NEMS-NGC-LNL-EGT-ICS-003 - Instrumentation and Control System Philosophy - R01

NIGERIAN GAS COMPANY
LIMITED
(A Subsidiary of Nigerian National Petroleum Corporation)
ENGINEERING, PROCUREMENT &

CONSTRUCTION OF NEW EGBIN METERING
STATION
INSTRUMENTATION AND CONTROL SYSTEM

PHILOSOPHY
DOCUMENT NO.:
NEMS-NGC-LNL-EGT-ICS-003
R01 8/02/2021 for Review A.O. B. A

PMC NGC
REV. DATE DESCRIPTION BY CHECKED
APPROVED
Project Sequence-
Client Contractor Doc. type Discipline Rev.
Code Number
Doc. Control No. NEMS NGC LNL EGT ICS 003 E01
This document is the property of Nigerian Gas Company Limited (NGC). Its information shall not be transferred to a third party
without the written consent of the Company.
NIGERIAN GAS COMPANY LIMITED NEMS-NGC-LNL-EGT-ICS-003
Engineering, Procurement and Construction of New Egbin Metering Station Status.: IFR Revision No.: R01
REVISION HIS TORY
Revision Date Description Remarks
R01 8/02/2021 Issued for Review
Instrumentation and Control System Philosophy Page 2 of 28

Table of Contents
TABLE OF FIGURES ......................................................................................................................... 5
1.0 INTRODUCTION...................................................................................................................... 6
1.1 PROJECT DESCRIPTION.................................................................................................... 6
1.2 PURPOSE ............................................................................................................................ 6
1.3 ABBREVIATIONS ................................................................................................................. 7
2.0 APPLICABLE CODES AND STANDARDS ............................................................................. 9
2.1 LIST OF APPLICABLE CODES & STANDARDS .................................................................. 9
2.2 ORDER OF PRECEDENCE ................................................................................................. 9
3.0 INTEGRATED AUTOMATION AND SAFETY SYSTEM ........................................................ 10
3.1 OPERATIONAL REQUIREMENT ....................................................................................... 10
3.2 MANNING STRATEGY ...................................................................................................... 10
4.0 PROCESS AUTOMATION SYSTEM ..................................................................................... 11
4.1 GENERAL .......................................................................................................................... 11
4.2 SYSTEM ARCHITECTURE ................................................................................................ 11
4.3 SYSTEM COMMUNICATIONS ........................................................................................... 11
4.4 PROCESS CONTROL........................................................................................................ 11
4.5 PACKAGE UNIT CONTROL............................................................................................... 12
4.6 OPERATOR INTERFACE (HMI)......................................................................................... 12
4.6.1 Displays and Graphics ................................................................................................. 12
4.6.2 Alarm/Event Handling .................................................................................................. 12
4.6.3 System Upgrade Capability ......................................................................................... 13
5.0 SAFEGUARDING SYSTEM................................................................................................... 14
5.1 GENERAL .......................................................................................................................... 14
5.2 SYSTEM HARDWARE ....................................................................................................... 14
5.3 FIELD INSTRUMENTATION INPUTS ................................................................................ 14
5.4 MAINTENANCE OVERRIDES............................................................................................ 15
5.5 SEQUENCE OF EVENT RECORDER (SER) ..................................................................... 15
5.6 SHUTDOWN DEFINITIONS ............................................................................................... 15
6.0 FIRE & GAS SYSTEMS (FGS) .............................................................................................. 16
6.1 SYSTEM DESCRIPTION ................................................................................................... 16
6.2 SYSTEM HARDWARE ....................................................................................................... 16
6.3 FIRE DETECTORS ............................................................................................................ 16
6.4 FGS HMI ............................................................................................................................ 16
6.5 SEQUENCE OF EVENT RECORDER (SER) ..................................................................... 17
6.6 MAINTENANCE OVERRIDES............................................................................................ 17

7.0 SYSTEM AVAILABILITY ....................................................................................................... 18

8.0 SYSTEM INTERFACES ......................................................................................................... 19
8.1 PAS/SIS INTERFACES ...................................................................................................... 19
8.2 PAS/FIRE & GAS INTERFACE .......................................................................................... 19
8.3 PAS/THIRD PARTY INTEGRATION .................................................................................. 19
8.4 FIRE & GAS/SIS INTERFACE ............................................................................................ 20
9.0 METERING ............................................................................................................................ 21
9.1 GAS MEASUREMENT ....................................................................................................... 21
10.0 FIELD INSTRUMENTATION ................................................................................................. 22
10.1 GENERAL .......................................................................................................................... 22
10.2 HAZARDOUS AND COMPLIANCE .................................................................................... 22
10.3 INSTRUMENT INDEX ........................................................................................................ 22
10.4 DISCRETE SIGNAL LEVELS ............................................................................................. 22
11.0 INSTRUMENT INSTALLATION AND INTERCONNECTIONS .............................................. 23
11.1 JUNCTION BOXES AND WIRING...................................................................................... 23
11.2 INSTRUMENT GROUNDING ............................................................................................. 23
11.3 MOTOR CONTROL INTERFACE ....................................................................................... 24
11.4 INSTRUMENT SYSTEM POWER SUPPLY ....................................................................... 24
11.5 INSTRUMENT GAS SYSTEM ............................................................................................ 24
11.6 INSTRUMENT PHYSICAL IDENTIFICATION..................................................................... 24
12.0 LIGHTNING PROTECTION ................................................................................................... 26
13.0 SCADA .................................................................................................................................. 27
14.0 SECURITY/ACCESS CONTROL ........................................................................................... 28

Table of Figures
Figure 1: Satellite view of Egbin Metering Station, Egbin .................................................................... 6

1.0 INTRODUCTION
NGC currently operates a gas metering station with an installed capacity of 431 mmscfd that supplies
gas to Egbin Power Plant.
As part of its expansionary drive, the owner of Egbin Power Plant has indicated readiness to
construct an additional power plant with capacity to receive up to 350 mmscfd of natural gas.
1.1 PROJECT DESCRIPTION

NGC intends to construct a new Egbin Metering Station to supply natural gas to the Egbin Power
Plant in Ikorodu axis of Lagos State to meet the additional customer demands and has secured the
services of Lateejay Nigeria Limited to carry out the Engineering, procurement, construction and
commissioning of the project.
The proposed gas metering station shall have the capacity to supply natural gas to both the existing
and the new Egbin Power Plants and will have an installed capacity of 500 mmscfd.
Figure 1: Satellite view of Egbin Metering Station, Egbin
1.2 PURPOSE
This document defines the basic philosophy guiding the detailed design of the Instrumentation and
Control Systems for New Egbin Metering Station.
System functional requirements have been deduced from International Standards and Company best
practices.

The purpose and limitations of the Instrumentation & Control System are described, along with
philosophies for architecture, interfaces, sensor technologies, executive actions and maintenance
activities.
The Metering Station Facilities are:
 Filter Separator
 Gas Scrubbers
 Heaters
 Pressure Reduction System
 Meter Runs
 Instrument Gas System
 Gas Flow Computer
 Fire & Gas System
 Process Control System
 Safety Instrumented System
 Human Machine Interface System
 Control & Equipment Room
The facility is to be centrally monitored and operationally managed from a Central Control Room
(CCR) at the new metering station.
This document should be read in conjunction with the NEMS Design Basis Memorandum document.
1.3 ABBREVIATIONS
AG Application Guide on Intrinsic Safety
API-RP American Petroleum Institute - Recommended Practice
BN Business Network
BS British standard
CCR Central Control Room
EN Euro Norm
EPIC Engineering Procurement Installation & Commissioning
ESD Emergency Shutdown
F&G Fire and Gas
FCU Field Control Unit
DED Detailed Engineering Design
FF Foundation Fieldbus
FGS Fire and Gas System

FISCO Fieldbus Intrinsic Safety Concept

HART Highway Addressable Remote Transducer
HMI Human Machine Interface
HOA Hand-Off-Auto
HVAC Heating, Ventilation, and Air Conditioning
I/O Input /Output
IASS Integrated Automation and Safety System
IEC International Electrotechnical Commission
IS Intrinsically Safe
ISO International Organization for Standardization
MVC Measurement Validation and Comparison
NEMS New Egbin Metering Station
NGPTC Nigerian Gas Processing and Transmission Company
OCC Operations Control Centre
OLE Object Linking and Embedding
OPC OLE for Process Control
PA Public Address
PAS Process Automation System
PCN Process Control Network
P & ID Piping & Instrumentation Diagram
PIN Process Integration Network
PLC Programmable Logic Controller
PSD Process Shutdown
SCADA Supervisory Control and Data Acquisition
SER Sequence of Event Recorder
SIS Safety Instrumented System
SPC Statistical Process Control
TCP/IP Transmission Control Protocol / Internet Protocol
UCP Unit Control Panel
VDC Volt Direct Current
VDU Video Display Unit

2.0 APPLICABLE CODES AND STANDARDS

2.1 LIST OF APPLICABLE CODES & STANDARDS
The design, construction and installation of the instrumentation and controls systems described in
this document shall be in conformance with the latest version of the codes and standards listed
below:
API RP 550 Manual on installation of refinery Instrument and Control Systems
EN 60529 Specification for degrees of protection provided by enclosures
BS EN60079-14 Code of practice for selection, installation and maintenance of electrical
apparatus for use in potentially explosive atmospheres
ISO 5167 Measurement of fluid flow by means of orifice plates, nozzles and venturi tubes
inserted in circular cross section conduits running full
ISO 5168 Methods of measurement of fluid flow: estimation of uncertainty of a flow-rate
measurement uncertainty of a flow-rate measurement
IEC 61508 Functional Safety of Electrical, Electronic, Programmable Electronic Safety
Related Systems
IEC 61511 Functional Safety: Safety Instrumented Systems for the Process Industry
Sector
IEC 60079 Electrical apparatus for explosive gas atmospheres
IEC 60801 Electromagnetic compatibility for industrial process measurement & control
equipment
BS 6651 Code of practice for the protection of structures against lightning
AG-163 Application Guide on Intrinsic Safety
OPC OLE for Process Control Standard, Version 1.0A
2.2 ORDER OF PRECEDENCE

In the event of conflicts between the above listed applicable regulations, codes and standards, the
following priority order shall be applied:
 Government legislation
 Project specifications and data sheets
 International Standards
 Industry standards
 Vendor / contractor codes and working standards
Latest editions of all codes and standards as at the date of issue of this document shall apply.
Deviations from applicable rules, codes and standards shall be subject to the written consent from
the company.

3.0 INTEGRATED AUTOMATION AND SAFETY SYSTEM

Overall control and monitoring of the facilities will be carried out by an Integrated Automation and
Safety System (IASS). This will be composed of the following elements, Process Automation System
(PAS), Safety Instrumented System (SIS) and Fire and Gas System (FGS).
The overall control, operations and management of business data shall be provided by the PAS.
3.1 OPERATIONAL REQUIREMENT

The IASS shall meet the following basic requirements:
 Centralized plant wide process monitoring and control of the gas Conditioning and Metering
Station locally, the Central Control Room with minimum intervention.
 Have a “single window” operator interface for PAS, SIS and FGS operation.
 Extensive Remote and Local diagnostic capability to enhance system availability
 Asset Management capability
 Be of an inherently reliable design.
 Have open systems of communication.
 Be supported for the 25 year lifetime of the project.
 Be easy to maintain.
3.2 MANNING STRATEGY
It is envisaged that the Central Control Room will be operationally manned on a 24 hour basis.

4.0 PROCESS AUTOMATION SYSTEM

4.1 GENERAL
The PAS shall comprise of an integrated plant automation, control and information system utilizing
the concepts of a global database and “single window” operational interface to the plant operational
and control functions. The PAS shall provide regulatory controls required to maintain operational
stability of the plant and equipment under safe operating conditions. It shall also offer advanced
control plus information functions aimed at enhancing availability. Facilities shall also be provided
within the PAS for online optimization and provision of management information on the plant
performance and operational indicators of the total plant for further optimization at field level in the
CCR or other Operation Bases.
In conceptual terms, the PAS shall include two distinct networks:
 Process Control Network (PCN)
This is an isolated network that shall provide communication between the Field Control Units (FCU)
and the workstations. The PCN shall extend across all Gas Processing and Metering facilities so that
full PAS operator functionality is provided both at the field, CCR and other operational bases.
 Process Integration Network (PIN)
A separate High Speed Ethernet network shall be provided along with an OPC/Server Integration to
form the Process Integration Network (PIN). The OPC Integration Server shall be connected to the
PCN and PIN. The PIN shall extend across all Egbin Metering Station gas conditioning and metering
facilities in a transparent and seamless manner to provide bi-directional data access between the
PCN and other applications running on the PIN. The PIN shall also support third party system
integration.
4.2 SYSTEM ARCHITECTURE

The entire IASS architecture shall be based on the Open system concept to provide greater flexibility
of sub-systems integration and seamless data transfer.
In hierarchy terms, the PAS is conceptually to consist of four basic layers:
 Field Control Units (FCU)
 Process Control Network (PCN)
 Process Information Network (PIN)
 Business Network (BN)
The functional requirements are described in the PAS Specification document.
4.3 SYSTEM COMMUNICATIONS

OPC shall be used exclusively as communication standard to provide data integration for sub system
integration.
4.4 PROCESS CONTROL

The Control of the various plants within the NEMS shall be accomplished within the PCN through the
FCU’s. The various field devices shall be integrated to the PAS-PCN through the FCU.

4.5 PACKAGE UNIT CONTROL

It is intended that modularized packaged equipment is utilized where possible to minimize site work,
and this equipment will in general be provided with its own measurement, control and protection
systems. Comprehensive OPC links between the package control system and the overall process
automation system will be implemented to provide the operators with a single HMI for all equipment.
The level of interface should allow remote start up, online control/monitoring and shutdown of
package equipment from the PAS.
Whilst standardization of types of control systems and protection systems is a consideration when
selecting the various packages, use of package vendors proven standard control systems is also a
desirable solution in order to avoid costs and design problems associated with bespoke systems. It is
a minimum requirement that the serial data links to the PAS should be configured utilizing the TCP/IP
protocol. A single method of data transfer over the TCP/IP links shall be adopted on the project; this
will be defined by the PAS vendor.
4.6 OPERATOR INTERFACE (HMI)

4.6.1 Displays and Graphics
The HMI shall be designed to allow multiple, simultaneous (multi-tasking) window sessions and user
display preferences set-up (colour choices, window sizes, etc.). It shall also be possible to operate in
a co-ordinate two monitor mode to obtain maximum parallel process information.
The update mode of the process variables shall be at a configurable “report by exception” or “report
at a fixed sample rate basis”. The process graphic application software shall utilize an object oriented
technology and shall be seamlessly integrated in the PAS.
Total mimic display shall be available within 1-3 seconds from completion of keying sequence.
The HMI shall be designed to satisfy the requirements stated in the PAS functional specifications.
4.6.2 Alarm/Event Handling

All alarms generated by the PAS shall be annunciated at the operator interface stations within one
second from occurrence.
An alarm shall generally be initiated to warn the operator of any abnormal condition. For example, if
the flow rate at any point within the system exceeds or fall below a defined threshold, the flow
computer can initiate an alarm to a local or remote control system using relay connections. Typical
relays include;
 Low flow alarm
 High flow alarm
 Pre-warn alarm
 Security alarm
If the alarm remains active for a certain number of seconds or if multiple alarms occur in succession
within a defined time frame, the control system shall be programmed to shut down equipment or
ramp up pumping speeds to balance the system flow

An event is a digital status change, or the crossing of a pre-defined threshold value (for analogues,
totalizes and derived values) or operator acceptance.
At least two alarm priority levels are required to indicate required urgency of response.
Any 'override' of an SIS shutdown function shall be individually alarmed in the PAS.
4.6.3 System Upgrade Capability

The proposed system shall be such that the required hardware and software for the initial project
phase can be installed and to incrementally make additions to the system whenever required without
rendering the initial hardware /software and general system architecture obsolete.

5.0 SAFEGUARDING SYSTEM

5.1 GENERAL
A separate and dedicated Safety Instrumented System (SIS) shall be provided for safeguarding of
the entire NEMS facilities to continuously monitor potential hazards and determine when normal
control action has failed or reached the limit of its control. Based on this analysis the SIS shall
generate alarms and take corrective action in accordance with the Cause and Effect Matrices. The
corrective actions shall include both manually and automatically initiated safe and controlled
shutdown of equipment, processes, plant and utilities. The shutdowns shall include means to isolate
equipment and de-pressurize facilities where appropriate and be in accordance with the NGPTC
Shutdown philosophies.
Shutdown facilities, including those associated with packaged units shall be implemented through the
SIS. ESD and PSD actions, as shown on the P & IDs, shall both be implemented within the SIS.
Manual push button stations shall be provided both locally throughout the facility were deemed
necessary and centrally for operational and safety reasons. These push buttons shall be wired in a
fail-safe manner (closed contact during normal conditions, open contact for trip) to the SIS I/O.
'Performance' monitoring and alarming shall be provided for all ESD valves, based on continuous
reconciliation of valve position and valve actuation signal through logic and software applications
implemented in the PAS.
The operator interface shall be implemented in the PAS but also have a hardwired operator interface
with the pushbuttons/indicators.
5.2 SYSTEM HARDWARE

A PLC based SIS is envisaged for the NEMS facilities to exploit the following advantages:
 Ease of interfacing with the rest of the PAS
 Fault tolerant capability
 Extensive on-line diagnostic capability
 Adaptation to future plant expansion/upgrade
The PLC system shall be of a redundant design in terms of controller, power supply, and
communication. Input/output cards shall be redundant as required.
The design of the Safeguarding system shall meet the NGPTC and International Standards.
5.3 FIELD INSTRUMENTATION INPUTS

The input sensors to the SIS shall be “HART” field transmitters. Alarm switches should only be used
for monitoring process excursions outside normal control boundaries when transmitters are
unavailable or impractical. All process signals to the SIS shall be derived from transmitters operating
in the analogue mode. Transmitters shall not be used in digital mode. The PAS shall compare
process values derived from trip transmitters to values derived from inputs to the process control and
monitoring system for earlier detection of faulty equipment.
The input/output of the SIS from field devices shall in general include all devices involved in the
protection of the plant.

5.4 MAINTENANCE OVERRIDES

A keyed maintenance override enable switch for each process unit shall be installed. These switches
shall be hardwired to the SIS. When the hardwired maintenance override function for a process unit
is enabled, a soft keyed individual input bypass shall be permitted. A maximum of one initiator per
protection group shall be overridden at any one time. Maintenance overrides shall only inhibit the
initiator’s input to shutdown functions and shall not inhibit the alarm function associated with the
initiator. SIS outputs shall not be overridden. The application and removal of maintenance overrides
shall be automatically recorded in a Maintenance Override Log.
5.5 SEQUENCE OF EVENT RECORDER (SER)

The SIS shall be equipped with a sequence of events recorder for acquiring, storing and retrieving
time stamped event data within the SIS. Preferably, all SER information will be transmitted with a
time stamp to the PAS through a standard protocol. The PAS should also have the possibility to
combine SER information from various sub-systems with the PAS alarm list and audit trail so that a
complete sequence of events can be presented to the operator.
5.6 SHUTDOWN DEFINITIONS

The shutdown levels shall be designed according to the NGPTC Shutdown Philosophy.

6.0 FIRE & GAS SYSTEMS (FGS)

6.1 SYSTEM DESCRIPTION
The Fire and Gas system will monitor the NEMS field detectors for any potentially hazardous
escapes of gas, outbreak of smoke or fire, as appropriate. In the event of any of these happening, it
will either, raise an alarm, initiate the release of relevant extinguishing medium and or issue an
executive command via the SIS for a process/ equipment trip, as appropriate.
The Centralized Fire and Gas system shall be designed with hardwired field detector inputs and
alarm outputs. The hardwired interface between the detector or control unit and the FGS shall be
either 4-20 mA or potential-free contact.
Executive actions derived from automatic or manual initiation of the Fire and Gas system will be
routed by hardwired connection via the safeguarding system.
The System shall be compatible with the full range of detection and manual initiation devices. It will
have in-built self-diagnostic capability with data interfacing facilities to PAS for fault reporting and
visual display of the NEMS alarm conditions.
CCR Fire and Gas systems shall be provided.
Provision will be made for the hardware to be tested on-line. Facilities for manual overrides of
executive action outputs shall be provided for maintenance and operational requirements.
6.2 SYSTEM HARDWARE

A PLC based FGS shall be provided for the NEMS facilities to exploit the following advantages:
 Ease of interfacing with the rest of the PAS
 Fault tolerant capability
 Extensive on-line diagnostic capability
 Adaptation to future plant expansion/upgrade
6.3 FIRE DETECTORS
The facilities shall incorporate “smart” fire & gas detectors. Devices such as rate of rise temperature
switches, smoke detectors and manual alarm call points shall utilize potential-free output contact only
but all other detectors shall incorporate a 4-20 mA DC output. The construction of the detector should
allow calibration and verification by a single person.
Fire & gas detectors shall be selected in accordance with, NGPTC and FGS- Fire, and gas detection
systems Philosophy Document number NEMS-NGC-LNL-EGT-ICS-004.
6.4 FGS HMI

The status of the FGS shall be available on the PAS operator station. The status shall include:
 I/O status
 Diagnostic information
 Abnormal situations
 Analogue values from trip transmitters

 Status of maintenance overrides

6.5 SEQUENCE OF EVENT RECORDER (SER)
An SER is required for the FGS.The same SER shall be utilized for both SIS and FGS.
6.6 MAINTENANCE OVERRIDES

Inputs to the FGS from initiators having executive actions other than alarming in the control room(s)
shall be provided with maintenance override facilities to allow testing of such inputs. The override
requirements shall be similar to the SIS overrides. Operational overrides shall not be used for FGSs.

7.0 SYSTEM AVAILABILITY

The IASS shall be designed to achieve very high availability.
The PAS shall offer an availability of 99.98% or better.
The availability targets for the SIS and the FGS shall be 99.98% or better.

8.0 SYSTEM INTERFACES

8.1 PAS/SIS INTERFACES
SIS information is required for Incident Analysis and Emergency Response purposes to provide an
accurate sequence of events leading up to an incident. To achieve this, the PAS will track the status
of all equipment which can be shutdown by the SIS, including maintenance and start-up overrides
and interlocks.
All SIS devices and operating parameters, PAS devices and operating parameters and similar data
from other sub-systems, shall be viewed through a common operator interface workstation as a
“single window” concept.
SIS monitoring, control and diagnostic information shall be passed on to the PAS for viewing,
printing, archiving, etc.
To facilitate the reporting function, the SIS shall be connected to the PAS either through a native
connection at the PAS control network or through an OPC link. No control signals, other than those
required for the operation of the link, will be accommodated. The control signals shall be hard wired.
The normal start / stop control of electrically operated equipment will be carried out by the PAS.
The emergency shutdown of electrically operated equipment shall be carried out by the SIS through
an interposing relay panel connected to the switchgear.
Final control elements which are used solely for SIS functions shall also be interfaced with the PAS
so that valve diagnostic data will be gathered and maintained by the PAS. The interface shall also
facilitate the synchronization of the PAS outputs and the SIS outputs for these control elements to
avoid discrepancies.
8.2 PAS/FIRE & GAS INTERFACE

To provide an audit trail for Incident Analysis & Emergency Response purposes, it is required that
following a hydrocarbon release, the area of release, the extent of spread and ignition point
sequence of events and associated analogue values be recorded. To confirm that the design integrity
of the asset is sustained, it will be necessary to keep an historic record of content, timing and
numbers of F&G alarms/alerts and F&G instrumentation performance.
Fire & Gas data will be viewed by the operator via mimic displays on the PAS. The F&G HMI will give
the operator sufficient information to quickly assess an incident and initiate the appropriate
emergency procedures. This information will include an overview of the status, identity, current value
and location of individual F&G end elements in alarm, to provide early warnings of impending
problems and the ability to track the course of an event.
To facilitate the reporting function, the Fire & Gas System shall be connected to the PAS either
through a native connection at the PAS control network or through an OPC link. No control signals,
other than those required for the operation of the link, will be permitted. The control signals shall be
hard wired.
8.3 PAS/THIRD PARTY INTEGRATION

Third Party equipment systems e.g. Heaters, Metering systems etc. shall be integrated with the PAS.
All equipment package operating parameters and the PAS operating parameters shall be viewed
through a common operator HMI. Communications between these shall be through a native

connection on the PAS-PCN network – PIN network shown on architecture drawing, via an High
Speed Ethernet link Device to the PAS-PIN Network, or an Ethernet OPC connection on the PAS-
PIN. Monitoring, control, and diagnostic information shall be passed on to the PAS for viewing,
printing, archiving, etc. Equipment package control systems shall where possible be HART devices
for processes control/monitoring and safeguarding respectively, which have embedded diagnostic
and/or resource data. In such a case, the diagnostic and resource data shall be integrated with the
PAS Device Management Application through the use of OPC Client-Server technology.
8.4 FIRE & GAS/SIS INTERFACE

The Fire & Gas system will be integrated into the SIS using the same family of hardware. Fire & Gas
and SIS I/O and logic operations will have their safety functions segregated by using separate
modules and cabinets but will have some non-safety functions such as the operator interface shared.
Each will have its own matrix panel for primary operator interface.
The Fire & Gas logic will directly drive outputs associated with fire dampers, status lights, etc.
However, outputs which require the shutdown and isolation of plant and/or process which directly
affects the process will be routed discretely into the SIS logic where the safety shutdown logic
resides.

9.0 METERING
The principal objectives of NEMS metering is to be able to accurately quantify the amount of gas
being consumed by the Egbin Power Plant. Provision shall also be made for evaluation of the quality
of the export gas.
9.1 GAS MEASUREMENT

Gas quantity metering will be carried out at the NEMS Station. This will be done automatically and
continuously by means of four (4) parallel Orifice Flow-meter runs.
The metering will generally be in accordance with NEMS Metering Philosophy OG1701-PHI-INS-001.
The metering instrumentation shall be connected to a dedicated metering panel complete with flow
computers.
 Volume flow rate for each meter run
 Total volume delivered
 Total daily volume delivered
The composition of the gas shall be determined by an on-line Gas Chromatograph, and moisture
analyzer.
The accuracy of the metering system shall be within +/- 5 % at normal operating conditions. All key
measurement points shall be accessible for display to the operator through the PAS.

10.0 FIELD INSTRUMENTATION

10.1 GENERAL
Field devices based upon 4 – 20ma/HART intelligent field devices shall be used to support asset
management. The Field devices shall be interfaced to the PAS through the FCU.
Dedicated intelligent transmitters conforming to the HART protocol shall be utilized for interface with
the SIS, certified for safety application consistent with IEC 61508, communicating in a 4-20 mA signal
mode. Direct process detection switches shall not be used.
The requirements for the intelligent transmitters (HART) are specified in the IASS Functional
Specification. HART compliance is required to ensure a common device data structure for on-line
diagnostics required to support Asset Management requirements.
SIS process instrument connections shall be independent of PAS instrumentation connections.
In order to minimize spare parts required for the facility, all instruments, by type, shall be of the same
manufacturer and model series for process control and SIS applications individually. Close-coupled
mono-block isolation/vent valves are the preferred installation option wherever practicable.
10.2 HAZARDOUS AND COMPLIANCE

Wherever possible, hazardous area instrumentation shall be intrinsically safe (IS), with consideration
to flameproof (EExd) only where intrinsic safe (EEx i) installations are not feasible or practical.
Within IS signal wiring; galvanic isolators should be applied rather than shunt-barriers.
10.3 INSTRUMENT INDEX

In order to provide a common database of configuration and specification information associated with
the instrumentation procured, an instrument index will be produced and maintained. Instrument tags
for process equipment will be extracted from the project P & IDs. Additional data that will be extracted
from the P & IDs will be the associated P & IDs number, equipment number, equipment description,
piping line number and asset management number. Equipment description will be used to form a
service description for the instrument.
10.4 DISCRETE SIGNAL LEVELS

Electric and pneumatic signal levels shall typically be configured such that loss of a signal equates to
an alarm condition:
 Discrete electrical signals shall be wired such that a closed contact or an energized relay or an
energized solenoid valve indicates a normal operating condition; an open contact or a de-
energized relay or a de-energized solenoid valve indicates an alarm and/or shutdown condition.
Exception to this is for fire system solenoids which are energized to operate.
 Discrete pneumatic signals shall typically be ported such that the presence of pneumatic pressure
indicates a normal operating condition; absence of pneumatic pressure indicates an alarm and/or
shutdown condition.

11.0 INSTRUMENT INSTALLATION AND INTERCONNECTIONS

11.1 JUNCTION BOXES AND WIRING
Field wiring shall, where possible, be intrinsically safe to allow maintenance of field devices without
de-energizing circuits. Digital and analogue IS signals shall be on segregated cables and junction
boxes.
Wiring from control devices to the PAS shall be separate from wiring from Safeguarding System
devices to the SIS. Specifically:
 PAS control devices and Safeguarding safety devices shall be separate sensors.
 Junction boxes shall be made of fiberglass reinforced polyester and be as a minimum of safety
“Ex e” type with protection degree IP 65.
 Junction boxes shall be labelled using engraved Trapholyte plates. Letters shall be 15mm high.
Plates shall be coloured as follows:
 “Process” junction boxes: White background with black letters
 “Safety” junction boxes: red background with white letters
 “Intrinsic safety” junction boxes: blue background with white letters.
 All accessories, screws or rivets shall be stainless steel.
 Separate PAS control junction boxes shall be utilized for 4-20 MA or 24VDC discrete signals.
 Separate cables shall be utilized for wiring of control devices and safety devices to the PAS and
SIS.
Wiring from field discrete sensors shall typically use closed contacts to signify a normal condition,
and open contacts to signify an alarm.
Wiring to field solenoid valves shall use an energized valve to command a normal condition, and a
de-energized valve to command a shutdown condition.
Armored cable shall be used for physical protection of wiring. Cable shall be routed directly from
instruments to junction boxes. From junction boxes to the IASS marshalling cabinets in the auxiliary
or control room, armored cable will be routed in cable trays/racks. Cable for intrinsically safe circuits
shall have a blue jacket.
11.2 INSTRUMENT GROUNDING

Conventional instrument grounding systems shall be designed such that each instrument control loop
system is grounded at a single point only, through the cable screens / shields. Screen grounds shall
be separated from 'dirty' panel grounds and IS grounds. 'Dirty' plant grounds are for electrical safety
grounding only.
A common bus-bar system should be provided for this single point grounding, preferably in Galvanic
Isolator Cabinets in the Auxiliary or Control Room.
Field instrument bodies, junction box housings, marshaling box cabinets and any other system
cabinet shall be solidly grounded to the plant ground.
In addition, and not as a substitute for cable shields, cable armor shall be continuous and grounded
via the glands at junction box, instrument, and panel.
11.3 MOTOR CONTROL INTERFACE

The interfacing between the electrical switchgear and the PAS shall be via digital signaling. SIS
interface shall be hardwired via galvanic isolation, between low voltage instrumentation (24 VDC) and
high voltage electrical equipment.
The following motor controls are typically provided for each process motor:
 A Permissive to Run signal from the SIS (via dry contact)
 A Start signal from the PAS
 A Stop signal from the PAS
 A motor Running indication to the PAS
 A motor HOA Status indication to the PAS (i.e., the field Hand-Off-Auto switch is not in Off, and
the motor is available to run)
Each motor starter shall interface with the SIS via a Permissive to Run contact closure. The SIS
contact shall be closed during normal operation. If the safety system requires that a motor be shut
down, this SIS contact will be de-energized and opened. If the motor is in non-critical or in utility
service (e.g. a water pump), and is never to be shut down by the SIS logic, this contact closure will
not be provided in the SIS and the appropriate motor starter terminals will be jumpered.
A local Hand-Off-Auto station shall be provided near each motor to allow Operations personnel to
stop the motor in the field. The Hand position is spring return to OFF to allow for local running of
motor.
11.4 INSTRUMENT SYSTEM POWER SUPPLY

Un-interruptible Power Supplies (UPS) shall be provided at each site to power instrumentation
systems. UPS voltage will be 230 VAC, 50 Hz. The UPS shall be able to provide two (2) hours
backup time at maximum load in the event of loss of main power.
11.5 INSTRUMENT GAS SYSTEM

An instrument gas conditioning system shall be provided. The system shall include filtering, and
drying facility of a natural gas to obtain a filtered and dry gas stream.
The filtered and dried gas stream shall be heated in a heater and regulated through a pressure
regulator.
The system shall be equipped with check valves, pressure regulators, heaters, relief valves, pressure
switches, dryers and buffer vessel in a redundant setup to provide the instrument gas for the
instrumentation. Operating pressure will normally be 6-9 barg. However, instruments and actuators
shall be designed to work in the complete range from 5 barg to 10 barg at instrument inlet.
11.6 INSTRUMENT PHYSICAL IDENTIFICATION

All instrument items shall be supplied with a securely attached nameplate, showing the instrument
tag number and purchase order number.
For field instrumentation, nameplates shall be screwed or riveted to the unit's body with SS hardware.
If the item is such that screws or rivets are not acceptable, or if a supplemental tag is required, an SS

tag may be wired to the item using a minimum of 18 gauge 316 SS wire. Adhesives shall not be
used as the sole means of attachment.
For indoor panels, nameplates may be Gravoply or 2-plex, instead of SS.

12.0 LIGHTNING PROTECTION

It is a major concern that all systems shall be designed to have a very high tolerance to lightning
strikes, which are prevalent in the area.
In order to reduce the effects of lightning strikes on the electronic control and safeguarding systems,
the following steps shall be taken to reduce the effects on electrical equipment.
Cabling systems for both power and signaling shall be protected by means of the installation of
proprietary anti surge devices, which route surges to earth thus protecting the equipment. Typically
anti surge devices shall be installed on the main power incomers to each building or equipment
enclosure. Additionally, individual electronic systems shall be protected by surge protection devices
in their power supplies and individual signal and data lines. Surge protectors shall also be installed
on antenna connections to the various radio systems.
For field instruments, locally mounted surge protection devices shall be used depending on their
criticality and consequences of failure of the particular instrument.

13.0 SCADA
To facilitate real time and remote operations and access to operations and maintenance data from
other sites and locations, the PAS shall embrace Wide Area Network capability inherent in the OPEN
SYSTEM architecture.
The PAS shall be fully compatible with the SCADA software; it shall be possible to transfer data
to/from the PAS via an OPC interface to satisfy the following typical diversely located user’s
requirements as a minimum:
 Operator (located at CCR); continuously monitor alarm status, review process variable trends,
and manage the process in general.
 Control System Engineer (located at CCR): Maintaining the PAS global database, device
configurations, network management etc.
 Process Engineer (located at the remote office): Monitoring process unit status and equipment
status to optimize system operation.
 System Administrator (located remote office). Maintaining administrative database and for
monitoring and maintaining performance of the PAS networks. He shall also be responsible for
maintaining all data archiving system.
 Production Manager (Remote office): Setting system gas production targets and maintaining
overall system availability. He uses the PAS to gather process variables, trends, equipment
status reports and for sensitivity analysis.

14.0 SECURITY/ACCESS CONTROL

The various levels of data within the PAS shall have strictly defined accessibility to ensure proper
user authorization.

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NIGERIAN GAS COMPANY

ENGINEERING, PROCUREMENT &

INSTRUMENTATION AND CONTROL SYSTEM

R01 8/02/2021 for Review A.O. B. A

REVISION HIS TORY

Revision Date Description Remarks

R01 8/02/2021 Issued for Review

Instrumentation and Control System Philosophy Page 2 of 28

Instrumentation and Control System Philosophy Page 3 of 28

7.0 SYSTEM AVAILABILITY ....................................................................................................... 18

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Instrumentation and Control System Philosophy Page 5 of 28

1.1 PROJECT DESCRIPTION

Figure 1: Satellite view of Egbin Metering Station, Egbin

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Instrumentation and Control System Philosophy Page 7 of 28

FISCO Fieldbus Intrinsic Safety Concept

Instrumentation and Control System Philosophy Page 8 of 28

2.0 APPLICABLE CODES AND STANDARDS

2.2 ORDER OF PRECEDENCE

Instrumentation and Control System Philosophy Page 9 of 28

3.0 INTEGRATED AUTOMATION AND SAFETY SYSTEM

3.1 OPERATIONAL REQUIREMENT

Instrumentation and Control System Philosophy Page 10 of 28

4.0 PROCESS AUTOMATION SYSTEM

4.2 SYSTEM ARCHITECTURE

4.3 SYSTEM COMMUNICATIONS

4.4 PROCESS CONTROL

Instrumentation and Control System Philosophy Page 11 of 28

4.5 PACKAGE UNIT CONTROL

4.6 OPERATOR INTERFACE (HMI)

4.6.2 Alarm/Event Handling

Instrumentation and Control System Philosophy Page 12 of 28

4.6.3 System Upgrade Capability

Instrumentation and Control System Philosophy Page 13 of 28

5.0 SAFEGUARDING SYSTEM

5.2 SYSTEM HARDWARE

5.3 FIELD INSTRUMENTATION INPUTS

Instrumentation and Control System Philosophy Page 14 of 28

5.4 MAINTENANCE OVERRIDES

5.5 SEQUENCE OF EVENT RECORDER (SER)

5.6 SHUTDOWN DEFINITIONS

Instrumentation and Control System Philosophy Page 15 of 28

6.0 FIRE & GAS SYSTEMS (FGS)

6.2 SYSTEM HARDWARE

6.4 FGS HMI

Instrumentation and Control System Philosophy Page 16 of 28

 Status of maintenance overrides

6.6 MAINTENANCE OVERRIDES

Instrumentation and Control System Philosophy Page 17 of 28

7.0 SYSTEM AVAILABILITY

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8.0 SYSTEM INTERFACES

8.2 PAS/FIRE & GAS INTERFACE

8.3 PAS/THIRD PARTY INTEGRATION

Instrumentation and Control System Philosophy Page 19 of 28

8.4 FIRE & GAS/SIS INTERFACE

Instrumentation and Control System Philosophy Page 20 of 28