FUNDAMENTAL RESEARCH OF MERCURY 

SPECIATION UNDER VARIOUS OPERATING 

PARAMETERS AT ST. JOHN’S RIVER POWER PARK 

Submitted to: 

Larry Bradley 

Superintendent, Technical, Fuels Procurement & 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 Science and Environmental Technology 

Western Kentucky University 

2413 Nashville Road 

Bowling Green, Kentucky 42101, U.S.A. 

July 16, 2006 
ICSET 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 service 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 Method - 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 Quality 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 

i 
3.4.1. 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 μg/NM3 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 Chart and Photos of the Leeman System.............. 21 

Figure 2-7 Diagram and Photos of the SCEM System .................................................... 22 

Figure 2-8 Hg Sampling Train Illustrating Single Trap................................................... 24 

Figure 2-9 SCEM Mercury Sampling, Analytical and QA/QC Procedures.................... 28 

Figure 2-10 Schematic Description of OHM Mercury Sampling, Analytical and QA/QC 

Procedures................................................................................................. 29 

Figure 3-1. SCEM testing results 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 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 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, SCEM 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 during 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 monitoring result during the period of when 70% 

Columbian Coal and 30% of petroleum coke was burned.............................. 41 

Table 3-9 OHM Hg monitoring results during 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 characterization 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 

iv 
Table 3-15 Mineral composition 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 details concerning a fundamental research aimed to study 

transformation of mercury speciation along the flue gas path under one consistent boiler 

load (632 ±10MWe) with three 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), and 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 this 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 measured with ASTM 6784-02 (also known as 

Ontario Hydro Method (OHM)), Institute 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 efficiency of the air pollution control devices 

(APCDs) and to validate the three testing methods. The acceptable range is 

between 80%-120%. 

The tested unit was set to the testing targeted 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) 

1 
and EPA Appendix (sorbent trap method). The results were summarized in Table 1-1. 

As can be seen, the differences between the three testing methods were all below 

1μg/NM3. 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 μg/NM3

. 

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 through the air pre-heater 

(APH), from the inlet at approximately 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 mercury oxidization. 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. Since the Hg (0) portion does not react 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, respectively. The removal efficiencies determined 

by SCEM are not much different from what were obtained from the OHM. 

2 
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 directly related to mercury 

oxidation and particulate mercury capture across 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 and the LOI content was found to be in a 

range of 3.97 to 6.7%. However, 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 under high temperature applications within 

post-combustion processes. Generally speaking, higher chlorine content (preferably 

between 500-1000 ppm) increases mercury oxidization. Kentucky 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 obtained 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 higher than the values calculated from SCEM 

data. 

Object 4

The concentration and speciation distribution 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 elemental form. However, the value 

was found to be slightly above 36% by SCEM results. The discrepancy is believed to be 

due to the different interaction of Hg and fly ash on their different filtration mechanism. 

3 
Table 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 Table 1-4. It is shown that 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. 

4 
Table 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-Fired 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% Kentucky Coal, and 30% Petroleum Coke 

The configuration of Unit 1 is shown in Figure 2-1. 

Figure 2-1 Unit 1 Configuration 

6 
2.2. 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 and 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, therefore, 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 the ESP inlet duct C and outlet duct C to 

determine the Hg speciation partitioning, namely, Hg (0), Hg (p) and Hg (T). This 

is also to further determine the Hg formation 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 stack 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. FGD 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 slurry) were collected and analyzed. By 

coupling the results obtained from vapor-phase Hg sampling, mercury material 

balance can be calculated. Detail solid sample 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 operating only period: two sets of coal samples 

were collected daily. The first set was collected 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.

7 
2.2.2. Sampling Schedule

This project includes three days for travel, 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), instrumentation was takendown and demobilized. Detail sampling schedule can be seen in Table 2-1. . 

Figure 2-2 Sampling Arrangement 

8 
9 

Figure 2-3 Solid Sample Collecting Arrangement 
10 

Table 2-1 Testing Schedule for St. John River Park Unit 1 
 

2.3. Methodology and Instrumentation 

2.3.1. Flue Gas Sampling System 

For a given sampling location, flue gas samples were collected by a versatile 

isokinetic sampling system specifically provided by Apex Instruments. 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, respectively. A glass fiber filter assembly is enclosed 

in a temperature-controlled heated sample box, in which the temperature were kept at 

248±25o

F. The nozzle, probe liner, connecting glassware, and filter are referred to as the 

“front-half” of the sample train. Following the filter is a condensation section, which is 

also known as the “back-half” of the sample train. The back half is cooled in an ice bath 

and kept at temperature below 68oF. 

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 and coarse metering valves. It also provides 

gas volume, sampling velocity, pressure, and temperature readings with respect to 

sampling conditions through flow meter, manometer, vacuum gauge, and digital display, 

respectively. 

This system permits sampling of vertical points or space-limited locations. After flue 

gas is collected, it passes through a set of impingers containing various solutions prepared 

depending on testing objectives. 

 During sampling, three types of sampling system leak check were perform; i.e., 

pre-test, during test, and post-test leak checks, as one of the quality assurance procedures. 

 

Figure 2-4 Apex Isokinetic Sampling System 

18
 

2.3.2. 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 coal-fired stationary sources. 

OHM is the only EPA method approved by ASTM (Method D6784) for measuring and 

speciating mercury in flue gas. The standard OHM consists of three key elements: 

isokinetic sampling, recovery, and solution analysis. All OHM sampling and analytical 

activities in ICSET followed EPA quality assurance/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 system. Flue gas was force passing through a 

series of impingers in an ice bath (Figure 2-5). Particle-bound mercury is then collected 

in the front half of the sampling train on a quartz fiber filter. Oxidized mercury is 

collected in impingers containing a chilled aqueous potassium chloride solution. 

Elemental mercury is collected in subsequent impingers (one impinger containing a 

chilled aqueous acidic solution of hydrogen peroxide and three impingers containing 

chilled aqueous acidic solutions of potassium permanganate). 

After sampling, all solutions are then recovered and digested 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, H2O2/HNO3, and 

KMnO4/H2SO4) recovered from perspective impingers were transferred to a 15-mL 

digestion cup, in which 0.2 mL concentrated H2SO4, 0.1 mL concentrated HNO3, 1.2 mL 

5% KMnO4, and 0.32 mL of 5% K2S2O8 was added automatically to each cup through a 

dispenser. The cups were heated in a water bath at a constant temperature of 95oC for 

two hours. After cooling, 1.333 mL of 12%:12% NaCl: hydroxylamine sulfate was 

added to prepare the solution ready for mercury analysis by a cold-vapor atomic 

absorption or fluorescence spectroscopy (Leeman Lab Hydra, Teledyne Leeman Labs, 

NH). During analysis, 5% HNO3 was employed as the rinse solution and 10% 

SnCl2/10% HCl solution was utilized as the reductant agent. The peristaltic pump was 

controlled at 5 mL/min, while the carrier gas was ultra high purity grade nitrogen flowing 

at a rate of 0.6 L/min. The OHM testing flow chart and the Leeman system can be seen in 

Figure 2-6. 

19
 

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

20
 

Figure 2-6 The OHM Analysis Flow Chart and Photos of the Leeman System. 

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

A mercury semi-continuous emission monitoring 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 200o

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 condensation 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 and blank at typically 14 

liters per minute. These gases go through the valve-switching box and can be directed to 

21
 

 

Figure 2-7 Diagram and Photos of the SCEM System 

the probe to completely check the system bias. The second probe was supplied by 

Apogee. 

22
 

2.3.4. EPA Appendix K

This method is used for the continuous sampling of mercury (Hg) emissions in 

combustion flue gas streams with sorbent traps. 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 extracted 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 performed by existing recognized procedures, 

such as that contained in ASTM Method D6784-02 or EPA Method 29. 

Sampling instruments used in this study included: 

Hg Sampling Train. A Schematic of a single trap sampling 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 performed 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 criteria 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 Method 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 should be obtained from a reliable source that 

has clean handling procedures in place for ultra 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 sorbent trap is the entire Hg sample. 

23
 

Figure 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 heating is required. For 

duct temperatures less than 200/F, the sorbent tube must be heated to at least 

200oF or higher to avoid liquid condensation in the sorbent 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 capable 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, Appendix A Method 5, to measure the total sample volume 

collected. The dry gas meter must be sufficiently accurate to measure the sample 

volume within 2 percent, calibrated at the selected flow rate and conditions 

24
 

actually encountered during sampling, and equipped with a temperature sensor 

capable of measuring typical meter temperatures accurately to within 3/C (5.4/F). 

Sample Analysis Equipment. Laboratory equipment required for analysis by AF. For 

analysis by AA, refer to Method 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 Combustion Emissions Monitoring System was 

used for measuring H2S (<2000 ppm), CO (1-10%), O2, NO and SO2. During each 

sampling run, this system was periodically used for leak check. 

25
 

2.4. Analytical Quality Assurance and Quality 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 described in this summary are highlights of these 

procedures and are by no means a comprehensive summary. Quality control for the 

Ontario Hydro Method starts at the very beginning 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 HNO3 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 twice 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-calibrated 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 sampling 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 during 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 blank 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 expected that these samples were at or below the 

detection limits of the instrument. 

Spikes 

 As part of the QA/QC, a field spike was associated 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 recovery 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. First, 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. Preliminary calculations include velocity, moisture, 

26
 

stack 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 with a calculator. Standardized 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 concentrations 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 data 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 include recalculation of results, data entry 

checks, and calculation of known and accepted data sets using the existing spreadsheet. 

2.4.1.Sample Identification and Chain of Custody

Samples are identified with unique sample numbers and descriptive notations. 

Custody of samples is maintained by WKU personnel; 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 logging 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, instrumentation, and other technical data is available upon request. 

The general SCEM and OHM QA/QC procedures are presented in Figure 2-9 and Figure 

2-10, respectively. 

The major QA/QC components for the EPA Appendix K method are outlined in 

Table 2-3. 

27
 

28

Oxygen 

analysis

Frequent 

replacement of 

syringe and 

septum

Independent 

check of MFC

Direct 

measurement

of HgO source 

(CavKit outlet)

Oxygen 

analysis

Sample Gas 

Conditioning 

& Transport

Direct 

instrument 

calibration

Independent 

check leakage 

of probe

Figure 2-9 SCEM Mercury Sampling, Analytical and QA/QC Procedures 

High span

Blank

Gold trap & Hg Lamp

High span

Blank

Sample Gas

Extraction Hg 

Measurement

High span

Blank
29

gas

Sam pling and Recovery Digestion Analysis

D ata V alid

Sa m pling environm enta l conditions: H Cl/SO 2 H 2O

 Ash lo ad Fly ash LO I Temperature D uct co nfiguratio n

Instrument 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 materials

Pre & Po st - test: Leak Check Temperature check

Iso k inetic ChecM oisture contenHg & speciatio n 

F ield blankS p ike

Solution preparatio n: D aily

N a 2S2O 3 , S o lut io n co lo r mo nito ring

M o re im pingersAsh-free pro beEPA M ethodTraverse

Figure 2-10 Schematic Description of OHM Mercury Sampling, Analytical and QA/QC Proced

N O

Immediate analysisCo ntam ination free op eratio nPressure stabilityStandard so lutio n calibratio nP um p rate stability

Chemicals:Trace M etal Deg ree Chemicals

Sampl e s pl i t
 

Table 2-3 QA/QC for Appendix K samples 

30
 

2.5. 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 was determined as per ASTM Method D 5142 

using TGA 601 or TGA 701 thermogravimetric analyzer (Leco, MI). The ultimate 

analysis for carbon and sulfur was determined 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 Mercury Analyzer (Leco Co, MI), which 

directly combusts solid samples at 750oC and applies atomic adsorption 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 has a 0.01 ng Hg detection limit 

with a working range from 0.05 to 600 ng. The 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 arrived on site at St. John’s River Power 

Plant Unit 1 on June 5, 2006, and started setting 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 collected 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 during a two-day testing period were consistent. 

The Hg content of Kentucky coal was found higher 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, SiO2 makes up over 50% of mineral composition for the ash fractionl, followed by 

Al2O3 and Fe2O3. 

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

6

Kentucky coal was tested on May 6th and 7th, 70% Columbian Coal-30% petroleum Coke was tested on 

May 8th and 9th. The 35% Columbian coal/35% Kentucky coal/30% petroleum coke was tested on May 

10th and 11th. 

32
 

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

Kentucky coal was tested on May 6th and 7th, 70% Columbian Coal-30% petroleum Coke was tested on 

May 8th and 9th. The 35% Columbian coal/35% Kentucky coal/30% petroleum coke was tested on May 

10th and 11th. 

The SCEM was set to be in monitoring service starting from June/6/06 to 

continuously record concentration and species distribution of Hg at 5 different sampling 

locations along the flue gas path (i.e., APH inlet, 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 particle-bound mercury (Hg (p)). The vapor-phase total (Hg 

(VT)) is the sum of the oxidized portion and elemental portion excluding 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 undetectable (ND), or insufficient amount of ash sample. 

33
 

3.2. 100% Domestic Kentucky Coal 

The boiler was fed with 100% Kentucky coal on June 6th and 7th. The SCEM was set 

to be in 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. 

3.2.1. 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 8.07μg/NM3 (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 concentration of Hg (2+) increased after passing the ESP 

unit, which is 7.09 μg/NM3

 (4.92 lb/tbtu) compared to 2.62 μg/NM3 (1.82 lb/tbtu) at the 

ESP inlet. The ESP unit significantly changed the distribution of Hg species. The 

transformation of Hg species was also observed 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 highest 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 the removal of oxidized mercury. 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 efficiencies of ESP and FGD can be calculated. 

It was found that ESP removed 14.9% and FGD 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 section of each tested trap was neither greater 

than 5 ng nor 2% of the concentration detected 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 the QA/QC requirements. By comparing the 

mean values of Appendix K results (1.58 μg/dscm) to the results obtained from OHM 

(2.10μg/dscm), it is found that the difference between two measurements was within 1 

μg/dscm. 

34
 

Table 3-3 OHM Hg monitoring results during 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) corresponding to the period of when only domestic 

Kentucky coal was used is summarized in Figure 3-1. The mean value of SCEM 

monitoring data collected during this period is listed in Table 3-5. The results obtained 

from OHM are also included in the table for comparison purposes. 

35
 

As can be seen in Table 3-5, 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 as the measurements 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 during 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 Date

Mercury 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 Date

Mercury 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 Date

Mercury 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 Date

Mercury Concentration, ng/Nm3

FGD Inlet Hg(V0) FGD Inlet Hg(VT)

38
 

Mercury 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 Date

Mercury Concentration, ng/Nm3

Stack Hg(V0) Stack Hg(VT)

Figure 3-1. SCEM testing results 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 

 

3.3. 70% Foreign Columbian Coal and 30% Petroleum Coke 

The boiler was fed with 70% foreign Columbian coal and 30% petroleum coke 

during the testing period from June 8th and 9th. Same as previous testing condition (i.e., 

100% Kentucky coal), SCEM, Appendix K, and OHM were used to monitor the 

concentration and (or) speciation distribution of Hg along the 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 μg/Nm3

 if the mercury 

concentration was measured to be lower than 5 μg/Nm3

 for the test to be valid. Appendix 

K was installed on the stack. 

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. The mercury data was 

dry-based and has been corrected to 3% oxygen. 

3.3.1. OHM Results 

Table 3-6 summarizes the results obtained 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% 

39
 

Kentucky 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 testing condition, the re-mission of 

Hg(0) was also observed. 

The emission of total Hg (i.e., Hg(T)) from this blended fuel (1.0μg/NM3 or 0.69 

lb/tBtu) was lower than what was observed from Kentucky coal (2.1μg/NM3 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 FGD removed 63.6% of the total Hg coming 

into the flue gas. A total of 77.2% removal 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 

 

 

40
 

3.3.2. 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 spiked 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 (0.67μg/NM3 or 0.46lb/tBtu) to the 

results obtained from OHM (1.0μg/NM3 or 0.69lb/tBtu), it is found that the difference 

between two measurements was within 1 μg/NM3. 

Table 3-7 Appendix K results at the stack during period when 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) corresponding to this testing period was used is 

summarized in Figure 3-2. The mean value of SCEM monitoring data 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 differences decreased as the measurements were 

conducted toward to the stack. The difference between the concentrations of Hg (VT) 

measured by OHM and SCEM was 3%. 

Table 3-8 Mean values of Hg SCEM Monitoring Result during the Period of when 70% 

Columbian Coal and 30% of Petroleum Coke was Burned 

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 Date

Mercury 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 Date

Mercury 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 Date

Mercury 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 Date

Mercury Concentration, ng/Nm3

FGD Inlet Hg(V0) FGD Inlet Hg(VT)

43
 

Mercury Concentration at Stack 

(70% Columbian Coal and 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 Date

Mercury Concentration, ng/Nm3

Stack Hg(V0) Stack Hg(VT)

Figure 3-2 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 

44
 

3.4. 35% Columbian Coal, 35% Kentucky Coal, and 30% Petroleum Coke 

The boiler was fed with a blended fuel, which consists of 35% Columbian coal, 

35% Kentucky coal and, 30% petroleum coke during the testing period from June 10th

and 11th. During this period, the SCEM was remained 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-emission phenomena observed in the previous 

two fuels tested was also found. 

Comparing with the other two fuels tested, the emission of total Hg (i.e., Hg(T) of the 

stack) from this blended fuel (1.17μg/NM3 or 0.81 lb/tBtu) was between what were found 

from the 70% Columbian coal-30% Petroleum coke (1.0μg/NM3 or 0.69 lb/tBtu) and 

Kentucky coal (2.1μg/NM3

 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 FGD removed 73.5% of the total Hg coming 

into the flue gas. A total of 88.1% removal efficiency was reached. The equipped ESP 

has very similar removal efficiency 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. . 

45
 

Table 3-9 OHM Hg monitoring results during period when 35% Columbian coal, 35% 

Kentucky coal and, 30% petroleum coke was used. 

 

3.4.2. Appendix K Results

 The results for the Appendix K sorbent trap testing are summarized 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 concentration 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 mercury concentration, which meet the QA/QC 

requirements. By comparing the mean values of Appendix K results (0.67μg/dscm) to 

the results obtained from OHM (1.0μg/dscm), it is found that the difference between two 

measurements was within 1 μg/dscm. 

46
 

Table 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) corresponding to this testing period was used is 

summarized in Figure 3-3. The mean value of SCEM monitoring data 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 difference 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 Date

Mercury 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 Date

Mercury Concentration, ng/Nm3

ESP inlet Hg(VT) ESP inlet Hg(V0)

48
 

(c) 

Mercury Concentration at ESP Outlet 

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

Calendar Date

Mercury 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 Date

Mercury 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 Date

Mercury 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 Period of when 70% Columbian Coal and 30% 

Petroleum Coke was Used 

50
 

3.5. 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 results 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 content are higher in the two blended fuels 

compared to Kentucky coal. The mean values of chemical characterization of each fly 

ash during the 2-day period were consistent. 

Table 3-12 Chemical characterization 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 filtration. As can be seen in the table, 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 majority of the fly ash sample 

followed by Al2O3 and Fe2O3. 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). 

51
 

Table 3-14 Hg Content in fly ash collected by filter 

52
 

Table 3-15 Mineral composition of ESP fly ash 

3.5.2. Material Mass Balance

Based on the OHM data and solid 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 calculated to be 1.09, 1.23, and 1.22 for Kentucky 

coal, 70% Columbian coal-30% Petroleum coke, and 35% Columbian coal-35% 

Kentucky coal-30% Petroleum coke, respectively. 

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
 

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 summarized in Table 1-1. It is found the emission 

of Hg from Unit 1 stack directly 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 coal (ranging from 0.088 and 0.1 

ppm for during a two-day testing 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 1μg/NM3. By 

using OHM, the Hg emissions of the three 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 μg/NM3

 (i.e., 1.53, 0.69, 

0.81lb/tBtu) respectively. The values were found to be 1.94, 1.03, and 1.09μg/NM3

(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 0.99μg/NM3 (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 μg/NM3

. 

4.2.Hg Removal Efficiency 

Mercury emission directly relates to the mercury content in the coal and the 

performance efficiencies of the post combustion and air pollutant control devices. 

Mercury removal efficiency is based on a combined effect of several controlling 

parameters (e.g., APCD configurations, temperature change, acid 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 air-preheater (APH), from the inlet at approximately 700 °F 

to the outlet at approximately 300 °F, the 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 testing, Hg (T) was measured to be 13.79 μg/Nm3 (10.04 

lb/tBtu) at the APH inlet and a concentration range of 10.50 (7.64 lb/tBtu) to 7.61 (5.54 

57
 

lb/Btu) μg/Nm3 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 μg/Nm3

 at the APH inlet and 2.79 to 4.12 μg/Nm3 at the ESP outlet. In the case of 

the third blended fuel, the Hg emissions of the three 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 μg/NM3 (i.e., 1.53, 0.69, 

0.81lb/tBtu) respectively. The removal efficiency of Hg based on the discussion above 

was calculated and it was found that the results were very similar. Based on the results 

obtained 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 LOI content in the fly ash is believed to play a significant role in capturing 

oxidized mercury through unburned carbon active sites. It is directly related to mercury 

oxidation and particulate mercury capture across the ESP. According to solid sample 

analyses (discussed in 3-6), the mercury content in the fly ash was found to fluctuate 

between 0.18 to 0.88 ppm for Kentucky coal and the LOI content was found to be in a 

range of 3.97 to 6.7%. However, 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 under high temperature applications within 

post-combustion processes. Generally speaking, higher chlorine content (preferably 

between 500-1000 ppm) increases mercury oxidization. Kentucky 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 calculation for each OHM run is discussed in each 

corresponding section. The data is also summarized in Table 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% petroleum 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. 

 

58
 

Appendix I: Conversion Factor for Converting μg/NM3 to lb/tBtu 

Question: I used our plant heat rate of 9,750 BTU/KWHR, the unit load during testing 

632 MWs and the CEM stack flow (1,612,800 SCFM) to convert micrograms/standard 

cubic meter to lb/TBTU. I came out with different values than you did 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 detail calculation formula is as following: 

( ) tBtu V MMBtu

kgMMBtu

kg

lb

g

kg

CF F

3

%3,

9

10

/

101 2046.2

××

⎟

⎠

⎞ ⎜

⎝

⎛ ⎟×

⎠

⎞ ⎜

⎝

⎛ ×

=

−

μ

where VF %3, is the flue gas volume generated by unit coal corrected for 3% O2, which can 

be calculated by 

F %3, = df

0

2OH 1)V-(a+V+VV 0 in NM3

/kg 

in which, , ,and are the dry flue gas volume generated by unit coal corrected 

for 3% O

0 Vdf V 2OH0 V

2, water vapor in flue gas, and air volume required for complete combustion of 

per unit coal, respectively. 

0

CO SO N

0

df 2 2 2 = V+V+VV

V 0.01866 arbonC CoalinContent CO 2 = ×

V 0.007 Surfur CoalinContent SO2 ×=

0.008+0.79VV Nitrogen CoalinContent 0 o

N = × 2

V 0.0889(Car 0.375+content bon 0.0333-content ygrogenh0.265+content) surfur content Oxygen 0 = × × ×

V 0.111 0.0124+Content Hygrogen arbonCVa0.0161+Content Water Content o

2OH ×= × ×××

) 2

o

0 2

df O-(21V

O V+1a

×

×=

= xygenoO gasflueincontent 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 calculation spread sheet is attached as following: 

59
 

No 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

O2 Oxygen concentration in flue gas O2 % 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 O2 % measured data 4.00 % 4.00

No Item Symbol Unit (E) Calculation Results (E) Unit (SI) Results (SI)

1 Excess air factor a - 1+Vo

DF*O2/(Vo

*(21-O 1.228 - 1.228

2 Air volume required for complete combustion of per 

unit coal

Vo ft3

/lb 0.0889(Car+0.375Sar 132.126 Nm3/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

Vo

DF ft3

/lb VCO2+VSO2+VN2

o 128.060 Nm3

/kg 7.994

5 CO2 volume in flue gas VCO2 ft3

/lb 0.01866Car 23.152 Nm3/kg 1.445

6 SO2 volume in flue gas VSO2 ft3

/lb 0.007S 0.345 Nm3/kg 0.022

7 N2 volume in flue gas VN2

o

ft3/lb 0.79Vo

+0.008Nar 104.563 Nm3

/kg 6.528

8 Water vapor in flue gas VH2O ft3

/lb 0.111Har+0.0124War 11.988 Nm3/kg 0.748

9 Oxygen volume in flue gas VO2 ft3

/lb 0.21(a-1)Vo 6.328 Nm3/kg 0.395

10 Dry flue gas generated by per unit coal VDF ft3

/lb Vo

DF+(a-1)Vo 158.192 Nm3

/kg 9.875

11 Real flue gas volume VF ft3

/lb Vo

DF+VH2O+(a-1)V0 170.180 Nm3

/kg 10.624

12 Volume fraction of N2 in dry flue gas N2 % (VN2

o

+0.79(a-1)*Vo)/V 81.147 % 81.147

13 Volume fraction of CO2 in dry flue gas CO2 % VCO2/VDF*100 14.635 % 14.635

14 Volume fraction of SO2 in dry flue gas SO2 % VSO2/VDF*100 0.218 % 0.2181

15 Volume fraction of O2 in dry flue gas O2 % VO2/VDF*100 4.000 % 4.000

16 Excess air factor for 3% oxygen a3% - 1+Vo

DF*3/(Vo

*(21-3) 1.162 - 1.162

17 Dry flue gas generated by per unit coal for O2 3% VDF3% ft3

/lb Vo

DF+(a3%-1)Vo 149.403 Nm3

/kg 9.327

18 Water vapor in flue gas VH2O ft3

/lb 0.111Har+0.0124War 11.847 Nm3/kg 0.740

19

Real flue gas volume generated by per unit coal foe

O2 3% VF3% ft3

/lb Vo

F+VH2O+(a-1)V0 161.391 Nm3

/kg 10.075

20 Flue gas generated by complete combustion of per 

unit coal Vo

F ft3

/lb Vo

DF+VH2O

0 139.563 Nm3

/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

60
 

Comparing with the calculation 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 composition. The discrepancy between the two 

calculation methods might be due to mainly the assumption of boiler efficiency. 100% 

boiler efficiency was assumed in the calculation 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 conversion 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

61
 

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

Question 2: I also tried to predict what our emissions would 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 look 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 bottom of the spreadsheet). I equated the test results with 

the percentages of fuels burned and then solved the simultaneous equations to derive the 

values for 100% foreign coal and 100% petcoke. 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 qualities 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 indication 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 presence of strong oxidation agents, such as 

vanadium oxides, is in the petcoke. Vanadium 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 efficienctly. We notice that there is no re-emission 

occurred in JEA's wet scrubber. Thirdly, there maybe some interaction on Hg(2+)when 

blending coals burned. Also, the calculation was based on assuming exact bending ratios 

between fuels. Slightly change of the blending might result in a different calculation 

result. It was found that a 10% derivation from a wanted blending ratio (63% Columbian 

coal and 37% of petroleum coke) can result in a positive P value. 

62