## FUNDAMENTAL RESEARCH OF MERCURY SPECIATION UNDER VARIOUS OPERATING PARAMETERS AT ST. JOHN’S RIVER POWER PARK

Submitted to:
Larry Bradley Superintendent, Technical, Fuels Procu rement & Strategic Initiatives
ST. JOHN'S RIVER POWER PARK

Submitted by:
Jason C.M. Cheng, Ph.D., Cao Yan, Ph.D., Bobby Chen Wei-Ping Pan, Ph. D.

Institute for Combustion Scien ce and Environmental Technology Western Kentucky University 2413 Nashville Road Bowling Green, Kentucky 42101, U.S.A.

July 16, 2006ICSET DISCLAIMER

LEGAL NOTICE This research report was prepared by the Institute for Combustion Science and Environment Technology, an agency of the Western Kentucky University, as an account of work sponsored by St. John River Power Park, JEA

. Because of the research nature of the work performed, neither the ICSET nor any of its employees make any warranty, express or imply or assume any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represent that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or serv ice by trade name. trademark, manufacturer or otherwise does not necessarily constitute or imply its endorsement or recommendation by the ICSET.

### TABLE OF CONTENTS

1. EXECUTIVE SUMMARY .................................................................................. 1

2. DETAILED TESTING ARRANGEMENTS ..................................................... 6

2.1. Tested Unit and the Air Pollution Control Device Configurations ...................... 6

2.2. Testing Arrangement ............................................................................................. 7

2.2.1. Sampling Location ...................................................................................... 7
2.2.2. Sampling Schedule ...................................................................................... 8
2.3. Methodology and Instrumentation ...................................................................... 18

2.3.1. Flue Gas Sampling System ....................................................................... 18
2.3.2. Ontario Hydro Met hod - ASTM D6784-02 .............................................. 19
2.3.3. PSA Analytical Mercury Continuous Emission Monitor (CEM) System 21 2.3.4. EPA Appendix K ...................................................................................... 23
2.3.5. Flue Gas Analyzers ................................................................................... 25
2.4. Analytical Quality Assurance and Qu ality Control (QA/QC) for the SCEM, OHM and Appendix K ......................................................................................... 26
2.4.1. Sample Identification and Chain of Custody............................................ 27
2.5. Solid Sample Analyses ......................................................................................... 31

3. RESULTS and DISCUSSION ........................................................................... 32

3.1. Measurement Overview ........................................................................................ 32

3.2. 100% Domestic Kentucky Coal ............................................................................ 34

3.2.1. OHM Results ............................................................................................ 34
3.2.2. Appendix K Results .................................................................................. 34
3.2.3. SCEM Results ........................................................................................... 35
3.3. 70% Foreign Columbian Coal and 30% Petroleum Coke .................................. 39

3.3.1. OHM Results ............................................................................................ 39
3.3.2. Appendix K Results .................................................................................. 41
3.3.3. SCEM Results ........................................................................................... 41
3.4. 35% Columbian Coal, 35% Kentucky Coal, and 30% Petroleum Coke ............ 45
i3.4.1. OHM Results ............................................................................................ 45
3.4.2. Appendix K Results .................................................................................. 46
3.4.3. SCEM Results ........................................................................................... 47
3.5. Hg Material Balance ............................................................................................ 51

3.5.1. Solid Sample Characterization .................................................................. 51
3.5.2. Material Mass Balance .............................................................................. 53

4. Conclusion ........................................................................................................... 57

4.1. Hg Emission from Unit 1 Stack ........................................................................... 57

4.2. Hg Removal Efficiency ........................................................................................ 57

4.3. Hg Material Mass Balance .................................................................................. 58
Appendix I: Conversion Factor for Converting μ g/NM 3 to lb/tBtu ........................... 59
Appendix II: Effect of Vanadium on the Conversion of Hg(0) to Hg(2+) ................. 62

ii

### List of Figures Figure 2-1 Unit 1 Configuration ......................................................................................... 6 Figure 2-2 Sampling Arrangement ..................................................................................... 8 Figure 2-3 Solid Sample Collecting Arrangement .............................................................. 9 Figure 2-4 Apex Isokinetic Sampling System .................................................................. 18 Figure 2-5 Diagram and photo of the OHM sampling train ............................................ 20 Figure 2-6 The OHM Analysis Flow Char t and Photos of the Leeman System. ............. 21 Figure 2-7 Diagram and Photos of the SCEM System .................................................... 22 Figure 2-8 Hg Sampling Trai n Illustrating Single Trap................................................... 24 Figure 2-9 SCEM Mercury Sampling, Analytical and QA/QC Procedures .................... 28 Figure 2-10 Schematic Descri ption of OHM Mercury Samp ling, Analytical and QA/QC Procedures ................................................................................................. 29 Figure 3-1. SCEM testing resu lts at (a) APH Inlet, (b) ESP Inlet, (c) ESP Outlet, (d) FGD Inlet, and (e) Stack during the Period of when 100% Kentucky Coal was Used ................................................................................................... 39 Figure 3-2 SCEM testing result s at (a) APH Inlet, (b) ESP In let, (c) ESP Outlet, (d) FGD Inlet, and (e) Stack during the Period of when 70% Columbian Coal and 30% Petroleum Coke was Uused.............................................................. 44 Figure 3-3 SCEM testing results at (a) APH Inlet, (b) ESP Inlet, (c) ESP Outlet, (d) FGD Inlet, and (e) Stack during the Period of when 70% Columbian Coal and 30% Petroleum Coke was Used ................................................................ 50

iii

### List of Tables

Table 1-1 Concentrations of elemental (Hg(0) ), oxidized (Hg(2+)), and total mercury in stack gas measured by OHM, SC EM and EPA Appendix K method. ............. 2 Table 1-2 Hg removal efficiencies of ESP and FGD units. ................................................ 3 Table 1-3 Concentrations of elemental (Hg(0) ), oxidized (Hg(2+)), and total mercury in APH inlet measured by OHM and SCEM. ....................................................... 4 Table 1-4 Mercury material balances ................................................................................. 5 Table 2-1 Testing schedule for St. John River Park Unit 1 .............................................. 10 Table 2-2 Sorbent trap and sampling requirements .......................................................... 25 Table 2-3 QA/QC for Appendix K samples ..................................................................... 30 Table 2-4 Coal and ash sampling and analysis matrix ..................................................... 31 Table 3-1. Approximate and ultimate analyses of the fuels tested. .................................. 32 Table 3-2 Mineral composition of fuels tested in this study ............................................. 33 Table 3-3 OHM Hg monitoring results duri ng period of when 100% domestic Kentucky coal was burned. .............................................................................................. 35 Table 3-4. Appendix K results at the stack during the period of when 100% domestic Kentucky Coal was burned. ............................................................................ 35 Table 3-5 Mean value of SCEM monitoring during the period of when Kentucky coal was burned ...................................................................................................... 36 Table 3-6 OHM Hg monitoring results during the period of when 70% Columbian coal and 30% of petroleum coke was burned ......................................................... 40 Table 3-7 Appendix K results at the stack during period of when 70% Columbian coal and 30% of petroleum coke was burned ......................................................... 41 Table 3-8 Mean values of Hg SCEM mon itoring result during the period of when 70% Columbian Coal and 30% of petroleum coke was burned .............................. 41 Table 3-9 OHM Hg monitoring results duri ng the period when 35% Columbian coal, 35% Kentucky coal and, 30% petroleum coke was used. ............................... 46 Table 3-10 Appendix K Results at the stack during Period when 70% Columbian Coal and 30% of petroleum coke was used............................................................. 47 Table 3-11 Mean values of Hg SCEM monitoring result during the period of when 70% Columbian coal and 30% of petroleum coke was burned ............................... 47
Table 3-12 Chemical char acterization of fly ash .............................................................. 51 Table 3-13 Concentration of Hg in FGD slurry ................................................................ 51 Table 3-14 Hg content in fly ash collected by filter ......................................................... 52

ivTable 3-15 Mineral com position of ESP fly ash ............................................................... 53 Table 3-16 Hg material balance of OHM run during the period of when 100% Kentucky coal was used .................................................................................................. 54 Table 3-17 Hg material balance of OHM run during the period of when 70% Columbian coal-30% petroleum coke was used ................................................................ 55 Table 3-18 Hg material balance of OHM run during the period of when 35% Columbian coal-35% Kentucky coal-30% petroleum coke was used ............................... 56

v

### 1. EXECUTIVE SUMMARY

This report provides detail s concerning a fundamental research aimed to study transformation of mercury speci ation along the flue gas path under one consistent boiler load (632 ±10MWe) with thre e types of fuel blending scenario. The testing was performed at St. John’s River Power Park Unit 1 (referred as unit 1 in the following sections) from 6/6/06 to 6/11/06.
The concentration of mercury in the flue gas of Unit 1 was measured by Ontario Hydro Method (OHM), also known as ASTM D6784-02, ICSET Semi-Continuous Emission Monitors (SCEM), a nd the EPA Appendix K method (a carbon trap method). The testing QA/QC procedures were performed according to part 75 and PS 12 testing guidelines described in section 2.9 Quality Assurance/Quality Control for the SCEM, OHM and Appendix K. The main objectives for th is testing were:

1. To determine the total Hg (i.e., Hg (T)) and mercury speciation in the Unit 1 stack under three different fuel blending meas ured with ASTM 6784- 02 (also known as Ontario Hydro Method (OHM)), Inst itute for Combustion Science and Environmental Technology (ICSET) Semi-Continuous Mercury Emission Monitoring (SCEM) and EPA Appendix (sorbent trap method).

2. To determine the particulate-bound Hg (Hg (P)) capture efficiency via the Unit 1 electro-static precipitator (ESP) with SCEM and OHM.

3. To determine the oxidized Hg (Hg(2+)) capture efficiency via the Unit 1 flue gas desulfurization (FGD) with SCEM and OHM.

4. To provide a baseline reference of Hg oxidation prediction for selective catalyst reduction (SCR) by performing SCEM and OHM testing at the Unit 1 air preheater (APH). SCR is in the future construction plan for Unit 1.

5. Coal, ash and FGD slurry were collected and analyzed along with the gas phase information for mercury material balance calculation to determine Hg partitioning, to evaluate the removal effici ency of the air pollution control devices (APCDs) and to validate th e three testing methods. The acceptable range is between 80%-120%.
The tested unit was set to the testing targ eted capacity throughout the entire testing period.

Observations : Object 1
The emissions of total mercury (i.e., Hg (T)) from the unit 1 stack as well as the distribution of mercury species in the stack gas under three different fuel blending was measured with OHM, ICSET Semi-Continuous Mercury Emission Monitoring (SCEM)

1and EPA Appendix (sorbent trap method). The results were summarized in Table 1-1. As can be seen, the differences between the three testing met hods were all below 1 μ g/NM 3 . Kentucky coal produces the highest Hg emission, followed by the third (i.e., 35% Columbian coal-35% Kentucky coal-30% Petroleum Coke) fuel. The second (70% Columbian Coal-30% Petroleum coke) fuel produces the lowest Hg emission. The distribution of Hg species measured by OHM and SCEM was found to be within 0.20 μ g/NM 3

.

Table 1-1 Concentrations of elemental (Hg(0) ), oxidized (Hg(2+)), and total mercury in stack gas measured by OHM, SCEM and EPA Appendix K method.

Object 2
Mercury removal efficiency is based on a combined functionality of temperature change, acid gaseous content (halogens), fly ash reactivity and surface area, and other minor metal effects. Normally, after the flue gas travels thr ough the air pre-heater (APH), from the inlet at appr oximately 700 °F to the outlet at approximately 300 °F, the mercury oxidization formation is complete. A lower temperature at the APH outlet increases the chances for me rcury oxidization. A portion of the oxidized mercury binds with the fly ash and is captured by the ESP, and the remainin g Hg (2+) is scrubbed out by the FGD. Since the Hg (0) portion does not re act with moisture or fly ash, it is emitted from the stack.

The removal efficiencies of Hg by the ESP unit were calculated for each fuel tested. As can be seen, SCEM shows the ESP unit can reach about 16.2, 11.2, and 13.2% of removal efficiency for fuel 1, 2, and 3, respec tively. The removal efficiencies determined by SCEM are not much different from wh at were obtained from the OHM.

2The LOI content in the fly ash is believed to play a significant role in capturing oxidized mercury through unburned carbon active sites. It is di rectly related to mercury oxidation and particulate mercury capture acro ss the ESP. According to solid sample analyses (discussed in 3-6), the mercury content in the fly ash was found fluctuate between 0.18 to 0.88 ppm for Kentucky coal an d the LOI content was found to be in a range of 3.97 to 6.7%. Howeve r, the fly ash produced by burning blended fuel 2 and 3 has much higher LOI, ranging from 18.45% to 35.99%. The high LOI values observed in the fly ash from fuel 2 and 3 did not result in a higher Hg removal efficiency for ESP. Other than LOI, halogen content, such as Cl, in coal has been identified as one of the main factors promoting mercury oxidation unde r high temperature a pplications within post-combustion processes. Generally speaking, higher chlorine content (preferably between 500-1000 ppm) increase s mercury oxidization. Kent ucky coal has higher Cl than the other two blended fuels. However, the contributed to a substantial amount of Hg (0) emission was not found.
Table 1-2 Hg removal efficiencies of ESP and FGD units.

Object 3
The Hg removal efficiencies of FGD for the three fuels tested were calculated and the results are listed in Table 1- 2. Based on the results obtain ed from OHM testing, it is found that FGD unit removes 64.2, 63.6, and 73.5% of Hg for fuel 1, 2, and 3, respectively. The results were slightly hi gher than the values calculated from SCEM data.
Object 4
The concentration and speciation distributi on of Hg at the APH inlet for the three fuels tested is summarized in Table 1-3. According to the results obtained from OHM, over 80% of the Hg presents in the flue gas as in its elemen tal form. However, the value was found to be slightly above 36% by SCEM re sults. The discrepancy is believed to be due to the different interaction of Hg and fly as h on their different filtration mechanism.

3Table 1-3 Concentrations of elemental (Hg(0)), oxidized (Hg(2+)), and total mercury (Hg(T)) at APH inlet measured by OHM and SCEM.

Object 5
The mercury material balance is listed in Tabl e 1-4. It is shown th at the ratios of Hg input to Hg output for fuel 1 are in a range from 0.98 to 1.27. The ratio is found slightly higher for fuel 2 and 3.

4Table 1-4 Mercury material balances

5

### 2. DETAILED TESTING ARRANGEMENTS

2.1. Tested Unit and the Air Pollution Control Device Configurations

Tested Units:
St. John’s River Park Unit 1 Boiler Configuration : Unit capacity: Unit 1: 660 MWe gross Boiler type: Unit 1: Front Wall-Fi red Pulverized Coal Burner. APCD Configurations:
Particulate control: Cold-side ESP
SOx control: Lime-stone forced oxidization FGD Fuel Type: Fuel 1: Kentucky Coal
Fuel 2: 70% Columbian Coal and 30% Petroleum Coke Fuel 3: 35% Columbian Coal, 35% Ke ntucky Coal, and 30% Petroleum Coke The configuration of Unit 1 is shown in Figure 2-1.

Figure 2-1 Unit 1 Configuration

62.2. Testing Arrangement

2.2.1. Sampling Location

Mercury removal efficiencies across the cold-side ESP and FGD were measured by OHM and SCEM at 5 locations, i.e., APH inlet, ESP inlet/outlet, FGD inlet and stack. This testing arrangement also determined the transformation of Hg speciation along the flue gas path. In addition to OHM a nd SCEM, EPA Appendix K method was also applied at the Unit 1 stack to measure total mercury emission. The total emission results obtained from the three methods can, ther efore, be compared. Detail sampling arrangements and testing schedule can be seen in Figure 2-2 and Table 2-1, respectively. Specific testing conditions and their perspective research objectives were described as following.

• Simultaneous sampling at the APH inlet duct A using OHM and SCEM to validate

measurement results. APH ducts A/B: 15ft in depth.

• Using ICSET modified OHM sampling at th e ESP inlet duct C and outlet duct C to

determine the Hg speciation partitioning, name ly, Hg (0), Hg (p) and Hg (T). This is also to further determine the Hg forma tion after the air preheater and the Hg (p) control efficiency across the ESP. APH ducts A/B: 15 ft in depth.

• Simultaneous sampling at the Unit 1 st ack using OHM, SCEM and Appendix K to

evaluate advantages and disadvantages of each testing method to provide JEA with long-term monitoring references. This is also to further determine the Hg (2+) control efficiency across the FGD. F GD inlet: 20’ in depth. Stack ID: 26.6’.

• Close continuous mercury emission monitoring at Unit 1 APH inlet, across the Unit

1 ESP and FGD.

• Solid samples (i.e., coal, fly ash, and FGD sl urry) were collected and analyzed. By

coupling the results obtained from vapor-phase Hg sampling, mercury material balance can be calculated. Detail solid sa mple collecting locations can be seen in Figure 3.

• Coal samples were collected from the feeder before each individual mill; a mixture

sample from all feeder samples (extracted after each feeder) was analyzed. During OHM sampling period: coal sample from each feeder was collected in sequence. The interval between two feeders was 150 minutes/the number of feeder for each individual boiler. During SCEM operati ng only period: two sets of coal samples were collected daily. The first set was co llected in morning and the other set was collected in the afternoon.

• Fly ash samples were collected from the 8 hoppers in middle of the first two front

rows. The sampling frequency is same as coal.
72.2.2. Sampling Schedule

This project includes three days for tr avel, instrumentation set-up/warm-up, and shelter installation. Testing was carried out constant operating conditions but with 3 different types of blended fuels. On the last day (6/12/06), in strumentation was takendown and demobilized. Detail sampling sche dule can be seen in Table 2-1.

.

Figure 2-2 Sampling Arrangement

89 Figure 2-3 Solid Sample Collecting Arrangement10Table 2-1 Testing Schedule for St. John River Park Unit 12.3. Methodology and Instrumentation

2.3.1. Flue Gas Sampling System

For a given sampling location, flue gas samples were collect ed by a versatile isokinetic sampling system specifi cally provided by Apex Instru ments. A complete set of Apex Instrument flue gas sampling system, as shown in Figure 2-4 includes a probe with glass liner, a heated filter box, a set of EPA method 5 specified glassware, U-cord, brushes, and a metering console.
The probe is equipped with type S pitot tubes and thermocouple sensor for measuring gas velocity and stack temperature, respectivel y. A glass fiber filter assembly is enclosed in a temperature-controlled heated sample box, in which the temperature were kept at 248±25 o F. The nozzle, probe liner, connecting gla ssware, and filter are referred to as the “front-half” of the sample train. Following the filter is a condensa tion section, which is also known as the “back-half” of the sample train. The back half is c ooled in an ice bath and kept at temperature below 68 o F.
An umbilical cord containing a vacuum hose, pitot lines, thermocouple wires, and a 4-wire electrical cord is used to connect sample train to a control box. The control box controls stack gas sampling rate using fine a nd coarse metering valves. It also provides gas volume, sampling velocity, pressure, an d temperature readings with respect to sampling conditions through flow meter, manome ter, vacuum gauge, and digital display, respectively.
This system permits sampling of vertical poi nts or space-limited locations. After flue gas is collected, it passes through a set of impi ngers containing various solutions prepared depending on testing objectives.
During sampling, three types of sampli ng system leak check were perform; i.e., pre-test, during test, and post-test leak checks, as one of the qua lity assurance procedures.

Figure 2-4 Apex Isokinetic Sampling System

182.3.2. Ontario Hydro Method - ASTM D6784-02

OHM (Ontario Hydro Method) is the standard test method for elemental, oxidized, particle-bound, and total mercury in flue gas generated from co al-fired stationary sources. OHM is the only EPA method approved by AS TM (Method D6784) for measuring and speciating mercury in flue gas. The standa rd OHM consists of three key elements: isokinetic sampling, recovery, and solution an alysis. All OHM sampling and analytical activities in ICSET followed EPA quality a ssurance/quality control (QA/QC) procedures throughout the test. Detail QA/QC procedures are described in the later section of this report.
While conducting testing, flue gas sample is isokinetically withdrawn from the source by an Apex Instruments flue gas sampling sy stem. Flue gas was force passing through a series of impingers in an ice bath (Figure 2- 5). Particle-bound merc ury is then collected in the front half of the sampling train on a quartz fiber filter. Oxidized mercury is collected in impingers contai ning a chilled aqueous pota ssium chloride solution. Elemental mercury is collected in subsequent impingers (one impinger containing a chilled aqueous acidic solution of hydrogen pe roxide and three impingers containing chilled aqueous acidic solutions of potassium permanganate).
After sampling, all solutions are then recovered and dige sted using an automated mercury preparation system (Leeman Lab Hydra Prep, Teledyne Leeman Labs, NH). Four-mL aliquot of each Hg adsorption solution (i.e., KCl, H 2 O 2 /HNO 3 , and KMnO 4 /H 2 SO 4 ) recovered from perspective impinge rs were transferred to a 15-mL digestion cup, in which 0.2 mL concentrated H 2 SO 4 , 0.1 mL concentrated HNO 3 , 1.2 mL 5% KMnO 4 , and 0.32 mL of 5% K 2 S 2 O 8 was added automatically to each cup through a dispenser. The cups were heated in a wa ter bath at a constant temperature of 95 o C for two hours. After cooling, 1.333 mL of 12%:12% NaCl: hydroxylamine sulfate was added to prepare the solution ready for me rcury analysis by a cold-vapor atomic absorption or fluorescence spectroscopy (Leem an Lab Hydra, Teledyne Leeman Labs, NH). During analysis, 5% HNO 3 was employed as the rinse solution and 10% SnCl 2 /10% HCl solution was utilized as the reduc tant agent. The peristaltic pump was controlled at 5 mL/min, while the carrier ga s was ultra high purity grade nitrogen flowing at a rate of 0.6 L/min. The OHM testing flow ch art and the Leeman system can be seen in Figure 2-6.

19Figure 2-5 Diagram and photo of the OHM sampling train

20Figure 2-6 The OHM Analysis Flow Char t and Photos of the Leeman System.

2.3.3. PSA Analytical Mercury Continuous Emission Monitor (CEM) System

A mercury semi-continuous emission mon itoring system provided by PS Analytical, UK, as presented in Figure 2-7, consists of four major components: (1) a probe, filter and pump module; (2) heated Teflon sample lines, which are normally kept at 200 o C and are needed to prevent loss of Hg along the sample lines, as well as keep the speciation the same as that in the stack, and to reduce c ondensation of acid gases; (3) a Hg conversion system; and (4) an analyzer and data process system. The system also has an Hg vapor generator, which is able to supply a constant stream of Hg vapor a nd blank at typically 14 liters per minute. These gase s go through the valve-switching box and can be directed to

21Figure 2-7 Diagram and Photos of the SCEM System
the probe to completely check the system bias. The second probe was supplied by Apogee.

222.3.4. EPA Appendix K

This method is used for the continuous sampling of mercury (Hg) emissions in combustion flue gas streams with sorbent trap s. Analysis of each trap was done by cold vapor atomic fluorescence spectrometry (AF), or by cold vapor atomic absorption spectrometry (AA).
Known volumes of flue gas were extracte d from a duct through a single or paired sorbent trap with a nominal flow rate of 0.2 to 0.6 liters per minute through each trap. Each trap was then acid leached and the resulting leachate was analyzed by cold vapor atomic fluorescence spectrometry (CVAFS) or by cold vapor atomic absorption spectrometry (AA). Analysis by AA can be pe rformed by existing rec ognized procedures, such as that contained in AS TM Method D6784-02 or EPA Method 29.
Sampling instruments used in this study included:
Hg Sampling Train . A Schematic of a single trap sa mpling train used for this method is shown in Figure 2-8. Where this method is used to collect data to demonstrate compliance with a regulation, it must be perfor med with paired sorbent trap equipment.
Sorbent Trap . Use sorbent traps with separate main and backup sections in series for collection of Hg. Selection of the sorbent trap shall be based on:
1) Achievement of the performance criteria of this method and
2) Data is available to demonstrate the method can pass the crit eria in EPA Method 301 when used in this method and when the results are compared with those from EPA Method 29, EPA Method 101A or ASTM Me thod 6784-02 for the measurement of vapor-phase Hg in a similar flue gas matrix.
The method requires the analysis of Hg in both main and backup portions of the sorbent within each trap. The sorbent trap shou ld be obtained from a reliable source that has clean handling procedures in place for ultr a low-level Hg analysis. This will help assure the low Hg environment required to manufacture sorbent traps with low blank levels of Hg.
Sorbent trap sampling requirements or needed characteristics are shown in Table 2-2. The sorbent trap is supported on a probe and inserted directly into the flue gas stream, as shown on Figure 2-8. The sampled sorben t trap is the entire Hg sample.

23Figure 2-8 Hg Sampling Train Illustrating Single Trap.
Sampling Probe

. The probe assembly shall have a leak-free attachment to the sorbent trap. For duct temperatures from 200 to 375oF, no heati ng is required. For duct temperatures less than 200/F, the sorb ent tube must be h eated to at least 200oF or higher to avoid li quid condensation in the sorb ent trap by using a heated probe. For duct temperatures greater than 375oF a large sorbent trap must be used, and no heating is required. A thermocouple is used to monitor stack temperature.

Umbilical Vacuum Line. A 250oF heated umbilical line shall be used to convey to the moisture knockout the sampled gas that has passed through the sorbent trap and probe assembly.

Moisture Knockout

. Impingers and desiccant can be combined to dry the sample gas prior to entering the dry gas meter. Alternative sample drying methods are acceptable as long as they do not affect sample volume measurement.
Vacuum Pump

. A leak tight vacuum pump capab le of delivering a controlled extraction flow rate between 0.1 to 0.8 liters per minute.
Dry Gas Meter

. Use a dry gas meter that is calibrated according to the procedures in 40 CFR Part 60, Appendi x A Method 5, to measure the total sample volume collected. The dry gas meter must be suffi ciently accurate to measure the sample volume within 2 percent, calibrated at the selected flow rate and conditions

24actually encountered during sampling, and equipped wi th a temperature sensor capable of measuring typical meter temper atures accurately to within 3/C (5.4/F).
Sample Analysis Equipment. Laboratory eq uipment required for analysis by AF. For analysis by AA, refer to Me thod 29 or ASTM Method 6784-02.

Table 2-2 Sorbent trap and sampling requirements

2.3.5. Flue Gas Analyzers

A tempest 100 Portable and Flexible Com bustion Emissions Monitoring System was used for measuring H 2 S (<2000 ppm), CO (1-10%), O 2 , NO and SO 2 . During each sampling run, this system was peri odically used for leak check.

252.4. Analytical Quality Assurance and Qua lity Control (QA/QC) for the SCEM, OHM and Appendix K
The quality control measures for this experiment are described in detail in the Ontario Hydro Method procedures. What is describe d in this summary are highlights of these procedures and are by no means a comprehe nsive summary. Quality control for the Ontario Hydro Method starts at the very begi nning of the procedure. Only ACS reagent grade or ACS certified chemicals are used in the sampling solutions, reagents, and even the wash solutions. Daily blanks are taken of the sampling solutions. Three additional blanks are taken with each run: a 0.1 N HNO 3 blank, a hydroxylamine solution blank, and a filter blank. A field blank is collected for every series of samples run by setting up the impinger train and letting it sit in the sampling location for the normal sampling period.
The Ontario Hydro Method outlines quality control for sample measurement as well. Every collected sample shall be analyzed tw ice with every tenth sample being analyzed in triplicate. The measurements of the samples must be within 10% of each other. Finally, every eleventh sample analyzed shall be a standard. If the measured value for the standard is incorrect, then the instrument shall be re-calibrate d and the previous ten samples shall be reanalyzed. Thus, the Ontario Hydro Method prescribes rigorous quality control measures.

Blanks
As part of the QA/QC, a field blank was associated with samp ling at each location for each test condition. A field blank is defined as a complete impinger train including all glassware and solutions that is taken out to the field du ring sampling and exposed to ambient conditions. These sample trains will then be taken apart and the solutions recovered and analyzed in the same manner as those sample trains used for sampling activities. If the field bl ank shows contamination above instrument background, steps must be taken to eliminate or reduce the contamination to below background levels. However, based on past experience, it is expect ed that these samples were at or below the detection limits of the instrument.
Spikes
As part of the QA/QC, a field spike was as sociated with each test condition. A field spike was prepared by the field chemist at a level similar to the field samples. These sample trains will then be taken apart and the solution recovered and analyzed in the same manner as those sample trains used for sampling activities. The target range for recovery of the field spike is ±20%. If the rec overy of the field spike is outside the target range, the procedures were reviewed, steps were taken to correct the problem, and the field spike was repeated.

Data Reduction
Data reduction will occur in two phases. Fi rst, preliminary data reduction occurs on the job site. On-site data reduction may be performed by sampling and analytical personnel or by the team leaders. Preliminar y calculations include velocity, moisture,

26stack gas flow, sample gas volume, percent isokinetic sampling, and flue gas mercury concentrations. Calculations are generally performed using spreadsheets on a portable computer; some averaging is typically done wi th a calculator. Standa rdized spreadsheets were used on this program. The second phase of data reduction occurs after the team has left the job site. This includes review of the field data entry and input of laboratory results to complete the calculated mercury concentr ations for the coal and ash samples. In addition, the mercury speciation calculations that were done in the field were rechecked and put into a predefined da ta sheet. Equations to be used in the calculations are contained in the method.

Data Validation
All data, data entry, and calculations are double-checked by the originator and reviewed by a second person. Reviews can in clude recalculation of results, data entry checks, and calculation of known and accepted da ta sets using the existing spreadsheet.

2.4.1. Sample Identification and Chain of Custody

Samples are identified with unique samp le numbers and descriptive notations. Custody of samples is maintained by WKU pe rsonnel; samples are stored and taken back to WKU. Once the samples are received by the WKU laboratory, the sample condition will check and then logged into the WKU logg ing system. Data sheets are kept in the custody of the originator, the program manager, or in locked storage until returned to the office. The original data sheets are used for report preparation, and any additions are initialed and dated.
Detailed information covering Quality Assurance/Quality Control (QA/QC), sampling protocol, instrumenta tion, and other tec hnical data is avai lable upon request. The general SCEM and OHM QA/ QC procedures are presente d in Figure 2-9 and Figure 2-10, respectively.
The major QA/QC components for the EP A Appendix K method are outlined in Table 2-3.

2728 Oxygen analysis

Frequent replacement of

syringe and

septum Independent check of MFC Direct measurement of Hg O source (CavKit outlet)

Oxygen analysis Sample Gas Conditioning & Transport

Direct instrument

calibration Independent check leakage

of probe

Figure 2-9 SCEM Mercury Sampling, An alytical and QA/QC Procedures High span

Blank

Gold trap & Hg Lamp High span

Blank 

### Sample Gas Extraction Hg Measurement High span

Blank29gasFinalreportSam pling and RecoveryDigestionAnalysisD ata V alidationSa m pling environm enta l conditions:H Cl/SO2H2OAsh lo adFly ash LO ITemperatureD uct co nfiguratio nInstrument C heck & C alibration:Sam pling: A nalyzer:M eter, P ump , No zzle, T hermo co uple, H ydra AASBaro meter, P ito t tube, O xygen senso r,C lean & R inse:G alssw areT eflo n materialsPre & Po st - test:Leak CheckTemperature checkIso k inetic CheckM oisture content checkHg & speciatio n checkF ield blankS p ikeSolution preparatio n:D ailyN a2S2O3,S o lut io n co lo r mo nito ringM o re im pingersAsh-free pro beEPA M ethodTraverseFigure 2-10 Schematic Description of OHM Mercury Sampling, Analytical and QA/QC ProceduresN OYesImmediate analysisCo ntam ination free op eratio nPressure stabilityStandard so lutio n calibratio nP um p rate stabilityChemicals:Trace M etal Deg ree ChemicalsD ata analysisfro m split samp leJob doneSampl e s pl i tTable 2-3 QA/QC for Appendix K samples

302.5. Solid Sample Analyses
Coal, fly ash, and slurry samples were collected to calculate mass balance and provide information on how ash composition affects the removal of mercury and to determine the stability of mercury in the ash.
The “loss on ignition” (LOI) of ash wa s determined as per ASTM Method D 5142 using TGA 601 or TGA 701 thermogravimetri c analyzer (Leco, MI). The ultimate analysis for carbon and sulfur was dete rmined using ASTM Methods D 5373 and D 4239, respectively. Leco CHN2000 and Leco SC432 were employed to determine carbon and sulfur contents, respectively. Mercury contents of coal and ash samples were analyzed by a LECO AMA-254 Advanced Me rcury Analyzer (Leco Co, MI), which directly combusts solid samples at 750 o C and applies atomic ad sorption spectroscopy to measure Hg concentration at trace level. This type of analyzer was the principal instrument used to develop the newest ASTM standard method of analysis for mercury in coal and combustion residues, D 6722. The analyzer ha s a 0.01 ng Hg detection limit with a working range from 0.05 to 600 ng. Th e reproducibility error is smaller than 1.5%. The coal fly ash, and FGD slurry analysis matrix are shown in Table 2-4.
Table 2-4 Coal and ash sampling and analysis matrix

Sample Proximate Analyses Ultimate Analyses Chloride and
Fluoride Sulfur Hg LOI

Coal X X X X X
Fly ash X X X X
FGD slurry X X X X

31

### 3. RESULTS and DISCUSSION

3.1. Measurement Overview
The ICSET sampling and analytical team a rrived on site at St. John’s River Power Plant Unit 1 on June 5, 2006, and started se tting up the OHM, SCEM and Appendix K sampling and analytical instruments. Three different blended fuels (i.e., 100% domestic Kentucky Coal, 70% foreign Columbian coal with 30% petroleum coke, and 35% Columbian: 35% Kentucky: 30% petroleum Coke blended coal) were tested in this study during the testing period from June 6, 2006 to June 11, 2006.
A total of 18 fuel samples were collect ed and characterized by approximate and ultimate analyses. The results are summarized in Table 3-1. The coal analyses indicated that the chemical properties of each fuel duri ng a two-day testing period were consistent. The Hg content of Kentucky coal was found highe r than the other two fuels. It is also true for chloride and ash content.
The mineral compositions of the fuels tested were also analyzed by XRF. For a given fuel, SiO 2 makes up over 50% of mineral composition for the ash fractionl, followed by Al 2 O 3 and Fe 2 O 3 .

Table 3-1. Approximate and ultimate analyses of the fuels tested.

6

Kentucky coal was tested on May 6 th and 7 th , 70% Columbian Coal-30% petroleum Coke was tested on May 8 th and 9 th . The 35% Columbian coal/35% Kentucky coal/30% petroleum coke was tested on May 10 th and 11 th

.

32Table 3-2 Mineral composition of fuels tested in this study

Kentucky coal was tested on May 6 th and 7 th , 70% Columbian Coal-30% petroleum Coke was tested on May 8 th and 9 th . The 35% Columbian coal/35% Kentucky coal/30% petroleum coke was tested on May 10 th and 11 th

. The SCEM was set to be in monitoring service starting from June/6/06 to continuously record concentra tion and species distribution of Hg at 5 different sampling locations along the flue gas path (i.e., APH in let, ESP inlet, ESP outlet, FGD inlet, and Stack). A total of 48 sets of OHM were conducted at the 5 sampling locations same as SCEM and 12 sets of Appendix K sorbent trap sampling at the Unit 1 stack were conducted throughout the entire testing period. During each OHM testing, one set of coal, ash and FGD slurry samples was collected and analyzed for Hg material balance calculation .The Ontario Hydro Method is an approved ASTM method, therefore the OHM results are presented in the following sections for validation purposes. The QA/QC procedures for OHM, SCEM and Appendix K were carried out following the EPA Part 75 requirements.
The total mercury (Hg (T)) is the sum of the elemental mercury (Hg (0)), oxidized mercury (Hg (2+)), and part icle-bound mercury (Hg (p)). The vapor-phase total (Hg (VT)) is the sum of the oxidized portion a nd elemental portion excl uding the particlebound mercury. The Hg (P) portion analyzed from each set of OHM sampling was found only detectable at the APH and ESP inlet. In the other locations, no Hg(P) data is available as the results of either the Hg content was under the instrumental detection limit, and therefore undetectab le (ND), or insufficient am ount of ash sample.

333.2. 100% Domestic Kentucky Coal
The boiler was fed with 100% Kentucky coal on June 6 th and 7 th . The SCEM was set to be in monitoring mode before the appendix K sorbent trap and OHM sampling were initiated. The Appendix K sorben t trap method was installed in the morning and set in sampling service for eight hours. The OHM sampling was carried out isokinetically. The testing results during this peri od are discussed in th e following section. The mercury data was dry-based and has been corrected to 3% oxygen.

3.2.1. OHM Results

The results obtained from the 16 sets of OHM measuring conducted at the 5 testing location during this period are summarized in Table 3-3. As can be seen, the concentration of Hg (0) was found to be an average of 8.07 μ g/NM 3 (5.87 lb/tbtu) at the APH inlet. This concentration decreased as the flue gas moved toward to the stack. For Hg(2+), the concentration remained relatively constant before flue gas entering the ESP unit. It can be seen that the concentrati on of Hg (2+) increased after passing the ESP unit, which is 7.09 μ g/NM 3 (4.92 lb/tbtu) compared to 2.62 μ g/NM 3 (1.82 lb/tbtu) at the ESP inlet. The ESP unit significantly chan ged the distribution of Hg species. The transformation of Hg species was also obser ved after passing through the ESP unit, but not significantly.
The transformation of Hg species can be better observed by evaluate the ratio of Hg(0) to Hg(VT). As can be seen in Table 3-3, the ratio has the hi ghest value at the APH inlet. The value decreases as the flue gas flows toward to the FGD inlet, where Hg(0)/Hg(VT) reaches the lowest value of 9.01. The value increased after flue gas passes through the FGD unit due to th e removal of oxidized mercur y. By comparing the Hg(0) concentrations obtained at the FGD inlet and stack, A re-emission of Hg (0) was observed. The concentration of Hg(0) increased from 0.81 to 1.34 ( 0.59 to 0.92 lb/tBtu ) before and after passing through the FGD unit.
Based on Table 3-3, the Hg removal efficienci es of ESP and FGD ca n be calculated. It was found that ESP removed 14.9% and FG D removed 64.2% of the total Hg coming into the flue gas. A total of 79.1% removal efficiency was reached.

3.2.2. Appendix K Results

The results for the Appendix K sorbent trap testing are summarized in Table 3-4. As can be seen, the Hg concentration in the B s ection of each tested trap was neither greater than 5 ng nor 2% of the concentration dete cted in section A which meet the QA/QC criteria of this method stated in the previous section. In addition, the recovery rates of the third spiked section of each pair were found to be within ± 25% of the initial spiked mercury concentration, which also meet th e QA/QC requirements. By comparing the mean values of Appendix K results (1.58 μ g/dscm) to the results obtained from OHM (2.10 μ g/dscm), it is found that the difference between two measurements was within 1
μ g/dscm.

34Table 3-3 OHM Hg monitoring results dur ing the period of when 100% domestic Kentucky coal was burned.

Table 3-4. Appendix K Results at the stack during the period when 100% Domestic Kentucky Coal was burned.

3.2.3. SCEM Results

The SCEM mercury data of each 5 sampling locations (i.e. APH inlet, ESP inlet, ESP outlet, FGD inlet, and Stack) correspond ing to the period of when only domestic Kentucky coal was used is summarized in Figure 3-1. The mean value of SCEM monitoring data collect ed during this period is listed in Table 3-5. The results obtained from OHM are also included in the table for comparison purposes.
35As can be seen in Table 3-5, the measur ement differences of Hg (0) and Hg(VT) between OHM and SCEM were significant at the sampling locations before the ESP unit. The differences decreased as as the measuremen ts were conducted toward to the stack. It discrepancy is believed due to the different fly ash effects caused by the two sampling methods

Table 3-5 Mean value of SCEM Monitoring durin g the period of when only Kentucky coal was burned

36(a)
Mercury Concentration at APH Inlet (100% Kentucky Coal)

0 2000 4000 6000 8000 10000 12000

6/6/2006

0:00 6/6/2006 4:48 6/6/2006 9:36 6/6/2006 14:24 6/6/2006 19:12 6/7/2006 0:00 6/7/2006 4:48 6/7/2006 9:36 6/7/2006 14:24 6/7/2006 19:12 6/8/2006 0:00 Calendar DateMercury Concentration, ng/Nm3 APH Inlet Hg(V0) APH Inlet Hg(VT)

(b)
Mercury Concentration at ESP inlet (100% Kentucky Coal)

0 2000 4000 6000 8000 10000 12000 14000

6/6/06 0:00 6/6/06 4:48 6/6/06 9:36 6/6/06 14:24 6/6/06 19:12 6/7/06 0:00 6/7/06 4:48 6/7/06 9:36 6/7/06 14:24 6/7/06 19:12 6/8/06 0:00 Calendar DateMercury Concentration, ng/Nm3 ESP inlet Hg(VT) ESP inlet Hg(V0)

37(c) Mercury Concentration at ESP outlet (100% Kentucky Coal)

0 2000 4000 6000 8000 10000 12000

6/6/06 0:00 6/6/06 4:48 6/6/06 9:36 6/6/06 14:24 6/6/06 19:12 6/7/06 0:00 6/7/06 4:48 6/7/06 9:36 6/7/06 14:24 6/7/06 19:12 6/8/06 0:00
Calendar DateMercury Concentration, ng/Nm3 ESP outlet Hg(V0) ESP outlet Hg(VT)

(d)

Mercury Concentration at FGD Inlet (100% Kenyucky Coal)

0 2000 4000 6000 8000 10000 12000

6/6/2006

0:00 6/6/2006 4:48 6/6/2006 9:36 6/6/2006 14:24 6/6/2006 19:12 6/7/2006 0:00 6/7/2006 4:48 6/7/2006 9:36 6/7/2006 14:24 6/7/2006 19:12 6/8/2006 0:00 Calendar DateMercury Concentration, ng/Nm3 FGD Inlet Hg(V0) FGD Inlet Hg(VT)

38Mercury Concentration at Stack (100% Kentucky Coal)

0 500 1000 1500 2000 2500 3000

6/6/2006

0:00 6/6/2006 4:48 6/6/2006 9:36 6/6/2006 14:24 6/6/2006 19:12 6/7/2006 0:00 6/7/2006 4:48 6/7/2006 9:36 6/7/2006 14:24 6/7/2006 19:12 6/8/2006 0:00 Calendar DateMercury Concentration, ng/Nm3 Stack Hg(V0) Stack Hg(VT)

Figure 3-1. SCEM testing resu lts at (a) APH Inlet, (b) ESP Inlet, (c) ESP Outlet, (d) FGD Inlet, and (e) Stack during the Peri od of when 100% Kentucky coal was used

3.3. 70% Foreign Columbian Coal and 30% Petroleum Coke
The boiler was fed with 70% foreign Co lumbian coal and 30% petroleum coke during the testing pe riod from June 8 th and 9 th . Same as previous testing condition (i.e., 100% Kentucky coal), SCEM, Appendix K, and OHM were used to monitor the concentration and (or) specia tion distribution of Hg along th e flue gas path. Both OHM testing and SCEM monitoring were performed at APH inlet, ESP inlet, ESP outlet, FGD inlet, and stack. The analytical results from the three sets of OHM trains had to agree with each other within 10 % or the RD had to be less than 1 μ g/Nm 3 if the mercury concentration was measured to be lower than 5 μ g/Nm 3 for the test to be valid. Appendix K was installed on the stack.
The testing results during this period ar e discussed in the following section. The mercury data was dry-based and has been co rrected to 3% oxygen. The mercury data was dry-based and has been corrected to 3% oxygen.

3.3.1. OHM Results

Table 3-6 summarizes the results obtaine d from the 16 sets of OHM measuring conducted at the 5 testing location during this period. As can be seen, the ratio of Hg(0) to Hg(VT) has the highest value of 94.5% at APH inlet. Same as previous 100%

39Kentucky coal, the ratio decreases as the flue gas flows toward to the FGD inlet, where Hg(0)/Hg(VT) reaches the lowest value of 7.73 %. The ratio of Hg(0) to Hg(VT) become 54.3% after passing the FGD unit. Same as previous testin g condition, the re-mission of Hg(0) was also observed.
The emission of total Hg (i.e., Hg(T)) from this blended fuel (1.0 μ g/NM 3 or 0.69 lb/tBtu) was lower than what wa s observed from Kentucky coal (2.1 μ g/NM 3 or 1.45 lb/tBtu). The results correspond to the Hg content in this blended fuel and Kentucky coal (Table 3-1).
The Hg removal efficiencies of ESP and FGD can be calculated based on Table 3-6. It was found that ESP removed 13.6% and FG D removed 63.6% of the total Hg coming into the flue gas. A total of 77.2% remova l efficiency was reached. The equipped ESP and FGD units have very similar removal efficiency for Kentucky coal and a 70% Columbian coal-30% Petroleum coke blended fuel.
Table 3-6 OHM Hg monitoring results during the period of when 70% Columbian coal and 30% of petroleum coke was burned

403.3.2. Appendix K Results

The results for the Appendix K sorbent trap testing are summarized in Table 3-7. As can be seen, the Hg concentration in the second section of each tested trap was neither greater than 5ng nor 2% of the concentration detected in the first section. In addition, the recovery rates of the third spik ed section of each pair were found to be within ± 25% of the initial spiked mercury concentration, which meet the QA/QC requirements. By comparing the mean values of Appendix K results (0.67 μ g/NM 3 or 0.46lb/tBtu) to the results obtained from OHM (1.0 μ g/NM 3 or 0.69lb/tBtu), it is found that the difference between two measurements was within 1 μ g/NM 3

. Table 3-7 Appendix K results at the stack during period wh en 70% Columbian coal and 30% of petroleum coke was burned

3.3.3. SCEM Results

The SCEM mercury data of each 5 sampling locations (i.e. APH inlet, ESP inlet, ESP outlet, FGD inlet, and Stack) correspond ing to this testing period was used is summarized in Figure 3-2. The mean value of SCEM monitoring da ta collected during this period is listed in Table 3-8. The results obtained from OHM are also included in the table for comparison purposes. As can be seen in Table 3-8, the measurement differences of Hg (0) and Hg(VT) between OHM and SCEM were significant at the sampling locations before the ESP unit. The differe nces decreased as the measurements were conducted toward to the stack. The differenc e between the concentr ations of Hg (VT) measured by OHM and SCEM was 3%.
Table 3-8 Mean values of Hg SCEM Mon itoring Result during the Period of when 70% Columbian Coal and 30% of Petroleum Coke was Burne d

41(a)
Mercury Concentration at APH inlet (70% Columbian Coke and 30% Petroleum Coke)

0 1000 2000 3000 4000 5000 6000

6/8/2006

0:00 6/8/2006 4:48 6/8/2006 9:36 6/8/2006 14:24 6/8/2006 19:12 6/9/2006 0:00 6/9/2006 4:48 6/9/2006 9:36 6/9/2006 14:24 6/9/2006 19:12 6/10/2006 0:00 Calendar DateMercury Concentration, ng/Nm3 APH Inlet Hg(V0) APH Inlet Hg(VT)

(b) Mercury Concentration at ESP inlet (70% Columbian Coal and 30% Petroleum Coke)

0 1000 2000 3000 4000 5000 6000

6/8/2006

0:00 6/8/2006 4:48 6/8/2006 9:36 6/8/2006 14:24 6/8/2006 19:12 6/9/2006 0:00 6/9/2006 4:48 6/9/2006 9:36 6/9/2006 14:24 6/9/2006 19:12 6/10/2006 0:00 Calendar DateMercury Concentration, ng/Nm3 ESP inlet Hg(VT) ESP inlet Hg(V0)

42(c) Mercury Concentration at ESP outlet (70% Columbian Coal and 30% Petroleum Coke)

0 1000 2000 3000 4000 5000 6000

6/8/2006

0:00 6/8/2006 4:48 6/8/2006 9:36 6/8/2006 14:24 6/8/2006 19:12 6/9/2006 0:00 6/9/2006 4:48 6/9/2006 9:36 6/9/2006 14:24 6/9/2006 19:12 6/10/2006 0:00 Calendar DateMercury Concentration, ng/Nm3 ESP outlet Hg(VT) ESP outlet Hg(V0)

(d)

Mercury Concentration at FGD Inlet (70% Columbian Coal and 30% Petroleum Coke)

0 1000 2000 3000 4000 5000 6000

6/8/2006

0:00 6/8/2006 4:48 6/8/2006 9:36 6/8/2006 14:24 6/8/2006 19:12 6/9/2006 0:00 6/9/2006 4:48 6/9/2006 9:36 6/9/2006 14:24 6/9/2006 19:12 6/10/2006 0:00 Calendar DateMercury Concentration, ng/Nm3 FGD Inlet Hg(V0) FGD Inlet Hg(VT)

43Mercury Concentration at Stack (70% Columbian Coal an d 30% Petroleum Coke)

0 200 400 600 800 1000 1200 1400 1600 1800 2000

6/8/2006

0:00 6/8/2006 4:48 6/8/2006 9:36 6/8/2006 14:24 6/8/2006 19:12 6/9/2006 0:00 6/9/2006 4:48 6/9/2006 9:36 6/9/2006 14:24 6/9/2006 19:12 6/10/2006 0:00 Calendar DateMercury Concentration, ng/Nm3 Stack Hg(V0) Stack Hg(VT)

Figure 3-2 SCEM testing result s at (a) APH Inlet, (b) ESP In let, (c) ESP Outlet, (d) FGD Inlet, and (e) Stack during the Period of when 70% Columbian Coal and 30% Petroleum Coke was used

443.4. 35% Columbian Coal, 35% Kentucky Coal, and 30% Petroleum Coke

The boiler was fed with a bl ended fuel, which consists of 35% Columbian coal, 35% Kentucky coal and, 30% petroleum coke during the te sting period from June 10 th and 11 th . During this period, the SCEM was rema ined at monitoring mode before the appendix K sorbent trap and OHM sampling were initiated. The Appendix K sorbent trap method was installed in the morning and set in sampling service for eight hours. The OHM sampling was carried out isokinetically. The testing results during this period are discussed in the following section. The mercury data was dry-based and has been corrected to 3% oxygen.

3.4.1. OHM Results

In Table 3-9, the results obtained from the 16 sets of OHM measuring conducted at the 5 testing location during this period are summarized. As can be seen, the ratio of Hg(0) to Hg(VT) has the highest value of 74.6% at APH inlet. Same as previous two fuels tested, the ratio decreases as the flue gas flows toward to the FGD inlet, where Hg(0)/Hg(VT) reaches 10.5%. The ratio of Hg (0) to Hg(VT) become 72.6% after passing the FGD unit. The same Hg(0) re-e mission phenomena observed in the previous two fuels tested was also found.
Comparing with the other two fuels tested, th e emission of total Hg (i.e., Hg(T) of the stack) from this blended fuel (1.17 μ g/NM 3 or 0.81 lb/tBtu) was between what were found from the 70% Columbian coal-30% Petroleum coke (1.0 μ g/NM 3 or 0.69 lb/tBtu) and Kentucky coal (2.1 μ g/NM 3 or 1.53 lb/tBtu). The results correspond to the Hg content in the three fuels tested.
The Hg removal efficiencies of ESP and FGD can be calculated based on Table 3-9. It was found that ESP removed 14.6% and FG D removed 73.5% of the total Hg coming into the flue gas. A total of 88.1% remova l efficiency was reached. The equipped ESP has very similar removal effi ciency for all of the coals tested; i.e., 14.9%, 13.6%, and 14.6% for Kentucky coal, 70% Columbian Coal-30% Petroleum coke, and 35%Columbian Coal-35% Kentucky coal-30% Petroleum coke, respectively. For this type of coal, the FGD units have slightly higher removal efficiency than the other two coals. .

45Table 3-9 OHM Hg monitoring results duri ng period when 35% Columbian coal, 35% Kentucky coal and, 30% pe troleum coke was used.

3.4.2. Appendix K Results

The results for the Appendix K sorb ent trap testing are su mmarized in Table 3-10. As can be seen, the Hg concentration in the second section of each tested trap was slightly greater than 5 ng nor 2% of the conc entration detected in the first section. In addition, the recovery rates of the third spiked section of each pair were found to be within ± 25% of the initial spiked merc ury concentration, which meet the QA/QC requirements. By comparing the mean values of Appendix K results (0.67 μ g/dscm) to the results obtained from OHM (1.0 μ g/dscm), it is found that the difference between two measurements was within 1 μ g/dscm.

46Table 3-10 Appendix K Results at the stack during Period when 70% Columbian Coal and 30% of Petroleum Coke was used

3.4.3. SCEM Results

The SCEM mercury data of each 5 sampling locations (i.e. APH inlet, ESP inlet, ESP outlet, FGD inlet, and Stack) correspond ing to this testing period was used is summarized in Figure 3-3. The mean value of SCEM monitoring da ta collected during this period is listed in Table 3-11. The results obtained from OHM are also included in the table for comparison purposes. As can be seen in Table 3-11, the measurement differences of Hg (0) and Hg(VT) between OHM and SCEM were significant at the sampling locations before the ESP unit. The differences decreased as the measurements were conducted toward to the stack. The di fference between the concentrations of Hg (VT) measured by OHM and SCEM was 3%.
Table 3-11 Mean values of Hg SCEM monitoring result during the period of when 70% Columbian coal and 30% of petroleum coke was burned

47(a) Mercury Concentration at APH inlet (35% Columbian coal, 35% Kentucky coal and, 30% petroleum coke)

0 1000 2000 3000 4000 5000 6000 7000 8000

6/11/2006 0:00 6/11/2006 4:48 6/11/2006 9:36 6/11/2006 14:24 6/11/2006 19:12 6/12/2006 0:00 Calendar DateMercury Concentration, ng/Nm3 APH Inlet Hg(V0) APH Inlet Hg(VT)

(b)

Mercury Concentration at ESP Inlet 35% Columbian coal, 35% Kentucky coal and, 30% petroleum coke

0 1000 2000 3000 4000 5000 6000 7000 8000

6/10/2006

0:00 6/10/2006 4:48 6/10/2006 9:36 6/10/2006 14:24 6/10/2006 19:12 6/11/2006 0:00 6/11/2006 4:48 6/11/2006 9:36 6/11/2006 14:24 6/11/2006 19:12 6/12/2006 0:00
Calendar DateMercury Concentration, ng/Nm3 ESP inlet Hg(VT) ESP inlet Hg(V0)

48(c)
Mercury Concentration at ESP Outlet 35% Columbian coal, 35% Kentuck y

coal and, 30% petroleum coke

0 1000 2000 3000 4000 5000 6000 7000 8000

6/10/2006 0:00 6/10/2006 4:48 6/10/2006 9:36 6/10/2006 14:24 6/10/2006 19:12 6/11/2006 0:00 Calendar DateMercury Concentration, ng/Nm3 ESP outlet Hg(V0) ESP outlet Hg(VT)

(d)

Mercury Concentration at FGD Inlet (35% Columbian coal, 35% Kentucky coal, and 30% Petroleum coke)

0 1000 2000 3000 4000 5000 6000 7000 8000

6/10/2006

0:00 6/10/2006 4:48 6/10/2006 9:36 6/10/2006 14:24 6/10/2006 19:12 6/11/2006 0:00 6/11/2006 4:48 6/11/2006 9:36 6/11/2006 14:24 6/11/2006 19:12 6/12/2006 0:00 Calendar DateMercury Concentration, ng/Nm3 FGD Inlet Hg(V0) FGD Inlet Hg(VT)

49(e)
Mercury Concentration at Stack (35% Columbian coal, 35% Kentucky coal, 30% Petroleum coke)

0 200 400 600 800 1000 1200 1400 1600

6/10/06

0:00 6/10/06 4:48 6/10/06 9:36 6/10/06 14:24 6/10/06 19:12 6/11/06 0:00 6/11/06 4:48 6/11/06 9:36 6/11/06 14:24 6/11/06 19:12 6/12/06 0:00 Calendar DateMercury Concentration, ng/Nm3 Stack Hg(V0) Stack Hg(VT)

Figure 3-3 SCEM Testing Results at (a) APH Inlet, (b) ESP Inlet, (c) ESP Outlet, (d) FGD Inlet, and (e) Stack during the Peri od of when 70% Columbian Coal and 30% Petroleum Coke was Used

503.5. Hg Material Balance

3.5.1. Solid Sample Characterization

The LOI and concentrations of S, Cl, F, Br, and Hg in the fly ash produced by the three tested fuels were analyzed and the result s are listed in Table 3-12. As can be seen, the Hg concentration is higher in the Kentucky coal compared to the other blended fuels. However, the values of LOI and sulfur c ontent are higher in the two blended fuels compared to Kentucky coal. The mean values of chemical characte rization of each fly ash during the 2-day period were consistent.

Table 3-12 Chemical char acterization of fly ash

The concentrations of Hg in FGD slurry were analyzed and the results can be seen in Table 3-13. Before analysis, each FGD slurry was separated into liquid (FGD waste) and solid (ATF) sub-samples by filtrati on. As can be seen in the ta ble, the Hg contents in the FGD slurry samples produced by the three different fuels were very similar.
Table 3-13 Concentration of Hg in FGD slurry

The fly ash samples collected by the filters used in OHM testing were analyzed for Hg. Only two sampling locations before ESP unit collected enough fly ash sample for Hg analysis. The results are shown in Table 3-14.
The mineral compositions of ESP fly ash samples determined by XRF are listed in Table 3-15. For a given fly ash sample, SiO2 consists the majo rity of the fly ash sample followed by Al 2 O 3 and Fe 2 O 3 . The three mineral make out of over 90% of the fly ash, which is very similar to the mineral composition found in the ash fraction of the three fuels tested in this study (Table 3-2).

51Table 3-14 Hg Content in fl y ash collected by filter

52Table 3-15 Mineral composition of ESP fly ash

3.5.2. Material Mass Balance

Based on the OHM data and so lid sample analyses, the mercury material balance of each OHM run is calculated and shown in Table 3-16, 3-17, and 3-18. The average mercury input/output ratios of were cal culated to be 1.09, 1.23, and 1.22 for Kentucky coal, 70% Columbian coal-30% Petroleu m coke, and 35% Columbian coal-35% Kentucky coal-30% Petroleum coke, respectively.

53Table 3-16 Hg material balance of OHM run dur ing the period of when 100% Kentucky coal was used

54Table 3-17 Hg material balance of OHM run dur ing the period of when 70% Columbian coal-30% Petroleum coke was used

55Table 3-18 Hg material balance of OHM run during the period of when 35% Columbian coal-35% Kentucky coal-30% petroleum coke was used

56

### 4. Conclusion

4.1. Hg Emission from Unit 1 Stack
The emissions of total mercury (i.e., Hg (T)) from the unit 1 stack as well as the distribution of mercury species in the stack gas under three different fuel blending was measured with ASTM 6784-02 (also known as Ontario Hydro Method (OHM)), ICSET Semi-Continuous Mercury Emission Monitoring (SCEM) and EPA Appendix (sorbent trap method). The results have been summar ized in Table 1-1. It is found the emission of Hg from Unit 1 stack direct ly corresponded to the Hg content in the combusted fuels. The domestic Kentucky coal emits about double amounts of Hg emitted from the other two blended fuels. The Hg content in the Kentucky co al (ranging from 0.088 and 0.1 ppm for during a two-day testin g period) is about twice as observed in fuel 2 (ranging from 0.025 to 0.045 ppm) and 3 (ranging from 0.028 to 0.04ppm).

The differences between the three testing methods were all below 1 μ g/NM 3 . By using OHM, the Hg emissions of the thr ee fuels tested, i.e., Kentucky coal, 70% Columbian Coal-30% Petroleum coke, and 35% Columbian coal-35% Kentucky coal30% Petroleum Coke, were measured to be 2.10, 1.00, 1.17 μ g/NM 3 (i.e., 1.53, 0.69, 0.81lb/tBtu) respectively. The values were found to be 1.94, 1.03, and 1.09 μ g/NM 3 (1.41, 0.71, 0.81 lb/tBtu) by SCEM. In the case of Appendix K method, the emissions of total Hg with the three fuels were 1.58, 0.67, and 0.99 μ g/NM 3 (1.15, 0.46, 0.69 lb/tBtu) respectively. The differences among the three testing periods were found to be all below 5%. The distribution of Hg species measured by OHM and SCEM was found to be within 0.20 μ g/NM 3

. 4.2.Hg Removal Efficiency
Mercury emission directly relates to the mercury content in the coal and the performance efficiencies of the post combusti on and air pollutant control devices. Mercury removal efficiency is based on a combined effect of several controlling parameters (e.g., APCD configurations, te mperature change, ac id gaseous content (halogen), as well as fly ash reactivity and surface area.
Hg can be removed by ESP unit due to the adsorption of Hg onto fly ash. After the flue gas travels through the ai r-preheater (APH), from the in let at approximately 700 °F to the outlet at approximately 300 °F, th e mercury oxidation is complete. A lower temperature at the APH outlet increases the chances for mercury oxidation. A portion of the oxidized mercury binds with the fly ash and is captured by the ESP, and the remaining Hg (2+) is scrubbed out by the FGD. Because the Hg (0) portion does not react with moisture or fly ash, it is emitted from the stack.
The APCDs equipped in the Unit 1 have very similar Hg removal efficiency for the three coals tested. During the tes ting, Hg (T) was measured to be 13.79 μ g/Nm 3 (10.04 lb/tBtu) at the APH inlet and a concentra tion range of 10.50 (7.64 lb/tBtu) to 7.61 (5.54

57lb/Btu) μ g/Nm 3 at the ESP outlet while burning the Kentucky coal. For the 70% Columbian coal-30% Petroleum coke, Hg (T) was measured to be in a range of 4.19 and 4.86 μ g/Nm 3 at the APH inlet and 2.79 to 4.12 μ g/Nm 3 at the ESP outlet. In the case of the third blended fuel, the Hg emissions of th e three fuels tested, i.e., Kentucky coal, 70% Columbian Coal-30% Petroleum coke, and 35% Columbian coal-35% Kentucky coal30% Petroleum Coke, were m easured to be 2.10, 1.00, 1.17 μ g/NM 3 (i.e., 1.53, 0.69, 0.81lb/tBtu) respectively. The removal efficien cy of Hg based on the discussion above was calculated and it was found th at the results were very sim ilar. Based on the results obtained from OHM testing, it is found th at FGD unit removes 64.2, 63.6, and 73.5% of Hg for fuel 1, 2, and 3, respectively.
The LOI content in the fly ash is believed to play a significant role in capturing oxidized mercury through unburned carbon active sites. It is di rectly related to mercury oxidation and particulate mercury capture acro ss the ESP. According to solid sample analyses (discussed in 3-6), the mercury c ontent in the fly ash was found to fluctuate between 0.18 to 0.88 ppm for Kentucky coal an d the LOI content was found to be in a range of 3.97 to 6.7%. Howeve r, the fly ash produced by burning blended fuel 2 and 3 has much higher LOI, ranging from 18.45% to 35.99%. The high LOI values observed in the fly ash from fuel 2 and 3 did not result in a higher Hg removal efficiency for ESP. Other than LOI, halogen content, such as Cl, in coal has been identified as one of the main factors promoting mercury oxidation unde r high temperature a pplications within post-combustion processes. Generally speaking, higher chlorine content (preferably between 500-1000 ppm) increase s mercury oxidization. Kent ucky coal has higher Cl than the other two blended fuels. However, the contribution to a substantial reduction of Hg (0) emission was not found.

4.3. Hg Material Mass Balance
The detail mercury material balance calcu lation for each OHM run is discussed in each corresponding section. The data is also summarized in Ta ble 1-4. The ratio of Hg output/input at each sampling location falls between 0.99 to 1.27 for Kentucky coal, 1.14 to 1.34 for the 70% Columbian coal-30% pe troleum coke fuel, and 0.93 to 1.43 for the third blended fuels (i.e., 35% Columbian coal -35% Kentucky coal-30% petroleum coke). At the stack, the ratio was in a range of 0.93 to 1.17.

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### Appendix I: Conversion Factor for Converting μ g/NM 3 to lb/tBtu

Question : I used our plant heat rate of 9,750 BTU/KWHR, the unit lo ad during testing 632 MWs and the CEM stack flow (1,612,800 SC FM) to convert micrograms/standard cubic meter to lb/TBTU. I came out with diffe rent values than you di d in table 1-1. Is there a standard EPA factor that is used to make this conversion?

Answer : ICSET method is based on the elemental analysis from coals which was adopted by Southern Co and TXU. JEA method is based on the measurement of the flue gas. The conversion factor used in this report was calculated theoretically from the contents of C, S, H, and N in the coal. The deta il calculation formula is as following: 

# ( ) tBtu MMBtu V kgMMBtu kg lb g kg
CF F 3 %3, 9 10 / 2046.2 101

×× ⎟ ⎠ ⎞ ⎜ ⎝ ⎛ × ⎟ ⎠ ⎞ ⎜ ⎝ ⎛ ×

= − μ

where is the flue gas volume generated by unit coal corrected for 3% O %3, F V 2 , which can be calculated by
in NM 0 OH 0 df F 1)V-(a+V+VV

2 = %3, 3 /kg
in which,
, ,and are the dry flue gas volume ge nerated by unit coal corrected for 3% O 0 df V OH V

2 0 V

2 , water vapor in flue gas, and air volume required fo r complete combustion of per unit coal, respectively.

0 N SO CO 0 df 2 2 2 V+V+VV =

CoalinContent arbonC 0.01866 V

2

CO × =

CoalinContent Surfur 0.007 V

2

SO ×=

CoalinContent Nitrogen 0.008+0.79VV o 0 N × = 2 content Oxygen 0.0333-content ygrogenh0.265+content) surfur 0.375+content bon 0.0889(Car V 0 × × × = Content arbonCVa0.0161+Content Water 0.0124+Content Hygrogen 0.111 V o

OH

2 ××× × ×=

) 2 o 2 0 df O-(21V O V+1a
×

×=

gasflueincontent xygenoO = 2

Based on the C, N, S, O, and H contents as well as the oxygen concentration in flue gas, the CF values for the three fuels tested are 0.734, 0.694, and 0.696, respectively. If using the measured flow rate, the volume has to be corrected to 25oC as per EPA’s standard condition. An example of the calculati on spread sheet is a ttached as following:

59No Item Symbol Unit (E) Calculation Results (E) Unit (SI) Results (SI) 1 Carbon content in coal Cd % Coal analysis data 78.30 % 78.30 2 Hydrogen content in coal Hd % Coal analysis data 5.21 % 5.21 3 Oxygen content in coal Od % Coal analysis data 3.21 % 3.21 4 Nitrogen content in coal Nd % Coal analysis data 1.45 % 1.45 5 Sulfur content in coal Sd % Coal analysis data 3.11 % 3.11 6 Water value of coal W % Coal analysis data 1.08 % 1.08 7 Ash content in coal Ad % Coal analysis data 8.60 % 8.60 8 Heat value of coal Heat Btu/lb Coal analysis data 13720.00 kJ/kg 31910.49

O 2 Oxygen concentration in flue gas O 2 % measured data 4.00 % 4.00

No Item Symbol Unit (E) Calculation Results (E) Unit (SI) Results (SI) 1 Carbon content in coal Car % Coal analysis data 77.45 % 77.45 2 Hydrogen content in coal Har % Coal analysis data 5.15 % 5.15 3 Oxygen content in coal Oar % Coal analysis data 3.18 % 3.18 4 Nitrogen content in coal Nar % Coal analysis data 1.43 % 1.43 5 Sulfur content in coal Sar % Coal analysis data 3.08 % 3.08 6 Water value of coal War % Coal analysis data 1.07 % 1.07 7 Ash content in coal Aar % Coal analysis data 8.51 % 8.51 8 Heat value of coal Heat Btu/lb Coal analysis data 13720.00 MMBtu/kg 3.02E-02

14 Oxygen concentration in flue gas O 2 % measured data 4.00 % 4.00

No Item Symbol Unit (E) Calculation Results (E) Unit (SI) Results (SI)
1 Excess air factor a

- 1+V o DF *O 2 /(V o *(21- O 1.228 - 1.228

2 Air volume required for complete combustion of per unit coal V o ft 3 /lb 0.0889(Car+0.375Sa r 132.126 Nm 3 /kg 8.248

3 Characteristic coefficient of fuel b - 2.37(Har-0.126Oar)/( C 0.142 - 0.142

4 Dry flue gas generated by complete combustion of per unit coal V o DF ft 3 /lb V CO2 +V SO2 +V N2 o 128.060 Nm 3 /kg 7.994

5 CO 2 volume in flue gas V CO2 ft 3 /lb 0.01866Car 23.152 Nm 3 /kg 1.445
6 SO 2 volume in flue gas V SO2 ft 3 /lb 0.007S 0.345 Nm 3 /kg 0.022
7 N 2 volume in flue gas V N2 o ft 3 /lb 0.79V o +0.008Nar 104.563 Nm 3 /kg 6.528
8 Water vapor in flue gas V H2O ft 3 /lb 0.111Har+0.0124Wa r 11.988 Nm 3 /kg 0.748
9 Oxygen volume in flue gas V O2 ft 3 /lb 0.21( a -1)V o 6.328 Nm 3 /kg 0.395
10 Dry flue gas generated by per unit coal V DF ft 3 /lb V o DF +( a -1)V o 158.192 Nm 3 /kg 9.875
11 Real flue gas volume V F ft 3 /lb V o DF +V H2O +( a -1)V 0 170.180 Nm 3 /kg 10.624
12 Volume fraction of N 2 in dry flue gas N 2 % (V N2 o +0.79( a -1)*V o )/ V 81.147 % 81.147
13 Volume fraction of CO 2 in dry flue gas CO 2 % V CO2 /V DF *100 14.635 % 14.635
14 Volume fraction of SO 2 in dry flue gas SO 2 % V SO2 /V DF *100 0.218 % 0.2181
15 Volume fraction of O 2 in dry flue gas O 2 % V O2 /V DF *100 4.000 % 4.000
16 Excess air factor for 3% oxygen a 3% - 1+V o DF *3/(V o *(21-3 ) 1.162 - 1.162 17 Dry flue gas generated by per unit coal for O 2 3% V DF3% ft 3 / lb V o DF + ( a 3% -1 ) V o 149.403 Nm 3 /k g 9.327 18 Water vapor in flue gas V H2O ft 3 /lb 0.111Har+0.0124Wa r 11.847 Nm 3 /kg 0.740

19 Re al fl u e ga s vol u m e ge n e r a t e d by pe r un i t c oal fo e O 2 3% V F3% ft 3 /lb V o F +V H2O +( a -1)V 0 161.391 Nm 3 /kg 10.075

20 Flue gas generated by complete combustion of per unit coal V o F ft 3 /lb V o DF +V H2O 0 139.563 Nm 3 /kg 8.713

No Item Symbol Unit (E) Calculation Results (E) Unit (SI) Results (SI) 8 Conversion factor form ug/m3 to lb/TMMBtu 0.734 1.Coal Analysis Data and Oxygen Concontration Input Sheet

2. Conversion of Coal Analysis Data

3. Calculation of Flue Gas Characteristics

4. Conversion Factor

60Comparing with the calc ulation method applied by St. John ’s River Power Park described in the following table, it is found that the conversion factor is 0.931, which is higher than
what is calculated from the coal com position. The discrepancy between the two calculation methods might be due to mainly the assumption of boiler efficiency. 100% boiler efficiency was assumed in the calcu lation method used in this study. If considering 0.9 predicted capacity factor (335 days of boiler working hours per year) and 0.85 boiler efficiency, the convers ion factors obtained by the two methods are very close.

The chemical characterization of each coal used in this study is listed in the following table



### Mercury Testing Calculator

2.1 micrograms/cubic meter inputs 2.2046E-09 lb/microgram outputs

1,612,800 standard cu ft/min CEM gas flow rate 0.882421

0.02832 cu meter/cu ft 0.750058 45674.496 cu meter/min gas flow rate 0.000211457 lb/min 525600 min/yr 111.1420027 lb/year for each unit for 100% capacity factor 0.9 predicted capacity factor 0.000190312 lb/min for each unit 100.03 lb/yr for each unit

95 lb/yr predicted allowance per unit in 2010 1 million tons of domestic allows us to run 2/2/2 The remaining time to be 70% CMC and 30% petcoke 632 MWs 9750 BTU/KWHR 71.43% 2/2/2 produces 42.01848 lb/yr/unit 6162000000 BTU/HR 28.57% 4 CMC/2 PC produces 14.36529 lb/yr/unit 0.006162 TBTU/hr TOTAL 56.38 lb/yr/unit 0.0001027 TBTU/min 1.85 lb/TBTU

The chemical characterization of each coal used in this study is listed in the following table.

Moisture Ash Vol. Mat Sulfur Btu Carbon Hydrogen Nitrogen Oxygen Chloride Mercury Fluoride Bromide

SampleName % % % % BTU/lb % % % % ppm ppm ppm ppm Kentucky Coal 3.21575 8.4633 36.0471 1.2041 12905.7 73.774 5.361 1.48458 9.713 1090.04 0.07395 ND ND Columbian Coal 4.90292 7.2045 36.2739 0.9721 12652.8 72.782 5.42425 1.40525 12.21 349.283 0.03603 ND ND Petroleum Coke 0.81522 1.7272 16.1563 5.4331 14551.5 84.182 4.111667 1.52667 4.753 382.12 0.02288 ND ND

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### Appendix II: Effect of Vanadium on the Conversion of Hg(0) to Hg(2+)

Question 2: I also tried to pr edict what our emissions w ould be with the scrubber bypass closed (we had approx. 7% flow through the by-pass during our testing). I would appreciate it if you could l ook it over and see if you spot any mistakes. An interesting result occurred when I tried to predict what each of our three fuels would discharge if burned alone (equations at the bot tom of the spreadsheet). I e quated the test results with the percentages of fuels burned and then solv ed the simultaneous equations to derive the values for 100% foreign coal and 100% petc oke. The petcoke actually came out to be a negative value. At first I thought that this was simply a math error or just an indication of the variability in the data, however after thinking about it, I'm not so sure. During the test, Dr. Cao and I discussed the potentially beneficial effects of the vanadium in the petcoke. We speculated that the oxidizing qu alities of vanadium may be promoting the conversion of Hg(0) to Hg(2+) which can then be removed in the scrubber. The negative value of a 100% petcoke burn may be an in dication of this phenomena. Have you and Dr. Cao had any other discussions on this topic?

Answer : The predicted calculation is reasonable. Three reasons might result in the negative value (or zero emission) of Hg by burning Petcoke. Firstly, low Hg content in Petcoke, i.e., 0.01 ppm. Secondly, the presen ce of strong oxidation agents, such as vanadium oxides, is in the petcoke. Vana dium oxide is the main constitute in SCR catalyst, which is surely can promote the conversion of Hg(0)to Hg(2+). Hg(2+) is then removed in the JEA's scrubber very efficienc tly. We notice that th ere is no re-emission occurred in JEA's wet scrubber. Thirdly, there maybe some inte raction on Hg(2+)when blending coals burned. Also, the calcula tion was based on assuming exact bending ratios between fuels. Slightly change of the bl ending might result in a different calculation result. It was found that a 10% derivation fr om a wanted blending ratio (63% Columbian coal and 37% of petroleum coke) can result in a positive P value.

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