hindustan petroleum corporation limited mumbai refinery...

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HINDUSTAN PETROLEUM CORPORATION LIMITED

MUMBAI REFINERY

DHT PROJECT

PART –II SECTION : B

BASIC ENGINEERING DESIGN BASIS

DOCUMENT NO : 44LK5100-00/P.02/0001/A4

Approved by HPCL: Date:

Rev No. Issue Date Pages Rev Description Prepared

By

Checked

By

Approved

By

A 08/02/2008 68 Issued for Client’s Comments / Approval

RVB RMK NSS

B 20/08/2008 71+ Annex -2

Issued for Client’s Comments / Approval

SM RMK NSS

C 21/11/2008 70+ Annex -2

Client comments Incorporated and issued for

FEED

MKK RVB NSS

D 09/02/2009 70 + Annex-2

Approved by HPCL MKK RVB NSS

HPCL, MUMBAI 44LK5100

BASIC ENGINEERING DESIGN BASIS Doc No. 44LK5100-00/P.02/0001/A4

PART – II SECTION: B of 72

Z:\4401-5100_Project\TENDER DHT\DHT TENDER EDITABLE FILES\Part II\B___Basic Engg Design Basis\44LK5100-00-P-02-0001-A4 BEDB Rev-D.doc

TABLE OF CONTENTS

Section

No.

Contents

1.0 INTRODUCTION

2.0 PROJECT DESCRIPTION

2.1 Brief Description

2.2 Project Title

2.3 List of facilities & unit numbers

2.4 Units of Measurement

3.0 PLANT LOCATION

4.0 METEOROLOGICAL DESIGN DATA

5.0 DESIGN PLANT LIFE

6.0 UTILITY SPECIFICATIONS

6.1 Utility Conditions at Battery limits

6.2 Steam and condensate systems

6.3 Water systems

6.4 Compressed air and nitrogen systems

6.5 Fuel systems

6.6 Flare systems

6.7 Liquid pump out & drain systems

6.8 Electrical system

6.9 Flushing oil systems

6.10 Other Utility system considerations

6.11 Caustic Storage, Preparation and Distribution

7.0 GENERAL DESIGN PHILOSOPHY

7.1 Energy integration

7.2 Vacuum design consideration

7.3 Feed, intermediate and product storage

7.4 Aromatics handling

7.5 Metallurgy

7.6 Corrosion allowance

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Section

No.

Contents

8.0 EQUIPMENT DESIGN PHILOSOPHY

8.1 Overdesign philosophy

8.2 Selection of mechanical design conditions

8.3 Heat Exchangers

8.4 Fired Heaters

8.5 Vessels

8.6 Towers

8.7 Pumps

8.8 Compressors

8.9 Steam Turbine drives

8.10 IBR requirements

9.0 INSTRUMENTATION

9.1 Control Philosophy

9.2 General requirements

9.3 Level Instruments

9.4 Flow Instruments

9.5 Start-up / shutdown operation from control room

9.6 Status indication lamps in control room

9.7 Control valve manifold

9.8 Pressure relief valves (PSV)

9.9 Control philosophy for vendor package items

9.10 Standard instrumentation

10.0 PIPING & INSULATION

11.0 ENVIRONMENTAL CONTROL

12.0 SAFETY

13.0 PFDs AND P&IDs

14.0 NUMBERING SYSTEM

15.0 STANDARDS & CODES

16.0 ANNEXURE 1

Caustic Soda Service Graph

17.0 ANNEXURE 2

Standard P&IDs





1.0 INTRODUCTION

1.1 Hindustan Petroleum Corporation Limited (HPCL) operates a refinery located at Mumbai in

the state of Maharashtra, India. HPCL now intend to engineer, construct, commission and

operate Diesel Hydrotreater Unit along with Hydrogen Generation Unit, Sulphur Recovery

Unit, Amine Regeneration Unit, Sour Water Stripping Unit and necessary Utilities and

Offsites as part of the project. Jacobs Engineering India Pvt. Ltd. (JACOBS) has been

retained by HPCL to provide services for Project Management Consultancy (PMC) and

Front End Engineering Design (FEED) for ISBL units and to provide EPCM services for

OSBL facilities including tankfarm and utilities.

The design basis presented here intends to provide the engineering contractors with the

technical information required to complete the engineering design specifications of the

project units in a uniform and consistent manner.

1.2 Basic Engineering Design Basis (BEDB) for all facilities, containing technical information

agreed between HPCL and Licensor, and HPCL and PMC shall be binding on the process

design and engineering of units, utility systems and offsite facilities.

1.3 The licensor's design basis for specific units form part of Process Package of the respective

units.

1.4 This document constitutes common Basic Engineering Design Basis defining overall project

requirements for making all units compatible and ensuring uniform design practices for the

total project. It also provides certain minimum requirements specified and used by licensors/

unit designers.

1.5 This BEDB constitutes the guidelines to be followed during detailed engineering design and

construction of the facilities in this project. LSTK Contractor to employ and incorporate their

best engineering practices and experience to ensure smooth and safe commissioning of the

plant including start-up and shutdown/normal operation and emergency handling.

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2.0 PROJECT DESCRIPTION

2.1 BRIEF DESCRIPTION

The project consists of 2.2 MMTPA Diesel Hydrotreating (DHT) unit to process and treat

Diesel from Mumbai Refinery to meet Euro-III/IV and Ultra Low Sulphur Diesel (ULSD)

quality specifications with reference to Sulphur and Cetane number. To meet the additional

requirement of Hydrogen, Hydrogen generation unit of 28,000 TPA is envisaged as part of

this project. Other auxiliary units, Amine regeneration unit (ARU), Sulphur recovery unit

(SRU), Tail gas treatment unit (TGTU), sour water stripper (SWS) and associated facilities

for utilities and offsites, as required, form part of this project.

The units under this project and licensors thereof are as follows:

UNIT LICENSOR

1 Diesel Hydro-treating Unit UOP

2 Hydrogen Generation Unit L-EPCC Basis

3 Sulphur Recovery Unit L-EPCC Basis

4 Tail Gas Treatment Unit L-EPCC Basis

5 Amine Regeneration Unit BEP by JACOBS

6 Sour Water Stripper Unit BEP by JACOBS

7 Offsites, Utilities & Tankages BEP by JACOBS

2.2 PROJECT TITLE : To be used for all documentation

Project Name : Diesel Hydrotreater Project

Owner : Hindustan Petroleum Corporation Limited

Location : Mumbai, Maharashtra (India)

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2.3 LIST OF PROJECT FACILITES

The project essentially consists of the following new facilities:

Sr.

No.

Facility Unit

Number

Capacity

1 Diesel Hydro-treating Unit 700 2.2 MMTPA

2 Hydrogen Generation Unit 701 28 KTPA

3 Sulphur Recovery Unit 704 2 x 65 TPD

4 Tail Gas Treatment Unit 704 1 x 130 TPD

5 Amine Regeneration Unit 702 164 m3/h

6 Sour Water Stripper Unit 703 25 m3/h

7 Nitrogen Plant

8 Compressed Air/ Instrument Air

9 Hydrogen Storage

10 Tankages

11 Pump House for Tankages

12 Flare System (Acid Gas)

13 Flare System (Hydrocarbon)

14 Raw Water / Service Water

15 Sea Cooling Water System

16 Bearing Cooling Water System

17 DM Water System

18 Drinking Water

19 Condensate Recovery & Polishing System

20 Boiler

21 Fuel Gas / Natural Gas

22 Offsite Utilities Network

23 Offsite Process Network

2.4 UNITS OF MEASUREMENT

2.4.1 MKS system of measurement shall be followed, with the exception of piping/tubing sizes,

which shall be reported in inches.

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UNITS

MKS

Composition vol % / wt %

Specific Enthalpy kcal/kg

Flow steam MT/hr

Flowing liquid m3/hr

Flowing mass kg/hr

Flowing vapour Nm3/hr

Furnace draft mm WC

Heat rate 106 kcal/hr or MM kcal/hr

Heat Transfer coefficient kcal/hr-m2-°C

Length m, mm

Level mm

Liquid Absolute Density kg/m3 at 15

°C

Liquid Flowing Density Kg/m3 at T

°C

Liquid Relative density Sp. Gr. T °C/15.6 °C

Vapour flowing density kg/m3

Mass kg Power kW Pressure kg/cm

2(g)

Pressure (absolute) kg/cm2(a)

Sound Pressure dB (A) Standard liquid Sm

3/hr at 15.6 °C

Standard vapour Nm3/hr at 0°C & 1.033 kg/cm

2a

Storage tank pressure mm WC Temperature °C Thermal conductivity kcal/hr-m-°C Vacuum mm of Hg Viscosity cP Viscosity (Kinematic) cSt

2.4.2 Material Balance in PFD shall be reported in following units:

a) GASES: Nm3/hr kg/hr

b) LIQUIDS: Sm3/hr kg/hr

PFD shall be flagged with following symbols:

Flow kg/hr

Density kg/m3 @ pressure and temperature

Pressure kg/cm2(g)

Temperature °C

Duty MM kcal/hr

Stream Number Numeric





3.0 PLANT LOCATION

Details of plant location are given below:

3.1 Site location : Mumbai, Maharashtra, India

Nearest railway station : Mumbai

Nearest important town : Mumbai

Nearest airport : Mumbai

Nearest sea port : Mumbai

Nearest national highway : NH-4 6 km

NH-8 20 km

Geographical bearing of site : Latitude: 19° 0’ 42” N

Longitude: 72° 54’ 14” E

3.2 Source of water : Municipal Corporation Supply

3.3 Rainy season : June to September

3.3.1 Annual rainfall Max/Min/Average. : 3481.6 / - / 1954 mm/yr.

Maximum recorded in 24 hrs : 575.6 mm

3.3.2 HFL Data for last 20 years

and maximum HFL recorded (m) : Site not prone to floods



HPCL, MUMBAI

44LK5100


4.0 METEOROLOGICAL DESIGN DATA

4.1 Meteorological design data is furnished in detail in Engineering Design Basis. This section

presents relevant data used towards preparing process engineering specifications in Basic

Design Package.

Sr.

No.

Parameter Minimum Normal /

Average

Maximum /

Design

(A) METEOROLOGICAL DATA

1 Elevation above mean sea level, m 12

2 Barometric pressure, mbar 1001.1 1008.6 1013.1

3 Ambient temperature, oC Tmin = 12 Tnor = -- Tmax = 40

4 Relative humidity, % 47 87

100% @ 32°C

5 Rainfall data : for 24 hours period, mm

Design intensity for surface water drainage

575.6

125 mm/hr

Wind data

(a) wind velocity

(b) wind direction

44 m/s

Per IS 875

Wind direction N E S W Calm NE SE SW NW

M 13 38 17 48 49 24 10 28 15 %age of time E 19 1 8 59 3 3 1 35 72

6

M : Morning 0830 hrs; E : Evening 1730 hrs.

(B) DATA FOR EQUIPMENT DESIGN

1 Design dry bulb temperature, oC

Coincident relative humidity % and temperature °C

42.0

100% @ 32°C

2 Design wet bulb temperature, oC 28

3 Low ambient temperature for MDMT, oC (unless otherwise specified) 10

4 Design air temperature for air cooled exchangers where followed by

water cooling, oC

42

5 Design air temperature for air cooled exchangers where not followed by

water cooling, oC

42

a) Coincident relative humidity, % and temperature °C for Air

Blower/ Air Compressor design (For Moisture)

100% @ 32°C 6

b) Design Temp. °C for actual inlet flow 42.0 °C

7 Earthquake Design Factor (Code IS-1893 Zone-III / Site spectra

whichever is governing)

8 Design ambient temperature for electrical equipment 42.0°C

Wind pressure shall be based on IS Code 875 (latest edition).

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5.0 DESIGN PLANT LIFE

5.1 The designer shall take a default plant operating life as 15 years with nil salvage value for

economic calculations.

5.2 The designer shall take default plant equipment design life as follows:

a) 30 years for reactors and associated separators.

b) 20 years for columns, vessels, separators, heat exchanger shells and similar services.

c) 10 years for piping and furnace tubes, for High Alloy exchanger tube bundles.

d) 5 years for Carbon Steel/Low Alloy heat exchanger tube bundles.

e) 20 years life for all rotating equipment.

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6.0 UTILITY SPECIFICATIONS

6.1 UTILITY CONDITIONS AT UNIT BATTERY LIMITS

Utility pressure and temperature levels, as made available at battery limits of a process unit,

are indicated in Table-6.1.

Table – 6.1 : Utility conditions at Unit battery limit

(All B/L pressures are as measured at grade)

Sr.

No.

Parameter Minimum Normal Maximum Mech

Design

1 VERY HIGH PRESSURE (VHP) STEAM

Pressure, kg/cm2(g) 36 38 40 44.0/FV

Temperature, °C 340 350 360 380

2 HIGH PRESSURE (MP) STEAM

Pressure, kg/cm2(g) 12.7 14.2 15.6 18.8/ FV

Temperature, °C 255 260 265 293

3 MEDIUM PRESSURE (MP) STEAM

Pressure, kg/cm2(g) 9.0 9.5 10.0 12.5/FV

Temperature, °C 235 240 245 273

4 LOW PRESSURE (LP) STEAM

Pressure, kg/cm2(g) 3.0 4.2 4.6 6.0/FV

Temperature, °C 145 Saturated 156 163

5 PURE CONDENSATE EXPORT (Note 4)

Pressure, kg/cm2(g) -------- ------ -------- --------

Temperature, °C -------- ------ -------- --------

6 SUSPECT CONDENSATE EXPORT(Note 4)

Pressure, kg/cm2(g) --------- -------- -------- --------

Temperature, °C -------- ------ -------- ---------

7 BEARING COOLING WATER (BCW)

Supply Pressure, kg/cm2(g) - 4.5 6.5 8.5

Return Pressure, kg/cm2(g) 2.5 - - 8.5

Supply Temperature, °C - 32 - 65

Return Temperature, °C - 39 - 65

8 SEA COOLING WATER (Note 1, 2)

Supply Pressure, kg/cm2(g) - 5.0 6.0 8.5


Supply Temperature, °C - 32 - 65

Return Temperature, °C - 45 - 65

9 PLANT AIR

Pressure, kg/cm2(g) 5.0 6.0 7.8 10.5

Temperature, °C AMB AMB 45 75

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Sr.

No.


Design

10 INSTRUMENT AIR

Pressure, kg/cm2(g) 5.0 6.0 7.3 10.5

Temperature, °C AMB AMB 45 75

Dew point @ atm pr °C (-) 40

11 FUEL GAS EXPORT

Pressure, kg/cm2(g) - 3.2 - 6

Temperature, °C - Amb-40 - 65

12 TYPICAL BH FUEL GAS (Note 5)

Pressure, kg/cm2(g) -------- -------- -------- --------

Temperature, °C -------- -------- -------- --------

13 TYPICAL RIL FUEL GAS (Note 5)

Pressure, kg/cm2(g) -------- -------- -------- --------

Temperature, °C -------- -------- -------- --------

14 TYPICAL GAIL /RLNG FUEL GAS (Note 5)

Pressure, kg/cm2(g) -------- -------- -------- --------

Temperature, °C -------- --------

15 TYPICAL REFINERY FUEL GAS

Pressure, kg/cm2(g) - 2.2 - 6

Temperature, °C - Amb-40 - 65

16 H2 RICH FUEL GAS FROM DHT UNIT (Note 6)

Pressure, kg/cm2(g) -------- 24.5 -------- --------

Temperature, °C -------- 46 -------- --------

17 HSFO (Note 3)

Supply Pressure, kg/cm2(g) 9.0 10.0 12.5 16.5


Supply Temperature, °C 150 155 165 260

Return Temperature, °C 150 155 165 260

LSFO (Note 3)

18 Supply Pressure, kg/cm2(g) 9.0 10.0 12.5 16.5


Supply Temperature, °C 150 155 165 260

Return Temperature, °C 150 155 165 260

19 DRINKING WATER

Pressure, kg/cm2(g) - 3.5 6.3 8.5

Temperature, °C - AMB AMB 65

20 SERVICE WATER

Pressure, kg/cm2(g) - 3.5 6.3 8.5

Temperature, °C - AMB AMB 65

21 BOILER FEED WATER

Pressure, kg/cm2(g) - 27.0 29.0 44.0

Temperature, °C - 110 120 180

22 DM WATER

Pressure, kg/cm2(g) 6.0 7.0 8.0 11.5

Temperature, °C AMB AMB AMB 65

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Sr.

No.


Design

23 NITROGEN

Pressure, kg/cm2(g) 5.0 6.0 7.0 10.5

Temperature, °C - AMB 45 65

Note 1 : Cement lined carbon steel piping is used for cooling water (sea water).

Note 2 : Water cooling to be minimised. Air-cooling to be maximized.

Note 3 : A fuel oil temperature is maintained consistent with viscosity of 20 cSt maximum at the

burner.

Note 4 : Pure Condensate and Suspect Condensate is to be segregated within ISBL.

Note 5 : For BH fuel gas, RIL fuel gas and GAIL/RLNG fuel gas, LEPCC contractor to specify

the conditions at which the gas is required, so that the natural gas system can be

designed accordingly.

Note 6 : In addition to possibility of hydrogen recovery from this gas, H2 rich fuel gas from DHT

unit is reduced to fuel gas condition and routed to fuel gas header. Escape route to

flare is provided.

6.2 STEAM & CONDENSATE SYSTEMS

6.2.1 The designer shall adopt this default philosophy towards sizing of equipment generating or

consuming steam:

(a) Steam turbine drives and ejectors shall be rated based on MINIMUM steam conditions

available at unit battery limits. (ISBL pressure and temperature drop to be considered).

(b) All other steam consuming equipment including heat exchangers shall be thermally rated

based on NORMAL steam conditions. However, LSTK contractor to verify the design for

minimum steam conditions also.

(c) All steam generating equipment shall be rated based on delivering steam at MAXIMUM

conditions to the header.

(d) NORMAL steam conditions shall be used for operating utility estimates, heat and material

balances and battery limit connectivity.

6.2.2 Condensate is segregated as follows:

Uncontaminated / Pure condensate: These are condensates originating from heat exchangers

having their minimum steam side pressure higher than the maximum process side pressure.

This means that even during a tube leak, possibility of contamination of condensate is remote.

Therefore, this condensate can be sent directly for steam generation without any need for

treatment in a condensate polishing unit.

Suspect condensate: These are condensates originating from heat exchangers having their

minimum steam side pressure lower than the maximum process side pressure. This means

that during a tube leak, contamination of condensate with process fluid will take place.

Therefore, the quality of this condensate needs to be checked before sending it to steam

generation.

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6.2.3 Condensate recovery will be maximized from process consumers. Pure condensate

generated in a facility will be considered as normally uncontaminated and will be directly

reused for steam generation.

Suspect condensate shall be treated in centralised condensate polishing unit before use in

refinery, if required. On line conductivity analyser with DCS alarms shall be provided in

condensate return header from each unit with in ISBL. Contamination detection by on-line

analyzers sensing conductivity and pH, with an option of automated drainage upon detection,

6.2.4 Condensate loss can be reduced in a number of ways, within unit battery limits.

In order to minimize the liquid effluent generation from the units, all condensate shall be

collected and effort shall be made to minimize condensate drain to OWS / storm water

sewer.

Condensate recovery from steam trap discharge, steam tracer discharge is not to be

considered. However condensate ex steam coils in tanks in unit battery limit shall be

recovered by connecting this consumer to condensate header only if recovery is more then 1

t/hr. Facility for draining of condensate from respective generation unit shall also be provided

to take care of emergencies.

6.2.5 Pure condensate recovery from consumer of steam shall be done by flashing the HP and MP

condensate to generate LP steam. LP steam may be used in the ISBL. Excess LP steam to

be connected to main LP steam header. Condensate from HP/MP flash vessel along with LP

condensate from LP steam users is flashed in an atmospheric flash vessel. Vent condenser,

preferably air cooler shall be provided on vents from atmospheric flash drum. Condensate

from flash vessel is pumped to unit battery limit.

Suspect condensate shall be flashed in an atmospheric pressure flash vessel. Suspect

condensate to be pumped to central condensate polishing unit. Vent condenser, preferably

air cooler, shall be provided on vent from atmospheric flash drum.

6.3 WATER SYSTEMS

6.3.1 The quality of boiler feed water, cooling sea water make-up water, fresh water are given in

Table 6.2 for process plants.

6.3.2 All cooling water consumers connected to recirculating sea cooling water system are to be

provided with backflush arrangement. The recommended Sea cooling water piping and

instrumentation arrangement is shown in Fig. 6.1.

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Fig 6.1 Typical Sea Cooling water piping and instrumentation at heat exchangers

TI

I

S

3” X ¾”

¾ ” X ½” ¾” LO

3” X ¾”

SS

CW RETURN

CW Backflush and drain line size upto 6” are same as line size. Above 6”, it is one size less than line size.

This connection to be provided for exchangers located at platform (18m or above)

SS

PSV 3” Tap-Off

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6.3.3 All pump / compressor bridle cooling water lines (for bearing cooling, gland cooling, seal

cooling) shall be minimum 1½” NB schedule 80. Recirculating bearing cooling water is

supplied from OSBL bearing cooling tower system. Fresh water is used as make-up for

recirculating bearing cooling water. Tapping should be taken from the top of the bearing

cooling water supply header. Closed system bearing cooling water returns through common

header within ISBL.

6.3.4 All laterals from Sea Cooling Water header must be from top of the header.

6.3.5 Bearing Cooling Water shall be used for sample cooler. For typical details refer P&ID No 44-

LK-5100-00-P-01 /0002 /A1 in Annexure II.

6.3.6 Quality of DM Water is indicated in Table 6.3 and quality of circulating sea water and

circulating bearing cooling water is reproduced in Table 6.4.

Table - 6.2 : Water Quality for Process plants

Sr.No. Parameter Boiler Feed

Water

Cooling Sea

Water

Make-up

Fresh Water

1 Turbidity, NTU (5min settled) 1000 (max) 5

2 pH 8.8-9.5 7.5-8.5 6.7-7.8

3 Total suspended solids, mg/l 3.2

4 Conductivity at 20 °C,

Microsiemens per cm

5 Total Dissolved solids, mg/l 30000-43000 120

6 M Alkalinity as CaCO3, mg/l 130 66

7 Ca Hardness as CaCO3, mg/l Nil 1000 48

8 Total hardness as CaCO3, mg/l 5950 30-80

9 Sodium as CaCO3, mg/l 9620 43

10 Total Silica (Reactive), mg/l 0.02 15 18-35

11 Colloidal Silica as SiO2, mg/l

12 Chloride as Cl, mg/l 19900 15-30

13 Free Chlorine, mg/l

14 F + Chloride, mg/l

15 Sulphate as SO4, mg/l 3819 2-17

16 SHMP (Sodium Hexa Meta

phosphate) as PO4, mg/l

17 HEDP as PO4, mg/l

18 Dissolved oxygen, mg/l 0.005 (max) 6.6 3-6.6

19 Total Iron as Fe, mg/l 0.01 (max) 0.01-0.5

20 Morpholine (residual), mg/l 2.01 (approx.)

21 TSP as PO4, mg/l 2.0 (approx.)

22 Total Iron as Fe, mg/l

23 KMnO4 value at 100 °C, mg/l 10 5

24 Total copper as Cu, mg/l 0.003 (max) 0.1 (max)

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Sr.No. Parameter Boiler Feed

Water

Cooling Sea

Water

Make-up

Fresh Water

25 Oil and Grease, mg/l Nil <1

26 KMnO4 consumption, mg/l

27 Total Cation/anion as CaCO3,

mg/l

99

28 Polymeric dispersant, mg/l

29 Zinc Sulphate as Zn, mg/l

30 Reactive Silica and SiO2, mg/l

31 Hydrazine (Residual), mg/l 1.0 (approx.)

32 COD, mg/l 3.5

33 Cation conductivity @ 25°C

micromho/cm

0.2

Table - 6.3: DM Water Quality

Table - 6.4: Circulating Sea water and BCW Quality

Sr. No. Parameter Circulating Sea

Water Cooling

Circulating

Bearing

cooling Water

1 TDS mg/l 36000-51600 480

2 Chlorides 22885-23880 mg/l 125 mg/l

6.4 COMPRESSED AIR & NITROGEN SYSTEMS

6.4.1 The specifications of plant air and instrument air are indicated in Table 6.5.

Sr. No. Parameter DM Water Utility

1 pH 6.5-7.0.

2 Total Hardness as CaCO3, wt ppm Nil

3 TDS, <0.1 mg/l

4 Conductivity, micromhos/cm < 0.2 @ 25 °C

5 Total Silica < 0.02 mg/l

6 Iron 0.01 as mg/l CaCO3 (max)

7 Turbidity formazine units < 1.0 NTU

8 Copper 0.003 mg/l (max)

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Table - 6.5: Plant Air & Instrument Air Quality

Sr. No. Parameter Plant Air Instrument Air

1 Dew Point at atmospheric pressure Water-free (-) 40 °C

2 Oil Content, ppm Nil Nil

6.4.2 Nitrogen specifications shall be as per Table 6.6 below :

Table - 6.6: Nitrogen Quality

Sr. No. Parameter Nitrogen Utility

1 Dew Point at atmospheric pressure (-) 100 °C max.

2 Oil Content, ppm Nil

3 Nitrogen purity, vol% 99.99% min.

4 Oxygen content, vol ppm 3 ppm max

5 Carbon dioxide content, vol ppm 1 ppm max

6 Carbon monoxide content, vol ppm 10 ppm max

7 Noble gases 86 ppm max

8 Other carbon compounds -

6.5 FUEL SYSTEMS

6.5.1 Liquid fuel system

Fuel oil is available as alternate fuel for fired heaters. There are two types of fuel oil (HSFO

and LSFO) in the refinery. Liquid fuel specification data is indicated in Table 6.8

Hot liquid fuel temperature shall assumed to drop by 5°C between unit battery limit and burner

manifold.

6.5.2 Fuel gas system

Fuel gas compositions for five different cases (BH gas, RIL gas, GAIL gas etc) are given in

Table 6.7.

6.5.3 Fuel gas liquid knockout drums and tracing for piping shall be:

a) Separate KOD for each process unit. Each KOD to have steam coils / tracing.

b) Fuel gas lines shall always be steam traced from KOD upto individual furnace burners.

6.5.4 In-line strainers on fuel gas / fuel oil and pilot gas are recommended in burner piping for each

unit. These shall be located not more than 20 meters upstream of the burner manifold and

shall be 1 on-line + 1 spare strainer with mesh size of 200 for Fuel Gas / fuel oil. All mesh

sizes are Tyler standard. Pilot gas line shall be provided with self actuated PCV. Pilot gas line

shall be in stainless steel (SS 304) downstream of strainer.

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Table - 6.7 : Fuel Gas Composition

Sr. No. Parameter

1 Name BH Gas RIL Gas Typical

Refinery

Fuel gas

H2 Rich

gas from

DHT Unit

RLNG/ GAIL

Gas

2 Operation Mode --------

3 Composition, mol% HOLD

Hydrogen 16.9 -------

Carbon Dioxide 2.0 1.0 -------

Carbon Monoxide -- -------

Oxygen 3.0 ------

Hydrogen Sulphide ------

Water ------

Methane / C1 84 80 (min) 11.8 ------ 90.3

Ethane / C2 10 10 (max) 24.5 ------ 6.0

Ethylene/ C2

Propane / C3 2 5.0 (max) 16.1 ------

Propylene/C3H6 0.7 ------ 2.1

i-Butane / C4 5.2

i- Butene , C4H8 ------ 0.4

n-butene/ C4H8 1.3 ------ 0.6

n-Butane / C4 0.5 Total

Butanes

3.0 (max)

7.4 ------

n-pentene, C5 H10 ------ 0.01

n-Pentane / C5 0.5 Total

Pentanes

2.0 (max)

0.8 ------

i-Pentane / C5 0.1 ---------

i-Pentene / C5H10 0.03

n-C6 -------

NH3 -------

N2 1.0 1.0 (max) 11.2 ------- 0.57

4 Molecular weight As

Calculated

--------- As

Calculated

5 Net heating value, kcal/kg 11038 9670 --------- 8983

Gross heating value,

kcal/Sm3

-------- 9869

6 S, wt ppm 40 10 (max) 100 -------- 20

7 Chloride, wt ppm --------

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Table - 6.8 : Fuel Oil Specification

Sr. No. Parameter HSFO LSFO

1 Name

2 Crude stock

3 Sp. Gravity @ °API 7.86 14.3

4 Sulphur content, wt% 1.2 0.33

5 Nitrogen content, wppm 2000 300

6 Nickel content, wppm 10 23

7 Vanadium content, wppm 5 5

8 Sodium content, wppm 81 230

9 Copper content, wppm

10 Iron content, wppm 9 4

11 Flash point, °C 250+ 250+

12 Pour point, °C 80 80

13 Viscosity @ burner tip °C, cSt

14 Viscosity @ 99°C, cSt 1396 2198 @40 °C

15 Viscosity @ 150°C, cSt 27 60 @ 100 °C

16 Temperature, °C required for 20 cSt

17 Initial boiling point @ 1 atm, °C

18 Conradson carbon residue, wt%

19 Ash content, wt% 0.2 wt ppm 0.2 wt ppm

20 Carbon:Hydrogen ration, wt:wt

21 Net heating value, kcal/kg 9500 9500

Note : Fuel oil temperature is maintained consistent with a viscosity of 20 Cst max at burner

tip.

6.6 FLARE SYSTEMS

6.6.1 There are two flare headers in refinery. Hydrocarbons released are routed to normal flare and

acid gases released are routed to acid flare.

6.6.2 Vapor releases of all molecular weights to be connected to flare system.

6.6.3 To comply with requirement of OISD Standard 106, the individual units shall be provided with

a flare knockout drum in addition to the main knockout drum at the flare stack. LSTK

contractor shall specify a horizontal unit flare KOD, sized to separate out liquid droplets down

to a size of 400 micron. The unit flare knockout drum shall be adequately sized for liquid relief

also. Sizing should be based on liquid relieving safety valve blowing for 20-30 minutes. The

liquids from flare KODs are routed to slop system.

Double block and bleed valves and blind shall be provided in the flare header at individual

units.

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Purge gas (Nitrogen) connection shall be provided in all dead ends of flare header in addition

to the normal fuel gas connection for purging. Nitrogen connection shall be with a rotameter to

monitor the flow.

6.6.4 Maximum flare backpressure shall be considered for sizing of pressure relief devices as given

in Table below :

Sr.

No.

Flare System Superimposed

Backpressure,

kg/cm2(g)

Built-up backpressure

at unit battery limit,

kg/cm2(g)

Total backpressure

in Safety Valve

Outlet, kg/cm2(g)

1 Normal Flare 0.1 1.4 1.7

2 Acid Flare 0.1 1.5 1.7

6.6.5 Overpressure (as percentage of set pressure) for sizing relief valves shall be as given in table

below :

Sr.

No.

Contingency Low pressures

< 70 kg/cm2(g)

High pressures

> 70 kg/cm2(g)

1 Steam Generator / Consumer 5% 5%

2 Fire case 21% As per designer

3 Thermal relief (Piping /

Equipment)

25% / 10% As per designer

4 Operational failure 10% As per designer

For Sr. Nos. 1 & 4, safety valves provided shall be of precision design.

6.7 LIQUID PUMPOUT & DRAIN SYSTEMS

6.7.1 Hydrocarbons drains

Connect equipment drains to buried closed blowdown (CBD) network, leading to a closed

blowdown drum. Design CBD system for 200 °C. CBD discharge shall be routed to slops tank

in offsite area.

Size of Buried Closed Blowdown drum shall be larger of the following:

Standard size of 10m3 for all units to cater to only residual drains.

OR

Individually sized for each unit for single largest equipment inventory.

CBD drum shall be provided with heating / cooling (by steam and beraing cooling water

respectively) coils. CBD drum shall be located in RCC pit and sand packed by Vibro

compression with lean concrete on top - 100 mm thick. Cathodic protection is not required for

the buried drum. Suitable paint to be provided. CBD pump shall be sized adequately to pump

out the liquid in maximum of 30 minutes. However, a pump of minimum 20 m3

/ Hr shall be

provided.

Pumpout from CBD drums shall be diverted to slop system..

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CBD lines are to be underground network with suitable flushing connections, if required.

6.7.2 Other Drains

a) Amine Systems

Individual units handling amine will be provided with separate buried amine closed

blowdown system from where amine stream will be pumped to regeneration unit via rich

amine line going out of the unit area.

Size of Buried Closed Amine System drain drum shall be larger of the following:

Standard size of 10m3 for all units to cater to only residual drains.

OR

Individually sized for each unit for single largest equipment inventory.

CAS drain drum shall be located in RCC pit and sand packed by Vibro compression with

lean concrete on top - 100 mm thick. Cathodic protection is not required for the buried

drum. Suitable paint to be provided. CAS pump shall be sized adequately to pump out the

liquid in maximum of 30 minutes. However, a pump of minimum 20 m3

/ Hr shall be

provided.

CAS lines are to be underground network.

b) Process sour waters

Process sour waters shall normally be routed to identified sour water stripper units.

Residual drains from instruments or during intermittent situation where unavoidable may

be drained to oily water sewer. The effluent treatment plant designer shall be advised to

incorporate provisions to receive the single largest stream of such sour water.

c) Acidic Wash Water

Acidic wash water from sources such as Air Preheater washing shall be routed to oily

water sewer. Provision for suitable neutralisation is to be explored.

6.7.3 Steam generated blow down drains

Flash MP and HP blow downs for recovery of LP steam. The LP steam vessel liquid to be

cooled in a cooling water exchanger to 40 °C and route the cooling tower sump through

pump.

6.7.4 Caustic Drains

All bulk caustic inventory drains shall leave process units under own pressure or be pumped

out. For residual caustic drains such as unpumpable vessel bottoms, level gauge drains etc,

collection of residual drains by temporary facility like drums and jars shall be adopted.

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6.7.5 Water drains

All process oily water shall be discharged to open funnels connected to oily water sewer

(OWS).

All other contaminated water drains including floor washings shall be routed to contaminated

rain water sewer (CRWS).

6.7.6 Exchanger Backwash

Sea water drains (back flush water from heat exchanger) shall have dedicated trench /

underground drain network within the ISBL area. The same shall be connected to sea water

trench / sewer at OSBL network.

OSBL sea water backwash trench / sewer shall be routed to treatment facility (oil removal)

prior to routing to storm sewer.

6.8 ELECTRICAL SYSTEMS

6.8.1 Voltage levels are:

TABLE - 6.7 : VOLTAGE LEVELS

Motor Rating Nameplate Voltage Phase Frequency

(Hertz)

From Through

0 kW 0.37 kW 240 + 10% V 1 50 ± 3%

> 0.37 kW 161 kW 415 ± 10% V 3 50 ± 3%

> 161 kW 6600 ± 10% V 3 50 ± 3%

Lighting : 240 V ± 6%, 50 HZ ± 3%

(single phase AC neutral grounded)

Instrumentation Main Power Supply : 110 V AC; 50 Hz from UPS

Power supply to Solenoid Valves & Field Switches : 24 V DC

6.8.2 Licensor shall specify reacceleration feature in some critical pump motor drives to ensure

faster start-up or to minimize plant down time in case of process disturbances due to

momentary voltage dips. Re-accelerations to be specified to cover brief interruptions upto 5

seconds in normal power supply.

In case of very large number of drivers requiring reacceleration facility, stage-wise grouping of

such drivers, depending upon permissible time of failure shall be provided by licensor. LSTK

shall review and finalize the same during detailed engineering in consultation with Owner and

PMC.

6.8.3 Emergency power supply may sometimes be stipulated to aid in safe shutdowns or to

minimize impact of normal power supply failure. Analysis of such emergency power supplies

usually leads to a requirement of reliable back-up source. Nominal requirements of

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emergency power such as for local panels, lube oil pumps, frame heating of compressors,

etc., can be then examined and suitably implemented.

a) Emergency lighting shall have DC supply

b) Licensor’s recommendations of emergency supply to critical drives to be followed

c) Emergency plant lighting shall be as per OISD standard

d) The load shedding logic and procedures are to be considered in the design for easy

and effective control of power and steam load shedding.

e) Cabling (LT/HT) will be done on overhead cable trays in unit and offsite areas.

However, LT & HT cables shall be laid in separate trays.

6.8.4 Duration of back up power required for safe shutdown of plant shall be as per licensor’s

recommendations.

6.9 FLUSHING OIL SYSTEMS

6.9.1 Normal Flushing Oil (NFO)

This is usually gas oil or procured diesel, charged to a header at a moderate pressure, for

flushing out equipment and piping handling congealing liquids. FLO is stored in offsites, either

separately or combined with product storage.

When also used as external flush for pump API seal plans, or for purging instruments in

congealing service, FLO needs to be boosted, the pressure being finalised during detailed

engineering.

6.10 OTHER UTILITY SYSTEM CONSIDERATIONS

6.10.1 Drinking water

Drinking water is made available at unit B/L.

Drinking water is fresh water & to be used for eyewash, safety showers, which are located

strategically in unit areas

6.10.2 Service water

Service water is made available at unit B/L.

Service water is fresh water & to be used for equipment flushing, calibration, floor washing,

cleaning etc.

6.11 Caustic storage, preparation and distribution:

a) Fresh caustic receipt

The required quantity of caustic shall be received and stored in a storage tank located in a

centralised non-process area.

b) Fresh caustic preparation

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Caustic of highest concentration required for the units shall also be prepared in the same

area as above. This caustic is pumped to all consuming units and separate solution making

arrangement shall be provided in respective units if a unit requires lower strength.

c) Fresh caustic distribution

Pumped from central storage area directly to consuming units, whether needed

continuously pr needed in batches.

d) Caustic handling equipment shall be of carbon steel construction and stress relieved

whenever required for the operating temperatures selected.

e) It is recommended that spent caustic generated in unit areas, after contacting with light

hydrocarbons, shall degas the stream in an atmospheric vessel floating with flare header

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7.0 GENERAL DESIGN PHILOSOPHY

7.1 ENERGY INTEGRATION

7.1.1 Improvement in overall energy efficiency shall call for unit-level and total plant-level

optimization of energy. Designer of a particular unit shall indicate the following at the outset of

design activities:

(a) The total energy consumption expressed as equivalent fuel oil (Btu/bbl or FOE%)

(b) The preferred temperatures for hot feeds and products from an energy integration

standpoint, if these are significantly different from that stipulated in unit BEDB.

The following shall be considered while optimizing the energy consumption,

(a) Energy shall be preferentially recovered into process streams. Steam generation shall be

considered thereafter to recover excess available energy. Steam generation levels shall

be chosen to preferably match the corresponding steam level demand within unit.

(b) Low-level energy recoverable for external consumption, say, for Boiler Feed Water

preheat serving other units.

7.2 VACUUM DESIGN CONSIDERATION

7.2.1 Vacuum design conditions shall be stipulated for:

(a) Equipment operating normally under vacuum conditions

(b) Equipment that are subjected to vacuum conditions during start-up, shutdown,

regeneration or evacuation

(c) Liquid full vessels or heat exchangers that can be blocked in and cooled down

(d) Distillation columns / towers and associated equipment which may undergo vacuum

condition due to loss in heat input is to be designed for full vacuum.

(e) All steam users consuming steam during normal operation and condensate vessels.

(f) Pressure vessels containing liquids having vapour pressure at minimum ambient

temperature less than atmospheric pressure.

(g) All equipment, except storage tanks, where steam out conditions are specified.

(h) Special consideration to be given (for vacuum design) to the design of vessels normally

subjected to internal pressure and connected to compressor suction.

7.3 FEED, INTERMEDIATE AND PRODUCT STORAGE

The storage systems for feed, intermediate and products shall be designed based on Owner/

Licensor requirements.

The specific requirements, if any, for the tanks e.g. type, blanketing; lining etc. shall be

furnished.

7.4 AROMATICS HANDLING

7.4.1 Special precautions could apply towards handling process streams containing aromatics.

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Following threshold values are to be used for applying the special precautions.

(a) Benzene content greater than 1% weight.

(b) C6 through C9 aromatics greater than 25 % weight

7.4.2 The design and equipment provisions toward special precautions shall be:

(a) Closed Sampling points and associated piping as defined in standard legend P&ID

(b) Dual mechanical seals for pumps

(c) Connecting the following to the unit closed blowdown system:

− Drains from vessels, pump, level instruments, control valve

− Drains of equipment which can be isolated for maintenance

7.5 METALLURGY

7.5.1 Metallurgy shall be specified by respective unit designer based on process considerations.

Piping metallurgy and metallurgy for instrumentation shall follow an unified overall Piping

Material Specification (PMS).

7.5.2 For cooling mediums for heat exchangers, metallurgy can be selected for either long tube life

at a higher initial cost or for shorter tube life at a lower initial cost with up gradations being

decided in the course of operating the plant. In specific cases superior metallurgy is dictated

by considerations such as seawater cooling, compatibility with NACE MR-01-75, etc., and

shall be as per designer. The minimum metallurgy preferred is:

Type of Service Cooling Water (Sea water)

Tube Duplex SS

Channel & Channel Cover Duplex SS

Tube Sheets Duplex SS

Floating Head Duplex SS

Baffles, Support plates, etc. Duplex Stainless Steel alloy

7.5.3 As a default all steam tracers shall be as per Piping Material Specification.

7.5.4 Preferred metallurgy for console lube oil cooler is stainless steel.

7.6 CORROSION ALLOWANCE

7.6.1 Minimum Corrosion allowances shall be as follows or as specified by Licensor (whichever is

higher)

Sr.

No.

Service Default

1 Carbon Steel pressure vessels 3.0 mm

2 Carbon Steel atmospheric vessels 3.0 mm

3 Alloy Steel vessels 1.5 mm

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4 Stainless Steel vessels nil

5 Clad / lined vessels 3.0 mm clad thk min.

6 Carbon Steel / LAS Exchangers 3.0 mm

7 Carbon Steel storage tanks Shell 1.5 mm

Roof 1.0 mm

Bottom most shell course & Bottom plate 3.0 mm

8 Column Trays, CS 1.5 mm on both sides 5 mm

SS410S 1.0 mm on both sides 5 mm

SS 0.5 mm on both sides 5 mm

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8.0 EQUIPMENT DESIGN PHILOSOPHY

8.1 OVERDESIGN PHILOSOPHY

Deleted

8.2 SELECTION OF MECHANICAL DESIGN CONDITIONS

Equipment and piping systems shall be designed for the most stringent coincident

temperature and pressure conditions, accommodating the maximum expected working

pressure and temperature without causing a relieving condition. The design shall be such that

instrument safeguarding systems or availability of emergency power or steam are not relied

upon for overpressure protection. Abnormal conditions shall be evaluated considering a

single contingency. A double or multiple contingencies shall not be considered, but, if one

failure is a result of another failure, both failures are to be considered as one contingency.

Guide for "Pressure relief and depressurizing systems", API RP 521 (latest edition) shall be

followed for evaluating failures.

8.2.1 Mechanical design pressure for pressure systems

Mechanical design criteria laid down in this section shall be followed as standard.

8.2.1.1 A pressure system protected by a pressure relief device connected to the flare system, shall

have a mechanical design pressure, calculated at the location of the relieving device, as the

higher of the following :

− i) For operating pressures above 70 kg/cm2(g), mechanical design pressure

shall be as per designer and as permissible by applicable codes.

ii) For operating pressure upto and including 70 kg/cm2(g), design pressure shall be

the highest of the following:

− Maximum operating pressure (kg/cm2(g)) x 1.1

− Maximum operating pressure + 2.0 kg/cm2

− 3.5 kg/cm2(g)

8.2.1.2 The design pressure calculated as per 8.2.1.1 is at the location of the relieving device such

as the top of a vertical vessel. The design pressure at the bottom of the vessel and of

associated pieces of equipment shall be determined by adding applicable maximum

operating liquid heads and pressure gradients.

8.2.1.3 Vessels operating under vacuum shall be, in general, designed for an external pressure of

1.033 kg/cm2(a) and full internal vacuum, unless otherwise specified. Vacuum design

stipulations shall be as per Clause 7.2.

Vacuum equipments shall be designed additionally for water filling /LP steam flushing.

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8.2.1.4 Emergency vacuum pressure of 0.4 kg/ cm2(a) can be considered by designer based on the

process requirements and assessment of transient operations.

8.2.1.5 For full liquid system at the discharge of a centrifugal pump, the mechanical design pressure

shall be as under :

Pdes = P max suction + ∆P max where,

Pmax suction = Maximum pressure at suction vessel bottom during suction

system relieving conditions (as per 8.2.1.2)

∆P max = Pump differential pressure at pump shutoff head

with maximum operating density. If not known:

∆P max = 1.3 x ∆H x ρ max : constant speed pump

∆P max = 1.1 x 1.2 x ∆H x ρ max : variable speed pump

∆P max = 1.3 x ∆H x ρ max : high head multistage pump

∆P max = 1.3 x 1.1 x ∆H x ρ max : Variable speed high head

Multistage pump

8.2.1.6 For a full liquid system at the discharge of a positive displacement pump, the mechanical

design pressure shall be the higher of:

P des = Prated discharge + 2 kg/cm2

P des = 1.1 x Prated discharge

8.2.1.7 For shell-and-tube heat exchangers, the low pressure (LP) side of exchanger, including

upstream and downstream system equipment, shall be preferably specified with a design

pressure at least equal to 10/13 of high pressure (HP) side design pressure, in order to avoid

having to install a pressure relief device on the LP side. The 10/13 criteria shall necessarily be

adhered to when:

(1) LP fluid is on the tube side.

(2) Relief discharge cannot be connected to flare header owing to nature of fluid.

(3) Relief discharge is two-phase and cannot be connected conveniently to a low

pressure destination with free-draining piping.

(4) Liquid relief cannot be connected to a closed blowdown system.

(5) When the 10/13 criteria calls for an increase by less than a factor of 1.5 of the

mechanical design pressure of the LP side as would be calculated from normal

estimation procedures.

However, based on process considerations and designers own practice, heat exchanger can

be designed without upgrading design pressure by providing tube rupture pressure relief

valve after getting consent on case to case basis from Owner / PMC.

For feed / effluent exchanger, the tubesheet and tubes in high pressure service need not be

designed for full design pressure of the shell and / or channel provided these components can

never experience these conditions. The same should be designed for maximum differential

pressure expected. Designer must consider start-up, shut-down and emergency

depressurising while deciding maximum differential pressure.

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In cases where shell side pressure is very low compared to tube side, for subsequent testing

of tube bundle, additional facility like spare shell for testing shall be considered.

8.2.2 Mechanical design pressure for storage tanks and atmospheric vessels

8.2.2.1 Design pressure of storage tanks shall be in accordance with latest editions of API-620, API-

650 and API-2000 (latest editions), as appropriate.

8.2.2.2 Blanketed storage tanks shall have a blanketing pressure of 150 mm WC, unless a higher

pressure is deemed necessary from process considerations. The design pressure of

blanketed storage tanks shall be determined to allow adequate overpressure for outbreathing

and emergency relief devices. The blanketed tanks shall also be designed for 50 mm

vacuum.

8.2.3 Mechanical design temperature

8.2.3.1 For systems operating at or above 0°C, the mechanical design temperature shall be the

higher of the following:

T des = 65 °C

T des = T Max. + 28 °C

T des = T relief (excluding fire relief temperatures).

Where

T max = Maximum operating temperature expected considering different possible

operations for the equipment or system, including start-up, regeneration,

air drying or gas drying conditions, etc.

T relief = Temperature corresponding to pressure relieving conditions for an

operational failure case (specifically excluding fire relief case)

8.2.3.2 For systems operating below 0°C, the mechanical design temperature shall be equal to the

lowest anticipated operating temperature.

8.2.3.3 For pressure vessels storing refrigerants or liquefied hydrocarbons at ambient temperature,

the design temperature (based on depressurization) shall correspond to the coincidental

design pressure when this lowest temperature is reached. The coincidental design pressure

can be different from the maximum design pressure specified for the vessel depending upon

the system under consideration. However, if this calls for a change in metallurgy, then fool

proof strategy to be devised to avoid the situation. Otherwise select the metallurgy to suit the

minimum temperature.

For heat exchangers, consideration should be given to possible failure of cooling medium

and resultant impact of higher temperature on tubes, tubesheets and floating head (inlet

maximum temperature). The design temperature is highest anticipated temperature in such

an event.

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8.2.4 Steam-out conditions

Vessels provided with steam out conditions shall be designed for the following steam out

conditions when LP Steam is considered adequate:

(a) Pressure = 0.5 kg/cm2(g) and full vacuum

(b) Temperature = Maximum LP Steam Temp. = 156°C

8.2.5 Storage tank bottoms shall be insulated using foam glass or similar material if operating

temperature is more than 100 °C and lower than 0 °C.

8.2.6 Minimum Design Metal Temperature (MDMT)

Designer shall specify MDMT. Ambient temperature data are as per Clause 4.

8.3 HEAT EXCHANGERS

8.3.1 Selection of Shell and Tube heat exchangers

8.3.1.1 Floating Head type exchanger is preferred construction in refinery service. The use of fixed

tubesheet heat exchangers shall be minimized to the extent possible. These can be used in

limited services such as vertical thermosyphon reboilers where steam is on shell side. Steam-

out conditions shall be specified for fixed tubesheet heat exchangers, considering either shell-

side or tube-side being steamed out at one time. Start-up and upset conditions for fixed

tubesheet exchangers to be specified as well.

Double pipe and multitube heat exchangers are not preferred.U- Tube bundles are also not

preferred.

8.3.1.2 The exchangers can be stacked considering the size of exchangers, equipment layout and

approach for operation and maintenance.

Stack upto 3 shells when shell diameters are less than 1000 mm and individual shell isolation

and bypasses are not provided. For other cases, limit stacking to 2 shells.

8.3.1.3 General criteria for selection of TEMA type of exchangers is :

Shell side fouling resistance

(Hr-m2-oC/Kcal)

Tube side fouling

resistance (Hr-m2-oC/Kcal)

TEMA type (preferred)

>0.0002 >0.0002 Floating head

≤0.0002 >0.0002 Fixed tube sheet

>0.0002 ≤0.0002 U tube bundle

≤0.0002 ≤0.0002 Fixed tube sheet / U tube bundle

OR as specified by licensor.

8.3.1.4 All shell and tube heat exchangers in a refinery application shall follow TEMA- R unless

required otherwise. Preferred exchanger type for refinery services shall be horizontal, single

pass shell, floating head tube bundle (TEMA type 'S') arranged with two or more tube passes

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per shell. Tube layout shall be square or rotated square for fouling services and triangular

pitch for clean services. Fouling factor > 0.0002 Hr m2 °C / kcal is defined as dirty service.

8.3.1.5 General criteria for specifying U-tube construction is :

− Services where steam is condensed or generated on tubeside; tube pitch shall be

triangular if shell side fluid is clean and square / rotated square if shell side fluid is fouling.

− TEMA type B stationary head: hydrogen services or when steam or other clean fluid is on

tube side, not requiring cleaning.

− TEMA type A stationary head when tube side fluid is cooling water or similar process

fluids, requiring cleaning

− TEMA type B or C stationary heads shall not be used when design pressure is higher

than 140 kg/cm2 (a). Tubesheet shall not be full diameter extended type when TEMA type

B stationary head is used.

− For U tube bundles, consideration shall be given for hydrotesting of tubes for IBR/normal

testing after preventive maintenance. If necessary, dummy shell shall be designed for

testing for maintenance purpose.

8.3.1.6 For design of coolers and condensers, consider normal cooling water conditions. (Table 6.1).

8.3.2 Selection of air-cooled heat exchanger

8.3.2.1 Air-cooled heat exchanger thermal design is as per ambient temperatures specified in Clause

4.1 (B).

8.3.2.2 Air cooled heat exchange is to be maximized except for specific intermittent services or small

cooling duties where air-cooled exchanger is not justified. The lowest process stream outlet

temperature for air cooled exchanger shall be

Air cooled exchanger not followed by water cooling :55

Air-cooled exchanger followed by water cooling: :65

However, to avoid small trim cooler or air cooler, these guidelines can be relaxed.

8.3.2.4 Forced draft fans are preferred for air cooled heat exchangers. Natural draft air cooled

exchanger can be considered if found warranted, when fan cooled or water cooled

exchanger has specific problem in an application.

However, for low approach temperature, less than 8 °C, induced draft fan shall be used in

consultation with owner / PMC.

8.3.2.5 Fan blades in Aluminium are preferred.

8.3.2.6 .Louvers with hot air recirculation and steam coils are to be provided for winterizing

requirements or for highly congealing service air cooler.

8.3.3 Preferred sizes for shell and tube exchangers with removable bundles

Tube length : 16 ft

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Maximum shell diameter : 5 ft

Maximum tube bundle weight : 12000 kg

Preferred tube dimensions (Note: For high pressure application tube thickness may be

increased):

Tube

Metallurgy

CS / Low Alloy

(upto and

including 5 Cr,

½ Mo)

Stainless

Steel

(above 5 Cr,

½ Mo)

High Alloy

Steel

Non –Ferrous

(Admirality,

Cu-Ni etc)

Super High

alloy (Inconel ,

Titanium etc)

Tube dia 1”if fouling

factor >0.0004

m2.hr °C/

Kcal.

¾” if fouling

factor ≤

0.0004 m2.hr

°C/ Kcal

1”if fouling

factor >0.0004

m2.hr °C/

Kcal.

¾” if fouling

factor ≤

0.0004 m2.hr

°C/ Kcal

1”if fouling

factor >0.0004

m2.hr °C/

Kcal.

¾” if fouling

factor ≤

0.0004 m2.hr

°C/ Kcal

1”if fouling

factor >0.0004

m2.hr °C/

Kcal.

¾” if fouling

factor ≤

0.0004 m2.hr

°C/ Kcal

1”if fouling

factor >0.0004

m2.hr °C/

Kcal.

¾” if fouling

factor ≤

0.0004 m2.hr

°C/ Kcal

Tube thk. 12/14 BWG 14/16 BWG 14/16 BWG 14 /16 BWG 18/20 BWG

Tube thk

(IBR)

13 BWG 13 BWG 13 BWG

8.3.4 Preferred location / sizes for Air-cooled exchangers

Air coolers may be located on pipe-rack or platform structures.

Air-cooled exchanger tube length to be used depends upon pipe-rack width / equipment

layout. Standard lengths are 8.5 m, 10.5 m and 12.5 m.

Air cooled exchanger bundle width : 3.2 meters (4.0 meters maximum)

Preferred tube dimensions:

Tube Metallurgy CS / LAS SS Alloy

Tube dia. 1” 1” 1 “

Tube thk. 12 BWG 14 BWG 14 BWG min.

Fin height 16 mm / 12.5 mm 16 mm / 12.5 mm 16 mm / 12.5 mm

Type of Fin Al; ‘G’ type upto

design temperature of

400 °C.

Above 400 °C, Welded

CS to be used.

Al; ‘G’ type upto

design temperature

of 400 °C.

Above 400 °C,

Welded CS to be

used.

Al; ‘G’ type upto

design temperature

of 400 °C.

Above 400 °C,

Welded CS to be

used.

Max. No. of fins 11 per inch for Al_G

type

6 per inch for Welded

CS type

11 per inch for Al_G

type

6 per inch for

Welded CS type

11 per inch for Al_G

type

6 per inch for

Welded CS type

Tube length 8.5 / 10.5 / 12.5 m 8.5 / 10.5 / 12.5 m 8.5 / 10.5 / 12.5 m

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Type of headers:

Plug header shall be provided if any of the following condition exist:

1. Hydrogen partial pressure > 7.0 kg/cm2(a)

2. Service with fouling factor < 0.0004 Hr. m2 °C/kcal

3. High pressure over 50 kg/cm2(g)

Otherwise cover headers are to be provided.

If interpass temperature difference exceeds 110°C or if inlet temperature exceeds 180°C, split

headers shall be used.

Minimum slope of 10 mm / meter shall be provided for single pass exchangers.

8.3.5 Grouping of Air-cooled exchangers

Large air-cooled exchangers shall be divided into sections and 2 nos (min) fans to be sized

and provided in each section. Air-coolers, which are smaller than section size, and without

any control arrangement can usually be grouped into one section and provided with a

common set of fans (for similar service), unless the designer has an over- ruling

consideration. However, air coolers provided with control arrangement cannot be combined

together.

8.3.6 Fouling factors

8.3.6.1 Fouling factors for process streams

Fouling factors for process streams are decided by licensor / designer based on past

experience and good design practices. However, specific requirements of Owner are

addressed in individual unit design basis document.

8.3.6.2 Fouling factors for utility streams :

The following default fouling factors for utility streams are to be considered.

Cooling Water (Sea water) : 0.0004 hr-m2-°C/kcal

Cooling Water (Bearing CW) : 0.0004 hr-m2-°C/kcal

Steam : 0.0001 hr-m2-°C/kcal

8.3.7 Tube-side velocities

It is a good practice to recommend specific tube side velocities for better on-stream factors of

heat exchangers in fouling services. Cooling water flow rates are normally not expected to be

turned down during operation and can be designed for a velocity constraint applied only for

normal flow.

Minimum tube side velocity for cooling water shall be 1.0 m/sec at normal flow. Process fluid

velocities are to be specified by licensor / designer considering the nature of fluid, e.g.

viscous, fouling, slurries etc. Velocity ranges shall be specified in unit Design Basis.

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8.3.8 Fin fan control Scheme

When fluid outlet temperature requires to be controlled (whether automatic or regulated

manually, say, for seasonal climatic variation) or when stipulated to conserve power, 50 % of

fans in a section of an air cooled exchanger bay shall be specified wih variable speed type as

a default.

High vibration alarm and trip switches shall be provided on fans. Running indication shall be

provided to control room.

8.3.9 Condensate control for steam consumers

For steam flows upto 1000 kg/hr to a steam-heated exchanger, steam traps shall be

considered for condensate removal. For larger consumers, condensate shall be collected in a

pot provided with a level control valve for condensate withdrawal. The condensate pot top

elevation shall be 300 mm lower than the exchanger bottom tangent line unless warranted

otherwise from a process control scheme consideration.

8.4 FIRED HEATERS

Fired Heater design shall be as per API-560 (Latest edition).

8.4.1 Selection of fuel

Fired heaters shall be designed for continuous operation with 100% firing

On either any of the fuel oil (as indicated in Table 6.8 ) or any of the fuel gases (as indicated

in table 6.7 ) or any combination of both unless constrained to reject use of fuel oil from the

reasons in process.

Or

100% firing on any of the fuel gases (as indicated in Table 6.7) for heaters less than 1.5

MMkcal/hr.

8.4.2 Target efficiencies

Achievable fired heater efficiencies depends on service, process temperature, furnace heat

duty and quality of fuel. Highest target efficiencies shall be pursued by an unit designer, as

found economically justifiable. Options such as cast tube and glass tube air preheaters,

HP/MP steam generation and superheat etc. shall be evaluated.

For heat duty below 7 MMKcal/hr, no air preheater shall be used. For heat duty >= 7 and < 20

MMKcal/hr on board air preheater shall be selected. For heat duty above 20 MMkcal/hr,

outboard air preheater shall be selected.

Target efficiency shall be: 92% on fuel gas and 90% on dual fuel firing.

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Excess air shall be considered as shown in table below for calculating the efficiency.

However, hydraulic design of flue gas duct and stack to be suitable for 40% excess air.

Excess air % Fuel oil Fuel gas

Natural draft 25% 20%

Forced draft 20% 15%

8.4.3 Combustion Air

Recommended combustion air configuration for forced-draft (FD) heaters is considering each

FD fan sized for 100% capacity but with both running normally at 50% capacity. Failure of one

FD fan shall cause the other fan to switch over to 100% load. Capacity control of fans shall be

through hydraulic fluid coupling for wattage upto 100kw and variable frequency for higher

wattage. Both fan failure shall result in heater shutdown and no stipulations shall be made for

automatic switchover to natural draft operation. Cold air bypass will be provided and heater

specifications shall allow operation at 100% normal duty with APH bypassed.

Additional Temperature indicator shall be provided to measure hearth temperature.

Spare induced-draft (ID) fans shall not be provided. Failure of ID fans shall cause APH

bypass to open to divert flue gas to the stack. Hydraulic coupling shall be used for capacity

control of ID fan upto 100 KW and variable frequency drive for higher wattage.

8.4.4 Detail heater design shall have provision for coil purging, snuffing steam and water washing

of FD fan impellers and out-board air preheaters.

8.4.5 Heater stack

Stacks shall be individually mounted on each heater unless there are considerations such as grade-

mounted APH or combined APH system for a group of heaters.

8.4.5.1 Minimum fired heater stack height shall be as 60 m.

Stack height using formula H = 14 (Q) 0.3

(where, H is stack height, meters and Q is total SO2

emission, kg/hr) shall also be calculated and if it is higher than that indicated above, same

shall be adopted.

8.4.5.2 For pollution monitoring, 6" NB size (with 1” inside lining) sampling nozzle shall be provided

on the stack as per Central Pollution Control Board guidelines:

4 nozzles for stack diameter > 2m.

2 nozzles for stack diameter ≤ 2.0 m.

Manual sampling point line extension to be brought upto furnace arch level.

Two port holes shall be provided in stack opposite to each other for measuring OPACITY of

flue gases by installing OPACITY meter.

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For sampling provisions on heater stack, refer fig. 8.1

8.4.6 Soot Blowers:

Soot blowers shall be specified for studded convection section of fired heaters having fuel oil

firing or combination firing. These shall be long retractable type, with single electric motor

drive having medium pressure steam as the motive medium, to be operated once every 8-

hour shift for best results.

Operation of soot blower can be either from automatic sequential panel at grade or through

local push buttons at each soot blower. Facilities shall be provided for manual retraction of

lance in case of motor or power failure and for bypassing any soot blower. Operating platform

will be provided to have access to each soot blower and controls.

8.4.7 Burners :

- Burners shall be Low NOx type with emission limit of 250 mg/Nm3 for gas burners

and 350 mg/Nm3 for oil burners.

- Turndown shall be 5:1 for fuel gas firing and 3:1 for oil firing, subject to confirmation

from burner vendor.

- Continuous self-inspirating, fuel gas fired pilot shall be specified for each burner.

Provision of high tension, high energy portable igniters shall be kept.

- Pilot burners shall not be automatically shut-off on main fuel failure. The metallurgy of

pilot gas line from the FG header shall be stainless steel.

- The noise level when all of the burners are firing at 100 % capacity shall be limited to

85 dBA.

- Burners shall be specified for operation at the following excess air levels also (in

addition to excess air levels to be used for heater design).

Fuel Oil Fuel Gas

Natural draft 15% 10%

Forced draft 10% 5%

- M.P. Steam to be considered for atomizing medium

- Minimum height of burner plenum from grade shall be 2000 mm

- Flame scanners to be provided for main flame burners and ionization rods to be

provided for pilots..

8.4.8 Convection section tube type preferred is finned tubes for gas firing and studded tubes for fuel

oil / duel firing. Studded tubes wherever provided should have soot blowers / manual steam

blowing provision through drop-out doors.

Convection banks for BFW preheating, steam generation and steam superheating shall be

designed for dry run condition.

Following outside fouling factors are to be considered for sizing convection tubes:

Gas fired = 0.001 hr m2 °C/ Kcal

Oil fired = 0.002 hr m2 °C/ Kcal (for viscosity <20 cst @150 °C)

Oil fired = 0.003 hr m2 °C/ Kcal (for viscosity >20 cst @150 °C)

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8.4.9 On line oxygen analyzer to be provided below convection section. Analysers for SOX, NOx,

hydrocarbon, carbon monoxide and SPM shall be provided above stack damper.

8.4.10 Return Bends

Return bends are preferred choice. Bends for the radiant section shall be inside firebox for

vertical cylindrical heaters and inside header box for Cabin Heater. Same shall be inside

header box for convection section.

Requirement of plug headers shall be specific to furnace service and will be given in Design

Basis of respective unit.

Steam to coils (if desired) connection should either be provided at the return bends at

convection inlet or convection outlet to radiation inlet at the convection header box.

8.4.11 Air Preheating Section

Air preheater shall be sized considering flue gas temperature entering APH at 25°C higher

than flue gas temperature leaving top of the convection section. 10% overdesign margin on

air and flue gas circuit shall be considered for sizing of cast / glass air preheaters.

8.4.12 Refractory

Following refractory specification shall be preferred for radiant section lining.

Radiant section: Ceramic Fiber

Arch: Ceramic Fiber

At the areas of high turbulence, ceramic fiber top layer shall be provided with rigidisers.

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FIGURE 8.1

TYPICAL SAMPLING PROVISION ON HEATER STACK

SAMPLING PORTS A. 2 PORTS, 90

o W / DIAMETER

LESS THAN 3M + PORT LENGTH 4 PORTS 90

o APART W / DIAMETER

OVER 3M + PORT LENGTH

PORT DIMENSIONS REQUIREMENTS 0.05M MIN. 0.2M MAX. UNLESS GATE VALVE INSTALLED 0.1M ID(MIN)INDUSTRIAL FLANGE CAPPED WHEN NOT IN USE INSTALL GATE VALVE IF STACK CONTAINS DANGEREROUS GASES OR GASES OVER 200

OF UNDER POSITTIVE PRESSURE.

STRENGTH REQUIRMQNT

AT LEAST TWO STACK DIAMETERS BELOW STACK EXIT

23 kg SIDE LOAD 23 kg RADIAL TENSION LOAD

91 kg VERTICAL SHEAR LOAD 105 kg M MOMENT

ATLEAST ONE STACK DIAMETER PLUS

0.9 M FROM STACK CIRCUMFERENCE

ATLEAST EIGHT STACK DIAMETERS ABOVE LAST OBSTRUCTION

CLERANCE ZONE

WORK AREA CLEARANCE

WORK PLATFORM

POWER SOURCE

A. ATLEAST 1M WIDE (1.2 M WIDE FOR STACKS WITH 3M OR GREATER ID) AND CAPABLE OF SPPORTING 3 PEOPLE AND 91KG OF TEST EQUIPMENT.

220 V 15A SINGLE PHASE 50 HZ AC. LOCATED ON PLATFORM

B. SAFE GUARDRAIL ON PLATFORM WITH ACCESS BY SAFE LADDER OR OTHER SUITABLE MEANS. IF LADDER IS USED LADDER MUST BE LOCATED AT LEAST 1M FROM PORTS.

C. NO OBSTRUCTIONS TO BE

WITHIN 1M HORIZONTAL RADIUS ON PLATFORM BENEATH PORTS.

(OUTSIDE)

1.2 M

(INSIDE)

GUARD RAIL

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8.4.13 Standard fired heater piping & instrumentation: Refer standard fired heater Air P&IDs (P&ID

Nos. 44LK5100-00/P.01/0003/A1 (2 sheets), 0004 and 0005) which are attached in Annexure

1. Following requirements are to be considered:

a) Low-Low fuel oil supply pressure shuts down fuel oil supply and return.

b) Low-Low fuel gas pressure shuts down fuel gas supply but keeps pilots running.

c) Low-low heater pass flow shuts down fuel oil and fuel gas but keeps pilots running.

d) Low-Low differential pressure between atomizing steam and fuel oil shuts down fuel

oil supply and return.

e) Failure of both the FD fans shut down fuel oil (supply and return) and fuel gas but

keeps pilot running-

f) High high furnace box pressure opens stack damper, shuts down fuel oil (supply and

return) & fuel gas and trips pilot & ID fan.

g) Emergency shutdown shuts down fuel oil and fuel gas as well as pilots.

h) Emergency coil steam, manual or automated, depending on criticality to be provided

with SDV.

i) Draft gage connections at: Burners, Below convection, Above and Below stack

damper. Indications to be provided in control room. Separate draft gauges shall be

provided at each location.

j) Flue gas sampling connections at: Below convection section, Above stack damper

i) Temperature measurement connections below convection section, below stack

damper, at hearth level, at APH inlet & outlet. Temperature measurement is also

required above dampers in case of ID/FD fan configuration.

j) Coils having horse shoe type bend shall be flanged at their terminal connections, like

cross-overs and furnace inlets / outlets.

k) Adequate number of flanged connections shall be provided for steaming out, water

freeing, steam air decoking (where applicable) and chemical cleaning. For chemical

cleaning, stubs with valves for draining to be provided.

n) Minimum metallurgy in hydrocarbon coils in heaters shall be 5 Cr, 1/2Mo.

o) Generally ceramic fibre modules /blankets shall be considered for heater insulation

for subsequent ease of maintenance unless otherwise not possible due to high flue

gas draft.

p) Painting of stack shall be suitable for 8-10 yrs of maintenance free operation.

q) Pad type skin thermocouples shall be considered for measuring temperature of

furnace tubes (for each pass).

All Licensors and Engineering Contractors shall follow the OISD guidelines while developing

the heater P&IDs as a minimum.

8.4.14 Coke thickness for hydraulic calculations

Coke laydown shall take place in fired heaters handling hydrocarbons containing coke

precursors. Heater tube diameter selection and hydraulics shall take cognisance of this in

respective unit Licensor's Design Basis. Steam air decoking facility shall be provided

wherever necessary.

8.4.15 Fired heater transfer lines shall be provided with nozzles required during passivation on case

to case basis.

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8.5 VESSELS

8.5.1 Hold-up criteria

Following requirements for vessel hold up volumes are recommended :

Designers can adopt criteria that call for higher hold-up volumes, if warranted from a design

point of view .The working hold up volumes are expressed as minutes of liquid residence time

between Low Operating Level (LOL) and High Operating Level (HOL) while additional hold

ups shall apply between the operating levels and corresponding tripping levels (LLL / HHL),

when a shutdown is stipulated. Refer figure - 8.2 for clarity. Refer clause 9.3.1 also, while

calculating hold-up requirement

- Unit feed surge drum, upstream unit in same control room: 15 minutes

- Unit feed surge drum, upstream unit in separate control room: 15 minutes

- Surge for fired heater feeds: 10 minutes

- Surge for tower feeds, same control station: 8 minutes

- Surge for tower feeds, remote control station: 12 minutes

- Surge for pumped rundown to storage / other unit surge drums 3 minutes (min)

- Surge for gravity rundown to storage / other unit surge drum: 3 minutes

- Surge for tower reflux streams in distillate drums: 5 minutes

(this surge is additive to surge for downstream tower feed or rundown)

- Compressor suction KOD (based on 5%wt of inlet vapor) 3 minutes

- Compressor inter-stage KOD (automated drain) 3 minutes

- Compressor inter-stage KOD (manual drain if <5m3) 8 -24 hours

- Additional surge, LOL to LLL, normal pumps 2 minutes

- Additional surge, LOL to LLL, large / high speed pumps 3 minutes

- Additional surge, HOL to HHL, gas to fuel gas system 2 minutes

- Additional surge, HOL to HHL, gas to large compressors 3 minutes

- Additional surge, HOL to HHL, critical compressors 5-10 minutes

For horizontal vessels, the normal liquid level shall be fixed at 50% of the vessel diameter.

Figure - 8.2 : Typical Sketch for Hold-up Volumes

HHL

HOL

LOL

LLL

WORKING

150mm MIN.

VOLUME

(Depending on Level Instrument Configuration)

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8.5.2 Vessel Dimensions

Vessel and tower diameters shall be reported based on inside diameter (ID) while drawoff

boot diameter shall be reported to outside diameter (OD). Normally Deep Torispherical heads,

80% crown radius & 15% knuckle radius, will be specified in addition to 2:1 ellipsoidal heads.

Hemispherical heads will be considered when relevant.

8.5.3 Nozzle requirements for vessels and towers :

8.5.3.1 Minimum recommended sizes of vessel nozzles are:

- Process or instrument nozzle in unclad vessel : 2” NB

- Process or instrument nozzle in internally lined vessel or clad vessels: 3” NB

For skirt supported vessels / columns, the nozzles at the bottom dished end coming out of

skirt shall be 6” NB minimum.

8.5.3.2 Thermowell nozzles on vessels shall be flanged with rating as per piping class (minimum

150# rating) and will be 2” NB minimum. However, for lined vessels, nozzle size shall be 3”

NB (minimum)..

Temperature instrument nozzles for shell and tube heat exchangers, air cooled heat

exchangers and fired heater shall have Class 300 as minimum.

8.5.3.3 Steamout connections will be provided on vessels which are stipulated to be steamed out

during normal startups or shutdowns. Steamout nozzles, 2"NB, shall be located, at minimum

elevation, on the head of horizontal vessels and above the bottom tangent line for vertical

vessels. Permanent steam connection with double block valves, bleed, spectacle blind and

NRV to be provided.

8.5.3.4 For vessels/columns less than 900mm diameter, when access is required due to presence of

internals / demsiters, vessel shall be provided with flanged top head. However, for vessels /

columns less than 900mm diameter where no access is required, hand holes (8” ID min) shall

be provided in place of body flanges.

Between 900-1000 mm diameter vessels, manways of 18” NB is recommended.

Manways will be of minimum 20” NB (of lining, where relevant) for vessels having diameter of

1000-1500 mm and 20” NB for trayed / packed towers. Larger size manways shall be

specified, as required to facilitate passage of internals in trays / packed towers.

For vessels above 1500 mm diameter, 24” NB manways shall be provided.

In vertical vessels, more than 900mm diameter, provided with demisters, at least one manway

shall be provided in the top head and one manway in the bottom section, to facilitate access

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from both sides of the demister. For vertical vessels, less than 900mm diameter, the top head

shall be flanged.

In horizontal vessels, the manway shall be preferably located on the vessel head, away from

the end that has internals such as internal displacers or baffles. Large horizontal vessels

above 3000 mm tangent length will additionally be provided with a blanked-off ventilation

nozzle at the top of the vessel, near the end opposite the manway. The vessel vent nozzle

can be welded to the ventilation nozzle blind flange.

In trayed columns, manways shall be provided above top tray, below the bottom tray, at the

feed tray, at any other tray at which removable internals are located, and at intermediate

points so that the maximum spacing of manways in the trayed section does not exceed 10

meters.

In case of skirt supported clad vessels / columns, the nozzles at the bottom dished end

coming out of skirt shall have a minimum of 6" NB size. This is required to facilitate cladding/

weld overlay in bend and spool piece pipe.

All nozzles to be approachable from working platforms.

8.5.3.5 Steamout, vent and drain nozzles and ventilation nozzles shall be as follows :

Vessel volume Length

(Horizontal vessel)

Vent nozzle Drain Nozzle Ventilation

nozzle

Less than 6.0 m3 – 2” NB 2 ” NB –

6.0 – 15.0 m3 – 2” NB 2” NB –

15.0 – 50.0 m3 – 2” NB 3” NB –

50.0 – 200 m3 – 3” NB 3” NB –

200 – 400 m3 – 4” NB 3” NB –

400 – 700 m3 – 6” NB 4” NB –

More than 700 m3 – 8” NB 6” NB –

– 3000 mm – 4500 mm – – 4” NB

– 4500 mm – 7500 mm – – 6” NB

– > 7500 mm – – 8” NB

However, in case of cladded vessels, minimum nozzle size criteria as given in 8.5.3.1 shall be

applicable. All vertical vessels not having any nozzle on top shall be provided with 2” NB

nozzle for hydrotesting in vertical position.

8.5.3.6 Level instrument nozzles (refer also section 9.3, "level instruments"):

- Standpipes with isolation valves shall be used for mounting level gauges and level

transmitters.

- External guided wave radar type level instrument is preferred upto maximum of 1524 mm.

For longer ranges, differential pressure level transmitter shall be considered.

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- The visible length of level gauge shall cover the maximum operating range. Where level

gauge is used in conjunction with level transmitter, the visible length of the level gauge

shall cover the entire range of level instrument.

- External guided wave radar type level instruments are not acceptable for hydrocarbon-

hydrocarbon interface and low dialectic service fluids.

- Standpipe 2” NB diameter, attached to vessel shall have minimum 300 # class flange

rating. The nozzle on the standpipe for level instrument shall be minimum 150# flange

class rating.

- The level instruments used for tripping purpose shall be directly mounted on the vessel

instead of standpipe.

8.5.4 Vessel size limitations

8.5.4.1 Single-piece heavy equipment such as Reactors considered to be shop-fabricated and

transported to site shall have to be within the shipping envelope.

It is preferred that equipments are transported in one piece. However, the LSTK contractor to

study and finalise the mode of transport to site.

Vessel size is limited by

Outside diameter (including Projection): 5.0 m

Overall Length : 33 m

Weight : 480 MT

8.6 TOWERS

8.6.1 Tray and Packing selection

Valve trays, in general, will be used except for liquid-liquid mass transfer applications and for

services where some extent of fouling is anticipated. Single-pass, Two-pass and Four-pass

trays can be envisaged as appropriate. Three-pass trays are generally not preferred.

Random or structured packings will be specified as considered necessary in services such as

vacuum distillation (low pressure drop).

Pressure drop indication for all the packing sections to be provided in the control room.

8.6.2 Tray / packing turndown

All trays and packings shall be designed for the same turndown as defined in respective unit

Design Basis. In some services, the reflux and reboiler rates may be turned down to a ratio

different from the unit turndown, while still meeting the overall turndown.

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8.6.3 Hold-up criteria for tower bottoms & tower draw-offs

Hold-up volumes for tower bottoms and tower drawoff trays shall follow item 8.5.1. Designers

can adopt criteria that call for higher hold-up volumes, if warranted from a design point of

view. Specific to towers, the following additional stipulations shall be followed:

Surge for thermosiphon reboiler feed (Circulating type) : 1 minute

Surge on Product drawoff tray : 2 minutes

Surge for tower bottoms quench : 2 minutes

Surge for direct feed to another tower (Excl. circulating flows) : 5 minutes

Additional surge, LOL to Low prealarm / HOL to high prealarm : 1 minute

Additional surge, Low prealarm to LLL / High prealarm to HHL : 1 minute

Surge for product drawoff : 2 minutes.

8.6.4 For columns of diameter ≤ 900 mm, flanged column sections shall be used. For such trayed

columns, each set of 15 to 20 (maximum) trays should be approachable from column

manholes one above and one below the set of trays.. For such packed columns, each packed

bed will have a manhole each above and below the bed. Handholes shall be provided just

above the packing support plates, for removal of random packing. These shall be two in

number and opposite each other. In case the column diameter permits, one of the handholes

shall be replaced by manhole. Such columns shall be located where suitable crane can

approach for gasket change of flanges in case of leaks.

Tray panel width should be kept at 480 mm minimum to permit provisions for tray manways

except for trays having cartridge type construction.

8.6.5 Datasheet requirements for towers

- Trays shall be numbered from bottom to top.

- Cartridge trays shall be considered for diameters less than 800mm.

- Proper size Tray manways shall be provided on each tray where tray drawings are

deliverables.

- Tray and downcomer flooding should not exceed 80% at turn-up condition specified.

8.6.6 Nozzle requirement for towers:

- Refer to clause 8.5.3 under “VESSELS”

8.7 PUMPS

8.7.1 Selection of type of pumps

− All pumps within process unit battery limits shall be specified to conform to API Standard

610 (latest edition). For very special services (like slurry), other options to be specifically

referred to Owner / PMC for review.

− Pump specifications shall assume unsheltered outdoor location. The pipe rack above the

pump bay may accommodate air-cooled heat exchangers, in which case, the unit has to

be provided with a safety system to minimize accidental pump hydrocarbon leakages

from being fanned out as an explosive vapour cloud.

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− In special applications, low flow, high head, vertical integrally geared (Sundyne type)

pumps can be specified, if found necessary.

− For fire water system pumps, specifications to confirm to TAC requirement.

Minimum number of pump makes and maximum interchangeability, wherever possible in the

unit should be considered.

8.7.2 Sparing of pumps

8.7.2.1 Process pump services in continuous and critical intermittent service will, in general, be

provided with 100% installed spare. Intermittent pump services such as chemical unloading,

batch make-up, etc., shall not be provided with installed spare. These shall be decided on a

case-to-case basis and possibility of common spares shall be examined.

8.7.2.2 Where more than one operating pump is found necessary for a service, or when defined by

owner, pump capacity and spare be as follows:

Total Pumps Operating pumps Rated capacity per pump Spare pumps

3 2 50% of total rated flow 1



8.7.2.3 For identified critical services, minimum 2 operating pumps shall be specified. Critical services

shall be finalized with licensor.

8.7.3 Specification of pump seals

8.7.3.1 Single mechanical seals shall normally be specified for centrifugal pumps unless other

considerations prevail (See Clause 8.7.3.3) Seal flushing where necessary, shall preferably

be with the process fluid itself through an appropriate API seal plan for all clean liquids.

8.7.3.2 External seal flushing oil shall be made a requirement only when a self-flushing plan or

steaming flushing plan is not feasible. For refinery services, light seal flushing oil (FLO - gas

oil fraction) will be available.

If otherwise, pump specification shall ask the vendor to select proper seal fluid and supply the

same as part of his scope.

8.7.3.3 Double (dual) mechanical seals shall necessarily be specified for the following pump services:

− Process liquids: Butanes and lighter and /or process liquids having vapour pressure more

than 15 psia at pumping temperature

− Sour waters with more than 100 ppm H2S

− Fouling service or environmentally hazardous toxic / carcinogenic service (e.g. Benzene

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− Hydrocarbons operating above auto-ignition temperature

8.7.3.4 Instrumentation for pump seals shall be as per API and unit licensor recommendation.

8.7.3.5 For vacuum services, seal selection shall be discussed with Owner / PMC.

8.7.3.6 For products with operating temperature >200 °C, pump seal shall be stationary metal

bellows type.

8.7.3.7 Specific preferences or constraints towards pump selection

- Proper access for filling seal liquid in seal vessels is to be provided.

- Seal vessel vent connection to flare is to be provided for hydrocarbon services.

- Minimum number of pump makes and maximum inter-changeability, wherever possible, in

the unit should be considered.

- For pump suction lines, Y-type strainer to be provided for line size upto 2”, for higher line

size, T-type strainer shall be provided.

Close cup (conventional) lube oil system shall be considered for pumps. However, provision

for Oil mist type lube system shall also be provided for future consideration.

8.7.4 Specification of drives

Motor drives shall be specified for pumps.

Running indication for motors shall be provided.

8.7.5 Minimum flow bypass (MFB) provisions & controls

8.7.5.1 Requirement of MFB for centrifugal pumps is usually determined during detailed engineering.

However, considering operational and equipment health consideration, following services

shall be provided with MFB irrespective of vendor data.

− High pressure, multistage pumps

− Pumps with discharge control valve operated by suction side vessel level control

− Low capacity pumps (< 10m3/hr) on case to case basis

− Pumps with “fail close” control valve in discharge line and single destination

− Pumps with discharge control valve operated by temperature controller (TIC)

− Pumps with LIC/FIC cascade or TIC/FIC cascade.

8.7.5.2 The scheme for MFB will usually be a spillback line with constant bypass flow through a

restriction orifice and a globe valve. A separate MFB for each pump (operating as well as

standby) shall be evaluated for high pressure, multistage pumps.

8.7.5.3 For large capacity (>15 KW BKW) pumps, except recirculating service pumps, an automatic

MFB with a protective minimum flow control shall be provided to save the pumping energy.

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8.7.5.4 For low capacity pumps, where forward flow can go below the minimum pump flow during unit

operation, minimum flow shall be added to maximum pump flow to specify pump rated flow.

8.7.6 Pump cooling

Recirculating bearing cooling water shall be used for pump (indirect) cooling. Refer clause

6.3.3 for details..

8.7.7 Motor specification for auto-start pumps

For all pumps operating in parallel or having an auto start, electric motor shall be specified for

end of the curve condition with discharge valve in full open condition.

8.7.8 Fire water spray system with deluge valve and detection system shall be provided for pumps

handling volatile hydrocarbons and located under pipe rack as per provisions of OISD-116.

8.8 COMPRESSORS

8.8.1 Selection of type of compressors

(a) Specification of a compressor shall assume installation under a compressor shed.

(b) Centrifugal compressors, conforming to API Standard 617 (latest edition), will be

specified where suitable. Axial compressors not preferred below capacities of 150,000

Nm3/hr. Centrifugal compressors shall not be spared but specifications shall be given for

a spare rotor. Driver selection shall be based on process requirements, criticality of

service, capital cost and Owner's preference as per respective unit design basis.

(c) Reciprocating compressors, conforming to API Standard 618 (latest edition), shall be

specified with adequate spare capacity to allow maintenance of one machine while the

plant remains on stream. Motor drivers shall be specified normally.

(d) Screw compressors, conforming to API Standard 619 (latest edition), can be specified in

special cases where found to have an operating, economic or maintenance advantage

over other choices. Screw compressors shall not be spared but specifications shall be

given for a spare rotor. Driver selection shall be as for centrifugal compressors.

8.8.2 Compressor controls

Compressor control (interlocks and shutdown) shall be PLC based and located in control

room. PLC make shall be standardized for entire unit. Only start-up operation is carried out

from local panel and normal controls from central control room.

8.8.3 Compressor seals

Dry gas seals are preferred.

Bi-directional and inter-changeability in Drive-end and driven end to be considered.

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8.8.4 Unit designers shall address issues such as common or individual compressor suction and

interchange KODs, common or individual compressor inter-stage coolers and surge control

etc., as part of unit operability and cost saving factors.

8.9 STEAM TURBINE DRIVES

8.9.1 Steam turbine drives are not preferred.

8.10 IBR REQUIREMENTS

8.10.1 Scope of IBR

Steam generators / steam users shall meet IBR regulations. Major IBR requirements are

summarised below:

a) Vessels: Any closed vessel exceeding 22.75 litres (five gallons) in capacity which is

used exclusively for generating steam under pressure and include any mounting or

other fittings attached to such vessels, which is wholly or partly under pressure when

steam is shut-off.

b) Piping: Any pipe through which steam passes and if :

i) Steam system mechanical design pressure exceeds 3.5 kg/cm2(g)

OR

ii) Pipe size exceeds 254 mm internal diameter

c) The following are not in IBR scope

I. Steam Tracing

II. Heating coils

III. Heating tubes in tanks

IV. Steam Jackets

d) All steam users (heat exchangers, vessels, condensate pots etc. ) where condensate is

flashed to atmospheric pressure i.e. downstream is not connected to IBR system are

not under IBR and IBR specification break is done at last isolation valve upstream of

equipment.

e) All steam users where downstream piping is connected to IBR i.e. condensate is

flashed to generate IBR steam are covered under IBR.

f) De-aerator, BFW pumps are not under IBR and IBR starts from BFW pump discharge.

8.10.2 Material Certificate: (This section is only for information on IBR requirement).

a) All items, which are part of steam piping i.e. pipes, valves, fittings, traps, safety valves

must have material certificates, countersigned by the local boiler inspectors.

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b) For imported items – Certificates issued by an authority empowered by Central

Boilers Board (As per IBR) or under the law in force in a foreign country in respect of

boilers manufactured in that country may be accepted.

c) All drawings and design calculations coming under purview of IBR shall be certified

by Local Boiler Inspector.

8.10.3 All datasheets of equipment which come under IBR scope shall have the annotation: "IBR is

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9.0 INSTRUMENTATION

9.1 CONTROL PHILOSOPHY

Process Control shall be facilitated through :

− Distributed Control System (DCS)

− Interlocks and shutdowns through Programmable Logic Controller (PLC)

9.2 GENERAL REQUIREMENTS

Following is the general requirement considered in basic engineering design :

Detailed instrumentation design philosophy would be developed in the course of detailed

engineering.

− All symbols in P&ID shall be as per ISA

− Sensor / transmitter for shutdowns separated from that for control / indication

− Solenoid valve for interlocks operation with interlock shutdown system only

− Hand switches. Push buttons and status signals indication shall be in DCS only.

− Shutdown signals shall be repeated in DCS through serial links from PLC

− Emergency I start-up override switches shall be hardwired only

(exceptions to be discussed with HPCL / PMC)

− Hardwired indicators or recorders shall not be used

− Analog inputs for shutdown and interlocks shall be connected directly to PLC without use

of receiver switch or trip amplifier

− Instruments shall have individual tappings from process lines

− Solenoid valve manual reset when required shall be the field.

− Block and bypass valves (TSO) to be provided for turbine meters, vortex meters, PD

meters and mass flow meters

− Rotating equipment with auto-start facility shall have auto-manual switch in field

− 2 out of 3 voting required for all critical trip interlocks.

− In general of field transmitters shall be digital with foundation field-bus. Transmitters shall

be provided with integral LED/LCD type output meter. Necessary guidelines for Hand

held Calibrator to be followed and its certification from statutory body is also to be

obtained.

− Continuous flushing oil purge is recommended for flow, level and pressure transmitters in

heavy residue services, except for bitumen product, which can become off-grade.

9.2.2 Process switch type shall be as follows:

1. For flow, pressure (very low values / vacuum), temperature, underground

sump level and interface level, use transmitters with direct connection to

system

2. Direct actuated field switches for all others.

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Thermocouples for trip circuit shall be provided with field-mounted transmitter.

9.2.3 All temperature elements are assumed to have minimum line size expansion of 4" to be

implemented in the course of detailed engineering. These may not be reflected in P&IDs.

9.2.4 Gas detectors, linear heat detectors for floating roof tanks, ROR Heat detector for clean agent

system shall be provided for process units and OSBL facilities as per provisions of OISD-116.

Interlock for operating FW / agent systems should also be provided.

9.2.5 Instrument impulse lines to be insulated / traced, wherever required, to avoid condensation /

congealing.

9.2.6 Critical rotating equipment to have vibration monitoring system with control room indication.

9.2.7 Instrument units of measurement

Property Units

Flow

Hydrocarbon liquid (Process),

Steam

m3/h

Kg/h

Non-Hydrocarbon liquid (Utilities) m3/h

Additive injection l/h

Gas and Vapour Nm3/h

Pressure

Above atmospheric Kg/cm2(g)

Atmospheric Kg/cm2(a)

Below atmospheric mm of Hg

Low draft gauges mm of H2O

Level % of Range

Temperature °C

Viscosity cP

Gas Characterization MW

Liquid Density Kg/m3

9.3 LEVEL INSTRUMENTS

9.3.1 Standpipe with a default size of 2" NB shall be considered for only clean, non-viscous and

non-crystallising services. Standpipes shall be used if more than 4 vessels nozzles are

anticipated for mounting all the level instruments in a given service.

Standpipes bottom tapping should be from side only. Standpipe bottom tapping not to have

any low pocket in order to ensure free draining of standpipe liquid into the vessel

For other cases level instruments shall be mounted directly on the equipment. In this case

minimum liquid level indicated shall be 150 mm above the BTL of the equipment.

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For interlock / tripping and critical control applications, separate nozzle shall be considered.

9.3.2 Following specific requirements for standpipes is to be followed :

− Standpipe shall not have instruments other than for level.

− Standpipe accommodating level gage / transmitter shall be separate from standpipe /

vessel tappings for level transmitter for alarm and trip.

− LC & LG Instruments can be mounted on the same stand pipe for the vessels.

− Standpipe shall not be connected to process lines

− Standpipes to have isolation valves at top and bottom tapping.

9.3.3 Following type of level gauges shall be specified for tanks :

Feed tanks Radar with watercut measuring functions

Intermediate tanks Radar with watercut measuring functions

Product tanks (non viscous) Radar with watercut measuring functions

Product tanks (viscous with steam coil) Radar

Tank Farm Management System Shall be considered.

All tanks require two level gauges: One to be Servo type (mechanical float) and one to be

Radar type.

9.4 FLOW INSTRUMENTS

In general Orifice Plate shall be used for flow measurement. Other types shall be decided

based on suitability, criticality and application.

General requirements for flow instruments is as follows :

− Liquid flow measurement process data shall include density at standard conditions in

addition to flowing density and normal / minimum / maximum flows, etc.

− For only local indications use calibrated differential pressure gauge across flow element.

9.5 STARTUP / SHUTDOWN OPERATION FROM CONTROL ROOM

Following emergency operations to be enabled from the control room:

− Individual unit emergency shutdown (control room)

− Fired heater emergency shutdown (control room and field)

− Critical rotating equipment shutdown (control room and field)

− All rotating equipment shutdown (only in the field)

− Shutdown valves to fail-safe position (Field Reset Only)

− Damper and gate operation (control room and field)

9.6 STATUS INDICATION LAMPS IN CONTROL ROOM

− All continuously running rotating equipment (in DCS)

− Alarm window in control room for all compressors

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− Hard wired alarm annunciation in control room for all compressors for critical parameters

and shutdown.

9.7 CONTROL VALVE MANIFOLD

9.7.1 As a default, control valves upto 8" size and in steam service shall be provided with a manifold of block and bypass valves. Bypass valves shall be globe valves. Control valves not having block and bypass provision shall be provided with handwheel for manual operation. For control valve above 8" size, block and bypass requirement shall be decided on case to case basis.

Block and piping bypass sizes will be per Table 9.7 below unless there are specific process reasons for deviation. When piping is expanded after a control valve station for flashing service, the bypass valve and the downstream block valve shall be equal to the expanded downstream pipe size. If the process cannot be operated manually, a bypass is not necessary.

TABLE 9.7

Line Size

Control Valve Size

(with bypass)

Control Valve Size (without bypass)

Block Valve Size

(when used)

Bypass Valve Size

(when used)

1” 1” 1” 1” 1”

1½” 1” 1” 1½” 1½”

1½” 1½” 1½” 1½” 1½”

2” 1” - 2” 1½”

2” 1½” 1½” 2” 2”

2” 2” 2” 2” 2”

3” 1½” - 2” 2”

3” 2” 2” 3” 3”

3” 3” 3” 3” 3”

4” 2” - 3” 3”

4” 3” 3” 4” 4”

4” 4” 4” 4” 4”

6” 3” - 4” 4”

6” 4” 4” 6” 6”

6” 6” 6” 6” 6”

8” 4” - 6” 6”

8” 6” 6” 8” 8”

8” 8” 8” 8” 8”

10” 6” - 8” 8”

10” 8” 8” 10” 10”

10” 10” 10” 10” 10”

12” 8” - 10” 10”

12” 10” 10” 12” 12”

12” 12” 12” 12” 12”

14” 10” - 12” 12”

14” 12” 12” 14” 14”

14” 14” 14” 14” 14”

9.7.2 All control valves shall be provided with ¾” drain valves as follows:

- Upstream and downstream of all control valves

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- Drain valve shall be with blind flange for all services

9.7.3 Shutdown valves shall not be provided with block and bypass valves. All shutdown valves to be provided with close / open position indicators in DCS.

9.8 PRESSURE RELIEF VALVES (PSV)

Pressure relief valve configuration is as follows :

− PSV for operational failures shall have installed spare with isolation facilities. (Only one

spare to be provided for multiple PSV)

− PSV exclusively for non-operational failures (external fire or heat exchanger tube rupture)

shall not have installed spare. Isolation valves shall be Lock Open. However, if fire case is

the governing case where process also requires safety valve, full capacity spare valve

shall be provided.

− Credit due to insulation should not be considered for determining fire case relief.Fire relief

calculation should be based on API 520 RP and API Std 2000.

− Spared and unspared PSV shall have upstream and downstream isolation when

connected to closed system. Isolation valves shall have LO/LC facility.

−

− PSV in IBR steam service shall not have upstream isolation. There shall be TWO full flow

safety valves for steam generation equipment.

− PSV in air service shall have only upstream isolation.

− PSV for thermal relief shall not have installed spare.

− PSV on spare equipment shall have downstream isolation only if connected to closed

system.

− Vessels are to be specified with one safety valve nozzle in case multiple safety valves are

being provided.

− Relief valve bypass should be of 2” gate valve, followed by spectacle blind and globe

valve. A ¾” bleed is to be provided in between.

− All safety valves / safety relief valves in critical services shall be of precision design.

− All PSVs shall be provided with ¾” bleed valve downstream of inlet isolation valve and

upstream of outlet isolation valve (except Thermal Relief case).

9.8.1 All drains on safety valves (wherever provided) shall be connected to the CBD. All safety

valves shall normally have carbon steel body with stainless steel trim. Other trim material can

be considered if any particular service demands a different material. Bronze or cast iron

bodied valves shall not be used.

9.9 CONTROL PHILOSOPHY FOR VENDOR PACKAGE ITEMS

For all vendor package supplies, mode of monitoring, control and logics shall be decided

during detail engineering.

9.10 STANDARD INSTRUMENTATION.

9.10.1 Packed Towers

− Control Room differential pressure indication for each bed

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− Control Room differential pressure indication for total section

− Differential pressure for Basket strainers in lines going to packed beds (Local and Control

room)

9.10.2 Heat Exchangers:

− Isolation valves at both inlet & outlet in cooling water service

− Isolation and bypass valves for only exchangers which can be taken out for maintenance

when plant is running

− Pressure gauge at inlet /outlet of each exchanger shell.

− Local TI at cooling water outlet of each exchanger.

− Control room TI at process inlet and outlet for each exchanger shell side and tube side.

9.10.3 Utility Lines : As a minimum, the following shall be provided in unit utility headers:

Table - 9 : Standard Utility Line Instrumentation

UTILITY Local

PI

DCS

PI

DCS

PAL/

PAH

Local

TI

DCS

TI

DCS

TAL/

TAH

DCS

FI

DCS

FAL/

FAH

DCS

FQ

VHP Steam YES YES YES YES YES YES YES YES YES

HP Steam YES YES YES YES YES YES YES YES YES

MP Steam YES YES YES YES YES YES YES YES YES

LP Steam YES YES YES YES YES YES YES YES YES

Condensate YES YES YES YES YES YES

CW supply YES YES YES YES YES YES YES YES

CW return YES YES YES YES YES YES YES

Instrument Air YES YES YES YES YES YES

Plant Air YES YES YES YES

Nitrogen YES YES YES YES YES YES

Fuel Gas YES YES YES YES YES YES YES YES YES

Fuel Oil YES YES YES YES YES YES YES YES YES

DM Water /

BFW

YES YES YES YES YES YES YES

Service Water YES YES YES YES YES YES

Flare YES YES YES YES YES

Fire Water YES YES YES

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10.0 PIPING & INSULATION

Engineering Design Basis shall define the detailed design requirements for overall piping,

insulation, painting and corrosion protection standards.

10.1 Insulation thickness to be adopted are given in Engineering Design Basis (Document No :

44LK5100-00/V.02/0001/A4)

10.2 It is mandatory to adhere to stipulations of OISD standard 118 for minimum inter-equipment

spacing and distance between process unit and process units & offsites.

10.3 Project Piping Material Specification (PMS) to be followed shall be HPCL Standard PMS

adopted for this project.

10.4 Steam tracing for piping handling congealing services shall be:

Steam tracing within unit battery limits as well as for OSBL.

LP steam upto vacuum gas oils & RCO, MP steam for heavy residues.

Steam tracing for OSBL – tapping for tracer to be from one steam header.

10.5 All incoming and outgoing lines from the units shall be provided with double isolation block

valves with a spectacle blind and drain. Details as per Unit Design Basis for ISBL lines. All the

valves to be provided at approachable height with suitable platforms ensuring accessibility,

safety and ease of operation.

10.6 Isolation valves available as a part of control valve assembly or provided for other process

reasons shall not be considered as a battery limit isolation valve.

10.7 Gear-aided operation shall be as per Piping Material Specification. For valves of 14" size and

above, (on case to case basis) motor-operated valves can be considered. However, licensor’s

recommendation for motor-operated valves, if any, to be complied with.

10.8 All special purpose valves shall be tagged in P&IDs or identified in appropriate piping class.

The Unit Design Basis shall contain appropriate specifications towards the same.

10.9 All piping within a process unit shall be above ground except for oily water sewer, closed

blow-down systems and contaminated rainwater sewer (CRWS). Cooling water supply and

return headers and fire water headers can be provided above ground (ISBL), if found suited

or necessary. In case ISBL Cooling Water Headers are to be routed underground, they must

be laid in sand filled concrete trenches with pre-cast covers. Firewater header if laid above

ground shall run away from process lines as per TAC. Otherwise, fire water header shall be

laid underground in sand filled concrete trenches and covered with pre-cast slab. The general

philosophy shall be: upto 30” on rack and >30” underground.

10.10 All condensing vapour lines shall be specified with no pockets, free draining requirement. If

this is not feasible then the line shall be steam traced.

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10.10 All critical piping items will be tagged and specifications will be furnished by licensor / unit

designer in the Process Package.

10.11 All process pumps shall be provided with strainers in the suction line, ‘Y’ type for sizes upto 2”

and 'T’ type for 3” dia and above with drain valve. Special strainers shall be specified by unit

designers.

10.12 All control valves in product circuit should be located in close proximity, preferably near the

Unit Battery Limit. Similarly, all sample points on run down product lines should be located in

close proximity with easy accessibility. OWS funnels to be provided in close proximity of

sample points.

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11.0 ENVIRONMENTAL CONTROL

11.1 Emission norms as stipulated by CPCB and other mandatory regulations shall be satisfied for

the project. Liquid effluent shall conform to MINAS standards.

11.2 All unit designers have to compile effluent data from all sources and necessarily furnish

complete effluent characteristics in the format given in Table 11.1 (liquids), 11.2 (gaseous),

11.3 (solids)

11.3 Deleted

11.4 NOISE LEVEL :

i) 85 dB(A) at 1 meter from source

ii) Deleted

Table - 11.1 : Format for aqueous effluent data

Source / Originating Point

Flow Rate (Average / Peak) M3/hr

Frequency of flow Continuous / Intermittent

Duration if Intermittent Hours / day

Temperature °C

Colour / Odour

Pressure kg/cm2(a)

Sp.Gravity

Viscosity cP

Vapour Pressure kg/cm2(a)

pH

BOD, 20°C mg/lit

COD mg/lit

Suspended Solids mg/lit

Sp.Gravity of solids

Particle size Microns

Total Dissolved solid mg/lit

Volatile matter mg/lit

Total Oil content mg/lit

Sp.gr. of Oil

Viscosity of oil cP

Pour Point of oil °C

Phosphates mg/lit

Sulphates mg/lit

Chlorides mg/lit

Fluorides mg/lit

Nitrates mg/lit

Total Nitrogen mg/lit

Free / Fixed Ammonia mg/lit

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Cyanides mg/lit

Sodium mg/lit

Calcium mg/lit

Magnesium mg/lit

Phenolic Compounds mg/lit

Heavy Metals mg/lit

Chromium mg/lit

Nickel mg/lit

Lead mg/lit

Zinc mg/lit

Mercury mg/lit

Any other mg/lit

Emulsified oil

Chemical Composition % wt

Table - 11.2 : Format for gaseous effluent data


Type of Emission (Fugitive / Stack)

Flow rate m3/hr

Type of Flow (Cont. / Intermit)

Frequency and Duration if Intermittent

Height of Stack / Source m

Diameter of Stack (TIP) m

Temperature of Gases oC

Pressure of Gases kg/cm2(a)

Mol. Weight of Gases

Density of Gases kg/m3

Viscosity of Gases cP

Exit Velocity of Gases m/sec

Composition of Gases (Wt.%)

Hydrocarbons (HC)

CO (Carbon monoxide)

CO2 (Carbon Dioxide)

SO2 (Sulphur Dioxide)

N2S (Nitrogen Sulphide)

SO3 (Sulphur oxide)

NOx (Oxides of Nitrogen)

N2 (Nitrogen)

O2 (Oxygen)

H2O (Water vapours)

Any other component (Chemical composition)

Suspended particulates matter (SPM)

Type of Particulate Matter

Density & Bulk Density kg/m3

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Nature of Dust

Amorphous

Crystalline

Needle shaped

Fibrous

Metallic

Particle Size Distribution (wt%)

Up to 5 microns

5-20 microns

20-40 microns

40-80 microns

Above 80 microns

Table - 11.3 : Format for solid effluent data


Quantity of Solid Waste kg/day

Continuous / Periodical

Frequency & Duration, if periodical

Temperature °C

Density kg/m3

Physical Condition (Slurry / Sludge / Powder / Lumps)

Viscosity, if slurry / sludge cP

Nature of Waste (Hazardous / Toxic / Explosive / Corrosive / Abrasive / Radioactive)

Calorific Value Kcal/kg

Chemical Composition Wt%

Volatile Matter Wt%

Moisture content Wt%

Recycling of Waste Required Yes / No

Recovery of Valuable component Yes / No

Schemes of Reuse / Recycle

Sale value of Waste Rs./ton

Availability of Land for disposal Yes / No

Leachate Characteristics (if slurry)



HPCL, MUMBAI

44LK5100


12.0 SAFETY

This section presents a short list of additional safety aspects that will be reflected, as

appropriate, in the basic engineering design or in the detailed engineering stages. This list is

not intended to be a complete enumeration of safety features for a project.

12.1 Push buttons for stopping critical motors, if identified, shall be provided at a safe location,

away from the fire-zone of the respective motors and also in control room. This is in addition

to usual start / stop push buttons provided for such motors.

Air cooler stop push button to be located at grade level in addition to start / stop button near

the fan at platform.

12.2 Gas detectors shall be provided in the critical process and off-sites areas as per OISD norms.

Number and location shall be decided by LSTK. The requirement of steam / air curtain shall

be based on designer’s requirement and to be consistent with rotating equipment seal

selection and leakage potential.

12.3 Suction / discharge valves and suction filter should be close to the pump in order to avoid

hydrocarbon wastage during filter cleaning and pump maintenance.

12.4 Flare line isolation valve at unit battery limits should be installed only in the horizontal line with

stem in horizontal position or vertical downward position to avoid free fall of gate and

blockage of flare system Each flare header leaving a unit shall be provided with such isolation

valves to facilitate maintenance of flare piping and pressure relief valves within the unit.

12.5 Dip hatch for the tanks should have the aluminium guide extended upto top surface of the

tanks (Short guides may cause serious hazards). Dip hatch cover should be ensured with a

rubber gasket for non sparking.

12.6 Harmful effects of liquids / gases handled in the plant on FRLS cables / PVC cables / XLPE

cables / Aluminium / Copper / Brass to be considered and suitable precautions to be taken.

12.7 Any specific requirement for lightning protection and protection against static charge is to be

incorporated.

12.8 Emergency lights in plant area and control room shall be provided.

12.9 Communication system to cover all areas of plants and offsites shall be provided.

12.10 Pumps taking suction from vessels containing butanes and lighter and materials at operating

temperature more than auto-ignition temperature will be protected by providing a fire safe

remote operated valve on the suction line near the vessel.

12.11 Emergency trips if specified for HT motor will be wired directly to switch gear in addition to

control room.

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12.12 All the valves are to be provided at approachable height with suitable platforms ensuring

accessibility, safety and ease of operation.

12.13 Fire alarm system shall be provided at strategic location with Pill boxes for fire alarm and field

telephones.

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13.0 PROCESS FLOW DIAGRAMS (PFDs) AND

PIPING & INSTRUMENTATION DIAGRAMS (P&IDs)

13.1 The following standard legend P&IDs which is attached in Annexure 2 shall be adhered to

across all process facilities:

Abbreviations & Symbols : P&ID No. 44LK5100-00/P.01/0001/A1

General notes & typical details : P&ID No. 44LK5100-00/P.01/0002/A1

13.2 INSTRUMENT REQUIREMENTS FOR P&IDS

All designers are required to adhere to the following requirements in Piping & Instrumentation

Diagrams:

− Control valve / Shut-down valve failure position shall be indicated along with outlet

destination

− Control valve sizes shall be indicated

− Pressure relief valve set points shall be indicated along with outlet destination.

− Pressure relief valve sizes with orifice designations shall be indicated.

− Interlocks shall be shown with sequence numbers matched to description.

− Minimum Flow stops, hand wheels for control valves, as required, shall be shown.

− Advanced or complex control loops shall be explained with description, mathematically if

necessary.

− Solenoid valves and limit switches shall be shown with tag numbers. Type of SOV i.e.

Field Manual Reset (FMR) to be indicated.

− Coupons and corrosion probes, wherever required, shall be shown.

− Interface type level instruments shall be clearly identified in the P&ID.

− Pressure and temperature elements shall be shown for flow measurement for gas service

with pressure and temperature compensation (except mass flow meters), where

stipulated.

− Block & Bypass valves shall be provided for Mass Flow meters, Integral Orifices, Positive

Displacement meters, Rotameters, Vortex flow meters and turbine flow meters

− All instruments required for APC to be provided.

− Battery Limit isolation valves along with spectacle blind and bleeders shall be provided in

all incoming and outgoing lines by unit process licensor with clear demarcation of scope

between unit & offsite upto the flange of offsite end.

− Insulation & heat tracing requirement for instruments

− Integral orifices shall be used upto 1½” NB only.

− Sampling system for online and manual analysis.

− Utilities connection, flare / vent / drain connections for analysers shall be shown in the

P&IDs. Additional vent / drain connections for high pressure circuit instruments to be

shown in P&ID.

13.3 PREFERRED DRAWING SIZE AND MEDIA

All P&IDs and Process Control Diagrams (PCDs) shall preferably be drawn in drawing size

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submit two sets of soft copies of all P&IDs at each approval stage along with necessary hard

copies. Soft copies shall be on standard CD Media (700 MB).

13.4 MISCELLANEOUS

P&ID to indicate rating at control valves, safety valves, vessel flanges, if they differ from line

rating.



HPCL, MUMBAI

44LK5100


14.0 NUMBERING SYSTEM

14.1 EQUIPMENT NUMBERING SYSTEM

14.1.1 Equipment numbering shall be as defined below:

XY - E - 1001

- Serial Number (4 digit)

- Equipment Designation

- Unit Number

14.1.2 The unit numbers have been defined in section 2.3. The equipment designations are

summarised in Table 14.1 covering the requirement of basic engineering. The serial number

shall be as assigned by unit designer. Separate series can be used to designate different

sections within the same unit.

14.2 PFD / P&ID NUMBERING SYSTEM

14.2.1 Specific to the numbering of Process Flow Diagrams and Piping &. Instrumentation Diagrams,

the following system shall be adhered to by all licensors / designers:

XXWWW-ZZ XY D- TT- VVVV

- Serial Number

Document Type

Dept / Discipline

- Unit Number

- Designer’s own

requirement(Project No)

.

14.2.2 This numbering essentially ensures that the first part of the drawing number takes care of a

licensors or designer's own company numbering requirements while the second part of the

number ensures a uniform philosophy for all PFD / P&ID serial numbers which will then be

utilised for numbering instruments and lines as per 14.3 and 14.4 below.

14.2.3 In the four-digit drawing serial number, the digits shall be used as follows:

First digit : ‘0’ for PFD , ‘1’ for P&ID, ‘2’ for PCDs, ‘3’ for equipment layout,

‘4’ for mechanical design diagram, ‘5’ for reactor mech. design drg.,

‘6’ for metallurgy flow diagram.

Second digit : '0' for iso size A0. '1' for iso size A1. so forth.

Last 2 digits : Serial number Starting from '11' for P&IDs, from ‘01’ for PFDs.




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14.3 LINE NUMBERING

14.3.1 Line numbering shall be as outlined below:

12” - P- XY-1201- AAA2-IT

- Insulation Designation

- Piping class Designation

- Serial Number

- Unit Number

- Service Designation

- Line size, inches

14.3.2 Service designation and insulation designation are listed in legend drawing # (Later) issued

for the project.

14.3.3 In the four-digit line serial number, the digits shall be used as follows:

First 2 digits : Same as last 2 digits of P&ID serial number.'

Last 2 digits : Serial number starting from '01'.

14.4 INSTRUMENT NUMBERING

14.4.1 Instrument numbering shall be as outlined below:

XY - PIC - 1201

Serial number

Instrument designation

Unit number (not indicated

in P&ID tag but used in instrument

specification / list)

14.4.2 Instrument depiction shall be as per ISA. The relevant table for the alphabetic depiction of

instrument type is included in drawing No. 44LK5100-00/P.01/0001/A1 and 0002/A1 (Refer

Annexure).

14.4.3 In the four-digit instrument serial number, the digits shall be used as follows:

First 2 digits : Same as last 2 digits of P&ID serial number.

Last 2 digits : Serial number starting from '01' for each P & ID.

Use of alphabetical suffixes, e.g. A, B, C is only allowed for split control valves. Even if the

suffix A, B, C is used, the total number of digits in the instrument tag number will not exeed 8.

14.5 DOCUMENT NUMBERING SYSTEM

14.5.1 With the exception of the above documents, licensor / LSTK contractor shall follow their

respective company procedures for document numbering.



HPCL, MUMBAI

44LK5100


Table - 14.1 : Equipment designations

Equipment

Designation

Description Equipment

Designation

Description

AC Air Conditioning Plant PM Pump Drive, Electrical Motor APH Air Preheater PSA PSA Unit

B Burner R Reactor

BIN Bin / Hopper RD Rupture Disks

C Compressor / Blower RF Refrigeration Plant

CM Compressor / Blower drive, Electric Motor

SIL Storage Silos

CT Cooling Tower ST Pump Drive, Steam Turbine

D Storage Sphere / Vessel STR Piping item, Inline Strainer

DM DM Plant T Column

DR Drier TK RCC Tank, Storage Tanks

DW Daerator TRP Piping item, Steam Traps

E Heat Exchanger WHB Waste Heat Boiler (Exchanger)

EM Electrical drive for Air Cooled Exchanger

X Expansion Join, general, Air mixer, Storage Tank mechanical mixer

EV Evaporator

AFC Air Cooled Exchanger

F Fired Furnace , Inclinerator

FA Flame Arresters

FAN Forces / Induced Draft Fan

FANM Electrical drive for FD / ID Fan

FIL Filter, general

FLR Flare

GEN Turbo Generator

H Storage Hopper

J Ejectors / Vacuum System

KTST Compressor / Blower drive, Steam Turbine

LZ Undefined Package Equipment

MD Mechanical Mixer for Vessel.

MX Static Mixer

P Pump

PA Silencer

C




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15.0 STANDARDS & CODES

Standards and Codes shall be as per Detailed Engineering Design Basis. Uniform codes and

standards are to be followed.



HPCL, MUMBAI

44LK5100


ANNEXURE -1

Curve Showing concentration of caustic solution versus temperature for fixing stress relieving requirement.




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ANNEXURE 2

Standard P&IDs

INDEX

Sr No P&ID No Description

1 44 LK-5100-P01/00001/A1 Piping and Instrumentation Diagram for Abbreviations and Symbols

2 44 LK-5100-P01/00002/A1 Piping and Instrumentation Diagram for General Notes and Typical Details

3 44 LK-5100-P01/00003/A1 Piping and Instrumentation Diagram for Standard Heater Heater /APH : Notes

(Total 2 Sheets)

4 44 LK-5100-P01/00004/A1 Piping and Instrumentation Diagram for Standard Natural Draft Heater

5 44 LK-5100-P01/00005/A1 Piping and Instrumentation Diagram for Stand Heater Firing Sections

6 44 LK-5100-P01/00006/A1 Piping and Instrumentation Diagram for Abbreviations and Symbols

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