SAES-J-100

Engineering Standard SAES-J-100

Process Measurement

06 October 2020

Document Responsibility: Instrumentation Standards Committee

Contents

1 SCOPE … 3

2 CONFLICTS AND DEVIATIONS … 3

3 REFERENCES … 3

4 GENERAL REQUIREMENTS … 6

5 PROCESS FLOW MEASUREMENT … 6

6 PRESSURE MEASUREMENT … 12

7 LEVEL MEASUREMENT … 14

8 TEMPERATURE MEASUREMENT … 26

REVISION SUMMARY … 34

APPENDIX 1 - MINIMUM STRAIGHT RUN LENGTHS FOR ORIFICE PLATES WITHOUT FLOW CONDITIONERS IN ACCORDANCE WITH ISO 5167-2 … 35

APPENDIX 2 - MINIMUM STRAIGHT RUN LENGTHS FOR CLASSICAL VENTURIS IN ACCORDANCE WITH ISO 5167-4 … 36

Previous Issue: 04 August 2019

Contacts: (abdumx1j) and (sahanfa)

Next Planned Update: 06 October 2025 Page 1 of 36

Saudi Aramco: Company General Use

Document Responsibility: Instrumentation Standards Committee Issue Date: 06 October 2020 Next Planned Update: 06 October 2025

SAES-J-100

Process Measurement

Summary of Changes

Paragraph Number

Previous Revision (04 Aug 2019)

Current Revision (06 Oct 2020)

Change Type (Addition, Modification, Deletion)

Technical Change(s)

3.1

N.A

3.2

N.A

N.A 4.2.2

N.A N.A N.A

5.7 and 5.8

7.4.4 7.12 7.12.4 7.13.1

8.1.2.7

N.A

3.1

N.A

3.2

4.1.4 4.2.2

5.6.1 5.6.2.3 5.6.3.2

N.A

7.5.4 7.12 7.12.4 7.13.1

Deletion

Addition

Deletion

Addition

Addition Modification

Modification

Addition Addition Addition

Deletion

Delete AD-036004,AC-036413, AB-036414, AE- 036175 Add new references SAEP-83 and SAES-A-017 Delete AGA 8, AGA 9, ISA MC96.1 and SAMA RC21-4:1966 Add references API MPMS 14.10, ASME MFC- 14M, ASME V&V 20, ISO 12242, ISO 17089-2 Add new section for dirty service requirement Clarify the requirement Revise the requirement for high accurate measurements Requirements for ultrasonic flowmeters Requirements for non-intrusive flowmeters Requirements for ultrasonic flare flowmeter Requirements for turbine and positive displacement meters to be based on API RP 551 Add commentary note and exception for GWR

Modification Modification Clarify requirement for GWR for ATG application Modification Modification

Clarify on the fabrication and installation of still well Add commentary note Add requirement for FEA and CFD models for helical thermowell

8.1.2.7

Addition

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Document Responsibility: Instrumentation Standards Committee Issue Date: 06 October 2020 Next Planned Update: 06 October 2025

SAES-J-100

Process Measurement

Scope

This standard defines the minimum mandatory requirements governing the design and installation of process measurement instruments. For custody measurements refer to applicable custody MSAERs.

This standards is based on API RP 551, “Process Measurement” All requirements of API RP 551 are applicable except as stated in this standard.

Conflicts and Deviations

Any conflicts between this document and other applicable Mandatory Saudi Aramco Engineering Requirements (MSAERs) shall be addressed to the EK&RD Coordinator.

Any deviation from the requirements herein shall follow internal company procedure SAEP-302.

References

The selection of material and equipment, and the design, construction, maintenance, and repair of equipment and facilities covered by this standard shall comply with the latest edition of the references listed below, unless otherwise noted.

3.1

Saudi Aramco References

Saudi Aramco Engineering Procedure

SAEP-302

Waiver of a Mandatory Saudi Aramco Engineering

SAEP-83

Mass Balance Guidelines

Requirement

Saudi Aramco Engineering Standards

SAES-A-017

Process Engineering Design Guidelines:

Hydrocarbon Filtration and Separation Systems

SAES-B-057

Safety Requirements: Refrigerated and Pressure

Storage Tanks and Vessels

SAES-J-003

Instrumentation and Control Buildings-Basic

Design Criteria

SAES-J-601

SAES-J-902

Emergency Shutdown and Isolation Systems

Electrical Systems for Instrumentation

Saudi Aramco Materials System Specification

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SAES-J-100

Process Measurement

34-SAMSS-913

Instrumentation and Thermocouple Cable

Saudi Aramco Standard Drawings

AB-036094

AA-036256

Standard Orifice Plates

Radar, Temperature, and Manual Gauging

Assembly for Floating Roof Tanks

AB-036521

Bridge Weld and Typical Brace Seal Welded and

Socket Welded Valves on Process Lines

AB-036019

Thermowell - Assembly and Detail

Saudi Aramco Library Drawings

DC-950045

DB-950046

Standard Instrument Standpipe

Instrument Piping Detail for Liquid Level Gauge

Glasses

DB-950047

Instrument Piping Details for Pneumatic Level

Instruments

DB-950048

Standard Instrument Piping Details for Electric

Level Instruments

3.2

Industry Codes and Standards

American Gas Association (AGA)

AGA Report 3

Orifice Metering of Natural Gas

American Petroleum Institute

API RP 551

Process Measurement

API MPMS 3.1A

Standard Practice for Manual Gauging of

Petroleum and Petroleum Products

API MPMS 3.1B

Standard Practice for Level Measurement of Liquid Hydrocarbon in Stationary Tanks by Automatic Tank Gauging

API MPMS 7

Temperature Determination

API MPMS 14.3.2

Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids - Concentric, Square-Edged, Orifice Meters, Part 2: Specifications and Installation Requirements

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SAES-J-100

Process Measurement

Commentary Note:

API-14.3/AGA-3 are identical documents, so they can be used interchangeably.

API MPMS 14.8

Natural Gas Fluids Measurement Chapter 14

Section 8 – Liquefied Petroleum Gas Measurement

API MPMS 14.10

Natural Gas Fluids Measurement Chapter 14 Section 10 – Measurement of Flow to Flares

American Society of Mechanical Engineers

ASME B16.36

Orifice Flanges

ASME B16.47

Large Diameter Steel Flanges: NPS 26 through NPS

60 Metric/Inch Standard

ASME B16.5

Pipe Flanges and Flanged Fittings

ASME PTC 19.3

Thermowells – Performance Test Codes

ASME MFC-14M

Measurement of Fluid Flow Using Small Bore

Precision Orifice Meters

ASME V&V 20

Standard for Verification and Validation in

Computational Fluid Dynamics and Heat Transfer

International Electrotechnical Commission

IEC 60751

Industrial Platinum Resistance Thermometers and

Platinum Temperature Sensors

International Organization for Standardization

ISO 5167 Parts 1-5

Measurement of Fluid Flow by Means of pressure Differential Devices Inserted in Circular Cross- Section Conduits Running Full

ISO 12242

Measurement of Fluid Flow in Closed Conduits –

ISO 17089-2

Ultrasonic Transit-time Meters for Liquid

Measurement of Fluid Flow in Closed Conduits – Ultrasonic meter for Gas – Part 2: Meters for Industrial Applications

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SAES-J-100

Process Measurement

General Requirements

4.1

Selection Criteria

4.1.1 The selection of process measurement instrumentation shall consider the following as a minimum: Application suitability, Reliability, Turndown ratio, Required Accuracy, Operability, and Maintainability.

4.1.2 Selection of instrumentation for ESD service shall meet requirements of

SAES-J-601 in addition to this standard.

4.1.3 Wake frequency/stress calculation shall be performed on all intruding

elements such as insertion type flowmeters, , thermowell, etc. In addition, these calculations shall be attached to the respective Instrument Specification Sheet (ISS).

4.1.4 Selection of instrumentation for dirty service shall meet the requirements in this standard and API 551. Refer to SAES-A-017 for classification of clean and dirty services.

4.2

Installation Requirement

4.2.1 All installation requirements shall follow SAES-J-003.

4.2.2

Instrument manifold valves can be either 2-way valves, 3-way valves or 5-way valves. The installation of the manifold shall be per API 551. Transmitters (unless close coupled) shall not be installed on process piping but on a dedicated instrument stand.

4.2.3 Diaphragm (Capillary) seals shall be used in lieu of impulse tubing for volatile, dirty fluids and applications that may cause impulse line blockage. The installation shall include drain valves between the process block valves and the diaphragm seal. Capillary seal fluids, when used, shall be suitable for external ambient conditions. Electronic remote seals are acceptable.

4.2.4 Wet leg shall be avoided.

Process Flow Measurement

If operation requirements dictate high accuracy measurements, a suitable flowmeter shall be selected with pressure and temperature compensation, if required.

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SAES-J-100

Process Measurement

Commentary Note:

Examples of high accuracy meters include mass balance flowmeters per SAEP-83 and petroleum product blending meters.

5.1 Meter Sizing

5.1.1 Sizing of orifices shall be done in accordance with API-14.3/ AGA-3 or

ISO 5167. Sizing software may be used.

5.1.2 Nozzle, Venturi, and other differential pressure device calculations shall

be in accordance with ISO 5167.

5.1.3 For other proprietary meters, the manufacturer’s sizing and calculation

methods shall be used.

5.1.4

In general, differential pressure type flow instruments should be sized such that normal flow is between 65% to 80% of design maximum.

5.1.5 Square root extractions in calculating flows from differential pressure based flow meters shall only be performed in one location either in the transmitter, or control system, preferably in the control system.

5.2

Installation and Piping

5.2.1 The installation of fluid measurement by means of differential pressure

devices shall be per SAES-J-003.

5.2.2 A line class root/isolation valve shall be provided at each process

connection. Piping from taps to this first root valve shall be specified and provided by the piping discipline.

Exception:

Closed coupled instrument mounting systems and special manifolds that combine piping and instrument valves maybe used. Effects of instrument size and weight as well as heat or vibration in piping systems should be carefully evaluated.

5.2.3 Orifice flanges are to be weld-neck with an internal bore to match the

internal diameter of the pipe. Any distortion resulting from the butt weld shall be removed and ground flush with the inside diameter of the pipe. Orifice flanges up to 24 inches shall be in accordance with ASME B16.36. Orifice flanges larger than 24” shall be based on ASME B16.47.

5.2.4 When piping is used for process connections, the piping and flange

specifications and installations shall follow the relevant piping standards.

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SAES-J-100

Process Measurement

From the root valve to the instrument, the instrument piping specification, material of construction, pressure rating, fittings, and valves shall meet or exceed applicable piping specifications for the process service. Flanges shall be rated to meet the service conditions.

5.2.5 For liquid services, pressure taps shall be located on the horizontal plane of the piping or alternatively up to 45 degrees down from horizontal for non-plugging applications. The impulse lines shall be sloped downward approximately 1:12 toward the transmitter.

5.2.6 For gas and vapor services, pressure taps shall be located on the vertical

from the top of the piping, or up to 45 degrees from top. The impulse lines shall be sloped downward approximately 1:12 toward the process connections.

5.2.7 For steam services, pressure taps shall be located on horizontal plane of the piping, and shall be equipped with seal pot or equivalent. Both seal pots must be at the same elevation.

5.2.8 All parallel pipe lines with adjacent orifice flanges or orifice fittings

shall have a minimum spacing of 300 mm (12 in) between flanges outside diameters if horizontal taps are required. In addition, they shall be staggered so that no two pairs of orifice flanges (centerline to centerline) are less than 1 m (3 ft) apart.

5.2.9 Flow measurements requiring temperature compensation, thermowells shall be located between 5 to 20 nominal pipe diameters downstream of the meter.

5.2.10 Unless otherwise required by the process or piping specifications, orifice plates, flow nozzles, pitot tubes, and flow conditioners shall be 316 stainless steel as a minimum.

5.2.11 Flow conditioners shall not be used if the meter is followed by rotating

process equipment (compressors, pumps, turbines, etc.) that can be damaged if a part of the conditioning device breaks off and enters the equipment.

5.2.12 The use of strainers and air eliminators shall be considered to protect

metering devices when performance or integrity is compromised without such protection.

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Document Responsibility: Instrumentation Standards Committee Issue Date: 06 October 2020 Next Planned Update: 06 October 2025

SAES-J-100

Process Measurement

5.3

Orifice Meter

5.3.1 The design and fabrication of orifice meter shall be in accordance to ISO

API-14.3/AGA-3 or 5167-2.

5.3.2 Flange taps shall be used for all orifice meter installations. The tap

connections shall conform to ASME B16.36.

5.3.3 Paddle type orifice plates shall be used where raised face orifice flanges

are used.

5.3.4 The orifice plate shall be fabricated per Standard Drawing AB-036094.

5.3.5 Orifice bore beta ratios are recommended between 0.20 and 0.70. For orifice plates in 24 inches and larger pipelines that require low pressure losses, a beta ratio of 0.75 is acceptable.

5.3.6 Appendix 1 shall be used for straight run requirements. For new orifice

plate installations, a beta ratio of 0.75 shall be assumed when determining the minimum length of straight piping required.

Commentary Note:

Small bore orifice is allowed for non-plugging service, and pipe size is less than 2”. It shall be in accordance with manufacturer’s recommendations and/or ASME MFC-14M. If high accuracy is required, Coriolis meters are recommended for installations on small pipe sizes.

5.3.7 When the static pressure compensation is required, the connection is recommended to be derived from the orifice meter upstream pressure tap.

5.4

Flow Nozzles

5.4.1

In high pressure (1,000 psig or higher) applications, the flow nozzle shall be welded directly into the pipe and a flanged drop out spool section shall be provided upstream of the flow nozzle for inspection and maintenance.

5.4.2 Pipe sections for the installation of flow nozzles shall be stamped with the Instrument Tag Number of the element, the element location in the pipe, the pipe internal diameter, and the direction of flow.

5.4.3 Minimum straight run pipe length requirements and construction shall be

in accordance with ISO 5167-3.

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SAES-J-100

Process Measurement

5.5 Venturi

5.5.1 Fabrication and calculations of Venturi meters shall be in accordance to

ISO 5167-4.

5.5.2 Minimum straight run pipe length requirements shall be in accordance

with Appendix 2.

5.6

Ultrasonic Flow Meter

5.6.1 The design and installation of ultrasonic flow meters shall follow ISO

17089-2 for gas, and ISO 12242 for liquid.

5.6.2 Non-Intrusive Flow Meters

5.6.2.1 Non-Intrusive meters are acceptable for non ESD services in

existing facilities in case pipe modification is not possible.

Commentary Note:

For Non-Intrusive meters, installation shall comply with the manufacturer requirements such as straight run, no gas pockets, temperature and pressure conditions, and suspended solids.

5.6.2.2 Non-Intrusive meters shall not be allowed for new pipe

construction.

Exceptions:

In addition to insertion and spool type ultrasonic meters, non-intrusive is also acceptable for tank dewatering and Pipeline Product Interface Detection applications. Both flow and sound velocity measurement are required for the dewatering application.

5.6.2.3 Non-Intrusive meters for permanent installation shall meet the

following:

5.6.2.3.1 The meter shall be approved for the classified area as

per SAES-J-902.

5.6.2.3.2 Transducers shall be mounted using permanent pads

5.6.2.3.3 The meter shall be field-tested and proven to be

working reliably (diagnostics parameters shall indicate healthy and accurate measurement) before it is permanently installed.

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SAES-J-100

Process Measurement

5.6.3 Flare flow meter

5.6.3.1 Ultrasonic flow meter shall be selected for flare service. Integral

extraction mechanism shall be provided to facilitate online cleaning or replacement of the transducers when required.

5.6.3.2 The design and installation shall follow ISO 17089-2 and API

MPMS 14.10.

5.6.3.3 A sampling point for composition is required.

5.6.3.4 Temperature and pressure compensation is required.

5.6.3.5 Diagnostic parameters for the flare meter shall be displayed at the

control system to provide analytical data on the flare flowmeter performance. As minimum, these parameters include speed of sound, flow velocity, channel gain, signal to noise ratio, signal quality and fault conditions.

5.6.3.6 The installation and commissioning of flare flow meters, shall be conducted by the manufacturer or a manufacturer-certified representative.

5.7

Averaging Pitot Element

5.7.1 Pitot Elements shall only be installed in clean noncritical services. In

addition, elements shall be provided with purge capability.

5.7.2 For a removable element, the process valve shall have the proper inside diameter to allow passage of the element. The valve shall meet applicable piping specifications.

5.7.3 Manufacturer’s installation recommendations shall consider element deflects and vibration in large diameter pipes or ducts or if high flow velocity.

5.8

Flow Switches

Vane (paddle) type flow switches shall not be used.

5.9

Transmitters and Indicator

5.9.1 Multivariable smart transmitters are acceptable for Temperature-Pressure

compensated flow loops whenever possible.

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SAES-J-100

Process Measurement

5.9.2 Sight Flow Indicators or Sight Flow Glasses shall only be installed if no other alternatives are available. Also, they shall not be used in toxic and corrosive services.

Pressure Measurement

6.1

General

6.1.1 As a minimum, all pressure devices shall be specified with over-range

protection to 1.5 times the maximum system operating pressure. In addition, transmitters shall be protected against vacuum in vacuum applications.

6.1.2 Pressure sensing elements shall withstand a proof pressure not less than

the system hydrostatic test pressure without damage to the element.

6.1.3 Material selection for pressure device wetted parts shall be type 316

stainless steel minimum with PTFE gaskets, unless other materials are required by the process.

6.1.4 Ranges shall be selected such that the normal operating pressure falls

between 30% and 70% of the scale range.

6.2

Installation Requirements

6.2.1 Branch connection up to and including the first block (root) valve shall

meet the applicable Saudi Aramco piping codes. If more than one instrument are sharing a common root valve, means to isolate each instrument independently shall be provided.

Commentary Note:

The device manifold is acceptable to provide the required isolation at the end- use device in clean/non-plugging services when multiple devices share a common root valve connection.

6.2.2 Process connections for direct-mounted instruments shall be located only

where line vibration is negligible.

6.2.3 For low-pressure service, e.g., furnace draft, the instrument is to be

mounted at the same elevation or above the pressure tap.

6.2.4 All pressure instrument installations shall be equipped with vent/drain

valves.

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SAES-J-100

Process Measurement

6.3

Pressure Gauges

6.3.1 Fill material shall be selected to be compatible with the process media.

6.3.2 Pulsation dampers should be considered in addition to filled cases.

6.3.3 The process connection for a pressure gauge shall be ½-inch MNPT

(either bottom or back connected).

6.3.4 Dials on Process pressure gauges shall be 100 mm or 4-½ inch in

diameter and shall be white with black numerals.

6.3.5 Siphons shall be specified in steam and other high-temperature

condensable vapor services.

Note: Siphons shall also be used for process fluids with a temperature over 250°C (480°F) when the gauge is above the tap connection.

6.3.6 Gauges supplied by vendors as part of other pneumatic devices such as current to pneumatic converters, instrument air supply regulators, valve positioners, piston actuators, and similar devices shall be vendor standard unless otherwise specified.

6.4

Pressure Switches

6.4.1 Pressure switch should only be considered when pressure transmitters

cannot be used and the deadband shall be compatible with the application.

Comment:

If the process runs close to the switch setting, a large deadband may prevent the switch from resetting after the trip has cleared.

6.4.2 Switch Process side connections shall be ½ inch NPT. Connections for

pneumatic tubing shall be ¼ inch NPT female, minimum.

6.4.3 Electric switch contacts shall be snap acting, single-pole, double-throw (SPDT) as a minimum. The contact rating shall be sufficient to operate solenoids, relays, or other devices as specified in the data sheet without the need for additional or interposing relays. Hermetically sealed switch contacts are preferred.

6.4.4 Switch actuation, as the result of increasing or decreasing pressure must

be specified.

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SAES-J-100

Process Measurement

6.5

Accessories

6.5.1 All pulsation dampeners (or snubbers), siphons, diaphragm seals and

similar accessories shall be shown on P&IDs.

6.5.2 Snubbers shall not be used on switches in critical service or dirty

services. Pulsation dampeners using a restriction orifice or a moving piston are acceptable. Capillary tube-type snubbers are not acceptable.

6.5.3 Gauge savers protecting instruments against pressures that are very high

compared to the operating range may be used, except on switches in critical service.

Level Measurement

7.1

Standpipes

7.1.1 When several instruments are required on a vessel for control and

monitoring purposes, a common standpipe should be used. The process shall be non-plugging, the tap nozzle size shall be at least 2 inches and the common isolation valves on the tap nozzle shall be car sealed open. For details of a typical standpipe refer to Library Drawing DC-950045.

7.1.2 Standpipes on spheroids shall be fabricated from 6 inch (NPS) carbon

steel pipe. Standpipes shall be supported from the spheroid shell. Standpipe connections to the spheroid shall be made by a 2 inch and a 3 inch isolating gate valve, located at the top and bottom of the standpipe, respectively. Both valves shall be Car Sealed Open (CSO).

7.1.3 Standpipe and individual level instruments shall be connected directly to

vessels and not to inlet or outlet piping. All connections shall be free draining. Connections to the bottom of vessels shall be avoided whenever possible. However, when used, bottom vessel connections shall include an internal nozzle extension to reduce bottom solids from entering the standpipe.

7.1.4 Standpipes shall be insulated when the operational temperatures ranges

are either above 60 °C or below 0°C.

Commentary Note:

Standpipes shall not be used in low temperature service, i.e., -7°C or below.

7.1.5 Standpipes shall not be used for ESD functions.

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SAES-J-100

Process Measurement

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 seal open (CSO). In addition, ESD and process control level transmitters shall have independent level bridle isolation valves and should be calibrated for the same range.

7.1.6 Standpipes shall not be used on packed towers, across filter pads,

demister pads, in viscous service and in applications where materials being handled contain high concentrations of solids.

7.1.7 For applications, highly sensitive to density change, the use of stand pipe

shall be reviewed and approved by proponent.

7.1.8 When required, a dedicated standpipe shall be provided for vessel boots.

The standpipe for vessel level measurement shall not be used for boot level measurement.

7.2

Block Valves

Capability to isolate each individual instrument from the process shall be provided by an instrumentation root valve installed as close as possible to the vessel or standpipe connection. Valves shall be in accordance with piping specifications. No fittings shall be allowed between this primary block valve and the connecting boss, except for a single pipe nipple. Threaded connections between the root valve and the boss shall be seal or bridge welded per Standard Drawing AB-036521.

7.3

Discharge Energy

Level instruments which discharge energy directly into the process shall have their sensor electronics certified for the electrical area classification inside the vessel.

7.4

Local Level Indicating Gauge

The design of process or safety system level instruments shall include an associated local level gauge (sight glass or magnetic level indicator MLI) to allow calibration, range checking, and visual level verification over the calibrated range of the instrument. MLI should be considered the first option when selecting level gauges

7.4.1 Sight Level Gauge Glasses

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SAES-J-100

Process Measurement

7.4.1.1 Sight 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.

7.4.1.2 The pressure and temperature ratings of the gauge glasses shall

be equal to or higher than the vessel design pressure and temperature. Minimum rating for the reflex type shall be 14,000 kPa (2,000 psig) at 40°C, and for the transparent type 7,000 kPa (1,000 psig) at 40°C.

7.4.1.3 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 set forth in previous paragraph.

7.4.1.4 Frost gauges shall be specified for low temperature service

below -7°C. Lucite or suitable alternative frost shields shall be included and shall extend through the gauge glass insulation.

7.4.1.5 Gauge glasses shall not be used on refrigerated storage tanks.

Refer to SAES-B-057.

7.4.1.6 For pressurized storage vessels, gauge glasses shall be installed only if required for calibration of other instruments. The gauge glass shall be a single 320 mm gauge 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.

7.4.1.7 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 316 stainless steel stem, seat and ball check.

7.4.1.8

Installation details should follow Library Drawing DB-950046.

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SAES-J-100

Process Measurement

7.4.2 Magnetic Level Indicator Gauges (MLI)

7.4.2.1 An MLI shall be used for dangerous or toxic services or

services in which obstruction or coating, due to process fluid nature, is very likely.

7.4.2.2 MLI 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.

7.4.2.3 MLIs shall not be installed in dirty or plugging service where

debris or buildup can cause float sticking.

Commentary Note:

Plugging service will require frequent flushing and purging and the selection of MLI shall be concurred by the operating facility.

7.4.2.4 MLI assemblies shall be minimum 1.5 inch NPT or 2 inch RF

flanged, class 150 and 40S chamber of 2 inch diameter. Installation is similar to external cage displacers - refer to Library Drawing DB-950047.

Commentary Notes:

Oversized chambers with guide rods are recommended for applications where the process fluid may boil or flash due to temperature differences between the process vessel and gage column. This type of chamber configuration is recommended for all light end hydrocarbon applications where the normal operating temperature is below 0°C to prevent the float from sinking.

Magnetic bargraph/flag type indicators are recommended. Follower, shuttle or any alternate indicator that utilizes a single component for level indication are not advised.

7.5

GWR Guided Wave Radar

7.5.1 Single probe GWR shall be used for liquid level and liquid-liquid

interface level measurement technology - for both process and ESD applications. Twin probe and coaxial GWR shall not be used. Other level measurement technology may be used if the single rod GWR is not suited to the application.

Commentary Notes:

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GWR technology should not be used for large emulsion layer interface detection such as inside GOSP desalters and dehydrators. Nuclear type level measurement is recommended for this process condition.

Exception:

Non-contact radar with suitable antenna can be used for level applications inside tanks, portable water tanks and sewage water sump.

7.5.2 Any ‘dead zones’ on the wave guide probe shall be designed outside the operating range of the GWR instrument. In no case shall a process level be capable of entering a probe ‘dead zone’.

7.5.3 Flushing ports shall be provided for all wave guide probes in viscous or

dirty service.

7.5.4 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. For underground vessels and where it is not practical to install GWR in bypass chambers, insertion type is acceptable provided there are means for verification and calibration.

Commentary Note:

For interface level measurement, connections of the external bypass chamber to process vessel shall be arranged so that there is always one connection in each phase of each interface being measured.

Exception:

Internally mounted GWR is allowed to situations where external mounted GWR design and installation is not possible. In this case, maintenance and removal of the GWR probe can only be done when the pressurized process vessels are isolated, depressurized and put out of service.

7.5.5 GWR Bypass chamber material shall meet the requirements of the

application, and be steel construction minimum. The size of the chamber and its connections for non-plugging services shall be minimum 2 inches for flanged on the top, bottom, or sides. The size of the chamber and its connection connections for potential plugging services shall be at least 3 inches. For chambers exceeding four meters in height, GWR manufacturer recommendation for the chamber size shall be followed.

7.5.6 Appropriate GWR process valves and connections shall be provided for

process isolation and for GWR calibration. Such connections shall include a vent.

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7.5.7 Dual chamber GWR with MLI designs shall only be permitted when

installing onto existing vessels where spare nozzles aren’t available or where it is impracticable to install a suitable standpipe.

7.5.8 All GWRs shall be configured and commissioned by the manufacturers

or a manufacturer-certified representative.

7.6

Differential Pressure Level Transmitters

7.6.1 Differential pressure level transmitters may be used for process and ESD

level and for liquid-liquid interface level measurements if radar (GWR) is not suitable for the application. Transmitters with diaphragm seals shall be used for process fluids that are highly viscous, containing entrained solids, highly toxic or in hot service.

7.6.2 Use of DP transmitter for refrigerated LPG tank level service should be

considered only when GWR level measurement is not feasible for the application. 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.

7.6.3 A diaphragm seal type installation shall include drain valves between the

process vessel block valves and the diaphragm seal - on both high and low pressure sides of the transmitter. Diaphragm seal transmitters shall be mounted at or below the lower vessel connection, preferably 1.4 m above grade or operating platform.

7.7

Displacement Level Transmitters

7.7.1 Use of displacement level transmitter shall be used only when GWR

level measurement is not feasible for the application.

7.7.2 Displacement level transmitters are normally used for liquid level ranges

up to and including 1,830 mm (72 in). Use of this technology shall be limited to non-viscous process fluids with low concentration of solids.

7.7.3 Displacement level transmitters shall normally be installed in cages

external to the process vessel, to allow for maintenance without process interruption or hazard.

7.7.4 An air-fin extension shall be provided between the level sensing element and the transmitter, for applications where fluid temperatures will exceed 200°C.

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7.7.5 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 ISS.

7.7.6 Displacer chambers shall have 1.5 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. For additional details on piping connections refer to Library Drawing DB-950047.

7.8

Capacitance Level Transmitters

Capacitance-type level instruments shall be considered only where GWR is not suitable. Capacitance probes shall not be used in liquids that contain entrained gas.

7.9

Nuclear Level Transmitters

7.9.1 Nuclear level instruments shall be considered only when other level

devices are not suitable such as GOSP desalters and dehydrators with large emulsion layers.

7.9.2 Both external and internal radiation detectors are acceptable providing

the full measuring range is covered by the device.

7.10 Level Switches

7.10.1 A dedicated, level switch shall only be used when level transmitters are not practical for the application. Emergency shutdown functions shall not be combined with control functions, refer to SAES-J-601, for details.

Commentary Note:

The vibration fork is the preferred level switch type.

7.10.2 On-Off Control

Internal tandem type displacement or vibration switches may be used for start-stop of pumps, open-close control of valves, initiation of high-low alarms, or combinations of these functions.

7.10.3 Level switches shall be hermetically sealed or totally encapsulated mechanical microswitches. Mercury switches shall not be used. Switch contacts shall be wired in a fail-safe, de-energize to alarm design.

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For example, contacts shall be closed during normal process levels. The contacts shall open at abnormal levels to alarm. Vibration switches shall be supplied with a self-test diagnostic facility.

7.11 Ultrasonic Level Measurement

Ultrasonic level measurement shall be avoided.

7.12 Automatic Tank Gauging (ATG) Systems

Single probe GWR shall be used for level and level based volume measurements on all hydrocarbon inventory tanks and tank farms.

Radar Tank Gauging (RTG) can be used only if the single probe GWR is not suitable for the given applications. Hydrostatic Tank Gauging (HTG), Servo Tank Gauging (STG), or float and tape based tank level gauges shall not be used.

Commentary Note:

For inventory tank gauging using GWR, the vendor shall confirm the specification and installation shall satisfy the requirement in API MPMS 3.1B. As a minimum, these requirements include:

i. GWR shall have a write-up protection.

ii.

Inherent uncertainty of 3mm

iii.

Installed uncertainty of 25mm

iv. Five (5) points calibration report for each GWR.

v. Traceability to national/international standards

7.12.1 Fixed Roof Tanks without Still Wells

7.12.1.1 GWR

Probe shall be installed correctly to avoid the probe sway, and shall be per vendor’s installation recommendations.

7.12.1.2 RTG

7.12.1.2.1 Cone or planar type microwave antennas shall be used on all clean products. The antenna shall be installed such that the microwaves can travel un- obstructed to the tank bottom. Obstacles, such as

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pipes and mixers, shall be designed around based on the RTG vendors’ requirements.

7.12.1.2.2 For condensing products that result in heavy

deposits (e.g., asphalt and fuel oils), the antenna design shall be such that minor deposits or condensation will not disrupt level measurement accuracy. A cleaning hatch or means to easily remove and clean the antenna shall be provided. The selection of antennas and installation details must be reviewed and concurred by the selected vendor.

7.12.2 Floating Roof or Internal Floating Pan Tanks with Still Wells

7.12.2.1 GWR

The GWR shall be able to operate within a still well, and shall be installed correctly to avoid probe sway. The GWR shall be per vendor’s installation recommendations.

7.12.2.2 RTG

RTGs especially designed to operate within a still well shall be utilized. The gauge shall use low loss circular microwave transmission mode to eliminate measurement errors due to corrosion of the still well interior wall.

7.12.3 Spheroid or Pressurized Tanks

7.12.3.1 General

7.12.3.1.1 GWR is the preferred technology for this

application.

7.12.3.1.2 Refrigerated LPG tanks shall be provided with

two (i.e. redundant) automatic tank gauging systems.

7.12.3.1.3 For additional guidance, please refer to

API MPMS 14.8.

7.12.3.2 GWR

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Probe shall be installed correctly to avoid probe sway, and shall be per vendor’s installation recommendations.

7.12.3.3 RTG

7.12.3.3.1 RTGs, designed for LPG/LNG service, shall be mounted on a 4 inch NPS still well to minimize the impact of waves and surface boiling on the measurement accuracy. Pressure and temperature measurements are required to compensate for composition changes in the vapor space.

7.12.3.3.2 The bottom datum plate and vendor supplied

reference pins shall be installed on the still well per vendor requirements, to permit on-line calibration and future verification of the level. However, at least one verification pin must be placed above the maximum working level of the tank to permit on-line calibration checks when the tank is full. The orientation of the reference pins shall be permanently marked on the still well flange and shall be within ±2 degrees.

7.12.3.3.3

Isolation block and bleed valves shall be provided to facilitate safe removal of the gauge head for in-service maintenance.

7.12.4 Still Well Design

The still well shall be designed and installed based on Standard Drawing AA-036256, or ATG (GWR and RTG) vendor requirements,. Vessel fabricator shall be responsible for the fabrication and installation of the still well.

7.12.5 Still Well Design for Pressurized Vessels

For all pressurized vessel applications, a still well shall be provided, if recommended by ATG vendors. The still well shall be fabricated from seamless, 316 stainless steel pipe, and shall be designed and installed per ATG vendor requirements.

7.12.6 Gauging Hatch

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For all atmospheric tanks, a reference gauge hatch shall be provided in close proximity to the ATG, for manual ullage measurements and periodic accuracy verification. See Standard Drawing AA-036256.

7.12.7 Maintenance Access Requirements

Sufficient access space above the tank in the X-Y-Z planes shall be provided to facilitate easy removal of the gauge. These dimensions should be in accordance with the vendor’s recommendations.

7.12.8 Product Temperature Measurement

Permanently installed, a single spot or multiple spot temperature elements shall be used whenever the functional specification requires automatic computation of Gross Standard Volume (GSV) or Net Standard Volume (NSV). The selection, design, and installation shall be per API MPMS 7, “Temperature Determination.”

7.12.9 Intrinsic Accuracy

The laboratory tested accuracy of the gauge shall be equal to or better than ±3 mm over the entire range of the ATG. Vendors shall provide certified test data to support their claims.

7.12.10 Operator Interface Unit

A Personal Computer (PC) based Human Machine Interface (HMI) and an industrial grade printer, shall be provided whenever the ATG system is not directly interfaced with a plant Digital Control System (DCS) or a host computer. The HMI shall be capable of handling configuration data, tank level displays and alarming functions.

7.12.11 Configuration

The ATG system shall be configurable via the field bus from a control room installed personal computer or the plant host computer, running vendor compatible tank farm management software. No external (mechanical) zero or span adjustments are permitted. For single or stand-alone installations without a field bus, calibration with a hand held programming device is acceptable.

7.12.12 Data Security

The ATG system shall be equipped with either a hard or soft switch, such that tank configuration data in the gauge head can be protected

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from accidental erasure. The tank management software shall have a password protection scheme to prevent accidental changes in the tank configuration data.

7.12.13 Safety Requirements

For RTG, during normal operation, bench testing or field service, shall not generate microwave power levels hazardous to humans. The maximum power level shall not exceed 2 milliwatts. The RTG shall have approval from the Federal Communication Commission (FCC, USA) and the Saudi Arabian Standards Organization (SASO). The vendor shall provide certification documentation to Saudi Aramco, upon request.

7.12.14 For high power RTG system, a local power disconnect switch, which is

easily accessible to an operator shall be provided preferably at the gauge head.

7.12.15 Verification Requirements

The frequency and procedure to verify the installed accuracy for ATG system shall be per API MPMS 3.1B. The installed accuracy of both systems must be verified by comparing the level readings against manual gauging. Manual gauging shall comply with API MPMS 3.1A.

7.12.16 Water Tanks

For water storage tanks, GWR and noncontact radar are recommended.

7.13

Independent Inventory Tank High High Level Alarms

7.13.1 An independent High High (HH) level alarm shall be provided on all atmospheric hydrocarbon storage tanks. This alarm shall be activated by a level transmitter which is completely independent of the inventory level monitoring ATG system. The independent HH level alarm shall annunciate in the control room, and if required, either divert the incoming flow or close the inlet valve per requirements specified by the proponent organization. The independent alarm and level transmitter system for this application shall not fail undetected. The alarm set point on the inventory ATG system shall be set such that approximately ten minutes time interval is available before the independent HH level alarm is reached. The interval computation shall be based on nominal fill rate.

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Commentary Note:

 Vessel fabricator shall be responsible for the fabrication and

installation of the stilling well.

 GWR and non-contact radar are acceptable for the

independent High High (HH) level alarm application.

 The devices and their stilling wells size and installation shall

comply with be per GWR / Non-contact manufacturer recommendations.

7.13.2 For pressurized or refrigerated hydrocarbon vessels, alarm requirements specified in SAES-B-057 shall apply.

Commentary Note:

This requirement is applicable to all new construction and major tank farm Instrumentation upgrade projects. This requirement is not retroactive to existing facilities. However, the Safe Operating Committee (SOC) for each effected plant should evaluate potential exposure, risk and the need to add the HH level alarm provision.

Temperature Measurement

8.1

Thermowells

8.1.1 General

All temperature sensing elements shall be installed in thermowells.

Exception:

Sensors for bearing, motor winding, furnace, skin or surface temperature measurement, ambient air, electronic equipment cabinets. (However, a mechanical protection sleeve shall be considered for the sensors in the area where there is possibility of damage such as pump bearings.)

8.1.2 Design

8.1.2.1 Flanged thermowells are highly recommended. Flanged

thermowells shall be used in ANSI Class 900 or greater or process temperature exceeding 535°C.

8.1.2.2 Weld-in thermowells shall only be used when ASME or Saudi

Aramco standards or specifications require welded connections.

8.1.2.3 Thermowells shall be 316 stainless steel unless alternative

metallurgy is specified or dictated by process conditions.

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8.1.2.4 Thermowells shall be constructed and installed in accordance

with API RP 551 Section 4.2.

Note: Threaded thermowells with ¾-inch NPT process connections shall be used only when required to replace existing ¾-inch thermowells.

8.1.2.5 Flanged thermowells shall be furnished with ASME B16.5

flanges. Flange size shall be minimum 1-½ inch, 150 #.

8.1.2.6 Standard thermowell bore selection for threaded and flanged

thermowells is 0.260 inch. The thermowell bore may be increased to 0.385 inch where required (e.g., filled systems). For the flanged thermowell the tip diameter shall then be increased to 0.75 inch.

8.1.2.7 Use of helical/vortex type thermowell is acceptable only if the

standard thermowell cannot meet ASME PTC 19.3 requirement. In this case, finite element analysis (FEA) and computational fluid dynamics (CFD) models are required for each suggested helical/vortex thermowell and its respective application. These models shall be validated according to ASME V V20.

8.1.3

Insertion Length

8.1.3.1

Initial insertion length “U” for thermowells in process piping shall be per Standard Drawing AB-036019.

Note: The final selection may be shorter based on wake frequency calculations.

8.1.3.2 For process vessels and columns, the maximum insertion length

shall be 600 mm (24 inches).

Exception:

For catalyst bed and other similar temperature profile measurements, extended thermowells are allowed. Extended thermowells shall be in a vertical orientation if feasible or supported such that vibration/gravity/ flow effects shall not cause fatigue or deformation failure of the thermowell.

8.1.3.3 The immersion of thermowell exposed to fluid flow shall be

sufficient, considering the projection length of the nozzle connection.

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8.1.4 Thermowell Vibration and Stress

8.1.4.1 Natural frequency and wake frequency calculations shall be performed on each thermowell application, per ASME PTC 19.3.

8.1.4.2 Standard U-lengths should be chosen, whenever possible.

8.1.4.3 For flanged thermowells, where the calculated U-length ends up being too short for good heat transfer, external dimensions such as root and tip diameter may be increased to lower the wake frequency and increase the resonant frequency. Collars shall not be used.

8.1.4.4 Maximum process pressure and static stress calculations shall be performed on each thermowell application, per ASME PTC 19.3.

Note: Pressure and static stress effects may combine with wake frequency vibration to cause failure of thermowells.

8.2

Thermocouple Instruments

8.2.1 Thermocouple Selection

8.2.1.1 Thermocouple construction, properties, calibration, color

coding, and limits of error shall comply with API 551.

8.2.1.2 Thermocouple selection shall be determined by the temperature

range to be measured. Type E, Type J, and Type K thermocouples are typically used in Saudi Aramco facilities.

Note: Type J TCs contain iron wire which is subject to corrosion in many locations.

8.2.2 Thermocouple Design and Installation

8.2.2.1 Thermocouples shall be insulated with packed magnesium oxide and protected with a ¼-inch o.d., 316 stainless steel sheath. Alternative sheath metallurgy may be used if required by process conditions.

8.2.2.2 Thermocouples may either be grounded or ungrounded.

With either type, single-point grounding of the signal loop must be observed. Ungrounded TCs shall be used to measure differential or average temperature.

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Note: Grounded thermocouples are preferred due to quicker response, and to consistently ground the signal wiring at the thermocouple end of the loop. Grounded junction TCs will not give accurate measurements when connected together to measure differential or average temperature.

8.2.2.3 Thermocouples shall be installed in thermowells such that the

end of the thermocouple is in contact with the bottom of the thermowell. Spring-loaded thermocouples are preferred to insure positive contact with the thermowell.

8.2.2.4 Dual element thermocouples are permitted when their intended function is to provide a spare thermocouple element for a single receiving instrument. A dual element thermocouple shall not be used to provide separate signals to different instruments or redundant inputs to a logic control system.

8.2.3 Thermocouple Extension Wire

8.2.3.1 Thermocouple extension wire shall be suitable for the specific type of thermocouple being connected. Thermocouple extension wire shall meet the requirements per API 551 and 34- SAMSS-913 and shall be installed in accordance with SAES-J- 902. Each pair shall be individually twisted and shielded.

8.2.3.2 For grounded thermocouples, the extension wire shield drain

wire shall be grounded at the thermocouple head. The continuity of the shield shall be maintained through junction boxes and transitions from single pair to multipair cables. The shield and drain wire shall be cut and secured (insulated) at the receiving instrument end of the extension wire.

8.2.3.3 For ungrounded thermocouples, the extension wire shield drain

wire shall be grounded at the receiving instrument end to the instrument circuit ground. The continuity of the shield shall be maintained through junction boxes and transitions from single pair to multipair cables. The shield and drain wire shall be cut and secured (insulated) at the thermocouple end of the extension wire.

8.2.3.4 The overall shield of a multicore thermocouple extension cable shall be grounded to the instrument circuit ground at the receiving instrument end.

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8.2.3.5 Thermocouple extension wire shall be terminated on terminal blocks. The number of intermediate terminations in a thermocouple loop should be minimized as much as practicable. As long as the terminal block is at a constant temperature along its length and is of homogeneous material, the conducting terminal needs not be constructed of like thermocouple material.

8.3

Resistance Temperature Detector (RTD) Instruments

8.3.1 RTD Selection

8.3.1.1 Resistance temperature detectors (RTDs) shall be used when

greater accuracy is required than is possible through the use of thermocouples.

Note: RTDs are preferred over thermocouples for most temperature sensing applications within Saudi Aramco. RTDs may be used for measuring temperatures up to approximately 650°C (1200°F). Above this temperature, thermocouples should be used.

8.3.1.2 Platinum RTDs conforming to IEC 60751, with an alpha

coefficient of 0.00385 ohm/ohm/°C and tolerance Class A shall be used. Resistance shall be 100 ohms at 0°C.

8.3.2 RTD Design and Installation

8.3.2.1 RTDs shall be insulated with packed magnesium oxide and

protected with a ¼-inch o.d., 316 stainless steel sheath. Alternative sheath metallurgy may be used if required by process conditions.

8.3.2.2 Three-wire RTDs shall be used to eliminate lead wire resistance

effects from the temperature measurement. For temperature measurement requiring maximum accuracy, four-wire RTDs shall be used.

8.3.2.3 RTDs shall be installed in thermowells such that the end of the RTD is in contact with the bottom of the thermowell. Spring-loaded RTDs are preferred to ensure positive contact with the thermowell.

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8.3.2.4 Dual element RTDs are permitted when their intended function is to provide a spare RTD element for a single receiving instrument. A dual element RTD shall not be used to provide separate signals to different instruments or redundant inputs to a logic control system.

8.3.2.5 Extension wire for RTD signals shall consist of shielded,

twisted triad copper conductors meeting the requirements of 34-SAMSS-913. Wiring shall be installed in accordance with SAES-J-902.

8.3.2.6 The extension wire shield drain wire shall be grounded at the

receiving instrument end to the instrument circuit ground. The continuity of the shield shall be maintained through junction boxes and transitions from single pair to multipair cables. The shield and drain wire shall be cut and secured (insulated) at the RTD end of the extension wire.

8.3.2.7 The overall shield of a multicore RTD extension cable shall be

grounded to the instrument circuit ground at the receiving instrument end.

8.3.2.8 Due to expected high vibration, RTDs shall not be used on the

discharge flange of a gas compressor.

8.4

Bimetallic Thermometers

8.4.1 Bimetallic dial thermometers shall be used wherever local temperature

indication is required.

8.4.2 Thermometers shall have a ¼-inch O.D., 316 stainless steel stem.

Alternative stem metallurgy may be used if required by process conditions.

8.4.3 Thermometers shall be installed in thermowells.

8.4.4 The thermometer stem shall be in contact with the bottom of the

thermowell.

8.4.5 Dial size shall be 127 mm (5 in). The angle of view and orientation of

the dial shall be adjustable. The dial shall be readable from grade, platform, or permanent ladder and shall face the point where any corrective action will be taken.

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8.4.6 When subject to vibration, thermometers shall be sealed and filled with

silicone oil.

8.5

Filled System Instruments

8.5.1 Filled System Selection

8.5.1.1 Filled system temperature sensing instruments shall be used

only for noncritical, local indication, where precise temperature control is not necessary.

Note: Due to the lower accuracy and repeatability associated with filled systems compared to thermocouple or RTD-based sensors, as well as the distance limits dictated by capillary length, filled systems should be limited to local control or indication.

8.5.1.2 The fill fluid may be either liquid or gas, depending on the temperature range of the process being measured.

8.5.1.3 Filled system temperature instruments shall always be provided

with a matching thermowell. The thermowell shall comply with this standard.

Note: Since there is no standard bulb diameter among different manufacturers, it is essential that a thermowell matched to the specific instrument be provided by the instrument manufacturer.

8.5.2 Thermometers

8.5.2.1 Filled system thermometers shall be used only when access,

process conditions, or mechanical considerations preclude the use of bimetallic thermometers.

8.5.2.2 Thermometers shall have uniform dial graduations.

Note: Depending on the fill fluid, dial graduations may be non-uniform, with the scale compressed at the lower end of the scale, or uniform, with equal scale graduations around the dial. For most applications, thermometers with uniform dial graduations are available.

8.5.2.3 Mercury-filled thermometers shall not be used.

8.6

Electronics

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8.6.1 Temperature elements shall not be connected to more than one receiving

instrument.

8.6.2 Transmitters

8.6.2.1 Transmitters shall provide burnout detection. The direction of the readout or output signal on thermocouple burnout shall be selectable.

8.6.2.2 Transmitters shall provide input and output signal isolation, cold junction compensation, linearization/characterization, ambient temperature compensation, and adjustable damping.

8.6.2.3 Transmitters shall be mounted remotely from the

element/thermowell assembly.

8.6.2.4 A local temperature indicator shall be provided for each

transmitter. The local indicator may be an integral part of the transmitter or a separate device, but must be readable from grade, platform, or permanent ladder.

8.6.3 Switches

8.6.3.1 Electric switch contacts shall be snap-acting, single-pole, and

double-throw (SPDT), The switch mechanism shall be user- selectable to activate on increasing or decreasing temperature.

8.6.3.2 The switch shall provide cold junction compensation for

thermocouples.

8.6.4 Multipoint Indicators and Multiplexers

8.6.4.1 Multipoint temperature indicators shall consist of a panel-

mounted readout and a means of selecting the desired element to display.

8.6.4.2 Multiplexers shall take the signals from a number of elements

as inputs and provide an output to a logic control system (DCS, PLC, etc.).

8.6.4.3 Multipoint indicators and multiplexers shall provide

linearization, cold junction compensation, and scaling of the element input signals.

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8.6.4.4 Signals from multipoint indicators or multiplexers shall not be

used for control.

8.6.4.5 A maximum of 100 inputs (including spares) shall be permitted

per multipoint indicator or multiplexer. Recommended spare capacity is 25% of the number of occupied inputs.

Revision Summary

06 October 2020 04 August 2019 08 May 2019 1 January 2018 12 October 2017

16 June 2016

Majore revision Editorial revision to remove RVL reference Editorial revision to comply with content confirmation Editorial revision to modify paragraphs 8.1.2.7, 8.2.2.1, 8.3.2.1, and 8.4.2. Major revision mainly to allow a single probe GWR for Automatic Tank Gauging (ATG) system. Major revision has been carried out as part of the optimization initiative for Instrumentation MSAERs.

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Appendix 1 - Minimum Straight Run Lengths for Orifice Plates without Flow Conditioners in Accordance with ISO 5167-2

NOTES:

 S is the separation between the two bends measured from the downstream end of the curved portion of the upstream

bend to the upstream end of the curved portion of the downstream bend.

 Column A is for lengths corresponding to “zero additional uncertainty” values intended for high accuracy meters.

 Column B is for lengths corresponding to “0,5% additional uncertainty” values intended for control and monitoring.

 For additional information refer to ISO-5167-2 for Orifice Plates.

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Saudi Aramco: Company General Use

Document Responsibility: Instrumentation Standards Committee Issue Date: 06 October 2020 Next Planned Update: 06 October 2025

SAES-J-100

Process Measurement

Appendix 2 - Minimum Straight Run Lengths for Classical Venturis in Accordance with ISO 5167-4

NOTES:

 Downstream straight lengths is 4D for zero additional uncertainty and 2D of 0,5% additional uncertainty



a The radius of curvature of the bend shall be greater than or equal to the pipe diameter.

b Column A for lengths corresponding to “zero additional uncertainty” values.

c Column B for lengths corresponding to “0,5 % additional uncertainty” values.

d The straight length in Column A gives zero additional uncertainty; data are not available for shorter straight lengths

which could be used to give the required straight lengths for Column B.

Saudi Aramco: Company General Use

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Saudi Aramco: Company General Use

Project: Q-31108 - Tecnicas - Riyas Folder: RFQ Files

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