General Specification: Process

GENERAL SPECIFICATION Process GS RC ECP 100

Process design criteria

01

12/2016

Revision as per appendix 4

00

06/2014

Original issue

Rev.

Date

Subject of revision

Contents Foreword ........................................................................................................................ 5 1. Subject ..................................................................................................................... 5 2. Reference documents ............................................................................................. 5 2.1

Priority rules .................................................................................................................... 7

2.2

Deviations ....................................................................................................................... 8

3. Applicability ............................................................................................................. 8 4. Definitions of terms................................................................................................. 8 4.1

Acronyms ........................................................................................................................ 8

4.2

Definitions ..................................................................................................................... 10

5. Design life .............................................................................................................. 14 6. Design Flow and Duty ........................................................................................... 15 7. Design temperature............................................................................................... 17 7.1

Design margins on temperature .................................................................................... 18

7.2

Specific equipment considerations ................................................................................ 19

7.3

Revamping or Debottlenecking ..................................................................................... 21

8. Design pressure .................................................................................................... 21 8.1

Design margins on pressure ......................................................................................... 22

8.2

Specific equipment considerations ................................................................................ 23

8.3

Revamping or Debottlenecking ..................................................................................... 27

9. Materials & corrosion allowance ......................................................................... 29 9.1

Material selection .......................................................................................................... 29

9.2

Corrosion allowance ..................................................................................................... 29

10. Vessels ................................................................................................................... 29 10.1

Position of vessel .......................................................................................................... 29

10.2

Vessel sizing ................................................................................................................. 29

10.3

Vessel internals............................................................................................................. 35

10.4

Vessel elevation ............................................................................................................ 35

10.5

Specific vessels ............................................................................................................ 35

11. Vessels nozzles ..................................................................................................... 37 11.1

Nozzles Tagging ........................................................................................................... 38

11.2

Vent, drain, utility and steam-out connections ............................................................... 38

11.3

Manholes ...................................................................................................................... 41

11.4

Instrument nozzles ........................................................................................................ 42

11.5

Other nozzles ................................................................................................................ 43

12. Columns and internals.......................................................................................... 43 12.1

Column sizing ............................................................................................................... 43

12.2

Tray versus packing selection ....................................................................................... 44

12.3

Trayed columns sizing .................................................................................................. 44

12.4

Packed columns sizing.................................................................................................. 46

12.5

Revamping or Debottlenecking ..................................................................................... 46

13. Heat exchangers ................................................................................................... 46 13.1

General ......................................................................................................................... 46

13.2

Thermal Design for shell & tubes exchangers ............................................................... 47

13.3

Mechanical and hydraulic design for shell & tubes exchangers ..................................... 51

13.4

Use of special types exchangers ................................................................................... 52

13.5

Exchanger integration in process scheme ..................................................................... 54

14. Air cooled heat exchangers ................................................................................. 55 14.1

General ......................................................................................................................... 55

14.2

Type of air-cooled heat exchangers .............................................................................. 55

14.3

Thermal design ............................................................................................................. 56

14.4

Mechanical design ........................................................................................................ 57

15. Fired heaters.......................................................................................................... 58 15.1

Fuel efficiency and flue gas temperature ....................................................................... 58

15.2

Fuel gas supply ............................................................................................................. 58

16. Pumps .................................................................................................................... 59 16.1

Centrifugal pumps ......................................................................................................... 59

16.2

Positive Displacement Pumps - Controlled Volume ....................................................... 63

16.3

Mechanical drive ........................................................................................................... 64

17. Compressors ......................................................................................................... 64

18. Lines ....................................................................................................................... 65 18.1

Line sizing criteria ......................................................................................................... 65

18.2

Flange leakage prevention and mitigation ..................................................................... 69

18.3

Strainers ....................................................................................................................... 70

19. Control valves ....................................................................................................... 70 19.1

Control valve Design ..................................................................................................... 70

19.2

P&ID development for control valve .............................................................................. 72

19.3

Revamping or Debottlenecking ..................................................................................... 74

20. Insulation and tracing ........................................................................................... 74 20.1

Insulation ...................................................................................................................... 74

20.2

Tracing .......................................................................................................................... 75

21. Control philosophy ............................................................................................... 76 21.1

Use of Auto-start ........................................................................................................... 76

21.2

Heat exchangers ........................................................................................................... 77

21.3

Air cooled heat exchangers ........................................................................................... 78

21.4

Compressors ................................................................................................................ 78

22. Isolation philosophy ............................................................................................. 80 22.1

Positive isolation ........................................................................................................... 80

22.2

Valved isolation ............................................................................................................. 81

22.3

Double valve requirement ............................................................................................. 83

22.4

Specific services ........................................................................................................... 84

22.5

Typicals......................................................................................................................... 84

Appendix 1

Minimum requirements for typicals development SYMBOLS ........................... 85

Appendix 2 Minimum requirements for typicals development – Control valves – Isolation and Draining .................................................................................................................... 86 Appendix 3 Minimum requirements for typicals development Pressure relief valves – Isolation and Draining...................................................................................................... 87 Appendix 4

Management of revision .................................................................................. 88

Foreword Engineering Companies and Design Offices that are contractually bound to TOTAL, are obliged to always check that the applicable regulations, in particular regarding SAFETY, QUALITY and protection of the ENVIRONMENT, do not impose more restrictive measures. If they do, alternative solutions in accordance with the regulations must be submitted in writing to TOTAL. Except for when it is used internally, the application of this specification is systematically covered by a contract.

1. Subject This General Specification gives the minimum requirements for process design criteria to be used by CONTRACTOR for the design of a new unit, and guidance for a revamp/debottlenecking of an existing unit. The objective is to ensure consistency in the design during the concept review phase, Licensors Design, pre-project phase, FEED Engineering and Detailed Engineering phase.

2. Reference documents The reference documents listed below form an integral part of this General Specification. Unless otherwise stipulated, the applicable version of these documents, including relevant appendices and supplements, is the latest revision published at the EFFECTIVE DATE of the CONTRACT. Standards Reference

Title

Not applicable Professional documents Reference

Title

API SPEC 12J

Specification for oil and gas separators

API STD 521

Pressure-relieving and depressuring systems

API STD 2000

Venting atmospheric and low-pressure storage tanks

NACE SP0407

Format, content, and other guidelines for developing a materials selection diagram - Item No. 21123

Regulations Reference

Title

Not applicable Codes Reference TEMA

Title Standards of the tubular exchanger manufacturers association

TOTAL General Specifications Reference

Title

DS RC MIT 403

Deviation form

GS RC COR 006

General Material selection guideline

GS RC ECP 101

Overpressure protection

GS RC ECP 103

Emergency shutdown and depressurization system

GS RC ECP 104

Flare header study

GS RC ENG 401

Plant lay-out

GS RC ENG 405

Liquid drainage & spill control

GS RC HSE 020

Prevention of electrostatic ignitions

GS RC HSE 022

Fire fighting

GS RC INS 105

Tag numbering for instrumentation equipment

GS RC INS 106

Graphic representation of instrumentation on PID

GS RC INS 200

Process connections for Instruments and Analysers

GS RC INS 210

Instrument air supply

GS RC INS 230

Process drains of instrument

GS RC INS 450

Control valves

GS RC INS 720

Instrumentation for Rotating Machines

GS RC ISL 101

Thermal Insulation of Equipment

GS RC MEC 610

Centrifugal pumps – API STD 610

GS RC MEC 614

Lubrication, shaft-sealing and control-oil systems and auxiliaries

GS RC MEC 617

Axial and centrifugal compressors and expander-compressors

GS RC MEC 618

Reciprocating compressors

GS RC MEC 670

Machinery safety system and procedure for centrifugal shaft line

GS RC MEC 675

Positive displacement pumps - Controlled volume

GS RC MEC 682

Pumps – Shaft Sealing Systems for Centrifugal and Rotary Pumps

GS RC MEC 685

Sealless centrifugal pumps according to API STD 685 2nd edition

GS RC MEC 688

Centrifugal pumps for chemical process and general purposes

GS RC MEC 698

Centrifugal pumps codes and standards selection

GS RC PJC 320

Deviation and Non Conformity Management

GS RC PVA 100

Design of metallic pipes

GS RC PVA 102

Refining & Chemicals piping classes

GS RC PVA 103

Refining piping classes

GS RC PVA 104

Petrochemicals piping classes

GS RC PVA 106

Steam tracing of equipment

Reference

Title

GS RC PVA 200

Metallic valves

GS RC PVA 208

Steam traps

GS RC PVE 001

Unfired metallic pressure equipment

GS RC PVE 002

Shell and tube heat exchangers

GS RC PVE 003

Air-cooled heat exchangers

GS RC PVE 010

Internes de réacteurs d’hydrotraitement et d’hydrodésulfuration

GS RC THE 001

Process furnaces

GS RC THE 002

High temperature furnace

GS RC THE 003

Burners for furnaces

GS RC THE 004

Instrumentation, control and safety functions for new, low temperature gas fired heaters

GS RC THE 005

Instrumentation, control and safety functions for revamping of low temperature gas fired heaters

GS RC THE 006

Instrumentation, control and safety functions for new, high temperature gas fired heaters

GS RC THE 007

Instrumentation, control and safety functions for revamping of high temperature gas fired heaters

GS RC THE 100

Shell boilers (Fire tubes)

GS RC WAM 011

Additional requirements for pressure equipments in wet H 2 S service

GS RC WAM 211

Additional requirements for metallic piping, pressure and safety accessories for special services (H 2 S, H 2 , etc.)

Other documents Reference

Title

Not applicable

2.1 Priority rules The subject of this specification shall satisfy, in descending order of priority, the requirements of: • the local regulations, when applicable, • the project’s Job specification, when existing, • this specification, • other codes, specifications and standards to which this specification refers. In the event of conflicting requirements between the selected construction code and these other codes, specifications and standards (if they are stipulated by a particular contract), the most restrictive requirement shall apply.

2.2 Deviations Any deviation from the requirements of this specification may be suggested by the General contractor, Engineering Company, Manufacturer or Contractor, if he considers such deviation beneficial for reducing the cost and/or completion time, provided that it does not compromise the safety of personnel or the regulatory requirements (when such regulations apply). Deviations must be submitted to TOTAL, as a variant with the necessary justifications, and must receive the written approval of TOTAL. Deviation requests shall be issued to COMPANY Project Manager using the Deviation form DS RC MIT 403, as explained in GS RC PJC 320.

3. Applicability This general specification provides rules and guidelines either for new projects, revamp or debottlenecking projects of existing units. Vendor Packages: For vendor packages, CONTRACTOR shall clarify together with COMPANY prior to purchase order which criteria have to be used for process design of the installation. Licensed Units: This Specification and the Basic Engineering Design Questionnaire (BEDQ) sent by the licensor will be discussed with COMPANY, and amended as agreed in order to provide a common set of rules which will be used by the Licensor to develop the Process Design Package (PDP). Where a Licensor requirement is more stringent than the corresponding requirement of this specification, the licensor’s specific requirement will be submitted to COMPANY’s approval.

4. Definitions of terms 4.1 Acronyms • BFW

Boiler Feed Water

• BWG

Birmingham Wire Gauge

• CA

Corrosion Allowance

• CAPEX

Capital Expenditure

• CET

Critical Exposure Temperature

• CMR

Carcinogenic, Mutagenic and toxic to Reproduction

• CS

Carbon Steel

• CSC

Car Seal Closed

• CSO

Car Seal Open

• DCS

Distributed Control System

• EOR

End Of Run

• ESD

Emergency ShutDown System (including SIS= Safety Instrumented System)

• FEED

Front End Engineering Design

• HAZOP

HAZard and OPerability

• HC

Heat Conservation

• HETP

Height Equivalent to Theoretical Plate

• HP

High Pressure

• ISBL

Inside Battery Limits

• KCS

Killed Carbon Steel

• KO

Knock Out (for KO drums)

• LAH

Level Alarm High (1)

• LAHH

Level Alarm High High (1)

• LAL

Level Alarm Low (1)

• LALL

Level Alarm Low Low (1)

• LC

Locked Closed

• LMTD

Log Mean Temperature Difference

• LO

Locked Open

• LP

Low Pressure

• LPG

Liquefied Petroleum Gas

• LSHH

Level Switch High High (1)

• LSLL

Level Switch Low Low (1)

• MAT

Minimum Allowable Temperature

• MAWP

Maximum Allowable Working Pressure

• MDMT

Minimum Design Metal Temperature

• MP

Medium Pressure

• NLL

Normal Liquid Level

• NPSH

Net Positive Suction Head

• NPSHA Net Positive Suction Head Available • NPSHR

Net Positive Suction Head Required

• OSBL

Outside Battery Limits

• PFD

Process Flow Diagram

• P&ID

Piping and Instrumentation Diagram

• PP

Personnel Protection

• PRV

Pressure Relief Valve also called PSV (Pressure Safety valve)

• PWHT

Post Weld Heat Treatment

• RD

Rupture Disk

• RO

Restriction Orifice

• SDV

Shut Down Valve

• SIF

Safety Instrumented Function

• SIL

Safety Integrity Level

• SOP

Settling Out Pressure

• SOR

Start Of Run

• SS

Stainless Steel

• UFD

Utility Flow Diagram

(1) Same apply to pressure (P), temperature (T) and flow (F) replacing the letter L (Level) by the relevant letter. Refer to GS RC INS 105.

4.2 Definitions • AUTO-REFRIGERATION: Also known as Joule-Thomson effect, can occur on adiabatic expansion of gases, and boiling of liquids, associated to a reduction in pressure. The resulting low temperature can result in metal embrittlement (potentially leading to BRITTLE FRACTURE). • BRITTLE FRACTURE: Is a failure that occurs in a break before-leak mode. Appears without deformation, and the damage may manifest in large rupture of the equipment, resulting in loss of containment. • CET- Critical Exposure Temperature: The CET curve corresponds to the adiabatic flash temperatures for a fluid/mixture, for pressures below the MAWP of the equipment. The CET curve represents the lowest anticipated temperatures to which the equipment will be subjected by the process, taking into consideration lowest operating temperature, operational upsets, auto-refrigeration, ambient temperature, and any other sources of cooling. • CHECK CASE: The performances of the unit or equipment are rated for a CHECK CASE, on the basis of the sizing done for the DESIGN CASE. In case of lower performances, either these adverse operating conditions are acceptable (e.g. temporary and manageable off-spec product quality during start-up) or the process variables need to be adjusted to maintain the performances (i.e: reduce unit flow rate). • CMR FLUID: For the purpose of this specification, a stream with Carcinogenic, Mutagenic and toxic to Reproduction (CMR) components at a concentration higher than 0.1% wt in a mixture will be considered as a CMR. This definition is based on UN GHS (United Nations - Globally Harmonized System of Classification and Labelling of Chemicals). However, at the beginning of the FEED this value shall be reassessed according to the type of CMR product and the operating conditions.

• CYCLIC SERVICE: The following conditions are given to assess a potential application in cyclic service: − 20% pressure variation in normal operating condition and/or, − 20% process flow rate variation and/or, − 110°C temperature variation in normal operating condition. A service is considered to be cyclic when the variation (cycle) occurs in a time frame of less than 24 hours and the number of cycles exceeds 12 per year. • COMPANY: COMPANY is defined in the contract agreement. • CONTRACTOR: The CONTRACTOR is the individual or Company responsible for carrying out the engineering (and eventually procurement and/or construction) services as defined in the contract agreement dedicated to the project. • DESIGN CASE: A DESIGN CASE is the operating case used to set design parameters (pressure, temperature, flow, duty etc.) for the sizing of the equipment and piping. • DESIGN CONDITIONS: Parameters used for material selection and mechanical design of equipment and piping including DESIGN PRESSURE, DESIGN TEMPERATURE, level (solid, liquid), CET, highest pressure drop. Generally, process DESIGN CONDITIONS correspond to "MAXIMUM OPERATING CONDITIONS" expected during service, increased or decreased by a design margin defined in the present document. Alternative process design conditions should be specified if the most severe pressure and temperature cannot occur simultaneously, or to describe cyclic/intermittent operation. One vessel can have sections with different sets of design conditions. - DESIGN PRESSURE: The design pressure results in the greatest component thickness (equipment) or the highest rating (piping). The design pressure of a vessel is defined at the top. The DESIGN PRESSURE is considered as the maximum allowable pressure in service Ps according to PED (Pressure Equipment Directive 2014/68/UE). Refer to MAWP definition. - DESIGN TEMPERATURE: Is the mean temperature of the material at the most severe coincident pressure, level, or pressure drop during service. Usually correspond to the warmest temperature for process conditions above 0°C. For fluids subject to auto-refrigeration, CET shall be indicated. • DESIGN FLOW: The DESIGN FLOW is equal to the MAXIMUM OPERATING FLOW during normal operation, increased by a design margin. Process simulation should not include any design margin.

The DESIGN FLOW is a process value; it can thus be different from the "Manufacturer’s rated capacity" of rotating equipment. The DESIGN FLOW will in particular correspond to the: − Rated capacity of the API STD 610 data sheet (centrifugal pump) − Required capacity of the API STD 618 data sheet (Reciprocating compressors) − Inlet volume of the API STD 617 data sheet (Centrifugal and axial compressor) • HEAT AND MATERIAL BALANCE: A HEAT AND MATERIAL BALANCE is the document giving the normal operating conditions, compositions, thermodynamic and physical properties in steady state of identified process streams for each case. • LIQUEFIED PETROLEUM GASES (LPG): LIQUEFIED PETROLEUM GASES (LPG) are hydrocarbons in liquid phase at operating conditions and having an initial boiling point at atmospheric pressure lower than 15°C. • MAXIMUM OPERATING FLOW: Maximum operating flow from the mass balances of the operating cases at NORMAL OPERATING CONDITIONS. This applies for continuous and discontinuous process (instantaneous flow-rate). • MAXIMUM OPERATING CONDITIONS: The MAXIMUM OPERATING CONDITIONS are the highest (hence, lowest for negative values) pressures and coincident temperatures during the equipment service including all foresee able operating situations: normal operation, start-up, shutdown, downgraded operation, regenerations, decoking, bypassing, desorption, full depressurisation, inerting, drain-off, washing, steam-out, dry-out, each operating phase of discontinuous process, etc. • MAT - Minimum Allowable Temperature: The MAT is the lower temperature boundary at all possible equipment pressures (stresses) to ensure that material remains ductile (avoid brittle fracture). • MAWP - Maximum allowable working pressure: The MAWP is the maximum gauge pressure permissible at the top of equipment at a coincident temperature. The MAWP is normally greater than the DESIGN PRESSURE, but can be considered equal to the DESIGN PRESSURE during design phase (MAWP has not yet been determined). MAWP is the least of the values for the internal or external pressure as determined by the design rules for each element of the equipment using actual nominal thickness, exclusive of additional thickness for corrosion allowance and loadings other than pressure. • MDMT- Minimum design metal temperature: For mechanical design, according to construction code ASME Sec. VIII Div 1, the MDMT is the MAT at the maximum allowable operating pressure (MAWP). The MDMT is stamped on the equipment nameplate.

• NORMAL OPERATING CONDITIONS: The NORMAL OPERATING CONDITIONS are the internal pressure, temperature, flow rate and fluid composition in steady state conditions, taking into account feedstock changes, SOR and EOR conditions for reactors, etc. NORMAL OPERATING CONDITIONS are required to maintain product specifications and system performance. These values are used to size the equipment and define the instruments range. • PIPING AND INSTRUMENTATION DIAGRAM (P&ID): A PIPING AND INSTRUMENTATION DIAGRAM is the detailed drawing used for assistance to construction and operation of a processing plant including associated off sites and utility fluids. Symbols are used for a good understanding and also in order to simplify the representation. Refer to GS RC INS 106. • PROCESS DATA SHEET: It is the data sheet with the Process information required for sizing equipment, packages, control and on-off valves, PRVs, rupture disks, in-line instruments, analyzers.... Where applicable, a sketch with main dimensions such as internal diameter, length, liquid levels for equipment will be given. • PROCESS FLOW DIAGRAM (PFD): It presents the succession of operations in the fluid(s) processing to reach the required product specifications. The main control loops, main safety interlock and all equipment are represented. Identifies the streams for the Heat and Material Balance including flowrate, pressure and temperature conditions. • SERVICE - AMINE SERVICE: Amine service refers to all amine solutions including MDEA (Methyl-Di-Ethanol-Amine), DEA (Di-Ethanol-Amine), MEA (Mono-Ethanol-Amine), DGA (Di-Glycol-Amine) and ADIP (Amine-Di-Iso-Propanol). • SERVICE - HYDROGEN SERVICE: Hydrogen service refers to hydrogen or its gaseous mixtures having a partial pressure of hydrogen equal or higher than 4 bar abs. • SERVICE - LPG SERVICE: LPG service refers to all streams containing LPG compounds at a concentration higher than 30% wt (e.g. C 3 , C 4 , mixtures of C 3 and C 4 ). • SERVICE - WET H 2 S SERVICE: Wet H 2 S service refers to both sour gas and oils whenever water is able to condense. Refer to GS RC COR 006 for wet H 2 S service categories.

• TOXIC FLUID: For the purpose of this specification, toxicity is referred only to the acute toxicity category 1, 2 and 3 according to the UN GHS (United Nations - Globally Harmonized System of Classification and Labelling of Chemicals) and specified in the material safety data sheet (MSDS). Only toxicity caused by inhalation or contact with the skin is considered. For the mixture of materials having different toxicity category, the criteria given in the UN GHS shall be applied to define the toxicity category of the mixture. • UTILITY FLOW DIAGRAM (UFD): Utility flow diagrams are equivalent to PFD for utilities generation and distribution systems.

5. Design life The following design life shall be applied to new equipment. Design Life Pressure Vessels Pressure Vessels, thickness < 75 mm

20 years

Pressure Vessels, thickness ≥ 75mm

30 years

Columns and reactors

30 years

Internals of Pressure vessels, Columns & Reactors

10 years

Tanks

30 years

Heat Transfer Equipment Air-cooled exchangers (including tubes)

20 years

Shell and Tube Heat Exchangers

20 years

Heat Exchanger bundles

10 years

Fired Heater tubes – convection

200 000 hours

Fired Heater tubes – radiation

100 000 hours

Rotating Equipment Pumps

20 years

Centrifugal Compressors

20 years

Reciprocating Compressors

20 years

Steam Turbines

20 years

Piping Piping & Valves (Carbon steel, low alloy steel, corrosion resistant alloys)

20 years

Pipelines (Underground & Aboveground)

20 years

Instrumentation Instrumentation [1] Equal to the corresponding design life of the piping.

20 years [1]

For specific pieces of equipment subject to severe conditions which lead to excessive equipment cost, CONTRACTOR may suggest a deviation to COMPANY (refer to § 2.2). For revamped equipment the residual service life time: • Is assumed to be acceptable if its design conditions are unchanged, unless COMPANY has stated differently. • Has to be re-assessed if its design conditions are modified.

6. Design Flow and Duty This section provides design margins on flow and duty for equipment design. Such margins will be optimized by LICENSOR/CONTRACTOR and submitted to COMPANY agreement. The objective is twofold: deliver a unit/equipment fit for purpose and limit the CAPEX, provided that safety and performance objectives are not compromised. The margins are applied on the MAXIMUM OPERATING CASE in order to define the DESIGN CASE. Margins do not apply to CHECK CASES. The overdesign for new items depends on the nature of the equipment and its use in the process scheme. The MAXIMUM OPERATING case applies through a circuit (example: pump and downstream equipment, compressor and downstream equipment). Two cases are considered: • New units, new sections of existing units, new equipment • Revamping or debottlenecking of existing units The margins defined here below are margins to apply on the MAXIMUM OPERATING FLOW in order to define the DESIGN FLOW. This margin depends on the nature of the equipment and its use in the process scheme. The design margins apply to the DESIGN CASE(S) only and not to the CHECK CASE(S). If there is more than one DESIGN CASE then, design margin will apply to the most constraining of the DESIGN CASE(S) of the concerned equipment. The design margins for a specific equipment shall be used for this equipment only and its impact shall not be considered for the design of downstream or upstream equipment and piping. The design margins as well as the sizing cases shall be clearly indicated on the equipment data-sheet. Revamping or debottlenecking: At first, evaluate the performance of existing equipment/unit by test runs at future/maximum throughput. The design margins for revamping or debottlenecking projects shall take into account the capacity available on the existing equipment foresee for reuse. Design margins will be reviewed jointly by LICENSOR/CONTRACTOR and COMPANY on a case by case basis.

Required Design Margin

New

Existing / Revamp

Flow

Flow

20%

10%

20% R + 10% E

10% R + 0%- E

Pipeline feed pumps

15%

0%

Feed pumps, other pumps

10%

0%

Product rundown pumps Transfer pumps from an equipment to another equipment

10%

0% (a) 5% (b)

Intermittent service pumps (e.g. batch operation)

0%

0%

Comment

Pumped circuit (1) Reflux, Pump-around or BFW pumps Double service: reflux (R) & export (E) pumps

Fire water pumps

(a) Flow control (b) Level control or cascaded Level and Flow control

Refer to the GS RC HSE 022

Compressors (2) Compressor having a safety function

20%

10%

Compressor with Power < 150kW

15%

5%

Compressor with 150kW < Power < 2MW

10%

0%

Compressor with Power > 2MW

5%

0%

Refer to above Power ranges

5% mini

Hydrogen Make-up compressors

E.g. quench rate preventing uncontrolled exothermic or runaway reactions

For mechanical spillback

losses

and

Columns and Columns Internals Fractionating zone Pump-around zone (L: liquid flow and V: vapour flow)

Required Design Margin

10%

5%

For flooding refer to (Columns and internals).

§

12

20% x L+ 10% x V

5%

For flooding refer to (Columns and internals).

§

12

New

Existing / Revamp

Flow / Duty

Flow / Duty

Comment

Fired Heaters (excluding Steam Reformers and Steam Cracking Furnaces) Fired Heaters

(c) / (c)

0% / 0%

(c) depends on the process. Consider preheat train at fouled conditions.

Required Design Margin

New

Existing / Revamp

Duty

Duty

10%

(d)

(d) depends on rated performance for the MAXIMUM OPERATING CASE

(e)

0%

(e) Design to be based on the specific choice of fouling factor and fouled pressure drop. Hydraulics consistent with the design of the feed pump and circuit.

0% (f)

0%

(*) 10% For thermal integration cases only.

Comment

Heat Exchangers (3) (4) Condensers and reboilers

Reaction section preheat train feed / effluent heat exchangers

Other heat exchangers Compressor inter-stage coolers

(g) Consistent with the operating conditions of the compressor . If interstage coolers are outside compressor’s package requisition, a margin of 10% on duty may be considered.

(g)

Air-cooled Exchangers (3) (4) Product streams air cooled exchangers

10%

0%

Reactor effluent air cooled exchangers

Max(10%; 5%x ET)

Max(5%; 2.5% x ET)

(h)

(h)

Other Air cooled exchangers

ET = reactor feed / effluent Exchanger Train duty (h) To be defined in a case by case basis

(1) Where RO are used as minimum flow protection, the permanent re-circulation flow shall be added to the net process flow rate. (2) The compressor associated equipment (suction drums, inter-stage coolers etc.) shall have the same overdesign as the compressor itself. (3) For heat exchangers and air-coolers, the design margin on duty shall be applied for the governing case in terms of heat exchange. The fouling factors will be agreed with COMPANY to avoid excess of exchange area that may result in high skin temperatures (clean tubes), promoting fouling. (4) Hydraulics: maximum allowable pressure drop and the nozzle size shall be specified for the MAXIMUM OPERATING FLOW multiplied by the design margin. The maximum allowable pressure drop (fouled) has to be agreed by COMPANY.

7. Design temperature This chapter specifies the DESIGN TEMPERATURE(S) calculation for a process system (equipment and piping). A distinction will be made between new design and revamping or debottlenecking of existing units. The DESIGN TEMPERATURE shall always be defined in combination with the DESIGN PRESSURE of the selected operating case. More than one set of design conditions should be specified if the most severe pressure and temperature cannot occur at the same time. For CYCLIC SERVICE, cycle duration shall be specified. Refer to § 4.

7.1 Design margins on temperature 7.1.1 Design margins on positive temperatures The DESIGN TEMPERATURE shall be the maximum of the following values: • 60°C for mild climate (e.g. Europe) or other specific value according to local weather conditions, or • MAXIMUM OPERATING TEMPERATURE plus a margin of 20°C, or • Design temperature of utility network or raw materials, or • As per Licensor specific requirement • For vessels with saturated liquids, or at equilibrium, the design temperature will be equal to the bubble point of the process fluid at the PRV set pressure. 7.1.2 Design margins on negative temperatures (MDMT) The minimum design metal temperature (MDMT) shall be the lowest temperature between: • The minimum ambient temperature specified in the site conditions. • The MINIMUM OPERATING TEMPERATURE minus a margin of 10°C. • The CET, for equipment with fluids subject to AUTO-REFRIGERATION Cf. §7.1.3. 7.1.3 Fluids subject to AUTO-REFRIGERATION The CET is equivalent to the adiabatic flash temperature, or the atmospheric boiling point of the fluid/mixture (excluding vacuum conditions that could originate lower boiling temperatures). Based on CET curve (provided by Process), the MAT (depends on the metallurgy) will be determined with the support from pressure vessel specialists. MDMT = MAT at the maximum allowable operating pressure (MAWP) MDMT should be equal or colder than the CET. Further considerations on material apply for equipment subject to Auto-refrigeration phenomena to minimize BRITTLE FRACTURE risk. To be addressed by the pressure vessel specialist. To prevent BRITTLE FRACTURE, if low temperatures have occurred, Operating procedures shall ensure that the equipment is not repressurized until the metal temperature has raised up to the Minimum Pressurization Temperature (MPT to be determined by PVHE specialist).. 7.1.4 Exceptional conditions Contingencies will be considered as part of the DESIGN CONDITIONS or addressed by protective devices. The decision results from the evaluation between inherently safe design, good engineering practices and investment, supported by a risk analysis. If a contingency is used to set a DESIGN condition, no margin will be applied. Nevertheless, the difference between the NORMAL and the DESIGN value, shall be sufficient to allow for implementation of corresponding alarms as required by the process. The following scenarios leading to severe temperature are considered as exceptional, based on low likelihood of the initial event, hence not taken into account to define the DESIGN TEMPERATURE of the equipment.

To prevent loss of containment, adequate mitigation measures are implemented (e.g. depressurizing system, fire proofing, fire fighting): • Fire case. For flare header refer to the GS RC ECP 104. • Runaway reactions of specific process units. • Tube rupture The list and justification of exceptional conditions considered by CONTRACTOR shall be submitted to COMPANY for written approval.

7.2 Specific equipment considerations 7.2.1 Heat Exchangers & Air-cooled Heat Exchangers Consider the following scenarios to determine the maximum and minimum temperature that can be reached simultaneously on both sides of a shell & tube heat-exchanger, in particular for fixed tubesheet mechanical design: • Possible isolation of the cold side of the heat exchanger while the hot side is in operation (if compatible with unit operation) • Complex heat-exchanger preheat-train temperature profile which varies with the fouling, or product composition (e.g. crude type). • Loss of feed, for feed-effluent heat exchangers. • Transient operations (start-up/ shut down). • Design temperatures: - The design temperature of the cold side of heat exchangers will be at least equal to the maximum operating temperature of the hot side. This temperature applies also to cold side piping between first inlet and outlet block valves. - The design temperature of the hot side applies also to the hot side piping including the first inlet and outlet block valves. - The design temperature of the piping downstream of heat exchanger hot side outlet, will be at least equal to hot side inlet maximum operating temperature. • For distribution box of air coolers, the inlet and outlet DESIGN TEMPERATURES are equal. 7.2.2 Equipment downstream of Heat Exchangers & Air-cooled Heat Exchangers 7.2.2.1 Downstream of a heat exchangers with bypass For equipment downstream of a heat exchanger with a bypass on the hot side, the DESIGN TEMPERATURE shall be the maximum between: • the bypass NORMAL OPERATING TEMPERATURE and • the equipment MAXIMUM OPERATING TEMPERATURE + 20°C.

7.2.2.2 Downstream of an air-cooled exchanger outlet The DESIGN TEMPERATURE of equipment placed downstream of an air-cooled exchanger (except offsite lines) shall be the highest of the following: • DESIGN TEMPERATURE defined as per § 7.1.1, • DESIGN TEMPERATURE at air-cooled exchanger inlet minus normal temperature drop across exchanger, • NORMAL OPERATING TEMPERATURE at air-cooled exchanger inlet reduced by expected cooling due to natural draft (consider 20% of the design duty). For offsite lines downstream of an air cooler, the general rule given in § 7.1.1 shall be applied, but the scenario of exceeding the design temperature shall be analyzed in the relevant safety reviews. 7.2.3 Vessels For vessels such as distillation columns, different sections (overhead, side-draws and bottoms) may have different DESIGN TEMPERATURES. The CONTRACTOR must therefore set the different DESIGN TEMPERATURES and justify the proposed breakdown. For vessels with a quench, the maximum temperature to be considered shall be at least equal to the temperature of the hot stream prior to being quenched. For vessels such as reactors where local temperature excursions could take place (e.g. exothermic reaction leading to local hot spots), consider using a larger margin than 20°C to set the DESIGN TEMPERATURE (refer to Licensor requirements). For vessels which are internally refractory lined or with internal thermal insulation ("cold wall" vessel), the DESIGN TEMPERATURE shall be calculated using the insulating properties of the lining material. The thermal calculation will take into account the maximum temperature of the stream and an ambient temperature equivalent to the maximum site conditions without wind. The calculation shall be submitted to COMPANY approval. 7.2.4 Internals For equipment with internals or coating, the compatibility of these internals with all design conditions has to be verified (ex: compatibility of polymer coating with steam out conditions). 7.2.5 Tracing For traced equipment and lines, higher operating temperature may occur due to: a) excessive tracing, b) no product flow. For these systems the DESIGN TEMPERATURE should be at least: • Saturation temperature of the steam at maximum operating pressure if steam tracing is used. • DESIGN TEMPERATURE defined as per § 7.1.1 if electrical tracing is used. NOTE: consider a realistic coincident pressure for this particular case. 7.2.6 Piping The piping DESIGN TEMPERATURE usually corresponds to the DESIGN TEMPERATURE of the equipment upstream. Exception for vessels lined with refractory: the DESIGN CONDITIONS of the piping connections are based on the process stream conditions.

7.3 Revamping or Debottlenecking When the MAXIMUM OPERATING CONDITION is lower or equal to the original DESIGN CONDITION of the equipment or is compatible with the existing piping class, there is no modification to be done. When the MAXIMUM OPERATING CONDITION of equipment is higher than its original DESIGN CONDITION, the mechanical strength of the equipment shall be checked by pressure vessel specialist at the new set of operating conditions without process design margin (temperature, pressure and corrosion allowance). If results are considered mechanically acceptable, a dossier (with new design conditions) shall be issued per equipment and submitted to authorities for approval. If the mechanical strength of the equipment or the piping class are not compatible with the new operating conditions, mechanical solutions will be developed by pressure vessel specialist (reinforcement, partial replacement). If still not compliant, processwise the following options will be investigated: a. The process can be modified in order to bring back the MAXIMUM OPERATING TEMPERATURE and/or MAXIMUM OPERATING PRESSURE to values compatible with the original design, b. Implementation of an alarm with sufficient time for operator action, c. Implementation of a safety instrumented function activated on high high switch, d. If the equipment/line is not protected against overpressure, the implementation of a PRV or a PRD If one of the above-mentioned solutions can be implemented, supported by a major risk analysis, and instrumentation specialist support for (b) and (c), then the concerned equipment or line can be reused as is. Otherwise, the equipment or the line shall be replaced. Decisionmaking process about equipment/piping replacement is iterative and implies several engineering disciplines. Deviations from the original DESIGN CONDITIONS from a technology Licensor (e.g. reaction loop, proprietary equipment, etc.) shall be submitted to COMPANY and the Licensor.

8. Design pressure This chapter specifies the DESIGN PRESSURE(S) for a process system (equipment and piping). A distinction will be made between new design and revamping or debottlenecking of existing units. The DESIGN PRESSURE shall always be defined in combination with the coincident DESIGN TEMPERATURE of the selected operating case. Combination of extreme pressure and temperature of different operating cases shall not be considered. Specification GS RC ECP 101 addresses "Overpressure protection". For cyclic operation, cycle duration shall be specified (refer to § 4. DEFINITIONS).

8.1 Design margins on pressure 8.1.1 Design margins for internal DESIGN PRESSURE Internal DESIGN PRESSURE is used when the internal pressure is greater than the external pressure. In case a system is protected against the risk of overpressure by a PRV, the PRV setpoint is at the most, equal to the internal design pressure. MAXIMUM OPERATING PRESSURE (P MAX. OP. )

DESIGN PRESSURE (barg)

Equipment:

Connected to the flare

Not connected to the flare

P MAX. OP. ≤ 1.5 barg

3.5 barg

2.5 barg

1.5 barg < P MAX. OP. ≤ 2.5 barg

P MAX. OP. + 1 bar

2.5 barg < P MAX. OP. ≤ 10 barg

P MAX. OP. + 1 bar

10 barg < P MAX. OP. ≤ 35 barg

P MAX. OP. x 110 %

35 barg < P MAX. OP. ≤ 60 barg

P MAX. OP. + 3.5 bars

60 barg < P MAX. OP. ≤ 80 barg (*)

P MAX. OP. + 4 bars

P MAX. OP. > 80 barg (*)

P MAX. OP. x105 %

(*) For high pressure equipment the corresponding allowance shall be submitted to COMPANY approval. Indicated values are the minimum requirement. This paragraph is intended for pressure vessels and heat exchangers, however other cases exist: • •

atmospheric storage tanks, refer to § 8.2.6; equipment fabricated without a recognized construction code/standard, operating at atmospheric pressure with open vent. The design pressure shall be defined at 0.5 barg (example: bins for chemicals, additives).

8.1.2 Design margins for external design pressure External DESIGN PRESSURE is used when the internal pressure is lower than the external pressure. Examples: steam coils inside drums, heat exchangers, jacketed equipment. The maximum differential pressure to consider will be: a) equipment protected by PRV: high pressure side at DESIGN PRESSURE (including accumulation) and low side at P= 0 gauge. b) equipment without PRV: high pressure side at DESIGN PRESSURE and low side at P= 0 gauge. The advice of the static equipment specialist is suitable to identify design pressure for complex equipment. The cases a) and b) are not applicable to equipment designed for vacuum. In case a system is protected against the risk of collapse by a vacuum breaker, the vacuum breaker set point is the highest external pressure differential.

8.1.2.1 Equipment operating under vacuum conditions The following systems are subject to vacuum: • Systems normally operating below atmospheric pressure. • Systems where vacuum conditions occur on start-up, shutdown, regeneration, or other alternative operation modes. • Systems subject to vacuum conditions in case of upset such as process failure (e.g. loss of heat input, cold utility temperature) or extreme weather conditions (e.g. rapid cooling due to deluge or rainstorm). • Systems which can be blocked in and contain condensable vapours which have an overall vapour pressure at minimum ambient temperature or at minimum achievable process temperature lower than the atmospheric pressure. • Systems normally operated full of liquid which may be blocked in and cooled down and which may consequently reach a vapour pressure below the atmospheric pressure. • Systems subject to vacuum condition due to elevation (e.g. cooling water heat exchangers placed at a higher elevation than the cooling water settling out pressure head). • Systems containing steam in normal operation and that are not connected to atmosphere. FV will be combined with the DESIGN TEMPERATURE. • Equipment with a plugged vent where liquid (non volatile) can be drained or pumped out (without atmospheric venting or gas injection for repressuring). Design pressure: equipment which may be subjected to a vacuum in service should be designed for an external pressure differential 25% greater than the maximum expected operating value up to a maximum of full vacuum (i.e., full vacuum should be the most severe case). In addition to vacuum, design pressure from § 8.1.1 shall apply. Partial vacuum may be considered after COMPANY approval when there is a physical limitation preventing vacuum (e.g. vacuum breaker, ejector design or vacuum pump design are such that vacuum is limited). 8.1.3 Equipment subject to Steam Out Design conditions to be considered for equipment and piping that can be steamed out and isolated, shall be at least -0.5 barg (half vacuum) at the steam saturation temperature at maximum operating Pressure or 150°C (where low pressure steam is used), whichever is greater. Before starting the steam out, the vent (to flare or to atmosphere) shall be opened. Prevent isolation of the system while purging with steam shall be clearly stated in the operating procedure.

8.2 Specific equipment considerations 8.2.1 Design pressure profile for columns and associated equipment The value of the DESIGN PRESSURE on a column datasheet shall be defined at the top calculated as per § 8.1.

The pressure to design the bottom of a fractionation column will be determined as follows: Maximum Pressure at Bottom = DESIGN PRESSURE at top + maximum Column Pressure Drop + Maximum Hydrostatic Head (consider overfilling scenario). For systems where Overfilling scenario has not been considered in the original design, if application of this GS is inducing major changes on existing items, either refer to GS RC ECP 101 for mitigation measures, or submit a derogation request to COMPANY. The DESIGN PRESSURE of the equipment associated to the column shall take into account the column DESIGN PRESSURE (top or bottom) and the relative position of the equipment (e.g. reboiler, etc.). As a preliminary figure, when over pressure protection is ensured by PRVs located at the top of the column or on the overhead line (upstream of the coolers), the DESIGN PRESSURE of downstream equipment (air cooler, trim cooler, reflux drum, etc.) should be equal to the column top DESIGN PRESSURE + 1 bar minimum at early design stage. The maximum hydrostatic head shall be checked when final equipment elevation is known by CONTRACTOR. 8.2.2 Pumps discharge All equipment located at the discharge of a pump shall have the same DESIGN PRESSURE. This DESIGN PRESSURE, shall be applied up to the last block valve before a section protected by a PRV. 8.2.2.1 Centrifugal pumps - Shut-off pressure The DESIGN PRESSURE at pump discharge is the maximum discharge pressure and is calculated as the sum of the maximum suction pressure and the maximum differential head of the pump (i.e. differential head at no flow or pump shut-off). When the differential head of a pump at no flow is not available (e.g. the pump is not yet purchased and the pump curve is not available), this DESIGN PRESSURE at pump discharge shall be estimated with the following formula: • For electrically driven pumps: 𝐷𝐸𝑆𝐼𝐺𝑁 𝑃𝑅𝐸𝑆𝑆𝑈𝑅𝐸𝑃𝑢𝑚𝑝 𝐷𝑖𝑠𝑐ℎ𝑎𝑟𝑔𝑒 = 𝑃𝑆𝑢𝑐𝑡𝑖𝑜𝑛 𝑀𝑎𝑥 + 120% ∗ ∆𝑃𝐷𝑒𝑠𝑖𝑔𝑛

• For pumps driven by a steam turbine or high speed pumps electrically driven : 𝐷𝐸𝑆𝐼𝐺𝑁 𝑃𝑅𝐸𝑆𝑆𝑈𝑅𝐸𝑃𝑢𝑚𝑝 𝐷𝑖𝑠𝑐ℎ𝑎𝑟𝑔𝑒 = 𝑃𝑆𝑢𝑐𝑡𝑖𝑜𝑛 𝑀𝑎𝑥 + 130% ∗ ∆𝑃𝐷𝑒𝑠𝑖𝑔𝑛

• For multistage pumps:

𝐷𝐸𝑆𝐼𝐺𝑁 𝑃𝑅𝐸𝑆𝑆𝑈𝑅𝐸𝑃𝑢𝑚𝑝 𝐷𝑖𝑠𝑐ℎ𝑎𝑟𝑔𝑒 = 𝑃𝑆𝑢𝑐𝑡𝑖𝑜𝑛 𝑀𝑎𝑥 + 140% ∗ ∆𝑃𝐷𝑒𝑠𝑖𝑔𝑛

P Suction Max =The maximum suction pressure. (i.e. considering design pressure of the suction drum, highest liquid level - LSHH, highest liquid density foresee, including start-up fluid)

ΔP Design = The differential head of the pump at DESIGN FLOW. The shut off pressure shall be checked when the certified characteristic curve of the selected pump is available. Centrifugal pumps in series: in the case of two or more pumps in series, the maximum differential head will be the sum of the maximum differential head of each pump if there is no PRV between the pumps.

Transient operation: for equipment operated with different condition during the start-up or shutdown phases, the DESIGN PRESSURE at the discharge of a pump shall be determined covering also these conditions (e.g. lower operating temperature and higher density during start-up than during normal operation). 8.2.2.2 Positive Displacement Pump The DESIGN PRESSURE on the discharge of a positive displacement pump shall be equal to the highest value between: • 110% of the discharge Maximum Operating Pressure, • The pressure defined as per § 8.1.1 This also sets positive displacement pumps PRV set pressure (refer to GS RC ECP 101). 8.2.3 Pumps suction For pumps operating with a spare, DESIGN PRESSURE of the pump suction up to and including the individual pump suction isolation block valves shall be equal to the discharge DESIGN PRESSURE. This will avoid overpressure in the spare pump system caused by the operating pump. For the specific case of pumps having a safety isolation valve in the suction line (refer to GS RC ECP 103), extension of the DESIGN PRESSURE up to and including this isolation valve shall be studied. 8.2.4 Compressors For compressors that can be isolated and for compressors included in a loop, the Settling Out Pressure (SOP) is the equilibrium pressure reached between the suction and discharge of the compressor system when the compressor is stopped. The DESIGN PRESSURE of equipment and piping of the compressor shall be equal to or higher than the SOP up to the suction isolation valve. In the case of reciprocating compressors protected by spring loaded PR valves, the PRV and the DESIGN PRESSURE of the discharge circuit shall be set above the maximum pulsation pressure, the pressure defined as per § 8.1.1 and 110 percent of the MAXIMUM OPERATING PRESSURE at compressor discharge, whichever is greater. 8.2.5 Heat Exchangers DESIGN PRESSURE shall be fixed as per § 8.1.or 8.2.2 for heat-exchangers at pump discharge. At preliminary design, the DESIGN PRESSURE of the low pressure side shall be equal or higher than the 10/13 of the design pressure on the HP side, (this rule is related to the ASME code). Once that the hydrotest pressure has been determined by mechanical specialist, the design pressure values will be verified, following API STD 521 § 4.4.14.2.1. The paragraph states the following: loss of containment of the low-pressure side to atmosphere is unlikely to result from a tube rupture where the pressure in the low-pressure side (including upstream and downstream systems) during the tube rupture does not exceed the corrected hydrotest pressure (see 3.1.22 (*) and 4.2.2). The user may choose a pressure other than the corrected hydrotest pressure, given that a proper detailed mechanical analysis is performed showing that a loss of containment is unlikely.

The use of maximum possible system pressure instead of design pressure may be considered as the pressure of the high pressure side on a case-by-case basis where there is a substantial difference in the design and operating pressures for the high-pressure side of the exchanger. (*) API STD 521 § 3.1.22: "Hydrostatic test pressure multiplied by the ratio of stress value at upset temperature to the stress value at test temperature" 8.2.6 Tanks For setting the DESIGN PRESSURE of atmospheric tanks refer to API STD 620, API STD 650, and API STD 2000. Tank liquid density used for design shall be the maximum between water density and product density at storage conditions. 8.2.7 Other Considerations 8.2.7.1 Jacketed/multi chamber equipment This paragraph covers equipment fitted with a jacket, or equipment formed by two sides (noncommunicating) separated by a dividing wall. DESIGN CONDITIONS to be specified on both sides. 8.2.7.2 Common element separating two pressure sides A differential design pressure (other than the ones specified in the GS RC PVE 001, GS RC PVE 002) shall not be used unless specifically approved by COMPANY. In the case where a differential design pressure design is approved by COMPANY the following requirements shall also apply: • in the deviation request, the Engineering Company shall justify the economical advantage and also demonstrate that it doesn’t impact reliability and / or service life. • For shell & tube heat exchanger, tube bundle and tubesheet shall be designed for a minimum differential pressure of 2.5MPa (25 bar) when the design pressure of either heat exchanger sides (shell or tube) is above 4.5MPag (45 barg) and service conditions make it impossible to pressurize one side of the exchanger without simultaneously pressurizing the other side. The process design study shall determine the minimum differential pressure which may be higher than 2.5 MPa. 8.2.7.3 Vessels internal supports For the design of internal supports (trays, packing bed, catalyst bed, demister, coalescer) the following shall be considered: • The differential DESIGN PRESSURE and DESIGN TEMPERATURE at the end-of-run (fouled) condition, • The differential pressure and temperature in regeneration mode if any, • Maximum Temperature and differential pressure in depressurization case (if applicable).

8.2.7.4 Vessels subject to internal explosion risk Special consideration shall be given to equipment subject to risk of internal explosion. As far as possible the DESIGN PRESSURE shall be such that the equipment can handle the pressure wave resulting from an explosion, otherwise CONTRACTOR will submit solutions to COMPANY. 8.2.7.5 Design pressure for reaction loops For single pressure relief device protecting several equipment in a process system (e.g. reaction loops), the DESIGN PRESSURE of each equipment shall be set as per API STD 521 annex B. 8.2.7.6 Pressure Surge During detailed engineering, CONTRACTOR shall analyze all systems in liquid services for potential pressure surges due to valve closure, pump shutdown or any other potential scenario leading to the phenomena of pressure surges. The results of this analysis, including the list of all potential line services subject to pressure surge shall be submitted by the CONTRACTOR to COMPANY. Preferred option to limit the hydraulic surge is to design the system with adequate time closure and DESIGN PRESSURE to prevent need of a relief device required for this contingency. If a pressure relief device is required refer to GS RC ECP 101. 8.2.7.7 Interconnecting Headers and Process Units Rundown Lines For interconnecting lines with multiple supply and/or multiple destinations, the DESIGN PRESSURE of the system shall be the maximum of the DESIGN PRESSURE among the supply (highest pump shut-off condition), except in the following cases: • No common mode failure scenario has been identified such as all way-outs can be closed at the same time, leading to a "blocked outlet" case, • A specific operating procedure is in place to ensure that in any case one way-out will be always open. Such procedure shall be approved by COMPANY. • A PRV protects the interconnecting system.

8.3 Revamping or Debottlenecking 8.3.1 General considerations Refer to § 7.3 8.3.2 General rules for piping When the MAXIMUM OPERATING PRESSURE is compatible with the existing piping class, there is no modification to be done; otherwise the line shall be replaced. NOTE: for high pressure systems, piping classes with optimized thickness may have pressure limits lower than the ones from R&C piping classes in GS RC PVA 102. The actual design pressure must be provided by the Inspection department from site.

8.3.3 Shut off pressure of centrifugal pumps In case an existing pump needs to be replaced by a new one or modified (e.g. increase of the impeller size), the new shut-off pressure shall be calculated as per the following steps: • Step 1: Apply the design rules given in the § 8.2.2 (Pumps discharge). If the DESIGN PRESSURE of the downstream equipment is higher or equal to the shut-off pressure there is no modification to be done. Otherwise go to step 2. • Step 2: Calculate the highest of the following pressures: − Normal suction pressure (including the maximum liquid level in the suction drum) plus the maximum differential head of the pump (at pump shut-off), − Maximum suction pressure (DESIGN PRESSURE of suction drum and static head for maximum specific gravity and high liquid alarm) plus the normal differential head of the pump. The above rule is subject to COMPANY written approval and the following shall be verified: − This rule applies only in revamps and debottlenecks studies. − The impact of impeller modification on the pump casing DESIGN PRESSURE. − There is no concomitant scenario of suction equipment at PRV set pressure and blocked outlet (e.g. isolation of pump outlet). An example of concomitant scenario is for a column reflux pump. In case of flow control failure leading to the closing of the flow control valve (FV) at pump discharge, the pressure in the column will rise up to the PRV set pressure, while the shut-off pressure will be reached at pump discharge. • Step 3: If the shut-off pressure calculated as step 1 and 2 is still higher than the DESIGN PRESSURE of downstream equipment or piping, pump manufacturer will be requested to find alternatives (adjust curve shape or change pump model). • Step 4: As a last resort, the installation of a PRV on the pump's discharge line associated with a safety instrumented function can be considered. The PRV relieving capacity is obtained from the pump curve and the relevant pump suction conditions. Evaluation shall take into account the pressure difference between shut-off pressure and PRV accumulation pressure. Enough margin shall be kept between the MAXIMUM OPERATING PRESSURE and the PRV set pressure When none of the above solutions allow operating the equipment and line below their original DESIGN PRESSURE the downstream equipment and, or lines shall be replaced. 8.3.4 Reaction loops For the reaction loops, the Settling Out Pressure (SOP) resulting from the recycle compressor shutdown shall be recalculated according to API STD 521 annex B. In any case, the margin between the SOP and the design pressure of the separator drum where PRV is located, shall be 5% minimum. Regarding verification of equipments DESIGN PRESSURE in the reaction loop, an alternative methodology (DP Translation) could be used if the values obtained from API method, result in higher DESIGN PRESSURE than current ones. If the SOP is higher than the set pressure of the PRV protecting the reaction loop (usually located at HP separator), CONTRACTOR shall submit solutions for COMPANY approval.

8.3.4.1 Use of dynamic simulation When a debottleneck is such that it is pushing to the design limits of the unit, it is recommended to develop a dynamic simulation of the reaction loop in order to verify the thermal and hydraulic behaviour of the loop at normal and upset operating conditions, including depressurisation of the loop. This will help to validate the operating limits of the revamped or debottlenecked unit, and also to design appropriate safeguards, including operating procedures.

9. Materials & corrosion allowance The selection of the material and the corrosion allowance shall be realised by CONTRACTOR in accordance GS RC COR 006 (General Material selection guideline) and the material selection diagram shall be reviewed and approved by COMPANY material specialist.

9.1 Material selection A material selection diagram shall be developed in accordance with the NACE SP0407 (Format, Content and Guidelines for developing a Materials Selection Diagram) and a review shall be organized with the participation of Licensor, corrosion specialist and process engineer from COMPANY. Material selection shall take into account the potential for corrosion (internal and external) and erosion problems associated with the fluids carried (composition, free water, carbon dioxide, hydrogen sulphide, oxygen, amount and characteristics of solids, hydrogen partial pressure etc.). Relevant component concentrations will be indicated on the material selection diagram. Concerning the wet H 2 S service and other specific services, refer also to the GS RC WAM 011 and GS RC WAM 211.

9.2 Corrosion allowance Corrosion allowance shall be selected in accordance with the design life requirements given in § 5.

10. Vessels Requirements concerning pressure vessels that are not addressed in the present specification are included in GS RC PVE 001.

10.1 Position of vessel Priority shall be given to: • HORIZONTAL vessels where the liquid flow is high (e.g. liquid separators, desalters, reflux drum). • VERTICAL vessels for better level measurement precision, for improved efficiency in gas/liquid separation in the gas phase (e.g. compressor KO drums, fuel gas drum) or in case of reduced plot space availability.

10.2 Vessel sizing 10.2.1

Vessel dimensions

The selection of the length over diameter ratio (L/D) is based on operating, economic or plot plan considerations.

Unless otherwise specified, the recommended ratios are: DESIGN PRESSURE (barg)

L/D (-)

< 7 barg

2 to 3

≥ 7 barg

3 to 5

L: Length of vessel between weld seams D: Diameter

For vessels with an internal diameter lower than 800 mm (32"), piping element may be used. For vessels with an internal diameter lower than 1000 mm (40"), flanged heads may be used. 10.2.2

Hold-up

The hold-up is defined as the volume contained between the high liquid level (HLL) and the low liquid level (LLL). Refer to § 10.2.3. Hereunder are given the typically recommended hold-ups for most common services based on NORMAL OPERATING CONDITION. • P = Liquid Product (m3/minute) • R = Reflux (m3/minute) • F = Feed (m3/minute) 3

SERVICE

HOLD UP (m ) Recommended EMERGENCY LEVEL SPANs (3) NORMAL LEVEL SPAN TYPE Above HLL Below LLL (LLL-HLL) (HLL-LSHH) (LSLL-LLL)

LIQUID FEED SURGE DRUM Feed to Unit

Horizontal or vertical

10P

2P

2P

Horizontal

Max (5R; 2P)

Max (2R; 1P)

1(P+R)

Liquid product to fractionator or Horizontal to Unit without surge drum VAPOUR / LIQUID SEPARATOR

Max (5R; 10P)

Max (2R; 1P)

1(P+R)

Liquid to storage

5P

2P

Liquid to fractionator or furnace Horizontal or vertical

5P

2P

Liquid to other equipment

5P (with pump) 3P (without pump)

REFLUX DRUM Liquid product to storage

Vertical

Horizontal or vertical

Compressor KO drum (suction, Vertical interstage) Fuel gas KO drum

Vertical

Steam gas KO drum, Steam condensate flash drum

Vertical

Max (5P; liquid volume 2P (note 1) equivalent to 3 m of feed pipe) Max (5P; liquid volume equivalent to 3 meters of feed pipe) Max (5P; liquid volume equivalent to 3 meters of feed pipe)

2P

-

-

-

3

SERVICE

Steam drum (boiler)

HOLD UP (m ) Recommended EMERGENCY LEVEL SPANs (3) NORMAL LEVEL SPAN TYPE Above HLL Below LLL (LLL-HLL) (HLL-LSHH) (LSLL-LLL) Horizontal Max (2F; 1/3 of boiler 1P 3P volume; 10P)

Steam exchanger condensate pot

Vertical

2P

Deaerator

Horizontal

15P

Amine surge drum (separation and degassing)

Horizontal

30P

LIQUID / LIQUID SEPARATOR (2) Liquid / Liquid separator

Horizontal

For hold-up refer to "Vapour/liquid separator" for each liquid phase

-

To Unit, to heat recovery train or transferred with a pump To storage (direct cooling) and transferred without a pump Exception: Column bottom product on flow control (without level override)

5P

2P

2P

2P

2P

2P

15P

1P

1P

To Fired Heater (reboiler) and to storage (P) To Fired Heater (different from reboiler heater) and to storage simultaneously Pf=Product on flow control Pl=Product on level control

5P

-

2P

10Pf + 5Pl

1P

1P

Min hold-up in tar pot

-

Amine absorber

-

5-10 seconds on P without quench facilities 5P 2P

Amine stripper

-

COLUMNS BOTTOMS with level control

2P

2P if there is an amine 2P 2P surge drum Max (5P; 2 days of amine make-up) elsewhere (1) If in normal operation no liquid product is expected (P = 0), either an upset operating case can be defined (lower inlet temperature, leak in upstream heat exchanger etc.) or a minimum value of 150 mm between HLL and LSHH shall be applied. (2) For retention time definition refer to 10.5.3. (3) The minimum hold-up for emergency level span indicated in the table have to be applied if only if an emergency level is required (LSLL or LSHH). Contractor shall ensure that at DESIGN RATE, the time between the alarm and the trip is realistic for the operator to take action.

10.2.3

Level positions

For level instrument nozzles refer to § 11.4.3. The level positions are described in the schemes below: Level Positions for Horizontal Vessels TTL 10%

LG TLN TLN

LSHH

LSHH-HLL = refer to § 10.2.2

HLL LAH

10% LLL – HLL

40% TLN – BLN = Measurement Range

= Hold-up (m3) refer to § 10.2.2

NLL

80%

40% LAL LLL

10% LLL-LSLLL = refer to § 10.2.2

LSLL

10%

BLN LG BLN

BTL

Level Positions for Vertical Vessels

TTL

LG TLN 10% TLN

LSHH

LSHH-HLL = refer to § 10.2.2

HLL LAH

10% 40%

TLN – BLN = Measurement Range

LLL – HLL

NLL

80%

to § 10.2.2

40% LAL LLL 10%

10%

LSLL BLN LG BLN

LLL-LSLLL = refer to § 10.2.2

BTL

Acronyms for Level Positions: TTL

Top Tangent Line

LG TLN

Level Gauge Top Level Nozzle (Centre line)

TLN

Top Level Nozzle (Centre line) – for the level transmitter

LSHH

Level Switch High High (also called HLCO: High Level Cut Off)

LAH

Level Alarm High

HLL

High Liquid Level

NLL

Normal Liquid Level

LLL

Low Liquid Level

LAL

Level Alarm Low

LSLL

Level Switch Low Low (also called LLCO: Low Level Cut Off)

BLN

Bottom Level Nozzle (Centre line) – for the level transmitter

LG BLN

Level Gauge Bottom Level Nozzle (Centre line)

BTL

Bottom Tangent Line

Note: Above acronyms are used for vessel sizing only. The applicable specification for "Tagnumbering for instrumentation equipments" is the GS RC INS 105. Vessel sizing will be performed as follows: Without LSHH or LSLL

With LSHH or LSLL

TTL - LG TLN

150 mm minimum

LG TLN – TLN

50 mm if the gauge is a level glass otherwise 0 mm (e.g. magnetic level). In order to ensure same level range for both, level gauge and level transmitter instruments.

TTL-LSHH

If no vapour flow in normal operation: 300 mm. If vapour flow in normal operation: Maximum of (300 mm (12") ; 20% of the diameter for horizontal vessel; value defined in § 10.2.4)

TLN-LSHH

10% of the Level measurement range (10%*(TLN-BLN)) (minimum)

LSHH-HLL

Without LSHH: LSHH-HLL = 0 mm

HLL-LAH

Without LSHH: With LSHH: HLL-LAH = 10% *(HLL-LLL) HLL = LAH unless otherwise specified for operational requirements

HLL-LLL

Refer to § 10.2.2. It shall not be lower than 300 mm.

NLL

At 50% of LLL-HLL unless otherwise specified for operational requirements

LAL-LLL

Without LSLL: With LSLL: LLL-LAL = 10% *(HLL-LLL) LLL = LAL minimum unless otherwise specified for operational requirements

LLL-LSLL

Without LSLL: LLL-LSLL = 0 mm.

LSLL-BLN

10% of the Level measurement range (10%*(TLN-BLN)) (minimum)

BLN – LG BLN

50 mm if the gauge is a level glass otherwise 0 mm (e.g. magnetic level). In order to ensure same level range for both, level gauge and level transmitter instruments.

LG BLN – BTL

150 mm minimum

With LSHH: Refer to § 10.2.2 or apply 2*P if the case is not specified in the table. It shall not be lower than 150 mm.

With LSLL: Refer to § 10.2.2 or apply 2*P if the case is not specified in the table. It shall not be lower than 150 mm.

The following recommendations shall also be considered when selecting the level positions in a vessel and shall be confirmed during safety reviews. • LSLL : − If the loss of level may cause a gas blow-by from a HP system into a LP system. − Where required for centrifugal pumps protection, refer to § 16.1.2.2. − If the loss of interface level in the drum may result in operational or safety concerns in downstream units. This is the case for instance for interface levels between: o Hydrocarbons and sour water, hydrocarbon flow to Sour Water Stripper. o LPG and either water or caustic or amine. − When applicable, the retention time below LSLL should be compatible with the time required to close the outlet emergency isolation valve or to stop the pump. • LSHH : − For columns with reboilers, the LSHH shall be located under the lower generatrix of the reboiler return nozzle on the column. − The LSHH point shall be set at a sufficiently low level so that, at the DESIGN TEMPERATURE, risk of liquid carry-over to the PRV is minimized (two-phase flow limiting the relieved flow). Therefore, the heat expansion of the liquid between the normal operating temperature and the DESIGN TEMPERATURE shall be considered for maximum liquid level selection, in particular for liquids close to their critical conditions (e.g. LPG). 10.2.4

Vapour area

Vessels shall be sized in order to keep the vapour phase velocity sufficiently low to minimize risks of liquid entrainment. The following excludes flare KO drums. The maximum vapour velocity in the vessel shall be lower or equal to the maximum allowable gas velocity defined as follows: With: • 𝑉 = maximum allowable gas velocity (m/s)

ρl − ρg V = K� ρg

• ρl = liquid density (kg/m3) • ρg = gas density (kg/m3)

• K = the Souders and Brown coefficient

For preliminary sizing, the following Souders and Brown coefficient values should be adopted: Configuration

Without mist eliminator

With mist eliminator With wire mesh With vanes (1)

Horizontal

0.08

0.10

0.16

Vertical

0.04

0.08

0.16

(1) Value to be confirmed by the vane pack supplier.

10.3 Vessel internals 10.3.1

Vortex breaker

On vessel liquid outlets, there is a risk of vapour entrainment through a vortex effect, which may cause damage to the downstream equipment. In a fouling service, the vortex breaker shall be installed at a minimum of 150 mm above the vessel bottom. A vortex breaker shall be provided on all liquid outlet nozzles: • To pump suction • To reboiler inlet • From Liquid draw off trays • To control valve 10.3.2

Mist Eliminator

When liquid droplet entrainment may result in operational or safety concerns in downstream systems, mist eliminator should be installed. If there is a risk of fouling or plugging of the mist eliminator, the nozzles connected to PIs or PRVs shall be located below the mist eliminator (as per GS RC ECP 101). A demister should be considered if it allows reducing the cost (e.g. in case of debottlenecking) or in case of layout constraints with the following considerations: • Wire mesh pads should be used by default. Mesh density, thickness and diameter shall be specified on the PROCESS DATA SHEET and reviewed with vendor. Usually the pad thickness is 6" (or 150 mm) minimum. • For some services and where the operating pressure is below 20 barg, vane packs or other vapour internals such as cyclones can be used after written approval from COMPANY. 10.3.3

Reactor internals

For Internals of hydro-treatment and hydro-desulfuration reactors refer to the GS RC PVE 010.

10.4 Vessel elevation In preliminary design phases (prior to FEED); in case a product at its boiling temperature is pumped, a minimum elevation of 5 m should be specified between the bottom tangent line (or bottom line for horizontal vessels) and grade. This elevation will be confirmed when NPSH requirements of the pump are finalized with piping layout and rotating equipment disciplines. If there is no other process requirement regarding the elevation, a note on P&ID will indicate "minimum for piping".

10.5 Specific vessels The above general requirements on vessels also apply to "specific vessels" unless otherwise mentioned here below.

10.5.1

Filters

A filter is normally spared, unless it can be bypassed a few hours without significant consequence on the process, in order to carry out cleaning operations. Spare filter can be either identical or sized for a shorter cleaning cycle. Consider the installation of a filter upstream of coalescers and of spray nozzles depending on service. Specifications of this filter shall be in accordance with coalescer supplier recommendations. The sizing criteria for the filter mesh shall be the following: • Mesh approximately 50% of the maximum particle size allowed by vendor of the downstream protected equipment, • Minimum open surface shall be 150% of the pipe size. Burner protection with filters is addressed in the GS RC THE 004. Basket filters or strainers are preferred for prevention of soil pollution and for ease of cleaning. Filters other than strainers are to be considered as vessels and therefore nozzle requirements are applicable. The pressure drop across the filters shall be measured at least locally. 10.5.2

Steam drums in process units

Refer to GS RC THE 100. 10.5.3

Liquid / Liquid Decantation

For liquid / liquid separators, the retention time for the two liquid phases shall be considered. The effective retention volume to be considered for the design of a vessel is the portion of the vessel in which the two liquid phases remain in contact with one another. As far as the two liquid phase separation is concerned, once either substance leaves the primary liquid section, although it may remain in the vessel in a separate compartment, it cannot be considered as a part of the retention volume. The retention volume of the higher density liquid is taken between the bottom and INLL (Interphase Normal Liquid Level). The retention volume of the lighter density liquid is taken between the INLL (Interphase Normal Liquid Level) and the NLL (Normal Liquid Level). The retention time for each phase depends on the effluents characteristics, the operating temperature, etc., and is fixed on a case by case basis. For water / hydrocarbons separation the values of the API SPEC 12J, 8th edition can be considered, see table below: Oil relative density G

Temperature T (°C)

G < 0.850 G > 0.850

Tr (min) 3 to 5

T > 38°C

5 to 10

25°C < T < 38°C

10 to 20

T < 25°C

20 to 30 th

Reference: API SPEC 12J, 8 edition

The distance between the LSLL (or LLL if there is no LSLL) of the lightest liquid and the LSHH (or HLL if there is no LSHH) of the heaviest liquid (interface) shall be 200 mm minimum in order to allow fluctuations of the interface unless the vessel is equipped with a weir. For liquid / liquid decantation, the hold-up of each liquid phase shall comply with the hold-up volumes (LLL-HLL, LSLL-LLL, HLL-LSHH) defined in § 10.2.2. If a maximum droplet size is required by the process, the decantation performance will be checked by using Stokes law: Vs Settling velocity (m/s), it is the downward velocity of the particle droplet (e.g. water) relative to the continuous phase (e.g. naphtha) 3

Vs =

2 (𝜌𝑃 − 𝜌𝐹 ) ∗ ∗ 𝑔 ∗ 𝑅2 𝜇 9

𝜌𝑃 Mass density of the particle (kg/m ) (e.g. water) 3

𝜌𝐹 Mass density of the fluid (kg/m ) (e.g. naphtha) 𝜇 Viscosity of the fluid (Pa.s) (e.g. naphtha) 𝑔 Gravitational acceleration = 9.81 m/s² 𝑅 Radius of the particle (m)

For the decantation of two liquids having a close density or for services requiring a high phase separation efficiency CONTRACTOR can propose the use of a coalescer pad to reduce significantly the size of the vessel. However, for fouling services, the use of a coalescer pad is not recommended. For hydro-desulfurisation units, a droplet size of 500 µm is typically considered downstream the coalescer of MP drum. 10.5.4

Closed drain drum

Refer to the GS RC ENG 405. 10.5.5

Flare KO drum

Refer to the GS RC ECP 104 10.5.6

Silos and hoppers

The volume of silos containing solids shall be based on the lowest apparent density. The mechanical design shall be based on 1.2 x the highest compressed apparent density. Consider LSHH height. The silos will be protected from vacuum by a breather valve to atmosphere (depending on product toxicity). They shall not be designed to withstand full filling with a liquid, unless a risk analysis identifies such scenario.

11. Vessels nozzles Additional requirements concerning vessels nozzles that are not addressed in the present specification are included in the following specifications: • GS RC PVE 001 • GS RC ENG 405 • GS RC INS 200

11.1 Nozzles Tagging Unless otherwise specified by the project, the vessel nozzles shall be tagged on data sheets and P&ID’s with a combination of a letter and a number. The letter indicates the nozzle function as listed in the table below. The number is used to differentiate nozzles having the same function. Nozzle

Function

Example of Nozzle Tagging

A Process inlet B Process outlet D Drain H Hand hole L Level connection M Manhole P Pressure connection T Temperature connection S Utility connection V Vent W Relief valve connection Notes: Use preferably E or K when none of the other symbols apply. Do not use I, O, Q, U, X, Y, Z.

B2 V

P A1 L1

L2

M S

L1

L2

B1

D

11.2 Vent, drain, utility and steam-out connections The whole plant shall be designed with steam out and purging connections adequate in number and size, to enable inert or hydrocarbons flushing during start-up, shutdown and maintenance operation. Vessels should have a utility and, or steam-out connection operational even when it is isolated (generally on the vessel). 11.2.1

Size

Vent, drain, utility and steam out connections shall be sized as follows: Vessel’s volume (m³)

Minimum Nozzle Diameters VENT (1) (2) (3)

DRAIN (4) (5)

UTILITY and STEAM OUT

V ≤ 15

2" (DN 50)

2" (DN 50)

2" (DN 50)

15 < V ≤ 75

3" (DN 80)

3" (DN 80)

75 < V ≤ 220

4" (DN 100)

4" (DN 100)

220 < V ≤ 420 V > 420

3" (DN 80) 6" (DN 150)

4" (DN 100)

1. In any case, the vent size shall be equal or larger than the drain size. 2. For vents used in normal operation (atmospheric vessels), it shall be sized to compensate any maximum filling or emptying scenario. 3. For vertical vessels where a manhole has not been provided at or near the highest part of the vessel, an air vent nozzle of 6" (DN150) minimum shall be provided to allow effective ventilation of the equipment during internal inspection. 4. For nominal drain size, the volume to be considered is the liquid volume to be drained and not the total volume of the vessel. 5. Specific criteria for connection to the closed drain are given in the GS RC ENG 405.

For vessels with internal baffles, one utility connection and one drain connection per compartment will be provided. For horizontal vessels longer than 6 m, additional drain connections are required with a maximum distance of 3 m in between any two drain connections. For vessels equipped with overflow connections, the overflow nozzle and line shall be sized, as a minimum, one nominal diameter above the inlet or outlet nozzle diameters (whichever is greater). 11.2.2

Vent

Vessels shall have at least one vent (at the highest point) connected directly to the vessel and equipped with a block valve. If the vent for degassing is connected to a piping line, an additional nozzle is required for ventilation. Refer to GS RC PVE 001 for further details. The vent is used to: • Ensure proper ventilation during personnel entry (e.g. inspection): the ventilation nozzle is not connected to a piping line. As specified in GS RC PVE 001 – § 8.9.3, a ventilation flanged nozzle shall be located at the highest point and shall have a minimum nominal diameter of NPS 6 (DN 150). • Remove air at start-up by purging with steam or nitrogen, • Perform steam-out at shutdown. Depending on the service, steam-out can also be sent to flare or to safe location via another connection. For horizontal vessels, the vent also needs to be placed opposite of the manhole, utility and steam-out connections. All open vents shall be protected by bird screen. The open vent end shall be curved in a way to avoid sand and water entrance. In this case, ventilation nozzle is not required. The vent valve shall be: • Screwed with a plug only for neither flammable nor harmful, nor toxic products (e.g. air, water) and under piping class of 150 #. • Flanged and blinded for all other cases. The vent connection arrangements are given here below:

Vent flanged with a blind V

Vessel

Vent Screwed with a plug V

Vessel

Vents to atmosphere cannot be used when hydrocarbon is present in the vessel, so double valve requirements given in § 22 do not apply to vents (single valve and blind is sufficient). 11.2.3

Drain

Vessels shall have at least one drain (at the lowest point) connected directly to the vessel and equipped with a block valve. Drain connections requirements are addressed in the GS RC ENG 405.

11.2.4

Utility and Steam out connection

No utility or steam out connection is required on equipment with service air, nitrogen, water or steam in normal operation. 11.2.4.1 Utility connections There are two different types of utility connections: • Utility connection for flexible hoses. This is the default utility connection. • Hard-piped utility connection. It should be considered in the following cases: − Large volume (nozzle ≥ 3") − Very frequent use. If the pressure on the process side is higher than the pressure on the utility side, positive isolation shall be foreseen (refer to § 22.1). The necessary protections shall be taken to prevent the process from polluting the utilities systems (e.g. check valves). Refer to typical given hereafter. 11.2.4.2 Steam Out connections Unless otherwise specified by existing more stringent rules from the site, the following steam pressure levels for steam out operation shall be applied: • Low Pressure (LP around 4 barg) steam will be used for vessel volume ≤ 220 m3 • Medium Pressure (MP around 15 barg) steam will be used for vessel volume > 220 m3 If it is economically justified, and if it is acceptable from an operation point of view a single steam out network could be considered. For equipment with internal coating, compatibility of the coating with steam temperature shall be verified. Steam out of equipment in amine or caustic service is authorized only after rinsing the equipment with fresh water ([Cl] < 250ppm). Facilities must be provided to allow rinsing before direct steaming. Steam out provided on vessels shall be at minimum distance from the bottom tangent line. Steam out connection 3" and larger shall be permanently connected to steam header with hard pipe. The utility and steam-out connection arrangements are given here below: Utility and Steam Out connection without hard pipe (flexible hose < 3")

Utility connection and Steam Out connection with hard pipe ( ≥ 3") Utility connection

Vessel

Vessel

¾’’

V

Steam Header

¾’’

V

MIN.

11.3 Manholes The nominal size of manholes shall be as follows: • Equal to or greater than DN 600 (NPS 24), • If justified, this dimension may be reduced to DN 500 (NPS 20) with prior written approval by COMPANY. CONTRACTOR shall verify that the chosen dimension is compatible with the dimensions of all the components needing to be installed or removed from the inside of the equipment. In particular, equipment requiring inspection and major maintenance work, such as catalytic cracker regenerators and reactors, shall at least have one manhole with a diameter large enough to allow the passage of large internals. All the manholes of same equipment shall be of the same diameter. For any vertical equipment (excluding hydro-treating plant reactors) or horizontal equipment, having a height or length greater than 6 metres, at least two manholes shall be provided. For shorter equipment, at least one manhole (or an inspection hole - see below when the equipment dimensions do not allow internal access) and one DN 150 (NPS 6) vent nozzle which shall be located at the end opposite to the manhole (or to the inspection hole) such as to provide effective ventilation during inspections. As a variant, the equipment may include a removable head (blind flange or formed head connected by flanges to the equipment shell) replacing the above mentioned manhole or inspection hole. When the equipment is in a horizontal position, at least one of the two nozzles (manhole or vent) shall be provided on the top of the equipment. When vertical, the vent nozzle shall be provided on the top head (whether or not there is piping connected to this head). For light gases, CONTRACTOR shall ensure the vent is located at the highest point of the equipment. For buried horizontal pressure drums, a minimum of two manholes shall be provided even if the equipment length is less than 6 metres. As a general rule for distillation towers, at least one manhole shall be provided every 6 meters, with one manhole necessarily located at the inlet feed nozzle level, one at the top of the tower and one at the limit of the internally lined areas. In very clean service, or in cases of frequent inspection (more than once a year), the number of manholes shall be respectively reduced or increased in agreement with COMPANY. One manhole shall also be provided: • on each side of a structured packing • at the level of each feed inlet nozzle • below the bottom tray • above the top tray. Inspection holes (also called hand holes): when the dimensions of the equipment do not allow for internal access, manholes shall be replaced by inspection holes. The number and location shall be submitted to COMPANY for approval. Their minimum nominal diameter shall be DN 150 (NPS 6).

Additional information concerning manhole and hand holes requirements are given in the GS RC PVE 001.

11.4 Instrument nozzles The instrument nozzles are addressed in the GS RC INS 200. The connections used for control and for safety functions shall be separate. Vessels connections shall be minimized by installing PRVs, temperature measurements, and pressure measurements on piping where possible instead of vessels (for cost saving). Instrument connections in bottom of vessels are not allowed (to avoid deposits and plugging concerns).

Instrumentation stand pipes (fluid column external to equipment enabling the installation of several instruments) are not allowed. 11.4.1

Pressure

A local pressure gauge shall be located preferably on the vessel overhead line. In any case, the pressure gauge shall be located in a dry area and be free draining into the vessel or overhead line. 11.4.2

Temperature

For distillation columns, thermowells shall usually be located at: • feed trays, • side stream draw-off trays (or return line from draw-off), • sensible tray (used for reboiler control) and shall be installed in the vapour phase 200 mm (8") below upper tray for conventional tray spacing (600 mm). 11.4.3

Level

In general, a vessel will have as a minimum one level transmitter for indication and control via the DCS and one local level gauge. A second level transmitter connected to the DCS may be installed in specific cases to meet availability requirements (e.g. for fouling service or critical control loops). Each level transmitters and each level gauge will have its own nozzles. All the bottom level transmitters’ nozzles (respectively all top level transmitters’ nozzles) shall be located in the same horizontal plane (for calibration purpose and for discrepancy or deviation alarms).

Level transmitters or level measurement glasses shall be equipped with isolation valves. The number of nozzles for each level instrument depends on the type of level measurement. The use of sight glass levels shall be justified case by case for dangerous products (risk of major leak) and is forbidden for LPG services. Level connections shall be located far enough away from the liquid feed to the vessel to avoid disturbance of measurement. 11.4.4

Pressure relief valves

For PRVs location apply the rules from GS RC ECP 101. For vessels equipped with mist eliminator refer to § 10.3.2.

11.5 Other nozzles 11.5.1

Pyrophoric services

Pyrophoric service shall be considered as a minimum when: • Iron sulphides could form during normal operation and could be trapped or, • Catalyst in contact with air can lead to violent heat release or, • Special services defined by licensors. For equipment with pyrophoric processes, one or several injection points shall be provided in the upper section of the vessel (above the internals that may burn in contact with air). These additional nozzles will serve for injection of water (for washing) or a neutralizing agent (e.g. CO 2 and isopropanol (IPA)/N 2 ) to prevent fire outbreak during a shutdown . The injection point shall be accessible from a platform. 11.5.2

Polythionic acid attack

During a shutdown, in the presence of air and liquid water (at dew point), the sulphides (e.g. H 2 S that has formed a thin iron sulphide film) convert to polythionic acid. The polythionic acid then corrodes the chromium-depleted grain boundaries of the sensitized alloy (e.g. stainless steel). The risk of polythionic acid attack shall be evaluated by material specialist. If the risk of polythionic acid attack exists, facilities must be provided to allow neutralisation before oxygen exposure.

12. Columns and internals 12.1 Column sizing Column height will be based on: • Number of trays and trays spacing or height of packing, • Number of manholes • Hold up time in the bottom of the column (refer to § 10.2.2)

12.2 Tray versus packing selection Conventional trays are preferred. If conventional trays cannot achieve the required performance, high capacity or high performance trays should be used. General criteria for tray versus packing selection are given in the table here below: TRAY applications Generally preferred application. High purity separation (e.g. polymer grade ethylene) Separation with corrosive, erosive or fouling product (e.g. coking, salt deposits) High operating pressure (> 10 barg)

PACKING applications Low pressure drop (e.g. vacuum distillation unit) Small diameter columns (< 910 mm) Debottlenecking

The internals choice should be based on experience on similar applications.

12.3 Trayed columns sizing 12.3.1

General

In the preliminary design for new units, start with standard trays (i.e fixed valves). Economics or debottlenecking reasons may justify using high performance internals (high efficiency trays, low pressure loss, etc.). Sieve trays may be used in fouling service and in services with high gas load where low pressure drop and limited turndown is required (e.g. pumparound sections). The tray’s Manufacturer shall provide performance guarantees for its design. The trays will be counted from top to bottom of the column unless otherwise specified by project requirement. 12.3.2

Design criteria

• Maximum flooding: to be guaranteed by tray’s Manufacturer. • Foaming factor: Depending on the foaming nature of the system, a foaming factor has to be specified. For non-foaming systems this factor is 1.0. For foaming systems a lower factor will be used (refer to below table, unless Operations’ or Manufacturer’s feedback indicates otherwise). If, for instance, a system factor of 0.8 is used, the tray will be designed for a maximum flooding factor of 82 x 0.8 = 65%. System

Foaming Factor

Oil Absorber (below 0°F)

0.8-0.95

Oil Absorber (above 0°F)

0.85

Amine Absorber

0.73-0.8

Amine Regenerator

0.85

Glycol Absorber

0.5-0.75

Glycol Regenerator

0.65-0.85

CO 2 Absorber

0.85

CO 2 Regenerator

0.8

Hot Carbonate Absorber

0.85

System

Foaming Factor

Hot Carbonate Regenerator

0.9

Dethanizer

0.85-1.0

Demethanizer

0.8-1.0

Depropanizer

0.9

H 2 S Stripper

0.85-0.9

Vacuum Tower

0.85-1.0

Crude Tower

0.85-1.0

Caustic Wash

0.65

Caustic Regenerator

0.3-0.6

Sour Water Stripper

0.5-0.7

Alcohol Synthesis Absorber

0.35

Fluorine System (BF3, Freon)

0.9

MEK Units

0.6

Sulfolane System

0.85-1.0

Furfural Refining Tower

0.8-0.85

Reference: FRI Design Handbook Chapter 5.1 Table II

• The "clear liquid equivalent height" in the downcomer to be assessed by tray’s manufacturer. • Minimum distance between trays Column diameter

Sieve tray or valve tray

< 1.9 m

450 mm

≥ 1.9 m

600 mm

Tray spacing has to be adapted in areas with a manhole (refer to § 11.3) or a feed or product nozzle. Further study from trays manufacturer may allow optimizing tray spacing. • Tray loading margin (flexibility): Unless otherwise specified in the process design basis a turn-down of 50% is required. For design margin on flow and duty refer to § 6. 12.3.3

General recommendation for sizing high fractionation columns

In order to minimize the diameter, or height of the column or to maintain the fractionation in one column only (e.g. height ≤ 100 m), and avoiding multiple columns in series, following deviations can be submitted to COMPANY written approval: • Use 450 mm tray spacing when using conventional valve trays; • Relax number of manholes. • Use, for instance, of non conventional tray (e.g. high capacity and high efficiency trays, MD™ or ECMD™ trays).

12.4 Packed columns sizing Packed columns shall be calculated, designed and supplied by specialist suppliers, in coherence with the hydraulic specifications of the packing itself. The packed columns shall be equipped with: • feed and reflux distributors, • packing support plate or grid, • hold-down or floating bed limiters (if necessary), • and liquid and gas redistributors, Maximum flooding • For packing, flooding shall be estimated in cooperation with the suppliers. Indicative values for design of packing: • 80% for fractionating zones • 85-95% for pump-around zones Packing support: • Bottom support grid must be horizontally installed. Support ring for this grid is preferred compared to support by the liquid collector. Packing bed limiter is required. Distributor design: • Ensure correct vapour/liquid distribution for the full range of specified flow rates taking into consideration the fouling tendency of the product. • Liquid velocity at the outlet of the feed collector shall be less than 0.8 m/s for a gravity distributor. • Filtration is required when spray distributors are used. The filter mesh size shall be 25% of the orifice diameter of the distributor.

12.5 Revamping or Debottlenecking The performances of column internals shall be guaranteed by the Vendor.

13. Heat exchangers 13.1 General This section covers the basic design considerations which shall be used when selecting, sizing and specifying: • Shell and tubes heat exchangers, • Double pipe heat exchangers, • Plate & Frame heat exchangers, • Electrical heat exchangers. Unless otherwise specified, in writing, by COMPANY, the exchangers shall respect the requirements of class "R" of the TEMA Standards.

CONTRACTOR will bring to COMPANY attention the possibility to reduce the number of shells if some of the below mentioned limits are slightly exceeded. CONTRACTOR shall examine the possibilities of tube bundle standardisation by specifying identical bundles for several exchangers where economically justifiable and by limiting the diversity of the tube lengths in order to minimize the number of spare bundles. Additional requirements concerning heat exchangers that are not addressed in the present specification are included in the following specifications: • GS RC PVE 002 • GS RC ECP 101 For heat exchanger control philosophy, refer to § 21.2.

13.2 Thermal Design for shell & tubes exchangers 13.2.1

LMTD

A LMTD correction factor (F), depending on the fluid temperatures, the number of shells in series and the geometry of the heat exchanger, is introduced in order to measure the deviation from ideal conditions (see TEMA §7.2 as a first approximation). LMTDeff = 𝐹 ∗ 𝐿𝑀𝑇𝐷

LMTD correction factor F shall be higher or equal to 0.8 (recommended higher than 0.85). For design of kettle and recirculating thermosyphon reboilers, attention shall be paid to equilibrium of static pressure and the film boiling phenomena. Calculation note shall be provided to COMPANY. 13.2.2

Fouling Resistance

Fouling resistances shall be in line with the COMPANY’s operating experience in similar service and as per process Licensor's recommendations or specifications, where applicable. In the absence of such information, the fouling resistance shall be selected from the values recommended by TEMA Section 10 with the following exceptions: Fouling resistance m².°C/W

h.m².°C/kcal

ft².hr.°F/Btu

Sea water

0.00035

0.0004

0.0020

Semi-open cooling water circuit (treated make-up)

0.00034

0.0004

0.0020

Closed cooling water circuit

0.00026

0.0003

0.0015

Steam

0.00017

0.0002

0.0010

Condensates

0.00017

0.0002

0.0010

Demineralised water

0.00017

0.0002

0.0010

Hot oil (* depends on composition)

0.00026

0.0003

0.0015

Oil-charged water

0.00030

0.00035

0.0017

LPG/ Ethylene / Propylene

0.00017

0.0002

0.0010

Natural Gas (network)

0.00013

0.00015

0.0007

Benzene

0.00017

0.0002

0.0010

Styrene

0.00034

0.0004

0.0020

For the purpose of this specification the fouling services are defined as follow: • Clean service :

≤ 0.000176 m².°C/W (0.001 ft².hr.°F/Btu)

• Moderately fouling service : ≤ 0.00035 m².°C/W (0.002 ft².hr.°F/Btu) • Fouling service :

≤ 0.00053 m².°C/W (0.0030 ft².hr.°F/Btu)

• Highly fouling service :

> 0.00053 m².°C/W (0.0030 ft².hr.°F/Btu)

The heat exchanger shall be calculated for maximum fouled conditions and checked for clean conditions. Special care will be taken concerning thermal stability (film boiling, polymerisation etc.). For preheat train design, criteria for pressure drop, velocities and fouling factors shall be agreed with COMPANY. Installation of spare exchangers for highly fouling services shall be considered against the frequence of cleaning, and unit availability criteria. Additional solutions for cleaning in service might be required. For cooling water service: maximum skin temperature and return temperature are function of the water quality, to be agreed with COMPANY. Typically return temperature is 40°C. 13.2.3

Shell and Tube fluid side selection

Tube-side shall generally be selected for the fluid with the highest ranking of the following: 1. Toxic fluid, 2. Corrosive fluid (high cost metallurgy) 3. Steam with condensate, 4. Cooling water, 5. Fouling or erosive fluid, 6. The least viscous fluid, 7. The highest pressure fluid, 8. The hottest fluid, 9. The lowest flow rate. Condensing fluids will enter at the top of the exchanger (downwards circulation) and vaporizing fluid will enter at the bottom of the exchanger (upwards circulation). Cooling water should also preferably circulate upwards. 13.2.4

TEMA type selection

Generally, exchangers rear end head should either be a "floating" type (TEMA type "S" or "T") or "U" tube type and the front end head type should be channel and removable cover (type "A"). For relevant information either on TEMA types submitted to COMPANY approval, or not allowed refer to GS RC PVE 002.

Front head: • Type "A" (removable channel and cover) is the preferred channel cover. • Type "B" (bonnet – integral cover) covers may be used when tube-side fluid is clean or moderately fouling (≤0.00035 m2.°C/W), or toxic, or for tube side DESIGN PRESSURE higher or equal to 50 barg and frequent access to the tubesheet is not anticipated. • Type "C" (integral with tube-sheet and removable cover) is preferred for high pressure applications (tube side DESIGN PRESSURE higher or equal to 100 barg), • Type "D" (special high-pressure closures) to be used for tube side DESIGN PRESSURE higher or equal to 100 barg, if constraints in terms of weight, or maintenance do not allow installation of type C. Manufacturing is more complex, the choice of closures to be discussed with COMPANY PVHE specialist. • Type "N" (Channel integral with tube-sheet and removable cover) shall not be used. Shell: • Type "E" is the preferred type. • Type "E" (one-pass shell), "G" (split flow), "H" (double split flow), shall be used for horizontal thermosiphons heat exchangers. • Type "J" (divided flow), "X" (cross flow), "H" (double split flow) shall be used for condensers with a very low allowable pressure drop (see table below) • Type "K" for kettle type reboiler. • Type "F" (two-pass shell with longitudinal baffle) is not allowed by COMPANY. In preliminary phase, the following indicative values may be used for shell type selection: Pressure drop

Shell

0.34 to 1.4 bar

E - single baffle

0.14 to 0.34 bar

E - double baffle

0.03 to 0.14 bar

J – single baffle

0.01 to 0.07 bar

J – double baffle E – single baffle NTIW (No Tube In Window)

<0.03 bar

X

Rear Head: Floating head type is required when both the shell and the tube sides are considered fouling, and require mechanical cleaning. Designs with shell expansion joint are not allowed except for conditions given in GS RC PVE 002. • Type "T" (pull through floating head) is used when shell DESIGN PRESSURE is higher or equal to 50 barg and for exchangers of the "Kettle" type. • Type "S" (floating head with backing device) is used when shell DESIGN PRESSURE is lower than 50 barg. • Type "U" (U-tube bundle) shall only be specified for use in clean tube-side services, or when tube-side can be chemically cleaned or when specified by the process licensor. For moderately fouling fluid (0.000176 to 0.00035 m2.°C/W), "U" tube may be used under COMPANY written approval.

• Type "P" (outside packed floating head) and "W" (externally sealed floating tube-sheet) shall not be used. • Type "L" (fixed tube-sheet like "A" stationary head), "M" (fixed tube-sheet like "B" stationary head), "N" (fixed tube-sheet like "C" stationary head): Fixed tube-sheet type shall only be specified for shell side clean and non-fouling services or when specified by the Licensor. Fixed tube-sheet specified by the licensor in fouling service required COMPANY written approval. However, fixed tube-sheet type is not acceptable in shellside wet sour services. Note: Fixed tube-sheet type can also be specified when shell side fluid is fouling ≥( 0.00035 m².°C/W) and fouling can be removed by Chemical Cleaning, under COMPANY written approval. For fixed tube-sheet exchangers, the mean shell and tube wall temperatures which give the maximum temperature differential shall be specified. The conditions of normal operating, start-up, shut-down, process upset, emergency, and steam-out shall be investigated to determine the maximum differential. The following guideline may be used: a?

No b?

Yes

Yes

d?

No c?

Yes No

e?

Yes U

No

T

No

e? Yes

Yes S

U

No

S

M/U

L

(a) Clean fluid on the tube side (≤ 0.000176 m².°C/W)? (b) Moderately fouling fluid on the shell side (≤ 0.00035 m².°C/W) or possible to perform a chemical cleaning ? (c) Pressure on the tube side > 50 barg or kettle (d) Toxic, flammable or dangerous (high P or T, acid, basic, corrosive, etc.) fluid on the shell side (e) Moderately fouling fluid on the tube side (≤ 0.00035 m².°C/W) and possible to perform a chemical cleaning ?

13.2.5

Maximum tube bundle size

The maximum size and weight of removable bundles is limited, refer to GS RC PVE 002. CONTRACTOR shall inform COMPANY where larger exchangers would be economically justified (without compromising tube bundle lifting for maintenance). The maximum number of stacked heat exchangers is given in the GS RC PVE 002 and GS RC ENG 401.

13.2.6

Standard tube diameter and thickness

The external diameter of the tubes and their minimum wall thickness shall be in accordance with the table in GS RC PVE 002. For highly fouling fluid (> 0.00053 m².°C/W) on the tube side, the tube diameter shall be 1" (25.4 mm). 13.2.7

Number of tube passes

It is recommended not to exceed 8 tubes-side passes per heat exchanger. Higher number of tube passes should be justified and brought to COMPANY attention. 13.2.8

Baffle orientation

The orientation of the baffle cut shall be: • Horizontal (perpendicular to nozzle axis) for single phase shell-side services. • Vertical (parallel to nozzle axis) generally for shell-side condensing and vaporizing services and for fluids containing suspended solids (risk of gas accumulation or deposition of solid sediments). Recommended baffle opening: 25 to 30% in height. 13.2.9

Minimum approach

One definition for thermal approach is the temperature difference between the cold fluid and the hot fluid at the exchanger outlet (HOCO). In shell and tubes exchangers this thermal approach will be minimized (typically for feed/effluent service). Thermal specialist shall optimize the exchanger design taking into account the impact in heat transfer area. To be agreed with COMPANY based on energy efficiency and economics criteria. 13.2.10 General thermal design considerations For overdesign margin on flow and duty refer to § 6. The floating head space, has a very low thermal efficiency and shall be excluded from the effective heat transfer area. Under certain conditions, the U-bend area may be integrated to the effective area, as per GS RC PVE 002. The design will be submitted to COMPANY approval. Kettle reboilers liquid droplets carry over design criteria: • Liquid carry over in the vapour outlet to be ≤ 0.5 wt % • Minimum height to be provided above the high high liquid level: 450 mm For thermosiphon heat-exchangers, the vaporisation rate shall be: • 15% to 30% for hydrocarbons • 2% to 10% for water

13.3 Mechanical and hydraulic design for shell & tubes exchangers The design pressure drop will be specified at DESIGN FLOW (refer to § 6).

Enough pressure drop has to be provided for exchangers installed in parallel/networks to allow equilibrium of operating pressures. As a preliminary figure, 0.7 bar can be considered for the design pressure drop on the cooling side of an exchanger (example cooling water network). 13.3.1

Velocity in tubes

Exchangers with sea or untreated water on the tube side as cooling medium shall have a minimum water velocity of 1.2 m/s to avoid suspended matters settlement. At the beginning of the Pre-Project, the minimum and maximum velocity shall be defined based on the actual water quality and the selected tube material. Refer to criteria on GS RC PVE 002. For other fluids, the minimum velocity at all points shall not be lower than 0.8 m/s (revamp) recommended 1 m/s minimum. 13.3.2

Tube pitch

GS RC PVE 002 defines COMPANY requirements for tube pitch. The CONTRACTOR shall choose the type of pitch fitted for service and considering the heat transfer coefficient, vibration, pressure drop, cost etc. 13.3.3

Nozzles

The following three criteria shall be used for the sizing of the inlet nozzles: • Inlet nozzle pressure drop to be less than 15% of the total allocated pressure drop • The ρv² at the shell inlet nozzle shall not exceed 6000 kg/m.s². For revamp, values of ρv² up to 9000 kg/m.s² are acceptable. For higher values submit a Deviation Request to COMPANY (include heat exchanger inspection reports, erosion and corrosion aspects). • Inlet nozzle diameter shall be less than 50% of shell diameter or 20" (whichever is lower). For vent and drain nozzles refer to the GS RC PVE 002. 13.3.4

Impingement protection

Impingement protection shall be installed to minimize tube bundle components erosion in the inlet/outlet areas of shells (see TEMA RCB-4.6). Dummy rods are recommended in the following cases: • Large diameter shells • ρv² at bundle inlet > 5 200 kg/m.s2, for liquids; • ρv² at bundle inlet > 3 200 kg/m.s2, for gases If impingement plate is installed, a vibration study shall be performed to check that the restricted area due to the impingement plate does not create either higher flow velocities promoting erosion, or tube damage due to vibrations. Requirements for vibration analysis are defined in GS RC PVE 002. Perforated impingement plates are not allowed.

13.4 Use of special types exchangers The use of special types exchangers (not limited to the below list) in a particular service should be supported by at least two units operating in the same service for a minimum of one year of proven industrial experience. The use of these exchangers shall be submitted to COMPANY written approval.

13.4.1

Enhanced heat transfer

Several technologies are available to improve energy efficiency in exchangers. Save operating cost, and increase cycle runlength. 13.4.1.1 TOTAL Inserts In-house development of turbulence promoters inserts for tubes, increasing heat transfer coefficient while minimizing fouling, contact Distillation and Heat Transfer (DTC) group for further details. Examples: INVERTED TURBOTAL, FIXOTAL, TURBOTAL, among others. 13.4.1.2 UOP high flux tubes™ technology UOP high flux tubes™ technology offers significant reduction of the number of shells to be installed and plot space. High flux tubes technology is restricted to fouling factors < 0.00026 m2.°C /W. 13.4.2

Low fin tubes

Low fin tubes can be looked at when a significant advantage to use this technology is shown for condensing or vaporizing services. Low fin tubes may be used for clean service on the shell-side and low surface tension fluids where their use is economically justified. 13.4.3

Hair pin type heat exchangers

Hairpin exchangers offer real counter-current or co-current flow, suitable for very close temperature approaches or large temperatures ranges. The design shall be determined by the Exchanger Manufacturer For hair pin type heat-exchanger the inner tube outside diameter shall be≥ 3/4" (19.05 mm). Preferred tube diameters are 3/4" (19.05 mm) and 1" (25.4 mm). The minimum tube wall thickness shall be specified in accordance with the following table:

13.4.4

External diameter

Carbon Steel and Low Alloy, Aluminium and aluminium alloy

High Alloy, copper and copper alloys, other alloys

3/4"(19.05 mm)

BWG 14 (2.11 mm)

BWG 16 (1.65 mm)

1" (25.4 mm)

BWG 12 (2.77 mm)

BWG 14 (2.11 mm)

Plate & Frame heat exchangers

Plate and frame heat exchangers are recommended for applications requiring a very low pressure drop. Main advantages are their size, plot space saving and reduced weight. The price is competitive compared to a S&T in alloy material. Restriction to the use of plate & frame heat exchangers These heat exchangers should not be used for hydrogen, wet sour, toxic, cyclic, condensing, boiling or very fouling process operation. Exception: welded plate heat exchangers in cold boxes. Gasketed exchangers are prone to leak, and shall be limited for services in which the MAXIMUM OPERATING PRESSURE is less than 20 barg, and the MAXIMUM OPERATING TEMPERATURE is less than 150°C. Thermal Design

For plate and frame heat exchangers, the fouling factor defined for shell and tube heat exchanger cannot be applied. Consequently an extra surface shall be added; plate and frame exchangers shall be designed with extra thermal capacities specified as follows: • A minimum of 15% excess thermal capacity at MAXIMUM OPERATING FLOW shall be provided for clean services such as cooling of process water, light oils and light process streams, utilizing tempered water as the cooling medium. • A minimum of 20% excess thermal capacity at MAXIMUM OPERATING FLOW shall be provided for fouling services such as cooling of crude oil, emulsion and heavy process streams, utilizing seawater or other process fluids as cooling medium. Frame size for plate heat exchanger should be selected such as to allow for a 25% capacity expansion (plate addition). The excess thermal capacity shall not exceed 25% of heat transfer surface area on clean duty at MAXIMUM OPERATING FLOW. For fouling fluid operation (e.g. presence of dirt, sludge, polymer etc.) with potential for blocking flow passages between plates, the following facilities shall be considered: • Filters upstream of the exchanger, • Cleaning facility, • Backwash facilities (e.g. on sea water), • Spare equipment. 13.4.5

Electrical heat exchangers

Electrical heat exchangers shall only be used in the following services and design conditions: • Hydrocarbon, hydrogen and utility services for DESIGN TEMPERATURE ≤ 700°C. • Clean, non-erosive services. Electrical heat exchangers can be considered for cyclic service (e.g. driers regeneration with hot nitrogen).

13.5 Exchanger integration in process scheme 13.5.1

Operating pressure

When a process heat exchanger is designed, wherever possible, the operating pressures shall be fixed such as the contamination of the LP side in case of a tube leak will be acceptable to the process. When a process or utility heat exchanger is designed, wherever possible and unless it is detrimental to the process in case of tube leakage, the utility side operating pressure shall be higher than the process side operating pressure to avoid contamination of the utility side in case of tube leaking. For the design of exchanger on lubricating oil for critical equipment, the cooling water operating pressure shall be lower than the oil operating pressure. 13.5.2

Isolation

For exchangers with circulating cooling water (or other circulating cooling media), the block valve at the outlet of the cooling water side should be a throttling valve (usually globe valve) and the block valve at the inlet of the cooling water side should be a gate valve. A flow bypass shall

be provided on the cooling water side when freeze protection is needed (when the exchanger is taken out of service). If an exchanger needs to be isolated during normal operation, it shall be equipped with: • Isolations valves with positive isolation (refer to § 22.1), • A bypass line equipped with a gate valve (if no control function is required). • Drain connections on the shell and tube sides. • A flushing system for high pour point service (≥ 20 cSt at 50°C) or for cleaning purpose. Requirement for chemical cleaning is usually determined during detailed engineering. For exchangers with fixed tubesheets, one shall include in the shell a minimum of two 8" inspection peepholes positioned in such a way as to allow for the evacuation of dirt and corrosion debris. If they are carefully positioned, such peepholes can be used for chemical injection. For heat-exchanger having a fouling factor higher than 0.001m².°C/W a heat-exchanger bypass shall be considered. When there is a possibility to isolate an exchanger, particular attention shall be paid to the risk of overpressure scenario. Refer to the GS RC ECP 101 for the "overpressure protection".

14. Air cooled heat exchangers 14.1 General Design of the air cooled heat exchangers are provided by a Manufacturer. Then it shall be ensured the Manufacturer’s proposed design, which includes bundle arrangement, tube pitch, number of rows, fin spacing/height, tube size, and number of passes are suitable for the intended service, for current operation, start-up, shut-down and upset operation. Additional requirements concerning air cooled heat exchangers that are not addressed in the present specification are included in the GS RC PVE 003. For air-cooled heat exchanger control philosophy refer to § 21.3. For design margins on flow and duty of air-cooled heat exchanger refer to § 6.

14.2 Type of air-cooled heat exchangers There are two types of air cooled heat exchangers: • Induced draft: fans are positioned above the tube bundles; • Forced draft: fans are positioned below the tube bundles. Principles for air-coolers specification are stated in GS RC PVE 003. The induced type offers better air distribution and natural convection; it is recommended in particular for cases with low temperature approach. The "forced draft" type has advantages in terms of maintenance. Forced draft should be considered in the following situations: • When winterisation is required since it is easily adaptable for warm air recirculation. • For inlet process fluids above 180°C. Otherwise, fan failure could subject the fan blades and bearings to excessive temperature. • For air outlet temperatures higher than 100°C to protect the mechanical system (fan blades, bearings, V-belts etc.).

For temperature control, if variable speed driving system is foresee the Electrical specialist has to be involved.

14.3 Thermal design 14.3.1

Air versus cooling water break point

The minimum approach temperature is the temperature difference between the cold air (max air dry bulb temperature) and the hot fluid at the outlet of the air cooled heat exchanger. The minimum approach temperature shall not be lower than 10°C and if possible should be higher or equal to 15°C. This will be used to define the optimum breakpoint temperature between air-cooling and water cooling based on economical criterion. Derogation for a lower approach with the air temperature can be accepted where the installation of a water trim cooler is to be avoided (for instance, in high pressure hydro-treatment unit). . A single water cooled heat exchanger might be used when the following conditions are met: • Temperature of the process stream downstream of the air cooler and trim cooler system is ≤ 65°C, and • Inlet temperature of the air cooler is not exceeding break point temperature by +15°C and duty of the air cooler is less than 10% of the overall required cooling duty, • And in any case if the air cooler duty is ≤ 1.0 MMkcal/h. Additional criteria could be mentioned to justify the choice of air coolers: reduce flare load in case of power failure. If the inlet temperature to the air-cooled heat exchanger is higher than 200°C alternate solutions with improved heat integration must be evaluated. 14.3.2

Design air temperature

Design air temperature shall exclude the hottest period of the year (15 days) otherwise it will lead to a large non justified overdesign. The air intake design temperature shall be based on the summer dry bulb temperature increased by 2°C in order to take into account any recirculation. Such data are available from the meteorological office (temperature variation chart at sufficient short intervals throughout the year). For critical systems (e.g. condensation of distillation columns overhead) a higher design margin may be considered. 14.3.3

Fouling factors

Fouling resistances inside the tubes shall be in line with the operation experience in similar service and as per process licensor’s recommendations or specifications, where applicable. In the absence of such information, the fouling resistance used for the inside of the tubes shall be selected from the values recommended in § 13. Air side fouling resistance is: 0.00035 m².K/W (0.002 ft².h.°F/Btu) based on the outside bare tube area. 14.3.4

Cooling of viscous products and freezing products

Direct air cooled heat exchangers are not recommended for the cooling of viscous products (> 50 cP) at low temperature. This should be done by means of a closed tempered water loop.

For cooling other products with dynamic viscosity greater than 50 cP at the outlet temperature, the CONTRACTOR shall submit the case where it envisages using an air-cooled heat exchanger to COMPANY for written approval. The CONTRACTOR shall submit, for approval by COMPANY, the system chosen to protect the equipment against congealment or frost (e.g. reheating device), in application of Appendix C of the ISO 13706 standard. Due consideration shall be given to transient phases (e.g. stagnant product, turn-down etc.).

14.4 Mechanical design For velocity and pressure drop criteria refer to the GS RC PVE 003. 14.4.1

Hydraulic considerations

For critical systems where a good flow distribution shall be achieved between all the bundles (e.g. water wash injection in reactor effluent aircooler), the piping arrangement shall be as per the below scheme and the number of bundle has to be 2n. In case equal distribution flow is required, this shall be clearly indicated on the P&ID. n Example of 2 configuration with n=3

In other cases, it should be ensured that equal distribution is obtained via symmetrical piping arrangement, i.e. not more than 5% difference in flow through-out the different bundles. As a preliminary figure, the following tube side pressure drop may be considered: • Between 0.05 and 0.5 bar for gas • Between 0.4 and 0.7 bar for liquids 14.4.2

Tubes and Fins

Refer to GS RC PVE 003 for design and fabrication rules. • Recommended external bare tube diameter is 1" (25.4 mm), except for fouling services 1.5”(38.1 mm). • The use of a high density fins design, which is a density beyond 10 fins per inch (394 fins per meter), is not allowed in heavy external fouling site conditions (risk of dust deposits). • 1% slope in last pass of tube bundle is to be considered for all condensing services, and for all liquid services whatever the viscosity of the liquid is.

15. Fired heaters Here after are given process engineering design requirements for fired-heaters. Additional requirements concerning fired heaters that are not addressed in the present specification are included in the following specifications: • GS RC THE 001 • GS RC THE 002 • GS RC THE 003 • GS RC THE 004 / GS RC THE 005 / GS RC THE 006 / GS RC THE 007 The following subjects are specifically addressed in the GS RC THE 001: • the minimum in tube mass velocity and fluid velocity, • pressure drop in tube, • maximum allowable radiant heat flux rates, • air pre-heaters, • decoking facilities. The following subject is specifically addressed in the GS RC THE 003: • pilot gas facilities

15.1 Fuel efficiency and flue gas temperature Minimum fuel efficiency shall be 90% unless unpractical or uneconomical according to the project energy efficiency investment criteria (e.g. it might not be economically justified for some small heaters). The process streams will be pre-heated in the convection to the maximum extent. When forced draft with air-preheater is used, fuel efficiency shall be at least 92% (expected value with fuel gas). For steam generation, the use of economizer for BFW preheating in the convection section must be considered for heaters without air preheater. Recommended values for flue gas temperature are given here below and should be confirmed based on the sulphur content of the combustible and approved by COMPANY: • Without air-preheater: Flue gas temperature shall be not more than 30 to 50°C higher than the coldest process fluid inlet to the fired heater. • With air-preheater (3% O 2 in flue gas outlet) with fuel gas: Flue gas temperature 150°C to 160°C, depending on the SO 2 content in the flue gas (acid dew point temperature). • With air-preheater (3% O 2 in flue gas outlet) with fuel oil: Flue gas temperature 180°C.

15.2 Fuel gas supply The required fuel pressure at the burner is given in the GS RC THE 003.

As preliminary value, 3.3 barg (with a minimum of 3.0 barg) should be considered at the outlet of the fuel gas KO drum (corresponding to a pressure drop of 1 bar for the burner filter, the control valve, the flow meter and piping).

16. Pumps 16.1 Centrifugal pumps Additional requirements concerning centrifugal pumps that are not addressed in the present specification are included in the following specifications: • GS RC MEC 610 • GS RC MEC 682 • GS RC MEC 685 • GS RC MEC 688 • GS RC MEC 698 16.1.1

Pump sizing

The pump type shall be selected in accordance with the criteria given in the GS RC MEC 698. The pump sealing system shall be selected in accordance with the criteria given in the GS RC MEC 682 appendix 1. CONTRACTOR shall specify the barrier fluid compatible with the process. Net Positive Suction Head (NPSH) The Net Positive Suction Head Available (NPSHA) is defined as follows: NPSHA = + Pressure of gas phase in the suction drum minus liquid vapour pressure (m) + Fluid static head (difference between liquid level in the suction drum and either the centre line for a horizontal pump or the suction impeller for a vertical centrifugal pump.) (m) – Pressure losses in the lines. For reciprocating pumps, the pressure loss due to system acceleration and pulsations shall also be taken into account. (m) – Partial pressure of dissolved gases if necessary (e.g.: stirred tank). (m) For preliminary calculation, 1 m could be considered for the position from the ground of the centre line of the pump. The DESIGN FLOW shall be specified for the minimum NPSHA (i.e. minimum operating pressure of the suction drum, lowest liquid level - LSLL, lowest liquid density, vapour pressure at maximum pumping temperature). The margins between NPSHA and NPSHR are specified in the GS RC MEC 610, GS RC MEC 685 and GS RC MEC 688. It is recommended to define NPSHA higher than 3.5 m in order to avoid special type pumps installation. For the value of NPSH specified on PROCESS DATA SHEET, the referenced elevation shall be indicated (e.g. grade, pump centre line, etc.).

Pump differential head Pump differential head indicated in the PROCESS DATA SHEET shall be calculated at DESIGN FLOW. In case of several operation modes (e.g. different fluid density, fluid viscosity or differential head) each case will be specified in the PROCESS DATA SHEET. Particular cases of operation such as pumps in auto start service (remote control, sequence activation, etc.), pumps without control valve at discharge, pumps under level control, pumps in parallel operation that can start without back pressure (end of curve operation), will be specified on the pump PROCESS DATA SHEET. For head calculation of pumps operated in parallel, barrel, double casing and submerged pumps refer to the GS RC MEC 610, GS RC MEC 685, GS RC MEC 688. Power • The maximum absorbed power is defined as follows: 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝐴𝑏𝑠𝑜𝑟𝑏𝑒𝑑 𝑃𝑜𝑤𝑒𝑟 (𝑘𝑊) =

𝐷𝑒𝑠𝑖𝑔𝑛 𝑓𝑙𝑜𝑤 𝑟𝑎𝑡𝑒 (𝑚3/ℎ𝑟) 𝑥 𝑑𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑡𝑖𝑎𝑙 ℎ𝑒𝑎𝑑 (𝑏𝑎𝑟) 36

• The required shaft power is defined as follows: 𝑅𝑒𝑞𝑢𝑖𝑟𝑒𝑑 𝑆ℎ𝑎𝑓𝑡 𝑃𝑜𝑤𝑒𝑟(𝑘𝑊) =

𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝐴𝑏𝑠𝑜𝑟𝑏𝑒𝑑 𝑃𝑜𝑤𝑒𝑟 (𝑘𝑊) 𝑃𝑢𝑚𝑝 𝐸𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑐𝑦

The pump (hydraulic) efficiency depends on the type of pump. • The required electrical power is defined as follows: 𝑅𝑒𝑞𝑢𝑖𝑟𝑒𝑑 𝐸𝑙𝑒𝑐𝑡𝑟𝑖𝑐𝑎𝑙 𝑃𝑜𝑤𝑒𝑟(𝑘𝑊) =

Typical motor efficiency: 70 to 90%.

𝑅𝑒𝑞𝑢𝑖𝑟𝑒𝑑 𝑆ℎ𝑎𝑓𝑡 𝑝𝑜𝑤𝑒𝑟 (𝑘𝑊) 𝑀𝑜𝑡𝑜𝑟 𝐸𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑐𝑦

For products sensitive to thermal degradation, the mechanical power output dissipated by heat into the fluid pumped could be estimated as follows for preliminary calculation: Power dissipated as heat (kW) = Shaft power(kW) x (1 − Pump Ef�iciency)

Acceptability of the resulting product temperature should be assessed by CONTRACTOR. For magnetic drive or submerged rotor pumps, lower efficiencies shall be taken into consideration to calculate the increase in temperature at minimum flow. For sealless pumps (submerged rotor or magnetic drive), additional overheating occurs on the internally recycled fluid, which is used for cooling and lubrication. The properties of the pumped fluid (specific heat and saturated vapour pressure) are specified to the supplier who shall calculate the increase in temperature of the internally recycled fluid. In case of internal vaporisation, it shall be necessary to increase the NPSHA. 16.1.2

Pump Protection

16.1.2.1 Minimum flow protection Operation of a pump at a flow lower than the minimum flow specified by the manufacturer for a long period can cause pump damage due to heating and partial vaporization of the pumped liquid. CONTRACTOR along with COMPANY mechanical specialists will assess the need for minimum flow protection. This requirement will be further confirmed with pump vendors.

Use 40% of rated flow in pre-project phase or when manufacturer’s data not yet available. Minimum flow protection is not required for pumps in circuits such as pump-around pumps and reflux pumps. Minimum flow protection is required for Boiler feed water pumps and wash water pumps as per GS RC MEC 610, and for all the pumps in accordance with GS RC MEC 685 and GS RC MEC 783. For pump minimum flow protection, the following systems can be used: • Flow control valve in the minimum flow recycle line. • Restriction orifice in the minimum flow recycle line. In this case, the permanent recirculation flow rate shall be added to the net process flow rate to set the DESIGN FLOW of the pump. The diameter of the orifice shall be greater than 5 mm to avoid plugging. • Automatic recirculation valve (Schroeder, Schroedal or equivalent) with adjacent minimum flow recycle line. The automatic recirculation valve has two functions: check valve and minimum flow control through the opening of its side discharge. Therefore, a pump discharge check valve is not required in this case. This type of arrangement shall be installed at least on multistage between bearings pumps (type BB3, BB4 or BB5). If a pump minimum flow protection is provided, a check valve shall be installed in the pump discharge line downstream of the minimum flow tie in to avoid backflow. In principle, one common recycle line for main and spare pumps shall be provided. However, for high pressure pumps, a dedicated mini-flow protection for each pump might be preferred (for example for MHC, DHC and HP HDS high pressure feed pumps). As far as possible, the minimum flow bypass line should be connected from the pump discharge to the pump suction vessel and not to the suction line. For a liquid, which has a low specific heat, or a liquid close to its boiling point, the increase in temperature at minimum flow shall be calculated and evaluated if acceptable. A heat exchanger on the minimum flow line may be envisaged if there is undesirable overheating. 16.1.2.2 Low low level in suction drum - pump protection Low-low level detection in the pump’s suction vessel shall stop the pump for following applications: • If the pump handles TOXIC FLUID In particular, liquids containing dissolved H 2 S at a concentration higher than 1%wt. • If the pump handles CMR FLUID. • If the pump handles a hazardous fluid, defined as: − LPG − Fluids at operating temperature above their auto-ignition temperature; • If the pump has a required shaft power higher than 100 kW 16.1.3

On-Off valve requirement

Requirement of emergency block valve at pumps suction or discharge is addressed in the GS RC ECP 103.

When an on/off valve is installed on a pump suction line, the open limit switch of that valve shall be used to set a permissive to start the pump. In order to protect a pump from running dry in case of unexpected closure of the automated valve a safety sequence shall trip the pump. But a limit switch of a valve shall never initiate automatic safety trip actions (including the trip of the pump). A physical measurement must be used to trip the pump, such as a pressure transmitter on the suction line (PSLL) or a flow transmitter on the discharge line (FSLL). When a manual action is implemented to close the valve at the pump suction, the activation of closing the valve activates at the same time the trip of the pump. 16.1.4

Centrifugal pump typical

The below scheme gives the minimum requirements for centrifugal pumps integration in a process scheme:

(1) Pump suction valve shall be of the same diameter as the line and full bore. (2) Temporary strainer shall be used during the commissioning and initial operating period of new plants to prevent foreign objects from entering the pump. Temporary strainers will be equipped either with a local pressure differential indicator or with connections for portable pressure instrument. If a "long term strainer" is required beyond commissioning and initial operating period, it shall then be "T" or "Y" type with minimum ½ inch openings and at least 150% flow area. Long term strainers will be equipped with a high differential pressure alarm. (3) Eccentric top flat reducer shall be foreseen where the suction line and the pump inlet nozzle are not the same size (in order to meet NPSH requirement). Pump suction line shall not be smaller than pump suction nozzle. (4) Pump casing vent and drain requirements, according to GS RC MEC 610 (3/4" diameter minimum). The vent line shall be connected back to the suction vessel for LPG, or TOXIC FLUID, or hazardous service, or fluid under vacuum pressure at pump suction or for operational vent (e.g. liquids with dissolved gas). (5) Concentric reducer. (6) By-pass line for warm-up or cool-down shall be foreseen if the operating temperature is higher or equal to 230 °C or if the freezing or solidification of the liquid needs to be prevented (pour point of the product below or equal to the ambient temperature) or for flashing product at ambient temperature (pump start-up). Requirement for RO or globe valve to be evaluated by EPC Contractor. The check valve by-pass can be connected either upstream or downstream the block valve at pump discharge. (7) For drain collection systems refer to GS RC ENG 405.

16.1.5

Utilities

When specifying once-through systems, consideration shall be given to the scaling potential of the cooling water. Pump flushing is applied in heavy fouling fluid, high pour point fluid and, or TOXIC FLUID and is done in forward flow. Indicate the flushing medium supply and return facilities on the P&ID if applicable. The flushing medium depends on the service (e.g. kerosene, diesel or Light Cycle Oil from Fluid Catalytic Cracking Unit for high pour point hydrocarbon service). The destination needs to be determined for each type of flushing system (e.g. slops, closed drain system, etc.). If steaming out, purging with nitrogen and, or flushing with service water (via flexible hoses connecting to a utility station) of a blocked in pump is required, the local pressure indicators are disconnected and these connections are used for this purpose. This means that dedicated utility connections are not required for pumps.

16.2 Positive Displacement Pumps - Controlled Volume Additional requirements concerning positive displacement pumps that are not addressed in the present specification are included in the GS RC MEC 675 (Positive displacement pumps Controlled volume). 16.2.1

Design criteria

The required operating range from minimum flow to the DESIGN FLOW shall be specified in the PROCESS DATA SHEET. In case of several operation modes (e.g. different fluid density, fluid viscosity or differential head) each case will be specified. The margins between NPSHA and NPSHR are specified in the GS RC MEC 675. 16.2.2

Low low level in suction drum - pump protection

Refer to § 16.1.2.2. 16.2.3

On-Off valve requirement

Refer to § 16.1.3. 16.2.4

Reciprocating pump typical

The below scheme gives the minimum requirements for reciprocating pumps integration in a process scheme:

(1) Temporary strainer shall be used during the commissioning and initial operating period of new plants to prevent foreign objects from entering the pump. Temporary strainers will be equipped either with a local pressure differential indicator or with connections for portable pressure instrument. If a "long term strainer" is required beyond commissioning and initial operating period, it shall then be "T" or "Y" type with minimum ½ inch openings and at least 150% flow area. Long term strainers will be equipped with a high differential pressure alarm. (2) Eccentric top flat reducer shall be foreseen where the suction line and the pump inlet nozzle are not the same size (in order to meet NPSH requirement). Pump suction line shall not be smaller than pump suction nozzle. (3) Concentric reducer. (4) Safety valve piped back to pump suction line or suction drum (5) Pulsation dampener to be shown, if required as per pump supplier (6) For drain collection systems refer to GS RC ENG 405.

16.3 Mechanical drive By default all pumps should be electrical motor driven. However special attention should be paid to difficult or critical services where it is important to keep the fluid flowing. For such cases the following configurations should be considered: • One electrical motor driven pump and one turbine driven pump • Two electrical motors with one on a safe electrical supply. For purposes of energy-savings, a variable speed drive shall be considered, particularly in the following cases: • Power consumption > 50 kW • normal flow/design flow ratio (< 0.7) • high discharge pressure The investment/variable costs optimum shall be considered.

17. Compressors Additional requirements concerning compressors that are not addressed in the present specification are included in the following specifications: • GS RC MEC 614 • GS RC MEC 617 • GS RC MEC 618 • GS RC MEC 670 All possible operating conditions (including but not limited to variations of gas compositions, molecular weight, Cp/Cv, suction/discharge pressure, suction temperature, flow rate) shall be considered when sizing the compressor, without omitting start-up and commissioning phases. These operating conditions shall be reported on the compressor PROCESS DATA SHEET. The settling out pressure (SOP) shall be calculated and operating cases of compressor restart at SOP condition will be defined. The maximum absorbed power shall be calculated for the DESIGN FLOW.

A temporary stainless steel conical strainer of adequate strength shall be installed, during commissioning, in the compressor suction line upstream of the suction pressure sensor. This strainer has to be mounted into a drop-out pipe spool. If a permanent strainer is required, it shall be installed with a pressure drop measurement. Basic compressor control philosophy is given is § 21 of the current specification.

18. Lines Additional requirements concerning lines that are not addressed in the present specification are included in the following specifications: • GS RC PVA 100 • GS RC PVA 102 • GS RC PVA 103 • GS RC PVA 104 • GS RC HSE 020

18.1 Line sizing criteria 18.1.1

General

The size of the lines shall be calculated based on the MAXIMUM OPERATING FLOW (without design margin). The velocities and the pressure drop are based on financial criteria and may be subject to adaptation. The ρv² is representative of the noise, vibration or good flow regime through the piping and shall therefore be respected. 18.1.2

Piping sizes

Except for instrument tubing, heat tracing, connections to equipment or piping in which minimum flow velocity requirements govern; the minimum piping size shall be as follows: • 1" for all lines located above ground except for the following: − 2" for process line on pipe rack or pipe-way. − 2" for utility line on main pipe rack. − 2" for pipe on pipe sleeper. • 2" for all lines located underground, whatever their material, i.e. steel pipe or non metallic piping. • ¾" for the "Utilities" and drainage above-ground piping. Additional pipe size requirements on drainage and flare headers are given respectively in GS RC ENG 405 and GS RC ECP 104. Piping with nominal diameter DN10 (3/8"), DN32 (1¼"), DN65 (2½"), DN90 (3½"), DN110 (4½"), DN125 (5"), DN175 (7"), DN225 (9") and DN550 (22") shall not be used. If the equipment has connections in one of the above diameters, the piping shall, from this connection be increased to the immediately larger nominal diameter.

18.1.3

Liquid lines

LIQUID LINES

Piping Maximum pressure Minimum velocity diameter (") drop (bar/km) (m/s) Grass root Grass root Revamp Pump suction, liquid 0.9 ∅ ≤ 2" at bubble point (1) 0.9 3" ≤ ∅ ≤ 10" 0.9 12" ≤ ∅ ≤ 18" 0.9 20" ≤ ∅ Vacuum pressure Pump suction, subcooled liquid

Pump discharge

∅ ≤ 2" 3" ≤ ∅ ≤ 6" 8" ≤ ∅ ≤ 18" 20" ≤ ∅ 2"≤ ∅ ≤ 12" 14” and above

P ≤ 50 barg P > 50 barg Reciprocating Pump Suction Discharge Gravity flow Column draw-off (2)

0.95

0.95

0.9 1.2 1.5 1.8

3 3 3 3

3 5

5 7

4.5 9.0 1 2 ∅ ≤ 2" 3" ≤ ∅

Specific products Rich amine Lean amine Sodium hydroxide Sulphuric acid (H 2 SO 4 ) Hydrofluoric acid: - CS or SS 316 - Special alloy 20 Chlorine Sulphur Process water (acidic/sour) Cooling / Service water ISBL OSBL

0.45

0.6

0.8

0.9 0.9

0.6 0.9

0.9 0.9

1.1 (4) 2.0 (4) 2.0 0.8 1.0 4.0 1.0 1.25 (4)

3.5 1.1

Demineralised water, 2" ≤ ∅ ≤ 14" BFW, desalinated 16" ≤ ∅ ≤ 22" water, drinking water Pop ≤ 50 barg Pop > 50 barg Sea water

3.5 3.5 3.5 3.5

Maximum velocity (m/s) Grass root Revamp 0.6 3 0.9 3 1.2 3 1.5 3

2" ≤ ∅ ≤ 10" 12" ≤ ∅

1 (3) 1 (3)

2-3 2-3 4 6

4.5 9

6 6 2 2

4 4

4.5 4.5

LIQUID LINES

Piping Maximum pressure Minimum velocity diameter (") drop (bar/km) (m/s) Grass root Grass root Revamp 12” and above

Maximum velocity (m/s) Grass root Revamp 4.5

1) At pump suction, to avoid cavitation, margin between NPSHa vs. NPSHr must be compliant with requirements from GS RC MEC 610, GS RC MEC 685 and GS RC MEC 685. Applicable for liquids containing dissolved gas (except for 12" < ∅ < 8": 0.9 m/s max). Not applicable to sewer networks. 2) Provide a vertical section of 3 meters minimum from the column nozzle and the same size as the nozzle, before reducing the pipeline diameter. 3) Flow velocity shall not be less than 1 m/s to minimize deposition of solids and fouling. 4) Refer to GS RC COR 006, for other velocities related to concentration/material.

18.1.4

Gas lines Piping

GAS LINES

diameter (")

General case (gas) Vacuum (1) 0 < Pop ≤ 20 barg 20 < Pop ≤ 50 barg 50 < Pop ≤ 80 barg Pop > 80 barg Column overhead Vacuum lines (1) 0 < Pop ≤ 3.5 barg 3.5 < Pop ≤ 10 barg 10 barg < Pop Vapour return line from stripper Kettle reboiler return line Compressor suction 0 < Pop ≤ 20 barg 20 < Pop ≤ 50 barg 50 < Pop ≤ 80 barg Pop > 80 barg

Maximum velocity (m/s)

Grass Revamp Grass root root

Maximum Rho*V² (Pa)

Revamp

Grass root

Revamp

90 (4)

6 000 6 000 7 500 10 000 15 000

15 000 15 000 15 000 20 000

4%*Pop (bara)

90 60 50 40 30

5 mmHg 0.3 1.0 1.5

90 15 35 45

15 000 15 000 15 000

0.7 reciprocating 1.2 centrifugal

10 10

6 000 7 500 10 000 15 000

1.15

15

see compressor suction

0.45

∅ ≤ 2" 3" ≤ ∅ ≤ 8" 10" ≤ ∅

Superheated steam

Grass root

Minimum velocity (m/s)

0.45

Compressor discharge (2) Saturated steam

Maximum pressure drop (bar/km)

∅ ≤ 2" 3" ≤ ∅ ≤ 8"

15 000 15 000 15 000 15 000

10 30 40

15 40 50

15 000 (3) 15 000 (3) 15 000 (3)

20 000 20 000 20 000

15 40

25 50

15 000 (3) 15 000 (3)

20 000 20 000

Piping GAS LINES

diameter (")

Maximum pressure drop (bar/km) Grass root

Minimum velocity (m/s)

Maximum velocity (m/s)

Grass Revamp Grass root root

10" ≤ ∅

50

Maximum Rho*V² (Pa)

Revamp

Grass root

Revamp

80

15 000 (3)

20 000

Steam Short line ≤ 200 m Pop ≤ 10 barg Pop > 10 barg

0.9 2.3

Long lines > 200 m Pop ≤ 10 barg 10 < Pop ≤ 30 barg Pop > 30 barg

0.3 0.9 1

Air-Nitrogen

4.5

(1) (2) (3) (4)

20

Admissible pressure drop to be determined depending on vacuum level The compressor Manufacturer’s requirements, where they exist, are applicable in priority The limit of 15 000 Pa for ρV² can change up to 25 000 Pa for the let down stations. Velocities shall not exceed 30% of sound velocity to avoid erosion on piping.

The above information concerning the line sizing criteria is valid for continuous service. In this case, the pressure drop (in bar/km) shall not exceed 5% of the absolute static pressure for long headers and 10% for short piping. These values can be exceeded after an analysis on a case by case basis, for intermittent service. 18.1.5

Mixed phase lines

For a two-phase flow, the average density shall be calculated and the line shall be sized using the following criteria: • Average velocity: − Min : 3 m/s to avoid slug flow regime − Normal : 10 m/s − Maximum : 23 m/s, • Average ρV²: − 5000 to 15000 kg/m.s². These criteria shall not be applied to heaters transfer lines. The flow characteristics shall be analysed. Plug type regime and slug type regime shall be prevented. The length of the pipe whose flow is two-phase should be minimised and adequate support shall be provided to avoid vibration. 18.1.6

Off-site pipeline

For all off-site pipelines, additional sizing rules based on economic studies or due to the type of product, regulatory requirements could be indicated in a project specification.

For example: • The linear velocities of the products (other than the kerosene and the jet fuels) shall not exceed 1.5 m/s in the suction lines and 2.5 m/s in the delivery lines, • For all the kerosene and jet fuel piping, the velocities shall not exceed 1 m/s in the last 100 meters of piping before arriving in a tank or at a loading station, to limit the risks associated with static electricity. 18.1.7

Powder / pellets

Pneumatic transportation systems shall be calculated, designed and supplied by specialised suppliers. The DESIGN FLOW shall be at least 10% higher than the nominal flow rate. CONTRACTOR shall indicate in the transportation system specification all the required information, in particular: • The physical properties of the product to be transported: − The type of product. − The physical state (powder, pellets, etc.) − The actual and loss bulk densities. − Particle-size distribution − Flow behaviour properties (flowing type, angle of repose etc...). − Product sensitivity to Heat. For example, the granules may stick together and form blocks, which may plug the lines. Product temperature evolution along the conveying line should be assessed. − Product sensitivity to abrasion shall be given. This may lead to: o Specific pipe inner wall treatment o Limit pellet/powder velocity inside the conveying line o The implementation of additional filtration system depending on the final product specification. − HSE: o Risk of powder explosion should be assessed if relevant (depending on the product composition, particle size distribution, minimum energy of ignition). o Possibility of product degassing which may lead to flammable mixtures should be assessed. − The quality of the atmospheric air available (rural, urban, industrial, marine, etc)

18.2 Flange leakage prevention and mitigation 18.2.1

Welded flanges

In some specific cases the flanges can be welded, as mentioned in the GS RC PVA 100 or as specified by the applicable piping class.

18.2.2

Temporary connection

The design shall maximise the provision of permanent rigid connection on all services. Particularly the prolonged use of flexible pipes or hoses in locations where it is possible to install rigid piping is not allowed. However, this prohibition does not apply to bulk loading or unloading points, supply of combustible on mobile units, distribution points of lube oil. In any case the length of the hoses used occasionally shall be as short as possible. 18.2.3

Steam rings

Steam rings criteria is given in the GS RC HSE 022. They shall be indicated on P&ID.

18.3 Strainers Permanent strainers, with "coarse" mesh, and a temporary fine filter mesh for start-up, shall be provided in the piping for the protection of the following equipment: • Pumps: − In all pump suction lines − In steam inlet of steam jet ejectors − In cooling water supply line to pump bearings • Turbines: − On turbines > 400 kW a Y-type strainer shall be installed vertical in the steam inlet line, downstream of the suction block valve at the header − On turbines < 400 kW a spool piece strainer shall be installed in the steam inlet line. • Compressors: − In all compressor suction lines − Screened intakes shall be provided for air compressor and air blower (if needed with steam coil) • Other: − At the inlet of steam traps (refer to GS RC PVA 208) For filters refer to § 10.5.1.

19. Control valves Additional requirements concerning control valves that are not addressed in the present specification are included in the GS RC INS 450. All valve types shall conform to the applicable piping class.

19.1 Control valve Design The process operating conditions required for sizing and selecting a control valve are listed in GS RC INS 450 appendix 7 (control valve data-sheet).

19.1.1

Flow rates

The following three flow conditions shall be specified for the NORMAL OPERATING CONDITIONS: • Normal Flow Rate • MAXIMUM OPERATING FLOW: It is the governing case for maximum CV capacity. • Minimum Flow Rate (e.g. plant or equipment turn-down): It is the governing case for the required trim performance (highest differential pressure). If the control valve has to operate outside the NORMAL OPERATING CONDITIONS (e.g. startup, venting, de-pressurizing, regeneration, change in product composition, etc.) then these alternate conditions shall be specified in the data sheet. It is important not to apply any design margin on the above mentioned flow rates, design margin is applied on CV size selection only (refer to GS RC INS 450). 19.1.2

Pressure Drop

A control valve should ensure good rangeability, it means that there is enough differential pressure available for the minimum and maximum operating cases. First check the operating pressure upstream and downstream the valve. Second, the allowed pressure drop through the control valve will be considered as follows: 1. At MAXIMUM OPERATING FLOW: For instance, consider most reasonable value between: a) 25% of the pressure loss due to friction in the system (excluding pressure drop in the control valve) and; b) Criteria from GS RC INS 450. A minimum pressure drop of 0.7 bar should be foreseen. However, pressure drops lower than 0.7 barg can be allowed in gas circuits. For gravity circuits, it shall be equal to 25% of the control valve pressure drop at zero flow (control valve in closed position). 2. The pressure drop of a closed control valve shall be preliminarily assumed as being equal to the upstream DESIGN PRESSURE. For reflux control valves, consider the difference between the pump shut-off pressure and the column pressure plus the static head of liquid. 19.1.3

Additional information

In addition, where applicable, the following details shall be stated in the notes of the control valve data-sheet: • For flashing services the downstream vapour fraction (in weight percent) and the vapour molecular weight shall be specified. • For two-phase flow services the upstream and downstream vapour fraction (in weight percent) and the vapour molecular weight shall be specified. • For control valves having a downstream temperature lower than 0°C (e.g. due to JouleThomson effect on a gas or flashing of a liquid), this temperature shall be specified. It will be used for material selection.

• For control valves which must remain in operation during a power failure or instrument air failure an instrument air reserve shall be specified (with position-holding time or number of opening or closing required). The design and manufacture of air reserve tanks are described in GS RC INS 210 and STD RC INS 210.

19.2 P&ID development for control valve 19.2.1

Bypass valves

Control valve bypass and isolation valves enable on-line maintenance of a control valve at any time without affecting the unit operation. 19.2.1.1 Bypass valves requirement The following applications do not require a manual bypass of the control valve: • Non-continuous service: − Intermittent operation (e.g. during start-up, regeneration, etc.). − Alternate operation (e.g. part of spared, duty/standby equipment or unit section), • Non-critical equipment which may be shut down without affecting the operation of the main process. • Applications where, for safety reasons, manual operation by means of a bypass valve is not desirable (e.g. anti-surge control, turbine speed control, valve included in a SIF, etc.). Control valves that do not have a manual bypass shall be equipped with hand wheel for manual control unless manual control is impossible. Bypass requirements are defined in GS RC INS 450, in addition: • Control valve diameter lower or equal to 6": bypass of the control valve shall be foreseen. • Control valve diameter higher than 6": the need of a control valve bypass will be reviewed and a justification shall be submitted to COMPANY approval. On high pressure service (e.g. high pressure steam production), a small diameter bypass valve (e.g. ¾") different from the maintenance bypass valve will be considered to allow a smooth pressurisation of the downstream system. Spare control valve: For applications where it is impractical, unsafe or frequent to operate the process on a manual bypass valve, a spare control valve may be installed in lieu of a manual bypass valve. It will be designed to ensure a smooth transfer of the control signal between the main control valve and the spare control valve. Alternatively, two smaller redundant control valves, each having 50% of the required flow capacity, may be provided. Such applications include, but are not limited to: • Quench flow control and temperature control on an exothermic reactor, • Main utility site control valves (e.g. fuel gas and air) • BFW control, • Control valves having a high probability of failure during the unit run time (e.g. distillate hydrocracker HP-LP flash control valve).

• For applications requiring control valve body sizes in excess of 12", multiple parallel arrangements of identical smaller body size valves may be considered. A duplicate control valve shall then be provided as a common bypass valve for any one control valve (in this case handwheel can be considered on the spare control valve instead of an actuator). • Control valves requiring special low-noise or anti-cavitation type trims (in this case handwheel can be considered on the spare control valve instead of an actuator). 19.2.1.2 Bypass valve size The annex 8 of GS RC INS 450 gives the nominal diameter of the bypass valve and isolation valves as a function of the control valve and the pipe diameter. Bypass valves shall have a flow coefficient (Cv) at least equal to the required Cv of the control valve, but not greater than twice the selected Cv of the control valve. Bypass valves shall have leaktight flow rate adjustment (globe valves up to DN100 inclusive). 19.2.2

Isolation valves

19.2.2.1 Isolation valves requirement Control valves with a bypass shall be installed with manual isolation valves. For sizing and requirements refer to GS RC INS 450. Control valves without a bypass shall be installed with manual isolation valves if: • The control valve isolation does not affect the operation of the main process (online maintenance). • The control valve maintenance requires unplanned unit or section shutdown (offline maintenance) and there is more than 10 meters of piping between the control valve and the other existing isolation valves allowing control valve removal (e.g. using pump discharge isolation valves). Intention is to avoid purging important product inventory during maintenance (e.g. reflux control valve on a distillation column). • The fluid is TOXIC FLUID, CMR FLUID or corrosive. For other applications, isolation valves are not required. Typicals for the isolation of Control valves are given in appendix 2. These typicals have to be reviewed and discussed at the start of FEED to take into account specific local requirement 19.2.3

Drain and vent valves

Drain or vent valves shall be provided upstream and/or downstream of control valves, irrespective of whether the control valve has isolation valves or not. • For "Fail Close" (FC) control valve, two maintenance drain or vent valves shall be installed one upstream and one downstream of the control valve. • For "Fail Open" (FO) control valve, one maintenance drain or vent valve shall be installed upstream of the control valve. Drain valves shall be installed on the bottom of each spool piece or reducer between the control valve and the block valves. For more detail on liquid drainage and spill control refer to appendix 2 and to the GS RC ENG 405.

19.2.4

Additional information

The following considerations shall be taken into account for P&ID development: • Three-way control valve shall not be used (refer to GS RC INS 450). • Self-acting or self-regulating control valves shall be used on exceptional basis and is subject to COMPANY written approval (refer to GS RC INS 450). • Control valves in flashing service shall be located as close as practically possible to the downstream vessel. • Control valves in two phase flow service shall have a minimum straight length of 5 to 10 pipe diameters from the control valve outlet to the first pipe elbow (to minimize erosion). • Control valves discharging to atmosphere, flare, fuel gas, compressor anti-surge and spillback services or similar system must be specified as tight shut off (TSO) in order to maximize energy conservation or to limit emissions (refer to GS RC INS 450). • In case a minimum flow through a control valve is required (e.g. compressors suction control) there are two possibilities: − The control valve shall provide a minimum flow capacity in the fully closed position (e.g. both the cage type trim and plug can have openings, the disc of a butterfly valve can have holes or be undercut, etc.). − A bypass valve, with restricted flow capacity and being locked open, may be installed across the control valve. Mechanical travel stop on a valve stem should not be used as it can be easily removed and the permanence of such a system after valve maintenance or replacement is difficult to ensure.

19.3 Revamping or Debottlenecking Exceptionally, for revamping or debottlenecking situation, the maximum opening of the control valve can be higher than 70%. This is a deviation to the criteria given in the GS RC INS 450 to be submitted to COMPANY.

20. Insulation and tracing 20.1 Insulation Additional requirements concerning insulation that are not addressed in the present specification are included in the GS RC ISL 101 (Thermal insulation of equipment). 20.1.1

Need for Insulation

Thermal insulation shall be applied on equipment and lines according to the criteria given in specification GS RC ISL 101. More generally, insulation can be used for at least one of the following functions: • Heat conservation (hot) (HC) • Cold Conservation (CC) • Protection against cold ambient conditions or Winterisation (WT)

• Protection of personnel (PP) • Insulation with heat tracing (HT) • Anti-condensation (AC) The Heat Conservation (HC) insulation shall be applied to: • Equipment and piping operating above 120°C and for which it is not desirable to lose heat unless otherwise specified by the project or by energy efficiency study. • Equipment and piping with heat conveying fluids (e.g. steam, hot oil etc.), regardless of the temperature. The below table gives examples of applications of winterisation (WT) and heat conservations (HC): Insulation function

Applicability of Insulation

Application

WT

HC

Bypass and dead ends (e.g. vents, drains, utility connection, PRV etc.)

YES

NO

Pumps, compressors casing

YES

NO

Steam turbine, vessels, heat-exchanger

YES

YES

Equipment where it is desirable to lose heat (e.g. cooling water exchanger, air-cooled equipment, steam traps etc.)

YES

NO

The Personnel Protection (PP) shall be applied to parts of equipment and piping operating at a temperature higher than 65°C or lower than -5°C that can be accessed or are likely to be accessed during operation and servicing procedures and that do not require neither Heat Conservation (HC) nor Cold Conservation or Anti-condensation. The Cold Conservation (CC) insulation shall be applied to equipment and piping operating below 20°C and for which it is not desirable to gain heat, unless otherwise specified by the project or by energy efficiency study. For equipment or piping operating at temperature between - 5°C and 20°C an anti-corrosion external coating shall be applied to limit corrosion under insulation (CUI). Anti-Condensation and Icing Formation Protection (AC): applies to equipment and piping operating at a temperature below 20 °C and for which Cold Conservation (CC) insulation is not required. The main purpose of this type of insulation is protecting the equipment and piping against external condensation and/or icing formation to avoid streaming (fall of liquid) that could generate an external corrosion on other equipment/piping located below.

Service shall be clearly identified in the line list to allow correct selection of insulation around valves and flanges (e.g. hazardous services, service above auto-ignition temperature such as hydrogen service, pitch, bitumen, sulphur product, superheated steam etc.).

20.2 Tracing Additional requirements concerning tracing that are not addressed in the present specification are included in the GS RC PVA 106 (Steam tracing of equipment). 20.2.1

Need for Tracing

Tracing shall be applied on equipment and lines according to the criteria given in GS RC PVA 106.

20.2.2

Tracing type selection

In addition to the general guideline given in the GS RC PVA 106, the following criteria may be used to select the type of tracing: Criteria

Tracing types

In general (e.g. prevention of condensation in vapour lines, prevention of crystallisation, etc.)

LP steam (around 4 barg)

Winterizing

LP steam (around 4 barg) Or Electrical (1)

Liquid with high viscosity or high pour point (up to 70 °C)

LP steam (around 4 barg)

Liquid with pour point higher than 70 °C Special applications for which steam tracing cannot be applied because the operating temperature is significantly lower than the LP steam temperature. For example caustic; steam tracing could lead to vaporisation of these respective highly corrosive and highly toxic components (3).

MP steam (around 15 barg) (2) Electrical

(1) Electrical tracing is recommended for small diameter water lines (<4") for a better control of the heat transfer (e.g. to avoid boiling of a liquid contained in a line). (2) For heavy product such as vacuum product, the steam tracing should be designed to avoid condensate circulation in the end of the circuit. (3) See also GS RC PVA 106 concerning the use of thick rigid insulation rings.

21. Control philosophy Additional requirements concerning control philosophy that are not addressed in the present specification are included in the GS RC INS 106.

21.1 Use of Auto-start As a general rule, automatic start (auto-start) should be avoided for pumps in hydrocarbon service, and for compressors. If no pump auto-start is required, the pump shall be started locally and be stopped locally and remotely. However, auto-start can be considered for the following cases: • Level control in on/off mode (e.g. sewer pumps, vacuum systems, Flare blow down drums, slop drums, etc.) • Fire water pumps • Potable water pumps • Air compressors for Service Air and Instrument Air • Air cooler fans under temperature control • Cooling water pumps • BFW pumps • Lubricating oil or sealing oil pumps For all other cases than those mentioned in the above list, automatic start of a rotating equipment shall be justified on case by case basis by CONTRACTOR (e.g. for safety reasons, or to avoid very frequent trips) and approved by COMPANY.

The auto-start sequence shall not stop the main pump(s) in operation; eventually, the pumps in operation will be stopped by the operator. Use of auto-start for turbines is not allowed.

21.2 Heat exchangers 21.2.1

Temperature

As a minimum a local temperature instrument shall be installed at the inlets and outlets of the heat exchanger (for process monitoring and heat balance purposes). Preferably, the temperature measurement should be transmitted to DCS to enable a proper monitoring of its performances. When a heat exchanger is composed of several shells, it is recommended to provide thermowells between individual shells or groups of stacked shells to enable local temperature measurement in case of fouling service and if there is a possibility to isolate part of the shells. When the heat exchanger is equipped with a bypass, at least two thermowells (or DCS temperature indicator) are required on the exchanger outlet, one upstream and one downstream of the bypass tie-in. 21.2.2

Pressure

Pressure connections shall be provided between exchangers on highly fouling service or by analogy with heat-exchanger on similar application to measure pressure drop during operation. 21.2.3

Steam heat exchanger

Controlling reboiler pressure is not suitable because the relationship between pressure and condensing temperature is not linear and changes due to fouling. The flow of steam can be controlled by either (a) steam inlet or (b) the condensate outlet. Here below some guidelines: With (a) the function of the control valve is to reduce the steam pressure in the channel head of the reboiler, acting on the differential temperature driving force. The actual steam rate is controlled by the condensation rate of steam inside the tubes. The advantage is that it offers a faster dynamic response than (b). If the steam pressure in the channel gets lower than the pressure in the condensate collection header, it affects the capacity to evacuate the condensate (potential instability), for this reason steam inlet control scheme is not suitable for low pressure steam. Steam traps can create problems when plugging or remaining open. In addition, the failure close of a control valve on the steam supply would lead to vacuum scenario. For (b) control in the condensate outlet, the vapour condenses at the header pressure, which is constant and provides heat exchange stability. It allows to operate reboilers at higher pressure than (a). However, response on heat based on level is slower than manipulating the steam flow. Condensate outlet control, with level fluctuations can be detrimental to thermosiphon reboiler stability in vacuum units. A condensate pot might be required on the condensate outlet when there is a risk of blow-by to the condensate header. As the drum level decreases the number of tubes in the exchanger exposed to the steam increases. The level override prevents loss of condensate seal. The relative elevation between the steam exchanger and the condensate pot shall allow an adequate level control of condensate in the heat exchanger and consequently of the heat transfer area and heat transfer rate (duty).

The condensate valve has to be properly designed to handle the amount of condensate. For revamps it might be needed to resize the valve or install a pump to evacuate the condensates. For a horizontal exchanger: the balance line should be connected below the pass partition baffle to make sure that pressure in the exchanger and the pressure in the condensate drum are identical. Otherwise the level in the drum will not be representative of the channel head.

21.3 Air cooled heat exchangers 21.3.1

Temperature points

As a minimum a local temperature instrument shall be installed at the inlets and outlets of the air-cooled heat exchanger (for process monitoring purposes). Preferably, the temperature measurement should be transmitted to DCS to enable a proper monitoring of its performances. Consider providing thermowells at the inlet and outlet pipes of each individual bundles of the air cooled heat exchanger to enable local temperature measurement in case of fouling service. 21.3.2

Air side control

The type of air side control depends upon the criticality of the process, the accuracy of control required, and economics. The following methods are recommended: • Manual shutdown, start-up of fan motors. • Use of variable speed motors shall be justified and approved by COMPANY since variable speed motors are an expensive way to control product outlet temperature. The number of motors with variable speed drive shall be ≤ 50% of the total. Beyond 8 motors (≥ 4 bays per unit/service) having 25% maximum of the motors on variable speed drive can be considered. Validate the implementation of variable speed drive system with electrical specialist. • Hot bypass of the air-cooled heat exchanger. However, this cannot be applied when there is a possibility of product freezing or fouling product (e.g. high pour point, hydrate etc.) in the air-cooler. The use of variable pitch fan blades is not recommended (operating feedback experience on these systems is showing that most of the time they are not properly working, and at the end temperature is controlled by manual shutdown and start-up of motors). But fans shall be equipped with blades which can be adjusted manually when stopped. The use of manual or automatically controlled louvers is limited to winterisation purpose.

21.4 Compressors The compressors’ recycle loop (including heat-exchangers and control valve) will be sized for 100% of the DESIGN FLOW of the compressor. 21.4.1

Centrifugal compressor

21.4.1.1 Anti-surge protection: A centrifugal compressor, either fixed or variable speed, whose flow rate may be brought under the surge point, for example by a suction or discharge adjustment valve shall be equipped with an anti-surge line (e.g. recycle compressor may not require anti-surge).

The anti-surge control shall be done through a dedicated controller having a very low response time (a DCS anti-surge controller is not acceptable). The anti-surge controller shall automatically maintain a flow through the compressor with a safe margin in excess of the surge flow during all operating conditions, by means of an automatic anti-surge recycle valve and recycle line. The anti-surge circuit length shall be minimized in order to reduce the reaction time. The compressor discharge check-valve will be placed downstream of the anti-surge line tie-in. Design criteria to be applied to the anti-surge recycle valve are given in the GS RC INS 720 (Instrumentation for Rotating Machines).The anti-surge control valve data sheet shall be specified or approved by the compressor vendor (e.g. technology, opening time, flow and pressure drop). Multiple stage compressors can have one single anti-surge control system for all the stages with the following exceptions: • If the gas flow may vary differently from one stage to the next (e.g. stages fed by additional side streams, stages offloaded by stream consumptions etc.) these stages shall have their own anti-surge control system. • If some stages are separated by process sections, these stages shall have their own antisurge control system. 21.4.1.2 Compressor Control: Controls and instrumentation shall be adequate to control the compressor at all specified operating conditions. Ways to control a centrifugal compressor shall be selected among the following systems: • Variable speed drives (VSD): E.g. steam turbine, variable electrical motor (variable frequency drive - VFD), fluid coupling. • Inlet guide vanes (IGV): The vanes adjust the capacity. This is accomplished by prerotation of the gas entering the impeller which reduces the head-capacity characteristics of the machine. • Suction valve throttling: Suction throttling shall not result in sub-atmospheric pressure and risk of air ingress into the process stream. The suction throttling control valve (when required to control the suction pressure or the motor power) shall be located upstream of the recycle line tie-in to the compressor suction piping. Partial cut-out of the disk of the valve (hole sized to avoid vacuum and surge conditions) is allowed but mechanical valve stem travel stops are not permitted as it could be removed. • Compressor recycle or spill-back valve: However, for energy saving reasons, the control by recycling should be limited to degraded modes. When compressors are operated in parallel arrangements, a load sharing controller shall function to distribute the load by keeping each machine equidistant from its surge curve or surge control margin. 21.4.2

Reciprocating Compressors

There are different ways to control a reciprocating compressor: • By step – with suction valve unloaders: Inlet valves in the same effect of the cylinder are kept open all the time and thereby limit the compressed flowrate to 0%, 50%, 100%.

• Stepless capacity control Inlet valves are kept open during compression stroke and closed when the desired inlet volume is in the cylinder. • Clearance volume pockets: additional pockets which are opened when unloading is desired. • Recycling: Flow control by recycling only should be avoided and shall complement the above listed controls. When recycle is required, the recycled gas should be cooled before arriving back to the compressor suction. • Variable speed control with variable frequency drives (VFD) is not recommended because of possible vibration problems (e.g. activation of acoustic or mechanical resonance mode). Flow-rate control on process compressors shall have as a minimum the following points of reference: 0%, 50%, & 100%, in accordance with process requirements and number of cylinders per stage. The process licensor or the CONTRACTOR shall recommend the capacity control requirements and if the compressor has to be loaded or unloaded in case of capacity control system failure.

22. Isolation philosophy This section addresses the minimum requirements concerning isolation of equipment, control valves and PRVs that have to be implemented in particular for maintenance purpose. Isolation is the separation of a system (e.g. individual equipment, process unit, section of process unit) from another system either in operation or not. There are two types of isolation: • Positive isolation. • Valved isolation. Valves and blinds have to be placed as close as possible to the system that is isolated. Isolation valves shall conform to the applicable piping class.

22.1 Positive isolation Positive isolation from a system in operation is ensured either by the use of blinds (spade blind, paddle blind or spectacle blind) or by disconnection (e.g. spool piece). Most of the time, the implementation of positive isolation requires isolation valves to allow the operation on blinds and spool pieces. 22.1.1

Positive isolation requirement

Positive isolation shall be provided: • At plant battery limit. • On all inlets and outlets of equipment that will be taken out of service while the adjacent equipment remain in service (e.g. filters, pumps, heat-exchangers that need to be isolated from live system). The blinds shall be installed against the isolation valves. • On all inlets and outlets of equipment that will not be taken out of service while the adjacent equipment remain in service but that need to be isolated for maintenance (e.g. heat-exchangers inspected during turn-around and inspection). Block valves are not required and blinds are sufficient.

• On all inlets and outlets of equipment subject to personnel entry for inspection (e.g. drums, columns, reactors). • On drains to a closed drain system and on vents to flare or atmosphere. Positive isolation is not required for: • Control valves, PRVs (block valves are sufficient). • Instrument connections on vessels (e.g. pressure, temperature or level transmitters that are "dead-ended") except if vapours or liquids can enter the vessel via the instrument connection (e.g. instrument with nitrogen flushing). • Non flammable, non combustible and non toxic fluids with a rating < 600 # and a temperature lower than 250°C. 22.1.2

Blinds

In general, spade blinds should be used rather than spectacle blinds. Spectacle blinds shall only be used in the following cases: • When required by Project specifications, • When frequent operation or maintenance is needed (e.g. filters), • At battery limit. • On drains If a piping system is too rigid to install a spade blind, a spacer ring is installed. During isolation the spacer ring is removed and replaced by a spade blind. Rating Diameter

Spade Blind or Paddle with < 600 # ≥ 600 #

Spectacle Blind

D < 8"

No spacer ring

No spacer ring

Acceptable (1)

8" ≤ D < 16"

No spacer ring

spacer ring

Acceptable (1)

16" ≤ D ≤ 24"

spacer ring

spacer ring

Acceptable (1)

24" < D

spacer ring

spacer ring

Consider Paddle with spacer ring instead

(1) A spacer ring with spade blind shall be used instead of a spectacle blind for cold insulated piping with operating temperature below 21°C.

22.2 Valved isolation Valves used for isolation purpose must provide a reliable seal. Check valves, control valves and other valves which do not provide tight shut off cannot be considered suitable for isolation. On/off valves are not intended to be used for maintenance purpose however, in case of double valve requirement, one existing on/off valve can be used as a manual block valve, provided that operating procedure is in place to define the consignment of the on/off valve. The impact of the isolation valve on overpressure scenario has to be taken into account (e.g. blocked outlet cases) and protection has to be foreseen. 22.2.1

Single valve isolation

Single valve isolation consists in a single block valve.

22.2.2

Double valve isolation

Double valve isolation consists in two block valves flange to flange. Requirement for double valve isolation is specified in § 22.3. 22.2.3

Double block & bleed isolation

Double block & bleed isolation consists in a first block valve, a bleed valve and a last block valve. It might be used where effectiveness of the isolation (stopping the material flow) has to be confirmed via a bleed point. It may apply, for instance, to some automatic shutdown systems, to some fuel gas supply to burners, and to equipment subject to operations which can be hazardous if the wrong product is fed during an operating phase (e.g. isolation of process and utility material). The bleed valve shall be connected: • To a closed drain or a flare system preferably, and mandatorily for TOXIC FLUID, explosive, above its auto-ignition temperature or if required by risk analysis. In this case a tapping shall be provided to confirm adequate depressurisation. • To atmosphere at safe location for other cases. In closed position, the "manual" bleed valves shall be equipped with a blind flange, for "automated" bleed valve consider the installation of gas detector at exhaust to atmosphere. The standard bleed arrangement shall be a single ¾" or 1" valve. 22.2.4

Valved isolation requirement

Single valve isolation or double valve isolation shall be provided at: • Plant battery limit (in addition to positive isolation). • On all inlets and outlets of equipment that will be taken out of service while the adjacent equipment remain in service (e.g. filters, pumps, heat-exchangers that need to be isolated from live system). The blinds shall be installed against the isolation valves. • Control valves. • Pressure relieving systems, when PRVs are spared. The isolation valve is LO (Locked Open) / LC (Locked Closed) or an interlock is in place. • Instrument connections. Valves can be omitted: • For economical reasons on large vapour lines like transfer and overhead lines. 22.2.5

Additional requirement

22.2.5.1 Root valves on utility lines Each utility take-off connection shall be located at the top of the horizontal main header or auxiliary header. Root valves (block valves) shall be provided for each utility take-off connection from a main header or auxiliary header which cannot be taken out of service without shutting down a complete processing unit or operating facility. Instrument air take-off connections to the plant utility station shall always be provided with root valves.

22.2.5.2 Emergency isolation valves and depressurisation valves The use of emergency isolation valves and emergency depressurisation valves is addressed in the GS RC ECP 103. 22.2.5.3 Gear Operated Valves Reduction gear requirements on valves are given in the GS RC PVA 200. 22.2.5.4 Use of locked open and locked close valves Locked open (LO) or locked close (LC) valve means three things: • Valve is physically chained and locked, with the key in the control room or in the inspection building. • Administrative procedure is in place for regular checking that the valve is kept locked. • Administrative procedure provides a check list of things to be done when valve is unlocked (e.g. during maintenance or inspection of the equipment protected by the locked open valve). The number of LO or LC shall be minimized. The reason is that a great number of LO and LC valves is difficult to manage and complicates the operation, especially for equipment requiring frequent maintenance (e.g. filters). The possibility to use LO/LC valves to avoid the installation of PRVs is addressed in the GS RC ECP 101. In case of n+1 PRVs, the isolation valves of the n PRVs shall be LO and the isolation valves of the spare PRV shall be LC unless a key interlock system is in place (Refer to GS RC ECP 101). The use of CSC (Car Seal Closed) or CSO (Car Seal Open) valves is not considered equivalent to LC or LO valves since a seal can be more easily removed (no need of a key) and that once a seal is cut a new seal has to be installed, whereas the lock on a chain can be closed again after the valve position has changed. The suitability of CSC or CSO should be validated at last during HAZOP review.

22.3 Double valve requirement 22.3.1

Operating Conditions Category A and B

Category A: Piping and equipment having a rating ≥ 600 # or operating at temperature ≥ 250°C Category B: Piping and equipment having a rating < 600 # and operating temperature < 250°C 22.3.2

Fluid ranking Category I, II, III, IV

Category I service: Category I service includes all streams containing TOXIC FLUID Category II service: Category II service includes streams containing: • Explosive materials (e.g. peroxides above a certain concentration), • Materials above their auto-ignition temperature, • Materials having a flash point lower than ambient temperature, • LPG service, • Hydrogen service.

Category III service: Category III service is related to flammable mixtures. Category IV service: Category IV service includes all non toxic and non flammable mixtures. 22.3.3

Isolation system selection

The table hereunder provides minimum valved isolation requirements related to operating conditions and fluid ranking. Category I Toxic

Category II Explosive, Above auto-ignition, LPG, H 2 service

Category III Flammable

Category IV Non toxic and non flammable

Category A ≥ 600 # or ≥ 250 °C

Double valve isolation

Double valve isolation

Double valve isolation

Double valve isolation

Category B < 600 # and < 250 °C

Double valve isolation

Double valve isolation

Single valve isolation

Single valve isolation

Fluid ranking Operating Conditions

The valves which are not used when the line or equipment is under pressure (e.g. vessel vents) are not doubled but will be provided with a blind flange. For piping class of 150# with neither flammable nor toxic services (e.g. air, water) threaded connections are allowed.

22.4 Specific services 22.4.1

Drain and sampling connections on LPG service

For LPG service the auto-refrigeration due to flashing to atmosphere can cause ice formation around the drain valve (temperature after flashing ≤ 0°C) and hamper its actuation. The following arrangement shall be applied for LPG service for drainage and sampling: • Two block valves are required with 500 mm minimum of pipe length in between. • The first block valve (i.e. HP side) shall be a ball valve • The second block valve (i.e. LP side) shall be a globe valve. For instrumentation on LPG service refer to GS RC INS 200 (Process connections for Instruments and Analysers) and to GS RC INS 230 (Process drains of instrument). 22.4.2

CMR

For CMR FLUID(S) double valve isolation is not required. Diaphragm seals are mandatory for pressure and flow transmitters if temperature is lower than 400°C.

22.5 Typicals Typicals for the isolation of Control valves and PRVs are given in Appendix 2 and Appendix 3. These typicals are based on the fact that positive isolation is required on drains to a closed drain system and on vents to flare. These typicals have to be reviewed and discussed at the start of FEED.

Appendix 1

Minimum requirements for typicals development SYMBOLS

General note: 1. The above symbols are used in the GS RC ECP 100 only. Other symbols may be used on specific projects for consistency reason with existing units. Rules given in the GS RC INS 106 shall prevail