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
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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
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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
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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
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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
Return Pressure, kg/cm2(g) 3.5 - - 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.
Parameter Minimum Normal Maximum Mech
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
Return Pressure, kg/cm2(g) 2.5 - - 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
Return Pressure, kg/cm2(g) 2.5 - - 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.
Parameter Minimum Normal Maximum Mech
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
and then pumped out to effluents treatment plant in OSBL.
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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
Monel 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
0.9 M
PART – II SECTION: B Page 41 of 72
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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
4 3 33% of total rated flow 1
6 4 25% of total rated flow 2
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
applicable".
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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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Source / Originating Point
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
Source / Originating Point
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
Dust Load g/m3
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Source / Originating Point
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
Source / Originating Point
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)
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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
ISO A1. The CAD software used shall be AUTOCAD Version 2007. LSTK Contractor shall C
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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.
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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.
PART – II SECTION: B Page 69 of 72
BASIC ENGINEERING DESIGN BASIS Doc No. 44LK5100-00/P.02/0001/A4
HPCL, MUMBAI
44LK5100
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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
HPCL, MUMBAI 44LK5100
BASIC ENGINEERING DESIGN BASIS Doc No. 44LK5100-00/P.02/0001/A4
PART – II SECTION: B
Page 70 of 72
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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.
PART – II SECTION: B Page 71 of 72
BASIC ENGINEERING DESIGN BASIS Doc No. 44LK5100-00/P.02/0001/A4
HPCL, MUMBAI
44LK5100
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ANNEXURE -1
Curve Showing concentration of caustic solution versus temperature for fixing stress relieving requirement.
HPCL, MUMBAI 44LK5100
BASIC ENGINEERING DESIGN BASIS Doc No. 44LK5100-00/P.02/0001/A4
PART – II SECTION: B
Page 72 of 72
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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