Insidious Corrosion of Fixed Equipment Detected Via Predictive Maintenance

 When walking through your plant, do you ever look at the piping and wonder if it is still sound and strong, or so corroded internally that it could burst at any moment?

Hopefully such a question isn’t entirely uninformed. You should have some sense of the condition of vessels and piping and whether they are nearing the end of their practical service life. The question is how accurate that sense really is.

Getting a better handle on stationary equipment condition is the topic of my article in the February 2020 issue of Oil & Gas Engineering, Insidious Corrosion of Fixed Equipment Detected Via Predictive Maintenance. It makes the point that many plants do not give the attention they should to these kinds of plant assets.

Discussions of predictive maintenance in the oil & gas industry usually focus on rotating equipment such as pumps and turbines. Those are certainly valid areas of concern, but the result of a failure is usually limited to the equipment itself. On the other hand, static equipment such as piping, vessels and similar equipment is not as maintenance intensive, but a failure can be catastrophic. This equipment should also receive predictive maintenance attention.

Most plants try to implement such a practice by using portable ultrasonic wall thickness measuring devices to check piping. This is fine as far as it goes, but it is difficult if not impossible to get consistent readings over multiple years. There are simply too many variables in play between the equipment and people using it, and in any case the results are reported periodically, and not continuously. One refinery reliability team willing to show us its data had to admit that it was statistically meaningless. Measurements taken by hand, in supposedly the same spots over 20+ years, were all over the place.

Predicting damage rates is challenging, especially in areas where the corrosivity or erosivity of the process fluid varies frequently. Nowhere in the production chain is this experienced more than refineries, which therefore have the highest variability in corrosion and erosion load. Traditional inspection methods just discussed simply don’t provide adequate quality or sufficient measurement frequency to drive predictive maintenance able to keep equipment running safely.

The answer is using permanently mounted thickness probes which measure continuously, drawn from Emerson’s Rosemount Wireless Permasense Corrosion and Erosion Monitoring System product family. This effort can be organized and managed using Emerson Connected Services for Corrosion and Erosion Monitoring, which brings together all the data collection and analysis to guide maintenance efforts.

So, as you think about your situation, do some digging into your own efforts so far:

  • Are there records of thickness measurements taken over the years?
  • Is this thickness measurement effort well organized and practiced routinely?
  • Do specific thickness reading locations indicate consistent metal thinning over time?
  • Are there plans to systematically replace piping and vessels based on this predictive measurement?
  • Is the injection of corrosion inhibitors to process media closely controlled based on pipe wall thickness measurements?

If you’re answering “no” to one or more of these questions, it’s time to consider what you might need to do before there is a catastrophe. Measuring wall thickness using permanently-mounted, ultrasonic wireless sensors provides highly useful data for maintenance programs, as discussed in greater detail in the article.

Let’s hear about your situation. How did you answer the questions just asked? Have you been successful with periodic manual measurements, or has it been haphazard?

1 Reply

  • Another kind of static equipment is the heat exchanger. There are plenty of those in the plant in various kinds of service: heating or cooling, sometimes using steam or cooling water, other times transferring heat from one part of the process which needs to cool to another which needs to be heated. Various types and sizes. Sometimes one bundle, other times many. In some services called a reboiler. When you walk past these you may also ask yourself: is it fouling? Does it need cleaning? Can it wait? Which bundle is fouling? In applications with cooling water or steam you can tell from the valve opening if the heat exchanger is fouling. But if it has multiple bundles you cannot tell which. In other applications it can be hard to tell how bad the fouling is. When there is fouling you have inefficiency you need to provide additional make up heat with burner which consumes fuel gas at cost, or cooling water also at cost, whichever the case may be. If vapor is not condensed you get over-pressure and flaring. Therefore plants put in heat exchanger analytics to tell if cleaning is required, and which bundle, or if you should inject anti-fouling chemicals. By knowing which bundle, you can bypass and clean just that one, while process still runs. The heat exchanger analytics uses existing data such as temperature measurement, flow, and possibly DP. There are four temperatures inlet and outlet, for hot and cold site. Two flows and two DP for hot and cold side. Most plants do not have all of this. Therefore they install additional sensors to collect the missing information. Wireless sensors are ideal for this as they can be installed without running signal wires or power cords. Four input temperature transmitters are a perfect fit. Learn what other plants are doing for their static equipment from this essay: