# Technology Evaluation of Furnace Sorbent Injection for SO 2 

# Control Within PEC

Prepared by Power Generation Engineering,

Strategic Engineering Section

March 16 th, 2009

Author: Jason Crump12 

## Table of Contents

Executive Summary

................................ ................................ ................................ ................................ ....... 3

Background

................................ ................................ ................................ ................................ ................... 4

What is FSI?

................................ ................................ ................................ ................................ ................... 4

Industry Experience

................................ ................................ ................................ ................................ ...... 5

Why Did PEC Consider FSI?

................................ ................................ ................................ ........................... 5

The Cape Fear FSI Test

................................ ................................ ................................ ................................ .. 6

The Robinson FSI Demonstration

................................ ................................ ................................ ................. 6

Results of the Robinson FSI Demonstration

................................ ................................ ................................ . 8

SO2 Redu ction

................................ ................................ ................................ ................................ ........... 9

Emissions

................................ ................................ ................................ ................................ ................. 10

Fouling and Slagging

................................ ................................ ................................ ............................... 11

FSI Economics

................................ ................................ ................................ ................................ .............. 11

Conclusion

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

Recommendations

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

FSI for SO 2 Control at Robinson

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

FSI for SO 2 Control within North Carolina

................................ ................................ ............................... 143 

## Executive Summa **ry**

Progress Energy Carolinas considered three SO 2 control technologies

, Wet Scrubbers, Dry Scrubbers, and Furnace Sorbent Injection (FSI) for the smaller coal fired units in order t o comply with the sulfur dioxide (SO 2 ) emission requirements of the Clean Air Interstate Ru le (CAIR) and the North Carolina Clean
Smokestacks Act (CSA)

FSI systems ha ve the promise of low capital cost s versus other control options but industry experience is
limited. Init ial financial analysis indicated that the net present cos ts for FSI were lower than the
alternatives

. Since FSI had the potential to be an economical SO 2 control technology , Progres s Energy embarked upon a full scale FSI demonstration on Robinson Unit 1 in South Carolina. The objectiv es of
th is FSI trial were :

**•** To achieve ~50% SO 2 reduction

**•** To maintain boiler reliability and availability

**•** To meet test permit air permit requirements for particulate matters (PM) emissions and opacity

**•** To safely and effectively manage the sorbent and byproduct materials

**•** To provide pro cess data to allow an accurate assessment of the feasibility of FSI in long term operation and evaluate its economics

The testing phase of the Robinson FSI trial was successfully concluded in December of 200 8
, meeting all
of its technical objectives. The trial demonstrated that Furnace Sorbent Injection technology is a viable
method of moderate SO 2 control and that it does not present any significant technical or operational
limitations

. However , results from the trial also revealed that capital costs f o r FSI would be higher than originally estimated due to need for several additional plant upgrades

, including a baghouse that would
be necessary in a permanent installation to control opacity

, and cost escalation since the in i tial financial analysis

. Additional ly the sorbent utilization efficiency was lower than anticipated

, resulting in high
consumable c ost per ton of SO 2 removed.

The data gathered from the Robinson trial allowed a more thorough evaluation of FSI capital, operational and overall lifec ycle costs. T he final evaluation showed that when compared with a Dry
Scrubber

, the net present and cumulative lifecycle costs of FSI are higher

. Additionally in SC , the price
for SO 2 allowances is also projected to be much lower than FSI operating costs per ton of SO 2 removed. As a result, Furnace Sorbent Injection technology is not currently recommended for future SO 2 co ntrol applications within Progress Energy Carolinas

. The existing Robinson FSI will be placed into long term storage and will be available for potential future use should the economics change

.4 

## Background

On June 20, 2002, senate bill 1078 , the Clean Smokestacks Act, was signed into law which capped
emissions of sulfur dioxide (SO 2 ) and nitrogen oxides (NOx) from utility owned coal

- f ired power plants
located in North Carolina. For PEC, these caps represent ed a 74% reduction in SO 2 emissions and a 56%
reduction in NOx emissions from 2001 levels. Additionally , On March 10, 2005, the US E nvironmental

P rotection A gency issued CAIR , a ruling that would have achieved the largest reduction in SO 2 and/or
NOx emissions in more than a decade. When fully implemented, CAIR would have reduced SO 2 emissions in 28 states by over 70 percent and NOx emissions by over 60 percent from 2003 levels.

W hile CAIR was remanded in 2008 , it is widely expected that similar regulations for control of SO 2 and other species will be enacted in the near future

.
Due to these regulatory drivers, PEC began evaluating options for SO 2 compliance and installed Wet
Scrubbers to reduce SO 2 emissions at its Asheville, Mayo, and Roxboro plants. However, Wet Scrubbers

a re more costly for small units and PEC is e valuating other SO 2 reduction options at these locations . The options being explored include switching to low sulfur “ compliance ” coal s , installation of d ry scrubbers

, and a promising but operationally unproven technology called Furnace Sorbent Injection (FSI).



## What is FSI?

Furnace Sorbent Injection (FSI) is a process that involves the injection of d ry sorbents into the boiler for
the reduction of SO 2 emissions. Calcium based sorbents are most commonly used in the FSI process due

to relatively high reactivity and the genera tion of manageable boiler deposits though sodium and magnesium based sorbents ar e also in use. The sorbent s are injected in the upper area of the furnace
where temperatures are in the optimum 2100

- 2200°F reaction range. T hese sorbents then react with
the SO 2 in the flue gas forming solid products that are then captured in the plant particulate control equipment
, reducing stack SO 2 emissions

.

What make s FSI attractive is that it has lower c apital costs when compared with Dry and Wet Scrubber
installations. This is because Furnace Sorbent Injection uses much of the existing plant eq uipment such as the boiler for the reaction vessel and the existing ESP for the product capture. However the use of FSI can also require significant plant upgrades to control fouling, particulate, and opacity from the increased dust loading . These upgrad es can include additional sootblowers, extensive ESP modifications, and a baghouse

.
The primary equipment required for a n FSI system includes sorbent storage silos, sorbent feeders, pneumatic trans port lines, and sorbent injection lances. F igure 1.1 shows a simplified diagram of an FSI
system.5 Figure 1.1

– FSI Process Diagram

Stack ESP Upgrades APH

Coal Sorbent Delivery Sorbent Storage

APH Sorbent Transport

Air Deposit management upgrades

Byproduct management upgrades Collection Sorbent injection FSI storage & transport Reduced SO 2 emissions

Combustion upgrades



## Industry **Experience**

Utility experience with FSI is very limited. Benchmarking was performed with other utilities known to
have some experience with FSI. These utilities include:

**•** Hoosier Energy

**•** Richmond P ower & Light

**•** Central Power & Light Florida

Though experiences differ, FSI systems are reducing SO 2 emissions by 3 0% to 70% depending on the sorbents used, sorbent/sulfur injection ratio, mixing rate, and unit operational specifics. The utilities reported significant issues with controlling PM and/or opacity. The se benchmarking activities validated that Furnace Sorbent Injection had potential for SO 2 reduction, b ut needed to be operationally proven

.



## Wh **y Did**  **PEC C**  **onsider FSI?**

Progress Energy Carolinas is exploring o ptions to meet SO 2 emissions requirements on smaller coal fired
units and FSI wa s an attractive SO 2 control technology due to its promise of :

**•** Potentially low er capital costs compared to Wet and Dry Scrubber s

**•** Potentially lower SO 2 reduction costs

**•** Potentially lower lifecycle costs

**•** Reduced exposure to escalating project costs6 **•** Moderate SO 2 control levels

**•** Multi pollutant control capability (SO x , HCL, and Hg )

However due to the limited industry experience, FSI ’s unknowns included :

**•** Plant upgrades required for permanent installation (to fully evaluate capital costs )

**•** Operational costs and consumable rates

**•** SO 2 reduction potential in long term operation

**•** Boiler impacts and potential for slagging and fouling

**•** ESP impacts and potential for particulate matter or o pacity i ssues

**•** Ash disposal impacts

**•** The potential for enhanced SO 2 removal due to Rotating Overfire Air (ROFA) mixing

Since FSI had the potential to be an economical for m of SO 2 control technology on its small units, but its operational characteristics and costs were not fully understood, Progress Energy began a series of FSI
demonstrations to gain more experience with FSI

.



## The **Cape Fear FSI**  **Test**

Due to FSI’s potential fit on PEC’s small er plants

, PEC performed a proof of concept test at Cape Fear
unit 5 in December of 2002

. In the test

, various types of sorbents were injected into the boiler to evaluate their SO 2 reduction. The results of this limited testing showed that 58% SO 2 reduction was possible

. However after one week into the trial

, e xcessive slagging occurred on the pendant superheater that required a shutdown of the unit and the remaining test ing was subsequently cancelled

.
Though limited

, PEC ’s FSI experience at Cape Fear 5 confirmed FSI had potential for SO 2 control but that additional plant modifications w ould also be necessary to control deposits and that a more thorough
evaluation of the other potential impacts would also be required

.



## The **Robinson FSI Demonstration**

Based on the experience at Cape Fear and a desire to more fully understand FSI operation al impacts
,
assess FSI’ s SO 2 reduction potential, and better evaluate the economics
, PEC contracted GE Energy to perform a multi

- phase project to demonstrate Furnace Sorbent Injection technology for SO 2 control. The purpose of this demonstration was to define the technical performance and operational economics of FSI as a potential means of meeting current and p ending regulatory em issions control requirements.7 The technical objectiv es of the FSI trial were :

**•** To safely and effectively manage the sorbent and byproduct materials

**•** To achieve ~ 50% SO 2 reduction

**•** To maintain boiler reliability and availability through successfully manage ment of the furnace and convective pass deposits

**•** To meet test permit requirements for particulate matters (PM) emissions and opacity

**•** To provide process data to allow an accurate ass essment of the feasibility of FSI and its lifecycle
economics

Unit 1 at the H.B. Robinson plant in Hartsville, South Carolina was chosen as the demonstration site for the long term FSI trial

. Phase I of the project included d etailed examination s of the Ro binson boiler structural configuration, process parameters, operational characteristics, and gas

- side flow field
characteristics.

To characterize potential operational impacts and to develop recommended corrective actions, a
detailed Failure Modes and Ef fects (FMEA) analysis was developed through a series of meetings
between GE and PEC . Potential failure modes were grouped into four categories. Each failure mode was assigned a Relative Priority Number based on the likelihood, detectability, and severity o f the failure. As
summarized in Table 1.1 , a total of 341 potential failure modes were identified. The FMEA was updated throughout the course of the project

.

Table 1.1

– Failure Modes and Effects Analysis

Relative Priority Number Range Material Handling Boiler Emissions Control Byproduct Removal Total

0

- 100 3 71 7 1 82 101

- 200 17 39 5 4 65 201

- 300 9 69 4 1 83 301

- 400 9 29 9 3 50 401

- 500 2 28 0 1 31 501

- 600 0 21 6 1 28 601

- 700 0 1 1 0 2 701

- 800 0 0 0 0 0

Total 40 258 32 11 341

The Phase I process design study applied several design tools, including physical flow modeling, computational fluid dynamics (CFD) modeling, thermal m odeling, and sulfation modeling to simulate the
boiler and FSI system performance. Based on the previous tri al at Cape Fear 5, GE’s modeling, and other industry experience, hydrated lime Ca(OH) 2 was chosen as the sorbent. T hough overall SO 2 reduction was GE’s main FSI design objective, other important FSI design considerations include impacts upon boiler deposit management, ESP perform ance, and byproduct management. The results from the study8 served as the basis for Phase II, development of the detailed e ng ineering design and specification of the FSI system

.

The unit’s ESP performance was al so reviewed by GE during and several improvements were identified to improve collection efficiency. These included adding anti sneak baffles, frame stabilizers, and increasing the number of inlet sections

.
Phase III, P rocure ment and I nstallation of the FS I System was completed in June 2008. In addition to the FSI system and ESP upgrades, the Robinson project also included other plant upgrades that benefited
the FSI demonstration but were also designed to continue to be utilized by the plant after the trial was completed. These upgrades included:

**•** A coal combustion management system (CCM) to improve temperature distribution at the reagent injection locations, improve combustion and lower LOI

**•** An intelligent sootblowing system (ISB) to reduce excessive so otblowing & tube wastage

**•** A d ry fly ash removal system to allow for future byproduct sales

Phase IV of the project , Commissioning and Equipment Performance Testing began in July 2008 and
consisted of equipment shake down testing in July & August, p arame tric testing in September, and the final long t erm operational testing October through December

.

All t esting was performed according to the test and measurement p lan s jointly developed by GE and
PEC

. The Robinson FSI trial successfully concluded in December 2 008 meeting all technical objectives of the project. Data analysis and reporting followed in January of 2009.



## Results of the **Robinson FSI Demonstration** 

The Robinson FSI d emonstration provided a significant amount of data to better evaluate FSI in long

term operation . The following are highlighted r esults from the Robinson t rial :

**•** SO 2 reduction from 40% to 55% was seen at the target injection Ca/S ratio of 2.5 :1
, performing
better at lower loads and averaging 47% overall

**•** 60%

- 70% SO 2 reduction was achieved with reagent injection rates representing a Ca/S ratio of 3.8 but sorbent efficiency dropped significantly at the higher injection rates and opacity could not be maintained due to the high particulate loading

**•** SO 2 reduction efficienc y decreased with load, performing best at lower loads due to better mixing effects

**•** As designed, ROFA operation improved performance due to the enhanced mixing

**•** Increasing FSI injection air improved performance at the expense of boiler efficiency and opacit y9 **•** Boiler efficiency decreased about 0.1% to 0.8% based on load and the reagent injection rate.

**•** B ackend gas temperatures increase d by approx imately 30° F, primarily due to an increase in
total air and possible reduction in boiler radiant heat transfer

**•** Opaci ty increase d with the increasing flue gas flow rate, dust loading, and air heater outlet
temperature , limiting injection amounts at higher loads

**•** Particulate mass emissions were within permit limits , ranging from 0.05 to 0.12 lb/ mmbtu

**•** No impact on CO & NO X emissions was observed

**•** Incremental mercury removal during FSI operation was about 80% at all unit operating loads

**•** Minimal ash deposition was observed

, validating the benefits of the additional sootblowers and
sonic horns that were installed



## SO2 Reduction

As noted above

, during the trial it was observed that s orbent reduction efficiency decrease d as Ca/S

ratios were increased , requiring a proportionally higher amount of hydrated lime per ton of SO 2 removed. The primary effect was the reduced mixing due to boiler limitations on the total injection air

.

Figure 1.2

– SO 2 reduction as a function of the calcium/sulfur molar ratio

0 10 20 30 40 50 60 70

0 0.5 1 1.5 2 2.5 3 3.5 4SO2 Reduction, %



### Ca/S Ratio

P arallel to the SO 2 reduction observations , sorbent utilization was also found to decrease as molar ratios
were increased. The sorbent utilization was 18.8% at the target Ca/S ratio of 2.5. Th is utilization was lower than expected and greatly increased the s orbent consumption rate and t otal ESP dust loading.10 Figure 1.3

– Sorbent utilization as a function Ca/S molar ratio

10 15 20 25 30 35 40

0 0.5 1 1.5 2 2.5 3Calcium Utilization, %

Ca/S Ratio



## Emissions As expected, opacity and particulate matter emissions increased during FSI operation. This was
attributed to the greatly increased ESP dust loading

, though increased ash resistivity may also have
contributed. This effect was anticipated since FSI increases fly ash mass loading, increases ash resistivity,
and decreases the mean ash particle size. Flue g as temperatures also increased significantly during FSI operation due to the increased ACFM and reduction in boiler radiant heat transfer . Interestingly, this temperature increase provided the strongest correlation to opacity as seen in Figure 1.4.

Figures 1.4 & 1.5

– Opacity as a func tion of outlet temperature & flue gas flow

0 5 10 15 20 25 30 35 40

200 220 240 260 280 300 Air Heater Outlet Temperature, deg. FOpacity, % Baseline

09/29 Vary Sorbent Flow 09/30 Vary Injection Air 10/01 Lower Injection 10/02 Low Load 10/03 ROFA OFF

77 MWg 158 MWg

0 5 10 15 20 25 30 35

1550 1600 1650 1700 1750 1800 Flue Gas Flow Rate, lb/hrOpacity, %

09/15 Clean Air Test

Robinson’s opacity limit is 40%, and the project guideline was to reduce FSI operation when ever opacity exceeded 35%. At certain full load conditions, opacity limited the amount of sorbent that could be11 inject ed into the boiler. Continuous full load injection at the desired Ca/S ratio of 2.5 could not be achieved during the trial until ambient temperatures fell late in the year , correspondingly lowering the flue gas exit temperatures. PM emissions increased b ut remained within permit limits. The range was 0.05 to 0.12 lb/mmbtu.

From the tests it was concluded that a humidification system and or additional ESP enhancements such
as field additions or expansions would be required for FSI to maintain opacity at th e desired Ca/S ratio of

2.5 ac r oss the load range . If SO 2 reduction s higher than 50% are desired, a fabric filter would then be required . The subsequently increased PM emissions may also trigger NSR.


## Fouling and Slagging
During the course of the Robinson trial, furnace deposits were successfully managed through the use of
the unit ’s upgraded sootblower/sonic horn system. While upper furnace deposits were visually observed to increase during FSI operation, the deposits coul d be readily removed . The trial’s final boiler inspection found minim al ash d eposition on superheat er pendants and slight ash deposits i n the air
heaters where the sootblowers could not reach

.



## FSI **Economics**

FSI was primarily attractive for SO 2 control on small units because it was projected to have lower capital

cost s compared to both Dry and Wet S crubbers. The net present costs of FSI were also projected to be much lower even though FSI operation would also require lower sulfur coals and the purchase of
additional SO 2 allowances. Table 1.2 shows the early predictions for FSI compared to the other options.

Table 1.2

– Pre Trial view of FSI compa red with Dry & Wet Scrubbers at Robinson (in 2006 dollars)

FSI Dry Scrubber Wet Scrubber Capital c ost $18.3 M $84.9 M $111.6 M

Net Present Cost (20 y ea r) $76.8 M $115.6 M $132.9 M

SO 2 % r eduction 50% 92.5% 97%

Results from the Robinson FSI trial w ere to then be used to better define the technical performance and operational economics of FSI to provide a more accurate comparison between the two

. The Robinson
FSI demonstration showed that FSI could not be successfully operated long term at the target Ca/S injection levels at full load while maint ain ing opacity limits without further upgrades

. Continuous operation across the load range and a desire to increase the SO 2 reduction above 50% would require the installation of a baghouse

, greatly increasing capital costs. Additionally, the net increase in waste disposal and the consumable costs wer e much higher than originally projected due to the higher Ca/S

ratio required , increasing FSI’s operating costs. Table 1.3 shows the revised cost projections.12 Table 1.3

– Revised FSI comparison with Dry Scrubber s at Robinson (in 2009 dollars)

FSI (Based on Robinson Trial) Dry Scrubber Capital c ost ( with AFUDC ) $51

- $ 83 M ( incl. baghouse) $64.5 M expected $ 95.91

- $ 191.48 M $ 140.93 M expected Net Present Cost (20 y ea r) $147 M $142.4 M

Ca/S molar injection rate 2.5:1 1.4 :1

SO 2 % removal 47% 92.5%

Sorbent u tilization % 18.8% (observed) 64.5%

Sorbent cost / ton SO 2 removed $863 $175

Practical Coal Sulfur Range ≤ 1.6lb/MMBtu ≤ 5lb/MMBtu

Though FSI’s capital cost is still lower than a Dry Scrubber’s, FSI’s consumable cost per ton of SO 2 removed is nearly five times that of a Dry Scrubber’s , negating capital savings in the long term. FSI’s net present cost is now projected to be higher than that of a Dry Scrubber

. Based on the revised predictions using the Robinson trial results, FSI is financially unattractive for SO 2 control when compared to Dry Scrubbers for installations lasting longer than 8 years. Figure 1.6 shows the predicted cumulative costs.

Figure 1.6

– FSI Lifecycle Cost Projections13 

## Conclusion

The Robinson FSI Trial demonstrated that Furnace Sorbent Injection technology is a viabl e method of
moderate SO 2 control and does not present any significant technical or operational limitations to its use

. The d ata gathered from the Robinson trial allowed a more thorough evaluation of FSI capital, operational and overall lifecycle costs.

The i ni tial evaluation of FSI technology was attractive for SO 2 control on small units due to the low projected capital costs and lifecycle costs

. However, the Rob inson demonstration indicated that several plant upgrades would be required for a permanent FSI installation , greatly increasing cost estimates

. Using the revised projections, FSI lifecycle c ost s are now comparable to a Dry Scrubber ’s

. In SC, SO 2 allowan ce costs are also projected to be much lower than FSI operating costs per ton of SO 2 removed.

It should also be noted that to achieve SO 2 reductions near 50%, Furnace Sorbent Injection generally

r equire s lower sulfur coals because of boiler limitations on total sorbent and transport air. This lower sulfur fuel requirement increases fuel costs and would reduce fuel flexibility. Due to the moderate SO 2 reduction amounts, FSI also would require SO 2 allowances to be purchased to comply with emi ssions
limi ts. Alternatively, Dry Scrubber s allow use of typically lower cost, higher sulfur coals and reduce or
eliminate SO 2 allowance purchases. These cost impacts were included in both the intial and final
financial evaluation.

Since the Cape Fear 5 & 6 units are a similar configuration as Robinson ’s

, the conclusions from the
Robinson trial can be applied to C ap e Fear . As for FSI p otential application s to other unit s within PEC,
FSI ’s performance was demonstrated on a tangentially fire d unit

. The mixing effects due to the swirling combustion significantly enhance d SO 2 reduction and the sorbent utilization. While FSI c ould be potentially applied to other boiler types

, such as wall and opposed fired, those units typically exhibit
lower rates of mi xing in the boiler and it can be assumed that the performance of a n FSI system on those units will be lower resulting in even higher SO 2 removal costs per ton.14 

## Recommendation **s**

FSI for SO 2 

## Control at Robinson
Based on the economic analysis, it is recommended that the FSI system at Robinson be prepared for long term storage and that SO 2 allowances be purchased to meet SO 2 regulatory limits within South
Carolina.

Though part of a demonstration project, the FSI equipment at Robinson was designed to allow

convers ion to a permanent installation if desired. From the standpoint of the Robinson FSI Trial’s permitting and project scope, the intent of the FSI system at Robinson was to operate throughout the long

- term trial and then shut down upon trial co nclusion

. A recommendation on the path forward for
SO 2 control at Robinson would then be made based on further evaluation using the results from the
trial. However, based on the trial experience, several additional plant upgrades would also be required

t o place Robinson’s FSI system into permanent service, primarily related to controlling opacity. These upgrades and other FSI recommendation s are outlined in GE’s Final Robinson FSI Project Report. The estimated cost of these upgrades is $10

- $45 million i n additional capital. However, even with the additional plant upgrades in place, FSI operation at Robinson would be burdened with high operating
costs due to the low utilization of the sorbent observed

.

Based on the results of the Robinson FSI demonstrat ion, the average consumable cost per ton of SO 2 removed is presently $8 63 and would increase in the future . The current cost projections for SO 2 allowances in SC are $120 per ton of SO 2 and are projected to decrease in the future . Since the SO 2 allowance costs are projected to be lower than FSI consumable costs, it would be un economical to
operate FSI for SO 2 control at Robinson. If SO 2 allowance prices rise above the consumable costs in the
future , FSI c ould be re

- e valuated to determine if the capital cos t of the plant upgrades required for the permanent operation of FSI at Robinson is then economically justified.


## FSI for SO 2 

## Control within North Carolina

At this time, Furnace Sorbent Injection is not a recommended technology choice for SO 2 co ntrol for
PEC’s units in North Carolina. Analysis of the results from the Robinson FSI demonstration indicates that FSI lifecycle costs are higher than a Dry Scrubber. Additionally at the design Ca/S ratio, the observed SO 2 reduction from FSI alone is li kely not high enough to comply with the NC Clean Smokestacks cap unless
other forms of SO 2 control are also employed.

A potential scenario that could make FSI economically viable in PEC is if a unit was scheduled for
retirement within ten years and PEC was required to install SO 2 control due to point source regulation

.