The Report Contains San Miguel Electric Cooperative and URS Confidential Information

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San Miguel Electric Cooperative

FGD Upgrade Program Update

Prepared for:

San Miguel Electric Cooperative

6200 FM 3387

Christine, Texas 78012

P.O. Box 280

Jourdanton, Texas 78026

Submitted by:

URS Corporation

9400 Amberglen Boulevard

Austin, Texas 78729

June 30, 2014
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Table of Contents

1.0 INTRODUCTION............................................................................................................. 1

2.0 SUMMARY OF UPGRADE OPTIONS EVALUATED............................................... 1

3.0 PROCESS ANALYSIS..................................................................................................... 7

4.0 COST ESTIMATE............................................................................................................ 9

5.0 ECONOMIC ANALYSIS .............................................................................................. 12

6.0 PROJECT SCHEDULE................................................................................................. 14

7.0 CONCLUSIONS ............................................................................................................ 14

8.0 ADDENDUM – INTERIM RESULTS OF IMPLEMENTATION OF OPTION 1 

AND 2 FGD IMPROVEMENTS............................................................................................... 14

9.0 SUMMARY ..................................................................................................................... 21
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List of Tables

Table 3-1. San Miguel DBA Consumption Predictions.................................................................. 9

Table 4-1. Summary of Purchased Equipment and Materials ...................................................... 10

Table 4-2. Cost Estimate............................................................................................................... 11

Table 5-1. Comparative Economics for Current FGD Operations versus Upgrade Options 1 and 2

............................................................................................................................................... 13

Table 8-1. Results of FGD testing from April 2012 through June 2014

List of Figures

Figure 2-1. Spray Pattern from Proposed Double Hollow Cone Spray Nozzles........................... 3

Figure 2-2. Spray Pattern from 28 Existing Six-Inch Nozzles in the Absorbers........................... 4

Figure 2-3. Spray Pattern from 28 Spiders, Each with Three Four-Inch DHC Nozzles................ 4

Figure 2-4. Rough Sketch of a Spider............................................................................................ 5

Figure 2-5. Spray Pattern from the 84 Three-Inch DHC Nozzles at the New Lower Absorber 

Spray............................................................................................................................ 7

Figure 3-1. FGDPRISM Predictions for San Miguel FGD System Performance ......................... 8

Figure 8-1. Graphics from CFD modeling study of San Miguel FGD reaction tanks

Figure 8-2. Results of CFD study of San Miguel absorber internals

Figure 8-3. Results of CFD evaluation showing uneven distribution of slurry to the upper tray

Figure 8-4. Results of CFD evaluation showing improved distribution of slurry to modifed upper 

tray

Figure 8-5. Example of SO2 gas traverses of the outlet duct of the A module

Figure 8-6. Inspection of San Miguel FGD Recycle Pump Showing Worn Impellor 
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1.0 Introduction

This report discusses the results of the program that URS undertook with San Miguel beginning 

in 2009 to study ways to upgrade the SO2 removal performance of the FGD system and 

subsequently to implement those changes on all four modules. The first sections summarize the 

results of URS’s engineering study to evaluate options to upgrade the SO2 removal performance. 

The last section provides an interim update of the FGD system and how it has performed since 

the upgrades were implemented.

Prior to initiating this FGD upgrade study, URS reviewed a report provided by San Miguel on 

the SO2 upgrade that was completed at the plant in 2006. The result of URS’ review indicated 

that there were additional opportunities to possibly improve the scrubbers to boost removal 

and/or reduce the reliance on the additive DBA. The study confirmed that initial assessment. 

The first sections describe the scope of work and costs for two different upgrade alternatives –

one a low-cost approach that could be completed in a relatively short period of time and a 

second, more comprehensive approach that involved more money and time, but which had the 

potential for greater benefits.

The rest of this report contains the following sections:

 Section 2 – Summary of Upgrade Options Considered;

 Section 3 – Process Analysis;

 Section 4 – Cost Estimate;

 Section 5 – Economic Analysis;

 Section 6 – Project Schedule; and

 Section 7 – Conclusions of the Study phase

 Section 8 - Interim Results of Implementation of Option 1 and 2 Improvements on FGD 

Performance

2.0 Summary of Upgrade Options Evaluated

The San Miguel FGD system consists of four modules that are typical of the first generation 

limestone FGD systems designed in the late 1970’s and early 1980’s. The modules have a 

venturi section for the first contact zone of flue gas and recycled slurry and an absorber section 

for the second contact zone where the majority of the SO2 scrubbing is accomplished. The 

venturi section was originally intended to remove residual fly ash and some SO2, and to saturate 

the flue gas prior to entering the tray section of the absorber. The absorber utilized two countercurrent trays and a flooding spray header to distribute the recycle slurry to the trays. At the time 

of the study, both zones of the modules have been modified from their original designs – the 

venturi had been opened up to reduce its pressure drop and the recycle slurry fed to it was 
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introduced in a down-flow, co-current-with-the-flue-gas manner. The absorber had its spray 

nozzles modified (wider spray angle).

When URS examined the layout of the recycle spray headers, good opportunities for 

improvement were identified. URS has been redesigning the internals of older FGD systems in 

the U.S. for many years. More recently URS has been focusing on how to improve gas/liquid 

contacting so that absorber towers can maximize SO2 removal – often targeting upper 90 percent 

SO2 removal efficiencies for absorbers without having to rely on organic acids like DBA. URS 

has also been designing and installing trays in some of these same towers, combining the synergy 

of the upgraded spray headers/nozzles with our new sieve tray designs to achieve high SO2

removals. 

Two basic upgrade options were identified and examined in the study phase of the program:

 Option 1 – Modification of Existing Absorber Spray Section; and

 Option 2 – Option 1 plus Moving Quench Spray to Absorber Section.

Both options included upgrading slurry spray headers to use the Lechler TwinAbsorb® spray 

nozzles. This nozzle has two outlets that produce intersecting hollow cone sprays, known as 

double hollow cones (DHC), which improves SO2 removal as compared with standard spray 

nozzles. Figure 2-1 shows the intersecting sprays, which break up the drops and regenerate 

droplet surface area. 

Research has shown that most of the SO2 removal in a spray tower absorber occurs within 18” of 

the spray nozzle exit. Improved scrubbing results when the spray is turbulent in that zone and 

the number of droplet-to-droplet collisions are high. Experience has shown that the DHC 

nozzles provide maximum scrubbing efficiency when designed with a wider spray angle. The 

two DHC outlets each have 120-degree spray angles, but the two are tilted about 15° apart, 

which creates an oval pattern overall. URS has installed DHC nozzles in a number of FGD 

systems and the results have consistently shown an improved ability to scrub SO2 compared to 

conventional single cone nozzles.
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Figure 2-1. Spray Pattern from Proposed Double Hollow Cone Spray Nozzles

The summary of equipment modifications and construction scope of work associated with each 

of these basic options is presented below. The information presented below is for one absorber 

(four absorbers have been upgraded):

 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.

Figures 2-2 and 2-3 on the next page show the improvement in spray pattern with the spiders. 

The 28 original six-inch nozzles provided only 85% coverage of the cross-sectional area of the 

absorbers at a point 18 inches below the nozzles; the 84 four-inch nozzles on the spiders provide 

265% coverage at the same distance. Figure 2-4 is a sketch of an individual spider arrangement.
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Figure 2-2. Spray Pattern from 28 Existing Six-Inch Nozzles in the Absorbers

Figure 2-3. Spray Pattern from 28 Spiders, Each with Three Four-Inch DHC Nozzles
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Figure 2-4. Sketch of the Spider

 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.
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- 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.

- 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.

Figure 2-5 on the next page shows the spray pattern from the 84 new three-inch DHC nozzles in 

the new lower spray header in the absorber section. The new spray coverage, measured 18 

inches below the nozzles, is 254%.
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Figure 2-5. Spray Pattern from the 84 Three-Inch DHC Nozzles at the

New Lower Absorber Spray

3.0 Process Analysis

To evaluate the potential benefits of improving the scrubbers at San Miguel by the options 

described in the previous section, we used the EPRI (Electric Power Research Institute) 

FGDPRISM computer model. This model was developed by URS for EPRI to simulate a variety 

of lime and limestone FGD systems based on numerous investigations of laboratory, pilot, and 

full-scale FGD systems. Based on the data supplied from San Miguel on the current system 

design and operation, we applied the FGDPRISM model to the existing layout and operating 

conditions and matched the currently observed SO2 removal efficiency by adjusting the model’s 

liquid and gas-side mass transfer coefficients. 

The different options being considered were then examined for operation at a higher inlet SO2

level of 10.5 lb SO2 / MMBtu. As described earlier, Option 1 consists of modifications where 

the absorber spray header systems are upgraded to provide improved gas/liquid contacting as 

well as a change-out of the type of spray nozzles to the higher performing double hollow cone 

designs. The second option includes Option 1 modifications plus additional changes where the 

quencher sprays are redirected to the absorber side and a second spray header installed above the 

two sieve trays and the quencher is essentially converted into straight-through ductwork. The 

existing trays are replaced with new, high efficiency trays having more open area to 

accommodate the additional slurry flow without excessive pressure drop.
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Figure 3-1 is a plot of the FGDPRISM predictions for Options 1 and 2 with respect to SO2

removal as a function of DBA concentration in the scrubbing liquor.

Figure 3-1. FGDPRISM Predictions for San Miguel FGD System Performance

Also shown in Figure 3-1 is the current operating point, 94.75% SO2 removal using 1400 ppm 

DBA with an inlet SO2 level of 9.6 lb SO2 / MMBtu. 

Results of the modeling indicated that the modifications associated with Option 1 would result in 

the SO2 removal efficiency being maintained at the 94.75% level while allowing the DBA 

concentration to be dropped to about 725 ppm (about 50% of current operation level). The 

predicted DBA consumption rate for this concentration is about 1.62 million lbs/yr as compared 

to the current consumption rate of about 3 million lbs/yr.

The FGDPRISM modeling results for Option 2, which involves more extensive modifications to 

the absorbers, are also shown in Figure 3-1. The model predicted that the current removal level 

of 94.75% could be achieved with 10.5 lb inlet SO2 using a DBA concentration of only 125 ppm. 

The predicted DBA consumption for this scenario is about 275,000 lbs/yr. 

Table 3-1 presents a summary of the DBA concentrations and predicted consumptions rates for 

the cases modeled by FGDPRISM. The DBA losses are broken into the solution loss (the 

amount that is bled from the system with the product solids and liquid blowdown) and the 

76.0

78.0

80.0

82.0

84.0

86.0

88.0

90.0

92.0

94.0

96.0

98.0

100.0

0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500

ppm DBA % SO2 Removal

Option 1 at 10.5 lb Inlet SO2

Option 2 at 10.5 lb Inlet SO2

Current at 9.6 lb Inlet SO2
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degradation loss (the amount that degrades into CO2 and H2O or is co-precipitated with the 

calcium sulfite solids) components.

Table 3-1. San Miguel DBA Consumption Predictions

Note: Current case is based on 9.6 lb SO2 lignite; Options 1 & 2 are based on 10.5 lb SO2 lignite.

4.0 Cost Estimate

Section 2 described the scope of work for the two upgrade options. Table 4-1 summarizes the 

purchased equipment and materials that were included in the Option 1 and 2 cost estimates. 

Table 4-2 presents the estimate for the total installed costs for each. The estimated total project 

cost (engineering, procurement, and construction) for Option 1 is $1,600,000 and for Option 2 is 

$8,800,000.

Soln Loss Deg. Loss lb/ton SO2 lb/yr

Current 1400 94.75 12.8 6.7 19.5 3,000,000

1 725 94.75 6.6 3.2 9.8 1,620,000

1 1500 97 13.4 6.4 19.8 3,390,000

2 125 94.75 1.1 0.5 1.6 275,000

2 240 97 2.1 1.0 3.1 538,000

2 500 98 4.4 2.1 6.6 1,140,000

Summary of DBA Consumption Predictions

DBA Consumption, lb/ton SO2 Total Consumption

Option DBA Conc, ppm % SO2 Rem
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Table 4-1. Summary of Purchased Equipment and Materials

Modification of Existing Recycle Slurry Spray Headers Trays

Spiders, 1-6" inlet with 3-4" outlets, flanged, 2205 Duplex 37% Open Area Tray (2 per module; 4 modules total)

DHC nozzles, 4", NBSC, 286 gpm each (includes 5% spares) Tray Level Supports (includes main beams, cross channels, and wall brackets)

Spray Impingement Plate, 2205 (includes wall attachment) Rubber Liner Repair at Tray Level (1 ft high around perimeter per tray)

Rubber Liner Repair at spray impingement plates

External Recycle Pipe Supports

Fasteners & Gaskets 20" Supports

4" Nozzle Connections 16" Supports

Fasteners, 2205 (4 per nozzle, 5/8") (includes 5% spares) 12" Supports

Gaskets, EPDM (1 per conn., 1/8" thick) (includes 5% spares) Spring Cans

6" Spider Connections Structural Steel for Supports

Fasteners, 2205 (4 per nozzle, 3/4") (includes 5% spares)

Gaskets, EPDM (1 per conn., 1/8" thick) (includes 5% spares) Fasteners & Gaskets

3" Nozzle Connections

Material Indirect Cost Fasteners, 2205 (4 per nozzle, 5/8") (includes 5% spares)

Freight (3.5% of material cost) Gaskets, EPDM (1 per conn., 1/8" thick) (includes 5% spares)

Vendor Field Services 12" Penetration Spool Connections (2 per spool)

Fasteners, 2205 (12 per conn., 7/8") (includes 5% spares)

Gaskets, EPDM (1 per conn., 1/8" thick) (includes 5% spares)

20" External Recycle Pipe Connections (2 total)

Fasteners, Galvanized CS (20 per conn., 1-1/8") (includes 5% spares)

Lower Level Recycle Slurry Spray (re-routed from current quench section) Gaskets, EPDM (1 per conn., 1/4" thick) (includes 5% spares)

External Recycle Slurry Pipe (20"), flanged, AR-FRP

External Recycle Slurry Manifold (20"x16"x12"), flanged, AR-FRP Relining of Absorber Internal Wall (wet/dry interface area only)

Expansion Joints, 12", rubber, filled arch, (one at each absorber penetration) Wall Paper, C276, 16 gauge, with 30% overlap

Absorber Wall Penetration Spools, 12", flanged, 2205

Spray Headers, 12"x10"x8"x6" with 8-4" stubs for nozzles, flanged, 2205 Modifications for Flow Distribution

Spray Header Supports, wall bracket type, 2205 Bullnose at transition from quench tower to absorber tower, C276, 1/4" plate

DHC nozzles, 3", NBSC, 133 gpm each (includes 5% spares)

Spray Impingement Plate, 2205 Structural Modifications (Absorber Wall)

Rubber Liner Repair at spray impingement plates Wall Stiffeners Modifications

Rubber Liner Repair at Spray Level (wall brackets and penetration spool repads) Wall Repads at new spray level penetrations, Internal, CS

Rubber Liner Repair for Relocated Internal Stiffners

Material Indirect Cost

Freight (3.5% of material cost)

Vendor Field Services

OPTION 2 INCREMENT OVER OPTION 1

OPTION 2 INCREMENT OVER OPTION 1 (Continued)

Description of Purchased Equipment and Materials

OPTION 1
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Table 4-2. Cost Estimate

a. New spiders to split the flow to 28 existing a. New spiders to split the flow to 28 existing

 nozzles in absorber. nozzles in absorber.

b. 84 new DHC nozzles, mounted on new spiders b. 84 new DHC nozzles, mounted on new spiders

c. Add spray impingement plates c. Add spray impingement plates

d. External FRP piping to relocate existing 

 quench flow to absorber, above top tray

e. New external FRP maniford, above top tray

f. New internal headers, above top tray

g. 48 new DHC nozzles on new headers

h. Replace existing trays with two new 

 high-efficiency trays

i. Wall papering and assoc rubber lining removal

j. New bull nose to distribute gas to bottom tray

 more evenly (if CFD modeling confirms need)

EP Contractor -- Engineering and Purchased Equipment

Total EP Contractor Costs* 1,100,000 4,700,000

Construction Contractor -- Construction Materials and Labor**

Wall papering and bull nose materials*** 0 1,100,000

Other construction materials 50,000 150,000

Construction labor and fees 450,000 2,850,000

Total Construction Contractor Costs 500,000 4,100,000

1,600,000 8,800,000

Notes: * Includes 5% spares for nozzles, bolting and other small parts plus 15% contingency on purchased equipment. There is no markup on purchased equipment.

 ** The extent of wall papering and the materials need for the "bull nose" to more evenly distribute the gas to the first tray will not be known until a CFD study is completed as part of the

 detailed engineering design by the EP Contractor. This estimate assumes that the materials for wall papering and the bull nose will be purchased by the construction contractor 

 (or by San Miguel) and will not be part of the equipment purchased by the EP Contractor.

 *** Estimated cost for the wall papering materials, the bull nose, and associated construction labor is an approximation at this point.

Total Project Cost (Engineering, Procurement, Construction, Guarantees)

EP Contractor and Construction Contractor

(Includes Option 1)

Scope of Work and Estimated Costs

Scope of Work Scope of Work

Estimated Cost, $

Option 1 Option 2

Estimated Cost, $
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5.0 Economic Analysis

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 SO2 per million Btu. This DBA level resulted in an annual consumption 

of around three million pounds of DBA (dry basis). At the then current DBA price of $0.90 per 

pound (dry basis), the annual cost of DBA was about $2.7 million dollars.

By installing the Option 1 upgrade described earlier, the required DBA level to achieve 94.75% 

SO2 removal with a 10.5 lb SO2 per million Btu fuel was predicted by the FGDPRISM process 

model to be about 725 ppm. Based on URS’s experience that the DBA feed rate would decrease 

directly proportional to the concentration in the scrubbing slurry, the annual consumption would 

drop to about 1.62 million lb per year. At a DBA cost at $0.90 per lb. this would be about $1.46 

million per year. An Option 1 upgrade was projected to reduce San Miguel’s annual DBA cost 

by nearly $1.3 million even with nearly 10% more sulfur in the lignite. With the Option 2 

upgrade described earlier, the required DBA level to achieve 94.75% SO2 removal with 10.5 lb 

SO2 per million Btu lignite was projected to be about 125 ppm, the DBA use would be about 

0.28 million lb per year, and the annual DBA cost at $0.90 / lb. would be about $0.25 million. 

The Option 2 upgrade was projected to reduce San Miguel’s DBA cost by nearly $2.5 million, 

again, at the higher sulfur level in the lignite.

Table 5-1 on the next page summarizes the cost savings for these two options, the associated 

costs of the upgrades, and the simple payback period of each for the current 94.75% SO2 removal 

situation. This analysis does not consider potential benefits from the sale of SO2 allowances

should a trading program be established in Texas. The payout for Option 1 is around 1.3 years 

and for Option 2 it is around 3.6 years. 
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Table 5-1. Comparative Economics for Original (pre-2010) FGD Operations versus Upgrade Options 1 and 2

SO2 Removal

DBA Price, $/lb dry

DBA Use 

Million 

Lb/yr

DBA Cost 

$Million

Cost 

Savings 

$Million/yr

Upgrade 

Cost 

$Million

Upgrade 

Payback 

Period 

Years

DBA Use 

Million 

Lb/yr

DBA Cost 

$Million

Cost 

Savings 

$Million/yr

Upgrade 

Cost 

$Million

Upgrade 

Payback 

Period 

Years

DBA Use 

Million 

Lb/yr

DBA Cost 

$Million

Cost 

Savings 

$Million/yr

Upgrade 

Cost 

$Million

Upgrade 

Payback 

Period 

Years

Case

Current equipment 3.00 2.70 0 NA NA NA NA NA NA

Option 1 1.62 1.46 1.60 3.39 3.05 1.60 NA NA NA

Option 2 0.28 0.25 8.80 0.54 0.48 8.80 1.14 1.03 8.80

Option 1 vs Current -1.38 -1.24 1.24 1.60 1.29 NA NA NA NA NA NA NA NA NA NA

Option 2 vs Current -2.73 -2.45 2.45 8.80 3.59 NA NA NA NA NA NA NA NA NA NA

Option 2 vs Option 1 -1.35 -1.21 1.21 7.20 5.93 -2.85 -2.57 2.57 7.20 2.80 NA NA NA NA NA

DBA Price, $/lb dry

DBA Use 

Million 

Lb/yr

DBA Cost 

$Million

Cost 

Savings 

$Million/yr

Upgrade 

Cost 

$Million

Upgrade 

Payback 

Period 

Years

DBA Use 

Million 

Lb/yr

DBA Cost 

$Million

Cost 

Savings 

$Million/yr

Upgrade 

Cost 

$Million

Upgrade 

Payback 

Period 

Years

DBA Use 

Million 

Lb/yr

DBA Cost 

$Million

Cost 

Savings 

$Million/yr

Upgrade 

Cost 

$Million

Upgrade 

Payback 

Period 

Years

Case

Current equipment 3.00 3.60 0 NA NA NA NA NA NA

Option 1 1.62 1.95 1.60 3.39 4.07 1.60 NA NA NA

Option 2 0.28 0.33 8.80 0.54 0.65 8.80 1.14 1.37 8.80

Option 1 vs Current -1.38 -1.65 1.65 1.60 0.97 NA NA NA NA NA NA NA NA NA NA

Option 2 vs Current -2.73 -3.27 3.27 8.80 2.69 NA NA NA NA NA NA NA NA NA NA

Option 2 vs Option 1 -1.35 -1.62 1.62 7.20 4.45 -2.85 -3.42 3.42 7.20 2.10 NA NA NA NA NA

98.0%

0.90

1.20 1.20 1.20

94.75%

0.90

97.0%

0.90
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6.0 Project Schedule

Based on vendor inquiries URS had made at the time of the study, all of the material needed for 

both options could be delivered by the March 2010. However, there was not enough time for 

URS to complete enough detailed design work to be able to order all the equipment needed for 

Option 2. The schedule did allow time to implement Option 1 during the March 23 - April 30, 

2010 outage.

7.0 Study Conclusions 

Based on the process model results the two options evaluated offered San Miguel the ability to 

substantially reduce absorber DBA concentration and therefore consumption with the current 

lignite sulfur content of 9.6 lb SO2 / MMBtu coal and the current SO2 removal level of 94.75%. 

Option 1 was the lowest cost and was recommended for implementation first. Option 2 being 

higher in cost was not implemented until 2012 and as described below was aimed primarily at 

achieving compliance with the original version of the Cross State Air Pollution Rule 

promulgated in 2011. 

8.0 Addendum – Interim Results of Implementation of Option 1 and 2 

FGD Improvements 

This section presents and discusses the results of upgrading the San Miguel FGD system with 

both Options 1 and 2 since the improvements were implemented up to the current date of June 

27, 2014. While successful in achieving the desired reduction in DBA concentration, the process 

has taken much longer and proven more challenging than expected. URS has had to expend

significant costs and resources to achieve the performance improvements. San Miguel has 

supported the URS initiatives by providing the labor to install equipment modifications that have 

been necessary and assisting in additional testing of the absorbers. The work has been a joint 

and cooperative with both parties participating in a collaborative fashion. 

San Miguel contracted with URS to install the Option 1 improvements in all four modules during 

the spring 2010 scheduled unit outage. The system was tested shortly after startup and the 

performance met or exceeded guarantees. To achieve an average SO2 removal efficiency of 

about 95% removal prior to the Option 1 improvements required the absorbers to operate at a 

DBA concentration of about 1,400 ppm. The absorbers were able to operate at a DBA 

concentration of around 700 ppm and achieve 95% SO2 removal, effectively cutting in half the 

required levels of DBA. 

Not long after the Option 1 improvements were installed, the Clean Air Interstate Rule (CAIR) 

was replaced by the Cross State Air Pollution Rule (CSAPR) in the summer of 2011. This rule 

required significant reductions in the annual SO2 emissions from San Miguel unit. URS was 

contracted in September 2011 to begin work on the detailed engineering of the Option 2 

improvements described above in Table 4.1 so that the unit could be kept in compliance with the 

new CSAPR requirements. 
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At the time, San Miguel conducted with URS’s assistance a test of the FGD system to quantify 

the performance of the absorbers after 1.5 years of operation and in a “seasoned” condition, 

meaning partially scaled and plugged components in the absorber internals (nozzles, spray 

headers, trays, mist eliminators, etc.). This test which was done in August 2011 revealed that the 

SO2 removal performance of the absorbers had degraded measurably relative to the performance 

test done shortly after the Option 1 improvements were installed in April 2010. Given the very 

high inlet sulfur dioxide concentrations in the flue gas entering the San Miguel FGD system, this 

result is not surprising. Any shortfall in the gas/liquid contact area is magnified to a much 

greater extent than in the typical FGD system in the U.S. 

The test results from August 2011 showed that the absorbers required over 50% more DBA in 

solution to maintain a nominal SO2 removal efficiency of 95% as compared to the testing 

conducted shortly after the Option 1 improvements were made in the spring of 2010.

The Option 2 improvements were installed in the spring outage of 2012. 

Table 8.1 presents results of a number of tests which were conducted over the course of time 

from when both the upgrades had been completed until present day. The first line in the Table 

shows the baseline SO2 removal efficiency and required DBA concentration for the FGD system 

prior to the absorbers being upgraded. As mentioned earlier, under typical conditions, the 

absorbers needed about 1,400 ppm of DBA to achieve nominally 95% SO2 removal. 

Results from the first test conducted shortly after the spring outage of 2012 and after the Option 

2 improvements were installed indicated that the absorbers were not performing anywhere near 

expectations. At that time, URS initiated a significant corrective action program to identify the 

reason for the performance shortfall and to come up with the best solutions. 

This work identified a number of possible causes for the performance shortfall including:

1) Low tray pressure drop

2) Trays coming detached from their supports allowing flue gas bypass and/or uplifting 

in the center area

3) The new wall ring obstructing flow of recycle slurry to the top tray

4) Low recycle pump flow due to eroded impellors

5) Poor quencher and absorber tank agitation

6) Short circuiting of slurry in the recycle tanks

7) Mal-distribution of slurry to the upper tray

8) Mal-distribution of flue gas from absorber to absorber
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Date

Load, 

MW

Average 

Absorber 

DBA, 

mg/L

Stack 

CEMS SO2, 

lbs/MMBtu

Average 

Module 

pH

Measured 

FGD 

Removal 

Efficiency, 

%

Guaranteed 

FGD Removal 

Efficiency, %

Measured vs 

Guaranteed 

Performance 

Pre 

Upgrade 430 1400 0.50 5.9 94.8% - -

4/26/2012 430 1670 0.71 5.9 93.2% 98.5% -5.3%

1/16/2013 430 710 0.63 5.9 93.0% 97.5% -4.5%

4/15/2013 430 230 0.61 6.15 93.5% 91.5% 2.0%

10/31/2013 435 838 0.31 6.1 96.9% 97.9% -1.0%

10/31/2013 431 841 0.25 6.1 97.5% 97.9% -0.4%

11/1/2013 430 782 0.29 6.15 97.1% 97.8% -0.7%

11/1/2013 430 663 0.62 5.96 93.8% 97.5% -3.7%

5/15/2014 415 504 0.39 5.96 96.1% 96.0% 0.1%

5/25/2014 431 250 0.56 5.95 93.8% 91.8% 2.0%

6/20/2014 432 275 0.69 5.94 91.9% 92.5% -0.6%

6/21/2014 431 530 0.56 5.95 93.4% 96.0% -2.6%

6/25/2014 435 430 0.45 6.02 94.7% 95.4% -0.7%

Table 8.1. Results of FGD testing from April 2012 through June 2014

The first problem that was solved was the lower than expected pressure drop. This required the 

reduction in the open area of the trays using thin pieces of stainless steel to block off holes. The 

result was some improvement in the system SO2 performance but not as much as expected. 

Inspections of the internals of the absorbers revealed that some of the trays had come loose from 

their supports allowing them to lift and therefore bypass flue gas around this critical scrubbing 

zone. An improved method of attaching the trays to their supports solved this problem around 

the perimeter of the tower and also clamps were installed in the center of the tower to make sure 

the trays remained flat. These improvements were added in the fall of 2012. Significant 

performance improvements were not seen after these were added.

URS conducted CFD modeling of both the absorber and quencher tanks to investigate if there 

was any short-circuiting of slurry from the down-comers directly to the recycle pump suctions. 

Short-circuiting can be very detrimental to SO2 removal and can lead to rapid scaling inside the 

absorbers and in downstream equipment. The CFD results did not identify any problems and 

showed that the agitators were providing very good mixing in each tank. San Miguel replaced 

all the original tank agitators in the 2011 to 2012 time frame with newer models that give better 

tank agitation. URS modeled the power inputs and prop speed of these new agitators. Figure 8.1 

is an example output from this tank modeling. 
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Figure 8.1. Graphics from CFD modeling study of San Miguel FGD reaction tanks

To determine if there were any problems with gas/liquid distribution inside the absorber in the 

key scrubbing zones around the spray headers and counter-flow trays, URS conducted a CFD 

study in that area of the system. This modeling did turn up a potential problem in that the new 

high efficiency double hollow cone spray nozzles could be impacting the walls of the towers and 

channeling slurry down to the tray in an irregular fashion. The new spray nozzles are designed 

for a 120 degree cone angle, which is wider than the old nozzles. The wider angle nozzles are 

important to maximize SO2 scrubbing from the spray headers. URS has used these exact nozzles 

and a very specific nozzle-to-nozzle spacing to achieve maximum SO2 removal efficiency from 

absorbers with limited recycle pump capacity as at San Miguel. There were no detrimental 

effects in these other absorbers, but then again they do not operate anywhere near the fuel sulfur 

levels at San Miguel.

The consequence of using the wider cone angle nozzle can be seen in Figure 8.2. 
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Figure 8.2. Results of CFD study of San Miguel absorber internals

The upper right CFD image shows that there is a fairly significant amount of slurry from the two 

spray headers that impacts the walls of the towers. While this is a normal occurrence in many 

other spray/tray FGD systems, the conditions at San Miguel with the much higher incoming 

SO2 means that highly efficient gas/liquid mixing must occur in all areas of the tower with no 

margin. So URS redesigned the upper tray to minimize the number and height of the partition 

walls on the outer areas of the tray. Modeling showed that the new trays would even out the 

recycle slurry distribution on the tray, allowing slurry coming down the walls to spread out

horizontally and evenly flood the tray. Figures 8.3 and 8.4 show the before and after slurry 

distribution to the upper tray, respectively. Given the flow improvement that could be achieved 

by redesigning about half of the upper tray compartments, URS procured new sets in late 2013 

for installation in the spring 2014 outage. 
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Figure 8.3. Results of CFD evaluation showing uneven distribution of slurry to the upper tray

 

Figure 8.4. Results of CFD evaluation showing improved distribution of slurry to modifed upper 

tray

Numerous times during the last two years URS has conducted traverses of each of the four 

absorber outlet ducts in an effort to determine if one or more of the absorbers was having a 

problem causing the stack SO2 to be elevated. There were no problems that were clearly 

identified from this work. It did show that in general the gas flowing near the outer areas of the 

absorber walls had very low SO2 concentrations as compared to the inner area where the SO2 
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20

was highest. Figure 8.5 is an example of the SO2 profile that was typically seen during these 

traverses. 

Figure 8.5. Example of SO2 gas traverses of the outlet duct of the A module

The results in the figure graphically show how the flue gas in the center part of the duct just 

above the absorber mist eliminators has much more SO2 in the middle area as compared to the 

perimeter. This supported the CFD modeling results of the absorber internals discussed earlier. 

Those results showed a significant portion of the recycle slurry was trapped around the outer 

areas of the trays. This heavy slurry loading on the outer regions of the tray would provide better 

SO2 scrubbing in that area. However, the heavy loading will force flue gas into the middle 

areas of the tray where there is less resistance due to a lower slurry loading. The combination of 

more flue gas passing through the center of the tray and proportionally less slurry there would 

have an overall detrimental effect on SO2 removal. These observations supported URS’s 

decision to pay for new trays in an effort to solve this problem and help boost overall SO2 

removal by improving gas/slurry contact. These trays were installed by plant personnel during 

the recent spring 2014 outage.

Another area that could cause lower SO2 removal of the upgraded system was the physical

condition of the absorber recycle pumps. These large capacity pumps need to be running at or 

near their rated outputs to allow the upgraded system to perform as designed. A common 

problem with older recycle pumps is worn impellors. Figure 8.6 shows a photo of one of the 

pump impellors taken during the fall 2012 outage. This impellor has significant wear and would 

not be expected to be able to pump at design capacity. Plant maintenance staff keep track of the 
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conditions of the pumps and this particular pump impellor was in line for replacement. San 

Miguel made a concerted effort to inspect and replace all excessively worn pump impellors to 

return the pumps to good operation condition. Subsequently, new pressure gauges were installed 

on the recycle pump discharge piping to confirm that the pumps are operationg satisfactorily. 

These have been tracked over the past year and for all pumps, the pressures indicate that the 

pumps are flowing at design levels.

Figure 8.6. Inspection of San Miguel FGD Recycle Pump Showing Worn Impellor 

9.0 Summary

Significant troubleshooting efforts have been completed by URS and San Miguel since the 

Option 2 improvements were installed in the spring outage of 2012. From all available 

information (flue gas and pump flows, absorber chemistry, absorber internals, CFD and process 

modeling, etc.), it appears the FGD system is currently operating as intended both from a 

chemical and physical design standpoint. Referring back to Table 8.1, the most recent 

performance data collected with the unit at full load during May and June, shows that the FGD 

system is achieving 94 to 95% SO2 removal efficiency at absorber DBA concentrations of about

400 ppm. As mentioned earlier, prior to the Option 1 and 2 upgrades, to achieve 94 to 95% 

removal typically required an absorber DBA concentration of 1,400 ppm. 
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The current required DBA concentration of about 400 ppm is what was expected from the 

absorber upgrades for a target SO2 removal in the range of 94 to 95%. The various re-work 

items described above completed in the past two years each contributed to achieving the goal. 

The redesigned trays were the latest improvement and resulted in the final incremental boost in 

performance. 

It should also be noted that improvements made in the FGD area, specifically in the rake upgrade 

in the T1 tank and conveyor improvements in the filter building, have allowed the absorbers to 

be controlled at higher thiosulfate concentrations and therefore lower sulfite oxidation levels. 

This is very important since it has proven very challenging to maintain consistent control of the 

absorber chemistry – in particular sufficient concentrations of thiosulfate in the absorber slurry –

to keep the sulfite oxidation levels in the desired range which is 5 to 10%, to minimize chemical 

scaling inside the absorbers. This scaling would occur whenever the thickeners or T1 had to be 

bypassed for cleaning due to pluggage of the equipment, or failure of the drum 

filters/conveyors/pug mill in FGD. The root cause of the problem was that the desirable, low 

oxidation conditions also brought with them the production of more pure calcium sulfite crystals, 

which settled much more rapidly causing problems with the dewatering systems that were not 

originally designed to handle them. 

Since the upgrades to the dewatering system, the feed rate of emulsified sulfur has been much 

more regular and there have been fewer cases of absorber blowdown slurry being sent directly to 

the pond which increases chemical consumption rates. Consistent operation of higher thiosulfate 

residuals in the quencher and absorber tanks has been the result. This will maintain cleaner 

conditions within the absorber towers and help the overall system to operate more efficiently for 

longer periods of time. 

URS and San Miguel recently conducted a final performance test in association with the FGD 

upgrade program. The tests were completed on 6/27/14 and within a month from that date the 

results should be available for review.