TCVN
NATIONAL NATIONAL STANDARD STANDARD
TCVN 64746474-1: 1: 2007
TCVN 64746474-9: 9: 2007
Second Se cond editio n
RULES FOR CLASSIF CLA SSIFICATION ICATION AND TECHNICAL TECHNICAL SUPERVISION OF FLOATING STORAGE UNITS
HA NOI -2007
BLANK PAGE
NATIONAL STANDARD
TCVN 6474-1: 2007
TCVN 6474-9: 2007
Foreword
National standards from TCVN 6474-1:2007 6474-1:2007 to TCVN 6474-9:2007 6474-9:2007 replace to TCVN 6474:1999. National standards from TCVN 6474-1:2007 6474-1:2007 to TCVN 6474-9:2007 6474-9:2007 are edited by Vietnam Register and TCVN/TC8 ''Shipbuilding and Offshore'' Technical Standard Board, is proposed by Ministry of Transportation and Standard - Measure - Quality General Department, is promulgated by Ministry of Science and Technology.
3
BLANK PAGE
4
NATIONAL STANDARD
TCVN 6474-1: 2007
TCVN 6474-9: 2007
CONTENTS Foreword
3
PART 1: CLASSIFICATION
25
1 General requirements requirements
25
1.1 Application
25
1.2 Reference documents
25
2 Definition and explaination
27
2.1 Floating storage units.
27
2.1.1 Purpose
27
2.1.2 Major Elements
27
2.2 Type of floating storage units
27
2.3 Coordinates and motion
28
2.4 Production Facilities
29
2.4.1 General
29
2.4.2 Production Support Systems
29
2.4.3 Hazardous Areas
29
2.4.4 Piping and Instrumentation Diagrams (P&IDs)
30
2.4.5 Safety Analysis Function Evaluation (S.A.F.E.) Charts
30
2.5 Position Mooring System
30
2.5.1 General
30
2.5.2 Spread Mooring
30
2.5.3 Single Point Mooring (SPM)
31
5
2.5.4 Dynamic Positioning and Thruster Assisted Systems
36
2.6 Subsea System
36
2.6.1 General
36
2.6.2 Floating Hose
36
2.6.3 On Bottom Flexible Flow Lines
36
2.6.4 Pipe Line End Manifold (PLEM)
36
2.6.5 Riser
36
2.6.6 Riser System
37
2.6.7 Riser Support
37
2.6.8 Submerged Jumper Hoses
37
3 Classification
38
3.1 Class assignation
38
3.2 Class of floating storage units
38
3.2.1 Scope of classification for floating storage units
38
3.2.2 Basic characters of classification classification for floating storage units
38
3.2.3 Class notations of hull of floating storage units
38
3.2.4 Class notations of machinery of floating storage units
39
3.3 Subdivision notation and additional notations
39
3.3.1 Subdivision notation
39
3.3.2 Notation for in water survey of submerged part of hull of floating storage units
40
3.3.3 Notation for enhanced survey programme
40
3.3.4 Notation for function of floating storage units
40
3.3.5 Dynamic positioning system
40
6
3.3.6 Notations for location and operational condition
40
3.3.7 Example for charaters and notations of classification
41
3.4 Class maintenance
41
3.5 Suspension of Class
41
3.6 Lifting of Suspension
42
3.7 Withdrawal of class and chance character of classification
42
3.8 Reclassification Reclassification
42
3.9 Requisition for a survey
43
3.9.1 Classification survey
43
3.9.2 Survey for class maintenance
43
3.10 Certificate of Classification
43
3.10.1 Issurance of Classification Certification
43
3.10.2 Endorsement of Classification Certificates
43
3.10.3 Issuance of Provisional Classification Certificates
43
3.10.4 Validity of Certificate of Classification and Provisional Certificate of Classification
43
3.10.5 Retention, Reissue, Rewriting and Return of Certificate of Classification
44
4 Technical documentation
46
4.1 Design documents for submission
46
4.1.1 Design documents for submission
46
4.1.2 Amendments to approved technical documentation
46
4.1.3 Submission of final design documentation
46
4.1.4 Requirements for the technical documentation for approval
46
4.1.5 Duration of validity of approved technical documentation
46
7
4.2 Documents issued by VR
47
4.2.1 Documents issued in compliance with the Rules
47
4.2.2 Seaworthiness certificate
47
5 Classification Surveys
49
5.1 Classification Surveys during Construction
49
5.1.1 General
49
5.2 Submission of Plans and Documents for Approval
49
5.2.1 Hull of floating storage units
49
5.2.2 Position Mooring System
52
5.2.3 Production Facilities and Production Support Facilities
52
5.2.4 Import/export system
54
5.2.5 Machinery installations and electrical installations
55
5.2.6 Manuals and Procedures
55
5.3 Presence of Surveyor
56
5.4 Hydrostatic and Watertight tests
57
5.5 Classification Survey of Unit not built under Survey
57
5.5.1 General
57
5.5.2 Tests
58
PART 2: ENVIRONMENTAL LOADING AND DESIGN BASIC
59
1 Environmental loading and design basis
59
1.1 Design Basis
59
1.2 Design Documentation
59
1.3 Design Conditions
60
8
1.3.1 Position Mooring System
60
1.3.2 Structural Strength and Fatigue Life
61
1.4 Environmental Conditions
63
1.4.1 General
63
1.4.2 Environmental Loads
64
1.4.3 Current
64
1.4.4 Wind
65
1.4.5 Waves
67
1.4.6 Directionality
69
1.4.7 Soil Conditions
69
PART 3 : TECHNICAL REQUIREMENTS
71
1
71
Technical requirements for floating storage units
1.1 All Vessels
71
1.1.1 General
71
1.1.2 Lightweight Data
72
1.1.3 Load Line
72
1.1.4 Operating Manual
72
1.1.5 Loading Manual (Operating Manual)
74
1.1.6 Trim and Stability Booklet (Operating Manual)
75
1.1.7 Engineering Analysis
75
1.1.8 Mooring Systems and Equipment
76
1.1.9 Material
76
1.1.10 Underwater marking
77
9
1.1.11 Corrosion Protection
77
1.2 Ship - Type Vesels
80
1.2.1 General
80
1.2.2 Definitions
81
1.2.3 Longitudinal Strength
81
1.2.4 Stability , Division and Loadline
81
1.2.5 Structural Arrangement
82
1.2.6 Structural Design of the Hull
82
1.2.7 Engineering Analyses of the Hull Structure
85
1.2.8 Analysis and Design of Other Major Hull Structural Features
90
1.2.9 Marine Piping Systems
94
1.2.10 Electrical Systems
94
1.2.11 Fire Fighting Systems and Equipment
97
1.2.12 Machinery
98
1.2.13 Equipment
98
1.2.14 Safety Equipment
98
1.3
98
Column-stabilized Vessels
1.3.1 General
98
1.3.2 Definitions
99
1.3.3 Loading Criteria
99
1.3.4 Wave Clearance
99
1.3.5 Structural Design
99
1.3.6 Engineering Analysis of the Vessel's Primary Structure
101
10
1.3.7 Analysis and Design of Other Major Structures
103
1.3.8 Stability
104
1.3.9 Marine Piping Systems
105
1.3.10 Electrical Systems
105
1.3.11 Fire Fighting Systems and Equipment
105
1.3.12 Machinery and Equipment
105
1.3.13
106
Safety Equipment
1.4 Existing Tanker Hull Structures (Ordinary Conversions)
106
1.4.1 Introduction
106
1.4.2 General
106
1.4.3 Alternative Acceptance Criteria for the 'Basic Design' of the Hull Structure
107
1.4.4 Assessing the 'Basic Design' of the Hull Structure
115
1.4.5 Optional: "Time to Steel Renewal" Assessment
116
1.4.6 Survey Requirements for an "Ordinary Conversion"
116
1.5 Tension Leg Platforms
119
1.6 Spar Vessels
119
PART 4: POSITION MOORING SYSTEM
121
1. Mooring system
121
1.1. Definitions
121
1.1.1. Spread Mooring
121
1.1.2. Single Point Mooring (SPM)
122
1.2. System Conditions
122
1.2.1. Intact Design
122 11
1.2.2. Damaged Case with One Broken Mooring Line
123
1.2.3. Transient Condition with One Broken Mooring Line
123
1.3. Mooring Analysis
123
1.3.1. Mean Environmental Forces and Moments
124
1.3.2. Maximum Offset and Yaw Angle of the Vessel
125
1.3.3. Maximum Line Tension
126
1.3.4. Mooring Line Fatigue Analysis
127
1.4. Mooring Line Design
128
1.5. Hawser Loads
128
1.6. Dynamic Positioning Systems
129
1.7. Thruster Assisted Mooring Systems
129
1.8. Mooring Equipment
129
2. Anchor Holding Power
130
2.1. Drag Anchor
130
2.2. Conventional Pile
131
2.3. Vertically Loaded Drag Anchors (VLA)
131
2.4. Suction Piles
132
2.5. Factor of Safety
133
3. Field Test
133
4. Single Point Moorings - CALMs, SALMs, Turrets and Yokes
135
4.1. Design Loadings
135
4.2. Structural Components
135 12
4.3. Mechanical Components
135
4.4. Hazardous Areas and Electrical Installations
136
4.5. Fire Fighting Equipment
136
4.6. Product Piping Systems and Floating Hoses
136
4.7 Turret Mooring
136
4.8. Turret/Vessel Structural Interface Loads
138
5. Surveys During Construction
138
PART 5 : HYDROCARBON PRODUCTION AND PROCESS SYSTEMS
141
1. Hydrocarbon Production and Process Systems
141
1.1. General requirements
141
1.2. Application
141
1.3. Subsea Equipment
142
1.4. Use other standards
142
1.5. Non-standard Equipment
142
1.6. Design and Construction
142
1.6.1 General
142
1.6.2 Arrangements
143
1.6.3 Structural Considerations
143
1.7. Process System
143
1.7.1 Submittals
143
1.7.2 Piping System and Manifolds
144
1.7.3 Pressure Relief and Depressurization Depressurization Systems
144
1.7.4 Process Equipment
144
13
1.7.5 Prime Movers
144
1.7.6 Safety Systems
144
1.7.7 Control System
145
1.7.8 Quick Disconnect System
145
1.7.9 Electrical Installations
146
1.8. Hazardous Area Classification
146
1.9. Fire protection
146
1.10. Fabrication and testing
146
1.10.1 Pressure Vessels, Accumulators, Heat Exchangers, Separators, and Manifolds
146
1.10.2 Pumps, Compressors and Diesel/Gas Engines
147
1.10.3 Motors and Generators
147
1.10.4 Switchboards and Control Panels
147
1.10.5 Process and Process Support Piping
147
PART 6 : IMPORT AND EXPORT SYSTEMS
149
1. Import and export systems
149
1.1. General
149
1.1.1 Riser Classification Boundaries
149
1.1.2 Basic Design Considerations
150
1.2. Submission of Plans and Design
150
1.3. Environmental conditions
151
1.4. System Design and Analysis
151
1.4.1 General requirements
151
1.4.2 Rigid Risers
151
14
1.4.3 Flexible Risers
153
1.4.4 Export Vessel Transfer System
154
1.4.5 System Components
154
1.4.6 Installation Analysis
154
1.5. Material
155
1.5.1 Material for Rigid Risers
155
1.5.2 Material for Flexible Risers
155
PART 7 INSTALLATION, INSTALLATIO N, HOOK-UP AND COMMISSIONING
157
1. Installation, Hook-up, and Commissioning
157
1.1. General requirements
157
1.1.1. General Description
157
1.1.2. Pre-installation Pre-installation Verification
157
1.1.3. Pile or Anchor and Mooring Line Installation
157
1.1.4. Tensioning and Proof Load Testing
158
1.1.5. Hook-up of the Anchor Chain System
159
1.1.6. Import/Export System Installation
159
1.1.6.1. Rigid and Flexible Risers
160
1.1.6.2. Export Vessel Transfer System
160
1.1.7. Disconnecting Procedure
161
1.2. Hook-Up Procedures Submittal
161
1.3. Start-Up and Commissioning Procedures Submittal
161
1.4. Surveys during Installation of the Mooring Systems
161
15
1.5. Surveys During Installation of the Import/Export System
162
1.6. Surveys during Hook-Up
163
1.7. Demonstration of the Disconnectable Disconnectable Mooring System
164
1.8. Surveys During Start-Up and Commissioning
164
PART 8: SURVEYS AFTER INSTALLATION INSTALLAT ION AND COMMISSIONING
167
1 Class maintenance surveys
167
1.1 Periodical surveys
167
1.1.1 General
167
1.1.2 Modification of Requirements
168
1.1.3 Definitions
168
1.1.4 Survey Reports File
169
1.1.5 Corrosion Prevention System - Ballast Tanks
170
1.2 Intervarls of periodical surveys
170
1.2.1 General
170
1.2.2 Annual surveys
170
1.2.3 Docking surveys
170
1.2.4 Underwater Inspection in Lieu of Drydocking Survey (UWILD)
170
1.2.5 Intermediate surveys
171
1.2.6 Special surveys
171
1.2.7 Boiler surveys
173
1.2.8 Propeller shaft and stern tube shaft surveys
173
1.3 Annual surveys
174
1.3.1 Requirements for Annual Surveys – Hull
174 16
1.3.2 Annual survey for Machinery installations and Electrical Installations
179
1.4 Docking surveys
184
1.4.1 General
184
1.4.2 Requirements for Docking survey
185
1.5 Underwater Inspection in Lieu of Drydocking Survey
186
1.5.1 General
186
1.5.2 Parts to be Examined
187
1.6 Intermediate Surveys
189
1.6.1 General
189
1.6.2 Intermediate survey for hull
190
1.7 Special surveys
191
1.7.1 General
191
1.7.2 Special surveys for hull
191
1.7.3 Special surveys for Machinery Installations and Electrical Installations
197
1.8 Boiler and thermal oil heater surveys
204
1.8.1 General
204
1.9 Propeller shafts and stern tube shaft surveys
204
1.9.1 General
204
1.10 Automatic and Remote Control System Surveys
204
1.11 Annual Surveys for Inert Gas Systems
204
1.11.1 General
204
1.11.2 Alarm and Safety Device
205
1.12 Special Periodical Surveys for Inert Gas Systems
206
17
1.12.1 General
206
1.12.2 Separate Inert Gas Generator System
207
1.12.3 Gas Stored in Bottles System
207
1.13 Annual Surveys – Production Facilities
207
1.14 Special Periodical Surveys - Production Facilities
207
1.15 Annual Surveys - Mooring Systems
208
1.15.1 Annual Surveys - Spread Mooring Systems
208
1.15.2 Annual Surveys - Single Point Mooring (SPM) Systems
208
1.16 Special Periodical Surveys - Mooring Systems
209
1.17 Annual Surveys - Import and Export Systems
210
1.18 Special Periodical Survey – Import and Export Systems
211
PART 9: SPECIFIC REGULATIONS
213
1 APPENDIX I: THE CONCEPT AND APPLICATION OF ENVIRONMENTAL SEVERITY FACTORS (ESFS) FOR SHIP-TYPE SITE-DEPENDENT SITE-DEPENDENT DESIGNED FLOATING OFFSHORE INSTALLATIONS INSTALLATIONS
214
1.1 ESFs of the Beta Type
214
1.2 ESFs of the Alpha Type
216
2 APPENDIX II: THE MODIFICATION OF SHIP-TYPE FLOATING PRODUCTION
SYSTEM CRITERIA FOR SITE-SPECIFIC ENVIRONMENT CONDITIONS
218
2.1 Deck Load
218
2.1.1 Loads for On-Site Operation
218
2.1.2 Load in Transit Condition
220
2.2 Sloshing Loads
220
18
2.3 Green Water
220
2.4 Bow Impact Pressure
221
2.5 Bottom Slamming Pressure
222
2.6 Local Structure of the Hull Supporting Deck Mounted Equipment
224
2.6.1 General
224
2.6.2 Load Pattern No. 1
224
2.6.3 Load Pattern No. 2
231
3 APPENDIX III: EXTENT OF STRUCTURES IS TO BE ANALYSED BY FINITE ELEMENT MODELS (FEM)
232
3.1 Methods of Approach and Analysis Procedures
232
3.2 3D Finite Element Models
232
3.3 2D Finite Element Models
232
3.4 Local Structural Models
232
3.5 Load Cases
232
4 APPENDIX IV: LOAD CRITERIA
234
4.1 General
234
4.1.1 Load Components
234
4.2 Static Loads
234
4.2.1 Still-water Bending Moment
234
4.3 Wave-induced Loads
235
4.3.1 General
235
4.3.2 Horizontal Wave Bending Moment and Shear Force
235
4.3.3 External Pressures
237
19
4.4 Nominal Design Loads
243
4.4.1 Hull Girder Loads – Longitudinal Bending Moments and Shear Forces
243
4.4.2 Local Loads for Design of Supporting Structures
244
4.4.3 Local Pressures for Design of Plating and Longitudinals
244
4.5 Combined Load Cases
245
4.5.1 Combined Load Cases for Structural Analysis
245
4.5.2 Combined Load Cases for Failure Assessment
245
4.6 Sloshing Loads
246
4.6.1 General
246
4.6.2 Strength Assessment of Tank Boundary Structures
246
4.6.3 Sloshing Pressures
247
4.7 Impact Loads
256
5 APPENDIX V: FATIGUE LIFE
257
5.1 Floating storage units with length more than 150 m
257
5.1.1 General
257
5.1.2 Procedures
257
5.1.3 Spectral Analysis
258
5.2 Floating storage units with length less than 150 m
259
6 APPENDIX VI: FAILURE CRITERIA – YIELDING
260
6.1 Floating storage units with length more than 150 m
260
6.1.1 General
260
6.1.2 Structural Members and Elements
260
6.1.3 Plating
261
20
6.2 Floating storage units with length less than 150 m
262
7 APPENDIX VII: MACHINARY, PROCESS SYSTEM ON FLOATING STORAGE UNIT
263
7.1 General
263
7.2 Definitions
263
7.3 Plans and Particulars to be Submitted
265
7.3.1 Plans and Particulars to be Submitted
265
7.3.2 Details
267
7.3.3 Hydrocarbon Production and Process Systems
267
7.3.4 Process Support Systems
269
7.3.5 Marine Support Systems
270
7.3.6 Electrical Systems
271
7.3.7 Instrumentation and Control Systems
273
7.3.8 Fire Protection and Personnel Safety
274
7.3.9 Arrangements for Storage Tank Venting and Inerting
275
7.3.10 Arrangements for Use of Produced Gas as Fuel
275
7.3.11 Start-up and Commissioning Manual
275
7.4 Hydrocarbon Production and Process Systems
276
7.4.1 General
276
7.4.2 Process Design
276
7.4.3 Facility Layout
277
7.4.4 Piping and Instrumentation Design
280
7.4.5 Emergency Shutdown (ESD) Stations
282
21
7.4.6 Pressure Relieving and Hydrocarbon Disposal Systems
282
7.4.7 Spill Containment, Open and Closed Drain Systems
286
7.4.8 Protection from Ignition by Static Charge
288
7.4.9 Major Equipment Requirements
288
7.4.10 Process Piping Systems
293
7.4.11 Packaged Process Units
294
7.5 Process Support Systems
295
7.5.1 General
295
7.5.2 Component Requirements
295
7.5.3 System Requirements
297
7.6 Electrical Systems
302
7.6.1 Applicability
302
7.6.2 Design Considerations
302
7.6.3 Rotating Electrical Machinery
306
7.6.4 Transformers
306
7.6.5 Switchgear
307
7.6.6 Wire and Cable Construction
312
7.6.7 Hazardous Areas
313
7.6.8 Ventilation
315
7.6.9 Cable Support and Installation
316
7.6.10 Power Source Requirements
316
7.6.11 Emergency Source of Power
318
7.6.12 Battery Systems
318
22
7.6.13 Short Circuit Current Calculations and Coordination Study
318
7.6.14 Protection from Ignition by Static Charges
319
7.7 Instrumentation & Control Systems
319
7.7.1 Applicability
319
7.7.2 Components
320
7.7.3 Instruments
321
7.7.4 Alarm Systems
321
7.7.5 Control and Monitoring
323
7.7.6 Safety Systems
324
7.7.7 Shutdown Systems
326
7.7.8 relief valves
326
7.7.9 Shutdown valves, blowdown valves, diverter valves
327
7.8 Fire Protection and Personnel Safety
327
7.8.1 Scope
327
7.8.2 Fire Fighting Systems
327
7.8.3 Fire and Gas Detection and Alarm Systems
343
7.8.4 Structural Fire Protection
344
7.8.5 Muster Areas
348
7.8.6 Means of Escape
349
7.8.7 Lifesaving Requirements
349
7.8.8 Personnel Safety Equipment and Safety Measures
350
7.9 Survey During Construction and Commissioning
351
7.9.1 Construction Surveys
351
23
7.9.2 Commissioning and Start-up Surveys
352
7.9.3 Start-up and Commissioning Manual
353
7.10 Survey for Maintenance of Class
360
7.10.1 Annual Survey
360
7.10.2 Special Survey
361
8 APPENDIX VIII: UNDERWATER INSPECTION PROCEDURE
363
8.1 Introduction
363
8.2 Conditions
363
8.2.1 Limitations
363
8.2.2 Thickness Gauging and Nondestructive Testing
363
8.2.3 Tailshaft Surveys
363
8.2.4 Plans and Data
363
8.2.5 Underwater Conditions
364
8.3 Physical Features
364
8.3.1 Stern Bearing
364
8.3.2 Rudder bearings
365
8.3.3 Sea Suctions
365
8.3.4 Sea Valves
365
8.4 Procedures
365
8.4.1 Exposed Areas
365
8.4.2 Underwater Areas
365
8.4.3 Damage Areas
365
24
TCVN 6474-1:2007 NATIONAL STANDARD
TCVN 6474-1:2007
Second Edition
RULES FOR CLASSIFICATION AND TECHNICAL SUPERVISION OF FLOATING STORAGE UNITS PART 1: CLASSIFICATION
1 1.1
General requirements Application
1.1.1 National standard – Rules for classification and technical supervision of floating storage units are applicable for all self-propelled and non-propelled floating storage units operating in Vietnamese seas 1.1.2 This standard assigns the requirements on the classifications and constructions of floating storage units. 1.1.3 The technical Supervision and Classification for any types of floating storage units are to be carried out by Vietnam Register (hereinafter referred to as VR). 1.1.4 The floating storage units are to met the requirements specified in this standards and other appropriate requirements specified in relevant regulations and reference standards. 1.1.5 Requirements of other equivalent Rules or technical Standards may be used, if agreed by VR 1.1.6 This standard is applied to both new building, alteration, repair of units and in operation. 1.1.7 Units are designed or built under regulations, which is different from these regulations, will be considered for classification by VR if safety levels are equivalent. In this case, VR should be informed from initial design stage for accept the basis of design. 1.2
Reference documents
1.2.1 Vietnamese standards from TCVN 6259-1: 2003 to TCVN 6259-11: 2003 – Rules
25
TCVN 6474-1:2007
for classification and construction of sea going ships and enclosed amendments. 1.2.2 Vietnamese standards from TCVN 5309:2001 to TCVN 5319: 2001 – Mobile offshore units - Rules for classification and construction. 1.2.3 TCVN 6968: 2005 – Rules for offshore lifting apppliance 1.2.4 TCVN 6809: 2001- Rules for classification and construction of single point moorings
26
TCVN 6474-1:2007 2
Definition and explaination
2.1
Floating storage units
2.1.1 Purpose 2.1.1.1 A Floating storage unit provides hydrocarbon processing and/or hydrocarbon storage and offloads hydrocarbons. A Floating storage unit configuration may be ship-type, semi-submersible type and other types, which is
depended on its
functions as specified in 2.1.1.2. 2.1.1.2 The notations FPSO, FPS, FSO were chosen to provide a clear description of the function of each configuration. FPSO
Floating Production, Storage and Offloading System An FPSO processes, stores
and offloads hydrocarbons. Floating Production (and Offloading) System, An FPS processes and offloads
FPS
hydrocarbons without storage capacity. Floating Storage and Offloading System, An FSO stores and offloads
FSO
hydrocarbons without hydrocarbon processing facilities. 2.1.2 Major Elements 2.1.2.1 A Floating storage unit consists of several of the following major elements: (1)
Vessel
(2)
Position mooring (or station keeping system)
(3)
Production processing facilities
(4)
Import/export system
2.1.2.2 Classification boundaries encompass the vessel and position mooring system and may include the production facilities. Import/export systems may be classed, as well. 2.2
Type of floating storage units
2.2.1 Floating storage unit refers to a floating structure and the machinery, equipment and systems necessary for safety, propulsion (if fitted) and auxiliary services. The structural configurations of these units may be ship-shaped (with or without propulsion), column stabilized or any other configuration of a purpose-built floating vessel. 27
TCVN 6474-1:2007
2.2.2 Ship-type floating storage units are displacement hulls, either ship-shaped or bargeshaped, which have been designed or converted to a floating production and/or storage system. They may have propulsion machinery and/or station keeping systems. 2.2.3 Column-stabilized Floating storage units consist of surface piercing columns, submerged pontoons and a deck supported at column tops. 2.2.4 Other Types: Purpose-built and new configurations, such as tension leg platforms and spar buoys, belong to this category. 2.3
Coordinates and motion
2.3.1 The coordinates of floating storage units are given in figure 1-1 below. 2.3.2 The oscillated motion of floating storage units consists three straight oscillations and three rotating oscillations, which are called in accordance with relevant axis and illustrated in figure 1-1. 2.3.3 Three straight oscillation consists: •
Straight oscillation in X-axis – Surge
•
Straight oscillation in Y-axis – Sway
•
Straight oscillation in Z-axis – Heave
2.3.4 Three rotating oscillation consists: • • •
28
Rotating oscillation in X-axis – Roll Rotating oscillation in Y-axis – Pitch Rotating oscillation in Z-axis - Yaw
TCVN 6474-1:2007
z
x
y
Figure 1-1: The oscillations of floating storage unit 2.4
Production Facilities
2.4.1 General 2.4.1.1 The production facilities typically consist of the processing, safety and control systems, production support systems and auxiliary equipment for processing hydrocarbon liquid and gas mixtures from wells or other sources. Generally, a production facility includes all elements located onboard the Floating Installation vessel. These elements are located from (and including) the Christmas tree or the first inlet flange of the well fluid flow line inboard to (and including) the last onboard flange. Some important items related to production facilities are defined in the following paragraphs. 2.4.2 Production Support Systems 2.4.2.1 The production support systems include power generation and distribution, instrument and service air, potable water, fuel oil systems, HVAC, instrumentation, communication systems and firewater systems required to support hydrocarbon production and processing. 2.4.3 Hazardous Areas 2.4.3.1 A classified area is an area in which flammable gases or vapors are or may be present in the air in quantities sufficient to produce explosive or ignitable mixtures. 2.4.3.2 An area classification plan is a set of drawings indicating extent, boundaries and classification of all classified areas. 29
TCVN 6474-1:2007
2.4.3.3 Hazardous areas are divided into three zones: zone 0, zone 1 and zone 2, which are defined as follows: (1) Zone 0: in which an explosive gas/air mixture is continuously present or present for long periods. (2) Zone 1: in which an explosive gas/air mixture is likely to occur in normal operation. (3) Zone 2: in which an explosive gas/air mixture is not likely to occur, or in which such a mixture, if it does occur, will only exist for a short time. 2.4.4 Piping and Instrumentation Diagrams (P&IDs) 2.4.4.1 P&IDs show the size, design and operating conditions of each major process component, piping and valve designation and size, sensing and control instrumentation, shutdown and pressure relief devices with set points, signal circuits, set points for controllers, continuity of all line pipes and boundaries of skid units and process packages 2.4.5 Safety Analysis Function Evaluation (S.A.F.E.) Charts 2.4.5.1 The S.A.F.E. charts list all process components and emergency support systems with their required sensing devices and the functions to be performed by each device and relate all sensing devices, shutdown valves, shutdown devices and emergency support systems to their functions. 2.5
Position Mooring System
2.5.1 General 2.5.1.1 A Position Mooring System keeps the vessel on station. The Position Mooring System includes mooring lines, connectors and hardware, winches, piles, anchors and thrusters. For a single point mooring system, the turret, turntable, disconnecting system, buoy, anchoring legs, etc., are also part of the system. 2.5.2 Spread Mooring 2.5.2.1 A spread mooring is a system with multiple catenary mooring lines anchored to piles or drag anchors at the sea bed. The other end of each line is individually attached to winches or stoppers on the vessel through fairleads as necessary. A catenary mooring line may have one or more line segments, in-line buoy(s) (spring buoy) or sinker(s) (clumped weight) along the line. 30
TCVN 6474-1:2007
2.5.3 Single Point Mooring (SPM) A single point mooring allows the vessel to weathervane. Three typical types of single point mooring systems that are commonly used are described below: 2.5.3.1 CALM (Catenary Anchor Leg Mooring): A catenary anchor leg mooring system consists of a large buoy anchored by catenary mooring lines. The vessel is moored to the buoy by soft hawser(s) or a rigid yoke structure. 2.5.3.2 SALM (Single Anchor Leg Mooring): A single anchor leg mooring system consists of an anchoring structure with built-in buoyancy at or near the water surface and is itself anchored to the seabed by an articulated connection. 2.5.3.3 Turret Mooring: A turret mooring system consists of a number of mooring legs attached to a turret that is designed to act as part of the vessel, allowing only angular relative movement of the vessel to the turret, so that the vessel may weathervane. The turret may be mounted internally within the vessel or externally from the vessel bow or stern. Typically, a spread mooring arrangement connects the turret to the seabed. 2.5.3.4 Yoke Arm A yoke arm is a structure at the end of the vessel that only allows angular relative movement between the vessel and the mooring attachment to the seabed. 2.5.3.5 The above mentioned types of single mooring system are illutrated in figures below:
31
TCVN 6474-1:2007
Figure 1-2 : Spread mooring
Figure 1-3: External turret mooring 32
TCVN 6474-1:2007
Figure 1-4: Internal turret mooring
Figure 1-5: CALM with rigid york structure 33
TCVN 6474-1:2007
Figure 1-6: CALM – Soft hawser
Figure 1-7: SALM with an articulated connection
34
TCVN 6474-1:2007
Figure 1-8: SALM with vertical hawser and connection rope 35
TCVN 6474-1:2007
2.5.4 Dynamic Positioning and Thruster Assisted Systems 2.5.4.1 A dynamic positioning system is defined as all of the equipment necessary to provide a means of controlling the position and heading of a Floating Installation within predetermined limits by means of vectored thrust. 2.5.4.2 A thruster-assisted system provides controlled thrust to assist the main (usually static) mooring system and reduce component loading of the main mooring system 2.6
Subsea System
2.6.1 General 2.6.1.1 A subsea system is a flexible/articulated piping system providing a conduit for the hydrocarbons from the subsea pipeline to the surface components. It includes subsea pipelines, subsea well system and risers. 2.6.2 Floating Hose 2.6.2.1 A floating hose is a floating conduit used to export hydrocarbons from a point of storage/production, either an SPM or vessel's manifold to a receiving vessel's manifold for transport. 2.6.3 On Bottom Flexible Flow Lines 2.6.3.1
These lines are conduit used to connect one subsea location to another subsea location prior to a vertical conveyance by the riser system to the surface.
2.6.4 Pipe Line End Manifold (PLEM) A PLEM is the assemblage of valves and components or equipment performing the equivalent function connecting the production facilities to the pipeline carrying product to or from the shore, an offloading system or to another facility. 2.6.4.1 Import PLEM: Import PLEM is the equipment connecting to the Import Riser and the import supply line or wellhead. 2.6.4.2 Export PLEM: Export PLEM is the equipment connection between the Export Riser and the product discharge line 2.6.5 Riser
36
TCVN 6474-1:2007
A riser is a subsea rigid or flexible pipe that connects the surface facilities with the sea floor and thus the conduit for fulfilling the desired function of conveying fluids, gas, electrical power, etc. 2.6.6 Riser System The riser system includes the entire assemblage of components, control systems, safety systems and tensioning devices that ensure the integrity of the riser throughout its operation. 2.6.7 Riser Support Riser support comprises any structural attachments, including buoyancy devices that are used to give structural integrity to the riser or transfer load to the supporting structure. 2.6.8 Submerged Jumper Hoses Jumper hoses are flexible lines used in conjunction with rigid risers to accommodate the relative motion between the Floating Installation and the submerged top of the riser. Jumper hoses may also be used to connect the subsea manifold to the wellhead.
37
TCVN 6474-1:2007 3
Classification
3.1
Class assignation
3.1.1 Units will be assigned a class and registered in VR Offshore Register book by VR when it is designed, constructed and surveyed in compliance with requirements of these regulations. 3.2
Class of floating storage units
3.2.1 Scope of classification for floating storage units 3.2.1.1 Scope of classification for floating storage units consists three main items: hull of floating storage units, position mooring systems and production facilities. 3.2.1.2 Other items such as import/export system may be classed if requested by floating storage unit’s owner. 3.2.2 Basic characters of classification for floating storage units The floating storage unit classed by VR will be assigned a class with following characters when it was found satisfactory with the requirements specified in this standards: VR or ∗VR or (∗)VR
∗
VR : Symbol of VR showing the supervision of units in compliance with the requirements of this standard. *
: Construction carried out under supervision of VR
*
: Construction carried out under supervision of a Classification Society authorized
or/and recognized by VR (*) : Construction without supervision of VR or under supervision of a Classification Society. These characters also use when classification service was carried out by VR for specific items or parts of floating storage unit as requested by owner. 3.2.3 Class notations of hull of floating storage units Characters of the classification and notations of the hull are as follows: * VRH : Hull design has been approved by VR in compliance with the Rules and hull has been constructed under supervision of VR in compliance with the approved plans and drawings. 38
TCVN 6474-1:2007
* VRH : Hull design has been approved by a Classification Society recognized or/and authorized by VR and hull has been constructed under supervision of that Society and then surveyed by VR in compliance with the Rules. (*) VRH : Hull design has not been approved by any Classification Society (or has been approved by an unrecognized Classification Society) and hull has been constructed without supervision of any classification (or under supervision of an unrecognized Classification Society) and then surveyed by VR in compliance with the Rules. 3.2.4 Class notations of machinery of floating storage units Due to almost existing and new building floating storage units are non-propelled and machinary systems in floating storage unit consist electrical generators and other machinary in machinary room, following characters of classification is assigned by VR to machinary system of floating storage units. The mentioned machinary system here is meant electrical generator and other machirary in machinary room: * VRM: Machinery installations design has been approved by VR in compliance with the Rules and machinery installations have been constructed under supervision of VR in compliance with the approved plans and drawings. * VRM : Machinery installations design has been approved by a Classification Society recognized or/and authorized by VR and machinery installations have been constructed under supervision of that Society and then surveyed by VR in compliance with the Rules. * VRM : Machinery installations design has not been approved by any Classification Society (or has been approved by an unrecognized Classification Society) and machinery
installations
have
been
constructed
without
supervision
of
any
Classification Society (or under supervision of an unrecognized Classification Society) and then surveyed by VR in compliance with the Rules. 3.3
Subdivision notation and additional notations
3.3.1 Subdivision notation A Floating storage unit which complies with the applicable requirements of Part 9 " Subdivision" TCVN 6259-9: 2003, one of the Subdivision distinguishing notations is added to the characters of classification as
1
, 2 , 3 . These figures denote the condition that the 39
TCVN 6474-1:2007
unit still remains afloat in a satisfactory state of equilibrium in compliance with the requirements of Chapter 3, Part 9 TCVN 6259-9: 2003 if any one compartment or any two or three adjacent compartments of her is/are flooded. 3.3.2 Notation for in water survey of submerged part of hull of floating storage units. If requested by unit’s owner and the floating storage unit was found satisfactory with VR’s requirement for in-water survey of submerged part of hull (see clause 1.2.4 TCVN 6474-8), the floating storage unit shall be assigned following additional notation: IWS (in water survey) 3.3.3 Notation for enhanced survey programme For floating storage units, which are to be applied the enhanced survey programme (see clause 1.7.2 TCVN 6474-8) in surveys for class maintenance in appropriate requirements specified in part 1B TCVN 6259-1: 2003, the class character of floating storage unit will be added following notation: ESP (Enhanced Survey Programme). 3.3.4 Notation for function of floating storage units 3.3.4.1 The charaters of classification of floating storage units will be added following notations depended on functions of the units: FPSO – Floating, production, storage and offloading systems FPS
- Floating, production and offloading systems
FSO - Floating, storage and offloading systems 3.3.4.2 If the floating storage unit has a function differed with functions mentioned in 3.3.4.1,
the additional notation for function of floating storage unit will be
considered by VR for each case. 3.3.5 Dynamic positioning system 3.3.5.1 If dynamic positioning systems were installed for station keeping purposes in floating storage unit , the charaters of classification of floating storage units will be added a notation DPS. 3.3.6 Notations for location and operational condition
40
TCVN 6474-1:2007
If the unit is operated in a particular location and when maximum loads incluced by wave, wind, ice and current in that location have been considered then the location, loads and ice reinforcement shall be stated in classification certificate . 3.3.7 Example for charaters and notations of classification * VRH, *VRM FSO IWS BACH HO FIELD – Class notation of floating unit, storage, offloading, unit has been constructed under supervision of VR, unit has notation for inwater survey of submerged part of hull, the unit is operated in Bach Ho field. * VRH, *VRM FPSO EPS DPS DRAGON FIELD – Class notation of floating unit, storage, production, offloading, Construction carried out under supervision of a Classification Society authorized or/and recognized by VR, unit has notation for Enhanced Survey Programme, unit has notation for dynamic positioning system, the unit is operated in Dragon field. 3.4
Class maintenance
3.4.1 The units which have been classed with VR will maintain the assigned class and character until, as a result of surveys inspections or test which have been carried out, the units are found to be in fully compliance with the relevant requirements of this standard. 3.4.2 Any damage or defect which may affect the class assigned is to be reported to VR without delay and an application for surveys is to be submitted by Owner/operator or their representative . 3.5
Suspension of Class
3.5.1.1 The class assigned to a unit by VR will be suspended under any one of the following conditions: (1) Class is suspended for any use, operation, loading condition or other application of any vessel for which it has not been approved by VR and that affects or may affect classification or the structural integrity, quality or fitness for a particular use or service. (2) If the periodical surveys required for maintenance of class are not performed by the due date and no Rule-allowed extension has been granted by VR, class will be suspended
41
TCVN 6474-1:2007
(3) If recommendations issued by the VR are not performed within their due dates, class will be suspended. (4) When the Owner fails to repair such damages and defects that affect the class of the unit in accordance with VR requirements; (5) Class will be suspended for any damage, failure, deterioration or repair that has not been completed as recommended by VR 3.5.1.2 If proposed repairs have not been submitted to VR and agreed upon prior to commencement, class may be suspended 3.6
Lifting of Suspension
3.6.1 Class will be reinstated after suspension for (1) overdue surveys upon satisfactory completion of the overdue surveys. (2)
overdue
recommendations
upon
satisfactory
completion
of
the
overdue
recommendation. (3) overdue continuous survey items upon satisfactory completion of the overdue items. 3.7
Withdrawal of class and chance character of classification
3.7.1 The class assigned to a unit by VR will be withdrawal under any one of the following conditions: (1) If the circumstances leading to suspension of class are not corrected within the time specified, the unit's class will be withdrawal; (2) VR recognized that the unit can no longer be used ; (3) When requested by the Owner of the unit; (4) Survey fees are not paid by the owner . 3.7.2 VR will change or wihdraw class notation stated in Classification certificate if there is change or violation of principle conditions which are basis for classification of unit. 3.8
Reclassification
3.8.1 When reclassification or class reinstatement is desired for a unit for which the class previously was assigned by VR and has been withdrawn, a special survey for reclassification, appropriate to the age and technical conditions of the unit, will be carried out by VR. 42
TCVN 6474-1:2007
3.8.2 If, at such survey, the unit is found that its conditions are fully compliance with the regulations, VR may reinstate its original class or assign such other class as may be deemed necessary . 3.9
Requisition for a survey
3.9.1 Classification survey The classification survey and registration will be carried out by VR when received a requisition by unit’s owner or shipyard. 3.9.2 Survey for class maintenance The periodical survey for class maintenance will be carried out when received a requisition for a survey by unit’s owner, barge captain or owner’s representative. 3.10 Certificate of Classification
3.10.1 Issurance of Classification Certification Upon the completion of the construction survey, classification survey for first entry of reclassification survey of a unit, if it is found that the unit complies fully with this standard, a classification certificate will be issued to the floating storage unit by VR. 3.10.2 Endorsement of Classification Certificates The Classification Certificate for Units issued by VR will continue to be valid, provided that the units are subjected to the annual surveys for maintenance of class as prescribed of the Regulations and results of the surveys are found satisfactory to the requirements of the Regulations 3.10.3 Issuance of Provisional Classification Certificates Pending the issuance of the Classification Certificate, where a result of surveys is found that the unit is in a fit an efficient condition and in compliance with the regulations, VR may issue a corresponding Provisional Classification Certificates to enable the unit to be put into service in the shortest possible period of time . 3.10.4
Validity of Certificate of Classification and Provisional Certificate of Classification
3.10.4.1A Certificate of Classification shall be valid for a period not exceeding five years. The validity of the Certificate of Classification may be extended for five months from the date of completion of the Special Survey when a registered unit has been 43
TCVN 6474-1:2007
subjected to a Special Survey in accordance with the Rules to the satisfaction of the Surveyor. 3.10.4.2A Certificate of Classification, the validity of which has been extended as described in 3.10.4.1 above, is to become invalid upon issue of the new Certificate of Classification. 3.10.4.3A Provisional Certificate of Classification is valid for five months from the date of issue of the Provisional Certificate of Classification. The Provisional Certificate of Classification is to become invalid upon issue of the Certificate of Classification. 3.10.4.4The full term classification certificate and provisional classification certificate is invalid when the class has been withdrawn as specified in clause 3.7. 3.10.4.5The certificate of classification of the unit is invalid if not satisfied the requirements in 3.10.2. 3.10.5 Retention, Reissue, Rewriting and Return of Certificate of Classification 3.10.5.1The master of a unit is to keep a Certificate of Classification or a Provisional Certificate of Classification on board the ship and present the same to VR upon request. 3.10.5.2The owner or master of a ship is to request VR without delay to reissue a Certificate of Classification or a Provisional Certificate of Classification when the same is lost or soiled. 3.10.5.3The owner or master of a unit is to request VR without delay to rewrite a Certificate of Classification or a Provisional Certificate of Classification when the particulars described in the same are changed. 3.10.5.4The owner or master of a unit is to return a Provisional Certificate of Classification when the Certificate of classification has been issued under the provisions of 3.10.1 or five months have passed from the date of issue of a Provisional Certificate of Classification and is to return the old Certificate if the Certificate has been issued under the provisions of 3.10.1 above to the VR immediately except the case the Certificate was lost. 3.10.5.5The owner or master of a unit is to return a Certificate of Classification or a Provisional Certificate of Classification to VR immediately when the class is withdrawn under 3.7. 3.10.5.6The owner or master of a unit is to, when a lost Certificate of Classification or a lost 44
TCVN 6474-1:2007
Provisional Certificate of Classification is found after reissuing the same under 3.10.5.2 above, return the Certificate found to VR immediately.
45
TCVN 6474-1:2007 4
Technical documentation
4.1
Design documents for submission
4.1.1 Design documents for submission 4.1.1.1 Prior to the commencement of the work on the new construction, modification of units or manufacture of materials and article liable to supervision by VR, the technical design documentation within a scope determined in the relevant parts of the Rules shall be submitted to VR for review and approval. If necessary, VR's may require the documents to be submitted on a wider scope. 4.1.1.2 The scope of technical documentation for units or products of special design, submitted for review and approval by VR is established in every particular case upon agreement with VR. 4.1.2 Amendments to approved technical documentation The unit designer, who intends amendments to the technical documentation approved by VR shall submit the amendment documentation to VR enclosed with the unitowner's acceptance for VR review and approval before work commencement. 4.1.3 Submission of final design documentation The final design documentation shall be submitted to VR for approval before VR issues a Classification Certificate to the unit. 4.1.4 Requirements for the technical documentation for approval 4.1.4.1 There must be enough data in the technical documentation submitted to prove that the requirements of the Rules have been fully satisfied. 4.1.4.2 Calculations for determining the parameters or data by a standard are to comply with the requirements of this standard, or by a method approved by VR.The calculation method used must ensure accuracy. 4.1.4.3 Approval of the technical documentation relating to the requirements of the Rules is confirmed by putting corresponding stamps of VR on it. 4.1.5 Duration of validity of approved technical documentation 4.1.5.1
46
Duration of validity of technical documentation approved by VR is as follows:
TCVN 6474-1:2007 •
The technical documentation of a unit for new construction approved by VR remains valid for a period of 5 years from the date of stamping.
•
Interval between the date of approval of the documentation and the commencement of the work on the construction a unit does not exceeds two and a half years
By the expiry of above term, the designer is required to submit the design documentation again for approval. The scope of added documentation is to be accepted by VR. 4.1.5.2 In addition to requirements specified in 4.1.5.1 above, the technical documentation approved by VR shall be submitted to alterations necessitated by the provisions of amendments to the International Conventions and International Codes to which the country whose flag a unit flies is a party. 4.1.5.3 In addition, all the documents and plans approved by VR shall be altered to comply with the instructions circulated by VR which provides for their unconditional fulfillment in units under construction, reconstruction or conversion. 4.2
Documents issued by VR
4.2.1 Documents issued in compliance with the Rules 4.2.1.1 The units classed with VR shall get the certificates specified in 3.10 of this part if they have been surveyed and certified by VR Surveyors in compliance with the requirements of the Rules. 4.2.1.2 Besides the certificates referred in 4.2.1.1 above, VR shall issue survey reports and other technical documents in compliance with the contents and survey results carried out by Surveyor. 4.2.2 Seaworthiness certificate 4.2.2.1 The following Vietnamese flagged units shall obtain the Seaworthiness certificate if they have been surveyed and certified by VR in compliance with the requirements of these Rules and other applicable Rules as well as the requirements of the International Conventions applicable for the units: (1) Units classed with VR (2) Units dually classed with VR and another Classification Society (3) Units having double classes of which one is VR's class 4.2.2.2 The validity of the Seaworthiness certificate shall not exceed the validity of the 47
TCVN 6474-1:2007
classification certificate and the certificates issued in accordance with the requirements of the national Regulations and/or the certificates issued in compliance with the requirements of the International Conventions (if applicable), the next periodical surveys and/or the period which the VR set out for the unitowner to clear the recommendations, whichever is shortest.
48
TCVN 6474-1:2007 5 5.1
Classification Surveys Classification Surveys during Construction
5.1.1 General In the Classification survey during construction, surveys are to be carried out on hull construction, equipment, machinery, construction of fire protection, means of escape, fire extinguishing arrangements, electrical installation, stability and load line and positioning systems in order to ascertain that they meet the relevant requirements of VR. 5.2
Submission of Plans and Documents for Approval
In the Classification Survey during construction, plans and documents as listed below are to be submitted for the approval by VR before the work is commenced, if applicable: 5.2.1 Hull of floating storage units 5.2.1.1 Ship-type units (1) General arrangement; (2) Transverse sections showing scantlings; (3) Longitudinal sections showing scantlings; (4) Shell expansion ; (5) Construction profile; (6) Cross curves of stability (7) Curves of righting moment and wind heeling moment (8) Capacity plans and sounding tables of tanks (9) Summary of distributions of fixed and variable weights for each reviewed condition; (10) Type, location and quantities of permanent ballast; (11) Plans indicating arrangement of watertight compartments, openings, their closing, their closing applicances, etc. necessary for calculation of stability; (12) Diagrams showing the extent to which the watertight and weathertight integrity is intended to be maintained; (13 ) Construction of frames, pillars and longitudinal girders under deck; (14) Construction of single bottoms and double bottoms and deck construction including details of helicopter deck, openings such as hatchways, wells, etc.; (15) Construction of watertight and oiltight bulkhead and deep tanks indicating the 49
TCVN 6474-1:2007
heights of the highest parts of tank and the tops of overflow pipes; (16) Tank bulkheads and flats with level of top of overflows and air pipes; (17) Construction of stem, sternframe, propeller post and rudder; (18) Construction of superstructures end deckhouses including their end bulkhead; (19) Arrangements to resist painting of both peaks and their vicinity; (20) Seatings of engines, boilers, thrust, blocks, plummer blocks, dynamos and other essentially important auxiliary machineries; (21) Foundations for anchoring equipment, industrial equipment, etc., where attached to hull structure, superstructures or deckhouses; (22) Turret mooring and yoke connection including mechanical details; (23) Corrosion control arrangements; (24) Methods and locations for nondestructive testing and procedures for thickness measurements; (25) Construction of machinery rooms, pump rooms and motor rooms including their casings and shaft tunnels ; (26) Masts, mast houses; (27) Pumping arrangements; (28) Arrangements and construction of watertight doors, hatchways, side scuttles and closing appliances of openings ; (29) Construction for fire protection with materials used in the construction of superstructures, bulkheads, decks, deckhouses, trunks, stairways, deck coverings, etc. and arrangements of closing appliances of openings and means of escape; (30) Fire extinguishing arrangements; (31) Details of inspection facilities; (32) Details of welding procedures; (33) Details of painting and corrosion control procedures; (34) Details of maintenance and inspection procedures; (35) Stability information booklet; (36) Loading manual, where the loading manual is to be provided in accordance with the requirement of 1.1.4 part 3; (37) Temporary mooring arrangements, towing arrangements and arrangements of positionings systems for a long period of time; 50
TCVN 6474-1:2007
(38) Arrangements and construction of positioning systems; (39) Plan indicating design loadings for all decks; (40) Details of docking plan and in-water inspection procedures; 5.2.1.2 For column stabilized type units In addition to the relevant plans or documents specified in 5.2.1.1, Plans and documents for construction of all columns, lower hull, upper hull, bracings, footings and below documents are to be submitted for the approval by VR: The following information is to be submitted and appropriate relevant information is to be provided in the Operating Manual: (1) Inspection plans for all compartments below the maximum immersion line; (2)
Closure means for external openings whose lower edges are below the levels to whichweathertight integrity is to be ensured;
(3) A plan identifying the disposition (open or closed) of all non-automatic closing devices and locations of all watertight and weathertight closures for each mode of operation afloat is to be submitted for review prior to the vessel’s delivery. Upon satisfactory review, the plan is to beincorporated into the Operating Manual; (4) Means for detection of and recovery from flooding of compartments that lie partly or completely below the operating or survival drafts and are adjacent to the sea or contain salt water piping or pumping equipment; (5) The estimated time to deballast the vessel from operating to survival draft; (6) Means of preventing progressive flooding via sounding tubes, tank vents and overflows, ventilating systems, trunks, etc., from compartments within the assumed damaged areas; (7) Means of detecting flooding of and means of water removal from void spaces not connected to the bilge or ballast systems; (8) Means of closure and evacuation of water from chain lockers;
(9) The remaining or “residual” range of stability resulting from the damaged condition and the type and location of appropriate closures to prevent downflooding; (10) Means of sounding tanks; (11) A description of the ballast piping and control system describing the items listed : 51
TCVN 6474-1:2007
(a) Redundancy of pumps, valves and controls and alternate means of valve operation. (b) Valve operating and indicating means. (c) Means of manual and remote operation of ballast pumps and valves. (d) Communication means between ballast control spaces and pump rooms, including those means of communication that are independent of the ship’s service communication system. (e) Means of determining the failure of critical ballast system components and means to overcome their failure. 5.2.2 Position Mooring System 5.2.2.1 Mooring Arrangement or Pattern; 5.2.2.2 Details of winching equipment; 5.2.2.3 Details of anchoring system; 5.2.2.4 Details of mooring line segments; 5.2.2.5 Connections at anchors and between mooring line segments; 5.2.2.6 Details of in-line (spring) buoys; 5.2.2.7 Details of buoy for CALM system (see definition in 2.5) ; 5.2.2.8 Details of SALM structures, if appropriate (see definition in 2.5) ; 5.2.2.9 Details of Turret System to show turret structure, swivel, turntable and disconnecting device ; 5.2.2.10Details of yoke (hard or soft) connecting the vessel and CALM/SALM structure(see definition in 2.5) ; 5.2.2.11Environmental Report; 5.2.2.12Mooring Analysis describing method of load calculations and analysis of dynamic system todetermine the mooring line design loads ; 5.2.2.13Model Test report when the design loads are based on model tests in a wave basin (applicable only for first unit in new building series); 5.2.2.14Thruster specifications and calculations of a system with dynamic positioning system for thruster forces and power to counteract environmental forces; 5.2.3 Production Facilities and Production Support Facilities The following design documentation and documentation specified in appendix VII, Part 9 of a floating production and storage system is required to be submitted, as applicable : 52
TCVN 6474-1:2007
(1) General Arrangements showing arrangements and locations of storage tanks, machinery, equipment, living quarters, fire walls, emergency shutdown (ESD) stations, control stations, crude loading and discharge stations and the flare (see Part 5); (2) Hazardous Area Classification Plans, as defined in 2.4.3 herein; (3) Details of Storage Tank Venting and Inerting indicating arrangements for storage tank venting and inerting; (4) Arrangements for Use of Produced Gas as Fuel showing piping and control arrangements for use of produced gas as fuel showing details of double wall or ducting arrangements for the pipe runs in way of the safe space; (5)
A design specification that is to include design parameters (environmental conditions,
geographical
location
of
the
unit,
external
loads,
pressures,
temperatures, etc.), standards and codes adopted throughout the design, construction and testing stages and the process description; (6)
A description of the field development plan, including well fluid properties, production rates, gas oil ratios, processing scheme, well shut-in pressures;
(7) Process flow sheets showing major process equipment components, process piping, material balance, normal pressures and temperatures at the inlet and outlet of each major component; (8) Piping and Instrumentation Diagrams (P&IDs) indicating location of all sensing and controlling elements on the process and production support systems, sizing and material specification of piping and the associated components, maximum design pressure and temperature ratings, piping strength and flow calculations ; (9) List of electrical equipment located in hazardous areas together with the certificates issued by an independent testing laboratory to show suitability of their use in the intended location; (10) Electrical one line diagram showing ratings of all generators, motors, transformers, type and size of wires and cables. Types and rating of circuit breakers with the setting, interrupting capacity of circuit breakers and fuses; (11) Short circuit current calculations and coordination data giving the maximum calculated short circuit current available at the main bus bars and at each point in the distribution system in order to determine the adequacy of the interrupting 53
TCVN 6474-1:2007
capacities of the protective device; (12) Safety Analysis, including Safety Analysis Function Evaluation (S.A.F.E.) charts; (13) Emergency shutdown system (ESD) relating to all sensing devices, shutdown valves, shutdown devices and emergency support system to their functions and showing ESD logic for the complete process and the subsea valves system; (14) Emergency backup and uninterrupted power source, supply and the consumers; (15) Pressure vessel (fired and unfired) and heat exchangers, design dimensional drawings, design calculations, material specifications, pressure and temperature ratings, together with weld details and the details of their support; (16) Pressure relief and depressurization vent systems showing arrangements sizing of the lines, capacities of the relief valve, materials, design capacity, calculations for the relief valves, knock out drums, anticipated noise levels and gas dispersion analyses; (17) Complete details of flares, including pilots, igniters and water seal and design calculations, including stability and radiant heat analyses; (18) Schematic plans for the production support systems, including the size, wall thicknesses, maximum design working pressure and temperature and materials for all pipes and the type, size and material of valves and fittings; (19) Compressors, pumps selection and control arrangements, including specification data sheet; (20) Fire and gas detection system showing the location and detailed description of all power sources, sensors, annunciation and indication, set point for the alarm system; (21) Passive and active fire protection system indicating locations of fire walls, fire pumps and their capacities, main and backup power supply, fixed and portable fire extinguishing, and fire fighting systems and equipment. In this regard, supportive calculations are to be submitted to show the basis of capacities and quantities of fire extinguishing equipment; (22) Escape route plan ; (23) Startup and commissioning procedures detailing sequence of events for inspection, testing and startup and commissioning of equipment and system; (24) Installation, Hook-up and Commissioning Procedures (see part 7); 5.2.4 Import/export system 54
TCVN 6474-1:2007
The design documentation required to be submitted is specified in Part 6. 5.2.5 Machinery installations and electrical installations 5.2.5.1 Machinery arrangement of machinery spaces, pump rooms, motor rooms and diagrams for internal communication systems including a diagram for an engineers' alarm systems; 5.2.5.2 For machinery installations used for the system or the equipment essential for the safety of the unit or for the propulsion of the unit ( only applicable to the unit which has the main propulsion machinery) : plans and documents required in the relevant in TCVN 6259-3:2003; 5.2.5.3 For machinery installations used solely for the operation which is the purpose of the unit: plans and documents specified in Chapter 2, Chapter 3, Chapter 9 and Chapter 10 TCVN 6259-3:2003 for diesel engines, steam turbines, boilers and incinerators, plans and documents specified in Chapter 13, TCVN 6259-3:2003 for piping systems, valves and fittings, plans and documents specified in Chapter 16, chapter 17. chapter 18 and chapter 19 for windlasses and mooring winches, refrigerating machinery, systems of automatic and remote control, spare parts, tools and instruments. 5.2.5.4 For the units provided with the dynamic positioning system Construction and control diagrams of dynamic positioning system 5.2.5.5 Plans and documents for electrical installations specified in 1.1.6 TCVN 62594:2003 5.2.5.6 Other plans and/or documents deemed necessary by the VR 5.2.6 Manuals and Procedures 5.2.6.1 Manuals (1) Loading Manual (see clause 1.1.4 part 3) (2) Trim and Stability(see clause 1.1.5 part 3) (3) Operation manual (see clause 1.1.6 part 3) 5.2.6.2 Procedures (1) Disconnecting Procedure, if applicable(see clause 1.1.7 part 7) (2) Drydocking Procedure (see clause 10.4) 55
TCVN 6474-1:2007
(3) Hook Up Procedures (see clause 1.2 part 7) (4) Import/Export System (see clause 1.1.4 part 6 and 1.1.6 part 7) (5) Installation Procedures and manuals (see clause 1.1 part 7) (6) Startup and Commissioning Procedures Survey (see clause 1.3 part 7) (7) Inspection Planning Document (see part 8) 5.3
Presence of Surveyor
5.3.1 The presence of the Surveyor is required at the following stages of the work in relation to hull and equipment: 5.3.1.1 When the material and equipments tests prescribed relevant parts are carried out 5.3.1.2 When the materials or parts manufactured away from the site are being applied to the unit concerned 5.3.1.3 When the tests of welding prescribed in relevant Part are carried out 5.3.1.4 When designated by the Society during shop work or sub-assembly 5.3.1.5 When each block is assembled 5.3.1.6 When hydrostatic tests, watertight tests and non-destructive tests are caried out 5.3.1.7 When hull is completed 5.3.1.8 When performance tests are carried out on closing appliances of openings, remote control devices, steering gears anchoring and mooring arrangements, piping, etc 5.3.1.9 When installing of rudder, profiling of keel line, measurement of principal dimensions, measurement of deflection of hull, etc. are carried out 5.3.1.10When the units are marked with the load lines in accordance with the requirements in TCVN 6259-11:2003 5.3.1.11When mooring systems are fitted on board and performance tests are carried out 5.3.1.12When sea trials are carried out 5.3.1.13When installing of fire extinguishing arrangements, and when the performance tests are carried out 5.3.1.14When inclining tests are carried out 5.3.1.15For column stabilized units, when the draught scales are fitted 5.3.1.16When deemed necessary by the VR; 5.3.2 The presence of the Surveyor is required at the following stages of the work in relation to machinery installations and electrical installations 56
TCVN 6474-1:2007
5.3.2.1 When the tests of materials of main parts machinery prescibed in Part 7-A TCVN 6259-7:2003 are carried out 5.3.2.2 When the materials are applied to the parts and the parts are installated on board 5.3.2.3 When machining of the main parts is finished and, if necessary, at a proper time during machining 5.3.2.4 In case of welded construction, before welding is commenced and when it is completed 5.3.2.5 When shop trials are carried out 5.3.2.6 When important machinery installations and electrical installations are installed on board 5.3.2.7 When performance tests are carried out on, remote control devices of closing appliances, remote control devices, steering gears, mooring arrangements, piping, etc 5.3.2.8 When each component consisting of a dynamic positioning systemis fitted on board and ferformance tests of each component are carried out 5.3.2.9 When sea trials are carried out 5.3.2.10When deemed necessary by the VR 5.3.3 The requirements specified in 5.3.1 and 5.3.2 may be modified having regard to the actual status of facilities, technical abilities and quality control at the work, except the case of sea trials and stability experiments 5.4
Hydrostatic and Watertight tests
5.4.1.1 Hydrostatic and watertight tests in the Classification Survey during construction are to be in accordance with the requirements in 2.1.6, Chapter 2, Part 1-B General , TCVN 6259-1:2003 5.4.1.2 Notwithstanding the requirement in 5.3.4.1, where considering the design condition and these are approved by the VR, hydrostatic and watertight tests are to be appropriate to the VR 5.5
Classification Survey of Unit not built under Survey
5.5.1 General 5.5.1.1 In the Classification Survey of Unit not built under VR's survey, the actual scantlings of main parts of the unit are to be measurd in addition to such 57
TCVN 6474-1:2007
examination of the hull and equipment, machinery installations, construction of fire protection and detection, means of escape, fire extinguishing arrangements, electrical instalations, stability and load lines and positioning systems as required for the special survey corresponding to the units' age in order to ascertain that they meet the relevant requirements in the Rules 5.5.1.2 The units intended to be surveyed in accordance with -1, necessary plans documents are required for the classification survey during construction are to be submitted for the approval by the VR 5.5.2 Tests 5.5.2.1 Hydrostatic and watertight tests are to be carried out in accordance with the requirements in 5.4 5.5.2.2 The stability experiments are to be carried out in accordance with the requirements in this standard. Where sufficient information based on previous stability experiments is available and neither alteration nor repair affecting the stability has been made after previous experiments, the stability experiments of the unit may be dispensed with. However, the dispension for stability experiments is not applied for column stabilized unit.
58
TCVN 6474-2:2007 NATIONAL STANDARD
TCVN 6474-2:2007
Second Edition
RULES FOR CLASSIFICATION AND TECHNICAL SUPERVISION OF FLOATING STORAGE UNITS PART 2: ENVIRONMENTAL LOADING AND DESIGN BASIC
Reference standards and definitions: see Part 1, TCVN 7474-1: 2007. 1
Environmental Loading and Design Basis
1.1
Design Basis
The design basis of a Floating Installation is to identify the production rate, storage capacity and loading capabilities. Since the system is site-specific, the environmental condition of the site directly influences the design of such a system. The effects of prevailing winds are to be considered to minimize the risk of vented or flared hydrocarbons to personnel, living quarters and evacuations means. Generally, atmospheric vents, flare systems and emergency gas release vents are to be arranged in such a way so that prevailing winds will carry heat and/or unburned gases away from potential ignition sources on the installation. The design environmental conditions are to include those for the operating, installation and transit portions of the Floating Installation's design life. This Part specifically covers the environmental design criteria for: (1) Position Mooring System. (2) Structural Strength and Fatigue Life Assessments 1.2
Design Documentation
The design documentation submitted is to include the reports, calculations, plans and other documentation necessary to verify the structural strength of the vessel itself and adequacy of the mooring system, production and other utility facilities and riser system (if included in the classification) for the intended operations. 59
TCVN 6474-2:2007 1.3
Design Conditions
1.3.1
Position Mooring System The position mooring system of a Floating Installation is to be designed to survive in the Design Environmental Condition and operate in the Design Operating Condition. For a disconnectable mooring system, the limiting condition at which the mooring system is to be disconnected or reconnected is to be specified.
1.3.1.1 Design Environmental Condition (DEC) The Design Environmental Condition (DEC) is defined as the extreme condition with a specific combination of wind, waves and current for which the system is to be designed. The DEC is to be one of the following combinations that results in the most severe loading case:
• 100-year waves with associated wind and current. • 100-year wind with associated waves and current. In areas with high current, additional design environmental load cases may need to be considered. The 100-year waves are normally characterized by a significant wave height with a spectral shape type and a range of associated peak wave periods. A minimum return period of 100 years for the DEC is required for Floating Installations. A minimum return period of 50 years will be specially considered if it is accepted by VR. Any environmental combinations with return periods shorter than that of the DEC which induce larger mooring load responses are to be used in the design. 1.3.1.2 Design Operating Condition (DOC) The Design Operating Condition (DOC) is defined as the limiting environmental condition that would require suspension of normal operations. 1.3.1.3 Design Installation Condition (DIC) The Design Installation Condition (DIC) is defined as the limiting environmental condition that would require suspension of installation operations. Specific limits
60
TCVN 6474-2:2007
on environmental conditions affecting safe operation during the installation phases described in Part 7 are to be established and documented. 1.3.1.4 Angular Separation of Wind, Current and Waves For single point mooring systems, which allow the vessel to weathervane, both collinear and non-collinear directions among wind, current and waves are to be considered. Proper angular separation for the DEC of wind, current and waves is to be determined based on the site-specific environmental study. If this information is not available, the following two angular combinations for non-collinear environments can be considered as a minimum: (1)
Wind and current are collinear and both at 30 degrees to waves.
(2)
Wind at 30 degrees to waves and current at 90 degrees to waves.
For spread mooring systems with limited change in vessel heading angles (less than 20 degrees) under design environmental loads, the collinear environments of wind, current and waves, which are generally controlling, can be used in design. For each design sea state, a long-crested sea without spectral energy spreading in direction is normally considered in the mooring analysis 1.3.2
Structural Strength and Fatigue Life
1.3.2.1 Project Site The site-specific wave conditions, including both long-term extreme events and wave scatter diagram data of wave height/period joint occurrence distribution, are to be considered for the vessel's hull strength and fatigue life assessment. A minimum return period of 50 years for the structural response will be specially considered, provided that it is accepted by VR. Different environmental conditions may induce different worst responses on various parts of the hull structure. The wave-induced maximum motion responses and maximum structural load effects may result from different wave periods. Therefore, the following environmental conditions are to be considered: (1) 100-year return period waves characterized by a significant wave height with a range of associated peak wave periods. Both winter storms and tropical cyclones (hurricanes or typhoons), if any, need be considered.
61
TCVN 6474-2:2007
(2) Wave scatter diagram data of wave height/period joint occurrence distribution. The length of time on which the data base for the wave scatter diagram data is constructed is long enough to be a reliable basis for design (preferably at least five years). The occurrence distribution is to be annualized with equal probability of occurrence for each data point. Each data point is to represent a sea state of approximately three hours in a continuous time duration of the database. (3) Wave directions of head seas and other directions relative to the vessel heading, including the effects of wind and current, with proper probability distribution are to be considered, irrespective of the type of mooring system utilized. (4) As appropriate, either long-crested seas or short-crested seas with cosine squared spectral energy spreading in direction are to be considered for various design issues. 1.3.2.2 Transit The wind and wave conditions representing the environment for the transit route from the building or outfitting site (or the shipyard where the conversion modifications are made) to the project site and the time of the year are to be determined for the design of a floating installation. As a minimum, the wind speed and significant wave height of 10-year return period are to be considered, unless a weather routing plan is to be implemented for the voyage. Seasonal effects on the design environments as appropriate for the proposed transit duration can be considered. In addition to the check on vessel's hull strength during transit, special attention is to be paid to items such as the flare boom, crane pedestal and process equipment supports that will be subject to motion-induced loading and/or effects of green water. Motion-induced loads during transit are to be calculated and the superstructures and their supports, which are included in the scope of classification, shall be verified against these loads. If fitted with an internal turret, special consideration is to be given to bottom slamming to preclude damage to the turret supports and bearings.
62
TCVN 6474-2:2007 1.4
Environmental Conditions
1.4.1
General The environmental conditions for the various design conditions described in 1.3 are to be submitted with adequate data for the specific site of operation. Statistical data and mathematical models that describe the range of pertinent expected variations of environmental conditions are to be employed. All data used are to be fully documented with the sources and estimated reliability of data noted. An environmental report describing methods employed in developing available data into design criteria is to be submitted in accordance with TCVN 6474-1: 2007. Probabilistic methods for short-term, long-term and extreme-value prediction are to employ statistical distributions appropriate to the environmental phenomena being considered, as evidenced by relevant statistical tests, confidence limits and other measures of statistical significance. Hindcasting methods and models are to be fully documented Generally, data and analyses supplied by recognized consultants will be accepted as the basis of design. Published design standards and data, if available for the location of interest, may be cited as documentation. Specifically, the following environmental data are normally to be provided: (1) Extreme events of 100-, 10- and 1-year return period data for wind speed, significant wave height and current. A range of associated wave periods is to be considered for each specified significant wave height. Both winter storms and tropical cyclones (hurricanes or typhoons), if any, need be considered. (2) Directional data and angular separation for extreme values of wind, waves and current. (3) Wave spectral shape formulation. (4) Current speed and directional variation through the water depth. (5) Wave height/period joint occurrence distribution (wave scatter diagram data with equal annual probability of occurrence for each data point). (6) Long-term wave statistics by direction. (7) Water depth and tidal variations, including wind and pressure effects of storms. (8) Air and sea temperature. 63
TCVN 6474-2:2007
1.4.2
Environmental Loads The design of a Floating Installation requires the establishment of environmental loads considering the following parameters: (1) Air and sea temperatures (2) Currents (3) Tides and storm surges (4) Waves (5) Wind Other phenomena such as loop currents, tsunamis, submarine slides, seiche, abnormal composition of air and water, air humidity, salinity, ice drift and icebergs may require special considerations. Wind tunnel and towing tank tests on the project-specific submerged hull and superstructures are preferred in determining current and wind loads. Alternatively, the following calculation procedures can also be applied.
1.4.3
Current The current forces on the submerged hull, mooring lines, risers or any other submerged objects associated with the system are to be calculated using a current profile established in accordance with 1.3. In areas where relatively high velocity currents occur, load amplification due to vortex shedding is to be considered. Current force, Fc on the submerged part of any structure is calculated as the drag force by the following equation: Lực dòng chảy Fc tác dụng lên các phần ngậ p nướ c của bất kì k ết cấu nào phải
đượ c tính toán theo công thức sau: Fc
= 1 2 ρ wC
D
Ac uc uc
,
N
where: 3
ρ w
=
density of sea water, 1,027 kg/m
CD
=
drag coefficient, in steady flow (dimensionless)
uc
=
current velocity vector normal to the plane of projected area, in m/s
64
TCVN 6474-2:2007
Ac 1.4.4
2
=
projected area exposed to current, in m .
Wind The wind conditions for various design conditions are to be established from collected wind data and should be consistent with other environmental parameters assumed to occur simultaneously. In general, the wind speed is to be based on a recurrence period of 100 years. The environmental report is to present wind statistics for the site of installation. The statistics are to be based on the analysis and interpretation of wind data by a recognized consultant. The report is to include a wind rose or table showing the frequency distributions of wind velocity and direction and a table or graph showing the recurrence period of extreme winds. The percentage of time for which the operational phase limiting wind velocity is expected to be exceeded during a year and during the worst month or season is to be identified.
1.4.4.1 Wind Load The wind loading can be considered either as a steady wind force or as a combination of steady and time-varying load, as described below: (1) When wind force is considered as a constant (steady) force, the wind velocity based on the 1-minute average velocity is to be used in calculating the wind load. (2) Effect of the wind gust spectrum can be taken into account by considering wind loading as a combination of steady load and a time-varying component calculated from a suitable wind spectrum. For this approach, the wind velocity based on 1-hour average speed is to be used for steady wind load calculation. The first approach is preferred to this approach when the wind energy spectrum cannot be derived with confidence. Wind pressure, pw, on a particular windage of a floating vessel may be calculated as drag forces using the following equations: Pw
2
2
=
0.610 CsChVr
N/m
=
0.0623 CsChVr
=
0.00338 CsChVr lbf/ft
2
2
Vr in m/s 2
kgf/m 2
Vr in m/s Vr in knots 65
TCVN 6474-2:2007
where Cs
=
Shape Coefficient (dimensionless), given in table 2-1
Ch
=
Height Coefficient (dimensionless), given in table 2-2.
The height coefficient, Ch, in the above formulation accounts for the wind velocity (Vw) profile in the vertical plane. The height coefficient, Ch, is given by the following equation: 2
C h
2 β
⎛ V ⎞ ⎛ z ⎞ = ⎜ ⎟ or C = ⎜ ⎟ , but ⎝ V ⎠ ⎝ z ⎠ z
h
r
≥1
Ch
r
where the velocity of wind, Vz, at a height, z, is to be calculated as follows: β
Vz
⎛ z ⎞ = V ⎜ ⎟ ⎝ z ⎠ r
r
Vr
=
velocity of wind at an reference elevation, Zr , of 10 m
β
=
0.09 - 0.16 for 1-minute average wind 0.125
for 1-hour average wind.
The corresponding wind force, Fw, on the windage is Fw = pw . Aw where: Aw
=
projected area of windage on a plane normal to the 2
direction of the wind, in m
The total wind force is then obtained by summing up the wind forces on each windage Representative values of Ch are given in Table 2-2 of this standard. Wind profiles for the specific site of the Floating Installation should be used. The shape coefficients for typical structural shapes are presented in Table 2-1 of this standard. To convert the wind velocity, Vt, at a reference of 10 m (33 feet) above sea level for a given time average, t, to velocity of another time average, the following relationship may be used: Vt = fV (1h )
66
TCVN 6474-2:2007
Example values of the factor f for a specific waters are listed in Table 2-3 . Values specific to the site of the Floating Installation are to be used. Wind forces on Floating Installations other than ship-type are to be calculated by the summation of wind forces on individual areas using the above formulas. If the 1-hour average wind speed is used, the wind's dynamic effect should be separately considered. The wind energy spectrum, as recommended in API RP 2A, may be used. 1.4.5
Waves Wave criteria are to be described in terms of wave energy spectra, significant wave height and associated period for the location at which the Floating Installation is to operate. Waves are to be considered as coming from any direction relative to the vessel. Consideration is to be given to waves of less than the maximum height because the wave-induced motion responses at waves with certain periods may be larger in some cases due to the dynamic behavior of the system as a whole (floating storage unit/ mooring system).
1.4.5.1 Wave Forces The wave forces acting on a floating vessel consist of three components, i.e., first order forces at wave frequencies, second order forces at frequencies lower than the wave frequencies and a steady component of the second order forces. This steady component of the wave force is called Mean Drift Force. The calculation of wave loading is necessary for assessing the vessel motion responses and the mooring system. It requires calculations of dynamic characteristics of the vessel and the hydrodynamic loading on the vessel for a given environmental condition For structures consisting of slender members that do not significantly alter the incident wave field, semi-empirical formulations, such as Morison's equation, may be used. For calculation of wave loads on structural configurations that significantly alter the incident wave field, appropriate methods which account for both the incident wave force (e.g., Froude-Krylov force) and the forces resulting from wave diffraction are to be used. In general, application of Morison's equation may be used for structures comprising slender members with diameters (or
67
TCVN 6474-2:2007
equivalent diameters giving the same cross-sectional areas parallel to the flow) less than 20 percent of the wave lengths. For a column-stabilized type of vessel consisting of large (columns and pontoons) and small (brace members) cylindrical members, a combination of diffraction and Morison's equation can be used for calculation of hydrodynamic characteristics and hydrodynamic loading. The designer may refer to TCVN 5310: 2001. Alternatively, the suitable model test results or full scale measurements can be used. Wave force calculations should account for shallow water effects which increase current due to blockage effects, change the system natural frequency due to nonlinear behavior of moorings and alter wave kinematics. 1.4.5.2 Wave-induced Vessel Motion Responses The wave-induced response of a vessel consists of three categories of response, i.e., first order (wave frequency) motions, low frequency or slowly varying motions and steady drift. (1) First Order Motions: These motions have six degrees of freedom (surge, sway, heave, roll, pitch and yaw – see definitions in Part 1) and are at wave frequencies that can be obtained from model tests in regular or random waves or by computer analysis in frequency or time domain. (2) Low Frequency Motions: These motions are induced by low frequency components of second order wave forces. The low frequency motions of surge, sway and yaw can be substantial, particularly at frequencies near the natural frequency of the system. The low frequency motion-induced mooring line tension in most systems with a tanker-type vessel is a dominating design load for the mooring system. The low frequency motions are to be calculated for any moored vessel by using appropriate motion analysis software or by model test results of a similar vessel. (3) Steady (Mean) Drift: As mentioned above, a vessel subjected to waves experiences a steady drift along with the first and second order motions. The mean wave drift force and yawing moment are induced by the steady component of the second order wave forces. Mean drift forces and yawing
68
TCVN 6474-2:2007
moments are to be calculated using appropriate motion analysis computer programs or extrapolated from model test results of a similar vessel. 1.4.6
Directionality The directionality of environmental conditions can be considered if properly documented by a detailed environmental report.
1.4.7
Soil Conditions Soil data should be taken in the vicinity of the foundation system site. An interpretation of such data is to be submitted by a recognized geotechnical consultant. To establish the soil characteristics of the site, the foundation system borings or probings prob ings are to be taken at all foundation locations to a suitable depth of at least the anticipated depth of any piles or anchor penetrations plus a consideration for the soil variability. As an alternative, sub-bottom profile runs may be taken and correlated with at least two borings or probings in the vicinity of anchor locations and an interpretation may be made by a recognized geotechnical consultant to adequately establish the soil profile at all anchoring locations. Table 2-1: Shape Coefficients Cs for Windages Shape
Cs
Sphere
0,4
Cylindrical Shapes
0,5
Hull above waterline
1,0
Deck House
1,0
Isolated structural shapes (Cranes, channels, beams, angles, etc.)
1 ,5
Under deck areas (smooth)
1,0
Under deck areas (exposed beams and girders)
1,3
Rig derrick
1,25
69
TCVN 6474-2:2007 Table 2-2: Height Coefficients C h for Windages
Height above Waterline m
ft
Ch 1 min
1 hour
0 to < 15,3
0 to <50
1,00
1,00
15,3 to < 30,5
50 to <100
1,18
1,23
30,5 to < 46,0
100 to <150
1,31
1,40
46,0 to < 61,0
150 to <200
1,40
1,52
61,0 to < 76,0
200 to <250
1,47
1,62
76,0 to < 91,5
250 to <300
1,53
1,71
91,5 to < 106,5
300 to <350
1,58
1,78
Table 2-3: Wind Velocity Conversion Factor
70
Wind Duration
factor f
1 hour
1,000
10 min
1,060
1 min
1,180
15 s
1,260
5s
1,310
3s
1,330
NATIONAL STANDARD
TCVN 6474 -3 : 2007 Second edition
RULES FOR CLASSIFICATION AND TECHNICAL SUPERVISION OF FLOATING STORAGE UNITS PART 3 :TECHNICAL REQUIREMENTS REQUIREMENTS
Reference standards and definitions: see Part 1 ,TCVN 6474-1: 2007 1
Technical requirements for floating storage units
1.1 1.1.1
All Vessels General
1.1.1.1This chapter cover the requirements for vessels (ship type and column stabilized) as
defined in Part 1. Other tyes ,as defined in 2.2.4 Part 1,will be considered on a case-by-case basis. 1.1.1.2This chapter cover the requirements for vessel that are
newly designed or are
undergoing a major conversion that affects the principal dimensions of the floating installation.The application of the requirements to existing vessel not undergoing major conversion will be considered by VR based on the service history, age, condition of the exsting floating installation. 1.1.1.3 The designer is required to submit to VR for review all applicable design
documentation,
such
as
reports,calculation,plans
and
other
documentation
necessary to verify the structural streng of the floating installation it self .The submitted design documentation is to include the design environmetal condition 71
TCVN 6474 -3:2007
(see 1.4 Part 2). 1.1.2
Lightweight Data.
The lightweight and center of gravity are to be determined for vessels of all types .An inclining test will be required for the first floating installation of a series, when as near to completion as practical, to determine accurately the lightweight and position of center of gravity . An inclining test procedure is to be submitted for review prior to the test, which is to be witnessed by a Surveyor of VR . 1.1.3
Load Line
1.1.3.1Every vessel is to have marks that designate the maximum permissible draft to which
the vessel may be loaded. Such markings are to be placed at suitable visible locations on the hull or structure to the satisfaction of the Bureau. On columnstabilized vessels, where practical, these marks are to be visible to the person in charge of liquid transfer operations . 1.1.3.2Except where otherwise permitted by the flag and coastal States, load line marks are
to be established under the terms of the International Convention of Load Lines, 1966. Where minimum freeboards cannot be computed by the normal methods laid down by the convention, such as in the case of a column-stabilized unit, they are to be determined on the basis of compliance with intact or damage stability requirement for afloat modes of operation . 1.1.3.3The vessel’s arrangements are to comply with all applicable regulations of the
International Convention on Load Lines. 1.1.4
Operating Manual As for every kind of vessel ,Operating Manual include information as following, if applicable , to be able to conduct operator to operate vessel in safety way:
1.1.4.1A general description of the unit, including major dimensions, lightship
characteristics;
72
TCVN 6474 -3:2007
1.1.4.2Summaries of approved modes of operation including for each mode of operation:
(1) Limiting environmental conditions, including wave height and period, wind velocity,
current velocity, minimum air and sea temperatures, soil
penetration, air gap and water depth; (2)Design deck loadings, mooring loads, icing loads, variable load, total elevated load, cantilever load, rated capacities of derricks, cranes and elevating systems and types of helicopter for which the helideck is designed; (3)Draft or draft range; (4)Maximum allowable KG versus draft curves or equivalent and associated limitations or assumptions upon which the allowable KG is based; (5)Position (open or closed) of watertight and weathertight closures 1.1.4.3General arrangements; 1.1.4.4Watertight and weathertight boundaries, location of unprotected openings, and
watertight and weathertight closures; 1.1.4.5Drawings indicating ballast system and type, location and quantities of permanent
ballast; 1.1.4.6Schematic diagrams of the bilge, ballast and ballast control system; 1.1.4.7Allowable deck loadings; 1.1.4.8Capacity, centers of gravity and free surface correction for each tank; 1.1.4.9Capacity and centers of gravity of each void provided with sounding arrangements
but not provided with means of draining; 1.1.4.10 Location and means of draining voids ; 1.1.4.11 Hydrostatic curves or equivalent;
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1.1.4.12 Hazardous areas; 1.1.4.13 Simplified electrical one line diagrams of main power and emergency power
systems; 1.1.4.14 Diagram of fuel oil filling pipes ; 1.1.4.15 Recommended sequence of emergency shut-downs; 1.1.4.16 Fire extinguishing arrangements; 1.1.4.17 Life saving appliance arangements and Escape route plan ; 1.1.4.18 Light ship data ; 1.1.4.19 Technical information of helicopter used for helideck design ; 1.1.4.20 Plans and description of the mooring system and instructions for mooring ; 1.1.4.21 Plans and description of the dynamic positioning system and instructions for
positioning ; 1.1.4.22 Stability information booklet; 1.1.4.23 Loading Manual ; 1.1.4.24 Other instruction if Bureau require. 1.1.5
Loading Manual (Operating Manual) .
1.1.5.1For a ship-type vessel, a loading manual is to be prepared and submitted for review
pertaining to the safe operation of the vessel from a strength point of view. This loading manual is to be prepared for the guidance of and use by the personnel responsible for loading the vessel. The manual is to include means for determining the effects of various loaded, transitional and ballasted conditions upon the hull girder bending moment . In addition, a loading instrument suitable for the intended service is to be installed on the vessel.
The check conditions for the loading
instrument and other relevant data are to be submitted for review . 74
TCVN 6474 -3:2007
1.1.5.2An operating manual is required for the marine operation of all Floating Installations,
containing the information listed in Section 1.1.6 of the Mobile Offshore Drilling Unit Rules , as applicable. The above mentioned loading manual may be included in the overall operating manual or issued as a separate document. The loading manual, if issued as a separate document, is to be referenced in the overall operating manual. 1.1.5.3Sections pertaining to each vessel type for additional requirements. 1.1.6
Trim and Stability Booklet (Operating Manual)
1.1.6.1In addition to the loading manual described in (1.1.4), a ship-type floating
installation is to be provided with sufficient information to guide the master and other responsible personnel in the safe loading, transfer and discharge of cargo and ballast with respect to the hull’s trim and stability. The information is to include various loaded, transitional and ballasted example conditions over the full range of operating drafts together with stability criteria to enable the responsible personnel to evaluate the intact and damage stability of any other proposed condition of loading. 1.1.6.2This information may be prepared as a separate trim and stability booklet or may be
included in the overall operating manual. If issued as a separate document, the trim and stability booklet is to be referenced in the overall operating manual. 1.1.6.3Sections pertaining to each vessel type for additional requirements . 1.1.7
Engineering Analysis.
1.1.7.1Documentation necessary to verify the adequacy of the hull structure is to be
submitted for review. The needed extent and types of analyses and the sophistication of such analyses vary, depending on one or a combination of the following factors: (1) The design basis of the hull structure versus the conditions to be encountered at the installation site; 75
TCVN 6474 -3:2007
(2) The relative lack of experience with the hull structure’s arrangement, local details, loading patterns, failure mode sensitivities ; (3) Potential deleterious interactions with other subsystems of the floating offshore installation ; 1.1.7.2The required structural analyses are to employ the loads associated with the
environmental conditions determined in association with Part 2. These conditions include those expected during the operational life of the Floating Installation on site and those expected during the transport of the structure to the installation site. 1.1.8
Mooring Systems and Equipment
1.1.8.1Position mooring systems are to meet the requirements of Part 4. For temporary
mooring equipment, see Chapter 25 ,TCVN 6259-2A:2003.Temporary mooring equipment is equipment used in port or proteced water area. 1.1.9
Material
1.1.9.1Steels are hull structure materials to be complied with the requirements given in
Chapter 3, 4, 5, 6 of Pt 7A TCVN 6259-7 : 2003 and TCVN 5317:2001. 1.1.9.2It is the responsibility of the Owner to comply with the requirements of Vietnam
Register relating to selecting materials, issuing certificates and surveys. 1.1.9.3Where aluminum alloys are used for secondary structures such as helicopter decks,
deckhouses, superstructures or other structural components they are to comply with the relevant requirements of Pt 7A, Ch 8 of TCVN 6259-7 :2003. 1.1.9.4If used steel and other material is different to above kinds of material ,their technical
properties are to be submitted to Bureau for approval . 1.1.9.5Air and sea-water temperature in design is based on selecting materials should be
minimum average temperature in day at operational location accordance to 50 years – period. 1.1.9.6Considerations should be given to other materials based on the their property
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accordance to each special application. 1.1.9.7Selected materials are complied with the design requirements accordance to static
stress, fugue stress, cracking resistant ability and corrosion resistant ability. 1.1.9.8Grades used in structure are selected to standards of thickness, positions in structure
and minimum designed temperature of seawater and air. 1.1.10 Underwater marking 1.1.10.1 The underwater structure of a unit intended to be surveyed on an in-water basis
should have its main frames, bulkheads and joints etc. clearly identified by suitable marking. Details are to be submitted for approval. 1.1.10.2 Underwater marking should consist of raised lines, numerals dud letters. Besides
painting, another material marking should be added. 1.1.10.3 If marking is to be carried out by welding the welds should be made with
continuous runs and the quality of welding and workmanship should be to an equivalent standard as the main hull structure. Marking by welding is not permitted in highly stressed areas or over existing butts or seams. The welding procedures and consumables are to be submitted for approval. 1.1.11 Corrosion Protection 1.1.11.1 Steelwork is to be suitably protected against corrosion (except inside of oil tank).
This protection may be by coating or by a system of cathodic protection or by any other approved method. The method is to be suitable for the position and purpose. 1.1.11.2 VR recommend that submerged hull should be protected by impressed current
cathodic protection- ICCP with the life is not less than 20 year. 1.1.11.3 The following plans and information are to be submitted:
(1) Evidence that any primers used will have no deleterious effect on subsequent welding or on subsequent coatings;
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(2) Details of the painting specification with regard to: (a) The generic type of the coating and its suitability for the intended environment. (b) The methods to be used to prepare the surface before the coating is applied and the standard to be achieved. (c) The method of application of the coating ; (d) The number of coats to be applied and the total dry film thickness; (3) Details of the areas to be coated . 1.1.11.4 Where a coating is to be applied in accommodation spaces, machinery spaces and
areas of similar fire risk, a statement that the coating is not formulated on a nitrocellulose or other highly flammable base and has low flame spread characteristic. 1.1.11.5 When a coating contains aluminum and is intended to be used on decks or in areas
where flammable gases may accumulate a statement from an independent laboratory confirming that appropriate tests have shown that the coating does not increase incentive sparking hazard in the area to which it is to be applied. 1.1.11.6 Proposals for the protection of wire ropes will be considered on their merits bearing
in mind the purpose of the rope, its construction and its intended life. In general, all steel wire ropes will be required to be protected with a zinc coating. 1.1.11.7 The cathodic protection system should be designed for a period commensurate with
the design life of the structure and it should be capable of polarizing the steelwork to a sufficient level in order to minimize corrosion. 1.1.11.8 Impressed current cathodic protection systems are not to be fitted in any tank. 1.1.11.9 Particular attention is to be given to the locations of anodes in tanks that can
contain explosive or other flammable vapour. 1.1.11.10
78
Aluminum and aluminum alloy anodes are permitted in tanks that may contain
TCVN 6474 -3:2007
explosive or flammable vapour but only at locations where the potential energy of the anode does not exceed 275 J (28kgfm). 1.1.11.11
Aluminum anodes are not to be located under tank hatches or other openings
unless protected by adjacent structure . 1.1.11.12
Magnesium or magnesium alloy anodes are permitted only in tanks intended
solely for water ballast, in which case adequate venting must be provided. 1.1.11.13
The arrangements for glands, where cables pass through the shell, are to
include a small cofferdam. Cables to anodes are not to be led through tanks intended for the carriage of low flash point oils. Where cables are led through cofferdams or clean ballast tanks, they are to be enclosed in a substantial steel tube. 1.1.11.14
Where bimetallic connections are made measures are to be incorporated to
preclude galvanic corrosion. 1.1.11.15
Where possible items such as risers and pipelines should be electrically
insulated from the unit. 1.1.11.16
Storage tanks and other compartments require corrosion protection where the
stored product may be corrosive. Particular attention should be paid to the likelihood of water in the bottom of hydrocarbon storage tanks and the elects of bacterial induced corrosion. Proposals for suitable protective measures are to be submitted for approval. 1.1.11.17
Where it is proposed to use inhibitors, biocides or other chemicals for the
protection of closed flooded compartments, full details, including : (1) Compatibility, with each other and ; (2) Evidence of satisfactory service experience or ; (3) Suitable laboratory test results or ; (4) Any other data to substantiate the suitability for the intended purpose are to
be
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submitted for consideration. 1.1.11.18
Cable and insulating material for impressed current anode systems should be
resistant to chloride, hydrocarbons and any, other chemicals with which they, may come into connect. 1.1.11.19
For impressed current anode systems the electrical connection between the
anode cable and the anode body is to be watertight and mechanically and electrically sound. 1.1.11.20
Potential surveys are to be carried out at agreed intervals. Should the results of
any potential survey are not meet the requirements then remedial action is to be carried out at the earliest opportunity . 1.1.11.21 1.2 1.2.1
Design of cathodic protection systems should be approved by VR .
Ship – Type Vesels General
1.2.1.1The design and construction of the hull, superstructure and deckhouses of ship-type
installations are to be based on all applicable requirements of the Steel Vessel Rules. However, the design criteria for those structures, as given in the Steel Vessel Rules, can be modified to reflect the different structural performance and demands expected of a vessel engaged in unrestricted service compared to a vessel positioned at a particular site on a long-term basis or a vessel with a specific and invariant route 1.2.1.2To reflect the site-dependent nature of the floating offshore installation is
accomplished through the introduction of a series of Environmental Severity Factors (ESFs), Reference is to be made to Appendix 2 for the applicable structural design and analysis criteria that have been modified to reflect site-specific service conditions. 1.2.1.3The design criteria for an oil-tanker-type vessel are located in TCVN 6259:2003.
TCVN 6259-2A:2003 is applicable to vessels of 90 meters or more in length while 80
TCVN 6474 -3:2007
TCVN 6259-2B:2003 applies to vessels under 90 meters in length. In addition, the applicable criteria contained in the Load Line, SOLAS and MARPOL Conventions issued by the International Maritime Organization are to be considered. 1.2.2
Definitions
The definition of a ship-type vessel is given in Part 1. See TCVN 6259-2:2003 for definition of primary vessel characteristics . 1.2.3
Longitudinal Strength
1.2.3.1Longitudinal strength is to be based onTCVN 6259-2:2003 . The total hull girder
bending moment, Mt is the sum of the maximum still water bending moment\\ and corresponding wave-induced bending moment (Mw) determined from 1.3 , Part 2 of this Guide considering both the expected on-site conditions and transit conditions to the installation site. In lieu of directly calculated wave-induced hull girder bending moments (vertical) and shear forces, recourse can be made to the use of the Environmental Severity Factor (ESF) approach described in Appendix 1,Part 9 . The ESF approach can be applied to modify the Steel Vessel Rules wave-induced hull girder bending moment and shear force formulas according to TCVN 6259-2:2003 (see Appendix 2 ,Part 9 ). 1.2.3.2Due account is to be given to the influence of mooring equipment and riser weights
in contributing to the vertical still water bending moments and shear forces 1.2.3.3For all vessels of 90 m (295 ft) or more in length ,TCVN 6259-2:2003 requires that
a “loading manual” based on still-water conditions be prepared and submitted for review. 1.2.3.4The influence of mooring equipment and riser weights in contributing to the vertical
still water bending moments and shear forces (z) is to be considered properly 1.2.4
Stability , Division and Loadline
1.2.4.1Requirement of stability for ship-type vessel is described in TCVN 6259-10:2003
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1.2.4.2Requirement of division for ship-type vessel is described in TCVN 6259 - 9:2003 1.2.4.3Requirement of Loadline for ship-type vessel is described in TCVN 6259 - 11:2003 1.2.4.4The intact and damage stability of the vessel are to be evaluated in accordance with
TCVN 5312:2001 .
In addition, the requirements of the 1966 Load Line
Convention and MARPOL 73/78 are to be considered.
See 1.1.5 for general
requirements pertaining to the makeup and issuance of loading guidance with respect to stability 1.2.5
Structural Arrangement
1.2.5.1The structural arrangement of the vessel are to comply with applicable requirements
of TCVN 6259-2:2003 . Reference should also be made to the 1966 Load Line Convention and MARPOL 73/78 1.2.6
Structural Design of the Hull
1.2.6.1The design of the hull is to be based on the applicable portions of TCVN 6259-
2:2003 . Where the conditions at the installation site are less demanding than those for unrestricted service that are the basis of TCVN 6259-2:2003
, the design
criteria for various components of the hull structure may be reduced to reflect these differences. However, when the installation site conditions produce demands that are more severe, it is mandatory that the design criteria are to be increased appropriately. 1.2.6.2Appendix 1, Part 9 presents an explanation of the Environmental Severity Factor
(ESF) concept, which is used to adjust the unrestricted service criteria of TCVN 6259-2:2003 . Appendix 2, Part 9
present criteria from TCVN 6259-2:2003 that
are modified to show the introduction of the ESFs into the criteria. 1.2.6.3In the application of the modified criteria, no minimum required value of any net
scantling is to be less than 85 percent of the value obtained, had all the Beta Values been set equal to 1.0 (which is the unrestricted service condition). 1.2.6.4The loads arising from the static tank testing condition are also to be directly
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considered in the design. In some instances, such cases might control the design, especially when the overflow heights are greater than normally encountered in oil transport service, or the severity of environmentally-induced load components and cargo specific gravity are less than usual. 1.2.6.5Hull Design for Additional Loads and Load Effects .
(1)
The loads addressed in this Subsection are those required in the design of a vessel in Appendix II & IV , Part 9 . Specifically, these loads are those arising from liquid sloshing in hydrocarbon storage or ballast tanks, green water on deck, bow impact due to wave group action above the waterline, bow flare slamming during vertical entry of the bow structure into the water and bottom slamming. All of these can be treated directly by reference to Appendix II & IV, Part 9 . However, when it is permitted to design for these loads and load effects on the site-specific basis, the formulations given in Appendix II & IV , Part 9 can be modified to reflect the introduction of the previously mentioned Environmental Severity Factors (ESFs-Beta-type) into the Rule criteria.
(2)
Sloshing of Produced or Ballast Liquids For ship-type vessels, it is typical that the tanks may be subjected to partial filling levels. For tanks where partial filling is intended, sloshing analyses are to be performed. Firstly, the sloshing analysis is to determine if the anticipated filling levels in each tank are close to the vessel’s natural pitch and roll motion periods. It is recommended that the natural periods of the fluid motions in each tank for each anticipated filling level are at least 20 percent greater or smaller than that of the relevant vessel’s motion. This range of vessel natural periods constitutes the “critical” range. If the natural periods of the tanks and vessel are sufficiently separated, then no further analyses are required. However, when the tanks are to be loaded within “critical” filling levels, then additional analyses are to be performed in order to determine the adequacy of the structure for the internal pressures due to sloshing
(3)
For vessel lengths of 150 m (492 feet) and above, the extent of sloshing analyses 83
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is indicated in Appendix IV, Part 9 . For vessels less than 150 m in length, the extent of sloshing analyses is according to recognised standards . (4)
However, it should be borne in mind that the sloshing assessment criteria given in Appendix IV, Part 9 are derived considering an unrestrained freely floating hull subjected to wave energy spectra representing the open ocean .Mooring restrain ,potential hull weathervaning different wave energy characterizations ( e.g.,energy spectra for ocean swells ,tropical cyclonic storms and water depth effects) may need to be additionally considered by the designer when establishing sloshing – induced loading.
(5)
When it is permitted to base the design on a site-specific modification, green water loads on deck , bow impact , slamming is to be modified as Appendix II, Part 9 .
1.2.6.6Superstructures and Deckhouses.
The designs of superstructures and deckhouses are to comply with the requirements of TCVN 6259-2:2005. 1.2.6.7Helicopter Decks
The helicopter deck structure is to be in accordance withTVCN 5310:2001 and technical regulation for offshore helicopter decks . 1.2.6.8Protection of Deck Openings
The machinery casings, all deck openings, hatch covers and companionway sills are to comply with 6259-2:2003. 1.2.6.9Bulwarks, Rails, Freeing Ports, Ventilators and Portlights
Bulwarks, rails, freeing ports, portlights and ventilators are to meet the requirements of TCVN 6259-2:2003. 1.2.6.10 Materials and Welding
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(1)
Materials and welding is to be in accordance with TCVN 6259-6:2003 and TCVN 6259-7:2003 .The weld type and sizing are to be shown on the scantling drawings or in the form of a welding schedule and are to comply with TCVN that govern the steel selection.
(2)
The topsides facilities (production deck) are to be constructed from steel selected in accordance with TCVN 7230: 2003.
(3)
Tower mooring systems and SPM are to be constructed from steel selected in accordance with TCVN 5317: 2001.
1.2.6.11 Machinery and Equipment Foundations
Foundations for equipment subjected to high cyclic loading, such as mooring winches, chain stoppers and foundations for rotating process equipment, are to be analyzed to ensure satisfactory strength and fatigue resistance. Calculations and drawings showing weld details are to be submitted to VR for review. 1.2.7
Engineering Analyses of the Hull Structure
1.2.7.1General
Documentation necessary to verify the structural strength of the vessel is to be submitted for review. The criteria in this Subsection relate to the analyses required to verify the scantling selected in the basic hull design in 1.2.6 as above. Except as provided in TCVN 6259-2:2005 , the results of analyses that are required in this Subsection cannot be used to reduce the scantlings established from 1.2.6 . Depending on the specific features of the offshore installation, additional analyses to verify and help design other portions of the hull structure will be required. Such additional analyses include those for the deck structural components supporting deck-mounted equipment and the hull structure interface with the position mooring system. Analysis criteria for these two situations are given in 1.2.8 . 1.2.7.2Strength Analysis of the Hull Structure
(1) For vessels of 150 m (492 feet) in length and above, the required extent of a Finite 85
TCVN 6474 -3:2007
Element Method (FEM) strength analysis is indicated in Appendix III, Part 9
. For
vessels less than 150 m in length, it is recommended that a Finite Element Method (FEM) analysis be performed if the vessel is of double hull construction or of unusual design . When the design is permitted to be based on site-specific environmental conditions, the load components from the Steel Vessel Rules to be used in the strength analyses can be adjusted as explained in 1.2.6 and Appendix II, Part 9 . (2) Generally, the strength analysis is performed to determine the load distribution in the structure. An appropriate three-dimensional FEM model is to be analyzed for this purpose.
To determine the stress distribution in major supporting structures,
particularly at intersections of two or more members, fine mesh FEM models are to be analyzed using the boundary displacements and load from the 3D FEM model. To examine stress concentrations, such as at intersections of longitudinal stiffeners with transverses and at cutouts, fine mesh 3D FEM models are to be analyzed. In the strength analyses, the following loading conditions are to be used: (3) General Cargo Load Patterns. The FEM analysis is to be performed in accordance with the load patterns specified in Appendix IV, Part 9 . The load patterns included in the Steel Vessel Rules have been developed to simulate the most severe load effects in selected structural components. The actual loading patterns for the vessel are to be reviewed to ensure that there are no other patterns producing more severe loading.
If any worse governing load patterns than those specified in the Steel
Vessel Rules exist, these load patterns are to be included in the analyses. (4) Tank Test Loading Conditions. In addition to the specified load patterns and cargo densities above, conditions representing tank testing are also to be investigated. For ESF values of 1.0 and greater, the tank load patterns of Load Cases No. 5 and 6 specified in Appendix IV, Part 9 are to be analyzed considering static conditions and seawater (Specific Gravity = 1.025). The tanks are to be loaded considering the actual height of the overflow pipe, which is not to be taken less than 2.44 m (8 feet) above the deck at side. The external drafts for these Load Cases are to be taken as 25 86
TCVN 6474 -3:2007
percent of the design draft. However, notes (1) and (2) of the foll owing paragraph are applicable. For ESF values of less than 1.0, the same load patterns of Load Cases No. 1 to 8 specified in Part 5, Chapter 1 of the Steel Vessel Rules are to be analyzed considering static conditions and seawater (Specific Gravity = 1.025). The tanks are to be loaded considering the actual height of the overflow pipe, which is not to be taken less than 2.44 m (8 feet) above the deck at side. The external drafts for these Load Cases are to be taken as follows:
1)
Load Case
Percent of Design Draft
1
55 (1)
2
100 (3)
3
67
4
67
5
25 (1)
6
25 (1) (2)
7
100 (3)
8
100 (3)
Where the actual tank test condition with the tank loading pattern as the center row of tanks results in a draft less than specified, the actual tank test draft is to be used
2 ) For a vessel with two outer longitudinal bulkheads only (inner skin), i.e., one tank across between the inner skin bulkheads, the minimum actual tank test draft is to be used. 3 ) The actual tank test patterns will most likely not result in 100 percent 87
TCVN 6474 -3:2007
draft, but the 100 percent draft is specified as the design condition to maximize external pressure loads. Site tank tests are to be conducted. These tank test cases are to be analyzed using the 1-year return period design operation condition loads and a minimum specific gravity of cargo fluid of 0.9. The tank pressure is to be calculated with the actual tank test pressure head on site. The external drafts for these load cases are to be specified according to the Loading or Operational Manual, or are to be agreed upon between VR and the Owner or Client to determine the design condition in terms of still water bending moments and shear forces along the length of the cargo block. (5) Transit Conditions. The transit condition is to be analyzed using the actual tank loading patterns in association with the anticipated environmental conditions to be encountered during the voyage (see 1.3, part 2). 1.2.7.3Fatigue Analysis
For all vessels of 150 m and above, the extent of fatigue analysis required is indicated in Appendix IV, Part 9 . For vessels of less than 150 m, the recognized requirements are applicable. The fatigue strength of welded joints and details at terminations, which may or may not be located in highly stressed areas are to be assessed, especially where higher strength steel is used. These fatigue and/or fracture mechanics analyses, based on the combined effect of loading, material properties, and flaw characteristics are performed to predict the service life of the structure and determine the most effective inspection plan.
Special attention is to be given to structural notches, cutouts,
bracket toes, and abrupt changes of structural sections. Consideration is also to be given to the following analyses: (1) The cumulated fatigue damage during the voyage from the fabrication or previous site to the operation site is to be included in the overall fatigue 88
TCVN 6474 -3:2007
damage assessment. (2) The stress range due to loading and unloading cycles is to be accounted for in the overall fatigue damage assessment, if it is significant.
For any
structural detail, a minimum criterion for computing the stress range is to consider the tanks at 90 percent full load capacity and at its residual capacity, with adjacent tanks also at their residual capacity. A maximum fluid specific gravity of 0.9 is to be adopted for calculating the pressure range. The stress range is also to account for pressure range variation due to sloshing of the fluid inside the tank at the various filling levels, if it is significant. 1.2.7.4Acceptance Criteria.
The total assessment of the structure is to be performed against the failure modes of material yielding, buckling and ultimate strength and fatigue. The reference acceptance criteria of each mode are given as follows: (1) Material Yielding The criteria are indicated in Appendix VI ,Part 9. (2) Buckling and Ultimate Strength The criteria are indicated in TCVN 6259-2:2003 . (3) Fatigue The required target fatigue life is 20 years. In the absence of more detailed environmental data, stress ranges are to be obtained in consideration of the unrestricted service environment. When the site-specific wave environment is used and produces less severe fatigue demand than the unrestricted service environment of the Steel Vessel Rules, credit can be given to the less severe environment by increasing the expected fatigue life. For site-specific environmental conditions producing more severe fatigue demand than the Steel Vessel Rule basis, the site-specific environmental data 89
TCVN 6474 -3:2007
are to be used, and the calculated fatigue life is to be not less than 20 years Due to the structural redundancy and relative ease of inspection inherent in typical hull structures of ship-type vessels, there is no further need to apply additional factors of safety above what is already built into the fatigue classification curves cited in the above reference. However, for areas of the structure which are non-inspectable or “critical,” such as in way of the connections to the mooring or production systems ), additional factors of safety should be considered. For existing vessels that are employed in floating installation service, the estimated remaining fatigue lives of the critical structural details are to be assessed and the supporting calculations submitted for review.
Special
consideration is to be given to the effects of corrosion and wastage on the remaining fatigue life of existing structures. Any areas determined to be critical to the structure are to be free of cracks. The effects of stress risers should be determined and minimized. Critical areas may require special analysis and survey. 1.2.8
Analysis and Design of Other Major Hull Structural Features
The analysis and design criteria to be applied to the other pertinent features of the hull structural design are to conform to recognized practices acceptable to the Bureau. For many ship-type installations, there will be a need to consider in the hull design the interface between the position mooring system and the hull structure or the effects of structural support reactions from deck mounted (or above deck) equipment modules or both. When it is permitted to base the design of the ship-type offshore installation on site-specific environmental conditions, reference is to be made to 1.2.6 and Appendix 2, Part 9 regarding how load components can be adjusted. Criteria applicable to the position mooring (e.g., turret) structure itself is given in 1.4, Section 4, and the above (or on) deck equipment or module structure is 90
TCVN 6474 -3:2007
referred to in 1.7,Section 5 1.2.8.1Position Mooring/Hull Interface
(1) Mooring/Hull Interface Modeling A FEM analysis is to be performed and submitted for review.
The modeling
technique employed should conform to that described in recognized standards. (a)
If the mooring system is of the turret or SPM type, external to the vessel’s hull, the following applies: 1)
Fore end mooring. The minimum extent of the model is from the fore end
of the vessel, including the turret structure and its attachment to the hull, to a transverse plane after the aft end of the foremost cargo oil tank in the vessel. The model can be considered fixed at the aft end of the model. The loads modeled are to correspond to the worst-case tank loads, seakeeping loads as determined for both the transit case and the on-site case, ancillary structure loads, and, for the on-site case, mooring loads. 2) Aft end mooring. The minimum extent of the model is from the aft end of
the vessel, including the turret structure and its attachment to the hull, to a transverse plane forward of the fore end of the aftmost cargo oil tank in the hull. The model can be considered fixed at the fore end of the model. The loads modeled are to correspond to the worst-case tank loads, seakeeping loads as determined for both the transit case and the on-site case, ancillary structure loads, and, for the on-site case, mooring loads. (b)
If the mooring arrangement is internal to the vessel hull (turret moored), the following applies: 1) Fore end turret . The model is to extend from the fore end of the vessel into
the cargo tank or hold aft of the one containing the turret. The model can be considered fixed at the aft end of the model. The loads modeled are to correspond to the worst-case tank loads, seakeeping loads as determined for 91
TCVN 6474 -3:2007
both the transit case and the on-site case, ancillary structure loads, and for the on-site case, mooring loads. 2) Midship turret . The model can be a 3-tank model similar to that described
in Appendix IV,Part 9 where the turret is located in the center tank of the model. Hull girder loads are to be applied to the ends of the model. The other loads that are modeled are to correspond to the worst-case tank loads, seakeeping loads as determined for both the transit case and the on-site case, ancillary structure loads, and, for the on-site case, mooring loads. (c) For spread moored vessels 1) The local foundation structure and vessel structure are to be checked for the
given mooring loads using an appropriate FEM analysis. The mooring loads to be used in the analysis are to be based on the breaking strength of the mooring lines (2) Net Scantlings for Mooring Interface Structure A “net” thickness or scantling corresponds to the minimum strength capability acceptable for classification, regardless of the design service life of the vessel, prior to the addition of the Rules-specified design corrosion margin.
The mooring
interface/hull structure analysis model is to use the design corrosion margin – 10 percent of each of the as-built, gross scantlings, but need not exceed 1.5 mm. These design corrosion margins are for use with the mooring/hull interface model and are minimum values. They are different from the corrosion margins to be used in the analyses specified in 1.2.7 . Should the design incorporate increased corrosion margins, their beneficial effects can be appropriately accounted for in the design evaluation. The required net scantlings determined using these corrosion margins only apply in way of the mooring structure, bounded transversely and longitudinally by watertight bulkheads or shell plate. The net scantlings can be used for obtaining stress levels for structure that is in way of any ancillary structure, such as flare towers or 92
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production decks. All other areas are to be in compliance with TCVN 6259-2:2003 and applied section , 1.2.6 and 1.2.7 of this Guide . (3) Acceptance Criteria Mooring/Hull Interface The total assessment of the structure is to be performed against the failure modes of material yielding, buckling and ultimate strength, and fatigue.
The reference
acceptance criteria of each mode is given as the following: (a) Material Yielding. The criteria are indicated in Appendix VI, Part 9 (b) Buckling and Ultimate Strength. The correlative criteria are indicated in TCVN 6259-2:2003. (c) Fatigue: Mooring/Hull Interface. The required target fatigue life is 20 years. However, due to the critical nature of these connections, additional factors of safety may be needed. (Also see 1.4.7,Part 4.) The fatigue life of the hull structure is to be investigated in accordance with recognized fatigue calculating guideline and submitted for review as described below: 1) For vessels with a forward end mooring, the fatigue life of the vessel should be investigated from the watertight bulkhead aft of the mooring to the fore end of the vessel. 2) For vessels with mid body mooring, a three-tank analysis, where the mooring is in the middle hold, is to be investigated 3) For aft end mooring, the fatigue life should be investigated from the watertight bulkhead forward of the mooring to the aft end of the vessel. Structural members in way of the turret structure or other mooring structure are to be effectively connected to the adjacent structure in such a manner as to avoid hard spots, notches and other harmful stress concentrations. Special attention is to be given to cutouts, bracket toes and abrupt changes of structural sections. These areas are considered to be critical to the vessel and 93
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are to be free of cracks. The effects of stress risers in these areas are to be determined and minimized. 1.2.8.2Hull Structure to Resist Equipment Reaction Forces
The forces to be resisted by the hull structural elements in way of the equipment supports are to be established by an acceptable method that accounts for the static and expected motion (seakeeping) induced and other applicable load effects and the appropriate combinations of these load components and effects. The strength of the hull structural elements is to be based on the applicable criteria of the Steel Vessel Rules. For vessels 150 meters (492 feet) in length and greater, the required strength is specified in Appendix VI, Part 9 , and for vessel less than 150 meters in length, reference is to be made to recognized Standards . 1.2.9
Marine Piping Systems
Marine piping systems are those systems that are required to conduct marine operations and are not associated with the process facilities. These systems include, but are not limited to, bilge, ballast, tank venting, sounding and fuel oil. Marine piping systems on ship-type installations are to be in accordance with the applicable requirements of TCVN 6259:2003. 1.2.10 Electrical Systems
Electrical Systems on ship-type installations are to comply with the applicable requirements of TCVN 6259-4:2003 and applicable requirements in Appendix VII . For area classification requirements, refer to Appendix VI, Part 9 of this Guide 1.2.10.1 Degree of protection for enclosure
Degree of protection of electrical equipment is against foreign bodies and liquid, type of enclosure required for protection of equipment is to be suitable for the intended location. Minimum degree of protection is shown as Table 3 – 3. In order to define degree of protection shown in Table 3 – 3 , following regulation is given. Degree of protection relating to protecting electrical equipment from falling of 94
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foreign bodies and liquid into inside is defined by IP numeral with two followed number.The first IP numeral indicate degree of protection of equipment from solid object, the second IP numeral indicate degree of protection of equipment from liquid. Details are given in Table 3-1 and Table 3-2. Table 3-1 Degree of Protection – Indicated by the first characteristic numeral
First IP
Short Description
Definition
Numeral 0
Non-protected
No special protection
1
Protected against solid Solid object exceeding 50 mm in diameter. objects greater than 50 mm
2
Protected against solid Solid object exceeding 50 mm in diameter. objects greater than 50 mm
3
Protected against solid Tools, wires, etc., of diameter or thickness greater objects greater than 2,5 mm than 2.5 mm.Solid objects exceeding 2.5 mm in diameter.
4
Protected against solid Wires or strips of thickness greater than 1 mm. objects greater than 1 mm Solid objects exceeding 1 mm in diameter.
5
Dust protected
Ingress of dust is not totally prevented, but dust does not enter in sufficient quantity to interfere with satisfactory operation of the equipment.
6
Dust-tight
No ingress of dust
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Table 3-2 Degree of Protection – Indicated by the second characteristic numeral Second IP
Short Description
Definition
Numeral
0
Non-protected
No special protection
1
Protected against dripping water
Dripping water (vertically falling drops) is to have no harmful effect.
2
Protected against dripping water when tilted up to 15 deg.
Vertically dripping water is to have no harmful effect when the enclosure is tilted at any angle up to 15 deg. from its normal position.
3
Protected against spraying water
Water falling as spray at an angle up to 60 deg. from the vertical is to have no harmful effect.
4
Protected against splashing water
Water splashed against the enclosure from any direction is to have no harmful effect.
5
Protected against water jets
Water projected by a nozzle against the enclosure from any direction is to have no harmful effect.
6
Protected against heavy seas
Water from heavy seas or water projected in powerful jets is not to enter the enclosure in harmful quantities.
7
Protected against the effects of immersion
Ingress of water in a harmful quantity is not to be possible when the enclosure is immersed in water under defined conditions of pressure and time.
8
Protected against submersion
The equipment is suitable for continuous submersion in water under conditions which are to be specified by the manufacturer. Note: Normally, this will mean that the equipment is hermetically sealed. However, with certain types of equipment, it can mean that water can enter but only in such a manner that it produces no harmful effects.
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TABLE 3-3 :Minimum Degree of Protection Example Of Location
Condition of Location
Switchboards, distribution boards, motor control centers & controllers Generators Motors Transformers, Converters Lighting fixtures Heating appliances (2) Accessories
Dry accommodation space
Danger of touching live parts only
IP20 -
IP20 IP20 IP20
IP20
IP20
Control rooms
Danger of dripping liquid and/or moderate mechanical damage
IP22 -
IP22 IP22 IP22
IP22
IP22
IP22 IP22 IP22 IP22 IP22
IP22 IP44
Steering gear rooms
IP22 IP22 IP22 IP22 IP22
IP22 IP44
Refrigerating machinery rooms
IP22 -
IP22 IP22 IP22
IP22 IP44
Emergency machinery rooms
IP22 IP22 IP22 IP22 IP22
IP22 IP44
General store rooms
IP22 IP22 IP22 IP22 IP22
IP22 IP22
Pantries
IP22 -
IP22 IP22 IP22
IP22 IP44
Provision rooms
IP22 -
IP22 IP22 IP22
IP22
IP22
-
-
-
-
IP34
IP44
IP55
-
-
IP44 -
IP34
IP44
IP55
IP44 -
IP44 -
IP34
IP44
IP55 (3)
IP44 -
IP44 IP44 IP34
IP44
IP55
-
IP44 -
IP44
IP55
Machinery spaces above floor (5) plates
Bathrooms & Showers Machinery spaces below floor
Increased danger of liquid and/or mechanical damage
Closed fuel oil or lubricating oil Ballast pump rooms Refrigerated rooms
Increased danger of liquid and/or mechanical damage
Galleys and Laundries
-
IP34
IP44 -
IP44 IP44 IP34
IP44 IP44
Open decks
Exposure to heavy seas
IP56 -
IP56 -
IP55
IP56 IP56
Bilge wells
Exposure to submersion
-
-
IPX8
-
-
-
(3)
IPX8
Notes 1.
Empty spaces shown with “–” indicate installation of electrical equipment is not recommended.
2.
“Accessory” includes switches, detectors, junction boxes, etc.
3.
Socket outlets are not to be installed in machinery spaces below the floor plates, enclosed fuel and lubricating oil separator rooms or spaces requiring certified safe type equipment.
1.2.11 Fire Fighting Systems and Equipment
Fire fighting systems and equipment for vessel service functions not associated with 97
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the process facilities are to be in accordance with the applicable requirements of TCVN 6259-5:2003
.
Fire fighting systems and equipment for protection of
hydrocarbon process and associated systems are to be in accordance with Appendix VII, Section 9 . 1.2.12 Machinery
Machinery and equipment not associated with the process facilities are to be in accordance with the applicable requirements of TCVN 6259-3:2003 . Machinery forming a part of the hydrocarbon processing facilities are to be in accordance with applicable requirements of Appendix VII, Part 9 . Refer to Section 5 of this Guide regarding process related machinery. 1.2.13 Equipment
Equipment not associated with the process facilities are to be in accordance with the applicable requirements of TCVN 6259-7B:2003 and TCVN 6259-2:2003 . Equipment forming a part of the hydrocarbon processing facilities are to be in accordance with applicable requirements of Appendix VII, Part 9 . Refer to Section 5 of this Guide regarding process related equipment . 1.2.14 Safety Equipment
See requirements in TCVN 6278:2003 and Appendix VII, Part 9 . 1.3 1.3.1
Column-stabilized Vessels General
The design and construction of the lower hull, columns, deck and deckhouses of column-stabilized type installations are to be based on all applicable requirements of TCVN 5309-5319:2001 . However, the design criteria, as given in TCVN 53095319:2001, can be modified to reflect the different structural performance and demands expected of a vessel in ocean service, compared to a vessel positioned at a particular site on a long-term basis.
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1.3.2
Definitions
See Section 1 for the definition of criteria that constitute a column-stabilized vessel. For vessels that are considered column-stabilized type, the definitions of primary vessel characteristics can be found in TCVN 5309:2001. 1.3.3
Loading Criteria
A vessel’s modes of operation should be investigated using anticipated loads, including gravity loads together with relevant environmental loads due to the effects of wind, waves, currents, and, where deemed necessary by the Owner or designer, the effects of earthquake, temperature, fouling, ice, etc. A loading plan is to be prepared for each design. This plan is to show the maximum uniform and concentrated loadings to be considered for all areas for each mode of operation. The minimum deck loadings is shown in TCVN 5310:2001. 1.3.4
Wave Clearance
Unless deck structures are satisfactorily designed for wave impact, reasonable clearance between the deck structures and the wave crests is to be ensured for all afloat modes of operation, taking into account the predicted motion of the vessel relative to the surface of the sea.
Calculations, model test results or prototype
experiences are to be submitted for consideration. 1.3.5
Structural Design
The design of the vessel is to be based on the applicable portions of TCVN 53095319:2001. Where the conditions at the installation site are less than those for full ocean service that are the bases of the Mobile Offshore Drilling Unit Rules, the design criteria for various components of the vessel structure may be reduced to reflect these differences. However, when the installation site conditions produce more arduous demands, it is mandatory that the design criteria be increased appropriately. 1.3.5.1Scantlings
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Vessel’s scantlings, including deck (upper structure), columns and lower hulls are to be designed in accordance with TCVN 5309-5319:2001 , with special attention to the effects and control of corrosion. 1.3.5.2Deckhouses
The design of the deckhouse is to comply with the requirements of TCVN 6259-2: 2005. 1.3.5.3Helicopter Deck
The design of the helicopter deck is to comply with the requirements of TVCN 5310:2001and technical Regulation for helicopter deck on offshore installation. 1.3.5.4Protection of Deck Openings
All deck openings, hatch covers and companionway sills are to comply with TCVN 6259-2:2005 . 1.3.5.5Guards and Rails
Guards and rails are to comply with the requirements of TCVN 6259-2:2003 and latest modifications. 1.3.5.6Machinery and Equipment Foundations
Foundations for equipment subjected to high cyclic loading, such as mooring winches, chain stoppers and foundations for rotating process equipment, are to be analyzed to ensure satisfactory strength resistance. Local structure in way of fairleads, winches, etc., forming part of the position mooring system is to be capable of withstanding forces equivalent to the breaking strength of the mooring line. 1.3.5.7Materials and Welding
Column stabilized vessels are to be constructed from steel selected in accordance with TCVN 5317:2001 , including the topsides facilities (strength deck) where the deck contributes to the strength of the vessel. 100
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All fabrication and welding are to comply with the requirements in TCVN 5318:2001. The weld type and sizing are to be shown on the scantling drawings or in the form of a welding schedule and are to comply with the Rules that govern the steel selection. 1.3.6
Engineering Analysis of the Vessel’s Primary Structure
1.3.6.1General
Document necessary to verify the structural strength of the vessel is to be submitted for review. The criteria in this Subsection relate to the analyses required to verify the scantlings selected in the basic design in 1.3.5 . Except as provided in TCVN 53095319:2001, the results of analysis that are required in this subsection cannot be used to reduce the scantlings established from 1.3.5 . Depending on the specific features of the offshore installations, additional analyses to verify and help design other portions of the vessel structural components will be required.
Such additional analyses
include those for the deck structural components supporting deck-mounted equipment and the vessel structure interface with the position mooring system. Analysis criteria for those two situations are given in 1.3.7. 1.3.6.2Strength Analysis of the Vessel’s Primary Structure
The primary structure of the vessel is to be analyzed using the loading and environmental conditions stipulated below. Conditions representative of all modes of operation are to be considered to determine critical cases. Calculations for critical conditions are to be submitted for review. The analysis is to be performed using recognized calculation methods and is to be fully documented and referenced. The environmental loads are to be developed in accordance with 1.3 and 1.4 , Part 2 ” In the design of the vessel’s in-place strength, the following design environmental conditions should be considered: •
Severe Storm Condition Environmental condition which produces a maximum response with a return 101
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period up to and including 100 years.
The design responses of a column-
stabilized vessel are prying/squeezing forces, torsion moments, longitudinal shear forces between lower hulls and deck accelerations. •
Normal Operations Condition Environmental conditions that are expected to occur frequently during the service life.
1.3.6.3Fatigue Analysis
The possibility of fatigue damage due to cyclic loading is to be considered in the design of the primary structures of a column-stabilized vessel. Special attention is to be given to the major connections between the bracing members, column and deck. Attention should also be given to structural notches, cutouts, brackets, toes and abrupt changes of structural sections. A fatigue analysis using an appropriate loading is to be performed to predict the service life of the vessel and determine the most effective inspection plan. 1.3.6.4Acceptance Criteria
The total assessment of the structure and details is to be performed against the failure modes of material yielding, buckling and ultimate strength and fatigue.
The
reference acceptance criteria of each mode is given as follows. (1) Material Yielding The criteria indicated in TCVN 5310:2001 should be used. (2) Buckling and Ultimate Strength The criteria indicated in TCVN 6259-2:2003 should be used. Alternatively, the criteria specified in other recognized standards can be used. (3) Fatigue The minimum allowable fatigue life is to be FS times the design service life, 102
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where FS is the factor of safety. FS depends on the inspectability of the structure, as well as the criticality of the structure. The FS values to be used in calculating the minimum fatigue life are as follows: FS = 3.00 For areas that are easy to inspect and are “non-critical” areas. FS = 10 For areas that are non-inspectable or “critical” areas. The word “critical” implies that failure of these structural items would result in progressive failure of the structure and may lead to catastrophe. For existing vessels, the remaining fatigue life of the vessels is to be assessed and the supporting calculations submitted for review. Special consideration is to be given to the effects of corrosion and wastage on the remaining fatigue life of existing structures. Any areas determined to be critical to the structure are to be free of cracks, and the effects of stress risers is to be determined and minimized. Critical areas may require special analysis and survey. 1.3.7
Analysis and Design of Other Major Structures
The analysis and design criteria to be applied to the other pertinent features of the vessel structural design are to conform to recognized practices acceptable to the Bureau. For the column-stabilized vessel, the following will need to be considered in the vessel structure design: the interface between the position mooring system and the vessel structure or the effects of the structural support reactions from deckmounted equipment modules. 1.3.7.1Position Mooring/Vessel Interface
The local foundation structure and vessel structure is to be checked for the given mooring loads using an appropriate FEA model. The mooring loads to be used in the analysis are to be the breaking strength of the mooring lines. The interface structure between the deck equipment or module structure and the vessel is to comply with the requirements in 1.7, Part 5. 103
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1.3.8
Stability
1.3.8.1Transit Voyage Stability
During transit voyages to and from the operational site, the vessel is to meet the stability requirements of TCVN 5309-5319:2001 . 1.3.8.2On-Site Stability
All vessels are to have positive metacentric height ( GM) in calm water equilibrium position for all afloat conditions, including temporary positions during fabrications, installations, ballasting and deballasting. All vessels are to have sufficient stability at intact, as well as damage, condition. The intact and the damage stability to withstand the overturning effect of the force produced by the defined “operating intact wind,” “severe storm intact wind” and “damaged wind” are to be investigated in accordance with TCVN 5309-5319:2001 under which the vessel was classed.
The wind velocities for calculating the wind
overturning moments are to be established using the site-specific environmental report and are to be identified in the design basis. The wind velocities used in TCVN 5309-5319:2001 for unrestricted service are quoted below for reference. Table 3.4 The wind velocities for unrestricted area
Conditions
Minimum Wind Velocity
Damaged
25.8 m/s
( 50 knots)
Operating Intact
36.0 m/s
( 70 knots)
Severe Storm Intact
51.5 m/s
(100 knots)
For the purpose of determining compliance with these stability requirements, it is to be assumed that the vessel is floating free of mooring restraints. However, detrimental effects of catenary mooring systems or of the thrusters for dynamically positioned vessels are to be considered. 104
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Vessels designed to ballast or deballast through designated draft ranges or “zones” need only comply with the above positive metacentric height requirement when ballasting or deballasting through these designated “zones.” The Owner is responsible for ensuring that such operations are performed only with proper loading conditions and during periods of acceptable weather. Alternative stability criteria may be considered acceptable by the Bureau. 1.3.9
Marine Piping Systems
Marine piping systems are those systems (such as bilge, ballast, fuel oil and tank venting) that are required to conduct marine operations and are not associated with process facilities.
Marine piping systems are to comply with TCVN 5309-
5319:2001. 1.3.10 Electrical Systems
Electrical systems are to comply with TCVN 5316:2001 and Appendix VII ,Part 9 . For area classification requirements, refer to Appendix VII , Part 9 of this Guide. 1.3.11 Fire Fighting Systems and Equipment
Fire fighting systems and equipment for vessel service functions not associated with the process facilities are to be in accordance with TCVN 5314:2001 . Fire fighting systems and equipment for protection of hydrocarbon process and associated systems are to be in accordance with Appendix VII , Section 9 . 1.3.12 Machinery and Equipment
Machinery and equipment not associated with the process facilities are to be in accordance with the applicable requirements of TCVN 5311 and 5315:2001 . Machinery and equipment forming a part of the hydrocarbon processing facilities are to be in accordance with the applicable requirements of Appendix VII , Part 9 .See Part 5 of this Guide regarding machinery and equipment associated with the process facilities . 105
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1.3.13 Safety Equipment
See requirements in TCVN 5319:2001 and Appendix VII, Part 9 . 1.4 1.4.1
Existing Tanker Hull Structures (Ordinary Conversions) Introduction
Regulation 1.1 and 1.2 apply to a new-build hull structure or a major conversion of an existing vessel. Major conversion is conversion that affects a principal dimension of the hull. Regulation 1.4 is applied for the typically more common conversion of an existing tanker to a ship-type FPI . The direct application of the criteria contained in 1.1 and 1.2 as the basis of acceptance of the hull structure of an existing tanker for FPI service is fully permissible . However, modified acceptance criteria, given in 1.4, may be used for some aspects of the vessel’s structural design as an ‘Ordinary Conversion’ for FPI service.
Regulation 1.4 applies to both the ‘Change of Class Designation’ and
‘Transfer of Class’ situations where the acceptance of the existing vessel’s hull structure as an ‘Ordinary Conversion’ is pursued. ‘Change of Class Designation’ refers to an existing tanker classed by the Bureau which is being converted to FPI service. Another situation, the ‘Transfer of Class’, refers to a vessel transferring into the Bureau’s classification from another Society. 1.4.2
General
All applicable criteria contained in this FPI Guide are to be used in the classification of an ‘Ordinary Conversion’, except that some criteria (primarily in1.1 and 1.2 ) can be modified. Specific modifications are given below for the affected criteria. The major criteria differences for the ‘Ordinary Conversion’ arise in the acceptance of the ‘basic design’ of the hull structure. The ‘basic design’ of the hull structure relates to hull girder longitudinal strength and local scantling selection. The minimum target fatigue life of the hull structure is also fundamentally different for a converted tanker . For a new-build, the minimum target fatigue life is 20 years; 106
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for an existing vessel to be converted to FPI service, the minimum target fatigue life can be less than 20 years . 1.4.3
Alternative Acceptance Criteria for the ‘Basic Design’ of the Hull Structure
1.4.3.1 General
For a vessel being converted from a tanker to FPI service, the design and construction of the existing hull, superstructure and deckhouses are to meet the applicable criteria of TCVN 6259 at the time of original build, or as applicable, the criteria presented in 1.4.7 below. In order to be eligible to apply this approach,Two flowing condition is to be satisfied, as described in Appendix 1,Section 9 of this Guide (which reflect expected conditions from the long-term mooring of the vessel at an offshore site), are 1.0 or less, and 1.2.5 on the required hull girder longitudinal strength is satisfied. If either of these conditions is not met, then the application of this alternative approach is not considered valid. In that case, the unmodified FPI Guide (i.e., Regulation 1.1
and 1.2 ) criteria or an alternative determined in
consultation with the Bureau is to be applied. In addition, it is expected that the applicable and most recent versions of the criteria contained in the Load Line, SOLAS and MARPOL Conventions issued by the International Maritime Organization are to be considered. 1.4.3.2 Structural Design of the Hull
Steel renewals to be performed at the time of conversion must be carefully considered. Estimation of corrosion rates are to be made, taking into account any future corrosion protection measures to be used, previous service experience, the type and temperatures of stored fluids and the other variables significantly affecting the corrosion rate. The anticipated corrosion predicted to occur over the proposed on-site life of the FPI is to be considered in the design. The loads arising from the static tank testing condition are also to be directly considered in design. It should be noted that in some instances such cases might control the design, especially when the overflow heights are greater than normally 107
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encountered in oil transport service or the severity of environmentally-induced load components and cargo-specific gravity are less than usual. 1.4.3.3 Engineering Analyses of the Hull Structure
(1) General Documentation necessary to verify the structural adequacy of the vessel is to be submitted for review. Depending on the specific features of the offshore installation, additional analyses to verify and to help design other portions of the hull structure will be required. Such additional analyses include those for the deck structural components supporting deck-mounted equipment and the hull structure interface with the position mooring system. Analysis criteria for these two situations are given in Part 6. Provided a scantling of the existing tanker is not below its renewal limit, or if it is to be renewed at the time of conversion, then it can be modeled in the structural analyses in the conventional SafeHull manner. That is, use the “net scantling,” which is the “as-built” value minus the current Rule (SafeHull based) specified “nominal design corrosion value.” (2) Strength Analysis of the Hull Structure Steel renewals to be performed at the time of conversion must be carefully considered. Estimation of corrosion rates are to be made, taking into account any future corrosion protection measures to be used, previous service experience, the type and temperatures of stored fluids and the other variables significantly affecting the corrosion rate. The anticipated corrosion predicted to occur over the proposed on-site life of the FPI is to be considered in the design. For vessels of 150 meters (492 feet) in length and above, the extent of Finite Element Method (FEM) strength analysis requirements are indicated in Appendix III,Part 9 of the Steel Vessel Rules. For vessels less than 150 m in length of double hull construction or of unusual design, see Steel Vessel Rules for Finite Element Method 108
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(FEM) analysis requirements. When it is permitted that the design can be based on site-specific environmental conditions, the load components from the Steel Vessel Rules to be used in the strength analyses can be adjusted as explained in 1.2.6 and Appendix 2, Part 9. Generally, the strength analysis is carried out to determine the load distribution in the structure. An appropriate three-dimensional FEM model is to be analyzed for this purpose. To determine the stress distribution in major supporting structures, particularly at intersections of two or more members, two-dimensional fine mesh FEM models are to be analyzed using the boundary displacements and load from the 3D FEM model.
To examine stress concentrations such as at intersections of
longitudinal stiffeners with transverses and at cut outs, fine mesh 3D FEM models are to be analyzed. In the strength analyses, the following loading conditions are to be considered: i.
General Cargo Load Patterns : as mentioned above, when the basic
design of the vessel is accepted as an ‘Ordinary Conversion’, this analysis may not be required. Where it is intended to perform this analysis, see the unmodified text of this paragraph appearing in 1.2.7. ii.
Tank Test Conditions : analysis for these conditions is required; see the unmodified text of this paragraph appearing in 1.2.7.2. (4)
iii.
Transit Condition : analysis to demonstrate the adequacy of the hull structure during the transit to the installation site is required; see the unmodified text of this paragraph appearing in 1.2.7.2.(8).
1.4.3.4Fatigue Analysis
For all vessels of 150 m and above, the extent of fatigue analysis required is indicated in Appendix, Part 5 of the Steel Vessel Rules. For vessels of less than 150 m, the requirements are indicated in Appendix, Part 5 of the Steel Vessel Rules. The fatigue strength of welded joints and details at terminations, which may or may 109
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not be located in highly stressed areas are to be assessed, especially where higher strength steel is used. These fatigue and/or fracture mechanics analyses, based on the combined effect of loading, material properties, and flaw characteristics are performed to predict the service life of the structure and determine the most effective inspection plan.
Special attention is to be given to structural notches, cutouts,
bracket toes, and abrupt changes of structural sections. Consideration is also to be given to the following analyses: (1)
The cumulated fatigue damage during the voyage from the fabrication or previous site to the operation site is to be included in the overall fatigue damage assessment.
(2)
The stress range due to loading and unloading cycles is to be accounted for in the overall fatigue damage assessment, if it is significant. For any structural detail, a minimum criterion for computing the stress range is to consider the tanks at 90 percent full load capacity and at its residual capacity, with adjacent tanks also at their residual capacity. A maximum fluid specific gravity of 0.9 is to be adopted for calculating the pressure range. The stress range is also to account for pressure range variation due to sloshing of the fluid inside the tank at the various filling levels, if it is significant.
1.4.3.5Acceptance Criteria
The total assessment of the structure is to be carried out against the failure modes of material yielding, buckling and ultimate strength, and fatigue.
The reference
acceptance criteria of each mode are given as follows. (1)
Material Yielding Criteria is given in Appendix VI ,Section 9 .
(2)
Buckling and Ultimate Strength Criteria given in TCVN 6259-2:2003 is applicable.Criteria in recognized standard is applicable
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(3)
Fatigue
For existing vessels that are employed in FPI service, the estimated remaining fatigue lives of the critical structural details are to be assessed and the supporting calculations submitted for review. Consideration is to be given to the effects of corrosion and wastage on the remaining fatigue life of existing structures. The required design fatigue life is 20 years. This design fatigue life can be modified for existing classed tankers converting to FPI service. The minimum acceptable design fatigue life for the FPI is the greatest of: •
The on-site design life of the FPI,
•
The time to the next Special Survey or five years.
In the absence of more detailed environmental data, stress ranges are to be obtained in consideration of the unrestricted service environment. The fatigue strength is based on a cumulative damage theory, which infers that the structure is likely to experience a fatigue failure after a finite number of stress cycles occur. This is especially important when looking at FPI conversions. The vessel has already experienced cycles of stress during the “ship” phase of its life and it will experience additional cycles during the “FPI” phase of its life. The basic concept is to keep the total number of cycles below the number that results in failure. For FPIs converted from tankers, an analysis procedure accounting for both the ship and FPI phases of the total fatigue life is acceptable. First, the historical cumulative fatigue damage up to the time of conversion is to be calculated through realistic temporal weighting of wave environments experienced along the service routes during the service life of the vessel. This will provide an estimate of the remaining fatigue life of the structural members at the time of conversion. Second, the expected cumulative fatigue damage is to be calculated using sitespecific wave environment and operational conditions. This will establish the 111
TCVN 6474 -3:2007
basis for comparison of expected fatigue life of the hull structure and the remaining life of the members being investigated. When the route and site-specific wave environments are used and they produce less severe fatigue demands than the unrestricted service environment of the Steel Vessel Rules, credit can be given to the less severe environment by increasing the expected fatigue life. For site-specific environmental conditions producing more severe fatigue demand than the Steel Vessel Rule basis, the site-specific environmental data are to be used. Due to the structural redundancy and relative ease of inspection inherent in typical hull structures of ship-type vessels, there is no further need to apply additional factors of safety above what is already built into the fatigue classification curves cited in the above reference. However, for areas of the structure which are noninspectable or “critical”, such as in way of the connections to the mooring or production systems additional factors of safety should be considered. Any areas determined to be critical to the structure are to be free of cracks, and the effects of stress risers should be determined and minimized. Critical areas may require special analysis and survey. For an existing classed tanker being converted to FPI service, the minimum fatigue lives of the structural components covered in 1.4.3.6 and 1.4.3.7 can be changed from 20 years to the alternative controlling value mentioned above . 1.4.3.6Acceptance Criteria Mooring/Hull Interface
The total assessment of the structure is to be performed against the failure modes of material yielding, buckling and ultimate strength, and fatigue. acceptance criteria of each mode is given as the following: (1) Material Yielding Criteria is given in Appendix VI ,Part 9 . (2) Buckling and Ultimate Strength 112
The reference
TCVN 6474 -3:2007
Criteria given in TCVN 6259-2:2003 is applicable .Recognized standard is applicable . (3) Fatigue The required target fatigue life is 20 years. However, due to the critical nature of these connections, additional factors of safety may be needed. (Also see Part 7.) The fatigue life of the hull structure is to be investigated in accordance with recognized standard and submitted for review as described below: i.
For vessels with a forward end mooring, the fatigue life of the vessel should be investigated from the watertight bulkhead aft of the mooring to the fore end of the vessel.
ii.
For vessels with mid body mooring, a three-tank analysis, where the mooring is in the middle hold, is to be investigated.
iii.
For aft end mooring, the fatigue life should be investigated from the watertight bulkhead forward of the mooring to the aft end of the vessel.
Structural members in way of the turret structure or other mooring structure are to be effectively connected to the adjacent structure in such a manner as to avoid hard spots, notches and other harmful stress concentrations. Special attention is to be given to cutouts, bracket toes and abrupt changes of structural sections. These areas are considered to be critical to the vessel and are to be free of cracks. The effects of stress risers in these areas are to be determined and minimized. 1.4.3.7Turret Mooring
A turret mooring system is one type of station keeping system for a floating installation and can either be installed internally or externally. Both internal and external turret mooring systems will allow the vessel to weathervane around the turret. The mooring lines are fixed to the sea bottom by anchors or piles.
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TCVN 6474 -3:2007
For an internal turret system, the turret is supported in the vessel by a system of bearings. The loads acting on the turret will pass through the bearing system into the vessel. Typically, a roller bearing is located near the vessel deck level, and radial sliding bearing is located near the keel of the vessel. For an external turret mooring system, the vessel is extended to attach the turret mooring system at the end of the vessel. The loads acting on an internal turret system include those basic loads induced by the mooring lines, risers, gravity, buoyancy, inertia and hydrostatic pressure. Other loads, such as wave slam and loads resulting from misalignment and tolerance, that may have effect on the turret should also be considered in the design. In establishing the controlling turret design loads, various combinations of vessel loading conditions ranging from the full to minimum storage load conditions, wave directions, and both collinear and non-collinear environments are to be considered. The mooring loads and loads applied to the external turret structure are transferred through its bearing system into the vessel. The load range and combinations to be considered and analysis methods are similar to those stated for an internal turret mooring system, with additional consideration of environmentally-induced loads on the turret structure A structural analysis using finite element method is required to verify the sufficient strength of the turret structure. The allowable von Mises stress of the turret structure is to be 0.6 of the yield strength for the operational intact mooring design conditions, as specified in 1.3,Part 2. A one-third increase in the allowable stress is allowed for the design storm intact mooring design conditions and for the design storm one-line broken mooring condition to verify the turret structure mooring attachment locations and supporting structure. (Note: the yield strength is to be based on the specified minimum yield point or 72 percent of the specified minimum tensile strength, whichever is the lesser.)
The buckling strength check for the turret structures is to be performed using requirement in TCVN 6259-2:2003 or recognized standard . A fatigue evaluation of 114
TCVN 6474 -3:2007
the turret system using a spectral method or other proven approaches is needed to determine the fatigue lives for the turret components. Fatigue life of the turret should not be less than three times the design life for inspectable areas and 10 times for uninspectable areas. 1.4.4
Assessing the ‘Basic Design’ of the Hull Structure
1.4.4.1General
The ‘Ordinary Conversion’ approach relies on a review of the hull’s ‘basic design’. The review consists of an assessment of the hull girder strength and midship region scantling review of local plating and plating stiffeners that directly contribute to the hull girder strength. Two major purposes for this review are to assess the adequacy of the hull girder and local strength, and to “benchmark” the values upon which local scantling renewals are to be based 1.4.4.2‘Basic Design’ Review Acceptance Criteria
The review of the ‘basic design’ of an existing hull structure, which is applicable to a tanker classed for unrestricted service, does not account for the increased or reduced local structural element strength requirements that could result from the long-term, moored operation of the vessel at an offshore site. The approach to the design review also allows variations in the acceptance criteria that can be based on: •
The Bureau’s Rules from the year of build of the vessel with the Bureau’s permissible corrosion limits for renewal; or
•
The Bureau’s Current Rules with the Bureau’s permissible corrosion limits for renewal; or
•
The prior IACS member’s approved scantlings using that society’s permissible corrosion limits.
The combination of the variety of ways to review local scantlings and the permissibility to account for site-dependent effects on global and local hull structural
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TCVN 6474 -3:2007
strength requirements can lead to a range of acceptable procedures. If it is desired to account for the on-site environmental effects and how these affect the required scantlings, it will be necessary to compute the required scantlings on this basis. 1.4.5
Optional: “Time to Steel Renewal” Assessment
The reviews and assessments described above will establish: the notional acceptability of hull girder strength and existing scantlings, structural areas and components requiring renewal and the limits to which structural areas and components may corrode before requiring renewal.
However, these review and
analysis procedures in themselves do not predict how much time in operation it may take before structural steel renewal limits could be reached. In a case where the design operational life is relatively long, the assumed corrosion rate is relatively fast or there are only small differences between the actual scantlings and the renewal limits, it could be very important to the Operator to pursue a hull structure life assessment.
This should be done to better assure freedom from disruption in
operation that might arise over the need to perform steel renewals during the operational life of the FPI. It should be noted that this type of analysis is suggested, but is not required for classification. 1.4.6
Survey Requirements for an “Ordinary Conversion”
1.4.6.1Conversion Survey Requirements
(1)
Drydocking Survey The vessel is to be placed on drydock and surveyed in accordance with the requirements of 1.4, Part 8.
(2)
Special Survey of Hull A Special Periodical Survey of Hull, appropriate to the age of the vessel, is to be carried out in accordance with 1.7, Part 8. All requirements for Closeup Survey and thickness measurements are to be applied.
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TCVN 6474 -3:2007
(3) Modifications All modifications to the vessel are to be carried out in accordance with VRapproved drawings and to the satisfaction of the attending Surveyor. In general, the IACS Shipbuilding and Repair Quality Standard (SARQS) requirements are to be followed unless a recognized shipyard or national standard is already established in the shipyard. 1.4.6.2Structural Repairs/Steel Renewal
All renewed material should be replaced by steel of the same or higher grade and to the approved design scantling or greater. 1.4.6.3Bottom Plate Pitting repair
The following repair recommendations apply to pitting found in both ballast and cargo tank bottom plating. (1) Repair Recommendations There are four main approaches used for dealing with severe bottom pitting. •
Partially Crop and Renew Affected Bottom Plating. Partial cropping and
renewal is primarily a matter of: proper welding technique, selection of an adequately sized plate insert and the appropriate nondestructive examination (NDE) of repaired areas. •
Clean Pitted Areas and Cover with Special Coating. Cleaning out and
covering with special coating without use of filler or weld build-up need only be limited by the maximum allowable depth of the pits (or allowable minimum remaining thickness of the bottom plating) permitted from a strength or pollution risk standpoint. The allowable loss of bottom crosssectional area must also be considered. •
Clean Pitted Areas and Fill with Plastic Compound.
Use of plastic
compound filler, such as epoxy, can be considered similar to above 117
TCVN 6474 -3:2007
method. •
Fill by welding.
Filling
with welding
warrants more serious
consideration. Suggested welding practices for bottom plating are noted below. (2)
Pitting up to 15% of Bottom Plating Thickness No immediate remedial action is necessary, however, if the surrounding tank bottom is specially coated, corrosion progress in the pitted areas may be very rapid due to the area ratio effect of protected versus non-protected surfaces, therefore, as applicable, the coating is to be repaired.
(3)
Scattered Pitting Up To 33% (1/3t) of Bottom Plating Thickness Those pitting may be filled with epoxy or other suitable protective compounds, provided the loss of area at any transverse section of the strake in question does not exceed 10%. Any areas that have been repaired by this method must be “mapped” and noted for close-up survey in the Survey and Inspection Plan .
(4) Pitting of Any Depth may be Welded, Provided : Pitting may be welded, provided there is at least 6 mm (0.25 in.) remaining original plating thickness at the bottom of the cavity and there is at least 75 mm (3 in.) between adjacent pit welding areas. The maximum nominal diameter of any pit repaired by welding may not exceed 300 mm (12 in.). (5) Requirements for the Welding of Pits •
Pit Welding. It is recommended that pit welding in bottom plating be built up at least 3 mm (0.125 in.) above the level of the surrounding plating and then ground flush.
•
Surface Preparation. Pitted areas are to be thoroughly cleaned of rust, oil and cargo residues prior to welding.
118
TCVN 6474 -3:2007 •
Filler Metal. When welding, the filler metal grade appropriate to the pitted base metal and preheating, if applicable, are to be employed.
•
Layer of Welding Metal. A layer of weld metal is to be deposited along a spiral path to the bottom center of the pitted excavation. The slag is to be completely removed and the next successive layer is to be similarly deposited to build up the excavation at least 3 mm
•
Nondestructive Examination. All welds to pitted areas in bottom plating are to be subject to nondestructive examination with particular attention to boundaries of the welded areas and at intersections of the welded areas and existing structural welding. Also, for welds of higher-strength steels, the NDE method is to be suitable for detecting sub-surface defects
•
Doublers. Fitting of a doubler over pits is not considered a satisfactory repair.
1.5
Tension Leg Platforms
Tension Leg Platforms is to be designed according to recognized Standards . 1.6
Spar Vessels
Spar Vessels is to be designed according to recognized Standards .
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TCVN 6474 -3:2007
BLANK PAGE
120
NATIONAL STANDARD
TCVN 6474-4:2007
Second Edition
RULES
FOR
CLASSIFICATION
AND
TECHNICAL
SUPERVISION
OF
FLOATING STORAGE UNITS PART 4: POSITION MOORING SYSTEM
Reference documents and definitions: See Part 1, TCVN 6474-1:2007 and this Part The position mooring system includes the mooring, anchoring and dynamic positioning (if any) systems. The purpose of the position mooring system is to keep the Floating Installation on station at a specific site. The Position Mooring System includes mooring lines, connectors and hardware, winches, piles, anchors and thrusters. For a single point mooring system, the turret, turntable, disconnecting system, buoy, anchoring legs, etc., are also part of the system. 1.
Mooring system
1.1.
Definitions
Typically, there are two types of position mooring systems: conventional spread mooring and single point mooring, as defined in Part 1. Thruster-assisted systems are defined in Part 1, Item 2.5.4. 1.1.1.
Spread Mooring A spread mooring is a system with multiple catenary mooring lines anchored to piles or drag anchors at the sea bed. The other end of each line is individually attached to winches or stoppers on the vessel through fairleads as necessary. A catenary mooring line may have one or more line segments, in-line buoy(s) (spring 121
TCVN 6474-4:2007
buoy) or sinker(s) (clumped weight) along the line. 1.1.2.
Single Point Mooring (SPM) A single point mooring allows the vessel to weathervane. Three typical types of single point mooring systems that are commonly used are described below:
1.1.2.1. CALM (catenary anchor leg mooring): A catenary anchor leg mooring system consists of a large buoy anchored by catenary mooring lines. The vessel is moored to the buoy by soft hawser(s) or a rigid yoke structure. 1.1.2.2. SALM (single anchor leg mooring): A single anchor leg mooring system consists of an anchoring structure with built-in buoyancy at or near the water surface and is itself anchored to the seabed by an articulated connection. 1.1.2.3. Turret Mooring: A turret mooring system consists of a number of mooring legs attached to a turret that is designed to act as part of the vessel, allowing only angular relative movement of the vessel to the turret, so that the vessel may weathervane. The turret may be mounted internally within the vessel or externally from the vessel bow or stern. Typically, a spread mooring arrangement connects the turret to the seabed. 1.1.2.4. Yoke Arm: A yoke arm is a structure at the end of the vessel that only allows angular relative movement between the vessel and the mooring attachment to the seabed. The above mentioned types of single mooring system are illustrated in Part 1. 1.2.
System Conditions
The various conditions of a Floating Installation which are important for the designer to consider are as follows: 1.2.1.
Intact Design A condition with all components of the system intact and exposed to an environment as described by the design environmental condition (DEC).
122
TCVN 6474-4:2007
1.2.2.
Damaged Case with One Broken Mooring Line A condition with any one mooring line broken at the design environmental condition (DEC) that would cause maximum mooring line load for the system. The mooring line subjected to the maximum load in intact extreme conditions when broken might not lead to the worst broken mooring line case. The designer should determine the worst case by analyzing several cases of broken mooring line, including lead line broken and adjacent line broken cases. For a disconnectable mooring system with quick release system, the mooring analysis for a broken line case may not be required. For unusual (non-symmetric) mooring pattern, mooring analysis for the broken line case for the disconnectable environmental condition may be required. For a system utilizing the SALM concept, the case with one broken mooring line is not relevant. A case considering loss of buoyancy due to damage of a compartment of the SALM structure should be analyzed for position mooring capability. The loss of thruster power or mechanical failure on thruster-assisted position mooring systems will be considered on a case-by-case basis.
1.2.3.
Transient Condition with One Broken Mooring Line A condition with one mooring line broken (usually the lead line) in which the moored vessel exhibits transient motions (overshooting) before it settles at a new equilibrium position. The transient condition can be an important consideration when proper clearance is to be maintained between the moored vessel and nearby structures. An analysis for this condition under the design environmental condition (DEC) is required. The effect of increased line tensions due to overshoot upon failure of one mooring line (or thruster or propeller if mooring is power-assisted) should also be considered.
1.3.
Mooring Analysis
The analysis of a mooring system of a Floating Installation includes the 123
TCVN 6474-4:2007
determination of mean environmental forces and the extreme response of the vessel in the DEC (design environmental condition, see in Part 2, Item 1.4) and the corresponding mooring line tension. A moored system is a dynamic system that is subjected to steady forces of wind, current and mean wave drift force, as well as wind and wave-induced dynamic forces. Calculations of the maximum mooring system loading are to consider various relative directions of the wind, wave and current forces. Depending on the level of sophistication and analysis objectives, quasi-static, quasi-dynamic (begins with calculating the low-frequency responses of the moored vessel followed by superposition of the wave-frequency motions) and dynamic analysis methods may be used. Both frequency and time domain approaches are acceptable. The designer should determine the extreme vessel offset and line tension in a manner consistent with the chosen method of analysis. For the final design of a permanent mooring system, the dynamic analysis method is to be employed to account for mooring line dynamics. For deepwater operations with large numbers of production risers, the mooring system analysis should take into account the riser loads, stiffness and damping due to significant interactions between the vessel/mooring system and riser system. 1.3.1.
Mean Environmental Forces and Moments The calculation of steady forces and yawing moments due to wind and current are outlined in Part 2. The available methods of calculating hydrodynamic characteristics and hydrodynamic loading are also indicated. The drift forces and yawing moments on a moored vessel consist of a mean wave drift force, along with the slowly varying oscillatory drift force at or near the natural period of the springmass system of the moored vessel. The mean and oscillatory low frequency drift forces may be determined by model tests or using hydrodynamic computer programs benchmarked against model test results or other data. Designers may use API RP 2SK for estimating purposes, if applicable, that
124
TCVN 6474-4:2007
provides mean drift force charts for ship type vessels with lengths from 122 m (400 feet) to 165 m (540 ft) and less general information for column stabilized vessels. Vessel-specific information is to be provided based on appropriate analysis or model testing or both. 1.3.2.
Maximum Offset and Yaw Angle of the Vessel The wave-induced vessel dynamic responses can be calculated by the methods outlined in Part 2, Item 1.4.5.2. The maximum offset consists of static offset due to wind, current and wave (steady drift), and both wave and wind-induced dynamic motions (high and low frequency). The maximum responses of surge, sway and yaw are to be determined, as follows, in accordance with API RP 2SK:
⎧S mean + Slf (max) + S wf ( sig ) ⎫ ⎬ ⎩S mean + Slf (sig ) + S wf (max) ⎭
S max = max ⎨
trong đó: =
S mean
mean vessel offset due to wind, current and mean (steady) drift force (m)
S lf(sig)
=
significant single amplitude low frequency motion (m)
S lf(max)
=
maximum values of low frequency motion (m)
S wf(sig)
=
significant single amplitude wave frequency motion (m)
S wf(max)
=
maximum values of wave frequency motion (m)
Alternatively, the maximum excursion can be determined through model tests. The maximum values of low frequency motion, S lf(max) and wave frequency motion, S wf(max) are typically calculated by multiplying the corresponding significant single
amplitude values by a factor C that is to be calculated as follows: C= N =
1
2
2 ln N
T T a
where: 125
TCVN 6474-4:2007
=
T
specified storm duration (seconds), minimum of 10,800 seconds (i.e., 3 hours). For areas with longer storm duration (e.g., a monsoon area), a higher value of T may need to be considered.
T a
=
average response zero up-crossing period (seconds).
For low frequency components, T a can be taken as the natural period, T n of the vessel with mooring system. T n can be estimated from the vessel mass (or mass moment of inertia for yaw motion), m (including added mass or mass moment of inertia for yaw motion), and mooring system stiffness, k for lateral and yaw motions at the vessel's mean position and equilibrium heading as follows: T n = 2π
m k
The quantities m and k are to be in consistent units. Note: The above formula may not be applicable for C for estimating either wave
frequency or low frequency motions. Refer to API RP 2SK for statistical limits on the value of C and applicable recognized industry standards. Other parameters affecting the low frequency motions, such as system stiffness and damping forces, are to be calibrated and the supporting data submitted to VR for review. 1.3.3.
Maximum Line Tension The mean tension in a mooring line corresponds to the mean offset and equilibrium heading of the vessel. The design (maximum) mooring line tension, T max is to be determined as outlined in API RP 2SK and is summarized below:
⎧Tmean + Tlf (max) + T wf ( sig ) ⎫ T max = max ⎨ ⎬ ⎩Tmean + Tlf (s ig ) + T wf (max) ⎭ where: T mean 126
=
mean mooring line tension due to wind, current and mean
TCVN 6474-4:2007
(steady) drift force (N) =
T lf(sig)
mean mooring line tension due to wind, current and mean (steady) drift force (N)
T wf(sig)
=
significant single amplitude wave frequency tension (N)
The maximum values of low frequency tension, T lf(max) and wave frequency tension, T wf(max) are to be calculated in the same procedure as that of obtaining the motions
at wave frequency and low frequency described in Item 1.3.2. 1.3.4.
Mooring Line Fatigue Analysis The fatigue life of mooring lines is to be assessed using the T-N approach, using a T-N curve that gives the number of cycles, N to failure for a specific tension range, T . The fatigue damage ratio, Di for a particular sea state, i is estimated in
accordance with the Miner's Rule, as follows: Di =
ni N i
where: ni
=
number of cycles within the tension range interval, i for a given sea state
=
N i
number of cycles to failure at tension range, i as given by the appropriate T-N curve
The cumulative fatigue damage, D for all of the expected number of sea states, NN (identified in a wave scatter diagram), is to be calculated as follows: D =
NN
∑D
i
i =1
D is not to exceed unity for the design life, which is the field service life multiplied
by a factor of safety, as specified in Table 4-4. It is recommended that a detailed fatigue analysis following the procedure outlined in Part 7.5 of API RP 2SK be performed for the permanent mooring system. 127
TCVN 6474-4:2007
The fatigue life of each mooring line component is to be considered. T-N curves for various line components are to be based on fatigue test data and a regression analysis. 1.4.
Mooring Line Design
The mooring lines are to be designed with the factors of safety specified in Table 44 with respect to the breaking strength and fatigue characteristics of mooring lines. These factors of safety are dependent on the design conditions of the system, as well as the level of analyses. Allowances for corrosion and abrasion of a mooring line should also be taken into consideration. Table 4-4: Factor of Safety for Anchoring Lines Factor of Safety All Intact
Dynamic Analysis
(DEC)
1.67
Quasi-Static
(DEC)
2.00
One broken Line (at New Equilibrium Position)
Dynamic Analysis
(DEC)
1.25
Quasi-Static
(DEC)
1.43
Dynamic Analysis
(DEC)
1.05
Quasi-Static
(DEC)
1.18
One broken Line (Transient)
Mooring Component Fatigue Life w.r.t. Design Service Life
1.5.
Inspectable areas
3.00
Non-inspectable and Critical Areas
10.00
Hawser Loads
Hawsers that are used to temporarily secure vessels to the component which is permanently anchored to the seabed are to meet the requirements of TCVN 6809:2001. 128
TCVN 6474-4:2007
1.6.
Dynamic Positioning Systems
Dynamic positioning systems installed for position mooring purposes will be subject to approval in accordance with the requirements of TCVN 5311:2001 or applicable recognized standards. 1.7.
Thruster Assisted Mooring Systems
Where Floating Installations are equipped with thrusters to assist the mooring system, the thrusters are subject to approval by VR or applicable recognized standards. The contribution of the thrusters in the mooring system design will be reviewed on a case-by-case basis. 1.8.
Mooring Equipment
Mooring equipment for Floating Installations includes winches, windlasses, chain, wire rope, in-line buoys and fairleads. Anchors and single point mooring mechanical systems are addressed elsewhere in this Part. For the review of mooring equipment, VR will apply the requirements in published TCVN/ relevant Guide for such equipment, are listed below: Buoyancy Tanks
ASME Boiler and Pressure Vessel Code
Chain
TCVN 6259-7B:2003 and TCVN 5311:2001
Winches and Windlasses
TCVN 5311:2001
Wire Rope
API Spec 9A and RP 9B
In general, the design load for the fairlead and its connection to the vessel is the breaking strength of the mooring line. Chain stoppers used in position mooring systems are to be designed for the breaking strength of the mooring line. The fatigue life for inspectable chain stoppers is not to be less than three times the service life. For chain stoppers that cannot be readily inspected, the fatigue life is to be at least 10 times the service life. 129
TCVN 6474-4:2007
The chain stoppers are to be function tested at the specified proof load to the satisfaction of the attending Surveyor. 2.
Anchor Holding Power
Different types of foundation systems used for floating installations are drag anchors, pile anchors, vertically loaded anchors (VLAs) and suction piles. Gravity boxes, grouted piles, templates, etc., may also be used and are considered to be within the scope of classification. 2.1.
Drag Anchor
For a mooring system with drag anchors, the mooring line length should be sufficiently long such that there is no angle between the mooring line and the seabed at any design condition, as described in Part 2, Item 1.3.1. Drag anchor holding power depends on the anchor type, as well as the condition of the anchor deployed in regard to penetration of the flukes, opening of the flukes, depth of burial, stability of the anchor during dragging, soil behavior of the flukes, etc. The designer should submit to the Bureau the performance data for the specific anchor type and the site-specific soil conditions for the estimation of the ultimate holding capacity (UHC) of an anchor design. Because of uncertainties and the wide variation of anchor characteristics, exact holding power is to be determined after the anchor is deployed and test loaded. The maximum load at anchor, F a is to be calculated, in consistent units, as follows: Fa = Pline − WsubWD − F f F f = f sl LbedWsub
where:
130
Pline
=
maximum mooring line tension (N)
WD
=
water depth (m)
f sl
=
frictional coefficient of mooring line on sea bed at sliding
TCVN 6474-4:2007
=
Lbed
length of mooring line on seabed at the design storm condition, not to exceed 20 percent of the total length of a mooring line(m)
=
W sub
submerged unit weight of mooring line (N/m)
Note: The above equation for F a is strictly correct only for a single line of constant, W sub without buoys or clump weights. Appropriate adjustments will be required for
other cases. The coefficient of friction f sl depends on the soil condition and the type of mooring line. For soft mud, sand and clay, the following values of f sl along with the coefficient of friction at start f st for wire rope and chain may be considered representative in Table 4-5: Table 4-5: Coefficient of Friction Coefficient of Friction, f
2.2.
Starting ( f st )
Sliding ( f sl)
Chain
1.00
0.70
Wire Rope
0.60
0.25
Conventional Pile
Conventional pile anchors are capable of withstanding uplift and lateral forces at the same time. Analysis of the pile as a beam column on an elastic foundation is to be submitted to VR for review. The analyses for different kinds of soil using representative soil resistance and deflection (p-y) curves are described in API RP 2A and API RP 2T, as applicable. The fatigue analysis of the pile should be submitted for review. 2.3.
Vertically Loaded Drag Anchors (VLA)
VLAs can be used in a taut leg mooring system with approximately a 35 to 45 degree angle between the seabed and the mooring lines. These anchors are designed to withstand both the vertical and horizontal loads imposed by the mooring line. The structural and geotechnical holding capacity design of the VLA 131
TCVN 6474-4:2007
are to be submitted for review. This is to include the ultimate holding capacity and the anchor's burial depth beneath the seabed. Additionally, the fatigue analysis of the anchor and the connectors joining the VLA to the mooring line should be submitted for review. The safety factors of VLA anchors' holding capacity are specified in Table 4-6 Table 4-6: Factor of Safety for Anchor Holding Capacities Factor of Safety Drag Anchors
Intact Design
(DEC)
1.50
Broken Line Extreme
(DEC)
1.00
Intact Design
(DEC)
2.00
Broken Line Extreme
(DEC)
1.50
Dynamic Analysis
(DEC)
1.05
Quasi-Static
(DEC)
1.18
Vertically Loaded Anchors (VLAs)
One broken Line (Transient)
Pile Anchors
Refer to API RP 2A, API RP 2T as applicable Suction Piles
Intact Design
(DEC)
1.5 to 2.0*
Broken Line Extreme
(DEC)
1.2 to 1.5*
* The safety factor to be used in the design should be based on the extent of the geotechnical investigation, confidence in the prediction of soil-pile behavior, experience in the design and behavior of suction piles in the area of interest, and the inclination of the mooring line load. 2.4.
Suction Piles
Suction pile anchors are caisson foundations that are penetrated to the target depth by pumping out the water inside of the pile to create underpressure within the pile. 132
TCVN 6474-4:2007
They may typically consist of a stiffened cylindrical shell with a cover plate at the top and an open bottom and generally have larger diameters and are shorter in length than conventional piles. These piles can be designed to have a permanent top or a retrievable top depending on the required vertical holding capacity. The padeye for the mooring line connection can be at the top or at an intermediate level depending on the application of the suction pile. Suction pile anchors are capable of withstanding uplift and lateral forces. Due to the geometry of the suction piles, the failure modes of the soils may be different than what are applicable for long slender conventional piles. The safety factors for the suction piles' holding capacity are specified in Table 4-6. Geotechnical holding capacity and structural analyses for the suction piles are to be submitted to verify the adequacy of the suction piles to withstand the in-service and installation loads. Additionally, fatigue analysis of the suction piles are to be submitted to verify the adequacy of the fatigue life of the critical locations. Installation analyses are to be submitted to verify that the suction piles can be penetrated to the design penetration and that the suction piles can be retrieved, if necessary. It is suggested that a ratio of at least 1.5 between the force that would cause uplift of the soil-plug inside of the pile and the effective pile installation force be considered in the penetration analysis. 2.5.
Factor of Safety
The factors of safety for anchor holding capacity in the design of drag anchors, VLAs and suction piles are specified in Table 4-6. The required ultimate holding capacity should be determined based on mooring line loads derived from a dynamic analysis to account for mooring line dynamics. Conventional pile anchors should meet the recommended factors of safety as specified in API RP 2A, and API RP 2T, as applicable. 3.
Field Test
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After the mooring system is deployed, each mooring line will be required to be pull-tested. During the test, each mooring line will be pulled to the maximum design load determined by dynamic analysis for the intact design condition and held at that load for 30 minutes. For certain high efficiency drag anchors in soft clay, the test load may be reduced to not less than 80 percent of the maximum intact design load. For all types of anchors, the attainment of design-required minimum soil penetration depth is to be verified at the site. VR will determine the necessity of a maximum intact design tension pull test depending on the extent of the geotechnical investigation, the magnitude of loading, analytical methods used for the geotechnical design and the experience with the soils in the area of interest. For suction piles, VR will also review the pile installation records to verify the agreement between the calculated suction pressures and the suction pressure used to install the suction piles. For conventional piles, VR will review the pile installation records to verify the agreement between the calculated pile driving blow counts and the actual blow counts required to drive the piles to the design penetration. If the maximum intact design tension pull tests are waived, VR will require preloading each anchor to a load that is necessary to develop the ultimate holding capacity of the anchor, but not less than the mean intact design tension, and to ensure the integrity and alignment of the mooring line. For a disconnectable mooring system, the pull test load will be the greater of the following two values: (1) Maximum
design
load
for
"Disconnecting
Environmental
Condition
(DISEC)", i.e., the limiting extreme environmental condition at which the vessel is to be disconnected. (2) Maximum design load of mooring line for the "Design Environmental Condition (DEC)" without the vessel, i.e., the disconnected mooring system alone. 134
TCVN 6474-4:2007
4.
Single Point Moorings - CALMs, SALMs, Turrets and Yokes
4.1.
Design Loadings
The design of structural and mechanical components is to consider the most adverse combination of loads, including, but not limited to, those listed below, and is to be submitted for review: (1) Dead Loads (2) Dynamic Loads due to motions (3) Mooring Loads (4) Fatigue Loads 4.2.
Structural Components
In general, structural components are to be designed to a recognized code or standard. The structural and buoyancy elements of CALMs and SALMs are to comply with the requirements of the Single Point Mooring Rules - TCVN 6809:2001. Minimum mooring turret and yoke arm scantlings are to comply with TCVN 5310:2001, Item 4.5.3 4.3.
Mechanical Components
Mechanical components of an SPM usually include the Product Distribution Unit (PDU), bearings, driving mechanisms and various types of connectors. TCVN 6809:2001 are generally applicable to these components, and in cases where specific requirements are not addressed in the TCVN 6809:2001 , VR will review those components for compliance with the following standards and codes: Product Distribution Unit
ASME Boiler and Pressure Vessel Code AISC Steel Code ANSI B31.3 (for Pipe Swivels) 135
TCVN 6474-4:2007
Bearings
AFBMA Codes (Anti Friction Bearing Manufacturers Association ASME 77-DE-39
Connectors: driving mechanisms ASME Boiler and Pressure Vessel Code AISC Steel Code API Standards as applicable Ancillary mechanical components, such as structural connectors, uni-joints, chain jacks, turret retrieval mechanisms, hoists, winches, quick connect and disconnect devices, are to be designed in accordance with Vietnam (or International) applicable industry standards, codes and published recommended practices if was approved by VR. 4.4.
Hazardous Areas and Electrical Installations
Requirements for hazardous areas and electrical installations are in TCVN 6809:2001. 4.5.
Fire Fighting Equipment
Fire fighting equipment is to comply with TCVN 6809:2001. Additionally, for the internal turret mooring arrangement, Appendix VII, Part 9 is applicable. 4.6.
Product Piping Systems and Floating Hoses
Product piping systems and floating hoses are to comply with the applicable requirements of TCVN 6809:2001 và , Appendix VII, Part 9. 4.7.
Turret Mooring
A turret mooring system is one type of station keeping system for a floating installation and can either be installed internally or externally. Both internal and external turret mooring systems will allow the vessel to weathervane around the turret. The mooring lines are fixed to the sea bottom by anchors or piles. 136
TCVN 6474-4:2007
For an internal turret system, the turret is supported in the vessel by a system of bearings. The loads acting on the turret will pass through the bearing system into the vessel. Typically, a roller bearing is located near the vessel deck level, and radial sliding bearing is located near the keel of the vessel. For an external turret mooring system, the vessel is extended to attach the turret mooring system at the end of the vessel. The loads acting on an internal turret system include those basic loads induced by the mooring lines, risers, gravity, buoyancy, inertia and hydrostatic pressure. Other loads, such as wave slam and loads resulting from misalignment and tolerance, that may have effect on the turret should also be considered in the design. In establishing the controlling turret design loads, various combinations of vessel loading conditions ranging from the full to minimum storage load conditions, wave directions, and both collinear and non-collinear environments are to be considered. The mooring loads and loads applied to the external turret structure are transferred through its bearing system into the vessel. The load range and combinations to be considered and analysis methods are similar to those stated for an internal turret mooring system, with additional consideration of environmentally-induced loads on the turret structure. A structural analysis using finite element method is required to verify the sufficient strength of the turret structure. The allowable von Mises stress of the turret structure is to be 0.6 of the yield strength for the operational intact mooring design conditions, as specified in Item 4.3. A one-third increase in the allowable stress is allowed for the design storm intact mooring design conditions and for the design storm one-line broken mooring condition to verify the turret structure mooring attachment locations and supporting structure. Note: the yield strength is to be based on the specified minimum yield point or 72 percent of the specified minimum tensile strength, whichever is the lesse.)
The buckling strength check for the turret structures is to be performed using the criteria in TCVN 6259-2:2003 or other applicable industry standards. A fatigue 137
TCVN 6474-4:2007
evaluation of the turret system using a spectral method or other proven approaches is needed to determine the fatigue lives for the turret components. Fatigue life of the turret should not be less than three times the design life for inspectable areas and 10 times for uninspectable areas. 4.8.
Turret/Vessel Structural Interface Loads
The vessel structure in the way of the turret mooring system interface is to be capable of withstanding forces (obtained as the maximum of all the design conditions considered) from the systems and is to be suitably reinforced. Mooring forces transmitted to the vessel's supporting structure by the turret mooring system are to be determined by an acceptable engineering analysis. The transmission and dissipation of the resulting mooring forces into the vessel's structure are required to be determined by an acceptable engineering method, such as finite element analysis. The loads acting on the vessel's supporting structures due to the turret system are mainly transmitted through the upper and lower bearings. The loading conditions are chosen to cause the most unfavorable loads and the load combinations that may occur. The derivation of mooring loads is to be determined as described in the previous Subsection of the "Turret Mooring System." The structural model used in the finite element analysis for the vessel's supporting structure should extend to a reasonable distance of the vessel to minimize the effects due to the boundary conditions. 5.
Surveys During Construction
Items of equipment to be used in a mooring system are to be examined during the fabrication process, and testing is to be performed to the satisfaction of the attending Surveyor. Components fabricated by welding are to meet the requirements of TCVN 62596:2003 and are to be to the Surveyor's satisfaction. Specifications to be used for chain, wire rope and connecting hardware are to be submitted for review. Physical testing, including break, pull, dimensional and nondestructive testing, is required to 138
TCVN 6474-4:2007
be performed in accordance with the submitted specifications to the satisfaction of the attending Surveyor.
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TCVN 6474-4:2007
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140
NATIONAL STANDARD
TCVN 6474-5 : 2007 Second edition
RULES FOR CLASSIFICATION AND SUPERVISION OF FLOATING STORAGE UNITS
TECHNICAL
PART 5 : HYDROCARBON PRODUCTION AND PROCESS SYSTEMS
Reference standards and definitions: see Part 1, TCVN 6474-1: 2007
1. Hydrocarbon Production and Process Systems 1.1.
General requirements
Hydrocacbon production and procesing system are to comply with requirements of Aoppendix VII, Part 9 and sections 1.2 to 1.11 below. 1.2.
Application
This section is applicable to the following: (1)
Systems that process hydrocarbon liquids, gasses, or mixtures from completed wells.
(2)
Production support systems associated with the process system, such as water, steam, hydraulics, pneumatics, and power supply to the process.
(3)
Fire protection systems for the protection of the process equipment and the process area
(4)
Systems that are utilized for stimulation of a completed well, such as chemical, gas, or water injection downhole through a Christmas tree. 141
TCVN 6474-5:2007
(5)
Power generation systems for export purposes.
(6)
Electrical systems and components associated with the process facilities.
(7)
Systems other than those mentioned above, such as methanol production and/or processing, and desalination, will be the subject of special consideration .
The scope of the hydrocarbon process system is defined in Regulation 2.4, Section 2 of this Rule. The scope of the hydrocarbon process system may also include the controls for the well head and subsurface safety valve, if these are included in the process safety shutdown system. 1.3.
Subsea Equipment.
1.3.1 Subse equipment is not a part of the classification boundaries as defined in 3.2, Part
1. However. subsea equipment may be classed if desired by the Owner, provided these items are approved by the VR for compliance with the requirements of recognized standards. 1.3.2 The VR is prepared to certify the subsea equipment if the manufacturers / Owner
wish to obtain VR
Certification. The design, contruction, and testing of the subsea
equipment are to be accordance with Appendix VII, Part 9. 1.4.
Use other standards
Use of other standards in the design and construction of the equipment and components is subject to pror approval and acceptance by the VR. The standards being applied are to be adhered to in its entirety. 1.5.
Non-standard Equipment
Equipment not designed to a recognized standard may be accepted based on approval of detailed design calculations and testing results that verify the integrity of the equipment. 1.6.
Design and Construction
1.6.1 General
Hydrocarbon process systems and associated equipment are to be designed to minimize the 142
TCVN 6474-5:2007
risk of hazards to personnel and property. This criterion is implemented be showed in the amendment VII, section 9. The implementation of this criterion is intended to: (1)
Prevent an abnormal condition from causing an upset condition.
(2)
Prevent an upset condition from causing a release of hydrocarbons.
(3)
Safely disperse or dispose of hydrocarbon gasses and vapors released.
(4)
Safely collect and contain hydrocarbon liquids released.
(5)
Prevent formation of explosive mixtures.
(6)
Prevent ignition of flammable liquids or gasses and vapors released.
(7)
Limit exposure of personnel to fire hazards.
1.6.2 Arrangements
General arrangement drawings are to be submitted for review in accordance with Regulation 5.2, section 1. The arrangements depicted are to comply with Regulation 17.3.2 and 17.7.4 , Appendix VII, applicable Sections of TCVN 6259:2003 and 5309-5319:2001, as applicable. 1.6.3 Structural Considerations
Structure that supports production facilities or forms an integral part of the equipment is to be designed to a recognized standard. Plans and calculations are to be submitted for reviewing. Process liquid weights and dynamic loads due to vessel motions and other loads, such as wind imposed loads, are to be considered . 1.7. 1.7.1
Process System
Submittals
The various data and plans that are to be submitted to the VR for review are listed Regulation 5.2, section 1.
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TCVN 6474-5:2007
Piping System and Manifolds
1.7.2
Piping of the process and process support systems are to comply with the requirements of recognized standards (refer to API 14E and ASME/ANSI B31.3 and B31.1). 1.7.3 Pressure Relief and Depressurization Systems
Pressure relief and depressurization systems are to comply with the requirements of recognized standards (refer to API RP 520 and API RP 521). 1.7.4 Process Equipment
Process equipments
are to comply with the applicable requirements in Subsections
17.3.9 of Appendix VII, section 9. 1.7.5 Prime Movers
Internal combustion engines and gas or steam turbines are to comply with Subsections 17.4.2 of Appendix VII, section 9. Safety Systems
1.7.6
Safety systems are to comply with Subsections 17.3.4 and 17.3.5 of Appendix VII, section 9. Specific items to be addressed are as follows: (1) The process safety and shutdown system is to comply with the requirements of recognized standards (refer to API RP 14C). (2) Fire detection and gas detection is to comply with the requirements of recognized standards (refer to API RP 14C and API RP 14G). The location of the fire and gas detectors is to be to the satisfaction of the VR . (3) The process safety shutdown system is required to shut down the flow of hydrocarbon from all wells and process systems. The discharge of processed hydrocarbons to the export lines is also to be controlled by the process safety shutdown system. Redundancy is to be provided in the power source to the
144
TCVN 6474-5:2007
process safety shutdown system such that, upon failure of the main power source, the secondary power source is brought online automatically. 1.7.7 Control System
Control systems, in general, are to comply with regulation 6 of Appendix VII, Section 9. Additionally, computer based control systems are to comply with the following: (1)
The control system is to be totally independent of the alarm and monitoring system.
(2)
Where computers are utilized for monitoring, alarm, and control, the arrangements are to be such that a fault in one of these functions will not impair the capability of other functions.
(3)
The computer system for monitoring alarms and control is to include redundancy arrangements in order to maintain continued operation of the hydrocarbon process system.
1.7.8 Quick Disconnect System
(1) Where the Floating Installation is fitted with a quick disconnect system, the control of this system is to be .totally independent of the process safety shutdown system required for the hydrocarbon process system. However, the source of power for the process safety shutdown system and controls for the quick disconnect system need not be totally independent, provided that the failure in one system does not render the other system ineffective, e.g., failure through leakage in the hydraulic or pneumatic control lines. (2) Means are to be provided for the activation of quick disconnect system from the control station and locally in the vicinity where the disconnect arrangements are located. (3) The disconnect arrangement is to be designed such that, upon its activation, all process flow to the Floating Installation is automatically stopped immediately without leakage of process fluids 145
TCVN 6474-5:2007
1.7.9 Electrical Installations
Electrical installations for the hydrocarbon process system are to comply with the requirements regulation 5 of Appendix VII, Section 9. 1.8.
Hazardous Area Classification
Hazardous areas are to be delineated and classified as required Regulation 3 of Appendix VII, Section 9. In general, API RP 500 & API RP 501 is to be applied to process areas, and the Steel Vessel Rules TCVN 6259:2003 or the Mobile Offshore Drilling Unit Rules TCVN 5309-5319:2001 are applied to non process areas. 1.9.
Fire protection
Fire extinguishing systems and fire fighting equipment associated with the hydrocarbon process facilities are comply with regulation 5 of appendix VII, Part 9. 1.10. Fabrication and testing
Inspection and testing of hydrocarbon process and associated equipment at the manufacturer’s facility are to be in accordance with Table 17-1 of Appendix VII, Part 9. Construction and fabrication is to be performed in accordance with approved planls and procedures. Respresentative survey interventions are listed as follows. 1.10.1 Pressure Vessels, Accumulators, Heat Exchangers, Separators, and Manifolds.
(1)
The construction, fabrication and material are accordance with design standard
shown on the approved plans. (2) Witness weld procedure and welder performance qualification tests. (3) Visual inspection of weld joints, witness non-destructive testing. (4) Fit up and joining of all pipe connections and pipe supporting arrangement. (5) Dimensional inspection during fit-up and after completion. (6) Internal examination. (7) Witness calibration of hydrostatic testing equipment. 146
TCVN 6474-5:2007
(8) Witness hydrostatic tests. 1.10.2 Pumps, Compressors and Diesel/Gas Engines
(1) Witness mechanical running tests. (2) Witness testing of auxiliary equipment and protective devices (controls, filters, coolers, oil pumps, alarms, trips, governors). 1.10.3 Motors and Generators
(1) Functional running test for machines greater than 100 kW. (2) Witness testing of auxiliary equipment and protective devices. 1.10.4 Switchboards and Control Panels 1.10.4.1
Inspection
and witness testing at the manufacturer's facility is not required for
switchboards and control panels. These components will be accepted for use, provided they have been designed and constructed to a recognized national or international code or standard . 1.10.4.2
Control and alarm panels for fire protection and safety systems are to be
function-tested at the manufacturer's facility. These tests are to be conducted in the presence of the Surveyor. 1.10.5 Process and Process Support Piping 1.10.5.1
Fabrication, inspection and testing of process and utility piping is to be
performed to the satisfaction of the attending Surveyor.
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148
NATIONAL STANDARD
TCVN 6474-6 : 2007
Second edition
RULES FOR CLASSIFICATION FLOATING STORAGE UNITS
TECHNICAL
SUPERVISION
OF
PART 6: IMPORT AND EXPORT SYSTEMS
Reference standards and definitions: see Part 1, TCVN 6474-1: 2007. 1. Import and export systems 1.1.
General
This section applies to import and export systems utilized in Floating Installations. These systems include rigid and flexible risers, connecting flow lines, submerged jumpers, and floating offloading hoses.
1.1.1 Riser Classification Boundaries
1.1.1.1 The import/export system is assumed to consist of only rigid, flexible hose/pipe or a
combination of both rigid and flexible hose/pipe, and associated riser components, such as the tensioning system, buoyancy modules, line buoys, permanent clamps, anchoring systems, and safety control systems 1.1.1.2 In a typical Floating Installation import (or export) system, the applicable starting and
termination points are the riser's connection point to the PLEM and the riser's connection point to the vessel or floating structure. The connection points are typically the discharge (or input) flange of the PLEM and the input (or discharge) flange of the vessel or floating structure 1.1.1.3 The Import System: The Import System is to include the import risers starting from the
Import PLEM but not including the Import PLEM. For a typical flexible riser system, the import riser may start at the PLEM/wellhead flanges and terminate at the input flange of the 149
TCVN 6474-6:2007
vessel or floating structure. 1.1.1.4 The Export System :
The Export System is to include the export risers that may start
from the discharge flanges of the vessel or floating structure and terminate at the Export PLEM but not including the Export PLEM 1.1.1.5 Where Import and/or Export Risers induce mooring restraint to the Floating Installation,
design, construction will require special consideration.
Basic Design Considerations
1.1.2
1.1.2.1 The import/export,'system is to be designed to maintain its integrity under the most
unfavorable combination of external environmental loads, internal loads due to fluid contents, pressure and temperature, and accidental loads. This is accomplished by ensuring that riser system design is consistent and compatible with the design philosophy used for the Floating Installation. 1.1.2.2 The dynamic response of the import/export system is to be investigated to the level of
detail necessary to ensure that interference between the floating production vessel and the associated mooring system does not affect the integrity of the vessel or the import/export system. 1.1.2.3 The riser is to to be designed in confomity with the maximum vessel offset. 1.2.
Submission of Plans and Design
Documentation outlining the design, manufacture, installation, and operating assumptions applicable to the project is to be submitted for review at the initiation of the project. The following summarizes the typical information that is required to help ensure that the design basis and criteria selection is consistent with the design philosophy. In general, the following are to be submitted for review: (1)
Site plan indicating bathymetric features, the location of obstructions to
be removed, the location of permanent manmade structures, and other important 150
TCVN 6474-6:2007
features related to the characteristics of the sea floor. (2)
Material specifications for the import/export system, its supports, and coatings.
(3)
Pipe manufacture, testing, and quality control procedures.
(4)
Flow diagrams indicating temperature and pressure profiles.
(5)
Specifications and plans for installation, field testing, inspection,
anticipated component replacement, and continued maintenance of the riser system. (6) 1.3.
Environmental and geotechnical report.
Environmental conditions.
Environmental loads are to be calculated in accordance with the method described in Part 2 1.4.
System Design and Analysis
1.4.1 General requirements 1.4.1.1 The design of the import/export system should consider all modes of operating, testing,
survival, and accidental events. The import/export system should be analyzed to determine its response to the design events. Each individual component should be examined for its strength and suitability for the service conditions.
1.4.2 Rigid Risers
1.4.2.1 Design Analysis
The analysis of a rigid riser is to follow the appropriate sections of API RP 2RD and API RP 2T for all relevant design load cases. The establishment of the critical design condition must be verified by a suitable verified program that properly simulates the dynamic response of the entire system operating under the required design condition. The following items, as applicable, are to be appropriately accommodated in the analysis:
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TCVN 6474-6:2007
(1) Environmental conditions. (2) Boundary conditions. (3) Riser configuration. (4) Riser joint properties. (5) Buoyancy devices. (6) Vessel motion (RAO's). (7) Applicable site conditions. (8) Effects of internal contents. (9) Pressure testing and accidental conditions. 1.4.2.2 Design Limits
Rigid risers are to be designed against the following limits based on the design load cases being investigated. Maximum Stress, Stability, and Buckling . Allowable stresses in plain pipe are to be limited per
API RP 2RD. Overall stability of the riser and local pipe buckling should be evaluated. Maximum Deflection.
Acceptable limits of maximum deflection are to be determined
considering the inherent limitations of riser components, equipment used in the riser, and the need to avoid interference with the Floating Installation. Fatigue and Fracture. The riser system is to be designed to ensure that an adequate margin of
safety is available for critical components to counteract the effects of fatigue caused by cyclic fluctuations (due to both internal and external loads) over the anticipated life of the system. The cumulative damage calculated by the use of Miner's Rule is to be 0.1 or less for a critical component, which cannot be easily inspected or repaired. For non-critical components, which can be easily inspected, the cumulative damage should be 0.3 or less.
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1.4.3 Flexible Risers
1.4.3.1 place Analysis
(1)On-bottom stability for flexible flow lines (2)Static and dynamic analysis for flexible riser (3)A system dynamic analysis to ensure: (a)
Maximum tension and minimum radius of curvature are within the
manufacturer's recommendations. (b) Suspended portions of the flexible pipe (e.g., sag bends) are not allowed to bounce on the sea floor or experience compression that might cause kinks. (c)
Suspended flexible pipes are not allowed to chafe against each other, the vessel
body, or mooring lines. (4) Flow induced motion analysis (5) Flexible pipe layer stress analysis. (6) The stresses in the flexible pipe layers shall comply with the requirements of recognized standards (refer to API SPEC 17J). (7) Mechanical gripping devices should not cause damage to the weaker exterior layer. (8) Service life analysis (9) Corrosion protection system design. 1.4.3.2 Design Limits
Design limits established for the riser system are to be determined in accordance with recognized standards (refer to API RP 17B) and confirmed by performance/acceptance testing during the manufacture of the flexible riser and the associated components. Where sufficient test 153
TCVN 6474-6:2007
data and service history exist to confirm a component's capability, VR may consider the acceptance of this documentation in lieu of performance/ acceptance testing.
1.4.4 Export Vessel Transfer System
This system may be classed if requested. Export of fluid to an export vessel is usually limited to stabilized crude oil and is usually accomplished by: Side-by-side transfer,
•
•
Tandem transfer, or
•
Single Point Moored Buoy via a floating hose or riser.
For certification of these systems, VR requires compliance to OCIMF Standards and MARPOL. The OCIMF Standard is applicable for operating pressures not greater than 1.5 Mpa (15 bar gauge). In complying with these standards, VR requires the Owner to observe the guidelines as given in The OCIMF Guide to Purchasing, Manufacturing, and Testing of Loading and Discharge Hoses for Offshore Moorings. The operation and safety considerations for transfer of crude are to be contained in the Floating Installation's operations manual and consistent with the requirements outlined in The OCIMF Ship to Ship Transfer Guide and Chapter 6.
1.4.5 System Components
All system components are to be designed in accordance with the appropriate criteria of recognized standards. The specification for the design and manufacture of the components is to be submitted. The specification is to include at a minimum the performance criteria established from the riser design and analysis and give explicit acceptance criteria needed to ensure the compliance to these criteria.
1.4.6
Installation Analysis
The installation analysis is to address all aspects of installation procedure discussed in 1.1.6 Part 154
TCVN 6474-6:2007
7. Calculations to demonstrate the structural integrity of the riser and its auxiliary components are to be submitted for review. The riser pipe is to be checked for all installation loads, tension and bending combination (bending from chute, sleeve, roller, or drum), and loads caused by the installation of auxiliary components.
Loads from mechanical gripping devices, such as clamps and tensioners, are to be checked and are not to cause damage to the weaker exterior layer of the flexible pipe.
1.5.
Material
1.5.1 Material for Rigid Risers
Material and dimensional standards for steel pipe are to be in accordance with recognized standards (refer
ANSI/ASME B31.4 and B31.8, API RP 2RD), for respect to chemical
composition, material manufacture, tolerances, strength, and testing requirements.
1.5.2 Material for Flexible Risers
Recognized standards may be used to assess the adequacy of the material standards for flexible risers. (refer API RP 17B and API SPEC 17J)
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156
NATIONAL STANDARD
TCVN 6474-7 : 2007 Second Edition
RULES
FOR
CLASSIFICATION
AND
TECHNICAL
SUPERVISION
OF
FLOATING STORAGE UNITS PART 7: INSTALLATION, HOOK-UP AND COMMISSIONING
Reference documents and definitions: See Part 1, TCVN 6474-1:2007. 1.
Installation, Hook-up, and Commissioning
1.1.
General requirements
The requirements in this Part apply to the procedures to be submitted and the surveys to be performed by VR for all VR-classed Floating Installations. Prior to carrying out the installation, the installation procedures are to be submitted to VR. The installation procedures to be submitted are to include the following, where applicable. 1.1.1.
General Description General description of the entire layout of the mooring system and of the Floating Installation with risers, subsea pipelines and, as applicable, pipeline end manifolds (PLEMs).
1.1.2.
Pre-installation Verification Pre-installation verification procedures for the seabed condition in way of the installation site and contingency procedures for removing any obstacles found on site.
1.1.3.
Pile or Anchor and Mooring Line Installation Pile or anchor and mooring line installation procedures which are to include, but
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TCVN 6474-7:2007
are not limited to, the following:
-
General preparations for installation.
-
Rigging arrangements for piles, chaser pile and driving hammers.
-
Work barge setup during the various phases of installation, taking into consideration the prevailing weather conditions.
-
Anticipated pile driving resistance.
-
Pile penetration acceptance criteria established by design and pile refusal and overdrive contingency procedures.
-
Procedure for positioning of the pile orientation toward the center of the Position Mooring System and the criteria for allowable deviations of position and orientation.
-
Procedure for installation of the mooring line and the precautions to be taken in order toprevent any twisting of the mooring chains during installation.
-
Procedure for installation of anchors, including piggyback anchors, if applicable, and procedure for determining the installed positions and orientations of the anchors. Criteria for allowable deviations in positioning and orientation are also to be included.
1.1.4.
Tensioning and Proof Load Testing Tensioning and proof load testing procedures of the anchor piles or anchors and chain system are to include the following:
-
Rigging arrangements for proof load tension testing of the mooring chains, anchor or pile system.
-
Work barge setup to perform the proof load testing of the chains and anchor or pile system.
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-
Detailed tensioning procedure, including type of tensioning device to be utilized and tensioning operations.
-
Chain retrieval and abandonment procedures during tensioning.
-
Procedure for chain proof load tensioning by ballasting the Floating Installation, if applicable.
1.1.5.
Hook-up of the Anchor Chain System Procedure for hook-up of the anchor chain system to the Floating Installation, which is to include the following:
-
Rigging and towing procedures for positioning of the Floating Installation for hook-up to the mooring system.
-
Preferred ballast condition of the Floating Installation prior to the hook-up.
-
Procedure for sequential hook-up of the chains, repositioning of the Floating Installation and tensioning of the chains.
-
Method of determining the correct tension of the chains and the acceptable design tolerance.
-
Procedure for determining the positioning of the SPM system relative to the PLEM or wellhead and the acceptable design tolerance for the position of the SPM center relative to the PLEM or wellhead.
-
Method of securing the chain turntable from movement and the overall safety precautions for the entire hook-up installation.
-
Procedure for chain tensioning by ballasting the Floating Installation, if applicable.
1.1.6.
Import/Export System Installation The Import/Export System Installation Procedure is to be submitted for review in 159
TCVN 6474-7:2007
conjunction with the design review so that it can be verified that all appropriate installation loadings have been considered. The manual is to describe procedures to be employed during the installation of the import/export systems. In addition, the manual is to include a list of allowable environmental limits under which system installation may proceed. Abandonment procedures, retrieval procedures and repair procedures are to be supplied, when deemed necessary. 1.1.6.1. Rigid and Flexible Risers The procedure to hook-up the import/export risers to the Floating Installation is to include the following items, where applicable: (1) Handling and rigging of the rigid and flexible riser during installation. (2) Positioning of the work barge for the various phases of the installation. (3) Procedure for installation of the buoyancy tank and arch support and clump weight, if applicable, including steps to avoid riser interference and precautions against damaging the riser during installation. (4) Tie-in rigging technique for hook-up of both ends of the risers. (5) Procedure for hydrostatic testing of the risers. Hydrotest pressure and test duration are to be in accordance with API or other recognized code of practice. 1.1.6.2. Export Vessel Transfer System The procedure for installing the export system is to include the following items, as applicable. (1) Rigging, handling and make-up of the export hose system and precautions against damage during installation. (2) Fitting of all the necessary accessory and navigational aids. (3) Procedure for paying out of the hose string into the sea.
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TCVN 6474-7:2007
(4) Procedure for filling and testing the hose string. The required design and testing pressure and testing duration are to be provided. 1.1.7.
Disconnecting Procedure For disconnectable mooring systems, the procedures for the disconnecting and connecting of the Floating Installation's mooring system are to be submitted. These procedures are to include the abandonment and retrieval of the import and export systems. (Also see Operating Manual requirements.)
1.2.
Hook-Up Procedures Submittal
Any system component installation intentionally left incomplete to ease the installation of the Floating Installation at site is to be documented and a procedure for site hook-up and testing is to be submitted to VR. 1.3.
Start-Up and Commissioning Procedures Submittal
Start-up and commissioning procedures for the production system are to be submitted for review in Appendix VII, Part 9. 1.4.
Surveys during Installation of the Mooring Systems
During installation, the requirements as contained in the following paragraphs are to be verified or witnessed, where applicable, by the attending Surveyor. 1.4.1.
All mooring components are to be examined for transit damages prior to installation. Any damages found are to be dealt with to the satisfaction of the attending Surveyor.
1.4.2.
All applicable components required to be certified at the manufacturers' facilities have received certification.
1.4.3.
The area at and in the vicinity of the mooring site is to be surveyed by divers or remotely operated vehicles (ROVs) to ensure that there are no obstructions or debris prior to installation.
1.4.4.
During the installation of the anchors or anchor piles, the following are to be verified in order, where applicable: 161
TCVN 6474-7:2007
(1) Proper locking of all connecting shackles from chains to piles or anchors and chains to chains. (2) Sealing of all kenter shackle locking pins. (3) All complements of anchor chains for correct sizes and lengths. (4) All anchor pile or anchors are installed in the designed positions and orientations and are within the allowable design tolerance. 1.4.5.
The paying out of the anchor chains after the installation of the piles is to be performed in accordance with the approved procedures.
1.4.6.
Unless otherwise approved by the attending Surveyor, the first pair of anchor chains to be cross-tensioned is the first pair to be installed.
1.4.7.
The cross-tensioning is to be verified to ensure all pretensioning loads are in accordance with the design and there is no movement or pullout of the anchor piles.
1.4.8.
Upon successful completion of the pretensioning, the subsequent hooking up of all of the chain legs to the chain stoppers in the turntable is to be verified.
1.4.9.
During tensioning of the chains for the position mooring system, the relative position of the mooring system's center to the PLEM is to be verified for compliance with the design specifications and tolerance.
1.4.10. Upon completion, the chain tension is to be verified by measuring the catenary angles of the chains for compliance with the design specifications and tolerance. Any excess length of chain above the chain stoppers is to be removed, unless it is designed to be retained in the chain well. 1.5.
Surveys During Installation of the Import/Export System
During installation of the import/export system, the following items are to be witnessed by the Surveyor, as applicable. 1.5.1.
The riser is to be examined for damage as it is being paid out, and sufficient tension is to be maintained to ensure the riser is free of deformations or buckles. The buoyancy tank and arch support are to be verified as being installed in the correct position relative to the water surface end of the riser.
162
TCVN 6474-7:2007
1.5.2.
The installation of the riser clamps on the buoyancy tank and arch support are to be monitored to ensure that the riser is adequately secured and not damaged due to excessive tightening of the clamps.
1.5.3.
The installation of the end flanges of the riser is to be monitored for compliance with the approved procedures.
1.5.4.
Upon completion of installation, the entire underwater complement of components is to be generally examined and verified by divers or ROVs for compliance with the reviewed design specifications and configurations. At a site with limited visibility, alternative means of verifying the installation are to be submitted for review and are to be performed to the satisfaction of the attending Surveyor.
1.5.5.
Hydrotesting of the import/export system is to be performed in accordance with the approved procedure. The test pressure and duration of the hydrotest should follow the appropriate codes, such as ANSI/ ASME B31.8, API RP 2RD and RP 17B.
1.5.6.
The make-up of the export floating hose string is to be verified for compliance with the approved procedures. Suitable gaskets for the hose flanges, positioning of all navigational aids, correct location of the breakaway couplings and tightening of the flange bolts are also to be verified.
1.5.7.
During the paying out of the hose string, verification is to be made that the hose string bend radii are not smaller than the manufacturer's recommended limits.
1.5.8.
Upon completion of installation, the entire export hose string is to be hydrostatically tested in accordance with the approved procedure and codes.
1.5.9.
Subsea controls, if installed, are to be satisfactorily tested.
1.5.10. All navigational aids are to be functionally tested and proven in working order. 1.6.
Surveys during Hook-Up
Survey during hook-up is to be performed following reviewed procedures and is to include the following, where applicable: 1.6.1.
Piping hook-up is to be verified for compliance with the reviewed drawings and procedures. Welds are to be visually inspected and nondestructive testing (NDT) performed as required. Upon completion of hook-up, the affected sections are to be hydrostatically tested to 1.5 times the design working pressure and proven tight. 163
TCVN 6474-7:2007
1.6.2.
Electrical hook-up is to be verified for compliance with the approved drawings and procedures. Proper support for cables and proper sealing of cable entries to equipment are to be verified. Upon completion of the hook-up, the affected sections of the equipment and cabling are to be insulation tested and proven in order. All grounding is also to be verified as being in order.
1.6.3.
Instrumentation hook-up is to be verified for compliance with the reviewed drawings and procedures. Tubing supports are to be verified. Upon completion, all systems are to be functionally tested and proven as being in order. The manufacturer's limits on bend radii for any component of the instrumentation system are to be observed.
1.6.4.
Mechanical equipment hook-up is to be verified for compliance with the reviewed drawings and procedures, including the grounding of the equipment. Upon completion, all equipment is to be functionally tested and proven as being in order.
1.7.
Demonstration of the Disconnectable Mooring System
1.7.1.
For a disconnectable mooring system, the system's capability to disconnect free from its mooring system is to be demonstrated to the satisfaction of the attending Surveyor, in accordance with approved test procedures.
1.7.2.
During the disconnect operation, the time taken to effectively free the Floating Installation from the mooring system is to be recorded in the Operation Manual.
1.8.
Surveys During Start-Up and Commissioning
The start-up and commissioning of hydrocarbon production systems are to be verified by the attending Surveyor. The scope of the start-up and commissioning to be verified by the Surveyor is to include the following items: 1.8.1.
The start-up and commissioning operations are to be in accordance with the reviewed procedures.
1.8.2.
Verify precautions for safety of personnel during commissioning, including checks of operational readiness of all life saving equipment, fire and gas detection systems, fire fighting equipment, Emergency Shutdown systems and unobstructed escape routes.
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1.8.3.
Verify establishment of communication procedures prior to the start of commissioning operations.
1.8.4.
Verify that emergency procedures are provided to deal with contingencies, such as spillage, fire and other hazards.
1.8.5.
Verify start-up and testing of all support utility systems, including main and auxiliary sources, for the process system prior to commissioning.
1.8.6.
Verify proper hook-up and testing of the entire process system prior to commissioning, including the testing of entire system for leaks, the process control functions and emergency shutdown system.
1.8.7.
Verify purging of the entire production system of oxygen to an acceptable level prior to the introduction of hydrocarbons into the production system.
1.8.8.
Verify the introduction of hydrocarbon into the process system and the system's capability to control the flow of the well effluent in the system in a stabilized manner without undue control upsets.
1.8.9.
Verify the start-up of the flare system, if applicable, including the necessary precautions taken to eliminate the risk of explosion or fire. The functional capability of the flare system is to be verified.
1.8.10. Verify that the post-commissioned process system is functioning satisfactorily for a duration of at least 12 hours. Equipment required to be verified but not used during the initial start-up and commissioning is to be identified for verification at the next Annual Survey.
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TCVN 6474-7:2007
BLANK PAGE
166
TCVN 6474-8 : 2007 NATIONAL STANDARD
TCVN 6474-8 : 2007
Second edition
RULES FOR CLASSIFICATION AND TECHNICAL SUPERVISION OF FLOATING STORAGE UNITS PART 8: SURVEYS AFTER INSTALLATION AND COMMISSIONING
Reference standards and definitions: see Part 1, TCVN 7474-1: 2007 1
Class maintenance surveys
1.1
Periodical surveys
1.1.1
General
1.1.1.1 All units classed with the VR are to be subjected to the following Periodical surveys:
1.1.1.2
(1)
Annual surveys ;
(2)
Docking Surveys;
(3)
Intermediate surveys;
(4)
Special surveys;
(5)
Boiler surveys and Thermal oil Heater survey;
(6)
Propeller shaft and stern tube shaft survey .
(7)
Automation system and remote control survey
(8)
Inert gas system survey
All examinations and tests in accordance with the requirements in 1.3 to 1.17 are to be carried out to the satisfaction of the Surveyor.
1.1.2
Modification of Requirements
At the Periodical Surveys ,the surveyor may modify the requirements for Periodical Surveys specified in 1.3 to 1.17 having regard to the size, service engaged, age, construction, results of last surveys and actual condition of the unit. 167
TCVN 6474-8 : 2007 1.1.3
Definitions
The definitions of terms in the following 1.1.3.1 to 1.1.3.7 are to be in accordance with Part 8: 1.1.3.1 " Ballast tank " : is a tank which is used for water ballast and includes segregated balast tanks ,side balast tanks, balast double bottom spaces, top-side tanks, hopper side tanks and peak tanks. A tank which is used for both cargo and ballast will be treated as a ballast tank when substantial corrosion has been found in that tank. 1.1.3.2 "Close-up survey" : is a survey where the details of structural components are within the close visual inspection range of the surveyor,i.e. preferably within reach of hand . 1.1.3.3 "Longitudinal members in the transverse section": include all longitudinal members such as plating, longitudinals and girders at the deck, side, bottom, inner bottom and longitudinal bulkheads in the considered transverse section. 1.1.3.4 "Representative tanks" : are those which are expected to reflect the condition of other tanks similar types and service and service and with similar corrosion prevention systems. When selecting representative tanks account should be taken of the service and repair history on board and identifiable critical and or suspect areas. 1.1.3.5 "Suspect areas" : are locations showing substantial corrosion and/or are considered by the Surveyor to be prone to rapid wastage. 1.1.3.6 "Substantial corrosion" : is such an extent of corrosion that that assessment of corosion pattern indicates a wastage in excess of 75% of allowable margins, but within acceptable limits. 1.1.3.7 "Oil " : is petroleum including crude oil , heavy fuel oil , lubricating oil, light oil kerosene, gas oil …. 1.1.4
Survey Reports File
All survey reports and records of all abnormalities found are to be compiled into the Survey Report File that is to be kept onboard the Floating Installation at all times for reference during any survey. The records to be kept include, but are not limited to, the following: 1.1.4.1 Approved Survey and Inspection Plan. 1.1.4.2 The updated status records of all class surveys. 168
TCVN 6474-8 : 2007 1.1.4.3 The records of all abnormalities found that are to include all videos and photographic records. 1.1.4.4 The records of all repairs performed on any abnormalities found and any further repetitive abnormalities found subsequent to the repairs. 1.1.4.5 Records of all corrosion protection system maintenance, including records of all cathodic potential readings taken, records of depletion of all sacrificial anodes, impressed current maintenance records, such as voltage and current demands of the system, coating breaks and the monitoring records of the steel material wastage in way of the coating break areas. 1.1.4.6 All classification reports pertaining to the Floating Installation. 1.1.4.7 All records of any findings of abnormalities by the crew personnel onboard, including all leakages in bulkheads and piping. 1.1.4.8 Reports of thickness measurements of the vessel or floating structure. 1.1.4.9 Reports of all NDT performed. 1.1.5
Corrosion Prevention System - Ballast Tanks
1.1.5.1 Corrosion Prevention System is normally used one of two following types: (1)
a full, hard coating that is supplemented by anode;
(2)
a full, hard coating .
1.1.5.2 Coating Condition of hard coatings is defined as follows: (1)
GOOD is a condition with only minor spot rusting.
(2)
FAIR is a condition with local breakdown at edges of stiffeners and weld connections and/or light rusting over 20 percent or more of areas under consideration, but less than as defined for POOR condition.
(3)
POOR is a condition with general breakdown of coating over 20 percent or hard scale at 10 percent or more of areas under consideration.
1.1.5.3 Salt Water Ballast Spaces (1)
In salt water ballast spaces, other than double bottom tanks, where poor coating condition is found and Owners or their representatives elect not to restore the coating, where a soft coating has been applied or a protective coating has not been applied, the ballast tanks are to be internally examined at 169
TCVN 6474-8 : 2007 each subsequent Annual Survey. 1.2
Intervarls of periodical surveys
1.2.1
General
1.2.1.1 A periodical survey, annual, intermediate or special, is to be considered as completed when the relevalt periodical surveys both for hull and for machinery have been completed, unless the special arrangement is made with the VR. 1.2.1.2 Except as amended at the discretion of the VR, the intervals of Periodical Surveys are specified in 1.2.2 to 1.2.8 following. 1.2.1.3 Class Periodical Surveys should, whenever practicable, be held concurrently with statutory periodical surveys or inspections. 1.2.1.4 Where both Annual Survey and Intermediate Survey are due at a time, only Intermediate Survey is to be carried out . 1.2.2
Annual surveys Annual surveys for hull, machinary of floating storage unit, production system and mooring system are to be carried out within three months either way of each anniversary date of the date crediting a Classification Survey or the previous Special Survey .
1.2.3
Docking surveys
1.2.3.1 Survey intervals: A Drydocking Survey is to be conducted two times in any 5-year period with an interval not exceeding three years between surveys . 1.2.3.2 Extension of Docking surveys: Consideration may be given for extensions of Rule-required Drydock Survey under special circumstances. An underwater inspection by a diver shall be required for such extensions. 1.2.4
Underwater Inspection in Lieu of Drydocking Survey (UWILD)
1.2.4.1 An VR’s approved underwater inspection by a diver may be considered equivalent to a Drydocking Survey, up to and including Special Periodical Survey No. 4. The UWILD after Special Periodical Survey No. 4 may be approved by special considerations by VR. 170
TCVN 6474-8 : 2007 1.2.4.2 Should the UWILD be contemplated, underwater inspection procedures per Appendix VIII, Part 9 are to be submitted for review and approval in advance of the survey. 1.2.4.3 The Underwater survey is to provide the information normally obtained from the docking survey, so far as is practicable. 1.2.4.4 Proposals for underwater surveys are to be submitted in advance of the survey being required so that satisfactory arrangements can be acceptable. 1.2.4.5 The under water survey is to be carried out at agreed geographical location under the surveillance of a VR surveyor, with the unit at a suitable draught in sheltered waters; the under-water visibility is to be good and the hull bellow the waterline is to be clean. The surveyor is to be sastisfied that the method of pictorial presentation is satisfactory. There is to be good two way communication between the surveyor and the diver. 1.2.4.6 Diving and under water survey operation are to be carried out by firms recognized by VR. 1.2.4.7 If the in-water survey reveals damage or deterioration that requires early attention, the surveyor may require that the unit be dry-docked in order that a fuller survey can be undertaken and necessary work carried out. 1.2.4.8 Where a unit has an IWS notation, the conditions of the high resistant paint is to be confirmed at each dry-docking in order that the IWS notation can be maintained 1.2.5
Intermediate surveys Intermediate Surveys are to be carried out on all units instead of the second or third Annual Survey after completion of Classification Survey and Special Survey.
1.2.6
Special surveys
1.2.6.1 Survey intervals Special Surveys are to be carried out at 5-yearly interval. The first Special Survey is to be completed within 5 year from the date of build or date of Special Survey for classification and thereafter 5 years from the date of completion of the previous Special Survey. 1.2.6.2 Commencement of special surveys 171
TCVN 6474-8 : 2007 th
The Special Survey may be commenced at the 4 annual Survey after Clasification Survey or previous Special Survey and be progressed during the succeeding year with view to completion by the 5th anniversary date. As part of the preparation for the Special Survey, the thickness measurement should be dealt with, so far as practical in connection with the 4th Annual Survey. 1.2.6.3 Premature commencement of Special survey Special surveys which are commenced prior to the date are not to extend over a period greater than 12 months, except with the priod approval of the VR. 1.2.6.4 Completion of special survey When a Special survey is not completely carried out one time, the date of completion of the Special Survey will be the date at which the principal part of the requirements is complied with. 1.2.6.5 Unusual Cases Special consideration may be given to Special Periodical Survey requirements in the case of Floating Installations of unusual design, in lay-up or in unusual circumstances. Consideration may be given for extensions of Rule-required Special Periodical Surveys under extreme circumstances. 1.2.6.6 Continuous Surveys (1)
At the request of Owners, and after approval of the proposed arrangements by the VR a system of Continuous Survey may be undertaken where by the Special survey requirements are carried out in rotation to complete all the requirements of the particular Special Survey within five years and interval of consecutive surveys of each part or item is not to exceed five years.
(2)
If any defects are found during the surveys, further parts or items are to be opened up and examined as considered necessary by the Surveyor, and the defects are to be repaired to his satisfaction.
(3)
Where some units of machinary are opened up and examined by the chief engineer as normal routine for maintenance at ports where the surveyor is not available or at sea, the opened-up-inspection of the units, at the request of Owners, under certain conditions, may be dispensed with at the discretion of
172
TCVN 6474-8 : 2007 the surveyor subject to a confirmatory survey at the next port of call where the surveyor is available. (4)
Drydocking or UWILD may be performed at any time during the cycle 5 year,
provided that all requirements of 1.4 or 1.5 are met and thickness measurements are taken when the vessel is surveyed. 1.2.7
Boiler surveys
1.2.7.1 Survey intervals (1)
Water tube boilers used for propulsion including double evaporation boilers are to be surveyed internally and externally at 2.5 year intervals, except for ships with single main boiler, where surveys are to be carried out at 2.5 year intervals until they are 7.5 years old, and subsequently annually.
(2)
Fired tube boilers: Boilers are to be surveyed when they are 4 year old and 6 years old, after that they are to be surveyed annually.
(3)
All other boilers of essential service, boilers of non-essential service having working pressure exceeding 0.35 MPa (3.5 bar or 50 psi) and heating surface 2
excceding 4,5 m , exhaust gas boilers, economizers, thermal oil heaters and steam generators are to be surveyed internally and externally at 2,5 yearly intervals (4)
Notwithstanding the requirements in (1) and (2), certain types of boilers, when the VR deems it necessary, may be required to be surveyed internally and externally at yearly intervals.
(5)
General inspection of boilers including confirmation of their safety devices is to be carried out at yearly intervas in the course of annual survey of the unit (see 3.7.1(6) TCVN 6259-1:2003).
(6)
Notwithstanding the requirements in (1) and (2), an extension of boiler survey may be granted for a period not exceeding 6 months from the due date, when requested by the Owners, subject to the survey for the extension.
1.2.8
Propeller shaft and stern tube shaft surveys
1.2.8.1 Ordinary surveys are to be carried out at intervals specified below: (1)
Propeller shaft kind 1 specified in 1.2.39 Part 1-A TCVN 6259-1:2003, are to 173
TCVN 6474-8 : 2007 be surveyed at least once every four years for units fitted with waterlubricated stern tube bearings (Which include shaft bracket bearings, the same being referred to hereinafter in this part) and five years for units fitted with oil-lubricated stern tube bearings . (2)
Propeller shaft kind 2 specified in 1.2.39 Part 1-A TCVN 6259-1:2003, are to be surveyed at least once every two and a half years. Where, however, the part of the construction of the shaft in the stern tube bearing corresponds to the shaft kind 1 and the construction of the shaft between the stern tube and the shaft bracket bearing corresponds to the shaft kind 2, the shaft may be surveyed at the intervals specified in 1.2.8.1(1) , on condition that the part of the shaft which corresponds to the shaft kind 2 is surveyed at least once every two and half years .
(2)
Notwithstanding the requirements in 1.2.8.1(1) , Ordinary surveys for propeller shaft kind 1A and stern tube shaft kind 1A, propeller shaft kind 1B and stern tube shaft kind 1B, and propeller shaft kind 1C may be postponned for not more than the period given in following Table from the date of the postponement survey prescribed in 3.11.2-2 TCVN 6259-1:2003 provided that the survey is carried out on the due date of the Ordinary Survey . Table 8-1: Postponement period
No
Kind
of
postponement Postponement
Survey Kind of shafts 1
Shafts kind 1A
2
Shafts kind 1B
3
Shafts kind 1C
Survey kind A
1 year
Postponement
Postponement
Survey kind B
Survey kind C
-
-
2,5 year
5 year
1.2.8.2 Notwithstanding the requirements in 1.2.8.1 or 1.2.8.2, The Ordinary Surveys may be postponned for not more than six months, when requested by the Owners, on the basis of the approval by the VR. However, this postponement may be granted only once in an interval between Ordinary Surveys. 1.3
Annual surveys
1.3.1
Requirements for Annual Surveys – Hull
174
TCVN 6474-8 : 2007 1.3.1.1 At each annual survey beetween special surveys, general condition for hull, equipment, fire extinguishing systems, etc. are to be examined as far as practicable, annual surveys includes following items and requirements specified in 1.3.1.2 to 1.3.1.7: (1)
Shell plating and piping systems above the waterline, externally;
(2)
Visual inspection is to be carried out for structures close to water level to make sure there is no damage due to impact (due to unit or other reasons).
(3)
Opening a such as side scuttles, doors, etc. together with their closing appliances of which watertightness and weathertightness are required ;
(4)
Each deck ;
(5)
Areas potentially having factigue damage due to stress concentration NDT examination may be required if deemed necessary.
(6)
Examine all navigational lights, alarm and sound devices including helicopter lights and other safety systems.
(7)
Mooring systems ; (a)
General examination of mooring lines ;
(b)
General examination of installations for mooring systems ;
(c)
General examination of anchors for anchor mooring systems ;
(d)
General examination of steel pipes for tension mooring systems ;
(e)
General examination of fenders or mooring lines for dolphin mooring systems ;
(8)
Ventilators, air pipes and sounding pipes together with their closing appliances ;
(9)
Protection of the crew, guard rails, lifelines, gangways and deckhouses accommodating crew;
(10)
Construction of fire protection and means of escape including functioning test as far as practicable;
(11) Fire extingguishing systems including operation and functioning tests as far as practicable; (12)
Examination of fire control plan; 175
TCVN 6474-8 : 2007 (13)
Examination of fire detection system as far as practicable;
(14)
Examination of main fire system and verification of performance of fire pumps including emergency pumps;
(15)
Examination of fire main, nozzles, hydrauts to ensure their satisfactory performance and placed in order ;
(16)
Examination of control system of fixed fire extinguishing control system, fire main, fire alarm signal, ensuring they are well maintained ;
(17)
Fire extingguishing bottles are placed in order and well maintenance ;
(18)
Remote control and shut-down system to stop fans, engines, stop tranfering fuel to engine room;
(19)
Shutdown systems for ventilation, funnels, skylight, acess and other relevant parts ;
(20)
Examination to ensure fire extinguishing tools are adequate and good order.
(21)
Examination of all hazardous areas including watertight doors and boundaries;
(22)
Ensure following equipments are in good operating condition : (a)
Ventilation system, fire extinguishing system, fans and relating devices;
(b)
All machanical and electrical safety devices;
(c)
Other safety equipment such as alarm system and communication system.
(23)
For the units which are necessary to be provided with the stability booklet, loading manual and the operating booklet are kept on board the unit for ready use ;
1.3.1.2 Suspect Areas and Ballast Tanks Suspect areas of the hull are to be examined , including an overall and Close-up Survey of those suspect areas which were identified at the previous surveys. Areas of substantial corrosion identified at previous surveys are to have thickness measurements taken. Where extensive areas of corrosion are found, thickness measurements are to be carried out and renewals and/or repairs made when wastage exceeds allowable margins. 176
TCVN 6474-8 : 2007 Where substantial corrosion is found, additional thickness measurements in accordance with are to be taken to confirm the extent of substantial corrosion. For Installations over 15 years of age: All sea water balast tanks closed to cargo(oil) tanks, in which thermal oil heater is used, are to be internal examined. If a structural defect was not found, the scope of examination is only included reviewing the efffectiveness of coating systems. 1.3.1.3 Helicopter Deck Where areas of the installation are designated for helicopter operations, the helicopter deck, deck supporting structure, deck surface, deck drainage, tie downs, markings, lighting, wind indicator, securing arrangements where fitted safety netting or equivalent, access arrangements including emergency escape, and access for fire fighting and rescue personnel, are to be examined. 1.3.1.4 Cargo Tanks Cargo tank openings including gaskets, covers and coamings. Pressure/vacuum relief valves, flame arrestors and flame screens. Tank vent protective devices are to be
examined externally for proper assembly and
installation, damage, deterioration or traces of carryover at the outlet. Where deemed suspect, the tank protective device is to be opened for examination. 1.3.1.5 Piping Systems Cargo, crude oil washing, bunker, ballast, steam, and tank vent piping systems above the weather deck and in the cargo pump room and pipe tunnels. Where suspect, piping may be required to be pressure-tested at the working pressure, thickness measured or both. Cargo and stripping pumps including foundations, gland seals, operation of remote control and shut-down devices. Confirmation that cargo discharge pressure gauges and level indicator systems are operational 1.3.1.6 Electrical Bonding and Equipment Electrical bonding arrangements on the weather deck and in cargo pump rooms, including bonding straps, where fitted, of cargo piping systems carrying flammable liquids and piping systems routed through hazardous areas.
177
TCVN 6474-8 : 2007 Confirmation that electrical equipment in hazardous locations, including the cargo pump room, has been properly maintained, including the following items: •
Intrinsically safe and explosion-proof features of electrical equipment installed in the hazardous areas, in particular any associated sealing arrangement.
•
The physical condition of cables (wiring) and fixtures and test of insulation resistance of the circuits. In cases where a proper record of testing is maintained, consideration may be given to accepting recent readings.
•
The cable supports and the means of cable protection from mechanical damage, as originally provided.
•
Gas detection system in the cargo pump room, if fitted.
•
Temperature-sensing devices fitted on bulkhead shaft glands, pump bearings and casings, if any
1.3.1.7 Cargo Pump Room Examination of pump room bulkheads for signs of leakage or fractures and, in particular, the sealing arrangement of all penetrations of bulkheads. Confirmation that there are no potential sources of ignition in or near the cargo pump room and cargo area and that pump room access ladders are in good condition. Operation of pump room bilge pumping system. Pump room ventilation system including ducting, dampers and screens. 1.3.1.8 For column stabilized units, general examinitions of the following iterms are to be carried: (1)
Upper hull and its supporting structure above the waterline the deck, deck houses, structures attached to the deck, accessible internal spaces;
(2)
Exposed parts of columns and bracings together with their connections above the waterline ;
(3)
Hatchways, manholes, and other openings in freeboard deck (bulkhead deck) and enclosed superstructure Decks ;
(4)
Machinery casings and covers, companionways, and deck houses protecting openings in freeboard or enclosed-superstructure decks;
178
TCVN 6474-8 : 2007 (5)
Portlights, together with deadcovers, cargo ports, bow or stern entries, chutes, and similar openings in hull sides or ends, below the freeboard deck or in way of enclosed superstructures ;
(6) Ventilators, tank vent pipes together with flame screens ; (7) Overboard discharges from enclosed spaces on or below the freeboard deck ; (8) Watertight bulkheads and end bulkheads of enclosed superstructures; (9)
Closing appliances for all of the above, including hatch covers, doors, check valves;
(10) Protection of the crew, guard rails, lifelines, gangways and deckhouses accommodating crew ; (11) The Surveyors are to be satisfied at each Annual Survey that no material alterations have been made to the Floating Installation, its structural arrangements, subdivision, superstructure, fittings and closing appliances upon which the load line assignment is based. 1.3.2
Annual survey for Machinery installations and Electrical Installations
1.3.2.1 At each annual survey between special surveys for machinery installations and electrical installations, general examination of machinery installations and electrical installations corresponding to relevant machinery installations and electrical installations of the units are be carried out in addition to the following surveys: (1)
The propelling machinery and essential auxiliaries are to be generally examined. The surveyor may, in addition, require such further items ro be opened up as considered to ascertain that theyare in good working condition.
(2)
Machinery and boiler spaces with particular attention to the fire and explosion hazards, and also emergency escape routes are to be examined.
(3)
All main and auxiliary steering gears including their associated equipment and control systems are to be examined and tested in operation.
(4)
All means of communication between the navigation bridge, control station and the machinery control positions, as well as the bridge and the alternative steering positions are to be tested.
(5)
Bilge pumping systems and bilge wells including operation of pumps, remote 179
TCVN 6474-8 : 2007 reachrods and level alarms where fitted, are to be examined as far as practicable. (6)
Boilers, thermal oil heaters, pressure and vessels and their mountings including safety devices, foundations, controls relieving gear, high pressure and steam escape piping, insulation and gauges are to be externally examined. Confirmation of the safety devices of the boilers and thermal oil heaters may be required as considered necessary by the surveyor.
(7)
Electrical machinery, emergency sources of the electrical power, switchgear and other electrical equipments are to be examined and also to be tested in operation as feasible. If automatic control system is fitted, it is to be tested on both automatic and manual modes.
(8)
Confirmation as far as practicable of the operation of all emergency sources of power is to be made and, if they are automatic, also in the automatic mode.
(9)
Parts which are opened up for maintenance at Owner's option are to be examinated as necessary.
(10)
Where automatic and/or remote controls are fitted for essential machinery, they are to be tested to demonstrate that they are in good working condition.
(11)
Dynamic positioning systems are to be generally examined and performance tests of them are to be carried out as far as practicable.
1.3.2.2 General conditions of electrical installations in the hazardous areas are to be examined. For the units of ten years of age and over, insulation resistance of these installations is to be measured. The measurement, however, may be dispensed with in case the proper measurement records are kept on board and found satisfactory by the surveyor. 1.3.2.3 Following Fire-extinguishing apparatus/ systems are to be examined and/or tested: (1)
Fire Main System Fire main system, including isolating valves and hydrants. Fire mains are to undergo satisfactory pressure testing at the working pressure.
(2)
Fire Pumps Fire pumps, including verification that each fire pump including the
180
TCVN 6474-8 : 2007 emergency fire pump can deliver two jets of water simultaneously from different hydrants. (3)
Fire Fighting Equipment Verification that fire hoses, nozzles, applicators and spanners are in good working condition and situated at their respective locations.
(4)
Semi-Portable and Portable Fire Extinguishers Verification that all semi-portable and portable fire extinguishers are in their stowed positions, checking for evidence of proper maintenance and servicing, conducting random check for evidence of discharged containers.
(5)
Fire Control Plans Confirmation that Fire Control Plans are properly posted .
(6)
International Shore Connection Confirmation that an international shore connection is provided..
(7)
Fixed Fire Fighting System Examination of fixed fire-fighting system controls, piping, instructions and marking, checking for evidence of proper maintenance and servicing, including date of last systems tests; foam concentrates are to be tested at intervals recommended by the manufacturer and renewed if found unsatisfactory for further use. An external examination of piping and cutout valves of cargo tank and cargo pump room fixed fire-fighting systems..
(8)
Remote Controls Verification, as far as practicable, that the remote controls for stopping fans and machinery and closing valves for fuel oil in machinary rooms are in working order.
(9)
Fireman's Outfits Verification that the fireman’s outfits are complete and in satisfactory condition .
(10)
Closing Arrangements Examination of the closing arrangements of openings in funnels, skylights, 181
TCVN 6474-8 : 2007 ventilators, doorways and tunnels. Ventilator ducts are to be opened to verify satisfactory condition and operation of dampers. (11)
Deck Foam System Confirmation that the deck foam system is in operating condition.
(12)
Unloading area An examination of unloading piping, including welded joints, identification, means of segregation from the cargo main line, closing arrangement of the unloading connection, draining and leak detection arrangements and spill containment. Means of communications between the cargo control room and the loading/unloading connection to be tested .
1.3.2.4 For the production units, the following are to be carried out: (1)
(2)
A general examination of : (a)
Cargo tank openings and pressure/vacuum valves;
(b)
Crude oil piping systems;
(c)
Cargo pump rooms ;
(d)
Escape routes ;
(e)
Fire extinction systems in crude oil tank and pump room area.
The following components and systems are to be surveyed and tested for correct functioning :
(3)
(a)
Gas detection systems, flammable and toxic gases;
(b)
Fire detection system;
(c)
System for crude oil tank level measurements;
(d)
General alarm system and communication between control stations
In hazardous areas the following equipment and systems are to be surveyed and tested :
182
(a)
Ventilation system including overpressure alarms ;
(b)
Alarms/shut-down for pressurized equipment and rooms ;
(c)
Electrical equipment and cables ;
(d)
Self-closing gastight doors, air locks, openings and accesses;
TCVN 6474-8 : 2007 (e) (4)
Protection devices for combustion equipment and engines;
The emergency shut-down system is to be surveyed and function tested for following equipments and components. Special attention is to be given to both manual and automatic activation, power supply and alarms:
(5)
(a)
ventilation;
(b)
wellhead valves/oil production facilities ;
(c)
all non-essential electrical equipment and essential electrical equipment
Where cross connections between piping system for oil production and safe piping system exits, the means for avoiding possible contamination of the safe system with the hazardous medium is to be surveyed
1.3.2.5 For the production plants , the following are to be carried out : (1)
For equipment installed subsea at time of an annual survey a review of the maintenance manual/test log is an acceptable survey method, provided satisfactory records and acceptable maintenance procedure .
(2)
An overall survey is to be carried out with particular emphasis on the structural interity of:
(3)
(a)
Flare ;
(b)
derrick;
(c)
skids .
Wire ropes (including end attachments) and sheaves of the tensioners and associated systems are to be surveyed. If deemed necessary by the surveyor, checking by MPI shall be carried out.
(4)
Pressure vessels and heat exchangers are to be externally surveyed. The general condition including mountings, piping and possible insulation is to be ascertained. The surveyor may require opening/internal survey or thickness measurements and /or crack detection test if found necessary. Safety valves, instrumentation and systems on tanks/separators are to be surveyed and tested in operating condition as found necessary by the surveyor .
(5)
Piping system including flexible pipes is to be surveyed and pressure tested to working pressure. Thickness measurements are to be carried out as deemed 183
TCVN 6474-8 : 2007 necessary by the surveyor (6)
High pressure/capacity pumps and compressors are to be externally surveyed and function tested .
(7)
Risers shall be visually surveyed and inspected for corrosion, cracks and wear as far as accessible. Pressure tests to working pressure are to be carried out .
(8)
The blowout preventers shall be surveyed and pressure tested to working pressure. NDT is to be carried out to the extent deemed necessary by the surveyor .
(9)
Riser handling devices and lifting devices for production and associated operations to be generally surveyed and functional testing of appliance and safety devices carried out as found necessary by the sutveyor. It is to be verified that the marking and component certificates are available and acceptable .
(10)
The process and utility safety systems are to be surveyed during operation and tested for correct funstioning as found necessary by the surveyor with particular emphasis on:
(11)
(a)
Shut-down valves ;
(b)
Shut-down instrumentation ;
(c)
Shut-down sequence and logic ;
(d)
Inter connection with emergency shut-down system;
(e)
Regulation/control system
(f)
Alarm/system;
Drainage systems for produced liquids, for hazardous and non-hazardous area to be surveyed .
(12)
Water protection systems in process area are to be surveyed .
1.3.2.6 Other examinations and tests deemed necessary by the surveyor are to be carried out . 1.4
Docking surveys
1.4.1
General
1.4.1.1 The unit is to be placed on blocks of sufficient height in a drydock or on a ship way. 184
TCVN 6474-8 : 2007 1.4.1.2 However, where the in-water survey is requested by the Owner and approved by the VR as substitution for a survey in a drydock or on a ship way, the in-water survey may be accepted. Where a docking survey is altered to the in-water survey, examinations deemed appropriate by the VR are to be carried out . 1.4.1.3 In addition to the requirements in 1.4.2, examinations as comprehensive as special surveys may be required as to the iterms which are considered necessary by the surveyor on the occasion of docking surveys . 1.4.2
Requirements for Docking survey
1.4.2.1 For all units, surveys are to be carried out in accordance with 3.4.1, Chapter 3, Part 1-B TCVN6259- 1:2003. 1.4.2.2 In addition to the requirements in -1, the following are to be to be performed during all of the Drydock Surveys: (1)
Cathodic potential readings are to be taken from representative positions on the entire underwater body and evaluated to confirm that the cathodic protection system is operating within design limits.
(2)
Sacrificial anodes are to be examined for depletion and placed in satisfactory .
(3)
Impressed current system anodes and cathodes are to be checked for damage, fouling by marine growth and carbonate deposits. The current and voltage demands of the system are to also be checked to ensure the system is functioning .
(4)
Additional examinations are to be performed on the wind and water areas of the structures where coating breaks are evident. Thickness measurements in these areas may be required if found necessary by the attending Surveyor.
1.4.2.3 Particular attention is to be given to corrosion control systems in representative ballast tanks, free-flooding areas and other locations subjected to sea water from both sides . 1.4.2.4 If the unit is provided with the dynamic positioning system, thrusters are to be examined. 1.4.2.5 In conjunction with dry docking surveys, after special survey No. 1 and between subsequent special surveys, the following ballast spaces are to be internally examinrd, thickness gauged and placed in satisfactory condition. Alternatively, 185
TCVN 6474-8 : 2007 ballast tank corrosion control arrangements are to be verified effective . (1)
For ship type and barge type units : One peak tank and at least two other representative ballast tanks between the peak bulkheads used primary for water ballast .
(2)
For column stabilized units: Representative ballast tanks in footings, lower hulls or free-flooding compartments as accessible, and at least two ballast tanks in columns or upper hull, if accessible.
1.5
Underwater Inspection in Lieu of Drydocking Survey
1.5.1
General
1.5.1.1 An approved underwater inspection by a diver may be considered equivalent to a Drydocking Survey, up to and including Special Periodical Survey No. 4. 1.5.1.2 For each drydocking or equivalent underwater examination after Special Periodical Survey No. 4, requests to conduct an UWILD, in accordance with previously approved plans, . For requirements of UWILD (in accordance with previously approved procedures) after special periodical survey No 4, proposal by unit’s owner for this UWILD is to be submitted for consideration well in advance of the proposed survey. The UWILD after special periodical survey No 4 may be accepted by special consideration by VR. 1.5.1.3 Should the UWILD be contemplated, underwater inspection procedures per Appendix VIII, Part 9 are to be submitted for review and approval in advance of the survey. This approved procedure is to be made available onboard. In addition, the inspection procedures are to also consist of the following: (1)
Scope of inspection that is not to be less than as noted in Appendix VII, Part 9.
(2)
Procedure for divers to identify the exact location at which they are conducting their inspection.
(3)
Procedure for cleaning the marine growth for inspection purposes that is to include the extent and location of the underwater cleaning.
(4)
Procedure and extent for measuring the cathodic potential readings in way of the structures.
186
TCVN 6474-8 : 2007 (5)
Procedure and extent for taking thickness gaugings of the structures and NDT of critical joints.
(6)
Qualifications of all divers conducting the inspection, NDT and thickness gaugings.
(7)
The type of underwater video and photography, including means of communication, monitoring and recording.
(8)
For Underwater Inspections in lieu of Drydocking Surveys (UWILD) associated with Special Periodical Survey, means are to be provided to permit the opening up of all sea valves and overboard discharges for internal examination. In addition, all Special Periodical Survey items related to the underwater portion of the hull or structure, including the gauging requirements are to be dealt with during the underwater survey.
1.5.1.4 However, during conducting UWILD if the inspection’s results was found unsatisfactory by Surveyor, Surveyor may reject these inspection’s results and may require that the unit be dry-docked. 1.5.2
Parts to be Examined
1.5.2.1 Hull and hull equipments of Floating storage unit For ship-type and barge-type units:
The following items are to be examined, as applicable: (1)
The keel, stem, stern frame, rudder, propeller, and outside of side and bottom plating are to be cleaned as necessary and examined, together with bilge keels, thrusters, exposed parts of the stern bearing and seal assembly, sea chest, rudder pintles and gudgeons, together with their respective securing arrangements.
(2)
All sea connections and overboard discharge valves and cocks, including their attachments to the hull or sea chests, are to be externally examined. All nonmetallic expansion pieces in the sea-water cooling and circulating systems are to be examined both externally and internally. The stern bearing clearance or weardown and rudder bearing clearances are to be ascertained and reported on.
For column-stabilized units, the following are to be examined:
(1)
External surfaces of the upper hull or platform, footings, pontoons or lower hulls, 187
TCVN 6474-8 : 2007 underwater areas of columns, bracing and their connections, as applicable, are to be selectively cleaned and examined. These areas include joints of critical structural members, areas susceptible to damage from supply vessels, anchor chains, dropped equipment, corrosion and erosion from loss of coating, or sand scouring and areas of progressed and accumulated wear-and-tear. (2)
Nondestructive testing may be required of areas found to be suspect. Joints of different configurations of major structural members are to be selected, cleaned and magnetic particle inspected. The selection of these joints are to be such that all joints underwater are to be inspected every five years.
(3)
Sea chests and strainers are to be cleaned and examined.
(4)
External portions of propulsion units are to be examined, if applicable.
(5)
The type, location and extent of corrosion control (coatings, cathodic protection systems, etc.), as well as effectiveness, and repairs or renewals to same should be reported in each survey. Particular attention is to be given to corrosion control systems in ballast tanks, free-flooding areas and other locations subjected to sea water from both sides.
(6)
All tanks and voids that are to be internally examined are to be thoroughly ventilated and gas freed prior to being entered and are to be carefully monitored for pocketing or emissions of hazardous gases during examination.
(7)
In conjunction with Drydocking Surveys (or equivalent), the following ballast spaces are to be internally examined, and the effectiveness of coatings or corrosion control arrangements are to be verified either visually by indicator strips or by thickness gauging (as considered necessary), placed in satisfactory condition, as found necessary, and reported upon: (a)
Representative ballast tanks in footings, lower hulls or free-flooding compartments, as accessible.
(b)
At least two ballast tanks in columns or upper hull, if applicable.
1.5.2.2 Mooring System For mooring systems, the following are to be cleaned and examined, where applicable: 188
TCVN 6474-8 : 2007 (1)
The mooring anchor chain or cable tensions are to be measured and the end connections of these components are to be examined. All mooring chains are to be generally examined for their entire lengths. Anchors, cables and their respective handling means are to be examined.
(2)
The buoyancy tanks are to be cleaned and examined, if applicable.
(3)
Chain and stopper assemblies are to be cleaned, examined and NDT performed, as considered necessary by the attending Surveyor.
(4)
Areas of high stress or low fatigue life are to be preselected, cleaned and NDT performed, if considered necessary.
(5)
Scour in way of anchors or anchor piles is to be examined.
(6)
Cathodic potential readings are to be taken from representative positions on the entire underwater structure of the mooring system to confirm that the cathodic protection system is operating within design limits.
(7)
Highly stressed, high wear and tear areas of the mooring chain are to be closely examined and nondestructively tested, if found necessary by the attending Surveyor. These include areas in way of the stoppers and sea bed touchdown areas.
1.5.2.3 Import System For import systems, the following are to be cleaned and examined, where applicable: (1)
The entire riser system.
(2)
The arch support buoyancy tanks, their structures and the clamping devices.
(3)
The flexible riser, including all end flanges and bolting arrangements and spreader bars, if applicable.
1.5.2.4 Export System For export systems, the following are to be cleaned and examined, where applicable: (1)
The entire export flexible system is to be examined for damage due to chafing and fatigue fractures.
(2)
All navigation aids are to be examined and functionally tested
1.6
Intermediate Surveys
1.6.1
General 189
TCVN 6474-8 : 2007 1.6.1.1 At each intermediate survey, all the requirements for an annual survey are to be complied with . 1.6.1.2 In addition to the above requirement, surveys required in following parts are to be carried out: 1.6.2
Intermediate survey for hull
1.6.2.1 For all units, the following requirements are to be complied with : (1)
Performance tests of openings such as side scuttles, doors, etc. required watertightness and weathertightness together with their closing appliances; However, performance tests may be dispensed with the discretion of the Surveyor.
(2)
Performance tests of positioning systems for a long period of time together with their installations ; and
(3)
Examination of anchor racks and fair leaders for anchor cables above the waterline together with hull connection of these .
(4)
Examination of electrical equipment in hardous areas in particular : (a)
Grounding;
(b)
Explosive casing of equipment;
(c)
Pressure regulating device casing and relevant components ;
(d)
Conditions of safety devices ;
(e)
Cable condition ;
(f)
Electrical shutdown of areas fitted with dampers;
(g)
Performance of pressure regulating device and function of alarm signal
1.6.2.2 For column stabilized units, examinations of the following items are to be carried out as far as practicable . (1)
Representative ballast tanks in footings, lower hull or free-flooding compartments as accessible, and at least two ballast tanks in columns, if accessible ;
190
(2)
External columns, bracings, lower hulls and footings ;
(3)
Connection parts between upper hull and columns, and columns and lower
TCVN 6474-8 : 2007 hulls or footings, and bracings. If deemed necessary by the Surveyor, the Surveyor may request a nondestructive test of these parts 1.6.2.3 For ship type units and barge type units, general examinations of construction of the surrounding to openings such as a moompool above the waterline are to be carried out in addition to 1.6.2.1. 1.7
Special surveys
1.7.1
General
1.7.1.1 The first special survey of the unit after the classification survey during construction is designted as ' 'Special survey No.1' and subsequent special surveys as designated as 'Special survey No.2' 'Special survey No.3 ' and ... 1.7.1.2 The kind of special survey of the unit not built under survey is to be determined in the similar sequence as specified in 1.7.1.1 basing upon what kind of special survey was corresponding to her classification survey 1.7.2
Special surveys for hull
1.7.2.1 Special Periodical Survey of Hull is to include compliance with the foregoing Annual Survey and Drydocking. 1.7.2.2 For all units, Special survey No. 1 for hull, equipment, fire extinguishing systems, etc., examinations and tests specified in the following are to be carried out : (1)
Internal and external of hull, especially machinery room, cofferdams, and water tanks such as water ballast tanks, and oil tanks such as fuel oil tanks deemed necessary by the VR are to be examined corresponding to the kinds of the special survey .
(2)
An overall survey is to be carried out with particular emphasis on the structural intergrity of the deck with supporting structure .
(3)
Tanks are to be tested under the pressure corresponding to the maximum head that can be experienced in service or designed. A pressure tests of the tanks may be omitted, provided that the Surveyor is satisfied with the condition of the tanks from the results of an external and internal examinations of the tanks.
(4)
The thickness of structural members of the following parts listed in (a) to (c) 191
TCVN 6474-8 : 2007 are to be gauged. For accurate gauging, appropriate ultrasonic equipment or other approved means are to be used. The results of the gaugings are to be reported to the VR . (a)
Structural members in any locations considered by the surveyor to be prone to rapid wastage showing excessive corosion.
(b)
Representative parts of splash zones or related structure near the
draught of operational condition . (c)
Suficient parts of structural members for general asessment and recording of corosion pattern .
(5)
Anchors, chain cables and ropes for temporary mooring are to be ranged, examined and measured .
(6)
For mooring systems, the following examinations are to be carried out :
(a)
Thorough examination of mooring lines
(b)
Thorough examination of installations for mooring systems
(c)
Thorough examination of anchors for anchor mooring systems
(d)
Thorough examination of steel pipes for tension mooring system and thickness gauging of the representative part of steel pipes
(e)
General examination of fenders or mooring lines for dolphin mooring system
(7)
Non-destructive tests may be required at important parts among those stated in the foregoing (1), (2) and (3) where deemed necessary by the VR
1.7.2.3 For column stabilized units, the following examinations are to be carried out. However, where the units is examined in floating condition, the examinations are to be appropriate to the VR. (1)
Connections of columns and bracings to upper hull or platform and lower hull or pontoons are to be sufficiently cleaned and examined .
(2)
Joints of supporting structure including bracings together with gussets and brackets and internal continuation or back-up structure for those are to be examined.
192
TCVN 6474-8 : 2007 (3)
Internal and external parts of columns, lower hulls or footinga and bracings are to be examined
(4)
Non-destructive examination may be required at suspect areas.
(5)
A deadweight survey is to be carried out. Where the deadweight survey indicates a change from the calculated light ship displacement in excess of 1% of the operating displacement, an inclining test is to be conducted.
(6)
All tanks, compartments and free-flooding spaces throughout the vessel are to be examined externally and internally. Internal examinations of lower hull are to be specially considered. Watertight integrity of tanks, bulkheads, hull, bulkhead deck and other compartments are to be verified by visual inspection. Suspect areas may be required to be tested for tightness, nondestructively tested or thickness gauged. Tanks and other normally closed compartments are to be ventilated, gas-freed and cleaned, as necessary, to expose damage and allow for a meaningful examination for excessive wastage. Internal examination and testing of void spaces, compartments filled with foam or corrosion inhibitors and tanks used only for lube oil, light fuel oil, diesel oil or other non-corrosive products may be waived, provided that, upon general examination, the Surveyor considers their condition to be satisfactory. External thickness gauging may be required to confirm corrosion control.
(7)
Attachments of anchor racks and anchor cable fairleads are to be examined. Foundations in way of selective anchor line fairlead support structures are to be cleaned and nondestructive examinations performed. Internal support structures in way of these foundations are to be closely examined.
(8)
Applicable structures, such as pipe racks, process support structures, deck houses, superstructures, helicopter landing areas and their respective attachments to the deck or hull..
(9)
Foundations and supporting headers, brackets and stiffeners for process related apparatus, where attached to hull, deck, superstructure or deck house.
(10)
At Special Periodical Survey No. 2 and subsequent Special Periodical Surveys, representative gaugings are to be required in accordance with Table 8-2. Special attention should be paid to the splash zones on hulls, columns and 193
TCVN 6474-8 : 2007 ballast tanks, free-flooded spaces and the bottom hulls. The thickness gauging requirements indicated in the table may be reduced or increased, as deemed necessary or appropriate by the Surveyor .
Table 8-2 Thickness Gauging Requirements for Column-Stabilized Units
Special Periodical
Special Periodical
Special Periodical
Subsequent Special
Survey No 1
Survey No 2
Survey No 3
Periodical Survey
194
TCVN 6474-8 : 2007 1) Suspect areas 1) throughout
2)
Columns
bracings
areas 1)
the throughout the unit.
unit. 2)
Suspect
Suspect
areas 1)
throughout the unit.
Representative 2)Representative
and gaugings of columns gaugings,
where and
bracings
wastage is evident
Splash
in Splash Zone.
together
in throughout,
throughout,
of of special and primary
with application
3) 1 girth belt of each of
onehalf
of
the
3) 1 girth belt of each columns and bracings
and of 2 columns and 2 in Splash Zone and
primary application bracings structure
2)Comprehensive
Zone special and primary application structures.
deemed necessary. Special
areas
throughout the unit.
gaugings,
internals in way as structures.
3)
Suspect
in
Splash internals
in
way
as
where Zone together with deemed necessary (i.e.,
wastage is evident.
internals in way as gauge half of the unit’s deemed necessary. 4)
Chain
columns and bracings
locker in
internals as deemed Splash Zone). necessary.
4)
Chain
5) Lower hulls in internals
as
locker deemed
way of mooring lines necessary. where
wastage
evident.
is 5) Lower hulls in way of mooring lines where
6) 1 girth belt of each wastage is evident. lower hull between 6) 1 girth belt of each one set of columns.
lower hull between one set of columns.
Note: Definitions for primary and special structures see TCVN 5318:2001 1.7.2.4 For ship and barge type units, All cargo tanks, ballast tanks, combined cargo/ballast tanks, including double bottom tanks, pump rooms, pipe tunnels, cofferdams and void spaces bounding cargo tanks, decks and outerhull are to be examined. This examination is to be supplemented by thickness measurementand testing as required, to ensure that the structural integrity remains effective. 195
TCVN 6474-8 : 2007 (1)
Cargo piping on deck, including Crude Oil Washing (COW) piping, and all piping systems within the above tanks and spaces are to be examined and operationally tested under working pressure to attending Surveyor’s satisfaction to ensure that tightness and condition remain satisfactory. Special attention is to be given to ballast piping in cargo tanks and any cargo piping in ballast tanks and void spaces. Surveyors are to be advised on all occasions when this piping, including valves and fittings, is open during repair periods and can be examined internally .
(2)
Structural appendages and ducts for posioning system are to be examined.
(3)
Hull structure around the openings such as the moon pool is to be examined.
(4)
Non-destructive tests may be required at important parts or stress concentrated parts where deemed necessary by the VR.
1.7.2.5 The requirements for Close-up Survey and thickness gauging, per TCVN 6259-1A: 2003 will be applied to ship- and barge-type units in the following cases: (1)
The ballast tanks are uncoated.
(2)
Tank coatings are in Poor condition as definition
(3)
Soft coatings are found to be no longer effective
(4)
Substantial corrosion is present
1.7.2.6 For ship- and barge- type units, the extent of Tank Testing are as follows: Tanks are to be hydrostatic tested with a head of liquid to the top of hatches for cargo tanks and to the top of air pipes for ballast tanks. Requirements for tank testing in accordance with unit’s age are specified as follows: (1)
Unit’s age ≤ 5 •
All balast tank boundaries.
•
Cargo tanks boundaries facing ballast tanks, void spaces, pipe tunnels, fuel oil tanks, pump room.
(2)
196
5 < Unit’s age ≤ 10 •
All balast tank boundaries.
•
Cargo tanks boundaries facing ballast tanks, void spaces, pipe tunnels, fuel oil
TCVN 6474-8 : 2007 tanks, pump room. •
(3)
All cargo tanks bulkheads which form the boundaries of segregated cargoes. Unit’s age > 10
•
All balast tank boundaries.
•
Cargo tanks boundaries facing ballast tanks, void spaces, pipe tunnels, fuel oil tanks, pump room.
•
All remaining cargo tank bulkheads.
1.7.2.7 At special periodical surveys after special periodical survey No 1, thickness measurement for ballast tanks is to be carried out in accordance with requerements 1.7.2.1 to 1.7.2.4 . 1.7.3
Special surveys for Machinery Installations and Electrical Installations
1.7.3.1 At each Special Periodical Survey, the following items are to be examined and placed in satisfactory condition: (1)
All shafts except propeller and stern tube shafts thrust blocks and lineshaft bearings are to be examined. The lower halves of bearings need not be exposed if alignment and wear are found satisfactory
(2)
Reduction gears are to be opened up as considered necessary by the surveyor and gears, pinions, gear teeth, shafts and bearings are to be examined.
(3)
Air compressors with their intercoolers, filters and/or oil separators and safety devices, and all pums and components used for essential services are to be opened up as considered necessary by the surveyor and examined. Air compressors, air reservoirs and associated piping are to be examined. If air reservoirs cannot be examined internally, they are to be hydrostatically tested. All relief valves and safety devices are to be proven operable .
(4)
All main and auxiliary steering gears including their associated equipment and control systems are to be examined. They are to be opened up for further examination if considered necessary by the surveyor
(5)
Windlass and mooring winches are to be examined including operational tests, check of the brake and testing of safety devices. They are to be opened up for further examination if considered necessary by the surveyor . 197
TCVN 6474-8 : 2007 (6)
Evaporators are to be opened up and examined. Their safety relief valves are to be checked under working condition.
(7)
The foundation bolts and chocks of mainand auxiliary engines, gear cases, thrust blocks and line shaft bearings are to be examined.
(8)
All air reservoirs and other pressure vessels for essential services together with their mountings and safety devices are to be cleaned internally and examined internally and externally. If an internal examination of them is not practicable, they are to be tested hydraulically to 1,5 times the working pressure .
(9)
Pumping and piping arrangements (a)
The bilge system : Valves, cocks and strainers of the bilge system including the emergency bilge suction valve are to be opened up as considered necessary by the surveyor and examinrd, and the systems including pumps, remote reachrods and level alarms, where firtted, are to be tested in operation .
(b)
The oil fuel, feed and lubricating oil systems and ballast connections and blanking arrangement to deep tanks, together with all pressure filters, heaters and coolers for essential servises are to be opened up and examined or tested as considered necessar by the surveyor. All safety devices for the foregoing items are to be examined .
(c)
Flammable oil tanks : Fuel oil tanks which do not form part of the hull structure are to be examined internally and externally. At the special survey No. 1, the internal examination of the tanks may be dispensed with, provided they are found satisfactory in the external examination. All mountings, fittings and remote shut-off device are to be examined as far as practicable .
(10)
Spare parts are to be checked .
(11)
Automatic and remote controls: Where automatic and/or remote controls are fitted up for essential machinery, they are to be tested to demonstrate that they in good working order .
(12) 198
Steam engines
TCVN 6474-8 : 2007 (a)
Steam turbine (main and auxiliary for essential service ) : Turbine blading, rotors together with bearings, casings, condensers and couplings between turbine and reduction gears are to be examined. At the special survey No.1 for the unit having more than one main propulsion ahead turbines of well experienced type and emergency crossover arrangements, the turbine casings need not be opened up provided vibration indicators and rotorposition indicators are fitted and the operating records are considered satisfactory by the surveyor. The bulkhead stop valves and manoeuvring valves are to be opened up and examined .
(b)
Main steam piping 1)
Selected number of main steam pipes are to be removed and examined internally. In case where the pipes are jointed together by welding and impracticable to be removed, alternative means such as inspection through inspection holes by optical means or checking pipe wall thickness by ultrasonic test may be accepted, and in this case welded seams are to be examined and crack detected to an extent as considered necessary by the surveyor.
2)
At the Special survey No. 3, and subsequent special surveys, pipes submitted to internal examination are to be hydraulically tested to 1,5 times the working pressure
3)
Where temperature of the steam at the superheater outlet does not exceed 450oC steam pipes need not be examined at the special survey No. 1.
(13)
Internal combustion engines ( main and auxiliary for essential service) : (a)
The following parts are to be opened up and examined : Cylinders, covers, valves and valve gears, fuel pumps and fittings, scavenge pumps, scavenge blowers and their driving devices, turbo chargers, pistons, piston rods, crossheads, guides, connecting rods, crank shafts and all bearings, crank case fastening and explosion relief devices, cam shafts and their driving gears, attached pumps and coolers, vibration 199
TCVN 6474-8 : 2007 dampers, balancers, and couplings to the shafting . (b) (14)
Crank shafts alignment is also to be checked .
Electrical installations : Electrical installations on unit the following surveys are to be carried out : (a)
The fittings on switchboards, section boards and distribution boards are to be examined, and overcurrent protective devices are to be checked .
(b)
Cables are to be examined as far as practicable without undue disturbance of fixtures.
(c)
All generators are to be run under loaded condition, either separately or in parallel, and performances of speed governors, generator circuit breakers and their associated relays are to be tested as far as practicable.
(d)
The insulation resistance of generators, switchboards, motors, heaters, lighting fittings and cables are to be tested, and adjusted if it is found not to comply with the requirements 2.18.1 TCVN 6259-4:2003 .
(e)
The whole systems of the emergency source of electrical power and its associated equipment are to be tested to demonstrate that the whole system is in good working order, and if they are automatic, in the automatic mode .
(f)
Navigation light indicators and all the means of communication between the navigation bridge, the control station and the machinery control positions as well as the bridge and alternative steering position, if fitted, are to be tested, and where considered necessary by the surveyor, emergency stopping means of motors for fuel oil pumps, ventilating fans and similar loads, interlocking devices for safety operation of electrical equipment, and motors and their control gears for essential servces are to be tested.
(15)
Machinery and boiler spaces with particular attention to the fire and explosion hazards, and emergency escape routes are to be examined .
(16) 200
Refrigerating installations
TCVN 6474-8 : 2007 Where the refrigerating installations not classed with the VR are installed on board, the following examinations are to be carried out : (a)
The condition on the safety devices attached thereto is to be examined to ensure that they are in good order .
(b)
The machinery is to be tested under working condition .
(c)
Parts of condensers, evaporators, and receivers exposed to primary refrigerant are to be tested at a pressure of 90% of the design pressure. However, the pressure test may be replaced by means as deemed appropriate by the VR and where the relief valves fitted on them are adjusted to opetate at lower than the design pressure, the testing pressure may be reduced to 90% of the setting pressure of the relief valves. The above pressure test may be dispensed with, at the discretion of the surveyor, except for those used for NH3 (R717) as refrigerant.
(17)
For the unit having hazardous areas defined in 1.3.15 all electrical installations and cable therein are to be examined, and insulation resistance of the electrical circuits therein is to be measured .
(18)
Dynamic positioning system (a)
Thorough examination of thruster systems is to be carried out .
(b)
Non-destructive test for mayjor parts of thruster systems is to be carried out, if deemed necessary.
(c)
Examinations and performance test are to be carried out in accordance the test procedure, if any
1.7.3.2 For oil production units the following surveys are to be carried out : (1)
Surveys for items accociated with oil production units specified in 1.3 ;
(2)
For units having boilers burning crude oil or slop, survey and testing of control equipment including monitoring systems and shut-down functions related to the following systems are to be carried out :
(a)
Ventilation and gas-tightness, fuel supply line and boiler with boiler front lagging; 201
TCVN 6474-8 : 2007 (b)
Fuel pumps and heating arrangement;
(c)
Drain pipe ducts and automatic closing drain traps;
(d)
Inert and purging systems;
(e)
Manual and automatic quick closing valves and shut-down systems;
(f)
Boiler hood ventilation system;
(g)
Boiler compartment ventilation ;
(h)
Boiler front extinguishing system;
(i)
Pilot burner arrangement ;
(j)
Gastight bulkhead penetrations;
(k)
Gas detection system;
(l) (3)
Fuel heater .
For units having turbines, engines or boilers burning gas, survey and testing of the safety and control equipment and alarm and shut-down functions related to the following systems are to be carried out:
(4)
(a)
Gas heating arrangement;
(b)
Ventilation arrangement;
(c)
Protection and flame screens;
(d)
Gas freeing and purging systems;
(e)
Manual and automatic shut-down system;
(f)
Gas detection system;
(g)
Pilot flame burner or fuel floor arrangement;
(h)
Governor stability swiching from gas fuel to oil, or vice versa.
Function test of instrumentaion and safety devices for component and systems given in 1.3.2 - 1.3.2.43 (2) is to be carried out.
(5)
The fire extinguishing system are to be surveyed and tested for correct functioning in/at :
202
(a)
Crude oil tank area;
(b)
Crude oil pump room;
(c)
Engine and boiler room
TCVN 6474-8 : 2007 (d)
Helicopter deck.
(6)
It is to be verified that the required signboards are in order;
(7)
The drainage system of the hazardous areas is to be surveyed;
(8)
The insulation resistance of the electrical installation in the hazardous area is to be checked ;
(9)
The fireman's outfit is to be surveyed.
1.7.3.3 For production plants the following are to be carried out : (1)
The requirements stipulated in 1.3.2.4 apply with the additions given in the following ;
(2)
The derrick installation is to be examined with emphasis on the structural condition of bracings particularly with respect to deformation and slack/loose bolts (if of bolted design). Thickness measurements and/or NDT ( nondestructive testing) examination of main structural components and checking of bolts after dismantling may be required as far as deemed necessary by the surveyor .
(3)
Main loading parts of overhead production equipment are to be checked by MPI. Thickness measurements of structural parts as far as deemed necessary required by surveyor. Thickness measurements of structural components and/or NDT to be carried out as far as deemed necssary .
(4)
Internal surveys, or if this is not practical, thickness measurements of pressure vessels and heat exchangers are to be carried out. Examination of related equipment, such as valves, pipes etc. is to be carried out. Examination of correct setting of safety valves including remote operation of same is to be carried out. Pressure test to maximum allowable working pressure to be carried out .
(5)
High pressure/capacity pumps and compressors shall be surveyed by opening up fully or partly as deemed necssary by the surveyor. Pressure testing to be carried out when relevant and found necssary by the surveyor .
(6)
The riser system to be close visually surveyed. Liquid penetrations or MPI methods shall be used to investigate critical areas for cracks. Thickness measurements may be required if found necssary by the surveyor . 203
(7)
The blowout preventer system shall be subject to complete overall and complete performance test. Pressure testing to maximum allowable working pressure to be carried out.
(8)
For lifting devices thickness measurements of structural parts to be carried out as far as deemed necssary. NDT of main structural components may be required as far as deemed necessary by the surveyor .
(9)
The fixed water protection systems in process area are to be surveyed and tested for correct functioning .
(10)
Function test of safety devices and instrumentation given in 1.3.2.4 is to be carried out
1.7.3.4 Other examinations and tests deemed necessary by the surveyor are to be carried out . 1.8
Boiler and thermal oil heater surveys
1.8.1
General Boiler and thermal oil heater surveys are to be carried out in accordance with the requipments in 3.8 Part 1-B, TCVN 6259-1:2003 .
1.9
Propeller shafts and stern tube shaft surveys
1.9.1
General Propeller shafts and stern tube shaft surveys are to be carried out inaccordance with the requipments in 3.9, Part 1-B,TCVN 6259-1:2003.
1.10
Automatic and Remote Control System Surveys
For Automatic and Remote-Control System Annual and Special Periodical Surveys, applicable requirements of TCVN 6277:2003 – Rules for Automatic and RemoteControl System - are to be complied with. 1.11
Annual Surveys for Inert Gas Systems
At each Annual Survey of Machinery the inert gas system is to be generally examined in so far as can be seen and placed in satisfactory condition. The survey is also to include the following, as applicable: 1.11.1
General
1.11.1.1External Examination 204
TCVN 6474-8 : 2007 External examination of all components and piping, including scrubber, fans, valves, stand pipe and screens. 1.11.1.2Inert Gas Blower Confirmation of proper operation of inert gas blowers. 1.11.1.3Scrubber Room Ventilation System Observation of the operation of the scrubber room ventilation system 1.11.1.4 Non-return device Deck seals or double block and bleed assemblies, and non-return valves are to be examined externally and proven to be in operation. Automatic filling and draining of the deck seal, operation of non-return valves and double block and bleed assemblies, and the water carryover are to be checked 1.11.1.5Control Valves. Verify the operation of all remotely operated or automatically controlled valves and, in particular, the flue gas isolating valves . 1.11.1.6Interlocking Feature Verify the operation of the interlocking feature of soot blowers 1.11.1.7Gas Pressure Regulating Valve Verify the automatic operation of the gas pressureregulating valve 1.11.1.8Operation and Maintenance Records The Surveyor is to examine the permanent records to verify the operation and maintenance of the system. 1.11.2
Alarm and Safety Device Verify the operation of the following alarms and safety devices using simulated conditions, where necessary:
1.11.2.1Flue Gas Systems •
Low water pressure or low water flow rate to the flue gas scrubber, including automatic shut-down of the inert gas blowers and gas regulating valve.
•
High water level in the flue gas scrubber, including automatic shut-down of the inert gas blowers and gas regulating valve.
•
205
High gas temperature at IGS blower discharge, including automatic shut-down of the
inert gas blowers and gas regulating valve. Failure of the inert gas blowers, including automatic shut-down of the gas regulating
•
valve. •
Oxygen content in excess of 8% by volume.
•
Failure of the power supply to the automatic control system for the gas regulating valve and to the oxygen content and gas pressure indicating devices.
•
Low water level in the water seal.
•
Gas pressure less than 100 mm water gauge.
•
High gas pressure.
•
Accuracy of fixed and portable oxygen measuring equipment by means of a calibration gas.
1.11.2.2Inert Gas Generating Systems •
Low water pressure or low water flow rate to the inert gas scrubber
•
High gas temperature
•
Oxygen content in excess of 8% by volume
•
High gas pressure
•
Insufficient fuel oil supply
•
Failure of the power supply to the generator
•
Failure of the power supply to automatic control system for the generator
•
Accuracy of fixed and portable oxygen measuring equipment by means of a calibration gas
1.12
Special Periodical Surveys for Inert Gas Systems
In addition to the requirements specified in 1.11, following items are to be surveyed: 1.12.1
General All valves, including valves at boiler uptakes, air seal valves at uptakes, scrubber isolating valves, fans inlet and outlet isolating valves, main isolating valve, recirculating valve (if fitted), pressure/vacuum breaker and cargo tank isolating valves are to be examined. •
206
Scrubber is to be examined.
TCVN 6474-8 : 2007 •
Fans (blowers), including casing drain valves are to be examined.
•
Fan (blower) drives, either electric motor or steam turbine are to be examined.
•
Bellows expansions pieces are to be examined.
•
Sea water pumps, valves and strainers for scrubbers and water seals together with piping connections at the scrubber, water seals, shell plating and the remainder of the sea water piping are to be examined.
•
Stand pipe, where fitted, for purging in each cargo tank is to be examined.
•
Deck seals or double block and bleed assemblies, and non-return valves are to be examined externally and internally.
1.12.2
Separate Inert Gas Generator System Surveys for separate inert gas generator systems are to comply with all applicable requirements in 1.12.1, together with the following: •
Automatic combustion control system is to be examined and tested, as necessary.
•
Combustion chamber and mountings are to be examined internally and externally.
•
Forced draft fan is to be examined.
•
Fuel oil service pumps are to be examined.
1.12.3
Gas Stored in Bottles System Systems using inert gas stored in bottles are to comply with all applicable requirements in 1.12.1, together with the following: •
Bottles are to be examined internally and externally. If they cannot be examined internally, they are to be thickness measured. When considered necessary by the Surveyor, they are to be hydrostatically tested. Relief valves are to be proven operable.
•
Where an alkali (or other) scrubber is fitted in the system, the scrubber, circulating pump, valves and piping are to be examined internally and externally.
1.13
Annual Surveys – Production Facilities
For Annual Survey of Production Facilities, the applicable requirements of the Appendix VII, Part 9 are to be complied with. 1.14
207
Special Periodical Surveys - Production Facilities
For Special Periodical Survey of Production Facilities, the applicable requirements of the Appendix VII, Part 9 are to be complied with. 1.15
Annual Surveys - Mooring Systems
1.15.1
Annual Surveys - Spread Mooring Systems At each Annual Survey, the spread mooring system is to be generally examined so far as can be seen and placed in satisfactory condition as necessary. In addition, the following above water items are to be examined, placed in satisfactory condition and reported upon, where applicable: (1)
The anchor chain stopper structural arrangements are to be visually examined, including the structural foundations of all of the stoppers or holders. Tensioning equipment is to be generally examined.
(2)
The anchor chain catenary angles are to be measured to ensure that the anchor chain tensions are within the design allowable tolerances. Where anchor cables are used, their tensions are to be verified to be within the allowable tensions.
(3)
The anchor chains or anchor cables above the water are to be visually examined for wear and tear.
1.15.2
Annual Surveys - Single Point Mooring (SPM) Systems At each Annual Survey, the single point mooring system is to be generally examined insofar as can be seen above water and placed in satisfactory condition as necessary. In addition, the following above water items are to be examined, placed in satisfactory condition and reported upon, where applicable: (1)
The anchor chain stopper structural arrangements are to be visually examined, including the structural foundations of all of the stoppers.
(2)
The anchor chain's catenary angles are to be measured to verify that the anchor chain tensions are within the design allowable tolerances. Where anchor cables are used, their tensions are to be verified to be within the allowable tensions.
(3)
The anchor chains or anchor cables above the water are to be visually examined for wear and tear.
(4) 208
The condition of the bearings is to be verified for continued effectiveness of
TCVN 6474-8 : 2007 the lubrication system. (5)
The entire assembly of the single point mooring structure above water is to be generally examined for damage, coating breaks and excessive signs of corrosion. This survey is to include all turret wall structures, accessible turret well structures, mooring arms, all structures supporting the disconnectable operations of the mooring system, etc., whichever are applicable
1.16
Special Periodical Surveys - Mooring Systems
Since it is impractical to cover all types of mooring systems, the following are provided as guidance to show the basic intent of the Requirements. Operators and designers may submit alternative survey requirements based either on service experience or manufacturer's recommendations. Upon review and if found acceptable, these alternative survey procedures will form the basis for the Special Periodical Survey of the Mooring System. The Special Periodical Survey is to include all items listed under the Annual Survey and, in addition, the following are to be performed, where applicable: 1.16.1
A Drydocking Survey or equivalent underwater inspection of the SPM system is to be performed. This survey is to include examination of the entire structure of the SPM, the protective coating, cathodic protection system, the chain stoppers and their locking devices.
1.16.2
Any suspect areas where excessive corrosion is evident are to be thickness gauged. Gaugings are to be taken on the structures of the SPM when it has undergone service for 15 years or more.
1.16.3
An examination is to be made on all anchor chains for excessive corrosion and wastage. In particular, the areas to be specially examined are the areas having the most relative movement between the chain links. These areas are normally located in way of the seabed touchdown sections of the catenary part of the chains. The chains are to be inspected for looses studs and link elongations. Sufficient representative locations are to be gauged for wear and wastage. Areas susceptible to corrosion, such as the wind-and-water areas, are to be specially gauged, if considered necessary by the attending Surveyor
1.16.4 209
A close examination is to be performed on all mooring components and accessible
structural members that carry the mooring loads. These structures include the chain stoppers or cable holders, the structures in way of the chain stoppers or cable holders, structural bearing housing and turret/structural well annulus areas. These structures are to be thoroughly cleaned and examined and any suspect areas are to be nondestructively tested. 1.16.5
A general inspection is also to be carried out on the degree of scour or exposure in way of the anchor or anchor piles to ascertain that these components are not overexposed
1.16.6
An examination is to be performed on the main bearing of the SPM system. This examination is to include visual inspection of bearing, if accessible, for water egress into the structural housing, corrosion, pitting and excessive wear. If the bearing is inaccessible, at least the weardown is to be ascertained and the condition of the bearing seals verified. If disassembled, the bearing rollers and the racer housings are to be examined.
1.16.7
For inaccessible structures, special alternative inspection procedures for inspection of these areas are to be submitted for approval.
1.16.8
The chain tensions are to be checked and where found not in compliance with the specifications are to be readjusted accordingly. Excessive loss of chain or tendon tensions are to be investigated.
1.16.9
Representative areas of the chains are to be examined and checked for excessive wastage. In particular, areas in way of the chain stoppers and the seabed touchdown areas are to be specially examined and measured for excessive wear
1.16.10 For disconnectable type mooring systems, the disconnect and connect system for the mooring system is to be tested as considered necessary by the attending Surveyor. Alternatively, records of disconnect/connect operations between the credit date of the last Special Periodical Survey and the current due date of same may be reviewed, and if found satisfactory, it may be considered to have been in compliance with this requirement 1.17
Annual Surveys - Import and Export Systems
At each Annual Survey, the import and export (when requested for classification) systems are to be examined as far as can be seen and placed in satisfactory condition 210
TCVN 6474-8 : 2007 as necessary. In addition, the following items are to be examined, placed in satisfactory condition and reported upon where applicable: (1)
A general examination is to be performed on all electrical and fluid swivels, flexible risers, floating hoses, cargo piping and valves associated with the import and export systems, expansion joints, seals, etc.
(2)
The fluid swivels are to be examined for signs of leaks through their "tell-tale" apertures.
(3)
Records of maintenance are to be reviewed, including records of hose hydrostatic testing.
(4)
Navigational aids for all floating hoses are to be examined and functionally tested.
(5)
Riser tensioning arrangements are to be examined for proper functioning order.
(6)
All electrical equipment, fitted in hazardous location is to be examined for integrity and suitability for the continued service
1.18
Special Periodical Survey – Import and Export Systems
Since it is impractical to cover all types of import and export systems, the following are provided as guidance to show the basic intent of the Requirements. Operators and designers may submit alternative survey requirements based either on service experience or manufacturer's recommendations. Upon review and if found acceptable, these alternative survey procedures will form the basis for the Special Periodical Survey of the Import and Export System The Special Periodical Survey is to include all items listed under the Annual Survey and, in addition, the following are to be performed: 1.18.1
Fluid and electrical swivels are to be disassembled, if considered necessary, and examined for wear and tear. The seals are to be examined. Upon completion of the reconditioning, the fluid swivels are to be hydrostatically tested. Similarly, the electrical swivels are to be insulation tested upon reassembly
1.18.2
During underwater inspection of the SPM system, flexible risers are to be examined, including all arch support buoyancy tanks. Risers are to be inspected for
211
damage in high stress areas, such as areas in way of the end flanges, areas in way of the arch support clamps and the bottom of all looped areas. Spreader bars, if fitted to separate one riser string from another, are to be inspected for wear and tear. Hydrostatic tests may be required to be conducted on the risers, as deemed necessary by the attending Surveyor 1.18.3
For deep sea applications, riser suspension or support systems are to be examined for deterioration and loss of tension. Support areas in way of the riser are to be closely examined for fretting corrosion, wear, kinks, creases, etc.
1.18.4
Floating export hoses are to be examined for kinks, surface cracks, chaffing damages, etc. Hydrostatic and vacuum tests may be required to be conducted on the floating hose string, as deemed necessary by the attending Surveyor.
1.18.5
All piping systems are to be opened up for examination. Nondestructive and hydrostatic tests may be required, where considered necessary by the attending Surveyor.
1.18.6
Hoses designed and manufactured based on OCIMF standards are to be tested in accordance with the OCIMF Guide for the Handling, Storage, Inspection, and Testing of Hoses in the Field.
⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯⎯
212
NATIONAL STANDARD
TCVN 6474-9 : 2007 Second edition
RULES FOR CLASSIFICATION AND TECHNICAL SUPERVISION OF FLOATING STORAGE UNITS PART 9 SPECIFIC REGULATIONS
Reference standards and definitions: see Part 1, TCVN 7474-1: 2007 and this part. This part specifies the specific regulations used in part 1 TCVN 6474-1: 2007 to part 8, TCVN 6474-8:2007.
1.
See appendix I: The Concept and Application of Environmental Severity Factors (ESFs) for Ship-Type Site-Dependent Designed Floating Offshore Installations;
2.
See appendix II: The Modification of Ship-Type Floating Production System Criteria for Site-Specific Environment Conditions;
3.
See appendix III: Extent of structures is to be analysed by Finite Element models (FEM);
4.
See appendix IV: Load Criteria
5.
See appendix V: Fatigue Life ;
6.
See appendix VI: Failure Criteria – Yielding;
7.
See appendix VII: Machinary, process system on floating storage units;
8.
See appendix VIII: Underwater Inspection procedure.
213
TCVN 6474-9 : 2007 1 Appendix I: The Concept and Application of Environmental Severity Factors (ESFs) for Ship-Type Site-Dependent Designed Floating Offshore Installations 1.1 ESFs of the Beta Type
This type of ESF compares the severity between the intended environment relative to a base environment, which is the North Atlantic unrestricted service environment. In the affected formulations, the Beta factors apply only to the dynamic portions of the load components, and the load components that are considered "static" are not affected by the introduction of the Beta factors. The definition of the severity measure Beta is as follows: Beta = Ls/Lu where: Ls - most probable extreme value based on the site-specific environment for the dynamic load parameters specified in Table 9.1-1; Lu - most probable extreme value base on the North Atlantic environment for the dynamic load parameters specified in Table 9.1-1. A Beta of 1.0 corresponds to the unrestricted service condition of a seagoing tanker. A value of Beta less than 1.0 indicates a less severe environment than the unrestricted case The values calculated for Ls and L u are to be consistent with vessel headings. This means that for any dynamic load parameter, if head sea is used for example on the calculation of Ls, the same heading is to be used for the calculation of Lu The net scantling is to be verified using a severity beta factor based on the intended site using a 100-year return period, and the transit condition using a return period as specified in Part 3, clause 1.2.7.2 , whichever is worst . For each dynamic load parameter, the severity measure beta is to account for the vessel headings as follows:
•
For the intended site, the worst case between head seas, following seas and equal probability
•
If no rosette information regarding the environment directionality is available for the transit condition, the worst case between head seas, equal probability and
214
TCVN 6474-9 : 2007 oblique seas (defined as equal probability between head seas and 60 degrees from the bow). Oblique seas are coming either from the port or the starboard side There are 13 dynamic load components for which the beta adjustment factors have been derived. These are for the following loads or load effects: Table 9.1-1: Dynamic Load Parameters or ESFs
No.
Name
1
Vertical Bending Moment
2
Horizontal Bending Moment
3
External Pressure Starboard
4
External Pressure Port
5
Vertical Acceleration
6
Transverse Acceleration
7
Longitudinal Acceleration
8
Relative Vertical Motion at Forepeak
9
Wave Height
10
Pitch Motion
11
Roll Motion
12
Vertical Shear Force
13
Horizontal Shear Force
As mentioned, the Beta values are a direct function of the long-term environmentallyinduced loads at the installation site compared to the unrestricted service environment that is the basis of the Rules. The Beta values also need to address other differences and factors between the design basis of a sea going and a moored vessel. These include:
•
Different design basis return periods for environmental loads (20 vs. 100 years).
•
Effects of mooring system on predicted vessel load effects (including weathervaning type behavior of a turret moored system). 215
TCVN 6474-9 : 2007
•
Different assumed wave energy spreading characterization between the open ocean and a site- specific situation.
•
Different basis of extreme design storm characterization (i.e., long-term winter storm vs. hurricane dominated characterization).
If a direct analysis of a floating offshore installation were to be performed, the influences of the mentioned factors would need to be assessed and used in the vessel's design. Notwithstanding the listed Beta factors and their intended usage, it is still necessary to introduce a limit to keep design parameters from going "too low". This limit is that the result of an application of a Beta factor (e.g., in the calculation of a required scantling) is not to be less than 85 percent of the unrestricted service (Rule) value. 1.2 ESFs of the Alpha Type
This type of ESF compares the fatigue damage between the specified environment relative to a base environment, which is the North Atlantic environment. First, this type of ESF is used to adjust the expected fatigue damage induced from the dynamic components due to environmental loadings at the vessel's installation site. Second it can be used to assess the fatigue damage accumulated during the historical service either as a trading tanker or as an FPI, including both the historical site(s) and historical transit routes The definition of the severity measure a is as follows:
α = D u/Ds where Du - annual fatigue damage based on the North Atlantic environment (unrestricted service) at the regions of the hull structure specified in Table 9.1-2. Ds - annual fatigue damage based on a specified environment, for historical routes, historical sites, transit and intended site, at the regions of the hull structure specified in Table 9.1-2. The values calculated for Ds and D u are to be consistent with the vessel headings. This means that for any structural detail, if head sea is used for examples on the calculation of Ds, the same heading is to be used for the calculation of D u.
216
TCVN 6474-9 : 2007 If the Owner provides no rosette information regarding the environment directionality, the severity measure a for each structural detail is to be selected according to the following criteria:
•
For site spread moored vessels the worst case between equal probability, head seas and following seas
•
For site turret moored vessel, the worst case between head seas, following seas, and oblique seas (defined as equal probability between head seas and 60 degrees heading from the bow), with oblique seas coming either from the port or the starboard side
•
For transit and historical route conditions, the worst case between head seas and oblique seas (defined as equal probability between head seas and 60 degrees from the bow), with the oblique seas coming either from the port or the starboard side Table 9.1-2 - The 6 Fatigue Damage Adjustment Factors
No
Alpha
Applies to
1
αdeck
Deck
2
αSShl
Side Shell
3
αLBhd
Longitudinal Bulkheads
4
αCBhd
Centerline Bulkheads
5
αInBm
Inner Bottom
6
αBttm
Bottom
217
TCVN 6474-9 : 2007 2 Appendix II: The Modification of Ship-Type Floating Production System Criteria for Site-Specific Environment Conditions 2.1 Deck Load
For the design and evaluation of deck structures, the following loads due to on deck production facilities are to be considered: (1) Static weight of on deck production facilities in upright condition. (2) Dynamic loads due to ship motions. (3) Wind load 2.1.1
Loads for On-Site Operation
The nominal forces from each individual deck production module at the center of gravity of the module can be obtained from the following equations: F v
= W cos(0.71 β φ C φ φ ) cos)(0.71 β θ C θ θ ) + 0.71β v cv av / g
F t
= W [sin(0.71 β θ C θ θ ) + 0.71β t ct at / g ]+ k t F wind
F l
= W [− sin(0.71 β θ C θ θ ) + 0.71β l c L al / g ] + k l F wind
Where
φ and θ are the pitch and roll amplitudes with V = 10 knots/h and βφ φ
in degrees, need not to be taken more than 10 degrees
βθ θ
in degrees, need not to be taken more than 30 degrees
di
av, at and a l are the vertical, transverse and longitudinal for heading
=
2 3
d f
μ in table 9.2-1
Fv =
vertical load from each production module, positive downward
Ft =
transverse load from each production module, positive starboard
Fl =
longitudinal load from each production module, positive forward
W =
weight of the production module, in kN
Fwind
2 = kAwind Cs ChVwind
= wind forces, kN Two combinations of wave-induced and wind forces are to be considered: Fv, Ft: Fv, Ft with factor k t =1 and F l with factor k l = 0 218
TCVN 6474-9 : 2007 Fv, Ft with factor k t =0 and Fl with factor k l = 1 The deck load is to be obtained for the maximum weight of on deck production facilities for head sea (Load Case A), beam sea (Load Case B) and oblique sea (Load Case C) listed in Table 9.2-1, where the correlation factors cv, c T, c L, C θ, C φfor each load case are also shown Table 9.2-1: Correlation factors
Load case
LC A (head sea) LC B (beam sea)
LC C (oblique)
cv
0,8
0,4
0,7
cT
0,6
0
0,7
cL
0
0,9
0,7
Cφ
-1
0
-0,7
Cθ
0
1
0,7
0
90
60
Wave angle
heading
μ( degree)
where Vwind = wind velocity based on 1-hour average speed Cs
= shape coefficient, defined in Part 2
Ch
= height coefficient, defined in in Part 2 for 1-hour average wind
The forces from each deck production module can be obtained based on long-term prediction for the realistic sea states of the specific site of operation. In no case are the forces Fv, Ft and Fi to be less than those obtained using the values of Environmental Severity Factors (ESFs) established from Appendix I where β φ
=
ESF for pitch amplitude
β θ
=
ESF for roll amplitude
β v
=
ESF for vertical acceleration
β t
=
ESF for transverse acceleration 219
TCVN 6474-9 : 2007 β φ
=
ESF for longitudinal acceleration
β φ
=
ESF for relative vertical motion at the forward perpendicular on centerline.
2.1.2
Load in Transit Condition Nominal loads of the production facility modules on deck during transit condition can be obtained from the equations in clause 2.1.2, above. Alternatively, corresponding forces can be calculated based on the sea condition for the specific voyage. Also see Part 2.
2.2 Sloshing Loads
Nominal sloshing pressure for strength assessment of tank boundary structures can be obtained from Appendix IV, with the following modifications: Pitch and roll natural motion periods should be obtained from Appendix IV, with V = 10 knots and di = 2/3 d f Parameters φes and
θes should be obtained from the following equations:
= 0,71βφ φ θ es = 0,71βθ θ φes
Where:
φes and θes are given in Appendix IV. φ and θ are the pitch and roll amplitudes defined in Appendix IV, with V = 10 knots and di= 2/3df Alternatively, nominal sloshing pressures can be calculated based on sea condition for the specific site of operation. 2.3 Green Water
When experimental data or direct calculations are not available, nominal green water pressure imposed on deck in the region from FP to 0.30L aft, including the extension beyond the FP, may be obtained from the following equations: Pgi
1/ 2
= k ( M Ri − k1Fbi )
kN/m
2
where Pgi = Green water pressure, uniformly distributed across the deck at specified 220
TCVN 6474-9 : 2007 longitudinal section i within the bow region under consideration . Pressure in between is obtained by linear interpolation. Pgi is not to be taken less than 20.6 kN/m2 . k = 19,614 k 1 = 1 1/ 2
1,39 Ai β vm ( L / C b )
MRi
=
for L in meters
Ai
=
in Table 9.2-2
βvm
=
a vertical motion factor
C b
=
Fulness coefficient in TCVN 6259-2:2003
L
=
length of vessel
F bi
=
freeboard from the highest deck at side to the load waterline (LWL) at
station i Table 9.2-2 - Values of Ai and Bi
Section i from F.P.
Ai
Bi
-0,05L
1,25
0,36
0
1,0
0,4
0,05L
0,8
0,4375
0,1L
0,62
0,4838
0,15L
0,47
0,5532
0,2L
0,33
0,6666
0,25L
0,22
0,8182
0,3L
0,22
0,8182
2.4 Bow Impact Pressure
When experimental data or direct calculations are not available, nominal bow impact pressures due to wave celerity above the load waterline (LWL) in the region from the forward end to the collision bulkhead may be obtained from the following equation: Pbij
= kCk CijVij2 sin γ ij
kN/ m2
where 221
TCVN 6474-9 : 2007 k
=
1,025 1/ 2
Cij = {1 + cos ⎡90 ( Fbi − 2a j ) / Fbi ⎤} ⎣ ⎦ 1/ 2 L ) Vij = ω1 sin α ij + ω 2 ( βWHT 2
ω1
=
3,09
ω2
=
1
βWHT
=
ESF for Wave Height
γ ij
αij
= tan −1 ( tan βij / cos α ij ) =
not to be taken less than 50 degrees
local waterline angle measured from the centerline, not to be taken less
than 35 degrees
βij
=
local body plan angle measured from the horizontal , not to be taken
less than 35 degrees F bi
=
freeboard from the highest deck at side to the load waterline (LWL) at
station i a j
=
vertical distance from LWL to WL-j
i,j
=
station and waterline to be taken to correspond to the locations under
consideration Ck
=
0.7 at collision bulkhead and 0.9 at 0.0125L, linear interpolation for in
between =
0.9 between 0.0125L and FP
=
1.0 at and forward of FP
2.5 Bottom Slamming Pressure
For a vessel with a heavy weather draft forward less than 0.04L but greater than 0.025L, bottom slamming loads are to be considered for assessing strength of the flat bottom plating forward and the associated stiffening system in the fore body region. The equivalent bottom slamming pressure for strength formulation and assessment should be determined based on well-documented experimental data or analytical studies. When these direct calculations are not available, nominal bottom slamming pressures may be determined by the following equations:
222
TCVN 6474-9 : 2007 Psi
= κκ i ( v02 + M Vi Eni ) E f
kN/m
2
where Psi
=
equivalent bottom slamming pressure for section i
κ
=
1,025
κ i
=
2, 2b* / d 0 + α , ≤ 40
b*
=
half width of flat bottom at the i-th ship station
d0
=
1/10th of the section draft at the heavy ballast condition
α
=
a constant as given in table 9.2-3
Ef
=
ω1
=
f1ω 1 L1/ 2
natural angular frequency of hull girder 2-node vertical vibration of the
vessel in the wet mode and the heavy weather ballast draft condition, in rad/second f 1
=
0,004 m
where b represents the half breadth at the 1/10th draft of the section. Linear interpolation may be used for intermediate values
= c0 L1/ 2 c0 = 0,29 m v0
1/ 2
MRi
=
Mvi
=
Gei
1,39 Ai β vm ( L / C b )
with L in metres
B iMRi where B i given in table 9.2-2
= exp ⎡⎣ − ( v02 / M vi + di2 / M Ri ) ⎤⎦
di
=
local section draft, in m
Eni
=
natural log of ni
ni
1/ 2
= 5730 ( M Vi / M Ri )
Gei
if n<1 then Psi = 0
223
TCVN 6474-9 : 2007 Table 9.2-3:Values of
b/d0
α
b/d0
α
1
0
4
20,25
1,5
9
5
22
2
11,75
6
23,75
2,5
14,25
7
24,5
3
16,5
7,5
24,75
3,5
18,5
25
24,75
2.6 Local Structure of the Hull Supporting Deck Mounted Equipment
This Section addresses deck transverses and deck girders 2.6.1
General Section modulus and web sectional area of the deck transverses and deck girders may be obtained in accordance with the procedure given below or other recognized design procedures. Section modulus and web sectional area of the deck transverse and deck girders are not to be less than specified below for the following load patterns: Load pattern No.1 when a tank under consideration is empty and the deck transverse and/or deck girder is loaded with reactions (forces and moments) from the topside structure . Load pattern No.2 when a tank under consideration is full and the deck transverse and/or deck girder is loaded with cargo pressure. The loads from the topside structure are not to be considered for this loading condition ).
2.6.2
Load Pattern No. 1
2.6.2.1 Section Modulus of Deck Transverse The net section modulus of deck transverses, in association with the effective deck plating, is to be obtained from the following equation: SM
(1) 224
= M / f b cm 3
For deck transverses in wing tanks
TCVN 6474-9 : 2007 M
= 105 k ( M p + M g + M s )
N-cm
For deck transverses in center tanks M
= 105 k ( M p + M g + M b )
N-cm
where k
=
1
M p
=
bending moment due to reactions from topside structure
= M v
( M v + M m ) f t = lt ∑ Pn ( k1n + k 2 n ) n
M m
= ∑ M n ( k3 n + k 4 n ) n
Pn
=
reaction deck force number n, in kN , applied to the deck transverse in
tank under consideration, see Figure 9.2-1 M n
=
reaction deck moment number n, in kN-m , applied to the deck
transverse in tank under consideration, see Figure 9.2-1 n
=
1, 2, 3 ……, Nv to obtain bending moment Mv
n
=
1, 2, 3 ……, Nm to obtain bending moment Mm
Nv
=
=
total number of reaction forces at deck transverse under
consideration, (in tank under consideration) Nm
=
total number of reaction moments at deck transverse
under
consideration, (in tank under consideration) lt
=
span of the deck transverse under consideration, in m
225
TCVN 6474-9 : 2007
an
=
distance, in m , from a point of application of reaction (force P n or moment
Mn) to the end of the deck transverse span 1 t, in m , as shown in Figure 9.2-1. z
=
coordinate (measured from the end of the span 1t) of the section of the deck
transverse under consideration, in m , as shown in Figure 9.2-1. For the toe of the deck transverse end brackets: ha
=
z
= ha / lt and
z
= 1 − ha / lt
distance, in m, from the end of the span to the toe of the end bracket of the
deck transverse Note: For a wide topside bracket, the vertical load on a deck transverse can be considered uniformly distributed with pressure qn = P n/c, and the concentrated bending moment can be substituted by force couples. Pm
= M n /(kc)
where Pn , M n
=
concentrated force and moment obtained from FE analysis of
topside structure c
=
width of the topside bracket
k
=
shape bracket factor, and may be taken as 0.8, unless otherwise
specified. Bending moment at the toe of the end brackets due to green water pressure, M g: M g
where 226
= 0,1c3ϕ Pgi slt2
TCVN 6474-9 : 2007 Pgi
=
nominal green water pressure imposed on the deck, in kN/m2 , as
defined in Appendix II, clause 2.3 s
=
spacing, in m, of the deck transverses
Bending moments due to pressure on side transverse and vertical web of longitudinal bulkhead
= ks β s c 2 pssl s2 2 2 M b = kb β b c pb slb M s
where k s = 0.1, and k b = 0.1, unless otherwise specified ls, l b = span, in m (ft), of side transverse and vertical web on longitudinal bulkhead, respectively 2
ps = nominal pressure, in kN/m , at the mid-span of side transverse when wing tank is empty, adjacent tanks full 2
p b = nominal internal cargo pressure, in kN/m , at the mid-span of the vertical web on longitudinal bulkhead when center tank is empty, adjacent tanks full Nominal pressure ps and p b can be obtained in appendix IV with the following modifications: i)
Coefficient wv can be multiplied by factor βv, coefficient wl – by factor βl , coefficient wt – by factor βt, coefficient cθ − by factor βθ, coefficient cφ −by factor βφ
ii)
Ship motions and accelerations
where βv , βl, βt, βθ, βφ are reduction factors accounting for effect of the environmental conditions onsite from Appendix I θ and φ are roll and pitch amplitudes, f t = 1 for tanks without deck girders f t = 1 − [0.67/(1 + 2 δ)] is not to be taken less than 0.70 for tanks with deck girders 3
δ = (l g/lt) (I t/Ig) lg = span of the deck girder, in m sg = spacing, in m , of the deck girder under consideration, 227
TCVN 6474-9 : 2007 4
It, Ig = net moments of inertia, in cm , of the deck transverse and deck girder with effective deck plating, clear of the end brackets, respectively f b = permissible bending stress, in N/cm
2
= 0.70 Smf y 2.6.2.2 Section Modulus of Deck Girder The net section modulus of deck girder with effective deck plating is to be not less than that obtained from the following equation: SM M
= M / f b cm 3
= 105 k ( M p + M g )
N-cm
where k=1 Bending moment due to reactions from topside structure, M p M p
= ( M v + M m ) f g
where Pn
= reaction force number n, in kN , applied to the deck girder under Consideration.
See figure 9.2-1 M n
= reaction moment number n, in kN-m , applied to the deck girder under
consideration. See figure 9.2-1 n = 1, 2, 3 ……, Nv to obtain bending moment Mv n = 1, 2, 3 ……, Nm to obtain bending moment M m Nv = total number of reaction forces at the deck girder between transverse bulkheads in the tank under consideration Nm = total number of reaction moments at the deck girder between transverse bulkheads in the tank under consideration
228
TCVN 6474-9 : 2007
bn = distance, in m , from reaction force Pn to the end of the deck girder span l
g
x = coordinate, in m , of the section of the deck girder under consideration, measured from the end of span l g For the toe of the brackets:
x
= ha / lg
and
x
= 1 − ha / l g
ha = distance, in m , from the end of the deck girder span to the toe of the end of the bracket f g
3 = 1 − 0,13 ⎡⎢( lg / lt ) ( lg / s )( I t / I g )⎤⎥ ⎣ ⎦
0,25
is not to be taken less than 0,65
Bending moment at the toe of the end brackets due to green water pressure, M g M g
= 0,083ϕ Pgi sg l g2
2.6.2.3 Web Sectional Area of Deck Transverse The net sectional area of the web portion of deck transverse is to be obtained from the following equation:: A = F / f s
cm
2
where F
= 1000k ( F p + Fg + c2 sDBc )
N
229
TCVN 6474-9 : 2007
l = span of the deck transverse, in m, he = length of the bracket, in m D = depth of a vessel, in m , as defined in TCVN 6259-2:2003 B = breadth of the center tank, in m f s
= permissible shear stress (N/cm2) =
0,45S m f y
2.6.2.4 Web Sectional Area of Deck Girder The net sectional area of the web portion of deck girders is to be not less than that obtained from the following equation : A = F / f s
cm
2
where
= 1000k ( F p + Fg )
F
F p
= ( Fv + Fm ) f g
Fv
= ∑ Pn (1− bn )
2
N
(1+ 2b ) + ΔF n
n
n
Fm
= 6∑bn (1− bn )M n / lg n
ΔFn = 0 if x ≤ bn = −Pn if x > bn Fg = cpgi ( 0,5l − he ) sg k = 1,0 f s
2
= permissible shear stress, (N/cm ) =
230
0,3Sm f y
TCVN 6474-9 : 2007 2.6.3
Load Pattern No. 2 Section modulus and web sectional area of deck transverses and deck girders for load pattern No. 2 are to be obtained from TCVN 6259-2A. Internal pressure can be obtained from Appendix IV with the modifications given in 2.6.2.
Figure 9.2-1 - Definition of Parameters
231
TCVN 6474-9 : 2007 3 Appendix III: Extent of structures is to be analysed by Finite Element models (FEM) 3.1 Methods of Approach and Analysis Procedures
Maximum stresses in the structure are to be determined by performing structural analyses, as outlined below. structural idealization, load application and structural analysis may be carried out in accordance with recognized documentation/ guideline. In general, the strength assessment is to be focused on the results obtained from structures in the mid hold of a three hold length model. However, the deck transverse, the side transverse, the vertical web on longitudinal bulkheads, the horizontal girder and the vertical web on transverse bulkheads and the cross tie are to be assessed using the end holds of a three hold length model as well. 3.2 3D Finite Element Models
A simplified three-dimensional finite element model, representing usually three bays of tanks within 0.4L amidships, is required to determine the load distribution in the structure. The same 3D model may be used for hull structures beyond 0.4L amidships with modifications to the structural properties and the applied loads, provided that the structural configurations are considered as representative of the location under consideration 3.3 2D Finite Element Models
Two-dimensional fine mesh finite element models are required to determine the stress distribution in major supporting structures, particularly at intersections of two or more structural members. 3.4 Local Structural Models
A 3D fine mesh model is to be used to examine stress concentrations, such as at intersections of longitudinals with transverses and at cut outs. 3.5 Load Cases
When performing structural analysis, the eight combined load cases specified in appendix IV are to be considered. In general, the structural responses for the still-water conditions are to be calculated separately to establish reference points for assessing the waveinduced responses. Additional load cases may be required for special loading patterns and 232
TCVN 6474-9 : 2007 unusual design functions, such as sloshing loads. Additional load cases may also be required for hull structures beyond the region of 0.4L amidships.
233
TCVN 6474-9 : 2007 4 Appendix IV: Load Criteria
The load criteria are applicable for floating storage units with length more than 150 m. For floating storage units with length less than 150 m, a recognized standard may be used. The load criteria in this appendix are used in conjunction with amendments given on appendix II. 4.1 General
4.1.1
Load Components
In the design of the hull structure of tankers, all load components with respect to the hull girder and local structure as specified in TCVN6259-2:2003 are to be taken into account. These include static loads in still water, wave-induced motions and loads, sloshing, slamming, dynamic, thermal and ice loads, where applicable. 4.2 Static Loads
4.2.1
Still-water Bending Moment
For still-water bending moment calculations, see TCVN 6259-2:2003. When a direct calculation of wave-induced loads is not submitted, envelope curves of the still-water bending moments (hogging and sagging) and shear forces (positive and negative) are to be provided. Except for special loading cases, the loading patterns shown in Figure 9.4-1 are to be considered in determining local static loads.
234
TCVN 6474-9 : 2007
Figure 9.4-1 - Loading Pattern 4.3 Wave-induced Loads
4.3.1
General
Where a direct calculation of the wave-induced loads is not available, the approximation equations given below and specified in TCVN6259-2:2003 may be used to calculate the design loads. When a direct calculation of the wave-induced loads is performed, envelope curves of the combined wave and still-water bending moments and shear forces, covering all the anticipated loading conditions, are to be submitted for review. 4.3.2
Horizontal Wave Bending Moment and Shear Force
4.3.2.1 Horizontal wave bending moment The horizontal wave bending moment, positive (tension port) or negative (tension
235
TCVN 6474-9 : 2007 starboard), may be obtained from the following equation: M H
= ±mh K3C1L2 DC b' ×10−3
kN-m
where mh
=
distribution factor, as given by Figure 9.4-2
K 3
=
180
D
=
depth of floating unit '
C1, L and
C b
are as given in Section 13, TCVN6259-2:2003.
Figure 9.4-2 – Distribution Factor mh
4.3.2.2 Horizontal Wave Shear Force The envelope of horizontal wave shearing force, F H, positive (toward port forward) or negative (toward starboard aft), may be obtained from the following equation: F H
= ± f h kC1 L D ( Cb' + 0, 7 ) ×10 −2
kN
where f h
=
distribution factor, as given in Figure 9.4-3
k
=
36
C1, L and C b’ are as given in Section 13, TCVN6259-2:2003.
236
TCVN 6474-9 : 2007
Figure 9.4-3 - Distribution Factor f h
4.3.3
External Pressures
4.3.3.1 Pressure Distribution The external pressures, pe , (positive toward inboard), imposed on the hull in seaways can be expressed by the following equation at a given location: Pe
= ρ g ( hs + ku hde ) ≥ 0
N/cm
2
where
ρg = specific weight of sea water 2
= 1,005 N/cm -m hs = hydrostatic pressure head in still water, in m k u = load factor, and may be taken as unity unless otherwise specified. hde = hydrodynamic pressure head induced by the wave, in m (ft), may be calculated as follows: =
k chdi
where k c = correlation factor for a specific combined load case, as given in 4.4.1 and 4.5.2. hdi = hydrodynamic pressure head, in m , at location i (i = 1,2,3,4 or 5; see figure 9.44)
237
TCVN 6474-9 : 2007 kλ α i hdo
= k λ
= distribution factor along the length of the floating unit =
1 + ( k λ o − 1) cos μ k λ 0
,
is as given in figure 9.4-5
= 1 amidships hdo = 1,36kC 1(m) k=1 α i
= distribution factor around the girth of floating unit at location i.
= 1 – 0,25 cos
μ
for i = 1, at WL, starboard
= 0,4 – 0,1 cos
μ
for i = 2, at bilge, starboard
= 0,3 – 0,2 sin μ = 2α3 –
α2
for i = 3, at bottom centerline for i = 4, at bilge, port
= 0,75 – 1,25 sin μ for i = 5, at WL, port α i at intermediate locations of i may be obtained by linear interpolation
μ
= wave heading angle, to be taken from 0° to 90° (0° for head sea, 90° for beam
sea for wave coming from starboard). The distribution of the total external pressure including static and hydrodynamic pressure is illustrated in Figure 9.4-6.
238
TCVN 6474-9 : 2007
Figure 9.4-4 - Distribution of h di
Figure 9.4-5 - Pressure Distribution Function
239
TCVN 6474-9 : 2007
Figure 9.4-6 - Illustration of Determining Total External Pressure
240
TCVN 6474-9 : 2007
Figure 9.4-7 - Definition of Tank Geometry
241
TCVN 6474-9 : 2007
Figure 9.4-8 - Location of Tank for Nominal Pressure Calculation
4.3.3.2 Extreme Pressures In determining the required scantlings of local structural members, the extreme external pressure, pe , to be used, is as defined in 4.3.3.1 with k u as given in 4.4 and 4.5. 4.3.3.3 Simultaneous Pressures When performing 3D structural analysis, the simultaneous pressure along any portion of the hull girder may be obtained from: Pes
= ρ g ( hs + k f ku hde ) ≥ 0 N/cm 2
where k f is a factor denoting the phase relationship between the reference station and adjacent stations considered along the vessel’s length, and may be determined as 242
TCVN 6474-9 : 2007 follows: k f
⎧⎪ ⎡ ⎫⎪ 2π ( x − x0 ) ⎤ cos μ = k fo ⎨1 − ⎢1 − cos ⎬ ⎥ L ⎦ ⎩⎪ ⎣ ⎭⎪
where x = distance from A.P. to the station considered, in m x0 = distance from A.P. to the reference station, in m L = the floating unit length, m = the wave heading angle, to be taken from 0° to 90° kf o = ± 1.0, as specified in Table 9.4-1 The simultaneous pressure distribution around the girth of the vessel is to be determined based on the wave heading angles specified in 4.4 and 4.5 4.4 Nominal Design Loads
4.4.1
Hull Girder Loads – Longitudinal Bending Moments and Shear Forces
4.4.1.1 Total Vertical Bending Moment and Shear Force The total longitudinal vertical bending moments and shear forces may be obtained from the following equations::
= M sw + ku kc M w = Fsw + ku kc Fw
M t
kNm
Ft
kN
where Msw and M w are the still-water bending moment and wave-induced bending moment, Fsw and F w are the still-water and wave-induced shear forces k u is a load factor and may be taken as unity unless otherwise specified k c is a correlation factor and may be taken as unity unless otherwise specified. For determining the hull girder section modulus for 0.4L amidships, the maximum stillwater bending moments, either hogging or sagging, are to be added to the hogging or sagging wave bending moments, respectively. Elsewhere, the total bending moment may be directly obtained based on the envelope curves, as specified in 4.2.1 and 4.3.1. 4.4.1.2 Horizontal Wave Bending Moment and Shear Force For non-head sea conditions, the horizontal wave bending moment and the horizontal 243
TCVN 6474-9 : 2007 shear Force , are to be considered as additional hull girder loads, especially for the design of the side shell and inner skin structures. The effective horizontal bending moment and shear force, MHE and FHE, may be determined by the following equations:
= ku kc M H kNm = ku kc FH kN
M HE F HE
where k u and k c are a load factor and a correlation factor, respectively, which may be taken as unity unless otherwise specified 4.4.2
Local Loads for Design of Supporting Structures
In determining the required scantlings of the main supporting structures, such as girders, transverses, stringers, floors and deep webs, the nominal loads induced by the liquid pressures distributed over both sides of the structural panel within the tank boundaries should be considered for the worst possible load combinations. In general, considerations should be given to the following two loading cases accounting for the worst effects of the dynamic load components. i.
Maximum internal pressures for a fully filled tank with the adjacent tanks empty and minimum external pressures, where applicable.
ii.
Empty tank with the surrounding tanks full and maximum external pressures, where applicable.
Taking the side shell supporting structure as an example, the nominal loads may be determined from either:
= ks ρ g (η + ku hd ) Pe = ρ g ( hs + ku hde ) Pi
i.
=0 Pe = ρ g ( hs + ku hde )
max
min
Pi
ii.
max
where k u = 1. 4.4.3
Local Pressures for Design of Plating and Longitudinals
In calculating the required scantlings of plating, longitudinals and stiffeners, the nominal pressures should be considered for the two load cases given in 4.4.3, using k u = 1.1 for pi and pe instead of k u = 1.0 as shown above
244
TCVN 6474-9 : 2007 4.5 Combined Load Cases
4.5.1
Combined Load Cases for Structural Analysis
For assessing the strength of the hull girder structure and in performing a structural analysis , the eight combined load cases specified in Table 9.4-1 are to be considered. Additional combined load cases may be required as warranted. The loading patterns are shown in Figure 9.4-1 for three cargo tank lengths. The necessary correlation factors and relevant coefficients for the loaded tanks are also given in Table 9.4-1 . The total external pressure distribution including static and hydrodynamic pressure is illustrated in Table 9.4-6. 4.5.2
Combined Load Cases for Failure Assessment
For assessing the failure modes with respect to material yielding, buckling and ultimate strength, the following combined load cases shall be considered. 4.5.2.1 Ultimate Strength of Hull Girder For assessing ultimate strength of the hull girder, the combined effects of the following primary and local loads are to be considered. (1) Primary Loads, Longitudinal Bending Moments in Head Sea Conditions (MH = 0, FH= 0) M t Ft
= M s + ku kc M w , k = 1,15, u
= Fs + ku kc Fw ,
k u= 1,15,
k c = 1 k c = 1
(2) Local Loads for Large Stiffened Panels Internal and external pressure loads as given for L.C. No. 1 and L.C. No. 2 in Table 9.4-1. 4.5.2.2 Yielding, Buckling and Ultimate Strength of Local Structures For assessing the yielding, buckling and ultimate strength of local structures, the eight combined load cases as given in Table 9.4-1 are to be considered. 4.5.2.3 Fatigue Strength For assessing the fatigue strength of structural joints, the eight combined load cases given in Table 9.4-1 are to be used
245
TCVN 6474-9 : 2007 4.6 Sloshing Loads
4.6.1
General
4.6.1.1 Except for tanks that are situated wholly within the double side or double bottom, the natural periods of liquid motions and sloshing loads are to be examined in assessing the strength of boundary structures for all cargo or ballast tanks which will be partially filled between 20% and 90% of tank capacity. The sloshing pressure heads given in this subsection may be used for determining the strength requirements for the tank structures. Alternatively, sloshing loads may be determined by model experiments or by numerical simulation using three dimensional flow analysis. Methodology and procedures of tests and measurements or analysis methods are to be fully documented and referenced. They are to be submitted for review. 4.6.1.2 The effects of impulsive sloshing pressures on the design of the main supporting structures of tank transverse and longitudinal bulkheads will be subject to special consideration. 4.6.2
Strength Assessment of Tank Boundary Structures
4.6.2.1 Tank Length and Pitch Induced Sloshing Loads 4.6.2.2 Roll Induced Sloshing Loads 4.6.2.3 For long or wide cargo tanks, non-tight bulkheads or ring webs or both are to be designed and fitted to eliminate the possibility of resonance at all filling levels. Long tanks have length, l, exceeding 0.1L. Wide tanks have width, b, exceeding 0.6B. 4.6.2.4 For each of the anticipated loading conditions, the “critical” filling levels of the tank should be avoided so that the natural periods of fluid motions in the longitudinal and transverse directions will not synchronize with the natural periods of the vessel’s pitch and roll motions, respectively. The natural period of the fluid motion, in seconds, may be approximated by the following equations:
246
1/ 2
T x
= ( βT λ e )
T y
= ( β Lbe )
1/ 2
/ k
in the longitudinal direction
/ k
in the transverse direction
TCVN 6474-9 : 2007 where λ e
=
effective length of the tank
be
=
effective breadth of the tank 1/ 2
= ⎣⎡( tanh H1 ) / ( 4π / g ) ⎤⎦ H1 = π d / λe ; π d b / be k
λ
4.6.3
Sloshing Pressures
4.6.3.1 Nominal Sloshing Pressure For cargo tanks with filling levels within the critical range , the internal pressures pis, including static and sloshing pressures, positive toward tank boundaries, may be expressed in terms of equivalent liquid pressure head, he, as given below: Pis
= ks ρ ghe ≥ 0
where Pis
2
= internal pressures including static and sloshing pressures, N/cm
k s = load factor he = =
cm hm + ku hc ku ⎡⎣ hc
for y below filling level d m
+ ( ht − hc )( y − d m ) / ( h − d m )⎤⎦
for y above dm
hm = static head, taken as the vertical distance, in m, measured from the filling level, dm, down to the point considered. dm = filling level, in m k u = load factor, and may be taken as unity unless otherwise specified hc = maximum average sloshing pressure heads, in m =
(
2
kc Cφ s hλ
1/ 2
+ Cθ s hb2 )
ht = sloshing pressure heads for upper bulkhead, in m =
(
2
kc Cφ s htλ
1/ 2
+ Cθ s htb2 )
h = depth of tank, in m y = distance, in m , measured from the tank bottom to the point considered
247
TCVN 6474-9 : 2007 k c = correlation factor for combined load cases, and may be taken as unity unless otherwise specified
Cφs and C θs are the weighted coefficients as given in Figure 10 9.4-10 where βT represents β for transverse bulkheads and βL represents β for the longitudinal bulkheads
λ e
= effective tank length that accounts for the effect of deep ring-web frames, in m *2
= be
βT λ
= effective tank width that accounts for the effect of deep ring-web frames, in m =
β L*2 b
*
β = 1.0 for tanks without deep ring webs
=
0, 25 ⎡4 − (1 − α * ) − (1 − α * )
2
⎢⎣
⎤ ⎥⎦ for α* to be determined at do
βT represents β * for transverse bulkheads β*L represents β* for longitudinal bulkheads β
= ( β 0 )( β s ) ≥ 0,5
βT represents β for transverse bulkheads. βL represents β for longitudinal bulkheads β 0
= 1 for tanks without a swash bulkhead =
β s
248
0, 25 ⎡4 − (1 − α 0 ) − (1 − α 0 )
⎣
2
⎤ ⎦ for tanks with a swash bulkhead
= 1 for boundary bulkheads that: i.
do not contain any deep horizontal girder; or
ii.
do contain deep horizontal girders but with an opening ratio, αs, less
TCVN 6474-9 : 2007 than 0.2 or greater than 0.4 =
0, 25 ⎡4 − (1 − α s ) − (1 − α s )
⎣
2
⎤ ⎦ for bulkheads with deep horizontal girders having
an opening ratio, αs, between 0.2 and 0.4
= xo if
xo1
xo
≤1 >1
= 1/ xo if xo
yo
= Ty / T r
yo1
= yo if
yo
≤1
= 1/ yo if yo
>1
d λ 1
= height of deep bottom transverses measured from the tank bottom, m
d λ 2
= bottom height of the lowest openings in non-tight transverse bulkhead
measured above the tank bottom or top of bottom transverses, m. n = number of deep bottom transverses in the tank d b1 d b 2
= height of deep bottom longitudinal girders measured from the tank bottom, m = bottom height of the lowest openings in non-tight longitudinal bulkhead
measured above the tank bottom, or top of bottom longitudinal girders, m. m = number of deep bottom longitudinal girders in the tank
249
TCVN 6474-9 : 2007
where '
'
C tb
C φ s
and C θ s are weighted coefficients, as given in Figure 9.4-10.
and
C tb
β L'
and
are
C t λ
β T '
C t λ
for hm = 0,7h;
and
htl shall not be less than hp; htb shall not be less than
correspond to β for do = 0.7h.
hr
4.6.3.2 Sloshing Loads for Assessing Strength of Structures at Tank Boundaries (1)
In assessing the strength of tank boundary supporting structures, the two combined load cases with loading pattern shown in Figure 9.4-14 , with the specified sloshing loads shown in Table 9.4-2 for the respective side on which the horizontal girder is located, are to be considered when performing a 3D structural analysis .
(2)
In assessing the strength of plating and stiffeners at tank boundaries, local bending of the plating and stiffeners with respect to the local sloshing pressures for structural members/elements is to be considered in addition to the nominal loadings specified for the 3D analysis in (1) above. In this regard, ku should be taken as 1.15 instead of 1.0.
4.6.3.3 Sloshing Loads Normal to the Web Plates of Horizontal and Vertical Girders In addition to the sloshing loads acting on the bulkhead plating, the sloshing loads normal to the web plates of horizontal and vertical girders are to be also considered for assessing the strength of the girders. The magnitude of the normal sloshing loads may be approximated by taking 25% of hc or h t for k u = 1.0, whichever is greater, at the location considered
250
TCVN 6474-9 : 2007
Figure 9.4-9 - Vertical Distribution of Equivalent Slosh Pressure Head
Figure 9.4-10 - Horizontal Distribution of Simultaneous Slosh Pressure Heads 251
TCVN 6474-9 : 2007
Figure 9.4-11 - Definitions for Opening Ratio, α
Figre 9.4-12 - Opening Ratios
252
TCVN 6474-9 : 2007
Figure 9.4-13 Dimensions of Internal Structures
Figure 9.4-14 - Loading Patterns for Sloshing Loads Cases
253
TCVN 6474-9 : 2007 Table 9.4-1 Combined Load Cases (*) L.C. 1
L.C. 2
L.C. 3
L.C. 4
L.C. 5
L.C. 6
L.C. 7
L.C. 8
L.C. 9
L.C.10
(-)
(+)
(-)
(+)
(-)
(+)
(-)
(+) (+ )
-
-
1
1
0,7
0,7
0,3
0,3
0,4
0,4
0
0
Vertical S.F.
(+)
(-)
(+)
(-)
(+)
(-)
(+)
(-)
-
-
k c
0,5
0,5
1
1
0,3
0,3
0,4
0,4
0
0
(-)
(+)
(-)
(+)
0,3
0,3
1
1
0
0
(+)
(-)
(+)
(-)
A. Hull Girder Loads (See 4.3)
Vertical B.M.
k c
Horizontal B.M.
0
k c
0
0
0
Horizontal S.F.
0
k c
0
0
0
0,3
0,3
0,5
0,5
0
0
B. External Pressure (See 4.3.3)
k c
0,5
0,5
0,5
1
0,5
1
0,5
1
0
0
k f0
-1
1
-1
1
-1
1
-1
1
0
0
k c
0,4
0,4
1
0,5
1
0,5
1
0,5
0
0
wv
0,75
-0,75
0,75
-0,75
0,25
-0,25
0,4
-0,4
0
0
wl
Fwd
Fwd
Fwd
Fwd
-
-
Fwd
Fwd
Bhd
Bhd
Bhd
Bhd
Bhd
Bhd
0,25
-0,25
0,25
-0,25
0,2
-0,2
Aft
Aft
Aft
Aft
Aft Bhd
Aft
Bhd
Bhd
Bhd
Bhd
-0,2
Bhd
-0,25
0,25
-0,25
0,25
-
-
-
-
-
-
-
-
C. Internal Tank Pressure
wt
-
-
-
-
0,2 Port
Port
Port
Port
Bhd
Bhd
Bhd
Bhd
-0,75
0,75
-0,4
0,4
Stbd
Stbd
Stbd
Stbd
Bhd
Bhd
Bhd
Bhd
0,75
-0,75
0,4
-0,4
cφ, Pitch
-1
1
-1
1
0
0
-0,7
0,7
0
0
cθ, Roll
0
0
0
0
1
-1
0,7
-0,7
0
0
(*) k u = 1.0 for all load components. L.C. = Load Case 254
TCVN 6474-9 : 2007 Table 9.4-2 Load Cases for Sloshing Type A: For Horizontal Girder on the Aft Side of Transverse Bulkhead External Pressures
Hull girder Loads( *)
Sloshing
Reference Wave Heading and Motions
Pressures**
VBM
VSF
k u
k c
k u
k c
k f0
k u
k c
Heading
Heave
Pitch
Roll
Down
Bow
Stbd
Down
Down
-0.9
0.9
Bow
Stbd
Up
Up
0.9
-0.9
Angle
LC S-1
LC S-2
HBM
HSH
k u
k c
(-)
(+)
1,0
0,4
(-)
(+)
1,0
0,7
(+)
(-)
1,0
0,4
(+)
(-)
1,0
0,7
1,0
1,0
0,5
0,5
-1,0
-1,0
1,0
1,0
1,0
1,0
600
0
60
Up
Type B: For Horizontal Girder on the Forward Side of Transverse Bulkhead External Pressures
Hull girder Loads*
Sloshing
Reference Wave Heading and Motions
Pressures**
VBM
VSF
k u
k c
HBM
HSH
k u
k c
(-)
(+)
1,0
0,4
(-)
(+)
1,0
0,7
k u
k c
k f0
k u
k c
Heading
Heave
Pitch
Roll
Up
Bow
Stbd
Up
Up
0.9
-0.9
Bow
Stbd
Down
Down
-0.9
0.9
Angle
LC S-1
LC S-2
(+) (+)
*
(-) (-)
1,0 1,0
0,4
1,0
1,0
0,5
0,5
-1,0
-1,0
1,0
1,0
1,0
1,0
600
600
Down
0,7
For determining the total vertical bending moment for the above two load cases, 70% of the maximum designed still water bending moment may be used at the specified wave vertical bending moment station.
**
Sloshing Pressures
VBM
is vertical wave bending moment
VSF
is vertical wave shear force
HBM
is horizontal wave bending moment
HSF
is horizontal wave shear force
H
Heave
P
Pitch
R
Roll
255
TCVN 6474-9 : 2007 4.7 Impact Loads
Impact Loads are calculated in accordance with appropriate clauses given in appendix II
256
TCVN 6474-9 : 2007 5 Appendix V: Fatigue Life 5.1 Floating storage units with length more than 150 m
5.1.1
General An analysis is to be made of the fatigue strength of welded joints and details in highly stressed areas especially where higher strength steel is used. Special attention is to be given to structural notches, cutouts and bracket toes, and also to abrupt changes of structural sections. The following subparagraphs are intended to emphasize the main points and to outline procedures where refined spectral analysis techniques are used to establish fatigue strength
5.1.1.1 Workmanship: As most fatigue data available were experimentally developed under controlled laboratory conditions, consideration is to be given to the workmanship expected during construction. 5.1.1.2 Fatigue Data: paid to the background of all design data and its validity for the details being considered. In this regard, recognized design data, such as those by AWS (American Welding Society), API (American Petroleum Institute) should be considered. If other fatigue data are to be used, the background and supporting data are to be submitted for review. In this regard, clarification is required whether or not the stress concentration due to the weld profile, certain structural configurations and also the heat effects are accounted for in the proposed S-N curve. Consideration is also to be given to the additional stress concentrations. 5.1.1.3 Design Consideration: In design, consideration is to be given to the minimization of structural notches and stress concentrations. Areas subject to highly concentrated forces are to be properly configured and stiffened to dissipate the concentrated loads.. 5.1.2
Procedures The analysis of fatigue strength for a welded structural joint/detail may be performed in accordance with the following procedures:
5.1.2.1 Step 1 – Classification of Various Critical Locations The class designations and associated load patterns are given in recognized 257
TCVN 6474-9 : 2007 standard/intruction. 5.1.2.2 Step 2 – Permissible Stress Range Approach Where deemed appropriate, the total applied stress range of the structural details classified in Step 1 may be checked against the permissible stress ranges, where stress range is Smax – S min. 5.1.2.3 Step 3 – Refined Analysis Refined analyses are to be performed, as outlined below, for the structural details for which the total applied stress ranges obtained from Step 2 are greater than the permissible stress ranges, or for which the fatigue characteristics are not covered by the classified details and the associated S-N curves. The fatigue life of structures is generally not to be less than 20 years, unless otherwise specified. (1)
Spectral analysis: Alternatively, a spectral analysis may be performed, as outlined in 5.1.3 below, to directly calculate fatigue lives for the structural details in question.
(2)
Refined fatigue data: For structural details which are not covered by the detail classifications, proposed S-N curves and the associated SCFs, when applicable, may be submitted to VR for consideration. In this regard, sufficient supporting data and background are also to be submitted to VR for review. The refined SCFs may be determined by finite element analyses
5.1.3
Spectral Analysis Where Refined Analysis is exercised, a spectral analysis is to be performed in accordance with the following guidelines.
5.1.3.1 Representative Loading Patterns Several representative loading patterns are to be considered to cover the worst scenarios anticipated for the design service life of the floating units with respect to hull girder local loads . 5.1.3.2 Environmental Representation Instead of the design wave loads specified in appendix IV, a wave scatter diagram (such as Walden’s Data) is to be employed to simulate a representative distribution of
258
TCVN 6474-9 : 2007 all of the wave conditions expected for the design service life of the vessel. In general, the wave data is to cover a time period of not less than 20 years. The probability of occurrence for each combination combin ation of significant wave height and mean period of the representative wave scatter diagram is to be weighted, based on the operation time of the floating units. 5.1.3.3 Calculation of Wave Load RAOs The wave load RAOs with respect to the wave-induced bending moments, shear forces, motions, accelerations and hydrodynamic pressures can then be predicted by floating unit motion calculation for a selected representative loading condition 5.1.3.4 Generation of Stress Spectrum The stress spectrum for each critical structural detail (spot) may be generated by performing a structural analysis, accounting for all of the wave loads separately for each individual wave group. For this purpose, the 3D structural model and 2D models specified in appendix III may be used for determining structural responses. The additional secondary and tertiary stresses are also to be considered. 5.1.3.5 Cumulative Fatigue Damage and Fatigue Life Based on the stress spectrum and wave scatter diagram established above, the cumulative fatigue damage and the corresponding fatigue life can be estimated by the Palmgren-Miner linear damage rule 5.2 Floating storage units with length less than 150 m
For Floating storage units with length less than 150 m, the procedures and fatigue calculation guideline given on recognized standards may be used.
259
TCVN 6474-9 : 2007 6 Appendix VI: Failure Criteria – Yielding 6.1 Floating storage units with length more than 150 m
6.1.1
General The calculated stresses in the hull structure are to be within the limits given below for the entire combined load cases specified in appendix IV.
6.1.2
Structural Members and Elements For all structural members and elements, such as longitudinals/stiffeners, web plates and flanges, the combined effects of all of the calculated stress components are to satisfy the following limits: f i
≤ Sm f y
where f i = stress intensity
( f =
2 L
f L
+
2
fT
−
1/ 2
2 + 3 f LT )
f L fT
N/cm
2
= calculated total in-plane stress in the longitudinal direction including primary
and secondary stresses f L1 + f L 2 + f L*2
=
N/cm2
f L1
= direct stress due to the primary (hull girder) bending , N/cm
f L 2
= direct stress due to the secondary bending between bulkheads in the
2
2
longitudinal direction, N/cm f L*2
= direct stress due to local bending of longitudinal between transverses in the 2
longitudinal direction, N/cm f T
= calculated total direct stress in the transverse/vertical direction, including
secondary stresses fT 1 + fT 2 + f T 2 *
=
N/cm
2
f LT = calculated total in-plane shear stress, N/cm
2
f T1 = direct stress due to sea and cargo load in the transverse/vertical direction, N/cm
2
f T2 = direct stress due to the secondary bending between bulkheads in the 260
TCVN 6474-9 : 2007 2
transverse/vertical direction, N/cm
f*T2 = direct stress due to local bending of stiffeners in the transverse/vertical 2
direction, N/cm
f y = specified minimum yield point, N/cm
2
Sm = strength reduction factor, given in VR’s Applicable material rules For this purpose,
f L*2
and
f T *2
in the flanges of longitudinal and stiffener at the ends
of span may be obtained from the following equation: f L 2
= 0, 07 spλ / SM L N/cm 2
fT*2
= 0, 07 spλ / SM T N/cm 2
*
where s = spacing of longitudinals (stiffeners), in cm l = unsupported span of the longitudinal (stiffener), in cm 2
p = net pressure load, in N/cm , for the longitudinal (stiffener) 3
SML (SMT) = net section modulus, in cm , of the longitudinal (stiffener) 6.1.3
Plating For plating away from knuckle or cruciform connections of high stress concentrations and subject to both in-plane and lateral loads, the combined effects of all of the calculated stress components are to satisfy the limits specified in 6.1.2 with f L and f T modified as follows: f L
=
f L1 + f L 2 + f L*2 + f L3
fT
=
fT 1 + f T 2 + fT 2 + f T 3
N/cm
2
N/cm
2
*
where f L 3 , f T 3
= plate bending stresses between stiffeners in the longitudinal and transverse
directions, respectively, and may be approximated as follows: 2
⎛s⎞ 0,182 p ⎜ ⎟ f L 3 ⎝ t n ⎠ N/cm 2 = 2
⎛s⎞ 0,266 p ⎜ ⎟ f T 3 ⎝ t n ⎠ N/cm 2 = 261
TCVN 6474-9 : 2007 2
p = lateral pressures for the combined load case considered , in N/cm s = spacing of longitudinals or stiffeners, in mm n
t = net plate thickness, in mm 6.2 Floating storage units with length less than 150 m
For Floating storage units with length less than 150 m, the appropriate requirements in TCVN 6259:2-2003 are to be complied with.
262
TCVN 6474-9 : 2007 7 Appendix VII: Machinary, process system on floating storage unit 7.1 General
This chapter defines the minimum criteria to equipment and systems on floating installations. These systems include: 1) Hydrocarbon Production and Process systems 2) Process Support Systems 3) Process Control Systems 4) Electrical Systems 5) Instrumentation and Control Systems 6) Fire Protection and Personnel Safety Systems 7.2
7.2.1
Definitions
Process Areas: Process Areas are areas where processing equipment is located. This includes wellhead/manifold Areas
7.2.2
Production Facilities/ System: production facilities are typically the processing, safety and control systems, utility and auxiliary equipment, for producing hydrocarbon liquid and gas mixtures from completed wells or other sources. The production facility is terminated at the inlet flange discharge into the storage tank.
7.2.3
Lower Explosive Limit (L.E.L.): The lowest concentration of combustible vapors or gases, by volume in mixture with air, which can be ignited at ambient conditions.
7.2.4
“H” Class Divisions “H” class divisions are those divisions formed by bulkheads and decks that are complied with requirements from (a) to (d) below, A test of a prototype fire wall or deck may be required by VR to ensure that it meets the above requirements for integrity and temperature rise: (a) constructed of steel or other equivalent material, (b) suitably stiffened, (c) These are designed to withstand and prevent the passage of smoke and flame for the 120-minute duration of a hydrocarbon fire test. (d) “H” class divisions are to be insulated by approved material by VR or other 263
TCVN 6474-9 : 2007 orgnization recognized by VR so that the average temperature of the unexposed face will not increase by more than 1390C any time during the two-hour hydrocarbon fire test, nor will the temperature, at any point on the face, including any joint, rise more than 1800C above the initial temperature, within the time listed below: class “H-120” 120 minutes class “H-60” 60 minutes class “H-0” 0 minutes This division is to remain intact with the main structure of the vessel, and is to maintain its structural integrity after two (2) hours. Structural integrity means that it will not fall under its own weight, nor will it crumble or break upon normal contact after exposure to the fire. 7.2.5
Abnormal Condition: A condition which occurs in a process system when an operating variable (flow, pressure, temperature, etc.) ranges outside of its normal operating limits..
7.2.6
Hazardous Area: A location in which flammable gases or vapors are or may be present in the air in quantities sufficient to produce explosive or ignitable mixtu res.
7.2.7
Closed Drains: Hard piped drains from process components, such as pressure vessels, piping, liquid relief valves etc., to a closed drain tank without any break to atmosphere.
7.2.8
Open Drains: Gravity drains from sources which are at or near atmospheric pressure, such as open deck drains, drip pan drains, and rain gutters..
7.2.9
Fire Wall: A wall designed and constructed to remain structurally intact under the effects of fire and insulated so that the temperature on the unexposed side will remain below a specified temperature for a determined amount of time..
7.2.10
Fired Vessel: A vessel in which the temperature of the fluid is increased by the addition of heat supplied by a flame within the vessel. Specifically for hydrocarbon services, there are two types of fired vessels: (1) Direct Fired Vessel: A vessel in which the temperature of process hydrocarbon fluids is increased by the addition of heat supplied by a flame. The flame is applied directly to the fluid container. The combustion takes
264
TCVN 6474-9 : 2007 place in the heater. (2) Indirect Fired Vessel: A vessel in which the energy is transferred from an open flame or product of combustion (such as exhaust gases from turbines, engines, or boilers) to the hydrocarbon, through a heating medium, such as hot oil. The heating medium is usually non-combustible or has a high flash point. The combustion may, but does not necessarily, take place in the heater. 7.3 Plans and Particulars to be Submitted
7.3.1
Plans and Particulars to be Submitted
7.3.1.1 Hydrocarbon Production and Processing Systems (1)
Project Specification
(2)
Process Flow Sheets
(3)
Heat and Mass Balance
(4)
Equipment Layout Drawings
(5)
Area Classification and Ventilation Drawings
(6)
Piping and Instrument Diagrams (P & ID’s)
(7)
Safety Analysis Function Evaluation (SAFE) Charts
(8)
Pressure Relief and Depressurization Systems
(9)
Flare and Vent Systems
(10)
Spill Containment, Closed and Open Drain Systems
(11)
Process Equipment Documentation
(12)
Process Piping Systems
(13)
Sub-sea Production Systems
(14)
Packaged Process Units
7.3.1.2 Process Support Systems (1)
Piping and Instrument Diagrams (P&IDs) for each system
(2)
Equipment Documentation
(3)
Process Support Piping Specifications
(4)
Internal-Combustion Engines and Turbines
(5)
Cranes 265
TCVN 6474-9 : 2007 7.3.1.3 Marine Support Systems (1)
See requirements in 2.8
7.3.1.4 Electrical Installations (1)
Electrical One-line Diagrams
(2)
Short-Circuit Current Calculations
(3)
Coordination Study
(4)
Specifications and Data Sheets for Generators and Motors and Distribution Transformers
(5)
Details of Storage Batteries
(6)
Details of Emergency Power Source
(7)
Standard Details of Wiring Cable and Conduit Iinstallation Practices
(8)
Switchboard and Distribution Panel
(9)
Panelboard
(10)
Installations in Classified Areas
7.3.1.5 Instrumentation and Control Systems (1)
General Arrangements
(2)
Data Sheet
(3)
Schematic Drawings-Electrical Systems
(4)
Schematic Drawings-Hydraulic and Pneumatic Systems
(5)
Programmable Electronic Systems
7.3.1.6 Fire Protection and Personnel Safety
266
(1)
Firewater System
(2)
Water Spray (Deluge) Systems for Process Equipment
(3)
Foam Systems for Crude Storage Tanks
(4)
Fixed Fire Extinguishing Systems
(5)
Paint Lockers and Flammable Material Storerooms
(6)
Emergency Control Stations
(7)
Portable and Semi-Portable Extinguishers
(8)
Fire and Gas Detection and Alarm Systems
TCVN 6474-9 : 2007 (9)
Fire and Gas Cause and Effect Chart
(10)
Structural Fire Protection (which indicates classification of all bulkheads for: quarters section, machinery spaces and processing facilities)
(11)
HVAC plan (including AHU location, duct layout, duct construction and bulkhead penetration details
(12)
Joiner detail arrangement and structural fire protection material certification
(13)
Guard Rails
(14)
Escape Routes (may be included on the fire control plan or separate plan)
(15)
Lifesaving Appliances and Equipment Plan (escape routes must be indicated)
(16)
Insulation of Hot Surfaces
7.3.1.7 Specific Arrangements (1)
Arrangements for Storage Tank Venting and Inerting
(2)
Arrangements for Use of Produced Gas as Fuel
7.3.1.8 Start-up and Commissioning Manual 7.3.2
Details All sizes, dimensions, welding and other details, make and size of standard approved equipment are to be shown on the plans as clearly and completely as possible.
7.3.3
Hydrocarbon Production and Process Systems
7.3.3.1 Project specification Submit project specification covering a brief description of field location, environmental conditions, well shut-in pressure, well fluid properties, production plans, oil/gas storage and transportation arrangements. 7.3.3.2 Process flow sheet Submit process flow sheets identifying each process stream, process equipment component, planned addition and symbols used . 7.3.3.3 Heat and mass balance Submit heat and mass balance specification, including flow rate, composition, and conditions (temperature, pressure, and vapor/liquid ratio) for each process stream under normal operating and expected extreme conditions.
267
TCVN 6474-9 : 2007 7.3.3.4 Equipment layout drawing Submit plans showing arrangements and locations of living quarters and control rooms, including entrances and exits; openings to these spaces; layout of machinery, process equipment, crude storage, fire wall, ESD station, location of fire protection equipments and escape route for decks. 7.3.3.5 Area classification and ventilation drawing Submit plans showing degree and extent of all Class I and the arrangements for ventilation of enclosed spaces . 7.3.3.6 Piping and Instrument Diagrams (P&ID's) Submit P & ID’s showing size, design, and operating conditions of each major process component, piping and valve designation and size, sensing and control instrumentation, shutdown and pressure relief devices with set points, signal circuits, set points for controllers, continuity of all line pipes, and boundaries of skid units and process packages. 7.3.3.7 Safety Analysis Function Evaluation (S.A.F.E.) Charts List all process components and emergency support systems with their required devices, and the functions to be performed by each sensing device, shutdown valve, and shutdown device. 7.3.3.8 Pressure relief and depressurization systems Submit sizes, arrangements, materials, and design calculations for relief valves and depressurization systems. 7.3.3.9 Flare and vent systems Submit sizes and arrangements, including details of flare tips, pilots, ignition system, water seals and gas purging systems, and provide design calculations for blow down rates, knockout drum sizing, flare and vent sizing, radiant heat intensities, and gas dispersion analysis including basis of analysis. 7.3.3.10Spill containment, closed and open drain systems Submit arrangements for spill containment, details of piping connections to all process components, and slope of drains. 7.3.3.11Process Equipment Documentation
268
TCVN 6474-9 : 2007 Submit specification, data sheet, standard of construction and testing, and general arrangement plans for Christmas tree assemblies (optional), pumps, and compressors. Submit complete design specification, including all design data such as pressure, temperature, corrosion allowances, service, external loads etc., dimensional drawings covering arrangements and details, material specification, weld details, extent of nondestructive testing, test pressure, and design calculations for verification of compliance to a recognized standard for process vessels, storage tanks, heat exchangers, fired heaters, manifolds and scraper launchers/receivers. 7.3.3.12Process Piping Specifications Submit line list with design conditions, pipe and fitting material lists, specifications, sizes, pressure ratings, and calculations for pipe wall thickness. 7.3.3.13Subsea Production Systems Provide stress calculations for structural components, P & ID’s, S.A.F.E. Charts, equipment specifications and data sheets, control schematics, assembly drawings, and installation and operation procedures. 7.3.3.14Packaged Process Units Packaged process units include, but are not limited to, the following: dehydration, sweetening, stabilizing, vapor recovery, and gas compression for fuel or re-injection. Documentation requirements for packaged process units include: Skid arrangements, P & ID’s, S.A.F.E. charts, Process equipment and piping system documentation, Electrical one-line diagrams, Specifications and data sheets, Structural design calculations for skid units in dry condition with a center of gravity height of more than 1.5 m , or a maximum operating weight in excess of 10 MT (metric tons). 7.3.4
Process Support Systems
7.3.4.1 A typical list of process support systems includes, but is not limited to, the following:: (1)
Utility/Instrument Air System
(2)
Fuel/Instrument Gas System
(3)
Purging System
(4)
Use of Produced Gas as Fuel
269
TCVN 6474-9 : 2007 (5)
Fuel Oil System
(6)
Hydraulic System
(7)
Chemical Injection System
(8)
Material Handling System (Cranes)
(9)
Platform Drilling Systems
(10)
Heating & Cooling Systems
7.3.4.2 Piping and Instrument Diagrams (P & ID's) As required in 7.3.3 7.3.4.3 Equipment Documentation Submit specifications, data sheets, and drawings for each equipment component such as pressure vessels, heat exchangers, pumps and compressors. Details as per 7.3.3. 7.3.4.4 Piping Specifications Submit specifications, materials, sizes, and pressure ratings for all pipes, valves and fittings, and calculations for pipe wall thickness. 7.3.4.5 Internal-Combustion Engines and Turbines Submit specifications for internal-combustion engines and turbines, including types, horsepower, revolutions per minute, shutdown arrangements, and manufacturer’s affidavit verifying compliance with recognized standards. 7.3.4.6 Cranes Submit specifications for cranes, including structural design calculations, load rating chart, and test certificates for wire rope. 7.3.5
Marine Support Systems Marine support systems include, but are not limited to, the following: (1)
Boilers and Pressure Vessels
(2)
Turbines and Gears
(3)
Internal-Combustion Engines
(4)
Pumps and Piping Systems (i.e. Fuel Oil, Lube Oil, Fresh Water, Ballast Control, Cargo, Inert Gas, etc.)
(5) 270
Propellers and Propulsion Shafting
TCVN 6474-9 : 2007 (6)
Steering Gears
Documentation is to be summited in accordance with Part 1. 7.3.6
Electrical Systems
7.3.6.1 Electrical One-Line Diagrams Indicate the ratings of generators, transformers, motors, and other loads; rated load current of each branch circuit; type and size and temperature rating of cables; rating or settings of circuit breakers, fuses, and switches; interrupting capacity of switchgear, motor control centers, and distribution panels.. 7.3.6.2 Short-circuit Current Calculations To establish that the protective devices have sufficient short-circuit breaking and making capacities, data is to be submitted giving the maximum calculated shortcircuit current in symmetrical r.m.s. and a symmetrical peak values available at the main bus bars, along with the maximum allowable breaking and making capacities of the protective device. Similar calculations are to be made at other points in the distribution system where necessary, to determine the adequacy of the interrupting capacities of protective devices. 7.3.6.3 Coordination study A protective device coordination study is to be submitted. 7.3.6.4 Specifications and Data Sheets for Generators and Motors For generators and motors of 100 kW (134 hp) and over, submit drawings showing assembly, seating arrangements, terminal arrangements, shafts, coupling, coupling bolts, stator and rotor details together with data for complete rating, class of insulation, designed ambient temperature, temperature rise, weights and speeds for rotating parts. For generators and motors under 100 kW (134 hp), submit nameplate data along with degree of enclosure 7.3.6.5 Details of Storage Batteries Submit arrangement, ventilation, corrosion protection, types and capacities, conductors and charging facilities, over-current and reverse current protection. 7.3.6.6 Details of Emergency Power Source
271
TCVN 6474-9 : 2007 Submit location, arrangement, and services required to maintain the integrity of the facility in the event of primary power loss.. 7.3.6.7 Standard Details of Wiring Cable A booklet on the standard wiring practices and details is to be submitted. The booklet is to include such items as cable supports, earthing details, bulkhead and deck penetrations, cable joints and sealing, cable splicing, watertight and explosion-proof connections to equipment, earthing and bonding connections, etc.. 7.3.6.8 Switchboard, Distribution Boards and Motor Control Centers (1)
A front outline of the switchboard, including overall dimensions, front view indicating instrumentation, circuit breakers, switches, drip-shields, hand-rail and securing supporting details.
(2)
Complete list of materials, including manufacturer’s name, model number, rating, size, type, testing laboratory’s listing number (if any), or indication of construction standard for components such as: switchboard enclosure, circuit breakers, all types of fuses, power and control wiring, bus bars, connectors and terminals and power switches.
(3)
Bracing arrangements and calculations to determine that bus bars and short runs of power cables are adequately braced to withstand the mechanical forces that the switchboard may be subjected to under fault conditions.
(4)
A complete wiring schematic, including type of wiring, size, and setting of protective devices.
(5)
One line schematic of the bus bars, indicating rating for each of the horizontal and vertical buses, the exact connection of circuit breakers to the bus bars, setting of the power circuit breakers and loads ampacities and power cable sizes, if available.
(6)
Actual bus bar arrangement of the horizontal, vertical, and ground buses, including bus bar material, size and rating, separation distances between bus bars, and between bus bars and bare metal parts.
272
(7)
Results/ data of tests
(8)
Grounding details
(9)
If applicable, details of metal barriers provided to isolate bus bars, wiring, and
TCVN 6474-9 : 2007 associated components. 7.3.6.9 Panel board The information as requested in 7.2.6.8 , as applicable 7.3.6.10Installations in Classified Areas List of electrical equipment installed in classified areas, together with documentation issued by an independent testing laboratory certifying suitability of same for intended services. 7.3.7
Instrumentation and Control Systems
7.3.7.1 General Arrangements Submit layout plans for local controllers, central controllers, displays, printers, and other instrumentation and control devices. 7.3.7.2 Instrumentation List Submit a list of instrumentation and control equipment, including a list of monitoring, control, and alarm set points and ranges.. 7.3.7.3 Schematic Drawings – Electrical Systems Include types and sizes of electrical cables and wiring, voltage rating, service voltage and current, overload and short-circuit protection for the following systems: (1)
Process control panels
(2)
Emergency shutdown (ESD) panels
(3)
Intrinsically safe systems
(4)
Fire and gas detection and alarm panels
(5)
Fire alarm circuits
(6)
Emergency generator or fire pump drive starting circuit
7.3.7.4 Schematic Drawings – Hydraulic and Pneumatic Systems Submit system description of hydraulic and pneumatic control systems, including pipe sizes and materials, pressure ratings, and relief valve settings.. 7.3.7.5 Programmable Electronic Systems Submit
the
control
philosophy,
schematic
alarm,
monitoring
and
control
arrangements, and redundancy arrangements. Provide failure modes of the system components. 273
TCVN 6474-9 : 2007
7.3.8
Fire Protection and Personnel Safety
7.3.8.1 Firewater System Submit plans indicating pump and piping arrangements, location of isolation valves, locations of firewater stations, details of fire pumps including pump drivers, pump capacity and pressure, and hydraulic calculations for sizing of fire pump capacity and fire main.. 7.3.8.2 Deluge Systems (Water Spray for Process Equipment) Submit plans showing the arrangement for firewater piping and spraying nozzles, as well as detailed hydraulic calculations.. 7.3.8.3 Foam Systems (for Crude Storage Tanks) Indicate the arrangement for firewater supply, foam supply and delivery, type of foam and expansion ratio, as well as capacity calculations for areas protected. 7.3.8.4 Fixed Fire Extinguishing Systems Submit plans showing the arrangement for piping, spraying nozzles, and storage of the extinguishing medium, and details of control and alarm for release of the extinguishing medium, as well as capacity calculations and discharge time calculations for areas protected. 7.3.8.5 Paint Lockers and Flammable Material Storerooms Submit plans and calculations showing details of fixed fire extinguishing systems for the paint lockers and flammable material storerooms. 7.3.8.6 Fire Control and Life Saving Equipment Plan Submit a fire control and life saving equipment plan for the process area. A fire control plan and life saving equipment plan for a process area is to include the following: (1)
Portable and Semi-Portable Extinguishers The plan is to show types, quantities and locations of portable and semi portable extinguishers for the production facility.
(2)
Fixed Fire Detection, Alarm and Extinguishing Systems The plan is to show locations, controls, protected spaces/areas and types of
274
TCVN 6474-9 : 2007 extinguishing system. (3)
Emergency Control Stations The plan is to show location and equipment.
(4)
Lifesaving Appliances and Equipment The plan is to show type, capacity, quantity and location.
(5)
Structural Fire Protection The plan is to show arrangements, locations, and types of firewalls for buildings and bulkheads installed in or adjacent to the process area.
(6)
Guard Rails and Escape Routes The plan is to show arrangement of protective guardrails, toe plates, and means of escape from normally manned spaces.
7.3.8.7 Fire and Gas Detection and Alarm Systems Indicate the locations and details of power supplies, sensors, annunciation and indicating equipment, set points of alarm systems, and data sheets for detectors. 7.3.8.8 Fire and Gas Cause and Effect Chart Relate all fire and gas sensors to shutdowns, operation of fixed systems and fire control plans. 7.3.8.9 Insulation of Hot Surfaces Submit details of insulation and shielding provided for personnel safety and fire protection. 7.3.9
Arrangements for Storage Tank Venting and Inerting Submit piping and control arrangements for storage tank venting and inerting systems
7.3.10
Arrangements for Use of Produced Gas as Fuel Submit piping and control arrangements for use of produced gas as fuel, showing details of double wall or ducting arrangements for the pipe runs in way of the safe space.
7.3.11
Start-up and Commissioning Manual The manual is to be submitted for review as early as possible, prior to the commissioning of the installation. 275
TCVN 6474-9 : 2007
7.4 Hydrocarbon Production and Process Systems
7.4.1
General
7.4.1.1 This section defines the minimum criteria applicable to equipment and systems for handling and processing produced fluids from completed wells.. 7.4.1.2 Process Safety Criterion The process safety overall criterion is that hydrocarbon production and processing systems be designed to minimize the risk of hazards to personnel, property and environment. Implementation of this criterion to production systems and associated facilities design is intended to:
7.4.2
(1)
Prevent an abnormal condition from causing an upset condition
(2)
Prevent an upset condition from causing a release of hydrocarbons
(3)
Safely collect and dispose of hydrocarbon gasses and vapors released
(4)
Prevent formation of explosive mixtures
(5)
Prevent ignition of flammable liquids or gases and vapors released
(6)
Limit exposure of personnel to fire hazards.
Process Design
7.4.2.1 Design Basis Production process design is to be based on production plans, expected well fluid properties, required pipeline or product custody transfer specifications, and other considerations. The floating processing drainage, production water discharge and displacement water discharge are to be in accordance with Vietnamese Regulations. 7.4.2.2 Process Design Conditions Process design conditions specified for equipment and systems are to include provision for handling short term and transient conditions, such as pipeline-riser slugging, cyclic pump operation, or pressure spikes, and to meet the required product specifications. Due consideration is to be given to the well fluid properties, such as presence of hydrogen sulfide (H2S), carbon dioxide (CO2), etc., for selection of materials. Design, procurement, and fabrication of equipment and equipment components that 276
TCVN 6474-9 : 2007 may be exposed to hydrogen sulfide under conditions conducive to Sulfide Stress Cracking is to be complied with recognized standards. Each process component or piping element is to be designed for the maximum extremes of pressure, temperature, and corrosive properties of the fluid, which it can encounter in service. 7.4.2.3 Process Flow Sheets Process flow sheets are to indicate all process components with associated piping systems, and define operating conditions for each component. Each flow stream is to be labeled by composition, flowrate, phase, pressure, and temperature. 7.4.3
Facility Layout
7.4.3.1 General Arrangement Machinery and equipment are to be arranged in groups or areas in accordance with recognized standard (refer to API RP14J). Equipment items that could become fuel sources in the event of a fire are to be separated from potential ignition sources by space separation, firewalls or protective walls. typical fuel and ignition sources are listed below: Fuel source:
•
Wellheads and Manifolds
•
Process Piping
•
Separators and Scrubbers
•
Risers and Pipelines
•
Coalesces
•
Vents
•
Gas Compressors
•
Pig Launchers and Receivers
•
Liquid Hydrocarbon Pumps
•
Drains
•
Heat Exchangers
•
Portable Fuel Tanks 277
TCVN 6474-9 : 2007
•
Hydrocarbon Storage Tanks
•
Chemical Storage Tanks
•
Gas Metering Equipment
•
Laboratory Gas Bottles
•
Oil Treaters (unfired vessels)
•
Sample Pots
Ignition source:
•
Fired Vessels
•
Electrical Equipment
•
Combustion Engines & Gas Turbines
•
Waste Heat Recovery Equipment
•
Living Quarters
•
Mobile phones
•
Flares Lightning
•
Welding Machines
•
Spark Producing Hand Tools
•
Grinding Machines
•
Portable Computers
•
Cutting Machinery or Torches
•
Cameras
• •
Static Electricity Non-Intrinsically Safe Flashlights
In case of a fire onboard a subject unit, the means of escape is to permit the safe evacuation of all occupants to a safe area, even when the structure they occupy can be considered lost in a conflagration.. With safety spacing, protective firewalls and equipment groupings, a possible fire from a classified location is not to impede the safe exit of personnel from the danger source to the lifeboat embarkation zone or any place of refuge.. 278
TCVN 6474-9 : 2007 7.4.3.2 Accommodation Spaces (Living Quarters) Accommodation spaces or living quarters are to be located outside of hazardous areas and may not be located above or below crude oil storage tanks or process areas. “H-60” ratings are required for the bulkheads of permanent living quarters, temporary living quarters and normally manned modules that face areas such as wellheads, oil storage tanks, fired vessels (heaters), crude oil processing vessels, and other similar hazards. If such bulkhead is more than 33 m (100 ft) from this source, then this can be relaxed to an “H-0” rating. “A-60” and “A” rated bulkheads, respectively, may be utilized provided that a risk or fire load analysis was done and reviewed by VR , indicating that these bulkheads are acceptable. 7.4.3.3 Wellhead Areas Wellhead areas are to be separated or protected from sources of ignition and mechanical damage. A-0 firewalls around wellheads are to be used to provide protection from potential uncontrolled flow from wellheads with shut-in pressures 2
exceeding 42 kg/cm (600 psig). 7.4.3.4 Storage Tanks and Slop Tanks Supported storage tanks for crude oil or other flammable liquids are to be located as far as possible from wellheads. In addition, they are to be located far from potential ignition sources such as gas and diesel engines, fired vessels, and buildings designated as unclassified areas, or areas used as workshops, or welding locations. For crude storage tanks, slop tanks, and low flash point flammable liquid storage o
tanks (flash point of 60 C or less), such as methanol storage tanks built as hull or integral tanks, are to be separated from machinery spaces, service spaces, and other similar source of ignition spaces by cofferdams of at least 0.76 m (30 in.) wide. Pump rooms, ballast tanks and fuel oil tanks may be considered cofferdams for this purpose 7.4.3.5 Fired Vessels Fired vessels, such as glycol reboilers, hot oil heaters, etc., are considered ignition sources. They are to be installed away from wellheads and other unfired hydrocarbon processing and storage equipment. Occasionally, it may not be possible to observe the above requirement, particularly when the space of the process area is limited, 279
TCVN 6474-9 : 2007 causing fired vessels to be located in the unfired process areas. In this case, the fired vessel is to be surrounded on all sides, except on the outboard side of the unit mounted on the perimeter of a platform or FPSO, by a minimum of A-0 rated firewall. For equipment such as the direct fired (crude oil) treater that is considered both a fuel and ignition source, a minimum of A-0 rated firewall is to be provided as described above, regardless of where the unit is installed (Fired or Unfired Process Areas).. 7.4.3.6 Structural Considerations for Process Deck Structure that supports production facilities or forms an integral part of the equipment is to be designed to a recognized standard. Plans and calculations are to be provided for verification. Process liquid weights and dynamic loads due to vessel motions are to be considered. If the vessel hull girder deflection has significant effects on the structure, this is to be taken into account in the design. 7.4.4
Piping and Instrumentation Design
7.4.4.1 Process Control System Essential process parameters (such as flow rate, pressure, temperature and liquid level) are to be automatically monitored and controlled, and the abnormal conditions are to be alarmed with visual and audible devices. The process control system used to maintain process variables within normal operating ranges is to be capable of accommodating a reasonable range of abnormal or transient conditions without creating an upset condition. 7.4.4.2 Safety System A safety system is to be provided in accordance with recognized standards approved by VR (refer to the recommended practices of API RP14C). Essential elements of the system are to include: (1)
Safety Sensing and Self-acting Devices The safety system is to provide two levels of protection (primary and secondary), with sensing and self-acting devices, which are functionally different types of devices. They are to be in addition to process control devices used to maintain normal process parameters. The safety system is to sense process variables. It reacts to a condition outside acceptable limits by
280
TCVN 6474-9 : 2007 automatically activating an alarm and initiating the necessary protective response. Pressure vessels, for example, are generally fitted with pressure control valves to protect against overpressure. Nevertheless, they are to be fitted with a safety system device such as Pressure Safety High (PSH) (primary) and a Pressure Safety Valve (PSV) (secondary). Loss of any single control or safety system component is not to cause an unsafe condition. (2)
Fire Detection A fusible plug system, or other means of automatically detecting fire, is to provide a shutdown signal for production facilities.
(3)
Gas Detection Combustible and hydrogen sulfide gas detectors are to be provided to initiate alarms and shutdowns.
(4)
Process Emergency Shutdowns (ESD) An emergency shutdown (ESD) system with manual stations is to be provided to shut down the flow of hydrocarbon from all wells and pipelines, and to terminate all production and injection activities of the facility. The emergency shutdown system is to be automatically activated by: (a)
The detection of an abnormal operating condition by flowline pressure sensors and sensors on any downstream component through which the pipeline fluids flow;
(b)
The detection of fire in the wellhead and process areas;
(c)
The detection of combustible gas at a 60% level of the lower explosive limit;
(d)
The detection of hydrogen sulfide (H2S) gas at a level of 50 ppm. Emergency Shutdown (ESD) valves for flowlines and pipelines are to be located as far away from the facility as practical.
(5)
Safety Analysis Safety Analysis Tables (SAT) and Safety Analysis Checklists (SAC) are to 281
TCVN 6474-9 : 2007 beused to verify that the safety devices provided to protect each process component and piping segment are adequate. Safety Analysis Function Evaluation (SAFE) Charts are to be prepared to show the integration of all safety devices and self-protected equipment into a complete facility safety system. 7.4.5
Emergency Shutdown (ESD) Stations Emergency shutdown stations are to be provided for manual activation of the Process Safety Shutdown system for shutdown of all wells and process systems. These manual activation stations are to be protected against accidental activation, and conveniently located at the primary evacuation points (i.e., boat landing, helicopter deck, etc.) and the emergency control stations . The following additional locations may be considered appropriate for emergency shutdown stations:
7.4.6
(1)
Exit stairway at each deck level
(2)
Main exits of living quarters
(3)
Main exits of production (process) facility deck
Pressure Relieving and Hydrocarbon Disposal Systems
7.4.6.1 Pressure Relief Systems (1)
Pressure Relief Valves Pressure relief valves are to be installed to protect all vessels and pressurerated equipment from overpressurization. Pressure relief valves are to be sized and installed in accordance with recognized standard approved by VR (Refer to API RP 520 and ASME Code) If block valves are installed in the relieving lines, means are to be provided to ensure that pressure relief valves are not isolated from the protected equipment. The practice of locking open block valves to eliminate the need for higher design pressures or additional relief protection is allowed if: (a)
closure of the valve would not result in the pressure rising more than 1.5 times the design pressure of the equipment or component under consideration, or
(b) 282
can be otherwise demonstrated that the proposed installation is safe and
TCVN 6474-9 : 2007 would not, in any circumstance, either planned or unplanned, inadvertent or intentional, result in a risk to personnel or facilities. (2)
Pressure Relief Valves for Gas Service Pressure relief valves in hydrocarbon gas service are to discharge to one or more closed relief headers for atmospheric discharge at either a flare or vent. Such flare or vent discharges are to meet the requirements of 7.4.6.3. Pressure relief headers are to be sized to handle the maximum anticipated discharges that could occur at any time. Relief header sizing is to be sufficient so that excessive backpressure does not develop, which may prevent any pressure relief valve from relieving at its design rate. Where necessary, separate high and low pressure relief headers are to be employed to meet this requirement.
(3)
Pressure Relief Valves for Liquid Service Pressure relief valves in liquid hydrocarbon service are to discharge to a lower pressure system such as a tank, pump suction, sump vessel, or closed drain system. Discharges to drip pans or other open drains are to be limited to small volume thermal releases.
(4)
Vapor Depressurizing An emergency vapor depressurizing system is to be provided for all equipment processing light hydrocarbon with operating pressures of 17.5 2
kg/cm (250 psig) and above. To gain rapid control of a situation in which the source of a fire is the leakage of flammable fluids from the equipment to be 2
depressurized, the equipment is to be depressurized to 7 kg/cm (100 psig). In cases where the equipment is handling high pressure and large inventories of hydrocarbon, and depressurizing to 100 psig is impractical, it is acceptable to depressurize to 50% of the equipment design pressure if such depressurization is achieved within 15 minutes. This is provided the equipment has been designed with ample margin of safety to prevent the vessel from failing due to overheating. Calculations, showing the maximum allowable temperature of the equipment would not exceed the equipment rated temperature, are to be submitted for verification. 283
TCVN 6474-9 : 2007 7.4.6.2 Pressure/Vacuum Venting System All atmospheric and low pressure storage tanks and similar components, such as flotation cells and atmospheric corrugated plate interception (CPI) separators, are to be provided with pressure and vacuum relief protection where required. Vent lines are to be routed to an atmospheric vent header, or to individual vents. 7.4.6.3 Flares and Vents (1)
Location Flares and vents for hydrocarbon gas disposal are to be located with respect to prevailing winds. This is to limit exposure of personnel, equipment and helicopter traffic to vented gas, flare exhaust, or flame radiation
(2)
Atmospheric Conditions Reasonable worst-case atmospheric conditions are to be used for radiation and gas dispersion calculations. Hence, flame radiation calculations are normally to assume a strong wind (32.2 km per hour (20 miles per hour), or worst-case scenario based on the project specification) distorting the flame pattern toward the facilities. Dispersion calculations are normally to assume still air and low vent velocity as a worst-case condition.
(3)
Heat Radiation from Elevated Flares The calculated radiant heat intensity from flaring (including solar radiation), at any deck level or location where normal maintenance or operating activity could take place, is not to exceed allowable limit. Allowable limit is given in recognized
standard
approved
by
VR
(Refer
to
API
RP
521
recommendations). The flare evaluation or analysis may be based on recognized industrial method (Refer to API RP 521 ) (4)
Atmospheric Discharge For hydrocarbon vapor disposal by atmospheric dispersion from a vent stack, the vent outlet is to be of sufficient height or distance from the facilities to accomplish the following: (a)
The calculated radiant heat intensity (including solar radiation) in case 2
of accidental ignition is not to exceed 4.73 kW/m at the maximum 284
TCVN 6474-9 : 2007 venting rate, at any deck level or location where normal maintenance or operating activity could take place. (b)
The following concentration of hazardous vapors, calculated per recognized standards, is not to be exceeded at any deck level where normal maintenance or operating activity could take place, based on the reasonable worst-case conditions (e.g., still air and low vent velocity). H2S: 10 ppm Combustible Vapors: 20% LEL
(c) The vent outlet is to be at least 8 m (25 ft) above any immediately adjacent process vessel or hydrocarbon processing equipment, and at least 3 m above the top of any vessel or equipment within an 8 m radius of the vent. (d) When a short vent stack is used in lieu of a vent boom arrangement as , the vent outlet is to be provided with devices to prevent the passage of flame into the system. The pressure drop of the flame arrestor is to be considered in the vent diameter sizing calculations. (5)
Fire Extinguishing Systems for Atmospheric Vent When a venting system is selected for disposal of hydrocarbon vapors, a vent snuffing system is to be provided to extinguish vented gases, should they ignite.
(6)
Ground Flares Ground flares may be used in place of the high stack flare. Ground flares are to be provided with automatic controls which will divert the flow of flare gas to a vent stack upon detection of flame failure, unless gas dispersion calculations show that the vapor concentrations do not exceed
specified
value. Draining connections are to be provided, to remove accumulated condensate or water to the open drain system. (7)
Flashback Protection Burn-back and flashback protection for flares is to be provided by sufficient purge gas rate maintained from a reliable source, or by a seal drum to prevent air intrusion. The purge gas source is to have sufficient gas supply for 285
TCVN 6474-9 : 2007 continuous purging during production shutdown, or for a complete purging of the flare system before re-ignition of the flare. The sizing of a seal drum is to be in accordance with recognized standard (8)
Flare Ignition The flare system is to be provided with means for purging sufficiently (below 5 percent of oxygen content) before ignition to prevent explosion inside the flare system.
7.4.7
Spill Containment, Open and Closed Drain Systems
7.4.7.1 Spill Containment Spill containment is to be provided in areas subject to hydrocarbon liquid or chemical spills, such as areas around process vessels and storage tanks with drain or sample connections, pumps, compressors, engines, glycol systems, oil metering units, and chemical storage and dispensing areas. Spill containment is to utilize curbing or drip edges at deck level, recessed drip pans, containment by floor gutters, firewalls or protective walls, or equivalent means to prevent spread of discharged liquids to other areas and spillover to lower levels. A minimum of 150 mm (6 in.) coaming is to be provided. A spill containment with less than 150 mm (6 in) coaming arrangement is subject to special consideration. Calculations showing sufficient spillage containment for the skid are to be submitted for verification 7.4.7.2 Open Drain Piping Each containment area, as well as any other plated deck or skid area subject to rainwater or other liquid accumulation, is to be equipped with drains connected to an open drain system, and installed and located so as to prevent the accumulation of standing liquid. Open drain piping is to be self-draining with a slope of not less than 1:100. Lines are to be sized for gravity drainage without backup or overflow, based on a full drainage rate from any single source, with consideration given to the maximum rainfall condition. Cleanouts or flushing connections are to be provided for removal of sediment or solids from open drains subject to potential blockage. 286
TCVN 6474-9 : 2007 Open drains are to be piped individually or collected in one or more piping systems, which are to convey the fluids, by gravity or pumping, to oily water treatment or final disposal location. 7.4.7.3 Sealing of Open Drains (1)
General Piping drain traps, floor drains with integral drain seal, submerged open-ended pipes, or other means of utilizing liquid head, are to be provided to prevent vapor release from the sump or drain vessel to atmosphere
(2)
Drain Seals Where flammable liquids (diesel fuel, tube oil, glycol, crude oil, etc.) could be present in an open drain system, a seal is to be provided at each open drain location. This is to prevent flammable vapors evolving from the liquids in the drain system from being released to atmosphere. Each such seal is to have a minimum effective water seal height of 3.8 cm (1.5 in.).
(3)
Pressure Seals Where an open drain system is subject to an applied pressure, such as pad gas on the sump or drain vessel which receives the open drainage, a liquid seal is to be provided on each drain header or drain line connected to the source of pressure. Minimum effective liquid seal height is to be 150 mm (6 in), or 80 mm (3 in) over the pad gas pressure, whichever is greater.
7.4.7.4 Segregation of Open Drain Systems Drains from classified and unclassified areas are to be separate. When this requirement cannot be met, drains from classified and unclassified areas or between different zone areas are to be connected or led to a drain tank in a hazardous area. The following requirements are applicable: (1)
Non-hazardous area drain header is to be equipped with a stop check valve at the safe area bulkhead, together with a loop seal with a leg length of at least 762 mm (30 in) installed before the inlet to the drain tank. The loop seal is to be so installed as to prevent freezing. Where drainage arrangement is such that the drain header from the classified areas are physically located lower than the 287
TCVN 6474-9 : 2007 unclassified areas, and there is no possibility of back flow into the safe areas, the check valve may not be needed. (2)
Drain outlets within the tank are to discharge against the tank side.
(3)
Vent outlets from the subject drain tank are to be led to the main deck, be equipped with a flame screen, and treated as zone 1 and/or 2, as applicable.
When pumping systems are used to remove liquids from hazardous areas or from drain tanks mentioned above, branch suctions from safe and hazardous areas are to be arranged so that such areas cannot be pumped simultaneously. 7.4.7.5 Closed Drain Systems (1)
General Drains or liquid relief from process vessels, piping or other sources that could exceed atmospheric pressure are to be hard piped without an atmospheric break to a drain vessel. The drain vessel is to be provided with pressure relief valve(s), which are to be sized to handle the maximum flow of gas or liquid that could occur under blocked outlet condition.
(2)
Connection to Open Drain System Drains or liquid relief from vessels containing non-toxic, non-flammable liquids, may be connected to an unclassified open drain piping system if the open drain system is sized to accommodate these additional drains.
7.4.7.6 Overboard Discharges from the Production Treatment Plan The Overboard Discharges from the Production Treatment Plan is to conform to the existing Vietnamese regulations and National/Regional Regulations, where FPSO is operated. 7.4.8
Protection from Ignition by Static Charge For specific requirements on protection from ignition due to static electric discharge, refer to 7.5
7.4.9
Major Equipment Requirements
7.4.9.1 Process Vessels (1)
General Pressure vessels are to be designed, constructed, and tested in accordance with
288
TCVN 6474-9 : 2007 the recognized standard approved by VR (refer to ASME). All process vessels are to be suitably supported and properly secured. (2)
Materials Low melting point or brittle materials such as cast iron, aluminum, brass, copper, or fiberglass, are not to be utilized in pressure retaining parts of vessels containing flammable or toxic fluids..
(3)
Thermal Considerations Supports and insulation of vessels subject to change in temperature are to be designed to accommodate the resulting thermal movement.
(4)
Design Load The design is also to ensure that stresses due to external nozzle loads and moments, stresses due to acceleration forces arising out of the motion of the floating installation, and stresses due to any other applicable external forces, such as wind, are within the limits allowed by the rules.
7.4.9.2 Process Heat Exchangers (1)
General 2
Process heat exchangers with a design pressure in excess of 1.05 kg/cm (15 psig) and handling flammable fluids are subject to the requirements of 7.4.9.1 and the following applicable requirements: (2)
Shell and Tube Heat Exchangers Process heat exchangers of tubular design are to conform to recognized standards (Refer to ASME)
(3)
Plate and Frame Exchangers Plate and frame exchangers may be employed for handling flammable liquid, with the following restrictions: (a)
Safety or protective devices are to be provided .
(b)
Each exchanger is to be provided with an exchanger enclosure, protective wall, shield or similar barrier, capable of containing spray in case of gasket leakage during operation.
(c)
Each exchanger is to be provided with spill containment and drain 289
TCVN 6474-9 : 2007 capable of handling a liquid release of at least 10% of the maximum flammable stream flowrate. (4)
Air Cooled Heat Exchangers Air-cooled heat exchangers are to comply with recognized standards (refer to API Std. 661)
(5)
Design Load The design is to ensure that stresses due to external nozzle loads and moments, stresses due to acceleration forces arising out of the motion of the floating installation, and stresses due to any other applicable external forces such as wind, are within the limits allowed by the Rules.
7.4.9.3 Process Electric Heater (1)
General Process electric heater shells with a shell operating pressure greater than 1.05 2
kg/cm (15psig) are to be designed and constructed in accordance with recognized standards (refer to ASME Code). (2)
Over Temperature Protection Process electric heaters in hydrocarbon service are to be provided with heater element skin high temperature alarms.
(3)
Overpressure Protection Where the vessel, tank or piping segment containing an electric heater can be isolated, a relief valve is to be provided for overpressure protection.
(4)
Low Level, Low Flow or High Temperature Protection Process electric heaters in liquid service are to be protected by low level, low flow, or high liquid temperature sensor to shut off electrical input.
(5)
Design Load The design is to ensure that stresses due to external nozzle loads and moments, stresses due to acceleration forces arising out of the motion of the floating installation, and stresses due to any other applicable external forces, such as wind, are within the limits allowed by the Rules.
7.4.9.4 Fired Vessels 290
TCVN 6474-9 : 2007 (1)
General All fire-tube type fired vessels, with a shell operating pressure greater than 2
1.05 kg/cm (15psig), are to be designed in accordance with recognized standard (refer to ASME Code). Fired vessel (heater) shells, (heater) coils or other components designed in accordance with ASME Code, are to conform to all applicable requirements of 7.4.9.1. (2)
Indirect Fired Vessels Indirect fired water bath heaters with working pressures lower than 1.05 2
kg/cm (15 psig) are to be designed and fabricated in accordance with recognized standards (refer to API Spec. 12K). (3)
Direct Fired Vessels Direct fired vertical or horizontal emulsion treaters are to be designed and constructed in accordance with recognized standards (refer to API Spec. 12L).
(4)
Ignition Control Where burner ignition or light-off is part of an automatic sequence, the following control functions are to be provided: (a)
Automatic timed purge interval prior to admitting pilot fuel. Purge may be by fan if so equipped, or by time delay to allow natural draft purge.
(b)
Firing limit on a trial for ignition (15 seconds maximum) on each attempted pilot light-off.
(c) (5)
Confirmation of pilot lighting prior to admitting main burner fuel.
Manual Light-off Each burner designed for manual light-off of the pilot is to be designed to allow an operator to light the pilot from a location which limits his exposure to flame flashback, should it occur. Burners are to be equipped with a sightglass suitable for verifying pilot light-off and for viewing of main flame.
(6)
Combustion Combustion air intakes for fired vessels are to be located in, or ducted from, a safe area.
(7)
Fired Vessel (Heater) Arrangement 291
TCVN 6474-9 : 2007 Any fired vessel (heater) installed within a firewall is to be arranged with means of shutdown from outside the firewall enclosure. (8)
Design Load The design is to ensure that stresses due to external nozzle loads and moments, stresses due to acceleration forces arising out of the motion of the floating installation, and stresses due to any other applicable external forces, such as wind, are within the limits allowed by the Rules.
7.4.9.5 Atmospheric Storage Tanks Atmospheric and low pressure storage tanks for flammable liquids are to be designed and fabricated in accordance with recognized standards Any storage tank larger than 20 barrels (2,312 liters) and operating at or near atmospheric pressure is to be equipped with one or more overflow connections, sized sufficiently to remove all incoming fluid in excess of the design operating level. 7.4.9.6 Compressors Natural gas compressors are to comply with recognized Standards (Refer to API Std. 617 for centrifugal compressors, API Std. 618 for reciprocating compressors, and API 619 for rotary type positive displacement compressors). Compressors rated for 2
3
less than 7 kg/cm (100 psig) and 28.3 m /min (1000 scfm) can be accepted on the basis of manufacturer’s certification data and test reports. A fusible plug fire detection system and directly activating the emergency shutdown system, is to be installed in the compressor package. The emergency shutdown system is to be interlocked to shutdown the compressor. 7.4.9.7 Pumps Centrifugal pumps intended for hydrocarbon service are to comply with recognized standard (refer to API Std, 610). Centrifugal pumps having stuffing box pressures in 2
excess of 14 kg/cm (200 psig) are to be provided with either single-balanced mechanical seals with means to collect and contain seal leakage, or tandem-balanced mechanical seals with alarm, to indicate primary seal failure. 7.4.9.8 Flowlines and Manifolds Flowlines and manifolds transporting gas and liquid in two-phase flow are to be designed and sized inaccordance with recognized standards (refer to API RP 14E) . 292
TCVN 6474-9 : 2007 Flow lines are to be fitted with a remotely operated shutoff valve at the first flange (as close as possible) on the loading manifold connecting the flexible lines that lead to the installation. These remote operated valves are to close upon actuation of the ESD System. 7.4.9.9 Scraper Launchers/Receivers Closures and barrels for scraper launchers/receivers are to be designed and constructed in accordance with recognized standards (refer to ASME Code) . Block valves are to be provided for isolation of process elements subject to pressure, to enable their safe removal when required. Means are to be provided to relieve pressure and to confirm the scraper launchers/receivers are not pressurized before opening the “quick opening closure”. 7.4.9.10Wellheads and Subsea Equipment Christmas tree assemblies and subsea equipment are not part of the classification boundaries for a normal production facility. However, the equipment may be classed if desired by the owner. Wellheads and Subsea Equipment is to be designed and constructed in accordance with recognized standards. 7.4.9.11Flare and Vent Structures Flare and vent booms and ground flare structures are to be designed and constructed in accordance with recognized standards (refer to API RP 2A) 7.4.10
Process Piping Systems
7.4.10.1General Process piping design, selection of valves, fittings and flanges, are to be in accordance with recognized standards (refer to API RP 14E) 7.4.10.2Thermal Relief Sections of piping systems that can be isolated with block valves, while they may be filled with cold liquid or liquid at near ambient temperature, are to be provided with thermal relief valves. This is to protect the piping from overpressure caused by solar heating or exposure to fire.
293
TCVN 6474-9 : 2007 7.4.10.3Isolation Valves Block valves are to be provided for isolation of process elements subject to pressure to enable their safe removal when required. Means are to be provided to relieve pressure from the blocked piping segment before removal of the control element.. 7.4.10.4Flexible Hoses Hose assemblies may be installed between two points where flexibility is required, if they will not be subject to twisting under normal operating conditions. Hoses carrying flammable fluids are to be fireresistant rated for maximum working pressure and temperature, and reinforced with wire braid or other suitable material. Burst pressure of the hose is not to be less than three (3) times the relief valve setting. 7.4.11
Packaged Process Units
7.4.11.1General Packaged process units are considered subsystems of the total production process systems. Subsystems are to comply with 7.3 for process system requirements and 7.3.9
for
major
equipment
requirements.
The
electrical
installation
and
instrumentation and control systems are to comply with 7.5 and 7.6 . Fire protection systems are to comply with 7.7. 7.4.11.2Skid Structures The skid structure is to be sufficiently rigid to support the mounted equipment and piping and, as required, to permit lifting during shipment without damage to the equipment or piping. Structural design calculations for skid units with a center of gravity height of more than 1.5 m (5 ft.), or a maximum operating weight in excess of 10 MT (metric tons) or 22.05 Kips, calculated in dry conditions, are to be submitted for review. 7.4.11.3Drip Pans Drip pans are to be provided to contain liquid spills and leaks from skid mounted equipment and piping, and to drain the liquid with adequate slope of 1 cm per meter (l/8 inch per foot) into open drain systems. A minimum 150 mm (6 in) coaming around the entire perimeter of a skid is to be provided. Skid beams that extend above the drip pan may be considered as meeting the coaming requirement, provided that the drip pan is seal-welded to the skid beams. A spill containment with less than 150 294
TCVN 6474-9 : 2007 mm (6 in) coaming arrangement is subject to special consideration. Calculations showing sufficient spillage containment for the skid are to be submitted for verification. 7.5 Process Support Systems
7.5.1
General This section presents criteria for the design and installation of process support systems on floating installations. Process support systems are utility and auxiliary systems that complement the hydrocarbon production and process systems. Process support systems include, but are not limited to, the following:
7.5.2
(1)
Utility/Instrument Air System
(2)
Fuel/Instrument Gas System
(3)
Use of Produced Gas as Fuel
(4)
Purging System
(5)
Fuel Oil System
(6)
Hydraulic System
(7)
Lubricating Oil System
(8)
Chemical Injection System
(9)
Heating and Cooling System
Component Requirements The component requirements listed below are intended for the components of process support systems not covered in 7.4.
7.5.2.1 Pressure Vessels Pressure vessels are to be designed, constructed, and tested in accordance with the recognized standards (refer to ASME codes) The design is also to ensure that stresses due to external nozzle loads and moments, stresses due to acceleration forces arising out of the motion of the floating installation, and stresses due to any other applicable external forces, such as wind, are within the limits allowed by the Rules. Consideration will be given to arrangements and details of pressure vessels that can 295
TCVN 6474-9 : 2007 be shown to comply with other recognized national Codes or Standards. 7.5.2.2 Heat Exchangers Heat exchangers are to be designed, constructed, and tested in accordance with the recognized standards (refer to ASME codes) The design is also to ensure that stresses due to external nozzle loads and moments, stresses due to acceleration forces arising out of the motion of the floating installation, and stresses due to any other applicable external forces, such as wind, are within the limits allowed by the Rules. Consideration will be given to arrangements and details of heat exchangers, that can be shown to comply with other recognized national Codes or Standards. 7.5.2.3 Pumps All pumps for process support service are to comply with a recognized industrial standard such as ANSI, UL, ASME, etc., and may be accepted on the basis of manufacturer’s affidavit of compliance with a recognized industrial standard. 7.5.2.4 Compressors Compressors, such as those used with air or refrigeration systems, are to be designed to a recognized industrial standard, and may be accepted on the basis of manufacturer’s affidavit of compliance with a recognized industrial standard. 7.5.2.5 Prime Movers (Internal Combustion Engines and Turbines) (1)
General Engines and turbines are to be designed and constructed in accordance with a recognized industry standard or code of practice.
(2)
Installation The installation of internal combustion engines and gas turbines is to be approved by VR, and is to comply with a recognized standard
(3)
Engines in Classified Areas Combustion engines are not to be installed in Class 1 areas, unless they are installed in an enclosure of fire resistive construction with adequate ventilation from a nonclassified area.
296
TCVN 6474-9 : 2007 (4)
Exhaust Manifolds Exhaust manifolds and piping are to be shielded for ignition prevention and personnel protection. Explosion relief valves or other appropriate protection against explosion are to be provided in the exhaust and scavenge manifolds. The explosion relief valves are to be of the return-seating type. The arrangement and location of the valves is to minimize the dangers from emission of flame. Exhaust piping from internal combustion engines and turbines is to be equipped with spark arresters, and discharge into nonhazardous areas.
(5)
Air Intakes Air intakes to internal combustion engines and gas turbines are to be not less than 3 m (10 ft) from hazardous areas. An explosion relief valve or other appropriate protection against explosion is to be provided in the air inlet manifold.
(6)
Starting Air Means are to be provided to exclude gas from starting air if the engine is airstarted. Starting air branch pipes to each cylinder are also to be provided with flame arresters..
(7)
Regulators When the gas pressure on the upstream side of a regulator exceeds 350 mm (14 in) of H2O, a relief valve is to be installed on the downstream side. This relief valve is to discharge to a safe location in the atmosphere through a flame arrester. The capacity of the relief valve is to be adequate in venting the volume of gas that would pass through the regulator if that device should fail.
7.5.2.6 Cranes Cranes and hoists are to comply with the TCVN 6968:2001. 7.5.3
System Requirements
7.5.3.1 Utility/Instrument Air System (1)
Arrangement Utility and instrument air may be supplied by a single air compressor or by a separate compressor for each service. When using a single compressor for 297
TCVN 6474-9 : 2007 both services, controls are to be provided to give priority to instrument air requirements. (2)
Air Quality Instrument air is to be oil-free and dried to prevent liquids and dirt from entering pneumatic instruments..
(3)
Piping Air compressor suctions are to be at least 3 m (10 ft) from hazardous areas. Air outlets from compressors are to be fitted with non-return valves and discharged into air receivers/scrubbers for oil and water removal. Instrument piping is to be installed to minimize low points, and provisions are to be included in the piping to allow removal of condensation. Crossovers where air and combustible fluids could be intermixed are not permitted anywhere in the system.
7.5.3.2 Fuel/Instrument Gas System Gas used for fuel or instrument systems is to be passed through a gas scrubber to remove entrainedliquid. The instrument gas may also have to be dried to meet requirements of the specific equipment that will use the gas. Gas containing hydrogen sulfide is not to be used as instrument gas. 7.5.3.3 Segregation of Piping Systems Piping systems carrying non-hazardous fluids are to be segregated from piping systems that may contain hazardous fluids. Cross connection of the piping systems may be made where means are provided for avoiding possible contamination of the non-hazardous fluid system by the hazardous medium. 7.5.3.4 Use of Produced Gas as Fuel Enclosed spaces located on the production deck having boilers, inert gas generators, and combustion engines using produced gas as fuel, are to have ventilation systems providing at least 30 air changes per hour. These spaces are to be fitted with gas detection systems to alarm at 20% L.E.L., and to activate automatic shutdown of the gas supply at 60% L.E.L. The automatic shutdown valve is to be located outside the space.
298
TCVN 6474-9 : 2007 This valve is also to be activated upon loss of the required ventilation in the enclosed space, and upon detection of abnormal pressure in the gas supply line. For produced gas containing hydrogen sulfide, provisions are to be made for gas sweetening, unless the equipment manufacturer has certified the equipment’s suitability for sour gas application, and the equipment is located in a freely ventilated, open space. To bring fuel gas containing H2S to equipment located in an enclosed machinery space, the sour gas must be sweetened. Additionally, the machinery space is to be equipped with H2S gas detectors. The detectors are to be set to alarm at 10 ppm, and to activate the shutdown valve at 50 ppm. 7.5.3.5 Purging System for Process Equipment (1)
Purging Process equipment and systems are to be purged prior to initial startup. They are also to be purged when being put back into service after shutdown, if there is a possibility of oxygen entering the system during shutdown.
(2)
Oxygen Content and Monitor The oxygen content of the inert gas used is not to exceed five percent (5%) by volume. Oxygen monitoring equipment is to be provided to monitor oxygen levels in the inert gas supply.
(3)
Isolating Valves Shutoff valves are to be fitted at the inlet and outlet of the final pressure regulator in a stored purging gas system.
7.5.3.6 Fuel Oil System This section is applicable to all fuel oil systems located on the production deck that supply fuel to the process equipment. For fuel oil systems serving marine support functions such as the fuel oil system for the vessel/unit service generator or for the helicopter deck refueling facility, see TCVN 6259:2003 and TCVN 5315:2001 for applicable requirements. (1)
Pumping Arrangements Fuel oil pumping arrangements are to be completely separate from other pumping systems, and are not to be connected to other piping systems. 299
TCVN 6474-9 : 2007 (2)
Pump Controls Fuel oil transfer pumps, fuel oil unit pumps, and other similar fuel pumps are to be fitted with local and remote controls so they may be stopped in case of an emergency. Remote controls are to be located in a space not affected by fire at the pump locations
(3)
Containment A containment at least 150 mm (6 in) high is to be provided at unloading and/or offloading stations, pump areas, and overflow/vent line locations, and arranged to direct a possible leak or spill to the open drain system.
(4)
Valves on Oil Tanks Where pipelines emanate from oil tanks at such a level that they will be subjected to a static head of oil from the tank, they are to be fitted with a positive closing valve located at the tank. Gray cast iron valves are not to be used as shutoff valves for fuel oil tanks. Arrangements are to be provided for closing the tank’s valve locally and from a space not affected by fire at the fuel oil tank location. This requirement may be omitted if the tank capacity is less than 132 US gallons (500 liters).
(5)
Non-metallic Expansion Joints and Hoses Non-metallic expansion joints and hoses for use in fuel oil systems are only allowed at machinery connections, provided they are in an easily accessible position, and pass the fire test in accordance with recognized standards.
7.5.3.7 Hydraulic System This section is applicable to all hydraulic oil systems located on the production deck that supply hydraulic fluid to control systems of process related equipment. High flash point hydraulic fluids are to be used, unless a specific system design requires the use of low flash point fluids. When low flash point fluids are used, precautions are to be b e taken to minimize mini mize fire hazard, by insulating ins ulating nearby hot surfaces that could ignite a low flash point fluid. 7.5.3.8 Lubricating Oil System (1)
300
Interconnection
TCVN 6474-9 : 2007 The lubricating oil piping is to be entirely separated from other piping systems. (2)
Valves on Lubricating Oil Storage Tanks Normally opened valves on lubricating oil storage tanks are to comply with the requirements given in 7.5.3.6.
(3)
Turbines (a)
Automatic Shut-off Turbines are to be provided with a means of automatically shutting off the steam or gas turbine fuel supply upon failure of the lubricating oil system.
(b)
Indicators Indicators are to be fitted to allow monitoring of the pressure and temperature of the water inlet and oil outlet of the oil coolers. Pressure systems are to be fitted with low-pressure alarm. Sump and gravity tanks are to be provided with suitable gauges for determining the level of oil within the tank.
(c)
Strainers and Filters For auxiliary turbines, a magnetic strainer and fine mesh filter (strainer) are to be provided in the lubricating oil piping to the turbine. Strainers are to be so arranged as to prevent, in the event of leakage, spraying oil onto heated surfaces.
(4)
Internal Combustion Engines (a)
Lubricating Oil Pumps: The lubricating oil pump is to be of sufficient capacity for the maximum output of the engine.
(b)
Filters Lubrication oil filter is to be provided and so arranged as to prevent, in case of leakage, spraying oil onto heated surfaces.
(c)
Low Oil Pressure Alarm An alarm device with audible and visual signals for failure of the lubricating oil system is to be fitted.
7.5.3.9 Chemical Injection System (1)
Materials 301
TCVN 6474-9 : 2007 The chemical storage tank, pumps, and piping are to be suitable for the chemicals being handled. Affidavit from tank manufacturers confirming the tank material is compatible with the chemical being stored is to be provided. Fiberglass reinforced polyester independent tanks may be considered for nonflammable chemicals only. For metallic tanks containing flammable or combustible fluids, scantling plans and calculations are to be submitted for review. Design and construction of non-metallic tanks for non-flammable liquids are to be in accordance with industry-recognized standards (2)
Arrangement and Components For multi-chemical systems, a separate tank or tank compartment is to be provided for each chemical used. Chemical storage tanks are to be provided with atmospheric vents and level glasses. Flame arrester is to be provided to flammable or combustible tank vent. The discharge of each pump is to be provided with a pressure relief device to return the chemical to the pump suction or chemical tank. Injection lines are to be fitted with non-return valves, and means are to be provided to automatically shutdown the injection pump in the event of process shutdowns.
7.5.3.10 Heating and Cooling Systems The medium used for heating or cooling any hydrocarbon system is to be contained solely within the classified area, unless the return line of the heating or cooling system to a non-classified area is provided with means to detect any hydrocarbon contamination. 7.6 Electrical Systems
7.6.1
Applicability Electrical systems used solely for hydrocarbon processing on floating installations are to meet the requirements of this Part. Where electrical systems or equipment are used to supply services other than Oil or Gas Production, the equipment is also to comply with the TCVN 6259-4:2003 Rules for classification and construction of sea going ships – Electrical systems .
7.6.2 302
Design Considerations
TCVN 6474-9 : 2007 7.6.2.1 Equipment and Enclosures. Electrical equipment and enclosures subject to the offshore environment are to be provided with a degree of o f protection p rotection suitable to the environment or hazard in i n which they are located, in accordance with recognized standard (refer to API RP 14F) 7.6.2.2 Selection of Materials. Materials of construction are to be selected that are suitable for their intended purpose and location. 7.6.2.3 Equipment Grounding (Earthing) Arrangements (1)
Permanent Electrical Equipment. All electrical equipment with metallic enclosures, whose arrangement and method of installation does not assure positive grounding to the metal hull or equivalent conducting body, is to be permanently grounded through a separate conductor. In addition, it is to be protected against damage. Where separate grounding conductors are required, they are to be in accordance with recognized standard (refer to API RP 14F). Systems designed to other recognized standards are to comply with such standards, but in no case are the separate grounding conductors to be of a cross-sectional area of less than indicated in Table 9.7-1.
(2)
Lightning Protection. Equipment and structure are to be protected against lightning damage in accordance with recognized recognized standard (refer to NFPA 780) .
303
TCVN 6474-9 : 2007 Table 9.7-1 Size of Ground (Earth)-continuity Conductors and Grounding (Earthing) Connections
Type of Grounding
Cross-sectional Area of
Minimum cross-sectional Area of
Connection
Associated Current
Copper Grounding Connection
Carrying Conductor (A) Ground-continuity conductor in flexible
A1
A ≤ 16 mm
A2
16 mm < A
A3
A> 32 mm
2
A
≤ 32 mm 2
2
2
16 mm
cable or flexible cord
Ground-continuity conductor
2
A/2
For cables having an insulated ground-continuity conductor 1a
A ≤ 1,5 mm
1b
1,5 mm < A
1c
16 mm < A
B1d
A> 32 mm
2
2
1,5 mm
incorporated in fixed cable
2
2
≤ 16 mm 2
A
≤ 32 mm 2
16 mm
2
2
A/2
For cables with bare ground wire in direct contact with the lead sheath
Separate fixed
2
B2
A ≤ 2,5 mm
B2b
2,5 mm < A ≤ 6 mm
2
2
1 mm 2
C1a
grounding conductor
2
1,5 mm
Stranded grounding connection: A ≤ 2,5 mm
2
2
1,5 mm < A
≤ 1,5 mm 2 2
A with A> 1,5 mm mm C1b
Unstranded grounding connection 2,5 mm
304
2
C2
2,5 mm < A
C3
8 mm < A
C4
A> 120 mm
2
≤ 8 mm 2
≤ 120 mm 2 2
2
2
4 mm A/2
70 mm
2
TCVN 6474-9 : 2007 7.6.2.4 System Grounding (Earthing) Where electrical systems are used solely for process facilities, system grounding is to comply with 6.10.2 of API RP 14F (1)
Vessels with Integral Hull Tanks. If the facility has integral hull tanks containing liquids with a flash point not exceeding 60°C (140°F), a grounded distribution system is not to be used, except for the following: (a)
Grounded intrinsically safe circuits
(b)
Power supplied control circuits and instrumentation circuits where technical or safety reasons preclude the use of a system without a grounding connection, provided the current in the hull is limited to 5 Amperes or less in both normal and fault conditions.
(c)
Limited and locally grounded systems, provided any possible resulting current does not flow directly through any hazardous areas.
(d)
Alternating current power networks of 1 kV root mean square (r.m.s.) (line to line) and over, provided any possible resulting current does not flow directly through any hazardous areas.
(2)
Ground (Earth) Return Paths Through the Hull The metal structure of an offshore installation is not to be used as a normal current return for the electrical distribution system, except for the following systems: (a)
Impressed current cathodic protection
(b)
Limited and locally grounded systems for battery systems for engine starting having a one-wire system and the ground lead connected to the engine
(c)
Grounded intrinsically safe circuits
7.6.2.5 Distribution and Circuit Protection Electrical installations are to comply with requirements as noted herein. (1)
General All ungrounded conductors and the devices and circuits which they serve are 305
TCVN 6474-9 : 2007 to be protected against over-current. Protective devices are to be provided to guard against overload and short circuit currents, and to open the circuit if the current reaches a value that will cause excessive or dangerous temperatures in the conductor or conductor insulation. (2)
Motor Controllers Motor starting and control installations, including overload protection and short circuit protection, are to be in accordance with recognized standards (refer to API RP 14F)
7.6.3
Rotating Electrical Machinery (1)
General Motors and generators are to be manufactured to recognized standards such as NEMA Standard MG-1 or IEC 60034 for performance, manufacture, protection, and construction. .
(2)
Temperature Rating Equipment is to be selected for the rated ambient temperature. If equipment is intended to be used in a space where the equipment’s rated ambient temperature is below the assumed ambient temperature of the space, it is to be used at a derated load.
(3)
Moisture Condensation Protection All generators and motors 50 hp (37,3 kW) or more are to be equipped with space heaters, to prevent accumulation of moisture and condensation when they are idle for appreciable periods. The space heaters are to be capable of being electrically isolated.
(4)
Temperature Detection Generators larger than 500 KVA are to be provided with at least one embedded temperature detector per phase, at the hot end of the stationary winding, with temperature indication at a manned location.
7.6.4
Transformers (1)
General Each power transformer is to be provided with a corrosion resistant nameplate
306
TCVN 6474-9 : 2007 indicating the name of the manufacturer and all pertinent electrical characteristics. They are to be constructed and tested in accordance with recognized standard (refer to ANSI C57). Transformers are to be protected in accordance with recognized standard (refer to API RP 14F Section 8). (2)
Transformer Supplying Services Other than Oil or Gas Production In addition to the above, transformers supplying services other than oil or gas production are to be selected, installed, and protected in accordance with their environmental conditions and applicable requirements in TCVN 6259:2003 Rules for classification and construction of sea going ships – Electrical arrangements .
7.6.5
Switchgear (1)
Application Main and emergency switchboards, power and lighting distribution boards, motor control centers and motor controllers, and battery charging panels, are to be designed, constructed, and tested in accordance with the provisions of this subsection
(2)
Construction, Assembly and Components (a)
Enclosures.
Enclosures and assemblies are to be constructed of steel or other suitable incombustible, moisture-resistant materials, and reinforced as necessary to withstand the mechanical, electromagnetic and thermal stresses which may be encountered under both normal and short circuit fault conditions. Enclosures are to be of the closed type. The degree of the protection is to be appropriate for the intended location. See also 7.6.1.1. All wearing parts are to be accessible for inspection and be readily renewable. (b)
Bus Bars 1) General: Bus bars are to be sized and arranged so that the temperature rise under the most severe loading conditions will not affect the normal operation of electrical devices mounted in the switchboard. 2) Bracing of Bus Bars: Bus bars and circuit breakers are to be mounted, braced, and located to withstand thermal effects and magnetic forces 307
TCVN 6474-9 : 2007 resulting from the maximum prospective short circuit current. 3) Bolted Connections: Bolted bus bar connections are to be suitably treated (e.g, silver plating) to avoid deterioration of electrical conductivity over time. Nuts are to be fitted with means to prevent loosening.. 4) Cable connections: Soldered connections are not to be used for 2
connecting or terminating any cable of 2.5 mm or greater. These connections are to be made with of soldered lugs or equivalent. 5) Clearance and creepage: Minimum clearances and creepage distances between live parts of different potential, i.e., between phases and between phase and ground, are to be in accordance with Table 9.7-2, as appropriate . Table 9.7-2 Clearance and Creepage Distance for Switchboards, Distribution Boards, Chargers, Motor Control Centers and Controllers.
Rate Insulation Voltage
Minimum Clearances,
Minimum Creepage Distances,
(V)
mm (in.)
mm (in.)
Up to 250
15(19/32)
20(25/32)
From 251 to 660
20(25/32)
30(1 13/16)
Above 660
25(1)
35(1 3/8)
NOTES: The values in this table apply to clearances and creepage distances between live parts as well as between live parts and exposed conductive parts, including grounding. (c)
Circuit Breakers: 1)
Compliance with a Standard: Circuit breakers are to be designed, constructed, and tested in accordance with recognized standard (refer to ANSI C37, NEMA AB-1, IEC 947-2). The certificates of tests are to be submitted upon request by VR.
2)
Short Circuit Capacity: Circuit breakers are to have sufficient breaking and making capacities as specified in the short circuit calculation. See 7.6.13
308
TCVN 6474-9 : 2007 3)
Isolation: Circuit breakers are to be mounted or arranged in such a manner that the breakers may be removed from the front of the switchboard, without first de-energizing the bus bars to which the breakers are connected. Draw-out or plug-in type circuit breakers that are arranged in such a manner that the breaker may be removed from the front without disconnecting the copper bus or
cable
connections,
are
acceptable
for
this
purpose.
Alternatively, an isolation switch may be fitted upstream (line or supply side) of the breaker. (d)
Fuses: Fuses are to be designed, constructed, and tested in accordance with recognized standard (refer to UL 248 or IEC 269) . The certificates of tests are to be submitted upon request from the Bureau. The requirements of 2) and 3) above are applicable. Where disconnecting means are fitted, they are to be on the supply side. If the switch is not rated to interrupt the circuit under load, it is to be provided with interlock to prevent opening until the load is de-energized
(e)
Internal Wiring. 1)
Wires: Internal instrumentation and control wiring is to be of the stranded type and is to have flame-retarding insulation. They are to be in compliance with a recognized standard.
2)
Protection: In general, internal instrumentation and control wiring is to be protected (by fuse or circuit breaker) against short circuit and overload, with the following exceptions:
•
generator voltage regulator circuits
•
generator circuit breaker tripping control circuits, and
•
secondary circuit of current transformer
These circuits, however, except that of the current transformer, may be fitted with short circuit protection only. 3)
Terminals: Terminals or terminal rows for systems of different voltages are to be clearly separated from each other, and the 309
TCVN 6474-9 : 2007 rated voltage is to be clearly marked. Each terminal is to have a nameplate indicating the circuit designation. (f)
Circuit Identification: Identification plates for feeders and branch circuits are to be provided, and are to indicate the circuit designation and the rating or settings of the fuse or circuit breaker of the circuit.
(3)
Switchboards In addition to the preceding requirements, main and emergency switchboards are to comply with a) and b) below.
(a) Bus Bars: Bus bars for switchboards supplied by generators are to comply with recognized standards (refer to Section 5.5.2.1 of API 14F) (b) Power Generation Switchboards. At minimum, the following equipment and instrumentation are to be provided for switchboards associated with power generation: 1)
Voltage Regulators
2)
Synchronizing Controls
3)
Synchronizing Relay
4)
Ground Fault Detection
5)
Prime Mover Speed Control
6)
Ammeter – with selector switch arranged to measure each phase
7)
Voltmeter – with a selector switch
8)
Frequency Meter
9)
Watt Meter / Power Factor Meter.
10)
Space Heater Pilot Lamp – where required
11)
Stator
Winding Temperature
Indicator
(500
kVA
and larger
Generators) (4)
Motor Controllers In addition to the applicable requirements in 7.6.5 (2) above, motor controllers are to comply with the following:
310
TCVN 6474-9 : 2007
(a) Overload and Under-voltage Protection. Overload protection and low-voltage protection, if provided in the motor controllers, are to be in accordance with recognized standard (refer to 7.4.4 of API RP 14F, or other appropriate standard) (b) Disconnecting Means A circuit-disconnecting device is to be provided for each motor branch circuit so that the motor and the controller may be isolated from the power supply for maintenance purposes. The circuit-disconnecting device is to be operable externally. (5)
Battery Charging Panels In addition to the applicable requirements in 7.6.5 (2) above, battery chargers are to comply with the following: (a)
Battery Charger:
Except when a different charging rate is necessary and is specified for a particular application, the charging facilities are to be such that the completely discharged battery can be recharged to 80 % capacity in not more than 10 hours. (b)
Reversal of Charging Current. An acceptable means is to be installed, such as reverse current protection, to prevent the battery charger component failure from discharging the battery.
(c)
Instrumentation : 1)
disconnect switch for power supply to the charge
2)
indicator light connected to the downstream side of the disconnect switch in (a)
(6)
3)
means for adjusting the voltage for charging
4)
voltmeter to indicate the charging voltage, and
5)
ammeter to indicate the charging current.
Switchgear Supplying Services Other than Oil and Gas Production Main and emergency switchboards, power and lighting distribution boards, 311
TCVN 6474-9 : 2007 motor control centers and motor controllers, and battery charging panels that are used to supply services other than Oil and Gas Production, are to comply with applicable requirements in TCVN 6259:2003 Rules for classification and construction of sea going ships – Electrical arrangements in addition to the above mentioned sections. 7.6.6
Wire and Cable Construction
7.6.6.1 General All wires and cables are to be constructed in accordance with recognized standards such as IEEE, ICEA, IEC, or other recognized standards. All cable and conduit fittings and wiring devices are to be constructed in accordance with an appropriate recognized standard 7.6.6.2 Conductor Type Conductors are to be of copper, and stranded in all sizes. Conductor sizes are to be in accordance with recognized standard (refer to API RP 14F). But in no case are they to be less than the following in cross sectional size: 2
(1)
1.5 mm (2,960 circ. mils) for motor feeder and branch circuit cables
(2)
1.0 mm (1,973 circ. mils) for power lighting and control cables
(3)
0.5 mm (786.5 circ. mils) for essential or emergency signaling and
2
2
communications cables, except for those assembled by the equipment manufacturer, and (4)
2
0.375 mm (739.3 circ. mils) for telephone cables for non-essential communications services, except for those assembled by the equipment manufacturer.
7.6.6.3 Insulation. Conductor insulation is to be rated suitable for a minimum operating temperature of 75°C (167°F) in wet environments. In addition, insulation rating is to be at least 10°C (50°F) higher than the maximum ambient temperature that the conductor can encounter at its service location. 7.6.6.4 Cable Flame Retardancy (1)
312
Standards
TCVN 6474-9 : 2007 All electric cables are to be at least of a flame-retardant type complying with the following: (a)
Cables constructed in accordance with recognized Standards such as IEEE, ICEA, IEC, are to comply with the flammability criteria of IEEE Std. 45 or IEC 60332.3 Category A where installed in trays, bunches, or similar groupings
(b)
Cables constructed to IEEE Std. 45 are to comply with the flammability criteria of that standard .
(c)
Cables constructed to IEC Publication 60092 standards are to comply with the flammability criteria of IEC Publication 60332-3, Category A.
Consideration will be given to special types of cables, such as radio frequency cables, which do not comply with the above requirements. 7.6.6.5 Fire Resistant Property When electric cables are required to be fire-resistant, they are to comply with the requirements of recognized standard (refer to IEC Publication 60331) 7.6.7
Hazardous Areas
7.6.7.1 General Areas and spaces in which flammable vapors or gases are handled, processed, or stored, are to be classified in accordance with the following sections. 7.6.7.2 Electrical Installations in Hazardous Areas Electrical installations in classified areas are to be limited to those systems needed to carry out necessary control, monitoring and power distribution functions, and are to be in accordance with recognized standards (refer to Section 4 of API RP 14F) 7.6.7.3 Area Classifications and Electrical Installations on Vessel Conversions (1)
General Electrical installations and delineation of classified areas for offshore installations having storage tanks for liquids with a flash point not exceeding o
o
60 C (140 F), and that are integral with the hull structure, need not comply with TCVN 6259-2:2003, provided they comply with applicable requirements as follows:
313
TCVN 6474-9 : 2007
(2)
Area Classification Delineation of classified areas is to be as follows: (a)
Open Decks: Over Crude Storage Tanks Freely ventilated, open and gas tight deck spaces to the full breadth of the ship and 3 m (10 ft) fore and aft of cargo block to a height of 2.4m (8ft.), or to the height of the production deck, are to be considered Zone 2 .
(b)
Enclosed Spaces: Adjacent to Crude Storage Tanks Semi-enclosed or enclosed spaces immediately adjacent to crude oil storage tanks are to be considered Zone 1
(c)
Pump Room: A continuously ventilated (20 air changes per hour) crude oil pump room is to be considered a Zone 1 area, provided the failure of ventilation is alarmed in a manned location.
(d)
Cofferdam: Spaces which are separated by a single bulkhead from crude oil storage tanks are to be considered Zone 1 areas
(e)
Crude Storage Tank Vents: Areas of unrestricted ventilation around cargo tank vents are to be considered Zone 1 areas with a spherical radius of 3 m (10 ft), and Zone 2 for an additional 7 m (23 ft) .
(3)
Electrical Interconnections Where marine service systems are interconnected with hydrocarbon production systems, a point in the system 2.4 m (8 ft) above the oil storage tank deck, is to be designated as an electrical system design code demarcation point. Above this point, electrical system design is to be in accordance with this section; below this point, in accordance with applicable sections of the TCVN 6259-4:2003
7.6.7.4 Wiring Methods in Hazardous Areas (1)
General Threaded metal conduit, armored cable, metallic sheathed cable, or other approved methods or cable types, may be installed in Zone 1 areas. Cables with moisture resistant jacket (impervious sheathed) may be installed in Zone 2 areas, provided they are protected from mechanical damage
(2) 314
Splicing
TCVN 6474-9 : 2007 No splices are allowed in classified locations, except in intrinsically safe circuits. (3)
Conduit Installations Conduit wiring systems in classified areas are to be in accordance with the recognized standards (refer to API RP 14F Section 6.4).
7.6.8
Ventilation
7.6.8.1 General Attention is to be given to ventilation inlet and outlet locations and air flow directions in order to minimize the possibility of cross contamination. Ventilation inlets are to be located in non-classified areas. Ventilation for classified spaces is to be completely separate from that for non-classified spaces. For engine and turbine air intakes, see 7.5.2(5). 7.6.8.2 Ventilation of Enclosed Classified Spaces Ventilation of enclosed classified spaces is to be made with under-pressure in relation to adjacent, less hazardous areas. The arrangement of ventilation inlet and outlet openings for the enclosed classified space is to be such that the entire space is efficiently ventilated, giving special considerations to locations of equipment which may release gas, and to spaces where gas may accumulate. Ventilation inlets are to be from non-classified areas. Ventilation outlets are to be led to outdoor locations that are of the same or a less hazardous classification than the ventilated space. Ventilating fans are to be of non-sparking construction. The capacity of the fan is to be such that the space is adequately ventilated, as defined by recognized standard (refer to API RP 500). 7.6.8.3 Ventilation of Non-classified Spaces Ventilation inlets and outlets for non-classified spaces are to be located in nonclassified areas. Where passing through classified spaces, ducts are to have overpressure in relation to the classified spaces. Enclosed non-hazardous working spaces opening into hazardous locations do not need to be considered hazardous, provided the arrangements required by 6.3.1 of the 1989 IMO MODU Code , are complied with. 7.6.8.4 Emergency Shutdown Means are to be provided for shutdown of ventilation fans and closing external 315
TCVN 6474-9 : 2007 openings from outside the spaces served, in the event of fire or detection of combustible or hydrogen or sulfide gas. 7.6.9
Cable Support and Installation The cable installation is to be in accordance with the “standard details” submitted in accordance with 7.2.6.
7.6.9.1 Mechanical Protection For cables which are not equipped with metal armor or metal sheathing, installation in rigid conduit or similar structural protection is to be utilized if such cable is employed near walkways, at deck level, near hoist or crane laydown or work areas, or where equipment maintenance work must be accomplished in a constrained area. 7.6.9.2 Splicing (1)
General In general, electrical cables are to be installed in continuous lengths between terminations. However, approved splices will be permitted for cables of exceptional length, to facilitate their installation. The location and particulars of the splices are to be submitted for review.
(2)
Construction Cable splice is to be made of fire-resistant replacement insulation equivalent in electrical and thermal properties to the original insulation. The replacement jacket is to be at least equivalent to the original impervious sheath, and is to assure a watertight splice. Splices are to be made with an approved splice procedure addressing the following components:
(3)
•
Connector of correct size and number
•
Replacement insulation
•
Replacement jacket
•
Instructions for use
Hazardous Areas See 7.3.6
7.6.10
Power Source Requirements This section details minimum electrical power generation sources for main and
316
TCVN 6474-9 : 2007 emergency modes of operation. It should be noted that the governmental regulations might require reserve main power or an emergency power source in excess of these requirements. Where the main power source is used to supply services other than oil or gas production, the main power source is to comply with TCVN 6259-4:2003 . 7.6.10.1Unmanned Facilities (1)
Main Power The main power source(s) is to be sufficient to maintain the maximum intended operational loads of the facility, without need to use the emergency source of power.
(2)
Emergency Power An emergency power source, independent of the facility’s main power, is to be sufficient to supply services for navigational aids as required by the cognizant Coastal Authority, but not for less than four (4) days.
7.6.10.2Manned Facilities (1)
Main Power The main power source(s) is to be sufficient to maintain the maximum intended operational load of the facility.
(2)
Emergency Power An emergency source of power for systems vital to safety, fire fighting, and protection of personnel, is to be provided to supply the services as listed herein. Where an emergency power supply has been provided for classification/flag state purposes, this source may also be used to provide emergency loads in production areas, provided the emergency source of power is adequately sized to supply all of the connected loads. Provision for emergency power supply, less than those listed herein, will be considered, provided adequate technical justification is submitted. Loads to be supplied by the emergency source of power are listed in (3) and (4) below.
(3)
Fire Pump:
If both fire pumps required by 7.7.2 are electric motor driven, one of these pumps is to be powered by the emergency source of power. The emergency source of power is to have sufficient fuel for at least 18 hours of fire pump operation. 317
TCVN 6474-9 : 2007
(4)
Other Loads:
The following loads are to be powered by the designated emergency source of power:
•
Fire detection 18 hours
•
Gas detection 18 hours
•
Communication 18 hours
•
ESD system (if electric) 18 hours
•
Paging and alarm system 18 hours
•
Emergency lighting from all spaces to all alternative egress points 18 hours
•
Electric blowout preventer control system 18 hours
•
Navigational aids As required by the applicable Coastal Authority, but not less than 4 days
7.6.11
Emergency Source of Power An emergency source of power as required by 7.5.10
may be supplied by an
emergency generator or batteries, in accordance with recognized standard (refer to section 5.6 of API 14F). Installations supplying services other than oil or gas production are to be in accordance with TCVN 6259-4:2003 . 7.6.12
Battery Systems Battery installations are to comply with recognized standard (refer to Section 10.3.4 of API RP 14F), except that equipment inside a battery room need to be certified for use in zone 1 or zone 2 only if the battery room is classified Zone 1 or 2, respectively, in accordance with API RP 500. Ventilation of battery rooms is to be separate from all other ventilation. Arrangements of equivalent safety will be given special consideration
7.6.13
Short Circuit Current Calculations and Coordination Study
7.6.13.1General The protection and coordination of power systems are to be in accordance with the TCVN 6259-4:2003 , IEC, IEEE 242, or equivalent standard
318
TCVN 6474-9 : 2007 7.6.13.2Short Circuit Capacity The maximum calculated short circuit current available at the main bus bars and at each point in the distribution system, is to be used to determine the adequacy of the short circuit capacities of the protective devices and bus bar bracing, as per 7.5.5 (2)(b). 7.6.13.3Coordination The power system coordination study is to show that the protective devices and their settings are properly selected to minimize damage to switchgear, transformers, generators, motors, conductors, conductor shielding and other equipment, as well as undesirable shutdowns. 7.6.14
Protection from Ignition by Static Charges Any ignition hazard due to a difference in electrical potential to ground is to be effectively controlled. This may require the use of conductive belts, grounding of combustible fluid loading or discharge equipment and hose, and the grounding of helicopters prior to refueling. All precautions against ignition due to static electric discharge are to be in accordance with recognized standard (refer to NFPA-77)
7.7 Instrumentation & Control Systems
7.7.1
Applicability This section defines criteria for the instrumentation and control systems for offshore facilities. The design of these systems is to comply with API RPI4C or other acceptable standards and the additional criteria contained in this section. Statutory governmental regulation or guidance, which may be applicable, is to be taken into consideration. The documentation pertaining to instrumentation and control systems required for submittal is listed in 7.2.7. (1)
General The control and instrumentation systems are to provide an effective means for monitoring and controlling pressures, temperatures, flow rates, liquid levels and other process variables for the safe and continuous operation of the facilities. Where control over the electrical power generation and distribution is required for the operation of the facilities then the control system should also be arranged 319
TCVN 6474-9 : 2007 to cover this. Control and instrumentation systems for process, process support, utility and electrical systems are to be suitable for the intended application All control and safety shutdown, systems are to be designed for safe operation of the equipment during start-up, shutdown and normal operational conditions. (2)
Installation (a)
Electrical Installations
Electrical installations for instrumentation and control systems are to be in accordance with 7.6. (b)
Hydraulic and Pneumatic Control Systems
Piping systems for hydraulic and pneumatic controls are to be in accordance with 7.4. 7.7.2
Components (1)
Environmental Considerations All instrumentation control and safety system components, including alarm and indicator devices, are to be designed for use in a marine environment, resistant to corrosion, and capable of operating under all prevailing environmental conditions. Each component is to be designed and tested for the extremes of pressure and temperature that it can encounter in service.
(2)
Suitability of Computer Based Equipment Where safety related functions are performed by computer based equipment then the equipment is to be tested in accordance with recognized standard
(3)
Electrical Variations Electrical and electronic components in AC systems are to be capable of operating satisfactorily under normally occurring variations in voltage and frequency. Unless otherwise stated, the variations from the rated value may be taken from table 9.7-3 . DC system devices are to be capable of operating satisfactorily at minus 15% voltage
320
TCVN 6474-9 : 2007 Table 9.7-3 Electrical Variations
Quantity in Operations
Permanent variation
Transient Variation
Frequency
±5%
±10%(5s)
Voltage
+6%,-10%
±20%(1,5s)
(4)
Loss of Power Loss of control power (pneumatic, hydraulic or electric) to any device is not to cause the system to go into an unsafe condition. Cause and effect matrices are to demonstrate loss of control power effects.
7.7.3
Instruments (1)
Temperature All temperature-sensing elements or devices are to be installed in separable socket type thermowells, so that they can be removed without danger of pressure or fluid release.
(2)
Pressure Pressure switches supplied as safety devices are to be equipped with test connections to enable application of an external pressure source without disturbing the switch installation. Pressure gauges and sensors are to be provided with an isolation valve to permit the safe removal of the gauge without the need to reduce the pressure in the system. The open or closed position of the valve is to be readily identifiable from the position of the handle or stem..
(3)
Level Liquid or interface level gauges are to be installed to cover the operating range and set points of level controllers or level switches. Direct viewing level gauges in processing or combustible fluid service are to be of the heavy-duty flat glass type and are to be equipped with self-closing valves at their ends. An equivalent type of level gauge may also be acceptable.
7.7.4
Alarm Systems (1)
Characteristics Alarm systems are to be of the self-monitoring type and designed so that a fault in the alarm system is self-revealing or will cause it to fail to the alarmed 321
TCVN 6474-9 : 2007 condition. Additionally, alarms are not to react to normal transient conditions or false signals. (2)
Independence Alarm systems are to be independent of control and safety systems, except that common sensors will be acceptable for non-shutdown related systems.
(3)
Visual and Audible Alarms Alarms are to be both audible and visual, and are to be provided at the control stations, as required in this Section. Alarms are to clearly identify the system and service of the faulted system or process components. Visual alarms are to be displayed in a distinguishable manner such that alarms for similar process components or systems are grouped together, and the colors representing a particular function or condition remain uniform. Visual alarms are to flash when first activated. Audible alarms associated with the process plant are to be of distinctive tone from other alarms such as fire alarm, general alarm, gas detection, etc., and they are to be of sufficient loudness to attract the attention of personnel on duty; for spaces of unusual high noise levels, a beacon light or similar device, installed in a conspicuous place is to supplement any of the audible alarms in such spaces; however, red light beacons are only to be used for fire alarms. A fault in the visual alarm circuits is not to affect the operation of the audible alarm circuits.
(4)
Acknowledgement of Alarms Alarms are to be acknowledged by manually changing the flashing display of the incoming alarm to a steady display and by silencing the audible signal; the steady state light display is to remain activated until the fault condition is rectified. Alarming of other faults that may occur during the acknowledgement process is not to be suppressed by such action, and is to be alarmed and displayed accordingly. Where a centralized control and monitoring station is provided, the silencing of the audible alarm from an associated remote control station is not to lead automatically to the silencing of the original alarm at the centralized control and monitoring station.
322
TCVN 6474-9 : 2007
(5)
Disconnection and Resumption of Alarm Functions Alarm circuits may be temporarily disabled for maintenance purposes or during initial plant start-up, provided such action is clearly indicated at the associated station in control and, where such station is provided, at the centralized control and monitoring station. However, such alarm is to be automatically re-activated after a preset time period.
(6)
Summary Alarms When individual alarms are displayed and alarmed at a centralized control and monitoring station, the visual alarms may be displayed and alarmed at other associated remote control stations as summary alarms.
(7)
Built-in Testing Alarm systems are to be provided with effective means for testing all audible and visual alarms and indicating lamps without disrupting the normal machinery or system operation. Such means are to be fitted in the associated remote stations.
7.7.5
Control and Monitoring (1)
General
Display systems are to comply with 7.7.4 (1), (3) and (7). (2)
Loss of Signal Loss of control signal from a field sensing device required to comply with this standard is to initiate an alarm or cause a shutdown..
(3)
Display of Parameters Operating parameter displays are to be clear, concise, consistent and grouped logically. Operating parameter displays are to be included in control stations.
(4)
Logic Circuit Features When logic circuits are used for sequential start-up or for operating individual process components, indicators are to be provided at the control console to show the successful completion of the sequence of operations by the logic-circuit and start-up and operation of the process component. If some particular step is not carried out during the sequence, the sequence is to 323
TCVN 6474-9 : 2007 stop at this point, and such condition is to be alarmed at the control console or, where provided, at the centralized control and monitoring station. Feedback devices are to be employed in order to sense steps carried out during the start-up sequence. Sequence operation is to stop upon lack of feedback signal. Where valves are employed in any start-up sequence, valve condition is to be sensed as valve stem position and not as a function of control or power signal to the valve.. (5)
Overrides. No condition of operation within normal ranges is to require the override of a required protective device or function. Where shutdown functions are bypassed during special operational modes described below, sensing devices are to be arranged to continue to indicate the condition of each process variable. In addition, an indicator for each function is to alert the operator that the shutdown function is being “bypassed”. Provisions to override shutdown functions may include the following: (a)
Calibration
To periodically test or calibrate field sensing device (b)
Out of Service To take the vessel or other process component out of service.
(c)
Start-up To allow process conditions to stabilize, automatic bypass of shutdown functions on start-up may be installed, provided the process variable condition is indicated, and an automated device is fitted which will return the shutdown function to operation once the normal processcondition has been attained. The use of timers in association with this required automatic function will be considered
7.7.6
Safety Systems (1)
General Safety systems are to be of the fail-safe type and are to respond automatically to
324
TCVN 6474-9 : 2007 fault conditions that may endanger the plant or safety of the crew. Unless otherwise required in this Section or specially approved, this automatic action is to cause the plant to take the least drastic action first, as appropriate, by reducing its normal operating output or switching to a stand-by process component, and last, by stopping it. Actuation is to result in audible and visual alarm. (See 7.3.4 for number of safety levels required) (2)
Independence Safety systems are to be completely independent of the control and alarm systems so that a failure in one of these systems will not prevent the safety system from operating.
(3)
Activation Each safety action is to be alarmed at the associated remote station. Where a centralized control and monitoring station is fitted, individual alarms are to be provided at that station; in which case, a summary alarm for the specific safety system will be acceptable at other associated remote stations. When both an alarm and a safety action are required for a specific failure condition the operating points are to be arranged such that alarm is activated earlier..
(4)
Resumption of Operation Process components that are stopped as a result of a safety action are to be manually reset before their operation is resumed..
(5)
Override of Safety Provisions Remote overrides are not to be provided for those safety actions specified in other Sections of this Guide. For safety actions specified in 7.7.5(5), any overrides of safety provisions are to be so arranged that they cannot go unnoticed, and their activation and condition are to be alarmed and indicated at the associated remote station. The override is to be arranged to preclude inadvertent operation and is not to deactivate alarms associated with safety provisions. The override mechanism to disconnect safety provisions is to be fitted at the associated remote station, except that where a centralized control and monitoring station is fitted, the override mechanism may be fitted at the centralized station instead. 325
TCVN 6474-9 : 2007
(6)
Adjustable Set-points Where means are provided to the field adjustable set points, either locally or remotely, positive indication of the value of the set point is to be clearly identified at the control location.
7.7.7
Shutdown Systems (1)
General Shutdown systems are to comply with the requirements of safety systems given in 7.7.6, except that systems supplied in accordance with 7.8, as applicable, are not to be automatically actuated and need not be fail safe.
(2)
Safety Analysis Where alarm and shutdown functions are required, a Safety Analysis Function Evaluation (SAFE) Chart is to be provided for equipment packages with their own control/shutdown panels, as well as for individual process components protected by a common safety shutdown system.
(3)
Emergency Shutdown (a)
General
Shutdown is to take place within 45 seconds or less as may be considered necessary for the safety of the plant after activation of the ESD system at a manual ESD station, or after detection of a trouble condition by an automatic shutdown device. Electric circuits essential to ESD that rely on the continued operation of the cable for correct operation of the system are to be of the fire resisting type . (b)
Emergency Shutdown – Automatic
See 7.3.4 (c)
Emergency Shutdown – Manual
See 7.3.5 All electrical circuits used in the manual ESD system are to be dedicated to this purpose and hard wired. 7.7.8 326
relief valves
TCVN 6474-9 : 2007 (1)
General Where spare relief valves are provided, the upstream block valve is to be locked closed and the downstream block valve is to be locked open to prevent the relief valve from being over-pressurized due to the leakage of the upstream block valve. The practice of using check valves in lieu of downstream block valves is not permitted. The upstream block valve is to have a full bore area equal to or greater than the pressure relief valve inlet. Similarly, the downstream block valve is to have a full bore area equal to or greater than the pressure relief valve outlet.
(2)
Provisions for Testing Provision is to be made for periodic testing of each relief valve without removing it from the line or vessel. Where necessary, relief valves are to be individually equipped with an inlet block or check valve and test connection so that an external pressure source can be applied.
(3)
Block Valve Locking Devices Any block valve upstream or downstream of a relief valve or rupture disc is to be equipped with a carseal or locking device to prevent the relief valve from being isolated while in service.
7.7.9
Shutdown valves, blowdown valves, diverter valves Automatically actuated shutdown, blowdown or diverter valves are to be equipped with position indicators at the valve operating station, or be of a type that valve position (open or closed) is externally obvious.
7.8 Fire Protection and Personnel Safety
7.8.1
Scope
The requirements of fire protection and personnel safety are appplicable for hydrocarbon process systems on floating installlation. The fire protection and personnel safetyto comply with this appendix . Fire Fighting Systems supplying services other than oil or gas production are to be in accordance with TCVN 6259-5:2003 and TCVN 5314:2001, depends on type of floating installation. 7.8.2
Fire Fighting Systems
7.8.2.1 Firewater Systems Fixed water fire fighting systems are to be provided as follows: 327
TCVN 6474-9 : 2007 (1) Piping (a)
General: Water fire fighting systems are to be capable of maintaining a continuous supply in the event of damage to water piping. Piping is to be arranged so that the supply of water could be from two different sources. Isolation valves are to be provided such that damage to any part of the system would result in the loss in use of the least possible number of hydrants, water spray branches, or foam water supplies. In most facility arrangements, this will require a loop type fire main. Connections of the primary and standby pump supplies are to be as remote from each other as possible..
(b)
Materials: Materials rendered ineffective by heat are not to be used in firewater piping systems.
(c)
Charging: The firewater distribution system may be maintained in a charged or dry condition. Where a system is maintained dry, relief devices and additional pipe bracing is to be considered to prevent damage to the piping system due to water hammer when the system is charged. When plastic pipe that passes only Level 3 fire endurance test is used, the firewater system design is to be pressurized (wet main) or be permanently in a charged condition..
(d)
Piping Maintenance: The distribution system is to be maintained such that internal and external corrosion of the piping is minimized. In areas where the system is subject to freezing, steps are to be taken to prevent freezing. For instance, drains, circulation loops or other means may be provided for cold water protection. If drains are provided, they are to be located at the lowest points in the system.
(2) Fire Pumps (a)
General: There are to be at least two independently driven and self-priming fire pumps. The fire pumps, together with their respective source of power, fuel supply, electric cables, lighting, ventilation, piping and control valves, are to be located such that a fire in any one location will not render both fire pumps inoperable. One of the two pumps is to be designated as the primary fire
328
TCVN 6474-9 : 2007 pump, and the other as the standby fire pump. At least one of the pumps is to be diesel engine driven, unless the emergency power supply can supply the load for an electric motor driven pump (b)
Capacity: The primary and standby fire pumps are each to be capable of supplying the maximum probable water demand for the facility. The maximum probable water demand is the total water requirement for protection of the largest single 2
fire area plus two jets of firewater at a pressure of at least 3.5 kg/cm (50 psi) Multiple-pump installations will be considered in lieu of a single primary and standby pump installation, provided they are arranged in such a manner that a fire in one area would not reduce the available supply of firewater required to handle that fire A means is to be provided for periodic testing of each fire pump. For a typical FPSO arrangement, the maximum probable water demand includes the water supply to the water spray system for a single fire on the production deck as discussed above, the water supply to the foam system on the tanker deck below, plus two jets of firewater. To determine the maximum probable water demand, the fire risk areas on the production deck may be divided into fire zones. If a fire is being considered in a single zone, the water supply for the water spray system is to be sufficient for that zone and adjacent zones. The water spray system requirement may be ignored for adjacent zones if these zones are separated by a firewall (no less than A-60) or by an adequate distance between process components to justify such zoning. The system emergency shutdown and the equipment blowdown may be considered a safe alternative to the water spray for low hydrocarbon liquid inventory equipment such as the gas compressor units (c)
Operability and Control: Pump(s) with sufficient capacity for process water spray systems is (are) to be provided with automatic starting. In addition to the pump automatic starting requirement, pump driver starters are to be provided with means for local and 329
TCVN 6474-9 : 2007 remote operation from a permanently manned station or a fire control station. Pump discharge control valves, used to separate the section of the firewater service system and the fire pump(s), are to be fitted in an easily accessible location outside of the pump space. Diesel driven fire pumps may be provided with electrical or pneumatic starting and control systems. (d)
Pump Drivers: Pump drivers may include diesel engines, natural gas engines, or electric motors. Fuel tanks, fuel lines to engines, and power cables and starters for electric motors, are to be protected against fire and mechanical damage
(e)
Fuel Systems Fuel systems are to comply with the requirements of 7.4.3. Fuel supplies for diesel engines are to be sufficient for 18 hours operation.
(f)
Lift Columns: Water lift columns are to be encased in pipe for protection against wave action and mechanical damage, and the protective pipe is to be securely attached to the structure in order to lessen wave action damage. Corrosion allowance is to be considered when the water lift column is designed. Where pipes for lift columns pass through floating structures, penetrations are to be made by approved methods to maintain the watertight integrity of the structure. Intake strainers constructed of corrosion-resistant materials are to be fitted at the suction end of the fire pump’s water lift column
330
TCVN 6474-9 : 2007
Figure 9.7-1 Fixed Installation Fire Pump Arrangement - Two-pump Scenario
Figure 9.7-2 Fixed Installation Fire Pump Arrangement Multiple-pump (Even Power) Scenario
331
TCVN 6474-9 : 2007
Figure 9.7-3 Fixed Installation Fire Pump Arrangement Multiple-pump (Uneven Power) Scenario
Figure 9.7-4 Fire Pump Arrangement Multiple-pump Scenario for Oil Carrier Converted to Offshore Installation 332
TCVN 6474-9 : 2007 a) Single Fire with A-60 Fire Wall
b) Single Fire with an Adjacent Zone that has no Liquid Inventory
Figure 9.7-5 (a and b) Typical Fire Zones Arrangement on a Production Deck of a FPSO
(3) Firewater Stations (a)
General
Firewater stations are to be located so that each station will be readily accessible in the event of a fire. All materials that comprise the firewater station and the access to firewater stations are to be of steel or equivalent material which would not be rendered ineffective by heat. (b)
Arrangement
Firewater stations are to be located on the perimeter of process areas. The stations and their arrangements are to provide at least two jets of water not emanating from 333
TCVN 6474-9 : 2007 the same fire station to reach any part of the production facility that may be exposed to fire. The firewater stations are also to be arranged to provide protection against fire damage or mechanical damage, operation free from interference by other emergency activities, and effective coordination with other stations. (c)
Monitors and Nozzles 2
Monitors are to be sized for a minimum flow of 1,892 liters/min. at 7.3 kg/cm (500 gpm at 100 psig).
Nozzles are to be adjustable from straight stream to full fog and to have a nozzle diameter of at least 12 mm (0.5 in.). Monitors and nozzles are to be of corrosion-resistant materials, and/or be protected with a suitable coating to protect the equipment from the offshore environment. All nozzles are to incorporate means for a shut-off.. (d)
Hoses
Fire hoses located outside, in the production area, are to be of a noncollapsible type mounted on reels. The hoses are to be of material resistant to oil and chemical deterioration, mildew and rot, and exposure to the offshore environment. They are to be sufficient in length to project a jet of water to any location in the areas where they may be required to be used. Each hose is to be provided with a nozzle and the necessary couplings. The maximum length of hose is not to exceed 30 m (100 ft.). For hoses located in the living quarters areas, machinery spaces, or other enclosed areas, If required, Fire hoses are to be of a collapsible type.The maximum length of hose is not to exceed 23 m (4) Water Spray (Deluge) Systems for Process Equipment (a)
General
A fixed water spray system is to be installed for the process equipment. Water spray systems are to be capable of being actuated both automatically by a fire detection system and manually.
334
TCVN 6474-9 : 2007 (b)
Materials Materials rendered ineffective by heat are not to be used in A fixed water spray system
(c)
Process Equipment
Process equipment, including hydrocarbon vessels, heat exchangers, fired heaters and other hydrocarbon handling systems, are to be protected with a water spray system. The system is to be designed to provide a water density of 10.2 2
liters/min/m of exposed surface area for uninsulated vessels, or 6.1 liters/min/m
2
of exposed surface area for insulated vessels. Process equipment support structure, including saddles, skirt, legs, but not secondary deck structural members, is to be protected with a water spray system 2
designed to provide a water density of 4.1 liters/min/m . Alternatively, the use of intumescent coatings may be acceptable in protecting the support structure, provided the selection of the fire rating of the coating is based on the results from a risk analysis and/or fire load calculation which must be reviewed and accepted by VR. The condition (intactness) of the coatings will be the subject of surveyor inspection during attendance of the unit following normal survey intervals For gas-handling equipment, such as gas compressor skids, where the hydrocarbon liquid inventory is kept minimal, a water spray system is not required if the equipment is provided with an automatic blowdown upon the process shutdown (d)
Wellhead Areas 2
Wellheads with maximum shut-in tubing pressures exceeding 42 kg/cm are to be protected with a water spray system. The water spray system is to be designed to 2
provide a minimum water density of 20.4 liters/min/m based on the protection of wellheads, ESD valves, and critical structural components including the firewall. (e)
Turret Areas (Internal Turret) 2
Internal turrets with swivel pressure ratings exceeding 42 kg/cm are to be protected with a water spray system. Turret areas, including the swivel and its associated equipment, are to be protected by a water spray system designed to 2
provide a minimum water density of 20.4 liters/min/m . (5) Foam Systems for Crude Storage Tanks 335
TCVN 6474-9 : 2007 For floating installations with crude oil storage capabilities, a foam system is to be provided for all crude storage tanks in accordance with TCVN 6259-5:2003.
If
process equipment is located or supported above crude storage areas in such a manner that a deck foam system may be obstructed by steel supporting members, foam applicators or fixed systems may be considered as an alternative. Deck foam system coverage in way of process equipment supports is to be no less effective than other tank deck areas 7.8.2.2 Dry Chemical Systems For production facilities with no liquid hydrocarbon storage capabilities and limited hydrocarbon liquid retention in processing equipment, dry chemical hose reel units may be used for fire fighting in lieu of firewater station required by section (3). Design of the dry chemical systems is to be in accordance with recognized standard (refer to NFPA Standard 17). 7.8.2.3 Fixed Fire Extinguishing Systems A fixed fire fighting system is to be provided in each enclosed space and enclosed skid module containing the following equipment: i)
Internal combustion machinery, including diesel and gas engines, having a total power output of not less than 750 kW (1000 hp)
ii)
Oil- or gas-fired boilers and other processes such as incinerators and inert gas generators
iii)
Oil fuel units. An oil fuel unit is defined as any equipment such as pumps, filters and heaters, used for the preparation and delivery of fuel oil to oil-fired boilers (including incinerators and inert gas generators), internal combustion engines or gas turbines at a pressure of more than 1.8 bar (26 psi).
iv)
Settling tanks for boilers
v)
Gas compressors
vi)
Transfer pumps for crude oil (storage facilities) and flammable liquid with low flash point such as methanol.
(1)
Gas Smothering Systems (a)
336
General
TCVN 6474-9 : 2007 1)
Storage:
Smothering medium storage location is to be outside of protected space. If gas bottles are kept in an enclosed compartment, the storage space is not to be used for purposes other than storing the bottles. The storage space is also to be situated in a safe and readily accessible position, and be effectively ventilated by a ventilation system independent of other spaces, including the protected space. 2)
Controls
Automatic release of fire-extinguishing medium for total flooding systems is not permitted. Two separate controls are to be provided for releasing the fireextinguishing medium into a protected space and to ensure the activities of the alarm. One control is to be used to discharge the gas from its storage containers. A second control is to be used for opening the valve of the piping, which conveys the gas into the protected space. This requirement is not applicable if the system is provided for a single space and the protected space 3
is relatively small (under 170 m ). Controls are to be grouped together to provide complete actuation of the system from their location. The number of release stations is to be limited to as few as possible, typically two, one at the gas storage location and another outside of the protected space. For the one outside of the protected space, it is to be located in proximity and along the main escape route of the space. 3)
Alarms
Means are to be provided for automatically giving audible warning of the release of fire-extinguishing gas into any space to which personnel normally have access. The alarm is to operate for at least a 20-second period before the gas isreleased. Alarms may be pneumatically (by the extinguishing medium or by air) or electrically operated. If electrically operated, the alarms are to be supplied with power from the main and an emergency source of electrical power. If pneumatically operated by air, the air supply is to be dry and clean and the supply reservoir is to be atomically kept charged at all times, and is to be fitted with a low-pressure alarm. The air supply may be taken from the starting air receivers. Any stop valve fitted in the air supply line is to be 337
TCVN 6474-9 : 2007 locked or sealed in the open position. Any electrical components associated with the pneumatic system are to be powered from the main and an emergency source of electrical power.. (b)
Carbon Dioxide Systems In addition to the above general requirements, the design philosophy of CO2 fire extinguishing systems is to be in compliance with Chapter II-2, Regulations 5 of SOLAS 1974 and Amendments,
(2) Foam Systems (a)
Fixed High Expansion Foam Systems Fixed high expansion foam systems are to be in accordance with Chapter II-2, Regulation 9 of SOLAS 1974 and Amendments.
(b)
Fixed Low Expansion Foam Systems Fixed low expansion foam systems may be installed in machinery spaces in addition to the required fixed fire extinguishing system. Fixed low expansion foam systems are be in accordance with Chapter II-2, Regulation 8 of SOLAS 1974 and Amendments.
(3) Fixed Water Spray Systems Fixed water spray systems are be in accordance with Chapter II-2, Regulation 10 of SOLAS 1974 and Amendments. 7.8.2.4 Paint Lockers and Flammable Materials Storerooms Paint lockers and flammable material storerooms located on production deck with deck’s area more than 4 m2 are to be protected by a fixed fire extinguishing system. One of the following systems may be considered: (1)
CO2 system designed for 40% of the gross volume of the space
(2)
Dry powder system designed for at least 0.5 kg /m3 (0.03 lb/ft3)
(3)
Water spray system designed for 5 liters/min/m2 (0.12 gpm/ft2). The water spraying systems may be connected to the unit’s fire main system.
(4)
Systems other than those mentioned above may also be considered.
For Paint lockers and flammable material storerooms on floatng installation but not located on production deck, appropriate requirements are given in 338
TCVN 6259-5:2003
TCVN 6474-9 : 2007 and TCVN 5314:2001 , depended on tpye of floating installation. 7.8.2.5 Fire fihgting system on helideck Requirements for Fire fihgting system on helideck are given in
TCVN 6259-5:2003
and TCVN 5314:2001 , depended on tpye of floating installation. 7.8.2.6 Emergency Control Station At least two emergency control stations are to be provided. One of the stations is to be located in a normally manned space such as the process control room. The other is to be at a suitable location outside of the hazardous area. The emergency control stations are to be provided with the following: i)
Manually operated switches for actuating the general alarm system
ii)
An efficient means of communication with locations vital to the safety of the installation
iii)
Manual activation of all well and process system shutdowns
iv)
Means for shutdown, either selectively or simultaneously, of the following equipment, except for electrical equipment listed in 7.8.2.7 :
•
ventilating systems, except for prime movers,
•
main generator prime movers,
•
emergency generator prime movers.
7.8.2.7 Operation after Facility Total Shutdown The following services are to be operable after a facility’s total shutdown: (1)
Emergency lighting required for evacuation from service/accommodation spaces and machinery spaces to embarkation stations. The lighting is to be provided for thirty minutes.
(2)
General alarm
(3)
Blowout preventer control system if fitted on the installations
(4)
Public address system
(5)
Distress and safety radio communications
All equipment in exterior locations which is capable of operation after activation of the prime mover/ventilation shutdown system, is to be suitable for installation in Zone 2 locations 339
TCVN 6474-9 : 2007
7.8.2.8 Portable and Semi-portable Extinguishers Locations, types, and quantities of fire extinguishers provided for the production deck area are to be in accordance with Table 9.7-4 and Table 9.7-5. For areas not specifically addressed in these tables, requirements for fire extinguishers is to be followed recognized standard. Table 9.7-4 Portable and Semi-portable Extinguishers
Classification
Water
Foam
Carbon dioxide,
Dry chemical,
Type & size
Liters
Liters
Kg
Kg
A-II
9,5
9,5
2,251
B-I
4,7
1,8
0,9
B-II
9,5
6,7
4,5
B-III
45
15,8
9,0
B-IV
76
22,52
13,5
B-V
152
452
22,52
C-I
1,8
0,9
C-II
6,7
4,5
C-III
15,8
9,0
C-IV
22,52
13,5
Note: 1
Must be approved as a Type A, B, and C extinguisher
2
For outside use only
Classification of Portable and Semi-portable Extinguishers Fire extinguishers are designated by types as follows: A
For fires in combustible materials, such as wood
B
For fires in flammable liquids and greases
C
For fires in electrical equipment
340
TCVN 6474-9 : 2007 Fire extinguishers are designated by size, where size I is the smallest and size V is the largest. Sizes I and II are portable extinguishers, and sizes III, IV and V are semi portable extinguishers. Table 9.7-5 Classification and Placement of Portable and Semi-portable Extinguishers Space
Classification
Quantity & location
Safety areas Main control room
C-I or C-II
2 near the exit (See Note 1 )
Stairway enclosure
B-II
Within 3m of each stairway on each deck level
Corridors
A-II
1 in each main corridor, not more than 45m apart
Lifeboat embarkation & lowering
--
None required
Radio room
C-I or C-II
2 near the exit (See Note 1)
Paint storerooms
B-II
outside each room in vicinity of exit
stations
(See Note 2 ) Storerooms
A-II
2
1 for every 232m or fraction thereof, located in vicinity of exits, either inside or outside of spaces (See Note 2)
Workshop and similar spaces
C-II
1 outside each space in vicinity of an exit (See Note 2)
ENCLOSED MACHINERY SPACES Gas/oil-fired boilers: spaces
B-II
2 required in each space
Either main or auxiliary, or their B-V
1 required in each space
containing gas/oil-fired boilers,
fuel oil units
341
TCVN 6474-9 : 2007 Internal combustion
B-II
1 for every 745kW but not less than 2 nor more than 6 in each space
or gas turbine machinery spaces
B-III
1 required in each space
ENCLOSED AUXILIARY SPACES Internal combustion engines or gas B-II
1 outside the space containing engines or
turbines
turbines in vicinity of exit (See Note 2)
Electric emergency motors or gas C-II
1 outside the space containing motors or
turbines
generators in vicinity of exit (See Note 2)
Steam drive auxiliary
--
None required
Fuel tanks
--
None required
B-II
1 required in vicinity of crane cab exit
Production areas
B-III or B-IV
(See Note 3)
Open areas
B-II
1 for every 3 internal combustion or gas
MISCELLANEOUS AREAS Cranes with internal combustion engines
turbine engines C-II
1 for every 2 electric generators and motors of 3.7 kW or greater
Turret area for internal turret
B-III or B-IV
1 for each turret area o
o
CHEMICALS AND FUELS WITH FLASH POINT BELOW 60 C~140 F Pump room
B-II
1 required in vicinity of exit (See Note 4)
Storage tank area
BV
required on open deck capable of reaching the storage tanks, tank vents, and transfer connections (See Note 4)
342
TCVN 6474-9 : 2007 NOTES: 1
One of which must be placed inside (dry chemical extinguishers not recommended for these applications).
2
Vicinity is intended to mean within 1 meter (3 ft.).
3
One B-III or B-IV extinguisher is to be provided at every entrance to any escape route, under no circumstances are two extinguishers to be placed more than 15.24 m (50 ft.) apart.
4
For methanol, foam extinguishers may be considered if the extinguishers are of the polar solvent type foam (alcohol-resistant type)
7.8.3
Fire and Gas Detection and Alarm Systems
7.8.3.1 Fire Detectors Open or enclosed areas are to be provided with automatic fire detection such that all potential fire outbreak points are monitored. The automatic fire detection system will sound an alarm and initiate necessary ESD functions for the facility. 7.8.3.2 Gas Detectors (1) Combustible Gases In all enclosed and semi-enclosed areas that might accumulate combustible gases, gas sensors of an explosion (flame)-proof type are to be . Sensors are also to be provided at fresh air inlets to non-classified areas (2) Hydrogen Sulfide Where hydrogen sulfide gas may be present in the well fluid in excess of 20 ppm, hydrogen sulfide gas detection systems are to be installed. (3) Detector Set Points The low and high gas alarm set points are to be 20% L.E.L. and 60% L.E.L. for combustible gases, and 10 ppm and 50 ppm for hydrogen sulfide. ESD functions are to be initiated upon high gas detection 7.8.3.3 Smoke Detectors A smoke detection and alarm system is to be provided for control rooms, switchgear rooms, and other areas where slow-developing fires might be expected. 7.8.3.4 Alarm Panel 343
TCVN 6474-9 : 2007 A master fire and gas panel is to be provided to receive and process all fire and gas detection signals. The panel is to be located in the central control room or other normally manned non-classified area. 7.8.3.5 General Alarm Means are to be provided for manually activating a general alarm system capable of producing a distinctive audible sound in all areas of the facility. Alarm-actuating devices are to be located at points of egress from accommodation areas, process areas, and machinery spaces 7.8.4
Structural Fire Protection
7.8.4.1 General The structural fire protection requirements are intended to address the need for fire protection of boundaries separating new and/or existing areas/spaces onboard the installation from the process facility equipment. Existing spaces that do not share common boundaries with the process facility equipment are to be treated based on the requirements that were in effect at the time of construction. Newly built spaces that do not share common boundaries with the process facility equipment and all portable/temporary living quarters are to comply with the latest Rule requirements 7.8.4.2 Requirements The minimum fire integrity of bulkheads and decks is to be as prescribed in Table 9.7-6 and Table 9.7-7: Windows and sidescuttles that face the production facilities are to possess a fire rating equivalent to the bulkheads in which they are fitted..
344
TCVN 6474-9 : 2007 Table 9.7-6: Fire Integrity of Bulkheads Separating Adjacent Spaces/Areas
1) Control Stations including
Central
Process
Control
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11)
(12)
A-0d
A-0
A-60
A-0
A-15
A-60
A-15
H-60
A-60
A-60
*
A-0
C
B-0
B-0
B-0
A-60
A-0
H-60
A-0
A-0
*
B-0
B-0
A-60
A-0
H-60
A-0
A-0
*
C
A-60
A-0
H-60
A-0
A-0
* b
B-0
Rooms 2) Corridors
A-0 b 3) Accommodation
C
B-0
Spaces
A-0 b
4) Stairways
B-0
B-0
A-0 b
A-0 b
5) Service Spaces
C
A-0 b A-60
A-0
H-60
A-0
A-0
*
B-0
*a
A-0 a
H-60
A-60
A-60
*
A-0
-
A-0a,c
H-0
A-0
A-0
*
A-0
---
H-60 H-60
*
H-60
-
A-0
*
A-0
10) Service Spaces
A-0
*
A-0
(high risk)
A-0c -
*
(low risk) 6)MachinerySpaces of Category A 7) Other Machinery Spaces 8) Process Areas, Storage Areas,
Tank Wellhead/
manifold Areas 9) Hazardous Areas
11) Open Decks 12)
Sanitary
and
C
Similar Spaces
Notes: applicable for tables 9.7-6 and 9.7-7 345
TCVN 6474-9 : 2007 C
bulkheads constructed of non-combustible materials
Symbols from a to d and X are meaning as follows: (a) If a space contains an emergency power source or components of an emergency power source, and adjoins a space containing a unit’s service generator or components of a unit’s service generator, the boundary bulkhead or deck between those spaces is to be an A-60 class division. (b) not use any type of structure described above and below (c) Where spaces are of the same numerical category and subscript (c) appears in the tables, a bulkhead or deck of the rating shown is only required when the adjacent spaces are for a different purpose. For example, in category (10), a galley next to another galley does not require a bulkhead, but a galley next to a paint room requires an A-0 bulkhead. (d) If the results of a Risk Analysis or Fire Load Analysis justify such, an “A-60” fire division may be used in lieu of an “H-60” bulkhead. *
Where an asterisk appears in the tables, the division is to be of steel or equivalent material, but is not required to be of an A-class standard. However, where a deck is penetrated for the passage of electric cables, pipes, and vent ducts, such penetrations are to be made tight to prevent the passage of flame and smoke. Where an X appears in the table, the configuration is not allowed.
346
TCVN 6474-9 : 2007 Table 9.7-7 Fire Integrity of Decks Separating Adjacent Spaces/Areas Space above
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11)
(12)
A-0
A-0
A-0
A-0
A-0
A-60
A-0
H-60
A-0
A-0
*
A-0
2) Corridors
A-0
*
*
A-0
*
A-60
A-0
H-60
A-0
A-0
*
*
3) Accommodation Spaces
A-60
A-0
*
A-0
*
A-60
A-0
X
A-0
A-0
*
*
4) Stairways
A-0
A-0
A-0
*
A-0
A-60
A-0
H-60
A-0
A-0
*
A-0
A-15
A-0
A-0
A-0
*
A-60
A-0
H-60
A-0
A-0
*
A-0
A-60
A-60
A-60 A-60
A-60
*
A-60
H-60
A-
A-60
*
A-0
Space below 1) Control Stations including Central Process Control Rooms
5) Service Spaces (low risk)
6)
Machinery
Spaces
of
Category A
7) Other Machinery Spaces
8) Process Areas, Storage Tank
60
a
Areas,
A-15
H-60
A-0
H-60
A-0
X
A-0
H-
A-0
H-60
A-0
*
a
a
H-60
H-
60
wellhead/
H-0
A-0
A-0
*
A-0
---
---
H-60
---
H-60
60
manifold Areas
9) Hazardous Areas
A-60
A-0
A-0
A-0
A-0
A-60
A-0
--
-
A-0
-
A-0
10) Service Spaces (high risk)
A-60
A-0
A-0
A-0
A-0
A-0
A-0
H-60
A-0
A-0
*
A-0
*
A-0
C 11) Open Decks 12)
Sanitary
and
Similar
*
*
*
*
*
*
*
--
-
*
A-0
A-0
*
A-0
*
A-0
A-0
H-60
A-0
*
*
Spaces
7.8.4.3 Wellhead Areas A-0 firewalls are to be used to provide protection from potential uncontrolled flare front wellheads with shut-in pressure exceeding 42 kg/cm2 (600 psi). These firewalls are 347
TCVN 6474-9 : 2007 independent of the requirements for structural fire protection of spaces. The intent of these firewalls is to provide protection for escape routes, temporary refuges, lifeboat embarkation stations, fire pumps and potential fire hazards. The dimensions of the firewall and distance from the wellhead are to be determined based on the results from fire load calculations or other recognized method. 7.8.4.4 Fired Vessels A-0 firewalls are to be used to provide protection from potential fire hazard of fired vessels. These firewalls are independent of the requirements for structural fire protection of spaces. The intent of these firewalls is to provide protection for escape routes, temporary refuges, lifeboat embarkation stations, fire pumps and potential fire hazards. The dimensions of the fire wall and distance from the direct fired heaters are to be determined based on the results from fire load calculations or other recognized method. 7.8.4.5 Helideck All helidecks are to be constructed of steel or other material which provides equivalent structural and fire integrity properties to that of steel. Helidecks which form the deckhead (roof) of the accommodations are to be insulated to an A-60 class standard. If the helideck is located less than one (1) meter above the deckhouse top, the helideck is to be constructed to an “A” class standard. Deckhouse roofs (below the helideck) are to have no openings. 7.8.4.6 Ventilation Ventilation are to be in accordance with the requirements contained in TCVN 6259:2003 and TCVN 5314:2001 . 7.8.4.7 Penetrations All penetrations through bulkheads and decks are to have the same fire integrity as the bulkhead and deck through which they penetrate. 7.8.4.8 Materials/Certification All materials used in the construction of structural fire divisions and protection of the penetrations are to be certified for the fire rating in which they are fitted. This includes structural fire protection and thermal insulation, joiner bulkheads, doors, HVAC ducts, flooring materials, windows, fire dampers, etc. 7.8.5 348
Muster Areas
TCVN 6474-9 : 2007 7.8.5.1 General All units are to have a designated muster station(s) were personnel can gather prior to entering the lifeboats.. 7.8.5.2 Materials All materials that comprise the muster stations routes are to be of steel or equivalent material. 7.8.5.3 Muster Stations The muster station is to be of sufficient area to accommodate the number of personnel to be gathered. The muster station is to be located in a safe location with respect to the processing equipment. The muster station may be a meeting room inside the accommodations or may be part of the lifeboat embarkation station.. 7.8.6
Means of Escape
7.8.6.1 General Arrangement of escape routes is to be in accordance with the requirements contained in TCVN 6259:2003 and sections 7.8.6.2, 7.8.6.3 and 7.8.6.4. 7.8.6.2 Material All materials that comprise the escape routes are to be of steel or equivalent material. 7.8.6.3 Marking and Lighting of Escape Routes Escape route paths are to be properly identified and provided with adequate lighting 7.8.6.4 Escape Route Plan An escape route plan is to be prominently displayed at various points of the facility. Alternatively, this information may be included in the Fire Control or Fire/Safety Plan 7.8.7
Lifesaving Requirements
7.8.7.1 General Lifesaving appliances and equipment are to be in accordance with the requirements contained in TCVN 6259:2003
and TCVN 5319:2001 and requirements in section
7.8.7.2 7.8.7.2 Lifesaving Appliances and Equipment (1)
Work Vests When personnel baskets are used to transfer personnel from the facility to work 349
TCVN 6474-9 : 2007 boats, or vice versa, a work vest is to be provided and kept with the personnel basket for each person riding in the basket.. (2)
Breathing Apparatus For operations involving hydrogen sulfide, each person expected on the facility is to be provided with a self-contained breathing apparatus of an approved type for escape purposes. The breathing apparatus for maintenance personnel is to have a minimum of thirty (30) minutes air supply. A designated safe area with proper supply of air is also to be provided and shown on the fire control/safety plan.
7.8.7.3 Means of Embarkation Each facility is to have means of embarkation to allow personnel to leave the facility in an emergency. The means of embarkation are to consist of at least two (2) fixed ladders or stairways, widely separated, and extending from the main and cellar decks to the water line. The ladders or stairways will preferably be located near lifeboat-launching stations. 7.8.8
Personnel Safety Equipment and Safety Measures
7.8.8.1 Fireman’s Outfits All fireman’s outfits and equipment are to be of an approved type, i.e., equipment is to meet the requirements of SOLAS. The requirements below are in addition to those required by the applicable Rules and/or Regulations: (1) Fireman's Outfit A minimum of two (2) sets of fire-fighting outfits and equipment is to be provided and stowed in a suitable container. The fireman’s outfits or sets of personal equipment are to be stored as to be easily accessible and ready for use, and where more than one fireman’s outfit or more than one set of personal equipment is carried, they are to be stored in widely separated positions. One of the outfits should be readily accessible from the helicopter deck. (2) Breathing Apparatus A minimum of two (2) self-contained breathing apparatus of an approved type is to be provided and stowed with the fireman's outfits. There is to be a sufficient number of spare compressed air charges. The breathing apparatus is to have a minimum of thirty (30) minutes air supply. 350
TCVN 6474-9 : 2007 7.8.8.2 Guard Rails The perimeter of all open deck areas, walkways around accommodation spaces, catwalks and openings, are to be protected with guardrails. The requirements for guard rails are given in TCVN 6259-2:2003. In addition, Toe plates are to be provided at the base of all guardrails. 7.8.8.3 Insulation of Hot Surfaces (1) Personal Protection All exposed surfaces with which personnel are likely to come in contact are to have o
temperatures that do not exceed 71 C . If this can not be achieved, then the exposed surfaces are to be insulated or shielded. (2) Spillage Protection Surfaces with temperatures in excess of 204°C are to be protected from contact with liquid hydrocarbon spillage and mist. (3) Combustible Gases Surfaces in excess of 482°C are to be protected from contact with combustible gases (4) Protection of Insulation Insulation is to be protected from weather, oil spillage, mechanical wear, and physical damage. 7.9 Survey During Construction and Commissioning
7.9.1
Construction Surveys
7.9.1.1 General During construction of equipment components and assemblies for an Offshore Production Facility, VR Surveyors are to have access to manufacturers’ or fabricators’ facilities to witness construction and/or testing as required by the Rules. The manufacturer/fabricator is to contact the VR Surveyor to make necessary arrangements to examine equipment and components. If the VR Surveyor finds reason to recommend repairs or additional surveys, notice will be immediately given to the Owner or his Representative so that appropriate action may be taken. 7.9.1.2 Survey at Vendor's Shop Survey requirements for equipment components and packaged units at vendor's shop are 351
TCVN 6474-9 : 2007 summarized in Table 9.7-8. Each vendor is required to have an effective quality system, which is to be verified by the attending Surveyor prior to the start of fabrication. 7.9.1.3 Module Fabrication Where equipment and components are assembled as skid mounted units or modules, the Surveyor is to inspect the fit-up, piping and electrical connections, and to witness pressure and function tests of the completed assembly in accordance with approved plans 7.9.1.4 Module Hook-up Survey during hook up is to be carried out per approved procedures, and to include the following where applicable: (1) All piping hook up is to be verified for compliance with approved drawings and procedures. All welds are to be visually inspected, and non-destructive testing (NDT) carried out as required. Upon completion of hook up, the affected sections are to be proven tight by hydrostatically testing to 1.5 times the design working pressure. (2) All electrical hook up is to be verified for compliance with the approved drawings and procedures. Proper support for all cables and proper sealing of cable entries to equipment are to be verified. Upon completion of all hook up, the affected sections of the equipment and cabling are to be insulation tested and proven in order. All grounding is also to be verified in order. (3) All instrumentation hook up is to be verified for compliance with the approved drawings and procedures. All tubing supports are to be verified. Upon completion, all systems are to be functionally tested and proven in order. (4) All mechanical equipment hook up is to be verified for compliance with the approved drawings and procedures, including the grounding of the equipment. Upon completion, all equipment is to be functionally tested and proven in order. 7.9.2
Commissioning and Start-up Surveys
The start-up and commissioning of all hydrocarbon production systems are to be verified by an attending VR Surveyor. The scope of the survey is to include the following: 7.9.2.1 The start-up and commissioning are to be in accordance with the approved start-up and commissioning procedures.
352
TCVN 6474-9 : 2007 7.9.2.2 Verify personnel safety precautions to be taken during commissioning, which are to include checks of operational readiness of all lifesaving, fire and gas detection, fire fighting equipment, ESD systems, unobstructed escape routes, etc. 7.9.2.3 Verify establishment of communication procedures prior to commissioning. 7.9.2.4 Verify that emergency procedures are provided to deal with any contingencies such as spillage, fire, and other hazards. Drills may have to be carried out to ensure the readiness of these procedures. 7.9.2.5 Verify start-up and testing of all support utility systems, including main and auxiliary sources for the process system, prior to commissioning.. 7.9.2.6 Verify proper hook-up and testing of the entire process system, prior to commissioning. This is to include testing of the entire system for leaks, of the process control functions and the emergency shutdown system.. 7.9.2.7 Verify purging of the entire production system of oxygen to an acceptable level, prior to the introduction of hydrocarbons into the product ion system. 7.9.2.8 Verify the introduction of hydrocarbon into the process system, and the system’s capability to control the flow of the well affluent in the system in a stabilized manner, without undue control upsets. 7.9.2.9 Verify the starting up of the flare system, if applicable, including precautions taken to eliminate the risk of explosion or fire. The functional capability of the flare system is to be verified. 7.9.2.10Verify that the post-commissioned process system is in satisfactory functioning order for a duration of at least 12 hours. Equipment required to be verified but not used during the start-up and commissioning is to be identified for verification at the next annual survey. 7.9.3
Start-up and Commissioning Manual
7.9.3.1 Functional Testing Procedures During commissioning, the following systems are to be functionally tested in accordance with approved procedures. (1) Piping and Equipment (a)
Pressure/Leak Test
353
TCVN 6474-9 : 2007 (b)
Purging
(2) Utility Systems (a)
Power Generation (Main & Emergency)
(b)
Process Support Facilities
(c)
Instrument Air
(d)
Cooling Water
(3) Fire Fighting and Safety Systems (a)
Fire Pumps
(b)
Fixed Fire Fighting Systems
(c)
Manual Equipment
(d)
Lifesaving Equipment
(4) Detection and Alarm (a)
Fire Detection
(b)
Gas Detection
(c)
Fire and Gas Panel
(d)
ESD Systems
(5) Process Systems (a)
Flare (pilot, ignition, snuffing and flare operational tests)
(b)
Instrumentation and Control (wellhead control and process control system)
(c)
Safety Shutdown Valves
(d)
Process Components
7.9.3.2 Start-up Procedure A step by step procedure is to be followed for the displacement of air or other fluid from the process systems prior to start-up. The Surveyor is to be permitted access to suitable vantage points to verify that the start-up procedures are satisfactorily accomplished. The Surveyor is to observe the facilities operating at the initial production capacity for at least a 12 hour period of uninterrupted normal operation. As applicable, the Surveyor is also to observe the facilities operating at various capacities under various conditions.
354
TCVN 6474-9 : 2007 Table 9.7-8 Construction Survey
A
B
C
Production Vessels
x
x
x
Storage Tanks
x
x
x
Heat Exchangers
x
x
x
Fired Vessels
x
x
x
D
E
Hydrocarbon production process systems
Meters, Strainers, Filters and Other Fluid Conditioners < 254 mm and 1,033 MPa > 254 mm or 1,033 MPa
x x
x
x
Pumps 2
< 7 kg/cm (100 psi) and 757 liters/min
x
2
> 7 kg/cm (100 psi) or 757 liters/min
x
x
Compressors < 686 kPa and 28,3 m
3
> 686 kPa and 28,3 m
3
x x
x
Flowlines and Manifolds
x
x
x
Scraper Launchers/Receivers
x
x
x
Packaged Process Units
x
x
x
x
Flare Systems
x
x
Subsea Systems
x
x
x
x
PROCESS SUPPORT SYSTEMS Pressure Vessels o
< 686 kPa and 93,3 C o
> 686 kPa or 93,3 C
x x
x
x
Heat Exchangers o
< 686 kPa and 93,3 C o
< 686 kPa or 93,3 C Pumps
x x
x
x x 355
TCVN 6474-9 : 2007 A
B
C
D
Air Compressors
E
x
Engines And Turbines < 100 kW
x
> 100 kW
x
x
Packaged Support Systems < 686 kPa and 93,3 oC > 686 kPa or 93,3 oC
x x
x
x
x
ELECTRICAL SYSTEMS Generators < 100 kW
x
> 100 kW
x
Motors < 100 kW
x
> 100 kW
x
x
Switchboard
x
INSTRUMENT AND CONTROL SYSTEMS Control Panels
x
FIRE PROTECTION & SAFETY EOUIPMENT Fire Pumps Alarm Panels
x x
Fire Extinguishing Systems (Components) COMPONENT SKID STRUCTURE
x x
Index: A
VR
attendance at Vendor's shop to verify materials for compliance with
drawings/specification and their traceability record, and to review welding and NDT specifications and procedures, and welder and NDT personnel qualification records.. B 356
VR attendance at Vendor's shop during critical phases of fabrication such as fit-up,
TCVN 6474-9 : 2007 alignment, and NDT examination. C
VR attendance at Vendor's shop to witness and report on pressure testing.
D
VR attendance at Vendor's shop to witness and report on operational tests to insure proper functioning of equipment.
E
Exempt from VR Shop Inspection and Testing when Vendor or manufacturer has provided acceptable documentation that component is designed, manufactured, and tested in accordance with an applicable standard or code.
Notes: Prior to the commencement of the construction surveys listed above, VR should have completed the review of any documentation submitted for systems and components as listed in 7.2. Table 9.7-9 Specific Testing Requirements on construction
The following specific tests, if required, are to be witnessed by the VR Surveyor. Other tests required by project specifications may also be witnessed and reported on by the Surveyor 1
Pressure Vessels (1)
Each vessel is to be subjected to a hydrostatic test which at every point in the vessel is at least equal to 1.5 times the maximum allowable working pressure.
(2)
For pressure vessels that cannot be safely filled with water, a pneumatic test equal to 1.25 times the maximum allowable working pressure is to be performed.
2
Pumps (1)
Each pressure casing or pressure-retaining part is to be hydrostatically tested with water at ambient temperature at a minimum of 1.5 times the maximum allowable casing pressure.
(2)
An operational test of the pump is to be performed to demonstrate satisfactory performance.
3
Compressors (1)
Pressure and operational tests, identical to items 1 and 2 under Pumps, are to be performed. 357
TCVN 6474-9 : 2007 (2)
Each compressor intended for toxic or flammable gas service is to be pressurized with an inert gas to the rated discharge pressure. The casing is to be held at this pressure for a minimum of 30 minutes to check for gas leaks, when subjected to a soap-bubble test or to another approved leak test.
4
Gas Turbines (1)
Pressure and operational tests, identical to items 1 and 2 under PUMPS, are to be performed.
(2) 5
See API Standard 616 for details of the mechanical running test.
Low Pressure Storage Tanks – 0.011 to 1.05 kg/cm2 (1)
Depending on the design of the tank, each storage tank is to be subjected to a combination hydrostatic-pneumatic test, or a completely hydrostatic test.
(2)
If the tank has not been designed to be filled with liquid to the tank, the tank is filled with water to its high liquid design level, and a test pressure of 1.25 times, design pressure of the vapor space is applied to the vapor space.
(3)
If the tank has been designed to be filled with liquid to the tank top, it is to be hydrostatically tested with a pressure under the topmost point equal to 1.25 times the vapor space design pressure.
(4)
Partial vacuum tests are to be conducted for tanks that are designed to withstand the partial vacuum.
6
Atmospheric Storage Tanks (1)
Atmospheric storage tanks are to be hydrostatically tested to the maximum liquid head to which the tank is likely to be subjected.
7
Piping Systems (1)
All piping systems are to be hydrostatically leak-tested prior to being placed into service. The test pressure is to be 1.5 times the design pressure, or 3.5 2
kg/cm (50 psig), whichever is greater. (2)
Where it is necessary to perform a pneumatic leak test, the test pressure is to be 1.1 times the design pressure.
(3)
All joints, including welds, are to be left uninsulated and exposed for examination during leak testing.
358
TCVN 6474-9 : 2007 8
Electrical Systems (Generators & Motors) (1)
Check windings for dryness. It is recommended that space heating be operated for a sufficient time prior to startup to assure dryness.
(2)
Measurement of stator insulation resistance to the motor or generator frame is to be made with an instrument applying a minimum of 600 volts across the insulation. The suggested minimum insulation resistance is 2.0 meghoms; new or rebuilt machines should provide at least 10 megohms in insulation resistance readings.
(3)
If generators are to be operated in parallel, check their phase rotation and the synchronizing circuits for proper operation.
(4)
Check motor starter overload relay heater elements for proper sizing.
(5)
Check circuit breaker trip settings and fuse sizes.
(6)
Jog motors to check for proper direction of rotation, but only after uncoupling any loads which might be damaged by reverse rotation.
(7)
Check motor-to-load and generator-to-prime mover alignments.
(8)
Perform an insulation test of all electrical circuits to ensure that cables are not damaged during installation.
(9)
Ensure all components are properly grounded.
(10)
After motors and generators are started, check for abnormal line currents, vibration, and high bearing temperatures.
(11)
Witness full-load heat run and saturation curve tests for the first unit of a particular design.
9
Electrical Systems (Switchboards) (1)
Check all bus-bars for correct sizing and spacing.
(2)
Check all components for correct voltage and current rating.
(3)
Ensure all components are properly grounded.
(4)
The various circuits of switchboard and panelboard assemblies are to be tested by conducting dielectric strength test and insulation resis tance measurements.
(5)
Satisfactory tripping and operation of all relays, contactors and various safety devices is to be demonstrated. 359
TCVN 6474-9 : 2007 10 Instrument and Control System (1)
Witness calibration of all pressure, level and temperature switches necessary for functioning of controls in accordance with SAFE Charts.
(2)
Review calibration records of all other instruments.
(3)
Ensure all instruments used as pressure-retaining parts have correct pressure ratings.
(4)
Ensure all electrical/electronic instruments to be installed in a hazardous location are suitable for that environment.
(5)
Ensure all electrical/electronic instruments are properly grounded.
(6)
Ensure all electrical circuits are installed in a 'fail safe' manner, that is all circuits in normal working state are to be electrically continuous, and noncontinuous when in an abnormal state.
(7)
Check logic functions with normal voltage applied to the control circuits, but preferably with the power circuits not energized.
(8)
Check each sensor and end device individually for proper operation before incorporating them into the system.
7.10 Survey for Maintenance of Class
7.10.1
Annual Survey
At each Annual survey, the Surveyor is to verify the effectiveness of the following items by visual examination and operational testing, as appropriate (1) Examination of corrosion protection system (2) Examination and testing of remote shutdown arrangements for fuel and ventilation equipment (3) Examination and testing of safety shutdown devices (4) Examination and testing of Emergency Control Stations (5) External examination and testing of safety relief valves (6) External examination during operation of all machinery, pumps and pumping arrangements, including valves, cocks and pipes (7) Examination of fire hoses, nozzles, and spanners at each fire station (8) Examination of fire protection system, including fire water pumps and related piping, 360
TCVN 6474-9 : 2007 hydrants, control valves and alarm systems (9) Examination of personnel protection, rescue and escape systems and devices, including alarm devices and emergency lighting for escape routes, landing platforms, etc. (10)General examination of structure, piping, electrical systems and machinery foundations for damage, deterioration, or hazard. (i.e., flare tower or ground flare, production systems, power generation, etc.) (11) Examination of enclosed hazardous areas, including ventilation, electric lighting, electricfixtures and instrumentation (12)Verification of the integrity of explosion-proof equipment (13) Operational test of emergency lighting systems, navigation and obstruction lights (14) External examination of boilers, separators, and similar process equipment and associated relief valves (15) Examination of steam-generating units. 7.10.2
Special Survey
The Special Survey is to include all items listed under the Annual Survey with the following additions: (1) Checking and weighing the contents of fixed fire protection systems, including the capability and stability of storage foam liquids. Blowing through and ensuring that piping for fixed fire extinguishing systems are not choked. (2) Non-explosion proof electric motors are to be examined, including automatic power disconnect to motors that are arranged to shut down in case of loss of ventilation. (3) Gauging of pressure vessels, heat exchangers, and storage tanks, as considered necessary (4) Internal examination of pressure vessels, pumps, compressors, and safety relief valves (5) Random thickness gauging of process piping, as considered necessary Hydrostatic testing of process related piping systems to 1.25 times the maximum allowable working pressure as considered necessary. (6) Lube oil examination record review 361
TCVN 6474-9 : 2007 (7) Measurement of the insulation resistance of generators and motors (8) Running of generators of under load, separately and in parallel (9) Examination of cable runs, bus ducts, insulators, etc. (10) Testing of circuit breakers, relays, etc. (11)Examination of electrical equipment and circuits for possible damage or deterioration (12) Vibration checks of rotating machinery (13) Internal examination of steam and gas turbines, as considered necessary (14) Testing of protective devices for engines, turbines, and gas compressors (15) Internal examination of diesel engines and gas engines rated 1000 hp output and above, as considered necessary (16) Operational check of process control equipment.
362
TCVN 6474-9 : 2007 8 Appendix VIII: Underwater Inspection procedure 8.1 Introduction
At drydocking surveys, VR may consider to accept underwater inspection inlieu of drydocking survey if underwater inspection,which is carried out by diver is equivalent to drydocking survey. The scope of underwater inspection is to be included all items, which are normally carried out during drydocking. See requirements in section 1.5 part 8. Following are the procedures and conditions under which a properly conducted underwater inspection may be credited as a Drydocking Survey 8.2 Conditions
8.2.1
Limitations
Vessels 15 years of age or over will be subject to special consideration before being permitted to have an underwater inspection. Underwater inspection in lieu of Drydocking Survey may be restricted or limited where there is record or indication of abnormal deterioration or damage to underwater body, rudder or propeller.. 8.2.2
Thickness Gauging and Nondestructive Testing
Underwater or internal thickness measurements of suspect areas may be required in conjunction with the underwater inspection. Means for underwater nondestructive testing may also be required for fracture detection. Note: Thickness measurement of the underwater body, as required for Special Periodical Survey, are to be taken in drydock in conjunction with visual inspection of the bottom plating by the Surveyor. 8.2.3
Tailshaft Surveys
Tailshaft Surveys are to be dealt with in accordance with the applicable Rules 8.2.4
Plans and Data
Plans showing the following items are to be submitted to the attending Surveyor, together with the proposed inspection procedures for review well in advance of the inspection. (1) Location of bottom shell seams and butts (Shell Expansion), including any doublers, straps, bottom plugs and all underwater openings. 363
TCVN 6474-9 : 2007
(2) Marks or other means for orienting the diver and identifying photographs. These should include specific areas of plating, (e.g., locations of bulkheads or tanks) sea suction and discharge openings, propeller blades and rudder surfaces. (3) Reference data and instructions to the diver for any necessary underwater operations such as means of access to rudder bearings and for determining clearances of rudder bearings or propeller shaft strut and stern bearings. 8.2.5
Underwater Conditions
The vessel’s bottom is to be sufficiently clean and the sea water clear enough to permit meaningful examination and photography (if necessary) by the diver. Where possible, the examination should be carried out in protected waters, preferably with weak tidal streams and currents and with the floating unit at light draft. Overall or spot cleaning may be required at the discretion of the attending Surveyor. Sufficiently clean is taken to mean that sections of the underwater body, including flat keel plating forward, amidships and aft, are cleaned to the extent that the Surveyor can determine the condition of the plating, welding and the coating. Additional cleaning may be necessary. Sea water clear enough means the underwater visial range is 5 m or more. 8.3 Physical Features
The following physical features are to be incorporated into the floating unit’s design in order to facilitate the underwater inspection. When verified, they will be noted in the floating unit’s records for reference at subsequent surveys 8.3.1
Stern Bearing
Means are to be provided for ascertaining that the seal assembly on oil-lubricated bearings is intact and for verifying that the clearance or weardown of the stern bearing is not excessive. For oillubricated bearings, this may only require review of operating history and on board testing including accurate oil-loss records and a check of the oil for contamination by sea water or white metal and/or oil sample reports. These considerations are to be included in the proposals for underwater inspection procedures. For wood or rubber bearings, an opening in the top of the rope guard and a suitable gauge or wedge would be sufficient for checking the clearance by diver. Where there is any doubt with oillubricated metal stern bearings, however, weardown could be checked by 364
TCVN 6474-9 : 2007 external measurements or by use of the vessel’s wear-down gauge, where the gauge wells are located outboard of the seals or the vessel can be tipped. For use of the wear-down gauges, up-to-date records of the base depths are to be maintained onboard. Whenever the stainless steel seal sleeve is renewed or machined, the base readings for the weardown gauge are to be re-established and noted in the vessel’s records and in the survey report. 8.3.2
Rudder bearings
Means and access are to be provided for determining the condition and clearance of the rudder bearings, and for verifying that all parts of the pintle and gudgeon assemblies are intact and secure. This may require bolted access plates and a measuring arrangement. 8.3.3
Sea Suctions
Means are to be provided to enable the diver to confirm that the sea suction openings are clear. Hinged sea suction grids would facilitate this operation.. 8.3.4
Sea Valves
The sea valves and their attachment to sea chest are to be examined externally. Nonmetallic expansion pieces in sea water cooling and circulating systems are to be examined externally. 8.4 Procedures
8.4.1
Exposed Areas
An examination of the outside of the shell plating above the waterline and exposed portions of appendages is to be carried out by the Surveyor. Means are to be provided to enable the Surveyor to accomplish this visual inspection. 8.4.2
Underwater Areas
An examination of the entire vessel below the waterline is to be carried out by a certified diver using closed-circuit television with two-way communication capable of being monitored by the Surveyor, as required, or photographic documentation, or both, depending on the age and type of vessel. This is to be supplemented by the diver’s report describing and attesting to the conditions found. A copy of this diver’s report and pertinent photographs are to be submitted to the attending Surveyor. Copies are also to be retained onboard. 8.4.3
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