10002-spc-in-00001-000-a01

Doc. No: 10002-SPC-IN-00001, Rev. A01

Title: SPECIFICATION FOR DELTA INSTRUMENTS

Page 2 of 58

SUMMARY PAGE

ABSTRACT

This document serves to define the Specification for Delta Instrumentation for the Process Control as well as that for the Emergency Shutdown and Fire and Gas. The Specification covers all Delta-included platforms, these being PFS7, PFS6, PFS3 and PFCP and defines the minimum compliance criteria for all Delta Instruments. Non-recommended and prohibited items are also indicated in the document

HOLDS

HOLD NONE

REFERENCED DOCUMENTS

Document Number Document Title

1 10002-BOD-GE-00001-000 Basis of Design

2 10002-LIS-IN-00003-000 Specification for Delta Control and Safeguarding

Systems

3 10002-LIS-IN-00001-000 Instrument and I/O List Delta 6 PFS7



6 10002-LIS-IN-00001-000 Instrument and I/O List Delta 6 PFCP

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TABLE OF CONTENTS TABLE OF CONTENTS.................................................................................................... 3

1 GENERAL .................................................................................................................. 8

1.1 INTRODUCTION ................................................................................................................. 8

1.2 PROJECT LOCATIONS ..................................................................................................... 8

1.3 PROJECT OVERVIEW ..................................................................................................... 10

1.4 PROJECT BATTERY LIMITS ........................................................................................... 10

1.5 OBJECTIVE ...................................................................................................................... 10

1.6 DEFINITIONS .................................................................................................................... 10

1.7 ABBREVIATIONS ............................................................................................................. 11

1.8 CODES AND STANDARDS ............................................................................................. 14

1.8.1 PETROM PHILOSOPHIES ............................................................................ 14

1.8.2 INTERNATIONAL INDUSTRY STANDARDS................................................ 14

1.8.3 SPECIFIC CODES AND STANDARDS ......................................................... 15

1.9 OMV PHILOSOPHIES ...................................................................................................... 16

1.10 UNITS .. ............................................................................................................................. 16

1.11 ELEVATIONS .................................................................................................................... 17

1.12 TAGGING .......................................................................................................................... 17

2 DELTA INSTRUMENTATION PHILOSOPHY ......................................................... 18

3 DESIGN AND CONSTRUCTION ............................................................................. 19

3.1 GENERAL ......................................................................................................................... 19

3.2 SIL RATED INSTRUMENTS ............................................................................................. 19

3.3 INGRESS PROTECTION .................................................................................................. 19

3.4 MATERIAL AND MATERIAL CERTIFICATION ............................................................... 19

3.5 FLANGED FITTINGS ........................................................................................................ 19

3.6 NOISE LEVEL REQUIREMENTS ..................................................................................... 19

3.7 RADIO FREQUENCY INTERFERENCE (RFI) ................................................................. 20

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3.8 NAMEPLATES / IDENTIFICATION .................................................................................. 20

3.9 SERIAL NUMBER ............................................................................................................. 20

4 DESIGN REQUIREMENTS ...................................................................................... 21

5 DESIGN MARGINS .................................................................................................. 22

5.1 DESIGN DEFINITIONS ..................................................................................................... 22

6 ELECTRICAL SUPPLY SYSTEMS AND REQUIREMENTS .................................. 24

6.1 INSTALLATION ELECTRICAL SUPPLIES ...................................................................... 24

6.2 INSTALLATION EARTH SYSTEMS FOR INSTRUMENTATION .................................... 24

7 HAZARDOUS AREA REQUIREMENTS ................................................................. 25

7.1 ATMOSPHERE EXPLOSIF (ATEX) ................................................................................. 25

7.2 CERTIFICATION CODE ................................................................................................... 25

7.3 ATEX CERTIFICATE NUMBER ....................................................................................... 25

7.4 CE MARK .......................................................................................................................... 25

7.5 INGRESS PROTECTION .................................................................................................. 26

7.6 INTRINSIC SAFETY ......................................................................................................... 26

7.7 LEVEL OF PROTECTION ................................................................................................ 26

8 INSTRUMENTATION CABLES ............................................................................... 27

8.1 SINGLE-PAIR INSTRUMENT COMMUNICATION CABLE CONSTRUCTION ............... 27

8.2 MULTI-PAIR INSTRUMENT COMMUNICATION CABLE CONSTRUCTION .................. 27

8.3 SINGLE-PAIR INSTRUMENT POWER CABLE CONSTRUCTION ................................. 28

8.4 MULTI-CORE INSTRUMENT POWER CABLE CONSTRUCTION .................................. 28

8.5 FIRE & GAS DETECTOR CABLE CONSTRUCTION ...................................................... 29

8.6 FIRE & GAS MASTER CABLE CONSTRUCTION .......................................................... 29

9 FIELD JUNCTION BOXES ...................................................................................... 30

9.1 IS JUNCTION BOXES ...................................................................................................... 30

9.2 NON-IS AND F&G JUNCTION BOXES ............................................................................ 30

9.3 CABLE GLANDS .............................................................................................................. 31

9.4 CABLE TERMINATION .................................................................................................... 31

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9.5 ELECTRICAL CONTACTS ............................................................................................... 31

9.6 ELECTRONIC ANALOGUE SIGNALS ............................................................................. 31

10 INSTRUMENT PROCESS CONNECTION .............................................................. 32

10.1 GENERAL ......................................................................................................................... 32

10.2 PROCESS TUBING / INSTRUMENT IMPULSE LINES ................................................... 32

10.3 QUALITY ........................................................................................................................... 32

11 FIELD INSTRUMENTS / DEVICES ......................................................................... 34

11.1 GENERAL ......................................................................................................................... 34

11.2 SURGE PROTECTORS .................................................................................................... 34

12 FLOW INSTRUMENTS ............................................................................................ 35

12.1 GENERAL ......................................................................................................................... 35

12.1.1 VOLUMETRIC FLOW MEASUREMENT ....................................................... 35

12.1.2 MASS FLOW MEASUREMENT .................................................................... 35

12.1.3 MAGNETIC INDUCTIVE ............................................................................... 35

12.1.4 VORTEX METER .......................................................................................... 35

12.1.5 ORIFICE MEASUREMENT ........................................................................... 36

12.1.6 INTEGRATED PITOT TUBE SYSTEM METERING ...................................... 36

12.1.7 TURBINE METER ......................................................................................... 37

12.1.8 CORIOLIS MASS-FLOW METER ................................................................. 37

13 LEVEL INSTRUMENTS ........................................................................................... 38

13.1 GUIDED WAVE RADAR LEVEL TRANSMITTER ........................................................... 38

13.2 SINGLE AND REMOTE SEAL LEVEL TRANSMITTERS ................................................ 38

13.3 BUOYANCY LEVEL TRANSMITTER ............................................................................... 38

14 PRESSURE INSTRUMENTS ................................................................................... 39

14.1 GENERAL ......................................................................................................................... 39

14.2 PRESSURE TRANSMITTER ............................................................................................ 39

14.2.1 MATERIALS .................................................................................................. 39

14.2.2 ELECTRICAL CONNECTIONS ..................................................................... 40

14.2.3 PROCESS CONNECTION ............................................................................ 40

14.3 DIFFERENTIAL PRESSURE TRANSMITTER ................................................................. 40

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14.3.1 MATERIALS .................................................................................................. 40

14.3.2 PROCESS CONNECTION ............................................................................ 40

15 PRESSURE GAUGES ............................................................................................. 41

15.1 GENERAL ......................................................................................................................... 41

15.2 PRESSURE GAUGE CASINGS ....................................................................................... 41

15.3 PRESSURE-SENSING ELEMENT ................................................................................... 41

15.4 CONNECTION .................................................................................................................. 42

15.5 SWITCHES ........................................................................................................................ 42

15.5.1 ESD AND F&G SYSTEM-CONNECTED SWITCHES ................................... 42

15.5.2 PCS-CONNECTED SWITCHES ................................................................... 42

16 MANIFOLD BLOCKS .............................................................................................. 43

16.1 GENERAL ......................................................................................................................... 43

16.2 MANIFOLD BLOCK/GAUGE ADAPTER FOR PRESSURE GAUGES ........................... 43

16.3 ORIFICE METER APPLICATIONS MANIFOLD BLOCK ................................................. 44

16.3.1 NON-INTEGRAL MOUNTING TRANSMITTERS .......................................... 44

16.4 MANIFOLD BLOCK FOR DIRECT OR REMOTE SEAL DP TRANSMITTER ................. 45

17 PROCESS CONNECTION OF FIELD INSTRUMENTS .......................................... 46

17.1 PRESSURE INSTRUMENT MOUNTING PHILOSOPHY ................................................. 46

17.2 PRESSURE INSTRUMENT ISOLATION VALVES .......................................................... 46

17.3 TEMERATURE INSTRUMENTS ....................................................................................... 47

17.3.1 TRANSMITTER PERFORMANCE SPECIFICATION .................................... 47

17.3.2 ELECTRICAL CONNECTION ....................................................................... 47

17.3.3 SENSOR CONNECTION .............................................................................. 47

17.3.4 HOUSING MATERIAL ................................................................................... 47

18 PT-100 RESISTANT THERMOMETER ELEMENTS (RTDS) ................................. 48

18.1 GENERAL ......................................................................................................................... 48

18.2 MATERIALS ...................................................................................................................... 49

18.3 PERFORMANCE .............................................................................................................. 49

19 TEMPERATURE GAUGES ...................................................................................... 50

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19.1 GENERAL ......................................................................................................................... 50

19.2 VESSEL MEASUREMENT ............................................................................................... 50

19.3 SKIN TYPE MEASUREMENT .......................................................................................... 51

19.4 THERMOWELLS .............................................................................................................. 51

19.5 CONTROL VALVES ......................................................................................................... 52

19.6 PNEUMATIC HART POSITIONERS ................................................................................. 52

19.7 HART DIAGNOSTICS ....................................................................................................... 52

19.8 SOLENOID VALVES ........................................................................................................ 52

20 FIRE AND GAS DETECTION & REQUIREMENTS ................................................ 54

20.1 GENERAL ......................................................................................................................... 54

20.2 FLAME DETECTOR ......................................................................................................... 54

20.3 ACCESSORIES ................................................................................................................ 55

20.4 GAS DETECTOR .............................................................................................................. 55

20.5 OPEN PATH GAS DETECTION RESPONSE TIME ........................................................ 55

20.6 POINT GAS DETECTION RESPONSE TIME .................................................................. 55

20.7 ACCESSORIES ................................................................................................................ 56

20.8 MANUAL CALL POINT REQUIREMENTS ...................................................................... 56

20.9 TERMS AND DEFINITIONS: ............................................................................................ 56

20.10ACTIVATION ..................................................................................................................... 56

20.11SURFACE PREPARATION AND PROTECTION ............................................................. 56

20.12DIMENSIONS .................................................................................................................... 56

20.13ACOUSTIC AND VISUAL ALARM (AVA) STATION ....................................................... 57

20.14IDENTIFICATION .............................................................................................................. 57

20.15TESTS . ............................................................................................................................. 57

20.16CALIBRATION .................................................................................................................. 58

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1 GENERAL

1.1 INTRODUCTION

PETROM is the largest Romanian oil and gas group with activities in the business segments

of Exploration and Production, Refining and Petrochemicals, as well as Marketing.

PETROM is part of the OMV group. The company operates approximately 15,000

Romanian onshore oil & gas wells and seven offshore platforms in the Black Sea for

exploration of the Histria Block Oil Fields located in the Romanian sector of the Black Sea

approximately 50 km offshore from the port of Constanta. The field consists of six satellite

platforms feeding in to a central production facility, where the main treatment of oil, gas and

water is undertaken prior to export of hydrocarbons to the onshore terminal, Midia. The

platform satellites to the west of the central production facility (PFCP) are aligned to the

western pipeline networks

PFS-8 PFS-7

A

B

PFS-6

A

B

PFS-3B

A

PFS-4M

A

H

PFS-1

PFS-2B A

PFCP-A B

C1

C2

PFS-U

Popa

s Si

torm

an(in

trar

e m

agis

tral

a)

Nisipari-Poarta Alba

TERMINAL MIDIA

Cablu de forta-12Kv (PFCP/C1-PGSU3) L= 1570m

Conducte chimicale (fascicul) PFCP/A-PFS4A, L= 2100m1 buc.=3 1/2"; 2buc.=2 3/8"

Injectie 3B-6A (6 5/8x 18mm) L= 7500m

Titei Terminal Midia-Nisipari (L= 62000m, DN=10 3/4")

Gaze Terminal Midia-SitormanDN=500mm si DN=700mm L=25000m (subteran)

S I S T E M D E E X P L O A T A R E S I I N J E C T I ETRANSPORTUL FLUIDELOR INTRE PLATFORMELE DE PRODUCTIE

Gaze 4A-PFCP/A12 3/4";L=2200m

Cablu optic C1-4A L= 2117m

Cablu de forta C1-4A L= 2140m

Injectie 6B-7A (6 5/8"x18mm) L=3000m

Injectie 7B-PFS86 5/8" x 18mm L= 10000m

Titei PFS8-6B(6 5/8" x 11mm) L= 12000m

Titei 7A-6B(6 5/8" x 11mm) L= 3000m

Injectie PFS1-3A (6 5/8" x 18mm) L= 1391m

Titei PFSU-PFS2A (6 5/8 x 11mm) L= 8900m

Titei 6B-3B(6 5/8" x 11mm)2 fire (L=7334m)

Titei 3A-PFS1 (12 3/4" x 16mm) L= 1950m

Gaze 3A-PFS-1(6 5/8" x 18mm L= 1500m

Titei 3A-2B(6 5/8" x 11mm)2 fire (L=2500m)

Gaze PFCP-Terminal MidiaSubmarin:PFCP-Vadu-16"; L=68657mUscat :Vadu-Terminal-16";L=15816m

TITEI PFCP-TERMINAL MIDIASubmarin: PFCP-Vadu (12 3/4"; L=68735mUscat: Vadu-Terminal (12 3/4"; L= 15875m

Figure 1, PETROM platform overview

1.2 PROJECT LOCATIONS

Delta-6 well shall be directionally-drilled and completed on PFS7 topside

The following locations and offshore platforms are included in the Delta Project:

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Location

PFS-7 Process Platform

New routed Associated Gas Pipeline PFS-7 to PFS-6 and

existing condensate pipeline PFS-7 to PFS-6


Existing Associated Gas Pipeline between PFS-6 to PFS-3 and

existing condensate pipeline PFS-6 to PFS-3


Existing Associated Gas Pipeline between PFS-3 to PFS-1 (PFCP complex) and

existing condensate pipeline PFS-3 to PFS-1 (PFCP complex)

PFS-1 Wellhead Platform

PFCP A Main Gas Process Platform

Figure 2 Location and extension of the offshore production system (source Petromar)

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1.3 PROJECT OVERVIEW

The Delta South oil reservoir was discovered in 2007 in the Histria Block. Delta South is

located about 3.5 kilometres to the North West of the PETROM production platform PFS-7

in approx. 40 metres water depth

The project scope comprises of one (1) oil well, Delta-6, drilled from and completed on

PFS7 topsides. Fluids from Delta-6 shall be directed to a new separator with gaseous phase

measured and sent onto PFS6 through a new gas pipeline and also liquid phase measured

and tied-in into an oil pipeline to PFS6. Gas shall be further sent to PFCP through two

existing pipelines PFS6-PFS3 and PFS3-PFCP dependent upon integrity assessment and

Certification for service by GL

1.4 PROJECT BATTERY LIMITS

The following battery limits shall apply to the Delta Development Project:

Upstream: PFS7 Topsides Christmas Tree - Delta-6 (D6)

Downstream:

Gas Tie-in into PFCP 2nd stage gas compression

Condensate Tie-in into PFCP HP separation system

Tie-in into PFS-7 oil export system via PFS6 & PFS3

1.5 OBJECTIVE

The objective of this document is to provide the Specification for Control and Safeguarding

Systems that shall enable the safe and compliant implementation of the Delta project on

PFS7, PFS6, PFS3 and PFCP to IEC61511

Further additional parameters to be used for design and engineering shall be quoted in

reports and specifications relevant to the associated subjects

1.6 DEFINITIONS

The following definitions shall be used:

Company is PETROM S.A. or a designated Integrated Project Management Team (IPMT) performing work on behalf of PETROM S.A

Contractor is the party, which carries out all or part of the design, engineering, procurement, installation and commissioning or management of a project or operation of a

facility for the Delta Project

Manufacturer / Supplier is the party, which manufactures or supplies equipment and services to perform the duties specified by the Contractor or Company

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Inspection Authority Germanischer Lloyd

The word shall indicates a requirement

The word should indicates a recommendation

The word may indicates a possible course of action

The word can indicates a possibility and capability

1.7 ABBREVIATIONS

The following abbreviations shall be used:

2oo3 Two out of three (Voting)

AC Alternating Current

BDV Blow Down Valve

BOE Barrel of Oil Equivalent

CA Corrosion Allowance

CCR Central Control Room

CITHP Closed In Tubing Head Pressure

CS Carbon Steel

CUPS Control Uninterruptible Power Supply

DC Directional Current

DCS Distributed Control System

dP Differential Pressure

EJB Electrical Junction Box

EPC Engineering, Procurement and Commissioning

ESD Emergency Shut Down

ESP Electrical Submersible Pump

Ex Explosion Proof

F&G Fire and Gas

FEED Front End Engineering Design

FTHP Flowing Tubing Head Pressure

FTHT Flowing Tubing Head Temperature

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FV Full Vacuum

GL Germanischer Lloyd

GDE Gas Detection Element

GOR Gas to Oil Ratio

HART Highway Addressable Remote Transmitter (Protocol)

HCl Hydrogen Chloride

HIPPS High Pressure Protection System

HMI Human Machine Interface

HP High Pressure

HV High Voltage

I/O Input/Output

IJB Instrument Junction Box

IP Internet Protocol

IPMT Integrated Project Management Team

IR Infra Red

IRP Interposing Relay Panel

IS Intrinsically Safe

LAN Local Area Network

LCR Local Control Room

LER Local Equipment Room

LFL Lower Flammable Limit

LOS Line of Sight

LP Low Pressure

LV Low Voltage

MAC Manual Alarm Call point

MSL Mean Sea Level

MV Medium Voltage

NL Normal Level

OLE Object Linking and Embedding

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OMV Oesterreichische Mineraloelverwaltung

OPC OLE for Process Control

PCS Process Control System

PFCP Central Platform Complex

PFS Platform Satellite

PLC Programmable Logic Controller

ppm parts per million

PSD Process Shut Down

PSLL Pressure System Low Level

PSV Pressure Safety Valve

RFI Radio Frequency Interference

SIL Safety Integrity Level

SIS Safety Instrumented System

SOW Scope of Work

SWB Steel Wire Braid

TCP/IP Transport Control Protocol / Internet Protocol

TMR Triple Module Redundancy

USD Unit Shut Down

UV Ultra Violet

VAC Volts Alternating Current

VDC Volts Direct Current

VLAN Virtual Local Area Network

VOIP Voice over Internet Protocol

VPN Virtual Private Network

WAN Wide Area Network

WAN Wide Area Network

WAT Wax Appearance Temperature

XT Christmas Tree

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1.8 CODES AND STANDARDS

This section includes an overview of applicable regulations, codes and standards to be

applied for the design and supply of the Delta Project facilities

Where codes and standards referenced herein have or may be superseded, the impact of

application of the updated standard on the existing facilities should be taken into

consideration

It is not intended that the referenced regulations, codes and standards included herein

should be exhaustive. Only base codes fundamental to overall design and supply are listed

Reference to specific codes and standards herein only indicates a general requirement and

shall not relieve any Responsible Party of his obligation to comply with the requirements of

any specific Contract relating to the Delta Project. Any errors, omissions noted shall be

immediately brought to the attention of the Company. Any conflict, inconsistency or

ambiguity between the codes and standards listed herein, and current practices shall be

identified by the Responsible Party

Where conflicts occur, the order of precedence shall be:

Local Regulations The provision of companys philosophy International standards National Standards

1.8.1 PETROM PHILOSOPHIES

The latest editions of the Petrom Offshore Philosophies shall apply:

1.8.2 INTERNATIONAL INDUSTRY STANDARDS

AISC American Institute of Steel Construction

ANSI American National Standard Institute

API American Petroleum Institute

ASME American Society of Mechanical Engineers

ASTM American Society of Testing and Materials

ATEX Atmosphere Explosif

AWS American Welding Society

BS British Standard

CCITT Comite Consultatif International Telephonique et Telegraphique

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CE Conformite Europeene

CENELEC European Committee for Electro-technical Standardisation

DIN Deutsche Industrienormung

DNV Det Norske Veritas

EC European Commission

EN European Norms

ETS European Telecommunications Standards Institute

GL Germanischer Lloyd

IEC International Electro-technical Commission

IEEE Institute of Electrical and Electronic Engineers

IMO International Maritime Organisation

ISA Instrument Society of America

ISO International Standardisation Organisation

ITU International Telecommunication Union

NACE National Association of Corrosion Engineers

NEMA National Electrical Manufacturers Association

NFPA National Fire Protection Association

Norsok Norsk Sokkels Konkuranseposisjon

UKOOA United Kingdom Offshore Operators Association

Unless the edition of any code, standard or document is specifically referenced to, the latest

edition at the time of contract award shall apply

1.8.3 SPECIFIC CODES AND STANDARDS

EU Directive

94/9/EC

Atmosphere Explosif (ATEX)

IEC61511 Functional Safety Safety Instrumented Systems for the Process

Industrial Sector

PED 97/23/EC Pressure Equipment Directive (European)

EN 54 Fire detection and fire alarm systems

EN 50081/2 Electromagnetic compatibility, generic emission, and immunity

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EN 60751 Industrial platinum resistance thermometer sensors

IEC 60079 Electrical apparatus for explosive atmospheres

IEC 60331 Tests on electric cables under fire conditions

IEC 60332-1/3 Tests on electric cables under fire conditions

IEC 60529 Degrees of protection provided by enclosures (IP code)

IEC 60079 Electrical apparatus for explosive gas atmospheres

IEEE 802.3 Industry Standard for Ethernet connections

IEC 61158 Digital data communications for measurement and control field-bus for

use in industrial control systems

IEC 61508 Functional safety of electrical/electronic/ programmable electronic

safety-related systems

IEC 61511 Functional safety - Safety Instrumented System

IEC 90003 Software engineering - guidelines for the application of ISO 9001:2000

to computer software

ISO 9001:2000 Management Systems - requirements

ISO 13709 Petroleum and natural gas industries - control and mitigation of fires

and explosions on offshore production installations

ISO 4406 Hydraulic fluid power - fluids - methods for coding the level of

contamination by solid particles

ISO 5167 Measurement of fluid flow by means of pressure differential devices

Other Specific Codes and Standards shall be referenced within the relevant project

documents

1.9 OMV PHILOSOPHIES

TO-HQ-02-121 Philosophy for Process Control Systems

TO-HQ-02-124 Philosophy for Emergency and Process Shutdown

TO-HQ-02-125 Philosophy for Fire and Gas Systems Offshore

1.10 UNITS

In general SI units shall be used as the main design units and all values quoted shall be in

these units. The size of the unit shall be appropriate to the value being measured, i.e., mm -

m - km

Where quoted in project documentation the following shall be used for reference conditions:

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Normal Conditions are at 0C and 1.01325bara (14.696psia) Standard Conditions are at 15.6C (60F) and 1.01325bara (14.696psia) Stock Tank Conditions are at 15.6C (60F) and 1.01325bara (14.696psia)

Standard conditions should be the preferred reference condition

1.11 ELEVATIONS

All offshore elevations shall be referenced to datum which is the Mean Sea Level (MSL)

1.12 TAGGING

New equipment, piping and valves shall be numbered as per the project tagging procedure

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2 DELTA INSTRUMENTATION PHILOSOPHY

The Instrumentation philosophy for Delta dictates that the following criteria shall be

observed during the Detailed Design stage:

1. All Instruments shall be ATEX certified

2. All instruments shall be two-wire

3. All instruments shall be hard-wired

4. All instruments shall be Highway Addressable Remote Transmitter (HART) capable

5. All Safety Instrumented System (SIS) instruments shall be Safety Integrity Level (SIL)

2/3 capable

6. Mod-bus protocol shall be used for communication with all Programmable Logic

Controllers (PLC)

7. Foundation Field-bus shall not be used

8. Profi-bus shall not be used

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3 DESIGN AND CONSTRUCTION

3.1 GENERAL

In view of the highly corrosive and saline atmosphere, all internal and external parts, which

are not corrosion-resistant by choice of material shall be prepared and finished with an

appropriate plating or paint finish. All printed circuit boards shall be coated so that their

tracks are not exposed to the atmosphere

All equipment shall also be able to withstand all adverse conditions during shipment,

storage and installation prior to commissioning

3.2 SIL RATED INSTRUMENTS

SIL-classified transmitters shall be third-party (e.g. TUV or equivalent) certified to fulfil SIL

2/3 requirements

3.3 INGRESS PROTECTION

All electronic / electrical instruments shall be protected to IP 65 as a minimum for field

mounted instruments, including junction boxes, cable glands and local control panels

SIL classified instruments shall be protected to IP66

3.4 MATERIAL AND MATERIAL CERTIFICATION

The vendor shall select the instrument wetted parts materials (e.g. tubes, seals,

diaphragms) so that they are resistant to the Process media and stated environmental

conditions.

See also relevant instrument data sheets

3.2 Material certification shall be provided in accordance with EN 10204.

3.5 FLANGED FITTINGS

All flanged items shall be in accordance with ANSI B16.5 with the exception of the flange

face finish, which shall be smooth (RA 3.2 to 6.3 to ANSI B46.1) for classes up to ANSI

1500

3.6 NOISE LEVEL REQUIREMENTS

To ensure the total allowable noise level of the installation is not exceeded, the actual

measured sound pressure level at 1m downstream of the line mounted item and 1m from

the piping shall not exceed 80dBA

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3.7 RADIO FREQUENCY INTERFERENCE (RFI)

These requirements apply to the equipment as normally installed, with installed cover,

closed doors, connected external cabling and powered-up

The equipment shall operate normally and within the same specifications, when subjected to

an RFI test according to IEC publication 801-3 Severity Class 3 (10 V/m), but over an

extended frequency range of 20MHz to 1000MHz instead of 27MHz to 500MHz. The total

effects of the radio frequency interference shall be equal or less than 0.1% of the output RF

power, this with the transmitter enclosure cover in place

3.8 NAMEPLATES / IDENTIFICATION

Each item shall be equipped with a manufacturers nameplate of 316 stainless steel

permanently attached with stainless steel screws or rivets indicating the specified data

referred to under the particular Instrument Specification, which shall show as a minimum:

1. Name of Manufacturer (and Supplier if different)

2. Type and Model Number (Including reference to any special features)

3.9 SERIAL NUMBER

Manifold blocks shall be provided with identification directly stamped on the body, or a non-

corrosive plate permanently attached to the manifold block by means of stainless steel rivets

or pins. The following information shall be provided, as a minimum:

1. Manufacturers name of trade mark

2. Manufacturers model number

3. Manufacturers serial number

4. Pressure/Temperature rating

Notes:

1. Manufacturers model number shall include type of trim material of the valve heads

2. Thermo-wells shall be stamped with Tag Number on flange edge

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4 DESIGN REQUIREMENTS

Design Life

The design life for all new equipment to be installed shall be 25 years, unless stated

otherwise

Availability

The new installations for the Delta Development shall be designed to achieve an overall

availability to be assumed in excess of 95%

Redundancy

The following Control or Control-associated equipment shall have critical component, N+1

or dual redundancy:

1. Control UPS

2. Distributed Control System

3. Safety Instrumented Systems (SIS) (ESD & F&G)

4. Instrument Air Supply

5. Microwave Communications Network

Other required redundancies shall be determined during detailed design

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5 DESIGN MARGINS

5.1 DESIGN DEFINITIONS

The following design definitions shall be used:

Design Capacity/Duty

The process heat and material balance capacity/duty of the most severe normal operating

case

Normal Operating Conditions

Normal Operating Conditions shall refer to the anticipated or calculated value of variables

(Temperature, Pressure, Speed etc) for a defined range of operating scenarios.

Subsequently, the stated Normal Operating Condition for any equipment item may be a

range of values

Rated Capacity

The rated capacity shall be the design capacity plus a design allowance

Rated Conditions

The values of other operating variables (E.g. Pressure, Temperature, Head etc) which occur

at the rated capacity

Design Conditions

The values of operating variables which define the mechanical design

Maximum Normal Operating Pressure

The maximum pressure expected during normal operation, including fluctuations due to

process control parameter changes

Design Conditions

The following statements on mechanical design conditions shall apply to all equipment and

piping:

Design Pressures

Design Pressures shall be set to allow continued operation under extreme ambient

conditions and off-design composition

Design Temperatures

Upper Design Metal Temperatures shall be a minimum of 60C (black bulb temperature), or

a minimum of 15C above the maximum heat and material balance case conditions,

whichever is the greater

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Minimum Design Metal Temperatures shall consider lowest operating temperature which

can be achieved or the minimum ambient temperature. Low temperature conditions such as

those resulting from blow-down activities shall be determined during detailed design

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6 ELECTRICAL SUPPLY SYSTEMS AND REQUIREMENTS

6.1 INSTALLATION ELECTRICAL SUPPLIES

The following power supplies shall be available on the installation:

Field Instrument Supply from UPS: 24V DC +/- 2~% (4-20 mA loop powered)

All instruments shall be suitable (if necessary by use of auxiliary equipment) for operation

within the above mentioned supply voltages/tolerances regardless whether these are

Process Control instruments or Safety Instrumented System instruments

6.2 INSTALLATION EARTH SYSTEMS FOR INSTRUMENTATION

All equipment for electronic data exchange/transmission, including the enclosures and

armoured/screened cables shall be properly earthed to ensure personnel safety and to

obtain the maximum possible attenuation of interference

The number of earth types shall be limited to two, i.e:

Safety Earth (General platform earth system Dirty Earth)

Instrument Earth Clean Earth for Instrument IS and Non-IS circuits

All earth connections shall be protected against corrosion, which might adversely affect the

earth resistance

All metal enclosures housing instruments and/or instrument systems and all cables screens

shall be connected to the general platform earth system

A dedicated instrument earth system shall consist of one or more earth electrodes installed

close to the control container, but at a safe distance from any general platform-earth

electrode

The resistance to earth shall be better than 4.0ohm. To achieve this criteria an array of

parallel electrodes may be used

All earths shall terminate on copper bus-bars, mounted centrally to all instrument

equipment, but electrically isolated from each other and any other equipment or structure

All connections to the copper bus bar shall be made using minimum 25mm2 stranded

copper cable or greater

To avoid undesired ground loops caused by differences in earth potential or due to influence

of surface currents, the screen of all instrument cables shall be connected to the dedicated

instrument earth system at one side only. The screen shall be kept isolated from cable

armour and instrument enclosures

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7 HAZARDOUS AREA REQUIREMENTS

7.1 ATMOSPHERE EXPLOSIF (ATEX)

Equipment and Protective Systems intended for use in potentially Explosive Atmospheres

shall be in accordance with the latest ATEX requirements of EU directive 94/9/EC

All electrical apparatus designated for use in Zone1 (Intermittent Hazard) Hazardous Areas

shall be marked according to the latest ATEX directives. E.g. II 2 G

1. - EU Explosive Atmosphere symbol

2. II - Equipment Group Non-mining

3. 2 - Equipment Category High Protection

4. G - Hazard Letter - Gas

All electrical apparatus for use in hazardous areas shall be certified by an ATEX-recognised

authority, e.g. BASEEFA, PTB and comply with IECEx or an equivalent ATEX-recognised

international standard

7.2 CERTIFICATION CODE

In addition, all electrical apparatus certified for use in a hazardous area shall also be marked

with a Certification Code (gases, vapours, and mists to EN 50014) E.g. Ex e IIC T4

1. Protection Concept Ex e Increased Safety

2. Gas Group IIC Class II Hydrogen

3. Temperature Class T4 Maximum Surface Temperature 135C

7.3 ATEX CERTIFICATE NUMBER

All electrical apparatus certified for use in a hazardous area shall also be marked with an

ATEX Certificate Number - E.g. Baseefa07ATEX1234

1. Baseefa - Notified body responsible for ATEX Examination

2. 07 - 2007 - Year Certification Issued

3. ATEX - ATEX Certified

4. 1234 Certificate Serial Number

7.4 CE MARK

All equipment shall bear a CE Mark including an ATEX Notified Body Identification number

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7.5 INGRESS PROTECTION

Marking for Ingress Protection according to EN 50281-1-1 shall be given on each instrument

certified for use in a Hazardous Area. E.g. IP66 T135C

7.6 INTRINSIC SAFETY

The following types of protection, in preferential order, shall be used in accordance with IEC

79 Electrical Apparatus for Explosive Atmospheres:

1. IEC 60079-11 Intrinsic Safety EEx ia

2. IEC 60079-01 Explosion proof EEx d

7.7 LEVEL OF PROTECTION

For reasons of standardisation, all field-mounted electrical equipment shall utilise the

following methods of protection:

1. All field instruments to be certified Intrinsically Safe EEx ia Gas group IIC and

Temperature Class T4 minimum

2. Junction boxes to be certified Intrinsically Safe EEx ia, ib Gas Group IIC and

Temperature Class T4 minimum

3. For solenoid valves (ESD/F&G/PAS SYSTEM) and associated junction boxes they

shall be certified EEx(d) Gas Group IIC and Temperature Class T4 as a minimum

All certificates and documentation required to satisfy the conditions of the certification shall

be provided by the Supplier as part of the equipment delivery

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8 INSTRUMENTATION CABLES

All instrumentation cables to be used shall be compliant IEC 60092-3. Separate cables are

to be used for IS, NON-IS and F&G circuits as specified in the following sections

8.1 SINGLE-PAIR INSTRUMENT COMMUNICATION CABLE CONSTRUCTION

Conductor: Plain annealed copper conductors, 7 wires stranded

Cabling Elements: Twisted single pair

Insulation: XLPE

Inner Sheath: Low Smoke Zero Halogen

Individual Screen: Not applicable due to single pair cable

Wrapping: At least one layer of plastic tape

Overall Screen: Plastic laminated metal foil + solid tinned copper drain wire

Armour: Galvanised metal braid

Outer Sheath: Low Smoke Zero Halogen

Outer Colour: Blue

Flame retardant or

Fire resistance: Flame retardant acc. IEC 60332

8.2 MULTI-PAIR INSTRUMENT COMMUNICATION CABLE CONSTRUCTION


Cabling Elements: Multi-pair acc. to project specification

Insulation XLPE


Individual Screen: PIMF pair screened + solid tinned copper drain wire





Outer Colour: Blue

Flame retardant or


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8.3 SINGLE-PAIR INSTRUMENT POWER CABLE CONSTRUCTION


Cabling Elements: Twisted single pair

Insulation: XLPE

Inner Sheath: Low Smoke Zero halogen

Individual Screen: Not applicable due to single pair cable





Outer Colour: According to project specification

Flame retardant or


8.4 MULTI-CORE INSTRUMENT POWER CABLE CONSTRUCTION


Cabling Elements: Multi-core acc. to project specification

Insulation: XLPE


Individual Screen: Not applicable due to non communication signals





Outer Colour: acc. to project specification

Flame retardant or


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8.5 FIRE & GAS DETECTOR CABLE CONSTRUCTION


Cabling Elements: Twisted 2 pairs

Insulation: Silicone or XLPE + Mica Tape







Outer Colour: According. to project specification

Flame retardant or

Fire resistance: Fire resistant acc. IEC 60331

8.6 FIRE & GAS MASTER CABLE CONSTRUCTION


Cabling Elements: Multi pairs acc. to project specification

Insulation: Silicone or XLPE + Mica Tape






Outer Sheath: Low smoke zero Halogen

Outer Colour: According to project specification

Flame retardant or

Fire resistance: Fire resistant acc. IEC 60331

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9 FIELD JUNCTION BOXES

As stated earlier for the cables, correspondingly separate junction boxes shall be used for

the termination of IS, Non-IS and F&G instruments

9.1 IS JUNCTION BOXES

The junction boxes for IS instruments termination shall have the following specification, as a

minimum:

Material: SS316L

Ingress Protection: IP 66

Entries: No rear or top entries permitted

Signal cable entry: Suitable for M20 cable glands

No of signal cable entries: According to detailed Design

No of master cable entries: According to detailed Design

Master cable entry: Suitable for M32 cable glands

Terminal type: WDU N.N (Mandatory blue in colour for EEx-i circuits)

Internal Earth Stud: Brass M8 minimum

External Earth Stud: Brass M8 minimum

ATEX approval: EEx (e) Gas Group IIC and Temperature Class T4

9.2 NON-IS AND F&G JUNCTION BOXES

Junction boxes for Non-IS and F&G instruments termination shall have the following

specification, as a minimum:

Material: SS316L

Ingress Protection: IP 66

Entries: No rear or top entries permitted

Signal cable entry: Suitable for M20 cable glands

M20 Adaptors F&G detectors & LOS detector proprietary cables

No of signal cable entries: According to detailed Design

No of master cable entries: According to detailed Design

Master cable entry: Suitable for M32 cable glands

Terminals type: EEx According to detailed Design

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Internal Earth Stud: Brass M8 minimum

External Earth Stud: Brass M8 minimum

ATEX approval: EEx (d) Gas Group IIC and Temperature Class T4

9.3 CABLE GLANDS

All cable glands shall be ISO metric entry thread with ISO M20 as the recommended

minimum size. However, cable gland size shall be as per the individual applicable

instrumentation cable. Cable glands shall be applied at all places where electrical signals

enter the housings of instruments and junction boxes

Cable glands shall be of Brass, Nickel Plated Brass, 316 Stainless Steel or Aluminium

manufacture, to Gas group IIC, Temperature Class T4, as a minimum

Cable glands shall be suitable to terminate Steel Wire Braid (SWB) armoured cables and

meet IP65 requirements, as a minimum. All cable glands shall be shrouded (black) as part

of the terminating procedure

Cable glands for Intrinsically Safe circuits shall have a blue-coloured shroud covering

Plastic glands shall not be used under any circumstances

9.4 CABLE TERMINATION

All terminations shall be screw clamp type terminals for N.Nmm2 conductors and correctly

certified where appropriate. No flying leads of any kind shall be permitted

9.5 ELECTRICAL CONTACTS

All potential-free contacts for instrument signals shall have 10 micrometer hard gold-plated

contacts. If such contacts are not available, hermetically-sealed contacts shall be utilised in

24VDC control circuits

All contacts shall be rated 1.0Amp at 24VDC for inductive circuits

9.6 ELECTRONIC ANALOGUE SIGNALS

The complete Electronic instrumentation transmission signals shall be provided by 2-wire

HART transmitters utilising a 4-20mA DC linear output signal from a nominal 24VDC supply.

RTD and thermocouple elements shall have their respective transmitters mounted locally,

also utilising 4-20mA DC

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10 INSTRUMENT PROCESS CONNECTION

10.1 GENERAL

Except for in-line instruments or instruments mounted in a thermo-well, each instrument

connection shall have an isolating block valve directly at the process tapping, supplied by

the piping department. This block valve shall be in addition to any required instrument

manifold block valve

Process connections for instrument impulse lines shall be terminated by a Swagelok

compression-type tube fitting. Swagelok shall be used as the mandatory manufacturer for

these applications throughout the project

10.2 PROCESS TUBING / INSTRUMENT IMPULSE LINES

For general applications, with regard to piping classes for carbon steel, low alloy steel,

stainless steel and aluminium alloys, the instrument impulse lines shall consist of fully-

annealed, high quality AISI 316 stainless steel components and Swagelok twin-ferrule

compression-type fittings

Vendors shall ensure that process tubes are of Imperial sizes

with 0.049 schedule, 3/8 with 0.065 schedule and with 0.083 schedule, shall be used

Note: Tubes or fittings based on metric size shall not to be used within the project. All fittings and tubes shall be manufactured by Swagelok

10.3 QUALITY

The general specifications shall apply, as a minimum:

1. All materials shall be seamless, cold-drawn, de-scaled, heat-treated, bright metal-

finished with clean, smooth surface

2. Material 1.4571 (~316 Ti) minimum (dependent upon process conditions)

3. Dimensions and Tolerances DIN 2462 D4 T4

4. D4 outside diameter +/- 0.1 mm and T4 wall thickness +/- 0.15 mm

5. Manufacture to DIN 17458 n2

6. Material Test Certificates according to EN 10204 3.2

7. All components, i.e. the tubing and compression fittings, shall be suitable for 413barg

maximum at 38C

8. The length of impulse lines shall be kept to an absolute minimum within the

constraints of accessibility

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9. Tubing shall be free from scratches and suitable for bending

10. Impulse lines shall be pressure-tested after installation

Manifold block valves shall have integral isolating facilities, in addition to the isolating valves

on the process connection. Any process, vent and drain connection (1/4 NPT female) shall

be provided by the manifold manufacturer with Swagelok compression fittings

For pressure gauges without diaphragm seals, a gauge block with an integral isolation valve

and an integral vent valve shall be applied in addition to the isolating valve on the process

connection

For pressure gauges with a diaphragm seal a gauge block is not necessary

For temperatures between - 100 C and + 200 C, close-coupled pressure gauges shall be

supported by the process connection and the associated gauge block. For all other

instruments, adequate supports shall be selected

All instrument impulse lines shall have facilities for venting or draining of instruments

Approximate 300 mm of tubing shall be fitted to these connections and directed downwards

The manifold block, which forms part of the impulse line arrangement, shall be bolted to a

mounting plate fixed to a support with stainless steel bolts, if applicable

The effect of water collecting in impulse lines, which slope downward towards the

instrument, shall be limited by keeping the difference in elevation between the instrument

and the process connection(s) at a possible minimum. Each sloped line of this kind shall be

stated by vendor of respective skid and approved by company. As a minimum, each sloped-

line shall be equipped with suitable draining facilities including condensate collection pots

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11 FIELD INSTRUMENTS / DEVICES

11.1 GENERAL

All electronic analogue instruments shall be equipped and installed with:

1. Local digital LCD-Display

2. SIL2/3 capable (only if connected to ESD or F&G system)

3. 4-20mA HART capable, 2-wire ATEX/Intrinsically Safe and loop-powered (only if

connected to PCS)

Simulation of analogue output for loop-check shall be provided and shall also be continuous

self-diagnostic

Instruments shall be insulated and/or heated and/or fitted with process separators when

fluid characteristics and/or temperature conditions could alter the performance and reliability

of the system

The electronic enclosures for instruments mounted in Zone1 Hazardous Areas shall be

certified as Intrinsically Safe (according to IEC 60079-14). In general, the housing shall be in

accordance with IP65 requirement as a minimum (according to IEC 60529) and with an

epoxy coated aluminium housing

Galvanic isolators shall be used in all instances, these to be situated in the main marshalling

areas

All field instruments and their accessories shall meet the area classification of the part of the

plant where they shall be located

Due to only minor number of non-ex instrumentation (instrument air supply) all instruments

shall be suitable for Hazardous Area Zone1 Gas Group IIC, Temperature Class T4, as a

minimum

In-line instruments shall comply with the requirements of the piping class or equipment in or

on which the instruments are installed

All instruments shall be installed with vent and drain facilities and for any hazardous and/or

polluting fluids the drain of the instruments shall be piped to the drain network, if required

11.2 SURGE PROTECTORS

Surge protectors shall be installed in the marshalling cabinets of the SIS/PCS vendor and

not in the field devices

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12 FLOW INSTRUMENTS

12.1 GENERAL

The following types of flow instruments and flow devices shall be considered for non-

custody transfer measurements

12.1.1 VOLUMETRIC FLOW MEASUREMENT

1. Magnetic inductive (For fluids with a conductivity of more than 5 S/cm, e.g. water)

2. Vortex (For gas or non-conductive fluids for pipes up to maximum 6)

3. Differential Pressure (Orifice plate)

4. Differential Pressure (Integrated pitot tube)

5. Turbine Meter (Inference meter)

12.1.2 MASS FLOW MEASUREMENT

Coriolis Mass-flow (for gas or fluid for pipes up to max. 6)

Some flow devices requiring high accuracy of (0.25% to 0.5% of actual reading), e.g.

meters for accountability or to establish mass balances, these shall be delivered as pre-

calibrated meter-runs

If required, flow tubes shall be installed upstream on the meter-run

Details on meter and material required shall be stated on dedicated project instrument data

12.1.3 MAGNETIC INDUCTIVE

Used for simple fluid and shall be designed with pulsed DC excitation

The instrument shall be an integral type (body/converter)

The Body shall be provided with flanges and not be of the sandwich-type

12.1.4 VORTEX METER

Vortex meters shall be used for gas measurement. The flow instruments accuracy shall be

independent from the inner diameter of the up- and downstream pipe of the different piping

classes (wall thickness/schedule)

Upstream straight pipe length shall be 5 to 10D. In cases of double bent non co-planar

upstream pipe, the straight pipe length shall be 20D. In the case of a control valve in the

downstream side, the straight pipe length shall be also 20D

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12.1.5 ORIFICE MEASUREMENT

Most routine flow measurement is performed with orifice plates, installed between orifice

flanges. Orifice-flow measurements shall be made in accordance with ISO 5167-1.

Computations for calorific values, actual density and relative density shall be as per ISO

6976

Where orifice measurement and high process availability is required dual-chambered orifice

fittings shall be specified

The upstream and downstream straight-run lengths shall be fully in accordance with the

requirements as stipulated in ISO 5167-1. All measurements for plant mass balance

checking shall have "zero additional uncertainty" straight lengths. Measurements used

solely for control (e.g. minimum pump flow) may have "0.5% additional uncertainty" straight

lengths

Orifice plates shall be fabricated of 316 SS, in accordance with ISO 5167-1, and must have

a welded tab, marking the upstream side of the plate, the orifice diameter and the type of

orifice. A drain-hole shall only be provided when measuring wet gasses in a horizontal line

Orifice plate d/D ratios (orifice diameter/pipe inside diameter) shall be limited to values

between 0.3 and 0.7, unless otherwise specified. 'Square Edge' type orifices shall be

selected, where the Reynolds Number of the fluid permits. For Reynolds values below the

limit defined by the formula, 3150 x d2/D inches, Conical Entrance orifice plates shall be

used. The d/D ratio shall then be limited to values between 0.1 and 0.32

If feasible, the dP cell range shall be 250mbar. However, in any case the range shall be

within 50-500 mbar. The differential pressure shall not exceed 25% of the static pressure at

the upstream tapping. The span ratio shall be at minimum 1:100

The influence of static pressure regarding the accuracy shall be 0.5% of the reading

Orifice diameter size shall be selected such that the multiplying factor for rate of flow for a

0 - 10 square root scale is an integer multiple of 10. In all cases, orifice sizing shall be such

that nominal flow shall be at 70% of maximum of flow meter

Straightening vanes shall not be used

Intelligent, multivariable HART-capable transmitters shall be used as inputs to the Flow

computation for the above described orifice meters

For small non-critical flows integral orifice meters shall be used

12.1.6 INTEGRATED PITOT TUBE SYSTEM METERING

The design of pitot tubes shall be as follows:

Capillary-free construction dictates that the overall inner-diameter at any part of the tube

shall not be smaller than 8 mm to allow passage of condensed water

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The tube-flow profile shall be designed and positioned in such a way that a drift of the flow

break-point shall not result in a loss of measurement in the defined range of the Reynolds

number

Process connection of the meter shall be 2 RF Class, according to Piping Class or Vessel

Class

The flow meter shall be equipped with an integral temperature and absolute pressure

transmitter sensor, which together with the differential pressure transmitter and associated

Pitot tubes, shall be housed in a common junction box

Additionally, an integral flushing connection in order to clean the sensor by use of Nitrogen

shall be provided. This shall ensure cleaning without the need of a pipe segment shut-down

12.1.7 TURBINE METER

Turbine Meters shall have the following specification, as a minimum:

1. Stainless Steel measuring chamber and internals

2. Locking stator

3. Hydrodynamic thrust balance

4. Hard-surfaced bearing type for high viscosities of crude oil

5. Flange-type design

12.1.8 CORIOLIS MASS-FLOW METER

Accuracy shall be within 1% of the reading

The Coriolis meter shall operate even when 3% gas content is included in the liquid. If this

occurs, the following meter functions/calibrations shall still be achievable:

1. Set output

2. Hold reading

3. Set reading to a set value

4. Set reading to zero

If in addition to the mass-flow, an accurate density measurement is requested as a second

output, a Coriolis meter with a U-tube shall be used

The Coriolis meter shall be able to measure accurately, even if the static pressure in the

pipe is against zero

The meter measurement shall be stable against external loads and vibrations

In the event of tube-clogging, the design shall allow access to remove blockages using

compressed air

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13 LEVEL INSTRUMENTS

13.1 GUIDED WAVE RADAR LEVEL TRANSMITTER

The guided wave radar transmitter shall be used for level and interface level measurements,

wherever indicated in the detailed design

Build-up, corrosion or condensation on the probe or vessel wall shall not influence the

measuring result. The sensor shall be set up without vessel-filling or adjustment with a

specified medium. Cable and rod probes shall be available for different lengths and loads.

The measured level accuracy shall be +/- 3mm

13.2 SINGLE AND REMOTE SEAL LEVEL TRANSMITTERS

For each level-measuring application, the accuracy of the complete measurement system

(seals, capillary, low volume flange and transmitter) shall take into account the ambient and

process temperature (maximum 0.5% of span)

Insulation and heating of the capillary shall be identified during detailed design and installed

to defined Standards and/or Manufacturers recommendations

Range suppression shall be available

Flange size shall be minimum DN50/2

For applications with vacuums under 500mbar absolute, the low-volume flange shall be

fully-welded at the capsular of the transmitter

For High Pressure Services at approximately 140bar (e.g. HP Vessel), the Level Signal shall

be gas-pressure compensated

13.3 BUOYANCY LEVEL TRANSMITTER

Buoyancy level transmitters shall be equipped with a displacer for liquid interface

measurements

The transmitter shall be easily adapted to the measuring point and be able to be locally-

calibrated

Top, bridle or side-mounting types shall be provided according to the relevant Instrument

data sheets and shall be dependent upon the vessel structure

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14 PRESSURE INSTRUMENTS

14.1 GENERAL

Normal working pressure of the instruments shall be between 50% and 75% of the scale or

span

Temperature limits shall be as per piping class or equipment/vessel design specification

Over-range protection shall be provided for pressure instruments, pilots, gauges, etc. that

may be subject to pressures that could cause damage or affect the calibration of the

instruments

If process conditions dictate, Instruments shall be equipped with pulsation dampers

Adjustment of instruments, when still pressurised, shall be possible

All pressure instrument connections shall be installed with a block and bleed valve assembly

14.2 PRESSURE TRANSMITTER

Pressure Transmitters shall comply with the following specification, as a minimum:

1. Changes to the sensors characteristics due to temperature fluctuation shall be

compensated for automatically by the device

2. The pressure transmitter shall be bus or loop-powered (9-32VDC)

3. The maximum current consumption per device shall not exceed 16mA

4. Pressure transmitters shall be supplied flange-mounted to instrument root valve

5. Span shall not be smaller than 0.1 of Upper Range Level (URL) of transmitter

6. Transmitter Range shall be selected accordingly

7. Accuracy shall be +/- 0.1% of span or better

8. Overpressure Limits shall be according to the associated piping class

9. Temperature Limits Process connection shall be -20/+75C

10. Stability shall be +/- 0.2% of URL for 1 year

14.2.1 MATERIALS

The bolts/nuts (pressure containing) shall be of austenitic stainless steel

Note: Cadmium and zinc plating (Galvanising) of bolts and nuts shall not be used

The enclosure material shall be of stainless steel or epoxy coated aluminium casting

Wetted Parts: Stainless Steel 316 L or better

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14.2.2 ELECTRICAL CONNECTIONS

The electrical connections for all the field instruments shall be facilitated as per the

individual instrument requirements

14.2.3 PROCESS CONNECTION

Integral mounting transmitter connections shall be used

14.3 DIFFERENTIAL PRESSURE TRANSMITTER

Differential Pressure Transmitters shall comply with the following specification, as a

minimum:

1. Changes to the sensors characteristics due to temperature fluctuation and static

pressure shall be compensated automatically by the device

2. The differential pressure transmitter shall be bus-powered (9-32VDC)

3. The maximum current consumption shall not exceed 16mA

4. Span shall not be smaller than 0.1% of Upper Range Level (URL) of transmitter

5. Transmitter Range shall be selected accordingly

6. Overpressure Limits shall be dependent on associated piping class

7. Temperature Limits, Process Connection: -20/+75C

8. Accuracy shall be +/- 0.1% of span

9. Remote seal Error shall not be greater than 0.7mbar for all applications

10. Stability shall be +/- 0.2% of URL for 1 year

14.3.1 MATERIALS

The bolts/nuts (pressure containing) shall be of austenitic stainless steel, hardness

according to NACE MR 01-75.

The enclosure material shall be stainless steel

Wetted Parts: Stainless Steel 316 L or better

14.3.2 PROCESS CONNECTION

For the Differential pressure transmitter, the process connection and facing shall be

compatible with DIN-19213, Part 2, Revision 1980 (54mm) except for the threading for the

fixing bolts which shall be 7/16 20 TPI UNF

Orientation of the process mounting side-connection of the differential pressure transmitter

shall be aligned is such a way, that when facing the process-connection side of the

transmitter, the High Pressure connection shall be on the right hand side

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15 PRESSURE GAUGES

15.1 GENERAL

Pressure gauge ranges shall be:

Standard: 0/1, 1.6, 2.5, 4, 6, 10, 16, 25, 40, 60, 100, 160, 250, 400, 600, 1000barg

Vacuum: -1/0barg

Combined pressure/vacuum: -1/0/0.6, 1.5, 3, 5

Bourdon tube-type pressure gauges shall be used for local indication only. If corrosion,

plugging, etc, are anticipated, pressure gauges with a diaphragm seal shall be used

When measuring a pulsating pressure, a suitable dampening device in the impulse line shall

be specified. For this application, glycerine/silicon oil-filled gauges shall not be acceptable

Pressure gauges shall be of the safety pattern (solid front) type and shall have a nominal

diameter of 100 mm

Panel-mounted gauges shall have 50mm or 60mm (2" or 2.5") dials. Instrument air gauges,

such as those on valve positioners may have smaller dial sizes. Gauges shall have 1/4

NPT Male threaded connections

15.2 PRESSURE GAUGE CASINGS

Pressure gauge casings shall meet the following specification, as a minimum:

1. A full blow-out device shall be fitted to the back of the Pressure Gauge case to

prevent the pressure in the gauge from exceeding 0.3barg (30kPa)

2. The case material, including the blow-out plate, shall be of stainless steel

3. The blow-out back plate shall be provided with a flexible compensation facility and

sealing ring, both made of a hydrocarbon resistant synthetic rubber

4. The gauge assembly shall be suitable for direct mounting

5. The window shall be of non-splintering glass

6. To avoid vibration influences and condensation effects inside the case, liquid-filled

cases shall be used. Filling medium shall be based on Glycerine (Except for impulse

lines)

15.3 PRESSURE-SENSING ELEMENT

Pressure-sensing elements shall meet the following specification, as a minimum:

The AISI-316 Bourdon tube shall be welded to AISI-316 shank and tube end-piece

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Both welds shall be full argon-arc welds (tight welding) and shall be made with the use of

AISI consumable

The Bourdon tube shall be placed at least 7mm inside the shank

Fillet-welds shall at least have a leg-length equal to the wall thickness of the tube. Fillet-

welds shall be smooth

The measuring element shall be able to withstand a temporary/permanent overpressure to

at least 33% of the specified range limits without calibration shift

In order to not overload the pressure gauge and to have accurate pressure indication at

normal operation conditions, the pressure gauge shall be able to withstand the maximum

design pressure according to the associated piping/equipment pressure class

All pressure-containing parts shall be designed with a safety factor 4 to 1

Pointer movement shall be of corrosion and wear resisting material, e.g. stainless steel or

Monel

A stainless steel flexible pointer stop on the dial shall be provided

15.4 CONNECTION

Process Connections shall be: 1/4 NPT male

15.5 SWITCHES

Threshold functions shall be based on analogue signals wherever possible, however if

switches are to be used then the following philosophy shall be applied

15.5.1 ESD AND F&G SYSTEM-CONNECTED SWITCHES

Switches routed to the ESD & F&G system shall be based on normally-closed contact

switch functions and shall be routed to a digital input card of the ESD/F&G system.

For normally-open contact switches, line monitoring shall be enabled. Switch signals shall

therefore be routed to an analogue input card of the ESD/F&G system.

15.5.2 PCS-CONNECTED SWITCHES

Proximity switches shall be used for actuated on/off valves and for status monitoring (close

and open status only). If normal switches are used for status indication they shall always be

based on normally-closed contacts

Normally-open contacts shall not be installed or used. If there is no alternative solution for

normally-open contacts, then available additional line-monitoring shall be enabled via an

end-of-line resistor and the signal shall then be handled as an analogue input signal

Doc. No: 10002-SPC-IN-00001, Rev. A01


Page 43 of 58

16 MANIFOLD BLOCKS

16.1 GENERAL

Integral slim line Double Block and Bleed (DB&B) with ball valves shall be used with the

instrument connection being integral mounted or via 1/4 NPT. The process connection shall

be 1/4 NPT threaded

The manifold type used shall be a double isolate/equalise/vent block for differential pressure

transmitters and a single isolate/vent block for pressure transmitters and pressure gauges

Manifold Block Design Conditions (minimum) shall be:

Maximum working Pressure: 150bar Maximum working Temperature: -20/75C

The body of the manifold shall be cast, forged or machined from bar stock material

Each manifold shall be provided with all required installation components as specified

below:

Bolts, nuts and flat washers for process connection Gaskets for process connection including 2 spares Transmitter fixing bolts, if required Manifold/Transmitter supports, if required Fully-equipped with Swagelok compression-type tube fittings Stainless Steel Vent-tube (minimum 300 mm) Impulse lines branching off to more than one instrument shall have individual isolating

facilities for each instrument

16.2 MANIFOLD BLOCK/GAUGE ADAPTER FOR PRESSURE GAUGES

Slim-line, Mono-flange Double Block and Bleed (DB&B) Manifolds shall be used for

Pressure Gauges ANSI Class 150, 300, 600,900 & 1500

Process Connection: ANSI 2" RF

Instrument Adapter Selection: 1/4" NPT Female Gauge Adapter

Material: SS 316

Mixed secondary valve PTFE (anti-tamper on Vent)

Vent Port Selection: " NPT Female

Doc. No: 10002-SPC-IN-00001, Rev. A01


Page 44 of 58

16.3 ORIFICE METER APPLICATIONS MANIFOLD BLOCK

Orifice Meter Applications Manifold Block for Differential Pressure Transmitters shall be as

follows:

Primary Orifice Process Connection: Material: SS 316 acc NACE Process Flange Size: or according to orifice metering Unit Size Instrument Flange Rating: same as Process Flange Rating Process Flange Type Selection: According ANSI/ASME - RF-Sealing Primary Valve Function: DB&B for ANSI Class 150-1500

(Mixed secondary valve PTFE - bleed is anti-tamper)

Vent Port Selection: " NPT Female SS-Impulse Lines shall be routed from the primary process manifold valve to the dP

Transmitter Manifold. Integral Mounting Transmitters shall be used

Compact T-type, 4-valve manifolds (double isolate/equalise/vent) shall be used to

accommodate integral-mounting differential pressure transmitters onto the manifold

Compact T-type Manifolds shall be:

Material: According to datasheet

Instrument Interface Type Integral Mounting


Process Port Selection: " NPT Female Adapter

Valve Option: Mixed operation PTFE Seals

-NPT Test Port with blind-plug fitted

16.3.1 NON-INTEGRAL MOUNTING TRANSMITTERS

If Non-integral Mounting Transmitters are used (DIN19213 Interface Connection) then the

manifold block shall be of an MD41 for DIN19213 Interface

Vendors shall submit a Technical Query/Clarification statement to the Contractor/Company

if non-integral mounting transmitters are to be quoted for

Vendors shall need Contractor/Company written approval before using non-integral

mounting transmitters in design or installation

Doc. No: 10002-SPC-IN-00001, Rev. A01


Page 45 of 58

16.4 MANIFOLD BLOCK FOR DIRECT OR REMOTE SEAL DP TRANSMITTER

Slim-line mono-flange manifold blocks shall be used to replace the primary and secondary

process valve assemblies which are usually needed for absolute or gauge pressure

instruments with a remote or direct seal. The manifold shall be a two (2) valve block and

effect the combination of the:

Primary process isolation valve An optional bleed valve An optional secondary valve

The Manifold shall meet the following specification as a minimum:

Material: According to datasheet

Process Flange Size: According to Diaphragm Flange Seal Size

Instrument Flange Rating: Same as Process Flange Rating

Instrument Flange Seal Size: According to Diaphragm Flange Seal Size

Process Flange Type Selection: According ANSI/ASME - RF-Sealing

Primary Valve Function: Double Block & Bleed for ANSI Class 150-1500

Mixed secondary valve PTFE (bleed is anti-tamper)


Doc. No: 10002-SPC-IN-00001, Rev. A01


Page 46 of 58

17 PROCESS CONNECTION OF FIELD INSTRUMENTS

17.1 PRESSURE INSTRUMENT MOUNTING PHILOSOPHY

Except in cases where high vibration is present or where temperatures are excessive (high

or low), all pressure instruments shall be mounted locally. Local mounting shall sacrifice the

convenience of pipe-stand mounting of instruments in order to:

1. Save on installation space - local mounting requires no tubing, fewer valves and no

pipe-stands

2. Achieve an installation which minimises the number of inter-connections

3. Minimise loss of inventory when the instrument is depressurised for testing or removal

- local mounting has no stored volume, as with tubing

4. Local mounting of instruments shall be accomplished by attaching the instrument

directly to the instrument isolation valve on the piping (the piping root valve). Locally-

mounted instruments shall be accessible for viewing

5. In cases of high vibration or extreme temperature, pressure instruments shall be

mounted on pipe-stands and connected to the process isolation valve via tubing

6. The connection for the process and vent/drain ports shall be NPT inch female,

using Swagelok compression-type tube fittings

7. The vent or drain valves shall be provided with a device to prevent tampering

8. A length of tubing, approx. 300 mm, shall be fitted to the vent or drain connections

and directed downwards

17.2 PRESSURE INSTRUMENT ISOLATION VALVES

The valves used to isolate an instrument from the process shall meet the following

specifications, as a minimum:

1. The instrument must be capable of being safely isolated from the process to permit

safe maintenance and/or removal. Double block and bleed valve arrangements shall

be used throughout

2. Pressure transmitters, switches, and other sensors shall be capable of being tested

whilst the process equipment is still in operation. This shall require a block valve to

isolate the instrument from the process. A vent valve and a separate port to inject test

pressures into the instrument

3. The minimum number of installation configurations shall be utilised, in order to

simplify operations and maintenance

Doc. No: 10002-SPC-IN-00001, Rev. A01


Page 47 of 58

4. Static pressure instruments shall be locally-mounted and installed directly on the

piping root valve

17.3 TEMERATURE INSTRUMENTS

All temperature elements shall be equipped with a remote mounted transmitter head

When temperatures exceeding 500C are encountered, thermocouples shall be used

instead of RTDs. Thermo-couplers shall be Chromel-Alumel, type K. The hot junction shall

be kept free from earth

17.3.1 TRANSMITTER PERFORMANCE SPECIFICATION

The Temperature Transmitter shall meet the following specification as a minimum:

Total Probable Error better than 0.10C, for Pt100 (alpha = 0.00385) sensor input at 30C ambient

Stability of +/- 0.1% of reading or 0.1C, whichever is greater, for 1 year for thermocouples

Stability of +/- 0.1% of reading or 0.1C, whichever is greater, for 2 years for RTDs

17.3.2 ELECTRICAL CONNECTION

Electrical Connection M20 x 1.5

17.3.3 SENSOR CONNECTION

Attached directly to the RTD or Thermocouple sensor

Remote mounted HART transmitters shall be installed in close proximity to the thermo-

couple and its thermo-well in order to eliminate long runs of specialist thermocouple cable

and to eliminate the need for special terminals inside field junction boxes

RTDs shall be wired to integrally-mounted transmitters, in order to eliminate long runs of

specialist RTD cable and to maintain consistency of field device wiring, calibration, and

control system inputs

17.3.4 HOUSING MATERIAL

The Housing material shall meet the following specification as a minimum:

Epoxy coated aluminium housing with BUNA-N O-rings on cover (NEMA 4X, IP67)

Doc. No: 10002-SPC-IN-00001, Rev. A01


Page 48 of 58

18 PT-100 RESISTANT THERMOMETER ELEMENTS (RTDS)

18.1 GENERAL

PT100 (RTDs) shall be used for small ranges (0C-100C) or when very accurate or stable

measurements between -2

10002-spc-in-00001-000-a01

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