## Technical Paper



# Burns & McDonnell

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

Carl Weilert , Burns & McDonnell1



### FGD SYSTEMS UTILIZING SINGLE ABSORBER MODULES – THE WAVE OF THE FUTURE FOR NEW UTILITY BOILERS?

Introduction
In the 1990s, FGD retrofitsto coal-fired utility boilers for compliance with Phase 1 and Phase 2 of the Clean Air Act Acid Rain Control Program were in most cases designed and installed without spare absorbers. Many of these 1990s FGD retrofits utilized single absorber modules. Four of these single-absorber FGD systems were built to handle the flue gas from two boilers. This contributed significantly to the reduction in the cost of these systems. During the same period, even though new coal-fired boilers up to 600 MW capacity were being designed and built in the U.S., they generally did not follow the trend to single modules. In the 1990s, no new U.S. electric utility boiler FGD system larger than 80 MW was built with a “single module”. Most even had spare modules. This is likely due to the requirement of the EPA’s new source performance standard (NSPS) for continuous compliance with a 30-day rolling average SO 2 removal, and the provision that stipulates a spare absorber module as a prerequisite to operation during emergency conditions with a malfunctioning FGD system. As many utilities now consider the installation of new coal-fired capacity, the trend toward large single absorbers that developed for “acid rain” FGD retrofits must be reevaluated in terms of the U.S. EPA’s NSPS requirements. This paper addresses the experience record of existing NSPS Subpart Da FGD systems with regard to invocation of the 40 CFR 60.46a(d) “emergency condition” provisions. It reports the results of a survey of operators of Subpart Da FGD systems. It presents an analysis of the reliability of existing single-absorber FGD systems in the U.S. This analysis will lead to a conclusion as to whether the cost of a spare FGD module is worthwhile in today’s utility environment, and what role single-absorber FGD systems are likely to play in the construction of new coal-fired electric utility boilers that are subject to Subpart Da.

Comparative Analysis of FGD Absorber Sparing Practices To assess the effect of the NSPS provisions related to spare modules on the decisions of plant owners and designers to incorporate spare absorbers in the design of FGD systems, a review of the historical record of absorber sparing was conducted. The results of the data analysis are presented graphically at the end of this section.
Data Source Information on the FGD systems serving electric utility boilers in the U.S. is available from the Energy Information Administration’s Form EIA-767, "Steam-Electric Plant Operation and Design Report". This form is used by the U.S. Department of Energy to collect information annually from all U.S. plants with a total steam electric generator nameplate rating of 10 MW or larger. Owners of units with nameplate capacity of 100 MW and above complete the entire form. For smaller units, an abbreviated version of the form is completed. The EIA-767 data can be downloaded from the EIA website at www.eia.doe.gov/cneaf/electricity/page/eia767.html

.2

As of this writing, the data for the calendar year 2000 is the latest available, and it has been used for the analyses presented here. Form EIA-767 includes information that can be used in assessing the design and operating characteristics of any FGD systems at the plant for which the form was completed. Relevant design and operating data for the purposes of this paper include the dates of initial operation for the boiler and the FGD system, the total number of installed FGD equipment trains (modules), the number of modules utilized at full load operation, and the hours during the year that the FGD system was in service. The megawatt rating of the unit(s) served by the FGD system, the hours under load for each boiler, and the U.S. EPA performance standard to which the unit is subject are also available in the database and have been used in the investigation. Categorization of FGD Systems Using the EIA’s database records for Form 767 as filed for the year 2000, it was determined that design information was available for a total of 201 FGD systems in the United States. As shown on Figure 1, a total of 39 FGD systems (19.4%) were identified as serving boilers that are subject to the provisions of the NSPS as codified at 40 CFR 60, Subpart Da. For these 39 systems, the design may have been influenced by the NSPS provisions related to SO 2removal and the sparing of absorber modules. The remaining 80.6 percent, representing 162 FGD systems, are not subject to the NSPS Subpart Da provisions, and are hereinafter termed “non-Da” systems. As described in the Introduction, the decade of the 1990s is significant in the historical development of FGD system designs because the 1990 Clean Air Act Amendments introduced the Acid Rain Control Program. This program regulates annual emissions of sulfur dioxide but does not require compliance with any specific shorter-term SO 2 emission limitation or removal percentage. Consequently, the FGD systems that were retrofit to electric utility boilers for compliance with the acid rain control program did not necessarily require the same level of reliability and redundancy as those subject to the NSPS Subpart Da. Because the acid rain program included a Phase 1 compliance period beginning with the year 1995 and a Phase 2 compliance period beginning with the year 2000, many FGD systems were retrofit to utility boilers in the U.S. during the decade of the 1990s. Figure 2 displays the results of categorization of U.S. FGD systems with respect to where their initial startup date as identified in the EIA-767 database falls with respect to this important decade. A total of 51 electric utility FGD systems started up in the U.S during the 1990s, while 147 systems started up prior to January 1, 1990. A few FGD systems that were identified in the year 2000 EIA-767 database had not yet started up as of the end of 1999, and these are not included in the subsequent analysis. Observed Trends in FGD Absorber Sparing Figures 3 and 4 display the apparent influence of the Subpart Da provisions on the degree of sparing incorporated into the design and operation of FGD systems. The degree of sparing was determined by comparing the data reported in Form EIA-767 as to the total number of modules installed versus the number of modules actually operated at full load. Note from Figure 3 that only 29 percent of the 116 “non-Da” FGD systems that started up prior to 1990 incorporated spare modules at full load operation. By comparison, 78 percent of the 31 “subpart Da” FGD systems starting up during that time have spare modules, as displayed in Figure 4.3 Figure 1 

## Categorization of U.S. FGD Systems By Applicability of NSPS Subpart Da

Non-Da Units 80.6% Subpart Da Units 19.4%

Figure 2 

## Categorization of U.S. FGD Systems By Date of Initial Start-up

1990s 26% Pre-1990 74%4 Figure 3 

## FGD Systems on Non-Da Units With Start-ups Before 1990

Spare Module 29%

Single Module 12% More Than Three Modules 24%

Three Modules 11% No Spare Module 71% Two Modules 24%

Figure 4 

## FGD Systems on Subpart Da Units With Start-ups Before 1990

More Than Three Modules 6%

Three Modules 10% No Spare Module 22% Spare Module 78%

Two Modules 3% Single Module 3%5

It is also noteworthy that the concept of a “single module” FGD system is certainly not new. There are 15 electric utility FGD systems in the U.S. that started up prior to 1990 and have single modules. Of the 116 “non-Da” systems shown in Figure 3, a total of 14 (12%) were built with only one module. By contrast, only one of the 31 subpart Da FGD systems started up prior to 1990 was constructed with a single module. This lone example is Stanton Unit 10, which is a 60 MW equivalent boiler unit equipped with a dry FGD system. The unit at Stanton has the distinction of being the first unit subject to 40 CFR 60 Subpart Da to be started up in the U.S. It started up in June 1982. Thirty more units subject to subpart Da were started up prior to January 1, 1990, but none of these were equipped with single-module FGD systems. The data comparison presented on Figures 3 and 4 indicates that FGD systems on boiler units subject to Subpart Da predominantly are operated with spare modules, whereas non-Da FGD systems predominantly are operated at full load without spares. To determine if this trend changed as FGD technology developed, a similar comparison was made for the group of U.S. FGD systems installed in the 1990s. This comparison is shown on Figures 5 and 6.By comparing the data as presented on Figure 3 and Figure 5, it can bee seen that the newer nonDa FGD systems show an increasing acceptance of the design practice in which no spare absorber module is provided. Furthermore, as shown in Figure 5, the international trend toward use of the “single absorber module” design for FGD systems has caught on for non-Da FGD systems in the U.S. Out of 43 non-Da FGD systems started up at electric utility plants in the U.S. during the 1990s, 19 systems (44%) have been designed as single-module systems. Although not shown on the chart, four of these FGD systems (at Bailly [Units 7 and 8], Culley [Units 2 and 3], Niles [Units 1 and 2] and Big Bend [Units 1 and 2]) have been designed and operated in the 1990s to treat the flue gas from two boilers in a single absorber module.
Did new coal-fired boilers installed in the U.S. in the 1990s demonstrate the same trend toward fewer spare modules and the use of single absorber modules? By comparing the data as presented on Figure 4 and Figure 6, it can bee seen that the newer subpart Da FGD systems do not show a significant trend toward acceptance of the “no spare module” design concept. Six of the eight FGD systems installed in the 1990s on new electric utility boilers subject to 40 CFR 60 Subpart Da included spare absorber modules in the design and operation of the system. Only one unit was installed with a single absorber module. This lone example is Neil Simpson 2, Unit 2, which is an 80 MW boiler unit equipped with a dry FGD system. The data presented on Figures 5 and 6 show basically the same situation as shown on Figures 3 and 4. That is, even for FGD systems installed in the 1990s, the systems on boiler units subject to Subpart Da predominantly were constructed with and are operated with spare modules, whereas the non-Da FGD systems predominantly are operated at full load without spares. What is the reason for this? And what does this mean for utilities planning new coal-fired capacity in the 21 st century? In the next section the requirements of 40 CFR 60 Subpart Da will be analyzed in an attempt to find the answers.6 Figure 5 

## FGD Systems on Non-Da Units With Start-ups in the 1990s

Two Modules 23% Three Modules 19%

Single Module 44% Spare Module 14% No Spare Module 86%

Figure 6 

## FGD Systems on Subpart Da Units With Start-ups in the 1990s

Spare Module 75% No Spare

Module 25% Single Module (1 Unit) Two Modules (1 Unit)7

Requirements of 40 CFR 60 Subpart Da The “Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978” are codified as Subpart Da of Part 60 of Title 40 of the Code of Federal Regulations (40 CFR 60, Subpart Da). These standards are applicable to fossil fuel fired electric utility steam generating units that are capable of a heat input of more than 250 million Btu per hour. As defined in the NSPS, the term electric utility steam generating unit means “any steam electric generating unit that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW electrical output to any utility power distribution system for sale”. The provisions of this standard would apply to any new coal-fired electric utility boilers being designed today. Emission Limitations and Percentage Reduction For design and operation of FGD systems on coal-fired boilers, the relevant emission limitation in Subpart Da is found at § 60.43a (Standard for sulfur dioxide). Units combusting solid fossil fuels must achieve:

1. An SO 2 emission limitation of 1.2 lbs/million Btu heat input and a 90 percent minimum reduction in the “potential combustion concentration”, or
2. A 70 percent minimum reduction in the “potential combustion concentration” when SO 2 emissions are less than 0.60 lb/million The requirement for a reduction in the “potential combustion concentration” of SO 2effectively means that a continuous system of SO 2emission reduction (such as an FGD system) must be installed and operated for all boiler units subject to Subpart Da. For coals with a “potential combustion concentration” for SO 2between 2.0 lbs/million Btu and 6.0 lbs/million Btu, the NSPS results in an emission limit of 0.6 lb/million Btu and a percentage reduction requirement ranging between 70 and 90 percent. The most stringent of either the emission limitation or the percentage reduction requirement will dictate the emission control requirement in each case. For example, if 90 percent reduction would result in emissions exceeding 1.2 lbs/million Btu, the reduction percentage must be increased until the emission limit is met. Or, if meeting the 0.6 lb/million Btu limit would require less than 70 percent reduction, the 70 percent reduction requirement applies. Requirements for Continuous Operation Compliance with the emission limitation and the percent reduction requirements are determined on a 30-day rolling average basis, using continuous emission monitoring systems. Compliance with the percentage reduction requirement is based on the average inlet and average outlet SO 2 emission rates for 30 successive days. This effectively requires nearly continuous operation of the FGD system, because the NSPS Subpart Da compliance provisions for SO 2 do not allow exemptions for periods of malfunction.8

For example, a Subpart Da unit firing a coal with an uncontrolled SO 2emission potential of 6.0 lbs/million Btu will require 90 percent SO 2removal on a 30-day rolling average basis to comply with the Subpart Da requirement. Assume that the average SO 2reduction for the previous 29 days has been 91 percent. Then, an incident which causes the FGD system removal efficiency to drop to zero during the 30th day must persist no longer than 7.9 hours, or else the unit will be out of compliance for the 30-day period that ends at midnight that day. Because the 30-day averaging provision provides so little leeway for complete cessation of the ability to remove SO 2 , many owners and designers of FGD systems on units subject to Subpart Da have included spare absorber modules, or at least multiple absorber modules, in the design process. The NSPS does not explicitly require a spare module under normal operation, but the stringency of the standard, as illustrated in the example cited above, makes provisions for sparing, or at least redundancy, advisable. The NSPS provisions effectively prevent the operator from bypassing a malfunctioning FGD system absorber for repairs unless the system can continue to stay in compliance continuously while the repairs are underway. An FGD system with multiple modules may be less likely to encounter problems with achieving continuous compliance with the 30-day rolling averages for percent reduction and emissions. This is likely the reason behind the observed difference in FGD absorber sparing practices between those FGD systems on units subject to Subpart Da and those on units not subject to the Da standard. Operation During Emergency Conditions There is one other provision in the Subpart Da NSPS that could have caused plant owners to specify the installation of a spare absorber module for their FGD systems. As noted above, the compliance requirements for emission limitation and removal efficiency for SO 2do not exempt periods of malfunction. However, they do exempt certain qualifying operations under “emergency conditions”. Subpart Da § 60.46a(c) states:
T he sulfur dioxide emission standards under § 60.43a apply at all times except during periods of startup, shutdown, or when both emergency conditions exist and the procedures under paragraph (d) of this section are implemented. The procedures cited in the referenced paragraph (d) include “designing, constructing, and operating a spare flue gas desulfurization system module for an affected facility larger than...(approximately 125 MW electrical output capacity).”. Although this provision also stops short of requiringall FGD systems to install a spare absorber module, it makes it clear that the owner of any electric generating unit subject to Subpart Da who wishes to continue to operate a unit with a malfunctioning FGD system during “emergency conditions” must first have installed such a spare module.9

Survey Regarding Invocation of the “Emergency Condition” Provision The authors’ reading of the definition of “emergency conditions” in Subpart Da at § 60.41a leads us to believe that it would be extremely rare for such conditions to occur. The list of requirements for any given time period to qualify as an emergency condition is extensive, and the steps required of the plant owner to seek alternative sources of electric power are rigorous. Furthermore, the emergency conditions would need to coincide with a malfunction of the FGD system in order for the clause to come into play. However, in order to determine if the installation of a spare absorber module would be warranted to allow unit operation during such conditions, we performed a survey of plants with Subpart Da units to determine the extent to which the emergency condition clause has been invoked in the past. Survey Procedure The survey was conducted by telephone and e-mail and was informal in nature. The representative of each plant to whom the questions about FGD system operation should be directed was identified by starting with the contact person named in the EIA-767 database for each plant. The survey was conducted solely for the purpose of obtaining information relevant to the preparation of this paper. Questions asked in the survey included the following:
1. Has the unit ever operated under the emergency condition as defined in Subpart Da? 2. If so, was the provision allowing bypass of a malfunctioning FGD absorber module used?
Due to the informal nature of the survey, and to provide additional information relevant to the topic of this paper, supplemental questions were posed in those cases in which the initial inquiry elicited a response. The purpose of the supplemental questions was to obtain the opinion of the utility representative regarding the following topics:

• Would a spare absorber module be considered if a new unit were being built today?

• Is the “emergency condition” clause sufficient reason to include a spare module?, and

• Should a “single module” FGD system design be considered for a new unit?
“Emergency Condition” Survey Results The survey generated responses from approximately 25 percent of all Subpart Da electric utility steam generating units. Of the nine subpart Da FGD systems represented by the responses, only one acknowledged ever having invoked the “emergency conditions” provision of Subpart Da. In that case, the respondent indicated that the provision of the regulation allowing bypass of a malfunctioning absorber module was never implemented. (Note that not all malfunctions of an FGD system are caused by the absorber modules). The survey results generally confirmed the authors’ belief that qualification for the “emergency condition” exemption from the SO 2 control requirements of Subpart Da is extremely rare. The composite operating history of the units covered by the survey responses exceeds 120 years, yet only a few instances at a single unit were found to have qualified as emergency conditions. The10

emergency condition clause of the NSPS does not appear to be a valid reason for inclusion of a spare absorber module in the design of an FGD system. Results of Informal Opinion Poll on Module Sparing All of the survey respondents provided feedback in the form of their opinion on the three supplemental questions dealing with how they would like to see the FGD system configured for a new unit if they were building one today. The opinions of the respondents (most of whom have been associated with the operation of an FGD systems equipped with spare modules) are summarized in Table 1:
Table 1 Results of Opinion Survey of Operators of Subpart Da FGD Systems
Question Responses and Number of Respondents Definitely would install a spare module Would

consider a spare module, but unsure if one would be installed Would install

multiple modules, but not a spare Definitely

would not install a spare module Would a spare module be considered for the FGD system on a new unit?

4 2 1 2 Is the Emergency Condition clause in Subpart Da reason enough for having a spare FGD module? No Yes Not Sure

7 1 1 No Yes Not Sure Should a “single module” FGD system design be considered for a new unit? 6 1 2 It is interesting to note that those people in the U.S. with the most direct experience dealing with compliance with the provisions of Subpart Da on a day-to-day basis generally see merit in providing spare capacity in the design of an FGD system to be used for that purpose. Most of the survey respondents credited their spare modules with avoiding load reductions, increasing unit capacity factor, and preventing forced outages. This spare capacity need not include a full standby spare module, however. Table 1 shows that the survey respondents do not believe a standby spare (stipulated by Subpart Da as the prerequisite to unit operation under emergency conditions during periods of FGD malfunction) is warranted. They were generally in favor of spare capacity but not in favor of single modules. Multiple modules could provide adequate spare capacity. Several of the survey respondents indicated that provision of spare spray levels or oversizing of the modules (e.g., two 65 percent capacity modules) should be adequate to overcome most problems they have encountered in the operation of their Subpart Da FGD systems.11

Analysis of Reliability Data for Single-Module FGD Systems As described in the analysis of the module sparing information from the EIA-767 data, there is no experience base in the U.S. with regard to single-module FGD systems on large units subject to Subpart Da. We must rely on data from non-Da single-module FGD systems to assess whether the reliability of such a configuration is adequate to comply with the NSPS Subpart Da requirements. The EIA-767 database provides some information that can be used for this purpose. Table 2 displays the results of such a comparison, using the latest available data. FGD system reliability is defined as the hours the FGD system operated divided by the hours the boiler was under load. For the systems serving two boilers, the boiler with the highest number of hours under load was used for the denominator in the calculation.

Table 2 Reliability Data for U.S. Single-Module FGD Systems With Start-up in the 1990s

(Data is For Calendar Year 2000 Except as Noted)

Plant Name Unit(s) Served By FGDFGD

Hours In Service Boiler

Hours Under Load Boiler

Hours Under Load FGD

System Reliability (Percent)

AES CAYUGA 1 8518 8494 100 AES CAYUGA 2 8294 8270 100 B L ENGLAND (1999 data) 3 6392 6392 100 BAILLY 7 & 8 8784 7525 7559 116 BIG BEND 1 & 2 6808 7632 8199 83 F B CULLEY 2 & 3 8328 8258 8119 101 HARRISON 1 6506 6506 100 HARRISON 2 7559 7559 100 HARRISON 3 7933 7933 100 HMP&L STATION 2 1 8280 8280 100 HMP&L STATION 2 2 7569 7593 100 NEIL SIMPSON 2 2 8491 8382 101 NILES 1 & 2 7054 6861 6045 103 PETERSBURG 1 8511 8511 100 PETERSBURG 2 7430 7430 100 PORT WASHINGTON 4 6843 6843 100 PORT WASHINGTON 1 6551 6551 100 YATES 1 8109 8109 10012

As shown in Table 2, every single-module FGD system except one achieved 100 percent reliability. It should be noted that the Big Bend 1 & 2 FGD system began operation in December 1999, so the period represented in Table 2 is its first year of operation. With the exception of Neil Simpson 2, Unit 2, the FGD systems listed in Table 2 are not subject to Subpart Da, and thus they do not need to continuously meet a 30-day rolling average SO 2 removal efficiency. The analysis cannot tell us if these systems would have remained in compliance with Subpart Da continuously had they been subject to it. However, the data available does tell us that it is possible to keep single-module FGD absorbers operating continuously during a calendar year. Experience from outside the U.S. also indicates that single-module FGD systems can be extremely reliable. For example, the FGD system at New Brunswick Power’s Dalhousie Station, which serves two Orimulsion®-fired boiler units totaling 315 MW, has operated for seven years without a forced outage.

Conclusions and Recommendations
Conclusions Based on our assessment of the “state of the art” and the data and analyses presented in this paper, the following conclusions can be drawn:

• The inclusion of a standby spare module in the design of an FGD system for the purpose of qualifying to operate the boiler unit during emergency conditions while the FGD system is malfunctioning is not warranted.

• Historically, there is no experience with FGD systems utilizing single modules to comply with the provisions of 40 CFR 60 Subpart Da on large utility boilers.

• Even a short interruption in the ability of an FGD system to remove SO 2from the flue gas can result in the potential for violation of the 30-day rolling average compliance provisions of Subpart Da.

• The available data indicates that single-module FGD systems can be extremely reliable.
Recommendations Are single-module FGD systems the wave of the future for new utility boilers in the U.S.? We believe there will definitely be some single-module FGD systems included in the round of new coal-fired utility boilers that are now in the planning stage. The answer may depend on the willingness of the plant owners to accept the consequences of non-compliance with the NSPS, which means shutting down the unit in the event of any significant FGD malfunction. To minimize the chance that will happen, the following design and operating practices are recommended for any single-module FGD system:

• Include spare spray pumps and spare spray levels in the absorber design.

• Design and operate the system to provide a margin of safety above the Subpart Da requirements. * * * * *