Section 12 — Instruments and Controls

Instrumentation for Above Ground Storage Tanks

IPE Engineering Practice IPE-EP-12-9-1

Document number: IPE-EP-12-9-1 · Section: 12 — Instruments and Controls

SCOPE

• This Practice defines the general requirements for the design, selection and installation of storage tank measurement equipment for liquid level and temperature.
• Use and installation of instrumentation on above ground storage tanks shall conform to the appropriate sections of EP 12–1–1, Control Systems.
• Any deviation from this Practice must be approved by the procedure described in EP 1–1–3.

2.0 REFERENCES

The latest edition of the following standards and publications are referenced herein, and shall be used with this Practice.

STANDARDS AND PUBLICATIONS

DEFINITIONS

• Contractor - Company or business that agrees to furnish materials or perform specified services at a specified price and/or rate to the Owner.
• Inspector - A Inflection Point Engineering, LLC appointed engineer or inspector.
• Manufacturer - The recipient of a direct or indirect purchase order for materials and/or equipment. In this context, a direct order is one issued to a manufacturer by a contractor or the Owner. An indirect order is one issued to a manufacturer by a vendor (recipient of a direct order) for materials, fabricated components, or subassemblies.
• Owner - Inflection Point Engineering, LLC.
• Owner’s Engineer - A Inflection Point Engineering, LLC appointed engineer.
• Purchaser - The party placing a direct purchase order. The purchaser is the Owner’s designated representative.

CATEGORIZATION OF TANK MEASUREMENT EQUIPMENT

• General Requirements
• Equipment for gauging the contents of storage tanks will be specified by IPE depending upon the purpose of its application and the required accuracy of measurement.
• Although fitness for purpose will be the primary criterion in specifying equipment standards, two general performance types have been established.
• Type 1: Fiscal or commercial custody transfer measurements.
• Type 2: General tank content monitoring and control.
• Type 1 Application
• Type 1 is the most stringent application requiring the highest standards of accuracy and reliability.
• The calibration of Type 1 gauges used for fiscal or custody transfer tank measurements will need to be regularly checked against manual tank dip measurements. The calibration of tank level and temperature instruments shall be in accordance with the API Manual of Petroleum Measurement Standards Chapter 3 - Tank Gauging and API 2545.
• Generally, only equipment from a limited range of equipment types will be capable of satisfying Type 1 accuracy and reliability standards.
• Type 2 Application

Type 2 gauges are suitable for general tank content monitoring and level control and may normally be of a lower accuracy standard. Although reliability is still a prerequisite for Type 2 equipment, the requirement for accuracy is reduced to a level compatible with the practical needs of the application. Calibration checks will not generally be required on a routine basis but will be carried out on suspicion of malfunction or high error. The calibration of Type 2 instruments should be in accordance with the principles of the API Manual of Petroleum Measurement Standards Chapter 3 - Tank Gauging and API 2545.

• Environment

All tank gauging equipment, regardless of type, shall be suitable for the environment in which it is to be installed and maintained.

TYPE 1 TANK GAUGING EQUIPMENT

• General Requirements
• Electrically powered servo–operated tank gauges with a surface sensor should be used for Type 1 applications. Alternative gauge types designed to detect tank levels using one of the following principles of operation may be used for Type 1 use, where independent evidence can be provided for satisfactory operation in an application similar to that of their intended use. Alternative gauge types shall be approved by the Owner’s Engineer:
• microwave
• radar,
• laser,
• ultrasonic,

• capacitance, or
• hydrostatic head (for mass).
• Ancillary Equipment

In addition to the level measurement device itself, tank gauging systems for Type 1 measurement shall include the following ancillary equipment:

• Tank content temperature sensing equipment.
• A data transmission system for level and temperature readings connecting with remote, microprocessor based data handling and readout equipment (see Paragraph 5.5 of this Practice).
• Local indication of tank level, and if specified, temperature.
• The gauge shall be capable of measuring density, or receiving an analog input from a densitometer, or calculating density from a differential pressure transmitter. The gauge shall be capable of providing a local and remote density display.
• The gauge shall have the ability to input up to 2 local switch inputs and transmit the switch status data over the transmission system.
• The gauge shall have the ability to control 2 relay outputs.
• Performance
• The accuracy and repeatability of Type 1 tank gauging systems shall conform with the requirements of IPE Petroleum Measurement Manual and IPE Crude Oil Measurement Manual and with the standards of any other interested parties, e.g., the fiscal authorities.
• Accuracy shall be +.1 inch to -.1 inch for automatic tank gauges, when compared with reference manual tank readings. Manual tank readings shall be in accordance with the IPE Crude Oil Measurement Manual and Petroleum Products Measurement Manual.
• The dynamic performance of Type 1 level gauges shall be adequate to follow, without loss of accuracy, the most severe rate of level changes (filling and emptying) which will be experienced in the application.
• Repeatability shall be +.0625 inch to -.0625 inch for automatic tank gauges.
• Type 1 gauge systems shall be of the highest reliability and shall be simple to install, operate and maintain.
• Temperature Measurement
• Temperature measurement in Type 1 systems shall be by averaging resistance thermometers, generally as recommended in API 2543 (ASTM D1086-64) Appendix 1. The temperature measurement accuracy shall be within +1.0 F to -1.0 F.
• For fixed roof tanks multi–element resistance thermometer assemblies or three point, (top, middle and bottom), resistance thermometer systems, may be used. The material of the sheath shall be immune to corrosion or other damage caused by contact with the tank liquid.

• For floating roof tanks a three point (top, middle and bottom) resistance thermometer system should be used. The material of the sheath shall be immune to corrosion or other damage caused by contact with the tank liquid.
• Resistance thermometer elements shall comply with EP 12–1–6, Primary Temperature Elements Assemblies.
• When a multi–element temperature measurement system is used, the longest totally immersed element shall be selected automatically by the level sensing equipment. The facility for override of the element selector switch shall be available in the remote location.
• A local temperature indicator, either operating directly from a separate in–tank spot temperature sensor or from the remote temperature indication transmission system shall be provided. Separate spot temperature sensors shall be positioned at least 18 inches in from the tank shell.
• Data Transmission and Remote Indication
• Type 1 tank gauging systems shall be used in association with readout equipment sited at an operator location. The readout equipment shall be microprocessor based with VDU screen displays of information and with data logging/printout facilities. The capability for a high resolution data link to other computer and microprocessor based systems shall be provided; for example, distributed control systems (DCS), refinery information systems (RIS), or management information systems. If a Distributed Control system is at the operator location, the VDU and data logging/printout facilities shall be provided by the DCS.
• In special cases, usually involving a small number of tanks and where it is economically advantageous, individual indication/readout facilities for each tank may be proposed, subject to approval by the Owner’s Engineer.
• Data transmission systems shall be protected from and shall be immune to interference or hazard from lightning strikes or other electrical transients and surges.
• Local Indication
• Where the requirement for local indication of tank level or temperature is specified, the indicators shall be located so as to be clearly visible from appropriate local control points, e.g., filling or draining valves, or steam heater control valves.
• The signals for local level indicators, may be taken from the data transmission circuits supplied for the remote indication system - provided that the additional loading does not prejudice the fidelity of the remote readout.

TYPE 2 TANK GAUGING EQUIPMENT

• General Requirements
• Because the requirements for level measurement quality, in terms of accuracy and repeatability, are normally lower for general tank content monitoring and control than for fiscal or custody transfer purposes, a wider and more economic range of gauge types may be acceptable for Type 2 Systems. However, reliability of measurement remains equally important, as does simplicity of installation, operation and maintenance.
• In addition to the types of tank gauge listed in 5.1, the following gauges may also be suitable for Type 2 application:

• Float type gauges (non–servo) and gauge boards.
• Hydrostatic head gauges (using continuous air or nitrogen purge) with the purge supply protected by a constant differential relay.

Note: This gauge type is not acceptable for critical application such as overfill or low level alarm systems.

• Nucleonic beam gauges, (suitable for difficult application e.g., bitumen storage).
• Performance
• The accuracy and repeatability of Type 2 tank gauging systems shall conform with the requirements of IPE Petroleum Measurement Manual and IPE Crude Oil Measurement Manual.
• Accuracy shall be +1 inch to -1 inch for tank gauges, when compared with reference manual tank readings. Manual tank readings shall be in accordance with the IPE Crude Oil Measurement Manual and Petroleum Products Measurement Manual.
• The dynamic performance of Type 2 level gauges shall be adequate to follow, without loss of accuracy, the most severe rate of level changes (filling and emptying) which will be experienced in the application.

TANK GAUGING OF LNG AND LPG

• Tank gauges fitted on high pressure tanks containing LNG and LPG shall conform with the recommendations for Type 1 gauging.
• For volatile fluids such as LPG or LNG, where measurement is required of the total volumetric or mass contents, accurate measurement shall be made of the temperature and pressure of the vapor phase in addition to that of the liquid. The value of these variables shall be recorded separately for later calculation of the total fluid contents.
• In addition to the primary gauge fitted for the accurate measurement of tank level, a secondary gauge shall be installed for alarm purposes. Gauging system for type 2 can be used for this secondary gauge. Independent transmission/wiring for the level signal to the remote control point shall be provided.

GAUGING OF REFRIGERATED LNG AND LPG

• Level gauging and temperature measuring equipment for refrigerated storage tanks shall comply with the recommendations of Type 1.
• Electrical powered servo–operated gauges shall be installed for Type 1 applications. Tapes shall be of a material with a low coefficient of thermal expansion.
• Temperature measurement shall be made of the liquid in the tank and in the vapor space above the liquid. Temperature measurement shall be by 3 or 4 wire platinum resistance thermometer (100 ohm). Alternatively copper/copper–nickel thermocouples may be proposed, subject to approval by the Owner’s Engineer.
• Pressure measurement of the vapor space in the tank shall be made.

• Density measurement; if specified, shall be by non–intrusive nucleonic densitometer (gamma– ray type). Alternative methods of density measurement may be proposed, e.g., vibrating element, ultrasonic or capacitive, subject to approval by the Owner’s Engineer.

ALARMS AND TRIPS

• General Requirements
• Measurement signals produced by level and temperature gauges on storage tanks may be used to operate alarm and trip circuits.
• Protection is required against the following circumstances:
• Tank overfill: by high level alarm
• Floating roof or mixer damage:
• by low level alarm
• by mixer motor trip
• Tank overheat or water bottoms boil over:
• by low level alarm
• by high temperature alarm
• by steam valve control
• Other events, e.g., excess rate of level change, alarm or control; as specified by the Owner’s Engineer.
• Level Alarms

Alarms shall be generated whenever preset high and low level points are reached. They may be initiated by any of the following methods:

• Where tank levels are scanned; by automatic checking of level readings against alarm set points.
• By electric switch in the gauge head.
• By externally mounted float type level switch.
• Alternative methods, e.g., by position switch on floating roofs, may only be used subject to approval by the Owner’s Engineer.
• Level Trips

All shutdowns shall be initiated by level sensors independent of any alarm switch or transmission system associated with normal level indication or monitoring duties.

• Temperature Alarms

Alarms shall be generated whenever preset high or low temperature set–points are reached. They may be initiated by any of the following methods:

• Where tank temperatures are scanned; by automatic checking of temperature readings against alarm set points.
• By individual electronic thermal trip units connected to the temperature transmission circuits, subject to approval by the Owner’s Engineer.
• By filled system temperature switch with armored capillary with the sensing element enclosed within a thermowell, subject to approval by the Owner’s Engineer.

9.5 Temperature Trips

Temperature shutdown, if required, shall operate from temperature sensors independent of alarm switches or transmission associated with normal temperature indication. On heated tanks the temperature sensor shall be mounted at least 6 inches but no more than 30 inches above the steam coils and the trip linked with the steam shut off valve.

INSTALLATION OF AUTOMATIC TANK GAUGING EQUIPMENT

• General Requirements

The installation of automatic tank gauging and temperature measuring equipment shall be in accordance with the recommendations of the manufacturer. Electrical design and installation shall be in accordance with EP 13–2–1.

• For Type 1 Gauge Systems
• Type 1 electrically powered servo–operated tank gauges used on vertical cylindrical tanks shall be mounted on top of a support pipe which may also be used as a still pipe for the surface sensor. The support pipe shall be installed per EP 9–1–4.
• The internal diameter and uniformity of support pipes for radar type gauges shall conform with the manufacturers recommendation.
• Alternative gauge types operating on a principle unsuited to support pipe mounting shall be mounted according to the manufacturer’s instructions, particularly with regard to the distance from the tank wall and the still pipe diameter. In any case, the mounting shall be such that the gauge accuracy is unaffected by any distortion of the tank shell. The mounting method shall be subject to approval by the Owner’s Engineer.
• A separate still pipe shall be provided for manual dipping/sampling.
• Still pipes, or support pipes where they are used as still pipes, shall be perforated with holes/slots in accordance with EP 9–1–4.
• The automatic tank gauge head, with a float inspection chamber, shall be mounted in proximity to the manual dip/sampling hatch and be accessible from the gauger’s platform. Whereover possible this should be situated on the shaded side of the tank and remote from disturbances from inlet/outlet pipes and the effects of mixers.
• The size of sample and dip hatches shall be as specified in EP 9–1–4.
• To facilitate maintenance both power and signal cables shall be capable of isolation from the gauge by provision of a switch mounted adjacent to the gauge head.
• For Type 2 Gauge Systems
• Electrically powered servo–operated gauges and mechanically operated gauges for Type 2 applications, shall be mounted in accordance with manufacturers recommendations. Tank shell mounted gauge heads shall be fixed at a height no greater than 5 feet above tank base level.

The mounting arrangements for other Type 2 type gauges shall be in accordance with the manufacturers recommendations.

• The installation arrangements for still pipes for manual dips and sampling, where provided, shall be as for Type 1 applications.

• Temperature Measurement Equipment
• For Type 1 applications multiple element resistance thermometers should be installed within a thermowell pipe situated on the shaded side of the tank and at a minimum distance of 18 inches from the tank wall.
• Type 1 three point resistance thermometers shall be installed through roof manholes and located as in EP 9–4–1. The top and bottom elements shall be located within the liquid, 12 inches from the surface, and the tank bottom respectively.
• Spot thermometers shall be mounted at a height of 30 inches from the tank bottom with the element 18 inches from the tank shell.
• For High Pressure Tanks (Horizontal)
• The installation of gauges and thermometers on high pressure tanks shall comply with the requirements of the manufacturer.
• For Type 1 applications, electrically powered servo–gauges shall be mounted on the inspection hatch, with the surface sensor within a still pipe.
• The inspection chamber shall be capable of isolation from the tank contents by a double block valve with bleed. The inspection chamber shall be fitted with a vent valve.
• Type 2 gauges may be mounted on a tank support.
• For Refrigerated Tanks
• The installation of gauges and thermometers on refrigerated tanks shall comply with the requirements of the manufacturer.
• For Type 1 applications, electrical power servo–gauges shall be rigidly mounted in relation to the tank wall or other datum, with the surface detecting element within a still pipe.
• On refrigerated spherical tanks the gauge shall be mounted on the pipe tower, with the gauge reference point on an imaginary vertical axis projecting through the south pole of the tank.
• The installation shall be such the surface sensor can be removed from the tank for inspection without leakage of vapor or product.

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