United States Office of Air Quality
Environmental Protection Rannlng and Standards
Agency Research Triangle Park, NC 27711
EMB Report 03-UTL-2
May 1003
Air
Electric Utility
Combined Cycle Gas-Fired
Gas Turbine
Emission Test Report
Houston Lighting and Power Company
T.H. Wharton Electric Generating Station
Houston, Texas
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FINAL REPORT
COMBINED CYCLE GAS-FIRED GAS TURBINE EMISSIONS TEST
HOUSTON LIGHTING AND POWER COMPANY
T. H. WHARTON ELECTRIC GENERATING STATION
HOUSTON, TEXAS
EPA Contract No. 68D20163
Work Assignment No. 1-34
Prepared by:
Research Division
Entropy, Inc.
Post Office Box 12291
Research Triangle Park, North Carolina 27709
Prepared for:
Lori Lay
U. S. Environmental Protection Agency
Emissions Measurement Branch
Research Triangle Park, North Carolina 27711
May 27, 1994
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DISCLAIMER
This document was prepared by Entropy, Inc. under EPA Contract No.
68D20163, Work Assignment No. 1-34. This document has been reviewed by the
U.S. Environmental Protection Agency (EPA).
The opinions, conclusions, and recommendations expressed herein are
those of the authors, and do not necessarily represent those of EPA.
Mention of specific trade names or products within this report does not
constitute endorsement by EPA or Entropy, Inc.
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TABLE OF CONTENTS
1.0 INTRODUCTION 1
1.1 BACKGROUND 1
1.2 DESCRIPTION OF THE PROJECT 1
1.3 PROJECT ORGANIZATION 3
2.0 PROCESS DESCRIPTION AND SAMPLE POINT LOCATIONS 4
2.1 PROCESS DESCRIPTION 4
2.2 CONTROL EQUIPMENT DESCRIPTION 6
2.2.1 Nitrogen Oxides (NOX) Control 6
2.2.2 Sulfur Dioxide (S02) Control 6
2.2.3 Particulate Control 6
2.3 SAMPLE POINT LOCATIONS 6
2.3.1 Turbine Outlet (HRSG Inlet) . 6
2.3.2 Stack (HRSG Outlet) 7
3.0 SUMMARY AND DISCUSSION OF RESULTS 10
3.1 OBJECTIVES AND TEST MATRIX 10
3.2 FIELD TEST CHANGES AND PROBLEMS 12
3.3 SUMMARY OF RESULTS 12
3.3.1 FTIR Results 12
3.3.1.1 Gas Phase Results 12
3.3.1.2 Sample Concentration Spectra 13
3.3.3 Process Operation During Testing 31
3.3.3.1 Process Results 31
3.3.3.2 Problems and/or Variations during Testing ... 31
4.0 SAMPLING AND ANALYTICAL PROCEDURES 36
4.1 EXTRACTIVE SYSTEM FOR DIRECT GAS PHASE ANALYSIS 36
4.1.1 Sampling System 36
4.1.2 Analytical System 37
4.1.3 Sample Collection Procedure 37
4.2 SAMPLE CONCENTRATION 40
4.2.1 Sampling System 40
4.2.2 Analytical System 40
4.2.3 Sample Collection Procedure 40
4.3 CONTINUOUS EMISSIONS MONITORING 43
4.4 FLOW DETERMINATIONS 44
4.5 PROCESS OBSERVATIONS 46
4.6 ANALYTICAL PROCEDURES 46
4.6.1 Description of K-Matrix Analyses 46
4.6.2 Preparation of Analysis Programs 47
4.6.3 Error Analysis of data 48
4.6.4 Concentration Correction Factors 50
4.6.5 Analysis of Sample Concentration Spectra 51
n
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(Continued)
5.0 QUALITY ASSURANCE/QUALITY CONTROL ACTIVITIES 52
5.1 QC PROCEDURES FOR MANUAL FLUE GAS TEST METHODS 52
5.1.1 Pitot Tube QC Procedures 52
5.1.2 Sample Concentration Sampling QC Procedures 53
5.1.3 Manual Sampling Equipment Calibration Procedures ... 53
5.1.3.1 Type-S Pitot Tube Calibration 53
5.1.3.2 Temperature Measuring Device Calibration ... 53
5.1.3.3 Dry Gas Meter Calibration 54
5.2 QC PROCEDURES FOR INSTRUMENTAL METHODS 54
5.3 QA/QC CHECKS FOR DATA REDUCTION, VALIDATION, AND REPORTING . 55
5.3.1 Sample Concentration 55
5.3.2 Gas Phase Analysis 56
5.3.3 FTIR Spectra . . . 56
5.4 CORRECTIVE ACTIONS . . . 57
6.0 CONCLUSIONS AND DISCUSSION 58
7.0 REFERENCES 61
APPENDICES
A - Results and Calculations
B - Raw Field Data and Calibration Data Sheets
C - Analytical Data
D - EPA Methods and Protocol
m
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1.0 INTRODUCTION
1.1 BACKGROUND
The U. S. Environmental Protection Agency (EPA) Office of Air Quality
Planning and Standards (OAQPS), Industrial Studies Branch (ISB), and Emission
Measurement Branch (EMB) directed Entropy, Inc. to conduct an emission test
at Houston Lighting and Power Company's (HLPC) T. H. Wharton Electric
Generating Station combined-cycle gas-fired gas turbine in Houston, Texas.
The test was conducted on May 17 and 18, 1993. The purpose of this test was
to identify which hazardous air pollutants (HAPs) listed in the Clean Air Act
Amendments of 1990 are emitted from this source. The measurement method used
Fourier transform infrared (FTIR) technology, which had been developed for
detecting and quantifying many organic HAPs in a flue gas stream. Besides
developing emission factors (for this source category), the data will be
included in an EPA report to Congress.
Before this test program, Entropy conducted screening tests using the
FTIR method at facilities representing several source categories, including
a coal-fired boiler. These screening tests were part of the FTIR Method
Development project sponsored by EPA to evaluate the performance and
suitability of FTIR spectrometry for HAP emission measurements. These tests
helped determine sampling and analytical limitations, provided qualitative
information on emission stream composition, and allowed estimation of the
mass emission rates for a number of HAPs detected at many process locations.
The evaluation demonstrated that gas phase analysis using FTIR can detect and
quantify many HAPs at concentrations in the low part per million (ppm) range
and higher, and a sample concentration technique was able to detect HAPs at
sub-ppm levels.
Following the screening tests, Entropy conducted a field validation
study at a coal-fired steam generation facility to assess the effectiveness
of the FTIR method for measuring HAPs, on a compound by compound basis. The
flue gas stream was spiked with HAPs at known concentrations so that
calculated concentrations, provided by the FTIR analysis, could be compared
with actual concentrations in the gas stream. The analyte spiking procedures
of EPA Method 301 were adapted for experiments with 47 HAPs. The analytical
procedures of Method 301 were used to evaluate the accuracy and precision of
the results. Separate procedures were performed to validate a direct gas
phase analysis technique and a sample concentration technique of the FTIR
method. A complete report, describing the results of the field validation
test, has been submitted to EPA.1
This report was prepared by Entropy, Inc. under EPA Contract No.
68D20163, Work Assignment No. 1-34. Research Triangle Institute (RTI)
provided the process information given in Sections 2.1 and 3.3.3.
1.2 DESCRIPTION OF THE PROJECT
The FTIR-based method uses two different sampling techniques: (1) direct
analysis of the extracted gas stream (hereafter referred to as the gas phase
technique or gas phase analysis) and (2) sample concentration followed by
thermal desorption. Gas phase analysis involves extracting gas from the
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sample point location and transporting the gas through sample lines to a
mobile laboratory where sample conditioning and FTIR analyses are performed.
The sample concentration system employs 10 g of Tenax sorbent, which can
remove organic compounds from a flue gas stream. Organic compounds adsorbed
by Tenax are then thermally desorbed into the smaller volume of the FTIR
absorption cell; this technique allows detection of some compounds down to
the ppb level in the original sample. For this test, approximately 850 dry
liters of flue gas were sampled during each run using the sample
concentration system. Section 4.0 describes the sampling systems.
Entropy operated a mobile laboratory (FTIR truck) containing the
instrumentation and sampling equipment. The truck was driven to the site at
T. H. Wharton, and parked next to the sampling location. Three test runs
were performed over a two-day period.
Entropy tested the exhaust gases from one of the gas turbines operated
by T.H. Wharton to generate electricity. The turbine burns natural gas. Hot
gases from the combustion of the natural gas drive the turbine. Gases (about
1000°F) exiting the turbine pass through an exhaust duct to a heat recovery
steam generator (HRSG). Heat is recovered in the HRSG to produce steam,
which in turn is used to drive a steam turbine. The cooled gases exit the
HRSG to be exhausted through a short stack. The only control device is a
water injection system used to minimize NOX emissions. Entropy installed
sampling equipment in ports available on the gas turbine exhaust duct
upstream of the heat recovery steam generator. Section 2.0 contains
descriptions of the process and the sampling point locations.
Direct gas phase analysis was used to measure carbon monoxide (CO),
carbon dioxide (C02), sulfur dioxide (S02), nitrogen oxides (NOX), and ppm
levels of other species. EPA instrumental test methods were used to provide
concentrations of CO, C02, 02, and hydrocarbons (HC). The sample
concentration technique was used to measure HAPs at ppb levels. Entropy
conducted three 4-hour sample concentration and gas phase runs at the turbine
exhaust duct upstream of the HRSG. In addition, a single sample concen-
tration run was also conducted at the HRSG stack simultaneous with Run 2 at
the inlet of the HRSG. Combustion gas volumetric flows were calculated from
fuel data provided by T. H. Wharton. Section 3.1 gives the test schedule.
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1.3 PROJECT ORGANIZATION
The test program was funded and administered by the Industrial Studies
Branch (ISB) and the Emissions Measurement Branch (EMB) of the U.S. EPA. A
representative from RTI collected process data. The following list presents
the organizations and personnel involved in coordinating and performing this
project.
HLPC Corporate Contact:
Mr. Derek Furstenwerth (713) 897-8603
T. H. Wharton Plant
Contacts:
Mr. Ron Jernigan
Mr. Edward Wong
(713) 897-2609
EMB Work Assignment
Managers:
Ms. Lori Lay
Mr. Dennis Holzschuh
(919) 541-4825
(919) 541-5239
Industrial Studies Branch
(ISB) Contacts:
Mr. Kenneth Durkee
Mr. William Maxwell
(919) 541-5425
(919) 541-5430
Entropy Project Manager:
Dr. Thomas Geyer
(919) 781-3551
Entropy Test Personnel:
Mr. Scott Shanklin
Ms. Lisa Grosshandler
Dr. Laura Kinner
Mr. Greg Blanschan
Mr. Mike Worthy
RTI Representative:
Mr. Jeffrey Cole
(919) 990-8606
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2.0 PROCESS DESCRIPTION AND SAMPLE POINT LOCATIONS
The process information was supplied by the T.H. Wharton Generating
Station.
2.1 PROCESS DESCRIPTION
Houston Lighting & Power Company's (HLPC) T.H. Wharton Unit Four is
located in Houston, Texas. Unit Four began operation in 1974 and consists of
four combined cycle gas turbines, numbered 41, 42, 43, and 44. Each combined
cycle gas turbine consists of a General Electric MS-7000 simple cycle gas
turbine and a heat recovery steam generator (HRSG). These components are
described below. The four combined cycle gas turbines and their associated
steam turbine are collectively referred to as a General Electric Stag 300
system (Figure 2-1). Gas turbine No. 41 (GT 41) was used for testing. One
or more of these GT's normally operate during peak usage times, which vary
depending on need. There is a 2-week planned outage for each GT once a year
for an annual inspection. The primary fuel source for GT 41 is natural gas.
GT 41 can also burn No. 2 fuel oil. Only natural gas was used during the
test period.
Each General Electric MS-7000 gas turbine is a 49 MW, single-shaft,
three-bearing machine connected to its own generator. The hot gases exiting
the combustion chambers drive the gas turbines, which in turn develop power
to drive the axial compressor and to produce useful shaft output for driving
the generator.
The exhaust from all four GT's is used in the combined-cycle mode as the
heat energy input to produce steam from HRSG feedwater. Each gas turbine has
its own HRSG. The saturated steam in each HRSG drum is superheated by gas
turbine exhaust. This superheated steam is collected from all four HRSGs and
used to turn a 102.5 MW steam turMne generator.
The gas turbine is equipped with a set of dampers which allow the
turbine to operate in simple-cycle or combined-cycle mode. The bypass damper
controls flow through the bypass or simple-cycle stack, and the isolation
damper controls flow through the HRSG. During start-up operations the
isolation damper is closed, preventing flue gas flow through the HRSG, and
the bypass damper is open, allowing flue gas to exit through the bypass
stack. This is referred to as simple-cycle operation. Once the turbine has
completed start-up procedures the isolation damper is opened and the bypass
damper is closed redirecting flue gas flow through the HRSG. The hot flue
gas heats boiler feed water to produce steam, which, once it has reached
sufficient quality, is used to drive a steam turbine to produce more
electricity. This is referred to as combined-cycle operation.
GT 41 can produce 48 to 62 MW depending on the time of year. In winter,
the inlet air is colder and denser, allowing more fuel to flow to the
turbines producing greater output. The opposite occurs during the summer
when the inlet air is less dense. Unit Four is nominally rated at 300 MW.
GT 41 can produce 210,000 Ib/hr of steam from its HRSG for the steam
turbine generator. All four GT's in Unit Four are capable of a combined
840,000 Ib/hr of steam.
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GT44 Natural
Gas
Combustion
System
GT43 Natural Exhaust
Gas
3.5' \Deaerator/
Condenser
Makeup
— W&ter
(it necessary)
Legend
Air & Gas - -
Fuel —
Water & Steam
- - •
- —
Figure 2-1. Houston Lighting & Power Co. - T. H. Wharton Electric Utility
Generating Station - Unit Four (General Electric Stag 300 System)
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2.2 CONTROL EQUIPMENT DESCRIPTION
2.2.1 Nitrogen Oxides (NOJ Control
-xJ
A water injection system for NOX control is incorporated in the design
of GT 41. The water injection system operates using demineralized water from
the station feedwater treatment system. Water is vaporized when it is
injected into the combustion air stream. The vaporization process removes
some of the heat from the combustion chamber, thus lowering the peak flame
temperature. The result of this temperature reduction is to reduce the
formation of thermal NOX.
2.2.2 Sulfur Dioxide (SO;) Control
Emissions of S02 are considered negligible for natural gas firing. When
using the alternate fuel (No. 2 distillate), S02 emissions are controlled by
the use of low sulfur content oil. The maximum sulfur content acceptable
under current permit specifications is 0.5 percent sulfur by weight.
2.2.3 Particulate Control
Particulate and visible emissions are limited by using natural gas as
the primary fuel and No. 2 distillate oil as an alternate fuel. In addition
to the low ash characteristics of No. 2 fuel oil, each gas turbine is
equipped with a swirl plate to impart a swirl to the combustion air to ensure
a thorough mixing of air and fuel so that complete combustion occurs.
2.3 SAMPLE POINT LOCATIONS
There were two options for a sampling location, at the turbine outlet
(HRSG inlet) or the stack (outlet of the HRSG). The turbine outlet location
was selected for testing because of concern that vents near the emission
point on the stack would allow ambient air to dilute to sample stream. A
second sampling train was available, and one sample concentration run of the
system was performed at the stack concurrently with sample concentration Run
2 at the turbine outlet.
2.3.1 Turbine Outlet (HRSG Inlet)
Figure 2-2 depicts the turbine outlet location. Six sample ports were
available across the top of the 22.5-foot wide, 7.25-foot deep gas turbine
exhaust duct. The ports were located 13 feet down-stream of a damper and
3.25 feet upstream of a widening in the duct (diffuser) that led to the HRSG.
The separate sample probes were installed in the two middle ports (see Figure
2-2). A pitot probe was installed in the port adjacent to the sample
concentration probe to provide indications of changes in the exhaust gas
flow. These ports were the only ports used during the test. The flue gas
conditions prohibited sample and pitot probe traverses to check for
stratification in the gas stream, and determine flue gas volumetric flow.
According to HLPC personnel, gas stratification was unlikely at this
location on the process. A sample point traverse across the duct through a
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single port was performed using the gas phase probe to check for
stratification and the results of the 02 traverse indicated the stream was not
stratified (see Section 3.3.2). The sample concentration and the gas phase
probe tips were both inserted to a depth of 3 ft.
Flue gas conditions at the sample point location were 990°F and about 20
inches of water positive pressure. Due to these extreme conditions, as a
safety concern, the facility did not fire the turbine during the installation
of the sampling probes, but fired the turbine once Entropy was ready to
proceed with the test.
2.3.2 Stack (HRSG Outlet)
Dimensions of the stack location are shown in Figure 2-3. The sample
port was 1-foot below the top of the stack which was open. The gas flow
presumably prohibited mixing between flue gas and air at the test point, but
there were no CEM, Orsat or gas phase FTIR measurements performed to verify
this. Horizontal vents around the stack just below the level of the sample
port were closed during the test run, so there should have been no air
leakage from this source. Although this location did not meet EPA Method 1
criteria, EPA believed the composition of the stack outlet to be of interest
so a single sample concentration run was performed.
The sample concentration probe extended through the port several feet
into the opening at the top of the stack. The gas stream was between 290 and
300°F during the test run. This allowed Entropy to set up the apparatus and
insert the probe while the process was operating.
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Gas-Fired
Gas Turbine
A Gas Phase Sample Port
B Sample Concentration Sample Port
C Pitot and Thermocouple
Damper
Diffuser •
TOD View
Stack
Gas-Fired
Gas Turbine
1 J'
k )
Bypass
s— Damper
7-3"
T
— f>»
Stack
Ctn/«U
Transition
HRSG
1
/
Side View
Figure 2-2. Houston Lighting and Power, T.H. Wharton Generating Station.
8
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Gas-Fired
Gas Turbine
22'-6"
Damper
IX
Diffuser
TOD View
Stack
i-n'-l
Stack
Transition
Sample
Port
Steam Generator
Elbow Module
End View
Figure 2-3. Houston Lighting and Power, T.H. Wharton Generating Station stack test location.
9
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3.0 SUMMARY AND DISCUSSION OF RESULTS
3.1 OBJECTIVES AND TEST MATRIX
The purpose of the test program was to obtain information that will
enable EPA to develop emission factors (for as many HAPs as possible) which
will apply to electric utilities employing gas-fired gas turbines. EPA will
use these results to prepare a report for Congress.
The specific objectives were:
• Measure HAP emissions (employing methods based on FTIR
spectrometry) in two concentration ranges, above 1 ppm using
gas phase analysis, and to sub-ppm levels using sample
concentration/thermal desorption.
• Determine maximum possible concentrations for undetected HAPs
based on detection limits of instrumental configuration and
limitations imposed by composition of flue gas matrix.
• Measure 02, C02, CO, and hydrocarbons using gas analyzers.
• Perform simultaneous testing at the inlet and outlet of the
HRSG and analyze data to assess effect (if any) of the HRSG on
HAP emissions.
• Obtain process information from T. H. Wharton. This
information includes the rate of power production during the
testing periods.
Table 3-1 presents the testing schedule that was followed at T. H.
Wharton.
10
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TABLE 3-1.
FTIR TESTING SCHEDULE AT T.H. WHARTON GAS FIRED GAS TURBINE
SAMPLING PERIODS
Date
5/17/93
5/17/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
Run#a
Amb
1
2
3
Amb
Amb
Locb
I
I
S
I
I
I
I
I
S
Sample0
Conditioning
H/W
H/W
COND
P/P
H/W
Gas Phase
Analysis
1804-1939
1140-1208
1226-1431
1521-1624
1635-1652
Sample
Cone.
1005-1105
1445-1845
1057-1407
1100-1500
1555-1955
2030-2130
1530-1645
CEM
Analyzers
1449-1940
1039-1208
1209-1431
1432-1624
1625-1654
Thermal Desorption
Date
5/18
5/18
5/19
5/19
5/19
5/18
5/18
Time
2226-2040
2328-2349
0026-0049
2349-0014
0053-0118
2246-2259
2304-2318
(a) Amb denotes an ambient sample.
(b) Location designations; I = Gas Turbine outlet (HRSG Inlet), S = Stack (HRSG Outlet).
(c) H/W = Hot/Wet Sample; COND = Condenser Sample; P/P = Perma Pure Sample.
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3.2 FIELD TEST CHANGES AND PROBLEMS
On the initial test day Entropy experienced difficulties aligning the
FTIR cell. It was important to achieve satisfactory alignment of the cell
because this determined the intensity of the signal reaching the detector,
which in turn influenced the signal to noise ratio (S/N) of the data. The
sensitivity of the instrument depends, in part, on S/N. The problem was
corrected but not before set-up of the sample concentration apparatus was
complete and the plant was operating under conditions suitable for testing.
It was decided to begin sample concentration Run 1 and begin direct gas phase
testing as soon as possible during Run 1. As a result there are direct gas
phase and CEM data covering only a portion of Run 1. This was deemed
acceptable because there was ample opportunity to obtain gas phase data on
the second test day.
The second change was introduced to permit the completion of two test
runs in a single day. Initially, the plan called for the completion of two
4-hour sample concentration runs with concurrent gas phase runs performed
over the entirety of the two 4-hour periods. Instead, sample concentration
Run 1 commenced as soon as the system was ready and the turbine was operating
at full capacity. Direct gas phase testing commenced about 40 minutes after
the beginning of Run 2. Gas phase analysis continued through the end of Run
2 and into Run 3 but was stopped before Run 3 was completed. This plan was
the best way to accomplish the test objectives and complete the test runs
within the originally scheduled time. Also, it was not necessary for the gas
phase analysis to run for the entire 4 hours of each Run to collect enough
data to characterize the flue gas stream.
3.3 SUMMARY OF RESULTS
3.3.1 FTIR Results
Gas phase and sample concentration data were analyzed for the presence
of HAPs and other species. All spectra were visually inspected and
absorbance bands were identified. Then spectra were analyzed, using analysis
procedures developed by Entropy, to determine concentrations of any species
detected. These results are presented in Table 3-2. Maximum possible
concentrations were determined for undetected HAPs. These results are
presented in Tables 3-3 to 3-5.
3.3.1.1 Gas Phase Results Each gas phase FTIR spectrum was separately
analyzed for the presence of HAPs or other species. The spectra revealed
that the gas phase samples were composed primarily of;
• water vapor
• C02
• Smaller amounts of NO (an average of about 15 ppm) and CO were also
detected.
• N02 was detected but not quantified because quantitative reference
spectra are not currently available.
Calculated concentrations of NO for each spectrum will be included in a
12
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table with the final report. No S02 or HC1 was detected in the gas phase
spectra. The spectra were analyzed for the presence of HAPs that are
currently represented in the quantitative reference spectra library. None
were detected. Previously, Entropy developed analysis programs to analyze
for HAPs in FTIR spectra of samples extracted from a coal-fired boiler stack.
Statistical analyses showed that the programs were successful in measuring
some HAPs in hot/wet and condenser samples.1 The major interferant species
detected at the coal-fired boiler are very similar to those that have been
identified at the gas-fired gas turbine (with the exception that S02 was not
detected in the gas-fired exhaust). Therefore, the same programs were used
to analyze the data obtained in this test. The results of the analyses are
presented in Appendix C.
A set of subtracted spectra was generated so that maximum possible
(minimum detectible) concentrations could be calculated for HAPs that were
not identified in the sample stream. Reference spectra of water vapor and C02
were scaled and subtracted from each of the field spectra. The remaining
base lines were then analyzed for every compound represented in the
quantitative spectral library to determine the maximum possible
concentrations of HAPs that were undetected. The calculations were performed
according to the procedures described in Section 4.6.3. Results for hot/wet
and dry (treated with the condenser or PermaPure dryers) spectra are
presented in Tables 3-3 and 3-4 respectively. The results are averages of
the calculated values for all of the spectra over the 3 sample runs.
The hot/wet gas phase spectra are the most difficult to analyze because
there is strong interference from water vapor. Even so, in results from the
hot/wet gas phase data, 92 compounds gave minimum detectible concentrations
below 10 ppm, and of these, 77 are below 5 ppm, and 26 are 1 ppm or lower.
The results represent upper limits for in-stack concentrations of the
HAPs listed. This means that, for a HAP to be present in the gas stream, its
concentration must have been below the calculated maximum possible concen-
tration.
3.3.1.2 Sample Concentration Spectra The sample concentration spectra
represent integrated samples taken over each 4-hour run.
• Ammonia (NH3) was detected in samples from all three runs at the
turbine outlet and in the sample taken from the HRS6 outlet. It
was also present in the ambient samples collected at each location.
• HC1 was detected in the sample from Run 1 and in both ambient
samples at the turbine outlet.
• Evidence of hexane Was observed in samples from both locations and
the ambient samples. Absorbances similar to hexane are often
observed in spectra of desorbed samples. These features may be due
to a mixture of alkane hydrocarbons, including hexane, the sum of
whose spectra gives absorbances which appear similar to hexane.
• A siloxane compound was detected that Entropy first identified in
spectra of samples taken at the coal-fired boiler validation test.1
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This compound was shown to be a product of a reaction between HC1
or water vapor in the gas stream and materials in the filter
housing of the Method 5 box. Entropy took steps to eliminate this
problem and the siloxane, if it is a contaminant, is present at
very low levels relative to validation data.
• Nitrous acid (HN02) was detected in spectra from Runs 1 and 2 and
from the HRSG outlet. This compound was probably formed by
reaction of the NOX in the gas stream with the water condensed in
the collection tube.
Table 3-2 shows calculated concentrations of HC1, NH3, and hexane in
samples where these species were detected. In-stack concentrations are also
given for the same species. In-stack concentrations were determined by
dividing the in-cell concentration by the concentration factor (see Section
4.6.4). The in-stack concentrations are based on the volume of gas sampled
and do not account for effects of the sampling system or the adsorption/
desorption efficiencies of HC1 and NH3. Therefore, the values in Table 3-2
represent lower limits on the concentrations for these species. Upper limits
are provided by the values given in the gas phase data (Tables 3-3 and 3-4).e
gas stream. Table 3-5 gives minimum detectible concentrations for species
not detected using Tenax and the maximum in-stack concentrations are based on
the amount of gas sampled (See Section 4.6.5)
Other absorbance bands were also observed which still remain
unidentified. None of these bands were attributed to HAPs for which Entropy
currently has reference spectra. When these bands are identified, it should
become clear whether they are due to emissions from the process or were
formed by conditions unrelated to the process (i.e. by contamination). These
bands do not consistently appear in every sample so it is possible that
concentrations of some species varied during the test Runs.
Spectral analysis programs were also developed for sample concentration
spectra. The analysis programs were used to evaluate the sample
concentration data for HAPs. The results, presented in Appendix C, give
calculated concentrations only for those HAPs that Entropy has proven in a
field validation study can be measured using Tenax.
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TABLE 3-2. CONCENTRATIONS CALCULATED FOR SOME COMPOUNDS
DETECTED IN SPECTRA OF CONCENTRATED SAMPLES EXTRACTED
FROM THE UNIT 4 STACK AT WHARTON GAS-FIRED TURBINE.
Spectra
TINL125B
TINL204B
TINL302B
TINLAMB1
TINLAMB2
TOUT109B
TOUTAMB1
Nitric Oxide (a)
In-Cell Flue Gas
(ppm) (c) (ppm) (d)
52.72
59.60
48.21
3.42
-0.34
54.81
5.20
0.3258
0.5575
0.2705
0.0230
-0.0023
0.3980
0.0377
Ammonia
In-Cell Flue Gas
(ppm) (ppm)
0.07
-0.22
0.01
-0.48
-0.81
16.68
1.73
0.0004
-0.0021
0.0001
-0.0032
-0.0055
0.1212
0.01 26
Hydrochloric Acid
In-Cell Flue Gas
(ppm) (ppm)
7.29
2.20
-120.66
23.22
2.70
4.22
2.95
0.0451
0.0206
-0.6771
0.1561
0.0182
0.0307
0.0215
Hexane (b)
In-Cell Flue Gas
(ppm) (ppm)
1.42
0.50
-14.91
3.09
0.71
4.33
1.42
0.0088
0.0046
-0.0837
0.0208
0.0048
0.0314
0.0103
(a) Compounds for which Entropy has obtained quantitative reference spectra.
(b) Probably a mixture of alkane hydrocarbons which may include hexane and together
give absorbancs similar to hexane.
(c) Concentration of detected compound in FTIR cell calculated using MCOMP analytical routine.
(d) Concentration of detected compound in flue gas calculated by dividing in-cell concentration by
the concentration factor (see Section 4.6.5).
-------
TABLE 3-3. CALCULATED MAXIMUM (MINIMUM DETECT1BLE) CONCENTRATIONS:
HAP SPECIES NOT DETECTED IN SPECTRA OF HOT/WET SAMPLES. UNIT 4 GAS-FIRED
GAS TURBINE OUTLET.
Location
Compound (a)
Acetonrtrile (e)
Acrolein
Acrylonrtrile
Ally! Chloride
Benzene
Bromoform
1 ,3-Butadiene
Carbonyl Sutfide
Chlorobenzene
Ethyl Benzene
Ethyl Chloride
Ethylene Dibromide
n-Hexane
Methyl Bromide
Methyl Chloride
Methyl Ethyl Ketone
Methyl Isobutyl Ketone
Methyl Methacrylate
Methylene Chloride
2-Nrtropropane
Propylene Oichloride
Styrene
Tetrachloroethylene
Toluene
1,1 ,2-Trichloroethane
Trichloroethylene
2,2,4-Trimethylpentane
Vinyl Acetate
Vinyl Bromide
Analytical Region (wn) (b)
1039.90 - 1064.00
2636.11 - 2875.59
922.19 - 997.82
893.51 - 1002.22
3020.15 - 3124.44
1134.18 - 1159.39
870.00 - 1052.64
2029.21 - 2075.69
1012.42 - 1036.64
2854.28 - 3122.12
2916.56 - 3041.03
1167.96 - 1208.92
2835.27 - 3005.43
2938.47 - 3002.81
2928.38 - 3099.97
1140.70 - 1222.63
2872.05 - 2994.95
1137.50 - 1232.04
1241.32 - 1290.95
831.47 - 868.50
2927.59 - 3031.58
886.32 - 931.22
899.20 - 925.20
2862.00 - 2924.00
909.41 - 960.62
826.25 - 860.91
2861.57 - 3009.23
832.23 - 906.69
939.59 - 944.72
Inlet
Max. Con.
RMS (c) (ppm) (d)
4.03E-03
1.91E-03
4.57E-03
5.13E-03
9.02E-03
3.78E-03
6.06E-03
1.98E-02
6.16E-03
8.00E-03
6.62E-03
5.84E-03
4.41 E-03
4.81 E-03
6.85E-03
5.76E-03
4.36E-03
7.50E-03
2.11E-02
3.24E-03
6.16E-03
2.26E-03
2.17E-03
1.99E-03
4.43E-03
3.41 E-03
4.78E-03
2.92E-03
4.90E-03
55.17
2.50
3.76
4.19
4.83
0.67
6.35
1.13
5.67
8.34
4.92
4.16
0.64
6.38
14.42
4.25
1.84
0.84
11.47
3.57
5.88
1.71
0.20
3.15
4.61
0.53
0.58
1.80
1.57
16
-------
TABLE 3-3. (Continued)
Location
Compound (a)
Vinyl Chloride
Vinylidene Chloride
O-xylene
P-xylene
Carbon Disulfide
Carbon Tetrachloride
Chloroform
Cumene
1 ,2-Epoxy Butane
Ethylene Oxide
Methanol
Methyl Chloroform
Methyl Iodide
Methyl t-Butyl Ether
Propyiene Oxide
M-xylene
Acetone
Acetaldehyde
Acetophenone
Acrylic Acid
Aniline
Benzotrichloride
Benzyl Chloride
Bis(chloromethyl)ether
Chloroacetic acid
2-Chloroacteophenone
Chloromethyl methyl ether
Chloroprene
o-Cresol
Analytical Region (wn) (b)
852.81 - 1056.06
1059.44 - 1113.01
2859.84 - 3095.04
2854.43 - 3083.14
2188.79 - 2196.47
758.21 - 804.29
1210.20 - 1229.00
2871.26 - 3095.39
902.37 - 919.70
866.90 - 875.00
2807.91 - 3029.40
710.05 - 736.84
1250.18 - 1253.53
1195.00 - 1210.00
2875.59 - 3097.75
2846.93 - 3090.79
1182.00 - 1255.03
3006.20 - 3009.20
1140.40 - 1286.06
758.79 - 1378.25
1102.90 - 1123.63
3069.50 - 3088.80
3070.16 - 3085.53
1218.65 - 1260.78
1094.97 - 1124.12
1274.39 - 1285.42
1111.02 - 1146.08
971.60 - 975.80
1092.80 - 1114.07
Inlet
Max. Cone.
RMS (c) (ppm) (d)
6.01 E-03
6.29E-03
7.20E-03
7.30E-03
2.74E-03
6.41 E-02
1 .32E-02
7.25E-03
2.01 E-03
1.60E-03
5.54E-03
5.84E-01
1.12E-03
3.54E-03
7.33E-03
7.27E-03
8.46E-03
2.54E-03
1.00E-02
1.67E-01
5.15E-03
6.30E-03
6.42E-03
1.05E-02
4.93E-03
8.38E-03
4.44E-03
3.56E-03
4.65E-03
6.14
1.68
4.56
3.99
2.18
2.96
3.01
18.16
1.46
0.38
4.46
37.19
1.01
0.56
4.64
7.00
3.67
6.04
1.29
83.84
1.64
5.12
10.35
3.91
1.05
1.54
0.64
1.88
1.93
17
-------
TABLE 3-3. (Continued)
Location
Compound (a)
m-Cresol
p-Cresol
,2-Dibromo-3-chloropropane
1 ,4-Dichlorobenzene
Dichloroethyl ether
1 ,3-Dichloropropene
Dichlorvos
N,N-Diethyl aniline
Dimethyl carbamoyl chloride
Dimethyl formamide
1,1 -Dimethyl hydrazine
Dimethyl phthalate
1 ,4-Dioxane
Epichlorohydrin
Ethyl Acrylate
Ethylene Dichloride
Ethylidene dichloride
Formaldehyde
Hexachlorobutadiene
Hexachlorocylcopentadiene
Hexachloroethane
Hexamethylphosphoramide
Hydrochloric Acid
Isophorone
Maleic Anhydride
Methyl hydrazine
Naphthalene
Nitrobenzene
N-Nitrosodimethylene
Analytical Region (wn) (b)
915.55 - 939.18
1245.80 - 1265.40
2959.13 - 2985.82
995.96 - 1031.06
2662.14 - 3089.07
768.00 - 791.00
835.77 - 876.95
2655.32 - 3156.07
889.55 - 917.52
2824.80 - 2873.60
856.12 - 974.09
1157.86 - 1254.16
2967.40 - 2970.30
943.52 - 981.73
1181.93 - 1210.00
2965.00 - 2999.00
2792.57 - 3132.83
2788.33 - 2842.20
976.90 - 997.70
1227.02 - 1240.42
785.50 - 793.00
949.42 - 1019.53
2817.35 - 2823.26
2681.20 - 3130.60
838.45 - 841.30
2683.00 - 3061.78
779.31 - 783.55
841.70 - 861.39
928.00 - 1085.28
Inlet
Max. Cone.
RMS (c) (ppm) (d)
2.64E-03
9.24E-03
5.33E-03
2.64E-03
7.06E-03
1 .66E-02
3.16E-03
8.71 E-03
1.81E-03
1.34E-03
3.92E-03
7.95E-03
1.91 E-03
4.61 E-03
5.12E-03
5.66E-03
8.64E-03
1.75E-03
3.73E-03
3.96E-03
3.17E-02
3.86E-03
8.23E-04
8.59E-03
1.90E-03
6.32E-03
2.40E-03
3.48E-03
6.44E-03
1.63
1.50
8.97
1.13
8.64
3.31
0.36
4.96
0.45
0.83
3.17
4.12
0.57
3.69
0.26
8.32
36.73
1.72
0.51
0.29
1.38
0.51
0.79
5.34
0.19
6.77
0.23
1.34
1.95
18
-------
TABLE 3-3. (Continued)
Location
Compound (a)
N-Nitrosomorpholine
Phenol
Deta-Propiolactone
Propionaldehyde
1 ,2-Propylenimine
Quioline
Styrene Oxide
1 ,1 ,2,2-Tetrachloroethane
2,4-Toluene diisocyanate
o Toluidine
1 ,2,4-Trichlorobenzene
2,4,5-Trichlorophenol
2,4,6-Trichlorophenol
Triethylamine
Ammonia
Analytical Region (wn) (b)
1024.64 - 1258.17
2494.80 - 2530.90
860.13 - 957.64
2546.18 - 3114.35
817.57 - 821.31
800.19 - 803.73
861.39 - 903.93
794.92 - 824.07
885.61 - 905.31
2729.50 - 2758.80
1009.00 - 1198.39
1178.04 - 1204.16
856.27 - 863.36
2756.62 - 2839.34
893.10 - 926.00
Inlet
Max. Cone.
RMS (c) (ppm) (d)
7.05E-03
1.17E-03
3.73E-03
7.44E-03
1 .39E-03
3.92E-03
2.46E-03
5.49E-03
1 .21 E-03
1.48E-03
5.98E-03
5.27E-03
1.84E-03
1.83E-03
2.07E-03
2.94
19.25
0.76
7.82
0.59
0.57
1.70
1.22
0.86
16.13
3.99
1.58
0.43
0.76
1.23
(a) HAP's for which Entropy has obtained quantitative reference spectra.
(b) Region, in wavenumbers (1/cm) chosen for the analysis.
(c) Calculated root mean square deviation over the analytical region in spectra that were generated by
subtracting reference spectra of interferant species from the sample spectra.
(d) Maximum Concentration of undetected compound calculated according to procedures discussed in
Section 4.6.3.
(e) For explanation and discussion of Max. Con. result see section 3.3.1.
19
-------
TABLE 3-4. CALCULATED MAXIMUM POSSIBLE (MINIMUM DETECTJBLE) CONCENTRATIONS:
HAP SPECIES NOT DETECTED IN SPECTRA OF CONDENSER SAMPLES
UNIT 4 GAS-FIRED GAS TURBINE OUTLET.
Location
Compound (a)
Acetonrtrile (e)
Acrolein
Acrylonrtrile
Ally! Chloride
Benzene
Bromoform
1 ,3-Butadiene
Carbonyl Sulfide
Chlorobenzene
Ethyl Benzene
Ethyl Chloride
Ethylene Dibromide
n-Hexane
Methyl Bromide
Methyl Chloride
Methyl Ethyl Ketone
Methyl Isobutyl Ketone
Methyl Methacrylate
Methylene Chloride
2-Nitropropane
Propylene Dichloride
Styrene
Tetrachloroethylene
Toluene
1 ,1 ,2-Trichloroethane
Trichloroethylene
2,2,4-Trimethylpentane
Vinyl Acetate
Vinyl Bromide
Analytical Region (wn) (b)
1039.90 - 1064.00
2636.11 - 2875.59
922.19 - 997.82
893.51 - 1002.22
3020.15 - 3124.44
1134.18 - 1159.39
870.00 - 1052.64
2029.21 - 2075.69
1012.42 - 1036.64
2854.28 - 3122.12
2916.56 - 3041.03
1167.96 - 1208.92
2835.27 - 3005.43
2938.47 - 3002.81
2928.38 - 3099.97
1140.70 - 1222.63
2872.05 - 2994.95
1137.50 - 1232.04
1241.32 - 1290.95
831.47 - 868.50
2927.59 - 3031.58
886.32 - 931.22
899.20 - 925.20
3018.19 - 3054.70
909.41 - 960.62
826.25 - 860.91
2861.57 - 3009.23
832.23 - 906.69
939.59 - 944.72
Inlet
Max. Con.
RMS (c) (ppm) (d)
1.95E-03
9.12E-04
2.33E-03
2.07E-03
3.89E-03
1.33E-03
2.93E-03
9.61 E-03
4.89E-03
3.54E-03
3.15E-03
1.56E-03
2.19E-03
1.68E-03
3.10E-03
1.71 E-03
1.96E-03
2.06E-03
5.02E-03
1.40E-03
2.67E-03
1.46E-03
1.22E-03
3.24E-03
2.10E-03
1.78E-03
2.10E-03
1.67E-03
1.71 E-03
26.72
1.19
1.92
1.69
2.08
0.24
3.07
0.55
4.50
3.70
Z34
1.11
0.32
Z23
6.52
1.26
0.82
0.23
2.73
1.55
2.55
1.11
0.11
1.54
2.19
0.28
0.25
1.03
0.55
20
-------
TABLE 3-4. (Continued)
Location
Compound (a)
Vinyl Chloride
Vinylidene Chloride
O-xylene
P-xyiene
Carbon Oisulfide
Carbon Tetrachloride
Chloroform
Cumene
1,2-Epoxy Butane
Ethylene Oxide
Methanol
Methyl Chloroform
Methyl Iodide
Methyl t-Butyl Ether
3ropylene Oxide
M-xylene
Acetone
Acetaldehyde
Acetophenone
Acrylic Acid
Aniline
Benzotrichloride
Benzyl Chloride
Bis(chloromethyl) ether
Chloroacetic acid
2-Chloroacteophenone
Chloromethyl methyl ether
Chloroprene
o-Cresol
Analytical Region (wn) (b)
852.81 - 1056.06
1059.44 - 1113.01
2859.84 - 3095.04
2854.43 - 3083.14
1545.78 - 1549.33
758.21 - 804.29
1210.20 - 1229.00
2871.26 - 3095.39
902.37 - 919.70
866.90 - 875.00
2807.91 - 3029.40
710.05 - 736.84
1250.18 - 1253.53
1195.00 - 1210.00
2875.59 - 3097.75
2846.93 - 3090.79
1182.00 - 1255.03
3006.20 - 3009.20
1140.40 - 1286.06
758.79 - 1378.25
1102.90 - 1123.63
3069.50 - 3088.80
1262.23 - 1277.98
1218.65 - 1260.78
1094.97 - 1124.12
1274.39 - 1285.42
1111.02 - 1146.08
971.60 - 975.80
1092.80 - 1114.07
Inlet
Max. Con.
RMS (c) (ppm) (d)
2.85E-03
2.62E-03
3.23E-03
3.21 E-03
4.44E-02
2.27E-02
3.13E-03
3.30E-03
1.15E-03
6.99E-04
2.41 E-03
5.30E-01
4.53E-04
1.25E-03
3.38E-03
3.15E-03
2.30E-03
1.17E-03
3.12E-03
1.73E-02
1.57E-03
2.53E-03
5.79E-03
2.93E-03
1.53E-03
2.60E-03
1.72E-03
7.95E-04
1 .39E-03
2.91
0.70
2.04
1.75
1.13
1.05
0.71
8.27
0.83
0.17
1.94
33.72
0.41
0.20
2.14
. 3.04
1.00
2.80
0.40
8.69
0.50
2.05
3.48
1.09
0.33
0.48
0.25
0.42
0.58
21
-------
TABLE 3-4. (Continued)
Location
Compound (a)
m-Cresol
p-Cresol
,2-Dibromo-3-chloropropane
1 ,4-Dichlorobenzene
Dichloroethyl ether
1 ,3-Dichloropropene
Dichlorvos
N,N-Diethyl aniline
Dimethyl carbamoyl chloride
Dimethyl formamide
1,1 -Dimethyl hydrazine
Dimethyl phthalate
1 ,4-Dioxane
Epichlorohydrin
Ethyl Acrylate
Ethylene Dichloride
Ethylidene dichloride
rormaldehyde
Hexachlorobutadiene
Hexachlorocylcopentadiene
Hexachloroethane
Hexamethylphosphoramide
Hydrochloric Acid
Isophorone
Maleic Anhydride
Methyl hydrazine
Naphthalene
Nitrobenzene
N-Nitrosodimethylene
Analytical Region (wn) (b)
915.55 - 939.18
1245.80 - 1265.40
2959.13 - 2985.82
995.96 - 1031.06
2662.14 - 3089.07
768.00 - 791.00
835.77 - 876.95
2655.32 - 3156.07
889.55 - 917.52
2824.80 - 2873.60
856.12 - 974.09
1157.86 - 1254.16
2967.40 - 2970.30
943.52 - 981.73
1181.93 - 1210.00
2965.00 - 2999.00
2792.57 - 3132.83
2788.33 - 2842.20
976.90 - 997.70
1227.02 - 1240.42
785.50 - 793.00
949.42 - 1019.53
2817.35 - 2823.26
2681.20 - 3130.60
838.45 - 841.30
2683.00 - 3061.78
779.31 - 783.55
841.70 - 861.39
928.00 - 1085.28
Inlet
Max. Con.
RMS (c) (ppm) (d)
1.62E-03
3.46E-03
1.68E-03
1 .43E-03
2.46E-03
8.46E-03
1 .35E-03
2.95E-03
1.17E-03
9.16E-04
2.10E-03
2.39E-03
4.87E-04
2.50E-03
1 .43E-03
1.95E-03
3.33E-03
8.29E-04
1.55E-03
1.13E-03
3.42E-02
2.17E-03
6.55E-04
2.93E-03
4.78E-04
2.29E-03
1 .62E-03
1.60E-03
3.72E-03
1.00
0.56
2.82
0.62
3.01
1.69
0.15
1.68
0.29
0.57
1.70
1.24
0.15
2.00
0.07
2.86
14.16
0.82
0.21
0.08
1.49
0.29
0.63
1.82
0.05
2.46
0.15
0.62
1.13
22
-------
TABLE 3-4. (Continued)
Location
Compound (a)
N-Nitrosomorpholine
'henol
beta-Propiolactone
Propionaldehyde
1,2-Propylenimine
Quioline
Styrene Oxide
1 ,1 ,2,2-Tetrachloroethane
2,4-Toluene diisocyanate
o Toluidine
1 ,2,4-Trichlorobenzene
2,4,5-Trichlorophenol
2,4,6-Trichlorophenol
Triethylamine
Ammonia
Analytical Region (wn) (b)
1024.64 - 1258.17
2494.80 - 2530.90
860.13 - 957.64
2546.18 - 3114.35
817.57 - 821.31
800.19 - 803.73
861.39 - 903.93
794.92 - 824.07
885.61 - 905.31
2729.50 - 2758.80
1009.00 - 1198.39
1178.04 - 1204.16
856.27 - 863.36
2756.62 - 2839.34
893.10 - 926.00
Inlet
Max. Con.
RMS (c) (ppm) (d)
3.61 E-03
7.68E-04
1.95E-03
2.41 E-03
8.74E-04
1.67E-03
1 .35E-03
2. 11 E-03
1.09E-03
7.17E-04
3.52E-03
1.50E-03
9.60E-04
8.16E-04
1 .23E-03
1.51
12.67
0.40
2.54
0.37
0.24
0.93
0.47
0.77
7.81
2.34
0.45
0.22
0.34
0.73
(a) HAP's for which Entropy has obtained quantitative reference spectra.
(b) Region, in wavenumbers (1/cm) chosen for the analysis.
(c) Calculated root mean square deviation over the analytical region in spectra that were generated by
subtracting reference spectra of interferant species from the sample spectra.
(d) Maximum Concentration of undetected compound calculated according to procedures discussed in
Section 4.6.3.
(e) For explanation and discussion of Max. Con. result see section 3.3.1.
23
-------
TABLE 3-5. CALCULATED MAXIMUM (MINIMUM DETECTJBLE) CONCENTRATIONS:
HAP SPECIES NOT DETECTED IN SAMPLE CONCENTRATION SPECTRA,
UNIT 4 GAS-FIRED GAS TURBINE
Locaoon
Compound (a)
&cetonKrile (f)
i\crolein
Acrylonrtrile
Allyl Chloride
Jenzene
Jromoform
1,3-Butadieoa
Carbonyl Sulfide
Chlorobenzene
Ethyl Benzene
Ethyl Chloride
ithylene Otbromide
Methyl Bromide
Methyl Chloride
ulethyl Ethyl Ketone
vtethyl Isobutyl Ketone
vtethyl Methacrylate
Vlethyteoe Chloride
2-Nitropropane
'ropylene Oichloride
Styrene
Tetrachloroethylene
Toluene
1 . 1 .2-Trichloroethane
Trichloroethylene
2,2,4-Trimethylpentane
i/lnyl Acetate
/myl Bromide
Analytical Region (wn) (b)
1039.90 - 1064.00
913.70 - 1000.35
922.19 • 997.82
893.51 - 1002.22
1010.22 - 1063.18
1134.18 - 1159.39
870.00 • 1052.64
2029.21 • 2075.69
1012.42 - 1036.64
2854.28 • 3122.12
943.43 • 1000.16
1167.96 - 1208.92
2938.47 - 3002.81
2928.38 - 3099.97
1140.70 - 1222.63
2872.05 • 2994.95
915.64 • 962.12
1241.32 - 1290.95
831.47 • 868.50
996.86 - 1038.00
886.32 • 931.22
899.20 - 925.20
2862.00 - 2924.00
909.41 • 960.62
919.70 - 959.88
2861.57 • 3009.23
919.53 • 1046.33
939.59 - 944.72
Turbine Outlet
Max. In-Cell
RMS (c) Cone, (pom) (d)
3.04E-O3
3.87E-03
3.94E-03
4.02E-03
5.40E-03
7.20E-03
7.69E-03
4.21 E-02
5.95E-03
6.18E-02
3.78E-O3
1.45E-02
1.24E-02
2.20E-02
1.79E-02
1.13E-02
3.57E-03
1.75E-01
1.37E-02
5.38E-03
3.88E-03
3.75E-03
3.20E-03
3.64E-03
3.63E-03
1.30E-02
5.25E-03
1.38E-03
41.66
2.46
3.24
3.29
13.19
1.28
8.05
2.40
5.48
64.51
5.27
10.30
16.45
46.27
13.20
4.76
1.81
95.32
15.08
6.33
2.94
0.34
5.05
3.79
0.70
1.57
2.63
0.44
Max Outlet
Cone, (ppm) (•
0.280
0.017
0.022
0.022
0.089
0.009
0.054
0.016
0.037
0.433
0.035
0.069
0.110
0.311
0.089
0.032
0.012
0.640
0.101
0.043
0.020
0.002
0.034
0.025
0.005
0.011
0.018
0.003
Stack
Max.kt-C««
RMS Cone, (ppm)
1.94E-02
4.91 E-02
5.05E-02
4.63E-02
1.83E-02
1.60E-02
3.79E-02
1.31 E-02
1.58E-02
6.25E-O3
4.B6E-02
1.19E-02
4.57E-03
6.60E-03
1.42E-02
4.48E-03
4.10E-02
2.92E-02
Z01E-02
1.50E-02
3.39E-02
1.3SE-02
2.16E-03
4.03E-02
3.96E-02
4.26E-03
4.27E-02
1.37E-O3
268.10
31.13
41.56
37.78
44.89
its
39.65
0.75
14.51
6.52
67.76
8.46
6.06
13.90
10.44
1.88
20.74
15.89
2Z20
17.68
25.68
1.23
-3.41
41.99
7.61
0.51
21.37
0.44
Max. Stack
Cone, (ppm)
1.932
0.226
0.302
0.274
0.324
0.021
0.288
0.005
0.105
0.047
0.492
0.061
0.044
0.101
0.076
0.014
0.151
0.115
0.161
0.128
0.186
0.009
0.025
0.305
0.055
0.004
0.155
0.003
24
-------
TABLE 3-5. (Continued)
Location
Compound (a)
tfnyl Chloride
tfnyltdene Chloride
0-xylene
'-xylene
Carbon Oisulfide
Carbon Tetrachloride
Chloroform
Cumene
1.2-Epoxy Butane
Ethylene Oxide
Methanol
Methyl Chloroform
Methyl Iodide
Methyl t-Butyl Ether
'ropylene Oxide
«4-xylene
Acetone
iVcetaldehyde
toetophenone
ton/lie Acid
Aniline
3enzotrichloride
3enzvl Chloride
3is(chloromethvl)ether
Chloroacetic acid
2-Chloroacteophenone
Chloromethvl methyl ether
Chloroprene
a-Cresol
Analytical Region (wn) (b)
852.81 • 1056.06
1059.44 - 1113.01
2859.84 - 3095.04
770.61 - 819.06
2188.79 - 2196.47
758.21 - 804.29
758.21 - 781.25
2871.26 - 3095.39
9O2.37 - 919.70
866.90 - 875.00
2807.91 - 3029.40
710.05 - 736.84
1250.18 - 1253.53
1195.00 - 1210.00
2875.59 - 3097.75
2846.93 - 3090.79
1182.00 - 1255.03
3006.20 - 3009.20
1140.40 - 1286.06
758.79 - 1378.25
1102.90 - 1123.63
866.50 - 877.90
3070.16 - 3085.53
1218.65 - 1260.78
1094.97 - 1124.12
1274.39 - 1285.42
1111.02 • 1146.08
971.60 - 975.80
1092.80 - 1114.07
Turbine Outlet
Max. In-Cell Max. Outlet
RMS (c) Cone, (ppm) (d) Cone, (ppm) (e
1.09E-02
7.41 E-03
2.10E-02
1.41E-02
1.64E-02
1.34E-02
6.59E-03
2.08E-02
3.73E-03
2.91 E-03
1.66E-02
2.90E-02
1.36E-03
6.24E-03
2.13E-02
2.10E-02
2.33E-02
3.66E-03
8.23E-02
3.01 E-01
6.07E-03
3.07E-03
2.13E-02
2.94E-02
5.91 E-03
1.78E-02
8.26E-03
1.53E-03
5. 11 E-03
11.14
1.98
13.30
8.05
13.03
0.62
0.33
52.18
2.71
0.70
13.34
1.85
1.23
0.98
13.44
20.25
10.13
8.73
10.60
150.90
1.93
0.56
34.32
10.96
1.25
3.26
1.19
0.81
2.13
0.075
0.013
0.089
0.054
0.088
0.004
0.002
0.350
0.018
0.005
0.090
0.012
0.008
0.007
0.090
0.136
0.068
0.059
0.071
1.013
0.013
0.004
0.230
0.074
0.008
0.022
0.008
0.005
0.014
Stack
Max. In-Cell Max. Stack
RMS Cone, (ppm) Cone, (ppm)
3.71 E-02
2.46E-02
6.15E-03
1.35E-02
2.49E-02
1.07E-02
6.01 E-03
6.28E-03
1.41 E-02
1.98E-02
3.93E-03
4.26E-02
1.25E-03
5.97E-03
6.33E-03
6.05E-03
1.68E-02
1.63E-03
2.00E-02
2.27E-01
2.38E-02
1.82E-02
4.74E-03
1.74E-02
2.12E-02
1.20E-02
1.77E-02
3.25E-03
1.78E-02
37.90
6.55
3.90
7.70
19.75
0.49
0.30
15.72
10.25
4.77
3.16
2.71
1.13
0.94
4.00
5.82
7.29
3.89
2.58
114.06
7.56
3.33
7.64
6.50
4.49
2.20
2.55
1.72
7.41
0.275
0.048
0.028
0.056
0.143
0.004
0.002
0.114
0.074
0.035
0.023
0.020
0.008
0.007
0.029
0.042
0.053
0.028
0.019
0.828
0.055
0.024
0.055
0.047
0.033
0.016
0.019
0.012
0.054
25
-------
TABLE 3-5. (Continued)
location
Compound (a)
n-Cresol
>-C(eso!
.2-Oibromo-3-chloropropane
1 ,4-Dichlorobenzene
Oichloroethvl ether
1 ,3-Dichloropropene
lichlorvos
N.N-Diethyl aniline
Dimethyl carbamoyl chloride
Dimethyl formamide
1,1-Dimethvl hydrazine
Dimethyl phthalate
1.4-Dioxane
zpichlorohydrin
Ethyl Acrylate
ithylene Oichloride
Ethylidene dichloride
:orm aldehyde
Hexachlorobutadiene
Hexachlorocylcopentadiene
Hexachloroethane
Hexamethvlphosphoramide
Isophorone
Maleic Anhydride
Methyl hydrazine
Naphthalene
Nitrobenzene
N-Nitrosodimethylene
Analytical Region (b)
915.55 - 939.18
2865.70 - 2893.00
2959.13 - 2985.82
995.96 - 1031.06
2662.14 - 3089.07
768.00 - 791.00
967.79 - 1000.25
2655.32 - 3156.07
889.S5 - 917.52
2824.80 - 2873.60
856.12 - 974.09
1157.86 - 1254.16
2967.40 - 2970.30
943.52 - 981.73
1181.93 • 1210.00
712.00 - 736.00
930.35 - 1126.16
2788.33 - 2842.20
976.90 - 997.70
1227.02 - 1240.42
785.50 - 793.00
949.42 - 1019.53
2681.20 - 3130.60
338.45 - 841.30
2683.00 - 3061.78
779.31 - 783.55
841.70 • 861.39
928.00 - 1085.28
Turbine Outlet
Max In-Cell Max Outlet
RMS (c) Cone, (ppm) (d) Cone, (ppm) (e
3.84E-03
1.57E-03
9.67E-03
3.22E-03
2.58E-02
1.04E-02
2.11E-03
5.30E-02
3.21 E-03
1.57E-03
8.81 E-03
2.25E-02
3.17E-03
4.23E-03
9.24E-03
2.99E-02
9.68E-03
2.04E-03
1.39E-03
5.82E-03
1.01E-02
4.04E-03
5.41 E-02
4.39E-03
2.24E-02
3.39E-03
1.73E-02
8.52E-03
2.37
2.81
16.26
1.38
31.60
2.08
0.29
30.20
0.79
0.97
7.11
11.66
0.95
3.38
0.46
5.25
13.29
2.01
0.19
0.43
0.44
0.54
33.60
0.43
24.04
0.32
6.67
2.58
0.016
0.019
0.109
0.009
0.212
0.014
0.002
0.203
0.005
0.007
0.048
0.078
0.006
0.023
0.003
0.035
0.089
0.014
0.001
0.003
0.003
0.004
0.226
0.003
0.161
0.002
0.045
0.017
Stack
Max. In-Cell Max Stack
RMS Cone, (ppm) Cone, (ppm)
4.93E-02
1.04E-03
4.82E-03
1.27E-02
4.77E-03
9.97E-03
2.39E-02
5.31 E-03
1.38E-02
1.04E-03
4.25E-02
1.69E-02
1.18E-03
5.69E-02
1.02E-02
4.44E-02
3.88E-02
1.14E-03
1.58E-02
4.91 E-03
9.61 E-03
4.36E-02
5.35E-03
2.35E-03
4.24E-03
5.70E-03
1.96E-02
4.32E-02
30.32
1.86
8.11
5.46
5.83
1.99
3.33
3.03
3.39
0.64
34.29
8.75
0.35
45.53
0.51
7.81
53.25
1.12
2.16
0.36
0.42
5.82
3.32
0.23
4.54
0.55
7.57
13.10
0.220
0.014
0.059
0.040
0.042
0.014
0.024
0.022
. 0.025
0.005
0.249
0.064
0.003
0.331
0.004
0.057
0.387
0.008
0.016
0.003
0.003
0.042
0.024
0.002
0.033
0.004
0.055
0.095
26
-------
TABLE 3-5. (Continued)
Location
Compound (a)
il-Nitrosomorpholine
'henol
leta-Propiolactone
'ropionaldehyde
1 ,2-Propylenimine
Quioline
Styrene Oxide
1 . 1 ,2.2-Tetrachloroetnane
2.4-Toluene diisocvanate
a-Toluidine
1 .2.4-Trichlorobenzene
2.4.5-Trichlorophenol
2.4,6-Trichlorophenol
Criethylamine
Analytical Region
-------
3.3.2 Instrumental and Manual Test Results
In accordance with standard turbine emission test requirements (i.e.,
Subpart GG and EPA Method 20), a preliminary 02 traverse was conducted
immediately prior to initiating Run 1 to determine an appropriate measurement
point location. Other probes were installed and could not be removed while
the turbine was in operation, therefore, only three of the six sample ports
were traversed during this check. The traverse point locations and
corresponding 02 measurements are presented in Figure 3-1. These results
indicated no change in the 02 levels across the duct; therefore, the probes
were positioned at a depth of 3 ft. within the duct for the testing.
Table 3-6 summarizes the results of the EPA Methods 3A and 10 tests as
described in Section 4.3. All CEM results in the table were determined from
the average gas concentration measured during the run and adjusted for the
pre- and post-test run calibration check results (Equation 6C-1 presented in
EPA Method 6C, Section 8). Although not required by Method 10, the same data
reduction procedures as that in Method 3A were used for the CO determinations
to improve the quality of the data. All measurement system calibration bias
and calibration drift checks for each test run met the applicable
specifications contained in the test methods.
No HC data were available from the test because the analyzer
malfunctioned during the first test run. Each test run CO emission rate was
computed using the averaged concentration measurement for the test run, the
flue gas volumetric flow rate, and the appropriate conversion factors.
The turbine exhaust gas flow rates used to compute mass emissions in
units of Ib/hr were determined using EPA Method 19 procedures and the
measured flue gas 02. An on-line process gas chromatograph analyzes a natural
gas sample every hour at the Wharton facility. The fuel analysis data
supplied by the source are included in Appendix B. The analysis data
collected for each test period were averaged. This information and the
amount of fuel fired by the turbine were used to compute the heat consumption
and Fd-factor needed to compute the dry exhaust gas volumetric flow rate (in
units of dry standard cubic feet per minute, dscfm) for each test run (see
Table 3-7). Wet basis flow rates (wscfm) were computed based on 13% H20 in
the flue gas.
As a quality assurance check of the 02 and C02 data, F0 factors were
calculated for each test run. The calculated F0 results presented in Table
3-8 are within the range of acceptable values.
28
-------
O 2 Measurements
Depth
r
2
3
4'
5
e
A
15.2
15.2
15.2
15.2
15.2
15.2
Port
B
15.1
15.2
15.2
15.2
15.2
15.2
C
15.1
15.1
15.1
15.1
15.1
15.1
T/Cand Sample
Pitot Conc-
F E| D
1
2
3
4
5
6
n rtfti f
1
C B A
i n n n
r-3"
Section K-K
Unit 41
Gas-Fired
Gas Turbine
Damper
Diffuser
Stack
501049/93
Figure 3-1. C>2 traverse data; HRSG Inlet.
29
-------
TABLE 3-6. SUMMARY OF CEM TEST RESULTS FROM T.H. WHARTON UNIT 41 HRSG INLET
DATE
5/17/93
5/18/93
5/18/93
RUN
#
1
2
3
SAMPLE
TIME
1804-1939
1140-1208
1226-1431
1521-1624
1635-1654
SAMPLING
SYSTEM
to FTIR
Hot/Wet
Hot/Wet
Condenser
Perma Pure
Hot/Wet
02
(%d)
15.1
15.1
15.1
15.1
15.1
C02
(%d)
3.3
3.3
3.3
3.4
3.4
CO"
Ppmd
1.8
2.3
1.9
2.4
2.7
Ib/hr
2.8
3.7
3.0
3.9
4.4
FLOW
RATE
(wscfm)
413,521
418,557
433,541
FLOW
RATE
(dscfm)
359,763
364,145
377,181
The CO emissions rates were calculated using dry basis
concentrations and flow rate data.
TABLE 3-7. TURBINE EXHAUST GAS VOLUMETRIC FLOW RATE DETERMINATIONS.
RUN
NO.
1
2
3
GCV
(Btu/ft3)
1010.15
1009.91
1026.83
AVG. FUEL
FLOW
(mmftVday)
16.5
16.7
17.0
HEAT
CONSUMPTION
(mmBtu/hr)
694.48
702.73
727.34
Fd
(dscf/mmBtu)
8625.6
8628.2
8634.7
02
(%d)
15.1
15.1
15.1
FLUE
GAS
FLOW
(dscfm)
359,763
364,145
377,181
TABLE 3-8. VALIDATION OF 0, AND CO, MEASUREMENT DATA
RUN NO.
1
2
3
02
(%d)
15.1
15.1
15.1
C02
(%d)
3.3
3.3
3.4
CALCULATED
F0
1.76
1.76
1.71
Calculated F0 = (20.9-%02) / %C02
EPA Method 3 acceptance criteria,
F0 range: 1.64 - 1.88 for natural gas
30
-------
3.3.3 Process Operation During Testing
3.3.3.1 Process Results Table 3-9 and Figures 3-2, 3-3, and 3-4 present the
process results and can be found immediately following this section.
3.3.3.2 Problems and/or Variations during Testing During Run 1 (2:45 p.m.
to 6:45 p.m., 5/17/93), there were no process operations that would interfere
with testing.
During Run 2 (11:00 a.m. to 3:23 p.m., 5/18/93), a piece of test
equipment overheated and was replaced with a reserve unit. The Run was
stopped during the down time, then restarted. The Run was extended to
achieve a total Run time of 4-hours.
During Run 3 (3:55 p.m. to 7:55 p.m., 5/18/93), the turbine's megawatt
output increased. This increase was due to a thunderstorm that passed over
the plant. GT 41 obtains its combustion air from ambient air outside the
unit. As the temperature dropped, the air density increased and the mass
flow through the turbine also increased, although fuel flow stayed
essentially the same. This increased mass flow provided more power to the
turbine and, thus, greater megawatt generation.
31
-------
TABLE 3-9.
Process Data Sheet: Houston Lighting and Power Co., T. H. wharton, Unit 4
Date
Testl
5/17/93
5/17/93
Time
MW
Operating capacity
2:45 PMl 52.0
3:01 PMl 52.0
5/17/93 i 3:16 PMl 52.0
5/17/93
5/17/93
5/17/93
5/17/93
5/17/93
5/17/93
5/17/93
5/17/93
5/17/93
5/17/93
5/17/93
5/17/93
5/17/93
5/17/93
Test 2
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
3:31 PMl 52.0
3:45 PMl 52.0
4:00 PMl 52.0
4:15 PMl 52.0
4:30 PMl 52.0
4:45 PMl 52.0
5:00 PM
5:15 PM
52.0
52.0
5:30 PM| 52.0
5:45 PMl 52.0
6:00 PM
6:15 PM
52.0
52.0
6:30 PMl 52.0
6:45 PMl 52.0
11:00 AMI 53.0
11:15 AM| 52.2
11:30 AM
11:45 AM
12:00 PM
12:15 PM
12:30 PM
12:45 PM
1:00 PM
1:15 PM
1:30 PM
52.1
52.1
52.5
52.1
52.1
52.1
52.1
52.1
52.1
1:45 PM| 52.1
5/1 8/93 1 2:00 PMl 52.1
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
TcstS
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
5/18/93
2:15 PM| 52.1
2:30 PMl 52.5
2:45 PMl 52.7
3:00 PMl 53.0
3:23 PM
3:55 PM
4:10 PM
4:25 PM
4.40 PM
4:55 PM
5:10 PM
53.0
54.0
55.0
55.2
55.7
55.7
55.0
5:25 PMl 55.0
5:40 PM| 55.0
5:55 PM
6: 10PM
6:25 PM
55.0
55.0
55.5
6:40 PM| 55.4
6:55 PMl 55.7
7:10 PMJ 55.6
5/18/93! 7:25 PMl 55.8.
5/18/931 7:40 PMl 56.0
5/18/931 7:55 PMl 56.0
DegF
Turbine gas exit temp.
989
989
989
990
990
990
990
990
990
990
990
990
990
990
990
990
990
989
989
989
990
989
990
990
990
990
990
990
989
989
989
989
989
990
985
985
990
990
990
990
990
990
990
990
990
990
990
990
990
990
990
990
DcgF
Stack gas exit temp
300
300
299
299
299
299
299
298
299
299
299
299
299
299
299
299
298
297
290
291
293
296
295
295
295
2%
297
297
297
295
295
295
295
295
295
295
298
298
295
295
298
298
298
298
298
299
298
299
298
299
299
299
Million cubic feet/day
Natural Gas Flow
16.5
16.6
16.6
16.6
16.5
16.5
16.5
16.4
16.4
16.5
16.5
16.6
16.6
16.5
16.5
16.6
16.6
16.8
16.8
16.8
16.8
16.7
16.7
16.7
16.6
16.6
16.6
16.6
16.6
16.6 '
16.6
16.8
16.8
16.7
16.7
16.9
17.0
17.0
17.1
17.0
17.0
16.9
16.9
17.0
16.9
17.0
17.0
17.0
17.0
17.0
17.1
17.0
32
-------
54
994
OJ
GJ
53
52
51
50
2:45 p m. 3:18 p.m. 3:45 p.m. 4:15 p m. 4:45 p.m. 5:15 p.m. 5.45 p m. 6:15 p.m. 6:45 p.m.
3.01 p m. 3:31 p.m. 4.00 p m. 4:30 p.m. 5:00 p.m. 5:30 p m. 6 00 p.m. 6:30 p m.
Generator Output, Megawatts
17
16.8
16.6
16.4
16.2
16
2:45 p m. 3:16 p.m. 3:45 p.m. 4.15 pm 4 45 p m. 5:15 p m. 5 45 p m. 6:15 pm 6:45 p m
3O1 p.m. 3.31 p.m. 4:00 pm. 430p.m. 5.OOpm S30pm 6OOpm 6:30 p.m.
Natural Gas Flow (MCFD)
MCFD = miHion cubic feet /day
992
990
988
986
2:45 p m. 3:16 p.m. 3:45 p m. 4:15 p m. 4.45 p.m. 5:15 p.m. 5:45 p m. A.I 5 p m 6 45 p n>
301 p m. 3.31 p m. 4:00 p m. 4:30 p.m. 5.00p.m. 5 30 p m. 6 00 p m 6 30 p m
Turbine gas exit temp. (F)
310
305
300
295
290
2:45 p m. 316pm 3:45 p.m. 4:IS p.m. 4:45 p.m. 5:15pm. 5:45 p m. 6:15 p m 6
-------
oo
54
53
52
51
50
1l:00rm. 11:30«m. 12:00p.m. 12:30pm. 1:00pm. 1:30p.m, 2:00pm. 2:30p.m. 3:00p.fn.
11:ISi.m. Il45tm 1215pm 1245pm. 115pm MS p.m. 215pm 245pm. J23pr
Generator Output, Megawatts
17.2
17
16.8
16.6
16.4
16.2
11.00a.m. I130«m. 1200pm 1230pm lOOpm 130pm. 200pm 230pm 300p.m.
11:1Sim. 11:4Sim 12:15 pm 12:45 pm. 1.15pm 1:45 pm 2:15 pm 245pm 323 pn
Natural Gas Flow (MCFD)
MCFO = million cubic feet / day
992
990
988
986
984
11:00 «m 11:30im 1200pm 1230pm 100pm. 1.30pm. 200pm. 230pm 300pm
I1:l5i. m. ll:4S«m 1215pm 12:45 pm 1:15pm. 1:4Spm 215pm 245pm 323pm
Turbine gas exit temp. (F)
305
300
295
290
285
1l:00i m 1130«m 1200pm 12:30 p.m. t.OOpm. 1:30p.m. 2:00 pm 2:30 pm 300pm
1l:15«.m 11:45 «m 12.15pm 1245pm. 1:l5pm 1:45p.m. 2:15pm 245pm 323pm
Stack gas exit temp. (F)
Figure 3-3.
Houston Lighting & Power Co., T. H. Wharton, Unit Four, Test #2, (5/18/93,11:00 a.m.-3:23 p.m.)
-------
OJ
on
56.5
56
55.5
55
54.5
54
53.5 ^
3:55 p.m. 4:25 p.m. 4:55 p.m. 5.25 p.m. 5 55 p.m. 6:25 p m. 6.55 p.m. 7:25 p.m. 7:55 p.m.
4:1 Op.m. 4:40 p m. 5:1 Op m. 5:40p.m. 6:10 p m. 6:40 p.m. 7:10p.m. 7:40p.m.
Generator Output, Megawatts
17.4
17.2
17
16.8
16.6
355 p m. 425 pm. 455 p m. 525 p m. 5.55 pm 625 p.m. 6:55 p m. 725p.m. 7:55 pm
4:10 p.m. 4:40 p m. 5:10 pm. 5:40 p.m. 6:10 pm. 6:40 p m 7:10 p.m. 7:40 p.m.
Natural Gas Flow (MCFD)
MCFD = million cubic feet / day
994
993
992
991
990
989
988
987
986
985
984
3:55 p m. 4:25 p m. 4:55 p.m. 5:25 p.m. 5.55 p m. 6:25 p.m. 6:55 p m 7.25 p m. 7 55 p m
4:10 p m. 4:40p.m. 5:1 Op.m. 5:40p m. 6:1 Op.m. 6:40p m. 7:10p m 7 40p m
Turbine gas exit temp. (F)
305
300
295
290
285
3.55 p.m. 4:25 p.m. 4:55 p.m 5:25 p.m. 5:55 p.m. 6:25 p.m. 6 55 p m. 7:25 p m. 7 55 p m
4:10 p m. 4:40 p.m. 5:10 p m 5:40 pm. 6:10 p.m. 6:40 p m. 7:1 Opm. 7 40 p m
Stack gas exit temp. (F)
Figure 3-4.
Houston Lighting & Power Co., T. H. Wharton, Unit Four, Test #3, (5/18/93, 3:55 p.m.-7:55 p.m.)
-------
4.0 SAMPLING AND ANALYTICAL PROCEDURES
The FTIR analysis is done using two different experimental techniques.
The first, referred to as direct gas phase analysis, involves transporting
the gas stream to the sample manifold so it can be sent directly to the
infrared cell. This technique provides a sample similar in composition to
the flue gas stream at the sample point location. Some compounds may be
affected because of contact with the sampling system components or reactions
with other species in the gas. A second technique, referred to as sample
concentration, involves concentrating the sample by passing a measured volume
through an absorbing material (Tenax) packed into a U-shaped stainless steel
collection tube. After sampling, the tube is heated to desorb any collected
compounds into the FTIR cell. The desorbed sample is then diluted with
nitrogen to one atmosphere total pressure. Concentrations of any species
detected in the absorption cell are related to flue gas concentrations by
comparing the volume of gas collected to the volume of the FTIR cell.
Desorption into the smaller FTIR cell volume provides a volumetric
concentration related to the volume sampled. This, in turn, provides a
corresponding increase in sensitivity for the detection of species that can
measured using Tenax. Sample concentration makes it possible to achieve
lower detection limits for some HAPs.
Infrared absorbance spectra of gas phase and concentrated samples were
recorded and analyzed. In conjunction with the FTIR sample analyses,
measurements of (HC), (CO), (02), and (C02) were obtained using gas analyzers.
Components of the emission test systems used by Entropy for this testing
program are described below.
4.1 EXTRACTIVE SYSTEM FOR DIRECT GAS PHASE ANALYSIS
An extractive system, depicted in Figure 4-1, was used to transport the
gas stream from the turbine exhaust duct directly to the infrared cell.
4.1.1 Sampling System
Flue gas was extracted through a stainless steel probe. In order to
protect the Teflon® sampling system components, a thermocouple was installed
at the outlet of the probe to verify that the sample gas temperatures had
been lowered to approximately 350°F before entering the heated line. A
Balston® particulate filter rated at 1 micron was installed at the outlet of
the sample probe. A 100-foot length of heated 3/8-inch O.D. Teflon® sample
line connected the probe to the heated sample pump (KNF Neuberger, Inc. model
number N010 ST.Ill) located inside the mobile laboratory. The temperature of
the sampling system components was maintained at about 300°F. Digital
temperature controllers were used to control and monitor the temperature of
the transport lines. All connections were wrapped with electric heat tape
and insulated to ensure that there were no "cold spots" in the sampling
system where condensation might occur. All components of the sample system
were constructed of Type 316 stainless steel or Teflon®. The heated sample
flow manifold, located in the FTIR truck, included a secondary particulate
filter and valves that allowed the operator to send sample gas directly to
the absorption cell or through a gas conditioning system.
36
-------
The extractive system can deliver three types of samples to the
absorption cell. Sample sent directly to the FTIR cell is considered
unconditioned, or "hot/wet." This sample is thought to be most
representative of the actual effluent composition. The removal of water
vapor from the gas stream before analysis was sometimes desirable; therefore,
a second type of sample was provided by directing gas through a condenser
system. The condenser employed a standard Peltier dryer to cool the gas
stream to approximately 38°F. The resulting condensate was collected in two
traps and removed from the conditioning system with peristaltic pumps. This
technique is known to leave the concentrations of inorganic and highly
volatile compounds very near to the (dry-basis) stack concentrations. A
third type of sample was obtained by passing the gas stream through a series
of PermaPure® dryers. This system utilized a network of semi-permeable
membranes. Water vapor was drawn through the membrane walls by a
concentration gradient, which was established by a counter flow of dry air
along the outside of the membrane walls. In addition to protecting the
absorption cell, water removal relieved spectral interferences, which could
limit the effectiveness of the FTIR analysis for particular compounds.
4.1.2 Analytical System
The FTIR equipment used in this test consists of a medium-resolution
interferometer, heated infrared absorption cell, liquid nitrogen cooled
mercury cadmium telluride (MCT) broad band infrared detector, and computer
(see Figure 4-2). The interferometer, detector, and computer were purchased
from KVB/Analect, Inc., and comprise their base Model RFX-40 system. The
nominal spectral resolution of the system is one wavenumber (1 cm ). Samples
were contained in a model 5-22H infrared absorption cell manufactured by
Infrared Analysis, Inc. The inside walls and mirror housing of the cell were
Teflon® coated. Cell temperature was maintained at 240°F using heated jackets
and temperature controllers. The absorption path length of the cell was set
at 22 meters.
4.1.3 Sample Collection Procedure
t
During operation of the gas turbine, the flue gas temperatures of 990°F
and a positive pressure of about 20 inches of water at the sampling location
presented a safety concern. Therefore, according to agreement with the
plant, the turbine was not operated until installation of the sampling probes
was completed. Once installation was completed, the plant fired the turbine
and the test proceeded.
During all three test runs, direct gas phase analysis was performed at
the stack concurrent with the sample concentration testing. Over each 4-hour
test run, flue gas continuously flowed through the heated system to the
sample manifold in the FTIR truck. A portion of the gas stream was diverted
to a secondary manifold located near the inlet of the FTIR absorption cell.
The cell was filled with sample to ambient pressure and the FTIR spectrum
recorded. After analysis, the cell was evacuated so that a subsequent sample
could be introduced. The process of collecting and analyzing a sample and
then evacuating the cell to prepare for the sample required less than 10
minutes. During each run, about 12 gas phase samples were analyzed.
37
-------
OJ
oo
Vent
In-Stack
Paniculate
Filter
Heated
Transport
Lines
Extractive
Probe
Heated
Pump
Heated
Manifold
FTIR
Cell
02
Analyzer
J.
CO
Analyzer
50104 9/93
Figure 4-1. Direct extraction gas handling system.
-------
OJ
IO
To To
Vacuum Vent
Pump
Preheated
N2
50104 9/93
Figure 4-2. Top view of FTIR measurement system.
-------
4.2 SAMPLE CONCENTRATION
Sample concentration was performed using the adsorbent material Tenax,
followed by thermal desorption into the FTIR cell. The sample collection
system employed equipment similar to that of the Modified Method 5 sample
train.
4.2.1 Sampling System
Figure 4-3 depicts the apparatus used in this test program. Components
of the sampling train included a heated stainless steel probe, heated filter
and glass casing, stainless steel air-cooled condenser, stainless steel
adsorbent trap in an ice bath, followed by two water-filled impingers, one
knockout impinger, an impinger filled with silica gel, a sample pump, and a
dry gas meter. All heated components were kept at a temperature above 120°C
to ensure no condensation of water vapor within the system. The stainless
steel condenser coil was used to pre-cool the sample gas before it entered
the adsorbent trap. The trap was a specially designed stainless steel Li-
shaped collection tube filled with 10 grams of Tenax and plugged at both ends
with glass wool. Stainless steel was used for the construction of the
adsorbent tubes because it gives a more uniform and more efficient heat
transfer than glass.
Each sampling run was 4-hours at approximately 0.12 to 0.13 1pm for a
total sampled volume of about 30 to 40 dcf. The sampling rate depended on
the sampling train used and was close to the maximum that could be achieved.
Collection times provided a volumetric concentration that was proportional to
the total volume sampled. The resulting increase in sensitivity should allow
detection to concentrations below 1 ppm for some HAPs.
4.2.2 Analytical System
Before analysis condensed water vapor was removed from the collection
tubes using a dry nitrogen purge for about 15 minutes. Sample analyses were
performed using thermal desorption-FTIR., The sample tubes were wrapped with
heat tape and placed in an insulated chamber. One end of the tube was
connected to the inlet of the evacuated FTIR absorption cell. The same end
of the tube that served as the inlet during the sample concentration run
served as the outlet for the thermal desorption. Gas samples were desorbed
by heating the Tenax to 250°C. A preheated stream of UPC grade nitrogen was
passed through the adsorbent and into the FTIR absorption cell. About
7 liters of nitrogen (at 240°F) carried the desorbed gases to the cell and
brought the total pressure of the FTIR sample to ambient pressure. The
infrared absorption spectrum was then recorded. The purging process was
repeated until no evidence of additional sample desorption was noted in the
infrared spectrum.
4.2.3 Sample Collection Procedure
During each 4-hour run, sample concentration testing was conducted at
the turbine outlet. During Run 2 a sample was also collected simultaneously
at the stack. The sample concentration test apparatus was set up at the
location after Entropy performed leak checks of the system. Sample flow,
40
-------
temperature of the heated box, and the tube outlet temperature were monitored
continuously and recorded at 10-minute intervals. At the end of each run,
sampling was interrupted and the collection tube was removed. The open ends
were tightly capped and the tube was stored on ice until it was analyzed. In
most cases, the tubes were analyzed within several hours after the sample
run.
41
-------
Heated
Filter Box
J
Probe
Duct Wall
Gas
Flow
Thermocouples
Heated
Teflon
Line
Air-Cooled
Condenser
Coil
T ) Thermocouple
Bypass
Valve
ft?
Vacuum Line ^
Main Valve
50104 9/93
Figure 4-3. Sample concentration sampling system.
-------
4.3 CONTINUOUS EMISSIONS MONITORING
Entropy's extractive measurement system and the sampling and analytical
procedures used for the determinations of HC, CO, 02, and C02 conform with the
requirements of EPA Test Methods 25A, 10, and 3A, respectively, of 40 CFR 60,
Appendix B. A heated extractive sampling system and a set of gas analyzers
were used to analyze flue gas samples extracted at the turbine outlet sample
point location. The analyzers received gas samples delivered from the same
sampling system that supplied the FTIR cell with condenser sample. These gas
analyzers require that the flue gas be conditioned to eliminate any possible
interference (i.e., particulate matter and/or water vapor) before being
transported and analyzed. All components of the sampling system that contact
the gas sample were Type 316 stainless steel and Teflon®.
A gas flow distribution manifold downstream of the heated sample pump
was used to control the flow of sample gas to each analyzer. A refrigerated
condenser removed water vapor from the sample gas analyzed by all the
analyzers except for the HC analyzer (Method 25A requires a wet basis
analysis). The condenser was operated at approximately 38°F. The condensate
was continuously removed from the traps within the condenser to minimize
contact between the gas sample and the condensate.
The sampling system included a calibration gas injection point
immediately upstream of the analyzers for the calibration error checks and
also at the outlet of the probe for the sampling system bias and calibration
drift checks. The mid- and high-range calibration gases were certified by
the vendor according to EPA Protocol 1 specifications. Methane in air was
used to calibrate the HC analyzer.
A computer-based data acquisition system was used to provide an
instantaneous display of the analyzer responses, as well as compile the
measurement data collected each second, calculate data averages over selected
time periods, calculate emission rates, and document the measurement system
calibrations.
Table 4-1 presents a list of the analyzers that Entropy used during the
test program. Figure 4-1 presents a simplified schematic of Entropy's
reference measurement system.
The test run values were determined from the average concentration
measurements displayed by the gas analyzers during the run and are adjusted
based on the zero and upscale sampling system bias check results using the
equation presented in Section 8 of Method 6C. The CEM data are presented in
Appendix A.
43
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TABLE 4-1. GAS ANALYZERS USED DURING THE TEST PROGRAM
PARAMETER (RANGE)
HC (0-10 ppmj
CO (0-100 ppmd)
C02 (0-20%d)
02 (0-25%d)
ANALYZER
Ratfisch Model RS255CA
Thermo Environmental
Model 48
Fuji Model 3300
Teledyne 320P-4
ANALYTICAL TECHNIQUE
Flame ionization
detector (FID)
Infrared gas filter
correlation (GFC)
Non-dispersive infrared
(NDIR)
Micro-fuel cell
4.4 FLOW DETERMINATIONS
Because of the high flue gas temperature and pressure conditions, it was
not possible to perform velocity traverses at point locations according to
EPA Method 1 specifications. In lieu of pitot measurements, flue gas
volumetric flow was determined using mass balance calculations based on the
natural gas fuel usage rate, fuel composition, exhaust gas diluent
concentrations, and an F-factor as outlined in EPA Method 19 (40 CFR 60).
The natural gas feed rate to the turbine was a process parameter
recorded by the RTI representative during the test program. The rates were
recorded at 15-minute intervals and then averaged for each test run period.
The Wharton facility operates an on-line gas chromatograph that analyzes a
natural gas sample every hour. This analysis data was supplied to EPA so
that the gross calorific value (GCV, in units of Btu/ft3) and Fd-factor (in
units of dry standard cubic feet of combustion gas generated per million Btu
of heat input, dscf/MM-Btu) could be determined for the computation of the
flue gas volumetric flow rates.
A pitot tube was positioned adjacent to the point where the sample
concentration probe was inserted. Single point AP values were recorded at 10
minute intervals to verify that flow characteristics, at the sampling point,
were not changing significantly during the test.
Heat consumption of the turbine was calculated from the fuel data:
HC = GCV x FQT x 3600E'6
(1)
where:
HC =
GCV =
FQT =
Heat Consumption (mmBtu/hr)
Gross Calorific Value of Fuel (Btu/ft3) from fuel analysis
data provided by Wharton.
Fuel Flow Rate (mmft3/day) provided by Wharton.
44
-------
The dry exhaust gas flow rate was calculated using EPA Method 19 procedures:
DSCFH = F °9
20.9-%02J
where:
Fd = Dry basis F-factor (dscf/mmBtu) determined from fuel analysis,
%02d = dry basis concentration measurement from EPA Method 3A
45
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4.5 PROCESS OBSERVATIONS
During the testing, an RTI representative monitored the process
operations so that emissions test data could be correlated with process
conditions. The process observations are presented in Section 3.3.3.
4.6 ANALYTICAL PROCEDURES
4.6.1 Description of K-Matrix Analyses
K-type calibration matrices were used to relate absorbance to
concentration. Several descriptions of this analytical technique can be
found in the literature2. The discussion presented here follows that of
Haaland, Easterling, and Vopicka3.
For a set of m absorbance reference spectra of q different compounds
over n data points (corresponding to the discrete infrared wavenumber
positions chosen as the analytical region) at a fixed absorption pathlength
b, Beer's law can be written in matrix form as
= KC+E
(3)
where:
K =
C =
The n x m matrix representing the absorbance values of the m
reference spectra over the n wavenumber positions, containing
contributions from all or some of the q components;
The n by q matrix representing the relationship between absorbance
and concentration for the compounds in the wavenumber region(s) of
interest, as represented in the reference spectra. The matrix
element K,,,, = banq, where anq is the absorptivity of the qth
compound at the nth wavenumber position;
The q x m matrix containing the concentrations of the q compounds
in the m reference spectra;
E =
"errors"
The n x m matrix representing the random
the analysis; these errors are not actually
Beer's law, but actually arise from
misrepresentation (instrumental distortion)
in Beer's law for
due to a failure of
factors such as
of the absorbance
values of the reference spectra,
spectrum concentrations.
or inaccuracies in the reference
The quantity which is sought in the design of this analysis is the
matrix K, since if an approximation to this matrix, denoted by K, can be
found, the concentrations in a sample spectrum can also be estimated. Using
the vector A* to represent the n measured absorbance values of a sample
46
-------
spectrum over the wavenumber region(s) of interest, and the vector C to
represent the j estimated concentrations of the compounds comprising the
sample, C can be calculated from A* and K from the relation
£= [^Sr'K'A* . (4)
Here the superscript t represents the transpose of the indicated matrix, and
the superscript -1 represents the matrix inverse.
; = ACfc[CCfc ]
"1
The standard method for obtaining the best estimate K is to minimize the
square of the error terms represented by the matrix E. The equation
represents the estimate K which minimizes the analysis error.
Reference spectra for the K-matrix concentration determinations were de-
resolved to 1.0 cm"1 resolution from existing 0.25 cm"1 resolution reference
spectra. This was accomplished by truncating and re-apodizing4 the interfer-
ograms of single beam reference spectra and their associated background
interferograms. The processed single beam spectra were recombined and
converted to absorbance (see Section 4.3).
4.6.2 Preparation of Analysis Programs
To provide accurate quantitative results,Hv^matrix input must include
absorbance values from a set of reference spectra which, added together,
qualitatively resemble the appearance of the sample spectra. For this
reason, all of the Multicomponent analysis files included spectra
representing interferant species and criteria pollutants present in the flue
gas.
Several factors affect the detection and analysis of .an analyte in the
stack gas matrix. One is the composition of the stack gas. The major
spectral interferant in the gas-fired boiler effluent are water and C02. At
C02 concentrations of about 10 percent and higher, weak absorbance bands that
are normally not visible begin to emerge. Some portions of the FTIR spectrum
were not available for analysis because of extreme absorbance from water and
C02, but most compounds exhibit at least one absorbance band that is suitable
for analysis. Significant amounts of NO, and N02 were also present in the
samples and these species needed to be accounted for in any analytical
program. A second factor affecting analyses is the number of analytes that
are to be detected because the program becomes more limited in distinguishing
overlapping bands as the number of species in the sample increases. A third
factor depends on how well the sample spectra can be modeled. The best
analysis can be made when reference spectra are available to account for all
of the species detected in the sample. When reference spectra are not
47
-------
available for a compound which has been identified, then it becomes more
difficult to quantify other species.
A set of Multicomp program files had been previously prepared for
analysis of data collected at a coal-fired utility for the purpose of
performing statistical validation testing of the FTIR methods. Separate
programs were prepared to measure 47 different compounds. Four baseline
subtraction points were specified in each analytical region, identifying an
upper and a lower baseline averaging range. The absorbance data in each
range were averaged, a straight baseline was calculated through the range
midpoint using the average absorbance values, and the baseline was subtracted
from the data prior to K-matrix analysis.
Before K-matrix analysis was applied to data all of the spectra were
inspected to determine what species had been detected. Program files were
constructed that included reference spectra representing the detected species
and were then used to calculate concentrations of the detected species.
Sample concentration spectra were also analyzed using program files that were
shown by the validation testing to be suitable for measuring some HAPs.
4.6.3 Error Analysis of data
The principal constituents of the gas phase samples were water, C02, NO,
and N02. A program file was prepared to quantify each of these compounds.
Other than these species and N20 no major absorbance features were observed
in the spectra. After concentrations of the main constituents were
determined, the appropriate standard was scaled and subtracted from the
spectrum of the sample mixture. This helped verify the calculated values.
New spectra were generated from the original absorbance spectra by
successively subtracting scaled standard spectra of water, C02, NO, and N02.
The resulting "subtracted" spectra were analyzed for detectible absorbencies
of any HAPs and, for undetected species, the maximum possible concentrations
that could have been present in the samples.
Maximum possible (minimum detectible) concentrations were determined in
several steps. The noise level in the appropriate analytical region was
quantified by calculating the root mean square deviation (RMSD) of the
baseline in the subtracted spectrum. The RMSD was multiplied by the width
(in cm"1) of the analytical region to give an equivalent "noise area" in the
subtracted spectrum. This value was compared to the integrated area of the
same analytical region in a standard spectrum of the pure compound. The
noise was calculated from the equation:
RMSD = ' -1- v " " ' v ° " (6>
fl i=i
where:
RMSD = Root mean square deviation in the absorbance values within a
48
-------
region.
Number of absorbance values in the region.
Absorbance value of the ith data point in the analytical
region.
Mean of all the absorbance values in the region.
If a species is detected, then the error in the calculated concentration is
given by:
RMSD x (x2 -
= 2
Area,
x CON,
(7)
where:
Eppm = Noise related error in the calculated concentration, in ppm.
x2 = Upper limit, in cm"1, of the analytical region.
x, = Lower limit, in cm"1, of the analytical region.
AreaR = Total band area (corrected for path length, temperature, and
pressure) in analytical region of reference spectrum of
compound of interest.
CONR = Known concentration of compound in the same reference
spectrum.
This ratio provided a concentration equivalent to measured area in the
subtracted spectrum. For instances when a compound was not detected, the
value Eppm was equivalent to the minimum detectible concentration of that
(undetected) species in the sample.
Some concentrations given in Tables 3-3 to 3-5 are relatively high
(greater than 10 ppm) and there are several possible reasons for this.
• The reference spectrum of the compound may show low absorbance at
relatively high concentrations so that its real limit of detection
is high. An example of this may be acetonitrile.
• The region of the spectrum used for the analysis may have residual
bands or negative features resulting from the spectral subtraction.
In these cases the absorbance of the reference band may be large at
low concentrations, but the RMSD is also large (see Equation 7).
49
-------
An example of this is methyl chloride. If the maximum possible
concentrations for the hot/wet samples (14.42 ppm) and the
condenser samples (6.52 ppm) are compared for methyl chloride, the
drier spectra give a significant improvement because it is easier
to perform good spectral subtraction on spectra where absorbance
from water bands is weaker.
• The chosen analytical region may be too large, unnecessarily
including regions of noise where there is no absorbance from the
compound of interest. An example of this may be ethyl benzene
where the chosen analytical region is more than 250 cm .
In the second and third cases the stated maximum possible concentration
may be lowered by choosing a different analytical region, generating better
subtracted spectra, or by narrowing the limits of the analytical region.
Entropy has already taken these steps with a number of compounds. If more
improvements can be made, they will be included in the final report.
4.6.4 Concentration Correction Factors
Calculated concentrations in sample spectra were corrected for
differences in absorption pathlength between the reference and sample spectra
according to the following relation:
p - fLr^ v ( TS^ v tc \ (ai
'-corr ~ T~ "r" ( '"'
\^B) \Lz
where:
CCOrr = The pathlength corrected concentration.
C0aio = The initial calculated concentration (output of the Multicomp
program designed for the compound)
Lr = The pathlength associated with the reference spectra.
L8 = The pathlength (22m) associated with the sample spectra.
T9 = The absolute temperature of the sample gas (388 K).
Tr = The absolute gas temperature at which reference spectra were
recorded (300 to 373 K).
Corrections for variation in sample pressure were considered, and found
to affect the indicated HAP concentrations by no more that one to two
percent. Since this is a small effect in comparison to other sources of
analytical error, no sample pressure corrections were made.
50
-------
4.6.5 Analysis of Sample Concentration Spectra
Sample concentration spectra were analyzed in the same manner as spectra
of the gas phase samples. To derive flue gas concentrations it was necessary
to divide the calculated concentrations by the concentration factor (CF). As
an illustration, suppose that 10 ft3 (about 283 liters) of gas were sampled
and then desorbed into the FTIR cell volume of approximately 8.5 liters to
give concentration factor of about 33. If some compound was detected at a
concentration of 50 ppm in the cell, then its corresponding flue gas
concentration was about 1.5 ppm. When determining the concentration factor
it was also important to consider that the dry gas meter was cool relative to
the FTIR cell. Also, the total sampled volume was measured after most of the
water was removed. The total volume of gas sampled was determined from the
following relation:
where:
Vfiue = Total volume of flue gas sampled.
Vco, = Volume of gas sampled as measured at the dry gas meter after
it passed through the collection tube.
Tf(ue = Absolute temperature of the flue gas at the sampling location.
T00| = Absolute temperature of the sample gas at the dry gas meter.
W = Fraction (by volume) of flue gas stream that was water vapor.
The concentration factor, CF, was then determined using V{,ua and the
volume of the FTIR cell (Vcell) which was measured at an absolute temperature
(Toell) of about 300 K:
CF = ^ (10)
\ V cell I
Finally, the in-stack concentration was determined using CF and the
calculated concentration of the sample contained in the FTIR cell, Coell.
r
'-flue
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5.0 QUALITY ASSURANCE/QUALITY CONTROL ACTIVITIES
Quality assurance (QA) is defined as a system of activities that
provides a mechanism of assessing the effectiveness of the quality control
procedures. It is a total integrated program for assuring the reliability of
monitoring and measurement data. Quality control (QC) is defined as the
overall system of activities designed to ensure a quality product or service.
This includes routine procedures for obtaining prescribed standards of
performance in the monitoring and measurement process.
The specific internal QA/QC procedures that were used during this test
program to facilitate the production of useful and valid data are described
in this section. Each procedure was an integral part of the test program
activities. Section 5.1 covers method-specific QC procedures for the manual
flue gas sampling. Section 5.2 covers the QC procedures used for the
instrumental methods. QC checks of data reduction, validation and reporting
procedures are covered in Section 5.3, and corrective actions are discussed
in Section 5.4.
5.1 QC PROCEDURES FOR MANUAL FLUE GAS TEST METHODS
This section details the QC procedures that were followed during the
manual testing activities.
5.1.1 Pi tot Tube QC Procedures
The QC procedures for pitot tube AP measurements during the test runs
followed guidelines set forth by EPA Method 2.
The following QC steps were followed during these tests:
• The S-type pitot tube was visually inspected before sampling.
• Both legs of the pitot tube were leak checked before and after
sampling.
• Proper orientation of the S-type pitot tube were maintained while
making measurements. The roll and pitch axis of the S-type pitot
tube was maintained at 90° to the flow.
• The magnehelic set was leveled and zeroed before each run.
• The pitot tube/manometer umbilical lines were inspected before and
after sampling for leaks and moisture condensate (lines were cleared
if found).
• Reported duct dimensions and cross-sectional duct area were verified
by on-site measurements.
• The stack gas temperature measuring system was checked by observing
ambient temperatures prior to placement in the stack.
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The QC procedures that were followed in regards to accurate sample gas
volume determination are:
• The dry gas meter is fully calibrated immediately before the field
test using an EPA approved intermediate standard.
• Pre-test and post-test leak checks were completed and were less than
0.02 cfm or 4 percent of the average sample rate.
• The gas meter was read to a thousandth of a cubic foot for the
initial and final readings.
• Readings of the dry gas meter and meter temperatures were taken every
10 minutes during sample collection.
• Accurate barometric pressures were recorded at least once per day.
• Post-test dry gas meter checks were completed to verify the accuracy
of the meter full calibration constant (Y).
5.1.2 Sample Concentration Sampling QC Procedures
QC procedures that allowed representative collection of organics by the
sample concentration sampling system were:
• Only properly cleaned glassware and prepared adsorbent tubes that had
been kept closed with stainless steel caps were used for any sampling
train.
• The filter, Teflon® transfer line, and adsorbent tube were maintained
at ±10eF of the specified temperatures.
• An ambient sample was analyzed for background contamination.
5.1.3 Manual Sampling Equipment Calibration Procedures
5.1.3.1 Type-S Pi tot Tube Calibration -- EPA has specified guidelines
concerning the construction and geometry of an acceptable Type-S pitot tube.
If the specified design and construction guidelines are met, a pitot tube
coefficient of 0.84 is used. Information pertaining to the design and
construction of the Type-S pitot tube is presented in detail in Section 3.1.1
of EPA document 600/4-77-027b. Only Type-S pitot tubes meeting the required
EPA specifications were used. The pitot tubes'were inspected and documented
as meeting EPA specifications prior to field sampling.
5.1.3.2 Temperature Measuring Device Calibration -- Accurate temperature
measurements are required during source sampling. The bimetallic stem
thermometers and thermocouple temperature sensors used during the test
program were calibrated using the procedure described in Section 3.4.2 of EPA
document 600/4-77-027b. Each temperature sensor is calibrated at a minimum
of three points over the anticipated range of use against a NIST-traceable
mercury-in-glass thermometer. All sensors were calibrated prior to field
sampling.
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5.1.3.3 Dry Gas Meter Calibration -- Dry gas meters (DGMs) were used in the
sample trains to monitor the sampling rate and to measure the sample volume.
All DGMs were fully calibrated to determine the volume correction factor
prior to their use in the field. Post-test calibration checks were performed
as soon as possible after the equipment was returned as a QA check on the
calibration coefficients. Pre- and post-test calibrations should agree
within 5 percent. The calibration procedure is documented in Section 3.3.2
of EPA document 600/4-77-237b.
5.2 QC PROCEDURES FOR INSTRUMENTAL METHODS
The flue gas was analyzed for CO, 02, C02, and HC. Prior to sampling
each day, a pre-test leak check of the sampling system from the probe tip to
the heated manifold was performed and was less than 4 percent of the average
sample rate. Internal QA/QC checks for the instrumental test 'method
measurement systems are presented below.
Method 3A requires that the tester : (1) select appropriate apparatus
meeting the applicable equipment specifications of the method, (2) conduct an
interference response test prior to the testing program, and (3) conduct
calibration error (linearity), calibration drift, and sampling system bias
determinations during the testing program to demonstrate conformance with the
measurement system performance specifications. The performance
specifications are identified in the following table.
TABLE 5-1. INSTRUMENTAL TEST METHOD SPECIFICATIONS.
PERFORMANCE TEST
Analyzer Calibration Error
Sampling System Bias
Zero Drift
Upscale Calibration Drift
Interference Check
SPECIFICATION
± 2% of span for zero, mid-, and
high-range calibration gases
± 5% of span for zero and upscale
calibration gases
± 3% of span over test run period
± 3% of span over test run period
± 7% of the modified Method 6 result
for each run
A three-point (i.e., zero, mid-, and high-range) analyzer calibration
error check is conducted before initiating the testing by injecting the
calibration gases directly into the gas analyzers and recording the
responses. Zero and upscale calibration checks are conducted both before and
after each test run in order to quantify measurement system calibration drift
and sampling system bias. Upscale is either the mid- or high-range gas,
whichever most closely approximates the flue gas level. During these checks,
the calibration gases are introduced into the sampling system at the probe
outlet so that the calibration gases are analyzed in the same manner as the
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flue gas samples. Drift is the difference between the pre- and post-test run
calibration check responses. Sampling system bias is the difference between
the test run calibration check responses (system calibration) and the initial
calibration error responses (direct analyzer calibration) to the zero and
upscale calibration gases. If an acceptable post-test bias check result is
obtained but the zero or upscale drift result exceeds the drift limit, the
test run result is valid; however, the analyzer calibration error and bias
check procedures must be repeated before conducting the next test run. A run
is considered invalid and must be repeated if the post-test zero or upscale
calibration check result exceeds the bias specification. The calibration
error and bias checks must be repeated and acceptable results obtained before
testing can resume.
Although not required by Methods 10 and 25A, the same calibration and
data reduction procedures required by Method 3A were used for the CO and HC
determinations to improve the quality of the reference data.
5.3 QA/QC CHECKS FOR DATA REDUCTION, VALIDATION, AND REPORTING
Data quality audits were conducted using data quality indicators which
require the detailed review of: (1) the recording and transfer of raw data;
(2) data calculations; (3) the documentation of procedures; and (4) the
selection of appropriate data quality indicators.
All data and/or calculations for flow rates, moisture content, and
sampling rates were spot checked for accuracy and completeness.
In general, all measurement data have been validated based on the
following criteria:
• Acceptable sample collection procedures.
• Adherence to prescribed QC procedures.
Upon completion of testing, the field coordinator was responsible for
preparation of a data summary including calculation results and raw data
sheets.
5.3.1 Sample Concentration
The sample concentration custody procedures for this test program are
based on EPA recommended procedures. Because collected samples were analyzed
on-site, the custody procedures emphasize careful documentation of sample
collection and field analytical data. Use of chain-of-custody documentation
was not necessary, instead careful attention was paid to the sample
identification coding. These procedures are discussed in more detail below.
Each spectrum of a sample concentration sample has been assigned a
unique alphanumeric identification code. For example, Tinll25A designates a
Tenax spectrum of a sample taken at the turbine outlet (HRSG inlet), from
sample tube number 25. The A means this is the spectrum of the first
desorption from this tube. Every adsorbent tube has been inscribed with a
tube identification number.
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The project manager was responsible for ensuring that proper custody and
documentation procedures were followed for the field sampling, sample
recovery, and for reviewing the sample inventory after each run to ensure
complete and up-to-date entries. A sample inventory was maintained to
provide an overview of all sample collection activities.
Two ambient samples were prepared at the turbine outlet. One was
obtained before the test began and a second after the test was completed.
One ambient sample was collected at the HRSG outlet. The ambient samples
were run through the identical trains used in the runs. This provided a
check for contamination of the sampling train. The charged ambient tube was
stored and analyzed in the same manner as those obtained during testing.
Ambient runs were 1-hour. The volume of air drawn for the blanks was
sufficient to verify that the sampling train was clean and performing
properly. Because relatively minor contamination was identified from the
ambient samples, it was accounted for in the subsequent analyses of the
sample spectra by using spectral subtraction. Major contamination was not
observed in the samples.
Sample flow at the dry gas meter was recorded at 10 minute intervals.
Results from the analyzers and the spectra of the gas phase samples provided
a check on the consistency of the effluent composition during the sampling
period.
5.3.2 Gas Phase Analysis
During each test run a total of 12 gas phase samples were collected and
analyzed. Each spectrum was assigned a unique file name and a separate data
sheet identifying sample location and sampling conditions. A comparison of
all spectra in this data set provided information on the consistency of
effluent composition and a real-time check on the performance of the sampling
system. Effluent was directed through all sampling lines for at least 5
minutes and the CEMs provided consistent readings over the same period before
sampling was attempted. This requirement was satisfied any time there was a
switch to a different conditioning system. When the cell was being
evacuated, the FTIR was continuously scanning to provide a spectral profile
of the empty cell. A new sample was not introduced until there was no
residual absorbance remaining from the previous one. The FTIR was also
continuously scanning during sample collection to provide a real-time check
on possible contamination in the system.
5.3.3 FTIR Spectra
For a detailed description of QA/QC procedures relating to data
collection and analysis, refer to the "Protocol For Applying FTIR
Spectrometry in Emission Testing." A spectrum of the calibration transfer
standard (CTS) was collected at the beginning and end of each data collection
session. The CTS gas was 100 ppm ethylene in nitrogen. The CTS spectrum
provided a check on the operating conditions of the FTIR instrumentation,
e.g. spectral resolution and cell path length. Ambient pressure was recorded
whenever a CTS spectrum was collected.
Two copies of all interferograms and processed spectra of backgrounds,
samples, and the CTS were stored on separate computer disks. Additional
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copies of sample and CIS absorbance spectra were also stored for use in the
data analysis. Sample spectra can be regenerated from the raw
interferograms, if necessary. FTIR spectra are available for inspection or
re-analysis at any future date.
Pure, dry ("zero") air was periodically introduced through the sampling
system in order to check for contamination. Contamination was not observed,
but on one occasion water condensed in the cell manifold. The lines and cell
were purged with dry N2, until the contamination was eliminated.
As successive spectra were collected the position and slope of the
spectral base line were monitored. If the base line within a data set for a
particular sample run began to deviate by more than 5 percent from 100
percent transmittance, a new background was collected.
5.4 CORRECTIVE ACTIONS
During the course of the test program, it was the responsibility of the
field coordinator and the sampling team members to see that all measurement
data procedures were followed as specified and that measurement data met the
prescribed acceptance criteria.
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6.0 CONCLUSIONS AND DISCUSSION
Entropy conducted an emissions test at T.H. Wharton Electric Generating
Station in Houston, Texas. Direct gas phase analysis, and sample
concentration testing were both performed over two days. At the same time
gas analyzers were used to measure CO, 02, C02, and hydrocarbons in the gas
streams. Three 4-hour sample concentrations runs were conducted at the gas
turbine outlet. Direct gas phase analyses and CEM measurements were
performed concurrently with the sample concentration runs. Additionally, one
4-hour sample concentration run was conducted at the stack during Run 2 at
the turbine outlet.
Gas phase analysis revealed the presence of water vapor, CO, C02, N02 and
NO. HC1, ammonia and nitrous acid (HN02) were detected in sample concen-
tration spectra. Also, some unidentified absorption bands were observed in
the sample concentration spectra.
A primary goal of this project was to use FTIR instrumention in a major
test program to measure as many HAPs as possible or to place upper limits on
their concentrations. Four other electric utilities were tested along with
the T.H. Wharton facility. Utilities present a most difficult testing
challenge for two reasons:
1) They are combustion sources so the flue gas contains high levels of
moisture and C02 (both are spectral interferants).
2) The large volumetric flow rates typical of these facilities can lead
to mass emissions above regulated limits even for HAPs at very low
concentrations. This places great demand on the measurement method
to achieve low detection limits. Furthermore, with natural gas as
the combustion fuel, concentrations of any HAPs formed in the process
would be expected to be very low.
This represents the first attempt to use FTIR spectroscopy in such an
ambitious test program. The program accomplished very significant
achievements and demonstrated important and fundamental advantages of FTIR
spectroscopy as an emissions test method:
• Using a single method quantitative data were provided for over 100
compounds.
• Software was written to analyze a large data set and provide
concentration and detection limit results quickly. The same or
similar software can be used for subsequent tests with very little
investment of time for minor modifications or improvements.
• The original data are permanently stored so the results can be
rechecked for verification at any time.
i
• A single method was used to obtain both time-resolved (direct gas)
and integrated (sample concentration) measurements of gas streams
from two locations simultaneously.
• The two techniques of the FTIR method cover different concentration
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ranges.
• Preliminary data (qualitative and quantitative) are provided on-site
in real time.
• With little effort at optimization (see below), detection limits in
the ppb range were calculated for 26 HAPs and between 1 and 5 ppm for
77 other HAPs using direct gas phase measurements of hot/wet samples,
which present the most difficult analytical challenge. Sample
concentration provided even lower detection limits for some HAPs.
• A compound detect is unambiguous.
It is appropriate to include some discussion about the "maximum possible
concentrations" presented in Tables 3-3 to 3-5. These numbers were
specifically not labeled as detection limits because use of that term could
be misinterpreted, but they will be referred to as "detection limits" in the
discussion below.
In FTIR analysis detection limits are calculated directly from the
spectra (see Section 4.6.3 and the "FTIR Protocol"). These calculated
numbers do not represent fundamental measurement limits, but they depend on
a number of factors. For example:
Some instrumental factors
• Spectral resolution.
• Source intensity.
• Detector response and sensitivity.
• Path length that the infrared beam travels through the sample.
• Scan time.
• Efficiency of infrared transmission (through-put).
• Signal gain.
Some sampling factors
• Physical and chemical properties of a compound.
• Flue gas composition.
• Flue gas temperature.
• Flue gas moisture content.
• Length of sample line (distance from location).
• Temperature of sampling components.
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• Sample flow.
Instrumental factors are adjustable. For this program instrument settings
were chosen to duplicate conditions that were successfully used in previous
screening tests and the validation test. These conditions provide speed of
analysis, durability of instrumentation, and the best chance to obtain
measurements of the maximum number of compounds with acceptable sensitivity.
Sampling factors present the same challenges to any test method.
An additional consideration is that the numbers presented in Tables 3-3
to 3-5 are all higher than the true detection limits that can be calculated
from the 1 cm'1 data collected at T.H. Wharton. This results from the method
of analysis: the noise calculations were made only after all spectral
subtractions were completed. Each spectral subtraction adds noise to the
resulting subtracted spectrum. For most compounds it is necessary to perform
only some (or none) of the spectral subtractions before its detection limit
can be calculated. With more sophisticated software it will be possible to
automate the process of performing selective spectral subtractions and
optimize the detection limit calculation for each compound. (Such an
undertaking was beyond the scope of the current project.) Furthermore, the
detection limits represent averages compiled from the results of all the
spectra collected at the sampling location. A more realistic detection limit
is provided by the single spectrum whose analysis gives the lowest calculated
value. It would be more accurate to think of "maximum possible
concentrations" as placing upper boundaries on the HAP detection limits
provided by these data.
Another important sampling consideration is the sample composition. In
Table 3-3 benzene's detection limit is quoted as 4.83 ppm. This was
determined in the analytical region between 3020 and 3125 cm"1. Benzene
exhibits a much stronger infrared band at 673 cm"1 but this band was not used
in the analysis because absorbance from C02 strongly interfered in this
analytical region. At a lower C02 emission source an identical FTIR
measurement system would provide a benzene detection limit below 1 ppm for
direct gas analysis (even ignoring the consideration discussed in the
previous paragraph).
Any difficulties associated with measuring particular compounds are
related to the sampling conditions and not the FTIR analysis. It was
necessary to cool the flue gas from about 1000°F down to about 300°F. This
introduced the possibility of condensing relatively non-volatile species in
the sampling line. The moisture content of the flue gas was estimated to be
about 15 percent and this should have caused no problem with condensation in
the sampling line. However, water soluble species are more difficult to
measure at higher moisture levels. FTIR techniques offer a good way to
measure unstable or reactive species because FTIR spectrometry can be readily
used to monitor the sampling system integrity. That was not done in this
test because the primary goal was the general one of measuring as many
compounds as possible, not optimizing the measurement system for any
particular compound or set of compounds.
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7.0 REFERENCES
1) "FTIR Method Validation at a Coal-Fired Boiler," EPA Contract No.
68D20163, Work Assignment 2, July, 1993.
2) "Computer-Assisted Quantitative Infrared Spectroscopy," Gregory L.
McClure (ed.), ASTM Special Publication 934 (ASTM), 1987.
3) "Multivariate Least-Squares Methods Applied to the Quantitative Spectral
Analysis of Multicomponent Mixtures," Applied Spectroscopy, 39(10), 73-
84, 1985.
4) "Fourier Transform Infrared Spectrometry," Peter R. Griffiths and James
de Haseth, Chemical Analysis, 83, 16-25,(1986), P. J. Elving, J. D.
Winefordner and I. M. Kolthoff (ed.), John Wiley and Sons,.
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