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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


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

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

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

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

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

which brought it closer conformance to the SIS standards. even though ANSI/ISA S84 (1996. 2003) and IEC 61511 (2004) were in place at that time. the API 2350 4th Edition (2012) committee took the lessons learned to heart and introduced a number of new risk. For existing installations.Trends in Technology Buncefield. “Buncefield’s Legacy: API 2350’s New Requirements. wireless cellular networks and global satellite networks. can also be solar-powered. the standard provides two options for implementation. Operators are required to categorize each tank under consideration for overfill prevention based on tank level instrumentation and operator surveillance procedures.  Emphasis on proof-testing of independent alarms and AOPS. using any one of the more than 50 fieldbuses available. This standard divided facilities into attended and unattended operations.and performance-based requirements. From an instrumentation perspective. the API 2350. 6. depending on whether the installation is existing or new. M  ore emphasis on operator response time for level alarms. (2012) committee took the lessons learned to heart and introduced a number of new risk. A risk assessment shall be used by the owner and operator to categorize risks associated with potential tank overfills. ASIsafe). maximum working level (MW) and automated overfill prevention system (AOPS) activation level. We can easily digitally transmit multiple sensor inputs across a pair of wires. When an AOPS is required. high-reliability shutdown systems connected by Modbus to centralized 11 . There are wireless applications for tank monitoring systems available using IEEE 802. 4th Ed. 2. Profisafe. particularly on existing tanks.11a and WirelessHART).”) Buncefield’s Legacy: New API 2350 Requirements Because of Buncefield. or the operation was fully automatic. Appendix A of the standard provides an acceptable. Tank farm remoteness and geographical distribution often make them suitable for wireless monitoring applications. 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. Another developing technology is mobile wireless applications. not maximum. to monitor tank levels. in addition to the control room operator. API 2350 had minimal requirements for safety instrumentation and no requirement for evaluation of the safety risk. For attended facilities. These followed. a number which are third party-approved safety protocols (for example. which brought it closer conformance to the SIS standards. The definition of a set of operating parameters. A overfill management system is required. which can be easily added to existing tanks. 3. Some of API 2350’s new requirements are: 1.and performance-based requirements. essentially prescriptive approach that contains aspects of ANSI/ISA 84. which allow tank farm field operators.. ly/1oRKeQZ ) should not be hijacked by “minimum” safety requirements in a standard. alarms and an automatic shutdown if the operator response time was not adequate. while unattended facilities required continuous monitoring. ANSI/ISA 84. 4. reducing wiring costs.01-2004 (IEC 61511 modified) must be Technology Can Help Placing instrumentation on widely geographically distributed tanks. particularly for cost reasons. including critical high level (CH).01-2004 (IEC 61511 modified). 5. high-high level (HH). can be a challenge both technically and in cost.00. but technology has advanced significantly in the past 10 years.00. bit. Because of the Buncefield explosion. there were no requirements for level detectors on the tanks. (See sidebar. Available automated safety shutdown systems geared to the tank farm environment range from local. For new installations. This highlights a cautionary note that one should always remember: All standards provide minimum requirements.4 (ISA 100.15. Following good engineering practice and in most cases common sense (an old friend who some say has passed on. Foundation fieldbus.

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

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memory boards for data acquisition and storage for hundreds of thousands of data points for displaying of trends. while the d/p cell is in an easy-to-access location. Today. the 1%AR error of the sensor (the precision of its discharge coefficient CD). the flow turndown is 14:1. the d/p cell error is 12. the total error is kept under 5%of actual flow (AR). in the past. Head-Type Flowmeters When measuring flow by any differential pressure generating element. methane). which is usually about one percent of actual flow (%AR). and the error of the d/p cell. alarms. In addition to the tremendous increase in the accuracy of the state-of-the-art d/p cells. Now I will describe some other. if we wanted to keep the total error at minimum flow under 3%AR. 14 . allowing the sensor to be located in hard-to-access areas. the maximum turndown capability of a smart. Adding to this ΔP error. 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.6%AR at minimum flow. self diagnostics. which used to be around 0.25% to 0. n my May column. Therefore.Trends in Technology Advances in Flow Instrumentation by Bél a Lipták I with local displays. this minimum ΔP error corresponds to a minimum flow error of √ 12. digital ΔP transmitter is nearly 200:1.065 = 12.11). 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. With a ΔP measurement error of 0. the full 14:1 turndown can only be realized if at minimum flow (100/14 = 7% of full scale).74% AR at the minimum ΔP (196x 0. Because of the square root relationship.065%FS.74% = 3.74%).000). the measurement error is the sum of the sensor error. the flow is still turbulent (RE > 8. total flows. Naturally. water. I described some new fiber-optic flowmeters used for subsea measurement of multiphase flows (oil. gives us a total error of only 4. the flow turndown (rangeability) had to be limited to about 4:1. Figure 1 shows the relationship between the turndowns in terms of flow and the corresponding turndown requirement of the ΔP transmitter.5% of full scale (%FS). and to provide cell phone connectivity. They can be mounted to the sensor or connected wirelessly (IEEE802.6%AR. this means that the flow rangeability is 14:1 (142 = 196). Because of the square root relationship. and at the minimum flow (100/14 = 7%).

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

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

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

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

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

Trends in Technology Figure 3. The upper gain limit to prevent fast oscillations occurs when the closed loop time constant equals to the dead time. 9 The lower gain limit to prevent slow oscillations occurs when the product of the controller gain and reset time is too small. Performance of linear PID level controller for a conical tank. Ti Ki * [(λf /Ki) + θp ]2 3 Ki * 4 * θp  Eq. 7 21 . 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. Kc < Ti = 2 * (λf /Ki ) + θp Eq. 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.

Prakash Jagadeesan is an assistant professor at Madras Institute of Technology (MIT) Anna University in Chennai India. The adaptive controller employs an optimal search method with re-centering that finds the process dead time. 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. 22 . the adaptive level controller eliminates the oscillations at low levels. and provides a more consistent level response across the whole level range. Performance of adaptive PID level controller for conical tank. The process models are categorized into five regions as indicated in Figure 4.Trends in Technology Kc * Ti > 4 Ki  Eq. 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 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. Dr. oscillations. Greg McMillan is a consultant and ControlTalk columnist. Figure 3 shows that for setpoints ranging from 10% to 90%. 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. Adaptive level controllers can eliminate tuning problems from the extreme changes in level control dynamics associated with different equipment designs and operating conditions. and process gain that best fits the observed response. 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. with protection against going outside the controller gain limits helps provide a more consistent tuning criterion. a decrease in process time constant greater than the decrease in process gain at low levels causes excessive oscillations. Sridhar Dasani is a graduate of Madras Institute of Technology (MIT) Anna University in Chennai India. 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. 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. Figure 5. As seen in Figure 5. It was found that the use of lambda time. Process models automatically identified for operating regions. process time constant.

With no up or downstream piping requirements it can be installed in the tightest spaces. The new CoriolisMaster from ABB is one of the most compact coriolis mass flowmeters on the enabling applications not possible before. Its smaller size and simplicity saves you precious time in installation. www. set up and maintenance.CoriolisMaster. Enjoy! Learn more and download a FREE flow handbook. Measurement made ABB Measurement Products .abb.

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

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

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

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

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. so any related instruments are safety-critical. The report and order are located at http://hraunfoss. The new limits will still protect measure.05 to 29. Robinson previously used a simple.250 www. but it didn’t link to any wider control system. but it must store the CS2 under a layer of water to prevent it from AT100 magnetostrictive level transmitter. The rules now require opted rules allowing “level probing radars” (LPRs) to operate any- measuring emissions in the main beam of the LPR antenna. and can boost its resolution to more than 100 times greater than a conventional reed switch-type device (Figure 2). which provides continuous level AT100 28 . Federal surement procedures to provide more accurate and repeatable Communications Commission (FCC) reported Jan. the U.robinsonbrothers.-based Robinson Brothers is using a magnetorestrictive level transmitter from ABB to meet strict safety standards for handling highly reactive carbon disulfide (CS2). ABB Reining in Reactivity While its tank isn’t out on the ocean. and will become effective the similar European Telecommunications Standards Institute’s 30 days after ICA recommended using ABB’s (www. MCAA also sought LPRs to operate on an unlicensed basis in the 5.” new rules allow. for monitoring or control. Most importantly.Trends in Technology FCC Allows Unlicensed “Level Probing Radar” in Open Air In a long-awaited and helpful regulatory update. this because it will improve the global competitiveness of U. an instrumentation specialist in Manchester. U.00 GHz and 75 to 85 GHz bands. floatbased device to measure the CS2 and water level. 24. U. edocs_public/attachmatch/FCC-14-2A1. out the regulatory process. (ETSI) Technical Standard for LPR devices. upon reflection of those emissions. transmits analog and/or digital signals careful with chemicals Figure 2. 15 that it’s ad- measurement protocols for these devices.pdf. the order modifies Part 15 of the FCC’s rules for measurements on main-beam emission limits. of the instruments and their suitability for its widely varying process and revises the mea- level instrumentation manufacturers. which also bases its Specifically.-based Robinson Brothers (www. In addition. adjusting emission limits to account for attenuation that occurs The Measurement.209’s more flexible emis- former rules to allow unlicensed LPRs in “any type of tank or sion limits because some LPRs need wider bandwidths than the open-air installation. The company uses CS2 at its Midlands specialty chemicals plant.S. by changing these technical testing reports it worked closely with the FCC through- any nearby receivers from encountering interfering signal probably has an even more difficult level measurement challenge—securing level indications for highly reactive carbon disulfide (CS2).K.925 to 7. Robinson sought help from ICA Services (www.fcc.K. magnetic. rules for LPRs with lished shortly in the Federal Register.S. They will be pub- the new FCC rules partially harmonize U. This means the level of the interface between the water and CS2 needs constant monitoring. and where in the country without a license. U.S. Control & Automation (MCAA.

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

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

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

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

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

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

4000 mmWC.05trans. In practice. 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. for example. The calibrations in the examples were 0 to 1100. (Fill) example mitter may be calibrated with spans between (say) 400 second SG (Fill) and the mmWC and 4000 mmWC.10 LT Back to Basics SG = 1. tween 100 mmWC and 1000 mmWC. a given differential pressure SG = 1. the transmitter zero is raised by 770 mmWC.10where the span is 880 mmWC. The span of a transmitter is the difference between the to be changed by 1000 mmWC. However. Note that these techniques involve applying hydraulics to the installation and application. Nowhere do we use terms such as elevation.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. Using this lower range 37 100 S . instruments. 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. In addition. respectively. gravity? These are important questions that should be asked (and answered) when considering the use of differential pressure level measurement zero may also be raised or lowered by up to. suppression and span. the specific gravity of 770 to 1650. differential pressure measure.10 1000 mm calibrations for interface level measurements. so that differ.100% Level 0% Level 0 mm LT SG = 1. This transmitter would 100% and 0% calibration values. their zerosPressure by more than 4000 mmWC. 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.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. and -1145 to -265 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. For example. brations are within the transmitter specifications. all of these caliliquid level measurement applications. Each many liquids is known and relatively stable. it could SGbe = 1. However. and the zero is lowered by 1145 used in the spans. In addition. Repeating. 0% Level 100% Level 200mm What Ifs What if the liquid density changes during SG = 1. Therefore.10 SG = 1. 0% Level the level measurement. respectively.05 = 1.mmWC.

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

you can leave the climbing to us. temperature and PRECISION DIGITAL CORPORATION Since 1974 . interface level.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. density.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 will unleash a whole new dimension of display possibilities. Best of all. Paired with a new Precision Digital Modbus Scanner you can display multiple variables including level.

What this means is that the voltage induced on the electrodes is directly proportional to the average velocity in the pipe and is. we’ve been looking for the one flowmeter that will work in every application. In fact. as well. such as plastic. The first use of the technology was in the huge sluices that drained the Zuider Zee in the Netherlands in the 1950s. As used in an electromagnetic flowmeter. or even acceptably. or magmeter. com). the magnetic flowmeter is generally considered the most accurate wide-application flowmeter in current use. which reduces zero drift to almost nothing. a small voltage is induced on the electrodes. This deflection is the sum of all of the velocity vectors impinging on the magnetic field. According to Jesse Yoder at Flow Research (www. How it is possible to scale up and down this broadly is directly related to the technology. (914 mm). (3048 mm). They turn the field off. coils are placed parallel to flow and at right angles to a set of electrodes in the sides of the pipe. Michael Faraday formulated the law of electromagnetic induction that bears his name. They’re often used for custody transfer when the 40 . No single flow technology works well. the one that works in the most applications. approaching the accuracy of positive displacement flowmeters.Back to Basics Back to the Basics: Magnetic Flowmeters Close to being “Prince Flowmeter Charming. significantly more accurate than any other velocity-based measurement principle that only looks at a point or line velocity. by Walt Boyes E ver since the invention in the 1790s of the Woltman-style mechanical turbine flowmeter. Magmeters are used in every process industry vertical. and typically vendors supply a size range from ½ in. there are 12 flow measurement technologies in common use for a very good reason. Magmeters also are made in the widest size range of any flowmeter technology because they can be scaled up almost infinitely.and abrasion-resistant linings and even clean-in-place (CIP) designs. The pipe must be non-magnetic and lined with a non-magnetic material. in all applications. the total global market for flowmeters is roughly $4. with several vendors supplying extended sizes up to 120 ins.” magmeters do it (nearly) all. Several vendors sell sizes below ½ in. They are designed for handling almost all water-based chemicals and slurries and are furnished with corrosion. They do this several times a second. How a Magmeter Works In 1831.7 billion. therefore. proportional to the deflection of the magnetic field. When the fluid (which must be conductive and free of voids) passes through the coils. across most industries and with higher accuracy than even differential pressure is the electromagnetic flowmeter. Modern magmeters operate on a switched DC field principle to zero out ambient electrical noise and noise actually in the process fluid. Unfortunately. measure the voltage that’s still induced on the electrodes. rubber or Teflon. Of the more broadly based flow technologies.flowresearch. (12 mm) to 36 in. generating a standing magnetic field (see Figure 1). then turn the field back on and subtract the off-state voltage from the on-state voltage. and magnetic flowmeters account for a little less than 20% of that total.

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

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

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

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

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

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

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

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

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.


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

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

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. in the winter or dripping condensation in the summer. Make sure that there is not too much turbulence or ripples (or if the flume or weir is large enough. Above all. and sometimes fail spectacularly. as well as front to back through the measurement zone. 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. if you follow these basic guidelines. 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. 134. the speed of sound. 5. 6. It’s easy to go to them as the unthinking sensor of choice for level applications. This can happen often in nitrifying wastewater discharges. you will have successful ultrasonic level installations. which worked correctly. The One-Trick Pony—Not! Ultrasonic sensors are simple to understand. and I learned something. 5. therefore. 3. As with any other field instrument. The speed of sound changes with temperature and density. You may want to aim the sensor because of rat-holing and angle-of-repose issues at the top. ultrasonic sensors and transmitters are tricky beasts. The primary device (flume or weir) measures flow. Try to have the transmitter calculate what the actual level might be. In solids and powders. The flow transmitter takes the level signal and produces a flow value based on the primary device. Make provisions to keep ice from forming on the sensor open-channel flow Figure 4. Yet. wave action) on the surface. Make sure that there isn’t foam on the surface. midpoint or bottom of the angle of repose. Many problems blamed on the ultrasonic transmitter are actually problems that are caused by the flume not being installed level both horizontally and vertically. Walt Boyes is a principal with process measurement consultancy Spitzer & Boyes. But. applying an ultrasonic level sensor too far outside the manufacturer’s recommended application envelope is destined to fail. Avoid pressurized tanks. There are a few more: 1.56 Flow transmitter Parshall flume (typ. Avoid wind and sun.Back to Basics sensor with a FMCW radar sensor.) 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). as many users have found. just as many people go to differential pressure level sensors. 2. easy to install and inexpensive. Wind can blow through the vapor space and attenuate the signal or blow it off course. The level sensor works exactly the same way—measures level. and pressurizing the vapor space above the level can affect the density of the vapor space and. make sure that the flume or weir is installed correctly. 54 . Sun can raise the temperature of the sensor housing itself beyond the operating temperature range of the device—and higher than the ambient temperature.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

with annual savings projected to be $2 million.” Siscoe explained. either by line voltage or by solar power. “After extensive review of many types of meters from various manufacturers. 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. and they are difficult to use as a flow transmitters. As a pilot. with a mechanical register for totalizing water usage. “The MVIC’s long term goal is to fully automate the system by installing wireless flowmeters and automatic control valves downstream of the meters.” Another reason for using ultrasonic flowmeters was the drastically reduced maintenance requirement. which results in no “Wireless automation at these two turnouts will demonstrate to the MVIC and its shareholders the benefit of remote flow measurement and control. Most turnouts require only one setting per season.000 Conservation Innovation Grant from the USDA’s National Resources Conservation Service.dynasonics. These numbers would yield a payback in about 18 months.” Siscoe said.” Knudsen said. turbine and propeller meters are maintenance problems. particularly replacement of our impeller flowmeters. and its descendants are similar in design.000 to install an electrical The transit-time flowmeters use strap-on transducers. low cost.” Knudsen said. “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.or battery-powered. The project has been so successful that the U. a decision was made to purchase ultrasonic flowmeters from Dynasonics (www. “While the flowmeter is under battery power.S. “Based on this success. which function as ultrasonic transmitters and receivers.Technology in Action produced in the 18th century. MVIC decided to use transit-time flowmeters clamped to the outside of the HDPE pipe. “We especially like their non-intrusive aspect. “Using solar power saved $25. which is highly advantageous in Colorado. MVIC has ordered another solar powered flow control gate for another canal next winter.” A wireless SCADA system will be implemented at two turnouts. flexibility and ease of installation. Siscoe reported. But. general manager of MVIC. service line to this remote location.” Knudsen said. is that the flowmeters can be solar. Smaller turnouts are powered by the district’s “ditch riders. Bureau of Reclamation (USBR) is providing $2. seven-mile project.” “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.9 million. Knudsen reported that the final project costs were $2. The large turnouts are supplied with continuous power. Walt Boyes is a principal with process measurement consultancy Spitzer & Boyes. They are very accurate and designed for water billing service.” said Jim Siscoe.” Knudsen said. “The Dynasonics flowmeters are now our standard for both new and retrofit applications. One of the reasons. 71 . 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. the district received a $75.1 million in stimulus grants to MVIC for construction of a second.” who carry portable 12-VDC batteries with them. “the measured flow rate is used to manually adjust flow via the butterfly valve immediately downstream from the meter.” The district now has to keep only one type of flowmeter in inventory.