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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


Simple. and reliable performance ensures VEGA is the right partner for your level measurement needs @vega_americas www.vega-americas. 1-800-FOR-LEVEL . 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. noise. and buildup ▪ Combination of speed. Reliable. excellent support.

com/modbus 5 Moore Industries 30 FCI 13 Lumenite 16 Siemens 26 Vega Americas 4 www.Advertiser Index Krohne 2 Kobold Instruments 34 Orion Instruments 6 Lumenite 29 Precision Digital 39 ABB 23 Emerson .sierrainstruments.Rosemount 8 Sierra Instruments 17 www.vega-americas.usa.lumenite.

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

Our reader surveys indicate that where possible and practical. vortex and ultrasonic flowmeters in recent years. Fiber optic probes developed for undersea oil and gas applications are measuring flowrate and composition with temperature and pressure to boot. users continue to move away from mechanical and electromechanical instruments towar electronic transmitters with few or no moving parts to stick or wear. 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. differentiated technology plays a role in establishing the independence of safety protection layers. too. ultrasonic and even sonic profiling gauges that offer a three-dimensional view of solids level in tanks and bins. 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. but play second fiddle to technology familiarity and trouble-free operation in others. back-to-basics tutorials. we hope you find it useful. demonstrate the complex interplay of criteria that go into a instrumentation purchase decision. familiarity and trouble-free operation often trump technical specifications when specifying flowmeters and level gauges. Accuracy and other desirable performance specifications are of overriding importance in some applications. this non-mechanical trend is indicated by the increased use of radar. 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. On the level measurement side. 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. And while more of today’s users pay at least lip service to lifecycle costs. The balance of this State of Technology Report is a compendium of the latest trends articles. Indeed. initial purchase price remains a key consideration. The continued preference for differential pressure flowmeters and level gauges. too. Guided-wave radar. Thermal dispersion mass flowmeters.Flow and Level Measurement Still a Subtle Engineering Task All other things equal. and application stories recently published in the pages of Control. —The Editors 7 . 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. despite the overall trend toward non-mechanical instruments for process measurements. but for many users the dependability and familiarity of a differential pressure cell still wins out over other considerations. electromagnetic. D espite ongoing advances in instrumentation technology. A mechanical switch or magnetic level indicator provides assurance against common cause failures when used in conjunction with an electronic gauge. Hence the growing popularity of Coriolis. Dramatic advances in ultrasonic technology in particular have spiked their broader use even in gas custody transfer applications. And while it doesn’t cover every corner of the application space. But the number one flow and level measurement technology actually measures neither. Sure. and well as the ongoing viability of numerous niche technologies. Here. remain an imporant option for a specialized range of gas measurement applications. For example. there exists a countervailing trend in favor of mechnical devices for safety applications such as pump protection or tank overfill prevention.

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

ly/1rHCPrB). One interesting fact that arose while looking at overfill incidents is that they mostly occurred off day shift. Another tank farm overfill also occurred in Kuwait. which have led in a few cases to major incidents. Process unit tank farms are typically a bit separate from the process units. oil fields or fuel distribution terminals or facilities. leading to an unconfined vapor cloud explosion that was deemed to be unprecedented—the largest ever explosion in peacetime Europe. Puerto Rico. it’s common to see large tank farms with vessels of various forms and shapes— cylinders. but they’re certainly not rare. no fatalities occurred. 43 people were injured. we have had some notable tank overfill incidents: Laem Chabang.Trends in Technology Prevent Tank Farm Overfill Hazards Catastrophic incidents have led to useful rules for systems that help avoid them. injuring three and resulting in the Caribbean Petroleum Corp. Many of these tank farms started out as remote sites. but plant expansions have sometimes met external industrial and residential sprawl to increase the potential consequences of a disastrous event. but some result in overfills. 11. riving around petrochemical plants. which is very advantageous in regard to people occupancy/exposure. The numbers of tank farm overfill incidents were probably under reported in this study. but where supervision is typically more relaxed. by William L. It was fortunate that the explosion occurred in the early morning hours on the weekend.” James Changa and Cheng-Chung Lin. resulting in a fire and explosion (“Overfill + Ignition = Tank Farm Fire. spheres. Journal of Loss Prevention in the Process Industries. UK. A study of storage tank accidents for the period of 1960-2003 covered 242 tank farm accidents. As it turns out. blast happened during working hours on a weekday. bit. The overwhelming majority are done safely. 2005. PE D explosion may not be considered common. tank farm overfill incidents in the study occurred on average every three years. having to file for bankruptcy. tank farm overfills that lead to a fire and 9 . Fuel distribution terminals. On Oct. Puerto Rico.300 filling operations (“Atmospheric Storage Tanks. are physically similar and may butt up against residential and light industrial areas. of which 13 resulted in a fire and explosion (“A Study of Storage Tank Accidents. diesel and other refinery products required by the market and government regulations. and spread over a large acreage. in 1999 (seven dead). Buncefield. which commonly straddle pipelines. emptying and transferring operations go on each month in these tank farms— maybe even every day. These tanks can store feedstocks. bullets and spheroids.” Risk Engineering Position Paper 01. and the Cataño oil refinery in Bayamón.51–59). A gasoline tank overflowed. All these involved spectacular explosions and fires with extensive damage to the facility. 23. Marsh Ltd. far worse. For refineries. located in bunds or diked areas. it could have been far. 19 [2006]. and there is less general oversight. in 2005 (43 injured). It’s safe to say that thousands of filing. Mostia. 2009. Had the 6:01 a. However. Fifteen overfill incidents were reported. but still. Looking over the past couple of decades. p.). What really brought tank farm overfills to the forefront was an industry-changing incident that occurred on Dec.” Presentation for HSE Moments/Alerts. Hemel Hempstead. UK. many of these tanks are used for what are called oil movements. intermediates and final products. at the Buncefield oil storage and transfer depot.m. as can some plant tank farms. for while the damage was extensive. Data compiled by a reputable operator in the United States estimated that an overfill occurred once in every 3. Thailand. another large overfill event led to a fire and explosion at the Cataño oil refinery in Bayamón. (three injured). which blend various products together to provide the many grades of gasoline.

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

3. We can easily digitally transmit multiple sensor inputs across a pair of wires. can also be solar-powered. 4. (See sidebar. the API 2350.4 (ISA 100. 2. high-high level (HH).Trends in Technology Buncefield. can be a challenge both technically and in cost. alarms and an automatic shutdown if the operator response time was not adequate. 6. Profisafe. reducing wiring costs.”) Buncefield’s Legacy: New API 2350 Requirements Because of Buncefield. Another developing technology is mobile wireless applications. Appendix A of the standard provides an acceptable. “Buncefield’s Legacy: API 2350’s New Requirements. not maximum. while unattended facilities required continuous monitoring. There are wireless applications for tank monitoring systems available using IEEE 802. For existing installations. essentially prescriptive approach that contains aspects of ANSI/ISA 84. A overfill management system is required.00. Available automated safety shutdown systems geared to the tank farm environment range from local.  Emphasis on proof-testing of independent alarms and AOPS. even though ANSI/ISA S84 (1996.00. Foundation fieldbus. Operators are required to categorize each tank under consideration for overfill prevention based on tank level instrumentation and operator surveillance procedures. The definition of a set of operating parameters. This highlights a cautionary note that one should always remember: All standards provide minimum requirements.. the standard provides two options for implementation.and performance-based requirements.01-2004 (IEC 61511 modified) must be Technology Can Help Placing instrumentation on widely geographically distributed tanks. high-reliability shutdown systems connected by Modbus to centralized 11 . ASIsafe). Some of API 2350’s new requirements are: 1. wireless cellular networks and global satellite networks. but technology has advanced significantly in the past 10 years. Because of the Buncefield explosion.11a and WirelessHART). This standard divided facilities into attended and unattended operations. ANSI/ISA 84. A risk assessment shall be used by the owner and operator to categorize risks associated with potential tank overfills. particularly for cost reasons. which allow tank farm field operators. For new installations. using any one of the more than 50 fieldbuses available. to monitor tank levels. particularly on existing tanks. which can be easily added to existing tanks. including critical high level (CH). maximum working level (MW) and automated overfill prevention system (AOPS) activation level. 4th Ed. bit. These followed. a number which are third party-approved safety protocols (for example. For attended facilities. or the operation was fully automatic.and performance-based requirements. ly/1oRKeQZ ) should not be hijacked by “minimum” safety requirements in a standard. 2003) and IEC 61511 (2004) were in place at that time. which brought it closer conformance to the SIS standards. which brought it closer conformance to the SIS standards.01-2004 (IEC 61511 modified). 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. in addition to the control room operator. M  ore emphasis on operator response time for level alarms. 5.15. the API 2350 4th Edition (2012) committee took the lessons learned to heart and introduced a number of new risk. depending on whether the installation is existing or new. When an AOPS is required. Following good engineering practice and in most cases common sense (an old friend who some say has passed on. From an instrumentation perspective. there were no requirements for level detectors on the tanks. API 2350 had minimal requirements for safety instrumentation and no requirement for evaluation of the safety risk. (2012) committee took the lessons learned to heart and introduced a number of new risk. Tank farm remoteness and geographical distribution often make them suitable for wireless monitoring applications.

which is virtually identical to IEC 61511.01 (IEC 61511 modified). 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. Alaska. which obviously can create a hazard. This technology could easily be applied to tank farms. at its Prudhoe Bay. which is how to proof-test these to meet API 2350 and ANSI/ISA 84. One of the main issues remains.00. The same type of drone has been used in test flights by ConocoPhillips. electrically classifying tank farm areas and ensuring that electrical equipment and instrumentation meet (and maintain) the classification. which by some estimation can range up there with a hydrofluoric acid leak hazard in a refinery. the FAA authorized BP to use a commercial drone.01-2004 (IEC 61511 modified). Tank level and inventory management system technologies also have advanced. since many of the gases involved are heavier than air. It would seem important to minimize the potential of an electrical ignition source by properly.00. but may also be held to API 2350 overfill requirements as RAGAGEP. Alaska. even if you can’t prevent it. Mostia.avinc. (www. Fellow. 12 . the sooner you can act to bring an developing incident to heel. supplied by Aerovironment Inc. site to fly aerial surveys over Alaska’s North Slope. is a frequent contributor to Control. and pointsource gas detectors can be effective inside bunds. To make our tank farms safe. and report them to the control room and field” but do not be fooled. site to fly aerial surveys over Alaska’s North Slope. Fire detectors are not as effective for overfill situations. you will be held to this standard or the burden of proof otherwise. through-the-air radar and traditional level measurement SIS-TECH Solutions. at its Prudhoe Bay. This API 2350 standard is listed as a “recommended practice. as William L. PE. Chemical plants should meet NFPA 30. On June 10. supplied by Aerovironment Inc. In the United States and in other countries that recognize API standards as recommended and generally accepted good engineering practice (RAGAGEP). use visual and IR sensors. While this seems to be a case of reaction rather than prevention. the FAA authorized BP to use a commercial drone. One of the biggest hazards in a refinery tank farm typically comes from butane or other compressed gas spheres. they can have a path length up to 200 meters.Trends in Technology BP systems to using safety PLCs. Open-path gas detectors could be particularly effective. if you have an incident in your refinery or fuel distribution tank farm. But that is a discussion for another day. Spill Spotter Figure 2. drones could be used to fly continuous circuits above a refinery or chemical plant.avinc. It seems like a reasonable prediction that in the not-too-distant future. the less the consequences will be. Improvements have been made in guided-wave radar (GWR). (www. This discussion only covered atmospheric tanks in tank farms. pattern recognition and analytical technology to detect abnormal conditions in the facility. One area that API 2350 does not address in tank farms is the use of combustible gas detectors and fire detectors. environmental and/ or financial incident does not occur in the future. Heed API 2350 API 2350 has been updated to be better in line with the industry standard ANSI/ISA 84. On June 10. but can help prevent pool fires from spreading to other tanks by detecting rim fires and jet fires.

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6%AR at minimum flow. Adding to this ΔP error. total flows. alarms. allowing the sensor to be located in hard-to-access areas.000). this minimum ΔP error corresponds to a minimum flow error of √ 12.74% = 3. and to provide cell phone connectivity.065 = 12.11). I described some new fiber-optic flowmeters used for subsea measurement of multiphase flows (oil.6%AR.74%). 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. this means that the flow rangeability is 14:1 (142 = 196). Head-Type Flowmeters When measuring flow by any differential pressure generating element. gives us a total error of only 4. With a ΔP measurement error of 0. 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 200:1.065%FS. Today. self diagnostics. methane). Naturally. n my May column. which used to be around 0. the d/p cell error is 12. while the d/p cell is in an easy-to-access location. and at the minimum flow (100/14 = 7%). if we wanted to keep the total error at minimum flow under 3%AR. which is usually about one percent of actual flow (%AR). the total error is kept under 5%of actual flow (AR). and the error of the d/p cell. the flow turndown (rangeability) had to be limited to about 4:1. Because of the square root relationship. Because of the square root relationship. memory boards for data acquisition and storage for hundreds of thousands of data points for displaying of trends. water. Therefore. the 1%AR error of the sensor (the precision of its discharge coefficient CD). the measurement error is the sum of the sensor error. the full 14:1 turndown can only be realized if at minimum flow (100/14 = 7% of full scale). They can be mounted to the sensor or connected wirelessly (IEEE802. Now I will describe some other.74% AR at the minimum ΔP (196x 0. the flow turndown is 14:1. the flow is still turbulent (RE > 8. 14 . the maximum turndown capability of a smart.25% to 0. in the past.5% of full scale (%FS).Trends in Technology Advances in Flow Instrumentation by Bél a Lipták I with local displays. 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. In addition to the tremendous increase in the accuracy of the state-of-the-art d/p cells.

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

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

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

50% level) and highest at the operating constraints (e. Adaptive level controllers can not only account for the effect of vessel geometry. In some applications. and prevents the situation of level loops being tuned with not enough gain and too much reset action. Conical Tank in MIT Anna University Lab with an industrial DCS. surge tanks). In the section on controller tuning.g. there may be an optimum batch level. an oscillatory response is addressed by decreasing the controller gain. a small change in level can represent a huge change in inventory and manipulated reflux flow. he or she may decrease the controller gain. 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. In other applications. 19 . What most don’t realize is that the opposite correction is more likely needed for integrating processes.g. exceptionally tight level control. the denominator of the integrating process gain that is the product of the density (ρ). level control can be challenging due to shrink and swell (e. If the controller gain is further increased. the oscillations will grow in amplitude (the loop becomes unstable). The quantity and quality of product for continuous reactors Figure 1. 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. 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. Even if these nonlinearities are not significant. For fed-batch operations. through enforcement of a residence time or a material balance for a unit operation.and high-level alarm and trip points). the cross-sectional area varies with level. Consequently. We are not so cognizant of the oscillations with a slow period and slow decay caused by too low of a controller gain. For horizontal tanks or drums and spheres. In other words. 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.Trends in Technology output goes directly to position a nonlinear valve. making the oscillations worse (more persistent). the reset time must be increased to prevent slow oscillations. if the user sees these oscillations and thinks they are due to too high a controller gain. low. Normally. is needed for best product quality. the adaptive level control with proper tuning rules removes the confusion of the allowable gain window. The period and decay gets slower as the controller gain is decreased. We are familiar with the upper gain limit that causes relatively fast oscillations growing in amplitude.g. 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. Since these overhead receivers are often horizontal tanks.g. 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. In these vessels. and crystallizers depend on residence times. boiler drums and column sumps) or because of the need for the level to float to avoid upsetting the feed to downstream units (e. 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. the integrating process gain is lowest at the midpoint (e.

html). standards. it is expected that the decrease in process time constant is much larger than the decrease in process gain with a decrease in level. The conical tank with gravity flow introduces a severe nonlinearity from the extreme changes in area. 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. 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. τp = r Variable-flow pump Fmax h Hand valve Reservoir Figure 2. the equations for the process time constant (τp) and process gain (K p) are developed from a material balance applicable to liquids or solids. 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 DCS allows graduate students and professors to explore the use of industry’s state-of-the-art advanced control tools. The equations are approximations because the head term (h) was not isolated. bark and coal to unit operations. 3 20 .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. 2 Kc = Ti Kp * ( λf * τp + θp )  Eq. 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. respectively. In Appendix A online (www. 4  Eq. Conical tank detail. 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. Less recognized is the opportunity to use the DCS for rapid prototyping and deployment of leading edge advances developed from university research. 5 h * Fmax 1/2 C * L max  Ti = τp Eq. The process no longer has a true integrating response. The conical shape prevents the accumulation of solids on the bottom of the tank. The dependence of discharge flow on the square root of the static head creates another nonlinearity and negative feedback. The use of a DCS in a university lab offers the opportunity for students to become proficient in industrial The Madras Institute of Technology (MIT) at Anna University in Chennai. India.

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. The upper gain limit to prevent fast oscillations occurs when the closed loop time constant equals to the dead time.Trends in Technology Figure 3. Kc < Ti = 2 * (λf /Ki ) + θp Eq. 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. 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 . Ti Ki * [(λf /Ki) + θp ]2 3 Ki * 4 * θp  Eq. Performance of linear PID level controller for a conical tank.

the adaptive level controller eliminates the oscillations at low levels. 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. 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. process time constant. It was found that the use of lambda time. 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. 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. 22 . Figure 5.Trends in Technology Kc * Ti > 4 Ki  Eq. As seen in Figure 5. Adaptive level controllers can eliminate tuning problems from the extreme changes in level control dynamics associated with different equipment designs and operating conditions. with protection against going outside the controller gain limits helps provide a more consistent tuning criterion. Greg McMillan is a consultant and ControlTalk columnist. oscillations. 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%. Dr. 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. 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. rather than lambda factors. The adaptive controller employs an optimal search method with re-centering that finds the process dead time. Performance of adaptive PID level controller for conical tank. and process gain that best fits the observed response. Process models automatically identified for operating regions. Prakash Jagadeesan is an assistant professor at Madras Institute of Technology (MIT) Anna University in Chennai India. Sridhar Dasani is a graduate of 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. and provides a more consistent level response across the whole level range. The process models are categorized into five regions as indicated in Figure 4.

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

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

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

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

www.” new rules allow. and where in the country without a license.-based Robinson Brothers is using a magnetorestrictive level transmitter from ABB to meet strict safety standards for handling highly reactive carbon disulfide (CS2). So.K. out the regulatory process. upon reflection of those emissions. U.250 GHz. U.K. but it must store the CS2 under a layer of water to prevent it from probably has an even more difficult level measurement challenge—securing level indications for highly reactive carbon disulfide (CS2).00 GHz and 75 to 85 GHz bands. but it didn’t link to any wider control system. ABB Reining in Reactivity While its tank isn’t out on the AT100 magnetostrictive level transmitter. transmits analog and/or digital signals careful with chemicals Figure 2. and can boost its resolution to more than 100 times greater than a conventional reed switch-type device (Figure 2). for monitoring or control. U. The company uses CS2 at its Midlands specialty chemicals plant.robinsonbrothers. They will be pub- the new FCC rules partially harmonize U. this because it will improve the global competitiveness of U.icaservices. Robinson previously used a simple. Most importantly. 24. which also bases its Specifically.fcc. so any related instruments are safety-critical. Federal surement procedures to provide more accurate and repeatable Communications Commission (FCC) reported Jan. the order modifies Part 15 of the FCC’s rules for measurements on main-beam emission In addition. adjusting emission limits to account for attenuation that occurs The Measurement. rules for LPRs with lished shortly in the Federal’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. Control & Automation (MCAA. edocs_public/attachmatch/ (ETSI) Technical Standard for LPR devices. Robinson sought help from ICA Services (www. which provides continuous level indication. and will become effective the similar European Telecommunications Standards Institute’s 30 days after that. The rules now require opted rules allowing “level probing radars” (LPRs) to operate any- measuring emissions in the main beam of the LPR antenna. an instrumentation specialist in Manchester. of the instruments and their suitability for its widely varying process conditions.Trends in Technology FCC Allows Unlicensed “Level Probing Radar” in Open Air In a long-awaited and helpful regulatory Robinson Brothers ( 15 that it’s ad- measurement protocols for these devices. magnetic.05 to 29. and revises the mea- level instrumentation reports it worked closely with the FCC through- any nearby receivers from encountering interfering signal levels. the U. 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. floatbased device to measure the CS2 and water level. This means the level of the interface between the water and CS2 needs constant monitoring. The report and order are located at http://hraunfoss. ICA recommended using ABB’s (www. by changing these technical testing requirements.925 to 7. The new limits will still protect measure. MCAA also sought LPRs to operate on an unlicensed basis in the 5. AT100 28 .

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

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GF met its goals by using Micro Motion Elite and H-Series flowmeters and Model FMT filling mass transmitters from Emerson Process Management (www. NRG Lab settled on McCrometer’s (www. 31 .Trends in Technology Flow Charts New Waters Flowmeters. Besides seeking to improve filling speed and accuracy. and enable in-line sterilization without disassembling the machine. most of the basic parameters of flow sensing and control are well known.endress. food and medical applications to precisely measure compounds for injections. For instance. GF previously used filling methods based on time-pressure instruments. and be applied by users that hadn’t considering using them before or couldn’t afford them. did recently to reduce filling times. NRG Lab reports its V-Cone flowmeter performs better than its former vortex flowmeter. at Stanlow refinery in Ellesmere Port. improve accuracy and in Parma. according to Marco Serventi.5 g to 5 kg to be dispensed without changing mechanical components. GF also wanted to enable users to change media without replacing the measuring instrument. Shell Lubricant Center (www.nrg-labs. infusions. as well as piston-syringe and peristaltic (roller type) pumps. on machines for its pharmaceutical customers. Eventually. GF’s filling machines are used in pharmaceutical. but continual advances in flow conditioning and management are enabling them to be implemented in some unusual applications and settings. It suits tight retrofit installations because it only requires a minimal 0-3 pipe diameters upstream and 0-1 diameters downstream. and enhances safety by avoiding having any electronics near the reactor vessel.” When its old vortex flowmeter wore out and a replacement wasn’t available. The flowmeters use Profibus DP communications. 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.. com).shell. Aiding Lubrication Applications To help give its new lubricant bottom-loading bay more efficient and safer driver-initiated loading.5% of the flow rate with +0. “We were able to improve system response time and reduce batch cycle times by taking advantage of integrated valve control from the transmitter. For example. syrups and detergent solutions. requires no maintenance such as changing differential pressure V-Cone flowmeter with built-in flow conditioning for accuracy to +0.1 repeatability.mccrometer. rather than the traditional pulse output set Nuclear and Underwater Likewise.emersonprocess. NRG Lab began searching for a substitute with long-life electronics. It uses flow metering to measure its nuclear laboratory and reactor’s basin cooling system.” explains Serventi. (www. while it might be surprising to see a bunch of Coriolis flowmeters sprouting on top of a filling machine. By Jim Montague I up through a PLC. but adding innovations and new capabilities to familiar technologies can make them show up in some unexpected facility in the Netherlands makes nuclear medical isotopes and tests materials for nuclear power plants. low maintenance and enable tighter filling tolerances on its advanced filling equipment (Figure 1). Cheshire. GF’s sales manager. good underwater performance and the ability to withstand radiation. the rangeability of these Coriolis flowmeters allows different media in the range of 0. “The reliability and accurate results provided by the Micro Motion instruments have now been validated by GF customers over a number of successful ophthalmic preparations. which uses a medium called “demiwater.A. that’s exactly what GF S.” t shouldn’t be Italy. NRG Laboratory’s (www. small footprint. U. recently deployed 10 Promass 83F Coriolis mass flowmeters from Endress+Hauser (www.K.

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

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

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

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

brations are within the transmitter specifications. tween 100 mmWC and 1000 mmWC. 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. suppression and span. a given differential pressure SG = 1.10 LT Back to Basics SG = 1. This transmitter would 100% and 0% calibration values. 0% Level the level measurement.10where the span is 880 mmWC. In addition. 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. In practice. it could SGbe = 1.05 = 1. Nowhere do we use terms such as elevation. for example.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. the specific gravity of 770 to 1650. The span of a transmitter is the difference between the to be changed by 1000 mmWC. For example. the transmitter zero is raised by 770 mmWC.10 1000 mm calibrations for interface level measurements. respectively. Repeating.10 SG = 1. (Fill) example mitter may be calibrated with spans between (say) 400 second SG (Fill) and the mmWC and 4000 mmWC.100% Level 0% Level 0 mm LT SG = 1.05trans. all of these caliliquid level measurement applications. and -1145 to -265 mmWC.mmWC. However. The calibrations in the examples were 0 to 1100. instruments. and the zero is lowered by 1145 used in the spans. 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. 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. However. differential pressure measure.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. In addition. Using this lower range 37 100 S . so that differ. 0% Level 100% Level 200mm What Ifs What if the liquid density changes during SG = 1. their zerosPressure by more than 4000 mmWC. Therefore.4000 mmWC. This transmitter should be calibrated 770 to 1650 mmWC to measure liquid levels of 200 mm to 1000 mm above the nozzle. The use of these terms can easily confuse and mislead the practitioner. Note that these techniques involve applying hydraulics to the installation and application. Each many liquids is known and relatively stable. respectively.

On the other hand. In this case. a vessel operating at 2. Therefore. In level measurement. the levels should have been expressed in percent. Using absolute level measurement units such as inches.8 meters does not readily indicate a problem to the operator even though the vessel overflows at 3. Some years ago. so it should be calibrated -1145 to -265 mmWC to measure liquid levels of 200 to 1000 millimeters above the lower nozzle. 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. Spitzer is a principal in Spitzer and Boyes and a regular Control contributor. Aside from using incorrect values.05 (Fill) LT SG = 1. 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.0% Level 100% Level 200mm SG = 1. This can easily become overwhelming and cause operator errors because plants often have hundreds of vessels. it’s generally desirable to use the lower range transmitter to reduce measurement error. 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.10 SG = 1. feet.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. all being equal. For example. transmitter (1000 mmWC) will usually be more accurate because of the smaller absolute errors associated with other specifications such as temperature.0 meters.10 500 mm LT SG = 1. 38 . 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. pressure and ambient temperature affects.05 (Fill) SG = 1.10 Figure 3. distributed control system inputs were incorrectly configured to correspond to the maximum transmitter spans. the vessel size is fixed. 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. Using the available information properly is another potential problem. the differential pressure transmitter subtracts the high side from the low side.

predig. Series Why Modbus Scanners? > > > > > > Scan up to 16 PVs Easy instrallation & setup Display level in feet & inches* SafeTouch® thru-glass buttons* Display PV and tag name 4-20 mA retransmission * Available on select meters 1-800-343-1001 • www. you can leave the climbing to us. you will unleash a whole new dimension of display possibilities. PRECISION DIGITAL CORPORATION Since 1974 . temperature and more.Leave the Climbing to Us Install a Precision Digital Modbus® Scanner as a Tank-Side Indicator level interface level density temperature volume Take Advantage of Your Modbus Signal By using the Modbus signal from your existing multivariable level transmitters. interface level. Paired with a new Precision Digital Modbus Scanner you can display multiple variables including level. Best of all.

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

Figure 1.5% of measured value from 0.Back to Basics flow is of relatively long duration. Using Magmeters Following these simple rules for using magmeters will produce a satisfactory application. they will not work on non-conductive fluids or on gases at all. They will not work when the pipe is full of entrained gas or air. Typical accuracy of a magnetic flowmeter is 0. up to 0. The minimum conductivity of a fluid is 5 μS (microSiemens) before a magnetic flowmeter will measure its velocity. They will not work when the pipe is not full (with the exception of several versions designed specifically for this application). for example. at very low flows. Most important. This combination of devices is used to measure mass flow where the pipe size is larger than 12 in. which is supposed to keep the pipe full at all times. (nominally 300 mm). 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. If the pipe is not full. One of the most common application failures of magnetic flowmeters is on a gravity-fed line discharging to atmosphere in a tank. 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. They don’t read out in mass flow units. 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. In practice. there will be significant error. saline brine or seawater. The velocity deflects the standing magnetic field and induces a voltage on the electrodes that is proportional to velocity. If the pipe fill drops below the line of the electrodes. 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. except for specially-designed units. Applications like this are designed with a u-tube in the line.1% of indicated flow rate. per sec (0. it’s not wise to use a magmeter on a fluid whose conductivity is this low. the pipe is actually not full. and the flowmeter will read in error.3 ft per sec to 33 ft.1 to 10 m/sec) velocity. Some vendors indicate even higher accuracies over portions of the flow range. Finally. magmeters have trouble working on fluids with extremely high or highly variable conductivity. they can produce a high-precision mass flow measurement. Very often. 41 . but when combined with an ancillary density measurement device.

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

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

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

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

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

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

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

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.


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

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

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

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

an analog output (usually 4-20 mADC). such as acids. Turbine meters come in both electronic and electromechanical styles. such as an orifice plate or Venturi tube. Because propeller meter rotors are large and located at the centerline of the pipe. as well as flow rate. hot tap assembly. They. These transmitters generally have a pulse output. 56 . Most insertion turbine meters have very small rotors. either in potable water systems or in irrigation systems. this is called a “corporation cock assembly. Insertion dP Flowmeters The most commonly used flow sensor in the world is the differential pressure transmitter connected to a primary device. the differential pressure sensor is connected to a pitot tube inserted in the flow stream. Sometimes. are inserted using a flange that mounts into the upright member of a tee fitting. and often have one or two programmable relay contact closure outputs. Propeller meters. In its insertion incarnation. they’re likely to be quite accurate. because their prop is significantly larger than a paddlewheel. and even insertion propeller meters have been certified for billing purposes for decades. Some more modern propeller meters use embedded magnets and either magnetic pickups or Hall-effect sensors. Like paddlewheels. Paddlewheels and insertion turbines can be used in a variety of applications. Like paddlewheels. These can be used as flow alarms. Laminar flow from 0 to 2500 Rn. which enable the signal to indicate either forward or reverse flow. which exists somewhere between 1/8 and 1/10 of the inside diameter away from the pipe wall. so they can be inserted through a small-diameter fitting or through a small diameter. 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. Turbulent flow from 4500+ Rn.Back to Basics to a mechanical or electromechanical totalizer with a cable very much like a speedometer cable.” 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. with materials of construction varying based on the requirements of the applications. which uses the pulse (or frequency) output to display flow rate and to increment a totalizer (usually electronic). but the only insertion turbine flowmeters are electronic. use either a mag pickup or a Hall-effect sensor to produce an output pulse that’s proportional to the velocity of the fluid. bases. using quadrature detectors. The signal from the paddlewheel or turbine or electronic propeller meter is sent to a transmitter. and hot or cold fluids. as diagnostic alarms or as a rudimentary. Electronic paddlewheels and turbines can be set up to be bidirectional. dead-band controller. like paddlewheels. they must be inserted to the “average velocity point. propeller meters have a pulse output that is proportional to the average velocity in the pipe. especially in the municipal water industry. same lines depending on the season. Propeller meters are almost always used for water service.

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

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

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

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

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

for boiling. The displays for the CM30s indicate the desired steam mass flow rate (the control setpoint) based on the kettle volume. p. which saved the expense of re-piping the brewhouse. 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. The calandria is a shell. the measured steam mass flow rate in lbs/hr. goes Figure 2. When starting a batch. 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. The CM30s receive the steam mass flow rates from the Swirl meters and convert them to engineering units used in the brewing process. p. which begins to condense. Wort. and develop a control signal to maintain the predetermined setpoint. The CM30 controller can also display 62 .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. (Figure 5. The CM30 provides indication. the saturated steam flows to the top of an internal boiler in the kettle called a calandria (Figure 4. 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. and the percent control valve opening.and-tube heat exchanger. 500-bbl kettles flowmeter. recording. math functions and proportional/integral control of the steam mass flow. Wort rises through the tube bundle in the calandria while heated by the down-flowing steam. The internal caldaria efficiently provides both heating and mixing of the wort. From the flowmeter. the basic beer solution. space for straight pipe to condition the steam flow (Figure 3). A deflector at the top of the calandria distributes the wort and prevents foam formation. 48). 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. the operator dials data representing the volume of wort in the kettle into an ABB ControlMaster CM10 flow computer. The CM30s compare the actual versus desired flow rate.

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

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

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

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

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. I am very happy with all of the instruments we’re using from Siemens Industry. and we were very surprised with the small size of the Sitrans LR560 and how much easier it was to install. 67 . and no maintenance is expected. Sitrans LR560 is available with HART. Our operators know what is going on throughout our process. During filling. Benefits Since the Sitrans LR560 was installed. We have acceptable performance from the Sitrans LR460. Profibus PA or Foundation fieldbus protocols. and we no longer have any overfilled silos or inaccurate readings from old technology. the cost of the new equipment was paid back well within the first year of its operation. There has been zero maintenance on the Sitrans LR560 since its installation. 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. Monte Smith is general manager at United Canadian Malt Ltd. and can be rotated in four positions. An integrated purge connection is readily available for self-cleaning of the antenna lens if the solids material is exceptionally sticky. 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. and reliable readings are provided all the way to the bottom of the cone area. graphical Quick Start Wizard that allowed operators to set up the Sitrans LR560 in a couple of minutes using the display pushbuttons. as the general manager at United Canadian Malt. Programming can be performed remotely with Simatic PDM (process device manager). UCML’s operators have noticed very stable readings from the transmitter. In fact. The local display interface has an easy-to-use.Technology in Action Sitrans LR560 uses a high frequency of 78 GHz and a unique lens antenna to provide a narrow 4° beam. set up and operate. AMS or PACTware with Siemens’ DTM. from completely empty to full.The 78-GHz frequency creates a very short wavelength that provides exceptional reflection from sloped surfaces and aiming is rarely necessary. The local display interface features a backlit display. how to make beer Figure 4. The brewing process at United Canadian Malt Ltd. UCML’s silo cleaning schedules have also benefitted from the Sitrans LR560’s compact design. Overall. and no additional fine-tuning was required. The extreme narrow beam of Sitrans LR560 provides plug-and-play performance. our operators simply keep an eye on the remote display. monitor the filling cycle and then shut the transfer system off if the level approaches the top of the silo.

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

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

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

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