April - Library

Lessons Learnt In 45 Years
of Condition Monitoring
Ray Beebe Monash University Gippsland Campus (Australia)
The author was inspired by the concept of condition monitoring to help prevent unnecessary overhauls when
he started as a young engineer in power generation in 1964. In parallel with a general engineering and middle
management career in several power plants in Australia and the UK, he developed and applied vibration and
performance analysis for pumps, steam turbines, boilers and heat exchangers. His experience and passion for
sharing knowledge led to presentation of many in-house and public courses and his first book. That in turn led
him to Monash University in 1992 and a second award-winning book in 2003. In that role, he reflected on his
experiences and has written 70+ papers, many of which have been chosen for conferences and technical journals
around the world. The lessons learnt stand forever, but not all are well-known. This paper of brief case studies in
narrative style is intended to entertain, inform and even inspire.
Introduction: the starting years
Yallourn Power Station was initially built in the watch of Sir John Monash, citizen soldier (WW1 Lt-General) and
engineer. It was the biggest one in the State from 1924 up to 1966. Such places tended to have the best engineers
and I was fortunate to have two excellent bosses there. They had responded to a request from the manager of
maintenance. He was apparently holding a sheaf of fault reports, overtime returns, spare parts usage reports, on
a turbine that had just come back into service after a major stripdown. “There has to be a better way than this” was
his cry. Research in POWER and ASME papers led to the Valves Wide Open test being applied. My involvement
in testing 60MW and 120MW turbines there gave me the topic for my engineering course dissertation.
Performance tests were also performed on the boiler feed pumps and used as a guide to overhaul.
Measurement and analysis of machine vibration as a guide to its internal condition was very basic. We had a
Philips velocity transducer and a readout box that gave overall vibration in thousandths of an inch. For some
machines of rotation speed below 900 r/min, a multiplier of 1.5 was used: nobody explained why (later I learnt
that it was because velocity transducers have a natural frequency below about 900 c/min). We could examine the
output on a CRO, and tell if most of the vibration was at rotation frequency and if there was any “high frequency”
present. This was adequate as most of the problems were caused by unbalance due to wear.
Two methods were used for balancing in the field. The timed-oscillation method required only a stop watch and
graph paper (Beebe, 2001). The other used a manually tunable filter that fired a stroboscope to detect previously
chalked numbers around the rotor. The usual vector calculations followed.
Lesson #1 Choose your bosses well
Lesson #2 When a plant is new and/or the major asset makes it easier to get proposals
for monitoring etc. accepted.
After further training attachments, I was assigned to Hazelwood Power Station in 1966. It had three 200MW units in
service, but would grow by a unit each year to reach eight, its current size. The boilers were essentially identical,
but there were two makes of steam turbines and boiler feed pumps.
The vibration measurement program was as at Yallourn, but more use was made of the balancing instrument to
find relative phase angles of the 1X vibration to give a crude operation deflection shape. For routine monitoring of
the steam turbines, permanent numbers were painted around the rotor line at a visible section.
Case study 1
A strange vibration was experienced on the newest machine at the generator drive end bearing. When runup
following a shutdown, the machine vibration was unacceptably high. The operators tripped it and ran for some
hours on turning gear (low speed rotation at 30 r/min). Back on line, the vibration was now acceptable. This
happened repeatedly: sometimes all would be OK after a shutdown, sometimes not. Vibration measurements
with our crude instruments on line in both states showed that the vibration amplitude and phase angle differed on
every run! All I could say was “these symptoms indicate that there is something loose inside the generator rotor
around that end”.
Stripdown was arranged and the generator rotor examined closely. Nothing was found. Eventually, a message
came from the OEM saying that one of the rotors – this one - was non-standard. At the end of manufacture, the
rotor centres were bored out to about 100mm diameter, and the hole packed tightly with rubber bungs. Flaws
were found in one of the rotors and a length was bored to a bigger diameter…. but bungs of the same size were
inserted – see Figure 1. You can guess the effect of these masses moving around! They were removed -“no
longer our practice” - and after an expensive 38 weeks off line, all ran well.
Vol 24 No 2