API Specification 6A, Specification for Wellhead and Christmas Tree Equipment API Recommended Practice 556, Instrumentation, Control, and Protective Systems for Gas Fired Heaters API Sta
Introduction
Instruments must be chosen to align with the specific needs of the facility, ensuring they deliver satisfactory performance under the given process conditions Reliability and robustness are essential qualities, and it is crucial to comprehend the limitations outlined in their datasheets and instruction manuals.
Calibration procedures and repair should be taken into account Maintainability issues include: parts availability, repair difficulty, tools and facilities, decontamination, skills necessary, and diagnostic test capabilities.
Measurement Terminology
A range with an elevated zero features a negative lower value and a positive upper value, typically positioning the zero point at the midpoint This type of calibration is commonly known as zero crossing measurement.
The range of a measured variable is defined as the interval where the zero value exceeds the low range value, a scenario commonly seen in wet leg differential level transmitters and bi-directional flow meters This condition is often referred to as a suppressed range.
Lowest value of the measured variable that a device can be adjusted to measure.
Lowest value of the measured variable that a device is adjusted to measure.
Region in which a quantity is measured, received, or transmitted The limits of this region are the lower and upper range values.
Absolute algebraic difference between the upper and lower range values For example, a calibration range of –25 to +5 in WC represents 30 in WC of span.
Range where the measured variable zero value is less than the low range value such as occurs with a dry leg differential level transmitter Occasional referred to as elevated range.
Highest value of the measured variable that a device can be adjusted to measure.
Highest value of the measured variable that a device is adjusted to measure.
Ratio of the sensor’s maximum span to the sensor’s minimum span For example a pressure transmitter with a maximum span of 150 psig and a minimum span of 1.5 psig has a 100:1 turndown.
See ISA 51.1-1979, for further information on measurement terminology.
Instrument Range Selection
Since uncertainty is dependent on the instrument span the normal operating point is recommended to lie between
The calibrated range of the instrument should encompass 50% to 75% of its full capacity, ensuring it does not fall below 25% This range must be carefully selected to cover the entire operating window and be sufficiently broad to accommodate varying conditions.
Combining normal and alternate operating conditions into a single instrument may not be practical It is essential to evaluate whether the operating window can be relaxed or if additional instruments are necessary In certain cases, it may be acceptable to record measurements during alternate operating conditions with reduced accuracy For instance, using a differential flow meter at 5% of its normal rate during startup could justify accepting a rough telltale measurement.
To accommodate process changes, the upper range limit should be set to allow for a calibrated range adjustment of 20% to 50% Additionally, a corresponding negative range limit is necessary for compound readings It is important to avoid excessively wide range limits, as they can increase measurement uncertainty.
To enhance clarity, it's essential to minimize the number of significant digits shown A broad measurement range can be simplified by adjusting the engineering units on the display, such as converting an actual flow of 5,234,567 SCFH to 5230 MSCFH It is advisable to limit the display to no more than three significant digits, although additional digits may be included when greater precision is required.
The optimal scale should feature a maximum of two significant digits, with the final digit being five, to minimize confusion Using additional digits can lead to increased ambiguity.
Avoid displaying suppressed zeros, such as 100 tons/day to 300 tons/day, unless necessary for enhancing the resolution of analog displays and gauges The "at rest position," or "self-position," must remain readable during both startup and shutdown phases Additionally, the calibrated lower range value should accurately reflect the zero or sub-zero process value, for example, ranging from 0 tons/day to 150 tons/day, 0% to 100% level, or 0 psig.
10 psig; –1 psig to 3 psig; 0 °C to 500 °C; –50 °C to 50 °C; etc.)
For effective comparisons, safety transmitters must match the range limits, calibrated range, and accuracy of their corresponding process transmitters Typically, trip settings are established between 10% and 90% of the calibrated range.
To minimize the risk of false trips, it is essential to establish a control band within the trip limits, ensuring an operating margin between normal operating setpoints and trip setpoints For example, if operational limits are set between 20% and 80% of the range, trip limits should ideally be between 10% and 90% It is advisable to avoid setting trip setpoints at 0% or 100% of the range, as even a minor error could obscure the true trip setpoint during an actual trip event.
In certain applications, particularly under high pressure or low levels, it is recommended to set the shutdown transmitter to a range that emphasizes the shutdown function This adjustment ensures that the trip point remains within 10% to 90% of the instrument's range.
3.3.2 Units of Measurement and their Presentation
U.S refineries primarily utilize a modified version of U.S Customary Units, known as the IP (inch-pound) system They commonly measure hydrocarbons in barrels (bbl), with one barrel equating to 42 U.S gallons (158 liters), serving as the standard unit for volume and material balance at 60°F Additionally, fluids with vapor pressures exceeding atmospheric pressure at 60°F are represented as liquids at their equilibrium vapor pressure.
Other non-hydrocarbons liquids are mostly represented in gallons (gal) at flowing conditions The flowing unit for steam is normally expressed as pounds/hour (lbs/h).
Gas flow, excluding steam, is typically measured in standard cubic feet per minute (SCFM), using H and D as suffixes to indicate hour and day, respectively The API MPMS and AGA equations reference a base condition of 101.6 kPa at 15.6 °C (14.73 PSIA at 60 °F), although this pressure is not universally accepted; many non-API metering and material balance calculations utilize 101.3 kPa (14.696 PSIA) instead This results in a 0.23% difference between the two pressure values.
Also, SI prefixes (e.g k as ×10 3 and M as ×10 6 ) are used intermittently Rather, Roman numerals are common scale factors for displays with M is a thousand (10 3 ) and MM is a million (10 6 ) which is a thousand squared.
For accurate unit abbreviation and conversion, refer to API MPMS Ch 15-2001 and MPMS Ch 1-1994, which define U.S Customary Units Both U.S Customary and SI units are included, and NIST Handbook 44-2010, Table C.2, serves as a reliable reference for the presentation and application of U.S Customary Units.
In the U.S Customary Unit system, pressure is measured in pounds per square inch (psi), with a "g" for gauge pressure and "a" for absolute pressure Conversely, the SI system utilizes the Pascal, commonly expressed as kilopascals (kPa), and typically omits a suffix unless the measurement basis is unclear For absolute pressure, kPa is often used, while higher pressures are represented in megapascals (MPa) to simplify notation In the European Union and other regions, the Bar, equivalent to 100 kPa, is a legally recognized unit, while kg/cm², approximately 98.07 kPa (14.2 psig), is still in use in some areas.
When defining ranges in inches of water column (WC), it is essential to consider the water temperature, as its density varies with temperature Most instruments are calibrated according to ISA RP2.1-1978, which is based on water at 20 °C Historically, differential flow meters were calibrated using water at 15.6 °C (60 °F) Current AGA and API metering standards now offer two calibration values to account for these variations.
Transposing temperature values can result in a systematic measurement error of 0.081% and a flow error of 0.04% Additionally, certain metrology standards are established based on the maximum density of water, which is observed at 3.98 °C.
Instrument Selection
The instrument selection process involves the following five steps.
1) Identify the expected operating cases such as: a) normal flow; b) batch cycles; c) standby/recycle flow; d) regeneration; e) start-up; f) shutdown; g) upsets and emergencies.
2) Collect the following process data: a) fluid name; b) phase; c) flow rate; d) pressure; e) temperature; f) density/molecular weight; g) viscosity.
To ensure comprehensive analysis, it is essential to gather additional information on various factors, including vapor pressure, dielectric properties, corrosiveness, erosion characteristics, and toxicity Additionally, consider the presence of solids and contaminants, foaming tendencies, depositing behaviors, and solidification processes such as coking It is also important to assess reactivity, hydraulic pulsations, bi-directional flow, backflow risks, and vibration effects.
4) Determine the range and accuracy needed to meet the requirements.
When selecting the appropriate instrument type, consider factors such as device survivability, long-term reliability, and mechanical integrity requirements Additionally, evaluate the materials of construction, including soft goods, as well as process connections and isolation valves It's essential to assess heating and insulation needs, location accessibility, and purging and flushing requirements Ensure the instrument can resist electrical noise and meets wiring and power supply specifications, along with necessary electrical classifications and safety integrity levels Certifications, safety, and environmental conditions should also be taken into account, alongside existing instruments and the expertise required for operation Finally, consider calibration facilities, disposal of expendables, potential failure modes, maintenance and sparing needs, and features like self-diagnostics and life cycle effectiveness.
Mechanical Integrity
For ensuring mechanical integrity, it is essential to establish design pressure and temperature under identical conditions In certain situations, it may be necessary to define two sets of pressure and temperature: one for the maximum pressure along with its corresponding temperature, and another for the maximum temperature paired with its associated pressure.
Metallurgy and Soft Goods Selection
Materials should be selected based upon the process requirements and their historical performance In refining there are services where additional care is needed:
— Hydrogen Sulfide attack in wet services;
— chloride stress corrosion with stainless steels;
Materials have temperature and concentration ranges where they are applicable They could become problematic operating outside these areas Metallurgy and soft goods selection includes the following considerations:
— operating, maximum and minimum temperature;
— the fluid composition, including contaminates;
— external ambient effects; e.g exposure to small quantities of corrosives.
Pressure measurement elements, such as bellows and Bourdon tubes, function as thin wall springs, and their dimensions can be altered by corrosion, impacting their mechanical properties This alteration may lead to potential loss of containment To mitigate this hazard, it is advisable to consult suppliers and experienced corrosion engineers for optimal material selection, as well as refer to API 571 for further guidance.
AISI Type 316 Stainless Steel is the preferred choice for measuring elements and tubing due to its superior corrosion resistance Upgrading wetted instrument parts enhances flexibility and reduces the need for spare parts This stainless steel is frequently utilized in applications where carbon steel would typically suffice.
Stainless steel is commonly used to eliminate the need for painting, while brass is suitable for air, uncontaminated water, and inert gases, though it is often avoided to maintain interchangeability and prevent confusion However, it's important to note that stainless steel pipe fittings and flanges exhibit inferior strength compared to carbon steel at temperatures of 425 °C (800 °F) or lower.
AISI Type 304 Stainless Steel is not advisable for instrument construction due to its inferior properties compared to AISI Type 316 Stainless Steel, except for its resistance to nitric acid AISI Type 316 offers greater flexibility and helps prevent mix-ups, making it the preferred choice without any price advantage for Type 304.
Aqueous chloride environments can lead to pitting and stress corrosion cracking in cold-worked 300 Series Stainless Steels, particularly when they are under external tensile stress This type of cracking typically occurs at elevated metal temperatures.
Instances of cracking have been observed at temperatures as low as 60 °C (140 °F), particularly in bellows and instrument tubing contaminated with chlorides The presence of dissolved oxygen further increases the likelihood of this issue.
Stainless steel should be avoided in applications involving chlorine, aliphatic amines, and ammonium compounds In near shore environments, N08825 is recommended as a substitute for stainless steel tubing and piping components to mitigate issues with chlorides For marine applications, it is essential to ensure a minimum Molybdenum content of 2.5%, making i316LM or 317SS suitable options, provided their hardness remains below 80.
Rb When chloride or hydrogen sulfide concerns exist carbon steel bodies with N06022 measuring elements should be considered over stainless steel construction.
Common stainless steels (e.g Type 316) are designed by AISI type designations regardless of their form (plate, casting, forging, etc.) Their composition and AISI type designation is defined in ASTM A240-2013.
When specifying construction materials, it's important to avoid using registered trademarks and brand names alone, as this can lead to procurement issues Instead, it is advisable to include the UNS material code from ASTM DS561 or the plastic code from ASTM D1600 and ASTM D1418 alongside the trade name This practice helps to clarify specifications, especially since some trade names, like Teflon®, encompass multiple products.
Below are some common trade names and their generic identifiers:
ASTM designations, as referenced in ASME B31.3, serve as a valid method for material identification These designations encompass not only the material composition but also its form, including options such as cast, forged, plate, and bar.
Instruments utilize o-rings and specialized gaskets to effectively seal their components Choosing the right elastomer can be complex; for example, while FKM is commonly used for instrument o-rings, it is unsuitable for applications involving amines or hot water and steam Elastomers can fail in various ways, including swelling, dissolving, or developing a compression set.
Elastomer suppliers provide various charts and technical reports that assess compatibility levels; however, different compounds or grades within the D1600/D1418 designation exhibit varying capabilities The most reliable indicator of compatibility is the actual performance of a specific elastomer with a particular fluid at the same concentration and temperature.
An elastomer’s maximum temperature, typically from 100 °C to 232 °C (212 °F to 450 °F), is a limiting factor in instrument applications FFKM, a perfluoroelastomer, is an exception to these limitations; it is operable to 315 °C
(600 °F) and some grades are resistant to steam.
Explosive Decompression (ED) happens when an elastomer absorbs process vapor and experiences a sudden pressure release, potentially damaging the seal and compromising its ability to maintain pressure Relevant standards such as EN 682 and ISO 23936 address the use of non-metallic elastomers in oil and gas production to mitigate these risks.
Table C.1, are the standards that cover the selection and evaluation of elastomeric seals for explosive decompression.
The NACE standards were developed to protect against catastrophic failure from sulfide stress cracking (SSC) due to
H2S Materials in aqueous environments containing H2S can crack under the influence of internal strains, which is usually measured by hardness Hard materials are more susceptible to SSC than softer materials.
NACE MR0103, and NACE MR0175, are the two commonly used NACE standards used for H 2 S bearing hydrocarbon services.
NACE MR0175 is the foundational standard for sour service, specifically designed to tackle hydrogen sulfide (H₂S) in low pH conditions It is applicable to various sectors, including petroleum production, drilling, gathering, and gas field processing facilities Additionally, NACE MR0175/ISO 15156 provides further guidelines for materials used in these environments.
In 2009, material selection is governed by the severity of sour service and pH levels, with unlisted materials requiring testing per NACE guidelines Various materials have specific concentration and pressure ranges, and merely stating NACE MR0175 compliance is often insufficient AISI Type 316 Stainless Steel is permitted for instruments and control devices, provided that environmental conditions, particularly chloride concentration, adhere to the guidelines outlined in Appendix A of Part 3.
According to Table A.6 of MR0175/ISO 15156-2009, instrumentation and control devices, including diaphragms, pressure measuring devices, and pressure seals, should be made from materials that are solution-annealed and quenched, or annealed and stabilized, and must not undergo cold work to enhance mechanical properties, with a maximum hardness of 22 HRC These materials can be utilized in production environments without restrictions on temperature, H2S, Cl-, or in situ pH, although while there are no limits on individual parameters, certain combinations of these values may be unacceptable.
Signal Transmission and Communications
Historically, analog technologies such as voltage, current, and pneumatic systems were utilized for measurement transmission While analog technology is still in use, many applications have transitioned to digital communications, including HART, Fieldbus, Wireless, and Ethernet.
Electronic analog transmission technology communicates a measurement or command using dedicated wires The signal value can be an analog value using current or voltage.
The 4-20 mA signal, recognized as the most prevalent analog signal, is defined by ANSI/ISA S50.00.01 and IEC 60381-1 standards This standard has been enhanced by NAMUR NE-43 to include diagnostic information Signal level interpretations for devices adhering to NAMUR NE-43 requirements are detailed in Table 2.
Typically, transmitter failures are indicated by one signal level which is often user selectable To indicate failure the signal is either less than 3.8 mA or greater than 20.5 mA
A 4-20 mA signal can be configured in two, three, or four wire formats and must drive three levels of load impedances: low (L), high (H), and ultra (U) The minimum acceptable impedance is ISA Class L, set at 300 ohms, while the standard input impedance is 250 ohms, allowing for 50 ohms for wiring and potential low impedance local meters Most instruments can handle 550 ohms or more, facilitating operation with two control or monitoring devices in series.
Two-wire instruments derive their power from signal wires, while three and four-wire instruments utilize additional wires for power Most process pressure transmitters, EMF/electrical transducers, and various inline flow meters and level transmitters are classified as "Full Isolated" ISA 2U devices per ISA S50.00.01 These two-wire devices operate on a nominal 24 VDC power supply, featuring electrically isolated power, output, and signal input terminals, capable of driving a 550-ohm load with the same 24 VDC supply.
Four wire devices are essential for measurements requiring over fifty milliwatts, unlike two wire devices that rely solely on signal wires Typically classified as ISA 4H devices, they can handle loads exceeding 800 ohms and feature an active output However, many of these devices lack isolation, which can be problematic, necessitating additional signal conditioning Without proper signal conditioning, different connection points may be required when integrating the device with the facility control system.
Pneumatic systems adhering to IEC 60382 or ISA S7.4 standards operate with signal ranges of 20 to 100 kPa or 3 psig to 15 psig Calibration of certain pneumatic field instruments, especially temperature transmitters, can be challenging due to the interaction between zero and span adjustments.
Pneumatic control systems are largely viewed as outdated, primarily utilized in control valve actuators and their accessories Their application is mostly restricted to remote valve and metering stations linked to gas pipelines and gathering systems, particularly in areas lacking a dependable electrical power supply In these cases, pipeline gas is employed to power the logic and measurement devices.
Probable open field wire 0 to 3.6Probable shorted field wire ≥22.0
Pneumatic devices play a crucial role in utility services where remote control is impractical and continuous monitoring is not required They are essential for regulating pressure, temperature, and level Pneumatic controllers are particularly beneficial when the setpoint exceeds the capabilities of a self-contained regulator, when tighter control is necessary, when the pressure drop is minimal for a regulator, when specific construction materials are unavailable, when additional thrust is required to open a valve after extended shutoff, and when significant pressure reduction is needed in a single stage.
Pneumatic level controls are integral with a measurement displacer Local pneumatic level displacer controllers are actively used for condensate drums, knockout pots, and the like.
Large case pneumatic controllers for pressure and temperature can be mounted on a valve actuator, a pipe stand, or a local panel.
Digital communications leverage the full potential of intelligent devices to enhance accuracy and reliability while minimizing maintenance requirements This technology facilitates seamless connectivity to facility control systems and enables multiple devices to share a single wire pair, significantly reducing wiring needs.
Digital communications enhance measurement accuracy by delivering superior information For example, the resolution of the measured variable is no longer constrained by the transmitter's 12-bit D/A converter This advancement enables the measured variable to be transmitted as a floating-point value in engineering units, independent of scaling, thereby fully utilizing the transmitter's measurement capabilities.
Various standards facilitate digital communication with field instruments, notably IEC 61158-3-1 and IEC 61158-4-1 The H1 Foundation Fieldbus is extensively utilized for process measurement in the refining and petrochemical sectors, receiving strong support from leading process instrument manufacturers.
The HART Protocol is highly supported and has developed from a frequency-shift keying (FSK) signal multiplexed onto the 4-20 mA signal It can be transmitted through various methods, including multi-drop networks and wireless communication.
For detailed insights on digital communications and analog signal transmission, consult API 552 Additionally, for a comprehensive overview of communication protocols used in industrial communications, refer to IEC 61784-1.
Power, Grounding, and Isolation
Various power sources are utilized based on the instrument, including type 2U loop powered systems as per ISA S50.00.01, type 4H DC or AC power also according to ISA S50.00.01, network power from fieldbus systems, and internal batteries.
Four-wire devices can be powered by a nominal 24 VDC power supply or an AC power source Although some older models function at 120 VAC or 240 VAC, the majority of modern AC power devices are designed as global products, accommodating voltage ranges from 95 volts to 240 volts and frequencies from 50 Hz to 60 Hz.
Most four-wire devices offer a 24 VDC option, which is the preferred power method for externally powered instruments However, it's important to note that distance limitations affect power transmission In oil refining or petrochemical facilities, wire runs can reach up to 180 meters (600 feet), and with a typical 15% voltage drop, loads are limited to 7 watts on an 18 AWG or 1.0 mm² wire pair in a multi-core cable Loads exceeding this limit may necessitate a heavier gauge wire or AC power from a UPS field panel, which is often more desirable as it eliminates the need for special cables Additionally, a locally mounted DC/DC power converter can effectively address voltage drop issues by boosting the voltage at the device.
Grounding for instruments involves two key considerations: adherence to electrical safety codes and achieving accurate, low-noise readings Proper wiring at both the instrument and control system is essential, as multiple grounds can lead to significant electrical noise, which is generally unacceptable.
NOTE See IEC 61000-5.2, IEEE 1050, API 552, and NAMUR NE 98 for further information regarding grounding and electrical noise reduction.
Instruments must be safeguarded against stray electrical potentials to prevent ground loops, adhering to ISA S50.00.01 isolation standards It is advisable to maintain a minimum dielectric strength of 500 VAC from ground and between isolated circuits Compliance with IEEE C37.90-2005 Section 8.2 or successful testing according to IEC 61298-2-2008 Sections 6.3.2 and 6.3.3 is essential, ensuring no measurable loss of resistance or flashover occurs.
Surge protectors are essential for transmitters located in electrically active areas, such as near switch yards or regions prone to intense lightning These surge protectors must comply with IEEE C37.90.1 standards and Category B of IEEE C62.41, as tested according to IEC 60770-1.
Local Indicators
Local indicators are essential for supporting field personnel, and they can take the form of directly connected gauges or electronic devices Adjustments made to local valves should be reflected in the local readout, allowing for easy observation of changes For example, during control valve maintenance, it is standard practice to install a local indicator that is visible from the control valve bypass.
Pressure gauges, bi-metal thermometers, and local level indicators serve as direct connected indicators that usually operate without external power However, these devices tend to lack precision and exhibit limited long-term reliability.
Direct process indicators have accuracy limitations and should not be used for calibrating transmitters It is recommended to use direct connected process pressure gauges for pressure switches and regulators ASME Section I mandates that boiler drums must have a visible pressure gauge with an upper range value approximately double the safety valve setpoint For temperature control, a transmitter with an integral indicator is more effective than a local temperature indicator Direct connected flow indicators larger than 2 inches NPS are impractical, so electronic indicators are preferred Battery-powered wireless transmitters with LCD indicators can provide local indication for applications like furnace steam air decoking flow control without needing a wireless gateway Additionally, direct connected local level indicators should be positioned on vessels for visibility from aisles or platforms.
Continuously online pressure gauges serve primarily as pump run indicators, but their overall value is limited Local dial indicators are susceptible to damage and calibration errors, offering minimal benefits after installation, especially post-startup Many facilities treat them as disposable, replacing them only when necessary Instead, it is advisable to utilize blind pressure taps and test wells, although decontamination and reuse may pose challenges with temporary pressure gauges.
Electronic indicators utilize signals from process transmitters, which can be either integrated with the transmitter or mounted remotely They typically operate on a 4-20mA signal, with a voltage drop of less than one volt, minimizing the impact on the loop These indicators feature either analog or digital displays, with digital displays easily configurable for engineering units In contrast, analog meters often require custom scales from specialized fabricators to provide direct readings in engineering units.
Fieldbus transmitters can feature integral indicators or have remote indicators connected back to the transmitter Additionally, independent fieldbus indicators are available, capable of displaying multiple values and performing calculations; however, they count as at least one device and contribute to the overall link loading.
Tagging and Nameplates
Instrument tagging should ideally occur during shipment, adhering to ASTM F992 standards This includes using Type III (Type 316 stainless steel, engraved) materials, Grade B (metal strapping or screw), Class 3 (≥20 gauge or 0.5 mm), and Size A (rectangular) specifications.
For optimal results, it is recommended to use a nameplate measuring 50 mm by 20 mm (or 2 in by 7/8 in.) with a Letter Size of 4 (1/8 in or 3 mm) The nameplates should be securely attached using 18 AWG (1.0 mm²) UNS N04400 tie wire, austenitic stainless steel screws, austenitic stainless steel cable ties, or banding.
Laser engraving is recommended and is a standard technique for producing stainless steel tags.
Laminated nameplates must be made from UV resistant materials like HDPE or PMMA marine-grade plastic, such as UVA acrylic The engraving should feature medium Helvetica or another sans-serif typeface, with a minimum height of 4 mm.
A minimum of one block valve is essential, with an additional valve permitted near the drum if it remains locked open The installation must be designed for blowout capability, utilizing multi-turn blowdown valves A siphon or equivalent device is required to maintain a water seal, as referenced in ASME B31.1-2012 paragraph 122.3 and BPVC Section 1-2013 paragraph PG-60.6 Instrument tag numbers and service descriptions must be clearly displayed, avoiding nameplates with black or dark surfaces to ensure readability Nameplates should be affixed using waterproof, solvent-resistant, high-strength, temperature-resistant cement, such as a two-step acrylic structural adhesive.
The nameplate must include the complete ISA 5.1 tag number with any unit prefix, along with optional details like purchase order and service information Additionally, thermowells should be marked with the tag number of the associated temperature element Abbreviations should follow the hierarchy of Plant Standards, ISA RP60.6, PIP PNC00002, and ASME Y14.38.
Configuration and Configuration Management
Configurable measurement devices allow users to set parameters and functions, with the full tag number ideally configured before installation When selecting these devices, it's essential to obtain the necessary tools and software for configuration Common devices for this purpose include handheld configurators that utilize direct wiring or infrared, personal computers with general or specific software, process control system interfaces, and instrument interfaces such as digital displays.
Procedures should be provided for configuration data retention besides the device itself
NOTE See API 554, Part 2 for further discussion of configuration management.
Documentation
Instrument information is usually recorded on data sheets, such as ISA TR20.00.01 forms or drawings For complex instrumentation, more comprehensive documentation is required, including written specifications Key resources for project documentation include PIP PCEDO001, which provides guidelines for control systems documentation, and ISA RP60.4 Additional references like ISA TR 77.70.01 and ISA 5.06.01 focus on tracking instrument data and functional requirements for control software applications, respectively Utilizing central instrument database software can effectively manage and disseminate this critical information.
Comprehensive instrument documentation is essential for effective maintenance According to Management of Change (MOC) regulations, it is necessary to evaluate and document any process, mechanical, and operational changes, which also includes the instruments and their wiring.
System integrity standards (e.g ISA 84.00.01 Part 1) require the information that validated the system be maintained This includes instrument data sheets and similar documentation Compliance with these standards can be mandatory.
Introduction
This section discusses the installation and selection of temperature measurement devices used in refinery services, focusing on thermowells and temperature sensors It also addresses the aspects of wiring, signal conditioning, and local indicators essential for accurate temperature monitoring.
Thermowells
Thermowells are used to protect the temperature elements and to allow their replacement during operation.
Installing temperature elements in thermowells can introduce time lag and measurement errors To minimize these issues, utilizing a spring-loaded fitting ensures that the element makes firm contact with the bottom of the thermowell, thereby reducing lag and errors For applications involving temperatures exceeding 290 °C (550 °F), it is advisable to use N07718 springs.
In specific scenarios like furnace ducts, sheathed elements are installed directly in the process for quicker response times It is essential to provide a clear nameplate indicating that extraction may lead to a process release To avoid accidental removal of the element, it is advisable to use a tack weld, cotter pin, or a car sealed locking fitting.
The insertion length, U, refers to the distance from the free end of the thermowell to the threads, flange face, or attachment point The immersion length is the portion of the thermowell that extends into the process fluid beyond the edge of the pipe or vessel Additionally, the lagging extension, T, is an extra section added to thermowells to extend them beyond pipe insulation For more details on thermowell terminology, refer to ASME B40.9.
Temperature measurement errors can arise from several factors, including fluid impingement heating the thermowell, thermal radiation inaccuracies, and heat transfer between the thermowell and the surrounding fluid Specifically, heat transfer errors occur as heat is conducted along the thermowell's length, from the process fluid at the tip to the atmosphere Consequently, the measuring element detects an intermediate temperature rather than the actual process temperature.
Higher temperatures combined with lower density and fluid velocity can lead to significant measurement errors Typically, insulated pipes with fully turbulent flow exhibit minimal conduction errors However, systems with low densities and flow rates, such as furnace stacks using standard length thermowells, may experience considerable inaccuracies In high-temperature lines exceeding 480 °C (900 °F), short thermowells can result in errors greater than 28 °C (50 °F) For moderate temperature liquids, the potential for error remains a concern.
For optimal performance, it is recommended to maintain a minimum immersion length of 50 mm (2 in.) at temperatures of 93 °C (200 °F) Additionally, the thermowell tip should be positioned outside the edge of the nozzle and must always remain in contact with the flow stream.
Longer and thinner thermowells can minimize errors by lowering thermal conductivity, although this may compromise their strength Additionally, the design of the element is crucial; for high-temperature applications like furnace outlets, it is advisable to heavily insulate the nozzle, flange, and exposed end of the thermowell.
To ensure accurate temperature measurements in flowing streams, RTDs and local temperature indicators must extend beyond the capabilities of thermocouples and thermistors A standard RTD element measures 15 mm (0.6 in.) in length, whereas a bimetal thermometer element can reach up to 62 mm (2.5 in.) long.
Further guidance on minimizing measurement errors in thermowell applications is found in ASME PTC 19.3.
The optimum immersion length is a tradeoff between accuracy and response time with mechanical strength requirements See Figure 2 for a typical thermowell installation
Thermowells are prone to vibration, which can lead to fractures and failures when their natural frequency is reached While some thermowells may fail within minutes due to destructive vibrations, others with damping mechanisms can operate safely in the locked-in frequency zone for extended periods before experiencing fatigue failure Additionally, there are instances where thermowells have not failed at all.
Thermowells are also subjected to steady state bending loads caused by the high velocity, high density flow Consequently, thermowells should be evaluated and documented for these failure modes.
ASME Performance Test Code PTC 19.3 TW outlines the design standards and calculation procedures for tapered, straight, and stepped-shank thermowells, while excluding those made from pipe or other materials This code assesses the forces exerted by external pressure, as well as the combined effects of steady-drag forces and dynamic forces, which include oscillating-drag or in-line forces and oscillating-lift or transverse forces due to fluid impingement.
When adequate measurement is not feasible according to ASME PTC 19.3 TW design requirements, a highly damped solution can be achieved through computational fluid dynamics for various configurations.
V tip diameter b shank root fillet radius
NOTE 1 9 in ASME B40.9 threaded themowell with lagging extension shown.
NOTE 2 9 in ASME B40.9 flanged themowell with 1 1 / 2 NPS Class 300 flange shown.
NOTE 1 To allow well removal, Dimension C should be 610 mm (24 in.) or the total length of the thermowell plus 76 mm (3 in.), whichever is greater.
NOTE 2 To prevent pockets, eccentric reducers should be provided on horizontal pipe.
NOTE 4 In non-cryogenic services the thermowell preferably is installed on the top of the pipe
For cryogenic liquids to avoid trapping vapors it is recommended that the well be located in the arc from the horizontal plane to 45° below that point.
The minimum pipe size is influenced by the depth of the nozzle and the total length of the well For detailed guidance on process pipe connections, refer to PIP PNF0200.
NOTE 6 To allow for the element length, the minimum depth for an RTD’s and Bimetal indicators should be 75 mm (3 in.).
For pipes with a nominal pipe size (NPS) of 6 inches or less, which are not addressed by ASME PTC 19.3 TW, it is advisable to utilize finite element analysis (FEA) and computational fluid dynamics (CFD) for a more accurate assessment of velocity limits It is essential that these models are validated in accordance with ASME V V20 standards.
The use of support collars is discouraged and falls outside the guidelines of ASME PTC 19.3 TW An interference fit, which is a press type fit, poses challenges in maintenance, especially when accounting for differential thermal growth and corrosion Additionally, due to its non-standard shape, a CFD analysis is required Instead, welded thermowells or studding outlets, as illustrated in Figure 4, should be utilized to guarantee sufficient projection of the thermowell into the process.
Installing thermowells at a 45° angle enhances their effective length and reduces bending stress at the root However, tip effects are significant, and the Strouhal number changes with the flow angle relative to the thermowell axis, making it necessary to use CFD evaluations to determine a velocity reduction factor Additionally, thermowells mounted in elbows facing the flow are not addressed by standard guidelines.
Thermocouples
Thermocouples are the predominant temperature measuring devices utilized in refining processes The materials used for thermocouples, as detailed in Table 3, can operate effectively within a temperature range of –270 °C to 1815 °C (–454 °F to 3300 °F), offering reliable accuracy and repeatability.
Type E thermocouples are known for their high EMF and exceptional noise resistance, making them suitable for various applications, including cryogenics In contrast, Type K thermocouples are commonly utilized in furnaces due to their wide temperature range, while Type N thermocouples are also recommended for similar furnace applications On the other hand, Type J thermocouples are often viewed as legacy devices because their iron thermo-element is susceptible to rusting.
Metal sheathed thermocouples are the preferred choice for thermocouple assemblies due to their extended lifespan and long-term accuracy Unlike bare wire thermocouples, metal sheathed options are ideal for applications requiring long installation lengths, such as in reactors The sheathing offers essential physical and chemical protection, and these thermocouples can be easily bent and welded onto surfaces.
Thermocouple assemblies consist of tightly packed thermo-elements within a high-purity insulating ceramic sheath, such as magnesium oxide The sheath diameters vary from 1 mm to 20 mm (0.04 in to 0.84 in.), accommodating wire sizes from 8 to 36 AWG For standard temperature measurements, 18 AWG wire is commonly utilized, often in a duplex design that includes two elements to ensure an online spare.
ASTM E230-2012 thermocouples are provided in two accuracy grades Standard Tolerance and Special Tolerance as shown in Table 4 Also, matched thermocouple pairs are available for differential temperature measurement.
Two types of measuring junctions (see Figure 6) are in general use.
Table 3—Standard ISA/ASTM Thermocouples Types
Recommended Range Limits Positive Lead (+) Negative Lead (-)
Red Platinum-30 % Rhodium Platinum-6 % Rhodium 870 to 1700 °C 1600 to 3100 °F
(Chromel) Nickel-5 % (Aluminum, Silicon) –200 to 1260 °C –328 to 2300 °F
Red Platinum-13 % Rhodium Platinum 0 to 1480 °C 32 to 2700 °F
Red Platinum-10 % Rhodium Platinum 0 to 1480 °C 32 to 2700 °F
Red Tungsten-5 % Rhenium Tungsten-26 % Rhenium 0 to 2315 °C 32 to 4200 °F
1) Type A has a grounded tip welded to the sheath for fast response and lower electrical noise.
2) Type B has an ungrounded tip and is electrically isolated from the sheath It has a slower response.
The selection between grounded and ungrounded thermocouples depends on the specific application requirements For Type A thermocouples, it is essential to establish a proper ground path via the thermowell, ensuring that the signal ground is maintained at a single point.
Sheathed thermocouples should be provided according to the requirements of ASTM E608 IEC 61515 also covers fabrication and testing of thermocouples Standard thermocouple tables are listed in ASTM E230
Figure 6—Metal-sheathed Thermocouple Types
Table 4—Thermocouple Interchangeability Tolerance Type Standard Tolerance Special Tolerance
Table 5—Recommended Limit for Single Element Sheathed Thermocouples
Sheath OD Wire Thermocouple Type °C (°F) in mm AWG T J E K N
When designing a high temperature thermocouple, it is essential to consider it as a cohesive system, ensuring compatibility among the sheath, mineral oxide insulation, and element material The sheath must be resistant to corrosion, spalling, and embrittlement, while the element material should be suitable for its specific environmental conditions.
For optimal performance, the sheath and mineral oxide insulation must be chemically compatible with the process conditions, as seen in furnaces where oxidation poses a challenge, and in hydro-treating processes where hydrogen can diffuse through the protective metal sheath, leading to element degradation Ensuring that the sheath's chemistry aligns with that of the conductors minimizes the diffusion of elements, thereby mitigating the common issue of output drift in high-temperature measurements Additionally, having similar coefficients of expansion for the sheath and element materials helps to reduce cold working.
Some sheaths work better with gas fuels while others (e.g UNS N06002) are superior at dealing with oil fuels.
Chromel thermo-elements restrict the use of Type E and K thermocouples due to a phenomenon called "green rot," which results from the preferential oxidation of chromium This condition can lead to temperature readings that are inaccurately low, potentially shifting downwards by as much as 17 °C (30 °F) before the thermocouple fails The severity of this oxidation attack is heightened in low or marginal oxygen environments, lessens in high oxygen levels, and is absent in zero oxygen conditions.
Hydrogen can cause significant damage to Chromel, making it unsuitable for use in reducing atmospheres At elevated temperatures, hydrogen may diffuse through the thermowell and sheath, with the most severe attacks occurring between specific temperature ranges.
Thermal aging of Chromel thermo-elements in Type E and K thermocouples primarily occurs within the temperature range of 149 °C to 482 °C (300 °F to 900 °F) This process typically results in an increase in the thermocouple's electromotive force (EMF) The extent of this shift is influenced by factors such as temperature history, prior cold working, impurities, and the material of the sheath.
Changes in thermoelectric properties are often linked to "atomic ordering." In the drifting temperature zone, a Type K thermocouple experiences a rearrangement of atoms in the positive thermo-element from a random to an ordered state, leading to a change in EMF output This atomic shift can cause a positive error ranging from 1.7 °C to 2.8 °C (3 °F to 5 °F) for Type K thermocouples In contrast, Type E thermocouples exhibit a smaller aging error To mitigate this issue, the use of stabilized thermocouple wire is recommended.
Type E and Type K thermocouples are highly susceptible to damage in sulfurous environments at elevated temperatures Sulfur adversely affects the thermo-elements, leading to rapid embrittlement and breakage of the negative wire due to intergranular corrosion.
ASTM E230 Type N thermocouples exhibit superior performance in high-temperature applications, demonstrating enhanced resistance to positive lead aging and reduced oxidation drift at temperatures of 1095 °C (2000 °F) and above Additionally, they offer improved durability against sulfur attack, making them a reliable choice for extreme conditions.
At elevated temperatures, using heavier gauge wire, such as eight gauge, can reduce aging and cold working effects while enhancing response and conduction accuracy Common sheath materials include stainless steel and nickel-chromium-iron alloys The strength of heavier wire helps resist cold working and delays the impact of impurities on the molecular structure, thereby mitigating thermocouple degradation.
Using a nickel-chromium-iron alloy sheath, such as N06600, instead of a stainless steel sheath can effectively control thermal aging The thermal expansion of the N06600 sheath closely matches that of the thermocouple wire, minimizing cold working of the thermocouple Additionally, this material choice reduces the potential for element diffusion, thereby decreasing drift.