The Role of a Sensor, Logic Solver and Final Element in a SIS (Safety Instrumented System)

UE One Series Safety Transmitter

IEC 61511 is a technical standard which establishes practices that ensure the safety of industrial processes through the use of instrumentation. Such systems are referred to as Safety Instrumented Systems. The title of IEC 61511 is "Functional safety - Safety instrumented systems for the process industry sector".

Traditional safety systems that follow the IEC 61511 standard consists of three major components: a sensor, or a transmitter; a logic solver, or a safety PLC; and the final element, which is often a pilot valve.

Many major manufacturers provide process transmitters with safety integrity level third-party certifications to provide the industry standard for 4-20 milliamp output. This analog signal retransmits the process variable to the safety PLC for analysis where algorithms test to see if the process is within safe operating parameters. If abnormal conditions are determined to exist, an alarm may be sounded and if dangerous conditions are confirmed, an emergency shutdown sequence may be initiated.

Further exploring the roles of each of these safety system components, all three must work together flawlessly in order to bring the plan to a safe state, or allow the process to continue and run in a safe manner. Reliability of each component becomes paramount to the proper operation of the safety instrumented function, or SIP, and therefore the safe operation in the plant.

For example, the central component must continuously monitor the process variable and provide this information to the safety PLC via a hardwired connection. What actually occurs however, is the analog signal from the sensor transducer is converted to the digital domain for processing. Digital signal processing occurs inside the transmitters electronics to adjust the signal for ambient and process temperature conditions, sensor response errors, signal filtering, user settings, sensor calibration, and the process variable display. The resulting conditioned and process signals converted back to the analog domain to retransmit the 4 to 20 milliamp signal over the hardwired connection to the safety PLC. The PLC must now determine if the analog signal reveals a dangerous condition by comparing the level of the analog signal with pre-programmed set points. Here is what actually occurs. The retransmitted analog 4-20 mA signal must be converted back to the digital domain for processing inside the safety PLC's electronics. The level of the signal is compared to a pre-programmed threshold that is set at the limit of safe operation. If the signal level is determined to be within the safe limits of operation, a relay inside the safety PLC will remain closed. If the signal level is determined to be outside in the safe operating limits of the process, the safety relay will open. The safety relay state - is it open or is it closed - will determine what action the final element will take via a hardwired connection.

The final element must now take action to perform the safety function. An example of a final element is a steam cut-off valve to a turbine generator. The valve, or the final element, can quickly close to cut off the steam that passes through the generator's rotor in order to stop the rotation. Here is what actually happens. A pilot valve is connected to the plant air supply. The pilot valve is actuated by energizing 120VAC solenoid coil. When the coil is energized, the valve is held open, allowing plant air to enter the pneumatic actuator for the steam valve. Air pressure is used to hold the steam valve open allowing steam to enter, and cause the turbine generator to rotate. If the signal from the safety PLC opens to de-energize the pilot valve coil, the pilot valve will close, cutting off the air supply to the steam valve, which will cause the steam valve to close. This is an example of a de-energized to trip (or DTT) safety function.

As you can see there are a lot of components that must operate as designed to shut down the turbine generator in the event that an abnormal condition exists. Examples of abnormal conditions may include low lubrication oil pressure, high lubrication oil temperature, steam pressure that's too high, inadequate plant air pressure, etc. In order to decrease the safety instrumented functions probability to fail on-demand, all of the functions described here must work flawlessly.

Basics of Continuous Level Measurement

Many industrial processes require the accurate measurement of fluid or solid (powder, granule, etc.) height within a vessel. Some process vessels hold a stratified combination of fluids, naturally separated into different layers by virtue of differing densities, where the height of the interface point between liquid layers is of interest.

A wide variety of technologies exist to measure the level of substances in a vessel, each exploiting a different principle of physics. This chapter explores the major level-measurement technologies in current use.

Level gauges (sightglasses)

Siteglass

Level gauges are perhaps the simplest indicating instrument for liquid level in a vessel. They are often found in industrial level-measurement applications, even when another level-measuring instrument is present, to serve as a direct indicator for an operator to monitor in case there is doubt about the accuracy of the other instrument.

Float

Perhaps the simplest form of solid or liquid level measurement is with a float: a device that rides on the surface of the fluid or solid within the storage vessel. The float itself must be of substantially lesser density than the substance of interest, and it must not corrode or otherwise react with the substance.

Hydrostatic pressure

A vertical column of fluid generates a pressure at the bottom of the column owing to the action of gravity on that fluid. The greater the vertical height of the fluid, the greater the pressure, all other factors being equal. This principle allows us to infer the level (height) of liquid in a vessel by pressure measurement.

Displacement

Displacer level instruments exploit Archimedes’ Principle to detect liquid level by continuously measuring the weight of an object (called the displacer) immersed in the process liquid. As liquid level increases, the displacer experiences a greater buoyant force, making it appear lighter to the sensing instrument, which interprets the loss of weight as an increase in level and transmits a proportional output signal.

Echo

Echo level (radar)

A completely different way of measuring liquid level in vessels is to bounce a traveling wave off the surface of the liquid – typically from a location at the top of the vessel – using the time-of-flight for the waves as an indicator of distance, and therefore an indicator of liquid height inside the vessel. Echo-based level instruments enjoy the distinct advantage of immunity to changes in liquid density, a factor crucial to the accurate calibration of hydrostatic and displacement level instruments. In this regard, they are quite comparable with float-based level measurement systems. Liquid-liquid interfaces may also be measured with some types of echo-based level instruments, most commonly guided-wave radar. The single most important factor to the accuracy of any echo-based level instrument is the speed at which the wave travels en route to the liquid surface and back. This wave propagation speed is as fundamental to the accuracy of an echo instrument as liquid density is to the accuracy of a hydrostatic or displacer instrument.

Weight

Weight level measurement

Weight-based level instruments sense process level in a vessel by directly measuring the weight of the vessel. If the vessel’s empty weight (tare weight) is known, process weight becomes a simple calculation of total weight minus tare weight. Obviously, weight-based level sensors can measure both liquid and solid materials, and they have the benefit of providing inherently linear mass storage measurement. Load cells (strain gauges bonded to a steel element of precisely known modulus) are typically the primary sensing element of choice for detecting vessel weight. As the vessel’s weight changes, the load cells compress or relax on a microscopic scale, causing the strain gauges inside to change resistance. These small changes in electrical resistance become a direct indication of vessel weight.

Capacitive

Capacitive level measurement

Capacitive level instruments measure electrical capacitance of a conductive rod inserted vertically
into a process vessel. As process level increases, capacitance increases between the rod and the vessel walls, causing the instrument to output a greater signal. Capacitive level probes come in two basic varieties: one for conductive liquids and one for non- conductive liquids. If the liquid in the vessel is conductive, it cannot be used as the dielectric (insulating) medium of a capacitor. Consequently, capacitive level probes designed for conductive liquids are coated with plastic or some other dielectric substance, so the metal probe forms one plate of the capacitor and the conductive liquid forms the other.

Radiation

Certain types of nuclear radiation easily penetrates the walls of industrial vessels, but is attenuated by traveling through the bulk of material stored within those vessels. By placing a radioactive source on one side of the vessel and measuring the radiation reaching the other side of the vessel, an approximate indication of level within that vessel may be obtained. Other types of radiation are scattered by process material in vessels, which means the level of process material may be sensed by sending radiation into the vessel through one wall and measuring back-scattered radiation returning through the same wall.

To download an excellent continuous level selection guide follow this link.

Industrial Level Instrument Selection Guide from Ives Equipment

Content above abstracted from “Lessons In Industrial Instrumentation”
by Tony R. Kupholdt under the terms and conditions of the

Creative Commons Attribution 4.0 International Public License.

Measuring H2S in CO2 Bottling Gas

OMA H₂S Analyzer 

Reprinted with permission from Applied Analytics

Prior to filling, beer bottles are purged with CO₂ to remove air and protect the taste against oxidation. In the fermentation process, yeast consumes sugar and expels a large amount of CO₂ which can be "reclaimed" and used for this bottle purging purpose. Unfortunately, fermentation often also produces toxic, odorous sulfides which can foam up into the piping and contaminate the reclaimed CO₂.

In order to continue using the great resource of CO₂ byproduct yet avoid contaminating the bottled beer with foul-smelling toxins, the reclaimed gas is run through sulfide removal skids. However, sulfide breakthrough can occur if the gas does not spend enough time in the scrubber. Employees are sometimes tasked with sniff-testing the reclaimed CO₂ , but this is an unhealthy practice and is too discrete to vigilantly prevent product contamination.

An automatic, continuous analysis solution is required in order to immediately divert contaminated CO₂ from use in bottling as well as provide feedback control for the sulfur removal processing time.

The OMA H₂S Analyzer is used to continuously measure concentrations of hydrogen sulfide (H₂S) and dimethyl sulfide (DMS) in the fermentation byproduct gas. This system uses a full-spectrum UV-Vis spectrophotometer to detect the absorbance of sulfides in the reclaimed CO₂ stream, an ideal method as CO₂ has zero absorbance in the UV spectrum. The OMA provides fast response alarms to high-concentration threshold which allows immediate diversion of contaminated CO₂.

For this application, the OMA is typically multiplexed to automatically cycle analysis between multiple sampling points. This maximizes system value by allowing one unit to monitor the raw fermentation gas entering the reclamation system, gas coming off the acid aldehyde scrubbers, and the bottling gas coming off of the sulfur removal beds -- all with sample stream switching at user-defined intervals.

Use of Process Analyzers in Fossil Fuel Plants

Steam Power Plant

In spite of all efforts concerning energy savings and efficiency, the growing world population and the aspired higher 'standard of living' will lead to a further in- crease of world energy demand. In this context, almost half of the primary energy demand will continue to be covered by solid fuels, particularly by coal, until 2020 and many years beyond.

This results in the challenge to power plant engineering to implement this increasing energy demand by using new technologies and applying the highest possible conservation of the limited resources of raw materials and the environment.

This includes new materials for higher operating temperatures and, therefore, higher efficien- cies of the power plants, as well as combined power plants that drastically reduce the share of unused waste heat or improved methods for reducing emissions.

Optimizing processes without delay, designing flexible operating conditions, improved use of the load factor of new materials and safely controlling emissions of toxic substances are all tasks that require the use of powerful measurement techniques. For this purpose, devices and systems of process analytics per- form indispensable services at many locations in a power plant.

In spite of all the alternatives, the undiminished increasing world energy demand also makes the expansion of energy recovery from fossil fuels necessary. However, the use of new materials and technologies further increases the efficiency of power plants and further reduces environmental pollution from the emission of toxic substances.

In this context, process analytics plays an important role: It determines reliable and exact data from the processes and thereby allows for their optimization.

Take a moment to review the document below, or if you prefer,  download the "Use of Process Analyzers in Fossil Fuel Plants" PDF file here.

Use of Process Analyzers in Fossil Fuel Plants from Ives Equipment

Differential Pressure Transmitters and Inferential Measurement

Differential Pressure Transmitter
(Siemens)

Differential pressure transmitters are utilized in the process control industry to represent the difference between two pressure measurements. One of the ways in which differential pressure (DP) transmitters accomplish this goal of evaluating and communicating differential pressure is by a process called inferential measurement. Inferential measurement calculates the value of a particular process variable through measurement of other variables which may be easier to evaluate. Pressure itself is technically measured inferentially. Thanks to the fact numerous variables are relatable to pressure measurements, there are multiple ways for DP transmitters to be useful in processes not solely related to pressure and vacuum.

An example of inferential measurement via DP transmitter is the way in which the height of a vertical liquid column will be proportional to the pressure generated by gravitational force on the vertical column. The differential pressure transmitter measures the pressure exerted by the contained liquid. That pressure is related to the height of the liquid in the vessel and can be used to calculate the liquid depth, mass, and volume. The gravitational constant allows the pressure transmitter to serve as a liquid level sensor for liquids with a known density. A true differential pressure transmitter also enables liquid level calculations in vessels that may be pressurized.

Gas and liquid flow are two common elements maintained and measured in process control. Fluid flow rate through a pipe can be measured with a differential pressure transmitter and the inclusion of a restricting device that creates a change in fluid static pressure. In this case, the pressure in the pipe is directly related to the flow rate when fluid density is constant. A carefully machined metal plate called an orifice plate serves as the restricting device in the pipe. The fluid in the pipe flows through the opening in the orifice plate and experiences an increase in velocity and decrease in pressure. The two input ports of the DP transmitter measure static pressure upstream and downstream of the orifice plate. The change in pressure across the orifice plate, combined with other fluid characteristics, can be used to calculate the flow rate.

Process environments use pressure measurement to inferentially determine level, volume, mass, and flow rate. Using one measurable element as a surrogate for another is a useful application, so long as the relationship between the measured property (differential pressure) and the inferred measurement (flow rate, liquid level) is not disrupted by changes in process conditions or by unmeasured disturbances. Industries with suitably stable processes - food and beverage, chemical, water treatment - are able to apply inferential measurement related to pressure and a variable such as flow rate with no detectable impact on the ability to measure important process variables.

Process Instrumentation White Paper: Seven Switch Myths Busted

One Series Pressure and Temperature
Transmitter-Switches (United Electric)

Reprinted from United Electric Controls ViewPoint.
More UE ViewPoints can be found here.

Summary

With more than 80 years of evolution since its introduction, switch technology as changed significantly enough that some of the common beliefs about switches are no longer true. Seven common myths surrounding switches are analyzed. Recent technology advancements in switch design and how these advancements solve problems in industrial and OEM applications are discussed. Readers will acquire a better understanding of the new technology available to improve control, process efficiency and safety.

1. Blind & Dumb

Prior generations of switches were incapable of displaying process measurements locally, forcing the installation of gauges that created more leak paths and added additional costs. Operators were unaware when installed switches stopped functioning due to welded contacts in the microswitch. Switches required removal from service and manual testing to conform functionality. Often, the control or safety function would go unprotected for days while the switch was in queue to be bench tested, creating an immediate safety concern.

These industry-wide problems inspired manufactures to innovate the next generation of switches that incorporate liquid crystal displays (LCD), presenting local process variable measurements, and integrated internal diagnostics, monitoring the health of the device. The addition of LCDs and device diagnostics increases up me and improves overall plant safety. Original equipment manufacturers (OEM) benefit from a reduction in installed components and a more dependable turnkey product for their customers.

2. Difficult Adjustments

Set point and deadband adjustments were a nuisance for operators and technicians. The instruments were required to be removed from service and calibrated on a bench in the maintenance shop. Installation instructions were not always available for installed devices, leading to wasted me searching for documentation or requesting additional information from the manufacturer. Delicate adjustments were required to achieve desired set points and deadbands, the dead time where no action happens, varied based on the microswitch inside the control. More often than not, instruments were mis- handled leading to premature failure due to inexperienced technicians.

Today’s generation of switches offer electronic platforms that reduce setup and programming to a ma er of seconds. A user interface on the local LCD provides simple prompts that allow users to program switch set points instantly without the need to remove the instrument from the process. Deadband and set point are now 100 percent adjustable, allowing operators to choose the desired range based on the application requirements. No longer are operators required to order and stock redundant devices in the event one failed in the eld. Users now have the flexibility of programming one switch to match many different process requirements.

3. Unsafe in Critical Applications - Not Appropriate for SIS

Industrial process plants are pushing pressure and temperature limits to new boundaries in an effort to stay competitive in a global market. Many of the systems designed 20 years ago were not intended to run at the current process extremes. It is only a ma er of me before these systems fail. Safety instrumented systems (SIS) are being installed to protect the process, people and the environment. These systems require devices that have been rigorously tested by third party agencies to verify the level of safety performance. Mechanical switches, referred to as sensors in SIS, are one of the most common components to fail in these systems. Users and designers require a switch that matches their required system performance level while also being fault tolerant.

Based on the strict performance requirements of SIS, newly introduced hybrid switches integrate the functionality of a switch and a transmitter. The switch portion of the device provides a direct digital output (relay output) to a final element that will instantly bring a process to a safe state in the event of a critically abnormal situation. The analog transmitter signal can be used for trending to determine the health of the device and the process. These new transmitter-switches and recently SIL 2 and 3 exida-certified devices (One Series Safety Transmitter) offer operators a simple and safe product that matches the demanding performance requirements of safety instrumented systems.

4. Problematic in Tough Environments

Whether installed on plant rotating equipment, such as turbines, or on demanding OEM auxiliary equipment, such as pumps or compressors, switches are required to function in tough environments that include shock, vibration, heat and pressure. Vibration is one of the leading causes of electro- mechanical switch failure. Most switches are mechanical in design and utilize a plunger to activate a microswitch. In areas of high shock and vibration, the plunger position can fluctuate and lead to false trips.

New solid-state, electronic switches provide a solution to the common problems with mechanical switches installed in high vibration applications. Because they have no moving parts, these switches can be mounted directly to the equipment or process without connecting impulse lines to keep them isolated from vibration. Industry leading turbine manufacturers and end users operating large compressors in petrochemical plants are experiencing much more reliability and fewer false trips with these new electronic switches, compared to the old mechanical designs.

5. Deploy Electromechanical Designs When Line Power is Unavailable

Most pressure switches sold over the past 80 years were designed to operate without electric power by incorpora ng a sensor that measures pressure by placing force on a plunger that would actuate a microswitch.

The first genera on of digital switches required line power to operate and were not adopted due the unavailability of line power and the cost of wiring. The new genera on of switches operates from leakage current in the circuit when connected to a host device, such as a Programmable Logic Controller (PLC), allowing electronic switches to be drop-in replacements for the old mechanical switches. Today, we have the ability to replace a blind and dumb mechanical switch with a new solid-state, electronic switch that offers a digital gauge, switch and transmitter in one instrument without adding any wiring or hardware.

6. Antiquated Technology

Today’s process plants run their processes faster and ho er than they were originally designed. Ultimately, these plants will have to ini ate modernization projects to support the new demands of the process. Old switches provided users with digital, on-off signals that were either wired to control a piece of equipment directly or sent to a PLC for alarm functionality. As plants go through modernization projects, they restructure control system input/outputs (I/O) to support more analog signals than the digital signals used in the past. Transmitters are commonly chosen and recommended over switches in these new projects, but transmitters do not provide the internal control functionality found in switches.

These modernization projects are costly requiring new equipment, updated wiring, expanded I/O, extensive engineering resources, and costly down me. Users are diligently exploring new ways to reduce overall project costs. The average process transmitter can cost upwards of $2,000 compared to the average process switch costing around $500. Process plants often have 100 to 1,000 switches installed. To upgrade all switches to transmitters could cost a plant up to $1.5 million. Consequently, switch manufacturers researched and developed new electronic switches that are capable of producing both digital and analog signals required by these new modernization projects, while keeping a similar price point to the original mechanical switches installed.

This dramatic savings allows plants to reduce the overall modernization project costs by upgrading the 2nd most likely component (sensor) to fail in a tradional safety system, without upgrading the rest of the safety system and reducing the down me needed to complete the project during a short shut- down turn- around project.

7. The Speed of Response of Transmitters is Faster than Switches

Without question, electromechanical switches are faster than any pressure transmitter on the market. With transmitters, huge amounts of conversions, computations, compensation, and other work must be done to get an accurate signal. Even using today’s high-speed processors, they cannot match the speed of the instantaneous reaction of a mechanical device. The fastest of these devices can be be er than 5 milliseconds while process transmitters can range from 300-500 milliseconds or more. Purpose built transmitters for safety applications designed for speed of response in lieu of accuracy (not needed in safety applications) can be as fast as 250 milliseconds. New solid state transmitter-switches can react in 100 milliseconds or less in the switch mode. If your application requires fast response such as in positive displacement (PD) pumps and turbine trip for over-speed protection, consider new solid-state transmitter-switches over process transmitters.

Recommendations

United Electric Controls has recognized the challenges faced by users and developed new products to match their growing needs. In an effort to reduce plant project costs and help OEMs design and build affordable and reliable equipment for the industrial sector, we have developed a new line of electronic switches that provide drop-in replacement of old mechanical switches. These new switches reduce the costs of plant modernizations. Built-in digital and analog communication provides users the op on of control- ling a piece of equipment locally or sending information back to a central control system for process trending and health, or both.

About this white paper:

UE ViewPoint white papers provide Executive, Business and Technical Briefs written by product, application and industry subject matter experts employed by United Electric Controls.  For more UE ViewPoint papers, visit this link.

Introduction to a Closed Loop Control System

Closed Loop Control System

The video below explains the concept of a closed loop control system, using a steam heat exchanger and food processing application as an example.

A closed loop control system uses a sensor that feeds current system information back to a controller. That information is then compared to a reference point or desired state. Finally, a a corrective signal is sent to a control element that attempts to make the system achieve its desired state.

A very basic example of a temperature control loop includes a tank filled with product (the process variable), a thermocouple (the sensor), a thermostat (the controller), and a steam control valve feeding a tubing bundle (the final control element).

The video outlines all the major parts of the system, including the measured variable, the set point, the controlled variable, controller, error and disturbance.

Contact http://www.ivesequipment.com with any process control or instrumentation requirement. Call 877-768-1600 for immediate assistance.