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COMPLEXO PETROQUÍMICO DO RIO DE JANEIRO

AREA:

GENERAL

TITLE:

COMPER/EE/EAI

DESIGN CRITERIA – INSTRUMENTATION AND AUTOMATION

REVISION INDEX REV

DESCRIPTION AND/OR AFFECTED SHEETS

0 A

ORIGINAL. INCLUDED REQUEREMENTS FOR BOILER, CEMS AND FILDBUS FUNDATION RISK MANAGEMENT.

B C D E

REVISED WHERE INDICATED. REVISED WHERE INDICATED REVISED THE CONCEPT FOR CABLE ENTRANCE IN CCL AND CIC AND CEMS ITEMS REVISED WHERE INDICATED

DATE DESIGN

REV. 0

REV. A

REV. B

REV. C

REV. D

REV. E

03-30-07

06-08-07

08-21-08

01-08-09

01-25-09

24-07-09

AB-PQF/UPB/ES

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AB-PQF/UPB/ES AB-PQF/UPB/ES/AEI AB-PQF/UPB/ES/AEI AB-PQF/UPB/ES/AEI AB-PQF/UPB/EE/AEI

EXECUTION

ORESTES

RICARDO

RICARDO

ORESTES

ORESTES

MARCIO

CHECK

RICARDO

ORESTES

ORESTES

DILERMANDO

DILERMANDO

ORESTES

FERNANDO

FERNANDO

DILERMANDO

FERNANDO

FERNANDO

DILERMANDO

APPROVAL

REV. F

THE INFORMATION CONTAINED IN THIS DOCUMENT IS PETROBRAS PROPERTY AND MAY NOT BE USED FOR PURPOSES OTHER THAN THOSE SPECIFICALLY INDICATED HEREIN. THIS FORM IS PART OF STANDARD PETROBRAS N-381-REV. G ENGLISH ANNEX A – PICTURE A-1.

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CONTENTS 1.

OBJECTIVE ......................................................................................................................6

2.

APPLICABLE STANDARDS ............................................................................................6 2.1.

PETROBRAS ..............................................................................................................................6

2.2.

ABNT (Associação Brasileira de Normas Técnicas). ......................................................9

2.3.

API (American Petroleum Institute). ..................................................................................10

2.4.

NFPA (National Fire Protection Association)..................................................................11

2.5.

IEC (International Electrotechnical Commission). .........................................................11

2.6.

ANSI ( American National Standards Institute )..............................................................12

2.7.

ASME (The American Society of Mechanical Engineers). ...........................................12

2.8.

ASTM (American Society for Testing and Materials). ...................................................13

2.9.

ISA (Instrumentation, Systems and Automation Society). ..........................................13

2.10. IEEE (Institute of Electrical and Electronic Engineers). ...............................................16 2.11. MSS (Manufacturers Standardization Society of the Valve and Fittings Industry Manufacturers Association)................................................................................16 2.12. NAMUR ......................................................................................................................................16 2.13. NR (Normas Regulamentadoras de Segurança e Saúde no Trabalho Ministério do Trabalho e Emprego). ..................................................................................16 2.14. ISO (International Organization for Standardization)....................................................17 2.15. EIA (Electronic Industries Association) ...........................................................................17 2.16. EEMUA (The Engineering Equipment and Materials Users Association)................17 2.17. UL (Underwriters Laboratories) . ........................................................................................17 2.18. Open Connectivity Organization (OPC). ...........................................................................17 2.19. Fieldbus Foundation (FF). ....................................................................................................17 2.20. INMETRO ( Instituto Nacional de Metrologia, Normalização e Qualidade Industrial)..................................................................................................................................18 2.21. AGA ( American Gas Association) .....................................................................................19 3.

DEFINITIONS..................................................................................................................19

4.

ENGINEERING UNITS ....................................................................................................20

5.

INSTRUMENTATION DESIGN CRITERIA......................................................................21 5.1.

GENERAL CONDITIONS........................................................................................................21

5.2.

INSTRUMENTS IDENTIFICATION........................................................................................24

5.3.

DESIGN DOCUMENTATION .................................................................................................26

5.4.

GENERAL REQUIREMENTS FOR DESIGN AND SPECIFICATION OF INSTRUMENTS. .......................................................................................................................44

5.5.

TEMPERATURE INSTRUMENTS SPECIFICATION .........................................................47

5.6.

PRESSURE INSTRUMENTS SPECIFICATION..................................................................48

5.7.

FLOW INSTRUMENTS SPECIFICATION............................................................................50


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DESIGN CRITERIA – INSTRUMENTATION AND AUTOMATION 5.8.

LEVEL INSTRUMENTS SPECIFICATION..........................................................................50

5.9.

CONTROL VALVES SPECIFICATION. .............................................................................51

5.10. SALFETY AND RELIEF VALVES SPECIFICATIONS ......................................................53 5.11. PROCESS ANALYZERS SPECIFICATIONS......................................................................53 5.12. MARSHALLING CABINET .....................................................................................................73 5.13. FIRE AND GAS DETECTION.................................................................................................74 5.14. RESERVE CRITERIA ..............................................................................................................75 5.15. INTERLOCKING AND EMERGENCY SHUTDOWN SYSTEM ........................................75 5.16. PROGRAMMABLE LOGIC CONTROLLER FOR GENERAL APPLICATIONS...........77 5.17. PROGRAMMABLE LOGIC FOR SAFETY SYSTEM.........................................................79 5.18. INSTALLATION OF INSTRUMENTS....................................................................................79 5.19. PACKAGE UNITS ....................................................................................................................83 5.20. MOTORIZED VALVES TELECOMAND SYSTEM..............................................................86 5.21. MEASUREMENT STATION FOR CUSTODY TRANSFER – LIQUID EMED ................90 5.22. EMED for measurement of gas ...........................................................................................94 5.23. CONTINUOUS EMISSION MONITORING SYSTEM - CEMS ..........................................96 5.24. EMERGENCY ISOLATION VALVE – EIV..........................................................................110 6.

7.

8.

9.

GAS COMPRESSORS AUTOMATION.........................................................................110 6.1.

SCOPE .....................................................................................................................................110

6.2.

GENERAL REQUIREMENTS...............................................................................................110

6.3.

RECIPROCATING COMPRESSORS. ................................................................................119

6.4.

CENTRIFUGAL COMPRESSORS ......................................................................................122

FIRED HEATERS AUTOMATION.................................................................................122 7.1.

SCOPE .....................................................................................................................................122

7.2.

GENERAL GUIDELINES ......................................................................................................122

7.3.

FUNCTIONAL REQUIREMENTS AND INTERFACES....................................................123

7.4.

LOGIC SEQUENCE DESCRIPTION...................................................................................125

7.5.

GENERAL REQUIREMENTS...............................................................................................131

7.6.

GENERAL NOTES .................................................................................................................132

PUMP AUTOMATION ...................................................................................................132 8.1.

SCOPE .....................................................................................................................................132

8.2.


8.3.

FUNCTIONAL REQUIREMENTS ........................................................................................132

8.4.

INTERFACES AND ADDITIONAL INSTRUMENTATION...............................................134

8.5.

BLOCK DIAGRAMS FOR PUMP AUTOMATION ............................................................135

8.6.

LARGE SIZE PUMP CONTROL ARCHITECTURE .........................................................139

AIR COOLER AUTOMATION .......................................................................................143


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DESIGN CRITERIA – INSTRUMENTATION AND AUTOMATION 9.1.

SCOPE .....................................................................................................................................143

9.2.


9.3.

FUNCTIONAL REQUIREMENTS AND INTERFACES....................................................143

9.4.

LOGIC SEQUENCE DESCRIPTION...................................................................................145

9.5.

BLOCK DIAGRAMS: AIR-COOLED HEAT EXCHANGERS AUTOMATION .............146

10.

BOILER CONTROL AND SAFETY REQUIREMENTS..................................................147

10.1. SCOPE .....................................................................................................................................147 10.2. GENERAL GUIDELINES ......................................................................................................147 10.3. CONTROL STRATEGIES .....................................................................................................148 10.3.1. Steam flow control..............................................................................................................148 10.3.2. Water level control in the steam drum ..........................................................................148 10.3.3. Steam temperature control...............................................................................................149 10.4. REQUIREMENTS FOR PROCESS INSTRUMENTATION .............................................149 10.5. PROCESS ALARMS REQUIREMENTS ............................................................................151 10.6. FIELD INSTRUMENTATION ................................................................................................152 10.7. SAFETY REQUIREMENT - SIS ...........................................................................................153 10.8. FUNCTIONAL REQUIREMENTS AND INTERFACES....................................................155 11.

LOCAL CONTROLLER ROOM (CCL) AND CONTROL INTEGRATED CENTER (CIC)..............................................................................................................................156

12.

SUPERVISION AND CONTROL SYSTEMS .................................................................158

12.1. SUPERVISION SYSTEMS....................................................................................................158 12.2. CONTROL SYSTEMS ...........................................................................................................158 13.

FOUNDATION FIELDBUS SPECIFICATION................................................................159

13.1. SCOPE .....................................................................................................................................159 13.2. . DEFINITIONS........................................................................................................................159 13.3. INSTALLATION CRITERIA ..................................................................................................159 13.4. FIELD DEVICES .....................................................................................................................160 13.5. HOST SYSTEM.......................................................................................................................161 13.6. SEGMENT DESIGN ...............................................................................................................162 13.7. CONFIGURATION TOOL .....................................................................................................166 13.8. MAINTENANCE TOOL..........................................................................................................167 13.9. DOCUMENTATION................................................................................................................168 13.10. ACCEPTANCE TESTS..........................................................................................................169 13.11. TRAINING ................................................................................................................................169 13.12. SPARE PARTS .......................................................................................................................170 13.13. FOUNDATION FIELDBUS SEGMENT RISK MANAGEMENT ......................................170 14.

DATA COMMUNICATIONS ROUTES - VCD ................................................................171


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DESIGN CRITERIA – INSTRUMENTATION AND AUTOMATION 15.

MODERN CONTROL STRATEGIES.............................................................................172

16.

THE ENTERPRISE-CONTROL SYSTEM INTEGRATION ............................................172

17.

DYNAMIC PROCESS SIMULATOR..............................................................................172

18.

TRADE AUTOMATED SYSTEM – TAS ........................................................................173

19.

ELECTRIC POWER SYSTEM FOR INSTRUMENTATION ...........................................175

20.

TANKING GAUGING SYSTEM.....................................................................................178


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1.

OBJECTIVE

The objective of this Technical Specification is to present the Instrumentation and Automation Design Criteria additional to those mentioned in the PETROBRAS standards, for the Basic and Detailed Design, of the RIO DE JANEIRO PETROCHEMICAL COMPLEX in Itaboraí, Rio de Janeiro State, Brazil. 2.

APPLICABLE STANDARDS

The following list of standards shall be applied for design and specification of equipment or materials that are to be used in the current project. In case of doubts, PETROBRAS shall be consulted. This Technical Specification complements and is complemented by the Specification Technique I-ET-6000.67-0000-700-PDY-001 - Design Criteria - Electricity.

2.1.

E

PETROBRAS

N-0058

Símbolos Gráficos para Fluxogramas de Processo e Engenharia

NI-0058

Graphic Symbols for Process and Engineering Flow-sheets

NI-0298

Graphic Symbols and designations employed in detailing drawings of industrials electrical instalations

N-0381

Execução de Desenhos e Outros Documentos Técnicos em Geral

NI-0381

Execution of Drawing and Other Technical Documents

N-0839

Pote para Instrumentação

N-0858

Construção, Montagem e Condicionamento de Instrumentação

N-1600

Construção, Montagem e Condicionamento de Redes Elétricas

N-1735

Pintura de Máquinas, Equipamentos elétricos e Instrumentos

N-1882

Critérios para elaboração de Projetos de Instrumentação

NI-1882

Criteria for Preparing Instrumentation Design

N-1883

Apresentação de Projeto de Instrumentação

NI-1883

Presentation of Instrumentation/Automation Design

N-1931

Material de Tubulação para Instrumentação


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N-1939

Formulários p/ Construção, Montagem e Condicionamento de Instrumentação

N-1996

Projeto de Redes Elétricas em Envelopes de Concreto e com Cabos Diretamente no Solo

N-1997

Redes Elétricas de Bandejamento para Cabos – Projeto, Instalação e Inspeção

NI-1997

Electrical Networks in Cable Tray Systems- Design, Installation and Inspection

N-2065

Elaboração de Informações Básicas de Empreendimentos do Abastecimento

NI-2065

Preparing Basic Information for Refining Projects

N-2160

Atuador Elétrico para Válvula

NI- 2160

Electric Valve Actuator

N-2166

Classificação de Áreas para Instalações Elétricas em Refinarias de Petróleo

N-2194

Controlador Programável

NI-2194

Programmable Controller

N-2236 Pessoal

Inspeção de construção e montagem em Instrumentação – Qualificação de

N-2247

Válvula Esfera em aço para Uso geral e Fire-Safe

N-2268

Verificação, Calibração e Teste de Instrumento de Nível

N-2270

Fabricação e Montagem de Linhas de Impulso

N-2271

Teste Pneumático para Linha de Alimentação e Sinal

N-2272

Montagem de Linha de Alimentação e Sinal Pneumático

N-2276

Teste Hidrostático e Pneumático para Linha de Impulso

N-2277

Teste de Isolação e Continuidade Elétrica de Circuito de Instrumentação

N-2279

Inspeção de Placa de Orifício

E

N-2316 Fornecimento de Instrumentação para Unidade em Pacote e “SKID”NI-2316 Supply of instrumentation for package and skid mounted units

E

N-2368

Inspeção, Manutenção, Calibração e Teste de Válvula de Segurança e /ou Alívio

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N-2384

Cabo Elétrico de InstrumentaçãoNI-2384

Electric instrumentation cable

N-2547

Conversor de Freqüência para Controle de Rotação de motor Elétrico até 660 VCA

NI-2547

Frenquency converter for speed control of electric motor up to 660 VAC

N-2595

Critério de Projeto e Manutenção para Sistemas Instrumentados de Segurança em Unidades Industriais

NI-2595 Design and maintenance criteria for safety instrumented systems in industrial unitis N-2669 Configuração de Rede de TelecomunicaçõesNI-2669 network configuration

Telecomunications

N-2747

Uso de Cor em Instalações Industriais Terrestres e Marítimas

NI-2747

Use of Color in Industrial Onshore e Offshore Facilities

N-2760

Sistemas Ininterruptos de Energia para Uso Industrial

NI-2760

Uninterruptible Power System for Industrial Use

N-2761

Critério de Segurança para Projeto de Sistemas de Detecção e Alarme de Incêndio e Gás no Refino

NI-2761

Safety Criteria for Design of Fire and Gas Detection and Alarm System in Refining Units

N-2778

Sistemas Ininterruptos de Energia para Uso Industrial – Folha de Dados

NI-2778

Uninterruptible Power System for Industrial Use – Data Sheet

N-2781

Diretrizes de Engenharia de Confiabilidade

NI-2781

Reliability Engineering Guidelines

N-2784

Confiabilidade e Análise de Riscos

NI-2784

Reliability and Risk Analysis

N-2802

Folha de Dados de Instrumentação Coletânea

N-2833

Formulários e Listas para Projetos de Instrumentação

NI-2833

Forms and Lists for Instrumentation Design

Diretriz Técnica – AB-RE/ES/TEE – DT-AB-RE/ES/TEE-001 – Instalação de Dispositivos de Segurança em Vaso de Pressão Technical Guideline - AB-RE/ES/TEE - DT-AB-RE/ES/TEE-006 - “Use of spaired PSVs”

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Technical Guideline – EB-RE/ES/TEE – DT-AB-RE/ES/TEE-013 – Requirements for Process and Storage of Aromatics Products

2.2.

ABNT (Associação Brasileira de Normas Técnicas).

NB 284

Válvulas de Segurança e/ou Alívio de Pressão – Aquisição , Instalação e Utilização

NBR 1333

Controle de Acesso para Segurança de Instalações Físicas de Processamento de Dados

NBR 5363

Equipamentos elétricos para Atmosferas Explosivas – Tipo de proteção “d” – Especificação

NBR 5410

Instalações Elétricas de Baixa Tensão

E C

IEC-NBR-60079-12 -Equipamentos elétricos para Atmosferas Explosivas – Invólucros com Pressurização ou Diluição Contínua - Tipo de proteção “p”

E

IEC-NBR-60079-0 Marcação de Equipamentos Elétricos para Atmosferas Explosivas

E

NBR 8447

Equipamentos elétricos para Atmosferas Explosivas de Segurança Intrínseca – Tipo de proteção “i”

NBR 9441

Execução de Sistemas de Detecção e Alarme de Incêndio

IEC-NBR-60079-7 Equipamentos elétricos para Atmosferas Explosivas – Segurança Aumentada Tipo de Proteção “e” NBR 10861 Prensa cabos NBR 11515 Critérios para Segurança Física de Armazenamento de Dados NBR 12313

Sistema de combustão – Controle e Segurança para Utilização de Gases Combustíveis em Processos de Baixa e Alta Energia

NBR 13225

Medição de Vazão de Fluídos em condutos fechados, Utilizando Placa de Orifício e Bocais em Configurações Especiais

NBR 10300

Cabos de Instrumentação com Isolação Extrudada de PE ou PVC para tensões de até 300 Volts

NBR 10700

Planejamento de Amostragem em Dutos e Chaminés de Fontes Estacionárias

NBR 10701

Determinação de pontos de Amostragem em Dutos e Chaminés em Fontes Estacionárias

NBR 14565

Procedimento Básico para Elaboração de Projetos de Cabeamento de Telecomunicações para Rede Interna Estruturada

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NBRIEC60529 Graus de Proteção para Invólucros de Equipamentos Elétricos (Código IP) NBRIEC60079-14 Equipamentos Elétricos Para Atmosferas Explosivas – Parte 14 Instalação Elétrica em Área Classificada (Exceto minas) NBRIEC60079-17 Equipamentos Elétricos Para Atmosferas Explosivas – Parte 17 Inspeção e Manutenção em Áreas Classificadas (Exceto Minas) NBRIEC60079-27 Conceito Fieldbus Intrinsecamente Seguro (FISCO) e Conceito Fieldbus Não Acendível (FNICO) NBRNM-IEC60050-426 Equipamentos Elétricos para Atmosferas Explosivas Terminologia NBRISO5167-1 Medição de Vazão Fluídos por Meio de Instrumentos de Pressão (Parte 1 – Placas de Orifício, Bocais e Tubos Venturi) E

NBRISO/IEC 27002 Tecnologia da Informação – Técnicas de Segurança – Código de Prática para a Gestão de Segurança da Informação

2.3.

API (American Petroleum Institute).

API RP 520 parts 1 and 2 Sizing, Selection and Installation of Pressure Relieving Devices in Refineries E

API STD 521

Guide for Pressure Relieving and Depressuring Systems

E

API STD 526

Flanged Steel Pressure Relief Valves

E

API STD 527

Seat Tightness of Pressure Relief Valves

E

API RP 536

Post Combustion-NOX for Fired Heater Equipment in General Refinery Services

API RP 540

Electrical installations in Petroleum Processing Plants

API RP 551

Process Measurement Instrumentation

API RP 552

Transmission Systems

API RP 553

Refinery Control Valves

API RP 554

Process instrumentation and Control

API RP 555

PART 1-2-3 Process Analyzers’

API RP 556

Instrumentation and Control Systems for fired Heaters and Steam Generators

API RP 557

Guide to Advanced Control Systems

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API STD 598

Valve Inspection and Testing

API STD 670 Vibration, Axial Position and Bearing Temperature Monitoring System API RP 2001 Fire Protection in Refineries API STD 2000 Venting Atmospheric and Low-Pressure Storage Tanks Nonrefrigerated and Refrigerated API PUBL 2218 Fireproofing Practices in Petroleum and Petrochemical Processing Plants

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API MPMS

Chapter 1 Vocabulary

API MPMS

CHAPTER 2 Tank Calibration

API MPMS

Chapters 3.1B and 3.3 Automatic Tank Gauging

API MPMS

Chapters 4.1 to 4.8 Provers and Proving Systems

API MPMS

Chapters 5.1 to 5.8 Measurement by Meters

API MPMS

Chapter 6.1 Lease Automatic Custody Transfer

API MPMS

Chapter 6.6 Pipeline Metering System

API MPMS

Chapter 7 Temperature Determination

API MPMS

Chapter 14.1 and 14.3.1. to 14.3.4 - Natural Gas Fluids Measurement

2.4.

NFPA (National Fire Protection Association).

75

Standard for the Protection of Information Technology Equipment.

85

Boiler and Combustion System Hazards Code

101

Code for Safety to Life from Fire in Buildings and Structures.

496

Purged and Pressurized Enclosure for Electrical Equipment.

2.5.

IEC (International Electrotechnical Commission).

IEC 60300

Reliability and Maintainability Management

IEC 60300-1

Dependability Program Management

IEC 60300-2

Guidelines for Dependability Management

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IEC 60300-3 parts 1 to 14 Dependability and Reliability Management Programs IEC 60751

Industrial Platinum Resistance Thermometers Sensors

IEC 60770 parts 1 to 3 Transmitters for Use in Industrial-Process Control Systems IEC 61000 parts 2 to 4 Electromagnetic Compatibility IEC 61508

Functional Safety of Electrical/Electronic/Programmable Electronic Safety- Related System

IEC TR61131-8 Guidelines for the Application and Implementation of Programming Language IEC 61131-3

Programmable Controllers – Programming Languages

IEC 62453-1

Field-bus Device Toll (FDT) Interface Specification – Concepts and Description

IEC 62453-3

Field-bus Device Toll (FDT) Interface Specification – PROFIBUS

IEC 62453-4

Field-bus Device Toll (FDT) Interface Specification – HART

IEC 62453-5

Field-bus Device Toll (FDT) Interface Specification – Foundation Field-bus

IEC TR61158-1 Digital Data Communications for Measurement and Control Fieldbus for Use in Industrial Control System - Overview and Guidance over IEC 61158 IEC 61158 parts 2 to 6 Digital Data Communications for Measurement and Control E

E C E

IEC 61285

Industrial-Process Control – safety of Analyzers Houses

IEC 61784-1

Digital Data Communications for Measurement and Control

ISO/IEC 7498-1

Information Technology – Open Systems Interconnection - Basic Reference Model

IEC TR 61831 On-line Analyzer Systems – Guide to Design and Installation 2.6.

ANSI ( American National Standards Institute )

ANSI/FCI 70.2 - Standard for Control Valve Leakage Classification 2.7.

ASME (The American Society of Mechanical Engineers).

ASME B1.20

Pipe Threads, General Purpose.

ASME MFC-2M Measurement Uncertainty for Fluid Flow in Closed Conduits

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ASME MFC-3M Measurement of Fluid Flow in Pipes Using Orifice, Nozzle and Venturi ASME MFC-4M Measurement of Fluid Flow by Turbine ASME MFC-5M Measurement of Fluid Flow in Pipes Using Transient-Time Ultrasonic Flow-meters ASME MFC-6M Measurement of Fluid Flow in Pipes Using Vortex Flow-meters ASME MFC-7M Measurement of Gas Flow by means of Critical Venturi Nozzle ASME MFC-9M Method for Estimating Installation Effects on Flow-meters ASME MFC-14M Measurement of Fluid Flow by Coriolis Mass Flow-meter ASME MFC-16M Measurement of Fluid Flow by Electromagnetic Flow-meter ASME MFC-16M Measurement of Fluid Flow by Variable Area Meter ASME PTC 19.3 Instruments and Apparatus : Temperature Measurement ASME PTC 19.13 Determination of Rotary Speed ASME PTC 19.16 Density determination of Solids and Liquids ASME PTC 19.17 Determination of the Viscosity of Liquids Instruments and Apparatus

2.8.

ASTM (American Society for Testing and Materials).

E-119

Standard Test Methods for Fire Tests of Building Construction and Materials.

E

D 3764

Standard Practice for Validation of Process Stream Analyzers

E

2.9.

ISA (Instrumentation, Systems and Automation Society).

ISA 5.1

Instrumentation Symbols and Identification

ISA 5.2

Binary Logic Diagrams for Process Operations

ISA 5.3

Graphic Symbols for Distributed Control/Shared Display Instrumentation, Logic and Computer Systems

ISA 7.0.01

Quality Standard for Instrument Air

ISA 18.1

Annunciator Sequences and Specifications

ISA 20

Specifications Forms for Process Measurement and Control Instruments

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ISA 37.16.01 A Guide for the Dynamic Calibration of Pressure Transducer ISA 50.00.01 Compatibility of Analog Signals for Electronic Industrial Process Instruments ISA 50.02Parts 2,3,4,5 e 6 Fieldbus Standard for Use in Industrial Control Systems ISA 71.01

Environmental Conditions for Process Measurement and Control Systems : Temperature and Humidity

ISA 71.02

Environmental Conditions for Process Measurement and Control Systems : Power

ISA 71.03

Environmental Conditions for Process Measurement and Control Systems : Mechanical Influences

ISA 71.04

Environmental Conditions for Process Measurement and Control Systems : Airborne Contaminants

ISA 75.01.01

Flow equations for Sizing Control Valves

ISA 75.02

Control Valve Capacity Test Procedure

ISA 75.05.01

Control Valve Terminology

ISA 75.08

Installed Face-to-Face Dimensions for Flanged Clamp or Pinch Valves

ISA 75.08.01

Face-to-Face Dimensions for Integral Flanged Globe-Style Control Valve Bodies (Classes 125, 150, 250, 300 and 600)

ISA 75.08.02

Face-to-Face Dimensions for Flangeless Control Valves (Classes 150, 300 and 600)

ISA 75.08.03

Face-to-Face Dimensions for Socket Weld-End and Screwed-End Globe-Style Control Valves (Classes 150, 300, 600, 90, 1500 and 2500)

ISA 75.08.05

Face-to-Face Dimensions for Butweld-End Globe-Style Control Valves (Classes 150, 300, 600, 900, 1500 and 2500)

ISA 75.08.06

Face-to-Face Dimensions for Flanged Globe-Style Control Valve Bodies (Classes 900, 1500 and 2500)

ISA 75.08.07

Face-to-Face Dimensions for Separable Flanged Globe-Style Control Valves (Classes 150, 300 and 600)

ISA 75.08.09

Face-to-face Dimensions for Sliding Stem Flangeless Control Valves (Classes 150, 300 and 600)

ISA 75.11.01

Inherent Flow Characteristic and Rangeability of Control Valves


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ISA 75.08.13

Method of Evaluating the Performance of Positioners with Analog Input Signals and Pneumatic Output

ISA 75.17

Control Valve Aerodynamic Noise Prediction

ISA 75.19.01

Hydrostatic Testing of Control Valves

ISA 75.22

Face-to-Centerline Dimensions for Flanged Globe-Style Angle Valve Bodies (ANSI Classes 150, 300 and 600)

ISA 75.23

Considerations for Evaluating Control Valve Cavitation

ISA 75.25.01

Test Procedure for Control Valves

ISA 75.26.01

Control Valve Diagnostic Data Acquisition and Reporting

ISA 77.20

Fossil Fuel Power Plant Simulator

ISA 84.00.01

Parts 1, 2 and 3 – Functional Safety : Safety Instrumented System for Process Industry Sector

ISA 88.00.02

Batch control part 2- Data Structures and Guidelines for Language

ISA 88.00.03

Batch control part 3- General and Site Recipe Models and Representation

ISA 88.00.04

Batch control part 4- Batch Production Records

ISA 88.01

Batch control Part 1 – Models and Terminology

ISA 95.00.01

Enterprise-Control System Integration Parts 1, 2 and 3

ISA TR99.00.01 Security Technologies for Manufacturing and Control Systems ISATR99.00.02 Integrating Electronic Security into the Manufacturing and Control Systems Environment ISA 100.11a

Wireless Industrial Automation Network

ISA 60079-0

Electrical Apparatus for Use in Class 1, Zones 0,1 and 2 Hazardous Locations : General Requirements

ISA 60079-1

Electrical Apparatus for Use in Class 1, Zone 1 Hazardous Locations : Type of Protection Flameproof “d”

ISA 60079-5

Electrical Apparatus for Use in Class 1, Zones 1 Hazardous Locations : Type of Protection Powder Filling “q”

ISA 60079-6

Electrical Apparatus for Use in Class 1, Zones 1 and 2 Hazardous Locations : Type of Protection Oil Immersion “o”

ISA 60079-7

Electrical Apparatus for Use in Class 1, Zones 1 and 2 Hazardous Locations : Type of Protection Increased Safety “e”


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ISA 60079-11 Electrical Apparatus for Use in Class 1, Zones 0, 1 and 2 Hazardous Locations : Intrinsic Safety “i” ISA 60079-15 Electrical Apparatus for Use in Class 1, Zone 2 Hazardous Locations : Type of Protection “n” ISA 60079-7

Electrical Apparatus for Use in Class 1, Zones 1 Hazardous Locations : Type of Protection Encapsulation “m”

ISA MC96.1

Temperature Measurement Thermocouples

2.10. IEEE (Institute of Electrical and Electronic Engineers). IEEE 802.3

Standard for Local and Metropolitan Area Networks – CSMA/CD

IEEE 802.11-A and B

Standards for Local and Metropolitan Area Networks – Wireless LAN

2.11. MSS (Manufacturers Standardization Society of the Valve and Fittings Industry Manufacturers Association). MSS SP-72

Ball Valves With Flanged or Butt-Welding Ends for general Service

MSS SP-99

Instrument Valves

2.12.

NAMUR

NE 107-“Self-monitoring and Diagnosis of Field Devices”. 2.13. NR (Normas Regulamentadoras de Segurança e Saúde no Trabalho Ministério do Trabalho e Emprego). NR 10

Instalações e Serviços em Eletricidade.

NR-13

Caldeiras e Vasos de Pressão.

NR 15

Atividades e Operações Insalubres – Anexos 1 e 2.

NR16

Atividades e Operações Perigosas.

NR 17

Ergonomia.

NR-18

Condições e meio ambiente de trabalho na indústria de construção.

NR-23

Proteção contra incêndios.

NR-26

Sinalização de segurança.


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2.14. ISO (International Organization for Standardization). ISO 11064 Parts 1,2,3,4 and 6 Ergonomic Design of Control Centers

2.15. EIA (Electronic Industries Association) . EIA/TIA RS-232 Interface Between Data Terminal Equipment and Data communication Equipment Employing Serial Binary Data Interchange EIA/TIA RS-422 Electrical Characteristics of Balanced Voltage Digital Interface Circuits Balanced Digital Multipoint Systems EIA/TIA RS-485 Electrical Characteristics of Generators and Receivers for use in Balanced Digital Multipoint Systems

2.16. EEMUA (The Engineering Equipment and Materials Users Association). E

Publication 138

Design and Installation of On-Line Analyzers System

Publication 191

Alarms Systems – A Guide to Design, Management and Procurement

Publication 201

Process Plant Control Desks Utilizing Human-Computer Interfaces

2.17. UL (Underwriters Laboratories) . UL 2196

Safety Tests for Fire Resistive Cables

UL 1709

Fire proofing Pratices in Petroleum and Petrochemical Processing Plants

2.18. Open Connectivity Organization (OPC). OPC UA parts 1 to 11 Unified Architecture – Concepts, Services, Data Access, Profiles, Historical Data, Alarms and Security

2.19. Fieldbus Foundation (FF). FF-103

Common File Format

FF-131

Standard Tables

FF-569

Host Interoperability System Test Procedures


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FF-593

High Speed Ethernet Redundancy

FF-581

System Architecture

FF-586

Ethernet Presence

FF-588

Field Device Access (FDA) Agent

FF-589

HSE System Management

FF-801

Network Management Specification

FF-803

HSE Network Management

FF-806

Data Link Protocol Specification Bridge Operation Addendum

FF-816

31.25 kbit/s Physical Layer Profile Specification

FF-821

Data Link Layer Services Subset Specification

FF-822

Data Link Layer Protocol Specification

FF-880

System Management Specification

FF-870

Fieldbus Message Specification

FF-875

Fieldbus Access Sublayer Specification

FF-890

Function Block Application Process - Part 1

FF-891


FF-892


FF-893


FF-894


FF-900

Device Description Language Specification

FF-940

31.25 kbit/s Communication Profile

FF-941

HSE Communication Profile36

2.20. INMETRO ( Instituto Nacional de Metrologia, Normalização e Qualidade Industrial). Portaria número 83 do INMETRO Regulamento de Conformidade de Equipamentos Elétricos para Atmosferas Potencialmente Explosivas, nas Condições de Gases e Vapores Inflamáveis


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2.21. AGA ( American Gas Association) Report 3 P1 Orifice Metering of Natural Gas and Other Related Hydrocarbons Fluids – part 1 – General Equations and Uncertainty Guidelines Report 3 P2 Specifications and Installation Requirements 3.

DEFINITIONS

a) MCC –Acronym of Motor Control Center. The electrical equipment responsible for the electrical motors protection and control. b) CEMS – Acronym of continuous emissions monitoring systems that is the complete systems for monitoring toxic gas emissions with origin in the furnaces, heaters and boilers. c) CIC – Portuguese acronym of “Casa Integrada de Controle” that means Integrated Control Center. From that house the operators supervise and operate all refinery process and utility units. The main equipment located in it is the DCS human machine interface. d) DCS – Acronym of Distributed Control System. System responsible for process data acquisition, control and disposal of process unit information to operator for supervision. e) EMED – Acronym for custody measurement station that is the set of equipment with controlled accuracy responsible for the measurement of liquid and products to be sold to third party. f) FF – Acronym of Foundation Fieldbus. g) HMI – Acronym of Human Machine Interface. h) LCP – Acronym of Local Control Panel. Local Control Panel is any instrumentation control panel, other than Remote I/O, located at field with control, interlock and/or process data acquisition purpose for a specific process systems or equipment. That panel can contain a PLC and any other specific equipment as well as a human machine interface (HMI). i) LP - Acronym of Local Panel. Local Panel is any instrumentation panel, located at field with the purpose to provide operator’s local supervision of a specific process systems or equipment through a Human Machine Interface (HMI). That panel has not any control or interlock function, but can contain an independent instrument or equipment with it purpose that was installed in it just making good use of the available enclosure. j) MC – Acronym of Marshalling Cabinet. Marshalling Cabinet is located at CCL and is used to re-arrange the cables coming from the field to match the wiring terminations of DCS controllers, PES or RCP. k) PASE – Acronym of “Protection and Automation of Electrical System”. The PASE is the equipment responsible for protection, load shedding and motor acceleration.


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l) PES – Acronym of Programmable Electronic System. Certified equipment developed to be applied as logic solver of a SIS. m) PLC – Acronym of Programmable Logic Controller. Equipment responsible for control and data acquisition of a specific system or equipment. n) RCP - Acronym of Remote Control Panel. Remote Control Panel is any instrumentation control panel, other than DCS and PES, located at CCL with control, interlock and/or process data acquisition purpose for a specific process system or equipment. That panel can contain a PLC and any other specific equipment as well as a human machine interface (HMI). o) RUPS – Acronym of Redundant Uninterruptible Power Supply. Is a full redundant uninterruptible power supply for 120Vac. E

p) CCL – Portuguese acronym of “Casa de Controladores Local” that means Local Controllers Room. That room shelter the main instrumentation equipment that interfaces the field instrumentation, of one or more process unit, for control and data acquisition purpose. q) SIL - Acronym of Safety Integrity Level. r) SIS – Acronym of Safety Instrumented System. System composed of sensors, logic solver, and final control elements for the purpose of taking the process to a safe state when a predetermined condition is violated. s) STVM – Portuguese acronym of “Sistema de Telecomando de Válvulas Motorizadas” that means Motor Operated Valve System. System composed of motor operated valves with smart actuators connected through a network for data acquisition and control purpose. That system is connected to DCS. t) TGS – Acronym of Tank Gauging System. System composed of smart level and temperature measurement instruments connected through a network for process data acquisition purpose. That system is connected to DCS. u) VCD – Portuguese acronym of Via de Comunicação de Dados – Data Communication Route that means the fiber optics routes for connecting parts of the digital networks DCS, SCMD , PLC Remote Maintenance Network, Monitoring Vibration of Machines and HART Asset Maintenance Network. v) VSD – Acronym of Variable Speed Driver.

4. E

ENGINEERING UNITS

The units of the process variables to be adopted to principals measurements are the following ones:

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Process Variable

Unit

Temperature

o

Flow (volumetric liquid)

m3/h (water) or m3/d @ 20o C

Flow (mass liquid)

Kg/h

Flow (Steam)

t/h

Flow (Gas)

m /h corrigido @ 1atm e 20C

Pressure

Kgf/cm

Vacuum and Low Pressure

mmH2O

Vacuum and Low Pressure

mm H2O (blowers’ discharge, vacuum in heaters and boilers) and mm Hg (in condensers)

Level

0 – 100 (%)

Density

kg/m

Viscosity

Cp

C

E E

E 3

2

E 3

Others variables to be measure shall follow the SI – Sistema Internacional de Unidades, published by INMETRO. 5.

INSTRUMENTATION DESIGN CRITERIA

5.1.

GENERAL CONDITIONS

5.1.1 This document is not intended to define the scope of work but only general criteria for detailing. In case of doubt, PETROBRAS shall be consulted at all times. 5.1.2 The development and presentation of the instrumentation and automation design shall comply with the standards listed beneath. a) presentation of design as per NI-1883; b) detailing of instrument and automation design as per NI-1882; c) detailing of underground networks as per N-1996; d) detailing of cable tray systems as per NI-1997; e) detailing of SIS units design as per N-2595; f) instruments identification as per ISA SP 5.1; g) codified numeration of the engineering technical documents as per N-1710;


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5.1.3 For the purchase of instruments and automation equipments the data sheets standardized in the PETROBRAS standards shall be used, as well as the associated specifications. 5.1.4 For the purchase of materials, the data sheets standardized in the PETROBRAS standards shall be used, where applicable.

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5.1.5 Equipment and materials shall be chosen bearing in mind the classification of areas and the conditions of aggressiveness of the surroundings, at the installation site. In places subject to intense humidity, provision shall be made for drains in the casings of panels for outdoor installation. The requirements of Standard ABNT NBR-5410 shall be considered. Electronics parts of the instruments and panels shall be protect against fungus due the possibility of the humidity or condensate happening. 5.1.6 The detail designer shall issue the whole of the documents stipulated in standard NI-1883, observing the minimum degree of detailing and the form of presentation of information called for therein. The fact that similar documents will be issued by equipment suppliers does not do away with the need for issuance of these items by the detailing designer. 5.1.7 Data Sheets, Technical Specifications and Materials Requisitions (RM) supplied by PETROBRAS as an integral part of the documentation issued for contracting purposes shall not be used directly for the purchase of instruments. 5.1.8 Except for the PETROBRAS standards and drawings referring to installations already in existence, no technical document on instrumentation and automation supplied by PETROBRAS shall be used over or directly revised by the detailing designer. All documents shall necessarily be issued by the detailing designer and shall include all contractual technical requirements. 5.1.9 When the design is developed for locations where there are PETROBRAS industrial facilities already constructed that have interfaces with this project, the following requirements shall be met: a) existing documents shall be revised and the whole of the remaining correlated documents affected by the revision shall also be updated, even if this means merely the inclusion of a reference; b) where there is lack of space or legibility in design documents already existing, or yet incompatibility of those with projects issued with the use of the computer, new documents shall be issued. These new documents, besides including the new information, shall consolidate the information existing in prior projects so as to avoid the need for consulting a number of documents to obtain a given piece of information; c) the designer shall conduct a complete field survey to develop the project, checking, amongst other items, the following factors: - actual situation of the installations and interferences that shall be avoided or overcome;


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- availability of existing installations (for example : spaces for enlargements), including issuance of a notice to PETROBRAS in case some specification prepared by the latter needs to be modified as a result of a field survey and the execution of the detailed design; -

all existing drawings involved to be revised.

5.1.10 Where applicable, the criteria and solutions adopted in the detailed design and in the selection of materials shall be compatible with the usual solutions adopted in the existing facilities. 5.1.11 Basic guidelines related to safety and health established in the Regulatory Standard NR 10 of “Ministério do Trabalho e Emprego – MTE” (Labor and Employment Ministry), shall be applied to the instrumentation and automation power supply design. 5.1.12 CONTRACTOR shall issue and furnish to PETROBRAS a Technical Appraisal, elaborated by a qualified Electrical Engineer, attesting that all the materials, equipment, project services, assembly services and the instrumentation and automation power supply system installed are in accordance with the requirements of the Regulatory Standard NR 10 of MTE and the ABNT Standards, mainly the Standard NBR 5410 Instalações Elétricas de Baixa Tensão . E

5.1.13 The CONTRACTOR shall generate the documentation electronically using a integrated Computer Aided Design – CAE software

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5.1.14 The use of programs Autodesk AutoCAD and Microsoft, ACCESS, EXCEL and WORD for WINDOWS, last versions can be used, since they are authorized by PETROBRAS, in writing. 5.1.15 The BID analysis of the following instruments shall be submitted to the approval of PETROBRAS: - analyzers; (conductimeters, chromatograph, densimeters, viscometers, photometers, etc);

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- pressure, differential pressure and temperature transmitters (applied to Level, Flow or Pressure measurement); - control valves and valve positioners; - shut-off valves and solenoid valves;

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- EIV, Emergency Inventory control Valve; - safety valves; - programmable logical controllers (PLC’s); - intelligent electric actuators - STVM;


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- radar or servo-operated level meters- TGS; - distributed control system - DCS; - programmable electronic system - PES; - server computers, switches, routers and firewalls; - advanced control software, reconciliation production data software, historical production data software, process alarm management software, control loop tunning and auditing software; - combustion emissions monitoring system – CEMS; - custody and transfer measurement station – EMED; - Dynamic Process Simulator; - Automated System for Selling Products.

5.2.

INSTRUMENTS IDENTIFICATION

5.2.1 Each instrument or Loop function shall be identified by an alphanumeric code or TAG classifying it functionally and sequentially, in accordance with ISA 5.1 Standard and I-DE-6000.67-0000-941-PDY-001 Standards drawings and specifications piping service & special identification. 5.2.2 To facilitate the use of data banks the following pattern for identification of instruments shall be followed: ID_FUNC v m

ID_LOOP

f f f

ID_FUNC v m fff

= = = =

SUFIX

- a a a a n n n Functional Identification (maximum 5 characters); Measured variable or starter (1 character) ; Modifier letter or variable (1 character); Function of instrument;

ID_LOOP = Identification of the loop (7 numbers) – Based on a range established by PETROBRAS; aaaa = area or unit – 4 digits; nnn = sequential number of loop; SUFFIX (optional) = letter used to differentiate instruments with the same functional and loop identification.


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5.2.3. For each process variable beginning with letter of ISA 5.1 table, sequence shall have all the range from 001 to 999. Instruments for the same service shall use the same sequential and a letter sufix. E

5.2.4 Exceptionally at 3200 area, the tag numbering shall be according to following rule: The main area - 3200 - will be break according to the next sub-areas: 3210 Feed Pre-heat and Furnaces 3220 Primary Fractionation and Quench 3230 Cracked Gas Compression (includes the Depropanizers, The Hydrogenation reactors, the Dehydrators and the Caustic tower) 3240 Cold Fractionation (Demethanizer, Deethanizer and C2 Spliter) 3250 Hot Fractionation ( C3 Spliter and Debutanizer) 3260 Refrigeration Systems 3270 spent Caustic Treatment 3290 Utilities 3550 C4 Hydrogenation 3600 Butadiene Extraction The construction of the instrument numbering criteria (tag number) shall be modified as: General tag construction = XX-AABBCCCDE, where: XX from 2 to 5 letters to identify instrument type, AA 2 numbers to identify the unit main part of the unit number 32, BB the subsystem identification, as showed on “a” sub item above, CCC serial number, 3 digits is mandatory, from 001 to 999, D suffix identification, 1 letter if necessary, it’s prohibited to a hyphen before suffix, E suffix modifier, 1 number, only if necessary;

5.2.5. Control and safety loops using the same primary element, such as orifice plate, the whole loop shall use the same sequential with letter suffix. In case of distinct instruments for control and safety loops at the same point, those for control shall have different tagging from those for safety. 5.2.6. Valve position transmitters, switches and indicators shall use the same number of the valve, with the inclusion of a letter suffix when required. The duplicity in other process variable shall be verified at the moment of use of ZS´s. 5.2.7. TAG number for motorized and electric-hydraulic valves shall be consistent with their respective loop.


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5.2.8 if the identification cannot be held down to 14 characters due to the limitations imposed by the Digital System, reduce the number of characters used for functional identification. The following fields shall appear in the structure of the data banks: Field TAG UNIT ID FUNC / LOOP SUFFIX

Number of Characters 14 4 9 2

How it is filled in normal TAG; adapted TAG; adapted TAG; adapted TAG.

b) Examples of functional identifications: • Transmitters and valves: FT, LT, PDT, TT, LV, PV; • Converters: TY, LY, PY; • Indicators: FI, FFI, PDI, PI, TI, LI, AI, DI, CI; • Controllers: FC, FFC, PDC, FQC, IDC, TC, PC, AC, FFC; • Alarms: PAH, PAHH, PDALL, PAL, ZAL, ZAH; • Positioners: ZT, ZSL, ZSH, ZLL, ZLH; Note : In undefined cases, modifying letters H and L shall not be used. Hand switches are HS or HMS (instantaneous). 5.3.

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DESIGN DOCUMENTATION

The technical documentation that shall constitute the instrumentation detailed design, is that defined in PETROBRAS Standard NI-1883, which shall be integrally followed. See the minimum of documents but not restricted at the table below. ITEM

DOCUMENT

1 2 3 4 5 6 7 8 9 10 11 12 13 14

BASIC DESIGN PROCESS FLOW DIAGRAM (DE) PROCESS DATA SHEET (FD) CAUSE AND EFFECT MATRIX (DE) PRELIMINARY LIST OF INSTRUMENT (LI) PRELIMINARY ENGINEERING FLOW SHEET (DE) SAFETY LOOP CLASSIFICATION REPORT INSTRUMENTATION DESIGN CRITERIA (ET) LOGIC DIAGRAM (DE) SYSTEM ARCHITECTURE (DE) DATA SHEET FOR SPECIAL INSTRUMENTS (FD) TECHNICAL SPECIFICATION FOR SPECIAL SYSTEMS (ET) PROCESS CONTROL DIAGRAM (DE) CONTROL LOOP DESCRIPTION (MD) DESCRIPTIVE MEMORANDUM FOR INSTRUMENTATION SYSTEM (MD)

1 2 3 4

DETAILED DESIGN PROJECT SCHEDULE (CR) LIST OF DESIGN DOCUMENTS (LD) LIST OF INSTRUMENTS (LI) LIST OF CABLES (LI)


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DESIGN CRITERIA – INSTRUMENTATION AND AUTOMATION 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39

LIST OF MATERIALS (LI) LIST OF SETPOINTS (LI) LIST OF ALARMS (LI) LIST OF INPUTS AND OUTPUTS (LI) COMMUNICATION LIST ( LI ) TECHNICAL SPECIFICATION FOR SUPERVISORY AND CONTROL SYSTEM (ET) TECHNICAL SPECIFICATION OF SAFETY INSTRUMENTED SYSTEM (ET) CALCULATION SHEET FOR SIZING PRIMARY FLOW ELEMENTS (MC) CALCULATION SHEET FOR SIZING CONTROL VALVES (MC) CALCULATION SHEET FOR SIZING RELIEF AND SAFETY VALVES (MC) PIPING AND INSTRUMENTATION DIAGRAM (DE) INSTRUMENT MATERIAL SPECIFICATION (ET) ELECTRICAL INTERCONNECTION DIAGRAM (DE) CONTROL ROOM LAYOUT PLAN (DE) PNEUMATIC INSTRUMENTATION PLAN (DE) ELECTRICAL INSTRUMENTATION PLAN (DE) PLAN SHOWING ROUTING OF MULTI-CABLES IN CONTROL ROOM (DE) LOOP DIAGRAM (DE) LOGIC DIAGRAM (DE) PROCESS INSTALLATION DETAIL (DE) PNEUMATIC INSTALLATION DETAIL (DE) ELECTRICAL INSTALLATION DETAIL (DE) FUNCTIONAL DIAGRAM (DE) LIST OF ELECTRICAL LOADS FOR INSTRUMENTATION (LI) GENERAL ASSEMBLY DETAILS (DE) SUPERVISORY SYSTEM ARCHITECTURE DRAWING (DE) INSTRUMENT DATA SHEET (FD) MATERIAL REQUISITION (RM) TECHNICAL REPORT (PT) DOCUMENTATION ISSUED BY MANUFACTURERS MANUFACTURING SCHEDULE EQUIPMENT, INSTRUMENT OR MATERIAL DRAWINGS LIST OF DOCUMENTS TEST REPORTS CERTIFICATES

The following items contain the modifications, inclusions and observations that shall be applied to documents. 5.3.1. LIST OF INSTRUMENTS E

Form : A3 - standard NI-2833; by engineering program output, spread sheet or data base; Notes : a) the instruments shall be grouped by variable in alphabetical order, for loop nº. in the ascending order and according to item 5.2.2; b) it shall include all instruments of the Unit, including those of “Package Unit”, c) the documents shall only be included in the list after its issuance;


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d) for instruments for which no documents will be issued (process/pneumatic/electrical details, loop diagram, etc.) the respective column shall be filled out with a line; e) the instrument list shall show the current situation of the project, being revised whenever a listed document is revised. 5.3.2. CONTROL ROOM LAY-OUT PLAN Form : A2 to A0 – standard N-381 Notes: a) all equipment shall be represented including the future ones; b) the equipment shall be represented in scale and with the indication of the maximum height; c) space shall be allowed for circulation, equipment inlet and outlet, maintenance, view of the process unit, etc; d) it shall be showed section views of the arrival of cables, of trenches, etc; e) the auxiliary systems shall be indicated (battery, telecommunications, conditioned air, pressurization, etc.); f) reference documents shall be listed. 5.3.3. ARRANGEMENT AND DETAILS OF PANEL AND / OR CONTROL DESK Form: A2 to A0 - standard N-381 Notes: a) the panel type shall be in accordance with the guidelines of the project; b) the layout of the instruments, commands and signals shall follow the main flow of the process; c) all instruments, commands, signals and tags shall be identified; d) the heights of the instruments, commands, etc., shall be identified; e) the tag inscriptions shall be identified; f) a detail of the panel fixture shall be indicated; g) a list of reference documents shall be indicated. 5.3.4. LOGIC DIAGRAM Form : A3 – standard N-381


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Notes: a) the used symbols shall be defined in a “symbols sheet”, according to Code ISA 5.2; b) all indicated events in the cause and effect diagram and / or in the descriptive memorial shall be indicated in the diagram; c) reference documents shall be listed. 5.3.5. FUNCTIONAL DIAGRAM Form : A3 – standard N-381 Notes : a) symbols shall be in accordance with standard N-898; b) electrical supply for instruments shall be indicated along with their switches, fuses and terminals; c) the physical connection of the logic shall be indicated whenever it is executed by relays, showing field switches, terminals, relays and final elements; d) when a relay is indicated, the contacts of this relay shall be identified related to its position in the functional diagram , through table of addresses in the same vertical of its coil. 5.3.6. LOOP DIAGRAM Form : A3 – standard N-381 Notes: a) pneumatic local loops that does not passes through junction boxes shall not be represented in this diagram , because it would be a repetition of the pneumatic installation detail; b) it shall be represented in the document the symbols system and codification; c) instruments and terminals shall be located in columns according to its location (field, junction box, rack, behind the panel, front of the panel, etc.); d) the cables, multi-cables, junction boxes, terminals, strips of terminals, number of the section of the panel, etc, shall be identified; e) the electrical supply of the instruments, with its switches, fuses and grounding bar shall be represented; f) indicate cables and multi-cables shields insulated next to the instrument and to the cabinets of the DCS, respectively;


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g) indicate general shields of the multi-cables originated in the field and of the cabinets of DCS connected in the grounding bars of the marshalling cabinets, for analog, thermocouple and digital signals; h) for analog signals diagrams, the individual shields of the individually connected pairs / terns shall be indicated in the terminals (terminals A and B in the marshalling cabinets) or alternatively in the vertical grounding bars (also individually) in the marshalling cabinets, for both the pairs / terns originated in the field as for those originated in the DCS or PES; i) the CONTRACTOR shall prepare the complete loop diagram, filling out the applicable information related to the DCS, such as: terminals, location, logical address based in the information generated by the configuration team; j) it is in the scope of the CONTRACTOR responsible for the detail design , the interconnecting design FIELD/DCS in the terminals marshalling cabinet based on Loading Table defining the connections in the DCS; l) it is in the scope of the CONTRACTOR responsible for the detail design , the interconnecting design FIELD/PES in the terminals marshalling cabinet based on Loading Table defining the connections in the PES; m) it is within in the scope of the CONTRACTOR responsible for the activity of construction and assembly the interconnection FIELD/DCS in the terminals of marshalling cabinet; n) it is within in the scope of the CONTRACTOR responsible for the activity of construction and assembly the interconnection FIELD/PES in the terminals of marshalling cabinet; m) it shall contain TAG’S index sheet. o) a loop diagram design with H1 Foundation Fieldbus segments shall be as the following examples: - General notes and symbols.


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- FIRST PART: Segments per gateway H1 to HSE with junction boxes and devices.

-

SECOND PART :Loop diagram

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5.3.7. LOCATION DISTRIBUTION

PLAN

FOR

PNEUMATIC

INSTRUMENTS

AND

AIR

Form : A2 to A0 – Standard N-381

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The location plan for pneumatic instruments and air distribution shall be extract by the 3D model – PDMS design. The ground of drawing shall have the equipments and principals pipes with the valves on their real positions. The equipments and pipes shall be represented with a thin line in a light gray scale and the instruments, instrument air distribution pipes and accessories shall be represented with a strong line to intent a contrast among then. Notes:

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a) the scale of the drawing and its limits preferably shall be the same of the equipment layout plant. The scales 1:50, 1:331/3, 1:25 can be used depending on the largest or smaller complexity of the drawing; b) the drawing shall include reference, axis, structure, equipments and principals points such as battery limits, grade, adjacent drawings, etc; c) the symbols used in the identification of the instruments shall be identified; d) the design north arrow shall be indicated on the drawing;


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e) in case there are more than two drawings, a key plan shall be represented on the title block of the drawing with the location of the respective drawing hatched; f) it shall be identified the elevation of the instruments and air distribution pots ;

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g) it shall be identified on the drawing data such as width of the pipes and trays, elevations, elevation changes, quantity and identification of the tubes and multi-tubes in the tray, size of the pipes, etc.;

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h) individual tubes of signal transmission shall be directed through reinforced fiberglass channel (perforated);

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i) a list of materials shall be referred on the reference documents also containing the materials for supports in addition to those used in the Mounting and air distribution system ; j) represent the main air line and their extensions with their respective diameters, instrumentations tie-ins and elevations;

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k) reference drawings shall be listed; E

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a) air distribution pots shall be design with a block and drain valves, listed their consumers, two types will be applied: a. type 1 prepare for 6 consumers and their respective block valve and let one spare outlets . b. type 2 prepare for 12 consumers and their respective block valve and let two spare outlets . m) installation between air distribution pots and consumers shall be represented on the pneumatic hook ups;

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n) specials consumers shall be detailed on the plan;

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5.3.8. LOCATION PLAN FOR ELECTRIC INSTRUMENTS, LOCALS PANELS, SPECIALS SYSTEMS AND CABLES ROUTING Form : A2 to A0 – standard N-381

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The location plan for electric instruments, locals panels, specials systems and cable routing, shall be extract by the 3D model – PDMS design. The ground of drawing shall have the equipments and principals pipes with the valves on their real positions. The equipments and pipes shall be represented with a thin line in a light gray scale and the instruments, panels, junction boxes, cable trays, conduits, specials instruments and accessories shall be represented with a strong line to intent a contrast among then. Notes:


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a) the scale of the drawing and its limit preferably shall be the same of the equipment layout plant. The scales 1:50, 1:33 1/3 and 1:25 can be used depending on the largest or smaller complexity of the plant; E

b) the drawing shall include reference, axis, structure, equipments and principals points such as battery limits, grade, adjacent drawings etc; c) the symbols used in the plant shall be identified; d) the design north arrow shall be indicated on the drawing; e) in case there are more than two drawings, a key plan shall be represented on the title block of the drawing with the location of the respective drawing hatched;

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f) it shall be indicated the elevation of the instruments, junction boxes, local panels, specials instruments, electrical conduits, cable trays and specials items represented on this drawing; g) it shall be identified on the drawing data as size and cables in the conduits, width and service of the cable trays, signal type, quantity and identification of cables and multicables, elevations and changes of elevations, junction boxes, locals panels, specials items, etc.; h) electronic signal cables shall be separated from the electrical sources according to the indicated distance in API RP 552; i) the electrical equipment installation shall be in accordance with the electric classification area; j) the symbols and coding of the electrical instalation shall be made according to N-298;

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k) The cables and multi-cables routing, in the field, shall be made through according to follow rules:

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1. Main cable routing – cable trays with 200mm minimum width, installed along to main pipe-rack, interconnecting areas and/or linking equipments inside the areas as: I. from junction boxes to local control room, II. from Local control to CIC. III. from Local panels to local control room, IV. networks

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2. Secondary cable routing – cable trays, with 100mm minimum width, installed inside the areas, at auxiliary pipe racks and structure to interconnecting internals instruments and components : I. from instruments to junction boxes II. from Local panels to junction boxes. III. from Local power supply panels to local consumers,


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The maximum width allowed for the cable tray shall be 600mm, the height shall be 100mm, The bend radius shall be 300mm

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3. Tertiary cable routing – Aluminum conduits, from ¾ to 2 inch size, to carry cables from cable trays to instrument or equipment, This kind of installation shall be applied to carry and distribute signals in the area.

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l) The cables shall be connected to the instruments and to the junction box through cable-press, at the end of the conduit shall be applied a bush to protect the cable; m) at least 3 different signal levels, far between 400 mm of distance trays with the following signal distribution shall be considered: 1ª tray: electronic signals (4-20 mA) and thermocouple 2ª tray: digital signal as Foundation Fieldbus, RS-485, RS-232 3ª tray: discrete signals – 24 Vdc and feed for instruments (24Vdc)

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Duplicated level of cable trays can be considered when the great number of cables requires, n) The fiber optics shall be mechanically protected, installed in aluminum conduits, running beside at the cable trays, the redundant route shall be installed in a alternative way, avoid to lost of the communication in case of accident. o) Avoid installing cable tray systems in regions with high fire-potential equipments, as defined in API 2218. In those cases in which routing cannot be avoided (see sections 5.2.1 up to 5.2.5, sections 9 and 10 of this standard), additional protection shall be installed for the cable tray system using covers resistant to direct hydrocarbon fire such as protective blankets or paint systems with fire-retardant characteristics dependent on Petrobras approval, in accordance with this Standard and the cable shall be calculated for this kind of installation.; p) as basic criteria cables trays near these great an medium fire risk area shall be avoided; q) the junction boxes shall be identified in the following way: CJ (A)-(B) (C) where: A D F T X

(A) signal type

Analog signals Digitals signals Digitals signals Low Level Power supply

4-20mA, electronic instruments 24 VDC, discrete instruments Fieldbus Foundation instruments Temperature instruments (mV or ohm) 120 Vac Instruments feeds

(B)

- number of the Unit (primary element)

(C)

- sequential number of the junction box unit


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r) the junction boxes shall be located preferably in areas of little electrical noise and of good natural illumination, considering the load distribution and whenever possible out of the electrical classified area; mounted at a structural steel rack in a easy access area.

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s) the inlet to the CCL shall be made through aerial cable trays;

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t) consider 30% of spare pairs / terns in the multi-cables from the junction boxes in the field to the marshalling cabinets. These spare pairs / terns shall be connected to the terminals in both, marshalling cabinets and junction boxes, In the marshalling cabinets and junction boxes there shall be plus 20% of spare terminals over the pairs / terns effectively connected; u) as criterion for grouping the signals of the multi-cables originated in the junction boxes there shall be, segregation by signal type and function, analog and digital signals of the same voltage level, terminal for solenoid, etc.) facilitating, this way, the marshalling to be done at the control room; at CJD’s, connecting digitals inputs and outputs shall be segregated in different terminals blocks and different multi cables. v) the electric feed cables for instruments 120 Vca, shall always be segregated of the signals cables; x) this document can be incorporated to the pneumatic routing plan , provided it will not be too congested; y) each VCD of the digital networks DCS, PES and Asset Management designed in different documents.

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shall be

z) The cable color code below shall be followed to facilitate the identification during the construction, maintenance and future expansion. Signal type

Analog signals

Instrument Type Explosion proof instruments Intrinsically safety instruments

Over jacket color Black Blue

Thernocouple signals

According to ISA/ANSI MC-96.1

RTDs signals

Black

Digitals signals

24 VCC

Black

Fieldbus Fundation signals

FF instruments network

Orange

Profibus signals

Profibus network

Violet or purple

Hard wired cables

By MAC

Fiber optics cables

By MAC

Power supply

Instruments and panels

Black

Fire and Gas signals

Fire & Gas Systems

Black

Temperature signals

Industrial Network


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5.3.9. PLAN SHOWING PANELS AND CABINETS POSITION AND ROUTING OF MULTI-CABLES IN CONTROL ROOM Form: A2 to A0 - standard N-381 Notes:

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a) This draw could be extract from 3D-model or drawn in 3D-CAD with the same coordinates (reference point) of the CCL on the 3D-model, the routing of the cables inside the control room shall be done through cable trays, aerial, under false floor or areas being allowed according to the design guidelines. The electric conduits use is only allowed to network route; b) The draw shall show the route of cable trays in plan, view and details, cabinets and panels lay-out, interconnection with others draw indicating the cables and multi-cables coming to CCL. c) the cable trays and / or electric conduits shall be independent according to the level of signal. The separation of the cables shall be as described in API RP 552;

d) the grounding point for the instruments and cables shall be exclusive, and the connection of this point to the grounding bars shall be done by insulated and independent cables for each bar according to API-550 and NI-1882; e) The cabinets, panels and cable tray shall be grounded at electrical ground at the CCL;

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f) a summary of the material used for the assembly shall be included (trays, supports, etc.); g) The cable tray inside CCL, shall be perforated type and fabricated in carbon steel hot dip galvanized,

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h) The cabinets and panel shall be fixed in the carbon steel structural support; 5.3.10.CABLES / MULTICABLES LIST AND INTERCONNECTION DIAGRAM Form : A3 – standard N-2833

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The cable list and diagram interconnection could be done on the same document, but the principals information shall be follow: Cable List information: a) identify the origin and the destination of the each cable or multi cable, b) shall be grouped in separated sheet by junction box, signal type, cable type;


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DESIGN CRITERIA – INSTRUMENTATION AND AUTOMATION c) Indicating the estimated length for each circuit; d) The summarize the quantity of each type of used cable; e) Plan of cables reel;

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Interconnection Diagram information: a) This document shall be use to interconnecting all cables and multi cables from field to CCL; b) identify all interconnection from the field instruments to marshalling cabinet, c) Only one multi cable shall be showed per sheet; d) Junction box, multi cables and terminal block at marshalling cabinet, shall be mnemonic;

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The cables, multi cables, junction boxes and terminal block shall be identified according to the follow criteria: a) For Hardwired cables: a. Cables from instrument to junction box use the instrument tag as cable tag; b. If the instrument has a power supply use prefix “X” to indicate electric feed to instrument and use a suffix “24” or “120” to indicate the power level, for ex: X-AIT-2200001-120; it means: electric feed to AIT-2200001 with 120V c. For junction boxes see item 5.3.8; in case of the junction box need to use two or more terminals block, these accessories shall be identify by letters “A”, “B”, ect; d. Multi cables from junction box to marshalling cabinets shall be identified with the same number of the junction box, for ex: Junction box = JBA-3200-01 Multi cable = MCA-3200-01, if there are more than one multi cable from this junction box, the multi cable shall have the follow identification = MCA-3200-01A; MCA-3200-01B, etc according to the terminal block it is connected; e. Terminal block at marshalling cabinet shall be identified according to the multi cable number, for ex:

MCA-3200-01 Multi cable, RBA-3200-01 terminal

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each multi cable shall be interconnected in only one terminal block, i.e., is forbidden to split the multi cable in many terminals block;

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b) For fieldbus foundation cables: a. Cables from instrument to junction box use instrument tag with a prefix “S” indicating the connection from instrument to spur. b. Fieldbus junction boxes, in the same segment all junction box shall be identified with the same sequential number plus a suffix “A”, “B” or “C”, for ex: one segment on 3100 area has a three junction boxes, these identification shall be: JBF-310001A + JBF-3100-01B+JBF-3100-01C


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DESIGN CRITERIA – INSTRUMENTATION AND AUTOMATION c. Cables interconnecting between trunks in different junction boxes use the Fieldbus junction boxes plus a suffix indicating both junction boxes to be interconnected, for ex: using the same example above the cable interconnecting JBF-3100-01A to JBF-3100-01B will be T-3100-01-AB, where T indicating trunk interconnection. d. Cable interconnecting segment junction boxes to controller use a prefix “FF” plus area and sequential, for ex: FF-3100-01, according to the above showed. e. Cable interconnecting one terminal strip side “B” from marshalling cabinet to only one DCS controller shall be directing connected, it is forbidden split the multi cable in many terminals strip and or DCS controllers;

Notes: a) all signal cables (analog and digital) shall be totally shielded; b) the shielding shall have electric continuity when passing by a junction box through terminal terminals; c) the multi-cables of analog signals shall have individual and total shielding as well as double cover layer and PVC anti-flame (internal layers and covering); d) for standardization shall only be used multi-cables of 12 and 24 pairs, except for the interconnection between DCS and the “B” terminal of the marshalling cabinet, where 08 or 16 pairs multi-cable shall be used. E

e) For triplet cables, the multi cables shall be standardization in 8 or 12 triplet 5.3.11.DETAILS OF ELECTRIC INSTALLATION

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Form : A3 – standard N-2833 Note: a) the abbreviations of the form shall be suppressed because they are only applied for process installation detail; b) this drawing represents typical electric installation detail between the instrument and the electric conduit (design limit between this detail and the electric location plan); c) the design detail and the installation material shall comply with the electric area classification;

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d) union and flexible electric conduit shall not be used; for connection of the cable to instrument or equipment shall be used cable press, and conduits end shall has a washer to protect the cable,


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e) a materials description table shall be used with their individual quantities by detail and total by sheet; f) the material code shall be in accordance with N-298; g) a material summary shall be included considering all sheets of the installation detail. 5.3.12.PNEUMATIC INSTALLATION DETAIL Form : A3 - standard N-2833

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Notes : a) this drawing represents typical details of pneumatic installation between the instrument and the block valve of air supply (detailing limit between this detail and the pneumatic location plan); b) this drawing shall indicate in a single page the whole field connection. In case the panel instrumentation is also pneumatic this field representation shall be to a junction box;

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c) a materials description table shall be used with their individual quantities by detail and total by sheet; d) special consumers shall have detailed on this set; like pressurized system for panels; instrument air supply to analyzers, etc. e) a material summary shall be indicated including all sheets of the installation detail.

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5.3.13.PROCESS INSTALLATION DETAIL Form : A3 - standard N-2833 Notes: a) All instruments connected to the process line by impulse line shall have their installation detailed on this document;

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b) Analyzers and specials instruments, which will be connected to the process line or equipment shall have these impulse line detailed on these details;

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c) Specials materials and accessories for sample conditioning system shall be listed on these detail, if no detailed or listed by the supplier;

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d) the limit of responsibility between the piping and the instrumentation installation shall be clearly represented indicating in these details, in case of the instrument installation in equipment, the first block valve (root valve) shall be installed by piping department, the orientation of the connections for the flow measurement (differential pressure flow elements) shall be represented on the detail with the high and low pressure connections;


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e) in the level details, the orientation of the connections and their respective elevations in the assemblies with “stand pipe” shall be represented; for the level instrument by differential pressure instruments, the high and low pressure taps shall be represented;

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f) in the detail indication of inclination of the tubes in the remote assemblies (not directly in the line) shall be represented; g) materials description table shall be used with their individual quantities by detail and total by sheet; E

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h) the material type selection shall be in agreement with I-ET-6000.67-0000-800PDY-004; i) an index shall be included (tag x page x rev.) organized by process variable and sequential numeric, when there are great amount of sheets in the detail; j) a material summary shall be represented including all sheets of the installation detail and the materials of the supports; k) the description of the material in the detail sheet can be simplified and the NM – (número do material) PETROBRAS identification numbering of material on the code position;

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l) transmitters of differential pressure that use integral “manifold” shall be supported by the “manifold” in order to facilitate the maintenance; m) the flushing system shall be detailed by piping department and connected near to the instrument pressure tap using a block valve;

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n) The seal fluid to fill the impulse line, shall be indicated on the detail sheet, and the will be used the drain connection of the manifold valve or drain point in the instrument to fill impulse line;

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o) When the toxic fluids will be measure, the vent and/or drain point shall be direct to safety or closed system;

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p) The insulation and energy conservation of the impulse lines shall be according to the process necessity; E

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q) The EPC shall indicating on these documents the limits of the pressure test (hydro or pneumatic) shall be applied at the impulse lines; r) When the process installation require welds, the weld condition, tests and approvals shall be specified according to welding procedure technical specification issue by the mechanical department; 5.3.14.GENERAL ASSEMBLY DETAILS Form : A3-A0 - standard N-381 Notes :


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a) include in these details metallic structures (local panels), typical assembly supports (“manifold” of instruments, electric conduits, trays, etc.) except for the supports of instruments already included in the process installation detail; b) a material summary shall be included with approximate amount of material used in the assembly fixation of the supports; c) indicate the amount of each typical support represented in this drawing. d) At the instrument supports the structure to fix the drain valve shall be detailed;

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e) All supports shall be prepared and painted before installation according to painting procedure by EPC contractor;

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f) Specials instruments shall be a covered to protect against direct sun light in yor LCD and rain;

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5.3.15.SET POINTS LIST Form : A4 – Standard N-381, by spread sheet or data base;

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It shall contain the instrument tag, the process measurement range, the instrument range, the type of alarm (if applicable) and the setpoint, in engineering units and range percentage. This list shall include all instruments having some type of calibration and those having alarms configured in supervisory, control or safety systems. Notes: It shall be Included all data configuration in other to deal with control and I/O blocks failure and change operation modes.

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5.3.16. LIST OF ALARMS E

Form : A4 – Standard N-381, by spread sheet or data base; Notes: Alarms shall be in accordance to Technical Specification no I-ET-6000.67-0000-800-PDY003 - REQUIREMENTS FOR ALARM DATA BASE.

5.3.17. CALCULATION SHEETS. E

Form : A4 – out put of calculations program, The CONTRACTOR shall deliver calculation sheets in the following cases:

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a) control Valves: Calculations according to NI-1882 recommendation and ISA 75.01.01 , 75.17 and IEC 60534-8-4 - CV; - noise level; - critical velocity of fluids; - control range; b) safety Valves:


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- orifice calculation, reaction force, selection. Calculations according to NI-1882 recomendation and API RP 520. c) pressure and vacuum valves : - calculation of relief flow (pressure and vacuum) in agreement with API- STD 2000; d) flow primary elements: - dimensional calculation, including thickness; - calculation of the maximum and / or differential flow for existing and / or standard elements in agreement with the following standards :

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- Standards : Square edge orifice plate - ISO 5167 (NBR-ISO 5167); Restriction orifice - ISO 5167 (NBR-ISO 5167) ; Venturi - ISO-5167 (NBR-ISO 5167); Annubar - ISO-5167 (NBR-ISO 5167); Flow Nozzle – ASME – MFC-3M Orifice plates of quadrant edge, conical inlet and eccentric orifice ABNT NBR 13225. For gas measurements in custody transfer applications use: AGA 3 for orifice plate; Mass balance flow measurements using orifice plates, the meter tube, orifice fitting, flow conditioner and uncertainty calculation shall be consider to improve the global mass balance; e) critical speed for thermo-wells : - calculation in agreement with ASME PTC 19.3. 5.3.18.MATERIAL REQUISITION. Form : A4 – standard N-2833

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The technical documentation to be supplied by the manufacturers of equipment and instruments, shall be described in the Materials Requisition. 5.3.19. DATA SHEETS. E

Form : A 4– standard N-2802 and ISA TR 20 Notes : a) the data sheets shall be issued in the specific forms that complies with ISA 20; b) for those not standardized , use the form standardized by N-381 for its issuance; c) the data sheets electronically elaborated shall follow the standardization of the original format of the specific form.


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5.3.20. E

LIST OF INPUT/OUTPUTS

Form : A4 - spread sheet or data base out put Notes :

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a) this document shall list all instruments, digital functions or electrical accessories to be connected to digital systems hardwired or via digital communications, organized per type of signal, per digital system and per signal transmission (hardwired or digital serial communication); b) the designer shall issue this document at about six months after the beginning of design. 5.3.21. LOADING SIGNALS TABLE

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Form : A3 – spread sheet or data base out put; Notes : a) this document shall consider all instruments connected to the digital system as PES, DCS and etc.. b) it shall identify for each instrument cable, the cabinet, chassis, module and terminals where it is connected. 5.4. GENERAL REQUIREMENTS FOR DESIGN AND SPECIFICATION OF INSTRUMENTS.

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The EPC CONTRACTOR will not issue a new design criteria, shall be used this document; 5.4.1 The design shall comply with PETROBRAS Standard NI-1882 and these recommendations. 5.4.2 The instrumentation shall be of the electronic type. Metering and Control Signals connected to PES and PLC´s of package units transmitted from the field shall be in 4 20 mA with the HART serial protocol in the same cable, fed at 24 VDC. 5.4.2.1 For analog instruments designed for control and monitoring connected to DCS , they shall specified with Foundation Fieldbus protocol compatibility . 5.4.2.2 For discrete instruments like limit switches and solenoid valves, the design shall consider Foundation Fieldbus devices, if there is no approved device available an alternative can be used a connection to multi input/output discrete to Foundation Fieldbus Converters and connected to DCS.

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5.4.2.3 The start/stop push buttons for the electric motors the design shall consider the connection direct to MCCs.


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5.4.3 In the case of 4 to 20 mA transmission, the option is for two wire type, with use of the four-wire system being accepted if the first option is not available in the market, and for a specific application. In that case the 4 -20 mA signal shall be galvanically insulated. 5.4.4 Transmitters shall be of the intelligent and microprocessor-based type. Handheld programmers shall be provided for configuring these instruments, considering 1 (one) programmer for every 25 (twenty five) transmitters from that manufacturer. In case the number of transmitters is less than 25 units, at least 01 (one) programmer shall be supplied per instrument manufacturer. 5.4.5 Absolute, gauge or differential pressure transmitters shall have digital output signal indication in engineering unit in the transmitter itself. 5.4.6 Pressure switches and thermostats shall not be used unless previously authorized by PETROBRAS. Flow switches shall only be used to detect the presence of flow where reliability is not important. Transmitters shall be used instead of level switches, pressure switches, thermostats, etc.

5.4.7 All field instruments shall have permanent stainless steel plates indicating the instrument TAG number. 5.4.8 Do not specify instruments under development or whose use is not yet consolidated. 5.4.9 Do not acquire instruments for the same function from different manufacturers.

5.4.10 Regulating filters shall have output pressure indication in Kgf/cm2. 5.4.11 All electronic instruments and equipment shall be built to display immunity to electromagnetic and radio frequency interference (EMF-RFI), as follows: induction less than 1% of SPAN, based on 5W/470MHz at 1 meter away. E

5.4.12 When more than one valve or flow transmitter is necessary for the same service , the engineering flow sheets shall show all the instruments and be submitted to PETROBRAS for approval. 5.4.13 Valves intended for special applications such as, for example, isolation valves, fire-safe valves and tight shut-off valves shall be selected according to the specifications of the basic design and submitted to PETROBRAS for approval. 5.4.14 The shut-off valves shall be design with approved gasket kit to warranty no leakage when the process fluid is toxic, volatile or others(as defined in environment criteria). 5.4.15 Instruments installed outdoors and in non-classified areas shall have enclosures with a degree of protection of IP 65, in accordance with NBR IEC 60529.


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5.4.16 The use of intrinsically safe (Ex-i) or EX na [L] instrumentation with FNICO or FISCO Foundation Fieldbus Concepts in classified areas as zone 0 , 1 and 2 shall complies with IEC 60079-27 . For 4-20 mA instruments the enclosure may be certified as Ex d bud submitted to PETROBRAS for approval. 5.4.17 Electrical instruments and electrical equipments shall be compatible with the electrical classification of the area and have a Conformity Certificate. This certificate shall also contain the degree of protection (IP) of the enclosure. 5.4.17.1 This Certificate of compliance shall be supplied according to regulation “Portaria numero 83 de 03 Abril de 2006” published by INMETRO, to attend Brazilian laws. 5.4.17.2 This certificate shall be issued by an Accredited Certification Organization (OCC), that is an entity accredited by INMETRO responsible by the issue of the conformity certificates and by the inspections of the certified products, attesting the similarity of the analyzed requirements, with the dispositions of the resolution mentioned above. The accredited certification organizations are the following: • CEPEL - Centro de Pesquisas de Energia Elétrica Escritório de Certificação de Produtos - ECPS Address: Av. 1, s/nº - Ilha da Cidade Universitária 21941-590 - Rio de Janeiro - RJ -Brasil Tel. + 55-21-598-2442 or 598-2461 Fax. + 55-21-598-2443 Contact: Mr. Marcelo Appel Silva • UCIEE – União Certificadora de Indústria Eletro-eletrônica Address: Av. Brigadeiro Faria Lima, 613, 2º andar São Paulo - SP -Brazil Tel. + 55-11-820-7144 Fax. + 55-11-820-2674 Contact: Mr. Paulo Vieira

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• CERTUSP – Serviço Técnico de Certificação do IEE/USP (Instituto de Eletrotécnica e Energia da USP) Address: Av. Prof. Luciano Gualberto, 1289 Cidade Universitária - São Paulo - SP CEP 05508-900 – São Paulo – SP - Brazil Tel. + 55-11-818-4912 Fax. + 55-11-212-9923 Contact: Mr. Jean Bodinaud http://www.iee.usp.br e-mail: [email protected] 5.4.17 For services with H2S and H2 the piping criteria and standards N-76 and N-1882 shall be followed. The following general requirements shall be considered: a. threaded process connections may not be used;


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b. if use of welded connection is necessary, use socket weld. Sealing weld is not acceptable; c. for pressure gauges use integrated diaphragm seal; d. piping criteria such as radiography, non-destructive tests, etc. shall be evaluated and used in the installation of instruments. These criteria shall be defined in the installation details; e. the use of diaphragm seals associated with capillaries shall be avoided, and will only be adopted with prior approval by PETROBRAS; f. the condition “H2 or H2S Service” shall be indicated on the Data Sheets of instruments and supplementary requirements of materials, tests and certificates required shall be included. 5.4.18 The current consumption of instruments shall be 20 mA (max.). 5.4.19 The AI function block execution time of temperature Foundation Fieldbus instruments shall be 60 ms maximum and 30 ms (max.) for other types. 5.4.20 The response time (time constant + dead time) of instruments shall be 250 ms (max.).

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5.4.21 All intelligent instruments shall be able to make self-diagnose.. All licenses nedded for achieve the advanced diagnoses shall be supplied with the instruments. Including the licenses nedded in the Asset Managment System, if applicable.

5.5.

TEMPERATURE INSTRUMENTS SPECIFICATION

5.5.1. SELECTION CRITERIA 5.5.1.1 Specify K type (chromel / alumel) thermocouple loops as standard for the entire unit. E

4.5.1.2 Specify RTD class A for temperature compensation with an operating temperature below 400 oC and for indicating or recording for operating temperatures below 60 oC. 5.5.1.3 All the temperature loops shall have a thermocouple connected to the temperature transmitter for the signal transmission to the digital monitoring, safety and control system.

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5.5.1.4 Indication temperature shall be design with multiplexer transmitter. This indication can’t be used to advanced process control. The distribution design of thermo elements shall consider that the lost of one multiplexer transmitter don’t cause the lost of information of one level of towers, one pass of fired heater and others group of indication raise difficulties of operating the unit.


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5.5.1.5 Do not use instruments with bulb and capillary (sealed expansion systems). 5.5.1.6 Use terminal block with compression spring, union and head in cast aluminum IP65 enclosure, NPT thread connection;

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5.5.2. PROTECTION OF PRIMARY ELEMENTS 5.5.2.1 Temperature metering units on sulfur lines shall be installed so that the sensor is immersed at all times in the liquid. 5.5.2.2 The designer shall present calculation sheets giving the resistance and vibration of thermometric wells, considering the maximum speed of fluid under operating conditions and performing the check in accordance with ASME PTC-19.3 Part 3. If wells under high vibration conditions are identified in this checking procedure, the well shall be resized according to the recommendations of the aforesaid code. 5.5.2.3 All flanged wells shall use a full penetration weld between the well and the flange. 5.5.3. THERMOCOUPLES 5.5.3.1 In control and safety functions, the thermocouples shall be double type. Thermocouples shall have mineral insulation presenting a minimum insulation of 20 M~ @ 600 °C, with magnesium oxide or alumina with a le vel of purity of 99.6%. 5.5.3.2 In thermocouples for measuring the temperature of furnace tubes, use shall be made of wells with the end opened and welded to the piping and flexible thermocouples to be inserted and removed with the furnaces in operation. If this type of installation is not possible, use a skin point as an alternative as per API RP 551. E

5.5.3.3 In thermocouples for measuring multiple temperature points of hydroprocessing (hydrocracking and hydrotreating), isomerization, catalytic reforming regenerators and fixed bed reactors, use shall be made of flexible sheath/thermowell with up to 9 thermocouples located along the length. 5.5.4. RESISTANCE BULB (RTD) 5.5.4.1 The RTD shall correspond to the following performance: Stability: +/- 0.025 °C/ year of op eration

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Repeatability: 0.025% or 0.05 °C ( whichever is the greater) E

5.5.4.2 In control and safety functions, the resistance bulbs shall be double type.

5.6.

PRESSURE INSTRUMENTS SPECIFICATION


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5.6.1. SELECTION CRITERIA (EXCEPT FOR ELECTRONIC TRANSMITTERS) 5.6.1.1 For measuring very low pressures or vacuums, bellows or sensors shall be used.

diaphragm type

5.6.1.2 The selection of the pressure sensor range shall cover a possible rise in pressure in the system and instantly absorb at least 1.3 times the maximum working pressure. 5.6.1.3 The pressure sensor shall withstand a direct or reverse overpressure equal to the maximum nominal static pressure without affecting calibration or displacing zero. 5.6.1.4 Any output variation caused by a static pressure variation equal to 100% of the nominal pressure of the element shall not exceed 1% of SPAN. 5.6.2. PRESSURE INSTRUMENT ACCESSORIES 5.6.2.1 Accessories such as pressure limiters, separators and pulsation dampers shall be used only when absolutely necessary. 5.6.2.2 Where there is intense vibration on the process line the instrument shall be provided with a pulsation damper or a seal with capillary extension for installation on a pedestal.

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5.6.2.3 All differential pressure instruments shall have an integral manifold with connection to the instrument through ½” oval flange, without dispensing the blocking of the line adjacent to the process connection. When the instrument is applied in H2S or H2 service, ½ “ oval flange shall be applied on both sides of the manifold; 5.6.2.5 All pressure gauges shall be installed using multi-valves with a built-in drain. 5.6.3. PRESSURE TRANSMITTERS 5.6.3.1 For all differential pressure metering instruments the high and low pressure connections shall be clearly and visibly indicated. 5.6.3.2 Pressure transmitters (absolute, gauge or differential shall be intelligent and programmable with an IP65 enclosure, Ex d, Ex i or Ex nA[L], capacitive or piezo-resistive sensor, foundation fieldbus or 4 – 20 mA output signal plus Hart, where applicable. 5.6.3.3 The transmitters shall be selected in accordance with the following ranges: a) gauge pressure transmitters: (-0.6 – 1.0 to 20.0 Kgf/cm2 ) or (0 – 1.0 to 20.0 Kgf/cm2 ) or (0 – 20.0 to 120.0 Kgf/cm2 ) or (0 – 120 to 250 Kgf/cm2 ) or (0 – 250 to 350 Kgf/cm2 ); b) absolute pressure transmitters: :(0 - 50 to 750 mmH2O)


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b) differential pressure transmitters:(0 - 12 to 100 mmH2O) or (0 – 250 mmH2O to 1000 mH2O ) or (0 – 1000 to 10000 mmH2O) or (0 – 1.0 to 5.0 Kgf/cm2 ) or (0 – 5.0 to 30.0 Kgf/cm2 ). 5.7.

FLOW INSTRUMENTS SPECIFICATION

For FIs in the field, BARTON cells shall not be used. Use transmitters with local indication on the transmitter itself or on a separate indicator or both when necessary. 5.7.1. DIFFERENTIAL PRESSURE TYPE METERS - ORIFICE PLATES 5.7.1.1 For flow rangeability greater than 9 to 1, the use of Ultrasonic, Vortex, Coriolis effect or thermal effect meters shall be preferably evaluated, avoiding the use of plate holders. 5.7.1.2 For arrangement of multiple instruments for the purpose of voting 2oo3 in the SIS system, the criteriais to specify two orifice flanges with connections for two transmitters each in serial installation. 5.7.1.3 When it is not possible to use the solution described above the design shall consider an arrangement of the orifice flanges with connections for four transmitters. 5.7.2. ORIFICE PLATE CALCULATIONS 5.7.2.1 The minimum dimension of the line for meters in conventional metering services is 2”. If the process lines are smaller than 2”, the lines shall be increased to 2”. 5.7.3. ULTRASONIC AND CORIOLIS METERS 5.7.3.1 In the installation of ultrasonic and coriolis meters the upstream and downstream distances specified by the manufacturer shall be respected. 5.7.3.2 Special attention shall be paid to the piping arrangement for liquid measurement since the line shall work permanently full for proper operation of the instrument. 5.7.3.3 The intrusive meter (spool) shall be used where an accuracy of 1% or less is required. 5.7.3.4 The non-intrusive ultrasonic meter (clamp-on) will be used only for measurements in which its service is only intended for operational follow-up and which do not require a high level of accuracy. E

5.7.3.5 the non-intrusive ultrasonic meter (clamp-on) shall be protected with a cover.

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5.8.

LEVEL INSTRUMENTS SPECIFICATION

5.8.1. LEVEL GAUGES. 5.8.1.1 Level gauges for services in hydrogen vessels at high pressure shall be installed using double blocking arrangements in accordance with PETROBRAS standard NI1882.


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5.8.1.2 The arrangement with stand-pipe shall not be used but when approved by PETROBRAS it shall have a block valve in accordance with the piping spec. between the vessel and the stand-pipe and another block valve of the ball type between the stand-pipe and the instrument according to the piping specification and with an operation blocking device. 5.8.1.3 The arrangement without a stand-pipe shall have double blocking arrangements between the vessel and the instrument, the first one being a gate valve and the second a ball valve. 5.8.2. LEVEL TRANSMITTERS. 5.8.2.1 Displacement level instruments shall be electronic, except in areas with temperature problems, in which case the pneumatic type shall be used. 5.8.2.2 The detailed design shall check the location of the nozzles on equipment drawings. 5.8.2.3 The elevation and orientation of nozzles shall be distributed around the entire vessel. 5.8.2.4 Care shall be taken to avoid concentrating the nozzles in a single region, thereby making it hard to access the instruments and do maintenance work. 5.8.2.5 Stand-pipes shall not be used for the installation of level instruments. For any reason if the application is recommended the design shall be submitted for approval.

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5.9.

CONTROL VALVES SPECIFICATION.

5.9.1. SELECTION CRITERIA. 5.9.1.1 The selection criteria shall complies with NI-1882 and the preference is for the globe cage valve. 5.9.1.2 Types of valves such as rotary eccentric plug type, split body type, diaphragm type, ball valves and low noise valves are accepted where necessary. 5.9.1.3 In electronic loops use a microprocessor-based electro-pneumatic positioner. The positioner shall be immune to electromagnetic field. All positioners shall be intelligent and programmable with Foundation Fieldbus protocol. 5.9.1.4 The flow characteristic of the valve shall be selected from the valve positioner or plug. E

5.9.1.5 Special seal gaskets with constant load using plate and coil shall be used when the process fluid is toxic (benzene, aromatics, H2S etc) in accordance to Technical Guideline - AB-RE/ES/TEE - DT-AB-RE/ES/TEE-013 – Requirements for Process and


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Storage of Aromatics products. The construction shall be certified by TA-Luft and tested according to standard ISSO-15848 parts 1&2. 5.9.1.6 The minimum cycles without adjusting shall be required on the data sheet as complementary information at the applications with toxics fluids;

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5.9.2. ACTUATORS. 5.9.2.1 All valves shall be supplied with a plug/stem travel indicator. 5.9.2.2 All actuators shall be capable to stroke with the minimum pressure of the air supply – 4,5 kgf/cm2;

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5.9.2.3 Piston actuator shall be capable to adjust the velocity of opening or closing by air vent adjustable plug; 5.9.2.4 For the diaphragm actuator the supplier shall inform the useful life of the diaphragm in cycles; 5.9.3. ACCESSORIES (SWITCHES, HAND WHEELS AND SOLENOIDS). 5.9.3.1 Where required, position switches shall be easily adjusted at the desired operating points. 5.9.3.2 The nominal electrical capacity of the switch contacts shall be at least 50% greater than that requested for normal operation, 2 A at 24 VDC. 5.9.3.3 All position switches of control valves or dampers shall be of the magnetic type (reed switch sensor) without mechanical contact. 5.9.3.4 For elements with monitoring of the two positions (open and closed) when the valve is in the intermediate position there shall also be indicative signaling in the DCS. 5.9.3.5 Hand wheels shall be used for control valves installed without by-pass, except in the case of valves whose sole function is to ensure the safety of the system in which they are installed, or self-operated valves for temperature and pressure control. In the latter case local indicators shall be provided to check the controlled variables. 5.9.3.6 All solenoid valves connected with XVs, except where determined by the basic design, shall not use field resetting arrangements. Resetting will be via the DCS. 5.9.3.7 Solenoid valves shall have low power, limit consumption of 2.0 watts at 24 VDC. 5.9.3.8 Solenoid valves used in interlocking and safety systems shall be energized during normal operation, except the vent valves of gas header of furnace SIS. For solenoid valve of the SIS the selection criteria shall consider the SIL level of the safety function and the requirements for “partial stroke capacity” and the reliability.

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5.9.3.8 all fittings and tubing shall be supplied in Stanley steel and fittings shall be supplied with double ferrule type;


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5.10. SALFETY AND RELIEF VALVES SPECIFICATIONS 5.10.1.SAFETY VALVES INSTALATION 5.10.1.1 In systems with pressure control with relief to flares, control valves cannot be considered to be safety equipment. 5.10.1.2 Do not align the discharge of PSV´s working with flammable or toxic products to the atmosphere. 5.10.1.3 The basic design shall define the services where more than one PSV is necessary and in this case where the switching on-line device is necessary. 5.10.1.4 The basic design shall define which PSV must have a device to indicate the opening of it and alarming in the DCS. 5.10.1.5 In critical process units systems where maintenance demand of valves is done without stopping the whole unit paired PSVs shall be used according to Technical Guideline - AB-RE/ES/TEE - DT-AB-RE/ES/TEE-006 - “Use of paired PSVs”. E

5.11. PROCESS ANALYZERS SPECIFICATIONS For additional information see ET-6000.67-0000-850-PDY-001, Sistemas de Amostragem, I-ET-6000.67-0000-951-WAP-028 – SPECIFICATION FOR PROCESS ANALYZER SYSTEMS AND NETWOR 5.11.1.DEFINITIONS a) Analyzer - An instrument which measures some material quality or property other than temperature, pressure, level or flow. b) Analyzer Cabinet - An enclosed housing that protects a small number of analyzers. Maintenance is performed from outside the cabinet with the door(s) open. c) Analyzer Shelter – Can be of the two types: Three sided shelter structure consisting of a roof and one to three walls and Closed shelter – structure like a container with door , both provides weather protection for one or more analyzers and for maintenance personnel. d) Analyzer System – A set of Analyzers, equipment, instruments, accessories and others, assembled together to form a whole system. e) Calibration – The manual or automatic action of adjusting analyzer output to agree with the reading expected from the calibration sample introduced. f) Calibration Sample – The material used to calibrate the analyzer, which quality or property is known. The calibration sample may have been analyzed in a local laboratory or purchased with a certificate of analysis. g) Contractor - The ones responsible for the supply of the material and/or services to PETROBRAS, and shall comply with any local rules or regulations which are specified.


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h) Manufacturer – The ones who manufacture or assemble equipments, instruments, modules or part of these ones. i) Response time – Response time for each stream is the period between two consecutive analyzer results. j) Sample Conditioning System (SCS) - A combination of modules installed directly upstream of an analyzer’s inlet to modify and adjust sample parameters according to those required by the analyzer. Modules commonly used in sample conditioning systems include filters, separators, vaporizers, scrubbers, reducing regulators and temperature controllers. k) Sample Tap - A connection point where samples are taken from a process stream. l) Sample Transport System - A piping system used to transport the sample from the sample tap to the SCS, to Sample Return System and back to process. m) Validation – The manual or automatic action of comparing (rather than adjusting) the analyzer’s output to the reading expected from the sample introduced. Validation results are kept on a control chart to demonstrate that the analyzer is operating in statistical control. n) Validation Sample – The material used to validate the analyzer, which quality or property is known. The validation sample may have been analyzed in a local laboratory or on the existing analyzer, or purchased with a certificate of analysis. If any definition of this document needs to be changed by contractor, PETROBRAS shall be consulted to approve it. 5.11.2.ANALYZER GENERAL 5.11.2.1 The detailed design shall determine the location of sample connections based on the specifications of the basic design and on the response time required by the process. 5.11.2.2 The required response time is the sum-total of the time for analysis and circulation of the sample from the process line to the input into the analyzer. E

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5.11.2.3 Electric power supply for Process Analyzers shall be provided by the Instrumentation Supply System. 5.11.2.4 A single integrating company shall be contracted for supply of each process analyzer of the project. The integrating entity will be responsible for the supply, installation, including a sampling system, consumers and start-up of the analyzers in accordance with analyzers specifications. 5.11.2.5 The protection shall be specified according to the product, importance, environmental and safety conditions and may be of the case, cabinet, shelter or house type.

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5.11.2.6 The protection involves specification of the ventilation (natural or forced) system, closed drains, safety vents, monitoring as to gas leakage and requirements for alarms. 5.11.2.7 For analyzers installed at a distance from the sample connection, sampling carrier systems shall be specified. These systems shall be designed in fast loop and sample recovery regime so as to minimize product loss. Calculations involve pressure


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drop, flow speed, line dimensions and fluid properties. Avoid removing fast loop connections on control valves. 5.11.2.8 Bypass systems shall be used in cases of vaporization of liquids for analysis of gases. E

5.11.2.9 For automatic control, single stream analyzers are recommended. Multiple stream analyzers may only be used after an evaluation is made demonstrating that system reliability is not jeopardized. 5.11.2.10 The design for the sampling system and installation shall complies with EEMUA Publication 138. 5.11.2.11 FAT (factory acceptance test) and SAT (site acceptance test) shall be performed for analyzers with all validation process that complies with ASTM D 3764. 5.11.2.12 A Notebook and/or Handheld computer shall be provided for access and connection to application programs for configuration and maintenance of this analyzer, including shelter monitoring and control systems such as PLCs. 5.11.2.13 Present a list of spare parts for two years of operation, covering all systems contained in the shelter such as: analyzer, PLC, sampling system and air conditioning system. 5.11.3.SCOPE 5.11.3.1 The Analyzers System shall be designed for continuous and efficient operation. The consumption and wastage of process samples and utilities shall be minimized. 5.11.3.2 Design practices shall be logical and consistent throughout the project. Consideration shall be given to uniformity in the selection and use of materials, components, and equipments. Construction materials shall be specified as noncorrosive and noncombustible in normal plant operating environments. 5.11.3.3 The analyzers shall be furnished in accordance with the project requirements. The Contractor may propose additional or alternative analyzers or methods for PETROBRAS approval. 5.11.3.4 PETROBRAS shall approve the analyzers data sheets completed by the manufacturer. Note: Plant upset conditions and extremes must be included in addition to normal process variations. 5.11.3.5 The analyzers manufacturers shall inform the sample temperature, pressure and flow requirements for the proper operation of the analyzers, as well as the sample components (with concentrations) that may cause damage or degradation to the analyzers. 5.11.3.6 The environmental variations (barometric pressure, temperature, humidity, etc.) shall be considered for the performance criteria assessment. Note: The manufacturer shall be responsible for installation of any device necessary to correct or compensate the environmental influence on the system performance.


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5.11.3.7 The sample system and analyzer shall be designed to recover automatically from upsets at the specified design limits. Note: The analyzer need not maintain its specified accuracy outside the specified normal operating range. 5.11.3.8 Analyzers and associated equipment shall meet the requirements of applicable national and local codes. The Contractor shall certify in writing that all of these requirements have been met. Any deviation from requirements must be submitted to PETROBRAS for approval prior to purchase and installation. 5.11.3.9 Drawing symbols shall conform to ISA 5.1. 5.11.3.10 The total analyzer system shall meet the electrical classification of the area in which it is installed. 5.11.3.11 All materials shall be suitable for the sample stream and the surrounding atmosphere. Nonmetallic materials or low-melting alloys shall not be used in lines handling hydrocarbon or other flammable substances. 5.11.3.12 A system for purging and cleaning the analyzers, sensors and sampling system shall be supplied to prevent deposits on the sensors during shutdown. 5.11.3.13The supply a return taps for all analyzers shall be defined in the P&ID. 5.11.3.14 The Analyzers System shall consist of sampling system, sample conditioning system, auxiliary equipments and accessories, as required to monitor and provide the necessary data for proper process operation. All related services as technical and engineering, assemblage, commissioning, start-up, pre-operation, and training shall be included. 5.11.3.15 The analyzers, sampling system, and related equipment shall be mounted and interconnected with utilities and accessories as required for continuous and unattended operation. 5.11.3.16 The Analyzers System shall include devices and facilities to provide convenient operation and maintenance. 5.11.4.MANUFACTURERS RESPONSABILITIES. 5.11.4.1 The manufacturers shall be responsible for the design from the process sample tap to the output signal wiring and include all aspects required for proper operation of the Analyzers System as well as the interconnecting piping, tubing, and wiring as required for installation of the Analyzers System at the jobsite. 5.11.4.2 The manufacturer shall be responsible for: a) the correct design and proper operation of the Analyzers System;


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b) compliance with technical specification; c) PETROBRAS technicians training; d) pre-operation, start-up, and assisted operation of the Analyzers System. 5.11.4.3 The manufacturer shall be responsible for all activities related to the design, assembly and installation of the Analyzers System. The extent of work shall include, but not be limited to the following: a) engineering design and specification of the Analyzers System; b) preparation of design drawings for Analyzers System; c) coordination and expedition of all purchase orders for calibration standards and equipment related to the Analyzers System.

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Notes: 1) the purchase orders necessary for the sample transport line (fast loop), may be emitted by CONTRACTOR in accordance with the manufacturer design specifications; 2) the purchase orders necessary for the cylinders and calibration standards shall be emitted to Brazilian companies (AGA, White Martins, etc); 3) all calibration standards shall have validation expiration date at least 6 months after plant start up. 5) assembly of Analyzers System according to design drawings and specifications; 5) test and inspection of all Analyzers System, at the factory and at the plant site; 5.11.4.4 The manufacturer shall be responsible for packing the Analyzers System properly for maritime and road transport. 5.11.5.CONTRACTOR RESPONSABILITIES. 5.11.5.1 CONTRACTOR shall be responsible for the following works, in accordance with the manufacturer design: a) civil work; b) sample transport line and utilities pipe work; c) installation of power and signal cables (serial, analog and discrete communication) between analyzers system and control room, including conduit and cable trays. 5.11.6.CONTRACTOR AND MANUFACTURER RESPONSABILITIES.


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5.11.6.1 On-site analyzers system installation. 5.11.6.2 Coordinate the manufacturer for preparation and submitting to PETROBRAS comments of any analyzers system documentation which could be defined later between PETROBRAS and CONTRACTOR. 5.11.7.ANALYZERS SPECIFICATION 5.11.7.1 MEASUREMENT AND OUTPUT SIGNAL. 5.11.7.1.1 The required analysis measurement and output signals are given in the Analyzers Data Sheet. 5.11.7.1.2 The analyzers shall include a local multifunction indicator to display the measured values according to the specified range. 5.11.7.1.3 The alarm signals to the monitoring system, related to analyzers, shall be briefed in one discrete signal and sent as an individually isolated contact closure. The contact shall open on status change or power failure to analyzers. (Fail-safe action). 5.11.7.1.4 The Analyzers shall have an output status signal to validate the analyses output signal as “good/not good”, resulting from auto diagnosis, according to the data sheets. 5.11.7.2 SPECIAL ACCESSORIES. 5.11.7.2.1 The manufacturer shall inform all needs on special accessories and auxiliary equipment required for installation, operation, and maintenance of the analyzers (i.e., interconnecting cable, consumable material, or calibration kits). E

5.11.7.2.2 All cylinders to be applied as carrier gas, combustion gas or other finality, shall be furnished at least two cylinders per function, with a double stage reduction valve and an automatic change over and a pressure sensor to alarm when the change occur. These cylinders shall be supplied in quantity necessary for all tests, commissioning, start-up and enough for a period of 5 months after acceptance. 5.11.7.2.3 The gas cylinders, and calibration standards, if required, shall be supplied by the manufacturer, as defined at item 4.11.4.3 sub-item “c”. 5.11.7.3 CALIBRATION STANDARDS

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5.11.7.3.1 The Standards shall be supplied in quantity necessary for all tests, commissioning, start-up and for one calibration per week during 4 months after acceptance. It shall be furnished at least two cylinders per standard, the standard composition shall be certified and the certificates shall traceable through NIST or NMI. 5.11.7.3.2 The standards certification shall inform: - Standard manufacturer name;


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- Cylinder identification; - Filling date; - Analysis date; - Certificate expiration date; - Composition; - Method of analysis; E

- Validity; - Name of the person who is responsible for certificate. 5.11.8.SAMPLING SYSTEM 5.11.8.1 GENERAL

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5.11.8.1.1 The Sampling System includes extract probes and transport lines, conditioning and disposal systems. It shall be designed to provide a representative process sample under conditions which are compatible with the operation of the analyzers. 5.11.8.1.2 The Sampling System shall be designed to minimize the consumption of process sample, thereby reducing product wastage and relieving potential hazards in the event of a leak. 5.11.8.2 DESIGN 5.11.8.2.1 The sampling systems shall be provided with filters, moisture removal, with control of sample temperature, pressure and flow, if required for proper operation of the analyzers. 5.11.8.2.2 Consideration shall be given to sampling streams for which temperature and pressure control are critical to maintain the dew or bubble point, and to prevent deterioration of the sample; Note: To guarantee the system performance, the manufacturer shall recommend, design and install special standard cylinders, line tracing, thermostatic cabinet, pressure control and any other devices to prevent system miss performance and malfunction. 5.11.8.2.3 In addition to these general design requirements and considerations, the Sampling System shall include the following specific features: a) samples shall be collected in order to guarantee representative information at the analyzer. The sample probe shall include a manual shut-off valve to allow isolation of the sample line at the tap;


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b) the Sample Transport and Conditioning Systems, if required, shall be designed to provide the least transport lag time from sample tap to analyzers entrance. The Sampling System shall incorporate a fast-flow loop to minimize transport lag time, if the analyzer is not close to the sample point; c) sample transport lines requiring heating shall have thermal insulation and steam tracing. Consideration shall be given to the operation and maintenance of heated sample systems without causing sample condensation. Sampling Systems requiring heating shall be installed in insulated enclosures; d) high temperature sample lines shall be insulated for personnel protection, according to piping thermal insulation standards recommendation; e) the analyzer shall be installed as close as possible of the sample tap, considering the analyzer limitations and personnel accessibility for maintenance and calibration; f) sample Conditioning Systems, if required, shall be mounted in IP-65 enclosures with thermal isolation and glass windows to observe and adjust the gauges inside without opening the cabinet doors; g) all sample indicators (temperature, pressure, or flow) shall be sized such that indication is in the second third of the scale under normal operating conditions; h) unless otherwise specified, primary sample filters and coalescers shall have a small internal volume; i) Sampling Systems shall include facilities for manual and automatic introduction of calibration samples to the analyzers, according to the data sheets; j) the design and assembly of Sampling Systems shall give proper consideration to the logical and consistent organization and configuration of component parts. Special consideration shall be given for sloping of lines, low point drains, condensation prevention, sample cross-contamination, dead-end pockets, and accessibility to maintenance items such as filter elements; k) a blocking system shall be supplied for the analyzers and for all the components of the sampling system (filters, coalescers, etc.) to allow maintenance work; l) a laboratory sample point shall be included in the analyzer system at an accessible point, near each analyzer to ensure that the laboratory sample is fresh and comparable to the sample supplied to the process analyzer. Note: Acquisition of a laboratory sample shall not interfere with the continued operation of the process analyzer. 5.11.8.3 COMPONENTS


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5.11.8.3.1 Sampling Systems shall be designed and assembled with components for easy maintenance and/or replacement. Uniformity of component selection shall be a prime consideration in order to minimize the spares parts stock. 5.11.8.4 MATERIALS OF CONSTRUCTION 5.11.8.4.1 All materials in contact with process samples shall be corrosion resistant. E

5.11.8.4.2 In general component construction shall be stainless steel (type 316 or better, as required) with TEFLON (or equivalent), considering the maximum temperature of the sample. 5.11.8.4.3 No copper, zinc, or silver bearing alloys shall be allowed in contact with process samples. 5.11.8.4.4 Sample tubing shall be type 316, seamless, stainless steel with a minimum 0.89 mm wall thickness. 5.11.8.4.5 Where other material is required for a specific application, it shall be identified on the sample system drawing.

5.11.8.5 EFFLUENT SAMPLE RETURN/VENT 5.11.8.5.1 Analyzers effluent samples or fast loop streams shall be preferably returned to process. If returning to process is impossible the sample shall be directed to flare system through a pressure regulator valve, that guarantees the pressure upstream 7 psi above the maximum flare pressure. 5.11.9. THREE SIDED SHELTER, CLOSED SHELTER AND CABINET 5.11.9.1 GENERAL 5.11.9.1.1 The cabinet shall be supplied as a completely assembled package suitable for installation on a concrete pad at ground level. 5.11.9.1.2 All equipment including tubing, wiring and supports shall be installed so as not to interfere with the operation, maintenance or removal of the analyzers, sampling system, and related items. 5.11.9.1.3 Accessibility for operation and maintenance shall be taken into first consideration on the design and assembly of the Analyzers System.

5.11.9.2 THREE SIDED SHELTER , CLOSE SHELTER AND CABINET FABRICATION 5.11.9.2.1 Cabinet - The cabinet shall be an enclosed housing in which analyzers are installed singly or grouped together in a small number. Maintenance is carried out from outside the


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cabinet with the door(s) open. - The monitor cabinet shall be designed to be weather and corrosion resistant. - The cabinet shall have glass windows to permit the visualization of the alarms and variables indication from outside. 5.11.9.2.2 Three Sided Shelter - The shelter shall be a structure consisting of a roof and one to three walls, that provides weather protection for one or more analyzers and for maintenance personnel. - The shelter roof shall extend over all the analyzer monitor cabinet, the calibration system and cylinder, at least 1.5 m at the front and back sides. 5.11.9.2.3 Closed Shelter The house shall be an enclosed container containing one or more process analyzers and associated equipment where streams for analysis are brought in and which is regularly entered by authorized personnel. The maintenance of the analyzer is normally carried out from within the closed shelter. 5.11.10.PIPING AND TUBING WORK E

5.11.10.1 The utility headers shall meet the following design requirements: a) utilities headers shall be sized according to the required capacity with spare allowance. The minimum size for headers shall be 1” pipe; b) they shall slope to a low point and include a drain/blown down valve, if required; c) connections to headers shall be at the top or side of the pipe; d) each header connection shall have an individual shut-off valve; e) steam and condensate headers shall be insulated; f) The gap between headers supports shall be 1.5 m at most; 5.11.11.TUBING 5.11.11.1 All interconnecting tubing shall be type 316, seamless stainless steel. All tube fittings shall be type 316 stainless steel, ½” and 0,065 inch thickness of wall. The tube fittings shall be double type. 5.11.11.2 Tubing for steam supply, tracing, and condensate return shall be insulated. 5.11.11.3 Tubing runs shall be organized and installed in logical groups and in a manner that allows easy identification;


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5.11.11.4 Tubing runs shall be supported every 1.5 m at most; 5.11.12.ELECTRICAL AND WIRING WORK 5.11.12.1 Electrical equipment, devices, and wiring shall comply with applicable codes and standards, and be suitable for the specified electrical area classification. 5.11.12.2 AC POWER. 5.11.12.2.1 AC Power will be available for the Analyzers System powering nominal voltages in accordance with Data Sheets. 5.11.12.2.2 Lighting inside the cabinet shall be supplied by fluorescent lamp fixtures. The light switches shall be located inside the cabinet. Note: Number required for 100 Lumens at working surface, vapor tight, industrial grade, Div.2. 5.11.12.2.3 The external lighting of the cabinet shall consist of fluorescent lamps, correctly supported for proper and adequate illumination of shelter inside and external panels. The light switches shall be located inside the shelter. 5.11.12.2.4 One convenience receptacle outlet shall be provided inside the shelter, besides the analyzers’. 5.11.12.3 ANALOG SIGNAL WIRING 5.11.12.3.1 DC signal wiring shall be run in a separate cable tray or conduit system and segregated from AC power wiring. A minimum of 300 mm separation shall be maintained with crossing made at a perpendicular angle. 5.11.12.3.2 DC signal wiring shall be cables with a twisted pair of wires and shield, unless special multi-conductor cables are required. 5.11.12.4 DISCRETE SIGNAL WIRING. 5.4.8.12.4.1 Discrete signal wiring shall be cables with pairs of conductors and run in a raceway system separate from AC power and DC signal wiring. 5.11.12.5 TERMINALS BLOCKS. 5.11.12.5.1 Terminal blocks shall be barrier type with tubular clamp connections and made of a non-hygroscopic material. 5.11.12.5.2 Terminal blocks shall be mounted on rails and installed in columns. 5.11.12.5.2 A minimum of 100 mm clearance shall be allowed for connection to terminal blocks.


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5.11.12.5.3 A minimum of 50% spare terminals shall be provided. 5.11.12.5.4 Connection of more than one wire to one terminal is prohibited. 5.11.13.ELECTRICAL AREA CLASSIFICATION 5.11.13.1 All of the equipment shall be in accordance with the electrical area classification. 5.11.13.2 The enclosures shall be used in order to allow convenient access for maintenance. 5.11.13.3 Explosion-proof enclosures are acceptable for electrical devices and equipment that does not require access for routine maintenance, or for electrical components that are supplied with explosion-proof enclosures as a standard for hazardous areas. 5.11.13.4 Under no circumstances shall purging be used with an explosion-proof enclosure. 5.11.14.SAFETY REQUIREMENTS 5.11.14.1 The Analyzers System shall be designed and assembled to minimize the exposure of personnel to hazard. 5.11.14.2 Suitable signs shall be provided to warn personnel of potential hazards (e.g., sources of radiation, high temperature, pressure, or voltage). 5.11.14.3 The installation shall include, but not be limited to, the following hazard reducing procedures: a) protective guards shall be installed over sources of high temperature or voltage; b) high pressure sources shall not be located in areas of normal occupancy. In general, high pressure sources, like cylinders, shall be located outside the shelter; c) the quantity of hazardous samples (toxic or flammable) entering the shelter / cabinet shall be minimized; d) pockets or void spaces where hazardous gas could accumulate shall be eliminated; e) Sampling Systems shall include facilities for draining prior to maintenance. 5.11.15.TAGGING 5.11.15.1 All connections, components, devices, analyzers, and related equipment in the Analyzers System shall be identified as follows:


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5.11.15.2 There shall be identification for : a) all termination points for field connections; b) analyzers, with the service, sample streams and measurements; c) sample system components, with the service and normal operating set-point; d) Power switches and circuit breakers, with the corresponding service; e) terminal blocks; f) all wires, with permanent wire markers; g) field mounted equipment, with the corresponding service. 5.11.15.3 It shall be furnished an additional identification or advising tag written in Portuguese besides each tag written in English. The translation of all texts shall be approved by PETROBRAS. 5.11.16.INSPECTION AND TESTS AT THE FACTORY 5.11.16.1 PETROBRAS shall be notified thirty days in advance of factory tests. 5.11.16.2 The Analyzers System shall be verified and tested prior to shipment, in order to assure the conformity with the design, and the proper installation and operation. 5.11.16.3 The checkout and testing shall include, at least, the following items: a) visual inspection of all work to assure mechanical completeness and compliance with all design drawings and specifications; b) visual inspection of all nameplates and tags to verify correct identification; c) point-to-point check of all wiring and tubing to verify proper interconnection; d) continuity and isolation test of all electrical wiring; e) pressure test of all piping and tubing; f) functional test of all electrical equipment, output signals, piping equipment, sampling system, analyzers and related equipment; g) calibration test of analyzers; h) Any other test agreed between PETROBRAS and manufacturer. 5.11.17.INSPECTION AND TESTS AT THE JOBSITE


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5.11.17.1 PLANT ACCEPTANCE TEST (PAT) 5.11.17.1.1 Plant Acceptance Test is a repetition of the Factory Acceptance Tests verifying the system operability and fixing possible damages occurred during the transportation, after the analyzer system delivery and installation at the definitive site and interconnected to DCS. 5.11.17.2 PERFORMANCE TEST 5.11.17.2.1 The analyzers system shall be considered ready for this test when it has being totally assembled, connected to process/utilities, integrated to plant control system, and all non-conformities found during the Plant Acceptance Test (PAT) have being solved . 5.11.17.2.2 During the assisted operation period, the following tests shall be performed Availability - Validation - Stability a) Availability Test The system under test shall be considered available when all of its parts (sampling system, analyzers, safety systems, controllers and all other associated equipment and systems) are working in conformity with the specification. All the system will be brought into operation for a period of 168 hours. After that period of time, the Individual Analyzer Availability (IAA) shall be higher than 95%. The calculations for this index are shown in the next table.


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If this index is not reached within a maximum period of 30 days, considering 15 continuous days of test, the system will be considered not acceptable. This test shall include all purchased equipment and software. b) Performance Evaluation The analyzer system will be considered as performing satisfactorily, if the results obtained during the test run are lower than the standard levels defined in item 5.11.17.2.2. If one of them is higher, the test shall be repeated to verify if the analyzer system is working satisfactorily, and the analyzer system final acceptance shall be issued only when the performance criteria have been achieved. 5.11.18.SHIPMENT 5.11.18.1 The Analyzers System shall be prepared and shipped to the jobsite, with the following minimum protection measures: a) lines shall be cleaned; b) all external connections shall be capped or plugged to prevent entrance of foreign material; c) fragile or sensitive equipment and components shall be removed and packaged separately; d) all movable parts shall be secured or supported with shipping braces to prevent damage from vibration; e) all loose equipment shall be packed in shipping crates or cartons suitable for shipment. 5.11.19.ANALYZER SPARE PARTS 5.11.19.1 Spare parts shall be supplied for two years operation, for all Analyzers System equipment and accessories. 5.11.19.2 Manufacturer shall recommend spare parts and consumable for the complete analyzers system, including, if necessary, but not limited to the following: - Electronic boards: 1 of each type; - Relays: 1 of each type Switches and circuit breakers: 1 of each type; - Switches and circuit breakers ( for CEMES ): 1 of each type; - Lamps: 10% of total (at least 1 of each type);


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- Gaskets, O-Rings, Valve Packing: 10% of total (at least 1 of each type) ; - Diaphragms and other elastomer parts: 10% of total (at least 1 of each type); - Thermocouples and RTD: 1 of each type; - Electronic equipment ventilators: 1 of each type Power supply modules: 1 of each type; - Fuses: 50% of total (at least 3 of each type); - Analyzers Detectors: 1 of each type Analyzers sources: 1 of each type ; - Gas Detector Sensors: 1 of each type; - Analyzers light sources (for CEMES) : 1 of each type - Electronic display: 1 of each type; - Solenoid valves: 1 of each type ; - Solenoid valve coils: 1 of each type; - Micro-motors: 1 of each type Sample conditioning system spares; - Sample recovery system spares; - Recommended analyzer shelter spares. 5.11.19.3 Spare parts for Analyzers interface microcomputers will not be necessary. 5.11.19.4 Spare parts shall be delivered clearly identified with name and part number. 5.11.19.5 The proposals shall list spare parts in detail, with name, part number and prices. 5.11.20.SERVICES SPECIFICATION 5.11.20.1 The technical services shall be developed and executed by the manufacturer to facilitate the installation, start up and operation of the Analyzers System. 5.11.20.2 Scope of Field Services shall include, at least: - sample and utility lines inspection; - remote system inspection, such as probes and field station; - signal and electric power lines inspection;


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- gas containers and accessories inspection; - process and sampling pipelines cleaning. 5.11.20.3 Analyzers System Pre-start up, Calibration and Test shall include, at least : - field work management of tubing, wiring, gas container and accessories connections; - functional inspection of all analyzers and equipments; - calibration and operation of analyzers to assure performance guarantees; - analyzers output signal transmission validation; - connecting the Analyzers to process, after the process is operating. 5.11.20.4 Process Connected Analyzers Start up shall include, at least: - analyzers calibration with standard samples validation; - analyzers sampling systems start up; - analyzers operation connected to process stream; - analyzers operation stability supervision for final acceptance. 5.11.21.TRAINING

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5.11.21.1 The training for Maintenance, Operation and Engineering people shall be conducted as classroom instructions, concerning shelter safety and operation, sampling system project, analyzers operation, calibration and maintenance, including the presentation of drawings and specifications (this training may be held by analyzers manufacturers) at the refinery site . Training shall be at least 40 hours duration in a Portuguese language. 5.11.21.2 MAINTENANCE. 5.11.21.2.1 The trainee shall be able to identify, diagnose, repair, document and report any problem or calibration deviation of all analyzers system, including analyzers, probe, transport and conditioning system, and all other associated systems; 5.11.21.2.2 The trainee shall be able of calibrating any of the analyzers of the system. 5.11.21.2.3 Training shall include theoretical and practical parts. 5.11.21.2.4 Theoretical part shall include: analytical principles, block diagrams of the analyzers and the system and the external influences that may cause any damage to the whole system, results evaluation, safety systems and calibration of all systems with statistical analysis.


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5.11.21.2.5 Practical part shall include: identification of each part of the system, presentation of the most common problems and its solutions; warning to special care with the system; preventive maintenance (routine indicative frequency and parts to be normally checked); mounting and dismounting of electronic devices; practical training during analyzers calibration and testing and during analyzers start up; standard introduction to the analyzers. 5.11.21.2.6 The trainee shall be able to identify, diagnose, repair, document and report any problem with the House and Analyzers Control System. 5.11.21.3 OPERATION. 5.11.21.3.1 The trainee shall be able to start and stop analyzers operation, as well as associated systems, and also replace standard cylinders or vessels; 5.11.21.3.2 Training shall include theoretical and practical parts. 5.11.21.3.3 Theoretical part shall include: analytical principles, block diagrams of the analyzers and the system, and a explanation of the external influences that may cause any damage to the whole system and results evaluation. 5.11.21.3.4 Practical part shall include: standard introduction to the analyzers, and practical operation of all system, making all the alignments. 5.11.22.ENGINEERING DOCUMENTS 5.11.22.1 The manufacturer shall send the project documents list to PETROBRAS, before delivering the first technical document, and issue, at least the following drawings and/or documents: a) Data Sheet of analyzer, equipments, instruments, auxiliary systems, valves, filters, manometers, rotameters, and other parts which compose the Analyzers System; b) Material Requisition associated to the designed items; c) Analyzers System Schematic Drawing presenting the architecture and details of the equipment functions which compose analyzers, sampling system, interface, with components identification, lines dimensions, and operating set-points; d) Analyzers System details, comprising: - analyzers’ cabinet and shelter drawings with dimensions, plot plan showing the principal equipments and location of all field connections; - point to point wiring diagrams with internal connection details of each analyzer, interface and safety system;


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- analyzers tubing interconnection drawings with utilities identification, and lines dimensions; - Analog and digital input/output connecting board drawings; - list of system modules interconnecting cables. e) Electric Power Wiring and Grounding Diagrams for analyzers, interface, illumination, load and AC power distribution, cable specifications, junction box terminal identification, and area classification; f) Arrangement and Dimensions of analyzers, sampling system and interfaces; g) Project Basic Criteria for each equipment which compose the Analyzers System including, at least, the following information: - calculation sheet for instruments, - head loss and system response time; - electrical power system requirements; - grounding system requirements; - requirements and instructions for sampling transport lines assembling; - Installation requirements and instructions. h) Verification Criteria including the measurement points and the outline values to be analyzed by the time of Commissioning, in order to verify if the Basic Criteria of the Project is reached. 5.11.23.TRAINING MATERIAL 5.11.23.1 The manufacturer shall provide training manuals, postscripts and all documents which integrate the training courses documentation, with copies to each trainee. One additional copy of this documentation shall be issued to PETROBRAS for appreciation. Note: The training manuals shall be written in English or Portuguese. 5.11.23.2 SPECIAL TECHINICAL DOCUMENTS a) test procedure for factory inspection, indicating the reference documents; b) test reports executed during the factory inspection including all events, actions or solutions adopted; c) plant acceptance test procedures indicating the reference documents; d) plant acceptance test reports including all events, actions or solutions adopted. e) transport procedure and cautions;


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f) description of special cautions that must be adopted, in case of equipment temporary storage at PETROBRAS, before definitive installation; g) Training Program for Maintenance and Operation courses; h) instruments calibration certifications; i) performance tests procedures indicating the reference documents; j) performance tests reports including all events, actions or solutions adopted; k) as-built final drawings, in CD-ROM, in electronic files format. 5.11.23.3 Analyzers System Maintenance and Operation Instruction Manuals, including at least: a) tubing schematic and electric diagrams; b) analyzers wiring; c) Drawings with material identification and part numbers of mechanical, electronic and electrical parts with part number and commercial identification of all components. 5.11.23.4 Configuration and Calibration Manuals, including at least: a) Specification of the analyzers calibration standards, procedure and data tests; b) All programs and configuration lists (analyzers, interface, etc.). 5.11.23.5 Operation Manuals, including at least: a) All the associated analyzers and equipment, with special operation instructions, including the sampling system and other special systems. 5.11.23.6 Maintenance Manual, including at least: a) All the diagrams and electric scheme with part number indication and all components commercial designation, procedures and routines for preventive maintenance, inspection with indication frequency, corrective maintenance, calibration, and tests for all associated analyzers and equipment; b) A list of all necessary equipment and kits for first level maintenance (circuit boards replacement), and special tools for mechanical and electrical maintenance; c) Services information which: - can not be executed by PETROBRAS technicians; - shall be executed by third part;


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- shall be executed by the manufacturer at the factory; - Shall be executed by the manufacturer at the plant. d) Hardware Configuration Manual of electronic systems boards presenting the disposition of keys, jumpers, straps and other configuration devices. 5.11.24.FINAL ACCEPTANCE 5.11.24.1 The analyzers system will be considered accepted, with the emission of the Definitive Acceptance Certificate by PETROBRAS, if the following requirements have been reached: 5.11.24.2 DOCUMENTS 5.11.24.2.1 All the documents shall be in accordance with item 5.11.22. 5.11.24.3 TRAINING 5.11.24.3.1 The Training Acceptance Certificate will be emitted by PETROBRAS if all needs of maintenance, calibration, operation and engineering training are reached, in accordance with item 5.11.21. 5.11.24.4 PERFORMANCE 5.11.24.4.1 The system will be considered approved if during tests periods, as defined in item 5.11.17, all the criteria are reached, as defined in the same item. 5.12. MARSHALLING CABINET 5.12.1 The marshalling cabinet shall be equipped with a duplicated terminal block, namely: - Input block (side “A”) for connecting wiring from the field; - Output block (side “B”) for interconnecting with the Monitoring System. 5.12.2 The internal re-arrangement shall be made between the blocks of side “A” and “B”. The block of side “B” shall mirror the interconnections with the I/O modules of the DCS or PES according to the loading table. 5.12.3 All shielding of cables and multi-cables shall be insulated in instruments, and shall be grounded only in the Marshalling Cabinet. Terminals shall be provided for interconnecting drain wires. E

5.12.4Terminal blocks and wire ways shall be separated for the circuits of different signal levels. 5.12.5 All wiring inside the cabinets shall be routed in PVC wire-ways with covers, conveniently distributed and sized, considering in all cases 30% (thirty per cent) of reserve capacity.


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5.12.6 Electrical continuity of all component parts of the cabinet structure shall be ensured. To obtain efficient grounding there shall be provided a connector for the grounding cable and an insulated copper bus-bar in the lower inside part of the cabinet. E

5.12.7 Terminal block and multicables shall be identified according to item- 5.3.10, using a compression and indirect tightening with tubular clamp; double terminal is not permitted to use; 5.12.8 The cables on the field side shall be identified with the instrument TAG and its wires with the number of the terminal to which it is connected. In the internal part between blocks “A” and “B” with the terminal number, and on the side of the DCS the identification of the card to which it is interconnected shall be adopted. 5.12.9 A lighting system shall be installed inside the cabinet with a fluorescent lamp and a service receptacle at 120 V ac, 60 Hz. 5.12.10 Only two conductors may be connected per terminal, one on each side. If there is a need for more conductors connected in parallel, a fixed bridge shall be used. 5.12.11 The cabinets shall be provided with doors occupying the entire front area, with hinges opening to 120 degrees. The doors shall be fitted with latches with locks,. 5.12.12 All cabinet components shall be corrosion-resistant, and the anti-corrosive treatment shall consist of pickling, phosphatization, neutralization and final painting with polymerization and cooling. The color of the cabinets shall be the same as that of the DCS panels to be installed in the Equipment Room. 5.12.13 The paintwork shall comply with PETROBRAS standard N-1735. 5.12.14 Wiring shall enter and leave the cabinets through the bottom part. 5.12.15 There shall be no mixing in one and the same cabinet of different types of signals: - high level analog signals (4-20 mA); - low level analog signals (mV); - discrete signals – 24 V dc. 5.13.

FIRE AND GAS DETECTION

5.13.1 When required, the instruments of the fire and gas detection system shall have their own junction boxes, cables and multi-cables and the same resources of the process instrumentation shall not be used. 5.13.2 The criteria adopted for reserve, routing, materials, etc. shall be the same as those used for the process instrumentation.

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5.13.3 The fire and gas detection and alarm system design shall comply with standard NI-2761 and I-ET-6000.67-5423-855-WAP-001 “Fire and Gas Detection System Specification”

5.14. RESERVE CRITERIA 5.14.1 In all systems, junction boxes, cables, multi-cables, cabinets, panels, etc. provision shall be made for reserves for modifications during startup and to meet occasional needs arising during commissioning. In addition, space for expansions shall also be considered. ITEM Valves for pneumatic supply Capacity of pneumatic supply header, multicables, etc. Cable Trays Marshalling Cabinets DCS, PLC, PES Input and outputs DCS , PES, PLC memory and processing capacity

Used in design 90 % 70 %

Installed Reserve 10 % 30 %

Space for future -

60 % 70 % 80 % 60 %

40 % 30 % 20 % 40 %

15% 10% -

Where : Used in design: resources used in the design. Installed reserve: resources actually available without the need for mounting or wiring. Space for future: area physically available for assembly in relation to the total installed area. 5.14.2 Switchboards for electrical circuits for instrumentation shall have 20% of reserve circuit breakers or four units, whichever is greater. 5.15. INTERLOCKING AND EMERGENCY SHUTDOWN SYSTEM 5.15.1 The system is divided into three main sections: input, logic and output. The input is basically the point of arrival of all signals coming from the process sensors and pushbutton stations. The logic is the section capable of providing the whole of the interlocking necessary to permit the required actions of interlocking and emergency shut-down. The output is the section that has to provide the necessary interface elements with the elements subject to the above-mentioned activities, that is, the solenoids, panels and electrical equipment, and to provide signals for monitoring of the plant through the dry contacts.


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5.15.2 Equipment design shall be handled in such a manner as to provide visibility and ease of access for replacement of any component in case of a breakdown. Cabinets shall be fitted with hinges so as to provide ready access to the interconnecting wiring between components. 5.15.3 Command failures shall be alarmed. 5.15.4 The system shall permit a state in which maintenance and reprogramming can be carried out on-line without stopping the process. 5.15.5 By-pass logics shall not be used, with preference being given to timers or repositioning of sensor elements. 5.15.6 The interlocking and emergency shutdown system shall be of the fail-safe type, meaning that the circuits shall be energized under normal conditions and de-energized under abnormal and/or emergency conditions. For de-energizing of the system under normal conditions, means of detection of continuity (line monitoring) shall be provided. 5.15.7 Transmission of safety interlocking / emergency signal in communication network is not accepted. 5.15.8 By definition, alarm is a visual and sound signaling to alert the operator, following a predetermined sequence; event is any status modification occurring in the field, and interlocking is dependence on one event for another to occur, and this can be in the control area (on/off) or safety area (shutdown). 5.15.9 In those cases in which to meet the demand it is necessary to use two transmitters, one for control and the other one for interlocking, separate connections shall be provided for orifice plates, that is, a pair for control connections and another pair for interlocking. In those cases in which, according to N-2595, three transmitters in voting are necessary for safety interlocking, provision shall be made for the installation of another orifice plate for measuring the same variable in order to meet the needs of a total of four transmitters (01 for control and 03 for interlocking). 5.15.10 INPUTS 5.15.10.1 The design shall make provision for terminal blocks duly identified for all inputs. The terminals shall have capacity for wires of up to 2.5 mm2 of straight crosssection 5.15.10.2 Input signals will be from instruments installed in the process unit and connected directly to PES. 5.15.10.3 No interlock shall be initiated by signal coming from digital communication. 5.15.11 LOGIC 5.15.11.1 The logic of the system shall implement all commands required in the logic interlocking diagram and/or cause and effect diagram.


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5.15.11.2 The safety interlocking logic will be implemented by means of an equipment selected in line with the criteria set out in IEC-61511. 5.15.12 OUTPUTS 5.15.12.1 A fuse shall be provided for each output. 5.15.12.2 Outputs for electrical equipment using a voltage different from that used for instrumentation shall be physically separated from the other outputs, using another terminal block. 5.15.12.3 Terminal block shall have capacity for wires up to 2.5 mm2 . 5.15.12.4 The basic design shall consider the outputs where is mandatory the application of partial stroke device for tests on-line off shut-off valves. 5.15.13 ALARM SYSTEM 5.15.13.1 Any abnormal condition that may cause a shutdown action shall alarm before shutdown occurs. 5.15.13.2 In the case of equipment (compressors, generators, etc.) having their own annunciators in local panels, individual alarms shall be reproduced in the DCS. If control over these equipment items is effected by means of PLCs, serial communication with DCS shall be preferably provided. 5.15.13.3 The designer shall consider the first cause alarm for all the equipments, subsystem and all the plant shut-down. 5.15.14 ASSET MAINTENANCE 5.15.14.1 The design shall consider the multiplex HART for all analog signals and connecting it to the HART remote maintenance network in each CCL (Panels room). 5.15.14.2 For the purpose of diagnostics a single fail shall not cause the shut-down and have an alarm in the DCS and/or a specific on-line maintenance asset network.

5.16. PROGRAMMABLE LOGIC CONTROLLER FOR GENERAL APPLICATIONS 5.16.1 This item defines the basic requirements for PLC used only in the package units. These basic requirements shall to be in accordance with N-2194, and containing at least the following: • Basic architecture; • Composition and sizing; • Technical characteristics of PLC components;


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• Redundancy; • Availability; • Training; • Tests; • Warranty; • Technical Assistance; • Drawings and documents; • Spare parts. 5.16.2 The programmable controller shall be entirely of solid state design displaying a modular conception. 5.16.3 Provision shall be made for a self-diagnosis system residing in non-volatile memory, with periodical and automatic implementation covering the following requirements: • dedicated circuits; • programs for checking performance of all modules; • routines for handling errors. 5.16.4 Redundancy: a) There shall be CPU redundancy that will be implemented using two racks each of which containing: Source, CPU, I/O ,Processor and communications processor; b) On duplication of the CPU, the logic controller shall function on a hot-stand-by basis; c)Transfer of control from I/O to spare CPU shall take place automatically upon detection of any failure in the main CPU; d) There shall be a communications channel dedicated to the updating of the spare CPU data bank. 5.16.5 PLCs shall have an ETHERNET port for communicating with the refinery’s asset management network. 5.16.6 PLCs shall be obligatorily from manufacturers included in the Vendor List. No exceptions will be permitted regardless of the systems being applied. 5.16.7 When PLCs are purchased, aspects of exchangeability and network communication with the DCS shall be considered, and the scope of supply shall include


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the drivers and switches needed for integration with the DCS. The selected protocol for this integration shall be the MODBUS-TCP Protocol. 5.16.8 The PLC configuration software shall be supplied in conjunction with a notebook for each type of PLC used with the respective licenses for the operating system and application programs. The configuration software shall preferably use LADDER or FUNCTION (FC) BLOCK type programming language, running in Windows environment with complies with IEC 61131. If the manufacturer uses another programming language, this matter shall be discussed in the phase for defining the supply with inclusion of training and supply of information for this language to be fully understood. Likewise, the software of Human-Machine Interfaces (HMIs) provided in the design shall be supplied. 5.16.9 Sequence of Event • •

The PLC system shall be able to apply time stamp with scan rate resolution of 1 ms even if events occur in different PLCs. Each PLC CPU shall have its own GSP to synchronize with a 1 ms resolution to be applied on alarms and events.

5.17. PROGRAMMABLE LOGIC FOR SAFETY SYSTEM 5.17.1 The SAFETY PLC shall be compatible with the safety level required by PETROBRAS standard N2595 and be TÜV Rheinland certified for SIL 3 it shall be for SIL3, as defined on IEC-61508. 5.17.2 The equipment shall be certified for application on TUV class VI, AK6. 5.17.3 The SAFETY PLC shall also have an ETHERNET port for communicating with the refinery’s maintenance network. This maintenance network shall have a centralized engineering workstation. 5.17.4 The interface to the DCS will be implemented using OPC - UA protocol. If there is no option for OPC-UA integration, MODBUS-TCP in redundancy mode maybe acceptable. The supplier have to furnish all the variable addresses, alias and other information needed to do the connection. 5.17.5 The SAFETY PLC shall be compatible with Technical Specification I-ET6000.67-0000-941-WAP-006 “Safety Instrumented System- SIS (Preliminary Programmable Electronic System - PES) Technical Specification and marshalling cabinets with all hardware and software items and engineering services for configuration”. 5.18. INSTALLATION OF INSTRUMENTS 5.18.1 INSTRUMENT CONNECTIONS E

5.18.1.1 Materials shall be selected according to the COMPERJ technical specification, I-ET-6000.67-0000-800-PDY-004, based on N-1931. In cases not covered by the


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COMPERJ technical specification the designer shall create a material specification sheet corresponding to the piping specification and submit it to PETROBRAS for approval. 5.18.1.2 Connections of vessels and towers shall be on the sides to prevent clogging. Avoid installing connections at the bottom of vessels and towers. In special cases PETROBRAS shall be previously consulted. 5.18.1.3 Do not use a sealing pot on impulse lines. Instead of the latter, install a tee as indicated in NI-1882, item 10.3.15. 5.18.2 MOUNTING OF INSTRUMENTS AND VALVES E

This item is in addition to item 4.3.8, 4.3.13 and N-858; 5.18.2.1 Transmitters shall be installed so that maintenance activities may be carried out without the need for scaffolding. Locate close to ground level or build platforms, the height of instrument center line shall be 1,4 m from floor.

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5.18.2.2 The pressure transmitter shall be installed on a pedestal wherever possible, welded supports and fixed at concrete structure may be acceptable if the instrument will be installed at place with easy access;. 5.18.2.3 Instruments shall not be attached to handrails, pipe-racks or other points subject to vibration, blows or other disturbances. 5.18.2.4 In the assembly of valves interference with process equipment and lines shall be observed. The installation shall allow access to maintenance, preventing the drain valves from being mounted too close to the ground level. 5.18.2.5 impulse lines above 60C in the instrumentation installation, shall be protected against injury;

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5.18.2.6 A warning slab (150 x 50 mm) shall be installed at the instrument manifold to advertise the operator and maintenance when the process fluid is toxic, hot or flammable;

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5.18.2.6 the tag of the instrument shall be painted on their pedestals;

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5.18.2.7 the tag of control valve shall be painted on their actuators;

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5.18.2.8 hydro test shall be done in impulse line; 5.18.3 PNEUMATIC INSTALLATION

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This item is in addition to item 5.3.7, 5.3.12 and N-858; 5.18.3.1 Pneumatic signals shall not be transmitted over distances longer than 50m;

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5.18.3.2 Individual pneumatic transmission tubes shall be protected by channel;


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5.18.3.3 When using cupper tubing there shall be a PVC overcoat protection; E

5.18.3.4 pneumatic test shall be done in the signal and air supply lines; 5.18.4 ELECTRICAL INSTALLATION.

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This item is in addition to item 5.3.8, 5.3.11; 5.18.4.1 The electrical installation shall be in accordance with standard N-858 and NI1882. E

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5.18.4.2 Junction boxes shall be provides as follows: a) Separate junction boxes shall be provided for each kind of signal or system, examples: temperature, analog, digital ,safety, interlocking signals and fire&gas detection; b) Junction boxes shall have a degree of protection of IP 65 and a cover for rain protection. Such boxes shall be made of corrosion-resistant material such as aluminum or reinforced fiberglass. c) Junction boxes of SIS shall be painted with safety orange color 5.18.4.5 Mechanical protection of cables shall be provided as follows:

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a) in outdoor areas use fiberglass channels or aluminum conduits for individual cables and multi-cables of the instrument from the field to the junction box. b) for individual cables and multi-cables from junction box to marshalling cabinet (CCL) or panels, in outdoor areas, use fiberglass channels or cable trays.. And in crossover pipe-ways use aluminum conduits;

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c) in aerial cable trays for multi-cables entrance in the CCL; E

d) For cable tray installed in indoors areas (buildings, substations, etc.) hot dip galvanized steel must be adopted, maximum width 600 mm. The cable trays will be in SAE 1008/1010 steel plate 12 ABNT (2,65 mm). 5.18.4.6 Do not install cable trays in areas of intense cargo handling activities and on top of equipment operating at high temperatures. 5.18.4.7 All terminals shall be of the indirect tightening type, with low resistance metal parts and protected against corrosion, with a minimum insulation of 500 V in high quality thermo-fixed or thermoplastic material.

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5.18.4.8 Only two conductors may be connected per terminal block, one on each side. In case more conductors connected in parallel are needed, a fixed bridge shall be used. 5.18.4.9 All cables, wires and terminal blocks shall be identified in a fixed, permanent and indelible manner.


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5.18.4.10 The electrical installation shall be in accordance with standard N-858 and NI1882. Four-wire instruments shall have bipolar fuses in the electrical power supply circuit. All 24 VDC cables that go to the field shall have individual bipolar fuses for each instrument. All fuse terminal shall have indication of circuit open. 5.18.4.11 All signals of a cable in conduit shall have the same voltage level. For grouping together signal cables, use the same segregation criterion adopted for junction boxes. 5.18.4.12 Electrical connections of two-wire instruments shall be in ½” NPT. The cable shall be connected to the instrument through of cable gland, avoiding the use of flexible conduits. The cable shall be routed from cable tray to instruments by aluminum conduit let open end near the instrument. 5.18.4.13 Digital signal cables interconnecting CJ-D with the field solenoids have a minimum gauge of 2 x 1.5 mm², with general shield. The maximum drop voltage acceptable is 5%. 5.18.4.14 Multi-cables shall be of 12 or 24 pairs for field application and with a number compatible with the number of channels of input/output modules of digital systems as PLC, F&G, SIS and DCS for interconnections with the marshalling cabinets. 5.18.4.15 4 to 20 mA signal multi-cables interconnecting CJ-A with the marshalling cabinets in the control room shall be of section 0.5 mm2 and shall obligatorily have twisted and numbered pairs with individual electrostatic shielding in aluminum tape, and total and other characteristics in line with N-2384, with at least 30% of spare pairs. 5.18.4.16 Cables interconnecting discrete instruments in the field to Foundation Fieldbus converters or interconnecting trip contacts from PES to the MCC in the substations shall have section of 1,0 mm2, in twisted numbered pair, with total electrostatic shielding, with at least 30% of spare pairs. 5.18.4.17 Cables and multi-cables shall be specified in accordance with PETROBRAS standard N-2384, and the gauge of conductors and number of pairs per multi-cable shall be defined according to the preceding items. 5.18.4.18 All other interconnections within a marshalling cabinet shall be in wires or single pairs without shielding having a minimum section of 0,75 mm2.

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5.18.4.19 Interconnection shall be made with terminals (fork, tubular or eye types) as necessary for proper connection of wiring to equipment. 5.18.5 GROUNDING 5.18.5.1 Grounding shall be in accordance with PETROBRAS standard NI-1882 and with the specifications of the manufacturer of the Monitoring System and other equipments. The level of resistance of the grounding for Instrumentation shall not exceed 3 ohms.

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5.18.5.2 metallic conduction of cables (conduits and cables tray) shall be grounded;

5.19. PACKAGE UNITS 5.19.1 GENERAL RECOMMENDATIONS 5.19.1 The instrumentation belonging to package units shall follow the vendor list of PETROBRAS. 5.19.2 This Technical Specification shall be fully followed with respect to the technical instrument selection criteria. 5.19.3 Provision shall be made for junction boxes which will serve as an interfacing element with the process units. If a local panel is used, use of junction boxes may be dispensed with, provided this is previously authorized by PETROBRAS. The designer shall consider recommendations of N-2316. 5.19.4 A list of inputs and outputs shall be prepared so as to permit the execution of the remainder of the design separate from the development of the package. This list shall contain at least the TAG number of the instrument, type of signal, destination and identification of terminal/terminal block of the interface element (junction box or local panel). 5.19.5 In the case of equipment (compressors, generators, etc.) with their own annunciators in local panels, individual alarms shall be reproduced in the DCS. If control over these equipment items is via PLCs they shall be provided with serial communication with DCS through Modbus-TCP communication protocol and provision shall also be made for use of an Ethernet port for interconnecting to the maintenance network of refinery.

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5.19.6 The HMI of local panel shall be used for monitoring purpose but it recommend to avoid implementation of commands and it is recommended to specify commands with push-buttons , in the package panel, multi led lamp shall be used as alarm lamp; 5,19.7 Protection against direct sun light on display or rain, shall be provided for field panels (with or without Man-Machine Interface), such as: roofs, covers, etc. 5.19.8 For the purpose of remote configuration of instruments all analog transmitters and positioners shall be connected directly to HART Input I/O cards and not to HART multiplexers. The exceptional use of HART multiplexers has to have the formal approval of Petrobras. In the case of the use of HART multiplexers, all the multiplexers shall be connected in a serial network and interconnected to HART engineering network mounted in the CCL. 5.19.9 The Vibration Monitoring system shall be connected to a Ethernet network mounted in the CCL. 5.19.10 All PLC´s shall have an Ethernet 802.3 port in processor control unit to be interconnect to the PLC remote maintenance network in the CCL.


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5.19.11 The same criteria established in the other items of this document are applicable. 5.19.12 Unless otherwise specified, the package unit control panel shall be located at CCL for maintenance and protection reasons. Then shall be called Remote Control Panel ( RCP). 5.19.13 Local Control Panels (LCP) in the field will only be accepted if there is any technical impediment to justify the same, In this case shall be approved by PETROBRAS. 5.19.14 RCP or LCP commands for electric motors shall be sent directly to MCC (Motor Control Center). 5.19.15 All PLCs related to critical equipment shall be TÜV Rheiland SIL3 certified as defined on IEC-61508. Critical equipment is an equipment whose failure can critically compromise safety, environment or asset aspects of the related process. 5.19.14 LOCAL PANEL (LP) AND LOCAL CONTROL PANEL (LCP) E

5.19.14.1 The minimum protection degree for LP and LCP shall be IP-55 in accordance with standard IEC 60529. 5.19.14.2 The LP and LCP shall be built in stainless steel AISI-304 enclosures. 5.19.14.3 LP and LCP shall be pressurized in accordance with standard IEC 60079-2 (flameproof shall be avoided). 5.19.14.4 All LP and LCP shall be electrically powered as defined in this specification. 5.19.14.5 Unless otherwise specified, LP and LCP shall be provided with a HMI, based on a flat monitor of 12”. 5.19.14.6 The HMI shall be provided with a canopy in order to prevent glare, which might preclude screen readability. 5.19.14.7 LCP shall be provided with a Hart processor in order to filter hart signals from the 4-20mA instruments and integrated in the Hart Instrumentation Maintenance System. 5.19.14.8 For the Vibration machine monitor specified to be supplied with the LCP, it shall be provided with an Ethernet Port for future connection with the On-line Machine Maintenance System . 5.19.15 REMOTE CONTROL PANEL (RCP) 5.19.15.1 Minimum protection degree for RCP shall be IP-31 in accordance with standard IEC 60529.


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5.19.15.2 RCP shall be electrically powered as defined in this specification. 5.19.15.3 RCP shall be provided with a Hart processor in order to filter hart signals from the 4-20mA instruments and integrated in the Hart Instrumentation Maintenance System. 5.19.15.4 RCP shall comply with DCS serial communication requirements defined bellow. 5.19.15.5 RCP shall comply with PLC requirements defined bellow. 5.19.15.5 For the Vibration machine monitor specified to be supplied with the RCP, it shall be provided with an Ethernet Port for connection with the On-line Machine Maintenance System . 5.19.15.6 Cable entrances shall be done through the control panel floor. 5.19.15.7 Terminal boards for cables coming from the field shall follow the same sequence of the junction boxes terminal boards in order to avoid cable pair crossings. 5.19.16 COMMUNICATION BETWEEN CONTROL PANELS (LCP / RCP) AND DCS 5.19.16.1 The operation of any package unit shall be carried out through DCS, and all signals required for supervision and operation of each package unit shall be available in the DCS. 5.19.16.2 The communication, for monitoring and alarm purpose, between the DCS and the Local Control Panel (LCP), shall be done through Ethernet communication using fiber optic cables with Modbus-TCP protocol, the DCS being master in this communication. 5.19.16.3 The communication, for monitoring and alarm purpose, between the DCS and the Remote Control Panel (RCP), shall be done through a Ethernet communication using fiber optical cables with Modbus-TCP protocol, the DCS being master in this communication. 5.19.16.4 For control and interlock purpose, the signals between the DCS and the LCP and RCP shall be done by hardwired connection. Serial communication is not permitted. 5.19.16.5 Remote commands to start and stop the package shall be done by hardwired connection; on the other hand, commands for auxiliary equipment, for maintenance and/or test purpose, can be done by serial communication. 5.19.16.6 Unless otherwise specified, the status (if it is in operation or not) of the package unit shall be provided for DCS by hardwired connection. 5.19.17 PROGRAMMABLE LOGIC CONTROLLERS (PLC’s) ( Package Units ) 5.19.17.1 Unless otherwise specified by basic design, control and/or logic solver functions of a package unit shall be done by a PLC, installed inside of a LCP or RCP.


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5.19.17.2 All PLC shall be provided with an Ethernet port for remote maintenance supervision purpose. 5.19.17.3 All PLC power supply sources shall be full redundant. 5.19.17.4 All PLC for non-redundant package units shall be provided with redundant CPU and redundant communication between CPU and I/O cards. 5.19.17.5 The PLC I/O cards shall be provided with a minimum of 10% spare for each signal type. 5.19.17.6 The general PLC used for package units shall follow the item 5.16 of this specification. 5.19.17.7 The safety PLC used for package units shall follow the item 5.17 of this specification. 5.20. MOTORIZED VALVES TELECOMAND SYSTEM 5.20.1 This technical specification establishes the necessary minimum functional, performance and hardware requirements for the design of the Motorized Valves Telecommand System (STVM). 5.20.2 The STVM shall be designed with Intelligent Electrical Actuators (AEI´s) coupled to the valves. 5.20.3 All operation commands of the valves shall be made through the Man-Machine Interface of the Digital Control System (DCS) and diagnosis and configuration functions will be performed by the engineering workstation of DCS. E

5.20.4. The basic design shall define the AEI´s that must have the fire-proof requirements for the great process barrier in case of fire. 5.20.5 The actuator shall be compatible with Foundation Fieldbus Protocol. The vendor shall prove the supply of more than 200 actuators with Foundation Fieldbus protocol with good performance certified by a client letter. 5.20.6 The electric actuator for process block valves and for emergency isolation valve (fireproof) shall be of the same vendor for each process unit. 5.20.7 FUNCTIONAL SPECIFICATION 5.20.7.1 The Motorized Valves Tele-command System (STVM) shall command the opening and closing of all valves interconnected of the system with the same performance requirement for all valves. 5.20.8 PERFORMANCE 5.20.8.1 STVM shall operate with minimum availability of 99,9%.


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Note : Availability = 1 - non available time (h) x 100% / Sampling Time (720 h). 5.20.8.2 A command of valve operation shall act on the valve within 2 seconds at most . 5.20.8.3 In case of failure of any internal mechanism the valve may be operated by a hand-wheel. 5.20.8.4 The minimum warranty of the actuator must be 3 years. 5.20.9 FUNCTIONAL SPECIFICATION - AEI 5.20.9.1 The AIE shall have the following requirements. 5.20.9.2 Commands

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a)

To open the valve partially or totally (local or remote);

b)

To close the valve partially or totally (local or remote);

c)

To stop the valve (local or remote).

d)

To move the valve for a continuous 0 to 100 % opening degree;

e)

To move to a pre-defined position (ESD).

f)

Partial stroke

5.20.9.3 Operation modes a)

Local

b)

Remote

c)

Local Manual using handwheel

5.20.9.4 Variables of supervision (digital and analog) a) Valve Position OPEN Detected by limit-switch; b) Valve Position CLOSED

Detected by limit switch;

c) Switch Position LOCAL / REMOTE; d) Valve Opening degree continuous 0 to 100 %; e) Valve in opening movement; f) Valve in closing movement;


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g) valve stopped in a middle position. h) Partial stroke sucesful

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5.20.9.5 Interlocking 5.20.9.5.1 Torque switch action: immediate stop of the motor in opening or closing operation of the valve. 5.20.9.5.2 Limit switch action: immediate stop of the motor operation of the valve. 5.20.9.5.3 Motor overload

in

opening

or

closing

action: immediate stop of the motor.

5.20.9.5.4 Reversion action: to Inhibit command to OPEN with valve Closing as well as command of CLOSING with valve opening. Since it implies in the automatic sequencing: command of stop, timing and operation, in this order 5.20.9.5.5 Blocked rotor action: immediate stop of the motor 5.20.9.5.6 Lack of Phase action: immediate stop of the motor with inhibition of any other command. E

5.20.9.5.7 For valves that belongs to SIFs the detailing design shall determine that eletronic parts of the AEIs shall have independent power supply in order to interrupt energy related to power supply, open/close emergency commands and MCC independent drawer. 5.20.9.5.8 The AEI housing and all electric/eletronic accessories installed on field must comply with Brazilian standards ABNT NBR Exd IIB T4 and NBR IEC 60529:2005. The AEI housing shall have internal sealing between connections compartment and other internal pars of the actuator. 5.20.9.5.9 STVM shall command open and close of all valves of the network, shall monitor AEI and network state, handle commands and report abnormal events to DSC using the Foundation Fieldbus protocol. The actuator shall have the ITK 5.0 or latter interoperability certificate from Fieldbus Foundation. 5.20.10 SPECIFICATION OF HARDWARE - AEI 5.20.10.1 Enclosure IP 67.

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5.20.10.2 Squirrel cage motor 480 VAC (+/-10%), 60 Hz @ 3 phases. 5.20.10.3 “Built-in actuator in the same enclosure.

and its electric and / or electronic accessories integrated

5.20.10.4 Certificate at least for classified area : Ex-d Gr II B T4.


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5.20.10.5.Local Signaling a) position indication : 0 to 100% continuous in an electronic display; b) open valve

: luminous in the green color;

c) closed valve

: luminous in the red color;

d) position and torque continuous indication (0% to 100% and <1% accuracy); e) fault/alarm state indication; d) calibration

: preferably in Portuguese language;

e) diagnostics

: preferably in Portuguese language;

5.20.10.6 Local command a) operation modes

: keys for local/remote selection;

b) to open valve

: push-button;

c) to close valve

: push-Button;

d) to stop valve

: push-button.

5.20.10.7 The Torque keys and limit switches shall be adjustable. 5.20.10.8 A hand-wheel shall be operate in manual way for coupling and in automatic way for decoupling.. 5.20.10.9 In the case power supply failure the last valve position, before the power supply failure, shall be stored in a non volatile memory, avoiding the loss of calibration and thus, guaranteeing actuator accuracy when power is normalized. 5.20.10.10 Closing and opening time shall complies with N-2160 and consider the valve size. E

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5.20.10.11 Electric connection with with - electric of 480 VAC thread NPT ( 1”);

VCD

thread

NPT,

(3/4”)

and

5.20.10.12 Painting procedure shall be corrosion and weather resistant and complies with PETROBRAS painting standards, if in fire proof service, intumescent coating shall be applied; 5.20.10.13 Identification shall be a nameplate in stainless steel, with the following data: Model, Number of Series, Tag.

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5.20.11 SPECIFICATION OF HARDWARE OF VCD 5.20.11.1 The protocol for communication in STVM VCD shall be Foundation Fieldbus Any proprietary protocol is not allowed. 5.20.11.2 Distance among elements of VCD without repeater use complies with Foundation Fieldbus segment specification. Any AEI of the VCD shall be able to be removed even energized without any interference to the other devices.

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5.20.11.3 The VCD cable with pair of twisted electric wires, with electrostatic shield and wire drain, for installation in apparent metallic conduit of (3/4”) and complies with Foundation Fieldbus physical layer specification. 5.20.11.4 Interface with VCD shall have Insulation of galvanic or optical type and protection against transients complies with CODE IEC 801-4-1988; 5.20.12 STVM SPARE PARTS RECOMMENDATION RECOMENDATION

QUANTITIES AEI

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5.21.

Electronic boards

5%

Contactors Relays Motor Transformers

5% 2% 2% 2%

keys and Electric Buttons Sealing rings and gaskets fuses and Lamps

5%

Thermostats Micro-switches

2% 5%

5% 20%

MEASUREMENT STATION FOR CUSTODY TRANSFER – LIQUID EMED

5.21.1 PROJECT 5.21.1.1 The EMED project shall complies with the following standards and regulations a) API Manual of Petroleum Measurement Standards - chapter 4 – Proving Systems (all section); - chapter 5 – section 5.3 – Measurement of Liquid Hydrocarbons by turbine meters;


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- chapter 5.4 – Accessory equipment for liquid meters - chapter 6 – section 6 – Pipeline Metering System b) ANP/INMETRO - Portaria Conjunta nº 1, 19.jun.2000 - DOU 20.jun.2000 5.21.2 MOUNTING 5.21.2.1 It shall be skid mounted with all of the major equipment mounted in a rigid structural skid base suitable for transportation to the refinery and for proper support during operation. 5.21.2.2 All skid instruments process tubings and fittings shall be specified as 316 SS. E

5.21.2.3 The EMED shall be a complete system mounting on a skid including measurement instruments, valves, tubes, prover, totalizer, printers and Flow computer panel. 5.21.2.4 The EMED shall have two set of measurement instruments. 5.21.2.5 The EMED shall have each Flow computer with redundant Ethernet communication with protocol modbus-TCP to integration with DCS.

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5.21.2.6 The EMED panel shall be installed in the CCL, with the flow computer mounted in their front surface; 5.21.2.7 The flow computer shall be capable to multi stream measurement, microprocessor based with 16 bits, electronic measurement according to API 21, as a minimum of functionality: LCD interface display; serial port (modbus; Ethernet ports; printer interface; analogic input; thermocouple and RTD input; diagnostic monitoring; storage capacity for 30th days; RTC – real time clock; event and alarm data logger; alarm configurable; 5.21.2.8 the calculation software shall be approved by international entity, and the flow computer shall have the model approved by INMETRO to be applied on custody transfer; 5.21.3 DOCUMENTATION 5.21.3.1 The design documentation shall at least contain: a) piping and instrument diagram; b) general assembly; c) instrument console lay-out; d) equipment list; e) loading plan; f) instrument list/data sheets;


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g) junction box detail; h) instrument loop diagram; i) control /status loop diagram; j) interconnect cable list; k) instrument hook up; l) installation instructions; m) operation and maintenance manual; n) map of memory – for Modbus-TCP communication to DCS; o) Logic diagram/ladder diagram – program of PLC. p) quality assurance data; q) acceptance test program; r) pressure drop calculations. 5.21.4 – Factory Acceptance Test 5.21.4.1 At the factory at least the following tests shall be made: a) visual inspection; b) hydrostatic test; E

c) instrument calibration and flow computer configuration; d) factor determination and repeatability– meter factor checked in seven consecutive passes or round trips, for a certain flow must repeat within 0,05 % (0,025 % of the average) - repeatability shall be checked in five different flow rates, - inhibited water shall be used as test medium, - the average of results from the passes of prover round trips then will become the meter factor to be used in subsequent operations. e) linearity – the meter factor in flow from the above test shall not oscillate more than +/0,25 % between each other, for turbine meter up to 3” in and +/- 0,15 % for larger turbines ; f) waterdraw – the average of five consecutive trips shall agree with 0,02 % (+/- 0,01% of the average) g) functional;


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h) pick-up coil – made with a oscilloscope. 5.21.5 Site Acceptance Test 5.21.5.1 At the refinery at least the following tests shall be made a) Linearity and repeatability – for minimum period of 1 (one) month, the meters shall be tested as often as possible. During this period, the meter factors for an identical operational condition should not be greater than +/- 0,1 % (linearity, repeatability and temperature); these conditions are the same described for factory acceptance tests and shall be frequently repeated pumping the product. b) pressure drop; c) temperature compensation –pump products each 2 hours and read local temperature each 15 minutes; the difference between net totalizer and gross totalizer corrected through manual calculation shall not be above 0,05 % (thermometer precision must be +/- 0,2 %). d) density meter – the difference between two consecutive density values from line sampling by picnometer method and values from inline densitometer shall not differ above 0,1 %. 5.21.6 – Turbine meter 5.21.6.1 The specification shall consider at least +/- 0,15% linearity and +/- 0,02% repeatability. 5.21.7 – The figure above shows an example of liquid EMED instrumentation.


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5.22.

EMED for measurement of gas

5.22.1 PROJECT 5.22.1.1 The EMED project shall complies with the following standards a) API Manual of Petroleum Measurement Standards - chapter 14 ; - chapter 21. b) AGA Report 3 c) ANP/INMETRO - Portaria Conjunta nº 1, 19.jun.2000 - DOU 20.jun.2000 5.22.2 MOUNTING 5.22.2.1 It shall be skid mounted with all of the major equipment mounted in a rigid structural skid base suitable for transportation to the refinery and for proper support during operation. 5.22.2.2 All skid instruments process tubings and fittings shall be specified as 316 SS. E

5.22.2.3 The EMED shall have each flow computer panel with redundant Ethernet communication with protocol modbus-TCP to integration with DCS 5.22.2.4 The EMED shall have two set of measurement instruments.

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5.22.2.5 The EMED shall have each Flow computer with redundant Ethernet communication with protocol Modbus-TCP to integration with DCS.

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5.22.2.6 The EMED panel shall be installed in the CCL, with the flow computer mounted in their surface;

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5.22.2.7 The flow computer shall be capable to multi stream measurement, microprocessor based with 16 bits, electronic measurement according to API 21, as a minimum of functionality:

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LCD interface display; serial port (modbus; Ethernet ports; printer interface; analogic input; thermocouple and RTD input; diagnostic monitoring; storage capacity for 30th days; RTC – real time clock; event and alarm data logger; alarm configurable; Gas chromatograph interface; 5.22.2.8 the calculation software shall be approved by international entity, and the flow computer shall have the model approved by INMETRO to be applied on custody transfer; 5.22.2.9 the flow computer shall be capable to be connected to a gas chromatography or receive the gas composition by serial link, the electronic module shall be able to calculate compressibility factor (Z), specific gravity and heating value;


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5.22.3 DOCUMENTATION 5.22.3.1 The design documentation shall at least contain : a) piping and instrument diagram; b) general assembly; c) instrument console lay-out; d) equipment list; e) loading plan; f) instrument list/data sheets; g) junction box detail; h) instrument loop diagram; i) control /status loop diagram; j) interconnect cable list; k) instrument hook up; l) installation instructions; m) operation and maintenance manual; n) map of memory – for Modbus.TCP communication to DCS; o) Logic diagram/ladder diagram – program of PLC. p) quality assurance data; q) acceptance test program; r) pressure drop calculations. 5.22.4 – Factory Acceptance Test 5.22.4.1 At the factory at least the following tests shall be made : a) visual inspection; b) hydrostatic test; E

c) instrument calibration and flow computer configuration; d) repeatability; e) linearity;

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g) functional. 5.22.5 Site Acceptance Test 5.22.5.1 At the refinery at least the following tests shall be made a) linearity b) repeatability; 5.22.6 Unit Conversion 5.22.6.1 The measurement value shall be converted for PETROBRAS normal conditions: 1,033 kgf/cm2 at 20 oC . 5.22.7 – The figure shows a example of EMED for gas.

5.23. CONTINUOUS EMISSION MONITORING SYSTEM - CEMS E

To additional information see I-ET-6000.67-0000-941-WAP-028 – Specification For Process Analyzer Systems and Network 5.23.1. SCOPE 5.23.1.1. This specification is for a CEMS that shall be required for monitoring emissions in combustion fuel gases from a stack . 5.23.1.2. The design shall consider the specification of automatic analyzers for monitoring gas emissions in heaters, furnaces and boilers stacks. 5.23.1.3. All the information shall be integrated in a centralized combustion Emissions Monitoring Systems, CEMS, and the information shall be available for the safety and environment refinery team.


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5.23.2. GENERAL 5.23.2.1. Design practices shall be logical and consistent throughout the project. Consideration shall be given to uniformity in the selection and use of materials, components, and equipment. Construction materials shall be specified as non-corrosive and non-combustible in normal plant operating conditions. 5.23.2.2. The analyzers shall be furnished in accordance with the project requirements as described in this document analyzers specification requirements topic 4.11, except for the specific topics for CEMS that will described in the next topics. 5.23.3. SPECIFIC REQUIREMENTS FOR CEMS 5.23.3.1. The following engineering units shall be considered as a standard for all the documentation and for analyzers display: a) Temperature

o

b) Concentration

mg / Nm3

c) Pressure

C

kgf / cm2

d) Low pressure

mm.H2O

e) Flow liters / h or liters / min f) High flow

Nm3 / h

5.23.3.2. The Analyzers System shall be designed for continuous and efficient operation. 5.23.3.3. The components to be measured are CO, CO2, NO2, NOx (NO+NO2), SO2, O2, H2S, moisture, dust and opacimeter using a cold-dry extractive sampling system. Note: Extractive dilution and in-situ systems will not be accepted. 5.23.3.4. The CEMS system will measure stack Flue flow and will provide analog and serial input to opacity measurement. 5.23.3.5. The system shall be installed in a cabinet, with an analyzer system management- ASM, auxiliary equipment and accessories. All the related services, as design, assemblage, commissioning, start-up, pre-operation, documentation, training and acceptance tests shall be included. 5.23.3.6. The analyzers, sampling system, and related equipment shall be assembled and interconnected with utilities and accessories as required for continuous and unattended operation. 5.23.3.7. The Analyzers System shall include devices and facilities to allow easy operation and maintenance.


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5.23.3.8. One analyzer system may be used for up to two sampling points. In this situation all the requirements stated for single sampling point analyzers shall also be met (total analyzers cycle time, etc). 5.23.4. BASE EQUIPMENT 5.23.4.1. Heated sample probe with standard 150 # (diameter) mounting flange 5.23.4.2. Continuous length of heated sample transport line. 5.23.4.3. Sample conditioning system as required to condition and prepare samples for analysis. 5.23.4.4. One set of gas analyzers to measure concentration of (CO, CO2, SO2, H2S, O2, moisture and NOx), dust and opacity in stack flue gas. 5.23.4.5. One flue stack flow measurement system. 5.23.4.6. Validation and Calibration gases, cylinder regulators, supply manifold and auxiliary devices necessary to perform system calibrations and validations. 5.23.4.7. A system enclosure designed to house, protect and maintain the sample conditioning system, ASM and analyzers within an acceptable ambient operating climate. 5.23.4.8. One set of special tools and calibration fixtures or devices, when required. 5.23.4.9. All interconnecting signal cables necessary to ensure proper operation of the system, excluding cables for connection with the DCS. 5.23.4.10. One set of consumable and spare parts for two years operation. 5.23.4.11. One ASM (analyzer system manager) that will control the sample conditioning system, connect and communicate with the analyzers , with the flue stack flow measurement system, with the opacimeter analyzer ,with the graphic operation interface and with the DCS. 5.23.4.12. One notebook computer for industrial use, with all software and accessories required for interfacing with the analyzers, the graphical interface and the ASM, along with software for maintenance, diagnostics, configuration and data base archiving, shall be furnished. 5.23.4.13. System documentation in the form of a CEMS operation and Maintenance manual, as-built system drawings, bill of materials, recommended spare and consumable spare parts. 5.23.5. RESPONSIBILITIES 5.23.5.1. Analyzer System Vendor – ASV.


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5.23.5.1.1. The ASV shall be responsible for the complete design of all analyzer system, from the process sample tap to the output signal wiring and include all aspects concerning adequate operation of the Analyzers System, as well as all of the interconnecting piping, tubing and wiring, as required for installation of the Analyzers System at the jobsite. 5.23.5.1.2. The ASV shall be responsible for all activities related to the design, assembly and installation of the Analyzers System. The extent of work shall include, but not be limited, to the following: a) Engineering design and specification of the Analyzers System, complying with technical specification; b) Preparation of design drawings for Analyzers System; c) Coordination and issuing of all purchase orders for materials, calibration standards and all equipment related to the Analyzers System. d) Assembly of Analyzers System according to design drawings and specifications; e) Testing and inspection of all Analyzers System, at the factory and at the plant site, to demonstrate compliant system operation. f) Mounting and installing CEMS hardware, cabinetry and probes. g) Installing sample umbilical. h)Installing hardware in the form of scaffolding, ladders, platforms and all necessary structural components necessary to install and service the CEMS equipment. i) PETROBRAS’ technical personnel training in the operation and maintenance of the CEMS. j) Pre-operation, start-up, commissioning and test services as required for guarantee the CEMS operational for normal continuous monitoring. 5.23.5.1.3. The ASV shall be responsible for packing the Analyzers System properly for maritime and road transport.

5.23.6. CEMS ANALYZERS 5.23.6.1. General 5.23.6.1.1. A system for purging and cleaning the analyzers, sensors and sampling system shall be supplied to prevent deposits on the sensors during shutdown. 5.23.6.1.2. The environmental variations (barometric pressure, temperature, humidity, etc.) shall be taken into consideration and compensated, if necessary, for the performance criteria assessment.


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Note: The ASV shall be responsible for installation of any device necessary to correct or compensate for the environmental influence on the system performance. 5.23.6.2. Analyzers Requirements D

5.23.6.2.1. Analyzers provided and integrated into the system shall incorporate the following accepted methods of detection; Components

Analyzer Technique

CO

Infrared Absorption

NOx

Infrared or Ultraviolet Absorption (see note 1 below)

SO2

Infrared or Ultraviolet Absorption

O2

Paramagnetic or Zirconium Oxide (see note 2 below)

NO2

Ultraviolet Absorption

CO2

Infrared Absorption

H2S

Ultraviolet Absorption

Moisture

Infrared Absorption

Opacimeter

Scattered Light

Dust

Electrostatic Detector

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Note 1: NOx measurement shall include NO2 to NO converter Note 2: Zirconium oxide shall not to be in-situ type 5.23.6.2.2. The analyzer system as whole, including accuracy, cycle-time, sampling system design, shall be capable of complying with CONAMA 382 resolution and/or local regulations and standard codes. 5.23.6.2.3. The analysis shall be of extractive type, dry base, in the reference conditions of 7 % and 15 % of O2 and without correction. In situ analysis and extractive with dilution will be not allowed. 5.23.6.2.4 Detectors of the gas analyzers shall respond to a minimum of 2 % of full scale step changes for the gas being monitored. 5.23.6.2.5. Analyzers detectors shall be tolerant to interfering components. A twofold concentration change of any single or combination of interfering constituents in the sample gas stream shall not affect the analyzer reading.


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5.23.6.2.6. The analyzers system shall include a local multifunction indicator to display the measured values according to the specified range, as well as any type of alarm concerning SCS malfunction and/or cabinet control. 5.23.6.2.7. Analyzers shall be capable of range changes either manually or automatically whenever gas concentrations exceed 90% of the full scale value. 5.23.6.2.8. Analyzers shall exhibit a zero drift response of less than 2% of the full scale reading for any 10oC temperature change over the recommended operating temperature range for the instrument. 5.23.6.2.9. Analyzers must be capable of providing a 90% response to a 100% concentration step change within 40 seconds or less. 5.23.6.2.10. Analyzers when connected in a series arrangement shall respond in accordance with required sample cycles (one complete set of sample measurements for constituent gases being monitored must be completed within 15 minutes or less, unless local codes requires shorter cycle times). 5.23.6.3. Measurement and Output Signal 5.23.6.3.1. The required analysis measurement range is given in the Analyzers Data Sheet. Adequate definition for analyzers range shall be made by ASV. 5.23.6.3.2. All analyzers system, flue stack flow measurement system and signals outputs shall be transmitted to the ASM. 5.23.6.3.3. The Analyzers shall have a status output signal to validate the analysis output signal as “good/not good”, resulting from auto diagnosis, according to the data sheets. 5.23.6.3.4. The communication mode between analyzers and ASM shall be using Modbus-TCP or OPC – UA as between ASM and DCS. Any other protocol shall be submitted for PETROBRAS approval 5.23.6.3.5. Isolated 4-20 mA outputs shall be used if serial communication is not possible between analyzers and ASM. 5.23.6.3.6. All the output signals, as (sampling, calibration, blow-back, communication interface, allowing personnel through the DCS or communication link.

well as status information related to each analyzer etc), shall be made available at the ASM them to be easily accessed by maintenance any other device remotely connected to the

5.23.7. SAMPLING SYSTEM 5.23.7.1. General 5.23.7.1.1. The Sampling System includes the transport line, conditioning and disposal systems. It shall be designed to provide a representative process sample under conditions which are compatible to the operation of the analyzers.


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5.23.7.1.2. The Sampling System shall be designed to minimize the consumption of process sample and minimizing potential hazards in the event of a leak. 5.23.7.2. Sample Probe Design a) Samples shall be collected with a low-volume sample probe. Such sample probe shall include a manual shut-off valve to allow isolation of the sample line at the tap. b) The standard probe shall be constructed of materials that are corrosion resistant and chemically inert with respect to the process gases being sampled. c) The probe pipe shall be fabricated with a length that ensures representative samples are obtained for analysis. The probe pipe shall extend a minimum one meter into the stack. In case of diameters smaller than three meters, the probe shall be extended to 1/3 diameter of the stack. d) Sampling probes shall be designed to incorporate a series of filters or other suitable technology to mitigate plugging resulting from uptake of particulate matter. Porosity size of the filters shall be engineered to maximize removal of particulate matter without restricting sample flow. e) Filtering media integrated into the sample probe shall be temperature controlled and maintained at a temperature which prevents condensation of moisture. f)

Replacement of probe filters shall be possible and require minimal effort.

g) Sample probe components mounted externally to the stack shall be completely enclosed within an enclosure suitable for protection from the specific environment. The enclosure shall be appropriately sized to facilitate maintenance and to prevent overheating of electrical elements. Enclosure shall attend IP 56 as a minimum. h) Sample umbilical shall connect to the sample probe with standard tubing fittings, either compression type or quick disconnect. i) The sample probe shall be designed to have the capability to accommodate cleaning of its filters either continuously or intermittently. j) The sample probe shall have the capability to accept and introduce calibration gas directly into the probe’s sampling orifice to simulate the sample flow path. Sampling systems shall include facilities for manual and automatic introduction of validation and calibration samples which may be done in two ways: directly to the analyzers or through the probe. Starting a validation and calibration cycle shall be possible from the field or from the control room (through the serial link between DCS and ASM). 5.23.7.3. Sample Transport Line a)

The sample transport line shall be umbilical type.


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b) The sample gas umbilical shall contain the required number of tubes necessary to accommodate transport of the sample, validation/calibration gases and compressed gas for probe blowback. c) Tubes within the sample umbilical shall be corrosion and chemically resistant to sample gases. Materials of composition should also be selected to minimize sample deposition, sample adsorption and loss of sample gas resulting from diffusion. d)

All tubing within the sample umbilical must be continuous.

e) Materials of construction for the sample umbilical shall conform to applicable NFPA and IEEE standards. f) Exterior sheathing for the sample umbilical shall be inert, abrasion resistant and flame retardant. g) Electrical heat tracing of the sample umbilical shall be provided. The umbilical temperature shall be adjustable between 40oC and 130oC, as a minimum range. h) Heat tracing shall be designed to accommodate the climatic conditions. Heating shall be consistent with the temperature limitations of the sample line’s tube materials. i) Proper insulation shall be provided for personnel protection, according to piping thermal insulation standards recommendation. j) A temperature sensor is required to monitor and control the temperature along the entire umbilical extension. k) Umbilical run shall be adequately designed to prevent moisture from accumulating within the sample line. l)

Sample tubes shall be appropriately sized to minimize lag times.

m) Overall physical characteristics such as diameter, overall length, bending radius and weight shall be minimized to facilitate installation. 5.23.7.4. Sample Conditioning System a) All system components shall be fabricated from materials that are corrosion resistant and chemically inert to the gases in the sample stream. b) The sample conditioning system shall incorporate all necessary components to prepare the sample gases for introduction into the analyzers. At a minimum, the sample conditioner shall ensure that a sample delivered to the analyzers is consistent with the sample requirements of each analyzer. Consideration shall be provided to appropriately adjusting or controlling the sample gases for the following: - Pressure - Temperature


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- Sample flow rate - Particulate concentration - Moisture content - Removal of interfering components and acidic mist. c) The sample conditioning system shall have the capability to condition and control validation/calibration gases identically to the sample gas conditioning. d) Components comprising the sample conditioning system shall be located in such a way to allow easy access for maintenance. e) Moisture removal from sample is required. Sample dew point must be lowered to a temperature that adequately removes excess moisture, subsequently preventing carryover to the analyzers. Neither compressor based cooling devices nor molecular sieve (permapure, etc) are accepted. f) Care shall be exercised by ASV to guarantee that dilution of any component (mainly SO2) in the moisture that was condensed and separated from sample is kept to a minimum. Maximum dilution figures shall be submitted by ASV to PETROBRAS approval during sampling system design. Redesign of sampling system shall be considered in case such figures will be considered not acceptable. g) The system shall be designed to have the capability to integrate alarms that monitor operation of the system and provide warning whenever sample conditions exceed specified limits such as flow, temperature, pressure or moisture content. h) Sampling Systems which are remotely located, related to the sample tap (e.g., at the cabinet) shall include a primary inlet shut-off valve to complete isolate the system from the transport line. i) Sample Conditioning Systems shall be mounted inside the cabinet. j) All sample indicators (temperature, pressure or flow) shall be sized so that the indication is in the second third of the scale under normal operating conditions. k) The design and assembly of Sampling Systems shall give proper consideration to the logical and consistent organization and configuration of component parts. Special consideration shall be given for sloping of lines, low point drains, condensation prevention, sample cross-contamination, dead-end pockets, and accessibility to maintenance items such as filter elements. l) Blocking valves shall be supplied for all components of the sampling system (filters, coalescers, etc.) to allow easy removal, for maintenance purposes. m) A laboratory sample point shall be included in the analyzer system at an accessible point downstream the sample pump, to ensure a fresh laboratory sample and comparable to the sample taken to the process analyzer.


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5.23.8. ANALYZER SYSTEM MANAGER (ASM) 5.23.8.1. The ASM shall be capable of acquiring and monitoring serial / analog / discrete signals and alarms from the cabinet, analyzers and sampling system. It shall also perform cabinet interlock, if required. 5.23.8.2. The ASM shall be capable of commanding external devices as motors, solenoid valves, buzzer, lamps, and similar devices, if required. The ASM shall communicate with the plant control DCS through modbus-TCP or OPC – UA to report all the analyzers system information and communicate with the multifunctional display/ operator display. 5.23.8.3. The ASM shall have a discrete, dry contact output wired to the DCS signaling the occurrence of any alarm at the analyzers system. 5.23.8.4. The following alarms shall be available at the digital communication with the DCS, as a minimum: •

Low sample flow

•

High temperature in the cabinet

•

Low temperature in the cabinet

•

High moisture in the sample at the analyzer inlet

•

Calibration failure

•

Cabinet pressurization loss

5.23.8.5. The ASM shall have a local operator interface, with suitable hardware and software to allow the supervision and control of the system. A local alphanumeric display for any analog variable indication and discrete variable signalizing, shall also be available. 5.23.8.6. The ASM shall have a local keyboard for configuration, operation and alarm acknowledgement. 5.23.8.7. The ASM shall have a local buzzer to warn about any analyzer, cabinet and/or system alarms. 5.23.8.8. The ASM configuration and programming shall be executed by the ASV. Such configuration parameters, as well as programming software, shall be made available to PETROBRAS. 5.23.8.9. Every solenoid valve, if required, shall be individually wired to discrete outputs of the ASM. In a similar way, every contact signal shall be individually connected to discrete inputs of the ASM. 5.23.8.10. In case of power supply loss, no solenoid valve shall allow flow of sample or standard gases into the casing or analyzers themselves.


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5.23.8.11. The ASM shall stop sampling and starting blowback in case there is a severe process upset or plant shutdown. This shall be implemented by means of serial signal from DCS or by a digital hardwire signal. 5.23.9. INSPECTION AND TESTS AT THE FACTORY 5.23.9.1. During the Analyzers System fabrication and tests, inspections may be performed by PETROBRAS or by PETROBRAS designated third party, to determine the work progress, specification compliance and adequacy of installation to its purpose. 5.23.9.2. After Analyzers System assembly completion, PETROBRAS will perform the final inspection and will supervise the tests at factory site. 5.23.9.3. PETROBRAS shall be notified at least thirty days in advance of factory tests. 5.23.9.4. The Analyzers System shall be verified and tested prior to shipment, in order to assure the conformity with the design, and the proper installation and operation. 5.23.9.5. The checkout and testing made by PETROBRAS’ personnel or designated third party shall include, at least, the following items: a) Visual inspection of all work to assure mechanical completeness and compliance with all design drawings and specifications. b) Visual inspection of all nameplates and tags to verify correct identification. c) Point-to-point check of all wiring and tubing to verify proper interconnection. d) Continuity and isolation test of all electrical wiring. e) Pressure test of all piping and tubing. f) Functional test of all electrical equipment, output signals, piping equipment, sampling system, analyzers and related equipment. g) Calibration test of analyzers. h) Functional test of ASM, according to the logic diagram and communication test. i) Functional test of gas detectors, if any. j) Any other test previously agreed between PETROBRAS and Analyzers System ASV. 5.23.10. INSPECTION AND TESTS AT THE JOBSITE 5.23.10.1. Plant Acceptance Test (PAT)


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5.23.10.1.1. Plant Acceptance Test is a repetition of verifying the system operability and fixing possible transportation, after the analyzer system delivery and and interconnected to DCS. That test shall be started Acceptance Test.

the Factory Acceptance Tests damages occurred during the installation at the definitive site before a Boiler or Fired Heater

5.23.10.2. Performance Test 5.23.10.2.1. The analyzers system shall be considered ready for this test when it has been totally assembled, connected to process/utilities, integrated to plant control system, and after all non-conformities detected during the Plant Acceptance Test (PAT) have been solved. During the assisted operation period, the following tests shall be performed: - Availability - Validation - Stability 5.23.10.2.2. During the assisted test operation period, all maintenance and necessary modifications shall be done by the ASV technician personal and responsibility. The ASV also is responsible for the spare parts and consumable used in this period. 5.23.10.3. Availability Test 5.23.10.3.1. The system under test shall be considered available when all of its parts (sampling system, analyzers, safety systems, controllers and all other associated equipment and systems) are working in conformity with the specification. 5.23.10.3.2. All the system will be brought into operation for a period of 720 hours. After that period of time, an index of 95% availability shall be reached. 5.23.10.3.3. The total observation time will not include the intentional interruption time for downloading of new files, data base modifications and other activities related to system configuration. 5.23.10.3.4. The availability of the analyzer and system should take into account the following down time causes. Time for the following should be subtracted from the Test Period. •

Utility failure (AC power, instrument air, steam)

•

Utility quality (AC low voltage, low instrument air pressure, low steam pressure)

• Maintenance time (preventive maintenance, planned calibration, planned modifications or upgrades) •

Process off spec (high vapor dew point, excessive dirt or catalyst fines)

•

Process shut down (pump failures, process temperature control)


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5.23.10.3.5. This test will be re-started every time the indexes fall below the values indicated in the table. The test shall be repeated until the availability indexes are reached within a maximum period of 90 days. After this period, the system will be considered not acceptable. 5.23.10.3.6. This test shall include all purchased equipment and software. 5.23.10.4. Stability Test 5.23.10.4.1. The validation standard gas shall be introduced into the analyzers once a day during 25 days. 5.23.10.4.2. All the data obtained during that period will be plotted on a control chart. There will be a chart for every component to be measured. The control chart will show the average value and the superior and inferior control limits. Those parameters will be calculated by the following equations: Average:

x=

x1 + x2 + ... + xn n

Superior Control Limit: SCL = x + 2.66 M R Inferior Control Limit: ICL = x − 2.66 M R Where: MR =

x1 − x 2 + x 2 − x 3 + ...+ x k −1 − x k k −1

5.23.10.4.3. The data will be evaluated according to the above limits. If all the data are within the limits, showing no drifts, the process will be considered under control and the analyzers will be approved. 5.23.10.4.4. Drifts will be revealed by the following events: - a sequence of 7 rising consecutive points; - a sequence of 7 consecutive points above the average line; - a sequence of 7 falling consecutive points; - a sequence of 7 consecutive points below the average line. 5.23.10.5. Accuracy Test 5.23.10.5.1. Considering the data obtained in the stability test the average and standard deviation shall be calculated. These results shall be compared to the information presented at the validation standard gas certificate. 5.23.10.6. Performance Evaluation


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5.23.10.6.1. The analyzer system will be considered as performing satisfactorily, if the results obtained during the test run are lower than the standard levels defined in the acceptance tests described above. 5.23.10.6.2. If one of them is higher, the test shall be repeated once again to verify if the analyzer system is working satisfactorily. Analyzer system final acceptance shall be issued only when the performance criteria have been achieved. 5.23.11. SERVICES SPECIFICATION 5.23.11.1. The technical services shall be developed and executed by the ASV to facilitate the installation, start-up and operation of the Analyzers System. 5.23.11.2. Scope of Field Services shall include, at least (after totally assembled, connected and integrated): - Analyzers Cabinet inspection. - Sample Conditioning System and utility lines inspection. - Signal and electric power lines inspection. - Gas containers and accessories inspection. - Process and sampling pipelines cleaning. 5.23.11.3. Analyzers System Pre-start-up, Calibration and Test shall include, at least: - Field work management of tubing, wiring, gas container and accessories connection to Analyzer Cabinet. - Functional inspection of all analyzers and equipments. - Calibration and off-line operation of analyzers for performance assurance. - Analyzers output signal transmission validation. - Connecting the Analyzers to process, after the lines have been cleaned and the unit has been continuously operating for at least 24 hours. 5.23.11.4. Connected Analyzers Start-up shall include, at least: - Analyzers validation/calibration with standard gases. - Analyzers sampling systems start-up. - Analyzers operation connected to process stream. - Analyzers operation tests for final acceptance.


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5.24. EMERGENCY ISOLATION VALVE – EIV 5.24.1. EIVs must be used with liquid flammable hydrocarbons and toxic products, according to ET-6000.67-0000-800-PDY-002. EIVs for gases are not required for inventories less than 2 tons. Whenever, the inventory exceeds 2 tons, HAZOP must evaluate the need for the usage and installation of these valves. Partial stroking systems are recommended, in order to test for the availability of the actuator. EIVs are valves which require a longer sealing warranty and service life, as they are positioned at critical points of the process units, storage, blending and utility systems. 5.24.2 The EIVs normally use electric actuators for failure on last position, can also use

the electro-hydraulic actuator, where the process request failure position closes. 5.24.3 The basic design shall define the Emergency Isolation Valves - EIV´s that must have the fire-proof requirements and complies with UL 1709 (fire protection for more than 30 minutes in a 1093º.C fire resistance). The type of actuator for the emergency isolation valve - EIV shall be of electric type with intumescent coating system for the actuator and gear box bodies. 6.

GAS COMPRESSORS AUTOMATION

6.1.

SCOPE

6.1.1 The automation requirements defined in this item apply to any gas compressors handling combustible gas; air compressors are not covered by these requirements. 6.1.2 These requirements apply to the gas compressor, its driver and its corresponding auxiliary systems. 6.1.3 Specific requirements, considering process unit characteristics, shall be defined in each respective process unit basic design. 6.2.

GENERAL REQUIREMENTS

6.2.1 GENERAL CONTROL ARCHITECTURE 6.2.1.1 The system shall be design with the following subsystem: •

One controller for MSIS – Machinery Safety Instrumented System

•

One controller for MCS – Machinery Control System

•

One Anti-surge control ( if applicable );

•

One dedicated controller for OPS – Over speed Protection System (if applicable);

•

And the MMS – Machinery Monitoring System.

6.2.1.2 Each compressor/driver set and its auxiliary system shall be provided with the following instrumentation panels.


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a) A Remote Control Panel (RCP), for its data acquisition, control and interlock purpose. b) A Local Panel (LP), for its local supervision purpose. 6.2.1.3 Each compressor/driver set and its corresponding auxiliary systems shall have a single dedicated RCP, installed in the CCL, accommodating all systems. The compressor RCP shall attend the following requirements established on item 5 (Instrumentation Design Criteria), in its item for Package Units, and to the additional requirements established in the following sub-items. a) All RCP electronic equipments (as PLC and dedicated controllers) with control and interlock functions shall be provided, as a minimum, with redundant CPU , redundant communication between CPU and I/O cards and redundant power supply. The CPU shall support software downloads without interrupting normal operation of the equipment. b) Shall be provided with an Ethernet interface for remote maintenance and supervision procedures for the PLC. c) Shall be provided with dual electrical power input in 125 Vdc, one main and another back, so that the loss of just one 125 Vdc feeder will not affect nor degrade the RCP controls and interlock functions. d) The 24Vcc power source, for power supply of any compressor field instruments and any other electronic equipment, shall be redundant and powered by both electrical 125 Vdc power input circuits. e) Shall be provided with component fail detection as CPU, electrical source and others and it shall be reported to DCS. f) Configuration data shall be stored in an EEPROM or another re-programmable nonvolatile device, so that the configuration will not be affected in case of power failure. g) When vibration monitoring modules are required to compressor/driver set, it shall be sheltered inside the compressor RCP unless the distance between sensors and the RCP is longer than the maximum distance recommended by vibration monitoring Manufacturer, when in that case vibration monitor modules shall be sheltered in LP and shall be approval by PETROBRAS. h) Shall be provided with others equipments, according to compressor type (reciprocating or centrifugal). i) The panel shall contain a graphical user interface with the same information of the LP graphical user interface. The program shall avoid the simultaneously operation. j) The analog modules of PLCs shall be able to read Hart information and provides them to the assets management system. k) The analog modules of dedicated controllers shall be connected to a multiplex Hart to read Hart information and provides them to the systems. In case of decrease of reliability this data should be submitted to Petrobras.


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l) Figure below shows the acceptable architecture for the RCP. RCP – Remote Control Panel Graphical User Interface ( HMI)

MCS- Machinery Control System -Automation procedures -Speed control Anti Surge System

PLC MSIS – Machinery Safety Instrumented System

OPS- Overspeed Protection System MMS- Machinery Monitoring System

6.2.1.3 The compressor LP shall attend the following requirements established on item 5 (Instrumentation Design Criteria), in its item for Package Units, and to the additional requirements established in the following sub-items. a) Shall be provided with a graphical user interface with the following screens: a general view of the system, start/stop monitoring, alarms, oil system status, seal system, antisurge control, operational monitoring status (showing vibration, axial displacement and bearing temperature) and other systems. b) All screens shall be supply in Portuguese language. c) The LP shall be provided with two pushbuttons, one for compressor trip and another for permissible start, both hardwired connected to the machinery RCP. d) The emergency shutdown push button shall be of the locking type e) The ESD push-buttons shall be hardwired to Analog Input modules with diagnostic and monitoring capabilities. f) The LP shall be located at about 3 to 5 meters from the set. g) The HMI shall be a flat panel LCD display with the following characteristics: - Full useful display area of 12” size, at least; - Keyboard for display operation (screen selection, paging, etc.). Touch-screen displays are acceptable but no command shall be implemented in the display. Flat membrane keypads should be avoided; - Easy screen reading under daylight conditions.


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6.2.1.4 Compressor start up shall be done only remotely, from DCS, upon a local start permission pushbutton actuated by operator in the LP. When this pushbutton is actuated, the compressor is enabled to start up during a determined time. After this time the compressor shall be locked for start up and a new start permission pushbutton actuation shall be done to enable it again. 6.2.1.5 The CONTRACTOR shall check and make appropriate recommendations for process and instrumentation design related to compatibility with the control system: sizing of the anti-surge valves, transmitter selection and location of recycle lines, coolers, flow elements and check valves. 6.2.1.6 All PLC´s, dedicated controllers and monitoring systems shall be provided with a 100 MBPS Ethernet interface for remote maintenance and supervision procedures. The Interface shall support the TCP/IP protocol. 6.2.1.8 The memory maps necessary for the communication shall be supplied by the CONTRACTOR based on a standardized defined by PETROBRAS. These memory maps shall include: addressing, data scaling, available functions and any necessary information for configuration support. Besides, they shall be organized in blocks to guarantee that the data refreshing in the DCS can be all concluded in 5 seconds at most. All data shall use the engineering units defined in item 4. 6.2.1.9 The recording of critical events shall have the potential to capture high-speed trend information for selected variables in the Machinery Monitoring Subsystem, Control Subsystem and Safety Interlock Subsystem, before and after any user-defined critical event. This storage system shall allow the visualization of graphical trends with 100 milliseconds of resolution at least. 6.2.1.10 All systems shall perform I/O module self-diagnosis and its configuration data shall be stored in an EEPROM or another reprogrammable non-volatile device, so that the configuration will not be lost in case of a power failure. The systems shall also support the replacement in operation mode of any electronic module. 6.2.2 MACHINERY CONTROL SYSTEM (MCS) 6.2.2.1 The MCS, which shall be located in the RCP, includes all hardware and software necessary to implement the start-up/shutdown, control, speed control and the anti-surge control, where applied. 6.2.2.2 The MCS shall provide graphical trends for the main process variables with at least 10 milliseconds of resolution. 6.2.2.3 Equipment shall be supplied with automatic start-up facilities, including required instrumentation, controllers and operation logic. 6.2.2.4 CONTRACTOR shall comment process P&I and suggest modifications to allow safety compressor remote start-up.


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6.2.2.5 CONTRACTOR shall supply all logic diagrams and text descriptions for automatic start-up, shutdown and interlock procedures. 6.2.2.6 A fallback strategy shall be configured so that any hardware fault will not cause the total loss of any control function. 6.2.3 Anti-Surge Control 6.2.3.1 The vendor shall provide a separate anti-surge control for each machine section; including field instrumentation and control valves. 6.2.3.2 The proposed anti-surge control strategy shall be previously submitted for PETROBRAS approval. 6.2.3.2 The dedicated anti-surge control shall be fully redundant, unless it is applied to redundant centrifugal gas compressors when a single dedicated anti-surge control is acceptable. 6.2.3.3 Vendor is the responsible for the proper design and operation of the anti-surge control system. Vendor shall check the sizing of the anti-surge valves, the sizing and location of the spillback lines, piping layout, transmitters, coolers and flow elements. Vendor shall also give technical advices on process and instrumentation design to assure that the anti-surge control system will work as expected. 6.2.3.4 Annubar flow meters are NOT allowed. 6.2.3.5 The maximum response time for pressure and differential pressure transmitter for the anti-surge control system shall be 100 ms; the maximum impulse tubing length shall be 2 m. 6.2.3.6 The anti-surge valve shall be preferably globe type, with linear inherent characteristic. This valve shall have a position transmitter (open/close), smart positioner and booster to guarantee a time constant less than 2 seconds. 6.2.3.7 The anti-surge control system shall be implemented in a digital equipment with a scan time less than 100 ms. 6.2.3.8 All parameters used in the surge control configuration shall be in engineering units, see item 4 of this specification. The documentation shall describe all parameter properties, ranges, their role in the control strategy, and the settings defined for this project. 6.2.3.9 If the gas can condense, the anti-surge valves shall be located above the compressor, at a sufficient height to avoid condensate accumulation. 6.2.3.10 Operation shall be able to actuate on the anti-surge control from the DCS. It shall be able to turn the anti-surge controller to manual mode and to take control of the anti-surge control valve; however, the anti-surge control shall override the manual under not normal conditions.


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6.2.3.11 In case of failure of a pressure or temperature signal, the anti-surge controller shall automatically receive the design value of the defective variable, or the value from at least 10 scans before remaining in normal operation mode. An alarm shall be sent out. In case of failure of the flow signal, the recycle valve must be open to a preset value and the anti-surge controller must switch from automatic to manual. 6.2.3.12 During the start-up, a test shall be conducted by vendor to identify the actual surge curve of the compressor. 5.2.4 Process Control and Speed Controller 6.2.4.1 Compressor capacity control shall manipulate the driver equipment (steam turbine) speed set point. Vendor shall supply speed controller with the MCS. 6.2.4.2 Compressor capacity control shall be configured in the DCS, with high and low set-point limits defined. 6.2.4.2 For compressors with steam turbine driver, the capacity control shall send the setpoint (hardwired) to the speed control and receive from it the actual speed signal (hardwired) for tracking purposes. Besides, the “start-up” and “permission to start-up” signals, sent from the DCS to the speed controller, shall be hardwired too. 6.2.4.3 Speed controller shall feedback the driver equipment (steam turbine) speed, for compressor capacity control output tracking, and its control output, providing 4-20 mA analogue signals to DCS. 6.2.4.4 Control valves related with speed control of the driver equipment (steam turbine) shall be supplied with position transmitter. The position information signal must be sent to the DCS by a hardwired link. 6.2.4.5 The driver equipment (steam turbine) speed must be measured by three dedicated speed sensors (magnetic pickup), other than the ones used by the overspeed detection system. 6.2.4.6 All parameters involved in the speed control configuration shall be in engineering units. The documentation shall describe all parameter properties, ranges and functions in the control strategy, as well as the settings for this project. The documentation shall be previously submitted for PETROBRAS approval. 6.2.5 MACHINERY SAFETY INSTRUMENTED SYSTEM (MSIS) 6.2.5.1 The safety instrumented system shall be responsible for driving the machine automatically to a safe state when a dangerous event occurs. 6.2.5.2 The logic solver for the MSIS of centrifugal compressor shall be a PLC certified as SIL 3, according to IEC-61508 and item 5.17 above. For reciprocating compressor the logic solver shall be a PLC for package unit describe in item 5.16.


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6.2.5.3 All trip initiators shall be redundant with a 2oo2 (two-out-of-two) voting scheme, and discrepancy alarm. The voting scheme 2oo3 is also accepted. 6.2.5.4 The compressor trip logic shall be programmed to detect transmitter failure and in that case change automatically the logic voter from: a) 2oo2 to 1oo1 logic voter; b) 2oo3 to 1oo2 logic voter. 6.2.5.5 A separate discrete input shall be predicted for shutdown from SIS Logic Solver, actuating directly on the final elements. If an interface were necessary, it shall be TÜV Rheinland certified for SIL3, as defined on IEC-61508. 6.2.5.6 After any trip event, the sequence of event (SOE), implemented in the SIL 3 PLC, shall be reported to DCS through redundant communication. 6.2.5.7 The shutdown by low pressure in the oil system shall have a delay of 1 second. 6.2.5.8 In case of power loss, the system shall drive the machinery to a process safe state. 6.2.5.9 The final elements shall be in 1oo2 (one-out-of-two) voting scheme driven by solenoids valves, de-energize to trip, as stated in API 612 (Petroleum, Petrochemical and Natural Gas Industries – Steam Turbines – Special Purpose Applications). 6.2.5.10 The panel annunciator system shall incorporate “first out sequence” feature (ANSI/ISA-18.1) for identifying which shutdown signal operated first. At DCS, all alarms shall be recorded with an indication of the respective time of occurrence in a special file, the alarm log. 6.2.5.11 Every shutdown shall always be preceded by an alarm. 6.2.5.12 Acknowledgement of an alarm must not inhibit the indication of any other faults. 6.2.5.13 Shutdown signals from the MSIS to the Safety Instrumented System (SIS) shall be hard-wired. A dry-contact output shall be available for this purpose at the MSIS. 6.2.5.14 Remote shutdowns through digital communication interfaces are NOT acceptable. 6.2.5.15 The solenoid valves shall be in a voting scheme of 1oo2 (one-out-of-two), deenergize to trip, as dictated by API 612. One solenoid is commanded by the MSIS and the other by the Over-speed Protection System. As shown in figure below, a trip originated from either one of the MMS or OPS causes the trip of the other, opening ultimately both solenoids.


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LP – Local Panel Graphical User Interface ( HMI) a) b)

Push Button -Trip Start Permission Field CCL

Graphical User Interface ( HMI)

MCS- Machinery Control System -Automation procedures -Speed control -Anti-surge Control

PLC MSIS – Machinery Safety Instrumented System rotection System

DCS

PES

OPS- Overspeed Protection System

MMS- Machinery Monitoring System

Hardwire Comunication RCP - Remote Control Panel

6.2.6 ALARM AND INDICATIONS 6.2.6.1 Every alarm and analog variable indications shall be individually indicated on Local Panel and DCS , in the local panel, multi led lamp shall be used as alarm lamp; 6.2.6.2 All shutdown shall always be preceded by an alarm. 6.2.6.3 The panel annunciator system shall incorporate “first out sequence” feature (ANSI/ISA-18.1) for identifying which shutdown signal operated first. At DCS, all alarms shall be recorded with an indication of the respective time of occurrence in a special file, the alarm log. 6.2.6.4 Acknowledgement of an alarm shall not block the indication of any other faults. 6.2.6.5 Alarms shall be in accordance to Technical Specification no I-ET-6000.67-0000800-PDY-003 - REQUIREMENTS FOR ALARM DATA BASE.


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6.2.7 DCS AND PES INTERFACE. 6.2.7.1 Any control signals, including set points, as well as trip, start and stop commands signals shall be hard-wired from DCS or PES to compressor RCP. Digital communication links for these kind of signals are NOT acceptable. 6.2.7.2 Supervision signals from remote control panel shall be done by communication using ModBus-TCP protocol with DCS as master in the communication. This communication shall be redundant. 6.2.8 FIELD INSTRUMENTATION 6.2.8.1 Field instrumentation installations shall comply with the PETROBRAS Standard N-858 and NI-1882, requirements defined on item 5 (Instrumentation Design Criteria) and to the additional requirements established in the following sub-items. 6.2.8.2 Sizing and selection criteria shall be provided for all new required auxiliary instrumentation including measuring elements, transmitters, valves, positioners and volume boosters. 6.2.8.3 Transmitters, flow measuring devices and anti-surge valves (where applicable) associated with the control system shall be evaluated for proper location and sizing. Analog instruments not connected to the PLC shall be connected to a standardized multiplex HART for the purpose of remote maintenance, in case of risk of decrease of reliability this data should be submit for PETROBRAS. 6.2.9 OVERSPEED PROTECTION 6.2.9.1 The overspeed shall be monitored by an electronic system, supplied by vendor. 6.2.9.2 This system shall be unique and exclusive for this application, complying with the API-670. 6.2.10 MACHINERY MONITORING SYSTEM (MMS) 6.2.10.1 The MMS is responsible for indicating, registering and alarming the variables that are important for machinery integrity such as vibration, axial displacement and bearing metal temperature, and for sending hardwired signals for tripping. 6.2.10.2 The MMS shall obey API 670 (Machinery Protection Systems) requirements for the quantity, type, position and installation of the sensors. 6.2.10.3 The MMS shall be located in a panel in the local control room, described in item 10.5. 6.2.10.4 The human-machine interface for the operation/configuration of the MMS shall be a personal computer, compatible with the MMS technology requirements. 6.2.10.5 System support software shall be supplied in order to allow configuration and troubleshooting procedures from the workstation.


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6.2.10.6 The storage of critical events shall be provided with the capacity to capture high-speed trend information for all critical process and system variables, before and after any user-defined critical event. Data resolution stored event files shall be 100 milliseconds or less. 6.3.

RECIPROCATING COMPRESSORS.

6.3.1 CONTROL ARCHITECTURES 6.3.1.1 Two different control architectures are presented for selection, one using continuous capacity control and the other one using capacity control by steps. 6.3.1.2 The selection shall be made during basic design, according to process unit characteristic and rotary equipments requirements. 6.3.1.3 Reciprocating compressor architecture with continuous capacity control.


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6.3.1.4 Reciprocating compressor architecture with capacity control in steps

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6.3.2 RECIPROCATING COMPRESSORS CAPACITY CONTROL 6.3.2.1 Basic design of each process unit shall define which capacity control type, continuous or by steps, shall be provided by each compressor. 6.3.2.2 When continuous capacity control is selected, the following requirements shall be considered. a) Capacity control shall be provided with supervision system for the following facilities: Load control system status monitoring; Stages dynamic pressure monitoring; Valves temperature monitoring; PV diagram analysis; Stem load estimative; Trend registers and alarms; Stem integrity monitoring. b) Capacity control actuators shall be electro hydraulic type. 5.3.2.3 When capacity control by steps is selected, the following requirements shall be considered. a) Capacity control shall be pneumatically actuated and shall be manually operated from LP or from DCS. b) Recirculation (between steps) capacity control shall be automatic and implemented at DCS.

6.4. E

CENTRIFUGAL COMPRESSORS

For additional information see I-ET-6000.67-0000-800-PDY-005 – Centrifugal and Axial Gas Compressor Automation 7.

FIRED HEATERS AUTOMATION

7.1.

SCOPE

7.1.1 The requirements defined in this item establish general guidelines for automation logic for all fired heaters. 7.1.2 These guidelines for fired heater automation project includes start-up sequence, interlock system and minimum required interface. 7.1.3 Specific requirements, considering process unit characteristics, shall be defined in each respective process unit basic design. It includes all control strategies related to fired heaters.

7.2.

GENERAL GUIDELINES


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7.2.1 DCS is the equipment responsible for the process monitoring and control of an Industrial Unit. 7.2.2 PES is defined as equipment responsible for the interlocking system of an Unit or a subsystem of the Unit. 7.2.3 For this Project, each fired heater automation strategies shall be implemented in a independent PES that shall be TÜV Rheinland certified for SIL3, as defined on IEC61508. 7.2.4 Fired heater automation shall be implemented in accordance with the minimum configuration: a) With electric igniters; b) With flame rod detectors at each pilot; c) With automatic valves in each individual pilot; d) With automatic valves in each individual fuel gas burner; e) With automatic valves in each individual fuel oil burner; f) With automatic valves in each atomizing steam line; g) With automatic natural draft doors. 7.3.

FUNCTIONAL REQUIREMENTS AND INTERFACES

E

Actuation From : Commands Field Purge Start Open/Close Pilot Gas Double Block and Close/Open Vent Valves Open/Close Pilot Gas Individual Valves Open/Close Fuel Gas Double Block and Close/Open Vent Valves Open Fuel Gas Individual Valves Close Fuel Gas Individual Valves Open/Close Fuel Oil Header, Return and Circulation Valves Open Fuel Oil Individual Valves Close Fuel Oil Individual Valves Open/Close Atomizing Steam Individual Valves Ignition Manual Shutdown Remote Start-up Permission

Local Panel

DCS X X X X

X X X X X X X X

X X X

7.3.1 All commands shall be implemented according to the interfaces defined on the following table:


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7.3.2 All indication shall be implemented according to the interfaces defined in the following table in the P&I diagrams : Indications Purge Started Purging and Remaining time T1 Purge completed Leakage test – State for each pilot and burner header Leakage test – Initial pressure of each pilot and burner header Leakage test – Pressure drop (%)of each pilot and burner header Leakage test – Alarms for each pilot and burner header Enable to Ignition Bypass of each pressure pilot header remaining time Permission to open burner header Bypass of each pressure burner header remaining time Permission light on burner Partial trip (and first event) General trip (and fisrt event)

Local Panel X X X X X X X X X X X X X X

DCS X X X X X X X X X X X X X X

7.3.3 All signals related to the fired heaters shutdown shall also be supplied from field to PES by hardwire. All commands related to fired heater shutdown shall be supplied from DCS to PES by hardwire. 7.3.4 Any other commands defined to be implemented on the DCS shall be sent to the PES by communication. 7.3.5 The individual burner valves shall be located as close as possible to the burners’ observation window in order to guarantee a comfortable and safe local operation of the equipment. 7.3.6 Indications available on PES shall be sent to the DCS by communication. 7.3.7 PES shall be installed on local control room close to the cabinets of the DCS. 7.3.8 The start-up sequence will be initiated from DCS. 7.3.9 The local panel shall have at least the following requirements: 7.3.9.1 The local panel shall be protected against rain and dust exposure with grade IP65 and with pressurized enclosure protection, in agree with IEC 60079-2, according to the area classification. 7.3.9.2 The local panel shall be a single for each furnace. 7.3.9.3 Operator shall have permission from local panel to start from DCS. When this pushbutton is actuated, the furnace is enabled to start up during a determined time. After this time the furnace shall be locked for start up and a new start permission pushbutton actuation shall be done to enable it again.

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7.3.9.4 The local panel shall be design with a LCD 17” for HMI. The screens shall display at least all the indications listed in 7.3.2 , limited switch (ZS’s) for all block valves, limited switch (ZS’s) for dampers, limited switch (ZS’s) for steam valves and all analogs indications related to the furnace, in the local panel, multi led lamp shall be used as alarm lamp;

HS located near burners’ windows for open and close commands for gas burners and oil burners

E

Local Panel -HMI -Push Button

Field

Safety Signals From Field Status Signals

CCL Control & Monitoring Signals From Field

Trip

(Local Control Room)

Commands

PES

Trip DCS System of the unit Trip

Commands Alarms And Indications Software Hardwired

7.4.

LOGIC SEQUENCE DESCRIPTION

7.4.1 Permission to purge sequence 7.4.1.1 The following conditions shall be fulfilled for the initial purge permission, indicated at the panel by the blinking of the “Enable to Purging” indication: a) Pilot gas individual supply pipelines shall be blocked; b) All Fuel gas/oil individual supply pipelines shall be blocked; c) Pilot gas double block valve(s) shall be closed and vent valve shall be opened; d) Fuel gas/oil double block valve(s) shall be closed and vent valve shall be opened; e) Control damper shall be opened;

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f) No flame indication. g) Not high level at fuel gas drum. I) Atomizing steam valves shall be fail closed. h) Forced Draft Fan in purge operation condition (flow or pressure indicator), if applicable. 7.4.1.2 Once all these conditions are satisfied, “Enable to Purge” indication shall blink. 7.4.2 Leakage Test sequence 7.4.2.1 Operator shall command to start purging from DCS. 7.4.2.2 The leakage test will be done during purge period for gas pilot header and main gas header, but the purge timer shall be started only at the end of pressurization system test.

Signal from Controller

ZSL ZSL

ZSL

4

5

ZSL

6 PT

4

5

4

5

3 2

ZSL 1

7

PI

ZSL

7.4.2.3 For a best comprehension, a figure above will be helpful. 7.4.2.4 The test checks the individual valves leakage (valves 4) and the second double block valve leakage (valve 2). 7.4.2.5 Pressure indicator (PI) between double block valves can be used for a double block leakage test during maintenance period. 7.4.2.6 Leakage test is a condition for continuing purge step. 7.4.2.7 The leakage test should be performed according flowchart below. Except when explicitly written, all actions should be automatic. 7.4.2.8 The maximum allowed pressure loss during pressurizing test can be 3 % from operational pressure. 7.4.2.9 All manual valves (5) should be opened for leakage test. If some manual valve (5) is closed before or during leakage test, it should be kept at this position during pilots or burners light-off.


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7.4.2.10 If the leakage test for individual valves (4) is not successful, the operator should verify leakage valve (2) closing valve (6), also according flowchart below. 7.4.2.11 If it is proven leakage at one valve (4), this problem should be solved by maintenance immediately. 7.4.2.12 The end of the leakage test occurs after depressurization of the stretch between the valves (2) and (4) by opening the valve (2) by pulse. 7.4.2.13 All leakage test shall be recorded.


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7.4.3 Purge sequence 7.4.3.1 If any automatic valve is manipulated during leakage test or during purge time, the start procedure is cancelled. 7.4.3.2 Snuffing steam valve shall be automatically opened and the “Purging” indication shall blink when the snuffing steam valve limit switch (ZSH) indicates full opening and snuffing steam pressure is higher than 20% of normal operation pressure. 7.4.3.3 For forced draft fired heater, forced draft fan should be used instead of snuffing steam. 7.4.3.4 Once the “Purging” indication is noticed, a timer shall be initiated and the purge time shall be started. The purge time shall be T1. The minimum T1 time should be defined to 3(three) trading of volume of the combustion chamber. 7.4.3.5 If the operator closes the snuffing steam valve before the total purge time, the start-up sequence shall be inhibited and a new purge shall be necessary to enable any ignition. 7.4.3.6 If any interlock that causes the general shutdown of the fired heater is triggered during the purge operation, the start-up sequence shall be aborted and, after the end of the purge operation, the ignition shall not be enabled. 7.4.3.7 The closing of snuffing steam valve after the purging time shall be: a) Automatic, after the operator command for open pilot double block valve and close vent valve.The “Enable to Ignition” indication shall blink during a time interval equal to T2. b) Automatic, after a delay timer, greater than T1 + T2. In this case, start up procedure is aborted. c) Manually, at any moment, according operation necessities. Also in this case, start up procedure is aborted. 7.4.3.8 The permission for open double block valve and close vent valve for ignition shall be given only if all shutdown conditions are normalized, exception for this initiators, that should be automatic by passed: a) Very high pressure for pilots, gas burner and oil burners. b) Very low pressure for pilots, gas burner and oil burners. c) No flame at 50 % of pilots.

7.4.4 Ignition sequence 7.4.4.1 In normal conditions, after the purging time, the “Enable to Ignition” indication shall blink during T2. This time, T2, shall be adjusted considering the ignition time of at least 50 % of pilots more one.


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7.4.4.2 During “Enable to ignition” indication, operator shall activate the ignition sequence logic by a hand switch. This logic will command the pilot gas double block valves to open and the vent valve to close. 7.4.4.3 When the pilot gas double block valves are commanded to open and the vent valve is commanded to close, the high and low pressure trip signals shall be bypassed during T3 timer or until after 30 seconds from header pilot pressure stabilization in order to enable the start-up. 7.4.4.4 Since the pilot double block valves are opened and vent valve is closed, each pilot shall be ignited individually. 7.4.4.5 After 2 seconds from ignition command, individual pilot valve shall be opened. 7.4.4.6 The ignition command shall energize the igniter during T4. After this time, the energizing shall stop and pilot light off should be proven by flame rod indication. 7.4.4.7 If flame is not detected 5 seconds after T4, the pilot valve shall be closed by the logic implemented at PES. In this case a new ignition will be possible just after T5. 7.4.4.8 The operator should light off the first pilot in a period of T9. If this not happens, a shutdown sequence should be started. 7.4.4.9 In case of expiration of the “Enable to ignition” time and at least 50 % or more of pilots without fire in each row, the fired heater shall be tripped. 7.4.4.10 In order to avoid spurious trips, a timer shall be configured in the logic actuated by the flame detectors. For the “flame detected” condition, the signal must be active for at least 5 seconds to be acknowledged. For the “no flame detected”, it must be active for at least 2 seconds. 7.4.4.11 By operational procedure, it shall be avoided more than two adjacent pilots without flame. 7.4.4.12 By operational procedure, operator should light off the pilots in an equal distribution form. Preferentially, pilots should be light off alternatively. 7.4.4.13 For fired heater with 10 or more pilots, if four unsuccessfully tries of lighting off pilot happens in the same row, logic shall guarantee: a) If the number of pilots on fire is less or equal than the minimal number (50% of total pilots), the furnace should be shut down. b) If the number of pilots on fire is greater than the minimal number (50% of total pilots), a timer of T10 should be started, avoiding the try of lighting off any pilot during this time. 7.4.4.14 During ignition time, logic should not permit to open the main gas header or the oil header.


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7.4.5 Fuel gas burner alignment sequence 7.4.5.1 Once the ignition sequence is established and, at least, 75% more one of pilots are on fire, operator shall activate the main burners sequence logic by a hand switch from DCS. This logic will command the burners fuel gas header valve to flare (valve 8 ) to open, the burners fuel gas double block valves to open and the vent valve to close., only if any process interlock which cause a “partial trip” on fired heater is not actuated. Valve (8) should be closed by operator or automatic after timer T9. 7.4.5.2 When the burners fuel gas double block valves are commanded to open and the vent valve is commanded to close, the high and low pressure trip signals shall be bypassed during T6 timer or until after 30 seconds from header fuel gas burner pressure stabilization in order to enable the fuel gas burner alignment. 7.4.5.3 Once the burner’s Fuel Gas double block valves are opened and vent valve is closed, the operator, near the burner, shall be able to open each Fuel Gas individual valve, since there is flame indication at the corresponding pilot. The following items shall be considered : a) it shall be provided two local hand switches: one for opening, another one for closing; b) by operational procedure the operator shall verify the quality of flame near the burner immediately after the Fuel Gas individual valve opens. 7.4.6 Fuel oil burner alignment sequence 7.4.6.1 Once the ignition sequence is established and, at least, 50 % more one of pilots are on fire, operator shall activate the main burners sequence logic by a hand switch from DCS. This logic will command the burner’s fuel oil block valve to open, the recirculation valve to open and the bypass valve to close, only if any process interlock which cause a “partial trip” on fired heater is not actuated. 7.4.6.2 When the burners’ fuel oil block valve and the recirculation valve are commanded to open and the bypass valve is commanded to close, the high and low pressure trip signals shall be bypassed during T8 timer or until after 30 seconds from header fuel gas burner pressure stabilization in order to enable the fuel oil burner alignment. 7.4.6.3 Once the burners’ fuel oil block valve and the recirculation valve are opened and the bypass valve is closed, operator, near the burner, shall be able to open each Fuel Oil individual valve, since there is flame indication at the corresponding pilot. The following items shall be considered: a) it shall be provided two local hand switches: one for opening, another one for closing; b) fuel oil burner alignment can not be from DCS. 7.4.7 Shutdown Step Sequence 7.4.7.1 The shutdown procedure should guide the equipment to a safe condition.


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7.4.7.2 Snuffing steam shall be open only at manual shutdown stop (HS). For this situation, snuffing steam valve should only be closed by operator. 7.4.7.3 For the others cases of general shutdown, it is enough to close double block valves, open vent valve and fully open control damper. The natural draft will purge the equipment. If, for any general shutdown, the control damper does not confirm full open, snuffing steam should be admitted. Also for this situation, snuffing steam should only be closed by operator. 7.4.7.4 For closing double block valve and opening vent valve, the logic should guarantee that valve (2) will close after valve (1) and after the opening of valve (3). The reason for this recommendation is depressurize the headline between valves (4) and (2). B

7.4.8 Recommendations For Timers 7.4.8.1 All timers configured on the start-up logic program shall be adjustable according to the following table. 7.4.8.2 Only supervisors shall be able for tuning these timers. Timer Identification T1 T2 T3 T4 T5 T6 T7 T8 T9 T10

7.5.

Description Purging time Time to ignite at least 50% +1 pilots Time to bypass pressure trips at the pilot system Igniter energizing time Minimum interval between ignition tries for each pilot Time to bypass pressure trips at the main fuel gas system Maximum time between the opening of burner individual valve and confirmed burner’s fire Time to bypass pressure trips at the main fuel oil system Maximum time for first pilot light off Time interval after 4 consecutive unsuccessful tries for pilot’s light off

Initial Reference Value 15 minutes 30 seconds/pilot 2 minutes 10 seconds 60 seconds 2 minutes 15 seconds 2 minutes 1 minute 2 minutes

GENERAL REQUIREMENTS

7.5.1 The combustion chamber pressure transmitter should be protected against wind, dust, dirty and so on, since it operates with a very low range. 7.5.2 The low-low and high-high pilot fuel gas pressure transmitters should be located one upstream to the first pilot and the other downstream to the last pilot.


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7.5.3 The high-high main fuel gas pressure transmitter should be located upstream to the first burner. The low-low main fuel gas pressure transmitter should be located downstream to the last burner. 7.5.4 All block valves should be tight shut off valves (TSO). 7.5.5 The flame rod and igniter should be mounted on the pilot, avoiding the existing problems on external mountings. 7.5.6 All individuals main gas block valves should have a slowly opening characteristic and a quick closing characteristic. 7.5.7 High pressure combustion chamber can automatic open control damper. 7.6.

GENERAL NOTES

7.6.1 General trip means burner and pilot shutoff. Partial trip means only burner shutoff. 7.6.2 All interlock initiators shall be configured with a filter to avoid spurious trips related to monitoring variable transients. The filter time shall be a tunable parameter. 8.

PUMP AUTOMATION

8.1.

SCOPE

8.1.1 The requirements defined in this item establish general guidelines for automation logic for all pumps. 8.1.2 This document contains basic guidelines, interfaces definition, minimum required instrumentation and all functional and logical requirements for pumps automation. 8.2.

GENERAL GUIDELINES

8.2.1 DCS’s are equipment responsible for the process monitoring and control of an Industrial Unit. They shall be able to execute process-originated logic functions for pumps motor start-up and shutdown. 8.2.2 Detailed engineering shall supply “Loop Diagrams” with all complementary instrumentation associated with pumps and pumps auxiliary systems based on this document and on each pump data sheet. 8.2.3 Pump auxiliary systems means lube oil system, cooling water system and sealing fluid system. 8.3.

FUNCTIONAL REQUIREMENTS

8.3.1 The main operation modes required for each pair of pumps shall be Local/Remote, Auto/Manual mode and Enable/Disable Start-up selection.


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8.3.2 All these selection commands shall be applicable to one set of main and stand-by pumps. 8.3.3 The “Local/Remote” selection command shall be provided at control room. 8.3.4 If the “Local/Remote” selection is not applicable, the pump shall start just from local panel. 8.3.5 The “Remote” mode selection implies start-up disable from local panel. 8.3.6 The “Auto/Manual” operation mode shall always be selected from the control room. 8.3.7 The “Auto” operation mode means that the stand-by pump shall be started up by process variables such as pressure, flow, level, or, eventually by another process variable according to specific requirements. Note: Automatic start up by low flow should not be used control is performed by discharge flow control valve. 8.3.8 For pumps which operate alternately starting up and shutting down from level switches, the “Auto” mode shall activate this logic and the stand-by pump shall be started automatically by a very high level switch. 8.3.9 If the “Auto/Manual” selection is not applicable, the stand-by pump shall start up just from operator manual command. 8.3.10 All start up logics is detailed above. 8.3.11 If a pump is running, the system shall automatically consider the other one, which is off, as the stand-by one. Exception is applied to the automation logic commanded by the process variable “level”. In this case there shall be a switch selector to define the main and stand-by pumps. 8.3.12 The automatic start-up of the stand-by pump, either by low pressure or by low flow signal, shall be commanded by an instrument installed at the common discharge of both main and stand-by pumps. 8.3.13 When in “Auto” operation mode, if either a manual shutdown signal or any interlock shutdown occurs, the pump shall stop and the operation mode shall be switched to “Manual”. 8.3.14 Every time the stand-by pump is started, the main pump shall not be turned off automatically. The main pump shall be turned off by the operator. 8.3.15 Pumps shall not be able to start-up from the “Process Control Equipment” and from field, as long as “Start-up Disable” command is selected. This selection shall be done from the control room. 8.3.16 Detailed Engineering shall devise local start-up inhibition when “Start-up Disable” command is actuated.


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8.3.17 All pumps shall be able to manually shutdown at any time, at the field or by the “Process Control Equipment”. 8.3.18 The shutdown commanded by the interlock system, due to an emergency condition, shall always actuate on both main and stand-by pumps. 8.3.19 For pumps which shall be operated with VSD, the stand-by pump shall start up according to the following routines: a) after the pump motor start-up, the VSD shall rise the pump rotation according to an internal ramp (for VSD which are supplied with internal acceleration ramp); b) after the pump motor start-up, the “Process Control Equipment” shall force the output of the controller which is sending its output to the VSD according to a fixed ramp (for VSD which are NOT supplied with internal acceleration ramp). 8.3.20 The connection between DSC and VSD shall be with Profibus DP protocol for status signals. The set-point and feedback speed signals shall be hardwired connections between VSD and the DCS. 8.4.

INTERFACES AND ADDITIONAL INSTRUMENTATION

8.4.1 The motor operational states and commands shall be designed following : (a) Serial link between DCS and MCC with Profibus-DP protocol for start/stop commands, stopped/running state, blocked/unblocked state, discharged/not discharged, reacceleration time expired state, failure state and current value. (b) Hard wired link between PES and MCC for trip signals. 8.4.2 Additional instrumentation not listed on Basic Design P&I for pumps and pumps auxiliary systems shall be tagged and supplied by Detailed Engineering based on this document and each pump data sheet. 8.4.3 Pumps which require previous circulation of cooling water shall be provided with a pressure transmitter installed at the cooling water pipeline. This instrument shall be located close to the pump after the valve that aligns cooling water to the equipment. 8.4.4 Pumps which require previous circulation of sealing fluid from external source shall be provided with a pressure transmitter installed at the sealing fluid pipeline. This instrument shall be located close to the pump after the valve that aligns sealing fluid to the equipment for mechanical seal failure detection. 8.4.5 Pumps which require previous circulation of sealing fluid from a seal reservoir in a closed loop shall be provided with a low level transmitter installed at the sealing reservoir. 8.4.6 For pumps referred in items 8.4.3, 8.4.4 and 8.4.5, the detection of either low pressure or low level shall be indicated on the DCS and shut down the pump.


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8.4.8 The non actuated condition set-point for these transmitters shall be necessary for every pump start-up enabling. 8.4.9 Detailed engineering shall supply the operational limit values for low pressure and low level parameters, for each pump. 8.5.

BLOCK DIAGRAMS FOR PUMP AUTOMATION

Note: The automation logic is described as a scan program between “Begin” and “End” blocks.


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Logic A : Automatic start-up of the stand-by pump from a low set-point pressure transmitter at common discharge.


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Logic B : Automatic start-up of the stand-by pump from a low flow transmitter at common discharge

Logic C: Automatic start-up and shut-down of the main pump by a level command and automatic start-up of the stand-by pump from a high level switch.


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8.6.

LARGE SIZE PUMP CONTROL ARCHITECTURE

8.6.1 The automation requirements defined in this item apply to any pump train which require a local panel and continuous monitoring system – radial vibration, axial displacement and bearing temperature; 8.6.2 These requirements apply to the large size pump, its driver and its corresponding auxiliary systems. 8.6.3 Specific requirements, considering process unit characteristics, shall be defined in each respective process unit basic design. 8.6.4 GENERAL CONTROL ARCHITECTURE 8.6.4.1 The system shall be design with the following subsystems: •

One dedicated controller for OPS – Over speed Protection System (if applicable);

•

And the MMS – Machinery Monitoring System.

8.6.4.2 Each compressor/driver set and its auxiliary system shall be provided with the following instrumentation panels. a) A Remote Control Panel (RCP), for its data acquisition, control and interlock purpose. b) A Local Panel (LP), for its local supervision purpose. 8.6.4.3 Each large size pump/driver set and its corresponding auxiliary have a single dedicated RCP, installed in the CCL, accommodating all pump RCP shall attend the following requirements established (Instrumentation Design Criteria), in its item for Package Units, and to requirements established in the following sub-items:

systems shall systems. The on item 5 the additional

a) For single pumps (with no spare pump), all RCP electronic equipments (as PLC and dedicated controllers) with control and interlock functions shall be provided, as a minimum, with redundant CPU , redundant communication between CPU and I/O cards and redundant power supply. The CPU shall support software downloads without interrupting normal operation of the equipment. b) Shall be provided with an Ethernet interface for remote maintenance and supervision procedures for the PLC. c) Shall be provided with dual electrical power input in 125 Vdc, one main and another back, so that the loss of just one 125 Vdc feeder will not affect nor degrade the RCP controls and interlock functions. d) The 24Vcc power source, for power supply of any compressor field instruments and any other electronic equipment, shall be redundant and powered by both electrical 125 Vdc power input circuits.


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e) Shall be provided with component fail detection as CPU, electrical source and others and it shall be reported to DCS. f) Configuration data shall be stored in an EEPROM or another re-programmable nonvolatile device, so that the configuration will not be affected in case of power failure. g) When vibration monitoring modules are required to large size pump/driver set, it shall be sheltered inside the pump RCP unless the distance between sensors and the RCP is longer than the maximum distance recommended by vibration monitoring Manufacturer, when in that case vibration monitor modules shall be sheltered in LP and shall be approval by PETROBRAS. h) Shall be provided with other equipment, according to pump type. i) The panel shall contain a graphical user interface with the same information of the LP graphical user interface. The program shall avoid the simultaneously operation. j) The analog modules of PLCs shall be able to read Hart information and provides them to the asset management system. k) The analog modules of dedicated controllers shall be connected to a multiplex Hart to read Hart information and provides them to the systems. In case of reliability decrease this data should be submitted to Petrobras. l) Figure below shows the acceptable architecture for the RCP.

RCP – Remote Control Panel Graphical User Interface ( HMI)

OPS- Overspeed Protection System MMS- Machinery Monitoring System

8.6.4.4 The pump LP shall attend the following requirements established on item 5 (Instrumentation Design Criteria), in its item for Package Units, and to the additional requirements established in the following sub-items. a) Shall be provided with a graphical user interface with the following screens: a general view of the system, start/stop monitoring, alarms, oil system status, seal system, operational monitoring status (showing vibration, axial displacement and bearing temperature) and other systems. b) All screens shall be supply in Portuguese language. c) The LP shall be provided with two pushbuttons, one for pump trip and another for permissible start, both hardwired connected to the RCP.


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d) The emergency shutdown push button shall be of the locking type e) The ESD push-buttons shall be hardwired to Analog Input modules with diagnostic and monitoring capabilities. f) The LP shall be located at about 3 to 5 meters from the set.

g) The HMI shall be a flat panel LCD display with the following characteristics: - Full useful display area of 12” size, at least; - Keyboard for display operation (screen selection, paging, etc.). Touch-screen displays are acceptable but no command shall be implemented in the display. Flat membrane keypads should be avoided; - Easy screen reading under daylight conditions. - If necessary in the local panel, multi led lamp shall be used as alarm lamp 8.6.4.5 Pump start up shall be done only remotely, from DCS, upon a local start permission pushbutton actuated by operator in the LP. When this pushbutton is actuated, the compressor is enabled to start up during a determined time. After this time the compressor shall be locked for start up and a new start permission pushbutton actuation shall be done to enable it again. 8.6.4.6 The CONTRACTOR shall check and make appropriate recommendations for process and instrumentation design related to compatibility with the control system: transmitter selection, coolers, flow elements and check valves. 8.6.4.7 All PLCs, dedicated controllers and monitoring systems shall be provided with a 100 MBPS Ethernet interface for remote maintenance and supervision procedures. The Interface shall support the TCP/IP protocol. 8.6.4.8 The memory maps necessary for the communication shall be supplied by the CONTRACTOR based on a standardized defined by PETROBRAS. These memory maps shall include: addressing, data scaling, available functions and any necessary information for configuration support. Besides, they shall be organized in blocks to guarantee that the data refreshing in the DCS can be all concluded in 5 seconds at most. All data shall use the engineering units defined in item 4. 8.6.4.9 The recording of critical events shall have the potential to capture high-speed trend information for selected variables in the Machinery Monitoring Subsystem, before and after any user-defined critical event. This storage system shall allow the visualization of graphical trends with 100 milliseconds of resolution at least. 8.6.4.10 All systems shall perform I/O module self-diagnosis and its configuration data shall be stored in an EEPROM or another reprogrammable non-volatile device, so that the configuration will not be lost in case of a power failure. The systems shall also support the replacement in operation mode of any electronic module.


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8.6.5 Dcs And Pes Interface 8.6.5.1 Any control signals, including set points, as well as trip, start and stop commands signals shall be hard-wired from DCS or PES to pump RCP. Digital communication links for these kinds of signals are NOT acceptable. 8.6.5.2 Supervision signals from remote control panel shall be done by communication using Modbus-TCP protocol with DCS as master in the communication. This communication shall be redundant. 8.6.6 Field Instrumentation 8.6.6.1 Field instrumentation installations shall comply with the PETROBRAS Standard NI-1882, requirements defined on item 5 (Instrumentation Design Criteria) and to the additional requirements established in the following sub-items. 8.6.6.2 Sizing and selection criteria shall be provided for all new required auxiliary instrumentation including measuring elements, transmitters, valves and positioners. 8.6.6.3 Transmitters, flow measuring devices and valves (where applicable) associated with the control system shall be evaluated for proper location and sizing. Analog instruments not connected to the PLC shall be connected to a standardized multiplex HART for the purpose of remote maintenance, in case of risk of decrease of reliability this data should be submit for PETROBRAS. 8.6.7 Overspeed Protection 8.6.7.1 The over speed shall be monitored by an electronic system, supplied by vendor. 8.6.7.2 This system shall be unique and exclusive for this application, complying with the API-670. 8.6.8 Machinery Monitoring System (Mms) 8.6.8.1 The MMS is responsible for indicating, registering and alarming the variables that are important for machinery integrity such as vibration, axial displacement and bearing metal temperature, and for sending hardwired signals for tripping. 8.6.8.2 The MMS shall obey API 670 (Machinery Protection Systems) requirements for the quantity, type, position and installation of the sensors. 8.6.8.3 The MMS shall be located in a panel in the local control room. 8.6.8.4 The human-machine interface for the operation/configuration of the MMS shall be a personal computer, compatible with the MMS technology requirements. 8.6.8.5 System support software shall be supplied in order to allow configuration and troubleshooting procedures from the workstation. 8.6.8.6 The storage of critical events shall be provided with the capacity to capture highspeed trend information for all critical process and system variables, before and after


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any user-defined critical event. Data resolution stored event files shall be 100 milliseconds or less. 9.

AIR COOLER AUTOMATION

9.1.

SCOPE

9.1.1 These guidelines include logic integration between control and start up sequence, and all requirements for remote operation of the air-coolers. 9.2.

GENERAL GUIDELINES

9.2.1 The total number of VSDs per air-cooled heat exchanger shall be described, by basic design, on the Data Sheets of each equipment. 9.2.2 In general, the number of VSDs is a function of the number of sections. A section of an air-cooled heat exchanger usually contains 2 fans. Up to 1 section, 100% of the heat duty shall be supplied by fans with VSDs when the temperature needs to be controlled. From 2 sections on, at least 50% of the heat duty is normally supplied by fans with VSDs. 9.3.

FUNCTIONAL REQUIREMENTS AND INTERFACES

9.3.1 The following commands shall be provided to enable the automatic operation of each air-cooled heat exchanger: a) “Available” / “In Maintenance” Selector; b) Auto” / “Manual” Selector; c) “Start-up” / “Shutdown” Command for each fan; d) All Fans General Shutdown command. 9.3.2 For maintenance reason, all fans motors shall be supplied with a mode selector switch with 2 positions: “Available”, and “In Maintenance”. At “In Maintenance” position, a fan shall not be under influence of the automation system logic nor the air cooler outlet temperature PID controller. In this case the fan shall be inhibited to be turned on even by operation staff or by the automation system logic. 9.3.3 When operator switches this selector to “Available” position, the fan shall be enabled to be turned on and off every time the operation staff or the automation system logic demands this operation. For fans supplied with VSDs, the selection to “Available” position shall also send the output of the air cooler outlet temperature PID controller to the VSD. 9.3.4 The “Auto” / “Manual” operation selector shall start and stop the automation system logic of all fans without VSDs which are in “Available” mode. The logic associated to this automation is described on items 9.4 and 9.5. When in “Manual” mode, operation staff shall start and stop each of the fans in “Available” mode.


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9.3.5 A general shutdown signal shall turn off all the fans of an air-cooled heat exchanger. 9.3.6 All signal interfaces related to air-cooled heat exchangers automation shall be supplied according to as described in the following diagram.

DCS


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9.4.

LOGIC SEQUENCE DESCRIPTION

9.4.1 Before the activation of the automation system logic, operation staff shall select the sequence in which each fan of the air cooler, without VSD, shall be started up. 9.4.2 To minimize thermal gradients between air cooler sections which causes mechanical stress on piping arrangement, design recommendation establishes that the air cooler fans operation shall be as symmetric as possible. Consequently, the start-up sequence shall be implemented as symmetric as possible. The example below shows by means of numbers, a general air cooler fans start-up sequence implementation.

9.4.3 Once the start-up sequence is defined, the shutdown sequence is established from the fan without VSD which is the longest time in operation. The longer time the fan is in operation, the shorter time the fan shall be shutdown. 9.4.4 After the definition of the start-up and shutdown sequence, operation staff shall start up, in “Manual” mode, the required number of fans without VSD and change the air cooler outlet PID temperature controller to “Automatic” mode. 9.4.5 The output of the temperature controller shall manipulate equally the rotation of the fans which are supplied with VSDs. 9.4.6 The output of the temperature controller, before being sent to all VSDs, shall be connected to an “Auto/Manual Loader” block which shall also be configured on DCS. This function shall bypass the output of the air cooler outlet temperature controller and enable the operation staff to manipulate the speed of each specific VSD independently. 9.4.7 The air cooler outlet temperature controller shall be tuned before the activation of the automation system logic. Once this controller is tuned, the automation logic mode selector switch shall be transferred to “Auto”.


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9.4.8 From this moment, every time the output of the air cooler outlet temperature 8ontroller is higher than 90% during 10 seconds and there still exist any fan out of operation with the “Available” status, the automation logic shall start up a fan motor according to the initially defined sequence. 9.4.9 In the same way, every time the output of the controller is lower than 10% during 10 seconds, the automation logic shall shutdown the fan according to the defined sequence. 9.4.10 After the start-up or shutdown of any fan motor, the automation system shall be bypassed for T1 minutes to wait for temperature stabilization dictated by the temperature controller output. 9.4.11 If the output of the controller is still greater than 90% or lower than 10% after T1, the automation system shall turn on or turn off a next fan motor. 9.4.12 T1 shall be adjustable according to the process dynamics and final tuning of air cooler outlet temperature controller, and shall be confirmed during plant normal operation. Initial suggested value is 2 minutes. 9.4.13 The block diagram associated to the automation system logic is presented on item 9.5.

9.5.

BLOCK DIAGRAMS: AIR-COOLED HEAT EXCHANGERS AUTOMATION

Note: The automation logic is described as a scan program between “Begin” and “End”


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10.

BOILER CONTROL AND SAFETY REQUIREMENTS

10.1. SCOPE 10.1.1. The requirements defined in this item establish general guidelines for boilers control and safety design. 10.1.2. These guidelines for boilers automation design include control strategy, interlock system, minimum required interface, minimum field instrumentation and need for process alarms. 10.2. GENERAL GUIDELINES 10.2.1. DCS and PES are the equipment responsible for the process monitoring and control of an Industrial Unit. 10.2.2. PES is defined as equipment responsible for the interlocking system of an Unit or a subsystem of the Unit. 10.2.3. Boiler safety strategies shall be implemented on a PES, certified as SIL 3, according to IEC-61508, SIS requirements in accordance with PETROBRAS standard N-2595, the logic system for burners management in accordance with NFPA 8502 and Brazilian standard code NR13. 10.2.4. Boiler control and monitoring shall be implemented in DCS architecture with Foundation Fieldbus protocol instruments. 10.2.5. SIS transmitters shall be in 4-20 mA standard with HART protocol. 10.2.6. The number of DCS controllers and PES controllers and how the inputs and outputs signals shall be distributed based on a reliability and availability study for the boilers system considering that each boiler could be stopped for maintenance purpose and not affecting the others. 10.2.7. The operator DCS interface will be installed in the COMPERJ Integrated Control Center – CIC.


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10.2.8. The Basic automation architecture is similar to fired heaters and is shown below:

10.3. CONTROL STRATEGIES 10.3.1. Steam flow control 10.3.1.1. The combustion control shall be implemented based on the produced steam pressure, measured in the steam header and defines the combustible flow ratio necessary to maintain it in the desired value. 10.3.1.2. The system has to get early the air excess adjust before any combustible variation. It shall be possible the combustible control based in the steam produced flow in order to maintain it the control range. The loop shall be implemented with crossed limits and limits in the burner pressure. 10.3.1.3. The combustion control shall be affected by the amount of oxygen in the combustion gas. 10.3.2. Water level control in the steam drum


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10.3.2.1. The loop shall be with three elements type in order to prevent against the “swelling” and” shrinking” effects. In this system, the water level measure in the steam drum controls the water feed flow, in cascade mode with a water feed flow controller, with the steam flow measure getting early the level correction in the fast feed variations. 10.3.2.2. The steam output measure shall be adjusted by the pressure in the area of secondary super-heater output. 10.3.2.3. The process taps and transmitters for process, alarms and safety shall be independents. The sensors for level transmission for control shall be of differential pressure type. 103.2.4. There shall be three transmitters for the SIS in the 2oo3 voting mode and also three with a voting logic in accordance with the failure status for the control in DCS. 10.3.3. Steam temperature control 10.3.3.1. The midway and final temperatures of superheated steam shall be controlled by the boiler water injection among the super-heater flow-steps, controlling the variable in the boiler output. 10.3.3.2. The water injection control shall be calculated to assure the correct superheating degree for the whole boiler operation range from the ignition and pressurization until the automatic operation. 10.3.3.3. The system shall be designed with a manual control for water desuperheating when the control would be out for maintenance purpose. 10.3.3.4. The design shall consider two control valves with different dimensions in a split range configuration. 10.4. REQUIREMENTS FOR PROCESS INSTRUMENTATION 10.4.1. There shall at least the following variables indications in the DCS . 10.4.1.1. Temperature: a) b) c) d) e) f) g) h) i) j) k) l) m)

Combustion air downstream the steam pre-heater (if it exists), Combustion air upstream the steam pre-heater (if exists), Combustion air upstream the “economizer”, Combustion gas in the inlet of “boiler bank”, Combustion gas in the output of “boiler bank”, Combustion gas in the output of air pre-heater. Super-heater wall Combustible oil Combustible gas Water in the inlet of 1o heater (if exists), Water in the outlet of 1o heater/inlet of 2o heater (if exists), Water in the outlet of 2o heater (if exists), Water in the boiler inlet (downstream the economizer),


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n) o) p) q) r) s)

Steam in the outlet of primary super-heater, Steam in the inlet of secondary super-heater, Steam in the outlet of secondary super-heater, Mechanical seal of forced draft fan, Mechanical seal of turbine of forced draft fan, Mechanical seal of gearbox of forced draft fan.

10.4.1.2. Pressure: a) b) c) d) e) f) g) h) i) j) k) l) m) n) o) p) q) r)

Combustible gas in the burners header, Combustible oil in the burners header, Atomizing steam (differential pressure), Combustion air upstream the steam pre-heater (outlet of fan), Combustion air in the inlet of air of gas pre-heater, Combustion air in the outlet of air of gas pre-heater, Air box, Furnace, Combustion gas in the outlet of super-heater, Combustion gas in the outlet of “boiler bank”. Combustion gas in the outlet of air of gas pre-heater, Steam drum, Steam outlet Vapor (super-heater), Sealing air, Feed water in the boiler inlet, Steam for cleaning, Lube oil upstream filter of forced draft fan, Lube oil downstream filter of forced draft fan.

10.4.1.3. Flow: a) b) c) d) e) f) g) h) i)

Combustible gas, Combustible oil ( It shall be of coriolis type), Steam in the boiler outlet, Feed water, Water for desuperheating, Continuous purge, Combustion air, Gas in the tube for atmosphere. Steam for cleaning.

10.4.1.4. Level: a) b) c) d) e) f)

Water in the steam drum, Water in the continuous purge drum, Condensate in the combustible gas. Heater of water no 1 (if exists), Heater of water no 2 (if exists), Drum water without air (two independent transmitters).

10.4.1.5. Others:

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a) b) c) d) e) f) g) h) i) j) k) l) m) n) o) p) q) r) s)

pH of water in the steam drum, pH of steam in boiler outlet, pH of water in the outlet of equipment for getting off air of water, Conductivity of water in the steam drum, Conductivity of steam in the boiler outlet, Conductivity of water in the outlet of equipment for getting off air of water, Silica analyzer in the steam drum,. Silica analyzer in the steam of boiler outlet, Residual of phosphat analyzer in boiler water, CEMS system with % de O2, CO, NOx e SOx analyzers, Position status for all shut-off, ball and plug valves, Flame sensors with analog indication , digital and sensor failure, CFTV for flame monitoring with only air cooling system, Vibration measurement of motor of forced draft fan, Vibration measurement of turbine of forced draft fan, Vibration of forced draft fan, Current indication of motor of forced draft fan, Measurement of turbine speed of forced draft fan, Trip indication locked / unlocked in the turbine of forced draft fan.

10.5. PROCESS ALARMS REQUIREMENTS 10.5.1. The design shall consider at least the following process alarms in DCS and they would be part of the alarm data base organized based in EEMUA 191 document: a) b) c) d) e) f) g) h) i) j) k) l) m) n) o) p) q) r) s) t) u) v) w) x)

Flame failure in each burner, High and low combustible gas pressure in the burners, High and low combustible oil pressure in the burners, Low pressure of boiler feed water, High and low water level in the steam drum, High and low level in the continuous purge drum, High and low steam final temperature, High and low steam temperature in the outlet of primary super-heater, High and low steam temperature upstream the desuperheater, High level in the button of combustible gas pipe, Stop status of forced draft fan, Stop status of the motor of forced draft fan, Stop status of turbine of forced draft fan, Start status of motor of forced draft fan, Start status of the turbine of forced draft fan, High and low pressure in the furnace, Low pressure of sealing air, Failure status in the electrodes level sensors of steam drum, High vibration in the fan of forced draft fan, High differential pressure in the air of steam pre-heater, High differential pressure in the air of gas pre-heater, For all the signals that develop trip event, the first event shall be indicated, High temperature in the “skin-points” (super-heater). Flame failure in each pilot,


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y) Low speed of turbine of forced draft fan, z) High air excess. 10.6. FIELD INSTRUMENTATION 10.6.1. The design shall consider at least the following local indicators to be installed near equipment and with necessary accessories: 10.6.1.1. Pressure: a) b) c) d) e) f) g) h) i) j) k) l) m) n) o) p) q) r) s) t) u) v) w) x)

Combustible gas of the burner header, Combustible gas for each pilot and burner, Combustible oil of the burner header, Combustible oil for each burner, Atomizing steam (differential pressure), Atomizing steam in each burner, Feed water, Steam in the steam drum, Steam in the boiler outlet, Continuous purge drum, Steam for moisture boiler, Steam in the inlet and outlet of turbine of forced draft fan, Furnace, Air box, Combustion air upstream the steam pre-heater, Combustion air in the inlet of air of gas pre-heater, Combustion air in the outlet of air of gas pre-heater, Combustion gas in the inlet of gas pre-heater, Combustion gas in the outlet of air of gas pre-heater, Steam drum, Steam in the boiler outlet, Sealing air, Feed water in the boiler inlet, Steam for cleaning.

10.6.1.2. Temperature: a) b) c) d) e) f) g) h) i) j) k) l) m) n)

Combustible gas of burner header, Combustible gas of burner header, Boiler feed water, Inlet water for the 1o heater (if exists), Outlet water from the 1o heater (if exists), Inlet Water in the 2o heater (if exists). Steam generated, Combustion gas in the boiler outlet, Combustion gas in the outlet of air of gas pre-heater, Combustion air upstream of steam pre-heater, Combustion air downstream the steam pre-heater, Combustion air upstream the gas pre-heater, Steam at inlet and outlet of turbine of forced draft fan, Outlet of the intermittent purge drum.


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10.6.1.3. Level : a) b) c) d) e) f)

In the steam drum : two magnetic level gauges, In the steam drum with remote indicator near the feed water control valve, In the continuous purge drum (magnetic level gauge), In the drum of equipment from getting off air from water, In the 1o heater (if exists), In the 2o heater (if exists).

10.7. SAFETY REQUIREMENT - SIS 10.7.1. The boiler SIS shall be in accordance with the latest version of NFPA 8502 (where applicable) and the PETROBRAS N-2595 standard. 10.7.2. The design of logic diagram with the descriptive memorandum and other documents shall be submitted for PETROBRAS comments and approval before any construction task. 10.7.3. Boiler Emergence Shutdown (Trip) 10.7.3.1. The following table shows at least the events that can initiate a ESD with redundancy for instrumentation criteria: Events

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Very low level at the steam drum Flame failure at the burner Furnace high pressure Low combustion air flow Loss of two drivers of forced daft fan Low combustible pressure High combustible pressure Condensate high at the combustible gas drum Very high air temperature at the outlet of gas pre-heater (if exists) Low pressure of atomizer steam Trip pushbutton (field, local control room and CIC).

Voting criteria Primary element 2oo3

CLASS *** (Minimum) VI

1oo2 /2oo2 1oo1 2oo3 1oo2 *

II II VI VI

1oo2 1oo2 1oo2

VI VI VI

2oo2

III

1oo1

IV

1 in each place

Notes : * Tachometers installed in the fan shaft. ** Trip of only the combustible gas system. *** Class of Safety Loop, see NI-2595 table 2


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10.7.3.2. Each burner shall have two flame sensors to monitor the flame for the combustible gas and for the Combustible oil. In the event of ignition the voting schema is 1oo2 and in the normal operating the voting schema for trip is 2oo2. This schema is for each burner. 10.7.3.3. The design shall consider a “FLAME ROD” for each pilot for pilot flame monitoring. It is important to design the sensor electronics far the high temperature area. 10.7.3.4. The primary element for air flow measurement shall be a single venture tube with three taps distributed in a 90 degree radius schema. The three flow DP transmitters shall be installed above the air tube without low parts in order to avoid condensate and measurement errors. 10.7.3.5. It shall be possible to stop the boiler from pushbuttons installed in three places: safety place near boiler, local control room and integrated control center – CIC and specified with lock device to avoid spurious trip. 10.7.3.6. The ignition of boiler shall be made from DCS console in CIC with local supervision. All, the requirements described shall in NFPA 85 standard shall be attended for the automatic start philosophy. E

10.7.3.7. For interlock purpose of low level of water of the steam drum the design shall consider conductive electrodes sensors technology in a 2oo3 voting with independent process taps. 10.7.3.8. The logic design shall consider a minimum purge time with at least 30 % of air flow in order to avoid explosive atmosphere inside the furnace during the ignition. 10.7.3.9. During the period of each burner ignition the logic shall limit in 90 seconds the pilot ignition timer and 20 seconds for the burner ignition timer. 10.7.3.10. The pilot shall be automatic type class 3 in accordance with NFPA 85. 10.7.3.11. The design shall consider a local monitoring panel with an HMI to show the boiler variables from PES. It will be connected to DCS and the communication shall use the MODBUS-TCP or OPC-UA protocol. 10.7.3.12. The design shall consider a shut-off valve in the combustible oil header and for each burner design shall consider a plug valve followed by a shut-off valve. 10.7.3.13. The design shall consider for each of the pilots and for burners combustible gas headers two shut-off valves in serial arrangement with a vent valve with connection to a safety place ( at least 4 meters above the highest boiler platform) installed at the midway. For each pilot or burner line the design shall consider an individual shut-off valve installed in the centre of a ball valve upstream and a globe valve downstream. 10.7.3.14. All boiler shut-off valves shall be of flanged type.


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10.8. FUNCTIONAL REQUIREMENTS AND INTERFACES 10.8.1. All commands shall be implemented according to the interfaces defined on the following table:

Note : Start-up permission command shall be a pulse, avoid continuous permission. 10.8.2. All indication shall be implemented according to the interfaces defined in the following table in the P&I diagrams :

10.8.3. All signals related to the fired heaters shutdown shall also be supplied from field to PES by hardwire. All commands related to fired heater shutdown shall be supplied from DCS to PES by hardwire. 10.8.4. Any other manual commands defined to be implemented on the DCS shall be sent to the PES by serial communication.


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10.8.5. Indications available on PES shall be sent to the DCS by serial interface. 10.8.6. PES shall be installed on local control room close to the cabinets of the DCS. 10.8.7. The local panel shall be protected against rain and dust exposure with grade IP65 and with pressurized enclosure protection, in agree with IEC 60079-2, according to the area classification , in the local panel, multi led lamp shall be used as alarm lamp; 10.8.8. The start-up sequence will be initiated from DCS. 10.8.9. Operator shall have permission from local panel to start from DCS. 10.9. OTHER INSTRUMENTATION REQUIREMENTS 10.9.1. The design shall consider independent and safety taps for gas sampling and pressure measurement in the following points: a) b) c) d) e) f)

Boiler outlet, Furnace outlet, Gas outlet boiler tube, Air box of burners, Tubes upstream and downstream of air and gas pre-heaters (if exists), Boiler Stack

10.9.2. The design shall consider safety valves in the steam drum and another safety valve with a remote open command initiated by the operator in the DCS or by the pressure signal in the super-heater. 10.9.3. The design shall calculate silencers devices in the outlet of the special safety valves mentioned above (maximum noise of 85 dB 1 meter far from the PSV). 10.9.4. The design shall consider sampling points with graduated needle valve cooling device with final temperature of 25 oC for steam in the boiler outlet, water in the steam drum and water outlet in the device for getting of air from water. 10.9.5. The design shall consider a CFTV with cameras for the monitoring of flame in burners and super-heater with air cooling system. The design shall consider monitors installation in CIC and in the local panel. 11.

LOCAL CONTROLLER ROOM (CCL) AND CONTROL INTEGRATED CENTER (CIC)

11.1 The location of the Local Controller Room shall be determined in such a manner as to allow future new enlargements of the building. The inside and outside arrangements of the equipment shall also make provision for their future enlargements and retrofits. It shall be constructed beside the electric substation building. 11.2 The CCL shall be located outside a hazardous area.


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11.3 The room of panels must possess air conditioning system, keeping a temperature of 25 oC. 11.4 The internal floor of the CCL building shall be a false floor type with 1.0 m above the level of the surrounding terrain. 11.5 Areas of the floor around the panels, used for removal of equipment, shall be at the same level as the equipment to be removed. In the case of withdraw able equipment mounted at a high point, a proper mechanism shall be provided for withdrawal of the equipment at its level of assembly. E

11.6 Cable shall enter and exit the CCL building through cable trays, located at the cables basement, this passage of circuits through openings in walls that separate hazardous areas and no hazardous areas shall be accomplished by multi-cables transit (MCT). Such cable trays shall be designed considering the arrangement and the reserves needed for future enlargements of the CCL. The spare cable trays assigned to future enlargements shall already be mounted in this stage. 11.7 All conduits entering or leaving the CCL shall be sealed. 11.8 The CCL building shall be built with the following characteristics and facilities: a) a telephone network, in order to allow the installation of a telephone set inside the CCL; b) conduit of a redundant data communication channel (VCD) comprised of fiber optic cables per each automation network 11.9 Equipment and doors shall be located so as to avoid any interference in case of removal of any piece of equipment.

B

11.10 Distribution instrumentation power panels shall be installed on the walls of the substation building. 11.11 All DCS controller and PES shall be provided with marshalling rack (MR) in order to rearrange the cables connections to its terminal strips. 11.12 Local Controller Room internal distribution cables shall be under the floor, through trays segregated by signal type and according to the established in API RP-552. 11.13 All digital electronic systems as DCS, PES, RCP, microcomputers and etc… shall be grounded as defined in API-552, item 20.9 (DES and Panel-boards ground buses). 11.14 Manufacturer grounding recommendations for digital electronic systems shall also be considered. 11.15 The design of the CCL shall consider the requirements for environmental conditions for process measurement and controls systems established in ISA 71.01 to 71.04.


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11.16 Requirements for CIC 11.16.1 The design of lay-out of CIC shall consider ergonomic requirements according to established in ISO 11064. 11.16.2 The design shall consider that there will be special rooms for : a) Dynamic Plants Process Simulator – room for equipments and for at least training five professionals and the instructor, b) Asset Management – room for people responsible for on-line dependability and reliability maintenance program, c) War Room – Room for Abnormal Situation Meeting Room, d) Severs Room – Room with access control for installation of servers and some clients for the DCS and production information data systems softwares. e) Printing Pool Room – room for installation of printers of the digital systems. 12.

SUPERVISION AND CONTROL SYSTEMS

12.1. SUPERVISION SYSTEMS 12.1.1 Supervision of all process and utility units shall be done through the DCS from its human machine interface located at CIC. 12.1.2 Specific package units, when required in its basic specification or recommended by its manufacturer, shall have a local supervision system in its LCP, LP and/or RCP. 12.1.3 The basic design shall define which package units shall have a local supervision system. 12.1.4 Data from all package units shall be sent to DCS, through serial communication or hardwired signals, in order to provide enough information to CIC operators supervise and operate overall process or utility unit, including each package unit.

12.2. CONTROL SYSTEMS 12.2.1 All control function shall be done in the DCS or in the designed Foundation Fieldbus field device, except for package units that have its own control panel. 12.2.2 The basic design shall define which package units shall have its control functions done by its own control panel (RCP or LCP). 12.2.3 All process and utility unit shall use Foundation Field-bus (FF).


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13.

FOUNDATION FIELDBUS SPECIFICATION

13.1.

SCOPE

13.1.1. This document establishes the requirements for a Foundation Fieldbus (FF) system design. 13.1.2. Contractor, that will design and supply part or all instrumentation and automation equipment, shall attempt for these requirements in this document. The Contractor shall take into account these requirements during detailing design, request of material and installation of some instrumentation items. 13.1.3. Additional or complementary functionalities from FF system vendor shall be submitted to PETROBRAS approval before vendor selection. 13.1.4. Noncompliance or complementary functionalities regarding configuration shall be submitted to PETROBRAS approval before configuration. 13.2. . DEFINITIONS a) FF - Fieldbus Foundation; b) ITK - Interoperability Test Kit; c) HIST - Host Interoperability System Test; d) VCR – Virtual Communication Relationship. 13.3.

INSTALLATION CRITERIA

13.3.1. Installation shall be in accordance with area classification of the unit. Design shall consider FISCO in a hybrid architecture (Ex e for trunk and Ex i for spurs) or FNICO (Ex n A[L] for trunks and spurs) Concepts for zones 0, 1 and 2. Ex d installation may be considered but a evaluation about maintainability shall be made considering aspects of IEC 60079-27. 13.3.2. Installation shall use "tree", "spur" or "combination" topology as shown below. Daisy chain topology shall not be used.


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13.3.3. Cables shall be type "A" , as stated in IEC 61158-2.. 13.3.4 Canceled. 13.3.5 There shall be 1 device per spur. 13.3.6. Trunk cable and spurs shall be tagged. Spur cables shall have segment and associated field device tags. 13.3.7. In non-intrinsically safe installations, passive multiport junctions ("bricks") and fast connectors shall be certified according to hazardous area classification. 13.3.8. Trunk and spur terminations in junction boxes shall connect through terminal block with protection against short-circuits. The protection against short-circuit shall fulfill the following restrictions: a) electronic short-circuit protection. Fuse protection shall not be used; b) the device may have visual short-circuit indication; c) have the a conformity certificate for classified area; d) current limit shall be 60 mA per spur. e) voltage drop in the segment shall conform to the calculation described in item 13.6.2. 13.3.9. Cable shielding shall be terminated at one end of the loop on the control room side, at a proper ground for this function. 13.3.10. Cable glands shall be included in the devices to connect it to the spur cable. 13.4.

FIELD DEVICES


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13.4.1. Devices shall be protected against polarity inversion. 13.4.2. All devices, and their respective function blocks shall be certified for FF ITK (Interoperability Test Kit) 5.0 or higher. Deviations shall be discussed with PETROBRAS. 13.4.3. Function blocks shall follow FF standards. Proprietary and "enhanced" blocks shall be clearly identified in documentation and submitted to PETROBRAS approval before its implementation. 13.4.4. Configuration of proprietary function blocks, or those not included in FF standards, shall be discussed with PETROBRAS prior to its implementation. 13.4.5. All devices shall be capable of performing on-line self-diagnostics, including selftest functions and be able to report diagnostic information at the HMI (Human-machine interface). 13.4.6. Measurement instruments shall have at least the following standard blocks: Resource, Transducer, one AI block, one PID block, one ARTHM, INTG and up to five more blocks among the following: ISEL, CS, OS, CS and MAI. Additional blocks shall be defined during detail engineering design and proposed to PETROBRAS. 13.4.7 Valve positioners shall have at least Resource, Transducer, one AO, AI block, one PID block and up to three more blocks among the following: other PID, two DI, DO, CS, ISEL, OS, and MAI . Additional blocks shall be defined during detail engineering design and proposed to PETROBRAS. 13.5.

HOST SYSTEM

13.5.1. Host System shall have a Letter of Compliance regarding the Host Interoperability System Test (HIST) as stated in FF-569 standards. The host system shall be approved for at least the following features: a) Device Tag Assignment; b) Device Address Assignment; c) Configuration of Link Master Devices; d) Block Tag Configuration; e) Standard Blocks; f) Enhanced Blocks; g) Custom Blocks; h) Function Block Linkage Configuration; i) Device Description Services; j) Capability Files.


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13.5.2. Host system shall have VCR capability to implement all control strategies and configuration in the field devices. Deviations from this specification shall be submitted to PETROBRAS. 13.5.3. Device address assignment shall be done automatically. 13.5.4. DD and Capability files shall suffice for field device configuration via host. Additional files or hardware are not acceptable. 13.5.5. Host system shall be able to add and configure new field devices, without segment shutdown or new start-up. This same ability shall be available to existing devices in the segment. 13.5.6. Neither device firmware nor host system software upgrades shall impact each other. 13.5.7. Host system shall be able to perform and access segment and field device diagnosis data. 13.5.8. Host system shall be able to export all data from segments, function blocks and modules. File format shall be ASCII. 13.5.9. Host system shall have OPC capability for integration with third-party systems. 13.5.10. Host system shall be provided with two 100 Mbps Ethernet interfaces. The Interfaces shall support the TCP/IP protocol. In case of a single fault, the communications shall not be interrupted. 13.5.11. Host system shall be able to: transfer data from one segment to the others, communicate with the PC platform and communicate with the configuration software, supervision software and asset management software. 13.5.12. Host system communication with the PC platform shall be done via OPC (OLE for Process Control). 13.6.

SEGMENT DESIGN

13.6.1 Segment Topology and Redundancy 13.6.1.1 All segments shall have redundant H1 interface card and redundant fieldbus power supply (FPS). The redundant interface cards and power supplies shall be installed in a hot-swap architecture. 13.6.1.2. Cable routing shall consider maximum trunk integrity and protection against hazards. Routing design shall be submitted to PETROBRAS approval 13.6.2. Bulk Power Supply (BPS) and Fieldbus Power Supply (FPS) 13.6.2.1. BPS is general power source and provide power conversion from 125Vdc to 24Vdc. FPS is a special power source designed to feed Foundation Fieldbus segments. 13.6.2.2 Segments shall be fed by redundant BPS.


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13.6.2.3. Both BPS and FPS shall have over current protection. 13.6.2.4. FPS shall provide isolation from BPS and impedance matching for the segment. 13.6.2.5. FPS shall be sized so that the minimum allowable voltage drop in a segment device shall be 11 VDC. 13.6.2.6. Status indication of the power supply shall be available on the supervisory system. 13.6.2.7. Sizing of segment power supplies shall comply with the items below: a) full segment power load; b) short circuit fail at one spur; c) excess of 25% current load above the previous items, considering the segment with the highest current load. 13.6.3 Voltage Drop Checking 13.6.3.1 All segments classified as level 1 or 2 shall have a detailed calculation sheet for voltage drop. 13.6.3.2 The other segment length shall be tested according to the equation below. L < 1000 *

(Vc − Vd ) R * ( It + Isc)

L => Segment length, in meters Vc => Voltage at FPS output, in volts Vd => Minimum allowable voltage drop on a field device, in volts Isc => Limit current for short-circuit protection, one device, in ampères It => Segment total current minus the value for the lowest consumption device, in ampères R => resistance per cable length, in ohm / kilometer In the case of equation in item above is violated, a detailed calculation sheet for the segment voltage drop shall be generated to verify minimum allowable voltage drop.

13.6.4. TERMINATORS (T) 13.6.4.1. Terminators shall be located at the each end of the longest run of the trunk cable.


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13.6.4.2. In case no disturbance is observed in communications, terminators may be internal to FPS. 13.6.5. Segment devices and Function Blocks 13.6.5.1. The main Link Active Scheduler (LAS) shall be configured in the H1 interface. 13.6.5.2. Backup LAS shall be configured either in the redundant H1 interface when available or in a fieldbus device of the segment. The device shall have only monitoring function in the segment. 13.6.5.3 In case a monitoring device can not be chosen, backup LAS shall be configured in the segment device with the most available bandwidth (fewer function block external links). 13.6.5.4. All function blocks in a control loop shall be in the same segment. Deviations from these criteria shall be discussed with PETROBRAS. 13.6.5.5. Function blocks involved in control loops shall be configured as standard FF blocks. Any proprietary function block or parameter configuration must be submitted to PETROBRAS approval. 13.6.5.6. When the design consider the PID block running in the field device, the PID blocks shall reside in the final control device. In case of simple cascade PID control, if PETROBRAS accept a final control device without two PID blocks available, the slave controller shall reside in the final control device and the master in the primary control loop transmitter. 13.6.5.7. When the design consider the PID block running in the field device , similarly, for a single PID control plus an override control, the override PID controller may reside in the transmitter of the restriction variable. 13.6.5.8. When the design consider the PID block running in the field device , for split range control, the PID block shall reside in one final control device. The second final control device shall communicate with the PID block in the first one. 13.6.5.9. Valves shall be driven to last control position in case of communication malfunction, unless process conditions require otherwise. 13.6.5.10. Valves shall be driven to fail safe position in case of power supply failure and shorted segment. 13.6.5.11. There shall be a maximum of 10 devices per segment, including at most 2 control valves. This requirement shall hold, unless it conflicts with control loop performance as stated below. 13.6.5.12. Segments with only monitoring devices shall have neither redundant H1 interface nor LAS in field device. 13.6.6 Function Block Tagging 13.6.6.1. Function block tag shall follow the pattern below.


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DEVICETAG FUNCBLCKTYPE INDEX Examples: FT202_AI_1, TT110_PID_2 13.6.7. Segment Scheduling 13.6.7.1. Unscheduled communication time shall not be less than 70% of the macro cycle. Unscheduled time availability shall be verified for all segments. 13.6.7.2. Macro-cycle frequency shall be at least 3 times the frequency response of the process. 13.6.7.3. A calculation sheet with segment scheduling shall be provided for each segment. The calculation sheet shall include function blocks execution time, as well as scheduled and unscheduled time sizing criteria. 13.6.7.4. It shall be possible for the user to configure the macro cycle. 13.6.8. Control Performance 13.6.7.1. The following periods shall be considered for maximum control response time: Process Variable

Maximum control response time

Flow

1000 ms

Pressure and Differential Pressure

1000 ms

Temperature

3000 ms

Level

3000 ms

Analytical

3000 ms

Fast process

150 ms

Note: These values can be modified due to technology licensor requirements. 13.6.8.2. The macro cycle shall be discussed with PETROBRAS during detail engineering for each H1 segment. The response time shall be considered according to the diagrams below for each case, control in the field or in the host. Deviations from specified performance shall be discussed with PETROBRAS.


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13.7.

CONFIGURATION TOOL

13.7.1. Configuration tool shall be fully integrated to host system software. 13.7.2. Configuration tool shall be able to set all parameters associated with the FF device. The tool shall be able to configure the device using only the information contained in the device description and capabilities files, as registered at FF. 13.7.3. Configuration tool shall perform the functions listed below: a) display device parameters and download of new settings in field device in a single download operation; b) display information about all segments in an organized template; c) generate reports on segment and device information, in ASCII format. Report on field devices shall have all configuration parameters settings; d) store templates for function blocks and control/monitoring loops. Information on the configuration of the components of the template shall be accessible and have the option to be exported into ASCII format file;


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e) partial download for device and function block strategies, without upsetting segment operation; f) Access and configure loops connected to host system, which are not in FF segments. 13.7.4. Configuration tool shall be able to import templates and parameterization databases. 13.7.5. Configuration tool shall have all drives and support for integration with supervisory system, including OPC (OLE for Process Control) drive. System vendor shall give support for system integration. 13.7.6. The Configuration Tool’s communication protocol shall support OPC (OLE for Process Control). 13.7.7 The configuration shall be done on-line, via an Ethernet-TCP/IP interface. The Configuration Tool shall be able to change the programming of any H1 device, including the scheduler, without upsetting segment and host operation. 13.8.

MAINTENANCE TOOL

13.8.1. A maintenance system shall be supplied with capability of configuring, calibrating and performing diagnosis of the fieldbus system, including devices, hosts and communications. 13.8.2. This system shall provide: a) configuration of field devices, b) acquisition of on-line and historical device data, c) device monitoring for alerts, d) field device tracing, with configuration changes and device replacement reports, e) import and export of data base and configuration to files, f) test host function and status, g) test communication between host system, segments and devices, h) test the devices performance such as valves signature. i) calibration tracing, with calibration changes reports. 13.8.3. Asset management functions shall be performed by maintenance tool with full integration to host system software. 13.8.4. Maintenance tool shall be able to supply all information therein through OPC protocol. System vendor shall give all support regarding asset tool integration with OPC servers/clients. Supplied information shall comprise, at least, the functions cited in item 13.8.2.


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13.9.

DOCUMENTATION

13.9.1. Documentation shall include, but not be limited to, the items mentioned in this section. Calculation sheets and other documentation mentioned previously shall be included. 13.9.2 Documentation shall be supplied in electronic format. 13.9.3. The following documentation shall be issued to PETROBRAS for comments prior to project implementation: a) Instrument Segment Diagram: showing physical connections and layout of the segment, not including logic information (function blocks, configuration etc). The drawing shall include the details listed below : - segment identification and connections, including H1 interface, power sources, junction boxes, devices, terminators, etc; - segment back-up LAS and terminator location shall be clearly identified; - length of trunk and spurs; - voltage in each device; - current of the segment. b) Instrument Data Sheets: containing standard information on instrument plus the items below. - current load and minimum operating voltage; - LAS capability; - firmware DTM revision and DD revision; - channel description and associated task; - function blocks available, indicating those with enhanced capabilities; - function blocks configured in the device and their parameterization; c) Segment Layout Plan: showing instrument location and segments in the unit, in 3dimensional diagram. Cable runs and segments shall be clearly identified; d) Control Loops Description: shall include control strategies, describing function blocks links and configuration parameters; e) Maintenance manuals and procedures: shall cover fieldbus system components, including technical data and troubleshooting procedures; f) Calculation sheets shall be provided for cables regarding voltage drops for all segments. Minimum segment voltage shall be stated in the document;


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g) Wave form signature plots shall be provided for each segment, showing that the wave form is in accordance with the limits established by the IEC 61158 h) Calculation sheets shall be provider the macrocycle for all segments, with synchronous and asynchronous periods discriminated.

13.10. ACCEPTANCE TESTS 13.10.1. All acceptance tests shall be performed and approved by both Vendor and PETROBRAS representatives. 13.10.2. Factory Test 13.10.2.1. Each fieldbus system component shall be tested for functionality including, but not limited to, compatibility with host system, access to device function blocks and communication within segment. Tests shall also include setup and calibration. 13.10.2.2. Field device calibration and setup procedures shall be documented and submitted to PETROBRAS approval. 13.10.2.3. Devices with LAS capability shall be tested for loss of H1 interface. 13.10.2.4. H1 interface and power supply redundancy tests shall be performed in order to check for system operation mal-functions. All H1 interfaces and power supplies shall undergo this testing. 13.10.2.5. Host system shall be tested for all functions as described in item13.5.1. 13.10.2.6. The following strategies shall be configured for testing purposes: one simple PID loop, one cascade PID loop, one PID ratio loop, one override PID loop and one flow pressure plus temperature compensation loop. 13.10.3. Site Test and Commissioning 13.10.3.1. The test shall comprise the same scope of the factory test plus segment commissioning. 13.10.3.2. Waveform signatures for communication shall be performed for every segment, and checked for compliance with IEC 61158 standard. 13.10.3.3. Test acceptance shall depend on both factory and site test approval by PETROBRAS.

13.11. TRAINING 13.11.1. The training for Maintenance, Operation and Engineering people shall be conducted as classroom instructions, concerning fieldbus system operation, calibration and maintenance, including the presentation of drawings and specifications at Refinery. Training shall be at least 40 hours duration.


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13.11.2. Training shall cover, at least, the following topics: a) Fieldbus system fundamentals, including host, LAS and segment operation; b) Device, host and function blocks configuration; c) System diagnostics: network and devices; d) Criteria for loop configuration: procedures and recommendations; e) Critical alerts and alarms. f) Maintenance: use of troubleshooting tools and procedures; g) Access to trend information and data base management;

13.12. SPARE PARTS 13.12.1. Spare parts shall be supplied for commissioning and two (2) years of operation. 13.12.2. A list of recommended spare parts shall be supplied by system vendor.

13.13. FOUNDATION FIELDBUS SEGMENT RISK MANAGEMENT The following valve criticality rating and network/segment loading method shall be used. The valve and associated measurement criticality shall be defined for prudent loading of Fieldbus segments. The following ratings shall be assigned to each valve and segment. 13.13.1. Level 1 Valves and Networks Failure of a Level 1 valve will result in a total system trip, causing a shutdown of the entire unit, or other unavoidable losses in excess of $10M. Normal Valve failure mode is to be used for this classification. Design Requirements: Level 1 valves and their associated measurement device (transmitter) shall reside on H1 networks that are only used for Level 1 control. The segment may have one (1) Level 1 Valve and associated Transmitter when services are independent, or two (2) Level 1 Valves and associated Transmitters when services are dependent. Dependent means that either of the two (2) valves will shut down the same piece of equipment (example pass flows on a fired heater). 13.13.2. Level 2 Valves and Networks


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Failure of a level 2 valve will result in a total system trip, causing a shutdown of the entire unit, or other unavoidable losses in excess of $100K. However, the Level 2 valve’s process dynamics allow time for quick recovery from the failure, either by quickly fixing a fault or by taking manual control. The material and energy capacity of associated vessels, geographic location, and elevation/accessibility of such valves shall be considered. The difference in Level 1 and 2 valves are dependent on operations ability to respond to a single failure. Design Requirements: Level 2 valves and their associated measurement device (transmitter) shall reside on H1 networks/segments that are only used for control. The segment may have one Level 2 valve and associated transmitter when services are independent, or two Level 2 valves or a Level 2 and a Level 3 valve and associated transmitters when services are dependent. Dependent means that either of the two valves will shut down the same piece of equipment (example pass flows on a fired heater). 13.13.3. Level 3 Valves and Segments Failure of this valve will not result in any short-term risk of total unit shutdown or major operating losses. Level 3 valves can go to their fail position without requiring immediate operator action. Design Requirements: Level 3 valves can reside on cards or networks/segments with up to three other level 3 valves, or on a segment with a level 2 valve. Networks containing Level 3 control contain products from multiple (approved) vendors including measurement only devices. 13.13.4. Level 4 Segments – No Control Level 4 devices are measurement only devices that shall not be used for control and may be configured in a way that could interrupt control on a network/segment. This class includes MAI, MAO, MDI, and MDO block communication devices.” 14.

DATA COMMUNICATIONS ROUTES - VCD

14.1 – The design shall consider data communications routes for integration of the many Digital Systems parts. 14.1.1- The VCD for the DCS shall be redundant and be designed in accordance with the technology’s choice . 14.1.2 – The VCD for the Asset Management of HART instruments , PLCs , PES and STVM´s master-stations and shall cover all the CCL’s and complies with Ethernet 100BASE-FX at least. 14.1.3 – The VCD for the Vibration Monitoring Machine Asset Network shall cover all th CCL´s and complies with Ethernet 100BASE-FX at least.


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15.

MODERN CONTROL STRATEGIES

15.1 - The basic design shall consider the requirements for implementation of a modern control strategy based on Predictive Controllers. This project may use the API 557 as a reference. 15.2- All instruments including control valves, transmitters, analyzers and the mathematical calculations variables shall be identified in the basic design. 15.3 – A cost and profit evaluating for the modern control implementation shall be developed to indicate the opportunity of the investment. 15.4 – It must be provided a system integrated or not with DCS with possibilities for best tuning of PID control loops. It shall have possibilities for audit of control loops performance with on-line diagnostics.

16.

THE ENTERPRISE-CONTROL SYSTEM INTEGRATION

16.1 The implementation of the enterprise-control system integration shall consider a Plant Information system as Historical Process Data Deposit . 16.2 It shall consider the capability for integration with the Company Enterprise Supply Chain Management – ERP. 16..3- It shall consider the capability for integration with a computerized maintenance management system – CMMS. 16.4 – It shall consider the capability for integration with a Data reconciliation System for the audit and control of energy and mass balance. 17.

DYNAMIC PROCESS SIMULATOR

17.1 The basic design of the units shall specify all information to allow the development of process models to be implemented in a single dynamic process simulator . 17.2 One Dynamic Process Simulator shall be specified for operator training purpose. 17.3 The Process Simulator shall support four operators and one instructor in the system at the same time. 17.4 It shall have at least the requirements: a) allows efficient model development;


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b) permits easy model modification to reflect changes in the process or control systems; c) provides robust trainee/operator link/ interface to major DCS systems; d) provides instructor features to allow the most effective and efficient simulator training. 16.5 It shall provide functionalities to the operator, at least; a) training in use of plant specific DCS configuration and the actual DCS system; b) training in all essential skills needed to operate the plant in a safe , reliable manner; c) training for plant startup/shutdown; d) training for normal operation-maintaining production to target rate and product quality in the face of disturbances; e) training in the correct response to failures of equipment, either in the process hardware or the control system; f) training in operation for different conditions of the plant equipment; g) handling of process upsets originating from external factors. 17.6 The Process simulator shall be mounted and in operational status at the refinery one year before the operation start of the first process unit. And so on each process model shall be implemented in the simulator a year before the operation start date for each refinery unit. 17.7 The system specification shall consider all the equipment , software and engineering services. 18.

TRADE AUTOMATED SYSTEM – TAS

18.1 For the purpose of the trade relationship with customers a complete automation solution shall be specified. 18.2 It shall have the following requirements : a) complete trade automation within the Refinery; b) product receipt integration; c) automation and integration with product storage; d) monitoring & control of product movement within Refinery;


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e) automation of tank truck / solid trucks/ rail car / ships loading & unloading operation; f) interface with ERP / Business System for Order to invoice integration; g) automated load scheduling; h) product accounting and stock reconciliation; i) inventory management with Tank Gauging Automation; j) automatic access control system to refinery site; k) remote valve control system ; l) pump operation optimization; m) solution expandable to pipeline automation on upstream and gas stations on downstream. 18.3 The following figure shows an example of a trade automated system.

Tank gauging sensors Level switches, Fire & Gas detectors, CCTV cameras

Ship

Schedule shipments, assign bay Monitor bay, meter, pump, valves Daily, monthly, MIS reports Communicate with field devices

Tank

MCC Batch controllers, Card readers Truck Safety devices (Overfill,grounding), ESDLoading Traffic light, CCTV

Fire&Gas detectors

Card readers (ID cards) CCTV cameras Physical verification Invoicing

Control room

Parking Check in counter, one for each

shareholder W e i g

h Guard

Load advice, Load ticket Weigh B in, out Remote display

Office Pump control PLC cabinet

18.4 The system specification shall consider all the components like : pumps, valves, gates, traffic lights, flow meters, weigh meters, card readers, transponder signals receiver, PLC, cameras and CCTV, printers, computers, printers, software, communications drivers to ERP Software and etc...


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18.5 The Interface with the ERP system may be represented as follow :

get loading data from Customers

Terminal Automation System Interface ERP Software

- Order processing - Delivery processing - Inventory management send loading data - Credit limit checking to Customers

send data

get loading data

Trade Automated System - Compatibility Check - Fill up processing - Entry check - Loading quantity check

18.6 The functionalities implemented in the ERP systems may be as following :

Send data TO/GET from TAS System

Send data TO Partner ERP System

LID Master Data Order Processing

Order / Contract Load Info forward Delivery Processing Shipment

Shipment Processing

ERP x TAS System Interface

19.

Load Info forward

Load Information

ELECTRIC POWER SYSTEM FOR INSTRUMENTATION

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19.1 The instrumentation electric power system shall be composed with the following electrical sources. a) A 120 Vac at 60Hz from redundant uninterrupted power supply system (RUPS) named as “120 Vac RUPS Circuit”; - The 120 Vac RUPS shall be fed from critical MCC. - The RUPS shall be provided with a serial communication with DCS, for monitoring, and diagnosis purpose, through a Profibus DP protocol. b) A 125 Vdc from redundant battery charger named as “125 Vdc CB”. - The 125 Vdc CB shall be fed from Critical MCC. 19.2 The 24Vdc, for feed field instruments and any equipment inside a control panel, shall be converted from 125 Vdc to 24 Vdc into the respective control panel and comply with the following requirements: a) it shall be redundant, composed by redundant sources ; b) each source or set of source shall be fed by redundant 125 Vdc CB coming from different circuits so if a single failure point will not affect the operation of the instruments and equipments powered by it. 19.3 When using two sources, each source shall be sized to support the electrical nominal load more 30%. 19.4 When using two sets of sources, each set shall be composed of the necessary number of 24 Vdc sources so that each source is sized to support the electrical nominal charge with more 20%, plus one source (n+1 configuration). 19.5 The sources of each set shall be provided with a load sharing system. 19.6 The system shall be provided with online replacement cards, in order to permit the change of any 24 Vdc source in operation. 19.7 The nominal voltage levels and the circuit feeder to be used, for the instrumentation in the process and utility units, shall comply with the table below.

Equipments

Electrical Source

PES, DCS, LCP and RCP

Two feeders in 125 Vdc from redundant CB´s

LP (see note 1 below)

One feeder in 120 Vac from the 120 Vac RUPS

Two wire transmitters

24 Vdc


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Four wire transmitters (including analyzers)

24 Vdc or 120 Vac from the RUPS

Discrete Inputs and Output.

24 Vdc

Solenoid Valves

24 Vdc

Dedicated Equipments for Control and Interlock (see note 1 below)

Two feeders in 125 Vdc from redundant 125 Vdc CB´s

Electric Hydraulic valves

480V 3Øf from critical MCC

Motorized actuators

480V 3Øf from critical MCC

Notes: 1) If LP has installed in it any four wire transmitter or dedicated equipment, either for control or interlock purpose, it shall follow the same criteria defined for it in the above table (Dedicated equipments for Control and Interlock). Example: for furnaces Local Panels its equipments for monitoring purpose shall be fed by 120 Vac RUPS from critical MCC and the flame rod monitors, that is a dedicated equipment for interlock, shall be fed by the two feeders in 120 Vac. 19.8 POWER DISTRIBUTION PANEL 19.8.1 The120 Vac Rups circuits for instrumentation shall be provided with a distribution panel to power individually each four-wire instrument, panel or any other load. 19.8.2 The 120 V ac distribution panel shall comply with the following requirements: a) a general input bipolar circuit breaker; b) each load shall have its individual bipolar circuit breaker. 19.8.3 125 Vdc CB circuits for instrumentation shall be provided with a distribution panel to power individually DCS, PES , LP , RCP or any other load. 19.8.4 The 125 Vdc distribution panel shall comply with the following requirements: a) a general input bipolar circuit breaker; b) each load shall have its individual bipolar circuit breaker. 19.9 GROUNDING SYSTEM 19.9.1 The grounding system shall be in agreement with NI-1882 standard (Installation of Grounding for Electronic Systems) of API-RP 552, as well as with each instrument or equipment manufacturer requirements.


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20.

TANKING GAUGING SYSTEM

20.1 The TGS is designed to measure and calculate information about the products stored in tanks and Esphere Park, units U-6300, U-6100, U-6312 and U-6314, the COMPERJ. 20.2 Must be followed the recommendations of the Manual of Petroleum Measurement Standards, cap. 3 and 7 of the API 20.3 The design of the system must be according to I-ET-6000.67-6300-853-PDY-001 System of Measurement in Tanks and Spheres - TGS. 20.4 TGS Will be used in operations: a) • Calculation of inventory, b) • Monitoring the transfer of custody, c) • Monitoring movement of products, d) • Monitoring of mixed products. e) • Aid the identification of leaks. f) • Aid to protect against overflow.

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