BASICS OF TRIPS, INTERLOCKS, PERMISSIVES & SEQUENCESThis post provides information about basics of Trip, Interlock, Permissive and Sequences which are regularly used in instrumentation control systems like ESD, DCS, PLC etc.Trip:The term Trip refers to an action that is initiated by the control system and which forces a device or devices to a pre-determined state.Example of Trip Signals: Close Valve, Open Valve, Stop motor, etc.The Safety Instrument System (SIS) or a Hardwired systems normally initiate trips, however the PLCs or DCS may also initiate trips provided the necessary independence and SIL ratings are met.Once a device or devices have been forced to a pre-determined state by the action of a Trip they will remain in that state until the Trip is manually reset by a conscious operator action.For example:High level in a vessel initiates a trip system which stops the pump feeding that vessel, the pump will remain stopped even if the level in the vessel falls to a safe level.The Trip must be ‘reset’ by the operator before the pump can be re-started.The Trip can only be ‘reset’ if the level in the tank has fallen to a safe level.Resetting the Trip will not cause the pump to automatically re-start, however it may be re-started by an operator action or a control system command e.g. part of a sequence.

The resetting of Trips is a controlled procedure which will only be possible if the operator is logged in and has the necessary access rights.Under normal circumstances it shall not be possible to ‘override’ or `defeat’ Trips.Interlock:An Interlock is in essence a ‘self resetting’ Trip. Interlocks are not deemed safety related and can be used for on/off control.Interlocks are normally initiated by the DCS or PLCs, however if an Interlock is deemed to be safety related it may, depending upon SIL rating, be implemented in the SIS or a Hardwired system.An interlock will force a device or devices to a pre-determined state e.g. Close valve, stop motor, etc.Once a device or devices have been forced to a pre-determined state by the action of an Interlock they will remain in that state until the initiating cause returns to a ‘healthy’ condition, the Interlock will then be automatically removed.Under normal circumstances it shall be possible to ‘override’ Interlocks for operational reasons or ‘defeat’ them for maintenance or other reasons.Permissive:A Permissive is a patricular type of Interlock used to prevent actions taking place until pre-defined criteria have been satisfied, for example prevents a pump starting until the suction valve is open.Permissives are normally initiated by the DCS or PLCs, however if a Permissive is deemed to be safety related it may, depending upon SIL rating, be implemented in the SIS or a Hardwired system.

Once a Permissive has been satisfied and the resulting action implemented it becomes inactive, for example once the suction valve has been opened and the pump started the Permissive takes no further action, even if the suction valve is closed while the pump is running.Under normal circumstances it shall be possible to ‘override’ Permissives for operational reasons or ‘defeat’ them for maintenance or other reasons.Sequence:A Sequence is defined as a pre arranged action or number of actions which are carried out by the control system. Sequences may be initiated by an event or operator actions.Sequences may be ‘single pass’ or ‘cyclic’.The following is an example of a ‘single pass’ sequence:An agitated vessel reaches a pre-determined level. The operator initiates a sequence that carries out the following actions:Stop the feed pumpClose the filling valveStop the agitator.Wait 30 seconds.Open the discharge valve.The following is an example of a ‘cyclic’ sequence:Low level in a vessel opens the filling valve.The valve remains open until high level is detected.On high level the valve closes.The valve remains closed until low level is detected.

On low level the valve opens and the sequence it repeated.Combined Functions:It is common for Trip, Interlock, Permissive and Sequences to fulfill combined functions, for example the following pump protection system illustrates how the same system can perform various functions.Permissive Prevent pump starting until suction valve is open.Interlock Pump running – suction valve closed-pump stops.Sequence High level in vessel-Pump stops Low level in vessel-Pump starts. Pump running – suction valve closed – pump stops, Suction valve re-opened – pump remains stopped. Operator resets trip. Pump available for re-start.

Overview of Safety Integrity Level

SAFETY INTEGRITY LEVELSafety Integrity Level (SIL) is a measure of safety system performance – not a measure of process risk. The higher the level of risk, the greater the system performance required. Based on a hazard and risk analysis, each individual Safety Instrumented Function (SIF) is assigned a required performance level, or SIL.

Safety Instrumented Systems may have different SILs for each of its individual SIFs.HOW TO CALCULATE INTEGRITY LEVEL

Industrial plants require a multidiscipline team to evaluate and assign SIL performance levels for SIFs, not a specific person. Common departments assigned to the team are process, mechanical design, safety, operations and control systems. Quantitative or qualitative analysis is used to calculate the SIL of each SIF:

1. ALARP, Risk Matrix and Risk Graphs

ALARP (As Low As Reasonably Practicable), Risk Matrixes and Risk Graphs are qualitative methods of determining SIL. Qualitative data is faster and easier, but is also subjective and many engineers are not comfortable using this data to assign performance levels. Systems analyzed using qualitative data are often built too conservatively, adding unnecessary costs.

2.LOPA (Layer of Protection Analysis)

LOPA is a quantitative method that identifies and analyzes the effects of independent layers of protection (IPL) – devices, systems or actions capable of preventing a hazardous event. LOPA are extremely detailed and require members of an organization to agree on risk tolerance levels. Quantitative

analysis typically delivers lower levels of required performance, reducing safety system costs.

Once SILs are assigned using quantitative or qualitative analysis and independent protection layers considered, a Safety Requirement Specifications (SRS) is written to describe the functional and integrity requirements of the system. Functional requirements describe the system inputs, outputs and logic. Integrity requirements describe the performance needed for each function. Incomplete or incorrect specifications cause 44% of accidents in safety applications, stressing the importance of fully understanding the functional and integrity requirements of the system.

Device failure rates – dangerous detected (DD), dangerous undetected (DU), safe detected (SD) and safe undetected (SU) – are required to calculate SIL. Failures In Time (FITs) is the data owner/operators require to calculate of Probability of Failure on Demand (PFD), Safe Failure Fraction (SFF), Risk Reduction Factor (RRF), Safety Availability (SA) and Mean Time to Failure (MTTF). This FIT data makes calculating target SIL levels rather easy for simplex systems.

To really understand a SIL rating you need to know what the Probability of Failure on Demand (PFD) is. The PFD is a likelihood that a loop will fail when a demand is placed on it. The PFD of a SIF is calculated using the number of potential dangerous undetected failures and the test interval of the loop.

Safety instrumented systems are used to implement SIFs as layers of protection to reduce process hazards. Its an automated way to take an action against a potentially unsafe condition and return a process to a safe or stable state.

Some major differences between a SIS PLC and BPCS hardware are;a Standard BPCS has unknown failure modesa SIS PLC will fail safely within a specified probability (SIL)a SIS PLC is certified to standards like IEC61508 for use in a safety applicationSafety PLC must be configured by person with appropriate competency in both safety and the development platform.

Also Read: Safety Instrumented Systems Interview Questions

A single SIS PLC can have any number of safety instrumented functions being controlled within it depending on how many unsafe conditions can exist in a facility, or area of a facility. Most safety loops are designed to be configured as a de-energize to

trip system, where the SIS PLC must remove power to trip the loop.

Sensing elements that are typically connected to a SIS are Pressure Transmitters, Level Transmitters, Temperature Transmitters, Flame Detectors, Smoke Detectors, Toxic Gas Detectors, Emergency Shut Down (ESD) switches, and any number of input devices.

Final elements are typically Solenoid Operated Valves (SOV), Beacons, Horns, Exhaust Fans, and Doors to name a few.

One thing to always keep in mind is that a SIS is not just a controller for a system. A SIS includes all transmitters and final elements, as well as associated solenoids, exhaust valves, and loop splitters. Any component where its failure could cause a potential failure on the loop is a component that is included in the SIS.

Dangerous failures occur when a component is unavailable when a demand is required. Device diagnostics greatly reduces the chance of dangerous failures. Safe failures, also known as nuisance /spurious trips, often lead to unplanned shutdowns. Sensor voting logic is commonly used to avoid nuisance trips and improve system performance.

IMPORTANCE OF INDEPENDENT SYSTEMS

Safety Instrumented Systems are required in the process industry because BPCSs are not perfect. Many industrial standards and guidelines recommend that the SISs be separate from the BPCS. “A device used to perform part of a safety instrumented function shall not be used for basic process control purposes, where a failure of that device results in a failure of the basic process control function which causes a demand on the safety instrumented function, unless an analysis has been carried out to confirm that the overall risk is acceptable.” – ANSI/ISA 84.00.01-2004 11.2.10.

Human issues are the most common reason why SISs and BPCSs are independent. People cannot be trusted to make safe decisions during emergencies, no matter how well trained. A study analyzing human performance in life threatening situations discovered that people make the wrong choice 99% of the time when required to do so in less than one minute, emphasizing the importance of an automated SIS to protect against hazardous events.

If components are allowed to be shared between SIS and BPCS, specifications may be overlooked leading to serious consequences. Separating the SIS from the BPCS assures that Safety Requirement Specifications (SRS) are reviewed before changes are made, and all new potential hazards caused by the proposed change will be identified before the change can be implemented. Consideration should be given to using devices that are differentiated by color, unique tags or a numbering system to help differentiate from BPCS devices.

SIS vs. BPCS

Safety instrumented Systems are passive and dormant, monitoring and maintaining the safety of the process. These systems operate for long periods of time in which they simply wait to respond to a system demand. Diagnostics are critical in SISs to ensure that components are functioning properly, reducing the frequency of manual tests. Changes after installation are subject to strict adherence to management of change (MOC). Even the smallest change can have a significant consequence.

Basic Process Control Systems (BPCS) are active and dynamic, controlling the process. These systems have a variety of digital and analog inputs and outputs that react to logic functions, making most failures self-revealing. Changes to BPCSs are very common and required to maintain accurate process control.

COMMON CAUSE FAILURES

Separating the SIS from the BPCS greatly reduces the risk of common cause failures, systematic failures that affect the entire system. Common cause failures can include loss of power, bugs in software or undetected device failures. Assumptions are made that installing redundant components will lead to a safer and more reliable system, but more is not always best. Typically, more components lead to more complexity in the system, leading to more problems. Common cause failures are often triggered by temperature fluctuations, equipment vibration, radio frequency

interference or power surges. The greater the performance level required of a SIF, the more aware you must be to common cause failures.

The ideal way to prevent common cause failures is to install redundant devices with diverse technologies and physically separate the devices. For example, if you install a safety differential pressure transmitter to monitor a level application, you should also consider installing a gauge pressure mechanical switch in the event you lose power to the transmitter.

Recommended methods to reduce these failures are:use of redundant devicesinstall devices with diagnosticschoose diverse technologiesphysically separate devices

WHICH TECHNOLOGY TO CHOOSE

CERTIFIED vs. PROVEN-IN-USE

A common question asked by many owner/operators is whether they should use certified or proven-in-use devices in their SISs. ANSI/ISA 84.00.01-2004 in no way mandates the use of certified components in a SIS. Some manufactures provide “proven-in-use” or “SIL suitable” components that are not certified to IEC 61508. Manufacturers that supply proven-in-use components are

required to provide quality programs, demonstrate acceptable performance levels in similar environments and prove a volume of experience..

The primary advantage of using certified devices is the ease of access to failure rate data (FITs) collected by an independent third party. If considering a “proven-in-use” or “SIL suitable” device, vendor’s field return data is often used to provide failure rate data, but this data does not accurately represent total device failures and is not independently analyzed. Data collected by a certified, independent third party allows owner/operators the ability to quickly calculate required performance level (SIL) of their SIFs with reliable and tested data.

Owner/operators can elect to install non-certified components, referred to as “proven-in-use” or “SIL suitable” in their SISs. This information is often available in facility maintenance records, vendor field return data and third-party databases. Non-certified component failure rate data is often inaccurate. Manufacturers use field return data to calculate product failure rates, but this data is dependent on customer returns. Further, facility maintenance records are not always up to date with device failure information unless an automated Maintenance Software Management System is installed. Use caution when considering devices that do not have independent third-party failure rate data.

TRANSMITTER vs. SWITCH

You should consider installing both transmitters and switches in SISs. Transmitters are usually the first componentconsidered in SISs due to the increased diagnostics, field indication, lower failure rates, and improved accuracy and repeatability. But thought should be given to include redundant and diverse technologies to avoid common cause failures in a system. Transmitters require power to operator and only provide control through a PLC or DCS.

What happens if you lose power? What happens if the PLC or DCS fail? What happens if the transmitter electronics fails? In this case, a mechanical switch will continue to operate and protect in the event a hazardous situation develops. By installing redundant devices, risk is reduced by avoiding common cause failures.

NUISANCE TRIPS

Nuisance trips are referred to as safe failures in SISs. Mean time to failure (MTTFspurious) is the term used in SIS calculations to determine when a device will suffer a safe failure. Safe failures occur when a device fails in a way in which the owner/operator is aware of the failure, typically an alarm or warning via the PLC or DCS. Safe failures are a nuisance to owner/operators and have economic consequences of lost production and downtime.

After a shutdown, it is required that manual action be taken by the owner/operator to reset the system – it is not allowed to be restarted automatically. The best way to avoid these nuisance trips is through sensor channel voting in a PLC or DCS. Voting

logic compares device channels and determines the action required.

It is important to understand the difference between safe and fault-tolerant. 1oo1 is very safe but is not fault-tolerant, meaning any measurement outside a sensor’s programmed range will cause a shutdown. 2oo2 is very fault-tolerant but is not as safe as 1oo1 because it requires two channels to agree before a shutdown occurs. 2oo3 is a suitable trade-off of both dual modes. 1oo2D is the preferred configuration to reduce nuisance trips and improve safety.

COMMUNICATION & DIAGNOSTICSComponent signals are commonly sent and received through a PLC or DCS. ANSI/ISA 84.00.01-2004 recommends that field devices be write-protected in the PLC or DCS to avoid the risk of making changes to a device outside the Safety Requirement Specification. Bi-lateral communication, such as HART or Foundation Fieldbus, is important in BPCS devices but is not useful in SIS. In fact, increasing cyber security threats highlights the importance of requiring devices be write-protected in the event device safety variables are manipulated during an attack. When installing SIS sensors, bi-lateral communication is not necessary and only adds additional and unnecessary cost.Device diagnostics continue to improve and provide owner/operators the health status of devices in their SISs. This information reduces the dangerous failure rates of the device by identifying when and how a device fails. Owner/operators can

then quickly replace the faulty device to ensure their process is being properly protected.

Interview Questions and Answers on Safety Systems1Q & A, Safety SystemsJanuary 14, 2016 A+A-EmailPrint

What are the standards that define the best rules for installation of field equipment of a SIF/SIS, on site?

IEC 61511 or ISA-S84-2003 (which is really the same thing, plus a grandfather clause) are intended for application in the process industry. They do the best job of defining what one needs to be concerned with for field instruments. The guidance may be considered somewhat minimal but the critical safety issues are there. Whatever would make a good installation for the basic process control system (BPCS) is a good installation for the SIS also. However, some different issues need to be recognized. First, the instruments need to be reliable. One measurement, referred to as “proven in use” means reliability data must be available for safety integrity level (SIL) calculations. If not then SIL-rated

instruments are an option. Next one must consider fault tolerance requirements for the Safety Instrumented Function (SIF). This is a function of the SIL level for each SIF in the SIS. There will of course always be the need to make sure the instruments are calibrated routinely and tested per the proof test requirement. If this is online then the engineer needs to make sure that those facilities plus the ability to do maintenance is designed into the project. Typically sensors need their own root valve and final control elements may need bypasses or means for partial stroke testing.

The routing of the individual cables of transmitter that is in a 2oo3 voting system–the same route, different routes?

Some reliability engineers would want to try to convince you that a different route is required. While everyone would like a diverse routing from a common mode point of view, (a fire, dropped crane load, chemical spill could destroy all the cables in the same tray, etc.) it is many times impractical to route differently. One deciding factor is availability. If high availability is require diverse routine is a good idea, but again not mandatory. Some companies may have internal standards on this subject. The other factor is whether or not the SIS fails safe. If a loss of a cable, causes the System to have a spurious safe trip the system is safe, but you have to deal with the cost of the spurious trip. If the SIF is energized-to-trip, one needs to look at separate routing. Also, end of line monitoring etc.

Can I install the three field devices in battery or in different places to avoid, common failure, e.g., vibration, risk of fire?

Field instruments are designed for the outdoor industrial environment. Utilize them correctly for their application. If it is a bad installation for the BPCS it is bad for the SIS also. While many SIS logic solvers have been industrially hardened to operate in a broad range of environmental conditions with numerous successful applications, it just stands to reason that putting them in environmentally controlled areas will improve potential reliability plus the ability to do maintenance.

Yes one must always be careful with respect to common mode. Common mode can wiped out the reliability gains of redundancy. That is why it is required to do SIL Calculations to verify that the common mode effect is not so strong that it renders the SIF ineffective.

Must I use the normal practices of engineering or do rules or recommendation exist for the installation of field equipment for the SIF/SIS?

One has to ask whose normal practices?? If we mean industry best normal practices the answer is yes again but one needs to follow the entire IEC-61511 Life Cycle to determine what that really means for each project. What is an acceptable solution for one plant may not work for another. The questions you ask really points out that to safely design a plant, the project needs to execute the IEC61511 Safety Life Cycle. Hazards are identified early in the project and solutions are designed around those hazards. The questions you asked should all be covered in the Safety Requirements Specification (SRS). There are 27 questions that cover the topics you have asked and more, much more. Inexperienced engineers may not be aware of this list of

questions that define an IEC61511 SRS. This is why you should work with experienced organizations. A study done by the Health and Safety Executive in the UK has shown that the majority of problems with SIS systems today are actually specified into the project. (Or shall we say not specified into the project, one does not know what one does not know.) Failure to execute the life cycle activities early and properly can have serious safety, schedule and cost implications on a project.

Installation Guidelines:

Sensor-To reduce common mode each sensor should have a separate process connection. There have been some good arguments made with regards to using different technologies in order to reduce common mode but one must look at practicality vs. benefits and risk reduction. Also, although the use of diverse technologies can reduce common cause it will not eliminate it completely.

Transmitters-For sensors integrated (or separate) with the transmitter, the geographical locations of the voted transmitters should be away from each other to the extent possible (so that in the event of a fire–all transmitters are not affected–as an example!)

Junction Boxes-Separate JBs for each transmitter / 2 core cable is preferred.

Multicore Cables-If separate JBs not possible, run each transmitter pair in separate multicore cables to the control room.

Cable Trays-Run the multicore cables in separate trays which have separate routes to the control room when practical. Availability would be the determining factor.

Safety Logic Solver-Each transmitter signal could be connected to separate SLS, on separate carriers. This would slightly compromise on the PFD value however and could also make the SIF configuration more complicated, but reduces common cause. SLS installed in two different cabinets in different control rooms would be even better! However common sense needs to be used and practicality. Same logic could be used for the output signals.

The extent to which one would go in segregating will depend on ALARP – As low as reasonably practicable (here ‘low’ refers to the risks involved). The Risk Reduction Factor (RRF) of the SIF and how much of the risk is the engineer / company ready to absorb, will dictate the decision. The common cause calculator (based on such segregation) is given in IEC 61508-6, Table D.5.

When is a Safety Integrity Level Rating of a Valve Required?

Basic Process Control System (BPCS) A system which responds to input signals from the process, its associated equipment, other programmable systems and/or an operator and generates output signals causing the process and its

associated equipment to operate in the desired manner but which does not perform any safety instrumented functions with a claimed SIL = 1.

This definition leads us to conclude that a BPCS is any system that has a SIL<1. Therefore, SIS systems employing Safety Instrumented Functions with a specified safety integrity level, which is necessary to achieve safety function, need to have a SIL rating equal to or above 1.

Based on this definition,Why are control valves that are used in a BPCS required to be SIL certified? As per IEC definition, a SIL rating is not required but it is possible that reliability data for a valve may be required. Industry or end user may require failure rate data of equipment or in loose term MTBF (Mean Time Between Failure).Essentially MTTF (mean time to fail) is the right term to define product reliability. It is usually furnished in units of hours. This is more common for electronic components, but trends are seen even for mechanical items.How can MTTF provide useful data for the calculation of PFDavg (probability of failure upon demand)? MTTF can be simplified to 1/(sum of all failure rates) or equal to 1/λ… MTTFs calculations provide plant availability, which is a very important measurement of process plant up-time capability. A spurious trip that is considered a safe but unplanned trip may be too strenuous for piping and other equipment. Not only are production and quality affected, profits may be as well. Also, it is

important to consider the higher risk associated with plant start up. IEC 61508 stresses more on “safety event”, in case of demands, which relates to dangerous undetected failures and are used to compute PFDavg.As such, mechanical equipment like valve bodies and actuators do not have any diagnostics capabilities. According to IEC 61508 part 2, table 2, with a hardware fault tolerance (HFT) of zero, with a single valve without additional diagnostics, only SIL 1 is achievable per IEC 61508. A digital valve controller mounted on a “Final Control Element” improves the diagnostic coverage factor, which in turn improves the SFF number, allowing the possible use of higher SIL rated applications (Per IEC 61508 part 2, table 3) by use of the Partial Stroke Test.If control valve is designated to carry out a safety function then it should meet the SIL level of the Safety Instrumented Function loop. In this case, failure rate numbers will be required to compute the total PFDavg of the loop. The end user may possibly ask for third party certification to comply with IEC 61508 requirements to meet certain SIL suitability.

What is SIL?

A Safety Integrity Level (SIL) is a measure of safety for a given protective function. Specifically, the extent to which the end user can expect the protective function to perform, and in the case of a failure, fail in a safe manner? This protective function is known as the Safety Instrumented Function (SIF). A Safety Instrumented System (SIS) is a collection of components (field devices and logic server) that execute one or more SIFs. In order to define the required SIL value, the SIF’s must be well defined and have undergone a Safety Analysis. Note that the SIL belongs to a specific SIF, not the whole SIS.

SIF verification can be optimized by the selection of components certified for use at the desired SIL value. For example, assume there is a SIF with a desired SIL value of 2. By using components that are SIL 2 certified, this goal may be achieved. However, it is important to note that simply combining components certified for a given SIL level does not guarantee the process will achieve the specified SIL. The SIF SIL value must still be verified by an appropriate method such as Simplified Calculations, Fault Tree Analysis, or Markov Analysis.

How is SIL different than reliability?

While the main focus of the SIL number is the determination of process safety, an important byproduct of the statistics used in calculating SIL ratings is the statement of a product’s reliability. In order to determine if a product can be used in a given SIF, the product must be shown to “BE AVAILABLE” to perform its designated task. In other words, how likely is it that the device in question will be up and functioning when needed to perform its assigned task? Considerations taken into account when determining “AVAILABILITY” include: Mean Time Between Failures (MTBF), Mean Time To Repair (MTTR), and Probability to Fail on Demand (PFD). These considerations, along with variations based upon system architecture (i.e. 2oo2 versus 2oo3, or TMR installation), determine the reliability of the product. Subsequently, this reliability data, combined with statistical measurements of the likelihood of the product to fail in a safe manner, known as Safe Failure Fraction (SFF), determine the maximum SIL environment in which the device(s) can be used.

SIL ratings can be equated to the Probability to Fail on Demand (PFD) of the device in question. The reciprocal of the PFD is known as the Risk Reduction Factor (RRF).

When does a Fire & Gas system become a SIS?

When an RRF greater than 10 is required

How does SIL relate to individual components?

It should be noted that a SIL number applies to a complete function (SIF), i.e. the field sensor, the logic solver and the final element. It is therefore incorrect to refer to any individual item or equipment having a safety integrity level. An individual component can be certified for use in a particular SIL application, but such a certificate constitutes only part of the verification effort, since the target SIL must be verified for the complete SIF.

Why would a customer want SIL certified products? Products certified in accordance with the requirements of IEC 61508 have been assessed by a third party (TÜV) for use up to a specified SIL. This assessment includes not only the FMEDA, but also software.A third-party SIL certified product offers several benefits to the customer. The most obvious benefit is the product has already had its’ reliability calculations performed and reliability statistics determined. The results are available for the SIS designer to derive the SIF SIL number. This can significantly cut lead times in

the implementation of a SIS. Another benefit is the reliability statistics have been validated by a third party with expertise in SIL certification and reliability engineering. Probably the most important benefit to using a SIL certified product is the certification report. Each certified product carries with it a report from the certifying body. This report contains important information ranging from restrictions of use, to diagnostics coverage within the certified device, to reliability statistics. Additionally, ongoing testing requirements of the device are clearly outlined.

Importance of Safety Integrity Level0Safety SystemsOctober 12, 2015 A+A-EmailPrint

The global importance of SIL (Safety Integrity Levels) has grown substantially in the oil/gas, petrochemical and other process industries over the last 10 years. However, for many end users, systems integrators, and product vendors, SIL is still a somewhat ambiguous concept that often is misinterpreted and incorrectly implemented. In order to fully understand SIL and its implications, it is important to grasp the overarching concept known as

Functional Safety, and how it applies to Safety Instrumented Systems (SIS) within the process industries

Functional Safety and SIS Background

Functional Safety, as defined by IEC standard 61508, is the safety that control systems provide to an overall process or plant. The concept of Functional Safety was developed in response to the growing need for improved confidence in safety systems. Major accidents around the world, as well as the increasing use of electrical, electronic or programmable electronic systems to carry out safety functions, have raised awareness and the desire to design safety systems in such a way as to prevent dangerous failures or to control them when they arise. Industry experts began to address functional safety and formalize an approach for reducing risk in the process plant environment through the development of standards IEC 61508, IEC 61511, and ANSI/ISA 84.

Previous safety standards were generally prescriptive in nature, not performance based. An emphasis on quantitative risk reduction, life-cycle considerations, and general practices make these standards different from their predecessors. Functional Safety is a term used to describe the safety system that is dependent on the correct functioning of the logic solver, sensors, and final elements to achieve a desired risk reduction level. Functional Safety is achieved when every safety function is successfully carried out and the process risk is reduced to the desired level.

A Safety Instrumented System is designed to prevent or mitigate hazardous events by taking a process to a safe state when predetermined conditions are violated. Other common terms for SISs are safety interlock systems, emergency shutdown systems (ESD), and safety shutdown systems (SSD). Each SIS has one or more Safety Instrumented Functions (SIF). To perform its function, a SIF loop has a combination of logic solver(s), sensor(s), and final element(s). Every SIF within a SIS will have a SIL level. These SIL levels may be the same, or may differ, depending on the process. It is a common misconception that an entire system must have the same SIL level for each safety function.

Safety Integrity Level

SIL stands for Safety Integrity Level. A SIL is a measure of safety system performance, in terms of probability of failure on demand (PFD). This convention was chosen based on the numbers: it is easier to express the probability of failure rather than that of proper performance (e.g., 1 in 100,000 vs. 99,999 in 100,000). There are four discrete integrity levels associated with SIL: SIL 1, SIL 2, SIL 3, and SIL 4. The higher the SIL level, the higher the associated safety level, and the lower probability that a system will fail to perform properly.

As the SIL level increases, typically the installation and maintenance costs and complexity of the system also increase. Specifically for the process industries, SIL 4 systems are so complex and costly that they are not economically beneficial to implement. Additionally, if a process includes so much risk that a SIL 4 system is required to bring it to a safe state, then there is a fundamental problem in the process design that needs to be

addressed by a process change or other non-instrumented method.

It is a very common misconception that individual products or components have SIL ratings. Rather, products and components are suitable for use within a given SIL environment, but are not individually SIL rated. SIL levels apply to safety functions and safety systems (SIFs and SISs). The logic solvers, sensors, and final elements are only suitable for use in specific SIL environments, and only the end user can ensure that the safety system is implemented correctly. The equipment or system must be used in the manner in which it was intended in order to successfully obtain the desired risk reduction level. Just buying SIL 2 or SIL 3 suitable components does not ensure a SIL 2 or SIL 3 system.

Risk Management and Selecting a SIS or SIL Level

The identification of risk tolerance is subjective and site-specific. The owner / operator must determine the acceptable level of risk to personnel and capital assets based on company philosophy, insurance requirements, budgets, and a variety of other factors. A risk level that one owner determines is tolerable may be unacceptable to another owner.

When determining whether a SIL 1, SIL 2, or SIL 3 system is needed, the first step is to conduct a Process Hazard Analysis to determine the functional safety need and identify the tolerable risk level. After all of the risk reduction and mitigation impacts from the Basic Process Control System (BPCS) and other layers of

protection are taken into account, a user must compare the residual risk against their risk tolerance. If there is still an unacceptably high level of risk, a risk reduction factor (RRF) is determined and a SIS / SIL requirement is calculated. The RRF is the inverse of the Probability of Failure on Demand for the SIF / SIS. The SIL level equals the number of zeros in the minimum Risk Reduction Factor. With SIL 2, for example, the minimum Risk Reduction Factor is 100 (see table below).

Selecting the appropriate SIL level must be done carefully. Costs increase considerably to achieve higher SIS / SIL levels. Typically in the process industry, companies accept SIS designs up to SIL 2. If a Process Hazard Analysis indicates a requirement for a SIL 3 SIS, owners will usually require the engineering company to re-design the process to lower the intrinsic process risk.

Example of SIS/SIF/SIL Determination

A simple example will help illustrate the concepts of SIS, SIF, and SIL. Consider the installation of a pressure vessel containing flammable liquid. It is maintained at a design operating pressure by the BPCS. If the process control system fails, the vessel will be subjected to an over-pressure condition that could result in a vessel failure, release of the flammable contents and even fire or explosion. If the risk in this scenario is deemed to be intolerable by the facility owner, a SIS will be implemented to further reduce this risk situation to a tolerable risk level.

The SIS system will be independent from the BPCS and will act to prevent or mitigate the hazardous condition resulting from pressure vessel over-pressure. The SIS will have a SIF which might include a pressure transmitter which can sense when an intolerable level of pressure has been reached, a logic solver to control the system logic, and a solenoid valve which might vent the contents of the vessel into a safe location (flare stack, environment, storage tank, etc.), thus bringing the pressure vessel to a safe state.If the risk reduction factor required from the Process Hazard Analysis is a factor of 100 then a SIL 2 level of SIF performance would be specified. Calculations for the components of the entire SIF loop will be done to verify that the PFD of the safety function is 10-2, meaning that the SIF is SIL 2 or reduces the risk of the hazard by a factor of 100. This one SIF may constitute the entire SIS, or the SIS may be composed of multiple SIF’s that are implemented for several other unacceptable process risks in the facility.

Safety Instrumented System Interview Questions & Answers2Q & A, Safety SystemsJanuary 27, 2016 A+A-EmailPrint

1. What is a SIS? A SIS is a Safety Instrumented System. It is designed to prevent or mitigate hazardous events by taking the process to a safe state when predetermined conditions are violated. A SIS is composed of a combination of logic solver(s), sensor(s), and final element(s). Other common terms for SISs are safety interlock systems, emergency shutdown systems (ESD), and safety shutdown systems (SSD). A SIS can be one or more Safety Instrumented Functions (SIF).

2. What is a SIF? SIF stands for Safety Instrumented Function. A SIF is designed to prevent or mitigate a hazardous event by taking a process to a tolerable risk level. A SIF is composed of a combination of logic solver(s), sensor(s), and final element(s). A SIF has an assigned SIL level depending on the amount of risk that needs to be reduced. One or more SIFs comprise a SIS.

3. What is SIL? SIL stands for Safety Integrity Level. A SIL is a measure of safety system performance, or probability of failure on demand (PFD) for a SIF or SIS. There are four discrete integrity levels associated with SIL. The higher the SIL level, the lower the probability of failure on demand for the safety system and the better the system performance. It is important to also note that as the SIL level increases, typically the cost and complexity of the system also increase.

A SIL level applies to an entire system. Individual products or components do not have SIL ratings. SIL levels are used when implementing a SIF that must reduce an existing intolerable process risk level to a tolerable risk range.

4. What does functional safety mean? Functional safety is a term used to describe the safety system that is dependent on the correct functioning of the logic solver, sensors, and final elements to achieve the desired risk reduction level. Functional safety is achieved when every SIF is successfully carried out and the process risk is reduced to the desired level.

5. Why were the ANSI/ISA 84, IEC 61508, and IEC 61511 standards developed? The standards were a natural evolution for the need to reduce process risk and improve safety through a more formalized and quantifiable methodology. Additionally, and specifically for IEC 61508, as the application and usage of software has evolved and proliferated, there was an increased need to develop a standard to guide system / product designers and developers in what they needed to do to ensure and “claim” that their systems / products were acceptably safe for their intended uses.

6. When do I need a SIF or a SIS? The philosophy of the standards suggests that a SIS or SIF should be implemented only if there is no other non-instrumented way of adequately eliminating or mitigating process risk. Specifically, the ANSI/ISA-84.00.01-2004 (IEC 61511 Mod) recommends a multi-disciplined team approach that follows the Safety Lifecycle,

conducts a process hazard analysis, designs a variety of layers of protection (i.e., LOPA), and finally implements a SIS when a hazardous event cannot be prevented or mitigated with something other than instrumentation.

7. What is a proof-test interval? Proof testing is a requirement of safety instrumented systems to ensure that everything is working and performing as expected. Testing must include the verification of the entire system, logic solver, sensors, and final elements. The interval is the period of time that the testing occurs. The testing frequency varies for each SIS and is dependent on the technology, system architecture, and target SIL level. The proof-test interval is an important component of the probability of failure on demand calculation for the system.

8. What is a Process Hazard Analysis (PHA) and who conducts this? A PHA is an OSHA directive that identifies safety problems and risks within a process, develops corrective actions to respond to safety issues, and preplans alternative emergency actions if safety systems fail. The PHA must be conducted by a diverse team that has specific expertise in the process being analyzed. There are many consulting and engineering firms that also provide PHA services. PHA methodologies can include a What-If Analysis, Hazard and Operability Study (HAZOP), Failure Mode and Effects Analysis (FEMA), and a Fault Tree Analysis.

9. What voting configurations are required for each SIL level?

Obtaining a desired SIL level is dependent on a multitude of factors. The type of technology employed, the number of system components, the probability of failure on demand (PFD) numbers for each component, the system architecture (e.g., redundancy, voting), and the proof testing intervals all play a significant role in the determination of a SIL level. There is not a standard answer for what voting configurations are required for each SIL level. The voting architecture must be analyzed in the context of all the factors noted above.

10. Will a SIL rated system require increased maintenance? SIL solutions are certainly not always the most cost-effective solutions for decreasing process risk. Many times, implementing a SIL solution will require increased equipment, which inevitably will require increased maintenance. Additionally, it is likely that the higher the SIL level, the more frequent the proof testing interval will be, which may ultimately increase the amount of system maintenance that is required. This is why the standards recommend a SIL based solution only when process risk cannot be reduced by other methods, as determined by LOPA.

11. Can a F&G system be a SIF or SIS? A Fire and Gas (F&G) system that automatically initiates process actions to prevent or mitigate a hazardous event and subsequently takes the process to a safe state can be considered a Safety Instrumented Function / Safety Instrumented System.

However, it is absolutely critical in a F&G system to ensure optimal sensor placement. If there is incorrect placement of the

gas / flame detectors and hazardous gases and flames are not adequately detected, then the SIF / SIS will not be effective.

Correct sensor placement is more important than deciding whether a F&G SIF / SIS should be SIL 2 or SIL 3.

12. What is SIL 4? SIL 4 is the highest level of risk reduction that can be obtained through a Safety Instrumented System. However, in the process industry this is not a realistic level and currently there are few, if any, products / systems that support this safety integrity level.

SIL 4 systems are typically so complex and costly that they are not economically beneficial to implement. Additionally, if a process includes so much risk that a SIL 4 system is required to bring it to a safe state, then fundamentally there is a problem in the process design which needs to be addressed by a process change or other non-instrumented method.

13. Can an individual product be SIL rated? No. Individual products are only suitable for use in a SIL environment. A SIL level applies to a Safety Instrumented Function / Safety Instrumented System.

14. What type of communication buses or protocols are applicable for SIL 2 or SIL 3 systems?

The type of communication protocol that is suitable for a SIL 2 or SIL 3 system is really dependent on the type of platform that is being used. Options include, but are not limited to: 4-20 mA output signal, ControlNet (Allen Bradley), DeviceNet Safety (Allen Bradley), SafetyNet (MTL), and PROFIsafe. Currently, the ISA SP84 committee is working on developing guidelines for a safety bus, to make sure that the foundations comply with IEC 61508, and IEC 61511 standards. The first devices with a safety bus should be available by 2008. The Fieldbus Foundation is actively involved in the committee and working on establishing Foundation Fieldbus Safety Instrumented Systems (FFSIS) project to work with vendors and end users to develop safety bus specifications.

15. For General Monitors, how can I access the PFD and MTBF data for the products? The General Monitors SIL certificates have the PFD, SFF, and SIL numbers that correspond to each product. MTBF data can be provided by request.

16. Can a manufacturer state their products are “SIL X certified” rather than “suitable for use in a SIL X system”? Individual products are only suitable for use in a SIL environment. A SIL level applies to a Safety Instrumented Function / Safety Instrumented System.

Product certificates are issued either by the manufacturer (self-certification), or other independent agency to show that the appropriate process is followed, calculations have been performed, and analysis has been completed on the individual

products to indicate that they are compatible for use within a system of a given SIL level.

Full IEC 61508 certification can apply to a manufacturer’s processes. Full certification implies that a manufacturer’s product development process meets the standards set forth in the appropriate parts of sections 2 – 3 of IEC 61508 (including hardware / system and software). Receiving full certification from an accredited notifying body gives the end user confidence that the manufacturer’s engineering process has been reviewed and its product’s electrical content, firmware and logic have been assessed and conform to the guidelines set forth in the standard.

There are very few nationally accredited bodies that can issue nationally accredited certifications. Other consulting firms issue certificates that indicate that the product and / or process has been reviewed by an independent third party.

17. Can a manufacturer state their products meet all parts of the requirements of IEC 61508 parts 1 to 7? IEC 61508 consists of the following parts, under the general title Functional Safety of electrical/electronic/programmable electronic safety-related systems:Part 1: General requirementsPart 2: Requirements for electrical/electronic/programmable electronic safety-related systemsPart 3: Software requirementsPart 4: Definitions and abbreviations

Part 5: Examples of methods for the determination of safety integrity levelsPart 6: Guidelines on the application of parts 2 and 3Part 7: Overview of techniques and measures

To be in compliance with the standard, it is necessary to conform to Parts 1 – 3. Parts 4 – 8 are informative only and can be useful in understanding and applying the standard, but do not have requirements for conformance.

Manufacturers of products generally meet Section 2 requirements to determine through a FMEDA analysis that their products are suitable for use within a given SIL level.

Companies choosing to certify their engineering processes and receive full IEC 61508 certification will also comply with Section 3 as it relates to software development.

18. What does SIL X suitable mean, is this a valid statement as per the standard IEC 61508 or can any other wording be used? SIL stands for Safety Integrity Level. A SIL is a measure of safety system performance, or probability of failure on demand (PFD) for a SIF or SIS. There are four discrete integrity levels associated with SIL. The higher the SIL level, the lower the probability of failure on demand for the safety system and the better the system performance. It is important to also note that as the SIL level increases, typically the cost and complexity of the system also increase.

A SIL level applies to an entire system if it reduces the risk in the amount corresponding to an appropriate SIL level. Individual products or components do not have SIL ratings. SIL levels are used when implementing a SIF that must reduce an existing intolerable process risk level to a tolerable risk range.

Only the end user can ensure that the safety system is implemented to be compliant with the standards. It is up to the user to ensure that procedures have been followed properly, the proof testing is conducted correctly, and suitable documentation of the design, process, and procedures exists. The equipment or system must be used in the manner in which it was intended in order to successfully obtain the desired risk reduction level. Just buying SIL 2 or SIL 3 suitable components does not ensure a SIL 2 or SIL 3 system.

19. Using a SIL 3 logic solver means that I have a SIL 3 system. No. When using a SIL 3 logic solver, it is critical that the entire system is designed to conform to SIL 3 requirements. The PFD for the entire system is important. If a user installs a SIL 3 logic solver but does not employ appropriate redundancy or does not incorporate components into the system with correct PFD calculations, then the entire system may not comply with a SIL 3 level. “A chain is only as strong as its weakest link.”

20. SIL 3 suitable products are better than SIL 1 or SIL 2 suitable products.

This is not necessarily true. While a higher SIL level corresponds to a lower probability of failure on demand, a SIL 2 suitable product may be perfectly acceptable for use in a SIL 3 environment if, for example, the proof testing interval is increased or if redundancy is used. It is very important for an end-user to understand the operating requirements of the products within a given SIL environment to ensure that once installed, the products maintain their SIL suitability levels. Incorrect installation, proof testing, or configuration of the products could make the SIL suitability level inaccurate.

21. There are many agencies that are capable of issuing SIL certifications. There are very few nationally accredited bodies that can issue nationally accredited certifications, including FM, TUV, and Sira. Many unaccredited consulting firms issue certificates that indicate they have reviewed the product and / or process for conformance to certain parts of the IEC 61508 standard. The standard does not mandate that certain companies or agencies are able to certify products and systems. Rather, it is suggested that analysis is either conducted or validated by an independent third party.

22. A vendor can determine whether a system meets the requirements of IEC 61511. No. Only the end user can ensure that the safety system is implemented to be compliant with the standards. It is up to the user to ensure that procedures have been followed properly, the proof testing is conducted correctly, and suitable documentation of the design, process, and procedures exists. The equipment or system must be used in the manner in which it was intended in order to successfully obtain the desired risk reduction level. Just

buying SIL 2 or SIL 3 suitable components does not ensure a SIL 2 or SIL 3 system.

23. A customer must purchase a complete SIL based solution, even if some functions do not require a SIL level. For most applications there will only be a few SIF functions being handled by the system, and the vast majority of the circuits may not need to be SIL rated at all. If the customer specifies SIL 2 or SIL 3 for the entire system he may add considerable cost with little or no benefit or improvement in safety.

24. “Safety” and “Reliability” are the same thing. No. Safety and reliability are often linked but are not the same thing. Safety is defined in the IEC 61508 standards as “freedom from unacceptable risk.” A safe system should protect from hazards whether it is performing reliably or not. Safety engineering assures that a safety system performs as needed, even when pieces fail. In fact, safety engineers assume that systems will fail, and design accordingly.

Reliability is a measure of how well the system does exactly what it is intended to do when operated in a specific manner. A reliable system may not always be a safe system. The challenge in functional safety is to ensure that a system is both reliable and safe.

25. Explain SIL and SIS and how they relate?

Safety Instrumented System (SIS): Instrumented system used to implement one or more safety instrumented functions. An SIS is composed of any combination of sensors, logic solvers, and final elements. This can include safety instrumented control functions, safety instrumented protection functions, or both. In many industrial processes, especially those in the chemical or oil & gas industries, involve inherent risk due to the presence of dangerous chemicals or gases. Safety Instrumented Systems are specifically designed to protect personnel, equipment, and the environment by reducing the likelihood or the impact severity of an identified emergency event.

Safety Integrity Level (SIL): SIL is a quantifiable measurement of risk used as a way to establish safety performance targets for SIS systems. IEC standards specify four possible Safety Integrity Levels (SIL1, SIL2, SIL3, SIL4); however, ISA S84.01 only recognizes up to SIL3 levels.

Additional terms in the Safety Design area:

Safety Instrumented Function (SIF): Safety function with a specified safety integrity level, which is necessary to achieve functional safety. A safety instrumented function can be either a safety instrumented protection function (define SIPF) or a safety instrumented control function (define SICF).

Safe Failure Fraction (SFF): is a relatively new term resulting from the IEC 61508 and IEC 61511

committees’ work to quantify fault tolerance and establish the minimum level of redundancy required in a safety instrumented function. Per IEC, “Safe failure fraction is the ratio of the (total safe failure rate of a subsystem plus the dangerous detected failure rate of the subsystem) to the total failure rate of the subsystem.” (In IEC terms, subsystem refers to individual devices).There are four types of random hardware failures:Safe undetected (SU);Safe detected (SD);Dangerous detected (DU);Dangerous undetected (DD).

Determining the SFF requires dividing the sum of the first three by the sum of all four. The assumption is that the operator is expected to take action based on the dangerous detected faults, therefore even if a device has a large fraction of dangerous failures, if enough can be detected and safe action taken, then the device is still considered a safe device.

Probability of failure in Safety Control Circuit0Instrumentation Design, Safety SystemsFebruary 23, 2016 A+A-

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The international standard IEC/EN 61508 has been widely accepted as the basis for the specification, design and operation of safety instrumented systems (SIS).

As the basic standard, IEC/EN 61508 uses a formulation based on risk assessment: An assessment of the risk is undertaken and on the basis of this the necessary Safety Integrity Level (SIL) is determined for components and systems with safety functions.

SIL-evaluated components and systems are intended to reduce the risk associated with a device to a justifiable level or “tolerable risk”.

Probability of failure

To categorise the safety integrity of a safety function the probability of failure is considered – in effect the inverse of the SIL definition, looking at failure to perform rather than success.

It is easier to identify and quantify possible conditions and causes leading to failure of a safety function than it is to guarantee the desired action of a safety function when called upon.

Two classes of SIL are identified, depending on the service provided by the safety function.

• For safety functions that are activated when required (on demand mode) the probability of failure to perform correctly is given, whilst

• for safety functions that are in place continuously the probability of a dangerous failure is expressed in terms of a given period of time (per hour)(continous mode).

In summary, IEC/EN 61508 requires that when safety functions are to be performed as specified in terms of a safety integrity level.

The probabilities of failure are also considered in safety integrity levels, as shown

The PFD value (Probability of Failure on Demand) is the probability of failure of a unit as a component part of a complete safety system in the low demand mode.The PFD value for the complete safety related function is derived from the values of individual components. Sensor and actuator

are fitted in the field, leading to exposed and physical stress factors (process medium, pressure, temperature, vibration, etc.).The risk of failure associated with these components is thus relatively high. 25 % of the entire PFD should be therefore reserved for the sensor, 40 % for the actuator. 15 % remains for the fail-safe control, and 10 % for each of the interface modules (interface modules and the control system have no contact with the process medium and are located in protected switch rooms).

Layers of Protection Analysis (LOPA) Interview Questions0Safety SystemsMarch 16, 2016 A+A-EmailPrint

Acronyms and Abbreviations Used

What is LOPA?

It is a simplified risk assessment method. It provides a method for evaluating the risk of hazard scenarios and comparing it with risk tolerance criteria to decide if existing safeguards are adequate, and whether additional safeguards are needed. Various LOPA methods are available.

LOPA does not suggest which safeguards to add or which design to choose but it does assist in deciding between alternatives.

LOPA can be viewed as an extension of Process Hazard Analysis (PHA). Typically, it is applied after a PHA has been performed. LOPA builds on the information developed in the PHA.

Why was LOPA developed?

Subjective engineering judgement is used to identify the need for additional safeguards in process hazard analysis. This can lead to disagreements and possibly the implementation of inappropriate measures to reduce risk. It was recognized that a more rational and objective approach was needed.

Can you tell me more about layers of protection?

Process designers use a variety of protection layers, or safeguards, to provide a defense in depth against catastrophic accidents. They are devices, systems or actions that are capable of preventing a scenario from proceeding to an undesired consequence. For example, they may be:

Inherently safe design featuresPhysical protection such as relief devicesPost-release physical protection such as fire suppression systemsPlant and community emergency responseSafety Instrumented Systems (SIS)

Ideally such protection layers should be independent from one another so that any one will perform its function regardless of the action or failure of any other protection layer or the initiating event. When they meet this criterion they are called Independent Protection Layers (IPL). Not all safeguards meet the independence requirements to be classified as an IPL, although all IPLs are safeguards. For example, two standby pumps that are both electrically powered do not fail independently in the event of loss of power.

LOPA addresses safeguards that are IPLs. Such safeguards include SIS, also called interlocks and emergency shutdown systems. SIS are addressed by the standard

ANSI/ISA S84.00.01-2004, Functional Safety: Safety Instrumented Systems for the Process Industry Sector, called S84 herein, which can include the use of LOPA.

Also Read: Safety Instrumented Systems Interview Questions

What is involved in LOPA?

Individual hazard scenarios defined by cause-consequence pairs are analyzed.

Scenario risk is determined by combining scenario frequency and consequence severity. Individual protection layers are analyzed for their effectiveness and the combined effects of the protection layers are compared against risk tolerance criteria to determine if additional risk reduction is required to reach a tolerable level.

Scenario frequency is determined by combining initiating event frequency, IPL failure probabilities and the probabilities of enabling events/conditions and conditional modifiers. Enabling events or conditions do not directly cause the scenario but must be present or active for the scenario to proceed, for example, the process being in a particular mode or phase. Commonly considered conditional modifiers are the probability that released flammable/explosive material will ignite, the probability that an individual will be present to be exposed to a hazard, and the probability than an exposed individual will actually be impacted. Order of magnitude estimates are used for frequencies, probabilities and consequence severity.

How do risk tolerance criteria help?

Without risk tolerance criteria, there is a tendency to keep adding safeguards in the belief that the more added, the safer the process. This can be a false assumption. Eventually safeguards will be added that are unnecessary. This reduces the focus on

safeguards that are critical to achieving tolerable risk. Unnecessary safeguards also add complexity that may result in new, unidentified hazard scenarios.

LOPA helps focus limited resources on the most critical safeguards.

How does LOPA relate to Quantitative Risk Analysis (QRA)?

LOPA adds simplifying assumptions for the numerical information used. The simplifications are intended to be conservative so that QRA would show less risk for a scenario than LOPA.

How should I conduct PHA’s to facilitate LOPA?

LOPA studies will be easier to conduct if the following issues are addressed during the

PHA:Clarify initiating events, i.e. causes of hazard scenariosProvide sufficient scenario detailExpress consequences in a form compatible with LOPARecord and identify candidate IPLs, i.e. safeguardsList all safeguards before deciding if they are IPLs

Consider identifying enabling events/conditions and conditional eventsRank hazard scenarios so they can be screened for LOPAFlag recommendations for additional IPLs

Are there other applications of LOPA?

Yes. It can be extended to many situations involving risk-informed decision making including:DesignCapital improvement planningManagement of changeEvaluating facility siting riskMechanical integrity programsIdentifying operator rolesIncident investigationEmergency response planningBypassing a safety systemDetermining the design basis for over-pressure protectionDetermining the need for emergency isolation valvesScreening tool for QRA

Can you summarize what LOPA does and doesn’t do?

There are three issues for protection layers:How safe is safe enough?How many protection layers are needed?How much risk reduction should each layer provide?Risk tolerance criteria must be established for LOPA and they address the first issue.LOPA helps decide how much risk reduction is needed and how many protection layers should be used. It does not help decide what specific IPLs should be used.Why should we perform LOPA?Provides an objective, rational and defensible basis for recommendations to install or not install safeguards after a PHA has been performed.Meets the requirements of the S84 standard for SIS. Note that OSHA expects compliance with S84.Provides the basis for a clear, functional specification for safety instrumented systems.

Overview of HIPPS System0Control SystemsJanuary 15, 2016 A+A-

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Introduction to HIPPS

HIPPS is an abbreviation of “High Integrity Pressure Protection System”. HIPPS systems are applied to prevent over-pressurisation of a plant by shutting-off the source of the high pressure. In traditional systems over-pressure is dealt with through relief systems. Relief systems have obvious disadvantages such as release of (flammable and toxic) process fluids in the environment and often a large footprint of the installation. With the increasing environmental awareness relief systems are no longer an acceptable solution.

HIPPS is applied to prevent over-pressurisation of a plant or pipeline by shutting off the source of the high pressure.

HIPPS provides a technically sound and economically attractive solution to protect equipment in cases where:

• High-pressures and / or fl ow rates are processed

• The environment is to be protected.

• The economic viability of a development needs improvement

• The risk profile of the plant must be reduced

HIPPS is an instrumented safety system that is designed and built in accordance with the IEC 61508 and IEC 61511 standards.

What is HIPPS?

The international standards IEC 61508 and 61511 refer to safety functions and Safety Instrumented Systems (SIS) when discussing a device to protect equipment, personnel and environment.

Older standards use terms like safety shut-down systems, emergency shut-down systems or last layers of defence. A system that closes the source of over-pressure within 2 seconds with at least the same reliability as a safety relief valve is usually called a HIPPS.

A High Integrity Pressure Protection System is a complete functional loop consisting of:

• The sensors, (or initiators) that detect the high pressure

• The logic solver, which processes the input from the sensors to an output to the final element• The final elements, that actually perform the corrective actions in the field by bringing the process to a safe state. The final element consists of a valve, actuator and possibly solenoids.Traditional systemsIn traditional systems over-pressure is dealt with through relief systems. Relief systems have obvious disadvantages such as release of (flammable and toxic) process fluids in the environment and often result in a large footprint of the installation. With increasing environmental awareness relief systems are no longer an acceptable solution. A relief system aims at removing any excess inflow, where as a HIPPS aims at stopping the inflow of excess fluids and thus avoiding over-pressure.Advantages of HIPPSHIPPS provides a technically sound and economically attractive solutions to protect equipment in cases where:High pressures and / or flow rates are processedThe environment is to be protectedThe economic viability of a development needs improvementThe risk profile of the plant must be reduced Overview of HIPPS HIPPS is an instrumented safety system that is designed and built in accordance with the IEC 61508 and IEC 61511 standards. These international standards refer to safety functions (SF) and Safety Instrumented Systems (SIS) when discussing a solution to protect equipment, personnel and environment. A system that closes the

source of over-pressure within 2 seconds, with at least the same reliability as a safety relief valve, is usually identified as a HIPPS.A HIPPS is a complete functional loop consisting of:The initiators that detect the high pressure. These initiators may be electronic or mechanical.For electronic HIPPS, a logic solver, which processes the input from the initiators to an output to the final element.The final elements, that actually perform the corrective action in the field by bringing the process to a safe state. The final element consists of a valve and actuator and possibly solenoids or mechanical initiators.Two types of HIPPS Based on experience and expertise offers two types of HIPPS1. Integral mechanical HIPPS, since 19742. Full electronic HIPPS, since 20001. Integral mechanical HIPPS – using mechanical initiatorsIn 1974 the German DVGW certified the final element including mechanical initiators in accordance with EN 14382 (former DIN 3381). Since that date has field experience with safety shut-off valves (with actuator and initiator) closing within 2 seconds.Main features of integral mechanical HIPPS:Integrated safety loop to IEC 61508 / EN 12186Safe and simpleOption not requiring external energy (stand-alone HIPPS)No wiring requiredSet point accuracy < 1%

System to SIL 3 or 4Third party validated failure data

2. Full electronic HIPPS – with electronic pressure transmittersWhen designing a HIPPS always treats a HIPPS (and other SIS) as a complete certified functional loop and not on separate component level. Safety wise the HIPPS loop is designed in accordance with IEC 61508 and 61511. On the specification side of the final element the design is in accordance with EN 14382 (DIN 3381). The misunderstanding that ‘system’ stands for controller and that a SIS can be designed on component level, is the cause of the biggest problem in the implementation of HIPPS. The under specification of mechanical components and the acceptance of component Safety Integrity Level (SIL) certification, instead of verification of the complete loop SIL is still a pitfall. Main features of full electronic HIPPS:Integrated safety loop to IEC 61508 and 61511No limit on distance between transmitters and final elementCommunication with Plant Safety SystemPossibility of integrated monitoringHard-wired solid-state logic solverHigh integrity manifold block for safer operationSystem to SIL 3 or 4HIPPS System: 1002 Electronic HIPPS system

Basics of Wellhead Control Panel (WHCP)0Control SystemsJanuary 16, 2016 A+A-EmailPrint

WHCP: Wellhead Control Panel

Gas wells and oil wells has a high potential hazard, either because the material ejected flammable nor the potential hazard of the gas pressure is high. Wellhead control panel is key equipment in oil & gas industry to protect oilfield facilities and environment from occurring wellhead fire and emergency incidents, which is one of main control systems to ensure oilfield oil production and transportation to be safely operation according to international standards and national regulation.Its function is to shut down the well in case conditions that harm or for other interventions as well as the work test, etc.

Wellhead control panel is composed of hydraulic power unit (HPU), tubing & fitting and instrument valve and electrical control

devices. HPU supply hydraulic resource to open and close SSVs including MSSV, WSSV and SCSSV.

The level of complexity of each well head control panel vary, each company has its own standard. So the definition of well head control panel in General will certainly vary, the definition of well head control panel if we review of its functionality is part of the surface facilities of the gas well or an oil well that is used to control well, like: be it to shutdown system, the casing pressure reading parameters, tubing pressure reading parameters, temperature well parameters. So to open or close a Wing Valve (WV), Master Valve (MV), as well as Down Hole Safety Valve (DHSV) can be through the Wellhead control panel. Generally inside wellhead control panel consists of control pneumatic or hydraulic. Control pneumatic or hydraulic composed of tubing and three way valve.

Here I will only discuss WHCP from gas wells, as I understand. Function or application WHCP depending of each type of wellhead control panel. It is a simple system, until there is a tricky. If it can be inferred is actually a function of well head control panel is to operate well, be it for shut in and POP (put on production). With the wellhead control panel we able to open or closed the DHSV via the push button in panel. Also we can open or close a master valve or wing valve with push button in the panel as well. It was all done manually, by pressing or pulling a push button. But to close the DHSV, Master valve, Wing Valve can be done automatically, namely through the integration with shutdown

system from the well. Surely this should follow the philosophy of the shutdown system used by each company .

By looking at the picture, it will give an overview of what functionality or usability of the wellhead control panels. The components are visible in the picture can be grouped into:

All of these components will give feedback or as a input signal to the Wellhead control panel (WHCP). While in the well itself (flowline) there is a sensor that is used to monitor the condition of the well, either to shutdown the system, or just for readability only.

Instrumentation for shutdown system e.g.:PALL (pressure switch low low)PAHH (pressure switch high high)The Fusible plug (for detection of fires), usually mounted above fangles, or parts that there is a possibility of leaks (the source of fire)

The instrumentation used for reading, for example:FR (flow recorder) or Flow IndicatorPR (pressure recorder) or Pressure indicatorTR (temperature recorder) or Temperature Indicator

The Final element of the system shutdown:DHSV, Down hole Safety valve ( drived by hydraulic power)MV, master valve (drived by hydraulic power)SSV, surface safety valve (drived by pneumatic power)Choke valve, manually operatedSDV (shutdown valve) installed in flow line of well, outside the part of the wellhead (X-mastree)

Valves are a part of which will receive command of the signal to be opened or closed from Wellhead control panel. So if I can give analogical WHCP is a controller (a control system), SSV, MV, DHSV, SDV are the part that receives the output from the controller, while the PALL, PAHH, fusible plug is the input of the controller. But don’t imagine WHCP like PLC in General. WHCP I discuss here is that it uses control pneumatic or hydraulic.

Why WHCP generally use pneumatic control, because most of the well gas wells far location (remote) so hard to find sources of energy such as electricity. And generally WHCP from gas wells using gas from the well itself as a source of pneumatic power. Later will be discussed where the pneumatic power source to run the WHCP. With pneumatic power from gas, we can also have hydraulic power, i.e. by install the hydraulic pump on run by pneumatic power. Hydraulic power is used to run valve actuator which relatively large power needs. Pneumatic-powered convert hydraulic power can become larger by using the pump.

The Problems That Often Arise in Wellhead Control Panel (WHCP)

From the various experiences, The problems that often arise in WHCP are leaking, popping, and stuck. Commonly Leaking occurred in the connection of nuts on tubing. It could be leaking at a three way valve components. To this we can issue leaked retighten the bolts or given a Teflon sealant. If for three way valve usually replace the internal parts like its o ring, whereas in order to overcome stuck at three way valve do greasing of internal plunger. Stuck in a 3 way valve because it is dirty or arid.

For ordinary problems popping occurs at PSV. PSV is safety equipment to handle excess pressure. Each panel of a pneumatic or hydraulic there must have been his PSV. Just like in the WHCP. When there is an excess pressure, PSV will popping, to release the excess pressure. When it was popping PSV unbiased back to its normal position, the problem is often the case. To fix this we clean the inside and then check the setting.

One of the disadvantages of pneumatic systems which use hydrocarbon gas as a source of power instrument is if the liquid into a pneumatic system. This will cause three-way valve not working well. If the wrong selection of the material, example the O ring not resistant with hydrocarbon substances, will certainly damage the o ring itself.

Main Function of WHCP

Local On/Off SSV

Remote control SSV through RTU

High-Low pressure sense shut-down automatically.

Fusible Plug, Anti-fire Shut-down automatically.

SSV can not be opened unless local reset after shutoff

Function of showing system pressure

Relief Valve shall be installed on each hydraulic circuit to prevent high pressure

Function of showing hydraulic level and level switch for alarm

Function of defending pressure impact of system

Function of defending exorbitant pressure

Function of system pressure monitoring(by pressure transmitter of control panel)

Function of remote emergency shut-down (by magnetic valve of control panel)

Function of On/Off SSV monitoring (by pressure switch of control loop of control panel)

Function of shield High-low pressure sense

Types of WHCP

Single wellhead Control Panel

wellhead control panel is used for controlling one well Surface controlled sub-surface safety valve (SCSSV), Master SSV and Wing SSV. SSVs can be shutdown automatically and manually by WHCP to response all kind of emergency situation.

Single well control panel is categorized the following system according to driven resource:Manual control systemElectrical control systemPneumatic control systemSolar powered control system

Manual control system

Feature and Function: Manual hydraulic pump supply hydraulic control and output pressure for SSV. Main function includes Remote ESD, Fusible plugs, low pressure / high pressure sensing, Manual shutdown at panel.

Electrical control system

Feature and Function: Electrical motor driven hydraulic pump with manual pump as standby will supply hydraulic to control SSV. Main function includes Remote ESD, Fusible plugs, low pressure / high pressure sensing, Manual shutdown at panel.

Pneumatic control system

Feature and function: Pneumatic driven hydraulic pump with manual pump as standby will supply hydraulic to control SSV. Main function includes Remote ESD, Fusible plugs, low pressure / high pressure sensing, Manual shutdown at panel.

Solar powered control system

Solar powered control system is designed to be used for wellhead control located remote area and desert area.

Feature and Function :Energy conservation, Reduce operation expense, Duel power supply, Standard control feature

Main function includes RTU shutdown；Fusible plugs；Low pressure/high pressure；Local Manual control

Multi-wellhead Control Panel

Each control module is drawable and can be inter-replaceable without any interruption of other well operation. Common module include oil reservoir, Pneumatic hydraulic pump and standby manual pump.

Main function shows as following: Remote RTU shutdown; Fire fusible plugs protection, Low pressure / high pressure sensing, Manual control at panel.

Well Head Control Panel Working Principle

It is very common in the oil & gas plant to control its oil or gas well through a wellhead control panel (usually called WHCP). Each well is always equipped with a SCSSV (Surface Controlled Sub-surface Safety Valves) or usually it is called as down hole valve (DHV) and a SSV (Surface Safety Valves) which is consist of a Master Valves (MV) and Wing Valves (WV). SCSSV in most

application is an on-off valve with hydraulic actuators. While SSV can be driven by hydraulic actuator or pneumatic actuator depends on the pressure rating. It is also a need to open or close SCSSV and SSV in sequence and accommodate an Emergency Shutdown signal from the systems. So what are WHCP and its essential component? This article tries to explain the WHCP systems in general application and how it works.

WHCP systems usually consist of hydraulic reservoir, strainer, hydraulic pumps, accumulator, wellhead control module, and hydraulic line which are supply and return to wellhead control module. Any other parts except wellhead control module are classified into basic cabinet. Each control module is built up dedicated for one well only. Therefore if there are 5 well in a wellhead platform, then there will be 1 basic cabinet and 5 wellhead control module needed.

First part of WHCP is a hydraulic reservoir. This reservoir contains hydraulic fluid in sufficient quantity to operate each wellhead. The size of reservoir is determine through an estimation of hydraulic fluid needed to operate each actuator, possible leakage, distance from the well, and an additional safety factor. Usually the hydraulic reservoir is an atmospheric tank with a flame arrestor venting.

To build up a hydraulic header (high or medium pressure) the WHCP utilize a hydraulic pump. In general the SCSSV will operate at high pressure rating and SSV will operate at medium pressure rating. Thus there will be two hydraulic headers at WHCP with its own hydraulic pump. The hydraulic pump can be pneumatic driven or electric driven depends on criticality and operation area.

All hydraulic pump suction will have a strainer to filter the hydraulic fluid from any particulate so that the hydraulic fluid goes to SCSSV or SSV is clean. To make the hydraulic demand from SCSSV or SSV achievable, the downstream of the hydraulic pump (hydraulic header) is equipped with an accumulator. It helps the hydraulic pump to supply quickly the hydraulic demand. This arrangement (reservoir, hydraulic pumps, and accumulator) usually is called as a hydraulic power pack or a hydraulic power unit.After the hydraulic fluid accumulated at the hydraulic header (both high pressure and medium pressure) then it’s ready to supply each wellhead control module. Usually the line from hydraulic header to wellhead control module is called a hydraulic supply lines. At this wellhead control module, the sequence and logic to operate the SCSSV and SSV is built up. The ESD signal mainly also goes to this module. When it needs to open the SCSSV and SSV, it supplies the high pressure or medium pressure hydraulic fluid to the SCSSV and SSV. In case there is a need to close it down, the hydraulic fluid supply will close and the hydraulic fluid will goes to a hydraulic return line through a three way valves selector. This hydraulic return line will goes to the hydraulic reservoir again.From this general explanation we can conclude that the wellhead control panel (WHCP) is a hydraulic system that utilizes a hydraulic power pack and a wellhead control module to perform its task. The output of WHCP is high pressure hydraulic supply and medium hydraulic supply to operate SCSSV and SSV. Wellhead control panel is also the interface between the plant control and safety system with the SCSSV and SSV systems.

De-energize to Safe Loop philosophy

Safety Instrument loop in a plant operate in two modes:Energized to safe De-energized to safeDe-energized to safe mode, also known as fail safe system means that during plant normal condition, there will be electrical current flows through the instrument loop. When trip/shutdown is required, then loop will be de-energized.De-energized to Safe ModeSee illustration on above picture of a simple unit consisting Pressure Switch High High and SDV. During plant normal condition the pressure switch contact is closed (pressure is lower than HiHi setting) and enables current flow within the loop. Likewise, the solenoid of SDV is energized by electrical power to allow air supply stroking the SDV and then forcing it in open position.As long as the control/safety system receiving current signal of pressure switch loop, plant is considered as normal. If the pressure increases and reaches HiHi setting, pressure switch will activate and contact changes from close to open and there will be no current flows, hence alarming plant control system.The predetermined executive action shall then be taken to put system in safe condition i.e. de-energize the SDV’s solenoid to make the main valve close.The reason de-energized to safe mode to be implemented in such system is to make it in safer state (in above case by closing the main valve) when either one of the following conditions occurs:– Unintended instrument cable disconnection (either pressure switch or solenoid valve)– Electrical black out

Energized to safe system will be discussed in other post.

Energize to Safe Loop philosophy

Safety Instrument loop in a plant operate in two modes:Energized to safe De-energized to safeEnergized to safe mode works as contrary to that of De-energized to safe loop.In Energized to safe mode, no electrical current flows through the instrument loop during plant normal condition. Loop will be energized during plant upset/trip/shutdown.For illustration, see below picture of a simple unit consisting push button (PB) and solenoid valve controlling a deluge valve (XV). During plant normal condition (no fire) the push button contact is at open position so that no current flows within the loop. Similarly, the solenoid valve of deluge valve is not being energized by electrical power. This condition drives the deluge valve to close position, prevents the fire water from ring main passing through the deluge valve.Energized to Safe LoopIf there is a fire in deluge coverage area, someone would activate the push button. Once activated, the switch within push button changes state to close position and enables electrical current flows within the loop. This current will signal the control system and execute the predetermined action i.e. to open deluge valve by energizing the solenoid valve loop. Therefore, once the solenoid valve energized, it will make the deluge valve to open, allowing water flows through to extinguish fire.

This mode is also commonly applied for ESD push button for shutting down a plant.The purpose of having energized to safe system in such system is to avoid misoperation of final element (activation of deluge valve on above example) due to instrument failure or unintended instrument cable disconnection.Imagine if this system applies de-energized to safe mode instead. Even only one failure on solenoid valve cable or system side fault e.g. I/O card, will cause the deluge to open automatically. Not only will this cause the equipment including surrounding instruments to wet, but this will also be dangerous as the equipment within the area is still not electrically isolated.Worse would happen in ESD push button, as it will cause a plant shutdown that results in production loss.Further discussion of line monitoring in energized to safe mode will be in next post.Additional Fact: Deluge valve is also activated by confirmed fire signal generated by flame detector, smoke detector or heat detector.

Instrumentation Inspection and Quality Control Questions1Q & AJune 11, 2015 A+A-Email

Print 1)What is QA/QC? Ans> QA/QC means Quality assurance/Quality control the purpose of this (QA/QC) is to establish the sequence of requirement for the quality of material quality of works its inspection and records. Instrumentation Inspection and Quality Control Questions

2)What is the basic responsibilities of a QA/QC personal ? Ans> To ensure execution of works and comply fully as per standard and approved speck. 3)What are QA/QC’s ITP’s and QCP? Give a brief? Ans> ITP: This is procedure informs about the kinds of quality check (surveillance inspection witness or hold points) means quality of works is being done in proper sequences. QCP: This is procedure addresses the activities and requirement in details. 4) What is NCR? Why does it need for a QA/QC personal? Ans> NCR means Non-Compliance Report, QA/QC personal has reserve the right issue a warning of the contractor doesn’t comply or violate with the standard procedure. 5) What are general work procedure (WP)? Ans> The. general sequence of activities will be as follows; Receiving Drawing and documents. Reproduction of Drawing

Issuing of Drawing to site New issuing New revision Shredding of Drawings Redlining Drawings Transmittal of redlines to client (As-built). Also Read : Field Instrumentation Interview Questions6) What is ISO? Explain some of its standards? Ans> ISO means international standard organization some of them are as below; ISO;9001, ISO;9002, ISO,9003 etc. 7) What are the standard height to install the instruments? Ans> Standard height to install the instruments is 1.4 meter but it can very less or more as per locations convenience. 8) What is loop check? Ans> To ensure that the system wiring from field to control console functioning fine. 9) What is different between open and close loop ? Ans> Open loop; A loop system which operates direct without any feedback and it generates the output in response to an input signal. Close Loop; A loop system which uses measurement of the output signal through feedback and a comparison with the desired output to generate and error signal that is applied to the actuator. 10) What are inspection points for a cable tray installation.

Ans> Material check as per approved spec, size and type, trays hook-up, proper distance structure, tray to tray i.e. power/control/and signal/low voltage and high voltage , support fixed strongly not shaking. 11) what are inspection point for field instruments with impulse tubing? Ans> Materials inspection as per approved spec material, type and size installation as per hook-up, check line route to avoid any obstruction check tube support, compression fitting of ferrules, and then pressure test (hydrostatic test) shall be done. 12) What are inspection points for cable laying. Ans> material inspection as per approved materials, type and size, meggering, cable routing drawing, completion of cable route (tray conduit or trench etc) and cable numbering tags, cable bending, use of proper tools and equipment for cable pulling. 13) What are inspection points for junction box and Marshalling cabinets. Ans> Material inspection, type, size as per approved specification, installation hook-up For frame, bracket or stands, fixed properly means shaking free, name plate and tag no. 14) how do you determine the correct installation of flow orifice? Ans> The orifice data (tag) shall be punched in the up stream of orifice , the data (tag) side shall be in the upstream of flow direction. 15) |Explain why shield of signal cable is not earthed on both sides? Ans> To avoid the current noise (resonance).

16) What is final RFI? When it shall be raised up? Ans> When the QA/QC department of contractor is satisfied that the work detailed in the construction RFI is completed, then request shall be submitted for inspection to the client QA/QC department. 17) What are the required documents for an inspection? Ans> Following are the required documents for an inspection; RFI (Request for inspection) P&ID for line verification PP for location (pipe plan) Wiring diagram for wiring details Data sheet for calibration and pressure test Hook-up etc. for remote tubing/air line QR for maintaining record WP, work procedure, to check each and every steps as per spec. QCO for issuing in case of little violation NCR, for issuing in case of major violation etc. 18) What are the required documents for a remote loop folder? Ans> Following are the required documents for a remote loop folder: Loop package check list ILD (instrument loop diagrams) Instrument loop acceptance records(TR/test record) P&ID (piping & instrument Diagram)

ISS/IDS(instrument specification sheet/instrument data sheet) Alarm List Calibration record (TR) Cable megger report (primary prior to pulling) Cable megger report (secondary after pulling) Pressure test record(TR) MC check record (remote loop)(green color) MC punch list Loop check punch list. 19) What are the required documents for a local loop folder? Ans> Following are the required documents for a local loop folder: Loop package check list ILD (if not mechanical loop) Cable megger report (primary prior to pulling) if not mechanical loop Cable megger report (secondary after pulling) if not mechanical loop Alarm list ( if not mechanical loop) P&ID ISS/ISD (instrument specification sheet/instrument data sheet) Calibration record (TR) Pressure test record(TR) if required MC check record (local loop)(green color)

MC punch list Visual check punch list/loop check punch list. 20) What is schedule Q? Ans> Schedule Q is an attachment to the contract, which is the provision of quality Assurance and control, Inspection and test plan. 21) What is ITPs? What is hold points Ans> ITP means inspection and test plan, details of work scope and required types of Inspections Hold point (H) is the level of inspection that client inspection must required through RFI and cannot be proceeded until inspection is done by client. Witness point (W) is the level of inspection that inspection activity can be proceeded without client inspection or if client is not available as per RFI timing. 22) What is RFI? When an RFI will be raised? Ans> Request for inspection (RFI), RFI shall be raised only when the status of the preliminary inspection is satisfactory, and the works (items) are hold or witness point.22) What is a Project Specification ? Ans> A project specification specifies the minimum requirements according to the design and relevant international codes and standards.23) What is an ITP ? ITP (INSPECTION & TEST PLAN) is a Document that defines the activities requiring inspection or test (witness hold points etc.) the controlling specifications the acceptance criteria the persons responsible and the record to be produced.24) What is a QCP ?

QCP (QUALITY CONTROL PROCEDURE) is a procedures that complements the ITP, by providing information that cannot practically be included in the ITP , but is necessary in order to perform control inspection and test .25)What is a Project Procedure ?PP is a procedure that presents the systematic controls to be implemented and identifies the responsibilities and authorities such as to ensure that the specified requirements are followed .

Interview Questions on controllers0Control Systems, Q & AMay 2, 2015 A+A-EmailPrint 1.What is a ‘controller’? Where are its application areas?A controller is an instrument used for controlling a process variable (measurement). Its continuously monitors the error signal and gives a corrective output to the final control element.Interview Questions on controllers

2.Explain the following terms in a controller?Measurement variable: It is the demand variable measured and controlled.Desired Variable: it is the demand signal (setpoint) to which the process variable is controlled.Deviation: it is the error signal caused by the difference between the measurement and the demand signal.Output: It is the corrective signal from the controller to the final control element.Also Download: Control Systems Interview Questions & Answers Android App3.Explain what is ‘direct action’ and ‘reverse action’ on a controller?Direct action : In a direct acting controller, the output increases when the process measurement (variable) increases.Reverse action : In a reverse action controller, the output decreases when the process measurement (variable) increases.4.What is a gap controller?A controller whose output changes from ;minimum to maximum (on-off) and vice-versa when the error signal (deviation) exceeds the set gap depending on the controller action.5.What is a ‘proportional band’? Explain with an example?It is the range in percentage for which the controller output changes proportionally from minimum to maximum and vice-versa when the measurement deviates from the setpoint.For example: A controller set at 50% proportional band

The controller output changes from minimum to maximum and vice-versa when the measurement exceeds 25% either side of the setpoint depending on the controller action.6.What is a ‘gain’? Write the relation (formula) between a gain and proportional band?A controller ‘gain’ is inversely proportional to its proportional band. . g = (1/p)*100 . g = gain . P = proportional bandAlso Read: Fire & Gas System Interview Questions & Answers7.What is a ‘reset action’? Explain with an example?Reset action in a controller is the integration of the proportional action by the set period. The reset action repeats the proportional action’s output per the reset time set, until the error signal becomes zero or the output gets saturated.For example :if the reset action is set for 30 sec.For a 0.5 volt correction output ;by the proportional action will be repeated by the reset action every 30 secs., until the error signal becomes zero or the output gets saturated.8.What is a ‘batch’ facility on a controller?Whenever a deviation persists for a long time the controller output saturates at the maximum of minimum output (-2.5 VDC or + 12.5 VDC/0 kPa or 140 kPa) depending on the controller action. In a normal controller when the process reverts to normal the output takes its time to come into control range.

In a batch controller the output reverts to the control limit (0VDC OR 10.00V DC 20 kPa or 100 kPa) as soon as the deviation enters the batch limits9.What will be the output (increases or decreases) of a direct action controller when the process goes above the setpoint?In a direct acting controller, the controller output increases when the process (measurement) goes above the setpoint)10.What will be the output of a reverse acting controller when the process changes from 50% to 75% where the proportional band is set at 50%, setpoint is set at 50%?The controller output will be zero.11.What is a ‘bump-less transfer’ in a controller’s auto/manual change over?‘Bump-less transfer’ is to eliminate the change in the controller’s output when the controller is changed from auto to manual control and vice-versa.12.Explain how to change a controller from auto to manual and vise-versa?Pneumatic controllers :While taking the controller from auto to manual, the manual output is to be balanced to the auto output and then transfer the auto-manual switch to manual. While changing the controller from manual to auto, the controller setpoint is matched to the manual output and then auto-manual switch is transferred.Electronic controllers :Auto to manual control may be transferred directly as the electronic circuit keeps the auto and manual output matched. But while changing the controller from manual to auto, the controller setpoint is to match to the process variable and then auto-manual switch is transferred.

13.What type of controller (P, PI, PID) is preferred on the following process control loops?Pressure: If the load change is minimum, then a proportional controller is suitable. If a frequent load change is expected then a Proportional + Integral controller is preferred. Level : Normally a proportional controller is preferred.Flow: Proportional + Integral controller is preferredTemperature: Proportional + Integral + Derivative controller is preferred14.Why is there a direct and reverse action on a controller when the control valves are already having direct (air fail to close)/reverse(air fail to open) actions”?The type of control valve action requirement on a process line, depends on the protection required on the upstream or downstream of the control valve incase of an air failure. Depending on the control valve action, the controller action has to be set to control the process. For example : Station back pressure control valve is reverse acting and its controller is set for reverse acting. If there is an air failure the control valve opens fully and prevents the separator from high pressure. If the separator gas pressure goes below the setpoint the controller output goes high and keeps the control valve closed. Separator level control valve is direct acting and its controller is set for direct acting. If ;there is an air failure, the control valve closes fully and prevents the surge tank from high pressure. If the separator level goes below the setpoint the controller output goes low and keeps the control valve closed.

Control Room and Field Instruments Questions & Answers0Q & AJanuary 31, 2016 A+A-EmailPrint

Intrinsically Safe Systems

What is “Intrinsically Safe”?

A protection method employed in potentially explosive atmospheres. Certificate IS tools are designed to prevent the release of sufficient energy to cause ignition of flammable material. IS standards apply to all equipment that can create one or more of a range of defined potential explosion sources.Electrical sparksElectrical arcsFlamesHot surfacesStatic electricity

Electromagnetic radiationChemical reactionsMechanical impactMechanical frictionCompression ignitionAcoustic energyIonizing radiation

What Industries are Intrinsically Safe Products Designed for?PetrochemicalOil platforms and refineriesPharmaceuticalPipelinesAny environment where explosive gases or vapors could be present

The Three Key Elements of Combustion are:Inflammable material (gases, particles/dust)Oxygen/airIgnition source

This combination is very common in chemical, petro-chemical, and pharmaceutical industries. Examples of the amount of

inflammable material necessary for ignition below show how small of an amount it takes to present a danger to workers.

What are the Regulations and Guidelines for IS?

ATEX (Europe)

European Union’s 94/9/EC Directive, commonly called ATEX (“Atmospheres Explosibles”) Europe’s primary regulation for protection systems and equipment intended for use in potentially explosive atmospheres. Indended to serve as total harmonization directive, laying down essential health and safety requirements, and replace existing divergent national and European legislation.

This directive became mandatory on electical and electronic equipment for use in environments subject to explosion hazard sold in the EU on 1 July 2003.

Derivatives of ATEX are being adopted across the world.

NEC (United States)

National Electrical Code (NEC), is the basis for all electrical codes in the United States. Classifications and related product markings for hazardous areas are covered in NEC 500 and 505. Interpretations of NEC 500, a longstanding regulation are utilized

throughout the world (outside Europe). NEC 505 is similar to ATEX.

Field Instruments

What is the measurement principle of an vortex flowmeter?

When a shedder bar is placed in a fluid, Karman vortices are generated on the downstream side. The vortex frequency is proportional to the flow velocity, and corresponds to a specific range of Reynolds numbers.The vortex frequency (f) is calculated by the formula; f=St*v/d v: flow velocity, d: width of shedder bar, St: Strouhal number

What are the advantages of a vortex flowmeter?

Frequency output is proportional to flowrate.

No moving parts are required because of vibration created by Karman vortices.

Wide measurement range

Can measure gas, steam and liquid

Outputs volumetric flowrate without influence of density, temperature, or pressureLimit Alarms

On limit alarms, what is meant by “failsafe”?When a limit alarm is configured for “failsafe” operation, the contact logic is reversed. This means that the coil, which controls the contact(s), will de-energize when the unit is in alarm, and energize when the unit is not in alarm. Thus, if the limit alarm looses power, the contacts will revert to the alarm condition.

This functionality is desirable if the user wants an alarm whenever the measured process is beyond acceptable values, or whenever power is lost to the limit alarm.

On limit alarms, what is meant by “deadband”? Deadband is the difference between the alarm “on” and alarm “off” setpoints. For example, if a limit alarm is calibrated to trip at a 14.7 mA input, and un-trip at 13.5 mA, the deadband, (or differential) is 1.2 mA.

What input range is used for the dc input limit alarms to accept a 4/20 mA signal? All the input ranges for the Action Instruments’ field configurable devices are zero based. One of the input ranges is 20 mA. This is the input range to use for all signals up to 20 mA. Accuracy is not affected. Having the input range begin at zero allows a limit alarm to be used for open circuit detection.

Also Read: Control Valves Basic Questions & AnswersThermocouple/RTD Input

What does “cold junction compensation” mean?Cold junction compensation allows accurate temperature measurement when using a thermocouple. What’s a thermocouple? Well, a thermocouple is created when wires made from two different types of metal are connected together, (such as Iron and Copper-Nickel). Thermocouples generate a small Voltage, which increases when the thermocouple junction gets hotter.

When the thermocouple wires are connected to an instrument, two more thermocouple junctions are created, because the terminals are made of a different material than the thermocouple wires. These “extra” junctions, (called cold junctions), create their own Voltage, which alters the Voltage generated by the actual thermocouple. Cold junction compensation negates the voltage created by these cold junctions, allowing only the Voltage created by the thermocouple to be sensed by the instrument.

Why does an RTD need an excitation source? Usually an electrical reference or excitation source is required for sensors whose electrical properties are measured. A thermocouple produces a potential difference between the two dissimilar metals that varies with temperature and is repeatable. The measurement is therefore a voltage.

The resistance of an RTD changes with temperature, therefore, a constant DC current excitation source is used as a reference to produce a proportionally changing voltage. Thus a signal conditioner which measures an RTD input provides a current reference as excitation and measures the voltage produced.Transmitters

What is the maximum load I can connect to the current output of a 4-wire transmitter? The maximum load that can be connected to a current output depends on the output compliance. Each product has an output compliance specification that can usually be found on the last page of the data sheet. We can determine the maximum allowable load by using Ohm’s Law.

For example, if the compliance of a 4-20 mA output signal is 15 V, then the maximum load is 750 ohms. (15 V / 0.02 A)=750 ohms.

What is the maximum load I can connect to the output of a 2-wire transmitter?Unlike a 4-wire transmitter, the maximum load that can be connected to a 2-wire transmitter is dependent on the power supply used to power the output current loop and the loop voltage drop of the 2-wire transmitter. The 2-wire transmitter has a minimum source voltage and a maximum source voltage.

The maximum output load would be realized using the maximum output source voltage. A 24 Vdc supply is most often used. The general formula is:

Max RL=(Vss – LVD) / 0.02

A Where RL is the maximum load, VSS is the DC power supply voltage, and LVD is the loop voltage drop. All 2-wire transmitters have a Loop Voltage Drop specification. For example, the RTD input transmitter has a loop voltage drop of 12 V. If a 24 Vdc power supply is used, what is the maximum load that can be connected to the output loop? Using the above formula the maximum load is 600 ohms.

What is the difference between a Two-Wire and a Three-Wire Transmitter? The three-wire transmitter is a blend of the four-wire and the two wire versions. The four-wire transmitter has two wires for power and two wires for the output signal. The power for a four-wire transmitter can be either AC or DC and the output signal can be either voltage or current. The two-wire transmitter has two wires for both power and the output signal.

A two-wire transmitter is always DC powered and the output can only be a current signal, typically 4-20mA. The three-wire transmitter uses two wires for power and the third wire is used for the output signal (+) positive terminal. The power (-) negative terminal is used as a common reference for power and the signal (-) negative reference. This allows the best of both transmitter

features to be utilized. There is one less wire required than a four-wire transmitter and powered outputs are provided for both 4-20mA signals and 0-10V signals.

These transmitters can be lower in cost than four-wire transmitters because they are DC powered and do not incorporate an isolating power supply. However, designers must be aware of grounding especially since several transmitters are usually connected to one power supply, and the negative (-) terminal is common to all signals.

On frequency input devices, what is the sensitivity adjustment? The sensitivity adjustment actually changes the level of an input filter; Switching the unit to “Low” sensitivity range filters all input signals up to 1 Volt peak amplitude. “High” sensitivity range blocks input signals of up to 10 Volt peak amplitude. The sensitivity potentiometer allows fine adjustment of the filter threshold within the chosen range. The purpose of the input filter is to block low-level electrical noise from the input of the device.

The presence of noise makes it harder for the unit to recognize the input frequency. Ideally, the filter is adjusted to block the low-level electrical noise, allowing only the desired input signal to be sensed by the signal conditioner.

Also Read: Top 100 Instrumentation Engineers Questions & AnswersIndicators

What is a loop powered indicator?

Loop powered indicators were designed for field (outdoor) use and have operating characteristics similar to two-wire transmitters. Like two-wire transmitters, they use a 4-20mA signal for power. Therefore, they are very low power devices which are ideal for hazardous environments as well. They typically use a liquid crystal display (LCD) for indication and are very easy to use since they can easily be included in a 4-20mA loop, requiring only a few volts (1 to 4V) of loop drive.General Signal Conditioning

What is the difference between “unipolar” and “bipolar”? A unipolar signal is zero based, such as: 0-10 Volts, 0-5 Volts, and 0-20 milliamps. A bipolar signal is negative as well as positive, such as: -10 to 10 Volts, -5 to 5 volts and -20 to 20 milliamps.

How do I connect several devices to the same signal?If the signal is a voltage signal the devices must be connected in parallel. It is desirable to know the input impedance of each device. Connecting devices in parallel decreases the total impedance. The current drive of the device providing the voltage signal cannot be exceeded if accurate signals are expected. Most 0/10 V output sourcing devices have a drive of 10 mA which translates (using Ohm’s Law: V=IR) to a minimum load of 1000 Ohms. It may become necessary to use an isolator as a voltage repeater. Voltage input devices should have a high input impedance, >100,000 Ohms.

If the signal is a current signal the devices are connected in series. It is critical to know the total input impedance of all the devices. Connecting devices in series increases the total impedance. The voltage drive of the current loop is another critical piece of information. Most current loops installed today are 4/20 mA. A typical current loop will have a voltage drive of 12 V which translates (using Ohm’s Law) to a maximum loop resistance of 600 Ohms. Current input devices typically have low input impedances, the lower the better. Many controller input devices have 250 Ohm input impedance. Action Instruments current input devices are even lower, typically 10-20 Ohms.

How do I convert a 0-5A AC signal coming from a current transformer (C/T) to a 4-20mA signal, None of your products accept a 5A AC input? A shunt resistor must be used. Action offers a a 0.1 Ohm shunt resistor, model C006. Connecting the shunt resistor in series with the C/T’s output, the 5 A signal is converted to a 500 mV AC signal via Ohm’s Law. This 500 mV AC signal becomes the input to an AC input signal conditioner.

What are standard output signals for signal conditioners? First 10-50mA, then 4-20mA became the industry standard signal for process control. The primary advantages of the 4-20mA signal is the “live zero” which refers to the 4mA minimum (0% of full scale) and the fact that current signals have a high immunity to induced noise. The live zero is an advantage in the case where signal wires might be damaged. If there were as open circuit no current would flow (e.g. 0mA or -24% of full scale) and an operator would be sure to recognize a problem, versus the case

where a 0-10V signal is used and an open circuit would produce 0V (or an intermediate value) which might be mistaken for 0% of full scale.

Regarding noise, the physical principals of electromagnetics prove that voltage signals and high impedance voltage input instruments are much more susceptible to noise generated by radio transmitters or electric motors and power lines than current signals and their low input impedance instruments. Other popular signal levels are 1-5V and 2-10V which are the result of 4-20mA current signals and 250 Ohm and 500 Ohm load resistors, respectively.Questions & Answers on Temperature Classification

What is Temperature Classification? Temperature classification (also known as temperature class, or T class) defines the maximum surface temperature that a product destined for use in a potentially hazardous atmosphere is allowed to operate at, relative to an ambient temperature of -20°C to +40°C.

According to the type of protection used on the product e.g. Exd, Exe etc, the temperature corresponds either to the maximum temperature of the external surface of the product, or to the maximum temperature of the internal surface of the product. Generally, Temp-class is based on fault conditions or, at the very least, worst case normal operating conditions.

Why is Temperature Class Important?

All flammable gases have an auto-ignition temperature. If a flammable mixture of the gas is exposed to a component above the auto-ignition temperature then the mixture will ignite. Therefore, when selecting equipment, the Temperature class must be below the auto-ignition temperature of the potentially explosive atmosphere where it will be installed.

If several different flammable materials may be present within a particular area, the material that gives the lowest auto ignition temperature dictates the overall area classification.

T-Class and Equipment Marking The ATEX directives typically require all products certified suitable for use in a hazardous area, e.g. instruments, enclosures, luminaries etc to be marked with their temperature class. Look out for a T number at the end of the protection concept marking on the product’s label e.g. EEx de IIB T3 indicates that this explosion proof apparatus has a temperature classification of T3 which corresponds to a maximum surface temperature of 200°C.

Temperature Class for Group I Applications “T” classes do not apply to group I applications. Equipment for use in the mining industry has either a rigid 150°C or 450°C limit.Questions & Answers on Cable Glands

Why Do We Use Cable Glands? – To firmly secure cable entering a piece of equipment

– To maintain the ingress protection of the piece of equipment (minimum of IP54 for ‘e’ and ‘n’ type enclosures. Where the enclosure wall thickness is less than 6mm a sealing washer or thread sealant will be required to maintain IP54 protection) – To maintain earth continuity between a piece of equipment and any armouring in the cable – To ensure containment of an internal explosion in flameproof equipment

Is There a British Standard for Cable Glands? The Code of Practice for selection, installation and inspection of cable glands used in electrical installations is covered in BS 6121-5 1989 Mechanical cable glands.

Selecting Cable Glands Items to consider when selecting a cable gland for a particular installation include: – Possibility of electrolytic action between the gland and the enclosure. Shortened lifetime for the glands and the cable entries can result if incompatible materials selected. The most common materials used are brass, stainless steel and plastic. Material choice will influence cost. – Degree of Ingress Protection required. See our page on IP ratings. – Certification of gland for use in Hazardous areas – Normal or barrier gland required – Size of cable being terminated

– Size of cable entry on piece of equipment

What is a Barrier Gland? Barrier glands are similar to normal glands, except a compound sealant material is used to ensure the inside of the cable is gas tight as well as the outside.

When Should a Barrier Gland be Used? BS EN60079-14 Electrical Apparatus for Explosive Gas Atmospheres Part 14 – Electrical Installations in Hazardous Areas (other than Mines) provides a selection process for deciding if a barrier gland is required. There are various options to consider, however if the hazardous gas require IIC apparatus, or if the volume of the enclosure is greater than 2 litres then it is likely you will need to use a barrier gland. IIC apparatus is generally associated with Hydrogen.

Cable Gland Sizing A rough gland sizing table is provided below, however reference should be made to the British Standard referenced above.

Questions & Answers on Relief Valve Orifice Sizes

What is a Relief Valve?

Relief Valves are mechanical devices designed to operate if an over-pressure situation occurs – they are used to safeguard the plant. Generally, they are the last line of defence; following on from ESD and operator intervention.

So what is a Relief Valve orifice? The American Petroleum Institute has developed a series of inlet size, orifice, outlet size combinations for various pressure classes of flanged relief valves. These combinations have been widely adopted by engineers throughout the oil and gas and allied industries. Central to these combinations are a series of fourteen standard orifice sizes each denoted by a letter ranging from D through to T. Each letter refers to a specific effective orifice area.

What do the orifices denote? The valve sizing engineer (usually a process or instrument engineer) determines the controlling relieving rate from all possible scenarios, then the required relief valve orifice size is determined using the appropriate equation given in API. Knowing the required relief valve orifice size, an actual orifice size equal to or greater than the calculated orifice size is chosen from a the standard range. The maximum flow through this actual orifice will be the valve’s capacity.

What are the standard orifice sizes? The full list of letters and corresponding effective area is shown below

CONTROL ROOM Q & A

Q: What is cable tray? Its type? Its size? Its support? Cable tray is nothing but the way or media through which we lay the field cables in plant. There are two basic types 1) Ladder type(made in Rungs type construction) 2) Perforated Type(Solid sheath consist of Holes for ventilation). Basically discussing about tray support than we could say it depends on the site conditions. Only care has to be taken considering adequate space for laying cable, considering their bends.Etc.

Q: How to decide cable tray size? According to the no. of cable occupancy in the cable tray and available tray size we have to choose it. they are available in foll. types 80,150,300,450,600 & 900.

Q: What is meant by instrument location & JB location? This consist of Instrument location considering the piping drawing given from Piping dept. We identifies the locations of the instrument in the equipment layouts and put the bubbles and elevation and JB nos for the location. Same way depending upon the accessibility we decide the location of JB and marking of it into the instrument location plan is JB location. There is no need to make a different drawing for this.

Q: While locating Instrument & JB which things we have to consider? Transmitter : Tube routing, maintenance area, man approach, Valve : Hand wheel operations, Maintenance area, Etc. Loop power indicators: Man approach Illumination from Electrical if instrument is not going to provide.

Q: What is the use for cable entry in control room? (sleeves & MCT) In the process plant Control room built considering the non-hazardous area. So in case if fire/Explosion takes place in the plant than that has to be restricted from entering into the control room. So MCT(Multiple cable transient) blocks are used. They are designed to sustain the fire for a fixed time duration. That block hold the cables which are entering into the CCR.

Q: What are Analog Input/output & Digital Input/output? 4-20 mA signals from instrument (transmitters) are analog input to control system. 4-20 mA signals to instrument (I/p & electro pneumatic positioner) are analog output from control system.

Q: Volt free (24V) contact (NO/NC) by instruments (all type of switches, ex. Limit switch, press,temp,flow,level switch) are digital input to control system. All powered signals (24V,48V,110V….) from system to instruments (SOV) are Digital outputs.

Q: Types of instrument cables? IS cables & NIS cables IS – Intrinsic safety & NIS – Non Intrinsic safety Which cable to use, depends upon hazards condition.

Q: Instrument JB’s? Instrument JB’s depend upon hazards area classification. JB’s also can be IS or NIS For IS signal IS JB’s used for NIS signal NIS JB’s used For analog I/p & o/p signal we can use same JB. But for Digital I/p & o/p we have to use separate JB’s. Because digital outputs are powered signal, by wrong connection there may be chances to damage the card. For DCS I/p & o/p and PLC I/p & o/p we used separate JB’s.

Q: What is open loop & close loop? OPEN LOOP : This is nothing but to sense the process signals from the field and to send it to the control room for operator observation. CLOSE LOOP : This is measuring the process signals for operator’s action. Means Tx sense the process and send it to the control room. Where the operators takes action i.e. control action and that given to the final control element as per the process requirement.

Q: What is DCS & PLC?

Distributed control system(DCS) and Programmable logic controller. These are the control systems which handles fields I/Os. Basic difference between DCS & PLC is 1) DCS handles more nos of I/Os rather than PLC. 2) PLC is faster system than DCS. 3) DCS can handles handsome quantity of I/Os so that can be used for total plant automation. Where as PLC has own limitations so it generally used for small but for important(Safety point of view) units, like boiler automations, Make-up compressor automations Etc. 4) In the above mentioned case the these PLC’s can be get connected with the DCS with the help of soft link. Generally this is used to make alert to both the operator. 5) As I heard the PLC used to handle the DI/DO signals so it can take fast actions. Some of the time it is used to handle few nos of AI/AO. 6) DCS & PLC’s speed depends on the scan rate of I/Os. 6) For both the system Marshalling panels, Consoles and other faculties of Ethernet Etc can be used according to the need. 7) According to the Cause and effects diagrams the System programmer assigns the control action block into the system, we can call them as memory assigning.

Q: While making Datasheets which things are to be considered? Basically it depends on the instrument item for which you are preparing the datasheet. As an Example. Temperature Element. We have collect following information to prepare D/s.

Q: What is potential free contact? What is the significance and application of this contact?

Contacts having not potential. E.g. Relay contacts/ field switches contacts. They are used in logic circuits. A potential free contact is usually wired into an electrical circuit. However it must be

ensured that the contact ratings are suitable for the service in which it is used.

Q: In split range control, whether the signal is splitted through I/P convertor or the convertor itself?

This can be typically achieved by two ways:

By connecting o/p of one I/P converter to two positioners adjusted suitably for split range operation of control valves. Taking two AO from DCS. Split range to be defined in DCS. Both I/P converters and positioners to be calibrated with input as 4to20 ma dc and 3to15 psi respectively.

Q: When do we use SOV of rating 110vac and 110vdc?

Primarily depends upon the availability of reliable power supply source.

Q: How is cold junction compensation in thermocouple carried?

This is typically performed in modern programmable instruments by means of measuring actual reference junction temperature using a temperature sensor mounted close to the ref. junction and compensating for the same using appropriate look-up table stored within the instrument’s memory.

Q: In which applications do we use 4 wire RTD?

Three wire is a better alternative. Primary objective of 3-wire and 4-wire arrangements is to eliminate effects of lead resistance on temp. measurement.

Q: What is the sensor used in coriollis mass flow meter to measure density?

Density is measured here by measuring the resonant frequency of a vibrating U-tube.

Q: What if thermocouple wire is opened in the field? What signal goes to DCS?

In most modern instruments the signal may be programmed to go to either maximum or minimum depending upon end user’s requirement.

Q: if the power supply connections to a two-wire transmitter get interchanged? What signal will go to DCS?

Usually there is a blocking diode to protect the transmitter against supply reversal and almost zero current signal should be transmitted.

Q: What are the possible reasons for the failure of barrier? !?!

Fuse blowing sometimes. Power circuits are most likely to fail.

Q: How can we say that the given RTD or Thermocouple is correct?

We can only measure sensor output (resistance / maillots ) accurately and look-up corresponding temperature in reference tables. The accuracy depends upon quality / condition of the sensor. Degraded sensors may not give accurate readings and must be replaced. To test a sensor, the sensor response may be tested using a high quality temperature calibrator and compared with reference tables.

Q: In some cases we have to select the cam position in a control valve for different application? How do we select that?

Refer to instruction manual for the positioner / control valve. The cams are often marked with limited amount of information, which may help an experienced person.

Q: What is the difference between a protocol and a field bus?

A protocol defines a standard method for communications. A fieldbus is a multidropping arrangement where multiple instruments communicate with special interface hardware using the same pair of wires and in most of the cases draw power from the same pair of wires.

Q: What happens if transmitter wires get shorted?

The barrier if installed limits electrical energy flowing into hazardous area. If there is no barrier, typically a fuse in the power distribution system will blow.

Q: What will happen if thermocouple wires get shorted?

A cold junction compensated instrument will typically indicate temperature of the location where the T/C wires are shorted.

Q: Why do we require loop-terminating resistor in any digital communication loop?

A minimum loop resistance is required so that modulated current signal produces a modulated voltage signal, which may be detected by the receiving equipment.

Q: What is adapter flange?

It is a transmitter part for allowing process connection to pipe/tube.

Q: How to calculate the safe distance between cables to avoid electromagnetic interference of each other ?

The design engineers / equipment manufacturers follow/publish certain guidelines w.r.t. different types of cables and the voltages/currents and types of signals carried by them.

Q: How Control loop should be tuned in process loop?

You may use Ziegler-Nichol’s method ( open loop / closed loop ) or special tuning software tools.

Q: What is the significance of single ended & differential ended input for PLC? Application wise comparison of these two types of inputs?

Differential inputs provide better common mode rejection and signal-to-noise ratio.

Q: What is Ground Loop? Preventive steps to avoid ground loop?

When ground wiring is not done properly, grounding of various points is not effective and potential differences exist between

them resulting in currents flowing between them. This leads to measurement errors and is not desirable. It can be eliminated by proper ground wiring.

Q: In a globe type control valve, what is the importance of flow direction (top to bottom or bottom to top)?

Control valves must be installed as per direction marking provided by the manufacturers or instruction manuals. Though people tend to generalize, this is often misleading.

Q: What is ATEX directives / FM Approval / CSA approved / CE certified ? What is the importance of individual certification? Are all these certification required for each instruments? Which certification do we prefer?

ATEX/FM/CSA certifications generally refer to certification for suitability of instruments for use in hazardous area when installed in accordance with recommended guidelines. Any certification, which is locally acceptable as per statutory requirements, may be used. We typically accept American/European/Indian certifications/approvals in India.

Q: Advantages of tachometer as speed measuring device compared to inductive type proximity switches?

Some tachometers provide analog output with almost instantaneous response time. They are highly suitable for speed control in some applications.

Q: Application wise advantages of Inductive type proximity switches over capacitive type switches?

Inductive proximity switches are better suited for detection of conducting metal objects and are easily tested for proper operation. Capacitive switches are typically used for detecting non-conductive materials. Questions & Answers on Dew Point in Compressed AirWhat is dew point?

Dew point temperature is a measure of how much water vapor there is in a gas. Water has the property of being able to exist as a liquid, solid, or gas under a wide range of conditions. To understand the behavior of water vapor, it is first useful to consider the general behavior of gases.

In any mixture of gases, the total pressure of the gas is the sum of the partial pressures of the component gases. This is Dalton’s law and it is represented as follows:

Ptotal = P1 + P2 + P3 …

The quantity of any gas in a mixture can be expressed as a pressure. The major components of air are nitrogen, oxygen, and water vapor, so total atmospheric pressure is composed of the partial pressures of these three gases. While nitrogen and oxygen exist in stable concentrations, the concentration of water vapor is highly variable and must be measured to be determined.

The maximum partial pressure of water vapor is strictly a function of temperature. For example, at 20 °C (68 °F), the maximum partial pressure of water vapor is 23.5 mbar. The value of 23.5 mbar is said to be the “saturation vapor pressure” at 20 °C (68 °F). In a 20 °C (68 °F), “saturated” environment, the addition of more water vapor results in the formation of condensation. This condensation phenomenon can be exploited to measure water vapor content.

Gas of unknown water vapor concentration is passed over a temperature-controlled surface. The surface is cooled until condensation forms. The temperature at which condensation forms is called the “dew point temperature.” Because there is a unique correlation between temperature and saturation vapor pressure (remember, the maximum partial pressure of water vapor, also known as saturation vapor pressure, is strictly a function of temperature), measuring the dew point temperature of a gas is a direct measurement of the partial pressure of water vapor. Knowing the dew point temperature, the corresponding saturation vapor pressure can be calculated or looked up. The following table shows some values for temperature and the corresponding saturation vapor pressure:

What is the difference between dew point and “pressure dew point?”

The term “pressure dew point” is encountered when measuring the dew point temperature of gases at pressures higher than atmospheric pressure. It refers to the dew point temperature of a gas under pressure. This is important because changing the pressure of a gas changes the dew point temperature of the gas.What is the effect of pressure on dew point?

Increasing the pressure of a gas increases the dew point temperature of the gas. Consider an example of air at atmospheric pressure of 1013.3 mbar with a dew point temperature of -10 °C (14 °F). From the table above,

the partial pressure of water vapor (designated by the symbol “e”) is 2.8 mbar. If this air is compressed and the total pressure is doubled to 2026.6 mbar, then according to Dalton’s law, the partial pressure of water vapor, e,

is also doubled to the value of 5.6 mbar. The dew point temperature corresponding to 5.6 mbar is approximately -1 °C (30 °F), so it is clear that increasing the pressure of the air has also increased the dew point temperature of the air. Conversely, expanding a compressed gas to atmospheric pressure decreases the partial pressures of all of the component gases, including water vapor, and

therefore decreases the dew point temperature of the gas. The relationship of total pressure to the partial pressure of water vapor, e, can be expressed as follows:

P1/P2 = e1/e2

By converting dew point temperature to the corresponding saturation vapor pressure, it is easy to calculate the effect of changing total pressure on the saturation vapor pressure. The new saturation vapor pressure value can then be converted back to the corresponding dew point temperature. These calculations can be done manually using tables, or performed by various kinds of software.

Why is knowledge of dew point in compressed air important?

The importance of dew point temperature in compressed air depends on the intended use of the air. In many cases dew point is not critical (portable compressors for pneumatic tools, gas station tire filling systems, etc.).

In some cases, dew point is important only because the pipes that carry the air are exposed to freezing temperatures, where a high dew point could result in freezing and blockage of the pipes. In many modern factories, compressed air is used to operate a variety of equipment, some of which may malfunction if condensation forms on internal parts. Certain water sensitive

processes (e.g. paint spraying) that require compressed air may have specific dryness specifications. Finally, medical and pharmaceutical processes may treat water vapor and other gases as contaminants, requiring a very high level of purity.What is the typical range of dew point temperatures to be found in compressed air?

Dew point temperatures in compressed air range from ambient down to -80 °C (-112 °F), sometimes lower in special cases. Compressor systems without air drying capability tend to produce compressed air that is saturated at ambient temperature. Systems with refrigerant dryers pass the compressed air through some sort of cooled heat exchanger, causing water to condense out of the air stream. These systems typically produce air with a dew point no lower than 5 °C (41°F). Desiccant drying systems absorb water vapor from the air stream and can produce air with a dew point of -40 °C (-40 °F) and drier if required.What are the standards for the quality of compressed air?

ISO8573.1 is an international standard that specifies the quality of compressed air. The standard defines limits for three categories of air quality:Maximum particle size for any remaining particlesMaximum allowable dew point temperatureMaximum remaining oil content

Each category is given a quality class number between 1 and 6 according to the reference values shown in the table below. As an

example, a system that conforms to ISO8573.1 and is rated for class 1.1.1 will provide air with a dew point no higher than -70 °C (-94 °F). All remaining particles in the air will be 0.1 µm or smaller, and the maximum oil content will be 0.01 mg/m3. There are other standards for compressed air quality, such as ANSI/ISA- 7.0.01-1996 for instrument air.

How is dew point in compressed air reliably measured?Some principles of dew point measurement apply to all types of instruments, regardless of manufacturer:Select an instrument with the correct measuring range:Some instruments are suitable for measuring high dew points, but not low dew points. Similarly, some instruments are suitable for very low dew points but are compromised when exposed to high dew points.Understand the pressure characteristics of the dew point instrument: Some instruments are not suitable for use at process pressure. They can be installed to measure compressed air after it is expanded to atmospheric pressure, but the measured dew point value will have to be corrected if pressure dew point is the desired measurement parameter.Install the sensor correctly: Follow instructions from the manufacturer. Do not install dew point sensors at the end of stubs or other “dead end” pieces of pipe where there is no airflow.

Top 100 Instrumentation Engineering Questions & Answers

11Q & ADecember 26, 2015 A+A-EmailPrint List any four objectives of process control.

Suppressing the influence of external disturbances, Optimizing the performance, Increasing the productivity, Cost effective.Define process

Any system comprised of dynamic variables usually involved in manufacturing and production operations. It is defines as a series of operations during which some materials are placed in more useful state.What is manipulated variable

It is a variable which is altered by the automatic control equipment so as to change the variable under and make it conform with the desired value.Define Controlled variable

It is the quantity of control system which is directly measured and controlled.What do you mean by self regulation?

The output will move from one steady state to another for the sustained change in input. This means that for change in some input variable the output variable will rise until it reaches a steady state (inflow = outflow). It is the tendency of the process to adopt a specific value of controlled variable for nominal load with no control operations.Why do we need mathematical modeling of process?

The physical equipment of the chemical process we want to control have not been constructed. Consequently we cannot experiment to determine how the process reacts to various inputs and therefore we cannot design the appropr iate control system. If the process equipment needs to be available for experimentation the procedure is costly. Therefore we need a simple description of how the process reacts to various inputs, and this is what the mathematical models can provide to the control designer.Name different test inputs.

Step, Ramp, Impulse, Sinusoidal, Pulse inputsName a process giving inverse response

Drum boiler system, in which the flow rate of the cold feed water is increased by a step the total volume of the boiling water and

consequently the liquid level will decreased for a short period and then it will start increasing.Define interacting system and give an example.

Load changes in first process affects the second process and vise versa when both are connected in series nature is called interacting system. Eg. Two level tanks are connected in series.A tank operating at 10ft head, 51pm outflow through a valve and has a cross section area of 10 sq f calculate the time constant.

T=R/A, R=H/Q=10/(5X5.885X10-4)What is meant by non-self regulation?

A system that grows without limit for a sustained change in input (constant outflow or outflow independent of inflow condition).Write any two characteristics of first order process modeling

The smaller the value of time constant the steeper the initial response of the system. A first order lag proce ss is self regulating the ultimate value of the response equal to Kp (steady state gain of the process) for a unit step change in the input.Distinguish between continuous process and batch process.

A process in which the materials or work flows more or less continuously through a plant apparatus while being treated is

termed as continuous process. The problem of continuous process is due to load changes. (e.g.) storage vessel control.

A process in which the materials or work are stationary at one physical location while being treated is termed as batch process. (e.g.) furnace.Explain the function of controller.

The element in a process control loop that evaluated error of the controlled variable and initiates corrective action by a signal to the controlling variable.What is the purpose of final control element?

Components of a control system (such as valve) is used to directly regulates the flow of energy or materials to the process. It directly determines the value of manipulated variable.Define Process control

It is the scheme that describes how much the manipulated variable should change inorder to bring the controlled variable back to the setpoint.List the two types of process control.

Direct process control

– Controlled variable directly indicates the performance of the process Eg. Water heater system

InDirect Process control the performance of the process.

– Controlled variable indirectly indicates Eg. AnnealingWhat is Servo operation and Regulatory operation.

If the purpose of the control system is to make the process follow the changes in setpoint as quick as possible, then it is servo operation.What is mathematical modeling.

Set of equations that characterize the process is termed as Mathematical Modelling.Define an non-interacting system.

The dynamic behaviour one tank is affected by the other, but the reverse is not true, then it is non-interacting system. Here the liquid heads are independent of each other.Define an interacting system.

The dynamic behavior one tank is affected by the other, but the reverse is also true, then it is non-interacting system. Here the liquid heads are dependent of each other.

Mention two drawbacks of derivative action

(i) The output of controller is zero at constant error condition.

(ii)It will amplify the noise present in the error signal.What are the steps involved to design a best controller?

Define appropriate performance criterion (ISE, IAE, ITATE). Compute the value of the performance criterion using a P, PI, or PID controller with the best setting for the adjusted parameters Kp, Ti, Td. Select controller which give the best value for the performance criterion.Define proportional control mode

A controller mode in which the controller output is directly proportional to the error signal P=Kpep+p0 P-controller output Kp= Propotional gain, ep=error in percent of variable range, P0-Bias.Define proportional band.

Proportional band is def ined as the change in input of proportional controller mode required to produce a full-scale change in outputWrite the relation ship between proportional band and proportional gain

The reciprocal of gain expressed as a percentage is called proportional band. Kp=100/PBDefine offset.

It is the steady state deviation (error) resulting from a change in value of load variable.Define error (deviation)?

It is the difference at any instant between the value of controlled variable and the set point. E=S.P-P.VSketch Pneumatic P+I controller

Refer Curtis Johnson, Page No.418, and Fig. 10.17.Why is the electronic controller preferred to pneumatic controller?

Electronic signals operate over great distance without time lags. Electronic signals can be made compatible with digital controllers. Electronic devices can be designed to be essentially maintenance free. Intrinsic safety techniques eliminate electrical hazards. Less expensive to install. More energy efficient. Due to the above said properties electronic controllers are preferred to pneumatic controller.Explain the function of controller.

The element in process control loop that evaluates error of the controlled variable and initiates corrective action by a signal to the controlling variable.Write any two limitations of single speed floating control.

The present output depends on the time history of errors and such history is not known, the actual value of controller output floats at an undetermined value. If the deviation persists controller saturates at either 100% or 0% and remain there until an error drives it towards opposite extreme.Sketch the input – output characteristic of single – speed floating controller.

Refer Curtis Johnson, Page No. 368, and Fig.9.7.Why derivative mode of control is not recommended for a noisy process?

The series capacitor in the derivative controller will amplify the noise in the error signal.Define integral (reset) windup?

The over charging in the presence of a continuous error of the integral capacitor which must discharge through a long time constant discharge path and which prevents a quick return to the desired control point.What are the two modes of controller.

Discontinuous and continuous mode are the two modes of controller.Define Discontinuous mode of controller

If for only two values of error, control action is taken, it is Discontinuous mode of controller.Define Continuous mode of controller

If for every value of error, control action is taken, it is Discontinuous mode of controller.Give an example for Discontinuous and Continuous mode of controller.

Discontinuous-ON-OFF controller.Define cycling.

Oscillations of error about zero is called cycling.Define controller turning.

Deciding what values to be used for the adjusted parameters of the controller is called controller turning.What is reaction curve.

In process controller, the reaction curve is obtained by applying a step change (either in load or in set point) and plotting the response of the controlled variable with respect to time.What performance criterion should be used for the selection and turning of controller?

Keep the maximum error as small as possible. Minimize the integral of the errors until the process has settled set Point.Define ultimate gain

The maximum gain of the proportional controller at which the sustained oscillations occur is called ultimate gain (Ku).What is ITAE and when to go for it?

ITAE means Integral Time Absolute Error. To suppress the errors that persist for long time, the ITAE criterion will tune the controllers better because the presence of large t amplifies the effect of even small errors in the value if integral.What are the parameters required to design a best controller?

Process Parameters (K,ô), Controller parameters (Kp,Ti, Td),performance creation (ISE, IAE, IATE)Write any tow practical significance of the gain margin

It constitutes a measure of how far the system is the brink of instability. Higher the gain margin (above the value of one), the higher the safety factor we use controller turning.

Typically, a control designer synthesizes a feedback system with gain margin larger than 1800.Why is it necessary to choose controller settings that satisfy both gain margin and phase margin?

The gain margin and Phase margin are the safety factors which is used for the design of a feedback system. Beyond the phase margin and gain margin the system goes to unstable position.What is turning a controller based on quarter – decay ratio?

It is the procedure in which adjusting the proportional gain of controller upto ¼ th decay ratio waveform is obtained.Name the time integral performance criteria measures.

Integral Square Error (ISE), Integral of absolute value of error (IAE), Integral of time weighted absolute error.Define Integral Square Errors (ISE)

If we want to suppress large errors, ISE is better than IAE Because errors are squared and contribute more to the value of integral.Define Integral Absolute Errors (IAE)

If we want to suppers small errors, IAE is better than ISE Because when we square small numbers, they even become smaller.Define Integral of Time weighted Absolute Error (ITAE)

To suppress errors that persist for long times, ITAE criterion will tune the controllers better because the presence of large t amplifies the effect of even small errors in value of integral.Define One-quarter decay ratio

It is reasonable trade off between fast rise time and reasonable setting time.Give the satisfactory control for gas liquid level process.

Proportional Control is the satisfactory control for liquid level process.Give the satisfactory control for gas pressure process.

Proportional Control is the satisfactory control for liquid level process.Give the satisfactory control for vapour pressure process.

PI Control is the satisfactory control for vapour pressure process having fast response.Give the satisfactory control for temperature process.

PID Control is the satisfactory control for temperature process.Give the satisfactory control for composition process.

PID Control is the satisfactory control for composition process.Define ratio control

Ratio control is a special type of feed forward control where two disturbances are measured and held in a ratio to each other.Define cascade control

Cascade control is defined as a control system composed of two loops where the set point of one loop (the inner loop) is the output of the control ler of the other loop (the outer loop)When cascade control will give improved performance than conventional feedback control?

In some process the secondary variables in it introduce disturbance throughout the system is measured and controlled by a separate loop.Explain the purpose of cascade control for heat exchangers?

In heat exchangers, the control objective is to keep the exit temperature of stream. But the flow rate of the stream creates the low disturbance throughout of its a function. The secondary loop is used to compensate the flow rate of the stream.What is meant by auctioneering control?

Such control configurations select among several measurements the one with the highest value and feed it to the controller. Thus it is a selective controller which possesses several measured outputs and only one manipulated input.Give any two types of selective control system.

Override control for the protection of process equipment, auctioneering control.What is limit switch?

In some cases it is necessary to change from the normal control action and attempt to prevent a process variable from exceeding an allowable upper or lower limit. This can be achieved b y the use of special t ype switches called limit switches.Mention the types of limit switches.

High Select Switch (HSS), Low Select Switch (LSS).What is HSS?

High Select Switch (HSS) is a limit switch which is used whenever a variable should not exceed an upper limit.What is LSS?

Low Select Switch (LSS) is a limit switch which is used whenever a variable should not exceed an lower limit.

What is override control?

During the operation of the plant, it is possible that some of the process variables exceed the limit. In such cases it is necessary to change from the normal control action and attempt to prevent a process variable from exceeding an allowable an allowable upper or lower limit. This can be achieved by the use of special type switches called limit switches called limit switches (HSS and LSS). This type of protective control is called override control.What is split-range control?

To control A single process output can be controlled by co-coordinating the actions of several manipulated variables all of which have same ef f ect on controlled output. Such systems are called split-range control systems.Differentiate split-range control and selective control.

Split-range control system involves one measurement and more than one manipulated variables but sele ctive control system involves one manipulated variables and several controlled outputs.Why are fuel and air sent at a specified ratio into a combustion chamber?

To obtain the most efficient combustion.What are decouplers?

The special element introduced in a system with two strongly interacting loops to cancel the interaction effect between the two loops and thus render two non-interacting control loops is called decoupler.When is inferential control used?

It is used in some cases where the output of the process and the influence of the disturbance cannot be measured.What are the advantages of feed forward controller

Acts before the disturbance is felt by the process. It is good for slow systems.What are the disadvantages of feed forward controller

Requires identification of all possible disturbances and their direct impact. Cannot cope with unmeasured disturbances.What are the advantages of feedback controller.

It does not require identification and measurement of disturbance.What are the disadvantages of feed forward controller

It is unsatisfactory for slow processes with significant dead time.What is flashing in control valve?

When a liquids enters a valve and the static pressure at the vena contracta less than the fluid vapour pressure and the valve outlet pressure is also less the fluid vapour pressure the condition called flashing exists.When do you use a valve positioner?

If the diaphragm actuator does not supply sufficient force to position the valve accurately and overcome any opposition that flowing conditions create a positioner may be required.Give two examples for electric actuator

Motor, Solenoids.What is the need of I/P converter in a control system?

In some process loop the controller is electronic and the fin al control element is electronic one. To interconnect these two we need a device that should linearly converts electric current in to gas pressure (4-20mA-315 psi). such device is called I/P converter.Why installed characteristics of a control valve is different from inherent characteristics?

Inherent characteristics is which the valve exhibits in the laborator y condition where the pressure drop is held constant. Installed or resultant characteristics is the relationship between flow and stroke when the valve is subjected to pressure conditions of the process.

Explain the function of pneumatic transmission lines.

Used to transmit the input signals into standard instrumentation pneumatic output signals (3 to 15 psi or 20 to 100 KPa).What is the purpose of final control element.

Components of a control system (such as valve) is used to directly regulates the flow of energy or materials to the process. It directly determines the value of manipulated variable.What is meant by cavitations in control valve?

When a liquid enters a valve and the static pressure at the vena contracta drops to less than the fluid vapor pressure and the recovering to above fluid vapour pressure, this pressure recovery causes an implosion or collapse of the vapour bubbles formed at the vena contracta. This condition is called cavitation.What is “equal percentage” in the equal percentage valve?

For equal incre ment of stem travel at constant pressure drop an equal percentage change in existing flow occurs.What are the characteristics of control valve?

Inherent characteristics, Installed characteristics.Differentiate inherent characteristics and installed characteristics.

Inherent characteristics is which the valve exhibits in the laborator y condition where the pressure drop is held constant. Installed or resultant characteristics is the relationship between flow and stroke when the valve is subjected to pressure conditions of the process.What is “quick opening” control valve.

For smaller movement of the stem, there is maximum flow rate.What is “Linear” control valve.

If stem position varies linearly with flow rate, then it is linear.Define Control Valve sizing.

Q=Cv.sqrt(P/Sg) Q-Flow rate

Cv-Valve coefficient

P-pressure difference across valve. Sg-Specific gravity of liquid.Name any one final control element.

Control Valve.What is the function of control valve in a flow control system.

The function of control valve in flow control system is to regulate the flow.Name one application of electrical actuator

Solenoid coil used to change gears.Name the two types of plugs.

Single-seated and double-seated plug type control valves.Define RangeabilityIt is the ratio of maximum controllable flow to minimum controllable flow.100. What is rotating shaft type control valves.Rotating-plug valvesButterfly valvesLouvers.

100 Instrumentation Basics0Q & ADecember 26, 2015 A+A-

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1) Define Viscosity.

It is a measure of fluidity of the system. Many fluids undergo continuous deformation with the application of shearing stress.

2) Define Newtonian fluids

If the force flow relation is linear then the fluid is Newtonian .

3) Define Non Newtonian fluids

If the force flow relation is non linear then the fluid is Newtonian .

4) Define Kinematic Viscosity.

Ratio of absolute viscosity to the density of the fluid.

5) Define Specific Viscosity.

Ratio of absolute viscosity of the fluid to the absolute viscosity of a standard fluid at the same temperature.

6) Define Relative Viscosity.

Ratio of absolute viscosity of the fluid at a given temperature to the absolute viscosity of a standard fluid at 20°c.

7) Define Viscosity index

It is an empirical number that indicates the effect of change of temperature on viscosity if a fluid.

8) Define fluidity.

It is the reciprocal of viscosity. It is unit is 1/ poise.

9) Define Humidity.

It is basically moisture content in air or it is the quantity of water vapour retained by gas.

10) Define Absolute Humidity.

Weight of water vapour in unit wait of gas. H=Wr / Wg

11) Define Specific Humidity.

It is weight of vapors in unit weight of mixture.

12) Define Relative Humidity.

This is the ratio of moisture content of gas to maximum moisture content of the gas at that temperature.

13) Define dew point.

This is the saturation temperature of the mixture at the corresponding vapour pressure. 14) Define various units of Humidity.

Vppm = parts per million / volume. G/ kg = weight concentration Relative humidity = in % Dew point in °C.

15) Define Hygrometer.

Used to measure the moisture content in air. It also used to measure humidity.

16) What is the basic principle of Hygrometer.

It consist of mechanical device measuring the dimension change of humidity sensitive materials like animal hair, animal membrane , paper etc.

17) Define Moisture.

Defined as the amount of water absorbed by solids or liquids.

18) What are the various methods of measurement of moisture.

Based on the weight of the particle

Based on the resistance, capacitance,

19) How will you find the % moisture present in the substances.

Mp = ( Wwet – Wdry ) / Wwet * 100

20) What are the different types of viscometer?

Say bolt viscometer Rotameter type Consistency meters.

21) What is Psychrometer?

Psychrometer is a device that uses the bulb thermometers to measure humidity. It is also used in air conditioning systems for maintaining humidity.

22) What are the different types of hygrometer?

Hair hygrometers, Wire electrode hygrometers, Electrolysis type hygrometers, Resistive type, Capacitive type Microwave reflector

23) Explain the principle of saybolt viscometer.

As the viscosity of the fluid varies , the flow rate and hence time taken to drain the fluid through the capillary tube varies. The time indicates the viscosity and is denoted by say bolt number.

24) What is meant by consistency?

General term for viscosity and more often used in connection with Non-Newtonian fluids.

25) Explain the principle of oscillating type consistency meters.

When the inner cylinder is given an axial sinusoidal motion through a mechanical drive rod, the fluid in the annular space gets a shearing force and the motion in the inner cylinder well to transmitted the magnitude of this transmission will depend on the consistency of fluid.

26) What are the units of velocity?

Feet per second (fsp)

Feet per minute (fpm)

Meters per second (mps)

27) Define Bernoulli equation.

In a given flow system, there is a relationship between pressure, fluid velocity, and elevation at any two points .

28) define Reynolds number.

Combination of density, viscosity of the fluid to a dimension describing length and the average fluid velocity.

29) Define rational expansion factor.

It is the ratio of compressible flow to the incompressible flow

30) What are the different types of orifice?

Concentric orifice

Eccentric Segmental

Quadrant edge

31) define Concentric orifice?

It has a circular hole in the middle and is installed in the pipe line with the hole concentric to the pipe. Its thickness depends upon pipe line size.

32) define eccentric.

It is installed in with the bore tangential to the upper surface of the pipe, it is used where the liquid contains a relatively high % of dissolved gases.

33) define segmental

its hole diameter is 98% of pipe diameter. It is installed with a curved section of the opening coincident with the lower surface of the pipe.

34) define quadrant

edges is rounded to form a quarter circle. used for the flow of heavy crudes and slurry and viscous flows.

35) What are the advantages of using venturi tube as a restriction element?

More suitable for slurry

Accurate

Calibrated easily

36) define pitot tube

It is an obstruction type primary element, used for fluid velocity measurement. Differential pressure across these taps is proportional to the velocity of the fluid.

37) What are the disadvantages of pitot tube?

They can become plugged with sediment and that the pressure difference sensed may not be large enough to give the desired accuracy for the flow rate under consideration.

38) What are the advantages of pitot tube?

No pressure loss

Economical

Some types can be easily removed from the pipe.

39) define stagnation point.

Fluid approaching the object starts losing its velocity till directly in front of the body where the velocity is zero. This point is known as stagnation point.

40) define dall tube

It is an obstruction type primary element, used for fluid flow measurement. It produces large differential pressure with low pressure loss.

41) mention the advantages of dall tube.

Slow head loss

Short lying length

Available numerous material of construction

42) mention the disadvantages of dall tube

pressure difference is sensitive to up stream disturbances

more straight pipe is required in the approach pipe line

43) what are sealing liquids commonly used?

Chloro naphthalene, dibutul phthalate, chlorinated oils.

44) what ae the different tapping of orifice?

Flange tape

Pipe tape Venacontracta tape

45) give the details about flange tape.

Located one inch either side of orifice plate.

Pressure difference is an integral part of the orifice.

46) give the details about pipe tape.

Located pipe diameter from the orifice.

Only the permanent pressure difference across the orifice is utilized.

47) give the details about vena contracta tape.

Down stream pressure tape is located variable distance from the orifice. Pressure difference is maximum for the given flow.

48) List the advantages of the orifice plate?

used in wide range of pipe sizes

used with pressure differential device.

Available in many materials

49) List the disadvantages of the orifice?

plate high permanent pressure loss

reduces the use in slurry services

accuracy depends on the care during installation.

It has the square root characteristics.

50) What are the different types of positive displacement meters?

Reciprocating piston type, Rotating vane type, Nutating disk type, Lobed impellar type, Oscillating piston type

51)List the advantages of reciprocating piston type

high accuracy

its construction material is not limited.

52) List the disadvantages of reciprocating piston

type high cost

subject to leakage

problems created by dirty particle

high maintenance cost

restricted to moderate flow rates

53) What are the major three methods of flow meters?

Area flow meter

Mass flow meter & Quantity meters

54) What are the different types of thermal flow meters?

Heat transfer flow meters

Hot wire flow meters

55) Name the different types of weighing methods

semiconductor feed belt weighing ( Batch weighing)

continuous conveyor scale

radio active transmission gauge

volumetric solid methods

56) Write any two points of calibration of flow meter

wet meter- manometer which is calibrated with mercury

dry meter- manometer which is calibrated with mercury

57) Explain the principle of turbine flow meter

when the liquid enter through inlet, due to the inflow, shaft rotates which cuts the magnetic pickup, and produces the voltage which is proportional to inflow of water.

58) What are the different types of mass flow meter?

Coriolis Mass Flow meter

Angular momentum type

Liquid bridge Calorimeter type

59) list the disadvantages of heat transfer flow meter

heat is directly placed in the fluid stream and easily damaged by corrosion large input power is required

60) List the advantages of turbine flow meter

good accuracy

excellent repeatability

low pressure drop & easy to maintain

good pressure & temperature range

compensation of viscosity variation

61) List the disadvantages of turbine flow meter

high cost

limited use for slurry application

62) List the advantages of rotary vane type

no pressure loss

high temperature & pressure

rating good accuracy

available numerous construction material

63) List the disadvantages of rotary vane

type high cost

accuracy decreases in increase of flow

64) List the advantages of lobed impellor

type increase accuracy at higher flow

rate leakage is decreased

can be used for corrosive

solids good capacity range

65) List the disadvantages of lobed impellor type

cost high & require frequent maintenance

66) List the disadvantages of glass Rotameter subject to breakage

It must mounted vertically

It limited to low temperature

Less accuracy

If pressure is greater than 35 kg/cm3 tube get damage

67) list the advantage of oscillating piston type

good accuracy

can be easily applied to automatic liquid batching system

good repeatability

moderate cost

68) list the disadvantage of oscillating piston type

available in small size

suitable for clean fluids

69) what is the principle of densitometer

float density less than the fluid density, level increases float moves up, resistance connected float varies, so output varies. Voltage output is proportional to the density of the fluid.

70) list the advantages of nutating disk type.

Less cost

Good accuracy

High temperature & pressure ratings

71) list the disadvantages of nutating disk type heavy

accuracy decreases in increase flow rate

72) what is Rotameter?

It is an example of variable area flow meter. When fluid enters lopped moves from the bottom to top. Distance is proportional to the flow rate.

73) Explain the principle of calorimeter flow meter

consist of two coil type resistance thermometer, difference of temperature between the thermometer is maintained constant.

74) List some example of inferential flow meter.

Turbine flow meters

Target flow meters

Ultrasonic flow meters

75) Explain Faraday’s law .

whenever a conductor cuts the magnetic field, an emf induced is equal to the rate at which the magnetic lines of force changes.

76) list the advantages of electromagnetic flow meter?

It can handle slurries & corrosive fluids

It has low pressure drop

It can be used as bi-directional meter Available in large pipe size & capacities

77) list the disadvantages of electromagnetic flow meter?

Expensive , Heavy and large size and Explosion

78) what are the different types of ultrasonic flow meters?

Doppler flow meter

Transit Time type meters

79) Explain the principle of vortex flow meter

it is based on vortex shedding which occurs when a gas or liquid flows around a non stream lined objects. When fluid flows pass an obstacle, boundary layers of slow moving fluid are formed along the outer surface of the obstacle and the flow is unable to follow contours of the obstacle of its downstream side.

80) What are the different methods of solid flow measurement?

Direct weighing system

Pneumatic method

Leakage flow technique

81) What are the advantages of solid flow measurement?

It is used for flow measurement upto 100 tonees/ hr

Accuracy is ±0.5 to ±0.75 of full scale deflection

82) What are the disadvantages of solid flow measurement?

For variation in size a correction factor is to be added.

83) list the applications of solid flow measurements

used in chemical & fertilizer industry

used in paper industry

mining & associated industry for sand, rock, cement, lime etc food processing unit.

84) explain the principle of hot wire anemometer

It is used for unsteady flow of gasses. Because of constant voltage wire gets heated. Heat loss changes due to change in viscosity of fluid.

85) Write any guide lines for the selection of flow meters?

In order to cover reverse flow, pulsating flow, response time and so on

Extreme applications such as corrosive, non conductive liquid with large solid content the list will probably consist of a single meter.

86) explain the principle of leakage flow technique to find the solid flow rate measurement

electrode is used as the capacitance detector. When a material flows this leakage field

changes and the capacitance increases. This increased capacitance detected at an interval depends on flow rate.

87) Rotameter is called variable area meter. Why?

The distance between the float and tapered glass varies. So area is also varying. So it named as variable area flow meter.

88) what are the advantages of using X- ray system?

It measures thickness with out contact with the material.

Well suited to measure thickness of sheet in rapid motion like rolling etc.

89) What are the uses of b-rays?

Used for thin metal sheets or foils, paper, rubber & plastics

90) What are the draw backs of using DC excitation in Electromagnetic flow meter?

Used for materials of low conductivity & flowing at slow speed.

DC amplifiers have many inherent problems

Output is quite small.

91) What are the advantages of using AC excitation in Electromagnetic flow meter?

High amplification

can be more reliably ,cheaply and easily done.

High speed and high conducitivty.

92) What is laminar flow?

Fluid particles move in a smooth fashion and tend to stray in layers. This layer like movement is called laminar flow.

93) What is turbulent flow?

Fluid velocity fast, particles also tends to have movement perpendicular to the over all the direction of flow, which is called turbulent flow.

94) define continuity equation.

It is the one of the most basic equation in flow calculations. It states that over all flow rate in the system is not changing with time.

95) What are the disadvantages of pitot tube?

They can become plugged with sediment and that the pressure difference sensed may not be large enough to give the desired accuracy for the flow rate under consideration.

96) What are the causes of pressure loss?

Due to friction, either with in the fluid or between fluid and boundaries. Fluid imparting (various fittings) on the objects.

97) List the direct level measuring methods.

Float type level indicator

Displacer type detector

Sight glass type.

98) List the indirect level measuring methods.

Hydrostatic measurement

Air purge system

Boiler drum system.

99) What are the advantages of sight glass level instrument?

Direct reading is possible.

Special designs are available.

Glass less devices are available in numerous material for corrosion resistance.100) What are the advantages of displacer level instrument?High accuracyReliable to clean liquidsMounted internally or externallyAdaptable to liquid interface measurement.

Foundation Fieldbus Interview Questions and Answers

0Communication, Q & AJanuary 24, 2016 A+A-EmailPrint What is FOUNDATION™ fieldbus (FF) technology?

The FOUNDATION™ fieldbus solution is a systemic technology comprised of a bi-directional communications protocol used for communications among field devices and to the control system. It uses a Function Block structure for true distributed control and Device Description (DD) technology for parameterisation and integration of data via a network hierarchy for subsystem integration and a well-defined system management structure for reliability and determinism of functional execution.Are there registered FF devices?

Yes. The Fieldbus Foundation registers a wide range of FF-compliant products from transmitters and meters to valve positioners, actuators, controllers and linking devices. These products are available from a wide variety of the world′s leading automation equipment suppliers. The online product catalogue (www.fieldbus.org) gives registered device information including which standard blocks were tested for interoperability, the

presence of untested Function Blocks (if any) and additional useful information about the device.What is FF H1?

The H1 Fieldbus is a bi-directional communications protocol used for communications among field devices and to the control system.What are the benefits of Fieldbus?

From a business viewpoint FF technology delivers savings in total installation costs. H1 Fieldbus reduces instrument wiring which in turn means less termination and fewer screwdriver turns. The technology reduces hardware requirements and lowers capital expenditures (CAPEX) whilst it also reduces operating expenses (OPEX) through improved plant efficiencies, better asset management and reduced maintenance requirements.

Specific benefits of Fieldbus technologies include reduced wiring; multi-variable information via a single multi-channel field instrument; simpler integration and easier maintenance. Ultimately, Fieldbus technology will be the key to greater manufacturing flexibility and productivity, higher quality products and improved regulatory compliance. This can be achieved by predictive maintenance scheduling and better upkeep via the embedded diagnostics, performance analysis data and operational statistics. Properly adjusted and calibrated devices ensure lower process variability and higher plant availability.

The isochronous bus cycle enables tighter loop tuning and as a result, better process control. Firmware download gives the ability to stave off obsolescence, giving Fieldbus plants longer life than other plants, with greater ease.How is FOUNDATION H1 unique?

FF H1 is the only digital Fieldbus protocol developed to fully meet with the original IEC 61158 requirements. Unlike other protocols, H1 provides explicit synchronisation of control and communication for precisely periodic (isochronous) communication and execution of control functions with minimised dead time and jitter. It synchronises clocks in Fieldbus devices for support of Function Block scheduling and alarm time-stamping at the point of detection.

Additionally, H1 provides automatic address setting, eliminating the need to manually set addresses off-line using a tool or DIP switches and avoiding subsequent mistakes. H1 also uses peer-to-peer communication where devices communicate directly using a publisher/subscriber communication relationship, enabling data to be sent to several devices in a single message and thus reducing system overhead. H1 includes alarm and event reporting for efficient diagnostics and process alarms, whilst online firmware downloads make it possible to upgrade devices in order to stay ahead of the obsolescence curve. Lastly, a rigorous interoperability-testing program ensures connectivity problems are minimised.Is FOUNDATION H1 easier to use than traditional technology?

H1 has made it possible to “mine” important information from the plant floor. When used correctly, this information empowers operators and technicians to make plant operation and maintenance easier. Some end users report commissioning time savings as high as 75% compared with conventional analogue technology by switching to Fieldbus technology.

FOUNDATION technology enables improved asset management using device management software, as many failures can be predicted and faults can be diagnosed in detail. Together, device management software and Fieldbus devices typically enable:Identification & informationDiagnostics, performance analysis & operational statisticsParameterisation, ranging, reconciliation & audit trailSimulation & overrideCalibration trim & logDocument accessDevice event capture & monitoringCommissioningMaintenance log & service notesDevice listingMaintenance & calibration schedulingHow does H1 “Fieldbus” differ from the various device-level networks now in use?

H1 was designed specifically for process automation. It differs significantly from device-level networks for factory automation in its ability to provide intrinsically safe power for field devices used in hazardous locations. Moreover, thanks to scheduling, H1 Fieldbus is isochronous, which is a requirement for continuous regulatory process control.

H1 was designed and developed as a system technology providing significantly more structure and benefit than mere communication networks. H1 technology delivers true distributed control networking and provides asset optimisation through a broad range of diagnostic capabilities and consistent data structures through the use of Electronic Device Description Language (EDDL). FF technology also provides easy and extensive integration capabilities through open and consistent integration to HSE in a single engineering environment. Device-level networks without power and intrinsic safety (and no scheduling) are mostly appropriate for on/off components with limited data and for dedicated applications such as machine control.What is FOUNDATION HSE?

FOUNDATION High Speed Ethernet (HSE) is a control network technology specifically designed for process automation to connect higher-level devices such as controllers and remote-I/O, high-density data generators etc., and for horizontal integration of subsystems.What are the benefits of HSE?

FOUNDATION HSE enjoys a fully fledged redundancy scheme giving control systems greater availability than systems using

simple ring-topology. Use of unmodified Ethernet and standard IP makes HSE systems more cost-effective than other Ethernet solutions and proprietary networks. Since HSE is a standard, it enables simple and tight integration between package units and the main control system. The HSE network is easier and cheaper to manage based on common network knowledge and standard SNMP tools.How is FOUNDATION HSE unique?

FOUNDATION HSE is based on unmodified IEEE 802.3 Ethernet and is therefore compatible with standard Ethernet equipment. Unlike “ring topology”FOUNDATION HSE provides complete “DCS style” redundancy with redundant network switches, redundant devices and redundant communication ports ensuring unsurpassed availability. FOUNDATION HSE is also based on standard IP, enabling it to coexist with other devices and ensuring compatibility with standard tools. At the highest level, FOUNDATION HSE includes a standard application layer that provides interoperability between devices beyond the mere coexistence provided by Ethernet and TCP/IP. FOUNDATION HSE communication is schedule-driven to minimise dead-time and jitter with support for peer-to-peer communication directly between devices. Again, a rigorous interoperability testing program ensures minimum connectivity issues.Is FOUNDATION HSE easier to use than RS485 and coax-based networks?

The hub-and-spoke tree topology of Ethernet makes it very easy to add and remove devices without upsetting the operating network. Because FOUNDATION HSE is based on unmodified Ethernet, standard Ethernet tools can be used for installation

qualification, testing and troubleshooting. These tools speed up the resolution of communication problems. FOUNDATION HSE is supported by troubleshooting tools that are not available for RS485 or coax, and since FOUNDATION HSE is based on UDP and TCP, standard network management tools employing SNMP, RMON, etc., can also be used. Similarly, familiar IP addressing is used including support for DHCP.What makes FOUNDATION devices interoperable?

Interoperability is made possible by the fact that devices and software are conforming to the same standard. Testing and registration ensures that Fieldbus devices bearing the official “checkmark” seal can be connected on the same bus or network and exchange information without significant integration effort. End users can select the best device for a specific measurement or control task, regardless of the manufacturer. A current list of registered products is available on the FF website (www.fieldbus.org).How is interoperability defined in relation to FOUNDATION technology?

Interoperability refers to the ability of any ITK-registered device to work with any HIST-analysed host. Users want to operate their entire plant from one operator interface and maintain all devices on the system with one maintenance application.Are Fieldbus devices interchangeable?

Yes. End users can substitute a registered Fieldbus device from one manufacturer with that of another manufacturer on their network without loss of degree of integration.What types of projects are appropriate for Fieldbus technology?

Fieldbus technology is now being utilised on automation projects of all sizes, including both new and retrofit installations. According to an ARC Advisory Group survey, a significant number of end users are installing small, medium and even very large Fieldbus systems consisting of over 2,000 I/O points. Shell, a major adopter of FF technology, reportedly has over 120,000 installed Fieldbus I/O with 31% of these devices replacing conventional instruments.What applications are best suited to Fieldbus?

Both H1 and HSE were specifically designed for process control. Because H1 and HSE have complementary characteristics covering diverse networking needs, Fiedlbus technology is appropriate for many applications. These include closed-loop continuous control, batch sequencing, remote-I/O and legacy system integration. The Fieldbus Foundation′s Safety Instrumented Systems (SIS) specification includes an additional safety layer based on IEC 61508 requirements, making it suitable for use in plant safety systems.How do end users influence the direction of the technology?

The Fieldbus Foundation established an End User Advisory Council (EUAC) to give end users a voice in the direction of its technology. The group meets two to three times per year to discuss issues involving their specific plants and industries.

Is Fieldbus an open technology available to all suppliers and end users?

Yes. A key tenet of both the Fieldbus Foundation and PROFIBUS protocols is that they are non-proprietary and available to all companies wishing to include it in their product offerings. Both the H1 Fieldbus and the HSE control network are part of the IEC 61158 protocol standard and IEC 61784 profile.Does FF technology allow traditional centralised control to be located in the DCS?

Yes. FF technology provides end users with the freedom to locate control in the control system or in the field devices. The Fieldbus Foundation does not advocate a particular control strategy.How does FF solve the business needs of enterprise automation applications?

FOUNDATION HSE enables information from intelligent devices to pass through control systems without loss, degradation or the delay associated with proprietary control networks to device management software. It also allows the possibility of electronic integration with higher-level MIS and ERP applications.How does FOUNDATION technology handle discrete I/O?

Fieldbus Foundation members provide a variety of discrete devices for mini remote I/O, relay, on/off valves, valve couplers, electric actuators, etc., on H1 as well as large remote I/O on HSE. Indeed, on/off signals in bulk are an integral part of the

FOUNDATION solution. The technology is well suited for hybrid control.Is FF technology a recognised international standard?

The IEC voted to include the FOUNDATION HI and HSE specifications in the IEC 61158 international Fieldbus standard. The CENELEC Technical Bureau added the FOUNDATION H1 specifications to EN 50170, the Fieldbus Euronorm. In addition, FOUNDATION technology is the only implementation of the ANSI/ISA-50.02 standard.

Both NAMUR (Germany) and JEMIMA (Japan) have voiced support for FOUNDATION technology, and provided input from the end user community that aided in specification development. Approval and support by key international industry bodies gives confidence to users that their investments in FOUNDATION solutions are based on recognised global standards.

What are the most common Fieldbus wiring errors?

There are two very common wiring errors that will cause operational difficulty if not remedied. The first is a short from the shield to one of the Fieldbus conductors. Although this may not immediately cause communication errors, it ground references (since the shield is grounded) the Fieldbus pair and makes it much more susceptible to electrical interference. The second most common problem is an incorrect number of Terminators. There should be two and only two Terminators on each Fieldbus segment. Since the Fieldbus installation will likely be installed by

contractors who are unfamiliar with Fieldbus, we recommend a Segment Checkout Procedure BEFORE powering up or commissioning the segment. Many host suppliers have such procedures. The Fieldbus Foundation also publishes an engineering document for Fieldbus that contains such a procedure.

How is Profibus PA different from Foundation Fieldbus?

Both Profibus PA and Foundation Fieldbus share the same Physical layer definitions. Therefore the connection and power equipment that will work identically for both types of busses. The difference is in the protocol. Therefore, FBT-3 Fieldbus Monitor will not work with Profibus PA as it was only designed for Foundation Fieldbus.

What is the difference between HART and Fieldbus?

That is like answering “what is the difference between a bicycle tire and a car?” HART is only meant for communication protocol, whereas Fieldbus is actually a system architecture including control strategy etc.

Not merely better, but radically different. Indeed, mistaking Fieldbus for a “digital 4-20 mA” or a better DCS is like mistaking the computer for a better typewriter. It cannot even be compared to “smart” transmitter protocols. Imagine for a moment: A system that renders obsolete all separate signal conditioners, isolation amplifiers, input cards, output cards, CPU cards, I/P converters, and their web of interconnecting wires, almost an entire DCS. A

system completely self-contained; expressed simply as field devices and a man-machine interface (MMI) like an operator console. A system where all controls, alarms, computation, selection, Totalization and much more – performed by the field devices’ microprocessors. A system so powerful it may overcome a process’ controls problems with a few clicks of a mouse.

Fieldbus is the ultimate. The signal transmission has evolved to completely digital, system architecture has evolved to completely distributed to the field. I.e. Fieldbus not only replaces 4-20 mA, but also the by now hopelessly outdated DCS architecture of the seventies.

What are the benefits of Fieldbus?The benefits of Fieldbus are many and some were already described;Lower cost of purchase and ownership;Productivity and quality increase;Higher integrity and accuracy;Access to more information and diagnosis;Easier installation and start-up;Freedom of component choice;Easier to configure;Easy for having single consistent database;

How does Fieldbus lower the cost?

Economic benefits spring mainly from the fact that less hardware is required. Of the expensive DCS only the operator console remains. Due to its non-critical nature, a PC or IPC (Industrially hardened PC) with off the shelf software may be used, even for large systems.

Fieldbus devices may perform multiple measurements, control and computations. The number of transmitters may be reduced, single loop controller and computational units will not be required, again saving cost.

Though Fieldbus, the device price may initially be higher than conventional or smart, the reduction in devices and wiring with associated cable trays and marshalling boxes will make the system cheaper. Manufacturers can no longer rely on proprietary technology to keep prices up. Open competition enabled by a playing field levelled by Fieldbus will reduce prices.

Cost is not only price… There are substantial long-term savings resulting from the increased information flow in terms of diagnostic information and easier calibration etc.

Many Fieldbus transmitters will be of a multiple variable type. For example, dual channel field mounted temperature transmitters measuring two temperatures being able to transmit both

variables in real time. Since a single transmitter can condition several sensors, the cost per measurement point will be lower. This is the ideal combination of price and performance. Previously multiple temperatures sensors where typically handled by conditioners in the control room with long wires into the field, having a penalty on accuracy and noise immunity due to factors like lead wire resistance, poor or no thermocouple compensation wire and poor routing of low level signals. Multiple variable technology makes it economically viable to use field-mounted transmitters right next to the sensors for immediate interface and transmission in the high integrity digital domain. Added advantage is the capability to perform high and low selection, redundant sensor voting, average and difference calculation in the field.

Fieldbus helps companies increase productivity, flexibility, quality and comply with ever more stringent environmental regulations, and at the same time lower their operating cost. Fieldbus is the means whereby companies will stay competitive well into the 21st century.

What is all this diagnostics stuff in fieldbus ?

The digital communication provides the means for all the device data, configuration, operation and diagnostics details to be accessed from the control room. The complete interoperability of Fieldbus enables this data to also be accessed by any software that desires to do so.

The multiple variable nature of Fieldbus also allows new innovative devices. Transmitters that measure more than one variable have built in flow and HTG computers etc.

Schemes for consistent diagnostics interrogation and failure alerts were designed into Fieldbus from the very beginning. The self-diagnostics of field devices may report failures and problems immediately, enabling maintenance personnel to pinpoint errors instantly or even before they can cause any harm. More self-diagnostics will therefore be implemented. Hardware failures like sensor, actuator and memory problems, and the operator reports all software problems like configuration or calibration errors without the need for manual interrogation. In the event of a fault it is reported with the associated information like which device, what type of fault, priority and the time stamp etc.

The benefit for the operator to get this information without having to bring the transmitter in to a workshop for testing is obvious. The time that can be saved by not having to test only a few transmitters is enormous. Diagnostics enables you to quickly determine if a process problem is due to the transmitter or not, without having to do several field visits. Production can get back in operation in minutes.

All this reduces errors and makes calibration less of a choir ensuring it is done correctly and on a periodic basis. The end result is a better measurement and improved quality.

What is a transducer block?

This blocks interfaces the function block to the device hardware such as sensors, actuators and switches. This block is responsible for information and functionality specific to for example the measurement of a particular physical property, such as pressure or temperature, or a specific measurement technology, such as ultrasonic or Coriolis.

The transducer blocks interface to the function blocks over hardware channel, which is different from function block links. Transducer block handle not only measurement, but also actuation and display.

What is a resource block?

The resource block contains information which is common to the whole resource, including device identification, hardware, device features, memory and CPU availability, write protection, management of failsafe and alarms.

The data is not processed in this block, so there is no block algorithm.

What is automatic alarm notification?

Alarms and events are jointly referred to as Alerts. The function blocks into the devices detect alarms. When alarms and other

critical events occur, the function block automatically notifies the MMI by sending an Alert. The MMI confirms receipt of alert notification to the field device. If the field device does not receive the confirmation, it will re-send the notification. Alerts are also issued when alarm conditions disappear. Thus the operator interface does not have to perform periodic polling to determine if there is an alarm condition, and surely any alarm can be detected. Information in the notification includes time and priority.

The current status of alarms and events may also be checked at any time from alarm and event parameters in each block.

How does distributed trending work?

The device may do trending itself. This way periodic time critical communication is not necessary. A MMI only needs to poll a device for data when a particular parameter is displayed on the screen. When the parameter is not displayed, polling need not be done.

A set of data, 16 samples, is collected over a short, user configurable, period of time and is then automatically sent in a single communication to the MMI where the long-term storage is done.

What is a device description?

Since profiles offers choices to what capabilities and parameters are implemented in a device, a configuration device or other MMI need to know which of these a particular device implements.

The device description (DD) specifies which application area and device profile a device belongs to. For certain parameters it also specifies options are valid and more specific meanings etc. DD may also define methods, e.g. for steps a Host to follow when calibrating the device. The DD file also can describe an user group or vendor specific features on these devices.

The DD is prepared by the device manufacturer and may either be stored in the device itself or be supplied separately, e.g. on a floppy disk or CD-ROM. A MMI may using the DD completely and correctly configure a new device or new version of a device without a corresponding upgrade.

What are the distinguishing features of a “true” Fieldbus, delivering the original promise?

The main characteristics of Fieldbus are:Completely digital replacement of 4-20 mA;Control, alarm, computation and other functions distributed to devices in the field;Multi-vendor interoperable through open specification;Specifically designed for process control;

DCS/smart-transmitter and other protocols calling themselves Fieldbus do not show these characteristics;

What is the benefit of being completely digital?

Unlike the “semi digital” DCS system, the Fieldbus system is a “pure digital” system. Instead of the system’s pressure or temperature transmitters converting a sensed digital process value to an analog 4-20 mA signal before feeding it to the DCS and the rest of the system chain, Fieldbus keeps the signal purely digital all the way from the transmitter to the digital input of the control valve. Fieldbus devices should not be mixed up with what we today call smart devices which are a hybrid of 4-20 mA and slow digital communication. Keeping the signal digital until the very end of the chain allows for infinitely more complex and precise signal processing. And the industry standard, inexpensive cable that links all the Fieldbus components together can be hundreds of meters long and remain totally free of the noise pickup and signal degradation associated with analogue signal transmission.

In a 4-20 mA analog system, a single value is transmitted by an infinite variation of a current. A signal error just changes a valid signal to another valid signal, noise and other signal distortion cannot be detected in an analog system. The signal from even the most accurate analog transmitter may be totally inaccurate by the time it reaches the controller. Much more noise is required to distort a digital signal such as in Fieldbus, which only has two valid states, one and zero. Secondly, error checking is also used to filter out scrambled messages and make sure they are sent again. All data is checked and guaranteed free from distortion due

to noise or impedance mismatch that may affect analog signals undetected.

Each analogue link – transmitter, signal conditioner, isolation amplifier, cable, input card, output card, I/P converter – whispers an ‘analogy’ of what it hears to the next, but something is always lost or added.

What emerges at the end may not even resemble the original message. No matter how long the chain, at its end digital equipment listens only for patterns of zero and one, which it reassembles into the original message, ignoring all other whispered information as noise. Hence the integrity of digital transmission: no accuracy lost, any noise added.

The integrity of a digital signalling results in better accuracy and security. The latter is being very important in the process industry where expensive equipment, life and the environment may be at stake. Fieldbus has taken this integrity even further. Measurement and control variables passed between function blocks have not only a value, but also a status, which include signal quality, limit information and a sub-status. The signal quality informs if e.g. a measurement is Good, totally Bad or perhaps Uncertain, e.g. out of range by a few percent. Other function blocks use this to e.g. put control in manual in case of fault, calculation function blocks may also take this information into consideration, e.g. exclude it when calculating an average.

How is Fieldbus more distributed than a “Distributed Control System”?

Unlike the “semi-distributed” DCS system, the Fieldbus system is a completely distributed. In Fieldbus the process control functions are distributed to equipment in the field, while still allowing operation and tuning from the control room using the digital communication. The field devices are typically multi-dropped, several connected to each other and the operator console, drastically reducing wiring with subsequent savings in cost of purchase and installation.

In the legacy DCS of the 1970 the control functions for several loops was centralised to one or more “unit controllers” which contains control, input and output cards.

Since in Fieldbus communication is completely digital no input or output cards are required, and since the control functions are performed by the devices in the field, no control cards are required either. Field devices may be connected directly to the operator console, hence a data highway connecting control cards is not required either. Since there are no cards and no data highway, they need not be made redundant either. All that remains of the classic DCS architecture is the field devices and the operator console. Obviously a Fieldbus system means a tremendous hardware and subsequent cost reduction.

Will Fieldbus replace DCS as we know it?

Yes. Some companies have a vested interest in saying that it won’t, but with Fieldbus there is no need for analog and digital

input cards (since communication is already digital) and there is no need for any controller “CPU” cards (since control is done in the field devices), nor is a “data high way” required to link the system together. All that will remain is the operator console. Ask yourself, is that a DCS as we know it?

The first DCS systems emerged more than twenty years ago. Though a major improvement at the time, this technology of yesteryear has many deficiencies.

Established DCS manufacturers now offering their own PC based control software, or buying out PC software companies must be seen as the final nail in the coffin for DCS.

Many control software packages for PC today have all the bells and whistles of a DCS and are available for secure and stable operating systems. These are most likely to serve as operator consoles to make complete Fieldbus systems.

Lets look at what would happen if a shortsighted customer decided to go for the legacy DCS architecture of the 1970s, and then upgrade to Fieldbus a few years later. He would most likely have to replace the entire transmitter for all measurements, wiring would have to be redone, power supplies, safety barriers and any interfaces would have to be replaced, input, output, CPU cards and “data-highway” (main and redundant) thrown away, and termination added – all that remains is the operator console. Upgradability to Fieldbus is an important consideration when choosing a control system.

What happens to data base configuration in a Fieldbus system?

Fieldbus is using the concept of a completely distributed database. Device and control loop information is encapsulated in the field device itself, ranges, tuning, wetted materials data etc. Any MMI that desires to display that information may access it. This way there are no duplicate inconsistent databases. In DCS synchronisation between the console and device database was not guaranteed.

There was always a risk that the device was calibrated for one flow range, but the console for another giving a wrong indication. In Fieldbus only one database exists, in the field device, and the MMI gets it scaling data from there. A hand-held configuration device accesses the same device data as the operator console.

Isn’t Fieldbus too slow, 31.25 kbit/s compared to several Mbit/s for DCS?

In Fieldbus there are typically only 12 device per segment (on a pair of wires) whereas on a DCS all the device of the entire plant are indirectly connected to a single bus which therefore must be faster.

In order to transfer all link and supervisory data fast enough to get tight closed loop control and fast MMI (Man-Machine Interface,

such as an operator console) screen update, Fieldbus implements a number features for communication optimisation.

• Automatic distributed alarm detection and notification • Distributed Trending • Parameter view object groups • Scheduling • Update event notification

Thanks to the mechanisms for passing of configuration, alarm and trend data this so-called background traffic has been reduced to a minimum leaving more time for operational traffic and again improving control performance. After configuration, the system resolves tags and parameter names into a format, which minimises communication.

What are View objects?

Block parameters have been arranged in four groups depending on usage and storage. All parameters in a group may be accessed in a single communication. This way an MMI need not occupy the bus by several requests get the parameters one by one.

What is an update event?

An event is also a form of Alert. The MMI is automatically informed about configuration changes through an event issued by the block, which is changed, and is also tracked by a revision parameter included in the view objects. Each time a static parameter is changed this revision parameter is incremented.

Therefore a MMI only need to update itself when a change has occurred, it does not have to make continuous checks.

What is scheduling?

Function block execution and communication is scheduled to optimise control and communication efficiency. It may be used to ensure that blocks are executed in the correct order. The sequential passing of dynamic time critical function block input and output data is called operational traffic. This traffic and the execution of the function blocks is scheduled by the system so as to occur on a precisely period basis with a minimum delay thereby achieving optimum closed loop control performance. Scheduling allows the user to control the order and also the frequency of execution of a block.

Without scheduling the loop dead time will most likely be longer than the time it takes to communicate the operational traffic on the Fieldbus network. Another reason is that without scheduling the blocks may be executed in the wrong order.

Is Fieldbus easy? It sounds complicated?

As the first protocol to bring the full power of microprocessor technology into field instrumentation, Fieldbus distil countless hours of thought into every aspect. When you press a key or click to change the configuration, the effect is powerful, yet all the work has been done for you. There is no need to understand the wealth of technical strength hidden in your field device in order to appreciate it. Fieldbus is easy to use, there is no need to understand the “layers” and “baud rate”, it has been taken care of by the best engineers from the leading companies in transmitters, systems and actuators.

Configuration becomes easier because it will be done the same way for basically all devices using the function block concept, no need for training on several device types or programming languages. All manufacturers use the same blocks, regardless if they are in a field device or not. Fieldbus is based on user-defined tags and standardized parameter names like SP and PV. He refers to devices by its tag. The user need not think of device address, memory address and bit numbers etc. Configuration may be edited on a PC and then down loaded to the devices in the field. If you want a flow transmitter to integrate, just instantiated the function block, no need to rewire or buy an additional device. Once physically connected, the links between function blocks may be changed, function blocks can be added and removed etc. More advanced devices may execute a virtually unlimited number of function blocks.

Procedures like calibration, range setting and diagnostics are implemented consistently between manufacturers and device types. I.e. a density and pressure transmitter from two different companies are operated in the same basic way. This reduces

confusion and makes operator training easy, even though your preferred vendor for various device types is different and may change over the years.

Fieldbus already has blocks for all kinds of process control functionality like input, output, control, calculate and various types of computations forming an advanced set. Several of the blocks implement alarm. New blocks will keep getting added.

Connection is a simple task since devices are connected in parallel and terminal number matching will be a minimum. One wire will typically connect as many as twelve devices. Cable trays, conduits etc. will be drastically reduced. It also becomes easy to add devices, just hook it up in parallel, no need to run a new wire.

Fieldbus has capability to simulate input or output values or status making it possible for a single person to from the control room safely test the system response to faults and process conditions which would otherwise be difficult or dangerous to try out. Previously making such a test was troublesome. Two persons equipped with walkie-talkies were always required, one climbing on tanks and pipes in the field with a simulator. There is no need to expose anybody to an unfriendly or hazardous environment.

“Ringing out” the transmitters, i.e. match the wires in the marshalling rack to their respective devices is also much easier, apply power and connect the Host and ask for the tag and you are done!>

Fieldbus devices store information useful for maintenance in the device, where it will never get lost. You may store a calibration data like when and by whom, description of the service of the device and even individual blocks may be stored, this could be e.g. “Level – Boiler 1”.

A wealth of information is available in the device, which also includes wetted materials information and serial numbers. This may not only be available with the Host, but also from operator console. Accessing the device operating temperature reading allows you to see if it is operating within range. The temperature reading proves extra valuable in applications where heat tracing and winterization is used. The temperature reading is an indication of if it is working or not, so that transmitter does not fail or pipes are clogged due to solidification.

Instrument calibration and maintenance data may be stored in the transmitter database where it, unlike if stored on paper or a disk, will not be misplaced or separated from the transmitter even if the device is moved around in the plant or even shelved. This may include information like performed by whom, where, when, how and at what value calibration last was made. The information is not only more than seen before, the interoperability of Fieldbus makes it more accessible than seen for smart transmitters. This instrument management is an important feature to help comply with ISO9000 and ISO14000 requirement for updated and traceable calibration records – again a tool for better sensing.

Won’t Fieldbus stifle innovation?

Since digital communication was first introduced in process control, manufacturers have been forced to adapt their products to a myriad of protocols as they emerge. A standard Fieldbus has relieved device manufacturers from this task. Once again they can concentrate on true innovations such as sensing techniques getting higher accuracy, reliability, stability to ambient effects, and transmitters for multiple variables.

Fieldbus is a performance specification. This means product developers have maximum choice over how they implement it into products. Fieldbus device manufacturers can select from the microprocessor, programming language and methods of their choice. This can greatly streamline the product development process, and production costs.

A single common Fieldbus will spur third party software and other accessories, as the market for a given product would be larger, providing an economy of scale factor justifying product development. More software and accessories will make Fieldbus more attractive contributing to the proliferation.

Fieldbus will just be another requirement in an already long list of standards specified by instrument buyers, essential when it comes to putting the pieces of a plant together, and being able to make replacements:Temperature sensors;Process connection;Electrical connection;Calibration;

Fieldbus;Cleaning for oxygen service;Environmental conditions testing;Intrinsic safety;Material grades;

Some have forgotten the beauty of standards and have take all the benefits of standardization for granted so much so that we even argue if they are good or not. The question is if the industrialized society could function if it was not for the thousands of standards making it tick. Could we even imagine going back to a time where a bolt and a nut from different shops do not fit together? If they were not for standards a lot of things in our lives would not work e.g. bolts and nuts. Standardization of measures, screws etc. is the very foundation on which engineering rests.

The situation we have now when new protocols show up every day is in a way hampering development because nobody dare to chose. Lack of standardization, new protocols coming up, instrument manufacturers and control software manufacturers has been tracking a moving target.Standards are especially in the USA criticized for stifling development. However, standards actually enables true innovation rather than just coming up with many new solutions for the same problem already solved. Once a standard has been laid down, enough people are willing to buy products based on it providing a large enough market for new ideas based on the technology in the standard. Manufacturers now dare to spend

money developing a new product making use of the standard, knowing the standard will not change so soon.Investing in development based on somebody else’s proprietary technology is a great risk, manufacturers at the mercy of the technology owner never know if there will be a new version out the next month rendering their development efforts useless.As an example, the technology to make multiple variable transmitters and control and computation in the field has been around for a long time, but it has basically been pointless before Fieldbus because only with the interoperability that Fieldbus provides is it possible to make good use of it.

Instrumentation Engineering Standards Questions & Answers0Q & A, StandardsDecember 25, 2015 A+A-EmailPrint Questions & Answers on Ingress Protection

What does IP stand for? IP is an acronym for Ingress Protection

Why is Ingress Protection Important? Liquid and/or solid particle ingress into electrical equipment may not only be harmful to the equipment, it may also be dangerous to the operator. Therefore when buying electrical equipment whether it be an electric motor, a light fiiting or an enclosure, it is essential to know what degree of ingress protection the item offers.

So how is Ingress Protection quoted? An “IP” number, or as it is commonly known, an IP rating is used to specify the environmental protection offered. The IP rating is composed of two numbers, the first referring to the protection against solid object ingress and the second against liquid ingress. The higher the number the better the protection.

Are there standards covering these ratings? The applicable European standards for ingress protection are: – BS EN 60529 Specification of Degrees of Protection Provided by Enclosures – IEC 529 Specification of Degrees of Protection Provided by Enclosures

What do they use outside Europe? In North America, the NEMA classification is used. NEMA (National Electrical Manufacturers Association) is a US trade association representing the interests of electroindustry manufacturers of

products used in the generation, transmission and distribution, control, and end-use of electricity.

How does the IP and NEMA systems compare? The IEC and NEMA degrees of protection can not be fully compared as equivalent ratings. The NEMA Standard includes tests for environmental conditions such as mechanical damage, corrosion, rusting, ice formation, etc. However the follwoing table can be used as a guide

Does NEMA produce standards? NEMA Standard Publication 250 and UL 40 Standard Publication both provide further information on ingress protection ratings used in the US.

Also Read: Instrumentation Standards & Field Instruments Questions & AnswersQuestions & Answers on ATEX Standards

What is Atex? ATEX is the common name given to the EU directive 94/9/EC, Equipment and Protective Systems intended for use in Potentially Explosive Atmospheres.

The word ATEX is derived from the French “ATmospheres EXplosibles”.

What is the intent of the ATEX Directive? To enable the free trading of ATEX products within the European Economic Area by removing the need for separate documentation and testing for each individual European market. Manufacturers may use a single CE mark on their products to show compliance with this (and any other relevant) Directive. What does ATEX apply to? The ATEX directive applies to both electrical and mechanical equipment intended for use in potentially explosive atmospheres. These include: – equipment and protective systems for use within potentially explosive atmospheres; – devices for use outside potentially explosive atmospheres, but which are required for, or contribute to the safe functioning of equipment and protective systems located inside such atmospheres; and – components relating to the above.

To what industries does ATEX apply? ATEX applies to any industrial location where there is a potential for an explosive atmosphere to exist, e.g. mines, factories, agricultural silos, oil and gas platforms, water and other chemical processing environments.

To whom does ATEX apply? If you design, manufacture or sell any equipment or protective system intended for use in potentially explosive atmospheres within the EU, then you will need to comply with the ATEX Directive 94/9/EC.

How do I know if a product complies with ATEX? The ATEX Directive sets a number of technical and quality objectives that must be complied with to the satisfaction of a notified body, but once these have been met, a manufacturer can mark his product with a CE Mark and is entitled to display the distinctive Ex mark.

What other marking can be shown? The following marking should be shown on all ATEX compliant equipment. – CE Mark – Ex-marking symbol followed by ATEX data – Name and address of manufacturer – Series or type, serial number – Year of construction – All further information essential to the safe use Marking, especially on small components can be an issue.

Show me an example of the CE, EX and Atex data marking

9876 II 2 G

What does the ATEX data mean? The ATEX Directive identifies two groups of equipment. – Group 1 equipment is intended for use in mining applications. Divided into categories M1 and M2. M1 identifies equipment that must continue to operate when a potentially explosive atmosphere is present. M2 identifies equipment that does not operate when a potentially explosive atmosphere is present. – Group 2 is intended for all other situations. Divided into categories 1,2 and 3. Category 1 equipment is intended for use in Zone O situations. Category 2 equipment is intended for use in Zone 1 situations. Category 3 equipment is intended for use in Zone 2 situations.

What are Zones? Zoned areas are areas where there is a risk of flammable material being released to atmosphere. The subscripts 0, 1 and 2 describe the probability of a flammable material being released to atmosphere in explosive concentrations.

And the G? G means the item has been tested for potentially explosive atmospheres due to the presence of gas D means the item has been tested for potentially explosive atmospheres due to the presence of dust.

Also Read: DCS & Field Interview Questions & AnswersQuestions & Answers on CE Markings

What is CE marking? CE marking identifies a product as conforming to European Directives. When a manufacturer affixes a CE mark to their product they are declaring compliance with ALL RELEVANT European Directives.

When did the CE mark start to be used? CE marking for instruments began on the 1st of January 1996. From then a CE mark must be carried by all electronic equipment sold within the European Economic Area. The regulations do not apply retrospectively.

What does a CE mark look like? The mark is shown in the top left hand corner of this page. This is usually stamped on to the manufacturers name plate.

What European Directives are relevant to Instrumentation? – 89/336/EEC (modified by 92/31/EEC, and 93/68/EEC), The Electromagnetic Compatibility Directive (from Jan 96) – 72/23/EEC (modified by 93/68/EEC), The Low Voltage Directive (from Jan 97) – 97/23/EC, The Pressure Equipment Directive, known as PED (from May 2002)

– 94/9/EC, Equipment and Protective Systems Intended for use in Potentially Explosive Atmospheres, known as ATEX (from 1/7/2003)

Which countries demand a CE mark? All 27 member countries of the European Union (EU), and the 3 member countries of EFTA (European Free Trade Association) consider it to be mandatory. It is estimated that around 70% of all products sold in these countries require to be marked. CE Marking obtained from one EU country is valid in all other EU count ires, and in the EFTA countries. It permits free movement of the product within all 28 countries.

Who belongs to the European Union? Austria, Belgium, Bulgaria, Cyprus, Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Holland, Hungary, Ireland, Italy, Latvia, Lithuania, Luxembourg, Malta, Poland, Portugal, Romania, Slovakia, Slovenia, Spain, Sweden, United Kingdom

Who belongs to EFTA ? As of February 2005; Iceland, Liechtenstein, Norway and Switzerland

Who Ensures Compliance? The law applies to the manufacturer, importer, supplier and the customer.

It is an offence to supply a product, which is not CE marked, regardless of where it is made. Therefore the manufacturer, importer and supplier must ensure products are CE marked. It is also an offence to use unmarked products. Therefore the purchaser must ensure products are CE marked. The relevant regulatory body in the country concerned is charged with enforcing the law. In the UK this falls to the trading standards department of local authorities.

What about spare parts? Components with no intrinsic function e.g. a circuit board do not require a CE mark. However, an instrument that is a spare part for a compressor package would require to be marked (assuming that one or more of the directives mentioned above apply)Questions & Answers on Hazards

What is Zone Classification in Hazards Location ?

Zone means something different depending on whether you are in North America, in Europe, or elsewhere in the world. Each individual country may have its own unique electrical codes that place different requirements on the equipment in the hazardous area. We generally receive requests for installation equipment in one of four main types of Zone classified hazardous areas:Class I/II, Zone 1 and 2ATEX Class I/II, Zone 1 and 2ATEX Zone 1/21 and 2/22

IECEx Zone 1/21 and 2/22

What is the hazard?

Gas and dust behave differently to create explosive environments.

Where will this equipment be installed?The Class and Zone (AEx Class) systems are part of the North American standardsThe ATEX system is the European standardThe IECEx system is the International Electric Code standard

A system that is Zone certified for North America or ATEX may not be acceptable for installation in Australia. If the system is certified for IECEx Zones, it may not be acceptable for installation in a facility in the United States. The authority having jurisdiction determines which of these is required for your installation.

There are actually two ways equipment can be certified in North America. Both come from section 505 of the National Electric Code (NEC), and each has its own marking for a certified system. NEC 505 lists the requirements for Class and Zone hazardous areas. According to NEC 505.9(C)(2), a system built and certified to the standards spelled out in NEC 505 requires a specific marking:

Example:

Class I, Zone (1 or 2), AEx Protection Designation (e, ia, px, etc.) Gas Group (IIC, IIB, IIA) Temperature Classification (T1-T6)

Interestingly, according to NEC 505.9(C)(1), a system that is built and certified for Class I, Division 1 can be installed in a Class I, Zone 1 area, and a Class I, Division 2 certified system can be installed in a Class I, Zone 2 area. In this case, the system is required to have a different marking:Example:

Class I, Zone (1 or 2), Gas Group (IIC, IIB, IIA) Temperature Classification (T1-T6)This means that a certified system builder could assemble components with all necessary certifications, and install them in an appropriately rated enclosure to provide a system that is certified for Class and Division as well as the equivalent Class and Zone for North American locations. If the actual “AEx” mark is not a requirement, this may be a better option. In addition, according to NEC 506.9(C), the same rules apply for Class II areas.

General Instrumentation Questions1Q & AOctober 12, 2015

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What is the difference between cation conductivity and specific conductivity?

To increase the sensitivity of conductivity measurement, the sample is first passed through a column of cation exchange resin in the hydrogen form, which converts all cations in sample into hydrogen ions. As a result of salts like NaCl and magnesium sulphate (which may enter into condenser through leakage) get converted into hydrochloric acid and sulphuric acid which have much higher conductivity than the salts. In such treatment, CO2 is unaffected. but amononia, / hydrazinc and caustic soda are completely removed from sample.. This type of measurement known is cation conductivity measurement. (and is proportional to the mineral carryover and independent of CO2 hydroxides,carbonates,NH3 or amines concentration) and the conductivity measurement made directly without passing the sample through the cation exchange resin is known as specific conductivity measurement

What is potential free contact? What is the significance and application of this contact?

Contacts having not potential. E.g. Relay contacts/ field switches contacts. They are used in logic circuits. A potential free contact is usually wired into an electrical circuit. However it must be ensured that the contact ratings are suitable for the service in which it is used.

What are the different types of torque measurement?( techniques )

There are two different types of torque measurements:

1) actual instantaneous torque

2) dynamic torque where primary objective is to measure variations of torque rather than the torque itself e.g. torque measurement in case of centrifuge.

Torque can be measured by

1) using an appropriately connected strain gauge transducer,

2) measuring the twist (angular) of an elastic element e.g.. The power transmitting shaft of a rotating machine or the twisting of torque tube in a displacer type level transmitter. In case of power transmitting rotating shafts, two identical slotted discs are installed at opposite ends of the shaft. Optical pickups are used to generate electrical pulses. Speed of the shaft is also measured.

The phase difference between two pulse trains is related to the twist in the shaft, which in turn is related to the torque transmitted.Why cooling fins are required in level switches?Cooling fins are used to prevent transfer of heat of the process medium to the electrical parts of the switch and maintain their temperature within suitable limits.What is meant by smart tuning and how is it done?Smart tuning, also known as self-tuning, refers to the ability of a controller to adjust its parameters/response automatically for optimum control loop performance when process parameters/response/characteristics change.Typically this is performed by a combination of mathematical calculations and heuristics (intelligent decisions based on the designer’s experience) and continual measurement of process characteristics.What does NPT stand for and what does it signify?National Pipe Thread

Safety Relief Valve Questions & Answers1Q & ASeptember 22, 2015 A+A-

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What is a pressure relief valve?

Relief valves are automatic valves used on system lines and equipment to prevent over pressurization. Most relief valves simply lift (open) at a preset pressure and reset (shut) when pressure drops only slightly below the lifting pressure.

System pressure simply acts under the valve disk at the inlet of the valve.

When system pressure exceeds the force exerted by the valve spring, the valve disk lifts off its seat, allowing some of the system fluid to escape through the valve outlet until system pressure is reduced to just below the relief set point of the valve. The spring then reseats the valve.

What is the difference between orifice and inlet size?

The orifice diameter is the internal opening of the valve and is used to calculate the flow capacity of the valve. It’s the inside hole. The inlet size is the interface or the size/type of the threads where you attach the valve. As of publication Kingston Valves do not come in metric sizes, only NPT (National Pipe Thread)

What if my pressure regulator is leaking or not working properly?

Leaking may occur due to debris getting under the diaphragm and preventing it from seating properly and creating gaps which allows air to pass. This could be caused by having a dirty air environment or by having inadequate filtration. You should first check the regulator to ensure that the diaphragm is clean and undamaged. You should also make sure that you have an adequate filter upstream and then consider changing the filter element. Dirty air and debris in the system can also cause the diaphragm to tear in which case you would experience the same performance issues. The diaphragm can be easily replaced by purchasing a repair kit.

Is there a difference in the definition of “Set Pressure” between Air & Liquid applications?

Yes. Liquid Applications: Liquids tend to be incompressible, meaning they cannot be compressed like air. Liquids can be under pressure but as soon as the volume changes they immediately lose all pressure (pressure goes to zero). There are three accepted definition in the industry for liquid applications. They are: start to leak, first steady stream and full flow. For Liquid applications – Kingston defines “Set Pressure” as the first steady stream of flow out of the valve.

Also Read: Basics of Valves Questions & Answers

Why is my valve leaking?

It is normal for spring-operated safety valves to exhibit leakage or simmer/warn, as the operating pressure approaches the nameplate set pressure, typically in the 80%-90% range of nameplate set pressure. The ASME Boiler and Pressure Vessel Code does not require a specific seat tightness requirement. A certain level of leakage is allowed per manufacturers’ published literature. Kingston defines seat tightness standards as follows: Factory Standard Seat Tightness Performance: o Hard Seat Valves – no audible leakage at 20% below nameplate set. o Soft Seat Valves – no audible leakage at 10% below nameplate set. At very low set pressures (20 psi and below), the ratio of the downward spring force as compared to the upward pressure force is very small. In these cases it may be impossible to achieve seat tightness. Use soft seat valves for superior seat tightness in applications which fall within the soft seat material temperature limitations. Although soft seat valves will typically provide a higher degree of seat tightness than metal seats, Factory Standard does not ensure bubble-tight seats, regardless of seat material.

What set pressure should the valve be set to open?

Typically, the valve should be nameplate set to open at the MAWP (Maximum Allowable Working Pressure) of the vessel the valve is intended to protect. There is a tolerance to actual set pressure, which means a valve set at 100 psig nameplate may open slightly above or below 100 psig. Consult the current ASME Boiler and Pressure Vessel Code for tolerance classes and special situations when the set pressure may be different than the MAWP.

What is the blowdown of a Section VIII or non-code safety valve?

The ASME Boiler and Pressure Vessel Code does not have blow down requirements for Section VIII (or non-code) valves. Blowdown may vary from less than 2% to more than 50%, depending on many factors including; valve design, dimensional tolerance variation, where the set pressure falls in the set pressure range of a spring, spring rate/force ratio, warn ring/guide settings, etc. Typical blow down for most valves is 15% to 30%, but cannot be guaranteed.

How does back pressure affect valve set pressure and capacity?

Back pressure reduces set pressure on a one-to-one basis, i.e., a valve set at 100 psig subjected to a backpressure at the outlet of 10 psig will not actuate until system pressure reaches 110 psig. Back pressure drastically reduces capacity; typically backpressure of 10% of set pressure will decrease capacity by 50%. Specific capacity reduction should be determined by the user on a case-by-case basis by flow testing. Back pressure in excess of 10% of set pressure is not recommended.

Does altitude affect set pressure?

No. Gage pressure (psig) is used to set valves so the effects of weather and altitude on set pressure can be ignored.

Why does my valve actuate/open early?

It may not be. Warn/simmer or seat leakage is sometimes mistaken for set pressure. Visible or audible leakage or system pressure drop is not set pressure. The correct definition of set pressure is:For liquid service, first vertical steady stream. For liquid service, first vertical steady stream. For some valves in air/gas service, First audible. Variance of set pressure is allowed, i.e., a Section VIII air valve with a nameplate of 100 psig set pressure may open from 97 psig to 103 psig, but will be factory set around 102 psig.

How high can my system pressure be before my valve opens?

Maintain a minimum operating gap of 10% between the system operating pressure and the safety valve’s nameplate set pressure. Since direct spring operated safety valves may “Simmer” or “Warn” at 90% of the nameplate set pressure, and since the factory standard leak test performed at 80% of nameplate set pressure, better seat tightness performance can be expected with an operating gap of 20%.

Also Read: Instrumentation Standards Questions & Answers

Which end should be connected for vacuum valves?

This is often a confusing topic. The correct installation often looks backwards from what appears to be correct. A paper instruction

tag illustrating the proper connection is attached to each valve. Vacuum valves should have the NPT threads that are cast integral to the body attached to the vacuum source. See the assembly drawing for additional clarification.Why is there a hole in the valve body?This drain hole is required on some models by the ASME Boiler and Pressure Vessel Code. It is intended to prevent any condensate from accumulating in the body that may freeze or corrode internal valve parts and prevent the valve from opening. The drain hole should be piped away to safely dispose of any discharge or condensate.What mounting orientation should be used to install a safety valve?Installing a safety valve in any position other than with the spindle vertical and upright may adversely affect performance and lifetime and may not meet code. Installation in any position other than vertical can violate code standards.How often should I test/inspect my valve?Maintenance should be performed on a regular basis. An initial inspection interval of no longer than 12 months is recommended. The user must establish an appropriate inspection interval depending on the service conditions, the condition of the valve and the level of performance desired.The ASME Boiler and Pressure Vessel Code does not require nor address testing installed valves. The only thing the codes states are design and installation requirements, such as some valves must have a lifting lever. For instance for section VIII: “Each pressure relief valve on air, water over 140F, or steam service shall have a substantial lifting device which when activated will release the seating force on the disk when the

pressure relief valve is subjected to a pressure of at least 75% of the set pressure of the valve. ”is the proper way to install a safety or safety-relief valve?Safety and safety-relief valves should be installed vertically with the drain holes open or piped to a convenient location. All piping must be fully supported.

Industrial Instruments Questions and answers1Q & AMay 23, 2015 A+A-EmailPrint 1. What are the process Variable? The process Variable are: 1) Flow 2) Pressure 3) Temperature 4) Level 5) Quality i. e. % D2, C02, PH etc.2. Define all the process Variable and state their unit of measurement. ? 1) FLOW: Kg I hr, Litter I min, Gallon I min. M3 I NM3 I HR. (GASES)2) PRESSURE: Force acting per unit Area. P = F/A Units: Bar I Pascals I Kg I CM I, Pounds

3) LEVEL: Different between two heights. Units: Meters, M M, C M, %.4) TEMPERATURE: It is the degree of hotness or coldness of a body. Units : Degree Centigrade, Degree Farenheit, Degree Kelvin, Degree Rankin.

5) QUALITY: It deals with analysis PH, % C02, % 02, Conductivity, Viscosity.3. What are the primary elements usedfor flow measurement. ? The primary elements used for flow measurement are: 1) Orifice Plate. 2) Venturi tube. 3) Pitot tube. 4) Annubars. 5) Flow Nozzle. 6) Weir & Flumes.4. What are the differnt types of orifice plates and state their uses? The different types of orifice plates are: 1) Concentric. 2) Segmental. 3) Eccentric.CONCENTRIC: The concentric orifice plate is used for ideal liquid as well as gases and steam service. This orifice as a hole in concentric and hence known as concentric orifice.

Eccentric & Segmental: The accentric orifice plate has a hole eccentric. The use this is made in viscous and sherry flow measurement.

The segmental orifice place has the hole in the form segment of a circle. This is used for colloidal and sherry flow measurement.Also Read:Flow Measurement Interview Questions & Answers5. How do you identify an orifice in the pipe line. ? An orifice tab is welded on the orifice plate which extends our of the line giving an indication of the orifice plate.6. Why is the orifice tab provided. ? The orifice tab is provided due to the following reasons. 1) Indication of an orifice plate in a line. 2) The orifice diameter is marked on it. 3) The material of the orifice plate. 4) The tag no. of the orifice plate. 5) The mark the inlet of an orifice.7. What is Bernoulli’s theoram and where it is applicable. ? Bernoulli’s theoram states the “total energy of a liquid flowing from one point to another remains constant.” It is applicable for non compressible liquids.8. How do you identify the H. P. side or inlet of an orifice plate in line. ? The marking is always done H. P. side of the orifice tab which gives an indication of the H. P. side.9. How do you calibrate a D. P. transmitter. ? The following steps are to be taken which claribrating :1) Adjust zero of the Xmtrs.

2) Static preasure test: Give equal pressure on both sides of the transmitter. Zero should not shift. If it is shifting carry out static aligntment.3) Vaccum test: Apply equal vaccum to both the sides. The zero should not shift.4) Calibration Procedure: a) Give 20 psi air supply to the transmitter.b) Vent the L.P. side to atmosphere.c) Connect output of the Instrument to a standard test gauge. Adjust zero.d) Apply required pressure to high pressure side of the transmitter and adjust the span.e) Adjust zero again if necessary.10. What is the seal liquid used for filling impulse lines on crude and viscous liquid? Glycol.11. How do you carry out piping for a Different pressure flow transmitter on liquids, Gas and steam services? Why? Liquid lines: On liquid lines the transmitter is mounted below the orifice plate. Since liquids have a property of self draining.Gas Service: On gas service the transmitter is mounted above the orifice plate because Gases have a property of self venting and secondly condensate formation.Steam Service: On steam service the transmitter is mounted below the orifice plate with condenlate pots. The pots should be at the same level.

12. An operator tells you that flow indication is more? How would you start checking?1) First flushing the transmitter. Flush both the impulse lines. Adjust the zero by equalizing if necessary. If still the indication is more then.2) Check L.P. side for choke. If that is clean then.3) Check the leaks on L.P. side. If not.4) Calibrate the transmitter.13. How do you do a zero check on a D.P. transmitter?Close one of the valve either H.P. or L.P. open the equalizing valve. The O/P should read zero.14. How would you do Glycol filling or fill seal liquids in seal pots 7Draw and explain.The procedure for glycol filling is :1) Close the primary isolation valves.2) Open the vent on the seal pots.3) Drain the use glycol if present.4) Connect a hand pump on L.P. side while filling the H.P. side with glycol.5) Keep the equalizer valve open.6) Keep the L.P. side valve closed.7) Start pumping and fill glycol.8) Same reeat for L.P. side by connecting pump to H.P. side, keeping equalizer open and H.P. side isolation valve closed.9) Close the seal pot vent valves.

10) Close equalizer valve. 11) Open both the primary isolation valves.15. How do you calculate new factor from new range using old factor and old range. ?New Factor = _!New Range Old Factor = _IOld Range Flow = K_!RangeQ = Factor X Unit FlowNew Factor = Old Factor I _IOld Range X _/New Range.16. How will you vent air in the D.P. cell? What if seal pots are used?1) Air is vented by opening the vent plugs on a liquid service transmitter.2) On services where seal pots are used isolate the primary isolation valves and open the vent valves. Fill the line from the transmitter drain pluge with a pump.13. Why is flow measured in square root?Flow varies directly as the square root of different pressure F = K square root of AP. Since this flow varies as the square root of differential pressure the pen does not directly inlicate flow. The flow can be determinded by taking the square root of the pen. Say the pen reads 50% of chart.

Field Instrumentation Interview Questions and Answers0Q & A

May 9, 2015 A+A-EmailPrint 1.What are different types of orifice plates? State their uses. Different orifice plates are: 1. Concentric 2. Segmental 3. Eccentric – Concentric: These plates are used for ideal liquid as well as gases and steam service. Concentric holes are present in these plates, thats why it is known as concentric orifice. – Segmental: This plate has hole in the form of segment of the circle. This plate is used for colloidal and sherry flow measurement. – Eccentric: This plate has the eccentric holes. This plate is used in viscous and sherry flow measurement.

Field instruments interview questions and answers

2.How do you identify an orifice in the pipeline?

An orifice tab is welded on the orifice plate which extends out of the line giving an indication of the orifice plate.

3.Why is the orifice tab provided?

Following reasons justify for providing orifice tab: 1. Indication of orifice plate in a line 2. The orifice diameter is marked on it. 3. The material of the orifice plate. 4. The tag number of the orifice plate. 5. To mark the inlet of an orifice.Also Read : Smart Transmitter Questions & Answers4.Explain Bernoulli’s theorem. State its application. Bernoulli’s theorem states that the ‘total energy of a liquid flowing from one point to another remains constant’. It is applicable for non-compressible liquids. For different types of liquid flow Bernoulli’s equation changes. There is direct proportion between speed of fluid and its dynamic pressure and its kinetic energy. It can be used in various real life situations like measuring pressure on aircraft wing and calibrating the airspeed indicator. It can also be used to low pressure in the venturi tubes present in carburetor.5.How can a D.P. transmitter be calibrated? D.P. transmitter can be calibrated using following steps: 1. Adjust zero of Xmtrs. 2. Perform static pressure test: Give equal pressure on both sides of transmitter. Zero should not shift either side. If the zero shifts then carry out static alignment.

3. Perform vacuum test: Apply equal vacuum to both the sides. Zero should not shift. 4. Calibration procedure: Give 20 psi air supply to the transmitter and vent L.P. side to atmosphere. Connect output of the instrument to the standard test gauge. Adjust zero. Apply required pressure to the high pressure side and adjust the span. Adjust zero gain if necessary.

6.How is flow measured in square root?

Flow varies directly as the square root of pressure. Thus, F=K of square root of applied pressure. Since this flow varies as the square root of differential pressure. The pressure pen does not directly indicate flow. Thus flow can be determined by taking the square root of the pen. Assume the pen reads 50% of the chart. So, flow can be calculated using the pen measure in the chart.

7.Name different parts of a pressure gauge. Explain the use of hair spring in the pressure gauge. Pressure gauge includes following components: a. ‘C’ type bourdon tube. b. Connecting link c. Sector gear d. Pinion Gear e. Hair spring

f. Pointer g. Dial Use of hair spring: Hair spring is responsible for controlling torque. It is also used to eliminate any play into linkages..8.How D.P. transmitter can be applied to close tank? In closed tank, bottom of the tank is connected to the high pressure side of the transmitter. Top of tank is connected to the lower pressure side of the transmitter. In this way vessel pressure can be measured.9.How D.P. transmitter can be applied to open tank? In open tank the lower pressure side is vented to the atmosphere. All pressure is applied to the high pressure side. This vessel pressure is measured through high pressure side.10.Explain the working of an electronic level troll? The variation in level of buoyancy resulting from a change in liquid level varies the net weight of the displacer increasing or decreasing the load on the torque arm. This change is directly proportional to change in level and specific gravity of the liquid. The resulting torque tube movement varies the angular motion of the rotor in RVDT providing a rotor change proportional to the rotor displacement, which is converted and amplified to a D.C. current.11.Explain the working of an enraf level gauge. Enraf level gauge is based on the ser powered null balance technique. A displacer serves as continuous level sensing element. A two phase ser motor controlled by a capacitive balance system winds unwinds the the measuring wire until the tension in the weight springs is in balance with the weight of the displaced part immersed in the liquid. The sensing system in

balance measures the two capacitance formed by the moving central sensing rod provided by the two capacitor plates and the si plates.12.What is the constant voltage unit? The constant voltage circuit consists of a rectifier, CR and a filter capacitor. It is followed by two stages of zener regulation. Abridge configuration is provided to lamp line voltage zener regulation. Regulation 1 and regulation 2 provides relatively provide constant current. Resistors form a bridge that may remoment line voltage effects.13.Explain the burnout feature. Burnout provides the warnsug feature of driving indicator at the end of scale, if the input circuit is open. A burnout resistor is provided which develops a voltage drop between the measuring circuit and amplifier. The polarity of the signal determines the direction of the servo drive upon an open circuit in the input. Upscale burnout: R value 10 M Downscale burnout: R value 22 M14.Why thermowells are used? What materials are used in thermo wells? In numerous applications, it is neither desirable nor practical to expose a temperature sensor directly to a material. Wells are therefore used to protect against damage corrosion, arosion, aborsion and high pressure processes. A thermowell is also useful in protecting a sensor from physical damage during handling and normal operations. Materials used in thermowells: Stainless steel, Inconel, Monel, Alloy Steel, Hastelloy

15.How is automatic reference junction compensation carried out in temperature recorders? In automatic reference junction compensation, variable nickel resistor is used. As the temperature changes, so does its resistance. This reference junction compensator is located, so that it will be at the temperature of the reference junction. The reference junction is at the poset where the dissimilar wire of the thermocouple is rejoined. This joint is invariably at the terminal strip of the instrument.16.What are de-saturators? When, in some processes, e.g. batch processes, long transient responses are expected during which a sustained deviation is present the controller integral action continuously drives the output to a minimum or maximum value. This phenomenon is called ‘integral saturation of the control unit’. When this condition is met, then this unit is de-saturated.17.Explain the working of Rotameter. Variable area meters are special form of head meters. Where in the area of flow restrictor is varied. So as to hold the differential pressure constant. The rota meter consists of a vertical tapered tube through which the metered fluid flows in upward direction. As the flow varies the ‘float’ rises or falls to vary the area of the passages that the differential across it balances the gravitational force on the ‘float’. The differential pressure is maintained constant. The position of the ‘float’ is the measure of the rate of flow.18.What is the working principle of the magnetic meter? An electric potential is developed when a conductor is moved across the magnetic field. In most electrical machinery the conductor is a wire. The principle is equally applicable to a moving, electrically conductive liquid. The primary device of

commercial magnetic meters consist of straight cylindrical electrically insulated tube with a pair of electrodes nearly flush with the tube walls and located at opposite end of a tube diameter. This device is limited to electrically conducting liquids. The magnetic meter is particularly suited to measurement of slurries and dirty fluids.19.Explain the mechanism behind the turbine meter. Turbine meters consist of straight flow tube within which a turbine or fan is free to rotate about it s axis which is fixed along g the centre line of the tube. Mostly, a magnetic pick up system senses the rotation of the rotor through the tube walls. The turbine meter is a flow rate device, since the rotor speed is directly proportional to the flow rate. The output is usually in the form of electric pulses from the magnetic pick up with a frequency proportional to the flow rate.20.How would you choose differential range? The most common range for differential range for liquid measurement is 0-100. This range is high enough to minimize the errors caused by unequal heads in the seal chambers. It is also dependent on the differences in the temperature of the load lines. The 100 range permits an increased in capacity up to 400. While decrease down up to 20 by merely changing the range tubes or range adjustments.Also Read: Instrumentation Interview Questions21.What is the use of single seated valve? The single seated valve is used on smaller sizes where an absolute shut off is required. The use of single seated valve is limited by pressure drop across the valve in the closed or almost closed position.22.What is the use of double seated valve?

In double seated valves the upward and downward forces on the plug due to reduction of fluid pressure are nearly equalized. It is generally used on bigger size valves and high pressure systems. Actuator forces required are less.23.What is the use of valve positioner? Valve positioner can be used for following reasons: a. Quick action b. Valve hysterisis c. Viscous liquids d. Split range. e. Line pressure changes on valve f. Bench set not standard g. Reverse valve operations 24.What are primary elements of measuring pressure? Which type of pressure can be measured by these elements? Primary elements of measuring pressure are: a. Bourdon Tube b. Diaphragm c. Capsule d. Bellows e. Pressure springs These elements are known as elastic deformation pressure elements. 25.Name different types of bourdon tubes.

Types of bourdon tubes: 1. C type 2. Spiral 3. Helix26.What are different types of control valves? The commonly used control valves can be defined as follows: a. Depending on Action: Depending on action there are two types of control valves 1. Air to close 2. Air to close b. Depending on body: Depending on body there are 4 types of control valves 1. Globe valves single or double seated 2. Angle valves 3. Butterfly valves 4. Three way valves 27.What is furnace draft control? Balanced draft boilers are generally used negative furnace pressure. When both forced draft and induced draft are used together, at some point in the system the pressure will be same as that of atmosphere. Therefore the furnace pressure must be negative to prevent hot gas leakage. Excessive vacuum in the furnace however produces heat losses through air infiltration. The most desirable condition is that the one have a very slight negative pressure of the top of furnace.28.What is intrinsically safe system?

Intrinsic safety is a technique for designing electrical equipment for safe use in locations made hazardous by the presence of flammable gas or vapours in the air. Intrinsically safe circuit is one in which any spark or thermal effect produce either normally or under specified fault conditions is incapable of causing ignition of a specified gas or vapour in air mixture at the most ignited concentration.29.What is zener diode? What is voltage regulator? The breakdown region of a p-n diode can be made very sharp and almost vertical diodes with almost vertical breakdown region are known a s zener diodes. A zener diode operating in the breakdown region is equivalent to a battery. Because of this current through zener diode can change but the voltage remains constant. It is this constant voltage that has made the zener diode an important device in voltage regulation.Voltage regulator: The output remains constant despite changes in the input voltage due to zener effect.30.What is force balance principle? State some of its’ advantages. Force balance principle: A controller which generates an output signal by opposing torque. The input force is applied on the input bellows which moves the beam. This crackles nozzle back pressure. The nozzle back pressure is sensed by the balancing bellows which brings the beam to balance. The baffle movement is very less about 0.002 for full scale output.Advantages: a. Moving parts are fewer. b. Baffle movement is negligible c. Frictional losses are less31.What is motion balance principle?

A controller which generates an output signal by motion of its parts. The increase in the baffle is to move towards the nozzle. The nozzle back pressure will increase. This increase in the back pressure acting on the balancing bellows, will expand the bellows. The nozzle is moved upward due to this. The nozzle will move until motion almost equals the input baffle motion.32.How will you test a transistor with a multimeter? 1. Emitter +ve of meter and base -ve output =Low resistance 2. Emitter -ve of meter and base +ve output =High resistance 3. Collector +ve and base -ve output =Low 4. Collector -ve and base +ve output =Low Emitter: Collector = High resistance PNP: Opposite Results33.Explain ratio control system. A ratio control system is characterized by the fact that variations in the secondary variable don’t reflect back on the primary variable. A ratio control system is the system where secondary flow is hold in some proportion to a primary uncontrollable flow. If we assume that the output of a primary transmitter is A. and the output of the secondary transmitter is B, and that the multiplication factor of the ratio relay is K, then for equilibrium conditions which means set valve is equal to measured valve, we find the following relation: KA-B=0 or B/A = K where ‘K’ is the ratio setting off the relay.34.What is solenoid valve? Where it is used? A solenoid is electrically operated valve. It consists of solenoid coil in which magnetic plunger moves. This plunger is connected

to the plug and tends to open or close the valve. There are two types of solenoid valves: 1. Normally Open 2. Normally closed Use: It is used for safety purpose in different electric work.

Interview Questions on Fire detection system1Fire & Gas System, Q & AMay 2, 2015 A+A-EmailPrint

1.What is a ‘fire triangle’?

A fire triangle represents the three elements, which causes a fire in a combustible mixture. The three elements are fuel, air and ignition.

2.What is importance or a ‘hood’ on a gas turbine?

During a gas turbine normal running condition, a hood provides:

a.prevention of turbine high dB noise to outside areas

b.keeps the gas turbine clean from external dust

c.provides a draft for the gas leak to the exhaust through the hood fan

During a gas turbine shutdown condition a hood provides:

a.cooling the turbine body by way of the hood fan

b.During a fire shutdown it facilitates to put out the fire by confining the fire extinguishers on the gas turbine.

3.Why do we use ‘Halon’ as a fire extinguisher in a gas turbine hood?

Halon is stored in liquid form in a cylinder. When it is released in a hood during the occurrence of the fire, it discharges the halon in gas from. Halon does not act or react on electrical components.

4.What is the expansion from of B.C.F?

The expansion form of B.F.C is Bromo chloro floride.

5.In a Ruston gas turbine, why are there two Halon cylinders in each bank? How do they function?

The first bottle is the ‘first shot’ and the second bottle is ‘Extended shot’. The first bottle discharges the Galon into the hood through a 1’’ pipe in approximately 15 seconds, where as the extended bottle discharges the Halon through a ¼’’ pipe for another ½’’hour period to maintain the inert atmosphere.

6.How many UV detectors are installed in Solar, Ruston TB-5000 and Ruston TA-1750 gas turbine hoods?

Solar gas turbine hood: 4 UV detectors

Ruston TA-1750 hood: 4 UV detectors

Ruston TB 5000 hood: 12UV detectors

7.What is voting Logic of UV detectors in Soar and Ruston gas turbines?

There are two voting logics, they are: 1 out of 4 UV s and 2 out of 4 UV s

8.What happens when UV detectors detect a fire?

1out of 4 UV s: creates annunciation, audible alarm on the control panel and siren in the field (refer to the station drawings for the exact function and operations).

2 out of 4 UV s: creates annunciation, audible alarm on the control panel, a siren in the field, shutdown of the turbine and release of the fire extinguisher (refer to the station drawings for the exact function and operations).

9.How much is the time delay between fire sensing by a UV detector and confirming with an alarm?

Generally it is set for 4 secs. The UV detectors initiates a fire alarm only when the UV is detecting the fire continuously for 4 secs (refer to the station drawings for the exact settings parameters).

10.What are the Halon manual release facilities available on a Solar gas turbine?

Auto Halon cylinder can be discharged manually from the fire & gas control panel in the control room. On instiating the manual release:

a.The unit shuts down.

b.The auto Helon cylinder gets discharged in the hood.

c.Auto halon discharge confirmation and the auto Halon cylinder pressure low alarm appears on the control panel.

d.Audible alarm in the control room and siren in the field occurs.

Manual Halon cylinder can discharged manually from the field through a pall string. On initiating the manual release:

a.The unit shutsdown.

b.The manual Halon cylinder gets discharged in the hood.

c.Manual Halon discharge confirmation and the manual Halon cylinder pressure low alarm appears on the control panel.

d.Audible alarm in the control room and siren in the field occurs.

11.Why are there ‘heat switches’ in side the hood, when there are UV detectors?

Heat switches are a mechanical type and they are considered to be a positive type of fire detection system. The heat switch settings are much higher than the hood temperature.

12.What maybe the reasons if a unit shutdown on false heat detected alarm?

The reason could be:

a.Hood ventilation fan has failed or stopped.

b.Major hot gas leak inside the hood.

13.What happens when a heat switch actuates?

On detection of heat, the heat switch initiates the following.

Annunciation, audible alarm on the control panel, a siren in the field, shut down of the turbine and release of fire extinguisher (refer to the station drawings for the exact settings parameters).

14.Explain the operating principle of a gas monitor?

Gas monitor measures the imbalance in the current loop caused by its active and in-active filaments in the presence of a combustible gas.

15.Explain the calibration procedure of a gas monitor system.Gas sensor loop current or voltage at the sensor head is set as per the manufacturer’s recommended value.Gas monitor zero is adjusted to the instrument air.A test gas with a known quantity of combustion gas (Generally methane 2% by volume) is fed to the sensor and the span is adjusted to read 40% on the monitor scale (refer to the station drawings for the exact settings parameters).The calibration procedure is repeated until the zero and span reads correctly.

16.What are the alarm and shut down setting on a gas monitor?

Generally on the gas monitor, the alarm is set at 20%rising and the shut down is set at 60%rising (refer to the station drawing for the exact settings parameters)

17.What has to be done prior to entering a gas turbine hood?

Prior to entering a gas turbine, turn on the ‘ventilation defeat switch’.18.What is a ventilation defeat switch?On activating, the ventilation defeat switch inhibits the release of Halon in the auto mode and also the unit shutdown on ‘ventilation failure’.19.How much is the delay between fire detection and Halon release? Why is the time delay required?A time delay of 15 secs. Is set between the detection of fire and the initiation of Halon release. This is to achieve effective fire extinguishing by allowing the hood fan to run-down to zero speed and the bleed valves to release the compressed air.20.What does a hood ventilation fan do when a fire is detected? And why?On detection of fire, the fire system initiates the hood fan shutdown. This is to minimize the presence of air the hood for releasing the extinguisher.

Difference between DCS & PLC Systems3Control Systems, Instrumentation DesignDecember 23, 2015 A+A-Email

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DCS stands for “Distributed Control System”. DCS’s were designed to control processes, not discrete operations. As such, a large number of the inputs and outputs are analog like a 4-20mA signal or 0-10V signal. In Literary meaning, a Distributed Control System (DCS) refers to a control system usually of a process or manufacturing system, in which the controller elements are not central in location (like the brain) but are distributed throughout the system with each component sub-system controlled by one or more controllers. Process plants used to have long series of panel mounted Single Loop Controllers (Analog/PID controllers).

PLC stands for “Programmable Logic Controller”. Historically a PLC was in discrete control of manufacturing processes. Whole discrete logic used to be implemented with relay circuitry. Most of the inputs and outputs for discrete control are binary, meaning they have only two states: On and Off.

What are attributes and characteristics which differentiate the PLC system from the DCS. There have been claims and counter claims from different manufacturers that their system is DCS or PLC. The topic has remained under debate for long, and especially today when we have already entered into new era of Hybrid Distributed Control Systems, it has become increasingly difficult to select and differentiate the advantages and drawbacks one can get from different systems.

There are few similarities and dissimilarities which I would like to mention here:

1) DCS are designed or made available to the user in a way that only configuration in form of a Functional Block has to be carried out unlike PLC, where complete programming has to be implemented using any one of the different languages available in the system.Now, Functional Blocks are also available in the PLC systems, which really makes it comparable to DCS.

2) When DCS started emerging in the market, idea was to supply DCS with whole bunch of hardware and software packages including for Human Interface, necessary for the complete automation of the plant, thus facilitating Single Point Configuration in terms of database and communication possible in general. Additionally, Human Interface does not need separate communication package i.e DDE server, to communicate with the controller. DCS includes higher levels of application software for regulatory and batch control.

In case of PLC systems, PLC were not suppose to be in packages but competition with DCS vendors forced the PLC manufacturers to offer necessary all other softwares and packages.

3) Many DCS are designed such that it is possible to configure cycle time for each Functional Block. Thus DCS system takes care of cycle time scheduling of the Functional Blocks which are the basic execution units. This is one of the reason that overall scan time of the DCS is comparatively higher than the PLC system.This

functionality has been introduced in PLC systems(s) in some form as well.

4) A DCS has inherently multiple processor capability thus making the functionality distributed across a network. In a typical multi-processors (multi-node) DCS architecture, Engineer has to put in less efforts for inter-communication of the processors or one controller can easily access the Tag(s) from the database of the other .i.e the input of FB in one controller can be output of FB of the other controller. This is possible now in PLC but more efforts have to be put in.

5) DCS programming is centered around configuration of Functional Blocks and discrete logic is implemented in DCS using FBs, thus making the DCS inherently an analog control system (although ladder programming is also possible in some of the DCS also). PLCs were programmed using Ladder/Relay language , before arrival of IEC 1131-3 standard and Analog control was incorporated inside Ladder inside Ladder Logic using special FBs. This is probably the reason we look at some of the process plants that process (Analog) control is done by the DCS, while emergency control (Discrete Control) is implemented by PLC based systems.

6) PLCs are still being used at RTU stations because of their simple, small and cheaper architecture as well as engineering (typically the RTU application) instead of big DCS. DCS have been used as the central system in a SCADA network. In a typical SCADA scenario, one DCS is connected to many PLCs systems.

7) Being Discrete in nature, PLC was natural choice of manufacturer and end-user to apply it for safety system. This led to production of specialized safety system conforming to SIL3 certification in accordance with ANSI / ISA 84.00.01-2004.

Today, a lot has changed, it is difficult to distinguish between two systems in terms of its main features. Differences between the two has virtually vanished due to Programming / Configuration language standard IEC-61131.The functionality of the PLC has evolved over the years to include sequential relay control, motion control, process control, distributed control systems and networking. However, in major industrial areas and structure markets, it is practice to deploy DCS for process control and PLC based system for safety control. Perhaps, for a large install base like more than 1000 I/Os system, cost of installation, addition and maintenance per I/O is less in case of DCS system.

Now, more important is cost, application, system integrity, reliability, maintainability, historical logging / intelligent statistics and learning / training. How much support is available from the vendor for the operation matters most to the operator now. This has resulted into ‘Solutions Packages’ by vendors to their customers instead of simply offering individual products. It is DCS or PLC, must come in a solution package. More and improved System functionalities have made these system more complex which require strong integration between the operator /user and the manufacturer.

Few vendors also introduced Hybrid DCS / PLC system or transformed their PLC based system into DCS by incorporating similar features. DCS vendors have now introduced packages for

Asset Optimization and management which seamlessly integrate with their systems. It is difficult to say which system to select ? It varies from user to user as discussed above. It is End-User who has to have all knowledge and courage to take responsibility of his system in totality.

DCS Vs. PLC

DCS stands for Distributed Control System. A DCS typically covers an entire process, and is capable of covering an entire plant.

A DCS combines one or more PLCs with an HMI, and allows the integrator to build both together. The project is often developed with the entire DCS in mind so that all aspects of the system are developed together – instead of developing the PLC first, then the HMI, followed by alarms, historian, etc.

A DCS takes the PLC/HMI combo and combines several other features into an integrated package:Servers and clients. The servers gather tag data from the PLC(s), contain the graphics, and serve both out to clients for operators to use.Redundant servers, controllers and/or networks.Synchronized alarming and security.Historical data logging and trending.Batch management.

What Are The Benefits of Each?

Now, onto the other major differences between the two. I’d like to preface this section by saying that there are always going to be exceptions. These are general differences and advantages, and are not meant to be exclusionary.

What Are the Benefits of a PLC/HMI Combo?

The biggest benefit I’ve seen to a PLC is that it is easier for plant personnel to implement and configure internally than a DCS. There are many technicians and engineers that have experience with ladder logic, and if you have one or more on your staff, you may decide to take care of your processes in-house.

Also, if the PLC will be controlling a machine that requires very fast response times, a PLC is the best choice. A DCS controller can have a fast response time, but that’s not what it’s intended for.

Furthermore, purchasing a PLC allows you to buy only the software with the features you need. If you have a simple application or a standalone skid system, a PLC (with a small HMI) might be all you need. If you were to buy a DCS, you might shell out a lot of money for features you don’t need.

Finally, in a pinch, a PLC can be installed, programmed and ready to go very quickly.

PLCs are often used in:Machine automation (quicker processing time).Skids, stand-alone systems (doesn’t need to be part of plant-wide system, or is developed by an OEM).Utilities (lower in cost).

What Are The Benefits of a DCS?

In addition to combining one or more PLCs with one or more HMIs, a DCS offers:High availability via: Redundant Controllers.Redundant operator system servers.Redundant networks.Server-client relationships.Reduced engineering time.Shorter start-ups.Minimal troubleshooting of included features.Controller code built with entire system in mind. Code includes settings for: HMI graphics and faceplates.Historical data and trending.Alarms.

Operator features and security.Lends itself to better organization and consistency than a PLC/HMI combo.Easily integrated with: Batch management.Process Historian.OPC server.

PLC vs. DCS: Which is Right for Your Operation?

Over the past decade, the functionality of different control systems has been merging. Programmable logic controllers (PLCs) now have capabilities once found only in distributed control systems (DCSs), while a DCS can handle many functions previously thought more appropriate for PLCs. So what’s the difference between the two control approaches, where’s the dividing line and are there still reasons to choose one over the other?

PLCs grew up as replacements for multiple relays and are used primarily for controlling discrete manufacturing processes and standalone equipment. If integration with other equipment is required, the user or his system integrator typically has to do it, connecting human-machine interfaces (HMIs) and other control devices as needed.

The DCS, on the other hand, was developed to replace PID controllers and is found most often in batch and continuous production processes, especially those that require advanced control measures. The vendor handles system integration, and HMIs are integral.

As users demanded more production information, PLCs gained processing power and networking became common. PLC-based control systems began to function like a mini-DCS. At the same time, the DCS hybridized to incorporate PLCs and PCs to control certain functions and to provide reporting services. The DCS supervises the entire process, much like the conductor in an orchestra. Protocols, like OPC, have eased interactions between the two control systems.

Since PLCs are less expensive and can now perform much like a DCS, wouldn’t it make sense to convert everything to PLCs? The answer, like most things in the world of automation, is that it depends on the needs of your application. Here are six key factors to consider:

1. Response time

PLCs are fast, no doubt about it. Response times of one-tenth of a second make the PLC an ideal controller for near real-time actions such as a safety shutdown or firing control. A DCS takes much longer to process data, so it’s not the right solution when response times are critical. In fact, safety systems require a separate controller.

2. Scalability

A PLC can only handle a few thousand I/O points or less. It’s just not as scalable as a DCS, which can handle many thousands of I/O points and more easily accommodate new equipment, process enhancements and data integration. If you require advanced process control, and have a large facility or a process that’s spread out over a wide geographic area with thousands of I/O points, a DCS makes more sense.

3. Redundancy

Another problem with PLCs is redundancy. If you need power or fault tolerant I/O, don’t try to force those requirements into a PLC-based control system. You’ll just end up raising the costs to equal or exceed those of a DCS.

4. Complexity

The complex nature of many continuous production processes, such as oil and gas, water treatment and chemical processing, continue to require the advanced process control capabilities of the DCS. Others, such as pulp and paper, are trending toward PLC-based control.

5. Frequent process changes

PLCs are best applied to a dedicated process that doesn’t change often. If your process is complex and requires frequent adjustments or must aggregate and analyze a large amount of data, a DCS is typically the better solution. Of course, the very flexibility of a DCS system also makes it much more vulnerable to “meddling” by operators that can cause spurious shutdowns.

6. Vendor support

DCS vendors typically require users to employ them to provide integration services and implement process changes.

System integrators perform similar functions for PLC-based systems. It has also become common for PLC vendors to offer support services through their network of system integrator partners.

Process control has become increasing complex. It’s difficult for any individual to know everything about these sophisticated systems, increasing the need for vendor support. Manufacturers also continue to reduce factory staff and a generation of experienced process control personnel has begun to retire. As a result, the quality of support has become a critical factor in vendor selection.

So, How Do I Choose Which One I Need?

What’s the long term plan for the facility? If you have any intent of tying it all together into a DCS, and the process you’re currently looking at has a part in it, there’s no time like the present to start your DCS migration.Is the process a stand-alone, supporting or skid system? If so, a PLC and HMI could be all you need, and if you decide to migrate the rest of the plant to a DCS in the future, this system could stay a PLC/HMI combo.Do you want to configure, build and commission the system yourself? If so, and you don’t have formal DCS training, you should put in a PLC and HMI combo. Most DCS packages are so complex that they require formal training, and without it, you could get into trouble.Do you need a high availability system? What if the controller dies, or your HMI goes down? You might need redundancy for your controllers and/or OS (operator system) servers. If so, consider a DCS.Are you going to need a historian, multiple clients, a trend package, batch system, and other DCS features? Granted, there are HMI packages that provide all these features, but keep in mind that a DCS provides them as well.Is it a large system that you will have an integrator build and commission? If so, I strongly recommend a DCS. It will save you time and money in the long run.

Intrinsic Safety Protection ia and ib0Standards

January 5, 2016 A+A-EmailPrint Difference Between ia and ib Intrinsic Safety Protection

ProtectionType ia

Apparatus is designed so that it is suitable for Zone 0 & it will not cause ignition when the maximum permitted values are applied to its terminals:

a) in normal operation with application of those non-countable faults which give the most onerous condition;

b) in normal operation with application of one countable fault and those non-countable faults which give the most onerous condition; and

c) in normal operation with application of two countable faults and those non-countable faults which give the most onerous condition.

Normal operation means that the apparatus conforms to the design specification supplied by the manufacturer, and is used within electrical, mechanical, and environmental limits specified by the manufacturer.

Normal operation also includes open circuiting, shorting, and grounding of external wiring at connection facilities. When assessing or testing for spark ignition, the safety factors to be applied to voltage or current are 1.5 in conditions a and b, and 1.0 in condition c. (These factors should properly be called “test factors.”

The real safety of intrinsic safety is inherent in the use of the sensitive IEC apparatus to attempt to ignite the most easily ignitable mixture of the test gas with hundreds of sparks. This combination of conditions is many times more onerous than any likely to occur in practice.)

North American Intrinsic Safety design standards are equivalent to ia intrinsic safety.

ProtectionType ib

Apparatus is designed so that it is suitable for Zone 1, & it is assessed or tested under the conditions of a and b above, with a safety factor on voltage or current of 1.5 in the condition of a and b.It is likely that Level of protection ic apparatus, equivalent to and replacing Type of Protection nL, suitable for use in Zone 2, will be standardized.Figure typical grounded and ungrounded two wire intrinsically safe circuits.Figure illustrates the principle that every ungrounded conductor entering the Division 1/Zone 0, or 1 location in this case where the transmitter or transducer is located, must be protected against unsafe voltage and current by appropriate associated apparatus. The boxes with three terminals represent barriers, independently certified protective assemblies, certified and rated according to the national standard. Nonintrinsically safe devices connected to the barrier need only be suitable for their location, and must not contain voltages higher than the Um rating of the barrier.Many barriers are passive, consisting of current limiting resistors and voltage limiting diodes in appropriate configuration and redundancy to meet the requirements of the standard. Others have active current or voltage limiting. Both types may be combined with other circuitry for regulating voltages, processing signals, etc. The user should follow the recommendation of the intrinsically safe apparatus manufacturer in the control drawing, or discuss the selection of appropriate barriers with the barrier vendor, all of whom have proven configurations for many field mounted devices.

Why choose intrinsic safety ?0Safety SystemsOctober 25, 2015 A+A-EmailPrint

Intrinsic safety (IS) is a low-energy signalling technique that prevents explosions from occurring by ensuring that the energy transferred to a hazardous area is well below the energy required to initiate an explosion.

The energy levels made available for signalling are small but useable and more than adequate for the majority of instrumentation systems.

The two mechanisms being considered that could initiate an explosion are:A spark

A hot surface

The advantages of intrinsic safety

The major advantage of intrinsic safety is that it provides a solution to all the problems of hazardous areas (for equipment requiring limited power) and is the only technique which meets this criterion. The significant factors are as follows:

a) The IS technique is accepted throughout the There is an increasing acceptance of international certificates issued under the IEC Ex scheme but this has some way to go. Intrinsic safety is an acceptable technique in all local legislation such as the ATEX Directives and OSHA. The relevant standards and code of practice give detailed guidance on the design and use of intrinsically safe equipment to a level which is not achieved by any of the other methods of protection.

b) The same IS equipment usually satisfies the requirements for both dust and gas

c) Appropriate intrinsically safe apparatus can be used in all In particular, it is the only solution that has a satisfactory history of safety for Zone 0 instrumentation. The use of levels of protection (‘ia’, ‘ib’ and ‘ic’) ensures that equipment suitable for each level of risk is available (normally ‘ia’ is used in Zone 0, ‘ib’ in Zone 1 and ‘ic’ in Zone 2

d) Intrinsically safe apparatus and systems are usually allocated a group IIC gas classification which ensures that the equipment is compatible with all gas/air Occasionally, IIB systems are used, as this permits a higher power level to be used. (However, IIB systems are not compatible with acetylene, hydrogen and carbon disulfide.)

e) A temperature classification of T4 (135°C) is normally achieved, which satisfies the requirement for all industrial gases except carbon disulfide (CS ) which, fortunately, is rarely

f) Frequently, apparatus, and the system in which it is used, can be made ‘ia IIC T4’ at an acceptable This removes concerns about area classification, gas grouping and temperature classification in almost all circumstances and becomes the universal safe solution.

g) The ‘simple apparatus’ concept allows many simple pieces of apparatus, such as switches, thermocouples, RTD’s and junction boxes to be used in intrinsically safe systems without the need for certifica This gives a significant amount of flexibility in the choice of these ancillaries.

h) The intrinsic safety technique is the only technique that permits live maintenance within the hazardous area without the need to obtain ‘gas clearance’ certifica This is particularly important for instrumentation, since fault-finding on de- energised equipment is difficult.

i) The installation and maintenance requirements for intrinsically safe apparatus are well documented, and consistent regardless of level of This reduces the amount of training required and decreases the possibility of dangerous mistakes.

j) Intrinsic safety permits the use of conventional instrumentation cables, thus reducing Cable capacitance and inductance is often perceived as a problem but, in fact, it is only a problem on cables longer than 400 metres, in systems installed in Zones 0 and 1, where IIC gases (hydrogen) are the source of risk. This is comparatively rare and, in most circumstances, cable parameters are not a problem.

Fig 1.0 Available Power Curves

Available power

Intrinsic safety is fundamentally a low energy technique and consequently the voltage, current and power available is restricted. Figure 1.0 is a simplified illustration of the available power in intrinsically safe circuits and attempts to demonstrate the type of electrical installation in which the intrinsically safe technique is applicable.

The blue and green curves are the accepted design curves used to avoid spark ignition by resistive limited circuits in Group IIC and IIB gases. The ‘ic’ curves are less sensitive because they do

not require the application of a safety factor in the same way as for

‘ia’ and ‘ib’ equipment. In general the maximum voltage available is set by cable capacitance (400 metres corresponds to 80nF which has a permissible voltage of 29V in ‘IIC ia’ circuits) and the maximum current by cable inductance (400 metres corresponds to 400µH which has a permissible current of 300 mA in IIC ia circuits). A frequently used limitation on power is the 1.3W, which easily permits a T4 (135°C) temperature classification. These limits are all shown in Figure 1.0

A simple approach is to say that if the apparatus can be operated from a source of power whose output parameters are within the (blue) hatched area then it can readily be made intrinsically safe to ‘ IIC ia T4’ standards. If the parameters exceed these limits to a limited degree then it can probably be made intrinsically safe to IIB or ‘ic’ requirements.

The first choice, however, is always to choose ‘IIC ia T4’ equipment, if it provides adequate power and is an economic choice, as this equipment can be used in all circumstances (except if carbon disulfide (CS ) is the hazardous gas, in which case there are other problems).

In practice almost all low voltage instrumentation can be made

‘IIB ic T4’ as the limits are set by the least sensitive of the ignition curves in Figure 1.0 (typically 24V 500 mA). The ‘IIB ic’

specification does restrict application to Zone 2 and where the hazardous gas is not hydrogen, acetylene or carbon disulfide but is still applicable to a large range of installations.

Conclusion

Intrinsic safety is the natural choice for all low voltage instrumentation problems. Adequate solutions exist which are compatible with all gases and area classifications. The technique prevents explosions rather than retains them which must be preferable, and the ‘live maintenance’ facility enables conventional instrument practice to be used.Why use intrinsic safety?The principal reason for using intrinsic safety is because it is essentially a low power technique. Consequently, the risk of ignition is minimised, and adequate safety can be achieved with a level of confidence that is not always achieved by other techniques.It is difficult to assess the temperature rise, which can occur if equipment is immersed in a dust because of the many (frequently unpredictable) factors, which determine the temperature rise within the dust layer. The safest technique is therefore to restrict the available power to the lowest practical level. A major factor in favour of intrinsic safety is that the power level under fault conditions is controlled by the system design and does not rely on the less well-specified limitation of fault power.Intrinsic safety also has the advantage that the possibility of ignition from immersed or damaged wiring is minimised. It is desirable to be able to do ‘live maintenance’ on an instrument system, and the use of the intrinsically safe technique permits

this without the necessity of special ‘dust free’ certificates. There is a need to clear layers of dust carefully and to avoid contamination of the interior of apparatus during maintenance but this is apparent to any trained technician. (There is no significant possibility of a person, in a dust cloud that can be ignited, surviving without breathing apparatus). To summarise, intrinsic safety is the preferred technique for instrumentation where dust is the hazard because:the inherent safety of intrinsic safety gives the greatest assurance of safety and removes concern over overheating of equipment and cablesthe installation rules are clearly specified and the system design ensures that all safety aspects are coveredlive maintenance is permittedequipment is available to solve the majority of problems.