E n te rg y Services, ine** on b e h a lf o f E n te rg y A rkan sas? Ine*
W h ite B luff Steam Electric Station
Redfield, Arkansas (AFIN 3 5 -0 0 1 1 0 )
Updated BART Five-Factor Analysis for SO2 for Units 1 and 2
Submitted to:
Arkansas Department of Environmental Quality (A D EQ ) Office of Air Quality
5301 Northshore Drive North Little Rock, AR 72118-5317
Prepared by:
TRINITY CONSULTANTS 5801 E. 41st St., Suite 450
Tulsa, OK 74135 (918)622-7111
August 18, 2017
Trinity Project 173702.0014
72 NDCA
EHSsolutions delivered uncommonly well
Tiers 8&9
ED 002061 00163091-00001
TABLE OF CONTENTS
1 EXECUTIVE SUMMARY
1-1
1.1 Report Updates.....................................................................................................................................................1-1
1.2 Summary of Updated BART Five Factor Analysis..................................................................................... 1-2
2 INTRODUCTION AND BACKGROUND
2-1
3 EXISTING EMISSIONS ANDBASELINE VISIBILITY IMPAIRMENT
3-1
3.1 Baseline Emission Rates.................................................................................................................................... 3-1
3.2 Baseline Visibility Impairment.......................................................................................................................3-2
4 S02 BART EVALUATION
4-1
4.1 Identification of Available Retrofit S02Control Technologies for Unit 1 and Unit 2 .................. 4-1
4.2 Eliminate Technically Infeasible S02Control Technologies for Unit 1 and Unit 2...................... 4-1
4.2.1 Fuel Switching - Low-Sulfur Coal............................................................................................................................ 4-1
4.2.2 Dry Sorbent Injection....................................................................................................................................................4-1
4.2.3 Dry /Semi-Dry Flue Gas Desulfurization..............................................................................................................4-2
4.2.4 Wet Flue Gas Desulfurization.................................................................................................................................... 4-3
4.3 Rank of Technically Feasible S02Control Options by Effectiveness for Unit 1 and Unit 2 .......4-3
4.4 Evaluation of Impacts for Feasible S02Controls for Unit 1 and Unit 2 ............................................4-3
4.4.1 Remaining Useful Life...................................................................................................................................................4-4
4.4.2 Cost of Compliance.........................................................................................................................................................4-4
4.4.3 Energy Impacts and Non-Air Quality Impacts....................................................................................................4-6
4.5 Evaluation of Visibility Impact of Feasible S02Controls for Unit 1 and Unit 2 ............................. 4-6
4.6 BART for S02for Unit 1 and Unit 2 .................................................................................................................4-8
APPENDIX A. CONTROL COST INFORMATION
A -1
APPENDIX B. BASELINE VISIBILITY IMPAIRMENT BY POLLUTANT
B-1
APPENDIX C. REFINED PM SPEGIATION CALCULATIONS
C-1
Entergy Arkansas,. Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analyses I Trinity Consultants
i
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00002
LIST OF TABLES
Table 3-1. Baseline Maximum 24-hour Emission Rates (As Hourly Equivalents)
3-2
Table 3-2. Baseline Visibility Impairment
3-2
Table 4-1. Available SO2 Control Technologies for Unit 1 and Unit 2
4-1
Table 4-2. Control Effectiveness of Technically Feasible SO2 Control Technologies
4-3
Table 4-3. Summary of SO2 Controls Cost Effectiveness for Unit 1 and Unit 2 Based on Actual Costs
4-5
Table 4-4. Summary of SO2 Controls Cost Effectiveness for Unit 1 and Unit 2 Based on Costs Adjusted
for EPA-Exclusions for Illustration Purposes
4-5
Table 4-5. Emission Rates Modeled to Reflect S02Controls for Unit 1 and Unit 2
4-7
Table 4-6. Summary of CALPUFF-Modeled Visibility Impacts from SO2 Controls for Unit 1
(Across All Modeled Years, 2001-2003)
4-7
Table 4-7. Summary of CALPUFF-Modeled Visibility Impacts from SO2 Controls for Unit 2
(Across All Modeled Years, 2001-2003)
4-8
Table B -l. Baseline Visibility Impairment Attributable to Unit 1 by Pollutant
B-l
Table B-2. Baseline Visibility Impairment Attributable to Unit 2 by Pollutant
B-2
Entergy Arkansas, Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analyses I Trinity Consultants
ii
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00003
1 EXECUTIVE SUMMARY
This report provides an update to the Best Available Retrofit Technology (BART) Five Factor Analysis for sulfur dioxide (SO2) for Unit 1 (SN-01) and Unit 2 (SN-02) at Entergy Arkansas, Inc.'s (EAl's) White Bluff Steam Electric Station (White Bluff) as well as revising the S02BART conclusion. EAI submitted the original BART Five Factor Analysis to the Arkansas Department of Environmental Quality (ADEQ) on February 21, 2013, with revisions on June 10, 2013 and October 15, 2013.
> Unit 1 (SN-01) is a primary boiler with a maximum net power rating of 850 megawatts (MW) and a nominal heat input capacity of 8,950 million British thermal units per hour (MMBtu/hr). The boiler burns sub bituminous or bituminous coal1as the primary fuel and No. 2 fuel oil or biofuel as a start-up fuel, and it is currently equipped with an electrostatic precipitator (ESP) for particulate matter (PM) control.
> Unit 2 (SN-02) is identical in design to Unit 1. It is a primary boiler with a maximum net power rating of 850 MW and a nominal heat input capacity of 8,950 MMBtu/hr. The boiler burns sub-bituminous or bituminous coal2as the primary fuel and No. 2 fuel oil or biofuel as a start-up fuel, and it is currently equipped with an ESP for PM control.
Specific updates incorporated in this version of the report are outlined below.
1.1 REPORT UPDATES This report includes the following updates to the previous SO2 Five Factor Analysis for White Bluff Units 1 and 2:
1. Updating the baseline period to 2009-2013.
2. Incorporating new information regarding the remaining useful life (RUL) of the units.
3. Incorporating a new control scenario representing combustion of only low-sulfur coal (LSC).
4. Incorporating additional information (i.e., cost information and modeling results) related to control options involving Dry Sorbent Injection (DSI).
5. Updating all modeling to reflect the newest methodologies for dividing ("speciating") particulate matter (PM or PM10)3 emissions into its constituents.
6. Updating the S02BART conclusion in consideration of the new information and updates listed above.
1The coal-fired units at White Bluff primarily burn sub-bituminous coal, but are permitted to burn bituminous or sub bituminous coal. Only sub-bituminous coals were burned during the baseline periods evaluated in this analysis.
2 Ibid.
3All PM represented in this report is assumed to have a mass mean diameter smaller than ten microns.
Entergy Arkansas, Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analyses I Trinity Consultants
1 -1
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00004
1.2 SUMMARY OF UPDATED BART FIVE FACTOR ANALYSIS
Trinity conducted the below five-step analysis based on EPA's BART Guidelines4in 40 CFR Part 51 and other EPA guidance5to evaluate SO2 BART for Units 1 and 2:
1. Identifying all available retrofit control technologies; 2. Eliminating technically infeasible control technologies; 3. Evaluating the control effectiveness of remaining control technologies; 4. Evaluating impacts and documenting the results; and 5. Evaluating visibility impacts.
The updated BART Five Factor Analysis concludes that combustion of LSC constitutes BART for Unit 1 and Unit 2 in light of the updated RUL. The proposed BART emission rate for S02is 0.6 pounds per MMBtu (lb/MMBtu) on a rolling 30-day average.
4The BART guidelines were published as amendments to EPA's Regional Haze Rule (RHR) at 40 CFR 51.308 on July 6, 2005. 5April 26, 2012, letter from Mr. Guy Donaldson, EPA Region VI, to Mr. Anthony Davis, ADEQ.
Entergy Arkansas,. Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analysis I Trinity Consultants
1-2
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00005
2 INTRODUCTION AND BACKGROUND
In the 1977 amendments to the Clean Air Act (CAA), Congress set a national goal to restore national parks and wilderness areas to pristine conditions by preventing any future, and remedying any existing, man-made visibility impairment. On July 1,1999, the U.S. EPA published the final Regional Haze Rule (RHR). The objective of the RHR is to restore visibility to pristine conditions in 156 specific areas across the United States known as Class I areas. The CAA defines Class I areas as certain national parks (larger than 6,000 acres), wilderness areas (larger than 5,000 acres), national memorial parks (larger than 5,000 acres), and international parks that were in existence on August 7,1977.
The RHR requires States to set goals that provide for reasonable progress towards achieving natural visibility conditions for each Class I area in their state. On July 6, 2005, the EPA published amendments to its 1999 RHR, often called the Best Available Retrofit Technology (BART) rule, which included guidance for making sourcespecific BART determinations. The BART rule defines BART-eligible sources as sources that meet the following criteria:
(1) Have potential emissions of at least 250 tons per year of a visibility-impairing pollutant, (2) Began operation between August 7,1962, and August 7,1977, and (3) Are included as one of the 26 listed source categories in the guidance.
A BART-eligible source is subject to BART if the source is "reasonably anticipated to cause or contribute to visibility impairment in any federal mandatory Class I area." For the purpose of determining which sources are subject to BART, a 1.0 Adv change or more from an individual source is considered to "cause" visibility impairment, and a change of 0.5 Adv is considered to "contribute" to impairment, which therefore establishes 0.5 Adv as a numerical screening threshold for subject-to-BART determinations.6 According to the BART guidelines, the CALPUFF modeling system (CALPUFF) or any other appropriate dispersion model can be used to predict the visibility impacts.7The model-predicted visibility impact, specifically when using CALPUFF the 98th percentile impact measured against natural background (and not the maximum impact), is compared to the 0.5 Adv threshold to determine if the source is anticipated to cause or contribute to the visibility impairment8
Once it is determined that a source is subject to BART, a BART determination must address air pollution control measures for the source. The visibility regulations define BART as follows:
...an emission limitation based on the degree o f reduction achievable through the application o f the best system of continuous emission reduction for each pollutant which is emitted by...[a BARTeligible source]. The emission limitation must be established on a case-by-case basis, taking into consideration the technology available, the cost of compliance, the energy and non-air quality
6"Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations; Final Rule," 70 Fed. Reg. 39,116-18 (July 6, 2005).
7Trinity and EA1 assert that CALPUFF is not the most appropriate model for estimating visibility impacts. Due to its numerous inherent limitations (e.g., limited chemistry mechanism, distance limitations, blanket background ammonia values, etc.), CALPUFF does not yield reliable results. Furthermore, CALPUFF is no longer an EPA-preferred model, which further indicates CALPUFF's unreliability. More advanced models like the Comprehensive Air Quality Model with Extensions (CAMx)--if processed appropriately--can yield more reliable characterizations of visibility impairment. Nevertheless (without waiver), CALPUFF modeling will continue to be presented in this report for consistency with past submittals.
Id. a t 39,163.
Entergy Arkansas, Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analysis 1 Trinity Consultants
2-1
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00006
environmental impacts of compliance, any pollution control equipment in use or in existence at the source, the remaining useful life of the source, and the degree of improvement in visibility which may reasonably be anticipated to resultfrom the use o fsuch technology.
The BART Guidelines state that a BART determination should address the following five statutory factors:
1. Existing controls; 2. Cost of controls; 3. Energy and non-air quality environmental impacts; 4. Remaining useful life of the source; and 5. Degree of visibility improvement as a result of controls.
Further, the BART Guidelines indicate that the five basic steps in a BART analysis can be summarized as follows:
1. Identify all available retrofit control technologies; 2. Eliminate technically infeasible control technologies; 3. Evaluate the control effectiveness of remaining control technologies; 4. Evaluate impacts and document the results; and 5. Evaluate visibility impacts.
As described in the above-referenced, previous submittals, the boilers at White Bluff meet the three BARTeligibility criteria, and the existing visibility impairment is modeled at greater than 0.5 Adv in at least one Class 1 area. Thus, the White Bluff units are subject to BART.
Entergy Arkansas, Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analysis I Trinity Consultants
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00007
3 EXISTING EMISSIONS AND BASELINE VISIB ILITY IMPAIRMENT
Five Factor Analyses require the determination of unit-specific baseline visibility impairment values to which any post-control scenarios can be compared. The unit-specific baseline modeling analyses are built upon, but are distinguished from, the baseline (a.k.a., "screening") modeling for the collection of BART eligible units at each source that is completed to determine if a BART eligible source is subject to BART. EAI is not updating the subject-to-BART determination at this time.
This section summarizes the baseline visibility impairment attributable to each ofWhite Bluffs units based on CALPUFF air quality modeling conducted by Trinity.9 Trinity conducted the modeling using the same protocol, methodologies, and inputs (except where specifically updated as described in this report) as presented in the October 15, 2013 submittal. The protocol and details method descriptions are not included with this report because nothing has changed and the CALMET dataset developed per the protocol has been used - and approved by EPA - numerous times since its development
While this report updates the BART Five Factor Analysis for S02emissions specifically, BART modeling must consider emissions of all visibility-affecting pollutants (VAP), including S02, oxides of nitrogen (NOx), and speciated particulate matter, including filterable coarse particulate matter (PMc), filterable fine particulate matter (PMf), elemental carbon (EC), inorganic condensable particulate matter (10R CPM) as sulfates (SO4), and organic condensable particulate matter (OR CPM), also referred to as secondary organic aerosols (SOA).
3,1 BASELINE EMISSION RATES
The updated modeled NOx and S02emission rates for Unit 1 and Unit 2 are the highest actual 24-hour emission rates based on Clean Air Markets Database (CAMD) data from 2009-2013.10The updated modeled PM10 emission rates for Unit 1 and Unit 2 are based on emission factors from AP-42 for filterable PM10 and condensable PM (with a 99.5 percent control efficiency for ESP applied to the PM10 filterable fraction) used in conjunction with the average 2009-2013 coal heating value and ash content (as a percentage of mass).11 Emission rates for specific PM10 species were calculated using the monitored filterable PM rate and the National Park Service (NPS) "speciation spreadsheet" for Dry Bottom Boiler Burning Pulverized Coal using only ESP12 except for SO4, which was calculated using an Electric Power Research Institute (EPRI) methodology that considers the S02to SO4 conversion rate and SO4 reduction factors for various downstream equipment.13Table 3-1 summarizes the emission rates that were modeled for S02, NOx, and PM10, including the speciated PM10 emissions.
9See footnote 7, above.
10The use of this baseline is a conservative approach. EAI would be justified in using a more recent baseline with lower emissions that would result in higher cost effectiveness values.
11AP-42, Chapter 1 External Combustion Sources, Section 1.1 Bituminous and Subbituminous Coal Combustion, Table 1.1-5, page 1.1-24 (September 1998).
12The baseline speciation is based on the NPS Workbook for a Dry Bottom Boiler burning Pulverized Coal using an ESP. Based on average 2009-2013 values, the following inputvalues were used: heating value of 8,587 Btu/lb, 0.27% sulfur, 4.96% ash, 8,950 MMBtu/hr heat input, and a baseline total PM10 emission rate of 119.2 lb/hr at both White Bluff Unit 1 and Unit 2. NPS: http://www.nature.nps.gov/air/Permits/ect/index.cfm.
13Electric Power Research Institute (EPRI) Estimating Total Sulfuric Acid Emissions from Stationary Power Plants: EPRI, Technical Update, Palo Alto, CA: March 2012.1023790.
Entergy Arkansas, Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analysis I Trinity Consultants 3-1
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00008
Table 3-1, Baseline Maximum 24~hoiir Emission Rates (As Hourly Equivalents)
Unit SN-01 SN-02
S02 (Ib/hr) 6,771.9 6,622.3
NOx (lb/hr) 3,355.4 3,590.5
Total PM10 (lb/hr) 119.2 119.2
S04 (lb/hr)
5.1 5.0
PMc (lb/hr)
40.4 40.4
PMf (lb/hr)
31.1 31.1
SOA (lb/hr)
9.3 9.3
EC (lb/hr)
1.2 1.2
3,2 BASELINE VISIBILITY IMPAIRMENT
Trinity conducted modeling to estimate the current visibility impairment attributable to Unit 1 and Unit 2 in four Class I Areas: Caney Creek Wilderness (CACR), Upper Buffalo Wilderness (UPBU), Hercules Glades Wilderness (HERC), and Mingo Wilderness (MING) using the CALPUFF dispersion model.14Table 3-2 provides a summary of the modeled visibility impairment attributable to Unit 1 and Unit 2 based on the emission rates shown in Table 3-1. This table shows the 98thpercentile impacts in Adv and the number of days with impacts greater than 0.5 Adv.
Table13-2, Baseline Visibility Impairment:
CACR
UPBU
HERC
MING
Unit
Year A
98th Percentile
No. of Days with
98th Percentile
No. of Days with
98th Percentile
No. of Days with
98th Percentile
No. of Days with
(Adv) Adv > 0.5 (Adv) Adv > 0.5 (Adv) Adv > 0.5 (Adv) Adv > 0.5
2001 1.505
38
1.051
30
0.925
24
0.802
16
SN-01 2002 1.306
29
0.742
15
0.567
10
0.708
21
2003 1.053
32
1.033
24
0.704
15
0.666
14
2001 1.533
39
1.059
30
0.912
25
0.819
15
SN-02 2002 1.322
29
0.739
16
0.568
11
0.719
20
2003 1.059
32
1.03
25
0.72
16
0.678
14
AMeteorological data year modeled.
14Due to an EPA-requested change in meteorological data (to a refined, or "NO OBS = 0", dataset), which excluded the Sipsey Class 1 Area from the modeling domain, Sipsey was not included in this analysis. See also footnote 7 above.
Entergy Arkansas,. Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analyses I Trinity Consultants
3-2
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00009
4 $ 0 2 BART EVALUATION
4 1 IDENTIFICATION OF AVAILABLE RETROFIT S 0 2 CONTROL TECHNOLOGIES FOR UNIT 1 AND UNIT 2
The boilers burn primarily coal. Sulfur oxides, SOx, are generated during coal combustion from the oxidation of sulfur contained in the fuel. SOx emissions are almost entirely dependent on the sulfur content of the fuel and are generally not affected by boiler size or burner design. S0Xemissions from conventional combustion systems are predominantly in the form of S02. Since S02is the predominant sulfur compound emitted from Unit 1 and Unit 2, the BART analysis is specific to emissions of S02. Reductions in emissions of S02are expected to reduce visibility impairment by reducing sulfate (SO4) formation.
Step 1 of the top-down control review is to identify available retrofit control options for S02. The available S02 retrofit control technologies for Unit 1 and Unit 2 are summarized in Table 4-1.
Table 4-1. Available S02Control Technologies for Unit 1 and Unit 2
______________________________ SO2 Control Technologies______________________________ Fuel Switching - Low-Sulfur Coal (LSC) Dry Sorbent Injection (DSI)
Dry / Semi-Dry Flue Gas Desulfurization (DFGD), e.g., Spray Dryer Absorber (SDA) Wet Scrubbing, i.e., Wet Flue Gas Desulfurization (WFGD)
4 ,2 ELIMINATE TECHNICALLY INFEASIBLE S 0 2 CONTROL TECHNOLOGIES FOR UNIT 1 AND UNIT 2
Step 2 of the BART determination is to eliminate technically infeasible S02control technologies that were identified in Step 1.
4.2.1 Fuel Switching - Low-Sulfur Coal With an achievable emission level of 0.6 lb/MMBtu, switching to LSC can reduce S02emissions by approximately 8.75 percent compared to baseline levels.15
4.2.2 Dry Sorbent Injection DSI involves the injection of a sorbent (e.g., Trona) into the exhaust gas stream where acid gases such as hydrogen chloride (HC1) and S02react with and become entrained in the sorbent The stream then passes through a particulate control device to remove the sorbent along with the entrained S02. The process was developed as a lower cost FGD option because the mixing of the S02and sorbent occurs directly in the exhaust gas stream rather than in a separate vessel. Sorbent injection control efficiency depends on residence time, gas stream temperature, and limitations of the particulate control device.
15Calculated based on a comparison of the maximum 30 boiler operating day SO2 emission rate during the baseline period to the proposed limit for low-sulfur coal of 0.6 lb/MMBtu.
Entergy Arkansas, Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analyses I Trinity Consultants
4-1
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00010
DSI is a technically feasible yet seldom used technology for moderate to high removal of SO2 from coal-fired power plants, with limited full-scale installations for SO2 control. A significant amount of testing of DSI for SO2 control has been performed in recent years. This testing has shown that a wide range of performance is achievable (up to 80 or 90 percent SO2 reduction in some cases). However, this testing has also shown that there are many factors that can impact the performance of these reagents, including particle size (milling), residence time, temperature, and the particulate collection equipment. The primary lesson learned through this testing is that each unit is unique, with various factors that can impact the achievable performance or required reagent feed rate. Different performance has even been seen on sister units. Therefore, it is critical to perform a demonstration or Proof of Concept test at each facility.
A demonstration has not to-date been performed on the White Bluff units to show the achievable SO2 control and associated reagent feed rates. The cost reports developed by S&L, included in Appendix A, show predicted performance and required reagent rates based on Sargent & Lundy's (S&L's) extensive experience with DSI testing and previous work with the White Bluff units. Two DSI technologies are considered for White Bluff: "DSI", which would utilize the existing ESP, and "enhanced DSI", which would include installation of a fabric filter or baghouse. Enhanced DSI should achieve greater SO2 reductions because the installation of a fabric filter increases residence time and improves collection efficiency to allow more sorbent to be injected. The S&L reports present predicted performance levels (SO2 emission rates) for DSI and enhanced DSI of 0.35 lb/MMBtu and 0.15 lb/MMBtu, respectively. Because the actual performance and required reagent rates may vary from the predicted values due to unforeseen site-specific conditions, it is possible that the capital and annual costs represented in the S&L reports, and in Section 4.4.2 of this report, could also vary. If a significantly higher injection rate were actually required to achieve the same performance level (SO2 emission rate) then the capital and annual costs, and corresponding cost-effectiveness of the DSI technologies, could dramatically increase.
Furthermore, DSI has yet to be demonstrated on similarly sized units to those at White Bluff. An important consideration for DSI technology is the design throughput of the system, beyond just the size and achievable performance (S02emission rate). The largest DSI system installed and operating has a design feed rate of 12 tons/hour, while most of the installed systems inject approximately five to six tons/hour. The predicted injection rate for the White Bluff enhanced DSI case is approximately 15 tons/hour. The greater the injection rates, the more issues associated with supply and delivery logistics that arise. At 15 tons/hour (per unit) White Bluff would consume one railcar (100-ton capacity) of Trona every 3.3 hours if both units are operating at full load.
Prior to moving forward with DSI technology as a compliance strategy, a demonstration test would need to be performed to confirm the feasibility, achievable performance and balance of plant impacts (brown plume formation, ash handling modifications, landfill/leachate considerations and impact to mercury control). The balance of plant impacts have been addressed as part of the S&L cost reports based on typical assumptions, but would also be impacted should the design injection rate vary. Any compliance strategy which were to rely on DSI technology would need to be contingent on successful completion of a demonstration test.
4.2.3 Dry / Semi-Dry Flue Gas Desulfurization
Of the various designs for dry or semi-dry FGD systems, the most popular is the Spray Dryer Absorber (SDA) design. In the SDA design, a fine mist of lime slurry is sprayed into an absorption tower where the SO2 is absorbed by the slurry droplets. The absorption of the SO2 leads to the formation of calcium sulfite and calcium sulfate within the droplets. The heat from the exhaust gas causes the water to evaporate before the droplets reach the bottom of the tower, resulting in the formation of a dry powder that is carried out with the gas and collected with a fabric filter.
Entergy Arkansas, Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analyses I Trinity Consultants 4-2
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00011
SDA systems can achieve control efficiencies ranging from 60 to 95 percent.16SDA is a technically feasible option for control of S02from Unit 1 and Unit 2. Based on a site-specific study completed by S&L, SDA could technically achieve an S02emission rate of 0.06 lb/MMBtu at Unit 1 and Unit 2.
4.2.4 Wet Flue Gas Desulfurization
While WFGD is technically feasible, it is not expected to achieve significant reductions beyond DFGD/SDA and was eliminated in the previous analyses and in EPA's final regulations (SIP approval and FIP). Accordingly, WFGD is not considered further in this analysis.
4 .3 RANK OF TECHNICALLY FEASIBLE S 0 2 CONTROL OPTIONS BY EFFECTIVENESS FOR UNIT 1 AND UNIT 2
The third step in the BART analysis is to rank the technically feasible options according to their effectiveness in reducing S02. Table 4-2Table 4-2 provides a ranking of the control levels for the controls listed in the previous section.
Table 4-2, Control Effectiveness of Technically Feasible S02Control Technologies
Control Technology Semi-Dry Scrubber (SDA)
Enhanced DS1 DSI
Low Sulfur Coal
Achievable Emission Rate (lb/MMBtu) A
0.06
0.15
0.35
0.6
4 ,4 EVALUATION OF IMPACTS FOR FEASIBLE S 0 2 CONTROLS FOR UNIT 1 AND UNIT 2
The fourth step in the BART analysis is the impact analysis, which evaluates the impacts for the control options deemed feasible in Step 2. This analysis typically is conducted to demonstrate that the most effective control technology does not necessarily constitute BART. The BART guidelines list the four factors to be considered in the impact analysis:
> Cost of compliance > Energy impacts > Non-air quality impacts; and > The RUL of the source
Because the RUL of the source directly affects the cost of compliance, RUL is considered first.
16EPA Basic Concepts in Environmental Sciences, Module 6: Air Pollutants and Control Techniques http://www.epa.gov/eogapti l/module6/sulfur/control/controI.htm
Entergy Arkansas, Inc, White Bluff Steam Electric Station SBART Five-Factor Analysis I Trinity Consultants
4-3
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00012
4.4.1 Remaining Useful Life
EAI anticipates Unit 1 and Unit 2 will cease to use coal by end of year 2028, and, upon acceptance of the BART determinations contained herein in an approved SIP, is prepared to take an enforceable restriction to this effect.
4.4.2 Cost of Compliance
The capital costs and annual operating and maintenance costs for the considered control options, except for the LSC option, were developed by S&L and are included in Appendix A. The annual cost increase due to burning only LSC is based on a cost premium of $0.50 per ton, which was the premium provided to EAI's fuel purchasing department by its coal suppliers. For the S&L-developed costs, two sets of values are presented. The first, in Table 4-3, is the actual cost estimated for each unit and control option. The second, in Table 4-4Table 4-4, is the estimated cost after excluding cost items that EPA has historically claimed should not be accounted for in BART cost effectiveness calculations. An example of an excluded cost is Allowance for Funds Used During Construction (AFUDC). AFUDC represents the interest expense incurred on the investment in a large capital project, such as a FGD installation, which can take several years to complete (> 5 years). Although interest expenses will certainly be incurred on such a project, and AFUDC is typically considered as part of the capital cost of such a project for standard accounting and rate-making purposes, EPA Region 6 has expressed concern with the inclusion of AFUDC and certain other costs. EAI disagrees and believes that determining the cost effectiveness of the control options must realistically reflect the actual cost of compliance. See EAI's comments on the proposed FIP.17 Nonetheless, for completeness, this analysis shows a range of cost effectiveness both including AFUDC and other costs and excluding those costs.
Trinity annualized the capital costs based on capital recovery periods reflecting the total amount of time that the control option could be employed until the unit ceases to use coal at the end of 2028. For the purpose of this report, the start of operation for the SDA option is assumed to be the end of 2021.18Therefore, the capital recovery period for SDA is set at seven (7) years (2028 - 2021 = 7 years). The LSC and DSI options can be employed two (2) years earlier than SDA which, for purposes of this report, is assumed to be the end of 2019. Therefore, the capital recovery period for these control options is set at nine (9) years (2028 - 2019 = 9 years).
Trinity determined the values for annual tons of SO2 reduced by subtracting the estimated controlled annual emission rate from the baseline annual emission rate. The baseline annual emission rate was based on the average rate for the 2009-2013 baseline period.19The controlled annual emission rates were based on the lb/MMBtu levels listed in Table 4-2 multiplied by the future annual heat input, which was based on the average actual heat input from CAMD for the 2009-2013 baseline period. For the LSC scenario, "controlled" annual emission rates were based on an 8.75 percent decrease compared to baseline annual emission rates, which is estimated by comparing the maximum 30-boiler operating day rolling average to the controlled emission rate of 0.6 lb/MMBtu.
The cost effectiveness in dollars per ton of SO2 reduced was determined by dividing the annualized cost of control by the annual tons reduced. Table 4-3 presents a summary of the cost effectiveness for each control
17 Entergy Arkansas Inc. "Comments On the Proposed Regional Haze and Interstate Visibility Transport Federal Implementation Plan for Arkansas" (EPA Docket ID No. EPA-R06-OAR-2015-0189), August 7, 2015, pp. 10-11.
18October 27, 2021 per 81 Fed. Reg. Vol. 81, p. 66416. However, given that actual installation would take at least five years, SDA likely could not be installed until 2023 or later.
19As noted above, this is a conservative baseline, and EAI would have been justified in using a more recent baseline with lower emissions that would have resulted in generally higher cost effectiveness values.
Entergy Arkansas, Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analyses I Trinity Consultants 4 .4
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00013
option. The cost of switching to low sulfur coal is less than $l,200/ton of SO2 reduced. The actual cost effectiveness of the add-on controls is economically infeasible at more than $7,000/ton of SO2 reduced. It's noted (without waiver) that the cost effectiveness of add-on controls even when excluding certain costs for which EPA has expressed concern (e.g., AFUDC), but that will be incurred as explained above, also results in economic infeasibility, at more than approximately $5,400/ton.20*
Table 4-3. Summary of SO2 Controls Cost Effectiveness for Unit 1 and Unit 2 Based on Actual Costs
Unit & Control Option SN-01 - LSC SN-02 - LSC SN-01 - DSI SN-02 - DSI SN-01 - Enhanced DSI SN-02 - Enhanced DSI SN-01 - SDA SN-02 - SDA
Baseline Emission
Rate ftpy) 15,939
16,034 15,939 16,034
15,939
16,034 15,939
16,034
Controlled Emission Rate (tpy)
14,544 14,631 9,770 9,807 4,187 4,203 1,675 1,681
Capital Cost ($MM) 0 0 190.11 190.11 393.74 393.74 495.74 495.74
Annualized Capital Cost ($MM/yr)
0 0 29.18 29.18 60.44 60.44 92.01 92.01
Annual O&M Cost ($MM/yr)
1.60 1.61 14.91 14.91 26.19 26.19 9.60 9.60
Average Cost
Effective ness
($/ton)
1,150
1,148
7,148
7,081
7,372
7,322
7,124
7,080
Incremental Cost
Effective ness v. LSC
($/ton)
8,900 8,807 8,209 8,153 7,771 7,722
Table 4-4. Summary of S02Controls Cost Effectiveness for Unit 1 and Unit 2 Based on Costs Adjusted for EPA-Exdusions for Illustration Purposes
Unit & Control Option SN-01 - LSC SN-02 - LSC SN-01 - DSI SN-02 - DSI SN-01 - Enhanced DSI SN-02 - Enhanced DSI SN-01 - SDA SN-02 - SDA
Baseline Emission
Rate (tpy) 15,939 16,034
15,939 16,034
15,939 16,034
15,939 16,034
Controlled Emission Rate (tpy)
14,544 14,631 9,770 9,807 4,187 4,203 1,675 1,681
Capital Cost ($MM) 0 0 154.79 154.79 321.42 321.42 364.83 364.83
Annualized Capital Cost ($MM/yr)
0 0 23.76 23.76 49.34 49.34 67.71 67.71
Annual O&M Cost f$MM/yr)
1.60 1.61 14.91 14.91 26.19 26.19 9.60 9.60
Average Cost
Effective ness
($/ton)
1,150
1,148
6,269
6,211
6,427
6,384
5,420
5,387
Incremental Cost
Effective ness v. LSC
($/ton)
7,764 7,683 7,137 7,088 5,883 5,846
20 Issues raised on appeal of the federal plan include EPA's use of undervalued cost of controls. However, without waiver of any claims or arguments, EPA's estimates also support the conclusion that SDA is not cost effective. Using EPA's estimates of capital cost ($247,709,875), total O&M cost ($16,877,127), and emissions reductions (14,363 tpy for Unit 1 and 15,221 tpy for Unit 2), adjusted only to consider the shortened remaining useful life value discussed above, the average cost effectiveness values for SDA are $4,376/ton for Unit 1 and $4,129 for Unit 2.
Entergy Arkansas,. Inc, White Bluff Steam Electric Station SBART Five-Factor Analysis 1 Trinity Consultants 4-5
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00014
4.4.3 Energy Impacts and Non-Air Quality Impacts
There are numerous energy impacts and adverse non-air quality environmental impacts associated with the add-on controls under consideration. Some examples related to the use of DSI include (a) the need for substantial storage and transportation - both delivery via rail and conveyance on site - of Trona, (b) the forced abandonment of the beneficial re-use of fly ash, and (c) potential negative impacts on the PM control device.21 These impacts are more fully addressed for all the considered control options in the S&L reports included in Appendix A.
4 .5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE S 0 2 CONTROLS FOR UNIT 1 AND UNIT 2
Trinity conducted an impact analysis to assess the visibility improvement achieved. The impact analysis compared the impacts associated with the baseline emission rates to the impacts associated with the maximum emission rates representative of each control option.
Table 4-5 summarizes the lb/hr emission rates that were modeled to reflect each control option. The N0Xand total PMio emission rates were modeled at the revised 2009-2013 baseline rates. The applicable NPS speciation spreadsheets were relied upon to determine emission rates for PM species.22-23'24SO4 emission rates were independently calculated using an EPRI methodology that considers the SO2 to SO4 conversion rate and SO4 reduction factors for various downstream equipment.25
21 Sargent & Lundy, Entergy Arkansas, Inc. White Bluff DSI Cost Estimate Basis Document, SL-014000 Final, Rev. 0, August 3, 2017, pp. 6-10. See Appendix A of this report.
22 Low sulfur coal PM speciation is based on the NPS Workbook for a Dry Bottom Boiler burning Pulverized Coal using an ESP. The following values were input: heating value of 8,587 Btu/lb, 0.27% sulfur, 4.96% ash, 8,950 MMBtu/hr heat input, and a baseline total PMio emission rate of 119.2 lb/hr at White Bluff Unit 1 and Unit 2. NPS: httpj/AwwwJiature,iip_s,gov
23 DSI and Enhanced DSI PM spciations are based on the NPS workbooks for a Dry Bottom Boiler burning Pulverized Coal using an FGD system with an ESP or Fabric Filter. The following values were input: heating value of 8,587 Btu/lb, 0.27% sulfur, 4.96% ash, 8,950 MMBtu/hr heat input, and a baseline total PMio emission rate of 119.2 lb/hr at White Bluff Unit 1 and Unit 2. NPS: Ibid.
24DFGD speciation is based on the NPS workbook for a Dry Bottom Boiler burning Pulverized Coal using an FGD system with a Fabric Filter. The following values were input: heating value of 8,587 Btu/lb, 0.27% sulfur, 4.96% ash, 8,950 MMBtu/hr, and a baseline total PMio emission rate of 119.2 lb/hr at White Bluff Unit 1 and Unit 2. NPS: Ibid.
25 Electric Power Research Institute (EPRI) Estimating Total Sulfuric Acid Emissions from Stationary Power Plants: EPRI, Technical Update, Palo Alto, CA: March 2012.1023790.
Entergy Arkansas,. Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analyses I Trinity Consultants
4-6
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00015
Table 4-5. Emission Rates Modeled to Reflect SO?, Controls for Unit 1 and Unit 2
Unit & Control Option SN-01 - LSC SN-02 - LSC SN-01 - DSI SN-02 - DSI SN-01 - Enhanced DSI SN-02 - Enhanced DSI SN-01 - SDA SN-02 - SDA
SO? (lb/hr) 5,370.0 5,370.0 3,132.5 3,132.5 1,342.5 1,342.5 537.0 537.0
S04a (lb/hr)
4.0 4.0 0.5 0.5 0.02 0.02 0.01 0.01
NOx (lb/hr) 3,355.4 3,590.5 3,355.4 3,590.5 3,355.4 3,590.5 3,355.4 3,590.5
PMc (lb/hr)
40.4 40.4 29.0 29.0 13.4 13.4 13.4 13.4
ASO4as it is displayed in this table represents ammonium sulfate.
PMf (lb/hr)
31.1 31.1 22.4 22.4 12.9 12.9 12.9 12.9
EC (lb/hr)
1.2 1.2 0.9 0.9 0.5 0.5 0.5 0.5
SOA (lb/hr)
9.3 9.3 13.4 13.4 18.5 18.5 18.5 18.5
Total PM10 (lb/hr) 119.2 119.2 119.2 119.2 119.2 119.2 119.2 119.2
Comparisons of the existing/baseline visibility impacts and the post-control visibility impacts are provided in Table 4-6 and Table 4-7.
Table 4-6, Summary of CALPUFF-Modeled Visibility impacts from SO? Controls for Unit 1 (Across All Modeled Years, 2001-2003)
CACR
UBPU
HERC
MING
98% Impact (Adv)
# Days >0.5 Adv
98% Impact (Adv)
# Days >0.5 Adv
98% Impact (Adv)
# Days > 0.5 Adv
98% Impact (Adv)
# Days > 0.5 Adv
Scenario Baseline LSC
Improvement over baseline
DSI
Improvement over baseline Improvement over LSC
Enhanced DSI
Improvement over baseline Improvement over LSC Improvement over DSI
SDA
Improvement over baseline Improvement over LSC Improvement over DSI Improvement over Enhanced DSI
1.505 99 1.051 69 0.925 49 0.802 51
1.376 89 0.908 54 0.758 34 0.687 40
0.129 10 0.143 15 0.167 15 0.115 11
1.197 64 0.676 30 0.584 19 0.469 17
0.308 35 0.375 39 0.341 30 0.333 34
0.179 25 0.232 24 0.174 15 0.218 23
1.013 41 0.496 14 0.458 11 0.366 6
0.492 58 0.555 55 0.467 38 0.436 45
0.363 48 0.412 40 0.300 23 0.321 34
0.184 23 0.180 16 0.126 8 0.103 11
0.902 35 0.409 7 0.400 6 0.298 2
0.603 64 0.642 62 0.525 43 0.504 49
0.474 54 0.499 47 0.358 28 0.389 38
0.295 29 0.267 23 0.184 13 0.171 15
0.111
6
0.087 7 0.058 5 0.068 4
Entergy Arkansas, Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analysis I Trinity Consultants 4.7
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00016
Table 4-7, Summary of CALPUFF-Modeled Visibility Impacts from SO? Controls for Unit 2 (Across AH Modeled Years, 2001-2003)
CACR
UBPU
HERC
MING
98% Impact (Adv)
# Days > 0.5 Adv
98% Impact (Adv)
# Days >0.5 Adv
98% Impact (Adv)
# Days >0.5 Adv
98% Impact (Adv)
# Days > 0.5 Adv
Scenario Baseline LSC
Improvement over baseline
DSI
Improvement over baseline Improvement over LSC
Enhanced DSI
Improvement over baseline Improvement over LSC Improvement over DSI
SDA
Improvement over baseline Improvement over LSC Improvement over DSI Improvement over Enhanced DSI
1.533 100 1.059 71 0.912 52 0.819 49 1.436 89 0.932 55 0.775 35 0.697 41
0.097 11 0.127 16 0.137 17 0.122 8
1.259 66 0.700 31 0.609 19 0.486 18
0.274 34 0.359 40 0.303 33 0.333 31 0.177 23 0.232 24 0.166 16 0.211 23
1.073 42 0.528 17 0.483 12 0.384 1
0.460 58 0.531 54 0.429 40 0.435 42 0.363 47 0.404 38 0.292 23 0.313 34 0.186 24 0.172 14 0.126 7 0.102 11
0.959 37 0.427 12 0.426 8 0.318 3
0.574 63 0.632 59 0.486 44 0.501 46 0.477 52 0.505 43 0.349 27 0.379 38 0.300 29 0.273 19 0.183 11 0.168 15 0.114 5 0.101 5 0.057 4 0.066 4
4 ,6 BART FOR S 0 2 FOR UNIT 1 AND UNIT 2
Based on the costs of the control options listed above, BART for Unit 1 and Unit 2, when considering the updated RUL, would be an emission level of 0.6 lb/MMBtu based on the use of low-sulfur coal.
Entergy Arkansas, Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analyses I Trinity Consultants
4-8
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00017
APPEN D IX C O NTRO L COST IN FO R M A TIO N S02Control Cost Information - Last Updated August 2017
Entergy Arkansas,. Inc, W itte Bluff Siearn Electric Station | BART Elve-Factor Analysis I Trinity Consultants A-1
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00018
APPENDIX B, BASELINE V ISIB ILITY IMPAIRMENT BY PO LLUTANT
Year
2001 2002 2003
2001 2002 2003
2001 2002 2003
2001 2002 2003
Table B-8. Baseime Visibility Impairment Attributable to Unit 1 by Pollutant
Maximum
(Adv)
2.912 2.048 4.020
2.089 1.438 1.773
1.643 1.184 1.977
1.538 0.898 1.003
98th
Percentile
(Adv)
1.505 1.306 1.053
1.051 0.742 1.033
0.925 0.567 0.704
0.802 0.708 0.666
No. of Days with Adv >
0.5
98 th
Percentile % SO4
Caney Creek
38
74.33
29
61.53
32
47.92
Upper Buffalo
30
68.58
15
79.11
24
79.79
Hercules Glades
24
90.21
10
74.20
15
86.02
Mingo
16
51.46
21
54.87
14
57.31
98th
Percentile
% NO3
25.34 34.59 50.35
31.17 20.19 19.92
9.56 25.45 13.73
48.03 44.82 41.18
98th
Percentile
% PM 10
0.17 0.83 0.35
0.26 0.37 0.28
0.23 0.25 0.25
0.39 0.31 0.41
98th
Percentile % NO2
0.15 3.04 1.39
0.00 0.32 0.00
0.00 0.10 0.00
0.12 0.01 1.11
Entergy Arkansas,. Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analyses I Trinity Consultants B-1
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00019
Year
2001 2002 2003
2001 2002 2003
2001 2002 2003
2001 2002 2003
Table B-9. Baseline Visibility Impairment Attributable to Unit 2 by Pollutant
Maximum
(Adv)
2.994 2.098 4.084
2.066 1.447 1.791
1.665 1.185 1.947
1.580 0.886 0.999
98th
Percentile
(Adv)
1.533 1.322 1.059
1.059 0.739 1.030
0.912 0.568 0.720
0.819 0.719 0.678
No. of Days with Adv >
0.5
98th
Percentile
% SO4
Caney Creek
39
36.23
29
59.43
32
96.37
Upper Buffalo
30
66.54
16
77.57
25
78.24
Hercules Glades
25
89.39
11
72.38
16
40.35
Mingo
15
81.62
20
58.93
14
55.08
98th
Percentile
% NO3
60.75 36.53 3.38
33.21 21.71 21.46
10.38 27.26 58.44
17.93 40.66 43.36
98th
Percentile % PM10
0.74 0.82 0.24
0.26 0.37 0.28
0.23 0.25 0.40
0.33 0.19 0.40
98th
Percentile
% NO2
2.28 3.22 0.01
0.00 0.35 0.00
0.00 0.11 0.82
0.12 0.22 1.17
Entergy Arkansas,. Inc, White Bluff Steam Electric Stetson j BART Five-Factor Analyses I Trinity Consultants B-2
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00020
APPENDIX REFINED PM SPECIATION CALCULATIONS
Entergy Arkansas,. Inc, White Bluff Steam Electric Station i BART Five-Factor Analysis 1 Trinity Consultants
'
'
C,1
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00163091-00021