BACKGROUND OF THE INVENTION
[0001] The invention relates generally to monitoring nitrogen oxide (NOx)
emissions. More particularly, the invention relates to predicting NOx emission rates
from a natural gas-fired boiler, and a method for monitoring and/or reporting NOx
emission rates that conforms to state and federal guidelines, and other reglations for
the aforementioned.
[0002] NOx is the generic term for a group of highly reactive gases, all of
which contain nitrogen and oxygen in varying amounts. Many of the nitrogen oxides
are colorless and odorless. However, one common pollutant, nitrogen dioxide (NO?)
along with particles in the air can often be seen as a reddish-brown layer over many
urban areas. Nitrogen oxides form when fuel is burned at high temperatures, as in a
combustion process. The primary sources of NOx are motor vehicles, electric utilities,
and other industrial, commercial, and residential sources that burn fuels. Combustion
boilers are used globally and produce NOx as a byproduct.
BRIEF DESCRIPTION OF THE INVENTION
[0003] A first aspect of the disclosure provides a method for predicting a
nitrogen oxide (NOx) emission rate of a non-continuous, natural gas-fired boiler, the
method comprising: calculating a correlation of the NOx emission rate to a measured
fuel flow rate, and a sampled oxygen (O2) concentration based on a plurality of
sampled NOx emission concentrations, measured fuel flow rates and sampled (O2)
concentrations during operation of the non-continuous, natural gas-fired boiler using a
1
computing device; calculating a predicted NOx emission rate based on the correlation
with the measured fuel flow rate and the sampled O2 concentration using the
computing device; and providing the predicted NOx emission rate for use by a user.
[0004] A second aspect of the disclosure provides a predictive monitoring
system for a nitrogen oxide (NOx) emission rate comprising: at least one device
including: a calculator for calculating a correlation of the NOx emission rate to a
measured fuel flow rate and a sampled oxygen (O2) concentration based on a plurality
of sampled NOx emission concentrations, measured fuel flow rates, and sampled O2
concentrations during operation of a non-continuous, natural gas-fired boiler; and a
calculator for calculating a predicted NOx emission rate based on the correlation of
the measured fuel flow rate and the sampled O2 concentration.
[0005] A third aspect of the disclosure provides a computer program
comprising program code embodied in at least one computer-readable medium, which
when executed, enables a computer system to implement a method of predicting a
nitrogen oxide (NOx) emission rate of a non-continuous, natural gas-fired boiler, the
method comprising: calculating a correlation of the NOx emission rate to a measured
fuel flow rate, and a sampled oxygen (O2) concentration based on a plurality of
sampled NOx emission concentrations, measured fuel flow rates, and sampled (O2)
concentrations during operation of the non-continuous, natural gas-fired boiler using a
computing device; calculating a predicted NOx emission rate based on the correlation
with the measured fuel flow rate and the sampled O2 concentration using the
computing device; and providing the predicted NOx emission rate for use by a user.
[0006] Other aspects of the invention provide methods, systems, program
products, and methods of using and generating each, which include and/or implement
2
some or all of the actions described herein. The illustrative aspects of the invention
are designed to solve one or more of the problems herein described and/or one or
more other problems not discussed.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] These and other features of this invention will be more readily
understood from the following detailed description of the various aspects of the
invention taken in conjunction with the accompanying drawings that depict various
embodiments of the invention, in which:
[0008] FIG. 1 shows a block diagram of an illustrative environment and for
implementing a predictive monitoring system for a nitrogen oxide (NOx) emission
rate, in accordance with an embodiment of the present invention;
[0009] FIG. 2 shows a flow diagram of a method for predicting a NOx
emission rate of a non-continuous, natural gas-fired boiler, in accordance with an
embodiment of the present invention;
[0010] FIG. 3 shows a NOx correlation curve in a method for calculating a
correlation for a NOx emission rate, in accordance with an embodiment of the present
invention;
[0011] FIG. 4 shows a NOx correlation curve in a method for calculating a
correlation for NOx emission rate, in accordance with another embodiment of the
present invention; and
3
[0012] FIG. 5 shows a flow diagram of a method for maintaining a predictive
monitoring system for a NOx emission rate in accordance with an embodiment of the
present invention.
[0013] It is noted that the drawings may not be to scale. The drawings are
intended to depict only typical aspects of the invention, and therefore should not be
considered as limiting the scope of the invention. In the drawings, like numbering
represents like elements between the drawings.
DETAILED DESCRIPTION OF THE INVENTION
[0014] As indicated above, aspects of the invention provide a predicted
nitrogen oxide (NOx) emission rate. As used herein, unless otherwise noted, the term
"set" means one or more (i.e., at least one) and the phrase "any solution" means any
now known or later developed solution.
[0015] Because of the harmful nature of NOx gasses, federal law requires the
monitoring of NOx gasses, and how the data is recorded and reported. Meeting
federal and state law mandates, and global regulations regarding the aforementioned
requires a large amount of time and effort, and consequently is expensive.
[0016] Referring to FIG. 1, an illustrated environment 10 for predicting a NOx
gas emission rate from a non-continuous, natural gas-fired boiler 100 during operation
is shown according to an embodiment. To this extent, environment 10 includes a
computer system 20 that can carry out predicting the NO* gas emission rate. In
particular, computer system 20 is shown including a predictive monitoring system
4
(PEMS) 30 for the NOx emission rate, which makes computer system 20 operable to
predict the NOx gas emission rate by performing a process described herein.
[0017] Computer system 20 is shown in communication with a natural gasfired
boiler 100. In an embodiment, boiler 100 may be a Nebraska Boiler Company
(Model No. N2S-7/S-100-ECON-SH-HM) water tube boiler. Boiler 100 may be a
non-continuous, natural gas-fired boiler with a rated heat input capacity of 244
MMBtu/hr. Steam from boiler 100 may be used to spin steam turbines to simulate
conditions that the turbines would encounter at an electric utility plant. The steam
pressure, temperature, and moisture content may be varied to simulate real-world
conditions while turbine performance data is recorded and appropriate adjustments to
the turbine are made.
[0018] In another embodiment, boiler 100 may be equipped with a NATCOM
Low NOx burner (Model No. P-244-LOG-41-2028) and a flue gas recirculation
apparatus (FGR) for NOx emissions control. Boiler 100 flue gases may be discharged
to the atmosphere, e.g., through a 60-inch inside diameter (ID) stack approximately 75
feet above grade. In another embodiment, boiler 100 may also include a natural gas
fuel flow rate meter 34, a NOx analyzer 120, and an oxygen analyzer 130.
[0019] In one embodiment of fuel flow rate meter 34, natural gas fuel flow to
boiler 100 may be monitored, e.g., using a coriolis type flow meter manufactured by
Emerson Process Management (Micro Motion Elite Series Model No. CMF300).
Emerson Micro Motion MVD Model 1700 flow transmitters may be used to convert
fuel flow meter output to natural gas fuel flow in units of standard cubic feet per hour
(scfh). In another embodiment of fuel flow meter 34, a multivariable flow meter may
5
be installed on boiler 100 to serve as a back-up fuel meter, e.g., Rosemount Model
3095.
[0020] In an embodiment of NOx analyzer 120, NOx emission concentrations
from boiler 100 may be monitored, e.g., using an Advanced Pollution Instruments
(API) model 200AH chemi-luminescent analyzer.
[0021] In an embodiment of oxygen analyzer 130, flue gas oxygen content for
boiler 100 may be continuously monitored using, e.g., a Yokogawa oxygen analyzer
(Model No. ZR202G). Analyzer 130 may be a single point wet, in-situ based system,
mounted directly on boiler exhaust breaching below the boiler economizer. Certified
calibration gases (zero and span) may be directed from calibration cylinders located
near boiler 100 to the sensor chambers via tubing. Sensor output may be sent to the
electronics assembly where it is converted to a linear (4-20 mA) signal proportional to
the percent oxygen in the flue gas.
[0022] Further, computer system 20 is shown in communication with a user
36 and a system maintainer 80. User 36 may, for example, be a programmer, an
operator, or another computer system. Interactions between these components and
computer system 20 are discussed herein.
[0023] Computer system 20 is shown including a processing component 22
(e.g., one or more processors), a storage component 24 (e.g., a storage hierarchy), an
input/output (I/O) component 26 (e.g., one or more I/O interfaces and/or devices), and
a communications pathway 28. In one embodiment, processing component 22
executes program code, such as PEMS 30, which is at least partially fixed in storage
component 24. While executing program code, processing component 22 can process
data, which can result in reading and/or writing the data to/from storage component
6
24 and/or I/O component 26 for further processing. Pathway 28 provides a
communications link between each of the components in computer system 20. I/O
component 26 can comprise one or more human I/O devices or storage devices, which
enable user 36 to interact with computer system 20 and/or one or more
communications devices to enable user 36 to communicate with computer system 20
using any type of communications link. To this extent, PEMS 30 can manage a set of
interfaces (e.g., graphical user interface(s), application program interface, and/or the
like) that enable human and/or system users 36 to interact with PEMS 30. Further,
PEMS 30 can manage (e.g., store, retrieve, create, manipulate, organize, present, etc.)
the data, such as PEMS data 32, using any solution.
[0024] In any event, computer system 20 can comprise one or more general
purpose computing articles of manufacture (e.g., computing devices) capable of
executing program code, such as PEMS 30 program code, installed thereon. As used
herein, it is understood that "program code" means any collection of instructions, in
any language, code or notation, that cause a computing device having an information
processing capability to perform a particular function either directly or after any
combination of the following: (a) conversion to another language, code or notation;
(b) reproduction in a different material form; and/or (c) decompression. To this
extent, PEMS 30 can be embodied as any combination of system software and/or
application software.
[0025] In any event, the technical effect of computer system 20 is to provide
processing instructions for monitoring and/or predicting NOx emission rates from a
non-continuous, natural gas-fired boiler 100 during operation. In another embodiment
7
of computer system 20, it may monitor, record, and track all operating parameters
related to boiler 100, including oxygen concentration data, natural gas fuel flow rate
data, and NOx emission concentration data. In another embodiment of computer
system 20, it may monitor, record, and track all data generated by system maintainer
80, as described herein.
[0026] Further, PEMS 30 can be implemented using a set of modules such as
calculator 40 and predictor 50. In this case, a module can enable computer system 20
to perform a set of tasks used by PEMS 30, and can be separately developed and/or
implemented apart from other portions of PEMS 30. PEMS 30 may include modules
that comprise a specific use machine/hardware and/or software. Regardless, it is
understood that two or more modules, and/or systems may share some/all of their
respective hardware and/or software.
[0027] As used herein, the term "component" means any configuration of
hardware, with or without software, which implements the functionality described in
conjunction therewith using any solution, while the term "module" means program
code that enables a computer system 20 to implement the functionality described in
conjunction therewith using any solution. When fixed in a storage component 24 of a
computer system 20 that includes a processing component 22, a module is a
substantial portion of a component that implements the functionality. Regardless, it is
understood that two or more components, modules, and/or systems may share
some/all of their respective hardware and/or software. Further, it is understood that
some of the functionality discussed herein may not be implemented or additional
functionality may be included as part of computer system 20.
8
[0028] When computer system 20 comprises multiple computing devices,
each computing device may have only a portion of PEMS 30 embodied thereon (e.g.,
one or more modules). However, it is understood that computer system 20 and PEMS
30 are only representative of various possible equivalent computer systems that may
perform a process described herein. To this extent, in other embodiments, the
functionality provided by computer system 20 and PEMS 30 can be at least partially
implemented by one or more computing devices that include any combination of
general and/or specific purpose hardware with or without program code. In each
embodiment, the hardware and program code, if included, can be created using
standard engineering and programming techniques, respectively.
[0029] Regardless, when computer system 20 includes multiple computing
devices, the computing devices can communicate over any type of communications
link. Further, while performing a method described herein, computer system 20 can
communicate with one or more other computer systems using any type of
communications link. In either case, the communications link can comprise any
combination of various types of wired and/or wireless links; comprise any
combination of one or more types of networks; and/or utilize any combination of
various types of transmission techniques and protocols.
[0030] PEMS 30 enables computer system 20 to provide processing
instructions for monitoring and/or predicting NOx emission rates of boiler 100.
PEMS 30 may include logic, which may include the following functions: a calculator
40, a predictor 50, an obtainer 60, and a user interface module 70. Predictor 50 may
additionally comprise a correlator 55. Structurally, the logic may take any of a variety
9
of forms such as a module, a field programmable gate array (FPGA), a
microprocessor, a digital signal processor, an application specific integrated circuit
(ASIC) or any other specific use machine structure capable of carrying out the
functions described herein. Logic may take any of a variety of forms, such as
software and/or hardware. However, for illustrative purposes, PEMS 30 and logic
included therein will be described herein as a specific use machine. As will be
understood from the description, while logic is illustrated as including each of the
above-stated functions, not all of the functions are necessary according to the
teachings of the invention as recited in the appended claims.
[0031] Obtainer 60 obtains data such as measured fuel flow rates, sampled
flue gas oxygen concentrations, and sampled NOx concentrations of boiler 100. In an
embodiment of obtainer 60, it may obtain a plurality of fuel flow rates from fuel flow
rate meter 34, and corresponding samples of oxygen concentrations from oxygen
analyzer 130 and samples of NOx concentrations from NOx analyzer 120 of the noncontinuous,
natural gas-fired boiler 100 at different points in time during operation.
In another embodiment, obtainer 60 may obtain a single measured fuel flow rate, a
single sampled flue gas oxygen concentration, and a single sampled NOx
concentration corresponding to the same point in time. In one embodiment, obtainer
60 may perform both functions.
[0032] In another embodiment, three obtainers 60 may be used; one for fuel
flow rate data acquisition, one for flue gas oxygen concentration data acquisition, and
another for NOx concentration data acquisition. Obtainer 60 may be in
communication with boiler 100 and in particular, natural gas fuel flow meter 34,
10
oxygen analyzer 130, and NOx analyzer 120 to obtain the respective data. In another
embodiment, obtainer 60 may be in communication with calculator 40 and/or
predictor 50 as described herein.
[0033] Alternatively, user 36 may provide data obtained from natural gas fuel
flow rate meter 34, oxygen analyzer 130, and NOx analyzer to computer system 20 via
I/O component 26. In another embodiment, obtainer 60 may obtain data such as
natural gas fuel firing rate, steam flow rate, steam pressure and temperature, and flue
gas regulator setting. One having ordinary skill in the art would recognize the
meters, sensors, etc. that may be used to provide the aforementioned data and thus, for
the sake of clarity, no further discussion is provided. Natural gas fuel flow rate meter
34, oxygen analyzer 130, and NOx analyzer 120 may be linked to computer system 20
in any conventional manner, and may provide data about fuel flow rate, oxygen
concentration, and NOx concentration in any conventional manner.
[0034] Calculator 40 calculates a correlation of a NOx emission rate to the
measured fuel flow rate and the sampled O2 concentration based on a plurality of
sampled NOx emission concentrations, measured fuel flow rates, and sampled O2
concentrations during operation of the non-continuous, natural gas-fired boiler. In
one embodiment, calculator 40 may receive the plurality of sampled NOx emission
concentrations, measured fuel flow rates, and sampled O2 concentrations from
obtainer 40. In another embodiment, calculator 40 may receive the plurality of
sampled NOx emission concentrations, measured fuel flow rates, and sampled 02
concentrations from user 36.
11
[0035] Predictor 50 predicts the NOx emission rate based on the correlation
with the measured fuel flow rate and the sampled O2 concentration, and alternatively,
using a method for predicting NOx emission rate of a non-continuous, natural gasfired
boiler as described herein. In one embodiment, predictor 50 may predict the
NOx emission rate by: obtaining a fuel flow rate and a corresponding O2
concentration of the non-continuous, natural gas-fired boiler during operation;
correlating the obtained fuel flow rate and corresponding obtained O? concentration
with the correlation, via a correlator 55, to arrive at the measured fuel flow rate and
the sampled O2 concentration; and predicting the NOx emission rate based on the
correlation with the measured fuel flow rate and sampled O2 concentration.
[0036] In an embodiment, predictor 50 comprises a correlator 55. Correlator
55 correlates the obtained fuel flow rate and corresponding obtained O2 concentration
with the correlation to arrive at the measured fuel flow rate and the corresponding
sampled O2 concentration.
[0037] PEMS 30 can provide the predicted NOx emission rate for use by user
36, for example, via a user interface module 70. In an embodiment, user interface
module 70 provides a graphical user interface. It is understood, however, that it may
be embodied in many different forms, e.g., a numerical representation without
graphics data suitable for processing by another system, etc. In one embodiment, user
36 may provide data about a fuel flow rate, flue gas oxygen, and/or NOx emission
concentration of boiler 100 by providing data to user interface module 70. In another
embodiment, user 36 may provide data representing correlations, as described for
boiler 100.
12
[0038] While shown and described herein as a NOx emission predictive
monitoring system, it is understood that aspects of the invention further provide
various alternative embodiments. For example, in one embodiment, the invention
provides a computer program embodied in at least one computer-readable medium,
which when executed, enables a computer system to predict the NOx emission rate of
a boiler. To this extent, the computer-readable medium includes program code, such
as PEMS 30, which implements some or all of a process described herein. It is
understood that the term "computer-readable medium" comprises one or more of any
type of tangible medium of expression capable of embodying a copy of the program
code (e.g., a physical embodiment). For example, the computer-readable medium can
comprise: one or more portable storage articles of manufacture; one or more
memory/storage components of a computing device; paper; and/or the like.
[0039] In another embodiment, the invention provides a method of providing
a copy of program code, such as PEMS 30, which implements some or all of a process
described herein. In this case, a computer system can generate and transmit, for
reception at a second, distinct location, a set of data signals that has one or more of its
characteristics set and/or changed in such a manner as to encode a copy of the
program code in the set of data signals. Similarly, an embodiment of the invention
provides a method of acquiring a copy of program code that implements some or all
of a process described herein, which includes a computer system receiving the set of
data signals described herein, and translating the set of data signals into a copy of the
computer program embodied in at least one computer-readable medium. In either
case, the set of data signals can be transmitted/received using any type of
communications link.
13
[0040] Further, system maintainer 80 is shown in communication with
computer system 20. System maintainer 80 comprises a calibrator 82, a data recorder
84, and a data reporter 86. Calibrator 82 calibrates computer system 20 and/or boiler
100, described herien. Data recorder 84 records data about computer system 20
and/or boiler 100, described herein. Data reporter 86 reports data about computer
system 20 and/or boiler 100, described herein. In one embodiment, system maintainer
80 may be in direct communication with boiler 100. In another embodiment, system
maintainer 80 may be in direct communication with user 36.
[0041] In still another embodiment, the invention provides a method of
generating a system for predicting the NOx emission rate of boiler 100 during
operation. In this case, a computer system, such as computer system 20, can be
obtained (e.g., created, maintained, made available, etc.) and one or more components
for performing a process described herein can be obtained (e.g., created, purchased,
used, modified, etc.) and deployed to the computer system. To this extent, the
deployment can comprise one or more of: (1) installing program code on a computing
device from a computer-readable medium; (2) adding one or more computing and/or
I/O devices to the computer system; and (3) incorporating and/or modifying the
computer system to enable it to perform a process described herein.
[0042] Referring to FIG. 2, an embodiment of a method for predicting a
nitrogen oxide (NOx) emission rate of a non-continuous, natural gas-fired boiler is
shown. Step SI includes calculating a correlation of the NOx emission rate to a
measured fuel flow rate, and a sampled oxygen concentration based on a plurality of
sampled NOx emission concentrations, measured fuel flow rates, and sampled oxygen
14
(O2) concentrations during operation of the non-continuous, natural gas-fired boiler.
In an embodiment, step SI may be performed by calculator 40 of PEMS 30, see FIG.
1. Step S2 includes calculating a predicted NOx emission rate based on the
correlation with the measured fuel flow rate and the sampled O2 concentration. In an
embodiment, step S2 may be performed by predictor 50 of PEMS 30, see FIG. 1.
[0043] In an embodiment of step SI of FIG. 2, calculating the correlation
comprises a step S1A, periodically sampling flue gas from the non-continuous,
natural gas-fired boiler during operation at the plurality of measured fuel flow rates to
obtain the plurality of corresponding sampled O2 concentrations and sampled NOx
concentrations. In an embodiment, step SI A may be performed by fuel flow rate
meter 34, NOx analyzer 120, and oxygen analyzer 130 of boiler 100, see FIG. 1.
[0044] In an embodiment of step SI A, sampling flue gas may be conducted on
two boilers, having the characteristics of boiler 100, see FIG. 1, to calculate the
correlation of the NOx emission rate to boiler operating load (represented by measured
fuel flow rate) and flue gas oxygen concentration. Hereon in and unless otherwise
stated, reference to boiler 100 will mean two boilers, i.e., boiler 1 and boiler 2. In an
embodiment, the boiler operating load is meant as the "degree of staged combustion"
as recited in United States 40 Code of Federal Regulation (C.F.R.) § 60.49b(c)(l) and
boiler 100 exhaust O2 concentration as the "level of excess air."
[0045] In an embodiment, natural gas fuel firing rate and boiler 100 exhaust
oxygen concentration may be monitored and recorded approximately every five
minutes during correlation testing. The standard fuel F-factor for natural gas (8,710
dscf/MMBtu) outlined in Table 19.2 of United States Environmental Protection
15
Agency (U.S.E.P.A.) Reference Method (RM) 19 may be used to normalize NOx
concentrations to heat input (lb/MMBtu). The foregoing data may be acquired by
NOx analyzer 120, fuel flow rate meter 34, and oxygen analyzer 130, see FIG. 1. In
another embodiment, steam flow rate, steam pressure and temperature, and flue gas
regulation settings may be monitored.
[0046] Flue gas may be sampled at test ports in the 60-inch ID boiler exhaust
stacks located approximately 27 feet (5.4 diameters) downstream of the FGR
breeching and approximately 6 feet (1.2 diameters) upstream of boiler 100 stack
exhaust. There may be four test ports located 90° apart in the same plane. A NOx
stratification check may be conducted prior to the start of testing in accordance with
U.S.E.P.A. RM 7E requirements. Sampled NOx concentrations may be determined
based on the results of this check.
[0047] Six boiler operating load points may be selected and sampling
corresponding to the six boiler operating load points may be done in triplicate. At
each load point, three O2 concentrations may be sampled (total of 54 test runs per
boiler). Corresponding natural gas fuel flow rates for the six set load points may be
selected based on natural gas heat content. In a embodiment, the natural gas heat
3
content may be 1,020 BTU/ft . The six boiler load points tested may be a percentage
of the rated boiler heat input.
[0048] Sampled NOx emission concentration analysis may be conducted
using U.S.E.P.A. RMs described in 40 C.F.R. § 60, Appendix A. RM 3A: gas
analysis for the determination of dry molecular weight and Method 7E: determination
of nitrogen oxide emissions from stationary sources - Instrumental analyzer
procedure - were used for the analysis. In an embodiment, the aforementioned
16
methods may be conducted in triplicate. The test durations may be approximately 21
minutes.
[0049] Boiler 100 exhaust concentrations of oxygen may be determined in
accordance with U.S.E.P.A. RM 3A (instrumental method). A continuous gas sample
may be extracted from the emission source at a single point through a sintered filter,
heated probe, and heated polytetrafluoroethylene (Teflon®) sample line and a gas
conditioner may be used to remove moisture from the gas stream. All material that
may come in contact with the sample may be constructed of stainless steel, glass, or
Teflon®. In an embodiment, data from oxygen analyzer 134 may be obtained by
obtainer 40 and recorded every two seconds on storage component 24 of computer
system 20, see FIG. 1. In another embodiment, data from oxygen analyzer 134 may
be continuously obtained by obtainer 40 and recorded on storage component 24 of
computer system 20, see FIG. 1. In an embodiment, emissions data may be reported
as 5-minute averages for each test run.
[0050] In an embodiment, sampled NOx emission concentration may be
analyzed in accordance with U.S.E.P.A. RM 7E. The same sample collection,
conditioning system, and Continuous Monitoring Emission System (CEMS) used for
RM 3A sampling may be used for the RM 7E sampling.
[0051] Oxygen concentration data, NOx concentration data, and fuel flow rate
data, may be embodied on a machine readable medium. For example, the medium
may be a CD, a compact flash, other flash memory, a packet of data to be sent via the
Internet, or other networking suitable means. Additionally the machine readable
medium can comprise: one or more portable storage articles of manufacture; one or
more memory/storage components of a computing device; paper; and/or the like.
17
Tables 1 and 2 list the plurality of sampled oxygen concentrations, sampled NOx
concentrations, and measured fuel flow rate data that was sampled for boilers 1 and 2
respectively in an embodiment of method step SIA of method step SI, see FIG. 2.
Table 1: Summary of Flue Gas Analysis for Boiler 1
Operating
Load (%)
90
90
90
90
90
90
90
90
90
70
70
70
70
70
70
70
70
70
Oxygen
Level
High
High
High
Normal
Normal
Normal
Low
Low
Low
High
High
High
Normal
Normal
Normal
Low
Low
Low
Run ID
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
Oxygen
(%)
4.10
4.12
4.14
4.12
3.05
3.06
3.06
3.06
2.47
2.47
2.47
2.47
4.21
4.23
4.23
4.22
3.12
3.11
3.11
3.11
2.34
2.35
2.38
2.36
NOx
(ppm)
31.6
32.0
31.8
31.8
33.5
33.6
33.6
33.6
34.0
34.1
34.2
34.1
28.8
28.7
28.7
28.7
29.6
30.2
30.3
30.0
30.0
29.85
29.66
29.8
NOx"
(lb NOx/MMBtu)
0.041
0.041
0.041
0.041
0.041
0.041
0.041
0.041
0.040
0.040
0.040
0.040
0.038
0.037
0.037
0.037
0.036
0.037
0.037
0.037
0.035
0.035
0.035
0.035
18
50
50
50
50
50
50
50
50
50
30
30
30
30
30
30
30
30
30
10
10
10
10
10
10
10
10
High
High
High
Normal
Normal
Normal
Low
Low
Low
High
High
High
Normal
Normal
Normal
Low
Low
Low
High
High
High
Normal
Normal
Normal
Low
Low
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
4.21
4.20
4.22
4.21
3.02
3.08
3.02
3.04
2.51
2.46
2.46
2.48
6.53
6.60
6.60
6.58
4.46
4.40
4.40
4.42
2.73
2.72
2.74
2.73
10.96
10.96
10.97
10.96
6.71
6.68
6.69
6.69
4.84
4.87
24.68
24.65
24.70
24.7
27.01
27.37
26.88
27.1
26.23
25.96
25.84
26.0
23.51
23.57
23.58
23.6
27.36
27.44
26.25
27.0
27.85
27.83
27.84
27.8
20.88
21.29
21.59
21.3
25.46
24.29
24.32
24.7
24.06
24.33
0.032
0.032
0.032
0.032
0.033
0.033
0.033
0.033
0.031
0.031
0.030
0.031
0.036
0.036
0.036
0.036
0.036
0.036
0.035
0.036
0.033
0.033
0.033
0.033
0.046
0.047
0.047
0.046
0.039
0.037
0.037
0.038
0.033
0.033
19
10
3.2
3.2
3.2
3.2
3.2
3.2
3.2
3.2
3.2
Low
High
High
High
Normal
Normal
Normal
Low
Low
Low
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
4.85
4.85
17.86
17.96
17.96
17.93
15.59
15.58
15.52
15.56
14.12
14.41
14.33
14.29
23.97
24.1
7.99
7.78
7.78
7.9
11.19
11.32
11.33
11.3
15.11
14.23
14.59
14.6
0.032
0.033
0.057
0.058
0.058
0.057
0.046
0.046
0.046
0.046
0.048
0.048
0.048
0.048
bCalculated NOx emission rate - see explanation infra
Table 2 : Summary of Flue Gas Analysis for Boiler 2
Operating
Load (%)
90
90
90
90
90
90
90
90
90
70
70
70
Oxygen
Level
High
High
High
Normal
Normal
Normal
Low
Low
Low
High
High
High
Run ID
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Oxygen
(%)
3.87
3.84
3.79
3.83
2.84
2.84
2.84
2.84
2.15
2.12
2.07
2.11
4.47
4.47
4.47
NOx
(ppm)
30.5
30.9
30.9
30.8
33.8
33.7
34.2
33.9
34.9
34.7
35.3
35.0
26.76
26.34
26.47
Noxb
(IbNOx/MMBtu)
0.039
0.039
0.039
0.039
0.041
0.041
0.041
0.041
0.040
0.040
0.041
0.040
0.035
0.035
0.035
20
70
70
70
70
70
70
50
50
50
50
50
50
50
50
50
30
30
30
30
30
30
30
30
30
Normal
Normal
Normal
Low
Low
Low
High
High
High
Normal
Normal
Normal
Low
Low
Low
High
High
High
Normal
Normal
Normal
Low
Low
Low
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
4.47
3.28
3.32
3.32
3.31
2.44
2.43
2.42
2.43
5.48
5.47
5.46
5.47
4.51
4.49
4.47
4.49
3.33
3.33
3.33
3.33
5.79
5.77
5.76
5.77
4.92
4.88
4.83
4.88
3.64
3.63
3.62
3.63
26.5
29.5
29.6
29.5
29.5
30.8
30.8
31.0
30.8
23.57
23.57
23.62
23.6
26.28
26.08
26.04
26.1
27.66
27.71
27.70
27.7
27.66
27.83
27.70
27.7
27.79
27.54
28.22
27.9
29.23
29.28
29.78
29.4
0.035
0.036
0.037
0.037
0.036
0.036
0.036
0.036
0.036
0.033
0.033
0.033
0.033
0.035
0.035
0.034
0.035
0.034
0.034
0.034
0.034
0.040
0.040
0.040
0.040
0.038
0.037
0.038
0.038
0.037
0.037
0.037
0.037
21
10
10
10
10
10
10
10
10
10
3.2
3.2
3.2
3.2
3.2
3.2
3.2
3.2
3.2
High
High
High
Normal
Normal
Normal
Low
Low
Low
High
High
High
Normal
Normal
Normal
Low
Low
Low
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
1
2
3
Average
10.54
10.54
10.51
10.53
7.31
7.24
7.17
7.24
4.68
4.65
4.68
4.67
17.65
17.65
17.63
17.64
16.12
16.11
16.10
16.11
14.77
14.74
14.74
14.75
23.09
23.53
23.68
23.4
23.21
22.66
22.40
22.8
23.11
22.32
22.24
22.6
8.35
8.30
8.41
8.4
10.47
10.69
10.73
10.6
14.22
14.41
14.31
14.3
0.048
0.049
0.050
0.049
0.037
0.036
0.035
0.036
0.031
0.030
0.030
0.030
0.056
0.056
0.056
0.056
0.048
0.049
0.049
0.048
0.050
0.051
0.050
0.051
Calculated NOx emission rate - see explanation infra
[0052] Referring to FIG. 2, in an embodiment of method step SI, step SI also
comprises a step SIB, calculating the correlation of the NOx emission rate based on
the plurality of measured fuel flow rates, and corresponding sampled NOx emission
concentrations and sampled O2 concentrations. In an embodiment, step SIB may be
performed by calculator 40 of PEMS 30, see FIG. 1.
22
[0053] Calculator 40, see FIG. 1, may calculate NOx emission rates in
lb/MMBtu using the sampled NOx concentration (NOx), sampled O2 concentration
(O2), and fuel flow rate data from Tables 1 and 2, and Formula 1.
(1) NOx emission rate (lb NOx /MMBtu) = NOx (ppm) x F-factor x A x [20.9/(20.9-
02%)]
A=1.194E-07forNOx
F-factor = 8,710 dscf Btu for natural gas
Calculated NOx emission rates are listed in Tables 1 and 2. The correlation may be
calculated by plotting the calculated NOx emission rates against the sampled O2
concentration and measured fuel flow rates. In an embodiment of the correlation,
FIG. 3 and FIG. 4 show curves that represent the correlation of the NOx emission rate
based on the plurality of sampled NOx emission concentrations, sampled oxygen
concentrations, and measured fuel flow rates for boilers 1 and 2 respectively. In an
embodiment, calculator 40 of PEMS 30, see FIG. 1, may calculate the foregoing
correlations.
[0054] One having ordinary skill in the art may, without undue
experimentation, apply the foregoing methodology of calculating a correlation for use
in predicting a NOx emission rate for other non-continuous, natural gas-fired boilers
that are low-NOx burners and have flue gas recirculation. Other non-continuous,
natural gas-fired boilers with low-NOx burners and flue gas recirculation may have
almost identical lb-NOx/MMBtu emissions at the same load points and oxygen value
though there may be some minor variance in actual values. For the sake of clarity, no
further discussion is provided.
23
[0055] In an embodiment of method step S2 of FIG. 2, calculating a predicted
NOx emission rate based on the correlation with the measured fuel flow rate and the
sampled O2 concentration, step S2 comprises a step S2A, obtaining a fuel flow rate
and a corresponding O2 concentration of the non-continuous, natural gas-fired boiler
during operation. In an embodiment, step S2A may be performed by obtainer 60 of
PEMS 30, see FIG. 1.
[0056] Referring to step S2A, obtainer 60 obtains a measured fuel flow rate
for boiler 100 during operation via fuel flow rate meter 34, see FIG.l. In an
embodiment, fuel flow rate data may be obtained continuously by obtainer 60, i.e.,
obtained during the entire operation of boiler 100. In another embodiment, fuel flow
rate data may be obtained non-continuously by obtainer 60, i.e., during intermittent
points in time during operation of boiler 100. Obtainer 60 also obtains the sampled
oxygen concentration of the flue exhaust gas corresponding to the measured fuel flow
rate via oxygen analyzer 130. In an embodiment, the output of oxygen analyzer 130
may be in units of percent oxygen (wet basis) and continuously obtained by obtainer
60. In another embodiment, sampled oxygen concentration may be obtained noncontinuously
by obtainer 60.
[0057] In an embodiment, method step S2 of FIG. 2 additionally comprises a
step S2B, correlating the obtained fuel flow rate and corresponding obtained O2
concentration with the correlation to arrive at the measured fuel flow rate and the
sampled O2 concentration. In an embodiment, step S2B may be performed by
correlator 55 of predictor 50, see FIG. 1.
24
[0058] In an embodiment of step S2B, the obtained fuel flow rate may be
correlated by applying the obtained fuel flow rate from step S2A to the correlation
curve, see FIG. 3 and FIG. 4, and selecting the measured fuel flow rate point from the
correlation curve that is closest to the obtained fuel flow rate. The foregoing may be
performed by calculator 40 of PEMS 30, FIG. 1. Calculator 40 then may convert the
obtained fuel flow rate to the selected measured fuel flow rate, e.g., to arrive at the
measured fuel flow rate. The sampled flue gas Oi concentration may also be similarly
applied to the correlation curve, see FIG. 3 and FIG. 4, and then selecting the nearest
sampled O2 concentration point from the correlation curve that is closest to the
obtained O2 concentration. Calculator 40 then may convert the obtained O2
concentration to the selected sampled O2 concentration, e.g., to arrive at the sampled
O2 concentration. Obtained fuel flow rate data below the 3 percent point of the
correlation or above the 90 percent load may default to the minimum and maximum
measured fuel flow rate, as applicable. Similarly, any obtained oxygen concentrations
that fall below or above a sampled O2 concentration on the correlation curve may
default to the nearest sampled O2 concentration point on the correlation curve.
[0059] In an embodiment, method step S2 of FIG. 2 additionally comprises a
step S2C, calculating the predicted the NOx emission rate based on the correlation of
the measured fuel flow rate and the corresponding sampled O2 concentration. In an
embodiment, step S2C may be performed by correlator 55 of predictor 50, see FIG. 1.
[0060] In an embodiment of step S2C, the NOx emission rate may be
predicted by selecting the calculated NOx emission rate from the correlation curve
corresponding to the measured fuel rate and the sampled O2 concentration arrived at
from the correlating step, S2B. In an embodiment of method step 2 of FIG. 2, steps
25
S2A to S2C may be repeated, e.g., a minimum of once per minute, during operation of
boiler 100.
[0061] The predicted NOx emission rate may be reported via user interface
module 70. The predicted NOx emission rate may be reported as often as steps S2AS2C
are performed. In an embodiment, the aforementioned data cycle and reporting
frequency may exceed 40 C.F.R. § 60.13(h)(2) C.E.M.S. data reporting criteria. In an
embodiment, any data considered "invalid" may not be included in emissions reported
by the foregoing method for predicting the NOx emission rate of a non-continuous,
natural gas-fired boiler. Invalid data may arise from periods when the O2 analyzer
130 is not performing within operational parameters, or when O2 analyzer data or fuel
flow meter data are not available due to malfunctions. In an embodiment, the
foregoing method may predict NOx emission rate data for a minimum of 75 percent of
the operating hours in a boiler-operating day and in at least 22 out of 30 successive
boiler operating days per 40 C.F.R. § 60.48b(f).
[0062] Referring to FIG. 5, an embodiment of a method for maintaining a
predictive monitoring system for a NOx emission rate is shown. The method
comprises: a step S30, calibrating a non-continuous, natural gas-fired boiler during
operation; a step S35, calibrating the predictive monitoring system; a step S40,
recording data related to either of the natural gas-fired boiler or the predictive
monitoring system during calibration; and a step S45, reporting the data related to
either of the natural gas-fired boiler or the predictive monitoring system resulting
from calibration. In an embodiment, steps S30-S45 may be performed by system
maintainer 80 of computer system 20, see FIG. 1.
26
[0063] Referring to step S30 of FIG. 5, and the illustrative environment and
computer infrastructure of FIG. 1, calibrator 82 may calibrate boiler 100, and in
particular, oxygen analyzer 130. Calibrator 82 may perform a two point (zero and
span) calibration of oxygen analyzer 130 at least once during operation of boiler 100
during an operating day of boiler 100. A boiler operating day may be defined as a day
(24 clock hour period) when any amount of fuel is fired in boiler 100. In addition,
calibration may be conducted on oxygen analyzer 130 on a business day prior to an
anticipated boiler 100 start-up to ensure that oxygen analyzer 130 is operating within
required specifications prior to boiler 100 start-up. In an embodiment, calibration of
oxygen analyzer 130 may be manually initiated. In another embodiment, oxygen
analyzer 130 calibration may be automatically initiated via computer system 20
and/or system maintainer 80. As outlined herein, oxygen analyzer 130 may be relinearized
following completion of calibration.
[0064] Re-linearizing oxygen analyzer 130 may include introduction of two
calibration gases to the system manifold and directed to a sensor cell in a probe sensor
assembly. Certified gases may be used for the daily calibrations for the zero gas and
for the span gas when compressed bottled air is used for the span. The zero gas may
have a concentration of approximately 0% to 1% oxygen. The span gas may have a
concentration of approximately 20.9 % oxygen (equivalent to fresh ambient air). In
another embodiment, instrument air is used in lieu of a compressed gas standard for
the span. In another embodiment, the minimum pressure for any daily calibration
cylinder used may be 200 psi. A calibration gas cylinder will not be used and will be
replaced when it reaches this pressure. In an embodiment, calibrator 82 may perform
the foregoing linearization.
27
[0065] Referring to step S40 of FIG. 5 and the illustrative environment and
computer infrastructure of FIG. 1, an embodiment of recording data by data recorder
84 is shown in Table 4. Table 4 lists a summary of daily oxygen analyzer 130
calibration data that may be recorded. Corrective actions that may need to be taken
by calibrator 82 are also provided in Table 4.
Table 4 Daily Oxygen Analyzer Calibration Check Criteria and Corrective
Actions.
a
Calibration Result
Less than 0.5% 0?
Greater than 0.5% but less than
1.0 %02
Greater than 1.0 %G"2 but less
than 2.0 %02
Greater than 2.0% O2 for any
single calibration
Greater than 1.0% for more than
5 consecutive days
Action Required
No action required
No action required
Analyzer adjustment
Re-calibration or repair
Re-calibration or repair
PEMS
b
in-Control?
Yes
Yes
Yes
No
No
Absolute difference between actual and expected calibration values
b
PEMS remains out-of-control until a daily analyzer calibration is successfully
passed.
[0066] In an embodiment, adjustments made to oxygen analyzer 130 by
calibrator 82 due to calibration drifts of oxygen analyzer 130 may be recorded by data
recorder 84. Daily calibration data may be recorded and may be available for review
within 24 to 48 hours of calibration. In an embodiment, immediately following any
corrective actions to oxygen analyzer 130 by calibrator 82, a two-point daily
calibration using zero and span gas standard calibration gases may be performed by
calibrator 82. In another embodiment, these calibration results may also be recorded
28
by data recorder 84. Recorded data may be maintained and may be available for
review anytime thereafter. In an event oxygen analyzer 130 malfunctions, the failed
component may be replaced or repaired per the O&M manual or vendor
recommendations.
[0067] If oxygen analyzer 130 needs to be taken out of service and replaced
with a spare oxygen analyzer, then the procedures described herein may be followed.
If oxygen analyzer 130 cannot be repaired or replaced with an identical replacement
due to non-availability of current models, oxygen analyzer 130 may be replaced with
an equal or improved analyzer. The procedures described herein may be followed.
[0068] Referring to step S30 of FIG. 5, and the illustrative environment and
computer infrastructure of FIG. 1, a cylinder gas audit (CGA) may be conducted
every three out of four operating quarters on oxygen analyzer 130 in accordance with
procedures outlined in 40 C.F.R. § 60, Appendix F using U.S.E.P.A., Protocol
Number 1 by calibrator 82. An operating quarter is defined as a calendar quarter
(January-March, April-June, July-September, and October through December) in
which boiler 100 operates.
[0069] In an embodiment, due to an expected low capacity factor of boiler
100, it may not operate for several months at a time. Consistent with Appendix F,
5.1.4, during these extended downtimes when boiler 100 does not operate during a
calendar quarter, it may not be necessary to perform a CGA. Additionally, a period of
three operating quarters may span more than three calendar quarters. In an
embodiment, no CGA may need to be performed during the operating quarter that
PEMS 30 Relative Accuracy Test Audit (RATA), described infra, is conducted unless
29
required for oxygen analyzer 130 replacement as described infra for oxygen analyzer
replacement certification procedures.
[0070] CGAs may be conducted using two audit gases with concentrations of
4% to 6% and 8% to 12% oxygen. Note that to conduct the CGAs, oxygen analyzer
130 may be placed in normal operating mode and the audit gases may be directed to
oxygen analyzer sensor chamber. During the CGAs, the oxygen analyzer 130 may be
challenged three times with each audit gas (non successive) and the average of the
analyzer response may be used to evaluate CGA results. The audit gases may be
injected for a period long enough to ensure that a stable reading is obtained. In an
embodiment, calibrator 82 of system maintainer 80 may perform the foregoing CGA
procedures.
[0071] In an embodiment, if the results of the CGA are not within specified
criteria of ± 15 % of the average audit value or ± 5 ppm, whichever is greater, per 40
C.F.R Appendix F Section 5.2.3(2), the oxygen analyzer 130 may be classified as not
functioning within operational parameters and corrective action may be taken by
calibrator 82, see FIG. 1. In an embodiment, once the problem is identified and
corrected, another CGA may be performed by calibrator 82.
[0072] Referring to step S30 of FIG. 5, and the illustrative environment and
computer infrastructure of FIG. 1, R.A.T.A. may be conducted on oxygen analyzer
130 in the fourth operating quarter in accordance with procedures outlined in 40
C.F.R. § 60, Appendix B, Performance Specifications (PS) 2 and 3. A third party
contractor may conduct the oxygen analyzer 130 R.A.T.A.s. Specific R.A.T.A. test
procedures are not detailed but the following section provides some general
background information and reporting requirements. Further information can be
30
found in referenced regulatory citations listed herein. In an embodiment, calibrator 82
of system maintainer 80 may perform the foregoing R.A.T.A. procedures.
[0073] The predicted NOx emission rate may be certified in units of lb NOx
/MMBtu and oxygen analyzer 130 may be certified in units of % oxygen on a wet
basis. During the R.A.T.A.s, boiler 100 may be firing natural gas and operating at a
load greater than 50 percent of rated capacity. The R.A.T.A.s may be conducted at a
single operating load and normal oxygen set point for a minimum of nine (9) 21-
minute operating periods. The following may be the RATA criteria for each
pollutant: NOx - 20 % based on the reference method or 10 % of the emission
standard (0.1 lb/MMBtu), whichever is less restrictive, and Ox - one percent oxygen
absolute difference.
[0074] NOx and oxygen concentrations may be determined in accordance with
U.S.E.P.A. RMs 7E and 3A, respectively. Stack gas moisture may be determined in
accordance with U.S.E.P.A. RM 4. Stack gas moisture content may be used by
calibrator 82, see FIG. 1, to correct oxygen concentrations for stack gas moisture as
the reference method oxygen values may be typically measured and reported on a dry
basis. Referring to step S40 of FIG. 5, RATA results may be recorded by data
recorder 84. Referring to step S45 of FIG. 5, RATA results may be included in a
semiannual Excess Emission Report that may be reported to the US.E.P.A. and the
New York State Department of Environmental Conversation (N.Y.S.D.E.C), when
completed during the semi-annual period.
[0075] Referring to step S30 of FIG. 5, and the illustrative environment and
computer infrastructure of FIG. 1, in cases where a spare oxygen analyzer may be
required to be installed on a temporary basis (less than 7 boiler operating days) due to
31
problems with the primary unit, an initial zero and span calibration may be conducted
on the spare analyzer by calibrator 82. If the spare oxygen analyzer is used to monitor
oxygen emissions for greater than 7 boiler operating days, a CGA may be conducted
by calibrator 82, on the spare analyzer. In an embodiment, a CGA may be conducted
on the primary oxygen analyzer by calibrator 82, following re-installation.
[0076] If the spare analyzer becomes the primary analyzer (permanent
replacement) for boiler 100, then a 7-day drift check may be conducted and an initial
CGA may be performed by calibrator 82. If a CGA was performed on this analyzer
th
after the 7 operating day, then this CGA may qualify as the initial CGA. A R.A.T.A.
may be conducted on the replacement oxygen analyzer when operationally practical,
but not later than the end of the second operating calendar quarter after installation of
this permanent replacement. In an embodiment, calibration of oxygen analyzer 130
may be performed by calibrator 82 in accordance with Yokagowa Electric
Corporation Instruction Manual, Model ZR202G Integrated type Zirconia Oxygen
Analyzer, Document IM 11M12A01-04E.
[0077] Referring to step S30 of FIG. 5, and the illustrative environment and
computer infrastructure of FIG. 1, calibrator 82 may calibrate boiler 100, and in
particular, fuel flow rate meter 130. Natural gas fuel flow meter 34 may be calibrated
each calendar year using a National Institute of Standards and Technology (NIST)
traceable calibration reference standard. Corrective actions such as re-calibration of
the transmitters, meter repair, or replacement may be conducted by calibrator 82
depending on the cause of the problem. In an event natural gas flow meter 34
malfunctions, it may be repaired or replaced per the O&M manual or vendor
recommendations. In an embodiment, fuel flow meter 34 may be calibrated and
32
maintained by calibrator 82 on an annual basis per an appropriate ISO Procedure -
Inspection, Measuring, & Test Equipment. In an embodiment, the ISO procedure
may provide for document control (electronic or hardcopy), calibration requirements,
supplier qualification, and quality control procedures for equipment procured.
[0078] Referring to step 40 of FIG. 5, and the illustrative environment and
computer infrastructure of FIG. 1, computer system 20 may monitor, record, and track
all operating parameters related to PEMS 30. The parameters may include oxygen
concentration readings, NOx concentration readings, and natural gas fuel flow. In an
embodiment, parameters may also include data from system maintainer 80, see supra.
In the event computer system 20 or a component of computer system 20 such as
PEMS 30 malfunctions, any failed components may be repaired and/or replaced per
manufacturer's recommendation.
[0079] Four to twenty milliamp loop checks may be performed to ensure
oxygen analyzer data, NOx analyzer data, and fuel flow data is correctly measured by
PEMS 30. In an embodiment, all calibrations performed and data recorded by system
maintainer 80 may also be recorded by PEMS 30. In case of PEMS 30 malfunction, if
data for fuel flow, oxygen readings, and NOx readings are available and can be
recreated in PEMS 30, then this data may be used to record NOx emissions from the
boilers. If this data cannot be recreated, then the NOx emission data for the time when
PEMS 30 malfunctions shall be considered "invalid." Any PEMS 30 data considered
"invalid" is not included in emission averages reported by PEMS 30. In an
embodiment, PEMS 30 may generate emissions data for a minimum of 75 percent of
the operating hours in each boiler-operating day, in at least 22 out of 30 successive
boiler operating days according to 40 C.F.R 60.48b(f).
33
[0080] Referring to step S40 of FIG. 5, an embodiment of maintaining a
predictive monitoring system by system maintainer 80, see FIG. 1, an example
schedule of PEMS 30 maintenance activities is shown below.
First Operating Quarter
Daily 02 analyzer calibrations during operating days
Start 7-day calibration drift check for each 02 analyzer
Initial CGA for each 02 analyzer
Second Operating Quarter
Daily 02 analyzer calibrations during operating days
CGA for each 02 analyzer
Third Operating Quarter
Daily 02 analyzer calibrations during operating days
CGA for each 02 analyzer
Fourth Operating Quarter
Daily 02 analyzer calibrations during operating days
RATA for each 02 analyzer and PEMS
This QA/QC test cycle for operating quarters shall repeat for the length of this permit with the
exception of the one-time only 7-day calibration drift check
Additional Boiler QA/QC Testing Activities
State permit Item 5-2: NSPS 5-day test for two hours per day (each boiler) once during permit
term. The same data used during a RATA test may also be used for this NSPS test data
requirement.
Other PEMS QA/QC Activities
Perform 02 end-to-end calibrations for each analyzer once per calendar year
Perform fuel meter end-to-end calibrations once per calendar year
Calibrate the natural gas flow sensors used for PEMS monitoring once per calendar year
[0081] Referring to step S45 of FIG. 5, recorded data related to boiler 100
calibration may be reported electronically or as a hardcopy. This step may be
performed by data reporter 86 of system maintainer 80.
[0082] Referring to step S45 of FIG. 5, a NOx PEMS 30 Excess Emissions
Report (EER) may be submitted to per federal and/or state requirements. The EER
report may contain two basic data sets; (1) NOx emissions and PEMS 30 downtime
information, and (2) PEMS 30 data assessment report (DAR) including results of
34
quarterly PEMS audits. The N0X emissions report requirements are discussed below;
the PEMS DAR is described thereafter.
[0083] The EER may provide NOx emissions data for each reporting period,
including periods when NOx emissions exceed the 30-operating day permit limit of
0.057 lb NOx/MMBtu. Excess emissions may be defined as any 30-day rolling NOx
average emission rate that exceeds permit limits, excluding start-ups, shutdowns, and
malfunctions as defined under N.Y.S.D.E.C. 6 New York Codes, Rules, and
Regulations (N.Y.C.R.R.) § 201.5(c).
[0084] The data assessment report (DAR) may be included as part of the semiannual
EER. Results of the quarterly audits and a summary of the daily oxygen
analyzer calibration checks may be included in the report. In an embodiment, the
DAR may include the following information:
• Facility name
• Address
• Facility owner/operator
• Analyzer model numbers
• PEMS location
In another embodiment, the following information may also be provided when oxygen
analyzer 130 exceeds tolerance limits:
• Date and time of each out-of-control calibration
• Calibration concentration (percent oxygen)
• Response calibration (percent oxygen)
• Drift results (percent oxygen)
• Corrective action for out-of-control period
35
The DAR may also include results of the quarterly audits. In an embodiment, the
CGA information described supra may be included in the semiannual report. In
another embodiment, the certification report from the R.A.T.A. subcontractor may
also be in included.
[0085] In an embodiment, the following PEMS 30 reports may be maintained
for a minimum of five years for review:
• PEMS certification reports
• PEMS quarterly cylinder gas audit reports
• PEMS natural gas certifications
• oxygen analyzer calibration results
• PEMS semiannual reports
• raw PEMS NOx emissions data
[0086] In an embodiment, the foregoing data may be reported by data reporter
86 of system maintainer 80.
[0087] In an embodiment, in order to ensure that PEMS 30 performance and
data reporting percentages remain within specified criteria, all changes or
modifications to PEMS 30 components, data acquisition systems, predictive
algorithms, calibration procedures, or other operational procedures may be reviewed
prior to any changes being made. These modifications may be the result of system
component or software upgrades, replacement of PEMS 30 components due to system
degradation or malfunction, or technical improvements to the system. PEMS 30
operational and maintenance procedural changes may be in response to changes in
36
permit requirements, regulatory agency guidelines, or requirements of newly installed
instrumentation.
[0088] All PEMS 30 modifications may be assessed with respect to regulatory
requirements and manufacturers specifications to assure that the accuracy of reported
PEMS data 32 would not be affected by the modification. Any proposed
modifications may also be reviewed to determine if subsequent audit procedures are
warranted as a result of the modification. Since boiler 100 may be permitted under a
N.Y.S.D.E.C. state-issued permit, all modifications to the PEMS 30 may be evaluated
within N.Y.C.R.R. to determine an application requesting such permit modifications
and receive department authorization prior to making such modifications is required
to be submitted.
[0089] In an embodiment, any changes and modifications which meet the
criteria under subparagraphs (i)-(iii) of N.Y.C.R.R. Subpart 201-5.4 may be
conducted without prior approval of the regulatory department and may not require
modification of the permit. Records of the date and description of such changes may
be maintained and such records may be available for review by department
representatives upon request. In an embodiment, such changes and modifications are
listed below.
(i) Changes that do not cause emissions to exceed any emission limitation
contained in regulations or applicable requirements under this Title.
(ii) Changes which do not cause the source to become subject to any
additional regulations or requirements under this Title.
(iii) Changes that do not seek to establish or modify a federally-enforceable
emission cap or limit.
37
[0090] In addition to the recordkeeping required under paragraph (1) of this
subdivision, the permittee may notify the department in writing at least 30 calendar
days in advance of making changes involving:
(i) the relocation of emission points within a facility;
(ii) the emission of any air pollutant not previously authorized or remitted in
accordance with a permit issued by the department;
(iii) the installation or alteration of any air cleaning installations, device or
control equipment.
[0091] A permit modification may be required to impose applicable
requirements or special permit conditions if it is determined that changes proposed
pursuant to notification under paragraph (2) of this subdivision do not meet the
criteria under paragraph (1) of this subdivision or the change may have a significant
air quality impact. In such cases it may be required that the permittee not undertake
the proposed change until a more detailed review of the change for air quality impacts
and/or applicable requirements is completed. A response may be made to a permittee
in writing with such a determination within 15 days of receipt of the 30 day advance
notification from the permittee. A determination may include a listing of information
necessary to further review the proposed change.
[0092] The terms "first,'" "second," and the like, herein do not denote any
order, quantity, or importance, but rather are used to distinguish one element from
another, and the terms "a" and "an" herein do not denote a limitation of quantity, but
rather denote the presence of at least one of the referenced item. The modifier
"about" used in connection with a quantity is inclusive of the stated value and has the
meaning dictated by the context, (e.g., includes the degree of error associated with
38
measurement of the particular quantity). The suffix "(s)" as used herein is intended to
include both the singular and the plural of the term that it modifies, thereby including
one or more of that term (e.g., the metal(s) includes one or more metals). Ranges
disclosed herein are inclusive and independently combinable (e.g., ranges of "up to
about 25 wt%, or, more specifically, about 5 wt% to about 20 wt %", is inclusive of
the endpoints and all intermediate values of the ranges of "about 5 wt% to about 25
wt%," etc).
[0093] The following codes and regulations are herein incorporated by
reference in their entirety: Subpart DB C.F.R. and E.P.A. rules (60.48b and 60.49b);
[72 Federal Register (F.R.) 32742, June 13, 2007, as amended at 74 F.R. 5089, Jan.
28, 2009]; 60.8 regulations: [36 F.R. 24877, Dec. 23, 1971, as amended at 39 F.R.
9314, Mar. 8, 1974; 42 F.R. 57126, Nov. 1, 1977; 44 F.R. 33612, June 11, 1979; 54
F.R. 6662, Feb. 14, 1989; 54 F.R. 21344, May 17, 1989; 64 F.R. 7463, Feb. 12, 1999;
72 F.R. 27442, May 16, 2007]; 60.13 regulations: [40 F.R. 46255, Oct. 6, 1975; 40
F.R. 59205, Dec. 22, 1975, as amended at 41 F.R. 35185, Aug. 20, 1976; 48 F.R
13326, Mar. 30, 1983; 48 F.R. 23610, May 25, 1983; 48 F.R. 32986, July 20, 1983;
52 F.R. 9782, Mar. 26, 1987; 52 F.R. 17555, May 11, 1987; 52 F.R. 21007, June 4,
1987; 64 F.R. 7463, Feb. 12, 1999; 65 F.R. 48920, Aug. 10, 2000; 65 F.R. 61749,
Oct. 17, 2000; 66 F.R. 44980, Aug. 27, 2001; 71 F.R. 31102, June 1, 2006; 72 F.R.
32714, June 13, 2007]; [48 F.R. 13327, Mar. 30, 1983 and 48 F.R. 23611, May 25,
1983, as amended at 48 F.R. 32986, July 20, 1983; 51 F.R. 31701, Aug. 5, 1985; 52
F.R. 17556, May 11, 1987; 52 F.R. 30675, Aug. 18, 1987; 52 F.R. 34650, Sept.14,
1987; 53 F.R. 7515, Mar. 9, 1988; 53 F.R. 41335, Oct. 21, 1988; 55 F.R. 18876, May
7, 1990; 55 F.R. 40178, Oct. 2, 1990; 55 F.R. 47474, Nov. 14, 1990; 56 F.R. 5526,
39
Feb. 11, 1991; 59 F.R. 64593, Dec. 15, 1994; 64 F.R. 53032, Sept. 30, 1999; 65 F.R.
62130, 62144, Oct. 17, 2000; 65 F.R. 48920, Aug. 10, 2000; 69 F.R. 1802, Jan. 12,
2004; 70 F.R. 28673, May 18, 2005; 71 F.R. 55127, Sept. 21, 2006; 72 F.R. 32767,
June 13, 2007; 72 F.R. 51527, Sept. 7, 2007; 72 F.R. 55278, Sept. 28, 2007; 74 F.R.
12580, 12585, Mar. 25, 2009; 74 F.R. 18474, Apr. 23, 2009]; and [52 F.R. 21008,
June 4, 1987; 52 F.R. 27612, July 22, 1987, as amended at 56 F.R. 5527, Feb. 11,
1991; 69 F.R. 1816, Jan. 12, 2004; 72 F.R. 32768, June 13, 2007; 74 F.R. 12590, Mar.
25,2009].
[0094] All references to state and/or federal regulations, requirements, criteria,
protocols, test procedures, reference methods, codes, and rules listed herein are herein
incorporated by reference in their entirety. All references instrument manuals and
operating instructions listed herein also are herein incorporated by reference in their
entirety.
[0095] While shown and described herein as a method and system for
predicting NOx emissions, it is understood that aspects of the invention further
provide various alternative embodiments. For example, in one embodiment, the
invention provides a computer program fixed in at least one computer-readable
medium, which when executed, enables a computer system to predict NOx emission
rates . To this extent, the computer-readable medium includes program code, such as
PEMS program 30 (FIG. 1), which implements some or all of a process described
herein. It is understood that the term "computer-readable medium" comprises one or
more of any type of tangible medium of expression, now known or later developed,
from which a copy of the program code can be perceived, reproduced, or otherwise
communicated by a computing device. For example, the computer-readable medium
40
can comprise: one or more portable storage articles of manufacture; one or more
memory/storage components of a computing device; paper; and/or the like.
[0096] In another embodiment, the invention provides a method of providing
a copy of program code, such as PEMS program 30 (FIG. 1), which implements some
or all of a process described herein. In this case, a computer system can process a
copy of program code that implements some or all of a process described herein to
generate and transmit, for reception at a second, distinct location, a set of data signals
that has one or more of its characteristics set and/or changed in such a manner as to
encode a copy of the program code in the set of data signals. Similarly, an
embodiment of the invention provides a method of acquiring a copy of program code
that implements some or all of a process described herein, which includes a computer
system receiving the set of data signals described herein, and translating the set of
data signals into a copy of the computer program fixed in at least one computerreadable
medium. In either case, the set of data signals can be transmitted/received
using any type of communications link.
[0097] In still another embodiment, the invention provides a method of
generating a system for predicting NOx emission rates . In this case, a computer
system, such as computer system 20 (FIG. 1), can be obtained (e.g., created,
maintained, made available, etc.) and one or more components for performing a
process described herein can be obtained (e.g., created, purchased, used, modified,
etc.) and deployed to the computer system. To this extent, the deployment can
comprise one or more of: (1) installing program code on a computing device; (2)
adding one or more computing and/or I/O devices to the computer system; (3)
41
incorporating and/or modifying the computer system to enable it to perform a process
described herein; and/or the like.
[0098] It is understood that aspects of the invention can be implemented as
part of a business method that performs a process described herein on a subscription,
advertising, and/or fee basis. That is, a service provider could offer to predict NOx
emission rates as described herein. In this case, the service provider can manage (e.g.,
create, maintain, support, etc.) a computer system, such as computer system 20 (FIG.
1), that performs a process described herein for one or more customers. In return, the
service provider can receive payment from the customer(s) under a subscription
and/or fee agreement; receive payment from the sale of advertising to one or more
third parties, and/or the like.
[0099] The foregoing description of various aspects of the invention has been
presented for purposes of illustration and description. It is not intended to be
exhaustive or to limit the invention to the precise form disclosed, and obviously,
many modifications and variations are possible. Such modifications and variations
that may be apparent to an individual in the art are included within the scope of the
invention as defined by the accompanying claims.
42
PARTS LIST
environment 10
natural gas-fired boiler 100
computer system 20
fuel flow rate meter 34
NOx analyzer 120
oxygen analyzer 130
user 36
system maintainer 80
processing component 22
storage component 24
input/output (I/O) component 26
PEMS 30
pathway 28
PEMS data 32
calculator 40
predictor 50
obtainer 60
correlator 55
user interface module 70
calibrator 82
data recorder 84
data reporter 86
Step SI includes calculating a correlation of the NOx emission rate to a measured fuel
flow rate, and a sampled oxygen concentration based on a plurality of sampled NOx
emission concentrations, measured fuel flow rates, and sampled oxygen (O2)
concentrations during operation of the non-continuous, natural gas-fired boiler
1
Step S2 includes calculating a predicted N0X emission rate based on the correlation
with the measured fuel flow rate and the sampled O2 concentration.
Step SI A, sampling flue gas may be conducted on two boilers, having the
characteristics of boiler 100, see FIG. 1, to calculate the correlation of the NOx
emission rate to boiler operating load (represented by measured fuel flow rate) and
flue gas oxygen concentration.
Step SIB, calculating the correlation of the NOx emission rate based on the plurality
of measured fuel flow rates, and corresponding sampled NOx emission concentrations
and sampled O2 concentrations.
Step S2A, obtaining a fuel flow rate and a corresponding O2 concentration of the noncontinuous,
natural gas-fired boiler during operation.
Step S2B, correlating the obtained fuel flow rate and corresponding obtained O2
concentration with the correlation to arrive at the measured fuel flow rate and the
sampled O2 concentration, the obtained fuel flow rate may be correlated by applying
the obtained fuel flow rate from step S2A to the correlation curve, see FIG. 3 and
FIG. 4, and selecting the measured fuel flow rate point from the correlation curve that
is closest to the obtained fuel flow rate.
Step S2C, calculating the predicted the NOx emission rate based on the correlation of
the measured fuel flow rate and the corresponding sampled O2 concentration.
Step S30, calibrating a non-continuous, natural gas-fired boiler
Step S35, calibrating the predictive monitoring system
Step S40, recording data related to either of the natural gas-fired boiler or the
predictive monitoring system during calibration
2
Step S45, reporting the data related to either of the natural gas-fired boiler or the
predictive monitoring system resulting from calibration

CLAIMS
What is claimed is:
1. A method for predicting a nitrogen oxide (NOx) emission rate of a noncontinuous,
natural gas-fired boiler (100), the method comprising:
calculating a correlation of the NOx emission rate to a measured fuel flow rate
and a sampled oxygen (O2) concentration based on a plurality of sampled NOx
emission concentrations, measured fuel flow rates, and sampled (O2) concentrations
during operation of the non-continuous, natural gas-fired boiler (100) using a
computing device (SI);
calculating a predicted NOx emission rate based on the correlation with the
measured fuel flow rate and the sampled O2 concentration (S2) using the computing
device (S2); and
providing the predicted NOx emission rate for use by a user (36).
2. A method for predicting a NOx emission rate according to claim 1, wherein
the calculating of the correlation comprises:
sampling flue gas from the non-continuous, natural gas-fired boiler(lOO)
during operation at the plurality of measured fuel flow rates to obtain the plurality of
corresponding sampled O2 concentrations and sampled NOx concentrations (SIA);
and
calculating the correlation of the NOx emission rate based on the plurality of
measured fuel flow rates, and the plurality of corresponding sampled O2
concentrations and sampled NOx concentrations using the computerized device (SIB).
43
3. A method for predicting a NOx emission rate according to claim 1, wherein the
calculating of the predicted NOx emission rate comprises:
obtaining a fuel flow rate and a corresponding O2 concentration of the noncontinuous,
natural gas-fired boiler (100) during operation (S2A);
correlating the obtained fuel flow rate and corresponding obtained O2
concentration with the correlation to arrive at the measured fuel flow rate and the
sampled O2 concentration using the computerized device (S2B); and
calculating the predicted NOx emission rate based on the correlation with the
measured fuel flow rate and the corresponding sampled O2 concentration (S2C).
4. A predictive monitoring system for a nitrogen oxide (NOx) emission rate
comprising:
at least one device including:
a calculator (40) for calculating a correlation of the NOx emission rate
to a measured fuel flow rate and a sampled oxygen (O2) concentration based
on a plurality of sampled NOx emission concentrations, measured fuel flow
rates, and sampled O2 concentrations during operation of a non-continuous,
natural gas-fired boiler (100); and
a calculator (40) for calculating a predicted NOx emission rate based
on the correlation of the measured fuel flow rate and the sampled O2
concentration.
5. A predictive monitoring system for a NOx emission rate according to claim 4,
wherein the predictor (50) comprises: a correlator (55) for correlating an obtained
44
fuel flow rate and corresponding obtained O2 concentration with the correlation to
arrive at the measured fuel flow rate and the corresponding sampled O2 concentration.
6. A predictive monitoring system for a NOx emission rate according to claim 4,
wherein the monitoring system is maintained by: calibrating a non-continuous,
natural gas-fired boiler (100) during operation (S30); calibrating the predictive
monitoring system (S35); recording data related to either of the natural gas-fired
boiler (100) or the predictive monitoring system during calibration (S40); and
reporting the data related to either of the natural gas-fired boiler (100) or the
predictive monitoring system resulting from calibration (S45).
7. A predictive monitoring system for a NOx emission rate according to claim 6,
wherein the data is selected from the group consisting of a NOx emission
concentration, fuel flow rate, flue gas oxygen concentration, downtime of the
predictive monitoring system, an audit result, a certification report for the predictive
monitoring system, a natural gas certification for the predictive monitoring system, a
calibration result, and a semiannual report.
8. A computer program comprising program code embodied in at least one
computer-readable medium, which when executed, enables a computer system (20) to
implement a method of predicting a nitrogen oxide (NOx) emission rate of a noncontinuous,
natural gas-fired boiler (100), the method comprising:
calculating a correlation of the NOx emission rate to a measured fuel flow rate
and a sampled oxygen (O2) concentration based on a plurality of sampled NOx
45
emission concentrations, measured fuel flow rates, and sampled (O2) concentrations
during operation of the non-continuous, natural gas-fired boiler using a computing
device;
calculating a predicted NOx emission rate based on the correlation with the
measured fuel flow rate and the sampled O2 concentration using the computing
device; and
providing the predicted NOx emission rate for use by a user (36).
9. A computer program according to claim 8, wherein the calculating of the
correlation comprises:
sampling flue gas (SIA) from the non-continuous, natural gas-fired boiler
(100) during operation at the plurality of measured fuel flow rates to obtain the
plurality of corresponding sampled O2 concentrations and sampled NOx
concentrations; and
calculating the correlation of the NOx emission rate based on the plurality of
measured fuel flow rates, and the plurality of corresponding sampled O2
concentrations and sampled NOx concentrations using the computerized device.
10. A computer program according to claim 9, wherein the calculating of the
predicted NOx emission rate comprises:
obtaining a fuel flow rate and a corresponding O2 concentration of the noncontinuous,
natural gas-fired boiler (100) during operation (S2A);
46
correlating the obtained fuel flow rate and corresponding obtained O2
concentration with the correlation to arrive at the measured fuel flow rate and the
sampled O2 concentration using the computerized device; and
calculating the predicted NOx emission rate based on the correlation with the
measured fuel flow rate and the corresponding sampled O2 concentration.
11. A method for predicting a nitrogen oxide (NOx) emission rate of a non-continuous,
natural gas-fired boiler, substantially as herein described with reference to accompanying
drawings and example.
12. A predictive monitoring system for a nitrogen oxide (NOx) emission rate,
substantially as herein described with reference to accompanying drawings and example.
13. A computer program comprising program code embodied in at least one computerreadable
mediimi, which when executed, enables a computer system to implement a method
of predicting a nitrogen oxide, substantially as herein described with reference to
accompanying drawings and example.