Safeguarding Philosophy
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South Pars Gas Field Development Phases 22, 23 & 24 Pars Oil and Gas Company
Plant: Onshore Facilities Doc. Number : RP-2224-999-1511-021
Rev.No.: 1 Class: 1
INSTRUMENT CONTROL AND SAFEGUARDING PHILOSOPHY
1
04-Jan-2011
AFC
B. Khodabakhshi
H.Tajik
B.Yousefian
F.zanjani
H.Hoseini-Nik
B.Yousefian
F.zanjani
H.Hoseini-Nik
P.M.
P.D.
DETAIL ENGINEERING 0
06-07-2010
IFR
A.Asghari
H.Tajik
REV.
DATE
DESCRIPTION
PREP.
CHKD.
APPD.
CONTRACTOR APPD.
This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
Page 1 of 47
COMPANY APPD.
South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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Page 2 of 47
South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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. 7.1.
CONTROL CENTERS........................................................................................................ 15 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. ENGINEER’S ROOM........................................................................................................... 15 7.1.4. PRINTER ROOM ................................................................................................................ 15 7.1.5. TELECOMMUNICATION BUILDING ....................................................................................... 16 7.2. 8. 8.1.
INSTRUMENT TECHNICAL ROOM (ITR) (SUBJECT TO CHANGE) ........................................... 16 OPERATOR INTERFACES)(SUBJECT TO CHANGE) .................................................... 17 CONTROL BUILDING ......................................................................................................... 17
8.1.1. CENTRAL CONTROL ROOM ............................................................................................... 17 This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
Page 3 of 47
South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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 This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
Page 4 of 47
South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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 This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
Page 5 of 47
South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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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Page 6 of 47
South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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 This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
Page 7 of 47
South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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 : BMS : CCTV : CMS : CPU : CCR : DCS : EDP : EPROM : ESD : ESDV : EW : F&G : FGS : GA : HC : HIPPS : HVAC : I/O : I/F : IPCS :
Blow Down Valve Burner Management System Closed Circuit TeleVision Custody Metering System Central Processing Unit Central Control Room Distributed Control System Emergency DePressurization Erasable Programmable Read Only Memory Emergency ShutDown Emergency Shut Down Valve Engineer workstation Fire and Gas Fire and Gas System General Alarm Hydrocarbon High Integrity Pressure Protection System Heating, Ventilation, Air Conditioning Input/Output Interface Integrated Plant Control System
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Page 8 of 47
South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021 IS : ITR : JB : LAN : LAS : LED : LFL : LP : LV : MP : MC : MCC : MLMS : MOS : MOV : MTBF : MTIS : MTTR : OCS : OCD : PB : PC : PCS : PDCS : P&ID : PLC : PMS : RAM : SBS : SC : SPD 22 & 24A : SPD 23 & 24B : SDV : SDH: SLS : SPIFON : SS : TGS : UCP : UHF : UPS : USS : VDU : VHF : XV : KV: TGTU:
Rev. 1
Intrinsically Safe Instrument Technical Room Junction box Local Area Network Loading Arms System Light Emitting Diode Lower Flammable Limit Local Panel for main equipment (heater, compressor) Low Voltage Manual Call Point Marshalling Cabinet Motor Control Center Mooring Load monitoring System Meteorological/Oceanographic System Motor Operated Valve Mean Time Between Failure Marine Terminal Information System Mean Time To Repair Operator Control Station Operator Control Desk Push-Button Personal Computer Process Control System Power Distribution Control System Piping and Instrumentation Diagram Programmable Logic Controller Pipeline Monitoring System Random Access Memory Ship Berthing System System Cabinet Wellhead Platform 1 Wellhead Platform 2 Shutdown valve Synchronous Digital Hierarchy Ship to Shore Link South Pars Integrated Fiber Optic Network Electrical SubStation Tank Gauging system Unit Control Panel Ultra high frequency Uninterruptible Power Supply Ultimate Safety System Video Display Unit Very high frequency Process on/off Valve Sequence Valve Tail Gas Treatment Unit
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Page 9 of 47
South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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 system’s 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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Page 10 of 47
South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021 6.2.1.1.
Rev. 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.
This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
Page 11 of 47
South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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). This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
Page 12 of 47
South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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)
This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
Page 13 of 47
South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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 POGC’s 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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Page 14 of 47
South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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. ENGINEER’S 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.
This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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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)
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ITR 1 for Gas Train 1,except Diesel storage& chemical storage
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ITR 2 for Gas Train 2,
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ITR 3 for Gas Train 3,
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ITR 4 for Gas Train 4,
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ITR 5 for Sulfur Recovery units 1,2 &TGTU
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ITR 6 for Sulfur Recovery units 3,4 & TGTU
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ITR 7 for Condensate Trains, Reception Facilities and, except Sea water supply intake and distribution network
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ITR 8 for MEG Regeneration Units, DMC, Diesel storage, Diesel generator, chemical storage , Propane refrigerant storage & Condensate storage
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ITR 9 for Propane & Butane treatment and drying
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ITR10 for NGL fractionation, Ethane treatment and drying , Export Gas Compression
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ITR 11 for Waste Water Treatment and all Utilities
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ITR 12 for Fire Water Area,
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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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South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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. This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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Rev. 1
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 Contractor’s 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. This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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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Rev. 1
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 functionality’s, 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. This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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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South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
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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Rev. 1
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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Rev. 1
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):
ESDV SDV BDV Control Valve XV MOV
ESD1 Yes No (3) No No Yes(4) No
ESD2 No /Yes(2) Yes No No No No
SD3 No /Yes(2) Yes Yes(1) Yes(2) No No
EDP No No Yes Yes(2) 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: This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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Rev. 1
CCR operator to reset ESD Logic at OCS, Valve local permissive reset activated at valve location Valve open command (close command for BDV) initiated at OCS. 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 Engineer’s 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 failsafe shall be line monitored. Redundant configuration with communication shall be provided.
redundant
processors
and
inter-processor
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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. This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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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 Operation by Operator Pumps manual action Systems logic Blowers Operator Air coolers manual (2) action Systems logic Motor Operator operated manual valves action Systems logic Equipment
Start/Opening Local Remote
Stop/Closing Local Remote
Shutdown Local
Remote
Yes (1&5)
Yes(1&3)
Yes
Yes(4)
Yes
No
N/A
Yes(3)
N/A
Yes(3)
N/A
Yes
Yes (1)
Yes (1&3)
Yes
Yes
Yes
No
N/A
No
N/A
No
N/A
Yes(7)
Yes (1&5)
Yes (1&6)
Yes(5)
Yes(6)
N/A
No
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.
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14. FIELD INSTRUMENTATION The availability and reliability of process control and safeguarding applications shall be examined according to the direct and indirect disturbances and risks induced by a failure and according to back up safety brought by other devices.
14.1. FIELD SENSORS AND FINAL CONTROL ELEMENTS GENERAL REQUIREMENTS Electronic transmitters shall be used as a general rule. However for a few local controls some pneumatic control loops are acceptable which required COMPANY approval. Transmitters shall be of the smart transmitter type, except those connected to the ESD system that will be preferably of conventional electronic type. If smart type transmitters are selected for ESD application they shall be configured as “read only”.
Smart transmitters (2 wires) with digital signal superimposed on 4-20mA signals shall be the rule. Remote calibration shall be performed from a “pocket” interface at marshalling level (No fieldbus provided for remote maintenance) or from maintenance station in ITR if the PCS can support digital communication with selected smart transmitters as a standard facility. The following general requirements have to be used as guidelines for reliability and redundancy of field sensors and final control elements. For monitoring of process measurement: level and pressure data available in CCR shall be backed by a local gauge; no similar requirement for temperature and flow, In case of pressurized tanks, continuous level measurement as well as alarm actuators shall be duplicated.
Process alarm shall preferably be detected with threshold on analog measurement, (i.e. signal which behavior may be tracked) and local switches shall be avoided except level switches which shall be subject to COMPANY approval.
For process closed control: level, pressure and temperature measurement, used by control loop shall be backed by a local gauge; flow measurement will be without back-up, failure of instrument or signal shall be monitored and treated in the control loop (freezing of control, default value ...), where no redundancy is provided, failure of one component shall bring actuating components of control loop to its (their) safe position (fail safe design) Where redundancy is provided, failure of one redundant component shall not have any consequence towards the process control, if combination of two or more failures induces loss of control, actuating component of concerned control loops shall be put at their safe state. For logic interlock and sequential control, redundancy of common components shall be examined with the redundancy of process equipment itself. For example, where two equipment are designed for 100% capacity in spare each other, the This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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redundancy of control equipment is not typically required if the control is performed by separated device. For safeguarding functions: safety systems shall work independently of the control system with their own initiating devices,
same initiating device shall not be used for SD3 function and for control or monitoring function,
Process variables used for initiating the shutdown systems shall be derived, as a general rule, from the electronic transmitter signals. The threshold function shall be achieved within safety systems logic. All transmitters shall have line integrity monitoring and fault reporting by the safety systems,
If control and safety transmitters are provided at the same location the ranges for both transmitters should be the same. Discrepancy monitoring shall be provided at the PCS by comparison of the control & safety transmitters measured variables and an alarm generated if the difference between the transmitters exceeds a predetermined threshold. Saturated signals under normal operating conditions shall be avoided (e.g. a small range transmitter signal for Low Low level detect ion),
Local switch shall be forbidden for temperature, pressure and flow process alarm; local switches may only be used for mechanical equipment if required by Vendor/Supplier standard. and will be subject to COMPANY approval,
when switches are used as sensing devices, they shall have normally closed contact to open on trip condition,
facilities shall be provided to detect sensors dormant failures (e.g.: monitoring of analog signal and comparison of measurements for control and safeguarding) ,
Online testing will be possible for sensors by using maintenance inhibit (refer to 10.4).
Online testing will be possible for actuators as per § 14.2,
failure of instrument or signal shall be monitored and treated in the safety loop (freezing of signal or safety position ...),
Failure of one element shall not jeopardize the availability of more than one safety loop. As a consequence, shared component which is common to more than one safety loop, which may fail and which is essential to the safety, shall be supplied fully redundant,
ESD1 final control element must be redundant. Redundancy of an ESDV can be ensured by a SDV valve closed by ESD1 or SD2/SD3 cascade effect.
SD2 & SD3 final control elements do not have to be redundant except if required by Process specific requirement and identified on P&IDs.
if a SDV is used for both SD3 & SD2 functions it shall be equipped with two solenoids, one controlled by DCS and one controlled by ESD system This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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if a BDV is opened further to ESD1 & SD3 initiation, it shall be equipped with two solenoids, one controlled by PCS (or UCP) and one controlled by ESD system.
Control valves may be used, on an exception which required COMPANY approval basis in case of small upstream inventory, as BDVs or SDVs (never ESDVs) if valve leakage is acceptable from a safety point of view. For such applications a solenoid valve , connected to PCS (for SD3 functions) or to ESD system (for SD2 functions) and independent from control loop, shall be installed in the pneumatic control line from the positioner to the actuator
No redundancy is required for SD2&SD3 sensors. Use of voting systems will be considered in case of specific need of additional availability or reliability. They will be identified on P&IDs.
Redundancy of measurements or actuating equipment shall be shown on P&IDs.
The physical principle of measurement (mainly flow) may be shared with another loop but the electronic processing must be segregated. For example, a single vortex meter body shall have two separate sets of electronic or one orifice plate primary device may be utilized with two transmitters connected to separate process tapping. This facility is not acceptable for pressure, level and temperature.
Facility shall be provided to detect open and short circuit
ESDVs shall be equipped with partial valve stroke testing facilities.
Redundancy for ESDVs will be subject to SIL study result.
14.2. ON/OFF VALVES The ON/OFF actuated valves considered are: Emergency shutdown valve (ESDV) Blowdown valve (BDV) Shutdown valve (SDV) Process On/Off Valve (XV) Sequence on/off Valve (KV) Close and open position switches of on/off valves actuated by ESD system shall be hardwired to ESD non-redundant input cards and discrepancy between command and position shall be detected by ESD logic and shall initiate an alarm. ESDVs, SDVs and BDVs, shall be actuated by the ESD systems. Close and open position switches of on/off valves actuated by ESD system shall be hardwired to ESD input cards and discrepancy between command and position shall be detected by ESD logic and shall initiate an alarm. Where on/off valves are used for several functions (I.e. ESD, PSS and DCS control), a dedicated solenoid valve for each function shall be considered. Actuators shall be air spring return or double acting actuators. Double acting actuators may be applied where single acting spring returns actuators are prohibitively large, or where 'stay-put' actuators are required. This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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Electrical motorization is prohibited for safety applications. ESDVs shall fail to closed position on air failure and when de-energized. Gas over oil actuators will be utilized where instrument air or other motive power is not available e.g. shutting down gas pipe lines, shoreline ESD valves. Use of hydraulic actuator shall be limited as far as possible and shall be subject to Company approval. SDVs shall generally fail to closed position on air failure and when de-energized. Exceptions shall be clearly indicated on P&IDs. BDVs shall generally fail to open position on air failure and when de-energized. In specific case, such as on slug catcher, BDV shall be air fail open and energized to open with line monitoring facilities. Air back up vessels, sized for three strokes, shall be provided for double acting actuators and BDVs. (1 stroke to safe position, 1 stroke corresponding to operator erroneous request, 1 stroke to safe position) The ESDVs and BDVs will have a local panel with a reset push button and/or test facilities as described hereafter. During all testing operations where the ESD system has no longer the possibility of closing the valve, local closure shall be possible. XVs and KVs cannot be considered as safety valves and are actuated by the PCS.
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Valve facilities can be summarized as follows: VALVE OPERATING FACILITY Local manual reset (Electrical) Auto reset Remote reset (individual) Control room console manual open command subsequent to ESD logic reset and electrical local reset (when relevant) (Note 1) Control room console manual close command subsequent to ESD logic reset and electrical local reset (when relevant) (Note 1) Control system open command (Note 5) Control system close command (Note 5) Local open command
ESDV Yes No No Yes
BDV Yes (Note 12) Yes (Note 11) No (Note 12) N/A
SDV (Note13) No (Note 7) Yes (Note 11) Yes (Note 10) Yes
XV/KV No Yes No N/A
N/A
Yes
No (Note 7)
N/A
No
Yes
No
Yes
No
Yes
No
Yes (Note 3)
No
Local close command
Yes (Note 3) No
As Required (Note 6) As Required (Note 6) As Required (Note 6) As Required (Note 6) No No
Partial stroking facility (Note 9) Yes Solenoid valve test facility (Note 8) Yes
No Yes
Yes (Note 3) No (Note 2) No (Note 2)
Notes: 1) Additional permissive condition when required shall be represented by Contractor on P&IDs. Actual valve shall be operated one after the other as per the operating manual. 2) Partial stroking and solenoid valve test facilities have to be specified for those SDV’s which are expected to be permanently open and which cannot be tested during planned equipment shutdown. These SDV’ are to be identified by Contractor on P&ID’s. 3) Requirement for local command shall be indicated by Contractor on PIDs. 4) Auto reset requirement to be identified on P&ID’s by Contractor. 5) Control system means ESD/PCS/UCP for ESDV’s/BDVs/SDVs depending on ESD logic. Control system means PCS/UCP for XVs. 6) Open and close commands have to be identified on P&IDs by Contractor. 7) Except if specifically required by Contractor on P&IDs 8) A by-pass operated by means of a special spring return key will allow the testing of the solenoid valve without moving the valve. Solenoid by pass will be monitored with PSL displayed in CCR. 9) A spring return key switch allows a partial stroking of the valve 10) When activated by SD2 11) When activated by SD3 12) When activated by ESD1 13) Facilities are described for fail close SDVs. For fail open SDVs, if any, reverse action shall be considered.
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15. SIGNAL TRANSMISSION 15.1. GENERAL Signal transmission, in the context of this document, refers to how instrument systems are interconnected, and can be summarized as follows (signals may go in both directions). Field to ITR, Within ITRs, From ITR to control building Within control building, From ITR to substations,
15.2. FIELD TO ITR Field instrumentation is connected to junction boxes in the process area via individual cables run in aerial cable trays. From the junction boxes, multi-pair/core cables will be routed underground, or aerial on pipe rack, to the field cable marshalling cabinets in the ITR. Multi-cables will be segregated according to voltage and signal type (24VDC, 48VDC, IS...) and service (process, emergency shutdown...) as far as possible. EDP/ESD signals may be connected to same JB. PCS/SD3 signals may be connected to same JB. As a general rule the cables that include F&G and ESD safety signals energized to trip shall be Fire resistant cables. Transmitters and contacts from field instrumentation, or Package field UCPs, shall be powered by the relevant control or safety systems. Solenoid valves shall not be powered by systems but by an external 48VDC source wired to marshalling cabinets. Light indicators managed by PCS in fire fighting station shall be powered by external 24VDC.
15.3. WITHIN ITR The field cables shall be terminated in field junction boxes order in the marshalling cabinets. Packaged units such as heaters, compressors, etc., shall have skid mounted wiring from measuring devices terminated at junction boxes or local panels mounted on skid. Multi-pair/ core cables shall then connect the signals to the marshalling cabinets in the ITR. This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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The marshalling cabinets related to "type C" packages will preferably be integrated in UCP and provided by Package Vendor/Supplier. The termination on the technical room side of the marshalling cabinets shall be organized in system cabinet order. Cross connection between field and system order shall be performed within the cabinet. Marshalling cabinets shall be dedicated to PCS&SD3 systems or ESD& F&G systems. Mixing of signals from different units in a same system input/output card shall be avoided. Hardwired interconnections between UCP, PCS, F&G and ESD systems shall be via marshalling cabinets. Contacts delivered by a system to an other system shall be generally be free of voltage and powered by input cards of this later system. High speed Serial links will connect UCPs, ESD system, F&G system and PCS communication interfaces within the same ITR. Electrical power, signal and serial link cables shall be routed beneath false floor.
15.4. FROM ITR TO CONTROL BUILDING DCS data transfer between ITR’s and CCR shall be via redundant communication channels. They shall follow different routes between the points they serve. For manual activation of ESD and F&G protection systems, multi pair/core cables shall be laid between ITRs and CCR OCD.
15.5. WITHIN CONTROL BUILDING Links shall be provided between: CCR and Telecom room for radio remote control units integrated in OCD CCR and Printer room for printers and video copier ITR0 and Engineer room for maintenance workstations (TGS, PCS, ...) ITR12 and Electrical technical room for High speed Serial links between PDCS master PLC and PCS communication interface
15.6. FROM ITR TO SS Multi-core cables shall be laid from ITR to SS for hardwired critical signals connected to MCC. The interposing relay function shall be as far as possible performed by the appropriate “relay” type digital output card of the DCS/SD3 and ESD systems. If not possible, external interposing relays shall be integrated in marshalling cabinets. Contacts delivered to MCC shall generally be free of voltage and powered from MCC. High speed Serial links shall connect PDCS PLC in substations to PCS communication interface in the relevant ITR. ( §13.3) This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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15.7. COMMUNICATION LINKS 15.7.1. GENERAL Communication links shall be 'transparent' and may be utilized as follows: Proprietary links used within and between systems equipment and cabinets from the same manufacturer shall be used as determined by the Vendor/Supplier to meet the purchase specification requirements. Foreign links are links between equipment supplied by different Vendor/Suppliers, they shall only be used for functional non vital or non safety critical signals between systems e.g. DCS from/to ESD/SD3, machinery monitoring instrumentation, MCC motor status and start/stop signals, analysis equipment, package controls, etc. Application shall as a minimum comply with the following: Links shall not be utilized to pass critical safety and/or control signals between systems, i.e. signals whose failure could directly prejudice either plant control or safety. Critical signals shall be exchanged via hardwired I/O connections. Links shall be implemented with a proven (with the systems selected) and industry standard protocol e.g. Modbus TCP/IP. Functions shall be fully tested with the project hardware and software during the integrated tests prior to delivery.
15.7.2. SERIAL COMMUNICATION LINKS REDUNDANCY REQUIREMENTS
High Speed Serial links between ESD and F&G systems and the PCS data communication network shall be via a redundant communication link. Exchange of data from PCS to ESD/F&G system shall be highly secure and shall be designed to preserve the integrity of the safety system. High Speed Serial links between PDCS master PLC and PCS communication in ITR12 and between PDCS slave PLCs and PCS communication interfaces in relevant ITR shall be redundant. High Speed Serial link between UCP and PCS will generally be redundant. High Speed Serial link between TGS and PCS will be non-redundant. High Speed Serial link between CMS and PCS will be non redundant High Speed Serial link between MTIS and PCS will be non redundant High Speed Serial link between MTU and PCS shall be redundant High Speed Serial link between PMS and PCS will be non redundant
For a detail list of serial communication links between DCS and other systems reference is to be made to specification RP 2224 999 1511 002.
This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
16. POWER SUPPLY All control and safety systems located in CCR and ITR shall be powered from 230 V AC Uninterruptible Power Supply (UPS) system located in electrical substations. Necessary autonomy requires battery back up for 2 Hours. Equipment such as PCS, ESD, F&G system cabinets, etc, shall be powered by a set of redundant UPS feeders (i.e. 2 feeders) for each equipment. Equipment such as printers, stations, etc, shall be powered by a single UPS feeder. PCS, ESD and F&G systems shall be equipped with reliable DC generation systems provided by Supplier. These internal power supplies and distribution systems shall be redundant. The 48V DC external source for powering solenoid valves shall be from a dedicated redundant power supply system supplied by a single feeder. Package control cabinets will receive 230V AC, 50 Hz, supplied by a single or dual feeder system (to be defined for each package) and 48V DC power via single feeder.
17. ONSHORE /OFFSHORE PHASES 22, 23 & 24 INTERFACES 17.1. SOUTH PARS INTEGRATED FIBER OPTIC NETWORK (SPIFON) The existing South Pars Integrated Fiber Optic Network (SPIFON) should be used for communication between offshore and onshore facilities. The required interface facilities should be design and developed by contractor in order to have a well arranged connection to existing network for applicable purpose. The detail of applications for SPIFON should be studied and defined during detail engineering.
18. ONSHORE PHASE 22, 23 & 24 SEALINE INTERFACES PCS shall interface with the Pipeline Monitoring system (PMS not included in Contractor scope of supply) through a non-redundant serial link. Data transmission from PCS to PMS will be typically: sealine flow, pressure and temperature main parameters. PMS operator interface shall be the dedicated PMS workstation located in Engineer's room.
This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
APPENDIX 1 (SUBJECT TO CHANGE)
Unit 100-1 100-2 101-1 101-2 101-3 101-4 102-1 to 6 103-1 103-2 104-1 104-2 104-3 104-4 105-1 105-2 105-3 105-4 106-1 to 7
Unit/ ITR/ OCD Assignment Description Reception facilities 1 / Scraper receiver sea line 1 Reception facilities 2 / Scraper receiver sea line 2 Gas treating tr ai n 1 Gas treating train 2 Gas treating train 3 Gas treating train 4 MEG regeneration and injection Condensate stabilization section 1 Condensate stabilization section 2 Dehydration and mercury guard train 1 Dehydration and mercury guard train 2 Dehydration and mercury guard train 3 Dehydration and mercury guard train 4 Ethane recovery train 1 Ethane recovery train 2 Ethane recovery train 3 Ethane recovery train 4 Export gas and metering
ITR 7 7 1 2 3 4 8 7 7 1 2 3 4 1 2 3 4 10
OCD 001 002 001 001 002 002 004 001 002 001 001 002 002 001 001 002 002 004
107-1
NGL fractionation section 1
10
001
107-2 108-1 108-2 108-5 108-3 108-4 108-6 109 110 111-1 111-2 111-3 111-4 111-5 111-6 112 113-1 113-2 114-1 114-2 115-1 115-2 116-1 116-2 121 122 123
NGL fractionation section 2 Sulfur recovery section 1 Sulfur recovery section 2 Sulfur recovery section 5 Sulfur recovery section 3 Sulfur recovery section 4 Sulfur recovery section 6 Sour water stripping Back up stabilization Propane refrigeration train 1 Propane refrigeration train 2 Propane refrigeration train 3 Propane refrigeration train 4 Propane refrigeration train 5 Propane refrigeration train 6 DMC Caustic Regeneration section 1 Caustic Regeneration section 2 Propane treatment and drying section 1 Propane treatment and drying section 2 Butane treatment and drying section 1 Butane treatment and drying section 2 Ethane treatment and drying section 1 Ethane treatment and drying section 2 Steam generation and distribution Fuel gas Instrument and service air
10 5 5 5 6 6 6 7 7 1 1 1 3 3 3 8 9 9 9 9 9 9 10 10 11 7 11
002 001 001 001 002 002 002 003 001 001 001 001 002 002 002 001 001 002 001 002 001 002 001 002 003 003 003
This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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South Pars Gas Field Development – Phase 22, 23 & 24 Doc. No. RP-2224-999-1511-021
Rev. 1
Unit/ ITR/ OCD Assignment Unit Description 124 Nitrogen 126-2 desalinated water distribution 127 Water Polishing 128 Potable water 129 Waste water effluent disposal 130 Fire water Diesel and Emergency Electrical Generation & 131 Distribution 131 Diesel storage 132 Cooling water 140 Flares and blow down - process area 140 Flares and blow down - storage a re a 141 Drains – process area 141 Drains - storage area 142 Burn pit - process area 142 Burn pit -storage area 143 Condensate storages and export 143 Off spec condensate storage. 144 Sulfur storage and solidification 145 Propane refrigerant storage 146 Chemicals storages 147 Propane Storage and Export 148 Butane Storage and Export 149 LPG Loading (jetty system) 171 SPD 22, 24A (offshore phase 22)
ITR 11 11 11 11 11 12
OCD 003 003 003 003 003 003
8
003
8 11 13 13 13 13 13 13 8 8 6 8 8 13 13 TLC Room TLC Room
004 003 004 004 004 004 004 004 004 004 002 004 004 004 004 004 001
171
SPD 23. 24B (offshore phase 23)
TLC Room
002
172
Onshore pipeline
TLC Room
003
Note: 1) OCD assignment is preliminary and shall be finalized by the EPC during the detail design
This document is the property of N.I.O.C.. Any unauthorized attempt to reproduce it, in any form, is strictly prohibited.
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