-
South Pars Gas Field Development Phases 22, 23 & 24
Plant: Onshore Facilities Pars Oil and Gas Company
Doc. Number : RP-2224-999-1511-021 Rev.No.: 1 Class: 1
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Page 1 of 47
INSTRUMENT CONTROL AND
SAFEGUARDING PHILOSOPHY
1 04-Jan-2011 AFC B. Khodabakhshi H.Tajik B.Yousefian F.zanjani
H.Hoseini-Nik
DETAIL ENGINEERING
0 06-07-2010 IFR A.Asghari H.Tajik B.Yousefian F.zanjani
H.Hoseini-Nik
P.M. P.D. REV. DATE DESCRIPTION PREP. CHKD. APPD.
CONTRACTOR APPD.
COMPANY APPD.
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South Pars Gas Field Development Phase 22, 23 & 24
Doc. No. RP-2224-999-1511-021 Rev. 1
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TABULATION OF REVISED PAGES
PAGE REV0 REV1 REV2 PAGE REV0 REV1 REV2
1 X X 33 X 2 X X 34 X 3 X X 35 X 4 X X 36 X X 5 X X 37 X 6 X X
38 X 7 X X 39 X 8 X X 40 X 9 X X 41 X
10 X X 42 X 11 X 43 X 12 X X 44 X X 13 X X 45 X X 14 X 46 X X 15
X 47 X X 16 X X 17 X X 18 X X 19 X 20 X X 21 X X 22 X 23 X 24 X 25
X X 26 X X 27 X 28 X X 29 X 30 X 31 X 32 X
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South Pars Gas Field Development Phase 22, 23 & 24
Doc. No. RP-2224-999-1511-021 Rev. 1
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CONTENTS 1. SCOPE
.................................................................................................................................7
2. ONSHORE
FACILITIES.......................................................................................................7
3. CODES AND STANDARDS
................................................................................................8
4. REFERENCE DOCUMENTS
...............................................................................................8
5. ABBREVIATIONS &
DEFINITION.......................................................................................8
5.1.
ABBREVIATION...................................................................................................................8
5.2.
DEFINITION.......................................................................................................................10
6. OPERATING AND CONTROL PHILOSOPHY
..................................................................10
6.1.
GENERAL.........................................................................................................................10
6.2. OPERATING
ASPECTS.......................................................................................................10
6.2.1. ONSHORE PLANT OPERATION
..........................................................................................10
6.2.1.1. NORMAL OPERATING ASPECT
......................................................................................11
6.2.1.2. ABNORMAL OPERATING ASPECT
..................................................................................11
6.2.2. LOADING AND SHIPPING OPERATIONS
..............................................................................12
6.2.3. ONSHORE PIPELINE OPERATION (OUT OF CONTRACTOR SCOP OF
WORK)...........................12 6.2.4. OFFSHORE OPERATION
....................................................................................................12
6.2.5. SOUTH PARS INTEGRATED FIBER OPTIC NETWORK (SPIFON)
..........................................12 6.3. ONSHORE SYSTEM
OVERVIEW...........................................................................................13
6.3.1. CONTROL SYSTEM
...........................................................................................................13
6.3.2. SAFETY SYSTEM
..............................................................................................................14
6.4. DESIGN CRITERIA FOR AVAILABILITY
................................................................................14
6.5. STANDARDIZATION OF EQUIPMENT
...................................................................................15
7. CONTROL
CENTERS........................................................................................................15
7.1. CONTROL BUILDING
.........................................................................................................15
7.1.1. CENTRAL CONTROL ROOM
(CCR)....................................................................................15
7.1.2. INSTRUMENTATION TECHNICAL ROOM (ITR0) IN CONTROL BUILDING
.................................15 7.1.3. ENGINEERS
ROOM...........................................................................................................15
7.1.4. PRINTER
ROOM................................................................................................................15
7.1.5. TELECOMMUNICATION
BUILDING.......................................................................................16
7.2. INSTRUMENT TECHNICAL ROOM (ITR) (SUBJECT TO CHANGE)
...........................................16 8. OPERATOR
INTERFACES)(SUBJECT TO CHANGE)
....................................................17 8.1. CONTROL
BUILDING
.........................................................................................................17
8.1.1. CENTRAL CONTROL
ROOM...............................................................................................17
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South Pars Gas Field Development Phase 22, 23 & 24
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8.1.2. PRINTER
ROOM................................................................................................................18
8.1.3. ENGINEER ROOM
.............................................................................................................18
8.2. JETTY CONTROL
ROOM....................................................................................................18
8.3. INSTRUMENT TECHNICAL
ROOM........................................................................................18
8.4. FIRE FIGHTING STATION AND NON PROCESS BUILDING
.......................................................19 8.5.
FIELD...............................................................................................................................19
8.6. SEE WATER INTAKE
..........................................................................................................19
9. CONTROL SYSTEMS)(SUBJECT TO
CHANGE).............................................................20
9.1. PROCESS CONTROL SYSTEM (PCS)
.................................................................................20
9.1.1. GENERAL ASPECT AND BASIC CONTROL
..........................................................................20
9.1.2. SUPERVISORY
FUNCTIONS................................................................................................20
9.1.3. PCS DESIGN GUIDELINES
.................................................................................................20
9.2. POWER DISTRIBUTION CONTROL SYSTEM
(PDCS)............................................................21
9.3. TANK GAUGING SYSTEM (TGS)
........................................................................................21
9.4. PROPANE AND BUTANE METERING SYSTEM (BY OTHERS)
.................................................22 9.5. PROPANE
AND BUTANE LOADING ARMS (BY OTHERS)
.......................................................22 9.6.
MARINE INSTRUMENTATION (BY OTHERS)
.........................................................................22
9.7. ASSET MANAGEMENT SYSTEM (AMS)
..............................................................................22
10. SHUTDOWN SYSTEMS
................................................................................................23
10.1. SHUTDOWN LEVELS
.........................................................................................................23
10.1.1.
GENERAL.....................................................................................................................23
10.1.2. SHUTDOWN LEVELS
.....................................................................................................23
10.1.3. DEPRESSURIZATION/BLOW
DOWN.................................................................................23
10.1.4. ELECTRICAL
ISOLATION................................................................................................24
10.1.5. INITIATION OF SHUTDOWN
.............................................................................................24
10.2. SEGREGATION OF ESD/EDP AND SD3 SAFETY
SYSTEMS.................................................24 10.3.
RESET FUNCTIONS
...........................................................................................................25
10.3.1. ESD LOGIC RESET
.......................................................................................................25
10.3.2. FIELD EQUIPMENT
RESET..............................................................................................25
10.4. INHIBIT
FUNCTIONS...........................................................................................................26
10.5. DESIGN GUIDELINES FOR SHUTDOWN SYSTEMS
.................................................................27
10.5.1. DCS/SD3 SYSTEMS
.....................................................................................................27
10.5.2. EMERGENCY SHUTDOWN SYSTEMS
...............................................................................28
10.5.3. ULTIMATE SAFELY SYSTEM
(USS)................................................................................29
10.5.3.1. GENERAL REQUIREMENTS
............................................................................................29
10.5.3.2. DEFINITION OF VALVES AND EQUIPMENT TO BE TRIPPED BY USS
...................................29
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South Pars Gas Field Development Phase 22, 23 & 24
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10.5.3.3. USS DESCRIPTION
.......................................................................................................29
10.6. INTERFACES BETWEEN ESD SYSTEMS AND OTHER SYSTEMS
.............................................29 10.6.1. INTERFACE
WITH F&G SYSTEMS
...................................................................................29
10.6.2. INTERFACE WITH PACKAGE UCPS
................................................................................29
10.6.3. INTERFACE WITH MCC
.................................................................................................29
10.6.4. INTERFACE WITH TGS
..................................................................................................30
10.6.5. DATA EXCHANGE BETWEEN ESD SYSTEM AND
PCS......................................................30 10.7.
SEQUENCE OF EVENT RECORDING (SER)
.........................................................................30
11. FIRE AND GAS SYSTEM
..............................................................................................31
11.1.
GENERAL.........................................................................................................................31
11.2. F & G SYSTEM DESIGN GUIDELINES
.................................................................................31
11.3. INTERFACES WITH OTHER SYSTEMS
..................................................................................32
11.3.1. INTERFACES WITH FIRE PROTECTION
SYSTEMS..............................................................32
11.3.2. INTERFACES WITH FIRE WATER
PUMPS..........................................................................32
11.3.3. INTERFACE WITH HVAC
SYSTEM...................................................................................32
11.3.4. INTERFACE WITH ESD SYSTEMS
...................................................................................32
11.3.5. INTERFACE WITH GENERAL ALARM
SYSTEM..................................................................32
11.3.6. DATA EXCHANGE BETWEEN F&G SYSTEMS AND PCS
...................................................32 12. PACKAGE
UNITS..........................................................................................................33
12.1.
GENERAL.........................................................................................................................33
12.2. PACKAGED UNITS CLASSIFICATION
...................................................................................33
12.3. INTERFACES BETWEEN UCP AND OTHER
SYSTEMS............................................................34
13. ELECTRICAL FIELD EQUIPMENT (PUMP, AIR COOLERS &
BLOWERS)................35 13.1. START/STOP OF EQUIPMENT -
OPENING/CLOSING OF MOV
................................................35 13.2. PUMP
START/STOP...........................................................................................................36
13.3. MOTOR CONTROL CENTER INTERFACES
...........................................................................36
13.4. ELECTRICAL DISTRIBUTION INTERFACE
.............................................................................36
14. FIELD
INSTRUMENTATION..........................................................................................37
14.1. FIELD SENSORS AND FINAL CONTROL ELEMENTS GENERAL REQUIREMENTS
.......................37 14.2. ON/OFF
VALVES...............................................................................................................39
15. SIGNAL
TRANSMISSION..............................................................................................42
15.1.
GENERAL.........................................................................................................................42
15.2. FIELD TO ITR
...................................................................................................................42
15.3. WITHIN ITR
......................................................................................................................42
15.4. FROM ITR TO CONTROL BUILDING
....................................................................................43
15.5. WITHIN CONTROL BUILDING
.............................................................................................43
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South Pars Gas Field Development Phase 22, 23 & 24
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15.6. FROM ITR TO
SS..............................................................................................................43
15.7. COMMUNICATION
LINKS....................................................................................................44
15.7.1.
GENERAL.....................................................................................................................44
15.7.2. SERIAL COMMUNICATION LINKS REDUNDANCY REQUIREMENTS
......................................44 16. POWER
SUPPLY...........................................................................................................45
17. ONSHORE /OFFSHORE PHASES 22, 23 & 24 INTERFACES
....................................45 17.1. SOUTH PARS INTEGRATED
FIBER OPTIC NETWORK (SPIFON)
..........................................45 18. ONSHORE PHASE 22,
23 & 24 SEALINE INTERFACES
............................................45
APPENDIX 1 (SUBJECT TO CHANGE)
.......................................................................................46
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South Pars Gas Field Development Phase 22, 23 & 24
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1. SCOPE
The SOUTH PARS Phases 22&23&24 Facilities Project is
part of the development of the South Pars gas field located
offshore at about 100km from the Iranian coast. The Project
includes: Two well-head platforms, A Gas Treatment Plant located
Onshore and two sea lines to be laid between
wellhead platforms and the Onshore plant to transport the
reservoir fluid, An Onshore 56 gas pipeline from the Onshore Plant
to IGAT tie-in manifold in the
vicinity of Kangan Refinery This specification defines the main
principles to be considered for the design and the Implementation
of the control & safety systems, the instrumentation of the
Onshore facilities, and the interfaces with the Phase
22&23&24 Offshore facilities.
2. ONSHORE FACILITIES
The new phases 22, 23 and 24 onshore facilities include the
following main process units: Receiving facilities Gas trains 1, 2,
3, 4 NGL fractionation units 1,2 Ethane, Propane and Butane
treatment and drying units 1,2 Sulfur recovery units 1, 2, 3, 4
Condensate trains 1, 2 Export gas compression unit MEG regeneration
unit Propane and Butane storages and loading Condensate storages
and export Sour water stripping Condensate back up stabilisation
Refrigerant units Caustic Regeneration Propane treatment Butane
treatment Ethane treatment TGT unit (1 train for each phase) DMC
Additionally to these process units the Plant includes the
following utility units: Drainage and Effluent treatment disposal
Process water handling Steam generation Fuel gas system Instrument
and Process air generation Nitrogen generation Electrical
Generation & Distribution Diesel and Emergency Electrical
Generation & Distribution Propane refrigerant storage Sea lines
Onshore pipeline See Water Intake
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3. CODES AND STANDARDS
Instrumentation and Systems will be designed and fabricated in
accordance with engineering codes and standards listed in
document:: DB 2224 999 P332 203: List of applicable codes &
industry standards"
4. REFERENCE DOCUMENTS
This philosophy is complemented by the following documents: RP
2224 130 1900 001: Safety Concept RP 2224 130 1900 002: Active fire
fighting RP 2224 999 1900 003: Fire and Gas detection RP 2224 999
1530 002: Telecommunication General Specification RP 2224 999 1511
002: Classification of Packages and DCS Serial
Interfaces DW 2224 999 1581 0001: IPCS Block Diagram DW 2224 999
1530 0002: Telecommunication general architecture DB 2224 999 P312
202: Overall process description DB 2224 999 P312 209: Safety
Systems process description RP 2224 999 1511 005: Tank Gauging
System General Requirements RP-2224-999-1511-033: Instrumentation
and Control for Packages
5. ABBREVIATIONS & DEFINITION
5.1. ABBREVIATION
The following terms and abbreviations will be used in this
document BDV : Blow Down Valve BMS : Burner Management System CCTV
: Closed Circuit TeleVision CMS : Custody Metering System CPU :
Central Processing Unit CCR : Central Control Room DCS :
Distributed Control System EDP : Emergency DePressurization EPROM :
Erasable Programmable Read Only Memory ESD : Emergency ShutDown
ESDV : Emergency Shut Down Valve EW : Engineer workstation F&G
: Fire and Gas FGS : Fire and Gas System GA : General Alarm HC :
Hydrocarbon HIPPS : High Integrity Pressure Protection System HVAC
: Heating, Ventilation, Air Conditioning I/O : Input/Output I/F :
Interface IPCS : Integrated Plant Control System
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South Pars Gas Field Development Phase 22, 23 & 24
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IS : Intrinsically Safe ITR : Instrument Technical Room JB :
Junction box LAN : Local Area Network LAS : Loading Arms System LED
: Light Emitting Diode LFL : Lower Flammable Limit LP : Local Panel
for main equipment (heater, compressor) LV : Low Voltage MP :
Manual Call Point MC : Marshalling Cabinet MCC : Motor Control
Center MLMS : Mooring Load monitoring System MOS :
Meteorological/Oceanographic System MOV : Motor Operated Valve MTBF
: Mean Time Between Failure MTIS : Marine Terminal Information
System MTTR : Mean Time To Repair OCS : Operator Control Station
OCD : Operator Control Desk PB : Push-Button PC : Personal Computer
PCS : Process Control System PDCS : Power Distribution Control
System P&ID : Piping and Instrumentation Diagram PLC :
Programmable Logic Controller PMS : Pipeline Monitoring System RAM
: Random Access Memory SBS : Ship Berthing System SC : System
Cabinet SPD 22 & 24A : Wellhead Platform 1 SPD 23 & 24B :
Wellhead Platform 2 SDV : Shutdown valve SDH: Synchronous Digital
Hierarchy SLS : Ship to Shore Link SPIFON : South Pars Integrated
Fiber Optic Network SS : Electrical SubStation TGS : Tank Gauging
system UCP : Unit Control Panel UHF : Ultra high frequency UPS :
Uninterruptible Power Supply USS : Ultimate Safety System VDU :
Video Display Unit VHF : Very high frequency XV : Process on/off
Valve KV: Sequence Valve TGTU: Tail Gas Treatment Unit
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South Pars Gas Field Development Phase 22, 23 & 24
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5.2. DEFINITION
COMPANY: PARS OIL & GAS COMPANY (POGC) or his nominated
representative.
Contractor: Shall be read P.S.A.
Vendor: Any person, firm or company which manufacture or
supply
6. OPERATING AND CONTROL PHILOSOPHY
6.1. GENERAL
The South Pars Phases 22, 23 & 24 Onshore Plant
instrumentation and control design philosophy is based on a
distributed concept, integrating: A permanently manned Central
Control Room (CCR) used to operate process
Trains and major utility units from a Distributed Control System
(DCS). A Jetty Control room located on the jetty for local
monitoring of information coming
from LPG tankers and of environmental conditions in the vicinity
of the berth. One redundant Fiber Optic communication link (via
SPIFON) will be provided to montor the required information on PCS
operating consoles in CCR.
Fourteen (14) unmanned instrument technical rooms (ITR) which
contain all the field interface units.
Inter communication between these locations, by communication
networks and by hardwired links for safety related functions.
Two wellhead Platforms normally unmanned. The Offshore platform
equipment will be monitored on consoles installed into CCR and
shared with onshore units
For See Water Intake, the individual control systems equipments
will be installed inside SS7 in dedicated instrument room. All
required information will be transferred and monitored in CCR by
one redundant communication link .
The overall control system must allow the integration and
independence of units considering plant operating and commissioning
phasing requirements into a central control building. In particular
the control and safety system shall be designed in such a way that
commissioning of one phase be possible with the other phase in
operation in the same time, and the system integration of this
phase shall be possible without the need to wait for Plant
overhaul.
6.2. OPERATING ASPECTS
6.2.1. ONSHORE PLANT OPERATION
The Phases 22, 23 & 24 Onshore Plant is controlled and
protected by an Integrated Plant Control system (IPCS). The IPCS
shall be capable of controlling the plant during start-up, normal
operation, and emergency shutdown.
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South Pars Gas Field Development Phase 22, 23 & 24
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6.2.1.1. NORMAL OPERATING ASPECT
Day to day plant operation of the process trains and major
utility units will be controlled from the CCR. The DCS operator
consoles shall be the main operating interfaces. Local panels shall
only be used where there is a need to operate, start or test major
plant equipment in the field. As an example, rotating equipment
auxiliaries (lube and seal oil, cooling water systems) shall
normally be started locally. Start-up inhibits shall be carried out
automatically as far as possible by the control system during a
start up sequence, or manually from the operator console. In normal
operation, the control system shall aim at a steady, efficient and
safe operation of the plant and should be capable of operating
between the maximum and the minimum design conditions as given in
the basis of design. Operator manipulations during normal operation
shall be restricted to adjustment of set points, change control
modes (auto, manual, cascade, ...) activate remote commands (open,
close, run, stop, ....), acknowledge alarms. Manual operation of
controls shall be limited to special cases such as: Repair of field
equipment, Start-up of rotating equipment, Infrequent and simple
operations. Roving field operators shall perform such tasks as
isolation, observation, changeover to standby equipment under the
supervision of CCR personnel. CCTV facilities for remote monitoring
of some specific areas (flares, ....) shall be available above
Operator Control desk (OCD) in CCR. Software inhibit functions
shall be available for safety systems for testing and maintenance
purposes via dedicated maintenance stations located in ITRs.
6.2.1.2. ABNORMAL OPERATING ASPECT
While operating the units, the operator shall be informed on
safety matters. Sufficient means such as trend functions,
indicators, and alarms shall be provided on DCS console in the CCR
to enable the detection of abnormal situation: abnormal operating
conditions, equipment failure, gas leaks, fire, and automatic
shut-down If the operating conditions approach the mechanical
limits of the plant equipment, the safety system shall
automatically drive the plant to a safe condition. Manual
activation of the safety shutdown systems shall be from the OCD in
CCR via hardwired PBs and/or from the field, to initiate shutdowns
or activate fire protection systems. After trips, return to normal
operation shall not be possible unless the safety shutdown systems
have been manually reset. This is to avoid the possibility of an
uncontrolled Plant re-start when the process has returned to a safe
condition.
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South Pars Gas Field Development Phase 22, 23 & 24
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6.2.2. LOADING AND SHIPPING OPERATIONS
Condensate Condensate will be transferred from tanks to ships
via dedicated condensate loading pumps. Selection of tanks and
transfer operations will be monitored from CCR OCD. Transferred
quantities will be determined using inventory data given by the
tank gauging system. LPG Propane and Butane will be transferred
from storages to ships via dedicated loading pumps, and loading
arms located on jetty. Selection of storage tanks, setting of batch
mass/volume, setting of holding/loading modes, initiation and
monitoring of loading operations will be done from CCR OCD.
Transferred quantities will be determined using Propane and Butane
metering systems data. Local monitoring of LPG loading operation
will also possible from Jetty Control Room on metering systems
workstation and local PCS station. A Marine Terminal Information
system will provide the operator with information concerning the
approach of LPG tanker to the berth and the meteorological
conditions, locally in the Jetty Control Room, and remotely in
CCR.
6.2.3. ONSHORE PIPELINE OPERATION (OUT OF CONTRACTOR SCOP OF
WORK)
All the control and monitoring functions of the pipeline shall
be accomplished at the pipeline area. There is no remote control or
monitoring facility by using the electronic signal
transmission.
6.2.4. OFFSHORE OPERATION
The Wellheads platforms (SPD 22, 24A & SPD 23, 24B) will be
normally unmanned. Monitoring and control of SPD 22, 24A & SPD
23, 24B platforms shall be performed from the CCR or locally under
supervision of CCR operator. Monitoring of SPD 22, 24A & 23,
24B is also available in SPQ1. A telemetry system (out of
Contractor scope of supply), connected to the Phases
22&23&24 Onshore DCS via SPIFON link, will allow: control
and monitoring of SPD 22, 24A & SPD 23, 24B platforms from
DCS
operator consoles in the CCR. monitoring of SPD 22, 24A &
SPD 23, 24B platforms shutdowns initiated locally
either on the local hydraulic panels or from local PBs remote
initiation of SPD 22, 24A & SPD 23, 24B platforms shutdown via
PBs on
CCR OCD CCTV facilities located above OCD in CCR will also allow
remote monitoring of SPD 22, 24A & SPD 23, 24B platforms.
6.2.5. SOUTH PARS INTEGRATED FIBER OPTIC NETWORK (SPIFON)
The SPD 22, 24A and SPD 23, 24B platform of Phases 22, 23 &
24 developments shall be connected to onshore facilities in
Assaluyeh through the existing South Pars Integrated Fiber Optic
Network (SPIFON).
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South Pars Gas Field Development Phase 22, 23 & 24
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The SPIFON Network is designed to connect all offshore platforms
to their respective onshore control building of their current
phases of development by fiber optic cable Initial existing
topology of the South Pars Integrated Fiber Optic Network (SPIFON)
includes Onshore Facilities and relevant Offshore platforms
,However the design of the SDH equipments are fully compatible with
the requirement of future phases. This integration shall be
achieved by installation of a 24-cores submarine heavy double
armored single mode fiber Optic cable, and also extension of
existing onshore ring from other phases to phases 22, 23 & 24
including all configuration and synchronization will be done by
SPIFON. The SDH nodes shall be installed in SPD22, 24A , SPD 23,
24B and phases 22, 23 & 24 onshore Telecom Building with all
necessary interfacing equipment in SDH nodes of other SPDs. The
network shall utilize SDH-STM16 ring configuration and shall be
easy to upgrade. The specification, network configuration and
protection, installation, fiber optic cables and SDH nodes, etc
shall be in full compliance with the existing SPIFON. Consequently
remote operation of SPD 22, 24A and SPD 23, 24B platforms shall be
provided by onshore facilities in Assaluyeh, Through SPIFON as well
as telecommunication facilities between platforms and onshore
facilities. The voice and data transmission from each platform to
counterpart SDH nodes shall include as a minimum, the PCS/Safety
data transmission (integration into the onshore communication over
high speed Ethernet in SDH nodes). Additionally some important
Production data, F&G, ESD system status/alarms, PABX
Connection, CCTV, Meteorological, and other telecommunication
requirements shall be transmitted to the nearby NIOC Phase 1
Development (SPQ1platform) just for monitoring purpose.
6.3. ONSHORE SYSTEM OVERVIEW
The Integrated Plant Control System (IPCS) consists of control
systems and safety systems.
6.3.1. CONTROL SYSTEM
The normal control & monitoring system is the Process
Control System (PCS) that will allow operational monitoring and
control from the CCR. The control and monitoring functions will be
implemented via a Distributed Control System (DCS) linked to other
subsystems such as: Power distribution control system (PDCS) Tank
gauging system (TGS) for Condensate , Propane and Butane storage
tanks, Propane and Butane custody metering systems (CMS) Package
programmable logic controllers (PLC) for major package equipment
The PCS shall also interface with the following systems provided by
others: Phases 22&23&24 Offshore SPIFON Phases
22&23&24 Pipeline Monitoring System (PMS)
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6.3.2. SAFETY SYSTEM
In the case of any malfunction of the plant equipment or its
associated instrumentation gives rise to hazards for personnel, or
leads to consequences of economic loss (e.g. damage of main
equipment or severe production loss), the safety systems will bring
automatically the relevant units or part of the units to a safe
condition. The lowest level of protection generally acts as an
additional loop that protects and/or trips equipment. These actions
will be performed on the DCS. The Emergency Shutdown systems are
the detection and logic systems that initiate shutdown actions and
depressurization (ESD/EDP) required by emergency situation and
applicable to the fire zones or the process units. The emergency
shutdown shall be SIL3 rated. The Ultimate Safety Systems (USS)
will be hardwired signals that provide diversified redundancy of
ESD action upon manual activation to avoid common modes of failure
with ESD/EDP systems and systematic failures (e.g. software
errors). The High Integrity Pressure Protection Systems (HIPPS) are
the detection & logic systems that stop a source of high
pressure and safely keep the pressure within the design limits with
limited release of process fluid to flare. Those systems are based
upon components of known high reliability and permit on-line
testing without reduction of trip integrity. The reliability
assessment of the system shall include the whole loop from sensor
to actuator and shall take into account operation and environment.
HIPPS systems shall only be used where it proves impractical or
prohibitively expensive to provide alternative ultimate protection.
This type of system shall be used with POGCs approval only. The
Fire and Gas systems (FGS) are the detection and logic systems that
monitor fire and gas detectors and initiate relevant actions.
6.4. DESIGN CRITERIA FOR AVAILABILITY
The IPCS systems and sub-systems shall be designed to minimize
the system failure in order to achieve safe start-up, normal
shutdown, emergency shutdown and safe, continuous, accurate, and
efficient operation with minimum maintenance. The following figures
are related to the control and logic, from system input cards to
system output cards. Control and monitoring systems (PCS/SD3)
Availability shall be better than 99.9 % with a MTTR of 4
hrs
Safety Systems (ESD/EDP, USS,FGS) Equal to SIL3(from input card
to output card) Availability shall be better than 99.99 % with a
MTTR of 4 hrs
High Integrity Pressure Protection System (HIPPS)
Availability shall be better than 99.99 % with a MTTR of 24 hrs,
Equal to SIL4
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6.5. STANDARDIZATION OF EQUIPMENT
As far as reasonably practicable, Equipment across the plant and
packaged units shall be standardized in the make and model. In
order to reduce procurement, Testing and maintenance costs. These
include. But not limited to items such as Programmable Logic
Controllers, On/Off valves, Control valves, Field transmitters,
Relief valves, Valve actuators, Instrument and tube fittings, for
which standardization is mandatory.
7. CONTROL CENTERS
7.1. CONTROL BUILDING
Appropriate facilities, air conditioning systems and lighting
including essential lighting shall be provided in Control room and
technical rooms.
7.1.1. CENTRAL CONTROL ROOM (CCR)
Plant operating consoles shall be located in the CCR. The
consoles include ancillary and related equipment e.g. hardwired
push buttons, telecommunication equipment, etc.
7.1.2. INSTRUMENTATION TECHNICAL ROOM (ITR0) IN CONTROL
BUILDING
The ITR0 shall house the following cabinets related to common
facilities: DCS, ESD, F&G cabinets including internal power
supply units and distribution,
processors units, input/output cards, communication interfaces.
SPIFON Interface facilities. Package control cabinets. DCS
historical data storage equipment. Marshalling cabinets for cross
connection between field/MCC equipment and
system I/O cards. IPCS centralized hardware. Power distribution
panel. Tank Gauging system.
7.1.3. ENGINEERS ROOM
A separate engineer's room shall be adjacent to the CCR. The
primary purpose of this room is to accommodate engineer
workstations of IPCS sub-systems.
7.1.4. PRINTER ROOM
The printer room shall house all printers and video copier.
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7.1.5. TELECOMMUNICATION BUILDING
The telecommunication building shall house the indoor equipments
of the telecommunication systems: Telephone network, Hotline
telephones, Radio systems, Plant CCTV systems, SPIFON cabinets,
etc...
7.2. INSTRUMENT TECHNICAL ROOM (ITR) (SUBJECT TO CHANGE)
The IPCS equipment shall be located in normally unmanned ITR. It
includes the following cabinets for related process units: DCS,
ESD, F&G cabinets including internal power supply units and
distribution,
processors units, input/output cards, communication interfaces
Package control cabinets Marshalling cabinets for cross connection
between field/MCC equipment and
system I/O cards Power distribution panels Fourteen separate
ITRs shall serve the areas and sections of the Plant as
follows:
- ITR 0 for common facilities, (refer to 7.1.2) - ITR 1 for Gas
Train 1,except Diesel storage& chemical storage - ITR 2 for Gas
Train 2, - ITR 3 for Gas Train 3, - ITR 4 for Gas Train 4, - ITR 5
for Sulfur Recovery units 1,2 &TGTU - ITR 6 for Sulfur Recovery
units 3,4 & TGTU - ITR 7 for Condensate Trains, Reception
Facilities and, except Sea water
supply intake and distribution network - ITR 8 for MEG
Regeneration Units, DMC, Diesel storage, Diesel generator,
chemical storage , Propane refrigerant storage & Condensate
storage - ITR 9 for Propane & Butane treatment and drying -
ITR10 for NGL fractionation, Ethane treatment and drying , Export
Gas
Compression - ITR 11 for Waste Water Treatment and all Utilities
- ITR 12 for Fire Water Area, - ITR 13 for Propane and Butane
storage & export & Flare K.O. Drum
System equipment related to Propane and Butane metering &
loading (units 149 and150) will be located in jetty building. ITRs
shall have air-conditioning units to maintain suitable
environmental conditions for the installed equipment and occasional
occupation. Refer to appendix 1 for list of process and utility
units connected to each ITR. The ITR and OCD relevant to new or
modified units will be defined during the FEED phase, based on the
plant layout.
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8. OPERATOR INTERFACES)(SUBJECT TO CHANGE)
Operator interfaces related to control and safety functions
shall be provided in several locations: Central Control Room, Jetty
Control Room, Instrument Technical Rooms, Field locations.
8.1. CONTROL BUILDING
8.1.1. CENTRAL CONTROL ROOM
The operating interface will be shared by four operating
consoles dedicated to the following plant areas: Gas Trains 1 and
2, Condensate Train 1, SRU Trains 1 and 2, Offshore platform
SPD 22, 24A and sealine 1, C2,C3,C4 Treatment TR. 1 Gas Trains 3
and 4, Condensate Train 2, SRU Trains 3 and 4, Offshore
platform
SPD 23, 24B and sealine 2. C2,C3,C4 Treatment TR. 2 Emergency
Diesel & Utilities Export Gas and Metering, MEG Regeneration,
Utilities, Flares & Blow down,
storages and offsites. Refer to appendix 1 for detail assignment
of the units to the different consoles. The assignment of the
different trains to the different consoles will be interchangeable.
Each operating console will house: Five operator control station
(OCS) for OCD 1 & 2: four for the PCS. one for ESD
and F&G function. Four operator control stations (OCS) for
OCD 3 & 4: three for the PCS. one for ESD and F&G
functions. These stations will be identical and configured in such
a way that they are operationally interchangeable.
An ESD panel with PBs hardwired to ESD systems to initiate
critical ESD/EDP
actions or USS actions per fire zone. An F&G matrix panel
that shall display the status of the F&G detection and
protection systems located in the different fire zones. The
F&G matrix shall also allow manual remote activation of the
deluge systems.
Miscellaneous telecommunication equipment such as CCTV control
panel,
Telephone sets, The utilities console will also house: A Fire
pumps remote control panel. This panel shall display the status and
faults of the fire pumps and provide manual remote activation of
fire pump start up sequence. An audible alarm shall be located in
CCR to warn the operators in case of F&G hazard. General
telecom equipment such as UHF and Marine VHF remote units,.., shall
be located on a dedicated telecom console.
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8.1.2. PRINTER ROOM
Two matrix printers will be provided for each operating console:
one shall be dedicated to process and safety alarms one shall be
dedicated to operator changes and events logging Each one shall
back up the other in case of failure. Following printers shall also
be provided: a report laser printer common for all OCS, a heavy
duty laser video copier (color printer) dedicated to engineer
workstation
and operator workstation a laser printer dedicated to engineer
workstation
8.1.3. ENGINEER ROOM
Engineer's room shall house: the PCS engineer workstations for
PCS configuration, the TGS workstation for maintenance and TGS
database configuration, the PMS workstation (not included in
Contractor scope of supply), the SPD workstation for offshore
platform (not included in Contractor scope of
supply).
8.2. JETTY CONTROL ROOM
A building located on the jetty at approximately 100km from ITR0
will include a Jetty Control Room in which will be installed the
Marine Terminal Information system workstation and the metering
workstation with associated ticket printers and will be connected
to the phases 22, 23 &24 Onshore DCS via SPIFON link. A PCS
station, provided for maintenance, will also allow the operator to
have a view on storage and jetty area operations when required. All
Jetty systems (MTIS and LAS) are in Contractors scope of supply and
contractor will make provision to interface in the Jetty Control
Room the above systems as follows: serial I/F between the DCS and
the MTIS workstation serial I/F between the DCS and the Custody
Metering System (CMS) hardwired connection between the ESD/FGS and
the LAS
8.3. INSTRUMENT TECHNICAL ROOM
Within each ITR, system maintenance and input inhibit during
field item maintenance operation shall be performed from: A
dedicated PCS station connected to PCS network, Maintenance PLC
consoles for ESD and F&G systems permanently installed in
the
each ITR. The permanent ESD / F&G maintenance console shall
also display the ESD or F&G system status (system fault, line
monitoring faults, cycle time,...), the ESD alarm file with time
stamping (refer to 10.7) or the F&G loops status.
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ESD and F&G system software/configuration modification
download and upload shall be restricted to a portable station,
password protected. This ESD and F&G system configuration
portable station shall not be permanently installed. For major
packaged units such as compressors, dedicated operator workstations
shall be provided as part of the Unit Control Panel. Engineering
workstations shall be provided if these UCPs employ programmable
logic controllers.
8.4. FIRE FIGHTING STATION AND NON PROCESS BUILDING
An alarm panel in Fire fighting station shall provide a general
overview of the status of F&G detection systems for the whole
plant. In non-process buildings (Administration buildings, service
buildings,) fire detection panels shall provide local alarming and
warning.
8.5. FIELD
Shutdown actions may be initiated locally via PBs near
equipment, main process areas,Manual call points will be installed
at strategic locations to provide for manual initiation of alarm in
the control room when a fire and gas emergency situation
occurs.
8.6. SEE WATER INTAKE
A sea water intake system is to be constructed to provide the
required water for South Pars Gas-Field Development Phases 22, 23
& 24 and other future phases located in Assaluyeh. Sea water
intake system is a vital utility and any accidental or partial or
total interruption in the water supply process generally provokes a
process shutdown. And will be connected to the Phases 22, 23 &
24 Onshore DCS via Fiber optic cable.
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9. CONTROL SYSTEMS (SUBJECT TO CHANGE)
9.1. PROCESS CONTROL SYSTEM (PCS)
9.1.1. GENERAL ASPECT AND BASIC CONTROL
Control, process interlocks and monitoring of the Plant shall be
executed from the PCS that includes the following main functions:
Provide a DCS VDU operator interface for remote control, operation
and
monitoring of the Phase 22&23&24 Onshore Plant and
Offshore platforms. Provide the display for all process and
auxiliary variables with recorded traces
(Real time and historical trend) Alarm management Regulatory
control and monitoring Sequential and control functions Data
acquisition, recording, archiving and trending functions
Measurements and control outputs from/to the field instrumentation
shall be connected to the geographically distributed DCS processors
and I/O modules located in ITRs. Redundant data highway cables
shall link the CCR DCS network with the system electronics in the
ITRs.
9.1.2. SUPERVISORY FUNCTIONS
Besides the control functionalitys, a number of functions shall
be available for plant supervision purposes. These functions shall
be: Mass balance; integrated values of corrected flows shall be
calculated to produce
mass balances per day for each process unit and overall mass
balances. These reports shall also contain figures for usage and
production of utility streams.
Logging; hourly averages of process and derived variables shall
be stored, logged and printed upon operator request.
Reporting; a flexible layout of the reporting system shall be
available for reporting selected process and derived variables over
selective periods.
9.1.3. PCS DESIGN GUIDELINES
The effect of failures of PCS devices shall be kept as low as
possible by using fail-safe design and segregation of functions.
Redundancy shall be provided for critical functions, such as power
supplies, data communication. For monitoring and control or
sequencing functions, redundant controllers with single I/O channel
configuration will be provided. I/O level redundancy shall be for
nominated I/O only and the requirement shall be further defined
during Detail Design. All control signals or sequencing functions
signals shall be provided with redundant processor & I/O's and
monitoring signals shall have non-redundant I/O cards. Note: As an
exception, monitoring signals can have redundant I/O cards based on
project requirements and will be specified during detail
design.
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Back up controller shall automatically take over primary
controller functions and control strategy in case of malfunction of
the later, and achieve continuous automatic control without process
disturbance or control upset. Back up communication device shall be
permanently tested to ensure it is not out of service. Transfer to
back up device in case of failure of primary device shall be
automatic without disrupting the system operation. Failure of data
communication link shall have no effect on operation of the PCS
controllers or any subsystems connected to PCS through serial
links. Failure of an individual OCS shall have no effect on the
operation of other OCS. For requirements related to safety
functions refer to 10.2 and 10.5.1
9.2. POWER DISTRIBUTION CONTROL SYSTEM (PDCS)
A Power Distribution Control System (PDCS) shall ensure the
supervision and control of the distribution system of the whole
facilities. The PDCS architecture shall be based on slave PLCs
distributed in electrical substations and connected via a common
network to a master PLC that will concentrate data and perform
load-shedding sequence. The PDCS shall be capable of interfacing
with all the equipment of the power distribution system (emergency
diesel generator's panel, LV/HV switchboards, UPS...). Normal
operation of the electrical network will be performed from
dedicated stations connected to PDCS network and located in CCR.
Only information necessary for process operation will be
transferred to PCS via redundant serial communication link.
9.3. TANK GAUGING SYSTEM (TGS)
Servo operated and/or radar level gauges will be installed on
the Condensate, the Propane and Butane storage tanks. They shall be
high accuracy, microprocessor based systems, suitable for inventory
control application. Level and temperature measurements will be
transmitted to the TGS main processing unit via a single fieldbus
and a single communication interface installed in instrument
cabinet. The field network shall be designed so that any failure of
one field device does not interrupt the acquisition of other tank
gauges by main processing unit. The TGS shall include a real-time
database. The standard database shall include all features suitable
for the tank farm management and inventory. Main tank inventory
data shall be sent to PCS for display on OCS, which will be the
normal operator interface with the tank gauging system. TGS
workstation in Engineer's room will mainly be used for
configuration and maintenance. It shall also ensure a back up for
tank data display in case of failure of communication link between
TGS. The provision of an Inventory Management system shall be
included in tank gauging system and communicate with the PCS by
non-redundant MODBUS protocol. The PCS will monitor the data from
tank inventory management system such as basic volumes. The PCS
will be the master of data exchanges.
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9.4. PROPANE AND BUTANE METERING SYSTEM (BY OTHERS)
A Custody Metering System (CMS), shall ensure custody
measurement for transfer of Propane and Butane to LPG tankers.
Metering skids will be installed on jetty and computers will be
installed in jetty building with common local operator interface
and ticket printers. Information will be transmitted to DCS via
SPIFON for remote monitoring on OCD in CCR.
9.5. PROPANE AND BUTANE LOADING ARMS (BY OTHERS)
Control and safety functions related to loading arms (Monitoring
of arms position, control of hydraulic power units, emergency
release ) will be ensured by a dedicated system provided by loading
arms Vendor. This system will be connected to general ESD system
via hardwired signals to ensure safety of loading operations and
alarm report to CCR. Related system equipment will be installed in
the jetty building.
9.6. MARINE INSTRUMENTATION (BY OTHERS)
The Marine Terminal Information System (MTIS) will consist of
the following subsystems: A Berth Approach system (BAS) used by the
tanker pilot and marine operations to
monitor the approach of the tanker to the berth. A Mooring Load
Monitoring system (MLMS) providing continuous monitoring of the
loads on each of the tanker mooring lines A Meteorological
system providing environmental data such as: wind speed and
direction, wave height, water level, water current direction and
speed, water temperature, air temperature...
The above systems shall be connected to a common operator
workstation in local control room (by others). MTIS workstation
will interface to DCS for remote monitoring of MTIS information in
CCR. A ship to shore link via fiber optic cable/IS copper cable
shall ensure transmission of ESD signals between tanker and onshore
ESD system.
9.7. ASSET MANAGEMENT SYSTEM (AMS)
Desk top operator station shall be provided in each ITR for
pre-commissioning, commissioning and maintenance operations
including monitoring /configuration / troubleshooting etc. of PCS
equipment located in the ITR and field devices with HART
functionality and relevant software in DCS to remotely configure
the transmitters from Maintenance Station as well as provision of
remote HART calibrator from marshalling cabinets. The Asset
Management System shall interface smart/HART instruments with
interface modules located in the marshalling cabinets via serial
data links. The interface modules in the marshalling cabinets shall
be provided and installed with the control system,
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10. SHUTDOWN SYSTEMS
10.1. SHUTDOWN LEVELS
10.1.1. GENERAL
The shutdown systems shall act to: detect any abnormal
operational or equipment condition, react to this condition
automatically by shutting down and/or isolating sections of
the plant shutdown utilities including HVAC, isolate the
electrical supplies blow down sections of the plant on operator
request with the objective of preventing any consequential effect
of the abnormal condition.
10.1.2. SHUTDOWN LEVELS
Several levels of shutdown are defined, depending on the
criticality of shutdown causes and consequences. Level 1 (ESD1) =
Fire zone emergency shutdown. ESD1 activation isolates the fire
zone and brings into safe shutdown conditions all process &
utilities systems inside the zone. It is initiated manually from
CCR & from field, or automatically further to Fire & Gas
detection or loss of essential control. As define by the P&IDs
and process cause & effect diagram. Level 2 (SD2) = Unit
shutdown. SD2 activation brings into safe conditions and isolates a
process unit. It is initiated manually from CCR or from field, and
automatically in case of loss of essential control or if operating
conditions reach beyond acceptable limits for safe operation. As
define by the P&IDs and process cause & effect diagram.
Level 3 (SD3) = Equipment shutdown. SD3 activation brings into safe
conditions and isolates a process equipment or packaged unit. It is
initiated manually or automatically in case of abnormal operating
condition. As define by the P&IDs and process cause &
effect diagram.
10.1.3. DEPRESSURIZATION/BLOW DOWN
The fire zone emergency depressurization and blow down (EDP)
allow reducing pressure from the maximum operating pressure to a
specific threshold further to detection of outdoors abnormal
F&G conditions. It will be manually trigged by dedicated PBs in
CCR, which initiate the fire zone depressurization on the condition
that ESD1 of related fire zone has been previously activated
(manually or automatically). Some equipment requires to be
depressurized after some fault, e.g. gas compressor after a seal
shaft failure; they will be fitted with depressurization system
activated independently from EDP.
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10.1.4. ELECTRICAL ISOLATION
Electrical shutdowns (distribution isolation, substation
isolation and battery unit's isolations) are initiated by ESD1 and
SD2. These isolations shall be performed by ESD systems even if
activated further to gas detection. Attention shall be given to
electrical shutdown categories in causes and effects charts.
10.1.5. INITIATION OF SHUTDOWN
Shutdown shall be initiated either manually or automatically
Cascade effect of shutdown
Higher shutdown level shall initiate lower levels directly or
using cascade effect depending on system reaction time.
Automatic initiation
Shutdown systems shall be designed to operate automatically when
the process is outside normal operating limits and when a dangerous
situation is likely to occur before an operator could intervene.
Shutdown should be automatically initiated only as last resort and
should generally be preceded by alarms displayed on OCS, to give
operators as much time as possible for corrective actions. Shutdown
systems will also be automatically activated by the F&G
logic.
Manual initiation Shutdown may be initiated manually, either
locally, or remotely from CCR.
SD3 may be activated locally by PBs hardwired to PCS/UCP, or in
CCR from the OCS.
Manual activation of ESD1 and SD2 shall be completely
independent from PCS so that PCS error cannot make this activation
inoperable. It shall be initiated by PBs hardwired directly to
input cards of ESD systems. A very few number of Ultimate Safety
PBs by passing the ESD logic, allow initiating main shutdown
actions in case of ESD PLC errors. Those PBs shall be directly
hardwired, in marshalling cabinets, to the electrical supply
circuits of solenoid valves that operate the essential ESDVs or
BDVs.
10.2. SEGREGATION OF ESD/EDP AND SD3 SAFETY SYSTEMS
SD3 functions may be implemented on DCS controllers or on
Package PLC with redundant configuration such as to meet required
criteria availability/reliability (refer to 10.5.1). The ESD1, SD2
and EDP functions shall be performed on dedicated fail safe PLCs
that will be installed in the ITRs in dedicated cabinets.
Assignment of shutdown functions to ESD/PLC or SD3/DCS and USS
shall be shown on P&IDs
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These valves will be: ESDV: Emergency shutdown valves BDV:
Blowdown valves SDV: Shutdown valves Control valves may be used, on
an exception basis as BDVs or SDVs (never ESDVs) and requires
COMPANY approval, in case of Activation of those valves by ESD
levels as follows (refer also to 14.2):
ESD1 ESD2 SD3 EDP ESDV Yes No /Yes(2) No /Yes(2) No SDV No (3)
Yes Yes No BDV No No Yes(1) Yes Control Valve No No Yes(2) Yes(2)
XV Yes(4) No No No MOV No No No No
Note 1: Only for depressurisation of specific equipment (further
to SD3 initiation) Note 2: On an exception basis Note 3: Refer to
DB2224 999 P312 209 Section 3.6.2 Note 4: On an exception basis,
Just in unit 100.
10.3. RESET FUNCTIONS
After ESD1 & SD2 shutdown actions the shutdown systems and
field control elements shall be reset manually to avoid an
uncontrolled Plant restart.
10.3.1. ESD LOGIC RESET
Onshore ESD logic reset Further to shutdown initiation, the
related ESD levels shall be reset individually and manually. The
OCS operator shall reset the onshore ESD logic relevant to each ESD
level. The ESD level shall return to normal condition only when ESD
cause (s) has disappeared or has been inhibited and the ESD logic
manual reset has been initiated.
Wellhead platform ESD logic reset
Well heads platforms ESD logic shall be reset manually, remotely
on OCS in the CCR, or locally on OCS in WP technical room.
10.3.2. FIELD EQUIPMENT RESET
Onshore On/Off valves : Unless otherwise specified, ESDVs/ BDVs
are locally and manually reset. The above valves shall move to
their normal operating position as per the following sequence:
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1) CCR operator to reset ESD Logic at OCS, 2) Valve local
permissive reset activated at valve location 3) Valve open command
(close command for BDV) initiated at OCS. 4) Auto reset are not
permitted Local permissive resets shall be input to ESD system.
SDVs shall be remotely reset if activated by SD2 logic and shall
move to their normal operating position as follows: 1) CCR operator
to reset ESD Logic at OCS, 2) CCR operator to reset SDV at OCS, 3)
Valve open command (close command for fail open SDVs) initiated at
OCS. SDVs and BDVs shall be of the auto reset type if activated
further to SD3 initiation and shall move to their normal operating
position as follows: 1) CCR operator to reset ESD logic at OCS, 2)
Valve open command (close command for BDV and fail open SDV)
initiated at
OCS.
Offshore valves : Off shore ESDV's and BDV's shall be locally
and manually reset at valve location. Valve open command (close
command for BDV) shall then be initiated in SPD 22, 24A or SPD 23,
24B technical room.
Package units (type C) : Packages start up can be initiated
after ESD logic reset as per the following sequence: 1) CCR
operator to reset ESD logic at OCS, 2) Field operator to restart
packages manually from UCP.
Electrical motors (e.g. coolers, pumps) :
Motors shall start as per the following sequence: 1) CCR
operator to reset ESD logic at OCS, 2) CCR operator to initiate
"permissive to start" at OCS 3) Field operator to restart manually
motors locally (or at OCS in case of remote
start).
10.4. INHIBIT FUNCTIONS
Start-up inhibit In order to be able to start equipment or
sections of process, it shall be necessary to inhibit some input to
the ESD/DCS systems, as sensor signal may be in an abnormal state
prior to start-up and could cause a shutdown. Such inhibits are
designated as "start-up inhibits". Activation of start-up inhibits
shall be carried out automatically, as far as possible, by the
ESD/DCS systems during a start-up sequence. However some inhibit
may have to be set manually by the operator from the operating
console. It will only defeat the shutdown function. Input status
monitoring shall remain in operation.
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Each inhibit function shall be reset automatically either by the
sensor signal reverting to the normal or healthy state, after a
dedicated step of the equipment start-up sequence, after a
predetermined time delay, or by a set of process conditions. If
cancelled automatically by the sensor signal, the input circuitry
will prevent nuisance trips being caused by oscillation of the
input around the reset value.
Maintenance inhibit
Maintenance inhibit switches shall be used to inhibit trip
initiators to enable maintenance or on-line functional testing. The
following shall be adhered to: When the trip transmitter is
inhibited, the operator shall check frequently the
associated control transmitter measurement so that manual
actions (remove the inhibit or activate manually ESD) can be taken
in case the process moves out of limits. Only one trip initiator
shall be inhibited per interlock at any one time to allow the
operator to monitor properly the situation.
Output shall not be overridden or isolated. A maintenance
inhibit function shall not inhibit the alarm function. For reasons
of security, inhibit facilities are not allowed on flame, axial
displacement and vibration sensors. A maintenance inhibit
function is not required for two-out-of-three trip initiator
configurations. For two-out-of-two trip initiator configuration
maintenance inhibits function shall be provided for each of the
initiators. Setting of only one maintenance inhibit function shall
create a situation such that the configuration temporarily
functions as a one-out-of-two system.
Maintenance inhibit for ESD system inputs shall be activated
from a dedicated console provided within to ESD cabinet in the ITR.
Maintenance inhibit for SD3 system input shall be activated from
DCS console located in Engineers room. A hardware keylock or a
password shall protect the access of maintenance inhibit function
from unauthorized personnel.
Start-up and maintenance inhibit display Maintenance inhibits
and start-up inhibits shall be individually displayed and recorded
in the Control Room on the OCS and printers. The process and ESD
graphics shall show all inhibits. Different display symbols shall
be used for maintenance inhibits and start-up inhibits. In
addition, dedicated inhibit summary pages shall list all start-up
and maintenance inhibits with their set, reset date/time and theirs
detailed description.
10.5. DESIGN GUIDELINES FOR SHUTDOWN SYSTEMS
10.5.1. DCS/SD3 SYSTEMS
Design guidelines for the DCS or Package PLC subsystems
dedicated to SD3 functions shall be as per guidelines for control
functions (refer to 9.1.3) with the exception of I/O channel
configuration which shall be redundant, allowing on line
replacement.
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10.5.2. EMERGENCY SHUTDOWN SYSTEMS
ESD systems shall be implemented on high reliability fail-safe
and fault tolerant PLC. The Emergency Shutdown System shall require
multiple nodes connected together on a dedicated safety network.
Executive actions shall be transmitted on this network between ESD
PLC controllers as long as it has been specifically designed for
such a purpose and the complete Emergency Shutdown System including
the communication network named safety network meet the appropriate
SIL level approval. Connection to offshore facilities shall be
performed through SPIFON. The Fire & Gas System shall require
multiple nodes connected together on a dedicated safety Network.
Executive actions shall be transmitted on this network between FGS
PLC controllers as long as it has been specifically designed for
such a purpose. Data exchange between FGS and ESD:
Safety trip signals resulting from a level higher (or equal)
than SD2 level shall be hardwired.
Data exchange between ESD PLCs:
Safety trip signals exchanged between ESD shall be either
hardwired within a common instrument technical room or through the
safety network between different instrument technical rooms.
Data exchange between FGS PLCs:
Safety trip signals exchanged between FGS shall be either
hardwired within a Common instrument technical room or through the
safety network between different instrument technical rooms.
Data exchange between ESD/FGS and other systems:
Safety trip signals exchanged from ESD/FGS to the other systems
are hardwired.
Data exchange between ESD/FGS and DCS
A redundant communication link is required in order to monitor
FGS/ESD related events.
Data that shall be able to be transferred from FGS/ESD to PCS
such as detection alarms system common alarms, inhibition status,
fire fighting systems status, reset commands, ESD systems (Logic
Solver central parts, I/O cards and communication cards) shall be
based on fault tolerant/redundant, programmable logic controller
technology and shall have hardware architecture that complies with
the requirements of SIL3 as minimum. The proposed system shall use
Supplier standard field proven product lines. ESD system shall
generally follow the principle of de-energize to trip except for
some specific devices such as ESD PBs. All input/output that are
not configured to be fail-safe shall be line monitored. Redundant
configuration with redundant processors and inter-processor
communication shall be provided.
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Redundant I/O channel configuration shall be provided allowing
on line replacement. Single I/O configuration may be provided only
for non-critical input, without any impact on ESD actions, such as
valve limit switches. PLC shall continuously monitor the status of
each component. Auto test and internal diagnostic of major parts
(I/O cards, processors, buses, memory, and power supply) shall be
considered as being of primary importance, as well as system faults
monitoring. The PLC "system" faults shall be managed by maintenance
station in ITR with few common alarms transferred to OCS
10.5.3. ULTIMATE SAFELY SYSTEM (USS)
Definition of valve and will be studied and revised during
detail deign engineering.
10.5.3.1. GENERAL REQUIREMENTS
Generally, one USS PB per fire zone shall be implemented
10.5.3.2. DEFINITION OF VALVES AND EQUIPMENT TO BE TRIPPED BY
USS
Only the ESDVs and BDVs directly tripped by ESD1. The valves
which are not directly tripped by ESD1 but by SD2 or SD3 actions
(Cascade or without ESD1) shall not be tripped by the USS. The
electrical isolation system (EIS) leads to the shutdown of all
motors in the fire zone.
10.5.3.3. USS DESCRIPTION
Additional contacts of the pushbutton shall be used for: 1
contact to ESD to initiate at the same time ESD1 and for monitoring
purpose. 1 contact to highlight the USS PB on the ESD panel. The
USS PB's shall be of flap protected and latched switch type.
10.6. INTERFACES BETWEEN ESD SYSTEMS AND OTHER SYSTEMS
10.6.1. INTERFACE WITH F&G SYSTEMS
F&G systems shall activate ESD logic, when required, via
hardwired signals. No data is transferred from ESD systems to
F&G systems.
10.6.2. INTERFACE WITH PACKAGE UCPS
Data exchange from/to UCPs will be limited to shutdown
activation via hardwired signals.
10.6.3. INTERFACE WITH MCC
Interface with MCC will be limited to motor shutdown activation
via hardwired signals.
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10.6.4. INTERFACE WITH TGS
Tank Gauging System (TGS) interface to the ESD system shall be
via 4-20mA level Measurements from level gauge 4-20mA output
modules and shall be directly hardwired to the ESD systems for very
high/low level detection and shutdown activation. TGS interface to
the DCS for level measurement and indication shall preferably be by
high speed serial link.
10.6.5. DATA EXCHANGE BETWEEN ESD SYSTEM AND PCS
A redundant communication link between PCS and ESD systems is
required in order to monitor ESD systems related events.
Transmission of ESD data to the PCS via an integrated redundant
data highway shall be considered. Via this communication link,
alarms and status shall be transmitted to PCS to be displayed on
dedicated mimics at OCS, printed on relevant printers, and activate
SD3 functions as required, ahead of automatic shutdown via "cascade
effect" ( 10.1.5). Data that can be transferred from ESD/EDP
systems to PCS are: ESD input measures or statuses and resulting
alarms System alarms (common alarms only) ESD output commands
status ESD input inhibit status Valve and equipment status The
following typical data can be transferred from PCS to ESD/EDP
systems: Start-up inhibit Tests initiation Reset commands Valve
commands (e.g. close BDV, open ESDV, etc...). Note: One integrated
bus could be used for both ESD & PCS system, only when it is
SIL3 certified.
10.7. SEQUENCE OF EVENT RECORDING (SER)
Time and date stamping of events generated by safety PLCs shall
be performed by the PLCs. The alarm status with time stamping shall
be transmitted to PCS via data link communication, for merging and
integration with PCS generated alarms and display in the PCS
Historian module at the CCR, ITRs and printing at the common system
printers. Sequence of Events shall be accessible from a dedicated
printer/Sequence of Event recorder shall be provided in the Printer
Room of each (onshore and offshore) facility to provide a permanent
record for maintenance and operations personnel. The time
synchronization of sub-systems shall be by the PCS, via output
signals from the PCS. The time signal shall be derived from a
master GPS clock.
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11. FIRE AND GAS SYSTEM
11.1. GENERAL
Fire and gas system shall be provided with the following
objectives: Monitoring of all plant areas for fire condition or gas
leakage, and activation of
related alarms Indication on DCS customized graphic display of
areas where fire or gas is
detected, Executive actions (fire pumps, shutdown
activation...). The Plant will be fitted with an automatic fire
detection system: heat, flame and smoke detectors, gas detection:
flammable and toxic gas detectors. In event of confirmed fire
or/and gas detection, the system shall automatically initiate the
appropriate alarms, activate relevant executive actions as per the
cause and effect matrices. Manual call points shall be incorporated
as part of the relevant F&G detection system. Initiation of
these call points shall trigger an audible alarm in CCR and a
visual alarm on the OCD F&G matrix panel without automatic
action. Fire alarms, gas pre-alarms, gas alarms per zones shall be
displayed on OCS simplified PCS mimics, representing the plant
layout (geographically) for easy tracing of the hazard. They shall
also be displayed on the OCD F&G matrix panel and on an
annunciation panel located in Fire station. Matrix and panels LEDs
shall be activated by hardwired signals from F&G system output
cards to ensure a redundancy of F&G alarms in case of
communication failure. Audible alarm shall be activated in CCR and
Fire station as per F&G cause & effect diagrams. For main
F&G functions in the system (from input cards to output cards),
the probability of failure on single input demand shall be less
than 10-3 to be SIL3.
11.2. F & G SYSTEM DESIGN GUIDELINES
All logic required to develop F&G safety strategy shall be
performed in high reliability fail safe and fault tolerant PLCs.
Each F&G PLC design shall be similar to ESD PLCs. If the size
of the combined ESD/F&G systems allows it, a common PLC may be
used. In this case dedicated I/O modules and racks shall be used
for F&G I/O, but processors will be in charge of implementing
both F&G and ESD logic. All fire and gas detectors shall be
connected via marshalling cabinet to F&G system standard
cards.
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F&G system will generally follow the principle of
de-energize to trip for systems. All input or outputs, which are
not configured to be fail-safe, shall be line monitored. Interface
between the different F&G systems shall be via hardwired
signals.
For non-process buildings, addressable fire detection panels
shall be provided. Only common alarm per type will be connected to
F&G PLCs via hardwired signals for display on CCR OCS and
F&G matrix panel.
11.3. INTERFACES WITH OTHER SYSTEMS
11.3.1. INTERFACES WITH FIRE PROTECTION SYSTEMS
Fire protection systems shall generally be stand-alone systems
not interfaced with F&G system. The only exception shall be the
CO2 systems within machine enclosures, activated automatically by
F&G logic further to confirmed detection. Related F&G logic
shall be implemented on Vendor/Supplier UCP. Local manual
activation shall be implemented on fire protection systems, deluge
valves and tank foam protection systems. Remote activation from
F&G matrix panel shall also be implemented for deluge systems
via command directly hardwired to related skids.
11.3.2. INTERFACES WITH FIRE WATER PUMPS
Fire water pumps will be actuated, automatically from F&G
system, or manually from CCR remote fire water pumps panel or from
local fire water pump panels. Signals from/to the CCR fire pumps
panel shall generally be hardwired to/from the local fire pump
panels through the F&G system.
11.3.3. INTERFACE WITH HVAC SYSTEM
Fire dampers shall be directly controlled by the F&G system.
The F&G system shall also send shutdown commands to the HVAC
system via hardwired links so that the HVAC system perform relevant
shutdown actions (trip motors...)
11.3.4. INTERFACE WITH ESD SYSTEMS
The F&G system shall initiate ESD1, SD3 and electrical
isolation via the ESD systems. The interface between the F&G
and the ESD system shall be via hardwired signals (except in case
of combined ESD/F&G systems).
11.3.5. INTERFACE WITH GENERAL ALARM SYSTEM
The general Alarm system, consisting of indoor sounders and
outdoor sirens, will be manually activated from CCR and Fire
station through FGS.
11.3.6. DATA EXCHANGE BETWEEN F&G SYSTEMS AND PCS
A redundant communication link between PCS and F&G systems
is required in order to monitor F&G systems related events.
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Data, which can be transferred from F&G systems to PCS, are:
Detection alarms (pre-alarm level and activation alarms) System
common alarms Inhibit status Fire fighting systems status. The
following typical data can be transferred from PCS to F&G
systems: Reset commands
12. PACKAGE UNITS
12.1. GENERAL
Packaged units shall have their control and shutdown
instrumentation implemented as follows: Critical packaged units
(loading arms, centrifugal compressors, boilers, etc....) shall
include the Vendor/Suppliers recommended control & safety
system. Less critical and specialized packaged units (water
treatment, air and nitrogen
production) may have their control functions implemented in
dedicated control systems connected to DCS by high speed serial
links or can be fully integrated into DCS.
For ESD of packages having few safety critical I/O, the plant
ESD systems can be utilized. For packages which require significant
ESD functions, the ESD functions may be implemented in dedicated
system (refer to 10.2). F&G detection and protection for
package units is generally included in the plant FGS. In some
cases, such as turbines, detectors and relevant logic may be
included in Vendor/Supplier scope of supply.
12.2. PACKAGED UNITS CLASSIFICATION
Packaged units shall be controlled according to the following
principles: Type "A" Stand alone packaged unit with no interface
with PCS, ESD and F&G systems. Type "B" Packaged unit fully
remotely controlled (monitoring and control functions) by the PCS
and ESD/F&G systems. There is no Vendor/Supplier supplied
control cabinet for these packages. Type "C" Packaged unit fully
controlled by the package control cabinet (UCP) located either on
the skid package itself or remotely in the technical room. Type "C"
package UCP shall be connected to the PCS, ESD and F&G systems,
for monitoring, control functions and shutdowns.
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12.3. INTERFACES BETWEEN UCP AND OTHER SYSTEMS
When a packaged unit is provided with its own control and safety
system (type C package), the interface (remote information, alarms
or commands) between this UCP and PCS shall be: either via
hardwired volt free contacts and 4-20 mA analogue signals when
few
data only are exchanged with PCS. or via a high speed serial
link when a large quantity of data are exchanged with
PCS In all cases signals to/from the ESD systems and F&G
systems shall be hardwired.
Main alarms shall be transmitted to the PCS for display on the
alarm summary table. When discrimination time on PCS is not
sufficient to allow correct sequencing of transmitted events and
alarms, information shall then be sequenced and time tagged by the
UCP (in memory). Detailed alarm annunciation shall be available on
cabinet in ITR. A specific register called first-up register will
be carried to the IPCS in order to detect the first shutdown.
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13. ELECTRICAL FIELD EQUIPMENT (PUMP, AIR COOLERS &
BLOWERS)
The general rules concerning starting-up/running and stopping or
shutdown for electrical equipment are laid down in following
matrix. Application of those general rules to operation of each
equipment shall be set up by Contractor during detailed design
phase, taking into consideration safety and optimum process
operation.
13.1. START/STOP OF EQUIPMENT - OPENING/CLOSING OF MOV
Start/Opening Stop/Closing Shutdown Equipment Operation by Local
Remote Local Remote Local Remote
Pumps Operator manual action
Yes (1&5) Yes(1&3) Yes Yes(4) Yes No
Systems logic N/A Yes(3) N/A Yes(3) N/A Yes
Blowers Air coolers (2)
Operator manual action
Yes (1) Yes (1&3) Yes Yes Yes No
Systems logic N/A No N/A No N/A Yes(7)
Motor operated valves
Operator manual action
Yes (1&5) Yes (1&6) Yes(5) Yes(6) N/A No
Systems logic N/A Yes(1&3) N/A Yes(3) N/A Yes(3)
Notes: 1) If not prevented by trip condition, ESD logic not
reset,... 2) Start/stop per fan - Emergency stop per module -
Analogue control
(speed/louver/pitch) per module on PCS 3) Remote operation shall
be indicated on P&IDs by Contractor when required 4) Equipment
started for safety/emergency reasons will only be stopped or
shutdown
manually in the field (local) 5) Only in "local mode" 6) Only in
"remote mode" 7) ESD1 Trip via Electrical Isolation System
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13.2. PUMP START/STOP
Local manual start/stop For all pumps start/stop PBs and
emergency stop PB shall be located at the local control station.
Local stop and Emergency stop shall always be active
CCR manual start/stop and automatic start/stop
Requirements for automatic start/stop or manual remote start/
stop from the OCS in CCR, shall be indicated by Contractor on
P&IDs. When required, the local/remote mode shall be selected
by CCR operator at OCS.
Duty/Stand by selection
In cases where a standby pump is provided as a back up against
duty pump failure, the first pump started by the operator will be
considered as the main. No switch "Duty/Stand by" will be
provided.
13.3. MOTOR CONTROL CENTER INTERFACES
All signals from ESD and/or DCS/SD3, including "trip" and any
other vital or safety critical signals to Motor Control Centres
(MCCs), shall be hardwired. Motor non-critical signals shall
interface with the DCS/PCS via high serial links from substation
PDCS slave PLC. These signals will be typically: From PDCS to PCS
:On/Off status, Unavailable/ Tripped status (grouped) From PCS to
PDCS : Start/ Stop commands as required. Exchange of non-critical
signals from UCP to PDCS will be done through PCS.
13.4. ELECTRICAL DISTRIBUTION INTERFACE
Selected operational parameters, main status and alarms
associated with electrical distribution systems shall be
transferred to PCS via a communication link between PDCS master PLC
in main substation and PCS data communication network, in ITR
12.