Overall_Design Basis (Digboi)- Process
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PART II - PROCESS PACKAGE .
SECTION A - ENGINEERING DESIGN BASIS
SECTION – IIA ENGINEERING DESIGN BASIS - PROCESS
00
ALL
Rev. Sheet
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26.12.07
IFC
Name
Date
Name
Date
Name
Date
Status
Prepared, revised
Checked
Issued for Comments Remark, kind of revision
Approved
Designation
Basis document DG
UNIT NO. 34, 35, 36 & 37 Project Name
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Blank form GFA 0373Ei Issue: Rev. 02 , 21.05.2002
Sheet 1 of 36
Table of Contents
_____________________________________________________________________________________________
S No.
Description
1
Introduction
2
Project Description
3
Meteorological Data
4
Utilities Specifications
5
Equipment Design Basis
6
Material of Construction Design Philosophy
7
Process Control and Instrumentation
8
Units of Measurement
9
Codes, Standards & Practices
10
Equipment Designation and Numbering
11
Line Numbering and Identification System
12
Instrument numbering
13
Analysis point numbering
14
Pressure relief valve numbering
15
Safety Recommendations
16
Environmental Requirements
17
Steam & Condensate System
18
Utility Stations, Safety shower & Eye wash
19
IBR Requirement
20
Plot Plan
21
Special Design Requirements
Project Name
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Index of Relevant Documents No.
Title
Project Name
MSQ UPGRADATION - IOCL DIGBOI EDP Ident. No.
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Summary of Revisions
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1.0
Introduction
Please consult the design information provided by the Process Licensor, M/S Axens with intimation to IOCL. 1.1 Indian Oil Corporation Limited (IOCL), the owner, intend to Engineer, Construct, Commission and Operate MS QUALITY UPGRADATION (MSQU) Project at its Digboi Refinery in the state of Assam. Lurgi India Company Pvt. Ltd. has been retained by IOCL to provide services for Project Management Consultancy (PMC) and Front End Engineering Design (FEED) The following process facilities are covered under the FEED package: The following units are part of the MS Quality Upgradation Project planned in IOCL AOD Digboi Refinery, India. •
The Naphtha Splitter unit 034 (NSU),
•
The Reformate Splitter unit 035 (RSU),
•
The New HDT unit 036
•
The Isomerization unit 037
. The objective of the Naphtha Splitter (unit 034) is to split the blend of feed composed by straight run naphtha (SRN), coker naphtha (CN), DHDT naphtha (DHDTN) and Guwahati naphtha (GRN) into a light Naphtha feeding the New ISOM- HDT unit (unit 036) and a heavy naphtha feeding an existing HDT/reforming unit. The objective of the Reformate Splitter (unit 035) is to split the feed from the existing reforming unit into a light reformate feeding the stripper of New HDT unit (unit 036) and a heavy reformate send to MS pool. The objective of the New ISOM-HDT unit (unit 036) is to treat light naphtha from unit 034 in order to produce a sulfur free and stabilized naphtha (including the light reformate feed from unit 035), containing less than 0.5 wt ppm sulfurand less than 0.1 wt ppm nitrogen, and 0.1ppm(max) Oxygen to feed the Isomerization unit (unit 037). The objective of the Isomerization unit (unit 037) is to increase the RON of the hydrotreated light naphtha cut. The Isomerization unit capacity is 46.76 Mt/year and the stream factor is 8000 h/yr. The unit turndown rate is 50 % of the design capacity while making on-specification products. The power requirement for the new facilities will be met from the existing system. Power will be distributed to proposed new units through a new substation including a new transformer to feed the new substation complete with facilities like ventilation, fire detection / protection etc. It includes all cabling from switchgear (for LT panel to new units) and HT feeder (for HT drives in new units) The scope also includes all ISBL utilities distribution for above mentioned units including flare, drains / sewers and blow down system. Licensor’s design for the above mentioned Units and PMC’s design of the ISBL Utility distribution (including flare, drains / sewers and blowdown) and FEED blend station forms part of the FEED Package of the project. The design basis presented here intends to provide the detail engineering contractor with the technical information required to complete the engineering design specifications of the project units in a uniform and consistent manner. 1.2 Engineering Design Basis (EDB) for all facilities, containing technical information agreed between IOCL and Licensor, and IOCL and PMC shall be binding on the process design and engineering of units, utility systems and offsite facilities. Project Name
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1.3 This document constitutes common Engineering Design Basis defining overall project requirements for making the units compatible and ensuring uniform design practices for the total project. It also provides certain minimum requirements specified and used by Licensor. 1.4 This EDB constitutes the guidelines to be followed during detailed engineering design, procurement and construction of the facilities in this project. LSTK Contractor shall 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. 1.5 The design basis in Process Data Book – Book 1 – Volume 1/1, which is part of Process Package from Licensor, shall also be considered an integral part of this EDB. In case of any discrepancy between Process Data Book – Book 1 – Volume 1/1 and this EDB, LSTK contractor shall report the same to PMC/IOCL in writing for necessary clarification.
2.0 2.1
2.2
Project Description Project Title To Be Used For All Documentation Project Name
:
MS Quality Upgradation
Owner
:
Indian Oil Corporation Limited
Location
:
Digboi Refinery, Assam
Unit Numbers The Unit numbers are as follows: Sr. No.
Facility
Unit Number
1
Naphtha Splitter
034
2
Reformate Splitter
035
3
New HDT unit
036
4
Isomerization unit
037
2.3
Unit Description
2.3.1
Unit 034 Naphtha Splitter Feed Capacity : Staight Run Naphtha Weight rate in kg/h
DHDT Naphtha
12 575
1 000
Coker Naphtha
Guwahati Naphtha
1 425
1 250
The purpose of the NSU (unit 034) is to split the naphtha feed composed by SRN, CN, DHDTN and GRN into: - a light naphtha feeding the ISOM-HDT to Isomerization unit. - a heavy naphtha feeding the existing HDT/CRU reforming unit. 2.3.2
Unit 035 Project Name
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Reformate Splitter Capacity: 10208 kg/h The purpose of the RSU (unit 035) is to split reformate feed from the existing HDT/CRU reforming unit into: - a light reformate sent to HDT stripper. - a heavy reformate sent to MS pool. 2.3.3
Unit 036
HDT Unit Feed Capacity: Weight rate in kg/h
LIGHT NAPHTHA 5 069
LIGHT REFORMATE 843
The purpose of the HDT (unit 036) is to produce a clean desulfurized naphtha cut to be processed in the Isomerization (unit 037) after removal of all impurities which are currently poisons for catalysts (sulfur, nitrogen, water, halogens, diolefins, olefins, arsenic, mercury and other metals). 2.3.4
Unit 037 Isomerization Unit Feed Capacity: 5845 kg/h Isomerization (unit 037) is the conversion of low octane straight chain compounds to their higher octane branched isomers. The light hydrodesulphurized naphtha feed is dried and passed over an activated chloride catalyst in the presence of once through hydrogen (also dried). The isomerization reactor temperatures are kept low in the range 120-160°C taking advantage of the higher equilibrium concentration of isomers at lower temperatures and minimizing hydrocracking. The reaction requires a very low partial pressure of hydrogen enabling once through hydrogen to be used. A deisohexanizer tower is included in the flow scheme to recycle the low octane C 6 n-paraffins and methyl pentanes back to the reactor circuit to obtain a high octane product.
2.4
Unit on Stream factor The units are designed with on-stream hours per year at 8000 hours.
2.5
Unit Turn down factor The units are designed to operate with a turn down of 50% on flow rate.
3.0
Meteorological data * Maximum temperature: 43OC * Design maximum ambient temperature: a) DBT for cooled exchanger design i.e not exceeded more than 5% of the time during four warmest months of the year = 40OC b) DBT and RH for air blowers and air compressor design = 40OC at 95% RH c) WBT for Cooling Tower = 32OC Project Name
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* Minimum temperature: 5OC * Winterizing temperature: 4OC * Design minimum temperature: 4OC * Relative humidity- Average: 75% - Maximum: 95% * Dry bulb temperature: 40OC * Barometric pressure
- Average: 1013 mbar
Additionals data: Average wind velocity
5 Km/hr
Maximum wind velocity
100 Km/hr
Earth quake factor
IS 1893 Zone V
Rainfall : Max recorded
80 mm in one hr
157.5 mm in 24 hr Unit elevation
141.8 m above sea level
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4.0
Utilities Specifications
4.1
Utilties conditions at unit battery limit are given below. The utilities pressure are as measured at the respective headers in the piperack, adjacent to the MSQ Site. grade level.
Sl 1
Parameter Pressure, kg/cm²g Temperature, °C
2 Pressure, kg/cm²g Temperature, °C 3 Pressure, kg/cm²g Temperature, °C 4 Pressure, kg/cm²g Temperature, °C 5 Pressure, kg/cm²g Temperature, °C 6 Supply Pressure, Kg/cm²g Return Pressure, Kg/cm²g Supply Temperature, °C Return Temperature, °C 7 Pressure, Kg/cm²g Temperature, °C 8 Pressure, Kg/cm²g Temperature, °C 9 Pressure, Kg/cm²g Temperature, °C 10 Pressure, Kg/cm²g Temperature, °C 11 Pressure, Kg/cm²g Temperature, °C 12 Pressure, kg/cm²g Temperature, °C 13 Pressure, kg/cm²g Temperature, °C 14 Supply Pressure, kg/cm²g Temperature, °C
Minimum Normal Maximum MEDIUM PRESSURE (MP) STEAM 10 11 12 250 260 300 LOW PRESSURE (LP) STEAM 2.0 2.5 5.0 130 160 170 MP CONDENSATE 6 LP CONDENSATE 6 NITROGEN 3.0 5.0 6.0 Amb Amb Amb COOLING WATER 2.7 3.0 5.0 2.2 33 33 33 45 DEMINERALISED WATER 4.5 5.0 5.5 Ambient Ambient Ambient BOILER FEED WATER 20 30 40 90 100 125 SERVICE WATER 1.8 20 30 DRINKING WATER 2.5 3.5 5.5 Amb Amb Amb PLANT AIR 6.0 7.0 8.0 Amb Amb Amb INSTRUMENT AIR 6.0 7.0 8.0 Amb Amb Amb FUEL GAS 1.5 2.0 2.2 Amb Amb Amb Fresh Caustic (Strength : 10 wt%) 8 Amb -
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Mech. Design 16.9 345 8.0 185 16.9 345 8.0 185 12.0 65 7.0 7.0 100 100
90 150
10.0 100 10.0 100 4.5 100 14 75
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15
HYDROGEN 19 45
Pressure, kg/cm²g Temperature, °C
23.5 100
16 Pressure, kg/cm²g Temperature, °C 17
4.2
Electrical Power Power for electric drives and lighting shall be: •
6600 V ±6%, 3 phase, 50Hz±5% Resistance grounded for drives of 161 KW and above.
• 415, V± 6%, 3 Phase, 50Hz±5% for drives from 0.37 KW up to 160 KW, Neutral is solidly earthed. • For motors up to 0.37 KW: 230 V ±5%. • For instruments the voltage shall be 230 V ± 6%, 50Hz ± 3%, single phase AC, grounded. • UPS system for instrument & control shall be 230 V AC. • For lighting, the voltage shall be 230V ± 10%, 50Hz ± 3%, AC, single phase. 4.3
Fuel Refinery Fuel Gas Refinery Fuel Gas will be available from the refinery gas net work at the following battery limit conditions:
• Fuel gas
Pressure
Temperature
Minimum:
1.5 Kg/cm²g
Ambient
Normal:
2.0 Kg/cm²g
Ambient
Maximum:
2.2 Kg/cm²g
Ambient
Mechanical design: 4.5 Kg/cm²g
100 °C
Fuel Gas Quality : * GAS TYPE: * LHV : * HHV : * PRESS. @ B/L : * TEMP. @ B/L : Min/Nor/Max. * MOLECULAR WEIGHT: COMPOSITION HYDROGEN CARBONDIOXIDE ETHYLENE ETHANE HYDROGEN SULPHIDE OXYGEN Project Name
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kcal/kg kcal/kg kg/cm 2g °C
FG TO HDT 11 756 1.5 min / 2 nor / 2.2 max 25 ( Nor ) 18.50 MOL % 23.43 0.01 3.24 14.98 0.10 0.00
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NITROGEN METHANE CARBONMONOXIDE C5=+ PROPANE PROPYLENE ISO-BUTANE N-BUTANE 1-BUTENE 2-METHYLE PROPENE T-2-BUTENE C-2-BUTENE 1,3 BUTADIENE ISO-PENTANE N-PENTANE TOTAL
0.53 51.07 0.52 2.97 0.72 0.00 0.15 0.53 0.04 0.03 0.00 0.00 0.00 0.73 0.95 100
Note : All new heaters will be fuel gas fired. 4.4
Inert Gas (N2) Licensor’s minimum quality requirements for Nitrogen is as follows (vol%) and same shall be made available by IOCL at unit battery limit O2
5 ppm max.
CO
20 ppm max.
CO2
20 ppm max.
Other carbon compounds 5 ppm max. Chlorine
1 ppm max.
Water
5 ppm max.
H2
20 ppm max.
N2
99.7 mini.
Noble gases
Balance
N2 QUALITY (volume composition) N2
99.9 vol % (normal)
O2
10ppm
CO
20ppm max (peak value) – 10 ppm normal
CO2
20ppm max (peak value) – 10 ppm normal
Chloride
1ppm max
Water
5ppm max Project Name
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H2
20ppm max
Other carbon compound
5 ppm max
Noble Gas
Remain
4.5
Hydrogen The quality of make-up hydrogen available at the battery limit is as follows – Component
Mole %
Hydrogen
99.5
C1
0.5
H2S
0.0002
≤ 0.0002
U-tube bundle
≤ 0.0002
≤ 0.0002
Fixed T/sheet or U-tube bundle
Corrosion allowance Unless otherwise specified corrosion allowance for all exchangers should be as per TEMA standard (Class R). For U tube exchanger, radius U bend should be at least 3 times tubes OD. Project Name
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c) Design pressure for heat exchange equipment •
Maximum anticipated operating pressure plus 10% or 2 kg/cm², whichever is greater. The minimum design pressure is 3.5 kg/cm² g.
•
Exchangers that are subject to pump shut off, in general, shall have design pressure equal to maximum shut off pressure as follows. Equipment which could have to bear the shut-off pressure of a pump in case of a valve closing (either control valve or block valve) is designed for the following pressure: Design pressure = Design pressure of the suction vessel + liquid height at vessel HLL at pump suction + 125% of pump differential pressure.
•
In case exchanger is operating under vacuum or in steam service, design should be for full vacuum.
•
The tubes of feed / effluent exchanger in high pressure service need not be designed for full design pressure of the shell provided these components can never experience these condition. Start-up, shutdown & emergency depressurisation condition should be considered. In addition to above criteria, design pressure of an exchanger should reflect the location and set pressure of the safety relieving valve protecting it. For high differential pressure, the design pressure of lowest pressure side should be at least 0.77 x highest pressure side design pressure.
d) Design temperature for heat exchange equipment
5.5
•
Exchanger operating between zero to 400° C shall be designed for the maximum anticipated operating temperature plus 28° C but not less than 65° C.
•
In case of possible loss of flow of cooling media, the tubes may be subjected to full process inlet temperature with no margin. These components should be designed for maximum process anticipated temp. of hotter medium.
•
For feed / effluent exchangers of reaction section + 25°C 35°C to be added to max. operating temperature to take into account the temperature profile modification at low capacity.
•
Exchangers operating at 0°C and below should be designed for minimum anticipated temperature. For operating temperatures below 0°C, design temperature to be minimum operating temperature – 5° C or minimum ambient temperature, whichever is lower.
•
The effect of autorefrigeration due to depressurisation to atmospheric pressure will be taken into consideration (LPG systems for example).
Pumps •
Spare philosophy : 100% spare for continuous service and critical intermittent service
•
Drive of pumps : Electric Motor, unless otherwise for process/safety reasons
•
Equipment which could have to bear the shut-off pressure of a pump in case of a valve closing (either control valve or block valve) is designed for the following pressure: Design pressure = Design pressure of the suction vessel + liquid height at vessel HLL at pump suction + 125% of pump differential pressure.
10% oversizing will normally be specified
20% oversizing will be specified on reflux and reboiler flow rates. Project Name
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The pump data sheets specify the process flow without provision for the minimum flow which will be specified by the pump’s vendor. Wherever required, the LSTK contractor to add the pump minimum flow, as per vendor information, to the process flow specified in the data sheet to arrive at pump capacity.
Electrical motor drivers will be specified. Critical service drivers will be either steam turbines or connected to electrical emergency network.
Continuous service process pumps will be specified with full spares.
5.6
Common spares can be specified whenever appropriate for metering pumps
Pumps on P&ID’s are shown with permanent strainers at suction.
All pump shall be provided with bridle cooling water lines (for bearing cooling, gland cooling, seal cooling) , as per vendor information, even if these lines are not shown on Licensor’s P&ID’s in FEED package. The return from all the pumps to be taken into a vessel from where the water to be pumped to the pumps shall be connected to a separate cooling water return header which will run parallel to main return header. The dedicated cooling water return header for pumps shall be connected to main return header at the battery limit with provision for isolation. Cooling water to / from each pump line sizes shall be minimum 1” NB. Pump vendor’s battery limit for cooling water shall be 1” NB ANSI 31.16 flange with counter flanges, gaskets, fasteners for both CWS and CWR lines at individual pumps.
Sight glass for cooling water flow at pump (bearing housing, seals etc.) should be ball type.
Drains from pump base plates shall be routed, through an open funnel and pipeline, for each individual pump, to nearest oily water sewer catch point.
Compressors •
Spare philosophy : For reciprocating compressors, provide 2 of 100% For Centrifugal, no spare required
5.7
•
The recommendation given in the API Recommended Practice 521, last edition, Appendix “F” and API Recommended practice 520, last edition, Appendix “B”, will be followed.
Electrical motor drivers will be specified. Critical service drivers will be either steam turbines or connected to electrical emergency network.
Owing to the high reliability of centrifugal compressors, a spare will not be specified. Full spare capacity will be specified for reciprocating compressors.
The compressor oversizing will be specified as follows: Make-up
(10 20% minimum)
Recycle
Depends upon the process
Gas quench
20 25% minimum
Start-up Blowers and Compressors •
Spare philosophy: No spare
•
Driver : Electric Motor
•
Rated flow for ID fan: 120% of normal flow
•
Rated flow for FD fan: 115% of normal flow
•
Rated Head for both: 125% of normal head
•
Spare for ID fan: No Project Name
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5.8
•
Spare for FD fan: yes
•
Driver: Motor
•
Control: 110% of rated shaft power variable speed
Stack Height Limitations •
Minimum stack height should be worked out using formula: H = 14 x (Q)
0.3
or 60 metres whichever is higher
Where, H = height of stack in metres Q = SO2 emissions in kg/h
6.0
Material of Construction Design Philosophy
6.1
Introduction
6.2
•
The criteria for selecting equipment and piping metallurgy for this project are based on Licensor’s extensive experience with hydro-processing technologies, and the general practices of the refining industry.
•
The primary objective in material selection is to prevent failure resulting from environment, normal operation, and upset conditions. The material selection for this purpose is based on mechanical design conditions.
•
The secondary objective is to provide adequate protection against the gradual material loss by corrosion, to achieve the targeted design life. Equipment or piping normal operating conditions are used for selecting the appropriate metallurgy for a targeted design life. Therefore, the selected material for a given service should satisfy both the objectives of metallurgical stability, and design life.
Recommendations for material of construction a) Equipment Design Life •
The following design life may be applied to the design of the unit as a standard base: Heavy wall reactors / vessels:
30 years
(including non removable internals and catalyst bed support beams) Reactor removable internals:
20 years
Columns, vessels:
20 years
Heat exchangers shell and similar services:
20 years
High alloy exchanger tube bundles:
10 years
Furnace tubes:
10 15years
Piping:
10 15 years Project Name
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Carbon steel / low alloy heat exchanger tube bundles:
10 years
b) Corrosion allowance The following values are resulting from Licensor’s experience based on process know-how in term of design criteria and also on operating Units feedback. They might be reviewed following detail engineering or client specific requirements. However, it must be noted that such a decision would be under the detail engineering or client responsibility and should be made by taking into account the procedures of inspection used by the owner. i) Pressure Retaining Equipment •
Licensor specifies that the calculated corrosion allowance shall be based on the designed number of years in service.
•
For carbon steel, consider a minimum corrosion allowance (CA) of 1/8” (3 mm) in general for non-corrosive environment as regular hydrocarbon.
•
In normal operation under Wet H2S Service, carbon steel shall have a CA of ¼”(6mm).
•
For other materials, minimum CA is 3 mm (1/8”) for low alloyed steels (up to 2.1/4% Cr included), 1.5 3.0mm (1/16”) for low alloyed steels (up to 9% Cr included) and 0.75 mm (1/32”) for stainless steel.
•
The corrosion allowance of 1.5 mm for low alloyed steels (up to 9% Cr) may be extended, in accordance with owner / user, to 3mm for critical equipment (i.e. Reactors, HP Vessels and Furnaces).
•
If equipment is cladded or overlayed, undiluted thickness of clad or overlay is considered as CA allowance.
ii) Internals •
Definitions:
“Non removable internals” means:
welded internals to vessels (support rings, support lugs, etc).
“Removable internals” means:
Non welded internals to vessels (fractionation trays, distributor trays, mixing trays, catalyst support trays, support beams, inlet diffusors, outlet collectors, Quench pipes, thermocouples supports, etc.).
•
Removable parts of carbon steel and low alloyed steels (up to 9% Cr) internals shall have a minimum CA of one half of total vessel shell CA on each side in contact with the operating fluid.
•
Fixed internals carbon steel and low alloyed steel (up to 9% Cr) made shall have the full corrosion allowance on each face (in total 2 times the designed CA of shell).
•
Ref to BEDQ P-46/96
Project Name
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For Carbon Steel and Low Alloyed Steel (up to 9 % Cr included): Minimum corrosion allowance (CA)
Axens standard recommendation
Client request Agreed
Removable internals
On each exposed surface: ½ of total CA applied to vessel shell On each exposed surface: full CA applied to vessel shell
Agreed
Fixed internals and structural support beams (*)
(*) i.e. Catalyst bed support beams and distributor / quench trays support beams of reactor • •
In general, no corrosion allowance will be given for removable internals made of stainless steel (13% Cr and above) as also for those made of non-ferrous high alloyed. However, a corrosion allowance shall be specified for some internals exposed to severe conditions such as non removable internals of reactor, catalyst bed support beams of reactor. These internals shall therefore have the CA, based on the reactor design life specified in paragraph “Equipment Design Life”, on each exposed surface.
•
No corrosion is considered for internals made with V wire screen or wire mesh.
iii) Process Piping •
For uniform corrosion, corrosion allowance for piping can be distributed as follows: Expected rate ≤ 5 mpy
Corrosion allowance 1/16” (1.5mm)
5 mpy 25 mpy
Upgrade the Material Specification
mpy : thousands of inch per year •
As a standard general practice, corrosion allowance for carbon steel piping can usually be split into four different levels of specifications as mentioned here below: Non-corrosive environment
0” 1.5 mm
Compressed Air, Nitrogen, Dry Hydrocarbon, etc. Mildly-corrosive environment Cooling water, Humid Hydrocarbons,
1/16” (1.5mm)
Steam, etc. Project Name
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Moderately-corrosive environment
1/8” (3mm)
Sour Water, Wet Sour Gas, Amines Caustics, etc. Severely-corrosive environment
1/4” (6mm)
Aerated water, Hot sulfur or sulfide (>260°C), wet salts, wet CO2 (ambient temperature), Hot steam (>540°C), etc. Note: Except for specific cases, or following owner requirements, it is the Licensor’s general practice to specify a minimum corrosion allowance of 0.75 1.5 mm on the stainless steel made piping components. c) Minimum Design Metal Temperature (MDMT) MDMT parameter shall be defined during material design in order to select materials capable of resisting brittle fracture at the said Minimum Design Metal Temperature. This is purely a mechanical design requirement (no corrosion concern). Three different criteria may be used to establish the minimum design temperature: •
It may be based on consideration of the lowest expected operating temperature, the lowest ambient temperature or an operational upset such as auto-refrigeration, or any kind of other source of low temperature. A transient condition such as auto-refrigeration may be governing, particularly if the restarting procedure does not permit warm-up before re-pressurising.
•
It may be established as the minimum exemption temperature allowed by the applicable engineering code. For example, the ASME B31-3 piping code permits most carbon steel piping with wall thickness of 12.7mm or less to be exempt from impact testing if used at temperature not colder than –29oC.
•
If the material of construction is impact tested, the Minimum Design Temperature is usually taken to be the said impact test temperature (which is, for example, the case for HDT reactor). The impact test conditions being defined as a function of the steel grade. Minimum Design Metal Temperature for reactors components is usually specified as – 30 oC or – 18oC (depending on steel grade considered) unless process conditions and/or owner requirement dictate a lower temperature
In the same manner, suitable measures shall be taken in respect of the water temperature during the hydrostatic test to avoid any brittle fracture. d) Temperature Embrittlement Low alloy steel such as 2.25Cr – 1Mo, 2.25Cr – 1 Mo – V and 3Cr – 1 Mo – V are susceptible to temper embrittlement when operated in the temperature range of typically 300 – 550 oC (i.e. hydrotreaters or hydrocrackers). Under such operating conditions, embrittlement phenomena may appear in connection with the behaviour of Cr-Mo steels after long term service exposure. Affected material can show a considerable reduction in toughness properties at ambient temperature, and special precautions need therefore to be taken to avoid brittle fracture, especially during transient phases (start-ups and shut-downs) and hydraulic pressure tests. This mainly applies to the components made from steel grade specified here above for such equipment as the reactors, associated vessels and certain HP heat exchangers. It is stressed that temper embrittlement effects are normally much more moderate for lower alloyed steels (e.g. 1.25Cr-0.5Mo). i) Restrictions to chemical composition Project Name
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Refer to section for specific recommendations for the metallurgy of the reactors ii) Increase of transition temperature In addition to the stringent restriction of the chemical composition, most users specify a sampled step cooling of steels coupons issued from material used for fabrication of shell and heads susceptible to Temper Embrittlement. Step cooling treatment, imperatively performed after PWHT, will simulate a fraction of the increase in the ductility-brittle transition that should occur after long-term service. For information only, a typical step cooling sequence could be: Heat to 595 oC
Hold for 1 hour, cool at 6 oC/h max. to 540 oC.
Heat to 540 oC
Hold for 15 hours, cool at 6 oC/h max. to 525 oC
Heat to 525 oC
Hold for 24 hours, cool at 6 oC/h max. to 495 oC
Heat to 495 oC
Hold for 60 hours, cool at 3 oC/h max. to 470 oC
Heat to 470 oC
Hold for 100 hours, cool at 28 oC/h max. down to 315 oC and then Air cooling.
This simulated isothermal embrittlement results in a certain increase (shift) of the material’s transition temperature. The increase in transition temperature (TT 55) from its original value has become an accepted tool for the determination of temper embrittlement susceptibility. In order to characterise a material for temper embrittlement resistance, a relationship was developed using the original or “as fabricated” TT 55 and the increase in TT 55 (Δ TT55). After step cooling heat treatment for impact properties (Charpy-V at thickness ) should meet the following requirements:
1/4T and 1/2T material
TT55 + 3ΔTT 55 < 10oC Where :
TT55 :
the 55 Joule transition temperature
ΔTT55 :
(TT 55 [step cooled] – TT 55 [original value])
The method generally used to avoid brittle fracture consists in maintaining pressure at a low level until reactor vessel exceeds the Minimum Pressurising Temperature (in that way, resulting stresses are then reduced below a stress value which could lead to brittle fracture propagation). This MPT takes into account the TT 55 estimated for the embrittled conditions and a safety margin which mainly takes into account the effect of hydrogen absorbed during operation (effect depending on wall thickness, steel quality and process conditions, it is the vessel vendor responsibility to guaranty the MPT values for the considered equipment). Below the MPT, the pressure should be kept not exceeding 25% of the design pressure for equipment built per ASME Code Section VIII, Div. 2 (some owners may allow higher value for equipment built per ASME Code Section VIII, Div.1 considering the higher safety factor on allowable stress values in that case). Any way, the MPT criteria for HP Reactors should always be given or approved by vessel vendor. e) Stabilizing Heat Treatment Austenitic stainless steel can become sensitised after prolonged exposure at elevated temperatures in the range of 425 – 850 oC (800 – 1600oF). This structural transformation during long term service at elevated temperature is due to a precipitation of chromium carbides (generally Cr23C6). In fact, this precipitation at the grain boundaries does not affect the mechanical properties. On the other hand, it involves sensitising to intergranular corrosion (refer to “Polythionic acids”). Although stabilised types of stainless steels (such as 321, 347 and 316Ti) have a much higher resistance towards sensitisation than the non-stabilised ones, literature indicates that their resistance can be further improved by stabilising heat treatment (around 900° C) of the solid SS individual components. This procedure encourages the formation of stable carbides, formed either from Titanium for Types 321 and 316 Ti or from Niobium/Columbium for Types 347, without chromium depletion. Project Name
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Therefore such stabilisation heat treatment is recommended for the furnace tubes. In addition it could even be decided to apply such heat treatment also for (the hottest parts of) the stainless steel piping despite its operating temperature remains somewhat lower. Note that no fissuring corrosion experiences have been reported to Licensor when using overlaid 347 SS (refer to Polythionic Acid Attack here after). f) Metallurgy Selection Guide Design The various modes of main corrosion concerns that are specific to refinery hydro-treating units are exposed and discussed in the following. i) High Temperature H2 Attack In services containing hydrogen, materials are selected based on their resistance to high temperature hydrogen attack. Hydrogen attack can occur at temperature above about 220°C. Dissolved hydrogen can react with iron carbides generating methane gas (CH 4) which is trapped into the metal. As the concentration of methane gas increases, increasing pressure begins to tear the grain boundary, causing fissures and then cracks. Simultaneously, the loss of carbides lowers the strength of the metal. Material recommendation is based on the Nelson curves (refer to API RP 941: “Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants”) for hydrogen resistance. The material is selected based on the maximum operating temperature, and hydrogen partial pressure, with appropriate allowance added to each of the variables to account for various operating modes. As the figures considered in API RP 941 are based largely upon empirical experience, safety margin of 28°C (50°° F ) and 3.4 bar (50 psi) below the relevant curves (respectively for maximum operating temperature and maximum operating hydrogen partial pressure) are typically used when selecting steels. Notes: The (P,T) values for Nelson Curves application shall not be compared with the Mechanical Design Pressure and Temperature which are used for mechanical calculation. If the temperature and pressure fall on one of the curves, then the higher alloy shall be used. There is no credit taken for a corrosion resistant stainless steel cladding, since hydrogen can still diffuse through the cladding. Where alloy cladding is used, the base metal shall consequently be selected for H2 Service. ii) High Temperature H2/H2S Corrosion The choice of material for services containing H 2S in hydrogen rich environment is based on the acceptable corrosion rate, to obtain the desired equipment life. At temperatures higher than 200°C, the corrosion rate is estimated as a function of temperature and H 2 S partial pressure for the selected material. The corrosion rate curves for the various metallurgy is based on the original NACE data (Couper & Gorman curves), and this is considered to provide a desirable degree of conservatism in the design. iii) High Temperature Sulphide Corrosion in H2 Free Environment The corrosion rate for services containing organic sulphur at temperatures above 260°C in hydrogen free environments (considered to be with ppH 2 < 50 psia) is obtained from curves based on the original NACE and API data. The estimated corrosion rates may be obtained, by using the Mc Conomy curves, as a function of normal operating temperature and organic sulphur content. iv) Naphthenic Acid Corrosion Naphthenic acid is the collective name given to the organic acids contained in some crude oils. The naphthenic acid content of the raw feed is generally expressed as neutralisation number, as determined by ASTM test methods D 664 or D974. Project Name
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It can cause corrosion at temperatures as low as 175 ° C (350°F). However, serious corrosion, pitting and/or grooving type, usually does not occur until the temperature exceeds 230 °C (450° F). Type 316L or 317 L SS (SS containing at least 2,5% wt. of molybdenum) should be used when neutralisation number exceeds 1.5 mg KOH/g oil for operating temperatures above 230 °C. Type 317 being preferred for severe combinations of TAN (Total Acid Number), Temperature, and velocity/turbulence, since the molybdenum content of this grade ranges from 3.0 to 4.0 wt. %. Carbon steel metallurgy is considered to be sufficient for equipment and piping for Total Acid Number TAN < 1.5 mg KOH/g and temperatures below 230°C. For all other conditions stainless steel specification shall be considered. v) Wet H2S Corrosion Wet sour services are common in the hydrocarbon producing and processing industries. The major concern for such services is the various forms of hydrogen cracking produced by wet hydrogen sulphide corrosion. As a matter of fact, H 2S dissociation in presence of free water leads to atomic hydrogen formation (particularly) in the cold part of the reaction section after the washing water injection in the reactor effluent, H2S amine absorbers and strippers overhead equipment are concerned), and can cause the following: •
Sulphide Stress Corrosion Cracking (SSCC)
•
Hydrogen blistering, Hydrogen Induced Cracking (HIC), Stress Oriented Hydrogen Induced Cracking (SOHIC).
The susceptibility of deterioration by the above mentioned risks are lowered, by specifying the following for the carbon steel metallurgy: •
Definition of different types of associated specifications Typical Applicable Documents: - Material requirements for Sulfide Stress Corrosion Cracking Resistant Metallic Material as per NACE Standard MR 01-75, latest edition. - Materials and Fabrication Practices for New Pressure Vessels Used in wet H 2S Refinery Service as per NACE International Publication 8X194. - Methods and Control to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining environments as per NACE Standard RP0472, latest edition.
•
Licensor’s general recommendations for carbon steel in “H2S Service”. Carbon steel must be Fully Killed Carbon Steel type Maximum Allowable Hardness 22 HRC Ni content less than 1% Carbon content shall be 0.20% maximum Plate material shall be supplied in Normalised condition, regardless of thickness Typical limitation of Carbon Equivalent are the following: - Ceq < 0.42% for plate less than 2” thick - Ceq < 0.45% for plate from 2” thick to 4” thick - Ceq < 0.48% for plates greater than 4” thick With Ceq = C+Mn/6 + (Cr+Mo + V)/5 + (Ni + Cu)/15 Project Name
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These Ceq values are indicative and may be re-considered if needed regarding the used steel grade. In that case, new proposed values should be submitted to EPC for approval. Thermal Stress Relieving required for all welds (PWHT) and/or for cold bend zone, even if it is not required by code. Typical recommendations for Process Piping and accessories in “H2S service” - Process piping shall be seamless type piping - Piping and accessories: Recommended Maximum allowable Phosphorus content 0.030% Recommended Maximum allowable sulphur content 0.020% An acceptable designation is ASTM A-106 Gr.B (applicable also for vessel’s nozzles as ASME SA-106-B) -
Flanges and accessories: Recommended Maximum allowable phosphorus content 0.030% Recommended Maximum allowable Sulphur content 0.025% An acceptable designation is ASTM A-105 for forging and ASTM A-216 WCB for castings (applicable also for vessel’s flanges as ASME SA-105).
These impurities level criteria are given for information, the final specification concerning the P & S impurities contents will be decided by the EPC (based on the owner specification if any) following its typical practice for “Piping in Sour Service”. •
Licensor’s recommendations for Carbon Steel Plates “HIC resistant”: The most important factor to avoid HIC is the purity (cleanliness) of the steel. The nonmetallic inclusions must be very low. In addition to the general recommendations relative to “H2S Service”, when “HIC resistant steel” is specified, the following requirements should also be met:. Plates for Pressure Parts of the Vessels: Carbon steel made by vacuum degassing process Oxygen content less than 0.002% Maximum allowable Phosphorus content 0.008% Maximum allowable Sulphur content 0.002% (0.007% if inclusion shape controlled by calcium treatment) Calcium treatment, if any, shall be Ca/S ratio > 1.2 It is required to pass the NACE standard TM 0284 (Evaluation of Pipeline and Pressure Vessels Steels for Resistance to Hydrogen-Induced Cracking) by using the acidified test solution specified in NACE standard TM0177 (Laboratory Testing of Metals for Resistance to Sulfide Stress Cracking and Stress Corrosion Cracking in H2S environments) with: Crack Length Ratio (CLR) ≤ 5% Mill test reports shall include the values for the crack length ratio (CLR), crack sensitivity ratio (CSR) and crack thickness ratio (CTR) as defined in NACE standard TM-02-84 and also carbon equivalent (CE). A possible designation is ASTM A 516 gr60. Project Name
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Note : The use of a standard carbon steel grade with SS cladding can be an alternative to “HIC resistant steels” especially for thick-wall vessels like cold HP separator since it should involve only a small cost premium over “HIC resistant steel” construction (the procurement could even be sometime more easy). The resulting protection against corrosion would be enhanced provided that SS solution would not lead to other kind of corrosion and/or deterioration. vi) Amine Stress Corrosion Cracking Amine solutions can cause pitting and stress corrosion cracking in carbon steels. Amine stress corrosion cracking can attack non-stress-relieved CS piping and equipment. Hence, stress relieving (PWHT) is recommended for all the welds and the cold formed parts of CS equipment and piping, regardless of operating temperature. API RP-945 (Avoiding Environmental Cracking in Amine Units) and the guides from technical committee NACE T- 8-16 would apply to these services for equipment and lines. Killed carbon steel is usually considered as acceptable under amines operation when fluid velocities are limited to a maximum of 0.9 m/s (3 ft/s) for rich amine and of 2.1 m/s (7 ft/s) for lean amine. On the other hand, it is recommended to specify type 316 stainless steel for turbulence and/or flash zone and/or high fluid velocities. Note that it is generally preferred to use stainless steel as cladding and not as solid form on account of possible presence of chlorides, highly dangerous for SS, in the fluid. The recommendations outlined for the wet H 2 S corrosion are applicable for the amine service as well. In particular, HIC resistant steels should be used for amine H2S absorbers. vii) Ammonium Bi-Sulphide Corrosion Water injection upstream of the reactor effluent coolers is required to prevent plugging from watersoluble ammonium bi-sulphide salts. The water injection rate should be adequate for saturating the vapour phase, and to provide about 25% excess water as liquid phase, at the coolers inlet. The water injection rate should also be sufficient to reduce the salt content of the sour water to less than 4 wt %. Licensor had specified Killed CS metallurgy for this service in several units. Based on Licensor’s experience, Killed CS metallurgy is sufficient for this service if the sour water salt content is maintained at less than 4 wt %, and the total fluid velocity is kept in the range of 3 to 6 m/s. Also, it is important to control the wash water quality as recommended by Licensor, especially the oxygen (less than 15 ppbw) and chloride (less than 50 ppmw) content to minimise corrosion. viii) Polythionic Acid Attack Where austenitic stainless steels have been selected, chemically stabilised types (321 SS and 347 SS) are required for processes in which the normal maximum sustained operating temperature exceeds 425° C, because of their higher resistance to intergranular corrosion and stress corrosion cracking caused by polythionic acid attack. This kind of attack can occur, especially during the shutdown periods as a result of sensitisation during service. As a matter of fact, once opened to the atmosphere, the association of iron sulphides produced during operation and air/moisture leads to formation of polythionic acids H 2 SxO6 . The resulting acid corrosion leads to the formation of intergranular cracks, typical of polythionic SCC corrosion (mainly into Heat Affected Zone). It is therefore strongly recommended to passivate the unit before contacting the equipment with atmosphere. The NACE Standard RP 0170 should also be followed as a guideline to carry out the soda ash washing of all the zones to be in contact with atmosphere after shut-down. This procedure is recommended in all the cases, even in the case of stabilized SS use. Based on Licensor’s experience, 347 SS shows a better resistance to sensitisation than 321 SS, and is recommended for severe services. Project Name
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However for maximum resistance to sensitisation, types 321 and 347 SS should be subjected to a stabilising heat treatment. ix) Chloride Attack Aqueous chlorides provide an excellent electrolytic environment for corrosion. Austenitic stainless steels are well known for their susceptibility to failure by chloride stress corrosion cracking (CSCC). This phenomenon may appear under almost any set of circumstances relative to the following critical variables: •
Temperature : CSCC is virtually unknown for neutral pH solutions at temperature below 60°C (140° F).
•
Chloride concentration : In evaluating the risks for CSCC, consider concentration mechanisms such as evaporation, which can increase low contents to dangerous levels. For this reason, vapour-liquid interfaces and crevices such as socket welds are to be avoided. Even trace of chloride into water is sufficient to induce stress corrosion cracking.
•
Stress: Stresses are usually due to the residual tensile stress caused by welding or cold work such as U-Bending heat exchanger tubes. Stress relieving heat treatment is also sometimes used to reduce cold forming or welding induced residual stresses in austenitic stainless steels.
In consequence of the difficulties to guaranty the environment state in presence of chloride, CSCC resistant alloys should be specified where CSCC is anticipated. Increase in molybdenum content enhances resistance of austenitic stainless steel to chloride attack (317L > 316 > 304, 321). Super austenitic stainless steel (904L), or duplex alloy stainless steel, as alloy 2205 (22 Cr-5.5 Ni-3 Mo-N/UNS S31803) or higher nickel alloys types such as Alloy 400 and Alloy 825 which are significantly more resistant to CSCC than austenitic 18-8 SS should also be considered. Notes : •
Monel, which may be specified where resistance to hydrochloric acid is required (top section of the crude tower for example), shall not be used when ammonia is injected for corrosion control due to its high susceptibility to stress corrosion cracking.
•
Water used for flushing or during hydro-tests in presence of austenitic stainless steel materials should typically have a chloride content of 30 ppm, not exceeding 50 ppm.
x) Caustic Soda Carbon steel is the basic recommended material of construction for moderate temperatures and concentrations. Threshold of operating limits are usually determined by using existing NACE caustic soda services curves which indicates preferred material at various temperatures and concentrations. PWHT is recommended for Carbon Steel welds in services above these thresholds to minimise the risk of stress corrosion cracking. Austenitic stainless steels may sometimes be specified up to 120° C (beyond this temperature threshold, these alloys can be susceptible to caustic stress corrosion cracking). However, caustics being often contaminated with chlorides, and since there are other competitive materials choices, selection of austenitic stainless steels for caustic service is usually avoided. For high severity services, Nickel Alloys such as Monel will be preferred. Anyway, it is highly recommended in caustic soda services to avoid at one and the same time piping low points where caustic could become highly concentrated, and hot spots. Project Name
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Note : Systems in which carbon steel could be in contact with caustic soda carryover during upsets should be stress relieved/postweld heat treated. If not possible, this system should be made of appropriated alloys as defined here above.
7.0
Process Control and Instrumentation
7.1
Unit operations shall be controlled from a central control room common to other units and shall be a microprocessor based Distributed Digital Control with Supervisory computer system. All process and product streams shall be measured and recorded. Level alarms wherever required shall be used. Dial thermometers shall be provided at inlet and outlet of heat exchangers. In case of very critical services hardwired alarms shall be provided as stand by unit. For Thermocouples in Temperature Control Loop, closed loop or connected to PLC, Temperature Transmitters shall be used.
7.2
Control Philosophy The plant shall be operated through Video Consoles along with Console panel with few dedicated Instruments, Recorders, Annunicators etc. and a Console desk having selector switches, push buttons, status indicators. The field switches, which are required to be triplicated for this purpose are shown on the P&I Diagram. The Interlocks (LOGIC) for the unit shall be performed in PLC capable of communicating with DCS. 2 out of 3 voting logic is envisaged for critical interlocks only.
7.3
Instruments •
All alarm points, Software and hardwired to be indicated in P&ID with proper legend as per ISA symbol.
•
All specification data sheets shall be as per ISA.
•
For security interlocks transmitters shall be used as field instruments connected to Analog Input card of PLC directly. No switches shall be used.
•
For temperature, Flow and interface level – Transmitters shall be used, Switches shall not be used.
No switches to be used anywhere in the unit including the packaged items •
All IOCL standards and instrument hook-up drawings may be used
•
For all Temperature closed loops, field mounted temperature transmitters to be used.
•
1 ½ “ flanged type thermowell with minimum flange rating of 300# shall be considered. Screwed type thermowells shall not be used.
•
Dedicated field instruments (Transmitters) shall be used for trip activation and critical alarms. Separate nozzle / tapping shall be used for such instruments.
•
Limit switch : proximity type limit switch may be used.
•
The symbols to be used will be in accordance with ISA (see General legend diagrams).
•
Alarms and shutdown devices: Alarms and shutdown devices will be specified where required for process, safety or equipment protection considerations. Shutdown device connections will be independent from instrument connections. All safety devices are connected to a PLC (Programmable Logic Controller Project Name
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7.4
•
Instrument impulse lines to be insulated / traced, wherever required, to avoid condensation / congealing.
•
Critical rotating equipment to have vibration monitoring system with control room indication.
Safety Valves •
Double safety valves shall be provided with isolation valves, such that on-stream isolation and maintenance of a safety valve is possible without affecting unit operational safety requirements. This shall be considered for all operation failure cases (guided or no-guided). Where safety valve provision is guided by fire case, single safety valve with isolation valve (locked open) shall be provided. However, in case of provision of safety valve considering fire case as governing case and where such provision is also required from process point of view, stand-by safety valve is to be considered. All isolation valves of pressure safety valves shall be lock open/close type. The isolation valves shall be mechanically interlocked where ever two PSVs are provided.
•
Pressure relief valves are normally installed on the equipment.
•
Pressure relief valves in hydrocarbon vapour service will normally discharge to a vapour system.
•
All relief valves load and size shall be calculated according to the following mentioned codes: -
API 520
-
API 521
-
API 526
-
API 527
-
API 2000
The size of relief valves are based on either over-pressure condition, fire exposure or vacuum situation for a particular system. •
•
Typical over pressure conditions are: -
Blocked Discharge
-
Inadvertent Valve Opening
-
Utility Failure
-
Electrical / Mechanical Failure
-
Loss of Air Cooler Fans
-
Loss of Heat in Fractionation
-
Loss of Instrument Air or Electric Power
-
Instrument Failure or Blow-by
-
Reflux Failure
-
Abnormal Heat Input From Reboilers
-
Heat Exchanger Tube Failure
-
Trapped Liquid Expansion
The following guidelines shall be applied for safety valve selection and line sizing: - Valve selection will be based on maximum operating temperature and relief valve set pressure. Project Name
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- Conventional type relief valves shall be used for the cases where the built-up back pressure and the variable superimposed backpressure doesn’t exceed 10% of the set pressure. For the cases, where it exceeds 10%, but is below 50 % of the set pressure, balanced bellow type relief valves shall be used. Pilot operated relief valves shall be used for the systems where maximum set point accuracy is required. Such relief valves shall be installed in equipment, which operate very close to the set pressure. - Safety valves on column circuits are preferred to be located at the highest point in the overhead vapors lines. - Pressure drop in a PSV inlet line must not exceed 3% of the set pressure of the PSV. -
PSV inlet and outlet line size has to be equal or greater as the PSV nozzle sizes.
- PSV discharge to be free draining to flare header. PSV inlet to be free draining towards the source. -
Inlet and outlet valves to be full port.
- Relief valves, which are susceptible to plugging, shall be steam traced and have a rupture disc installed under them. -
Staggered pressure setting may be specified to minimise losses.
- For atmospheric relief, the open end of discharge will be located 30m from any source of ignition. Discharge is usually 3m higher than any equipment or manholes (ladder, platform etc.) within 15m radius. - Relieving device discharge lines, shall be sized based on the back pressure data - The flare header shall be sized according to pressure drop constraints. •
7.5
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.
Control Valves •
As a default, control valves upto 8” size and in steam manifold of block and bypass valves. Bypass valves shall above 8” size, block and bypass requirement shall be However, Control valves not having block and bypass handwheel for manual operation.
service shall be provided with a be globe valves. For control valve decided on case to case basis. provision shall be provided with
All control valves should have two isolation valves and min one bypass valve. •
All control valves shall be provided with 3/4 drain valves, which can be provided as: Upstream and downstream of all control valves Drain valve shall be capped (In non-hydrocarbon & non-IBR LP steam service) Drain valve shall be blind flange (In all Hydrocarbon, toxic/hazardous chemicals & IBR steam service)
•
Shut down valves shall not be provided with block and bypass valves.
•
The control valve pressure drop should be the greater of the following – 50 – 60 % of the total frictional loss excluding the control valve 0.7 Kg/cm 2 15 % of the pump differential head Project Name
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For valves installed in extremely long or high pressure drop lines, the percentage drop across control valve may be lower, but at least 15 % up to 25%, where possible, of the system friction drop.
7.6
•
The selected control valve must allow maximum flow through it at 80% opening (maximum) and minimum flow at 15 to 20% opening minimum.
•
Control valves must be evaluated for flashing / cavitation and choked flow condition before selection.
Flow Indication For material Balance all flow indications should be of mass flow type Any other flow instruments should have pressure and temperature compensation. •
Flow indications with totaliser for the following streams entering / leaving the battery limit shall be available in the control room over and above those required for process control of the unit: -
All Feed to the unit
-
All Products from the unit
-
Fuel gas to the unit
-
Hydrogen rich gas to the unit
-
Hydrogen for start-up
-
Hydrogen to the unit
-
Any other relevant streams
•
7.7
Flow indications with totaliser for the following utility streams shall be available in the control room: -
HP/MHP steam to/from the unit
-
MP steam to and from the unit
-
LP steam to and from the unit
-
Cooling water to the unit
-
Condensate from the unit
-
Condensate from other units
-
Nitrogen to the unit
-
BFW to the unit
-
Plant Air & Instrument Air to the Unit
-
DM Water to the Unit
Level Instruments •
Standpipes with a default size of 2” NB shall be considered for only clean, non-viscous and non-crystallizing 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. Project Name
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•
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 switches for alarm and trip. Standpipe shall not be connected to process lines Standpipes to have isolation valves at top and bottom tapping. Standpipe bottom tapping to have slope towards the vessel. Standpipe connections to be on sides only.
7.8
•
Radar type of level gauges shall be specified for tanks
•
Diaphragm seals shall be specified for congealing / high viscosity / corrosive / crystallizing services (pressure upto 600#).
Utility Lines battery limit Instrumentation •
Utility Lines : As a minimum, the following shall be provided in unit utility headers: UTILITY
Local PI
DCS PI
MP/LP Steam
YES
Condensate
YES
CW supply
YES
CW return
YES
Instrument Air
YES
Plant Air
YES
Nitrogen
YES
YES
Fuel Gas
YES
Hydrogen
DCS PAL/ PAH
YES
Local TI
DCS TI
DCS TAL/ TAH
YES
YES
YES
DCS FQ
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
YES
BFW
YES
YES
YES
YES
YES
DM water
YES
YES
YES
Service Water
YES
Potable water
YES YES
YES
YES YES
YES
YES
YES YES
YES YES
YES
YES
YES
Standard Heat Exchanger Instrumentation •
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.
•
Local TI at process inlet and outlet of each service Project Name
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DCS FAL/ FAH
YES
Flare 7.9
DCS FI
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•
DCS TI at cooling water outlet of each exchanger.
•
DCS TI at process inlet and outlet of each service
•
Local and DCS PI at process inlet & outlet
•
Local PG in inlet and outlet of CW
Note:
The detail data sheet for allthe instruments/CVs/SDVs/ Final Control Element including T/W length, flange size,diameter to be provided.
All instruments should be close couple type.
No block & bleed valve to be used as instrument tapping .
2 out of 3 voting shall be connected to DCS/PLC in different cards.
8.0
Units of Measurement MKS (Old Metric) Temperature
°C
Pressure
kg/cm²g
Vacuum
mmHg
Weight
kg
Volume
m³
Flow of Process fluid Liquid -
Mass flow
kg/h
Volume flow
m³/h
Flow of steam
kg/h
Enthalpy
Kcal/Kg
Heat duty
MMKcal/h
Power
kW
Heat Transfer rate
Kcal/m² °C.h
Fouling resistance
m² °C.h/Kcal
Viscosity
cP
Equipment size
mm
Pipe length
km
Pipe diameter
in
Vessel nozzle sizes
in
The normalized conditions for gas measurement are:
9.0
Standard
:
760 mmHg, 15.5°C (60°F)
(Sft³/mn or SCFM)
Normal
:
760 mmHg, 0°C
(Nm³/h)
Codes, Standards & Practices Project Name
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Latest revisions of following documents •
Please provide the latest editions of the codes/standards as given below. For example for Centrifugal pumps the latest edition of API standard 610 is 10 th edition and not 8th ed. (Aug. 95)
9.1
Plot Plan OISD-STD-118 Rev 1, July 1995
9.2
Vessels ASME (1995), section VIII :
9.3
9.4
9.5
•
Div. 1
•
Div. 2 (High pressure services)
Compressors •
Reciprocating : API standard 618, 4th ed. (June 95)
•
Centrifugal : API standard 617, 6th ed. (Feb. 95)
Pumps •
Positive displacement – Reciprocating : API standard 674, 2nd ed. (June 95)
•
Positive displacement – Controlled volume : API standard 675, 2nd ed. (Oct. 94)
•
Centrifugal : API standard 610, 8th ed. (Aug. 95)
Fired heaters •
9.6
9.7
9.8
API standard 560, 2nd ed. (Sept. 95)
Shell and Tube Heat Exchangers •
API standard 660, 5th ed. (June 93)
•
TEMA, 8th ed. (1999)
Air-cooled heat exchangers •
API standard 661, 4th ed. (Nov. 97)
•
TEMA, 8th ed. (1999)
Piping •
ASME/ANSI B 16.5 (1996, Add. 98) B 31.3 (1996)
9.9
Materials/Corrosion •
Hydrogen service : API standard 941, 5th ed. (Jan. 97)
•
Amine service : API standard 945, 2nd ed. (Oct. 97)
•
Wet H2S service : NACE 8X 194 (June 94) Project Name
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9.10
9.11
9.12
•
NACE MR 175-95
•
Polythionic Acid service : NACE RP 0170 (1997)
Pressure- Relieving and Depressuring Systems •
API recommended practice 520 Part I, 6th ed. (March 93)
•
Part II, 4th ed. (Dec. 94)
•
API recommended practice 521, 4th ed. (March 97)
•
ASME section I (Boiler and pressure vessels code)
Instrumentation •
ISA 55.1 (July 92)
•
ASTM
Quality Control •
ISO 9001, rev. 2 (1994)
10.0
Equipment Designation and Numbering
10.1
Unit numbering
10.2
Unit name
Number
Naphtha Splitter
034
Reformate Splitter
035
HDT
036
Isomerisation
037
Equipment numbering and identification a) Equipment identification Symbol
Equipment
FF
Heaters
RB
Reactors
CC
Towers and Columns
VV
Drums, Separators
EE
Heat Exchangers
EA
Air coolers
DR
Dryers
RP
Pumps
KA
Compressors
T TT
Storage Tanks
M
Miscellaneous
PM
Motors (pumps) Project Name
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KM
Motors (compressors)
KT
Turbines (compressors)
Type of Equipment
CF
Centrifugal
GR
Geared
RP
Reciprocating
SC
Screw
MT
Metering
SM
Submersible
Axens has kept identification code “M” for all the packages under PMC/EPCC scope. However PMC should assign equipment identification code as the list provided above. b) Equipment numbering Example : 034 - PA - CF - 001 – A/B Where: 034 is unit number PA is equipment symbol CF is type of pump, i.e. centrifugal type 001 is equipment number
11.0
Line Numbering and Identification System
11.1
11.2
General Notes •
Numbering will start at 01.
•
The number changes after control valves and main equipment..
•
The number is different for the lines connected to equipment in parallel.
•
Each type of fluid will have a separate numbering sequence.
•
Drains and vents without permanent flows are neither identified nor listed.
•
Design pressures and temperatures are shown on piping specification sheets.
Example of Line numbering Line number: 6”
-P
- 034 - 0103
- A1A-IH
Where: 6” is nominal pipe size Project Name
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P is fluid code 034 is unit number 01 is P&ID number 03 is line sequential number A1A-IH is piping specification
Example of line numbering: X - P - 0XX - YYXX – B1AS - IH
6. Insulation 5. Specification + special requirement (wet H2S for instance) 4. Line number 3. Unit number 2. Fluid 1. Nominal pipe size
11.3
Fluid codes Heating / Cooling
HO
Heat transfer fluid
SL
Low pressure steam
CL LC
Low pressure steam condensate
SM
Medium pressure steam
CM MC
Medium pressure steam condensate
SMH
Medium high pressure steam
CH
High pressure steam condensate
SH
High pressure steam
SSL
Low pressure superheated steam
SSM
Medium pressure superheated steam
SSH
High pressure superheated steam
CWS
Cooling water supply
CWR
Cooling water return
FR
Refrigerant Project Name
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FG
Fuel gas
FO
Fuel oil
Chemicals IG
Inert gas
ZS NA
Caustic soda
N
Nitrogen
ZA GA
Ammonia
CT CA
Catalyst
ZC C
Chemicals
AI IA
Instrument air
AP PA
Process air (oil free)
AS UA
Utility air
WR
Raw water
WP PW
Process water
DW DM
Demineralised water
WT TW
Tempered water
BFW
Boiler feed water
WDK
Drinking water
FW
Fired Water
SW
Service Water
Effluents disposal BD CBD
Close Blow down
CS
Chemical sewer
SWS
Sour water sewer
OS OWS
Oily Water sewer
ATM VA
Vent to atmosphere
FL
Flare
P SL
Slops
CAS
Closed amine system
SS
Storm Sewer
AMN
Amine
Process fluids P
Process
Piping Specification: The material specification to be followed is given is here below: 11.4
Project Name
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•
Material for pipe (1 digit - letter) Type
Material
ASTM specs. used by Axens for schedule or thickness calculation
A
CS
A106-B
B
Killed CS
A 333 –Gr6
C
C-1/2 Mo
A 335 – P1
D
1 Cr – ½ Mo
A335 – P12
E
11/4Cr – ½ Mo
A335 – P11
F
21/4Cr – 1 Mo
A335 – P22
G
3Cr – 1 Mo
A335 – P21
H
5Cr-1/2 Mo
A335 – P5
I
9Cr – 1 Mo
A335-P9
J
SS-TP316
A312 - TP316
K
SS-TP316L
A312 - TP316L
L
SS-TP304
A312 - TP304
M
SS-TP304L
A312 – TP304L
N
SS-TP321
A312-TP321
P
SS-TP347
A312 – TP347
U
Monel 400
B-165
Project Name
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•
Corrosion allowance (1 digit – number) 0 1 2 3 6
•
Special Requirement (I digit – letter) S HIC R
•
ANSI Rating 150 lbs 300 lbs 600 lbs
Flange type (1 digit – letter) F J
•
Sulfide stress cracking resistant Hydrogen induced cracking resistant Internal lining
Flange rating (1 or 2 digits – number) Item 1 3 6
•
0.25 mm 1.0 mm 1.5 mm 3.0 mm 6.0 mm
Raised face Ring type Joint
Insulation (1 digit – letter) Item H P C T J
Designation Heat conservation Personal protection Refrigeration conservation Tracing Jacketing
Special requirement (1 digit - letter) Wet H2S or amine services S Category 1: Moderate service ”Wet H2S resistant steels”(*) H Category 2: Severe service ”HIC resistant steels”(*) (*) Refer to Axens Standard Material Specification IN-43
R
Specific requirement Internal lining
C
PWHT(**) mandatory for corrosion reason
(**) PWHT: Post Weld Heat Treatment
Insulation Item
IH IP
Designation Heat conservation Personal protection
Item
IT IJ
Designation Tracing Jacketing
Project Name
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IC
Refrigeration conservation
12.0
Instrument numbering
12.1
Symbols •
12.2
According to ISA code
Numbering Example: 34 – TI – 0101 Where: 35 (two digits) is Unit number TI (2 to 4 letters) is instrument symbol as per ISA code 01 (2 digits) is P&ID number 01 (2 digits) is instrument serial number On P&ID’s:
TI XX01 (XX = P&ID number)
On data sheet :
34 TI XX01 (34 = Unit number)
Example of instrument numbering: 0XX - YYYY – ZZYYA/B
Serial no starting from ‘01’ for each P&IDs Last two digit of P&IDs no.
Instrument designation Unit number A/B : One PSV to remain as standby WITH INDIVIDUAL ISOLATION VALVES HAVING following locking ARRANGEMENT:
13.0
Analysis point numbering The analysis points will be listed with their type (A, B, C….). The type conforms to the typical analysis point schemes (see General legend diagrams). Project Name
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Example: 34AP.A – 0101 Where: 34 is unit number A is type of analysis point 01 is P & ID number 01 is serial number
Example : 0XX - SA - ZZYY Where, 0XX : Unit No A : Type of sample point ZZ : P&ID No YY : Serial No
14.0
Pressure relief valve numbering Same as for instruments Example: On data sheet :
34 PSV XX01 (XX = P&ID number)
On PID:
PSV XX01
Example of PSV numbering:
0XX - PSV – ZZYY A/B
PSV NUMBER P&IDs no.
Instrument designation Unit number A/B : One PSV to remain as standby
15.0
Safety Recommendations PSM (Process Safety management) regulations (e.g. OSHA 1910.119) refer to the need of using good engineering practices (GEPs). A GEP is a generally recognised and acceptable way of accomplishing a technical goal. In the VPP (Voluntary Protection Program) Participant’s Association Conference, Sept. 1995, OSHA for instance indicated that GEPs published by API, AICHE are sources of GEPs. This is also outlined in the Appendix C to regulation 1910.119 : ‘ Compliance guidelines and Recommendations for Process Safety management’. Project Name
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It is the duty and responsibility of the refiner – in order to protect the safety of its employees and public – make sure that GEPs are incorporated in the design of the plant. The following safety recommendations are derived from the use of GEPs. 15.1
SIS (Safety Instrumented Systems) a) SIS related to chemistry In case of risk due to the chemistry of the reaction, Licensor advises the SIL (Safety Integrity Level) in order to specify the corresponding SIS For this project i.e. Units 85/86/87, 034/035/036/037 the SIS for chemistry risk is not applicable (as per ISA 584 or IEC 61 508) b) SIS not related to chemistry The SIL and the corresponding SIS connected to equipment protection will be the responsibility of the LSTK contractor. Licensor has shown on P&ID a simple configuration of the SIS
15.2
Fast depressurisation •
Fire case: Normally considered for the reaction sections operating at a pressure ≥ 17 barg, the depressurisation shall be done normally through HC from DCS. Also, a push button shall be provided at field DCS at grade level with protection from spurious operation. Duration of depressurization : 15 minutes.
•
Fast depressurization shall be done in two steps i.e. 7 kg/cm 2 per minute and 21 kg/cm 2 per minute depending on the requirement.
•For vessel with thickness lower than 25 mm or for vessel with light hydrocarbons (C 3 to C5) the depressurization shall be done to 7 barg (or 50 per cent of the vessel design pressure if lower), duration : 15 minutes. •
15.3
Runaway case : Considered for the possibility of runaway in the reactor, Axens will specify depressurization device and the activation in accordance with the SIL level. The SIS corresponding to this depressurization shall be in accordance with the SIL level already specified for the risk of runaway.
Shutdown of pumps by low level in upstream vessel Licensor will specify automatic shutdown of the pumps by low level in upstream vessel for: •
feed pumps with high delta P≥ 70 barg
•
Sealless pumps
For all other cases, LSTK Contractor will check with the pump’s vendor if automatic shutdown is required. 15.4
Minimum flow bypass on centrifugal pumps with flow control Licensor will indicate a minimum flow bypass with flow control for centrifugal pumps for the following cases: •
high differential pressure multistage pumps (water differential head ≥360m)
•
large pumps with driver power > 180 kW
•
for process reason (turndown), flow rate ≤ 30% of max flow rate
•
the control valve at the pump discharge fails in close position
The pump data sheet will specify the process flow without provision for the minimum flow which will be specified by the pump’s vendor. 15.5
Automatic isolation valves between process vessel and pumps Project Name
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Licensor has considered automatic isolation valves for: •
an inventory of the process vessel over 8 m³ of light ends (LPG)
•
an inventory of the process vessel over 8 m³ and with a product above its autoignition temperature or at a temperature above 250°C
• 15.6
an inventory of the process vessel above 16 m³ and a flammable product.
High level in feed drum or reaction section separator drum To avoid overfilling, an independent high high level alarm via LT (LAH LLHH) to be has been specified
15.7
Prevention of back flow overpressure Following devices will be considered at the pump discharge:
15.8
•
P ≤ 40 barg: one check valve
•
40 ≤ P ≤ 80 barg: two check valves of different conception
•
P ≥ 80 barg: two check valves of different conception plus an automatic shut-off valve in case of reverse flow
Back flow prevention of a fired heater In case of tube rupture in a fired heater and to minimise the consequences of a fire, check valve or motor operated isolation valve will be installed at the outlet of a fired heater in the following cases:
15.9
•
heater operation at high pressure ≥ 70 barg
•
reboiling heater of a large a column with high gas inventory
Seals on pumps Dual mechanical seals (pressurised or unpressurised according to process considerations) shall be considered in the following cases: •
LPG
•
Hydrocarbons above their auto ignition temperature or at a temperature > 250°C
•
Toxic or carcinogenic fluid (HCl, benzene etc.)
•
High pressure pumps (> 50 barg)
• 15.10
Constraints due to handling of benzene Due to the known carcinogenity of benzene, the following provisions shall be taken when applicable: For all streams containing 1% weight or more of benzene and 25% weight or more of C7 through C9 aromatics, the following shall apply: •
closed sampling
•
closed aromatics collection system with an underground drum receiving all drains of the corresponding process part
•
pumps will be equipped with dual mechanical seals or pumps will be sealless if operating conditions allow it Project Name
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•
detailed engineering of valves, flanges and joints shall be such as to satisfy the requirements of TWA (Time-Weighted Average) exposure limit of 1 ppm for an 8 hour workday (OSHA’s requirement)
All water streams saturated with aromatics shall be sent to a suitable processing or treating facility in order to minimise aromatic emissions to the environment. 15.11
Constraint due to streams with high content of H 2S When a process unit contains streams with high H2S content, the following precautions shall be taken into account to avoid release of H2S to atmosphere: •
Sample connections will be with a closed loop
•
Draining of pressurised liquids which could release H2S after expansion shall be sent to a dedicated system: underground drum for hydrocarbons sour water treatment system for acid waters
LSTK Contractor shall provide adequate H2S detection system in the process unit. 15.12
Following additional safety requirements to be complied with by LSTK contractor: •
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. All feed and reflux pumps are to be treated as critical.
•
Air cooler stop push button to be located at grade level in addition to start / stop button near the fan at platform.
•
Suction / discharge valves and suction filter should be close to the pump in order to avoid hydrocarbon wastage during filter cleaning and pump maintenance.
•
Flare line isolation valve at unit battery limits should be installed only in the horizontal line with stem in 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.
•
Dip hatch for the tanks should have the aluminum 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.
•
Harmful effects of liquids / gases handled in the plant on FRLS cables / PVC cables / XLPE cables / Aluminum / Copper / Brass to be considered and suitable precautions to be taken.
•
Any specific recommendation for lightning protection and protection against static charge.
•
Emergency lights in plant area and control room shall be provided.
•
Communication system to cover all areas of plants and offsites shall be provided (field intercoms and talk-back paging systems, closed circuit cameras and TVs)
•
Pumps shall have a DCS stop facility in central control room along with running lamp indication
•
Emergency trips if specified for HT motor will be wired directly to switch gear in addition to control room.
•
Double isolation valves with spectacle blind are to be provided at each battery limit in all the process lines.
•
All the valves are to be provided at approachable height with suitable platforms ensuring accessibility, safety and ease of operation. Project Name
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Double isolation valves shall be provided on all vents and drains for high pressure service with end blind.
16.0
Environmental Requirements
16.1
Waste Water
16.2
Process waste water:
To be routed to Oily Water Sewer(OWS) by Gravity.
Boiler blow-down:
To be routed to storm water sewer after cooling to around 45-50 deg C
Blow down and Flare •
Process drain will be routed to either OWS or Closed Blow-Down (CBD) vessel inside battery limit.
•
All hydrocarbon / combustible gases and vapors shall be relieved to the flare.
•
Bleed from double block and bleed to be vented to safe location.
•
Liquid relief system shall be separate from vapour relief system to CBD.
•
In case two phase is envisaged in the relief system, provide knock out pot at the battery limit. Knock out Pot will be designed by other on bases defined by Licensor.
•
Flare header back pressure at battery limit. Normal
Max
HC flare
kg/cm²g
0.7
1.7
Acid flare
kg/cm²g
0.5
1.5
For reference for gaseous emission please refer to the attached file on Expert Committee report.
•
Expert Committee MeetingMoEF'0...
• •
Gaseous emission shall be within the following stipulations: Particulate matter, max
150 mg/NM³
Carbon monoxide, max
500 PPM volume
NOX, PPM vol, max
210 for FO w/o preheat 240 for FO with preheat
NOX, PPM vol, max
50 for FG w/o preheat 80 for FG with preheat
SOx emission
To be reported
Only low NOx burners to be provided for NO x emission control. However, the achievable emission level is to be indicated. Project Name
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16.3
Safety Valves All drains of safety valves shall be connected to the Blow down vessel. 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.
16.4
Noise Level Maximum noise level generated by any new item of equipment shall be less than 85 dB(A) at a distance of 1 m.
16.5
Open or Closed Drainage Systems
Two type of CBD system will be employeed. CBD1 : For all HC liquid drain CBD2 : For all chemical and Chloride stream with caustic line for neutralization. The following closed drainage systems shall be provided at battery limit:
16.6
•
Oily sewer system (CBD) gathering all drainage contaminated with hydrocarbon oil. systems are provided for this project:
•
Oily sewer system containing chlorides (CBD-CL)
•
Closed Amine sewer system
•
Contaminated rain water from ISBL area shall be routed to underground sewers system (CRWS).
•
Oily water (OWS) is an open system, but effluent is carried through underground piping network.
3
Requirements on chloride emissions •
No chloride shall be burnt at the non acid flare or in furnace firing system
•
Isomerization reactions are catalyzed on a fixed bed catalyst (chlorinated alumina catalyst). A continuous injection of C2Cl4 is made up to maintain an optimum HCl concentration in reactors.
•
Licensor’s design is based on following arrangement in order to ensure that no chloride is sent to non acid flare: •
Discharge of isomerisation reactor PSV to HC acid flare
•
Discharge of Stabilizer PSV to HC acid flare
•
Discharge of Caustic Scrubber PSV to HC (non acid) flare
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Depressurization line of reactors discharges to stabilizer
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Depressurization line of stabilizer discharges to scrubber
Please elaborate Please refer to Process Package Page No I-37
“Discharge of chloride to flare shall be minimized Discharge of chloride to flare shall be minimized for environmental reasons but also because HCl is corrosive when in presence of traces of water. Project Name
MSQ UPGRADATION - IOCL DIGBOI EDP Ident. No.
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Isomerization reactions are catalyzed on a fixed bed catalyst (Chlorinated alumina catalyst). A continuous injection of C2Cl4 is made up to maintain an optimum HCl concentration in the reactors. AXENS design is based on following arrangement in order to ensure that discharge of chloride to flare is minimized: •
The Caustic Scrubber has been designed in order to ensure full neutralization of the gas effluent that contains HCl.
•
Discharge of the isomerization reactor PSVs and stabilizer PSV are connected to the flare. However unit has been carefully designed, in order to minimize the PSV discharge risks for these relief valves (redundant PSHH at stabilizer overhead, dedicated PSV on liquid feed to isomerization reactors, from feed pump discharge to feed surge drum).” Depressurization line at stabilizer is connected to the flare. Depressurization is designed for fire case and temperature excursions in reactors The Caustic Scrubber has been designed in order to insure neutralisation of gas effluent, containing HC1, based on maximum stabilizer offgas flow rate (this flow rate is maximized when LPG recovery section Is bypassed. This system will insure that all gas effluent containing HCl will be neutralised, before sending to (non acid) flare system in case of upset on the reaction or stabilizer sections. Moreover, Stabilizer and Isomerization reactors have been located (see Preliminary Plot Plan ) in different fire zones, in order to avoid cumulative fire cases on both sections. •
No Chloride shall be sent to drainage systems •
•
•
17.0
All drains (control valves, pumps, block valves) containing hydrocarbon and HCl must be connected to a dedicated header (CBD3). Effluents shall be routed to a dedicated drum full of caustic that will neutralize HCl.
Chloride in final products (Isomerate – LPG) •
In case of Stabilizer or LPG recovery unit upset, some chlorides may contaminate the final products. In order to reduce the risk of contamination of final products with chlorides, Chloride guard beds have been installed on isomerate and LPG.
•
These guard beds have been designed to cover the worst upset cases.
•
The chloride maximum content in the final products shall be below 0.5 ppm wt.
Fire-safe area for C2Cl4 •
C2Cl4 is not flammable. process fire.
•
C2Cl4 storage area should consequently be located outside and preferably upwind of the process area that can be affected by a fire.
•
Furthermore, C2Cl4 storage area should be surrounded by a small wall to contain possible spills of C2Cl4 (to be adsorbed by an inert material). This wall will also impede propagation of a process fire towards C 2Cl4storage tank. The location of this wall can be located at 30 meters of the drainage point of the paved process area, where a process fire can occur. In these conditions the C 2Cl4 storage area may be considered in a fire safe area. This does not exclude the fact that C2Cl4 storage should be reached by water for fire fighting equipment, to cool it during an external fire.
Fire around C 2Cl4 storage can only result from an external
Steam & Condensate System Project Name
MSQ UPGRADATION - IOCL DIGBOI EDP Ident. No.
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18.0
•
All 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.
•
NORMAL steam conditions shall be used for operating utility estimates, heat and material balances and battery limit connectivities.
•
Condensate recovery will be maximized from process consumers. 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.
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Condensate from steam trap discharge and steam coils in tanks shall be recovered by connecting these consumers to condensate header.
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The MHP condensate is flashed to generate MP condensate & MP steam.
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MP condensate & LP condensate shall be routed to battery limit separately.
Utility Stations, Safety Showers & Eye wash •
Drinking water is to be used for eyewash and safety showers, which are to be located strategically in unit.
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LP steam, plant air and service water outlets shall be furnished at utility stations.
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A dedicated LP steam header (parallel to main header) shall be provided for supplying LP steam to only Utility stations.
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All utility outlets at utility stations are to terminate with a hose connection of minimum size 1”.
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Assuming a maximum hose length of 25m, utility stations for LP steam, plant air and service water shall be provided at the following locations :
At grade to serve all equipment within maximum 25m radius
At all platforms of structures
At those platforms of self-standing towers where man-holes/hand holes are located. Top and bottom platform Every alternate platform
At top platforms of drums located at the grade
Near the pumping stations and tanks
Fired Heater Structure – One LP steam point at every platform.
Technological Platform – two (minimum) per platform level including grade, beyond 15 m length/width, provide additional utility point.
Reactor Structure – Same a Technological Platform
Compressor House –
Three stations at compressor level
Two stations at grade level
Air Cooler Maintenance Platform
Two stations minimum below plenum Project Name
MSQ UPGRADATION - IOCL DIGBOI EDP Ident. No.
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19.0
IBR Requirement •
Steam generators/steam users shall meet IBR regulations. summarised below:
Major IBR requirements are
Vessels : Any closed vessel exceeding 22.75 liters (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.
Piping : Any pipe through which steam passes and if: - Steam system mechanical design pressure exceeds 3.5 kg/cm 2(g) or - Pipe size exceeds 254 mm internal diameter
The following are not in IBR scope - Steam Tracing - Heating coils - Heating tubes in tanks - Steam jackets
•
•
20.0
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 down at last isolation valve upstream of equipment.
All steam users where downstream piping is connected to IBR i.e. condensate is flashed to generate IBR steam are covered under IBR.
IBR starts from BFW pump discharge.
Safety valves / Relief valves on IBR system will not have isolation valve.
Material Certificate
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.
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. In case of imported boiler IBR items, prior advice of Director of Boiler, West Bengal State shall be obtained.
All drawings coming under preview of IBR shall be certified by Local Boiler Inspector.
Plot Plan Plot Plan Requirements •
Isomerization reactor 037-RB-001, 037-RB-002 and 037-RB-003 shall not be located in the fire zone of stabilizer 037-CC-001.
•
Isomerization regeneration section shall be located as close as possible to dryers section.
•
C2Cl4 drum 037-M-001 shall be located in a fire safe area as defined hereafter. Project Name
MSQ UPGRADATION - IOCL DIGBOI EDP Ident. No.
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C2Cl4 is not flammable. Fire around C2Cl4 storage can only result from an external process fire. C2Cl4 storage area should consequently be located outside and preferably upwind of the process area that can be affected by a fire. Furthermore, C2Cl4 storage area should be surrounded by a small wall to contain possible spills of C2Cl4 (to be adsorbed by an inert material). This wall will also impede propagation of a process fire towards C 2Cl4 storage tank. The location of this wall can be located at 30 meters from the drainage point of the paved process area where a process fire can occur. In these conditions, the C 2Cl4 storage area may be considered in a fire safe area. This does not exclude the fact that C 2Cl4 storage should be reached by water for fire fighting equipment to cool it down during an external fire.
21.0
Special Design Requirements •
In case of motor operated valves, (critical service) indication of valves position should be available in the control room. Shut-down valves should be operable from the control room.
•
The blow-down from stream drum if any should be routed to storm water sewer after cooling it. Use of blow-down from the steam generators of Hydrogen Unit to the extent it is possible within the unit. Excess quantity, if any, should be drained to storm water sewer after flashing and cooling in a blow-down drum.
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Instrument and electrical cables shall be above ground and under ground respectively inside the unit battery limit.
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General HAZOP analyses should be considered in the design of the unit.
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Furnace with 8-10% excess air.
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The following non-standard line sizes shall not be used unless approved by PMC-¼”, 2½”, 3½”, 5”, 7”, 9”
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The following guidelines for minimum line / nozzle sizes shall be applied –
•
2” NB
Minimum nozzle size for vessels, tanks and heat exchangers
2” NB
Minimum process (hydrocarbon) line size
1½” NB
Minimum utility line size
¾” NB
Minimum bridle drain or pump casing vent / drain
½” NB
Minimum chemical injection line size. Tubing size to be 10 mm
1½” NB
Minimum on pipe rack
4” NB
Minimum for underground lines
The following roughness coefficients shall be used unless stated otherwise – Material
•
Carbon Steel
0.0018
Flare / Vent headers (Heavily corroded)
0.018
Stainless Steel Pipe
0.001
Glass Reinforced Epoxy Pipe
0.0001
A margin of at least 0.6 m between NPSH available and required NPSH shall be applied. In case of requirement of lower difference, concurrence of PMC/IOC is to be obtained. Project Name
MSQ UPGRADATION - IOCL DIGBOI EDP Ident. No.
Roughness (inches)
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•
NPSH test shall be performed where ever the difference between NPSH available and NPSH required is less than 0.9 m.
•
Vents & Drains in Heat Exchangers Provide 1” NB x 300# (min.) flanged vents and drains at high and low points respectively on all heat exchangers. All vents and drains shall be valved and blanked off. Exchangers in total condensing service shall be provided 2” vent connection at the opposite end of the shell inlet. Sizes of multi-purpose connections and pressure gauge connections on exchanger nozzles shall be 1” NB x 300# (min.) for below 12” nozzles and 2” NB x 300# (min.) for 12 “ & above nozzles.
•
•
Vents & Drains in Piping Pipe Size in Inches
Vent Size, inches
Drain Size, Inches
4 & below
¾
¾
6 to 10
¾
1
12 & above
1
1½
Vents & Drains in Air Coolers On air coolers, one no. 2” vent shall be provided at the highest point on the inlet header and one no. 2” drain at the lowest point in the outlet header. These connections shall be valved and blanked off.
•
Vents & Drains in Pump Casing For non-volatile services, casing vents and pump drains shall be piped into a sewer or closed drain system. For volatile services, casing vents and drains are to be piped to the relief header and sewers.
•
Double Block Valves Philosophy Double block valves shall be provided for the following conditions – For cases where cross contamination can’t be tolerated. For vents and drains in ANSI Class 600 rating and above For drains containing C5 or lighter hydrocarbons. In this case, the double block valves must be minimum of 1000 mm straight pipe apart. Where high pressure (above ANSI 300# rating) is likely to be removed on the run; e.g. spare machinery or equipment For gas stream > 100 bar g or liquid systems > 60 bar g or gas/liquids which are potentially toxic. For the equipment, which may be opened for maintenance on the run e.g. filters.
•
Fire proofing shall be carried out as per OISD-164.
Note: 1. PMC should develop a feed scheme for the MSQ Unit as per discussion with IOCL as there will be some variation from what has been proposed by Axens in the Process Package. Project Name
MSQ UPGRADATION - IOCL DIGBOI EDP Ident. No.
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2. Specifying all speciality items identified or implied in process package such as strainers, filters, steam traps, flame arrestors, special purpose valves, heat exchanger isolation valves with blinding provision, Instrument tapping isolation valve, pump/heat exchanger drains to CBD/OWS, control valve upstream & downstream side bleeders, sample points in CW return line, feed & product rundown lines. 3. Installation of Gas Detectors as per OISD/ CCTV/Pegging System/ Fire Water & Foam Network as per OISD, Fire Alarms etc for safety of the equipments & the units. 4. Sight glass may be provided in the drain to CBD lines. advice of PMC/Owner.
CBD/OWS system may be designed as per
5. Flare & Fuel gas (with KODs) network is to be developed. All field Instruments shall be suitable for zone 1, IIC T3 shall be certified by a statutory body with gas grouping as per requirement. 6. Steam silencers with proper design are to be provided. 7. Automation (Sequance Logic Diagramfor pumps & dryer operation, will be developed and implemented.
8. For reciprocating compressors, 2out of 3 voting system to be incorporated for important interlocks such as vibration interlock. 9. Provision of DM water to be kept instead of Cooling Water for Compressor seal, Gear jacket cooling etc.
Box, Cylinder
10. Critical rotary equipment running signal to be provided at DCS 11. Utility connections to all Heat Exchangers/ Vessels/ Columns are to be provided for flushing. Steam flushing in Isomerisation section is to be avoided.. 12. Back flushing facility in water side in all water coolers to be provided. 13. Condensate Recovery network is to be developed. a.Process assistance in development of PRDS and Steam de-superheater for 3 Bar steam from 10 Bar steam b.Steam (MP/IP/LP)/ BFW/DM Water/ Instrument Air/Plant Air/ Cooling Water/ Service Water/ Drinking Water/ Hydrogen gas/ Nitrogen Gas distribution networks are to be developed. c. LICENSOR has recommended MOCs in equipment datasheet. However, the MOCs of all critical equipments which are subjected to corrosive service are to be cross checked and confirmed. 14. Packages e.g Compressor with interstage KOD/s & Intercooler/s and other associated facilities like lube oil system, cooling system, instrumentation & control philosophy with selection of proper unloading technology, start-up ejector system, HDT fired heater with auxiliary facilities inclusive passivation facility for heater tubes & flue gas analyzer, sulfiding agen (DMDS) injection & passivation package, corrosion inhibitor (CHIMEC 1044) injection package, chloriding agent (C2CL4) injection package, caustic solution preparation package, dryer package, electrical heater with auxiliary facilities, steam condensate pots & accessories, analyzer package, Ammonia & HCL dosing package etc Process interlocks/instrumentation linked to central control room for operator interface are to be indicated. 15. Utility connection to be provided to Vessels/ Columns for flushing. Steam flushing in Isomerisation section is to be avoided. Vessel isolation system, drain points and utility connections are to be shown in upgraded P&IDs. 16. All Heat Exchangers isolation system, drains at both ends i.e tube side as well as shell side & utility connections are to be provided in upgraded P&IDs. Project Name
MSQ UPGRADATION - IOCL DIGBOI EDP Ident. No.
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17. Analyzer package for analyzers if required like Oxygen analysers e.g Orbisphere 410. 18. Flare Load Summary: PMC shall check the adequacy of flare header. 19. Details for package items like Feed Filter, Compressors Package, Fired Heater Package, Electric Heater Package, Sulfiding Agent Dosing Package, Corrosion Inhibitor Dosing Package, Chloriding Agent Dosing Package, Dryer Package, Steam Condensate Recovery Package including condensate pots, Analyzer Package, Caustic Solution Preparation Package, Ammonia & HCL Dosing Package Prefilter – Coalescer, Ejector, etc to be developed by PMC/LSTK.
Project Name
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Index of Revisions Rev. Sheet Prepared, revised
00
ALL
Checked
Approved
Name
Date
Name
Date
Name
Date
Status
CS
24.12.07
TSM
26.12.07
SMK
26.12.07
IFC
Project Name
MSQ UPGRADATION - IOCL DIGBOI EDP Ident. No.
Remark, kind of revision
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