Document Title: Guideline for the use of Level Measuring Instruments

This page was intentionally left blankDocument AuthorisationAuthorised For Issue September 2011

TABLE OF CONTENTSSummary71Introduction82General Design Requirements92.1Instrument Selection92.2Accuracy92.3Location and Orientation92.4Level Measurement for Safeguarding Application92.5Electrical103Differential Pressure Level Transmitters113.1General113.2Application113.3Calibration123.4Transmitters123.5Installation133.6Process Connection134Guided wave Radar Level Transmitters144.1GWR Applications144.2Guidelines for GWR Level Instrument Selection144.3Interface Level Measurement154.4GWR Mounting, Materials and Connections154.5GWR Transmitter165Displacement Level Transmitters175.1Application175.2External Displacement Level Transmitters185.3Internal Displacement Level Transmitters186Capacitance Level Transmitters196.1Application196.2Installation197Radioactive Level Transmitters207.1Application207.2Installation207.3Transmitters218Ultrasonic Level transmitters228.1Application228.2Installation229Sight Level Glasses2310Magnetic Level Gauges24Appendix 1 GWR Probe Selection Chart25Appendix 2 Selection Guidelines for Level Instruments27Appendix 3 Template Datasheet for GWR Type Level Instrument28

IntroductionThis standard prescribes minimum mandatory requirements governing the design of process level measurement, in order to support optimal and cost effective use of the assets in line with PDO's Corporate Objectives and General Operating Philosophy.General Design RequirementsAll level measurement components and systems shall be suitable for continuous operation in desert environmental conditions.Level measurement shall be represented in percentage on Human Machine Interface.To measure the level inside equipment over a particular range, various types of instruments are available.Depending on the process conditions, the following techniques may be applied:-Differential pressure type instruments (with or without remote diaphragm seals);-Capacitance and admittance type instruments;-Guided wave radar, microwave and ultrasonic type instruments;-Radioactive type instruments;-Magnetostrictive type;-Displacer type instruments.Instrument SelectionThis Standard is not intended to be an exclusive listing of types of level instruments. When engineering considerations so dictate and when not prohibited, other types may be used. Selection of level instrument shall be from vendors listed in PDO PGSC.AccuracyAccuracy of level transmitter shall be as per DEP 32.31.00.32 depending on application.Location and OrientationLocal instruments shall be accessible at grade level or from a platform. Local level sight gauges and magnetic level indicators shall be accessible from grade level, platform or fixed ladder. Individual level instruments shall be connected directly to vessels and not to inlet or outlet piping. Connections to process piping may be considered in exceptional cases, such applications require approval by the C&A CFDH. The use of stand pipes in level applications shall be avoided since it may introduce systematic measurement errors as a result of density variations; such application requires approval by the C&A CFDH. All connections shall be free draining. Connections to the bottom of vessels shall be avoided whenever possible. Local receiving instruments shall be installed 1.40 m above grade.Level Measurement for Safeguarding ApplicationESD level inputs shall have separate process taps located at the same elevation as the process control and monitoring transmitter taps. ESD level transmitters shall be calibrated for the same range as the process control level transmitter and designed with its own local level sight gauge and drain/vent valves.

Exceptions:ESD Level transmitters may use the same process taps as the process control or monitoring transmitters when the tap nozzle size is at least 2 inches, the process is non-plugging and the common isolation valves on the tap nozzle are car sealed open. In addition, ESD and process control level transmitters shall have independent isolation valves and shall be calibrated for the same range. The ESD and process control/monitoring level transmitters shall be designed with local level sight gauge and their own drain/vent valves to allow independent isolation and calibration while the other remains in service. Multiple ESD FunctionsA single transmitter may be used to provide both Low-Low (LL) and High-High (HH) ESD input signals if that the transmitter's calibrated range spans both LL and HH trip settings, and that it is acceptable to bypass both LL and HH inputs at the same time when performing maintenance on the transmitterElectricalElectrical and electronic level instruments installed in hazardous areas shall meet the hazardous area classification with certification by a body approved by ATEX/CENELEC. Foundation Fieldbus level instruments shall meet the specific hazardous area certification requirements of SP-1245Level instruments which discharge energy directly into the process shall have their sensor electronics certified for the electrical area classification inside the vessel.All level transmitters shall be HART or Foundation Fieldbus microprocessor based smart transmitters with integral indicators.Differential Pressure Level TransmittersGeneral Head measurement theory is based on measuring the downward force of the liquid head. The downward force is based on the height of the liquid and its density. Typically head measurement calculations use specific gravity, which is based on the density. Because the specific gravity of water at standard conditions is 1.0, most head measurements should be referenced to an equivalent head of water and should be calibrated in inches or millimetres of water column (WC).To determine the calibration of a head instrument, the height of the liquid should be multiplied by the specific gravity. The head associated with the legs of a differential pressure transmitter should also be accounted for. See Figure 1 for an example of the calibration calculations of a differential pressure transmitter with filled legs.

SG= 0.98 100 IN

SG=1.0

LT 12 IN HP LPFigure 1: Calibration of differential pressure transmitter with filled legs

Low level head calculation:If the level is at or below the bottom connection, the force on the high pressure leg (the lower vessel nozzle) will see 12 inches X 1.0 = 12 inches WC. The low pressure leg (the higher vessel nozzle) will see 112 inches X 1.0 = 112 inches WC. The differential is 12 inches WC 112 inches WC = -100 inches WCHigh level head calculation:If the vessel is full, the force on the high pressure leg will be 12 inches X 1 + 100 inches X 0.98 = 12 + 98 = 110 inches WC.The low pressure side will see 112 inches X 1.0 = 112 inches WC.The differential is 110 inches WC 112 inches WC = -2 inches WC.Conclusion:The transmitter shall be calibrated for -100 to -2 inches WC.ApplicationFor most applications differential pressure transmitters shall be used. Differential pressure level transmitters may be used for process and ESD level and for liquid-liquid interface level measurements. Transmitters with diaphragm seals and capillary are recommended for closed tank with process fluids that are extremely viscous, containing entrained solids or in hot service. Diaphragm seals shall be an integral part of the instrument.Where it is necessary to avoid plugging of the nozzle, the instrument shall have an extended diaphragm flush with the inside of the equipment. The extended diaphragm shall not be specified for instruments on equipment requiring mechanical cleaning. For instruments with an extended diaphragm, the diameter of the extension shall allow free passage in the nozzle. The use of extended diaphragm type instruments requires the approval of the C&A CFDH.Note: Where specific gravity varies, height measurement (e.g., radar, displacement, float, or other technology) is preferred over differential pressure.CalibrationThe instruments shall be calibrated for the anticipated operating density of the liquid in the vessel. The possible variations in liquid densities during normal or abnormal operating conditions shall be investigated and recorded when level measurement configurations using differential pressure type transmitters are designed.TransmittersThe instrument shall have inch NPT process connections, a universal pipe mounting bracket, a minimum body rating of 10,500 kPa (1,500 psig), and over range protection that is equal to or better than the body pressure rating. Meter body and sensing element isolation diaphragm material shall be minimum type 316 stainless steel. Hasteloy C and Monel shall be used whenever process fluid compatibility demands such materials.Diaphragm Seal Transmitters Transmitter and Chemical Seal shall be assembled and calibrated at transmitter manufacturing facility. Chemical seal transmitters shall either be flush mounted or extended type as indicated in data sheet. The diaphragm seal size shall be selected to obtain the required instrument accuracy. Typically, DN80 or DN100 diaphragm seals flanged to the required ASMEclass should be used for level measurement. Wherever specified the chemical seal shall be provided with the capillary. The capillary material shall be of SS 316 with SS armouring, the capillary tubing shall be welded directly onto both ends of the sensor. The length of the capillary tubing shall suit the application but shall be at least 1 metre. For differential pressure applications with two remote seals, the two parts of the capillary tubing shall be of the same length. For DP Level applications direct mount flange level transmitter on HP side and capillary on LP side is preferred. The process connections shall be on the same side of the equipment. Vendor shall analyse the temperature effects and response time in case of diaphragm seal Transmitters and select seals, capillary and fill fluid carefully and indicate response time in their offer. The flushing ring shall be provided wherever indicated in the data sheet. The material of construction shall be same as that of transmitter body, unless specified.Installation For open tanks, only the connection of the high pressure process connection is required. The low pressure connection of the instrument shall be protected from the entry of the dust and other airborne contaminants. In all other cases, the low-pressure connection shall be connected to the vapour space by means of a reference leg. Depending on the arrangement, this reference leg is dry (filled with gas) or wet (filled with a liquid). Instruments in wet and dry leg service shall be mounted at or below the lower vessel connection, preferably 1.4 m above grade level or operating platform.A dry reference leg can be used where:-self-purging occurs in equipment which is always at temperatures below ambient temperature and contains liquids which will still fully evaporate under all normal and abnormal operating pressures at the lowest ambient temperature.-external gas purging is allowed and a reliable source of suitable non-condensing purge gas of sufficient pressure is available (purging through the dry leg). This arrangement is vulnerable and maintenance intensive and should only be used if alternatives are less attractive.A wet reference leg shall be used where the reference leg will fill with process liquid when it condenses at the lowest ambient temperature.Two options are available for filling the wet reference leg:- the process liquid:This method should be applied if the process liquid is non-viscous, non-corrosive and not very toxic and is self-condensing under any normal and abnormal operating pressure at the highest ambient temperature.

- a sealing liquid:This method shall be applied in all other cases.

On vessels subject to rapid changes in level, such as gas-oil separating vessels, adjustable pulsation dampening in the transmitter or transmitter output may be required to improve stability. Differential pressure level transmitters in refrigerated LPG service shall be installed above the process connections with dry pressure sensing legs. The pressure sensing legs shall be sufficiently heated so that any fluid in the sensing lines remains in a gaseous state at all times.Process ConnectionThe process connection size for flange-mounted differential-pressure level instruments shall have a size of DN80, DN100 or DN150, dependent on the type of instrument and flanged to the required ASMEclass. The connection shall be internally free from burrs.Guided Wave Radar Level Transmitters GWR Applications GWR level transmitter may be used for liquid level and liquid-liquid interface level measurement technology for both process and ESD applications. Large diameter coaxial type/single rod probes will be used for all suitable GWR hydrocarbon applications. Any dead zones on the wave guide probe shall be outside the operating range of the application. Flushing ports shall be provided for all wave guide probes based on process application. Non-contact radar should be considered for tanks in excess of 6 meter height. Guidelines for GWR Level Instrument SelectionIt is important to note that the key to successful application of this technology is the choice of correct probe and engineering to meet the dynamics of the process. Following important data shall be specified in datasheet to enable proper selection of GWR probes: a) Dielectric constant of the process liquid (generally all hydrocarbons are non-conductive)b) Process pressure and temperaturec) Viscosity and suspended solids, possibility of crystallisation, maximum particle size etc.,d) Possibility of coating & build-upe) Possibility of foam formationf) Agitation / turbulent conditions causing breaking forcesg) Advance overfills protection (required on external chamber mounted units, underground sumps, etc.)h) Installation of the instruments (top, side mounted, bypass stilling wells etc.,)i) Disturbing EMC environment in tankj) Cleaning of probeRefer to Appendix-I for probe selection chart.The following information shall also be indicated in the datasheet to enable proper selection of GWR instruments:a) Process connection & sizeb) Nozzle height,c) Orientation,d) Tank internalse) Cathodic protection etc.,Interface Level MeasurementThe following additional points should be considered for the use of GWR technology in interface level measurements.a) Lower dielectric fluid must be on topb) Dielectric difference of two liquids must be at least 6c) Upper dielectric must be known.d) Maximum thickness of upper layer is dependent upon its dielectrice) Target applications, low upper layer dielectric (20)If above information is not provided/available with process, GWR should not be specified for interface level measurement. Note: If Emulsion layer is >= 150mm then consider DP cell type transmitter with diaphragm and flushing ring connection for interface level measurement. GWR may be recommended on a case by case basis for the following applications:a) IPF applications up to SIL2 function for light crude, clean crude and condensate applications. For IPF function of SIL>2 GWR instruments may be combined with other proven technology.b) Control & Monitoring of light crude, clean crude applications. Use of GWR is not recommended for the following applications until further experience and confidence is gained: a) Equipments/vessels where sludge, sand, heavy crude depositsare expected.b) Noisy environments typically flare gas knock out vessels due to higher gas velocities.c) IPF function of SIL>2 Note: CFDH C&A shall be consulted during the design for advice in the selection and application of GWR technology for liquid interface level measurements.GWR Mounting, Materials and Connections GWR shall be designed so that transmitter electronics can be replaced or removed for service while the process remains in service. GWR wave guide probes shall be mounted such that they may be removed while the process remains in-service. For pressurized process vessels, probes shall be flange mounted in external bypass chambers. GWR Bypass chamber material shall meet the requirements of the application, and be steel construction minimum. Chamber connections shall be minimum 2 inch flanged on the top, bottom, or sides. Standpipes may be used for GWR bypass chambers. An associated local sight level gauge or magnetic indicator is required for all GWR level transmitters installations to allow for process level verification and calibration. Appropriate GWR process valving and connections shall be provided for process isolation and for GWR calibration, venting, and filling.

GWR Transmitter GWR shall be HART or Foundation Fieldbus based smart transmitters. The transmitter shall include an integral indicator. All software required to setup, calibrate or diagnose Foundation Fieldbus based GWR transmitters must be accessible from the Host DCS maintenance works-station. No direct 'guest' connections shall be made on the Fieldbus segment to maintain GWR transmitters. GWR transmitters installed in hazardous areas shall meet the hazardous area classification with certification by a body approved by ATEX/CENELEC. Foundation Fieldbus GWR transmitter shall meet the specific hazardous area certification requirements of SP-1245 GWR transmitters discharge energy directly into the process and shall have their sensor electronics certified for the electrical area classification inside the vessel. The Guided Wave Radar transmitter shall have advanced diagnostics capability to monitor coating / build up over the probe. The instrument shall allow the user to input customized coating / build up limits, and if this limit exceeded, then an alert shall be given. GWR electronics heads/housings shall have the capability to be removed from their associated wave guide probe assembly.Displacement Level TransmittersApplication Use of displacement level transmitters shall be limited to non-viscous process fluids with low concentration of solids. Distinction must be made between displacement and float devices. Displacer elements are heavier than the liquid being measured, and remain stationary. The measurement signal is derived from the buoyancy effect due to immersion in a liquid. A float device on the other hand, moves with the liquid level and the measurement signal is derived from the float motion or position. Displacement level transmitters shall normally be installed in external chambers, external to the process vessel, to allow for maintenance without process interruption or hazard. Internal displacement type instruments shall be used only where the process requires the primary element to be at the same temperature as the vessel liquid, where high sensitivity is required, where the density difference between liquid interface is small, and where the vessel can be opened for maintenance requirements without process interruption or hazard. For external chamber the housing shall be arranged for right or left hand mounting as specified in data sheet (the instrument case of a right hand unit is to the right of the displacement cylinder, when viewed from the front of the case). The housings shall be capable of being reversed in the field without additional parts. The external chamber orientation shall be side-side. The bottom of the external chamber shall be drilled and tapped 1/2 NPT for drain purpose. Similarly the top of the chamber shall be drilled and tapped 1/2 NPT for vent purpose. The same shall be provided with NPT plug unless until specified. Displacement type instruments shall not be used in highly corrosive services or services where salts or other deposits may precipitate onto the displacer or on the walls of the chamber. The displacer shall be installed vertically. The center of the displacer shall be at the elevation at which the level in the vessel is to be maintained. An air-fin extension shall be provided between the level sensing element and the transmitter, for applications where fluid temperatures will exceed 200C. Ranges for displacer instruments shall be 356, 813, 1219, 1524, 1829, 2134, 2438, 2743, 3048, 3200, 3300, 3400 mm etc.Notes: 1. Displacer chambers for external displacer instruments shall be in accordance with Standard Drawing S38.056. The hanger extension length of the displacer instrument shall be: -185 mm for rating ASME class150/300; -215 mm for rating ASME class600; -230 mm for rating ASME class900; -255 mm for rating ASME class1500.2.For liquid/liquid interface service with small differences in densities, a large displacer or float may be required to achieve a satisfactory sensitivity. A displacer chamber with a size DN150 body and top flange may be required.External Displacement Level TransmittersMaterialsDisplacer chambers and torque tube housing materials shall meet requirements of the application. Cast iron shall not be used. As a minimum, displacers shall be minimum 316 stainless steel with 316 stainless steel or Inconel torque tubes. For low temperature and other severe service applications materials compatible with the process shall be specified on the instrument data sheet.ConnectionsDisplacer chambers shall have 1 inch NPT or 2 inch flanged connections. All displacer chambers shall have a rotatable head flange. All chambers shall be provided with a top flange to facilitate cleaning and removal of the displacer.Internal Displacement Level TransmittersMaterialsMounting flanges and torque tube housings shall be steel. Cast iron shall not be used. Displacers shall be minimum 316 stainless steel with 316 stainless steel or Inconel torque tubes. For low temperature and other severe service applications materials compatible with the process shall be specified on the ISS.MountingSide mounting instruments are preferred for tall vessels. A mounting flange shall be provided on the vessel for top-mounted instrument installation.InstallationInternal displacement type instruments shall have ample clearance for removal of the displacer and rod. Provisions should be made on the vessel for access to the internal parts, e.g., a manhole.Stilling WellsA process vessel internal displacer shall be mounted inside an internal mounted guide pipe, termed a still well, to protect and guide the displacer. The still well shall be open at the bottom, shall include adequate equalization and vent holes along its length, and be of sufficient diameter to prevent hang-up of the displacer. Internal displacement type instruments shall not be used in vessels where high turbulence is expected.Use of internal displacement level transmitters requires written approval from C&A CFDH.Capacitance Level TransmittersApplication Capacitance-type level probes are particularly suitable for the following applications:a)liquids with varying density;b)liquid/liquid interface;c)level switches;d)corrosive services.For liquid services which tend to foul an admittance probe should be considered. Automatic temperature compensation shall be provided in probe circuitry for liquids in which the dielectric constant changes as a function of temperature. Capacitance level transmitters shall not be used if the liquid conductivity can change from nonconductive to conductive. The level detection system shall consist of an insulated probe, responsive to changes in level with head mounted or remote mounted electronic unit as indicated in the data sheet. In case of remote electronics unit, vendor shall advise the type of interconnecting cable to be used in between probe and electronic unit, and also distance limitations, if any. The probe shall be immersion type & shall work on RF admittance principal. The length shall be as indicated in instrument data sheet. Operation of the instrument shall not be affected by specific gravity, conductivity of the fluid. Wherever asked for in the data sheets, vendor shall provide the active build up compensation circuitry. The probe material and other wetted parts material shall be minimum SS316 or equivalent or as indicated in data sheet. The insulation material e.g. PTFE or PE shall be selected according to the application.Installation Capacitance level measurement probes must be top mounted. Probe length and mounting requirements shall be in accordance with manufacturer's instructions. The preferred vessel installation is with a sealed isolating valve to allow the probe to be removed without releasing the process pressure. The probe shall be installed so that it is not affected by the filling stream. If this is not feasible, the probe shall be protected with a shield or baffle. Unless otherwise indicated in the data sheet, the process connection shall be 2 NB, 150# RF flanged. Flanged end connection shall conform to ANSI B 16.5 standard (Latest Edition).Radioactive Level TransmittersApplication Nuclear instruments provide a noncontact means for measuring level. Nuclear instruments can be used for the following difficult applications and can provide high accuracy if properly calibrated: a) Viscous or dirty materials that cannot be measured by other methods b) Liquids subject to polymer build upc) Cryogenic service d) Foaming servicee) Highly corrosive servicef) Toxic serviceg) Solids/liquid systemsh) Molten liquids The use of level instruments which contain radioactive sources type shall require approval from C&A CFDH. Verification of the selection of type of radioactive source, isotope strength, pressure and temperature rating based on the information furnished on the instrument data sheet and the geometry of equipment and the obstructions if any, inside the equipment shall be of the vendor. Vendor shall assist Company in obtaining necessary clearance for shipment to and use of this equipment, to the location indicated elsewhere. Vendor shall advise the radiation level around source and on the vessel / piping surface and suggest the protective measures if required. In case required, a portable instrument for measuring radiation intensity will be offered alongwith the instrument. Vendor shall make specific recommendation on design of source viz. Point source / Rod source and the type of counter. Wherever required based on the process data and site conditions, vendor to advise the requirement of cooling water and furnish the required flow, pressure and temperature of the cooling water.Installation Nuclear instruments include a radiation source and detector. The source radiates the signal into the vessel. The mass in the vessel absorbs or reflects the radiation and blocks a percentage of it from reaching the detector. A standpipe can be used if the vessel is large and requires a large source size. The source shall be CJ 137 or cobalt as indicated in data sheet. A protective source housing with an enclosed radiation source for flange mounting externally to one side of the vessel. The shielding of the source shall be designed to meet the international standards on radiation protection (ISO 2919 or equivalent). Unit shall have a key operated switch for opening/closing the source beam. The detectors shall be compatible to the source used. A high sensitive detector tube (e.g. Scintillation counter) suitable for externally mounting on the opposite side of the Vessel / Pipe relative to source. Detector shall have automatic source decay compensation. Cooling water jackets, if required, shall be supplied by vendor and wherever asked for vendor shall provide mounting brackets for installation of the source and detectors. Nuclear devices can be difficult to calibrate accurately. It may be required to empty and fill the vessel to zero and span the device to obtain the desired calibration accuracy. Lock out procedures and equipment are required so that maintenance can be performed safely on the system. Some processes require extensive engineering to determine the correct nuclear source size and source isotope to be used. Some applications require extremely large sources, which can increase delivery time, increase total cost, increase licensing requirements, and require special mounting considerations.TransmittersThe detector shall be connected to the remote mounted HART or Foundation Fieldbus based smart transmitter. The transmitter unit shall convert the pulses received from counting tube, in to an isolated signal.Ultrasonic Level TransmittersApplication Ultrasonic instruments determine level by reflecting a sound signal from the liquid surface and measuring the time it takes to receive an echo. Ultrasonic level measurement shall be used only on non-critical utility service including sewage and water only sumps. Ultrasonic level measurement shall not be used in oily water sump pits or dedicated hydrocarbon applications. Ultrasonic transmitters can be used to measure liquid/liquid interfaces in applications where the transmitter sensor is mounted in one of the liquid phases directing energy to the liquid/liquid interface. Ultrasonic transmitters are useful if liquid coating or build up caused by instrument contact with process liquid could impair other measurement devices (e.g., floats). Ultrasonic transmitters are useful if variations in composition, density, thermal or electrical conductivity, capacitance, or other characteristics in fluid are common or expected. Ultrasonic instruments shall not be used in high-density vapor spaces that have dusty fines or droplets forming a heavy fog. (The sound signal may be dispersed, high-density vapor spaces, with droplets forming a heavy fog, or dusty fines may prevent the measurement from working properly). Applications with foam or froth shall be reviewed with the manufacturer for applicability of ultrasonic measurement (Some designs may disregard the foam and measure the liquid. Others may measure the top of the foam only). Ultrasonic transmitters shall not be used in vacuum service. As the sound velocity is subjected to the temperature and pressure influence, ultrasonic measurements shall be temperature and pressure compensated, the control unit shall continuously detect the ambient temperature so that the level measured is independent of the temperature.Installation Ultrasonic installations require consideration of vessel geometry and nozzle location and size. Internal obstructions such as baffles, standpipes, etc., need to be considered. For applications where the liquid is turbulent, a slotted stilling well can dampen turbulence of the liquid. Stilling wells may also be used to avoid the effects of internal vessel obstructions. Installation and design of a stilling well shall meet manufacturers criteria for the probe and system used to avoid errors that are due to pipe diameter, connection sizes, branch connections, internal vessel obstructions, etc. Ultrasonic Transducer shall operate with frequencies of 16 kHz to 70 kHz with beam angle of minimum 10 deg . Range of the transducer shall be as indicated in data sheet. Unless otherwise indicated on the data sheets, process connection shall be 3 #150 RF flanged. Wetted part material shall be minimum SS316 or PTFE or suitable for the specified application.Sight Level GlassesSight Level gauge glasses in hydrocarbon service shall be transparent or reflex type heat-resistant glass with chambers machined from solid bar alloy steel and with drop-forged alloy steel covers. Area lighting shall be provided for all gauges installed in poorly lighted areas. Gauge illumination shall also be provided to all transparent gauges. where readings are taken at night or are vital for safe operation of the process.The pressure and temperature ratings of the gauge glasses shall be equal to or higher than the vessel design pressure and temperature.Gauge glass gaskets shall be graphoil or graphite-impregnated type material. The gasket material must be asbestos-free and capable of sealing under the continuous pressure and temperature conditions.For pressurized storage vessels, gauge glasses shall be installed only if required for calibration of other instruments. The gauge glass shall be with ball check gauge cocks. The gauge glass shall be installed at the elevation required to calibrate the other instrument. The other instrument may be local or remote indicating.Ball check type gauge cocks shall not be used in dirty services where waxy or gummy components exist and deposition can lead to potential blockage of the ball check flow passages. For corrosive service, the gage cock body and trim shall be made from corrosion resistant alloys which are compatible with the process fluids. The minimum requirement for corrosive service is stainless steel stem, seat and ball check.Reflex Gauges: Reflex gauges shall be used on all clean services, except for liquid interface level. Reflex gauges use a prism to reflect the light from the liquid or from the backplane of the gauge. Reflex gauges cannot detect a liquid interface. Reflex gauges require proper gasket selection and special torquing procedures. Weld pad type reflex gauges shall be used only in ambient temperature and atmospheric pressure applications.Transparent Gauges Transparent gauges shall be used for acid, caustic, dirty or dark-colored liquids, liquid interface, high viscosity fluids, high-pressure steam applications. Suitable shields (e.g., mica) on the inside of the gauge shall be considered for steam, caustic and other fluids that may adversely affect glass. Transparent gauges consist of two blocks of glass on opposite sides of a standpipe. The glass allows light to pass through the contained fluid. Transparent gauges require proper gasket selection and special torquing procedures.Magnetic Level GaugesA Magnetic Level Gauge may be used for services in which: Sight level gauge glass assemblies are not recommended for the measurement of dangerous or toxic fluids; Glass breakage would be likely; Sight level gauge glass can be obscured or coated due to the nature of the process fluid. High pressure vessel applications.Magnetic Level Gauge assemblies shall be installed only in areas that are free of physical forces or materials that would adversely affect the magnetic operation of the system.Magnetic Level Gauges shall not be installed in dirty or plugging service where debris or buildup can cause float sticking.The floats in magnetic level gauges can be thin-walled and may collapse from excessive pressure (e.g., hydro-testing). If floats are not rated to withstand hydrostatic testing, they should be removed during such testing.Magnetic gauges can become uncoupled between the float and the local indicator. Continuous bar-style indicators are not susceptible to uncoupling and are preferred to point-style indicators.The float in a magnetic gauge is engineered for a certain range of liquid densities. If the fluid density varies beyond that range, the level indicator may stop working (i.e., the float may sink). This is particularly critical in interface applications.Magnetic gauges should generally be limited to a maximum measuring length of 10 feet (3 meters). Gauges over 10 feet length may require additional support. Utilize multiple overlapping gauges for longer spans.Magnetic Level Gauge assemblies shall be installed with top, bottom, or side connections. The chambers and float materials shall be suitable for the application, with 316 stainless steel minimum. For low temperature and other severe service applications materials compatible with the process shall be specified on the Instrument data sheets.

Appendix 1 GWR Probe Selection Chart ServiceTypical Process LiquidsProbe TypeRemarks

Co-Axial Large DiameterCo-Axial Standard DiameterTwin RodSingle Rod

Hydrocarbons - White productsDielectric < 2Diesel, Kerosene, LPG, Propane, Butane, HC Condensate etc.,YesYesNoYes(See Note 1)

Hydrocarbons Black ProductsDielectric > 2 Viscosity 2Viscosity >500 cP,