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In today’s world-class facilities, maintenance and reliability departments require data collection on a consistent and periodic basis to guarantee that assets in a plant operate efficiently and reliably.

Vibration monitoring actively monitors the health of critical assets for potential failure conditions. This yields great results in identifying potential failure conditions for repair before unwanted downtime or other costly consequences are experienced.

Typical walk-around vibration programs can take time to establish and get going, whereas online condition monitoring can be expensive due to the installation costs including labor, cables, sensors, etc. Moreover, a cabled installation might even be impossible in certain situations due to accessibility issues.

On the other hand, an IoT solution such as wireless technology can solve all of these problems and is an ideal solution for most facilities.  Having a wireless vibration program with smart sensing technology is cost-effective for all manufacturing applications.  A wireless vibration solution such as the Sensoteq Kappa X with prolonged battery life, a Fmax of 10kHz, and 6400 lines of resolution with signal analysis with enveloping can provide unparallel level of diagnostic capabilities and asset health monitoring of your plant machinery.

Wireless Vibration Monitoring

Data can be viewed from anywhere in the world and you can be notified of any issue arising in your assets via either a PC or mobile device, and the data can also be seamlessly entered into your facility’s PLC or DCS system.

by Ana Maria Delgado, CRL

Reliability groups are often expected to collect data on critical assets in a consistent manner to ensure the asset’s health is monitored efficiently, and to maximize the life of that equipment. Doing this task manually may pose a safety or health risk to the personnel responsible for collecting the data. One of the solutions is to install permanently mounted sensors and wire them to a termination/switch box in a safe location.

Vibration sensors mounted on machine

It is important to note that there are several ways to permanently mount sensors to an asset, but the most common are:

Adhesive Mount

As the name says, this process entails utilizing a strong epoxy-like adhesive that creates a sturdy bond between the sensor and the asset. It is imperative that the two surfaces be thoroughly stripped of any paint and/or corrosion using a steel wire brush. This should be done to remove any surface imperfections that can compromise the integrity of the bond between the sensor and the asset, as well as remove signal dampening layers between the sensor and the machine.

Drilling and Tapping Mount

This process entails physically drilling a small pilot hole into the casing of the asset and then tapping the hole to match the thread of the stud included with the chosen sensor. This method is one of the preferred methods in the industry as it ensures a perfectly solid mount between the sensor and the asset.

Switch Box Vibration Data Collection

For either of the above methods, cabling must be routed to provide communication. It is of the utmost importance to route the cable through suitable conduits so that it is protected from harsh temperatures or chemical exposure that can potentially cause damage.  Utilizing a label machine to identify each cable will ensure that the final wiring in the termination/switch box is accomplished properly and easily.  Once the physical installation of the permanently mounted sensors and wiring is completed, the reliability technician that oversees the Condition Monitoring program can safely and efficiently collect data with the help of a capable data collector such as the BETAVIB’s VibWorks system. This will greatly improve the uptime of a facility’s assets and help maintain world-class reliability while maximizing the safety of its employees.

by Ana Maria Delgado, CRL

Frequency is Everything!

In the world of vibration analysis frequency is everything.  Frequencies are generated by many sources within a machine. The running speed of the machine is one example frequency; this is the velocity of the rotating element which in many cases is a drive shaft connected to an application (like a fan or a pump). Each frequency will have a magnitude associated with it; this is the total amount of energy of that specific frequency.  The amount of energy of any given frequency can tell us a lot about what is going on within a machine.  When we use a vibration sensor to measure a machine, this is what we are detecting, frequencies, and magnitudes of those frequencies.

frequency

The maximum frequency that a sensor can measure is called the Fmax.  This value lets the user know what type of faults they can detect on a machine. It is typically listed in hertz (Hz).  The higher the Fmax value, the greater number of faults that a sensor will detect, but it will also allow for earlier indication of potential faults, like a bearing failure. Some ISO standards will reference a Fmax of 1kHz – whilst taking a reading up to 1kHz is suitable for most acceptance testing, it will not highlight even the most basic of bearing faults.  A minimum of 2.5kHz Fmax is recommended for good coverage.

Recently, a new sensor has entered the market that boasts a Fmax up to 10kHz. This Fmax gives great coverage for a wide variety of faults, and will accurately inform users of issues on complex equipment like gearboxes that have many higher fault frequencies. In addition, a higher frequency will give an earlier indication of bearing faults. Bearing failures will typically start within the subsurface of the metal with a very small amount of energy being emitted to the sensing element, thus having a sensitive measurement device with the right Fmax is critical to understanding the health of your machine early, prior to failure impacting any processes or causing downtime.

Thank you David Procter with Sensoteq for sharing this educational article with us! 

by Diana Pereda

We previously discussed in this series, Do we really need Oil Analysis if We’re Performing other CM Techniques? – Part 2. In this follow-up blog, we will discuss selecting the best CM technique for your equipment.

Part 3 – Selecting the best CM technique for your equipment

We’ve made it to the final installment of this trilogy! Let’s do a quick recap of what we’ve learned thus far. In Part 1, we spoke all about understanding the consistency of oil sampling and determining the criticality of your assets. Next, in Part 2, we really found out more about reading the actual oil analysis report and understanding what the numbers actually mean. We talk about the standard types of tests in addition to some of the specialty tests that can be done for turbines when determining if varnish is present. Let’s take a deeper dive into ways of selecting the best condition monitoring technique for your equipment.

The P-F curve

If you work within the reliability sector or even within maintenance, you will be familiar with the P-F curve. This curve is used to represent the way in which an asset can fail. It can be adapted to any asset but users must acknowledge that not every asset will follow this curve exactly. This curve can be used as a guide to charting the progression of asset failures. According to the ISA (International Society of Automation), the P-F curve demonstrates the technologies used to detect failure from the earliest to the latest as per below:
1. Oil Analysis
2. Ultrasound
3. Vibration
4. Thermography
5. Motor Testing
6. Physical Inspection

P-F Curve
Reference: International Society of Automation (“The P-F Curve: One of the first, yet hardest, things to learn” by Kevin Clark CMRP)

As seen in the figure above, Oil analysis is the first detection point once a failure has been initiated. However, this should not be the only CM technique used as there are quite a number of factors that contribute to the validity of the data from an oil sample.

Other CM techniques

Since we’ve discussed oil analysis at length (in Parts 1 & 2 of this trilogy), we now need to ask the underlying question, “Do we need other CM techniques if Oil Analysis is already being conducted?”. The simple answer is, yes. While oil analysis may be positioned as the first indicator of an abnormality within a system, there are times when oil analysis results can be misrepresented. If a representative sample is not taken, mislabeled, or not shipped off to the lab in time, then the results can be skewed. This can cause users to miss the window of maintenance or perform misguided maintenance leading to the occurring issue not being solved.

As per the P-F curve, there are a few types of technologies that can be employed to detect the onset of an asset failure before it affects its functionality. These are namely, Ultrasonic, Vibration, or Thermography, all of which LUDECA can provide. The key to any successful CM program is firstly establishing its requirements and then modeling the program based on these. If the main requirement is to detect impending failures on critical gearboxes then the CM program should be designed to capture the information, feed this back to the operators and maintenance department in a timely manner and have the issue resolved before its functional failure.

One way of determining complementary technologies is to evaluate the strengths and weaknesses of each type of CM technology. With Oil analysis, we can only detect the presence (or absence) of materials that come into contact with the oil. This will not include other parts of the machine which may not be lubricated. For these parts, perhaps another type of technology can be employed, so the entire asset is monitored, not just the lubricated parts. Additionally, what if there are no lubricated parts? Then, we can’t use oil analysis as a CM technique!

Selecting the best CM technique

When selecting the best CM techniques for your plant, you can look at:

1. Application of the technique across most of the assets – if a technique is being applied, we have to make sure it is scalable. It may not make much sense if we’re only applying the technique to one asset and have to either buy the equipment or get in-house personnel certified to use it. If technicians will be trained in using the technique, then it should be integrated across the assets to bring more value.
2. Integration of these CM techniques into the PM programs – most technicians are not very fond of having another task added to their routine. However, by showing technicians the value that these techniques bring and the possibility of reducing their future workload.
3. Frequency of application – depending on how often the technique will be used, then a decision can be made on whether the company should invest in the actual CM equipment and have in-house personnel trained or if it makes more sense to have a third party perform the inspections. The ROI on the investment into the CM technology should be weighed before making such a decision.

Essentially, while oil analysis is a great predictive method of detecting failures it should be complemented with other CM techniques. This allows us to get the full picture of what is occurring throughout the equipment. Users should select the CM techniques which are best suited for their plant or facility as per their requirements. Ideally, users should consider all of the options before selecting the best-suited CM technique.

Thank you Sanya Mathura with Strategic Reliability Solutions Ltd for sharing this informative and educational article with us!

Related Blog: One Condition Monitoring Technology is Not Enough!

by Diana Pereda

We are thrilled to announce LUDECA and Sensoteq join forces in the US and Caribbean! Sensoteq is a market leader in industrial wireless sensor technology for Condition Monitoring. Together, LUDECA and Sensoteq bring the new, industry-leading Kappa X wireless sensor to the condition monitoring market, together with its cloud-based Analytix software, giving you instant condition monitoring security, all supported by our network of Solutions Providers and technical staff.

Wireless Sensors mounted on machine

We are delighted to launch our latest product, Kappa X, together with LUDECA in the US and Caribbean. With over 40 years of expertise in the provision of reliability services, LUDECA boasts an invaluable customer service network which teams perfectly with our reliability technology.” —Idir Boudaoud, Sensoteq CEO

At LUDECA, we are always looking for ways to serve our customers better. With the addition of Sensoteq, we bring the world’s finest wireless sensor technology to our customers. Our sales partners and dedicated support team are ready to help you implement this innovative technology.” —Alex Nino, LUDECA Product Manager 

Kappa X features all the benefits reliability experts expect from a smart sensor, combining unrivalled wireless technology, a replaceable battery design, and a 10kHz FMax market-leading fault detection capability within a compact 1-inch footprint. It’s quick and easy to install, affordable, and user-configurable so you can mount it on virtually any piece of rotating equipment in any industry.

Analytix Condition Monitoring Software

About LUDECA 
LUDECA is a leading provider of Predictive and Proactive Maintenance Solutions including laser alignment, ultrasound testing, vibration analysis, and balancing equipment as well as related software, rentals, services, and training. For more information, visit www.ludeca.com

by Diana Pereda

We previously discussed in this series, Do we really need Oil Analysis if We’re Performing other CM Techniques? – Part 1. In this follow-up blog, we will discuss reading the oil analysis report.

 

Part 2 – Reading the oil analysis report

An oil analysis report can seem like a lot of numbers and colors all jumbled together for those who may not be familiar with it. The basic element of all reports is that they provide the values seen in your equipment and compare them to those given by the OEM or seen in the field. Some labs provide the reference values while others just stipulate whether they are either within the limits or outside of them. Labs may also provide some advice on courses of action to get help return the oil to normal values.

Oil analysis reports are similar to blood test reports, there are a lot of values and limits but only when we can interpret them properly do they actually make sense. For instance, if the blood report stated that the cholesterol levels were getting into the warning range, we can then adjust our diet and lifestyle to help reduce these. Similarly, with the oil analysis tests, based on the values in the report, we can inspect the machine for evidence of wear or schedule some preventive maintenance accordingly.

Standard tests within the industry are those which give an overview of the overall health of the oil. Typically, this measure the oil’s viscosity, TBN/TAN, presence of wear metals, contaminants, and additive packages. These properties can guide the user to understand what is happening in their equipment and possibly perform corrective actions before the asset reaches the failure point (on the P-F curve).

properties of the overall health of the oil
Figure 1: Standard oil analysis tests

The oil’s viscosity is usually measured using the ISO grading system. In this system, the actual viscosity of the oil is placed within a grade. For instance, an oil with a viscosity of 63cSt or 73cSt will be classed as an ISO 68 oil. Thus an ISO 68 grade doesn’t necessarily translate to an oil with a viscosity of 68cSt. With the ISO grades, they have a range of +/-10%. The range for an ISO 68 oil lies between 61.2 CST and 74.8cSt, if it falls out of this range it is no longer classified as an ISO 68 oil. A good reference value for used oil is a change of +/-5% which can determine whether degradation has occurred or not.

The TAN (Total Acid Number) or TBN (Total Base Number) values depict the amount of acid which is being built up in the oil. Engine oils have TBN values while other industrial oils have TAN values. In engine oils, a decrease of approximately 50% of the TBN value is a cause for concern. Any type of acid within your system is not good and a decrease of the TBN by 50% means that the acid level has increased by the same amount. On the other hand, an increase of 0.2 mgKOH/g is a cause for concern in other oils.

The presence of wear metals indicates that there is some form of wear occurring within the equipment. Depending on the type of wear metal which has been detected, one can pinpoint the source of wear. For instance, if the levels of chromium keep increasing in the oil analysis reports and the asset has chrome rings then the source of wear could be isolated to these rings. Thus during maintenance, they can be inspected for wear. Different OEMs have varying values for their equipment especially based on the environment in which they operate, so the best advice is to follow their guidelines or those of the lab for this equipment.

Contaminants are the bad actors which can cause major problems. Just like a pebble in your shoe, contaminants can cause a lot of misery to the equipment it affects. This is particularly important for hydraulic oils where contamination is a huge challenge especially due to the small clearances in this type of equipment. Most OEMs have guidelines on the amount of tolerable contamination for their equipment.

Additives are sacrificial in that their main purpose is to be depleted. However, when this depletion begins at an accelerated rate, that’s when they may no longer be protecting the oil. This is where most of the issues begin. While Oil manufacturers don’t give out the ratio of the additives in their blends, it is always a wise idea to perform oil analysis on a new oil sample and use this as your reference for all the other samples.

These properties help to determine the health of the oil. Thus, by monitoring them, we can get a better picture of what is happening inside the equipment. Remember, changes in the oil are a reflection of what is occurring within the equipment. For instance, if the TBN value drops drastically by 60% or more within one week of the oil being in the equipment, this can indicate the presence of fuel dilution. If the viscosity has also decreased significantly with the 60% decrease in TBN then a possible cause can be fuel dilution. This is the importance of trending the data along with the various properties so hypotheses can be made and then verified through checks.

While these are just some of the standard tests, specialty tests also exist when we’re trying to determine other factors. For instance, in turbine oils, if the viscosity levels are a bit higher than expected or the additive values have dropped to a concerning level, operators may want to investigate the presence of varnish. Varnish can be detrimental to the equipment as it causes a lot of unplanned downtime. Deposits can stick to the insides of the equipment and insulate heat causing equipment temperatures to rise outside of the operating ranges.

The two main types of test to be done for varnish would include; MPC (Membrane Patch Calorimetry) where the oil is passed through a patch and a value is given based on the patch intensity. This can tell us if there are deposits in the oil or varnish pre-cursors. The next test would be the RULER (Remaining Useful Life Evaluation Routine) test which gives a quantitative value of the remaining antioxidants (both primary and secondary) for the oil. This can tell us if oxidation is present and whether the antioxidants have significantly depleted or not. In part 3 of this series, we will talk a bit more about the other types of condition monitoring techniques as well as the method for selecting the best one for your equipment. Stay tuned!

Thank you Sanya Mathura with Strategic Reliability Solutions Ltd for sharing this informative and educational article with us!

by Diana Pereda

Part 1 – Understanding the consistency of oil Sampling

Oil analysis has been one of the most widely used Condition Monitoring (CM) techniques to observe any changes occurring internally in the equipment. Typically, it is one of the most basic techniques utilized within the industry and is viewed as the first line of defense to detect any abnormalities. However, is there a need for oil analysis if the team employs other CM techniques which can also detect changes within the equipment?

In this trilogy, we will explore these main concepts:

  • Understanding the consistency of oil sampling (Part 1)
  • Reading the oil analysis report (Part 2)
  • Selecting the best CM technique for your equipment (Part 3)

Oil Sampling – Consistency is key!

Let’s think about a turbine system and taking a sample from one of these systems. A gas turbine may be connected to compressors, gearboxes, and other small assets. Thus, if we’re trying to monitor the internal condition of the turbine, we need to ensure that the sample we obtain is representative of the system. As such, it is critical that a sample is taken from a turbulent area (or an area that is not a dead zone). Samples should also be taken upstream of the filters (this ensures that any debris or contaminants are not filtered out and can be examined) and downstream of components.

If we are sampling from a closed-loop system, we need to remember to label the sampling points and ensure that the samples are taken with consistency. Data trending is one of the main aspects of oil analysis. When reading oil analysis reports, it is usually compared to the last report/s to determine if there was any progression of contaminants, wear metals, or even additive packages. Thus, if someone samples upstream of the filter and component for one sample but then samples downstream of the filter and component for the follow-up sample, there can be a big difference in the results leading to misconceptions about the condition of the equipment.

How often do you sample?

While consistent sampling is important, determining the frequency of sampling is also critical. There are a couple of factors to consider when calculating this frequency of sampling, namely;

  1. Aim of the program
  2. Criticality of the asset
  3. Type of test/oil
Factors to consider when determining sampling frequency
Figure 1: Factors to consider when determining sampling frequency

 

The most important factor to consider is the aim of the test. What are we trying to establish, trend, or prevent? When we fully understand this, then this provides us with the purpose of the oil analysis program. This allows us to then tailor a program suited for the assets within our plant or facility and to determine whether continuous monitoring is needed or if sampling should be done at a specified frequency.

Criticality of your assets

The criticality of the asset helps us to determine the frequency of sampling and the types of tests that need to be carried out. Assets can be classified into critical, semi-critical, and non-critical. Critical assets are those which can cause a significant impact on the plant or facility. The type of impact can vary depending on the factors which are important to the plant. Some plants may hold production as an important factor while others may hold the availability of their equipment for service as their important factor, others can hold both or many others. Sometimes, these can also be tied to the KPIs (Key Performance Indicators) of the plant.

For critical assets, samples should be taken monthly or even bi-weekly depending on what the user is trying to find out. Let’s take a gas turbine as an example. At start-up, if we wanted to monitor the rate of antioxidant depletion or the rate of degradation of the oil, we could test the sample on a bi-weekly schedule for the first two months and then move the sampling to a monthly, quarterly, or even semi-annual schedule once it goes into operation. This is also dependent on the results we get from the sample.

Semi-critical assets are those which do not significantly impact the plant. For instance, if these go down, the plant can still function but at a lower capacity. This does not mean that they are of lesser importance. It simply suggests that the frequency of sampling for these semi-critical assets would not be the same as for critical assets. On the other hand, the non-critical assets are those which do not impact the plant if they shut down. Typically, these are the secondary pumps or equipment. These assets will have a lower sampling frequency than the semi-critical assets. The criticality of the asset should be assessed before determining the frequency of testing.

The types of tests also have a role in determining the sampling frequency as there are some tests that require 24-48 hours to be processed before a result is given. Typically, these tests are slightly more expensive and designed to measure specific properties which may not degrade at a very rapid rate. These specialty tests are usually done quarterly, semi-annually, or even annually such as RPVOT, RULER, and MPC. They also require a larger volume of oil samples which makes it difficult to obtain from those smaller equipment sumps.

When determining the oil sampling frequency, a matrix can be used to help rank assets as per criticality. These assets can also be classified according to the type of oil test they require and if any specialty tests may be needed. Determining the frequency of sampling is just one aspect of having a successful oil analysis program. The next factor is actually reading the results and making maintenance recommendations for the assets. Stay tuned for part 2 when we take a deeper dive into reading the oil analysis report.

Thank you Sanya Mathura with Strategic Reliability Solutions Ltd for sharing this informative and educational article with us!

Related Blog: Equipment Criticality Ranking Tip

by Diana Pereda

ISOStandardsBlogPart 9

Disclaimer: The author is not trying to present himself as an authority on all available CM standards. This blog post is simply an attempt to help those who may be unaware that such guidance exists or of the extent of such standards.

 

We previously discussed a series of international standards pertaining to condition monitoring of industrial equipment with vibration analysis in, Condition Monitoring & Vibration Classification Standards Awareness: Part 8 20816-9:2020This blog is number 9 in a series of blogs describing some international standards as a help to our Ludeca partners. This blog is about the xx816 standard that concerns itself with industrial wind turbines. The standard described in this blog regards collecting and classifying the vibration of horizontal axis wind turbines with a mechanical gearbox and a rated output exceeding 200kw. See the scope quoted below for the complete description of covered machines. The ISO 10816-21 standard is formatted with the evaluation zones of A to D, just like the other 10816 & 20816 standards, but only offers guidance for the zone boundaries for onshore machines (found in Annex A).

Both acceleration and velocity band quantities are assessed by this standard with many more averages than most of the greater population of industrial equipment; averages overtime of 10 minutes being typical to classify the vibration of the nacelle and tower. Less is needed for the gearbox and generator. The lowest band required by this standard begins at 6cpm (0.1hZ) for the tower, nacelle, and gearbox, while the band with the highest cutoff (5kHz or 300kcpm) is required on the generator.

This standard does provide some acceptance testing guidance. As with most of the other standards in the general xx816 family, “-21” gives guidance for some general condition assessment, but does not attempt to provide diagnostic guidance.

This standard is titled:

ISO 10816-21:2015

Mechanical vibration — Evaluation of machine vibration by measurements on non-rotating parts

 

Part 21: Horizontal axis wind turbines with gearbox

The scope of this standard is quoted below from the ISO.org preview page (quotation in bold):

Scope:

This part of ISO 10816 specifies the measurement and evaluation of mechanical vibration of wind turbines and their components by taking measurements on non-rotating parts. It applies to horizontal axis wind turbines with mechanical gearbox and rated generator output exceeding 200 kW and the following design and operational characteristics:

  1. installation on supporting systems (tower and foundation) made of steel and/or concrete;
  2. horizontal axis rotor with several rotor blades;
  3. rotor bearing separate from or integrated into the gearbox;
  4. generators are driven via gearbox;
  5. generators of the synchronous or asynchronous type (mostly equipped with 4-pole generator);
  6. generators with only a fixed pole number or which are pole-changeable for speed adjustment;
  7. output control by rotor blades (pitch or stall wind turbines);
  8. generator coupled to the power grid via converter or directly.

This part of ISO 10816 recommends zones for evaluating the vibration at continuous load operation. However, in most cases, these evaluation zone boundaries might not be suitable for the early detection of faults. This part of ISO 10816 does not specify vibration values for the zone boundaries because there are insufficient data available for the complete range of wind turbines in the worldwide fleet covered by this part of ISO 10816. However, for information only, Annex A presents evaluation zone boundaries for onshore wind turbines. These zone boundaries are based on vibration data from about 1 000 wind turbines with rated generator output up to 3 MW. They can be helpful in facilitating discussion between users and manufacturers. Evaluation zone boundaries for offshore wind turbines are not yet available.

Although the type and implementation of broad-band vibration monitoring for wind turbines is addressed, this part of ISO 10816 does not apply to diagnostics or fault detection by condition monitoring of wind turbines.

NOTE 1 Information on condition monitoring and diagnostics of wind turbines will be given in ISO 16079 (all parts)1.

The evaluation of the balance quality of the slowly turning wind turbine rotor, which requires special measurements and analysis, is not covered by this part of ISO 10816.

This part of ISO 10816 does not apply to the evaluation of torsional vibration in the drive train. Although coupled lateral and torsional vibration of the tower and drive train can affect the amplitudes of the defined vibration characteristics, diagnosis of this kind of vibration source is not feasible by the described measurement methods described in this part of ISO 10816. For general design verification purposes and for specific fault diagnosis, special measurements are required which are beyond the scope of this part of ISO 10816.

NOTE 2 IEC/TS 61400–13 describes load measurement by use of strain gauges on the supporting structure and blades. Techniques to assist the detection of rolling element bearing and gearbox defects can be found in ISO 13373-2. Measurement and evaluation of structure-borne noise with rolling element bearings are given in VDI 3832.

This part of ISO 10816 does not also apply to acceptance measurements on gearboxes and generators in the manufacturer’s test facility.

NOTE 3 These are assessed on the basis of appropriate standards namely ISO 8579-2 and IEC 60034–14.

To read the ISO’s preview of this standard, click here.

This concludes our series of planned standards blog posts. Requests for further informational blogs on standards will be considered. Thank you for your attention.

 

by Diana Pereda

ISOStandardsBlogPart 8

Disclaimer: The author is not trying to present himself as an authority on all available CM standards. This blog post is simply an attempt to help those who may be unaware that such guidance exists or of the extent of such standards.

 

We previously discussed a series of international standards pertaining to condition monitoring of industrial equipment with vibration analysis in, Condition Monitoring & Vibration Classification Standards Awareness: Part 7 ISO 20816-8:2018. This is number 8 in a series of blogs describing some international standards as a help to our Ludeca partners. This blog is about what we believe to be the newest addition to the xx816 standard family.

The standard described in this blog concerns itself with collecting and classifying the vibration of gear units sized from about 13HP to 134,000HP. The ISO 20816-9 standard is formatted with the evaluation zones of A to D, just as the other 10816 & 20816 standards. It also provides acceptance testing guidance. Like most of the other standards in the general xx816 family, “-9” provides guidance for general condition assessment, but does not attempt to guide the user through mode determination or supplant narrow band analysis.

‍‍This is the first edition of a “-9” or gearset-focused standard in the xx816 family, but it is a technical revision of the ISO 8579-2:1993 standard. ISO 8579-2:1993 was withdrawn in 2016.

This standard is titled:

ISO 20816-9:2020

Mechanical vibration — Measurement and evaluation of machine vibration

 

Part 9: Gear units

The scope of this standard is quoted below from the ISO.org preview page (quotation in bold):

Scope:

This document specifies requirements for determining and classifying mechanical vibration of individually housed, enclosed, speed increasing or speed reducing gear units. It specifies methods for measuring housing and shaft vibrations, and the types of instrumentation, measurement methods, and testing procedures for determining vibration magnitudes. Vibration grades for acceptance are included.

Torsional vibration measurements are outside the scope of this document.

It applies to a gear unit operating within its design speed, load, temperature range and lubrication for acceptance testing at the manufacturer’s facility. By agreement between manufacturer and customer and/or operator, it can be used for guidelines for on-site acceptance testing and for routine operational measurements.

This document applies to gear units of nominal power rating from 10 kW to 100 MW and nominal rotational speeds between 30 r/min and 12 000 r/min (0,5 Hz to 200 Hz).

This document does not apply to special or auxiliary drive trains, such as integrated gear-driven compressors, pumps, turbines, etc., or gear type clutches used on combined-cycle turbo generators and power take-off gears.

The evaluation criteria provided in this document can be applied to the vibration of the main input and output bearings of the gearbox and to the vibration of internal shaft bearings. They can have limited application to the evaluation of the condition of those gears. Specialist techniques for evaluating the condition of gears are outside the scope of this document.

This document establishes provisions under normal steady-state operating conditions for evaluating the severity of the following in-situ broad-band vibration:

  • structural vibration at all main bearing housings or pedestals measured radially (i.e. transverse) to the shaft axis;
  • structural vibration at the thrust bearing housings measured in the axial direction;
  • vibration of rotating shafts radially (i.e. transverse) to the shaft axis at, or close to, the main bearings;
  • structural vibration on the gear casing.

NOTE Vibration occurring during non-steady-state conditions (when transient changes are taking place), including run up or run down, initial loading, and load changes are outside the scope of this document.

To read the ISO’s preview of this standard, click here.

by Diana Pereda

ISOStandardsBlogPart 7

Disclaimer: The author is not trying to present himself as an authority on all available CM standards. This blog post is simply an attempt to help those who may be unaware that such guidance exists or of the extent of such standards.

 

We previously discussed a series of international standards pertaining to condition monitoring of industrial equipment with vibration analysis in, Condition Monitoring & Vibration Classification Standards Awareness: Part 6 ISO 10816-7:2009. This is number 7 in a series of blogs describing a certain family of international standards. The current standard described in this blog is concerned with classifying the vibration of compressors mounted on rigid foundations. The scope (quoted below) is perhaps even more narrow than that of most of the others, and does not offer itself as a condition monitoring tool, but appears to be aimed at helping to identify and avoid fatigue risk for the machine and its related environment.

This standard is titled:

ISO 20816-8:2018

Mechanical vibration — Measurement and evaluation of machine vibration

 

Part 8: Reciprocating Compressor Systems

The scope of this standard is quoted below from the ISO.org preview page (quotation in bold):

Scope:

This document establishes procedures and guidelines for the measurement and classification of mechanical vibration of reciprocating compressor systems. The vibration values are defined primarily to classify the vibration of the compressor system and to avoid fatigue problems with parts in the reciprocating compressor system, i.e. foundation, compressor, dampers, piping and auxiliary equipment mounted on the compressor system. Shaft vibration is not considered.

This document applies to reciprocating compressors mounted on rigid foundations with typical rotational speed ratings in the range 120 r/min up to and including 1 800 r/min. The general evaluation criteria which are presented relate to operational measurements. The criteria are also used to ensure that machine vibration does not adversely affect the equipment directly mounted on the machine, e.g. pulsation dampers and the pipe system.

NOTE The general guidelines presented in this document can also be applied to reciprocating compressors outside the specified speed range but different evaluation criteria might be appropriate in this case.

The machinery driving the reciprocating compressor, however, is evaluated in accordance with the appropriate part of ISO 10816ISO 20816 or other relevant standards and classification for the intended duty. Drivers are not included in this document.

It is recognized that the evaluation criteria might only have limited application when considering the effects of internal machine components, e.g. problems associated with valves, pistons and piston rings might be unlikely to be detected in the measurements. Identification of such problems can require investigative diagnostic techniques which are outside the scope of this document.

Examples of reciprocating compressor systems covered by this document are

  • horizontal, vertical, V-, W- and L-type compressor systems,
  • constant and variable speed compressors,
  • compressors driven by electric motors, gas and diesel engines, steam turbines, with or without a gearbox, flexible or rigid coupling, and
  • dry running and lubricated reciprocating compressors.

This document does not apply to hyper compressors. The guidelines are not intended for condition monitoring purposes. Noise is also outside the scope of this document

To read the ISO’s preview of this standard, click here.

by Diana Pereda

ISOStandardsBlogPart 6

Disclaimer: The author is not trying to present himself as an authority on all available CM standards. This blog post is simply an attempt to help those who may be unaware that such guidance exists or of the extent of such standards.

 

We previously discussed a series of international standards pertaining to condition monitoring of industrial equipment with vibration analysis in, Condition Monitoring & Vibration Classification Standards Awareness: Part 5 ISO 20816-5:2018. This is number 6 in a series of blogs describing a certain family of international standards mainly intended to help determine general machine condition, primarily from machine casing vibration levels (with a few exceptions where shaft vibration is also considered).

The standard focused on in this blog concerns itself with characterizing the condition of rotodynamic pumps starting at just above 1 horsepower. Read the scope (quoted below) carefully, as with all the standards. This standard has application to both acceptance testing and in-service condition monitoring.

This standard, unlike the dash 3 (-3) standard, suggests alarm limits without regard to where the machine is operating in relation to a critical speed. It does, however, class pumps into criticality groups, in order to give users flexibility with their alarm sets.

This standard is titled:

ISO 10816-7:2009

Mechanical vibration — Evaluation of machine vibration by measurements on non-rotating parts

 

Part 7: Rotodynamic pumps for industrial applications, including measurements on rotating shafts

The scope of this standard is quoted below from the ISO.org preview page (quotation in bold):

Scope:

This part of ISO 10816 gives instructions for the evaluation of vibration on rotodynamic pumps for industrial applications with nominal power above 1 kW. It defines the special requirements for the evaluation of vibration when the vibration measurements are made on non-rotating parts (bearing housing vibration). It provides specific guidance for assessing the severity of vibration measured on bearing housings of rotodynamic pumps in situ and for the acceptance test at the manufacturer’s test facility or in the plant. This part of ISO 10816 also gives general information and guidelines for assessing the relative shaft vibration of the rotating shaft.

This part of ISO 10816 specifies zones and limits for the vibration of horizontal and vertical pumps irrespective of their support flexibility. The general evaluation criteria are valid for operational monitoring of rotodynamic pumps and for acceptance tests1) in situ or at the manufacturer’s test facility if specified. For the acceptance test at the manufacturer’s test facility, special conditions are given.

For monitoring the vibration values during long-term operation, two criteria are provided for assessing the machine vibration. One criterion considers the magnitude of the observed vibration and the second considers changes in magnitude. The evaluation criteria are applicable for the vibration produced by the pump itself and not for vibration which is transmitted to the pump from external sources. The criteria mainly serve to ensure a reliable, safe long-term operation of the pump, simultaneously minimizing harmful effects on connected devices. Additionally, recommendations are given for defining operational limits and setting alarm and trip values.

For pump units with integrated electrical motors (impeller directly on the motor shaft or impeller shaft rigidly connected to the motor shaft), this part of ISO 10816 applies to the whole coupled unit.

For flexibly coupled motors, this part of ISO 10816 is applicable for the pump only. Also, separately mounted drivers are not within the scope of this part of ISO 10816. Those drivers are dealt with in ISO 10816-3.

The following types of pumps are excluded from this part of ISO 10816:

  • reciprocating and rotating positive displacement pumps;
  • reciprocating engine driven pumps;
  • pumps in hydraulic power generating and pumping plants with power above 1 MW (see ISO 7919-5[4] and ISO 10816-5);
  • solids handling, slurry, and submersible pumps.

Torsional vibration is not dealt with in this part of ISO 10816.

To read the ISO’s preview of this standard, click here.

by Diana Pereda

ISOStandardsBlogPart 5

Disclaimer: The author is not trying to present himself as an authority on all available CM standards. This blog post is simply an attempt to help those who may be unaware that such guidance exists or of the extent of such standards.

 

We previously discussed a series of international standards pertaining to condition monitoring of industrial equipment with vibration analysis in, Condition Monitoring & Vibration Classification Standards Awareness: Part 4 ISO 10816-4:2018. Next in the series of international standards, developed for the purpose of having a sound foundation to establish the general condition of industrial equipment via the overall vibration and in some instances including a measure of rotational frequency vibration or frequencies specific to the equipment type (i.e. vane passing frequency vibration), is ISO 20816-5.

This standard is titled:

ISO 20816-5:2018

Mechanical vibration — Measurement and evaluation of machine vibration

 

Part 5: Machine sets in hydraulic power generating and pump-storage plants

The scope of this standard is quoted below from the ISO.org preview page (quotation in bold):

Scope:

This document provides guidelines for evaluating the vibration measurements made at the bearings, bearing pedestals, or bearing housings and also for evaluating relative shaft vibration measurements made on machine sets in hydraulic power generating and pump-storage plants when the machine is operating within its normal operating range. The normal operating ranges for each type of turbine covered by this document are defined in Annex A.

This document is applicable to machine sets in hydraulic power generating plants and in pump-storage plants with typical rotational speeds of 60 r/min to 1 000 r/min fitted with shell or pad (shoe) type oil-lubricated bearings.

NOTE The current database includes machine speeds ranging from 60 r/min to 750 r/min (with a very small sample of 1 000 r/min machines).

This document defines different limit values of bearing housing and shaft vibration depending on the type of turbine, the orientation of the shaft (i.e. horizontal or vertical), and for each of the bearing locations.

This document is based on statistical analysis and provides criteria for the most common types of turbines, pump-turbines, and pumps. For specific information on which types of units are covered in this document, see Annex A.

Machine sets covered by this document can have the following configurations:

  1. generators driven by hydraulic turbines;
  2. motor-generators driven by pump-turbines;
  3. motor-generators driven by hydraulic turbines and separate pumps;
  4. pumps driven by electric motors.

This document is not applicable to the following unit configurations, parameters, and operating conditions:

  • hydraulic machines with water-lubricated bearings;
  • hydraulic machines or machine sets having rolling element bearings (for these machines, see IEC 62006 and/or ISO 10816-3);
  • pumps in thermal power plants or industrial installations (for these machines, see ISO 10816-7);
  • electrical machines operating as motors except for the use of these machines in pump-storage applications;
  • hydro generators operating as synchronous condensers (with the water in the turbine depressed by compressed air);
  • assessment of absolute bearing housing vibration displacement;
  • assessment of axial vibration;
  • assessment of transient conditions;
  • non-synchronous operation;
  • assessment of vibration of the generator stator core or the stator frame level.

Measurements made of the bearing housing vibration and shaft vibration occurring in machine sets in hydraulic power generating and pump-storage plants can be used for the following purposes:

  • Purpose A: to prevent damage arising from excessive vibration magnitudes;
  • Purpose B: to monitor changes in vibrational behavior in order to allow diagnosis and/or prognosis.

The criteria are applicable for the vibration produced by the machine set itself. A special investigation is needed for vibration transmitted to the machine set from external sources, e.g. transmitted to the machine via the station foundations.

Once again, as in the previous standard, this standard is quite specific.

To read the ISO’s preview of this standard, click here.

by Diana Pereda

ISOStandardsBlogPart 4

Disclaimer: The author is not trying to present himself as an authority on all available CM standards. This blog post is simply an attempt to help those who may be unaware that such guidance exists or of the extent of such standards.

 

We previously discussed a series of international standards pertaining to condition monitoring of industrial equipment with vibration analysis in, Condition Monitoring & Vibration Classification Standards Awareness: Part 3 ISO 10816-3. Next in the series of international standards developed for the purpose of having a groundwork to establish the general condition of industrial equipment via the overall vibration and in some instances including a measure of rotational frequency vibration or frequencies specific to the equipment type (i.e., vane passing frequency vibration) which is ISO 20816-4.

This standard is titled:

ISO 20816-4:2018

Mechanical vibration — Measurement and evaluation of machine vibration

 

Part 4: Gas turbines in excess of 3 MW, with fluid-film bearings

The scope of this standard is quoted below from the ISO.org preview page (quotation in bold):

This document is applicable to land-based gas turbines with fluid-film bearings and power outputs greater than 3 MW and an operating speed under load between 3 000 r/min and 30 000 r/min. In some cases (see the list of exclusions below), this includes other rotating machinery coupled either directly or through a gearbox. The evaluation criteria provided in this document are applicable to the vibration of the main input and output bearings of the gearbox but are not applicable to the vibration of the internal gearbox bearings nor to the assessment of the condition of those gears. Specialist techniques required for evaluating the condition of gears are outside the scope of this document.

This document is not applicable to the following:

  1. gas turbines with power outputs greater than 40 MW at rated speeds of 1 500 r/min, 1 800 r/min, 3 000 r/min or 3 600 r/min (see ISO 20816-2);
  2. aero-derivative gas turbines (including gas turbines with dynamic properties similar to those of aero-derivatives);

NOTE ISO 3977-3 defines aero-derivatives as aircraft propulsion gas generators adapted to drive mechanical, electrical or marine propulsion equipment. Large differences exist between heavy-duty and aero-derivative gas turbines, for example, in casing flexibility, bearing design, rotor-to-stator mass ratio and mounting structure. Different criteria, therefore, apply for these two turbine types.

  • gas turbines with outputs less than or equal to 3 MW (see ISO 7919-3 and ISO 10816-3);
  • turbine driven generators (see ISO 20816-2ISO 7919-3and ISO 10816-3);
  • turbine driven pumps (see ISO 10816-7);
  • turbine driven rotary compressors (see ISO 7919-3and ISO 10816-3);
  • the evaluation of gearbox vibration (see this clause) but does not preclude monitoring of gearbox vibration;
  • the evaluation of combustion vibration but does not preclude monitoring of combustion vibration;
  • rolling element bearing vibration.

This document establishes provisions for evaluating the severity of the following in-situ broad-band vibrations:

  • structural vibration at all main bearing housings or pedestals measured radial (i.e. transverse) to the shaft axis;
  • structural vibration at thrust bearing housings measured in the axial direction;
  • vibration of rotating shafts radial (i.e. transverse) to the shaft axis at, or close to, the main bearings.

These are in terms of the following:

  • vibration under normal steady-state operating conditions;
  • vibration during other (non-steady-state) conditions when transient changes are taking place, including run up or run down, initial loading and load changes;
  • changes in vibration which can occur during normal steady-state operation.

As you can see from the “Scope” declaration, this standard is quite specific and likely is a “must have” for those who are monitoring gas turbines within the scope of the standard.

To read the ISO’s preview of this standard, click here.

by Diana Pereda

ISOStandardsBlogPart3

Disclaimer: The author is not trying to present himself as an authority on all available CM standards. This blog post is simply an attempt to help those who may be unaware that such guidance exists or of the extent of such standards.

 

We previously introduced a series of international standards pertaining to condition monitoring of industrial equipment with vibration analysis in, Condition Monitoring & Vibration Classification Standards Awareness: Part 1 & 2. This series ends with the numeric sequence of xx816-x. The original standards from 1974 (ISO 2372) and 1985 (ISO 3945) were replaced or superseded by ISO 10816-1 in 1995. 10816-1 was amended in 2009 and then replaced by ISO 20816-1 in 2016. Next (numerically) is the standard we also mentioned in our previous blog, 20816-2. The dash 2 standard covers the measurement and evaluation of vibration on large land-based gas or steam turbines and generators.

The subsequent standard in the series, the “dash 3” standard is the focus of this blog. This standard is titled:

INTERNATIONAL STANDARD ISO 10816-3

Mechanical vibration — Evaluation of machine vibration by measurements on non-rotating parts

 

Part 3: Industrial machines with nominal power above 15 kW and nominal speeds between 120 r/min and 15 000 r/min when measured in situ

ISO 10816-3 is the current standard in the series that covers a general range of equipment types and sizes. When first created it was the “catch-all” standard used for many types of machines (such as centrifugal pumps which are now covered by the dash 7 standard) that have since come to be covered by their own specific part of the series. The “10816” issuance of the dash 3 standard is still in force, but to be current it must be joined by a 2017 amendment, “Amendment 1”. This amendment actually modifies the scope of the standard, so it is critical to its being considered current.

The scope of this standard is quoted below from the ISO.org preview page (quotation in bold).

Important Note: The scope shown in the preview cannot be considered current because it is modified by Amendment 1.

Scope:

This part of ISO 10816 gives criteria for assessing vibration levels when measurements are made in situ. The criteria specified apply to machine sets having power above 15 kW and operating speeds between 120 r/min and 15 000 r/min.

The machine sets covered by this part of ISO 10816 include:

  • steam turbines with power up to 50 MW
  • steam turbine sets with power greater than 50 MW and speeds below 1 500 r/min or above 3 600 r/min (not included in ISO 10816-2)
  • rotary compressors
  • industrial gas turbines with power up to 3 MW
  • generators
  • electrical motors of any type
  • blowers or fans

NOTE: However, the vibration criteria presented in this part of ISO 10816 are generally only applicable to fans with power ratings greater than 300 kW or fans that are not flexibly supported. As and when circumstances permit, recommendations for other types of fans, including those with lightweight sheet metal construction, will be prepared. Until such time, classifications can be agreed upon between the manufacturer and the customer, using results of previous operational experience, see also ISO 14694[4].

The following are excluded from this part of ISO 10816:

  • land-based steam turbine generator sets with power greater than 50 MW and speeds of 1 500 r/min, 1 800 r/min, 3 000 r/min, or 3 600 r/min (see ISO 10816-2)
  • gas turbine sets with power greater than 3 MW (see ISO 10816-4)
  • machine sets in hydraulic power generating and pumping plants (see ISO 10816-5)
  • machines coupled to reciprocating machines (see ISO 10816-6)
  • rotodynamic pumps including integrated electric motors, i.e. where the impeller is mounted directly on the motor shaft or is rigidly attached to it (see ISO 10816-7)
  • rotary positive displacement compressors (e. g. screw compressors)
  • reciprocating compressors
  • reciprocating pumps
  • submerged motor-pumps
  • wind turbines

The criteria of this part of ISO 10816 apply to in situ broad-band vibration measurements taken on the bearings, bearing pedestals, or housing of machines under steady-state operating conditions within the nominal operating speed range. They relate to both acceptance testing and operational monitoring. The evaluation criteria of this part of ISO 10816 are designed to apply to both continuous and non-continuous monitoring situations.

This part of ISO 10816 encompasses machines that may have gears or rolling element bearings but does not address the diagnostic evaluation of the condition of those gears or bearings.

The criteria are applicable only for the vibration produced by the machine set itself and not for vibration which is transmitted to the machine set from external sources.

To read the ISO’s preview of this standard, click here.

by Diana Pereda

ISOStandardsBlogParts 1&2

Disclaimer: The author is not trying to present himself as an authority on all available CM standards. This blog post is simply an attempt to help those who may be unaware that such guidance exists or of the extent of such standards.

 

Are you looking for some guidance on a well-designed approach to condition monitoring and/or acceptance criteria for some types or categories of equipment? The International Standards Organization (ISO) has brought together standards groups from around the world and compiled excellent general guidelines for the condition monitoring (and in some cases acceptance testing) of many major groups of machine types.

The U.S. participant in the development of the standards is the American National Standards Institute (ANSI). ANSI itself has hundreds if not thousands of member societies that are well represented on the sub-committees such as the sub-committee “ISO/TC 108/SC 2” which is responsible for the development of the ISO 20816-1 standard. Many of the members of ANSI are quite recognizable to those of us who have been around the industry for some time including ASHRAE, ASME, SAE, ABMA, AGMA, ASNT, AWEA, HI, and API.

If you are interested in standardized guidance to condition monitoring on your equipment, then consider beginning with the standard “ISO 20816-1” which is the compilation of the general vibration monitoring guidelines for numerous other standards, each of which applies to a specific group of equipment types. The current standard was completed in 2016 and is titled:

ISO 20816-1: 2016

Mechanical vibration – Measurement and evaluation of machine vibration

 

Part 1: General guidelines

The scope of this standard is quoted below from the ISO.org preview page (quotation in bold listed below):

Scope:

This document establishes general conditions and procedures for the measurement and evaluation of vibration using measurements made on rotating, non-rotating and non-reciprocating parts of complete machines. It applies to both absolute and relative radial shaft vibration measurements concerning the monitoring of radial clearances but excludes axial shaft vibration. The general evaluation criteria, presented in terms of both vibration magnitude and change of vibration, relate to both operational monitoring and acceptance testing. They have been provided primarily concerning securing the reliable, safe, long-term operation of the machine while minimizing adverse effects on associated equipment. Guidelines are also presented for setting operational limits.

NOTE 1 The evaluation criteria for different classes of machinery will be included in other parts of ISO 20816 when they become available. In the meantime, guidelines are given in Clause 6.

NOTE 2 The term “shaft vibration” is used throughout ISO 20816 because, in most cases, measurements are made on machine shafts. However, the ISO 20816 series is also applicable to measurements made on other rotating elements if such elements are found to be more suitable, provided that the guidelines are respected.

For the purposes of ISO 20816, operational monitoring is considered to be those vibration measurements made during the normal operation of a machine. The ISO 20816 series permits the use of different measurement quantities and methods, provided that they are well-defined and their limitations are set out so that the interpretation of the measurements is well-understood.

The evaluation criteria relate only to the vibration produced by the machine itself and not the vibration transmitted to it from the outside.

This document does not include consideration of torsional vibration.

To read the ISO’s preview of this standard, click here.

Stay tuned as we will be introducing other standards in this xx816 track in the coming weeks, beginning today with the current part 2, which was completed in 2017:

ISO 20816-2: 2017

Mechanical vibration – Measurement and evaluation of machine vibration

 

Part 2: Land-based gas turbines, steam turbines, and generators over 40 MW, with fluid-film bearings and rated speeds of 1 500 r/min, 1 800 r/min, 3 000 r/min, and 3 600 r/min

The scope of this standard is quoted below from the ISO.org preview page (quotation in bold listed below):

Scope:

This document applies to land-based gas turbines, steam turbines, and generators (whether coupled with gas and/or steam turbines) with power outputs greater than 40 MW, fluid-film bearings, and rated speeds of 1 500 r/min, 1 800 r/min, 3 000 r/min or 3 600 r/min. The criteria provided in this document can be applied to the vibration of the gas turbine, steam turbine, and generator (including synchronizing clutches). This document establishes provisions for evaluating the severity of the following in-situ, broad-band vibration:

  1. structural vibration at all main bearing housings or pedestals measured radial (i.e. transverse) to the shaft axis;
  2. structural vibration at thrust bearing housings measured in the axial direction;
  3. vibration of rotating shafts radial (i.e. transverse) to the shaft axis at, or close to, the main bearings.

These are in terms of the following:

  • vibration under normal steady-state operating conditions;
  • vibration during other (non-steady-state) conditions when transient changes are taking place, including run up or run down, initial loading and load changes;
  • changes in vibration which can occur during normal steady-state operation.

This document does not apply to the following:

  1. electromagnetic excited vibration with twice line frequency at the generator stator windings, core, and housing;
  2. aero-derivative gas turbines (including gas turbines with dynamic properties similar to those of aero-derivatives) 
    • NOTE ISO 3977-3 defines aero-derivatives as aircraft propulsion gas generators adapted to drive mechanical, electrical, or marine propulsion equipment. Large differences exist between heavy-duty and aero-derivative gas turbines, for example, in casing flexibility, bearing design, rotor-to-stator mass ratio, and mounting structure. Different criteria, therefore, apply for these two turbine types.
  3. steam turbines and/or generators with outputs less than or equal to 40 MW or with rated speeds other than 1 500 r/min, 1 800 r/min, 3 000 r/min, or 3 600 r/min (although generators seldom fall into this latter category) (see ISO 7919-3 and ISO 10816-3);
  4. gas turbines with outputs less than or equal to 40 MW or with rated speeds other than 1 500 r/min, 1 800 r/min, 3 000 r/min or 3 600 r/min (see ISO 7919-3or ISO 7919-4and ISO 10816-3 or ISO 10816-4);
  5. the evaluation of combustion vibration but does not preclude monitoring of combustion vibration.

To read the ISO’s preview of this standard, click here. Check out the standards. If they sound like they may be helpful to you, they can be purchased at numerous places on the web including the ANSI website, ISO store, and/or the one I use, Techstreet store.

An analyst or organization using these standards should be aware that RMS overall velocity from 600cpm to 60kcpm (or 10Hz to 1kHz – the primary quantity used in the standard) does a fairly good job generally gauging the effect of things like unbalance, misalignment, mechanical looseness, resonance involvement, and even some electrical problems characterized by single-digit multiples of the line frequency, but may not give an acceptably early warning for several failure modes and certainly not for bearing defects in many cases. The overall or “unfiltered” measurement is not intended in any way to identify the source or cause of the vibration.

There is an ISO standard that is targeted to provide guidance on diagnosing specific faults (ISO 13373) which will likely be the subject of a future blog post after finishing the series on the xx816 family of standards.

by Diana Pereda

Below is a short list of when someone should consider using permanently mounted vibration sensors. This scenario would involve either epoxying on the vibration sensors or drilling into the equipment to allow for the sensor to be physically attached to the equipment. A vibration cable is then attached to the sensor and terminated into a junction or switch box. The junction or switch box can vary on the number of points that need to be collected. Once the cables are terminated into the junction box the analyst can collect data directly from the junction box.

Permanently-Mounted-Vibration-Sensor

Please note a handheld vibration collector like our VIBWORKS portable vibration data collector, would need to be connected to the junction box to collect vibration data from the permanently mounted sensors.

  • Safety – Some equipment can be dangerous to be near
  • Saves time – Some equipment can be mounted in hard to reach places
  • Avoid hazardous environment – The junction box can be mounted outside the hazardous area
  • The first phase of an online deployment – The installation, sensors, and cables are a large cost in any online project. A Cortex online system can be added later to replace the junction box.

Below is a short list of when someone might not consider using permanently mounted vibration sensors. This scenario would involve either epoxying on the vibration sensors or drilling into the equipment to allow for the sensor to be physically attached to the equipment. A vibration cable is then attached to the sensor and terminated into a junction or switch box. The junction or switch box can vary on the number of points that need to be collected. Once the cables are terminated into the junction box the analyst can collect data directly from the junction box.

Please note a handheld vibration collector like our VIBWORKS portable vibration data collector, would need to be connected to the junction box to collect vibration data from the permanently mounted sensors.

  • Cost – Multiple sensors and cables can become expensive
  • Time – Installation of the sensors, cables, junction boxes, and conduit
  • Loss of human interaction – The analyst cannot use their senses (sight, hearing, and touch) as they are not near the machines
  • Damaged cables or sensors – Sensors dislocated and cables cut

Do you have any pros or additional cons to using permanently mounted sensors? Do you have any images of junction boxes that are currently in use or comments on why permanently mounted vibration sensors would not function for your applications? Please share those with us!

by Diana Pereda

A sensor generally measures 95% of what it’s capable of measuring in line with the sensor. Two common types of vibration sensors are:

  • Single axis accelerometers

  • Triaxial accelerometers

So which one is best for your application?

A single axis sensor simply measures vibration in only one axis, so the sensor can be moved to the direction or axis of interest to be measured. A triaxial sensor has three sensors built into one housing and therefore can measure three axes or directions without having to relocate the sensor, as with a single axis sensor.

Single Axis vs Triaxial Sensors

Image Courtesy of Connection Technology Center, Inc. – CTC

All data systems on the market today will use a single axis sensor, however, some are also capable of utilizing a triaxial sensor but not all three channels at once.  Some two-channel instruments can use a triaxial sensor but they will only process two axes at one time then take the third axis reading.  To collect all three axes simultaneously you need a true three-channel (or greater) analyzer. For example, the VIBWORKS vibration instrument allows for both triax and single axis data collection. The VIBWORKS is a true four-channel instrument. Triaxial data collection can be a time saver when collecting large amounts of data, but as with all things there are pros and cons.  Using single axis sensors would typically involve moving the sensor from the horizontal to vertical to axial positions at each bearing to collect the data.  Using a triaxial sensor you place the sensor at the bearing and collect all three axes simultaneously.  Drawbacks to triaxial sensor are the cost of the sensor and cable; the sensor alone can cost 3× or more the price of a single axis sensor.  At some facilities that use a triaxial sensor they simply place the sensor at a single location on a machine and take the three axis readings and move onto the next machine.  Only if a problem is detected they return to the machine and take more precision data.  The user must make sure the sensor is always orientated and placed the same each time readings are collected as the sensor has three axes X,Y, and Z and if the orientation of the sensor is turned the trend of the machine data becomes skewed or void.

by Diana Pereda

First one must know what the definition of phase is in the reliability world.  Phase is simply the relationship between two events.  There is absolute phase that is usually measured as either “phase-led”, which is from the peak in a filtered time waveform to the tachometer, or once per revolution indicator, or “phase-lag” which is from the tachometer or once per revolution indicator to the peak in a filtered time waveform. Of the two, phase-lag is probably the most common.

Phase Measurement Examples

There is also relative phase which takes two filtered time waveforms and compares the phase between the two. Generally your Channel One or A (as the case may be) is stationary and you can move Channel Two or B from position to position and get the indicated phase.  Relative phase can be a time saver as the user can get an indicated phase without shutting down the machine to put reflective tape on the shaft for a laser or optical pick-up.  This can be used to verify or diagnose unbalance, misalignment, and looseness, etc., but it cannot be used for dynamic balancing which requires absolute phase for repeatable calculations.  Whichever type of phase is used, you can use it to identify and/or confirm unbalance; check the phase on each side of the coupling as well as across the coupling to determine misalignment and what type of misalignment. Note: Always remember the orientation of the sensor as motion towards an accelerometer is positive energy in the time waveform and motion away from the accelerometer is negative energy in the time waveform.

The user can place the sensor on each side of a junction where two surfaces come together and look for a phase shift which indicates the two surfaces are not tight to each other.  This could be looseness between a motor foot to the base, or from the base to the sole plate, or from the sole plate to the foundation, or even from the foundation to the slab.  If everything is tight then the machine will move as one.

Phase can also be used to look for cocked bearings, bent or bowed shafts and other things as well.

Our advanced vibration analyzers, along with phase analysis, can help you better diagnose fault conditions.

Featured Graphics taken from Vibration Diagnostics report by Alena Bilosova and Jan Bilos – Ostrava 2012

by Diana Pereda

First off, “triax” is short for “triaxial accelerometer sensor”. A triaxial sensor has three (tri) separate sensors (that collect data in the X, Y, and Z directions) contained in one housing, compared to a single axis sensor in a normal accelerometer.

A triaxial sensor vs a single axis sensor for vibration data collection

There are many pros and cons to using a triaxial sensor. A few things to consider:

  1. Cost
  2. Position
  3. Data frequency
  4. Time

The triax sensor (Fig. 1) is more expensive than the single axis sensor (Fig. 2). When using the triax sensor, it has to be mounted in the same orientation each time or the directions will not match the data that was collected before. Many places sell triax mounting pads to make certain that the sensor is locked in a certain orientation to ensure correct data collection. This represents an additional cost, and time must also be budgeted to mount the pads. Do not mix sensors when collecting data. If the same motor is having vibration data collected using a triax sensor, then do not collect data another month with a single axis sensor. A single axis sensor will need to be moved three times to the correct orientation for data collection whereas the triax was mounted in just one position. This could affect the trending of your data.

The VIBWORKS vibration instrument allows for both triax and single axis data collection. The VIBWORKS is a true four-channel instrument. This allows the instrument to collect data in all three directions at once. Normally three directions are taken per bearing on equipment. Depending on the setup and the equipment, it could take up to 20 seconds per direction to collect and save the vibration data. On a normal motor-fan machine train this means 12 directions which would take around 4 minutes to collect vibration data on, using a single axis sensor. Using a triax sensor it would only take 80 seconds to collect vibration data on the entire machine train.

When selecting a triax sensor, make certain that the vibration instrument is not multiplexing the vibration channels. For example it the instrument is only capable of two channels it will collect two channels at the same time and then collect the third channel separately. This means it would take almost three minutes to collect data as all three channels are not being collected at the same time.

by Diana Pereda

Where to place the vibration sensor depends on what data you wish to see.  Certain defects show up better in the horizontal direction while other defects show up better in the vertical direction.  So which location should I choose to place my vibration sensor?  Most sensors in use today are single-axis sensors, so generally 95% of what they pick up or detect is in line with the sensor.  Therefore, since placement of the sensor is crucial, some thought should be given as to what data shows up best in which of the three directions—vertical, horizontal, and axial.  Data taken in the vertical direction will typically show looseness better than in the horizontal direction (at least on a horizontally mounted piece of equipment); however the horizontal will show unbalance better than the vertical.  Axial vibration will show angular misalignment better than a radial reading will.

Also, it should be considered that in the real world there are times that the sensor cannot be placed directly on a bearing, such as with the non-drive end bearing on an electric motor due to the fan cover; on large motors this cover can extend 10 in. or more from the bearing, and considering that rolling element bearing generate high frequency data in early stages of failure and high frequency data only travels short distances, the data can and will be diminished the further from the bearing that you take your reading.  In these cases you simply get as close as possible to the bearing knowing the generated signal may be diminished; in such case you should pay special attention to the frequencies present as they may be at lower levels than expected.  If you are dealing with vertical equipment it’s typically stiffer in-line with the discharge than perpendicular to the discharge and that will affect your data as well.

For more information on a vibration tool to collect and analyze your sensor data, check us out!

by Diana Pereda

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