TECHNICAL SPECIFICATION N I-ET-3010.XX-1200-940-1DC-001 … · technical specification n o....

TECHNICAL SPECIFICATION N

O

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I-ET-3010.XX-1200-940-1DC-001 CLIENT: AGUP SHEET: 1 of 338

JOB: FPSO XXXXX -

AREA: XXXXX -

SRGE TITLE:

GENERAL TECHNICAL DESCRIPTION NP-2

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INDEX OF REVISIONS

REV. DESCRIPTION AND/OR REVISED SHEETS

0 ORIGINAL REVISION – FOR GROUP REVISION

A FOR BID

B MODIFICATIONS ON ITEMS 7.11.2, 7.11.4, 9.2.1; REPLACEMENT OF

ATTACHMENTS I-ET-3000.00-5529-850-P6B-001 and I-ET-3010.00-5529-854-

PAZ-005 BY NEW ONES I-ET-3000.00-5529-850-PEK-001 AND I-ET-3010.00-

5529-854-PEK-001; UPDATED I-ET-3010.00-1200-956-P4X-004; I-ET-3010.00-

1359-960-PY5-001, I-ET-3010.00-1200-940-P4X-003, I-ET-3010.0V-5521-931-

PEA-001, I-ET-3010.1U-5530-850-PEA-001 and I-ET-3000.00-8222-941-PJN-

001. MODIFICATION ON ITEM 2.1.2 note 8

REV. 0 REV. A REV. B REV. C REV. D REV. E REV. F REV. G REV. H

DATE 20/08/19 24/03/2020 06/05/2020 DESIGN XXXXX XXXXX XXXXX

EXECUTION JPAULO CNUNES CNUNES

CHECK MSANTOS MSANTOS MSANTOS APPROVAL VITALINO VITALINO VITALINO INFORMATION IN THIS DOCUMENT IS PROPERTY OF PETROBRAS, BEING PROHIBITED OUTSIDE OF THEIR PURPOSE

FORM OWNED TO PETROBRAS N-0381 REV. l

TECHNICAL SPECIFICATION No. I-ET-3010.XX-1200-940-1DC-001

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INDEX

1 GENERAL ................................................................................................................................................. 9

1.1. INTRODUCTION ..................................................................................................................................... 9

1.2. GENERAL DESCRIPTION ................................................................................................................... 11

1.2.1. REFERENCE DOCUMENTS ........................................................................................................ 11

1.2.2. GENERAL DESCRIPTION ............................................................................................................ 13

1.3. CLASSIFICATION ................................................................................................................................. 21

1.4. CERTIFICATES, TERMS AND STATEMENTS .................................................................................... 22

1.5. NOT APPLICABLE ................................................................................................................................ 22

1.6. RULES, REGULATIONS, STANDARDS AND CONVENTIONS REQUIREMENTS ............................ 23

1.7. DOCUMENTATION, UNITS AND IDENTIFICATION OF EQUIPMENT............................................... 25

1.8. INSPECTIONS, TESTS AND TRIALS .................................................................................................. 25

1.9. TRANSPORT AND INSTALLATION ..................................................................................................... 26

1.10. HEALTH SAFETY AND ENVIRONMENTAL ...................................................................................... 27

1.11. MATERIALS ........................................................................................................................................ 28

1.12. ISOLATION PHILOSOPHY ................................................................................................................. 30

1.13. NOT APPLICABLE .............................................................................................................................. 36

2. PROCESS .................................................................................................................................................. 37

2.1. FLUID CHARACTERISTICS ................................................................................................................. 37

2.1.1. PRODUCED OIL AND RESERVOIR ............................................................................................ 37

2.1.2. PRODUCED WELLS COMPOSITION .......................................................................................... 38

2.1.3. WELL TEST CHARACTERISTICS ................................................................................................ 42

2.1.4. PRODUCED GAS .......................................................................................................................... 44

2.1.5. PRODUCED WATER .................................................................................................................... 44

2.2. PROCESS ............................................................................................................................................. 44

2.2.1. CARGO TANKS/EXPORTED OIL ................................................................................................. 44

2.2.2. PRODUCED WATER DISPOSAL ................................................................................................. 45

2.2.3. SERVICE AND LIFT GAS ............................................................................................................. 48

2.2.4. EXPORTED GAS .......................................................................................................................... 49

2.2.5. HEAVY HYDROCARBON RICH STREAM (C3+) ......................................................................... 50

2.3. SEAWATER INTAKE ............................................................................................................................ 50

2.3.1. COMPOSITION ............................................................................................................................. 51

2.4. WATER INJECTION ............................................................................................................................. 52

2.5. DESIGN SUMMARY ............................................................................................................................. 57

2.5.1. WELL DESIGN SUMMARY ........................................................................................................... 57

2.5.2. PROCESS DESIGN SUMMARY ................................................................................................... 58

2.6. OIL & GAS COLLECTION SYSTEM .................................................................................................... 59

2.6.1. TOPSIDE MANIFOLDS AND FLEXIBILITY .................................................................................. 59

2.6.2. ARTIFICIAL ELEVATION SYSTEM .............................................................................................. 71

2.6.2.1. SMBS REQUIREMENTS AND INTERFACE CONNECTIONS WITH FPSO ........................ 72

2.6.2.3 AREA AND MATERIAL HANDLING ..................................................................................... 74


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2.6.2.4 PIPING FACILITIES ............................................................................................................... 74

2.6.2.5 ELECTRICAL AND INSTRUMENTATION FACILITIES ......................................................... 75

2.6.2.6. SAFETY REQUIREMENTS ................................................................................................... 76

2.7. PROCESS FACILITIES ........................................................................................................................ 76

2.7.1. SEPARATION AND TREATMENT ................................................................................................ 76

2.7.2. OIL TRANSFER SYSTEM ............................................................................................................. 80

2.7.3. GAS PROCESS PLANT ................................................................................................................ 81

2.7.3.1 OBJECTIVES .............................................................................................................................. 81

2.7.3.2 DESIGN CASES .......................................................................................................................... 82

2.7.3.3 PROCESS CONFIGURATION .................................................................................................... 82

2.7.3.4 GAS SWEETENING UNIT (NOT APPLICABLE) ........................................................................ 84

2.7.3.5 DEHYDRATION/HYDROCARBON DEWPOINT UNIT (GDU/HCDP UNIT) ............................... 84

2.7.3.6. VAPOR RECOVERY UNIT (VRU) ............................................................................................. 87

2.7.3.7. CENTRIFUGAL GAS COMPRESSORS .................................................................................... 90

2.7.3.7.1 MAIN GAS COMPRESSOR ..................................................................................................... 94

2.7.3.7.2 EXPORTATION GAS COMPRESSORS .................................................................................. 95

2.7.3.7.3 INJECTION GAS COMPRESSORS ......................................................................................... 95

2.7.3.7.4 CENTRIFUGAL COMPRESSOR DRIVERS ............................................................................ 96

2.7.3.8. OTHER REQUIREMENTS ......................................................................................................... 98

2.7.3.9. GAS PIPELINE AND KEEL-HAULING RISERS PRE-COMMISSIONING ............................ 98

2.7.3.10. MEG TREATMENT UNIT ......................................................................................................... 99

2.7.3.10.1 PRE-TREATMENT SECTION .............................................................................................. 101

2.7.3.10.2 RECONCENTRATION SECTION ........................................................................................ 102

2.7.3.10.3 RECLAMATION SECTION ................................................................................................... 103

2.7.3.11. HEAVY HYDROCARBON RICH STREAM (C3+) PUMP ................................................ 105

2.7.4. PRODUCED WATER TREATMENT ........................................................................................... 106

2.7.5. FLARE AND VENT SYSTEM ...................................................................................................... 109

2.7.5.1. FLARES .................................................................................................................................... 110

2.7.5.2. ATMOSPHERIC VENTS .......................................................................................................... 113

2.8. CHEMICAL INJECTION ...................................................................................................................... 114

2.9. SAMPLE COLLECTORS .................................................................................................................... 131

2.10. CORROSION MONITORING ............................................................................................................ 134

2.11. LABORATORY .................................................................................................................................. 139

3. UTILITIES ................................................................................................................................................. 144

3.1. GENERAL ........................................................................................................................................... 144

3.2. SEAWATER LIFT SYSTEM ................................................................................................................ 144

3.3. COOLING WATER SYSTEM .............................................................................................................. 145

3.4. FRESH AND POTABLE WATER SYSTEM ........................................................................................ 146

3.5. HEATING MEDIUM SYSTEM ............................................................................................................. 147

3.6. DIESEL SYSTEM ................................................................................................................................ 148

3.7. SEWAGE SYSTEM ............................................................................................................................. 149

3.8. DRAIN SYSTEMS ............................................................................................................................... 149

3.9. COMPRESSED AIR ............................................................................................................................ 150

4. ARRANGEMENT ..................................................................................................................................... 150


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4.1. SUPERSTRUCTURE (ACCOMMODATIONS) ................................................................................... 153

4.2. PROCESS PLANT .............................................................................................................................. 153

4.3. UTILITY ROOM (ENGINE ROOM) ..................................................................................................... 154

4.4 DIVING FACILITIES ............................................................................................................................. 154

4.5 HELIDECK ........................................................................................................................................... 156

4.6 SAFETY MAINTENANCE UNIT (SMU) ............................................................................................... 157

4.7 LAY-DOWN AREAS ............................................................................................................................. 158

5. HEATING VENTILATION AND AIR CONDITIONING SYSTEMS (HVAC) ............................................ 159

5.1. GENERAL ........................................................................................................................................... 159

5.2. HVAC SYSTEMS ................................................................................................................................ 159

5.3. REFRIGERATION SYSTEM (PROVISIONS) ..................................................................................... 160

5.4. CONTROL AND OPERATION ............................................................................................................ 161

5.5. VENTILATION OF THE TURRET AREA (NOT APPLICABLE) .......................................................... 161

5.6. STANDARDS AND BRAZILIAN REGULATION ................................................................................. 161

5.7 ELECTRICAL SWITCHBOARD ROOMS (E-HOUSE) ........................................................................ 161

5.8 HVAC EQUIPMENT ............................................................................................................................. 162

5.9. DESIGN REQUIREMENTS FOR VENTILATED AND AIR CONDITIONED ROOMS ........................ 162

6. SAFETY ................................................................................................................................................... 168

6.1. GENERAL ........................................................................................................................................... 168

6.2. ASBESTOS POLICY ........................................................................................................................... 168

6.3. RISK MANAGEMENT ......................................................................................................................... 168

6.4. NOT APPLICABLE .............................................................................................................................. 169

6.5. NOT APPLICABLE .............................................................................................................................. 169

6.6. SAFETY BARRIERS MANAGEMENT ................................................................................................ 169

6.7. PEOPLE ON BOARD (POB) MANAGEMENT SYSTEM .................................................................... 169

6.7.1. E-MUSTERING (POB-M) ............................................................................................................ 169

6.7.2. E-TRACKING (POB-T) ................................................................................................................ 170

6.7.3. TECHNICAL REQUIREMENTS .................................................................................................. 170

6.7.4. INTERFACES .............................................................................................................................. 172

6.8 PROCESS SAFETY SPECIAL REQUIREMENTS .............................................................................. 172

7. AUTOMATION AND CONTROL ............................................................................................................. 174

7.1. GENERAL ........................................................................................................................................... 174

7.2. CENTRAL CONTROL ROOM (CCR) ................................................................................................. 176

7.2.1. PLANT INFORMATION SYSTEM (PI) ........................................................................................ 178

7.2.2. CONTROL NETWORK ARCHITECTURE .................................................................................. 179

7.2.3. CYBERSECURITY ...................................................................................................................... 180

7.3. CONTROL AND SAFETY SYSTEM (CSS) ........................................................................................ 180

7.3.1. PACKAGE AUTOMATION SYSTEMS (PAS) ............................................................................. 183

7.3.2 ASSET MANAGEMENT ............................................................................................................... 185

7.3.3. AUTOMATION AND CONTROL SYSTEM PROGRAMMING ......................................................... 186


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7.4. CARGO TANK MONITORING SYSTEM (CTMS) .............................................................................. 187

7.5. SUBSEA PRODUCTION CONTROL SYSTEM (SPCS) .................................................................... 187

7.5.1 TYPES OF CONTROL SYSTEM USED BY THE SUBSEA EQUIPMENT .................................. 188

7.5.2 SPCS MAIN SPECIFICATIONS ................................................................................................... 191

7.5.3. SPCS UMBILICALS AND TOPSIDE UMBILICAL INTERFACES ............................................... 201

7.5.4. SPCS OPERATOR INTERFACES .............................................................................................. 206

7.5.5. SPCS HYDRAULIC POWER UNIT (HPU) .................................................................................. 209

7.5.6. WELL CONTROL RACK (WCR) FOR DIRECT HYDRAULIC CONTROL SYSTEM.................. 211

7.5.7. DOWNHOLE DATA ACQUISITION SYSTEM (SAS PANEL) ..................................................... 212

7.5.8. NOT APPLICABLE ...................................................................................................................... 214

7.5.9. PORTABLE UMBILICAL PRESSURIZATION SYSTEM (PUPS)................................................ 214

7.5.10. SRBGLV/SCGBLV/SESDV CONTROL PANEL ........................................................................ 215

7.5.11. SUBSEA MULTIPLEX PUMP CONTROL SYSTEM (SMPCS) ................................................. 216

7.6. OFFLOADING MONITORING TELEMETRY SYSTEM (OMTS) ........................................................ 218

7.7. METERING ......................................................................................................................................... 218

7.7.1 METERING ADDITIONAL REQUIREMENTS .............................................................................. 228

7.7.2 MULTIPHASE METERING ........................................................................................................... 236

7.8. NOT APPLICABLE .............................................................................................................................. 240

7.9. DPRS – DYNAMIC POSITIONING REFERENCE SYSTEMS ........................................................... 240

7.10. ENV – METOCEAN DATA GATHERING AND TRANSMISSION SYSTEM .................................... 240

7.11. RISER MONITORING SYSTEM ....................................................................................................... 240

7.11.1. POSITIONING SYSTEM FOR MOORING OPERATION AND OFFSET DIAGRAM ................ 240

7.11.2. MODA RISER MONITORING SYSTEM .................................................................................... 241

7.11.3. ANNULUS PRESSURE MONITORING AND RELIEF SYSTEM .............................................. 242

7.11.4. RRMS ........................................................................................................................................ 242

7.13. OPTIMIZATION AND ADVANCED CONTROL ................................................................................ 242

7.14. MACHINERY MONITORING SYSTEM (MMS) ................................................................................ 243

7.15 NOT APPLICABLE ............................................................................................................................. 244

7.16. GENERAL REQUIREMENTS FOR FIELD INSTRUMENTATION ................................................... 244

7.16.1. MOUNTING AND INSTALLATION REQUIREMENTS .............................................................. 246

7.17. REMOTE OPERATION ..................................................................................................................... 248

7.17.1. REMOTE SUPERVISION AND OPERATION ........................................................................... 249

7.17.2. NETWORK ................................................................................................................................ 249

7.18. SMBS CONTROL AND MONITORING SYSTEM ............................................................................ 249

8. ELECTRICAL SYSTEM ........................................................................................................................... 251

8.1 GENERATION POWER MANAGEMENT SYSTEM (PMS) ................................................................. 251

8.1.1 PMS GENERAL REQUIREMENTS .............................................................................................. 251

8.1.2 SPECIFIC REQUIREMENTS ....................................................................................................... 253

8.1.3 ACCEPTANCE TESTS ................................................................................................................. 254

8.1.3.1 GENERAL REQUIREMENTS.................................................................................................... 254

8.1.3.2 FIELD TESTS TO BE PERFORMED ...................................................................................... 255

8.2. GENERATORS ................................................................................................................................... 256

8.2.1. MAIN GENERATORS .................................................................................................................. 256

8.2.2. MAIN TURBOGENERATORS GENERAL REQUIREMENTS .................................................... 257


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8.2.3 GENERATORS ELECTRICAL REQUIREMENTS ....................................................................... 260

8.2.4 ESSENTIAL/AUXILIARY GENERATORS .................................................................................... 260

8.2.5. EMERGENCY GENERATOR ...................................................................................................... 261

8.3. ELECTRICAL DISTRIBUTION SYSTEM ............................................................................................ 263

8.3.1. POWER DISTRIBUTION ............................................................................................................. 263

8.3.2. GROUNDING .............................................................................................................................. 264

8.3.3. ELETRICAL EQUIPMENT RATED VOLTAGE ........................................................................... 265

8.3.4. SHORT CIRCUIT LIMITS ............................................................................................................ 267

8.3.5 LOW VOLTAGE SYSTEM ............................................................................................................ 269

8.3.6. VDC SYSTEM ............................................................................................................................. 269

8.4. ELECTRICAL EQUIPMENTS ............................................................................................................. 269

8.4.1 POWER TRANSFORMERS ......................................................................................................... 270

8.4.2 SWITCHGEAR, MOTOR CONTROL CENTER AND PANELS ................................................... 270

8.4.3 ELECTRICAL MOTORS ............................................................................................................... 273

8.4.4 UNINTERRUPTIBLE POWER SUPPLY (UPS) AC AND DC ...................................................... 273

8.4.4.1. UPS FOR AUTOMATION/INSTRUMENTATION SYSTEM ..................................................... 274

8.4.5. EMERGENCY LIGHTING SYSTEM ............................................................................................ 275

8.4.6. BATTERIES ................................................................................................................................. 275

8.4.7. GENERAL REQUIREMENTS FOR EQUIPMENT AND MATERIALS ........................................ 275

8.5. LIGHTING ........................................................................................................................................... 276

9. EQUIPMENT ............................................................................................................................................ 278

9.1. NOISE AND VIBRATION .................................................................................................................... 278

9.1.1. NOISE .......................................................................................................................................... 278

9.1.2. VIBRATION ................................................................................................................................. 279

9.2. HOISTING AND HANDLING SYSTEMS ............................................................................................ 279

9.2.1. CRANES ...................................................................................................................................... 281

9.3. HEAT EXCHANGERS ........................................................................................................................ 283

9.3.1 SHELL AND TUBE HEAT EXCHANGERS .................................................................................. 284

9.3.2 PRINTED CIRCUIT HEAT EXCHANGERS ................................................................................. 284

9.3.3 GASKET PLATE HEAT EXCHANGERS ...................................................................................... 285

9.3.4. HEAT EXCHANGER - INSTRUMENTATION ............................................................................. 286

9.4 PROCESS PUMPS .............................................................................................................................. 286

9.4.1 WATER INJECTION PUMPS ....................................................................................................... 287

9.4.2 WELL SERVICE PUMPS ............................................................................................................. 287

9.4.3 PRODUCED WATER PUMPS ..................................................................................................... 287

9.5 METERING PUMPS ............................................................................................................................ 288

9.6 UTILITIES PUMPS ............................................................................................................................... 288

9.7 HEAVY HYDROCARBON RICH STREAM PUMPS ............................................................................ 288

9.8 ROTARY PUMPS ................................................................................................................................ 288

9.9 FIRE WATER PUMPS ......................................................................................................................... 288

9.10 PRESSURE VESSELS ...................................................................................................................... 288

9.11 DIESEL ENGINES ............................................................................................................................. 289

9.12 SEA WATER LIFT PUMPS ................................................................................................................ 289


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10. TELECOMMUNICATIONS .................................................................................................................... 290

11. STRUCTURE AND NAVAL DESIGN .................................................................................................... 290

11.1. LOAD REQUIREMENTS .................................................................................................................. 290

11.1.2. LOAD PLAN ............................................................................................................................... 293

11.2. CONVERSION SURVEY (IF APPLICABLE) .................................................................................... 293

11.2.1 PLATE REPLACEMENT CRITERIA .......................................................................................... 294

11.3. MATERIALS ...................................................................................................................................... 298

11.4. WEIGHT CONTROL PROCEDURES ............................................................................................... 298

11.5. STABILITY ANALYSIS ...................................................................................................................... 298

11.6. HULL ................................................................................................................................................. 299

11.6.1. TURRET AND CARGO TANK INTERFACE (NOT APPLICABLE) ........................................... 300

11.6.2. RISER BALCONY AND HULL INTERFACE (SPREAD MOORING OPTION) ........................ 300

11.6.3 TOPSIDE STRUCTURES .......................................................................................................... 301

11.6.4. CATHODIC PROTECTION AND PAINTING ............................................................................. 302

11.6.5. CARGO AND BALLAST TANKS STRUCTURAL INSPECTION............................................... 303

11.6.6. HULL EXTERNAL INSPECTION .............................................................................................. 303

11.7. FATIGUE ASSESSMENT REQUIREMENTS ................................................................................... 303

11.8. MOTION ANALYSIS ......................................................................................................................... 306

11.8.1. GENERAL .................................................................................................................................. 306

11.8.2. RAO – RESPONSE AMPLITUDE OPERATOR ........................................................................ 307

11.8.3. MODEL TESTS ......................................................................................................................... 308

11.8.4. VERTICAL LIMITATION FOR RISERS ..................................................................................... 309

11.9. PASSIVE FIRE PROTECTION ......................................................................................................... 309

12. OPERATIONAL CONDITIONS .............................................................................................................. 310

12.1. MAXIMUM DESIGN CONDITION ..................................................................................................... 310

12.2. MAXIMUM OFFLOADING DESIGN CONDITION ............................................................................ 311

12.3. BEAM SEA CONDITION (NOT APPLICABLE) ................................................................................ 312

12.4. MAXIMUM PULL-IN / PULL-OUT ENVIRONMENTAL CONDITION ................................................ 312

12.5. MOTIONS AND ACCELERATIONS DESIGN CONDITIONS ........................................................... 312

12.5.1. NORMAL OPERATION AND EXTREME CONDITIONS .......................................................... 312

12.5.2. OPERATIONAL CONDITION FOR UTILITIES ......................................................................... 313

12.5.3. FOUNDATIONS AND FASTENINGS STRUCTURAL REQUIREMENTS ................................ 313

14.1. RISERS CHARACTERISTICS .......................................................................................................... 315

14.2. RISERS INSTALLATION AND DE-INSTALLATION PROCEDURES .............................................. 316

14.3. RISER HANGOFF AND PULL-IN SYSTEMS ................................................................................... 316

16.1. MAIN CONCEPTS ............................................................................................................................ 317

16.1.1. RULES, REGULATIONS AND REQUIREMENT ...................................................................... 317

16.1.2. CARGO PUMP ROOM .............................................................................................................. 317

16.2. GENERAL REQUIREMENTS APPLICABLE TO HULL SYSTEMS ................................................. 317

16.2.1. DOUBLER PLATES ................................................................................................................... 317

16.2.2. TANK OPENINGS IN CARGO AREA ....................................................................................... 318

16.2.3. HULL SYSTEMS BUTTERFLY VALVES .................................................................................. 319


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16.2.4. BOTTOM PLUGS ...................................................................................................................... 319

16.2.5. REINFORCED PIPING PENETRATION PIECES ..................................................................... 319

16.2.6. HULL PIPING SUPPORTS........................................................................................................ 321

16.2.7. SPECTACLE FLANGES............................................................................................................ 321

16.2.8. DROPLINES .............................................................................................................................. 321

16.2.9. OVERBOARD DISCHARGES ................................................................................................... 322

16.2.10. MARINE PIPE RACK ............................................................................................................... 322

16.2.11. SEA CHESTS .......................................................................................................................... 322

16.2.12. STRUCTURAL TANKS MAINTENANCE ................................................................................ 322

16.2.13. P&IDS ...................................................................................................................................... 322

16.3. HULL HYDRAULIC SYSTEM FOR VALVES ACTUATION .............................................................. 323

16.4. LOADING SYSTEM .......................................................................................................................... 323

16.5. CARGO SYSTEM ............................................................................................................................. 324

16.5.1. SUBMERGED PUMPS OF CARGO AREA ............................................................................... 324

16.6. TANKS CLEANING AND TRANSFERENCE SYSTEM .................................................................... 326

16.7. BALLAST SYSTEMS ........................................................................................................................ 328

16.8. FLOODING MONITORING SYSTEM ............................................................................................... 328

16.9. SLOP TANKS DRAINAGE SYSTEM ................................................................................................ 328

16.10. INERT GAS SYSTEM ..................................................................................................................... 329

16.11. CLOSED VENTING SYSTEM......................................................................................................... 329

16.12. PRESSURE, TEMPERATURE, ULLAGE AND INTERFACE MONITORING SYSTEM ................ 330

16.13. GAS SAMPLING SYSTEM ............................................................................................................. 331

16.14. HULL CENTRAL COOLING SYSTEM ............................................................................................ 331

16.15. ENGINE ROOM BILGE SYSTEM ................................................................................................... 331

16.16. SEWAGE SYSTEM ......................................................................................................................... 331

16.17. ANTIFOULING SYSTEM ................................................................................................................ 332

16.18. HULL DRAINAGE SYSTEM ........................................................................................................... 332

16.18.1. MAIN DECK DRAINAGE SYSTEM ......................................................................................... 332

16.18.2. UPPER RISER BALCONY DRAINAGE SYSTEM .................................................................. 332

16.19. DIESEL SYSTEM ............................................................................................................................ 333

16.20. PRODUCED WATER SETTLING SYSTEM ................................................................................... 333

16.21. SLOP OIL RECOVERY SYSTEM ................................................................................................... 333

16.22. OFFLOADING SYSTEM ................................................................................................................. 334

17. ENVIRONMENT IMPACT STUDIES ..................................................................................................... 335

17.1. GENERAL ......................................................................................................................................... 335

17.2. GENERAL DESCRIPTION ............................................................................................................... 335

17.3. EFFLUENTS ..................................................................................................................................... 336

17.4. ATMOSPHERIC EMISSIONS ........................................................................................................... 337

17.5. WASTE MANAGEMENT ................................................................................................................... 338

18. PETROBRAS LOGOTYPE .................................................................................................................... 338


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1 GENERAL

1.1. INTRODUCTION

The intent of this specification and documents referenced hereinafter is to provide the

CONTRACTOR with general information of intended service and requirements for the

design, construction (conversion)), assembly, transport, installation and operation of one

Floating Production Storage and Offloading System (FPSO), also called “the Unit” in this

document. The complete outfitted and equipped Unit shall be installed offshore Brazil.

The Unit operation and design life shall be at least 25 years. During the operational life

period, the Unit shall be adequate for uninterrupted operation, without the need of dry-

docking. Fatigue life and hull substantial corrosion criteria used during the design shall

comply with the CS (Classification Society) requirements and Structure and Naval Design

requirements (Chapter 11), in order to allow continuous offshore operation during its

operational lifetime, with no dry-docking in a shipyard. In addition, the Unit shall be fitted with

facilities that enable any inspection and maintenance required during the operational lifetime

without affecting the production/processing capacity of the Unit.

The Unit’s accommodation capacity shall be compatible with 240 People On Board (POB).

The POB required is to meet PETROBRAS’s operation, maintenance and asset integrity

management plans.

All requirements herein provided must be considered as a minimum, according to the terms

agreed upon in the Contract.

All CS, Brazilian Regulatory Authorities and Flag Administration requirements for the Unit

shall be complied with. in case of discrepancies between these requirements that are

included in CONTRACTOR’s scope of work and PETROBRAS’ Technical Requirements,

CONTRACTOR shall inform PETROBRAS immediatally for further decision..

The Unit shall enable surface diving, supervised, operated and supplied from the Unit,

according to requirements issued by Brazilian Regulatory Authorities and NR (“Normas

Regulamentadoras”) issued by the Brazilian Ministry of Economics (“Ministério da

Economia”).

This document shall be read together with all technical documents. In case of conflicting

information between this GENERAL TECHNICAL DESCRIPTION and other technical

document, this specification shall prevail. In case of conflicts between GTD and SAFETY


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GUIDELINES FOR OFFSHORE PRODUCTION UNITS - BOT/BOOT, PETROBRAS shall

be consulted.

This GENERAL TECHNICAL DESCRIPTION provides necessary information for the

development of the Design. However, they do not exempt CONTRACTOR from contractual

responsibilities. CONTRACTOR shall be responsible for the provision of all services and

other requirements necessary to deliver one complete functional Production Unit as

described herein. Any calculation presented in this document is preliminary and shall be

reviewed during the Detail Design Phase.

In all documents, the word “shall” and equivalent expressions like “is to”, “is required to”, “has

to”, “must” and “it is necessary” are used to state that a provision is mandatory.

In all documents, the verb “consider” and “foresee” and all their forms (considered,

considering, etc.) are used as “taking into account” and state that a provision must be

complied with.

Unless otherwise expressed, any reference to “CONTRACTOR responsibility” or

“CONTRACTOR’s responsibilities” means that the CONTRACTOR will design, supply,

install, operate and maintain according to the Contract provisions with no commercial

interference or responsibility from PETROBRAS.

PETROBRAS, at its sole discretion, may accept or not any solution that is different from

those herein specified.

The design of the Unit shall be based on field proven solutions and PETROBRAS, at their

sole discretion, have the right to reject any detail of the Unit’s design.

CONTRACTOR shall address the need of stand-by equipment, ready to operate, for systems

which require full capacity on continuous operation, in order to guarantee no process

capacity reduction or degradation of the oil, gas and water specification. CONTRACTOR

shall also comply with stand-by philosophy for equipment whenever specifically required in

this General Technical Description.

CONTRACTOR shall develop all necessary Engineering Design work (design details,

workshop drawings, specifications, etc.) in order to deliver the complete Unit, which in all

aspects, shall be ready for the intended service on arrival in Brazil according to the Contract

provisions.


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The Unit, as delivered, shall be completed with all its parts and appurtenances proven to be

thoroughly workable as specified. The Unit shall be seaworthy and able to perform its

designed functions as specified.

CONTRACTOR is responsible for any infringement of patents related to its scope of work in

Brazil and in any other countries where work will be carried out.

CONTRACTOR shall promptly inform PETROBRAS about any amendments of rules and

regulations and consequences thereof during the Contract term.

1.2. GENERAL DESCRIPTION

1.2.1. REFERENCE DOCUMENTS

Throughout this document, the following Technical Specifications and drawings are

referenced:

Table 1.2.1.1 - Referenced Documents Lists

# Document Number Rev. Title

1 I-ET-1400.00-1000-941-PPC-001 B Metocean data for design of offshore systems

- deep water XXXXX fields

2 I-ET-3274.00-1350-940-P76-001 A Spread Mooring & Riser Systems

Requirements

3 I-ET-3010.00-5400-947-P4X-011 A SAFETY GUIDELINES FOR OFFSHORE

PRODUCTION UNITS - BOT/BOOT

4 I-ET-3010.00-1359-960-PY5-001 O Offshore Loading System Requirements

5 I-ET-3010.0V-5521-931-PEA-001 B

REQUIREMENTS OF METOCEAN DATA

ACQUISITION SYSTEM FOR THE XXXXX –

MÓDULO I

6 I-ET-0600.00-5510-760-PPT-565 B Telecommunications System

7 I-ET-3274.00-5139-800-PEK-001 0

HYDRAULIC POWER UNIT FOR SUBSEA

EQUIPMENT WITH MULTIPLEXED

ELECTROHYDRAULIC AND DIRECT

HYDRAULIC CONTROL SYSTEM

8 I-ET-3010.00-1300-279-PPC-301 0 DIVERLESS BELL MOUTH SUPPLY

SPECIFICATION


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9 I-ET-3010_00-1300-279-PPC-203 0 BELL MOUTH SUPPLY SPECIFICATION

10 I-ET-3010.00-5529-812-PAZ-001 F ANNULUS PRESSURE MONITORING AND

RELIEF SYSTEM

11 I-ET-3000.00-5529-850-PEK-001 0 RIGID RISER MONITORING SYSTEM (RRMS) – FPU SCOPE

12 I-ET-3010.00-1500-274-PLR-001 C RISER TOP INTERFACE LOADS ANALYSIS

13 I-ET-3010.00-5529-854-PEK-001 0 MODA RISER MONITORING SYSTEM – FPU SCOPE (SPREAD MOORING)

14 I-ET-3010.1U-5530-850-PEA-001 B POSITIONING AND NAVIGATION SYSTEMS

FOR THE XXXXX – MÓDULO I

15 I-DE-3274.00-1500-941-P56-001 B Riser suports arrangement – FPSO balcony

(Note 1)

16 I-ET-3010.1U-1350-190-P4X-001 C ACCOMODATIONS AND COMPARTMENTS

17 I-ET-3010.00-1200-956-P4X-004 B COATING PHILOSOPHY

18 I-ET-3010.00-1200-220-P4X-001 A VALVE SELECTION PHILOSOPHY

19 I-ET-3010.00-1200-940-P4X-003 C MATERIAL SELECTION PHILOSOPHY

20 I-ET-3000.00-8222-941-PJN-001 E Laboratory - Equipment

21 I-ET-3010.00-1200-901-P4X-001 B Reliability Availability And Maintenability

(Ram) AnalysisRequirements

22 I-ET-3010.00-1200-000-P61-001 A Operational Modes

Note 1: Will be confirmed at Project kick-off meeting.


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1.2.2. GENERAL DESCRIPTION

The Unit shall be a ship-shaped or barge-shaped vessel provided with a topside crude oil

process plant, gas process plant, produced water and injection water plant. The Unit shall

be capable to be moored offshore Brazil, at a location with water depth up to 2,600 meters

considering the Metocean Data (see Section 1.2.1).

As a brief overview, the Unit will receive the production from subsea oil wells and subsea

non associated gas wells and shall have production plant facilities to process fluids, stabilize

them and separate produced water and natural gas. Processed oil will be metered, stored in

the vessel cargo storage tanks and offloaded to shuttle tankers.

Produced gas shall be compressed, dehydrated, treated and used as a fuel gas for the FPSO

and lift gas for the subsea production wells. Surplus gas will be exported through a gas

pipeline to PETROBRAS gas pipeline system or reinjected in the reservoir. The heavy

hydrocarbon rich stream (C3+) effluent from the gas treatment shall be pumped, in order to

allow its disposal in the reservoir.

Produced water will be reinjected into reservoir or disposed overboard according to

CONAMA requirements.

CONTRACTOR shall consider the SUBSEA LAYOUT (see Section 1.2.1) documents for a

Spread Moored FPSO.

The Unit shall have the minimum facilities specified in this document to be connected to a

Subsea Multiphase Boosting System (SMBS). This scenario may occur during the production

life.

The Process Plant shall have the processing capacities as listed in Table 1.2.2.1.

Table 1.2.2.1 Process plant capacities.

Parameter Capacity

Total Maximum Liquids 22,300 Sm3/d

Total Maximum Oil 19,100 Sm3/d

Total Produced Water 15,900 Sm3/d


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Total Water Injection (De-

Sulphated Sea Water and/or

Produced Water)

31,800 Sm3/d

Gas Handling, including lift gas,

treatment and compression

10,000,000 Sm3/d

(Note 1)

Note 1: Gas flow rate at outlet of first stage separation (Free Water KO Drum and Inlet Gas

Separator). The gas coming from internal recycles shall be added to define the total

main gas compression/treatment capacity.

The riser balcony of the Unit shall be designed on the Starboard, with guide tubes or

receptacles and a support for the upper balcony installed on the Hull upper side.

PETROBRAS highlights this is a preliminary plan. It can be changed up to Kick-off Meeting.

CONTRACTOR shall consider that risers can come from portside and/or starboard side of

Unit.

The riser balcony of the Unit shall be designed in order to connect the flexible or rigid risers

listed in Table 1.2.2.2.

Table 1.2.2.2. Risers Details

FPSO Risers Function Total Comments

Oil Production Trunkline with boosting 6”ID to 8”ID Oil Production 1

The production riser can be flexible (6”ID or 8”ID) or SLWR (6”ID or 8”ID).

Unit shall be prepared that both alternatives.

(OP01 to OP02)

6"ID Gas Lift / Service 1

Gas lift riser can be flexible ( 6" ID) or SLWR ( 6" ID).

Unit shall be prepared to both alternatives.

UEH (note 8) Control 1

Umbilical can be either TPU (termo plastic umbilicals or STU (steel tube umbilicals).


UIP Power and Chemicals 1



Satellite Oil Production 6”ID to 8”ID Oil Production 1

The oil production riser will be flexible (6”ID or 8”ID).


(OP03 ) 4”ID to 6"ID Gas Lift / Service 1 Gas lift riser will be flexible (4” or 6" ID).



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Satellite Oil Production 6”ID to 8”ID Oil Production 5

The oil production risers can be flexible (6”ID or 8”ID) or SLWR (6”ID or 8”ID).


(OP04 to OP08)

4”ID to 6"ID Gas Lift / Service 5

Gas lift risers can be flexible (4” or 6" ID) or SLWR (4" or 6" ID).



Umbilicals can be either TPU (termo plastic umbilicals or STU (steel tube umbilicals).


Gas Production Trunkline

6”ID to 8"ID Gas Production 1

The gas production riser can be flexible (6”ID or 8”ID) or SLWR (6"ID or 8"ID).


(GP01 to GP02)

4”ID to 6"ID Gas Lift / Service 1

Gas lift riser can be flexible (4”ID or 6"ID) or SLWR (4" ID or 6" ID).


UEH ( note 8) Control 1



Satellite Gas Production 6”ID to 8"ID Gas Production 2

The gas production risers will be flexible (6”ID or 8”ID).


(GP03 to GP04)

4”ID Gas Lift / Service 2 Gas lift risers will be flexible (4”ID).

UEH ( note 8) Control 1



Gas Production Manifold (up to 4 wells)

6”ID to 8"ID Gas Production 2

The gas production risers will be flexible (6”ID or 8”ID) or SLWR (6"ID or 8"ID).


(GP05 to GP08)

4”ID Gas Lift / Service 1

Gas lift riser can be flexible (4”ID) or SLWR (4" ID).





Water Alternating Gas (WAG) Injection Wells

6”ID Water Alternating Gas

(WAG) Injection 6

The WAG injection risers can be flexible (6”ID) or SLWR (6”ID).

(IWAG01 to IWAG06) Unit shall be prepared that both alternatives.

Trunkline Water Injection Wells

6”ID to 8”ID Water Injection 1

The water injection riser can be flexible (6”ID or 8"ID) or SLWR (6”ID or 8"ID).

(IW01 to IW02)



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Satellite Water Injection Wells

(IW03 to IW05)

6”ID to 8”ID Water Injection 3

The water injection risers can be flexible (6”ID or 8"ID) or SLWR (6”ID or 8"ID).


UEH (note 8) Control 1 Umbilicals can be either TPU (termo plastic umbilicals or STU (steel tube umbilicals).

Gas Export

9,13’’ ID to 11,13" ND (flexible riser option)

12’’ ID to 14" ND (SLWR option)

Gas Export 1



UEH SESDV control 1



TOTAL SLOTS 46

Note 1: the sequence, functions and diameters of each riser slot will be defined at the project

kick-off meeting together with the subsea layout.

Note 2: Wells in subsea trunkline configuration are connected in pairs, sharing:

2.a) production trunkline (oil or gas): 1 production riser + 1 gas lift / service riser for each

pair of wells;

2.b) water injection trunkline: 1 injection riser for each pair of wells.

Note 3: Wells at positions GP05, GP06, GP07 and GP08 will be connected to subsea gas

production manifold;

Note 4: Each WAG injection slot may inject water, diesel, heavy hydrocarbon rich stream

(C3+) effluent from gas treatment, or gas alternately and independently. Each position

IWAG01 to IWAG06 will be interconnected in pairs of wells. The pairing between these wells

will be defined during kick-off meeting, together with the subsea layout;

Note 5: hard pipe, spools, supports, etc. shall be installed/furnished by CONTRACTOR in

order to install the rigid risers.

Note 6: Detailed figure of wells interconnections is presented on figures 2.6.1.2 and 2.6.1.3.

Note 7: To avoid cross contamination between the injection water and the injection gas in

WAG wells, CONTRACTOR shall afford means to have temporarily positive isolation, to be

provided on both Gas Injection and water injection lines. Alternatively, CONTRACTOR shall


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afford 2 (two) Double block and bleed isolation valves with drain and pressure alarm in

between, to be provided on both Gas Injection and water injection lines.

Note 8: Where indicated, umbilicals are considered apart, so it can be shared using subsea

distribution units (SDUs), subsea gas production manifold or umbilical termination

assemblies (UTAs), grouping up to 5 wells each. Each SDU will attend a cluster

of production (OP and GP positions) and injection wells (IWAG and IW positions).

Distribution of wells versus SDUs (and its respective control umbilicals) or similar subsea

equipment will be defined at the project kick-off meeting together with the subsea layout. For

more details, see Chapter 7.5.

a) Flexible risers:

• Positions OP01/OP02 (oil production trunkline pair of wells) - one flexible oil production

riser (8” or 6” ID) + one control umbilical + one flexible service riser (6” ID) + one integrated

HV power, control and chemical umbilical (UEH-P) for subsea boosting required for this

trunkline pair: 4 bellmouths are required;

• Position OP03 – one flexible production riser (8”ID or 6”ID) + one flexible gas lift / service

riser (6”ID or 4”ID) + control umbilical (well control) – 3 bellmouths are required;

• Positions GP05, GP06, GP07 and GP08 (wells connected to subsea manifold) – two gas

flexible production risers (8”ID or 6”ID) + one flexible gas lift / service riser (4”ID) + one

umbilical for manifold/wells control + one umbilical for riser’s ESDVs required for the manifold

= 5 bellmouths are required;

• Positions OP04, OP05, OP06, OP07, OP08, GP03, GP04 – one flexible production riser

(8”ID or 6”ID) + one gas lift / service riser (6”ID or 4”ID) required for each position + 5 control

umbilicals = 2 x 7 + 5 = 19 bellmouths are required;

• Positions GP01/GP02 (gas production trunkline pair of wells) – one flexible gas production

riser (8”ID or 6”ID) + one flexible gas lift / service riser (4”ID) + one control umbilical required

for this trunkline pair and for the pair’s ESDV: 3x1= 3 bellmouths are required;

• Positions IWAG01, IWAG02, IWAG03, IWAG04, IWAG05 and IWAG06 - one flexible water

injection riser or one flexible C3+/gas injection riser (Slot A) (see note 4) (6” ID) + one flexible

water injection riser or one flexible C3+/gas injection riser (Slot B) (see note 4) (6” ID) for

each pair of positions: 2 x 3 = 6 bellmouths are required;


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• Positions IW01/IW02 (water injection trunkline pair of wells) – one flexible water injection

riser (8”ID or 6”ID) required for this trunkline pair of wells- 1x1 = 1 bellmouth are required;

• Positions IW03, IW04 and IW05 - one flexible water injection riser (8”ID or 6”ID) required

for each well – 1x3= 3 bellmouths are required;

• gas export – one flexible gas export riser (9,13” to 11,13” ID) + one control umbilical for

ESDV: 2x1= 2 bellmouths are required.

b) Rigid risers:

• Positions OP01/OP02 (oil production trunkline pair of wells) – one oil production SLWR (8”

or 6” ID) one service SLWR (6” ID) required for this trunkline pair: 2 receptacles are required

• Positions GP05, GP06, GP07 and GP08 (wells connected to subsea manifold) – two gas

production SLWR (8”ID or 6”ID) + one gas lift / service SLWR (4”ID) required for the manifold

= 3 receptacles are required;

• Positions OP04, OP05, OP06, OP07, OP08 – one production SLWR (8”ID or 6”ID) + one

gas lift / service SLWR (6”ID or 4”ID) required for each position = 2 x 5 = 10 receptacles are

required;

• Positions GP01/GP02 (gas production trunkline pair of wells) – one gas production SLWR

(8”ID or 6”ID) + one gas lift / service SLWR (4”ID) required for this trunkline pair: 2x1= 2

receptacles are required;

• Positions IWAG01, IWAG02, IWAG03, IWAG04, IWAG05 and IWAG06 - one water

injection SLWR or one C3+/gas injection SLWR (Slot A) (see note 4) (6” ID) + one water

injection SLWR or one C3+/gas injection SLWR (Slot B) (see note 4) (6” ID) for each pair of

positions: 2 x 3 = 6 receptacles are required;

• Positions IW01/IW02 (water injection trunkline pair of wells) – one water injection SLWR

(8”ID or 6”ID) required for this trunkline pair of wells- 1x1 = 1 receptacle are required;

• Position IW04 - one water injection SLWR (8”ID or 6”ID) – 1x1= 1 receptacle is required;

• gas export – one gas export SLWR (9,13”ID) = 1 receptacle is required.;

In summary, the Unit shall have the following main characteristics:


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• Ship-shaped or barge-shaped unit of VLCC size or greater, with a minimum storage

capacity of 1.400.000 bbl of crude oil. For this purpose, storage capacity is defined as

the minimum volume of oil available, in the cargo tanks, to be offloaded. The amount

of oil considered as permanent ballast, if necessary, shall be added to this value. To

calculate the “volume of oil available to be offloaded”, CONTRACTOR shall proceed

as follows:

1) One condition approved by the Classification Society of maximum loading of oil

shall be included in the "Trim and Stability booklet";

2) One condition of minimum loading safe operational condition approved by the

Classification Society shall be included in the "Trim and Stability booklet";

3) The "volume of oil available to be offloaded" is to be calculated as follows:

(Volume of oil available to be offloaded) = (Oil capacity in the maximum loading

condition) – (Oil Capacity in the minimum loading safe operational condition);

4) The volume of oil available to be offloaded shall be equal or greater than 1,400,000

bbl;

• Offloading system, including hawser and export hose, as specified in the document

OFFSHORE LOADING SYSTEM REQUIREMENTS (see 1.2.1);

• Process plant, comprising deck structure, safety facilities, steel flare tower or flare

boom, equipment for oil processing, associated gas treatment, gas compression, gas

exportation and/or reinjection, heavy hydrocarbon rich stream (C3+) injection, water

treatment and injection, etc.;

• Utilities necessary to keep the Unit’s standalone operation capacity, according to

operational lifetime;

• Power generation system to meet all the needs of the Unit, based on dual fuel gas

turbine-generators; During the design phase, CONTRACTOR shall submit to

PETROBRAS, the planned gas consumption, which shall consider the optimization of

energy use onboard.

• Gas compression plant comprising high-pressure centrifugal compressors driven by

electric motor or gas turbine;


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• Accommodation in accordance with Brazilian regulatory authorities;

• Spread Mooring System;

• Facilities to connect risers for oil production, gas-lift, water injection, gas export, gas

reinjection, heavy hydrocarbon rich stream (C3+) injection,control umbilical and

SMBS connection;

• Cargo handling systems, including cranes, monorails, rail cars, etc.;

• Helideck, suitable for Sikorsky S-61, S-92, Agusta AW-139, and Eurocopter EC 225

helicopter landing;

• Telecommunication facilities;

• The Unit and its equipment shall be designed to withstand operational, test, lifting and

assembly conditions as well as the environmental conditions stated in METOCEAN

DATA document (see 1.2.1). It shall also withstand the environmental conditions

along the towing or sailing route, from the construction or conversion yard to the final

offshore site in Brazil. If the CONTRACTOR decides to use a wave spreading

formulation for XXXXX Basin , it should use spreading parameters prescribed in

METOCEAN DATA document (see 1.2.1). The decision to use or not use a wave

spreading formulation is CONTRACTOR's responsibility.

All systems and its components (equipment, piping, cable, panels, valves, etc.) for the

FPSO operation (hull systems and topsides systems) shall be new. This requirement shall

be also fullfilled if Contractor converts an existing oil tanker to a FPSO.

All equipment/systems/components (main engine, boilers, rudder, instrumentation and

electrical items, piping, HVAC, etc.) from existing oil tanker shall be scrapped and

removed from vessel during hull conversion. No oil tanker existing

equipment/systems/components will be accepted to be kept on board the new UNIT, being

it repaired, overhauled, refurbished, restored as new, reused, reconditioned,

decommissioned or laid up.

The FPSO shall not have any cargo pump room. In case of conversion, the pump room

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cargo tanks, slop tanks, produced water tanks and any other tank in the cargo area

designed to store oil or oil-water mixtures.

Note: The fluid transfer system dedicated to cargo, slop, produced water and settling tanks

(if applicable) shall be based on submerged type pumps.

1.3. CLASSIFICATION

CONTRACTOR shall contract a single CS to follow and approve the whole project during

contractual term . The CS shall also consider all construction loads and the environmental

loads during transportation from construction/conversion shipyard to Brazil.The CS shall

consider those conditions for the final approval of the Unit design. CONTRACTOR shall also

contract the same CS for the classification and statutory survey of the Unit. The CS’s

Contract shall clearly specify that the Unit shall comply with all requirements for continuous

operation during its operational lifetime, as stated in Section 1.1, at the site without the need

to be dry-docked.

Acceptable CSs are DNV (Det Norske Veritas), BV (Bureau Veritas), ABS (American Bureau

of Shipping) and LRS (Lloyd’s Register of Shipping).

The scope of the work shall be carried out in accordance with the requirements of this

document, CS Rules and Brazilian Regulatory Authorities and Flag Administration

requirements. All relevant aspects in design and construction phases, shall consider the

stated operational lifetime.

As stated above, the contract between CONTRACTOR and CS shall comprise the design,

construction, installation on site, commissioning and start-up phases. This CS shall be the

same during all project phases.

The Unit shall obtain Class notation for the following items:

• Vessel structure, equipment and marine systems;

• Permanent mooring system;

• Production facilities and utilities;

• Fuel gas system;

• Oil storage;


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• Offloading;

• Inert gas system;

• Automation and control systems;

• Centralized Control Room Operation;

• Lifting Appliances.

• Under water survey in lieu of dry-docking

Note: Riser system Classification is not part of CONTRACTOR’s scope of work.

CONTRACTOR’s scope shall cover down to the last flanged connection in all risers.

CONTRACTOR shall be assisted by the CS to ensure that the engineering practice,

construction work and operation of the Unit comply with the rules and regulations.

In the CS contract, CONTRACTOR shall clearly establish the following items as minimum

requirements:

• Permission for the CS to inform PETROBRAS or notify directly, under PETROBRAS’

formal request, the Classification status regarding pending and/or outstanding items

and any other relevant information about the Unit;

• CONTRACTOR shall promptly inform PETROBRAS about all changes in the rules

and regulations that will affect this project;

• CONTRACTOR shall promptly inform PETROBRAS of any CS rule or regulation that

have not been fulfilled by CONTRACTOR, even though the CS has exceptionally

waived it;

1.4. CERTIFICATES, TERMS AND STATEMENTS

CONTRACTOR shall submit to PETROBRAS, whenever required, an electronic copy of any

FPSO terms and certificates issued by Classification Society and Authorities (including, but

not limited to Flag Authority and Brazilian Authorities). The original versions shall be available

to Petrobras, whenever required, during the execution and operational phase.

1.5. NOT APPLICABLE


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1.6. RULES, REGULATIONS, STANDARDS AND CONVENTIONS REQUIREMENTS

The Unit shall be designed, built and operated in accordance to international rules approved

by the International Maritime Organization (IMO). All such CODES and CONVENTIONS are

turned into law in Brazil and in the intended flag country.

RULES shall be complied with where applicable and shall include any amendment and/or

revision in force on the date of Contract signature.

The Unit shall be designed to be registered under a convenient flag and it is

CONTRACTOR’s obligation to comply with the rules and regulations stated by Flag and

Brazilian Authorities (see also 1.8 - INSPECTION, TEST AND TRIALS) for further

information see Exhibit I – Scope of Work

The following philosophy shall be used for FPSO design:

• CONTRACTOR shall comply with Classification Society requirements in order to obtain

and keep the FPSO Class Notation as specified in Section 1.3.

• CONTRACTOR shall comply with any codes and/or regulations prescribed within the

Classification Society Rules.

• CONTRACTOR shall design Process plant according to the following norm: API RP 14C

and API STD 521.

• CONTRACTOR shall comply with specific design requirements whenever specifically

mentioned on this GTD and its annexes.

Piping and valves design, materials fabrication, assembly, erection, inspection and testing

shall comply with ASME B31.3,CS rules and PETROBRAS specifications mentioned in the

contract. Piping system layout, design, structural and fatigue analyses are required. Special

attention shall be taken, but not limited to, well production lines, vents/drains of hydrocarbon

system and other lines subjected to vibration (e.g. compression/pump systems and vibration

deadleg), including small line diameters and instrument connections. Regarding such subject

the compliance to NORSOK L-002 is required.

For line sizing, recommended velocities to prevent problems with erosion shall be based on

recognized standards such as NORSOK, API 14E, etc.


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Mechanical Design Codes: ASTM, ASME Sec VIII Div 1 and 2, ASME B-73.1 B-73.2, API-

610, API- 660, API-662, API- 682, API-674, API-675, API-676, TEMA, ISO 15156, NFPA 20,

API-618, API-619, ISO 8573, API Spec 7B / 11 C, ASME PTC 17, ISO 3046, API Spec 2 C

, API STD 613, API STD 614, API STD 670, API STD 671, ISO 14691.

HVAC design shall comply with the following: NRs – Ministry of Economics , Resolução RE-

09: 2003 da ANVISA, Resolução CONAMA – 267, ISO 15138 – Petroleum and natural gas

industries - Offshore production installations - Heating, ventilation and air-conditioning

Second Edition, IEC 61892-7 - Mobile and fixed offshore units – Electrical installations – Part

7: Hazardous areas, NORSOK S-002 – Working Environment.

All standards applied to the project shall be used on their last edition at proposal submission

date.

CONTRACTOR shall fully comply with all applicable Brazilian regulation during all stages of

the contract, especially but not limited to:

• National Agency of Petroleum, Natural Gas and Biofuels (Agência Nacional do

Petróleo, Gás Natural e Biocombustíveis) (ANP);

• Health Authorities (Agência Nacional de Vigilância Sanitária) (ANVISA);

• Health Ministry (Ministério da Saúde);

• National Council of Environment (Conselho Nacional do Meio Ambiente) (CONAMA);

• Environment Authorities (Instituto Brasileiro do Meio Ambiente e Recursos Naturais

Renováveis) (IBAMA);

• Diretoria de Portos e Costas (DPC) and Brazilian Navy (Marinha Brasileira);

• Brazilian Army (Exército Brasileiro);

• Brazilian Air Force (Força Aérea Brasileira) and Aeronautic regulations;

• Federal Police (PF);

• Telecommunication Authorities (Agência Nacional de Telecomunicações) (ANATEL);

• Brazilian Economic Ministry (“Ministério da Economia”),including all applicable

“Normas Regulamentadoras”.


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During contract period, if at any time, CONTRACTOR is submitted to external audits, or

inspections, PETROBRAS shall receive, whenever requested, a copy of the pending list with

action plans to resolve each item.

1.7. DOCUMENTATION, UNITS AND IDENTIFICATION OF EQUIPMENT

The metric system complying with ISO standard, as far as practicable shall be used for

equipment, machinery and fittings identification and data.

The Standard conditions are defined as:

• Sm3 @ 15.6ºC and 101.3 kPa(a);

• Nm3 @ 20ºC and 101.3 kPa(a), as per ANP metering regulation requirement.

CONTRACTOR shall issue to PETROBRAS the Unit design documentation as well as the

“AS BUILT” documentation.

All Unit identification, signs and documents shall be written according to the Brazilian

Regulatory Authorities and regulations and Flag Authorities requirements.

Operation manual, including operational plant and vessel, maintenance manual and

SOPEP - Ship Oil Pollution Emergency Plan shall be available in Portuguese language.

Safety plan, scape route plan, classification area plan and kit salvage shall also be available

in Portuguese language. All the documents shall be updated considering the latest version

of the design and including risk management follow up as per safety studies. As required

by Brazilian Regulatory Authorities, others documentations related to Regulatory

Compliance requirements shall be provided in Portuguese language. These documentation

shall be kept updated during the contract period of the FPSO.

1.8. INSPECTIONS, TESTS AND TRIALS

CONTRACTOR shall carry out inspections, tests and trials during construction of the Unit in

accordance to the latest inspection standards and CS guidelines, technical specifications

and test procedures, which shall be submitted for CS’s approval.

Special attention shall be given to the testing of pressure vessels, heat exchangers, boilers

(if applicable), and piping. Tests shall be carried out in presence of CS’s representatives,


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which will issue a test certificate to meet the requirements of NR-13 (“Norma

Regulamentadora”) from the Brazilian Economic Ministry (“Ministério da Economia”).

1.9. TRANSPORT AND INSTALLATION

CONTRACTOR shall be responsible for the Unit’s transportation to the specified site

locations, according to the Contract terms and conditions.

CONTRACTOR shall be responsible for engineering and Marine Warranty Survey activities

for transportation in general.

CONTRACTOR shall be responsible to provide towing bridles whenever necessary as well

as cables/wires/chain to assist FPSO positioning using PETROBRAS towing boats.

After the propeller shaft removal, a procedure for sealing the shaft tube shall be designed for

the entire lifetime of the FPSO. This procedure shall be submitted for formal approval by the

Classification Society.PETROBRAS will suport CONTRACTOR with a towing and scout

AHTSs from sheltered water to the final offshore site location. These boats will be mobilized,

as part of PETROBRAS scope/cost, 4 (four) days before departure to offshore location. Pilots

for the PETROBRAS towing and scout boats, whenever required falls under PETROBRAS

scope of supply.

The conditions stated in NORMAM-20/DPC - Ballast Water Management and Control – and

IMO Resolution MEPC. 207(62) - Guidelines for the Control and Management of Ships’

Biofouling to Minimize the Transfer of Invasive Aquatic Species - shall be applied.

If the Unit is transported from a site outside Brazilian Waters, CONTRACTOR shall ensure

the hull to be free of marine growth/biofouling as follows:

(i) Hull and niche areas cleaning shall be performed and properly reported within 30 days

before sailing to Brazilian Waters. Cleaning reports with cleaning method description, and

photos after the cleaning shall be submitted to PETROBRAS appraisal, and shall be attested

and signed by a qualified professional, as biologists or oceanographers, capable to state that

the hull and all niche areas are free of macrofouling. CONTRACTOR shall also deliver to

PETROBRAS videos and photos of all the cleaning process in a separate report.

(ii) Monthly under water hull and niche area cleaning to be performed during the hull stay at

Brazilian yard, or sheltered waters (whenever those areas have proven occurence of target


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species, such as, sun coral - Tubastraea coccinea and Tubastraea tagusensis) in order to

prevent any marine growth/biofouling. Cleaning reports as per item (i) shall be performed.

(iii) Within 30 days before sail away to final location CONTRATOR shall perform hull and

niche inspection in order to verify the occurence of sun coral - Tubastraea coccinea and

Tubastraea tagusensis. If the presence of those species is confirmed than hull and ninche

area cleaning shall be performed. Cleaning reports with cleaning method description, and

photos after the cleaning shall be submitted to PETROBRAS appraisal, and shall be attested

and signed by a qualified professional, as biologists or oceanographers, capable to state that

the hull and all niche areas are free of sun coral. CONTRACTOR shall also deliver to

PETROBRAS videos and photos of all the cleaning process in a separate report.

CONTRACTOR shall execute another Preliminary Hazard Analysis study focusing on the

risks associated to the transportation of the Unit from the shipyard to Brazil.

CONTRACTOR shall provide an emergency anchoring system in accordance to CS`s and

Brazilian Naval Authorities requirements. This system shall be similar to the mooring system

required for a ship of similar size under the CS’s normal “Steel Vessel Rules” and is intended

for use in shallow coastal waters and harbors.

CONTRACTOR shall answer for all onboard mooring and risers’ installation procedures and

shall supply all devices and facilities onboard to perform mooring and riser pull-in and pull-

out connections. CONTRACTOR shall be able to perform these onboard operations 24 hours

a day with skilled crew working simultaneously at two different mooring cluster.

CONTRACTOR shall provide handling devices, which include pull-in winches, mooring

winches/chain-jacks, auxiliary winches, snatch blocks, sheaves, pull-in wires, guide tubes, if

any, and all devices and facilities for mooring and risers’ installation as well as accessories

to be used in those operations (messenger lines, etc). In addition, CONTRACTOR shall

answer for any diver assistance during the mooring and pull-in/out operation as well as during

other diving operations required onboard.

CONTRACTOR is also responsible for the Unit installation at the site, as described in

documents SPREAD MOORING & RISERS SYSTEM REQUIREMENTS (see 1.2.1).

1.10. HEALTH SAFETY AND ENVIRONMENTAL


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During its operational phase, the Unit shall obtain a certificate of compliance with OHSAS

18001, ISO 14000 and ISM Code, issued by a Brazilian Certification Society authorized by

Inmetro, to ensure health, safety and environmental appropriate operations.

1.11. MATERIALS

CONTRACTOR shall submit the reasoning and calculations considered during the design to

specify the materials, for all piping, valves, fittings and equipment, according to each type of

fluid, considering the corrosion allowance as well as the protection considered. These

selections shall be in accordance with Material selection philosophy (I-ET-3010.00-1200-

940-P4X-003). The corrosion protection by means of coating shall observe the requirements

of Coating philosophy (I-ET-3010.00-1200-956-P4X-004). The valve selection shall be in

accordance with the valve selection philosophy (I-ET-3010.00-1200-210-P4X-001).

CONTRACTOR shall also comply with the following minimum materials specification, for the

indicated portions of the topsides process facilities:

1) Materials specification shall be carried out based on the following inlet fluids

characteristics and normal operating conditions:

• Produced gas CO2 content: up to 2% mol on separated gas;

• Produced gas H2S content: up to 11 ppmv on separated gas ;

• Produced gas H2O content: up to saturated;

• Produced liquid BS&W: up to 95%;

• Produced water Chloride (Cl-1): up to 60,000 mg/L;

• Produced water Minimum pH: 5,0 (*).

(*) Acetic acid shall be injected on production and test headers.

2) For the Main Gas Compressors, construction materials shall be selected considering the

following contents on the process gas:

• CO2: To be determined by simulation;


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• H2S: To be determined by simulation;

• H2O: up to saturated.

3) For the VRU compressors, construction materials shall be selected considering the

following contents on the process gas:



• H2O: up to saturated at all conditions.

4) For the Exportation Gas Compressors, construction materials shall be selected

considering the following contents on the process gas:


• H2S: To be determined by simulation;H2O: saturated during commissioning.

5) For the Injection Gas Compressors, construction materials shall be selected considering

the following contents on the process gas:



• H2O: saturated during commissioning.

6) For dehydration/ Hydrocarbon dew point adjustment unit construction materials shall be

selected considering the following contents on the process gas:



• H2O: up to saturated.

CONTRACTOR shall consider ocurrency of low temperature for material selection.

7) CONTRACTOR shall provide choke and downstream lines compatible with depressurizing

temperature during well startup with gas segregation in the riser top. The estimated

temperature downstream the choke is -70°C. Despressurizing temperatures may also occure

at service lines and gas export lines.


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GENERAL NOTES

Note 1: Operational conditions shall include upset conditions such as, but not limited to,

dehydration/ Hydrocarbon dew point adjustment unit malfunction.

Note 2: PETROBRAS may accept deviation from materials specifications whenever asked

based on technical reasons provided by CONTRACTOR, during the design phase.

Note 3: For gas compressors, free water carryover shall also be considered due to the

scrubbers’ efficiency and water condensation along the piping, both suitable to occur on

normal running, on cold startup and on pressurized stop condition.

Note 4: CONTRACTOR shall take measures to guarantee compressor performance and

availability if wet gas is used for commissioning, start-ups or fuel gas.

Note 5: CONTRACTOR shall consider flowrate regime (stagnant, intermittent or

continuously flowing) when evaluating corrosivity and selecting piping material.

Note 6: Gaskets materials shall be compatible with fluid and operational temperatures to

avoid risk of leakage. Hydraulic paper shall not be used for hot water piping systems

1.12. ISOLATION PHILOSOPHY

CONTRACTOR shall submit the ISOLATION PHILOSOPHY for PETROBRAS approval.

The philosophy shall consider operation/design pressure and service, fiscal metering

removal for calibration etc, and include, at least:

1) Positive isolation philosophy: Positive isolation shall be provided by one of the following

arrangements:

a. Physical disconnection - the removal of a flanged spool piece or valve and the

secure fitting of a blank flange and gasket of the correct pressure rating to the

open ended pipes;

b. A line blind, spectacle blind or spade and spacer system of the correct pressure

rating.

Positive isolation shall be applied, at least, to achieve the following goals:

a) To permit line isolation of major items of equipment or group of items;


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b) To isolate a section of plant during long term maintenance when a complete plant

shutdown is not desirable or necessary;

c) To prevent contamination of utility supplies where these are permanently

connected to a process unit or package;

d) To single block, fill, vent and drain valves on process systems and equipment.

These will be fitted with fully rated blind flanges.

Positive isolation shall always be applied in the following circumstances:

a) Confined space entry;

b) Naked flame hot work on process systems;

c) Work on prime movers.

d) To eliminate the potential for hazardous fluid breakthrough into a vessel during

man entry;

Additionally, equipment requiring positive isolation with Spectacle blind flange (Figure-

8) must have a device at all inputs and outputs. For small diameter pipes, the possibility

of using a "paddle blank" should be evaluated on a case-by-case basis. All equipment

nozzles must have devices for positive insulation for maintenance.

All risers awaiting future connection must remain positive isolated, in addition to valved

blocking already in place.

1.1) Identification for “Insertion Parts Between Flanges”: All IPF's, with locking

function for maintenance, inspection, repairs and final installation, must receive indelible

identification (stamped) located on the cable on both sides. For the paddle blanks and

spacer rings with a nominal diameter greater than eight inches (8 ") the identification

must be located on the side of the part, as shown in the figure below, containing at least

the following information: Nominal diameter in inches, Pressure Class, Specification of

the part material according to ASTM and the thickness in millimeters.


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Paddle blank identification, spacer ring and Spectacle blind flange (Figure-8) with lock

function

1.2) Identification of Special Paddle Blanks for Hydrostatic Pressure Test and

Tightness Test: The identification of paddle blanks, for exclusive use in pressure

testing, must receive indelible identification (stamped) located on the cable on both

sides, containing at least the following information: Pressure Class; Hydrostatic test

pressure; Nominal diameter in inches; Specification of the part material according to

ASTM and the thickness in millimeters.

All special paddle blanks, whether for exclusive use in pressure testing or for blocking,

must be painted in red safety color applied to the cable and along its thickness, in order

to facilitate visualization in the field and prevent them from being installed and/or

maintained improperly.

1.3) Identification of Special Paddle Blanks for Positive Isolation: The identification

of special Paddle Blanks, for positive insulation, must receive indelible identification

(stamped) located on the cable on both sides, containing at least the following

information: Pressure class; Nominal diameter in inches, Maximum Allowable Working

Pressure (MAWP) in Kgf/cm2, Specification of the part material according to ASTM and

the thickness (T) in millimeters.

Identification on the Side

Identification on the Handle


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These special paddle blanks should also be painted in a safety red color to facilitate

visualization in the field.

Identification paint for special locking paddle blanks temporarily installed and detail of

identification on the handle

1.4) Identification of Special Paddle Blanks for Cleaning/Inerting/Purging: The

paddle blanks for cleaning, inerting or purging must receive indelible identification

(stamped) located on the cable on both sides, containing at least the following

information: Pressure class; Nominal diameter in inches, P ATM (ATMOSPHERIC

PRESSURE), Specification of the part material according to ASTM and the thickness in

millimeters.

The special paddle blanks for cleaning, inerting or purging must have a minimum

thickness (T) of 4.8mm. These special paddle blanks must also be painted in Orange-

Safety.

The special paddle blank for positive insulation and hydrostatic test must be painted in

a color Red Safety special paddle blank for drain/purge should be painted Orange

Safety and standard paddle blank should be painted in white.

The special paddle blank for positive insulation should be calculated for the design

pressure of the line. Special paddle blank for hydrostatic testing must be calculated for

90% of the yield stress. Special paddle blank for drain/purge must have a minimum

thickness of 4.0 mm.

2) Valved isolation (or double block isolation).

During design, when opting for isolation using block valves, factors such as nominal

pipe diameter, pressure class and fluid hazard must be taken into account to choose


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between Single Block (SB), Single Block and Bleed (SBB) or Double Block and Bleed

(DBB). The Table below should be considered.

3) Securing Valve Position: Manual isolation valves shall be locked (either open or closed)

if inadvertent operation of the valve could lead to damage to equipment or a potentially

unsafe condition. Secure locking should ideally utilize proprietary key locking systems

(e.g. Castell, Smith, Netherlocks etc.) with dedicated keys. Key control for such systems

will of course be critical. Use of simple padlock and chain should be a last resort

approach.

4) ESD Valves (Emergency Shutdown)

5) Isolation of Instrumentation

6) Vessel Vents

7) Vessel/Equipment Drains

8) Utility Connections

9) Boundary Isolation

10) Specification Breaks: Spec breaks must always be located on valves. Valves that limit

"spec" breaks must be specified to the most critical "spec" (eg design pressure,

corrosivity, temperature, etc.).

11) Reverse Flow Protection: Check valves must be double to be considered a valid

safeguard against reverse flow. The CONTRACTOR must analyze if there is a need for


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them to be dissimilar. Consider and analyze the consequences of any leakage, even in

case of double retention (API 521).

12) Relief Valves: Safety relief valves protecting items of equipment and systems are

required to be inspected regularly to ensure safe operation and may require

replacement at any time if they start to leak. Normally the protected equipment or

system will have to be taken out of service to replace or maintain a single relief valve.

Spare relief valves shall be installed where it is unacceptable for an item of equipment

or system to be out of service before the relief valve can be maintained.

Where spare relief valves are installed, the following shall be assured:

• Simultaneous isolation of the operating and spare relief valves shall be prevented using

an mechanical interlock;

• There is an unobstructed path through to flare from the operating valve;

• The relief valves available are adequately sized to discharge at the required capacity

for the equipment or system.

13) Pig Launcher/Receiver End Closure Interlocks: All pig launchers and receivers shall

have their operation controlled by virtue of a key interlocked system incorporating all

pertinent valves in the operating sequence. The interlocking system, whether

mechanical or software/hard-wired from pushbutton control panel logic, shall as a

minimum incorporate main valves, kicker valves, drain valves, vent valves and the end

closure or door. If flushing operations are required, such as for pig receivers in waxy

service, the interlock system shall incorporate valves on flushing fluid supply lines. In

addition, the launcher/receiver door shall have a mechanical safety device to prevent it

from being opened when the launcher/receiver is under pressure.

14) Control Valves: The requirement for control valves to be provided with a manual bypass,

hand-wheel or parallel spare control valve will be dictated by the criticality of the service

with respect to maintaining production availability and the viability of controlling the

process manually (whether via a bypass globe valve or hand-wheel) in the event of a

control valve failure.

Provision of either manual bypasses or hand-wheels for control valves shall not be

considered unless safe operation can be achieved under purely manual control.

Production availability requirements and the overall facility isolation philosophy shall

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of whether the control valve is to be maintained on-line (e.g. whilst production continues

via a manual bypass valve or parallel spare control valve) or only maintained at a

convenient wider system shutdown (e.g. production continuing in the interim via a spare

control valve).

Where a control valve (e.g. one in production critical service) is to be maintainable

without shutting down and depressuring the wider system, then valve isolation to

facilitate this shall be provided upstream and downstream of the control valve in

accordance with the table presented on item 2.

For fail closed control valves, drain connections shall be installed on each side of the

control valve in-board of any isolation block valves.

1.13. NOT APPLICABLE

1.14. RELIABILITY AVAILABILITY AND MAINTAINABILITY ANALYSIS

An independent supplier shall carry on a RAM (Reliability Availability and Maintainability)

analysis. The analysis shall follow the principles and criteria defined on I-ET-3010.00-1200-

901-P4X-001 - Reliability Availability And Maintenability (Ram) Analysis Requirements. The

study shall be presented during the development of the project. Minimum redundancies and

plant equipment configuration defined on this GTD are not to be relaxed.


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2. PROCESS

CONTRACTOR shall also design the topsides facilities according to riser characteristics

included but not limited to item 14.1.

Process Plant and Utilities shall operate normally when subjected to the motions induced by

the environmental conditions (see Section 12).

CONTRACTOR shall bear in mind that, as the design is part of the Contract and falls under

CONTRACTOR’s responsibility, production shutdown or degraded oil, water or gas

specification or any other equipment malfunction due to vessel motions shall not be

acceptable. CONTRACTOR shall minimize vessel motions in all environmental conditions,

especially in Beam Sea Condition.

Unit must have stand-by equipments, ready to operate, in order to guarantee no process

capacity reduction or degradation of the oil, gas and water specification. This requirement

includes the necessary redundancy for the process vessels PSVs.

2.1. FLUID CHARACTERISTICS

2.1.1. PRODUCED OIL AND RESERVOIR

The typical range of properties for the oil production wells to be tested is indicated in the

Table below and shall be taken into account for all design purposes. CONTRACTOR shall

design the Unit to process oil within these properties and acoording to Table 2.1.2.1.

CONTRACTOR shall make simulations to assess the correct design parameters.

CONTRACTOR shall submit the process simulation files and report to PETROBRAS

considering the range of fluid components. Heat and Mass Balance (H&MB) shall include

the contaminants content forecast for all streams, including oxygenated compounds

(MEG/TEG/ETHANOL) and benzene.

Table 2.1.1.1 Oil Properties

Well A /

Well C Well B Well D Well E

Oil API Grade 38.2 39.6 35.5 48.5

@ 30ºC 7.8 5.3 7.8 1.8


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Viscosity (cp)

(dry – dead oil)(1)

@ 40ºC 5.8 4.1 5.8 1.5

@ 50ºC 4.5 3.2 4.5 1.2

Initial Paraffin

Deposit

Temperature

(ºC) (2),(3)

(1st event) 39.9 35.8 37.3 15.8

(2ndevent) 26.1 22.6 24.2 -

Pour Point -24ºC 9ºC -42ºC 6ºC

Foam Yes Yes Yes Yes

Solids (4) - - - -

Note 1: Pressure loss due to emulsified oil viscosity shall be considered.

Note 2: CONTRACTOR shall design production plant to ensure operational continuity

considering that wax crystals and wax deposition.

Note 3: Wax is expected to deposit only in the second event.

Note 4: Some amounts of solids are expected. The installation of manual facilities to remove

solids (corrosion products and precipitated salts), for example some spare nozzles,

is required for FWKO, Test Separators and electrostatic treaters.

2.1.2. PRODUCED WELLS COMPOSITION

CONTRACTOR shall design the Unit with the compositions given below. CONTRACTOR

shall submit to PETROBRAS, during the execution phase, the process simulation

considering the range of reservoir fluid components.

These simulations shall show clearly the operating conditions of process plant equipment.

These simulations shall consider the premises in Table 2.1.2.1 (steady flow condition):

Table 2.1.2.1 Design Cases.

Cases Train Fluid

(NOTE 4)

Temp.

(ºC)

(NOTE 1)

Oil

Flowrate

(Sm3/d)

(NOTE 2)

Liquid

Flowrate

(Sm3/d)

(NOTE 9)

Gas

Flowrate

(Sm3/d)

(NOTE 3)


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Max Oil / Max

Liquid /

Max Gas

1

Oil Well A + B (70/30) 85 15,900 19,100 6,000,000

Non associated gas Well D + E (65/35) 0 3,200 3,200 4,000,000

Total 19,100 22,300 10,000,000

Max Oil / Max

Liquid /

Max Gas

2

Oil Well A 40 15,900 19,100 6,000,000


Total 19,100 22,300 10,000,000

Max Gas 3

Oil Well A + B (70/30) 40 9,000 9,000 4,500,000


Total 11,000 11,200 10,000,000

Max Gas 4

Oil Well A 85 9,000 9,000 4,500,000


Total 11,000 11,200 10,000,000

Max Gas 5

Oil Well A + B (70/30) 85 9.000 9.000 4.500.000

Non associated gas Well E 0 1.700 1.900 5.500.000

Total 10.700 10.900 10.000.000

40% BSW / Max

Liquid 6

Oil Well A 40 11,500 19,100 To be

simulated

Non associated gas Well D + E (30/70) 0 3,000 3,200 To be

simulated

Total 14,500 22,300 To be

simulated

Max Water 7

Oil Well C 85 3,400 19,100 To be

simulated

Non associated gas Well D + E (70/30) 0 400 600 To be

simulated

Total 3,800 19,700 To be

simulated

Max Water 8

Oil Well C 40 3,400 19,100 To be

simulated

Non associated gas Well D + E (30/70) 0 400 600 To be

simulated

Total 3,800 19,700 To be

simulated

Max Oil Wells 9

Oil Well A + B (70/30) 40 19,100 19,100 7,000,000

Non associated gas 0 0 0

Total 19,100 19,100 7,000,000

Max Oil Wells 10

Oil Well A 85 19,100 19,100 7,000,000

Non associated gas 0 0 0

Total 19,100 19,100 7,000,000

Max Non

Associated Gas

Wells

11

Oil 0 0 0

Non associated gas Well D + E (60/40) -5 5,000 5,200 8,000,000

Total 5,000 5,200 8,000,000

Max Non

Associated Gas

Wells

12

Oil 0 0 0

Non associated gas WellE 40 2,500 2,700 8,000,000

Total 2,500 2,700 8,000,000


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Low Flow 13

Oil Well B 70 3,000 3,000 1,000,000

Non associated gas

Total 3,000 3,000 1,000,000

Note 1: Operational temperature downstream of production choke valve. During the

production, the temperature can vary from 40°C to 85°C on oil production train and from -

5°C to 40°C on non associated gas production train.

Note 2: The standard flow rate shall be applied to oil conditions as per item 2.2.1. It refers

to dead oil conditions.

Note 3: Gas Flow Rate at outlet of Free Water KO Drum and Inlet Gas Separator. Any

recirculation of gas streams must be added on to this Gas Flow Rate. Gas Lift recirculation

should not be taken into account.

If necessary, in order to achieve the desired Gas Oil Ratio (GOR) for each design case,

simulation may be adjusted by subjecting Well Fluids through a series of flashes, and

recombining the gas and oil rates to match the flowrates indicated in Table 2.1.2.1.

Note 4: The mixture of wells is based on oil flowrates at Standard Conditions.

Note 5: During project execution phase PETROBRAS will provide to CONTRACTOR the

pressure, temperature and flow rate conditions (steady flow and well start-up) to size

production choke valves. CONTRACTOR shall submit choke valves calculation report to

PETROBRAS.

Note 6: During project execution phase, PETROBRAS will provide to CONTRACTOR the

pressure, temperature and flow rate conditions to size gas export control valve and lift gas,

water injection, gas injection and heavy hydrocarbon rich stream (C3+) injection choke

valves. CONTRACTOR shall submit choke valves and gas export control valve calculation

report for PETROBRAS.

Note 7: The shut-in pressure at top production riser is 26,000 kPa(a) for the oil production

wells and 31,600 kPa(a) for the non-associated gas production wells.

Note 8: The minimum operation pressure upstream of oil and non associated gas

production choke valves, in steady state condition, is 2,000 kPa(a). Under some conditions,

eg. intermittent flow, pressure can achieve lower values. ,

Note 9: Liquid flowrate refers to oil/condensate and water. MEG flowrate is not included.


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Given the well data supplied in GTD, CONTRACTOR shall, during the design phase, inform

the maximum allowable oil flow rates without gas lift.

Table 2.1.2.2 shall be taken into account for the fluid composition.

Table 2.1.2.2: Well Fluid Composition

Composition

OIL GAS

Well A Well B Well C Well D Well E

CO2 0.85 0.85 0.80 1.14 0.48

N2 0.47 0.35 0.44 0.41 0.41

C1 62.65 55.29 75.75 70.93 84.97

C2 7.77 6.91 8.00 5.31 5.54

C3 5.15 7.45 4.90 4.74 2.71

IC4 1.19 1.93 1.06 1.07 0.71

NC4 2.34 3.39 1.82 1.96 0.91

IC5 1.04 1.43 0.58 0.8 0.46

NC5 1.02 1.19 0.55 0.74 0.38

C6 1.42 1.41 0.75 0.84 0.5

C7 2.03 1.67 0.76 1.26 0.53

C8 2.21 2.11 0.81 1.47 0.39

C9 1.59 1.82 0.51 1.12 0.22

C10 1.26 1.59 0.40 0.87 0.28

C11 0.97 1.23 0.31 0.67 0.2

C12 0.79 1.04 0.25 0.55 0.17

C13 0.81 1.07 0.26 0.58 0.17

C14 0.64 0.85 0.20 0.47 0.14

C15 0.63 0.86 0.20 0.44 0.13

C16 0.48 0.66 0.15 0.34 0.1

C17 0.43 0.61 0.14 0.3 0.09


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C18 0.42 0.58 0.13 0.3 0.08

C19 0.4 0.53 0.13 0.27 0.07

C20+ 3.45 5.18 0.40 3.41 0.35

Mol. Weight

C20+

481 442 481 444 354

Density C20+ 0.9215 0.8966 0.9215 0.9037 0.886

Note 1: CONTRACTOR to consider 11 ppmv of H2S on separated gas from Well D.

Note 2: CONTRACTOR to consider BTEX concentrations presented in table 2.1.2.3 as

fractions of component Cn of Table 2.1.2.2.

Note 3: CONTRACTOR to consider 2 µg/Sm3 of Hg in the produced gas.

Table 2.1.2.3: BTEX

concentrationsComp

onent

Included as

following component

(Cn)

% mol

Well A Well B Well C Well D Well E

Benzene C7 3.73 2.43 3.73 3.02 14.29

Toluene C8 30.53 29.44 30.53 32.07 24.56

C2-Benzene C9 4.34 4.49 4.34 0.00 5.71

M. and P. Xylenes C9 26.54 25.12 26.54 29.02 22.86

O. Xylene C9 6.63 6.68 6.63 6.53 8.57

2.1.3. WELL TEST CHARACTERISTICS

Table 2.1.3.1 shall be taken into account to define the test separator system (test heaters,

three-phase test separators, pumps and other related items).

Table 2.1.3.1: FPSO capacities.

CHARACTERISTICS NOTE VALUE

Oil production wells

Oil Flow rate Maximum 5,000 Sm³/d


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Minimum, for accuracy of

measurement purpose 100 Sm³/d

Gas Flow rate Maximum 2,000,000 Sm³/d

Minimum 100,000 Sm³/d

Water cut For accuracy of measurement

purpose 0 to 95%

Arrival temperature downstream

choke valve -

40 ºC to 90 ºC

(Note 9)

Non associated gas production wells

Condensate Flow rate

Maximum 3,000 Sm³/d

Minimum, for accuracy of

measurement purpose 30 Sm³/d

Gas Flow rate Maximum 3,500,000 Sm³/d

Minimum 100,000 Sm³/d

Arrival temperature downstream

choke valve -

-5 ºC to 40 ºC

(Note 9)

Note 1: Oil Wells Test Separator shall be able to operate from low pressure (atmospheric)

up to the Free Water KO Drum normal operating pressure of 1,300 kPa(a). During

low pressure operations, expected for well kick-off purpose, produced gas from Test

Separators may be routed to flare, and liquids routed further lower pressure

separation stages. Non Associated Gas Wells Test Separator shall be able to

operate at the Inlet Gas Separator normal operating pressure of 1,300 kPa(a).

In normal operation, the oil shall be routed back to process plant upstream Oil/Oil

Pre-Heater and produced water shall be routed to Produced Water Treatment.

Note 2: Test Separators shall be sized for maximum liquid and gas flows with normal

operating pressure. An additional case of 2,500 m3/d (oil) with 50% water cut

associated to maximum gas flow rate shall be considered for Oil Wells Test

Heater/Separator design. The maximum total liquid to Test Heaters/Test Separators

is equal to the maximum oil flow rate.

Note 3: Test Separators will also receive fluids such as wells completion fluids and special

operations fluids. During early execution phase, PETROBRAS will submit to


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CONTRACTOR a Subsea Operating Philosophy, including a preliminary description

of all intended procedures for Subsea operations.

Note 4: 2 (Two) x 100% of capacity oil test separators pumps shall be installed at least for

low pressure operations.

Note 5: 2 (Two) dedicated test trains, one for oil production wells and one for non associated

gas production wells, shall be installed.

Note 6: The well Test Heaters and Test Separators will receive wax crystals.

Note 7: The UNIT shall provide Test Heaters bypass.

Note 8: The standard flow rate shall be applied to oil conditions as per item 2.2.1.

Note 9: Test Separators normal operating temperature shall be the same as Free Water KO

Drum and Inlet Gas Separator. For Test Heaters design purpose shall be considered

a heating of +20°C to all design cases.

Note 10: Produced water from Non Associated Gas Wells Test Separator shall be routed to

MEG treatment unit.

Note 11: An online analyser to monitor the H2S content shall be installed in the outlet gas

of both Test Separators.

2.1.4. PRODUCED GAS

The complete description of the gas treatment and compression plant is found on item 2.7.3.

2.1.5. PRODUCED WATER

Salinity up to 80,000 mg/L (as NaCl).

The complete description of the produced water treatment, injection and disposal is found

on item 2.2.2 and 2.7.4.

2.2. PROCESS

2.2.1. CARGO TANKS/EXPORTED OIL

The oil to be exported shall meet the following specification:


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• Basic Sediment & Water content (BS&W): lower than 0.5% vol.;

• Salt content: less than 285 mg/L-NaCl;

• RVP: 37 kPa at 37.8 C

• H2S : < 1 mg/kg;

• Maximum Oil TVP @ measurement temperature: 70 kPa (a).

2.2.2. PRODUCED WATER DISPOSAL

The disposal of produced water shall comply with the Brazilian Regulatory Authorities

regulations issued by Environmental Ministry, through its CONAMA Resolutions 393/2007,

430/2011 (art.28), and Nota Técnica IBAMA 01/2011. The analytical method used to

determine the content of Oil & Grease (TOG) in produced water to be discharged to

overboard shall be the Standard Method (SM) SM-5520B, which determines the total hexane

extractable material (HEM).

Manual sampling devices shall comply with the CONAMA Regulation and “OSPAR (Oslo

and Paris Commissions) - Methodology for the Sampling and Analysis of Produced Water

and Other Hydrocarbon Discharges”.

The sample points for produced water can be classified as:

- Compliance with Legislation: sampling for environmental monitoring, it shall be located

downstream the last equipment before produced water discharge;

- Operational: other sample point used to evaluate the produced water system performance.

The sample points installed to comply with legislation shall follow, at least the following

requirements:

• It shall be intrusive, positioned in the center line of piping and with a curvature of 90o

against the flow. A schematic is represented on Figure 2.2.2.1 below:


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Figure 2.2.2.1 – Produced water sample point – Intrusive – Piping with curvature of 90º

• It shall be located in a vertical section of piping with ascendant flow;

• The piping shall be of stainless steel with a minimum diameter of ½ “;

• In case where intrusive sampling is not practicable (eg.: small diameter piping), a lateral

nozzle shall be used;

• The length of sampling piping shall be as minimum as possible, preferably lower than 4

(four) meters;

• It shall be kept constantly opened in the maximum opening of sampling valve.

A sample point shall be installed downstream the online TOG (Oil in Water Content)

analyzers.

The operational sample points shall follow, at least the following requirements:

• It shall be intrusive, positioned in the center line of piping. It shall be provided with a

curvature of 90o against the flow or with a 45o chamfered pipe end, as indicated on

Figures 2.2.2.2 and 2.2.2.3 below:


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Figure 2.2.2.2 – Produced water operational sample point – Intrusive – Piping with curvature

of 90º

Figura 2.2.2.3 – Produced water operational sample point – Intrusive

• Preferably use points located in vertical sections, with ascending flow. Where this is

impracticable, it can be located in a horizontal section with turbulent flow, downstream

elements such as, knees, curves, level control valves, etc;

• The piping shall be of stainless steel with a minimum diameter of ½ “;

• In case where intrusive sampling is not practicable (eg.: small diameter piping), lateral

nozzles can be used. If located in an horizontal section, the sample point shall be

preferably positioned in the lateral of pipe, bottom or top configurations shall be avoided;

• The length of sampling piping shall be as low as possible, preferably lower than 4 (four)

meters and shall be equipped with drip trays.

Online TOG analyzers (content of oil and grease in water) shall be provided at each

produced water overboard discharge. Minimum two produced water overboard discards: one

at the outlet of flotators and other at the outlet of the produced water tanks.

Logics should also be implemented so that the overboard is interrupted if produced water is

out of discharge limits. Automatic cleaning system of acoustic (ultrasonic) type shall be

provided. The analyzer shall be installed close to the sampling points, in preference at

upwards flow points, aiming to avoid possible interference from phase stratification

commonly observed in horizontal flows.


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Note 1: Slop tanks shall not be considered for handling the produced water treatment

system.

Note 2: The produced water shall not be mixed with any other water or effluent.

Note 3: The end of the disposal line shall be above sea level, on all draft of the vessel, in

order to allow visual inspection of the water quality.

2.2.3. SERVICE AND LIFT GAS

The lift gas to provide artificial lift shall meet the following specification:

Gas lift riser:

• Normal lift gas temperature at the top of the riser: 40 ºC;

• Maximum lift gas temperature at the top of the riser: 60 ºC;

• Normal Operating Pressure: at the top of the riser: 32,000 kPa (a);

• Design Pressure: 34,500 kPa (a);

• Maximum 5 ppmv of H2S;

• Maximum 3% of CO2;

• Maximum H2O content: 10 ppmv;

Gas injection riser:

• Normal injection gas temperature at the top of the riser: 40 ºC;

• Maximum injection gas temperature at the top of the riser: 60 ºC;

• Normal Operating Pressure at the top of the riser: 52,000 kPa (a);






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2.2.4. EXPORTED GAS

Gas export riser (these values will be further confirmed by Petrobras):

• Maximum exported gas temperature at the top of the riser: 60ºC

• Normal exported gas temperature at the top of the riser: 40ºC;

• Normal operating pressure at the top of the riser: 32,000 kPa (a)

• Design pressure: 34,500 kPa (a);



• Maximum H2O content:10 ppmv;

Besides general specification above, gas export shall meet the following specifications

according to modes operation 1 and 2. For more details of each mode, see Section 2.7.3.3.

MODE 1: Treated gas exportation and heavy hydrocarbon rich stream (C3+) injection

Gas export specification shall comply with Resolution ANP No16/2008 (XXXXX region).

Table 2.2.4.1 summarizes the requirements.

Table 2.2.4.1: Gas export specification

PARAMETER UNIT VALUE (2) METHOD

NBR ASTM D ISO

HHV kJ/ m³

35,000 a

43,000 15213 3588 6976

kWh/m³ 9.72 a 11.94

Wobbe Index kJ/m³ 46,500 a

53,500 15213 - 6976

Number of methane, min. 65 - - 15403

Methane, min. mol% 85.0 14903 1945 6974

Ethane, max. mol% 12.0 14903 1945 6974

Propane, max. mol% 3.0 14903 1945 6974


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Butane+, max. mol% 1.5 14903 1945 6974

Oxygen, max. mol% 0.5 14903 1945 6974

Inerts (N2+CO2), max. mol% 8.0 14903 1945 6974

CO2, max. mol% 3.0 14903 1945 6974

Total sulphur, max. mg/m3 70 - 5504

6326-3

6326-5

19739

H2S, max. mg/m3 13 - 5504

6228 6326-3

Water dew point @ 1atm,

max. °C -39 - 5454

6327

10101-2

10101-3

11541

Hydrocarbon dew point @

4.5 MPa, max. °C 15 - -

6570

23874

Mercury, max. µg/m³ Report value - - 6978-1

6978-2

MODE 2: Gas exportation and partial heavy hydrocarbon rich stream (C3+) injection

Hydrocarbon Dew Point specification up to 25°C @ 4.500 kPa(a).

2.2.5. HEAVY HYDROCARBON RICH STREAM (C3+)

Heavy hydrocarbon rich stream injection riser:

• Normal injection condensate temperature at the top of the riser: 40 ºC;

• Maximum injection condensate temperature at the top of the riser: 60 ºC;

• Normal Operating Pressure at the top of the riser: 52,000 kPa (a);



2.3. SEAWATER INTAKE


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During project execution phase, CONTRACTOR shall evaluate the seawater intake depth

in order to reduce seawater intake temperature and achieve lower organic residual

content. The minimum depth shall not be less than 30 m.

2.3.1. COMPOSITION

Table 2.3.1.1: Sea water composition.

SEA WATER ANALYSIS

pH 8.27

Conductivity 64.75 µS/cm

K+ 1,277.6 mg/L

Na+ 54,036mg/L

Ca++ 526 mg/L

Mg++ 1 ,657 mg/L

Ba++ <0.1 mg/L

Sr++ 6.1 mg/L

Fe total 0.2 mg/L

HCO3- 130mg/L

NO3- 13.35 mg/L

Cl- 24,720mg/L

SO4-- 2,800 mg/L

Salinity 40,736 mg/L

Total suspended solids 88 mg/L

Oxygen content 7 mg/L

Turbidity 0.45 FTU

Silt density index 5.1

m-SRB 25 MPN/mL

Anaerobic bacterias 25 MPN/mL


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Table 2.3.1.2: Sea water particle size distribution.

PARTICLE SIZE DISTRIBUTION

SIZE RANGE (μm) NUMBER OF PARTICLES

(part./100mL)

5 to 15 9,769.9

15 to 25 495.8

25 to 50 152.6

50 to 100 25.3

>100 1.2

TOTAL 10,444.7

Note 1: This information does not take into consideration the vessel and UNIT overboard

lines interferences, e.g., temperature, particles and others.

Note 2: First filter downstream sea water lift pumps shall be specified for 1000 µm.

2.4. WATER INJECTION

The Unit shall be able to operate continuously with only one injection well up to eleven

connected wells through IW01 to IW05 and IWAG01 to IWAG06 positions.

With regard to water injection capacity per well, CONTRACTOR shall consider the

information stated on item 2.5.1.

The water injection system shall be able to inject continuously up to 31,800 m³/day at

maximum operating pressure of 25,000 kPa(a).

The water injection temperature shall be controlled downstream the injection pump and its

set point shall be up to 60°C. Minimum operating temperature shall be 40ºC even when

injecting only seawater. It may be considered energy integration with cooling water system

return to heat injection water.

Means shall be provided to allow water injection at the correct specification, even when

operating at minimum flow rate (only one well connected with minimal flow) or at full capacity

(all wells connected). Means shall be provided for individual well flow rate control, using


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information from operational flow meters (see 7.7). The water injection system shall have no

stagnation points. If inevitable, water drainage points shall be provided.

Installed spare pumps shall be provided for booster and main injection pumps (at least

3x50%).

Suitable pressure equalization valves shall be predicted among main injection pump

discharge and alignment to system header, preferably under remote control (central control

room).

For details about water injection pumps mechanical requirements, see Section 9.4.1.

The sea water injection system shall have a Sulphate Removal Unit (SRU). The sea water

injection water quality specification is as follows (maximum values):

o Content of suspended solids (TSS): 1.5 mg/L;

o Maximum particles/mL greater than 5 µm: 10 (ten) per milliliter;

o Dissolved oxygen: 10 ppb (vol) O2;

o Soluble sulfide content: 2 ppm (vol);

o Bacteria (SBR planctonic – mesophile): 50 NMP/mL;

o Total anaerobic bacteria (BANHT planctonic): 5,000 NMP/mL;

Maximum sulphate content after SRU: 100 mg/L. (This value can be higher, if requested by

PETROBRAS, during operational lifetime)

The sea water injection system shall consist of cartridge filters (pre-treatment), sulphate

removal unit (including CIP system), deaerator system, chemical injection (for details see

item 2.8).

The Sulphate Removal Unit shall be located upstream Deaerator.

SRU feed pumps shall have a connection to overboard (between pumps and membranes)

in order to allow comissioning and start-up procedures.

The SRU shall be provided with 2 (two) stages and a configuration for trains/package which

allows, during cleaning operation, a maximum reduction in the unit flowrate of 20%.


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For operational adjustments of hydraulic balance of the unit and in order to guarantee an

efficient pressure and control flowrate, spare connections for additional vessels installation

shall be provided. The connections shall be provided based on 10% of each bank capacity.

It shall be provided flowrate measurement in the inlet and outlet of permeate and reject of

each membranes bank of first stage as well as in the outlet of permeate and reject of second

stage.

In order to guarantee pressure control in SRU membranes, pressure valves interlocked with

pressure transmitters shall be foreseen in all permeate lines.

In permeate lines, PSV shall be used instead of rupture disk.

The redox analyzer shall be duplicated and the dosages of scale inhibitor and chlorine

scavenger shall be interlocked with the SRU. The analyzer shall be located upstream of

shock biocide and scale inhibitor injection points. These instruments shall be provided with

by-pass for maintenance purpose.

Multi-media or coarse filters (selfcleaning candle type for 25 µm) can be used upstream

cartridge filters to minimize cartridge filter replacement. If cartridge filters (fine filters) are

selected, the following specification shall be applied for filters:

• They shall be absolute type in order to guarantee the SDI (Silt Density Index) specified

by nanofiltration membranes supplier. The filter elements shall be of propylene with 6”

of diameter and 60” of height, provided with O-ring sealing and filtration from inside to

outside (inside-out);

• The maximum flowrate per cartridge shall be 15 m3/h;

• The material of carcass and cover shall be coated carbon steel and internals materials

shall be SS 316L, SS 321 or Superduplex;

• The maximum differential pressure supported by the vessel and its internal shall not

be lower than that supported by the filter elements;

• The closing system of the filters shall be of the type with quick opening.

The same specification above also applies for the filters of SRU’s CIP.

Regarding CIP system, the connection of chemical products shall be above CIP tanks and

shall be provided with rigid lines. Online pH motinoring shall be provided.


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Ultrafiltration membranes can also be employed as an alternative to cartridge filters.

If ultrafiltration is the selected alternative, design of the UF recovery shall consider inlet solid

content defined by membrane supplier. This unit shall comply with the following

specifications as a minimum:

• Normal operation permeate flux and maximum permeate flux to maintain the total

water injection flowrate at all times, including backwashing and/or cleaning and routine

maintenance;

• Maximum permeate flux in operation during cleaning: 80 LMH@25ºC;

• Membrane shall be sodium hypochlorite (NaOCl) resistant to a minimum of 500 ppm

during cleaning procedure;

• Membrane absolute pore size: maximum of 0,22 µm.

• Ultrafiltration design specification shall be in accordance to SRU supplier’s

requirements.

Full and partial bypass of SRU unit shall be considered (bypass shall not cover filters

upsteam membranes). The bypass will be used whenever requested by Petrobras. The

bypass shall not be used to reach the water injection quota unless when requested by

PETROBRAS. The bypass may be used during SRU unit cleaning to sustain water injection

flow, whenever requested by PETROBRAS.

In case of using vacuum deaerator, vacuum pumps shall be equipped with proper

instruments for performance curve evaluation. These pumps shall be provided with a stand-

by.

The unit shall be able to inject seawater, produced water and mixtures of them, as shown

on figure 2.4.1.

The injection water system shall have an online O2 analyzer installed at downstream

deaerator, downstream produced water treatment unit and downstream water injection

pumps.

The produced water treatment system description is detailed on item 2.7.4.

The produced water to be injected into reservoir shall meet the following specification

(maximum values):


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o Content of suspended solids (TSS): 10 mg/L;

o Dispersed oil, as measured by SM5520F: 29 mg/L;

o Maximum particles size: 25 µm

o Dissolved oxygen: 10 ppb (vol) O2;

o Soluble sulfide content: 15 ppm (vol);

o Bacteria (SBR planctonic – mesophile): 50 NMP/mL;

o Total anaerobic bacteria (BANHT planctonic): 5,000 NMP/mL;

Figure: 2.4.1 Simplified diagram for produced water treatment and injection

Water injection riser

• Normal Operating Pressure: 25,000kPa (a);

• Design Pressure (maximum injection pressure): 27,800 kPa (a);


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• Maximum 10 ppb (vol) O2;

• Design Temperature: 20°C to 60°C.

2.5. DESIGN SUMMARY

2.5.1. WELL DESIGN SUMMARY

Table 2.5.1.1: Well design data.

Design data (1) (3)

Oil production wells

Maximum production oil flow rate per well 5,000 Sm3/d

Minimum production oil flow rate per well 100 Sm3/d (2)

Watercut from one well 0% to 95%

Maximum gas production flow rate per well 2,000,000 Sm3/d

Maximum lift gas flow rate 4,000,000 Sm3/d

Maximum lift gas flow rate per well 1,500,000 Sm3/d

Non associated gas production wells

Maximum production condensate flow rate per well

(XXXXX and XXXXX) 3,000 Sm3/d

Minimum production condensate flow rate per well 30 Sm3/d (2)

Maximum gas production flow rate per well 3,500,000 Sm3/d

Water injection wells

Maximum water injection flow rate per well position 8,000 Sm3/d (6)

Minimum water injection rate per well position 1,000 Sm³/d (2)

Gas injection wells (4)

Maximum gas injection flow rate per well position 2,500,000 Sm³/d

Minimum gas injection flowrate per well position 250,000 Sm³/d (2)

Heavy hydrocarbon rich stream (C3+) injection wells (4) (5)

Maximum heavy hydrocarbon rich stream (C3+) injection

standard liquid flow rate per well position 1500 m³/d

Minimum heavy hydrocarbon rich stream (C3+) injection

standard liquid flowrate per well position 100 m³/d (2)


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Note 1: All piping, instrumentation, and equipment must be provided for all the producers,

gas, heavy hydrocarbon rich stream (C3+) and water injection wells, before leaving

the conversion / construction shipyard.

Note 2: For measurement accuracy purposes.

Note 3: The standard flow rate shall be applied to oil conditions as per item 1.7.

Note 4: A PSHH and PSLL shall be installed downstream of each gas and heavy

hydrocarbon rich stream (C3+) injection choke valve and interlocked with the

respective injection riser boarding SDV valve. The set points will be informed during

the project execution phase, and updated during operational phase.

Note 5: Heavy hydrocarbon rich stream (C3+) is liquid under injection conditions. Indicated

flowrate is in liquid standard conditions (15.6°C). CCE expected GOR

approximatedly 5000 Sm³/m³.

Note 6: Well B shall consider 8,000 Sm3/d, other wells shall consider 6,000 Sm3/d.

2.5.2. PROCESS DESIGN SUMMARY

Table 2.5.2.1: Process design summary.

Design data (note 1)

Total liquids processing capacity 22,300 Sm3/d (~140,000 bpd)

Total oil processing capacity 19,100 Sm3/d (~120,000 bpd)

Produced water capacity 15,900 Sm3/d (~100,000 bpd)

Gas treatment & compression system 10,000,000 Sm3/d (Note 2)

Gas-lift pressure 32,000 kPa (a)

Maximum lift-gas capacity 4,000,000 Sm3/d

Exported gas pressure at top of riser 32,000 kPa (a)

Exported gas capacity 8,000,000 Sm3/d

Gas injection pressure 52,000 kPa (a)

Gas injection capacity (note 4) 7,000,000 Sm3/d


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Heavy hydrocarbon rich stream (C3+) injection pressure 52,000 kPa (a)

Total water injection capacity 31,800 Sm3/d (~200,000 bpd)

Water injection pressure downstream of the choke valve 25,000 kPa (a)

Note 1: All piping, instrumentation, and equipment must be provided for all the producers,

gas, heavy hydrocarbon rich stream (C3+) and water injection wells, before leaving

the conversion / construction shipyard.

Note 2: Gas flow rate at outlet of first stage separation (FWKO and Inlet Gas Separator).

The gas coming from internal recycles shall be added to define the total main gas

compression/treatment capacity.

Note 3: The selection of relief devices, if necessary, shall protect subsea equipments (e.g

risers, UEH) against overpressure and shall take into consideration: (i) operating

conditions defined on this chapter 2, ; (ii) each riser required design pressure as per

Table 14.1.1; (iii) maximum overpressure (full open condition) of relief device set

pressure.

Nota 4: For this operation, all non associated gas production wells are to be closed.

2.6. OIL & GAS COLLECTION SYSTEM

2.6.1. TOPSIDE MANIFOLDS AND FLEXIBILITY

The oil production wells shall be connected to 1 (one) oil production header and 1 (one) oil

test header. Both these headers shall be able to accommodate all oil producer wells. The

non associated gas production wells shall be connected to 1 (one) gas production header

and 1 (one) gas test header. Both these headers shall be able to accommodate all non

associated gas producer wells. Problems on the test trains shall not affect the main process

trains. The same philosophy applies to the production risers producing to the test headers.

The Test Header and the Test Separators shall provide periodical production test for each

well.

Production and test headers shall be provided with chemical injection to enhance the

separation and/or protect the facilities (anti-foaming, demulsifier, corrosion/scale inhibitor,

acetic acid, etc.).


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Emergency Shut down valves (ESDV) shall be installed in all wells lines including production,

injection and service lines. ESD valves shall be located in a position:

- in which it can be safely inspected, maintained and tested without provisionary scaffolding;

- such that it is above water;

- such that its exposure to topsides incidents is minimized

Subject to the above, such that the distance from the ESD valve to the base of the riser is as

short as reasonably practicable. Scenarios of Risers releases shall be evaluated as part of

studies like HAZOP, Preliminary Hazard Analysis, Fire and Explosion Study.

The Unit shall also have facilities to inject an ethanol or MEG bed during pigging,

commissioning and WAG fluid change-over operations.

CONTRACTOR shall provide temperature and pressure transmitters upstream and

downstream each choke valve. Temperature transmitters shall also be provided for gas-lift

risers. CONTRACTOR shall provide a differential pressure transmitter connected to PSD

(Process Shutdown System) for each production choke valve. Logic implementation will be

discussed during detail design.

Each production well shall have adjustable chokes at both lines (production and service/gas-

lift). The production choke shall be remotely actuated from the Central Control Room. The

choke valve shall also be able to be manually operated. In addition, each gas lift line, gas

injection, heavy hydrocarbon rich stream (C3+) injection and water injection wells shall have

individual chokes.

A service header to allow flexibility to access each position slot (production, water injection,

gas lift/service and gas/C3+ injection) with no disturbance to the others shall also be

provided. This service header may be used to perform diesel injection (pigging operations,

diesel circulation, bullhead operation, etc.), dead oil circulation, water circulation, gas

circulation as service gas (pigging operations) and special operations (squeeze, etc). All Gas

Lift Slots shall be capable to receive (back flow from well) small amounts (up to 30 m³) of

liquid. This is not to be used often and is restricted to cases of depressurization to remove

hydrate blockage in any part of the subsea system.


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Each IWAG01 to IWAG06 position shall have a connection from both slots (A and B) to the

test header. This alignment refers to service header operations. The fluids from WAG

positions shall be sent to test header.

For the positions OP01/OP02 (“trunkline” pair),OP03 to OP08 (satellite wells), GP01/GP02

(“trunkline” pair), GP05 to GP08 (“manifolded” wells), IWAG01 to IWAG06 (“WAG loop”

wells), IW01/IW02 (“trunkline” pair), IW04 (satellite well) and Gas Export, CONTRACTOR

shall comply with the following requirements:

One instrumented pig launcher and receiver shall be provided for each gas lift / service riser.

One instrumented pig launcher and receiver shall be provided for each production riser.

One instrumented pig launcher and receiver shall be provided for each water injection riser.

One instrumented pig launcher and receiver shall be provided for export gas pipe line.

All pig receivers shall have alignment to test separators in order to allow receiving fluids from

risers. Pig receivers for production risers shall also be connected with Free Water KO Drum

and Inlet Gas Separator.

For the positions GP03 and GP04, CONTRACTOR shall comply with the following

requirements:

One non instrumented pig launcher (only foam pig) shall be provided for each gas lift/service

riser.

Non instrumented (only foam pig) pig receiver shall be provided for the GP03 and GP04 gas

productions risers. This non instrumented pig receiver may have wye to serve GP03 and

GP04.

All pig receivers shall have alignment to Gas Test Separator and Inlet Gas Separator in order

to allow receiving fluids from risers.

For the position IW03 and IW05 no pig launcher or receiver is required. This position shall

have line to test separators in order to allow receiving fluids from riser.

Wye, can be either symmetric or no, but shall be 30º and convergent type, 2 pipeline arriving

in one, in accordance with figure 2.6.1.1.


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Figure 2.6.1.1: Wye

The topside pig arrangement shall be compatible with the use of foam and rigid pigs

(conventional scrapping pigs) as well as intelligent / instrumented pigs.

CONTRACTOR shall comply with the following requirements of the NBR 16381, for the use

of “intelligent / instrumented” pigging for all wells and gas export pipes.

a) Requirements for Launcher, Receiver and Launcher/Receiver:

The pig launcher, pig receiver and pig launcher/receivers of the wells shall be installed in

horizontal direction, parallel to the floor (no slope) and a work space shall be provided behind

the pig trap, with dimensions in accordance with table 2 of NBR 16381.

For installations with space limitations, arrangement of vertical launchers, receivers and

launchers-receivers shall be submitted to PETROBRAS analysis.

The design of closure shall be in accordance with the code ASME BPVC Section VIII,

Division 1.

Pig Launcher, receiver and receiver/launcher shall be safety interlocked during chamber

hatch and valves open or closure.

The closure shall be of the quick opening type, provided with hinge or other mechanism

capable of supporting the moving part during the opening and closing operation, and

equipped with a pressure warning device which prevents closure opening when the barrel is

pressurized.


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The closure shall have a locking device distributed in a continuous and uniform manner along

the entire sealing region.

The reducer of the launcher and the launcher-receiver trap shall be eccentric and that of the

receiver trap shall be concentric. For a launcher or launcher receiver installed in a vertical

position, the reducer of the trap shall be concentric. The included angle of the reducer shall

be smaller than or equal to the limit defined on NBR 16381.

For “piggable” systems, the inside diameter of pipes and fittings located between the barrel

reduction and pipeline derivation shall not be smaller than the smallest pipeline inside

diameter. If the inside diameter of pipes and fittings located between the barrel reduction

and main pipe derivation are different, shall be provided a conical diameter transition,

maximum inclination 1:4 (30 degrees of the pipe wall).

Branchers with outside diameter equal to or greater than the half of outside diameter of

pipeline shall be provided with guide bars to avoid pig stuck at branch. In case of multi

diameters the smallest one shall be taking into account.

The branches shall be assembled at horizontal position (3 or 9 o'clock positions) or on the

top of pipe (12 o'clock position), and can not be located on the bottom on the bottom of pipe

(6 o'clock position) or in any descending position.

A pressure equalization line of the pig trap shall be installed, equipped with a block and a

throttling valve.The pipe nominal diameter of pressure equalization line shall be 25 mm (1

in) for pipelines with a nominal diameter up to 150 mm (6 in) and 50 mm (2 in) for the other

nominal pipeline diameters.

Launchers/receivers designed for intelligent pig passage with nominal diameter of 200 mm

(8”) and larger shall have a flanged outlet with nominal diameter of 50 mm (2”) to help loading

the pig into the barrel, using a pulling cable. This outlet shall be installed horizontal (3h or 9h

positions), inclined at 45° and without interference with the equipment block valve.

Two vents shall be installed, one upstream and another downstream from the reducer, to

make possible the adequate filling or depressurizing of the pig trap.

In installations that require closed system vents, there shall be vents additional to the

atmospheric ones. At installations of pig launcher, receiver and receiver/launcher, blowdown

shall be firstly done for closed system aligned to flare or platform vent.


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Three pressure indicators shall be installed: first one shall be located near to the closure;

second one shall be installed at straight run between isolation valve and pipe reduction. A

third gauge, also called as vaccuum gauge, ranged on 760 mmHg full scale from zero

through 2 bar, shall be installed on the major barrel. Over pressure protection shall be

provided for every pressure gauge (set up 2,2 bar). These both pressure indicators shall be

capable to indicate the barrel operating pressure in the middle third of the scale range.

All launchers, receivers and launcher/receivers shall have closed drain system. This drain

system shall be connected to a sump tank.

When the passage of an intelligent is expected, a branch shall be installed in the pig trap,

with a block valve, for nitrogen injection, positioned upstream from the atmospheric vent

block valve which is installed closest to the closure. The nitrogen injection branch shall have

a check valve to avoid that the product being transported by the pipeline return to the nitrogen

system.

An internal tray (basket) shall be included as supply scope of pig launcher, receiver and

launcher/receiver. The internal tray shall be proper to foam pig retaining in the major barrel,

to facilitate its removal.

The pig launcher/receiver of the gas export shall be installed on the horizontal direction.

The pig launcher/receiver and pig receiver shall have adequate basket inside for proper

pigging operation.

A system for collecting drainage from receivers, launcher and launcher/receivers shall be

provided.

Space, trolleys, carts or any device suitable for PIG handling shall be part of the

CONTRACTOR scope.

Two pressure indicators shall be installed in the pig trap. First one shall be installed before

reducer (near the closure) and the second one shall be installed after the reducer (between

reducer and block valve). These both pressure indicators shall be capable to indicate the

barrel operating pressure in the middle third of the scale range.

CONTRACTOR shall provide safety interlock device for pigging operations, such as key

interlock.

b) Piping Requirements


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b.1) With regard to OP01/OP02 (“trunkline” pair),OP03 to OP08 (satellite wells), GP01/GP02

(“trunkline” pair), GP05 to GP08 (“manifolded” wells) positions, topside piggable piping for

the service risers (including pig launcher) shall have their internal diameter minimum 4.00”

to maximum 6”.00. All bend radius shall be 30”. Adjoining bends or any two components or

features like Tees, Wyes shall be separated by straight spool pieces of pipe with the same

O.D and I.D and at least 3xD long each, where D is nominal diameter. The transitions

between topside pipes/subsea pipelines/components with different internal diameter shall be

made with chamfer of maximum angle of 15º with the centerline of the pipe.

b.2) With regard to OP01/OP02 (“trunkline” pair),OP03 to OP08 (satellite wells), GP01/GP02

(“trunkline” pair), GP05 to GP08 (“manifolded” wells), IWAG01 to IWAG06 (“WAG loop”

wells), IW01/IW02 (“trunkline” pair), and IW04 (satellite well)positions, topside piping for the

production/water injection risers, including pig launcher/receivers, shall have their internal

diameter minimum 6.00” to maximum 8.00”. All bend radius shall be 40”. Adjoining bends or

any two components or features like Tees, Wyes shall be separated by straight spool pieces

of pipe with the same O.D and I.D and at least 3xD long each, where D is nominal diameter.

The transitions between topside pipes/subsea pipelines/components with different internal

diameter shall be made with chamfer of maximum angle of 15º with the centerline of the pipe.

b.3) With regard to GP03 and GP04 positions, topside piping for the water injection riser

lines, including pig launcher/receivers, shall have their internal diameter minimum 6.00” to

maximum 8.00”. All bend radius shall be 24”. Adjoining bends or any two components or

features like Tees, Wyes shall be separated by straight spool pieces of pipe with the same

O.D and I.D and at least 3xD long each, where D is nominal diameter. The transitions

between topside pipes/subsea pipelines/components with different internal diameter shall be

made with chamfer of maximum angle of 15º with the centerline of the pipe.

b.4) Piping for the gas export pipeline systems, including pig launcher/receiver, shall have

their internal diameter minimum 10,5”. All bend radius shall be 53". Adjoining bends shall be

separated by straight spool pieces of pipe with the same OD and ID and at least 3xD long

each, where D is nominal diameter. The transitions between topside pipes/subsea

pipelines/components with different internal diameter shall be made with chamfer of

maximum angle of 15º with the centerline of the pipe.

b.5) All topsides piping, free access areas, launcher and launcher/receiver nominal/internal

diameter and length shall comply with the following requirements of the NBR 16381 and shall


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be submitted to PETROBRAS comments/information before placing orders. A Preliminary

General Arrangements representing the required free access areas shall be also submitted

to PETROBRAScomments/information.

b.6) In addition, CONTRACTOR may be required to perform a pig test in the yard to

demonstrate that the pig can freely (without any damage) pass through each piping of the

service and production pipeline systems.

CONTRACTOR shall also consider topside piping sizing (internal diameter) to handle flow

rates required.

All the pig launcher/receivers, pig launchers and pig receivers installations implies in

providing facilities to inject lift-gas to push the pigs, as well as other fluids required. It means

that the topside manifolds shall allow to leak test the risers with water, circulate diesel with

or without pigs and push pigs using lift gas also.

All of those subsea service operations (diesel circulation, leak test, pigging, etc.) shall be

done using facilities onboard. CONTRACTOR shall take into account the requirements of

those operations, for example, volume control, pressure control, etc.).

The unit shall have facilities and space to allow the injection of nitrogen in risers/subsea

system. The NGU (Nitrogen Generator Unit) will be supplied by PETROBRAS (aproximatley

3 skids of 2.6 x 6.3m demanding air, water and electricity).

Well service system requirements:

The Unit shall be able to inject diesel, an ethanol or MEG bed, oil from the cargo tanks and

seawater in each of the production, injection and servicelines.

The well service system shall be able to circulate fluids in order to prevent hydrate, perform

pig passage, bull heading and circulate during commissioning (dewatering) with or without

pig.

The system shall be also able to perform pressurization after production stop, pressurization

to equalize WCT valves pressure and pressurization to equalize DHSV. The system shall be

composed by two different sets of pumps in order to perform high flow rate operations (e.g

circulation) and low flow rate operations (e.g pressurization).

The diesel, oil and seawater feed lines shall be provided with double block and bleed.


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Facilities shall allow use of service gas in one producer well with controlled flow and injection

of diesel in other wells simultaneously.

Whenever necessary the well service system shall be prompt to be used.

Removable spools are not acceptable.

The service pumps and tanks for high flow rate operations shall be sized for a total flow from

12 up to 360 m3/h of diesel at maximum operational discharge pressure of 32,000 kPa(a).

The service pumps range shall not comprise low very flow and very high pressure, related

to piping leak test services. This application shall be attended by separated pump (leak test

pump). The service pump shall have a flow fiscal metering, and a design pressure of 34,500

kPa(a). Flow control shall be obtained by variation in pump speed with a variable speed drive

without supplemental bypass. An arrangement of 3 x 33% to the high flow rate service pump

is required.

A spare connection from lay-down area to downstream of well service pump shall be

available to allow connection (chicksan) of a rented service pump (including connections for

supply to rented pump tank). This spare connection shall also be prepared to perform with

special operations fluids (squeeze, xylene, etc.).

An additional pumps arrangement of 2 x 50% to the low flow rate operations (lines

pressurization) shall be provided with a total flow rate of 4 m3/h of diesel at maximum

operational discharge pressure of 32,000 kPa(a). Flow control is not required.

The well service system shall have two different headers, one for positions OP1 to OP3 and

a second header for the remaining well positions as indicated in table 1.2.2.2. The system

shall have flexibility to align each pump to both headers, in order to allow the high flow rate

operation of two pumps dedicated to one header and the third pump dedicated to the second

header.

Protection filters shall be provided upstream each pumps suction, the filter specification shall

be according to manufacturer´s pump recommendation. For details about well service pumps

mechanical requirements, see Section 9.4.2.

For the diesel well injection operations and oil well injection operations, the well service pump

shall do the suction only from a dedicated non-structural atmospheric topsides diesel tank,

called as “diesel/oil wells service tank” . This tank shall comply with the following aditional

minimum requirements:


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The “diesel/oil wells service tank” shall be located in a Process Plant open area.

The diesel oil supplied to the “diesel/oil wells service tank” shall be a non treated diesel oil

from the diesel oil storage tanks .

The line conecting the engine room diesel oil storage tanks with the “diesel/oil wells service

tank” shall have a spool piece located as near as possible the “diesel/oil wells service tank”,

in a process plant open area

The “diesel/oil wells service tank” shall be an atmosferic tank with an indepent venting line.

The discharge of this venting line shall be located in a safe position.

The design of the well service injection system (including crude oil, MEG, Diesel) shall be

submitted to PETROBRAS appraisal.

Under no circumstances the system shall maintain the formation alined with the structural

tanks.

Special operations requirements:

• The Unit shall also be prepared to perform remote operations using pumps from Special

Purpose Boats (squeeze, xylene, etc.) to operate alongside of the FPSO. Therefore,

CONTRACTOR shall provide one permanent and dedicated 4” rigid line from the bunkering

station to be tied into to the discharge of the service pump. This line shall be designed

considering the pressure rate of the well service pump. During special operations service

pump shall be isolated to prevent contact with special fluids.

• The CONTRACTOR shall provide facilities to isolate and drain service line and also

flush topsides piping (using inert fluid) after the remote operation.

• The Unit shall have a special permanent support with access and railing located at

the side shell to fit the flexible lines coming from the special boat. Means for spill

containment must be provided at the support. The place where the platform will install

the special permanent support shall have structural capacity to support 18,000 kg.

The flexible line shall be fitted using the FPSO crane. The flexible line weight will be

12,000 kg.

• The CONTACTOR shall provide WECO 1502 connection adapter, 3 inch diameter, installed

at the permanent and dedicated injection line.


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CONTRACTOR shall guarantee the performance of pigging operation regarding pig velocity.

PETROBRAS is responsible for supplying those pigs during operational lifetime.

The gas-lift header shall allow individual injection to each gas-lift riser. Choke valves shall

be installed for each gas lift line to the wells. CONTRACTOR shall take into account the

requirements to control the flow rate at normal well production and during pigging operations.

An individual flow meter and pressure transmitter with indication in the Supervisory System

shall be installed for each gas-lift riser. For pigging purposes the gas flow rate shall be

controlled and totalized.

Facilities shall be provided to allow the depressurization of any riser, including production,

gas lift, gas injection and export gas pipeline with no production disturbance. These facilities

shall allow:

a) Depressurization of all oil production risers within 1 hour (considering the proposed

subsea arrangement issued by PETROBRAS) in order to avoid hydrate blockage;

b) Depressurization of all gas production risers within 12 hours (considering the proposed

subsea arrangement issued by PETROBRAS);

c) Depressurization of each gas lift riser within 1 hour and 30 minutes (considering the

proposed subsea arrangement issued by PETROBRAS), not ultrapassing 3 hours for

despressurization of all production gas lift risers;

d) Depressurization of gas exportation riser with no time constraint;

e) Control and monitoring the depressurization of production, gas lift, gas injection and

exportation risers at a rate up to 5.2 bar/min, according to operational procedure to be defined

by Petrobras.

Note 1: CONTRACTOR shall submit to PETROBRAS the documentation that shows that

requirements (a) through (e) were fulfilled.

Note 2: The design may consider the depressurization through the pig receiver.

Note 3: Facilities shall be provided to allow export gas pipeline depressurization through

fuel gas consumption (preferably) and through flare.

Note 4: CONTRACTOR shall consider maximum continuous burning flare capacity in order

to project lines and accessories for its operation.

Drainage shall be in accordance with the same philosophies of the process plant.


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Exported gas pressure shall be limited according to riser restrictions and exported gas flow

measured. CONTRACTOR shall foresee provisions to send instrumented pig to the gas

export riser.

CONTRACTOR shall take care during the design and construction phase to avoid any

pigging problems such as protruding welds inside piping or other arrangement that cause

risk to the pigging operation. Barred tees shall be provided on branch connections where the

I.D is greater than 2 inches for the piggable pipes.

Hard-piping, instrumentation, valves, etc. shall be fitted before FPSO sails away from

shipyard. The hard-piping shall be designed and routed in order to comply with table in Riser

and Bundle Characteristics item from Spread Mooring and Riser System Requirements.

FPSO shall have manifolds with well piping flexibility in order to ensure the following:

Figure 2.6.1.2 – Wells piping arrangement (production wells – oil or gas)

OP03 OP04OP01 and OP02 OP05 OP06 OP07 OP08

service header

gas lift header

oil production header

oil production test header

GP03 GP04GP01 and GP02

service header

gas lift header

gas production header

gas production test header

subsea gas manifold (well positions GP05 to GP08)

gas production header


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Figure 2.6.1.3 – Wells piping arrangement (injection wells – WAG and water inj. wells)

During early execution phase, PETROBRAS will submit to CONTRACTOR a Subsea

Operating Philosophy, including a preliminary description of all intended procedures for

Subsea operations. Design and operational philosophy is CONTRACTOR’s scope and shall

be sent to PETROBRAS for information / comments. CONTRACTOR to guarantee that these

operations are included in Risk Assessment Studies.

2.6.2. ARTIFICIAL ELEVATION SYSTEM


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A Subsea Multiphase Boosting System (SMBS) is planned to be installed in OP01/OP02

position (one system attending two wells) and produce to the FPSO. The SMBS consists of

a Subsea Pump Module that receives production from a production well and pump it to the

FPSO. The main additional interface between FPSO and SMBS is one integrated umbilical

and topside equipment to provide power and control to subsea (Figure 2.6.2.1).

Figure 2.6.2.1 – SMBS Topside Equipment Schematics

2.6.2.1. SMBS REQUIREMENTS AND INTERFACE CONNECTIONS WITH FPSO

Complete independent SMBS topside containers will be installed in the FPSO. Figure

2.6.2.1.1 shows a schematic of the interfaces between SMBS´s umbilical and topside

equipment with Unit facilities.


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Figure 2.6.2.1.1 – SMBS´s containers and umbilical schematic interfaces with Unit

facilities.

CONTRACTOR shall provide all supplies mentioned in Figure 2.6.2.1.1, as follows:

• HVAC cooling water

• HVAC drain

• High Voltage (HV) supply

• Low Voltage (LV) supply

• Low Voltage UPS supply

• Barrier Fluid (BF) drain (might be oil or water/MEG)

• Control Fluid drain

• Fire and Gas hardwired (2.6.2.6)

• PA/GA & Telephone

• ESD hardwired

• PSD hardwired

• CIS and CCR interface

• Chemicals

• Service air

• Fresh air intake

• Air outlet


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• Air supply for BF system

• Air supply for Control Fluid system

• High Voltage junction boxes

• Low Voltage junction boxes

• Fiber Optic (FO) junction boxes

• TUTU plates

2.6.2.3 AREA AND MATERIAL HANDLING

CONTRACTOR shall provide:

Overall free area: 150m2 (designed for 200 ton) – dimensions at least 10 x 15 m2;

The free area shall be located within a Non-hazardous Zone so called “Secondary SMBS

Lay-Down Area” convered by fixed crane provided by CONTRACTOR;

The area shall be covered by FPSO offshore crane capable to make an offshore lifting

operation of maximum 25 ton;

The “Secondary SMBS Lay-Down Area” if located adjacent to the FPSO main lay-down

area shall be provided with structural barriers to avoid damaging the SMBS containers

during any material handling operations.

Dedicated team and infrastructure providing support to all SMBS installation services in

the Unit, including but not limited to cable laying, scaffolding assembly, cable

interconnection and termination, material handling, equipment installation and fastening,

etc.

2.6.2.4 PIPING FACILITIES

CONTRACTOR shall provide the following infrastructure from Unit facilities to

“Secondary SMBS Lay-Down Area”:

• Service air supply: 02 (two) outlets independent lines N.D. 2” each;

• Fresh water supply: 02 (two) outlets independent lines N.D. 2” each;

• Instrument air supply: 01 (one) outlets independent lines N.D. 1” each;


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• Location of supplies in the Secondary SMBS lay-down area shall be mutually

agreed during early stage of the detailed design.

2.6.2.5 ELECTRICAL AND INSTRUMENTATION FACILITIES

CONTRACTOR shall provide [email protected] power factor to supply SMBS system.

CONTRACTOR shall provide the following infrastructure (circuit breakers, cables trays,

supports, junction boxes etc.) from LER to Secondary SMBS Lay-Down Area:

• 01 (one) High Voltage (HV) circuit breaker to protect SMBS feeder cables and

SMBS VFD input transformer: 10MVA – 3 phases – 60Hz – input voltage from

Unit main switchgear

• Redundant cabling (2x3off) for from HV Circuit Breaker to an Electrical Remote

Terminaion Unit for MODBUS communication between SMBS VFD and HV

Circuit Breaker

• Main power for SMBS VFD: 01 (one) Junction Box with 10MVA – 3 phases –

60Hz – operational voltage of the Unit generation power system;

• Auxiliary power for HVAC: 01 (one) Junction Box with 400-690V – 400kW;

• Auxiliary power for control: 01 (one) Junction Box with 110-230V – 200kW;

• UPS: 01 (one) Junction Box with 110-230V – 10kW.

CONTRACTOR shall provide the following infrastructure (cable trays, cables, supports,

junction boxes etc.) from “Secondary SMBS Lay-Down Area” to Riser Balcony Area:

• Space for installation of HV Junction Boxes (minimum 1500mm width, 2500mm

height and 500mm depth) at the “Secondary SMBS Lay-Down Area” and at the

Riser Balcony. HV Junction Box space at Riser Balcony shall be on top of

umbilical hang-off flange. Separate and exclusive cable tray connecting the HV

Junction Boxes shall be designed considering space, curves and angles for future

installation of up to 6 three-phase armoured cables of 3#180mm2@26/45(52) kV;

• LV Junction Box at “Secondary SMBS Lay-Down Area” (2 off) + LV electrical

cabling (2 off) on separate cable tray + LV Junction Box (2 off) at Riser Balcony


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Positions. Electrical Cable specification: 2 cables x 4 conductors x 16mm2,

1.8/3kV, Type: Twisted. Screened, Armored Quad. Junction Box insulation

voltage 3kV.

• FO Junction Box at “Secondary SMBS Lay-Down Area” (3 off) _ Fiber Optic

cabling (3 off) + at Riser Balcony. Fiber Optic Cable specification: Single Mode

Fiber Optic Cable (ITU-G.652), 3 cables, each containing 24 individual fibers

rating 9/125 µm, wavelength 1550nm.

NOTE: HV, LV and FO junction boxes as well as TUTU plate distance from the umbilical

shall be agreed with PETROBRAS.

CONTRACTOR shall also provide tubing for the Barrier Fluid HPU and for the SMBS Control

Fluid HPU from Secondary SMBS Lay-Down Area to Riser Balcony Area.

CONTRACTOR shall consider scope listed in item 7.5 for integration between SMBS

containers to FPSO CIS at Central Control Room.

CONTRACTOR shall provide proper means for hard-wired signals and serial links to FPSO

facility control system to “secondary SMBS lay-down area”.

2.6.2.6. SAFETY REQUIREMENTS

CONTRACTOR shall provide all safety equipment needed for Secondary SMBS Lay-Down

Area in accordance with applicable rules and standards, including but not limited to: fire

detection, gas detection at air intakes, manual alarm call point (MAC), fire extinguishers,

telecommunication means (PA speakers, telephone), safety signaling. Fire/gas detectors

and MAC shall be hardwired to the F&G System.

2.7. PROCESS FACILITIES

2.7.1. SEPARATION AND TREATMENT

Oil Separation and Treatment System capacity shall be 22,300 Sm³/d (~140,000 bbl/d) and

maximum oil production of 19,100 Sm³/d (~120,000 bbl/d).


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The oil processing shall be constituted of a stage of three-phase separator, pre-heater of

produced liquid (using the heat recovered from the processed oil), oil heater, degasser,

electrostatic pre-treater, degasser for RVP/TVP specification, electrostatic treater, and oil

cooler as shown in Figure 2.7.1.1. Two dedicated test separators for the oil and non

associated gas wells production test shall also be installed.

First separation stage shall be carried through two dedicated production trains, one for oil

production wells (Free Water KO Drum) and one for non associated gas production wells

(Inlet Gas Separator),

The producing oil wells will flow to the oil test and production headers. From there oil is sent

directly to a first stage three-phase separation, the Free Water KO Drum (FWKO), operating

at 1,300 kPa(a). For design purposes, CONTRACTOR shall consider carryover of up to 40%

water cut from FWKO. The separator shall be able to separate gas from oil and water, routing

the gas to the gas compressors (via KO Drum) and water to Produced Water system.

The producing non associated gas wells will flow to the non associated gas test and

production headers. From there, fluid is sent to a heat exchanger to reach minimum 40oC,

which is upstream first stage three-phase separation, the Inlet Gas Separator, that

operates at 1,300 kPa(a). The separator shall be able to separate gas from condensate

and MEG plus water, routing the gas to the gas compressors (via KO Drum) and the MEG

plus water back to MEG Regeneration system.

The minimum parameters to be considered in the design of the internals of the Inlet Gas

Separator, Free Water K.O. Drum and Test Separators are as follows:

1) Primary Separation Section: A foam breaking cyclonic device shall be installed with

bolts to allow easy removal for maintenance;

2) Devices for mist removal from the gas phase shall be installed, either the cyclone type

or a vane-type device. Facilities shall be provided to allow these internals removal for

cleaning purposes;

3) Anti-vortex devices of the cross plate type shall be installed at the oil and water outlet

lines;

4) Wave breaker devices;

5) Sand Jet System.


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The oil stream from the Free Water KO Drum is commingled with oil stream from Inlet Gas

Separator, so Oil System equipment downstream first separators shall be carried through

one production train. Oil stream from both separators are sent to be heated to reach the

treatment temperature. The operational oil treatment temperature for design purpose shall

be at least 90°C and CONTRACTOR may apply higher temperatures, if necessary, to meet

GTD requirements. For oil treatment, the maximum heating medium temperature shall be at

most 120°C. Production heater shall be shell and tube type. It will not be accepted plate type

for this service.

In order to help removing salt deposits and to help pre-treater performance during low BSW

production period,CONTRACTOR shall provide a dilution water injection upstream Oil/Oil

Pre-Heater and shall consider oil or produced water recirculation from electrostatic pre-

treater and production water from electrostatic treater to upstream FWKO. CONTRACTOR

shall consider oil recirculation to size Main Gas Compressor and VRU flowrates

The heated oil is sent to a flash vessel/electrostatic pre-treater, which has the function to

specify the outlet oil phase for the final stage of treatment, constituted by an electrostatic

treater, with addition of dilution water.

After the electrostatic pre-treater, the oil stream is sent to the electrostatic treater. Dilution

(deaerated fresh or deaerated desulphated) water must be added to the oil at the pre-treated

outlet to achieve the desired quality (less than 285 mg/L NaCl, BS&W< 0.5% and H2S < 1

mg/kg). It is not expected the need of any additional crude processing to meet this H2S

specification. The design shall include ability to inject H2S scavenger into the suction header

of the offloading pumps or upstream offloading metering skid.

Regarding the field instrumentation required for oil-water interface level measurement:

Standpipes shall not be used for oil-water interface level measurement neither in

Gravitational Separators nor in Oil Dehydrators. In such cases, the oil-water interface level

measurement shall be performed in the interior of the vessels, directly immersed in process

fluid, using one of the following technologies: energy absorption, nuclear or electric

conductivity profiler. For nuclear profiler, CONTRACTOR shall comply with “Resolução

CNEN 215/17” and is responsible for the collection, management, handling, temporary

storage and final disposal of any contaminated waste, including radioactive sources, due to

the use of this technology.


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The treated oil from the electrostatic treater is cooled in the oil/oil pre-heater and in the oil

cooler to reach the temperature of 40ºC. The stabilized oil will be metered and pumped to

the cargo tanks of FPSO.

The minimum parameters to be considered in the design of Electrostatic Pre-treater and

Electrostatic Treater, are as follows:

• The acceptable technologies are AC electrical field (vertical and horizontal flow),

combination of AC and DC (AC/DC) electrical field and Variable Frequency electrical

field.

• High velocity technologies, i.e., technologies that introduce the emulsion directly or

close to the electrodes zone, only will be accepted if the BSW at treater inlet is lower

than 20%, and will not be acceptable for pre-treater (the first stage of dehydration). In

this case, the charge for this treater shall be stable, i.e., with no flow variation.

• Devices to prevent vortex at water outlets shall be installed.

• For sample collecting in the interface region, 5 (five) try-cocks shall be installed.

• For each treater using Single AC Technology, AC/DC Technology or Variable

Frequency Technology, one spare transformer shall be supplied for each installed

one. The spare transformers shall be assembled on the vessel, ready to operation.

• The TAP switching operation of the electrostatic treaters transformers shall be done

through an external selector, to be performed without the transformer opening.

• Leak detection methods shall be provided between the bushings and each

transformer in addition to remote leakage alarm.

• Maintenance of the inlet bush shall be performed externally to the vessel, without the

need for internal access to it.

• Internals components shall be entirely and easily removable for cleaning and removal

of possible incrustations and deposits, or any required maintenance.

• Liquid distributors shall not be placed between the electrodes.

Oil processing plant heat exchangers, heaters and coolers shall be designed to guarantee

high availability in the oil treatment and shall be provided with by-pass lines. A minimum

configuration of 2 x 50% is required for them. Facilities for periodical cleaning of exchangers

shall be foreseen as well as all necessary equipment for cleaning in place (CIP) of equipment

CONTRACTOR shall consider slug volume (NLL to LAH of the vessel) in the FWKO

Separator, Inlet Gas Separator and Test Separators design (20.0 m3 for FWKO Separator


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and Inlet Gas Separator and 10.0 m3 for Test Teparators). The FWKO, Inlet Gas Separator

and Test Separators design shall consider wax crystals dispersed in oil phase.

Salt precipitation is expected. So Oil/ Pre-Heater and Production Heater shall have pipe

conections for chemical cleaning.

Optimizations on the Process described in items 2.7.1 and 2.7.3 or different solutions can be

accepted by PETROBRAS, provided the following:

• Same final specifications;

• Any different solution must be presented to PETROBRAS.

The Figure 2.7.1.1 present simplified proposed flow diagram of the Oil Processing scheme.

Equipment type and configuration presented are generic and does not refer to a specific

requirement for project design.

Figure 2.7.1.1 – Oil processing diagram

2.7.2. OIL TRANSFER SYSTEM


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The oil treated in the Process Plant shall be routed to the Fiscal Metering Station, and from

this station it shall be routed to the Loading System. For more details of the Loading System

see Section 16 – Marine Systems and Piping.

A network of remote actuated valves shall be installed for oil distribution to the cargo tanks,

so that tank filling is independent of tank discharging and cleaning operations.

2.7.3. GAS PROCESS PLANT

2.7.3.1 OBJECTIVES

The gas shall be gathered, treated and compressed, to comply with four main applications:

• transport to shore, through a gas pipeline;

• reservoir injection;

• fuel gas;

• lift gas for the producing wells.

The export gas pipeline operating pressure range in topside outlet is up to 32,000 kPa(a).

Proper device Control shall be installed at the Exportation Gas Compressors discharge

header to guarantee the required lift gas pressure level of 32,000 kPa(a), and send the

excess gas to the export pipeline.

CONTRACTOR must perform analysis of the composition of the gas (hydrocarbon up to

C6+, CO2 and N2) with portable chromatograph to the following streams, as a minimum:

• Test Separators gas outlet for well test (also H2S content shall be determined);

• 1st stage separation gas outlets (also H2S content shall be determined);

• Downstream Hydrocarbon Dew Point Unit

• Downstream Exportation Gas Compressor (Exported gas and Gas Lift header);

• Upstream Heavy Hydrocarbon Rich Stream Pump;

• Fuel gas;

• Gas to HP and LP flare tips (automatic vacuum sampler shall be provided).


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CONTRACTOR must perform analysis of the composition of the gas (hydrocarbon up to

C12+, CO2 and N2) with online chromatograph downstream Exportation Gas Compressor.

2.7.3.2 DESIGN CASES

Refer to Section 2.1.2

2.7.3.3 PROCESS CONFIGURATION

The gas treatment plant shall be designed according to Figure 2.7.3.3.1.

Figure 2.7.3.3.1 – Process Plant Overview

Gas WellsOil Separation and Treatment

Vapor Recovery Unit

(VRU)

ProducedWater

Treatment

Cargo

Tanks

Heavy HC Rich Stream Pumping

Gas Export

Main

Compression

Injection GasCompression

Gas Dehydration /HC DewPoint

Injection

Wells

Overboard

Injection

Exportation Gas Compression

Fuel Gas Lift Gas

Oil Wells

MEGRegeneration


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The gas treatment and compression system shall take into account all design cases on Table

2.1.2.1 and shall be able to operate in four (4) different modes, as follows:

MODE 1: Treated gas exportation and heavy hydrocarbon rich stream (C3+) injection

During this operation mode, all condensate resulted from Mechanical Refrigeration System

is injected into reservoir and treated gas will be consumed as fuel, compressed to be

exported and used as lift gas.

The required specification for exported gas shall be as Section 2.2.4 (MODE 1). The required

specification for heavy hydrocarbon rich stream (C3+) injection shall be as Section 2.2.5.

MODE 2: Gas exportation and partial heavy hydrocarbon rich stream (C3+) injection

This is the normal operating mode where part of condensate resulted from Mechanical

Refrigeration System is nominated to be commingled with treated gas stream upstream

Exportation Gas Compression and feed the export gas pipeline.

Condensate flow injected into gas stream shall be controlled in order to achieve hydrocarbon

dewpoint in treated gas as specified in Section 2.2.4 (MODE 2). Dewpoint measurement

shall be done via dew point analyzers located on gas pipeline in a point after the mixture of

streams. During this operation mode, hydrocarbon dewpoint shall be monitored and remain

in the range 20-25oC even with feed flow and/or composition changes.

The required specification for heavy hydrocarbon rich stream (C3+) injection shall be as

Section 2.2.5.

MODE 3: Rich gas exportation

During this operation mode, all condensate resulted from Mechanical Refrigeration System

is commingled with treated gas stream upstream Exportation Gas Compression and feed the

export gas pipeline and feed the export gas pipeline.

The required specification for exported gas shall be as Section 2.2.4.

MODE 4: Gas and heavy hydrocarbon rich stream injection

During this operation mode, all condensate from Mechanical Refrigeration System and part

of the gas, that is not consumed as fuel or used as gas lift, are injected into reservoir.


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For this operation, all non associated gas production wells are to be closed.

The required specification for gas to be injected shall be as Section 2.2.3. The required

specification for heavy hydrocarbon rich stream (C3+) injection shall be as Section 2.2.5.

The Figure 2.7.3.3.2 presents simplified proposed flow diagram of the GDU/HCDP Unit and

Heavy HC Rich Stream Pump Unit scheme.

Figure 2.7.3.3.2 - GDU/HCDP Unit and Heavy HC Rich Stream Pump Unit scheme

2.7.3.4 GAS SWEETENING UNIT (NOT APPLICABLE)

Not applicable.

2.7.3.5 DEHYDRATION/HYDROCARBON DEWPOINT UNIT (GDU/HCDP UNIT)

Main

Compression

GAS/LIQUID

EXCHANGER COLD SEPARATOR

COALESCER FILTER

HEAVY HC RICH

STREAM PUMP

REFRIGERATION SYSTEM

GAS/GAS

EXCHANGER

Exportation

Compression

MEG

Regeneration

MEG

CONDENSATE DRYER

CONDENSATE

COOLER

CONDENSATE

HEATER

HEAVY HC RICH

STREAM FLASH

VESSEL

(MODES 1, 4)

(MODES 2, 3) Injection

Wells


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The gas dehydration and hydrocarbon dewpoint shall be accomplished by a single

temperature reduction process with mechanical refrigeration plus MEG injection.

The unit comprises of minimum:

1) Gas/Liquid Exchanger

2) Gas/Gas Exchanger

3) Chiller

4) Refrigeration System

5) Three phase separator (Cold Separator)

6) Gas Coalescer Filter

7) Condensate Dryer

Warm inlet gas is cross-exchanged with out-going cold condensate and with out-going cold

dewpointed gas and then flows to the gas chiller. To prevent hydrates forming, MEG is

injected in the tubes at the warm end of both exchangers. CONTRACTOR shall install spray

nozzles in order to ensure proper distribution of MEG in the wet gas. The temperature of the

chiller is adjusted to condense both water and hydrocarbons from the feed gas. Fluid

refrigerant boils in the chiller at a very low, controlled temperature, removing heat from the

gas stream. The use of flammable refrigerant fluids such as propane, and toxic refrigerant

fluids, such as ammonia, are not acceptable. The cold gas exiting the chiller together with

the rich MEG solution and condensed hydrocarbons enters the Cold Separator. The rich

MEG is sent to MEG Treatment Unit where the water is removed. Cold condensate is sent

to pre-cool the incoming wet gas (tube side) and to remove residual water in Condensate

Dryer before heating to be pumped to reservoir and/or to be commingled with treated gas

stream. Cold dewpointed gas is sent to Exportation Gas Compressor after passing through

Coalescer filter to remove entrained droplets and pre-cooling the incoming wet gas (tube

side).

GDU/HCDP Unit shall be designed to achieve the gas specification as required in Sections

2.2.3 and 2.2.4, considering the necessary low temperature to condensate water and

hydrocarbons. The effect of water absorption after MEG injection shall not be taken into

account in the design of GDU/HCDP Unit. As 10 ppmv H2O content in gas specification is


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required in any mode operation, very low temperature (estimated as -35oC @ 4200 kPa (a))

shall be considered in Refrigeration System.

A minimum configuration of 2 x 50% is required for Gas/Liquid Exchanger, Gas/Gas

Exchanger, Gas Coalescer Filter and Condensate Dryer. Configuration of the Refrigeration

System shall consider a stand-by unit, including all equipments (chiller, compressor,

condenser etc.).

Machinery protection system for refrigeration system compressors shall be in accordance

with API 670.

The GDU/HCDP Unit shall be designed as following:

• Inlet gas specification (water content) = up to saturated.

• Inlet gas CO2 content = to be simulated.

• Inlet gas H2S content = to be simulated.

• Design gas flow rate = to be simulated.

• Outlet gas specification = as Sections 2.2.3 and 2.2.4;

• Outlet heavy hydrocarbon rich stream (C3+) specification = as Section 2.2.5.

For startup purposes, part of the gas from Cold Separator should be expanded and blended

with the expanded liquid stream, in order to help achieving the required inlet temperature in

the Liquid/Gas exchanger.

Water content (or water dew point) and hydrocarbon dew point online monitoring shall be

provided in the treated gas upstream Exportation Gas Compression and Gas Export

Pipeline. The analysers shall directly indicate the measured variable, avoiding internal

correction factor. The acceptable technologies are quartz crystal and "Tunable diode laser

absorption spectroscopy (TDLAS)".

The gas water content analyzer shall be adjusted to execute gas water content validation by

internal permeation tube (at least weekly check).

CONTRACTOR to provide supplier calibration of gas water content analyzer at least in a

period of one year or when it occurs some divergence during periodical check.


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CONTRACTOR shall provide a gas flow meter (transmitter), with local indication, upstream

GDU/HCDP Unit. The flow meter shall have flow and totalizing indication in the supervisory

system, with pressure and temperature correction at 20ºC and 101.3 kPa (a).

2.7.3.6. VAPOR RECOVERY UNIT (VRU)

The Vapor Recovery Units (VRU) shall be API-619 dry screw compressor type.

Gear box shall be in accordance with API 613.

Couplings shall be in accordance with API 671.

Machinery protection system shall be in accordance with API 670.

The mineral lube oil system shall be designed according to API 614 with the following typical

configuration:

• Main oil pump driven mechanically or by AC electric motor;

• Oil reserve pump driven by AC electric motor;

• Duplex heat exchanger;

• Duplex oil filter.

Note: The main lubricating oil pump, when mechanical, must be driven by the gearbox. In

case the pumps (main and reserve) have electric drive, they must be an essential load.

The VRU package supplier shall be the compressor OEM (original equipment manufacturer).

The compressor package shall be supplied with the OEM control system and with the built-

in protections. The OEM shall assume full responsibility for the design (architecture),

engineering, operational philosophy, control systems, instrumentation and PLC-based

safeguards. The operating philosophy shall consider the equipment start, stop, operate and

monitor from the UCP HMI and/or remote HMI installed in the Central Control Room. Every

HMI of VRU service, shall be able to operate any compressor of the same service.

Each unit unit shall be provided with a dedicated UCP (control unit panel) containing part of

the control and safety system hardware and interconnected to the remote I / O. Each UCP

must operate independently, so that failure of any component within UCP does not affect the

availability of any other UCP and / or other unit.


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The shaft seals shall be of bi-directional self-acting tandem dry gas seals (DGS) type with

intermediate seal gas labyrinth as per API 692. For the VRUs the primary seal gas shall be

fuel gas, nitrogen shall be used as primary gas seal back-up.

The primary seal gas shall be sufficiently clean to avoid particulate and its temperature far

from the dew point to avoid liquid condensation. Each compressor package shall include a

seal gas treatment system for each compressor barrel casing consisting, as a minimum, of

a separate vessel (KO drum), a booster compressor to provide the required positive feed

pressure to the seals on any start/operating/stop condition, one separator/coalescer duplex

filter and either one electric heater with spare heater element installed or, alternatively, a

duplex electric heater. This system shall be designed according to API 692 and shall be

supplied by the DGS manufacturer. O-rings and any other polymer-based sealing element

in contact with process gas shall be strongly resistant to explosive decompression taking into

account a large number of compressor starts/stops.

Nitrogen as the secondary seal gas shall be injected in the intermediate labyrinth seal. The

oil separation seal gas shall be nitrogen.

N2 and air utilities shall be foreseen for compressor package, e.g. DGS, instruments and seal

gas booster driver.

VRU simulated capacity shall be defined by CONTRACTOR, in accordance with all design

cases simulations and considering all recycles.

VRU suction pressure shall be higher than atmospheric pressure.

The design capacity shall be defined considering the flowrate as 120% of the simulated

capacity.

The compressor shall be designed for continuous operation at any flow rate between zero

and 100% of the design capacity.

A stand-by unit is required (2 x 100%).

Note 1: CONTRACTOR shall consider Unit as compressor machine, scrubber, coolers etc.

The driver shall be electric motor. The capacity control may be performed by VFD and/or

recycling. Variable Frequency Drivers (VFD) are not accepted for Screw Compressors with

electric demand greater than 5MW.

Clamp connections are not acceptable for process piping or compressor nozzles.


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Compressor and process piping connections shall be made through removable spools to

easy disassembly and removal of the compressors for maintenance.

A removable filter shall be provided at suction of each compressor stage. The filter element

replacement shall be possible to be done without piping disassemble.

CONTRACTOR shall consider one dedicated capacity controller for each compression

service and one dedicated load sharing controller for each compression train. The capacity

controller of each compression service shall be interconnected to allow the integrated action

with different services.

The master control and load sharing must be implemented in dedicated hardware (not shared

with other functions such as sequencing, protection, etc.) and specifically developed for this

purpose.The Load Sharing Control shall have an electrical power limit when the compressor

is driven by an electric motor.

CONTRACTOR shall design the compressor skids considering pressurized and

depressurized shutdowns.

There must be acoustic silencers for the suction and discharge of each compression stage.

Housing (Enclosure) of VRU shall be made of 316L stainless steel.

The gas process plant, the fuel gas and liquid system, the electrical and non-electric utility

systems must be capable of allowing the operation of all the machines of the same service

simultaneously, including the reserve machine. Load sharing control must balance the gas

flow to allow continuous operation of all compression trains in parallel and smooth load

transfer among them. Equipment shall be installed with the main axis aligned to logitudinal

FPSO axis.

The compressor OEM-supplied VRU package shall be composed of at least: machine skid,

control and protection panels, CCM, process skid, which shall include gas heat exchangers,

separator vessels, piping, silencers in the suction and discharge lines, blocking valves,

recycling valves, relief valves, instrumentation.

CONTRACTOR shall perform coupled closed loop test run with inert gas (nitrogen) in all

topsides gas compressors/drivers as part of FPSO’s commissioning and Provisional

Acceptance Tests prior sail-away to final offshore location. Procedure of this test shall be

included in project documentation. OEM supervision for this test shall be foreseen and


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included in purchase scope. Any deviation due to a mandatory and reasonable motivation

on this requirement shall be submitted for PETROBRAS appraisal.

CONTRACTOR shall provide a gas flow meter (transmitter), with local indication,

downstream each compressor. It shall not be associated with anti-surge control system. The

flow meter shall have flow and totalizing indication in the supervisory system, with pressure

and temperature correction at 20ºC and 101.3 kPa(a).

2.7.3.7. CENTRIFUGAL GAS COMPRESSORS

All centrifugal gas compressors shall be radially split, designed according to API 617-Part 2

and comply with ASME PTC-10. Couplings shall be in accordance with API 671.


The mineral lube oil system shall be design according API 614 with the following typical

configuration:





Note: The main lubricating oil pump, when mechanical, must be driven by the gearbox /

HVSD or by the turbine shaft. In case the pumps (main and reserve) have electric drive, they

must be an essential load.

The compressor packages supplier shall be the compressor OEM (original equipment

manufacturer). Additionally, all compressors shall be supplied by the same OEM.

The compressor package shall be supplied with the OEM control system and with the built-

in protections. The OEM shall assume full responsibility for the design (architecture),



monitor from the UCP HMI and/or remote HMI installed in the Central Control Room. Every

HMI of a specific compression service (Main, Exportation and Injection), shall be able to

operate any compressor of the same service.


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Each unit unit shall be provided with a dedicated UCP (control unit panel) containing part of

the control and safety system hardware and interconnected to the remote I / O. Each UCP

must operate independently, so that failure of any component within UCP does not affect the

availability of any other UCP and / or other unit.

The shaft seals shall be of bi-directional self-acting tandem dry gas seals (DGS) type with

intermediate seal gas labyrinth as per API 692.For the Main, Exportation and Injection gas

compressors the primary seal gas shall be treated and conditioned from compressor

discharge process gas.

The primary seal gas shall be sufficiently clean to avoid particulate and its temperature far

from the dew point to avoid liquid condensation. Each compressor package shall include a

seal gas treatment system for each compressor barrel casing consisting, a minimum, of a

separate vessel (KO drum), a booster compressor driven by pneumatic air to provide the

required positive feed pressure to the seals on any start/operating/stop condition, one

separator/coalescer duplex filter that allows online filter changeover and either one electric

heater with spare heater element installed or, alternatively, a duplex electric heater. This

system shall be designed according to API 692 and shall be supplied by the DGS

manufacturer. O-rings and any other polymer-based sealing element in contact with process

gas shall be strongly resistant to explosive decompression taking into account a large

number of compressor starts/stops.

Nitrogen as the secondary seal gas shall be injected in the intermediate labyrinth seal. The

oil separation seal gas shall be nitrogen.

N2 and air utilities shall be foreseen for compressor package, e.g. DGS, instruments and seal

gas booster driver.

Recycle system for anti-surge control shall be of “hot recycle” type, meaning that there is no

cooler or scrubber vessel installed in between the compressor discharge and the related

recycle valve. CONTRACTOR shall consider one antisurge recycle line for each stage.

Overall recycle line shall not be accepted.

The condensate from inlet, inter-stage and final compressor stage collected on the scrubber

vessels shall be routed to the oil plant or to upstream gas scrubbers. They shall not be sent

to slop or drain system.


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The compressors shall be designed for continuous operation from full recycle to full capacity

(0 to 100%), considering all the design cases.

An electronic decoupling algorithm (decoupling control) shall be used to avoid interaction

between anti surge control and capacity/load sharing control for each train compressor

service. A similar control strategy shall be designed in order to avoid cascade trips from

different service compressor.

Each compressor train shall include a self lube oil system and control process panel

Extraction or injection of gas streams from or into compressor casing is not acceptable,

except for self-sealing gas.

CONTRACTOR shall consider the molecular weight range corresponding to all design cases.

Shared driver is not acceptable between compressors of different services.

CONTRACTOR shall perform coupled closed loop test run with inert gas (nitrogen) in all

topsides gas compressors/drivers as part of FPSO’s commissioning and Provisional

Acceptance Tests prior sail-away to final offshore location. Procedure of this test shall be

included in project documentation. OEM supervision for this test shall be foreseen and

included in purchase scope. Any deviation due to a mandatory and reasonable motivation

on this requirement shall be submitted for PETROBRAS appraisal.

Clamp connections are not acceptable for process piping or compressor nozzles.

Compressor and process piping connections shall be made through removable spools to

easy disassembly and removal of the compressors for maintenance.

A removable filter shall be provided at suction of each compressor stage. The filter element

replacement shall be possible to be done without piping disassemble.

The mineral oil system shall be unique and be used to lubricate the entire centrifugal

compressor package, ie the oil shall be the same for the driver, gearbox/HVSD and

compressor, except for aeroderivative turbines, which use synthetic oil.

The anti-surge recycle valves and associated instrumentation (flow, pressure and

temperature transmitters, positioner and booster) of anti-surge system must be specified and

certified by the anti-surge control system supplier, as well as the throttle valve and check-

valve, when applied.


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A double check-valve shall be installed on process pipe in order to segregate every

compressor casing.

CONTRACTOR shall consider one dedicated capacity controller for each compression

service and one dedicated load sharing controller for each compression train. The capacity

controller of each compression service shall be interconnected to allow the integrated action

with different services.

Antisurge Controler shall have an algorithm to compensate automatically molecular weight,

pressure and temperature changes on suction conditions in order to make the surge control

line independent of suction conditions variations of the compressor.The Antisurge Controler

shall have adaptive actions that allow the displacement of the surge control line as a function

of the displacement rate of the operating point, with automatic return to the original position,

as well as open loop correction action when the operation is between the surge control line

and the surge line.

The master control, load sharing and anti-surge system must be implemented in dedicated

hardware (not shared with other functions such as sequencing, protection, etc.) and

specifically developed for this purpose.The Load Sharing Control shall have an electrical

power limit when the compressor is driven by an electric motor.

The load-sharing system shall allow the parallel or individual operation of the compressors.

During parallel operation, the system must divide the load by keeping the compressors at

operating points equidistant from the surge control lines.

CONTRACTOR shall design the compressor skids considering pressurized and

depressurized shutdowns.

Shutdown Valves (SDVs) at gas inlet and outlet of each compressor package shall be

provided, as well as at the scrubbers condensate outlet pipings, in order to isolate the

machine. It shall be evaluated the need of installing additional SDVs.

A final aftercooler shall be provided for each compressor package.





transfer among them.


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Equipment shall be installed with the main axis aligned to logitudinal FPSO axis.

CONTRACTOR shall provide a gas flow meter (transmitter), with local indication, upstream

and downstream each compressor. It shall not be associated with anti-surge control system.

The flow meter shall have flow and totalizing indication in the supervisory system, with

pressure and temperature correction at 20ºC and 101.3 kPa(a).

2.7.3.7.1 MAIN GAS COMPRESSOR

The first step compressors shall be designed according to the following:

• inlet pressure = 1,000 kPa(a) (estimated, depends on previous pressure drop and to be

confirmed by CONTRACTOR);

• discharge pressure range = to be defined by CONTRACTOR;

• A stand-by unit is required.

• The compressors shall be designed to continuous operation for any flow rate between

zero and 100% of the design capacity (full recycle), considering all design cases.

A Safety K.O. drum shall be installed upstream Main Gas Compressor, in order to separate

the condensate formed due to inlet gas cooling and carried droplets, as well as to avoid any

liquid carried-over. This condensate shall be routed to second stage oil separation system.

Under no circumstances it shall be sent to the slop or drain system.

The Safety K.O. drum design, as a minimum, CONTRACTOR shall consider:

• Three devices (three individual separation stages) to ensure the required gas-liquid

separation:

o Inlet device to receive the incoming process stream and evenly distribute the flow

to improve gravitational liquid separation in the vessel inlet zone;

o Mesh or Vane device to separate large liquid droplets, drain it the liquid without

re-entrainment;

o Demisting cyclones to ensure high efficiency of droplet removal;

• The maximum condensate liquid increased of 5% of gas mass flow;


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2.7.3.7.2 EXPORTATION GAS COMPRESSORS

The second step compressors shall be designed according to the following:

• capacity and gas compositions = according to process simulations for all design cases

and Operation Modes;

• inlet pressure = to be defined by CONTRACTOR;

• discharge pressure = 32,000 kPa(a) at the top of the lift gas risers;

• Operating temperature downstream discharge cooler= 40-55ºC;

• A stand-by unit is required;



A Safety K.O. drum shall be installed upstream Exportation Gas Compressor, in order to

separate the condensate formed and carried droplets, as well as to avoid any liquid carried-

over. This condensate shall be routed to second stage oil separation system. Under no

circumstances it shall be sent to the slop or drain system.

The Safety K.O. drum design, as a minimum, CONTRACTOR shall consider:

• Three devices (three individual separation stages) to ensure the required gas-liquid

separation:

o Inlet device to receive the incoming process stream and evenly distribute the flow

to improve gravitational liquid separation in the vessel inlet zone;

o Mesh or Vane device to separate large liquid droplets, drain it without re-

entrainment;

o Demisting cyclones to ensure high efficiency of droplet removal;

• The maximum condensate liquid increased of 5% of gas mass flow;

Gas Lift take off point shall be downstream Exportation Gas Compressor.

2.7.3.7.3 INJECTION GAS COMPRESSORS

The second step compressors shall be designed according to the following:


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• capacity and gas compositions = according to process simulations for all design cases

and Operation Modes;

• inlet pressure = 32,000 kPa(a) (estimated, to be confirmed);

• discharge pressure = 52,000 kPa(a) at the top of gas risers;

• Normal operating temperature downstream discharge cooler= 40ºC;

• A stand-by unit is required;



2.7.3.7.4 CENTRIFUGAL COMPRESSOR DRIVERS

Electric motors with speed variation or gas turbines (designed according to API 616 and

comply with ASME PTC-22) are acceptable as compressors drivers.

For electrical motor power limit see 8.2.3.

For speed variation with electric motor driver the preferred solution is a Hydraulic Variable

Speed Driver. Variable Frequency Drivers (VFD) are not accepted for Centrifugal

Compressors with electric demand greater than 5MW.

If Gas Turbine is selected as the driver option for the compressors which process the fuel

gas, than such turbine shall be of dual fuel (gas and diesel) type, unless the turbine is capable

to start-up on low pressure fuel gas from the production gas separators (boot-strap option).

Gas turbine with ISO Power greater than 25000kW shall be aeroderivative type. Gas turbine

with ISO Power lower then 25000kW shall be aeroderivative or industrial type.

The fuel gas and liquid fuel for the gas turbines shall be properly treated to comply with the

gas turbine manufacturer requirements.

The gas turbine combustor shall be of the standard type. Multiple fuel manifolds for low

emission control are not acceptable. Radioactive components are prohibited. Turbine

housing (Enclosure) firefighting system shall be water mist type.

For the calculation of the maximum power at driver shaft the following factors and equation

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- Mechanical losses in the compressor (efficiency of 0.995 F1);

- Mechanical losses in the gearbox (efficiency 0.985 F2) or HVSD (efficiency 0.925 F3);

- Losses related to degradation of the compressor F4 (dP <60 bar efficiency 0.98 or 60 bar

<dP <150 bar efficiency 0.97 or dP> 150 bar efficiency 0.96); (dP = the differencial pressure

across division wall or the differencial pressure across balance piston, whichever is higher.

In case of multiple casings evaluate each one and use the highest value)

- API margin 110% (for electric motor);

- Turbine degradation losses (efficiency of 0.97 F5);

- Fouling losses of the turbine compressor (efficiency of 0.98 F6);

- Loss on admission and exhaustion without WHRU (efficiency of 0.98 F7) or with WHRU

(efficiency of 0.97 F8);

- Derate referring to the ISO temperature correction for Site (at 30oC efficiency of 0.85 F9);

Electric motor power = 1.1 x Gaspower (max) / [F1 x (F2 or F3) x F4]

Turbine ISO power = Gaspower (max) / [F1 x (F2 if applicable) x F4 x F5 x F6 x (F7 or F8) x

F9]

Selected Electric motor and Turbine shall exceed the maximum power required on the drive

shaft as calculated above.

A demineralized water circuit shall be available for each gas turbine module for feeding the

on-line / off-line washing system.

In the case of shutdown without electric power, the lubrication during coastdown time must

be provided by a run-down tank or a pump driven by the gearbox/ HVSD. DC-powered pump

is acceptable only for post-lube (cooldown time), as long as the OEM also provides the entire

battery system and other accessories for its operation. The proposed system shall have

sufficient capacity to withstand the required cooldown time, including care of the intermittent

drive of the DC pump, throughout the cooling period.





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High speed systems are not accepted for the stages of filtering combustion air / ventilation

air turbine, except for the stages of inertial separation.

Air combustion filtering system for gas turbines shall be submitted for Petrobras.

The access around the combustion air filter box of the turbines shall be sufficient spacious

and shall have a hoisting device to move the air filter elements for the replacement task.

Housing (Enclosure) of gas turbine shall be made of 316L stainless steel.

2.7.3.8. OTHER REQUIREMENTS

Utilities (including power generation system) shall be designed considering at least the

capacity of 10,000,000 Sm3/d, representing the produced gas including lift gas, for the

compression system.. All internal recycles from process plant shall be added to this flowrate

to define the total compression capacity.

2.7.3.9. GAS PIPELINE AND KEEL-HAULING RISERS PRE-COMMISSIONING

Pre-commissioning of the gas export pipeline and other keel-hauling pipelines shall occur

after pull-in of risers (and pull-in of umbilicals for respective subsea ESDV’s control, when

applicable) and will be PETROBRAS scope of work (performed from the subsea PLET in

direction to the FPSO).

The unit CONTRACTOR shall provide space on deck (PETROBRAS estimates area with

dimensions of 10m x 10m in the keel-hauling risers region or very close to it) to receive and

storage the provisional Pig receiver and other equipment (piping/hoses, storage tanks,

manifolds, chokes, silencer and valves) from a vessel to the Unit and subsequent internal

movement to enable it to be assembled on the “dry” extremity of the respective hard pipe.

This temporary set of equipments (provided by the pipelines installer) will be used for the

water discharge, MEG recovery/storage, N2 discharge (all under internal pressure) and pig

receiving.

The pipeline installer personnel shall be responsible for all the provisionals equipments

assemblies, and CONTRACTOR shall be responsible for the permanent hardpiping

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Provision should be made for the necessary support and access for the personnel who will

execute the PLR and other equipment/piping assembly and operations during the keel-

hauling risers/pipelines pre-commissioning (it will be executed by the pipeline installer) and

the availability of resources for SLWR installer (Compressed air, water and electricity ) on

board the FPSO.

The Unit shall be prepared to handle properly the residual inert gas and drain from the keel-

hauling risers/pipelines during pre-commissioning.

CONTRACTOR shall consider extra POB for personnel – 8-off (3rd party, subcontractor,

pipeline installer) onboard FPSO during keel-hauling risers pre-commissioning (dewatering,

drying and nitrogen purging procedures).

CONTRACTOR shall be responsible only for the part of the commissioning procedure that

requires operations and support personnel onboard the FPSO. The procedure will be issued

by PETROBRAS.

2.7.3.10. MEG TREATMENT UNIT

Contractor shall design a Mono Ethylene Glycol (MEG) Treatment Unit in order to inject

continuously MEG into non associated gas production wells and in dehydration/hydrocarbon

dewpoint unit .

The MEG Treatment Unit (MTU) shall be designed as following:

• Lean MEG injected into Christmas Tree: 300 m3/d (total);

• Lean MEG injected into Christmas Tree: 100 m3/d (per well);

• Lean MEG injected in gas dewpoint control: to be calculated by CONTRACTOR.

Minimum value to be adopted: 150 m3/d;

• Design capacity shall be defined by CONTRACTOR. Minimum capacity: 500 m3/d;

• Inlet stream of Rich MEG specification (MEG content): calculated by CONTRACTOR;

• Lean MEG specification (MEG content): 84 – 90 wt% concentration

• Lean MEG salt content: maximum 0.5 g/l;

• Lean MEG maximum particulate diameter of 70 µm;

• Effluent Water MEG content: < 500 mg/L. It shall comply with CONAMA Resolutions

393/2007;

• MEG injection pump pressure (into reservoir): 69,000 kPa(a);


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• Maximum MEG loss: 0.5% of the MEG feed rate

Salt contents in water from non associated gas production wells:

Table 2.7.3.10.1: Produced water composition

Components (mg/L)

pH 7.4

K+ 111

Na+ 7330

Ca++ 278

Mg++ 57

Ba++ 22

Sr++ 35

Fe total <0.1

Cl- 14916

SO4-- 32

The MTU consists of three distinct processing steps that are the Pre-treatment,

Reconcentration and the Reclamation (Desalting) sections. The MEG system also includes

an injection line with MEG pumps and monitoring system for hydrate control.

Machinery protection system for MEG Injection pumps shall be in accordance with API 670.

CONTRACTOR shall provide storage tanks for lean MEG and for rich MEG. Rich and lean

MEG tanks shall be internally split into two tanks, to allow proper cleaning. Capacity of

storage tanks shall be able to allow continuous lean MEG injection during at least one day

of operation, in case of MTU shutdown. Rich MEG tank capacity shall be designed

considering lean MEG capacity plus maximum produced water volume.

The non associated gas production wells can produce water with a salt content up to 80,000

ppm and specific monitoring system shall be provided in order to detect free water

production. Condensed water is also expected. For design purposes, CONTRACTOR shall

consider a maximum of 200 m3/d of produced water with 80,000 ppm salinity, for the total

set of non associated gas production wells.


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The main purpose of the MTU is to remove produced and condensed water from the rich

MEG, and remove salts and other impurities that can be harmful to the MEG equipment and

piping.

The Pre-treatment and the Reconcentration section shall be designed for the maximum rich

MEG flow. The MEG Reclamation section shall be able to process at least 25% of the total

Rich MEG design flow rate but it is CONTRACTOR responsibility to define the design

capacity of the Reclamation section to comply with the maximum requirement for desalting

at lean MEG.

It is CONTRACTOR responsibility to propose the best process solution to comply and

optimize the process requirements of this specification. Any deviations shall be clearly

justified and shall be analyzed and approved by PETROBRAS.

All equipment that may need frequent cleaning shall be provided with a stand-by (MEG

Cartridge/Coalescing/Charcoal Filters, Lean/Rich MEG Exchanger, Pre-Flash Heater, Pre-

Flash Pump, Recycle Pump, Recycle Heater, Salt Pump, Centrifuge, Vacuum Pump, Lean

MEG Pump). The piping of the unit shall have flanged spools and tie-ins connections and

facilities for easy cleaning operation.

Nitrogen or other inert gas blanketing system shall be provided in all vessels, tanks and

equipment where the operation pressure is close to atmospheric.

All equipment mentioned in this Specification, as well as any other additional equipment

deemed necessary to comply with the process Requirements, shall be included in the MTU

supplier scope.

CONTRACTOR shall update equipment identification according to the selected technology.

Data from chemical injection package shall be available at Supervision and Operation

System (SOS) and also on PI onshore. Also, information from chemical injection flow meters

shall also be available for MCS, as an input for subsea multiphase flow meters.

2.7.3.10.1 PRE-TREATMENT SECTION

The MTU is fed with a stream of rich MEG from two different spots: from the process plant

Inlet Gas Separator, which operates at a maximum pressure of 5000 kPa(a) and a maximum

temperature of 30°C, and from Cold Separator which operates at 4200 kPa(a) and -35°C.


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The Pre-Treatment shall prepare the rich MEG for reconcentration by:

• Separating hydrocarbon gas and liquid in the Low Pressure Separator.

• Precipitating low solubility salts (such as CaCO2 and other divalent cations salts) by

chemicals adjustments.

• Separating low solubility salts by filtering in the MEG Cartridge/Charcoal Filters.

• Buffer volume for process stability.

The LP Separator shall be designed with a residence time of at least 10 minutes. The LP

Separator shall have pressure control valves to send out the flashed gas to the Vapor

Recovery Unit (VRU). The LP Separator shall be designed considering the following

scenarios: gas blow-by or condensate carry over coming from the Inlet Gas Separator and

Gas Test Separator.

The vent tower of MTU shall be evaluated in the gas dispersion study considering the

following scenario: gas blow-by or condensate carry over coming from the LP Separator.

The filters shall have: quick opening devices, block valves and globe by-pass valves,

differential pressure indication and alarm at the control room, suitable space and handling

facilities to allow proper change of filtering element.

2.7.3.10.2 RECONCENTRATION SECTION

Rich MEG is heat exchanged against the lean MEG before water is removed in a hot water

heated reboiler (Pre-Flash Heater). The Lean/Rich MEG Exchanger shall have block valves

and tie-ins connections with blind flange upstream and downstream for cleaning purpose.

The coil bundle of Pre-Flash Heater shall be retrievable and there shall be suitable space

and handling facilities to remove it.

MEG is stripped in the Pre-flash Column to keep the MEG content in the effluent steam below

500 ppm.

The Pre-flash Column shall use randomic metallic type packing. All removable internals shall

be designed to permit easy installation and withdrawal through the manhole.

Lean MEG leaves the bottom of Pre-flash Column and is pumped out (Pre-Flash Pump) for

reclamation.


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Slip stream operation mode (bypass of reclamation section) is allowed, but the piping and

equipment of reclamation section shall be designed considering the maximum flow rate

capacities (full stream operation mode).

The vapor from the top of Pre-flash Column is routed to LP Flare.

2.7.3.10.3 RECLAMATION SECTION

The purpose of the reclamation section is to remove high solubility salts from the lean MEG.

Part of the lean MEG from reconcentration section is fed to the Flash Separator. The Flash

Separator operates at vacuum (vacuum level shall be defined by CONTRACTOR) and

temperature normally varies from about 110 to 130°C. Energy to vaporize the feed is

introduced through a recycle stream which is pumped by the Recycle Pump from the bottom

of the Flash Separator, heated 10°C in the Recycle Heater, and return to the Flash Separator.

The recycle flow rate shall be defined by CONTRACTOR.

The Recycle Heater shall have block valves and tie-ins with block valves and blind flange

upstream and downstream for cleaning purpose. The recycle piping shall have heat tracing

The increase temperature and the pressure drop to near vacuum causes flashing of the feed.

Because all of the incoming liquid is vaporized, the dissolved solids, such as salt, precipitate

out of solution and form crystals that then accumulate in the pool of salty liquid MEG in the

Flash Separator.

These particles descend into the Brine Displacement salt removal system connected to the

bottom nozzle of the Flash Separator. CONTRACTOR shall design and supply the MTU with

the two techniques to remove the solid products: settling tanks and centrifuges. The Brine

Displacement salt removal comprises Salt Tank, Salt Pump, Centrifuge and Salt Dissolving

Tank.

The removed salts from the centrifuge shall be conveyed to collecting tanks and then

disposed. The Brine Displacement salt removal system shall be also designed to allow

dilution of the removed salts with water from the Reflux Drum in the Salt Dissolving Tank

before disposal to overboard. The produced salt cake/brine shall comply with CONAMA

Resolutions 393/2007. The Salty MEG centrate shall be sent to Flash Separator in order to

reduce MEG losses.


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The evaporated MEG and water from the Flash Separator is routed to the Distillation Column

which shall be fitted with structured packing. All removable internals shall be designed to

permit easy installation and withdrawal through the manhole.

The vapour exiting overhead is condensed in a cooling water Condenser. The condensed

stream and some non-condensable vapour are collected and separated in the Reflux Drum.

The condensed water from Reflux Drum is pumped back to the Distillation Column by Reflux

Pump. Other part of the condensed water is sent off-skid for disposal and is used for

dissolving salt in the Salt Dissolving Tank as mentioned before.

To provide and control the vacuum in the reclamation section, the Vacuum Pump draws the

non-condensable from the Reflux Drum to a liquid Knockout Vessel. The discharge from the

Vacuum Pump is routed to LP-Flare or Atmospheric Vent. The vent shall be proper located

in order to allow dispersion of non-condensable gas and to avoid condensate steam spill

over the FPSO.

All equipment operating with vacuum shall be mechanically design for full vacuum. An

oxygen scavenger chemical injection system shall be provided upstream the equipment that

operate under vacuum. An oxygen monitoring system shall be provided. This system shall

comprise a sampling point to allow laboratory analysis and an online oxygen analyzer.

The bottom product of the Distillation Column is a lean dry MEG at a concentration of at least

90 wt%. The produced lean MEG shall be pumped by Lean MEG Pump and mixed with the

other lean MEG stream from the bottom of Pre-flash Column. This total lean MEG stream

shall be cooled before storage by heating the inlet feed of the regeneration section in the

Lean/Rich MEG Exchanger.

A chemical injection system for pH control shall be provided, using MEA, MDEA or other

neutralizing amine, to allow control of the pH of the MEG stream in order to avoid corrosion.

The Figure 2.7.3.10.1 presents a simplified proposed flow diagram of MTU. Equipment type

and configuration presented are generic and does not refer to a specific requirement for

project design.

Optimizations on the process described in item 2.7.3.10 or different solutions providing the

same specifications can be proposed by CONTRACTOR and must be submitted to

Petrobras approval.

Flow measurement instruments shall be installed in:


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• rich MEG stream inlet MEG unit;

• recycle streams and the produced water stream;

• lean MEG stream;

• bypass stream from reclamation section, when applicable.

Figure 2.7.3.10.1 – Simplified Diagram for MEG Treatment Unit (MTU).

2.7.3.11. HEAVY HYDROCARBON RICH STREAM (C3+) PUMP

The condensate (heavy hydrocarbon rich stream) from GDU/HCDP Unit shall be heated to

reach the temperature of 90ºC and collected on a flash vessel (Heavy HC Rich Stream Flash

Vessel) in order to separate the gas formed due to inlet gas cooling and carried droplets, as

well as to avoid any gas carried-under. This gas shall be commingled with treated gas

upstream Exportation Gas Compressor and/or pumped to reservoir.

Heavy Hydrocarbon Rich Stream (C3+) pumps shall be able to inject condensate into

reservoir at 52,000 kPa (a) and/or send it to be commingled with treated gas stream at 32,000


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kPa (a), according to mode operation (Section 2.7.3.3). CONTRACTOR shall install stand-

by pumps to guarantee continuous performance. For details about equipment requirements,

see Section 9.7.

The condensate shall be cooled upstream pumps to maintain temperature downstream in

the range of 40-55ºC.

It shall be considered shutdown valve (SDV) to protect the system against reverse flow from

high pressure discharge to low pressure section.

2.7.4. PRODUCED WATER TREATMENT

Produced water plant shall be designed to treat as per Table 1.2.2.1 and to meet specification

described on item 2.2.2.

Configurations of the following equipment shall be assessed for disposal treatment: skimmer

vessel, hydrocyclones, and flotation unit.

Configuration of the following equipment shall be assessed complementing treatment for

water reinjection: produced water tank and solid removal system.

In case of off-spec water the Unit shall be able to automatically interrupt overboard discharge

and route this fluid to an off-spec tank and also send this fluid back to the water treatment

plant to be reprocessed. The recovered oil from produced water treatment shall be sent to

the oil process plant.

The Figure 2.4.1 earlier presented the simplified scheme proposed for the Produced Water

System considering both alternatives, reinjection back to reservoir as well as disposal to

overboard.

Alternative configuration may be submitted for Petrobras evaluation.

The produced water from Process Plant is accumulated in the Skimmer and further routed

to Hydrocyclones and Flotation Unit as normally proceed in other units. Then, the produced

water from Flotation Unit shall be routed to Produced Water Tank from where it shall be

pumped to Solid Removal Unit and then to reinjection in the reservoir (with or without mixing

with seawater).

The filtration step – Solid Removal Unit – shall be either: self-cleaning filters or ceramic

membranes or multi-media filters.


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The system shall consider that desulphated water will supply the necessary water injection

flowrate in the beginning of production life of the unit and once produced water is available

for injection, it will be the another source for injection and total flowrate may be

complemented with desulphated water.

Connection with overboard (ex.: from PVs or FVs for pump capacity control) is not allowed

after the mixture of streams, during the reinjection operation.

Contractor may submit to PETROBRAS a different configuration for the solid removal reject

destination and disposal.

The next paragraphs describe briefly the expected functionality for each one of the

equipment potentially involved.

• Skimmer

It is a water accumulator.

• Oily Vessel

This vessel has the function of receiving sources of oily waters, from Skimmer,

Hydrocyclones, Flotation Unit and Produced Water Tank. From this vessel, the collected

reject shall be routed back to process.

• Hydrocyclone

For oil removal from produced water based on centrifugal forces and density differences

between oil and water.

The hydrocyclones inlet header shall be accessed for internal cleaning.

The liners must be aligned per group of liners in order to allow alignment without opening

of the vessels and to meet the optimum flow rate per liners during the unit lifetime.

• Flotator

It has the function of final polishing (removing oil content) for produced water and shall

guarantee required oil content in any scenario, reinjection into reservoir or discharge

overboard.

The residence time in Flotator shall be, at least, 10 minutes.

• Water cooler


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The operation temperature, as well as pH and salinity can influence the organic components

solubility in water. Therefore, based on the expected range of temperature for produced

water, the cooler location shall be defined taking into account at least the following

requirements:

• Adequate temperature to hydrocyclone and flotator operation;

• Maximum allowed temperature for the Produced Water Tank;

• Maximum allowed temperature for the injection risers.

• Produced Water Tank

The tank has the aim to be an accumulator before final step of solid removal in the case of

produced water is reinjected into reservoir.

It may also contribute for the reduction of dispersed oil content and solid removal prior to

produced water reinjection, increasing the reliability of Produced Water System.

The following configuration shall be considered for Produced Water Tank: at least two

separated Produced tanks with facilities to allow them to be connected in series. The

effective volume of the two tanks combined shall be of at least 15,900 m³.

The fluid inlets and outlets should be designed to minimize turbulence and recirculation,

hampering the separation process by decantation.

Shock Biocide and Biostatic shall be foreseen to be injected in the inlet line of tank in order

to allow a proper mixing and effectiveness of chemical product as well as to minimize

turbulence in the tank.

Produced water tanks shall be provided with proper device (ex.: collector, pumps) installed

at a convenient vertical level in order to remove skimmed oil from tank.

• Pumps

The configuration for water pumps shall consider at least 2x 50% ( 2 x 7,950 m3/d), per

tank.

For skimmed oil pumps, if adopted, the configuration shall be defined by CONTRACTOR.

For details about equipment requirements, see Section 9.4.3.

• Solid Removal


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It is the last step of produced water treatment before reinjection.

A proper system shall be foreseen downstream of Produced Water Tank in order to specify

solid content as required for reinjection into reservoir.

Acceptable technologies for solid removal are:

• Self-cleaning filters;

• Ceramic membranes filters;

• Multimedia filters.

The necessary injection flowrate shall be kept during the cleaning step of device as well the

required quality for reinjection.

The reject stream of this system shall be sent back to the Produced Water Tank. The inlet

pipe in the tank shall be arranged in order to not cause re-entrainment of solid in the water

stream to be filtered. CONTRACTOR shall be responsible for managing residual disposal.

The minimum requirements for filtration are summarized bellow.

• The configuration shall consider at least 3 x 50% (3 x 7,950 m3/d) trains.

• Filters shall have differencial pressure transmitter.

• Filtration shall collect particles in two stages: 80 µm and 25 µm.

• Self cleaning filters shall have a maximum filtration flux of 1,200 m3/m2.h.

• Multimedia filters shall have a maximum filtration flux of 15 m3/m2.h.

• Ceramic membranes filters shall have a maximum filtration flux of 4.5 m3/m2.h.

2.7.5. FLARE AND VENT SYSTEM

The flare system shall execute the combustion of the gaseous effluents disposed. The

combustion shall remain fully operational under stormy weather conditions (wind velocity of

100 km/h) even at low gas outlet velocity.

Flare system shall be designed for continuous and emergency burning. Flare System’s parts

and components shall endure continuous burning for an indefinite time, as well as emergency

burning periods of at least 24hours.

The Unit shall be equipped with at least 2 (two) independent flare systems, one operating at

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released from safety valves, pressure control valves, blow down valves, pipelines, etc.

Additional low temperature disposal headers may also be considered by CONTRACTOR.

These systems shall be designed to operate simultaneously. Design of the disposal systems

shall comply with API STD 521:2014, CS Requirements and Guidelines, and NR-13

requirements for periodical testing of PSVs.

The system shall be designed for emergency disposal, as well as for a continuous disposal

from low flowrates to at least 2,000,000 Sm³/d. CONTRACTOR shall prepare an Emergency

Depressurizing Philosophy to be submitted to PETROBRAS to coments/information.

Disposal streams shall be collected in a close system and directed preferentially to flare,

unless they can be sent back into process.

The disposal system K.O. drums shall be designed to accommodate gas and liquids relief

flows and have effective level measurement and control.

Designing relief systems of process plant (equipment or piping) shall take into account the

possibility of low temperatures and associated hydrate formation, adhesion, risk of plugging.

Flare system design shall evaluate scenarios which may lead to high depressurization rates

above flare capacity, such as unit blackout leading to the simultaneous opening of all BDVs,

and provide safeguards to prevent such scenarios CONTRACTOR shall ensure that in case

of platform blackout, with failure of UPS (Uninterruptible Power Supply), a safe

depressurization of all modules shall take place. For emergency and normal blowdown, if

BDV opening sequence is necessary, CONTRACTOR shall submit to PETROBRAS the

BDV opening sequence, philosophy and calculation for comments.

2.7.5.1. FLARES

In the thermal design of Flare System, the standards API STD 521/ISO 23251 shall be

followed for the acceptance of the maximum total radiation incident on the working areas in

any weather condition. Under continuous burning, the maximum radiation incident in the

working areas of the unit shall not be higher than 1578 W/m2, being 789 W/m2 due to flare

and 789 W/m2 due to solar radiation. In the emergency conditions, the maximum total

radiation incident in the working areas of the unit shall not exceed 4737 W/m2 for a period

of 3 minutes as recommended by standards API STD 521/ISO 23251.


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The thermal design of Flare System shall ensure that maximum total radiation in the working

areas (where there may be people present) comply with these guidelines, without the use of

heat shield in the unit.

Special attention shall be given on radiation levels on offloading equipment, flare startup

system location (propane/LPG), electrical, and gas and flame detectors.

CONTRACTOR shall also conduct dispersion analysis during flare snuffing scenarios and

noise level studies for the determination of the flare stack height.

Flaring of the High Pressure Gas shall be effected through low-radiation and sonic type

burners.

CONTRACTOR shall guarantee that:

• flare system have suitable supports in order to avoid transferring vibration to the flare

piping system;

• flare type be a non-pollutant type, with low NOx emissions. Burning efficiency shall

be high enough to guarantee low HC emissions to the atmosphere;

• smokeless burning, in accordance with Level 1 of the RINGELMANN Scale for

operational flaring condition. Assistance gas shall be used.

• operational flaring scenarios be evaluated to guarantee flame stability and quality,

especially for the lowest expected flowrates. Concern is excessive radiation and

damage to flare structure in staged flare designs;

• flare design consider fire scenarios according to fire propagation study results which

can lead to high depressurization flow rates.

• flare system design shall evaluate scenarios which may lead to high depressurization

rates above flare capacity, such as unit blackout leading to the simultaneous opening

of all BDVs, and provide safeguards to prevent such scenarios.

• flare system shall have the proper piping slope upstream and downstream knockout

drums in order to avoid liquid accumulation.

The flare system shall be designed with a gas recovery unit.

In order to minimize gas burning at flare system, either low pressure or high pressure flare

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FGRS shall consist of a system with a pressure recovering equipment to make possible to

return gas to process. If selected, liquid-ring compressor shall be designed according to API

681. CONTRACTOR shall consider the minimum capacity of 50,000 Sm3/d for FGRS

design.

The pressure recovering equipment shall start to recover the flare gas as the flare header

pressure reaches a set point. Whenever discharges exceed FGRS capacity, the system shall

stop and gas shall be directed to the flare to be burnt. In order to keep system reliability, it

shall be installed QOVs (Quick Open Valves) on HP and LP headers. Each QOV shall have

at least 2 (two) Buckling Pin Valve (BPV) protection with a bypass line. The headers pressure

shall be monitored by 3 (three) pressure transmitters, located upstream QOV, and shall be

configured with a voting logic of 2 (two) of 3 (three) in order to open/close QOV.

For the design of the Safety Instrumented Functions (SIFs) responsible for the QOVs (Quick

Opening Valves) actuation, installed in the flare gas relief lines (low and high pressure), SIL

(Safety Integrity Level) 3 must be considered as the level of integrity required.

Flares shall be designed with a backup of the ignition system. Flare and pilot shall be

designed to guarantee flammability and flame stability. There will be at least two pilots for

each LP and HP burners. The ignition of the pilots shall be done by a flame front system and

by an electro-electronic system. Automatic re-ignition shall be by electro-electronic system,

and shall be triggered locally or from the control room.

The pilots flame shall be permanently monitored by a termocouple prediction of local audible

alarm and in the control room. The flare pilot monitoring system shall consider a backup,

based on one of the following technologies: UV radiation, IR radiation, flame ionization or

acoustic signatures of flame.

At least two sources of purge gas shall be provided, with provision for measuring flow, low

flow alarm and automatic changing between sources. The maximum oxygen content of purge

gas shall be 5%.

The minimum purge gas flow shall be according to API STD 521 requirements or supplier

information, which is higher.

In the Flare Gas Recovery System (FGRS), the high pressure and low pressure headers

shall be purged with nitrogen locally generated from the atmospheric. The nitrogen


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generators shall have a 2x100% configuration and its electrical energy source shall be from

emergency generator (CDC Essential).

The Nitrogen Generator Units shall be connected in the supervisory system to allow an

automatic start-up. In case of failure of both generators, a dedicated fuel gas source shall be

used to purge the flare system. Purge gas shall be injected in HP and LP headers

downstream respective QOV (Quick Open Valve) valves.

The secondary purge source gas shall be monitored by 3 (three) low pressure or low flowrate

transmitters, located at purge lines to HP and LP Flare, and shall be configured with a voting

logic of 2 (two) of 3 (three) in order to initiate a PSD (Process Shutdown). For stage systems,

provide points for nitrogen and fuel gas purge downstream each valve of stages normally

closed, in order to maintain a continuous flow of purge gas up to the top of the flare.

The purge system shall be provided with flowrate or pressure monitoring with low flowrate or

low pressure alarm and automatic source changeover. The purge gas flowrate metering shall

be exclusive for this purpose. Purge flow control shall be carried out trough restriction

orifices.

Logic shall be provided to switch the purge source to fuel gas in case of mismatch of N2

detected by the oxygen analyzers.

2.7.5.2. ATMOSPHERIC VENTS

Independent vent systems shall be provided to collect low pressure (around atmospheric

pressure) gases and vent them safely. Vent shall be provided at least:

• to collect vent gases from cargo tanks;

• for risers.

The design of Atmospheric vent shall follow the API RP 2000.

CONTRACTOR shall consider proper access to flame arrestor for all atmospheric

vents.Flame arrestors shall be installed in safe location complying with API 14C.

CONTRACTOR shall create an inventory of all atmospheric vents that have the potential to

release hydrocarbon liquid above its flash point, assess the risks according Risk

Management Program, document and implement remedial steps in design.


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2.8. CHEMICAL INJECTION

The Unit shall be equipped with a chemical injection system, which will be used to improve

and enhance the operating conditions of topside and subsea. The Unit shall be designed to

inject the following main products:

• H2S scavenger for subsea;

• H2S scavenger for offloading;

• Gas hydrate inhibitor for topside and subsea;

• Scale inhibitor for topside;

• Scale inhibitor for subsea

• Wax inhibitor for subsea;

• Asphaltene inhibitor for subsea;

• Water-in-oil demulsifier for topside;

• Water-in-oil demulsifier for subsea

• Oil defoamer for topside;

• Polyelectrolyte (inverted emulsion inhibitor);

• Coagulant

• Biocide for Slop Tanks and Produce Water Tanks;

• Biostatic for Slop Tanks and Produce Water Tanks;

• Acetic Acid (75%)

• Gas corrosion inhibitor (subsea and topside/export pipeline);

• Oil corrosion inhibitor (subsea);

• Low Dosage Hydrate Inhibitor (LDHI) for subsea;

• Oxygen scavenger.

• All the manufacturer recommended chemicals for MEG Treatment Unit. As a

minimum CONTRACTOR shall consider:


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o pH stabilizer;

o corrosion inhibitor;

o oxygen scavenger;

o antifoam;

o calcium control chemical (sodium carbonate).

• All the manufacturer recommended chemicals for the Sulphate Removal Unit and

Ultrafiltration Unit. As a minimum CONTRACTOR shall consider:

o Membrane biocide and/or shock biocide;

o Chlorine scavenger and/or oxygen scavenger;

o Scale inhibitor for SRU;

o Acid cleaning for SRU;

o Alkaline cleaning for SRU;

o Water Injection Shock biocide;

o Biofouling disperser.

Whenever necessary, the Unit shall have facilities, via the well service system, to inject other

products also including diesel, water and nitrogen.

The Unit shall be designed to inject chemicals into subsea and in topside facilities, as

specified in Table 2.8.1.

Where not specifically mentioned, storage tanks for chemicals shall have enough capacity

for 9 days of normal consumption, calculated by using 100% of the maximum injection rate

indicated in Table 2.8.1.

Each tank for chemicals shall be provided with an independent 2-inch feed line, with 10-

mesh screen, to avoid product contamination. Supply manifolds are not allowed.

Tanks shall have the following characteristics:

· Cone bottom to facilitate cleaning;

· Coamings to contain liquid spills;

· Manhole to allow internal inspection and cleaning;


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· Liquid level gauge.

· Easy access to instruments and valves;

· High level alarm;

· Low level alarm;

· Tank sampling valve (may be on the pump discharge).

Tanks shall be installed in naturally ventilated areas and shall be provided with individual

air vents. Vents for flammable products shall be in accordance to API RP 2000. The tanks

for flammables shall also be provided with flame arresters.

All the chemical products tanks shall have a level transmitter and outlet nozzle with at least

150 mm distance from the bottom. Also, bottom shall be slopped toward to drain nozzle in

order to facilitate tank cleaning operations.

In order to reduce the length of flexible hoses and then minimize the risk of contamination,

storage tanks shall have rigid lines to the point of supply with lock valves identified with the

generic name of the product and fitted with threaded caps.

The Level Gauge must be of a total volume indication (0 to 100% including dead volume)

and have drain.

Tanks for performance chemicals such as corrosion inhibitor, defoamer, demulsifier (top

side), scale inhibitor (subsea and topside) and H2S scavenger (subsea) shall be divided in

two partitions with isolating valves from the common pump suction header and also isolating

valves on filling line. Instrumentation, drains and vents shall consider the partition. These

facilities are to be used during testing of new products or diferent batches of the same

products.

For umbilical (subsea) injection, a specific drainage routine / procedure shall be established

during operation phase, to keep cleanliness level of SAE AS4059 class 8 B-F. Filters

(2x100%, 100 mesh stainless steel) on pump suction and (2x100%, 400 mesh stainless

steel) on pump discharge shall be added. These filters shall have remote differential

pressure alarm for replacement. Both filters elements and downstream system shall be

corrosion resistant (AISI 316L or superior). These filters must have ∆P transmitters.

CONTRACTOR shall install stand-by filters at all subsea chemical injection system to

guarantee continuous performance. CONTRACTOR shall follow practices and


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recommendations of API TR 17TR5 (Avoidance of Blockages in Subsea Production Control

and Chemical Injection System) during design and operation.

Sufficient area shall be provided for receiving and storing a quantity of tote tanks

corresponding to the consumption of chemicals in 7 days at 100% of the maximum injection

rate indicated in the first Table of this item at maximum gas, oil, produced water and

injection water flowrates. Products of non-continuous use shall not be considered in this

calculation. No stacking of tote tanks is allowed.

Install the hydraulic unit next to the chemical product unit, to avoid separate storage areas.

All chemical injection pumps shall have a filter upstream. CONTRACTOR shall install stand-

by pumps at all chemical units to guarantee continuous performance, even high-volume

pumps as ethanol, MEG and oxygen scavenger. Also, chemical dosing pumps shall have an

adjustable flow range of 10:1 unless if defined differently on Table 2.8.1. Positive

displacement pumps shall have PSV on discharge.

For all chemical injections (subsea and topside) CONTRACTOR shall provide a pump

system to guarantee the individual flow control per point. Each injection point shall have

individual pump or multi head pump.

The required discharge pressure for subsea chemicals is 69,000 kPa.

Each injection point shall have an online flow meter (transmitter) and a calibration gauge

glass, protected against chock, shall be placed upstream pump inlet in order to measure the

injection rate. The flow meters shall have flow and totalizing indication in the supervisory

system, as well as low flow alarm.

CONTRACTOR shall comply with flow meter maintenance plan recommended by the

supplier. Flow meters for topside scale inhibitor, oil defoamer, demulsifier and subsea

chemicals shall be Coriolis type, transmitting online flow and density.

Each injection point shall have a pressure transmitter online.

All the topside injection points in the gas shall be installed with spray nozzle to accelerate

the chemical mixing.

Each topside injection point shall be in the center of pipe. A check valve and a block valve

shall be installed as near as possible to injection point.


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The Contractor shall provide two Chemical Injection panels. One panel shall be used to inject

chemical at subsea and another one shall be used to inject chemical at topside.

When using dosing pumps, these shall be the piston or double-diaphragm type (protection

against leaking of toxic products). In case of systems that shall not be automated, use

dedicated pumps for each type of product and an injection point, with lock in the regulation

system. For oil corrosion inhibitor pumps, at least an annual maintenance plan shall be

foreseen.

Oil corrosion inhibitor system shall have 99% reliability. CONTRACTOR shall issue a specific

study based on the methodology presented on Reliability Availability And Maintenability

(Ram) Analysis Requirements (see item 1.2.1).

Data from chemical flowmeters shall be available at Supervision and Operation System

(SOS) and also on PI onshore.

Concentration ranges for each chemical to be complied with when designing the chemical

injection system are (during operational life, diferent dosages within pump or system

capacities may be applied):

Table 2.8.1 – Chemical Injection Rates & Requirements

PRODUCT INJECTION RATE AND REQUIREMENTS

Gas hydrate inhibitor: MEG

continuous (subsea and

topsides)

To inhibit hydrate formation, MEG shall be injected continuously

upstream GDU/HCDP (topsides) and into the non associated gas

production wells Wet Christmas Trees. The injection could be

done through the umbilical and through the service line of

production wells.

The attachment of chemical injection device to tubing or

equipment shall be via flanged connection. Retractile nozzles

system (the part in contact with the fluid can be inserted and

removed in operation) is required for maintenance.

The subsea pumping system shall have a configuration of at least

3x50% pumps with a total flowrate of 300 m3/d and 69,000 kPa(a)

injection pressure.


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The topsides pumping system shall have a configuration of at

least 3x50% pumps with a total flowrate of 150 m3/d.

For others specification see item 2.7.3.10

Gas hydrate inhibitor: ethanol

or MEG for oil production wells

(subsea)

There shall be a storage of 2 (two) tanks of 40 m³ each. At any

time, each of the tanks may be used for ethanol or MEG.

To inhibit hydrate formation, the inhibitor shall be injected into the

oil production wells Wet Christmas Trees. The injection could be

done through the umbilical and through the service line of

production wells.

The subsea pumping system shall have a configuration of at least

3x50% pumps with a total flowrate of 5000 l/h.

The injection is not planned to be continuous, however, it should

be possible to inject it in up to two points at the same time.

The pump could be used in the commissioning of gathering

system and gas export lines.

Gas hydrate inhibitor: ethanol

or MEG for topside

These facilities will share the same tank used to subsea injection.

Injection points are required at the topside facilities in case of water

content gas out of spec.

The attachment of chemical injection device to tubing or

equipment shall be via flanged connection. Retractile nozzles

system (the part in contact with the fluid can be inserted and

removed in operation) is required for maintenance.

CONTRACTOR shall provide the following injection points:

· Gas exportation pipeline;

· Gas-lift lines, individually per well;

· Downstream gas injection compressors;

· Upstream fuel gas pressure control valve (if necessary);

· Condensate outlet of the high pressure fuel gas vessel (if

necessary).


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It shall be considered additional injection points, where hydrate

could form, to be eventually used in the operation to remove any

hydrate formed due to an abnormal operation condition.

The injection system provided shall consider a total flowrate of 300

l/h: 200 l/h for gas exportation pipeline and 100 l/h for gas-lift lines

(range of 1 to 15 l/h per line). The minimum flow rate for each

injection point shall be 1.0 (one) l/h.

Gas corrosion inhibitor

(subsea and topsides)

The Unit shall be prepared to inject this product continuously in the

gas export pipeline and in the gas-lift/service lines at topside

injection point.

For the non associated gas production wells Wet Christmas Trees,

this product shall be injected continuosly through umbilical lines.

CONTRACTOR shall provide dedicated pumping systems for

topside injection at 32,000 kPa (a).

The injection system provided shall consider dosage of 0.5 – 3 l/h

per MMm³/d of produced gas (subsea injection) or exported gas

and gas-lift/service lines (topside injection) into each injection

point.

Oil corrosion inhibitor

(subsea)

The Unit shall be prepared to inject this product continuously

for the oil production wells Wet Christmas trees through umbilical

lines.

The injection system provided shall consider dosage of 2.5 – 10 l/h

per 100 m³/h of produced oil into each injection point.

Scale inhibitor for topside

Minimum effective tank capacity: 30 m³.

CONTRACTOR shall provide independent systems for topside and

subsea scale inhibitor injection. PETROBRAS informs that there is

a high potential of scaling at topside and different products could

be used in subsea and topside at the same time.

The Unit shall be prepared to inject the scale inhibitor continuously

at the topside facilities (production headers, test headers,


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upstream heat exchangers, produced water outlet of FWKO, Oil

Test Separator and treaters - as close as possible to the water

outlet nozzles, upstream hydrocyclones, upstream mixing device

oil/dilution water) whenever required by PETROBRAS.

The injection points into production headers shall be upstream the

choke valves at least 1 (one) meter away from the choke valve,

preferably upstream of some pipe accident, such as valves, curves

and others.

The injection system provided shall operate in the range of 10 to

100 l/h into production headers.

The injection system provided shall operate in the range of 1 to 40

l/h per other injection points.

Scale inhibitor (subsea)

Minimum effective tank capacity: 35 m³.

CONTRACTOR shall guarantee the individual flow control per well.

Each scale inhibitor line will pass through X-tree and Tubing

Hanger down to the well bottom to guarantee the scale inhibition

as close as possible of perforations. Additionally, in the case of

blocking downhole injection system, the chemical shall be injected

into the production wells Wet Christmas Trees.

The injection system provided shall operate in the range of 3 to 30

l/h per well.

Shared

facilities for

future use

Asphaltene

inhibitor

(subsea)

There shall be a storage of 3 (three) tanks of 20 m³ each.

The facilities defined for this item should be able to attend the five

products specified, not simultaneously. Wax inhibitor

(subsea)


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LDHI

(subsea)

Wax and Asphaltene inhibitors use xylene/toluene as solvent.

Each scavenger line will pass through X-tree and TH down to the

well bottom to allow H2S scavenger to react with H2S in the tubing.


100 l/h per well.

Water in oil

Demulsifier

(subsea)

H2S scavenger

(subsea)

H2S scavenger for topsides

Minimum effective tank capacity: 20 m3

H2S scavenger for subsea and topside may be different

chemicals and the storage shall be done at different tanks.

Injection point: upstream each offloading pump.

The injection system provided shall operate in the range of 200-

1000 l/h.

This product should be used just contingently and in agreement

with PETROBRAS.

Xylene

Batch use

The use of xylene will be done through service boats and there is

no need of xylene storage.

Injection rate will be informed during the engineering detailing

phase.

Water-in-oil demulsifier for

topsides

Minimum effective tank capacity: 35 m³

The Unit shall be prepared to inject this product continuously in the

following topside injection points: production and test headers

(more distant upstream), oil outlet of FWKO and oil outlet of Pre-

Treater (upstream addition of dilution water oil wash).


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80 l/h per point.

Oil defoamer


The Unit shall be prepared to inject this product continuously in

the follow topside injection points: production and test headers

(more distant upstream), upstream FWKO (oil level control valve

of the FWKO) and flash vessels.


70 l/h per point.

Acetic Acid (75%)

Minimum effective tank capacity: 30m3

Acetic acid shall be injected on production and test headers

(more distant upstream) considering 800 ppmv of product based

on total produced water flow rate.

This product may be used to reduce pH in order to improve oil

removal from produced water on overborad scenario.

Attention shall be taken to corrosion on injection points due do pH

reduction.

The injection of acid shall be provided upstream demulsifier

injection with a minimum distance of 5

meters.

Injection point type: Quill.

Produced Water Biocide

Minimum effective tank capacity: 5m³

The Unit shall be prepared to inject this product in batch in the

following topside injection points: Slop tanks and Produced Water

Tanks.

Batch treatment uses 1 m³/h as product flow rate.


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Produced Water Biostatic


The Unit shall be prepared to inject this product in batch in the

following topside injection points: Slop tanks and Produced Water

Tanks.

Batch treatment uses 1 m³/h as product flow rate. These pumps

may be shared with Produced Water Biocide.

Polyelectrolyte (inverted

emulsion inhibitor)


The Unit shall be prepared to inject this product continuously

downstream hydrocyclones and upstream Skim Vessel level

valve.


40 l/h.

The dilution system of polyelectrolyte shall use fresh water on line

to adjust the dilution range. The polyelectrolyte pump and the

dilution pump shall have a turndown ratio of 1:10. The dilution

pump maximum flow shall be 36 (thirty six) times the maximum

flow of polyelectrolyte pump.

Polymaster type pump (or similar) is acceptable.


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Coagulant


The injection shall be upstream and downstream hydrociclones

with dosage from 10 to 60ppmv based on produced water flow

rate.

This product may be used to enhance solid removal for reinjection

scenario.

The coagulant injection shall be made diluted. The dilution system

of chemical product shall be made with fresh water online and the

range of 5% to 20% of coagulant shall be considered. Polymaster

type pump (or similar) shall be used. For injection point provided

downstream hydrociclones, a static mixer shall be installed.

(SRU) Acid cleaning and

(SRU) Alkaline cleaning

Batch use.

During project execution phase, SRU cleaning procedure shall be

submitted to PETROBRAS for comments/information.

The cleaning system shall have alignment flexibility for one train,

stage or bank cleaning.

Shock Biocide: DBNPA

From 100 to 500 ppm twice a week during one hour, inject

upstream SRU.

PETROBRAS states that DBNPA is a corrosive product so its

injection system shall not be metallic.

Water injection shock

biocide: THPS (tetrakis

hydroxymethyl phosphonium

sulfate) or glutaraldehyde

Minimum effective tank capacity: 5 m³ (not the same as Produced

Water Biocide)

The Unit shall be prepared to inject this product in batch twice a

week upstream and downstream deaerator, not simultaneously.


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Batch treatment uses 100 to 1000 ppm as product flow rate.

These pumps may be shared with Produced Water Biocide.

Scale inhibitor for SRU


Dosage from 1 to 20 ppm upstream SRU.

Chlorine scavenger Dosage from 1 to 30 ppm upstream SRU.

Oxygen scavenger

Dosage from 5 to 20 ppm upstream and downstream deaerator,

not simultaneously (operational deaerator).

Dosage from 100 to 200 ppm upstream and downstream

deaerator, not simultaneously (non-operational deaerator).

Dosage from 100 to 200 ppm upstream Solids Removal Unit.

Biofouling disperser Dosage from 5 to 20 ppm downstream deaerator.

Configuration for Chemical Routing Panels are presented in the figures bellow.


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Figure 2.8.1 - Chemical Routing for gas Wells

gas hydrate inhibitor gas corrosion inhibitor other chemicals asphaltene inhibitorscale inhibitor

ANM

chemical injection mandrel

subsea

topside

subsea injection

header (see fig. 2.8.3)

flowmeter

legend:

check valve


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Figure 2.8.2 - Umbilical Chemical Routing for oil Wells

Figure 2.8.3 - Chemical routing for products with shared tanks (topside and injection points)

oil corrosion inhibitor other chemicals asphaltene inhibitorscale inhibitor

ANM

chemical injection mandrel

subsea

topside

hydrate inhibitor(from subseadistribution unit)(see figure 2.8.3)

flowmeter

legend:

check valve

gas corrosion inhibitorgas hydrate inhibitor

for gas export pipeline / service lines of gas wells (GP01 to GP04) and subsea manifold (GP05 to GP08)

for gas export pipeline / service lines of gas wells (GP01 to GP04) and subsea manifold (GP05 to GP08)

for subsea injectionof gas wells (see figure 2.8.1)

for subsea injectionof gas wells (see figure 2.8.1)

pump system for topside injection

pump system for topside injection

pump system for subsea injection



for subsea distribution units (umbilical lines) of oil wells (OP01 to OP08)

topside

subsea

for subsea distribution units (see figure 2.8.2)

TOPSIDE INJECTION PANEL

SUBSEA INJECTION PANEL

for subsea injection -of oil wells and WAG wells

and WAG wells (IWAG01 to IWAG06)

flowmeter

legend:

check valve

pump system


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For chemicals under PETROBRAS’ supply responsibility, PETROBRAS will define the

supplier and the chemicals products.

PETROBRAS will provide the following chemicals up to the limit mentioned in the table

2.8.2, measured monthly. These quantities are referred to the maximum flowrate (Refer to

item 2.5.2) or storage capacity mentioned in the table 2.8.1. For flow rates smaller than the

maximum, a proportional amount will be considered.

Table 2.8.2 – Chemicals products deliveries

PRODUCT Quantities (Maximum limits / month)

Scale inhibitor for subsea See remark 1 below

Scale inhibitor for topside See remark 1 below

Demulsifier for topside 50 m3

Demulsifier for subsea See remark 1 below

Oil defoamer 60 m3

Polyelectrolyte (inverted

emulsion inhibitor) 20 m3

Low Dosage Hydrate Inhibitor

(LDHI) for subsea; See remark 1 below

Gas hydrate inhibitor for top

side and subsea See remark 1 below

Wax inhibitor See remark 1 below

Asphaltene inhibitor See remark 1 below

Oil corrosion inhibitor See remark 1 below

pH stabilizer See remark 1 below

Chlorine scavenger See remark 1 below

Scale inhibitor for SRU See remark 1 below

Acid cleaning for SRU See remark 1 below

Alkaline cleaning for SRU See remark 1 below

Biofouling disperser Seeremark 1 below

Biocides to water injection DPNA – 5,6 m3


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PRODUCT Quantities (Maximum limits / month)

THPS –3,8 m3

Oxygen Scavenger

50 m3

H2S scavenger for subsea See remark 1 below

H2S scavenger for offloading See remark 1 below

Gas Corrosion inhibitor See remark 1 below

Acetic Acid See remark 1 below

Coagulant See remark 1 below

Remarks:

1. Chemicals will be provided by Petrobras at no cost. CONTRACTOR must use the volume

or dosage requested by PETROBRAS.

2. The quantities above may be revised during the operation, if CONTRACTOR presents

technical evidence that supports such need and is accepted by PETROBRAS.

3. As chemical injection facilities may contain low flashpoint, flammable and/or toxic

substances, these risks shall be used in development of the appropriate protection

requirements.

4. Due to potential hazards, the location of chemical injections packages shall not obstruct

escape and evacuation routes by any very toxic substances that might result from an

incident.

Chemicals are received from supply vessels in portable tanks (tote tanks) within 5m3 capacity

and must be stored in specific chemical storage areas within the range of at least one of the

Unit's cranes. These chemical storage areas shall preferably allow the gravity transfer of

chemicals to the storage tanks in the chemical injection unit.

For tote tanks dimensions, CONTRACTOR shall consider


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W: Width, H: Height, L: Length

2.9. SAMPLE COLLECTORS

Provisions to collect samples shall be designed in such a way as to guarantee correct sample

accuracy. Each collecting point shall be in accordance with regulations and shall allow safe

operation with no environmental impact. Therefore, CONTRACTOR shall install an adequate

drain system, for each of the collecting points listed on Table 2.9.1.

For each sampling point, it shall be considered the following items:

· Sampling valves shall be located and positioned in order to minimize segregation of fluid

components;

· Preferably use points located in vertical sections, with ascending flow. Where this is

impracticable, select points with turbulent flow to ensure that the fluid components are

suitably mixed. Sampling points must not be placed in descending flow;

· Avoid installing sampling points of hard access or situated on very high or low places in

order to guarantee readiness of access and minimize ergonomic issues;

· Do not use pipe ends and zones without turbulent flow.

Provide sampling point collectors with sufficient drain line capacity and diameter, to avoid

overflow. Material for sampling point construction shall be compatible with the sampled fluid

and with pipe specification. For injection water sampling, the valve construction material shall

be the same as the water piping to the first block valve, and stainless steel thereafter.The

sampling point collectors shall be provided with drip trays.

The possibility of precipitation of organic and inorganic compounds during the definition of

the sampling point type shall be evaluated.

m³ Valve Connection PB Dimension Tare (kg)

1,0 ball Ø2" Screw BSP restricted gate H=1,5m X L=1,3m X W=1,5m 2651,5 ball Ø2" Screw BSP restricted gate H=1,9m X L=1,3m X W=1,5m 4403,0 ball Ø3" Screw BSP restricted gate H=2,3m X L=2,3m X W=2,3m 1.5005,0 ball Ø3" Screw BSP restricted gate H= 2,3m X L= 3,0m X W=2,3m 1.7005,2 ball Ø3" Screw BSP tripartite restricted gate H=2,3m X L=3,1m X W=2,3m 1.700


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Table 2.9.1 – Sample Points

POINTS SAMPLE COLLECTION

Produced

oil/Condensate

(1,2,3,8)

• Test and production headers (upstream from the

chemical injection points);

• Upstream and downstream of process vessels;

• Try-cocks on FWKO, Inlet gas separator, pre-

electrostatic treater and electrostatic treater;

• Transference pump discharge (from the process plant to

the cargo tanks);

• All production header lines;

• Offloading line;

• Slop and Cargo Tanks.

Produced Gas (3,4,5)

• Upstream and downstream of process vessels;

• Gas export (upstream of pig launcher)

• Fuel Gas;

• High Pressure Flare gas;

• Low pressure Flare gas;

• Service header;

• Gas lift header;

• All production header lines;

• Gas reinjection header;

• Upstream and downstream of Dew Point Control Unit

• Slop and Cargo Tanks;

Heavy Hydrocarbon

Rich Stream

• Upstream and downstream process vessels.

• Heavy hydrocarbon rich stream injection header

(WAG wells)

Produced water (1,6) • Downstream process vessels


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• Upstream and Downstream of individual water

treatment equipment

• Slop vessels/tanks

• Water discharge piping to overboard (located near the

oil and water online analyzer)

• Upstream and Downstream of the Produced water

Tank

• Downstream of the Solid Removal Unit

Injection water

• Upstream and downstream deaerator;

• Seawater intake, upstream water lift pumps;

• Sulfate removal membrane unit: inlet, treated water

and Sulfate stream (in each vessel);

• Water Injection header (WAG wells and water

injection wells) and risers.

• Upstream and downstream filters (pre-treatment)

Dilution water • Upstream dilution water heater

Cooling Water • Downstream circulation pumps

• Downstream heat exchangers

Hydraulic control fluid • High pressure header for DHSVs

• Low pressure header for WCTs

Sewage system • Upstream and downstream sanitary effluent

treatment unit

Subsea Chemicals • Upstream of the Umbilical injection pumps

MEG

• Upstream and Downstream vessels

• Rich/lean MEG upstream and downstream of

contactor Tower

• Rich/lean MEG upstream and downstream of MEG

Regeneration Unit


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Note 1: CONTRACTOR shall provide means to collect samples and to determine BTEX

content in produced oil according to EPA 3585/ EPA 8260C and produced water according

to EPA 5021/ EPA 8260C.

Note 2: CONTRACTOR must provide facilities to collect samples of oil in vessels of 0,25L

up to 1000 L (container). Sampling condition must be at atmospheric pressure (test and

production separators and crude oil fiscal meter to cargo tanks shall also foresee pressurized

samples). All the gas released in this process must be sent to a safe place.

Note 3: For gas and oil sampler points related to the flow meters of the FMS, Resolução

Conjunta ANP/Inmetro nº1 of 2013 shall be complied with. For a list of all metering points

and additional requirements see chapter 7.7.

Note 4: CONTRACTOR shall also provide sample collection in every online analyzer (gas

chromatographer, moisture analyzer, oil in water content, etc.) and meter.

Note 5: CONTRACTOR shall provide means to collect and to determine BTEX content in

produced gas according to GPA 2286.

Note 6: CONTRACTOR shall provide sample collection at produced water discharge pipe,

according to current regulamentations and to analyze TOG in a laboratory certified by

INMETRO.

Note 7: The sample systems shall have material specification compatible with sampled

fluids.

Note 8: CONTRACTOR shall provides an hermetic system to collect and determine benzene

content (%v/v) in all oil, water and condensate streams, as presented in Norma

Regulamentadora Nº 15 – NR-15 (Portaria SSST n.º 14, December 20, 1995) Annex 13 A.

2.10. CORROSION MONITORING

Due to the presence of contaminants in the oil, CONTRACTOR shall take special care with

the material selection for the process plant and also provide means to monitor the corrosion

on piping and equipment, and report to Petrobras.

As a minimum, corrosion monitoring equipment shall be provided in the points along the

produced oil, gas and water flow, as follows:


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Table 2.10.1 – Corrosion Monitoring Points

System/

Equipment Devices Note

Production

header

coupons of mass

loss, electric

resistance (ER) and

probe for erosion

evaluation

probes installed downstream of the

production choke

Oil transfer lines coupons of mass

loss and ER

Probes to be installed upstream pig

receiver

Production

Separator

coupons of mass

loss and ER

Probes to be installed at inlet oil

pipping of separator

Test Separator ER Probes to be installed at inlet oil

pipping of separator

Heating water coupons of mass

loss and ER

Probes to be installed downstream of

corrosion inhibitors injection

Cooling water coupons of mass

loss and ER


corrosion inhibitors injection

Water injection

lines

coupons of mass

loss and ER and

Linear Polarization

Resistance(LPR)


the pumps after chemical injection

points

K. O. Drum coupons of mass

loss and ER

Probes to be installed at inlet gas

pipping

Main

compression

coupons of mass

loss and ER

Probes to be installed downstream

each cooler of compression system

Gas Dehydration coupons of mass

loss and ER

Probes to be installed downstream

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ER Probe to be installed at downstream

MEG tower, at low pressure circuit.

Probe to be installed at recirculation

circuit, after MEG heater.

Gas lift coupons of mass

loss and ER

Gas transfer line coupons of mass

loss and ER

Probes to be installed upstream pig

receiver

Gas

Combustible

coupons of mass

loss and ER

Heavy HC rich

Stream pump

Non intrisuve

At systems with prevision of corrosion inhibitors injection, on-line corrosion monitoring

system shall be implemented. PETROBRAS will not provide chemicals for corrosion

protection of topsides equipment.

CONTRACTOR shall provide an probe for erosion evaluation per each well and they shall

be installed according to supplier requirements.

Corrosion monitoring points are not required at CRA (Corrosion Resistance Alloys) lines,

except when is relevant for corrosion diagnostic of dowstream carbon steel systems. The

following systems shall have monitoring points regardless of the material:.gas transfer line;

water injection line and probe for erosion evaluation of production header

NOTE: The access point of coated system shall be provided trougth a CRA spools.

All components of the corrosion monitoring systems shall be suitable for marine

environment according to class CX of ISO 12944 Part 2 and the fluid service.

The access fittings shall be hydraulic type. Mechanical access fittings may be acceptable

provided previous PETROBRAS approval. The corrosion monitoring system and the access

fittings should be from only one supplier. Different suppliers may be accepted if their

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Contractor shall supplied a complete retrieval tool kit and a manual data collector for the

monitoring system.

On-line corrosion monitoring systems shall be integrated directly in the automation and

control system of the unit with the data available in the PI. The maximum scan time allowed

for those transmitters shall be 6 hours.

Non-intrusive corrosion monitoring systems shall be selected, in place of intrusive devices,

at systems that operate at high pressure (class 2500 or higher), or with process fluid

hydrogen and other fluid at autoignition temperature (equal or higher).

The places for installing the monitors SHALL be according the criteria below:

• At least two points of access, one for coupon and one for probes, spaced at least 500 mm;

• Downstream of corrosion inhibitors injection;

The access fittings in oil and gas systems shall be horizontally installed on straight pipe

sections at the position pipe bottom 6.0 o’clock position.

The access fittings in water systems with monophasic flow (without stratification or biphasic

flow) may be installed in any generatriz of piping, being also accepted the installation in

vertical piping. In case of other flow condition, the points shall be installed at the 6.0 o’clock

position.

The corrosion monitoring points should be located at a minimum distance of 5 times the

piping diameter from any piping accident, like bands, tees and valves that may case

turbulence.

Every corrosion monitoring point shall have adequate clearance for the operation of the

recovery tool. The clearance shall be at least one free cylindrical area of 50.0 cm radius

and 2.0 m in length with respect to the connection of the monitoring point, according to

Figure 2.10.1 and Figure 2.10.2.


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Figure 2.10.1: Superior View

Figure 2.10.2: Lateral View

Corrosion monitoring points shall have access provided in the design through access

structures (ladders and platforms). Where this is not possible, the monitoring points shall

be at a maximum floor height of 3.5 m in order to facilitate access via scaffolding or ladders.

No corrosion monitoring point shall be positioned over the sea. All access fitting shall be

projected as welded to the pipings system. In order to avoid interference, the welding shall

precede the pipe drilling. The indicated method of drilling is HTM (hot tap machine) with

35mm drill bit, to provide adequate insertion and alignment of coupons and probes.


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The coupons, ER/LPR probes SHALL be tangential type if they will be installed in the “PIG”

path.

2.11. LABORATORY

CONTRACTOR shall provide onboard a Laboratory equipped to perform, as a minimum, the

following analysis onboard:

Table 2.11.1 – Laboratory Analyses

SYSTEMS ANALYSIS

Produced

Oil/Condensate

• BS&W and watercut (1);

• Salinity (8);

• Sand content (9);

• Density/API gravity (10)

• H2S content (2);

• Vapor Pressure (11);

Cargo and Slop tanks

• BS&W and watercut (1);

• H2S content (in oil (2), in water (3), in vapor

phases (4));

Produced and

discharged water

• Oil content (12) at all points of discharge to

overboard;

• Chloride content (13);

• Calcium and Magnesium content (14);

• pH (27);

• Composition (5) and (17)

• O2 content (15) and (32)

Injection water (from

sea water treatment or

producted water

treatment)

• O2 content (15) and (32);

• SDI (16);

• Bacteria (SBR planctonic – mesophilic and

thermophilic) (18) and (31);


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• Total anaerobic bacteria (BANHT planctonic)

(28) and (31);

• Number of particles (19);

• Sulfate Content (20);

• Chlorine content (6);

• H2S content in water (3);

• Total suspended solids (TSS) (29) and (31);

• pH (27);

• Oil content in water (12)

Produced gas • H2S content (4) or (22);

• Hydrocarbons and CO2 content (23)

Treated gas

• H2O content (7);

• H2S content (22);

• Hydrocarbons and CO2 content (23)

Injeção de C3+

• Hydrocarbons content (23);

• Density (10);

• H2O content (7);.

Hydraulic control fluid • Cleanliness (24)

Sea Water Lift System • Chlorine content (6)

Cooling and Heating

Medium Systems;

• pH (27);

• Chloride (13);

• Corrosion inhibitor content (26);

• Iron content (25)

Make-up water

• Chlorine content;(6),

• Chloride content (13);

• pH (27);

• Iron content (25)

• Sulfate Content (20)

• O2 content (15);


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Potable Water • In accordance with Decree nº5 (09/28/2017),

Annex 20, published by Health Ministry

Subsea Chemicals • Cleanliness (24)

Lean and Rich MEG • MEG Content (30)

• Salinity (8);

Note 1: BS&W on oil = ASTM D 4007 (BS&W higher than 5%) and ASTM D 4928 (BS&W

lower than 5%).

Note 2: H2S content in oil= Potentiometry UOP 163.

Note 3: H2S content in water = Standard Methods 4500-S2-J-Acid-Volatile Sulfide .

Note 4: H2S content in vapor phase = ASTM D 4810 – Standard Test Method For Hydrogen

Sulfide In Natural Gas Using Length-of-Stain Detector Tubes. Analyses method should be

able to measure H2S content within 0 to 500 ppmV, at least.

Note 5: These analyses shall not be performed onboard. CONTRACTOR shall provide these

analyses onshore.

Note 6: Chlorine content = Standard Methods for the Examination of Water & Wastewater,

Method 4500-Cl G. DPD Colorimetric Method or Application note Merck MColortest TM

Chlorine Test with liquid reagent for the determination of free chlorine. Laboratory analyses

should be able to measure at least the specification of 0,1 to 2 ppmV of chlorine content.

Note 7: H2O content = CONTRACTOR shall be able to perform the primary standard lab

analysis according to ASTM 1142 (Chandler Chanscope Digital Dew Point Meter), including

provision for the low temperature needed for the analysis, such as a liquid nitrogen generator.

The analyses must be able to measure with accuracy H2O content below 1 ppmv.

Note 8: Salinity = Salt-in-Crude analyzer (ASTM D 3230) or Potentiometric method (ASTM

D 6470)

Note 9: Sand Content = ASTM 4381 - Standard Test Method for Sand Content by Volume

of Bentonitic Slurries

Note 10: Density/ API gravity = ASTM D 5002-13 - Standard Test Method for Density and

Relative Density of Crude Oils by Digital Density Analyzer.


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Note 11: ASTM D6377: Standard Test Method for Determination of Vapor Pressure of Crude

Oil: VPCRx PCRxard Test Method

Note 12: Oil content in water = For onboard process monitoring ASTM D 8193 – Standard

Test Method for Total Oil and Grease (TOG) and Total Petroleum Hydrocarbon (TPH) in

Water and Wastewater with Solvent Extraction Using Non-Dispersive Mid-IR Transmission

Spectroscopy. Gravimetric TOG analysys must be in a laboratory certified by INMETRO

according to Standard Method (SM) SM-5520B and in accordance with CONAMA 393/2007.

Note 13: Chloride content in water = ASTM D512 or ASTM D4458

Note 14: Calcium and Magnesium content in water = ASTM D 511-14 (Standard Test

Methods for Calcium and Magnesium In Water)

Note 15: O2 content = ASTM D5543-15 (measurement range shall be from 0 to 1000 ppb).

Note 16: SDI (Silt Density Index) = ASTM D4189

Note 17: Composition shall include: Salinity, Organic acids, Bicarbonates, Calcium,

Magnesium, Bromide, Barium, Strontium, Iron, Manganese, Potassium, Lithium, Boron,

Sulfates. US EPA Method 300/ ASTM 4327/ Standard Methods 4110 B/ ASTM D691/ ASTM

D1976.

Note 18: Bacteria (SBR planctonic – mesophilic and thermophilic) = ASTM D 4412

Note 19: Number of particles = Standard Methods for the Examination of Water and

Wastewater - 22a Edition - 2012 (2560 C. Light-Blockage Methods)

Note 20: Sulfate Content = Ion Chromatographic – For reference IC 861 Metrohm or

Photometry – Standard Methods 4500E

Note 21: H2S and CO2 content by length of stain tubes = GPA STD 2377-14

Note 22: H2S content = by iodometry GPA STD 2265, and by potenciometry ISO6326-3

Note 23: Hydrocarbons and CO2 content by chromatographic analysis = ASTM D1945 or

ABNT NBR 14903 and ISO 6974-2.

Note 24: Cleanliness = ISO 11500/ ISO 4406/ SAE AS4059

Note 25: Iron content = Hach Pocket Colorimeter™ II, Iron (FerroVer®); Aplication Note

Merck MColortestTM Iron Test; Standard Methods for the Examination of Water and


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Wastewater (SMWW) 22ª ed. 2012 – Method 3500-Fe B/ ASTM D1976/ Standard Methods

3120 B/ US EPA Method 6010 C

Note 26: Nitrite content = Method 8153 Hach Nitrite - Ferrous Sulfate Method, Standard

Methods for the Examination of Water and Wastewater - 22a edição, 2012 (Method 4500-

NO2 B). If another type of inhibitor be used, CONTRACTOR shall provide an especific

method of anlysis.

Note 27: pH = SMWW - Standard Methods for the Examination of Water and Wastewater:

Metodo 4500 pH Value, or ASTM E-70 - Standard Methods for pH of Aqueous Solutions With

the Glass Electrode.

Note 28: BANHT – plantonic = Standard Methods 9221 C

Note 29: Total suspended solids (TSS) = Standard Methods 2540 D/ ISO 11923/ NACE

TM0173

Note 30: ASTM E 1064: Standard Test Method for Water in Organic Liquids by Coulometric

Karl Fischer Titration.

Note 31: CONTRACTOR shall provide the sample collection, preservation and storage in

accordance with appropriated rules of safety and engineering, and deliver it to PETROBRAS.

Note 32: CONTRACTOR shall perform O2 measurement on the Injection header of

Seawater and produced Water;

All Laboratory equipment and analysis methodology shall provide reliable results and shall

be submitted to PETROBRAS during the engineering design phase. PETROBRAS at their

own discretion will collect samples for further comparison with the measured results obtained

in the Unit.

All glassware and equipment should be calibrated with certified standards of RBC/Inmetro.

Laboratory shall be located in a non hazardous area, next to the Utilities Module and as close

to the Accommodation Module as possible. Laboratory drain system shall prevent the

possibility of back-flow of flammable vapors.

Air conditioning should be exclusive for laboratory facilities.

Separates sinks shall be installed. One sink dedicated to inorganics (e.g. water) and other

sink dedicated to organics (e.g. kerosene).

An eye-washer and shower shall be provided inside the laboratory.


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Each equipment should have its own socket.

CONTRACTOR shall supply the equipments required at I-ET-3000.00-8222-941-PJN-001.

Additionally CONTRACTOR must supply all the equipment necessary to perform the tests

required by RESOLUÇÃO ANP Nº 16, DE 17.6.2008.

3. UTILITIES

3.1. GENERAL

This item describes the minimum requirements and specifications that shall be applied to

utility systems and equipment of the Unit.

For heat exchangers requirements see item 9.3.

No steam system shall be accepted in the FPSO, as a whole (Topsides and Hull).

The instrument air shall comply with ISA 7.0.01 – Quality Standard for Instument Air.

3.2. SEAWATER LIFT SYSTEM

A Sea Water Lift System shall be installed to supply seawater to the deaerated water injection

system, to the production plant cooling water system and to meet other Unit’s needs. For

seawater characteristics, CONTRACTOR to consider Item 2.3.1 of this GTD and

METOCEAN DATA. For seawater temperature, CONTRACTOR to consider temperature at

each water depth.

An emergency lift system powered by the emergency generator shall be provided for

essential consumers.

For installation/maintenance purposes, the Unit shall be designed to install and repair the

intake water hose in the final location offshore.

The bottom of lift caisson or sea chest shall be provided with screen with mesh of 100 mm x

100 mm.

Chlorine shall be injected at the inlet of the seawater lift system intake water hose, to avoid

fouling or marine growth.


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CONTRACTOR is responsible to supply the chlorine to be used onboard. To control the

injection, according to demand, the residual chlorine content shall be monitored through the

redox potential, which shall be between 0.5 and 1 ppm. The design shall define the

monitoring point to assure the entire system protection.

There shall be an alignment from the seawater lift pumps discharge to the chlorine injection

points, in order to allow chlorine dosage to systems which are not in operation.

Electrochlorination units shall be installed in an open deck with a distribution tank provided

with a device which provides appropriate hydrogen dispersion.

There shall be modules of independent electrochlorination cells, including a stand-by

module, allowing isolation for maintenance without dosage interruption for consumers. The

unit shall be provided with a CIP (Cleaning in Place) system.

The seawater lift system shall be designed in order to supply, besides all other consumption

requirements, water to fill the service and production lines before service and production

lines pressurization and leak test.

Machinery protection system for sea water lift pumps shall be in accordance with API 670

If submersible pump types are selected, the piping arrangement shall contain minimum flow

lines, besides air release valves, upstream block valves, for each pump set.

3.3. COOLING WATER SYSTEM

A closed fresh water cooling system shall be provided to supply cooling medium to the Unit,

including the process plant. Two independent cooling systems shall be provided, one to cool

hydrocarbon (gas-cooling water, oil-cooling water and produced water-cooling water heat

exchangers) and the other one to supply cooling medium to the other systems

(accommodation, marine and etc.).

If CONTRACTOR decides to use PCHE (Printed Circuit Heat Exchanger), all the cooling

medium control valves shall guarantee the minimum flow rate to the PCHE (typically around

20%), rudder stop valves are recommended. A side stream filtration (polishing) system shall

be included and all measures necessary to guarantee the high quality and cleanliness of the

cooling water, as recommended by PCHE manufacturer. The coolant operating pressure

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to prevent boiling in low flow or turndown conditions, and higher than the sea water pressure,

to prevent sea water ingress to the closed loop in case of any leaks in the sea water cooler.

The design shall not use seawater as the cooling medium in hydrocarbon heat exchangers.

CONTRACTOR shall fulfill all Brazilian Regulatory Authorities regulations issued by

Environment Ministry (“Ministério do Meio Ambiente”), through its CONAMA Resolução

Nº357/2005 and CONAMA Resolução Nº430/2011.

CONTRACTOR shall provide a temperature transmitter with a high temperature alarm to

monitor sea water used as cold utility overboard temperature.

During project execution phase, CONTRACTOR shall provide cooling water system design

basis, such as system inlet and outlet temperature.

Machinery protection system for cooling water pumps for classified areas shall be in

accordance with API 670."

3.4. FRESH AND POTABLE WATER SYSTEM

Water maker units shall be installed to generate sufficient fresh and potable water for the

Unit’s consumption.

The fresh and potable water aboard shall comply with Ordinance MS Nº 2914/2011 and

ANVISA RDC 72/2009. Chlorination of potable water is mandatory. Special attention shall

be given to the quality parameters as well as cleanness requirements, tanks and distribution

lines disinfection, analysis routine and the separate storage of water for human consumption

of distinct sources. Material selection for potable water piping system (upstream and within

accommodation) shall avoid corrosion particles and contaminants.

Despite the Unit being prepared to generate fresh and potable water, a minimum of 2 (two)

filling connections (one for water and another for diesel) shall be installed at each bunkering

station. The bunkering stations to be located at Portside side of the Unit near each aft and

forward cranes respectively. The bunkering stations shall be located as close as possible to

the supply boat mooring area and allow quick operation. Piping shall be at least 4” diameter.

When provided by supply boat, the water salinity shall be monitored in the inlet through

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The bunkering stations shall be provided with separate hoses, connections and valves for

diesel (see item 3.6) and fresh water, as follows:

Connections:

• Type EVERTIGHT quick connect-disconnect couplers for diesel and fresh water

hoses;

• Filling station end: swaged-on male NPT carbon steel nipple + female thread/male

adapter + female coupler/female straight pipe thread (connected to the filling station

piping);

• Supply-boat end: swaged-on male NPT carbon steel nipple + female straight pipe

thread/female coupler.

Hoses:

• 120 m (3 x 40 m) for all hoses;

• The 3 x 40 m sections of the 4” diesel hoses shall be connected by non-leakage

couplings. WECO wing union type SHU and similars are not allowed. One connection

between the diesel hoses sections shall be of Safety Break-Away Coupling type to

prevent pull-away accidents and avoiding sea contamination;;

• 150 psi working pressure;

• Cover: black, weather, ozone and oil resistant high quality chloroprene rubber;

• Reinforcement layers: synthetic textile yarns;

• Tube: black, smooth fuel/oil resistant high quality nitrile rubber;

• Temperature range: -30 to +80 ºC.

Remarks: 1. Lifting clamps shall be provided at hose ends;

2. Hoses shall float (self floating hoses or with floating devices)

3.5. HEATING MEDIUM SYSTEM

A Heating Medium System shall be provided to recover the heat from the turbines exhaust

gas and from other systems. Each gas turbine generator shall have its own and dedicated

waste heat recovery unit (WHRU), in order to allow to run any turbine generator without


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impact on heating medium capacity. Heating medium piping and accessories shall be

designed to withstand expected temperatures and pressures.

Sample points for water shall be provided in the system.

Utilities consumers (desalinization units and marine systems facilities) shall not be directly

heated from the same heating source which is used in hydrocarbon processing equipment.

3.6. DIESEL SYSTEM

The diesel system shall be designed in order to supply, besides all other consumption

requirements, the service pump to push pigs, and clean flowlines (see item 2.6.1).

For details of bunkering station connections see item 3.4.

Diesel hoses located FPSO filling stations shall have end connection type dry disconnect

female coupling manufacture according to NATO STAGNA 3756 for operations with the

supply vessel. In addition, FPSO shall provide, as a loose item, one adaptor to connect in a

CAMLOK tank end of the supply vessel (old fleet vessels).

A drip-pan shall be installed to collect any leakage from all bunkering station connections

with manually operated drainage valve located at the pan bottom.

Diesel shall be filtered and on-line metered before being sent to the storage tank.

Diesel Lift pump and oil lift pumps for well service shall be designed in order to guarantee

the required flowrate of the well service pump (as per item 2.6.1).

A minimum configuration of 2 x 100% is required for both diesel lift pump and oil lift pumps

for well service which shall be designed in order to guarantee the required flowrate of the

well service pump (as per item 2.6.1). The diesel lift pumps and oil lift pumps shall be

dedicated to each fluid (segregated) and they shall have filter upstream and recicle for flow

control to avoid frequent start/stop and guarantee the required mixture of diesel/crude oil.

Facilities to inject hot diesel (maximum 90 ºC) upstream each production choke valve shall

be provided. The expected rate of hot diesel injection is 34 m³/h. Pigging will not use hot

diesel.

The diesel tank volume shall have enough capacity to provide diesel to be used as fuel for 7

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Note: in addition to the 7 days continuous storage for fuel, CONTRACTOR shall consider

5,000 m³ storage volume in the design to flush the production lines.

PETROBRAS will provide diesel in accordance with ANP requisition. DMA (Diesel Marítimo

TIPO A) shall be considered for turbogenerator projects.

3.7. SEWAGE SYSTEM

Please refer to chapter 16 – Marine Systems.

3.8. DRAIN SYSTEMS

Contractor shall design drain system to collect and convey unit drained liquids to an

appropriate treating and/or disposal system in such a way as to protect personnel,

equipment and to avoid environmental pollution. Drainage system shall comply with NOTA

TÉCNICA CGPEG/DILIC/IBAMA Nº 01/11 and MARPOL requirements. The effluents shall

be segregated, treated (TOG lower than 15 ppm) and monitored through dedicated TOG

analyzer(s), previously to being discharged overboard.

Drain systems shall be segregated into specific systems, each designed for a particular

type of stream, with no interconnection between the systems. Further to this, when

appropriate, features such as seal loops and air gaps shall be used to segregate areas

served for the same drain system.

Drains systems from hazardous areas shall be collected and routed completely separated

from the non-hazardous areas drains. Under no circumstances, liquids or vapors from these

areas shall be put in contact with each other.

The open drain system shall be designed in order to collect and drain the flowrate from rain,

fire-fighting activities and credible spills from equipment. The system design shall follow the

recommendations of standards ISO 13702 (ANNEX B), NORSOK P-002 (clause 7.2) and

NORSOK S-001. Open drain headers shall be provided with liquid seal and piping

submerged in the slop tank.

All closed drain shall be routed to a closed drain vessel, liquid in the outlet of vessel shall

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Process vessels, piping or other sources containing hazardous liquids which need to be

drained for interventions/maintenance/inspection reasons, and may not be drained directly

to atmosphere without undue risk to personnel, environment or assets from release of

flammable or toxic vapours, shall be connected to a contained drain system (e.g closed

drain). By toxic vapours CONTRACTOR shall consider streams containing poisonous

substances at critical concentrations, such as, but not limited to H2S. Critical concentrations

shall be discussed on a case by case analysis during detail design phase and submitted to

PETROBRAS’ comments.

Instrument drains shall be accounted for in hazardous area classification. The handling of

instrument drains shall be on a case by case analysis (special attention for poisonous

substances at critical concentrations), however in all cases, the instrument drain piping or

tubing shall be arranged so that the draining liquid is visible to the operator when the

instrument is being drained.

Equipment foundations, steel outfits and topside module structures on exposed decks shall

be designed to avoid trapped water and guarantee a proper deck draining.

3.9. COMPRESSED AIR

Compressed air units installed in closed area shall be designed in order to reduce local hot

and/or umid air release. Air dryers exhaust flow shall be directed to exhaust system.

Compressor relief at partial load shall also be ducted to an exhaust system.

4. ARRANGEMENT

The Unit arrangement shall be consistent with the CONTRACTOR Hazard Management

Program. Risk assessments outputs shall be incorporated into the layout development and

optimization (See SAFETY GUIDELINES FOR OFFSHORE PRODUCTION UNITS -

BOT/BOOT).

In the developing of the facility layout, the following HSE points shall be considered, as a

minimum:

• Maximize natural ventilation.


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• Minimize escalation of ignited flammable or toxic release. Therefore, arrangement,

facilities and equipment shall prevent the possibility of propagation of any potential

risk from one area to another. For this purpose, equipment malfunction as well as

operational error shall be considered. In the developing of the process plant layout,

CONTRACTOR shall take measures to segregate equipment of oil treatment system

with large inventory of hydrocarbons considering the Inherently Safer Design (ISD)

philosophy whenever they are 'reasonably practicable'. Moreover, Heavy HC Rich

Stream Flash Vessel shall be segregated from key safety functions and large

inventories that can generate long-term fire scenarios minimizing the possibility of

Boiling Liquid Expanding Vapor Explosion (BLEVE).

• Minimize probability of ignition.

• Continuous permanent ignition sources shall always be installed in non classified

areas and their location must ensure that there is no risk to personal safety or to the

operation of any equipment.

• The Unit arrangement shall follow a logical sequence of process and utilities flows,

as well as provide the grouping of systems and subsystems. The routing of high-

pressure pipelines, with hazardous fluids (Heavy HC Rich Stream, for example), shall

be minimized without compromising maintenance and operation facilities. The HC

Dew Point and the Heavy HC Rich Stream Pumping units shall be located in Riser

Balcony side as close to the Heavy HC Rich Stream injection manifold as possible.

• Layout shall provide the maximum practical separation between: Classified Areas vs.

Non Classified Areas, Systems with hydrocarbon-containing inventory vs. potential

sources of ignition.

• The risk of loss of containment should be minimized by minimizing the possibility of

mechanical damage. Protecting hydrocarbon equipment from dropped objects should

be a main consideration. The outputs of dropped objects studies prescribed in

SAFETY GUIDELINES FOR OFFSHORE PRODUCTION UNITS - BOT/BOOT shall

be considered.

• Provision of suitable means for escape (whether or not these are regularly manned),

temporary refuge and evacuation. Stairs shall be used as the mainly way to escape

from areas. The use o ladders shall be minimized. Note: In accordance with item


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11.2.1 of ASTM F1166 (Standard practice for human engineering design for marine

systems, equipment and facilities) angle of Inclination for Stairs shall be determined

by the vertical change in height. Angles between 30 and 50° are acceptable but a

stair angle of 38° is preferred. Angles between 50 and 75° should not be used.

• Proper implementation of working environment (Human Factors) guidelines, tools and

techniques into the design (e.g.Proper and safe access for valves and equipment

operation according to criticality analysis. Equipments and valves operated manually

and routinely shall have permanent access).

• Human Factors Engineering shall be considered in the design, according to NR- 17

(Ergonomics). Specific report shall be issued, according to the NR-17 (Ergonomics)

and its application manual, and must include analysis of main activities (critical work

positions) at operational areas, maintenance, cargo handling and stairs and means

of access. Special emphasis must be given to the main ergonomic aspects of valve

and instrument positioning and access to equipment. Also the areas described in I-

ET-3010.1U-1350-190-P4X-001 shall have the ergonomic report as required. All

reports shall be issued according the AET method ( Ergonomic Work Analysis) and

shall be developed by qualified Ergonomic Professionals with experience.

• All equipment associated with emergency power (Emergency generator, emergency

switchboard, storage batteries and inverters, etc.) shall be situated in non-hazardous

areas, with adequate protection against fire and explosion.

The concept of Risk Tolerability Criteria in comparing alternative layout design shall be

considered valuable as part of the decision-making process, and will support in the

demonstration of the risk criteria have been achieved considering ALARP (As Low As

Reasonable As Possible).

CONTRACTOR shall carry out Layout Reviews considering HSE aspects.

The objective of these Layout Reviews is to identify any issues associated with the overall

planned layout of the topsides, utilities, marine systems and accomodations.

Layout review activities shall take place at different stages during the project development

cycle including all changes during the course of the project. These reviews shall be


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conducted with a multidisciplinary team to ensure that the requirements of all disciplines have

been incorporated in the layout design.

Complementary to item.5,4.3.10 of SAFETY GUIDELINES FOR OFFSHORE

PRODUCTION UNITS – BOT/BOOT, the gas dispersion study shall consider presence of

toxic gases (e.g H2S) in vent of the slop tank and produced water tank.

The offloading station shall be located at stern and bow (see the OFFSHORE LOADING

SYSTEM REQUIREMENTS document, as indicated in item 1.2.1).

The use of long-bolt (wafer) type valves for services which contains flammable or

combustible fluids shall not be acceptable. As the only exception, LUG type valves with

threaded holes would be acceptable.

Pipings and fittings shall be designed so that, for their removal, its not be necessary

dissassemble parts of skids main structure.

4.1. SUPERSTRUCTURE (ACCOMMODATIONS)

Concepts for living quarters and storage areas shall comply with the CS Rules, OHSAS

18001, Brazilian Regulations (NRs, especially NR 37 ) and safety requirements of SOLAS.

For detailed information about Accommodations and Compartments, see I-ET-3010.1U-

1350-190-P4X-001.The smoking area shall be provided in the outer area with natural

ventilation and protected from the weather and shall comply with Civil law 12.546/2011 and

Decree 8262/2014.

The smoking area shall be an open safe area, 360 degree open to the environment with

natural ventilation.

Galley, mess room and storage area shall comply with RDC 216/2004 and RDC 72/2009,

ANVISA, with emphasis on the separation between vegetables, meat (poultry, fish and red

meat), pasta and storage areas, and waste disposal.

The infirmary installations shall comply with NORMAN 01 CHAPTER 9, SECTION V;

ANVISA RDC 50/2002 and ANVISA Resolution RDC 222/2018.

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CONTRACTOR shall submit a maintenance and load handling plan evidencing that the

arrangement of the process plant equipment, skids and accessories allows maintenance at

site without affecting the production/processing capacity of the Unit according to the technical

specification hereinafter considered.

Enough space for operational maintenance of production plant equipment shall be

provided, taking into account the personnel circulation, safety and CS requirements

(Human Factor Engineering shall be considered as part of this assessment).

CONTRACTOR shall take into account the effects of green water, according to item 11.6.3,

with the vessel in a maximum draft condition, to define the height of the main process plant

deck level as well as its layout. Location of equipment on the main deck shall be minimized.

In the development of layout, drainage systems and fire fighting means of the areas reserved

for storage of chemicals and gas cylinders, CONTRACTOR shall follow applicable

requirements for safety, health and environment, as well as take in consideration chemical

compatibility.

Each module shall be provided proper means of containment and drainage to prevent liquids

falling on sea, main deck or the deck below.

All equipment and components subject to leakage or overflow of combustible and / or

flammable liquid, contaminated liquids, and chemicals shall have individual containment and

drainage.

Special attention shall be taken related to confinement of these equipment in order to

guarantee adequate ventilation in case of gas dispersion accidental scenarios.

PIG launchers and receivers doors should face outboard of the platform to minimize the

possibility of any projectiles hitting personnel or other equipment.

4.3. UTILITY ROOM (ENGINE ROOM)

CONTRACTOR shall submit a maintenance procedure plan evidencing that the Unit

arrangement for utility systems, skids and accessories allows maintenance at site with a

minimum disturbance of the Unit’s performance.

4.4 DIVING FACILITIES


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CONTRACTOR shall provide the Unit with diving stations preferably at main deck level, to

be used during CS underwater surveys, pull-in/pull-out operations, risers inspections, etc.

The diving stations shall be in compliance with NR-15, NORMAM 15 and IMCA D023

guidelines, whichever is most stringent. The stations shall not interfere with the FPSO

facilities and other operations (supply boats, cargo transfers, etc). The following

requirements shall also be fulfilled:

• Proper means (cranes, mono-rails, skidding, crawlers, slings, rigging, etc.) for the

installation/de-installation of the diving equipment on the stations shall be available.

The heaviest piece of equipment to be handled is 5 mT

• Access to the diving stations shall not be dependent on vertical ladders, which may

require specific training for work at height or hinder evacuation of injured personnel

• Each station shall have enough room for the minimum diving equipment required by

IMCA D023

• Gas discharges (e.g. inert gas vent posts) and overboard points (e.g. slop tanks,

produced water) shall not interfere with diving operations

• Each station shall be provided with the utilities listed below:

o Compressed air - two outlets for diving bell and ballast winches:

- Required pressure: 7 kgf/cm²

- Required outflow: 20 Nm³/min

o Electric power - 2 outlets for diving equipment (from different power sources

and backed by the emergency generator):

- 440V/60Hz/30 A/3 phases

o Fresh water supply – one outlet for cleaning diving equipment and clothes:

- Required pressure: 1 kgf/cm²

- Required outflow: 20 l/min

o Communication:

- One telephone connection for internal and external calls


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- One web connection access intranet and internet

CONTRACTOR shall also provide permanent areas on both sides of the main deck,

accessible by cranes and with same utilities listed above, for the installation of diving

equipment.

CONTRACTOR shall supply round padeyes SWL 10 mT along the hull sides and a handrail

system in closed pattern on the bottom to help divers work during CS underwater surveys.

All hull openings and overboards below maximum draft line shall be provided with watertight

covers. Sea chests must have its grills provided with articulated joints at the lower edge, for

opening without removal.

The diving stations layout, locations plan and the diving equipment handling plan shall be

submitted for PETROBRAS.

4.5 HELIDECK

The helideck shall be designed and located according to Brazilian Navy Regulations

(NORMAM) including NORMAM 27 and CAP 437. In addition the following

international/national standards shall also be complied (latest editions):

• ICA 63-10 Estações Prestadoras de Serviços de Telecomunicações e de Tráfego

Aéreo – EPTA. DECEA;

• ICA 63-25 Preservação e Reprodução de Dados de Revisualizações e

Comunicações ATS – EPTA. DECEA;

• “Standard Measuring Equipment for Helideck Monitoring System (HMS) and Weather

Data", HCA, Bristow Group, Bond Offshore, CHC;

• MCA 105-2/2013 Manual de Estações Meteorológicas de Superfície - DECEA.

Meteorological and ship motion data shall be transmitted to HMS (Helideck Monitoring

System) in real time, through analogic or digital applicable interface.

CONTRACTOR shall ensure remotely access to HMS, at any time, through internet. Such

access shall be available in real time to Petrobras and Helicopter Operator Company through


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the same screen/system used by radio-operator of FPU. The Internet access shall be

compatible with standard software, e.g., Microsoft Internet Explorer, Mozilla Firefox or

Google Chrome.

HMS and all related systems/sensors shall be considered essential loads and shall operate

even in case of loss of power in the main generators.

CONTRACTOR shall present evidence that there is no interference between Unit’s normal

operation and helicopter operations. An Exhaust Gas Dispersion Study shall be implemented

in order to verify the influence of exhaust gas from turbogenerator, fire pumps, emergency

and auxiliar generators over the helideck.

To establish the safe location of the helideck, the environmental effects shall be considered,

such as wind direction and velocity, as well as aerodynamic aspects (turbulence over the

helideck), and the temperature rise due to exhaust gases. Hot plumes over the helideck,

generally, are related to main turbo-generator chimneys, however, the other equipment (for

instance: emergency generators or auxiliaries and fire-fighting pumps, etc.) should also be

considered in the identification of potential sources of hot gases.

CONTRACTOR shall present evidence that helideck final location minimizes downtime by

using computational fluid dynamics (CFD) studies, considering all the aspects mentioned

above.

The design of the helideck shall be submitted to CFD studies for the evaluation of hot air flow

and exhaust according to CAP 437, section 3.10. Petrobras recommends using Method 3

described in Norsok C-004, section 5.4: "A method using Computational Fluid Dynamics

(CFD) codes to determine the acceptable level of risk for helicopter offshore operations in

relation to the emission of hot gas of Turbine Exhaust Outlets - "Method 3".

CONTRACTOR shall paint in the helideck a codification (to be informed during execution

phase) as per NORMAM 27.

4.6 SAFETY MAINTENANCE UNIT (SMU)

CONTRACTOR shall provide one station at the main deck level to receive the gangway of

the Safety Maintenance Unit. This station shall be at the opposite side of the riser balcony

and have a free area of 7 m x 7 m.


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The landing gangway should have the following characteristics:

• The elevation of the base shall be 20.45 m distant from the waterline.

• The landing gangway and the deck of the unit shall have structural capacity to resist the

following loads:

- Vertical load: 28 ton

- Longitudinal load: 2 ton

- Transversal load: 6 ton

• The region must also be able to operate as a storage area. For this purpose it shall be

disigned withstand an overload of 15 KN/m².

• The gangway support deck should be marked with the appropriate cone support location

and 2 cone padeyes that should be 2.5 m from the center and 1.5 m from the edge. Each

eye should have the capacity of 5 tons and be faced to the floor so as not to damage the

gangway cone.

• The water and diesel filling stations should be close to the base, to ease the connection of

hoses passing through the gangway.

4.7 LAY-DOWN AREAS

In addition to the chemical storage area, the Unit shall have lay-down areas with space and

location compatible with the type and frequency of loads to be handled.

CONTRACTOR shall provide:

• One main lay-down on process plant deck level, with minimum overall free area of

300 m², covered by the aft crane, located within a Non-Hazardous Zone;

• One lay-down area on process plant deck level covered by the forward crane;

• Lay-down areas on main deck level covered by at least one of the Unit cranes.

All lay-down areas shall be provided with structural barriers to avoid damaging facilities

during any material handling operations and high strength wooden planks for industrial use.


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5. HEATING VENTILATION AND AIR CONDITIONING SYSTEMS (HVAC)

5.1. GENERAL

The air conditioning and ventilation systems shall be calculated to suit the site (see

METOCEAN DATA) environmental conditions. For determining the design conditions (dry

and wet bulb temperatures) CONTRACTOR to use ASHRAE methodology (Fundamentals

Handbook - Climatic Design Information – 2013 edition), adopting a percentile of 0.4% for

monthly design dry-bulb and mean coincident wet-bulb temperatures. Mean conditions for

XXXXX Basin are as follows:

SUMMER

- Dry Bulb Temperature (TBS): 32°C

- Relative Humidity: 61%

- Daily Temperature Range: 3,6°C

5.2. HVAC SYSTEMS

In general, the minimum air change required due to safety and hygienists requirements for

ventilated rooms is 6 changes per hour (considering recirculation). For compartments where

the inside equipment handle hydrocarbons, the minimum air changes per hour shall be 12,

as required in SAFETY GUIDELINES FOR OFFSHORE PRODUCTION UNITS -

BOT/BOOT.

There shall be an independent system of air conditioning for sealed batteries room.

Cooling fluids with HCFC and CFC are not acceptable. Only cooling fluids with HFC are

acceptable.

Insulation shall be provided with CFC-free polyurethane foam injected under pressure for

uniform thermal efficiency and strength.

The air intakes shall be placed in a safe area and, whenever possible, where the prevailing

winds are favorable.

Supply air for sealed and non-sealed batteries shall be supplied to the room at floor level

and be exhausted through the upper part (as high as possible) of the room facilitating the


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removal of hydrogen released by the batteries and avoid the formation of hydrogen gas

pockets near the room’s ceiling.

Whenever main classified areas ventilation equipment is lost, standby equipment shall start

automatically.

The ventilation systems shall not connect the following compartments:

• Battery room and laboratories exhaust with risk of contamination with other compartments

• Areas of different classification of electric equipment installation.

Air intakes ducts/sections shall be designed to ensure a retention time sufficient to allow the

closure of the damper before the air contaminated with gas reach the Air Handling Unit.

Means shall be provided for manual opening of fire dampers and tightness dampers.

External air drawn into the HVAC system must be taken from a safe area, located at least 3

meters away from classified areas and 4.5 meters from exhaust ventilation systems,

combustion discharges and vents. It shall be guaranteed that HVAC equipment selected

shall be capable of operating under conditions described in item 12.5.2.

For rooms where any unit fed by emergency generator is installed, the HVAC equipment

configuration 2 x 50% (minimum) shall be used. It shall be provided means for manual

opening of the dampers in rooms that have internal combustion engines, when they draw the

combustion air from the room.

Closed compartments with openings located less than 3.0 m distant from classified area limit

shall be positively pressurized and monitored. Ventilation and air conditioning operational

conditions shall be continuously monitorated and any fail shall be remoted alarmed in control

room. Closed compartments with internal sources of flammable gases or vapors shall be

pressurized negatively to neighbor compartments.

Accommodation shall be slightly pressurized and designed to function without build-up of

high pressure by providing pressure relief dampers where necessary. The system design

shall include suitable quantity of outside air to maintain a positive pressure in the building

and to meet the air change requirements of designated POB.

5.3. REFRIGERATION SYSTEM (PROVISIONS)


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Cooling fluids with HCFC and CFC are not acceptable. Only cooling fluids with HFC are

acceptable.

Insulation shall be provided with CFC-free polyurethane foam injected under pressure for

uniform thermal efficiency and strength.

5.4. CONTROL AND OPERATION

Independent air supply systems, with their own air reservoirs, shall be provided for fire

dampers and pressurization of instrumentation panels located in hazardous areas. This shall

be provided in order to avoid any further consequence caused by a fault in the air supply.

Application and installation of fire damper shall be based on the recommendations of SOLAS

and Classification Society requirements.

5.5. VENTILATION OF THE TURRET AREA (NOT APPLICABLE)

Not applicable.

5.6. STANDARDS AND BRAZILIAN REGULATION

CONTRACTOR shall comply with applicable Brazilian Regulations and ISO 15138.

The minimum outside airflow per person is 27 m3/h, in order to comply with Brazilian

Legislation for Conditioned Rooms (“Portarias do Ministério da Saúde MS 3523/1998”, “MS

9/2003” and Resolução CONAMA 267). Ducts shall be designed and assembled taking into

consideration the requirements for inspection and maintenance established by Health

Ministry. For Battery room (Non-Sealed Battery), the minimum airflow shall be also

calculated for the H2 dilution as defined in IEC 61892-7.

5.7 ELECTRICAL SWITCHBOARD ROOMS (E-HOUSE)

E-House (Electrical Switchboard Room) shall be pressurized and air-conditioned inside

temperature (<24oC), 2 x 100% or 3 x 50% machines. Variable Speed Drive, if used, shall

be installed in air-conditioned rooms.


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Sealed type or VRLA type batteries shall be installed in air-conditioned rooms inside

temperature (<25oC). A minimum of 12 changes per hour shall be assured.

UPS and battery chargers shall be installed in air-conditioned rooms.

Chilled Water Pipes and/or Cooling Water shall not be installed inside panels rooms,

electrical equipment, transformers rooms, control rooms, radio room and telecom. Exception

to condensed water drain piping from air cooled HVAC equipment. In this case, equipment

and piping must always be located on the floor level and close to the bulkhead. It shall be

foreseen a restricted area around the HVAC equipment (50 cm radios), surrounded by a

physical barrier of at least 20 cm height, with two drain collecting points to ambient outdoor.

5.8 HVAC EQUIPMENT

All HVAC equipment shall be provided with Anti Vibration Mounts (AVM) in order to reduce

vibration levels transmitted to structure.

Compressor shall be scroll or screw type, semi-hermetic.

All external air intakes shall have droplet eliminators with filters.

5.9. DESIGN REQUIREMENTS FOR VENTILATED AND AIR CONDITIONED ROOMS

Table 5.9.1 – Design Requirements for Ventilated and Air Conditioned Rooms


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1 - Renovations of air per hour or enough flow to keep gas and vapor concentration rates

below 20% LEL for compartments with flammable gases or vapors considering the maximum

leakage possible in normal operational conditions, whichever is higher.

2 - The biggest airflow shall be considered.

3 - Not applicable

EQUIPMENT CONFIGURATION [3],[4]

Min Air

ch/h

Manned areas –

Control Room, Radio Room [5]

[6]24 50 1.5 27 2x100%

sedentary w ork

Ballast Control Room (for

Semi-submersible

units)

24 [7] 50 1.5 27 2x100%

Changing Room w ith

toilet35 n/a 15 n/a n/a 2x100%

Laundry 35 n/a 40 n/a n/a 2x100%

Freezers Compartment

[8]24 n/a 1.5 27 2x50%

Restroom/WC 35 n/a 15 n/a n/a 2x100%

Mess Room [9] 24 55 1.5 17 1x100% [10]

Library, Offices Music Room, Kiosk, Coffee Shop, Phone Cabin,

Meeting Rooms

24 50 1.5 27 1x100% [10]

Dry Provision Store [11]

24 50 1.5 - 1x100%

Gymnasium 24 50 1.5 27 1x100%

Living quarter areas

Games Room 24 55 1.5 17 1x100%

Cinema, TV/Video

Room, Briefing Room

24 55 1.5 17 1x100%

Cabins[12] 24 50 1.5 27 1x100%

Galley 24 55100%

outside airf low

27 2x100% [13]

Corridors [14] 35 n/a 6 n/a n/a 2x100%

Stairw ays 35 n/a 6 n/a n/a 2x100%

AMBIENT EXAMPLESINTERNAL

TEMPERATURE – Max. Dry Bulb (°C)

RELATIVE HUMIDITY

(%)

MINIMUM AIRFLOW (ch/h)

[1]

OUTSIDE AIRFLOW CALCULATION CRITERIA

[2]

m3/h per person


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4 - For those rooms not described in table above, standby equipment requirements is only

applicable for essential and classified areas and where continuous operation is necessary.

5 - Not Applicable

6 - The Main Air Conditioning System which attends the Central Control Room, Radio Room,

Telecom and UPS must be independent from the others accommodation rooms

7 - In emergency condition, the maximum temperature of 40 ° C shall be adopted, without

air-conditioning system, which can be obtained through a ventilation system back-up or using

their own fans of AHU, if applicable

8 - Condensing units shall be located outside of compartment.

9 - The air of the mess may be partially or totally exhausted through the galley exhaust

system.

10 - In case total decentralized system is used at least one fan-coil shall be installed for each

conditioned compartment. For big compartments or those with a high human concentration

(such as recreation rooms), more than one fan-coil shall be provided to guarantee a correct

air distribution. The central fresh air-handling unit shall have a 2x100% configuration.

11 - No re-circulation air to the Central Air Conditioning unit is permitted.

12 - The exhaust shall be through a duct grille or through a door grille. When there is an

associated WC, the air may be partially or totally exhausted through a door or a bulkhead

grille to the WC.

13 - Configuration also valid for exhaust fans.

14 - This air may also serve as make-up air for other rooms (WC, laundry, etc.):

• The air shall be supplied at the lower part of the stairway through grille(s);

• It shall be avoided to supply air directly to the steps, to avoid uncomfortable conditions;

• The air shall leave the compartment at the upper part;

• There shall be a specific duct branch for the stairways, not only for the supply but also for

the exhaust air;

• It shall be guaranteed positive pressure close to outdoor openings.


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Living quarter areas

Medical Unit [1][2][3]

24 50100%

outside airf low

- 1x100%

Laboratory [1] 23 50100%

outside airf low

- 2x100% [4]

Tools Room, Electrical,

Instrumentation and Mechanical

Workshops

24 50 1.5 27 1x100%

Welding room, Blasting Room, Paint Shop [5]

40 n/a 12 n/a n/a 1x100%

Paint Shop [6] 40 n/a 12 n/a n/a 2x100%

Warehouse/Store

35 n/a 6 n/a n/a 1x100%

Unmanned w ithout

Inert Gas Generator

Room40 n/a 30 n/a n/a 2x100%

electrical equipment

Paint Store 35 n/a 12 n/a n/a 2x100%

CO2 Room 35 n/a 12 n/a n/a 2x50%

Garbage Room 35 n/a 12 n/a n/a 1x100%

Purif ier Room 40 n/a 12 n/a n/a 2x50%

Machinery Room (FPSO)

[7]40 n/a 6 n/a n/a 1x100% [8]

Unmanned w ith

electrical equipment –

w ithout critical instrument

Unmanned w ith

Normal Electrical Panels

Rooms [9], Essential

Electrical Panels

electrical equipment

Rooms [9] [10],

UPS/Battery Charges Room

[10]

Telecom. Room

Unmanned w ith

automation panels

Remote I/O Panels Room

35 n/a 6 n/a n/a 2x100%

Equipment rooms w ith

temperature-critical

instruments

Equipment rooms w ithout temperature-

critical instruments

2x100% [14]

Battery room (Vented

battery)[15][16]35 n/a 30 n/a n/a 2x100%

Battery room (Valve-

regulated Battery)

[10][11][12][13]

24 50 12 -

n/a n/a 2x100%

24 50 1.5 27 2x100%

Light manual w ork

Light manual w ork

Transformer room

40 n/a 6


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1- 100% outside air means that all the room air shall be exhausted and not be mixed or

recirculated to any other HVAC system: Design Criteria for HVAC Design.

2 - No re-circulation air from the Medical Unit to the Central Air Conditioning unit is permitted:

Design Criteria for HVAC Design.

3 - When there is a WC specific for the medical unit, the air shall be totally exhausted through

door or bulkhead grilles to this WC.


5 - These values apply for normal ventilation of the rooms. Specific ventilation for room

operation shall be included in scope of supply of welding and blasting room.

6 - These values apply for normal ventilation of the rooms. Specific ventilation for room

operation shall be included in scope of supply of Paint Shop.

7 - Machinery rooms are rooms containing only equipment (pumps, compressors, etc.) and

their drivers/push buttons, where no electrical panel is installed.

8 - For rooms where any unit fed by emergency generator is installed, 2 x 50% configuration

shall be used.

9 - Relative Humidity must be greater than 30%. .

10 - In emergency condition, the maximum temperature of 40°C shall be adopted, without

air-conditioning system, which can be obtained from AHU or through a ventilation system

back-up if applicable..

11 - The minimum airflow shall be also calculated for the H2 dilution as defined in IEC 61892-

7: Safety requirements compliance

12 - Valve-regulated Battery shall also have an exhaust system, which shall comply with

Battery Rooms requirements established in item 5.2.

13 - Battery Room must have an exclusive exhaust system. Supply system shall only be

installed in case battery room location jeopardizes the direct outside air intake with not

suitable air admission risk.


15 - The minimum airflow shall be also calculated for the H2 dilution as defined in IEC 61892-

7.


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16 - Battery room must have an exclusive exhaust system. Supply system shall only be

installed in case battery room location jeopardizes the direct outside air intake with not

suitable air admission risk.

17 - Ventilation system for Utilities Room must be in accordance with the last revision of

S.O.L.A.S. (Petrobras Safety Philosophy shall also be considered) and Classification

Society recommendations.

18 - Ventilation system for Cargo Pump Room must be in accordance with the last revision

of S.O.L.A.S. (Petrobras Safety Philosophy shall also be considered) and Classification

Society recommendations, regardless there is a cargo pump or not.

19 - Engine radiator shall be mounted on an external bulkhead of the room (direct driven fan

by engine). The necessary engine cooling and combustion air shall be supplied by radiators

fan.

20 - One ventilating fan (1x100%) shall be supplied for operate when generator is not

running and guarantee 6 air changes/hour in the room

Production Modules

40 n/a n/a n/a

Utilities Room [17]

40 n/a 6 n/a n/a 2x50%

Cargo Pump Room

(for FPSO) [18]

Fire Fighting Pump – in operation

40 n/aTo be defined by

manufacturern/a n/a 2x50%

Fire Fighting Pump – not operating

35 n/a 6 n/a n/a 1x100%

Diesel Auxiliary/Emerg

ency Generation – in

operation

40 n/a 6 n/a n/a note [19]

Diesel Auxiliary/Emerg

ency Generation – not operating

35 n/a 6 n/a n/a note [20]

2x50%

Unmanned w ith diesel

engines

Unmanned

40 n/a 20 n/a n/a


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6. SAFETY

6.1. GENERAL

The Unit’s safety philosophy shall comply with SAFETY GUIDELINES FOR OFFSHORE

PRODUCTION UNIT - BOT/BOOT (see 1.2.1).

6.2. ASBESTOS POLICY

CONTRACTOR shall remove all materials containing asbestos from the Unit and assure that

the materials are disposed of properly. No new materials containing asbestos shall be used.

6.3. RISK MANAGEMENT

A Risk Management Program shall be implemented, to continuously monitor and control the

risks identified by the Risk Analysis and Evaluation studies during contract termas defined in

SAFETY GUIDELINES FOR OFFSHORE PRODUCTION UNIT - BOT/BOOT.

PETROBRAS shall take part in any Risk Assessment or workshop, for example: Layout

Reviews, HAZOPs, and Preliminary Hazard Analysis .

PETROBRAS shall participate in the SGSO audit, including the verification of Critical

Elements of Operational Safety mentioned in item 5.4.2 of the SAFETY GUIDELINES FOR

OFFSHORE PRODUCTION UNITS - BOT/BOOT.

An independent Consultant Company shall be hired to perform the risk assessment studies

established in the scope of the project. This Consultant Company shall have a proven

previous experience in this type of studies.

At early stage of the project, CONTRACTOR shall provide a HSE Plan for the all life cycle

phases of the project. This HSE Plan shall be updated as required and according project

phase. As reference, HSE plan can follow the "IOGP report 423 - Appendix 3: Guidelines for

Working in a Contract Environment". The HSE Plan shall include a description of the scope

and methodologies that will be followed.

The Qualitative Risk Assessments, Consequence Analyses, SAFETY REPORT and the Risk

Management Program, as defined in SAFETY GUIDELINES FOR OFFSHORE

PRODUCTION UNIT - BOT/BOOT item 5, shall be submitted to PETROBRAS for comments

/ information.


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6.4. NOT APPLICABLE

6.5. NOT APPLICABLE

6.6. SAFETY BARRIERS MANAGEMENT

During operational phase a Safety Barriers Management System shall be in place, covering

the Critical Elements of Operational Safety for the major hazards. The system shall

monitor the status of Safety Barriers considering their integrity, based on preventive and

corrective maintenance, tests, inspections and audits of these barriers, as a minimum. The

first audit of the safety Barrier System shall be performed before the start of the first oil.

The results of this monitoring shall be integrated through a permanent online user-friendly

graphic interface, preferably using bow tie methodology, and shall be available to

PETROBRAS on real time.

CONTRACTOR shall submit to PETROBRAS for comments/information the philosophy and

methodology of the proposed Safety Barriers Management System prior to implementation.

6.7. PEOPLE ON BOARD (POB) MANAGEMENT SYSTEM

CONTRACTOR shall design and install an Electronic POB Management System

incorporated to Unit’s Safety Procedures. This System aims to:

• Provide in real time the number and identification of persons on site (POB system);

• Provide an electronic solution to perform the mustering process in case of General

Alarm (E-mustering system);

• Register the personnel location and control the access (E-Tracking system).

• The Electronic POB Management System shall be based on RFID technology.

Different solutions can be accepted by PETROBRAS, provided the following:

o Same final specifications;

o Any different solution must be presented to PETROBRAS.

The system shall be able to accommodate extraordinary events (major maintenance,

construction work, etc.) leading to the presence of additional personnel and also some

routine events such as daily visitors.

6.7.1. E-MUSTERING (POB-M)


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The system shall provide accurate on-line real-time information to site relevant personnel in

order to control/manage the mustering and evacuation process and allow emergency follow-

up:

• Allow people to check at mustering area

• Allow follow-up of mustered people on the site itself and on connected installation (if

relevant)

• Allow identification and location of people member of the Emergency Response Team

• Allow management of escape means

• Allow the possibility of managing people having evacuated and then returning to the

Unit

• Identify missing personnel during mustering process.

Each person allocated to an emergency role must be clearly identified in the system.

The system shall be able to generate a report which will indicate, as a minimum, personnel’s

name and surname, assigned TAG number, his/her last registered location, his/her job

position and eventually his emergency role, his/her assigned lifeboat, his/her assigned

muster point.

The System shall also be able to provide typical statistics and indicators (timing of

movements of people, duration of mustering, anomalies, etc).

6.7.2. E-TRACKING (POB-T)

The system shall record when personel is entering/exiting selected locations which shall be

defined during detail design phase, for example, restricted access areas, accommodations,

e-house, pump room, machinery room. Readers shall be placed at entry/exit points to allow

personel to register in/out. Real-time information shall be available on the central system

concerning identification and tracking of all personnel on each location. A general view shall

represent the status of the site.

All events (entry allowed or refused, bad TAG reading) shall be logged.

6.7.3. TECHNICAL REQUIREMENTS


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All system equipment shall be adequate for the hazardous zone it will be installed/used.

POB-M/T field equipment shall be certified for zone 1 so that they can remain energized in

case of gas detection.

The full system shall be suitably designed for permanent operation in marine environment.

Considered as a safety system, the POB-M/T system shall be fully redundant.

The POB-M/T system shall be designed in such a way that the failure of any server,

communication or network equipment, power supply unit, interconnection cables shall not

result in a loss of service in any situation. The POB-M/T hard disk backup shall be performed

using RAID technology.

The POB-M/T system shall be stand-alone (dedicated system), with minimum interaction

with CSS.

The POB-M/T central system shall be duplicated on site in two systems (system “A” and “B”)

located in different technical rooms. Those systems shall be interconnected through

duplicated link and synchronized at all time. Sign-in operations shall be updated on both

systems in real time.

POB-M/T central systems shall be fed from redundant UPS power supplies with minimum

autonomy of 12 hours.

At the Muster Points, Emergency Response Room, PETROBRAS’ representative office and

Control Room, a secured Wireless Access point and HMI shall be provided. The HMI of the

application shall be user friendly and provide in a very clear way all useful information for the

mustering process. All wireless access point shall be duplicated; one connected to System

“A” and the other one to System “B”. Wireless network for POB-M/T shall be independent

from other operational wireless networks.

It shall be ensured that all POB-M/T field equipment are always connected and synchronized

with the system in operation. All field equipment shall be powered and data connected to

both systems “A” and “B” through segregated cable route, for real-time update.

Readers shall be equipped with LED and sounders to show correct sign-in regarding POB-

M/T and refused sign-in (location overmanned, tag incorrect, etc), as well as lost link with

POB-M/T system. Readers and their supports shall be visible and clearly identified.


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In case of central systems failure, readers shall be equipped with buffer in such a way to

ensure local sign-in storage. Reader memory capacity shall allow local sign-in operations

(capacity to be defined during execution phase). Sign-in data shall be updated on servers as

soon as systems recover.

The TAG shall be generated on site. TAG shall be based on a bracelet waterproof or

equivalent. It shall be ensured that the tag shall be easily worn by personnel at all time,

without creating any safety risk.

The system shall take future requirements into consideration: 20% input/output spare shall

be supplied for future expansion (i.e. increase in number of readers). In addition, 20% of

unused shelf space shall be available in the cabinets.

The system access shall be controlled according to the level of authorization to

access/modify the system.

The System shall allow remote access using IP protocol and shall be directly connected to

the FPSO firewall.

6.7.4. INTERFACES

The POB-M system shall be connected to the General Alarm system to allow beginning of

muster process as soon as an alarm occurs.

POB-M/T systems shall be minimally interfaced with the CSS system:

• POB-M/T shall report system failure alarm to CSS (alarm shall be available in control

room);

• CSS shall send shutdown signals to POB-M/T.

6.8 PROCESS SAFETY SPECIAL REQUIREMENTS

Besides the technical requirements established at the I-ET-3010.00-5400-947-P4X-011

(SAFETY GUIDELINES FOR OFFSHORE PRODUCTION UNITS – BOT/BOOT), some

process safety special measures shall be foreseen.


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The following equipment shall have their supports protected by PFP (Passive Fire

Protection): Free Water Separator (FWKO), Inlet Gas Separator, Test Separators and

Electrostatic Treaters.

The gas detection system shall be able to detect propane and methane, within the

flammability limits provided at the I-ET-3010.00-5400-947-P4X-011.

The firefighting strategy for oil and condensate (Heavy Hydrocarbon Rich Stream) pool fires

shall meet the requirements defined in the item 3.1.1.2 of I-ET-3010.00-5400-947-P4X-011.

Evacuation, escape and rescue plan shall consider accidental scenarios from the PHA

(Preliminary Hazard Analysis) and Consequence Analyses, according to the item 5.4.3.15 of

I-ET-3010.00-5400-947-P4X-011.

The cryogenic effect of condensate (Heavy Hydrocarbon Rich Stream) leaks in installations

shall be analyzed. Risk reduction measures shall be proposed. The analysis shall include

impacts on the flare system and segregation of drainage systems for low temperature

discharges.

An external thermal insulation to the Heavy Hydrocarbon Rich Stream Flash Vessel, to

minimize liquid vaporization due to heat from the external fire scenario, shall be provided.

To reduce the probability of BLEVE, a remote connection point for water injection into the

Heavy Hydrocarbon Rich Stream Flash Vessel and the Cold Separator, during an emergency

scenario, shall be foreseen.

The floor under the Heavy Hydrocarbon Rich Stream Flash Vessel and the Cold Separator

shall have a minimum slope of 2.5% to ensure that, in case of leakage, the liquid moves

away from the vessel.

At least two firewalls (“J60” class fireproof) shall be foreseen. The Heavy Hydrocarbon Rich

Stream Pump and its discharge shall be isolated by a firewall, keeping the entire Heavy

Hydrocarbon Rich Stream injection line isolated from the process plant. Another firewall shall

be foreseen alongside the riser balcony, from the Main Deck to the Process Deck.

The living quarters’ forward bulkhead shall be classified as “J60”.

The length of the Heavy Hydrocarbon Rich Stream injection line shall be minimized.

The Heavy Hydrocarbon Rich Stream injection line shall be welded, the use of flanges shall

be only in the extremities.Passive Fire Protection (“J60” fireproof class) and deluge


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throughout the line from Heavy Hydrocarbon Rich Stream Pump discharge up to the injection

SDVs shall be provided.

The Fire Propagation Study and Smoke Dispersion Analysis shall consider the following

scenario: leakage of condensate at the Heavy Hydrocarbon Rich Stream Flash Vessel and/or

any other point in the high-pressure injection system, including the Hydrocarbon Rich Stream

Pump and its discharge.

For the interconnected systems operating at different pressures, the higher design pressure

shall be considered to define the piping and equipment minimum wall thickness for the

systems.

To reduce the risk of loss of condensate (Heavy Hydrocarbon Rich Stream) containment,

for the design of safety instrumented functions (SIFs), the possibility of considering the

requirements defined at the item 5.3 of ISO 10418 shall be analyzed. This approach, if

adopted, shall comprise, at least, the Hydrocarbon Dew Point Control System, Cold

Separator, Condensate Dryer, Gas/Liquid Exchanger, Heavy Hydrocarbon Rich Stream

Heater, Heavy Hydrocarbon Rich Stream Flash Vessel, Heavy Hydrocarbon Rich Stream

Pump, Heavy Hydrocarbon Rich Stream Cooler, to the Heavy Hydrocarbon Rich Stream

injection riser connector. The analysis shall be submitted to Petrobras for approval.

7. AUTOMATION AND CONTROL

7.1. GENERAL

The Instrumentation/Automation design is to be mainly based on an integrated operation and

supervision system of the Unit as a whole, through graphic interfaces.

The Unit shall be supplied with an overall Automation and Control (A&C) Architecture

composed by field instruments and control/automation systems. The main characteristic of

the Architecture is the integration promoted among these systems by means of redundant

digital communications along all layers, including optical and electrical networks, switches,

hubs modems etc. The supervision and operation of the Unit shall be integrated for hull and

topsides.

The systems of the A&C Architecture, which shall be supplied with the Unit, are:

• Control and Safety System (CSS);


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• Supervision and Operation System (SOS);

• Addressable Fire Detection System (AFDS);

• Flow Metering System (FMS);

• Cargo Tank Monitoring System (CTMS);

• Subsea Production Control System (SPCS);

• MODA Riser Monitoring System (MODA);

• Rigid & Hibrid Riser Monitoring System (RHMS)

• Closed Circuit Television System (CCTV);

• Dynamic Positioning Reference System (DPRS);

• Positioning System for Mooring Operation and Offset Diagram (POS);

• Offloading Monitoring Telemetry System (OMTS);

• Environmental Monitoring System (ENV);

• Annulus pressure monitoring and relief system

• Machinery Monitoring System (MMS)

• SMBS Control and Monitoring System;

A&C systems response time, from initiator devices to final elements shall not compromise

safe operation of the Unit. Redundancy shall be applied to the A&C systems and field

instrumentation to the extent necessary to guarantee safe and reliable operation of the Unit

and for achieving the required overall reliability, maintainability and availability in

accordance with the Unit technical and CS requirements.

The A&C systems shall be designed in order to assure that a single failure at any component

of the system would not cause a loss of a safety function or system. Network between any

CSS Controller and its respective RIO (Remote Input Output) Panels shall be routed by

redundant physical independent routes.

For the field instrumentation, the redundancy criteria shall be such that a fail on instruments

or equipment, junction boxes, cabling, remote I/O cards or field level networks do not

compromise a safety function by a single failure. Signals from process redundant systems


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and voting instruments shall be distributed in the I/O cards in a way that avoids the loss of

more than one system in case of an I/O card failure.

During early execution phase, PETROBRAS will submit to CONTRACTOR a Subsea

Operating Philosophy, to describe the intended operations. Detailed Subsea Operational

Procedures will be provided by PETROBRAS 4-5 months prior to start of operations, in

order to guide the interface relations between PETROBRAS and CONTRACTOR. With this

information, CONTRACTOR shall prepare and submit for PETROBRAS approval an

Interface (FPU-Subsea) Operating Manual.

CONTRACTOR shall develop an automation and control system security program for the

unit, in accordance with IEC 62443 (see section 7.2.3).

All instruments, panels and equipment (if applicable) proper to be used in hazardous areas,

shall have conformity certificates complying with: the latest revision of API RP 505, IEC-

60079 and all its parts; PORTARIA INMETRO Nº 179, de 18/maio/2010, and its annexes,

changed by PORTARIA INMETRO Nº 89, de 23/fereveiro/2012 (or the one which is in

force); and shall be approved by Classification Society. Every Automation and Control

System device shall be properly connected to earth/ground. Panels and instruments shall

have earth/ground bars. Instrinsically safe instruments shall be connected to a separate

earth/ground bar, specific for instrinsically safe circuits. Earth/Ground Fault devices shall be

installed, alarming in SOS should such faults occur.

No equipment with obsolescence foreseen within 10 years from project phase shall be

considered in Unit's design.

7.2. CENTRAL CONTROL ROOM (CCR)

The Unit shall have a CCR with an integrated working area from which the Topside process

and utilities plant, subsea production/injection systems and Hull/Marine systems shall be

continuously monitored, operated and controlled, enabling the proper operation of the Unit

as a whole.

The supervision and monitoring shall be done by navigating through HMI (human machine

interface) screens showing the Topside and Hull/Marine diagrams and other fixed structures.

The main components of this hardware (such as equipment, valves, detectors, process

analyzers and instruments) shall be animated by displaying changes to their status, such as

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The term HMI refers to the displays, computers and software that serve as an interface with

all field systems, specialized in processing/displaying the field data in a suitable format,

leaving the tasks of data gathering to the other systems, such as CSS, CTMS, SPCS and

OMTS.

The SOS has at least five primary functions:

(i) provide visualization of process parameters and methods to control the process;

(ii) provide alarms summary and history, as well as indications to the operator that the

process is outside limits or behaving abnormally or that the CSS has detected faults

or failures;

(iii) provide a method to allow the operator to understand the process behavior, as

tendency and time response (trending functionality);

(iv) provide reports of the unit, such as overrides;

(v) provide means to collect and register historical data.

All safety interlocks, Fire & Gas logics, automated sequences and on/off controls shall be

represented in Cause and Effect Charts in SOS HMI screens.

If the Unit is provided with a permanently manned engine control room (ECR), the engine

room equipment shall be controlled from the ECR and only the critical alarms and status

signals repeated back to the CCR.

The CONTRACTOR shall mirror all CCR (and ECR, if applicable) HMIs at the PETROBRAS

Office (according to item 4.1) , including Alarms Management System (alarms' and events'

logs and statistics screens), in order to allow PETROBRAS to monitor the UNIT.

A “black box” device shall be foreseen into the CCR, in which all Topsides, subsea and

Hull/Marine systems monitored data, events, audit trails and alarms of the last 30 (thirty)

days shall be recorded in an easily removable data storage unit which can be carried off the

Unit in case of abandonment.

CONTRACTOR shall design and operate an Alarm Management System according to the

standard IEC 62682, in order to ensure that:

• UNIT shall have an alarm management system that provides the operator with an

adequate set of warnings against excursions beyond its safe operating limits during

normal operation and during abnormal situations (startups, shutdowns and upsets);


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• Actions necessary to bring the process back to its normal state shall be defined for

every safe operating limit and details shall be available to the operator. The operator

shall be capable to execute such actions.

The alarm management system shall also minimize and where necessary suppress standing

alarms, nuisance alarms, repeating alarms and alarm floods.

7.2.1. PLANT INFORMATION SYSTEM (PI)

During the operation phase, all main Topsides, Subsea, Turbomachinery and Hull/Marine

data shall be available online at PETROBRAS’ PI®-Server, with the following conditions:

• The interface between supervisory system and Plant Information System (PI ®) shall

be based on OPC (Ole for Process Control) (provided that the supervisory system is

based on Windows ®)The interface between the supervisory system and OPC shall

be hosted in a dedicated server in the supervisory system layer, if it is Native OPC

Client-Server. (CONTRACTOR)

• OPC-PI® drivers with store and forward mechanism shall be hosted in a computer

located in the DMZ, that is installed in Telecommunications Room. (CONTRACTOR)

• Both supervisory system-OPC and OPC-PI® interfaces shall be installed in

redundancy, including hardware and licenses. (CONTRACTOR)

• PI-Server software shall also run in DMZ (PI-Server will be located in on-shore DMZ).

(PETROBRAS)

• The data to be stored in PI® will be defined by PETROBRAS during the Detail

Engineering Design Phase.

• In case of using a diferent protocol for the communication between supervisory

system and PI®, the licenses and configuration, if so, shall be provided by

CONTRACTOR.

• Information and network security mechanisms between CONTRACTOR supervision

and operation system and PI® shall be installed and configured by CONTRACTOR.


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Figure 7.2.1 – Plant Information Architecture

Reference for Telecommunication System: I-ET-0600.00-5510-760-PPT-565

Telecommunications Systems.

7.2.2. CONTROL NETWORK ARCHITECTURE

Network communications among the CSS Controllers shall preferentially be by a

deterministic network protocol. Signals to indicate safety interlock actions among CSS

Controllers and/or Package Systems (including SIL Logic Solvers, if used) shall be hard

wired, e. g., a signal from the FGS/ESD Controller to PSD Controller indicating that a process

shutdown shall occur due to confirmed fire in the process plant shall be done using a digital

output card in the FGS/ESD side and a digital input card in the PSD side. Network

interconnection of the CSS Controller systems shall not be used for safety and interlock

actions initiation.

All network levels, supervision network, control network and field network shall have

diagnostics and Management System in order to indicate fault of communication at any level.

Proper actions shall be taken to assure the safety of the FPSO, i. e., all safety functions that

cannot be concluded shall lead the system to the safe position, e. g., valves shall go to their

fault position.

The Network Management System shall, at minimum: (1) be capable to show the installed

topology, (2) have network sniffer function, (3) switch remote configuration function (such

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The cabling for Ethernet network shall be done using ISO/IEC 11801 and ISO/IEC TR 14763,

all parts. All networks shall be certified in order to assure compliance of installation to the

design, to prevent communication faults and to grant peformance, reliability and avaliability.

7.2.3. CYBERSECURITY

In order to protect data to be transferred from the Automation network unit to Contractor

network, Petrobras corporate network and to the GIOP onshore rooms, it shall be foreseen

firewalls, passwords, virtual LANs (VLANs), flash drives disabling and routers.

Writing in CSS processors and in the supervisory software from outside the Automation

network shall not be allowed, unless explicitly authorized for Operation necessity. All writing

and reading accesses in the Automation network shall be logged and registered.

All data exchanged between Control and Automation System networks and Corporate

Networks shall be carried via DMZ located in the FPSO.

It shall be foreseen different firewalls for connection between the Automation network and

Petrobras corporate network/GIOP onshore rooms and between Automation network and

Contractor network.

7.3. CONTROL AND SAFETY SYSTEM (CSS)

The Unit shall be equipped with fully integrated and automated control system, named

Control and Safety System (CSS), to provide both control and safeguarding functions

according to SAFETY GUIDELINES FOR OFFSHORE PRODUCTION UNITS - BOT/BOOT.

The Electrical System shall possess an interface with the CSS, in order to automatically

switch off electrical loads in case of emergency. Besides, electrical loads shall be available

both for monitoring and control in the Automation System.

CSS shall have 3 independent layers of protection: process control, prevention and risk

mitigation, those subsystems (layers of protection) are named of PCS to process control,

PSD (Process Shutdown System) to prevention of risk and FGS (Fire & Gas System) to risk

mitigation. PCS' availability shall be greater than 99%, whereas PSD' and FGS' shall be

greater than 99,5%. PCS, PSD and FGS processors shall be located as close as possible to

CCR.


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A number of dedicated CSS controllers (redundant CPUs/processor modules in a fully hot

stand-by scheme), designed to be independent systems, shall be foreseen for the following

functions:

a. Process Control System (PCS), for Unit systems remote controlling and monitoring.

Regulatory control (PID), monitoring, remote actuation, control transmitters data acquisition

and process alarms shall be carried out by this system;

b. Process Shutdown System (PSD), for carrying out overall Unit safety and safeguarding

preventive automatic and manual actions. PSD functions are:

i) equipment variables and state monitoring, focusing on the detection of the escape of the

process conditions from normal operation boundaries;

ii) detection (and alarming) of abnormal process conditions;

iii) Automatic actions for process interlocking, process isolation (closure of shut down

valves) and electrical isolation (equipment power off), with the objective of preventing the

escalation of abnormal conditions into a major hazardous event and limiting the extent and

duration of any such events that do occur;

iv) Generation of ESD-1 and ESD-2 signals (for further details see I-ET-3010.00-5400-947-

P4X-011 - SAFETY GUIDELINES FOR OFFSHORE PRODUCTION UNITS - BOT/BOOT);

v) indication of the root cause of the emergency shutdown, whenever it happens,

highlighting it from the other causes and preventing its loss among the alarm avalanche

c. Fire & Gas System (FGS), for carrying out overall Unit safety mitigation automatic actions.

FGS whose functions are:

i) monitoring the presence of hazardous conditions at the FPSO, i.e., fire and gas detection;

ii) Presenting visual and audible alarms to the crew whenever emergency conditions

happen. The PA/GA (Public Alarm/General Alarm) shall be interconnected to the FGS in

order to allow for the automatic announcement of emergencies at the Unit's Loudspeakers.

This interconnection shall be made using discrete signals between those systems

iii) mitigation of the consequences of hazardous events, by automatically switching off

electrical equipment, performing process isolation (by closing shutdown valves),

performing process depressurization (by opening blow down valves) and by activating

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iv) start-up of safety actions in the HVAC of rooms and accomodations (closing dampers

and by shutting down fan motors, exhaust systems and air conditioning systems, as

appropriate)

v) Generating ESD-3P and ESD-3T and treating ESD-4. Both the starters and their

correspondent actions shall be physically connected to the FGS by hardwired connections

vi) These shutdown actions shall be started either by the automatic detection modes

aforementioned as well as by emergency pushbuttons in panels in the Central Control Cool

and in Radio Room. Manual Fire alarms shall also be scattered over the unit in order to

allow crew members to manually report fire conditions.

PCS shall be an independent system from PSD and FGS. It is recommended that PCS, PSD

and FGS be from the same vendor. All control loops shall be executed by one single

processor

The sensors that generate ESD signals and their corresponding automatic actions shall be

physically connected to the same subsystem (PSD), by hardwired connections.

CONTRACTOR shall update control loops tuning during plant start-up. CONTRACTOR shall

also present control strategies to minimize flow instabilities in separator vessels due to oil

slug.

Regarding the decision of using Safety Instrumented Systems (SIS) in accordance with IEC

61508/61511 for selected CSS safety interlocking loops, according to SAFETY GUIDELINES

FOR OFFSHORE UNITS - BOT/BOOT, should be evaluated by CONTRACTOR taking into

account the associated risks, the risk tolerability criteria, proper risk tool analysis and

Classification Society requirements. In case of using SIS, a Safety Integrity Level (SIL)

determination review (which shall be integrated to the Risk Management Program - see Item

6.5) shall be carried out to define the integrity levels required of the system(s) taking into

account the Unit safety life-cycle, according to IEC 61511- 1. These selected safety

instrumented functions shall be submitted to Petrobras for approval.

Automation system comissioning shall follow IEC 62381 and its references. Petrobras, at its

own discretion, may witness the Factory Acceptance Test (FAT) and the Site Integration Test

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All CSS components, including the ones internal to panels, shall be dimensioned taking into

account installed spare parts and avalaible space for future expansions. It shall be

considered expansions for use during detail engineering design phase and during the unit

life cycle. These expansions shall be considered for I/O count, trays, terminals inside panel

and junction boxes, CSS I/O addressing and controllers memory usage.

In order to accomplish that, at the end of basic engineering design, the I/O quantity shall be

counted. To this quantity, it shal be added 20%, for each panel, section and I/O type and

these shall be installed connected to a terminal strip.

Additionally, for each panel section, it shall be foreseen empty slots related to 10% of the

total I/O count of that section, for future use.

All automation and Control panels shall be resistant to regular movement and inherent

vibration of the Unit, electromagnetic interference and all Classification Society

requirements. Hoisting and fixing facilities, maintenance space and access protection shall

be granted. Panels shall be located in areas so as to prevent damages from mechanical

impact .

All Automation and Control panels located in non-classified internal areas shall have

minimum degree of protection IP-22, according to IEC-60529.

All Automation and Control Panels located in external areas (classified and non-classified

areas) shall be constructed in stainless steel AISI 316L, with IP-56 degree of protection

according to IEC-60529 and pressurization px type, according to NFPA-496.

7.3.1. PACKAGE AUTOMATION SYSTEMS (PAS)

Some equipment may be supplied as package units with their own Control and Automation

System. These shall also be integrated to the unit´s Automation & Control Architecture, and

shall comply with Classification Society rules, specially regarding to the segregation between

control and safeguarding functions. Fire and Gas signals of these package units shall also

be integrated to the unit Fire and Gas system.

Aiming to standardize the signals exchanged between the Package Unit and the CSS,

Package Units shall be classified according to their integration level with the CSS and with

the SOS, as follows:


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- P0 Packages: Package Units that do not possess their own control and safety system, and

therefore whose logic runs in the CSS;

- P1 Packages: Package Units that possess their own controller and a hardwired interface

with the CSS monitoring the main states of the package: Running, Stopped, Local/Remote,

Unit Alarm Malfunction (UAM), shutdown started (UAS-1), shutdown successfully completed

(UAS-2), blowdown started (UAB-1), blowdown successfully completed (UAB-2). Besides

from these state signals, P1 Packages shall receive from the CSS: a hardwired shutdown

request and a hardwired blowdown request.

- P2 Package: Package Units with the same requirements as P1 Packages, but, additionally,

it shall possess an IEEE 802.3 standard network connection with the SOS. This connection

with the SOS may not be redundant, however every package shall possess a unique door in

the communication SOS LAN Switches.

- P2S Package: Package units with the same requirements as P2 Packages, but,

additionally, it shall possess a dedicated HMI placed in the Central Control Room (CCR);

- P2C Package: Package units with the same requirements as P2 Packages, but,

additionally, it shall allow for remote operation, actuation and control of variables from the

SOS;

- P2SC Package: Package units with the same requirements as P2S Packages, but also

allowing for remote operation, actuation and control of variables from the SOS.

Note 1: In case a Package Unit is defined as P2C or P2SC, command signals shall arrive

from several different sources (SOS, local HMI, or, in P2SC cases, from their local IHM in

the CCR). Therefore, an additional programming shall be foreseen in the package controller

in order to allow for remote commands from the SOS.

Note 2: If required, other hardwired signals may be added between the Package Units and

the CSS. These signals shall be identified in the design documents, package per package,

based on the documentation supplied by the Package Manufacturers.

Note 3: Packages P2/P2S/P2C/P2SC shall be supplied with their respective communication

drivers to the SOS. OPC UA shall be used.

Note 4: During the detailed engineering design, the data that shall be sent to the SOS via

Ethernet network shall be defined in conjunction with Petrobras. The same applies to the


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Supervision screens. However all Package Unit's states and variables shall be available in

the Package controllers memory map for SOS consulting (regardless if used or not).

As a general rule, fire and gas detection and firefighting on the modules shall be performed

by FGS.

In case a package is contained in a hood, the fire and gas detection instruments and

firefighting equipment contained in the hood shall be connected to the Package Unit safety

control system.

The following summary signals shall be hardwired from Package Unit safety control system

to the FGS: fire detected, fire confirmed, gas detected, gas confirmed. Further details

regarding these alarms may be sent using network.

The Package Units load classification, i.e., whether the Package Unit is an emergency or

essential load, shall be informed in the Unit's design.

Every Package Unit shall possess a manageable ethernet switch internally. The Package

Unit shall be connected to the Automation network via this switch. CONTRACTOR shall issue

an IP list containing both the Automation network IPs and the Package Unit IPs.

The variables of P1 (hardwired), P2, P2S shall be available at the CCR HMIs for monitoring.

The variables of P0, P2C and P2SC packages shall be available at the CCR HMIs for both

for monitoring and operation.

7.3.2 ASSET MANAGEMENT

The following components of the Automation, Control and Instrumentations system shall

have diagnostic capabilities:

- Instrumentation, through a dedicated computer with Instrumentation Asset Management,

in order to allow maintainance personell to remotely configure and monitor instrumentation

healthy through HART network. This is extended to package units´ instrumentation.

CONTRACTOR shall inform which instruments will be monitored and send its procedures to

do so;

- Automation network: all automation network levels shall have Diagnostics and Management

System in order to indicate failure of communication at any level. The Network Management


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System shall, at minimum: (1) be capable to show the installed topology, (2) have network

sniffer function. The Automation network switches and routers shall have remote

configuration functions, using SNMP protocol;

- Control and Safety System equipment (CSS): CPUs, network cards, I/O cards, power

supplies and industrial switches/routers,

- Supervision and Operation System (SOS): CPUs and network cards.

7.3.3. AUTOMATION AND CONTROL SYSTEM PROGRAMMING

Considering that discrete inputs may assume different state values at NORMAL and

ABNORMAL conditions, it is necessary to establish internal standard values to represent

them, in order to simplify the programming. Internally to CSS controllers, the binary polarized

input signals shall always assume the following values downstream the polarization logic:

Variable in Normal Condition = 0 (FALSE);

Variable in Abnormal Condition = 1 (TRUE);

Physical Inputs: Open Contact = 0 (FALSE); Closed Contact = 1 (TRUE);

Logical outputs shall be 1 (TRUE) in the following conditions: Engine ON and Valve Opened

(all valves).

The final control elements shall be energized under the following conditions:

- CO2 (triggering valve): Energize to open;

- SDVs and XVs (fail close valves): Energize to open;

- BDVs and XVs (fail open valves): Energize to close.

Note: Since 1 means “valve opened”, the output of the BDV and fail open XV blocks shall be

connected to a logical inverter (“0” to “1” and “1” to “0”).

Logic shall base itself on the premise that devices are fail-safe, i.e., in case of failure (power,

network, component malfunction, etc), the respective component shall receive the logic value

that ensure that the safety of the unit is preserved. The fail safe states of all outputs shall be

defined and documented in the design.

The following items shall be supplied by CONTRACTOR:


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- The source codes of the application of the Automation and Control System in editable

formats, with comments;

- Automation and Control System programming tools and licenses;

- Configuration files of the supervision and operation system, including possible auxiliary

scripts;

CONTRACTOR shall also ensure that the same items above shall be supplied for Package

Automation Systems (PAS).

7.4. CARGO TANK MONITORING SYSTEM (CTMS)

The Cargo Tank Monitoring System shall provide reliable, fast and highly accurate

information on tank level and related variables (draft, pressure, etc.).

The CTMS comprises, at least, the following main subsystems:

• Cargo tanks level measurement;

• High level interlocking independent from control;

• Cargo tanks inert gas pressure measurement;

• Draft electronic based level measurement;

• Loading calculator (hardware and software);

• Online oxygen content in produced inert gas.

CONTRACTOR shall control an inventory of all storage tanks containing fluids that have

the potential to overfill resulting in a vapor cloud explosion. CONTRACTOR shall also

assess the risks, document and implement remedial steps. This also refers to topside

storage tanks.

7.5. SUBSEA PRODUCTION CONTROL SYSTEM (SPCS)

The SPCS comprises the integration between the Floating Production Unit (FPU) Central

Control Room (CCR), Flow Metering System (FMS) and Control & Interlocking System (CIS)

equipment and the following types of subsea control systems:


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• Electrohydraulic Multiplex Subsea Control System (EHMUXSCS) for all wells and

manifolds that can be connected to the FPU;

• Direct Hydraulic Control System (DHCS) for two (2) wells connected directly to FPU,

for Subsea Riser Base Gas Lift Valves (SRBGLV), for Subsea Canyon Base Gas Lift

Valves (SCGBLV) and for the FPU’s Subsea Emergency Shutdown Valves (SESDV).

7.5.1 TYPES OF CONTROL SYSTEM USED BY THE SUBSEA EQUIPMENT

7.5.1.1 Electrohydraulic Multiplex Subsea Control System (EHMUXSCS)

This type of subsea control system combines two fundamental characteristics at the same

time:

• It allows the use of a small number of common hydraulic supplies from topside to actuate

all subsea valves. This is accomplished locally subsea by opening or closing an

electrohydraulic valve that provides hydraulic pressure from a common supply header from

topside to the subsea equipment valve actuator.

• It allows the use of a small number of common electrical supplies and a communication

link from topside with a “Subsea Electronics Module (SEM)” subsea to select

electrohydraulic valve that provides hydraulic pressure from a common supply header from

topside to the subsea equipment valve actuator to open or close it according to the

Operator command selected topside.

The electrohydraulic valve is typically a three-way, two position, solenoid operated

Directional Control Valve (DCV) or “Solenoid Valve”. The DCV pressurize or depressurize

the hydraulic control line to the subsea valve actuator whenever commanded to open or

close by the SEM after this one receives the respective command from the SPCS. A given

number of DCV are housed together with two SEM inside a retrievable Subsea Control

Module (SCM) installed in a Wet Christmas Tree (WCT) or subsea manifold. A typical gate

valve counts as one SCM Function, while choke valves and some types of downhole valves

with two actuators requires two SCM Functions.

The EHMUXSCS used by PETROBRAS is an open-type system. When the hydraulic

pressure from the SCM common supply header for the subsea actuators is removed by its

respective DCV in the SCM, a given volume of hydraulic fluid between the DCV and valve

actuator is expelled (vented) to seawater by the SCM. The EHMUXSCS will use water-


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based hydraulic fluid that needs to be maintained according to ISO 4406 Class 17/15/12

cleanliness standard by the CONTRACTOR at all times.

Each subsea equipment with EHMUXSCS will be provided with two sets of dual redundant

hydraulic supplies from the SPCS HPU topside:

• The “Low Pressure” set with two individual supplies referred as LP1 & LP2 providing

between 4,000 psi and 5,000 psi operating pressure range for subsea gate valves;

• The “High Pressure” set with two individual supplies referred as HP1 & HP2 providing

between 6,500 psi and 7,500 psi for the WCT’s downhole valve(s). The upper limit may

be raised to 10,000 psi in the future if needed by PETROBRAS.

Data acquisition from subsea sensors is provided by the SCM. The SCM also provides its

own internal “housekeeping” data for periodic record and display by the SPCS. The open

or closed status of a subsea valve is provided by indirect means using the fast scan

monitoring of the pressure in the respective control function DCV outlet, together with other

measurements such pressure or flow rates in the SCM hydraulic headers and fluid vent.

Electrical power and communication for the SCM is provided from topside by a pair of

EHMUXSCS Control Cabinets. Power is feed by electric cables whilst communication is

provided by optic cables of the umbilical. This combination is referred as a “Channel or

Line”. A topside EHMUXSCS Control Cabinet pair provides two Channels for the SCM. The

Channels are referred as “Channel A” or “Line A” and “Channel B” or “Line B. Each Channel

will use one twisted pair or twisted quad for power and one optic cable with 8 monomode

fibers.

Each topside EHMUXSCS Control Cabinet pair is composed by two identical Control

Cabinet racks, with each rack dedicated to a SCM Channel. An EHMUXSCS Control

Cabinet rack typically houses the Channel A or B electrical power supply, optic modem, ,

and data servers. Each EHMUXSCS Control Cabinet rack also have a Programmable Logic

Controller (PLC) or industrial grade computer with the logic memory map of all subsea

valves, sensors, housekeeping data and status functions that the SPCS will access to send

valve commands and read all EHMUXSCS data relevant to SPCS operation.


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Both EHMUXSCS Control Cabinet racks belonging to the same pair will normally operate

in “hot stand-by” redundancy mode, with periodic update of their memory map variables.

One of the two SCM Channels will be always the “active” or “master”, with automatic or

manual change over to the other (“stand-by”) Channel in case of communication loss or

failure. Each EHMUXSCS Control Cabinet rack has network communication and hardwired

I/O interface with the CCR and CIS Systems in the FPU.

Additionally, each EHMUXSCS Control Cabinet rack has communication (digital, Modbus

RTU over EIA/TIA 485 phy, and analog, 4~20mA) interface with the Flow Metering System

(FMS).

Although the SPCS operation shall be fully integrated in the CCR, a limited degree of stand-

alone EHMUXSCS operation will be possible from a dedicated Operator Work Station

(OWS) to be supplied by PETROBRAS. The OWS is intended to offer temporary operation

back-up capability during CONTRACTOR integration work for EHMUXSCS Control

Cabinet racks. The OWS software and display graphics may not allow the same flexibility

and resources available in the CCR System. A pair of OWS will be provided for use in a

network with all EHMUXSCS Control Cabinet pairs from the same Supplier.

7.5.1.2 Direct Hydraulic Control System (DHCS)

This type of control system is defined here as the one which each valve actuator of a Wet

Christmas Tree (WCT), downhole valve, SRBGLV, SCGBLV or SESDV is directly connected

to topside electrohydraulic valve through a dedicated umbilical line (thermoplastic hose or

tube) in the control umbilical. The electrohydraulic valve, also referred as solenoid operated

Directional Control Valve (DCV) or “Solenoid Valve”, pressurizes or depressurizes the

umbilical control line directly to the subsea valve actuator.

A given number of DCV are housed together topside in a Well Control Rack (WCR), with

electrical power for the solenoids provided by the FPU CIS and pressurized hydraulic fluid

by the SPCS HPU. The Direct Hydraulic control system used by PETROBRAS is a closed

type system where the control fluid depressurized from an umbilical line by a DCV returns to

the SPCS HPU return reservoir. The SRBGLV/SCGBLV/SESDV will be actuated by a

dedicated control panel. The return fluid from each SRBGLV/SCGBLV/SESDV will not be

allowed to return to the SPCS HPU.


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The WCR and the SRBGLV/SCGBLV/SESDV Control Panel will provide the following

operating pressures according to type of equipment used:

a) 5k-Type WCT or 10k-Type WCT:

• Between 3,000 psi and 4,000 psi for all WCT gate valves;

• Between 4,000 psi and 5,000 psi for the WCT’s well downhole valve(s).

b) 10k-Type E&P Pre-sal standard WCT adapted for DHCS:

• Between 4,000 psi and 5,000 psi for all WCT gate valves;

• Between 6,500 psi and 7,500 psi for the WCT’s downhole valve(s). The upper limit may

be raised to 10,000 psi in the future if needed by PETROBRAS.

c) Subsea Riser Base Gas Lift Valve (SRBGLV), Subsea Canyon Base Gas Lift Valve

(SCGBLV) and Subsea Emergency Shutdown Valve (SESDV):

• Between 3000 psi and 4000 psi.

The open or closed status of a given subsea equipment gate valve is provided by indirect

means by monitoring the pressure in the respective control function DCV valve outlet in the

WCR or SRBGLV/SCGBLV/SESDV Control Panel for display in the respective well P&ID on

the CCR. The three 4-20 mA analog sensors of typical PETROBRAS 5k or 10k Direct

Hydraulic WCT (production pressure; production temperature and annulus or gas injection

pressure) are typically connected directly to the CIS by two electrical pairs in the umbilical.

The 4-20 mA analog sensors of SRBGLV/SCGBLV/SESDV are typically connected directly

to the CIS by six electrical pairs in the umbilical.

The exact configuration will be provided by PETROBRAS during the detail design phase.

The downhole pressure and temperature gauge will be connected directly to the topside

Signal Acquisition System (SAS) Panel (see item 7.5.7).

7.5.2 SPCS MAIN SPECIFICATIONS

The SPCS includes (but it is not limited to) the following types of subsea and topside

equipment listed below:


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• Wet Christmas Tree fitted with electrohydraulic multiplex subsea control system

(EHMUXSCS–WCT) Supplied by PETROBRAS;

• Wet Christmas Tree for direct hydraulic control system (DHCS-WCT)– Supplied by

PETROBRAS;

• Subsea gas production manifold fitted with electrohydraulic multiplex subsea control

system (MSPG) – Supplied by PETROBRAS;

• Downhole valves: DHSV (safety), VHIF (formation isolation valve, if installed) –

Supplied by PETROBRAS;

• Downhole Pressure & Temperature Transmitter (PDG) – Supplied by PETROBRAS;

• Subsea Emergency Shut Down Valve (SESDV) – Supplied by PETROBRAS;

• Subsea Riser Base Gas Lift Valve (SRBGLV) – Supplied by PETROBRAS;

• Subsea Canyon Base Gas Lift Valve (SCGBLV) – Supplied by PETROBRAS;

• Subsea Umbilical – Supplied by PETROBRAS;

• Topside EHMUXSCS Control Cabinet pair – Supplied by PETROBRAS;

• Topside stand-alone Operator Workstation (OWS) pair for all EHMUXSCS Control

Cabinet pairs from the same EHMUXSCS Supplier – Supplied by PETROBRAS;

• Topside Signal Acquisition System (SAS) Cabinet – Supplied by CONTRACTOR;

• Rack mounted Signal Acquisition System (SAS) for downhole pressure &

temperature transmitter (PDG) used for well with DHCS – Supplied by

PETROBRAS;

• Topside SPCS Hydraulic Power Unit (HPU) – Supplied by CONTRACTOR;

• Topside Well Control Rack (WCR) for WCT fitted with Direct Hydraulic control system

– Supplied by CONTRACTOR;

• Topside SESDV Control Panel – Supplied by CONTRACTOR;

• Topside Portable Umbilical Pressurization System (PUPS) – Supplied by

CONTRACTOR;


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The SPCS shall provide operation control and monitoring of up to Thirty-six (36) subsea equipment from the CCR:

• twenty six (26) EHMUXSCS-WCT. Each EHMUXSCS-WCT control and monitor the respective well downhole valves (DHSV and VHIF, if installed) and PDG.

• Two (2) DHCS-WCT for production wells, a set of downhole valves (DHSV and

VHIF, if installed) and the PDG for each satellite well;

• four (4) Subsea Emergency Shutdown Valves (SESDV);

• two (2) Subsea Riser Base Gas Lift Valves (SRBGLV)

• two (2)Subsea Canyon Base Gas Lift Valves (SCGBLV)

. The WCTs could be connected to the FPU in four different ways:

• Satellite wells: the WCTs are connected directly to the FPU by its own control

umbilical.

• Subsea interconnected pairs: two WCT share one umbilical

• Subsea distribution: a single umbilical could be shared by up to five (5) WCTs, limited to 2 producer wells per umbilical.

• Subsea Gas Production Manifold (MSPG): a single umbilical connected directly to the

FPU by its own control umbilical. Each MSPG can be connected to a maximum of

four (4) wells.

Note 1: The number of WCT, Manifolds, SRBGLV, SCGBLV and SESDVs will be confirmed

by PETROBRAS during the detail design phase.

Note 2: PDGs data shall be read by CCR from Topside EHMUXSCS Control Cabinet

Normal operation shall be performed from CCR screens selected by the Operator.

PETROBRAS will provide P&ID’s for each subsea equipment according to their respective

type of control system, for CONTRACTOR to include in the SPCS CCR screens. The P&ID’s

will include a selection of the most important EHMUXSCS and DHCS parameters that shall

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The SPCS HPU shall provide hydraulic supplies for EHMUXSCS , DHCS, MSIAs and

MSPGs. CONTRACTOR shall provide the SPCS HPU, the WCR, the SRBGLV/

SCGBLV/SESDV control panel and the PUPS according to the specifications 7.5.5, 7.5.6

and 7.5.9.

The SPCS hydraulic system shall be fully compatible with the following water-based control

fluids: MacDermid HW443, MacDermid HW525P and Castrol Transaqua DW. PETROBRAS

will select the fluid during execution phase.

CONTRACTOR shall provide the whole SPCS hydraulic system topside flushed to ISO 4406

class 17/15/12 cleanliness standard (former standard NAS1638 Class 6), using either

MacDermid HW443, MacDermid HW525P or Castrol Transaqua DW fluids (to be defined by

PETROBRAS).

CONTRACTOR is required to always recirculate the SPCS hydraulic fluid transferred from

fluid manufacture’s barrels to the SPCS HPU until achieving the required ISO 4406 Class

17/15/12 cleanliness specification.

Each umbilical slot hang off position (except for SRBGLV/SCGBLV/SESDVs) shall be

provided with four hydraulic supplies LP1, LP2, HP1 and HP2 directly from the SPCS HPU.

CONTRACTOR shall provide the topside hydraulic distribution for all LP1 and LP2

EHMUXSCS supplies with ½” Internal Diameter (ID) thermoplastic hoses or Stainless Steel

Tubes suitable rated for continuous operation with 5,000 psi (maximum) internal pressure.

CONTRACTOR shall provide the topside hydraulic distribution for all HP1 and HP2

EHMUXSCS supplies with ½” Internal Diameter (ID) Stainless Steel Tubes suitably rated for

continuous operation with 10,000 psi (maximum) internal pressure.

Two production well umbilical slot hang off positions shall provide a dual control system

capability to operate an EHMUXSCS-WCT or a DHCS-WCT. This umbilical slot hang off

position shall be provided additionally with sixteen (16) control lines from the WCR for the

operation of a 5k-Type or 10k-Type DHCS-WCT and downhole valves. At least four (4) lines


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shall be provided with 3/8” ID Stainless Steel Tubes to allow continuous operation with

10,000 psi (maximum) internal pressure. The remaining shall be provided with 3/8” ID

Stainless Steel Tubes or thermoplastic hoses rated for continuous operation with 5,000 psi

(maximum) internal pressure. The exact assignment of each line according to the DHCS-

WCT types will be provided by PETROBRAS during the detail design phase.

SRBGLV/SCGBLV/SESDV umbilical slot hang off position shall be provided with ½” ID

control lines rated for 5,000psi maximum operating pressure from the SESDV Control Panel.

The number of control lines will be provided by PETROBRAS during the detail design phase.

CONTRACTOR shall provide the integration (see below the definition for “integration”) of

Third Party SPCS equipment supplied by PETROBRAS. The main types of such equipment

are:

a) Topside Control Cabinets for EHMUXSCS;

b) SAS Panels.

Note: Topside Control Cabinets for EHMUXSCS are herein referred only as “SPCS Control

Cabinets”, except when each specific type is identified.

For the “Integration” specified above, CONTRACTOR shall provide the complete installation

and commissioning of all SPCS Control Cabinets’ racks and their OWS to be supplied by

PETROBRAS. CONTRACTOR scope of supply shall also include (but it is not limited to):

SAS Cabinet, , all cables (power; signal; instrumentation) with suitable connectors and

terminations required; CIS/CCR/FMS hardware and software; configuration of

CIS/CCR/FMS for communication with SPCS Control Cabinets; configuration of CIS/CCR

for SPCS cause and effect chart; configuration of SPCS operation screens in the CCR.

PETROBRAS will provide the dimension drawings and interface documentation for each type

of topside SPCS Control Cabinet and SAS Panels. PETROBRAS will also provide Third

Party technical assistance to CONTRACTOR’s integration work.

VERY IMPORTANT: The assignment of each well or manifold to specific SPCS Control

Cabinets is preliminary. PETROBRAS will provide the first assignment configuration of at

least one EHMUXSCS Cabinet pair up to three months in advance of the scheduled start of

operation offshore Brazil for CONTRACTOR make the interconnections in the Control

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CONTRACTOR shall provide installation, integration and commissioning for topside

EHMUXSCS Control Cabinets manufactured by four (4) different subsea control system

suppliers.

PETROBRAS will provide the topside SPCS Control Cabinets according to the Table 7.5.2.1

below:

Table 7.5.2.1: SPCS Topside Control Cabinets

Individual

Control

Cabinet

Number

Cabinet Pair

Type (note 1)

Channel

or Line Preliminary assignment

1

A

OP07 – OP08 – IWAG01 – IWAG04 – IWAG05 – IWAG06 -

SDU-02

2 B

OP07 – OP08 – IWAG01 – IWAG04 – IWAG05 – IWAG06 -

SDU-02

3

A OP05 – OP06 –

IWAG02 – IWAG03 – IW04 – SDU-01

4 B OP05 – OP06 –

IWAG02 – IWAG03 – IW04 – SDU-01

5

A OP01 – IW01 – SDU-04

6 B OP01 –IW01 – SDU-04

7

A MSPG-01

8 B MSPG-01

9

A GP01 – SDU-03

10 B GP01 – SDU-03

11

A GP03 – GP04 – IW03

12 B GP03 – GP04 – IW03

13

A OP03 – IW05

14 B OP03 – IW05

15

Note 1

A TEOAP-A TEOAP-A TEOAP-A

only TEOAP-A

only TEOAP-A

only only only

16 B TEOAP-B TEOAP-B

only TEOAP-B

only TEOAP-B

only TEOAP-B

only only

17 SAS Panel OP04 OP04 IWCS 1

18 SAS Painel IWCS 2 IWCS 3


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Notes and abbreviations:

Note 1 To be defined by PETROBRAS during detail design.

Quantity of SPCS Control Cabinet racks per FPU: eighteen (18).

MOST IMPORTANT: The assignment of each well or manifold to specific SPCS Control

Cabinets is preliminary. PETROBRAS will provide the first assignment configuration of at

least one EHMUXSCS Cabinet pair up to three months in advance of the scheduled start of

operation offshore Brazil for CONTRACTOR make the interconnections in the Control

Cabinet room.

CONTRACTOR shall provide installation, integration and commissioning for topside

EHMUXSCS Control Cabinets manufactured by four (4) different subsea control system

suppliers.

At least two EHMUXSCS Control Cabinets (one pair) will be delivered at the CONTRACTOR

shipyard. PETROBRAS is going to provide 60 man-days of technical assistance to the

CONTRACTOR for this first integration.

CONTRATOR shall take into account that not all topside SPCS Control Cabinets will be

available for shipyard installation before the FPU starts production.

CONTRACTOR shall provide at any time with no cost to PETROBRAS the installation,

integration and commissioning of any quantity of SPCS Control Cabinets up to the total

specified by Table 7.5.2.1, whenever requested by PETROBRAS, including while the FPU

is offshore. PETROBRAS will request to CONTRACTOR this offshore installation and

integration work with at least three months in advance. CONTRACTOR shall plan and carry

out this work with minimum or no impact for the FPU’s operation.

The layout of the SPCS Control Cabinet room shall allow the easy installation and removal

of each SPCS Control Cabinet rack, including while the FPU is offshore. Special attention

shall be given to position cable trays and junction boxes in order to cope with installing and

removing cable interconnections. Cable entries to each SPCS Control Cabinet shall be from

the bottom of each Cabinet rack.


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CONTRACTOR shall provide the cabling between each umbilical slot hang off electrical

junction box and the SPCS Control Cabinet room with at least six (6) high grade 0.6/1.0 kV

class 6 mm² twisted pairs with individual shield per pair with PE (Protection Earth) and two

(2) optic cables, with 8 monomode fibers type ITU-T G.652.D each, to be used by the

EHMUXSCS.

CONTRACTOR shall provide at any time with no cost to PETROBRAS the reassignment of

the electrical and optic connections between the six (6) twisted pairs and two (2) optic cables

from each EHMUXSCS umbilical to any individual topside SPCS Control Cabinet.

For this purpose, CONTRACTOR shall provide two (2) TOPSIDE ELECTRICAL OPTICAL

ASSIGNMENT PANELS (TEOAP-A and TEOAP-B). Each TEOAP (A or B) will be connected

to all EHMUXSCS control cabinets, respective A or B channels, i.e., TEOAP-A to all

EHMUXSCS Channel A control cabinets and TEOAP-B to all EHMUXSCS Channel B control

cabinets.

Each TOPSIDE ELECTRICAL ASSIGNMENT PANEL shall be in the form of a single,

enclosed type rack with front and rear doors that allows the electrical and optical connection

of the three (3) of the six (6) twisted pairs from each EHMUXSCS umbilical to any individual

topside EHMUXSCS Control Cabinet of the same Channel. The TEOAP shall allow changing

the connections very easily whenever required, without the need to reposition the cables

arriving to the panel itself. The use of wire jumpers between the TEOAP cable termination

blocks or something similar for this purpose may be considered. In a similar fashion, optic

cables shall have patch panels for connections, or similar solution. The final configuration

assignment between wells, manifolds and their respective control cabinets will be confirmed

by PETROBRAS up to 90 days before the FPU leaves the integration

shipyard.CONTRACTOR shall consider housing all Control Cabinets, TEOAP-A, TEOAP-B

, and SAS Panel in the same room to facilitate cable routing among them.

CONTRACTOR shall submit to PETROBRAS for approval the design documents for the

complete installation and commissioning of SPCS Control Cabinets, TEOAP-A, TEOAP-B

and SAS Panels. CONTRACTOR shall also submit to PETROBRAS for approval the SPCS

cause and effect chart.

CONTRACTOR shall guarantee the SPCS Control Cabinet room ambient temperature to be

kept lower than 35ºC at all times, taking as a premise that all SPCS Control Cabinets listed


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in Table 7.5.2.1 will be in full operation. The room temperature shall be monitored and

recorded at all times by the CCR.

Each EHMUXSCS Control Cabinet will be based on 19” type rack with preliminary

dimensions of: 900 mm (W) x 1,400 mm (D) x 2,500 mm (H). The exact dimensions will be

confirmed by PETROBRAS during the detail design phase.

CONTRACTOR shall provide permanent front and rear accesses for each SPCS Control

Cabinet rack. The access shall allow both front and rear doors to fully open when necessary.

PETROBRAS will provide to CONTRACTOR two (2) desktop Operator Work Stations for all

EHMUXSCS Control Cabinets from the same supplier. The Operator Work Stations can be

used as a local Master Control Station (MCS) with limited operator interface capabilities,

allowing some back-up to the full operation of the EHMUXSCS from the CCR.

CONTRACTOR shall provide room and desktop facilities in the CCR or nearby room for the

Operator Work Stations. Specifications of the cables and connectors between the

EHMUXSCS Control Cabinets and the Operator Work Stations will be provided by

PETROBRAS during the detail design.

CONTRACTOR shall request PETROBRAS to specify the communication network and

protocol interface between the following topside equipment:

a) CIS/CCR with each EHMUXSCS Control Cabinet;

b) Each EHMUXSCS Control Cabinet rack from the same subsea control system

supplier and their pair of OWS (three (3) such networks shall be implemented, being

one for each subsea control system supplier equipment);

CONTRACTOR shall provide all necessary switches Layer 3 to connect the equipment as

above.

Each network above shall have its own and exclusive cable network. For each one,

CONTRACTOR shall provide PETROBRAS’s choice among the two following options:

i. Ethernet TCP/IP with OPC protocol;

ii. MODBUS/TCP;


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Each network cable interface shall be 100-BASE-T or 100-BASE-FX type optical connection,

also to be defined by PETROBRAS together with the interface protocol.

CONTRACTOR shall provide the following digital hardwire shutdown signals from CIS to

each individual EHMUXSCS Control Cabinet rack:

• ASD (Abandon Ship and Total FPU Shutdown): 1-off signal activated by the CIS to

perform the shutdown sequence in all wells and the respective DHSV;

• ESD (Emergency Shutdown): 1-off signal activated by the CIS to perform the shutdown

sequence in all wells without closing the respective DHSV;

• PSD (Process FPU Shutdown): 1-off signal activated by the CIS to close the WCT

Crossover and Pig Crossover valves;

• USD (Well Shutdown): 1-off digital signal per well, activated by the CIS to perform the

shutdown sequence in each well individually except for the DHSV. The number of signals

shall be according to the number of wells controlled from the respective EHMUXSCS

Control Cabinet. Each subsea manifold requires 1-off USD signal per well. The exact

configuration will be provided by PETROBRAS during the detail design phase.

For each shutdown signal above, CONTRACTOR shall provide a CIS-powered 24VDC two

wire signal, hardwired to a relay type Digital Input interface on each EHMUXSCS Control

Cabinet rack. PETROBRAS will inform the maximum current drawn by each coil during the

detail design phase. For further information about ASD, ESD, PSD and USD, see SAFETY

GUIDELINES FOR OFFSHORE PRODUCTION UNITS - BOT/BOOT.

The EHMUXSCS Control Cabinet will provide the signals of the subsea gas lift flowmeters

to the FMS. This signal connection will require the following interfaces between each

EHMUXSCS Control Cabinet and the FMS:

• 4x MODBUS RTU over EIA/TIA 485 communication links;

• 12x 4-20 mA analog outputs;

These interfaces will be used to send gas lift instruments variables to the FMS flow computer,

for flow calculation. The subsea gas lift instrument will be either a Venturi or a Cone type

primary element. For each gas lift instrument, MCS will provide to the FMS the differential

pressure across the primary element, static pressure and temperature.


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Cabling and interfaces into the FMS for this application is under CONTRACTOR’s scope.

Additionally, MEG injection flowrates, measured by individual flowmeters in each topside

MEG line connected to the subsea umbilicals, shall be available in the CCR to be acquired

by the EHMUXSCS Control Cabinet, either by OPC or Modbus TCP (to be defined with

PETROBRAS during execution phase).

Each SPCS Control Cabinet rack shall be powered by 220 VAC @ 60 Hz from the FPU

Uninterruptable Power Supply, allowing 15 minutes of full power operation after an electrical

shutdown. Power consumption of each EHMUXSCS Control Cabinet rack will be 6.0 kVA

and heat dissipation of each Control Cabinet will be 3.5 kW.

NOTE: The higher power consumption of each EHMUXSCS Control Cabinet when

compared to previous projects is to consider the application of three (3) Subsea Chemical

Injection Valves in the WCT. This higher power consumption requirement will be confirmed

by PETROBRAS during the execution phase.

CONTRACTOR shall provide the interface between the SAS Panel and the CCR. All DHCS-

WCT sensors shall be displayed in the respective well P&ID screen.

7.5.3. SPCS UMBILICALS AND TOPSIDE UMBILICAL INTERFACES

The SPCS shall be designed for operation with the following types of control umbilicals:

a) 7,500 psi Standard TPU (Thermoplastic Umbilical):

• 4x 1/2" x 7,500 psi – Thermoplastic hoses for the four EHMUXSCS hydraulic

supplies;

• 6x 1/2" x 7,500 psi – High Collapse Resistant (HCR) hoses for chemical injection;

• 1x electrical cable with four (4) individually screened (shielded) twisted pairs of 4.0

mm² or 6.0 mm² conductors with Voltage Class 0.6/1.0 (1.2) kV, according with

IEC 60502-1 (Power cables with extruded insulation and their accessories for

rated voltages from 1 kV (Um = 1.2 kV) up to 3 kV (Um = 3.6 kV)).

b) 10,000 psi STU (Steel Tube Umbilical):


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• 12 x 1/2" x 10,000 psi – Steel Tubes (see notes below);

• 1x Electrical cable with six (6) individually screened (shielded) twisted pairs of 6

mm² or 10 mm² or 16 mm² conductors with Voltage Class 0.6/1.0 (1.2) kV,

according with IEC 60502-1 (Power cables with extruded insulation and their

accessories for rated voltages from 1 kV (Um = 1.2 kV) up to 3 kV (Um = 3.6 kV));

(see note II below)

• 2x Fiber optic 8F monomode specified according to ITU-T G.652.D; (see note II

below)

Note about configuration according to WCT control system:

I. EHMUXSCS: four (4) ST for EHMUXSCS hydraulic supplies and six (6) or eight (8) ST for chemical injection;

II. The exact assignment will be provided by PETROBRAS during the detail design phase.

c) 10,000 psi STU (Steel Tube Umbilical):


• 1x Electrical cable with six (6) individually screened (shielded) twisted pairs of 6 mm² conductors with Voltage Class 0.6/1.0 (1.2) kV, according with IEC 60502-1 (Power cables with extruded insulation and their accessories for rated voltages from 1 kV (Um = 1.2 kV) up to 3 kV (Um = 3.6 kV)); (see note III and IV below)


III. EHMUXSCS: four (4) ST for EHMUXSCS hydraulic supplies and six (6) or eight (8) ST for chemical injection;

IV. The exact assignment will be provided by PETROBRAS during the detail design phase.

c) 5,000 psi Standard TPU for 5k DHCS-WCT:

• 9x 3/8" x 5,000 psi – Thermoplastic hoses for direct hydraulic control of the WCT

and downhole valves;

• 3x 1/2" x 5,000 psi – High Collapse Resistant (HCR) hoses for chemical injection;

• 1x Electrical cable with three twisted pairs of 2.5 mm2 conductors with Voltage

Class 0.6/1.0 (1.2) kV, according with IEC 60502-1 (Power cables with extruded


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insulation and their accessories for rated voltages from 1 kV (Um = 1.2 kV) up to

3 kV (Um = 3.6 kV)) for the WCT pressure and temperature transmitters, and the

PDG for the respective well.

d) 10,000 psi STU (Steel Tube Umbilical):


• 4 x 1” x 10,000 psi - Steel Tubes (see note below VI);

• 1x Electrical cable with six (6) individually screened (shielded) twisted pairs of 6 or 10 or 16 mm² conductors with Voltage Class 0.6/1.0 (1.2) kV, according with IEC 60502-1 (Power cables with extruded insulation and their accessories for rated voltages from 1 kV (Um = 1.2 kV) up to 3 kV (Um = 3.6 kV)) (see note below VI);

• 2x Fiber optic 8F monomode specified according to ITU-T G.652.D;( see note VI below)


V. EHMUXSCS: four (4) ST for EHMUXSCS hydraulic;

VI. The exact assignment will be provided by PETROBRAS during the detail design phase.

e) 5,000 psi Umbilical for SRBGLV/SCGBLV/SESDV:

• 9x 1/2" x 5,000 psi – Thermoplastic hoses or STU (Steel Tube)

• 1x electrical cable with six (6) individually screened (shielded) twisted pairs of 6.0

mm² conductors with Voltage Class 0.6/1.0 (1.2) kV, according with IEC 60502-1

(Power cables with extruded insulation and their accessories for rated voltages

from 1 kV (Um = 1.2 kV) up to 3 kV (Um = 3.6 kV)).

Note: The exact SRBGLV/SCGBLV/SESDV umbilical configuration will be provided

by PETROBRAS during the detail design phase.

All subsea control umbilical slot hang off positions (including SRBGLV/SCGBLV/SESDV)

shall allow the operation of any of the following umbilical types:


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a) 7,500 psi TPU for one or more WCTs, one interconnected up to five (5) wells or

subsea manifold with EHMUXSCS;

b) 10,000 psi STU for one or more WCTs with EHMUXSCS;

Two of the production wells umbilical slot hang off positions shall allow additionally the

operation of the 5,000 psi Standard TPU for 5kpsi DHCS-WCT. The exact slot with this dual

control system capability will be informed by PETROBRAS during the detail design phase.

Hydraulic connections for umbilical hoses or Steel Tubes shall be provided by their

respective fittings grouped in a plate herein referred as “Topside Umbilical Termination Unit”

Plate (TUTU Plate). The specifications for umbilical hose and Steel Tube fittings will be

provided by PETROBRAS during the detail design phase. Umbilical hydraulic hose pig-tails

are typically 600 mm long.

Each control umbilical slot hang off position (including for SRBGLV/SCGBLV/SESDV) shall

have combined or individual TUTU Plate(s) for both types of EHMUXSCS umbilical. The

production well umbilical slots with dual control system capability shall have an additional

TUTU Plate dedicated for the DHCS, capable to receive hoses and steel tubes of any of the

three umbilical types: 5,000 psi TPU; 7,500 psi TPU, and 10,000 psi STU.

SRBGLV/SCGBLV/SESDV umbilical slots hang off positions shall be provided with a TUTU

Plate for 5,000 psi TPU.

Figure 7.5.3.1 presents a block diagram of the SPCS interfaces.


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Figure 7.5.3.1 – SPCS Interface Diagram

TUTU Plates shall be positioned in order to not block or interfere with pull-in/pull-out

operations. Where this cannot be fully guaranteed, they shall be made removable.

CONTRACTOR shall present each TUTU Plate design for PETROBRAS comments /

information.

Each umbilical hang off position (including SRBGLV/SCGBLV/SESDV) shall be provided

with an Electrical Junction Box (EJB) for the termination of the umbilical electrical cable.

For the umbilical hang off positions where PETROBRAS specified the capability to use

umbilicals with different electrical cable configurations, the EJB shall have one cable entry

specific for each type of umbilical cable or a single cable entry adaptable according to the

type of umbilical installed.

The subsea umbilical’s electrical pig-tails are typically 600 mm long.

Each EJB shall have terminal blocks capable to accept any conductor size between 2,5 mm²

and 16 mm². Terminal blocks shall be dimensioned with individual ground connections for

every pair of umbilical conductors.

Each EJB shall be positioned in order to not block or interfere with pull-in/pull-out operations.

Where this cannot be fully guaranteed, they shall be made removable.


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CONTRACTOR shall present EJB design for PETROBRAS comments / information.

The electrical cable pig-tails preparation and connection inside the EJB is CONTRACTOR’s

scope of work. Details on the cables nominal diameters will be provided by PETROBRAS

during the design phase.

Each umbilical hang off position (except SRBGLV/SCGBLV/SESDV) shall be provided with

an Optical Junction Box (OJB) for the termination of the umbilical fiber optic cable.

For the umbilical hang off positions where PETROBRAS specified the capability to use

umbilicals with different fiber optic cable configurations, the OJB shall have one cable entry

specific for each type of umbilical cable or a single cable entry adaptable according to the

type of umbilical installed.

The subsea umbilical’s optic pig-tails are typically 600 mm long.

Each OJB shall be positioned in order to not block or interfere with pull-in/pull-out operations.

Where this cannot be fully guaranteed, they shall be made removable.

CONTRACTOR shall present OJB design for PETROBRAS comments / information.

The fiber optic cable pig-tails preparation, cable splices and connection inside the OJB is

CONTRACTOR’s scope of work. Details on the cables nominal diameters will be provided

by PETROBRAS during the design phase.

7.5.4. SPCS OPERATOR INTERFACES

The SPCS shall be operated from the CCR using dedicated screens and pop-up menus

according to the particular CCR system used.

As a preliminary requirement, the following screens shall be implemented as an intuitive way

of navigating through the system in a logical manner as the main building blocks are

connected:

a) Well type, according to respective P&IDs;

b) Subsea manifolds and associated wells, according to their respective P&IDs;

c) Assignment of individual wells to a manifold;

d) SPCS HPU monitoring;

e) SCM monitoring;


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f) SRBGLV/SCGBLV/SESDVs.

CONTRACTOR shall implement without cost to PETROBRAS all CCR screen

reconfigurations needed by future changes in the SPCS subsea layout. The reconfiguration

shall be easily accomplished by the use of simple pop-up menus on the CCR screen under

password protected supervisor level. PETROBRAS will request such reconfigurations at

least three months in advance with the new subsea P&IDs for configuration of the HMI

screens.

The following minimum information shall be displayed on the CCR screens for each well

P&ID:

a) Downhole valve status (opened or closed);

b) Downhole pressures and temperatures;

c) WCT valve status (opened or closed);

d) WCT Instrumentation, including flowmeters;

e) Pig detection;

f) Corrosion monitoring of pipeline (to be confirmed by PETROBRAS during the detail

design phase);

g) ESD status;

h) PLEM valves status (WCT production PLEM);

i) Choke position (measured by position sensor and calculated by control steps given);

The following minimum information shall be displayed on the CCR screens for each manifold

respective P&ID:

a) The respective manifold well’s P&ID;

b) Valve status (opened or closed);

c) Pressure and temperatures;

d) Production and Injection flow rates (measured and calculated);

e) Pig detection;


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f) Corrosion monitoring of pipeline (to be confirmed by PETROBRAS during the detail

design phase);

g) ESD status;

The SPCS HPU shall be monitored from the CCR using dedicated screens and pop-up

menus according to the particular CCR system used. At least the following data monitored

from the SPCS HPU shall be displayed on the CCR screens:

a) Reservoirs levels;

b) Unregulated header pressure (both headers);

c) Regulated header pressure (both headers);

d) Pump status;

e) Individual supply pressures LP1, LP2, HP1 and HP2 for each EHMUXSCS umbilical;

f) Individual supply pressures for the WCR and for RBGLV/SCGBLV/SESDV Control

Panel;

The hydraulic pressure of each umbilical line (control and chemical injection) shall also be

monitored as close as possible of their respective hang off connection plate. Pressures shall

be displayed on the CCR.

The following minimum information specific for the subsea equipment provided with

EHMUXSCS shall be displayed on the CCR screens:

a) Hydraulic supply pressures monitored by each Subsea Control Module;

b) Active Line or Channel providing communication and power to each SCM;

c) Subsea electronic module (two for each SCM) health status and internal temperature;

d) Individual Control Cabinet statuses (to be confirmed by PETROBRAS during the detail

design phase);

e) ESD status;

The following minimum information shall be displayed on the CCR screens for each

SRBGLV/SCGBLV/SESDV:


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a) Valve status (opened or closed) for SRBGLV/SCGBLV/SESDV;

b) Pig detection for SESDV;

c) Pressure and Temperature

7.5.4.1. Time delay for subsea valve command operations

It shall be possible to configure a time delay for the SPCS initiate a subsea valve operation

after the command is issued by the Operator. This configuration shall be available for each

subsea valve tag and be easily accomplished by simple pop-up menus on the CCR screens

at password protected supervisor level. Default values for time delays will be informed by

PETROBRAS during the detail design phase.

7.5.4.2. Subsea valve open and close sequences

It shall be possible to configure open and close sequences for all valves of each subsea

equipment and SRBGLV/SCGBLV/SESDV. It shall also be possible to configure open and

close sequences among the subsea equipment installed. Such configurations shall be easily

accomplished by calling special CCR screens under password protected supervisor level.

Default sequences will be informed by PETROBRAS during the detail design phase.

7.5.5. SPCS HYDRAULIC POWER UNIT (HPU)

CONTRACTOR shall provide SPCS HPU according to PETROBRAS specification number:

I-ET-3274.00-5139-800-PEK-001 ( hydraulic power unit for subsea equipment with

multiplexed electrohydraulic and direct hydraulic control system) – see item 1.2.1.

The SPCS HPU shall be dimensioned in terms of reservoirs, accumulator bank and pumps

capacities according to the criteria specified by the SPCS HPU specification referred above.

The first filling of the HPU fluid tanks falls under CONTRACTOR´s scope. During operations

PETROBRAS will provide the fluid make-up whenever necessary, if the HPU is operating

properly and without leakages.

The SPCS HPU will provide the following pressure regulated supplies for each EHMUXSCS

subsea equipment:


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• LP1: Operation between 4,000 psi and 5,000 psi;

• LP2: Operation between 4,000 psi and 5,000 psi;

• HP1: Operation between 6,500 psi and 7,500 psi;

• HP2: Operation between 6,500 psi and 7,500 psi.

The SPCS HPU specification includes the capability for the conversion of all HP1 and HP2

supplies upper operating range to 10,000 psi. CONTRACTOR shall provide the HPU

conversion whenever required by PETROBRAS during the Contract lifetime. PETROBRAS

will request this conversion at least six months in advance.

The SPCS HPU will provide three unregulated hydraulic supplies outlets for the WCR operate

the following subsea valves (according to WCT Type used):

• WCT gate valves requiring between 3,000 psi and 5,000 psi;

• Downhole valves requiring between 4,000 psi and 5,000 psi;

• Downhole valves requiring between 6,500 psi and 7,500 psi;

The SPCS HPU specification includes the capability to supply the WCR to operate between

6,500 psi and 10,000 psi. CONTRACTOR shall provide the HPU conversion whenever

required by PETROBRAS during the Contract lifetime. PETROBRAS will request this

conversion at least six months in advance.

The SPCS HPU will provide two hydraulic supplies for the SRBGLV/SCGBLV/SESDV Control

Panel. Both will allow the operation of the SRBGLV/SCGBLV/SESDV between 3000 psi and

4000 psi.

MOST IMPORTANT: Fluid depressurized from SRBGLV/SCGBLV/SESDV shall NOT be

allowed to return to the SPCS HPU reservoirs. This fluid shall be disposed by the

CONTRACTOR whenever necessary.


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All SPCS HPU supplies shall have individual pressure transmitters downstream of the HPU

for Operator’s monitoring on the CCR screens.

7.5.6. WELL CONTROL RACK (WCR) FOR DIRECT HYDRAULIC CONTROL SYSTEM

CONTRACTOR shall provide the WCR for the number of wells that may be equipped with

DHCS-WCT according with specifications 7.5.2 above.

The WCR shall be capable to control two 10k and the 5k DHCS-WCT types and the well’s

downhole valves. A total of sixteen (16) control functions (see below), each with a Directional

Control Valve (DCV), shall be provided for each well. The P&ID for each DHCS-WCT type

will be provided by PETROBRAS during the detail design phase.

The WCR shall be provided with three (3) unregulated pressure supplies from the HPU for

this purpose:

• One to allow the operation of subsea valves with pressures between 3,000 psi and

5,000 psi;

• One to allow the operation of downhole valves with pressures between 4,000 psi and

5,000 psi;

• One to allow the operation of downhole valves with pressures between 6,500 psi and

7,500 psi (default) or 10,000 psi in case of PETROBRAS requiring the SPCS HPU be

converted as such.

The WCR shall provide a set of three separate headers for each well, derived from the three

DHCS supplies from the SPCS HPU. Each set of headers shall be provided with manually

adjusted pressure regulators upstream of the respective well’s Directional Control Valves

(DCV) in order to allow the control of a 5 kpsi or 10 kpsi WCT and downhole valves. The three

headers shall be divided according to:

• One header to allow the operation of DHCS-WCT gate valves (3,000-4,000 psi range

when used for a 5 kpsi type WCT and 4,000-5,000 psi when used for a 10kpsi type WCT).

This header will supply eight (8) WCT valve functions;


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• One header to allow the operation of downhole valves typically used with 5 kpsi type

DHCS-WCT (4,000-5,000 psi range). This header will supply four (4) downhole valve

functions;

• One header to allow the operation of downhole valves typically used with 10 kpsi type

DHCS-WCT (6,500-7,500 psi range). This header shall have the capability to have its

maximum continuous operating pressure converted to 10,000 psi in case this conversion

is required by PETROBRAS during the Contract lifetime. PETROBRAS will request this

conversion at least six months in advance. This header will supply four (4) downhole

valve functions;

The WCR shall be designed to avoid back pressures in the umbilical control lines, considering

the worst case depressurization of all control lines at the same time to the SPCS HPU. Return

fluid lines from the WCR to the SPCS HPU shall be sized with sufficient flow capacity for this

purpose. The WCR shall allow all WCT and downhole valves to close in less than 10 minutes.

The Directional Control Valves for the WCR shall be spring return fail-close solenoid valve

type energized from the CCR/CIS. They shall bleed the pressure when the electrical power

for the solenoid is removed. The DCV shall be specified to avoid any pressure drop during

subsea hydraulic lines pressurization and depressurization. Their minimum internal passages

shall be equivalent in area to a 6 mm² bore It is important to take into account the pressure

drop during the pressurization of the subsea system. This shall not cause any malfunction to

the solenoid valves.

It is recommended that all DCVs and hydraulic components be installed in stainless steel

manifold blocks. It is also recommended that WCR itself to be made in stainless steel.

Individual pressure transmitters shall be provided downstream of each WCR DCV for

Operator’s monitoring on the CCR screens.

CONTRACTOR shall provide at least four (4) individual lines for continuous operation with

10,000 psi between the WCR and the respective umbilical hang off positions for the wells with

dual control system capability (operation of either an EHMUXSCS-WCT or a DHCS-WCT).

All the other lines shall be provided for continuous operation with at least 5,000 psi.

7.5.7. DOWNHOLE DATA ACQUISITION SYSTEM (SAS PANEL)


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The SAS equipment is for topside data acquisition of Permanent Downhole Gauges (PDG)

installed in wells completed with DHCS-WCTs.

The SAS equipment provides RS-232, RS-485 and Ethernet network interfaces with

MODBUS RTU protocol. Power must be supplied with 220 VAC, phase-to-phase, 60 Hz from

UPS with available internal outlets to all equipment in NEMA 5-15 standard and 24 VDC.

Each SAS equipment requires standard 19” & 3U rack space.

CONTRACTOR shall install the SAS Equipment(s) in 19” type standard rack(s), herein

referred as SAS Panel, with a height of 2,500 mm. Front and rear accesses shall be provided

with transparent frontal door.

PT & TPT 4-20 mA transmitters from each DHCS-WCT and from each

SRBGLV/SCGBLV/SESDV shall be read by the FPU CIS/CCR system PLC and displayed

in the CCR. The DHCS-WCT electrical system schematic will be provided by PETROBRAS

during the execution phase.

Depending on the hydraulic-type Intelligent Completion system that may be used,

PETROBRAS will require up to three (3) panel mounted engineering workstations (IWCS)

(each with monitor and notebook) to be installed in the SAS Panel.

CONTRACTOR shall provide to PETROBRAS no longer than 60 days after the Contract

award the preliminary drawings showing the space available in the SAS Panel to be used.

All SAS Cabinets shall be supplied by CONTRACTOR according with the quantities specified

on Table 7.5.2.1.

Maximum electrical power of each SAS Cabinet is 1,5 kVA, with heat dissipation of 400

Watts.

Each SAS Cabinet shall comply with the following requirements:

Be provided with circuit breakers, fans, terminal blocks, lightning and all required materials

necessary for cabinet finishing;

All cables shall be tagged, including electrical cables from riser balcony;

CONTRACTOR shall provide each SAS Cabinet with an Ethernet Switch to connect all IWCS

equipment (worst case: two (2) groups of four (4) rack mounted 6U Notebooks) to all

EHMUXSCS Control Cabinets.


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The installation, integration and commissioning of the IWCS equipment manufactured by two

(2) different suppliers in the WCS Cabinets are CONTRACTOR´s Scope of work.

For the “Integration” specified above, CONTRACTOR shall provide the complete installation

and commissioning of all IWCS equipment to be provided by PETROBRAS. CONTRACTOR

scope of supply shall also include (but it is not limited to): All cables (power; signal;

instrumentation) with suitable connectors and terminations required; configuration of CI-HD

Ethernet Switches for communication with the EHMUXSCS Control Cabinets;

CONTRATOR shall take into account that IWCS equipment may be not available for shipyard

installation before the FPU starts production. CONTRACTOR shall provide at any time with

no cost to PETROBRAS the installation, integration and commissioning of any quantity of

IWCS equipment whenever requested by PETROBRAS, including while the FPU is offshore.

PETROBRAS will request to CONTRACTOR this offshore installation and integration work

with at least three months in advance. CONTRACTOR shall plan and carry out this work with

minimum or no impact for the FPU’s operation. For each WCS Cabinet, PETROBRAS is

going to provide a total of 10 man-days of technical assistance to the CONTRACTOR for

IWCS equipment installation.

The installation, integration, commissioning and operation of these panels, onboard, are

CONTRACTOR´s Scope of work.

7.5.8. NOT APPLICABLE

7.5.9. PORTABLE UMBILICAL PRESSURIZATION SYSTEM (PUPS)

PUPS is a topside portable device to allow the CONTRACTOR to safely pressurize each

control line of an umbilical during installation, from any LP or HP pressure supply from the

SPCS HPU. The PUPS device shall allow for quick air removal and safe pressurization and

depressurization of up to twelve (12) umbilical tubings or thermoplastic hoses from one or

two hydraulic supplies at any TUTU Plate.

The PUPS device shall be composed of two identical hydraulic headers, each one with a

common pressure inlet port, a pressure regulator, manometer, 6 (six) function branch outlet

ports and one drain port to drain/bleed any of the 6 outlets. Each drain and outlet port, as

well as each manometer shall have their own isolating valve. All components shall be


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stainless steel type with at least ½” O.D suitable for the above said control fluid and fluid

cleanliness. The drain/bleed ports shall be used also to take fluid sampling when necessary.

JIC fittings mentioned below in this chapter are just for reference. CONTRACTOR shall

provide the PUPS with the matching hydraulic terminations for umbilical hose and Steel

Tube fittings to be informed by PETROBRAS during the detail design phase.

The PUPS device shall be able to pressurize each umbilical line with a regulated pressure

between 1,000 psi and 3,000 psi, from any supply between 4,000 and 10,000 psi. However,

all PUPS hydraulic components shall be rated to 10,000 psi operation. Each of the 12

(twelve) pressurization outlets shall be terminated with a quick connector adapter to allow

the fitting of a ½” or 3/8” male JIC 37° termination prior the pressurization. Each PUPS device

shall be provided with sets of at least 13x 3/8” and 5x ½” male JIC 37° fittings.

CONTRACTOR shall consider provide each PUPS with its own storage box for those fittings

when not in use.

CONTRACTOR shall provide and maintain at least two identical PUPS devices always

ready for use when asked so by PETROBRAS.

The PUPS device shall be used for CONTROL LINES only with water-based control fluids

MacDermid HW443, MacDermid HW525P or Castrol Transaqua DW.

CONTRACTOR shall maintain the PUPS devices always flushed to ISO 4406 Class 17/15/12

cleanliness.

7.5.10. SRBGLV/SCGBLV/SESDV CONTROL PANEL

CONTRACTOR shall provide the SRBGLV/SCGBLV/SESDV control panel for the number of

SRBGLV/SCGBLV/SESDV and PLEM valves according with specifications 7.5.2 above.

The SRBGLV/SCGBLV/SESDV control panel shall be provided with two (2) regulated

pressure supplies from the HPU for actuation of:

• Up to six (6) SRBGLV/SCGBLV/SESDV valves with pressures between 3000 psi and

4000 psi;

The SRBGLV/SCGBLV/SESDV control panel shall be designed to avoid back pressures in

the umbilical control lines, considering the worst case depressurization of all control lines at

the same time to the SPCS HPU. Return fluid lines from the SRBGLV/SCGBLV/SESDV


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SESDV control panel shall be sized with sufficient flow capacity for this purpose. The return

fluid from SRBGLV/SCGBLV/SESDV SESDV control panel shall not be allowed to return to

the SPCS HPU.

The SRBGLV/SCGBLV/SESDV control panel shall allow all SRBGLV/SCGBLV/SESDV to

close in less than two (2) minutes.

The Directional Control Valves for the SRBGLV/SCGBLV/SESDV control panel shall be

spring return fail-close solenoid valve type energized from the CCR/CIS. They shall bleed the

pressure when the electrical power for the solenoid is removed. The DCV shall be specified

to avoid any pressure drop during subsea hydraulic lines pressurization and depressurization.

Their minimum internal passages shall be equivalent in area to a 6mm² bore. It is important

to take into account the pressure drop during the pressurization of the subsea system. This

shall not cause any malfunction to the solenoid valves.

It is recommended that all DCVs and hydraulic components be installed in stainless steel

manifold blocks. It is also recommended that SRBGLV/SCGBLV /SESDV control panel itself

to be made in stainless steel.

Individual pressure transmitters shall be provided downstream of each

SRBGLV/SCGBLV/SESDV control panel DCV for Operator’s monitoring on the CCR

screens.

7.5.11. SUBSEA MULTIPLEX PUMP CONTROL SYSTEM (SMPCS)

General: The SMPCS will be an electro-hydraulic or all-electric multiplex control and

monitoring system. Control fluid, if used will be the same water based type provided by the

SMPCS CFHPU, keeping the same ISO 4406 Class 17/15/12 cleanliness.

In case the Subsea Production Systems (SPS) is provided with electro-hydraulic multiplex

control, it will have its own Subsea Control Module (SCM), housing the electronics and

solenoid valves that allow the multiplex system to collect data from the local instrumentation

and actuate all hydraulic valves. Each SCM will also perform data acquisition from internal

and external (SPS) sensors. Hydraulic supplies will be provided as dual redundant Low

Pressure (LP) 4,000 psi to 5,000 psi operating range.


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In case the SPS is provided with an all-electric multiplex control, it will have its own Electric

Subsea Control Modules (ESCM), housing the electronics that allow the multiplex system

to collect data from the local instrumentation and control the SPS subsea electric actuators.

Each ESCM will also perform data acquisition from internal and external (SPS) sensors.

The topside SMPCS equipment will be composed by a total of two (2) Pump Control

Cabinets. Each PCC will provide redundant power and communication superimposed in

the same pair of wires (power line carrier) for each pump SCM or ESCM, even in case of

the SPS uses barrier fluid hydraulical power unit on the topside. Each pair is referred as

one “channel”, so two such channels will be provided to each SMP through their control

umbilicals. The SMPCS will provide two optical communication channels between the PCC

and the SCM or ESCM.

All PCC shall be located in the same room with air conditioning. The maximum room

temperature shall be less than 35ºC.

Each PCC shall be powered from 220V AC @ 60 Hz from the FPSO Uninterruptable Power

Supply. Power consumption of each Control Cabinet rack will be 5 KVA and heat

dissipation of each Control Cabinet will be 3,5 kW.

E- Module (Local Equipment Switchgears Module) shall have HVAC system considering

25% loss on overall Control Cabinets. CONTRACTOR shall verify the HVAC is properly

designed.

Each PCC will have available 32 digital inputs (0-24VDC) for interface with PSD, such

ESDs levels. The exact functions and Cause & Effect Diagram shall be agreed together

with PETROBRAS during the detail design;

Each PCC will have available 16 digital outputs (0-24VDC) for interface with PSD. The

exact functions and Cause & Effect Diagram shall be agreed together with PETROBRAS

during the detail design;

The PCC will be shipped to the CONTRATOR already integrated in the SPS topside

container. CONTRACTOR shall perform the installation and integration at any time

whenever asked by Petrobras at least three months in advance.

CONTRACTOR shall specify within 60 days after the contract award the network interface

protocol between the CCR/CSS and the PCC, taking into account the two following options:

a. MODBUS/TCP;


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b. Ethernet TCP/IP with OPC protocol;

For both options, the network shall be dedicated for CCR/CSS and Control Cabinets

interface only. Cable interface shall be 100-BASE-T or 100-BASE-FX type optical

connection, also to be defined by the CONTRACTOR together with the interface protocol,

as required above.

CONTRACTOR shall power all PCC with an Uninterruptible Power Supply, allowing 15

minutes of full power operation after shutdown.

CONTRACTOR shall provide room and desktop facilities in the CCR or nearby room for

the two SMPCS Operator Workstations (SPOWS). Specifications of the cables and

connectors between the Control Cabinets and the SPOWS are to be provided by

PETROBRAS during the detail design.

7.6. OFFLOADING MONITORING TELEMETRY SYSTEM (OMTS)

The Unit’s Telemetry System shall comply with the OFFSHORE LOADING SYSTEM

REQUIREMENTS document (see 1.2.1).

7.7. METERING

The Flow Metering System (FMS) shall comply with Brazilian legislation, including National

Agency of Petroleum, Natural Gas and Biofuels (ANP) and Brazilian National Institute of

Metrology, Quality and Technology (Inmetro) regulations.

The FMS shall be designed, selected, installed, commissioned and tested in order to comply

with all technical requirements mentioned in the Technical Regulation Measurement of Oil

and Natural Gas, or just RTM, approved by Resolução Conjunta ANP/Inmetro nº1 de

10/06/2013 (or other updated document which substitutes it), in other supplementary

regulations issued by ANP/Inmetro and in manufacturer’s recommendations, including all

applicable standards and reference technical documents.

Standards, codes and recommendations that shall be followed in the design of the FMS are

listed in RTM-Appendix D or explicitly referenced in this document.


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The following requirements for the FMS shall be interpreted as minimum and are in

accordance to the RTM. Other metering points may be necessary depending on the topside

process philosophy adopted and should not be omitted.

Additionally, CONTRACTOR shall test each production well every 30 (thirty) days as well as

perform associated sampling and analyses, as a minimum.

The Metering System shall be supplied by one integrator (the scope of supply shall be

responsibility of a single vendor).

Table 7.7.1 - Metering Points

Item Fluids Metering points Duty Type of meter Accuracy

(note 1)

1 Oil

Cargo pump

discharge

(offloading)

Custody

transfer

metering

Ultrasonic or Coriolis

(note 2) or helical

turbine meters; flow

computer. Minimum 1

spare meter installed.

± 0.3%

(system)

± 0.2%

(sensor)

2 Oil

Cargo pump

discharge

(offloading)

Calibration

of Custody

transfer

metering

Master meter and

Prover (note 2), or

only Prover; flow

computer

± 0.1%

(system)

3 BSW

Cargo pump

discharge

(offloading) Online

Online transmitter (0-

20%) (note 4)

± 0,2%

absolute

4 BSW

Cargo pump

discharge

(offloading) Sampler

Automatic and manual

(installed downstream

of the static mixer)

(note 5)

5 Oil Crude oil to

cargo tanks

Fiscal

metering

Ultrasonic or Coriolis

(note 2) or helical

turbine meters; flow

computer. Minimum 1

spare meter installed

± 0.3%

(system)

± 0.2%

(sensor)

6 Oil Crude oil to

cargo tanks

Calibration

of fiscal

metering

Master meter and

Prover (note 2), or

only Prover; flow

computer

± 0.1%

(system)

7 BSW Crude oil to

cargo tanks Online


20%) with static mixer

(note 4)

± 0,2%

absolute


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(note 1)

8 BSW Crude oil to

cargo tanks Sampler




(note 5)

9 Oil

Well injection

operations

(Diesel and/or

Treated Oil)

Fiscal

Metering

Positive Displacement,

Coriolis (with volume

indication) or helical

turbine meter (note 3);

flow computer (note

12)

± 0.3%

(system)

± 0.2%

(sensor)

10 BSW

Well injection

operations

(Diesel and/or

Treated Oil)

Sampler

Automatic and Manual



(note 5)

(note 12)

11 Oil Oil Test

separator

Allocation

metering


indication) (note 3);

flow computer

± 1.0%

(system)

± 0.6%

(sensor)

12 BSW Oil Test

separator Online



± 1,5%

absolute

13 BSW Oil Test

separator Sampler

Manual



14 Oil /

Condensate

Gas Test

separator

Allocation

metering



flow computer

± 1.0%

(system)

± 0.6%

(sensor)

15 BSW Gas Test

separator Online



± 1,5%

absolute

16 BSW Gas Test

separator Sampler

Manual



17 Oil

Free Water KO

Drum

(oil production

separator)

Allocation

metering



flow computer

± 1.0%

(system)

±0.6%

(sensor)

18 BSW

Free Water KO

Drum (oil

production

separator)

Online



(note 4)

± 1,5%

absolute


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(note 1)

19 BSW

Free Water KO

Drum (oil

production

separator)

Sampler

Manual



20 Oil /

Condensate

Inlet Gas

Separator (gas

production

separator)

Allocation

metering



flow computer

± 1.0%

(system)

±0.6%

(sensor)

21 BSW

Inlet Gas

Separator (gas

production

separator)

Online



(note 4)

± 1,5%

absolute

22 BSW

Inlet Gas

Separator (gas

production

separator)

Sampler

Manual



23 Condensate

Heavy

Hydrocarbon

Rich Stream –

Total Injection

Fiscal

Metering

Ultrasonic or

Coriolis (note 2) or

helical turbine

meters; Minimum

1 spare meter

installed online

densimeter

(upstream); flow

computer

± 0.3%

(system)

± 0.2%

(sensor)

24 Condensate

Heavy

Hydrocarbon

Rich Stream –

Total Injection

Calibration

of Fiscal

Metering

Master meter and

Prover (note 2), or

only Prover; flow

computer

± 0.1%

(system)

25 BSW

Heavy

Hydrocarbon

Rich Stream –

Total Injection

Online

Online transmitter

(0-20%) with static

mixer (note 4)

± 0,2%

absolute

26 BSW

Heavy

Hydrocarbon

Rich Stream –

Total Injection

Sampler




(note 5)

27 Condensate

Heavy

Hydrocarbon

Rich Stream –

Operational

Metering

Ultrasonic; flow

computer

± 1.0%

(system)

±0.6%

(sensor)


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(note 1)

Individual

Injection per well

28 Gas HP Flare Fiscal

metering

Ultrasonic flare meter

(FLUENTA or GE

type) with flow

computer

± 5.0 %

(note 6)

29 Gas LP Flare Fiscal

metering


(FLUENTA or GE

type) with flow

computer

± 5.0 %

(note 6)

30 Gas Vent

(if needed)

Fiscal

metering


(FLUENTA or GE

type) with flow

computer

± 5.0 %

(note 6)

31 Gas

Topside

Individual Gas

Lift

Allocation

metering

Orifice plate meter with

flow computer; Dual

chamber orifice fittings

and removable straight

pipe sections to be

provided

± 2.0 %

32 Gas Topside Total

Gas Lift

Operational

metering

Cone or Orifice Plate

meter (Dual chamber

orifice fittings and

removable straight pipe

sections to be provided)

with flow computer

± 3.0 %

33 Gas Export Line

(notes 11)

Fiscal

metering

Orifice plate meter with

flow computer; Dual



pipe sections to be

provided

± 1.5%

34 Gas Import Line (note

10)

Fiscal

metering

Orifice plate meter

with flow computer;

Dual chamber orifice

fittings and removable

straight pipe sections

to be provided

± 1.5%

35 Gas Oil Test

separator

Allocation

metering

Orifice plate meter

with flow computer;



± 2.0 %


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(note 1)


to be provided

(note 13)

36 Gas Gas Test

separator

Allocation

metering

Orifice plate meter

with flow computer;




to be provided

(note 13)

± 2.0 %

37 Gas

Free Water KO

Drum

(oil production

separator)

Allocation

metering

Orifice plate meter

with flow computer;




to be provided

(note 13)

± 2.0 %

38 Gas

Inlet Gas

Separator (gas

production

separator)

Allocation

metering

Orifice plate meter

with flow computer;




to be provided

(note 13)

± 2.0 %

39 Gas

Degasser

Eletrostatic

treaters

Operational

Metering


meter (Dual chamber

orifice fittings and

removable straight pipe

sections to be provided)

with flow computer.

± 3.0 %

40 Gas Total Fuel Gas

HP (note 7)

Fiscal

Metering

Orifice plate meter

with flow computer;




to be provided

± 1.5 %

41 Gas Total Fuel Gas

LP (note 7)

Fiscal

Metering

Orifice plate meter

with flow computer;

Dual Chamber orifice



to be provided

± 1.5 %


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(note 1)

42 Gas

Fuel Gas

Consumers

(note 7)

Operational

Metering


meter (single or dual



pipe sections to be

provided) with flow

computer

± 3.0 %

43 Gas Flare Pilot

(notes 8, 9)

Operational

metering

Orifice plate meter

with flow

computer; Dual

chamber orifice

fittings and

removable straight

pipe sections to

be provided

± 3.0 %

44 Gas Flare Assist

(notes 8, 9)

Operational

metering

Orifice plate meter

with flow

computer; Dual

chamber orifice

fittings and

removable straight

pipe sections to

be provided

± 3.0 %

45 Gas Flare Purge

(notes 8, 9)

Operational

metering

Orifice plate meter

with flow

computer; Dual

chamber orifice

fittings and

removable straight

pipe sections to

be provided

± 3.0 %

46 Gas Total Gas

Injection

Fiscal

Metering

Orifice plate meter

with flow

computer; Dual

chamber orifice

fittings and

removable straight

pipe sections to

be provided

± 1.5 %

47 Gas Individual Gas

Injection

Operational

metering

Cone or Orifice

Plate meter Dual

chamber orifice

± 3.0 %


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(note 1)

fittings and

removable straight

pipe sections to

be provided) with

flow computer

48 Water Oil Test

separator

Operational

metering

Orifice plate meter,

magnetic meter (spool

type) or Coriolis meter;

pressure and

temperature

transmitter, flow

computer

1.0%

49 Water Gas Test

separator

Operational

metering




pressure and

temperature

transmitter, flow

computer

1.0%

50 Water

Free Water KO

Drum

(oil production

separator)

Operational

metering




pressure and

temperature

transmitter, flow

computer

1.0%

51 Water

Inlet Gas

Separator (gas

production

separator)

Operational

metering



type) or Coriolis

meter; pressure and

temperature

transmitter, flow

computer

1.0%

52 Water

Electrostatic Pre-

Treater

(upstream level

control valve)

Operational

Metering




pressure and

temperature

transmitter, flow

computer

1.0%

53 Water Electrostatic

Treater

Operational

Metering


magnetic meter (spool 1.0%


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(note 1)

(upstream level

control valve)


pressure and

temperature

transmitter, flow

computer

54 Water Total water

injection

Operational

metering


Cone meter, magnetic

meter (spool type);

flow computer

1,0%

55 Water Individual

Injection

Operational

metering


Cone meter, magnetic

meter (spool type);

flow computer (note

14)

1,0%

(individual)

56 Water Produced Operational

metering

Orifice plate meter, Cone

meter, magnetic meter

(spool type); temperature

transmitter; flow

computer

1.0%

57 Water Disposal Operational

metering

Orifice plate meter, Cone

meter, magnetic meter

(spool type); temperature

transmitter; flow

computer (note 11)

1.0%

58 Multiphase Production riser

(note 1-5)

Allocation

metering

Multiphase topside flow

meter

(notes 16,

17)

NOTES:

(1) Maximum allowable errors for liquid metering; uncertainty for gas metering;

(2) Ultrasonic meter shall have 4-channels as minimum. In case of using ultrasonic or coriolis

meters as duty meter, a master meter and a prover are required and the master meter shall

be a helical turbine meter.

(3) The duty meter shall be calibrated against a master meter or a prover at the FPSO

facilities. If a master meter is used, it shall be proved against a prover at the FPSO facilities.

(4) The transmitter shall be able to be disassembled without interruption of the whole

metering system operation.

(5) 2 (two) samplers shall be available, one manual and other automatic.


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(6) Although classified as fiscal measurement, the meter technologies and process

conditions do not allow better uncertainties than the one specified; each flow loop shall be

composed by: flow meter (FE), electronic unit (manufacturer’s "flow computer”) (FT),

pressure (PT) and temperature (TT) transmitters and flow computer (FQl); the FT, PT and

TT shall be linked to the FQI (control room); this kind of arrangement is acceptable by ANP-

Inmetro once they are characterized as fiscal points (even at a 5.0% uncertainty level); The

piping lengths related to the flare gas flowmeter are based on the minimum number of

straight pipe runs: 20 nominal diameters upstream and 10 nominal diameters downstream.

All flow computation and data storage shall be done at FQI (Inmetro approved flow

computer); sensors shall be removable in order to enable the dry calibration procedure; Flow

meter shall be supplied in a spool; Electronic unit shall communicate with flow computer

using field network (MODBUS RTU protocol).

(7) CONTRACTOR shall provide means to measure separately the gas flow rates of the

following fuel gas consumers (if applicable): gas-turbines, turbo-generators and boilers (if

applicable); flow meters as part of those equipment packages are acceptable. Fiscal gas

meter configuration shall not measure gas streams twice or more, i.e. in case a process unity

uses fuel gas and returns it to process, this fuel gas shall be derived upstream the fuel gas

fiscal meters;

(8) Flare pilot, flare assist gas, flare purge or any other flow which is flared without being

previously measured by LP Flare Meter or HP Flare Meter shall automatically generate Daily

Metering Reports in “.XML” files containing production, configuration and log data extracted

from flow computers according to ANP specifications (“Resolução ANP 65/2014” and other

supplementary regulations issued by ANP/Inmetro).

(9) If not measured in other flows by a fiscal meter, purge gas, assist gas and pilot gas shall

comply with fiscal measurement requirements and be installed with a dual chamber orifice

fitting.

(10) CONTRACTOR shall install one online CGA – Gas Chromatographic Analyzer for

hydrocarbon composition (until C6+), CO2 and N2 in the gas import and export lines (if

applicable) and linked to the flow computer, which shall inform daily:

a) Gas composition;

b) Total Gas flow rate;


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c) Gas flow rate per compound;

d) Gas Higher Heating Value.

(11) Produced water to overboard requires an installed spare meter;

(12) When using diesel or treated oil on well operations such as hydrate prevention on flow

lines, a fiscal metering system shall be provided to measure injected volumes. Meter

calibration shall be done with fluid similar to operational conditions. In case of using diesel

the calibration may happen outside FPSO facility.

(13) There shall be provided means to avoid condensate on separators gas meters, such as

piping thermal coating, meter location as close as possible to the separator and piping

downstream of flowmeter with no upward slope.

(14) The water injection metering shall be designed to allow the water injection flow rate

measurement of each well separately. One temperature transmitter and one pressure

transmitter shall be provided. Shared temperature and pressure transmitters for injected

water points are acceptable depending on the design.

(15) There shall be installed one multiphase topside flow meter for each production riser slot

on riser balcony.

(16) Multiphase meters shall meet the following uncertainty criteria over the entire operating

range:

• Expanded uncertainty in volumetric liquid flow, at actual conditions, less than or equal

to ± 6% with 95% coverage probability;

• Expanded uncertainty in volumetric gas flow, at actual conditions, less than or equal

to ± 10% with 95% coverage probability;

• Expanded uncertainty in measured WLR, at actual conditions, less than or equal to ±

4% with 95% coverage probability.

(17) Topside multiphase meters shall be used jointly with subsea multiphase meters for

continuous allocation measurement and comparison. Topside meters are especially useful

in contingency situations, if subsea meters present faulty measurements or even partial or

total failure of their functionality.

7.7.1 METERING ADDITIONAL REQUIREMENTS


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• It is not allowed any kind of bypass at fiscal or custody transfer metering points;

• All fiscal, allocation, operational control (as defined at ANP metering regulation),

custody transfer flowmeters and flow computers shall have valid Model / Type

Approvals by Inmetro (except orifice plates, cones and multiphase meters) by the time

of the FPSO design phase (procurement). All the technical requirements and

constraints inside each of Inmetro Approval Document shall be complied. All flow

computers shall comply with “Portaria Inmetro 499/15”, from 02-Oct-2015 (or other

updated document which substitutes it). Initial verification for flow computers is

manufacturer’s responsibility;

• Every flow meter shall at all times comply with nominal flow rate ranges specified in

Inmetro Type Approval;

• All fiscal, allocation, operational and custody transfer meters (except multiphase

meters) shall be connected to flow computers, which shall be installed on temperature

controlled rooms;

• The Inmetro Initial Verification procedure shall be included in the scope of supply of

the fiscal, allocation and custody transfer oil metering systems, according to Portaria

INMETRO 64/2003 (or any other that may substitute and complement it). The Initial

Verification procedure, which is responsibility of the metering systems manufacturer,

shall be executed on a single phase basis. The metering systems manufacturer shall

submit its Initial Verification procedure for Inmetro approval before its execution.

Immediately after Inmetro approval of this procedure, a copy of the document and

evidence of Inmetro approval shall be presented to Petrobras for information only

• The crude oil to cargo tanks fiscal metering system shall be provided with at least 3

meter runs, one acting as stand-by meter. For rangeability purposes, CONTRACTOR

shall also consider that only 1 condensate well may be operating at a determined

time;

• The allocation metering system shall be capable of measuring each well individually

during their respective life span;

• Double block and bleed valves with drain shall be installed in oil calibration systems,

allocation alignments, and where else tightness is required to be verified. In order to


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fulfill ANP/Inmetro, these valves shall be submitted to leakage performance tests

between intervals no longer than 1 year;

• Control valves shall be used on oil calibration systems so that it is possible to calibrate

flow meters at any flow rate along its full range of flow. Control valves shall be located

downstream of the flowmeters;

• Routing hydrocarbon volumes directly to cargo tanks without fiscal metering is not

acceptable; this requirement also includes any recovered oil volume and condensate

streams from H.P Flare K.O Drum, L.P Flare K.O Drum, Closed Drain (if applicable),

overflow (oil stream) from hydrocyclones, overflow (oil stream) from the flotation unit,

overflow (oil stream) from slop tanks and others; the Unit shall be also capable to

collect and treat these streams and route them back to the process plant upstream oil

fiscal metering system. Off-spec tanks (and any other tanks that may have crude oil

not fiscal metered) alignments that do not return the oil to process plant shall have

valves sealed controlled with open/close register on unit supervisory system (PI

included). Unit shall have operational procedure to ensure that the above mentioned

alignments are used only in special circumstances and crude oil not fiscal metered is

not routed to cargo tanks;

• Oil and water flow meters at the discharge of process vessels shall be located

upstream the respective vessel level control valves;The gas meter systems with dual

chamber orifice fittings shall allow the change and/or retrieving of the orifice plates

during normal operation under pressure;

• Technical design and certifications of all orifice plate metering points shall comply with

ISO 5167 standards, meeting a minimum internal pipe diameter of 2"; All orifice plate

metering points shall use Zanker flow conditioner as a mean to shorten the upstream

straight run;

• For fiscal or allocation natural gas metering points using differential pressure

transmitters where there is expectation for rangeability greater than 4:1, there shall

be foreseen the installation of 2 transmitters (split range);

• Secondary tapings such as pressure and temperature tapings shall be installed in

piping or straight run at same diameter as primary meter. Meter flange diameter shall

be considered as meter reference diameter;


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• The use of cone meters shall include means of dimensional verification and/or

calibration and they shall be sized according to ISO 5167-5 and calibrated with flow

in all cases following ISO 5167-5 directives.. A verification procedure shall be

presented for PETROBRAS comments/information during the basic project; this

procedure shall have ANP approval. For each metering point, one spare cone shall

be available;

• Each gas metering point shall be provided with representative manual sampler

devices (flare included), as close as possible to its respective metering point and

easily accessible by the operator. The manual sample points must comply with the

recommendations of the API MPMS 14-1. The probe shall be intrusive and installed

at least 5 diameters downstream of any disturbing element. For orifice plate and cone

meters, the manual sampler shall be installed upstream the meter;

• Gas sample points shall be provided with sampling panels, tag labelled, which shall

have bottle/cylinder support and means for gas purge before handling collection. Gas

purged through sampling points shall be directed to Flare. Flare sampling system shall

be able to collect representative samples even with the low pressure, so devices such

as vacuum pump shall be foreseen; Lines that are operating at or near the gas

stream’s dew point may require special probes designed to overcame the problems

of condensation in the gas.

• Regarding periodicity and procedures to collect and analyze oil and gas samples and

implementation of the results (physicochemical properties) into the flow computers,

CONTRACTOR shall comply with “Resolução ANP 52/2013”, which details and

complements “Resolução Conjunta ANP/Inmetro n° 1/2013”;

• All oil metering points shall have sample collecting points, which can operate at

atmospheric pressure aiming to the determination of BS&W and density values. For

oil allocation and fiscal crude oil to cargo tanks metering points, the sampling points

shall also allow the collecting at the same pressure conditions of the process, aiming

to the determination of shrinkage factor (FE) and solubility ratio (RS) values;

• The manual samplers shall comply with API MPMS 8.1 and API MPMS 8.3, and

automatic samplers shall comply with API MPMS 8.2 and API MPMS 8.3;


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• Samples homogeneity shall be assured from sampling to analysis. If sampling point

is located at a horizontal line, a mixer shall be installed.

• Automatic samplers shall foreseen a mixing pump for close loop connected to the

containers to achieve a homogenous sample inside the container, in order to allow

the operator to bring a smaller representative sample to the laboratory.

• Online BSW oil analyzers shall comply with TR 2570.

• The topside individual gas lift metering shall be designed to measure gas lift flow rate

of each service riser individually and total gas lift flow rate as well;

• The gas injection metering shall be designed to measure gas injection flow rate of

each well individually and the total gas flow rate as well;

• The heavy hydrocarbon rich stream (C3+) injection metering shall be designed to

measure the injection C3+ flow rate of each well individually and the total C3+ flow

rate as well;

• Calibration and inspection procedures as required by ANP and maintenance of the

metering systems shall not cause any impact (decrease and/or shutdown) on the

Unit’s production;

• The metering systems shall cover the flow range since the Unit start-up (when low

flows will be present) to Unit full production (when high flows will be present) up until

its mature phase (high BSW contents and low well flow rates);

• Complete access for installation, maintenance and removal shall be provided

(including lifting capacity, if necessary) to all flowmeters and associated components

by means of walkways, stairs or platforms;

• Pressure and differential pressure transmitters shall have their process connections

and installation according to the fluid being measured: for gas measurement, the

impulse lines shall be mounted "above the taps", on horizontal pipes, taps from 9:00

to 3:00 o’clock on the top of the line with the 12:00 o’clock position being preferred;

for liquid measurement, the impulse lines shall be mounted "below the taps", on

horizontal pipes, tap position located 45° below the horizontal plane;

• Impulse lines shall be kept as short as possible. For fiscal, allocation and custody

transfer applications, impulse lines tubings shall be no more than 1 meter long;


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• In cases where process operation pressures is equal to or below 10 bar (i.e.: HP Flare

and LP Flare), the PIT shall be of absolute pressure type;

• A bypass line or meter redundancy shall be used in operational metering systems

(exception to orifice plates) to allow meters removal for calibration without process

interruption.

• All calibration and dimensional requirements: pressure, temperature and flow

calibrations, as well as dimensional inspections (including for flare ultrasonic meters)

shall be made through accredited laboratories (Inmetro or ILAC or IAAC);

• In the beginning of the Unit design, within 3 months time, CONTRACTOR shall

provide to PETROBRAS the following documents (in Portuguese language) to be

submitted to ANP for approval, according to Resolução Conjunta ANP/Inmetro nº1 de

10/06/2013: (1) “Schematic Diagram for Metering System/Diagrama Esquemático

das Instalações”; and (2) “Technical description of the production unit metering

system /Memorial Descritivo dos Sistemas de Medição”;

• 6 months before production system start-up, CONTRACTOR shall provide to

PETROBRAS the documentation (in Portuguese language) of the metering system

(design and operating description reports, diagrams and other related documents) to

be submitted to ANP for approval, according to Resolução Conjunta ANP/Inmetro nº1

de 10/06/2013. The complete list of required documents will be sent by PETROBRAS

on the beginning of the detailed phase;

• An interface with the Automation System (ICSS) of the production unit shall be

provided in order to enable the operational data transfer from the flow computers to

the supervisory system of the unit and to the PI Server. PI data list to be available in

onshore servers shall be confirmed during detailed phase;

• The flow computer panel shall be provided with an HMI (Human-Machine Interface)

for local operation and maintenance of the system;

• The FMS Workstation shall enable all necessary functionalities for the full operation

and calibration of the flowmeters, including the automatic remote actuation of the

valves alignment and calibration flowrate adjustments, besides the generation of

metering reports, among others;


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• The FMS Workstation shall retain all historical registers and reports for at least 10

years (RTM item 10.1.6), using hard disks and on an incremental daily basis;

• Metering reports (hourly, daily and monthly production; calibration; batch for well

testing and offloading; alarm and events; audit trail) shall be readily available for ANP

and/or PETROBRAS Representatives on board, as well as recorded for further

internal or authority audit; the measurement data shall also be available at the

workstation in PETROBRAS Office onboard;

• Flow & Supervisory Computers - All log files shall be created based at the actual data

from the flow computers simply by uploading, keeping their inviolability; the files shall

be kept at the FMS Workstation non-volatile memory / dedicated directory and shall

be recorded at the DVD recorder on a monthly basis;

• General log files to be generated by Flow Metering System:

o Daily Configuration Data Log (for each flow computer);

o Daily Input and Output Data Log (for each flow computer);

o Daily Audit Trail Log (for each flow computer);

o Daily Alarm Log (for each flow computer);

o Daily Production (for each metering point);

o Offloading (for each offloading metering point).

• All log files shall be generated according to the formats defined in (most recent

editions): API/MPMS 21.1, Electronic Gas Measurement; API/MPMS 21.2, Flow

Measurement-Electronic Liquid Measurement;

• In order to set up the better synchronicity between all Flow Computers and the FMS

Workstation clocks, there shall be means of synchronization of the flow computers

with the FMS, considering the FMS clock as reference;

• Metering Reports in “.XML” files containing production, configuration and log data

extracted from flow computers shall be automatically generated according to ANP

specifications (Resolução ANP 65/2014 and other supplementary regulations issued

by ANP/Inmetro). Data flow shall be designed to avoid data tampering, taking

measures such as access control;


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• FMS workstation and flow computers shall have control access to avoid inadverted

modifications. Flow computers shall only be configurable through FMS and not via

ICSS, with traceability to all moditifications (audit log);

• Fidelity between flow computers, FMS workstation and other automation systems -

All production volumes at the FMS workstation shall be based on the variable

“Previous Day Net (NSV) Totalizer” of each flow loop;

• Note: NSV is an acronym to “Net Standard Volume” which means: The total volume

of all petroleum liquids, excluding sediment and water and free water, corrected by

the appropriate volume correction factor (CTL) for the observed temperature and

specific gravity to a standard temperature and also corrected by the applicable

pressure correction factor (CPL) and meter factor;

• A measurement management system shall be included and applied on the FPSO

according to ISO 10012 “Measurement management systems — Requirements for

measurement processes and measuring equipment” in order to assure the

effectiveness and adequacy to the intended use, besides managing the risk of

incorrect metering results. This system shall be implemented according to Petrobras

Standards and recommendations;

• Production separator meters, test separator meters and gas lift meters shall have their

mass flow values calculated and recorded. Daily and hourly totalizers shall also be

recorded.

• Every service line shall have a gas lift meter installed on topside.

• CONTRACTOR shall consider flow computers to interconnect to subsea gas lift flow

meters (9 flow meters shall be considered). Flow computers to communicate to MCS

panel via Modbus RTU or 4-20mA input cards (to be confirmed during detailed

phase). Data from these flow meters shall be available at FMS Workstation.

CONTRACTOR shall be responsible for the integration between MCS and FMS.

Operation and parametrization of subsea gas lift meters is CONTRACTOR scope;

• Subsea gas lift measurements shall be continually compared by means of

reconciliation factors against gas lift topside meters in order to monitor the

measurement quality of subsea meters.


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• It must be possible to test a single gas lift subsea meter against the topside individual

gas lift meter. These performance tests should be performed to verify the accuracy of

gas lift subsea meters whenever malfunctions are suspected.

• CONTRACTOR shall foreseen interface meetings with subsea flow meter

manufacturer (multiphase and gas lift) for intercommunication details implementation.

CONTRACTOR shall also foreseen commissioning of subsea meters together with

meter manufacturer.

• The FMS flow meter of each incoming production line and each gas injection line shall

have its instantaneous flow rate signal sent to Process Shutdown System (PSD)

through a hardwire connection. Logic implementation will be discussed during detail

design with PETROBRAS.

7.7.2 MULTIPHASE METERING

• The multiphase metering system shall comply with Resolução ANP 44/2015.

• In the beginning of the Unit design, within 6 months time, CONTRACTOR shall

provide to PETROBRAS the preliminar documents (in Portuguese language) of

multiphase metering system to be submitted to ANP for approval, according to

Resolução ANP 44/2015.

• 20 months before production system start-up, CONTRACTOR shall provide to

PETROBRAS the complementary documentation (in Portuguese language) of the

multiphase metering system to be submitted to ANP for approval, according to


• Every production riser shall have a Topside MultiPhase Flow Meter (TMPFM) installed

on topside. Maximum acceptable pressure loss due to multiphase meters is 400 kPa

per production line.

• If multiphase meters are equipped with radioactive sources, CNEN resolutions shall

be complied with.

• PETROBRAS will install a dedicated Subsea MultiPhase Flow Meter (SMPFM) to

each production well. Subsea arrangement may be with a trunkline, manifold or

satellite well.


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• The FMS Workstation shall receive and store the process data, parameters and

diagnostics available on subsea and topside multiphase meters. These data must

also be available to PI system, considering the following variables as a minimum:

o Volumetric oil flow at reference conditions (m³/h);

o Volumetric water flow at reference conditions (m³/h);

o Volumetric gas flow at reference conditions (m³/h);

o Volumetric oil flow at actual conditions (m³/h);

o Volumetric water flow at actual conditions (m³/h);

o Volumetric gas flow at actual conditions (m³/h);

o Mass flow of oil (kg/h);

o Mass flow of water (kg/h);

o Mass flow of gas (kg/h);

o Mass flow of liquid (kg/h);

o HC mass flow (kg/h);

o Total mass flow (kg/h);

o Oil hold-up at actual conditions (%);

o Gas hold-up at actual conditions (%);

o Water hold-up at actual conditions (%);

o GLR at reference conditions (%);

o GOR at reference conditions (%);

o WLR at reference conditions (%);

o GLR at actual conditions (%);

o GOR at actual conditions (%);

o WLR at actual conditions (%);

o Static pressure (kPa);

o Differential pressure (kPa);


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o Temperature (°C);

o Water salinity (PSU);

o Oil specific mass at reference conditions (kg/m³);

o Gas specific mass at reference conditions (kg/m³);

o Water specific mass at reference conditions (kg/m³);

o Oil specific mass at actual conditions (kg/m³);

o Gas specific mass at actual conditions (kg/m³);

o Water specific mass at actual conditions (kg/m³);

o Oil dynamic viscosity at reference conditions (cP);

o Gas dynamic viscosity at reference conditions (cP);

o Water dynamic viscosity at reference conditions (cP);

o Oil dynamic viscosity at actual conditions (cP);

o Gas dynamic viscosity at actual conditions (cP);

o Water dynamic viscosity at actual conditions (cP).

• FMS shall communicate with SPCS ro receive SMPFM data. In addition, FMS shall

be able to write in defined registers of SPCS, to be defined during execution phase.

FMS Workstation shall foreseen supervisory screens for this SMPFM interface.

• The FMS Workstation shall handle any verification of the topside and subsea

multiphase meters, either by performing a calibration against a test separator or

continuously monitoring flow between subsea and topside meters.

• Oil, gas and water samples shall be collected from test or production separators no

longer than 6 months for analysis, recombination and updating as directed by subsea

and topside multiphase meters manufacturers. The interval may be longer than 6

months only if authorized by PETROBRAS.

• SMPFM shall be continuously compared by reconciling factors with TMPFM and

production/test separator metering systems to monitor the measurement quality of

subsea meters. TMPFM shall also be continuously compared by reconciliation factor


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with the production/test separator in order to monitor the measurement quality of

topside meters.

• It shall be possible to align topside and subsea multiphase meters against production

and test separators for individual performance testing. These performance tests shall

be performed to verify the accuracy of multiphase meter whenever a malfunction is

suspected.

• Operation and verification of topside and subsea multiphase meters is the

CONTRACTOR‘s responsibility, which includes parameterization. It shall be possible

to update the parameters of the topside and subsea multiphase meters from the FMS

Workstation.

• Maintenance of topside multiphase meters is the CONTRACTOR‘s responsibility,

while maintenance of subsea meters is the responsibility of PETROBRAS.

• Maintenance and verification plans to keep the proper functioning of multiphase

meters shall be defined and carried out by the CONTRACTOR and approved by

PETROBRAS.

• The installation of multiphase meters shall allow the maintenance and replacement of

these equipment without interrupting the operation of the FPSO. The operating

envelope of the multiphase meters shall encompass the entire expected flow range

over the lifetime of the wells. If it is not possible to attend the required uncertainty with

the same multiphase meters over operational lifetime, additional streams in parallel

shall be foreseen.

• Each multiphase meter in operation shall have one backup meter in stock for rapid

replacement in case of failure. It is acceptable that only one backup meter is provided

for each group of identical meters.

• For approval of the multiphase metering project, the multiphase meters model shall

be subject to performance testing in an independent laboratory to ensure that

performance meets the required uncertainty criteria as per paragraph 3.1 of


• Performance tests should be conducted with fluids as close as possible to actual

process conditions, covering the operating envelope and flow rates multiphase

meters would be subjected to during the actual application.


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• FAT shall be done for every TMPFM supplied, covering at least functional tests,

according to technical specification, and individual performance proven through

calibration.

• PETROBRAS is expected to witness the performance approval test and FAT of the

multiphase meters. Notification shall be sent at least 45 days in advance.

7.8. NOT APPLICABLE

7.9. DPRS – DYNAMIC POSITIONING REFERENCE SYSTEMS

CONTRACTOR shall provide and install the three reference systems according to the

requirements mentioned on the Technical Specification OFFSHORE LOADING SYSTEM

REQUIREMENTS included in the BID documentation (see 1.2.1).

• DARPS 900B - Differential Absolute and Relative Positioning System (DARPS).

• Artemis - a microwave radio positioning system of “range-bearing” type, ARTEMIS

Mark V or latest version, fixed station.

• Fan-beam - an optical laser positioning system target.

7.10. ENV – METOCEAN DATA GATHERING AND TRANSMISSION SYSTEM

This system shall be supplied and installed by the CONTRACTOR according to the specific

document cited in Item 1.2.1.

7.11. RISER MONITORING SYSTEM

7.11.1. POSITIONING SYSTEM FOR MOORING OPERATION AND OFFSET DIAGRAM

The Technical Specification I-ET-3010.1U-5530-850-PEA-001: POSITIONING AND

NAVIGATION SYSTEMS FOR THE XXXXX – MÓDULO I (see item 1.2.1) describes the

requirements for the POS - Positioning System (positioning, navigation and monitoring

activities) of the FPU - Floating Production Unit operating for PETROBRAS in Brazilian

offshore basins.


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Through DOF (Diagram of Offset), the position monitoring allows faster assessment of

possible damage to the mooring system. The content of this document is to allow the FPU

control during critical operations as towing, entrance on location (hook-up), connections and

disconnections (pull-in and pull-out, respectively) of risers, tensioning of mooring lines,

mooring lines maintenance, supplying and off-loading operations. This document will also

allow monitoring FPU ride to calculate the stresses of risers and alarm in the event of

disruption of a tie, as well as monitoring boats around.

The Contractor shall provide to PETROBRAS a document containing the maximum offset for

intact condition in 16 directions considering the environmental conditions: 100-year and 1-

year. Those 16 directions determine a polygon with includes all the offsets environmental

cases analyzed.

For that, the table below could be used as an example:

Table 7.11.1.1: Maximum offset for intact condition.

100 – year (Intact)

Point Offset

(%) Offset (m) Angle (deg) UTM E UTM N

1-16 % WD

Offset -

meters

Direction “going to”

related to North, positive

clockwise Coordinate UTM East Coordinate UTM North

7.11.2. MODA RISER MONITORING SYSTEM

The tensile armor wires of every flexible risers / jumpers shall be monitored by the MODA

System. This system shall be applied to all flexible risers (production risers, water injection

risers and service risers (gas lift) of all wells).

The MODA system scope is specified in the document “MODA RISER MONITORING

SYSTEM – FPU SCOPE (SPREAD MOORING)”, I-ET-3010.00-5529-854-PEK-001.

MODA software, final integration with riser, and the optical cables between the riser and the

splice boxes are not included in the scope of supply of the CONTRACTOR


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7.11.3. ANNULUS PRESSURE MONITORING AND RELIEF SYSTEM

CONTRACTOR shall provide the annulus pressure monitoring and relief system, to

guarantee a safe release for the gas permeated in the annulus space of flexible risers and

to detect any pressure build up that may damage the risers.

CONTRACTOR shall perform detailed engineering of this system (including piping, valves,

pressure sensors, supervisory integration, etc.).

This system shall be applied to all flexible risers (production risers, water alternating gas

(WAG) injection risers and service risers for gas lift) of all wells.

Additional information is presented in the Technical Specification I-ET-3010.00-5529-812-

PAZ-001: Annulus Pressure Monitoring and Relief System (see 1.2.1).

7.11.4. RRMS

The Rigid Riser Monitoring System (RRMS) system is intended to verify rigid riser

geometry through two-axis inclinations and top loads. It includes subsea sensors, field

equipment and data processing equipment to be supplied by PETROBRAS and

infrastructure to be provided by the FPSO.

CONTRACTOR shall be responsible for providing FPSO-side infrastructure for the RRMS

system, for all rigid riser positions, as specified in the document “RIGID RISER

MONITORING SYSTEM (RRMS) – FPU SCOPE”, I-ET-3000.00-5529-850-PEK-001.

7.13. OPTIMIZATION AND ADVANCED CONTROL

Optimization and advanced control are intended to increase production efficiency, process

plant stability and safety of control loops of critical equipment. CONTRACTOR shall be

responsible for providing infrastructure for optimization and advanced control:

• 1 (one) machine (server) in the platform automation network to host advanced control

applications. Through this microcomputer, it shall be possible to access (read/write) all

control loops running in CSS (main topsides, subsea and Hull/Marine data) via OPC protocol.

PETROBRAS will provide the ADVANCED CONTROL software solution and

CONTRACTOR will configure the OPC connection with the Supervisory System to access

the control loops in CSS.


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• CONTRACTOR shall provide means, via supervision HMIs, allow the operator to enable

(on/off) the advanced control, as well as to define its limits and setpoints.

• CONTRACTOR shall set up watchdog logic in automation (A&C) systems to take the

correct actions and inform the operator when a communication fail has occurred between

the computer, where advanced control is running, and the automation system of the platform.

• All the necessary intervention in automation (A&C) system for the implementation of

optimization and advanced control is CONTRACTOR responsibility.

7.14. MACHINERY MONITORING SYSTEM (MMS)

CONTRACTOR shall provide a Machinery Monitoring System for critical rotating equipment

(all gas compressors, gas turbines, turbogenerators, main water injection pumps, booster

water injection pumps, sea water lift pumps, cooling water pumps for classified areas, MEG

injection pump, Heavy Hidrocarbon Rich Stream Pump and Refrigeration Unit Compressors)

and its drivers and gearbox/HVSD.

Note: If a heavy hydrocarbon rich stream booster pump is required, it shall be included in the

MMS..

MMS shall be integrated with the equipment sensors or, where available, with the Machinery

Protection Systems.

For a basic description, the primary function of the MMS is to perform analysis of the

mechanical parameters: all machinery protection system signals, with possibility to make

analysis like FFT, full spectrum, Bode plot, cascade and waterfall diagrams, shaft average

center line, orbit, X-Y plot and experience-based vibration analysis, and auxiliary system

signals (lube, seal, etc.).

The Machinery Monitoring System shall have the following functions:

• Data acquisition of vibration signals from machinery sensors and bearing temperatures

as a minimum;

• Data logging and event/variable recording and storing (compressed data feature to allow

the access of significant values with high resolution within measurements spanning five

years);

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• Historical trending (all variables);

• Real-time measurements in order to allow diagnostics of fault detection and analysis;

• Display of equipment schematic layout;

• Measurements covering the widest possible range of machine faults.

• Real-time display of process variables such as temperatures, pressures, flows, speed,

electrical measurements, valve position, tank levels, etc; and others applicable variables

for each equipment class.

The CONTRACTOR shall mirror MMS at the PETROBRAS Office through offshore DMZ, in

order to allow PETROBRAS to monitor the Machines. MMS and MPS shall have a dedicated

Ethernet network for vibration signals, separated from the network used to mirror MMS to

Petrobras Office. In addition to the signal available through MPS Communication,

CONTRACTOR shall make available the process variable signals through the Fast Ethernet

Network to perform the functions above in the Machinery Monitoring System, with acquisition

interval of at least one second

7.15 NOT APPLICABLE

7.16. GENERAL REQUIREMENTS FOR FIELD INSTRUMENTATION

The following shall be applied for field instrumentation:

• API RP 551 shall be used as the standard for instrumentation design, selection and

installation.

• All cable glands used in classified areas and in external areas, classified or not, shall

be specified taking into account cold-flow prevention, according to IEC 60079-14,

independently of the characteristics of cables and multi-cables

• In order to maintain standardization of future Operation and Maintainance, all field

instrumentation, including package units´ones, shall be supplied with 4-20mA + HART

signals. Field networks will not be accepted.


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• In order to comply with BDV opening sequence and blowdown calcutations, the

flowrate output of certain BDVs must be limited. This flowrate limitation of certain

BDVs shall be achieved using restriction orifices designed and constructed in order

to produce a critical flowrate (choked flow).

• All junction boxes and electronic field instrument enclosures shall be supplied in

stainless steel AISI 316.

• Remote reset of Topsides shutdown (SDVs), blowdown (BDVs) and on-off (XVs)

valves shall be foreseen from CCR (supervisory system).

• Automatic deluge valves (ADVs) shall be supplied with facilities for both field and

remote reset. Besides, the ADV actuation system shall allow the manual opening of the

valve, according to figure below:

Figure 7.16.1 - ADV actuation scheme

As required by I-ET-3010.00-5400-947-P4X-011 - SAFETY GUIDELINES FOR

OFFSHORE PRODUCTION UNITS – BOT / BOOT, the circuits below need to operate

during fire conditions and, therefore, shall be interconnected by fire resistant cables in

conformance with standards IEC 60331 and IEC 60332:

• ADV, BDV: solenoid and limit switch cables;

• SDV: limit switch cables;


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• Dampers: limit switch cables;

• Bypass SDV (small SDV installed in order to reduce shutoff pressure of large SDVs

during reopening operations): solenoid and limit switch cables;

• ESV (quick opening valve for Flare gas recovery systems): limit switch cables;

• ESV (quick opening valve for Flare staging): solenoid and limit switch cables;

• Backup for ESV (quick opening valve for Flare gas recovery systems) – such as

buckling pin valves or rupture disk: position indicator cables and actuation cables;

• Fire and gas detector cables, including cables for open path gas detection emmiters.

• Cables for systems that are started/remain operational during ESD-3P, ESD-3T or

ESD-4;

7.16.1. MOUNTING AND INSTALLATION REQUIREMENTS

Tubing for Topside HPU connections up to 5.000psi and instrumentation air shall be made

of stainless steel ASTM A 269 Gr. TP 316L with minimum Molybdenum content of 2.5%.

The allowable tubing for impulse line diameters and wall thickness are present in table

7.16.1.1.

Table 7.16.1.1: Impulse line diameters and wall thickness

External

Diameter

Wall

Thickness

Internal

Diameter

(mm)

Work

Pressure Material Application

½" 0,065” 9,4

Up until

33.000

kPa

ASTM A 269

Gr. TP 316L

(note 1)

Gas/Dry air;

Water/Vapour

¾” 0,095” 14,2

Up until

33.000

kPa

ASTM A 269

Gr. TP 316L

(note 1)

Gas/Wet air;


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½” 0,065” 9,4

Above

33.000

kPa

Super

Duplex

ASTM A789

UNS

S32750 or

S32760

Gas/Dry air;

Water/Vapour

¾” 0,083” 14,8 Above

33.000

kPa

Super

Duplex

ASTM A789

UNS

S32750 or

S32760

Gas/Wet air;

Note 1: Where the temperature exceed 60ºC the tubing material and its connectors shall be

selected in DSS, SDSS or Monel 400.

Supports that may present crevice corrosion shall not be used, such as strip type or clamp

type supports. Tubing supports shall be designed minimizing the number of contact points

between the tubing and the support, in order to reduce the number of points of crevice

corrosion points.

Desired tubing support is presented on figure 7.16.2. Other support types shall be presented

for Petrobras approval.


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Figure 7.16.2 - Tubing Suport

7.17. REMOTE OPERATION

A remote onshore control room ("Sala de Controle Remota", SCR) may be installed onshore

at a PETROBRAS building.

The onboard main supervision and operation system shall exchange data with the onshore

control room so that it is possible to fully monitor and operate the FPSO from shore. Remote

monitoring shall always be possible from shore, however, remote operation may or may not

be allowed. Thus, it shall be possible to block FPSO remote operation from shore, at

Operation discretion. The use of software tools to perform remote operation blocking is

acceptable.


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The communication requirements between offshore and onshore main supervision and

operation systems are defined on Telecommunication Systems - I-ET-0600.00-5510-760-

PPT-565.

In order to perform that in the future, the following shall apply.

7.17.1. REMOTE SUPERVISION AND OPERATION

The main supervision and operation system, as well as the package units´operation systems

and/or local HMI, shall have physical and logical resources that permit remote utilisation by

means of RDP (Remote Desktop Protocol) or equivalent software. The monitors, sound,

mouse and keyboard shall be accessible by the Remote desktop tool.

All physical and logical resources to be installed onboard in order to perform remote

operation of the above mentioned systems shall be supplied by CONTRACTOR.

All generators and compressors shall be accessible by this tool.

For those systems which are technically unable to perform remote access in the remote

onshore control room (SCR), the systems shall be mirrorred using RDP at the PETROBRAS

Office.

7.17.2. NETWORK

The systems and package-units that will be operated through SCR shall be connected to the

Automation network.

In order to perform that, the Automation network shall be extended up to SCR, using the

availabe telecommunication media offshore. Cybersecurity mechanisms shall be supplied to

protect the Automation network.

7.18. SMBS CONTROL AND MONITORING SYSTEM

The SMBS Control and Monitoring System comprises all Automation and Control equipment

needed for the correct operation of the SMBS system.


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The core of this system is the SMBS Master Control Station (SMBS MCS), which is a set of

panels that is the single-point automation interface with all other SMBS equipment. PSD and

FGS/ESD hardwired signals shall be exchanged bidirectional between the SMBS MCS to

the CIS. Besides, the SMBS MCS shall make the main process variables of the SMBS

available to the supervisory system via computer network using Modbus TCP or OPC-UA

protocols (final protocol will be defined by PETROBRAS during SMBS installation). The

SMBS MCSs shall have their power supplied by the UPS. The MCS may require an external

connection to the Internet through the platform firewall.

Additionally, the CCR HMIs shall display in dedicated screens and in real-time all the

variables of the SMBS system. If the SMBS supplier furnishes a dedicated Operation

Workstation, this workstation shall be placed in CCR and all its interconnections with the

CIS/MCS shall be supplied, installed and configured by CONTRACTOR.

Other A&C equipment may include the following items:

a) Barrier fluid HPU (BF HPU)

b) Control Fluid HPU (CF HPU)

c) Electronic Power Unit

d) Topside Umbilical Terminal Unit (TUTU)

e) Electrical Junction Boxes distinct from the TUTU

f) Optical Junction Box distinct from the TUTU

This equipment is considered an integrated part of SMBS package and, as so, shall be

supplied or endorsed by the SMBS manufacturer in order to preserve the warranty of the

whole system.

Additionally, it is the MANUFACTURER scope of work:

• Provide the correct internal interconnection of all SMBS topsides equipment

(process, electrical, automation and instrumentation connections, etc.) and with the

umbilical terminal unit;

• Provide configuring, testing and internal commissioning and any other services in

order for the HISEPTM system to be fully functional.


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CONTRACTOR shall provide the correct interconnection of all SMBS systems (including

MCS and Operation workstation) with FPSO systems (automation, electrical, pneumatic,

hydraulic, etc.).

CONTRACTOR shall provide, configuring, testing and commissioning of the SMBS system

integration with the CIS in order for the SMBS system to be fully functional in the FPSO.

CONTRACTOR shall provide the connections between umbilical terminal units and the

umbilical.

CONTRACTOR shall follow all operational requirements (such as maintaining the

cleanliness levels of the SMBS HPU hydraulic fluids) defined in section 7.5.2 - SPCS MAIN

SPECIFICATIONS.

Dedicated drawers in the MCC shall be foreseen for the Barrier Fluid HPU power supply.

The BF HPU shall therefore be energized by FPSOs MCC. The commands for the BF HPU

shall come from the SMBS MCS.

8. ELECTRICAL SYSTEM

The electrical system design and installation shall comply with latest version IEC 61892

series, IEC 60079, and IMO MODU CODE.

The electrical system shall comply with Brazilian NR-10 – Safety in Electrical Installation and

Services.

8.1 GENERATION POWER MANAGEMENT SYSTEM (PMS)

Apart from the usual generation unit controls ( frequency , voltage control and turbine

controllers) a master independent generation control shall be supplied in order to maintain

full simultaneous control of all generators of the FPSO. This controller shall be hereinafter

called PMS (Power Management System).

A power management system (PMS) shall be provided to give stability to the power

distribution network, controlling automatically selected generators for operation in parallel,

through frequency control, voltage and the active and reactive powers.

8.1.1 PMS GENERAL REQUIREMENTS


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The PMS shall be a microprocessor-based controller.

The product shall have proven satisfactory performance and shall be type approved by Class

Societies.

The PMS shall basically comprise generator paralleling control, load sharing, peak shaving,

automatic load shedding, load import/export control and protection ( see also item 8.1.2).

The PMS shall have independent algorithms for dependency between the modes of load

shedding (instantaneous and gradual).

The PMS shall perform event registration and allow export records in editable file (txt, xls,

etc).

The PMS event log shall include the condition status of the main generators circuit breakers,

tie circuit breaker of the main high voltage panel, high and low voltage of transformers circuit

breakers, generators auxiliary and emergency circuit breaker.

PMS load shedding operation times shall be compatible with the generation loss stability limit

of the electrical system.

The under frequency load shedding (instantaneous and gradual) shall allow associated load

and timing adjustment .

The PMS shall have a load shedding priority choice functionality. This functionality shall be

of easy access and easy execution by the operator.

The PMS shall provide TGCPs` remote manual and automatic actuation commands

performing synchronization of the main generators for the closure of their respective circuit

breakers

The PMS shall be able to perform the synchronization among generators through each

generator circuit breaker (main bus bar switchgear synchronization) and through each bus

bar tie circuit breakers (synchronism between electrical isolated islands).

In case of operation in electric Islands, the load shedding shall be able to identify the island

with electric generation and shed loads only on this island.

Load shedding shall be "hardwired", i.e. through dry contact from the digital outputs of the

PMS.


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8.1.2 SPECIFIC REQUIREMENTS

The PMS controller shall be comprised by the following facilities:

a) Intelligent Load Shedding, comprising:

• Alarm due to gradual overload

Fast acting initiated by sudden loss of generating capability;

• Generator gradual overload shedding;

• Under frequency shedding;

• Rate of change of frequency shedding according to multiple or dynamic load priority

tables;

• Islanding load shedding capability.

Load shedding notes:

• The load shedding shall command the shutdown of predetermined loads of medium

voltage switchgear in the case of overload of the main generation.

• Each load or group of loads shall be configured according to the following priority

disposal.

• The selection of loads and priorities will be defined for the project.

b) Automatic load control (control of Voltage, Frequency, Power, MVAr/Power Factor),

including :

• Power system frequency and voltage control;

• Power sharing (MW and MVAr) at any predetermined proportion;

• Individual generator baseload target control (MW, MVAr and PF);

• Group set-point target (MW, MVAr and PF);

• Islanding operating modes ( independent islanded subsystem control).

Load sharing notes:

• The Division of load (kW and kVAr) between generators shall be possible in:


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• Automatic Base, considering the complete system with the main generation switchgear

TIE circuit breaker closed.

• Automatic Base, considering each separated system, each “island”, with the main

generation switchgear TIE circuit breaker open.

The control of the Load division (kW and kVAr) between generators shall be compatible with

the control modes of the generators groups provided. Be adivised that some manufacturers

use different control modes than traditional Droop and Isochronous control modes.

c) Additional features required:

• Voltage boosting facility;

• Generator capability de-rating;

• Generator Set Management/Dispatch;

• Load starting inhibit system in case of low spinning reserve;

• Automatic start sequence prior to large motor start;

• Manual generator start and stop sequence initiation from HMI;

• Black starting;

• Load start inhibits.

d) Human Machine Interface (HMI):

• HMIs to provide improved control and visualisation of the electrical power system;

• Comprehensive trending and event recording facilities are included;

• Means for operators to initiate commands for functionalities such as generator starting

and stopping, busbar synchronizing;

• Opening and closing of circuit breakers ( including tie breaker).

e) Data Transfer capability with external systems ( protective relays and generator and

turbine controllers)

8.1.3 ACCEPTANCE TESTS

8.1.3.1 GENERAL REQUIREMENTS

Acceptance tests shall include factory tests, commissioning tests at the shipyard and also

final checking and fine adjustment of the control parameters.


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At any time Petrobras reserves the right to send a representative technician to witness the

tests.

Commissioning tests listed on item 8.1.3.2 shall be performed at the shipyard and shall be

witnessed by Petrobras representative. The adequacy of the PMS load sharing and load

shedding functions shall be demonstrated with two main generators in parallel operation

supplying a temporary medium voltage load bank rated at least 1.2 times the active rated

power of one main generator.

The mentioned temporary load bank shall be a containerized product including control,

protection and switching capability to allow for adequate stepping of the load .The load bank

shall be made of a combination of resistive and reactive loads.

PMS factory tests shall be conducted with various scenarios. These scenarios shall be single

and multiple simultaneous failures (i.e.: loss of a generator followed by loss of another

generator at 100 ms interval, TIE circuit breaker opening and loss of generator, etc).

8.1.3.2 FIELD TESTS TO BE PERFORMED

Complete field test shall be carried out under load conditions ( with the generating system

connected to a distribution switchgear and supplying a combined load bank rated at least 1.2

times one of the main generators rated active power), including at least:

• Busbar voltage control with two or more generators in parallel operation;

• System frequency control with two or more generator in parallel operation, upon

increasing and decreasing load steps.

• Checking of conventional operation (on/off/synchronization) of generators;

• Automatic load transfer from a running generator to be stopped to other generators

the be kept running;

• Control (synchronization) of tie circuit-breaker connecting two islanded generator

subsystems;

• Checking of proper actuation of active and reactive load sharing among two or more

generators in parallel operation;

• Checking of proper operation of load start inhibit system;


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• Checking of proper operation of load shedding system;

• Checking of proper operation of field forcing control process.

8.2. GENERATORS

8.2.1. MAIN GENERATORS

The power generation system shall be designed considering the following cases:

• 100% of the treated gas shall be reinjected simultaneously with 100% water injection

capacity.

• The generators packages on duty shall be designed to supply the maximum electrical

load at maximum ambient temperatures (30 degrees Celsius).

• Subsea Multiphase Boosting System demand shall not be considered.

Each power generation package consists of a synchronous alternator driven by dual fuel gas

turbine, designed to operate on fuel gas (normal) or on diesel fuel (no fuel gas available).

For main power generation based on gas turbines, two different and independent means (i.e.

the auxiliary and the emergency diesel-generators groups) shall be capable to start-up the

main generator, assuming dead-ship condition. Pneumatic motor is not acceptable to start

the gas turbine. Independent means for starting the auxiliary generator shall be provided

apart from the operation of the emergency generator.

The auxiliary systems and peripherals of these diesel-generators, including tension control,

means of departure, their means of recharge etc should be completely independent, without

common failure mode, each with their own means of cold start.

In the case of shutdown without electric power, the lubrication during coastdown time must

be provided by a run-down tank or a pump driven by the gearbox. DC-powered pump is

acceptable only for post-lube (cooldown time), as long as the OEM also provides the entire

battery system and other accessories for its operation. The proposed system shall have

sufficient capacity to withstand the required cooldown time, including care of the intermittent

drive of the DC pump, throughout the cooling period. The equipment shall have a load-

sharing capability to allow the parallel or individual operation of the turbogenerators in order

to allow parallel operation in "droop" and isochronous conditions.


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8.2.2. MAIN TURBOGENERATORS GENERAL REQUIREMENTS

Gas turbine with ISO Power greater than 25000kW shall be aeroderivative type. Gas turbine

with ISO Power lower than 25000kW shall be aeroderivative or industrial type. Gas turbines

shall be designed according to API 616 and comply with ASME PTC-22. The gas turbine

combustor shall be of the standard type. Multiple fuel manifolds for low emission control are

not acceptable. CONTRACTOR shall fulfill all Brazilian Regulatory Authorities regulations

issued by Environment Ministry (“Ministério do Meio Ambiente”), through its CONAMA

Resolução Nº382/2006. Radioactive components are prohibited.


The main generators shall be capable to immediately restart at any time after a shutdown

event. Restart locking sequence "forced lockout time" is not accepted. Each unit shall be

provided with a dedicated UCP (control unit panel) containing part of the control and safety

system hardware and interconnected to the remote I / O. Each UCP must operate

independently, so that failure of any component within UCP does not affect the availability of

any other UCP and / or other unit.

For the same service, any HMI shall be capable to operate any equipment train.

The mineral lube oil system shall be design according API 614 with the following typical

configuration:





Note: The main lubricating oil pump, when mechanical, must be driven by the gearbox /

HVSD or by the turbine shaft. In case the pumps (main and reserve) have electric drive, they

must be an essential load.

The fuel gas and liquid fuel for the gas turbines shall be properly treated to comply with the

gas turbine manufacturer requirements.

The main power generation package supplier shall be the turbine OEM (original equipment

manufacturer). The waste heat recovery unit (WHRU) and Power Management System

(PMS) shall be included in main power generation package scope of supply.


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Turbine housing (Enclosure) firefighting system shall be water mist type.

Produced gas shall be treated as necessary to be used as fuel for the gas turbines, flare pilot

and flare purge according to each vendors specifications.

The configuration of the main generator packages shall consider one generator in stand-by

condition, for all cases indicated in item 8.2.1.

Contractor is requested to present the following on the technical proposal submission in order

to evidence power generation compliance to GTD:

X(KW) = Turbine ISO output power at 15 degrees Celsius temperature](KW) * [N-1]

generators

Y(KW) = [maximum electrical demand from electrical load balance calculation report]

(KW) / FF

X(KW) shall be greater or equal than Y (KW)

[N] = total number of main turbogenerators sets installed.

FF = [F11 x (F12 if applicable) x F13 x F14 x (F15 or F16) x F17]

Where:

- [N] is the total number of main turbogenerators sets installed.

- Mechanical losses in electric generator (efficiency of 0.975 F11);

- Mechanical losses in the gearbox, if applicable (efficiency 0.985 F12);

- Turbine degradation losses (efficiency of 0.97 F13);

- Fouling losses of the turbine compressor (efficiency of 0.98 F14);

- Loss on admission and exhaustion without WHRU (efficiency of 0.98 F15) or with

WHRU (efficiency of 0.97 F16);

- Derate referring to the ISO temperature correction for Site (at 30oC efficiency of 0.85

F17);

Note: PETROBRAS considers that Bidder will built-in design contingencies into the

maximum expected electrical demand. However PETROBRAS consider those contingencies

(margins) as a bidder internal issue.


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High speed systems are not accepted for the stages of filtering combustion air / ventilation

air turbine, except for the stages of inertial separation. Air combustion filtering system for gas

turbines shall be submitted for Petrobras approval.

The access around the combustion air filter box of the turbines shall be sufficient spacious

and shall have a hoisting device to move the air filter elements for the replacement task.

All fuel gas and liquid fuel systems shall be made of 316L stainless steel,.

All piping and appurtenances downstream oil filters of oil systems shall be made of AISI 316L

stainless steel.

Housing (Enclosure) of gas turbine shall be made of 316L stainless steel.

All inlet air system components of gas turbine shall be in AISI 316L stainless steel.

The gearbox between the turbine and electric generator shall meet API 613 latest version.

One or more online/offline gas turbine washing system shall be provided according to the

turbine manufacturer specification with easy handling for all the gas turbine units. The

washing system shall include piping to receive demineralized water from the water source

and shall have 2 (two) tanks, one for pure demineralized water and the other for mix of

demineralized water and detergent.

The turbogenerator skids shall be installed with the length dimension of the equipment

aligned with the longitudinal axis of the FPSO.





transfer among them. That includes diesel system design.

The turbogenerator package shall be supplied with the OEM control system and with the

built-in protections. The OEM shall assume full responsibility for the design (architecture),



monitor from the UCP HMI and remote HMI installed in the Central Control Room.Every HMI

of Main Generator service, shall be able to operate any generator of the same service.


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8.2.3 GENERATORS ELECTRICAL REQUIREMENTS

Power generation packages shall include all required auxiliary systems and controls, i.e.,

voltage/reactive power control, speed/active power control, synchronization, load shedding,

etc

The vacuum impregnation method shall be used for winding insulation construction for

Generators with rated voltage equal to, or higher than 6kV.

Generators with rated voltage equal to, or higher than 6kV shall be designed and

manufactured in such a way as to be approved in sealed winding spray-test, in accordance

with the procedures indicated on NEMA MG 1.

Generators with rated voltage equal to or greater than 6kV and rated power equal to or

greater than 5MVA shall have a coupling capacitor unit per phase suitable for on-line

monitoring of partial discharges.

For starting the largest motor it shall be considered 2 main generators running, to keep

transient voltage drop within tolerable limit for the electrical system, according to IEC61892-

2.

Note: In case the generating system is comprised by 4x25 MW generators, the maximum

allowed motor rating shall be 11MW, specially designed with reduced starting current.

For 4x28 MW generation case , the maximum allowed motor rating shall be 13MW, specially

designed with reduced starting current.

Note: The number of the generators running shall have PMS limit control to comply with

CONAMA requirements. Design of large motors starting shall take this limitation into account.

Contractor shall consider stand-by compressor start-up without turn off the running

compressor during load transfer.

Due to ambient temperature it shall be considered the loss of Engine Power to design each

one.

8.2.4 ESSENTIAL/AUXILIARY GENERATORS

For auxiliary generator package, CONTRACTOR shall use new equipment.

The Auxiliary generator shall be the main way to start the turbogenerators.


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The Auxiliary generation system shall be designed to provide condition to start the

turbogenerators when these ones are off.

The Auxiliary generation system is the backup of the Emergency Generation System. In this

way, it shall be designed with the same requirements applied for Emergency Generator.

The use of an auxiliary generator, apart from the main ones, to meet peak loads during

offloading is acceptable.

The Essential Generators Control Panel shall be designed with a dedicated microprocessor-

based device (for example, EGCP-3 ® or similar controller). This controller shall include the

control for starting of the system and be certified for Naval use.

The control panel shall be designed with dedicated Controller for each group.

A quick-closing fuel valve shall be a normally-open, “energize to close” coil. A manual acting

closing device shall be provided to close the fuel valve, outside auxiliary generator rooms, in

case of fire inside. This valve shall be installed close to CO2 push bottom of respective

ambience.

The control panel shall comprise analog gauges and resources for synchronization,

periodical tests and restarting of the unit after a blackout.


one.

The design shall provide synchronization conditions acting in the following circuit breakers

from the AGCP:

a) the essential/auxiliary generator circuit breaker;

b) input circuit breaker of essential/auxiliary generator Switchgear;

c) TIE circuit breaker of essential/auxiliary generator Switchgear

d) back-feed circuit breakers of essential/auxiliary generator Switchgear

To allow your proper operation, auxliary generator control panel shall be built with all keys

and control devices on its frontal side. This panel shall possess fault signaling device on the

electrical generator and diesel engine.

8.2.5. EMERGENCY GENERATOR


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Emergency generator shall be dimensioned to feed simultaneously all loads indicated in the

SAFETY GUIDELINES FOR OFFSHORE PRODUCTION UNITS – BOT / BOOT, IMO

MODU CODE and required by C.S., for at least 18 hours without need of refueling

The emergency generator shall be a standalone unit [IMO MODU CODE], air cooled with

radiator mounted on the motor base and the fan powered by diesel engine shaft.

Emergency generator system shall not be composed by grouping small existing units from

ship to be converted and shall consist of a single new package.

The emergency generator system should be tested in accordance with item 5.4.16 from IMO

MODU CODE. Testing at regular intervals shall also cover load operation without interruption

The Emergency Control Panel shall be designed with a dedicated microprocessor-based

device (for example, EGCP-3 ® or similar controller). This controller shall include the control

for starting of the system and be certified for Naval use.

The project shall provide conditions for manual synchronization with the operator in EGCP

and automatically via the controller (EGC).

The control panel shall be designed with dedicated Controller for each group.

The control panel shall comprise analog gauges and resources for synchronization,

periodical tests and restarting of the unit after a blackout.

A quick-closing fuel valve shall be a normally-open, “energize to close” coil. A manual acting

closing device shall be provided to close the fuel valve, outside the emergency generator

rooms, in case of fire inside. This valve shall be installed close to CO2 push bottom of

respective ambience.

It shall be provided two independent starting system. The first one shall be sized to allow at

least 6 (six) consecutive starts. The second one starting system shall be sized for at least 3

(three) consecutive starts.

Independent energy recharging and storage system shall be provided for each emergency

generator starting system (six times and three times).

The emergency generator system shall be designed for heavy duty, in continuous operation

(Base Load), as defined by ISO 8528.


one.


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The emergency generator shall not have common failure mode with plataform UPS systems.

Emergency generator control panel shall provide suitable devices to enable Emergency

generator operation in parallel with the main or auxiliary generation. Weekly parallel test shall

be performed.

The emergency generator shall operate with speed control in isochronous mode when

operating insulated or droop or base load when operating in parallel with the main or auxiliary

generation. When operating in parallel with the main or auxiliary generation, the voltage

regulator of the emergency generator shall be in power factor control or reactive power

control.

In addition diesel engine protections, the emergency generator shall have short circuit

current protection (time overcurrent voltage-constrained 51V ANSI function), loss of field

protection (ANSI function 40) and motoring protection(ANSI 32 function).

Multifunction microprocessor protection relays (digital) shall provide event logging

capabilities and oscillography.

The insulation class of the emergency generator shall be F (155° C) and temperature rise B

(80° C).

It shall not be used minimum voltage coil circuit breakers in the emergency generator circuit

breaker.

To allow your proper operation, emergency generator control panel shall be built with all keys

and control devices on its frontal side. This panel shall possess fault signaling device on the

electrical generator and diesel engine.

8.3. ELECTRICAL DISTRIBUTION SYSTEM

8.3.1. POWER DISTRIBUTION

The HV, LV and UPS distribution system shall be designed with required redundancy, so

that a single failure in any equipment, circuit or bus section does not impair the whole system

and neither reduce the production/processing capacity of the Unit.

For main generation systems, the main bus shall be subdivided in at least two parts which

shall be normally connected by a tie circuit breaker.


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The power distribution system shall be of secondary-selective type, with main bus subdivided

in at least two parts which shall be normally connected by a tie circuit breaker; each bus

part shall normally be fed from secondary of duplicated and fully redundant HV/LV

transformers with tie circuit breaker open.The main switchgear panel, for Medium Voltage

generation and distribution systems, shall be in 13.8 kV, 3 phase, neutral earthinhg by high

resistance system.

The main switchgear panel, for Medium Voltage generation and distribution systems, shall

be in 13.8 kV, 3 phase, neutral earthinhg by high resistance system.

The voltage control circuits of Medium voltage and low voltage switchgears and the Low

voltage Motor control centers shall have redundancy feeders. In this way, a fail of one feeder

of voltage control will not provoke the lost of production and lost of Main Generation system

even during transitory undervoltage.

The following definitions shall be considered for all Electrical Design:

a) Essential Loads are those loads defined as “Emergency Loads” by IMO MODU CODE

and Classification Society rules. All essential loads shall remain energized by

Emergency Generation System after shutdown stop ESD3-T and after Main

Generation System failure.

b) Emergency Loads are those loads which shall remain energized by batteries after the

Emergency Generation System failure.

c) Normal (including Auxiliary) Loads are those loads fed only by Main Generation

System or Auxiliary Generation System. They are not classified as Emergency or

Essential Loads. Normal loads shall remain de-energized during emergency

shutdown ESD3-T.

It shall be provided interconnections (backfeed) between the Switchgear where the

Emergency Generator will be connected and the Switchgear where the auxiliary generator

will be connected.

It shall be possible to feed the essential panel by both emergency generator and auxiliary

generator.

8.3.2. GROUNDING


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The earthing and detection methods shall comply with IEC 61892-2 requirements and the

Classification Societies’ rules, as applicable.

For Medium Voltage generation and distribution systems, the high resistance earthing, with

instantaneous selective tripping in the event of earth fault, shall be adopted.

8.3.3. ELETRICAL EQUIPMENT RATED VOLTAGE

Unless otherwise stated in PETROBRAS documentation, the selection of rated voltage of

electrical system and equipment shall follow the criteria defined in the below.

For all Vac systems, frequency shall be 60 Hz.

Table 8.3.3.1: System Rated Voltages and Grounding Systems

System Rated

Voltage

Grounding

System Remark

13800Vac High Resistance

Grounded at Main Generators neutral

point, using grounding resistors with

grounding transformers.

4160Vac High Resistance Grounded at distribution transformers

neutral point.

690Vac Ungrounded Only for Regeneration Gas Heaters

480Vac Ungrounded

220Vac Ungrounded

220/127Vac Solidly Grounded

Grounded at lighting transformers

neutral point.

Only for distribution inside

accommodation module.

220Vdc Ungrounded

125Vdc Ungrounded

120Vac Solidly grounded Only for control inside electrical panels

48Vdc

According to

telecommunication

documentation

Only for telecommunication loads

24Vdc Ungrounded


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Table 8.3.3.2:Rated Voltage for Electrical Equipment

Equipment

Rated

Voltage N º

Phases or

Poles

Remarks

Main Generators 13800Vac 3ph

Motors with rated power above 120W 13800Vac 3ph

Motors with rated power above 150kW up to 1200kW (1) 4000Vac 3ph

Motors with rated power above 355kW up to 1500kW using VSD 4000Vac 3ph

Resistive loads of Regeneration Gas Heaters 690Vac 3ph

Resistive loads with rated power above 4kW 480Vac 3ph

Power socket-outlets 480Vac 3ph

Motors with rated power up to 150kW using direct-on-line start 440Vac 3ph

Motors with rated power up to 355kW using soft-starter or VSD (2)

440Vac 3ph

Motors and loads for refrigerant chambers, galleys and laundries 220Vac 3ph

Resistive loads with rated power up to 4kW 220Vac 2ph

Anti-condensation heaters 220Vac 2ph Fed from normal

panels

General use socket-outlets for external areas 220Vac 3ph

General use socket-outlets for internal and external areas 220Vac 2ph (3)

Fan coil motors with rated power up to 0.5kW 220Vac 2ph Fed from lighting

panels

Normal lighting 220Vac 2ph

Essential lighting 220Vac 2ph

External power source for control of switchgears and medium-

voltage MCCs 220Vac 2ph

Fed from

battery-chargers

External power source for A&C control panels, remote I/O

panels and workstations 220Vdc 2p

Fed from

battery-chargers (4)

Subsea Master Control Stations (MCS) 220Vac 2ph Fed from UPS

Emergency Lighting 220Vdc 2p Fed from battery

chargers

Socket-outlets for accommodations, galleys and maintenance

rooms 127Vac 1ph (5)


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Navigation aid warning lights 125Vdc 2p

Motors of post lubrication pumps for gas compressors and main

generators 125Vdc 2p If necessary

Motors of emergency ventilation system of hoods of turbines 125Vdc 2p If necessary

Internal control circuits of switchgears and medium voltage

MCCs 220Vcc 2p

Fed from

battery-charger

Internal control circuits of low-voltage MCCs 120Vac 1ph Fed from

internal VT

Telecommunication equipment

220Vac 2ph,

48Vdc 2p or

24Vdc 2p

Gas and fire detection sensors 24Vdc 2p

A&C instruments 24Vdc 2p

Notes: 1) There are some loads (typically Package loads) with rated power

above 150kW, which rated voltage are 440V (motors) or 480V

(non-motors), due to PACKAGER standard;

2) There are some motors (typically Package motors) with rated

power above 355kW, which rated voltage are 440V, due to

PACKAGER standard;

3) Socket-outlets for A&C workstations shall be fed from UPS and

socket-outlets for general service shall be fed from normal lighting

panels or essential lighting panels, depending on their location;

4) Some A&C panels are not fed from battery-chargers;

5) This voltage shall not be allowed outside accommodation module.

Maintenance rooms shall have also socket-outlets in 220Vac.

6) Telecommunication equipment fed in 220Vac are fed by normal,

essential and emergency panels.

8.3.4. SHORT CIRCUIT LIMITS


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The acceptable shor-circuit limits are indicated on the table 8.3.4.1. Different shor-circuit

levels may be proposed by CONTRACTOR and submitted to Petrobras approval during bid

phase.

Table 8.3.4.1: Short-circuit limits.

Voltage Level

Calculated Thermal Equivalent

Short-Circuit Current (Ith) for

1s (1)

Calculated Peak Short-Circuit

Current (ip) (1)

13.8kV ≤50kA < 130kA

4.16kV ≤ 40kA < 104kA

440V,480V and

690V (CDC) ≤50kA (2) < 105kA

440V or 480V

(CCM) ≤18kA 52kA

220V or 240V

Switchboard (3) ≤ 15kA < 30kA

220V or 240V

Distribution Board (4)

≤ 9kA < 20kA

NOTES:

(1) As defined in IEC 60909;

(2) It shall be accepted the limit ≤65kA for switchgears connected directly or by back-

feed to Emergency or Auxiliary Generators, considering operational condition of

momentary parallel operation with Main Generation. For these cases the calculated

peak short-circuit current (ip) shall be limited to 143kA;

(3) 220V or 240V Switchboards are the panels directly connected to secondary winding

of transformers that feed the 220V system;

(4) 220V or 240V Distribution Boards are the panels connected to the 220V or 240V

Switchboards;


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(5) Limits for other rated voltages shall be agreed with PETROBRAS.

8.3.5 LOW VOLTAGE SYSTEM

Low voltage distribution system shall be divided into different groups and switchboards:

• Normal Process Plant loads;

• Normal Utilities/Ship Service loads;

• Essential loads.

If the low-voltage system has insulated neutral grounding, it shall be fitted with failure to

ground detection systems.

In the case of back-feed between low-voltage panels, there shall be no mismatch between

the low-insulation monitoring system of the different electrical panels.

The low insulation alarm shall be sent to the central control room (CCR).

It shall not be used minimum voltage coil circuit breakers in circuits essential or emergency

loads.

It shall only be used multifunction microprocessor protection relays (digital), with event

logging capabilities and oscillography.

It shall be provided means of protection against electric shock in wet areas (for example:

kitchen, laundry, cafeteria, etc.) with use of residual circuit breaker (DR) of 30 mA.

It shall be provided means of protection against electric shock in industrial areas power

sockets (aimed for the use of manual tools) with use of residual circuit breaker (DR) of 30

mA.

8.3.6. VDC SYSTEM

The VDC system shall comprise:

• Emergency Generator Starting and Control;

• Auxiliary (Essential) Generator Starting and Control

• Fire Water Pumps Starting and Control.

8.4. ELECTRICAL EQUIPMENTS


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All equipment shall have an IP protection according the local of installation and complying

with the requirements from Classification Society. Exception shall be consider to:

a) Emergency generator which shall be IP54.

b) Equipment located in ambience protected by deluge system which shall be IP 55.

Electrical equipment shall meet the requirements of IEC 61892-7.

For installations in hazardous areas, the requirements of IEC 61892-7 and relevant parts of

IEC 60079 are to be observed, according to the type of protection "Ex".

8.4.1 POWER TRANSFORMERS

Dry-type transformers specification shall meet IEC 60076-11.

Power transformers shall be dry-type moulded in epoxy resin or encapsulated with glass

fiber epoxy resin under vacuum, except for eletrostatic oil treater when oil cooled transformed

are accepted. The transformers shall comply IEC 60076 and the Fire Behaviour Class shall

be F1.

The use of transformers immersed in oil or silicon fluid shall be limited to electrostatic oil

separator. These transformers are an integral part of the "package" of the unit's oil treatment

system.

Each two-windings transformer (one secondary) or three-windings (two secondaries) shall

be dimensioned to feed 110% of the respective downstream switchboards load demand, with

no forced ventilation, on a contingency condition (“L” configuration with redundant

transformer out of service).

Power transformers shall be dimensioned without forced ventilation.

Transformers dedicated for LCI (line commutated) convertors shall comply with IEC 60146.

Transformers dedicated for other kind of non-linear loads shall comply with IEC 61378-1.

Transformers for both, linear and non-linear loads, shall comply with requirements of IEC

60076 12 and IEEE C57.110.

8.4.2 SWITCHGEAR, MOTOR CONTROL CENTER AND PANELS


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Medium Voltage Panels shall have classification for internal arc IAC AFLR (all faces with

category of restricted accessibility to authorized personal), according to IEC 62271-200.

Microprocessor-Based Multifunction Relays (MMRs) for Medium Voltage Panels shall be

multi-function, digital microprocessor-based type (based on microelectronics and integrated

circuits which has an analog-to-digital converter, a digital signal processor (DSP), software

and communication), and allow replacement of the software version through the

communication ports. The MMRs shall comply with the requirements of IEC 61850 and IEC

62439-3.

Switchgears shall be classified for providing personal protection under arcing conditions,

complying with at least criteria 1 to 5 of IEC TR 61641. The permissible current under arcing

condition (Ip arc) shall be equal to or greater than the rated short-time withstand current (Icw)

and the permissible arc duration (tarc) shall be at least 0.3s, during tests.

The voltage control circuits of Low voltage Motor control centers(CCM) and CCMs of

auxiliaries of Turbogenerators shall be designed in such way that a fail of one feeder of

voltage control or transitory under voltage will not provoke the lost of Main Generation

system.

Electric panels shall have the front and rear floor covered by insulating rubber matting

complying with ASTM D-178-01 requirements for Type II – ABC (ozone, fire and oil resistant)

and minimum Class 0 (tested for 5kV) for panels with rated voltage up to 690V and minimum

Class 1 (tested for 10kV) for panels with rated voltage above 690V.

Each cubicle with rear access shall have identification label affixed to backdoor equal to

frontal identification label. These labels shall be installed in fixed parts and shall be visible

when the doors are removed.

The position and direction of control movement and the corresponding expectation action

shall be according to IEC 60073 and IEC 60447.

Electrical switchgears/CDCs, MCCs, UPSs, battery chargers, VSDs, soft-starters,

transformers, distribution panels, electrical package unit power and control panels, field push

buttons for local operation, push buttons for other functions etc. shall have indication of the

NAME and the FUNCTION of the equipment, in addition to the alphanumeric TAG at each

outgoing/drawer.


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The protection relays for switchgear fed motor shall be overload electronic relays (IEDs). For

the switchgear fed non-motor loads, the circuit breaker incorporated protection relays (IEDs)

can be used. In any case, a communication link shall be provided and the short circuit

protection shall be done by the instantaneous unit of the trigger built into the circuit breaker.

The maximum incident energy which can be release from HV Panels, LV Panels, Lighting

Panels and UPS distribution Panels shall not exceed 8 cal/cm2, calculating according to IEEE

1584.

Spare drawers shall not have immediate use. However, they shall be supplied completely

mounted and wired, installed with all components in the Panels and ready for operation. At

least 10% of the total drawers shall be provided including one of them as equivalent of the

biggest drawer of the panel.

Basic criteria that shall be considered for the Electrical Protection Coordination and

Selectivity of the Switchgear and Motor Control Centers. These criterias shall be according

to IEEE Std 242.

In order to also provide voltage control for the essential Switchgear, a supply from the

emergency generator itself shall be provided by means of manual control.

The essential Switchgear shall also have voltage control powered by a redundant system. In

this way, any interruption of its functionality shall not occur if one of the voltage control

feeders fails.

The Essential Switchgear shall have this Voltage control fed by a redundant system in way

that no interruption of its funcionnatility will occur if one of the voltage control feeders fails.

It shall be possible to start the essential no motoric loads with no manual actuation from

operator, after the fail off the turbogenerators.

The feeders of essential loads shall not be disconnected after a fail of the Turbogenerators

and as consequence under voltage at Essential Switchgear.

The configuration back-to-back for Medium Voltage, Low Voltage CDCs and MCCs shall be

avoided. However, it shall be acceptable if the following requirements are complying with:

a) The manufacturer shall garantee that all maintenance will be done by frontal part of

the panel


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b) All electrical connection shall be monitored and protected by automatic temperature

sensors.

c) Means shall be provide to avoid arcing due to internal fault.

Appropriate protective measures against electric shock are required, especially for sockets

for tools and light fixtures with the use of protection based on residual differential type (DR)

circuit breaker.

8.4.3 ELECTRICAL MOTORS

The Induction Electric Motors shall comply with the applicable requirements from IEC 60034

and IEC 61892-3 and ANSI/NEMA MG1.

Insulation of motors shall have Thermal Class F (155°C), or Thermal Class higher than F,

with a maximum temperature rise at full load not exceeding the limit defined to Thermal Class

B (130°C), according to IEC 60085.

The protection of electrical motors shall comply with ANSI/IEEE C 37.96.

The vacuum impregnation method shall be used for winding insulation construction for

motors with rated voltage equal to, or higher than 6kV.

Motors with rated voltage equal to, or higher than 6kV shall be designed and manufactured

in such a way as to be approved in sealed winding spray-test, in accordance with the

procedures indicated on NEMA MG 1.

8.4.4 UNINTERRUPTIBLE POWER SUPPLY (UPS) AC AND DC

Both UPS AC and/or DC systems are allowed.

UPS shall be arranged and dimensioned to feed simultaneously all loads indicated in the

SAFETY GUIDELINES FOR OFFSHORE PRODUCTION UNITS – BOT / BOOT, IMO

MODU CODE, IEC 61892-2 and required by C.S., and corresponding autonomy time.

The Uninterruptible DC Power Supply shall meet IEC 60146-1-3, IEC 61892-3, IEC 62040-

2 and IEC 62040-3.


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Provision should be made for the periodic testing of the complete UPS and DC system.

Testing at regular intervals shall also cover load operation and battery discharge test, without

interrupting connected loads.

UPS log report shall be recordable, retrievable and available for PETROBRAS as requested,

providing comprehensive information on the equipment status and diagnostic information.

The Emergency Loads shall be fed in direct current, 220 VDC, through a system composed

of rectifier and battery Bank (UPS CC), redundant (2x100%).

The UPS systems shall be powered by the emergency switchgear and essential/auxiliary.

In the event of a normal power supply failure, the UPS shall keep the emergency loads

energized during the autonomy required time.

In cases of UPSs for separate systems, they shall be independent of each other, without

common mode of failure.

The equipment sets of the uninterrupted power system (UPS, Inverters, batteries and

distribution panels) when redundant shall be installed in separate rooms.

The output of the UPSs (DC) and inverters shall be isolated from ground, with detection of

ground fault on each bus and sending alarm to the CSS.

It shall not be used minimum voltage coil circuit breakers in UPS and battery chargers loads.

8.4.4.1. UPS FOR AUTOMATION/INSTRUMENTATION SYSTEM

Both UPS AC and/or DC systems are allowed.

The UPS system for Automation shall comprise two redundant units (2 x 100%), operating

isolated. Each UPS, if AC, shall be provided with dedicated by-pass transformer, with

automatic transfer through static switches.

Each UPS shall feed one distribution switchgear. The distribution switchgears shall have full

capacity interconnecting circuit breakers for transfer all connected loads to and from

redundant UPS, keeping the loads operating (without temporary black-out).

UPS output voltage shall be isolated from earth. Ground fault detection with local and remote

alarm at CCR shall be provided; means for troubleshooting and locating ground fault as

portable clamp meter should be provided without interrupting services.


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The AC and DC power supply for all components of the A&C Architecture shall be redundant,

fed from duplicated and redundant UPS. Common failure mode shall be avoided.

8.4.5. EMERGENCY LIGHTING SYSTEM

The emergency lighting system will be powered from UPS DC maintained by dedicated

batteries for this system.

The emergency lighting system shall consist of fluorescent lighting fixtures supplied by

220VDC system from UPS DC system.

The emergency Lighting system shall be redundant ( 2x100%). This system shall have two

battery chargers (CB) with the respective batteries. Each CB and batteries shall have

capacity to feed 100% of the load.

8.4.6. BATTERIES

Batteries shall be stationary-use type and constituted of vented lead-acid elements or

Alkaline . The lifespan for Alkaline batery shall be at least 20 years. For lead acid batery shall

be at least 10 years.

Lead-acid valve regulated batteries (VRLA) shall be installed in a room with a dedicated

HVAC system (maximum 25ºC). This HVAC system shall not be splited with other ambiance,

according to IEC 61892-6 and IEC 61892-7.

Alkaline (Nickel-Cadmium) batteries shall be designed so that during the expected 20-year

lifespan under normal operating conditions it will not be necessary to complete the electrolyte

level.

The installation of electrical and electronic equipment in the Batteries rooms should be

avoided. If this is not possible, for example in the case of luminaires, the classification of

areas of the environment shall be respected in order to define the appropriate type of

protection for the equipment.

8.4.7. GENERAL REQUIREMENTS FOR EQUIPMENT AND MATERIALS


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Cable trays for external areas shall be stainless steel AISI-316L or heavy-duty, non-metallic,

manufactured in composite material reinforced with fiberglass.

It is not permitted the use of the non-metallic cable trays in internal areas.

LED (Ex) luminaires can be adopted for external illumination.

A sufficient number of outlets shall be installed to allow the connection of temporary

containers, portable tools, and others, with the following voltages:

a) 480 VAC, three phase, 32 A, 4 poles (3P + E);

b) 220 VAC, single phase, 16 A, 3 Poles (2P + E).

The use of floor insulation mats in electrical panel rooms shall meet the requirements of

Solas 74, Norman-01 and the classification society.

8.5. LIGHTING

The lighting system of the Unit shall comply with requirements of IEC 61892 and with

regulations from Brazilian Economic Ministry (Ministério da Economia), Brazilian Navy

(Marinha Brasileira) and Diretoria de Portos e Costas (DPC) regulations and any mandatory

international regulations.

All outdoors lighting fixtures shall be directed to internal areas of the Unit, in order to not

impact marine life. Only specific lighting systems required by statutory and Brazilian

regulations shall be directed to sea areas.

8.6 ELECTRICAL STUDIES

Contractor shall present to PETROBRAS, whenever required, electrical studies, such as:

a) Main and Emergency Generation electrical load balance;

b) Checking of rated power of transformers;

c) Short-circuit calculation according to IEC 60909 to check the estimated fault levels,

and circuit-breakers making and breaking capacities. This study shall be carried out

for all foreseen operational condition, defining the most severe situation.


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d) Calculations of voltage drop due to the biggest motor starting. This study shall be

carried out using a calculation program that considers AVR response, generator load,

and shall use IEC or IEEE calculation procedures. It shall be done for All Switchgear

and MCCs;

e) Calculation of the voltage drop for starting the largest load motor in all essential buses

being fed only by the emergency generator and only by the auxiliary generator;

f) Calculation of the voltage drop for starting the strater motor of the first Turbogenerator

that will be put in operation, after blackout of the unit. In this case, being fed only by

the emergency generator and only by the auxiliary generator.

g) Stability study

h)Harmonic analysis calculation report;

i) Protection coordination and selectivity calculation report;

j) Arc fault incident energy calculation report;

k) UPS and battery bank sizing report;

l) Cable sizing report;

m) Grounding Fault Analysis.

Electrial Studies Notes:

• Voltage drop calculation report due to engine starting shall indicate the starting

condition (2TGs, 3 TGs in operation) and to define the conditions of pre-starting

loading and system voltage.

• The main generation system shall be able to start the largest 13.8 kV motor in the

conditions considered for operation in section 8.2.3;

• The selectivity and coordination protection calculation report shall set all parameters

required for calibration of the protection relays (according to model and manufacturer)

used in each electrical panel;

• Transformer energization minimum conditions shall be done considering 1 main

turbogenerator and 2 main turbogenerators in operation.

• In case of frequency converters use, it shall be developed harmonic distortion study.


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8.7. GENERAL OPERATION REQUIREMENT

Electrical equipment and systems shall operate satisfactorily under all environmental

conditions. It shall be considered for the installation: climatic variations, location of the unit,

and the maritime atmosphere. Relative variations to operational aspects and transitional

conditions shall be considered.

Electrical switchgears and panels shall be provided with resources that allow preventive

and predictive maintenance (online and offline) through monitoring and inside inspection,

without the need to stop operation. These panels shall be built-in with arc monitoring

devices.

The installation of electrical equipment in classified areas should be avoided.

9. EQUIPMENT

9.1. NOISE AND VIBRATION

CONTRACTOR shall conduct Noise and Vibration Study including process areas, marine

areas and accommodations to evaluate working environment and implement mitigating

measures whenever required.

9.1.1. NOISE

Noise limits shall be in accordance with the Brazilian Safety and Health at Work Regulations

(NR-15), Annex A of NORSOK S-002 – Working Environment, CS rules and guidelines

requirements for FPSO and / or MODU where applicable. Additionally, noise limits of living

quarters and closed areas shall comply with Annex A of NORSOK S-002 – Working

Environment

Equipment operating at high noise levels shall be accoustically treated using hoods,

silencers, filters or other noise control system to meet the requirements.

Noisy machines that need to use accoustic insulation shall have control panels and display

installed outside hood in order to have easy access during operation and maintenance

procedures.

After completion of services, if noise levels exceed the specified limits, CONTRACTOR may

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Such remedial measures can be, for example, the installation of AVMs (Anti-Vibration

Mounts), foundations for smaller equipment and additional insulation for limited areas.

9.1.2. VIBRATION

CONTRACTOR shall carry out structural and main equipment vibration measurements during

commissioning and sea trials in order to verify acceptable levels of vibration, according to NRs, CS

rules, and guidelines requirements for FPSO and / or MODU where applicable. Additionally,

acceptable levels of vibration for living quarters and closed areas shall be verified according to clause

8, table 3 of NORSOK S-002 - Working Environment.

.

CONTRACTOR shall rectify the stiffening of equipment and/or the equipment itself, if

vibrations are clearly in excess of the recommendations of the above mentioned standards.

9.2. HOISTING AND HANDLING SYSTEMS

CONTRACTOR shall submit to PETROBRAS for comments and information a detailed

procedure for equipment maintenance that should include their removal/disassembly from

any part of the Unit, as well as to allow the installation of a new one. The procedure shall

foresee facilities to allow offshore maintenance of the Unit, without affecting the

production/processing capacity. The handling procedure shall consider routine and non-

routine operations for maintenance and operation of the Unit.

The handling procedure should be thorough in relation to loads that should be supported on

the routes of movement, whereas the devices that will be used, and the resources which

may be allocated temporarily in smaller events. The handling procedure shall include the list

of equipment (or parts thereof) and other loads that need to be moved around, informing the

TAG, the amount, the location in the Unit, the weight and dimensions. Routes, including the

distance and the minimum height required to move the largest item of the module, and the

devices to be used for the movement of each load.

These routes of cargo handling should be represented in the unit/modules arrangement

drawings.

Special attention shall be given to provide the area necessary for hoisting, handling and

maintenance of the following equipment, but not limited to: electric motors, hydraulic variable


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speed drivers, gearboxes, gas turbines; gas compressors, pumps, engines, electric

generator rotors, WHRU tube bundles and gas coolers’ tube bundles of the main generators,

gas compressors, water injection pumps, fire fighting pumps, sea water lift pumps,

auxiliary/emergency generators and equipment that are composed by large pieces with

large weights. Means of transportation shall be forseen for each equipment, or parts thereof,

which will be maintened on board, from the place where they are installed to the workshops.

For equipment that will not receive maintenance on board, a dedicated means shall be

provided for its handling, or its parts, to the laydown area.

Laydown areas shall be protected by means of bumpers ( impact resistant).

A study of cargo handling of the UNIT shall be done considering at least, the following places,

but not limited to: machinery spaces, pump room and modules. Routes, including the

distance and the minimum height required to move the largest item of the module, and the

devices to be used for the movement of each load shall be detailed. The resources and

route alteration during handling shall be listed, also devices to be aquired for temporary

intervention.

These routes of cargo handling shall be represented in the unit/modules arrangement

drawings.

During design phase a specific handling study for machinery spaces and pump room shall

be issued considering equipment weight, dimensions and the load matrix.

Table 9.2.1: Requirements for cargo handling

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Hull

9.2.1. CRANES

All cranes shall be certified for “man-riding” by Classification Society, i.e., transportation of

personnel to/from the supply vessels and shall comply with requirements of NRs, and API

2C.

The equipment shall be designed, manufactured, tested and certified in accordance with API

SPEC 2C (latest edition). API2C monogram is acceptable.

Crane capacities shall be compatible with equipment parts to be removed/disassembled (e.g.

main generator rotor, heat exchanger tube bundles, diving equipment, etc.) and to transfer

Weight Range Daily / WeeklyYearly / Periodic /

OccasionalDaily / Weekly

Yearly / Periodic /

Occasional

W > 40t

1t < W < 40tfour wheels hand or self-

propelled truck

permanent handling structure an permanent

powered handling equipment

300Kg < W < 1t Four wheels hand truck

permanent/temporary handling structure and

powered/manual handling equipment

20Kg < W< 300kg

W < 20Kg two wheel hand truck manual transfer

MATRIX

Frequency

no transfer external barge crane facilities

no transfer

permanent handling structure and permanent

powered handling equipment

two wheel hand truckpermanent/temporary handling structure and

removable manual handling equipment

manual handling

Transfer Matrix Handling Matrix

Weight Range Handling Method

W < 25 kg Manual

25 < W < 300 kgManually driven mechanical devices (ex.: manual chain hoist with trolley; hand cart)

Preferably, motor driven mechanical devices (ex.: electric motor driven hoist with trolley; crane)Alternative: when the load is out of the reach of the nearest motor driven device, manually driven mechanical devices may be used (ex.: manual chain hoist) to bring the load to an area within the reach of the motor driven device.

W > 300 kg


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material/equipment to/from supply vessels to the Unit. Crane outreaches are measured

outboard from the Unit’s side shell.

In this option, as the risers shall come up on the Unit’s Starboard, this side shall not be used

for any supply boat operations. All cranes shall be located on the Portside side.

The Afterward (AFT) Portside crane shall be of knuckle boom type, or alternatively lattice

boom type, and built to operate under the following conditions:

• Loading/unloading minimum 25,000 kg from/to a supply vessel with an outreach able

to transshipping at a distance of 28 m from FPSO’s side. Maximum capacity shall be

defined based on handling study, but limited by Table 9.2.1: Requirements for cargo

handling) (40,000 kg). The significant wave height (Hs) shall be as defined in table

9.2.1.1.

• The whip hoisting system shall be able to lift 15,000 kg (minimum) with any boom

angle;

• Transportation of personnel to/from the supply vessels.

The Forward (FWD) Portside crane shall be located to pick up the heavier loads, mainly

those related to the risers pull-in operations and other special subsea operations. This crane

shall be designed and built to operate under the following conditions:

• Loading/unloading minimum 25,000 kg from/to a supply vessel with an outreach able

to transshipping at a distance of 28 m from FPSO’s side. Maximum capacity shall be

defined based on handling study, but limited by Table 9.2.1: Requirements for cargo

handling (40,000 kg). The significant wave height (Hs) shall as defined in table

9.2.1.1.

• The whip hoisting system shall be able to lift 15,000 kg (minimum) with any boom

angle;

• Transportation of personnel to/from the supply vessels.

The wind velocities shall be assumed according to the Standards and cannot be less than

18m/s (26m/s gust) for cranes in-service.


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Table 9.2.1.1: Significant Wave Height Specification

Hook Radius

Offboard Lift

Capacity

Significant Wave Height

Units

Main Hook 28m max 1.5 T / M

Main Hook 28m 15000 2.0 T / M

Auxiliary hook

max 15000 2.0 T / M

The unit shall have handling means to cargo transfer (limited to maximum capacity of

Afterward Portside Crane) from one laydown to another (AFT crane and FWD crane lay-

down areas) in order to avoid the usage of supply vessels.

CONTRACTOR shall provide means of transporting supplies/goods/spares from a lay-

down area to the galley store, machineries spaces, ware-houses, etc. (i.e., aft

spaces/compartments).

Note: All above mentioned capacities are net lift capacities. Vessel motions and dynamic

loads shall also be considered to properly design each crane.

In case of black out of main generation system electro-hydraulic cranes shall be able to

operate even with reduced speed either boom luff and load lifting restrictions. Therefore

without any restriction concerne load capacity. In this situations crane has to be driven via

emergency power pack unit.

Main cranes shall be electro-hydraulic or diesel-hydraulic driven. Cranes shall be of

mounted swing bearing lattice boom, king post lattice boom, telescopic box boom or fixed

length box boom type, as shown in API SPEC 2C Figure 1 - Crane Illustrations. The

auxiliary cranes shall be fixed pedestal mounted, provided with a cabin, and may be

equipped with a folding boom.

9.3. HEAT EXCHANGERS


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CONTRACTOR shall design heat exchangers and pressure protection systems according

to the ruptures scenarios as per API 521, especially where large pressure difference is

observed [e.g. 7000 kPa or more], where dynamic analysis are recommended in addition

to the steady state approach, and where the low pressure side is liquid-full and the high-

pressure side contains a gas or a fluid that flashes across the rupture.

All Heat exchanger mechanical design shall comply with ASME VIII div 1 or 2.

All Heat exchanger materials exposed to H2S shall comply with ISO 15156.

9.3.1 SHELL AND TUBE HEAT EXCHANGERS

Thermo & Hydraulic design of shell and tube heat exchanger shall comply with TEMA and

API 660.

Only seamless heat transfer tubes are acceptable for shell and tube heat exchanger.

Finned heat transfer tubes are not acceptable for any type of heat exchanger.

Shell & tube heat exchanger shall follow NR-13 regulations requirements.

9.3.2 PRINTED CIRCUIT HEAT EXCHANGERS

If CONTRACTOR decides to use PCHE (Printed Circuit Heat Exchanger) the

commissioning, operation and maintenance procedure shall be defined by PCHE vendor.

PCHE will only be accepted for gas coolers in gas compression systems and dewpoint

control system .

An integral T-type (or similar) strainer shall be supplied on the gas inlet. A separate Duplex

in line cleanable strainer with a side filtration of 10% of total cooling water shall be supplied

for the cooling medium side in order to remove eventual suspended solids. The filtration

efficiency and filtration grade shall be defined by CONTRACTOR during execution phase.

The strainer aperture for both cases shall be advised by manufacturer. The pressure drop

across the PCHE (core) and also the pressure drop across the strainers shall be individually

and remotely monitored for both streams.

The pressure of cooling water in the outlet of PCHE shall be higher than the vapor pressure

of water at maximum gas temperature in the inlet of exchanger.


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9.3.3 GASKET PLATE HEAT EXCHANGERS

Gasket Plate Heat Exchangers, if considered by Contractor, shall be designed as per API

STD 662 - Part 1. Equipment shall be designed as "severe service" per API 662. They shall

be able to stand dynamics pressure variations resulting from fluid flow and process control.

For cyclic services, fatigue design shall be in accordance with ASME BPVC Section VIII,

Division 2.

Presence of hydrocarbon shall be considered in order to specify the equipment.

In order to increase the stability of the set plates for hydrocarbon services, the titanium

plates shall have a minimum thickness of 0,8 mm. Plate heat exchangers design shall

consider the occurance of pressure transients during operation.

Gasket plate heat exchanger is not acceptable to gas heating or cooling aplications.

Gasket plate heat exchanger shall not be accepted for main production heater.

Sea water cooling water heat exchanger shall be gasket plate type, titanium plates.

Gasket plate heat exchanger design pressure shall be 20 bar(g) through design

temperature range.

The maximum design temperature shall be 150°C .

The maximum design temperature of plate heat exchanger shall consider the temperature

of the hottest fluid. Minimum design temperature shall be greater than metal minimum

design temperature.

Plates dimensions, height, width, thickness and chevron angles should contribute to

equipment stiffness. Maximum plate dimentions are 700 mm width and 2200 mm height in

reference to nozzles center lines.

Maximum amount of plates shall be less then 350 whenever designed to hydrocarbon

service. Otherwise up to 500 plates in case of cooling water service. In addition,

reinforcement plate shall be included at package to limit the number of contiguous plates

to 300 to provide mechanical stability..

The gasket heat exchanger shall be designed (structure, rods and brackets) in order to

allow at least 20% additional future expansion. If the total number of plates after the

augmentation exceeds the limit of 300 contiguous plates, an intermediate device shall be


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installed. Plate heat exchanger maintenance area shall have spare space to allow plate

removal.

Plate heat exchanger shall be designed to withstand pressure surges ( dynamic pressure

variations) due to process fluctuations.

For cyclic service endurance design life shall be in accordance with ASME BPVC Sec VIII

div 2.

Only U arrangement is acceptable (all fluid connections on the fixed plate), excepted when

specified by Petrobras.

9.3.4. HEAT EXCHANGER - INSTRUMENTATION

Heat exchangers shall be provided with instrumentation with remote sign in supervisory

system for inlet and outlet temperature and pressure indication, as well as differential

pressure (the required variable indication shall be available for both sides of heat exchanger

9.4 PROCESS PUMPS

Sealing system and piping arrangement per API 610 and API 682.

The hydrodinamic bearing lub system shall be according API 614.

Transfer pumps, offloading pumps, injection pumps, cooling water pumps, hot water services

and inline fire fighting pumps shall have proper surface on bearing housings to install portable

acceloremeters probes (machined plain surfaces). CONTRACTOR shall provide minimum

flow control for these pumps. Means shall be provided, such as a bulls-eye or an overfill plug,

for detecting overfilling of the bearing housings. A permanent indication of the proper oil level

shall be accurately located and clearly marked on the outside of the bearing housing with

permanent metal tags, marks inscribed in the castings, or other durable means.

All centrifugal process pumps shall be designed, tested and fabricated in accordance with

API 610.

For SRU feed pump, booster pumps and water injection pumps minimum continuous flow

valve bypass, whenever operational condition is out of preferred pump flow range, shall be

provided and properly sized in order to avoid valve cavitation damage, due to expected high

differential pressure service.


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9.4.1 WATER INJECTION PUMPS

The main water injection pumps and booster water injection pumps shall comply with API

610. Pump drivers may be electric motors, or gas turbines from the vendor list.

The main water injection pump shall be monitored, at least, for vibration, axial displacement,

bearing and motor temperature. All monitored data shall also be available for PI Software, in

order to Contractor monitor the system performance and to prevent failure.

Machinery protection system for main water injection pumps and booster water injection

pumps shall be in accordance with API 670.

For high energy pumps, per API 610, Forced Lubrication system shall be according to API

614.

9.4.2 WELL SERVICE PUMPS

The well service pumps for high flow rate operations shall be positive displacement type

according to API 674 including acoustic studies (acceleration head and suction head).

Structural vibration also has to be checked. Pump drivers shall be electric motor with variable

speed driver.

The well service pumps for low flow rate operations shall be controlled by set up pressure

on demand ( on/ off signal) accordingly. These pumps shall be either designed per API 674.

9.4.3 PRODUCED WATER PUMPS

Produced water pumps shall be either hydraulic submerged type or deep well pump driven

by electrical drives on main deck. Pumps shall be designed to be fitted in bottom of produced

water tanks for water removal and to route solid removal.

Produced water pumps shall be provided with variable flow, taking into account the expected

produced water forecast and shall be dimensioned to keep oil water surface within an

acceptable level range, during the whole field production life.

Produced water pump operation shall be automatic in order to control levels and oil water

interface at acceptable range.


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9.5 METERING PUMPS

Metering pumps (chemical injection pumps) shall comply with API 675.

9.6 UTILITIES PUMPS

Utilities pumps shall comply with either ASME ANSI 73.1 (150#) or API 610.

9.7 HEAVY HYDROCARBON RICH STREAM PUMPS

Heavy Hydrocarbon Rich Stream Pumps shall be positive displacement type according to

API 674 including accoustic studies (acceleration head and suction head). Structural

vibration also has to be checked. Pump drivers shall be electric motor with variable speed

driver. Forced Lubrication system shall be adopted according to API 614, as mandatory.


9.8 ROTARY PUMPS

Rotary pumps shall comply with API 676.

9.9 FIRE WATER PUMPS

Fire water pumping units shall be designed in accordance with NFPA 20.

Fire water pumping units shall be equiped with proper instruments for performance curve

evaluation (ISO2548GrII- operation point of fire water pump).

Cardan type coupling shall not be acceptable for booster pumps. Flexible type couplings shal

be specified per ISO 14691.

If the pumps are installed in seachests a minimum continuous flow valve bypass shall be

provided.

9.10 PRESSURE VESSELS

Every pressure vessel shall comply with regulatory requirements NR-13.


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Metallic pressure vessels shall be designed in accordance with ASME BPVC Sec VIII.

FRP ( fiber reinforced plastic) vessels shall be designed in accordance with ASME BPVC

Sec X.

9.11 DIESEL ENGINES

Maximum speed of diesel engines shall be 1800 rpm.

9.12 SEA WATER LIFT PUMPS

1. Pumps with submersible electrical motors shall comply with the following requirements:

a) mechanical seals shall be cartridge type;

b) it shall be foreseen means as starting equipment to minimize water hammer effects;

c) anticorrosive protections, as coatings and sacrifice anodes, shall be provided, where

applicable, for submersible lift pumps, ensuring minimum operational availability of 5 years.

2. Pumps with submersible electrical motors (except those with energy/fluid conductors

integrated system (without external cables), shall comply with the following requirements:

a) cable shall be provided with suitable supports at pump column;

b) sealing lines/ return lines and external electrical/instrumentation cables shall be placed

next to buffers internal diameters. Sealing lines/ return lines shall be rigid tubings until top

plate; Flexible lines are not permitted.


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10. TELECOMMUNICATIONS

The Unit’s telecommunications shall comply with the TELECOMMUNICATIONS document

(see 1.2.1).

11. STRUCTURE AND NAVAL DESIGN

Hull Assessment, Motion Analysis and Mooring Design shall not be performed by the CS that

will classify and certify the design, follow the construction or conversion and operation of the

Unit.

All FEM structural models (global and local) shall be provided to PETROBRAS together with

the respective calculation report, in at least two moments: at the end of the construction (as

built) and at the delivery of the unit to PETROBRAS (considering all model updates). Models

shall be in electronic format, considering all the necessary inputs for the analysis (including

geometry, loads, boundary conditions, properties, materials, mesh, etc).

11.1. LOAD REQUIREMENTS

Besides the CS load requirements for the operation of the Unit at the site, CONTRACTOR

shall also design the Unit to withstand all construction loads and the environmental loads

during transportation from construction/conversion shipyard to Brazil and, after the

decommissioning, from Brazil to a site outside its territory.

11.1.1 – MINIMUM LOADS

CONTRACTOR shall consider, for the deck areas structural dimensioning, the variable

functional loads based on the values proposed in the table herein after as the Petrobras

minimum requirements.

Dead weight is not included in the table herein after and has to be added to variable loads

specified in the table for structural analyses purposes.

Table 11.1.1 – Variable functional loads on deck areas

Area Local design Primary

design

Global

design


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distribute

d load

(kN/m²)

poin

t

load

(kN)

(2)

distribute

d load

(kN/m²)

distribute

d load

(kN/m²)

Storage Q=max(γ x

H;13) 1,5q Q q

Lay-down 40 40 30 30

Lifeboat

platform 9 9 9

may be

ignored

Between

equipment 5 5 5

may be

ignored

Walkways,

staircases and

Platforms

4 4 4 may be

ignored

Walkways and

staircases for

inspection only

and scape

routes

3 3 3 may be

ignored

Process (1)(4) 9 9 may be

ignored

may be

ignored

Utilities (1)(4) 7,5 7,5 may be

ignored

may be

ignored

Accommodatio

n 4 4 4

may be

ignored

Diving

equipment 25 25 15 15

Store room,

workshop 15 15 15

may be

ignored

Helideck 2 P (3) 2 may be

ignored


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Roofs 2,5 2,5 2,5 may be

ignored

Upper bridge

deck 5,0 5,0 5,0 2,5

The following notations are used:

• Local design: design of plates, stiffeners, secondary beams and brackets;

• Primary design: design of deck girders and columns, deck module girders not

included on trusses;

• Global design: design of main structure: hull, jacket and foundations, deck module

trusses, module;

• supports (bases, stools).

Notes:

γ = specific weight of storage material; H = storage height;

(1) For equipment loads, the worst case between the table above or the equipment weight

plus structural dead weight and plus 5 kN/m2 applied over a free surrounding area shall

be considered. See figure 11.1.1.

(2) Point loads may be applied on an area 100 x 100 mm, and at the most severe position,

but not added to wheel loads or distributed loads;

(3) “P” is the helicopter maximum take-off weight and has to be considered on the

helideck structural analysis. For helicopter specification see item 1.2.2;

(4) Process overload refers to the workload on the platforms and modules in the UEP

process plant region. The utilities overload refers to the workload in the regions of the

UEP outside the process plant region such as engine room, area between

accommodation module, utilities room, etc.


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Figure 11.1.1 – Example of applying overload between equipment

11.1.2. LOAD PLAN

CONTRACTOR shall prepare the load plan containing information of loading capacity on all

cargo areas presented on table 11.1.1 (Variable functional loads on deck areas).

The drawings for all structural levels, with an indication of the allowable loadings, will take

part of the load plan. Total and local loading capacities, for laydown areas, should be

indicated on the floor and also on the bumper structure.

11.2. CONVERSION SURVEY (IF APPLICABLE)

The hull shall be fully inspected according to CS requirements. The Unit must maintain

continuous offshore operation during its operational lifetime with no dry-docking. All

damaged areas, including cracks of any nature, and all defective structural element/part,


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including welds and all warped areas, shall be replaced or restored to fit conversion

specifications per CS requirements.

The Unit shall be surveyed prior to the installation of any new structure. The survey report

shall inform all items that do not match the original design. Special attention shall be paid to

the following items:

• Structure - girders, beams, stiffeners and plates - dimensions;

• Out of tolerance imperfections of structural elements;

• Changes in the material specifications;

• Corrosion of structural elements.

Hull areas with defect history or which during the former and/or future operational life were

and/or will be overstressed, based on the hull structural reassessment, must be extensively

NDT inspected. This also applies to areas with critical fatigue predicted life that may have its

design modified to the satisfaction of the CS in order to meet the survey requirements of a

new Unit.

Ships that have been involved in explosion, grounding damage, lay-up and/or collision

relevant incident during their operational life since the last class survey shall not be utilized

for conversion.

However, further inspections (to be made by a third party) may be required by Petrobras

during the engineering design phase, as part of the Survey Report.

The hull assessment shall be submitted to a third party for reviewing and validation. This

third party shall be a CS, other than the one that is classing the Unit, or a recognized

consultant previously approved by PETROBRAS.

11.2.1 PLATE REPLACEMENT CRITERIA

The design philosophy shall take into consideration that no hot work should be done due to

plating/structural replacement during the Unit’s operational lifetime.

Specification of hull steel renewal at conversion is based on the requirement that no part of

the hull will fall under substantial corrosion during the operational life.


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Hull steel renewal shall take into account both local corrosion (pitting and grooving) and

overall corrosion.

For overall corrosion of plating and stiffeners, renewal thickness at conversion is defined

such that the substantial corrosion margin will not be reached within the FPSO life, taking

into account anticipated corrosion losses during the FPSO life. The substantial corrosion

margin is defined as 75% of the allowable corrosion margin as specified in the inspection

criteria of the rules.

When re-assessment is performed, the FPSO required gross thickness (TR) is defined as

required thickness for use as FPSO without reduction for corrosion, based on the

environmental site specific design parameters, even in the case that the re-assesssed

thickness is lower than the original “as-built” thickness.

Both ultrasonic gauging report and the reassessment study shall be submitted to CS for

approval and PETROBRAS for information.

As a minimum, the following procedure shall be adopted to determine the steel renewal

thickness at conversion:

Tmeasured < TR * (1 – 0.75 * RL) + M25 Element must be renewed

Tmeasured – Structural element thickness – based on the Thickness Reading Report

M25 – 25 years corrosion margin for uncoated steel.

TR – rule required gross thickness – to be defined by the Reassessment Study.

RL – rule allowed corrosion percentage according to Classification Society rules

The following table shows the corrosion margin values (M25) to be used for 25 years of

operation for different uncoated structural elements where γ = 1,0 (20,0 years/ 20,0 years) is

the correction factor for the corrosion margin.

Table 11.2.1.1: Corrosion margin values.

LOCATION ITEM

CORROSION MARGIN (mm)

Cargo Tank Ballast

Tank


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LONGITUDINAL

ELEMENTS

Deck plating 3.0 x γ 3.0 x γ

Deck longitudinals 2.0 x γ 2.5 x γ

Side shell plating 3.0 x γ 3.0 x γ

Side shell longitudinals 2.5 x γ 2.5 x γ

Longitudinal bulkheads

plating

3.0 x γ 3.0 x γ

Longitudinal bulkheads

longitudinals

3.0 x γ 3.0 x γ

Bottom shell plating 3.0 x γ 3.0 x γ

Bottom shell longitudinals 2.0 x γ 2.0 x γ (1)

TRANSVERSE

WEB FRAMES

Deck transverse web plating 2.5 x γ 2.5 x γ

Bottom transverse web

plating

2.0 x γ 2.0 x γ

Side shell transverse web

plating

2.5 x γ 2.5 x γ

Long. bhd. transverse web

plating

2.5 x γ 2.5 x γ

TRANSVERSE

BULKHEADS

Plating 2.5 x γ 2.5 x γ (1)

Vertical stiffener (web) 2.0 x γ 2.0 x γ

Horizontal stringer web

plating

3.0 x γ 3.0 x γ

Vertical girder plating 2.5 x γ 2.5 x γ

SWASH

BULKHEADS

Web plating 2.5 x γ 2.5 x γ

Horizontal stringer web

plating

3.0 x γ 3.0 x γ

Vertical girder plating 2.0 x γ 2.0 x γ

(1) For the slop tank elements the same corrosion margins of the ballast tank shall be

considered except for bottom shell longitudinals (2.5 x γ mm) and for plating (3.0 x γ mm).

(2) For void spaces shall be consider 1.5 x γ mm of corrosion margin for all items.


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By means of coating, the start of corrosion will be postponed. Therefore, a corrosion

postponement can be considered, if CONTRACTOR ensures application of high quality

epoxy painting scheme with guarantee not lesser than 10 years. As so, the corrosion

margins given in the table above can be de-rated, due to the referred corrosion

postponement effect, for structural elements that are fully painted with the high quality

performance epoxy scheme. The reduction on the required corrosion margins in case of

coated steel structural elements can be 5 years/25,0 years (20% reduction) on the corrosion

margins given in the table above.

For pitting inspection/acceptance bottom plating shall be fully inspected after being sand

blasted. The following plating renewal criteria shall be considered:

Figure 11.2.1.1: Plating renewal criteria.

1 - If in the inspected region d < 0,15 . TR Plate to be treated and painted

2 - If in the inspected region 0,15 . TR < d < TR /3 See note below

3 - If in the inspected region d > TR /3 Plate to be renewed

NOTE:

Additional criteria to be considered for those regions related to item 2 above:

• If pd > 200 mm plate renewing

• If pd ≤ 200 mm and either:

o dbp < 75 mm plate renewing

o dbp ≥ 75 mm and cpfd ≤ 80 mm plate renewing


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o dbp ≥ 75 mm and cpfd > 80 mm and tr < (6 mm or TR/3) plate

renewing

where : pd - pitting diameter

dbp - distance between pittings

cpfd - continuous pitting weld filling distance

tr - residual plate thickness below pitting

to - original plate thickness

Remark: Cpfd is the minimum continuous weld bead necessary to fill up a pit.

11.3. MATERIALS

All materials used for the Unit shall meet the specifications of CS latest revision requirements

for construction of a FPSO. Topsides materials shall also comply with the specifications of

item 1.11. CONTRACTOR shall submit to PETROBRAS for comments and information the

design philosophy to specify materials to be used with each type of fluid and the corrosion

allowance and protection considered. These choices shall be compatible with the specified

operational lifetime defined in item 1.1.

To prevent the lamellar tearing effect, steel with Z quality (strength through the thickness)

shall be used in places where plate stress occurs in the transversal direction, such as fairlead

connections, riser balcony connections, crane pedestal connection, etc. Special details may

be adopted to avoid stress in the transversal direction of steel plate.

11.4. WEIGHT CONTROL PROCEDURES

It is CONTRACTOR’s responsibility to evaluate the Unit’s weight and Center of Gravity during

the design, installation and operation phases, according to the design and CS requirements.

11.5. STABILITY ANALYSIS


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The Unit shall comply with the latest CS - Rules for Building and Classing Mobile Offshore

Drilling Units and correlated rules, MARPOL Annex I and the MODU Code, regarding intact

and damage stability.

Intact and damage stability analysis shall be performed for at least five loading conditions:

minimum loaded, 40% loaded, 60% loaded, 80% loaded and fully loaded.

For wind heeling levers, in intact stability, the 100-year return period, 1-minute sustained

wind shall be considered.

The distribution of weights and vertical reactions imposed by the spread mooring and riser

system on the Unit shall be calculated for the purpose of evaluating trim and stability

conditions

Wind forces and moments can be estimated according to the following criteria and shall be

submitted to CS for approval and PETROBRAS for information:

• Process plant equipment and deck, flare boom, cranes, helideck, etc. - According to

CS methodology for wind forces and moments calculation.

11.6. HULL

The FPSO hull shall comply with the following requirements:

a. Conversions from oil tankers - Double-Hull or Double Side type

b. New building based in oil tanker design – Double-Hull type

c. Newbuilding barge type or other types– Double-Side or Double-Hull type

Only second hand tankers with life up to 10 years old (considering keel laying), designed

and built in accordance to IACS Common Structure Rules (with class notation CSR), and

with Hull Condition Assessment Program (HCAP) with grades 1 or 2 will be accepted by

PETROBRAS as possible of conversion.

The existing bilge keels, if any, shall be enlarged in order to improve roll motion. If such

structural elements are not present, appropriate bilge keels shall be installed.

In lieu of a risk analysis and/or a drifting analysis that defines the scenarios for vessel

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withstand an impact energy (collision accidental load) imposed by a 9,000-MT displacement

supply vessel, plus added mass, with speed of 2 m/s, for the worst cases of sideways, bow

and stern impact scenarios, without causing the rupture of FPSOs cargo tank longitudinal

bulkhead and without compromising the global structure.

Side shell structure shall also be designed at the same area to withstand an impact energy

imposed by the same 9,000-MT displacement supply vessel, plus added mass, at 0.5 m/s

for the worst cases of sideways, bow and stern impact scenarios, associated with normal

operation conditions, without any rupture to the side shell structure.

Criteria and methodology shall follow NORSOK N-003 and NORSOK N-004,

The referred area shall have elastomeric fenders fixed to side shell by steel beams, in order

to prevent contact between supply boat and the Unit and to help side shell structure to absorb

the collision energy for normal operation conditions of supply vessel, for which fenders and

fender back structures shall be spaced and dimensioned. Floating fenders are not allowed.

This solution can be adopted at ballast tanks or void spaces areas.

The longitudinal extent area of side shell to be protected shall be 30 m aft from the crane

and 30 m forward. The vertical extent of the protection shall cover the entire length

considering the variation between the maximum and minimum draft of the unit, taking into

account an additional length of 3 meters above the maximum operation draft and 1.5 meters

below the minimum operation draft of the FPSO.

Other external equipment/structures/piping (e.g. caissons for seawater uptake) connected to

side shell at the supply vessel approaching area shall be protected by specific structures,

plus elastomeric fenders, using same premises.

To complement gravitational separation in the slop tanks, the Unit shall have a separate

water treatment system in order to treat the oily water prior to discharge. Water discharge

from slop tanks shall be measured and monitored for TOG.

11.6.1. TURRET AND CARGO TANK INTERFACE (NOT APPLICABLE)

Not applicable.

11.6.2. RISER BALCONY AND HULL INTERFACE (SPREAD MOORING OPTION)


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If any existing tank is used to place the balcony structure, it shall be modified in accordance

to the balcony installation requirements and shall be cleaned, painted and maintained as a

void space or segregated ballast tank.

CONTRACTOR shall perform a finite element analysis, at the balcony/hull interface region,

in order to achieve an adequate load transfer path and to verify structural strength and fatigue

life. This analysis shall be submitted to CS for approval.

Means/barriers for oil containment must be considered at the main deck and the upper riser

balcony (perimeter) in order to prevent oil or oily water spill on the sea.

11.6.3 TOPSIDE STRUCTURES

Green Water occurrence and effects on topside structures of FPSO shall be checked.

When impact loads on hull as those identified in item 11.6.4 are significant and may affect

the dynamic response of a topside structure, then its natural frequencies should be kept

away from hull girder natural frequencies a minimum of 20% difference for full range of

operational drafts (light load up to full load conditions) and in transit condition, in order to

avoid large dynamic amplification. CONTRACTOR shall perform integrated analyses for

most susceptible structures, that is, slender structures and other potentially affected

structures, e.g. hull/flare tower model (including dynamic effects), to evaluate the flare

tower integrity under dynamic hull deflections, for both strength and fatigue, similarly for

the other structures.

When, otherwise, those impact loads are not significant for these structures, then the

difference between their natural frequencies and those of hull girder should still be a

minimum of around 10%.

Fairlead support structures, riser balconies, aft hull structures and other attached structures

subject to wave slamming loads shall be analyzed considering the probability of occurrence

and the corresponding load. Significance of effects on onboard comfort and on hull girder

stresses are also to be addressed.


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Sufficiently inclined flat plates at the bottom of each of these structures shall be employed in

order to minimize wave slamming, and, in consequence, whipping hull girder effects.

Slamming loads can be calculated considering CFD softwares or as described in DNV-RP-

C205 – “Environmental Conditions and Environmental Loads”.

Fatigue calculations shall also include the slamming loads with the corresponding probability

of occurrence.

11.6.4. CATHODIC PROTECTION AND PAINTING

The cathodic protection system, painting specification and corrosion protection shall be part

of the philosophy to allow the Unit to operate continuously during its operational lifetime

without any production interruption. Therefore, design shall clearly identify those

requirements. The painting specification shall be in accordance with requirements of Coating

philosophy (I-ET-3010.00-1200-956-P4X-004).

Galvanic anode CP system shall be used for internal tanks and dimensioned for the whole

operational life. Fresh water tanks shall have a different solution in order to avoid water

contamination.

For external hull, impressed current cathodic protection systems is required. The potential

control (manual and automatic) shall comply with DNVGL-RP-B101. Submerged defective

parts replacement shall be feasible via diver operation. Additionally, galvanic anode for

limited areas of external hull with complex geometry may be acceptable under Petrobras

approval.

Special attention shall be given to chain pipes and other similar underwater structures to

allow maintenance, inspection and replacement with no dry-docking/shutdown and to avoid

problems caused by corrosion and marine growth.

Zinc anodes shall be adopted if the “anode installation height X anode gross weight” is

greater than 28 kgf x m and the maximum operation temperature is less or equal to 50ºC.

Cargo and any other oil or water oil mixtures tanks in cargo area shall be provided with

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Produced Water Tanks and Slop Tanks, shall be entirely painted with a high performance

epoxy scheme considering design life, as stated in Section 1.1. Anodes shall protect all tank

internal surface.

CONTRACTOR shall provide an anti-fouling painting scheme for the external hull,

encompassing bottom plate and side shell plate up to transit draft (maximum foreseen draft

during transit phase from conversion yard to Brazil). The anti-fouling painting scheme shall

follow NORMAM 23 requirements and IMO Resolution MEPC.207(62) - Guidelines for the

Control and Management of Ships’ Biofouling to Minimize the Transfer of Invasive Aquatic

Species requirements.

11.6.5. CARGO AND BALLAST TANKS STRUCTURAL INSPECTION

All cargo/ballast/slop tanks access arrangements shall comply with IMO Recommendations

A 272 (VIII) and A 330 (IX).

CONTRACTOR shall submit to PETROBRAS and CS an inspection plan of the cargo, ballast

tanks or any other structural compartments evidencing that the Unit enables safe inspection

inside all tanks. This plan shall be based on the Fatigue Analysis and shall consider the

continuous operation during operational lifetime with no dry-docking and shall not affect the

production capacity of the Unit.

Means shall be provided to allow a safe “free-for-fire” certificate with minimum disturbance

of the Unit’s operation. In addition, cargo piping shall be installed with devices to reduce the

risk of any accidents during inspection and “hot” services (e.g.: devices to avoid valves or

expansion joints leakage).

11.6.6. HULL EXTERNAL INSPECTION

CONTRACTOR shall provide facilities for the installation of diving support equipment and for

the diving operation itself (handrail, eye lugs, etc), consideringthat the entire hull must be

visually inspected, as required by CS, twice every 5 (five) years.

11.7. FATIGUE ASSESSMENT REQUIREMENTS

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The fatigue analysis shall be submitted to a third party for reviewing and validation. This third

party shall be a CS, other than the one that is classifying the Unit, or a recognized consultant

previously approved by PETROBRAS.

Fatigue Damage calculation for the support structures, foundations, etc., shall be carried out

in accordance with the CS rules and requirements.

CONTRACTOR shall use the current profiles for fatigue analysis given in the METOCEAN

DATA document (see 1.2.1), as mentioned in Section 12.

Design Fatigue Factors (DFF) presented on Table 11.7.1 to 11.7.3 are PETROBRAS

minimum requirements. Structure shall be designed considered DFF presented.

Table 11.7.1 – Minimum Design Fatigue Factors (DFF): General

Position

Classification of

structural

components based

on the

consequence of

failure

Accessibility for inspection and repair

Accessible Not

accessible (3)

Above the

minimum

operating draft

Below the

minimum

operating draft

Hull High 3 5 10

Low 2(1) 3(2) 5

Topside High 2 - 10

Low 1 - 5

(1) DFF = 1 External structure, accessible for periodic inspection and repair in dry and clean conditions;

(2) DFF = 2 Internal structure, accessible and not welded directly to the submerged part (applicable only to

ballast tanks and void spaces);

(3) Includes areas that can be inspected under dry or submerged conditions, but requires dry docking for

repair;

Table 11.7.2 – Minimum Design Fatigue Factors (DFF): Hull structures


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Structural components (except for joints not accessible) DFF

Hull:

Side shell and Main Deck – Plates and stiffeners above

minimum draft

2.0

Side shell and Bottom – Plates and stiffeners below minimum

draft, including double bottom

3.0

Bulkheads – Plates and stiffeners 2.0

Frames and Girders 2.0

Equipments Foundations, Riser Balcony Foundations e

Mooring Support Foundations

3.0

Stools and Topside Support Structure Foundations, including

pipping supports

2.0

Structure inside tanks (except for locations where higher

factors are required)

2.0

Hull appendix:

Mooring Balcony and Fairlead structures (above / below

minimum draft)

3.0/5.0

Bilge Keel 5.0

Lower Riser Balcony and support 10.0

Upper Riser Balcony and support 5.0

Stools and Topside Support Structure 2.0

Crane pedestal and foundations 2.0

Flare Tower and connection with the Hull 2.0

Pipping support 1.0


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Pull-in structure 1.0

Offloading hose support (above minimum draft) 1.0

Casings and caissons supports (e.g. for seawater captation) 2.0

Elements in secondary project areas except those defined

above

1.0

Non-critical elements in splash zone (considered non-

inspectable)

5.0

Table 11.7.3 – Minimum Design Fatigue Factors (DFF): Topside structures

Structural components (except for joints not accessible) DFF

Nodes of secondary structure 1.0

Nodes of main structure 2.0

Topside connection / module vs hull 2.0

Topside connection / module vs hull (not-inspectable parts) 10.0

11.8. MOTION ANALYSIS

11.8.1. GENERAL

Motion analysis results, regarding motions and accelerations, shall be used for the analysis

of the following items:

• Process plant structural design;

• Fairlead and riser support structure/hull interface design (Spread-Mooring);

• Flare boom / tower structural design;


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• Helideck structural design;

• Crane foundation structural design;

• Equipment operational limit assessment;

• Offloading operational limit assessment;

• Pull-in / out operational limit assessment.

11.8.2. RAO – RESPONSE AMPLITUDE OPERATOR

CONTRACTOR shall issue to PETROBRAS the RAO (Response Amplitude Operator)

curves and tables with their corresponding amplitude and phase angles, for the Unit’s 6 (six)

degrees of freedom.

The RAOs shall be informed with the motions natural periods and linear equivalent viscous

damping considered. The viscous damping coefficients shall be submitted to PETROBRAS

for comments / information. Model tests shall be used to validate the CONTRACTOR

proposal.

The RAOs shall be computed considering linear roll damping varying according to the

significant wave height level:

1) Hs < 2.5m (irregular waves contour curves).

2) 2.5 < Hs < 4 (irregular waves contour curves).

3) Hs > 4 (irregular waves contour curves).

RAOs shall be computed also considering the following:

• At least five loading conditions: minimum loaded, 40% loaded, 60% loaded, 80%

loaded and fully loaded. The roll viscous damping shall be derived for each draught.

If applicable, the percentage of time associated with these drafts shall be 5%

(minimum draft), 25%, 40%, 25% and 5% (maximum draft).

• The mooring lines and risers shall be considered only as vertical load items to

compose the loading condition and no dynamic effect shall be included in the RAO

analysis.

• Excitation frequencies ranging from 0,2 to 3,0 rad/sec.


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• The number of calculated frequency components shall be at least 60.

• Around the peaks presented in the Roll and Heave RAOs, the frequency discretization

shall correspond to a 0,1s period interval.

• Wave incidences ranging from 0 up to 360 degrees with 7,5 degrees increments,

being 0 degree value the “aft”, 90 degrees value the “starboard”, 180 degrees the

“bow”.

• These curves and tables shall be referred to the C.O.G. (Center of Gravity of the Unit).

Thus, the C.O.G shall be informed with the RAOs .

• The waves considered for the roll damping estimation shall be the beam sea condition

(irregular waves) that causes the higher motions (higher Hs or wave peak period: Tp

equal to the natural period of the roll motion for each specific draft). All roll damping

estimation shall be done with no current.

The reference system and direction conventions shall be included in the report. The

expression that needs to be employed to generate motion time series shall be also published

by CONTRACTOR.

The RAOs will be used in analyses of stresses acting on the risers, mooring lines and

secondary structures.

Numerical output data (RAO, added mass coeficients, potential damping coeficients, wave

exciting forces and quadratic transfer functions, including for roll motions if the roll natural

period calculated in the model tests is greater than 17 seconds as described in 11.8.3) shall

be released in Microsoft Excel file by CONTRACTOR. The RAO shall be released to

PETROBRAS 9 months after kick-off.

11.8.3. MODEL TESTS

Sea-Keeping model tests (FPSO motions) are required during the engineering design phase.

In order to verify the predicted FPSO motions, the roll viscous damping level in the presence

of the bilge keel, green water, slamming (occurrence and mitigation options) and induced

loads, CONTRACTOR shall submit the model test matrix to PETROBRAS approval and

carry out the model test program based on that.


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For FPSOs with roll natural periods above 17 seconds, considering all operational drafts,

second order effects for rolling motions must be addressed in the model test scope.

Actual dimensions shall not be reduced by a factor greater than one hundred (100), in order

to obtain adequate model dimensions.

11.8.4. VERTICAL LIMITATION FOR RISERS

The FPSO shall have a limited vertical motion, in order to allow the safe operation of the

risers that will be connected to it. A bilge-keel shall be designed and installed in order to keep

a limited roll motion, which contributes to the vertical motion at the riser top connections,

below the herein established limits.

The vertical motion is conceived to be shown by the short term response of the FPSO under

a specific wave condition.

The requirement shall be demonstrated by the CONTRACTOR through calculations

including the wave data and the calibrated RAO tables and curves, considering the FPSO at

the free floating condition (with no lines in terms of stiffness and damping).

The maximum ship motion for any riser support point location, considering all the 100yr wave

Hs-Tp pairs in 16 directions, contained in reference document Metocean Data document

(see 1.2.1), shall not exceed the following values:

• Most probable maximum vertical motion single amplitude: 8 m;

• Most probable maximum vertical acceleration single amplitude: 1,8 m/s².

11.9. PASSIVE FIRE PROTECTION

The use of passive fire protection on structural elements of manned platforms shall be

applied at all points subject to fire scenarios that affect the integrity of the structure and critical

safety functions. The fire and explosion scenarios that will be used as input data in the

passive fire protection design of the structure and fire break bulkheads are identified in the

Fire Propagation Study and Explosion Study.

Structural analysis should be performed considering the loads acting for the accidental

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These analyzes should contemplate physical and geometrical non-linearity and the thermal-

structural coupling, capturing the redistributions of tension caused by the change of the

properties of the material according to the temperature.

The methodology for the fire-structure analysis used in design of the passive fire protection

of structural members is present I-ET-3010.00-1300-140-P4X-003 (Fire Structure Analysis

for Passive Fire Protecton Design) which is attached to I-ET-3010.00-5400-947-P4X-011

(Safety Guidelines for Offshore Production Units – BOT/BOOT).

Drawings shall be developed to reflect the passive fire protections to attend the structural

and safety criteria.

12. OPERATIONAL CONDITIONS

The Unit shall be designed to operate and withstand environmental conditions, described in

the METOCEAN DATA document (see 1.2.1). In addition, the Unit shall be verified for the

environmental conditions on the specified route during transportation from the construction

to the offshore site and from site to outside Brazilian waters, at the end of the Contract.

Additionally, CS requirements on the use of such data for design shall be accounted for.

For motion requirements, the more stringent criterion shall be considered.

12.1. MAXIMUM DESIGN CONDITION

The Unit shall be designed to operate normally (as defined in item 12.5.1) in an extreme

storm condition with 3 (three) hour duration and only the Unit moored (no shuttle tanker in

tandem), at any drafts ranging from fully loaded to minimum loaded condition, in accordance

with CS requirements, and varying from no riser connected to all risers connected. Under

these conditions, the Unit shall maintain its offset within the limits stated in the documents

SPREAD MOORING & RISERS REQUIREMENTS (see 1.2.1). The most unfavorable of the

following environmental combinations shall be adopted for the Maximum Design Condition:

1) 1-hour average wind speed and wind spectra described in the specific metocean data

combined with a sea state corresponding to 100 (one hundred)-year-return period and a 10

(ten)-year-return period current. Average API wind spectra shall be used if no data is

available.


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2) 1-hour average wind speed and wind spectra described in the specific metocean data

combined with a sea state corresponding to 10 (ten)-year-return period and a 100 (one

hundred)-year-return period current. Average API wind spectra shall be used if no data is

available.

Note: design wind speed should refer to an elevation of 10 m above still water level.

Regarding the incoming directions for the environmental parameters, the most critical

approach shall be adopted as follows:

• A co-linear approach, considering wind, waves and current coming from the same

direction;

• Wind and waves coming from the same direction but the current direction may be up

to 45 degrees out of alignment with chosen wind/waves direction.

12.2. MAXIMUM OFFLOADING DESIGN CONDITION

The Unit shall be designed to operate normally with a Suezmax sized shuttle tanker (up to

150,000 dwt), moored in tandem. The design shall ensure that the Unit can withstand any

range of draft conditions for the Unit itself and the shuttle tanker in tandem, and varying from

only 3 (three) risers connected (production, gas-lift and umbilical control risers for one

production well) to all risers connected.

Maximum mooring design conditions to be considered are:

• Winds - 1 (one)-year return period, 10-minute average wind speed, 10 m above sea

level;

• Waves - The waves shall be considered as being aligned with the wind and limited up

to: HS = 3.5m and TZ = 12.0 sec;

• Current - 1 (one)-year return period. The current shall be considered in any direction,

up to 45 degrees out of alignment with the wind and waves. The worst case shall be

accounted for.

The incidences to be considered are from 0o to 360o, with increments of 22.5o. The shuttle

may be moored to the Unit bow-to-bow or bow-to-stern for offloading.


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12.3. BEAM SEA CONDITION (NOT APPLICABLE)

Not Applicable

12.4. MAXIMUM PULL-IN / PULL-OUT ENVIRONMENTAL CONDITION

All equipment, component and/or accessory that will be part of the risers pull-in/pull-out

system shall be designed or specified to perform these operations accordingly to the

SPREAD MOORING & RISERS REQUIREMENTS (see 1.2.1).

12.5. MOTIONS AND ACCELERATIONS DESIGN CONDITIONS

12.5.1. NORMAL OPERATION AND EXTREME CONDITIONS

For motions and accelerations responses, short term statistics shall be evaluated for the

DEC (design extreme conditions – 100 year return period seas) and DOC (design operational

condition – 1year return period seas) waves from METOCEAN DATA. These responses shall

be appraised on the COG of the FPSO and on as many points as needed for the right

structural sizing as well. The distribution of the points to be evaluated in this analysis shall

be in accordance with CS requirements.

Sea states (Hs x Tp) in motion analysis for the site location shall consider METOCEAN

DATA, specifically extreme distribution contour curves with range of periods, for all specified

directions.

The Unit shall also be able to operate normally for DOC conditions, at any draft from fully

loaded to minimum loaded

Under DOC conditions, the Unit’s single-amplitude roll motion shall not exceed 10 degrees,

while under DEC conditions the Unit’s single-amplitude roll motion shall not exceed 15

degrees. The roll angle single-amplitude values shall be demonstrated during the model tests

to be carried out by CONTRACTOR.

CONTRACTOR shall design and install a bilge keel in the hull as following:

(i) CONTRACTOR shall present calculations in order to back-up the bilge keel width and

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(ii) Regardless the calculations in item (i), the minimum width of the bilge-keel shall be 1,5m.

REMARKS:

1. To operate normally means a state in which all systems and processes on the Unit can

be started or kept running without tripping alarms or safety shut-down devices or

endangering equipment and personnel involved. This includes the oil collecting system,

oil offloading system, utility systems, vessel systems, oil transfer to/from cargo tanks and

other handling devices operation as well as the maintenance processes of any systems.

In addition, process facilities shall be designed to ensure the efficiency of separation and

treatment and transfer of oil, gas and water;

12.5.2. OPERATIONAL CONDITION FOR UTILITIES

The Unit’s utility systems shall operate normally when subjected to the worst of the following

conditions:

• The motions and accelerations associated with the design extreme condition (item

12.5.1);

• All CS requirements, including towing condition;

• At least 15 degrees single-amplitude roll, with a 10 s period and pitch motions taken

as the worst obtained from the application of the conditions stated in item 12.1.

REMARK:

Utility systems are any facilities employed to provide power generation, water for cooling,

compressed air, HVAC to keep the vessel operating while the offloading or pull-in/pull-out

operations cannot proceed due to the weather conditions.

12.5.3. FOUNDATIONS AND FASTENINGS STRUCTURAL REQUIREMENTS

The foundations and fastenings shall be designed according to CS requirements in order to

withstand the worst of the following:

1. Motions and accelerations associated with DOC and DEC design condition (item 12.5.1);

2. All CS requirements, including towing condition;


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REMARKS:

Only in the towing condition no live weights can be considered present in the cargo piping.

This consideration must be checked against CS requirements.

All safety systems and life-saving systems, including emergency equipment and vessel

abandonment equipment, shall continue to operate while under the worst of the conditions

listed above in this item.

13. MOORING

CONTRACTOR (or respective SUBCONTRACTOR) shall demonstrate previous experience

in mooring design, i.e. in similar projects with at least 2000 m water depth and VLCC or larger

hulls, and submit to PETROBRAS approval.

The Unit’s Mooring shall comply with the Spread Mooring & Riser Systems Requirements

document (see 1.2.1).

The mooring system shall comply with following requirements:

• Mooring winches capacity shall be equal to the highest mooring line pretension value

multiplied by a factor of 1.75.

• Mooring lines hook-up winches shall be electro-hidraulically actuated chain jacks (linear

winches for chain). Mooring line hook-up capstans are not acceptable.

• Chain lockers associated with each mooring station shall be capable of storing 250 meters

of chain (150 meters of installation chain and additional 100 meters of top chain). Chain

lockers can be either movable or fixed.

• Minimum chain jack winches pull-in speed shall be 1.5 m/min in any chian pull-in condition.

• Chain lockers of the mooring system shall not be installed inside the FPSO hull nor be a

structural space.

• The chain pipe shall be located in a non-hazardous area.

• Chain stoppers and load cells, if not installed at the main deck, must not be located

underwater so that inspection and maintenance can be realized without impacting the normal

operation of the Unit.


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• The minimum safety factor to be adopted for polyester ropes must be higher than 10% of

the minimum required by ISO 19901-7 standard.

14. FLEXIBLE AND RIGID RISERS

14.1. RISERS CHARACTERISTICS

CONTRACTOR shall provide supports for flexible and rigid risers that may be connected to

the Unit in accordance with SPREAD MOORING & RISERS REQUIREMENTS (see Table

1.2.1.1).

CONTRACTOR shall consider the following for protect the risers regarding pressure and

temperature:

Table 14.1.1: Pressure for risers protection.

Subsea Line

Design

Pressure

(kPa(a))

Leak Test

Pressure

(kPa(a)) (2,3)

Oil Production Line 35,200 45,760

Gas Production Line 35,200 45,760

Gas Lift/Service Line 34,500 45,760

Water Injection Line 27,800 35,750

WAG Injection Line 57,800 74,360

Gas Export Line 34,500 42,900

Note 1: During the leak test an overpressure of 4% above the leak test pressure for all risers

may be requested by PETROBRAS.

Note 2: A separate portable low capacity (2.5 m3/h with 100% re-circulation), positive

displacement pneumatic driven pump shall also be provided to achieve the required pressure

up to 65,000 kPa(a) for leak test all risers after hook-up. The service tank shall be connected

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the presence of sea water. Free area shall be foreseen in the riser balcony for the pumping

system installation.”

Note 3: The required leak test pressures are related to riser test. Topsides piping and

accessories may not be designed considering the riser leak test pressure.

Note 4: Facilities to allow the leak test of the risers using rented service pumps shall be

provided.

Note 5: During execution phase PETROBRAS will provide to CONTRACTOR the temperature

requirement for riser protection.

Note 6: The selection of relief devices to protect the risers against overpressure shall take into

consideration each riser required design pressure and maximum overpressure (full open

condition) not higher than 110% of design pressure.

Note 7: The selection of relief devices on the discharge of Main/Injection Compressors and

Water Injection Pumps shall also take into consideration each riser required design pressure

as per Table 14.1.1.

Note 8: Facilities to monitor the pressure and depressurize risers during leak test operation

shall be provided.

Note 9: The leak test for risers shall obey the maximum pressures from table 14.1.1.

Note 10: The pressure values above are subject to alterations and shall be confirmed with

PETROBRAS during early execution phase.

14.2. RISERS INSTALLATION AND DE-INSTALLATION PROCEDURES

CONTRACTOR shall supply man-power as well as all devices and facilities onboard to

perform the riser pull-in and pull-out connections.

CONTRACTOR shall prepare and submit to CS and PETROBRAS for comments a detailed

installation and de-installation procedure for the risers.

CONTRACTOR shall consider also take into account the requirements in the document

SPREAD MOORING & RISER SYSTEMS REQUIREMENTS.

14.3. RISER HANGOFF AND PULL-IN SYSTEMS


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CONTRACTOR shall refer to the reference documents (see 1.2.1):

• SPREAD MOORING & RISERS REQUIREMENTS (Spread Mooring option);

• RISERS TOP INTERFACE LOADS ANALYSIS;

15. SOIL DATA

Refer to the document SPREAD MOORING & RISERS REQUIREMENTS (see 1.2.1).

16. HULL SYSTEMS AND PIPING

16.1. MAIN CONCEPTS

16.1.1. RULES, REGULATIONS AND REQUIREMENT

The Hull Systems shall follow the requirements of MODU CODE, CS rules, guidelines

requirements, all vendors’ equipment recommendations, Administration and SOLAS

requirements applicable for oil tankers.

16.1.2. CARGO PUMP ROOM

The FPSO shall not have any cargo pump room, i.e., a pump room which handles oil or oily

water mixtures.

Note 1: In case of a tanker conversion to FPSO, the pump room shall not have any

equipment, piping and other accessories connecting this space to the cargo tanks, slop

tanks, produced water tanks and any other oil or oily water mixture tanks in the Cargo Area.

Note 2: The fluid pumping system dedicated to cargo, slop, produced water and any other

oily water mixtures tanks in the Cargo Area shall be based on submerged type pumps.

Each cargo tank shall have at least one cargo pump.

The slops, produced water and any other oil or oily water mixtures tanks in the Cargo Area

shall have at least one submerged pump dedicated to each function.

16.2. GENERAL REQUIREMENTS APPLICABLE TO HULL SYSTEMS

16.2.1. DOUBLER PLATES


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Doubler plates shall be welded in line with the suction and discharge of each tank. The doubler

plates shall be at least of the same thickness of the plating which it will be welded.

Note: In cargo, slop, produced water, other oily water mixture tanks in Cargo Area an

abrasion resistant coating should be applied to the outer surfaces of the doubler plates,

see Coating Philosophy item 5.8.6. In all other tanks, the doubler plates paint scheme shall

follow the paint scheme of the respective tank.

16.2.2. TANK OPENINGS IN CARGO AREA

There shall be provided the following deck openings:

• Openings for the tanks degasification exhaust fans (minimum of five openings for the

cargo and oil settling tanks (if applicable) other oily water mixtures tanks in Cargo

Area, and two openings for slop tanks and produced water tanks) (*);

• Openings for the assembling of portable cleaning machines;

• Openings for the maintenance of submerged pumps;

• Openings for the gravel removal (**);

• Openings for the removal or replacement of structural elements (**);

• Openings for the removal of injured persons;

Openings for the portable cargo pumps (***).

The Tank Openings Plan (including void spaces and cofferdams) shall be submitted for

Petrobras.

For all compartments that can be flooded with cargo oil due to a crack in one of the adjacent

watertight bulkheads with cargo, slop, produced water or any other oily water mixture tanks

in Cargo Area, it shall be possible to install the portable cargo pump in one of the

compartment openings. There shall have be no obstruction from the referred opening to

the bottom of the compartment.

(*) These openings can be used to the removal of injured persons since there is no

obstruction to allow the direct lifting of one stretcher from the bottom of the tank

compartment to the Main Deck.


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Note: The minimum dimensions for the removal of injured person on stretcher are

800x600mm.

(**) If the tank is served by submerged pumps (cargo tanks, slop tanks, produced water

tanks other oily water tanks in Cargo Area, the openings for its removal can be used for

this purpose.

(***) The openings for the portable cargo pumps shall have means to allow the installation

and removal of the pumps without inert gas leakage.

16.2.3. HULL SYSTEMS BUTTERFLY VALVES

All hull systems butterfly valves shall comply with API 609 Cat. B specifications.

16.2.4. BOTTOM PLUGS

All Bottom plugs shall be removed during conversions. In the case of new buildings it shall

not exist.

16.2.5. REINFORCED PIPING PENETRATION PIECES

The piping penetration piece located at the shell side, bottom plating, Main Deck, Fore

Castle Deck and Poop Deck shall be constructed with reinforced schedule as required

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Notes:

1) The Internal Coating shall be in accordance with I-ET-3010.00-1200-956-

P4X-004 - COATING PHILOSOPHY – BOT/BOOT;

2) The Penetration Piece is located between the side shell/bottom and the

second valve;

3) Side/bottom penetration piece of discharge piping of deck seal and inert

gas cleaning tower shall have a 15 mm minimum thickness.

4) SC thickness shall be considered whether it is higher than specified in the

table and notes.

Sch thickness (mm)

01/fev - -

03/abr - -

1 XXS 9,09

1 1/2 XXS 10,15

2 XXS 11,07

2 1/2 S-160 9,53

3 S-160 11,13

4 S-120 11,13

6 XS 10,97

8 XS 12,7

10 XS 12,7

12 XS 12,7

14 XS 12,7

16 XS 12,7

18 XS 12,7

20 XS 12,7

24 XS 12,7

26 XS 12,7

28 XS 12,7

30 XS 12,7

32 XS 12,7

34 XS 12,7

36 XS 12,7

Carbon Steel

NPSAPI 5L B PSL 1

epoxy internally coated (FBE)


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The external painting scheme of the piping penetration piece shall be the same as the

region where they are located. The internal painting scheme shall follow the document

Coating Philosophy.

The piping penetration pieces shall be welded to the hull and flanged to the bottom/side

valves and intermediate valves.

16.2.6. HULL PIPING SUPPORTS

The horizontal pipes in the exposed decks, ballast tanks, cofferdams, void spaces and

other areas with corrosive atmosphere shall be provided with PTFE (or similar material)

pads in all supports in order to avoid friction between the piping and supports. The standard

of the pads to be used shall be submitted to the approval of PETROBRAS and

Classification Society.

16.2.7. SPECTACLE FLANGES

All Main Deck piping that penetrates in cargo, slop, produced water and any other oily

water mixture tanks in Cargo Area, including the pipe stacks of cleaning machines and

cargo pumps, shall be provided with spectacle flanges between their blocking valve and

the penetration piece of the pipe in the tank.

Note 1: The spectacle flanges shall be located in a horizontal pipe at a approximately

distance of 300 mm from the centerline of the penetration pieces on main deck;

Note 2: These spectacle flanges shall be constructed in stainless steel AISI 316 or similar

material;

Note 3: The requirement outlined above does not apply to the Closed Venting System. In

this particular case, a spool piece shall be assembled close to the penetration.

16.2.8. DROPLINES

Each cargo, slop, tank and produced water and any other oily water mixture tank in Cargo

Area shall be provided with droplines. These droplines shall be designed to minimize the

risk of static electricity generation inside the tanks.

The droplines shall perform the loading from the top to the bottom of the cargo and slop

tanks. For the produced water tanks and any other oily water mixture tank in Cargo Area,


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the droplines shall do the loading below the operational level of these tanks in order to

mitigate the risk of static electricity generation.

The design of the droplines discharges shall be approved by the Classification Society.

16.2.9. OVERBOARD DISCHARGES

The FPSO overboard discharges shall comply with the following requirements:

• It shall not have any overboard discharge over the risers and the mooring lines;

• It shall not have any overboard discharge located in the region of the supply boat or

SMU operation areas;

The overboard discharge of systems which operate with oily water mixtures shall be

located above the summer draft load line.

16.2.10. MARINE PIPE RACK

There shall be a pipe-rack on the Main Deck dedicated to Hull systems. This pipe rack

shall be installed at a free height greater than the minimum height of the escape routes

throughout its extension and there shall be no installed valves and other elements directly

on the longitudinal headers.

Note: Free height is the distance between the plating of the Main Deck and the lower point

of the pipe-rack structure or the bottom of the pipes, whichever is less.

16.2.11. SEA CHESTS

Outfittings (handrails, eye lugs, etc) shall be installed on the Hull close to each sea chest

in order to allow both the ROV and diving operations.

16.2.12. STRUCTURAL TANKS MAINTENANCE

It shall be possible to do an intervention/maintenance in any structural tank without stopping

the Process Plant.

16.2.13. P&IDS


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CONTRACTOR shall submit all P&IDs of the systems herein stated to Petrobras.

16.3. HULL HYDRAULIC SYSTEM FOR VALVES ACTUATION

The following marine system valves shall not have any kind of automatic actuation:

• Loading System;

• Cargo and Offloading System;

• Tanks Cleaning and Recirculation System;

• Ballast System;

• Slop Tanks Discharge System;

• Any other marine system which operation interferes with the hull longitudinal girder

strength and/or with the FPSO stability.

NOTE: Automatic valve actuation is any valve actuation without human action. Remote

actuation is not considered as an automatic actuation.

All remotely actuated valves shall have their positions indicated on the Control Room panel,

on the valves themselves, and on the Solenoid Boxes or Solenoid Panel.

All manual seawater inlet valves through sea chest, side discharges, headers

communication, system valves that ensure pressure and vacuum levels in inerted tanks

and any others that ensure the bending moment and shear force of the hull girder and the

Unit stability shall be provided with indication on the Control Room panel and also local

indication on the valves themselves.

All valves operated through local hydraulic pumps shall have position indication on the

hydraulic device themselves and in the Control Room Panel.

16.4. LOADING SYSTEM

The purpose of this system is to receive the treated oil from the Process Plant and to load

this oil in the cargo tanks. This treated oil shall pass by the fiscal metering station before

entering in the loading system.


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Each cargo tank shall have a dedicated loading system dropline. The communication

between the Loading Header and the cargo droplines shall be made by double blocking of

valves in order to mitigate the possibility of spurious loading in the cargo tanks, with

consequent risk to the integrity of the hull girder. Moreover, it shall be possible to vary the

loading flow in each dropline, allowing the loading of more than one tank at a time.

The system shall allow the loading of a single or several tanks at a time, without affecting

the production of the Process Plant.

16.5. CARGO SYSTEM

The main purpose of the cargo system is to collect the oil from the cargo tanks and to

export this oil to a shuttle tanker, according to the document OFFSHORE LOADING

SYSTEM REQUIREMENTS (see 1.2.1).

Additionally, this system shall collect oily-water mixtures from the slop tanks and oil from

the cargo tanks and transfer them to the Tanks Cleaning and Transference System.

CONTRACTOR shall limit exported oil temperature through export hoses, from a minimum

of 35 ºC to a maximum of 55 ºC, to comply with shuttle tankers requirements.

The FPSO shall be equipped to export 1,000,000 bbl of oil to the shuttle tanker in no more

than 24 (twenty-four) hours. The total discharge of oil shall be made considering the Unit

FPSO at all operational draft variations. Attention must be paid to the oil physical

properties, particularly to the viscosity and temperature, and for the losses through the

offloading system (valves, hose reel, offloading hose, etc.)

The Cargo System shall be provided with a system that prevents the water hammer effect

in the case of a sudden closing of the North Sea Vale in the shuttle tanker, during the

offloading operations. This system shall be submitted to Petrobras.

The FPSO shall be able to perform any step of offloading operation during any time,

meaning that operations such as shuttle tanker connection and disconnection, oil transfer

shall be performed day or night time

The submerged pumps suction on the cargo area and ballast piping suction shall be

installed in the low point of the tanks, according to the operational trim of the FPSO.

16.5.1. SUBMERGED PUMPS OF CARGO AREA

The requirements outlined below are to be applied to the following pumps:


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• Cargo pumps;

• Slop pumps;

• Oil removal pumps of the slop tanks;

• Discharge pumps of the slop tanks;

• Water pumps of the produced water tanks;

• Oil removal pumps of the produced water tanks;

• Any other submerged pump at the cargo area including portable pumps

(1) The following pump types are accepted:

• Submerged pumps hydraulically actuated;

• Deepwell pumps electrically actuated from the main deck.

(2) Portable cargo pumps shall be provided. These pumps shall be always of the

hydraulically actuated type.

Each portable cargo pump shall comply with the following minimum requirements:

• Flowrate: 300 m3/h

• Height: 50 m WC

• The hoses shall be formally approved by classification society for their use.

The header of cargo pumps shall have connections with valve and blind flange for the

installation of the portable cargo pumps discharge. There shall be connections to all

cargo, slop produced water tanks as well as any other oily-water mixture tanks in the

Cargo Area.

Hydraulic lines connections shall be provided to allow portable cargo pump operation.

(3) If submerged hydraulically actuated pumps are adopted, the following items shall be

supplied by the pump manufacturer:

• Pumps, pipe-stacks and hydraulic motors;

• Main HPU;

• HPU of the portable pumps;


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• All pipings, valves, hydraulic vessels and other accessories of the hydraulic

actuation system;

• Local and remote control panels.

(4) When deep well electrically actuated from the main deck is adopted the following items

shall be provided by the pump manufacturer:

• Pumps, pipe-stacks and shaft lines;

• HPU of the portable pumps;

• All pipings, valves, hydraulic vessels and other accessories of the hydraulic

actuation system;

• Electrical motors;

• Local and remote control panels;

• VSDs.

(5)These pumps shall be actuated by the Control Room and also by a local panel.

(6) For both type of pumps mechanical handling (tripods, eye lugs, deck openings, etc)

shall be provided to allow proper removal of pumps and/or pipe stacks

If the pumps are deep well pumps driven by electric motors on the Main Deck, a forced

lubrication system utilizing lubricating oil shall be provided. The use of crude oil for the

lubrication of shaft and its bearings will not be accepted.

Regardless of the technology adopted for the submerged pumps, it shall be possible to

remove the pumps from the tanks without the need to remove their respective pipe stack.

The pipe stacks of the submerged pumps shall be segmented taking into account the free

height between the main deck and the lower level of the process plant in order to allow

them to be removed in case of maintenance. Structures and accessories on the main deck

(pipe racks, for example) shall not interfere with the removal of pipe stacks from these

submerged pumps.

16.6. TANKS CLEANING AND TRANSFERENCE SYSTEM

The main purposes of this system are:

• Transfer cargo between cargo tanks;


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• Perform the SWW (Sea Water Washing) or COW (Crude Oil Washing);

The transference of oil or oily mixtures between the cargo and slop tanks shall be done by

the Tanks Cleaning and Transference System. Oil transference by gravity between cargo

tanks are not allowed.This system shall have an independent header located on the Main

Deck.

The cargo tanks, slop tanks, produced water tanks and any other oil or oily-water mixture

tank in the Cargo Area shall have tanks cleaning machines.

There shall be a dedicated transfer dropline per cargo tank and slop tank. Transfer

droplines shall be made by double blocking of valves in order to mitigate the possibility of

spurious loading in the cargo and slop tanks.

A Shadow Diagram shall be made for cargo, slop, and produced water tanks as well as

other tanks containing oil or oily water mixtures in the Cargo Area. This diagram shall follow

the IMO requirements for oil tankers and shall indicate the number of fixed cleaning to be

used. The diagram shall be submitted for formal approval for the manufacturer of the

cleaning machines together with the approval document. The installation of cleaning

machines shall be done according to these diagrams.

For the cleaning machines arrangement on tanks CONTRACTOR shall present solutions

with a minimum quantity of bottom and portable cleaning machines installed.

The CONTRACTOR shall provide the specified number of portable cleaning machines,

with their hoses and other accessories

The SWW operations shall be done with a temperature of 60º C in the washing machines

inlet.

The total capacity of the dirty and clean slop tanks (at 98% of their maximum volume) shall

be at least 2.5% of the total combined capacity of all cargo tanks at 98% of their maximum

volume.

Any of the slop tanks shall perform all the functions provided for the set of two slop tanks,

considering repair and inspection situations of one of these tanks.

If the slop tanks have a contiguous bulkhead, a void space shall be provided between

them.

In case of FPSO based on tankers conversion, the Balance Line that communicates the

dirty and clean slop tanks shall not be installed inside the Pump Room.

If the hull chosen by the contractor is of the barge type, the Balance Line shall not have

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provided on the respective Balance Line in each slop tank and located adjacent to each

bulkhead that the Balance Line penetrates. One valve of the Balance Line shall be of

proportional type.

Heating coils inside cargo and slop tanks are not acceptable.

16.7. BALLAST SYSTEMS

The FPSO ballast system shall be dimensioned to operate only with the ballast tanks

located in the Cargo Area and with the Fore Peak tank.

The Ballast system shall fulfill all Brazilian Regulatory Authorities requirements and shall

have its inspection report submitted to PETROBRAS for comments and information.

There shall be two independent ballast systems one dedicated to the ballast tanks situated

aft of the Engine Room Forward Bulkhead and another one dedicated to the ballast tanks

situated forward of the Engine Room Forward Bulkhead. Each system shall have

redundancy of pumps, self-priming units, sea chests in a way to guarantee all operations

of ballast and deballast.

The ballast system located aft of the Engine Room Forward Bulkhead shall have

redundancy to ensure its operational continuity.

The ballast system located forward the Engine Room Forward Bulkhead shall have two

ballast pumps and any one of these pumps shall be able to do the suction from any of the

ballast tanks in the cargo area including the Forward Peak Tank.

A TOG analyzer shall be provided at each discharge of the ballast system that serves the

Cargo Area. The TOG analyzer shall be adjusted to a limit less than or equal to that defined

by MARPOL in the slop tanks discharge. Under no circumstances, it is allowed to discharge

ballast with oil into the sea.

The system shall be designed to prevent ballast operation by gravity.

The system shall allow the ballast of cargo tanks in contingency situations

16.8. FLOODING MONITORING SYSTEM

The Engine Room, Pump Room, cofferdams, void spaces, and Boatswain Store shall be

provided with a flood monitoring system.

16.9. SLOP TANKS DRAINAGE SYSTEM


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The slop tanks shall be provided with a system for collection and treat oily water to

discharge overboard. This system shall comply with the following requirements:

• A capacity of 350 m3/h or the required to drain 60% of the volume of one slop in 10

hours, which one is greater;

• All component of the system shall be installed on the Main Deck, exception for the

submerged pumps;

• The pump of each slop tank shall have redundancy. The pump of one slop tank shall

not serve the other slop tank;

• Oily water treatment equipment shall have redundancy;

• The maximum amount of oil in the water at the discharge shall be under the limits

specified by MARPOL.

NOTE: This system shall not operate by gravity. The drain of slop tanks shall be

performed by submerged pumps installed inside these tanks.

The overboard discharge of the Slop Tanks Drainage System shall be supplied with a

flowmeter. The amount of liquid discharged shall be measured and stored in the FPSO’s

Supervisory System.

16.10. INERT GAS SYSTEM

An Inert Gas System shall be installed for cargo, slop, production water and any other oil

or oily water tanks in Cargo Area.

The inert gas generation shall be supplied by two dedicated (2x100%) inert gas generators.

Generators shall be fed by a dual fuel system, burning preferably fuel gas and alternatively

marine diesel oil.

NOTE: Inert gas generated by boilers will not be accepted.

The inert gas generators shall be actuated by the Control Room and by a local panel.

The inert gas system of the hull shall have means to allow inertization of ballast tanks,

cofferdams and void spaces, located forward the Engine Room Forward Bulkhead in

contingency situations.

16.11. CLOSED VENTING SYSTEM


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A Closed Venting System shall be installed for cargo, slop, production water and any other

oil or oily water tanks in Cargo Area. An independent venting header shall be installed for

these tanks venting.

A double barrier against pressure and vacuum inside the tanks served by the Closed

Venting System shall be always maintained. One of these barriers is the inert gas system

Pressure Vacuum Breaker. The second barrier is the pressure-vacuum valves (P/V

valves).

NOTE 1: The double barrier shall be maintained even in case of maintenance of the

vacuum-pressure valves.

NOTE 2: Internal pressure monitoring of tanks is not considered as a protective barrier

NOTE 3: The Contractor shall not load nor offload any cargo or slop tank if the two barriers

against vacuum or pressure inside these tanks are not in operation. The same

requirement applies to the produced water tanks and any other oil or oily water tank in

the Cargo Area.

The vent posts of the Closed Venting System shall allow the maintenance or replacement

of their flame arresters without stopping production of the Process Plant, nor exposing the

tanks to risks of structural collapse by pressurizing them. In addition, the arrangement of

the vent posts shall not have the risk of gas return to the Process Plant in any

environmental condition presented in the METOCEAN of the Project. The exact location

and height of the vent posts should be confirmed by a gas dispersion study.

Considering the impact of the positioning of the vent posts for the safety of the FPSO and

the support vessels, a specific HAZOP shall be performed for this system.

16.12. PRESSURE, TEMPERATURE, ULLAGE AND INTERFACE MONITORING

SYSTEM

Each cargo, slops, produced water and any other oil or oily water mixture tank in the Cargo

Area shall be provided with a pressure, ullage and temperature monitoring systems.

The slops, produced water and any other oily water mixture tanks in the Cargo Area shall

also be provided with interface level monitoring system.

For the tanks inerted by inert gas system, visual and sound alarms shall be activated and

registered on CCR at the scenario of tanks high and low pressure alarm.

Structural Tanks not inerted by Inert Gas system shall have a level monitoring at the CCR

(Hull Control System panel);


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16.13. GAS SAMPLING SYSTEM

A Gas Sampling System shall be provided in ballast tanks, void spaces and cofferdams

adjacent to cargo, slops, produced water and any other oil or oily water tanks in Cargo

Area, according to the requirements of FSS Code (chapter 16).

16.14. HULL CENTRAL COOLING SYSTEM

Central cooling systems based on closed freshwater and open seawater circuits shall be

provided for all marine systems. Cooling systems that provide seawater directly to the

equipment are not accepted. Cooling systems of the hull systems shall be completely

segregated and independent from the topsides systems.

16.15. ENGINE ROOM BILGE SYSTEM

The overboard discharge of the Engine Room Bilge System shall be supplied with a

flowmeter. The amount of liquid discharged shall be measured and stored in the FPSO´s

Supervisory System.

16.16. SEWAGE SYSTEM

Unit shall have sewage treatment units in compliance with MARPOL, MPEC 159(55), and

IBAMA requirements especially but not limited to the “Resoluções” CONAMA and the

NOTA TÉCNICA CGPEG/DILIC/IBAMA Nº 01/11.

NOTE: Both grey and black waters shall be previously treated and metered before

discharged to sea.

The black water sewage system piping shall be of vacuum type.

The FPSO shall have two independent sewage treatment units (2x100%). Each unit shall

be dimensioned to 100% of the POB.

The sewage treatment units shall be of biological type and they shall be dimensioned to

comply with the following requirements:

• The units periodic maintenance interval shall be of a minimum period of 365 days;

• The maximum volume of residues that shall be removed in a maintenance procedure

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• The unit shall not require residues removal in the period between the normal

maintenance procedures;

• According to Brazilian laws (IBAMA, CONAMA), a certificate or similar document

shall be presented to prove that the solid residues have required pathogenic inertia.

It shall be provided dedicated sampling points in the following locations:

• In all the intakes of grey and black waters in both sewage treatment systems units;

• In all overboard discharge of the sewage treatment system to the sea.

The overboard discharge of the Sewage System shall be supplied with a flowmeter. The

amount of liquid discharged to the sea shall be registered in the FPSO’s Supervisory

System.

16.17. ANTIFOULING SYSTEM

An Antifouling System (MGPS) based on copper/aluminum anodes is acceptable as an

alternative to hypochlorite injection on the sea chests of the Engine Room, if and only if,

these sea chests are dedicated to the hull systems only.

16.18. HULL DRAINAGE SYSTEM

16.18.1. MAIN DECK DRAINAGE SYSTEM

Steel spill coamings shall be welded on the main deck around the main deck area to

mitigate the risk of pollution of the sea with oil. The coamings shall also mitigate the risk of

having oil in the main deck aft of the Accommodation Module forward part and forward of

the collision bulkhead. Spill coamings shall be designed in accordance with MARPOL

requirements.

The Main Deck draining in the Cargo Area shall not be performed by gravity to the slops,

cargo and any other oil or oily-water tanks in the Cargo Area.

16.18.2. UPPER RISER BALCONY DRAINAGE SYSTEM

The Upper Riser Balcony shall be provided with a fixed draining system. The drainage shall

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Around all risers slots that will conduct oil shall have oil coamings.

Note: WAG riser slots shall have these same oil coamings.

16.19. DIESEL SYSTEM

The Diesel Oil System arrangement shall allow the intervention and inspection of their

diesel tanks without interruption of the diesel oil supply to the FPSO.

The Diesel Oil / Cargo Oil Injection System shall not be allowed to maintain the wells

directly aligned with the hull structural tanks, an intermediate tank installed in the topsides

area shall be provided, refer to item 2.6.1 for details.

16.20. PRODUCED WATER SETTLING SYSTEM

The produced water tanks shall comply with the following requirements:

• At least two structural tanks in cargo area shall be provided for produced water;

• The effective volume of these tanks shall be equivalent to 24 hours of production of

the process plant;

• The tanks shall be communicated by a reversible balance line;

• These two tanks shall not have a contiguous bulkhead between them. If necessary

a void space between them shall be installed;

• The tanks shall be completely painted with a compatible painting scheme for

produced water and the expected tank temperature. Further details about the

painting scheme can be found in COATING PHILOSOPHY I-ET-3010.00-1200-956-

P4X-004.

• The tanks shall be provided with a cathodic protection system made by sacrifice

anodes. These anodes shall be compatible with the expected tank temperature.

• The suctions and discharges of these tanks shall be designed to minimize the

turbulence inside the tank and to optimize the settling process;

16.21. SLOP OIL RECOVERY SYSTEM

Each slop tank shall be provided with a system to remove the oil and oil emulsions from

the top layer of its content and send it back to the Process Plant.


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16.22. OFFLOADING SYSTEM

The Offloading Equipment shall be of the reel type.

As the FPSO will have a Spread Mooring System, CONTRACTOR shall provide 2 (two)

offloading systems (one forward and other afterward), each complete with its own hose

and hawser, one at the stern another at the bow, in order to allow the offloading operation

in a broader range of weather conditions.

CONTRACTOR shall provide arrangements and facilities to allow proper cleaning of the

offloading system (including the offloading hose), which will be performed immediately after

every cargo transfer (offloading) as follows:

• The FPSO shall allow pumping water through the offloading hose from the FPSO

to the shuttle tanker.

• After the oil offloading being performed, the shuttle tanker will pump the water back

to the FPSO. Therefore the FPSO shall not have any constraint, such as non-return

valves at the hose reel that may jeopardize the seawater pump-back operation from

shuttle tanker to FPSO.

• Additionally the FPSO shall be capable to perform final flushing (cleaning) of the

offloading hose on a “closed-circuit mode”. The closed circuit mode means the

offloading hose will be reeled and stored onboard the FPSO.

• The arrangements for connecting water lines to cargo system, slop tank or dedicated

return tank shall be submitted to PETROBRAS for comments/information.

The inspection and maintenance of the offloading hose shall fall under the

CONTRACTOR’s responsibility.

The offloading system, including the hose reel, shall be designed considering the operation

with Suezmax shuttle tankers, as described in document Offshore Loading System

Requirements (see Section 1.2.1).

CONTRACTOR is responsible for the operation and the maintenance of the system during

contract period.

An emergency offloading system with outlet, valve, oil tray and the necessary devices to

lift the external hose to the FPSO shall be installed at the Unit's bow and stern.

The forward and the aft offloading systems shall be provided with oil trays to collect oil from

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Note: NSV is an acronym to North Sea Valve which is detailed on Section 6.5.3 of I-ET-

3010.00-1359-960-PY5-001 (OFFSHORE LOADING SYSTEM REQUIREMENTS).

These oil trays shall have a draining system collecting oil from the trays and discharging

this oil in the slop tanks.

17. ENVIRONMENT IMPACT STUDIES

17.1. GENERAL

PETROBRAS will engage third party for Environmental Risk Assessment, in which case

CONTRACTOR shall take part in the assessment, provide all necessary information and

comply with recommendations.

CONTRATOR shall provide a report with information requested by the document called

"Environmental Impact Study and Report" (Estudo de Impacto Ambiental e Relatório de

Impacto Ambiental – EIA-RIMA).

This report shall be submitted within 6 (six) months after Letter of Intention (LOI) or Contract

signature and include the following items.

17.2. GENERAL DESCRIPTION

a) Table with the FPSO characteristics including FPSO name, mooring type, length, molded

breadth, depth, molded depth, light weight, maximum draft, flare height, total cargo oil

tanks storage capacity, fuel gas and diesel consumption list, crane capacities, power

generation (main, essential, emergency) rating, sewage treatment system capacity and

technology, quarters capacity, helideck specification, saving equipment;

b) Hull description;

c) Tank capacity plan including each tank material specification and specific requirements

e.g. painting;

d) Inert gas system description;

e) Ballast system description;

f) Description of the Fluid processing plant (oil, gas, produced water and injected water);


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g) Simplified diagram containing produced oil, produced water, gas and sea water treatment

and injection process;

h) Diagram (for each process: oil treatment, gas treatment, produced water treatment and

sea water treatment for injection) containing main equipment as separators, scrubbers,

heat exchangers, compressors and pumps;

i) Table with pressure, temperature, flow rate and contaminant content (watercut for liquid

systems, CO2, H2S and water for gas systems) for inlet and outlets of each main process

equipment as separators, heat exchangers, compressors and pumps

j) Cooling sea water overboard characteristics such as discharge maximum flow rate,

temperature, internal diameter, direction and position in relationship to sea water surface.

The draft variation due to FPSO load shall be informed;

k) Cooling water closed loop system description, including pumping configuration and flow

rate;

l) Industrial water supply system description including type of treatment, suction depth, flow

rate and consumers list;

m) Potable water system description including type of treatment and flow rate;

n) Simplified diagram of industrial and potable water treatment;

o) Power generation description including capacities of main, auxiliary, uninterruptible and

emergency systems, as well as fuel consumption for each generator considering all fuel

sources;

p) Cranes description including length and capacity;

q) Flare and vent systems description including flow rate capacities, and stack height;

r) Topsides and Subsea Chemical injection system description including a table expected

chemical, dosage rate, injection points, and storage capacity.

17.3. EFFLUENTS

Details about effluent discharge on sea are being requested to support plume dispersion

included in environmental studies.


REV.

B

FPSO XXXXX SHEET

337 of 338

TITLE:


SRGE

a) Sulphate removal/ Ultrafiltration reject flow rate, composition, discharge temperature, pipe

internal diameter, direction and position in relationship to sea water surface. The draft

variation due to FPSO load shall be informed;

b) Sulphate removal/ Ultrafiltration membranes cleaning procedure description including

expected frequency and the duration of each step, waste water overboard description

containing composition, pH, discharge volume and duration, density, salinity, chemical

concentration, flow rate, pipe internal diameter, direction and position in relationship to sea

water surface. The draft variation due to FPSO load shall be informed;

c) Produced water system description, oil content, measurement points, interlock between

measurement and discharge, reprocessing philosophy description, discharge flow rate,

pipe internal diameter, direction and position in relationship to sea water surface. The

draft variation due to FPSO load shall be informed;

d) Drainage system description, estimate of volume generated monthly, composition, oil

content, measurement points, interlock between measurement and discharge,

reprocessing philosophy description, discharge flow rate, pipe internal diameter, direction

and position in relationship to sea water surface. The draft variation due to FPSO load

shall be informed;

e) Simplified scheme containing all drainage systems (topsides and marine).

17.4. ATMOSPHERIC EMISSIONS

a) Annual quantification (for commissioning and operation phase) of gas pollutants

concentration and mass flow rate of each source as turbines, boilers, flare, vent, etc. It

shall be quantified at least the following emissions : NOx, SOx, CO, CO2, CH4, N2O,

particulate matter and total hydrocarbons. For power generators with more than one fuel,

the quantification shall be done for each fuel. A table containing all these information shall

be provided.

In case of a venting gas system all CO2 and CH4 content shall be considered in atmospheric

emissions balance.

b) A preliminary description of UNIT commissioning shall also be provided including expected

atmospheric emissions as per item 17.4.a.


REV.

B

FPSO XXXXX SHEET

338 of 338

TITLE:


SRGE

17.5. WASTE MANAGEMENT

Solid residues characterization, residue class, disposal destination, annual mass generation

including change out process materials (molecular sieve, CO2 membranes cartridges,

sulphate removal membranes cartridges, etc.), sewage sludge, oil tank sludge, slop tank

sludge, flotation cell unit sludge, ordinary garbage, nursery garbage, dangerous residues,

food debris, oily residues, chemicals, sewage sludge, etc.

18. PETROBRAS LOGOTYPE

CONTRACTOR shall paint PETROBRAS logo type in the following Unit places:

• Funnel (both sides);

• Portside and Starboard in visible area.

Date post:	19-May-2020
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