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October 2014

State of Technology Report

Flow & Level
The Latest Technology Trends, Back-to-Basics
Tutorials, and Application Stories—All Together
in One Convenient eBook

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TDR Radar

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Table of Contents
Flow and Level Measurement Still a Subtle Engineering Task


Trends in Technology
Prevent Tank Farm Overfill Hazards


Advances in Flow Instrumentation


Adaptive Level Control


The Incredible Fiber-Optic Flowmeter


Level Reaches New Heights


Flow Charts New Waters


Back to the Basics
Beginner’s Guide to Differential Pressure Level Transmitters


Back to the Basics: Magnetic Flowmeters


The Right Tool for Tricky Measurement Jobs


Bidirectional Flow Measurement


Back to Basics: Ultrasonic Continuous Level Measurement


Stick It!


The Lowdown on Radar Level Measurement


Technology in Action
Saving Steam Saves Money


Radar Technology for Level Measurement


Ultrasonic Flowmeters Make Chiller Control Easier


Water Is Money. Accuracy Matters

3 1-800-FOR-LEVEL . excellent support. Accurate. VEGAPULS Through-air Radar Technology for Continuous Level Measurement ▪ Maintenance-free operation offers a simple solution for continuous level measurement of bulk solids ▪ Highly sensitive electronics filter out false signals from dust.vega-americas. Reliable. and buildup ▪ Combination of speed. and reliable performance ensures VEGA is the right partner for your level measurement needs @vega_americas www. Emerson .com Vega Americas 4 ABB 23 Siemens 26 www.Rosemount 8 Moore Industries 30 Kobold Instruments 34 Lumenite 29 5 Orion Instruments 6 Sierra Instruments 17 FCI 13 Lumenite 16 Precision Digital 39 www.lumenite.Advertiser Index Krohne 2 www.

personnel safety. . 4 #1 Magnetic Level Indicator & Magnetostrictive Level Transmitter The readers of Control Magazine have preferred Orion Instruments for 6 consecutive years. (60 m) 140° viewing angle www. and reliability can all be improved over traditional sight glass gauges.orioninstruments.a better way to view LEVEL 316 SS Construction IP66/68 + 200 ft. Contact us to find out how maintenance frequency. cost of High-visibility level indicators from Orion Instruments are custom-engineered and built tough for the most demanding applications.

Here. this non-mechanical trend is indicated by the increased use of radar. And while it doesn’t cover every corner of the application space. is an increasingly popular technology that falls into that category of minimal moving parts: only the float is free to move along a waveguide probe. For example. remain an imporant option for a specialized range of gas measurement applications. And while more of today’s users pay at least lip service to lifecycle costs. Guided-wave radar. back-to-basics tutorials. users continue to move away from mechanical and electromechanical instruments towar electronic transmitters with few or no moving parts to stick or wear. Sure. The continued preference for differential pressure flowmeters and level gauges. the differential pressure transmitter remains the most commonly applied flow and level measurement device—in no small part because engineers are so familiar with it. too. —The Editors 7 . electromagnetic. Fiber optic probes developed for undersea oil and gas applications are measuring flowrate and composition with temperature and pressure to boot. but play second fiddle to technology familiarity and trouble-free operation in others. specifying a flowmeter or level gauge that will reliably perform over the anticipated range of process conditions often remains a complex and subtle engineering task. we hope you find it useful. But the number one flow and level measurement technology actually measures neither. Dozens of niche instrumentation technologies have been developed over the past several decades to exploit nearly every conceivable physical phenomenon that might be correlated with level or flow. Hence the growing popularity of Coriolis. initial purchase price remains a key consideration. differentiated technology plays a role in establishing the independence of safety protection layers. The balance of this State of Technology Report is a compendium of the latest trends articles. and well as the ongoing viability of numerous niche technologies. On the level measurement side. Thermal dispersion mass flowmeters. Indeed. D espite ongoing advances in instrumentation technology. vortex and ultrasonic flowmeters in recent years. ultrasonic and even sonic profiling gauges that offer a three-dimensional view of solids level in tanks and bins. a differential pressure cell paired with an orifice plate or other primary element can make for a relatively complicated installation (although pre-integrated assemblies are making this less troublesome) as well as incur an energy-consuming pressure drop penalty. and application stories recently published in the pages of Control. despite the overall trend toward non-mechanical instruments for process measurements. Accuracy and other desirable performance specifications are of overriding importance in some applications. too. A mechanical switch or magnetic level indicator provides assurance against common cause failures when used in conjunction with an electronic gauge. familiarity and trouble-free operation often trump technical specifications when specifying flowmeters and level gauges. Dramatic advances in ultrasonic technology in particular have spiked their broader use even in gas custody transfer applications.Flow and Level Measurement Still a Subtle Engineering Task All other things equal. but for many users the dependability and familiarity of a differential pressure cell still wins out over other considerations. demonstrate the complex interplay of criteria that go into a instrumentation purchase decision. Our reader surveys indicate that where possible and practical. there exists a countervailing trend in favor of mechnical devices for safety applications such as pump protection or tank overfill prevention.

you can gather more detailed insights into the health of your entire process without adding infrastructure. see case studies at Rosemount. accurate instruments to minimize measurement drift and confidently run your facility as close as possible to critical levels. And with intuitive diagnostic tools and wireless transmitters. The Emerson logo is a trademark and a service mark of Emerson Electric Co. © 2013 Emerson Electric Co. I need to get more out of my assets so I can meet my performance goals. maintain a smarter workflow and operate at your full ® View video with our take on efficiency.I get measured on hitting my production targets. . To learn how Emerson can help you hit your production targets and maximize the capacity of your assets with measurement instrumentation. Our specialists will show you how to use stable. Turn to Emerson measurement experts and Rosemount instrumentation to get more production out of your current equipment. so you can stay optimized longer and avoid downtime. YOU CAN DO THAT Discover new efficiencies and achieve unmatched throughput with Rosemount instrumentation.

2009. All these involved spectacular explosions and fires with extensive damage to the facility. Puerto Rico. PE D explosion may not be considered common.). 2005. emptying and transferring operations go on each month in these tank farms— maybe even every day. As it turns but where supervision is typically more relaxed. in 2005 (43 injured). UK. at the Buncefield oil storage and transfer depot. It’s safe to say that thousands of filing. Another tank farm overfill also occurred in Kuwait. Process unit tank farms are typically a bit separate from the process units. p. as can some plant tank farms. intermediates and final products.” James Changa and Cheng-Chung Lin. 23. injuring three and resulting in the Caribbean Petroleum Corp. Puerto Rico.” Presentation for HSE Moments/Alerts. Journal of Loss Prevention in the Process Industries. bullets and spheroids. by William L. which have led in a few cases to major incidents. One interesting fact that arose while looking at overfill incidents is that they mostly occurred off day shift. and spread over a large acreage. in 1999 (seven dead). leading to an unconfined vapor cloud explosion that was deemed to be unprecedented—the largest ever explosion in peacetime Europe. Data compiled by a reputable operator in the United States estimated that an overfill occurred once in every 3. which commonly straddle pipelines. but some result in overfills. A gasoline tank overflowed. no fatalities occurred. another large overfill event led to a fire and explosion at the Cataño oil refinery in Bayamón. Thailand. but plant expansions have sometimes met external industrial and residential sprawl to increase the potential consequences of a disastrous event. Fifteen overfill incidents were reported. located in bunds or diked areas. having to file for bankruptcy. and the Cataño oil refinery in Bayamón. bit. Fuel distribution terminals. many of these tanks are used for what are called oil movements. Hemel Hempstead. On Oct. Had the 6:01 a. riving around petrochemical plants. For refineries. for while the damage was extensive. The numbers of tank farm overfill incidents were probably under reported in this study. What really brought tank farm overfills to the forefront was an industry-changing incident that occurred on Dec. Buncefield.Trends in Technology Prevent Tank Farm Overfill Hazards Catastrophic incidents have led to useful rules for systems that help avoid them. Looking over the past couple of decades. (three injured). tank farm overfill incidents in the study occurred on average every three years. it’s common to see large tank farms with vessels of various forms and shapes— cylinders. Marsh Ltd. UK.” Risk Engineering Position Paper 01.51–59). far worse. which blend various products together to provide the many grades of gasoline. we have had some notable tank overfill incidents: Laem Chabang. resulting in a fire and explosion (“Overfill + Ignition = Tank Farm Fire. blast happened during working hours on a weekday.300 filling operations (“Atmospheric Storage Tanks. 11. However. It was fortunate that the explosion occurred in the early morning hours on the weekend. Many of these tank farms started out as remote sites. which is very advantageous in regard to people occupancy/exposure. The overwhelming majority are done safely. spheres. A study of storage tank accidents for the period of 1960-2003 covered 242 tank farm accidents. of which 13 resulted in a fire and explosion (“A Study of Storage Tank Accidents. are physically similar and may butt up against residential and light industrial areas. but they’re certainly not rare. tank farm overfills that lead to a fire and 9 .m. but still. oil fields or fuel distribution terminals or facilities. and there is less general oversight. 19 [2006]. Mostia. 43 people were injured. diesel and other refinery products required by the market and government regulations. These tanks can store feedstocks. it could have been far.

” many times they can suffer when maintenance budgets are was the practice of Buncefield operators “working to alarms.Trends in Technology While not due to an overfill event. Part 1 for SIL-related systems that come out of the risk assessment. Hemel Hempstead. reading (www. 02/11). but showing the potential consequences. In 2009. injured more than 200 and completely destroyed the tank farm.” which covers atmospheric tanks storing Class I (flammable) and Class II (combustible) petroleum poor testing practices.” Meanwhile.K. Kuwait also had a level gauge and independent high-level alarm—neither functioned. India.” Both API 2350-January 1996 and 2005 state that. Health and Safety Executive (HSE) required the competent authority and operators of Buncefield-type sites to develop and agree on a common methodology to determine safety integrity level (SIL) requirements for overfill prevention systems in line with the risk assessment principles in BS EN 61511. How do your operators really operate your tank farm transfers? The U. neither of which worked. Another interesting thing to come out of the Buncefield U. The resulting unconfined vapor cloud explosion was the largest ever in peacetime Europe.K. but poor operational discipline always seems to trump standards and procedures..K. “A Review of Layers of Protection Analysis (LOPA) Analyses of Overfill of Fuel Storage Tanks” and “Safety and Environmental Standards for Fuel Storage Sites. It seems there is a potential pattern: poor instrument maintenance. They should then apply the BS EN 61511. the U. after Buncefield. “High-level detectors and/or automatic shutdown/diversion systems on tanks containing Class I and Class II liquids (2005 only) shall not be used for control of routine tank fining operations. “Overfill Protection for Storage Tanks in Petroleum Facilities. Since tank farms do not “make money. The practice is not new in the process industries.” The 2012 version specifically prohibits this practice. the same year as 10 . overflowed. was issued in January 2005. issued a number of comprehensive reports and recommendations regarding Buncefield that are worthwhile Precipitating Event Figure 1: In December 2005 a gasoline tank at the Buncefield oil storage and transfer depot. Trust in the protection systems is a form of faithbased risk-taking founded on prior experience. Bad Practices The Buncefield tank that overflowed had both a level gauge and an independent high-level shutdown. particularly where there are automatic shutdowns protecting transfers into a tank or other process operations. API RP 2350 3rd Edition. “Buncefield: Why Did It Happen?” (COMAH.buncefieldinvestigation. the liquid level in the tank could not be determined because the facility’s computerized level monitoring system was not fully operational. the HSE issued the reports. on the west side of the Atlantic. htm under Reports). UK Government Poor Instrumentation. Part 3. U. and generally represents normalization of non-conformance to procedures resulting from poor or slack operating discipline. as it may be more common than one might think. lack of operational discipline—take your pick. Control of Major Accident Hazards (COMAH) report.K. a 2009 tank farm fire and explosion in Jaipur. In Puerto Rico. From a standards perspective. but may deserve more looking into. killed 12 people.

4. 2.01-2004 (IEC 61511 modified) must be Technology Can Help Placing instrumentation on widely geographically distributed tanks. reducing wiring costs. Tank farm remoteness and geographical distribution often make them suitable for wireless monitoring applications. can be a challenge both technically and in cost. Because of the Buncefield explosion. 4th Ed. For new installations. Profisafe. essentially prescriptive approach that contains aspects of ANSI/ISA 84. A overfill management system is required. 5. Foundation fieldbus. These followed. 3. particularly on existing tanks. ANSI/ISA 84. there were no requirements for level detectors on the tanks.  Emphasis on proof-testing of independent alarms and AOPS. the standard provides two options for implementation. but technology has advanced significantly in the past 10 years. wireless cellular networks and global satellite networks.11a and WirelessHART). The definition of a set of operating parameters. which can be easily added to existing tanks. There are wireless applications for tank monitoring systems available using IEEE 802. We can easily digitally transmit multiple sensor inputs across a pair of wires. including critical high level (CH).and performance-based requirements. ASIsafe).4 (ISA 100. not maximum. API 2350 had minimal requirements for safety instrumentation and no requirement for evaluation of the safety risk.00. the API 2350 4th Edition (2012) committee took the lessons learned to heart and introduced a number of new risk. to monitor tank levels. which brought it closer conformance to the SIS standards.. in addition to the control room operator. This highlights a cautionary note that one should always remember: All standards provide minimum requirements. high-high level (HH). while unattended facilities required continuous monitoring.and performance-based requirements.Trends in Technology Buncefield. From an instrumentation perspective. Operators are required to categorize each tank under consideration for overfill prevention based on tank level instrumentation and operator surveillance procedures. 6. Appendix A of the standard provides an acceptable. ly/1oRKeQZ ) should not be hijacked by “minimum” safety requirements in a standard. Available automated safety shutdown systems geared to the tank farm environment range from local. depending on whether the installation is existing or new. a number which are third party-approved safety protocols (for example. high-reliability shutdown systems connected by Modbus to centralized 11 . 2003) and IEC 61511 (2004) were in place at that time.”) Buncefield’s Legacy: New API 2350 Requirements Because of Buncefield.01-2004 (IEC 61511 modified). M  ore emphasis on operator response time for level alarms. Another developing technology is mobile wireless applications. alarms and an automatic shutdown if the operator response time was not adequate. The third edition of API 2350 was prescriptive in nature and a compilation of best practices that had over the years expanded its reach to these categories. A risk assessment shall be used by the owner and operator to categorize risks associated with potential tank overfills.15. bit. This standard divided facilities into attended and unattended operations. For existing installations. Some of API 2350’s new requirements are: 1. For attended facilities. When an AOPS is required. using any one of the more than 50 fieldbuses available. (2012) committee took the lessons learned to heart and introduced a number of new risk. (See sidebar. which allow tank farm field operators. the API 2350. even though ANSI/ISA S84 (1996. “Buncefield’s Legacy: API 2350’s New Requirements. maximum working level (MW) and automated overfill prevention system (AOPS) activation level. can also be solar-powered. particularly for cost reasons. Following good engineering practice and in most cases common sense (an old friend who some say has passed on. which brought it closer conformance to the SIS standards. or the operation was fully automatic.00.

since many of the gases involved are heavier than air. Fellow. the less the consequences will be. This technology could easily be applied to tank farms.01 (IEC 61511 modified).01-2004 (IEC 61511 modified). is a frequent contributor to Control. 12 . On June 10. pattern recognition and analytical technology to detect abnormal conditions in the facility. While this seems to be a case of reaction rather than prevention. But that is a discussion for another day. Spill Spotter Figure 2. and pointsource gas detectors can be effective inside bunds. which is virtually identical to IEC 61511. Improvements have been made in guided-wave radar (GWR). Alaska. and report them to the control room and field operators.” but do not be fooled. This API 2350 standard is listed as a “recommended practice. you will be held to this standard or the burden of proof otherwise. but can help prevent pool fires from spreading to other tanks by detecting rim fires and jet fires. SIS-TECH Solutions. Fire detectors are not as effective for overfill situations. One area that API 2350 does not address in tank farms is the use of combustible gas detectors and fire detectors. Chemical plants should meet NFPA 30. On June 10. Heed API 2350 API 2350 has been updated to be better in line with the industry standard ANSI/ISA 84. supplied by Aerovironment Inc. environmental and/ or financial incident does not occur in the future. In the United States and in other countries that recognize API standards as recommended and generally accepted good engineering practice (RAGAGEP). at its Prudhoe Bay.avinc. at its Prudhoe Bay. Tank level and inventory management system technologies also have advanced. the sooner you can act to bring an developing incident to heel. site to fly aerial surveys over Alaska’s North Slope. (www. Mostia. It would seem important to minimize the potential of an electrical ignition source by properly. which obviously can create a hazard. It seems like a reasonable prediction that in the not-too-distant future. Open-path gas detectors could be particularly effective. One of the main issues remains. electrically classifying tank farm areas and ensuring that electrical equipment and instrumentation meet (and maintain) the classification. supplied by Aerovironment Inc. (www. To make our tank farms safe. which by some estimation can range up there with a hydrofluoric acid leak hazard in a refinery.00. Alaska. we should apply the same safety rigor of assessment that we apply to our process units to our tank farms to ensure that a significant safety.00. One of the biggest hazards in a refinery tank farm typically comes from butane or other compressed gas spheres. drones could be used to fly continuous circuits above a refinery or chemical plant.avinc. site to fly aerial surveys over Alaska’s North Slope. the FAA authorized BP to use a commercial drone. they can have a path length up to 200 The same type of drone has been used in test flights by ConocoPhillips. as William L.Trends in Technology BP systems to using safety PLCs. even if you can’t prevent it. which is how to proof-test these to meet API 2350 and ANSI/ISA 84. through-the-air radar and traditional level measurement technologies. use visual and IR sensors. This discussion only covered atmospheric tanks in tank farms. if you have an incident in your refinery or fuel distribution tank farm. but may also be held to API 2350 overfill requirements as RAGAGEP. the FAA authorized BP to use a commercial drone.

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if we wanted to keep the total error at minimum flow under 3%AR.25% to 0. self diagnostics.000). Naturally. allowing the sensor to be located in hard-to-access areas. Therefore. 14 .6%AR at minimum flow. alarms.065 = 12. and to provide cell phone connectivity. Now I will describe some other.6%AR.5% of full scale (%FS). Head-Type Flowmeters When measuring flow by any differential pressure generating element. the measurement error is the sum of the sensor error. n my May column. gives us a total error of only 4. total flows. Figure 1 shows the relationship between the turndowns in terms of flow and the corresponding turndown requirement of the ΔP transmitter. digital ΔP transmitter is nearly 200:1. Adding to this ΔP error. the 1%AR error of the sensor (the precision of its discharge coefficient CD). With a ΔP measurement error of 0. I described some new fiber-optic flowmeters used for subsea measurement of multiphase flows (oil. the d/p cell error is 12.74% AR at the minimum ΔP (196x 0. and the error of the d/p cell. Today. the flow turndown (rangeability) had to be limited to about 4:1. which is usually about one percent of actual flow (%AR). and at the minimum flow (100/14 = 7%). Because of the square root relationship. memory boards for data acquisition and storage for hundreds of thousands of data points for displaying of trends. this minimum ΔP error corresponds to a minimum flow error of √ 12. In addition to the tremendous increase in the accuracy of the state-of-the-art d/p cells. Because of the square root relationship. in the past.Trends in Technology Advances in Flow Instrumentation by Bél a Lipták I with local displays. this means that the flow rangeability is 14:1 (142 = 196). more recent advances in the field of flow instrumentation that have occurred partly because of the need for transporting and accurately metering large quantities of oil and natural gas. the full 14:1 turndown can only be realized if at minimum flow (100/14 = 7% of full scale).74%).11). which used to be around 0.74% = 3. They can be mounted to the sensor or connected wirelessly (IEEE802. water. the flow turndown is 14:1. the flow is still turbulent (RE > 8. the total error is kept under 5%of actual flow (AR). methane). the maximum turndown capability of a smart.065%FS. these smart units are provided 100 90 80 70 9:1 16 : 1 50 196 : 1 100 : 1 36 : 1 60 40 30 20 10 10 20 30 40 50 60 3:1 70 80 90 100 % Flow 4:1 6:1 10 : 1 14 : 1 Flow rangeability digital accuracy gives higher turndown Figure 1: At a ΔP turndown of 196:1. while the d/p cell is in an easy-to-access location.

two-way ultrasonics Figure 4: Bi-directional. • V-shaped cones. Figure 2: Wireless orifice flowmeters are appropriate for some hardto-reach applications in oil-and-gas markets. For example: • Conditioning orifice meters with wireless transmission (Figure 2). but their conditioning effect reduces the straightrun requirement. • Averaging Pitot tube inside a flow nozzle combined with pressure/temperature sensors to calculate mass flow of natural gas. multi-path. some of the other head-type flowmeter features also are competing on the hydrocarbon and other markets. These cones require individual calibration.Emerson Rosemount Emerson Rosemount Trends in Technology the temperature of flow Figure 3: Flow transmitter with pressure and temperature sensors playing in the hydrocarbon space calculates mass flow of known molecular weight gases. • Regular and Venturi wedge meters for fluids containing sand or slurries. and • Flow transmitters with pressure and temperature sensors can calculate mass flow of known molecular weight gases (Figure 3). ultrasonic mass flowmeter for gas service. Emerson/Daniel While the Venturi flowmeter is still the favorite when it comes to pressure recovery and accuracy. 15 .

the water cut meter. is also editor of the Instrument Engineers’ Handbook and is seeking new co-authors for the coming new edition of that multi-volume work. intense activity in the hydrocarbon industry has catalyzed advances in other flowmeter families. for example. Similarly. but other technologies are also competing for that market. this bi-directional. oil and gas and the undersea multiphase flowmeter. in case of large flows. which uses five NIR wavelengths to distinguish water.Trends in Technology One should note that. a number of multiphase (oil. multi-path. In custody transfer applications. He can be reached at liptakbela@aol. These units are designed for operation at some miles of depth under the ocean. while something like the V-shaped cone causes an intermediate amount of permanent loss (~ 40%). the unrecovered (permanent) pressure loss caused by the meter is an important consideration. Other Flowmeter Types In addition to head-type flowmeters. methane) flowmeters have been introduced. control consultant. water and gas content by simultaneous measurements of variables. PE. at the drilling end of the hydrocarbon production process. the accurate and reliable Coriolis flowmeter is still the favorite. for water. which calculates the total flow and its oil. . ultrasonic mass flowmeter for gas service (Figure 4). Béla Lipták. for example. This permanent loss is the worst in case of sharp restrictions (orifice ~ 70%) and the best with smooth transitions (Venturi ~ 15%).

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The integrating process gain (K i ) for this general case of level control. Here we offer a more complete view with derivations in Appendix A. the tuning settings depend upon maximums. the ramp stops. Control systems studies have shown that the most frequent root cause of unacceptable variability in the process is a poorly tuned level controller. A higher level does not force out more flow. process conditions. The flow maximum (Fmax) and level maximum (Lmax) in Equation 1 must be in consistent engineering units (e. and the process has an integrating response. Frequently. Most of the published information on process gains does not take into account the effect of measurement scales and valve capacities. we investigate the use of an adaptive controller for the conical tank in a university lab and discuss the opportunities for all types of level applications. However. Prakash Jagadeesan T he tuning of level controllers can be challenging because of the extreme variation in the process dynamics and tuning settings. the discharge flows are independent of level. If the controller K i = Fmax / [(ρ * A) L max ] 18 Eq.html).controlglobal.g. There is no steady state. There is no process self-regulation. the manipulated flow must drive past the balance point for the level to reach the new setpoint. available on the ControlGlobal website (www. Any unbalance in flows in and out causes the level to ramp. as derived in Appendix A. is: General Dynamics for Vessel Level There have been a lot of good articles on level control dynamics and tuning requirements. The maximums are the measurement spans for level and flow ranges that start at in Technology Adaptive Level Control Exploring the Complexities of Tuning Level Controllers and How an Adaptive Controller Can Be Used in Level Applications By Greg McMillan. 1 . the feed flow must be driven lower than the exit flow for a decrease in setpoint. The ramp rate of level in percent per second for a 1% change in flow is the integrating process gain (%/sec/% = 1/sec). Next we clarify how tuning settings change with level dynamics and loop objectives. The equation for the integrating process gain assumes that there is a linear relationship between the controller output and feed flow that can be achieved by a cascade of level to flow control or a linear installed flow characteristic. If we consider the changes in the static head at the pump suction to have a negligible effect on pump flow.000001%/sec) to exceptionally fast rates (1%/sec). there often are details missing on the effect of equipment design. For a setpoint change. and a lower level does not Since the PID algorithm in nearly all industrial control systems works on input and output signals in percent. transmitter calibration and valve sizing that are important in the analysis and understanding. Sridhar Dasani and Dr. force out less flow. level measurement span and flow measurement span for the general case of a vessel and the more specific case of a conical tank. If we are manipulating the feed flow to the volume. The most common tuning mistake is a reset time (integral time) and gain setting that are more than an order of magnitude too small. meters for level and kg/sec for flow). the flows are pumped out of a vessel. Finally. The ramp rate can vary by six orders of magnitude from extremely slow rates (0. In this article we first provide a fundamental understanding of how the speed and type of level responses varies with volume geometry. fluid density. When the totals of the flows in and out are equal.

surge tanks). if the user sees these oscillations and thinks they are due to too high a controller gain. boiler drums and column sumps) or because of the need for the level to float to avoid upsetting the feed to downstream units (e. low. Normally. the adaptive level control with proper tuning rules removes the confusion of the allowable gain window. through enforcement of a residence time or a material balance for a unit operation. Since these overhead receivers are often horizontal tanks. The period and decay gets slower as the controller gain is decreased. Conical Tank in MIT Anna University Lab with an industrial DCS. For horizontal tanks or drums and spheres. and prevents the situation of level loops being tuned with not enough gain and too much reset action. If the level controller gain is decreased to reduce the reaction to inverse response from shrink and swell or to allow the level to float within alarm limits. the equation should be multiplied by the slope at the operating point on the installed characteristic plotted as percent maximum capacity (Fmax) versus percent stroke. the denominator of the integrating process gain that is the product of the density (ρ). the cross-sectional area varies with level. he or she may decrease the controller gain. What most don’t realize is that the opposite correction is more likely needed for integrating processes. In other words. If the controller gain is further increased. exceptionally tight level control. cross-sectional area (A) and level span (mass holdup in the control range) is so large compared to the flow rate that the rate of change of level is extremely slow. The quantity and quality of product for continuous reactors Figure 1. making the oscillations worse (more persistent).g.g. is needed for best product quality. In other applications. level control can be challenging due to shrink and swell (e. and crystallizers depend on residence times. In some applications. Most level loops are tuned with a gain below a lower gain limit. but also deal with the changes in process gain from changes in fluid density and nonlinear valves. 50% level) and highest at the operating constraints (e.g.Trends in Technology output goes directly to position a nonlinear valve. In these vessels. The variability in column temperature that is an inference of product concentration in a direct material balance control scheme depends on the tightness of the overhead receiver level control. the oscillations will grow in amplitude (the loop becomes unstable). a small change in level can represent a huge change in inventory and manipulated reflux flow. For fed-batch operations. Adaptive level controllers can not only account for the effect of vessel geometry. In the section on controller tuning.and high-level alarm and trip points). Consequently. We are not so cognizant of the oscillations with a slow period and slow decay caused by too low of a controller gain. the integrating process gain is lowest at the midpoint (e. Even if these nonlinearities are not significant.g. 19 . there may be an optimum batch level. the reset time must be increased to prevent slow oscillations. an oscillatory response is addressed by decreasing the controller gain. Most people in process automation realize that a controller gain increased beyond the point at which oscillations start can cause less decay (less damping) of the oscillation amplitude. we will see that the product of the controller gain and reset time must be greater than a limit determined by the process gain to prevent these slow oscillations. We are familiar with the upper gain limit that causes relatively fast oscillations growing in amplitude.

For a self-regulating process the controller gain (K c) and reset time (Ti) are computed as follows from the process gain (K ρ). The conical tank with gravity flow introduces a severe nonlinearity from the extreme changes in area. process time constant and process dead time (θp): π * r2 1/2 3*C *h  Kp = Conical tank Eq. Since the radius (r) of the cross-sectional area at the surface is proportional to the height of the level as depicted in Figure 2. 3 20 . Controller Tuning Rules The lambda controller tuning rules allow the user to provide a closed-loop time constant or arrest time from a lambda factor (λf) for self-regulating and integrating processes. interfaces and tools. The dependence of discharge flow on the square root of the static head creates another nonlinearity and negative feedback. τp = r Variable-flow pump Fmax h Hand valve Reservoir Figure Less recognized is the opportunity to use the DCS for rapid prototyping and deployment of leading edge advances developed from university research. bark and coal to unit operations. respectively. The Madras Institute of Technology (MIT) at Anna University in Chennai. 4  Eq.html). The equations are approximations because the head term (h) was not isolated. The DCS allows graduate students and professors to explore the use of industry’s state-of-the-art advanced control tools. India. The use of a DCS in a university lab offers the opportunity for students to become proficient in industrial terminology. standards. The upper and lower controller gain limits are a simple fall out of the equations and can be readily enforced as part of the tuning rules in an adaptive controller. the equations for the process time constant (τp) and process gain (K p) are developed from a material balance applicable to liquids or solids. has a liquid conical tank controlled by a distributed control system (DCS) per the latest international standards for the process industry as shown in Figure 1. Conical tank detail.Trends in Technology Specific Dynamics for Conical Tank Level Conical tanks with gravity discharge flow are used as an inexpensive way to feed slurries and solids such as lime. The process no longer has a true integrating response. The conical shape prevents the accumulation of solids on the bottom of the tank. 5 h * Fmax 1/2 C * L max  Ti = τp Eq. In Appendix A online (www. 2 Kc = Ti Kp * ( λf * τp + θp )  Eq. it is expected that the decrease in process time constant is much larger than the decrease in process gain with a decrease in level.controlglobal.

6 Kc < For an integrating process the controller gain (K c) and reset time (Ti) are computed as follows from the integrating process gain (K i) and process deadtime (θp): Kc =   Eq. Performance of linear PID level controller for a conical tank. Ti Ki * [(λf /Ki) + θp ]2 3 Ki * 4 * θp  Eq.Trends in Technology Figure 3. Kc < Ti = 2 * (λf /Ki ) + θp Eq. 9 The lower gain limit to prevent slow oscillations occurs when the product of the controller gain and reset time is too small. 7 21 . The upper gain limit to prevent fast oscillations occurs when the closed loop time constant equals to the dead time. 8 The upper gain limit to prevent fast oscillations occurs when the closed loop arrest time equals the dead time: τp Kp * 2 * θp  Eq.

An adaptive controller integrated into the DCS was used to automatically identify the process dynamics (process model) for the setpoint changes seen in Figure 3. The integrated tuning rules prevent the user from getting into the confusing situations of upper and lower gain limits and the associated fast and slow Figure 4. Sridhar Dasani is a graduate of Madras Institute of Technology (MIT) Anna University in Chennai India. Prakash Jagadeesan is an assistant professor at Madras Institute of Technology (MIT) Anna University in Chennai India. a decrease in process time constant greater than the decrease in process gain at low levels causes excessive oscillations. Figure 5. oscillations. process time constant. Adaptive level controllers can eliminate tuning problems from the extreme changes in level control dynamics associated with different equipment designs and operating conditions. rather than lambda factors. This scheduling of the identified dynamics and calculated tuning settings eliminates the need for the adaptive controller to re-identify the process nonlinearity and tuning for different level setpoints. with protection against going outside the controller gain limits helps provide a more consistent tuning criterion. Dr.Trends in Technology Kc * Ti > 4 Ki  Eq. As seen in Figure 5. and process gain that best fits the observed response. the adaptive level controller eliminates the oscillations at low levels. and provides a more consistent level response across the whole level range. The trigger for process identification can be a setpoint change or periodic perturbation automatically introduced into the controller output or any manual change in the controller output made by the operator. Performance of adaptive PID level controller for conical tank. The adaptive controller employs an optimal search method with re-centering that finds the process dead time. 10 Opportunities for Adaptive Control of Conical Tank Level A linear PID controller with the ISA standard structure was tuned for tight level control at 50% level for a detailed dynamic simulation of the conical tank. Figure 3 shows that for setpoints ranging from 10% to 90%. The controller gain and reset settings computed from the lambda tuning rules are then automatically used as the level moves from one region to another. The process models are categorized into five regions as indicated in Figure 4. The smoother and more consistent response allows the user to optimize the speed of the level loop from fast manipulation of column reflux and reactor or crystallizer feed to slow manipulation of surge tank discharge flow control. Process models automatically identified for operating regions. It was found that the use of lambda time. 22 . Greg McMillan is a consultant and ControlTalk columnist.

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These separators were not only slow (often intermittent). water and gas flows were separately measured. or in automating new nuclear power plants that will operate underwater. safe and clean energy is better. This is Now In the past. Most of today’s multiphase flow rate measurements use Venturi tubes and nuclear densitometers. it’s good to know if the total flow rate or the composition of the product changes. This technique was also expensive and took up a lot of space. some nations will be waging wars over what oil and gas is left. but because we will slowly discover that inexhaustible. multiphase flow and composition determinations. I answered 2014. the oil. water. pressure and temperature) into dynamic. the flow rate and composition of the product was determined by above-ground separators and. ast year. Measurement of the multiphase fluid rate and fluid composition is also important for production efficiency reasons and for zonal allocation of gas production in multi-zone well completions. Here I will discuss flow measurement. and if you ask me next year.” packaged and Offshore Drilling and Fiber-Optic Flowmeters Oil or natural gas production is a multiphase stream 24 . density. Thus. It also supports identification and localization of injection or production anomalies in real time.Trends in Technology The Incredible Fiber-Optic Flowmeter by Bél a Lipták L consisting of oil. and use sophisticated flow models to interpret multiple measurements (flow. I call this transition time the “scraping the bottom of the barrel” period. During this period. but there are others. not because we ran out of stone. reduction of the need for surface well tests and surface facilities. about which a decade ago I would have said everything that can be discovered already had been. it will take another generation or two to make this transformation. after separation. Today. So what’s the challenge for our profession? It is to help both. The subsea multiphase flowmeters are “marinized. my answer is late 2015. determination of well productivity index. the hydrocarbon/nuclear age will end. gas and sand. subsea. but they also usually separated only a small bypass stream. multiphase flowmeters was a major advance both in terms of safety and efficiency. This is very important for safety reasons. not because we run out of these materials. which was not necessarily representative. when I was asked about the publication date of the 5th edition of my handbook. Yet. replacing the separators with in-line. my answer might also shift. They have no moving parts. etc. We Have Entered a New Age The stone age ended. while one will use some of its budget to develop green energy technology. Similarly. That Was Then. I will describe only one new flow detector. Why? Because of the explosion of inventions and international competition during the past decade to meet the needs of the new processes from deep-sea drilling to solar hydrogen. but because we discovered that bronze tools were better than stone ones. don’t require much maintenance. When drilling a couple of miles deep under the ocean or fracking a couple miles below the groundwater layer in North Dakota. Here I will concentrate on the first group and focus only on the oil and gas flow measurement advances that are occurring in fracking and undersea production processes.

The refractive index profile of the fiber core shows the change of the refractive indexes (n0. a wavelength-specific mirror is obtained. The method. the receiver algorithm “knows” which wavelengh is coming from which optical sensor. Optical fiber Fiber core Core refractive index Fiber-Optic Flowmeters The latest technology in subsea flow metering uses downhole fiber-optic (FO) cables mounted on the surface of the production pipe. The differential pressure between two detectors. Therefore. Béla Lipták. water and oil) passing through the production pipe travels at some average temperature and pressure. uses a fiber Bragg grating (FBG). Figure 2 shows the structure of an FBG system. Thereby. is also editor of the Instrument Engineers’ Handbook. and the cable connecting the distributed optical pressure sensors (DPS) is shown in blue. the FO cable connecting the distributed optical temperature sensors (DTS) is shown in red. This system is usually referred to as a distributed Bragg reflector. On the right of Figure 1. FBGs are constructed from segments of optical fibers. the angle at which total reflection occurs. The refractive index n of a particular substance equals the ratio of these two speeds (n = C/V). that occur very quickly. These optical sensors take advantage of the fact that light in vacuum travels at velocity (C). is related to the volumetric flow passing through the pipe. Each of these fiber segments reflects one particular wavelength of light and transmits all others. They interrogate multiple pressure and temperature sensors mounted on the outside surface of the production pipe. the refractive index determines how much of the light is refracted when it hits the interface of a particular substance. gas bubbles. but also reservoir management and allocation metering. Both of these variables oscillate around some average value. and serve not only the management of individual wells. if one is able to prepare an optical filter grating element that transmits all wavelengths except one. n2 …) along the core. for example. specific gravity changes composition variations. allowing a number of sensors to be interrogated by a single FO cable. Optical Pressure and Temperature Sensors The fluid (a mix of gas. Therefore. which interpret them into flow rate and composition. which is specific to them and which it reflects. He can be reached at liptakbela@aol. and can read many sensors at the same time.Trends in Technology deployed by specialist subsea companies to replace topside well test separators. 25 . while the time it takes for a particular fluctuation to travel from one detector to another relates to the velocity of the fluid. The extremely fast optical pressure and temperature detectors pick up these oscillations and forward them to the sophisticated algorithms at the receiving end of the FO cable. automation. and the material behaves like a mirror. The refractive index (n) also determines the critical angle of reflection. and the spectral response at the bottom shows how the incident broadband signal is split into the transmitted and reflected components at the Bragg wavelength (λB). etc. each of which blocks or reflects a different specific wavelength. and when it reaches the surface of a substance. it slows to velocity (V). The FGB can therefore be used to provide in-line optical filters. n1. safet y and energy consultant. Spectral response Input ? ?B Transmitted ? Reflected ? all the wavelengths but one Figure 2: Fiber-optic cable with a core containing gratings (n0 to n3) that transmit all wavelengths except one (λB). These fluctuations (the noise superimposed over the average values of the pressure and temperature of the fluid) carry valuable information because they are caused by eddy currents.

usa.© 2014 Siemens SITRANS LR250 – your radar solution for liquids and slurries SITRANS LR250 is your choice for liquid level measurement in storage and process vessels.siemens. With its new flanged encapsulated . Inc. Higher temperatures or pressures? Those too. corrosive and other aggressive materials are no problem for this transmitter. Reliability and improved safety? We do that.siemens. • • • • • • • Simple installation Minimal maintenance Suitable for temperatures up to 338 °F True inventory management Reliable level measurement Flexible communications Proven performance usa. Welcome to liquid level perfection.

Texas. leading to unplanned downtime. BP Exploration replaced the existing GWRs with Rosemount 5300 GWRs with signal-processing that ensures detection of low-dielectric fluids. BP Exploration (www. production. the Rosemount 5300’s FF interface level on the high seas Figure 1. lasers and nuclear devices have met or at least partly satisfied each new level measurement challenge over the years. floats. sticky fluids had made it difficult to measure level on the FPSO. Also.77 million barrels of oil. As a result. and can send and receive cleaner. storage and off-loading (FPSO) vessel to secure accurate and reliable level measurements in challenging process conditions about 100 miles off the coast of Africa. BP’s FPSO processes and stores oil for export.emersonprocess. sonics. sticky. Its original GWR transmitters weren’t compatible with the FPSO’s Foundation fieldbus (FF) in Houston. and eliminate trips due to false readings. foam and vapor. and dirty. and most continue to be refined even now. Changing process conditions. displacers. storage and off-loading (FPSO) ship with guided-wave radar (GWR) transmitters from Emerson Process Management (www. The ship is 310 meters long. Operating about 100 miles off Africa’s west coast. and can process up to 240. recently replaced unreliable level transmitters on a floating. However. BP Exploration is using guided wave radar (GWR) transmitters from Emerson Process Management on its floating. prompting new ways to look into tanks without opening them. This allows use of single-lead probes that increase tolerance to solids build-up and coating.Trends in Technology Level Reaches New Heights Ever-improving instruments and relaxed regulations are allowing workhorse technologies to excel in dynamic. new problems are always arriving. by Jim Montague W made installation and configuration quicker and easier. and their limited ability to detect low-dielectric hydrocarbons required coaxial probes to increase surface signal strength. can store 1.bp. After the Rosemount 5300 GWRs were installed. production. these probes were prone to sticky build-up. multiphase and politically sensitive applications.000 barrels per day. magnets. Emerson Process Management Tank Vessel Meets Ship Vessel For example. radar. 27 . the FPSO’s process data confirmed the accuracy and reliability indows. stronger signals (Figure 1). com). However.

They will be pub- the new FCC rules partially harmonize U. magnetic. So.250 GHz. This means the level of the interface between the water and CS2 needs constant monitoring. U.S. (ETSI) Technical Standard for LPR devices. an instrumentation specialist in Manchester. 15 that it’s ad- measurement protocols for these devices.925 to 7. but it must store the CS2 under a layer of water to prevent it from igniting. ICA recommended using ABB’s ( which provides continuous level indication.S.-based Robinson Brothers is using a magnetorestrictive level transmitter from ABB to meet strict safety standards for handling highly reactive carbon disulfide (CS2). Most floatbased device to measure the CS2 and water level. transmits analog and/or digital signals careful with chemicals Figure 2.05 to 29. the U. adjusting emission limits to account for attenuation that occurs The Measurement. and will become effective the similar European Telecommunications Standards Institute’s 30 days after that. this because it will improve the global competitiveness of In addition. and the FCC’s technical office The FCC’s order also granted MCAA’s request to continue an op- drafted a Notice of Proposed Rulemaking in 2012 to revise its tion for certifying LPRs under Section 15. of the instruments and their suitability for its widely varying process conditions.00 GHz and 75 to 85 GHz bands. for monitoring or control.fcc. ABB Reining in Reactivity While its tank isn’t out on the ocean.” new rules allow. U.Trends in Technology FCC Allows Unlicensed “Level Probing Radar” in Open Air In a long-awaited and helpful regulatory update. so any related instruments are safety-critical. The report and order are located at http://hraunfoss. The company uses CS2 at its Midlands specialty chemicals the order modifies Part 15 of the FCC’s rules for measurements on main-beam emission limits. Robinson sought help from ICA Services (www.K. U.209’s more flexible emis- former rules to allow unlicensed LPRs in “any type of tank or sion limits because some LPRs need wider bandwidths than the open-air installation. MCAA also sought LPRs to operate on an unlicensed basis in the 5. and where in the country without a license. 24. out the regulatory process. Federal surement procedures to provide more accurate and repeatable Communications Commission (FCC) reported Jan. and can boost its resolution to more than 100 times greater than a conventional reed switch-type device (Figure 2). edocs_public/attachmatch/ reports it worked closely with the FCC through- any nearby receivers from encountering interfering signal levels. which also bases its Specifically. The new limits will still protect measure. Control & Automation (MCAA.-based Robinson Brothers (www. by changing these technical testing requirements. but it didn’t link to any wider control system. AT100 28 . upon reflection of those emissions. rules for LPRs with lished shortly in the Federal Register. Robinson previously used a AT100 magnetostrictive level transmitter.K. The rules now require opted rules allowing “level probing radars” (LPRs) to operate any- measuring emissions in the main beam of the LPR probably has an even more difficult level measurement challenge—securing level indications for highly reactive carbon disulfide (CS2). and revises the mea- level instrumentation manufacturers.

” says Carsella. such as water/wastewater or other plants with outdoor or open vessels. are bringing level instruments closer to plug and play. while electronic device descriptions (EDDs) standardized by the FDT Group (www. Robinson’s E&I manager. Boyce Carsella. consultant at Magnetrol (www. reports level measurement’s migration to lower-power sources has enabled it to serve in new and hazardous applications. “Radar and guided-wave radar are the most successful level measurement technologies today because they’re non-contact.Trends in Technology also meets the most-extreme ATEX Exd IIC T6 protection standard and toughest SIL1 performance standards. FDT and FCC Aid Level While ongoing technical advances get the main spotlight in level measurement.” says Tom Rutter. and can handle the widest range of applications. and it meets our internal requirement for SIL1-capable instrumentation.’ which will allow it to be applied outside or on open tanks [see sidebar]. “Our new system provides process signals that output to both our local and site monitoring systems.magnetrol.fdtgroup. unaffected by atmosphere. Low-Power. organizational efforts have helped. “ This will open up many applications. radar’s popularity will be helped even more by the FCC’s adding to its Part 15 rules on ‘level probing radar.” Jim Montague is Control’s executive editor .

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. NRG Lab began searching for a substitute with long-life NRG Lab reports its V-Cone flowmeter performs better than its former vortex flowmeter. small footprint. By Jim Montague I up through a PLC. recently deployed 10 Promass 83F Coriolis mass flowmeters from Endress+Hauser ( differential pressure V-Cone flowmeter with built-in flow conditioning for accuracy to +0. while it might be surprising to see a bunch of Coriolis flowmeters sprouting on top of a filling machine.” t shouldn’t be surprising. rather than the traditional pulse output set Nuclear and Underwater Likewise. Italy.1 repeatability. and enable tighter filling tolerances on its advanced filling equipment (Figure 1). 31 .shell. GF also wanted to enable users to change media without replacing the measuring instrument. and be applied by users that hadn’t considering using them before or couldn’t afford them. according to Marco Serventi.A. It uses flow metering to measure its nuclear laboratory and reactor’s basin cooling system. which uses a medium called “demiwater. facility in the Netherlands makes nuclear medical isotopes and tests materials for nuclear power plants. “The reliability and accurate results provided by the Micro Motion instruments have now been validated by GF customers over a number of successful applications. GF’s sales manager.Trends in Technology Flow Charts New Waters Flowmeters. that’s exactly what GF S. but continual advances in flow conditioning and management are enabling them to be implemented in some unusual applications and settings.5 g to 5 kg to be dispensed without changing mechanical components. syrups and detergent infusions. and enhances safety by avoiding having any electronics near the reactor vessel.” explains at Stanlow refinery in Ellesmere Port. food and medical applications to precisely measure compounds for injections. and enable in-line sterilization without disassembling the machine. The flowmeters use Profibus DP communications. the rangeability of these Coriolis flowmeters allows different media in the range of 0. NRG Laboratory’s (www. most of the basic parameters of flow sensing and control are well known. requires no maintenance such as changing cables. ophthalmic preparations. as well as piston-syringe and peristaltic (roller type) pumps. Besides seeking to improve filling speed and accuracy. (www. Shell Lubricant Center (www. low maintenance costs. did recently to reduce filling times. com). It suits tight retrofit installations because it only requires a minimal 0-3 pipe diameters upstream and 0-1 diameters downstream.5% of the flow rate with +0.mccrometer.p. GF’s filling machines are used in pharmaceutical. NRG Lab settled on McCrometer’s (www. controllers and their supporting components and software are adding new functions that are allowing them to take on some new and unusual tasks and applications.nrg-labs. For instance. U. GF previously used filling methods based on time-pressure instruments. “We were able to improve system response time and reduce batch cycle times by taking advantage of integrated valve control from the transmitter. improve accuracy and repeatability. Also.K. good underwater performance and the ability to withstand radiation. GF met its goals by using Micro Motion Elite and H-Series flowmeters and Model FMT filling mass transmitters from Emerson Process Management (www. Aiding Lubrication Applications To help give its new lubricant bottom-loading bay more efficient and safer driver-initiated loading. but adding innovations and new capabilities to familiar technologies can make them show up in some unexpected places.endress. For example. on machines for its pharmaceutical in Parma.” When its old vortex flowmeter wore out and a replacement wasn’t available.

and the Promass flowmeters are low-maintenance. and links seamlessly with Shell’s inventory control system. is using Micro Motion Coriolis flowmeters to reduce filling times.Photo courtesy of Emerson Process Management Trends in Technology Coriolis Collection Figure 1: Italy-based filling machine builder GF S. knowing product density is crucial due to changes cause by temperature fluctuations. which can reduce lubrication. needs to constantly lubricate the 13. load qualities and grades are validated automatically.p. Also.8 grams per liter (g/l). 32 . Germany.000 tons of aluminum rolls it makes each year with high-quality oil. “Driver-initiated loading has proven to be a real benefit all round. Shell Lubricant’s E&I engineer. secure and user-friendly. and enable tighter filling tolerances on its filling aluminum flat-rolling mill in Lüdenscheid. and this provides added density and temperature data. such as diagnostic information. accurate. reduces cabling and I/O requirements. improve accuracy and repeatability.” says Chris Turner. damage the rolls. the driver-initiated loading functions are more efficient because drivers no longer have to wait for manual link-ups to pumps.” Likewise. and this streamlines and cuts the required steps by 50%. helps us maintain smooth operation and system integrity. this oil often thins during production. Oil thinning is accompanied by a minimum density change of around 0. Novelis’ (www. Because Shell’s tankers load according to volume. However. “All the data provided by Profibus.novelis. and stop production.

has deployed Rosemount 8800 vortex flowmeters to help reduce energy consumption and optimize fuel provided to its arc furnaces. Besides high-precision density measurement.p. its Adaptive Digital Signal Processing (ADSP) signal filtering and a mass-balanced sensor design maximize measurement reliability. but they made it difficult to handle changing process requirements and meet user demands for more accurate control. and implemented Emerson’s Rosemount 8800 vortex flowmeters.5 g/l in field adjustments. The company needed more accurate instruments with a broader measurement range. optimize steel quality. to meet demands for greater flexibility in furnace installations. we’ve Optimized Arc Furnace Figure 2: More s. so it evaluated vortex flowmeters. Photo courtesy of Emerson Process Management Optimized Oxygen = Stronger Steel While a steel plant might not seem like the most logical place for a in Gemona del Friuli.l (www. and Novelis can take countermeasures to prevent damage to the rolls.” Jim Montague is Control’s executive editor.Trends in Technology To prevent these problems. providing greater opportunities to vary steel characteristics for different applications. a closer look at More s. which extends furnace lifecycles. which are designed to addresses the limits of traditional vortex flowmeters. and provide additional energy from exothermic reactions. “By implementing Emerson’s vortex technology. and eliminate the impact of vibrations on measurement accuracy. More also supplies auxiliary steelmaking equipment. Rosemount 8800’s 25:1 rangeability helps optimize gas heaters. so unique trends can be observed. reveals the electric arc furnaces it supplies to mini-mills are using vortex flowmeters to minimize fuel and oxygen consumption. “We’ve been able to optimize furnace efficiency in terms of productivity and steel quality. These chemicals are injected into the furnace during the manufacturing process to improve steel quality.” says Roberto Urbani.r. including sidewall injector systems used with chemical energy packages such as oxygen. carbonaceous fuels. helping to reduce overall energy com). 33 . lime and other fine compounds. been able to build electric arc furnace solutions that guarantee optimum furnace efficiency for users. This means fluctuations in density can be detected much earlier. For example. Over-oxidation is no longer an immediate concern. More’s purchasing manager. More had been using differential pressure flowmeters to measure critical oxygen flows in its furnaces.l. FCB350 also gives the rolling mill a smooth density signal. prevent rework and reduce costs (Figure 2). Novelis recently installed CoriolisMaster FCB300 mass flowmeters from ABB (www. which can perform density measurements at up to 0. Also. Energy consumption and ambient pollution were also reduced. Italy.more-oxy.

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the differential pressure transmitter calibrated for water would measure 50 millimeters higher than the actual 500 millimeter liquid level. capacitance. Continuing with the previous example. the same 500-millimeter level of another liquid with a specific gravity of 1. magnetostrictive. a water level that is 1000 millimeters above the centerline of a differential pressure transmitter diaphragm will generate a pressure of 1000 millimeters of water column (1000 mmWC) at the diaphragm. radar. Conversely. this transmitter will measure lower than the actual level. All have problems that can potentially affect the level measurement. Three Calculations All is not lost because the calibration of the differential pressure transmitter can be modified to compensate for a different specific gravity. Incorrect or inappropriate measurements can cause levels in vessels to be excessively higher or lower than their measured values. One remedy that can help avoid a GIGO scenario is to understand the measurement technique and its limitations to the extent that its application can be reasonably evaluated. Differential pressure level measurement technology infers liquid level by measuring the pressure generated by the liquid in the vessel. but rather infers level. The importance of level measurement cannot be overstated. while high levels can cause vessels to overflow and potentially create safety and environmental problems.Back to Basics Beginner’s Guide to Differential Pressure Level Transmitters The Not-So-Straightforward Basics of This Measurement Technique By David W.10 at operating conditions in the above vessel will generate 550 mmWC of pressure at the transmitter. As such. if the liquid has a specific gravity that is lower than that of water. Note that this example presumes that the liquid is water. Vessels operating at incorrect intermediate levels can result in poor operating conditions and affect the accounting of material. For example. Similarly. Spitzer G IGO means “garbage in. Examples of direct level measurement include float. The level of a liquid in a vessel can be measured directly or inferentially. Liquids with other specific gravities will generate other differential pressures and cause inaccurate measurements. a level of 500 millimeters will generate 500 mmWC. retracting.” This phrase applies in industrial automation because using faulty measurements can fool even the best control system. Differential pressure level measurement is one of those key measurements you need to understand to avoid the dreaded GIGO. Weight and differential pressure technology measure level inferentially. This technique used to calculate the 35 . garbage out. Calibrating this differential pressure transmitter for 0 to 1000 mmWC will allow it to measure water levels of 0 to 1000 millimeters. ultrasonic and laser level measurement technologies. Low levels can cause pumping problems and damage the pump. This example illustrates that differential pressure technology does not measure level.

vations does not affect the calibration. the differential pressure below the nozzle. Using similar techniques as in the previous examples. the pressures100% at the Level high and low sides 1. Figure 3 illustrates the use of a differential pressure bar)} minus {1.10*(200 mm) + (3 bar)} and {1. the pressure at the transmitter is + (3 bar)}. Figure 1 shows the vessel both at 0% and 100% level. the low-pressure diaphragm is located above the liquid to 1000 millimeters Note that the static pressure in the vessel does not afto compensate for the static pressure in the vessel. Further that locatspond to the nozzle positions. the pressures at the high and low sides of the trans. we need to take the mea.05*(1300 mm) + (3 bar)}.10on both sides of the calibration because it SG appears complications include the densities of liquid and capil-SG fect 500 mm 500 mm lary fill fluid and 0% and 100% levels that do not corre. At 0% level.10*(1000 mm) + (3 bar)} and mmWC.10 = 1.10 uid levels of 0 mm to 1000 mm. The pressure is 1.10 SG = 1.05*(1300 mm) 36 .10*(500+1000 mm) or 1650 of the transmitter are {1.10*(200 mm) + (3 bar)} minus {1. At 100% level.Back to Basics 100% Level 0% Level new calibration is useful for both straightforward and more complex installations. the transmitter should be calibrated -1145 at the nozzles in a pressurized vessel. the transmitter should be LT LT mm calibrated 0 to 1100 mmWC to measure liqSG = 1. In this application.10*(0 mm) when the vessel at 0% and 1.measure liquid levels of 0 to 1000 millimeters. or 770 mmWC. Other = 1. Therefore. transmitter with diaphragm seals to sense the pressures Therefore.the differential pressure transmitter where it effectively 1000 mm LT LT analysis also will reveal cancels out. or -1145 mmWC. surement from 200 mm to 1000 mm above the nozzle. at ing the differential pressure transmitter at different ele0% level. mmWC to -265 mmWC to measure liquid levels of 200 200mm above the lower nozzle. The pressure generated by the liquid at the level transmitter diaphragm is the liquid height times the specific gravity. Therefore. In addition.05*(1300 mm) + (3 bar)} respectively. the 0%At Level pressure at the transmitter is 1.10*(500 +200 mm). 1000 mm A somewhat more complex application is illustrated in Figure 2. the transmitter is located 500 mm + (3 bar)} respectively. Therefore. The level transmitter for these vessels should be calibrated 0 to 1100 mmWC to for process reasons.10*(1000 mm) + (3 1000 mm above the nozzle.transmitter will subtract the high side from the low side and ditions at both 0% and 100% level is the same as performed measure {1. Note that the technique of sketching con. These same techniques can be used to determine the mitter are {1. Similarly. In this application.05*(1300 mm) in Figure 1. Figure 1.10*(1000 mm) when the vessel at 0 100%. 100% level. the 770 to 1650 mmWC to measure liquid levels of 200 mm to differential pressure transmitter subtracts the high side from the low side to measure {1. or -265 mmWC. the transmitter should be calibrated {1.

This transmitter should be calibrated 770 to 1650 mmWC to measure liquid levels of 200 mm to 1000 mm above the nozzle. so that differ.10 SG = 1. The span of a transmitter is the difference between the to be changed by 1000 mmWC. Using this lower range 37 100 S . Repeating.4000 mmWC. instruments. the specific gravity of 770 to 1650. Each many liquids is known and relatively stable.05trans.10 operation? What if the change is due to 500 mm 500 mm changes in the composition of the liquid? 1000 mm LT LT What if the change is due to temperature changes? What if the vessel is filled with a different liquid that has a different specific Figure 2. However. a given differential pressure SG = 1. their zerosPressure by more than 4000 mmWC. it could SGbe = 1. In addition. the transmitter zero is raised by 770 mmWC.05 = 1. Nowhere do we use terms such as elevation. suppression and span. This transmitter would 100% and 0% calibration values. 0% Level 100% Level 200mm What Ifs What if the liquid density changes during SG = 1. Calibrations that do not meet the transment does not measure liquid level—it infers liquid level— mitter specifications are potentially subject to significant so specific gravity changes can affect the performance of error. 0% Level the level measurement. the calibrated span specified for another Spanning Specifications The differential pressure transmitter should be operated transmitter model of the same manufacture may be be1300and mmallow the zero within its published specifications to1300 maintain mm accuracy. However. In practice. In addition. and the zero is lowered by 1145 used in the spans. and -1145 to -265 mmWC.has a span greater than 400 mmWC and less than 4000 = 3 bar are not raised or lowered ential pressure techniques are commonly applied to many mmWC. Differential pressure not be applicable to the first 200 and mm third examples where LT LT transmitters have specified minimum and maximum the span is 1100 mmWC. for example.10 1000 mm calibrations for interface level measurements. For example.100% Level 0% Level 0 mm LT SG = 1. all of these caliliquid level measurement applications.10where the span is 880 mmWC. Note that these techniques involve applying hydraulics to the installation and application.mmWC. differential pressure measure.10 LT Back to Basics SG = 1. respectively. gravity? These are important questions that should be asked (and answered) when considering the use of differential pressure level measurement zero may also be raised or lowered by up to. brations are within the transmitter specifications. The use of these terms can easily confuse and mislead the practitioner. tween 100 mmWC and 1000 mmWC. respectively. Therefore. (Fill) example mitter may be calibrated with spans between (say) 400 second SG (Fill) and the mmWC and 4000 mmWC. The calibrations in the examples were 0 to 1100.

Some years ago. The maximum flow rate of flowmeters is often specified to be significantly higher than the design flow rate to allow for transients and increased plant throughput over time.10 500 mm Back to Basics 1000 mm LT 0% Level 100% Level Pressure = 3 bar 1300 mm 1300 mm 1000 mm 200 mm LT SG = 1.10 500 mm LT SG = 1. Therefore.0% Level 100% Level 200mm SG = 1. feet. Aside from using incorrect values. Differential pressure measurement is a workhorse of industrial level measurement that’s been used for decades and will continue to be used for decades to come. all being equal. In level measurement. Using the available information properly is another potential problem. This can easily become overwhelming and cause operator errors because plants often have hundreds of vessels.10 Figure 3. distributed control system inputs were incorrectly configured to correspond to the maximum transmitter spans. the differential pressure transmitter subtracts the high side from the low side.8 meters does not readily indicate a problem to the operator even though the vessel overflows at 3. transmitter (1000 mmWC) will usually be more accurate because of the smaller absolute errors associated with other specifications such as temperature. the operator can easily determine that a vessel operating at 93% level might warrant attention and that a vessel operating at 97% may need immediate attention.05 (Fill) SG = 1. In this case. a vessel operating at 2.05 (Fill) LT SG = 1. David W. millimeters or meters increases the potential for error because operators must remember the height of each vessel to put the level measurement in context with the vessel. Using absolute level measurement units such as inches. so using a higher range differential pressure transmitter provides no similar benefit and typically results in additional measurement error that can be avoided by using a lower range transmitter. 38 . the vessel size is fixed. so it should be calibrated -1145 to -265 mmWC to measure liquid levels of 200 to 1000 millimeters above the lower nozzle.0 meters. the levels should have been expressed in percent. On the other hand. pressure and ambient temperature affects.10 SG = 1. Spitzer is a principal in Spitzer and Boyes and a regular Control contributor. For example. it’s generally desirable to use the lower range transmitter to reduce measurement error.

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the magnetic flowmeter is generally considered the most accurate wide-application flowmeter in current use. or magmeter. Magmeters also are made in the widest size range of any flowmeter technology because they can be scaled up almost infinitely. coils are placed parallel to flow and at right angles to a set of electrodes in the sides of the pipe. proportional to the deflection of the magnetic field. generating a standing magnetic field (see Figure 1). we’ve been looking for the one flowmeter that will work in every application. by Walt Boyes E ver since the invention in the 1790s of the Woltman-style mechanical turbine flowmeter. Unfortunately. and magnetic flowmeters account for a little less than 20% of that total. How it is possible to scale up and down this broadly is directly related to the technology. When the fluid (which must be conductive and free of voids) passes through the coils. Michael Faraday formulated the law of electromagnetic induction that bears his name.and abrasion-resistant linings and even clean-in-place (CIP) designs. therefore. and typically vendors supply a size range from ½ in. They do this several times a second. No single flow technology works well. (3048 mm). The first use of the technology was in the huge sluices that drained the Zuider Zee in the Netherlands in the 1950s. They are designed for handling almost all water-based chemicals and slurries and are furnished with corrosion. the one that works in the most applications. Modern magmeters operate on a switched DC field principle to zero out ambient electrical noise and noise actually in the process fluid. then turn the field back on and subtract the off-state voltage from the on-state voltage. What this means is that the voltage induced on the electrodes is directly proportional to the average velocity in the pipe and is. This deflection is the sum of all of the velocity vectors impinging on the magnetic field. across most industries and with higher accuracy than even differential pressure is the electromagnetic flowmeter. measure the voltage that’s still induced on the electrodes.” magmeters do it (nearly) all.Back to Basics Back to the Basics: Magnetic Flowmeters Close to being “Prince Flowmeter Charming. com).7 billion. They turn the field off. there are 12 flow measurement technologies in common use for a very good reason. As used in an electromagnetic flowmeter. The pipe must be non-magnetic and lined with a non-magnetic material. or even acceptably. Magmeters are used in every process industry vertical. which reduces zero drift to almost nothing. How a Magmeter Works In 1831. (12 mm) to 36 in. They’re often used for custody transfer when the 40 . rubber or Teflon. as well. According to Jesse Yoder at Flow Research (www. Of the more broadly based flow technologies. approaching the accuracy of positive displacement flowmeters. (914 mm). In fact. in all applications. significantly more accurate than any other velocity-based measurement principle that only looks at a point or line velocity.flowresearch. with several vendors supplying extended sizes up to 120 ins. such as plastic. Several vendors sell sizes below ½ in. a small voltage is induced on the electrodes. the total global market for flowmeters is roughly $4.

If the pipe fill drops below the line of the electrodes. Using Magmeters Following these simple rules for using magmeters will produce a satisfactory application.5% of measured value from 0. They will not work when the pipe is full of entrained gas or air. there will be significant error. If the pipe is not full.3 ft per sec to 33 ft. They will not work well where the flow starts and stops repeatedly because there’s a lag between the time the flow starts and the correct velocity is read by the meter.1 to 10 m/sec) velocity. saline brine or seawater. Finally. This means that (again with the exception of some units that are specifically designed to be very fast) magnetic flowmeters don’t work well in short-duration batching operations. it’s not wise to use a magmeter on a fluid whose conductivity is this low. they can produce a high-precision mass flow measurement. and the flowmeter will read in error. This changes the computed volume of the pipe and changes the volumetric flow through the meter in an uncontrolled fashion that’s proportional to the amount of bubbles (or void fraction) in the pipe. it will not read at all. magmeters have trouble working on fluids with extremely high or highly variable conductivity. for example. they will not work on non-conductive fluids or on gases at all. Typical accuracy of a magnetic flowmeter is 0. (nominally 300 mm). at very low flows. Very often. Most important. but when combined with an ancillary density measurement device. In practice. Some vendors indicate even higher accuracies over portions of the flow range. Where Magmeters Won’t Work Magmeters have such a wide application that it’s easier to say where they will not work than to list all the applications in which they will. except for specially-designed units. They don’t read out in mass flow units. Applications like this are designed with a u-tube in the line. This combination of devices is used to measure mass flow where the pipe size is larger than 12 in. One of the most common application failures of magnetic flowmeters is on a gravity-fed line discharging to atmosphere in a tank.1% of indicated flow rate.Back to Basics flow is of relatively long duration. They will not work when the pipe is not full (with the exception of several versions designed specifically for this application). The velocity deflects the standing magnetic field and induces a voltage on the electrodes that is proportional to velocity. up to 0. Figure 1. which is supposed to keep the pipe full at all times. per sec (0. The minimum conductivity of a fluid is 5 μS (microSiemens) before a magnetic flowmeter will measure its velocity. 41 . the pipe is actually not full.

the insulating properties of the buildup can either reduce Yes No Discharge into an open tank is not a good design Figure 2. Magnetic flowmeters have become one of the most widely used flow technologies in the 50 years since their first introduction. causing potential hazard. Both Teflon and polyurethaneare de-rated for pressure at the upper end of their temperature range and will deform if overheated. Although a magmeter will operate over the entire range from 0. Right Sizing. One way to make sure you have a fully developed flow profile moving through the meter is to mount your magmeter so that the flow is through the meter in the vertical direction. Magnetic flowmeters are designed to work at moderate temperatures and pressures and should not be stressed. Proper Grounding. 42 using magmeters . and if necessary. and no diameters of straight run downstream. often as little as three diameters upstream of the electrode plane (the centerline of the meter body.09 to 10 meters per second) velocity. Flow Straight Run. Some basic rules of thumb for Walt Boyes is a principal with Spitzer & Boyes. The electronics are susceptible to interference if they’re floating above ground. it isn’t wise to install a magmeter that’s going to operate permanently at the lower end of that range. Magmeter vendors all have grounding procedures. Magnetic flowmeters need less straight run than most flowmeters. 5D downstream Flow the voltage or break the circuit entirely. because the vacuum can pull the lining right out of the meter. Spiraling flow causes severe inaccuracy in a magmeter. They’re simple. they can operate for years without maintenance.3 fps to 33 fps (0. usually). install a properly designed meter run. easy to maintain. which you ignore at your peril. But sometimes. Magnetic flowmeters should not be operated where a vacuum can be pulled inside the flow tube when there is a pressed-in polyurethane or Teflon lining. This helps in cases of spiraling flow and also helps reduce air entrainment. Temperature and Pressure. Vertical Mounting. For example. It’s better to size the flowmeter for a normal flow that’s about 60% of maximum for that pipe size. Either will cause inaccurate readings.Back to Basics Good 3D upstream. spiraling flow (swirl in the pipe) can propagate for hundreds of diameters after a three-dimensional turn in piping. sometimes as much as 40% of measured value. and because they have no moving parts. a better choice is to go with as much straight run as you can get. 1D downstream Better 10D upstream. This can cause buildup of solids inside the flow tube and sometimes on the electrodes themselves. The pipe section of the magmeter needs to be non-conductive for the circuit to work. and if buildup occurs on the electrodes. If buildup occurs inside the flow tube. the calculated volume is now in error.

by Walt Boyes L can empty and clean them. the answer to all of these applications has been the proper application of a gamma level gauge. (25 mm) of steel. Designing to Fit In order to figure out how much energy will reach the detector. has a big agitator in it. rising material would simply trigger a relay if the energy beam were interrupted. has a level application that is both critical and difficult. and has both a jacket made of 1-in. and extruded glass. Worse yet. engineers came up with the idea that rising material or liquid would change the amount of energy reaching a detector on the other side of the vessel from an emitting source. In the case of a point level switch measurement (Figure 1). (1. Oh yeah. and fly ash is very hot and also acts like concrete and sticks to everything. In the case of a continuous level measurement (Figure 2). You’ve even tried weigh cells. so it must flow by gravity down a firebrick-lined channel to where it is cast or molded or extruded. with all that tare weight. Your requirement is that you have to measure the level of the molten glass and control it to ±0. but anything you stick into the hopper just gums up and fails so fast that you have given up. What do you do? You are responsible for the air pollution control system for a very large coal-fired power plant. You need some way to tell when the hoppers are full. you can’t drill any holes in it either. Glass castings have holes called holidays in them. causing international pollution incidents and costing your utility millions in air-pollution-control violation fines. cuts the energy from a gamma beam by 50%. The glass is produced by melting silica sand. if not impossible. you must measure the level in the vessel with significant precision. (25-mm) copper cooling coils and a 4-in. glass-lined. glass frit from recycled bottles and some trace minerals in a very hot furnace with firebrick walls that are over 1 ft (300 mm) thick. and when the level fell.013 mm).0005 in. the rising material would cause a decrease in the intensity of the energy beam reaching the detector that could be calibrated to be proportional to the rise in level. but there isn’t enough precision to just weigh the contents of the reactor. (±0. for example.Back to Basics The Right Tool for Tricky Measurement Jobs Gamma nuclear level gauges handle the toughest applications. or the process doesn’t work. It is 6 ft. and since it is a glasslined and code-stamped vessel. (100-mm) layer of insulation covered with thin steel lagging. suppose you’re making glass for a variety of products. whether tube or sheet. to measure. What do you do? Or. Very early on. then the energy would likewise increase. What do you do? Sound familiar? Nearly every plant. and you can’t stop the reactor to modify it. But the hoppers that hold the precipitated fly ash keep plugging up. has flaws and holes. from mining to wastewater and every process vertical in between. so you Enter the Gamma Level Gauge Since the 1950s. there are no accessible entrances into the top of the vessel that aren’t already being used for something. The glass is too hot to pump. You have electrostatic precipitators that remove the fly ash from the stack gas before it gets released into the atmosphere. essentially all you have to do is to add up the densities and thicknesses of all the materials between the energy source and the detector.8 m) in diameter. Gamma gauges work based on both the inverse-square law—radiated energy decreases with the square of distance—and the fact that dense materials absorb gamma energy—1 in. For the process to work. et’s say you have a reactor vessel. and make the energy beam intense 43 .

enough to pass through all that material and reach the detector. Rising material decreases the intensi- Figure 3. ty of the energy The blades of the agitator need to be considered. not forgetting the air gap between the walls of the vessels—air has density. a manufacturer of gamma level gauging products. There’s a lot of firebrick on either side of the glass channel. The way to do this application is to “shoot a chord” of the vessel’s diameter—that is.” All manufacturers of gamma level gauges have software that makes the calculation of energy source size straightforward. “Modern detector designs have made it possible to use significantly lower activity sources than in previous years. This is not quite as easy as putting a source and a detector across from each other because there are vessel internals. and. Rising material triggers a relay if the Figure 2. Now let’s look at the glass level gauge. Here the apex of the triangle is energy beam is interrupted. It just makes the signal noisy. eliminated by shooting the chord between the blades and the vessel wall.berthold. If that isn’t possible. aimed at the point detector. so it may be necessary to drill holes in the firebrick to reduce its thickness. that have to be missed.Back to Basics Gamma Point Level Switch Continuous Level Measurement Strip Source and Point Detector Figure 1. Gamma energy does not cause any of the measured product or the vessel to become radioactive. business unit manager of Berthold Technologies USA LLC (www. in most cases. You or the vendor plug in the numbers for the thicknesses and densities of the material.” says Mick Schwartz. Gauging in the Real World So let’s look at how to do the level application in the jacketed vessel we talked about earlier. put the source and detector off to one side of the diameter. This will cause the temperature on the outside to rise. if possible. many gamma level gauges can be programmed to ignore the repetitive density fluctuation caused by blades swinging into and out of the beam. the source activity that will be required will be greater by some amount than shooting the diameter would be. including an agitator. Because the thicknesses that the energy beam will shoot through will be greater. “This means that the risk of exposure to gamma energy for personnel is minimized and amenable to proper safety precautions. so the 44 . and energy decreases with the square of distance— and the software spits out an optimized energy source size and. Safety requires that the intensity of the energy beam be designed to be as small as possible and still make the measurement. the appropriate housing design and detector selection.

“The holding tank is 38 in. “the diaphragm seals would become coated due to the temperature of the product.processresource. “I was looking for a level system that wouldn’t be affected by the properties of the product due to the thermal processing. while the gamma level gauge remained constant..ingomarpacking. “The installation was made much easier with the help of all the individuals from Berthold. [Process Resource Inc.” Point level switch in a hopper Figure 4.” Fontes goes on. which would control the level in a holding tank. Fly ash hoppers are classic examples of this kind of application.Back to Basics How to Measure a Tank of Tomato Paste Larry Fontes.134 at 210 ºF to 215 ºF (a little over 100 ºC) at a flow rate of approximately 250 gallons per minute. Third. The energy activity of the source must be sized. Next is a strip source that is characterized to produce a similar shaped beam. In point level applications (Figure 4). corrosion. maintenance and production supervisor at Ingomar Packing Co. detector must be water-cooled to bring the internal temperature of the electronics down to the normal range. so I was somewhat familiar with the technology. perhaps as much as a couple of inches. (www. Calif.” Fontes reports that the problem became so severe that product spilled out the vent on top of the tank. including radar. there is the geometry of a strip source and a strip detector. such as vertical risers. www. A narrowly collimated conical beam is aimed across the vessel at the point detector.” Fontes says.1 m) tall. “We had used a [gamma] device to measure soluble solids from Berthold in Los Banos.” Fontes reports. Fontes looked into other level technologies.” And how has it worked out? “Since the installation of the Berthold level gauge (Figure 5) in 2007.” Fontes continues. Berthold worked with the consulting engineer we had contracted for the expansion of our aseptic processing system. This geometry is often used for highly precise level measurement on small diameter vessels or pieces of pipe. abrasion. 45 . We operate the gauge under the general license in the Code of Federal Regulations. the reason a gamma gauge is being used is because the inner walls of the vessel are subject to vibration. uses a gamma level gauge on a very difficult food industry application. The product inside the tank is tomato paste with a specific gravity of about 1. There are three geometries that can be used in continuous gamma level measurement. “We were using a dual remote diaphragm seal system with chemical T diaphragm seals and a 4-20 mA DC HART transmitter to control a valve. but with the apex of the triangle at the point detector (Figure 3).com] “Berthold provided onsite start-up and training for myself and several of our operators.” he says. The dual diaphragm system level indication began to drift.” “After a 100-day processing season. In most point level applications. the source produces a narrowly collimated conical beam that is aimed across the vessel at the point detector. “we have had instances during a couple of processing seasons that would have resulted in the same issues as before.. and the level indication would begin to drift as the diaphragm was unable to pick up the change in pressure as the level changed. The most common is a point source that is collimated to produce a right-triangle-shaped beam with the 90º angle at the top of the detector. or fouling or coating with material. so that the point level gauge continues to work correctly through a reasonable thickness of fouling or coating. (nominal 1 m) in diameter and about 30 ft (9. while the transmitter reported little or no change in percent level.

They will operate with fewer maintenance headaches and. gamma level gauges are required to be licensed. “Many gamma level gauges can be distributed under the So There You Have It Gamma level gauges are a good long-term solution to many of the most difficult level applications you will run into. but has restrictions on gauge geometry.” says Berthold Technologies’ radiation safety officer (RSO). paperwork and rules have to be known. licensed person is required to change the geometry of the gauge or to move it. However. Walt Boyes is a principal with process measurement consultancy Spitzer & Boyes. in some cases. shielding. No license is required by persons doing that level of maintenance. Fontes concludes. and the U. operate where nothing else will. as the gauge owner. maintenance on source housings is minimal. NRC plans to do away with it in one to three years anyway. even the smoke detectors in your house. And when you aren’t using it anymore. take title to it (so you and your management don’t have to keep track of it forever). 46 .3 million expansion to the flash cooler. exposure levels. The Business of Using Gamma Level Gauges Similar to every other device that uses nuclear byproduct material. The other kind of license. understood. During a 100-day processing season. This means that applications. can be done by any plant-qualified instrument tech or maintenance tech. and send you a document saying that you are no longer responsible for it. “but the general license does not exist in other countries. the gamma level gauge remained constant. licensing can be relatively simple and not too onerous. Since a gamma energy source is basically a steel-jacketed lead box with a capsule the size of a horse-pill inside of it. which is part of our aseptic processing. once you are set up to do this. you are required to dispose of it properly—not just send it to a junkyard. including the detector. So what does this mean for operations and maintenance? Maintenance on the electronics. followed and kept current. are licensed to do several specific things with the gamma level gauge you own. Continuous level gauge on tomato-filled column Figure 5.” This means that you. Knowing these simple rules in advance can mitigate management’s reluctance to undertake a new regulatory duty. and other environmental health and safety issues. “The Berthold level gauge installation was part of a $1. A trained.Back to Basics general license in most states in the United States. used globally as well as in the United States is called a “specific license. The NRC plans to make the specific license procedure simpler and more streamlined.” The general license has less paperwork. Mark Morgan.S. in favor of specific licensing. Most manufacturers of gamma gauging instruments will accept a returned source.

This sometimes creates difficult situations. pitot. • Utility and circulating pumping of dielectric fluid into underground electrical cables in order to dissipate heat generated by high-voltage power lines. Accurate flow measurements ensure the safety of the process and profits in plants. Bidirectional Flow Measurement Using Volumetric Flowmeter Options The selection process of bidirectional flow metering depends on application requirements. Coriolis. but some will be bidirectional. they are always difficult. Better measurement can only be achieved by selecting the best/most suitable flow technology for each flow application. Bidirectional Flow Measurement Bidirectional flow lines are not very common in refineries and petrochemical plants. along with the turndown factors. etc). For bidirectional flow. challenges. • Gas injected or withdrawn from the gas storage field or reservoir. end-user accuracy requirements and physical design constraints of the flowmeter itself. limitations. The challenge is to find out the value of the product stream being measured. Most of these applications will be unidirectional. thus providing the most reliable and cost-effective solution to the end users. We will further discuss the selection of the appropriate metering for bidirectional situations and applications. such as regular flow control (steam. the Venturi or wedge element. advantages and disadvantages. process interruptions and/or measurement inaccuracies that can significantly affect the production and profitability of the plant. maintenance and installation costs. Criticality of flow measurement in the plants has become a major component in the overall economic success or failure of given processes. and others. Instances where a bidirectional flow measurement is required include • Possibility of having two different flow rates in either 47 . vortex. process flow rates. such as DP transmitters with an orifice. the piping scheme uses the same line to accomplish delivery and/or control functions for flows moving in opposite directions (forward or reverse flow). is available for various flow applications. gas. process demand. ultrasonic. and • Chilled water plant decoupling headers.Back to Basics Bidirectional Flow Measurement The right flowmeter Is a balance between technical needs and cost-efficiency. Sometimes the accuracy required by the end users is the most significant factor for the specific application. turbine and magnetic flowmeters. utilities. by Ruchika Kalyani F low measurement plays a critical role in chemical. but if they are needed. depending upon the process conditions and objectives. oil and gas plants. Instrument engineers should convince the end user to not install a flowmeter that is more expensive than the yearly value of the stream and the potential loss of money caused by inaccuracies. but the bidirectional flow measurement capability is required to measure the flow rates within the same flow loop in opposite directions. • Bidirectional steam lines supplying steam from one unit to another unit in the plant. Various flowmeters are available with bidirectional flow capabilities. The measurement of unidirectional flow rate is possible with all types of flow technologies. A diverse range of flowmeters. Examples of bidirectional flow are • R aw water feed to two or more water treatment plants. petrochemical. • Purging and blanketing of nitrogen in plants. fiscal or custody-transfer metering.

In this case. This must be clearly communicated to the piping design team during design reviews and before construction begins. With this combination. are the best solution for measuring the steam flows in/out of the plant. zero flow point will be a calculated value. The square root function is complicated by the one-transmitter option because reconfiguration of the transmitter signal (4-12 mA and 12-20 mA) requires added function blocks and. It’s also necessary to make sure of the full “upstream” straight lengths on both sides of the flow instrument. can 48 . In cases where it’s only a matter of knowing the reverse flow direction. or by using the built-in capability of the flowmeter to be used in both forward and reverse flow directions. transmitters are equipped with a feature that allows reconfiguration of the DP transmitter range. Bidirectional Flow Measurement with a Single DP Transmitter A single DP flow transmitter coupled to a primary element option. the other unit will supply the required steam to the deficient unit and vice versa. meter installation requirements and the complexity of signal switching. additional hardware. can be directly applied to the transmitter by either installing special bidirectionality software at the control system side. 4mA is shown. then the existing DP set without configuration can be used. If reverse and forward flow rates are identical in both directions. flow direction will be indicated as the output value (4-12mA = Reverse and 12-20 mA = Forward). This arrangement will cut down the expense of installing another (second) DP transmitter. • T he need to measure reverse flow in the process. At zero flow. then dual transmitters. along with temperature compensation. and precise accuracy is not required. for example. and for unequal flow rates. subsequently. square-edge type orifice plate should be used. and accuracy is not important. • Bidirectional flow measurement using dual DP transmitter options. corresponding function blocks or logic at the distributed control system (DCS) side. one for each flow direction. due to the process and design conditions.or five-day period. such as square root functions. For bidirectional flow measurement between two process units in a process plant.Back to Basics also be adopted for cheap reverse-flow measurement. and the two edges of the orifice should comply with specifications for the upstream edge mentioned in the ISO 5167 standard. and an output less than 4 mA can be used to alarm for reverse flow even when the square root function is on. The bidirectional function. smarter flowmeter techniques. such as the special orifice plate mentioned above. orifice plate. do not expect high accuracy and turndown. Bidirectional Flow Measurement with Vortex Flowmeters The other option of two vortex flowmeters can also be used for steam bidirectional flow if higher accuracy is required than can be achieved using the orifice solution. direction. • Reverse-flow accuracy is required by end user or by the process. and both flows need to be measured. With equal flows. as it is easy to maintain and replace. a non-beveled. Two DP transmitters with an orifice plate. such as split-range output signal (4-20 mA) to the system side (DCS. this dual transmitter combination option will be ideal in cases where the transmitter will experience reverse flow once every four or five years for a four. Also. With newer. zero flow point is established based on the DP range of forward and reverse flow. With equal or unequal flow rates. can be used for the bidirectional flow. when two steam units are linked to each other. at the time of deficiency of steam in one unit. PLC). This combination will provide the lowest installed cost with acceptable accuracy.

Back to Basics

However, this application is limited to smaller line sizes
because vortex meters are more economical up to 4-in.
(100-mm) pipe size. Beyond this size, orifice plates are
more economical. In addition, the selection of a vortex-shedding flowmeter may increase the maintenance
and installation cost.
Wherever higher accuracy is required, vortex flowmeters are not a good option, as vortices shed by both bluff
bodies propagate really far beyond the pipe and may affect the other meters’ readings. Another drawback is that
the straight pipe run distance required between two vortex meters is unpredictable. For example, in the case of
no obstructions, the meter required the run of 10 D (diameters) to 15 D, and if there is a control valve in either
direction, the meter may require a higher run of 25 D to
30 D or even more. In comparison to the options of dual
transmitters for bidirectional flow measurement between
the two process units, DP flow measurement may be the
most cost-effective solution.

changes. In this application, turbine flowmeters can provide the solution for bidirectional flow measurement
with moderate accuracy. However, drawbacks associated
with this technology include a poor response of the flowmeter at low flows due to bearing friction; lack of suitability for high-viscosity fluids because the high friction
of the fluid causes excessive losses; as well as the requirement for regular maintenance and calibration to maintain its accuracy.
The magnetic flowmeter can also be used for bidirectional flow measurement. It has the advantages of no
pressure drop, linear output, short inlet/outlet pipe runs
(five diameters upstream of the electrode plane and two
diameters downstream), and good turndown. Magnetic
flowmeters are relatively expensive and are mainly limited to conductive fluid applications, such as acids, bases
and slurries, as well as water. A pre-requisite for this type
of flowmeter is that the fluid is electrically conductive
with an absolute minimum conductivity of 2-5 µSiemens.

Bidirectional Flow Measurement with
Turbine and Magnetic Flowmeters
Bidirectional flow measurement is always a challenge
when there are changes in process parameters, such as
viscosity, conductivity, etc. It is always worth keeping
these specific situations in mind while selecting any
flowmeter technology, but with bidirectional flowmeter
applications, it is especially important. DP type meters
are usually not really well-suited to handle these process
parameter variations.
Again, an example is utility pumping and circulating plants pumping dielectric fluid into underground
electrical cables in order to dissipate heat generated by
high-voltage power lines. This application requires flow
rate monitoring upstream and downstream because it
involves dielectric fluid; therefore, it requires viscosity
compensation as the temperature of the dielectric fluid

Bidirectional Gas Flow Measurement with Ultrasonic Flowmeters
At gas storage fields or natural gas reservoirs, accurate
gas flow measurements are required for tasks such as injection and withdrawal of gas from these reservoirs. Reservoirs are used as buffers between suppliers and consumers. In order to maintain the balance for the entire
reservoir, it’s necessary to monitor bidirectional flow at
the wellhead.
For this purpose, conventional DP flowmeters with an
orifice are far from a suitable solution, as they lack accuracy and reliability. Orifice plates are subject to wear
and tear. Secondly, regular inspections and maintenance
are required. While measuring the dirty gas, the pressure
taps of the orifice plates are particularly exposed to clogging due to the solid particles which may be present in
the dirty gas. These will definitely distort the accuracy of

Back to Basics

In these cases, an ultrasonic flowmeter may be a far
better solution because this type of flowmeter has no
pressure drop, no flow blockage, no moving parts, and is
suitable for high-volume bidirectional flow and also for
low-flow measurements where other types of flowmeters
do not provide the required results.
The advantage of using the clamp-on gas flowmeter
transducer on the outside of the pipe is that it doesn’t
require any pipe work or any kind of process interruption. With this type of flowmeter even a little moisture
content present in the gas can’t significantly affect the
The reliability, negligible maintenance with highest
accuracy and long-term cost of ownership are the major
benefits of this technology.

drawbacks of volumetric technologies, such as the requirement for significant upstream and downstream
straight piping length and the reduction of potential errors that occur in compensation for temperature, pressure, viscosity or specific gravity. The Coriolis mass flowmeter technology does not require that compensation.
Coriolis meters measure mass flow. They do have their
own inaccuracies, but these tend to be low relative to
other types of flowmeters. The turndown of Coriolis meters is high compared to other types of flowmeters. Another advantage is that no recalibration is required when
switching fluids or for changing process conditions.
Purchase Price vs. Cost of Ownership
It’s important for control system engineers to evaluate accuracy required for applications before selecting any bidirectional flowmeter technology, as more accurate and
precise flow measurement often results in higher cost of
the flowmeter.
The control system engineer must understand that
price is always the consideration. However, there are
some important distinctions to be made in terms of
price. A flowmeter can have a low purchase price, but
can be very expensive to maintain. Alternatively, a flowmeter can have a high purchase price, but will require
very little maintenance. In these cases, the lower purchase price may not be the best bargain. Other components of price include the cost of installation, the cost of
associated software, the cost of training people to use the
flowmeter, the cost of maintaining the meter, and the
cost of maintaining an inventory of any needed replacement parts. All these costs should be taken into account
when deciding what flowmeter to buy. This should be
the one reason for many users to look beyond purchase
price when considering flowmeter costs.

Bidirectional Flow Measurement with Coriolis Mass Flowmeters
In the process industries, Coriolis technology has set the
standard for flow and density measurements. This technology is used for various applications, such as mass balance, monitoring of fluid density and custody transfer,
but also to reduce maintenance, and for bidirectional
flow measurements.
In refineries, there are bidirectional applications, such
as import and export of product, product transfer to storage and to petrochemical plants, and where the accurate
measurement is more important than cost.
Coriolis mass flowmeters can be used for accurate and
reliable measurements of all streams in and out of the
plant. This is critical for accounting and profitability.
End users should take into account that inaccurate measurements sometimes may cause them to give away more
product than they are being paid for. This can result in a
significant loss of profit.
Conpared to the traditional use of volumetric flow
technology for bidirectional measurements, the use of
Coriolis mass flowmeters eliminates various well-known

Ruchika Kalyani is a control system engineer at Fluor Daniel India Pvt Ltd.


Back to Basics
Back to Basics: Ultrasonic Continuous
Level Measurement
Ultrasonic level is one of the five non-contacting continuous level measurement technologies,
and the one that is most often misused or misapplied. Here’s how to do it right.
by Walt Boyes


he five non-contacting level measurement technologies are radar, nuclear, laser, weight and ultrasonic.
Each of them has both good points and bad. Radar, for
example, is relatively expensive in the more accurate versions (frequency-modulated, continuous-wave, FMCW),
while nuclear level is limited to relatively small vessels,
and there are licensing and safety considerations. Lasers
appear to have developed an application niche, especially
in the measurement of bulk solids and powders. Weighing
systems can be used in some vessels, but it is, again, a relatively niched application solution. Of all of these, ultrasonic level measurement is the most widely used non-contact technology. Ultrasonic level transmitters are used in
most industries and are very widely used in open-channel
flow measurement systems, sited atop a flume or weir.

Cutaway mounting


6° cone beam

How Does It Work?
Ultrasonic level sensors work by the “time of flight” principle using the speed of sound. The sensor emits a high-frequency pulse, generally in the 20 kHz to 200 kHz range,
and then listens for the echo. The pulse is transmitted in
a cone, usually about 6° at the apex. The pulse impacts the
level surface and is reflected back to the sensor, now acting
as a receiver (Figure 1), and then to the transmitter for signal processing.
Basically, the transmitter divides the time between the
pulse and its echo by two, and that is the distance to the
surface of the material. The transmitter is designed to listen to the highest amplitude return pulse (the echo) and
mask out all the other ultrasonic signals in the vessel.
Because of the high amplitude of the pulse, the sensor
physically vibrates or “rings.” Visualize a motionless bell
struck by a hammer. A distance of roughly 12 in. to 18 in.

Signal echoes
from surface

ultrasonic sensor
Figure 1. The sensor sends pulses toward the surface and receives
echoes pulses back.


The change in ambient temperature is usually compensated. you may get a spurious high amplitude echo that will swamp the real return echo from the surface of the material. Most sensors come with a PVC or CPVC housing. PVDF. Hard-conduit-wiring an ultrasonic sensor can increase the acoustic ringing and make the signal unusable. sometimes so much that there is no longer enough power to get through the coating to the surface and back. Sometimes you can do this with an additional waveguide. Make sure that the operating temperature range of the sensor is not exceeded on either the high or low temperature end. 52 . Make sure the materials of construction of the sensor housing and the face of the sensor are compatible with the material inside the vessel. Some transmitters provide a signal “figure of merit” that can be used to detect coatings or other signal failures and activate an alarm function. called the “blanking distance” is designed to prevent spurious readings from sensor ringing. In some cases. 6.” that can compensate for the effects on the echo of the agitator blade moving in and out of the signal cone. Always use the vendor-supplied mounting hardware for the sensor. If you can’t. If it isn’t possible to avoid coatings. Locate the sensor so that the face of the sensor is exactly 90° to the surface of the material. Coatings attenuate the signal. try to provide some means of cleaning the sensor face. this can be modified (and this will be discussed in a later section of this article). The materials of construction may deform or the piezoelectric crystal may change its frequency if the temperature range is exceeded. either by an embedded temperature sensor. This is especially important in liquid and slurry level measurement. In some bulk solids measurements.Back to Basics (300 mm to 450 mm). Mount your sensor where it can’t be coated by material or condensation inside the vessel. 7. your echo will either be missed entirely by the sensor. 2. make sure you purchase a transmitter Vortex from agitator installation issues Figure 2. Sometimes the measured value is “what the level would be if the agitator were turned off. If they do. Make sure that the vessel internals do not impinge on the pulse signal cone from the sensor. a housing of aluminum or stainless steel with a polymer face can be provided. Motor driven agitator Physical Installation Issues There are some important physical installation considerations with ultrasonic level sensors. or it will use an echo that is bouncing off the vessel wall or a vessel internal structure instead of the real level. PTFE (Teflon) and PFA (Tefzel) are usually available. This is important for installation in areas where the distance above the level surface is minimal. 5. 1. Most ultrasonic sensor vendors provide a wide selection of sensor materials of construction in case the standard sensor housing isn’t compatible. Make sure you avoid agitators and other rotating devices in the vessel. 4. If you do not do this. 3. a remotely mounted temperature sensor or a target of known distance that can be used to measure the ambient temperature.

where air or another gas is introduced into the vessel by means of diffusers or spargers. the sensor was regularly reading 80% to 100% because the early summer heat had caused the vapor blanket to fill the tank. This is not a real measurement. In some cases. We replaced the ultrasonic 53 . This “ghost level” phenomenon is a function of the volatile liquid in the tank. Intermittent echo can sometimes be dealt with using a sample-and-hold circuit or algorithm in the transmitter so that the level doesn’t change until the next good echo. 2. when the customer reported that the sensor was insisting that the level in the tank was several feet higher than it actually was. however. as in the case of a vessel where the level is quite near the maximum fill point. Second. Try to avoid agitated tanks even when the agitator is below the surface of the material. 3. Sparged tanks. Agitation can produce whirlpools or cavitation. that can be dangerous. foam. A false echo can occur from somewhere in the foam layer. Third. foam can provide a false reading of the true level. Bubbles. Avoid foam. A layer of bubbles or foam can attenuate the signal either entirely or partly. The sensor was installed in early November. yet still be a high enough signal to fool the transmitter. rather than either the surface of the foam or the surface of the liquid below the foam (Figure 3). I sold an ultrasonic transmitter to a major northeastern United States utility for the measurement of level in huge bunker oil tanks. and it worked acceptably well until mid-May of the following year. the agitation may be so extreme that the measurement you are trying to make is “what the vessel level would be if the agitator was turned off ” (Figure 2). By late June. Vapor layer Internal structures Foam layer Sparger Bubbles from sparger challenges at the outer edge of the envelope Figure 3. they’re often used at the outer edge of the application envelope. It is more insidious if it only attenuates the signal partly. instead of the actual oil level in the tank. 1. It is good to avoid this application. the vapor blanket on top of the bunker oil began to become more dense and increased in height. can cause bubbles or foam to form on the surface of the material. it can attenuate the signal so that there is no echo or only an intermittent echo. and erratic or erroneous signal and signal failure often result. Sometimes. The ultrasonic sensor picked up the top of the vapor layer. there will be no echo return. instead of the actual level. Avoid volatile liquids. which may attenuate the signal or cause it to bounce off a vessel wall. Foam can do three things to the accuracy of the level measurement. vapor and internal structures make ultrasonic measurement very difficult. Back when I was in sales. As the ambient temperature rose. and the sensor may receive an echo that has made one or two hops against the side of the vessel. If it attenuates the signal entirely. foam clumps can cause the echo to be deflected away from the vertical. First. 4.Back to Basics Motor driven agitator Application Considerations Because ultrasonic level sensors and transmitters are inexpensive and usually easy to install. and it may not be possible to make it with any degree of confidence or accuracy. and all of them are bad. You can get a reading from inside the foam layer.

134. The primary device (flume or weir) measures flow. which worked correctly. 5. 5. You may want to aim the sensor because of rat-holing and angle-of-repose issues at the top. Make sure that there is not too much turbulence or ripples (or if the flume or weir is large enough. if you follow these basic guidelines. The flow transmitter takes the level signal and produces a flow value based on the primary device. The level sensor works exactly the same way—measures level. But. as well as front to back through the measurement zone. Walt Boyes is a principal with process measurement consultancy Spitzer & Boyes. It’s easy to go to them as the unthinking sensor of choice for level applications. applying an ultrasonic level sensor too far outside the manufacturer’s recommended application envelope is destined to fail. ultrasonic sensors and transmitters are tricky beasts. 6. The speed of sound changes with temperature and density. 2. and pressurizing the vapor space above the level can affect the density of the vapor space and. Avoid wind and sun. 4. As with any other field instrument. Sun can raise the temperature of the sensor housing itself beyond the operating temperature range of the device—and higher than the ambient temperature. Most of the same caveats apply to ultrasonic level sensors used as flowmeters as apply to ultrasonic level sensors used as tank level measurement devices. therefore. 54 . and sometimes fail spectacularly. and I learned something. Make provisions to keep ice from forming on the sensor open-channel flow Figure 4. Try to have the transmitter calculate what the actual level might be. make sure that the flume or weir is installed correctly. Wind can blow through the vapor space and attenuate the signal or blow it off course. Make sure that there isn’t foam on the surface. There are a few more: 1. Above all. as many users have found. Many problems blamed on the ultrasonic transmitter are actually problems that are caused by the flume not being installed level both horizontally and vertically. just as many people go to differential pressure level sensors. in the winter or dripping condensation in the summer.) 6° beam Channel Ultrasonic Open-Channel Flowmeters One of the most important applications for ultrasonic level sensors and transmitters is measuring open-channel flow (Figure 4). wave action) on the surface.Back to Basics sensor with a FMCW radar sensor. you may have to aim the sensor at a point that is not 90 degrees to the level surface (perpendicular to the vertical axis of the vessel).56 Flow transmitter Parshall flume (typ. Yet. 3. the speed of sound. The One-Trick Pony—Not! Ultrasonic sensors are simple to understand. This can happen often in nitrifying wastewater discharges. At least one vendor has developed a multiple sensor array that can scan the angle of repose and determine what the actual filled volume of the vessel is. Avoid pressurized tanks. midpoint or bottom of the angle of repose. you will have successful ultrasonic level installations. In solids and powders. easy to install and inexpensive.

flow studies have shown that in a pipe with a fully developed flow regime. Turbulent flow. occurs between about 2500 and 4500 Reynolds numbers. propeller. either fully turbulent or fully laminar. the average velocity in the line can be found at a point somewhere between 1/8 and 1/10 of the way in from the side wall. there is some evidence for David W. Propeller meters use a prop shaped very much like an outboard motor’s propeller and are generally connected How Does This Work? In Figure 1. and are more accurate at lower flow rates as well. depending on the flow study you read. which allows the sensor to be inserted and retracted without shutting down the flow or relieving the pressure in the pipe. and come in technology variations that mimic full-pipe meters. Spitzer’s claim in his book Industrial Flow Measurement that insertion flowmeters are a type all their own. Paddlewheels range from very inexpensive to inexpensive. The least expensive use polymer bearings. Some paddlewheel sensors can be inserted into the pipe using a hot tap assembly. vortex and differential pressure sensors. you see turbulent flow and laminar flow. which is a dimensionless number relating to the ratio of viscous to inertial forces in the pipe. while turbulent flow profiles are seen as plug flows. The best use jeweled bearings and ceramic shafts. turbine. 55 . Hall-effect sensors generally are able to read lower flow rates. magnetic. These are based on the concept of the Reynolds number. The first is a paddlewheel because the rotor is parallel to the centerline of the pipe. and are designed to be disposable. The advantage of the magnetic pickup is that it generates the sine wave without additional power. But with no exceptions. and cause the rotor to wobble before the rotor shaft cuts through a bearing and goes downstream. Insertion flowmeters are popular in many industries. just like a paddlewheel steamboat. vortices and swirls in the pipe. In fact. which go out of round. The spinning of the rotor is sensed by either a magnetic pickup that generates a sine wave the frequency of which is proportional to velocity.effect sensor is that it does not cause “stiction” (the momentary friction stop when the rotor sees the magnetic pickup’s magnet). Paddlewheel flow sensors are designed to be easily inserted into a small hole cut into the pipe using a custom fitting. so they have much more longevity and less drag. where the flow profile is straight and smooth. where there are eddies. The advantage of the Hall. or a Hall-effect sensor that generates a proportional square wave. occurs above 4500 Reynolds numbers. Without getting too far into the math. insertion flowmeters are not the same as their full-pipe counterparts. inexpensive. Insertion Paddlewheels. Laminar flow profiles are usually visualized as being bullet-nosed. because they appear to be easy to install. Propellers and Turbines There are three very similar types of insertion flowmeters that use a rotor that spins with the velocity of the fluid. by Walt Boyes Y ou can get flowmeters in insertion versions that are paddlewheel. occurs at Reynolds numbers of less than about 2500. which is neither fully laminar nor fully turbulent. but they all share similar characteristics and problems.Back to Basics Stick It! Insertion flowmeters come in many varieties. Transitional flow. Laminar flow.

this is called a “corporation cock assembly. Electronic paddlewheels and turbines can be set up to be bidirectional. Like paddlewheels. the differential pressure sensor is connected to a pitot tube inserted in the flow stream. Laminar flow from 0 to 2500 Rn. so they can be inserted through a small-diameter fitting or through a small diameter. either in potable water systems or in irrigation systems. and hot or cold fluids. which uses the pulse (or frequency) output to display flow rate and to increment a totalizer (usually electronic). using quadrature detectors. Sometimes. Because propeller meter rotors are large and located at the centerline of the pipe. which exists somewhere between 1/8 and 1/10 of the inside diameter away from the pipe wall. Like paddlewheels. Propeller meters. because their prop is significantly larger than a paddlewheel.” but it is essentially the same thing—a way of inserting a probe through a valve and still maintaining the pressure in the pipe without leaks. Turbulent flow from 4500+ Rn. bases. are inserted using a flange that mounts into the upright member of a tee fitting. In its insertion incarnation. These can be used as flow alarms. Propeller meters are almost always used for water service. propeller meters have a pulse output that is proportional to the average velocity in the pipe. dead-band controller.Back to Basics to a mechanical or electromechanical totalizer with a cable very much like a speedometer cable. they must be inserted to the “average velocity point. Most insertion turbine meters have very small rotors. and often have one or two programmable relay contact closure outputs. These are often used in HVAC applications where chill water and hot water flow through the Laminar Flow Turbulent Flow Fully Developed Flow Figure 1. hot tap assembly. These transmitters generally have a pulse output. Insertion dP Flowmeters The most commonly used flow sensor in the world is the differential pressure transmitter connected to a primary device. as diagnostic alarms or as a rudimentary. use either a mag pickup or a Hall-effect sensor to produce an output pulse that’s proportional to the velocity of the fluid. 56 . with materials of construction varying based on the requirements of the applications. Paddlewheels and insertion turbines can be used in a variety of applications. They. like paddlewheels. Turbine meters come in both electronic and electromechanical styles. they’re likely to be quite accurate. Some more modern propeller meters use embedded magnets and either magnetic pickups or Hall-effect sensors. such as an orifice plate or Venturi tube. especially in the municipal water industry. an analog output (usually 4-20 mADC). but the only insertion turbine flowmeters are electronic. which enable the signal to indicate either forward or reverse flow. as well as flow rate. same lines depending on the season. such as acids. and even insertion propeller meters have been certified for billing purposes for decades. The signal from the paddlewheel or turbine or electronic propeller meter is sent to a transmitter.

or it is being used as a low-cost sensor or a low-cost replacement for an original meter. Several companies now manufacture multiple-point pitot sensors.” which is assumed to be somewhere between 1/8 and 1/10 of the diameter of the pipe inbound from the pipe wall. Walt Boyes is a principal with process measurement consultancy Spitzer & Boyes. They are inherently more accurate and have volumetric calibrations instead of just velocity calibrations. The “average velocity point” theory is dependent on a fully developed flow profile with no swirling or distortion. and have several pitot ports located along their length. These sensors are mounted perpendicular to the diameter of the pipe. the single point pitot tube meter will not be accurate. into account. therefore. you need to be much more careful of piping issues than if you were using a calibrated spool-piece meter. Insertion mag meters use the same concept of “average velocity point” as the insertion paddlewheel does.controlglobal.” but they can be quite repeatable. Insertion Mag Meters Insertion magnetic flowmeters are not the same as spoolpiece magnetic flowmeters. but have fewer moving parts and no rotor. Where a spool-piece magnetic flowmeter can reliably be assumed to be close to 0. the sensor is connected to a standard differential pressure transmitter. It’s almost certain that insertion meters will not be “accurate. either for safety or expense reasons. In a spool-piece magnetic flowmeter. do it. even though they share the operation of Faraday’s law. the design geometry of the coils and the electrodes cause the signal output on the electrodes to be directly proportional to the average velocity in the pipe. not several of them. This way. The reason to use an insertion meter is nearly always that it was not designed into the piping originally. you will use insertion flowmeters where you can’t use a spool-piece. or worse. Design and Specifcation If you can use a spool-piece flowmeter for your application. and can. regardless of technology. Insertion Vortex and Target Meters Insertion vortex-shedding flowmeters have their proponents. an insertion mag meter can often be 10% or 15% of rate. from one side wall to the other. Multiple-port pitot tube flowmeters can be calibrated to take very disturbed flow] 57 . This makes them the clear favorite from a maintenance point of view. Generally.5% of rate accuracy. These devices must also be inserted to the “average velocity point. When you design an application for an insertion meter. Insertion paddlewheel flowmeters are often used in industrial water treatment applications and for driving chemical feed systems. in a flow control loop application may be all you really need. [Extended version at www. it measures the velocity in the fluid flowing in the pipe. the insertion flowmeter can be a useful tool in the design engineer’s tool bag. These devices have accuracies similar to insertion turbine sensors. Even the multiple-port pitot tube flowmeters are less inherently accurate or repeatable than a spool-piece flowmeter. The way these multi-point sensors work is that the differential pressure sensed is the average of all the differentials across the pipe—producing an output signal that very closely corresponds to the average velocity in the pipe. which. Insertion mag meters have a great advantage over other insertion types: They have no moving parts. Be aware that the accuracy is going to be substantially less than you can get otherwise..Back to Basics and just as a pitot tube measures velocity on the outside hull of an aircraft. Accuracy and Calibration The accuracy problem with insertion flowmeters is that they’re inserted into an uncalibrated spool section of pipe or even an elbow. For these applications. If the average velocity point is not calculated correctly. and are about as accurate. such as that in a 90° elbow. be used in locations where no other flowmeter can be used. and are usually highly resistant to acids. bases and abrasives.

com/wp_downloads/pdf/ LevelContinuumChart_Ronan100709. is introduced into the vessel e have talked in this magazine about what I call the level measurement continuum before. You’re able to mount the device in many existing vessels using an existing connection.controlglobal. It is one of the three measurement principles that can do the “really difficult” applications: radar. The physical design is well-suited for tank level measurement. there are level measurement applications that are very easy to do. somewhat similar to an RF admittance probe in physical shape. Free-air radar solves many of the problems of difficult level measurement applications. the distance from the device to the level is derived. free-air radar. It’s substantially immune to vapor blanket variation in the vessel. laser and nuclear level gauges. and one of the most affordable measurement principles. Vessel nozzles on many vessels are unused and available. However. or it may not work at all.Back to Basics The Lowdown on Radar Level Measurement Free-air or guided-wave — which do you use when? by Walt Boyes W foam in the vessel.] One of the “Okay to Use” bars in the chart that goes furthest toward “Too Hard to Do” is radar level measurement. If the dielectric is low and there are other issues. vessel internals. we’ve been installing capacitance or RF admittance devices in tanks to measure level. have appropriate materials of construction and the tank isn’t agitated much. dust and 58 . and used to calculate the level of the liquid or solid being measured. Using either transit time or frequency modulation techniques. granular materials or extreme coating of the vessel side walls? These all reduce the ability of the radar level gauge to receive the return signal. if at all. [Editor’s note: the chart detailing these level measurement concepts can be downloaded at www. These devices work very well—if they can be installed to miss internal structures.pdf. lay all the level measurement applications that require increasingly complex and costly measurement devices (Figure 1). The dielectric constant of the material being measured matters too. and any level measurement device will work. A probe. Free-air radar works much better than ultrasonic level gauges and is significantly less costly than nuclear level gauges or laser level devices. a signal is sent from a non-contacting device and received back at the device. In free-air radar measurement (Figure 2). to 12 in. Between easy and too hard to do. which is normally 4 in. and can be easily removed for cleaning and calibration. and these devices can often be inserted through a tank nozzle much smaller than the ones necessary for free-air radar level measurement. In the case of transit-time. There are also level measurement applications which are simply too hard to do with current technologies. free-air radar may not work well. Radar level measurement is basically divided into two groups. free-air and guided-wave. what happens if you have a vessel where there’s extreme agitation. For decades. to steam. signal loss can be total. The problem is that radar works on applications where capacitance or RF admittance devices do not. Enter a technology called time domain reflectometry (TDR). It is the one of the three with the widest applicability. Basically.

Nozzles can be as small as 2 in. and uses the time differential between them to calculate the distance from the probe to the surface of the level to be measured. The difference between that measured distance and the bottom of the vessel is the actual level in the vessel. that has a different dielectric constant from that of the vapor space in the vessel. liquid or solid. Generated pulses of microwave energy are transmitted down the probe. The transmitter’s circuitry cre- ates the transmitted pulses. the technology is 59 . for this purpose.Back to Basics Figure 1: The Level Measurement Continuum through a tank nozzle. (Figure 3 shows a typical TDR setup. a reflection is generated. receives the reflected pulses. and a return pulse travels back up the probe.) Because the probe is used as a waveguide. As soon as the energy pulse encounters a material.

Interface measurements between thick emulsions are not always good applications for guided-wave systems.html). Guided-wave radar gauges can be installed in stilling wells to replace existing mechanical float or displacer gauges. such as oil and (http://www. usually called guided-wave radar. (www. Profibus or Foundation fieldbus outputs as well as the standard analog 4-20 mA DC output. Using a wave guide. That typical range of dielectrics covers a very large spectrum of materials from hydrocarbons to water-based liquids such as and its precision is comparable to many FMCW radar gauges.controlglobal. where the dielectric of the top level material is lower than the dielectric at the interface. one of the vendors of guided-wave radar gauges. and can generally retrofit existing capacitance probe applications quickly and easily. reflected back to the transmitter. Walt Boyes is a principal with process measurement consultancy Spitzer & Boyes. Magnetrol International. and the gauge can be programmed to see the interface as well as the top level. Guided-wave radar gauges can also be used for interface measurements. 60 . Both levels send back reflections.5 to around 100. bases and other industrial products. it is usually acceptable for service in tanks with food-grade liquids such as orange.Back to Basics Transmitted pulses Signal Path Through Free Air Wave guide Time Domain Reflectometry — Guided-Wave Radar Free-Air Radar Level Figure 2. the signal is sent down the probe and gives the level in the vessel. Guided-wave radar works very well in confined areas where the beam spread of an ultrasonic or a free-air radar level gauge does not. One of the most useful sets of data in that handbook is the tables of dielectric constants for selected materials. Most guided-wave radar gauges have HART. Because the wave guide probe can be cleaned in place. as well as other water-based liquids. It also works with materials that are of a lower dielectric constant than a typical pulse radar unit. A typical range of dielectric constants for a guided-wave radar gauge is from about 1. Using the distance between the device and the top level Figure 3. and the introduction of steam into the vapor space can cause errors of on the order of 20% because of the high dielectric constant of the steam.magnetrol. Guided-wave radar helps extend the performance line of radar level gauges in our Level Measurement Continuum chart. apple or grape juice. For many has published a Technical Handbook that we host at ControlGlobal.

We make the Saranac brand of specialty products. sugary solution. 500-bbl (15. leaving very little 61 . currently head the management team at the brewery. typically maltose. to create a malty. (www. The brewery currently makes up to 30 varieties of Saranac beer during the course of the year. stability and consistency. Steam cost is one Boiling wort—–malt. the brewery continues to craft beer to the exacting standards set forth more than a century ago. We were looking for a way to improve steam quality and reduce steam use. One of the kettles boils the wort while the other is cleaned and prepared for the next cycle. Under the leadership of these third and fourth generations of the Matt family. After mashing. rl-stone. (Figure 2) The Swirl meter is a “vortex precessing” meter. The boiling operation continues for 90 minutes. somewhat akin to a vortex-shedding flowmeter. now called wort.000 per year using mass flow instrumentation. on instrumentation to optimize the wort boiling operation. the solution. Depending on the atmospheric pressure. We selected this type of meter because our piping geometry was tight. Following wort boiling. Stone Co.000 gallon) kettles for boiling (Figure 1). grain and water—and steam are at the heart of every batch of good beer. Syracuse. of the most important energy variables Matt Brewing deals with. We consulted with R.Y. sterilizes the wort and affects flavor.L. Matt Brewing Company sells the filtered grain byproduct to local farmers as animal feed. except that the Swirl meter has far better turndown at low flows and requires minimal upstream and downstream straight pipe. A pound of steam represents a certain value of BTUs. Fred Matt. From the steam header. As the wort temperature reaches the boiling point. the solution goes through a period in fermentation tanks and finally packaging in bottles and kegs. goes into one of two steam-heated. which includes the addition of the hops. compared to other flowmeter types.Technology in Action Saving Steam Saves Money Matt Brewing Co. Nick Matt and his nephew. This operation. evaporating about 5% to 10% of the The hops provide bitterness and flavor. Steam pressure management is crucial. we need to control the steam pressure to get more or less BTUs of heat into the kettle. Brewing starts with the addition of malted barley grain and water to the mash cooker. Mashing allows the enzymes in the malt to break down the starch in the grain into sugars. the steam in the bottom preheat coil shuts off.. From the filter press. the resulting solution flows to a filter press that separates out the grain. reduced energy cost to brew beer by $230. N. the saturated steam flows through a control valve and an ABB Swirl flowmeter before reaching the kettle. and the recently installed automatic steam heating system takes over. The new instrument system measures and computes mass flow rates of steam to control heat for boiling the wort. with distribution to about 20 states. The heart of a brewing operation is boiling the wort. A manually operated coil for steam at the bottom of the kettle preheats the wort. by Rich Michaels T he Matt Brewing Company is a family-owned business founded in 1888.

The 4-20 mA DC control signal goes to a set of ABB TZIDC intelligent electro-pneumatic positioners we installed on our existing Fisher control valves. The CM30 controller can also display 62 . (Figure 5. The CM30s compare the actual versus desired flow rate. which saved the expense of re-piping the brewhouse. The CM30 provides indication. 500-bbl kettles flowmeter. The displays for the CM30s indicate the desired steam mass flow rate (the control setpoint) based on the kettle volume. 48). 48) This unit calculates the optimum mass flow rate of steam based on wort volume and feeds that rate to the ControlMaster CM30 single-loop controller as a setpoint. When starting a batch. An I/P (current to pneumatic) module within the TZIDC positioner precisely regulates air flow to pressurize and depressurize the valve while minimizing air consumption. goes Figure 2. From the flowmeter. The internal caldaria efficiently provides both heating and mixing of the wort. the measured steam mass flow rate in lbs/hr. The CM30s receive the steam mass flow rates from the Swirl meters and convert them to engineering units used in the brewing process. and the percent control valve opening. recording.and-tube heat exchanger. which begins to condense. the basic beer solution. Wort rises through the tube bundle in the calandria while heated by the down-flowing steam. the saturated steam flows to the top of an internal boiler in the kettle called a calandria (Figure 4. The calandria is a shell. p. p. This schematic shows the flow of saturated steam through a control valve and a Swirl into one of two steam-heated. The Swirl meter contains a built-in inlet flow conditioner and outlet straightening vanes. and develop a control signal to maintain the predetermined setpoint. Wort.Technology in Action Mash cooker Wort Wort Filter press To vent CM30 TZIDC positioners Steam out Calandria heat exchanger CM10 CM10 Steam in To vent CM30 Control valve Swirl meter Swirl Steam meter in Preheat steam coil Boiler copper kettles the engineer’s guide to brewing Figure 1. math functions and proportional/integral control of the steam mass flow. A deflector at the top of the calandria distributes the wort and prevents foam formation. the operator dials data representing the volume of wort in the kettle into an ABB ControlMaster CM10 flow computer. for boiling. space for straight pipe to condition the steam flow (Figure 3).

It also saves about 1200 gallons of water per brew cycle. This would eliminate manual entry errors.000 per year).Technology in Action a tight squeeze Figure 3. Measured and calculated variables included kettle volume. depending on the brew volume and the operator. both heats and mixes the on a flow computer prior to batch start. The calandria. Prior to the installation of the new instruments. The new system for controlling steam pressure has generally reduced required steam pressures from 24 psi to 12 psi. and necessary water additions. The CM10 displays wort volume in the kettle dialed in by the operator. We’re considering adding a system to automatically send a signal value for wort kettle volume to the CM10 controller. We estimate the savings at approximately $630 per day (about $230. Rich Michaels is brewing super visor at Mat t Brewing Company. . we collected three months of data for the wort boiling operation. and the payback time for the instrumentation project is about three to four months. The new system reduces steam use by approximately a third. 63 steam flow rate trends. double duty dialing up the volume Figure 4. The results of the new control system are better quality and shelf life for our products with the added benefits of reduced energy and water use. a type of heat Figure 5. We compared the data we collected to what we believed to be optimum operating conditions and estimated possible savings. An operator sets the wort kettle volume exchanger. steam pressure and temperature. Matt chose the Swirl meter because its piping geometry left little room for straight-run piping to condition the steam flow. Our savings have resulted from reduced natural gas costs and water usage. We’re also planning to add a system for reclaiming energy from plant wastewater to generate electricity for the plant. percent evaporation. wort.

we need a very reliable. biscuits and pastries to chocolate. beer. bread. pharmaceutical and brewing industries. pet food. The additional advantage is malt extract’s ability to enhance these foods naturally with a unique. In the food industry. and since then has been a major international supplier of premier malt extracts and sweeteners for the food. diastatic and non-diastatic extracts of malted barley. Our company was founded in Peterborough. 64 . United Canadian Malt Ltd. nited Canadian Malt Ltd. chewing gum. oats and rice. where it happens Figure 1. wheat.2-ft) steel silos.” Precise quality control on temperature. Our customer base is extremely diverse. malt offers an improvement over plain sugar syrups. extracts are used in a variety of baked goods.” is separated by filtration from the spent grains. as the fermentation process assistance improves structure. the natural enzymes inherent in the malted barley convert the grain starches and proteins to soluble and digestible sweeteners and protein components. United Canadian Malt manufactures approximately 300 different liquid extracts using a variety of grains and process parameters to produce these natural. which is stored in UCML’s two 15-m (49. by Monte Smith U nutritional components from the grain. viscous sweeteners. vinegar.Technology in Action Radar Technology for Level Measurement Precise knowledge of the grain level in UCML’s storage silos is essential to production. the distinct flavor of both liquid and dried malt extracts is an effective vehicle for active substance administration. From them. Malt extract is a vacuum-concentrated sweetener made from high-quality malted barley. is stored in two outdoor silos. ice cream. as customers use our ingredients in everything from cereal. accurate and robust system to provide constant grain level information from our silos. UCML is a certified organic production facility offering liquid extracts and syrups made from a range of organically certified grains. Ontario in 1929. time and specific water quantity allows the release of Challenge Brewing production scheduling requires an accurate assessment of our primary ingredient—the malted barley. malted barley. The wort is then concentrated by evaporation to produce a viscous malt extract consisting of 80% solids material. In the pharmaceutical industry. crushed and then blended with water to yield a slurry called “mash. the main ingredient. it is drawn. With its broad nourishment characteristics. During this process. and. of course. The resultant fluid. subtle and desirable flavor. Radar measurement is the key. manufactures extracts of malted barley for the food industry. At our facility. (UCML) is Canada’s largest manufacturer of a wide variety of liquid and dry. color and crust appearance. called “sweet wort. To do so.

it must be able to handle the grain silo’s intense dust level during the filling cycle. as workers had to climb the silo. Sitrans LR460 (in background) and Sitrans LR560 (in foreground) are measuring the level of malted barley at UCML. but accurate Figure 2. were too expensive to retrofit onto our existing silos. Repairing our weight and cable system’s electronics was also quite costly. really. length of the silo—especially the bottom cone discharge section. as this would save both time and money. Finally. the only benefit from all of this climbing to the top of the silos was the positive effect on the manager’s heart rate and his fresh air exposure! All of this took place at UCML with malted barley grain arriving by rail car or truck every few days. we temporarily used a manual level control system. The compact size of Sitrans LR560 makes it easy to carry to the top of the silo. Load cells. a very accurate method. considering its mechanical problems. Solution United Canadian Malt was already familiar with Siemens Industry’s level measurement transmitters in its manufacturing process. Grain delivery was always a control headache. Precise inventory monitoring ensures that unloading from rail cars or trucks takes place within the allotted days. and without exceeding the silos’ capacity.2-ft) silo during a June rainstorm. An ideal system would have mechanically and electronically reliable construction.and low-level alarm shut-off option. it is crucial to have constantly accurate inventory level measurement. since cleanup of spilled grain on surrounding streets is not easy. however. and would be accurate over the full small. UCML investigated several options for reporting silo grain levels. Imagine removing caked-on grain dust from an inoperative spindle wheel atop a 15-m (49. Time and safety issues were substantial cost and efficiency factors. UCML had previously installed a Sitrans 65 . Or better yet. Such a solution would also have a remote readout capability at some distance from the silo and capability for a high. as the silo’s capacity is much less than the more than 70 metric tons (MT) on a rail car. just how accurate is that flashlight level check? Truthfully. And.Technology in Action Our previous weight and cable level measurement system and rotary paddle switches resulted in ongoing maintenance and reliability issues. We also wanted the ability to coordinate the brewing usage of the grain discharged from the silos without shutting down production. When the electronics of the weight and cable system failed. reseating the control rope and winding motor in January’s frigid and icy weather. open the hatch and check levels with a flashlight. With the variable delivery schedules and the expense of rail car unloading demurrage time.

From our electrician’s point of view. It is connected to a remote display inside the building. Sitrans LR460 is a non-contacting. despite at times working through a meter of foam and its accompanying sticky residue.Technology in Action LG200 guided wave radar transmitter on a wort tank. The stainless-steel housing two degrees of accuracy Figure 3.” This process required the silo to be near empty. the unit’s two-wire configuration was also instrumental in saving installation work and wiring costs. Due to the center location of the Sitrans LR460. 66 . UCML’s first silo level control monitoring device was a Sitrans LR460 installed on the first of our two outdoor silos. the 8° wider beam of the Sitrans LR460. horn antenna with an 8° beam angle. requires fine-tuning to find the correct echo profile. which imparts a great deal of confidence in the reliability of Siemens’ instruments. The Sitrans LR460 uses a 4-in. Sitrans LR460 provided acceptable readings. Alternatively. This unit has done so for several years. United Canadian Malt selected the new Sitrans LR560 for a solution for level measurement of the second silo. except for the lower cone area. The tank also requires a weekly chemical sanitation bath and a high-pressure water washdown. complicating the installation of any instrumentation. Sitrans LR460 provided reliable operation. and its compact size made it easy to carry the transmitter to the top of the silo for the installation. both from our production and maintenance operators’ standpoints. The transmitter is connected to a remote display at the operator’s station to enable convenient remote monitoring. and there is little headroom. After some fine-tuning of the signal. The LG200 performs consistently and accurately. With the success of the both the Sitrans LG200 and the Sitrans LR460 in mind. Once configured. 25-GHz frequency-modulated continuous wave (FMCW) radar level transmitter. the transmitter was detecting the seams of the silo. The installed Sitrans LG200 operates with a flexible. which were tuned out via the process intelligence feature called “Auto-False-Echo-Suppression. single cable probe with a sanitary tri-clamp fitting. was readily adaptable to UCML’s preferred way of installation on our silo inspection hatch. Wort is a challenging substance to measure because of high temperatures and excessive steam and foam that are generated during the wort transfer process. Sitrans LR560 has plug-and-play performance because of the 4° narrow beam and 78 GHz. and it uses a four-wire connection (two for 115 VAC power supply and two for the mA output).

An integrated purge connection is readily available for self-cleaning of the antenna lens if the solids material is exceptionally sticky. In fact. from completely empty to full. UCML’s silo cleaning schedules have also benefitted from the Sitrans LR560’s compact design. AMS or PACTware with Siemens’ DTM. The seams of the inside of the silo did not interfere with the level readings. The yearly maintenance cost associated with the previous mechanical level system has been eliminated. monitor the filling cycle and then shut the transfer system off if the level approaches the top of the silo. and no maintenance is expected. the cost of the new equipment was paid back well within the first year of its operation. During filling. There has been zero maintenance on the Sitrans LR560 since its installation. We have acceptable performance from the Sitrans LR460. The brewing process at United Canadian Malt Ltd.The 78-GHz frequency creates a very short wavelength that provides exceptional reflection from sloped surfaces and aiming is rarely necessary. and reliable readings are provided all the way to the bottom of the cone area. The local display interface features a backlit display. and we were very surprised with the small size of the Sitrans LR560 and how much easier it was to install. as the general manager at United Canadian Malt. 67 . graphical Quick Start Wizard that allowed operators to set up the Sitrans LR560 in a couple of minutes using the display pushbuttons. Profibus PA or Foundation fieldbus protocols. Benefits Since the Sitrans LR560 was installed. and we no longer have any overfilled silos or inaccurate readings from old technology. Overall. The extreme narrow beam of Sitrans LR560 provides plug-and-play performance. Programming can be performed remotely with Simatic PDM (process device manager). Its low profile and lack of extended horn have meant a significantly easier—and safer—cleaning process for the two workers who are on top of the silo performing the required operation. how to make beer Figure 4. UCML’s operators have noticed very stable readings from the transmitter. our operators simply keep an eye on the remote display. and can be rotated in four positions. An optional aiming flange is available to aim the antenna away from obstructions or towards the center of the discharge cone for reliable readings in the cone area. set up and operate. Our operators know what is going on throughout our process. Sitrans LR560 is available with HART.Technology in Action Sitrans LR560 uses a high frequency of 78 GHz and a unique lens antenna to provide a narrow 4° beam. and no additional fine-tuning was required. I am very happy with all of the instruments we’re using from Siemens Industry. The local display interface has an easy-to-use. Monte Smith is general manager at United Canadian Malt Ltd.

out the facility. Withprovided by flowmeters. communications and air temperature system running dry or water overflowing into other equipment. Another system is our worry about anything outside of their responsibilities. computer support. For heating and The heart of the ARTCC facility is the bidirectional flows. Even if we are forced into manual operation. humidifiers. but invisible to the personnel transit-time clamp-on flowmeters. all year long. flowmeters on the ters provide the information needed to natural gas that fires our boilers. Figure 1.industry.5 million BTUs of heat into the waprovide the environment that allows the rest of the team to not ter flowing through the hot-side piping.Technology in Action Ultrasonic Flowmeters Make Chiller Control Easier Clamp-on flowmeters are reliable and easily replaceable for maximum uptime by Kevin H. and flowmeters on the hot operators the information they need to and cold water loops that move throughmeasuring hot & Cold make the system work. flowmeters on control the system. single thing we do is focused on this one goal. in part. each with a caOne of our Air Route Traffic Control Center (ARTCC) in the southwestern United States handles approximately 5000+ com. These aren’t desktop PCs. For the hot loop. Evans F or the Federal Aviation Administration (FAA). We have flowmeters on the water In all of these situations. cilities I maintain. now maufactured by Sieworking the screens. thousands of different mens (www.pacity of 350 tons of cooling. we have three mercial flights a day. the flowmeters the air delivered throughout the ducts of are responsible for giving the human the buildings. Our main building depends on four chillers. flowmeters on our electricity.siemens. More specifically to my facility. We oper. but mainportant product is the safety of the traveling public. cooling purposes. The chiller makes the facility’s task easier. this information is to the chill loop and the condenser. seven ters on the air vented from the buildings. We even have flowmeOur facility runs 24 hours a day. the machinery could have a sudden and catastrophic failure. The system design called for many Controlotron ultrasonic are things that need to be present.the flight control data. Providing support to the rest of our team are making their measurements. and.The HVAC air handling system is an essential part of the faate facilities that allow modern levels of air transport to occur. our part of the team effort is to boilers which can transfer 3. out this data.usa. and boiler control system must know how This coordinated effort is made possible much hot and cold water is being used to by control automation. These meters work especially well for chill water refrigeration units must work in coordination us because they do not change the flow in the pipe where they with each other. These meters are able to handle hot and cold water and indicate days a week. The whole system depends on its that report directly to a items from mainframe computers to multi-hundred-ton distributed control system. Locally. this means two chillers high-powered computers that manage 68 . For the control aucreate the discharge temperature supplied tomation to work well. it needs to have information. our most im. Power. Every frames that generate considerable heat and must be kept cool. Flowmeters are essential to avoid damage from a water. the flowmecoming into facility.

designed the first transit-time ultrasonic flowmeter. When the start command is given. ensuring sufficient number of air changes per hour in the facility. The electronic transmitter measures the upstream and downstream times to determine the flow How Transit-Time Meters Work rate. and the previously operating chiller is placed in reserve. The transit-time flowmeters provide the fail-safe information to the control processor in the chiller. In such situations flowmeters can balance the demands on the system and reduce overall energy requirements.How Transit-Time Meters Work Tech- Siemens Controlotron’s founder. Following the operation cycle from the point where new chillers and boilers are rotated into the system. the exhaust fans from the rooms have flowmeters that verify the air is being removed from the room. flush with the pipe wall or clamped on the outside of Figure 1. other flowmeters confirm that air really is moving to the vents located within the various rooms of the facility. Improper start-up and improper shutdown can severely damage such systems. DOT FAA. the upstream ultrasonic energy will travel slower and take more time than energy traveling downstream. Boilers can be tricky systems. By measuring the difference in the speed of the pipe (Figure 1). more transit-time flowmeters inside the chill water loop provide the information and feedback to ensure that the amount of water flowing to the ultrasonic meters measure velocity and compute flow. when the power goes down. Additionally. allowing each step in the starting routine to proceed by verifying that the valves are in the correct position. a previously operating chiller is turned off and placed into reserve status. With good control automation. Sensors can be wetted. these From The Consumer Guide to Ultrasonic and Correlation Flowmeters. there is an increase in the difference between the times required for the ultrasonic energy to travel upstream and downstream between the sensors. Finally. air handlers’ coils is the right amount for the building’s heat load. Transit-time ultrasonic flowmeters. and two boilers in operation. One of the reasons the Siemens Controlotron flowmeters were selected was their ability to handle both hot and chill water in the air handlers. The basic principle is simple. water flow and valve positions exist. The first operation is to bring online a new chiller. Again the flowmeters are integral to the process. the process looks something like this. Joseph Baumel. 2004. sometimes called time-of-flight ultrasonic flowmeters. or that pipes do not freeze from lack of heat in the building. the second chiller is rotated into service. Inside the air handlers. we have multiple redundant flowmeters so that we can depend on having them when we need them. and you’re on batteries. transmit ultrasonic energy into the fluid in the direction and against the direction of flow. Often heat and cooling are required at the same time in an air handler. and that water really is moving through the piping loops for the condenser and chill water sides of the refrigeration unit. When the oncoming chiller is fully operational and is providing chilled water to the system. When the fluid moves faster. the heating system cycles boilers in and out of service and maintains proper temperature inside the hot water loop. As all of the chiller rotations are happening. the chiller repeatedly checks the output of the flowmeters in the condenser and chilled water loops in order to make certain that proper operating conditions. and also verifying that water flow to the air handlers is correct. and significantly reduces the number of people needed to rotate fresh chillers into and out of operation. flowmeters can tell you when things have stopped. Evans is an Airway Transportation Systems Specialist. Kevin H. Again the flowmeters verify that the chiller is indeed off and the valves are closed. As the cycle continues. 69 . Proper optimization and careful programming can make the system a pushbutton operation. it takes the same amount of time to travel upstream and downstream between the sensors. Sometimes they provide the critical bit of warning in order to ensure that things like electronic devices do not overheat from cooling loss. providing information for the boiler start-up and shutdown processes. At no-flow conditions. sound transmitted and received (transit time). Under flowing conditions. reports from the flowmeters are sent to the control automation network and regulate the pumps to move the water through the system. Similar to the chill water system. Spitzer and Walt Boyes. by David W. In our operation.

The first water turbine meter was s we progress into the 21st century.mvic.” Using high-density polyethylene (HDPE) pipe made it possible to lay the pipe down existing canals in most cases. of AgriTech Consulting. to 36-in. and MVIC needed better if it was going to measure and control the entire water distribution system. and California. Energy is becoming more expensive. But MVIC realized that as much as 60% of the water that enters an open canal is wasted by evaporation. Each shareholder is served by a “turnout. The second butterfly valve is the throttle or shutoff valve for the owner. The main supply ranges from 12-in.Technology in Action Water Is Money. seepage and losses at the end of the canal. Montezuma Valley Irrigation Company. It reduces evaporation. ( uses such a system This irrigation district provides 1400 shareholders with water for their farms and crops. Accuracy Matters Sustainability Includes Making the Water Distribution System More Efficient By Walt Boyes A made of HDPE with a transition to the PVC pipe commonly used in farming for distribution and irrigation. because it is flexible and easy to work with. In open-channel water distribution systems. and save energy and manpower costs.S. in diameter and is pressurized to 30-50 psi. Moving water requires energy. Cortez. closed-pipe water distribution systems have used mechanical flowmeters. “A decision was made to replace five miles of open-ditch irrigation canals with a poly pipe water distribution system.” said Gerald Knudsen. The first valve is controlled remotely by MVIC and is used to set flow rates according to the number of shares of water allocated to that shareholder. Monitoring a far-flung water distribution system requires substantial manpower—manpower that is getting more expensive and hard to find. flow measurement is made via Parshall flumes or wier boxes. All you have to do is Google “Colorado River water rights” to get a good picture of how critical water and water use can be.” also In this pilot project. open ditch irrigation canals were replaced with a closed water distribution system. So. MVIC decided on an ambitious project to conserve water. Many of the same drivers pushing industrial plants to implement plans for sustainable manufacturing are also pushing water utilities the same way. Colo. and water itself is becoming scarce and must be conserved. the district’s consulting engineer. while new supplies are becoming less available. water destined for potable service or for irrigation has traditionally been moved through a huge series of canals. 70 . “The projected savings were on the order of 1000 acre-feet of water per year. Each branch turnout is supplied with a flowmeter and two butterfly valves.. PE. water usage for domestic and industrial uses will increase. Their accuracy ranges from a best of 5% of flow to a typical 20% of flow. such as MVIC’s old one. All over the Southwest U. Traditionally. cuts seepage and eliminates end-of-channel water losses.

either by line voltage or by solar power. Most turnouts require only one setting per season.S.or battery-powered. general manager of MVIC.” Siscoe explained. But. flexibility and ease of installation. and they are difficult to use as a flow transmitters. “While the flowmeter is under battery power. and its descendants are similar in design. MVIC decided to use transit-time flowmeters clamped to the outside of the HDPE pipe.” Another reason for using ultrasonic flowmeters was the drastically reduced maintenance requirement.” Knudsen said.Technology in Action produced in the 18th century. low cost. Two transducers infer the velocity of the water by measuring the difference in the time it takes for an ultrasonic signal to move upstream and downstream through the fluid.” Knudsen said. a decision was made to purchase ultrasonic flowmeters from Dynasonics (www. Siscoe reported. One of the reasons. the district received a $75. The project has been so successful that the U. The large turnouts are supplied with continuous power. They are very accurate and designed for water billing service. “This portion of the project will demonstrate flow control and measurement at a remote location where flow needs to be changed regularly throughout the season.” said Jim Siscoe. Smaller turnouts are powered by the district’s “ditch riders. “The MVIC’s long term goal is to fully automate the system by installing wireless flowmeters and automatic control valves downstream of the meters. Bureau of Reclamation (USBR) is providing $2. Knudsen reported that the final project costs were $ 71 .” “All the turnouts on the closed pipe network have ultrasonic flowmeters with electronics capable of sending flow measurement data to the SCADA master control center at the MVIC office. “Wireless automation at these two turnouts will demonstrate to the MVIC and its shareholders the benefit of remote flow measurement and control.000 Conservation Innovation Grant from the USDA’s National Resources Conservation Service. is that the flowmeters can be solar. MVIC has ordered another solar powered flow control gate for another canal next winter. which results in no maintenance. These numbers would yield a payback in about 18 months. “The Dynasonics flowmeters are now our standard for both new and retrofit applications. “Based on this success.” Knudsen said. which function as ultrasonic transmitters and receivers. Scope items for the CIG grant include a solar-powered gate to control water level in the feeder canal and a wireless flow control and measurement system.1 million in stimulus grants to MVIC for construction of a second. turbine and propeller meters are maintenance problems. which is highly advantageous in Colorado.dynasonics. As a pilot. seven-mile project. Walt Boyes is a principal with process measurement consultancy Spitzer & Boyes. service line to this remote location.” Siscoe said. “After extensive review of many types of meters from various manufacturers. with annual savings projected to be $2 million.” Knudsen said. “We especially like their non-intrusive aspect. “the measured flow rate is used to manually adjust flow via the butterfly valve immediately downstream from the meter.” The district now has to keep only one type of flowmeter in inventory.” who carry portable 12-VDC batteries with them. particularly replacement of our impeller flowmeters.9 million.000 to install an electrical The transit-time flowmeters use strap-on transducers.” A wireless SCADA system will be implemented at two turnouts. with a mechanical register for totalizing water usage. “Using solar power saved $25.