TECHNICAL FIELD
The present invention relates generally to the detection of corrosion in gas turbine
systems, and, more particularly, to an apparatus and method for providing in-situ
detection of corrosion pitting in gas turbine compressor blades.
BACKGROUND
As a fuel with low CO2 emissions, natural gas has experienced a major expansion
worldwide. When distance and topography between gas fields and consumer markets
do not allow pipeline transport, the gas can be reduced to, for example, 1/600* of its
free volume by liquefaction. Liquefied Natural Gas (LNG) plants liquefy purified
natural gas in cryogenic heat exchangers so that the purified liquid natural gas can be
stored in tanks prior to being loaded on designed tankers for transportation between
an LNG plant and consumer regions. At the consumer regions, the LNG product is
unloaded in an LNG receiving terminal, pumped up to pipeline pressure, and regasified
for feeding into the buyer's natural gas pipeline grid.
In response to these increased demands, the size of LNG plants has, therefore, grown
considerably over the past few decades. This, in turn, has contributed to lowering
LNG production costs, while at the same time increasing the competitivity of the
LNG marketplace. For example, in the 1980s, it was common practice to produce 2-3
million tons per steam per year. Present units produce 4-5 million tons per year, and
engineering companies are now (i.e., 2009) planning plants with unit capacities in the
order of 7-8 million tons per year.
In LNG plants, it is common practice to use, for example, gas turbines to drive the
refrigerating compressors utilized in the cryogenic heat exchangers responsible for the
liquefaction of natural gas. Thus, production output may be closely associated with
reliable plant operation, in particular, gas turbine reliability. The reliable operation of
gas turbine systems may be hampered by a myriad of different failure causes. As
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described in the following paragraphs, one such cause is the adverse effect of
corrosion on the Inlet Guide Vanes (IGVs) and rotor blades of the gas turbine's turbo
compressor.
LNG plants are typically located in marine coastal environments, where corrosive
elements such as Chlorides and Sulphides are prevalent in the atmosphere. The
Chlorides originate as a result of proximity to the sea, while the Sulphides are
generated by the LNG plant's gas flares. The air filtration system of a gas turbine
needs both correct design and maintenance, especially since it provides the key to the
successful operation and reliability of the overall plant by purifying air that is inlet
into the combustion section of the gas turbine system. Despite attempts to maintain
reliable and effective air filtration, the presence of corrosive elements such as
Chlorides and Sulphides in the various stages of the gas turbine system, such as, the
axial compressor blades of the gas turbine (e.g., IGVs and Rl rotor blades) is
unavoidable. These elements (i.e.. Chlorides and Sulphides) may, for example,
corrode the material construction of the gas turbine's IGVs and first stage (Rl) rotor
blades by causing corrosion pitting, which if undetected, eventually leads to the
initiation and propagation of cracks within the blades. The consequences of such
cracks are breakages in one or more of gas turbine's IGVs and Rl rotor blades, thus,
causing an eventual gas turbine outage.
These outages are extremely costly. Usually, there is zero-redundancy associated
with the production machinery/equipment of LNG plants. Within a given gas turbine
train, the outage of one gas turbine can cause an overall train outage or, at least, a vast
reduction of LNG production rate. As a consequence, LNG shipment may also be
postponed, generating additional costs and/or profit losses that may be estimated in
the range of $2 - $7 Million Dollars/day depending on the specific plant size and
production plan. For this reason all catastrophic failures, such as those generated by
corrosion pitting, should be avoided since an outage of 7-10 days duration is the
expected duration for restoring the system back to an operational status.
Thus, in order to avoid a gas turbine outage situation as a result of undetected failure
conditions, it would be advantageous to provide in-situ corrosion detection within
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LNG gas turbine systems without the need for disassembUng the gas turbine system
(e.g., casing).
SUMMARY OF INVENTION
Various embodiments of the present invention provide methods and apparatuses for
detecting corrosion pitting in turbine blades. In accordance with at least one
embodiment, a corrosion detection device (e.g., EC probe device) for detecting
corrosion in one or more blades of a gas turbine system comprises a detection head
having a shape that conforms to a surface geometry of a filet section of a gas turbine
blade, whereby the detection head is operable to move along the axial length of the
filet section for detecting corrosion pitting. At least one coil device located within the
detection head induces a first magnetic field within an area of the filet in contact with
the detection head. A receiver device is adapted to detect a signal corresponding to a
second magnetic field received from the area of the filet exposed to the first magnetic
field, where the second magnetic field is generated by induced currents in the area by
the first magnetic field. A signal processing device then processes the detected signal
for correlating a corresponding amplitude of the detected signal with the presence of
corrosion pitting in the area such that the presence of corrosion pitting is determined
without any casing disassembly of the gas turbine system.
In accordance with one aspect, the at least one coil device comprises a plurality of coil
devices located within the detection head and operable to each induce the first
magnetic field within an area of the filet in contact with the detection head, whereby
the detected signal includes a plurality of signals corresponding to the second
magnetic field. The signal processing device is operable to process the plurality of
detected signals for correlating corresponding amplitudes of the detected signals with
the presence of corrosion pitting in the area, where each of the processed plurality of
detected signals corresponds to a signal channel associated with a respective one of
the plurality of coil devices, thereby providing for multi-channel detection of
corrosion pitting.
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In accordance with another aspect, the at least one coil device comprises separate
coils including: (a) a first coil operable to generate the first magnetic field; and (b) at
least one other coil operable to receive the second magnetic field.
According to one aspect, the receiver device may include: (a) a first and a second coil
device operable to generate a first and a second received signal fi-om the second
magnetic field, respectively; (b) a first and a second band-pass filter device
respectively coupled to the first and the second coil device, wherein the first and the
second band-pass filter device are operable to filter the first and the second received
signal, respectively; and (c) differential amplifier device coupled to the first and the
second band-pass filter device, wherein the differential amplifier is operable to
differentially amplify the filtered first and the filtered second received signal and
generate the detected signal.
According to another aspect, the detection head may include a substantially
cylindrical shape including a radius that corresponds to a curvature radius of the filet,
or a substantially cylindrical shape including a radius that is less than the curvature
radius corresponding to the filet.
According to another aspect, the detection apparatus further includes a handle section
coupled to the detection head, the handle section including a flexible portion operable
to move the detection head into a measurement position by enabling contact between
the detection head and the filet section of the one of a plurality of first stage Rl rotor
blades based on manipulating the flexible portion and detection head between the
plurality of inlet guide vanes located at the front of the Rl rotor blades.
According to another aspect, the detection apparatus further includes a video camera
coupled to the handle section, the video camera located in proximity to the detection
head and operable to assist an operator move the detection head into the measurement
position.
According to another aspect, the detection apparatus further includes a driver device
operable to generate a drive signal that is applied to the at least one coil device,
whereby the driver device manipulates at least one characteristic (e.g., amplitude,
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frequency, etc.) of the drive signal for producing a signal-to-noise ratio associated
with the detected signal that exceeds a designated threshold.
According to another aspect, the signal processing device includes a digital signal
processing (DSP) device comprising: (a) an analog-to-digital convertor operable
to digitize the detected signal amplitude; (b) a first storage region operable to store an
amplitude corresponding to the detected signal with other stored detected signal
amplitudes based on the amplitude corresponding to the detected signal and the other
stored detected signal amplitudes corresponding to a detected corrosion pit; (c) a
second storage region operable to store reference data associated with a plurality of
pre-generated corrosion pitting areas created on a sample filet surface of a gas turbine
blade; and (d) a processor section operable to compare the amplitude corresponding to
the detected signal with the stored reference data for determining the presence of
corrosion pitting in the filet section.
According to another aspect, the first storage region includes time-stamp information
that is added to both the amplitude corresponding to detected signal and the other
stored detected signal amplitudes for calculating a time interval between the
determinations of corrosion pitting in the filet section. The first storage region may
also include drive signal information that is added to the stored detected signal
amplitude and the other stored detected signal amplitudes.
In accordance with another embodiment, a probe device for detecting corrosion in one
or more blades of a gas turbine system includes: (a) a detection head having a shape
that conforms to a surface geometry of a filet section of a gas turbine blade, the
detection head operable to move along the filet section for detecting corrosion pitting;
(b) at least one transducer device located within the detection head and operable
to induce a first magnetic field within an area of the filet in contact with the detection
head; (c) a receiver device operable to detect a signal corresponding to a second
magnetic field received from the area of the filet exposed to the first magnetic field,
wherein the second magnetic field is generated by induced currents in the area by the
first magnetic field; and (d) a signal processing device operable to process the
detected signal for correlating a corresponding amplitude of the detected signal with
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the presence of corrosion pitting in the area, whereby the presence of corrosion pitting
is determined without any casing disassembly of the gas turbine system.
In accordance with yet another embodiment, a probe device for detecting corrosion in
one or more blades of a gas turbine system includes: (a) a detection head having a
shape that conforms to a surface geometry of a filet section of a gas turbine blade, the
detection head operable to move along the filet section for detecting corrosion pitting;
(b) a transceiver device located within the detection head and operable to induce a
first magnetic field within an area of the filet in contact with the detection head and
detect a signal corresponding to a second magnetic field received from the area of the
filet exposed to the first magnetic field, wherein the second magnetic field is
generated by induced currents in the area by the first magnetic field; and (c) a signal
processing device operable to process the detected signal for correlating a
corresponding amplitude of the detected signal with the presence of corrosion pitting
in the area, whereby the presence of corrosion pitting is determined without any
casing disassembly of the gas turbine system.
According to one aspect, the transceiver device may include: (a) a transmitter
operable to generate the first magnetic field; and (b) a receiver operable to receive the
second magnetic field and generate the detected signal amplitude. The transmitter
may include a first coil device, and a coil driver operable to apply an electrical drive
signal to the first coil device. The receiver may include a second coil device; a third
coil device; and a differential amplifier coupled to the second and the third coil device
and operable to differentially amplify a second and a third signal received from the
second and the third coil device, respectively, whereby the differential amplifier
generates the detected signal.
In accordance with at least one other embodiment, a method of detecting corrosion in
one or more blades of a gas turbine system is provided. The method comprises
detecting corrosion pitting along the axial length of a filet section of a gas turbine
blade by conforming the detecting to the surface geometry of the filet section, and
inducing a first magnetic field within an area of the filet during the detecting of the
corrosion. A signal corresponding to a second magnetic field received from the area
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of the filet exposed to the induced first magnetic field is detected, where the second
magnetic field is generated by induced currents in the area by the induced first
magnetic field. The detected signal is then processed by correlating a corresponding
amplitude of the detected signal with the presence of corrosion pitting in the area.
The presence of corrosion pitting is thus determined without any casing disassembly
of the gas turbine system.
In accordance with at least one aspect, conforming the detecting to the surface
geometry comprises using a probe head having a cylindrical shape that includes a
radius that is substantially the same as or less than a radius of curvature associated
with the filet section.
In accordance with at least one other embodiment, a corrosion pitting detection unit
comprises a plurality of probe devices, where each probe device includes: (a) a
detection head having a shape that conforms to a surface geometry of a filet section of
a gas turbine blade, the detection head operable to move along the axial length of the
filet section for detecting corrosion pitting; (b) at least one coil device located within
the detection head and operable to induce a first magnetic field within an area of the
filet in contact with the detection head; (c) a receiver device operable to detect a
signal corresponding to a second magnetic field received from the area of the filet
exposed to the first magnetic field, wherein the second magnetic field is generated by
induced currents in the area by the first magnetic field; and (d) a signal processing
device operable to process the detected signal for correlating a corresponding
amplitude of the detected signal with the presence of corrosion pitting in the area,
where the presence of corrosion pitting is determined without any casing disassembly
of the gas turbine system, and whereby the results of the detected signal processed by
each signal processing device of the plurality of probe devices is output on a
corresponding channel.
It will be appreciated by those skilled in the art that the foregoing brief description
and the following detailed description are exemplary and explanatory of the present
invention, but are not intended to be restrictive thereof or limiting of the advantages
which can be achieved by this invention. Additionally, it is understood that the
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foregoing summary of the invention is representative of some embodiments of the
invention, and is neither representative nor inclusive of all subject matter and
embodiments within the scope of the present invention. Thus, the accompanying
drawings, referred to herein and constituting a part hereof, illustrate embodiments of
this invention, and, together with the detailed description, serve to explain principles
of this invention.
BRIEF DESCRIPTION OF THE DRAWINGS
Aspects, features, and advantages of embodiments of the invention, both as to
structure and operation, will be understood and will become more readily apparent
when the invention is considered in the light of the following description made in
conjunction with the accompanying drawings, in which like reference numerals
designate the same or similar parts throughout the various figures, and wherein:
FIG. lA illustrates a block diagram of an Eddy Current (EC) probe device in
accordance with an embodiment of the present invention;
FIG. IB illustrates the position of the EC probe head relative to surface under
inspection in accordance with an embodiment of the present invention;
FIGS. 2A-2C illustrate the mechanical construction and relative positioning of the EC
probe device relative a gas turbine system rotor blade under inspection in accordance
with an embodiment of the present invention;
FIG. 3 illustrates an imaging device used in cooperation with the EC probe device in
accordance with an embodiment of the present invention;
FIG. 4 illustrates a photographic image of a calibration block 402 used in the
generation of stored reference data according to an embodiment of the present
invention;
FIG. 5 illustrates an operation flow diagram of the EC probe device according to an
embodiment of the present invention;
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FIG. 6 illustrates an operation flow diagram of the signal processing performed by
the EC probe device according to an embodiment of the present invention;
FIG. 7 illustrates experimental performance data associated with determining the
operating parameters of the EC probe device according to an embodiment of the
present invention; and
FIG. 8 illustrates an example of a unit incorporating a multi-channel EC probe device
in accordance with an embodiment of the present invention.
DESCRIPTION OF EMBODIMENTS OF THE INVENTION
The following describes various embodiments and aspects of the present invention
that utilizes Eddy Currents (EC) for the detection and analysis of the corrosive
characteristics (e.g., corrosion pitting) found in gas turbine rotor blades. Accordingly,
a novel EC detection probe and application methodology is provided for detecting
corrosion pitting in the first stages of gas turbine rotor blades. The first stages of the
gas turbine rotor blades (i.e., Rl rotor blades) are typically more susceptible to
corrosion pitting. Moreover, using the probe device, the first stage rotor blades (i.e.,
Rl) are directly accessible by a user via an opening in the intake plenum of the gas
turbine.
The corrosively generated pits ("a corrosion pit") may or may not be substantially
circular and generally include indentations in a material's surface. These
indentations, although very small (i.e., typically having depths and diameters of less
than 1 millimeter), lead to more serious defects such as cracks. In the case of the first
stages (i.e., Rl) of a gas turbine's rotor blades, detection of corrosion pitting avoids
the subsequent initiation and propagation of cracks, whereby the creation of such
cracks can lead to rotor blade breakages during the operations of a gas turbine and
thus leading to a catastrophic failure. While cracks provide a sharp discontinuity that
makes them suitable for conventional detection via signal phase changes using EC
detection equipment, a corrosion pit does not exhibit such a sharp discontinuity.
Therefore, according to at least one embodiment of the present invention, sensitive
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receiver designs may be utilized for the detection of signal amplitude changes
resulting from the presence of a corrosion pit.
FIG. lA schematically depicts an EC probe device 100 in accordance with an
embodiment of the present invention. Device 100 comprises a primary coil driver
102, a coil system 104, band-pass (BP) filters 106a and 106b, a differential amplifier
108, an analog-to-digital (A/D) convertor 110, a signal processing device 112, a
reference data storage medium 114, a data log storage medium 116, and a detection
indicator 118 (e.g., a visual display, audio buzzer). The operation of the EC probe
device 100 is further explained in relation to the flow diagrams illustrated in FIG. 5
and FIG. 6.
The primary coil driver 102 includes an electrical signal source that provides an
alternating drive signal (e.g., sinusoidal signal, pulsed signal, ramped signal, etc.) to
the coil system 104 for inducing eddy currents in the surface 120 of the material under
inspection (i.e., filet portion of gas turbine Rl rotor blades). Coil system 104 may
include three coil devices, as illustrated in the expanded bottom view 122. As
depicted at 122, coil CI is a primary coil device operable to generate a primary
magnetic field (Bl) that is induced in surface 120, which produces eddy currents
within the surface 122. Coil devices C2 and C3 are measurement coils used to receive
a net magnetic field comprised of the interaction between the generated primary
magnetic field (Bl) and the generated eddy current magnetic field (B2) fi-om surface
122. As previously mentioned, sensitive receiver designs may be utilized for the
detection of signal amplitude changes resulting from the presence of a corrosion pit.
One such design consideration applies to the measurement coils (i.e., C2, C3). These
coils should exhibit a coil diameter that has a comparable geometry (e.g., diameter) to
that of the indentations caused by corrosion pitting. For example, a coil diameter of
1.6mm may be used to detect corrosion pits having diameters of 0.25 mm, 0.50 mm,
and 0.75 mm, and a depth of 0.25 mm, 0.50 mm, and 0.75 mm, respectively.
Measurement coil devices C2 and C3 are each coupled to the inputs of BP filters 106a
and 106b, respectively. The BP filters 106a, 106b serve to reduce or eliminate,
among other unwanted artifacts, signals such as high frequency noise and low
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frequency signal variations that may occur as a result of physically manipulating the
EC probe device 100 relative to measurement area when, for example, the device is
utilized as a hand-held device. In addition, BP filters 106a and 106b also enhance the
signal-to-noise (S/N) ratio of the signals received by coil devices C2 and C3,
respectively. The configuration of coils CI, C2, and C3 illustrated at 122 is one
example of many different kinds of possible coil arrangements. For example, another
configuration may include positioning measurement coils C2 and C3 on either side of
drive coil CI (located in the center). According to another example, a single coil such
as coil CI may be utilized to both generate the primary magnetic field (Bl) and
receive a net magnetic field (B2) generated as a result of eddy currents induced by the
primary magnetic field (Bl).
The output from BP filters 106a and 106b are coupled to the differential inputs of
differential amplifier 108. When no defects are present on surface 122, the filtered
inputs received from the BP filters 106a, 106b at the differential inputs of the
differential amplifier 108 are substantially the same. Consequently, the differential
amplifier 108 generates an output voltage of low signal amplitude close to zero.
Alternatively, if defects are present on surface 122, the filtered inputs received from
the BP filters 106a, 106b at the differential inputs of the differential amplifier 108 are
not the same. Consequently, the differential amplifier 108 generates an increased
output voltage. As one of the measurement coils (i.e., C2 or C3) moves over a pitted
area (due to corrosion), the reactive component of this coil (e.g., C2) changes relative
to the other coil (e.g., C3). This in turns causes a differential change in signal current
that is applied to the differential amplifier 108 and, thus, an increase in output voltage.
The amplitude of the generated output signal may depend on several factors such as,
but not limited to, the geometry of the pit (e.g., 0.3x0.45 millimeters), the sensitivity
of the measurement coils to changes in eddy-current-induced magnetic fields caused
by the pit, and the optimization of the electrical drive parameters associated with the
coil driver 102 (e.g., waveform, amplitude, and frequency of the signal driving the
primary coil). The generated output signal may be converted from an analog to a
digital format by A/D convertor 110 prior to being processed at the signal processing
device 112. Alternatively, the analog to a digital conversion may be performed within
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the signal processing device 112 without the need for a separate device such as A/D
convertor 110.
The signal processing device 112 provides various processing on the digitized
amplitude signals output from the differential amplifier 108. For example, the signal
processing device 112 may perform threshold detection in order to determine whether
the detected amplitude constitutes an amplitude signal caused by the detection of a
corrosion pit. Signal processing device 112 also accesses reference data from the
reference data storage medium 114 in order to correlate the received amplitude signal
with existing reference data (e.g., various digitized amplitude values) entered in the
reference data storage medium 114. Each reference data entry found within reference
data storage medium 114 may optionally provide information associated with a
corrosion pit having a specific geometry and/or dimension. Alternatively, the
accessed reference data may confirm the presence or absence of a corrosion pit based
on the degree of amplitude correlation between a received amplitude signal (i.e.,
digitized) and various amplitude values (i.e., digitized) entered in the reference data
storage medium 114 without providing geometry and/or dimension information.
Additional digital signal processing (DSP) such as digital filtering and equalization
may also be carried out on the received amplitude signals in order to further aid the
detection of corrosion pits.
The detection indicator 118 alerts a user of the probe device 100 once it has been
determined that a corrosion pit has been detected. The detection indicator 118 may
comprise a visual indicator such as a light emitting device (e.g., LED) and/or an audio
indicator such as a buzzer.
The signal log storage medium 116 stores data information associated with each
detected corrosion pit. Once the signal processing device 112 confirms the detection
of a corrosion pit, it stores the detected amplitude value along with time-stamp
information within the signal log storage medium 116. The time-stamp may comprise
date (e.g., year/month/day) and time (e.g., 24 hour clock) information associated with
each detected corrosion pit, which may, among other uses, provide a means for
calculating the different time intervals between the different occurrences of detecting
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corrosion pitting in the gas turbine rotor blades. The signal log storage medium 116
may also store drive signal information corresponding to each of the detected
amplitude values and time-stamp information. The stored drive signal information
may include the amplitude characteristics, shape, and frequency of the signal applied
to primary coil CI based on the detection of a corrosion pit.
Although FIG. 1A illustrates a separate reference data storage medium 114 and signal
log storage medium 116, both storage mediums (i.e., 114 and 116) may be integrated
within the signal processing device 112.
FIG. IB illustrates the position of an EC probe detection head 126 relative to surface
120 under inspection in accordance with an embodiment of the present invention. As
shown, the primary coil device CI, along with measurement coils C2 and C3 (not
shown in FIG. IB), is located within the probe detection head 126. In operation, the
probe head detection 126 is contactively applied to the surface 120 under inspection
(e.g., an Rl rotor blade). The distance between Coil CI and surface 120 is called liftoff,
which affects the mutual inductance of the coils. In the example shown in FIG.
IB, the lift-off may be in the range of 0.2-0.4 millimeters (mm). The distance
between coil end 128 and surface 120 may be about 0.2 mm. In addition, outersurface
130 of probe detection head 126 may comprise an additional protective layer
(not shown) having a thickness of about 0.2 mm (e.g., 0.2 mm of PTFE adhesive
tape).
FIGS. 2A-2C illustrate the mechanical construction and relative positioning of an EC
probe device 202 relative a gas turbine system rotor blade under inspection in
accordance with an embodiment of the present invention. As shown in FIG. 2A, the
EC probe device 202 comprises a probe detection head 204, a probe stem 206, and a
probe guide 208 or extended handle. In FIG. 2A, the size of the probe device 202
relative to rotor blades 210a, 210b, and 210c is exaggerated for aiding the illustrative
process. For example, the length of the probe head 204 relative to the length of the
filet section 214 of each of the rotor blades is around 1/6. The length of the probe
guide 208 may be in the region of 30 centimeters (cm), while the probe stem may
have a length of about 5 cm.
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The axis of the probe guide 208 may be substantially perpendicular to the axis of the
probe stem 206, whereby the probe guide 208 facilitates the manipulation of the probe
device 202 into measurement position such that physical contact is established
between the probe head 204 and the filet section 214 of rotor blade 210a. This is also
illustrated with the aid of the expanded view of region 205 shown in FIG. 2B.
As shown in FIG. 2B, the filet region 214 of rotor blade 210a is a region located
between platform 224 and airfoil 226. The filet region of the rotor blades are of
particular interest in detecting corrosion pitting according to the described
embodiments of the present invention. During corrosion pitting detection, the probe
head 204 is manipulated to contactively slide along the length of the filet 214 between
filet, edge 218a and 218b in the Z direction. During this sliding motion, the angle
between the axis of the probe stem 206 and horizontal plane is kept relatively
constant. The probe head 204 is manipulated to contactively slide along the length of
the filet 214 multiple times. Each time, the probe stem 206 is rotated in the XY plane
in order to form a new angle between the axis of the probe stem 206 and the
horizontal plane. By changing the angle, the primary coil device CI induces a
primary magnetic field (Bl) in a different area of the filet 214. By contactively
sliding the probe head 204 along the length of the filet 214 at different angles,
corrosion detection measurements covering the entire filet region is facilitated.
This angular variation in the probe stem 206 is illustrated in the cross sectional view
of the rotor blade 210a depicted in FIG. 2C. According to the example shown in FIG.
2C, during the corrosion detection measurements, the probe stem is rotated in the XY
plane to form three angles between the axis of the probe stem 206 and horizontal
plane 230. More specifically, firstly, the probe head 204 is manipulated to
contactively slide along the length of the filet 214 at an angle of 15 degrees, as
defined by 232. Second, the probe head 204 is manipulated to contactively slide
along the length of the filet 214 a second time at an angle of 45 degrees, as defined by
234. Finally, the probe head 204 is manipulated to contactively slide along the length
of the filet 214 at an angle of 75 degrees for a third and final time, as defined by 236.
15
The number or slides and angles utilized during detection measurements can be
varied. However, once a corrosion pit is detected, the probe head 204 is manipulated
to contact that particular corrosion affected area. Once in the corrosion affected area,
the angle between the axis of the probe stem 206 and horizontal plane 230 can be
varied to determine whether other corrosion pits are also present in that particular
section of the filet 214.
FIG. 3 illustrates an imaging device 302 used in cooperation with an EC probe device
304 in accordance with an embodiment of the present invention. The imaging device
302 (e.g., video camera) may be located in proximity to the probe device's 304 probe
detection head 306 for the purpose of providing the user of the device 304 with an
enhanced visual view of the filet portion 310 of the rotor blade 312 under inspection.
The captured images may be displayed to the user on a handheld or portable video
monitor 314.
FIG. 4 illustrates a photographic image of a calibration block 402 used in the
generation of the reference data that is stored in the reference data storage
medium 114 (FIG.l) according to an embodiment of the present invention. The
calibration block comprises a plurality of pre-generated corrosion pitting areas 404,
406, 408 that are created on a sample filet surface 310 using electrical discharge
machining (EDM). The illustrated example shows several pre-generated corrosion
pitting areas 404, 406, 408 each having different diameters and depths that have been
accurately formed on the sample filet surface 310 using EDM. Pre-generated
corrosion pit area 404 includes a diameter of 0.25 mm and a depth of 0.25 mm. Pregenerated
corrosion pit area 406 includes a diameter of 0.50 mm and a depth of 0.50
mm. Also, pre-generated corrosion pit area 408 includes a diameter of 0.75 mm and a
depth of 0.75 mm. As defined at 414, an expanded view of pre-generated corrosion
pit 406 is provided.
When an EC probe device such as device 100 (FIG. 1) performs a corrosion pit
measure on the pre-generated corrosion pitting areas 404, 406, 408, each
measurement will generate a specific signal amplitude that corresponds to each of pregenerated
corrosion pitting areas 404, 406, 408. Therefore, each amplitude correlates
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with a particular corrosion pit having a know geometry. These signal amplitudes and
their corresponding geometries may form at least some of the reference data that is
stored. In this manner signal amplitudes that are generated during field tests can be
correlated with the reference data in order to determine the existence of corrosion
pitting. Optionally, the approximate geometry of any detected corrosion pit may also
be provided.
FIG. 5 illustrates an operational flow diagram 500 associated with EC probe device
100 (FIG. 1) according to an embodiment of the present invention. Flow diagram 500
is described with the aid of FIGS 1 and 2. At step, 502, a user accesses the inlet guide
veins (IGVs) and the Rl rotor blades located directly behind the IGVs using an
opening in the intake plenum at the front of the compressor mouth (i.e., bell mouth) of
a gas turbine.
At step 504, a probe detection head having a radius of curvature less than or
substantially the same as the filet section of the Rl rotor blades under inspection is
selected. For example, radius R (FIG. 2B) of the probe detection head 204 (FIG. 2B)
is designed to be slightly less than the radius of curvature of the filet section 214
(FIG. 2B).
At step 506, the probe head 204 is applied to the first edge 218a (FIG. 23) of the filet
214. At step 508, the angle between the probe stem 206 (FIG. 2B) and the horizontal
plane 230 (FIG. 2C) is then set at a relatively constant value of around, for example,
15 degrees, as defined at 232 (FIG. 2C).
At step 510, the drive coil CI (FIG. lA) within the probe head 204 applies a primary
magnetic field to the area corresponding to the first edge 218a (FIG. 2B) of the filet
214. Using the measurement coils C2, C3 (FIG. lA) within the probe head 204, a
second magnetic field is detected based on the current induced in the conductive
surface of the first edge 218a (FIG. 2BJ area of the filet 214 (step 512). Based on the
received second magnetic field by coils C2 and C3, an amplitude signal may be
generated and processed by the differential amplifier 108 (FIG. lA) and the signal
processing device 112 (FIG. 1 A) on the basis of a detected corrosion pit (step 514).
17
At step 516, it is determined whether the probe head 204 has reached the second edge
218b (FIG. 2B) area of the filet 214. If (YES) the probe head 204 has reached the
second edge 218b (FIG. 2B) area (step 516), it is determined whether the
repositioning of the probe angle between the probe stem 206 (FIG; 2B) axis and the
horizontal plane 230 (FIG. 2C) has been completed (step 520). For example, if the
probe head 204 is operated using three angles of 15, 45, and 75 degrees, the
repositioning is completed if measurements are carried out for all three angles of 15,
45, and 75 degrees. If (YES) repositioning is completed (step 520), the process of
operational flow diagram 500 is repeated for another Rl rotor blade (step 524).
If (NO) repositioning is not complete (step 520), the probe angle between the probe
stem 206 (FIG. 2B) axis and the horizontal plane 230 (FIG. 2C) is changed to the next
desired angle (step 522). For example, if the probe head 204 is operated using three
angles of 15, 45, and 75 degrees, and the current angle is 15 degrees, the probe is then
manipulated to the next angular setting to form a 45 degree angle. Following step
522, process steps 506, 508, 510, 512, 514, and 516 are then repeated.
If (NO) at step 516, the probe head 204 has not reached the second edge 218b (FIG.
2B) area, the probe head 204 is applied to another section of the filet 214 by sliding
along the Z axis (FIG. 2B) direction of the filet 214 (step 518). Following step 518,
process steps 510, 512, 514, and 516 are repeated.
FIG. 6 shows an operation flow diagram 600 for the signal processing performed by
the EC probe device 100 (FIG. lA) in detecting a corrosion pit according to an
embodiment of the present invention. At step 602, a net magnetic field is detected by
measurement coil C2 (FIG. lA). Similarly, at step 604, a net magnetic field is also
detected by measurement coil C3 (FIG. lA). The net magnetic field is a fijnction of
the interaction between the primary magnetic field generated by coil CI (FIG. lA)
and the magnetic field generated by the eddy-currents induced in the conductive
surface of the filet 214 (FIG. IB).
At step 606, the differential amplifier 108 (FIG. lA) generates a signal amplitude
when a different net magnetic field is experienced between measurement coils C2 and
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C3. For example, if measurement coils C2 and C3 are receiving a net magnetic field
from the surface of the filet 214 having no corrosion pits, the current magnitude
induced in both measurement coils will be substantially the same. Thus, the
differential amplifier 108 will not generate a signal exhibiting an increase in
amplitude. However, if measurement coil C2 receives a net magnetic field from an
area of the filet 214 where there is a corrosion pit, the corrosion pit will disrupt the
flow of eddy-currents in that area such that the net magnetic field detected by coil C2
changes relative to the net magnetic field detected by coil C3. Under these
conditions, the differential amplifier 108 will generate a signal exhibiting an increase
in amplitude.
At step 608, it determined whether the signal generated by the differential amplifier
108 exceeds a predetermined threshold value. This threshold detection is carried out
within signal processing device 112. If (NO) the signal generated by the differential
amplifier 108 fails to exceed the predetermined threshold value, process steps 602,
604, and 606 are repeated. If (YES) the signal generated by the differential amplifier
108 exceeds the predetermined threshold value (step 608), additional signal
processing (e.g., digital filtering, equalization, etc.) may be carried out within signal
processing device 112 (Step 610).
At step 612, the signal processing device 112 accesses the reference data storage
medium 114 in order to utilize the stored reference data. As previously described, the
stored reference data may include premeasured amplitude values that correspond to
various pre-generated corrosion pits. Using the accessed reference data, the signal
processing device 112 correlates the detected amplitude signal generated by the
differential amplifier 108 with one of the premeasured amplitude values of the
accessed reference data (step 614).
Based on the correlated premeasured amplitude value, data information (e.g.,
corrosion pit geometry) associated with the detected corrosion pit may also be
accessed from the reference data storage medium 114 using the signal processing
device 112 (step 616). Data information (e.g., time-stamp data, pit geometry data,
19
etc.) associated with the detected corrosion pit may then be logged by the signal
processing device 112 in the data log storage medium 116 (step 618).
FIG. 7 illustrates experimental performance data associated with determining the
operating parameters of an EC probe device such as EC probe device 100 (FIG. lA)
according to an embodiment of the present invention. Graph 702 shows the
repeatability of measurements carried out by an EC probe operated over a frequency
range of 100-600 KHz. The frequency range applies to frequencies used to drive the
primary coil of the EC probe under evaluation. As shown, frequencies in the range of
300-400 KHz desirably provide relatively the same measurement repeatability (e.g.,
detected amplitude values).
Graph 704 shows a measure of standard deviation associated with the detected signal
amplitudes over a frequency range of 100-600 KHz. As shown, frequencies in the
range of 300-400 KHz also provide a relatively constant standard deviation for the
amplitude values detected by the EC probe.
Graph 706 shows a measure of signal-to-noise (S/N) ratio associated with the detected
signal amplitudes over a frequency range of 100-600 KHz. As shown, in relation to
the amplitude values detected by the EC probe, frequencies in the range of 300-400
KHz also exhibit the highest S/N ratios. Therefore, using such experimental
evaluations, a suitable range of operating frequencies (e.g., 300-400 KHz) may be
determined for a particular EC probe device.
It may be possible to incorporate several EC probe devices into a single unit in order
to conduct measurements over an increased surface area of a filet section. In such a
configuration, a multi-channel EC probe device may be provided, where each channel
accesses measurement data. For example, a three channel device may be utilized.
Such examples are shown in Fig. 8. According to one embodiment, a multi-channel
probe device 800 may include three discrete probe devices 802 that are configured
such that their respective probe detection heads are coupled to each other to form a
longitudinally enlarged probe head 804. Each discrete probe device 802 constitutes a
single channel and may, for example, comprise the same design as EC probe device
20
100 (FIG. lA). According to another embodiment, a multi-channel EC probe 810
may comprise a single probe head 812 incorporating multiple coil systems 814a-814n,
whereby each coil system may, for example, include the same configuration as coil
system 104 (FIG. lA). The stem 820 of multi-channel EC probe 810 may house a
signal multiplexer (not shown) that sequentially reads received signals from each coil
system 814a-814n. The processing of the received signals may be carried out using
either an individual processing device (e.g., device 112, FIG.IA) or a parallel
processing approach incorporating multiple processing devices (e.g., muhiple devices
112, FIG.IA). It will be appreciated that a myriad of different processing
architectures may be employed in the accessing and processing of multiple charmels.
The present invention has been illustrated and described with respect to specific
embodiments thereof, which embodiments are merely illustrative of the principles of
the invention and are not intended to be exclusive or otherwise limiting embodiments.
Accordingly, although the above description of illustrative embodiments of the
present invention, as well as various illustrative modifications and features thereof,
provides many specificities, these enabling details should not be construed as limiting
the scope of the invention, and it will be readily understood by those persons skilled
in the art that the present invention is susceptible to many modifications, adaptations,
variations, omissions, additions, and equivalent implementations without departing
from this scope and without diminishing its attendant advantages. For instance,
except to the extent necessary or inherent in the processes themselves, no particular
order to steps or stages of methods or processes described in this disclosure, including
the figures, is implied. In many cases the order of process steps may be varied, and
various illustrative steps may be combined, altered, or omitted, without changing the
purpose, effect or import of the methods described. It is further noted that the terms
and expressions have been used as terms of description and not terms of limitation.
There is no intention to use the terms or expressions to exclude any equivalents of
features shown and described or portions thereof Additionally, the present invention
may be practiced without necessarily providing one or more of the advantages
described herein or otherwise understood in view of the disclosure and/or that may be
realized in some embodiments thereof It is therefore intended that the present
21
invention is not limited to the disclosed embodiments but should be defined in
accordance with the claims that follow.

WE CLAIM:
1. A probe device for detecting corrosion in one or more blades of a gas turbine
system, the device comprising:
(a) a detection head having a shape that conforms to a surface geometry of a filet
section of a gas turbine blade, the detection head operable to move along the axial
length of the filet section for detecting corrosion pitting;
(b) at least one coil device located within the detection head and operable to
induce a first magnetic field within an area of the filet in contact with the detection
head;
(c) a receiver device operable to detect a signal corresponding to a second
magnetic field received from the area of the filet exposed to the first magnetic field,
wherein the second magnetic field is generated by induced currents in the area by the
first magnetic field; and
(d) a signal processing device operable to process the detected signal for
correlating a corresponding amplitude of the detected signal with the presence of
corrosion pitting in the area,
wherein the presence of corrosion pitting is determined without any casing
disassembly of the gas turbine system.
2. The device according to claim 1, wherein the receiver device comprises:
(a) a first and a second coil device operable to generate a first and a second
received signal from the second magnetic field, respectively;
(b) a first and a second band-pass filter device respectively coupled to the first and
the second coil device, wherein the first and the second band-pass filter device are
operable to filter the first and the second received signal, respectively; and
23
(c) a differential amplifier device coupled to the first and the second band-pass
filter device, wherein the differential amplifier is operable to differentially amplify the
filtered first and the filtered second received signal and generate the detected signal.
3. The device according to claim 1 or claim 2, wherein the detection head
comprises a substantially cylindrical shape including a radius that corresponds to a
curvature radius of the filet.
4. The device according to any preceding claim, wherein the detection head
comprises a substantially cylindrical shape including a radius that is less than or
substantially equal to a curvature radius corresponding to the filet.
5. The device according to any preceding claim, wherein the gas turbine blade
comprises one of a plurality of first stage Rl rotary blades located behind a plurality
of inlet guide vanes.
6. The device according to claim 5, further comprising a handle section coupled
to the detection head, the handle section including a flexible portion operable to move
the detection head into a measurement position by enabling contact between the
detection head and the filet section of the one of a plurality of first stage Rl rotary
blades based on manipulating the flexible portion and detection head between the
plurality of inlet guide vanes.
7. The device according to claim 6, fiirther comprising a video camera coupled
to the handle section, the video camera located in proximity to the detection head and
operable to assist an operator move the detection head into the measurement position.
8. The device according to any preceding claim, wherein the induced currents
comprise Eddy Currents.
9. The device according to any preceding claim, fiirther comprising a driver
device operable to generate a drive signal that is applied to the at least one coil device,
wherein the driver device manipulates at least one characteristic of the drive signal for
producing a signal-to-noise ratio associated with the detected signal that exceeds a
designated threshold.
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10. The device according to claim 9, wherein the at least one characteristic
comprises drive signal amplitude.
11. The device according to claim 9, wherein the at least one characteristic
comprises drive signal frequency.
12. The device according to claim 9, wherein the at least one characteristic
comprises a combination of drive signal amplitude and drive signal frequency.
13. The device according to any preceding claim, wherein the signal processing
device comprises a digital signal processing (DSP) device comprising:
(a) an analog-to-digital convertor operable to digitize the detected signal
amplitude;
(b) a first storage region operable to store an amplitude corresponding to the
detected signal with other stored detected signal amplitudes based on the amplitude
corresponding to the detected signal and the other stored detected signal amplitudes
corresponding to a detected corrosion pit;
(c) a second storage region operable to store reference data associated with a
plurality of pre-generated corrosion pitting areas created on a sample filet surface of a
gas turbine blade; and
(d) a processor section operable to compare the amplitude corresponding to the
detected signal with the stored reference data for determining the presence of
corrosion pitting in the filet section.
14. The device according to claim 13, wherein the first storage region comprises
time-stamp information that is added to both the amplitude corresponding to detected
signal and the other stored detected signal amplitudes for calculating a time interval
between the determination of corrosion pitting in the filet section.
15. The device according to claim 13, wherein the first storage region comprises
drive signal information that is added to the stored detected signal amplitude and the
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other stored detected signal amplitudes for assessing the determination of corrosion
pitting in the filet section.
16. A probe device for detecting corrosion in one or more blades of a gas turbine
system, the device comprising:
(a) a detection head having a shape that conforms to a surface geometry of a filet
section of a gas turbine blade, the detection head operable to move along the filet
section for detecting corrosion pitting;
(b) at least one transducer device located within the detection head and operable
to induce a first magnetic field within an area of the filet in contact with the detection
head;
(c) a receiver device operable to detect a signal corresponding to a second
magnetic field received from the area of the filet exposed to the first magnetic field,
wherein the second magnetic field is generated by induced currents in the area by the
first magnetic field; and
(d) a signal processing device operable to process the detected signal for
correlating a corresponding amplitude of the detected signal with the presence of
corrosion pitting in the area,
wherein the presence of corrosion pitting is determined without any casing
disassembly of the gas turbine system.
17. A probe device for detecting corrosion in one or more blades of a gas turbine
system, the device comprising:
(a) a detection head having a shape that conforms to a surface geometry of a filet
section of a gas turbine blade, the detection head operable to move along the filet
section for detecting corrosion pitting;
(b) a transceiver device located within the detection head and operable to induce a
first magnetic field within an area of the filet in contact with the detection head and
detect a signal corresponding to a second magnetic field received from the area of the
26
filet exposed to the first magnetic field, wherein the second magnetic field is
generated by induced currents in the area by the first magnetic field; and
(c) a signal processing device operable to process the detected signal for
correlating a corresponding amplitude of the detected signal with the presence of
corrosion pitting in the area,
wherein the presence of corrosion pitting is determined without any casing
disassembly of the gas turbine system.
18. The device according to claim 17, wherein the transceiver device comprises:
(a) a transmitter operable to generate the first magnetic field; and
(b) a receiver operable to receive the second magnetic field and generate the
detected signal amplitude.
19. The device according to claim 17 or claim 18, wherein the transmitter
comprises:
(a) a first coil device; and
(b) a coil driver operable to apply an electrical drive signal to the first coil device.
20. The device according to any of claims 17 to 19, wherein the receiver
comprises:
(a) a second coil device;
(b) a third coil device; and
(c) a differential amplifier coupled to the second and the third coil device and
operable to differentially amplify a second and a third signal received from the second
and the third coil device, respectively, wherein the differential amplifier generates the
detected signal.
27
21. The device according to claim 20, wherein the second and the third coil each
comprise:
(a) a coil diameter of about 1.6-2.0 millimeters;
(b) a cylindrical coil support;
(c) a coil frequency range of about 50-900KHz; and
(d) a coil signal to noise ratio of about 5/1.
22. A method of detecting corrosion in one or more blades of a gas turbine
system, the method comprising:
(a) detecting corrosion pitting along the axial length of a filet section of a gas
turbine blade by conforming the detecting to the surface geometry of the filet section;
(b) inducing a first magnetic field within an area of the filet during the detecting
of the corrosion;
(c) detecting a signal corresponding to a second magnetic field received from the
area of the filet exposed to the induced first magnetic field, wherein the second
magnetic field is generated by induced currents in the area by the induced first
magnetic field; and
(d) processing the detected signal by correlating a corresponding amplitude of the
detected signal with the presence of corrosion pitting in the area,
wherein the presence of corrosion pitting is determined without any casing
disassembly of the gas turbine system.
23. The method according to claim 22, fiirther comprising:
(e) imaging the gas turbine blade using an imaging device for facilitating the
detecting of corrosion pitting; and
(f) displaying the imaged gas turbine blade to user.
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24. The method according to claim 23, wherein conforming the detecting to the
surface geometry comprises using a probe head having a cylindrical shape that
includes a radius that is substantially the same as or less than a radius of curvature
associated with the filet section.
25. The device according to claim 1, wherein the at least one coil device
comprises a plurality of coil devices located within the detection head and operable to
each induce the first magnetic field within an area of the filet in contact with the
detection head;
wherein said detected signal comprises a plurality of signals corresponding to said
second magnetic field; and
wherein said signal processing device is operable to process the plurality of detected
signals for correlating corresponding amplitudes of the detected signals with the
presence of corrosion pitting in the area,
wherein each of the processed plurality of detected signals corresponds to a signal
channel associated with a respective one of the plurality of coil devices, thereby
providing for multi-channel detection of corrosion pitting.
26. The device according to any of claims 1 to 15, wherein the at least one coil
device comprises separate coils including:
(a) a first coil operable to generate the first magnetic field; and
(b) at least one other coil operable to receive the second magnetic field.
27. A corrosion pitting detection unit comprising a plurality of probe devices,
wherein each probe device includes:
(a) a detection head having a shape that conforms to a surface geometry of a filet
section of a gas turbine blade, the detection head operable to move along the axial
length of the filet section for detecting corrosion pitting;
29
(b) at least one coil device located within the detection head and operable to
induce a first magnetic field within an area of the filet in contact with the detection
head;
(c) a receiver device operable to detect a signal corresponding to a second
magnetic field received fi-om the area of the filet exposed to the first magnetic field,
wherein the second magnetic field is generated by induced currents in the area by the
first magnetic field; and
(d) a signal processing device operable to process the detected signal for
correlating a corresponding amplitude of the detected signal with the presence of
corrosion pitting in the area,
wherein the presence of corrosion pitting is determined without any casing
disassembly of the gas turbine system, and
wherein the results of the detected signal processed by each signal processing device
of the plurality of probe devices is output on a corresponding chaimel.