Turbine-Generator Shaft Torsional Vibration Monitoring Using an RF-Powered Multi-Sensor Module - MTA-MA-013

Administrative Items
Date	12/15/2020
Functional Area Where Benefits Will Be Realized	Maintenance Engineering Probabilistic Risk Assessment
Reference Implementation Guidance	Strain-Based Turbine Generator Torsional Vibration Monitoring System – Phase 3: Prototype Field Application (EPRI 3002006234)
Industry SME	EPRI – Constantin Chitic-Foldi Contact: NuclearPlantMod@epri.com
Previous Implementation	Please contact EPRI for implementation examples and contacts.
Implementation Enablers	N/A
SWEEP Score	Cost – Level 3 – Implementation costs should be less than $1 million. Savings – Level 1 – Savings are less than $1 million per year. Payback – Level 3 – Torsional vibration testing is required for insurance stipulations. Thus, payback period is immediate compared to alternative OEM methods. Licensing Readiness – Level 3 – The technology has already been implemented at nuclear power plants. Technology readiness – Level 3 – The technology has already been implemented at nuclear power plants to satisfy insurance stipulations. However, TDMS’s ability to detect turbine‑generator failures early requires further research. Implementation proficiency – Level 3 – Technology does not require site‑specific experience related to wireless data infrastructure, wireless data transmission for maintenance and monitoring, or cyber‑security protocols, etc.
Applicability	All reactor types All geographic regions
Keywords	Natural frequencies; shaft torsional vibration; steam turbine generators; strain gage telemetry; torsional testing; turbine blade failure
Business Case Analysis Cross-Reference	N/A

Description

Shaft torsional vibration in power production turbomachinery can be induced by electrical grid transient disturbances and generator negative‑sequence currents. The resulting dynamic torque transmitted to the generator rotor via the air gap can excite torsional vibration modes of the entire shaft system. If severe enough, these vibrations can accumulate fatigue damage in highly stressed rotor elements such as turbine blades, couplings, and generator rotor retaining rings. These torsional vibrations are undetectable by normally installed plant instrumentation (e.g., lateral vibration probes) until later stages of failure. Therefore, if fatigue damage is occurring, it can lead to catastrophic failure without warning or with very short notice.

Torsional natural frequency testing is part of the loss‑control standards stipulated by insurers, such as Nuclear Electric Insurance Limited (NEIL). The conventional approach to meet insurance standards is to perform a one‑time torsional vibration test. This test is typically achieved by installing special monitoring instrumentation during an outage and then passively monitoring the torsional vibration of the rotor train during the subsequent restart, until the unit reaches full power and rotor train components reach their steady‑state operating temperature. This test can be performed through the turbine original equipment manufacturer (OEM), but cheaper and less invasive testing alternatives exist.

This MTA focuses on the EPRI Turbine Dynamics Monitoring System (TDMS), commercially provided by Suprock Technologies: a small, sensitive, and self‑powered (induced power supply) sensor that can monitor torsional strain and shaft surface acceleration during turbine‑generator operation. The TDMS sensor module satisfies the insurance standards for determination of torsional natural frequencies. It is attached through either an epoxy bonding process or a brazing option and is powered by radio‑frequency (RF) transmitters located about one meter from the turbine shaft. The module uses transceivers that continuously measure both strain and acceleration on the turbine shaft and wirelessly transmits data to stationary receivers that capture the data. Data can later be post‑processed by plant personnel and/or the vendor.

Since the instrument monitors both strain and acceleration in one sensor module, only one location along the entire rotor train is typically needed to allow monitoring of all critical torsional vibration modes. The module has also been specifically designed with a focus on reducing installation duration and complexity. Combined with only needing installation at one location, this reduces installation time and cost compared to conventional testing approaches. The equipment can be left installed for long‑term continuous monitoring, providing opportunities for enhanced online monitoring in special circumstances. Detection of non‑harmonic excitation from other grid sources is one example. Shaft crack detection and LP last‑stage blade cracking may be detectable through shaft torsional vibration monitoring also, although more research and development is needed to demonstrate these capabilities.

Benefits

Benefits Estimate

Level 1 – Savings are less than $1 million per year and consist of savings compared to alternative torsional vibration monitoring methods. Potential benefits (> Level 1) may be experienced if TDMS aids in successfully avoiding a turbine failure; however, additional research will need to verify TDMS’s early turbine‑failure detection ability related to blade vibration monitoring and shaft crack detection.

Benefits Description

• Reduced installation complexity and time leads to cost savings compared to conventional sensor installation.
• The instrumentation has an indefinite life, and therefore could be used to perform torsional testing over the period of several years with one installation. This could be beneficial in cases where sectionalized rotor replacements are being performed across multiple outages.
• Long‑term continuous monitoring capability provides the ability to identify non‑harmonic excitation from other grid sources that could be potentially damaging. Also, early fault detection (e.g., rotor or blade cracking) may be possible, allowing for avoidance of a catastrophic failure and associated recovery costs (although more research is needed to fully characterize TDMS’s ability in this area).
• TDMS has greater sensitivity and frequency resolution compared to alternative test methods. This enables TDMS to more clearly identify low‑amplitude or closely spaced torsional mode frequencies. This is especially useful near the frequency range of concern (2x grid frequency) to be able to differentiate a torsional mode frequency from the always‑present forced response at the 2x grid frequency.

Costs and Schedule

Cost

Level 3 – Implementation costs associated with sensors should be less than $1 million. Costs consist of the sensor module, installation and supporting equipment and are approximately $100,000 per implementation.

Schedule

Less than six months, which includes planning and implementation.

Scope Context

Per unit. The stationary portion of the TDMS equipment can be used between units in a multi‑unit plant.

Risks

The TDMS system is limited to operation below 250 °F. The technology is typically used with shaft components adjacent to the low‑pressure turbine or generator.