Typically WDA will pick wear debris indicating fatigue 3-6 months before VA, cutting wear can be very difficult to detect with VA until there are fatigue areas to change the VA signal
The down side is of course WDA is expensive if used incorrectly , VA is very cost efficient,
this is how we normally advise the monitoring should proceed, VA monthly every machine you can get to with safety and money restraints, Oil sample bimonthly (Depending upon contamination levels, perhaps monthly with high contamination levels) and oil test any machines that show irregular VA signals and all critical equipment.
The oil samples would be screened for significant changes to; particle count, viscosity, TAN Oxidation and Water
If VA and or oil test indicate abnormality then resample and complete WDA to visually check what contaminates are present and whether to oil change or not will be apparent.
VA and Oil Testing monthly using WDA or Ferrogram results as the referee is the best system to apply in the Australian environment because the environmental contamination is extremely hard and often under estimated in instances we note like using Basalt mined from an extinct volcano for rail track ballast and wondering why the car drives are melting away are typical results of allowing hard environmental particle ingress into the lubricated area of machinery down under in the big red country.
Vibration analysis and oil analysis can tell you the condition of your machine at a point in time. When the lab tech or vibe tech is doing analysis of those samples, the machine condition may have changed again, maybe even drastically.
Vol. 140, No. 4. May 205 issue of Platts Power (Business and Technology for the Global Generation Industry) a McGraaw Hill Companies. Article Condition monitoring automates preventive maintenance.
"Whenever the EPI software detects the earliest signs of physical deterioration in a piece of machinery (excessive temperature or vibration, for example). it sends a signal to the Avantis software. . . . Two years ago, Entergy's 2,050-MW Sabine Generating Station in Bridge City, Texas put this capability to good use and likely avoided a forced outage as a result. On February 21, 2003, the SmartSignal EPI software detected a 14F rise in temperature on turbine bearing #6 of Sabine Unit 3 . . . One week later . . . the Center detected a small (1-mil) step change in the vibration of the bearing. At this point, a specialist in the PM&D Center recommended a more thorough evaluation of the bearing as soon as possible. . . . March 26. . . . the Sabine maintenance crew performed an in-depth inspection of the bearing during the outage -- something that wouldn't have been done had it not been specifically recommended. Upon inspection, bearing #6 was found to be damaged and its shaft scored . . . After the bearing's babbit material was replaced and the journal smoothed. the temperature and vibration readings returned to normal. Had the CM software not detected the abnormalities, bearing #6 would have continued to deteriorate and might have caused a forced outage . . ."
The first point is, temperature should be watched.
Did the cooling water for the turbine oil stop for a short amount of time? When the temperature rose, was it due to the lack of cooling water, or was it when the shaft touched the bearing? - either way there was a problem identified by "excessive temperature".
Second point is, vibration was picked up after the damage occurred.
Was the vibration from the hydraulic turbulence caused by the scored shaft and/or the now elliptical bearing?
A simple bearing alarm for under $ 200.00 could have spotted the temperature change and alerted an operator. http://www.pmalert.com/. or a temperature gun from Raytech or someone like that, done on a daily basis would have caught it.