1211 Operate and Maintain Pumps Preprint 4

February 5, 2019 | Author: maxwell777 | Category: Pump, Flow Measurement, Gases, Chemical Engineering, Applied And Interdisciplinary Physics
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 A CEP  Preprit © 2011 AIChE

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Learn to Effectively Operate and Maintain Pumps Daniel Kernan

Centrifugal pumps play a central role in chemical processing. Proper pump operation and maintenance can improve a facility’s productivity, reduce downtime, and trim costs.

ITT Goulds Pumps


or transporting uids ranging from water to crude oil and pigments to pesticides, pumps serve an important function in the chemical process industries (CPI). Pumps are the second most widely used industrial machine (after motors), and are found in all CPI plants. Despite such  prevalence  prevalen ce and signican signicance, ce, however however,, pumps are often often overlooked as a potential source of improved productivity and cost reductions.  Vertical

Realizing this potential requires not only selecting the right pump, which is the subject of a previous CEP article (1),  but also also prope properly rly operat operating ing and and maintai maintaining ning the pump pump — the focus of this article. In addition to discussing best practices for centrifugal pump operation and maintenance, this article also describes continuous monitoring systems and pres ents two case studies that show how they can be applied to improve system performance and reduce maintenance costs.

Pump basics

Horizontal Shaft  Axial Casing


Pump Inboard Bearing

Pump Outboard Bearing

Although enhancements to pump designs and materials and the expanding use of digital monitoring technology have improved pump performance, the operating principle and  basic structure structure of centrifugal centrifugal pumps (the (the most most commonly commonly used pump in the CPI) have changed little in decades. A centrifugal pump (Figure 1) is a rotating machine comprised of six main parts: an impeller, a pump casing,  bearings,  bearing s, a bearing bearing frame, frame, a shaft, shaft, and a mechanica mechanicall seal. These parts work together to convert mechanical energy into  pressure:  pressu re: The The rotating rotating impeller accelerate acceleratess the incoming incoming liquid, and as the uid travels through the pump casing, its velocity is converted to pressure. The pressurized liquid then exits the pump discharge.

Efciet pump operatio Mechanical Seal

Figure 1. The main parts o a centriugal pump are the impeller, casing, bearings, bearing rame, shat, and mechanical seal. p



December 2011 CEP

A key factor to assess whether a pump is operating prop erly is the best efciency point (BEP), which is the owrate at which a pump’s efciency is highest. Although few pumps operate at their BEP all of the time because of process vari-

ability, a pump that is properly sized for its application will maintain a ow near peak efciency. Maintaining a owrate of 80–110% of BEP is a good range to maximize efciency and minimize the risk of excessive wear or pump failure. Unfortunately, many pumps do not operate within this range. A study by the Finnish Technical Research Center that evaluated nearly 1,700 pumps at 20 process plants across multiple industries found that the average pumping ef ciency was below 40% of BEP and that more than 10% of  the pumps were running below 10% efciency. When the owrate is higher than the pump was designed to handle, the pump is operating above its BEP, a condition known as runout. The high ow increases the exit velocity of the uid leaving the pump, which in turn creates a low pressure area inside the pump. Operating below the BEP occurs when the discharge ow is restricted, causing uid to recirculate inside the pump. This also creates a low-pressure area within the pump. In either case, the pressure imbalance inside the pump increases the radial load on the impeller and causes the shaft to bend, which increases vibration of the pump. The increased vibration and imbalanced forces create stress on the pump’s internal components. This usually manifests itself rst in the bearings and/or mechanical seals — the two  parts of a centrifugal pump that fail most often. Cavitation is another possible outcome of inefcient  pump operation. Cavitation happens when the net positive suction head (NPSH) — the difference between the suc tion pressure and the vapor pressure of the uid — is too low. If the uid pressure on the trailing side of the impeller   blade (opposite the pump intake) falls below the vaporization point of the uid, the uid will begin to boil, creating vapor bubbles. Cavitation occurs when these vapor bubbles reach an area of high pressure inside the pump and collapse violently — causing pitting damage to the impeller, along with sudden, uneven axial and radial loading on the impel ler. This, in turn, can cause shaft deection that is random in direction and often severe in magnitude. A common reason for inefciency is improper pump size. In an ideal world, all pumps would be properly sized to run constantly at their best efciency points. In the real world of an industrial plant, however, this is impractical. Many process pumps are oversized for the needs of the application, often because pumps need to be specied  before all of the process parameters have been dened and engineers tend to err on the side of overestimating pump needs. Furthermore, a pump might be perfectly suited to an application but changing process demands render it unsuit able. Processes are uid — literally and guratively. Formulations change and production rates vary, but typically the hundreds or thousands of pumps supporting the  processes do not change with them. Thus, continued reliable

 pump operation requires a robust maintenance program centered around monitoring basic machine health data and  pump operating conditions. A pump maintenance and monitoring program contains three main elements: • pump performance monitoring and pump system analysis • vibration and bearing temperature monitoring • visual inspections. Individually, each of these elements is an important indicator of pump health. Collectively, they provide a complete  picture of the actual condition of the pump.

Perormace moitorig  Ideally, ve parameters should be monitored to under stand how a pump is performing: suction pressure, discharge  pressure, power, pump speed, and owrate. At a minimum, suction and discharge pressures are essential for determining the total dynamic head (TDH), which is critical to under standing the pump’s operation with respect to BEP, and the available net positive suction head (NPSHA). Suction and discharge pressures. The suction and discharge pressures are measured either by pressure tranduc ers that can transmit real-time data or by pressure gages. If   pressure gages will be used, the gage taps should be installed in a straight section of pipe, ideally one whose length is 10 times the diameter, adjacent to the pipe wall and on the horizontal centerline of the pipe. Taps in elbows or reducers will not accurately measure the true static pressure due to the velocity head component of the pressure reading. Also avoid  putting taps in the top or bottom of the pipe, where they can  become air-bound or clogged with solids. Using only suction and discharge pressure measure ments to assess pump operation has limitations. For instance, when a pump is operated by a variable-speed drive, the speed of the pump must be factored into the evaluation using the afnity laws, which state that the change in TDH is proportional to the square of the speed. It is also difcult to determine pump wear based on only suction and dis charge pressure data. As the pump wears, internal clearances increase (i.e., the area through which the uid passes gets larger) and the pump’s ability to generate pressure decreases. Without additional information, this decrease in pressure could be interpreted as a change in the process conditions and not necessarily a worn pump.  Power. An accurate power measurement, in combination with suction and discharge pressure readings, can be a  powerful tool to assess pump performance. Although transducers that measure current are the most basic and costeffective power-monitoring solution, their readings should  be applied judiciously. The motor’s current reading is not directly proportional to load. Factors such as input voltage,


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 power factor, and motor efciency should be considered to accurately determine the actual shaft horsepower being transmitted to the pump. Low-voltage pump load monitors are available for xedspeed pumping applications. For a typical investment of less than $1,000, these devices offer protection against underload and overload conditions that could result in mechanical seal damage or pump failure.  Pump speed. Pump speed also plays a role in centrifugal  pump load monitoring because of its relationship to power  utilization. While a pump’s output varies in direct proportion to the speed of the motor, the horsepower required to operate centrifugal pumps varies with the cube of the speed. This means that if the speed of the pump motor is reduced to onehalf of the base speed, the required horsepower is only oneeighth of the rated horsepower. Changes in uid properties such as specic gravity and viscosity can impact pump speed and power requirements and thus should also be considered.  Flowrate. In an ideal world, it would be possible to obtain ow measurements on all pumps. Although this is often impractical, owrate data are vital for understanding

350 325

5 ft

6 ft 45

8.375 in

the overall efciency of the pump. Some facilities have installed permanent owmeters to make the job of monitoring easier. If your plant uses such owmeters, make sure they are working properly and are calibrated on a regular schedule. A clamp-on ultrasonic ow meter can provide a non-intrusive, temporary solution. These devices can be used on a range of pipe diameters and have an accuracy of approximately 1%. The challenge is nd ing a straight run of pipe, typically 10 times longer than the diameter upstream of the meter and ve times longer than the diameter downstream, on which to attach the owmeter. In some cases, it will be very difcult (or impossible) to determine all of these parameters in the eld. In such cases, you will need to combine the known measurements with your engineering experience to assess whether a particular   pump is properly sized and performing the job adequately. The key document for a pump is the pump performance curve. Pump curves (which are covered in more detail in Ref. 1) depict the total dynamic head, brake horsepower, efciency, and NPSH, all plotted over the capacity range of  the pump (Figure 2).

8 ft 55


10 ft 58


Model: 3196 Size: 2X3-8 - MTX/MTi/LTX/LTi Imp. Dwg.: 100–162 Pattern: 53812 Eye Area: 5.4 in2




300 8 in


90 12 ft

16 ft

14 ft

18 ft

275 80


7.5 in 250    t    f  ,    d   a   e    H

62 60

225 7 in 200



6.5 in


30 hp

6 in 55

150 5.5 in


25 hp

  m  ,    d   a   e    H



125 20 hp 100

5 hp


50 15 hp

75 10 hp 0










m3 /h 0









Figure 2. A pump curve shows, at a glance, how the pump will operate at a given speed as a unction o impeller diameter. Constant horsepower, eciency, and NPSH lines are superimposed over the head curves. p



December 2011 CEP

The design of a piping system, especially the pump suction piping, can have a signicant impact on pump operation. Boost suction pressure Elevate the eed tank, or increase the suction pressure available to the pump. Many centrifugal pump problems are caused by poor suction conditions. Suction Lower operating Lowering the operating temperature reduces the uid’s  piping should never be smaller than the temperature vapor pressure, which increases the available NPSH.  pump intake, and, in most cases, it should Reduce owrate Reduce the owrate to reduce the NPSH required; this  be one size larger. An eccentric reducer, can be done by installing several smaller pumps. which has a at top to prevent the buildup Reduce speed Pumps running at lower speeds have lower NPSH of air bubbles, should be used rather than a requirements. In many cases, however, this will require a larger pump. concentric reducer. Suction pipes should be as short and Install a larger impeller I a pump has a relatively small impeller (which is ideal and reduce pump speed rom a hydraulic viewpoint), installing a larger impeller straight as possible. If an elbow or tee will reduce the NPSH R. is located adjacent to the pump suction nozzle, install a straight run of pipe, three Pump system aalysis to ve times longer than the pipe diameter, Pump system analysis is more comprehensive than  between it and the pump suction. A general rule of thumb is monitoring the performance of an individual pump. It is the to keep suction pipe velocities within the range of 5–8 ft/s. discipline of assessing pumping requirements in the context Higher velocities will increase the friction loss and can cause of an overall system designed to move uids as part of an air/vapor separation from the uid and uneven ow patterns. industrial process. This can prevent the liquid from evenly lling the impeller  It is often overlooked because operators assume that the and lead to hydraulic imbalance, excessive shaft deection, system was constructed with the installed pumps in mind, vibration, and cavitation. and that the pumps are operating according to design speci The Hydraulic Institute, a nonprot trade association cations. This often is not the case, however. of pump manufacturers and suppliers, denes NPSH as the Many pumps are purchased as individual pieces of  total suction head in feet absolute, determined at the suction equipment to meet specic process needs (or estimated nozzle and corrected to datum, minus the vapor pressure needs), rather than as part of a comprehensive system of the liquid. The energy conditions on the suction side of  design. Ensuring that the pump is right-sized for the applica a pump determine whether the liquid will vaporize at the tion, has good suction piping design, and has adequate suc lowest pressure in the pump. If the pressure falls below the tion pressure are essential to reliable operation. vapor pressure of the liquid, the liquid will vaporize and An oversized pump is typically operated with its dis cavitation can occur. To prevent cavitation, pump manu charge valve throttled back to limit ow. This has the effect facturers publish the net positive suction head requirement of applying a mechanical brake to the pump, forcing it to operate outside its optimal ow range, away from its BEP.  Vibration Composite Mathematical  Vibration Components  Vibration  Analysis Spectrum As discussed previously, running a pump away from the BEP causes the internal hydraulic forces to become imbal   s 1X    /   n    i anced, which puts stress on the pump shaft, seals, and bear  ,   e FFT    d =   u ings, which in turn can lead to premature failure. 2X  Analysis    t    i    l   p When monitoring a pump, it is important to note the   m    A 5X discharge valve position. A valve that is throttled more than 1X 2X 5X Frequency, Hz 50% can indicate that the pump is oversized for the applica Mechanical Looseness tion. The simplest and most cost-effective way to right-size Imbalance Misalignment the pump is to trim the impeller. A more-exible option is to add a variable-frequency drive to ramp the pump speed up or down. If the pump is drastically oversized, it may have to be hydraulically re-rated or a new pump may need 1X 2X 3X 4X 5X 1X 2X 3X 4X 5X 1X 2X 3X 4X 5X to be installed. Many factors go into this decision, such as Frequency, Hz Frequency, Hz Frequency, Hz demand variability, static head requirements, and exibility p Figure 3. By dissecting the vibration signal and analyzing the individual for future capacity changes. The energy savings and reduced components o the ast Fourier transorm (FFT) spectrum, the specic maintenance costs will often offset the initial investment to machine deects can be identied. For example, high vibration at the running right-size the pump. speed typically indicates machine imbalance. Table 1. Cavitation can be eliminated by increasing the suction pressure, lowering the fuid temperature, or reducing the required NPSH.


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(NPSHR ) for each pump. NPSH R  is the minimum suction  pressure required by the pump to prevent cavitation. Table 1 lists some remedies for cavitation. A typical pump system analysis includes analysis of the suction pressure requirements, evaluation of the pump’s operation, and a thorough review of the piping conguration and valving. The more complete understanding the engineer  has of the pumping system, the more effective the mainte nance program will be.

 Vibratio aalysis Vibration analysis is the cornerstone of all pump-perfor mance monitoring programs. Vibration is directly related to the pump’s operation relative to its BEP — the higher the vibration level, the further away from the BEP. Organizations such as the Hydraulic Institute and the Vibration Institute have developed criteria for normal, acceptable vibration levels. However, exercise caution when applying these published values, because the allowable vibration level for a specic pump depends on the applica tion, and there is no absolute vibration level that indicates a  pump in distress. Since every installation is unique, each plant should develop its own site-specic criteria. When a pump is ini tially started up, take vibration readings on the outboard and inboard bearing housings of both the pump and motor, in the vertical and horizontal directions, and record the pump’s operating point. Compare these data to published values for  the specic pump, and use this information to set alarm lev els. These setpoints can be programmed into a digital moni toring system or checked during walkaround inspections.

Evaluate the frequency and the amplitude of the vibra tions. Frequency identies the type of defect that is causing the problem, and amplitude indicates the problem’s severity. The total vibration is comprised of multiple smaller vibra tions, each due to a specic condition, such as pressure imbalance, shaft misalignment, looseness of parts, or vane  pass — the varying frequencies created by the rotation of  multi-vane impellers. The measured vibration signal can be mathematically dissected using fast Fourier transform (FFT) analysis to reveal the individual contributing components (Figure 3). A plot of amplitude vs. frequency can then be evaluated to identify the source of vibration and the condi tions that may ultimately cause machine failure. Bearing defect analysis is another useful conditionmonitoring tool. Each component of a pump’s roller bearing has its own unique defect frequency. Vibration monitors enable the engineer to isolate bearing defects and determine whether the bearing is in distress. This allows the user to shut down the machine prior to a catastrophic failure. Sev eral methods of bearing defect analysis are available. The most practical defect analysis technique is bearing enveloping. In this method, lters built into the vibration analyzer amplify repetitive frequencies produced by the  bearings. Bearing manufacturers publish charts of defect frequency as a function of running speed, which can be used to identify and monitor the defect frequency. As noted earlier, a  baseline must be established and then trends monitored. Another good practice is to monitor bearing temperature. Higher-than-normal temperatures provide an early indication of lubrication breakdown or lack of lubricant. In most CPI applications, a temperature sensor mounted on the outside

Pump Failure Cited as the Cause of Catastrophes Case study 1: Failed pump causes a refnery shutdown. A

catastrophic ailure occurred at a refnery that produces about 70,000 bbl/d o oil. A fre broke out at the bottom o a vacuum tower, orcing a three-day shutdown that cost $1.5 million in damages and lost production time. An investigation quickly identifed a ailed vertical inline pump as the cause.  A root-cause analysis traced the origin o the fre to the pump’s mechanical seal, and a review o maintenance records revealed numerous repairs and parts replacements consistent with o-BEP pump operation in the weeks and months leading up to the fre. A ter the fre, the refnery installed a continuous monitoring system. In the two yea rs since the system was installed, the refnery h as required no unplanned maintenance on its pumps. This is a more common occurrence than one might think among pumps that are not operated and maintained properly. On average, one o every 1,000 pumps with a ailed mechanical seal leads to a fre.



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Case study 2: Corn processor employs predictive condition  monitoring. A large corn processor operates three manuac-

turing plants that run 24 hours a day, seven days a week. The processing equipment refnes corn kern els into starches and syrups used by sot-drink makers, canners, conectioners, and bakers. The equipment operates at high speeds with extreme precision, creating saety issues i any piece malunctions. This plant uses a web-based c ondition monitoring approach to reduce the risk o equipment trouble. Se nsors in three dierent areas o the plant collect data on variables such as bearing vibrations, temperature, speed, oil level, liquid leaks, and pump cavitation. The data are ed continually via a wireless transmitter to a monitoring system server, and displayed through a standard web browser. I any measured data are higher than the alarm setpoint, operations personnel are notifed via email or telephone. Managers can go online at any time rom any computer to check pump readings. The system has improved plant saety and equipment u ptime.

of the bearing housing is sufcient to measure bearing temperature. Alternatively, an infrared (IR) sensor  (2) can  be used. Note that an IR temperature detector measures the outside surface of the bearing housing and not the actual bearing temperature — a distinction that should be taken into consideration when using this technique.

 Alarm Notifications

Control Room Online Access


Cotiuous coditio moitorig  The most rudimentary form of condition monitoring is visual Pump Health Data inspection by experienced engineers, operators, and maintenance personnel. Dashboards & Analysis Walkarounds are part of any preven tive maintenance program, and are p Figure 4. The monitoring data rom a digital condition-monitoring system can be sent to both the useful for detecting failure modes control room and to a web-based monitoring platorm. Key perormance indicators (KPIs), such as NPSH A , such as cracking, leaking, or corrosion fowrate relative to BEP, and vibration data, allow operators (with no special training) to monitor pump  before pump failure is likely to occur. operations. When more-advanced diagnostics are necessary, such as vibration spectrums and time-wave orms, the reliability and maintenance teams can access the system via the web. Integrating maintenance The central concept of the walkand operational data improves operational eciency and reduces the need or onsite manual monitoring. around is something children learn at an early age: stop, look, and listen. key machine health indicators — including performance  Noise, visible vibration, visual corrosion, and leaks are easily (efciency), vibration, temperature, owrate, pressure, detectable signs of trouble. The earlier these problems can be and power — and provide advance warning of impending caught, the lower the cost of repair and risk of downtime. trouble. In general, wired systems are more costly to imple Another way to spot developing problems before they ment and provide more comprehensive process-related infor lead to pump failure — the essence of predictive mainte mation. Wireless systems are simpler to install and provide nance — is the use of continuous vibration analysis. In its greater accessibility to information. Data from wired and/or  simplest form, this technique involves installing a simple wireless systems can be fed to automated process-control mechanical vibration switch or digital warning light that will systems to provide a fully integrated program. indicate excessive vibration on individual pumps. Wrappig up To achieve the full benets of a predictive maintenance  program, plants can employ digital monitoring systems Proper pump operation and maintenance involves (Figure 4) that gather more comprehensive data on pump ensuring that pumps are operating near the BEP and closely  performance. Options include: monitoring key performance parameters — suction pressure, • wired systems — the equipment sensors are hardwired discharge pressure, owrate, pump speed, and power. Pre to rack-based computer servers, and data are accessed and dictive maintenance uses condition-monitoring systems that analyzed over an internal network  collect machine status and process data to identify pumps • wireless systems — sensors transmit data to a central that are about to fail and the underlying problems. By imple hub, and data are accessed and analyzed over secure Internet menting the best practices described in this article, you can connections run your pumps efciently, while reducing risk of equipment CEP • integrated systems — hardwired and wireless sensors failure and downtime. feed data to an internal server-based network. All of these systems provide continuous monitoring of  DAnIE KEnAn is the manager of the monitoring and control group at ITT Literature Cited 1.

Kelly, J. H., “Understand the Fundamentals of Centrifugal Pumps,” Chem. Eng. Progress, 106 (10), pp. 22–28 (Oct. 2010).


Freemer, G., “Measuring Temperature by Indirect Means,” Chem. Eng. Progress, 107 (11), pp. 24–27 (Nov. 2011).

Goulds Pumps (Phone: (315) 568-7874; Email: [email protected]uids.ittind. com). He has spent the last decade integrating technologies such as power electronics, embedded sensors, and wireless systems with rotating equipment to improve equipment reliability and reduce energy consumption. In collaboration with his team, he has helped numerous customers in the oil and gas industry to implement pumping and pump control systems. He holds three patents or patents pending in technology related to improving pump reliability. Kernan obtained his BS in mechanical engineering from the Univ. of Rochester.


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