3 TNK Bapiraju

ChennaiPetroleumCorporationLimited(AGroupcompanyofIndianOil)

Refining Process, Refinery Configuration& Design Aspects

REFINERY PROCESSES

REFINERY CONFIGURATION

PROJECT DESIGN ASPECTS

PRESENTATION PLAN

STEPS IN REFINING PROCESS

w SEPARATION PROCESS

w CONVERSION PROCESS

w FINISHING

REFINERY PROCESS - Overview

REFINERY PROCESSING STEPS

Crude oil

Objective

Examples

Improving the qualities of products by:

Blending products of different qualities to get an optimal mix

Treating products (typically with hydrogen) to remove impurities

Gasoline blending Hydro-treating

SeparationSeparation ConversionConversion Finishing

Breaking up a mixture into its components

Distillation/fractionation

Extraction

- Fundamentally changing the chemical structure of a product by:

Breaking down molecules

Combining molecules

Rearranging structure

Coking Cracking Alkylation (combining) Isomerization

(rearranging)

SEPARATION PROCESS

DISTILLATION COLUMN

Separation of components from a liquid/vapor mixture via distillation: Depends on the differences in boiling points of the

individual components

Depends on the concentrations of the components present

Hence, distillation processes depends on the vapour pressure characteristics of liquid mixtures.

DISTILLATION PRINCIPLE

The Dew-point is the temperature at which the saturated vapour starts to condense.

The Bubble-point is the temperature at which the liquid starts to boil.

Relative volatility is a measure of the differences in volatility between 2 components, and hence their boiling points. It indicates how easy or difficult a particular separation will be.

DEW POINT , BUBBLE POINT AND RELATIVE VOLATILITY

Column

Column internals9 Trays9 Packing

Reboiler

Condenser

Reflux Drum

MAIN COMPONENTS OF DISTILLATION

Temperature

Pressure

Draw off and reflux rates

Pump around

Stripping steam rate

OPERATING VARIABLES

CRUDE- FEED PREPARATION

Effect of Bottom, Sediments & Water:

Deteriorates equipment performance Shorter run length High Energy Consumption

This can be achieved only by proper feed preparation.

Impurities in crude: Inorganic salts Acids

Desalting helps to remove these impurities

PREHEAT TRAINS & FURNACE

Pre-heat trains:

Utilize the heat available in the products and PA

Reduces the fuel consumption in the furnace

Furnace:

Natural draft

Forced Draft

Balanced Draft

ATMOSPHERIC DISTILLATION

VACUUM DISTILLATION

VACUUM DISTILLATION

Vacuum distillation can improve a separation by:

Prevention of product degradation

Reduced mean residence time especially in columns using packingrather than trays.

Increasing capacity, yield, and purity.

Reduced capital cost, at the expense of slightly more operating cost.

CRUDE DESALTER

CRUDE FURNACE

CRUDE ATMOSPHERIC COLUMN

Lube Oil Base Stocks

SPINDLE LIGHT NEUTRAL INTERMEDIATE NEUTRAL 500 NEUTRAL HEAVY NEUTRAL BRIGHT STOCK

LUBE PROPERTIES

Properties /Components

Viscosity ViscosityIndex

Pour Point

Paraffins Low High High

Naphthenes Medium Medium Medium

Aromatics High Low Low

LUBE PROCESSING STAGES

S.NO PROCESS PROPERTY CONTROL

1 Vacuum Distillation Viscosity, Flash Point

2 Solvent Extraction/ Viscosity Index

3 Solvent Dewaxing / Iso-Dewaxing

Pour Point

4 Hydrofinishing Colour / Oxidation Stability

FurfuralExtraction

Unit

FurfuralExtraction

Unit

NMPExtraction

Unit

NMPExtraction

Unit

MEKDewaxUnit

LubeHyFiUnit

Atm.DistlColumnAtm.DistlColumn

VacuumDistillatnColumn

PDAUnit

LUBE PROCESSING BLOCK

Crude

RCO

Vac. Distl

Vac. Residue

Extract

Extract

Pitch

DAO

Raffinate DWO LOBS

Slack Wax

FEED CHILLING

FILTERSSOLVENTRECOVERYFROM WAX

SOLVENTRECOVERYFROMFOOTS OIL

DEOILED WAXSTORAGE

PRODUCTSTORAGE

HY.FIUNIT

NH3 REFRIGERATION

INERT GAS

FOOTS OIL

WAX PROCESSING

CONVERSION AND TREATING PROCESS

CONVERSION AND TREATING PROCESS

Conversion Process:

9Thermal processes

9Catalytic processes

Treating Process

9Catalytic processes

9Chemical treating process

THERMAL (VISBREAKER UNIT)

Mildthermaldecomposition(visbreaking)

Reductionofviscosity&pourpointoffeed

DesirableReaction Cracking

SomepolymerizationcondensationreactionalsooccursCokeformation

THERMAL (VISBREAKER UNIT)

CRACKEDRESIDUEVACUUM

FLASHER

STEAMVISBREAKER

FEED VACUUMFLASHED

HVGO

LVGO

GAS+SLOPS

GO

STABNAPHTHA

GAS

STEAM

HEATER SOAKERFRACTIONATOR

GAS

Stabiliser

300 c

426 c

440 c

380 c

7.7 kg/cm2

39

26

96 c

160 c0.95 kg/cm2

210 c

9.8 kg/cm2

25 mmhg130 c

300 c

(Thermal) Delayed coking

Reactor DesignBetter performance and operational flexibility can be achieved:

Choice of catalyst

Choice of feed

Operating conditions

Reactor configuration

Synergy with other units

Better internals

CATALYTIC (REACTORS)CATALYTIC (REACTORS)

REACTOR INTERNALS

Catalystunloadingnozzle

Aluminaballs

Catalyst

Debrisbasket

Distributornozzle

Outletnozzle

Inletnozzle

Screen

REACTOR INTERNALS

Outletnozzle Screen

Catalystunloadingnozzle

Aluminaballs

Catalyst

Debrisbasket

Distributornozzle

Inletnozzle

Quench

Catalyst

CHEMISTRY:

Dehydrogenation

Isomerisation

Dehydro cyclization

Hydrocracking

CATALYTICREFORMING

DEHYDROGENATION:

C7H14 >C7H8+3H2Methylcyclohexane Toluene

RON: 73.8 119.7

ReactionishighlyEndothermic

Promotedbylowpressureandhightemperature

Occuronmetalsite(Platinum)

FastestreactioninReforming

CATALYTICREFORMING

+ 3H2

Reaction is mildly Exothermic

Occur on acid site(Al2O3 and HCL)

Second fastest reaction in Reforming.

C

Methy Cyclo Pentane Cyclo Hexane BenzeneRON - 89.3 RON - 110 RON - 120

Naphthene AromaticNaphthene

CATALYTICREFORMING

ISOMERISATION:

C

Toluene119.7

+ 3H2

n-HeptaneRON 0.0

Reaction is Endothermic

Promoted by low pressure and high temperature

Occur on acid and metal site

Slowest reaction in Reforming

-C-C-C-C-C-C-C-

ParaffinAromatic

CATALYTICREFORMING

DEHYDROCYCLISATION:

Naphtha Hydrotreating & Cat. Reforming

Naphtha

Impurities: S,N,Metals

Risk of poisoningCCR catalyst

Naphtha Hydrotreating Hydro treated

Naphtha

Impurities:Nil or low

No Risk of poisoningCCR catalyst

Low octane number

Continuous CatalyticReforming

ReformateHigh OctaneNumber: 102

HydrogenRich gas

NHT CCR

CCR REACTOR-REGENERATOR

NHT ISOM

NHT Section - Main reactions

Hydrorefining reactions removal of impurities Desulfurization Denitrification

Hydrogenation reactions saturation of the olefins and diolefins

Demetallation reactions removal of metallic impurities

ISOM Section - Main reactions

Benzene hydrogenation to form cyclohexane Isomerization (eg. N-pentane to i-pentane)

Surge Drum

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Feed Heater

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NHDTSeparator

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Light IsomerateStorage

Heavy Isomerate

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LPG Product

To Isomerate Storage

To FCCC5/C7+ Cut

Recycled H2 To R1

FeedNaphtha

C1

F1R2R1

C2K2 A/B

C4

C13

C16C17

R3R4

C19

C22

C29 C30

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Surge Drum

K1A/BMake-up H2 compressor

NHT ISOM

HYDROCRACKER BLOCK

Reaction Chemistry

Hydro-treating Reactionsa) Demetallizationb) Desulfurizationc) Denitrificationd) Olefins Saturatione) Aromatics Saturation

Hydrocracking Reactions

Catalyst (Ni3S2)CnH2n+2 + (x-1) H2 x C n/xH2n/x +2 + Heat

UCO (to FCCU)

Off-gas to PSA (for

H2 recovery)VGO feed

Feed preheating

and filtration

Furnace

Product stripper

Light end recovery section

Fractionator

Fuel gas (to header)

LPG (to storage)

Light Naphtha (to MS pool / HGU)

Heavy Naphtha (to Diesel pool / CRU)

Kerosene / ATF

Diesel..

HP gas separator

LP gas separator

Recycle gas compressor

(RGC)Amine treating

Recycle gas

Furnace

Gas

Liquid hydrocarbon

Heavierhydrocarbons

Lighter hydrocarbons

Lighter hydrocarbons

Make-up H2 from HGU

3600C

Reactors172.5 Kg/cm2

3780C

Make-up H2 compressorQuench H2

Make-up H2.

HYDROCRACKER

CPCL HYDRO CRACKER

FLUIDCATALYTICCRACKINGUNIT

FlueGas680C Flue Gas

Slide Valve

Regenerator650C

Spent CatalystSlide Valve

Regenerated CatalystSlide Valve

Catalyst circulation 10 MT/min

Air43000

nm3/hr Raw OiL 120 m3/hr 370C

Stripping Steam

Reactor500C

Products to Main Column

FINISHING PROCESS

DHDT UNIT (Hydrodesulphurization)

DHDT REACTOR

Reactor Dimensions

Height,m 31.3

Width,m 4.4

Parameters SOR EOR

Reactor Inlet Pressure, kg/cm2g 77.7 79.6

Reactor Inlet Temp, C 331 375

Reactor Outlet Temp., C 351 388

Reactor Outlet Pressure, kg/cm2g

75.0 75.0

SULFUR RECOVERY UNIT

Step 1:H2S + 1 O2 SO2 + H2O + HeatStep 2:2H2S + SO2 3/n Sn + 2 H2O + HeatOverall reaction of Claus Process 3H2S + 1 O2 3/ n Sn + 3 H2O + Heat

Chemical Reactions

Sulphur Recovery Block

AmineRegn.(ARU)

2-stageSWSUnit

Tail GasTreating

ThermalConverter

CatalyticConverters

SulphurA

c

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G

a

s

lean amine

rich amine from process units

rich amine to ARU

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Sour water from process units

stripped water

Lean amine

CPCL SRU

1. REFINERY PROCESSES

2. REFINERY CONFIGURATION

3. PROJECT DESIGN ASPECTS

PRESENTATION PLAN

Refinery ConfigurationKey Considerations & Available Options

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LPG

PROPYLENEPBFS/MEKFS

MS

NAPHTHA

ATF

DIESEL

LUBEOILBASESTOCKS

PARAFFINWAX

ASPHALT

FO

AmineTreating

Amine/MeroxTreating

DHDS/DHDT

Extraction Dewaxing LubeHDT

Hydrocracker

FCCU

LPGTreating

PropyleneRecovery

MeroxTreating

Visbreaking

Biturox Unit

AmineRegeneration

SulphurRecovery

Ref.FuelGasSystem

A TYPICAL REFINERY CONFIGURATION

NaphthaSplitter

ATFTreating

NHT/ISOM

HexanePlant

HydrogenGeneration

CatalyticReforming

GAS

LPG

LT.NAP Naphtha(4590C)

Naphtha(90130C)

ATF

Diesel

LUBEDistillates

VGO

UCO

Hydrogen(H2)

LongResidue

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Isomerate

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Reformate

CrackedGasolineC

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HY.NAP

HEXANE

COKE

SULPHUR

SK

DelayedCoking

ShortResidue

WaxDeoiling&WaxHydrofinishing

SK

LCGO HCGO

LPG

CRUDEOIL

STORAGE

H2

H2

Global Economic Downturn & Recovery

Global Oil Outlook

India - Net Oil Import Dependence

Reference: IEA WEO 2009

Projects Classification

Drivers for New Projects Identification

Supply Demand Balance

Change in the market scenario

Impact of products Slate / demand (Zero FO export, Dieselization, etc.)

Stringent Product Specifications

Environmental improvement / regulations

Profitability through capacity expansion

Diversification into new areas

Achieving overall economics of scale in operations

Impact of Product Demand

Reference: OPEC WOO 2010

Global Product Demand 2009 to 2030

Stringent Product SpecificationsGASOLINE Euro-III Euro-IV Euro-VSulphur, ppm 500 150 50 10RON, min 88 91 91 95MON, min - 81 81 85RVP (max), Kpa 60 60 60 60Benzene (max), vol% 5/3 1 1 1Aromatics (max), vol% - 42 35 35Olefins (max), vol% 21 21 18

DIESEL Euro-III Euro-IV Euro-VSulphur, ppm 500 350 50 10Cetane Number 48 51 51 5195% recovery, C 370 360 360 360Flash Point (Abel), C 35 35 60

Product Spec Changes Mean More Complex Refineries

Drivers for Revamp Projects Identification

Capacity Expansion

Quality Improvement of products

New Technology Implementation

Crude Feed Selection

High Sulphur Crudes (Dubai-Brent crude spread)

Heavy Crudes

High TAN crude

High nitrogenous / mercuric crude

Tar Sands, Oil Shales

Over half of worlds oil supply is heavy & sour crude

New refineries built with capability to handle heavy crudes.

Marker Crude Dubai rose higher than Brent in Dec 08 due to Rise in demand for sour crude OPEC production cuts, etc.

Not only is sour crude seeing more demand growth, it also outstrips light, sweet crude in production growth.

Share of sour, heavy crude is likely to increase vis-a-vis light, sweet crude.

Trend in Crude ProcessingHeavy/Sour Crudes

The Total Acid Number (TAN) is the amount of potassium hydroxide in milligrams that is needed to neutralize the acids in one gram of oil

TAN >1.0 leads to NAC (naphthenic acid corrosion)

Share of High TAN crude in overall oil production Current - 20% In next five years - 25%

Acidic Crudes Characteristics Yield low S Gas Oil Low Cetane value

Handling of Acidic Crudes Blending with non-acidic crudes & Specialized Metallurgy & Chemical

Injection for corrosion abatement

E.g.) Penglai (Australian), Duri (Indonesian), Marlim (Latin America), etc.

Processing of Opportunity CrudesHigh TAN Crudes

High Pour Crudes need to be blended with normal crude for pipeline transportation.

Pricing benchmark of these crudes need to be considered for economic viability.

Processing of high pour crudes also require Coker facilities within the refinery.

For example: Handil (Indonesian), Rajasthan crude

Processing of Opportunity Crudes

High Pour Crudes

Topping Refinery

Skimming Refinery

Cracking (hydro/catalytic) Refinery

Coking refinery

Integrated Refinery

Lube Refinery

Types of Refineries

Primary Processing Units Distillation Blending

Secondary Processing Units Catalytic Cracking Hydro-cracking Catalytic Reforming Isomerization / Alkylation, etc

Bottom Upgradation Units Visbreaking Delayed Coking

Treating Units Hydrotreating

Processing Units in Oil Refineries

Units Capacity (MMTPA)

Crude / Vacuum Distillation Unit(65% Arab Light and 35% Arab Heavy) 6.0

Full Conversion Hydrocracker 1.95Diesel Hydrotreater 1.63Delayed Coker Unit 1.36Hydrogen Unit 0.07Naphtha Hydrotreater 1.0CCR Reformer Unit 0.5Isomerization Unit 0.3Sulphur Recovery Unit 2 x 180 MTPD

BORL Configuration, Bina, M.P

Refinery Configurations

S.No SECONDARYUNITS RESIDUNITS

1 VGOHDT+PetroFCC DCU

2 OHCU+ConvFCC DCU

3 FullConv.HCU+DHT(Integrated) DCU

4 VGOHDT+PetroFCC SDA+SlurryHCU(50%DAO)

5 OHCU+PetroFCC SDA+SlurryHCU(50%DAO)

6 FullConversionHCU SDA+SlurryHCU(50%DAO)

7 ConventionalFCC DCU

8 FullconversionHCU DCU

9 VGOHDT+PetroFCC SDA+SlurryHCU(60%DAO)

10 OHCU+PetroFCC SDA+SlurryHCU(60%DAO)

11 FullconversionHCU SDA+SlurryHCU(60%DAO)

Cases Studied

EuroVGASOIL

COKE

KERO

VGOHDT

FCCPC

DCU

POLYPROPYLENE

ALKYLATION

EuroVGASOLINE

LPG

DHT

NHT/CCR/ISOM

CDU/VDU

PPU

FCCNap.Splitter

EuroIVGASOLINE

EuroIVGASOIL

BITUMEN

Sample Block - VGO HT + PFCC + DCU

EuroVGASOIL

COKE

KERO

HCU

ALKYLATION

EuroVGASOLINE

LPG

DHT

NHT/CCR/ISOM

CDU/VDU

EuroIVGASOLINE

EuroIVGASOIL

SDA SlurryHCU BITUMEN

Sample Block - FC HCU + DHDT + Slurry HCU

Raw water & Drinking water system Compressed air system Fuel gas system Fuel oil system Condensate Recovery system Nitrogen System Cooling towers DM water treatment plants Generation & Distribution of steam Generation & Distribution of Power Flare system

Refinery Power & Utilities

Refinery IntegrationBenefits

DistributionProductsProcessingTreatingSupply

Asset Utilization

Environmental Concerns

Integration with PetrochemicalsPetrochemical Sector: 13% annual growth projected

Major Petrochemicals : Ethylene, Propylene, Butadiene, PVC, HDPE, BTX, etc.

Crude Oil

Associated Gas

LPGEthane Methane

PropyleneEthylene C4s

Naphtha

PyGas TolueneBenzene Xylene

Naphtha

AromaticsOlefins

Cases Studied

Case-1: VGO HDT, FCC-PC, DCU, AC and PC

Case-2: OHCU, FCC-PC, DCU,AC and PC

Case-3: OHCU, DCU, AC and PC (in this case OHCU bottoms are routed to Naphtha Cracker)

Case-4: VGO HDT, FCC-PC, LC Fining, AC and PC

Case-5: Part MRDS, DCU, FCC-PC, AC, and PC

Integration with Petrochemicals

CDU / FCCU / OHCU / DCU

HEAVY NAPHTHA HDT CCR

HY.

NAPHTHAREFORMER SPLITTER

LT. REFORMATE

HY. REFORMATE

SULFOLANE EXTRACTION UNIT

BENZENE TOLUENE EXTRACTION

TRANS ALKYLATION

XYLENE FRACTIONATION UNIT

XYLENE ISOMERISATION

PARA XYLENE SEPARATION

PARA XYLENE 800 TMT

BENZENE 340 TMT

Integrated Refinery with Aromatics complex

Vac. GASOILS / Crk. GASOILS

VGO

DHDT

UNIT

ETHYLENE

CRACKER

UNIT

SWING UNIT

MEG UNIT

ETHYLENE

LLDPE / HDPE

Integrated Refinery with Petrochemical Block

HDPE UNIT HDPE

MEG

DEG

362 TMT

400 TMT

700 TMT

135 TMT

HY. NAPHTHA

FCC OFF GAS

Syn. Diesel/

Naphtha

PART DIESEL FROM DHDT

CPCL NAPHTHA

1200 TMTPA

668 TMTPROPYLENE

Slide79of64

FCCU PC

CRACKED LPG

PROPYLENE RECOVERY UNIT

PROPYLENE POLY PROPYLENE UNIT

POLY PROPYLENE

PROPYLENE EX-CRACKER

1120 TMT

668 TMT

432 TMT

FCC Unit with Petrochemical Block

Gasification: A commercially proven process that convertshydrocarbons such as heavy oil / petroleum coke, and coal intohydrogenandcarbonmonoxide(synthesisgas).

4 CH + 2 H2O + O2 4 H2 + 4 CO(Fuel) (Water) (Oxygen) (Hydrogen) (Carbon Monoxide)

SyngasGasification Technology

Competitive with unconventional & alternative resourcesExtensive commercial applicationGenerate value added productsFeedstock and product flexibility

Refinery Power Integration

Gasification MultipleSegmentOptions

PetCoke/ Coal

SNG thruMethanation

Syngas Hydrogen / Power / Steam

Power

Fuels by F-T Synthesis

ChemicalsSulphur

Slag

Refinery Power IntegrationCoke from Coker Unit can be Gasified to produce Syngas & Power / Hydrogen

Project Execution Methodology

Conceptualization of Project

Project Formulation

Preliminary FeasibilityReport (PFR) Stage

Licensor Selection

Process Package Preparation

Detailed Feasibility Report (DFR)

Final Investment Approval from Board

Project Implementation Phase

Mechanical Completion of the unit

Pre-Commissioning & Commissioning stage

Unit Start-up & Stabilization

Carry out PGTR

Project Completion

Phase-I Phase-II

PFD REVIEW

P&ID REVIEW

ENGINEERING KICKOFF

HAZOP & 3D MODELING

ORDERING/FABRICATION

ERECTION/CONSTRUCTION

P&ID CHECK/INSPECTION

PRE-COMMISSIONING

START-UP & PGTR

FLUSHING/LEAK TEST

P&ID CHECK/INERTING

1ST DRYOUT

CAT. LOADING

2ND DRYOUT

FINAL INERTING

FEED CUT-IN

Phase-II Breakdown Structure

Parameters Studied during the Project Evaluation

Various Refinery Configurations will be evaluated based on

Economic Feasibility Capex & Opex of projects Yield of Distillates Refinery Margins Plot Plan Availability

Financial Appraisal Net present value Internal Rate of Return

Financing Assumptions D/E ratio, interest rate, repayment tenor, moratorium period, etc. Macro-economic assumptions

The net GRM for the project worked out by deducting Operating Costs

Net incremental cash flows to the project worked out by deducting Tax Outgo Capital investment Net working capital from the net benefit Financial viability of the project established by computing post-

tax IRR and NPVNet Incremental Cash Flows = [ Incremental GRM ] less [ Opex +Income Tax +

Core Capital Investment + Increase in Net Working Capital ]

Financial Appraisal

1. REFINERY PROCESSES

2. REFINERY CONFIGURATION

3. PROJECT DESIGN ASPECTS

PRESENTATION PLAN

PROJECT DESIGN ASPECTS

Design Aspects

Unit/Equipment Design Philosophy (Margin & Turndown)

Battery limit philosophy for units

Vacuum Design

Instrumentation Philosophy

Metallurgy of Equipments (e.g. DSS for Water Coolers)

Piping Material Specifications

Energy efficiency / integration systems

Adherence to Standard Design & Codes

Codes & StandardsBIS Bureau of Indian standards

ASME American Society for Mechanical Engineers

API American Petroleum Institute

ANSI American National Standards Institute

ASTM American Society for Testing and Materials

AISI American Iron and Steel Institute

AWWA American Water Works Association

SSPC Steel and Structure Painting Council

MSS-SP Manufacturer Standardization Society - Standard Practice

NACE National Association for Corrosion Engineers

BS British Standard Specification

Codes & Standards

ASME Codes For Mechanical devices such as pressure vessels, boilers (e.g.) ASME Section 8, B 31.3 : Standards of process piping

API Standards Designed to help users improve the efficiency and cost-effectiveness

of their operations (e.g.) API 610 : centrifugal pumps (e.g.) API 682 : mechanical seals (e.g.) API 6D : Pipeline Valves (e.g.) API 560 : Fired Heaters (e.g.) API 616 : Gas Turbines (e.g.) API 617, 618 : Compressors

Other Codes & Standardscontd.

IS (Indian Standard) Codes For civil works and construction (e.g.) IS-456 for Plain & Reinforced Concrete

TEMA Standards For Heat Exchangers

Sl# Parameter Minimum Normal /Average

Maximum /Design

(A) METEOROLOGICAL DATA1 Elevation above mean sea level, m 3.52 Barometric pressure, mbar3 Ambient temperature, C tmin =18 tnor = 35 tmax =454 Relative humidity, % @ tmin @ tnor 80% @ tmax5 Rainfall data (mm) (a) for 1-hour

period(b) for 24-hour period

100450

6 Wind data (a) wind velocity

(b) wind direction

180 km/hr (as per IS:875 Part-III).North East & South West

(B) DATA FOR EQUIPMENT DESIGN 1 Design dry bulb temperature, C 382 Design wet bulb temperature, C 293 Low ambient temperature for MDMT, C NA4 Design air temperature for air cooled exchangers

where followed by water cooling, C40

5 Design air temperature for air cooled exchangers where not followed by water cooling, C

42

6 Coincident temperature and relative humidity for Air Blower / Air Compressor design.

80 % at 45 o C

7 Min. Design temperature for equipment 65 o C

Meteorological Design Data

Plant Life

Default plant operating life as 15 years with 5% salvage value will be considered for economic calculations.

The default plant equipment design life shall be taken as follows:a) 30 years for heavy wall reactors and separatorsb) 20 years for columns, vessels, heat exchanger shells and similar

services.c) 12 years for piping, furnace tubes, High Alloy exchanger tube bundles.d) 5 years for Carbon Steel / Low Alloy heat exchanger tube bundles.e) 15 years for reactors removable internals

Sl Parameter Minimum Normal Maximum Mech Design

1 VERY VERY HIGH PRESSURE (VVHP) STEAM Pressure, kg/cm2g 90 95 95 104/FVTemperature, oC 495 505 505 505

2 VERY HIGH PRESSURE (VHP) STEAMPressure, kg/cm2g 44.8 48 54.9 58.0/FVTemperature, oC 379 425 435 440

3 HIGH PRESSURE (HP) STEAMPressure, kg/cm2g 29.5 30.5 32.5 36.0/FVTemperature, oC 270 280 290 300

4 MEDIUM PRESSURE (MP) STEAM Pressure, kg/cm2g 9.5 10.5 12.5 15.0/FVTemperature, oC 200 220 240 280

5 LOW PRESSURE (LP) STEAM Pressure, kg/cm2g 2.7 3.5 4.0 7.0/FVTemperature, oC Saturated 170 190 240

6 CONDENSATE RETURN Pressure, kg/cm2g 5.0 13Temperature, oC 140-150 210

7 SERVICE WATERPressure, kg/cm2g 6.0 10.5Temperature, oC Amb. 65

8 COOLING WATERSupply Pressure, kg/cm2g 4.5 8.0Return Pressure, kg/cm2g 2.5 8.0Supply Temperature, oC 33 65Return Temperature, oC 45 65

9 DEMINERALISED WATER Pressure, kg/cm2g 7.0 8.0 9.0 14..0 Temperature, oC Amb. Amb. Amb. 65

Utility Conditions @ Unit Battery Limits

Sl Parameter Minimum Normal Maximum Mech Design10 BOILER FEED WATER (MP/HP)

Pressure, kg/cm2g 19.0/38.0 29.0/55.0Temperature, oC 105-110 150/150

11 PLANT AIR Pressure, kg/cm2g 5.0 6.0 6.5 10.0Temperature, oC Amb. Amb. Amb. 65

12 INSTRUMENT AIRPressure, kg/cm2g 5.0 6.0 10.0Temperature, oC Amb. Amb. 65

13 FUEL GAS Pressure, kg/cm2g 2.5 3.0 3.8 7.0Temperature, oC 40 65

14 REFINERY FUEL OILSupply Pressure, kg/cm2g 10.0 12.0 17.5Return Pressure, kg/cm2g 2.5Temperature, oC 80 165-200 220 250

15 SURFACE CONDENSATE (EX TURBINE)Pressure, kg/cm2g 6.0 15.0Temperature, oC 40 100

16 NITROGENPressure, kg/cm2g 5.0 6.0 7.0 9.5Temperature, oC Amb. Amb. Amb. 65

Utility Conditions @ Unit Battery Limits

WATER SYSTEMSBackflush arrangement shall be provided for All cooling water consumers Only overhead condensers Cooling water consumers with water line sizes greater than NB.

Back flush lines to be provided with same size as main cooling water line when main line size is 6. One size lower to be provided for main line size > 6 For much higher line sizes e.g 14 and above to be decided based on case to case basis

Water Qualityl Parameter Cooling Water

make up ( from TTP of ETP)

Cooling Water DM Water

BFW

PH 7.2-7.5 7.2-7.7 6.8-7.2/8.3-8.5 8.5-9.5

Turbidity, NTU < 2

Water Qualitycontdl Parameter Treated Raw Water as DM water

Make upDesalinated water as DM water

make upPH 7 - 7.8 7-7.8Turbidity, NTU 15 NATotal suspended solids, Total dissolved solids, NA mg/l 350 Conductivity micromho/cm NA 493Mo Alkalinity, 240 (as CaCO3)mg/l 2.9 (as CaCO3)mg/lCa Hardness as CaCO3, 176 mg/l 1.3 mg/l (as Ca)Total Hardness as CaCO3, Total cation/anion asCaCO3, 608 NATotal Silica as SiO2, 40 0.1Colloidal Silica as SiO2, mg/lSodium as Na, 344 (as CaCO3) mg/l 135.3 (as CaCO3) mg/lPotassium as K, mg/lChlorides as Cl, 172 mg/l 142-220 mg/lFree chlorine,Sulphates as SO4, 121 mg/l 12.5 mg/lPoly phosphates as PO4,Nitrates as NO3, NA mg/l 0.2 mg/lTotal Iron as Fe, 0.3 mg/l NACopper + Iron, Mg , Hardness NA mg/l 4.5 mg/lZinc as Zn, Zinc Sulphate as Zn, Boron, mg/l NA 1 mg/lDissolved Fe, mg/ lOil content, KmnO4 value at 100 oC, 20 mg/l NAHydrazine (residual), Morpholine (residual),

Compressed Air & Nitrogen System

Sl Parameter Plant Air Instrument Air

1 Dew Point at atmospheric pressure water-free (-)40oC

2 Oil Content, ppm nil nil

Sl Parameter Inert Gas Nitrogen1 Dew Point at atmospheric pressure (-) 100oC

2 Oil Content, ppm nil3 Nitrogen purity, vol% 99.99

4 Oxygen content, vol ppm 3 (max)

5 Carbon dioxide content, vol ppm 1 (max)

6 Carbon monoxide content, vol ppm nil

Liquid fuel system for the project shall be one of the following. No liquid fuel system applies to the project. Existing liquid fuel system in Refinery III shall cater to the project,

After Augmentation, if required. Alternately, new liquid fuel system shall be provided.

Fuel gas system for the project shall be one of the following. No fuel gas system applies to the project. Existing fuel gas system in Refinery III shall cater to the project,

After Augmentation, if required. New fuel gas system for the total project:

(a) Integrated to existing facility (b) Independent of existing facility

Refinery Fuel Systems

9 Burner turndown requirements have to be met at liquid fuel pressures at burner not less than the normal anticipated return header pressure. The fuel oil system shall be designed for a recirculation rate of 2:1.

9 Fuel gas liquid knockout drums and tracing for piping shall be separate for each process unit.

9 In-line strainers in burner piping are recommended for each unit. These shall be located not more than 20 meters upstream of the burner manifold and shall be 1 on-line + 1 spare strainer with mesh sizes 100 for Fuel Oil, Fuel Gas and atomising steam.

9 In-line strainers for FO, FG and atomising steam to be provided on common header supplying to all heaters within each unit.

9 Hot liquid fuel temperature shall be assumed to drop by 5oC between unit battery limits and burner manifold.

Fuel Systems

Sl Parameter Case-1 Case-2 Case-3 (Note-C)

1 Name PG VR BH VR+VAC.DIESEL

UCO+VR

2 Crude stock 3 Density @ 15oC, kg/m3 930 - 1030 978 852-8574 Sulfur content, wt% 4 (Note-1) 0.84 0.275 Nitrogen content, wppm 3700 1000 (max.) 3006 Nickel content, wppm 18 37 Vanadium content, wppm 200 5 118 Sodium content, wppm 80 129 Copper content, wppm

Case A Case B Case C Case D Case E Case F Case GCOMPONENTMOLE % Normal

OperationRefinery Start

up case

Max FG production

H2O 0.81 0.13 1.29

0.86

0.43 0.31 0.69

H2 35.35 80.1 0.0 45.49 34.48 74.96 25.63

C1 29.43 8.01 0.0 25.95 26.35 11.41 32.6

ETHYLENE 0.45 0.24 0.0 0.0 0.79 0.18 0.32

C2 16.08 4.04 9.43 15.06 13.29 6.23 20.64

PROPYLENE 1.21 0.64 0.0 0.0 2.11 0.47 0.85

C3 7.96 2.59 44.08 6.06 8.53 3.09 9.44

IC4 1.99 0.93 9.09 1.48 3.06 0.76 2.23

1BUTENE 0.50 0.26 0.0 0.0 0.87 019 0.35

NC4 3.22 1.63 36.07 2.59 5.36 1.24 5.43

1C5 06 0.17 0.04 0.77 1.05 0.13 0.27

NC5 1.32 0.79 0.0 0.94 2.31 0.57 0.87

C6+ 0.78 0.31 0.0 0.78 0.83 0.34 0.5

H2S Note-1 Note-1 Note-1 Note-1 Note-1 Note-1 Note-1

NH3 0.00 0.00 0.00 0.00 0.01 0.00 0.00

N2 0.30 0.16 0.0 0.0 0.53 0.12 0.21

TOTAL 100.00 100.00 100.00 100.00 100.00 100.00 100.00

MW 20.004 8.2533 48.79 16.717 22.537 8.9845 22.66

KGM/HR 354.51 667.9 0.353 275.5 203 914.7 507.4

KG/HR 7091.5 5512 17.2 4605 4575 8218 11498

LHV, Cal/kg 11798 14544 10964 12184 11648 14120 11613

Fuel Gas Specifications

Refinery Flare systemFlare systems for the project shall be:

Existing Refinery flare system will be used, if found adequate. Alternately, new flare header shall be provided for the project.

Single flare for all released streams Normal flare for hydrocarbons and Acid gas flare for released acid gases Separate high-pressure flare header for flared hot, hydrogen rich

gases Hydrocarbon drain from the Flare K.O. drum will be routed by gravity flow

to the CBD. In addition, pump-out facility will be provided for the Flare K.O. drum.

Philosophy of relieving flammable vapors shall be: Vapor releases of all molecular weights to be connected to flare system Vapor releases below molecular weight of vented to atmosphere Hot hydrogen-rich gases (>300C) vented to atmosphere Other:

For adherence to OISD standard # 106, individual units shall be provided with a flare knock-out drum whenever significant liquid relief is anticipated from the pressure relieving devices, apart from the main knock-out drums at the flare stack. Unit designer / contractor shall specify a horizontal unit flare KOD, sized to separate out liquid droplets down to a size of 400 .

# Flare system Built- up back pressure,kg/cm2g

Superimposed back pressure at unit battery limits, kg/cm2g

Built-up back pressure at PSV outlet,kg/cm2g

1 Normal flare 0.2 default = 1.5 default = 1.72 Acid Gas flare 0.2 default = 0.5 default = 0.73 High Pressure flare

# Contingency Low pressures< 70 kg/cm2g

High pressures> 70 kg/cm2g

1 Steam generating / consuming equipment under IBR

5% (as per IBR)

5% (as per IBR)

2 Fire case 20% as per designer

3 Thermal relief 25% as per designer

4 Operational failures 10% as per designer

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

Overpressure (as percentage of set pressure) for sizing relief valves

Refinery Flare system

Liquid Pumpout & Drain Systems

Congealing hydrocarbon drains: Combined with non-congealing hydrocarbon drains. Provided with combined cooling and heating coil

Steam generator blowdown drains: Flash MP and HP blowdowns for recovery of LP Steam. The LP steam vessel

liquid to be cooled in a CW exchanger to 40 deg C and route to Cooling tower sump through cooling water sump/pumps.

Non-congealing hydrocarbon drains: Buried Closed Blowdown drum shall be: Standard size of 10m3 to cater to only residual drains. Individually sized for each unit for single largest equipment inventory. Provided with cooling coil Connect equipment to closed blow down (CBD) network leading to a CBD drum.

CBD drum will be located in a pit and the same will be sand filled. Design CBD system for 200oC.

Caustic drains:All bulk caustic inventory drains shall leave process unit under own pressure or be pumped out. For residual caustic drains such as unpumpable vessel bottoms, level gage drains, etc., one of the following shall be adopted:

Provide underground caustic CBD system with buried vessel and pumpout. Collect residual drains by temporary facility like drums and jars. Provide caustic drains to nearby neutralization pit outside the unit area.

Acidic drains:(a) Amine systems Bulk amine drains shall be only lean amine, displaced to amine storage tank. All rich amine streams shall be routed to amine regeneration section under own pressure or under inert gas pressure or displaced with water. Residual amine drains shall be connected to a buried amine closed blowdown system located in the Amine Regeneration section. Amine-bearing drains from Amine Wash sections shall be routed to this buried vessel or collected through temporary facilities. Individual units handling amine will be provided with separate buried amine closed blowdown system from where amine stream will be pumped to regeneration unit.

(b) Sulphuric acid systems When consumed only in non-process areas, temporary facilities will be defined. Sulphuric acid storage and unloading facilities near cooling tower (existing).

(c) Process sour waters1. Process sour waters shall normally be routed to identified sour water strippers. Residual drains or during intermittent situations where unavoidable, these may be drained to oily water sewer. The effluent treatment plant designer shall be advised to incorporate provisions to receive the single largest parcel of such sour water.2. Flare water seal drum sour water to be sent to sour water stripper.

Liquid Pumpout & Drain Systems

FLUSHING OIL SYSTEMS

Normal flushing oil (FLO)- No flushing oil tank and pumps will be provided in outside battery limits.- OSBL flushing oil header will be provided with mainly CDU/VDU Gas oil, which will have hot or cold gas oil to the header. The main header also will have alternate source of FLO. - For external flushing of pumps API seal plans, or for purging instruments in congealing service, the FLO pressure will be boosted. For this purpose, a separate vessel with (1+1) screw pumps will be provided independently with in the respective unit. The connection for make up flushing oil to vessel will be provided from maintenance Flushing oil header.

Heavy flushing oil (HFLO)Straight run Vacuum Gas Oil from CDU/VDU will be taken as Heavy Flushing Oil for external flushing of hot, heavy fluid handling pumps API seal plan. To maintain the temperature of VGO about 80-110 C, the separate vessel with steam coil will be provided with in the unit. A separate set of screw pumps (1+1) will be provided to pump the flushing oil to necessary pressure level for pump seal flushing.

Operating condition Mechanical DesignSl# Stream

P, kg/cm2g

T, oC P, kg/cm2g T, oC

1.2.

Flushing Oil (Gas Oil)Heavy Flushing Oil (VGO)

6.0-16.04.0-6.0

40-10370-80

27.027.0

141100

Energy integration

Improvement in overall energy efficiency shall call for unit-level and total plant-level optimization of energy. Designer of a particular unit shall indicate the following at the outset of design activities:

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

(b)The preferred temperatures for hot feeds and products from an energy (c)integration standpoint, if these are significantly different from that stipulated in unit BEDB.

(c)Energy shall be preferentially recovered into process streams. Steam generation shall be considered thereafter to recover excess available energy. Steam generation levels shall be chosen to preferably match the corresponding steam level demand within unit.

(d) Low-level energy recoverable for external consumption, say, for Boiler Feed Water preheat serving other units.

Vacuum Design

Vacuum design conditions shall be stipulated for:

(a) Equipment operating normally under vacuum conditions

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

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

(d) Distillation columns and associated equipment that can be subjected to vacuum conditions through loss of heat input.

(e) All steam users consuming steam during normal operation.

(f) Pressure vessels containing liquids having vapor pressure at minimum ambient temperature less than atmospheric pressure.

Vacuum design conditions are not to be specified for the eventuality of blocking in after equipment steam-out or operator maloperation.

EQUIPMENT DESIGN PHILOSOPHY%turnup %turndown

Process Towers (atmospheric or above) 10%Process Towers (vacuum) 10%Fired Heaters (potentially coking services) 15%*

Fired Heaters (clean services) 15% *Heat exchangers (fouling service): overdesign on duty 10%

Heat exchangers (fouling service): overdesign on flow 10%

Heat exchangers (clean service): overdesign on duty 10%

Heat exchangers (clean service): overdesign on flow 10%

Tower overhead exchangers: overdesign on flow & duty and reboilers

20%

Pumparound exchangers: overdesign on flow 20%

Recycle compressors 10% Make-up compressors 10% minimum

Pumps in general 10%Reflux and pumparound pumps 20%3-phase separators (in and out flowrate) 10%2-phase separators(in and out flowrate) 10%Crude preheat exchangers 15%

Selection Of Mechanical Design Conditions

Equipment and piping systems shall be designed for the most stringent coincident temperature and pressure conditions, accommodating the maximum expected working pressure and temperature without causing a relieving condition

A pressure system protected by a pressure relief device connected to the flare system, shall have a mechanical design pressure, calculated at the location of the relieving device, as the higher of the following:

I)For operating pressures above 70 kg/cm2g, mechanical design pressure shall be as per designer, subject to a minimum of 77 kg/cm2g.II)For operating pressure up to and including 70 kg/cm2g, design pressure shall be the highest of the following:Maximum operating pressure (kg/cm2g) x 1.1Maximum operating pressure + 2.0 kg/cm2

Vessels operating under vacuum shall be, in general, designed for an external pressure of 1.033 kg/cm2abs and full internal vacuum, unless otherwise specified

For a full liquid system at the discharge of a centrifugal pump, the mechanical design pressure shall be as under:

Pdes = Pmax suction + Pmaxwhere,Pmax suction = Maximum pressure at suction vessel bottom during suction system relieving conditions (as per 8.2.1.2)Pmax = Pump differential pressure at pump shutoff head with maximum operating density. If not known:Pmax = 1.2 x H x max : constant speed pumpPmax = 1.1 x 1.2 x H x max: variable speed pumpPmax = 1.3 x H x max : high head multistage pump

For a full liquid system at the discharge of a positive displacement pump, the mechanical design pressure shall be the higher of:

Pdes = Prated discharge + 2 kg/cm2Pdes = 1.1 x Prated discharge


For shell-and-tube heat exchangers, the low pressure (LP) side shall be preferably specified with a design pressure at least equal to 10/13 of high pressure (HP) side design pressure, in order to avoid having to install a pressure relief device on the LP side

For systems operating at or above 0oC, the mechanical design temperature shall be the higher of the following:

Tdes = 65CTdes = Tmax + 20CTdes = Trelief (excluding fire relief temperatures)

For systems operating below 0C, the mechanical design temperature shall be equal to the lowest anticipated operating temperature.


Furnace - Design Aspects

FURNACE

TYPES OF FURNACE Cylindrical furnace

Low plot space Low cost Higher heat flux For clean services

Box furnace High plot space High cost Even heat flux For fouling services

FURNACE

TYPES OF FURNACE Natural Draft

Air for combustion enters due to pressure difference Forced Draft

FD fan is used to supply air, usually air gets heated up in convection zone.

Balanced Draft

FD fan is used to supply air and ID fan is used to suck the fluegas and heat is exchanged between air and flue gas through an external heat exchanger (APH)

FURNACE

TYPES OF FURNACE Single fired heater

Common pattern in heaters For low fouling / sensitive fluid Peak flux >80% of average flux

Double fired heater For high fouling service Low residence time Fire on both side of coil Uniform heat flux & peak flux < 20% of average flux

Fired HeatersSelection of fuelFired heaters shall be designed for continuous operation with:

100% firing on either fuel oil or fuel gas or any combination of both, unless constrained to reject use of fuel oil from reasons of process or acid gas dew point. 100% firing on fuel gas for heaters less than 1.5 MMKcal/hr.

Target efficienciesAchievable fired heater efficiencies depend on service, furnace heat duty, process temperatures and quality of fuel. Highest target efficiencies shall be pursued by a unit designer, as found economically justified. Options such as cast tube and glass tube air preheaters, steam generation and superheat, etc., shall be evaluated. Target efficiency shall be: 92% on fuel gas fired heaters only 90% on combination firing heaters (with either fuel oil or fuel gas or dual fuel mode)

Excess Air Fuel Oil Fuel GasNatural Draft 25 % 20 %Forced Draft 20 % 15 %

Fired HeatersHeater stackStacks shall be individually mounted on each heater unless there are considerations such as grade-mounted APH or combined APH system for a group of heaters.

Minimum fired heater stack heights shall be the higher of indicated heights in respective unit BEDB Part-A documents or as calculated from the formula below:

H = 14 (Q)0.3(Minimum stack height as per TNPCB / MoE&F to be provided, SOx / NOx nozzles to be provided)

where, H: stack height, metresQ: total SO2 emission, kg/hr

Middle of Radiant Section Convection Section

Furnace Burner

HEX - Design Aspects

FURNACEOPERATION

Draft inside the furnace

Air ingression

Arch pressure slightly positive Stack damper

Combustion air control thro Air registrars

Excess air : 5-10% for gas and 10-15% for fuel oil

Monitored & controlled by Arch zone O2 analyser

Skin temperature

Stack temperature

FURNACE

INTERLOCKS

Process fluid low / no flow

Fuel oil / gas - ring pressure low

Arch pressure high

APH interlocks

FD fan trip

ID fan trip

Arch pressure high

SPECIAL OPERATION Economiser

Steam Soot blowing

Steam air Decoking Steam spalling

Temperature cycling

Coke burning Convection water wash

Standard fired heater piping & instrumentation(a) Low-low fuel oil supply pressure shuts down fuel oil supply and return

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

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

(d) Low Low pilot gas pressure shuts down the pilot gas supply

(e) Low-low differential pressure between atomising steam and fuel oil shuts down fuel oil supply and return.

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

(g) Emergency coil steam, manual or automated, depending on criticality.

(h) Draft gage connections at: Burners Below convection Above stack damper Below stack damper

(i) Flue gas sampling connections at: Below convection section Below stack damper

(j) On-line analysis with location as per (g), connections mounted at the same plane: O2 analyser NOx analyser SOx analyser SPM analyser CO analyzer HC

analyser

(k) Temperature measurement connections below convection section, below stack damper, at hearth level.

(l) Skin thermocouples shall be considered for measuring temperature of furnace tubes.

HEX - Design Criteria

9 Material selection9 Thickness Calculations

Shell, Channel, Covers, Tube sheets9 No of shell passes9 Velocity of the fluid9 Pressure Drop9 Tube Pattern9 Consideration of Fluids through Tubes9 Easy maintenance

Tube size, U- Tube, Cover header, Fluid choice

Tube Metallurgy with Carbon steel

Tube MOC with Stainless Steel

HEX Material of Selection

HEX - Codes & Standards

Typical TEMA TypeHeat

Exchangers

Codes & StandardsWhich type of TEMA Heat Exchanger?


Preferred Sizes for Shell && Tube HEX

Tube Metallurgy CS / Low Alloy High alloy/SS/BrassTube Diameter 25 mm 25 mmTube Thickness 2.5 mm 2.0 mmTube Length 6.0 m

Criteria for selection of TEMA Type

Shell side Fouling Resistance

Tube side Fouling Resistance (Hr-m2-C/kcal)

TEMA type

> 0.0002 > 0.0002 Floating head 0.0002 > 0.0002 Floating Head> 0.0002 0.0002 U tube bundle 0.0002 0.0002 Fixed tube

sheet/ U-tube bundle


Tube Pitch Selection

PitchPattern

PitchAngle

ShellSideFluid

FlowRegime

Triangular 30 Clean All

RotatedTriangular

60 Clean Rarelyused

Square 90 Fouling Turbulent

RotatedSquare

45 Fouling Laminar

HEX Sample Datasheet (Pg 1/2)

HEX Sample Datasheet (Pg 2/2)

PUMPSDESIGN

Selectionoftypeofpumps Sparingofpumps

Specificationofpumpseals

Specificationofdrives

Minimumflowbypass(MFB)provisions&controls

# Operating pumps Rated capacity per pump Spare pumps

2 50% of total normal flow 1



Steam Turbine drives

When to select a steam turbine drive?Steam turbine drives shall be specified in extremely critical services where even short-term failure of a drive can result in a shutdown from where an operational recovery is difficult, time-consuming or has a large economic penalty, such as irreversible catalyst poisoning.Steam turbine drives shall also be specified for the following drives, that, among other considerations, shall ensure that a power failure does not automatically lead to a steam failure:

(a) Cogeneration / Steam generation plant BFW pumps yes no(b) Cogeneration / Steam generation plant FD Fan yes no(c) Cooling water pumps yes no(d) Compressor lube oil & seal oil pumps yes no(e) Hot well pumps yes no(f)Emergency evacuation pumps yes no

PUMPS Sample Datasheet

IBR RequirementsScope of IBRSteam generators / steam users shall meet IBR regulations. Major IBR requirements are summarized below:a) Vessels: Any closed vessel exceeding 22.75 litres (five gallons) in capacity which is used exclusively for generating steam under pressure and include any mounting or other fittings attached to such vessels, which is wholly or partly under pressure when steam is shut-off.b) Piping: Any pipe through which steam passes and if:

i) Steam system mechanical design pressure exceeds 3.5 Kg/cm2 g ORii) Pipe size exceeds 254 mm internal diameter

c) The following are not in IBR scope:i) Steam Tracingii) Heating coilsiii) Tubes of tanksiv) Steam Jackets

d) All steam users (heat exchangers, vessels, condensate pots etc.) where condensate is flashed to atmospheric pressure i.e. downstream is not connected to IBR system are not under IBR and IBR specification break is done at last isolation valve upstream of equipment.e) All steam users where downstream piping is connected to IBR i.e.condensate is flashed to generate IBR steam are covered under IBRf) Deaerator, BFW pumps are not under IBR and IBR starts from BFW pump discharge.

INSTRUMENTATION

InstrumentationPhilosophyforallequipments&pipelines

E.g.)PackedTowersForcolumndifferentialpressureindicationtwoseparatePTshallbeprovidedanddifferentialpressureshallbederivedinDCS.

Localdifferentialpressureindicationforeachbed: yes no Localdifferentialpressureindicationfortotalsection: yes no ControlRoomdifferentialpressureindicationforeachbed: yes no ControlRoomdifferentialpressureindicationforcriticalbeds: yes no ControlRoomdifferentialpressureindicationfortotalsection: yes no 1+1Basketstrainersinlinesgoingtopackedbeds: yes no Singlebasketstrainersinlinesgoingtopackedbeds: yes no

Utility Line InstrumentationUTILITY local

PIDCSPI

PAL/PAH

localTI

DCSTI

TAL/TAH

DCSFI

FAL/FAH

DCSFQ

MP STEAM 9 9 9 9 9 9 9 9 9

LP STEAM 9 9 9 9 9 9 9 9 9

Condensate 9 9 9 9

CW supply 9 9 9 9 9 9 9 9

CW return 9 9 9 9

Instrument Air 9 9 PAL 9 9 9

Plant Air 9 9 9Inert Gas 9 9 9 9 9 9Fuel Gas 9 9 9 9 9 9 9 9 9Fuel Oil 9 9 9 9 9 9 9 9 9DM Water 9 9 9 9 9 9Service Water 9 9 9

Flare 9

Block & Bypass Valve Size for Control Valve ManifoldControl Valve SizeLine

SizeBlock & By paas Valve

0.5 0.75 1 1.5 2 3 4 6 8 10 12 14 16

0.5 BlockBypass

0.50.5

0.75 BlockBypass

0,750.75

0.750.75

1 BlockBypass

11

11

11

1.5 BlockBypass

1.51.5

1.51.5

1.51.5

1.51.5

2 BlockBypass

22

22

22

22

3 BlockBypass

22

22

33

33

4 BlockBypass

33

33

43

44

6 BlockBypass

44

64

66

8 BlockBypass

66

66

86

88

10 BlockBypass

88

88

108

1010

12 BlockBypass

1010

1010

1210

1212

14 BlockBypass

1210

1412

1414

16 BlockBypass

1412

1614

1616

Notes:1.All sizes are nominal sizes in inches.2.Bypass pipe diameter shall

be same as bypass valve.3.Bypass valve will be globe

valve upto 8" size and gate valve above 8".

Control Valve Sample Datasheet

PIPING & INSULATION Insulationthicknessforheatconservation,personnelprotection,electrically

tracedlines&coldinsulation

MaterialUsage CellularGlassforprocesstemperaturesupto350C. RockWoolforprocesstemperatureupto550C CalciumSilicateforprocesstemperaturesfrom551 760C.

AdherencetostipulationsofOISDstandard#118formin. interequipmentspacingandinterdistancebetweenprocessunitandoffsites

Steamtracingforpipinghandlingcongealingservicesshallbe: Steamtracingwithinunitbatterylimits,electrictracingforoffsitesupto

150C

Steamtracingwithinunitbatterylimits,electrictracingforoffsitesupto250C

Steamtracingforbothbatterylimitsandforoffsites LPSteamuptovacuumgasoils,MPSteamforheavyresidues MPSteamforallcongealingservices

Environmental Parameters

Sulphur Recovery for reduced sulphur emissions

Flare gas recovery unit to recover hydrocarbons

Usage of low sulfur fuel in all process heaters/boilers

Incorporation of Low NOx Burners/DeNOx Technology

Continuous Ambient Air Monitoring & Stack Monitoring

Segregated collection of solid wastes.

Oil sludge treatment is done through chemical, mechanical and

bio-remediation routes.

Environ Impact Assessment Study

IsoplethsShowingMeasuredSPMConcentrations

-15000 -10000 -5000 0 5000 10000 15000

X Direction (East) Distance, m

-15000 -10000 -5000 0 5000 10000 15000

-15000

-10000

-5000

0

5000

10000

15000

Y

D

i

r

e

c

t

i

o

n

(

N

o

r

t

h

)

D

i

s

t

a

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,

m

-15000

-10000

-5000

0

5000

10000

15000

1234567891011121314151617181920212223242526272829303132333435363738

394041

0

50

100

150

200

250

300

Pollutant: SPM

Unit: ug/m3

0 1000 2000

Scale

m

Min Max AvgSl.No. Parameter g/m31 SPM 18 287 70 234

2 RSPM 15 147 34 70

3 SO2 6 40 7 124 NOx 3 15 3 7

5 H2S 1 23 1 4

6 NH3 5 57 6 34

7 HC and VOC 10 14 -

Ambient Air Quality Data

Fugitive Emissions from the Work Zone Area of MRC Benzene < 1 ppm (OSHA)

Environment Noise & WaterParameter Residential Commercial Industrial Inside the

Plant Area

Noise levels(dBA)

46 - 82 72 - 79 66 - 79 77 - 84

Standard(dBA)

55 65 75 85

Water Environment

Surface WaterGround WaterBacteriological Quality

Risk Analysis Study

HeatRadiationEffectsduetoBLEVE(CDUVDU)

37.5kW/m2(315m)

12.5kW/m2(591m)

4.0kW/m2(1032m)

Individual & Societal Risk Factors due to that project are studied & analysed

Risk Analysis Study

REFINERY PROCESSING STEPSCRUDE- FEED PREPARATIONPREHEAT TRAINS & FURNACEATMOSPHERIC DISTILLATIONVACUUM DISTILLATIONVACUUM DISTILLATIONCRUDE DESALTERCRUDE FURNACECRUDE ATMOSPHERIC COLUMNLube Oil Base Stocks REACTOR INTERNALSREACTOR INTERNALSCATALYTIC REFORMINGCATALYTIC REFORMINGCATALYTIC REFORMINGCATALYTIC REFORMINGCPCL HYDRO CRACKERSULFUR RECOVERY UNITRefinery ConfigurationKey Considerations & Available OptionsGlobal Economic Downturn & RecoveryGlobal Oil OutlookIndia - Net Oil Import DependenceProjects ClassificationDrivers for New Projects IdentificationImpact of Product Demand Stringent Product SpecificationsDrivers for Revamp Projects IdentificationCrude Feed SelectionTrend in Crude ProcessingProcessing of Opportunity CrudesProcessing of Opportunity CrudesTypes of RefineriesProcessing Units in Oil RefineriesRefinery ConfigurationsRefinery - Integration BenefitsIntegration with PetrochemicalsIntegration with PetrochemicalsGasification Multiple Segment OptionsRefinery Power IntegrationPlant LifeWATER SYSTEMSWater QualityWater QualitycontdCompressed Air & Nitrogen SystemFURNACEFURNACEFURNACEFURNACEFURNACEHEX - Design CriteriaHEX Sample Datasheet (Pg 1/2)HEX Sample Datasheet (Pg 2/2)PUMPSPUMPS Sample DatasheetINSTRUMENTATIONControl Valve Sample DatasheetPIPING & INSULATIONEnvironmental ParametersIsopleths Showing Measured SPM ConcentrationsEnvironment Noise & Water

Documents

3 TNK Bapiraju