-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

PROPERTY OF PETROBRAS 74 pages, Index of Revisions and WG

Criteria for Development of Instrumentation Designs

Procedure

This Standard replaces and cancels its previous revision.

The CONTEC - Authoring Subcommittee provides guidance on the interpretation of this Standard when questions arise regarding its contents. The Department of PETROBRAS that uses this Standard is responsible for adopting and applying the sections, subsections and enumerates thereof.

CONTEC Comisso de Normalizao

Tcnica

Technical Requirement: A provision established as the most adequate and which shall be used strictly in accordance with this Standard. If a decision is taken not to follow the requirement (non-conformity to this Standard) it shall be based on well-founded economic and management reasons, and be approved and registered by the Department of PETROBRAS that uses this Standard. It is characterized by imperative nature.

Recommended Practice: A provision that may be adopted under the conditions of this Standard, but which admits (and draws attention to) the possibility of there being a more adequate alternative (not written in this Standard) to the particular application. The alternative adopted shall be approved and registered by the Department of PETROBRAS that uses this Standard. It is characterized by verbs of a nonmandatory nature. It is indicated by the expression: [Recommended Practice].

SC - 10

Copies of the registered non-conformities to this Standard that may contribute to the improvement thereof shall be submitted to the CONTEC - Authoring Subcommittee.

Proposed revisions to this Standard shall be submitted to the CONTEC - Authoring Subcommittee, indicating the alphanumeric identification and revision of the Standard, the section, subsection and enumerate to be revised, the proposed text, and technical/economic justification for revision. The proposals are evaluated during the work for alteration of this Standard.

Instrumentation and Industrial Automation

The present Standard is the exclusive property of PETRLEO BRASILEIRO S.A. - PETROBRAS, for internal use in the Company, and any reproduction for external use or disclosure, without previous and express authorization from the owner, will imply an unlawful act pursuant to the relevant legislation through which the applicable responsibilities shall be imputed. External circulation shall be regulated by a specific clause of Secrecy and Confidentiality pursuant to the terms of intellectual and industrial property law.

Introduction

PETROBRAS Technical Standards are prepared by Working Groups - WG (consisting specialized of Technical Collaborators from Company and its Subsidiaries), are commented by Company Units and its Subsidiaries, are approved by the Authoring Subcommittees - SCs (consisting of technicians from the same specialty, representing the various Company Units and its Subsidiaries), and ratified by the Executive Nucleus (consisting of representatives of the Company Units and its Subsidiaries). A PETROBRAS Technical Standard is subject to revision at any time by its Authoring Subcommittee and shall be reviewed every 5 years to be revalidated, revised or cancelled. PETROBRAS Technical Standards are prepared in accordance with PETROBRAS Technical Standard N-1. For complete information about PETROBRAS Technical Standards see PETROBRAS Technical Standards Catalog.

.

erctProjeto-P

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

2

Summary Foreword.................................................................................................................................................. 8

1 Scope................................................................................................................................................... 8

2 Normative References......................................................................................................................... 8

3 Terms and Definitions......................................................................................................................... 13

4 Symbols or Abbreviations.................................................................................................................. 15

5 Documentation, Engineering Units, Symbology and Identification.................................................... 16

5.1 Design Documentation......................................................................................................... 16

5.2 Engineering Units ................................................................................................................. 16

5.3 Symbology and Instrument Identification .............................................................................. 16

6 Supervision, Control and Safety Systems ......................................................................................... 17

6.1 General................................................................................................................................. 17

6.2 Alarm System....................................................................................................................... 17

6.3 Safety Instrumented System................................................................................................ 17

6.4 Fire Alarm and Detection Systems....................................................................................... 17

7 Control Room .................................................................................................................................... 17

7.1 General................................................................................................................................. 17

7.2 Air Conditioning and Pressurization..................................................................................... 18

7.3 Equipment and Panel Arrangement ...................................................................................... 19

7.4 Electrical Installation.............................................................................................................. 19

7.5 Grounding.............................................................................................................................. 19

8 Instrumentation Power System........................................................................................................... 19

8.1 Pneumatic Systems............................................................................................................... 19

8.1.1 Instrument Air Generation............................................................................................. 19

8.1.2 Instrument Air Distribution............................................................................................. 20

8.2 Electrical Systems................................................................................................................. 20

8.3 Hydraulic Systems................................................................................................................. 21

9 Selection and Specification of Instruments ....................................................................................... 22

9.1 General.................................................................................................................................. 22

9.2 Temperature Instruments...................................................................................................... 24

9.2.1 Selection and Specification Criteria .............................................................................. 24

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

3

9.2.2 Thermometers............................................................................................................... 24

9.2.3 Thermocouples and Resistance Temperature Devices (RTD)..................................... 25

9.2.4 Transmitters .................................................................................................................. 25

9.2.5 Thermostats .................................................................................................................. 26

9.2.6 Wells for Temperature Measurement Elements ........................................................... 26

9.3 Pressure Instruments ............................................................................................................ 27

9.3.1 Selection and Specification Criteria .............................................................................. 27

9.3.2 Manometers .................................................................................................................. 27

9.3.3 Transmitters .................................................................................................................. 27

9.3.4 Pressure Switches ........................................................................................................ 28

9.3.5 Accessories for Pressure Instruments .......................................................................... 28

9.4 Flow Rate Instruments .......................................................................................................... 28

9.4.1 Selection Criteria........................................................................................................... 28

9.4.2 Orifice Plate Meters....................................................................................................... 29

9.4.3 Vortex Type Meters....................................................................................................... 30

9.4.4 Venturi, Flow Nozzles, Pitot and V-Cone Meters.......................................................... 31

9.4.4.1 Venturi................................................................................................................... 31

9.4.4.2 Flow Nozzles......................................................................................................... 31

9.4.4.3 Averaging Pitot Tubes........................................................................................... 31

9.4.4.4 V-Cone.................................................................................................................. 31

9.4.5 Restriction Orifices ........................................................................................................ 32

9.4.6 Ultrasonic Flow Meters.................................................................................................. 32

9.4.7 Coriolis Flow Meters...................................................................................................... 32

9.4.8 Variable Area Meters (Rotameters) .............................................................................. 33

9.4.9 Positive Displacement Meters....................................................................................... 33

9.4.10 Turbine Type Meters ................................................................................................... 33

9.4.11 Electromagnetic type Meters ...................................................................................... 34

9.4.12 Transmitters ................................................................................................................ 34

9.4.13 Flow Switches ............................................................................................................. 34

9.5 Level Measurement Instruments........................................................................................... 34

9.5.1 Selection and Specification Criteria .............................................................................. 34

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

4

9.5.2 Gauge Glasses ............................................................................................................. 35

9.5.3 Magnetic Level Gauge .................................................................................................. 36

9.5.4 Differential Pressure Level Meter.................................................................................. 36

9.5.5 Guided Wave Radar Meter ........................................................................................... 37

9.5.6 Contactless Radar Meter .............................................................................................. 38

9.5.7 Ultrasonic Meter ............................................................................................................ 38

9.5.8 Displacer Type Measurement ....................................................................................... 38

9.5.9 Capacitive Type Transmitter ......................................................................................... 38

9.5.10 Level Switches ............................................................................................................ 39

9.5.11 Level Measurement in Storage Tanks (Telemetering)................................................ 39

9.6 Control Valves ....................................................................................................................... 39

9.6.1 Selection ....................................................................................................................... 39

9.6.2 Sizing............................................................................................................................. 40

9.6.3 Inherent Flow Rate Characteristics............................................................................... 42

9.6.4 Constructive Characteristics ......................................................................................... 42

9.6.5 Actuators ....................................................................................................................... 43

9.6.6 Positioners .................................................................................................................... 43

9.6.7 Accessories................................................................................................................... 44

9.7 On-off Valves......................................................................................................................... 44

9.7.1 General ......................................................................................................................... 44

9.7.2 Valve ............................................................................................................................. 44

9.7.3 Actuators ....................................................................................................................... 45

9.7.4 Accessories................................................................................................................... 45

9.7.4.1 General ................................................................................................................. 45

9.7.4.2 Solenoid Valve ...................................................................................................... 46

9.7.4.3 Position Switch...................................................................................................... 46

9.7.4.4 Regulating Filter Valve.......................................................................................... 46

9.8 Relief and Safety Valves ....................................................................................................... 47

9.8.1 Selection and Sizing...................................................................................................... 47

9.8.2 General Characteristics................................................................................................. 48

9.8.3 Technical Requirements ............................................................................................... 48

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

5

9.8.4 Accessories................................................................................................................... 49

9.9 Pressure and Vacuum Relief Valves..................................................................................... 49

9.10 Rupture Discs...................................................................................................................... 49

9.11 Process Analyzers............................................................................................................... 49

9.12 Flame Sensors .................................................................................................................... 49

9.13 Fire and Gas Detectors ....................................................................................................... 50

9.13.1 General ....................................................................................................................... 50

9.13.2 Gas Detectors ............................................................................................................. 50

9.13.2.1 Hydrocarbon Detectors ....................................................................................... 50

9.13.2.2 Hydrogen Detectors (H2)..................................................................................... 51

9.13.2.3 Toxic gas Detectors - Hydrogen Sulfide (H2S) and Ammonia (NH3) .................. 51

9.13.3 Fire Detectors.............................................................................................................. 51

9.13.3.1 Smoke Detectors ................................................................................................ 51

9.13.3.2 Flame Detectors.................................................................................................. 52

9.13.3.3 Heat Detectors .................................................................................................... 52

9.13.3.4 Manual Fire Alarm Starters ................................................................................. 52

10 Specification of Instrumentation Cables ........................................................................................... 52

10.1 Electric Instrumentation Cables for Use on Onshore Facilities........................................... 52

10.1.1 General ....................................................................................................................... 52

10.1.2 Cables for Analog and Discrete Signals ..................................................................... 52

10.1.3 Cables for Thermocouple Signals............................................................................... 53

10.1.4 Cables for Intrinsic Safety Signals .............................................................................. 53

10.1.5 Cables for Special Signals .......................................................................................... 54

10.1.6 Cables for Serial and Network Communication .......................................................... 54

10.1.6.1 RS-485 Cables using Modbus Protocol.............................................................. 54

10.1.6.2 Cables for Foundation FieldBus ......................................................................... 55

10.1.6.3 RS-485 Cables Using Protocol ProfiBus/DP ...................................................... 55

10.2 Electrical Instrumentation Cables for use in Offshore Facilities.......................................... 55

10.2.1 Service Conditions ...................................................................................................... 55

10.2.2 Constructive Characteristics ....................................................................................... 55

10.2.3 Identification ................................................................................................................ 57

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

6

10.2.4 Tests............................................................................................................................ 57

10.3 Optical Instrumentation Cables for Use on Onshore and/or Offshore Facilities ................. 57

11 Instrumentation Panel Specification ................................................................................................. 58

11.1 Constructive Requirements................................................................................................. 58

11.2 Requirements for Internal Connection of the Components................................................. 59

11.3 Requirements for Internal Components .............................................................................. 59

12 Instrumentation Specification in Package Units ............................................................................... 60

13 Instrument Installation Design .......................................................................................................... 60

13.1 General................................................................................................................................ 60

13.2 Accessibility and Visibility.................................................................................................... 61

13.3 Pneumatic Power for Instruments ....................................................................................... 61

13.4 Temperature Instrument Installation ................................................................................... 61

13.5 Pressure Instrument Installation.......................................................................................... 61

13.6 Flow Instrument Installation ................................................................................................ 61

13.7 Level Instrument Installation ............................................................................................... 62

13.8 Control Valve Installation .................................................................................................... 63

13.9 Safety and Relief Valve Installation..................................................................................... 63

13.10 Installation of Flame Sensors in Burners .......................................................................... 63

14 Signal Transmission Installation Design........................................................................................... 63

14.1 General................................................................................................................................ 63

14.2 Cable Forwarding and Routing ........................................................................................... 64

14.3 Wiring and Connection........................................................................................................ 65

14.4 Grounding and Protection against Electrical and Electromagnetic Interference ................ 65

Appendix A - Probable Total Error Calculation...................................................................................... 66

Appendix B - Wells and Stem Dimension.............................................................................................. 71

Appendix C - Restriction Orifice Dimensioning on Isentropic Critical Flow Regime for Real Gas ........ 75

Appendix D - Restriction Orifice Thickness Calculation ........................................................................ 76

Appendix E - Process Connections....................................................................................................... 77

Figures

Figure B.1 - Flanged Installation on Piping ........................................................................................... 73

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

7

Figure B.2 - Threaded Installation on Piping ......................................................................................... 73

Tables

Table 1 - Line Nominal Diameter versus Plate Thickness .................................................................... 30

Table 2 - Speed Limits at Control Valve Entrance ................................................................................ 42

Table 3 - Protection Degree .................................................................................................................. 58

Table B.1 - Insertion Length (U) for Flanged Wells Installed on Piping.............................................. 71

Table B.2 - Insertion Length (U) for Threaded Wells Installed on Piping ........................................... 71

Table B.3 - Stem Length (L) for Flanged Wells Installed on Piping.................................................... 72

Table B.4 - Stem Length (L) for Threaded Wells Installed on Piping ................................................. 72

Table B.5 - Immersion Length for Flanged Wells Installed on Vessels or Towers................................ 74

Table C.1 - Restriction Orifice Dimensioning on Isentropic Critical Flow Regime for Real Gas ........... 75

Table E.1 - Process Taps for Flow Rate Instrumentation ..................................................................... 77

Table E.2 - Process Taps for Pressure Instrumentation ....................................................................... 77

Table E.3 - Process Taps for Level Instrumentation ............................................................................. 78

Table E.4 - Process Taps for Temperature Instrumentation ................................................................. 78

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

8

Foreword This Standard is the English version (issued in 01/2012) of PETROBRAS N-1882 REV. D 02/2011, including its Erratum - 04/2011 and Amendment - 01/2012. In case of doubt, the Portuguese version, which is the valid document for all intents and purposes, shall be used. 1 Scope 1.1 This Standard establishes basic criteria for the development of instrumentation designs for industrial plants. Any other criteria that have not been mentioned by this standard, or that could complement those defined herein, shall be prescribed in additional documentation in order to encompass any specific needs of each project. 1.2 This Standard applies to:

a) processing units; b) terminals; c) oil and gas pipelines; d) production facilities; e) thermoelectric plants; f) other PETROBRAS facilities that might use the same type of instrumentation as the one

established in this Standard. 1.3 This Standard applies to instrumentation designs, initiated from the date of its publishing, for new facilities as well as for refit in existing facilities. 1.4 This Standard contains Technical Requirements and Recommended Practices. 2 Normative References The following referenced documents are indispensable for the application of this document. For dated references, only the edition cited applies. For undated references, the latest edition of the referenced document applies.

Norma Regulamentadora no 10 (NR-10) - Segurana em Instalaes e Servios em Eletricidade; Norma Regulamentadora no 13 (NR-13) - Caldeiras e Vasos de Presso; Norma Regulamentadora no 23 (NR-23) - Proteo Contra Incndios; Portaria INMETRO MDIC 179/2010 - Requisitos de Avaliao da Conformidade para Equipamentos Eltricos e Eletrnicos para Atmosferas Explosivas; Portaria INMETRO NIT DICLA 021 - Expresso da Incerteza de Medio; PETROBRAS N-57 - Projeto Mecnico de Tubulaes Industriais; PETROBRAS N-133 - Soldagem; PETROBRAS N-332 - Retificador para Uso Industrial; PETROBRAS N-1883 - Apresentao de Projeto de Instrumentao/Automao; PETROBRAS N-1996 - Projeto de Redes Eltricas em Envelopes de Concreto e com Cabos Diretamente no Solo; PETROBRAS N-1997 - Redes Eltricas em Sistemas de Bandejamento para Cabos - Projeto, Instalao e Inspeo;

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

9

PETROBRAS N-2595 - Critrios de Projeto, Operao e Manuteno de Sistemas Instrumentados de Segurana em Unidades Industriais; PETROBRAS N-2760 - Sistema Ininterrupto de Energia para Uso Industrial; PETROBRAS N-2791 - Detalhes de Instalao de Instrumentos ao Processo; PETROBRAS N-2900 - Gerenciamento de Alarmes; ABNT NBR 5410 - Instalaes Eltricas de Baixa Tenso; ABNT NBR 10300 - Cabos de Instrumentao com Isolao Extrudada de PE ou PVC para Tenses at 300 V; ABNT NBR 14105 - Manmetros com Sensor de Elementos Elstico - Recomendaes de Fabricao e Uso; ABNT NBR 17240 - Sistemas de Deteco e Alarme de Incndio - Projeto, Instalao, Comissionamento e Manuteno de Sistemas de Deteco e Alarme de Incndio; ABNT NBR IEC 60079-0 - Atmosferas Explosivas - Parte 0: Equipamentos; ABNT NBR IEC 60079-10-1 - Atmosferas Explosivas - Parte 10: Classificao de reas - Atmosferas Explosivas de Gs; ABNT NBR IEC 60079-14 - Atmosferas Explosivas - Parte 14: Projeto, Seleo e Montagem de Instalaes Eltricas; ABNT NBR IEC 60079-25 - Equipamentos Eltricos para Atmosferas Explosivas - Parte 25: Sistemas Intrinsecamente Seguros; ABNT NBR IEC 60529 - Graus de Proteo para Invlucros de Equipamentos Eltricos (Cdigo IP); ABNT NBR IEC 61241-10 - Equipamentos Eltricos para Uso na Presena de Poeiras Combustveis - Parte 10: Classificao de reas Onde Poeiras Combustveis Esto ou Podem Estar Presentes; ISO 4126-9 - Safety Devices for Protection against Excessive Pressure - Part 9: Application and Installation of Safety Devices Excluding Stand-Alone Bursting Disc Safety Devices; ISO 5167-1 - Measurement of Fluid Flow by Means of Pressure Differential Devices Inserted in Circular-Cross - Section Conduits Running Full - Part 1: General Principles and Requirements; ISO 5167-2 - Measurement of Fluid Flow by Means of Pressure Differential Devices Inserted in Circular-Cross - Section Conduits Running Full - Part 2: Orifice Plates; ISO 5167-3 - Measurement of Fluid Flow by Means of Pressure Differential Devices Inserted in Circular-Cross - Section Conduits Running Full - Part 3: Nozzles and Venture Nozzles; ISO 5167-4 - Measurement of Fluid Flow by Means of Pressure Differential Devices Inserted in Circular-Cross - Section Conduits Running Full - Part 4: Venturi Tubes; ISO 5208 - Industrial Valves - Pressure Testing of Metallic Valves; ISO 7240-2 - Fire Detection and Alarm System - Part 2: Control and Indicating Equipment; ISO 7240-5 - Fire Detection and Alarm System - Part 5: Point-Type Heat Detectors; ISO 7240-7 - Fire Detection and Alarm System - Part 7: Point-Type Smoke Detectors Using Scattered Light, Transmitted Light or Ionization; ISO 7240-10 - Fire Detection and Alarm System - Part 10: Point-Type Flame Detectors;

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

10

ISO 7240-11 - Fire Detection and Alarm System - Part 11: Manual Call Points; ISO 8573-1 - Compressed Air - Part 1: Contaminants and Purity Classes; ISO 10497 - Testing of Valves - Fire Type-Testing Requirements; ISO 10790 - Measurement of Fluid Flow in Closed Conduits - Guidance to the Selection, Installation and Use of Coriolis Meters (Mass Flow, Density and Volume Flow Measurements); ISO 16852 - Flame arresters - Performance Requirements, Test Methods and Limits for Use First Edition ISO 28300 - Petroleum, Petrochemical and Natural Gas Industries - Venting of Atmospheric and Low-Pressure Storage Tanks; ISO GUIDE 98-1 - Uncertainty of Measurement - Part 1: Introduction to the Expression of Uncertainty in Measurement; ISO GUIDE 98-3 - Uncertainty of Measurement - Part 3: Guide to the Expression of Uncertainty in Measurement (GUM:1995); ISO TR 12764 - Measurement of Fluid Flow in Closed Conduits - Flowrate Measurement by Means of Vortex Shedding Flowmeters Inserted in Circular Cross-Section Conduits Running Full; ISO TR 15377 - Measurement of Fluid Flow by Means of Pressure-Differential Devices - Guidelines for the Specification of Orifice Plates, Nozzles and Venturi Tubes beyond the Scope of ISO 5167; AGA REPORT 9 - Measurement of Gas by Multipath Ultrasonic Meters; API MPMS 3.1B - Manual of Petroleum Measurement Standards Chapter 3 - Tank Gauging Section 1B - Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging; API MPMS 3.3 - Manual of Petroleum Measurement Standards Chapter 3 - Tank Gauging Section 3 - Standard Pratice for Level Measurement of Liquid Hydrocarbons in Stationary Pressurized Storage Tank by Automatic Tank Gauging; API MPMS 4.1 - Manual of Petroleum Measurement Standards Chapter 4 - Proving Systems Section 1 - Introduction; API MPMS 4.5 - Manual of Petroleum Measurement Standards Chapter 4 - Proving Systems Section 5 - Master-Meter Provers; API MPMS 5.2 - Manual of Petroleum Measurement Standards Chapter 5 - Metering Section 2 - Measurement of Liquid Hydrocarbons by Displacement Meters; API MPMS 5.3 - Manual of Petroleum Measurement Standards Chapter 5 - Metering Section 3 - Measurement of Liquid Hydrocarbons by Turbine Meters; API MPMS 5.6 - Manual of Petroleum Measurement Standards Chapter 5 - Metering Section 6 - Measurement of Liquid Hydrocarbons by Coriolis Meters; API MPMS 5.8 - Manual of Petroleum Measurement Standards Chapter 5 - Metering Section 8 - Measurement of Liquid Hydrocarbons by Ultrasonic Flow Meters using Transit Time Technology; API MPMS 14.3.1 - Manual of Petroleum Measurement Standards Chapter 14 - Natural Gas Fluids Measurement Section 3 - Concentric, Square-Edge Orifice Meters Part 1 - General Equations and Uncertainty Guidelines;

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

11

API PUBL 2218:1999 - Fireproofing Practices in Petroleum and Petrochemical Processing Plants; API RP 520 Pt II - Sizing, Selection, and Installation of Pressure-Relieving Devices in Refineries - Part II - Installation; API RP 551:1993 - Process Measurement Instrumentation; API RP 552 - Transmission Systems; API RP 553 - Refinery Control Valves; API RP 554 Part 2 - Process Control Systems - Process Control System Design; API STD 520 Pt I - Sizing, Selection, and Installation of Pressure-Relieving Devices in Refineries - Part I - Sizing and Selection; API STD 526 - Flanged Steel Pressure Relief Valves; API STD 527 - Seat Tightness of Pressure Relief Valves; API STD 609 - Butterfly Valves: Double-Flanged, Lug- and Wafer-type; ASME B16.5 - Pipe Flanges and Flanged Fittings NPS 1/2 Through NPS 24 Metric/Inch Standard; ASME B16.10 - Face-to-Face and End-to-End Dimensions of Valves; ASME B16.36 - Orifice Flanges; ASME BPVC Section I - Boiler and Pressure Vessel Code - Section I: Rules for Constructions Power Boilers; ASME BPVC Section VIII Division 1 - Boiler and Pressure Vessel Code - Section VIII: Rules for Construction of Pressure Vessels; ASME BPVC Section VIII Division 2 - Boiler and Pressure Vessel Code - Section VIII: Rules for Construction of Pressure Vessels - Division 2: Alternative Rules; ASME BPVC Section VIII Division 3 - Boiler and Pressure Vessel Code - Section VIII: Rules for Construction of Pressure Vessels - Division 3: Alternative Rules for Construction of High Pressure Vessels; ASME MFC-12M - Measurement of Fluid Flow in Closed Conduits Using Multiport Averaging Pilot Primary Elements; ASME MFC-16 - Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flow meters; ASME MFC-18M - Measurement of Fluid Flow Using Variable Area Meters; ASME PTC 19.3 TW - Thermowells Performance Test Codes; IEC 60092-376 - Electrical Installations in Ships Part 376: Cables for Control and Instrumentation Circuits 150/250 V (300 V); IEC 60331-1 - Tests for Electric Cables under Fire Conditions - Circuit Integrity - Part 1: Test Method for Fire with Shock at a Temperature of at least 830 Degrees C for Cables of Rated Voltage up to and Including 0,6/1,0 kV and with an Overall Diameter Exceeding 20 mm; IEC 60331-11 - Tests for Electric Cables under Fire Conditions - Circuit Integrity - Part 11: Apparatus - Fire Alone at a Flame Temperature of at Least 750 Degree C;

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

12

IEC 60332-1-2 - Tests on Electric and Optical Fibre Cables under Fire Conditions - Part 1-2: Test for Vertical Flame Propagation for a Single Insulated Wire or Cable - Procedure for 1 kW Pre-Mixed Flame; IEC 60332-3-22 - Tests on Electric and Optical Fibre Cables under Fire Conditions - Part 3-22: Test for Vertical Flame Spread of Vertically-Mounted Bunched Wires or Cables - Category A; IEC 60534-4 - Industrial Process Control Valves - Part 4: Inspection and Routine Testing; IEC 60534-2-1 - Industrial Process Control Valves - Part 2-1: Flow-Capacity - Sizing Equations for Fluid Flow Under Installed Conditions; IEC 60534-8-3 - Industrial-Process Control Valves - Part 8-3: Noise Considerations - Control Valve Aerodynamic Noise Prediction Method; IEC 60534-8-4 - Industrial-Process Control Valves - Part 8-4: Noise Considerations - Prediction of Noise Generated by Hydrodynamic Flow; IEC 60584-1 - Thermocouples - Part 1: Reference Tables; IEC 60584-2 - Thermocouples - Part 2: Tolerances; IEC 60584-3 - Thermocouples - Part 3: Extension and Compensating Cables - Tolerances and Identification System; IEC 60684-1 - Flexible Insulating Sleeving - Part 1: Definitions and General Requirements; IEC 60751 - Industrial Platinum Resistance Thermometers and Platinum Temperature Sensors; IEC 60754-1 - Test on Gases Evolved During Combustion of Materials from Cables - Part 1: Determination of the Amount of Halogen Acid Gas; IEC 60754-2 - Test on Gases Evolved During Combustion of Electric Cables - Part 2: Determination of Degree of Acidity of Gases Evolved During the Combustion of Materials Taken from Electric Cables by Measuring pH and Conductivity; IEC 60794-1-1 - Optical Fibre Cables - Part 1-1: Generic Specification - General; IEC TR 60890 - A Method of Temperature-Rise Assessment by Extrapolation for Partially Type-Tested Assemblies (PTTA) of Low-Voltage Switchgear and Controlgear; IEC 61034-2 - Measurement of Smoke Density of Cables Burning under Defined Conditions - Part 2: Test Procedure and Requirements; IEC 61158-2 - Industrial Communication Networks - Fieldbus Specifications - Part 2: Physical Layer Specification and Service Definition; ISA 5.1 - Instrumentation Symbols and Identification; ISA 18.1 - Annunciator Sequences and Specifications; ISA 75.08.1 - Face-to-Face Dimensions for Integral Flanged Globe-Style Control Valves Bodies (Classes 125, 150, 250, 300, and 600); ISA 75.08.2 - Face-to-Face Dimensions for Flanged and Flangeless Rotary Control Valves (Classes 150, 300, and 600); ISA 75.08.5 - Face-to-Face Dimensions for Buttwelded-End Globe-Style Control Valves (Classes 150, 300, 600, 900, 1500, and 2500);

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

13

ISA 75.08.6 - Face-to-Face Dimensions for Flanged Globe-Style Control Valve Bodies (Classes 900, 1500, and 2500); NAMUR NE 43 - Standardization of the Signal Level for the Failure Information of Digital Transmitters.

NOTE For documents referred in this Standard and for which only the Portuguese version is

available, the PETROBRAS department that uses this Standard should be consulted for any information required for the specific application.

3 Terms and Definitions For the purposes of this document, the following terms and definitions apply: 3.1 thermowell immersion length length from the free end of the well up to the internal surface of the piping or the equipment in which the well is inserted 3.2 thermowell insertion length length of the free end of a well up to its mechanical fixation point on the flange or thread. It is represented by the U symbol 3.3 reference conditions set of ranges, usually narrow, corresponding to the operational conditions under which a given instrument or equipment is submitted to, when its performance characteristics are determined 3.4 fugitive emissions gas or vapor emissions from equipment under pressure which might happen due to involuntary or irregular leaks 3.5 Probable Total Error (PTE) maximum expected error for the instrument when submitted to usage conditions different from those in reference by the time of calibration and/or those informed by the manufacturer 3.6 toxic fluid fluids which, once released to the atmosphere beyond their admissible limits, pose potential risks to people or the environment 3.7 hysteresis maximum difference observed in the values indicated by the instrument, for any value of the measured range, whenever the variable goes over the whole scale in both increasing and decreasing directions NOTE Hysteresis is usually expressed in percentage of span.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

14

3.8 linearity degree of proximity between a curve and a straight line. Normally quantified as the maximum deviation between the curve and a straight line, positioned in order to minimize such deviation. The linearity of an instrument indicates the degree of proximity of its calibration curve with a straight line 3.9 control loop loops whose function is to keep one or more process variables within specified limits or being part of a sequencing or maneuver command aiming to actuate a final element (control valve, on-off valve, equipment start-up relay etc.) 3.10 indication loop loops whose functions are indication or alarm for supervision purposes 3.11 interlocking loop loops whose function is to protect equipment or avoid dangerous events to people or the environment NOTE It includes safety instrumented functions and the sequencing considered as such (e.g.: loops

that are part of the furnace start-up sequence). 3.12 legal metrology it refers to the legal, technical and administrative requirements related to measurement units, measurement methods, measuring instruments and materialized measures. These apply to the measurement systems related to commercial transactions, as well as those related to health and safety of people 3.13 design pressure pressure value used in the design of a vessel or other process equipment, in order to determine the minimum acceptable thickness or the physical characteristics of the internal parts for a given temperature 3.14 range measurement range located between two given values NOTE This value can be determined in relation to operational conditions (measuring),

measurement capacity limits of a given instrument, or the adjusted range of an instrument. 3.15 repeatability the degree of proximity between the values obtained by means of successive measurements at the output of a given instrument or equipment for a similar value applied at the input, with the other operational conditions kept constant NOTE Such measurements are performed throughout the instrument or equipment range, in the

same direction, in order not to include the hysteresis effects.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

15

3.16 skid equipment and accessories supplied and mounted on the same basis 3.17 span algebric difference between the upper and lower values of the range EXAMPLE

range -20 C to 100 C, span: 120 C 3.18 package unit a set of equipment and accessories designed to perform a defined unit operation, supplied for a same source and object of a single purchase request 3.19 control valve final control element that receives a command signal to adjust the passage area in order to change the flow rate value for the process fluid 3.20 on-off valve a valve that can assume two different states (open or closed), releasing or blocking the process fluid 4 Symbols or Abbreviations

ABNT - Brazilian Association of Technical Standards; AC - Alternate Current; ANSI - American National Standards Institute; API - American Petroleum Institute; ASME - American Society of Mechanical Engineers; CV - Flow Rate Capacity; DC - Direct Current; PTE - Probable Total Error; IEC - International Electrotechnical Commission; IHM - Human-Machine Interface; INMETRO - National Metrology, Normalization and Industrial Quality Institute; IR - Infrared Radiation; ISA - The International Society of Automation; ISO - International Organization for Standardization; LEL - Low Explosive Limit; NA - Normally Open; NBR - Brazilian Standard; NR - Regulatory Standard; PLC - Programmable Logical Controller; PSV - Pressure Safety Valve; RM - Material Requisition; SCADA - Supervision, Control and Data Acquisition System; DCS - Distributed Control System; SI - International Unit System; SIS - Safety Instrumented System.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

16

5 Documentation, Engineering Units, Symbology and Identification 5.1 Design Documentation The documentation for the instrumentation design shall be developed according to PETROBRAS N-1883. 5.2 Engineering Units 5.2.1 Units to be adopted in the project: [Recommended Practice]

a) temperature: C; b) flow rate: kg/h; c) pressure: kPa or kgf/cm2 (gauge or absolute); d) vacuum and low pressures: Pa or mmH2O; e) level: mm; f) density: kg/m3; g) absolute viscosity: cP or Pa.s.; h) kinematic viscosity: cSt.

5.2.2 Units to be adopted on instrument and IHM displays: [Recommended Practice]

a) temperature: C; b) flow rate (water steam): t/h; c) flow rate (liquids): kg/h or m3/h @ 20C/1 atm; d) flow rate (gas): m3/h @ 0C/1 atm (Nm3/h) or m3/h @ 20C/1 atm; e) pressure: kPa or kgf/cm2 (gauge or absolute); f) vacuum and low pressures: mmH2O; g) level: range %; h) density: kg/m3; i) absolute viscosity: cP or Pa.s; j) kinematic viscosity: cSt.

NOTE 1 For other variables, the SI units shall be used. NOTE 2 The use of more than one unit for each variable by project shall be submitted to

PETROBRAS for prior approval. 5.3 Symbology and Instrument Identification 5.3.1 The identification and the symbology to be used in engineering process and instrumentation diagrams shall meet the requirements on ISA 5.1, except in case of expansion of existing units, when it is acceptable to use local criteria. 5.3.2 All symbology not covered by ISA 5.1 shall be clearly showed on an additional drawing with subtitles. 5.3.3 The definitions below shall be used on items not defined by ISA 5.1:

a) C - electrical conductivity; b) D - density or specific gravity; c) M - humidity; d) AT - gas detectors; e) YS - smoke, flame and heat detectors.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

17

6 Supervision, Control and Safety Systems 6.1 General 6.1.1 The architecture for the supervision, control and safety systems, as well as their respective specifications of several equipments such as DCS, SCADA, PLC, SIS PLC etc shall be defined by PETROBRAS in an additional document. 6.1.2 In order to elaborate the documentation concerning 6.1.1, it is recommended to follow API RP 554 Part 2. [Recommended Practice] 6.2 Alarm System 6.2.1 The design criteria for alarm systems in industrial facilities shall be according to PETROBRAS N-2900. 6.2.2 When used, the alarm annunciators shall follow ISA 18.1 by means of the ISA-A or ISA-F1A sequences. 6.3 Safety Instrumented System The design criteria for safety instrumented systems shall be according to PETROBRAS N-2595. 6.4 Fire Alarm and Detection Systems The design of the fire alarm and fire detection systems shall meet the requirements found on ABNT NBR 17240. 7 Control Room 7.1 General 7.1.1 The criteria defined on 7.1 apply only to the control rooms that house the instrumentation equipment (panels, racks and cabinets) that make the interface with the field instruments or other equipments (equipment environment). 7.1.2 The criteria for the control rooms that house the interfaces with the operator (operation environment) shall be defined by PETROBRAS in an additional document. 7.1.3 The area where the control rooms are located shall be, preferably, non-hazardous, as determined by ABNT NBR IEC 60079-10-1 or ABNT NBR IEC 61241-10. 7.1.4 The control rooms internal area shall be dimensioned in order to provide an available area, for future equipment installation, equivalent to, at least, 10 % of the total area used by all the planned equipment.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

18

7.1.5 The access doors for equipment shall be dimensioned considering the dimensions for the biggest equipment with, at least, a gap of 30 cm in height and width. 7.1.6 It is not allowed process lines in the control room. 7.1.7 Unless otherwise specified in an additional document, control rooms shall have an air pressurization system. In the absence of a pressurization system, alternative measures shall be considered in order to prevent the entry of salt, dust, gases and other pollutants from the external environment that may damage the operation of equipment. Such measures shall be submitted to PETROBRAS approval. 7.1.8 Unless otherwise specified in an additional document, control rooms shall have an air conditioning and ventilation system. In the absence of an air conditioning and ventilation system, alternative measures shall be considered in order to avoid the degradation of equipment due to ambient temperature. These measures shall be submitted to PETROBRAS approval. 7.1.9 It is recommended that the control rooms be provided with elevated floor in order to facilitate the installation of cables for the equipments. [Recommended Practice] 7.2 Air Conditioning and Pressurization 7.2.1 It shall be provided, whenever the gas detection at the entrance of the ventilation air is applicable, a protection system for dampers closure and ventilation engines shutdown in the presence of gas on air ducts inlet. This protection system shall meet the following requirements:

a) It shall be always active while the air conditioning and pressurization system is in operation, even when in manual mode;

b) It shall provide discrete inputs to receive the signals originated from the gas detection system, which represent gas detection.

7.2.2 It shall be provided alarms in the supervision and control systems, in order to announce any abnormalities in the ventilation and air conditioning system, such as: machinery failure, high temperature, etc. 7.2.3 Unless otherwise specified in an additional document, the air conditioning and ventilation system shall be specified to maintain the ambient temperature at 24 oC 1 oC and relative humidity at 50 % 5 %. 7.2.4 Unless otherwise specified in an additional document, the pressurization system shall be specified for an overpressure in relation to the external ambient of the building of 4 mmH2O for non-hazardous areas and 6 mmH2O for hazardous areas.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

19

7.3 Equipment and Panel Arrangement All instrumentation equipment, located inside the control room, shall be placed in order to comply with the following requirements:

a) provide enough space for doors opening and access, for the purpose of inspection or maintenance of these equipments as well as meeting the minimum width required by NR-23 for access ways at any point in the room, considering the equipment doors closed;

b) ensure that the distance from any point in the control room to the exit complies with NR-23, considering the control room as a low risk ambient, unless other analysis determine on the contrary;

c) reduce the length of cables through the approximation of equipment that might have interconnections among themselves;

d) reduce the possibility of electromagnetic interference in equipment that receive highly sensitive signals (machinery vibration signals, thermocouple signals and pulse signals) keeping them away from noise generating equipment (uninterrupted power systems and variable frequency drivers).

7.4 Electrical Installation 7.4.1 For installation of instrumentation cables and equipment electrical power cables, inside the control room, cable trays are recommended. [Recommended Practice] 7.4.2 Cable trays shall be segregated by signal level and follow the distances determined by API RP 552. 7.5 Grounding The grounding of equipment, cabinet and signal cable shielding, inside control rooms, shall comply with API RP 552 requirements and the equipment manufacturers recommendations. 8 Instrumentation Power System 8.1 Pneumatic Systems 8.1.1 Instrument Air Generation 8.1.1.1 The dimensioning of the instrumentation air generation system capacity shall follow the API RP 552 recommendations. 8.1.1.2 In places where the control systems use natural gas, the following requirements shall be considered:

a) natural gas filtering and liquid separation; b) instruments with pilot valves without bleeding; c) trim material compatible with the natural gas composition.

NOTE In case the installation is housed, the gas escape shall be provided in the highest point of

the housing.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

20

8.1.1.3 Under normal operational conditions, the instrument air supply system shall have a minimum and controlled gauge pressure, in the main feeder, of 7 kgf/cm. This pressure shall not exceed 10.5 kgf/cm. The instrument air distribution network shall be designed to ensure a minimum gauge pressure of 5 kgf/cm in its extremities. 8.1.1.4 Instrument air quality shall comply with the requirements of ISO 8573-1 with the following classes:

a) solid particles: class 3; b) humidity content: select the class with a dew point temperature 10C lower than the

lowest local ambient temperature; c) oil content: class 3.

8.1.2 Instrument Air Distribution 8.1.2.1 Instrument air distribution shall comply with the recommendations of API RP 552. 8.1.2.2 It is recommended to measure the flow rate in the main feeder, at the instrument air generation system output. [Recommended Practice] 8.1.2.3 The pressure indication and the low pressure alarm shall be both provided at the supervision and control system. 8.1.2.4 It is recommended that the instrument air distribution be made through a closed ring. [Recommended Practice] 8.1.2.5 All taps for instrument air supply shall be located on the piping upper side, with individual block valves. It shall be provided, as minimum, a 10% spare of these taps, uniformly distributed on the area, for future derivations. 8.1.2.6 The low points and the branch terminals shall be provided with drain valves. 8.1.2.7 The distribution network shall be dimensioned in order to allow air flow rate at a maximum speed of 20 m/s. 8.2 Electrical Systems 8.2.1 The system configuration, as well as its voltage level, shall be determined by PETROBRAS in an additional document. 8.2.2 For definition of the power supply system, it is recommended to use, as reference, the recommendations provided by API RP 554 Part 2. [Recommended Practice] 8.2.3 It shall be scope of the instrumentation design team to determine:

a) system configuration; b) voltage variation ranges; c) system capacity;

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

21

d) minimum time of autonomous operation for systems, in case of power failure; e) instrument distribution associated to each power supply system.

8.2.4 Electrical power supply systems for instruments are defined as below. 8.2.4.1 Normal Systems Systems supplyed by alternate current, provided by a main feeder, which may have an automatic switching for a secondary feeder, such as an emergency generator. The switching time between these feeders might interfere on the supervision and control systems normal operation. 8.2.4.2 Uninterrupted Systems Systems whose switching time is lower than the maximum admissible time so that no supervision and control system component may switch off or interrupt the output signal. These systems are composed of:

a) in DC (rectifier and battery bank) according to PETROBRAS N-332; b) in AC with static switch (rectifier, battery bank, inverter and static switch); c) in AC with redundant parallel configuration according to PETROBRAS N-2760.

8.2.5 It shall be powered by an uninterrupted system all instruments, equipments and devices of supervision, control and safety systems involved in:

a) ensure safe process trip; b) keep continuity of operation/production of essential equipment (boilers, compressors,

wells, among others) in industrial units whose trip, even for a short period of time, is not desirable.

8.2.6 Unless otherwise stated in an additional document, the uninterrupted systems shall be dimensioned to keep the output load supplied for a minimum period of 30 minutes in order to ensure the safe trip. 8.2.7 It shall be provided, on the control and supervision system, alarms for any abnormalities in the uninterrupted system, such as: lack of voltage at the input, system powered by battery and internal system failures. 8.2.8 The following power voltage levels can be used: [Recommended Practice]

a) field instruments for monitoring, control and safety, including solenoid valves: 24 VCC; b) field instruments with high consumption (analyzers): 120 VCA; c) safety system panels: 120 VCA or 125 VCC; d) supervision and control system panels: 120 VCA or 125 VCC; e) supervision and control system panels for the production area: 220 VCA.

8.3 Hydraulic Systems The definitions on system type, supply and other characteristics shall be defined by PETROBRAS in an additional document.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

22

9 Selection and Specification of Instruments 9.1 General 9.1.1 The definition of measurement technology shall always take into account acquisition, installation and maintenance costs throughout the equipment life cycle. 9.1.2 Standardization for the transmission of field instrument signals shall follow the criteria below:

a) pneumatic instrumentation: 0,2 kgf/cm2 to 1 kgf/cm2; b) analogic electronic instrumentation: 4 mA to 20 mA; c) thermocouples and thermal-resistences: according to standard for thermal elements; d) Instrument communication through field networks: according to standard of chosen

protocol. 9.1.3 Digital communication protocols, physical media and network topologies used for information exchange between supervision and control systems and other equipment and subsystems shall be defined by PETROBRAS in an additional document. Only the communication cables for these systems are covered in this standard. 9.1.4 When measurement accuracy is required by the basic process design, selected sensor and transmitter set shall present an PTE lower than 80 % of the accuracy required by the process. PTE calculation shall be made according to the procedure defined in Appendix A. 9.1.5 Transmitters and control valve positioners in 4 mA to 20 mA shall be provided with HART protocol. Specific cases shall be specified in an additional document. 9.1.6 Every transmitter shall meet the requirements below. Specific cases shall be specified in an additional document.

a) be supplied with a display for local process variable indication in engineering unit; b) be electronic, microprocessed and programmable; c) provide signal transmission in the same physical media as the electrical power (two

wires) and be able to operate at 24 VCC, with a maximum loop resistance of 600 ; d) have the capacity of self-diagnosis with failure modes according to

NAMUR NE 43, in case of 4 mA to 20 mA transmission; e) four wires transmitters shall have an isolated output signal and be submitted to

PETROBRAS's approval. 9.1.7 The transmitter calibrated range and the local indicators range shall be chosen so that the process variable value in normal process conditional is located between 40% and 60% of this range. [Recommended Practice] 9.1.8 Pneumatic instrumentation shall meet the requirements below:

a) the use shall be restricted to actuators and control valve positioners, on-off valve actuators, damper actuators and electropneumatic converters. The use of pneumatic instrumentation for measurement and control shall be limited to situations where it is previously requested by PETROBRAS;

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

23

b) pneumatic connections of instruments shall be of 1/4 NPT, unless the necessary flow rate for instrument actuation, within the specified value, requires a higher diameter;

c) these shall be specified to operate, without restrictions, with an air quality as determined on 8.1.1.4.

9.1.9 All parts that are exposed to atmosphere shall be resistant to environmental conditions, including those potentially produced by the process. It shall be always verified in the process data whether there is any special condition. 9.1.10 Field instruments shall support environmental temperatures of up to 80 C. In case of an impossibility to meet this requirement, the use of the instrument shall be submitted to PETROBRAS approval and it shall be protected against direct sun radiation incidence and heat transfer resulting from nearby equipment. 9.1.11 Instruments, especially those applied in critical services or those requiring special attention (example: H2S and H2) shall meet the requirements established on material piping specifications regarding constructive aspect (materials, manufacturing process, inspection and tests). 9.1.12 All instrument parts in contact with process fluid shall be adequate to support designs pressure and temperature of the pipe or associated equipment. 9.1.13 Unless specified differently in specific items of this Standard, the instrument and field equipment enclosures shall have the following protection degree:

a) onshore facilities: IP-65; b) offshore facilities: IP-56.

9.1.14 All instrument and electric equipment shall present certificates of protection type compatible to their respective area classification, according to ABNT NBR IEC 60079-0 and INMETRO Administrative Rule MDIC 179/2010. 9.1.15 The electrical connection of the instruments shall be 1/2 NPT. Exceptions shall be submitted to PETROBRAS approval. 9.1.16 The instruments shall be specified to operate within the electric energy supply range. 9.1.17 The pneumatic connections of the instruments shall be 1/4 NPT. 9.1.18 The switches shall meet the following requirements:

a) have their contacts hermetically sealed; b) the current capacity of the switches contacts shall be at least 2 A or 50 % greater than that

required in normal operation; c) the operating voltage of the switches, in DC or AC, must be compatible with the power

supply of the circuit to which they are connected; d) the process switches shall have an adjustable setpoint; the adjustment devices must be

internal; when they have external access, they shall be provided with protective cover.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

24

9.1.19 All instruments shall be supplied with AISI 316 stainless steel identification plates permanently fixed to the instruments. 9.1.20 Instruments shall not be specified without consolidated use on the desired application or without study approved by PETROBRAS regarding its applicability. 9.2 Temperature Instruments 9.2.1 Selection and Specification Criteria 9.2.1.1 The use of thermometers shall be restricted to applications where there is a need of operation at the field and there is no available transmitter with local indication. 9.2.1.2 For remote measurement, a thermocouple or thermal resistance sensor shall be used. 9.2.1.3 For applications requiring higher measurement accuracy, with a PTE lower than 3 C, thermal resistance sensors shall be used. 9.2.1.4 In control or interlocking loops, a temperature transmitter connected to the sensor element shall be used. 9.2.1.5 For indication loops, it is recommended to use a temperature transmitter connected to the sensor element. [Recommended Practice] 9.2.1.6 Sealed expansion systems shall not be used. Only for thermometers above 500 C the use of sealed systems is accepted. 9.2.1.7 For the dimensioning of stems length, the values indicated in Appendix B shall be considered. 9.2.2 Thermometers 9.2.2.1 Sensor elements shall be bimetallic type for temperatures below 500 C. 9.2.2.2 Thermometers shall have the following general features:

a) display of, at least, 100 mm in diameter; b) connection to well of 1/2 NPT; c) stainless steel stem AISI 304 or 316 with a 6 mm external diameter; d) measurement uncertainty: 1 % of span; e) AISI 304 stainless steel box, with protection degree IP-55; f) needle zero adjustment; g) scales shall be made on white background with black characters.

9.2.2.3 In applications subject to vibration or measurement at lower temperature, it shall be used bimetalic thermometers with liquid filling.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

25

9.2.2.4 It is recommended not to use thermometers with adjustable displays (every angle). [Recommended Practice] 9.2.3 Thermocouples and Resistance Temperature Devices (RTD) 9.2.3.1 Thermocouples shall be of K type and shall follow the requirements established on IEC 60584-1 with, in case it is not specified in the basic design, Class 2 tolerance according to IEC 60584-2. 9.2.3.2 RTD shall be on 3 or 4 wires, in platinum, with a standard of 100 ohms at 0C and shall comply with the requirements established on IEC 60751 with, in case it is not specified in the basic design, Class A tolerance. 9.2.3.3 In applications where the required accuracy by the process basic design is not met, according to criterion established on 9.1.4, it shall be used transmitters programmed with the specific Callendar-van Dusen coefficients for the respective RTD sensors. In this case the transmitters shall be programmed by their manufacturer. 9.2.3.4 Thermocouples and RTD shall have mineral insulation and a AISI 316 stainless steel sheath. In cases where the use of protection wells is not applicable, the sheath material shall be specified according to the environment conditions. Example: skin point. 9.2.3.5 Sheath external diameter shall be of 6 mm. 9.2.3.6 All connections between thermal elements and cables for signal transmission shall be made at the head of the thermal elements. 9.2.3.7 Serial or parallel connection of thermocouples for measurement of temperature difference or average temperature, respectively, is not acceptable. 9.2.3.8 Thermocouples shall have an insulated measurement joint (not grounded). 9.2.3.9 All accessories, including well, head, terminal blocks and others, shall be supplied together by the thermal elements manufacturer. 9.2.3.10 Heads shall have an IP-55 protection degree and be made in aluminum for onshore facilities and AISI 316 stainless steel for offshore facilities. The cover of the heads shall have a retention chain connected to the body. 9.2.3.11 The connection of the thermal element to the well shall be made through use of a union together with nipples. All connections between the well and the thermal element shall be of 1/2 NPT. 9.2.4 Transmitters 9.2.4.1 Transmitters shall meet the general requirements defined on item 9.1 of this standard.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

26

9.2.4.2 Transmitters shall have enclosures with dual-compartment housing. 9.2.4.3 Miniature temperature transmitters (internally installed in the head of thermocouples or RTDs) are not accepted. 9.2.5 Thermostats Thermostats shall not be used, unless previously authorized by PETROBRAS. 9.2.6 Wells for Temperature Measurement Elements 9.2.6.1 All temperature sensor elements shall be protected with wells, unless otherwise specified in an additional document. 9.2.6.2 The wells shall be supplied together with sensor elements by the manufacturer, in order to ensure that the sensor element is in contact with the bottom of the well. 9.2.6.3 The wells shall be machined from a AISI 316 stainless steel bar or, in case this material is not suitable to the process conditions, from another material. The indication of the well material shall be stamped on the flange. 9.2.6.4 The wells shall meet the requirements established on ASME PTC 19.3 TW regarding vibration and tension aspects. 9.2.6.5 The wells shall be conical or, in case the conical does not meet the tension and vibration requirements, step-shank type. 9.2.6.6 Wells dimensioning shall meet the requirements found on Appendix B. 9.2.6.7 On vessels, towers and tanks, as well as whenever the possibility of galvanic corrosion due to contamination of the thread intervals with process fluid exists, flanged wells shall be used. 9.2.6.8 Whenever flanged process connections are required, the well flange shall be 1 1/2, unless the compliance to the vibration and tension requirements on ASME PTC 19.3 TW require the use of a higher diameter flange. 9.2.6.9 Whenever threaded connections are allowed, these shall be of 3/4 NPT. 9.2.6.10 On flanged wells, the well stem shall be fixed to the flange by means of welding and shall follow the treatments and procedures established on PETROBRAS N-133. In these cases, the welding certificates for the procedures and the executants qualification shall be supplied. In services with presence of H2 or H2S, this welding shall be of total penetration type. 9.2.6.11 Test wells shall be provided with plugs and chains, both in AISI 304 stainless steel.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

27

9.3 Pressure Instruments 9.3.1 Selection and Specification Criteria 9.3.1.1 The use of manometers shall be restricted to applications in which there are field operations that needs local indication. In case there is a local indication already available through a transmitter, the use of the manometer shall also be avoided. 9.3.1.2 The material for the parts in contact with the process fluid shall be AISI 316 stainless steel, unless the process fluid demands other type of material. 9.3.1.3 In service facilities with compressed air, it is recommended that the material for the sensor elements be bronze or brass. [Recommended Practice] 9.3.2 Manometers 9.3.2.1 Bourdon sensor elements are recommended. [Recommended Practice] 9.3.2.2 It is recommended the adoption of manometers made in compliance with ABNT NBR 14105. [Recommended Practice] 9.3.2.3 The manometers shall meet the minimum requirements below:

a) display with 100 mm diameter; b) manometer display shall be white and the numbers and characters in black; c) 1/2 NPT connection, whenever the piping material specification allows; d) box made on plastic or AISI 304; e) balanced needle with micrometrical adjustment; f) rupture disk at the rear; g) socket shall be on the same material as that for the sensor element: AISI 316 stainless

steel . 9.3.2.4 Manometers with a scale above 20 kgf/cm shall have a solid front. 9.3.2.5 The manometer display shall be made of safety glass with, at least, a 75 % transparency. The manometer cover shall be bayonet type. 9.3.2.6 Manometers with electrical contacts, digital contacts or those with needles to indicate maximum pressure shall not be used. 9.3.2.7 The scale used in differential manometers shall directly indicate the value of the measured differential pressure. 9.3.3 Transmitters Transmitters shall meet the general requirements defined on item 9.1 of this standard.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

28

9.3.4 Pressure Switches Pressure switches shall not be used, unless previously approved by PETROBRAS. 9.3.5 Accessories for Pressure Instruments 9.3.5.1 The manometer with pulsation dampeners shall be installed on services where occurs pulsations of the process fluid, such as at discharge of alternative pumps and at suction and discharge of alternative compressors. 9.3.5.2 In cases where the process' maximum pressure might exceed the instrument overpressure limit, the instrument shall be supplied with overpressure limiters adjusted for the full scale value. 9.3.5.3 On piping and equipment with liquid and high temperatures, which might damage the instrument, it shall be provided and installed additional length for the impulse lines, for the necessary thermal dissipation. For applications where the process fluid is steam, use the siphon tube or cooling serpentine. 9.3.5.4 For lines where the process fluid is corrosive, viscous, solidifiable or have a combination of these properties, pressure instruments shall:

a) manometers: use the diaphragm seal; b) transmitters: be installed with a sealing T or a diaphragm seal, according to the needs.

9.3.5.5 When selecting the diaphragm seal, the following shall be observed:

a) filling fluid compatibility with the process temperature; b) diaphragm material adequacy to process fluid and to temperature and pressure limits; c) diaphragm shall be integrated to the instrument supplied by the manufacturer and with a

flanged connection to the process; d) capillary length shall be minimized in order not to allow any excess; e) in differential pressure, temperature variations between the taps shall be considered for

filling fluid selection and the capillaries of each side shall have the same length. 9.3.5.6 Typical applications where the diaphragm seal shall be avoided:

a) flow rate measurement; b) differential pressure measurement at the interior of towers; c) measurement of low absolute pressure (vacuum).

9.4 Flow Rate Instruments 9.4.1 Selection Criteria 9.4.1.1 For measurement, it shall be used orifice plates with differential pressure transmitters or vortex meters.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

29

9.4.1.2 Other types of instruments such as ultrasonic, coriolis, venturi, V-Cone, averaging pitot, positive displacement, turbine, electromagnetic, and others, shall be used where their use is required by process conditions, installation conditions and the service for which the meter is intended. 9.4.1.3 For piping with internal diameter lower than 50 mm shall be used instruments, for local indication and transmission, of the following types:

a) integral orifice; b) vortex meter; c) coriolis meter.

9.4.1.4 For services requiring only local flow rate indication, it shall be used rotameters, positive displacement meters or sensors compatible with the application. For pipes with an internal diameter lower than 50 mm, operating with non-toxic and non-flammable fluids, rotameters shall be used. 9.4.1.5 For flow rate measurement with the aim of legal metrology, the type of meter shall be defined by PETROBRAS in an additional document and its specification shall meet the Standards below:

a) positive displacement for liquid measurement: API MPMS 5.2; b) turbine for liquid measurement: API MPMS 5.3; c) coriolis for liquid measurement: API MPMS 5.6; d) ultrasonic meter for liquid measurement: API MPMS 5.8; e) ultrasonic meter for gas measurement: AGA REPORT 9; f) orifice plate for natural gas: API MPMS 14.3.1 or ISO 5167-1 and 5167-2; g) provers for calibration of liquid meters: API MPMS 4.1 and API MPMS 4.5.

9.4.2 Orifice Plate Meters 9.4.2.1 For general applications, use concentric orifice plates with a sharp edge, according to ISO 5167-1 and 5167-2. 9.4.2.2 Sharp edge concentric orifice plates shall always be used, unless:

a) pipe diameter is below than that specified on ISO 5167-2, in this case use integral orifice; b) reynolds number is below than that specified on ISO 5167-2, in this case use quadrant

edge orifice plate or conical entrance orifice plates; c) process fluid containing suspension solids, in this case use eccentric or segmental orifice

plates. 9.4.2.3 The following requirements shall be met when specifying and sizing the orifice plate:

a) all calculation factors for the orifice plates shall be taken in normal operation flow conditions;

b) for applications where a flow rate range between 5:1 and 9:1 is necessary, two differential pressure transmitters shall be used, upon consulting the process engineering for confirmation of these operational conditions;

c) whenever only one transmitter is used, the maximum operation flow rate shall be at most equal to 95 % of the maximum calculated flow rate;

d) it is recommended that the normal operation flow rate be situated between 50 % and 80 % of the maximum calculated flow rate; [Recommended Practice]

e) minimum operation flow rate shall be at least 20% of the maximum calculated flow rate;

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

30

f) maximum calculated flow rate shall be always rounded up to a multiple of 10, in order to

facilitate the scale factor; g) it is recommended that the differential pressure for plate calculation, as well as the upper

limit of the transmitter range be equal to 2 500 mmH2O; [Recommended Practice] h) when it is not possible to choose this value, it is recommended to adopt greater or lower

values, with intervals of 250 mmH2O, limited to the maximum permanent head loss allowable by the process for the meter. Ex: 1 250 mm H2O, 2 000 mmH2O and 3 000 mmH2O; [Recommended Practice]

i) use pressure taps at the flanges, unless otherwise specified on an additional document; j) for quadrant edge, conical entrance and eccentric orifice plates, use ISO TR 15377 as

reference; k) the integral orifices shall be avoided in fluids containing suspended solids; l) the plates material shall be AISI 316 stainless steel, unless service conditions require

another material; m) the dimensions and shape for sharp edge orifice plates shall meet the limits established

on ISO 5167-2; n) the recommended thickness for sharp edge orifice plates shall follow Table 1.

Table 1 - Line Nominal Diameter versus Plate Thickness

Line nominal diameter Plate thickness 2 to 6 1/8

8 to 14 1/4 16 to 20 3/8

9.4.2.4 Unless otherwise specified in an additional document, the finishing of the plate surface in contact with the sealing joint shall follow the same standard (roughness and slots) for the orifice flange face, as determined by ASME B16.5. 9.4.2.5 The orifice flanges shall meet the recommendations of ASME B16.36. 9.4.2.6 The lengths of straight sections required for measurement upstream and downstream, according to ISO 5167-2, shall be considered during design elaboration. 9.4.3 Vortex Type Meters 9.4.3.1 Specification and installation shall follow the recommendations of the manufacturer and ISO TR 12764. 9.4.3.2 In the specification for these meters, minimum operation flow rate shall be above the flow rate cut-off value of the meter. 9.4.3.3 For the installation at places with difficult access, the transmitter shall be supplied for remote installation in order to be accessible from floor or platforms. 9.4.3.4 The meter shall be specified in order to allow the sensor element replacement without the need to stop the process. 9.4.3.5 Vortex meters shall not be used in fluids with suspended solids.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

31

9.4.3.6 The length for straight sections required for measurement upstream and downstream, according to ISO TR 12764, shall be considered during design elaboration. 9.4.4 Venturi, Flow Nozzles, Pitot and V-Cone Meters 9.4.4.1 Venturi 9.4.4.1.1 Venturi sizing and specification shall follow the recommendations on ISO 5167-4. 9.4.4.1.2 Typical Applications:

a) whenever low head loss is required; b) lines in presence of suspended solids; c) rectangular section ducts; d) whenever it is necessary more than two differential pressure measurements taps (e.g:

measurement redundancy). 9.4.4.1.3 The length of the straight sections required for measurement upstream and downstream, according to ISO 5167-4, shall be considered during design elaboration. 9.4.4.2 Flow Nozzles 9.4.4.2.1 Flow nozzles sizing and specification shall follow the recommendations on ISO 5167-3. 9.4.4.2.2 Typical applications: whenever flow rate measurement at high speed flow is required. 9.4.4.2.3 The length of straight sections required for measurement upstream and downstream, according to ISO 5167-3, shall be considered during design elaboration. 9.4.4.3 Averaging Pitot Tubes 9.4.4.3.1 Sizing, specification and installation design for averaging Pitot tubes shall follow the recommendations of the manufacturer and ASME MFC-12M. 9.4.4.3.2 Typical applications:

a) large diameter lines where the meters presented on ISO 5167-1, 5167-2, 5167-3 and 5167-4 are not applicable;

b) whenever a insignificant head loss is required. 9.4.4.4 V-Cone 9.4.4.4.1 V-Cone sizing, specification and installation design shall follow manufacturers recommendations.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

32

9.4.4.4.2 Typical applications:

a) measurement locations with little straight section available upstream; b) whenever a low permanent head loss is required.

9.4.5 Restriction Orifices 9.4.5.1 Restriction orifices shall be used to generate a permanent head loss in liquid or gas flow or when it is required to limit gas flow rate in critical flow condition. 9.4.5.2 For restriction orifice sizing in a sub-critical flow condition, it shall be adopted the sizing procedure of a sharp edge orifice plate by means of the reference flow rate and the upper limit value of the associated range that generates the permanent head loss desired by the process. In an approximate way, it can be considered that plates with taps at the tubes (pipe taps) have an upper range limit equal to the permanent head loss. 9.4.5.3 For restriction orifice sizing in critical flow condition, use the expression on Appendix C. 9.4.5.4 Construction material shall be in AISI 316 stainless steel unless process conditions require another material. 9.4.5.5 Minimum thickness for restriction orifices shall be determined according to the criteria presented on Appendix D. 9.4.6 Ultrasonic Flow Meters 9.4.6.1 Ultrasonic meter shall have, by measurement principle, the transit time and be of insertion type assembled on a spool. External type meters shall only be used upon approval by PETROBRAS. 9.4.6.2 Specification and installation design shall follow the requirements on API MPMS 5.8 (for liquids) and AGA REPORT 9 (for gases). 9.4.6.3 Typical applications:

a) wherever theres a need for a lower measurement uncertainty in relation to those obtained with orifice plates and vortexes;

b) wherever theres a need for a higher range than those obtained with orifice plates and vortexes;

c) wherever an insignificant head loss is required; d) high viscosity products; e) legal metrology for natural gas measurement.

9.4.7 Coriolis Flow Meters 9.4.7.1 Specification shall follow manufacturers recommendations, ISO 10790 and, in case of legal metrology for liquids, API MPMS 5.6.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

33

9.4.7.2 It shall be verified if the associated head loss meets process conditions. 9.4.7.3 Typical applications:

a) wherever theres a need for a lower measurement uncertainty in relation to those obtained with orifice plates and vortexes;

b) wherever theres a need of a higher range than those obtained with orifice plates and vortexes;

c) wherever mass flow rate measurement is required; d) high viscosity products; e) little availability of straight sections in the installation.

9.4.8 Variable Area Meters (Rotameters) 9.4.8.1 Specification and installation design shall follow manufacturers recommendations and ASME MFC-18M. 9.4.8.2 Non-metallic rotameters shall only be used in local indications for non-toxic flammable or corrosive fluids and in lines lower than 2. 9.4.8.3 In other situations, rotameters with metallic tubes, vertical input and side output shall be used, being the floater removable by the top of the meter body and with magnetic coupling. 9.4.8.4 Rotameters shall be specified in order to place normal flow rate between 50 % to 60 % of the meter range. 9.4.8.5 Connections to the piping shall be compatible with the line pressure class, being normally flanged for process lines. 9.4.9 Positive Displacement Meters 9.4.9.1 Specification shall follow manufacturers recommendations and those on API MPMS 5.2. 9.4.9.2 Typical applications:

a) flow rate totalization on liquid services without suspended solids; b) bunker (ship fuel) mixer unit; c) legal metrology systems for viscous products.

9.4.10 Turbine Type Meters 9.4.10.1 Specification and installation design shall follow manufacturers recommendations and API MPMS 5.3. 9.4.10.2 Turbine meters shall not be used in fluids with suspended solids.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

34

9.4.10.3 Typical applications:

a) legal metrology systems for low viscosity liquids and gases; b) in-line blending systems.

9.4.11 Electromagnetic type Meters 9.4.11.1 Specification and installation design shall follow manufacturers recommendations and ASME MFC-16. 9.4.11.2 Typical applications:

a) water; b) fluids with suspended solids; c) corrosive fluids; d) whenever an insignificant head loss is desired; e) fluids with physical property variations.

9.4.12 Transmitters Transmitters shall meet the general requirements defined on item 9.1 herein. 9.4.13 Flow Switches 9.4.13.1 Flow switches shall only be used in applications whose function is detection of flow presence or absence. 9.4.13.2 Flow switches with movable parts are not acceptable. 9.4.13.3 Whenever it is necessary to detect pre-determined values, different from zero, a flow rate transmitter shall be used. 9.5 Level Measurement Instruments 9.5.1 Selection and Specification Criteria 9.5.1.1 For level indication in vessels and towers, gauge glasses shall be used and in tanks shall be used ruler level indicator. 9.5.1.2 All tanks without a remote level indication shall have, at least, a local level indicator. 9.5.1.3 For level measurement in vessels and towers, it shall be used electronic instruments, such as differential pressure type or guided wave radars. Other kinds of instruments, such as: displacer type, radar, capacitive, ultrasonic, conductivity, radioactive, bubbling, servo-operated, magnetostrictive and others shall be used whenever its use is required by process conditions.

-PUBLIC-

N-1882 REV. D ENGLISH 02 / 2011

35

9.5.1.4 When measuring level for legal metrology purpose, the meter shall be defined by PETROBRAS and shall follow API MPMS 3.3. 9.5.1.5 Level instrument installation shall have appropriate heating, with steam jacket, steam trace or electric trace, whenever the operations handle viscous products, subject to solidification at ambient temperature. 9.5.1.6 All parts in contact with the process fluid, such as: flanges, displacers, diaphragms, plugs, shall be made of AISI 316 stainless steel, except when process conditions require a different material. 9.5.1.7 Instruments with associated electronics used in services with temperatures higher than 200 C or lower than 0 C shall be provided with extension. 9.5.1.8 Whenever external chamber instruments are used, the chamber body shall be flanged, in order to allow for instrument removal. The installation of instruments internally to the equipment shall be subject to previous approval by PETROBRAS. 9.5.2 Gauge Glasses 9.5.2.1 Reflex gauge glasses shall be used in applications with transparent, clean and non-viscous fl