Electronic and Pneumatic Control System

Learning Outcome

Upon successful completion of this module, the student will be able to compare electronic and pneumatic instrumentation as applied to typical industrial control systems.

Enabling Objectives

The student will be able to:

(a) Describe the advantages and disadvantages of pneumatic vs. electronic instrumentation and control systems.

(b) Explain why one system may be chosen over another for a typical application.

(c) Sketch and describe the equipment and components required for a typical electronic instrumentation and control system.

(d) Sketch and describe the equipment and components necessary to form a pneumatic control system.

INTRODUCTION

Modem instrumentation vendors present the designer or prospective user with a formidable array of sophisticated devices and wonderful systems, almost all electronic. People are often blinded by the glitter of new technology and can make poor choices in basic system design. This can result in unexpected costs and less than expected performance.

Undoubtedly, electronic instruments are the best choice for most applications. However, there are some particular cases for which pneumatics may be a better choice. In this module, the student will look at how each system is designed, and explore the capabilities and disadvantages of each system.

PNEUMATIC INSTRUMENT SYSTEMS

Most pneumatic systems operate on clean, dry, regulated compressed air, but other gases such as nitrogen or methane are used for certain applications. A typical pneumatic system consists of the following:

• Air compressor.
• Air drier and filters.
• Distribution piping with pressure safety valves.
• Pressure reducing stations.
• Field instrument connections.
• Field instruments for measuring and control.
• Control systems.

Fig.1 shows a simplified pneumatic system.

Figure 1: Pneumatic System

Air Compressors

The air compressor is selected on the basis of expected air usage in scfm or m3/min. Large plants require two or more units. The units can be a reciprocal type or rotary, single or multistage, and are usually driven by electric motors, gas turbines, or diesel engines.

Compressor capacity is determined from the plant airflow requirements. Plant air usage is determined by summing the maximum air usage (approximately 0.02 m3/min of each device and adding a leakage factor.)

Instrument air compressors are located in a utilities building along with the power boilers. If a sulphur plant is on site, it is difficult to keep ambient hydrogen sulphide and sulphur dioxide from being pulled into the instrument air system through the compressor intake. However, the concentrations are low and, if the air is kept dry, no damage will result.

The receiver tank is designed to add storage capacity to the system and also avoid pressure fluctuation.

Air Driers and Filters

The compressed air discharged from the final stage of the compressor is usually relatively wet, and contains dirt and oily residues from the compressor itself. Since the air must be clean and dry, it is necessary to remove the water and the particulate matter.

Air driers can be any of several types, but the most common is the regenerative drier. Two towers filled with an adsorbent like activated alumina are required. One drier is on-line, drying air while the other is off-line, being regenerated with heated air. The regeneration cycles are usually controlled by a fully automatic time-sequencing system.

Air filters are usually placed in the header supplying the control panel instruments, and adjacent to the supply air for the field instruments, as shown in Fig. 1. The filter performs the function of removing dirt and scale, and also trapping moisture and oil. A blowdown valve is provided at the bottom of the filter sump to remove trapped moisture. In some cases a filter/regulator combination can be used to directly supply air to a single valve or transmitter.

1. Specification For Instrument Air Quality

A reliable supply of compressed air that is clean, dry, and regulated is required for proper, low-maintenance operation of pneumatic instruments. Liquid or solid contaminants can clog the tiny orifices integral to all pneumatic devices. Water can freeze, and the ice not only will cause clogging, but also cause damage to small parts. ISA Standard S7.3 recommends the following minimum requirements for instrument air:

Moisture

The dewpoint at the line pressure should be 10°C (18°F) below the minimum ambient temperature, but in no case should it be more than 2°C 3.6° F) above the minimum ambient temperature.

• Particle Size

The maximum particle size in the air stream at the instrument should be 3 mm.

• Oil Content

The maximum oil content should be as close to zero as possible, but in no circumstances should it exceed 1 ppm.

2. Supply Pressure

For 20 - 100 kPa (3 - 15 psi) instruments, ISA Standard S7.4 allows a maximum supply pressure of 140 kPa (20 psi). The supply pressure must be high enough to deliver a reasonable volume of air, but if it is too high, damage to the instruments will result.

The supply pressure should be constant to avoid measurement errors. It is therefore important to avoid excessive pressure drops in the supply fines leading to the instrument supply headers.

Distribution Piping and Pressure Safety Valves

The main piping used to deliver instrument air throughout the plant is commonly 50.8 mm (2 inch) schedule 40 carbon steel. Air supply branch piping that leads to individual instrument headers is usually 25.4 mm. (1inch) galvanized pipe.

Pressure safety valves are required by code to provide overpressure relief The one shown in Fig.1 on the air receiver provides relief in case of blocked air flow downstream of the receiver. The relief valve on the main air header may provide relief in case of fire or some other condition that would cause arise in pressure.

Pressure Reducing Stations

Pressure-reducing stations, in this application, are pressure regulators of various sizes and types. Their function is to reduce air pressure from 700 kPa (102 psi) to a usable level, usually 140 kPa (20 psi). However, there are some installations that may require very low pressure air for process line purging or some other purpose.

There are some cases in which emergency instrument air may come from another air system that is at a higher pressure, so that a pressure reducing station is required at the tie-in point. There are also special cases where instruments are supplied from a high pressure natural gas line.

Instrument Connections

Air supply tubing from the piping isolation valve to the regulator should be a minimum size of 9.5 mm (3/8 inch), pvc jacketed copper or plated carbon steel tube to avoid any significant pressure drop, particularly for control valves. To avoid problems with vibration, the connecting tubing should be looped; alternately, air hose can be used.

Tubing connections are almost always compression type fittings. The older flared fittings are rarely used. Tubing nuts must not be overtightened and manufactures like Swagelok supply a gauge to check for proper tightness.

Field Instruments

Pneumatic field instruments, employing the baffle-nozzle amplifier, have developed over the years to the point where they can do an amazing number of tasks. The intent of this module is to look at them only in an overall system perspective.

Names and brief descriptions of some of the more common pneumatic devices found in the plant follow:

• Transmitters

These convert a process physical quantity such as level, pressure, flow, or temperature into a representative pneumatic analog signal, usually 20 - 100 kPa, which is then transmitted to a centrally located control room.

• Boosters

When a signal has to be transmitted more than 80 in (262 ft), it often starts to exhibit excessive time lag due to the increasing resistance and capacitance. A signal booster with its own 140 kPa air supply is connected at distances of every 80 - 100 in (262-328 ft) to speed up the signal. Boosters are normally1:1 (signal in = signal out), but 1: 1.5, and 2: 1 boosters are available.

• Selector Relays

When it is necessary to select one of two or more signals, a high or low selector can be used. For instance, if only one of the two flow lines shown in Fig. 2 is active at any one time, a high selector can be used to direct only the active signal. A > symbol denotes a high selector and the < symbol denotes a low selector.

Figure 2: High Selector Used in a Flow System

• Pressure repeaters

These devices are useful in head level measurement of closed vessels where it is desirable to maintain a dry leg. The vapour pressure will be imposed on the diaphragm of the repeater and a matching air pressure will appear at the output.

• Controllers

Many control loops in a process plant are single, local (mounted on the process), pneumatic control loops. The main advantage is low cost installation and quick response. The main disadvantage is that the operator has to go out to the controller to change the setpoint or switch to manual control. The designer should be aware that these controllers do not usually come with a manual station, so it must be specified as an option.

An example of a local, field-mounted controller is a pressure control on a 7000 kPa to 2400 kPa (1000 - 350 psi) steam letdown station. Another is a pressure control on a natural gas line, where the natural gas also supplies the controller and the valve. Other single loop, local controllers control level, temperature, and flow. A commonly used displacer-type level controller is shown in Fig. 3.

Figure 3: Displacer-Type Local Level Controller

• Control Valves

Control valves are responsible for forcing process changes by altering fluid flow in a pipeline, and are a very important part of the control system. Most control valves in process plants are pneumatically actuated, like the example shown in Fig. 4.

Figure 4: Control Valve with Pneumatic Diaphram Actuator

• Pneumatic Switches

Pneumatic level switches are available for level, pressure, temperature, and flow. The output of a switch will be either 20 kPa (3 psi) or 100 kPa (15 psi), depending on whether or not it is in an alarm state.

• Chart Recorders

These are used mainly for recording flows around the plant for accounting purposes. Operators must change charts at intervals. Strictly speaking, these are mechanical devices but are associated with pneumatic systems.

Signal Transmission

1. Signal Range

Pneumatic signal transmission most commonly uses the 20 - 100 kPa (3 - 15 psi) signal range, although 20 - 185 kPa (3 - 27 psi) is found on older systems, particularly on boiler controls. The 20 kPa bias is a boon to detecting component failures.

2. Signal Transmission Dynamics

Pneumatic signals are transmitted through 6.3 mm (0.25 inch) O.D tubing made of plastic, aluminum, or copper; or, in some rare cases, stainless steel. Larger tube diameters are available, but expense increases dramatically with size.

The longer the tubing run, the more lag can be expected. Long lag times can degrade control system performance, and must be avoided where possible. There are lags inherent in all processes, so lags due to signal lines can only add to the problem.

Flow loops are most vulnerable to added lags, and temperature loops are least vulnerable. Volume boosters and valve positioners are the usual solutions to long signal line lag.

Signal response is quicker at 100 kPa (15 psi) than it is at 25 kPa (4 psi), which can add to control dynamics problems. This is why it is preferable for process controls to operate at a high point in their range.

Control Room Panel Design

1. Requirements

Control panels must display all the important information from the process or processes at a glance. They must be designed to point the operator quickly to loops indicating an alarm, and provide easy access to setpoint controls, hand/auto switches, on/off switches, and push buttons. They must also provide the operator with historical information pertaining to the process over a period of time, in order to track problems and to include information in shift reports.

NOTE: Control panels using electronic instruments are also laid out in much the same way, because the fundamental philosophy of operator convenience remains the same. The major difference between them lies in the back-of-panel design. The current trend in upgrading is to remove the control panels entirely, and replace them with VDTs (video display terminals).

2. Control System Layout

Controllers are arranged in groups representing distinct sections of the process. In a gas plant, for example, the inlet separators would be in a separate group from the fractionation train. This technique of dividing into groups helps the operator follow the process flow. An upset event at the front end will eventually be reflected throughout the entire process.

In large operations, with large control panels, more operators are required, and each one is assigned a particular section of the control panel.

3. Annunciator Panels

Annunciators are designed to alert the operator to a process alarm condition. One or more lamps in an array of visual indicators will come on, and also cause an audible alarm. This will allow the operator to be quickly apprised of the cause of the alarm, so that immediate action can be taken. The operator can acknowledge the audible alarm by pushing a button, thus shutting it off. The lamp indicating the alarm condition will remain lit until the process returns to its normal range, and the alarm is reset.

4. Process Graphics

Graphics, on a pneumatic panel, are not the computer graphics that have become so common, but they undoubtedly fathered the concept. Panel graphics are made from coloured plastic, and are designed to show the process flow with plastic graphics symbols that represent parts of the process, like fired heaters, distillation towers, and heat exchangers. More sophisticated graphic displays have coloured lights embedded in the graphic symbols of pumps, to show pump status (on or off).

5. Historical Trends

Chart recorders maintain an historical record of the process over a twenty-four hour period or more. The charts are used to assess plant performance and to assist in spotting problems with process equipment. Flow charts are also integrated to obtain flow totals. Flow totalizers keep a numerical, running count of the unit mass or volume of flow through the plant. These are manually recorded by an operator at the end of each shift.

6. Behind the Panel

The arrangement at the back of the panel is as important as the front. Sufficient space must be allowed for air headers, tubing runs, conduit, ductwork, and so forth. Mounting racks must exist to mount switches, relays, transducers, square root extractors, and other auxiliary components. The layout must be designed to provide easy access for maintenance, with provision for AC power outlets and lights.

Pneumatic junction boxes for incoming and outgoing signal tubing, and thermocouple wire junction boxes, are customarily mounted on the wall behind the control panel.

ELECTRONIC INSTRUMENT SYSTEMS

Electronic instrument systems must have a reliable supply of either commercial power, power produced on site, or a combination of both. Electronic instruments are ruggedly built and can withstand environmental extremes, but it is still necessary to supply clean (spike free), stable power. An electronic instrument system consists of the following:

• Power supplies.
• UPS (backup power).
• Power and signal distribution system.
• Field instrumentation.
• Signal conditioning.
• Marshalling cabinets and panel design.
• Control panels or consoles.
• Control systems.

Fig. 5 shows a simplified typical electronic instrumentation system

Figure 5: Electronic Instrumentation

Power Supplies

An important part of any electronic instrumentation system, whether it be individual controllers or a complete computer control system, is the power supply. These units must supply reliable 12 or 24 VDC power to every loop in the plant, and must quickly recover from accidental events like short circuits.

Uninterruptible Power Supplies (UPS)

The UPS shown in Fig. 5 is designed to provide emergency power for at least thirty minutes after a power failure, and to maintain instrument loop power during "brown out" conditions. This type of emergency power is justified for critical process loops and for computer control systems.

The four main components of a UPS are the battery charger, battery bank, DC/AC inverter, and the transfer switch. They are described as follows:

• The battery charger keeps the lead-acid batteries fully charged during normal conditions.

• The battery bank provides a source of stored energy for backup power.

• The inverter converts 12 or 24 volt DC power to 120 volt AC power.

• The transfer switch rapidly (1/4 cycle) switches from line to UPS power when a power failure is detected.

Power and Signal Distribution Systems

For electronic control system design, whether the control system is computerized or not, certain fundamental decisions have to be made in terms of system design, long before the equipment is purchased. The wrong decision can mean huge construction budget overruns, costly maintenance, and costly future expansion.

The main factor influencing the design is the safety classification of the various areas of the plant. Hazardous areas are ones where electrical sparks could initiate a fire or explosion. A CSA Class 1, Division I area in an oil refinery, for example, is considered very hazardous. Extremely flammable vapours are expected to be in the surrounding air most of the time.

A water treatment plant is classified by the Canadian Electrical Code as a nonhazardous, or general purpose area, in terms of its potential for explosions.

Design of electrical systems for hazardous areas requires a lot of thought, and requires a thorough knowledge of the electrical code and other standards. There are two safe wiring methods that can be selected, each with advantages and disadvantages.

1. Explosion Proof / Design

The system shown in Fig. 5 is an explosion proof system. Explosion proof means that if an explosive mixture were ignited by an electrical spark within an enclosure, it would be contained within that enclosure, and not propagate an explosion over a wide area.

Seals are put in conduits to prevent gases from migrating from hazardous areas to areas that are supposed to be safe. Also, purging of enclosures and cabinets with air or nitrogen is sometimes employed to reduce the degree of hazard. All switches, wire terminations, lights, indicators, analyzers, and transmitters must be contained within Canadian Standards Association (CSA) certified explosion proofhousings.

Explosion proof electrical equipment is not only very heavy and very expensive, but it is also difficult to access for maintenance. Maintenance personnel must ask an operator to check the area for gas, and then to issue a work permit, before an enclosure can be opened.

2. Intrinsically Safe Wiring

"Intrinsically safe" means that there is no electrical component in the hazardous area that can produce a spark with enough energy, or generate enough heat, to create an explosion. This means that all wiring must be extended through special electrical barriers between the safe and the hazardous areas, and that all components such as transmitters must be CSA certified as intrinsically safe for the area.

A barrier is essentially a special current-limiting device, employing zener diodes, that limits electrical energy in field circuits to below that required to cause ignition of the gases, vapours, or dust expected to be in a particular area. An intrinsically safe instrument loop is shown in Fig. 6.

The main advantage of I. S. (intrinsically safe) circuits is that enclosures in the field only have to be weather-proof. This means that they can be opened without a permit. The biggest disadvantage is that barriers, and separate cabinets to put them in, must be specified and procured.

I. S. wiring cannot be mixed with non I. S. wiring under any circumstance. Cable containing I. S. wiring is usually colour coded with a blue covering. Junction boxes that are used for I. S. wiring cannot be used for any other purpose.

Figure 6: Intrinsically Safe Instrument Loop Wiring

Field Instrumentation

1. Transmitter

The most common device in the field is the transmitter, used to measure flow, pressure, level, and temperature. Transmitters are either conventional, analog, or smart. The output signal is almost always 4 - 20 mA, regardless of which type is used.

The smart transmitter is capable of digital communications with a hand held calibrator, or with a computerized, distributed control system if it is compatible.

The selection of wetted parts (parts that contact the process) is the same as for any pneumatic transmitter, and connection to the process is identical.

The ambient temperature limits for most transmitters are from -40° to 60°C (-40° to 140° F), but some transmitters designed for the European market have a lower limit of only -20°C (-5°F).

There are transmitters certified as intrinsically safe, and some only explosion proof. Even if the transmitter is on a barriered I. S. circuit, it cannot be used in Alberta unless it is certified as I. S. by the CSA.

2. Switches

These are very common devices in the field, used mainly on level, flow, and pressure. In hazardous areas, the switches must be on barriered circuits or be enclosed in explosion proof housings.

3. Analyzers

Various types of analyzers (chromatographs, O2, moisture) are becoming more common as field devices. These nearly always have unique design and installation requirements that present some interesting challenges. Placing these devices in hazardous areas, building shelters for them, and attempting to connect them to communications networks all create special problems.

4. Control Valves

These are mostly pneumatic, and require current-to-air converters to convert the 4 - 20 mA signal to 20 - 100 kPa (3 - 15 psi). There have been a number of developments with electric motor actuators, mostly involving the application of advanced electronics and microcomputer circuits to make the device smarter.

Signal Conditioners

In addition to current-to-pressure converters, the large variety of special instrumentation requires other devices such as electrical isolators, linearizers, and voltage-to-current, current-to-voltage, and current-to-current converters. The requirement for these separate devices will decrease as instrumentation technology becomes more standardized. However, for the foreseeable future these devices will need to be bought, placed in explosion proof cabinets in the field, or in cabinets in the electrical centres, to allow one instrument to be connected to another.

Control Rooms

The subject of control rooms has been covered in the pneumatic section and, aside from obvious differences (wiring vs. tubing), the layout is the same. However, the trend is toward control rooms that contain only video display terminals (VDTs) and operator keyboards. Even this could change as new networking techniques make decisions that are now made by operators. The control room could even disappear altogether, and be replaced by information terminals scattered throughout an office.

Distributed control systems (DCS) are currently replacing the conventional control panel. The actual control is done in process interface cabinets located in a separate termination room, or in electrical centres scattered throughout the plant site.

PNEUMATIC INSTRUMENTS COMPARED TO ELECTRONIC   INSTRUMENTS

Now that the student has a knowledge of pneumatic and electronic control systems, the advantages and disadvantages can be summarized.

Pneumatic Instruments

1. Advantages

• Pneumatic devices are easier to install in remote sites where only natural gas is available.

• They are inherently intrinsically safe. No explosion proof or I. S. circuits are required, and therefore no special enclosures are needed. There is no electromagnetic interference and no shock hazard.

• Local loops are easy to implement, and the controller output can drive a valve directly.

• There is inherent damping due to resistance and capacity of signal lines, and the compressibility of air.

• Self-purging keeps out foreign material.

• Used pneumatics are often available through various salvage companies. This can greatly reduce the cost of instrumenting a small operation.

• Maintenance and trouble shooting is generally easier.

• Calibration equipment is less expensive and easier to use.

• They are not affected by ground loops or lightning strikes.

• Control rooms do not have to be environmentally controlled.

• Ambient temperature limits are very wide, and the lower limit is the dewpoint of the air.

• Adequate storage of air will run the plant after a power outage.

2. Disadvantages

• Signal runs are limited in length without boosters.

• There are few manufacturers still making pneumatic instruments. (Three instrument companies who still do are Foxboro, Moore, and Fisher.)

• Gathering and transmission of data over long distances are not possible.

• There is no data storage capability. Data must be converted to electrical signals for data logging.

• Signals are slow to respond to changes.

• Instruments tend to be bulky.

• Compressors and air drying equipment are required.

• Control systems are very difficult to reconfigure.

Electronic Instruments

1. Advantages

• The 4 - 20 mA current loop is compatible with the latest control systems. New transmitters allow digital communication.

• Response speed is high, and they will not add lag to the process control loop.

• Wiring over long distances is less expensive.

• Glass fibre can be used for transmission.

• Data can be collected and transmitted over long distances.

• There is excellent potential for network integration.

• Solar panels allow use in remote areas.

• Their design is compact.

• Control systems allow great flexibility, and control configurations can be changed easily.

• High accuracy can be expected.

• Information from field devices can be stored in an automated data base.

2. Disadvantages

• Wiring in hazardous areas is very expensive.

• Calibration equipment is more expensive, and requires highly qualified personnel to use it properly.

• There is a lack of standardization, especially in communications, between manufacturers.

• New devices become obsolete quickly. It is very difficult to keep technical manuals up to date.

• Vendor information and choices abound, making it more difficult to choose instruments for a particular application within a system.

• Specifications are sometimes vague and confusing.

• Devices portrayed as multipurpose rarely are, in fact.

• Signal conversion is required to drive pneumatic valves.

• Electrical noise and ground loops are always a problem.

• UPS is required for critical loops.

• Degraded components that cause intermittent problems are very hard to detect, even with powerful diagnostic tools.

• The instrument or analyzer you want sometimes will not "talk" with the rest of your system, without expensive interface equipment, and then only partially in some cases.

SUMMARY

While it is generally believed that electronics technology is superior in every way, the student will have learned from this module that this may not always be true. Often, pneumatic controls are not used only because fewer people are aware of them and of their advantages.

For instance, exotic electronic instruments are often chosen for tank level measurement, when a simple bubble tube operating on natural gas would do a better job.

Electronic instruments have evolved, and will continue to evolve at a rapid pace, but there will always be a use for pneumatic instruments.