Turbine Supervisory Instrument

GE Oil & Gas

Turbine Supervisory Instrumentation (TSI) Application Guide Bently Nevada* Asset Condition Monitoring Table of Contents 1 Purpose.........................................................................................................1 2 Scope.............................................................................................................2 3 References...................................................................................................2 4 System Design and Engineering................................................................2 5 Steam Power Plant Overview....................................................................2 6 Condition Monitoring and Protection Measurements.........................4 6.1 Radial Vibration...................................................................................................................5 6.2 Thrust/Axial Position........................................................................................................8 6.3 Keyphasor*.........................................................................................................................11 6.4 Eccentricity.........................................................................................................................13 6.5 Speed Measurements...................................................................................................13 6.6 Expansion............................................................................................................................16 6.7 Dual Case Expansion......................................................................................................20 6.8 Valve Position....................................................................................................................20 6.9 Temperature Monitoring..............................................................................................21 6.10 Monitoring - Other........................................................................................................22 6.11 Installation Best Practices....................................................................................... 24 6.12 Installation Guidelines and Pitfalls......................................................................25 7 Condition Monitoring/Machinery Management................................. 25

1 Purpose To provide a single document which outlines the best practices in condition monitoring and protection for steam turbine generators with respect to GE Bently Nevada’s offering.

All drawings and diagrams contained herein were produced by GE and cannot be reproduced or copied without GE’s express consent.

application note

application note 2 Scope

5 Steam power plant overview

This document describes steam turbine generator best practices including monitoring and diagnostics needs, and also provides basic information such as steam power generation overview and unplanned outage cost examples. This will help the reader understand turbine supervisory instrumentation application and monitoring best practices enableing users of this application guide to gain a better understanding of proven monitoring and diagnostic methodologies.

Steam power plants are very complex with a wide variety of equipment. The overall goal of a steam power plant is to generate steam and convert the high-pressure steam to electricity. The type of plant creates variations in operation style and may add more layers of complexity. Steam can be generated from a variety of different sources, such as fossil fuels (coal, oil, natural gas), a nuclear reaction, biomass products (sugar cane, wood chips, municipal waste, methane gas, etc.), geothermal energy and concentrated thermal solar energy to name a few.

3 References

Large steam plants are used for base load and the goal is to operate them as steadily as possible with any fluctuations in operation being due primarily to demand in electricity. In more recent years there has been a growing business trend to cycle plants. The decision to cycle a plant or use them as base load is primarily based on the type and size of plant and business needs. For instance, all nuclear power plants are base load due to the complexity of generating steam from a nuclear reaction. Historically, coal-fired plants were base load. However, with recent environmental concern over coal burning and reduction in gas prices, many coal plants are now being cycled in some parts of the world. Both simple cycle and combined cycle plants are now being used for base load, load following, and for peak demand .

API-670 Fifth Edition, November 2014; EPRI Program on Technology Innovation: Integrated Generation Technology Options 1022782 Technical Update, June 2011.

4 Transducer Installation Guide - System design and engineering Bently Nevada has more than 50 years of installation and application experience. It is recommended for new applications or upgrades that customers leverage this expertise. This will minimize installation and application problems and provide the greatest likelihood of successful system performance. Our involvement would include: • System design and layout • Electrical system and interconnect designs • Electrical installation • Mechanical designs • Mechanical installation • Machine train diagrams

Lost revenue of an unplanned outage An unplanned outage is extremely costly. Let’s use some hypothetical numbers and assume that the cost to generate a Megawatt hour is $30 and the wholesale price is $60. The cost of lost production is equal to (the time out-of-service x the power output x (the wholesale price of the power – the generation cost per MWH)). If the unit generates 600 MW, and has to be removed from service for 24 hours, the cost of lost production of an unplanned outage would be 24 x 600 x $30 = $432,000.

• Transducer check out

The above example only accounts for lost production, and does not include any of the following, which also needs to be taken into consideration:

• Loop checks

• Staff and public safety

• Monitor configuration

• Regulatory fines and fees and environmental impacts

• IT system security design

• Maintenance labor and materials

• Software configuration

• Product or production quality depending on available data

• Software optimization

• Cost of purchasing replacement power

• Systems & Instrumentation (S&I) Reports

• Power plant fuel contracts may oblige them to purchase fuel that would have been used during the outage even if the fuel is not used.

• Transducer installation

• Project documentation • Start-up assistance and diagnostics • System supporting services • Remote monitoring and diagnostics support

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Total revenue loss of an unplanned outage for a medium to large generating unit can be in the millions of dollars per day. Project or opportunity specific ROI models can be built for Bently Nevada customers by contacting your regional FAE, PG PLM or Global Projects Manager for support.

application note Machine overview As illustrated in Figure 1, Turbine Supervisory Instrumentation (TSI) is installed on large turbine generator sets (100 MW and up) to monitor and protect the rotating machinery. The installed machinery has characteristics driving the selection of proper sensors and monitors. Fluid Film Bearings – The need for tight mechanical clearances between casing and rotor coupled with fluid film hydrodynamic bearings drives the need to measure the shaft vibration and position relative to the casing. This leads to the selection of noncontacting proximity probes as a primary vibration monitoring and protection sensor. Counteracting and balancing the axial forces within the steam turbine cases requires fluid film thrust bearings which also lend themselves to the use of non-contacting proximity probes. Both radial and thrust bearings also require monitoring of the bearing temperature to avoid overloading and bearing damage. Both RTD and TC measurement can be used to meet this need. Differential Thermal Growth – When the steam turbine is initially brought up to operating conditions, a great deal of thermal growth occurs in both the casing and the rotor(s). During this time, it is imperative that design clearances between the rotor and casing are maintained. The measurement of differential expansion between the rotor and casing with a non-contacting proximity sensor is ideal for this application.

Casing Vibration – Thick walled, heavy casings are required to contain the rotors and the high-pressure superheated steam passing through the turbine. Significant levels of rotor vibration usually does not pass through to these heavy casings, so casing vibration is generally a poor indicator of rotor vibration and may not be required in all instances. As a general rule, if the casing vibration is less than 10% of the overall rotor vibration, casing vibration sensors are not required. Frequency of Vibration – The relatively slow maximum speed of the turbine generator set, 3000 RPM (50 Hz) or 3600 RPM (60 Hz), allows all significant vibration frequencies to be monitored with shaft relative probes and possibly velocity transducers for casing vibration. Because of the lack of high-frequency vibration, accelerometers are generally not required for these TSI applications. Overspeed – Finally, any condition that would cause the turbine generator set to exceed approximately 112% of rated speed can have dire consequences. As a minimum, shutdown and inspection of the components may be required under this overspeed condition, and higher levels of overspeed could result in failure and destruction of one or more of the machine train components. An overspeed detection system is a critical part of the overall overspeed protection system that is provided to protect against any failure that may result in excessive overspeed.

Casing Expansion – The entire case of the turbine also must be free to move under the forces of thermal expansion. This freedom to grow is provided by fixing one end of the turbine casing and allowing the other end to slide freely. To assure that the casing is expanding uniformly without binding, sensors are placed at each side of the free end of the turbine to monitor the growth. These sensors are usually Linear Variable Differential Transformer (LVDT) sensors.

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application note 6 Condition Monitoring and Protection Measurements

Figure 1 - A typical transducer suite for a large Turbine Generator set connected to a 3500 series monitoring system. The monitoring system in turn is connected to System 1 and a DCS system with Ethernet switches.

Turbine Supervisory Instrumentation (TSI) is capable of providing machine monitoring, protection, machine diagnostics and instrument diagnostics. These capabilities are briefly defined as: Monitoring – TSI monitoring provides continuous on-line measurement of critical parameters which provides an indication of the condition or health of the operating machinery. The state of the machine train is available to operators and alarms can be set to bring the operator's attention to conditions that may compromise the operation of the machine train. The critical nature and large capital investment involved in these machine trains justifies the cost of purchase and installation of continuous monitoring systems. If a machine train is only monitored, operator intervention is required to shut down the machine if monitoring levels indicate an operating condition requiring a shutdown. Protection – operators are nearly always present during the operation of these TSI machine trains, but TSI end users may choose to protect the machine using automatic shutdown of the equipment when critical levels are exceeded. This provides protection when an operator’s intervention may not occur quickly enough to prevent damage. The decision to tie the TSI system output into the machine control/shutdown system

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without operator intervention is dependent upon the operating methodology of the end user. Diagnostics – operating data should be trended and archived so that when a monitoring/protection system indicates an alarm, the end-user can determine the proper corrective action. With this data, diagnosis methods may be applied well before conditions become severe enough to require a shutdown, thus allowing continued operation until planned corrective action can be taken. When an unexpected shutdown occurs, whether automatic or operator initiated, diagnostic data is very critical in determining root cause and corrective action. Clear quantitative data on machine conditions just prior to and throughout the shutdown can assist machinery experts and operators in determining the cause of the shutdown and facilitate a restart of the machine. Collection of operational data is performed through interfacing the monitoring/protection system with proper software and computer systems such as the GE Bently System 1*. Sometimes it is helpful to temporarily install equipment, both transducers and separate data collections instruments such as GE Bently ADRE* 408 system, to facilitate a complete machinery diagnostics study. This is frequently done on the initial commissioning of a new TSI installation.

application note Instrument Diagnostics: Every TSI instrumentation package has extensive self-testing that is performed continuously. A self-test failure will be displayed to the end user in several ways such as the green OK LED light going off, the instrument rack OK relay (normally energized) changing state, (in the operator display, if supplied) and in the monitor events list. It is extremely important that end users are aware of and take advantage of these self-test indicators so that instrumentation problems can be addressed before there is a false or missed alarm event.

Shaft Absolute Vibration – vibration of the shaft motion referenced to free space. It is measured using a vector summation of shaft relative motion and bearing seismic motion with both transducers mounted at the same location (proximity and integrated Velocity signals).

Vibration transducer mounting considerations: •

The first consideration should be the measurement of the shaft motion (dynamic and position) relative to the bearing or bearing constraint.

•

The second consideration should be the measurement of the bearing or bearing constraint absolute motion.

•

Radial vibration measurement types

The third consideration should be based upon the measurements of shaft absolute. When shaft absolute is to be monitored, it is essential that the relative and seismic sensors are mounted properly to sum to the absolute signal (see Figure 2).

•

Three distinct types of vibration measurements can be made on Steam Turbine Generators (STGs):

The fourth consideration should be based upon transducer accessibility and ease of maintenance.

•

Based upon the four best practice considerations above, our best practice is XY proximity probes mounted relative to and near the bearing, with XY seismic transducers mounted to the bearing support structure with redundant or spare transducers applied where ease of maintenance is an issue.

Below is an overview of the measurements that are typical in Turbine Supervisory Instrumentation (TSI).

6.1 Radial Vibration

Shaft Relative Vibration – Vibration measured with respect to a chosen reference. Proximity probes measure shaft dynamic motion and position relative to the probe mounting, usually the bearing or bearing retainer. Absolute (Seismic) Vibration – Vibration of an object as measured relative to an inertial (fixed) reference frame. Accelerometers and velocity transducers measure absolute vibration typically of machine housings or structures; thus they are referred to as seismic transducers or inertial transducers.

If the machine bearing structure is sufficiently stiff and cost is a consideration, it may be acceptable to use XY proximity probes only as long as they are mounted to the bearing or bearing retainer. As a rule, monitoring of casing vibration is recommended if the casing vibration is 10% or more of the overall machine vibration.

Figure 2 - Recommended Shaft Relative and Absolute Seismic Transducer installation design (the two transducers can be summed for shaft absolute)

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application note

Figure 3: Recommended Shaft Relative Vibration Probe Installation Design

In the 1950’s and 60’s, many Turbine-Generator (TG) sets were equipped with “shaft riders” to measure shaft absolute vibration. The shaft rider was an assembly consisting of a moving coil Velocity Transducer mounted on top of a mechanical assembly which contacted the shaft surface but was decoupled from the bearing housing by a lubricated sliding bearing. When in perfect condition, the shaft rider transducer follows the shaft dynamic motion within a narrow frequency band from about 500 cpm up to approximately 7200 cpm or 2X shaft rotative speed. This is a measure of shaft absolute vibration, thus some end-users may request to shutdown on shaft absolute vibration. Bently Nevada does not consider this a best practice (see further discussion below.) The potential for deterioration of the rider contacting tip and friction to develop in the sliding bearing was considerable, resulting in inaccurate measurements due to intermittent contact between the probe and the bearing. With the availability of non-contacting proximity probes which also provide shaft radial position measurements (impossible with a shaft rider), the shaft rider was rendered obsolete about 30 years ago. When a customer does replace their shaft rider system, some will try to use the location where the shaft rider was mounted, using an externally mounted Dual Probe Housing assembly.

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It is important to note that with this type of probe or dual probe installation, all shaft relative radial position and relative shaft vibration is measured with the outer bearing housing as the reference point. This installation practice conveniently reduced installation complications and cost; however significant measurement inaccuracies can arise as a result of this type of installation for the following reasons: •

The bearing cover has no bearing retention function and is structurally weak. When mounted there, seismic vibration measured by the Velomitor element of the dual probe may be dominated by vibration of the cover and give a poor measurement of the bearing vibration. Structural resonance of the cover can lead to grossly inaccurate measurements of both shaft relative and shaft absolute vibration, with varying impact depending on machine speed and operational mode.

•

When the bearing cover on many STGs is only weakly referenced to the bearing, measurements of shaft radial position can be very inaccurate. The bearing cover may expand differentially or distort; since the reference point for the measurement of shaft radial motion is the mounting point of the dual probe on the cover, the position of the shaft relative to the bearing surface will be inaccurate.

application note If the bearing cover does not move relative to the bearing surface, the position measurement equates to the shaft minus the bearing movement. When installing a dual probe using an existing shaft rider tube/sleeve with it’s flange on the outer bearing cover, there is typically a substantial radial distance from the flange to the shaft surface—in some cases as much as 15-inches (38 centimeters). A correspondingly long tube or sleeve is required for mounting the proximity probe component of the dual probe. Transverse mechanical resonance of the tube can occur and be excited by machine vibration. This can lead to inaccurate vibration measurements and the potential for fatigue failure of the probe sleeve. Whenever a probe sleeve is longer than 15-inches, a support should be provided at or near the probe tip. This is to avoid excitation of a mechanical resonance in the probe sleeve that could cause structural fatigue and potentially inaccurate measurements. All external mountings of radial vibration probes for steam turbine generators should be reviewed for proper application prior the decision to use an external mounting. GE Bently Nevada Field Application Engineers (FAE) can perform or assist in this review. If required the FAEs can engage appropriate service departments, trained in design and installation such as the Minden Application Engineering group, the GE Power Generation Product Line Manager or Power Generation Global Project Manager as required.

6.1.1 Shaft Relative Proximity Probes in an X-Y configuration – installation considerations Two orthogonally mounted shaft relative proximity probes must be installed at each bearing, preferably mounted directly to the bearing. If the probes cannot be mounted directly to the bearing, the bearing constraint may be used, but only if it is the primary

bearing retaining device. Secondary covers which are not the bearing constraint do not provide adequate support for shaft relative vibration or radial position measurements. Figure 3 above illustrates an example of a typical installation.

6.1.2 Bearing Absolute Vibration (Seismic) Transducers in an X-Y Configuration Two orthogonally mounted bearing absolute vibration transducers (Velomitor*) are recommended at each bearing location, using a mounting position as close as practical to the mounting position of the shaft relative proximity probes. If the signals will be summed for a shaft absolute measurement, both the proximity transducers and the seismic transducers need to be mounted on the same structure. Care must be exercised to ensure that the mounting position provides a meaningful indication of the bearing relative and bearing absolute vibration behavior. Note: A Bently Nevada Velomitor is an accelerometer-based device with internal electronics that integrate the signal; the output of the device is in velocity units. Note: Accelerometers are not suitable for bearing absolute vibration, because it would require double integration of the signal at the monitor, which greatly increases susceptibility to noise. Note: Moving coil velocity transducers are not suitable for bearing absolute vibration. Moving coil transducers have suspension springs which have a finite service life; failure of the suspension springs may occur after a relatively short period of service. The presence of high-vibration in a plane perpendicular to the transducer's direction of measurement (“cross axis vibration”) significantly reduces the service life of the transducer and can cause signal spiking. Figure 2, illustrates an example of a typical installation.

Figure 4: Example of mode identification probes on spool pieces

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application note 6.1.3 Mode Identification Probes Mode shape identification probes can be useful to view the true mode shapes of the coupled turbine rotors and generator rotors. The span between two machine cases can be very long and mode identification probes can help identify issues such as misalignment, shaft mode shapes and balance issues. Mode shape identification probes are a set of XY proximity transducers, mounted between bearings on the coupling side, that observe a jack shaft or spool piece near the coupling. These mode shape probes are optional, but can prove to be useful for machine diagnostics. If the end user desires, these can be connected to a 3500/40 or 3500/42 for enhanced diagnostics.

6.1.4 Radial Vibration Monitors The 3500/42M Proximity/Seismic monitor is the recommended monitor for this application. Configuration of 3500/42 monitors should take advantage of the many variables that can be configured in this monitor. The 3500/42 incorporates alert and danger time delays to avoid nuisance alarms. Time delay settings for radial vibration measurements should not exceed three seconds for alert and one second for danger on TG sets. Actual time delays for alert and danger need to be determined by the machinery OEM or customer.

Shaft Relative For shaft relative measurements, alert and danger should be configured for the following parameters: overall direct values and probe gap voltage alarms. Alerts should be configured for 1X amplitude and phase, 2X amplitude and phase, not 1X, and Smax dependent on geographical region. Smax is defined in ISO 7919-1 as the maximum peak to peak shaft vibration. For a circular orbit, Smax and the X or Y vibration are identical. For an orbit where vibration is purely in a line oriented at 45 degrees relative to the X and Y probe mounting axes, direct vibration (measured by the probes) will understate the true vibration amplitude by 30%. This error is not generally a significant issue for machinery monitoring, and it is generally ignored. Some geographical regions may require Smax to eliminate this concern.

Bearing Absolute For bearing absolute measurements, alert and danger should be configured for the following parameters: overall direct values. Alerts should be configured for 1X amplitude and phase and 2X amplitude and phase.

Shaft Absolute Shaft absolute is a vector summation of shaft relative and bearing absolute amplitude and phase to provide a shaft absolute measurement equal to that provided by the obsolete shaft rider sensor. Alarming can be provided on shaft absolute, but shutdown using shaft absolute is not recommended because of the risk for false shutdown due to errors in the summation process. It may be appropriate to alarm and shutdown on the absolute bearing vibration if the stiffness of the bearing allows significant absolute bearing motion. End users may also require shutdown on shaft

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absolute to allow correlation of machine data previously gathered using shaft riders. However, the end user needs to be aware that there is an increased risk for false alarms and shutdowns when shaft absolute is the shutdown parameter. Shaft relative should always be the first line of defence on these large turbomachines. If shaft absolute vibration is to be monitored, the vibration signals from the X-Y shaft relative probes and the X-Y bearing absolute transducers should be connected to monitor channel pairs in a single monitor module. Caution: When a bearing absolute vibration signal is integrated from velocity to displacement, high-pass filtering of the signal is required. The high-pass filter must have a corner frequency setting not lower than 10 Hz (600 cpm) in frequency. In many cases a setting of 15 Hz may be applicable. Filtering is applied to eliminate low-frequency noise from the velocity signal to obtain an accurate and stable integrated displacement signal. When the machine operating speed is in the region of the high-pass corner frequency, significant errors in amplitude and phase of shaft absolute vibration signal may occur. These errors will be especially apparent during start-up or shut-down when the shaft rotative speed (1X or synchronous frequency) passes through the corner frequency of the high-pass filter. Non-synchronous vibration (nX frequency) will be affected according to the actual vibration frequency relationship to the filter corner frequency.

6.2 Thrust / Axial Position 6.2.1 Thrust Position Thrust position is the measured axial position of a machine rotor relative to the thrust bearing. The thrust bearing is the point of axial constraint of the rotor within the machine casing. Ideally, the thrust bearing must be fixed in the machine case, if it is not, then an additional application measurement called rotor position (defined below) must be made. Under normal operation the rotor can shift axially within the clearance limits of the thrust bearing. This movement is known as axial float or end float. The range of float (the “float zone”) is mechanically set and is a direct function of the size and design of the machine. The float zone is determined by measuring the tightest clearance between the stationary and rotating elements of the machine being monitored and then adjusting the position of the thrust bearing (shimming) to some percentage of that clearance as defined by the OEM or customer, and then locking the bearing into position. The shimmed float must be less than the tightest clearance between the rotating and stationary elements with thermal factors taken into consideration. The thrust bearing takes the axial load being applied to the turbine and under normal operation prevents stationary and rotating element axial rubs. A thrust bearing failure can quickly lead to a catastrophic machine failure. Because of the potential for rapid thrust bearing failure, thrust monitors are nearly always enabled for machinery shutdown. The dual voting thrust monitor, 2 out of 2 voting (2oo2), was developed by Bently Nevada in the early 1970s to increase the reliability of this shutdown measurement. Two proximity

application note transducers must be installed in an axial plane at each thrust bearing in order to detect thrust bearing degradation and/or failure. Thrust monitors set up in a dual voting configuration, 2 out of 2 (2oo2), has a proven reliability in machinery protection. The dual voting 2oo2 is a best practice as recommended in API 670. An OEM or end user may specifically request a triple modular redundant (TMR) configuration, 2 out of 3 voting (2oo3), to conform with local operating practices or to achieve a required SIL level. When OEM’s or end users require triple modular redundancy (2oo3 voting), a separate monitor is required for each transducer and a TMR Relay card is required. If TMR or 2oo3 thrust voting is requested, GE Bently Nevada FAEs are available to provide assistance.

of-specification probe response and inaccurate readings. This becomes even more important with larger transducer sizes (25mm, 50 mm), where side view constraints can severely limit use with small thrust collars. Contact your FAE for advice. The linear range of the transducer used must be suitable for expected rotor axial position changes relative to the thrust bearing under both normal and abnormal thrust bearing loading and wear. A common mistake on steam turbine generators is to make the monitored thrust position too small and built around the axial float. The system should be designed to look at the total range of potential rotor axial position change in reference to the thrust bearing INCLUDING designed or worst case thrust bearing wear. When designing for this application it is mandatory to understand the tightest axial clearance of rotating to stationary components, typically in the HP turbine. The thrust bearing is designed to take the turbine load and to restrain the rotor so that this clearance is never exceeded. In the event of thrust bearing wear it is ideal to be able to monitor that wear and manage a safe shutdown of the machine before an axial rub occurs.

Figure 5

Thrust position has to be measured by two or more proximity probes, which observe the thrust collar or other integral, axial shaft surface relative to the thrust bearing or non-moving integral support. The preferred mounting arrangement for the thrust position transducers is directly attached to or through the thrust bearing, however in many cases the machine design does not permit this. Thrust position transducer installations may also be engineered to observe the end of the shaft (within 300mm or 12 inches from the thrust bearing), or another integral collar on the shaft (within 300 mm or 12 inches from the thrust bearing) but only if the thrust bearing is an integral component within the machine casing (it does not move). The 12 inches is recommended in API 670 based on the following: •

Example calculation: 12 inches (300 mm) of 4140 steel with a temperature change of 100°F (38°C) will grow 0.008 inches (0.2 mm). Therefore, the measurement will show 8 mils. of apparent thrust motion that is due only to thermal growth. This must be considered when establishing thrust Alert and Danger setpoints.

If the location of the thrust position transducers requires observing a shrunk-on or bolt-on collar, only one of the two or three voting transducers should observe that collar. The other transducers should observe an integral part of the shaft. Otherwise, if the collar were to come loose, the shaft could move and provide a false indication of axial position change. Specialty transducer designs such as “Button probes” and “Right Angle probes” may be employed when the geometry of the machine prohibits the use of standard transducers. For most applications, custom transducer mounting brackets will be required to adapt the transducers to the proper mounting location and observed surface. Shown in Figure 6 below.

Figure 6: Thrust Position & Keyphasor Installation

The figure above depicts a thrust position installation on a steam turbine generator with 3300 Series 8mm proximity probes. The custom-made bracket allows the probes to be mounted on the thrust bearing so that they observe an adjacent collar. In this particular example, the mounting brackets also serve as a mounting bracket for the Keyphasor* probes, which is fairly common. This particular installation clearly illustrates the use of safety wire to secure all nuts and bolts. The extension cables would have been secured to the machine case and sealed where they exit the machine with a Bently Nevada 43501 cable seal.

Thrust collars must be large enough to ensure adequate side view clearance and provide the minimum required observed target size for installed probes. Either situation can result in out-

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application note 6.2.2 Rotor Position Measurement Some large steam turbines have thrust bearings that have axial clearances relative to the machine casing. For these machines, the measurement of the rotor position relative to the thrust bearing may not provide adequate warning of insufficient axial clearance between the rotating and stationary elements of the machine. In these cases a second measurement, rotor position, is used to measure the axial position of the machine rotor relative to the casing. For machine designs where the thrust bearing is designed such that it can move within its point of constraint (casing), an additional set of transducers needs to be installed to measure rotor position relative to the machine. In this case both thrust position and rotor position are required measurements for proper machine protection and diagnostics (See Figure 7). In Figure 7, the left drawing illustrates a machine where the thrust bearing supports are integral with, or are rigidly connected to,

the machine casing. For such a machine, the thrust position measurement will be adequate for monitoring the axial position of the rotor within the casing, as well as the axial position of the thrust collar within the thrust bearing itself. The right drawing in Figure 7 shows a larger machine (such as a mid or large power generation steam turbine) where the thrust bearing is supported independently of, and is able to move separately from, the machine casing. For such a machine, the thrust position measurement alone may not be adequate for indicating the axial position of the rotor within the casing. In this situation, it is appropriate to install a separate probe (or set of probes) to directly measure the axial position of the rotor relative to a fixed point on the machine casing. For these machine designs, both Thrust Position and Rotor Position are required from proper machinery protection.

Figure 7

The actual installation will require the creation of two custom-made brackets to mount the probes on the machine case, adjacent to the thrust bearing, allowing the probes to observe a hub on the coupling within 12" (305mm) of the thrust bearing. Probes and brackets should be installed using safety wire to secure the nuts and bolts. The extension cables will also be secured to the machine case and sealed where they exit the machine through a Bently Nevada 43501 cable seal. It is recommended that two separate brackets are used, affixed to the machine case."

6.2.3 General considerations for proper Thrust Position and Rotor Position measurements If the installation requires observing a shrunk-on or bolt-on collar, only one of the dual voting probes should observe that collar. The

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second probe should observe an integral part of the shaft. If both probes are viewing the collar and the collar becomes loose, the shaft could move without any indication on the monitor, resulting in a missed trip, or collar motion could cause a false trip. If one of the probes is observing the shaft and one the collar, the monitor will show a discrepancy between the two probe readings visible on the monitor alerting the operator. As noted above the Thrust Bearing is the point of constraint of the rotor within the casing. When designing for this application it is always good to understand the tightest axial clearance of rotating to stationary components, typically in the HP Turbine. The Thrust Bearing is designed to take the turbine load and to restrain the rotor so that this clearance is never exceeded. In the event of Thrust Bearing wear it is ideal to be able to monitor that wear and manage a safe shutdown of the machine before an axial rub occurs.

application note 6.2.4 Thrust/Axial Position Monitors For thrust position, a 3500/40M, 3500/42M or 3500/45 monitor can be used. Thrust position measurements are made using as a minimum, 2 out of 2 voting with both channels wired to the same monitor. The transducers can be wired to the same monitor or for additional redundancy, separate monitors can be used. If transducers are wired to different monitors, failure of one module does not impact the operation of the protection system.

6.3 Keyphasor The Keyphasor signal is a once-per-turn voltage pulse provided by a transducer, normally a proximity probe that is used for the measurement of machine rotative speed and the phase lag angle of the vibration. The Keyphasor signal is essential in the generation

Keyphasor information can help the operator or machinery specialist identify developing machine problems or distinguish serious problems from less serious ones. A Keyphasor transducer must observe the shaft of the driver. In machine trains with shafts turning at different speeds, a Keyphasor must observe each shaft speed. The target notch or protrusion shall be designed to generate the correct signal at all machine states and care must be taken to place the Keyphasor transducer in the correct location. A Keyphasor transducer should be located as close to the thrust bearing area as possible to minimize thermal growth effects which could move the reference marker out of view of the transducer. The notch or projection must be integral to the driver rotor, not the coupling or coupled component. When reference markers are located on non-integral rotor components such as couplings, stub shafts, jack shafts and shrunk on collars, historical phase information may be jeopardized due to rearrangement of the rotor components during reassembly after an outage. Because notches are stress concentrators, they should not be located in high torque areas, such as at coupling hubs or flanges. Notches or projections should be designed into the machine. The design should include proper internal radiuses, with the width, depth or height and length based on transducer type, rotative speed and rotor size. They should be lined up with the #1 balance hole, 0° on the balance ring, or some other obvious feature of the shaft.

Figure 8

of much of the information regarding the condition of the machine, including shaft rotative speed. Because loss of Keyphasor information severely impacts machine monitoring and diagnostics, installation of redundant Keyphasor probes is a recommended best practice. This is especially critical for machines with internally mounted transducers. A spare transducer should be installed, with the extension cable routed to the transducer interface housing, external to the machine. The Keyphasor signal is used for monitoring, diagnostic, and management systems to generate filtered vibration amplitude, phase lag angle, speed, and a variety of other information, including vector information for balancing the rotor. It is also an essential element in measuring rotor slow roll bow or runout information.

Figure 9: Motor Thermal Growth Effects

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application note

Figure 10: Example of Keyphasor notch and projection

An axial Keyphasor transducer is not normally recommended and should never interfere with or double as a thrust position transducer. Keyphasor transducer locations, angular mounting orientations, and notch locations should be properly documented. Accurate documentation is critical to the proper use and configuration of diagnostic instruments and software.

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Of the two methods for obtaining a Keyphasor pulse, a notch is more desirable than a projection because a notch is easier to set up and is less likely to damage the probe. When the marker is a notch, the probe gap is set while observing the smooth shaft surface, not the notch. When the marker is a projection, the probe gap is set while observing the top of the projection.

application note

Figure 11

6.3.1 Keyphasor Module For Keyphasor Signals, a 3500/25 module is used. These modules are ½ the height of a standard monitor and has two Keyphasor signal connections. Two Keyphasor modules can be installed in a rack position for a total of 4 Keyphasor signals per rack.

The eccentricity transducer provides two measurements, direct Eccentricity, which is the instantaneous eccentricity value, and peak-to-peak eccentricity, which is the difference between the positive and the negative extremes of the rotor bow. Peak to peak eccentricity requires the use of a Keyphasor transducer to determine one full revolution of the machine shaft.

If a tachometer (3500/50) card is used in the rack and the tachometer is driven by the Keyphasor probe, the tachometer can double as the Keyphasor module, in which case no Keyphasor card is needed.

6.4 Eccentricity In large steam turbines, it is desirable to provide an indication of eccentricity at slow-roll, also called peak-to-peak eccentricity. Eccentricity is the amount of bow in the rotor measured at slow roll speeds, typically below 600 RPM. Eccentricity is best measured by the peak-to-peak amplitude as the rotor turns on turning gear. Before a machine can be brought up to speed, the peak-to-peak amplitude has to be at an acceptable level, to prevent damage to seals caused by rotor rubs. Eccentricity is measured by a Proximity Probe, typically mounted at the high pressure steam turbine. Eccentricity: A single shaft relative non-contact proximity transducer installed on the HP turbine (normally NDE) to observe potential rotor bow conditions. The eccentricity measurement is made with a proximity probe mounted away from the bearing so that maximum bow deflections can be measured. Most machines that require this measurement already have an “eccentricity” collar designed on the rotor specifically for making this measurement. Since there is a mass suspended between two bearings, common causes of bow in the rotor are gravity and temperature changes. By slow rolling the machine, the bow will work itself out over time.

Figure 12

6.4.1 Eccentricity Monitor For eccentricity, a 3500/40M or /42M monitor is used. The eccentricity monitor can be programmed to display both instantaneous eccentricity and peak-to-peak eccentricity. For peak to peak eccentricity, the eccentricity channel needs to be associated with the Keyphasor sensor.

6.5 Speed Measurements In a typical TSI installation, several types of speed related measurements are made. These are rotor speed, zero speed and rotor acceleration. The same transducers can be used for all three measurements. For zero speed, two transducers are required to minimize the generation of a false zero speed indication due to a transducer failure.

13

application note 6.5.1 Rotor Speed (Tachometer) Machine speed measurements are typically made by a Proximity Probe observing a keyway or multi-event wheel or gear. A multi-event wheel provides faster updates of speed changes and increased resolution of the speed measurement at slow speeds. The 3500/50 tachometer also allows up to four Danger/Alarm 2 setpoints (two over and two under setpoints). If observing a turning gear, it is recommended to use an 11 mm reverse mount probe installed in a 21000/31000 assembly. If using a multi-toothed wheel, the transducer can also be used for zero speed and rotor acceleration measurements, but two transducers should be installed to make these measurements.

6.5.2 Zero Speed Zero speed is a speed measurement that indicates the machine is nearing or has reached zero RPM (thus the term “zero speed”). The zero speed set point can range between 0 and 300 RPM. When the zero speed set point has been reached a relay can be activated. Zero speed is measured by two proximity probes observing a multievent wheel.

Figure 13

Zero speed monitoring is frequently used as part of a permissive for the engagement of the turning gear For turbines that require zero speed indication, two probes must be utilized in lieu of a single Keyphasor transducer. Most often, zero speed measurements are used on steam turbine generators to indicate that the shaft has reached a pre-selected speed Magnetic pickups are not recommended for zero speed because the signal pulses become too small to be useful at low speeds.

6.5.3 Rotor Acceleration Rotor acceleration is the rate of acceleration of a rotor (rpm/minute) as its speed increases from zero rpm to running speed. The machine operator needs this information to prevent operational errors and to help get the machine up to speed without damage. This measurement is most often used on large turbine generators that require a slow rate of acceleration while machine components expand as they reach operating temperatures. Rotor acceleration is measured by a proximity probe observing a multi-toothed wheel. Rotor acceleration is sometimes used in smaller machines instead of a differential expansion measurement. Following the OEMs rotor acceleration guidelines is essential to assure that the casing and rotor thermal growth rates stay within the OEMs limits during machine startup.

14

Figure 14

application note 6.5.4 Overspeed Overspeed of machines can cause catastrophic damage to the machinery and plant. An overspeed detection system detects when a turbine exceeds its rated operating speed. An overspeed condition can be caused by a number of conditions ranging from a coupling failure, a control valve malfunction, a turbine overspeed test, a control system failure etc. Bently Nevada provides the 3500/53 Overspeed Detection System (OSD) or the 3701/55 Emergency Shutdown Device (ESD) as a speed detection component of an overall Overspeed Emergency Shutdown system.

Three (3) non-contact proximity transducers (ODS speed transducers) should be installed on the driver and mounted in the same radial plane. No secondary shafts or gears are allowed and sensors cannot be on the driven side of any coupling. Other control system sensors, such as governor speed are to be independent of the ODS speed transducers.

Figure 15

Figure 16

Typical Overspeed System 1. Interposing Relays

6. Trip valve

2. Control oil supply

7. Power supplies

3. Solenoid

8. 3500 Overspeed Detection System

4. Drain

9. Operator

5. Fuel

15

application note For detailed information about an ODS, please refer to the best practice ODS document and application note. Due to the complexity and criticality of the design of an Overspeed Emergency Shutdown system, Bently Nevada recommends that any request for a complete Overspeed Emergency Shutdown be quoted separately from the TSI system. The GE M&C Controls group can handle these quotations.

6.5.5 Speed Monitors For speed measurements, a 3500/50 tachometer is used. The tachometer can be programmed to display speed, zero speed and rotor acceleration. Each of these measurements can be programed to provide alarms. The tachometer can accept signals from a transducer observing a multi-toothed wheel or a Keyphasor transducer. Using a multi-toothed wheel results in a faster tachometer update time when monitoring a lower speed machine or a machine on turning gear. A tachometer module may be used in lieu of the Keyphasor module when a Keyphasor transducer is used for speed indication. The 3500/50M tachometer modules are two-channel modules that accept a pulse input from either a proximity transducer or a magnetic pickup when used with multiple events. Caution: The Bently Nevada 3500/50M tachometers are not designed for use independently as, or components of, a speed control or overspeed protection system. The monitors do not provide the protective redundancy and the response time needed for reliable operation as a speed control or overspeed protection system.

6.5.5.1 Zero Speed The 3500/50 tachometer is designed to indicate zero speed but should not be used to automatically engage the turning gear or automatically activate some other process. The zero speed input can be a Keyphasor signal or multi-event signal from a proximity probe. The Zero Speed function requires inputs from two transducers. Voting logic between two transducers minimizes false zero speed indication in the event of a failed transducer.

6.5.5.2 Rotor Acceleration Although this monitor has alarms for positive or high acceleration rates, it is typically used for indication only.

6.5.5.3 Overspeed An Overspeed Detection System (ODS) can be part of a TSI system, however a stand-alone ODS or ETS Module is the recommended Best Practice (i.e. separate rack, power supplies etc.). When the ODS is placed in a rack with other monitors, there is a possibility a failure of one of the other monitors causing the OSD to trip the machine. Please reference the Overspeed Detection best practice document.

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6.6 Expansion 6.6.1 Differential Expansion Differential expansion is the relative thermal growth between rotating and stationary parts, and it is a vital parameter in the operation and management of large steam driven turbines. It is a critical factor in avoiding internal rubs during the start-up of the turbine since the non-rotating parts and the rotating parts have significantly different thermal mass and will grow at different rates. Wherever practical, end users should install a redundant Differential Expansion probe and route the lead to an external junction box. This allows the end user to switch to the backup sensor should the internal probe fail. The harsh environment within the casing and potential for the probe to be exposed to high-temperature steam, increase the possibility of Differential Expansion probe failures. Under similar conditions of cooling or heating, casing and rotor contraction and expansion characteristics can be different. Expansion differences are always present in machinery that is heated or cooled as a result of operation or process performance. Thermal contractions and expansions of machine trains are proportional to the size of the machinery involved. The machine case consists of the non-rotating elements (case, nozzle blocks, guide vanes, etc.) and houses the rotating elements (rotor, shaft with assembled wheels, vanes, etc.) necessary to accomplish the intended work. Proper location and position of the differential expansion transducer is as important as the range capability of the transducer. The expected growth differential should be based on the tightest allowable casing to rotor clearance which may be obtained from the original equipment manufacturer and/or customer. With the acceptable growth differential known, the proper transducer can be selected and installation methods determined to assure clearances are maintained during the start-up. Depending on the size of the turbine there may be more than one differential expansion measurement location.

application note 6.6.2 Single Differential Expansion

6.6.3 Complementary Input Differential Expansion

Figure 17

The drawing above illustrates a method of measuring differential expansion using a single transducer. The transducer is referenced (attached) to the case and measures the rotor thermal contraction and expansion relative to the case. Note: knowledge of expansion toward the probe (top) or away from the probe (bottom) needs to be known to properly set up the DE monitor.

Figure 18

The drawing above illustrates a complementary input application. Probes may be as shown in the diagrams above. The range of one probe is complemented by the range of the second probe. This installation allows the measurement of twice the range of a single probe.

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application note 6.6.4 Ramp Differential Expansion

Figure 19

The drawing above illustrates a probe installation on a shaft with dual ramps. Two probes (A and B) are necessary to determine the shaft radial position shifts unrelated to differential expansion. Ramp differential expansion can be measured on ramps of 5° to 45°. Measurable range depends upon the angle of orientation and the linear range of the transducer used.

When quoting differential expansion, as with any proximity system, target size and side view needs to be a consideration. Transducers that are used in differential expansion measurements are our 50 mm, 25 mm, 16 mm or 11 mm transducers. Below is a chart showing the minimum target size required for each of the transducers Probe Size

Minimum Target

System Linear Range

50 mm

102 mm (4.0 in) or larger

27.9 mm (1100 mils)

25 mm

61 mm (2.4 in) or larger

12.7 mm (500 mils)

16 mm

31 mm (1.2 in) or larger

4.0 mm (160 mils)

14 mm

31 mm (1.2 in) or larger

4.0 mm (160 mils)

11 mm

31 mm (1.2 in) or larger

4.0 mm (160 mils)

35mm transducers are no longer available for new sales. Figure 20

The drawing above illustrates an application on a shaft with a single ramp. Two probes (A and B) are necessary to determine the shaft radial position shifts and differential expansion. The A or A1 probe is used to determine shifts in radial position, while the B probe determines differential expansion. Shifts in radial position seen by the A or A1 probe are used to modify the B probe reading to provide an accurate differential expansion measurement.

18

If insufficient target area is available for a system that can cover the range requirements, two smaller probes observing a collar in a complementary fashion can be used (Figure 18) or two probes observing ramps on the shaft (Figure 19).

application note When using probes observing a ramp, consult the chart below for transducer selection. Allowed ramp angles in degrees for various ramp transducers and full-scale ranges. Composite Full-scale Range

3300XL 11mm, 3300 16mm HTPS, 7200 11 & 14mm

3300XL 25mm, 25mm and 35mm Extended Range

50mm DE and 50mm Extended Range

3300XL 50mm

5-0-5mm 2-0-8mm 0 - 10mm Custom

4 to 18

4 to 45

11 to 45

11 to 45

0.25-0-0.25inch 0.15-0-0.35inch 0 - 0.5inch Custom

4 to 15

4 to 45

11 to 45

11 to 45

10-0-10mm 5-0-15mm 0 - 20mm Custom

4 to 9

4 to 33

11 to 45

11 to 45

0.5-0-0.5inch 0.25-0-0.75inch 0 - 1.0inch Custom

4 to 7

4 to 25

11 to 45

11 to 45

25-0-25mm 10-0-40mm 0 - 50mm Custom

Not allowed

4 to 12

11 to 28

11 to 28

1.0-0-1.0inch 0.5-0-1.5inch 0 - 2.0inch Custom

Not allowed

4 to 12

11 to 28

11 to 28

1.10-0-1.10inch 0 - 2.20inch 28-0-28mm 0-56mm

Not allowed

Not allowed

Not allowed

11 to 28

6.6.5 Rotor Expansion

6.6.6 Special Applications

Rotor Expansion is the measurement of the rotor thermal expansion measured from a non-rotating fixed point, such as the machine foundation. The difference between differential expansion and rotor expansion is that in differential expansion, both the nonrotating and the rotating elements expand (or contract) and in rotor expansion, the non-rotating element is fixed, while the rotating element expands.

In addition to the above common differential measurements there are additional types of differential expansion measurements, such as a collar that is too small for proximity probes. On some machines, a magnetic pendulum is used which employs magnets to follow a short collar. The movement of the top of the pendulum is measured with proximity probes to derive the differential expansion of the rotor.

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application note 6.7 Dual Case Expansion Case expansion is a measurement of the machine casing growth relative to its foundation. During startup of a steam turbine, thermal growth of the casing is expected. Casing expansion can be measured at multiple points along the machine train and is used to confirm proper case thermal growth. Often, casing growth is accommodated by sliding guides on either side of the case that are designed to slide as the case grows. Nonuniform case expansion can occur when one side of the casing guide sticks or the casing does not expand uniformly. This condition can cause misalignment of rotor to casing components potentially leading to a rub, excessive vibration, or thrust bearing failure. Dual case expansion measurements are used to detect non-uniform casing growth and to annunciate this condition, but are generally not used as an input for automatic turbine shutdown. Best practice is to measure both sides of the case using Linear Variable Differential Transformers (LVDT’s). Figure 21 shows the application of 2 LVDT’s to measure Case Expansion

6.8.1 Linear Variable Differential Transformer (LVDT) Application If the predominant motion for making the valve position measurement is linear (not a cam or rotating motion), use an LVDT. Due to high temperatures at the valve location, AC type LVDTs are always used. It is best practice to install the LVDTs with weatherproof housings. Several types of valve position measurements can be made requiring anywhere from one to eight LVDTs. The application and quantity are based upon the design of the machine. The biggest concern when installing LVDTs for valve position measurement is high temperature, which can cause thermal expansion between various parts of the valve assembly. When installing LVDTs make sure the installation design will not damage the LVDT or valve assembly as thermal expansion between the valve assembly and the mounting brackets occurs. Figure 22 is an example of a typical valve position LVDT installation.

Note: If one sliding foot binds, it will show up as uneven growth. It is best practice to install the LVDT’s where the core is physical attached to the case rather than use a spring return core. Over time, the spring can wear out and dirt build-up can prevent the core from moving. Physically attaching the core connecting rod to the transducer target bracket eliminates this problem.

Figure 21

6.8 Valve Position Valve position – is the measured position of a valve stem or cam in relation to valve opening or “crack” and full valve stroke. These measurements are most often made with Linear Variable Differential Transformers (LVDT’s), or with Bently Nevada’s specially designed linear rotary position transducers (LRPT’s). This measurement is used to validate steam flow and is measured as a percent of full or 100% open. Valve position can be measured on various valve installations such as throttle valves, stop valves and control valves. In our application, these transducers are not used for machine control and must be completely independent of valve position sensors used for the control of the turbine. Any valve position sensor used in the control loop of the turbine must never be paralleled into the Bently Nevada TSI system.

20

Figure 22

The LVDT mounts to a stationary assembly with a bracket and the LVDT connector rod (plunger) attaches to the moving valve linkage with a connector rod bracket. Connecting the core to the bracket with a “ball joint rod end” works well, because it allows easy adjustment and locking of the core to set up the zero point and it rotates in all planes to accommodate thermal expansion.

application note 6.8.2 Valve Position - Linear Rotary Position Transducer A linear rotary position transducer is used to measure valve position on rotating cam applications. The Transducer is mounted to the end of the valve cam assembly by attaching the transducer housing to the Valve block (stationary) and connecting the Transducer shaft to the rotating cam with a coupling. The centerline of the input shaft must coincide with the centerline of the rotating part. If the shaft and rotating part are off center, stress could damage the transducer and cause erroneous measurements.

Best practice for temperature sensor installations is described in API 670. For radial bearings, API 670 uses the definition of short and long bearings as shown in the picture below. API 670 defines long bearings as having a length/diameter (L/D) ratio greater than 0.5. Short bearings have an L/D < 0.5. For long bearings, API recommends temperature sensor placement at 25% of the length from each end. For short bearings, mount the sensors in the middle. In the case of big turbine-generator bearings there is nothing wrong if the distance between the measurement points is > 50%. Note: The sensors are mounted in the minimum film thickness location of the bearing for normal loading in a well-aligned horizontal machine. 2-axial plane temperature measurements are useful when a misalignment between the bearing and the shaft occurs. Figure 24 presents a situation where having only one transducer in the mid part of the bearing could possibly miss the misalignment of the bearing – rotor system.

Figure 23

6.8.3 Expansion / Valve Position Monitors For Differential Expansion, Case Expansion and Valve Position a 3500/45 monitor is used. Differential expansion, DC LVDT’s (case expansion) and linear rotary position transducers use the same IO module, while AC LVDT’s, often used for valve position uses a different IO module.

6.9 Temperature Monitoring Temperature transducers for condition monitoring systems are an important source of data for condition monitoring and machine protection. Temperature changes can be an indication of change of mechanical condition of a machine component, and can be correlated with vibration changes. Temperature can also be correlated to changes in the process. Typical TSI temperature measurements include radial and thrust bearing metal temperatures and bearing lube oil temperatures.

6.9.1 Radial Bearing temperature Babbitt bearings are susceptible to excessive temperature and many of the failure modes in turbine-generator sets will cause an abnormal temperature in one or more bearings. The location of the sensors and the choice of RTD vs. thermocouples is based on OEM recommendations and/or end user preferences.

Figure 24

The rules of temperature transducer location for multi-pad bearing are clearly described in API 670.

6.9.2 Thrust / Axial Temperature Measurements Thrust bearing metal temperature is measured on both the active and inactive thrust bearing segments. The location of the sensors and the choice of RTD vs. thermocouples is based on OEM recommendations and/or end user preferences. Best practice for temperature sensor installations is described in API 670. Note: The thrust bearing position measurement should never be voted with thrust bearing temperature for the danger alarm. This voting was promoted by some end users in the past based upon the premise that excessive thrust motion also generated elevated bearing temperature. There are two reasons not to do this. First, temperature measurements can have a long lag time because of the time it takes for surface heat to heat the bearing babbitt and reach the sensor. This can produce a significant time lag that will delay protection alarming. Secondly, an internal rub frequently occurs at the limit of the thrust motion which will unload the bearing and cause the temperature to fall below the alarm level and prevent a danger alarm resulting in damage that could have been prevented by tripping on thrust position.

21

application note 6.9.3 Bearing lube oil temperatures Bearing lube oil temperature measurements are used to detect changes in inlet and outlet temperatures across the bearing. It provides an indication that oil temperatures remain in an acceptable range. This measurement can help provide an indication of problems with bearing loading or the lubrication system. It is best practice to make two bearing lube measurements for each bearing. They are: •

Input oil temperature

•

Output oil temperature

For normal operation at steady state load, the difference between these temperatures should not change significantly. Changes in either direction can indicate a problem.

accept isolated tip thermocouples, 3-wire RTD, 4-wire RTD, or a combination of TC and RTD inputs. The 3500/65 does not provide recorder outputs. When using thermocouples, the length of the field cable run needs to be considered. If temperature transmitters are used (typically providing a 4-20 mA proportional signal) and the customer wants to incorporate these temperature measurements into their TSI system, a 3500/62 monitor can be used. The 3500/62 process variable monitor is a 6-channel monitor for processing machine critical parameters (pressures, flows, temperatures, levels, etc.) that merit continuous monitoring. The monitor accepts +4 to +20 mA current inputs or any proportional voltage inputs between -10 Vdc and +10 Vdc. It conditions these signals and compares the conditioned signals to user-programmable alarm setpoints. If needed, temperature monitors can be configured to make differential temperature measurements.

6.9.4 Additional optional temperature measurements

6.10 Monitoring – Other

For steam turbine generators additional temperature measurements can be incorporated in a TSI system. These measurements can include:

6.10.1 TSI Monitors General

•

Seal temperatures

•

Generator Temperature Monitoring

Note: Most generators have temperature sensors designed in the windings.

The recommended platform for turbine supervisory instrumentation is the 3500 system. The 3500 system provides continuous, online monitoring suitable for machinery protection applications, and is designed to fully meet the requirements of the American Petroleum Institute’s API 670 standard for such systems. The system’s components consist of:

6.9.5 3500 Temperature Monitors For condition monitoring purposes it is best to have the temperature measurements discussed above connected to the 3500 rack dedicated to the steam turbine/generator. This configuration is shown by the 3500/65 monitors in the example TSI system in Figure 1. The reason for this is that all measurements for the machine are made at the same moment when connected to System 1 software. Time stamping provided by various DCS systems can be very different, and therefore data will be hard to correlate. For temperature measurements, a 3500/60, 3500/61 or 3500/65 monitor is used. The 3500/60 & 61 modules provide six channels of temperature monitoring and accept both resistance temperature detector (RTD) and thermocouple (TC) temperature inputs. The modules condition these inputs and compare them against user-programmable alarm setpoints. The 3500/60 and 3500/61 provide identical functionality except that the 3500/61 provides recorder outputs for each of its six channels while the 3500/60 does not. The 3500/65 monitor provides 16 channels of temperature monitoring and accepts both resistance temperature detector (RTD) and isolated tip TC temperature inputs. The monitor conditions these inputs and compares them against user-programmable alarm setpoints. The 16-channel monitor can be configured to

22

•

3500/05 instrument rack(s)

•

Two 3500/15 power supplies per rack

•

3500/22M transient data interface module per rack

•

3500/32 6 channel or /33 16 channel relay card

•

3500/25 Keyphasor Module(s)

•

3500/92 or /91 Communications Gateway for connection to a DCS, historian or any other device accepting MODBUS inputs (Optional)

•

3500/94 display (optional)

•

Various TSI monitors as discussed under the individual transducer sections

The 3500 Series monitoring system has alarm set points, which automatically raise an alarm when the predetermined alarm level is reached. The 3500 monitoring system has alarm relays for alert and danger conditions, which can be used as an indication to an operator or as a permissive to a shutdown system. The radial vibration and axial position modules can be certified to SIL 1 if required by the end user.

6.10.2 Rack Chassis The 3500/05 Instrument Rack can be 19" EIA rack mount, panel mount, or bulkhead mount if access from the back of the rack is limited. If needed, panel mount racks can be mounted in a 3500/06

application note weatherproof housing. Multiple racks can be mounted in custom enclosures offered by Bently Nevada. Refer to the “Enclosures” section for more detail.

6.10.3 Power Supplies The 3500/15 power supplies can be configured with low and high AC or DC voltage options. True redundant power supply modules reside in the TSI rack(s) and operate in auto-changeover mode. Failure of one power supply module does not affect or interrupt the protection and monitoring functions of any module in the rack. Power regulation is done at the monitor level (not at power supply) so that in the event of a regulator failure, only a single monitor will be affected. The following input voltage options are available.

Supported protocols include: •

Modicon Modbus protocol (via serial communications)

•

Modbus/TCP protocol (a variant of serial Modbus used for TCP/ IP Ethernet communications)

The following measurements should be trended if appropriate for the measurement type: •

Overall channel level

•

Channel OK status

•

Channel alert and danger

•

Probe gap

•

Direct vibration amplitude

•

85 to 125 Vac

•

1X amplitude and phase

•

175 to 250 Vac

•

2X amplitude and phase

•

20 to 30 Vdc

•

Not 1X

88 to 144 Vdc

•

Smax (depending on region)

•

It is recommended that each power supply in the rack is powered from a different source for increased reliability. AC and DC power supplies can reside in the same rack. It is highly recommended that at least one of the power supplies is connected to an uninterruptable power supply (UPS).

6.10.4 Transient Data Interface (TDI) Module The 3500/22M TDI is the interface between the 3500 monitoring system and System 1 software. The TDI provides an interface for rack configuration using 3500/01 configuration software loaded on a portable computer. For enhanced security, the TDI incorporates key-lock access in conjunction with software passwords for rack configuration. It is recommended that the key is removed from the rack, kept in a secure place and only made available to authorized personnel to prevent unauthorized configuration changes. Every 3500 rack requires one TDI, which always occupies Slot 1 (next to the power supplies). Many end users have cyber security requirements built into their networkable equipment. Bently Nevada has numerous hardware, such as TDI_Secure, and service solutions available to cost effectively mitigate cyber security risks. Bently Nevada Services can work with users to identify the most cost effective solution for their needs.

6.10.5 Communication Gateway Module The 3500/92 communication gateway module provides communication capabilities of all rack monitored values and statuses for integration with process control and other automation systems using both Ethernet TCP/IP and serial (RS232/RS422/ RS485) communications capabilities. Every 3500 rack should incorporate at least one communications gateway for connection to a historian or DCS.

If an interface to a GE system that requires ethernet global data (EGD) is required, the 3500/91 EGD communication gateway module is used. EGD is a GE-proprietary protocol used in a wide variety of GE control and automation products such as programmable controllers, turbine control systems, plant data historians and human machine interfaces (HMI). Support of the EGD protocol provides customers with easier and less costly integration options when a 3500 system must share data with other GE control and automation products. The EGD protocol used in 3500 has been specifically tested to work with the GE SPEEDTRONIC* Mark* VIe turbine control platform, allowing the machinery protection system to integrate tightly with the turbine control system. Multiple Gateways of both types can reside in the same 3500 rack.

6.10.6 Relay Modules Two types of relay modules are available for the 3500 system, the 4-channel 3500/32 and 16-channel 3500/33 modules. The 3500/32 4-channel relay module and 3500/33 16-channel module are full-height modules that provide 4 or 16 relay outputs. Any number of 4 and or 16 channel relay modules can be placed in any of the rack slots to the right of the Transient Data Interface Module. Each output of the 4 or 16 channel relay module can be independently programmed to perform AND and OR voting logic. For machinery protection, at least one relay card shall be installed in each TSI rack. It is not recommended to use a Modbus link or 4-20 mA recorder outputs as an input to an auxiliary system for machinery protection. The TSI system considers the critical path to be from measured parameter sensor to the closure of the relay contacts. Modbus links and 4-20 mA recorder outputs are not considered part of the critical path for protection and thus may not provide the same level of reliability for machine protection as the relay contact closure. End users need to be aware of these potential limitations when these links are interfaced to their digital control systems.

23

application note The use of danger bypass is not recommended for turbinegenerators. In situations where machines temporarily exceed danger levels during a start up or shut down resonance, it is recommended that trip multiply is used. Extreme caution should be used applying trip multiply. It only should be used if the machine design dictates a trip multiply to pass the machine through a resonant frequency. Trip multiply maintains a level of protection against catastrophic failures during transient resonances. Levels of trip multiply should be determined by the customer or machinery OEM. Alert and danger levels should be based on machine configuration and design. Timed OK channel defeat (TOCD) is a feature that prevents the channel measured value from participating in alarm voting when the transducer is in a Not OK state. This feature is designed to prevent false alarms when noise in the transducer signal causes the signal level to repeatedly go beyond OK limits. For most radial vibration applications, 30 seconds after the transducer returns to an OK state, the channel measurement will be allowed to participate in alarm voting. This option is available only if the OK mode is set to Non-latching. The option to use TOCD is a customer preference. The customer end user should be informed of the risks and benefits of this feature. TOCD involves a trade-off between initiating a false alarm verses failing to initiate a valid alarm. The customers operating requirements should dictate the proper decision on use of this feature.

6.10.7 System Display The 3500/94 color VGA touch screen display is recommended for TSI applications if a local display is required.

6.10.8 Monitoring System Segregation Best practices for maintainability and availability dictate that each Turbine/Generator train should have a dedicated machinery protection rack (or racks). Combining multiple machine trains in one rack may hinder unit maintenance when one unit is down while the other is operating. Additionally, a failure occurring in a shared rack could potentially affect the monitoring and/or protection for multiple units. In summary: •

Turbine generating units should not share common racks (for example Unit 1 and 2 do not reside in the same rack.

•

Individual monitor modules may not be shared across machine trains.

24

•

Each machine is provided with its own relay module (where shutdown is required).

6.10.9 Monitoring Rack Expansion Capacity It is recommended that future system expansion is reviewed closely with the customer and that rack expansion slot capacity is defined. Whenever possible, there should be spare slots available for additional monitoring rather than filling every rack position.

6.10.10 System Enclosures (Packaged Systems) If free standing system enclosures (cabinets) are required it is recommended that Bently Nevada supply these enclosures. Full system configuration and factory acceptance testing (FAT) is available to assure full system functionality prior to system installation. Packaged systems provide a fully engineered, pre-mounted, pre-wired, site-ready, and factory-tested industrial enclosure solution for machinery protection and condition monitoring instrumentation. A packaged system is designed to simplify site installation, provide suitable protection for the installed instrumentation from the surrounding environment, and facilitate ongoing ease of use and maintenance. Packaged systems are supplied with all the needed enclosure and electrical drawings.

6.11 Installation Best Practices It is recommended that additional field wiring be pulled from the machine train to the instrument rack for future expansion and an additional 10% spares in the event of a cable failure and to facilitate adding monitoring capability in the future. Connector protectors should always be used, both internal and external to the machine. Often, the generator bearing pedestals are isolated. If this is the case, transducers should be isolated from the bearing. Phenolic isolation blocks are available as standard parts.

application note Additional Drawings and Photos

Figure 25 Absolute Vibration with Redundant Relative and Seismic Transducers.

Temperature: From a practical viewpoint, it is advised to use a similar approach to installing temperature sensors as is used to install Proximity Probes. This means that the temperature sensors have an integral cable with a connector that will work well in an oil environment. The cable length should match that of the proximity system, in most cases, 9 meters. Typically, silicon or Teflon™ cables are used for temperature transducers. Often, the connection of the temperature sensor cable to the extension cable is made under the bearing cover. Therefore, the same feed through that is used for XY transducer cables can be used for the temperature cables. A mechanical protection of the transducer cables between the feed through and terminal housing can be provided using flexible conduits.

7 Condition Monitoring / Machinery Management Many additional tools are available to monitor the condition of the machine. It is a best practice to use condition monitoring and management software tools. A vital element in performing machine management and diagnostics a reliable Keyphasor signal. As indicated in the Keyphasor discussion above, best practice is to install a redundant Keyphasor to assure that this signal is available for the machinery specialist and the diagnostic tools. It is also a recommended practice to input the Keyphaser signal into one channel of a 3500/42 monitor to allow capture of the Keyphasor signal. The System 1 software platform enables operators, equipment engineers, process engineers, instrument technicians, and other plant personnel to quickly identify, evaluate, and respond to important events. This increases equipment availability and reliability, and reduces maintenance costs.

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application note Best practice for System 1 software used on a TG set includes the following System 1 modules / capabilities:

Depending on customer needs/requirements, additional tools and services are available.

•

User notification

These tools / services include:

•

Anomaly detection

Decision Support:

•

Integration with DCS and plant historians

•

Thermal performance

•

Current values

•

Bargraph

Decision support is a system extender to System 1 software using pre-configured sets of rules designed specifically to perform real-time data validation, real-time calculations and analysis, and real-time detection of specific events and malfunctions. System 1 has steam turbine generator specific decision support tools which use the data to look for patterns that would indicate one or more known failure modes. Below is a list of the malfunctions that can be detected with these tools:

•

Machine train diagram

•

Shaft bow

•

Alarm/System event list

•

High synchronous vibration

Trend / multivariable trend/vector trend (amplitude/phase/time (APHT))

•

Fluid induced instability (Whirl and Whip)

•

Radial pre-load forces (Including Misalignment)

•

Tabular list

•

Acceptance region violation

•

Timebase (with option for superposition of baseline data)

•

Rotor rubs

•

Orbit / timebase (with option for superposition of baseline data)

•

Loose rotating parts

•

Orbit (with option for superposition of baseline data)

•

High runout

•

Shaft average centerline

•

Spectrum / full spectrum (with option for superposition of baseline data)

•

Campbell diagram

•

X vs. Y

•

Waterfall / full waterfall

•

Polar/acceptance region

•

Bode

•

Cascade / full cascade

Specific plot types are available in System 1 Display for Power Generation. For steam turbine generators the following plots should be configured as a best practice.

•

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Customer Training: Training on the use, maintenance and management of the systems should be included with every proposal.

Supporting Services: If an end user is not investing in in-house capabilities to support their condition monitoring equipment, a Bently Nevada Supporting Service Agreements (SSA) should be considered. . These agreements are tailored to the end users’ needs and a customized asset care service program can help to maximize the value of their investment in asset condition monitoring technology. These services can be performed on-site and are enhanced by remote connectivity. For additional help, contact your SSA regional lead.

application note

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© 2015 General Electric Company. All rights reserved. Information provided is subject to change without notice. Best practices and recommendations herein are applicable to most aeroderivative gas turbines contingent on OEM design and adherence to OEM guidelines.

GE Oil & Gas 1631 Bently Parkway South Minden, NV 89423

*Denotes a trademark of Bently Nevada, Inc., a wholly owned subsidiary of General Electric Company. The GE brand, GE logo, Bently Nevada, System 1, Keyphasor, Proximitor, Velomitor, RulePaks, Bently PERFORMANCE SE, ADRE, SPEEDTRONIC, Mark, and SmartSignal are trademarks of General Electric Company.

24/7 customer support: +1 281 449 2000 geoilandgas.com/

Modbus, Modicon, and Teflon are trademarks of their respective owners.

GEA31795 (05/2015)