The Report Contains San Miguel Electric Cooperative and URS Confidential Information

i 

# 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 Boule vard Austin, Texas 78729
June 30 , 2014The Report Contains San Miguel Electric Cooperative and URS Confidential Information

ii 

### Table of Contents

1.0 INTRODUCTION

................................ ................................ ................................ ............. 1

2.0 SUMMARY OF UPGRADE O PTIONS 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 RESUL TS OF IMPLEMENTATION OF OPTION 1
AND 2 FGD IMPROVEMEN TS

................................ ................................ ............................... 14

9.0 SUMMARY

................................ ................................ ................................ ..................... 21The Report Contains San Miguel Electric Cooperative and URS Confidential Information

iii 

### List of Tables

Ta ble 3

- 1. San Miguel DBA Consumption Predictions

................................ ................................ .. 9
Table 4

- 1. Summary of Purchased Equipment and Materials

................................ ...................... 10
Table 4

- 2. Cost Est imate

................................ ................................ ................................ ............... 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. Sp ray 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 Mi guel 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 trav erses of the outlet duct of the A module Figure 8

- 6. Inspection of San Miguel FGD Recycle Pump Showing Worn ImpellorThe Report Contains San Miguel Electric Cooperative and URS Confidential Information

1 

### 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

. Th e first sections summarize the

results of URS ’s e ngineering study to evaluate options to upgrade the SO 2 removal performance

. The las t 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 SO 2 upgrade that was completed at the plan t 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.

Th e first sections de scribe 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 involve d more money and time, but which ha d the potential for greater benefits.

Th e rest of this report contains t he following sections:

 Section 2

– Summary of Upgrade Options Considered;

 Section 3

– Process Analysis;

 Section 4

– Cost Estimate;

 Section 5

– Economic Analysis;

 Section 6

– Project Schedu le; and

 Section 7

– Conclusions of the Study phase

 Section 8

- Interim Results of Implementation of Option 1 and 2 I mprovements on FGD

Performance



### 2.0 Summary of Upgrade Options Evaluated

The San Miguel FGD syste m 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 th e first contact zone of flue gas and recycled slurry and an absorber section for the second contact zone where the majorit y of the SO 2 scrubbing is accomplished. The venturi section was originally inten ded to remove residual fly ash and some SO 2 , and to saturate the flue gas prior to entering the tray section of the absorber. The absorber utilized two counter

current trays and a flooding spray header to distribute the recycle slurry to the trays. At the time of the study, b oth zones of the modules have been modified from their or iginal designs

– the

venturi had been opened up to reduce its pressure drop and the recycle slur ry f ed to it wasThe Report Contains San Miguel Electric Cooperative and URS Confidential Information

2 introduced in a down

- flow, co

- current

- with

- the

- fl ue

- gas manner. The absorber had its spray nozzles modified (wider spray angle).

When URS examined the layout of the re cycle spray headers, good opportunities for improvement were identifie d . URS has been redesigning the internals of older FGD systems in

the U.S. f or many years. More recently URS has been focusing on how to improve gas/liquid contacting so that absorber towers can maximize SO 2 removal

– often targeting upper 90 percent

SO 2 removal e fficiencies for absorbers without having to rel y 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 design s to achieve high SO 2 removals

.

Two basic upgrade optio ns 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 include d 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 improve s SO 2 removal as compared with s tandard 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 SO 2 removal in a spray tower absorber occurs within 18” of the spray nozzle exit. Improv ed scrubbing results when the spray is turbulent in that zone and the number of drop let

- 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 out lets each have 120

- degree spray a ngles

, 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 SO 2 compar ed to conventional single cone nozzles.The Report Contains San Miguel Electric Cooperative and URS Confidential Information

3 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 t hese 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 s teel flow splitters or “spiders”, one at each six

- inch flange where the existing six

- inch spray nozzles are currently located. The s piders are approximately two fee t 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 s pray from the DHC nozzles hits the walls to protect the rubber lining from erosion.

- Repair the existing rubber lining after the impingement plates we re installed

.

Figures 2

- 2 and 2

- 3 on the next page show the improvement in spray pattern with the spider s. The 28 original six

- inch nozzles provide d only 85% coverage of the cross

- sectional area of the absorbers at a point 18 inches below the nozzles; the 84 four

- inch no zzles on the spiders provide

265 % coverage at the same distance. Figure 2

- 4 is a sketch of an individual spider arrangement.The Report Contains San Miguel Electric Cooperative and URS Confidential Information

4 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 NozzlesThe Report Contains San Miguel Electric Cooperative and URS Confidential Information

5 Figure 2

- 4

. Sketch of the Spider

 Option 2

– Op tion 1 plus Mov e Quench Spray to Absorber Section.

- Option 1 work scope

- Remove the e xternal 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

.

- R emove 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 expansi on joints from the flange ref

erred to above to the absorber section between the existing sprays and the top tray.

- Reloc ate (raise by one foot ) the existing absorber stiffener beams between the existing spra ys 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 bracket s (2205 alloy) between the existing absorber spray and the top tray, approximately in the locati on of the existing internal absorber
stiffener beams described above.The Report Contains San Miguel Electric Cooperative and URS Confidential Information

6 - Ins tall 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 fo r this new absorber spray section

.

- Install 2205 duplex SS spray impingement plates on the walls just below th e new spray header s /DHC nozzles.

- Repair the damage to the existing rubber lining incurred while relocating the beams and installing the new spray header s and the spray impingement plates

.

- Remove the two existing trays

. R e us e d 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 C FD 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 spra y pattern from the 84 new three

- inch DHC nozzles in

the new lowe r spray header in the absorber section. The new s pray coverage, measured 18

inches belo w the nozzles, is 2 54 %.The Report Contains San Miguel Electric Cooperative and URS Confidential Information

7 Figure 2

- 5

. Spray Pattern from the 84 Three

- Inch DHC Nozzles at the

New Low er 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 SO 2 removal efficiency by adjusting the model’s liquid and gas

- side mass transfer coefficients.

T he different options being considered were th en examined for operation at a higher inlet SO 2 level of 10.5 lb SO 2 / MMBtu. As described earl ier, O ption 1 consist s of modifications where the absorber spray header systems are upgraded to provide improved gas/liquid contacting as well as a change

- out o f 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 ab ove 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 dr op.The Report Contains San Miguel Electric Cooperative and URS Confidential Information

8 Figure 3

- 1 is a plot of the FGDPRISM predictions for Options 1 and 2 with respect to SO 2 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% SO 2 removal using 1400 ppm

DBA with an inlet SO 2 level of 9.6 lb SO 2 / MMBtu.

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

the SO 2 removal efficiency being maintained at the 94.75% level while allow ing 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 co nsumption rate of about 3 million lbs/yr.

The FGDPRISM modeling results for Option 2

, which involves more extensive modificatio ns 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 SO 2 using a DBA concentration of only 125 ppm. The predicted DBA consumption for this scenario is about 2 75,000 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 an d liquid blowdown) and theThe Report Contains San Miguel Electric Cooperative and URS Confidential Information

9 degradation loss (the amount that degrades into CO 2 and H 2 O 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 SO 2 lignite ; O ptions 1 & 2 are based on 10.5 lb SO 2 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 estimate s

. Tab le 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 $1,6 00 ,000 and for Option 2 is $8,8 00,000.The Report Contains San Miguel Electric Cooperative and URS Confidential Information

10 Table 4

- 1. Summary of Purchased Equipment and MaterialsThe Report Contains San Miguel Electric Cooperative and URS Confidential Information

11 Table 4

- 2

. Cost EstimateThe Report Contains San Miguel Electric Cooperative and URS Confidential Information

12 

### 5.0 Economic Analysis

Prior to the start of the u pgrade program, the San Miguel FGD system required a DBA level of approximately 1400 ppm to achieve 94.75% SO 2 removal while firing lignite with an averag e sulfur conte nt of 9.6 lb SO 2 per million Btu. This DBA level result ed 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 a bout $2.7 million dollars.

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

SO 2 removal with a 10.5 lb SO 2 per million Btu f uel was predicted by the FGDPRISM process

model to be about 725 ppm. Based on URS’s experience that the DBA feed r ate 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 w as 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% SO 2 removal with 10.5 lb

SO 2 per million Btu li gnite w as 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,

a gain, 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% SO 2 removal

situation. This analysis does not consider potential benefits from the sale of SO 2 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.The Report Contains San Miguel Electric Cooperative and URS Confidential Information

13 Table 5

- 1

. C omparative Economics for Original (pre

- 2010) FGD Operations versus Upgrade Options 1 and 2The Report Contains San Miguel El ectric Cooperative and URS Confidential Information

14 

### 6.0 Project Schedule

Based on vendor inquir ies URS had made at the time of the study , all of the material needed for both options could be delivered by the March 2010 . Howev er, 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

Ba sed on the process model results t he two options evaluated offer ed San Miguel the ability to substantially reduce absorber DBA concentration and therefore consumption with the cu rrent lignite sulfur content of 9.6 lb SO 2 / MMBtu coal and the current SO 2 r emoval level of 94.75%. Option 1 was the lowest c ost and was recommended for implementation first . Option 2 being higher in cost was not implemented until 2012 and as described belo w was aimed primarily at achieving compliance with the original version of the Cross State Air Pollution Rule promul gated 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 Mi guel 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

. T he work has bee n a joint and coope rative 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

per formance met or exceeded guarantee s. To achieve an average SO 2 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% SO 2 removal, effectively cutting in half the required levels of DBA.

Not long after the Option 1 improvements were installed , the Clean Air Interstate Rule (CA IR) 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 engineeri ng 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

.The Report Contains San Miguel El ectric Cooperative and URS Confidential Information

15 At the time, San Miguel conducted with URS’s assistance a test of the FGD system to quantify the performance of th e absorbers after 1.5 years of operation and in a “seasoned” condition, meaning partially scaled and plugged components in the absorber internals (nozz l es, spray headers, trays, mist eliminators, etc.). This test which was done in August 2011 revealed tha t 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 ente ring 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 req uired over 50% more DBA in
solution to maintain a nominal SO 2 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 ou tage 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 SO 2 removal efficiency and requir ed 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% SO 2 removal.

Results from the first test conducted short ly 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 f or 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 obstruct ing 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 o f slurry to the upper tray 8) Mal

- distribution of flue gas from absorber to absorberThe Report Contains San Miguel El ectric Cooperative and URS Confidential Information

16 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

G uaranteed 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 abs orbers 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 p erimeter 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 condu cted 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 s caling 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 tim e frame with newer models that gi ve 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.The Report Contains San Miguel El ectric Cooperative and URS Confidential Information

17 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 t urn 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 f rom 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.The Report Contains San Miguel El ectric Cooperative and URS Confidential Information

18 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 to wers. 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 redesi gned 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 pr ocure d new sets in late 2013 for installation in the spring 2014 outage.The Report Contains San Miguel El ectric Cooperative and URS Confidential Information

19 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 slu rry 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

identifie d 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 SO2The Report Contains San Miguel El ectric Cooperative and URS Confidential Information

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 sl urry was trapped around the o uter

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 ther e 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 a n overall detriment al effect on SO2 removal. These observations supported URS’s

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

removal by improving gas/slurry cont act

. These trays were installed by plant personnel during the recent spring 2014 outage.

Another area that could cause lower SO 2 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 recyc le pump s 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 o f theThe Report Contains San Miguel El ectric Cooperative and URS Confidential Information

21 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 p ressure gauges were installed on the recycle pump discharge piping to confirm that the pumps are operationg satisfactorily.

These have been tr acked 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

S ignificant troubleshooting efforts have been completed by URS and San Miguel since the Option 2 improvements were installe d in the spring outage of 2012. From a ll 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

, show s that the FGD
system is achieving 94 to 95 % SO2 removal efficiency at absorber DBA conc entrations of about

4 00 ppm

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

removal typically required a n absorber DBA concentration of 1,400 ppm

.The Report Contains San Miguel El ectric Cooperative and URS Confidential Information

22 The current required DBA concentration of about 400 ppm is what was expected fro m the

absorber upgrades for a target SO2 removal in t he range of 94 to 95%

. T he various re

- work items described above completed in the past two years each contributed to achieving the goal. The redesigned tray s were the latest improvement and resulted in the final incremental boost in performance.

It sh ould 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 lowe r 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 oxidatio n 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/con veyors/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 system s 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 a bsorber blowdown slurry being sent directly to the pond whi ch 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 availab le for review.