Basic Instrumentation

Prepared By: Scott Craig, Instrument Specialist, QG3&4 Completions / Commissioning Team July 2008Reference information provided by: Liptak, B.G (editor in chief), Instrument Engineers Handbook: Process Measurement and Analysis;

ObjectiveThe objective of this presentation is to give operations personnel a general appreciation of the main elements and devices for process instrumentation and measurement. We will also look at on site applications and general considerations with respect to installation requirements on the given equipment. Within this material we will be looking at the main principles and instrument devices to accurately measure for: Flow Level Pressure Temperature

We will also cover an overview of: Distributed Control Systems (DCS) Emergency Shutdown Systems (ESD) Loop and Function Testing. Foundation Fieldbus

Flow MeasurementPurpose of Flow Measurement Accurate measurement of flow is essential in many process control applications. These measurements are used to monitor and control flow rates. The flow measurement, along with measurements of temperature, pressure, and composition, are used to develop material and energy balances on processes. Also, in some applications, controlling the feed rate in a particular upstream process helps to sustain the efficiency and to minimize waste in downstream processing operations. Flowmeter Definition A flowmeter is defined as A device that measures the rate of flow or quantity of a moving fluid in an open or closed conduit. It usually consists of a primary device and a secondary device. Primary Device Definition A primary device is defined as The device mounted internally or externally to the fluid conduit that produces a signal with a defined relationship to the fluid flow in accordance with known physical laws relating the interaction of the fluid to the presence of the primary device. Secondary Device Definition A secondary device is defined as The device that responds to the signal from the primary device and converts it to a display or to an output signal that can be translated relative to flow rate or quantity. Note: The secondary device may consist of one or more elements as needed to translate the primary device signal into standardized or nonstandardized display or transmitted.

Flowmeter

Orifice PlateOrifice Plate An orifice plate is the main element within an orifice meter tube. An orifice plate is the simplest and most economical type of all differential pressure flowmeters. An orifice plate is constructed as a thin, concentric, flat metal plate. The plate has an opening or orifice. An orifice plate is installed perpendicular to the fluid flow between the two flanges of a pipe. As the fluid passes through the orifice, the restriction causes an increase in fluid velocity and a decrease in pressure. The potential energy (static pressure) is converted into kinetic energy (velocity). As the fluid leaves the orifice, fluid velocity decreases and pressure increases as kinetic energy is converted back into potential energy (static pressure). on an orifice plate installation there is a pair of flanges, upstream and downstream piping, and a pressure tap. The pressure taps are located either on orifice flanges or upstream and downstream of the pipe from the orifice plate.

General Considerations Orifice plates should be installed in straight runs of pipework 20-25 times the diameter of the pipe upstream and 5-7 times the diameter of the pipe downstream. Orifice plates should be installed with the tagged handle installed in the upstream direction and the chamfered edge (Bevel) in the downstream direction. Orifice plate chamfered edge should be clean, sharp and be at an angle of 45 degrees. Orifice plates should be stored / protected accordingly to prevent mechanical damage prior to installation. Orifice plates should be removed from pipework prior to line blowing / flushing to prevent damage.

Orifice Tube

HP

LP

Flow

HP

LP

Flow

Differential PressureDifferential Pressure Transmitters The differential pressure flowmeters output a nonlinear signal that corresponds to the square of the flow rate. A change in flow at a low rate produces a very small signal change. A change in a large flow rate produces a much larger signal change. For example, a small flow rate from 0 to10% outputs a signal from 0 to 1%; for a large flow rate, a 90 to 100% flow rate change outputs an 81 to 100 % signal. A transducer called a square root extractor is often used with transmitters. A transducer converts a square root signal to a linear signal. The differential pressure transmitter outputs a signal that is used for control, indication, or totalization.

General Considerations Transmitters should be mounted in areas which are free from vibration The transmitter should be mounted at a convenient height of 4 or 5 feet (1.2 or 1.5 meters) above grade, platforms or walkways. If this is not possible other permanent means of access should be provided. Impulse lines for remote devices should be as short as possible lines greater than 6 meters should be avoided. For Liquid service impulse lines should slope downward to device (general rule 25cm per 300cm) For Gas service impulse lines should slope upwards to device (rule as above) Process and manifold valveing should be checked and lined up appropriately before introduction of process. Instrumentation should have appropriate preservation measures attached up to the point of commissioning

Level MeasurementPurpose of Level Measurement The purpose of level measurement is to provide a measured variable representing the height or material presence within a vessel. Level measurement is essential to the effective control of a vessels process material level. The level control scheme for a vessel requires a level measurement value. The level measurement value provides the level control scheme either a quantity, such as a representation of height, or a logical value, such as the on/off condition of a limit switch that represents the detection of process material presence. Continuous Level Process Measurements In continuous level process measurements, a level measurement system can provide a numeric representation of the current position (height) of the process materials surface. The numeric value, sometimes expressed in meters or feet, is based upon a proportion of material currently sensed by the level measurement system. The level is measured continuously between a lower reference level and an upper reference level.

Displacer Level MeterTorque Tube Displacer Displacement level measurement is the most common measurement within the process industry. A torque tube displacer is so named because torque due to buoyancy. Forces acting upon the displacement element are used to infer a level measurement. At the top of the torque tube chamber, the displacers buoyancy force is measured by a torque arm assembly. As the level in the tank changes, the level in the external chamber changes. As the level changes, the buoyant forces placed upon the displacer changes. Although the small movement on the displacer appears insignificant to an observer, the small movement produces a torque that can be measured and converted to a level measurement.

Level SwitchLevel Switch A Level switch operates on the same principle as the float in a household flush toilet tank. Many level switches operate on this principle. Instead of activating a mechanical valve, floats activate switches. The switches, in turn indicate status, control equipment, such as a pump or control valve. The control equipment raises or lowers the level until the switch de-activates, which in turn causes the control equipment to go to the desired on or off state.

General Considerations Instrumentation should be mounted in a location free from vibration. Items should be installed in location that is accessible. For general service, externally mounted level devices housed within a chamber are preferred, since they permit access for calibration and maintenance. Block valves should be located at the vessel connection or on a standpipe so that each instrument can be isolated. Connections between vessels and heavy gauges, controllers, or transmitters should be relieved of strain by properly supporting such instruments. Equipment should only be installed when possibility of mechanical damage is negligable. Instrumentation should have appropriate preservation measures attached up to the point of commissioning

Pressure MeasurementPurpose of Pressure Measurement In process measurement, the values of process variables (e.g., pressure, temperature, level, and flow) in a process operation are continually determined to permit the process operation to be monitored or, more specifically, to permit the process variables to be controlled (i.e., held at their setpoints or within their operating ranges). Effective monitoring depends on accurate measurements of pressure for the following reasons: Pressure values themselves are essential data for monitoring. Often, the values of process variables other than pressure are derived from (inferred from) the values that are measured for pressure. As an example of inferral from pressure, the value for the level of a liquid in a storage tank can be derived from the value of the hydrostatic pressure that is exerted by the liquid. As another example, the value for the rate at which a fluid is flowing through a pipeline can be derived from a differential pressure value that is produced by an orifice plate.

Pressure TransmitterThe pressure transmitter has a diaphragm as pressure receiving part which converts pressure to strain, and the strain is detected by semi-conductor strain gage. The detecting part has full bridge system which consists of four semi-conductor strain gages. Electrical signal is obtained from the bridge circuit that is proportional to the strain. The signal is converted to direct current output or DC voltage output by a signal conversion circuit. This linear strain is then correlated to the corresponding pressure.

Pressure GaugeTypically, pressure gauges are devices used for measuring the pressure of a gas or liquid. The value of pressure is then read manually at the point location within the field. This reading is essential from the point of view that outside operators can determine if process plant is operating as intended and providing a visual representation of the actual pressure in the system. The pressure gauge functions by means of expansion of a Bourdon tube which moves proportionally to applied pressure.

General Considerations Instrumentation should be mounted in a location free from vibration The transmitter should be mounted at a convenient height of 4 or 5 feet (1.2 or 1.5 meters) above grade, platforms or walkways. If this is not possible other permanent means of access should be provided. Impulse lines for remote devices should be as short as possible lines greater than 6 meters should be avoided. For Liquid service impulse lines should slope downward to device (general rule 25cm per 300cm) For Gas service impulse lines should slope upwards to device (rule as above) Process and manifold valveing should be checked and lined up appropriately before introduction of process. Pressure gauges should be installed at a stage where mechanical and accidental damage is negligable. Instrumentation should have appropriate preservation measures attached up to the point of commissioning

Temperature MeasurementPurpose of Temperature Measurement Accurate temperature measurement is essential to the process control of distillation, fractionation, storage, and transportation of intermediate and final products. Additionally, temperature measurement contributes to greater product yield and better quality processing. Accurate temperature measurement is essential to maximize the efficiency or throughputs of processing operations. Measuring and controlling temperature also minimizes the reprocessing of the product because it does not meet the specification requirements.

Thermowell A thermowell helps protect a temperature sensor from a process fluids pressure, corrosive or erosive effects, or mechanical damage from the impact of flowing fluids. A thermowell is constructed as a sturdy, metallic, tube-shaped enclosure. Industry standards, such as ISA S1.2 and ISA S19.3, define thermowells that permit interchangeability among bimetallic thermometers, thermocouples, and RTDs. The thermowells constructed to these standards are engineered to give the best combination of strength and speed of response. The thermowell is often specified along with the temperature sensor and related assemblies to make sure that the sensor fits within the thermowell.

ThermocoupleThermocouples are perhaps one of the most common devices used in process control for temperature measurement. A thermocouple consists of two dissimilar metal wires fastened together at one end to form a junction. The junction is called the hot or measuring junction. The opposite end of the wires can be joined to form a reference or cold junction.

Resistance Temperature Detector RTDA resistance temperature detector is a sensor whose electrical resistance change is a function of temperature change. Certain materials have been identified that provide a predictable and stable relationship between resistance and temperature. Only a few metalssuch as platinum, copper, or nickelhave those properties necessary to make an RTD. Platinum is especially suited for RTD construction.

General Considerations Thermowells are required to be sized accordingly to minimise the effect of damage due to flow rates (Wake Frequency) Thermocouples and RTDs are required to be fitted inside thermowells. Thermocouples / RTDs should be fully grounded (Touching the bottom) within the thermowell to ensure correct temperature indication. Thermocouple types should be selected to match required temperature ranges. Cables connected to Thermocouples / RTDs should be kept clear of process pipework to prevent damage. Instrumentation should have appropriate preservation measures attached up to the point of commissioning

Typical On-Site Installations

Typical On-Site Installations

Typical On-Site Installations

On-Site PreservationGOOD PRESERVATION

BAD PRESERVATION

Distributed Control SystemDistributed Control Systems (DCSs) are dedicated systems used to control manufacturing processes that are continuous or batch-oriented, such as LNG production, oil refining and petrochemicals. DCSs are connected to sensors and actuators and use setpoint control to control the flow of material through the plant. The most common example is a setpoint control loops consisting of a pressure sensor, controller, and control valve. Pressure or flow measurements are transmitted to the controller, usually through the aid of a signal conditioning Input/Output (I/O) device. When the measured variable reaches a certain point, the controller instructs a valve or actuation device to open or close until the fluidic flow process reaches the desired setpoint. Large oil refineries have many thousands of I/O points and employ very large DCSs. A typical DCS consists of functionally and/or geographically distributed digital controllers and, in addition to proportional, integral, and derivative (PID) control, can generally perform logic and sequential control. DCSs may employ one or several workstations and can be configured at the workstation or by an off-line personal computer. Local communication is handled by a control network with transmission over twisted pair, coaxial, or fiber optic cable. A server and/or applications processor may be included in the system for extra computational, data collection, and reporting capability.

Emerson Delta VWithin QG3&4 the DCS system will be Emerson Delta V DeltaV hardware consists of a variety of input/output modules connected to a digital control computer located with the I/O modules. This hardware is proprietary. The controllers are attached to a larger redundant DeltaV plant-wide network which includes the PC-based engineering workstations and the operator workstations. Redundant hardware at the controller and I/O level is possible with the DeltaV architecture. Redundant hardware increases overall system availability. If redundant hardware is used, it is possible to update firmware and while maintaining process control. Operator interface As with all DeltaV applications, the DeltaV operator interfaces run on dedicated DELL PC hardware and Microsoft Windows XP / Server2003 operating system software. DeltaV Operate is the application program in the DeltaV suite which presents the interface to the operator and allows the operator to view and manipulate the process.

DCS Face Plate Displays

Emergency Shutdown SystemEmergency shutdown systems (ESDs) are used to provide for the safe operation of process plants. Safe operation involves safety of plant personnel and of the community surrounding the plant as well as plant operation without severe damage to equipment. ESDs are stand alone systems and provide 1 layer of a multi layer protection system which provides mitigation of unexpected emergencies in the process plant environment. ESDs are designed to protect plant equipment and plant personnel, the environment, and the . community in proximity to plants from potential adverse effects caused by unexpected emergencies, such as fires, explosions, and hydrocarbon or toxic gas releases. ESDs also function to isolate hydrocarbon streams entering or exiting plant equipment and facilities, remove heat input to process heaters and boilers, and de-energize all associated rotating equipment. ESDs interface with DCS systems via Communication links to all inputs to the ESDs and outputs from the ESDs can be viewed and manipulated from the DCS.

TRICONEXWithin QG3&4 the main ESD system will be Triconex The TRICONEX System is a state-of -the-art fault tolerant controller based on a Triple-Modular Redundant (TMR) architecture. TMR employs three isolated, parallel control systems and extensive diagnostics integrated into one system. The system uses two-out-of-three voting to provide high integrity, error-free, uninterrupted process operation with no single point of failure. All diagnostic information is stored in system variables and annuniciated with Light Emitting Diode (LED) indicators. This indication is also re-transmitted back to the DCS system. Benefits and features of the Triconex. No single point of failure The failure of any single component will not affect the correct operation of the system. Design flexibility Applications vary in their design requirements and the system's strength is its ability to be configured according to the level of safety, availability and system cost required. Simplex and dual I/O modules allow you to choose between different levels of coverage ranging from simplex to TMR and reducing overall system cost. Very high safety integrity With its TMR architecture and high diagnostic coverage, the TRICON system achieves Safety Integrity Level 3 as defined in the IEC 61508 Draft Standard on Functional Safety. This system is also certified by TUV for safety related operation in applications requiring the German Safety Requirement Class 5.

ESD Face Plate Displays

Function & Loop TestingLOOP TESTING Object: To prove that the installed instrumentation functions correctly and is operational, ready to hand-over for plant commissioning Input Test: A simulation of the process variables is applied and read in the control room on the relevant DCS screen. Output Test: The final action e.g CVs is checked against output settings made at the DCS console for 0,25,50,75 & 100% Output FUNCTION TESTING Object: To prove the functionality of advanced and complex controls, interlocks, IPS Logic, Vendor Control and Overall System Integrity. Function tests consist of simulating the respective systems inputs and then monitoring the resultant outputs to ensure compliance with the design intent.

Loop Testing

Input Check: 1. Field technician connects communicator or process simulator to transmitter. 2. Field technician then injects signal appropriate to actual process values. 3. Control room technician monitors and records values on DCS Screen. Output Check: 1. Control room technician inputs values to DCS (0,25,50,75,100%) 2. Field technician monitors valve movement as inputted by Control room tech. 3. Control room technician monitors feedback, Auxiliaries, etc

Loop Testing by System

Function Testing

1. 2. 3. 4.

Field technician manipulates field device or devices Control room technician monitors Control System / IPS / MARK VI / F&G etc Field Technician witnesses operation of output device or devices Control room technician witnesses feedback and records actions for compliance with design specification / Cause and Effect etc.

Function & Loop TestingOperations Involvement Testing will take place between field and relevant ITRs / Control Room Loop Tests 100% Witnessed by Company for Verification and Sign off in Project Completions Database. Witnessing by Operations for Appreciation of Loop Testing Process and Familiarisation with DCS Screens and Actions. Function Tests 100% Witnessed by Company for Verification and Sign off in Project Completions Database. Operations included to RFI look ahead for Function Tests to allow the Required Level of Witnessing and Familiarisation with the Functionality of the Relevant Instrument System.

Foundation FieldBus FOUNDATION fieldbus is an all-digital, serial, two-way communications system that serves as the base-level network in a plant or factory automation environment. It's ideal for applications using basic and advanced regulatory control, and for much of the discrete control associated with those functions. Two related implementations of FOUNDATION fieldbus have been introduced to meet different needs within the process automation environment. These two implementations use different physical media and communication speeds. H1 works at 31.25 Kbit/sec and generally connects to field devices. It provides communication and power over standard twisted-pair wiring. H1 is currently the most common implementation. HSE (High-speed Ethernet) works at 100 Mbit/sec and generally connects input/output subsystems, host systems, linking devices, gateways, and field devices using standard Ethernet cabling. It doesn't currently provide power over the cable, although work is under way to address this.

Foundation FieldbusConventional analog and discrete field instruments use point-to-point wiring: one wire pair per device. They're also limited to carrying only one piece of information -- usually a process variable or control output -- over those wires. As a digital bus, FOUNDATION fieldbus doesn't have those limitations. Multidrop wiring. FOUNDATION fieldbus will support up to 32 devices on a single pair of wires (called a segment) -- more if repeaters are used. In actual practice, considerations such as power, process modularity, and loop execution speed make 4 to 16 devices per H1 segment more typical. That means if you have 1000 devices -- which would require 1000 wire pairs with traditional technology -- you only need 60 to 250 wire pairs with FOUNDATION fieldbus. That's a lot of savings in wiring (and wiring installation). Multivariable instruments. That same wire pair can handle multiple variables from one field device. For example, one temperature transmitter might communicate inputs from as many as eight sensors -- reducing both wiring and instrument costs. Other benefits of reducing several devices to one can include fewer pipe penetrations (for improved safety and reduced risk of fugitive emissions) and lower engineering costs. Two-way communication. In addition, the information flow can now be two-way. A valve controller can accept a control output from a host system or other source and send back the actual valve position for more precise control. In an analog world, that would take another pair of wires. New types of information. Traditional analog and discrete devices have no way to tell you if they're operating correctly, or if the process information they're sending is valid. As a consequence, technicians spend a lot of time verifying device operation.

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