Evaluating Installation of Vibration Monitoring Equipment for Gas Turbines

Note: The source of the technical material in this volume is the Professional Engineering Development Program (PEDP) of Engineering Services.

Warning: The material contained in this document was developed for Saudi Aramco and is intended for the exclusive use of Saudi Aramcos employees. Any material contained in this document which is not already in the public domain may not be copied, reproduced, sold, given, or disclosed to third parties, or otherwise used in whole, or in part, without the written permission of the Vice President, Engineering Services, Saudi Aramco.

Chapter : Mechanical For additional information on this subject, contact File Reference: MEX-214.05 PEDD Coordinator on 874-6556

Engineering Encyclopedia Saudi Aramco DeskTop Standards

EVALUATING INSTALLATION OF VIBRATION MONITORING EQUIPMENT FOR GAS TURBINES

Engineering Encyclopedia Gas Turbines

Evaluating Installation of Vibration Monitoring Equipment for Gas Turbines

Saudi Aramco DeskTop Standards i

Section Page

INFORMATION ............................................................................................................... 3 INTRODUCTION............................................................................................................. 3 VIBRATION MONITORING EQUIPMENT ...................................................................... 5

VIBRATION MONITORING .................................................................................... 5 Basic Vibration ................................................................................................ 5 Transducers for Vibration Variables .............................................................. 12 Seismic Probes ............................................................................................. 19

TEMPERATURE MONITORING INSTRUMENTS ................................................ 23 Resistance Temperature Detector ................................................................ 23 Thermocouples ............................................................................................. 25

TYPICAL VIBRATION MONITORING ARRANGEMENTS............................................ 30 HEAVY-DUTY GAS TURBINES ........................................................................... 31

Vibration Monitoring ...................................................................................... 31 Temperature Monitoring................................................................................ 41

AERO-DERIVATIVE GAS TURBINES.................................................................. 43 Vibration Monitoring ...................................................................................... 43 Temperature Monitoring................................................................................ 44

GAS TURBINE THERMODYNAMIC PERFORMANCE MONITORING ........................ 45 COMPRESSOR DISCHARGE TEMPERATURE .................................................. 45 TURBINE INLET TEMPERATURE ....................................................................... 47 TURBINE EXHAUST TEMPERATURE................................................................. 48

GLOSSARY .................................................................................................................. 49



Saudi Aramco DeskTop Standards ii

LIST OF FIGURES

Figure 1. Basic Relationship of Measured Parameters with a Simple Harmonic

Motion ............................................................................................................ 9 Figure 2. Formation of a Complex Harmonic Signal........................................................ 9 Figure 3. Views from the Time and Frequency Domain ................................................ 10 Figure 4. Range and Limitations on Machinery Vibration Analysis Systems and

Transducers................................................................................................. 14 Figure 5. Eddy Current Proximity Probe........................................................................ 18 Figure 6. Velocity Transducer ....................................................................................... 20 Figure 7. Piezoelectric Accelerometer........................................................................... 21 Figure 8. Noncontact Eddy Current Probe Orientation.................................................. 34 Figure 9. API 670 Axial Position Probe Installation for a Shaft with an Integral

Thrust Collar ................................................................................................ 37 Figure 10. API 670 Standard Axial Position Probe Installation Arrangement ................ 38 Figure 11. Typical Vibration and Axial Position System Arrangement for a Heavy

Duty Gas Turbine......................................................................................... 40 Figure 12. Oil Drain Line Thermocouple Installation...................................................... 42

LIST OF TABLES

Table 1. Advantages, Disadvantages, and Useful Ranges of Transducer Types.......... 13



Saudi Aramco DeskTop Standards 3

INFORMATION

INTRODUCTION A vibration, axial-position, and bearing-temperature monitoring system consists of probes, accelerometers, and temperature sensors; signal conditioning devices, interconnecting cables, power supplies, monitors, and communication devices. As defined by Saudi Aramco Engineering Standard SAES-J-604, the Vibration, Axial Position and Bearing Temperature Monitoring System will be referred to simply as the Vibration Monitoring System.

For heavy duty, industrial gas turbines, vibration and axial position information is acquired by transducers and proximity probes positioned at optimal locations on a gas turbine. Transducers convert mechanical responses to electric signals that are conditioned and processed by electronic instruments.

For aero-derivative gas turbines, accelerometers measure casing vibration and supply signals to dedicated filters that continuously read 1 (running speed) vibration for each rotor, and they can supply a frequency versus amplitude spectrum when required. Axial displacement is not monitored since the axial float is restricted by an anti-friction thrust bearing.

Gas turbine bearing temperature information is acquired by temperature detectors positioned at the bearings.

The vibration monitoring system provides the information necessary to monitor gas turbine condition and to diagnose faults. Vibration monitoring systems provide the electrical signals to the Rotating Machinery Protection System (RMPS) and the condition monitoring system. The RMPS automatically sends shutdown commands to the turbine control system if a turbine vibration, axial position, or monitored temperature exceeds a specified limit. The condition monitoring system is a computer-based data collection system that communicates directly to the vibration monitoring system. The condition monitoring system will also accept process data from communication links to the Distributed Control System (DCS) or directly from process instruments. The condition monitoring system collects, stores, processes, displays and prints the gas turbine operating data in a variety of formats. The condition monitoring system data will typically be used for historical trending, machinery diagnostics, and predictive maintenance purposes but not for shutdown protection.




Additional temperature measuring instrumentation outside of the scope of the vibration monitoring system is used for monitoring and protection of the gas turbine. This instrumentation includes measurement of gas turbine compressor discharge temperature, turbine exhaust temperature, and wheelspace temperatures.

This module describes the types of vibration monitoring system equipment that are used for gas turbines and the installation arrangements that are used at Saudi Aramco installations.




VIBRATION MONITORING EQUIPMENT This section of the manual describes the following processes and the equipment that are used for condition monitoring:

Vibration Monitoring Temperature Monitoring

Vibration Monitoring Vibration monitoring is a monitoring method and process. Vibration monitoring measures the condition of the machine from the initial vibration signature after installation and then at periodic intervals throughout the machines life. This monitoring method and process enables an accurate accrual or trend of information by which problems may be diagnosed at an early stage.

Because vibration is the most sensitive and accurate of the indicators that are used for monitoring machinery condition, the information from the vibration sensors is typically used to prevent unscheduled downtime and/or equipment failure. Saudi Aramco requires automatic vibration shutdown at preset levels on all critical equipment. Vibration sensors can identify a machinery defect earlier than can other types of sensors, and they can also be used to pinpoint the specific source or machinery component that is defective; therefore, vibration analysis is frequently used in predictive-maintenance programs to provide the basic guidance for performance of maintenance and overhauls.

Basic Vibration

Vibration is the back and forth motion across a point of equilibrium. Rotating equipment vibration is usually periodic, that is, it is related in some manner to the action of the rotating element. At times, there are nonperiodic vibrations in rotating equipment, but such vibrations are normally from external sources. The vibration motion is described by the variables of frequency, displacement, velocity, and acceleration.

The terms and expressions that are used in this discussion of vibration monitoring are presented in the text that follows.




Vibration is defined as the oscillation of an object about its position of rest. When the mass of an object is set in motion, it will move back and forth between some upper and lower limits. This movement of the mass through all of its positions and back to the point where it is ready to repeat the motion is defined as one cycle of vibration. The time that it takes to complete this cycle is the period of vibration.

Frequency is the number of cycles in a given time period. Frequency is occasionally stated in cycles per minute (cpm) or cycles per second (cps), and it is also referred to as hertz (Hz). More frequently, however, frequency is expressed in multiples of rotative speed of the machine because of the tendency of machine vibration frequencies to occur at direct multiples or sub-multiples of the rotative speed of the machine. Frequency of vibration is expressed in terms as one times rpm, two times rpm, or 43 percent of rpm, rather than being expressed in terms of cycles-per-minute or hertz. Frequency is one of the basic characteristics that is used to measure and describe vibration. The force that causes the vibration is the first event that occurs in time. The responses to these forces are the other basic characteristics or movements, such as displacement, velocity, and acceleration. The magnitude of each of these characteristics describes the severity of vibration.

The magnitude, or severity, is described by the amplitude of the movement. Amplitude of vibration on most heavy-duty, industrial gas turbines is expressed in peak-to-peak mils while vibration on aero-derivative and smaller industrial gas turbines is measured by accelerometers. Signals from accelerometers are typically integrated to read in inches per second with typical allowable values less than 0.35 inches per second zero to peak. Vibration probes that are mounted near bearings or on casings can sense the maximum excursion (amplitude) of the shaft or the high frequency casing vibrations. A normal operating gas turbine will generally have a stable amplitude reading of an acceptable low level less than 2.0 mil (50 microns). Any change in this amplitude reading indicates a change of the machine condition. Increases or decreases in amplitude should be considered justification for further investigation of the particular machine condition.




Phase, or phase angle, is another characteristic of vibration that is important to diagnose and correct machinery problems. Phase angle is used to compare the motion of a vibrating part to a fixed reference or to compare two parts of a machine structure that vibrate at the same frequency. Phase angle can be defined as the angular difference at a given instant between two parts with respect to a complete vibration cycle. Phase angle is usually expressed in degrees. The phase angle measurement is a means of describing the location of the rotor at a particular instant in time. Phase angle is also valuable in determining the rpm location of the natural rotor balance resonance or critical speeds. Furthermore, a good phase angle measuring system will define the location of a high spot on the rotor at each transducer location relative to some fixed point on the machine train. Through determination of these high spot locations on the rotor, the amount and the locations of the residual unbalances on a rotor can be determined. Changes in the balance condition of a rotor may cause a change in phase angle. Accurate phase angle measurements are important in the balancing of rotors, and they can be extremely important in the analysis of a particular machine malfunction. Determination of phase angle requires use of portable analysis or of the computer-based condition monitoring systems.

In measurements of radial vibration with displacement probes, amplitude of displacement is labeled peak-to-peak displacement and is measured in units of mils peak to peak.

Velocity indicates the speed at which the object is vibrating. It is highest where the object passes through its position of rest, and it is zero at the upper and lower maximum displacement limits of a harmonic vibration. The maximum value is usually the value that is recorded when measurements are taken. Velocity is measured in units of inches per second peak. Saudi Aramco standards specify Root mean square (rms) for velocity measurements. Velocity is usually the best parameter for machinery-vibration analysis, particularly where important frequencies lie in the 600 to 60,000 cpm range (low and mid frequencies). Velocity is always used to monitor antifriction (ball and roller) bearing systems. Velocity is also the best method for detecting a wide variety of different machinery defects that occur at low, mid, and high frequencies. Displacement primarily senses low-frequency problems, and acceleration primarily senses high-frequency defects.




The acceleration of the object is related to the forces that cause the vibration. Acceleration reaches a maximum value as the object reaches its maximum limits of displacement or when it begins to move in the opposite direction. The maximum or peak acceleration that is measured is usually the recorded value. Acceleration is measured in units of g peak (1 g = 386 in/sec2) or rms. Acceleration monitors are typically used to monitor antifriction (ball and roller) bearing systems; however, because of their large range, they are also used to monitor other sources of vibration.

Simple harmonic motion provides an illustration of the relationship between displacement, velocity, and acceleration. In simple harmonic motion, vibration occurs at a single frequency, with acceleration being proportional to displacement and occurring in a direction opposite to displacement. Simple harmonic motion can be represented by a sine wave, and it can be illustrated as the linear vertical motion of a weight that is suspended or supported on a coiled spring. The displacement of the weight below and above its point of rest and its return to the point of rest, as a function of time, is the frequency variable. The change in the amount of displacement as a function of time is the velocity variable. During a single cycle, this velocity constantly changes from a value of zero at the peak displacement above and below the rest or equilibrium point, to a maximum velocity value as the weight passes through the equilibrium point at zero displacement. The rate of change in the velocity is the acceleration variable. The acceleration variable is a negative value as the velocity slows down and the displacement approaches maximum.




The phase relationships between the variables for vibration measurement (displacement, velocity, and acceleration) are shown on a simple sine wave in Figure 1.

Figure 1. Basic Relationship of Measured Parameters with a Simple Harmonic Motion

Typical vibration signatures are not as simple as a single sine wave. Most machinery vibration consists of complex harmonic signals. A complex harmonic signal can be described as many sine waves mixed together. Figure 2 shows a basic example of a complex harmonic signal that consists of two pure sine waves. The upper sine wave is four times the frequency and one-fourth the amplitude of the lower sine wave. The resulting complex harmonic signal results when the two sine waves are mixed together.

Figure 2. Formation of a Complex Harmonic Signal




The vibration signals shown in Figures 1 and 2 are shown as amplitude verses time, which is also known as the time domain. Amplitude is on the vertical axis, and time is on the horizontal axis. If a vibration transducer is connected to an oscilloscope, the oscilloscope display is in the time domain. Another method to view vibration signals is to plot the amplitude verses the frequency, which is called the frequency domain. Figure 3 shows the same two sine waves that were previously shown in Figure 2, but it shows them as a three-dimensional plot illustrating the views from the time and frequency domain.

Figure 3. Views from the Time and Frequency Domain




The French mathematician, Jean Babtiste Fourier, discovered that all complex harmonic signals can be broken down into a series of simple sine waves by means of a mathematical method. The mathematical method can be used to break down periodic signals into discrete waves (sine waves, square waves, and triangular waves) as long as the waves repeat themselves. An FFT spectrum analyzer takes a complex waveform from a vibration transducer, calculates, by means of Fouriers mathematical method, the discrete waves that form that signal, and displays the individual waves in the frequency domain. Through digital technology, the process has been made fast, leading to the term fast Fourier transformation or FFT.

In addition to sine waves, which are pure tones, there are random vibrations. Random vibrations look similar to a complex vibration signal except that the vibrations do not repeat regularly or on a cycle. It is difficult to assign a frequency to random vibrations. Random vibrations can occur in gas turbines when the moving gas encounters stationary objects, such as stage nozzles, which create vortices and turbulence. Shock waves in transonic compressor stages and friction can also cause random vibrations.

In rotary equipment, mechanical sources of vibration such as rotor unbalance, misalignment, critical speeds, associated gearing, and looseness in parts, are only partially responsible for any vibration. Process-type sources that also contribute to vibration may come from the high velocity and turbulence of the air flow through the ducting, the compressor and gas flow through the exhaust, and vibration sources from the driven equipment.




Transducers for Vibration Variables

There are two general applications for vibration sensors that are used on rotating equipment. Both applications are used by Saudi Aramco.

One application is used to detect the actual vibrations of the rotating shaft within a hydrodynamic radial bearing and to provide a signal to the appropriate monitoring equipment. Saudi Aramco uses a noncontacting proximity sensor for the detection part of the vibration system in this type of application. Noncontacting proximity sensors are used for most large (greater than 10 MW) gas turbines.

The second application is used to detect the effects of the rotating element vibrations on the static equipment casing and/or bearing housings. The seismic-type sensor is used in this application, and it is directly mounted on the surface of the body to be monitored. When antifriction bearings are used in a machine, the seismic sensor gives a good indication of rotor motion because antifriction bearings have essentially zero clearance, and the dynamic force of rotor vibration is directly transmitted to the bearing bracket through the bearings. Seismic sensors are used for all aero-derivative gas turbines and for small-to-medium-sized industrial gas turbines (less than 10 MW).

Vibration information is acquired through the use of transducers that are strategically located in various positions on the gas turbine or the auxiliary equipment. The vibration transducers convert the mechanical motion of the equipment to an electrical signal that is sent to a monitoring/control unit. Table 1 describes the advantages, the disadvantages, and the useful ranges of the transducer types. The selection and positioning of the proper transducers are discussed later in various parts of this module.




Transducer Type

Useful Frequency

Range

Measure- ment Advantages Disadvantages

Radial shaft vibration transducer

0-1 kHz Displacement Sensor observes shaft directly

Senses surface imperfections

Conductive parts only

Mounting difficulty

Frequency limits

Velocity pickup 1-4 kHz Velocity Self-generating

Good indicator of machine condition

Hand-held

Moving parts

Large

Senses EMFs

Frequency limits

Accelerometer With acceleration output = 10-

20 kHz

With velocity output = 2.5-

20 kHz

Acceleration High frequency capability

Rugged

Small size

Temperature limits

Table 1. Advantages, Disadvantages, and Useful Ranges of Transducer Types

Figure 4 shows the range and the limitations on machinery vibration analysis systems and transducers. The acceleration line shows that the signal strength (vibration amplitude) is low at low frequencies. The displacement line shows that displacement probes have a low signal strength at high frequencies, but the frequency response of displacement probe is flat at frequencies where signal strength is good. The velocity sensor line indicates that the signal strength is good throughout a range of frequencies, but frequency response rolls off at high or low frequencies.




00.1

0.1

1.0

10

100

1 10 100 1000 10,000 100,000

Figure 4. Range and Limitations on Machinery Vibration Analysis Systems and Transducers

Displacement Probes - Displacement is generally the best parameter to use for very low-frequency measurements (i.e., less than 600 cpm) in which velocity and acceleration amplitudes are extremely low. Displacement is traditionally used for machinery balancing at speeds up to 10,000 or 20,000 rpm, and it should also be used where stress levels or clearances are the important criteria. Displacement probes are available for a variety of applications, and they are sometimes referred to as transducers. Saudi Aramco uses noncontacting proximity systems for displacement probes.




The noncontacting proximity systems, as used by Saudi Aramco, have the following basic applications that are related to the proximity probe installations: radial to the rotating shaft, axial to the rotating shaft, shaft speed, and phase reference. Regardless of the application, the same types of proximity systems are used. Each type consists of the noncontact proximity probe that is connected with a precise impedance cable to an oscillator/demodulator unit, which is also known as a proximitor. Typically, the outputs from the proximitors that are mounted on a single piece of equipment are instrument wired to a common plug-in module installed in a rack that houses plug-in modules for one or more than one machine train.

Noncontacting Proximity Sensor Probes - Noncontacting proximity sensor probes do not contact the rotating element; however, they are rigidly positioned so that the probe tip is in close proximity to the rotating surface. The sensor measures the gap between the probe tip and the surface. Such measurement makes the sensor very suitable to detect and to measure the radial displacement of the shaft within its radial bearing. A number of different types of proximity probes are made that operate on different principles to achieve basically the same result. The following are types of proximitors:

Optical Light Proximity Probe Inductance Proximity Probe Capacitance Proximity Probe Eddy Current Proximity Probe Although Saudi Aramco only uses the eddy current-type probes and some light proximity probes, a brief description of each type is presented below.

The optical proximity probe consists of a light source, a two-way light-conducting fiber-optic lead and probe, and a photo-electric sensor. Light is conducted to the probe tip through use of half of a fiber-optic bundle. This light is directed at the surface of the rotating element. Light that is reflected back by this surface is conducted to the photo-electric sensor by the other half of the fiber-optic bundle, and it is converted to a voltage. The light intensity at the photo-sensor is proportional to the gap between the sensed surface and the probe tip.

This system has high sensitivity, resolution, and frequency response, and the system can be used to observe any type of




surface that is reflective or that can be made reflective. However, industrial application is limited by the following two problems:

Circumferential variations in surface finish and reflectivity of most shafts cause significant noise and errors when observing rotating shafts.

Oil mist or process-fluid vapors may distort the light in the probe-to-shaft gap and cause noise and errors due to the variations in gap transmittance.

Due to the erratic responses, the optical proximity probe is used only as a phase reference transducer by Saudi Aramco.

The inductance proximity probe consists of a ferromagnetic core inside a coil of wire. A high frequency alternating current is supplied to the coil, which establishes an alternating magnetic field at the tip of the probe. The proximity of a metallic surface near the probe tip varies the strength of the magnetic field and changes the probe inductance, which modulates the amplitude of the high frequency alternating current.

The rotating element under the inductance probe tip does not have to be made of a magnetic material, but it must be conductive and magnetically permeable. The probe will not sense nonconducting materials; therefore, if the conducting material has a nonconducting coating applied to it, the probe will only respond to the underlying metal. Any defects or eccentricity of the underlying surface will cause noise and erratic false readings even though the actual finished shaft surface is running true. Because the probe calibration curves are relatively nonlinear and vary with different materials, the inductance proximity probe is not satisfactory for use on Saudi Aramco rotating equipment.




The capacitance probe is basically only one plate of a capacitor. The rotating element forms the other plate, and the air in the gap is the dielectric material. The variable capacitance of the probe is generally placed in the feedback loop of an operational amplifier with a high frequency ac excitation signal. Variations in the probe-to-shaft gap size vary the capacitance of this circuit element, which changes the excitation signal. The readout circuitry transforms this signal to a dc voltage that is proportional to the instantaneous gap.

The capacitance system offers the greatest accuracy, linearity, and freedom from drift and temperature effects of all the proximity systems. However, the capacitance system is not applicable for many industrial uses because the type of material in the probe-to-shaft gap affects the output signal. Water vapor that passes through the probe tip gap will change the dielectric and output signal or will short-circuit the output completely. When the rotating shaft is coated with dielectric materials, such as plasma-sprayed ceramics, the probe senses only the metallic substrate.

The eddy current probe consists of a small coil, usually a flat pancake shape, at the tip of the probe. A high-frequency ac (in the frequency range for radio transmission) is applied to this coil from an oscillator circuit. The proximity probe sets up a magnetic field in the gap between the end of the probe and the rotating shaft. In turn, the magnetic flux induces eddy current in the portion of the shaft that is exposed to this flux. Loss of energy in the returning signal is detected through use of the proximitor. Relative distance or displacement is measured between the probe tip and the surface by sensing the change in the gap. The eddy current probe is useful for gaps from about 10 to 120 mils (depending on dc voltage supplied to the probe), which is the approximate linear range of the eddy current probe. The sensitivity of most eddy current probes is 200 mV/1 mil. The demodulator circuit in the proximitor converts the amplitude-modulated ac to a varying dc signal (along a scale of 0 to -24V or 0 to -18 Vdc).




The eddy current type of noncontact proximity probe is shown in Figure 5.

Figure 5. Eddy Current Proximity Probe

The eddy current system is not affected by water vapor in the probe tip gap. The output signal provides an indication (in mV) of the varying gap between the sensor and the observed shaft surface.

The impedance of the probe to proximitor system is a critical item as the proximitors are tuned to a matching impedance in the connecting wire cable. Impedance matching prevents errors in measurement. Tuning is controlled through the use of only certain equivalent electrical lengths of cable that match the required impedance. During field installation, this cable length must never be cut to make an attractive installation. The excess cable should be rolled and neatly installed. If the cable length is changed, the system will require recalibration. If the system is ever replaced, it should be replaced with a cable of the same impedance or equivalent electrical length.




Seismic Probes

Seismic (mass-spring) transducers use the response of a mass-spring system to measure vibration. The seismic transducer consists of a mass that is suspended from the transducer case through the use of a spring of specific stiffness. The motion of the mass within the case may be damped by a viscous fluid, a spring, or an electric current. When the transducer case is contact mounted to the moving part, the transducer may be used to measure velocity or acceleration, depending on the frequency range of interest.

Velocity transducers are being used less by Saudi Aramco. Velocity measurements (usually required for all structural vibrations with the exception of high frequency gear mesh vibrations) are obtained through the use of an accelerometer with signal integration to velocity. This type of transducer configuration is sometimes called a piezoelectric velocity transducer.

Velocity Transducers - The velocity transducer is an adaptation from a voice coil in a speaker, and it is shown in Figure 6. There are two configurations of velocity transducers: stationary magnet/moving coil and stationary coil/moving magnet. Figure 6 represents a stationary magnet/moving coil configuration. The velocity transducer consists of an internal mass (in the form of a permanent magnet or coil) that is suspended on springs. A damping material, usually ribbon, surrounds the mass. A coil of wire or magnet is attached to the pickup case. The case is held against the vibrating object. The pickup case moves with the vibrating object while the internal mass remains stationary suspended on the springs. The relative motion between the permanent magnet and the coil generates a voltage that is proportional to the velocity of motion.




Figure 6. Velocity Transducer

The velocity transducer is self-generating and produces an output that can be fed to the monitoring system channel without any further signal conditioning. The raw (unfiltered) output signal from a velocity transducer can be transmitted to an oscilloscope or other analyzer instrument. The measurement processed from a velocity transducers output is a seismic measurement (referenced to inertial space). For this reason, a velocity transducer is also called a seismic transducer.




The velocity transducer has an internal natural frequency (referred to as mounted resonance) of about 8 Hz (those types that are used for machine monitoring). This natural frequency is simply the resonance of the single degree of freedom of the internal mass suspended on springs. The response at resonance is highly damped. The upper high frequency is limited to approximately 2.5 kHz. This transducer produces a linear output only above this resonant frequency.

Accelerometers - The most common acceleration transducer is the piezoelectric accelerometer, as shown in Figure 7. Accelerometers are used to measure the casing vibration of all aero-derivative gas turbines and some industrial gas turbines. The piezoelectric accelerometer consists of piezoelectric disks that are made of a quartz crystal (or barium titanate, an industrial ceramic) with a mass bolted on top and a spring that compresses the quartz. A piezoelectric material generates an electric charge (voltage) output when it is compressed.

Figure 7. Piezoelectric Accelerometer




In operation, the accelerometer base is contact mounted to the vibrating object and the mass wants to stay stationary in space. With the mass stationary and the base moving with the vibration, the piezoelectric disks get compressed and relaxed. In the most typically used compression-type models, the seismic mass and the base alternately exert compression in the piezoelectric discs. The piezoelectric disks generate a charge (voltage) output going positive and negative as the disks are alternately compressed tighter and relaxed. The charge output follows the motion of the surface in the direction of the accelerometers sensitive axis. The immediate millivolt output of this transducer is proportional to the acceleration of the vibrating subject; if the acceleration level is high, then the force transmitted from the shaft to its supporting radial bearing is high. This force is the cause of excessive wear and premature failure in a radial bearing.

The measurement processed from an accelerometers output signal is seismic (absolute motion relative to inertial space). Unlike the velocity pickup, it is practically unaffected by external electrical or magnetic fields. Accelerometers are as sensitive to ground loops as other pickups. Ground loops can be easily eliminated by providing ground isolating washers at the accelerometer base.

As specified in API Standard 670, the accelerometer channel accuracy for measuring casing vibration must be within 5 percent of 100 millivolts per g (mV/g) over a minimum range of 0.1 g to 75 g, peak, and over the frequency range of 10 Hz to 10 kHz. To avoid problems from noise and cable whip and to minimize error in measurement, the electrical impedance of the cable that links the accelerometer to the signal conditioner and to the channel plug-in module is matched to the electrical impedance of the accelerometer case.




The accelerometer has a very high mounted resonance, typically 25,000 kHz, because it has no moving parts. The response is linear for the first third of the accelerometers range, and it is used below its mounted resonance. The range is 5 to about 10,000 kHz, depending on its size. Small accelerometers have low sensitivities but higher operating frequencies. Some small accelerometers are useful above 50,000 kHz. Large accelerometers have high sensitivities but lower high-frequency limits (800 to 1000 kHz). In gas turbine applications, the accelerometer output signal is usually modified (integrated) to a velocity signal.

Temperature Monitoring Instruments Temperature monitoring instruments are used to monitor bearing conditions on gas turbines, as well as compressor discharge, first stage turbine inlet, and turbine exhaust temperatures.

Resistance Temperature Detector

A Resistance Temperature Detector (RTD) is a general term for any device that senses temperature through a measurement of the change in resistance of a material. All metals produce a positive change in resistance for a positive change in temperature. RTDs are available in many forms; however, they usually appear in sheathed form. An RTD probe is an assembly that consists of a resistance element, a sheath, a lead wire, and a termination connection. The sheath, which is a closed end probe that immobilizes the element, protects the element against moisture and the measured environment. The sheath also provides protection and stability to the transition lead wires from the fragile element wires. Some RTD probes can be combined with thermowells for additional protection. In this type of application, the thermowell will also isolate the system gas from the RTD.

When the nominal value of the RTD resistance is large, system error is minimized. To obtain a high RTD resistance, a metal wire with high resistivity must be chosen. Platinum has the highest resistivity of the selected metals that are commonly used for RTD construction.




RTDs can be constructed of several different types of metal. Gold and silver are rarely used as RTD elements because of their lower resistivities. Tungsten has a relatively high resistivity, but it is reserved for very high temperature applications because it is extremely brittle and difficult to work. Tungsten would also suffer in an oxidizing environment because of the high reaction rates. Copper is occasionally used as an RTD element. Coppers low resistivity forces the element to be longer than a platinum element, but its linearity and very low cost make it an economical alternative. Copper RTDs have an upper temperature limit of 120C (248F).

The most common RTDs are made of platinum, nickel, or nickel alloys. The economical nickel derivative wires are used over a limited temperature range. Nickel wire output is nonlinear and tends to drift with time. For the best measurement integrity, platinum is the metal of choice. Platinum is used at the primary element in all high-accuracy resistance thermometers. Platinum is especially suited for widely varying degrees as it can withstand high temperatures while maintaining excellent stability. As a noble metal, platinum shows limited susceptibility to contamination. Saudi Aramco 34-SAMSS-625 specifies three-wire platinum RTDs, calibrated to 100 ohm at 0C (32F), with a temperature coefficient of resistance equal to 0.00385 ohm/ohm/degree C from 0C to 100C, as the standard temperature sensor for thrust and journal bearing temperature channels.

Although the RTD is an accurate temperature measurement device, some errors may develop. The RTD is a passive resistance element, and a current must be applied to the RTD to develop an output signal. This current generates heat, which becomes objectionable when the heat is sufficient to significantly change the temperature to be measured. This self-heating effect causes minor errors. A limited amount of power used to produce the output signal should minimize the error.




Another error that may affect the accuracy of the temperature measurement can be caused by the lead wire. The copper lead wire for connection of the RTD to the transducer, although a satisfactory trade-off between cost and resistance, represents a resistance in series with the RTD and thus is a source of inaccuracy. For long transmission distances, ambient temperature effects can cause appreciable errors; however, these errors can be compensated for by designing the RTD as a three- or four-terminal device.

Lack of standardization among manufacturers concerning the relationships between resistance and temperature may cause an accuracy problem. Errors can occur when RTDs of several manufacturers are used in a single system, or when the element of one manufacturer is replaced with the element of another manufacturer. These errors can be avoided by not mixing RTDs with different temperature versus resistance curves.

Inaccuracy of an RTD may also result from slow dynamic response. Slow response may be caused by the RTD construction; the RTD sensing element consists of an encapsulated wire that is cut to a length that provides a predetermined resistance at 0C. The temperature-sensitive portion of the probe, which depends on the length of the sensing element, is from 0.5 to 2.5 in. The RTD is thus considered to be an area-sensitive device, and it has a significantly slower dynamic response than point-sensitive devices like thermocouples. Because RTDs are invariably installed in thermowells, the thermowells represent a much larger contribution to the slowing of the dynamic response; therefore, the error is of little significance.

Thermocouples

Thermocouples are another reliable method of temperature measurement. Thermocouples function very differently from RTDs, but they generally appear in the same configuration. Thermocouples are usually sheathed, and they can be used in conjunction with a thermowell. Thermocouple-type instruments have a range of -280 to +2750C (-440 to +5000F) and an accuracy of 0.1C (0.2F).




The thermocouple (T/C) consists of two dissimilar metal or alloy wires that are joined at one end, the so-called measuring (or "hot") junction. The free ends of the two wires are connected to the measuring instrument to form a closed path in which current can flow. The point at which the T/C wires connect to the measuring instrument is designated as the "reference" (or "cold") junction.

Application of heat to the measuring junction causes a small electromotive force (EMF or voltage) to be generated at the reference junction. When a readout device is employed, it converts the EMF that is produced by the temperature difference between the measuring and the reference junctions to record or otherwise display the temperature of the measuring junction. When the reference temperature is known (usually 0C), and when the measuring junction is exposed to an unknown temperature, the EMF that is developed will vary directly with changes in the unknown temperature.

The noble metal T/C, Types B, R, and S, are all platinum or platinum-rhodium T/C and share many of the same characteristics. Platinum wire T/C should only be used inside a nonmetallic sheath, such as high-purity alumina, due to metallic vapor diffusion at high temperatures that can readily change the platinum wire calibration. The only other acceptable sheath would be one made from platinum, which would rather expensive.

The platinum-based T/C is the most stable of all the common T/C. Type S is so stable that it is specified as the standard for temperature calibration between the antimony point (630.74C/1167.33F) and the gold point (1064.43C/1947.97F). Type R is similar to the type S; the only difference is that the rhodium makes up 10 percent instead of 13 percent of the positive leg wire.

The Type B T/C is the only common thermocouple that exhibits a double-valued ambiguity. Due to the double-valued curve, Type B is not used below 50C (122F). Because the output is nearly zero from 0C (32F) to 42C (107.6F), Type B has the unique advantage that the reference junction temperature is almost immaterial when it is between 0C (32F) and 40C (104F). However, the measuring junction temperature is typically very high.

Due to their high costs, the noble metal thermocouples are typically used only for measuring very high temperatures or




where other factors justify the cost. For most applications, base metal T/C, Types T, J, E, or K, is used. Types E, J, and K are typically used in Saudi Aramco facilities, depending on the application.

The Type E T/C positive element is made from a nickel-chromium alloy generally referred to by the trade name Chromel. The negative leg is made from a copper-nickel alloy called Constantan. The Type E is ideally suited for low temperature measurements because of its low thermal conductivity and high corrosion resistance. The Type E thermocouple is useful for detecting small temperature changes.

Iron is the positive element in a Type J T/C, with the negative leg being Constantan. Iron is an inexpensive metal and is rarely manufactured in pure form, which contributes to the poor conformance characteristics. Although the impurities in the iron are high, the Type J T/C is popular because of its low price. The Type J T/C has a more restrictive temperature limitation than most T/C. At 760C (1400F), an abrupt magnetic transformation occurs that can cause decalibration even when the T/C is returned to lower temperatures. Saudi Aramco Standard 34-SAMSS-625 specifies grounded, Type J thermocouples manufactured in accordance with ANSI MC96.1 (IEC 584-1) as the standard optional temperature sensor for journal and thrust bearing temperature channels.

The Type K T/C is similar to the type E with the exception that the negative element is made from a nickel alloy instead of Constantan. Type K has a higher temperature range than Types E or J.

The measuring instrument usually is located away from the point at which the temperature is measured; therefore, an extension is needed. Because the temperature-sensing resistor for maintaining a constant reference junction EMF can be most conveniently located in the instrument as a part of its circuit, the reference junction itself must be located in the instrument; therefore, the thermoelectric circuit must be extended from the measuring junction, at the point where the temperature measurement is desired, to the reference junction in the instrument. This extension is done through the use of extension wires.

Extension wires theoretically extend the T/C to the reference junction in the instrument. This wire is generally furnished in the form of a matched pair of conductors. The simplest procedure is




to use the same types of wire from which the T/C itself is made. However, in installations with noble-metal T/C where several hundred feet of extension wire must be used, or where numerous T/C are employed, such a procedure may become too expensive. In such cases, alternative lower-cost materials with similar characteristics at lower temperatures are available.

Thermocouples, much like RTDs, suffer from errors in their measurement. Static electrical noise may be introduced into T/C circuits by adjacent wires carrying ac power or rapidly varying (pulsating) dc. Static electrical noise may also be introduced if the T/C extension wires are capacitively coupled to an electric field. These noises can be minimized or avoided by shielding each pair of extension wires and by grounding the wire shields. T/C wires must never run in the same conduit with electric power wires.

Magnetic noise may be induced into a T/C circuit any time the extension wires are subjected to a magnetic field, and a current is produced to oppose the magnetic field. This magnetic noise can be minimized by twisting each pair of T/C extension wires. Crosstalk noise between adjacent wire pairs in the same conduit may also occur. Crosstalk can be avoided by shielding each pair of extension wires.

Common-mode noise in the circuit between the measuring junction and the transducer may occur when the circuit is grounded in more than one place, or when different grounding potentials exist along the wire path. Three different approaches can avoid these problems: the noise can be minimized by proper grounding (T/C circuits are usually grounded at the measuring junction only), by shielding each pair of extension wires and grounding the shields at the T/C only, or by using differential input measuring devices.

The monitor/control unit should be the same as the general control instrumentation. Monitors must consist of a separate alarm unit for each point and a single, time-shared temperature indicator. The alarm units must have dual setpoints and outputs, and they must accept the signal directly from the element. The alarm units must be suitable for back-of-panel rack mounting, or for mounting at a remote location. The alarms must be displayed on a separate annunciator.




The monitor must provide a fault alarm for open or short circuits in the control wiring between the detector and the monitor. Monitor relays that are used for prealarm and shutdown output functions must be the hermetically sealed, plug-in type. The trip settings must be in accordance with the recommendations of the turbine manufacturer.

In accordance with SAES-J-601, Recommended Temperature Alarms and Input Shutdown Devices, 100-ohm platinum RTDs or thermocouples that are wired directly into a Triple Modular Redundant Emergency Shutdown (TMR ESD) system, or analog 4-20 mA dc, or digital signals from ambient temperature-compensated temperature transmitters/transducer are recommended for measuring and inputting ESD temperature signals. Capillary or bimetallic type, direct process actuated temperature switches with an associated indicating gauge must not be used unless thermocouple or RTD measurements are not practical or feasible.




TYPICAL VIBRATION MONITORING ARRANGEMENTS Vibration monitoring arrangements describe the type of monitoring instruments and the locations of the monitoring instruments on a gas turbine and other elements of the machinery train. API 670 requires that a monitoring arrangement plan be furnished for each machinery train. Monitoring arrangement plans typically illustrate the following:

The position of each vibration detector. The direction of active thrust for the gas turbine (heavy duty,

industrial type only).

The direction of turbine rotation as viewed from the drive end of the turbine.

A complete description of the monitoring system that includes the following:

1. The number, type, and position of vibration detectors.

2. The type of bearings.

3. The radial clock position of the vibration detectors, with degrees referenced to the vertical top dead center (TDC) as zero.

4. The location of axial position detectors (if applicable).

5. The arrangement of the gas turbine/oscillator-demodulator box.

6. The layout of the radial shaft vibration, axial position, casing vibration, and bearing temperature monitors and all signal locations on the monitor.

7. The location and orientation of the key phaser probe and the location of the target relative to the numbered valance holes.

The following section will describe the monitoring equipment requirements and arrangements for heavy-duty and aero-derivative turbines as defined by industry and Saudi Aramco standards.




Heavy-Duty Gas Turbines In accordance with SAES-K-502, vibration and temperature monitoring systems must be installed in accordance with the following standards:

34-SAMSS-625, Vibration, Axial Position, and Bearing Temperature Monitoring Systems

API 616, Gas Turbines For Refinery Service (by reference) API 670, Vibration, Axial Position, and Bearing Temperature

Monitoring Systems (by reference)

Additional requirements for installation of vibration and temperature monitoring systems for gas turbines are located in SAES-J-604, Protective Instrumentation for Rotating Machinery

Vibration Monitoring

SAES-K-502 specifies that unless operating temperatures exceed instrumentation limits, the following vibration measurement and monitoring instrumentation shall be provided for heavy-duty gas turbines:

Key phasor on each shaft. Journal bearings shall have noncontacting X-Y probes

mounted at 45 from the vertical centerline, where possible.

Bearing housings shall have a piezo-velocity seismic transducer displaying velocity, RMS.

The thrust bearings shall have dual probes with voting logic monitoring the axial position.

The X-Y probes are used for diagnosis, monitoring and alarm. The seismic transducers are used for diagnosis, monitoring, alarm and emergency shutdown. Installation and calibration shall be in accordance with 34-SAMSS-625.

Proximity Probes - As mentioned previously, the noncontact proximity systems as used by Saudi Aramco have the following applications related to the proximity probe installations: radial to the rotating shaft, axial to the rotating shaft, rotative speed, and phase relationship.




A noncontact proximity probe is usually permanently mounted in a bearing housing to analyze the surface of a rotating shaft. Noncontact proximity probes can also be clamped to the bearing housing, in which case the mounted resonance of the fitting must be taken into consideration. The probe must be calibrated for the specific shaft material, and the material must be electrically conductive for the proximity probe to properly set up a magnetic field to sense any gaps.

The proximity probe senses shaft surface defects, such as scratches, dents, and variations in conductivity and permeability. The proximity probe also senses electrical and mechanical runout but has difficulty distinguishing vibration from runout. Electrical runout can be described as an electrical signal from a proximity probe due to the effect of irregular shaft conductivity and magnetic permeability in the shaft material. Mechanical runout can be described as the measurements of shaft surface imperfections. Shaft surface imperfections are always present. A proximity probe cannot readily distinguish shaft runout (mechanical runout) from vibration. A slow roll may be performed, however, to allow the electronic circuit to memorize all of the shaft imperfections and shaft runout, and subtract the signal of shaft imperfections from the signal that the proximity probe reports at running speed. Slow roll is low rpm (200 to 600 rpm) that occurs during the turbine startup or coastdown. A digital vector filter (used to obtain the Bode plot) must be zero nulled so the runout will not be a factor during the slow roll.

The acceptable shaft vibration limit at any speed and load up to the maximum continuous speed, excluding electrical runout, is the maximum of 2 mils or the following:

Allowable shaft vibration in mils peak-to-peak = rpm

12,000




The measurement of radial vibration is accomplished by monitoring the dc output of a displacement probe that is associated with the radial vibration at the journal bearings. Under normal operation and with no internal or external preloads on the shaft, the shaft position of most machine designs will be approximately 15 to 30 off the vertical centerline in the direction of rotation.. However, as soon as the machine receives some external or internal type preload (steady-state force), the radial position of the shaft in the journal bearing can be anywhere. The radial position measurement can be an excellent indicator of journal bearing wear and heavy preload conditions, such as misalignment. In installations in which only single-plane monitoring is present, radial position must be measured on a periodic basis.

Radial displacement should be closely monitored during turbine startup or coastdown. During a turbine startup (with hydrodynamic radial bearings), the shaft would be expected to rise from the bottom of the bearing to some place toward the horizontal centerline of the bearing. This movement is fundamentally due to the oil flowing under the shaft, which causes the shaft to rise in the bearing. It is generally believed that the oil film is about one mil in thickness.

Because of the ability of the radial position to change under varying conditions of machinery load and alignment, the proximity probe transducer system must have a sufficiently long linear range to allow for the large radial position changes. A long linear range is required in large machines in which large bearing clearances are normally present.




For a radial vibration transducer, Saudi Aramco requires that two noncontact proximity probes be mounted to or in each radial hydrodynamic bearing of the turbine rotor. Unless the rotating equipment construction prevents access to the bearings, this requirement should be strictly adhered to. As shown in Figure 8, the two probes should be installed with as close to 90 degrees of radial separation as feasible. The probes must be in the same axial plane to the shaft, so that a true representation of the shaft movement can be monitored. Also, the probes must be installed so that each probe is offset by 45 degrees from the top dead center of the bearing. The probes should be identified as X and Y, not horizontal and vertical. The position of the X and Y probes is defined by Saudi Aramco convention. The position of the X and Y probes is determined by standing outboard, facing the gas turbine in the direction of gas flow.

Figure 8. Noncontact Eddy Current Probe Orientation

As specified in API Standard 670, the noncontact proximity probe for a phase reference transducer (key phasor) must be




installed so that its radial axis of observation is along a plane other than the plane for the radial axes that are observed by the probes for a radial vibration transducer.

A phase reference transducer also serves as a noncontact proximity probe. Only a single probe is required to be radially mounted on an equipment train with the same rotation and speed. If part of the train has a different rotation or speed, a separate probe should be provided.

The phase reference transducer detects, once each revolution of the shaft, a phase reference mark on the shaft. This mark may be a keyway, a key, a hole, a slot, or a projection on the shaft. Any of these marks will cause a radical change in the probe tip gap and thus provide a signal change to the proximitor on each revolution.

An oscilloscope references the output signal from a phase reference transducer to a filtered output signal from a radial vibration transducer. On the oscilloscope display, the detection of the phase reference mark appears as a pulse on the radial vibration waveform. Phase angle is the number of degrees (along the x axis of the X/Y plot) from a pulse mark to the first positive peak in the waveform from left to right.

Axial displacement measurements are typically used to monitor the condition of thrust bearings in heavy duty, industrial gas turbines, which always use hydrodynamic thrust bearings. Axially mounted noncontact proximity probes are used to detect the axial movement of the rotating element during operation. All rotating elements have some axial movement in response to external forces, such as forces that are imposed through couplings from other equipment in the train or from the coupling itself, and in response to internal forces in the rotating equipment, such as changes in process conditions and thermal changes. All hydrodynamic machines have sufficient axial clearance that allows relatively large gaps to be set for alarm and trip setpoints. At least two axial thrust position probes should be mounted to provide axial thrust position protection. Under the normal operating conditions of a gas turbine, thrust position can vary with the load of the driven machine, so a variation in thrust position measurements under different loads and conditions of a machine are not uncommon.

The axial shaft movements are normally constrained within allowable limits by the design of the equipment. Axial shaft movement constraints are commonly thrust bearings or thrust




shoulders, both of which interact between the rotating and stationary parts of the equipment.

During normal operation, rotating equipment will have a thrust load in one direction. The direction of the thrust load depends on the relative levels of the thrust in the compressor section (directed from the discharge end toward the suction end in an axial compressor) and the turbine section (directed from the turbine inlet towards the turbine exhaust, that is, in the opposite direction). The rotating element must be protected from excessive axial movement that is caused by normal thrust bearing wear or thrust bearing failure that would then permit internal rotating element wear and catastrophic failure.

Two axially mounted noncontact proximity probes are installed to sense changes that occur in the axial position of the shaft in either direction. The movement will be restricted to allowable values for gas turbine alarm and shutdown functions.




In accordance with 34-SAMSS-625, Saudi Aramco uses axial position probe arrangements specified in API Standard 670. There are two probe installation arrangements: an arrangement for a shaft that is equipped with an integral thrust collar and an arrangement for a shaft without an integral thrust collar. Figure 9 shows the axial position probe installation for a thrust bearing with an integral thrust collar. Because integral thrust collars are preferred (API 616), this arrangement will be the more common arrangement. One probe is mounted to measure the integral thrust collar, the other probe is mounted to measure the end of the shaft.

Figure 9. API 670 Axial Position Probe Installation for a Shaft with an Integral Thrust Collar




Figure 10 shows the axial position probe installation for a shaft without an integral thrust collar. This configuration is referred to by the API Standard 670 as the standard axial position arrangement. Both axial position probes are mounted to measure the end of the shaft. Noncontact proximity probes must never be installed to observe a nonintegral thrust collar. The arrangement prevents incidental gas turbine shutdown or alarm in the event that a nonintegral thrust collar comes loose and allows the shaft to move axially.

Figure 10. API 670 Standard Axial Position Probe Installation Arrangement

In accordance with the requirements specified in API Standard 670, the axial position monitoring system must use dual voting logic. In a dual voting logic system, the measurements processed from the outputs of each transducer must equal or exceed the setpoint to activate the danger alarm or shutdown (two out of two).




Seismic Probes - In addition to displacement probes, bearing housing seismic transducers displaying RMS velocity are required on all heavy-duty gas turbines. Piezoelectric velocity transducers must have a minimum linear operating range of 2500 Hz. Piezoelectric acceleration transducers must have a minimum linear operating range of 10 kHz. All piezoelectric transducers must be rated for temperatures above 120C. The seismic transducers are used for shutdown functions, as well as monitoring.

Figure 11 shows a typical vibration and axial position system arrangement for a heavy-duty gas turbine.




P2

3Y

4X

5Y

ELLIPTICAL JOURNALBEARING

3Y

T4

T5

4X

TURBINE

A2

A1

A2

P1

6X

COMPRESSOR

A1

ELLIPTICAL JOURNALBEARING

5Y

AC

TIV

E TH

RU

ST

6X

T3

T2

T1

P1 P2

3

KINGSBURY THRUSTBEARING

4

5

6 1

VIBRATION MONITORINGSYSTEM JUNCTION BOX

A2A12

AXIAL POSITION PROBE

TURBINE END RADIALVIBRATION PROBE 45 OFF TDCTURBINE END RADIALVIBRATION PROBE, 45 OFF TDC

COMPRESSOR END RADIALVIBRATION PROBE 45 OFF TDC

NUMBER 2 BEARING RADIALACCELEROMETER 90 OFF TDCNUMBER 3 BEARING RADIALACCELEROMETER 90 OFF TDCAXIAL POSITION PROBE

COMPRESSOR END RADIALVIBRATION PROBE, 45 OFF TDCPHASE REFERENCE PROBE 45OFF TDC

Figure 11. Typical Vibration and Axial Position System Arrangement for a Heavy Duty Gas Turbine




Temperature Monitoring

SAES-K-502 specifies that for heavy-duty gas turbines, each hydrodynamic thrust and radial bearing is required to have a replaceable RTD installed in a pad that is expected to carry the greatest load. For thrust bearings, RTDs will be required for both the active and inactive side, since thrust loading will vary with machine load. Additionally, bearing lube oil drain thermocouples must be provided for every bearing.

In addition to bearing temperature monitoring, SAES-K-502 requires that heavy-duty gas turbines be equipped with two thermocouples for each wheel space. These thermocouples must be replaceable during operation. The wheel spaces are the areas fore and aft of each turbine wheel. Excessive temperatures in these areas are indicative of wear or damage to turbine rotating blade root seals, which allow the wheel and rotor to be directly exposed to the hot gases. Because the materials from which the rotor and wheel are constructed are not as resistant to high temperatures as the hot gas path materials, this can result in a shortening of the turbine rotor life. The turbine manufacturer will provide wheel space temperature alarm limits. There is generally no trip function associated with wheel space temperature.

Embedded Probes - An embedded temperature monitoring probe is typically an RTD or thermocouple, with RTDs required for bearing temperature monitoring, as noted above. Saudi Aramco does not permit the use of spring-loaded bayonet-type temperature sensors that contact the outer shell of the bearing metal because experience has shown that a consistently good contact for reliable and accurate readings is not obtained. In addition, through-drilling and puddling of the babbitt are not permitted. The thermocouple is inserted through a drilled hole in the bearing retainer, and its tip is made to firmly contact the backing metal but not in contact with the babbitt. This installation method provides the most reliable results and can detect a temperature change more quickly than the drain thermocouples that measure the temperature of the oil stream. Measuring the backing material could be significant in the case of a sudden rapid rise in bearing temperature, which might lead to severe bearing or turbine damage before the turbine could be shut down.




Oil Drain Probes - Oil drain probes consist mainly of thermocouple-type temperature detectors installed in the oil drain line, as shown in Figure 12. The thermocouple is installed in a thermowell with the tip of the thermocouple in contact with the bottom of the thermowell. Oil drain temperature is monitored to identify potential operational problems that may cause failure. The turbine vendor will provide alarm and emergency shutdown limits for bearing drain temperature.

Figure 12. Oil Drain Line Thermocouple Installation




Aero-Derivative Gas Turbines In accordance with SAES-K-502, vibration and temperature monitoring systems for aero-derivative gas turbines must be installed in accordance with the following standards:

34-SAMSS-625, Vibration, Axial Position, and Bearing Temperature Monitoring Systems.

API 616, Gas Turbines For Refinery Service (by reference). API 670, Vibration, Axial Position, and Bearing Temperature

Monitoring Systems (by reference).

Additional requirements for installation of vibration and temperature monitoring systems for gas turbines are located in SAES-J-604, Protective Instrumentation for Rotating Machinery.

This section will describe the requirements that specifically apply to aero-derivative gas turbines.

Vibration Monitoring

All aero-derivative gas turbines utilize antifriction (rolling element) bearings. For aero-derivative gas turbines, vibration measurement and monitoring are per the Vendor's standard. A minimum of two transducers are required: one on the compressor casing and one on the turbine casing. The selection of whether piezoelectric velocity or acceleration transducers are used depends on the frequency and the temperature requirements. Piezo-velocity transducers apply up to 2 kHz and piezo-accelerometers apply above 120C (248F). Both transducers are used for alarm and emergency shutdown purposes. Usually, each transducer sends a signal to a filter that provides dedicated output signals in velocity (inches per second zero to peak or RMS) for each rotor. The signal is usually filtered to rotor running speed (1) but has the capability of full frequency range monitoring for diagnostic purposes.

The alarm and shutdown limits for aero-derivative gas turbines are typically designated by the gas turbine vendor. The typical filtered (1) alarm limit is 0.35 inches per second rms, and the typical filtered shutdown limit is 0.5 inches per second rms.




Temperature Monitoring

Because of the type of bearings used, bearing temperature monitoring for aero-derivative gas turbines cannot be used. However, SAES-K-502 does require that machines with antifriction bearings be equipped with instrumented metal chip detection in the lube oil drain lines as a minimum. When specified, an on-line metallic debris monitoring system must be provided in the drain lines. Detection by this system of any chips or debris in the oil will be annunciated in the plant control room, which will provide early warning of impending bearing failure.

Aero-derivative gas turbines are required by SAES-K-502 to have, as a minimum, two wheel space thermocouples downstream of the last turbine wheel. The thermocouples and the conduits must be as small as possible, must utilize the existing struts in the turbine/exhaust casing, and must not cause significant disturbance to the air and hot gas flow.




GAS TURBINE THERMODYNAMIC PERFORMANCE MONITORING The vibration and temperature monitoring systems discussed so far are used primarily for monitoring the mechanical performance of the machine. Increased vibration and increased bearing temperatures are typically indicative of mechanical deterioration of the machine, such as wear or mechanical damage. The monitoring system is used to detect this mechanical deterioration before it progresses to the point of catastrophic failure.

API 616 requires that temperature instrumentation be provided to monitor important temperatures within the unit and to record the more important items, such as exhaust temperature. Important temperatures that are useful in monitoring gas turbine thermodynamic performance (efficiency) include the compressor discharge temperature, the turbine inlet temperature, and the turbine exhaust temperature. Of these temperatures, the turbine inlet temperature is not generally measured due to the lack of long-term reliability of most temperature probes at the high temperatures encountered. Instead, this temperature is calculated by the control system based on measurements of the turbine exhaust temperature, the ambient temperature, and the compressor discharge pressure. In two-shaft machines with a separate power turbine, the inlet temperature to the power turbine may be measured.

This section will take a brief look at using the above measurements for monitoring gas turbine thermodynamic performance.

Compressor Discharge Temperature As was stated in Module 214.03, compressor performance has a significant impact on the overall performance of the gas turbine. Even with the inlet filtration provided, the compressor section of the turbine can become fouled, which reduces compressor performance. For this reason, SAES-K-502 requires that all gas turbines be equipped with both on-line and off-line compressor wash systems. Performing a compressor wash can remove fouling deposits and restore compressor performance.




Compressor performance is monitored to determine the need for a wash by trending compressor efficiency. The compressor isentropic efficiency is calculated by using the compressor inlet temperature and pressure and the compressor discharge temperature and pressure as follows:

12

k1k

1

21

TT

1PPT

=

Where:

T1 = compressor suction absolute temperature (R or K)

T2 = compressor discharge absolute temperature (R or K)

P1 = compressor suction absolute pressure (psia or KPa abs)

P2 = compressor discharge absolute pressure (psia or KPa abs)

k = ratio of specific heats

The ratio of specific heats, k, varies slightly with temperature; however, for trending purposes, it can be assumed to be a constant equal to 1.4. An efficiency calculated with k = 1.4 will be slightly higher than the efficiency calculated using variable gas properties, but, as long as it is used consistently, it will be adequate for monitoring changes in compressor performance.




The following is an example of calculating compressor isentropic efficiency:

( )

90.3%.903600

541.84

600111.395539.67

539.671139.67

114.7

167.5539.67

.2857

1.411.4

===

=

=

Local ambient barometer - 29.92 Hg (14.7 psia)

Compressor inlet temperature - 80F (539.67R)

Compressor discharge pressure - 152.8 psig (167.5 psia)

Compressor discharge temperature - 680F (1139.67R)

Because compressor efficiency varies with load, calculations for performance trending should be made at the same turbine load and compressor inlet conditions each time.

Turbine Inlet Temperature As noted above, turbine inlet temperature is not normally measured by temperature instruments but calculated by the control system. For a base-loaded turbine, the control system will control the fuel to maintain a constant turbine inlet temperature or exhaust temperature. For a two-shaft machine, the turbine inlet temperature to the power turbine may be measured. If this temperature is increasing for a given load, it is an indication that the efficiency of the gas generator (compressor and HP turbine) is decreasing.




Turbine Exhaust Temperature The temperature of the gas turbine exhaust is a measure of how much energy is contained in the exhaust. The energy in the exhaust is the energy that was not used by the machine to produce work; so, it is a measure of the inefficiency of the gas turbine. As the gas turbines exhaust temperature increases, the efficiency of the gas turbine decreases.

As discussed in MEX 214.03, the efficiency of the turbine varies with changes in ambient temperature; therefore, the expected turbine exhaust temperature would also change with a change in ambient temperature. SAES-K-502 requires the turbine vendor to furnish data to include curves that show exhaust temperature corrections versus ambient temperature and curves that show exhaust temperature versus load for various ambient temperatures; therefore, the Mechanical Engineer can obtain an indication of gas turbine efficiency by comparing measured exhaust temperature with that predicted by the curves.

Turbine exhaust temperatures can also be used to diagnose problems that occur in the combustion section of the gas turbine during operation. If problems in the combustion section of the turbine result in an uneven temperature pattern at the turbine inlet, the uneven temperature profile will also show up at the turbine exhaust due to incomplete mixing of the gases as they pass through the turbine; therefore, monitoring the spread in exhaust temperatures will help to detect combustion system problems. An increasing exhaust temperature spread indicates problems with one or more fuel nozzles or a problem with fuel distribution to the various nozzles




GLOSSARY

acceleration The rate at which velocity increases or decreases. Measured in gs (the acceleration produced by gravity at the earths surface; equal to 386.087 in/sec2).

accelerometer A transducer that responds to force and that produces an electrical output signal (in millivolts) that is directly proportional to acceleration. Some accelerometers contain circuitry to integrate the response to acceleration to an output signal proportional to velocity.

amplitude The magnitude of a variable that varies periodically at any instant during a cycle (or period).

babbitt A soft lead/tin mixture used for a surface in bearings.

condition monitoring A process and a method of monitoring specific parameters on equipment to determine the status of the mechanical condition.

critical equipment Equipment that is considered to be vital to continued production and that is usually nonspared.

displacement Movement of an object from a position of rest, equilibrium, or in relation to a reference point.

electromotive force A rise in electrical potential energy.

frequency The number of cycles that a periodic variation completes in a given period. Sometimes stated in cycles per minute (cpm) or cycles per second (cps, Hertz, Hz). For vibration, frequency is also expressed as a multiple (1, 2) of shaft rotative speed.

noncontact proximity probe

A sensor that detects the gap between its tip and a shaft surface.

phase angle An expression in degrees that defines the relationship between events that occur as a rotating shaft vibrates. Typically, phase angle defines the number of degrees that the unbalance mass (heavy spot) in a shaft has rotated between the event in which a phase reference transducer detects a phase reference mark and the vent in which the heavy spot makes the closest approach (high spot) to the sensor of a radial vibration transducer.

phase reference transducer

A transducer that identifies a once-per-revolution event (phase reference mark) on the rotating shaft.




Resistance Temperature Detector (RTD)

A general term for any device that senses temperature by measuring the change in resistance of a material.

root mean square (rms)

In reference to measurements of vibration, 71% (.707) of a zero-to-peak value for velocity or acceleration sine waves. Calculated algorithmically as follows: a number of instantaneous values occurring during one cycle or during several cycles are squared; the average of the squared values is taken; and the square root of this average is then taken. In a vibration monitoring system, velocity and acceleration are often measured in terms of RMS values.

seismic transducer A transducer that is used to measure velocity or acceleration. The term seismic indicates the measurement type: motion in relation to free space or to a fixed point in free space. Seismic transducers include accelerometers and velocity transducers, which measure structural vibration.

thermocouple A junction of two dissimilar metals that has a voltage output that is proportional to the difference in temperature between the hot junction and the cold junction.

thermowell A closed-end tube that is designed to protect temperature sensors from harsh environments, high pressure, and flows. Thermowells can be installed into a system by pipe thread or welded flange, and they are usually made of corrosion-resistant metal or ceramic material.

triple modular redundant emergency shutdown system

An emergency or safety shutdown system that employs a two-out-of-three voting scheme to determine the appropriate output action.

velocity The time rate at which an object is moving. For vibration, measured in inches per second (in/sec).

velocity transducer A transducer that senses velocity of vibration and that produces an electrical output signal (in mV) that is proportional to velocity.

vibration Motion in which an object undergoes periodically occurring displacement. Vibration is measured in terms of its variables of displacement (mils), velocity (in/sec), and acceleration (gs). For rotating machinery, vibration is assessed in terms of frequency, peak-to-peak amplitudes of displacement, and either root mean square (RMS) values or zero-to-peak values for velocity or acceleration.

Evaluating Installation of Vibration Monitoring Equipment for Gas Turbines

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