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Instrumentation course Document Transcript

  • 1. Oil and Gas Measuring Instruments Course Aim The aim of this training course is to build up the procedural and declarative knowledge required to be recognized by projects engineer that do not have past background of oil and gas measuring instruments. This will help them to supervise projects dealing with instrumentation in plants with a strong background. In this course, the training cycle is divided in five steps that necessitate the cooperation between the instructor and the trainees. These steps are shown in figure below, they are summarized as follows: 1. Define the knowledge and skills required to be developed. 2. Define the elements of each knowledge or skill. 3. Formulate a verbal phrase for the learning objective of each element. 4. Choose an adequate instructional activity to present each element. 5. Set up an indicator to measure the outcomes of the course and modify the training skills to adapt the vocational needs. Define Knowledge Determine & Skills Elements Measure Learning & Correction Objectives Instruction Activity Training Cycle. 1
  • 2. Oil and Gas Measuring Instruments Knowledge and Elements  Introduction to measurements.  Introduce general terms.  Introduce quantities and units.  Distinguish between different gauges and switches.  Introduce how quantity is measured.  Illustrate main components of instrument.  Classify different types of measuring instruments.  Develop knowledge about different transmitters and sensing elements.  Establish knowledge base about transmitter technology.  Introduce Sensing Element.  Introduce theory of operation.  Introduce some analyzers.  Gas Chromatography.  Moisture Analyzer.  Oxygen Analyzer. 2
  • 3. Oil and Gas Measuring Instruments Table of Contents Section I Chapter 1 Introduction to Measuements 5 Chapter 2 Transmitters 16 Section II Chapter 3 Mechanical Transducers 25 Chapter 4 Electric Transducers 36 Chapter 5 Flowmeters 73 Section III Chapter 6 Analyzers 102 Chapter 7 Basic Considerations 109 3
  • 4. Oil and Gas Measuring Instruments 4
  • 5. Oil and Gas Measuring Instruments Chapter 1 Introduction to Measurement 1.1 Learning objectives 1. Introduce measurements and instruments. 2. Classify instruments and functions. 3. Understand instruments characteristics. 1.2 Measurements The measurement of a given quantity is an act or the result of comparison between the quantity and a predefined standard. Since two quantities are compared, the result is expressed in numerical values. In fact, the measurement is the process by which one can convert physical parameters to meaningful numbers. In order that the results are meaningful, there are two basic requirements: 1. The standard used for comparison purposes must be accurately defined and should be commonly accepted. 2. The apparatus used and the method adopted must be proved. 1.2.1 Significance of Measurements The advancement of science and technology is dependent upon a parallel progress in measurement techniques. There are two major functions in all branches of engineering: 1. Design of equipment and processes. 2. Proper operation and maintenance of equipment and processes. Both of these functions require measurements. 5
  • 6. Oil and Gas Measuring Instruments 1.2.2 Methods of Measurements  Direct Method: The unknown quantity is directly compared against a standard.  Indirect Method: Measurement by direct methods are not always possible, feasible and practicable. These methods in most of the cases are inaccurate because of human factors. They are also less sensitive. 1.2.3 Instruments In simple cases, an instrument consists of a single unit which gives an output reading or signal according to the unknown variable applied to it. In more complex situations, a measuring instrument consists of several separate elements. These elements may consist of transducer elements which convert the measurand to an analogous form. The analogous signal is then processed by some intermediate means and then fed to the end devices to present the results for the purposes of display and or control. These elements are:  A detector.  An intermediate transfer device.  An indicator. The history of development of instruments encompasses three phases:  Mechanical.  Electrical.  Electronic. 6
  • 7. Oil and Gas Measuring Instruments 1.2.4 Classification of Instruments  Absolute instruments: These instruments give the magnitude of the quantity under measurement in terms of physical constants of the instrument. Example: Galvanometer.  Secondary Instrument: These instruments are constructed that the quantity being measured can only be measured by observing the output indicated by the instrument. 1.2.4.1 Deflection Type The deflection of the instrument provides a basis for determining the quantity under measurement as shown in figure (1.1). Figure 1.1 Deflection Type 1.2.4.2 Null Type A zero or null indication leads to determination of the magnitude of measured quantity as shown in figure (1.2). 7
  • 8. Oil and Gas Measuring Instruments Figure 1.2 Null Type 1.2.4.3 Contact Type Often when a measured pressure reaches a certain max or min value, it is desirable to have an alarm sound a warning, a light to give a signal, or an auxiliary control system to energize or de-energize. A micro switch is the device commonly used for this purpose. Figure 1.3 Contact Type 8
  • 9. Oil and Gas Measuring Instruments 1.2.5 Analog and Digital Modes of Operation  Analog Signal: signals that vary in a continuous fashion and take an infinite number of values in any given range.  Digital signal: signals that vary in discrete steps and thus take only finite different values in a given range. 1.2.6 Functions of Instruments  Indicating function.  Recording function.  Controlling Function. 1.3 Characteristics of Instruments 1.3.1 Performance It is to define a set of criteria that gives a meaningful description of quality of measurement. Performance characteristics are obtained in one form or another by a process called calibration. The calibration of all instruments is important since it affords the opportunity to check the instrument against a known standard. 1.3.2 Errors in Measurement Measurements always involve errors. No measurement is free from errors. An understanding and thorough evaluation of the errors is essential. 9
  • 10. Oil and Gas Measuring Instruments Figure 1.4 Visual error 1.3.3 True Value True Value: The true value of quantity to be measured may be defined as the average of an infinite number of measured values when the average deviation due to the various contributing factors tends to zero. 1.3.4 Ranges  Scale range: it is defined as the difference between the largest and the smallest reading of the instrument, i.e. scale range from 200 to 500 degree C.  Scale Span: It is may be confusing with scale range but it is given to be 300 degree C.  Effective Range: It is defined as the range over which it meets some specified accuracy requirements.  Rangeability (turndown): If the effective range is from A to B, then the rangeability is defined by B/A. 1.3.5 Discrimination, Accuracy, Error, Precision and Sensitivity  Discrimination (Resolution): It is used to describe how finely an instrument can measure. For example, the discrimination of a 10
  • 11. Oil and Gas Measuring Instruments digital electronic timer reading in milliseconds is a hundred times as great as that of a stopwatch graduated in tenths of seconds. It is often wrongly referred as sensitivity.  Accuracy: It is the closeness with which the instrument reading approaches the true value of the quantity. Thus accuracy means conformity to truth.  Error: It is defined as the difference between the measured value and the true value. One kind of error is observational error.  Precision: It is a measure of the degree of agreement within a group of measurements. High precision means a tight cluster and repeated results while low precision indicates a broad scattering of results.  Certainty: It is often used as a synonym for accuracy. However, Uncertainty is the property of a measurement rather than the instrument used to make the measurement.  Sensitivity: It is a measure of how an instrument is sensitive to the measured quantity variation. It is the ability to produce detectable output. Figure 1.5 Accuracy and Repeatability 1.3.6 Reproducibility, Repeatability and Hysteresis  Reproducibility: It is the closeness of agreement among repeated measurements of the output for the same value of input mode under 11
  • 12. Oil and Gas Measuring Instruments the same operating condition over a period of time, approaching from both directions.  Repeatability: It is the closeness of agreement among a number of consecutive measurements of the output for the same value of input under the same operating conditions, approaching from the same direction. Figure 1.6 Repeatability  Hysteresis and Dead Band: It is the maximum difference for the same input between the upscale and downscale output values during a full range transverse in each direction.  Dead Time: It is defined as the time required by an instrument to begin to respond to a change in the measurand.  Dead Zone: It is defined as the largest change in which there is no output from the instrument. 12
  • 13. Oil and Gas Measuring Instruments Figure 1.7 Hysteresis and Dead band 1.3.7 Drift Perfect Reproducibility means no drift. No drift means that with a given input the measured values do not vary with time.  Zero Drift: if the whole calibration gradually shifts.  Span Drift: If there is a proportional change in the indication all along the upward scale.  Zonal Drift: In case the drift occurs only over a portion of the span. Figure 1.8 Drift 13
  • 14. Oil and Gas Measuring Instruments 1.3.8 Noise A spurious current or voltage extraneous to the current or voltage of interest in an electrical or electronic circuit is called noise. 1.3.9 Linearity It is the closeness to which a curve approximates a straight line. It is a measure of the extent to which the instrument calibration curve over its effective range departs from the best fitting straight line. Figure 1.9 Linearity 1.3.10 Loading Effects The ideal situation in a measuring system is that when an element used for any purpose, the original signal should remain undistorted. In practical conditions, it has been found that any element in the system extracts energy and thereby distorting the original signal. 14
  • 15. Oil and Gas Measuring Instruments 1.3.11 Other Effects  Temperature Effect  Pressure Effect  Vibration Effect 1.4 Role Play Each Trainee should speak thoroughly about one of the learning objective elements. 15
  • 16. Oil and Gas Measuring Instruments Chapter 2 Transmitters 2.1 Learning Objectives 1. Introduce history of transmitter technology. 2. Understand analog transmitters. 3. Understand smart transmitters with HART protocol. 2.2 Transmitter Technology Transmitters are instruments that transfer measured output signal to distance places where it is needed. The technology development through years is: 1. Pneumatic and Hydraulic. 2. Electrical (Analog – 4-20 mA). 3. Electronic (Analog – 4-20 mA + Digital – HART protocol). 4. Electronic (All digital – Foundation Fieldbus). Figure 2.1 Pneumatic Transmitter 16
  • 17. Oil and Gas Measuring Instruments 2.3 Analog Transmitters Analog transmitter uses a variable conversion element to translate and accommodate the physical non-electrical measurand to electrical analog signal (4-20 mA). Figure 2.2 Analog Transmitter 2.3.1 Measurement Converters of Electrical Quantities  Measuring amplifiers: demands on measuring amplifiers, negative feedback, ideal operational amplifier, basic circuits of measuring amplifiers using operational amplifiers (OAs)  Measurement of low voltages and currents using OAs, estimating uncertainty of measurement (including influence of input voltage offset and input bias).  Rectifiers (converters of the rectified mean value). 2.3.2 Ideal Operational Amplifiers Figure 2.3 Ideal OP-Amp 17
  • 18. Oil and Gas Measuring Instruments 2.3.3 Inverting amplifier Figure 2.4 Inverting Amplifier 2.3.4 Current to Voltage Converter Figure 2.5 Current to Voltage converter 2.3.5 Voltage Controlled Current Source Figure 2.6 Voltage controlled Current source 2.3.6 Rectifiers Figure 2.7 Rectifier 18
  • 19. Oil and Gas Measuring Instruments 2.3.7 Adders Figure 2.8 Adders 2.3.8 Differential Amplifiers Figure 2.9 Differential Amplidier 2.3.9 Integrators Figure 2.10 Integrators 19
  • 20. Oil and Gas Measuring Instruments 2.4 HART Protocol 2.4.1 HART Overview For many years, the field communication standard for process automation equipment has been a milliamp analog current signal. HART field communications protocol extends the 4-20 mA standards to enhance communication with smart field instruments. It was designed for use with intelligent measurement and control instruments which traditionally communicate using mA analog signals. HART preserves the 4-20 mA signals and enables two way digital communications to occur without affecting the integrity of 4-20 mA signal. Figure 2.11 Hart Digital Signal HART, highway addressable remote transducer, makes use of Bell 202 FSK standard to superimpose digital signal at a low level on top of analog signal; i.e. 1200 Hz for logic 1 and 2200 Hz for logic 0. HART communicates 1200 bps without interrupting the mA signal and allows a host application to get two or more digital updates per second from a field device. 20
  • 21. Oil and Gas Measuring Instruments Figure 2.12 HART Connection HART is a master/slave protocol which means that a field device (slave) only speaks when spoken to by a master. HART provides for up to two masters, primary and secondary, as shown in figure (2.12). Figure 2.13 Master/Slave The most commonly employed communication mode is the master/slave, figure (2.13). The optional burst communication mode where a slave device can continuously broadcast a HART reply message, figure (2.14). Figure 2.14 Burst 2.4.2 HART Benefits 2.4.2.1 35-40 data items Standard in every HART device  Device Status & Diagnostic Alerts;  Process Variables & Units;  Loop Current & % Range;  Basic Configuration Parameters;  Manufacturer & Device Tag; 21
  • 22. Oil and Gas Measuring Instruments 2.4.2.2 Increases control system integrity  Get early warning of device problems;  Use capability of multi-variable devices;  Automatically track and detect changes (mismatch) in Range or Engineering Units;  Validate PV and Loop Current values at control system against those from device; 2.4.2.3 HART is Safe, Secure, and Available  Tested and Accepted global standard;  Supported by all major instrumentation manufacturers; 2.4.2.4 Saves Time and Money  Install and commission devices in fraction of the time;  Enhanced communications and diagnostics reduce maintenance & downtime;  Low or no additional cost by many suppliers; 2.4.2.5 Improves Plant Operation and Product Quality  Additional process variables and performance indicators  Continuous device status for early detection of warnings and errors  Digital capability ensures easy integration with plant networks 2.4.2.6 Protects Your Asset Investments  Compatible with existing instrumentation systems, equipment and people  Allows benefits to be achieved incrementally  No need to replace entire system 22
  • 23. Oil and Gas Measuring Instruments 2.5 Role Play Each Trainee should speak thoroughly about one of the learning objective elements.  Analog Transmitters  Smart Transmitters and HART Protocol. 23
  • 24. Oil and Gas Measuring Instruments 24
  • 25. Oil and Gas Measuring Instruments Chapter 3 Mechanical Transducers 3.1 Learning objectives 1. Understand the theory of operation of different sensing elements. 3.2 Springs Most mechanical input instruments employ mechanical springs of one form or another. Various common types of springs are shown in figure (3.1). These range from cantilever, helical and spiral springs. Figure 3.1 Springs 3.3 Pressure Sensing Elements Most pressure devices use elastic elements for sensing pressure at the primary stage. A link and gear mechanism are used to convert the movement to rotational motion to be connected the scale and pointer. 25
  • 26. Oil and Gas Measuring Instruments 3.3.1 Bourdon Tubes The bourdon tubes are made out of an elliptical flattened bent tube. One end is sealed and the other is open for fluid to enter. The pressure of the fluid tends to straighten out the tube. This motion is transferred to the pointer. 3.3.1.1 C-Type It is the most used for local indication. Figure 3.2 Bourdon Type 26
  • 27. Oil and Gas Measuring Instruments 3.3.1.2 Spiral Type Increasing the number of turns will increase the displacement of the free tip without changing the wall thickness. Figure 3.3 Spiral type 3.3.1.3 Helical Type The displacement of the tip of the helical type is larger than that of the spiral one. Figure 3.4 Helical type 3.3.2 Bellows A metallic bellows is a series of circular parts, resembling the folds in an accordion. The parts are designed in such a way that there are expanded and contracted. 27
  • 28. Oil and Gas Measuring Instruments Figure 3.5 Bellows Type 3.3.3 Diaphragms The operating principle of diaphragm elements is similar to that of the bellows. The pressure applied causes it to deflect where the deflection is proportional to the applied pressure. Figure 3.6 Diaphragm Type 28
  • 29. Oil and Gas Measuring Instruments 13.4 Temperature Sensing Elements 3.4.1 Bimetallic Thermometer They are used for local temperature measurements. It is constructed by bonding two different metals such that they cannot move relative to each other. All metals try to change their physical dimensions at different rates when subjected to same change in temperature. The differential change in expansion of two metals results in bending or flattening the structure, which in turn moves the pointer via the intermediate element. 3.4.1.1 Strip Figure 3.7 Strip Type 3.4.1.2 Spiral Figure 3.8 Spiral type 29
  • 30. Oil and Gas Measuring Instruments 3.4.1.3 Helical Figure 3.9 Helical Type 3.4.2 Distance Reading There are three basic types of distant reading thermometers.  Liquid filled  Gas filled  Combination liquid-vapor filled The thermometers are filled with fluid at some temperature and sealed. Almost the entire volume of the fluid is in the sensing bulb. Figure 3.10 Distance Reading Type 30
  • 31. Oil and Gas Measuring Instruments 3.5 Level Sensing Elements Figure 3.11 Installation 3.5.1 Transparent Glass Sight Glasses for Level Gauges grant the best chemical and physical properties, holding a very precise place as for chemical composition within the very large group of "Borosilicate Glass" which is suitable for many applications. Figure 3.12 Level Glass 3.5.2 Circular Sight Ports These are used to allow observation within sealed vessels. Figure 3.13 Dight Port 31
  • 32. Oil and Gas Measuring Instruments 3.5.3 Reflex Type Reflex level gauges working principle is based on the light refraction and reflection laws. Reflex level gauges use glasses having the face fitted towards the chamber shaped to have prismatic grooves with section angle of 90°. When in operation, the chamber is filled with liquid in the lower zone and gases or vapors in the upper zone; the liquid level is distinguished by different brightness of the glass in the liquid and in the gas/vapor zone. The reflex level gauges do not need a specific illumination: the day environmental light is enough. Only during the night an artificial light must be provided. Figure 3.14 Reflex Type 3.5.4 Bicolor Type An illuminator with special red and a green filters is fitted on the gauge at the opposite side with respect to the observer. This special illuminator conveys light through the filters obliquely to the back glasses of the level gauge. Said filters allow crossing only to red and green rays. Such colored rays reach, through the back glass, the media inside level body. When the gauge contains steam, green rays are considerably deviated and prevented from emerging by the observer side; then only red light, whose rays are smoothly deviated by steam, passes through the whole internal hole, reaching the observer. Conversely when rays find 32
  • 33. Oil and Gas Measuring Instruments water, red rays are considerably deviated and lost inside the internal part of level gauge, green rays can reach the front glass and seen by the observer. Figure 3.15 Bicolor Type 3.5.5 Magnetic Type Operation of BONT Magnetic Level Gauge is based on some elementary physical principles:  The principle whereby liquid in communicating vessels is always at same level;  Archimedess principle according to which a body immersed in a liquid receives a buoyancy equal to the weight of displaced liquid;  The principle of attraction between North and South poles of two permanent magnets and that of repulsion between like poles. o This principle has two applications in the BONT magnetic level gauge:  first between the magnet in the chamber float and every single magnet of the indicating scale:  Second between the magnets of the indicating scale. 33
  • 34. Oil and Gas Measuring Instruments Figure 3.16 Magnetic Type 3.5.6 Gamma Level Switching The transmission of gamma radiation through a container is affected by the level contents. The intensity of the transmitted radiation is measured and used to activate switches when pre-set intensity levels are reached. Figure 3.17 Gamma Rays Type 3.6 Seismic Transducer (Vibration) A schematic diagram is shown in figure (3.18). The mass is connected through a spring and damper arrangement to a housing frame. The housing frame is connected to the source of vibrations to be 34
  • 35. Oil and Gas Measuring Instruments measured. The mass has the tendency to remain fixed in its spatial position so that the vibration motion is registered as a relative displacement between mass and housing frame. The seismic transducer may be used in two different modes. A large mass and a soft spring are suited for displacement mode, while a relatively small mass and a stiff spring are used for acceleration mode. Figure 3.18 Seismic Type 3.7 Role Play Each Trainee should speak thoroughly about:  Pressure Sensing  Level Sensing  Temperature Sensing  Vibration Switches. 35
  • 36. Oil and Gas Measuring Instruments Chapter 4 Electrical Transducers 4.1 Learning objectives 1. Introduce electrical transducers. 2. Understand the theory of operation of different transducers. 4.2 Introduction In order to measure non-electrical quantities, a detector is used usually to convert the physical quantity into a displacement. In electrical transducers the output is different, it is in electrical form. The output gives the magnitude of the measurand. The electric signal may be current, voltage or frequency and production of these signals is based upon electrical effects which may be resistance, capacitance, induction, etc. A transducer may be defined as a device, which converts energy from one form to another. In electrical instrumentation, a transducer may be defined as a device which converts a physical quantity into electrical signal. Another name of a transducer is pick up. 4.2.1 Advantages of Electrical Transducers  Amplification and attenuation may be done easily.  The mass-inertia effects are minimized.  The effects of friction are minimized.  Low power level.  Use of telemetry. 36
  • 37. Oil and Gas Measuring Instruments 4.2.2 Classification of Transducers The transducer consists of two closely related parts:  Detector Element: It is the part that responds to physical phenomenon.  Transduction Element: It transforms the output of the sensing element to an electrical output. Classification of transducers is as follows:  Based on Transduction: like piezoelectric, thermoelectric, etc.  Primary and Secondary: Example, a primary part that transforms pressure into displacement and secondary part that transforms displacement into electrical form.  Passive and Active: Depends on whether the transducer will derive power from or to the circuit.  Analog and Digital: Analog continuous form like voltage or digital form like pulses.  Transducers and Inverse Transducers: It depends whether the transducer convert physical quantity to electrical signal or vice versa. 4.3 Pressure Sensing Elements 4.3.1 Strain Gauges If a metal conductor is stretched or compressed, its resistance changes on account of the fact that both length and diameter are changed. This property is called piezoresistivity. Figure 4.1 Strain Gauge 37
  • 38. Oil and Gas Measuring Instruments 4.3.2 Inductive Type Figure (4.2) shows an arrangement which uses coils to form the two arms of an AC bridge. The pressure acts on the diaphragm and disturbs the reluctance of the paths of magnetic flux for both coils. Figure 4.2 Inductive Type 4.3.3 Capacitive Type They convert pressure into displacement which changes the capacitance value by changing the distance between the two parallel plates of a capacitor. Figure 4.3 Capacitive Type 38
  • 39. Oil and Gas Measuring Instruments 4.3.4 Linear Variable differential Transformer The LVDT is used as secondary transducer for measurement of pressure. The pressure is converted into displacement which is sensed by LVDT and converted into a voltage. Figure 4.4 LVDT 4.3.5 Photoelectric Type As shown in figure (4.5) the light path is affected by the applied pressure which in turn affects the quantity of light received by the photoelectric transducer. Figure 4.5 Photoelectric Type 39
  • 40. Oil and Gas Measuring Instruments 4.3.6 Piezoelectric Type A piezoelectric material is one in which an electric potential appears across certain surfaces if the dimensions of the crystal are changed by the application of mechanical force. The potential is produced by the displacement of charges. The effect is reversible and is known as the piezoelectric effect. Figure 4.6 Piezoelectric Type 4.4 Temperature Sensing Elements 40
  • 41. Oil and Gas Measuring Instruments 4.4.1 Thermocouple The thermocouple is one of the simplest of all sensors. It consists of two wires of dissimilar metals joined near the measurement point. The output is a small voltage measured between the two wires. Figure 4.7 The thermocouple While appealingly simple in concept, the theory behind the thermocouple is subtle, the basics of which need to be understood for the most effective use of the sensor. 4.4.1.1 Thermocouple theory A thermocouple circuit has at least two junctions: the measurement junction and a reference junction. Typically, the reference junction is created where the two wires connect to the measuring device. This second junction it is really two junctions: one for each of the two wires, but because they are assumed to be at the same temperature (isothermal) they are considered as one (thermal) junction. It is the point where the metals change - from the thermocouple metals to what ever metals are used in the measuring device - typically copper. The output voltage is related to the temperature difference between the measurement and the reference junctions. This is phenomena is known as the Seebeck effect. In practice the Seebeck voltage is made up of two components: the Peltier voltage generated at the junctions, plus the Thomson voltage generated in the wires by the temperature gradient. 41
  • 42. Oil and Gas Measuring Instruments Figure 4.8 Signal generated by temperature gradient The Peltier voltage is proportional to the temperature of each junction while the Thomson voltage is proportional to the square of the temperature difference between the two junctions. It is the Thomson voltage that accounts for most of the observed voltage and non-linearity in thermocouple response. Each thermocouple type has its characteristic Seebeck voltage curve. The curve is dependent on the metals, their purity, their homogeneity and their crystal structure. In the case of alloys, the ratio of constituents and their distribution in the wire is also important. These potential inhomogeneous characteristics of metal are why thick wire thermocouples can be more accurate in high temperature applications, when the thermocouple metals and their impurities become more mobile by diffusion. 4.4.1.2 The practical considerations of thermocouples The above theory of thermocouple operation has important practical implications that are well worth understanding: 1. A third metal may be introduced into a thermocouple circuit and have no impact, provided that both ends are at the same temperature. This means that the thermocouple measurement junction may be soldered, brazed or welded without affecting the thermocouples calibration, as long as there is no net temperature gradient along the third metal. Further, if the measuring circuit metal (usually copper) is different to that of the thermocouple, then provided the temperature of the two connecting 42
  • 43. Oil and Gas Measuring Instruments terminals is the same and known, the reading will not be affected by the presence of copper. 2. The thermocouples output is generated by the temperature gradient along the wires and not at the junctions as is commonly believed. Therefore it is important that the quality of the wire be maintained where temperature gradients exists. Wire quality can be compromised by contamination from its operating environment and the insulating material. For temperatures below 400°C, contamination of insulated wires is generally not a problem. At temperatures above 1000°C, the choice of insulation and sheath materials, as well as the wire thickness, become critical to the calibration stability of the thermocouple. The fact that a thermocouples output is not generated at the junction should redirect attention to other potential problem areas. 3. The voltage generated by a thermocouple is a function of the temperature difference between the measurement and reference junctions. Traditionally the reference junction was held at 0°C by an ice bath: Figure 4.9 Traditional Thermocouple Measurement The ice bath is now considered impractical and is replaced by a reference junction compensation arrangement. This can be accomplished by measuring the reference junction temperature with an alternate temperature sensor (typically an RTD or thermistor) and applying a correcting voltage to the measured thermocouple voltage before scaling to temperature. 43
  • 44. Oil and Gas Measuring Instruments Figure 4.10 Modern Thermocouple Measurement The correction can be done electrically in hardware or mathematically in software. The software method is preferred as it is universal to all thermocouple types (provided the characteristics are known) and it allows for the correction of the small non-linearity over the reference temperature range. 4. The low-level output from thermocouples (typically 50mV full scale) requires that care be taken to avoid electrical interference from motors, power cable and transformers. Twisting the thermocouple wire pair (say 1 twist per 10 cm) can greatly reduce magnetic field pickup. Using shielded cable or running wires in metal conduit can reduce electric field pickup. The measuring device should provide signal filtering, either in hardware or by software, with strong rejection of the line frequency (50/60 Hz) and its harmonics. 5. The operating environment of the thermocouple needs to be considered. Exposure to oxidizing or reducing atmospheres at high temperature can significantly degrade some thermocouples. Thermocouples containing rhodium (B, R and S types) are not suitable under neutron radiation. 4.4.1.3 The advantages and disadvantages of thermocouples Because of their physical characteristics, thermocouples are the preferred method of temperature measurement in many applications. They can be very rugged, are immune to shock and vibration, are useful 44
  • 45. Oil and Gas Measuring Instruments over a wide temperature range, are simple to manufactured, require no excitation power, there is no self heating and they can be made very small. No other temperature sensor provides this degree of versatility. Thermocouples are wonderful sensors to experiment with because of their robustness, wide temperature range and unique properties. On the down side, the thermocouple produces a relative low output signal that is non-linear. These characteristics require a sensitive and stable measuring device that is able provide reference junction compensation and linearization. Also the low signal level demands that a higher level of care be taken when installing to minimize potential noise sources. The measuring hardware requires good noise rejection capability. Ground loops can be a problem with non-isolated systems, unless the common mode range and rejection is adequate. 4.4.1.4 Types of thermocouple About 13 standard thermocouple types are commonly used. Eight have been given an internationally recognized type designator. Some of the non-recognized thermocouples may excel in particular niche applications and have gained a degree of acceptance for this reason, as well as due to effective marketing by the alloy manufacturer. Each thermocouple type has characteristics that can be matched to applications. Industry generally prefers K and N types because of their suitability to high temperatures, while others often prefer the T type due to its sensitivity, low cost and ease of use. A table of standard thermocouple types is presented below. The table also shows the temperature range for extension grade wire in brackets. 45
  • 46. Oil and Gas Measuring Instruments Positive Negative Accuracy*** Range °C Type Comments Material Material Class 2 (extension) Good at high temperatures, 0.5% 50 to 1820 B Pt, 30%Rh Pt, 6%Rh no reference junction >800°C (1 to 100) compensation required. 1% 0 to 2315 Very high temperature use, C** W, 5%Re W, 26%Re >425°C (0 to 870) brittle 1% 0 to 2315 Very high temperature use, D** W, 3%Re W, 25%Re >425°C (0 to 260) brittle -270 to 1000 General purpose, low and E Ni, 10%Cr Cu, 45%Ni 0.5% or 1.7°C (0 to 200) medium temperatures 1% 0 to 2315 Very high temperature use, G** W W, 26%Re >425°C (0 to 260) brittle -210 to 1200 High temperature, reducing J Fe Cu, 45%Ni 0.75% or 2.2°C (0 to 200) environment Ni, 2%Al General purpose high -270 to 1372 K* Ni, 10%Cr 2%Mn 0.75% or 2.2°C temperature, oxidizing (0 to 80) 1%Si environment M** Ni Ni, 18%Mo 0.75% or 2.2°C -50 to 1410 . Ni, Relatively new type as a Ni, 14%Cr -270 to 1300 N* 4.5%Si 0.75% or 2.2°C superior replacement for K 1.5%Si (0 to 200) 0.1%Mg Type. A more stable but P** Platinel II Platinel II 1.0% 0 to 1395 expensive substitute for K & N types -50 to 1768 R Pt, 13%Rh Pt 0.25% or 1.5°C Precision, high temperature (0 to 50) -50 to 1768 S Pt, 10%Rh Pt 0.25% or 1.5°C Precision, high temperature (0 to 50) Good general purpose, low -270 to 400 T* Cu Cu, 45%Ni 0.75% or 1.0°C temperature, tolerant to (-60 to 100) moisture. * Most commonly used thermocouple types, ** Not ANSI recognized types. *** See IEC 584-2 for more details. Materials codes:- Al = Aluminum, Cr = Chromium, Cu = Copper, Mg = Magnesium, Mo = Molybdenum, Ni = Nickel, Pt = Platinum, Re = Rhenium, Rh = Rhodium, Si = Silicon, W = Tungsten 46
  • 47. Oil and Gas Measuring Instruments 4.4.1.5 Accuracy of thermocouples Thermocouples will function over a wide temperature range - from near absolute zero to their melting point, however they are normally only characterized over their stable range. Thermocouple accuracy is a difficult subject due to a range of factors. In principal and in practice a thermocouple can achieve excellent results (that is, significantly better than the above table indicates) if calibrated, used well below its nominal upper temperature limit and if protected from harsh atmospheres. At higher temperatures it is often better to use a heavier gauge of wire in order to maintain stability. As mentioned previously, the temperature and voltage scales were redefined in 1990. The eight main thermocouple types - B, E, J, K, N, R, S and T - were re-characterized in 1993 to reflect the scale changes. (See: NIST Monograph 175 for details). The remaining types: C, D, G, M and P appear to have been informally re-characterized. 4.4.1.6 Thermocouple wire grades There are different grades of thermocouple wire. The principal divisions are between measurement grades and extension grades. The measurement grade has the highest purity and should be used where the temperature gradient is significant. The standard measurement grade (Class 2) is most commonly used. Special measurement grades (Class 1) are available with accuracy about twice the standard measurement grades. The extension thermocouple wire grades are designed for connecting the thermocouple to the measuring device. The extension wire may be of different metals to the measurement grade, but are chosen to have a 47
  • 48. Oil and Gas Measuring Instruments matching response over a much reduced temperature range - typically - 40°C to 120°C. The reason for using extension wire is reduced cost - they can be 20% to 30% of the cost of equivalent measurement grades. Further cost savings are possible by using thinner gauge extension wire and a lower temperature rated insulation. Note: When temperatures within the extension wires rating are being measured, it is OK to use the extension wire for the entire circuit. This is frequently done with T type extension wire, which is accurate over the - 60 to 100°C range. 4.4.1.7 Thermocouple wire gauge At high temperatures, thermocouple wire can under go irreversible changes in the form of modified crystal structure, selective migration of alloy components and chemical changes originating from the surface metal reacting to the surrounding environment. With some types, mechanical stress and cycling can also induce changes. Increasing the diameter of the wire where it is exposed to the high temperatures can reduce the impact of these effects. The following table can be used as a very approximate guide to wire gauge: 48
  • 49. Oil and Gas Measuring Instruments 8 Gauge 16 Gauge 20 Gauge 24 Gauge 28 Gauge 30 Gauge Type 4.06mm 1.63mm 0.91mm 0.56mm 0.38mm 0.32mm B 1820 - - 1700 1700 - C 2315 2315 2315 2315 2315 - D 2315 2315 2315 2315 2000 - E 870 620 540 430 400 370 G 2315 2315 2315 2315 2315 - J 760 560 480 370 370 320 K 1260* 1000* 980 870 820 760 M 1260* 1200* - - - - N 1260* 1000* 980 870 820 760 P 1395 - 1250 1250 1250 - R 1760 - - 1480 1480 - S 1760 - - 1480 1480 - T 400 370 260 200 200 150 * Upper temperature limits only apply in a protective sheath At these higher temperatures, the thermocouple wire should be protected as much as possible from hostile gases. Reducing or oxidizing gases can corrode some thermocouple wire very quickly. Remember, the purity of the thermocouple wire is most important where the temperature gradients are greatest. It is with this part of the thermocouple wiring where the most care must be taken. Other sources of wire contamination include the mineral packing material and the protective metal sheath. Metallic vapor diffusion can be significant problem at high temperatures. Platinum wires should only be used inside a nonmetallic sheath, such as high-purity alumna. 49
  • 50. Oil and Gas Measuring Instruments High temperature measurement is very difficult in some situations. In preference, use non-contact methods. However this is not always possible, as the site of temperature measurement is not always visible to these types of sensors. 4.4.1.8 Color coding of thermocouple wire The color coding of thermocouple wire is something of a nightmare! There are at least seven different standards. There are some inconsistencies between standards, which seem to have been designed to confuse. For example the color red in the USA standard is always used for the negative lead, while in German and Japanese standards it is always the positive lead. The British, French and International standards avoid the use of red entirely! 4.4.1.9 Thermocouple mounting There are four common ways in which thermocouples are mounted with in a stainless steel or Inconel sheath and electrically insulated with mineral oxides. Each of the methods has its advantages and disadvantages. 50
  • 51. Oil and Gas Measuring Instruments Figure 4.11 Thermocouple Sheath Options  Sealed and Isolated from Sheath: Good relatively trouble-free arrangement. The principal reason for not using this arrangement for all applications is its sluggish response time - the typical time constant is 75 seconds  Sealed and Grounded to Sheath: Can cause ground loops and other noise injection, but provides a reasonable time constant (40 seconds) and a sealed enclosure.  Exposed Bead: Faster response time constant (typically 15 seconds), but lacks mechanical and chemical protection, and electrical isolation from material being measured. The porous insulating mineral oxides must be sealed  Exposed Fast Response: Fastest response time constant (typically 2 seconds), depending on the gauge of junction wire. In addition to problems of the exposed bead type, the protruding and light construction makes the thermocouple more prone to physical damage. 51
  • 52. Oil and Gas Measuring Instruments 4.4.1.10 Conversion Table ITS-90 Table for type J thermocouple Thermoelectric Voltage in mV °C 0 1 2 3 4 5 6 7 8 9 10 0 0.000 0.050 0.101 0.151 0.202 0.253 0.303 0.354 0.405 0.456 0.507 10 0.507 0.558 0.609 0.660 0.711 0.762 0.814 0.865 0.916 0.968 1.019 20 1.019 1.071 1.122 1.174 1.226 1.277 1.329 1.381 1.433 1.485 1.537 30 1.537 1.589 1.641 1.693 1.745 1.797 1.849 1.902 1.954 2.006 2.059 40 2.059 2.111 2.164 2.216 2.269 2.322 2.374 2.427 2.480 2.532 2.585 50 2.585 2.638 2.691 2.744 2.797 2.850 2.903 2.956 3.009 3.062 3.116 60 3.116 3.169 3.222 3.275 3.329 3.382 3.436 3.489 3.543 3.596 3.650 70 3.650 3.703 3.757 3.810 3.864 3.918 3.971 4.025 4.079 4.133 4.187 80 4.187 4.240 4.294 4.348 4.402 4.456 4.510 4.564 4.618 4.672 4.726 90 4.726 4.781 4.835 4.889 4.943 4.997 5.052 5.106 5.160 5.215 5.269 100 5.269 5.323 5.378 5.432 5.487 5.541 5.595 5.650 5.705 5.759 5.814 110 5.814 5.868 5.923 5.977 6.032 6.087 6.141 6.196 6.251 6.306 6.360 120 6.360 6.415 6.470 6.525 6.579 6.634 6.689 6.744 6.799 6.854 6.909 130 6.909 6.964 7.019 7.074 7.129 7.184 7.239 7.294 7.349 7.404 7.459 140 7.459 7.514 7.569 7.624 7.679 7.734 7.789 7.844 7.900 7.955 8.010 4.4.2 RTD Resistance Temperature Detectors (RTDs) rely on the predictable and repeatable phenomena of the electrical resistance of metals changing with temperature. The temperature coefficient for all pure metals is of the same order - 0.003 to 0.007 ohms/ohm/°C. The most common metals used for temperature sensing are platinum, nickel, copper and molybdenum. While the resistance - temperature characteristics of certain semiconductor and 52
  • 53. Oil and Gas Measuring Instruments ceramic materials are used for temperature sensing, such sensors are generally not classified as RTDs. 4.4.2.1 How are RTD constructed? RTDs are manufactured in two ways: using wire or film. Wire RTDs are a stretched coil of fine wire placed in a ceramic tube that supports and protects the wire. The wire may be bonded to the ceramic using a glaze. The wire types are generally the more accurate, due to the tighter control over metal purity and less strain related errors. They are also more expensive. Figure 4.12 RTD Film RTDs consist of a thin metal film that is silk-screened or vacuum spluttered onto a ceramic or glassy substrate. A laser trimmer then trims the RTD to its correct resistance value. Film sensors are less accurate than wire types, but they are relatively inexpensive, they are available in small sizes and they are more robust. Film RTDs can also function as a strain gauge - so dont strain them! The alumina element should be supported by grease or a light elastomer, but never embedded in epoxy or mechanically clamped between hard surfaces. 53
  • 54. Oil and Gas Measuring Instruments Figure 4.13 Typical Sheath Mounted RTD Probe RTDs cannot generally be used in their basic sensing element form, as they are too delicate. They are usually built into some type of assembly, which will enable them to withstand the various environmental conditions to which they will be exposed when used. Most commonly this is a stainless steel tube with a heat conducting grease (that also dampens vibration). Standard tube diameters include 3, 4.5, 6, 8, 10, 12 and 15 mm and standard tube lengths include 250, 300, 500, 750 and 1000 mm. 4.4.2.2 Characteristics of RTDs Metal RTDs have a response defined by a polynomial: R(t) = R0 ( 1 + a.t + b.t 2 + c.t 3 ) Where R0 is the resistance at 0°C, "t" in the temperature in Celsius, and "a", "b" and "c" are constants dependent on the characteristics of the metal. In practice this equation is a close but not perfect fit for most RTDs, so slight modifications are often be made. Commonly, the temperature characteristics of an RTD are specified as a single number (the "alpha"), representing the average temperature coefficient over the 0 to 100°C temperature range as calculated by: 54
  • 55. Oil and Gas Measuring Instruments alpha = ( R100 - R0 ) / 100 . R0 in ohms/ohm/°C Note: RTDs cover a sufficient temperature range that their response needs to be calibrated in terms of the latest temperature scale ITS90. It is also of interest to note that the temperature coefficient of an alloy is frequently very different from that of the constituent metals. Small traces of impurities can greatly change the temperature coefficients. Sometimes trace "impurities" are deliberately added so as to swamp the effects of undesired impurities which are uneconomic to remove. Other alloys can be tailored for particular temperature characteristics. For example, an alloy of 84% copper, 12% Manganese and 4% Nickel has the property of having an almost zero response to temperature. The alloy is used for the manufacture of precision resistors. 4.4.2.3 Types RTDs While almost any metal may be used for RTD manufacture, in practice the number used is limited. Temperature Metal Alpha Comments Range Copper Pt -200°C to 260°C 0.00427 Low cost 0.00300 Lower cost alternative to platinum in the Molybdenum Mo -200°C to 200°C 0.00385 lower temperature ranges Nickel Ni -80°C to 260°C 0.00672 Low cost, limited temperature range Ni- Nickel - Iron -200°C to 200°C 0.00518 Low cost Fe 0.00385 Platinum Pt -240°C to 660°C Good precision 0.00392 55
  • 56. Oil and Gas Measuring Instruments 4.4.2.4 Platinum RTDs Platinum is by far the most common RTD material, primarily because of its long-term stability in air. There are two standard Platinum sensor types, each with a different doping level of impurities. To a large extent there has been a convergence in platinum RTD standards, with most national standards bodies adopting the international IEC751-1983, with amendment 1 in 1986 and amendment 2 in 1995. The USA continues to maintain its own standard. All the platinum standards use a modified polynomial known as the Callendar - Van Dusen equation: R(t) = R0 ( 1 + a.t + b.t2 + c.(t - 100).t3 ) Platinum RTDs are available with two temperature coefficients or alphas - the choice is largely based on the national preference in you country, as indicated in the following table: Alpha R0 Standard Polynomial Coefficients ohms/ohm/°C ohms 200°C < t < 0°C a = 3.90830x10-3 b = -5.77500x10-7 IEC751 0.00385055 100 c = -4.18301x10-12 (Pt100) 0°C < t < 850°C a & b as above, but c = 0.0 a = 3.97869x10-3 SAMA 0.0039200 98.129 b = -5.86863x10-7 RC-4 c = -4.16696x10-12 The international IEC 751 standard specifies tolerance classes as indicated in the following table. While only Classes A and B are defined in IEC 751, it has become common practice to extended the Classes to C 56
  • 57. Oil and Gas Measuring Instruments and D, which roughly double the previous error tolerance. The tolerance classes are often applied to other RTD types. Tolerance Class Tolerance Equation (°C) Class A ± ( 0.15 + 0.002.| t | ) Class B ± ( 0.30 + 0.005. | t | ) Class C ± ( 0.40 + 0.009. | t | ) Class D ± ( 0.60 + 0.0018. | t | ) Where | t | indicated the magnitude of the temperature in Celsius (that is sign is dropped). Some manufacturers further subdivide their RTD Tolerance Classes into Tolerance Bands for greater choice in price performance ratios. 4.4.2.6 Characteristics of Platinum RTDs The IEC751 specifies a number of other characteristics - insulation resistance, environmental protection, maximum thermoelectric effect, vibration tolerance, lead marking and sensor marking. Some of these are discussed below: Thermoelectric Effect: Platinum RTD generally employs two metals - the platinum sensing element and copper lead wires, making it a good candidate for a thermocouple. If a temperature gradient is allows to develop along the sensing element, a thermoelectric voltage with a magnitude of about 7 µV /°C will be generated. This is only likely to be a problem with very high-precision measurements operating at low excitation currents. Wiring Configurations and Lead Marking: There are three wiring configurations that can be used for measuring resistance - 2, 3 and 4 wire connections. 57
  • 58. Oil and Gas Measuring Instruments Figure 4.14 Wiring configurations IEC751 requires that wires connected to the same end of the resistor be the same colour - either red or white, and that the wires at each end be different. 4.4.3 Thermistor Thermistor temperature sensors are constructed from sintered metal oxide in a ceramic matrix that changes electrical resistance with temperature. They are sensitive but highly non-linear. Their sensitivity, reliability, ruggedness and ease of use, has made them popular in research application, but they are less commonly applied to industrial applications, probably due to a lack on interchangeability between manufactures. Thermistors are available in large range of sizes and base resistance values (resistance at 25°C). Interchangeability is possible to ±0.05°C although ±1°C is more common. 4.4.3.1 Thermistor construction The most common form of the thermistor is a bead with two wires attached. The bead diameter can range from about 0.5mm (0.02") to 5mm (0.2). Figure 4.15Themistor 58
  • 59. Oil and Gas Measuring Instruments Mechanically the thermistor is simple and strong, providing the basis for a high reliability sensor. The most likely failure mode is for the lead to separate from the body of the thermistor - an unlikely event if the sensor is mounted securely and with regard to likely vibration. The sintered metal oxide material is prone to damage by moisture, so is passivated by glass or epoxy encapsulation. If the encapsulation is compromised and moisture penetrates, silver migration under the dc bias can eventually cause shorting between the electrodes. Like other temperature sensors, thermistors are often mounted in stainless steel tubes, to protect them from the environment in which they are to operate. Grease is typically used to improve the thermal contact between the sensor and the tube. 4.4.3.2 Thermistor characteristics The following are typical characteristic for the popular 44004 thermistor from YSI: Parameter Specification Resistance at 25°C 2252 ohms (100 to 1M available) Measurement range -80 to +120°C typical (250°C max.) Interchangeability (tolerance) ±0.1 or ±0.2°C Stability over 12 months < 0.02°C at 25°C, < 0.25°C at 100°C Time constant < 1.0 seconds in oil, < 60 seconds in still air self-heating 0.13 °C/mW in oil, 1.0 °C/mW in air Coefficients a = 1.4733 x 10-3, b = 2.372 x 10-3, c = 1.074 x 10-7 (see Linearization below) Dimensions ellipsoid bead 2.5mm x 4mm 59
  • 60. Oil and Gas Measuring Instruments 4.4.4 Semiconductor The semiconductor (or IC for integrated circuit) temperature sensor is an electronic device fabricated in a similar way to other modern electronic semiconductor components such as microprocessors. Typically hundreds or thousands of devices are formed on thin silicon wafers. Before the wafer is scribed and cut into individual chips, they are usually laser trimmed. Semiconductor temperature sensors are available from a number of manufacturers. There are no generic types as with thermocouple and RTDs, although a number of devices are made by more than one manufacturer. The AD590 and the LM35 have traditionally been the most popular devices, but over the last few years better alternatives have become available. These sensors share a number of characteristics - linear outputs, relatively small size, limited temperature range (-40 to +120°C typical), low cost, good accuracy if calibrated but also poor interchangeability. Often the semiconductor temperature sensors are not well designed thermally, with the semiconductor chip not always in good thermal contact with an outside surface. Some devices are inclined to oscillate unless precautions are taken. Provided the limitations of the semiconductor temperature sensors are understood, they can be used effectively in many applications. The most popular semiconductor temperature sensors are based on the fundamental temperature and current characteristics of the transistor. If two identical transistors are operated at different but constant collector current densities, then the difference in their base-emitter voltages is proportional to the absolute temperature of the transistors. This voltage difference is then converted to a single ended voltage or a current. An offset may be applied to convert the signal from absolute temperature to Celsius or Fahrenheit. 60
  • 61. Oil and Gas Measuring Instruments In general, the semiconductor temperature sensor is best suited for embedded applications - that is, for use within equipment. This is because they tend to be electrically and mechanically more delicate than most other temperature sensor types. However they do have legitimate application in many areas, hence their inclusion. 4.5 Level Sensing Elements 4.5.1 Radar Tank Gauging Figure 4.16 RTG FMCW radar principle and FFT signal analysis, (FMCW = frequency-modulated continuous wave). A radar signal is emitted from an antenna, reflected from the target (in this case, the product surface) and received back after a delay interval t. The distance of the reflecting product surface is measured by way of the transit time t of the microwave signal: for every meter from a target the waves travel a distance of 2 m, 61
  • 62. Oil and Gas Measuring Instruments for which they require a time of approx. 6.7 ns. In general, the measured distance is a = c x t / 2; where c = the speed of light. The FMCW radar system uses a linear frequency-modulated high- frequency signal; transmission frequency increases linearly within a time interval (frequency sweep). Since the transmission frequency changes due to the time delay during signal propagation, a low-frequency signal (typically, up to a few kHz), the frequency f of which is proportional to the reflector distance a, is obtained from the difference between the current transmission frequency and the received frequency. The product level is then computed from the difference between tank height and distance. Figure 4.17 RTG Signalling 62
  • 63. Oil and Gas Measuring Instruments 4.5.2 Vibrating Fork A piezoelectric crystal operated Vibrating Fork type level switch for detection of level of powders / granules / solids in the hoppers, bins and silos, etc. Figure 4.18 Vibrating fork 4.5.3 LVDT The letters LVDT are an acronym for Linear Variable Differential Transformer, a common type of electromechanical transducer that can convert the rectilinear motion of an object to which it is coupled mechanically into a corresponding electrical signal. LVDT linear position sensors are readily available that can measure movements as small as a few millionths of an inch up to several inches, but are also capable of measuring positions up to ±20 inches (±0.5 m). Figure 4.19 LVDT Core 63
  • 64. Oil and Gas Measuring Instruments The figure (4.19) shows the components of a typical LVDT. The transformers internal structure consists of a primary winding centered between a pair of identically wound secondary windings, symmetrically spaced about the primary. The coils are wound on a one-piece hollow form of thermally stable glass reinforced polymer, encapsulated against moisture, wrapped in a high permeability magnetic shield, and then secured in cylindrical stainless steel housing. This coil assembly is usually the stationary element of the position sensor. The moving element of an LVDT is a separate tubular armature of magnetically permeable material called the core, which is free to move axially within the coils hollow bore, and mechanically coupled to the object whose position is being measured. This bore is typically large enough to provide substantial radial clearance between the core and bore, with no physical contact between it and the coil. In operation, the LVDTs primary winding is energized by alternating current of appropriate amplitude and frequency, known as the primary excitation. The LVDTs electrical output signal is the differential AC voltage between the two secondary windings, which varies with the axial position of the core within the LVDT coil. Usually this AC output voltage is converted by suitable electronic circuitry to high level DC voltage or current that is more convenient to use. 4.5.3.1 Advantages LVDTs have certain significant features and benefits, most of which derive from its fundamental physical principles of operation or from the materials and techniques used in its construction.  Friction-Free Operation 64
  • 65. Oil and Gas Measuring Instruments One of the most important features of an LVDT is its friction-free operation. In normal use, there is no mechanical contact between the LVDTs core and coil assembly, so there is no rubbing, dragging or other source of friction. This feature is particularly useful in materials testing, vibration displacement measurements, and high resolution dimensional gauging systems.  Infinite Resolution Since an LVDT operates on electromagnetic coupling principles in a friction-free structure, it can measure infinitesimally small changes in core position. This infinite resolution capability is limited only by the noise in an LVDT signal conditioner and the output displays resolution. These same factors also give an LVDT its outstanding repeatability.  Unlimited Mechanical Life Because there is normally no contact between the LVDTs core and coil structure, no parts can rub together or wear out. This means that an LVDT features unlimited mechanical life. This factor is especially important in high reliability applications such as aircraft, satellites and space vehicles, and nuclear installations. It is also highly desirable in many industrial process control and factory automation systems.  Over travel Damage Resistant The internal bore of most LVDTs is open at both ends. In the event of unanticipated over travel, the core is able to pass completely through the sensor coil assembly without causing damage. This invulnerability to position input overload makes an LVDT the ideal sensor for applications like extensometers that are attached to tensile test samples in destructive materials testing apparatus.  Single Axis Sensitivity An LVDT responds to motion of the core along the coils axis, but is generally insensitive to cross-axis motion of the core or to its radial 65
  • 66. Oil and Gas Measuring Instruments position. Thus, an LVDT can usually function without adverse effect in applications involving misaligned or floating moving members, and in cases where the core doesnt travel in a precisely straight line.  Separable Coil And Core Because the only interaction between an LVDTs core and coil is magnetic coupling, the coil assembly can be isolated from the core by inserting a non-magnetic tube between the core and the bore. By doing so, a pressurized fluid can be contained within the tube, in which the core is free to move, while the coil assembly is depressurized. This feature is often utilized in LVDTs used for spool position feedback in hydraulic proportional and/or servo valves.  Environmentally Robust The materials and construction techniques used in assembling an LVDT result in a rugged, durable sensor that is robust to a variety of environmental conditions. Bonding of the windings is followed by epoxy encapsulation into the case, resulting in superior moisture and humidity resistance, as well as the capability to take substantial shock loads and high vibration levels in all axes. And the internal high-permeability magnetic shield minimizes the effects of external AC fields. Both the case and core are made of corrosion resistant metals, with the case also acting as a supplemental magnetic shield. And for those applications where the sensor must withstand exposure to flammable or corrosive vapors and liquids, or operate in pressurized fluid, the case and coil assembly can be hermetically sealed using a variety of welding processes. Ordinary LVDTs can operate over a very wide temperature range, but, if required, they can be produced to operate down to cryogenic temperatures, or, using special materials, operate at the elevated temperatures and radiation levels found in many nuclear reactors. 66
  • 67. Oil and Gas Measuring Instruments  Null Point Repeatability The location of an LVDTs intrinsic null point is extremely stable and repeatable, even over its very wide operating temperature range. This makes an LVDT perform well as a null position sensor in closed-loop control systems and high-performance servo balance instruments.  Fast Dynamic Response The absence of friction during ordinary operation permits an LVDT to respond very fast to changes in core position. The dynamic response of an LVDT sensor itself is limited only by the inertial effects of the cores slight mass. More often, the response of an LVDT sensing system is determined by characteristics of the signal conditioner.  Absolute Output An LVDT is an absolute output device, as opposed to an incremental output device. This means that in the event of loss of power, the position data being sent from the LVDT will not be lost. When the measuring system is restarted, the LVDTs output value will be the same as it was before the power failure occurred. 4.5.3.2 Theory of Operation This figure illustrates what happens when the LVDTs core is in different axial positions. The LVDTs primary winding, P, is energized by a constant amplitude AC source. The magnetic flux thus developed is coupled by the core to the adjacent secondary windings, S1 and S2 . If the core is located midway between S1 and S2 , equal flux is coupled to each secondary so the voltages, E1 and E2 , induced in windings S1 and S2 respectively, are equal. At this reference midway core position, known as the null point, the differential voltage output, (E1 - E2), is essentially zero. 67
  • 68. Oil and Gas Measuring Instruments Figure 4.20 LVDT Signalling If the core is moved closer to S1 than to S2 , more flux is coupled to S1 and less to S2 , so the induced voltage E1 is increased while E2 is decreased, resulting in the differential voltage (E1 - E2). Conversely, if the core is moved closer to S2 , more flux is coupled to S2 and less to S1 , so E2 is increased as E1 is decreased, resulting in the differential voltage (E2 - E1 ). The top graph shows how the magnitude of the differential output voltage, EOUT, varies with core position. The value of EOUT at maximum core displacement from null depends upon the amplitude of the primary excitation voltage and the sensitivity factor of the particular LVDT, but is typically several volts RMS. The phase angle of this AC output voltage, EOUT, referenced to the primary excitation voltage, stays constant until the center of the core passes the null point, where the phase angle changes abruptly by 180 degrees, as shown in the middle graph. This 180 degree phase shift can be used to determine the direction of the core from the null point by means of appropriate circuitry. This is shown in the bottom graph, where the polarity of the output signal represents the cores positional relationship to the null point. The figure shows also that 68
  • 69. Oil and Gas Measuring Instruments the output of an LVDT is very linear over its specified range of core motion, but that the sensor can be used over an extended range with some reduction in output linearity. The output characteristics of an LVDT vary with different positions of the core. Full range output is a large signal, typically a volt or more, and often requires no amplification. Note that an LVDT continues to operate beyond 100% of full range, but with degraded linearity. 4.5.4 Servo Motor A micro-controller based multi-function instrument for precision level measurement of liquids stored in Cone Roof, Floating Roof tanks, pressurized Spheres, Mounded Vessels, Bullets and Cryogenic storage tanks. Figure 4.21 Servo-motor Type 4.5.5 Pressure Sensing Type In this type of level gauging, the pressure or differential pressure is measured converted to level by the following equation. 69
  • 70. Oil and Gas Measuring Instruments P  g (h2  h1 ) If the tank is open to atmosphere the pressure at the bottom is indication of level. In closed tanks, differential pressure is the measurand that indicates the level. The linkage may be direct, liquid filled or sealed liquid filled. Figure 4.22 Pressure sensing Type 4.6 Vibration Sensing 4.6.1 Inductive Sensor (Eddy Current) Inductive sensors use currents induced by magnetic fields to detect nearby metal objects. The inductive sensor uses a coil (an inductor) to generate a high frequency magnetic field as shown in Figure 4.23. If there is a metal object near the changing magnetic field, current will flow in the object. This resulting current flow sets up a new magnetic field that opposes the original magnetic field. The net effect is that it changes the 70
  • 71. Oil and Gas Measuring Instruments inductance of the coil in the inductive sensor. By measuring the inductance the sensor can determine when a metal have been brought nearby. These sensors will detect any metals, when detecting multiple types of metal multiple sensors are often used. Figure 4.23 Inductive Sensor The sensors can detect objects a few centimeters away from the end. But, the direction to the object can be arbitrary as shown in Figure 4.24. The magnetic field of the unshielded sensor covers a larger volume around the head of the coil. By adding a shield (a metal jacket around the sides of the coil) the magnetic field becomes smaller, but also more directed. Shields will often be available for inductive sensors to improve their directionality and accuracy. Figure 4.24 Shielded and Unshielded 71
  • 72. Oil and Gas Measuring Instruments 4.7 Role Play Each Trainee should speak thoroughly about one of the electrical transducers for  Pressure.  Temperature.  Level Gauging and Vibration Sensing. 72
  • 73. Oil and Gas Measuring Instruments Chapter 5 Flow Measurement 5.1 Learning Objectives 1. Review basic properties of fluid flow. 2. To understand the theory of operation of different flow meters. 3. Select the optimum meter according to the application. 4. To avoid pitfalls in flow metering. 5.2 Basic Principles of Fluid Flow and Measurement 5.2.1 Density and Specific Volume The density of a fluid is the ratio of its mass to its volume. Its specific volume is the reciprocal of its density. The density of water is roughly 1000 times that of air at atmospheric pressure. M  V 5.2.2 Thermal Expansion Coefficient The thermal expansion coefficient, , is the fractional increase in specific volume, Vs, caused by a temperature increase of 1 degree. 1 dVs  Vs dT 73
  • 74. Oil and Gas Measuring Instruments 5.2.3 Compressibility The compressibility of a fluid, , is the fractional decrease in specific volume caused by unit increase of pressure. 1 dVs   Vs dP 5.2.4 Viscosity The viscosity, , of a fluid is a measure of its resistance to shearing at a constant rate.    where  is the shear stress and  is the rate of shear strain. The SI unit of viscosity is Pascal second, but it is usual to express it in centipoises, cP, where one cP being 0.001 Pa s. Viscosity is referred to as absolute or dynamic viscosity to distinguish it from kinematics viscosity, , which is the ratio of viscosity to density. The Si unit of which is m 2 s-1 and commonly known by centistokes, cSt, where one cSt being 10 -6 m2 s-1. 5.2.5 Air Solubility of Liquids Air is soluble in liquids, and its solubility is directly proportional to the absolute pressure. The solubility decreases markedly as the temperature of the water increases. It is very much soluble in hydrocarbons where the solubility is not decreased much with increasing temperature, until quite high temperatures are reached. 74
  • 75. Oil and Gas Measuring Instruments 5.2.6 Humidity in gases Gases may be either dry or humid. This is because a gas at a given temperature is capable of holding a certain maximum amount of water vapor; this value increases with temperature increase. The relative humidity is defined as the ratio of the actual partial pressure of the water vapor to the value of partial pressure that would exist under saturated conditions at the same temperature. Sudden changes in humidity may cause errors in gas flow measurement. In particular, errors easily occur if unsaturated gas is passed through a wet gas meter, or if a sudden expansion cools a gas sufficiently to cause precipitation of some of its water vapor. 5.2.7 Reynolds Number The behavior of fluids flowing through pipes is governed by a quantity known as Reynolds number which is defined by vD Re D   where v is the mean velocity and D is the pipe diameter. The numerator is a measure of the flowing fluids ability to generate a dynamic forces, while the denominator is a measure of its ability to generate viscous forces. This means that Reynolds number indicates which kind of forces predominate the flowing fluid. 5.2.8 Laminar and Turbulent Flow Laminar flow occurs at Reynolds numbers below about 2000. This can be likened to the flow of traffic on a busy motorway, with the traffic 75
  • 76. Oil and Gas Measuring Instruments in the various lanes traveling on parallel paths at different speeds. Turbulent flow occurs at Reynolds number above about 2000. 5.2.9 Rotation and Swirl Bends, flowmeters, valves, etc., produce what is known as rotation in the flow. The fluid on the outside of the bend has to travel farther than the fluid in the inside and this distorts the pattern of the flow in highly complex fashion. On consequence of this is the rotary motion. The flow returns to steady flow after some distance. For two adjacent bends in different planes the flow rotates in three dimensions, i.e. swirls. It takes longer distance for swirl to come back to steady flow. Figure 5.1 Rotational Flow 5.2.10 Continuity and Bernoullis Equation In simple, what goes at one end of the pipe comes out at the other. This simple fact is the basis of continuity, which holds that the mass flow rate is the same at all cross-sections of one continuous pipe having no branches. If the fluid is incompressible, the volumetric flow rate remains constant also. The energy possessed by a flowing fluid is the same at every cross- section along the pipe. Bernoullis equation expresses this fact in mathematical terms. P  1 2 v 2  constant at all sections. 76
  • 77. Oil and Gas Measuring Instruments 5.2.11 Velocity Head The expression v2=2g provides a convenient way of indicating the amount of kinetic energy possessed by the fluid flowing in the pipe. It has the dimensions of length and is equal to the head to which the fluid would rise if it were projected vertically upwards. An important use of this concept is to express the tendency of pipe fittings to dissipate energy in terms of velocity heads. 5.2.12 Cavitation It follows from Bernoulli that when the mean velocity increases the pressure will decrease. In water, volatile hydrocarbons and liquefied gases cavitation generally occurs only when the pressure at some point reaches the vapor pressure of the liquid causing bubbles and vapor pockets to appear. In viscous oil and non-volatile liquid fuels cavitation generally takes a different form. It begins at pressures somewhat below atmospheric, but well above the vapor pressure. 5.2.13 Double Block and Bleed Valve Flowmeters are frequently installed in complex network of piping containing a number of shut off valves. To eliminate the bypassed flow a system of double block and bleed valves are installed to confirm the operator that the valves are sealing perfectly. Figure 5.2 Double block and bleed valve. 77
  • 78. Oil and Gas Measuring Instruments 5.2.14 Definitions  The mean pipe velocity is related to volumetric flowrate, Q V, and pipe cross-sectional area, A. QV  vA  Volumetric flowrate, QV, is defined as the rate of change of volume. dV QV  dt  Mass flowrate, QM, is the rate of change of mass with time.  The results of calibration may be plotted as a graph of flowmeter readout against flowrate. The graphs may be linear or non-linear.  A more detailed graph is the performance index, which displays any small deviations from ideal behavior by the flowmeter. 5.2.15 Factors  Coefficient of discharge, C, is defined by QT C QI where QT denotes true flowrate and QI denotes the flow indicated by meter. Figure 5.3 Coefficient of discharge 78
  • 79. Oil and Gas Measuring Instruments  Meter correction factor is defined by VT  VI  VI  Meter factor, F, is used in connection with meters for total volume and is given by VT F VI  K-Factor is a term used to describe the performance of meters whose output is in the form of a series of electrical pulses, and where total pulse count, n, is nominally proportional to the volume passed, and the pulse frequency, dn/dt, is nominally proportional to the flowrate. n K VT Figure 5.4 K-factor 5.3 Differential Pressure Meters 5.3.1 Principle of Operation The meter depends on the fact that when a fluid flows through a contraction it must accelerate; this causes its kinetic energy to increase, and consequently its pressure must fall by a corresponding amount. The volumetric flowrate is given by 79
  • 80. Oil and Gas Measuring Instruments 1  2P  CA2 2 QV      2 2    1 1 m  1  where  is an empirical coefficient, the expansibility factor. This depends upon the physical properties of the gas being metered, as well as the geometry of the flowmeter. Figure 5.5 Differential Pressure measurement 5.3.2 Advantages  Simplicity of construction.  Versatility: used with almost any fluid.  Economy.  Experience. 5.3.3 Disadvantages  Accuracy is not quite enough.  The output signal is not linear to flowrate 5.3.4 Selecting the Meter It is usually not difficult to decide which type is better for a particular job. The lengthy expensive venturi meter has a low head loss 80
  • 81. Oil and Gas Measuring Instruments and its high initial cost is justified in situations where large quantities of liquids are being pumped, i.e. in main water supply pipelines. Gas plants where head loss is not important the orifice plates are the decision. A compromise for intermediate cost and size is the nozzle. 5.3.4.1 Venturi Tubes The venturi tube is the original form of differential pressure meter. A typical design is shown in figure (5.6). Because energy losses are low and flow conditions are not far removed from the ideal, the discharge coefficient of venturi meters is very near unity. Figure 5.6 Venturi Tube 5.3.4.2 Orifice Plates An orifice plate is simply a plate with a hole in it, forming a partial obstruction to the flow. The flowing fluid follows the same kind of path as it does in venturi tube. However, the narrowest part of the flow stream is not in the orifice itself, but some distance downstream; this narrowest section is known as vena contracta. Between the vena contracta and the pipe wall, numerous eddies form, which dissipate great deal of kinetic energy that is responsible for the high head loss. 81
  • 82. Oil and Gas Measuring Instruments Figure 5.7 Orifice Plate Concentric orifice plates are made with a circular orifice concentric with the pipe. In figure 5.7, the tapings are in the adjacent pipes at distances shown. Another common arrangement is to put the tapings in the pipe flanges adjacent to the orifice plate. The position of the tapping affects the discharge coefficient. The orifice plate in figure (5.8) is described as square-edged because that is the shape of the upstream although the downstream edge is chamfered. This is used in clean gases and clean liquids with low viscosity. With viscous liquids it is necessary to make the edges raduissed or chamfered upstream and square downstream and they are called quarter-circle or conical-entry. Concentric orifice plates cannot be used with dirty fluids because dirt gradually builds up behind the plate until its performance is impaired. Instead eccentric or chord orifice plates are commonly used but they are less accurate. Figure 5.8 Orifice Plate Types 82
  • 83. Oil and Gas Measuring Instruments 5.3.4.3 Nozzles Nozzles are more costly than orifice plates but they have three advantages over them: they have a discharge coefficient very much closer to unity; they can be used to discharge directly into the atmosphere; and they have no sharp edge to blunted, i.e. they can be used with dirty and abrasive fluids. Figure 5.9 Nozzles 5.3.5 Points to watch when Using  Install orifice plates correctly watching the edges back and front.  Installing differential pressure meters, take care the pressure tapings in acceptable position. These must never be at the bottom so that would not clog with dirt. With liquids the tapings must not be positioned at the top so they would fill with bubbles. The best place is at the side of the pipe.  Stay within the recommended range of flowrates.  Cavitation must not be allowed to occur. 83
  • 84. Oil and Gas Measuring Instruments  Make periodic inspections for meter and pipe work to trace any film of dirt, corrosion or organic growth.  Inspect sharp edges in the orifice if worn or not.  When used with wet gases, plates are often provided with drain hole. 5.3.6 Drag Plate The principle of the drag plate meter is illustrated in figure (5.10) A circular plate is supported centrally in the pipe by means of hinged arm. The flowing fluid produces a positive pressure on the upstream side of the plate and suction on the downstream. This pressure difference produces forces which tend to move the plate in the direction of flow, but this force is resisted by a null-balance supporting element at the end of the support arm. The signal from the null-balance device is proportional to the force on the plate which is proportional to the square of the flowrate. Figure 5.10 Drag plate 5.3.6.1 Advantages  Dirt cannot be built up.  There are no pressure tapings to be blocked. 84
  • 85. Oil and Gas Measuring Instruments  The flowrate range can be adjusted by a simple range switch. 5.3.6.2 Disadvantages  Square root characteristics  For good accuracy, large diameters are used and hence high head loss.  The force on large drag plate would be too great to be supported effectively by null-balance system. 5.3.6.3 When to Use The drag plate is suitable for liquids containing suspended solids. 5.3.7 Rotameters In the simplest type of rotameter the body is a tapered transparent tube of glass or plastic with a scale engraved on it. Inside the tube is a small solid body with a circular cross-section, the float, when there is no flow the float rests at the bottom. Flow causes it ot be lift off. Its very low price is its advantage. The high head loss is its disadvantage. Figure 5.11 Rotameters 85
  • 86. Oil and Gas Measuring Instruments 5.3.8 Spring Loaded Variable Aperture Flowmeters In the differential pressure flowmeter, the area of constriction is kept constant and the pressure difference is varying. In variable aperture flowmeters the reverse effect occurs. In this type two degrees of freedom are possessed which can be used for meter readout. One degree is for the pressure difference and the other is for the displacement of the member controlling the aperture. Figure 5.12 Spring Loaded Variable Aperture 5.3.8.1 Advantages  Wide range of operation with tolerable accuracy.  Linear output.  Less sensitive for viscosity changes.  Can be installed horizontal, vertical or inclined. 86
  • 87. Oil and Gas Measuring Instruments 5.3.8.2 Disadvantages  Larger in diameter than the pipes.  Expensive.  High head loss. 5.3.9 Laminar Flowmeters In turbulent flow, pressure drop is proportional to the square of the velocity. In laminar flow it is linear. The simplest laminar flowmeter consists of fine capillary tube with highly sensitive differential pressure micro manometer connected across it. Figure 5.13 Laminar Flowmeters 5.3.9.1 Advantages  Approximately linear output.  Wide rangeability.  No moving parts.  Used for extremely low flow rates. 5.3.9.2 Disadvantages  Bulky and expensive.  Calibration is upset by dust particles.  Sensitive to changes in viscosity. 87
  • 88. Oil and Gas Measuring Instruments 5.4 Rotating Mechanical Meters 5.4.1 Positive Displacement Meters In principle, liquids are measured using containers. This technique is accomplished in continuous process for positive displacement meters. In gases the mechanism must have very low frictional resistance. Figure 5.14 Postive displacement meters 5.4.1.1 Advantages  High accuracy.  They are not affected by upstream flow disturbances so they can be used very close to bends. 5.4.1.2 Disadvantages  Large sizes.  High head loss.  Can be damaged by dirt particles.  If they clutch they will block flow. 5.4.1.3 Points to Watch  One direction flow only. So installation should be supervised.  When used with water check internals for non-corrosive materials. 88
  • 89. Oil and Gas Measuring Instruments 5.4.2 Turbine Meters It consists of a short length of pipe in the centre of which there are two bearings supported by spiders. A propeller is mounted so that it can spin freely on these central bearings. The propeller materials should be either magnetic or small magnet is inserted in the tip of each blade and a pick up is installed on the pipe. Meter readout is pulses. Figure 5.15 Tyrbine Meters 5.4.2.1 Advantages  They are very accurate.  The output is digital.  Moderate head loss.  Compact in size.  If they clutch the flow does not block. 5.4.2.2 Disadvantages  Expensive.  Need periodic calibration to compensate for wear up.  Sensitive to viscosity changes.  Sensitive to flow disturbance and especially swirl. 89
  • 90. Oil and Gas Measuring Instruments 5.4.2.3 Points to Watch  Does the application justify cost?  Examine calibration curves for suitable accuracy.  Is it applicable for use with the fluid, temperature and pressure?  Never blow out the line with compressed air or steam because over speed would damage it.  For dirty liquids use coarse filters.  Any nearby electrical signal might introduce errors in pick ups.  Avoid cavitation. 5.4.3 Bypass Meters The flowrate in the bypass is approximately a constant fraction of the flow in the main pipe. The interesting result is that the relationship between flowrate and pressure drop in the bypass follows square law and thus it cancels out the square root effect of the orifice plate itself. The advantage is economical and the disadvantage is that accuracy and linearity are inferior to those more expensive meters. Figure 5.16 Bypass meters 5.4.4 Metering Pumps A metering pump may be regarded as a combination of pump, flowmeter and flow regulator. It consists of a piston pump with a variable stroke, a device counting the number of strokes delivered and a pre- settable mechanism that will stop the pump when the required number of strokes has been delivered. 90
  • 91. Oil and Gas Measuring Instruments 5.5 Other Volumetric Flowmeters 5.5.1 Electromagnetic Flowmeters It utilizes the same basic principle of electrical generator: when a conductor moves across a magnetic field a voltage is induced in the conductor, and the magnitude of the voltage is directly proportional to the speed of the moving conductor. If the conductor is a section of a conductive liquid flowing in a non-conductive pipe through a magnetic field, electrodes are mounted in the pipe wall at the positions shown in figure (5.17). The voltage induced across the electrodes is proportional to the flowrate. Figure 5.17 Electromagnetic Flowmeter 5.5.1.1 Advantages  There is no obstruction whatever to the flow, suitable for measuring flow rates of heavy suspensions like mud, sewage and wood pulp.  Zero head loss.  Wide range of meter sizes. 91
  • 92. Oil and Gas Measuring Instruments  Not affected with upstream flow.  Not affected by density or viscosity variation.  Linear output.  Bi-directional. 5.5.1.2 Disadvantages  Fluid must be electrical conductive.  Not very accurate.  Not cost effective for small pipe sizes. 5.5.1.3 Things to Watch  Make sure of whole range of duty.  Is a built in electrode cleaning device needed?  How the meter is calibrated?  If installed below ground level make sure it withstands drowning.  Never to alter meter duty.  Never install meter with electrodes in vertical diameter because they would be affected with air bubbles.  Check zero reading periodically.  If the pipe system is electro galvanic corrosion prevention system, then bonding straps are used to bypass the currents around the meter. 5.5.2 Ultrasonic Flowmeters Ultrasonic flowmeters use sound waves to determine the flowrate. Pulses from a transducer travel through a moving fluid at the speed of sound and provides an indication of fluid velocity. 92
  • 93. Oil and Gas Measuring Instruments The first method uses a transit-time method, in which two opposing transducers are mounted so that sound waves traveling between them are at 45 degree angle to the direction of the flow. The speed of sound from the upstream transducer to the downstream transducer represents the inherent speed of sound plus a contribution due to fluid velocity. The opposite direction transducer is used to extract the fluid velocity from speed of sound. It is essential that the fluid is free of entrained gas or solids to prevent scattering of sound waves. Figure 5.18 Ultrasonic meters The second method uses the Doppler Effect. This type uses two transducer elements mounted in the same side of the pipe. An ultrasonic sound wave of constant frequency is transmitted into the fluid by one of the elements. Solids or bubbles within the fluid reflect the sound back to the receiver element. The Doppler principle states that there will be a shift in apparent frequency when there is a relative motion between the transmitter and receiver. Doppler ultrasonic meters require entrained gases and suspended solids within the flow. Ultrasonic meters advantages are freedom of obstruction in the pipe and negligible cost-sensitivity with respect to pipe diameter. The disadvantages are that performance is very dependent on flow conditions and that fair accuracy is attainable when properly applied to appropriate fluids. 93
  • 94. Oil and Gas Measuring Instruments 5.5.3 Vortex Shedding Meters The operating principle is based on the phenomenon of vortex shedding known as the von Karman effect. As a fluid passes a bluff body, it separates and generates vortices that are shed alternately along and behind each side of the bluff body. These vortices cause areas of fluctuating pressure that are detected by a sensor. The frequency of vortex generation is directly proportional to fluid velocity. Vortex shedding meters are aimed the section of market as orifice plates. They have the same moderate accuracy as orifice plates, similar head and the same sensitivity to upstream flow disturbances. There is no rotating mechanism so there is no wear. It scores over orifice plates by having linear output. Figure 5.19 Vortex shedding meters 5.5.4 Thermal Flowmeters This type of flowmeters is for mass flowrates. The mass flow rate is given by H QM  c p T2  T1  where H is the power supplied in the form of heat and c p is the specific heat capacity at constant pressure. The main use for this type is with gases at relatively low pressure and flowrates. 94
  • 95. Oil and Gas Measuring Instruments Figure 5.20 Thermal Flowmeter 5.5.5 Coriolis Meters The Coriolis meter uses an obstruction less U-shaped tube as a sensor and applies Newtons second law of motion to determine flow rate. Inside the sensor housing, the sensor tube vibrates at its natural frequency. The sensor tube is driven by an electromagnetic drive coil located at the center of the bend in the tube and vibrates similar to that of a tuning fork. Figure 5.21 Sensor vibration The fluid flows into the sensor tube and is forced to take on the vertical momentum of the vibrating tube. When the tube is moving upward during half of its vibration cycle, the flowing into the sensor resists being forced upward pushing down on the tube. The fluid flowing out of the sensor has an upward momentum from the motion of the tube. As it travels around the tube bens, the fluid resists changes in its vertical 95
  • 96. Oil and Gas Measuring Instruments motion by pushing up on the tube. The difference in forces causes the tubes to twist. When the tube is moving downward during the second half of its vibrating cycle, it twists in the opposite direction. This twisting characteristic is called Coriolis effect. Figure 5.22 Forces on sensor Due to Newtons second law of motion, the amount of sensor tube twist is directly proportional to the mass flowrate of the fluid flowing through the tube. Electromagnetic velocity detectors located on each side of the flow tube measure the velocity of the vibrating tube. Mass flow is determined by measuring the time difference exhibited by the velocity detector signals. During zero flow conditions, no tube twist occurs, resulting in no time difference between the two velocity signals. With flow, a twist occurs with a resulting time difference between the two velocity signals. This time difference is directly proportional to mass flow. Digure 5.23 Sensor Twisting 96
  • 97. Oil and Gas Measuring Instruments 5.6 Velocity Measuring 5.6.1 Pilot Tubes It is the oldest and simplest form of fluid meter. The fluid in the mouth of the tube has been brought to rest, and its kinetic energy has been converted to pressure energy, which creates an enhanced pressure inside the pilot tube. P  1 2 v 2 Figure 5.24 Pilot Tubes 5.6.2 Hot Resistor Anemometers The basic principle is an electrically heated element is placed within the stream flow; the higher velocity the more it tends to cool the element; the change in temperature causes a change in resistance, which can be measured by some appropriate circuitry. 5.6.3 Laser Doppler Velocity Meters The schematic arrangement is shown in figure (25). The laser beam is first passed into a beam splitting prism, and then the two parallel 97
  • 98. Oil and Gas Measuring Instruments component beams are passed through a lens which makes them converge at a point where the flow velocity is to be measured. Whenever a dirt particle passes through the bright spot where the two beams intersect, it reflects light in all directions. This reflected light possesses a Doppler frequency shift. Some of it is picked up by a collecting lens and focused on a photo detector which reads out the velocity. Figure 5.25 Laser Doppler velocity meter 5.7 Two Phase Flow Wherever possible it is better to separate the gas and liquid phases and meter each one on its own. If it is not practical, there are some recognized techniques for measuring two phase flow. You will have to work very hard to obtain accuracy approaching 10%. Figure 5.26 Two Phase flow behavior 98
  • 99. Oil and Gas Measuring Instruments 5.8 Choosing the Right Flowmeter 99
  • 100. Oil and Gas Measuring Instruments 5.9 Calibrating Flowmeters Calibration of flowmeters can be done using any of the following techniques depending on how practical the technique is.  Volumetric Tank Figure 5.27 Volumetric calibration  Weighing Figure 5.28 Dynamic Weighing calibration  Master Meter Figure 5.29 Master meter calibration 5.10 Role Play Each Trainee should speak thoroughly about one of the learning objective elements. 100
  • 101. Oil and Gas Measuring Instruments 101
  • 102. Oil and Gas Measuring Instruments Chapter 6 Analyzers 6.1 Learning objectives 1. Understand the theory of operation of oxygen, moisture and gas chromatography analyzers. 6.2 Oxygen Analyzers The analyzer uses an electrochemical sensor technology to achieve the measurement of oxygen. See Figure (6.1). The sensor is a self contained disposable unit which requires no maintenance. The sensor utilizes the principle of electrochemical reaction to generate a signal proportional to the oxygen concentration in the sample. The sensor consists of a cathode and anode which are in contact via a suitable electrolyte. The sensor has a gas permeable membrane which covers the cathode allowing gas to pass into the sensor while preventing liquid electrolyte from leaking out. As the sample diffuses into the sensor, any oxygen present will dissolve in the electrolyte solution and migrate to the surface of the cathode. The oxygen is reduced at the cathode. Simultaneously, an oxidation reaction is occurring at the anode generating four electrons. These electrons flow to the cathode to reduce the oxygen. The representative half cell reactions are: Cathode: 4e- + 2H2O + O2 → 4OH- Anode: 4OH- + 2Pb → 2PbO + 2H2O + 4e- 102
  • 103. Oil and Gas Measuring Instruments The resultant overall cell reaction is: 2Pb + O2 → 2PbO This flow of electrons constitutes an electric current which is directly proportional to the concentration of oxygen present in the sample. In the absence of oxygen, no oxidation / reduction reaction occurs and therefore no current is generated. This allows the sensor to have an absolute zero. Figure 6.1 Oxygen analyzer sensing element 6.3 Gas Chromatography The word “Chromatography” is at present used as a collective term for a group of methods that at first sight appear somewhat diverse. These methods, however, have a number of common features. All chromatographic separations, for instance, involve the transport of a sample of a mixture through a column. The mixture may be a liquid or a vapor. The column contains a substance, the stationary phase, which may consist of a solid absorbing agent or of a liquid partitioning agent supported by a solid. The transport of the constituents of the sample through the column is affected either by a gas or a liquid, the moving phase. Owing to the 103
  • 104. Oil and Gas Measuring Instruments selective retention exerted by the stationary phase, the components of the mixture move through the column at different effective rates. They, thus tend to segregate into separate bands or zones. The column is designed to affect this separation at the exit of the column where the individual bands may be directed to a detector for determination. The separation obtained with this principle of operation is easily observed by using a piece of filter paper and putting a drop of oil in the center of the paper. With time, the light molecules of the oil will travel through the capillaries of the filter paper faster and farther than the heavy molecules. These light molecules are small in size and, generally, have fewer side branches or “arms and legs” to cause restriction to flow; and therefore, tend to move through the capillaries in an easier way than the larger molecules. It is easy to see the heavy, large, dark molecules of the oil restricted and retained near the center of the filter paper where the original drop was placed. Some oils will even show slight color bands as the separation of molecules occurs while traveling toward the edge of the filter paper. Figure 6.2 Filter Paper Similar separation takes place in a packed column, (stationary phase), where the sample molecules are injected at the head of the column and begin to move through the column under the motive forces of the carrier gas, (moving phase), where the light molecules travel through the column faster than the heavy ones. Therefore, the time that the light 104
  • 105. Oil and Gas Measuring Instruments molecules are in the column will be shorter than the time the heavy molecules stay in the column. It is this difference in column retention for different molecules that provides the separation. A detector is then employed to measure the relative concentration of each component while the elution time sequence can be employed to identify each component. Figure 6.3 Sample column 6.3.1 Thermal Conductivity Detector (TCD) The Thermal Conductivity Detector used in the GCX utilizes two filaments, one for sample gas and one for reference gas flow. The unbalancing of the bridge due to the dilution of the carrier gas by the sample, and hence the change in Thermal Conductivity offers excellent sensitivity for most applications. 6.3.2 Flame Ionization Detector (FID) When a hydrocarbon sample passes through a hydrogen flame, the molecular structure is altered so that the bond is broken and the carbon atom becomes a negatively charged and the hydrogen atoms become positively charged. When placed in an electric field, the ions may be collected. In the case of the GCX, a positive potential on the polarizing 105
  • 106. Oil and Gas Measuring Instruments plate causes all positive ions are collected on the measuring plate or collector and al negatively charged particles are collected on the polarization plate. This current may be converted to a voltage for further processing. The hydrogen/air mixture that supports the flame is converted to water and exits the burner through the vent. Most of the oxygen is consumed by the flame with only small amounts of excess hydrogen remaining. The excess hydrogen (H2) passes through the flame to the vent without being ionized. The only ionization that occurs is with the hydrocarbon samples. By placing the burner tip within the effective electric field, all positive ions will be collected and measured by the measuring circuit. All negative Ions will be attracted to the positive polarizing plate. Any extraneous electric fields that exist within the system will change the performance of the burner. Thus, maintaining a constant electric field and a clean system is of the utmost importance. Response of the burner to hydrocarbon components. - In a chromatograph system, each component to be measured is separated so that there is no interference between components. Each component is calibrated using a known concentration to determine response of the system to that component. The relationship between components does not depend upon each other but only on the calibration factor. Figure 6.4 FID 106
  • 107. Oil and Gas Measuring Instruments 6.4 Moisture Analyzer The electrolytic moisture sensor consists of a pair of spirally wound, parallel, electrode wires, partially embedded within the length of a glass tube. A thin layer of highly absorbent, phosphorous pentoxide (P2O5) completely coats the interior of the tube. In operation, the sample gas stream passes through the tube, giving up its entrained water molecules to the absorbent coating. A current is applied to the electrode windings, whereby the water molecules are completely and continuously electrolyzed into their respective hydrogen and oxygen elements. The streams moisture level is derived from the current required for complete electrolysis of the absorbed water. Interpretation of this value is based on the application of Faradays Law of Electrolysis, which describes the quantitative relationship of electrolyte production with the application of electric current. H2O + e- -> H2 + ½ O2 The current required to electrolyze the absorbed water is directly proportional to the number of moisture molecules present, as electrolyzed over a given time; that is the mass rate of water entering the sensor. As the current measurement is completely dependent upon the mass rate, it becomes crucial that pressure and flow are strictly regulated. Figure 6.5 Moisture Sensing element 107
  • 108. Oil and Gas Measuring Instruments 6.5 Role Play Each Trainee should speak thoroughly about one of the analyzers.  Oxygen  Moisture  Gas Chromatography 108
  • 109. Oil and Gas Measuring Instruments Chapter 7 Basic Considerations 7.1 Learning objectives 1. Introduce basic considerations for transmitter selection and installation. 7.2 Corrosion Effects Corrosion is the gradual destruction of a metal by chemical or electrochemical means. The most generic form of corrosion is galvanic corrosion. A combination of a cathode, an anode, and an electrolyte must be present for this type of corrosion.  Material Selection Guide as for Rosemount E= Excellent Resistance, Corrosion Rate (CR) < 0.05mm/year. G= Good Resistance, CR < 0.5mm/year. F= Fair Resistance, CR < 1.27 mm/year. P=Poor Resistance, CR > 1.27 mm/year. -- = Data Not Available. 7.3 Lightning and Static Effects Lightning is the attraction of a charged cloud to an oppositely charged earth, another cloud, or another area within the same cloud. Clouds produce lightning with the help of strong updraft air currents. These air currents cause rapid freezing of water droplets, which inherit a charge as they crystallize. Among the many types of lightning, cloud to 109
  • 110. Oil and Gas Measuring Instruments ground strikes are the greatest threat to industrial electronic equipment. Four factors are important in assessing the threat of lightning damage to a plant or facility.  Frequency and severity of lightning storms.  Vulnerability of existing and proposed instrumentation.  Exposure of systems wiring to possible lightning discharge.  Potential harmful impact of instrument failure on the process. Comparing the above factors to the costs of not protecting electronic equipment will help to decide if protection is beneficial. Figure 7.1 Globalannual Lightning stroms Three strategies are effective in minimizing lightning induced transients on industrial electronics.  Diversion: Grounded metallic structures form a cone of protection for equipment and cabling. 110
  • 111. Oil and Gas Measuring Instruments  Attenuation: Careful wiring practices, such as metallic raceways, cable shields, twisted pairs, and extensive grounding and earthing reduce the magnitude of transients.  Suppression: Add-on devices limit the magnitude of the transient appearing at the instrument. 7.4 Winterizing Transmitters Ensuring that electronic pressure transmitters operate under all weather conditions requires consideration of three important variable: installation, protective measures, and cost. First, the transmitter must be located properly with respect to the process pipe. Second, once optimum installation is determined, consider the degree of temperature protection required. Third, the degree of weatherization needed should then be balanced against bottom line cost. Failures can be caused by the freezing water or of solutions containing significant amounts of water. A volume of water will increase about ten percent as it changes to ice at atmospheric pressure. If the expansion is contained, the pressure exerted by the frozen fluid increases the magnitude of this increase is large in comparison with each incremental decrease in temperature. Temperature (F) Pressure (psia) 32 14.7 30 2100 25 7000 18.5 12660 9.5 20056 5.0 23115 0.5 26103 111
  • 112. Oil and Gas Measuring Instruments In any case, proper installation is necessary for good transmitter performance. In determining the best location, remember the following guidelines:  Keep corrosive or hot process material out of contact with the transmitter.  Prevent sediment from depositing in the impulse piping.  Keep the liquid head balanced on both legs of the impulse piping.  Keep the impulse piping as short as possible. Avoid ambient temperature gradients and fluctuations 7.4.1 Liquid Service For liquid flow measurement, mount the transmitters below the process taps with the drain/vent valves facing downward. This allows the trapped gases to vent into the process line. Make the taps to the side of the line to avoid sediment deposits. Figure 7.2 Liquid service connection 112
  • 113. Oil and Gas Measuring Instruments 7.4.2 Gas Service For gas flow measurement, install the transmitter above the process taps with the drain/vent valves facing upward. This provides automatic drainage and ensures that no liquid accumulates at the transmitter. Figure 7.3 Gas service connection. 7.4.3 Protective Measures Although winterizing a transmitter is relatively easy, protection should not end there. Impulse lines must also be protected from the point of measurement to the transmitter this may be accomplished in several ways. Lines may be protected by tracing, insulation or both. 7.5 Total Probable Error Total Probable error, TPE, is amore realistic number than would obtained by simply adding up all the possible errors, since it is unlikely 113
  • 114. Oil and Gas Measuring Instruments that all errors would go in the same direction from their means. The root sum square method, RSS, determines TPE by summing the squares of the individual errors and taking the root square of the total. Below is a comparison of two transmitters. 7.6 Discussion An open discussion is to be opened about different consideration for selection of transmitters. 114
  • 115. Oil and Gas Measuring Instruments References 1. Hugh Jack, "Automating Manufacturing Systems with PLCs", (jackh@gvsu.edu); version 4.6 December, 2004. 2. A.K. Sawhney, "Electrical and electronics measurements and instrumentation", J.C. Kapoor for Dhanpat Rai Co, Ltd. Naisarak, Delhi 1999. 3. Leamington Spa, "Flowmeters", 1979. 4. R.B.Helson, " The HART –protocol- a solution enabling technology", HART communication foundation, 9390 research blvd., suite II-250, Austin, Texas 78759. 5. Rosemount Measurement Catalog. 6. AEA Technology, "Level gauging", United Kingdom: 329 Harwell, Didcot, OX11 0QJ. 7. KROHNE, "Level Radar BM700". 8. Integrated Publishing – Engine Mechanics, www.tpub.com. 9. SBEM, www.sbem-india.com 10. Sensor Network, www.sensornet-work.com. 115