REFINERS FOCUS ON MODERN MAINTENANCE TECHNIQUES

Jan. 1, 1990
Effective maintenance techniques and modern maintenance technology are critical elements of the safe and efficient operation of refineries and petrochemical plants. The importance of effective maintenance is highlighted each year at the National Petroleum Refiners Association annual refinery and petrochemical plant maintenance conference, most recently held May 23-26,1989, in San Antonio.

Effective maintenance techniques and modern maintenance technology are critical elements of the safe and efficient operation of refineries and petrochemical plants.

The importance of effective maintenance is highlighted each year at the National Petroleum Refiners Association annual refinery and petrochemical plant maintenance conference, most recently held May 23-26,1989, in San Antonio.

At this important process industry meeting, refiners and petrochemical plant operators from around the world exchanged experiences and new ideas on ways to keep their processing operations running at peak capability. Presented here are excerpts of the question and answer sessions concerning predictive maintenance; rotary machinery care; and vessel, heat exchanger, and piping examination and repair.

What is the panel's experience with on-line plant condition monitoring, with emphasis on its cost effectiveness and reliability? To what extent has this been integrated with computerized maintenance management systems?

ALLSUP: We specifically have used two types of online condition monitoring: infrared and vibration monitoring. When appropriately applied, both have been shown to be very reliable and cost effective. Of course, cost effectiveness will depend on methods of justification. If you have never had a problem, do not anticipate one, and the consequences of a failure are not significant, then the justification and cost effectiveness may not be there.

In sessions that I have attended in the last couple of days, it appears that there are some companies that apply vibration monitoring to all of their rotating equipment. We only apply it on equipment that we have identified as "critical." Typically, the critical brand is restricted to the larger pieces (generally larger than 1,000 hp).

Our on-line monitoring is applied to radial vibration, bearing temperature, and thrust position. Automatic shut-down is only used on the thrust position. Our maintenance repair efforts pretty much guard the reliability of the factors that affect radial vibration and bearing temperature. And with our ability to monitor trends on these locations we are able to predict required shutdown. On the other hand, thrust problems do not normally show themselves in trends and most often are a result of instantaneous equipment/operation problems.

We have not tied these efforts into computerized maintenance management.

We are just in the throes of establishing a maintenance management system and expect a significant enhancement to our vibration monitoring efforts when it is implemented.

BETTS: Suncor's experience with on-line monitoring is that on 80% of our critical rotating equipment, we have installed permanent vibration monitoring instrumentation. A special emphasis was given to our compressor trains and our critical pumps. The question of its cost effectiveness or its justification can be easily answered by calculating the production losses and the potential damage to the equipment if monitoring was not installed. Suncor, while evaluating this, determined if we should install any such system.

In regards to its reliability, that depends mainly on a number of topics: (1) the installation of the actual system, (2) the operator awareness, which is a very important factor, (3) preventive maintenance-such as calibration and the inspection of any system, (4) responding to changes in alarms, and (5) the training of the actual user or the operator. The reason why I say responding to changes and training is that these are important. I have experienced some problems where systems have been installed and the reliability and the credibility of that system have created problems. I am very much in favor of installing plant condition monitoring on critical systems basically due to potential failures that we have prevented at Suncor over the years.

On the second part of the question, as to what extent has this information been integrated with the maintenance management system, we use a manual system for monitoring trends and wear patterns to determine expected life and potential failures. It is my opinion that trending and conditions are the most important functions of any on-line condition monitoring.

What are the elements of your predictive maintenance program and how effective are they? Do you differentiate between preventive and predictive maintenance?

KURZ: The primary element of our predictive maintenance program is collecting vibration data on rotating equipment. The data are collected monthly on approximately 250 pump and compressor trains. We then upload these data into a computer, analyze it, and store it. A report is written each month to the maintenance manager and work orders are generated from this report to further investigate or make repairs to the equipment. We still have some bearing failures that are not identified by the vibration checks, but we feel we are greatly improved over what we were finding. I believe we are finding about 75% of our bearing problems by this method.

We have just started a lube oil analysis program on some of our major equipment, We started our first test last month. We also periodically do infra-red temperature scans of our electrical substations and also some of our reactors, particularly in our catalytic cracker area. Currently we have no set schedule to take measurements but we normally do this every 12 to 18 months. We also occasionally do transformer oil analysis to check the condition of our transformer.

We recognize both predictive and preventive maintenance techniques. We have a preventive maintenance program as part of our computerized maintenance information system. This program identifies repetitive maintenance tasks that can be done on a preset schedule, and work orders are automatically generated periodically. These tasks are completed by the maintenance journeymen. On the other hand our predictive maintenance activities are not generated by work order and are completed by salaried employees, although we do often have work orders written as a result of a predictive maintenance recommendation. We do not classify these work orders as either preventive or predictive maintenance.

RAMSAY: Our predictive maintenance program is very similar to the one just mentioned, consisting predominantly of vibration condition monitoring. We are running about 50% of our plants' rotating equipment on a routine basis. We expect to add about another 15% this year. It has a proven track record and is well accepted by the plant. One of the unexpected benefits that we have accumulated as a result of this is some of the process conditions that we have spotted with our routine vibration collection have rolled back into the process group or the production department as unexpected problems that they did not realize were out there - such as pluggage and that type of thing.

Again we also differentiate between predictive and preventive maintenance. One of the main elements of our preventive maintenance program is a lubrication program, again computer generated and tracked. Even though our major rotating equipment is worked on a preventive maintenance frequency based upon annual or biannual turnarounds, the scope of that work is based on condition.

BETTS: Some of the elements of a good predictive maintenance program are:

  • vibration monitoring, permanent or periodic sampling using data collectors;

  • condition monitoring where you physically check equipment, i.e., seal leaks, steam leaks, oil levels, etc;

  • lube oil sampling;

  • performance monitoring;

  • past history records;

  • infra-red, which at Suncor is being used more each year.

All six, of course, are equally as important to determine the condition of any piece of equipment. I have experienced situations where there has been little change in the vibration characteristic, but I have seen a definite change in the lube oil analysis. That is why I say that one is just as important as the other.

There is a tendency today to lean more towards predictive than preventive simply because the petrochemical industry is trying to get the maximum life out of equipment. The question is often raised, and I am sure you have seen advertisements,

"Why pull a machine apart to do a preventive maintenance when you can determine its condition by predictive maintenance methods?" With the technology that is available today, that becomes more real every year. As we learn the new technologies of instrumentation, we can predict life histories and we can predict the equipment a lot more accurately than we could do 10 years ago.

What type of vibration monitoring is done on rotary equipment? How do you decide which equipment to monitor?

BETTS: The type of vibration monitoring we use on rotating equipment is permanent monitoring using non-contact displacement probes. However, we do use accelerometers and velocity transducers on some gear boxes of critical machines. In conjunction with this we use the vibration condition monitoring data collectors which monitor all our equipment on a weekly basis, only in our fixed plants. If I understand the question correctly, the type of vibration monitoring would mean the type of measurement that is used in general. The majority of readings taken on our plant are in velocity. This would obviously depend on the equipment, the speed, and there are other parameters you have to look at. One of the most important issues when selecting a vibration monitoring parameter is the type of transducer to use. This is really a key factor when selecting any type of vibration monitoring system.

On portable vibration data collector instruments, there are both velocity and accelerometer based. There are a lot of new instruments coming out in the market, most of which are accelerometer based. They do have integration from acceleration to velocity. I would recommend that if you are not familiar with vibration monitoring, you can discuss this question with a consultant. There are also papers written by the vibration institute to assist you.

I am often asked the question "What is the best piece of equipment to use at our plant?" Only you can decide that and I would suggest you read up on it or talk to some consultants. If you talk to suppliers, they will always tell you their equipment is the best. Be careful when you are choosing data collectors. Most important, vibration data collectors on the market now are accelerometer based and they are integrated into velocity and double integrated into displacement.

KURZ: We continuously check only one major equipment train in our plant. It is our FCC blower. We have non-contact probes on that machine. On our other equipment we do as Mr. Betts mentioned with the data collector, taking vibration readings. However, we do ours monthly, not weekly. We started out taking readings only on our primary equipment, but recently we have started taking readings also on installed spares and on equipment that is not run continuously, such as some of our tank farm equipment.

ALLSUP: We do two types of vibration monitoring: on-line continuous monitoring (primarily on "critical" equipment), and data collectors (for general purpose equipment). The majority of our vibration monitoring is performed with data collectors. The data collector equipment uses software to lend itself to computer analysis which in turn allows for prompt evaluation and application of the results. However, the process is time constrained by the field gathering of the data and unless priority methods can be established the general purpose vibration monitoring may not be as effective as it should be.

The effectiveness of the vibration monitoring is strongly influenced by data interpretation. And data interpretation has proven to be limited only by our experience level. In the two plus years that we have been developing the equipment, we continue to expand our application and implementation.

BRAZIL BURGESS (Hill Petroleum Co.): On all of our sleeve bearings in large major equipment, we use proximity probes. We have found in the past that these do not give us the total picture. As long as the bearings are tight and stiff, you will find that the problems associated with imbalance or even to some extent blade pass are transmitted directly through the bearings to the case without showing up on your proximity probe readouts. So we have installed accelerometers on the case also. This is primarily on our FCC power train and wet gas compressor. We do not have any other major centrifugal compressors that we monitor continuously.

We have also found that on major equipment, you are probably better off with recorders somewhere. Once things start happening to that particular unit, the operators tend to forget about the equipment and start worrying about what is happening to the process. It is a point you might want to remember.

We also have a monitoring program with velocity probes on the majority of our pumps and we are trying to maintain a history.

Has anybody had any extensive experience with computerized programs that allow you to track the history?

What is the experience with X-ray surveys of existing welds in piping and equipment that do not meet current standards?

RAMSAY: We have done some of this work trying to upgrade piping systems. While we have met a few welds that have not met the upgraded requirements, most of our systems come surprisingly close. We would not however try an extreme case of going from something like a Class 3 inspection to a lethal standard. We would expect significant difficulty in achieving that.

ALLSUP: Our piping systems were specified, built, and inspected according to standards. Our expectations are that the original installation met those requirements. And typically, we do not find defects in existing welds that do not meet current standards.

However, occasionally we have found welding related defects. In these instances, we have taken the attitude that if we find problems with pipe that has been in service, regardless of successful operating experience, we will evaluate the extent of the problem and make repair.

BETTS: Our radiography standards at Suncor have not changed over the years. We radiograph 10% of all welds.

However, under our present survey program put into place during 1984, we went back and looked at most of the original welds using a high resolution film. For 80% of our work on a corrosion survey program we use RT, 20% UT. We find that we get an actual picture of the pipe we are looking at. We can actually measure the thickness, and we input the data into our "AMSPEC" program. However, any faults that we did find on existing welds, we did actually go back and repair.

CHARLES WAGUESPACK (Tesoro Alaska Petroleum Co.): We just implemented a cathodic protection program at our refinery last year. I am interested in what Mr. Ramsay had said that they routinely test. What type of routine do you go through, what frequency?

RAMSAY: I believe we are on a six-month frequency on our routine testing. Our plant is getting into the 20-year-old-range, and we are actually having to replace some of our sacrificial beds at this time. So it is proving to be effective, The few cases we have had to look at underground lines we consider to be successful.

ROBIN RINGER (ICI Tracerco): With regard to gamma ray scanning to locate blockage and buildup in pipe and pipelines, we found blockage in pipes using the portable gama ray scanner. We can do about 300 ft of line, taking a reading every 1 0 ft or so to locate buildup in flare headers or coke deposits in transfer lines. It is a very quick and easy service. It is not a continuous or real-time service. We will come in and identify by difference in density in the pipe buildup.

What techniques are being used to repair coke drum, skirt-to-shell, and head-to-shell attachment welds? Have other areas of "chronic" failure been found?

BETTS: Depending on the material involved and the complexity of the repair, a specific procedure is written detailing all welding and testing requirements. This would involve the removal of the lining material, the repair or replacement of the damaged area, examination as required, and the testing as applicable.

Any bottom shell course section found deformed is subsequently replaced. The most probable cause we found was overheating. We have had no chronic failures. However, we have had some experience with cracking of the bottom head. We attributed this to over torquing at the bolts.

JIM PROKUPEK (Lyondell Petrochemical Co.): Mr. Betts, you said the problem in the coke drums was overheating, do you know what caused the exotherm, or what caused the overheating problems in your coke drums?

BETTS: No, I do not.

DIANE TURNER (E.I. duPont de Nemours & Co. Inc.): What sort of testing and inspection do you recommend for caustic storage tanks or process vessels in caustic service?

What kind of inspections do you perform on any vessels where there may be caustic embrittlement?

ALLSUP: Well, not being familiar with your material of construction, I would start with a visual inspection and carry on from there. Do you have any special problems with the equipment? Inspection techniques would be best on special problems.

RAMSAY: I will add that we have not experienced any real caustic embrittlement problems on our storage tanks. Again temperatures and concentrations may not be in the proper range and typically we try to operate outside of the ranges where we expect caustic embrittlement.

What experience has there been with "U" tube exchanger cleaning in high fouling service (tube size, length, cleaning U-section)?

BETTS: Depending on the service application and the design conditions of the unit to be cleaned and the method of cleaning, our experiences vary greatly. Since our operation involves a multitude of applications, our primary cleaning method is the use of high pressure water. There are some problems when cleaning "U" tube bends where flexible lances are not able to go around the bend.

It has been proven that power lances now clean "U" tube bends better. Suncor is now looking into on-line chemical cleaning.

KURZ: For tube side fouling services we try not to use "U" tubes. We have used flexible tip water lances on our slurry exchangers and have good success. These exchangers primarily need cleaning from plugging more so than true fouling. Other methods can be used, of course, chemical cleaning and power lances as have been mentioned. I have heard of people using sand or other abrasive materials-the sand jet method. I am not sure how effective this method is.

BRAZIL BURGESS (Hill Petroleum Co.): We have had a problem with this in our crude unit and we tried water blasting, power lances, and slurry blasting with a sand solution. About the only thing that we have managed to use that has done any real good, particularly in the "U" bends, is to actually bake the material out. Even that has some question of success because at least two or three tubes will always be left plugged. If you have a "U" tube with constant plugging problems, the best solution is probably a floating head.

What programs have been implemented for replacing all asbestos gaskets and packing material?

ALLSUP: We are making an extensive effort to move away from asbestos-containing gaskets and packing. Replacements are only being made with maintenance opportunity and we have chosen to replace with Teflon or graphite products. We are not allowing a wholesale change to asbestos fiber substitutes.

It has not been easy to be cost effective in our efforts to select an asbestos substitute. The asbestos fiber substitutes are desirable from a cost point of view. However, we are concerned that the non-asbestos products corrosion resistance and mechanical properties will not allow arbitrary substitution.

Are people using seamed pipe in high-pressure service?

RAMSAY: We have used welded pipe for steam at 1,250 psig. We do require additional testing to utilize that material. A lot of our pipe specifications currently specify seamless pipe in the systems that we believe need to be more reliable. However, we are rapidly approaching the point that we believe a thoroughly inspected welded pipe with the additional inspection requirements of welded pipe is as reliable if not more so than seamless.

BETTS: In the Province of Alberta, the use of seamed piping in high pressure service is not normally acceptable by the Department of Labor. We do not use it.

GEORGE THOMAS (Chevron Chemical Co.): You stated that you consider seamed piping acceptable with pressures up to 1,200 psi, provided that it is properly inspected. Please tell me briefly what you consider proper, adequate inspection of welded pipe.

RAMSAY: We include eddy current or ultrasonic testing on that pipe before using it.

HIGGINS: Does anyone use spiral welded pipe?

RAMSAY: We have used the spiral welded pipe in some water applications. I think we have two applications in the plant.

We have had no problems with it but currently we would not use it for process.

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