column instrumentation basics

Instrumentation is critical to un-derstanding and troubleshooting all processes. Very few engineers specialize in this field, and many

learn about instrumentation through experience, myth and rumor. A good understanding of the various types of instrumentation used on columns is a valuable tool for engineers when evalu-ating column performance, starting up new towers or troubleshooting any type of problem. This article gives an over-view of the common types of instru-ments used for pressure, differential pressure, level, temperature and flow. A discussion of their accuracy, common installation problems and troubleshoot-ing examples are also included.

The purpose of this article is to pro-vide some basic information regarding the common types of instrumentation found on distillation towers so that process engineers and designers can do their jobs more effectively.

Introduction Anyone trying to complete a simple mass balance around a column under-stands that process data contain some error. Closing a mass balance within 10% using plant data is usually consid-ered very good. Generally, some values must be thrown out when matching a model to plant data. Understanding which measured plant data is likely to be most accurate is invaluable in making good decisions about a model of the plant, column performance and future designs.

The following is a real case and a telling example of how little the aver-age chemical engineer may understand about instrumentation. A process engi-neer with over 20 years of experience was doing a material balance around a distillation tower, illustrated in Figure

1. Based on the material balance, the engineer concluded that the bottoms flowrate must be in error and wrote a work order to have the flowmeter recalibrated. The instrument group disagreed heartily. By the end of this article, the reader will understand the instrument group’s response.

Pressure There are three common types of pres-sure transmitters: flush-mounted diaphragm transmitters, remote-seal diaphragm transmitters and impulse-line transmitters. All use a flexible disk, or diaphragm, as the measuring element. The deflection of the flexible disk is measured to infer pressure. The diaphragm can be made of many different materials of construction, but the disk is thin and there is little tolerance for corrosion. Coating of the diaphragm leads to error in the mea-surement. The instrument accuracy of all three types of pressure trans-mitters is similar, usually 0.1% of the span, or calibrated range.

Flush-mounted diaphragms These pressure transmitters are com-mon in low-temperature services, such

as in scrubbers and storage tanks. The process diaphragm, an integral part of the transmitter, is mounted on a nozzle directly on the vessel, and the transmitter is mounted directly on the nozzle.

Remote-seal diaphragm Used in higher temperature service when the electronics must be mounted away from the process, a flush-mounted diaphragm is installed on a nozzle at the process vessel. A capillary tube filled with hydraulic fluid connects the flush-mounted diaphragm to a second diaphragm, which is located at the re-motely mounted pressure transmitter. The hydraulic fluid must be appropri-ate for the process temperature and pressure. Hydraulic fluid leaks will lead to errors in measurement. Cali-bration is complex because the head from the hydraulic fluid must be con-sidered. The calibration changes if the transmitter is moved, the relative po-sition of the diaphragms changes or if the hydraulic fluid is changed.

Impulse-lineImpulse-line pressure transmitters can either be purged or non-purged.

Feature report

48 ChemiCal engineering www.Che.Com marCh 2008

Feature report

Ruth R. SandsDuPont Engineering Research & Technology

Column Instrumentation Basics

Figure 1. Which flowmeter is the most accurate? What is the source of error in the material balance?

Figure 2. Flush-mounted diaphragm pressure transmitters are common in low-temperature services

An understanding of instrumentation is valuable in evaluating and troubleshooting column performance

Purged impulse-line pressure trans-mitters measure purge-fluid pressure to infer the process pressure. Most commonly, the purge fluid is nitro-gen, but it can also be air or other clean fluids. The purge fluid is added to an impulse line of tubing to detect pressure at the desired point in the process. The purge fluid enters the process and must be compatible with it. Check valves are required to en-sure that process material does not back up into the purge-fluid header. The system must be designed so that the pressure drop through the im-pulse line is negligible. A pressure transmitter measures the purge-fluid pressure with a diaphragm to infer the process pressure.

Non-purged, impulse-lineRather than a purge fluid, this type of pressure transmitter uses process fluid. Usually, this style is chosen when the process is non-fouling or it is undesirable to add inerts to the process. One example is a situation where emissions from an overhead condenser vent must be minimized. An impulse line is connected from the desired measurement point in the process to a pressure transmitter, which measures the process pressure at the remote point. The system must be designed so that the pressure drop through the impulse line is negligible. The system designer must consider the safety implications of an impulse-line failure. The consequence of releas-ing hazardous material from a tubing failure may warrant the selection of a

different type of pressure transmitter. Adequate freeze protection on the im-pulse lines is also important to obtain accurate measurements. Example 1. A good example of a prob-lem with impulse-line pressure trans-mitters can be found in Kister’s Distil-lation Troubleshooting [2]. Case Study 25.3 (p. 354), contributed by Dave Simpson of Koch-Glitsch U.K., de-scribes three redundant impulse-line pressure transmitters used to mea-sure column head pressure. Following a tray retrofit, operating difficulties eventually led to suspicion of the head pressure readings. The impulse lines and pressure transmitters had been moved during the turnaround. The transmitters had been moved below the pressure taps on the vessel. Con-densate filled the impulse lines and caused a false high reading. Relocat-ing the transmitters to the original location above the nozzles solved the problem by allowing condensate to drain back into the tower.

Transmitters in vacuum servicePressure transmitters in vacuum ser-vice are generally the most problem-atic, leading to greater inaccuracy in the measured value. Damage to the diaphragm can occur from exceeding the maximum pressure rating of the instrument. Often, this happens on startup, or it can happen when per-forming a pressure test of the vessel. The diaphragm deflects permanently and introduces error.

Calibration of vacuum pressure transmitters is more difficult for in-

strument mechanics. The operating range must be clearly defined; for ex-ample, is the range 100-mm Hg vac-uum, 100-mm Hg absolute, or 650-mm Hg absolute? Using different measure-ment scales in the same plant is con-fusing, and it can make it very hard for mechanics to calibrate the pressure transmitters accurately.

Another issue is measuring the relief pressure. The system designer must consider the instrument ranges available and the accuracy of the measurement for the operating range versus the relief pressure range. It is good practice to install a second pres-sure transmitter on vacuum towers to measure the relief pressure. Example 2. An excellent example of calibration problems is illustrated in vacuum service in Reference [2]. Case Study 25.1 (p. 348), contributed by Dr. G. X. Chen of Fractionation Re-search, Inc., describes several years of troubleshooting a steam-jet system in an attempt to achieve 16-mm Hg absolute head pressure on a tower. It was eventually determined that the calibration of the top pressure trans-mitter was wrong, and they had been pulling deeper vacuum than they thought. The top pressure transmitter was calibrated using the local airport barometric pressure, which was nor-malized to sea-level pressure and was off by 28-mm Hg.

Differential pressure Differential pressure can be measured either with a differential pressure (dP) meter or by subtracting two pressure

ChemiCal engineering www.Che.Com marCh 2008 49

DEFINITIONS

Instrumentation rangeThe instrumentation range, the scale over which the instrument is capable of measuring, is built into the device by the manu-facturer. The purchaser defines the desired measured range, and the vendor should provide a device that is appropriate for the application.

Calibrated rangeThe calibrated range is the scale over which the instrument is set to measure at the plant. It is a subset of the instrument range. The calibration has a zero and a span. The zero is the minimum reading, while the span is the width of the calibrated range. The calibrated range will simply be referred to as the range at a plant site.

Instrument accuracy

Accuracy ErrorScale of Measurement

100%

The instrument accuracy is published by the manufacturer in the product documentation, which is easily obtained on-line. A few examples of how accuracy can be expressed are:

• Best-in-class performance with 0.025% accuracy• ±0.10% reference accuracy• ±0.065% of spanThese examples refer to the ideal instrument accuracy, which is only the accuracy of the measuring device itself. The total ac-curacy, on the other hand, includes the instrument accuracy plus all other factors that contribute to error in the measured reading as compared to the actual value. These other factors can include digital to analog conversions, density errors, piping configura-tions, calibration errors, vibration errors, plugging and more.

Turndown ratioThe ratio of the maximum to minimum accurate value is an impor-tant factor in considering the total accuracy of a measured value.

Turndown ratio imum accurate valueimu

=maxmin mm accurate value

For example, an instrument with 100:1 turndown and 0–100- psi instrument range would have the stated instrument accuracy down to 1 psi. Below 1 psi, the instrument might read, but it will have greater inaccuracy. ❏

measurements. Subtracting two pres-sure readings is not always accurate enough to obtain a meaningful mea-surement, so it is important to consider the span of the anticipated measured readings. If the dP is a substantial frac-tion of the top pressure, then it is okay to subtract the readings of two pres-sure transmitters. However, if the dP is a small fraction of the top pressure, then it will be within the instrument error of the pressure transmitter.

For example, a column at a plant runs at 30 psia top pressure. The expected dP is 2-in. H2O over a few trays. The in-strument error for a 0–50 psi pressure transmitter is 1.4-in. H2O. The mea-surement is within the accuracy of the pressure transmitters, and a dP meter is the appropriate meter to obtain an accurate measurement. The downside of dP meters is that very long impulse lines are required on tall towers.

LeveL Level and flow are the hardest basic things to measure on a distillation tower. Kister reports that tower base level and reboiler return problems rank second in the top ten tower mal-functions, citing that “Half of the case studies reported were liquid levels ris-ing above the reboiler return inlet or the bottom gas feed. Faulty level mea-surement or control tops the causes of these high levels...Results in tower flooding, instability, and poor separa-tion...Vapor slugging through the liq-uid also caused tray or packing uplift and damage.” (Reference 2, p. 145)

One of the main reasons for faulty level indications is that dP me-

ters are the most common type of level instrument, and an accurate density is required to convert the dP reading to a level reading. In many cases, froth in the liquid level de-creases the actual density and causes faulty readings. Changes in composi-tion or the introduction of a different process feed with a different density are cited several times as reasons for level measurement problems. Plug-ging of impulse lines and equipment arrangements that make accurate readings impossible are also very common problems.

Differential pressure transmitters are the most common type of level transmitter. The accuracy of the in-strument is quite good, at 0.1% of span (calibrated range). Any type of dP meter can be used: flush-mounted diaphragms, remote-seal diaphragms, purged impulse-line, or non-purged impulse-line pressure transmitters. The level measurement is dependent on the density of the fluid: P

height of liquidl

ft,

An accurate density is required for calibration. Changes in composition or the introduction of a process feed with a different density will cause errone-ous readings. Level transmitters suf-fer from the same problems that occur in pressure transmitters. Hydraulic fluid leaks, compatibility of the hy-draulic fluid, damage to diaphragms, and plugging or freezing of impulse lines are just a few of the problems that can be encountered with dP level transmitters.

Example 1. A column in a high-tem-perature, fouling service began to ex-perience high pressure drop, and the plant engineers were concerned that they were flooding the column. Calcu-lations showed that the tower should not be flooding if the trays were not damaged. Downcomer flooding was a possibility if the cartridge trays had become dislodged and reduced the downcomer clearance. The tower was taken down, and internal inspection revealed no damage to the internals. It was determined that a false low level caused the bottoms flow control-ler to close. This raised the level in the tower above the reboiler return line and above the lower column pressure tap. The column dP meter was reading the height of liquid above the lower-column pressure tap. Consultation with the instrument manufacturer revealed that the remote, seal hydrau-lic fluid was not appropriate for the high temperature of the process. The hydraulic fluid was boiling in the cap-illary tubes and had deformed the dia-phragm, which was also coated from the fouling service. The level transmit-ter was switched to a periodic, purged impulse-line dP meter. An automated high-flow nitrogen purge prevents ac-cumulation of the solids in the impulse lines and is done once per shift. Logic was added to the control loop to main-tain the previous level reading during the short nitrogen purge, a method that has eliminated the problem with the level.Example 2. Another common ex-ample of a level transmitter failure is based on the fact that equipment is designed in such a way that an ac-curate level reading can never be ob-tained. Though this may be surpris-

Feature report


Figure 3. (left) Remote-seal diaphragm pressure transmitters are used in high-temperature service

Figure 4. (above) Location of reboiler return nozzle does not

allow for accurate level reading

Figure 6. Non-contact radar level transmitters generate waves that are reflected from the surface of the level back to the transmitter

Figure 5. Nuclear level transmit-ters are non-contact devices

ing, it is mentioned in Ref. [3], Case Study 8.4 (p. 149), as illustrated in Figure 4. A column that was being retrofitted was originally designed so that the reboiler return was intro-duced directly between the two liq-uid-level taps. The level in the tower could never be accurately measured, and it was modified on the retrofit to rectify this situation.

Nuclear level transmitters Common in polymer, slurry and highly corrosive or fouling services, these instruments work by placing a radioactive source on one side of the vessel and a detector on the other side. The amount of radiation reaching the detector depends on how much mate-rial is inside the vessel. A strip source and strip detector are more accurate than a single source, strip detector. A sketch of a single source, strip detector is shown in Figure 5. The advantage of nuclear level transmitters is that they are non-contact devices, making them ideal for services where the pro-cess fluid would coat or damage other types of level instruments.

Nuclear level transmitters are more expensive than other level devices. They also require permits and a radia-tion safety officer, so they are often only used as a last resort. The instrument accuracy is generally ±1% of span. The total accuracy depends on how well the system was understood by the designer and installer. The thickness of the ves-sel walls and any other metal protru-sions in the measuring range, such as baffles, must be taken into account in the calibration, along with the correct rate of decay of the source. Build-up of solids in the measuring range will also result in error.

Radar level transmitters This type of level transmit-ter has been used in the chemical processing in-dustries (CPI) for the last 30 years. They demonstrate high ac-curacy on oil tankers and have been used frequently in storage-tank appli-cations. Radar level transmitters are now being applied to distillation tow-ers but are still more commonly found on auxiliary equipment, like reflux tanks. There are contact and non-con-tact types of radar level instruments.

A non-contact, radar level transmit-ter generates an electromagnetic wave from above the level being measured. The wave hits the surface of the level and is partially reflected to the instru-ment. The distance to the surface is calculated by measuring the time of flight, which is the time it takes for the reflected signal to reach the transmit-ter. Some things that cause inaccuracy with non-contact radar are: size of the cone, heaving foaming, turbulence, deposits on the antenna, and varying dielectric constants caused by changes in composition or service. The instru-ment accuracy is reported as ±5 mm.

Contact radar sends an electromag-netic pulse down a wire to the vapor-liquid interface. A sudden change in the dielectric constant between the vapor and the liquid causes some of the signal to be reflected to the trans-mitter. The time of flight of the re-flected signal determines the level.

Guided wave radar can be used for services where the dielectric constant changes, but is not a good fit for fouling services. A bridle (Figure 7), is used on distillation towers to reduce turbulence and foaming and therefore increases

the accuracy of the measurement. In-strument accuracy is ±0.1% of span. Example 3. A reflux tank on a batch distillation tower had a non-contact radar level transmitter. The tower stepped through a series of water washes, solvent washes, and process cuts. The reflux-tank level transmit-ter gave false high readings during the solvent wash cycle, which used tolu-ene. The reflux pumps would always gas off during this part of the process. The dielectric constants of the various fluids in the reflux tank, of which tolu-ene had the lowest dielectric constant, varied ten times during the cycle, af-fecting the height of liquid able to be measured. Larger antennas focus the signal more and give greater signal strength. As the dielectric constant de-creases, a larger antenna is required to measure the same height of fluid. The level transmitter used in this service was not appropriate for all measured fluids and could not accurately mea-sure the liquid level when the reflux drum was inventoried with toluene.

TemPeraTure There are two common types of tem-perature transmitters in distillation service — thermocouples and Resis-tive Temperature Devices (RTDs). Both are installed in thermowells. Thermocouples. The most popular temperature transmitter, thermocou-ples, consist of two wires of dissimilar metals connected at one end. An elec-tric potential is generated when there


Figure 9. For vapor or gas applica-tions, orifice flowme-ters require tempera-ture and pressure compensation

Figure 8. Resis-tive temperature de-tectors respond to a temperature change with a change in resistance

Figure 7. Guided wave radar level transmitter on a distillation tower level [5]

is a temperature delta between the joined end and the reference junction. Type J thermocouples, made of iron and Constantine, are commonly used in the CPI for measuring tempera-tures under 1,000°C.

RTDsThe second most-common type of tem-perature transmitter, RTDs consist of a metal wire or fiber that responds to a temperature change by changing its resistance. Though RTDs are less rugged than thermocouples, they are also more accurate. Typically, they are made of platinum. The instrument accuracy of thermcouples and RTDs is very good in both. However, ther-mocouples have a higher error than RTDs. The total accuracy of a thermo-couple is 1–2°C. There is greater error due to calibration errors and cold-ref-erence junction error.

It is important to note that, with temperature transmitters, there is a lag in the dynamic response to changes in process temperatures. All temperature measurements have a slow response, because the mass of the thermowell must change in tem-perature before the thermocouple or RTD can see the change. The lag time will depend on the thickness of the thermowell and on the installation. The thermocouple and RTD must be touching the tip of the thermowell for best performance. If there is an air gap between the thermowell and the measuring device, the heat-transfer resistance of the air will add substan-tially to the lag time, which is also why temperature transmitters work better in liquid service. The response time for temperature transmitters in liquid service is between 1–10 s, whereas the response time for tem-perature transmitters in vapor service is about 30 s. Heat-transfer paste is a thermally conductive silicone grease; it has been used with success in some plants to improve the response time of temperature transmitters. Example. The plant in this example experienced a temperature lag prob-lem. A thermocouple near the bottom of a large tower controlled the steam to the reboiler. The temperature con-trol point had a 10-min delayed re-sponse to changes in steam flowrate.

The rest of the column responded to the change in boilup in about 3 min. The lag in the control point caused cycling of the steam flowrate and cre-ated an unstable control loop. The cause was determined to be a thermo-couple that was too short for its ther-mowell. Normally, thermocouples are spring-loaded to ensure that the tip is touching the end of the thermow-ell, but the instrument mechanics had installed a thermocouple of the wrong length because they lacked the proper replacement part. The poor heat transfer through the air gap between the end of the thermocouple and the thermowell caused the delay in tem-perature response. Replacing the in-stalled thermocouple with one of the proper length fixed the problem.

FLow There are many different types of flowmeters. Here, the types commonly used in plants will be discussed: orifice plates, vortex shedding meters, mag-netic flowmeters and mass flowmeters.

Orifice plates Orifice plates are the most common type of industrial flowmeter. They are inexpensive, but they also have the greatest error of all the common types of flowmeters. Orifice plates measure volumetric flowrate according to the following equation:

Q C P1

2

Q is the volumetric flowrate, C is a con-stant, ∆P is the pressure drop across the orifice, and ρ is the fluid density. To obtain an accurate flowrate, an ac-curate fluid density must be known. Temperature and pressure compen-sation are required for vapor or gas applications and may be required for some liquids. Figure 9 shows the

equipment arrangement for an orifice flowmeter with temperature and pres-sure compensation.

Typical turndown for orifice plates is 10:1. Below 10% of span, the measure-ment is extremely erroneous because the volumetric flowrate is proportional to the square root of the ∆P. At 10% of span, the meter is only measuring 1% of the ∆P span (Figure 10).

Multiple meters can be used to overcome the turndown ratio when high accuracy is required over the entire span. This is often worth the effort when measuring the flowrate of raw materials or final products. At one plant, three orifice plates in par-allel were used to measure the plant-boundary steam flowrate due to the large span and the accuracy required at the low end of the range. This re-sulted in a very complicated system.

There are many common problems that lead to error in the orifice plate measurement, including inaccurate density, impulse-line problems, erosion of the orifice plate, and an inadequate number of pipe diameters upstream and downstream of the orifice plate.

An accurate density is required to obtain an accurate flowrate. In a plant that has a process feed that varies from as low as 12% to as high as 30% water, the density changes signifi-cantly, and therefore an orifice meter will not provide an accurate reading without density compensation.

Impulse line problems include plugging, freezing due to loss of elec-tric heat tracing, and leaking. Con-densate filling the impulse lines in vapor/gas service and gas bubbles in the impulse lines in liquid service are also commonly cited. Figure 11 shows a pipe just upstream of an ori-fice that was in “clean” water service for two years. There was a filter just upstream of this section of pipe. The

Feature report


Figure 10. Volumetric flowrate is proportional to the square root of the ∆P, causing high error at less than 10% of span

Figure 11. Due to impulse line problems, this "clean" ser-vice did not meet standards

impulse lines to the orifice plate flow-meter were completely plugged. This section of pipe was removed and a Teflon-lined magnetic flowmeter was installed instead.

Orifice plates can erode, especially in vapor service with some entrained liquid. This is common in steam ser-vice, and orifice plates should be checked every three years for wear.

Orifice plates generally need 20 pipe diameters upstream and 10 pipe diameters downstream of the orifice plate for the velocity profile to fully develop for predictable pressure-drop measurement. This requirement var-ies with the orifice type and the piping arrangement. This is rarely achieved in a plant, which introduces error in the measurement.

The instrument accuracy of orifice plates ranges from ±0.75–2% of the measured volumetric flowrate. Vari-ous problems are encountered with orifice plate installations, and they have the highest error of all flowme-ters. “Orifice plates are, however, quite sensitive to a variety of error-induc-ing conditions. Precision in the bore calculations, the quality of the instal-lation, and the condition of the plate itself determine total performance. Installation factors include tap loca-tion and condition, condition of the process pipe, adequacy of straight pipe runs, gasket interference, mis-alignment of pipe and orifice bores, and lead line design. Other adverse conditions include the dulling of the sharp edge or nicks caused by corro-sion or erosion, warpage of the plate due to water hammer and dirt, and grease or secondary phase deposits on either orifice surface. Any of the above conditions can change the ori-fice discharge coefficient by as much as 10%. In combination, these prob-lems can be even more worrisome and

the net effect unpredictable. There-fore, under average operating condi-tions, a typical orifice installation can be expected to have an overall inac-curacy in the range of 2 to 5% AR (ac-tual reading)” [6].

Vortex shedding meters Vortex shedding meters contain a bluff body, or a shedder bar, that cre-ates vortices downstream of the object when a fluid flows past it. The meters utilize the principle that the frequency of vortex generation is proportional to the velocity of the fluid. The whis-tling sound that wind makes blowing through tree branches demonstrates the same phenomenon.

The fluid’s density and viscosity are used to set a “k” factor, which is used to calculate the fluid velocity from the frequency measurement. The fre-quency, or vibration, sensor can either be internal or external to the shedder bar. The velocity of the fluid is con-verted to a mass flowrate using the fluid density. Therefore, accurate fluid density is important for accurate mea-surements. Vortex meters work well both in liquid and gas service. They are commonly used in steam service because they can handle high tem-peratures. They are available in many different materials of construction and can be used in corrosive service.

Vortex meters have lower pressure drop and higher accuracy than orifice plates. A minimum Reynolds num-ber (Remin) is required to achieve the manufacturer’s stated accuracy. Vortex meters exhibit non-linear operation as they transition from turbulent to laminar flow. Typical accuracy above the Remin is 0.65–1.5% of the actual reading. In general, the meter size must be smaller than the piping size to stay above the Remin throughout the desired span. The requirements

for straight runs of pipe upstream and downstream of the meter vary, but both are usually longer than for orifice plates. In general, 30 pipe diameters are required upstream and 15 pipe diameters downstream. The upstream and downstream piping must be the same size pipe as the meter.

There are only a few problems com-monly encountered with vortex me-ters. Older models may be sensitive to building vibrations, but newer models have overcome this issue. If the shed-der bar becomes coated or fouled, the internal vibration sensor will cease to work. This can be avoided by using an external vibration sensor. The most common issue is failing to meet the Remin requirements over the desired span. At one plant, every vortex meter was line-sized, which means it was the same size as the surrounding pip-ing. The flow went into the laminar region in the desired measured range in every case. The flow read zero when it transitions to laminar, making the meters useless.Example. Another good example of failing to meet the Remin require-ments over the desired span hap-pened on a project where a tower that had been out of service for some time was recommissioned. The distillate flowrate was substantially lower than the original tower design and was in the laminar flow region over the en-tire operating range. The distillate flow was a major control point on the tower, but the vortex meter could not read the flowrate. The control strat-egy had to be changed to work around this issue until an appropriate meter could be installed.

Magnetic flowmeters Faraday’s law states that the voltage induced across any conductor as it moves at right angles through a mag-


Figure 12. Vortex meters contain a shedder bar that creates vortices down-stream when fluid flows past it (left). Depending on the application and pipe size, vortex shedding meters are available in a range of sizes and shapes (right)

Figure 13. The magnetic flowmeter prin-ciple states that the voltage induced across a conductor as it moves at right angles through a magnetic field is proportional to its velocity.

netic field is proportional to the velocity of that conductor. This is the principle used to measure velocity in magnetic flowmeters, which are commonly referenced to as mag meters (Figure 13).

Mag flowmeters measure the volumetric flowrate of conduc-tive liquids. Fluids like pure organics or deionized water do not have a high enough conduc-tivity for a mag meter. An ac-curate density is required to convert the volumetric flowrate to a mass flowrate. The meters are line-sized, but they have a minimum and maxi-mum velocity to achieve the stated instrument accuracy. A smaller line size may be necessary to achieve the velocity requirements throughout the desired span. The instrument accuracy is quite good, generally at ±0.5% of the actual reading. The error is very high below the mini-mum velocity. Turndown for newer mag meters is 30:1, but older models will be closer to 10:1.

Mag meters do not have a lot of op-erating problems. They must be liq-uid-full to get an accurate reading and are often placed in vertical piping to achieve this. They rarely plug as they can be specified with Teflon liners and are often used in slurry service. Mag flowmeters are more expensive to install because they usually require 110-V power.

Mass flowmeters Mass flowmeters use the Coriolis effect to measure mass flowrate and density. A very small oscillating force is applied to the meter’s flowtube, perpendicular to the direction of the flowing fluid. The oscillations cause Coriolis forces in the fluid, which deform or twist the flow-tube. Sensors at the inlet and outlet of the flowtube measure the change in the geometry of the flowtube, which is used to calculate the mass flowrate. The os-cillation frequency is used to measure the fluid’s density. The temperature of the fluid is measured to compensate for thermal influences and can be chosen as an output of the meter.

The original mass meters were U-tubes, but several different shapes are now available, including straight tubes as shown in Figure 14. Mass

flowmeters have the highest ac-curacy of all the different types of flowmeters, usually ±0.1–0.4% of the actual reading. The measurement is independent of the fluid’s physical properties, making mass flowmeters unique in that most flowmeters re-quire the fluid density as an input. Mass flowmeters are insensitive to upstream and downstream pipe con-figurations. Practical turndown is 100:1, although the manufacturers claim 1,000:1. The density measure-ment is not as accurate as a density meter. Mass flowmeters are gener-ally very reliable and only require periodic calibration to zero them.

Mass flowmeters are on the expen-sive end to purchase and to install. They require 110-V power. Pressure drop can sometimes be an issue, and the meters are only available in line sizes up to 6 in. Coating of the inside of the flowtube will result in higher pressure drop and can result in loss of range and accuracy if the tube is re-stricted. Wear and corrosion can result in a gradual change of the mechanical characteristics of the tube, resulting in error. Zero stability was an issue with older meters but this problem has been solved in newer units. Example 1. The reflux flowrate on a final product column was an im-portant measurement, and the reli-ability of the existing flowmeter was questioned. Product literature for mass flowmeters promised high ac-curacy and low pressure drop. The plant-area engineer coordinated a small project to replace the existing orifice plate flowmeter with a mass flowmeter. Column performance was very poor after startup. The new meter had to be bypassed to operate the column normally. The overhead condenser was gravity drained, and

the new mass flowmeter had enough additional pressure drop to force the liquid level into the condenser tubes and restrict rates — an expensive les-son for a new engineer.Example 2. Another tower had a mass flowmeter installed on the bot-toms flow, which was pumped but not cooled. The mass flowmeter al-ways had erratic readings and was never believed. A closer examination of the system revealed enough pres-sure drop through the mass flowme-ter to result in flashing in the flow-tube. The two-phase flow caused the erratic readings.

Epilogue With a knowledge of the basics of column instrumentation, the ques-tion posed in the introduction should seem trivial. Our experienced en-gineer had concluded that the bot-toms flowrate of the column had to be erroneous, but the instrument group had disagreed. The flowmeter in question was a mass flowmeter in relatively clean and non-corrosive service. The other three flowmeters on the column were orifice plates and are known to have a myriad of problems that introduce error.

Summary Some basic knowledge of instrumen-tation can be a very valuable trouble-shooting and design tool. Gauging whether an instrument installation will ever give accurate readings or whether it is an expensive spool piece is useful in itself. Being able to assess the relative accuracy of two measure-ments will help determine from which data to draw conclusions. Knowledge of common instrument problems can help in troubleshooting.

Get to know the instrumentation

Feature report


Figure 14. Mass flowmeters use the Coriolis effect to infer mass flowrate from the mea-surement of flowtube deflection

on your towers. Gather the manufac-turer’s information so you can assess the instrument accuracy. Keep in mind that the manufacturer’s litera-ture refers to the ideal instrument accuracy, which is the accuracy of the measuring device itself. There are many other factors that contribute to the accuracy of the reading that is displayed on the DCS screen or in the data historian. The total accuracy in-cludes the instrument accuracy plus all of the other things that contribute to error in the measured reading as compared to the actual value. Other inaccuracies lie in digital to analog conversions, density errors, piping configurations, calibration errors, vi-bration errors, and the list goes on and on. Check the field installation to see what types of problems your meters will experience.

Get to know your mechanics and in-strumentation experts at your plant. Now that you know some of the lingo of instrumentation, you can better converse with your instrument engi-neers and mechanics.

AcknowledgementsThis paper is a compilation of in-strumentation basics obtained from the references listed below, of trou-bleshooting experience from many colleagues at DuPont, and of trou-bleshooting examples from Henry Kister’s most recent book, Distilla-tion Troubleshooting. Much of the technical information and many of the examples come from Nick Sands, Process Control Leader for DuPont Chemical Solutions Enterprise in Deepwater, N.J. Nick has worked for DuPont for 17 years and is a special-ist in process control. In addition

to Nick, the following DuPont col-leagues contributed their instrument war stories, and the author is grate-ful for their willingness to share their experiences: • Jim England, DuPont Electronic

Technologies (Circleville, Ohio) • Charles Orrock, DuPont Advanced

Fibers Systems (Richmond, Va.)• Adrienne Ashley, DuPont Advanced

Fibers Systems (Richmond, Va.) • Joe Flowers, DuPont Engineering

Research & Technology (Wilming-ton, Del.)

References1. Gillum, Donald R., Industrial Pressure,

Level and Density Measurement. Resources for Measurement and Control Series. ISA, 1995.

2. Kister, Henry Z., “Distillation Troubleshoot-ing,” John Wiley & Sons, 2006.

3. Spitzer, David W., Industrial Flow Measure-ment. Resources for Measurement and Con-trol Series. ISA, 1990

4. Trevathan, V. L., editor. A Guide to the Auto-mation Body of Knowledge. ISA, 2006.

5. emersonprocess.com/rosemount6. omega.com7. efunda.com8. us.endress.com9. spiraxsarco.com

Figure 15. With an under-standing of the accuracies of mass flowmeters and orifice

flowmeters, we revisit the question — Which flowmeter

is the most accurate?

AuthorRuth Sands is a senior con-sulting engineer for DuPont Engineering Research & Technology (Heat, Mass & Momentum Transfer Group, 1007 Market St., B8218, Wilmington, DE 19898; Phone: 302-774-0016; Fax: 302-774-2457; Email: [email protected]). She has specialized for the last nine years in mass transfer unit

operations: distillation, extraction, absorption, adsorption, and ion exchange. Her activities include new designs and retrofits, pilot plant testing, evaluation of flowsheet alternatives, and troubleshooting. She has 17 years of experience with DuPont, which includes assignments in process engineering, manufacturing, and corpo-rate recruiting. She holds a B.S.Ch.E. from West Virginia University, is a registered professional engineer in the state of Delaware, and is a mem-ber of the FRI Executive Committee.

MICROFILTRATION

ULTRAF I LTRAT ION

N A N O F I LT R AT I O N

WWW.MICRODYN-NADIR.COM

Hav

e a

bat

h w

ith

a f

rien

d

LEIPZIG 14. - 18. APRIL

STAND G9

IFAT MUNICH

5. - 9. MAY

HALL A2

STAND 303

MICRODYNTECHNOLOGIES INCP. O. Box 98269Raleigh, NC. 27624Phone 001 - 919 - [email protected]

56x254_biocel_messe_usa_rz.indd 1 07.02.2008 15:36:39 Uhr

Circle 31 on p. 76 or go to adlinks.che.com/7370-31

column instrumentation basics

Documents