U.S. patent application number 17/613953 was filed with the patent office on 2022-08-11 for systems and methods for detecting discrepancy in a combustion system.
This patent application is currently assigned to OnPoint Technologies, LLC. The applicant listed for this patent is OnPoint Technologies, LLC. Invention is credited to Kevin ANDERSON, Chad CARROLL, Thomas KORB, Ryan MORGAN, Nicholas RUSSELL, Mark VACCARI, Junda ZHU.
Application Number | 20220252265 17/613953 |
Document ID | / |
Family ID | 1000006361029 |
Filed Date | 2022-08-11 |
United States Patent
Application |
20220252265 |
Kind Code |
A1 |
CARROLL; Chad ; et
al. |
August 11, 2022 |
SYSTEMS AND METHODS FOR DETECTING DISCREPANCY IN A COMBUSTION
SYSTEM
Abstract
Systems and methods for determining operating discrepancy a
process heater. The discrepancy may be identified by solving a
fired-systems model of the heater. The fired-systems model is then
compared to current operating data. If the sensed current operating
data is outside of the expected value(s), as defined by the
fired-systems model, the systems and methods may take a remediation
action to resolve the discrepancy. The discrepancy may include
convection fouling identification and identification of tramp-air
leaks within the process heater that are otherwise not easily
detected by a human operator.
Inventors: |
CARROLL; Chad; (Tulsa,
OK) ; KORB; Thomas; (Tulsa, OK) ; MORGAN;
Ryan; (Tulsa, OK) ; RUSSELL; Nicholas; (Broken
Arrow, OK) ; ANDERSON; Kevin; (Davis, CA) ;
VACCARI; Mark; (Broken Arrow, OK) ; ZHU; Junda;
(Tulsa, OK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
OnPoint Technologies, LLC |
Wichita |
KS |
US |
|
|
Assignee: |
OnPoint Technologies, LLC
Wichita
KS
|
Family ID: |
1000006361029 |
Appl. No.: |
17/613953 |
Filed: |
June 19, 2020 |
PCT Filed: |
June 19, 2020 |
PCT NO: |
PCT/IB2020/055821 |
371 Date: |
November 24, 2021 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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62864967 |
Jun 21, 2019 |
|
|
|
62864997 |
Jun 21, 2019 |
|
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|
62865021 |
Jun 21, 2019 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
F23N 5/242 20130101;
F23N 2229/20 20200101 |
International
Class: |
F23N 5/24 20060101
F23N005/24 |
Claims
1. A method for determining discrepancy in air-flow of a process
heater, comprising: receiving sensed current oxygen level within a
housing of the process heater; calculating a delta between the
sensed current oxygen level and an expected oxygen level; comparing
the delta to a predetermined threshold; when the delta indicates
excess air-flow, determining an amount of the excess air-flow in
terms of leakage area within the housing based at least in part on
geometry of the housing, and an identified draft within the
housing; and, outputting a remediation action in response to the
delta breaching the predetermined threshold.
2. (canceled)
3. The method of claim 1, further comprising comparing the leakage
area to size of known components of the process heater; wherein
outputting a remediation action includes outputting the remediation
action with respect to at least one known component of the known
components when the leakage area matches the size of the at least
one known component.
4. The method of claim 3, the at least one known component
including a viewing access panel.
5. The method of claim 1, further comprising displaying the leakage
area at a process controller of the process heater.
6. The method of claim 1, further comprising, determining the
predetermined threshold based at least in part on verified air-flow
settings.
7. The method of claim 6, the verified air-flow settings including
one or more of: burner damper settings, stack damper settings,
stack fan settings, and forced fan settings.
8. The method of claim 1, wherein identifying sensed oxygen level
includes identifying a plurality of sensed oxygen levels each
respectively corresponding to a plurality of heights within the
housing of the process heater; and, wherein calculating a delta
between the sensed current oxygen level and an expected oxygen
level includes calculating a plurality of deltas each respectively
corresponding to at least one of the plurality of sensed oxygen
levels and a corresponding at least one of a plurality of expected
oxygen levels; the method further comprising identifying a height
at which one or more of the plurality of deltas breach the
predetermined threshold; and the outputting a remediation action
including outputting a zone of the housing having likely tramp-air
penetration based at least in part on the height.
9. The method of claim 1, further comprising: performing an optical
scan of inside the housing of the process heater; and identifying
irregularity within the optical scan indicating tramp-air
penetration; the outputting a remediation action including
outputting a zone of the housing of the process heater having the
irregularity.
10. The method of claim 9, the optical scan including an infrared
image.
11. The method of claim 9, the optical scan including a tunable
diode laser absorption spectroscopy (TDLAS) scan.
12. The method of claim 1, when the delta indicates deficient air
within the process heater, the method further comprising:
performing an optical scan of a burner of the process heater;
identifying irregularity of a burner flame based at least in part
on the optical scan; and, the outputting a remediation action
including outputting a zone of the process heater based at least in
part on the irregularity.
13. The method of claim 12, the optical scan including an infrared
image.
14. The method of claim 12, the optical scan including a tunable
diode laser absorption spectroscopy (TDLAS) scan.
15. The method of claim 1, further comprising, prior to outputting
a remedial action, verifying fuel-flow rates within the process
heater.
16. A system for determining operating discrepancy a process
heater, comprising: a processor; and, memory storing computer
readable instructions that, when executed by the processor, operate
to: receive sensed current operating data within the process
heater; calculate a delta between the sensed current operating data
and an expected current operating data corresponding to the sensed
current operating data; compare the delta to a predetermined
threshold; when the delta indicates excess air-flow, determine an
amount of the excess air-flow in terms of leakage area within the
process heater based at least in part on geometry of the process
heater, and an identified draft within the process heater; and,
output a remediation action in response to the delta breaching the
predetermined threshold.
17. (canceled)
18. (canceled)
19. (canceled)
20. (canceled)
21. A combustion system having burner tip plugging indication,
comprising: a burner having a burner tip; a fuel pressure sensor
generating fuel pressure data of a fuel source input into the
burner; a processor; and, memory operatively coupled to the
processor storing a burner tip monitor as computer readable
instructions that when executed by the processor operate to:
generate a calculated fuel heat release of the burner by executing
a fired-systems model of the burner based at least in part on fuel
information, a fuel pressure, and burner geometry, and compare the
calculated fuel heat release of the burner to a measured heat
release to generate a burner tip health indication of the burner
tip.
22. The combustion system of claim 21, the measured heat release
being further based at least in part on fuel temperature data
sensed by a fuel temperature sensor of the combustion system.
23. The combustion system of claim 21, the burner tip health
indication including a ratio of the measured heat release to the
calculated fuel heat release.
24. The combustion system of claim 23, the computer readable
instructions including computer readable instructions that when
executed by the processor operate to compare the ratio to a burner
tip health threshold to identify a plugged burner tip.
25. (canceled)
26. (canceled)
27. (canceled)
28. (canceled)
29. (canceled)
30. (canceled)
31. The combustion system of claim 21, the burner including a
plurality of burners; the burner tip monitor including further
computer readable instructions that when executed by the processor
operate to: identify a specific burner or group of burners having a
tip malfunction identified in the burner tip health indication
based at least in part on in-heater data.
32. (canceled)
33. (canceled)
34. (canceled)
35. (canceled)
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to, and benefits from each
of: U.S. Provisional Application Ser. No. 62/864,967, filed Jun.
21, 2019, and U.S. Provisional Application Ser. No. 62/864,997,
filed Jun. 21, 2019; and U.S. Provisional Application Ser. No.
62/865,021, filed Jun. 21, 2019. This application is also related
to each of: U.S. Provisional Application Ser. No. 62/864,954, filed
Jun. 21, 2019; U.S. Provisional Application Ser. No. 62/864,992,
filed Jun. 21, 2019; U.S. Provisional Application Ser. No.
62/865,007, filed Jun. 21, 2019; and U.S. Provisional Application
Ser. No. 62/865,031, filed Jun. 21, 2019. The entire contents of
each of the aforementioned applications are incorporated herein as
if fully set forth.
BACKGROUND
[0002] Combustion systems operate by converting fuel and air into
thermal energy within a process heater. Downstream from this
conversion location, various sensors operate to collect emissions
and flue gas composition data such as Nitrous Oxide (NO.sub.X),
Oxygen (O.sub.2), and Carbon Monoxide (CO). Many parameters are
sensed by various sensors throughout the combustion system. Oxygen
measurements, in particular, are indicative of the amount of air
input into the system that is in excess of the required amount of
air needed for the conversion of the fuel to thermal energy
(stoichiometric air requirements). These oxygen measurements are
used to control the input and ratio of fuel and air into the
system. If these oxygen measurements are not correct, such as due
to unwanted excess air entering the system at leaks in the system
housing (sometimes referred to as tramp air), or extra fuel
entering the system (via holes in the process tubes of the
combustion system), or insufficient air being provided to the
system (via malfunctioning or blocked air inlets at the burners),
the control of the heater becomes inefficient and potentially
unsafe.
[0003] Process heaters have multiple burners (sometimes up to 200+
burners per furnace) and each one has one or multiple burner tips,
each configured to inject fuel according to a specific flow
rate/pattern for combustion within the heater. Over time, these
burner tips become clogged or begin to foul with "coke" and other
material. This clogging (also known as plugging) causes the
collective burner system to operate inefficiently. Additionally,
plugged gas tips can cause an otherwise stable burner to lose its
flame anchoring or relighting capability, causing substantial
safety concerns if not maintained frequently or properly.
BRIEF DESCRIPTION OF THE FIGURES
[0004] The foregoing and other features and advantages of the
disclosure will be apparent from the more particular description of
the embodiments, as illustrated in the accompanying drawings, in
which like reference characters refer to the same parts throughout
the different figures. The drawings are not necessarily to scale,
emphasis instead being placed upon illustrating the principles of
the disclosure.
[0005] FIG. 1 depicts an example system of a process heater with
automatic air register setting determination, in embodiments.
[0006] FIG. 2 depicts a typical draft profile throughout a heater
(e.g., the heater of FIG. 1).
[0007] FIG. 3 depicts a plurality of example process tube
types.
[0008] FIG. 4 depicts a diagram showing air temperature and
humidity effects on sensed excess O.sub.2 levels.
[0009] FIG. 5 depicts a schematic of air and fuel mixture in a
pre-mix burner, in embodiments.
[0010] FIG. 6 depicts a schematic of air and fuel mixture in a
diffusion burner, in embodiments.
[0011] FIG. 7 depicts an example cutaway diagram of a burner, which
is an example of the burner of FIG. 1.
[0012] FIG. 8 depicts an example air register handle and indicator
plate 804 that is manually controlled.
[0013] FIG. 9 depicts example burner tips with different shapes and
sizes.
[0014] FIG. 10 depicts example burner tips with the same shape, but
different drill hole configurations.
[0015] FIG. 11 depicts a block diagram of the process controller of
FIG. 1 in further detail, in embodiments.
[0016] FIGS. 12-16 depict various operating conditions result in
sensed oxygen readings by the oxygen sensor of FIG. 1 that cause
incorrect control of the input fuel/air ratio to the burner of FIG.
1, in examples.
[0017] FIG. 17 depicts an air analyzer, which is an example of the
air analyzer, of FIG. 11, in an embodiment.
[0018] FIGS. 18 and 19 show example tramp air indicators, in
embodiments (the cumulative difference between the calculated and
the measured excess O2)
[0019] FIG. 20 depicts a method for determining air-flow
discrepancy in a combustion system, in embodiments.
[0020] FIG. 21 depicts an example of clogged fins on process
tubes.
[0021] FIG. 22 depicts an example draft analyzer including draft
discrepancy identifier, in embodiments.
[0022] FIGS. 23-28 depict graphs indicating heater operation over
time when the fins of process tubes become clogged due to harsh
conditions in the heater, in an embodiment.
[0023] FIG. 29 depicts data table represented by the graphs of
FIGS. 23-28.
[0024] FIG. 30 depicts a method for determining discrepancy in a
combustion system, in embodiments.
[0025] FIG. 31 depicts a burner having a burner tip that has
completely failed, in an example.
[0026] FIG. 32 depicts a fuel analyzer, which is an example of the
fuel analyzer of FIG. 11, in an embodiment.
[0027] FIG. 33 depicts a comparison of a calculated heat release to
a measured heat release.
[0028] FIG. 34 depicts an example burner tip health indication in
the form of a graph depicting the ratio of the measured heat
release to the calculated heat release.
[0029] FIG. 35 depicts a method for generating a combustion system
burner tip health indication, in embodiments.
[0030] FIGS. 36 and 37 depict example data showing oxygen data used
to verify that tip plugging was not occurring.
[0031] FIG. 38 depicts a method for determining discrepancy in a
combustion system, in embodiments.
DETAILED DESCRIPTION OF THE EMBODIMENTS
[0032] FIG. 1 depicts an example system 100 of a process heater
with intelligent monitoring system, in embodiments. The system 100
includes a heater 102 that is heated by one or more burners 104
located in the housing 103 thereof. Heater 102 can have any number
of burners 104 therein, each operating under different operating
conditions (as discussed in further detail below). Moreover,
although FIG. 1 shows a burner located on the floor of the heater
102, one or more burners may also be located on the walls and/or
ceiling of the heater 102 without departing from the scope hereof
(indeed, heaters in the industry often have over 100 burners).
Further, the heater 102 may have different configurations, for
example a box heater, a cylindrical heater, a cabin heater, and
other shapes, sizes, etc. as known in the art.
[0033] Burner 104 provides heat necessary to perform chemical
reactions or heat up process fluid in one or more process tubes 106
(not all of which are labeled in FIG. 1. Any number of process
tubes 106 may be located within the heater 102, and in any
configuration (e.g., horizontal, vertical, curved, off-set,
slanted, or any configuration thereof). Burner 104 is configured to
combust a fuel source 108 with an oxidizer such as air input 110 to
convert the chemical energy in the fuel into thermal energy 112
(e.g., a flame). This thermal energy 112 then radiates to the
process tubes 106 and is transferred through the process tubes 106
into a material therein that is being processed. Accordingly, the
heater 102 typically has a radiant section 113, a convection
section 114, and a stack 116. Heat transfer from the thermal energy
112 to the process tubes 106 primarily occurs in the radiant
section 113 and the convection section 114.
[0034] Airflow into the heater 102 (through the burner 104)
typically occurs in one of four ways natural, induced, forced, and
balanced.
[0035] A natural induced airflow draft occurs via a difference in
density of the flue gas inside the heater 102 caused by the
combustion. There are no fans associated in a natural induced
system. However, the stack 116 includes a stack damper 118 and the
burner includes a burner air register 120 that are adjustable to
change the amount of naturally induced airflow draft within the
heater 102.
[0036] An induced airflow draft system includes a stack fan (or
blower) 122 located in the stack (or connected to the stack) 116.
In other or additional embodiments, other motive forces than a fan
are be used to create the induced draft, such as steam injection to
educts flue gas flow through the heater. The stack fan 122 operates
to pull air through the burner air register 120 creating the
induced-draft airflow within the heater 102. The stack fan 122
operating parameters (such as the stack fan 122 speed and the stack
damper 118 settings) and the burner air register 120 impact the
draft airflow. The stack damper 118 may be a component of the stack
fan 122, or separate therefrom.
[0037] A forced-draft system includes an air input forced fan 124
that forces air input 110 into the heater 102 via the burner 104.
The forced fan 124 operating parameters (such as the forced fan 124
speed and the burner air register 120 settings) and the stack
damper 118 impact the draft airflow. The burner air register 120
may be a component of the forced fan 124, but is commonly separate
therefrom and a component of the burner 104.
[0038] A balanced-draft system includes both the air input forced
fan 124 and the stack fan 122. Each fan 122, 124 operate in
concert, along with the burner air register 120 and stack damper
118 to control the airflow and draft throughout the heater 102.
[0039] Draft throughout the heater 102 varies depending on the
location within the heater 102. FIG. 2 depicts a typical draft
profile 200 throughout a heater (e.g., heater 102). Line 202
depicts a desired draft that is consistent with the design of the
heater and components therein. Line 204 depicts a high draft
situation where pressure in the heater is more negative than
desired (and thus further negative compared to atmospheric pressure
outside of the heater). Line 206 depicts a low draft situation
where pressure in the heater is more positive than desired (and
thus closer to or greater than atmospheric pressure outside of the
heater). As shown, by line 202, heaters are often designed to have
a -0.1 pressure at the arch of the heater.
[0040] Draft throughout the heater 102 is also be impacted based on
the geometry of the heater and components thereon. For example,
draft is strongly a function of heater 102 height. The taller the
heater 102, the more negative the draft will be at the floor of the
heater 102 to maintain the same draft level at the top of the
heater 102 (normally -0.1 in H.sub.2O). The components greatly
impact the draft. For example, FIG. 3 depicts a plurality of
process tube types. The convection section process tubes 106 may or
may not have heat sink fins thereon to manage the heat transfer
from the thermal energy 112 to the process tube 106. These
convection section fins may plug or corrode overtime-varying the
required draft within a heater as compared to the designed draft
for the same heater with the same components. As the convection
section flue gas channel open area begins to decrease, a greater
pressure differential is required to pull the same quantity of flue
gas through the convection section.
[0041] Referring to FIG. 1, pressure (indicating draft) within the
heater 102 is measured at a variety of locations in the heater
respectively via one of a plurality of pressure sensors. Floor
pressure sensor 126(1) measures the pressure at the floor of the
heater 102. Arch pressure sensor 126(2) measures the pressure at
the arch of the heater 102 where the radiant section 113
transitions to the convection section 114. Convection pressure
sensor 127 measures the pressure of the convection section 114.
Stack pressure sensor 129, if included, measures the pressure of
the stack 116.
[0042] The pressure sensors 126, 127, 129 may include a manometer,
or a Magnehelic draft gauge, where the pressure readings are
manually entered into process controller 128 (or a handheld
computer and then transferred wirelessly or via wired connection
from the handheld computer to the process controller 128) including
a sensor database 130 therein storing data from various components
associated with the heater 102. The pressure sensors 126, 127, 129
may also include electronic pressure sensors and/or draft
transmitters that transmit the sensed pressure to the process
controller 128 via a wired or wireless connection 133. The wireless
or wired connection 133 may be any communication protocol,
including WiFi, cellular, CAN bus, etc.
[0043] The process controller 128 is a distributed control system
(DCS) (or plant control system (PLC) used to control various
systems throughout the system 100, including fuel-side control
(e.g., control of components associated with getting fuel source
108 into the heater 102 for combustion therein), air-side control
(e.g., control of components associated with getting air source 110
into the heater 102), internal combustion-process control (e.g.,
components associated with managing production of the thermal
energy 112, such as draft within the heater 102), and
post-combustion control (e.g., components associated with managing
the emissions after production of the thermal energy 112 through
the stack 116). The process controller 128 typically includes many
control loops, in which autonomous controllers are distributed
throughout the system 100 (associated with individual or multiple
components thereof), and including a central operator supervisory
control.
[0044] Operating conditions within the heater 102 (such as draft,
and the stoichiometry associated with creating the thermal energy
112) are further impacted via atmospheric conditions, such as wind,
wind direction, humidity, ambient air temperature, sea level, etc.
FIG. 4 depicts a diagram 400 showing air temperature and humidity
effects on sensed excess O.sub.2 levels. The changes in operating
conditions are often controlled by monitoring and manipulating the
draft conditions within the heater 102. The stack dampers 118 are
commonly digitally controlled, and therefore often controllable
from the operating room of the system 100, via the process
controller 128. However, many systems do not include burner air
registers 120 that are digitally controlled. Because of this,
system operators often control draft within the heater 102 using
just an electronic stack damper (e.g., stack damper 118) thereby
avoiding timely and costly manual operation of each burner air
register (e.g., burner air register 120) associated with each
individual burner (e.g., burner 104). This cost grows depending on
the number of burners located in each heater--each heater may have
over 100 burners therein.
[0045] In addition to the draft as discussed above, burner geometry
plays a critical role in managing the thermal energy 112 produced
in the heater 102. Each burner 104 is configured to mix the fuel
source 108 with the air source 110 to cause combustion and thereby
create the thermal energy 112. Common burner types include pre-mix
burners and diffusion burners. FIG. 5 depicts a schematic 500 of
air and fuel mixture in a pre-mix burner, in embodiments. In a
pre-mix burner, kinetic energy of the fuel gas 502 draws some
primary air 504 needed for combustion into the burner. The fuel and
air mix to create an air/fuel mixture 504 having a specific
air-to-fuel ratio prior to igniting to create the thermal energy
112. FIG. 6 depicts a schematic 600 of air and fuel mixture in a
diffusion burner, in embodiments. In a diffusion burner, air 604
for combustion is drawn (by induced- or natural-draft) or pushed
(by forced-, or balanced-draft) into the heater before mixing with
the fuel 602. The mixture burns at the burner gas tip 606.
[0046] FIG. 7 depicts an example cutaway diagram of a burner 700,
which is an example of the burner 104 of FIG. 1. Burner 700 is an
example of a diffusion burner. Burner 700 is shown located mounted
in a heater at the heater floor 702. Proximate the burner 700 in
the heater floor 702 is a manometer 704, which is an example of the
pressure sensors 126, 127, 129 discussed above. The manometer 704
may be another type of pressure sensor without departing from the
scope hereof. Burner 700 is shown for a natural or induced-draft
heater system, and includes a muffler 706 and a burner air register
708. Ambient air flows through the muffler 706 from outside the
heater system. In a forced or balanced-draft system, the muffler
706 may not be included and instead be replaced with an intake
ducting from the forced fan (e.g., forced fan 124 in FIG. 1). The
burner air register 708 is an example of the burner air register
120 discussed above with respect to FIG. 1, and may be manipulated
via an air register handle 710 to one of a plurality of settings
defining how open or closed the air register 708 is. As discussed
above, the air register handle 710 is typically manually controlled
(although sometimes is fitted with an actuator, or provided with
mechanical linkage and an actuator so a single actuator manipulates
a plurality of burners). FIG. 8 depicts an example air register
handle 802 and indicator plate 804 that is manually controlled. The
input air then travels through the burner plenum 712 towards the
burner output 714 where it is mixed with input fuel and ignited to
combust and produce thermal energy (e.g., thermal energy 112 of
FIG. 1).
[0047] The fuel travels through a fuel line 716, and is output at a
burner tip 718. The fuel may be disbursed on a deflector 720. The
burner tip 718 and deflector 720 may be configured with a variety
of shapes, sizes, fuel injection holes, etc. to achieve the desired
combustion results (e.g., flame shaping, emissions tuning, etc.).
FIG. 9 depicts example burner tips with different shapes and sizes.
FIG. 10 depicts example burner tips with the same shape, but
different drill hole configurations. Furthermore, one or more tiles
722 may be included at the burner output 714 to achieve a desired
flame shape or other characteristic.
[0048] Referring to FIG. 1, control of the system 100 occurs both
manually and digitally. As discussed above, various components,
such as burner air register 120 are commonly manually controlled.
However, the system 100 also includes a variety of sensors
throughout the heater 102, the fuel-side input, and the air-side
input used to monitor and control the system using the process
controller 128.
[0049] At the stack 116, an oxygen sensor 132, a carbon monoxide
sensor 134, and NO.sub.x sensor 136 can be utilized to monitor the
condition of the exhaust and emissions leaving the heater 102 via
the stack 116. Each of the oxygen sensor 132, carbon monoxide
sensor 134, and NO.sub.X sensor 136 may be separate sensors, or
part of a single gas-analysis system. The oxygen sensor 132, carbon
monoxide sensor 134, and NO.sub.x sensor 136 are each operatively
coupled to the process controller 128 via a wired or wireless
communication link. These sensors indicate the state of combustion
in the heater 102 in substantially real-time. Data captured by
these sensors is transmitted to the process controller 128 and
stored in the sensor database 130. By monitoring the combustion
process represented by at least one of the oxygen sensor 132,
carbon monoxide sensor 134, and NO.sub.x sensor 136, the system
operator may adjust the process and combustion to stabilize the
heater 102, improve efficiency, and/or reduce emissions. In some
examples, other sensors, not shown, can be included to monitor
other emissions (e.g., combustibles, methane, sulfur dioxide,
particulates, carbon dioxide, etc.) on a real-time basis to comply
with environmental regulations and/or add constraints to the
operation of the process system. Further, although the oxygen
sensor 132, carbon monoxide sensor 134, and NO.sub.x sensor 136 are
shown in the stack 116, there may be additional oxygen sensor(s),
carbon monoxide sensor(s), and NO.sub.x sensor(s) located elsewhere
in the heater 102, such as at one or more of the convection section
114, radiant section 113, and/or arch of the heater 102. The above
discussed sensors in the stack section may include a flue gas
analyzer (not shown) prior to transmission to the process
controller 128 that extract, or otherwise test, a sample of the
emitted gas within the stack 116 (or other section of the heater)
and perform an analysis on the sample to determine the associated
oxygen, carbon monoxide, or NO.sub.x levels in the sample (or other
analyzed gas). Other types of sensors include tunable laser diode
absorption spectroscopy (TDLAS) systems that determine the chemical
composition of the gas based on laser spectroscopy.
[0050] Flue gas temperature may also be monitored by the process
controller 128. To monitor the flue gas temperatures, the heater
102 may include one or more of a stack temperature sensor 138, a
convection sensor temperature sensor 140, and a radiant temperature
sensor 142 that are operatively coupled to the process controller
128. Data from the temperature sensors 138, 140, 142 are
transmitted to the process controller 128 and stored in the sensor
database 130. Further, each section may have a plurality of
temperature sensors--in the example of FIG. 1, there are three
radiant section temperature sensors 142(1)-(3). The above discussed
temperature sensors may include a thermocouple, suction pyrometer,
and/or laser spectroscopy analysis systems that determine the
temperature associated with the given temperature sensor.
[0051] The process controller 128 may further monitor air-side
measurements and control airflow into the burner 104 and heater
102. Air-side measurement devices include an air temperature sensor
144, an air-humidity sensor 146, a pre-burner air register air
pressure sensor 148, and a post-burner air register air pressure
sensor 150. In embodiments, the post-burner air pressure is
determined based on monitoring excess oxygen readings in the heater
102. The air-side measurement devices are coupled within or to the
air-side ductwork 151 to measure characteristics of the air flowing
into the burner 104 and heater 102. The air-temperature sensor 144
may be configured to sense ambient air temperatures, particularly
for natural and induced-draft systems. The air-temperature sensor
144 may also be configured to detect air temperature just prior to
entering the burner 104 such that any pre-heated air from an
air-preheat system is taken into consideration by the process
controller 128. The air-temperature sensor 144 may be a
thermocouple, suction pyrometer, or any other temperature measuring
device known in the art. The air humidity sensor 146 may be a
component of the air temperature sensor, or may be separate
therefrom, and is configured to sense the humidity in the air
entering the burner 104. The air temperature sensor 144 and air
humidity sensor 146 may be located upstream or downstream from the
burner air register 120 without departing from the scope hereof.
The pre-burner air register air pressure sensor 148 is configured
to determine the air pressure before the burner air register 120.
The post-burner air register air pressure sensor 150 is configured
to determine the air pressure after the burner air register 120.
The post-burner air register air pressure sensor 150 may not be a
sensor measuring the furnace draft at the burner elevation, or
other elevation and then calculated to determine the furnace draft
at the burner elevation. Comparisons between the post-burner air
register air pressure sensor 150 and the pre-burner air register
air pressure sensor 148 may be made by the process controller to
determine the pressure drop across the burner 104, particularly in
a forced-draft or balanced-draft system. Air-side and temperature
measurements discussed herein may further be measured using one or
more TDLAS devices 147 located within the heater 102 (at any of the
radiant section 113, convection section 114, and/or stack 116).
[0052] Burner 104 operational parameters may further be monitored
using a flame scanner 149. Flame scanners 149 operate to analyze
frequency oscillations in ultraviolet and/or infrared wavelengths
of one or both of the main burner flame or the burner pilot
light.
[0053] FIG. 1 also shows an air handling damper 152 that is located
prior to the burner air register 120. The air-handling damper 152
includes any damper that impacts air-flow into the heater 102, such
as a duct damper, variable speed fan, fixed-speed fan with air
throttling damper, etc.) In certain system configurations, a single
air input (including a given fan 124) supplies air to a plurality
of burners, or a plurality of zones within a given heater. There
may be any number of fans (e.g., forced fan 124), temperature
sensors (e.g., air temperature sensor 144), air humidity sensors
(e.g., air humidity sensor 146), air pressure sensors (e.g.,
pre-burner air register air pressure sensor 148) for a given
configuration. Further, any of these air-side sensors maybe located
upstream or downstream from the air handling damper 152 without
departing form the scope hereof.
[0054] The process controller 128 may further monitor fuel-side
measurements and control fuel flow into the burner 104. Fuel-side
measurement devices include one or more of flow sensor 154, fuel
temperature sensor 156, and fuel-pressure sensor 158. The fuel-side
measurement devices are coupled within or to the fuel supply
line(s) 160 to measure characteristics of the fuel flowing into the
burner 104. The flow sensor 154 may be configured to sense flow of
the fuel through the fuel supply line 160. The fuel-temperature
sensor 156 detects fuel temperature in the fuel supply line 160,
and includes known temperature sensors such as a thermocouple. The
fuel-pressure sensor 158 detects fuel-pressure in the fuel supply
line 160.
[0055] The fuel line(s) 160 may have a plurality of fuel control
valves 162 located thereon. These fuel control valves 162 operate
to control the flow of fuel through the supply lines 160. The fuel
control valves 162 are typically digitally controlled via control
signals generated by the process controller 128. FIG. 1 shows a
first fuel control valve 162(1) and a second fuel control valve
162(2). The first fuel control valve 162(1) controls fuel being
supplied to all burners located in the heater 102. The second fuel
control valve 162(2) controls fuel being supplied to each
individual burner 104 (or a grouping of burners in each heater
zone). There may be more or fewer fuel control valves 162 without
departing from the scope hereof. Further, as shown, there may be a
grouping of fuel-side measurement devices between individual
components on the fuel supply line 160. For example, a first flow
sensor 154(1), first fuel temperature sensor 156(1), and first
fuel-pressure sensor 158(1) are located on the fuel supply line 160
between the fuel source 108 and the first fuel control valve
162(1). A second flow sensor 154(2), second fuel temperature sensor
156(2), and second fuel-pressure sensor 158(2) are located on the
fuel supply line 160 between the first fuel control valve 162(1)
and the second fuel control valve 162(2). Additionally, a third
flow sensor 154(3), third fuel temperature sensor 156(3), and third
fuel-pressure sensor 158(3) are located on the fuel supply line 160
between the second fuel control valve 162(2) and the burner 104.
The third fuel temperature sensor 156(3), and third fuel-pressure
sensor 158(3) may be configured to determine flow, temperature, and
pressure respectively of an air/fuel mixture for pre-mix burners
discussed above with respect to FIG. 5.
[0056] The process controller 128 may also measure process-side
temperatures associated with the processes occurring within the
process tubes 106. For example, system 100 may further include one
or more tube temperature sensors 168, such as a thermocouple, that
monitor the temperature of the process tubes 106. The temperature
sensor 168 may also be implemented using optical scanning
technologies, such as an IR camera, and/or one of the TDLAS devices
147. Furthermore, the heater controller 128 may also receive sensed
outlet temperature of the fluid within the process tubes 106 from
process outlet temperature sensor (not shown), such as a
thermocouple. The process controller 128 may then use these sensed
temperatures (from the tube temperature sensors 168 and/or the
outlet temperature sensor) to control firing rate of the burners
104 to increase or decrease the generated thermal energy 112 to
achieve a desired process temperature.
[0057] FIG. 11 depicts a block diagram of the process controller
128 of FIG. 1 in further detail, in embodiments. The process
controller 128 includes a processor 1102 communicatively coupled
with memory 1104. The processor 1102 may include a single
processing device or a plurality of processing devices operating in
concert. The memory 1104 may include transitory and or
non-transitory memory that is volatile and/or non-volatile.
[0058] The process controller 128 may further include communication
circuitry 1106 and a display 1108. The communication circuitry 1106
includes wired or wireless communication protocols known in the art
configured to receive and transmit data from and to components of
the system 100. The display 1108 may be co-located with the process
controller 128, or may be remote therefrom and displays data about
the operating conditions of the heater 102 as discussed in further
detail below.
[0059] Memory 1104 stores the sensor database 130 discussed above,
which includes any one or more of fuel data 1110, air data 1118,
heater data 1126, emissions data 1140, process-side data 1170, and
any combination thereof. In embodiments, the sensor database 130
includes fuel data 1110. The fuel data 1110 includes fuel flow
1112, fuel temperature 1114, and fuel-pressure 1116 readings
throughout the system 100 regarding the fuel being supplied to the
burner 104. For example, the fuel flow data 1112 includes sensed
readings from any one or more of the flow sensor(s) 154 in system
100 transmitted to the process controller 128. The fuel temperature
data 1114 includes sensed readings from any one or more of the fuel
temperature sensor(s) 156 in system 100 transmitted to the process
controller 128. The fuel-pressure data 1116 includes sensed
readings from any one or more of the fuel-pressure sensor(s) 158 in
system 100 transmitted to the process controller 128. In
embodiments, the fuel data 1110 may further include fuel
composition information that is either sensed via a sensor located
at the fuel source 108 or that is determined based on an inferred
fuel composition such as that discussed in U.S. Provisional Patent
Application No. 62/864,954, filed Jun. 21, 2019 and which is
incorporated by reference herein as if fully set forth. The fuel
data 1110 may also include data regarding other fuel-side sensors
not necessarily shown in FIG. 1, but known in the art.
[0060] In embodiments, the sensor database 130 includes air data
1118 regarding the air being supplied to the burner 104 and heater
102. The air data 1118 includes air temperature data 1120, air
humidity data 1122, and air pressure data 1124. The air temperature
data 1120 includes sensed readings from any one or more of the air
temperature sensor(s) 144 in system 100 transmitted to the process
controller 128. The air humidity data 1122 includes sensed readings
from any one or more of the air humidity sensor(s) 146 in system
100, and/or data from local weather servers, transmitted to the
process controller 128. The air pressure data 1124 includes sensed
readings from any one or more of the pre-burner air register air
pressure sensor 148, and a post-burner air register air pressure
sensor 150 (or any other air pressure sensor) in system 100
transmitted to the process controller 128. The air data 1118 may
also include data regarding other air-side sensors not necessarily
shown in FIG. 1, but known in the art.
[0061] In embodiments, the sensor database 130 includes heater data
1126. The heater data 1126 includes radiant-section temperature
data 1128, convection-section temperature data 1130, stack-section
temperature data 1132, radiant-section pressure data 1134,
convection-section pressure data 1136, and stack-section pressure
data 1138. The radiant-section temperature data 1128 includes
sensed readings from the radiant temperature sensor(s) 142 of
system 100 that are transmitted to the process controller 128. The
convection-section temperature data 1130 includes sensed readings
from the convection temperature sensor(s) 140 of system 100 that
are transmitted to the process controller 128. The stack-section
temperature data 1132 includes sensed readings from the stack
temperature sensor(s) 138 of system 100 that are transmitted to the
process controller 128. The radiant-section pressure data 1134
includes sensed readings from the radiant pressure sensor(s) 126 of
system 100 that are transmitted to the process controller 128. The
convection-section pressure data 1136 includes sensed readings from
the convection pressure sensor(s) 127 of system 100 that are
transmitted to the process controller 128. The stack-section
pressure data 1136 includes sensed readings from the stack pressure
sensor(s) 129 of system 100 that are transmitted to the process
controller 128. The heater data 1126 may also include data
regarding other heater sensors not necessarily shown in FIG. 1, but
known in the art.
[0062] In embodiments, the sensor database 130 further includes
emissions data 1140. The emissions data 1140 includes O.sub.2
reading(s) 1142, CO reading(s) 1144, and NO.sub.X reading(s) 1146.
The O.sub.2 reading(s) 1142 include sensed readings from the oxygen
sensor 132 transmitted to the process controller 128. The CO
reading(s) 1144 include sensed readings from the carbon monoxide
sensor 134 transmitted to the process controller 128. The NO.sub.X
reading(s) 1146 include sensed readings from the NO.sub.X sensor
136 transmitted to the process controller 128. The emissions data
1140 may also include data regarding other emissions sensors not
necessarily shown in FIG. 1, but known in the art.
[0063] In embodiments, the sensor database 130 includes
process-side data 1170 regarding the conditions of the process
tubes 106 and the process occurring. The process-side data 1170
includes process tube temperature 1172, and the outlet fluid
temperature 1174. The process tube temperature 1172 may include
data captured by the process tube temperature sensor 168, discussed
above. The outlet fluid temperature 1174 may include data captured
by an outlet fluid sensor (not shown), such as a thermocouple. The
process-side data 1170 may also include data regarding other
process-side sensors not necessarily shown in FIG. 1, but known in
the art.
[0064] Data within the sensor database 130 is indexed according to
the sensor providing said readings. Accordingly, data within the
sensor database 130 may be used to provide real-time operating
conditions of the system 100.
[0065] The memory 1104, in embodiments, further includes one or
more of a fuel analyzer 1148, an air analyzer 1150, a draft
analyzer 1152, an emissions analyzer 1154, a process-side analyzer
1176, and any combination thereof. Each of the fuel analyzer 1148,
air analyzer 1150, draft analyzer 1152, emissions analyzer 1154,
and process-side analyzer 1176 comprise machine readable
instructions that when executed by the processor 1102 operate to
perform the functionality associated with each respective analyzer
discussed herein. Each of the fuel analyzer 1148, air analyzer
1150, draft analyzer 1152, emissions analyzer 1154, and
process-side analyzer 1176 may be executed in serial or parallel to
one another.
[0066] The fuel analyzer 1148 operates to compare the fuel data
1110 against one or more fuel alarm thresholds 1156. One common
fuel alarm threshold 1156 includes fuel-pressure threshold that
sets a safe operation under normal operating condition without
causing nuisance shutdowns of the system 100 due to improperly
functioning burner 104 caused by excess or low fuel-pressure. The
fuel alarm thresholds 1156 are typically set during design of the
system 100. The fuel analyzer 1148 may analyze other data within
the sensor database 130 not included in the fuel data 1110, such as
any one or more of air data 1118, heater data 1126, emissions data
1140, process-side data 1170, and any combination thereof to ensure
there is appropriate air to fuel ratio within the heater to achieve
the stoichiometric conditions for appropriate generation of the
thermal energy 112.
[0067] The air analyzer 1150 operates to compare the air data 1118
against one or more air alarm thresholds 1158. One common air alarm
threshold 1158 includes fan operating threshold that sets a safe
operation condition of the forced fan 124 and/or stack fan 122
under normal operating condition without causing nuisance shutdowns
of the system 100 due to improper draft within the heater 102
caused by excess or low air pressure throughout the system 100. The
air alarm thresholds 1158 are typically set during design of the
system 100. The air analyzer 1150 may analyze other data within the
sensor database 130 not included in the air data 1118, such as any
one or more of fuel data 1110, heater data 1126, emissions data
1140, process-side data 1170, and any combination thereof to ensure
there is appropriate air to fuel ratio within the heater to achieve
the stoichiometric conditions for appropriate generation of the
thermal energy 112.
[0068] The draft analyzer 1152 operates to compare the heater data
1126 against one or more draft alarm thresholds 1160. One common
draft alarm threshold 1160 includes heater pressure threshold that
sets safe operation conditions of the heater 102 under normal
operating condition without causing nuisance shutdowns or dangerous
conditions of the system 100 due to positive pressure within the
heater 102 (such as at the arch of the heater 102). The draft alarm
thresholds 1160 are typically set during design of the system 100.
The draft analyzer 1152 may analyze other data within the sensor
database 130 not included in the heater data 1126, such as any one
or more of fuel data 1110, air data 1118, emissions data 1140,
process-side data 1170, and any combination thereof to ensure there
is appropriate operating conditions within the heater 102 to
achieve the stoichiometric conditions for appropriate generation of
the thermal energy 112.
[0069] The emissions analyzer 1154 operates to compare the
emissions data 1140 against one or more emission alarm thresholds
1162. One emissions alarm threshold 1162 include a minimum and
maximum excess oxygen level that sets safe operation conditions of
the heater 102 under normal operating condition without causing
nuisance shutdowns or dangerous conditions of the system 100 due to
too little or too much oxygen within the heater 102 during creation
of the thermal energy 112. Other emission alarm thresholds 1162
include pollution limits set by environmental guidelines associated
with the location in which system 100 is installed. The emission
alarm thresholds 1162 are typically set during design of the system
100. The emissions analyzer 1154 may analyze other data within the
sensor database 130 not included in the emissions data 1140, such
as any one or more of fuel data 1110, air data 1118, heater data
1126, process-side data 1170, and any combination thereof to ensure
there is appropriate operating conditions within the heater 102 to
achieve the stoichiometric conditions for appropriate generation of
the thermal energy 112.
[0070] The process-side analyzer 1176 operates to compare the
process-side data 1170 against one or more process thresholds 1178.
One common process threshold 1178 includes a desired outlet
temperature to achieve efficient process conversion in the process
tubes 106. Another example process threshold 1178 includes a
maximum temperature threshold of the process tube 106 at which the
process tube 106 is unlikely to fail. The process-side analyzer
1176 may analyze other data within the sensor database 130 not
included in the process-side data 1170, such as any one or more of
fuel data 1110, air-data 1118, heater data 1126, emissions data
1140, and any combination thereof to ensure there is appropriate
air to fuel ratio within the heater to achieve the stoichiometric
conditions for appropriate generation of the thermal energy
112.
[0071] The fuel threshold 1156, air threshold 1158, draft threshold
1160, emissions threshold 162 and process threshold 1178, and any
other thresholds discussed herein may differ from system to system.
They may be based on the amount of deviation from an expected value
that an operator is willing to allow. The thresholds discussed
herein may be set based on sensor and other hardware error
tolerances. The thresholds discussed herein may be set based on
regulations allowing certain tolerances for emissions or other
operating conditions. The thresholds discussed herein may be set
according to safety conditions for operating the heater 102.
[0072] The thresholds may also be set based on an uncertainty
associated with calculated or predicted values, such as an
artificial intelligence engine uncertainty. In such embodiments,
the systems and methods herein may accommodate error ranges to
provide a confidence region around the output of an expected value
that is then compared to sensed values to trigger one or more of
the control signals 1164, alarms 1166 and/or displayed operating
conditions 1168 when the sensed value deviates from the expected
value past one or more of the fuel threshold 1156, air threshold
1158, draft threshold 1160, emissions threshold 162 and process
threshold 1178. The sensors used to capture sensed data (e.g., the
real-time sensed data and/or historical data of the system) may not
be entirely accurate resulting in a sensor-based calculation
uncertainty value. The sensor-based calculation uncertainty value
is typically a fixed percentage that can change based on a
calculated value (e.g., sensors are X % efficient when measuring
temperatures across a first range, and Y % efficient across a
second range). Similarly, the artificial intelligence engine may
have an AI uncertainty that varies based on given inputs to the
artificial intelligence engine. The AI engine, for example, models
historical combined data distributions and analyzes statistical
deviations of the current distribution on a scale of 0 to 100%. The
confidence region allows a given prediction by the physics-based
calculations and/or the AI-based engine to accommodate variances in
the associated data. The confidence region may be calculated based
on a predicted value plus or minus an uncertainty value based on
one or both of the sensor-based calculation uncertainty value
and/or the AI-engine uncertainty. The uncertainty value may be, for
example, the sum of the sensor-based calculation uncertainty value
and/or the AI-engine uncertainty. The uncertainty value may be, for
example, the square root of the sensor-based calculation
uncertainty, squared, plus the AI-engine uncertainty, squared. Use
of an uncertainty value when comparing sensed and
expected/predicted/calculated values prevents false identifications
of conditions within the process heater 102 in the system. Use of a
confidence region based on an uncertainty value as discussed above
may apply to any one or more of the "expected", "modeled",
"predicted", "calculated" values or the like discussed in this
application.
[0073] The fuel analyzer 1148, the air analyzer 1150, the draft
analyzer 1152, the emissions analyzer 1154, and the process-side
analyzer 1176 operate to create one or more of control signals
1164, alarms 1166, and displayed operating conditions 1168. The
control signals 1164 include signals transmitted from the process
controller 128 to one or more components of the system 100, such as
the dampers 118, air registers 120 (if electrically controlled),
fans 122, 124, and valves 162. The alarms 1166 include audible,
tactile, and visual alarms that are generated in response to
tripping of one or more of the fuel alarm threshold 1156, air alarm
threshold 1158, draft alarm threshold 1160, and emission alarm
threshold 1162. The displayed operating conditions 1168 include
information that is displayed on the display 1108 regarding the
data within the sensor database 130 and the operating conditions
analyzed by one or more of the fuel analyzer 1148, air analyzer
1150, draft analyzer 1152, emissions analyzer 1154, and
process-side analyzer 1176.
[0074] Referring to FIG. 1, one or more of the fuel analyzer 1148,
the air analyzer 1150, the draft analyzer 1152, the emissions
analyzer 1154 and the process-side analyzer 1176 may be entirely or
partially implemented on an external server 164. The external
server 164 may receive some or all of the data within the sensor
database 130 and implement specific algorithms within each of the
fuel analyzer 1148, the air analyzer 1150, the draft analyzer 1152,
the emissions analyzer 1154 and the process-side analyzer 1176. In
response, the external server 164 may transmit one or more of the
control signals 1164, the alarms 1166, and/or the displayed
operating conditions 1168 back to the process controller 128.
Determination of Airflow Discrepancy in a Combustion System
[0075] When unwanted excess air (also referred to as tramp air)
enters the heater 102, the excess oxygen level sensed by the oxygen
sensor 132 increases. Air is "unwanted" in that it is not expected
during control of the system--all burners are controlled to have at
least some amount of excess air to drive a desired amount of excess
oxygen at the stack while maintaining safe and stoichiometric
conditions for combustion. Conversely, the oxygen level sensed by
the oxygen sensor 132 may lower for a variety of reasons such as:
additional fuel entering the system (e.g., via a leak in the
process tubes 106 causing excess material to enter the heater
housing 102); when a burner air register is not moving when
actuated; when something--e.g., debris, insulation, etc.--is
blocking the air input at one or more burners 104, ambient air
inlet blocked via insects and/or birds' nests, heater insulation
falling into the burner 104 throat, etc.).
[0076] FIGS. 12-16 depict various operating conditions result in
sensed oxygen readings by the oxygen sensor 132 that cause
incorrect control of the input fuel/air ratio to the burner 104, in
examples. FIG. 12 shows a tile 1202 fallen from the interior of the
housing and blocking air input to a burner. FIG. 13 depicts one
pin-hole that causes excess fuel to enter into the system for
example as shown in the infrared image of FIG. 14. FIG. 15 shows a
blown-open process tube 1502 causing significant release of fuel
into the system as shown in FIG. 16. The polished look 1504 of the
tubes adjacent the failed process tube 1502 in FIG. 15 indicates
flame impingement causing inefficient or improper heating
conditions within the process tube, which was likely the cause of
the tube failure.
[0077] Significant excess air within the heater 102 or not enough
air within the heater 102 causes an unbalanced stoichiometric
condition for generating the thermal energy 112, thereby resulting
in unfavorable (and often unsafe) operating conditions. Typically,
the oxygen sensor output is trusted by operations personnel to be
the primary indication that there is sufficient and proper air for
combustion to occur safely. Currently, there are limited options
for ensuring that the measured excess oxygen in the system is
coming through the burners as designed. Visual analysis by a human
operator is frequently required to check for conditions in the
heater that may indicate excess or insufficient air. When there is
excess tramp air in the system, if the operator is unaware and
controlling based on the sensed oxygen levels by the oxygen sensor
132, the operator and/or heater controller 128, often reduces the
input air to the burner because the global oxygen sensor 132
indicates there is too much air. Thus, the flames (e.g., thermal
energy 112) from the burner 104 may extend too far from the burner
104 because the oxygen in the excess tramp air is being used to
burn the extra fuel (because the controlled input fuel/air ratio is
too high). These extended flames cause the process tubes 106 in the
system to heat improperly resulting in inefficient or dangerous
operation. Blocked input air in the system (see FIG. 12), or excess
fuel in the system (see FIGS. 13-16) causes the operator or control
system to increase the air flow through the burners, in attempts to
raise the measured excess O2. In doing so, the burner air fuel
ratio will be unintentionally driven to a fuel lean condition (more
excess air going through the burners than is being measured), which
can result in unstable burners which is also dangerous and/or
inefficient condition.
[0078] FIG. 17 depicts an air analyzer 1700, which is an example of
the air analyzer 1150, of FIG. 11, in an embodiment. Air analyzer
1700 includes an air-flow discrepancy analyzer 1702. Air-flow
discrepancy analyzer 1702 includes computer readable instructions
that when executed by a processor (e.g., processor 1102), operate
to identify air-flow discrepancy and output a remediation action
1704 based on the identified discrepancy.
[0079] In embodiments, to identify air-flow discrepancy, the
air-flow discrepancy analyzer 1702 compares an expected oxygen
level 1706 against a sensed oxygen level 1708. The expected oxygen
level 1706 is determined by the air-flow discrepancy analyzer 1702
by performing physics-based modeling according to the measured
operating parameters 1710 regarding operation within the heater 102
to generate a fired-systems model 1705. The measured operating
parameters 1710 may include the firing rate of each burner 104, and
a measured (e.g., as sensed by an air-flow sensor) or calculated
air flow through each burner 104. The air flow through each burner
may be calculated using the fired-systems model 1705 based on
physics-based modeling that analyzes the operating parameters 1710
such as the draft within the heater 102 to determine a burner
pressure drop, and use this variable in combination with one or
more of the stack damper 118 setting, burner air register 120
setting, stack fan setting 122, forced fan setting 124, fuel
control valve 162 settings, ambient air information etc. to
determine the expected air flow rate through each burner. Using
these expected air flow rates per burner and the measured or
calculated heat release, the air-flow discrepancy analyzer 1702
executes a combustion chemistry calculation to determine what the
expected cumulative oxygen levels would be at the location of the
oxygen sensor 132. Combustion chemistry calculations may include,
but are not limited to, those described in chapter 4 of the "John
Zink Hamworthy Combustion Handbook", which is incorporated by
reference in its entirety (Baukal, Charles E. The John Zink
Hamworthy Combustion Handbook. Fundamentals. 2nd ed., vol. 1 of 3,
CRC Press, 2013).
[0080] The physics modeling used to solve the fired-systems model
1705 may further be based on other information of the system 100
(such as one or more of fuel information 1712, heater geometry
1714, air-flow ductwork geometry 1716, and burner geometry 1718,
weather information 1720, and any combination thereof). The fuel
information 1712 includes the fuel composition that is either
sensed, or inferred as discussed above, and may also include other
information such as expected fuel temperature and other data within
fuel data 1110. The heater geometry 1714 indicates the shape and
dimensions of the heater 102. The heater geometry 1714 (such as the
shape and height) of the heater housing plays an important role in
defining how the draft within the heater will travel through the
heater. This affects how the air will be input and output from the
system through convection influenced by the draft. The heater
geometry 1714 may include process tube geometry defining the
orientation of the process tubes (e.g., tubes 106), as well as
size, shape, etc. such as shown in FIG. 3, above. As discussed
above, the characteristics of the process tubes may influence the
draft in the heater and thus influence the air-flow throughout the
system 100 and available airflow from each burner 104 therein. The
air-flow ductwork geometry 1716 includes the geometry of the
airflow ductwork (e.g., ductwork 151) throughout the system 100.
This includes any air handling register (e.g., air handling
register 152), the air-flow zones, and the geometry of each of the
above. The burner geometry 1718 includes the number, location, and
physical geometry of the burners, the burner zones within the
heater, as well as burner settings for each burner, such as the
controllable range of the burner air register (e.g., burner air
register 120) such as the controllable range shown on indicator
plate 804 in FIG. 8. The weather information 1720 may be received
at the fuel analyzer 1300 from a weather server, or generated on
site using one or more sensors (e.g., precipitation, humidity,
barometric, and/or temperature sensors at the heater 102).
[0081] The fired-systems model 1705 may be for an entire combustion
system (e.g., from the air-input and the fuel-input through the
exit of the stack), or may be for one or more specific components
within a given combustion system (such as one or more of a burner
model, an air ductwork model, a model of draft within the heater, a
model of heat transfer surrounding process tubes, etc.). The
fired-systems model 1705 model may be based on any one or more of
combustion chemistry, combustion kinetics, air and fuel fluid
dynamics, heat transfer, process side modeling, computational fluid
dynamics modeling, and other various types of combustion modeling.
The fired-systems model 1705 may account for various system
constraints and operational characteristics and real-time changes
of the system during use of the system (for example, the burner
tips can develop coke therein that blocks the drilled holes causing
the burners to operate slightly different than designed).
[0082] The sensed oxygen level 1708 may include the 02 reading(s)
1142 sensed by the oxygen sensor(s) 132.
[0083] In embodiments, the sensed oxygen level 1708 includes a
plurality of sensed oxygen levels at a plurality of locations
within the heater 102. For example, the plurality of locations may
include a plurality of heights within the heater 102. As another
example, the plurality of locations may include a plurality of
horizontal locations at a similar height, such as at a plurality of
locations of the radiant section 113 of the heater 102. The
expected oxygen level 1706 is then determined (using the physics
and chemistry based models of the fired-systems model 1705) at each
of the plurality of locations within the heater 102 such that
individual sensed oxygen levels 1708 at each location is compared
by the air-flow discrepancy analyzer 1702 to an expected oxygen
level 1706 corresponding to that location. Analyzing a plurality of
locations accommodates the realization that global oxygen readings
are impacted by a variety of combustion conditions (such as
tramp-air and/or excess fuel entering the heater 102). Thus, a
global oxygen reading may indicate no discrepancy, or indicate a
false or inaccurate discrepancy, where excess oxygen due to an
amount of excess air (tramp-air) entering the heater 102 at one
location is cancelled out, or otherwise compensated for, by
additional fuel entering the heater 102 (and thus burning
additional oxygen) at the same or other location of the heater
102.
[0084] When the sensed oxygen level 1708 is above the expected
oxygen level 1706, the air-flow discrepancy analyzer 1702 generates
an unwanted excess air quantifier 1722 (which may be a part of or
separate from the remediation action 1704). The unwanted excess air
quantifier 1722 is a display of the air leakage based on the delta
between the expected oxygen level 1706 and the sensed oxygen level
1708. The unwanted excess air quantifier 1722 may be in displayed
in mass or volume per time, such as kg/seconds. FIGS. 18 and 19
show example unwanted excess air quantifier 1722, in
embodiments.
[0085] In embodiments, the unwanted excess air quantifier 1722
indicates excess air in terms of leakage area 1724, such as square
inches. This provides the advantage that operators may search for
openings in the heater 102 that match, or approximately match, the
area indicated. The leakage area 1724 may be determined based on
the delta between the expected oxygen level 1706 and the sensed
oxygen level 1708 and the sensed draft within the heater 102 as
identified via in-heater air data 1726 (which is similar to the
heater data 1126 discussed above).
[0086] Indeed, in some embodiments, the air-flow discrepancy
analyzer 1702 compares the identified leakage area 1724 against a
database of known components 1728 of the heater 102, such as
input/output pipes that pass through the wall of the heater 102,
access windows, and other potential leakage points of the heater
102. Accordingly, the unwanted excess air quantifier 1722 (and/or
the remediation action 1704) may define a list of potential
components 1730 of the known components 1728 that match, or match
within an area-threshold 1732, the leakage area 1724. If no known
components 1728 match, the unwanted excess air quantifier 1722
(and/or the remediation action 1704) indicates the identified
leakage area 1724 such that an operator may perform a manual scan
to identify potential holes in the heater 102 matching said
area.
[0087] In embodiments, the unwanted excess air quantifier 1722
indicates an approximate location of the leak based on a
correlation of the height at which the sensed oxygen level 1708
becomes above the expected oxygen level 1706. As discussed above,
in certain embodiments, the oxygen level is sensed at a plurality
of heights. Because the draft within the heater 102 creates a flow
of air, excess air entering the heater 102 may not cause the sensed
oxygen level 1708 to differ substantially from the expected oxygen
level 1706 below the location of the leak.
[0088] In certain embodiments, the air-flow discrepancy analyzer
1702 may identify location of the tramp-air leak based on an
optical scan data 1734 to further to pinpoint the cause of such
discrepancy. In embodiments, the optical scan data 1734 includes
data captured by one or more of the TDLAS devices 147, discussed
above. Additionally, or alternatively, the optical scan data 1734
may include a visual, infrared, and/or ultraviolet wavelength data
captured by one or more cameras within the heater 102. Knowledge of
the field of view, or scanning path, of the optical device used to
generate the optical scan data 1734 allows the air-flow discrepancy
analyzer 1702 to correlate the field of view, or scanning path, to
a specific location within the heater 102 and therefore provide the
remediation action 1704 accordingly. The optical scan data 1734 may
indicate tramp-air leak because the temperature is lower in the
heater 102 at the location of the tramp-air leak.
[0089] In certain embodiments, when the sensed oxygen level 1708 is
below the expected oxygen level 1706, the air-flow discrepancy
analyzer 1702 may analyze the optical scan data 1734 to further to
pinpoint the cause of such discrepancy. Knowledge of the field of
view, or scanning path, of the optical device used to generate the
optical scan data 1734 allows the air-flow discrepancy analyzer
1702 to correlate the field of view, or scanning path, to a
specific location within the heater 102 and therefore provide the
remediation action 1704 accordingly. The optical scan data 1734 may
indicate a process tube 106 leak if there are flames exiting one of
the process tubes 106, shown in FIGS. 14 and 16. The optical scan
data 1734 may indicate a blocked burner 104 if there is a dark spot
over a burner 104 that should be firing, or a bright spot adjacent
a burner 104 indicating a burning or hot piece of insulation or
tile adjacent the burner, such as shown in FIG. 12. If, after
analysis of the optical scan data 1734, there is no indication of a
faulty burner 104 or process tube 106 leak, the remediation action
1704 may instruct the operator to analyze the inlet of ambient air
to check for blocked air inlet. In embodiments, instead of an
optical scan, the air-flow discrepancy analyzer 1702 analyzes one
or more temperature sensors (e.g., thermocouples located on one or
more of the process tubes 106) to correlate the location of a
punctured process tube 106 or other inlet of fuel other than that
intended by the control scheme of the system.
[0090] In embodiments, the air-flow discrepancy analyzer 1702
indicates an approximate location of a punctured process tube 106
based on a correlation of the height at which the sensed oxygen
level 1708 becomes below the expected oxygen level 1706. As
discussed above, in certain embodiments, the oxygen level is sensed
at a plurality of heights. Because the draft within the heater 102
creates a flow of air, the punctured process tube 106 may not cause
the sensed oxygen level 1708 to differ substantially from the
expected oxygen level 1706 below the location of the punctured
process tube 106.
[0091] In embodiments, the remediation action 1704 includes a
safety control signal 1736 that changes operation of the system 100
to prevent further dangerous or inefficient operating conditions
within the heater 102. For example, the control signal 1736 may
alter the air/fuel ratio being supplied to one or more burners 104
by controlling the fuel control valve(s) 162. In some cases, for
example, the tramp air indication may suddenly increase, and the
controller may require operator approval before reducing the air
flow in the firebox to allow time for operations to investigate the
source of the rising tramp air indication. As another example, the
control signal 1736 may alter the air/fuel ratio being supplied to
one or more of the burners 104 by controlling the stack fan 122,
forced fan 124, the stack damper 118, the air register 120
(automatically if capable, or via an instruction to manually change
the air-register stetting), or a combination thereof.
[0092] In embodiments, the air-flow discrepancy analyzer 1702 does
not generate the remediation action 1704 unless the sensed oxygen
level 1708 is above or below the expected oxygen level 1706 by a
delta that meets or exceeds a discrepancy threshold 1738. The
discrepancy threshold 1738 allows an operator to control the
tolerance of tramp-air within the system before the air-flow
discrepancy analyzer 1702 generates the remediation action 1704.
Furthermore, there may be distinct discrepancy thresholds 1738 for
a positive delta (indicating excess air in the heater 102) and a
negative delta (indicating insufficient air in the heater 102, or
excess fuel in the heater 102). Insufficient air in the heater 102
may present a more dangerous condition, and thus the discrepancy
threshold 1738 for a negative delta needs to be a tighter threshold
to prevent catastrophic failures.
[0093] In embodiments, the air-flow discrepancy analyzer 1702 is
executed after the heater controller 128 verifies the fuel-side of
the system 100. In other words, the heater controller 128 may
execute computer readable instructions that analyze the fuel data
1110 sensed against expected fuel data to verify no inconsistencies
within the system 100. If no (or nominal) fuel inconsistencies
exist, and the oxygen levels are not as expected, as discussed
above, this condition indicates that the output remediation action
1704 is associated with an air-flow discrepancy, even if the
specific air-flow discrepancy cannot be pinpointed via the optical
scan discussed above (or some other in-heater sensed
condition).
[0094] Additionally, the characterized and expected emissions data
may be compared to the measured emissions data to provide further
data necessary to point operators towards the likely root cause of
the variation in tramp air indications. Furthermore, additional
troubleshooting may be performed to verify the root cause of the
tramp air. For example, historical data such as maintenance records
may be utilized to identify potential areas of tramp-air leakage,
or blocked airways.
[0095] Any portion of the heater controller 128, including the air
analyzer 1700 of FIG. 17 may be implemented using an edge computing
scheme. For example, the air analyzer 1700 may be located at the
external server 164, and data (such as the measured operating
parameter 1710, fuel information 1712, heater geometry 1714,
air-flow ductwork geometry 1716, burner geometry 1718, weather
information 1720, in-heater air data 1726, known heater components
1729, area threshold 1732, optical scan data 1734, sensed oxygen
level 1708, or any combination thereof may be transmitted from the
heater controller 128 (or another device) to the external server
164. This allows the fired-systems model 1705 to remain on the
external server 164 for analysis thereon. The remediation action
1704 may then be transmitted from the external server 164 to the
heater controller 128.
[0096] FIG. 20 depicts a method 2000 for determining air-flow
discrepancy in a combustion system, in embodiments. Method 2000 is
implemented in the air-flow discrepancy analyzer 1702 discussed
above, for example. In certain embodiments, method 2000 is
implemented after verification of the fuel-side of the system
associated with the method.
[0097] In block 2002, the method 2000 senses oxygen level inside
the process heater. In one example of block 2002, the sensed oxygen
level 1708 is captured by the oxygen sensor 132 and transmitted to,
and received by, the heater controller 128. In certain embodiments
of block 2002, the method senses the oxygen level inside the
process heater at a plurality of locations. For example, the
plurality of locations may include a plurality of heights within
the heater 102. As another example, the plurality of locations may
include a plurality of horizontal locations at a similar height,
such as at a plurality of locations of the radiant section 113 of
the heater 102.
[0098] In block 2004, the method 2000 calculates the expected
oxygen level correlating to the location of the sensed oxygen
level. In one example of block 2004, the air-flow discrepancy
analyzer 1702 performs physics-based modeling according to the
measured operating parameters 1710 of the heater 102 to calculate
the expected oxygen level 1706 thereby determine what the expected
oxygen levels are at the location of the oxygen sensor 132. If
block 2002 includes sensing oxygen levels at a plurality of
locations, then block 2004 also includes determining expected
oxygen level 1706 at corresponding plurality of locations.
[0099] In blocks 2006 and 2008, respectively, the method 2000 then
determines if the sensed oxygen level from block 2002 is greater
than or less than the expected oxygen level calculated in block
2004. In one example of block 2006, the air-flow discrepancy
analyzer 1702 determines if the sensed oxygen level 1708 is greater
than the expected oxygen level 1706 (at a single location, or at a
plurality of locations). In one example of block 2008, the air-flow
discrepancy analyzer 1702 determines if the sensed oxygen level
1708 is less than the expected oxygen level 1706 (at a single
location, or at a plurality of locations).
[0100] If, at block 2006, the sensed oxygen level is greater than
the expected oxygen level, method 2000 proceeds with block 2010.
Else, method 2000 repeats block 2002.
[0101] At block 2010, the method 2000 displays an excess air
indicator including the delta between the sensed oxygen level of
block 2002 and the expected oxygen level at block 2004. In an
example of block 2010, the air-flow discrepancy analyzer 1702
displays the unwanted excess air quantifier 1722 on the heater
controller 128, or another device such as an operator mobile
device, computer, or other electronic device. The displayed excess
air indicator of block 2010 may be in kg/s.
[0102] In certain embodiments, method 2000 includes blocks 2012
which is a decision in which method 2000 determines if the sensed
oxygen level is above the expected oxygen level beyond a
discrepancy threshold. In one example of block 2012, the air-flow
discrepancy analyzer 1702 determines if the sensed oxygen level
1708 is above the expected oxygen level 1706 by a delta that meets
or exceeds a discrepancy threshold 1738.
[0103] In certain embodiments, the block 2010 includes sub-blocks
that determine and analyze a leakage area of the discrepancy in
air-flow. In block 2014, the method 2000 identifies a leakage area
based on the delta between the sensed oxygen level and the expected
oxygen level. In one example of block 2014, the air-flow
discrepancy analyzer 1702 determines the leakage area 1724 based on
the delta between the expected oxygen level 1706 and the sensed
oxygen level 1708 and the sensed draft within the heater 102 as
identified via in-heater air data 1726 (which is similar to the
heater data 1126 discussed above).
[0104] In block 2016, the method 2000 displays the leakage area
determined in block 2014. In one example of block 2016, the
air-flow discrepancy analyzer 1702 displays the leakage area 1724
on the heater controller 128, or another device such as an operator
mobile device, computer, or other electronic device.
[0105] In certain embodiments, the method 2000 further includes
blocks 2018-2024. In block 2018, the method 2000 compares the
leakage area to known components of the process heater. In one
example of block 2018, the air-flow discrepancy analyzer 1702
compares the leakage area 1724 to known heater components 1728.
[0106] In block 2020, the method 2000 determines if there is a
match between the leakage area and known components of the process
heater. If so, method 2000 proceeds with block 2022, else method
proceeds with block 2024.
[0107] In block 2022, the method 2000 outputs a remediation action
including known component(s) that match the leakage area. In one
example of block 2018, the air-flow discrepancy analyzer 1702
outputs the remediation action 1704 including the potential leak
components 1730.
[0108] In block 2024, the method 2000 outputs the remediation
action including one or more of the leakage area (similar to block
2016), and/or identification of the oxygen sensor (e.g., oxygen
sensor 132) corresponding to the location at which the sensed
oxygen level exceeded the expected oxygen level. Identifying the
oxygen sensor allows the operator to determine whether the oxygen
sensor needs to be calibrated (or is otherwise "drifting" from
appropriate readings).
[0109] If, at block 2008, the sensed oxygen level is less than the
expected oxygen level, method 2000 proceeds with block 2026. Else,
method 2000 repeats block 2002.
[0110] In block 2026, the method analyzes in-heater data to narrow
the location of the air-flow discrepancy. In one example of block
2026, the air-flow discrepancy analyzer 1702 analyzes optical scan
data 1734 and/or other temperature data within the heater 102 (such
as thermocouples or TDLAS measurements located at one or more
positions within the heater, including at locations on the process
tubes 106).
[0111] At block 2028, the method 2000 determines if the cause of
the discrepancy can be pinpointed. If yes, method 2000 proceeds
with block 2030, else method 2000 proceeds with block 2032. In one
example of block 2028, the air-flow discrepancy analyzer 1702 uses
knowledge of the field of view, or scanning path, of the optical
device used to generate the optical scan data 1734 thereby allowing
the air-flow discrepancy analyzer 1702 to correlate the field of
view, or scanning path, to a specific location within the heater
102 and therefore provide the remediation action 1704 accordingly.
The optical scan data 1734 may indicate a process tube 106 leak if
there are flames exiting one of the process tubes 106, shown in
FIGS. 14 and 16. The optical scan data 1734 may indicate a blocked
burner 104 if there is a dark spot over a burner 104 that should be
firing, or a bright spot adjacent a burner 104 indicating a burning
or hot piece of insulation or tile adjacent the burner, such as
shown in FIG. 12.
[0112] At block 2030, the method 2000 outputs a remediation action
including the location of the air discrepancy. In one example of
block 2028, the air-flow discrepancy analyzer 1702 outputs the
remediation action 1704 including the location corresponding to the
field of view, or scanning path, of the optical device used to
generate the optical scan data 1734.
[0113] At block 2032, the method 2000 outputs a remediation action
including identification of the oxygen sensor and/or an intake
signal. In one example of block 2032, the air-flow discrepancy
analyzer 1702 outputs the remediation action 1704 including (e.g.,
oxygen sensor 132) corresponding to the location at which the
sensed oxygen level exceeded the expected oxygen level and/or an
intake signal instructing the heater operator to manually inspect
the air intake for birds' nests, bugs, or other obstructions.
Identifying the oxygen sensor allows the operator to determine
whether the oxygen sensor needs to be calibrated (or is otherwise
"drifting" from appropriate readings).
[0114] At any time during method 2000, the method 2000 may execute
block 2034 and determine if the sensed oxygen level(s) are at a
dangerous condition. If so, method 2000 executes block 2006 and
outputs a remediation action including a safety control signal. In
one example of block 2034, the air-flow discrepancy analyzer 1702
determines if the sensed oxygen level 1708 is at dangerous levels,
such as if there is insufficient airflow, or too much airflow, that
could cause a stoichiometric unbalance resulting in a catastrophic
failure. In one example of block 2036, the air-flow discrepancy
analyzer 1702 outputs the remediation 1704 including control signal
1736.
Determination of Airflow Discrepancy in a Combustion System:
[0115] It should be appreciated that other discrepancies may be
detected by the systems and methods described herein. For example,
FIG. 21 depicts an example of clogged fins on process tubes. These
clogged fins will greatly impact the draft through the heater 102,
and thus the sensed data will not be consistent with the expected
data. As such, in embodiments, output remediation will indicate
incorrect draft in the heater, and/or identify the location of the
draft discrepancy, recommend maintenance thereon, and/or implement
a control signal (e.g., control signal 1164) to automatically
remedy the clog. If the clogged fins cause unsafe conditions, an
alert (e.g., alarm 1166, or displayed operating condition 1168)
1250 may include a remediation action that shuts down the system
for safety concerns.
[0116] FIG. 22 depicts an example draft analyzer (e.g., draft
analyzer 1152 of FIG. 11), including draft discrepancy identifier
2202, in embodiments. Draft discrepancy identifier 2202 includes
computer readable instructions that when executed by a processor
(e.g., processor 1102), operate to generate one or more of
remediation action 2204, which may include an alert 2206, control
signal 2208, and/or displayed operating condition 2210, and any
combination thereof. Alert 2206 is an example of alarm 1166 of FIG.
11. Control signal 2208 is an example of control signal 1164 of
FIG. 11. Displayed operating condition 2210 is an example of
displayed operating condition 1168 of FIG. 11.
[0117] FIGS. 23-28 depict graphs indicating heater operation over
time when the fins of process tubes become clogged due to harsh
conditions in the heater, in an embodiment. FIG. 29 depicts data
table represented by the graphs of FIGS. 23-28. Conventionally, an
operator is unaware of the clogging of process tube fins that
results in an improper draft within the heater (e.g., heater 102).
As previously illustrated, convection fouling is a build-up of
debris on the tubes and extended surfaces in the convection. This
causes an increase in thermal resistance reducing the heat
transferred to the process and increased flue gas side pressure
drop. Convection fouling causes a decrease in efficiency.
Conventionally, the operator does not have enough insight into the
heater operation to be fully aware of what is causing this decrease
in efficiency. The operator is unable to visually see the fin
clogging unless the is continuously viewing through a viewport of
the heater 102, which is unrealistic. Because of this, the heater
is typically controlled to fire at a higher rate forcing more duty
to be absorbed in the radiant section. The overall absorbed
duty/coil outlet temperature must be maintained to allow for proper
process of the material in the process tubes. Increased thermal
resistance can be seen as a decrease in coil crossover temperature
(if available), increase in firing rates, increase in bridgewall
temperature, and an increase in stack temperature. Along with
increased thermal resistance, this fouling forces the flue gas
across a decreasing cross-sectional area along its flow path. This
throttling effect increases the flue gas side pressure drop across
the convection. This can be seen with an increase in open
percentage of the stack damper to compensate and maintain the draft
pressure at the bridge wall.
[0118] The analyzers discussed above, such as the draft discrepancy
identifier 2202, may be configured to recognize discrepancies in
the required draft throughout the heater 102. Draft discrepancy
identifier 2202 utilizes a fired-systems model 2205 to calculate
expected values of draft throughout the heater 102 at any given
time. The fired-systems model 2205 is similar to the fired-systems
model 1705 discussed above with respect to FIG. 17. Comparison of
these expected values defined by the fired systems model 2205 to
real-time sensed data 2212 allows the draft discrepancy identifier
2202 to automatically detect and diagnose anomalies in the draft
within the heater 102, such as convection fouling (e.g., clogging
of the fins/heat sinks of process tubes 106). In FIGS. 23-29, it is
seen that during time slot 1 (start of run "SOR"), the heater 102
is operating as expected, where the modeled convection section dP
(e.g., expected draft within the heater 102 as defined by the
fired-systems model 2205) matches the sensed convection section dP
(e.g., sensed draft data 2212). However, as time passes, the
modeled convection section dP defined by the fired-systems model
2205 begins to deviate from the sensed convection section dP. At a
certain point, the delta between the measured and modeled
convection section dP may become greater than a predetermined
discrepancy threshold 2214, at which the draft discrepancy
identifier 2202 may generate the remediation action 2204. The
modeled convection section dP may include a confidence region based
on an uncertainty value as discussed above.
[0119] In certain embodiments, when the modeled convection section
dP differs from the sensed convection section dP greater than the
discrepancy threshold 2214, the draft discrepancy identifier 2202
may control a device (e.g., the TDLAS scanner 147, or an optical
scanner) within the heater 102 to obtain optical scan data 2217
(similar to optical scan data 1734 discussed above) to further to
pinpoint the cause of such discrepancy. Knowledge of the field of
view, or scanning path, of the optical device used to generate the
optical scan data 2217 allows the draft discrepancy analyzer 2202
to correlate the field of view, or scanning path, to a specific
location within the heater 102 and therefore provide the
remediation action 2204 accordingly. The optical scan data 2217 may
indicate tube clogging at a specific height or other location
within the heater 102 that causes certain of the process tubes 106
to operate in a different manner than others because the clogging
of the fins on those tubes does not allow for designed convection
at the location of those tubes. If, after analysis of the optical
scan data 2217, there is no indication of process tube clogging,
the remediation action 2204 may include the alert 2206, or
displayed operating condition 2210, that instructs the operator to
physically view the location of the draft discrepancy to check for
other obstructions at the location of the draft (e.g., fallen
refractory tiles at the process tubes 106 at the location of the
draft discrepancy). In embodiments, instead of an optical scan, the
draft discrepancy identifier 2202 analyzes one or more temperature
sensors (e.g., thermocouples located on one or more of the process
tubes 106) to correlate the location of a clogged fins on one or
more process tube 106.
[0120] In embodiments, the remediation action 2204 includes a
safety control signal 2208 that changes operation of the system 100
to prevent further dangerous or inefficient operating conditions
within the heater 102. For example, the control signal 2208 may
alter the air/fuel ratio being supplied to one or more burners 104
by controlling the fuel control valve(s) 162. As another example,
the control signal 1736 may alter the air/fuel ratio being supplied
to one or more of the burners 104 by controlling the stack fan 122,
forced fan 124, the stack damper 118, the air register 120
(automatically if capable, or via an instruction to manually change
the air-register stetting), or a combination thereof.
[0121] In embodiments, the draft discrepancy identifier 2202 does
not generate the remediation action 2204 unless the delta between
modeled convection section dP and the sensed convection section dP
meets or exceeds the discrepancy threshold 2214. Controllability by
the operator of the discrepancy threshold 2214 allows an operator
to control the tolerance of the process tube 106 fin clogging
within the system before the draft discrepancy identifier 2202
generates the remediation action 2204. Furthermore, there may be
distinct discrepancy thresholds 2214 for a positive delta
(indicating a higher sensed draft as compared to measured draft in
the heater 102) and a negative delta (indicating lower sensed draft
as compared to measured draft in the heater 102). Insufficient
draft in the heater 102 may present a more dangerous condition or
inefficient operation of the heater 102 to process the material
within the process tubes 106, and thus the variable discrepancy
threshold 2214 allows the operator to control efficiency thresholds
for operating the system 100.
[0122] In embodiments, the draft discrepancy identifier 2202 is
executed after the heater controller 128 verifies the fuel-side of
the system 100. In other words, the heater controller 128 may
execute computer readable instructions that analyze the fuel data
1110 sensed against expected fuel data to verify no inconsistencies
within the system 100. If no (or nominal) fuel inconsistencies
exist, and other aspects of the fuel-side of the system 100 are
normal, but the sensed draft data 2212 are not as expected, as
discussed above, this condition indicates that the output
remediation action 2204 is associated with a draft discrepancy,
even if the specific draft discrepancy cannot be pinpointed via the
optical scan discussed above (or some other in-heater sensed
condition).
[0123] Additionally, the characterized and expected emissions data
(which may or may not include a confidence region based on an
uncertainty value as discussed above) may be compared to the
measured emissions data to provide further data necessary to point
operators towards the likely root cause of the variation in
draft.
[0124] Furthermore, additional troubleshooting may be performed to
verify the root cause of the draft discrepancy. For example,
historical data 2216 such as maintenance records may be utilized to
identify potential areas fin clogging on the process tubes 106. As
another example, the draft discrepancy identifier 2202 may compare
other sensed data, such as one or more of: absorbed duty 2218
(defining the amount of duty absorbed by the process tubes 106);
current firing rate 2220 (defining firing rate of all burners 104
in the system 100); heater efficiency 2222; bridge wall temperature
2224 (defining temperature as sensed by an optical scanner,
thermocouple, or laser scanner); tube metal temperatures 2226
(defining temperatures of the process tubes 106); stack temperature
2228; air handling settings 2230 (defining positions of the burner
dampers, stack dampers, and any other fans that control airflow
within the heater 102; and process tube pressure drop 2232
(defining pressure in the process tubes 106)) to determine if those
are in an expected range. Depending on which of these variables is
within or out of expected range, the draft discrepancy identifier
2202 is able to pinpoint the cause of the discrepancy.
[0125] The draft discrepancy identifier 2202 provides insight that
operators conventionally previously did not have. Operators were
typically unaware of what the convection section dP should be.
Instead, operators had to manually visually inspect process tubes
106 to determine if the process tubes 106 were clogged. In
contrast, the present system and methods are capable of flagging an
anomaly when the heater's efficiency is lower than what it
historically was (e.g., via monitoring the varying heater
efficiency over time as shown in FIGS. 23-29) for the current
process conditions (absorbed duty, inlet temperature, outlet
temperature, etc.) and raise some questions. The present system is
able to determine that the problem is not internal fouling (coking)
occurring in the radiant tubes because the process pressure drop
and tube metal temperatures are within the expected range. The
present system is able to determine that the problem is convection
fouling because, for the current firing rate there is an increase
in bridge wall temperature, stack temperature, and the air handling
settings is more open than expected as indicated by the
fired-systems model 1204.
[0126] The above discussed anomaly detection may occur in either
methods 2400 or 2600 during operation of the heater in blocks 2422
and 2618, respectively. Furthermore, the above discussed anomaly
detection may be performed by other "analyzers" described herein,
such as the fuel analyzer 1148, the draft analyzer 1152, the
emissions analyzer 1154, and the process-side analyzer 1176. Each
of these analyzers may operate to detect different anomalies, as
well.
[0127] Furthermore, the above discussed discrepancy detection may
be performed by other "analyzers" described herein, such as the
fuel analyzer 1148, the draft analyzer 1152, the emissions analyzer
1154, and the process-side analyzer 1176. Each of these analyzers
may operate to detect different discrepancies, as well.
[0128] Any portion of the heater controller 128, including the
draft analyzer 2200 of FIG. 22 may be implemented using an edge
computing scheme. For example, the draft analyzer 2200 may be
located at the external server 164, and data (such as the sensed
draft data 2212, historical data 2216, absorbed duty 2218, current
firing rate 2220, heater efficiency 2222; bridge wall temperature
2224, tube metal temperatures 2226, stack temperature 2228; air
handling settings 2230, and process tube pressure drop 2232, or any
combination thereof may be transmitted from the heater controller
128 (or another device) to the external server 164. This allows the
fired-systems model 2205 to remain on the external server 164 for
analysis thereon. The remediation action 2204 may then be
transmitted from the external server 164 to the heater controller
128.
Determination of Burner/Fuel Discrepancy in a Combustion System
[0129] The present disclosure acknowledges that, as heaters operate
over time, the burner tips begin to foul (plug up from debris or
coking) and the fuel pressure going through that burner tip
increases to maintain a constant fuel flow rate (firing rate) so
that a cumulative desired process outlet temperature is maintained.
As some burners gas tips begin to foul and gas pressure increases,
the unfouled burner gas tips will also experience an increase in
gas pressure and flow. This causes a maldistribution of fuel gas
within the burner array, causing heat maldistribution within the
firebox. This ultimately results in inefficiency caused by the
non-uniform heat transfer to the process tubes. Additionally,
non-uniform gas tip plugging will cause a maldistribution of air to
fuel ratio per burner that can be a significant safety concern.
When a burners gas tips get too plugged, the burner must be shut
down for cleaning maintenance. In most cases, tip plugging is
identified by visual observation. Because of this, the heater may
be running for long periods of time with significant process
heating maldistribution and inefficiency, costing the operator
significant profit losses.
[0130] FIG. 30 depicts two images of an array of burners installed
into a heater with some burners that have plugged burner tips and
all burners with clean burner tips. The image on the left depicts
some burners that are plugged and thus not firing correctly. The
wall of the heater has significant dark spots in various locations
down the length of the heater causing inconsistent heating
throughout the heater. The image on the right depicts burners
operating after a cleaning process. It is apparent that the heater
wall is being evenly heated, the combustion is occurring as
designed, and that the process tubes have an improved uniformity in
duty per burner.
[0131] FIG. 31 depicts a burner having a burner tip that has
completely failed, in an example. The burner tip has entirely
burned off, and a large amount of gas flow is entering the furnace
completely asymmetrically compared to the original design of the
burner.
[0132] FIG. 32 depicts a fuel analyzer 3200, which is an example of
the fuel analyzer 1148, of FIG. 11, in an embodiment. Fuel analyzer
3200 (or another one of the analyzers shown in FIG. 11) includes a
burner tip monitor 3202. Burner tip monitor 3202 includes computer
readable instructions that when executed by a processor (e.g.,
processor 1102), operate to generate a burner tip health indication
3204.
[0133] The burner tip monitor 3202 executes a fired-systems model
3206 on the burner (e.g., burner 104) to determine a calculated
burner heat release 3208 assuming clean burner tips. The
fired-systems model 3206 model may be based on any one or more of
combustion chemistry, combustion kinetics, air and fuel fluid
dynamics, heat transfer, process side modeling, computational fluid
dynamics modeling, and other various types of combustion modeling.
For example, the fired-systems model 3206 may be based on a
measured firing rate 3210, the fuel information 3212, and the
burner geometry 3214. The measured firing rate 3210 indicates the
rate at which all burners 104 is to be operated as controlled by
the heater controller 128. The fuel information 3212 includes the
fuel composition that is either sensed, or inferred as discussed
above, and may also include other information such as expected fuel
temperature and other data within fuel data 1110. The burner
geometry 3214 includes the design characteristics (such as the
burner tip orifice size, and the number of orifices on the burner
tip) of the burner 104 that determine the fuel pressure drop
through the burner.
[0134] In certain embodiments, the fired-systems model 3206 is
based on additional information, such as one or more of the fuel
supply line geometry 3216. Many process heaters do not include fuel
control valves 162 at each individual burner. Instead, a single
fuel control valve 162 may control the fuel flow to the entire
heater, or multiple fuel control valves 162 may each control
individual zones of the heater, each zone having a plurality of
burners therein. Therefore, by analyzing the fuel supply line
geometry 3216, the burner tip monitor 3202 performs modeling of the
fuel flow through the fuel supply line(s) 160, and as a result
accurately calculates the heat release for all burners based on a
single fuel input. Without knowledge of the fuel supply line
geometry 3216, the burner tip monitor 3202 may not have accurate
prediction of fuel pressure at each burner due to pressure
deviations occurring at directional changes in the supply line(s)
160, or at the fuel control valve(s) 162.
[0135] After determination of the calculated burner heat release
3208, the burner tip monitor 3202 may compare the calculated heat
release 3208 against a real-time measured heat release 3218. To
generate the real-time measured heat release 3218, the burner tip
monitor 3202 may analyze real-time sensed fuel data 3220. In
embodiments, the real-time sensed fuel data 3220 includes the fuel
pressure data 1116. In embodiments, the real-time sensed fuel data
3220 additionally includes the fuel temperature data 1114.
[0136] FIG. 33 depicts a comparison of a calculated heat release
3208 to a measured heat release 3218. The real-time measured heat
release 3218 is significantly lower than the calculated heat
release 3208. FIG. 34 depicts an example burner tip health
indication 3204 in the form of a graph 3400 depicting the ratio
3402 of the measured heat release 3218 to the calculated heat
release 3208. In embodiments, the burner tip monitor 3202 may
monitor this ratio of the burner tip health indication 3204 against
a burner tip health threshold 3222. The burner tip health threshold
3222 may be a delta, or range of delta, of the ratio. For example,
any ratio that is less than 1, within a delta of .about.0.03, may
indicate some tip plugging or system plugging (pipe supply) is
occurring. It could also mean one of the instruments used in these
measurements or calculations is drifting as discussed in further
detail below.
[0137] Moreover, the burner tip health threshold 3222 may
alternatively or additionally include a threshold level that
defines a burner tip burn-off (such as shown in FIG. 31). If the
ratio of measured heat release 3218 to the calculated heat release
3208, as defined in the burner tip health indication 3204, is above
1, it indicates that the burner is releasing more heat than
expected and thus a burnt-off tip, or that there is a potential gas
leak downstream of the measurement devices. For example, any ratio
greater than one, within a delta of .about.0.03 may indicate a
burnt-off tip or potential gas leak downstream of the measurement
devices. The "ratio of measured heat release 3218 may be based on
expected uncertainty that can be attributed to, for example, the
manufacturers published measurement uncertainty of each measurement
device, and tolerances of the burner geometry and then set based on
the operational goals of the facility. Thus, the delta, although
described herein as 0.03, may be a dynamic number that is definable
so as to not alarm unless necessary.
[0138] Various burner alarms 3224 may be generated depending on
which burner tip health threshold 3222 is breached by the burner
tip health indication 3204, and each alarm may be an visual (e.g.,
displayed as displayed operating conditions 1168 of FIG. 11,
above), audio and/or tactile alarm (e.g., alarm 1166 of FIG. 11,
above).
[0139] Trends in this ratio may be used by the burner tip monitor
3202 to predict when maintenance on the burner tip is necessary and
generate a burner tip maintenance schedule 3226. For example,
historic statistical trends of the ratio 3402 may be analyzed by
the burner tip monitor 3202 to determine the expected time at which
the burner tip health indication 3204 will breach one or more of
the burner tip health threshold 3222. The burner tip monitor 3202
may then output the maintenance schedule 3226 defining when the
burner tip should be cleaned or replaced. This provides the
advantage that the system operator may control when shutdowns occur
and how long to space out maintenance shutdowns. Additionally,
operators resort to "scheduled maintenance" for cleaning burner gas
tips. When this is the case, they may spend countless hours
cleaning perfectly well performing gas tips, and may accidently
cause premature enlarging of the gas tip holes by cleaning them too
frequently. They are typically cleaned with high pressure steam or
by mechanically running a drill bit of the correct diameter, by
hand, in and out of the gas ports. So if the wrong drill bit
diameter is used for cleaning, or if the person cleaning the tips
uses a drill with the bit instead of cleaning the port by hand, it
can bore the hole out beyond its intended tolerances.
[0140] In embodiments, prior to generating one or more burner
alarms 3224, the burner tip monitor 3202 may verify the tip
malfunction. There may be a variety of reasons besides burner tip
plugging or burn-off that cause the ratio of the burner tip health
indication 3204 to breach a burner tip threshold 3222. For example,
the pressure sensor obtaining the real-time sensed fuel data 3220
may be malfunctioning and thus the sensed data may deviate from
actual conditions. Thus, the burner tip monitor 3202 may further
analyze oxygen data 3228 from the oxygen sensor 132 to determine if
the oxygen readings are as expected. If the fuel is not being
injected to through the burner tip because of tip plugging, then
the air/fuel ratio will be higher because not as much fuel is being
injected into the heater as expected. Thus, the excess oxygen
levels sensed by the oxygen sensor 132 will be greater because not
all of the air being input into the heater is being consumed to
produce the thermal energy 112. Further, if the burner tip monitor
3202 has verified that there is no additional tramp air (e.g., via
the discussion of FIGS. 12-20, above), or has accounted for an
estimated amount of tramp air, then the burner tip monitor 3202 is
able to verify the ratio in the burner tip health indication 3204
utilizing the sensed excess oxygen data 3228.
[0141] While the most accurate method for monitoring real-time
sensed fuel data 3220 at each given burner would be to include a
fuel flow measurement sensor at each burner, this is simply not
cost effective. Most process heaters do not include a fuel flow
measurement sensor (e.g., mass flow sensor 154(3)) measuring
pressure at that specific burner. Instead, often, a fuel flow
sensor, such as only mass flow sensor 154(2), is included that
measures fuel pressure to the entire heater. Thus, in embodiments,
the burner tip monitor 3202 may further analyze in-heater data 3230
to determine the specific burner that is malfunctioning. For
example, as discussed above, a plurality of TDLAS monitoring
systems may be located within the heater 102. These may be used to
detect the temperature of the heater at specific locations.
Further, as shown in FIG. 30, on the left image, the burner tip
malfunction may cause inconsistent heating, where the dark spots
indicate cooler areas of the heater than expected. Thus, the TDLAS
systems may generate in-heater data 3230 that is able to identify
these cool spots. Based on the cool spots, the burner tip monitor
3202 is able to specify which burner, or plurality of burners, have
burner tips that are plugged. Other systems and sensors may
generate the in-heater data 3230, such as imaging systems (visual
and infrared), in-heater temperature sensors, etc. Where the burner
tip monitor 3202 is able to identify the specific burner that is
malfunctioning, the burner tip health indication 3204 may include
an identification of said specific burner.
[0142] Some "cool spots" may be completely expected within the
firebox even with complete clean burner gas tips due to the complex
flue gas aerodynamics that occur within the firebox. In this case,
a full computational fluid dynamics simulation (CFD), including the
combustion process, can be executed on a connected and reoccurring
basis. This CFD simulation may be a portion of the fired-systems
model 3206 and can then be used to calculate what flue gas patterns
and temperature profiles are expected to be present within the
firebox based on clean gas tips throughout. The burner tip monitor
3202 can then be configured to query the same or similar
measurement path as configured with one of the TDLAS devices 147.
The comparison of the calculated temperature, CO, or oxygen along
the TDLAS measurement path can make even more accurate
identification of a problem area within the heater, and effectively
point operators towards the burners with plugged gas tips much more
effectively.
[0143] FIG. 35 depicts a method 3500 for generating a combustion
system burner tip health indication, in embodiments. Method 3500
may be implemented using system 100 discussed above with respects
to FIGS. 1-11, and 30-34, and, in some embodiments, within burner
tip monitor 3202.
[0144] In block 3502, method 3500 calculates the burner heat
release of a burner, or a plurality of burners assuming clean
burner tips. In one example of block 3502, the burner tip monitor
3202 executes the fired-systems model 3206 on the burner (e.g.,
burner 104), or burners within the heater 102 to determine an
expected burner heat release 3208. In embodiments of block 3502,
the fired-systems model 3206 may be based on a controlled fire rate
3210, the fuel information 3212, and the burner geometry 3214. In
certain embodiments of block 3502, the fired-systems model 3206 is
based on additional information, such as the fuel supply line
geometry 3216.
[0145] In block 3504, method 3500 determines a measured burner heat
release. In one example of block 3504, the burner tip monitor 3202
analyzes the real-time sensed data to determine the real-time
measured heat release 3218. In embodiments, the real-time sensed
fuel data 3220 includes the fuel pressure data 1116. In
embodiments, the real-time sensed fuel data 3220 additionally
includes the fuel temperature data 1114.
[0146] In block 3506, method 3500 compares the expected burner heat
release to the measured burner heat release to generate a burner
tip health indication. In one example of block 3506, the burner tip
monitor 3202 determines burner tip health indication 3204 including
the ratio of the measured heat release 3218 to the calculated
burner heat release 3208.
[0147] In block 3508, if included in method 3500, method 3500
determines if the burner tip health indication is at or below a
burner tip threshold. In one example of block 3508 the burner tip
monitor 3202 analyzes the ratio of the burner tip health indication
3204 against a burner tip health threshold 3222. The burner tip
health threshold 3222 may be a delta, or range of delta, of the
ratio. In an example of block 3508, the burner tip health threshold
3222 is 1 with a delta of 0.03 such that if the ratio defined in
the burner tip health indication 3204 is below 0.97, then the
burner tip is sufficiently plugged and requires maintenance. The
"ratio of measured heat release may be based on expected
uncertainty that can be attributed to, for example, the
manufacturers published measurement uncertainty of each measurement
device, and tolerances of the burner geometry and then set based on
the operational goals of the facility. Thus, the delta, although
described herein as 0.03, may be a dynamic number that is definable
so as to not alarm unless necessary.
[0148] If yes, method 3500 proceeds with block 3512, else method
3500 proceeds with block 3510 (if included) or loops back to block
3504.
[0149] In block 3510, if included in method 3500, method 3500
determines if the burner tip health indication is at or above a
burner tip threshold. In one example of block 3510 the burner tip
monitor 3202 analyzes the ratio of the burner tip health indication
3204 against a burner tip health threshold 3222 that defines a
burner tip burn-off (such as shown in FIG. 31). If the ratio of
measured heat release 3218 to the calculated heat release 3208, as
defined in the burner tip health indication 3204, is above 1, it
indicates that the burner is releasing more heat than expected.
Thus, the burner tip health threshold 3222 may be 1 with a delta of
0.03 such that if the ratio defined in the burner tip health
indication 3204 is at or above 1.03, then the burner tip is likely
burnt off and requires replacement. Any other delta may be used
without departing from the scope hereof. If yes at block 3510, then
method 3500 proceeds with block 3512, else method 3500 loops back
to block 3504.
[0150] At block 3512, if included in method 3500, the method 3500
verifies the tip malfunction. In one example of block 3512, the
burner tip monitor 3202 may further analyze oxygen data 3228 from
the oxygen sensor 132 to determine if the oxygen readings are as
expected. If the fuel is not being injected through the burner tip
because of tip plugging, then the air/fuel ratio will be higher
because not as much fuel is being injected into the heater as
expected. Thus, the excess oxygen levels sensed by the oxygen
sensor 132 will be greater because not all of the air being input
into the heater is being consumed to produce the thermal energy
112. Further, in alternate or additional embodiments of block 3512,
if the burner tip monitor 3202 has verified that there is no
additional tramp air, or has accounted for an estimated amount of
tramp air, then the burner tip monitor 3202 is able to verify the
ratio in the burner tip health indication 3204 utilizing the sensed
excess oxygen data 3228.
[0151] FIGS. 36 and 37 depict example data showing oxygen data used
to verify that tip plugging was not occurring. Graph 3600 shows the
measured heat release 3602 versus the calculated heat release 3604
based on clean gas ports with the known fuel composition and fuel
pressure. This graph would seemingly illustrate that there is "tip
plugging" occurring on the burners. However, graph 3700 shows that
the calculated oxygen value 3704, which is an expected oxygen value
calculated based on an assumption of clean burner tips and measured
fuel pressure, matches very closely to the measured "ZoneO2" value
3706. However, when we look at the "CustomerFlowResults" expected
O2 3702, which is based on real-time measured heat release based on
fuel flow meter, it is seen to be much higher than the measured
"ZoneO2" 3706. So, because of this analysis, the method could
confidently conclude there is no tip plugging and output the
maintenance schedule 3226 instructing to verify/calibrate the fuel
flow meter.
[0152] At block 3514, if included in method 3500, the method 3500
verifies determines the specific burner tip having a malfunction.
In one example of block 3514, the burner tip monitor 3202 may
further analyze in-heater data 3230 to determine the specific
burner that is malfunctioning. For example, as discussed above, a
plurality of TDLAS monitoring systems may be located within the
heater 102. Thus, the TDLAS systems may generate in-heater data
3230 that is able to identify these cool spots. Based on the cool
spots, the burner tip monitor 3202 is able to specify which burner,
or plurality of burners, have burner tips that are plugged. In
additional or alternative embodiments, other systems and sensors
may generate the in-heater data 3230, such as imaging systems
(visual and infrared), in-heater temperature sensors, etc. Some
"cool spots" may be completely expected within the firebox even
with complete clean burner gas tips due to the complex flue gas
aerodynamics that occur within the firebox. In this case, a full
computational fluid dynamics simulation (CFD), including the
combustion process, can be executed on a connected and reoccurring
basis. This CFD simulation may be a portion of the fired-systems
model 3206 and can then be used to calculate what flue gas patterns
and temperature profiles are expected to be present within the
firebox based on clean gas tips throughout. The burner tip monitor
3202 can then be configured to query the same or similar
measurement path as configured with one of the TDLAS devices 147.
The comparison of the calculated temperature, CO, or oxygen along
the TDLAS measurement path can make even more accurate
identification of a problem area within the heater, and effectively
point operators towards the burners with plugged gas tips much more
effectively.
[0153] In block 3516, the method 3500 outputs a burner tip health
indication. In one example of block 3516, the burner tip monitor
3202 outputs the burner tip health indication 3204. Where the
burner tip monitor 3202 is able to identify the specific burner or
group of burners that is malfunctioning, the burner tip health
indication 3204 may include an identification of said specific
burner or group of burners. The burner tip monitor 3202 may be
output to the heater controller 128 for display thereon. The burner
tip health indication output in block 3516 may also include any of
the above discussed burner tip alarms 3224, in embodiments.
[0154] In block 3518, if included in method 3500, the method 3500
determines and outputs a burner tip maintenance schedule. In one
example of block 3518, the burner tip monitor 3202 analyzes trends
in the ratio of the measured heat release 3218 to the expected
burner heat release 3208 within the burner tip health indication
3204 to predict when maintenance on the burner tip is or will be
necessary and generate the burner tip maintenance schedule 3226.
The burner tip monitor 3202 may then output the maintenance
schedule 3226 to the heater controller 128 defining when the burner
tip should be replaced.
[0155] Any portion of the heater controller 128, including the fuel
analyzer 3200 of FIG. 32 may be implemented using an edge computing
scheme. For example, the fuel analyzer 3200 may be located at the
external server 164, and data (such as the fuel information 3212,
real-time sensed fuel data 3220, sensed oxygen data 3228, and/or
in-heater data 3230) may be transmitted from the heater controller
128 to the external server 164. This allows the fired-systems model
3206 to remain on the external server 164 for analysis thereon. The
burner tip health indication 3204, burner tip alarm 3224, and
burner tip maintenance schedule 3226 may then be transmitted from
the external server 164 to the heater controller 128.
[0156] FIG. 38 depicts a method 3800 for determining discrepancy in
a combustion system, in embodiments. Method 3800 is implemented in
any one or more of the fuel analyzer 1148, the air analyzer 1150,
the draft analyzer 1152, the emissions analyzer 1154, and the
process-side analyzer 1176 discussed above, including the air
analyzer 1700, the draft analyzer 2200, and the fuel analyzer 3200
discussed in FIGS. 17, 22, and 32 respectively. In certain
embodiments, method 3800 is implemented after verification of the
fuel-side of the system associated with the method.
[0157] In block 3802, the method 3800 senses real-time data inside
the process heater. In one example of block 3802, any one or more
of the fuel data 1110, air data 1118, heater data 1126, emissions
data 1140, and process-side data 1170 is captured and stored in
sensor database 130.
[0158] In block 3804, the method 3800 determines a fired-systems
model. In certain embodiments, the fired-systems model is
determined for the entire heater 102. In certain embodiments, the
fired systems model is determined for a specific location
correlating to a potential discrepancy location (e.g., at the
process tubes 106, or at the location of a potential tramp-air
leak). Fired-systems model 1705, and 2205, and 3206 are examples of
the fired-systems model determined in block 3804.
[0159] In blocks 3806 and 3808, respectively, the method 3800 then
determines if the real-time sensed data from block 3800 is greater
than or less than the expected value defined by the fired-systems
model determined in block 3804. In one example of block 3806, the
draft discrepancy identifier 2202 determines if the sensed draft
data 2212 is a value greater than the expected draft data defined
by the fired-systems model 2205 (at a single location, or at a
plurality of locations). In one example of block 3808, the draft
discrepancy identifier 2202 determines if the sensed draft data
2212 is a value less than the expected draft data defined by the
fired-systems model 2205 (at a single location, or at a plurality
of locations). If, at block 3808, the sensed data is greater than
the expected data, method 3800 proceeds with block 2010. Else,
method 3800 repeats block 3802. In another embodiment, blocks 3508
and 3510 are an example of blocks 3806 and 3808.
[0160] At block 3810, the method 3800 displays an operating
condition defining the difference between the expected and the
sensed values from blocks 3804 and 3802, respectively. In an
example, blocks 3516 and 3518 are examples of block 3810.
[0161] In certain embodiments, method 3800 includes blocks 3812
which is a decision in which method 3800 determines if the sensed
value is above the expected value beyond a discrepancy threshold.
In one example of block 3812, the draft discrepancy identifier 2202
determines if the sensed draft level 2212 is above the expected
draft level defined by the fired-systems model 2205 by a delta that
meets or exceeds a discrepancy threshold 2214.
[0162] In certain embodiments, the block 3810 includes sub-blocks
that determine a location of the discrepancy. In block 3814
captures additional data corresponding to the potential
discrepancy. In one example of block 3814, the draft discrepancy
identifier 2202 may control a device (e.g., the TDLAS scanner 147,
or an optical scanner) within the heater 102 to obtain optical scan
data 2217 (similar to optical scan data 1734 discussed above,
and/or the in-heater data 3230 discussed above) to further to
pinpoint the cause of such discrepancy. Knowledge of the field of
view, or scanning path, of the optical device used to generate the
optical scan data 2217 allows the draft discrepancy analyzer 2202
to correlate the field of view, or scanning path, to a specific
location within the heater 102 and therefore provide the
remediation action 2204 accordingly. In embodiments of block 3814,
instead of an optical scan, the draft discrepancy identifier 2202
analyzes one or more temperature sensors (e.g., thermocouples
located on one or more of the process tubes 106) to correlate the
location of a clogged fins on one or more process tube 106.
[0163] In sub-block 3816, the method 3800 determines if the
additional data from sub-block 3814 matches the potential
discrepancy. In one example of sub-block 3816, the optical scan
data 2217 may indicate tube clogging at a specific height or other
location within the heater 102 that causes certain of the process
tubes 106 to operate in a different manner than others because the
clogging of the fins on those tubes does not allow for designed
convection at the location of those tubes. If yes at sub-block
3816, the method 3800 proceeds to sub-block 3818, else the method
proceeds to sub-block 3812.
[0164] In sub-block 3818, the method 3800 outputs remediation
action including location of the discrepancy. In one example of
sub-block 3818, the draft discrepancy identifier 2202 outputs a
remediation action 2204 defining the location of the draft
discrepancy (e.g., location of the clogged fins of the process
tubes 106.
[0165] In sub-block 3820 the method 3800 outputs remediation action
indicating to visually inspect a specific location of the heater.
In one example of sub-block 3820, if, after analysis of the optical
scan data 2217, there is no indication of process tube clogging,
the remediation action 2204 may include the alert 2206, or
displayed operating condition 2210, that instructs the operator to
physically view the location of the draft discrepancy to check for
other obstructions at the location of the draft (e.g., fallen
refractory tiles at the process tubes 106 at the location of the
draft discrepancy).
[0166] The blocks 3512-3518 are examples of sub-blocks 3814-3820.
The sub-blocks 2014-2024 are examples of sub-blocks 3814-3820.
[0167] If, at block 3808, the sensed data is less than the expected
oxygen data, method 3800 proceeds with block 3826. Else, method
3800 repeats block 3802.
[0168] Certain discrepancies are present when the sensed data is
lower than the expected data, and certain discrepancies are present
when the sensed data is greater than the expected data. Thus,
blocks 3826, 3828, 3830, and 3832 are similar to blocks 3814, 3816,
3818, and 3820, respectively but are triggered when the sensed data
from block 3002 is less than the expected data from block 3004.
[0169] At any time during method 3800, the method 3800 may execute
block 3834 and determine if the sensed data are at a dangerous
condition (e.g., above predefined threshold levels, a threshold
level difference between expected and sensed, etc.). If so, method
3800 executes block 3836 and outputs a remediation action including
a safety control signal. In one example of block 3836, the draft
discrepancy identifier 2202 determines if the sensed draft level
2212 is at dangerous levels, such as if there is insufficient
airflow, or too much airflow, that could cause a stoichiometric
unbalance resulting in a catastrophic failure. In one example of
block 3836, the draft discrepancy identifier 2202 outputs the
remediation 2204 including control signal 2208.
[0170] Cloud Computing Embodiments:
[0171] In embodiments, a portion or all of the air-flow discrepancy
analyzer 1702, draft discrepancy identifier 2202, burner tip
monitor 3202 or other discrepancy detectors may be implemented
remotely from the process controller 128, such as in the
network-based "cloud", where the air-flow discrepancy analyzer and
the process controller 128 are a portion of an edge computing
scheme. For example, the air-flow discrepancy analyzer 1702, draft
discrepancy identifier 2202, burner tip monitor 3202 or other
discrepancy detectors may be stored and executed at the external
server 164, such that after the remediation action 1704, the
remediation action 2204, burner tip health indication 3204, burner
tip health threshold 3222, burner tip alarm 3224, or burner tip
maintenance schedule 3226, or any combination thereof is generated,
said generated data then transmitted from the external server 164
to the process controller 128 for display on the display 1108
thereof or used automatic control of the hardware associated the
system 100. The measured operating parameters used by one or more
of the air-flow discrepancy analyzer 1702, draft discrepancy
identifier 2202, burner tip monitor 3202 or other discrepancy
detectors may be gathered at the process controller 128 (such as at
the system DCS or PLC (plant control system) and transmitted to the
external server 164 for analysis by the respective analyzer located
on the external server 164. Alternatively, or additionally, one or
more of the devices capturing the measured operating parameters may
be an embedded device having data transmission capability that
transfers its respective data directly to the external server 164
for analysis by the air-flow discrepancy analyzer 1702, draft
discrepancy identifier 2202, burner tip monitor 3202 or other
discrepancy detectors.
[0172] System Component Validation:
[0173] Continued understanding on the modeling side (by any of the
above described "analyzers", or other physics-based modeling, or
analytics discussed herein or in any of the provisional
applications incorporated by reference as discussed above) allows
for the process controller 128 to monitor and validate the
measurement devices that populate the data within the sensor
database 130. Because the modeling provides optimized control
settings, the analyzers discussed herein are able to compare the
measured data to the expected data generated via calculations. If
the measured data varies with respect to the calculated data, the
system is able to troubleshoot the particular reason for that
discrepancy.
[0174] For example, a variation in a fuel-side calculation may
indicate that the calculated heat release based on pressure with
clean burner tips is higher than a given fuel mass flow
measurement. In such situation, the fuel analyzer 1148 may
implement the following troubleshooting: (i) identify that one or
more of the burners are out of service, (ii) determine if one or
more of the fuel valves are full-open (even though they are
supposed to be at a specific setting), (iii) determine if the
burner tips have additional fouling that is visually identifiable,
(iv) determine if the burner tips have a different orifice diameter
than expected, and (v) determine if the pressure transmitter or
flow meter providing the measurements are in need of
calibration.
[0175] As another example, a variation in a fuel-side calculation
may indicate that the calculated heat release based on pressure
with clean burner tips is lower than a given mass flow measurement.
In such situation, the fuel analyzer 1148 may implement the
following troubleshooting: (i) confirm quantity of out-of-service
burners, (ii) verify that the out-of-service burners are truly out
of service, (iii) determine if there are gas leaks within the
combustion system (visually observed by small "candle flames" until
the tip is plugged), (iv) determine if flame patterns match
conditions indicating missing burner tips or burner tips that have
ports that are eroded, (v) confirm burner tip orifice diameter,
(vi) determine improper line loss calculations, (vii) determine if
the pressure transmitter or flow meter providing the measurements
are in need of calibration.
[0176] As another example, a variation in an air-side calculation
may indicate that the calculated oxygen is higher than a measured
oxygen level. In such situation, the air-side analyzer 1150 (or the
emissions analyzer 1154) may implement the following
troubleshooting process: (i) confirm the number of burners
out-of-service, (ii) confirm that the air register settings are
accurate within the model, (iii) analyze the burners for blocked
air passages, such as blocked air inlets, refractory fallen into
burner throats, wall burner air-tip fouling, loos burner
insulation, flashback or combustion back pressure within the
burner, (iv) determine potential leaks within the process tubes
(and shut down if so), (v) verify ambient air conditions, (vi)
check wind speeds, (vii) calibrate air-side measurement devices
such as the air-pressure and O2 analyzer.
[0177] As another example, a variation in an air-side calculation
may indicate that the calculated oxygen is lower than a measured
oxygen level. In such situation, the air-side analyzer 1150 (or the
emissions analyzer 1154) may implement the following
troubleshooting process: (i) confirm the number of burners
out-of-service, (ii) confirm that the air register settings are
accurate within the model, (iii) analyze for tramp-air entering the
system (such as via sight ports, lighting ports, gas tip riser
mounting plates, etc.), (iv) determine potential leaks within the
process tubes (and shut down if so), (v) verify ambient air
conditions, (vi) check wind speeds, (vii) analyze for additional
gas leakage into the system, (viii) calibrate air-side measurement
devices such as the air-pressure and O2 analyzer.
Definitions
[0178] The disclosure herein may reference "physics-based models"
and transforming, interpolating, or otherwise calculating certain
data from other data inputs. Those of ordinary skill in the art
should understand what physics-based models incorporate, and the
calculations necessary to implement said transforming,
interpolating, or otherwise calculating for a given situation.
However, the present disclosure incorporates by reference chapter 9
of the "John Zink Hamworthy Combustion Handbook", which is
incorporated by reference in its entirety (Baukal, Charles E. The
John Zink Hamworthy Combustion Handbook. Fundamentals. 2nd ed.,
vol. 1 of 3, CRC Press, 2013) for further disclosure related to
understanding of fluid dynamics physics-based modeling and other
calculations. It should be appreciated, however, that
"physics-based models" and transforming, interpolating, or
otherwise calculating certain data from other data inputs is not
limited to just those fluid dynamics calculations listed in chapter
9 of the John Zink Hamworthy Combustion Handbook.
[0179] Changes may be made in the above methods and systems without
departing from the scope hereof. It should thus be noted that the
matter contained in the above description or shown in the
accompanying drawings should be interpreted as illustrative and not
in a limiting sense. The following claims are intended to cover all
generic and specific features described herein, as well as all
statements of the scope of the present method and system, which, as
a matter of language, might be said to fall therebetween. Examples
of combination of features are as follows:
[0180] (A1) In a first aspect, a method for determining discrepancy
in air-flow of a process heater includes: sensing current oxygen
level within a housing of the process heater; calculating a delta
between the sensed current oxygen level and an expected oxygen
level; comparing the delta to a predetermined threshold; and,
outputting a remediation action in response to the delta breaching
the predetermined threshold.
[0181] (A2) In an embodiment of (A1), the method further including,
when the delta indicates unwanted excess air-flow: determining an
amount of the unwanted excess air-flow in terms of leakage area
within the housing based on the geometry of the housing, and an
identified draft within the housing.
[0182] (A3) In an embodiment of any of (A2), the method further
including comparing the leakage area to size of known components of
the combustion system and outputting the remediation action with
respect to one of the known components when the leakage area
matches the size of the known component.
[0183] (A4) In an embodiment of any of (A2)-(A3), the known
component being a viewing access panel.
[0184] (A5) In an embodiment of any of (A2)-(A4), the method
further including displaying the leakage area at a process
controller of the combustion system.
[0185] (A6) In an embodiment of any of (A1)-(A5), the method
further including determining the predetermined threshold based on
verified air-flow settings.
[0186] (A7) In an embodiment of any of (A6), the verified air-flow
settings including burner damper settings, stack damper settings,
stack fan settings, and/or forced fan settings.
[0187] (A8) In an embodiment of any of (A1)-(A7), the method
further including sensing the oxygen level at a plurality of
heights within the housing of the combustion system; the outputting
a remediation action including identifying a height at which the
delta breaches the predetermined threshold, and outputting a zone
of the housing having likely tramp-air penetration based on the
height.
[0188] (A9) In an embodiment of any of (A1)-(A8), the outputting a
remedial action comprising performing an optical scan of inside the
housing of the combustion system; identifying irregularity within
the optical scan indicating tramp-air penetration; and, outputting
a zone of the housing of the combustion system having the
irregularity.
[0189] (A10) In an embodiment of any of (A9), the optical scan
including an infrared image.
[0190] (A11) In an embodiment of any of (A9)-(A10), the optical
scan including a tunable diode laser absorption spectroscopy
(TDLAS) scan.
[0191] (A12) In an embodiment of any of (A1)-(A11), when the delta
indicates deficient air within the combustion system, the
outputting a remedial action comprising performing an optical scan
of a burner of the combustion system; identifying irregularity of a
burner flame based on the optical scan; and, outputting a zone of
the combustion system based on the irregularity.
[0192] (A13) In an embodiment of any of (A12), the optical scan
including an infrared image.
[0193] (A14) In an embodiment of any of (A12)-(A13), the optical
scan including a tunable diode laser absorption spectroscopy
(TDLAS) scan.
[0194] (A15) In an embodiment of any of (A1)-(A4), the method
further including, prior to outputting a remedial action, verifying
fuel-flow rates within the combustion system.
[0195] (B1) In a second aspect, a system for determining operating
discrepancy a process heater includes: a processor; and, memory
storing computer readable instructions that, when executed by the
processor, control the processor to: receive sensed current
operating data within the process heater; calculate a delta between
the sensed current operating data and an expected current operating
data corresponding to the sensed current operating data; compare
the delta to a predetermined threshold; and, output a remediation
action in response to the delta breaching the predetermined
threshold.
[0196] (B2) In an embodiment of (B1), the computer readable
instructions including further instructions that, when executed by
the processor, cause the processor to: solve a fired-systems model
to determine the expected current operating data.
[0197] (B3) In an embodiment of any of (B1)-(B2), the computer
readable instructions including further instructions that, when
executed by the processor, cause the processor to: capture
additional data when the delta breaches the predetermined
threshold; determine the location of a discrepancy between the
expected current operating data and the sensed current operating
data based on the additional data.
[0198] (B4) In an embodiment of any of (B3), the additional data
including optical scan data of a location of a potential
discrepancy.
[0199] (B5) In an embodiment of any of (B1)-(B4), the sensed
current operating data defining one or more of: absorbed duty,
current firing rate, heater efficiency, bridge wall temperature,
tube metal temperatures, stack temperature, damper positions, and
process tube pressure drop; the remediation action identifying
convection fouling when there is an increase in bridge wall
temperature, stack temperature, and air handling settings are more
open than expected as defined by the expected current operating
data.
[0200] (B6) In any embodiment of any of (B1)-(B5) the instructions
implementing any of the features of (A1)-(A15).
[0201] (C1) In a third aspect, a combustion system having burner
tip plugging indication, includes: a burner having a burner tip; a
fuel pressure sensor generating fuel pressure data of a fuel source
input into the burner; a processor; and, memory operatively coupled
to the processor storing a burner tip monitor as computer readable
instructions that when executed by the processor operate to:
generate a calculated fuel heat release of the burner by executing
a fired-systems model of the burner based on fuel information, a
fuel pressure, and burner geometry, and compare the calculated fuel
heat release of the burner to a measured heat release to generate a
burner tip health indication of the burner tip.
[0202] (C2) In an embodiment of C1), the measured heat release
being further based on fuel temperature data sensed by a fuel
temperature sensor of the combustion system.
[0203] (C3) In an embodiment of any of (C1)-(C2), the burner tip
health indication including a ratio of the measured heat release to
the calculated fuel heat release.
[0204] (C4) In an embodiment of any of (C3), the computer readable
instructions that when executed by the processor operate to compare
including computer readable instructions that when executed by the
processor operate to compare the ratio to a burner tip health
threshold to identify a plugged burner tip.
[0205] (C5) In an embodiment of any of (C1)-(C4), the burner tip
health threshold being a ratio less than 1.
[0206] (C6) In an embodiment of any of (C1)-(C5), the burner tip
health threshold being a ratio determined based on expected
uncertainty associated with the calculation.
[0207] (C7) In an embodiment of any of (C1)-(C6), the computer
readable instructions that when executed by the processor operate
to compare including computer readable instructions that when
executed by the processor operate to compare the ratio to a burner
tip health threshold to identify a burnt-off burner tip or other
gas leakage.
[0208] (C8) In an embodiment of any of (C7), the burner tip health
threshold being a ratio greater than 1.
[0209] (C9) In an embodiment of any of (C1)-(C8), the burner tip
health threshold being a ratio determined expected uncertainty
associated with the calculation.
[0210] (C10) In an embodiment of any of (C1)-(C9), the burner tip
monitor including further computer readable instructions that when
executed by the processor operate to: verify the burner tip health
indication by analyzing oxygen data sensed by an oxygen sensor
within the combustion system.
[0211] (C11) In an embodiment of any of (C1)-(C10), the burner
including a plurality of burners; the burner tip monitor including
further computer readable instructions that when executed by the
processor operate to: identify a specific burner or group of
burners having a tip malfunction identified in the burner tip
health indication based on in-heater data.
[0212] (C12) In an embodiment of any of (C11), the in-heater data
including data captured by one or more tunable diode laser
absorption spectroscopy (TDLAS) systems within the combustion
system.
[0213] (C13) In an embodiment of any of (C11)-(C12), the in-heater
data including data captured by one or more image sensors within
the combustion system.
[0214] (C14) In an embodiment of any of (C1)-(C13), the burner tip
monitor including further computer readable instructions that when
executed by the processor operate to: analyze historical data
within the burner tip health indication to identify trends of the
burner tip health indication, and generate a burner tip maintenance
schedule predicting when the burner tip will need replacement.
[0215] (C15) In an embodiment of any of (C1)-(C14), the burner tip
monitor being located remotely from a heater controller in an edge
computing configuration, and the burner tip monitor configured to
transmit the burner tip health indication to the heater
controller.
[0216] (C16) In any embodiment of any of (C1)-(C15) the
instructions implementing any of the features of (A1)-(A15), and/or
(B1)-(B6).
[0217] (D1) In a fourth aspect, a method for generating a burner
tip health indication, comprising: calculating a fuel heat release
of a burner by executing a fired-systems model of the burner based
on fuel information, a fuel pressure measurement, and burner
geometry, and comparing the calculated fuel heat release of the
burner to a measured real-time heat release to generate a burner
tip health indication of a burner tip of the burner.
[0218] (D2) In any embodiment of any of (D1) the method further
including any of the features of (A1)-(A15), (B1)-(B6), and/or
(C1)-(C16).
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