additional modifications necessary to eliminate the bypass, such as adding fan capacity, 

upgrading the electrical distribution system, and conversion to a wet stack could be 

performed using proven equipment and techniques.

 The additional SO2 emission reductions resulting from the scrubber upgrade are

substantial and cost effective.

A summary of our analyses is as follows:

Table 19. Summary of Scrubber Upgrade Results

Unit

2009-2013

3-yr Avg. 

SO2

Emissions 

(eliminate 

max and 

min)

(tons)

SO2

Emissions 

at 95% 

Control

(tons)

SO2

Emissions 

Reduction 

Due to 

Scrubber 

Upgrade

(tons)

SO2 Emission 

Rate at 95% 

Control 

(lbs/MMBtu)

W. A. Parish WAP8 2,586 836 1,750 0.04

Monticello 3 13,857 1,571 12,286 0.06

Sandow 4 22,289 4,625 17,664 0.20

Martin Lake 1 24,495 3,706 20,789 0.12

Martin Lake 2 21,580 3,664 17,917 0.12

Martin Lake 3 19,940 3,542 16,389 0.11

Limestone 1 10,913 2,466 8,446 0.08

Limestone 2 11,946 2,615 9,331 0.08

Total SO2 Removed 104,572

We calculated the cost effectiveness for each of these units. Because those calculations 

depended on information claimed by the companies as CBI we cannot present it here, except to 

note that in all cases, the cost effectiveness was less than $600/ton. We invite the facilities listed 

above to make arrangements with us to view our complete cost analysis for their units.
56

7.3.1 San Miguel 

The San Miguel facility is located near Christine, within Atascosa County, Texas. It consists of 

one unit, which is a wall fired boiler, rated at 390.3 MW and became operational in 1982. Unit 1 

burns a high sulfur lignite. 

According to the EIA, it employs OFA and LNBs to control NOx, and a cold side ESP to control 

PM. A wet limestone FGD manufactured by Babcock and Wilcox was installed with the boiler 

in 1982 to control SO2. Each scrubber includes four absorbers, all of which operate at 100% 

load. It does not employ a bypass. EIA does not indicate that San Miguel utilizes a DBA system 

to improve SO2 removal efficiency, but the facility does in fact utilize a DBA system. Weilert 

and Meyer report that the San Miguel scrubber utilizes inhibited oxidation.132

Figure 3. Aerial view of the San Miguel facility

According to information provided by San Miguel,133 its SO2 scrubber’s original 1982 design 

efficiency was 86% with an average efficiency of approximately 84%. It was equipped with a 

 

132

 Weilert, C., and Meyer, E., Utility Design Trends, Power Engineering, 8-1-2010; personal communication. See 

summary of this data elsewhere in Section 6.

133

 Email from Joe Eutizi to Joe Kordzi on 5-12-14, and report entitled, “San Miguel Cooperative FGD Upgrade 

Program Update,” transmitted by email from Joe Eutizi to Joe Kordzi on 7-1-14.
57

bypass, two levels of trays, one level of absorber spray nozzles, and a venturi quencher inlet 

section. San Miguel’s scrubber has undergone a number of upgrades since its installation in 

1982:

Table 20. Scrubber Improvements Performed at the San Miguel Facility

Timeframe Scrubber Improvement

1983/84 Installed DBA to improve limestone reactivity.

2000 Increased DBA usage to improve efficiency up to 90%.

2002 Decreased using bypass except for limited maintenance time frames. 

Scrubber efficiency was increased to 91%.

2006

Opened venturi & installed concurrent spray nozzles. Replaced course 

spray absorber nozzles with fine spray absorber nozzles. Scrubber 

efficiency increased to 93%.

2007 Removed scrubber bypass.

2008 Added turning vanes to inlet ductwork for improved gas distribution.

2009 Added water proof liner to interior of brick liner of the stack and 

upgraded the breeching expansion joint in the stack.

2010 Replaced absorber spray nozzles with duel cone high efficiency nozzles, 

improving the efficiency to 94%.

2011/2012 Added anti-sneakage baffles, move quencher sprays to second level of 

absorber sprays, replaced absorber trays to handle larger flow. 

2013

Moved anti-sneakage baffle –was too close to trays and prevented tray 

flooding. Installed borosilicate block in lower 80’ of stack to prevent 

damage to brick liner (water proof liner installed in 2009 failed in this 

area of the stack in 2012)

2014

Partial change out of upper tray to improve liquid distribution on trays. 

Modified sludge handling system to handle the larger heavier sludge 

due to the improved scrubber chemistry.

San Miguel is a mine mouth lignite fired station. They do not have a rail unloading system so 

the lignite mined is the only solid fuel that is burned. The sulfur content in the coal varies 

depending on the area that is being mined. San Miguel reports the following average yearly 

sulfur percent and Btu value for our lignite for the past 5 years:

Table 21. San Miguel Sulfur Content and Btu Coal Value

Year % Sulfur Btu/lb

2009 2.68 5,280

2010 2.82 5,303

2011 2.75 5,280

2012 2.49 5,179

2013 2.38 5,209
58

San Miguel states that these values would equate to uncontrolled SO2 emission rates that range 

from a high of 10.64 lbs/MMBtu to a low of 9.14 lbs/MMBtu. We are unaware of any facility in 

the United States that burns a higher sulfur coal.

San Miguel provided a 2013 report134 that detailed the scrubber upgrades that San Miguel has 

performed. In that report, URS outlines two options for improving the scrubber efficiency:

Option 1 – Modification of Existing Absorber Spray Section (quantities are per absorber)

 Remove the 28 existing six-inch spray nozzles

 Install 28 2205 duplex stainless steel flow splitters or “spiders”, one at each six-inch 

flange where the existing six-inch spray nozzles are currently located. The spiders are 

approximately two feet tall and split the flow from each six-inch connection (24,000 gpm 

/28 = 857 gpm) so that it feeds three tangential four-inch nozzles at the bottom of the 

spider.

 Install three new high-efficiency 4-inch silicon carbide DHC nozzles on each spider. 

Each DHC nozzle has 286 gpm of flow.

 Install a spray impingement plate on the walls where the spray from the DHC nozzles hits 

the walls to protect the rubber lining from erosion.

 Repair the existing rubber lining after the impingement plates were installed.

Option 2 – Option 1 plus Move Quench Spray to Absorber Section.

 Option 1 work scope

 Remove the external FRP headers feeding the two existing quench spray levels and 

existing 20-inch FRP piping that fed those headers back to the 20-inch rubber-lined steel 

pipe flange.

 Remove the existing internal headers, nozzles, and any non-structural internal beams or 

other items in the existing quench spray area. Repaired rubber lining at new wall 

penetrations.

 Install new 20-inch abrasion-resistant FRP piping, supports, and expansion joints from 

the flange referred to above to the absorber section between the existing sprays and the 

top tray.

 Relocate (raise by one foot) the existing absorber stiffener beams between the existing 

sprays and the top tray so they do not interfere with the new header/sprays described 

below.

 Install six new 12-inch penetration spools (2205 duplex) and six new self-supporting 

internal headers and support brackets (2205 alloy) between the existing absorber spray 

and the top tray, approximately in the location of the existing internal absorber stiffener 

beams described above.

 Install 14 new high-efficiency 3-inch DHC nozzles on each of the six new internal 

headers for a total of 84 DHC nozzles. Each DHC nozzle has 133 gpm of flow for a total 

of 11,300 gpm for this new absorber spray section.

 

134

 San Miguel Electric Cooperative, FGD Upgrade Program Update, URS, June 30, 2014. This report is in our 

docket.
59

 Install 2205 duplex SS spray impingement plates on the walls just below the new spray 

headers/DHC nozzles.

 Repair the damage to the existing rubber lining incurred while relocating the beams and 

installing the new spray headers and the spray impingement plates.

 Remove the two existing trays. Reused the existing tray supports as much as possible.

 Install two new 2205 duplex high-efficiency trays with 37% net open area (versus 31.7% 

net open area for the existing trays).

 Conduct CFD modeling to evaluate gas and liquid flow patterns from the modified 

equipment to determine the extent of the wet-dry interface, alloy wall papering needed, 

and the design of an internal baffle to smooth the gas flow immediately upstream of the 

bottom tray.

 Install C-276 alloy wall papering in the new wet/dry interface areas and baffle as needed 

based on the CFD modeling.

 Remove existing rubber lining as needed to install the wall paper and the baffle.

A key goal of the both Option 1 and 2 was to reduce the reliance on DBA, while improving the 

SO2 removal efficiency, in order to reduce the scrubber’s annual operating expenses. URS 

reports that the estimated total project cost (engineering, procurement, and construction) for 

Option 1 was $1,600,000 and for Option 2 was $8,800,000. 

URS states that prior to the start of the upgrade program, the San Miguel FGD system required a 

DBA level of approximately 1400 ppm to achieve 94.75% SO2 removal while firing lignite with 

an average sulfur content of 9.6 lb/MMBtu, resulting in an annual cost of DBA of about $2.7 

million dollars.

Option 1 was designed to achieve the same 94.75% SO2 removal with a higher 10.5 lb/MMBtu 

coal with a lower DBA concentration of about 725 ppm and an annual cost of DBA of about 

$1.46 million per year. This represented a savings of about $1.3 million per year, with a nearly 

10% greater lignite sulfur content. Option 2 was designed to achieve the same 94.75% SO2

removal with 10.5 lb/MMBtu lignite with an even lower DBA concentration of about 125 ppm, 

and an annual cost of DBA of about $250,000. This represented a savings of about $2.5 million 

per year, with a nearly 10% greater lignite sulfur content.

San Miguel elected to initially install the Option 1 scrubber upgrade in all four of its absorber 

modules during its spring 2010 outage, and the Option 2 scrubber upgrade during its spring 

outage in 2012. San Miguel subsequently further upgraded the scrubber system by making 

improvements to the tank agitators in 2011 - 2012, and again replacing its trays with an 

improved design during the spring 2014 outage. URS states that it appears the FGD system is 

currently operating as intended both from a chemical and physical design standpoint. The most 

recent performance data collected with the unit at full load during May and June, shows that the 

FGD system is achieving approximately 94% SO2 removal efficiency at absorber DBA 

concentrations of about 400 ppm.
60

Table 22. Summary of SO2 Emissions from the San Miguel Facility

2009 2010 2011 2012 2013

2009-

2013 

Average

Annual monitored 

emissions (tpy) 11,064.4 10,151.2 10,123.4 10,950.2 8,985.1 10,254.9

Calculated 

uncontrolled SO2

emissions (tpy)

179,595.1 181,455.2 185,834.6 165,495.7 140,094.5 170,495.0

Average estimated 

control level 93.8% 94.4% 94.6% 93.4% 93.6% 94.0%

Annual monitored 

SO2 emission rate 

(lb/MMBtu)

0.64 0.63 0.60 0.63 0.58 0.62

Calculated 

uncontrolled SO2

emission rate 

(lb/MMBtu)

10.30 10.63 10.40 9.59 9.12 10.03

The above table was constructed from the file, “Coal vs CEM data 2009-2013.xlsx,” which is in 

our docket. “Annual monitored emissions (tpy),” represents the average annual SO2 emissions 

as reported to our Air Markets Program Data website.135 “Calculated uncontrolled SO2

emissions (tpy)” represents what the theoretical calculated annual SO2 emissions would be if San 

Miguel had no SO2 scrubbers, based on coal dated reported to the EIA. The last two rows are 

similarly explained.

 

135

 http://ampd.epa.gov/ampd/
61

San Miguel’s monthly SO2 emission data from 2013 is:

Table 23. 2013 Monthly SO2 Emission Data for the San Miguel Facility

Year Month

Operating 

Time 

(hours)

SO2

(tons)

SO2

Emission 

Rate 

(lbs/MMBtu)

2013 1 744 886.184 0.544

2013 2 671.5 759.849 0.569

2013 3 49.75 74.948 0.710

2013 4 668.5 753.295 0.587

2013 5 344.75 383.038 0.594

2013 6 720 917.028 0.637

2013 7 731 922.075 0.581

2013 8 649 795.605 0.626

2013 9 379 439.158 0.530

2013 10 728.75 967.086 0.552

2013 11 720 1104.451 0.624

2013 12 744 982.405 0.545

2014 1 536 510.134 0.425

2014 2 511 554.017 0.519

2014 3 1 0.047 0.079

2014 4 127 126.051 0.572

2014 5 743.5 925.666 0.580

2014 6 720 811.227 0.521

We propose to conclude that the San Miguel facility has upgraded its SO2 scrubber system to 

perform at the reasonably highest level that can be expected, based on the extremely high sulfur 

content of the coal being burned, and the technology currently available. We conclude, based on 

the scrubber upgrades it has recently performed and its demonstrated ability to maintain an 

emission rate below this value on a monthly basis from December 2013 to June 2014 that it can 

consistently achieve this emission level.