iocl report

Summer Internship undertaken at

Indian Oil Corporation Ltd - Guwahati Refinery, Noomati, Guwahati, Assam.

Project submitted by

G.Pranesh

Alagappa college of technology,Anna University, Chennai-600025

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ACKNOWLEDGEMENT

At the outset, we are extending grateful to Mrs Sita Baruah , for having given the opportunity of this internship training at Guwahati Refinery Training Center,Noomati.

We are thankful to our training co-ordinator Mrs Padmashri Sarma , Assistant Manager (T&D) for the continued support and valuable guidance throughout the internship training. We are extremely thankful to Mr Mahesh Kumar DGM(FS) , Fire & Safety department for sharing his knowledge and expertise with us.

We are extremely thankful to Mr Arup Laskar, CPNM production department for sharing his knowledge and expertise with us

We are very thankful to Dr.S.Kalaiselvam, Prof and head, Dept of Applied science and technology for his constant support.

We would like to thank all the technical assistants for their valuable time, patience, explaining the process and giving us an insight to real practical working atmosphere of the oil industry

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CONTENTS

1. Overview of IOCL.2. Crude Distillation Unit.3. Delayed Coking Unit.4. Hydrotreater Unit.5. INDMAX Unit.6. Hydrogen Generation Unit.7. Effluent Treatment Plant.8. Motor Spirit Quality Upgradation Unit.9. Oil Movement and Storage.

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Overview of IOCL- Guwahati

Guwahati Refinery was set up at Noonmati in Guwahati on January 1, 1962. Guwahati Refinery is the first Public Sector refinery of India and belongs to Indian Oil Corporation Limited. The refinery was inaugurated by Late Pandit Jawahar Lal Nehru, the first Prime Minister of independent India. The refinery was built with Romanian Collaboration and has a capacity of 1.0 million metric tonnes per annum. This refinery process crude oil from Upper Assam Oil Fields, India and helps cater energy need of the region. Major Products of this refinery are:

1. LPG,2. Motor Spirit (Petrol),3. Aviation Turbine Fuel (ATF),4. Kerosene,5. High Speed Diesel,6. Light Diesel Oil and7. Raw Petroleum Coke.

With growing environmental consciousness, Guwahati Refinery, Indian Oil Corporation Limited has also ventured into ecologically friendly fuel and subsequently installed 3 new units: the ISOSIV, the Hydrotreater and the INDMAX. The ISOSIV unit produces Lead Free Petrol by the Molecular Sieve Technology, which separates Octane rich MS components from feed naphtha. The Hydrotreater Unit (HDT) enables the Refinery to produce High Speed Diesel of very low sulphur and cetane number conforming to BIS specifications. The HDT also produces ATF, Superior Kerosene Oil with high smoke point and low sulphur. The Indane Maximization (INDMAX) technology developed by R&D Centre of Indian Oil installed at the Refinery is designed to achieve LPG yield as high as 44% through Fluidized Catalytic Cracking of residual feed stocks like Reduced Crude Oil, Coker Fuel Oil and Coker Gasoline. The INDMAX unit also enables Guwahati Refinery to upgrade all its residual products to high value distillate products and make it a zero residue Refinery.

COMPOSITION OF CRUDE OIL ( in weight percent)

Carbon : 82-87 Hydrogen : 11-15 Oxygen : 0.1-1.5 Nitrogen : 0.1-2 Sulphur : 0.5-6 Metals : <0.1

PROPERTIES OF CRUDE OIL

reddish brown to black in colour combustible oily liquid

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UNITS IN GUWAHATI REFINERY

UNIT CAPACITY (MMTPA) LICENSORCrude Distillation UnitDelayed Coking UnitHydro treating Unit 0.6 MMTPA UOP,USA Hydrogen Generation Unit 10 TMTPA Technip, ItalyINDMAX unit 0.15 MMTPA IOCL R&D

MSQU 45 TMTPA UHDE, India PVT Ltd.

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CRUDE DISTILLATION UNIT

In the primary unit of the Refinery i.e. the Crude Distillation Unit (CDU), desalted crude from the desalter is heated up through a series of heat exchangers and is fed into a pre fractionator column. Here the lighter gases, LPG and unstabilised gasoline are separated. The outputs from CDU are gasoline, Kero-I, Kero-II and Straight Run Gas Oil. Reduced Coke Oil (RCO) which is the bottom product from the main fractionating column, forms the main raw material for Coking unit and indmax

Gasoline from the main fractionator is fed into Naptha Splitter where it is separated into three different fractions namely Light Naphtha (LN), Reformate Naptha (RN) and Heavy Naptha (HN). LN forms the feed for Hydrogen unit, while RN is a component in the gasoline pool and HN is fed to the Hydrotreater unit.

DETAILED DESCRIPTION ABOUT THE PROCESS:

Crude oil from the three storage tanks is pumped through a centrifugal pump. Crude is stored in storage tank at ambient temperature. The crude is heated initially by heat exchanging with products from distillation column. By using series of heat exchangers, the temperature is raised to about 130oC which is sufficient temperature for desalter.

In desalter, a high electrical voltage is applied. The crude is mixed with water and emulsifier before entering the mixing tank. Water and crude coalesces and forms a suspension. Solubility of salt in water is more than the solubility of salt in the crude so salt dissolves in water. Hence, when electric field is applied emulsion breaks into water (with salt) and crude. The brine solution settles at the bottom while the desalted crude floats over the brine solution. The brine solution is drained from the bottom of the settler. About 30% of brine is left in the sealer to prevent the drainage of crude.

The important parameters of desalter are

i) voltage( electric field)ii) pressureiii) concentration of saltiv) flow(brine)

It is noted that the difference of pressure before and after the mixing tank should be kept minimum to ensure complete mixing. The brine solution is later diluted and used for other purpose (fire fighting cooling).

ELECTRIC DESALTING

Salts present in crude: sodium, magnesium, calcium, potassium, iron

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These salts associated with crude oil both as a fine suspension of droplets also as a more permanent emulsion. The less stable mixtures can be separated by simple settling methods. The impurities in crude oil can be classified as OLEOPHOBIC and OLEOPHILIC

OLEOPHOBIC (insoluble) OLEOHILIC (soluble)

a) Salts Mainly chlorides and sulphates of sodium, potassium, calcium & magnesium

Sulphur compounds

b) Sediments Silt, sand, mud& iron sulphides etc

Organic metallic compounds i.e nickel, vanadium, iron & arsenic

c) H2O Present as soluble emulsified and dispersed H2O

d) Others Napthenic acids and nitrogen compounds

NEED FOR REMOVAL:

Equipment corrosion in the CDU caused by HCl (hydrolysis or dissociation of chloride salts)

Increased consumption of ammonia to neutralise HCl Erosion of pumps, pipelines, valves suspended matters Plugging of equipment and fouling of heat transfer surfaces Product degradation due to high ash content in fuel oil Trace metal act as catalyst poison

The electric desalter operates in two steps

i) Forming an emulsion of crude oil and H2Oii) Emulsion formed in first part is broken by means of electric field

The process initially involves adding 3-6% of H2O and then heated to 100-150oC. The electric field breaks the film and allows droplets to combine which cant combine before due to small size. Now due to high specific weight they settle down in the bottom of the vessel and are withdrawn for dispersal. A droplet of one liquid suspended in another assumes a perfect spherical shape when no external forces are present. When a higher electric field acts it becomes elliptical shape which means a dipole is being formed. They attract opposite charges, collide and outer films are broken, they grow and settle down.

The desalted crude from the desalter is heated through a number of heat exchanger in series to increase the temperature to about 205◦C. The heated crude(205◦C) is sent to a pretopping column

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which acts as a prefractionator. In the pretopping column light gasoline is separated as the top product. Addition of NH3 and ahuralan is done to prevent corrosion. pH of the crude is maintained at about 6 to 6.5 because slightly acidic is much better than slightly alkaline, ahuralan forms an interface(coating) on the inner surface of distillation column which prevent the corrosive chemicals to come in direct contact with metal surface. At the top of pretopping column, the temperature is maintained to about 120◦C by using product reflux.

The bottom of the pretopping of column is steam stripped to remove the higher ends present in the hydrocarbon, more vapour pressure it produces. Therefore to reduce the pressure load on main fractionator higher ends are removed in pretoping column .the pressure of pretopping column is maintained to 1.7kg/cm2.

The lighter gasoline removed crude from pretopping column is called as skimmed crude. The pressure in main fractionator is maintained at 0.7kg/cm^2. The skimmed crude is then passed through the two pass furnace and heated to about 364◦c and sent to the main fractionators. In the main fractionator, heavy gasoline is obtained as the top product. It is followed by kero-1 , kero-2,gas oil and reduced crude.kero-2 and gas oil are sent to the stripping section to increase the quality .Nowadays kero-2 is not stripped and used for blend for HSD.

The light gasoline obtained as the top product from pretopping column is sent to a stabilizer. The bottom product is sent to NSF unit. The top product is separated into LPG and light naphtha .

The heavy gasoline from the top of the main fractionator is sent to NSF as feed which is separated into heavy naphtha ,reformed naphtha and light naphtha in successive fractionators . The only finished product from CDU is LPG and all other are intermediate products.

OPERATING PARAMETERS:

Desalter:

Temperature: 125-130◦C Pressure : 9-13 kg/cm2 Inter-phase level : 30-40% Delta pressure across mixing valve:1-1.5 kg/cm2g Wash water flow rate : 4-5% of crude. Demulsifier injection rate: 7-8 ppm

Pre-Topping column:

Inlet temperature : 220◦C Top temperature : 112◦C Top pressure : 2 kg/cm2g Reflux drum temperature: 40◦C

Furnace:

Coil inlet temperature : 250◦C Coil outlet temperature : 112◦C Combustion air temperature : 195-220◦C

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Combustion air pressure at burner:25 mmWC

Main fractionator column:

Crude inlet temperature :360◦C Column top temperature: 144◦C Column top pressure: 0.4 kg/cm2g Column bottom temperature : 336◦C Kero draw temperature : 230◦C Gas oil CR draw temperature :300◦C

Stripper:

Kero-I Draw Temperature: 157◦C Kero-II Draw Temperature: 260◦C Gas Oil Draw Temperature: 289◦C

Stabilizer:

Inlet Temperature :130◦C Column Top Temperature: 58-62◦C Column Bottom Temperature: 163◦C

PRODUCTS:

Crude Naptha Kero-1 Kero-2 Gas oil LPG RCO

CHEMICALS USED:

Caustic soda Ammonia Ahuralan Brine water

UTILITIES:

MP steam Cooling water Condensate Drinking water Fuel oil supply Fuel oil return Fuel gas LP steam

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Service air Nitrogen Instrument air

DELAYED COKING UNIT

Delayed coking unit is the main secondary unit where the refinery produces middle distillates from heavy ends. Main feedstock to DCU is RCO, which is heated to high temperatures of about 500◦c in a furnace. Due to high temperatures, RCO is thermally cracked and yields various hydrocarbon fractions like LPG, coker gasoline, coker kerosene, coker gas oil, coker fuel oil, residual fuel oil and coke.`

PROCESS DESCRIPTION:

Process consists of the following main steps:

Pumping and preheating of RCO feed. Introduction of RCO feed to the main fractionator ‘s and control of bottom temperature. Introduction of fractionation’s bottoms into heater and cracking. Cracking to coke and distillates.

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Removal of RFO. Fractionation. Withdrawal of side cuts. Cooling of CR. Coke chamber operations.

PUMPING AND PREHEATING:

Feed for the unit is RCO from CDU and CLO from INDMAX. The feed is initially heated to 80◦C and it is increased to 250◦C.

INTRODUCTION OF FEED AND CONTROL OF BOTTOM TEMPERATURE:

The bottom temperature of fractionator is maintained at 365◦c which is maintained by varying the amount of RCO entering using a temperature controller provided at column liquid zone inlet line.

The heated stream of RCO is heat exchanged with vapours from quench column. Heavy portion is condensed at bottoms and forms a recycle with surplus quantity of fuel oil.

Column bottom temperature: 365◦c

Recycle ratio: 0.73

CRACKING AND HEATING:

RCO with recycle at 365◦c is sent to second pump. It enters into 4 equal passes having individual flow controllers.

Inlet pressure: 25-35 kg/cm2

Outlet temperature: 498-500◦C

It is heated in radiant section section of the charge heater.

To minimize the coke formations, BFW is injected into the coil at 50 kg/cm2g and at a rate of 300 kh/hr/pass.

For water injection, high-pressure boiler feed water from TPS is used and its flowis controlled with the help of flow controllers.

Charge heater is a balanced draft furnace with an air pre-heater to an thermal efficiency of 89-90%.

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CRACKING TO COKE DISTILLATES:

Furnace outlets enter the bottom of one of the 2 coke chambers operated alternately.

While one remain cooling, cutting, cleaning, pressure testing and vapour heating operations other chamber remains under filling the change over from one chamber to another is done after 24 hours under normal circumstances.

Cracked vapour leaves chamber from top at 440◦C under coking operation, while the more reactive heavy hydrocarbon moleculesin the liquid undergo polymerization level of coke builds up inside the chamber as time passes. A residence time of 24 hours is allowed for coke formation and this is why it is called delayed coking. It is endothermic and so temperature drops.

Vapour is quenched at outlet of chamber by chamber by stop/gas oil injection to arrest further reaction in vapor line which otherwise may cause coking up of the vapor lines. It also increases vapor velocity reducing coke formations. All the gases and the light distillate vapor leaving the chamber from top after quench enters quench column through the vapor line at a temperature of about 430◦C. Reduced crude oil is called as long residue.

Coking is a thermal cracking process in which high molecules break giving lighter ends and some molecules combine giving higher ends.

Reactions:

Primary Reaction- Heavier hydrocarbons decompose to smaller ones – Cracking.

Secondary Reaction- Smaller reactive molecules combine producing heavy tarry materials - polymerization

Coke drum is where cracking and polymerization reactions take place. For this lengthening of time of liquid phase cracking and polymerization reaction to take place which is why it is called delayed coking.

ABSORPTION OF RFO IN QUENCH COLUMN

Column is provided with melagrid packing and the dropout leg, a part of the hot or cold circulating reflux is routed at the top of the column which:

Washes off all the entrained heavy materials from the vapour coming out of the chamber. Maintains the column top temperature around 415◦C.

To increase the service period of Quench column and to minimize the chances of blockage, the system is flushed with hot CGO from the CGO stripper.

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FRACTIONATION

FEED: RCO + Vapors from quench column

Coker of gases Coker gasoline Coker kerosene Coker gas oil Coker fuel oil Furnace feed

Quench column vapors are contacted with preheated RCO in heat transfer trays followed by downcoming liquid in the upper sieve and valve trays. On the way, it condenses to generate various fractions with the uncondensed vapors leaving from the top unconverted residue leaves from the bottom as secondary feed to the furnace.

WITHDRAWAL OF SIDECUTS:

Coker kerosene: Tray 8

Coker gas oil : Tray 19

Coker fuel oil: Tray 26

CIRCULATING REFLUX:

To maintain the temperature profile of the column a circulating reflux has been provided inbetween CK and CGO draw off zones. Circulating reflux is drawn from chimney tray below 19 at the rate of around 90-120m3 /hr at a temperature of 280◦C.

One part of CR, sent to the stabilizer bottom reboiler to maintain the bottom temperature and another to exchanger where it preheats the RCO feed to fractionation column. The remaining CR sent to thermosiphon reboiler for steam generation in waste heat boiler.

VAPOUR BLOWDOWN RECOVERY SYSTEM

Used to recover HC and reduce pollution during cooling of isolated coke chamber.

Capacity: 0.336MMTPA

HC recovery rate: 10 ton/hr of oil.

LPG RECOVERY UNIT

Recover LPG from coker off gas to absorb heavier ends of CG with stabilized naptha (recycle naptha) in rectified absorber column and then separation of LPG components from unstabilized naptha in stabilizer column. Stabilised naptha and LPG are caustic wash and then to storage.

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OUTLET PARAMETERS

Top : Temp 49.5◦C Pressure 14.2 kg/cm2

Bottom: Temp 151◦C Pressure 14.6 kg/m2

COMPRESSOR SECTION

Coker off gas from DCU fractionating column reflux drum goes to compressor first stage section knockout drum through compressor at 1 kg/cm3 and 10◦C temperature.

RECTIFIED ABSORBER SECTION

Feed- CG at 15kg/cm2

Feed gas enters at 20th tray flow upward wash recycled and unstabilised naptha. Rectified absorber has 44 valve trays. Capacity of pump is 31m3/hr Discharge pressure of 19 kg/cm3

Recycle naptha is a part stabilisied naptha at 40 th tray unstabilized naptha and condensate from knockout drum.

STABILISATION SECTION

It has 32 valve trays.

Function is to split the stabilizer feed to LPG and stabilized naptha.

It has level guage high and low level alarms, temperature indicator, pressure guage at over head line, safety valves. Bottom of the rectified absorber is fed to stabilizer.

OUTLET PARAMETERS

Top: Temp 59◦C Pressure 9.6kg/cm2 gm

Bottom: Temp 167◦C Pressure 9.95Kg/cm2 gm

SPONGE ABSORBER

Rectified absorber overhead vapour flow from top of absorbers section to bottom sponge absorber.

Lean sponge oil (kero) from kero stripper is fed to reduce naptha loss in rectified absorber. Sponge absorber overhead vapour (sour fuel gas) rooted to fuel gas.

Rich sponge oil from bottom is used to cool lean sponge oil in kero lean or rich sponge oil exchangers and sent to coker fractionators.

CGO COALESCER

Used to remove water from products. Coker kero and coker gas oil passes through pre filter catridge and then coalesce. Products having less than 15ppm water leave to storage tank. Level

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transmitters monitor water RCGO and water or CK interface level in sump provided at coalesce vessel.

CIRCULATING REFLUX

To maintain temperature profile of column, it is provided between CK and CGO draw off zones. CR set at 19th tray around 90-120m3/hr ath 280◦C.

Part of CR goes to stabilizer bottom reboiler to maintain bottom temperature and another to exchanger where it preheats the RCO feed to fractionation column. Remaining is set to thermo-siphon for steam generation in waste heat boiler.

Heat exchangers are connected to steam drum where steam is generated in terms of low process heat demand or shut down. Cooler circulating reflux is sent to quench column.

PRODUCTS

CGO CFO COKER KEROSENE COKE

CHEMICALS USED

CAUSTIC SOLUTION SILICONE FLUID AHURALAN

UTILITIES

FUEL OIL FUEL GAS MP STEAM LP STEAM BOILER FEED WATER COOLING WATER

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HYDROTREATER UNIT

Hydrotreater reduces the sulphur content of diesel by treating it with hydrogen at high pressure and temperature over catalyst to convert the bound sulphur in diesel to H2S. The unit is also used to achieve 48.5 cetane number during diesel operation and 21mm smoke point during kerosene operation. The unit also has the flexibility to process SR Kero I alone to produce aviation turbine fuel if required.

PROCESSING STEPS:

Pumping of feed to the desired pressure. Mixing recycle gas with feed. Heating of feed and recycle gas mixture to the desired temperature. Contacting the feed and recycle mixture with catalyst. Cooling the reactor effluent Separating liquid and vapour from the reactor effluent Recycling the separated gases to reactor’s inlet. Stripping the liquid reactor effluents to remove lower boiling fractions as wild naphtha Cooling and polishing of products before sending to storage

UNIT SECTIONS:

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Feed section:

o Feed transfer pumpso Coalescero Preheatingo Feed filtero Surge vesselo Feed pump

Reaction section:

o Reactorso Reactor effluent separationo Heatero H2 makeup compressoro Recycle gas compressor system

Fractionation section:

o Product stripper for separation of diesel and naphthao Net gas compressoro Product coolero Coalescer

Other systems:

o Flare systemo OWSo CRWSo CBDo Utilities ,etc

CATALYSTS:

Oxides of Nickel Cobalt Molybdenum on Alumina base

Shape:

Sphere and extruded with special shape

Catalyst selection:

Depends on type of feedstock, desired product properties, process design condition.

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CATALYST FUNCTION:

KF-542-9R: Saturates coke precursors , picks up particulates and helps in improved liquid distribution.

KF-647-3Q: Traps a variety of metals – Ni, V,Na,Si,As. Considering the high level of metals and silica in coker streams.

N-205-1.5Q/ KF-859-1.5Q: Main catalyst in bottom bed of reactor. This is a Ni-Mo catalyst for HDS and HDN reactions necessary to treat coker streams. Helps in trapping Si.

KF-848-1.3Q: Super-active and highly reactive Ni-Mo catalyst. Main HDS and HDN catalyst in reactor. Helps in effectively saturating aromatics and thus helps in achieving the smoke point specification of kerosene as well as density reduction, cetane index and distillation shift specifications of distillation product stream.

CATALYST DEACTIVATION:

The catalyst maybe deactivated by any one of the following

Coke deposition Metal accumulation Catalyst sintering

REACTIONS:

Sulphur removal Nitrogen removal Oxygen removal Olefin saturation Aromatic saturation Metal saturation Halides removal Hydrocracking reactions


1. Feed is received from 3 sections:a) Diesel feed from tanks.b) Directly CK-I and CGO feed.c) Kero feed.

2. Various processing steps involved:a) Pumping of feed to desired pressure. b) Mixing recycle gas with feed.c) Heating of feed and recycle gas mixture to the desired temperature.d) Contacting the feed and recycle gas mixture with catalyst.e) Cooling the reactor effluent.

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f) Separating liquid and vapour from the reactor effluent.g) Recycling the separated gases to reactors inlet.h) Stripping the liquid reactor effluents to remove lower boiling fractions as wild

naphthai) Cooling and polishing of products before sending to storage

3. Feed : Diesel pumped at 8.3 kg/cm2 gm ATF or Kero 1 pumped at 7.7 kg/cm2 gm

4. Pumped feed is sent to coalescer where water is coalesced from feed. It has a water boot where water coming along with feed gets separated and water is removed.

5. Filter is backwash type and is designed to retain particles of size 25microns or higher. It is provided with the differential pressure indication on DCS and a high differential pressure alarm on DCS.

6. Filtered feed is sent to shell side of feed preheat exchanger then heated by stripper feed bottom exchanger tube side effluent.

7. Preheated feed now passes to feed surge drum. Pressure is controlled through a split range controller which admits N2 in event of pressure falling below set point and vents off vapours to flare if pressure increases more than the set point.

8. Feed is then sent to charge pumps which pumps around 120.9 kg/cm2 gm and directed to the cold, combined feed exchangers.

9. Emergency shutdown is provided for feed surge drum liquid level; no flow of feed.10. Feed pumps take suction from feed surge drum and its discharge passes through effluent

feed cold exchangers and hot combined feed exchangers.11. Recycle gas goes to upstream of cold combined feed exchangers, the feed gas mixture

after preheater passes to charge heater for further heating for proper reactor inlet temperature.

12. 49-F-01 is a vertical cylindrical heater with top mounted convection section. Feed entry through convection section and leaves through radiation section. Then it goes to reactor.

13. Combined feed leaves at a temperature range of 354-385oC , 334-343oC and 334-348oC for diesel, kerosene and ATF respectively depending on the catalyst activity. Outlet temperature is controlled by varying firing in heater using temperature controller cascaded to fuel gas pressure controller.

14. Recycle gas quench exchanger RGC is given in between reactor catalyst bed to control inlet temperature of lower bed and WABT.

15. As the reactants flow downward through catalyst bed, various exothermic chemical reactions occur and the temperature of the flowing stream increases.

16. Due to exothermic nature of the reactions taking place outlet temperature is greater than inlet temperature.

17. Catalyst deactivation increases temperature of desired product. Increasing reactor temperature increases catalyst activity.Recommended temperature : 385oc above which coke formation is rapid.

18. Units are typically designed for a maximum reactor bed temperature rise of less than 42oC.

19. Reactor effluent cooling is done by heat exchangers.20. Wash water is injected into the stream before it enters the condenser in order to prevent

the deposition of salts that can corrode and foul the coolers.

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21. The wash water can be a cold, clean condensate or a combination of sttripped water from sour water stripping unit and cold clean condensate. Air-cooled exchanger with 4 bundles – 2 for inlet, 2- outlet. The vapour phase from high pressure separator.

22. Vapour, liquid and sour water are specialized which is a horizontal vessel with a water boot on its underside.

23. HC liquid in effluent is separated from vapour and aqueous phases. Level of HC liquid is maintained by a level controller. The HC phase leaves from the bottom of vessel to stripper feed /bottom exchanger ,by split range control logic through LV -1604A/B

24. Sour water collected in the boot of 49-V-04 is sent under level control to the 49-V-09 via 49-P-06A/B minimum circulation line. sour water collected in the stripper receiver boot is sent to the sour water treating unit located in sulfur block.

25. Vapour phase from high pressure separator is sent to recycle gas KOD (49-C-01)and finally to recycle gas compressor (49-K-01) suction.

26. Pressure in (49-V-04) high pressure separator is controlled by a split range controller which controls a separator pressure either by varying the make up hydrogen rate or by venting the separator over head to the flare .

27. Over heads from 49-C-01 are directed to recycle gas compressor,49-K-01A/B. bottom from 49-C-01 are drained manually to CBD. Alternatively, the bottoms can also be drained to ONS .

28. 49-K-01A/B is a reciprocating machine designed to compress a large volume of gas at a relatively low compression ratio

29. Stripping steam is given at bottom of stripper (49-C-02) through control valve FV-250 to control flash point of diesel. Steam is injected into the column from bottom through control valve.

30. VL mixture is sent to stripper receiver 49-V-09 where separation of vapour ,liquid and water takes place. Water collected in the water boot along with sour water sent from high pressure separator to interface level control to sour water stripper unit.

31. Vapors then to pass on to stripper of gas knockout drum 32. Over head process to wet gas compressor.33. The pressure at49-V-09 is controlled through split range control PIC-2601. On high

pressure at 49-V-09 . The gas gets released through fuel gas header through control valve and on low pressure which opens the control valve PV-2601A and PV-2601B(split range) from net gas compressor outlet line to 49-V-09

34. HC liquids from 49-V-09 are directed to the stripper overhead pumps discharge from 49-P-06A/B is sent to 49-C-02 top tray as reflux. A part of discharge from 49-P-06A/B is drawn and sent to CDU or DCU as un stabilized over head liquid product(naphtha ). HC level in 49-V-09 is controlled by LIC-2602 controlling the amount of HC refluxed to 49-C-02 through cascading unit with its flow controllers FIC-2701.

35. Bottom from 49-C-02 are directed to stripper bottom pumps 49-P-05A/B. Discharge from 49-P-05A/B is sent through 49-E-07A/B/C, 49-E-01A/B and product coolers ,49-E-06A/B to diesel product coalescer ,49-V-06 .

36. During diesel mode of operation ,product from 49-V-06 is passed through the salt dryer 49-V-15 keeping caustic wash tower and sand filter bypassed for final removal of water.

37. When the level of rock salt in the dryer falls, it is replaced with fresh load. Dried product from top of 49-V-15.

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38. During KERO/ ATF run ,the product from 49-V-06 is sent through caustic wash tower,49-V-07 to remove any residual hydrogen sulfide from the product stream and then to sand filter 49-V-08 to remove entrained caustic 49-V-15 remains bypassed PP1-3101 is provided across the sand filter to check the differential pressure.

39. Product from the product treatment section is sent under flow control LIC-2501 to one of the following locations depending upon its quality:a) ON-SPEC hydro treated product to product storageb) OFF-SPEC hydro treated product to stops .Additionally ,the line for startup circulation going back to 49-G-01 inlet has also been provided.

40. Arrangement is also made for mixing neat hydro treated KERO and SRK-1 to diesel and kerosene product line respectively by blending pump 07-P-01A/B. There are provisions for antistatic agent in the ATF product through antistatic mixing tank (49-V-18) and antistatic pump 49-P-13. A back wash line is also provided from salt dryer outlet line to the feed filters 49-G-01.

41. Over head from stripper off gas KOD ,49-V-17 is directed to net gas compressor suction ,49-K-02A/B.Net gas from compressor discharge is directed to net gas knockout drum (49-V-14)via net gas cooler.

42. Partially net gas is used for pressure control of stripper receiver (49-V-09) and balanced net gas is directed to amine adsorption unit. The liquid from 49-V-14 is withdrawn to CBD through level control (LIC-2901) and from 49-V-17 through manual valve. On high level of 49-V-17, LAHH-2604 will stop the net gas compresser(49-K-02A/B).

CORROSION INHIBITOR INJECTION:

This is injected to control the corrosion of downstream equipment and piping.

WASH WATER SYSTEM:

Wash water used in plant is a mixture of condensate and stripped water from sour water stripping unit.

Catalyst sulfiding of the catalyst is done to convert metal present in the catalyst to its metal oxides.

PRODUCTS:

Hydrogen

UTILITIES:

Boiler feed water MP steam DMW

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INDMAX UNIT

The INDANE MAXIMISATION ( INDMAX) technology is an in-house technology developed by R&D center of Indian oil designed to achieve LPG yield as high as 44%. The INDMAX technology was first commissioned at GUWAHATI REFINERY. Besides its function of maximization of LPG, it enables the refinery to upgrade its residual products to high value distillate products and make it a zero residual refinery.

INDMAX unit is a high severity catalytic cracking process in which catalysts have excellent metal tolerance with coke and dry gas selectivity. In this process high molecular weight components are cracked to LPG range products. The special features that distinguish INDMAX and FCC are:

High yield of LPG( 40-65 wt% feed). Very high catalyst/ oil ratio coupled with high reactor temperature for severe cracking. Novel catalyst formulations for high yield of LPG, low coke, low dry gas and very high

vanadium tolerance. Wide flexibility in feed stock.( naphtha to heavy residue).

FEED:

Residual crude oil from CDU. CFO and CGO from DCU.

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CATALYST:

Component A: Medium pore pentasil zeolite Component B: Consists of partially or fully ultra stabilized Y-zeolite with specified rare

earth metals, active silica –alumina based matrix and binder Component C: Mostly contains large pore or mesoporous acidic non-crystalline active

matrix.

PRODUCTS:

LPG Gasoline ( high octane number). TCO (diesel). CLO FG Steam (HP).

OPERATING CONDITONS:

Temperature: 530-600◦C.

Catalyst to oil ratio: 15-25(wt/wt).

Higher riser steam in the range of 10-15 wt% of feed.

DESIGN INFORMATION:

The design capacity of INDMAX unit at Guwahati refinery is 0.1 MMTPA based on 8000 on stream hours. INDMAX unit consists of:

Feed storage and pumping section. Reactor and regenerator section. Fractionation section. Gas concentration section. LPG/Gasoline treatment section.

Unit turndown capacity: 50%.


The mixed feed (RCO + CFO) and CG is sent to a riser where residence time is 3 seconds.

The Y-steam (medium pressure) is added to riser . From the riser, it enters into the reactor where 2 cyclone seperators are present. Primary

and secondary seperators are present for complete separation of catalyst and hydrocarbons.

The spent catalyst enters the regenerator.

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The regenerator is at high pressure than reactor. The catalyst moves from reactor (lower pressure) to regenerator (high pressure) where the

catalyst settles in reactor forming a pack. Due to pressure difference the valves SCSV and ACSV works.

RISER, REACTOR AND REGENERATOR:

It consists of four subsections

Catalyst handling and loading Riser reactor and stripper Regenerator Flue gas waste heat recovery section

Catalyst handling and loading:

Catalyst is fluidized with dry aeration air and transported to fresh catalyst hopper. During loading of catalyst to the hopper, the fresh catalyst hopper is kept under vacuum, by connecting to the catalyst loading steam ejector with silencer. Vacuum level is maintained at 9kg/cm2gpressure. Equilibrium catalyst hopper is used for storage of equilibrium catalyst from the regenerator or for the equilibrium catalyst obtained from elsewhere for the purpose of unit startup. Catalyst hopper is kept under pressure of 4 to 4.5kg/cm2gpressure with processor during catalyst loading to the regenerator

Riser, Reactor and Stripper:

Regenerated catalyst enters riser at about 686◦C. The RLSV controls the catalyst flow based on the riser top temperature. The catalyst is fluidized at the bottom of the riser with stabilization steam, which enters through the nozzle .

The CG feed enters at temperature of 40◦C is sprayed on the rising catalyst in the riser uniformly through the CG nozzle.

Mixed feed coming from preheat train at a temperature of 182 to 255◦C enters at riser bottom just above CG feed entry point through mixed feed nozzles. This will ensure proper mixing of catalyst and HC feed vapors in the riser.

In order to maintain low HC partial pressure in riser and to reduce the residence time of reactants, dilution steam is injected through a dedicated dilution steam nozzle located on riser well above mixed feed nozzle, enabling significant reduction in thermal cracking.

Catalyst and product vapor enters riser cyclone placed inside the reactor which separates 99% catalyst from product vapors. Steam is injected into the reactor to quench the product vapors thereby minimizing post riser cracking.

Stripper has perforated baffles for counter current contact of steam and catalyst. The flow of spent catalyst to regenerator takes place due to the gravity head generated by the catalyst bed in stripper. Also differential pressure between the reactor and the regenerator is very critical which maintains the gradient required for the flow of spent catalyst.

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Regenerator:

Spent or coke laden catalyst is regenerated by burning it in hot air which is exothermic in nature. This hot catalyst will transfer heat from the regenerator to riser or reactor. Regenerator also acts as catalyst surge vessel. Temporary deactivation of catalyst occurs due to coke deposition while permanent deactivation occurs due to hydrothermal deactivation, vanadium poisoning.

Fresh catalyst is added to compensate permanent deactivation. Some catalyst is withdrawn to keep the total reactor-regenerator system catalyst invertery at normal levels.

Regenerator is normally operated in turbulent fluidization regime.

The regenerator top pressure is maintained between reactor and regenerator through the adjustment by opening of FGSV-a double disk slide value.

Flue gas waste heat recovery section:

The off gases are heat exchanged with boiler feed water which in turn produces high pressure steam. These gases are then sent to stack where it is released to the atmosphere. The high pressure steam produced is used in other sections of the system.

Gas concentration section:

It is to separate dry gas, LPG, stabilized gasoline from wet gas and unstabilised gasoline.

Sub-sections of gas concentration section:

Wet gas compressor Primary absorber Sponge absorber C2 stripper Debutanizer or stabilizer

Three cut splitter:

The design capacity of three cut splitter is 55TMTPA based on 8000 on-stream hours

The purpose of three cut splitter is to split a blend of INDMAX gasoline and wild naphtha to three cuts:

Top cut: Light gasoline (TBP range C5 -70◦C) has high octane number and low aromatics sent to MS pool.

Middle cut: Heart cut (TBP range 70-90◦C) which will be high in benzene, sulfur, aromatics and olefins hence cannot be directly absorbed in Euro III grade MS pool. This stream will be routed to NHDT unit as feed followed by further treatment in ISOM and DIH sections.

Bottom cut : Heavy naphtha (TBP range 90-200◦C) for partial adsorption in MS pool or DHDT or finished HSD pool.

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HYDROGEN GENERATION UNIT

The Hydrogen plant is designed for Indian Oil Corporation Ltd. (IOCL) refinery at Guwahati, India. The hydrogen generation is based on steam reforming technology of KTI using a mixture of light naphtha (SRN) and off-gases ex-LPG Recovery Unit (LRU) as primary feed. Necessary provisions have been made for proper conditioning of the off-gas feed in terms of olefin saturation and desulphurization. For achieving the required feed flexibility, a pre-reforming step is applied upstream the reforming using Kvaerner’s technology. For the purification of raw hydrogen after the shift conversion, Pressure Swing Adsorption (PSA) process is applied to produce the high purity hydrogen product. The unit behaviour and its performance has been also simulated for the foreseeable operational as well as upset modes.

The hydrogen unit consists of Desulphurization, Pre-reforming, Reforming and process gas cooling and High temperature / Low temperature shift conversion sections to increase the hydrogen content of the process gas. Purification is done with a PSA Unit. The feedstock to the Hydrogen unit is LRU off gas and Light Naphtha feed. Purpose of the hydrogen unit is to supply hydrogen to Hydro treating unit (to meet out the Cetane specifications in diesel fuels) and MSQU unit (to meet the Octane and aromatic content specification of gasoline fuels).


The light gases from the LRU (OSBL) together with SR (light) naphtha form the feed of Hydrogen Generation Plant. The Hydrogen Plant is divided into 6 main sections:

1. Feed treatment

2. Pre-reforming

3. Reforming

4. Heat recovery

5. Shift

6. Product recovery, i.e. PSA unit

Some hydrogen is recycled to the feed treatment section to be able to meet hydrogen demand there and the purge gas from the PSA unit is used as fuel in the reforming section.

Catalyst Poisons For maintaining long production cycle of hydrogen, time period between two successive catalyst change outs have to be maximized. This is possible only when feedstocks for the unit consisting of Naphtha and Process Steam shall be free from poisons. The catalyst poisons irreversibly damages the active sites on the Catalyst & thereby destroys its activity. The catalysts used in steam reforming of naphtha are highly selective, extremely active and very sensitive. Even small

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levels of poisons in hydrocarbon feed stocks such as sulphur, chlorine and organometallic compounds diminish the catalyst activity.

Sulphur Sulphur is poison for Pre-reforming, Reforming and LT shift catalyst. Any sulphur slipping from desulphurisation section will be adsorbed by pre-reforming catalyst & reduce its activity. The desulphurisation section is designed to remove sulphur to a level of <0.1 PPMW.

Chlorine Chlorine is serious poison to pre-reforming and shift catalyst. LT shift catalyst LK-821-2 is especially very sensitive to chlorine. Many alloy steels are sensitive to chloride induced stress corrosion. Chloride accelerates the sintering of metal crystallites in catalysts.

Silica Other possible poison is silica, which comes in contact with the catalyst through process steam. Silica is poison to pre-reforming and LT shift catalyst. Silica content in process steam should be less than 0.2 PPM. The limits of silica and total dissolved solids are to protect the catalysts as well as preheat coils.

Steam to Carbon Ratio and Carbon Formation. The stoichiometric requirement of steam per carbon atom for steam reforming and shift reactions is 2.0, but it is always maintained higher as carbon forming reactions are promoted under steam reforming conditions. The severity of the carbon formation depends on. 1. The feed stocks 2. The operating conditions (steam to carbon ratio, pressure and temperature) 3. The type of reformer design. 4. The catalyst loading. 5. The state of catalyst

Carbon forming reactions are suppressed by using excess steam in steam reformers. In industrial steam reforming, with adiabatic pre-reformer configuration, carbon deposition can take place at steam to carbon ratio less than 1.5 or due to overheating of the feed.

The carbon deposition occurs due to the following reactions.:

CH4 C+2H2 Methane Cracking CO+H2 C+H2O CO Reduction 2CO C+CO2 CO Disproportionation

In steam naphtha reformer, cracking of higher hydrocarbons to carbon can also take place. The risk of carbon formation due to cracking is eliminated in the Reforming with pre reformer configuration.

The steam to carbon ratio is controlled at the inlet of the reforming section. Three different steam to carbon ratios can be used to determine the amount of steam that has to be added:

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Steam to feed weight ratio: The ratio at the Prereformer inlet of the weight flow of steam to the weight flow of total hydrocarbon feed.

Steam to carbon ratio: The ratio at the Reformer inlet of the moles of steam to the moles of carbon (excluding carbon dioxide). The moles of carbon are counted as atoms. Thus one atom of ethane represents two atoms of carbon.

Overall steam to carbon ratio: The ratio of all steam added to the process gas, to the moles of carbon (excluding carbon dioxide) present in the feed.

Equilibrium A system is at equilibrium if the rate of forward reaction equals the rate of reverse reaction. The conversion of reactants to product is not complete at equilibrium for a reversible reaction. For the methane reforming reaction the equilibrium constant at the exit of the steam reformer can be calculated by the equation. [CO] P [H2]3 K= P [CH4] P [H2 O] The equilibrium concentration at the exit of the steam reformer is function of the exit pressure and temperature and feed composition to the reformer. Approach to Equilibrium The composition of the gas leaving the steam reformer is generally not at equilibrium for the particular pressure and temperature at the reformer O/L but is actually near the equilibrium. The approach to equilibrium at the exit of the catalyst bed is the difference between actual gas exit temperature at the O/L of Reformer and the equilibrium temperature corresponding to the gas composition and the pressure.

Feed Pre-treatment Section The Nickel based Catalyst used in Pre Reformer will be poisoned by the Sulphur & chlorides present in the Naphtha. In the feed pre-treatment section Sulphur content in Naphtha is reduced to < 0.1 ppm.

Feed Hydrogenation / Hydrodesulphurization: LRU off-gases contain significant amount of olefins in addition to H2S. The light naphtha contains Mercaptanes as well as trace amounts of heavy metals such as arsenic, lead, vanadium, copper which are catalyst poisons. The olefins are saturated by hydrogen over the catalyst in the Hydrogenator. This reaction is highly exothermic which needs proper recycle loop for keeping the temperature rise under control. The resulting temperature is high enough for complete conversion of mercaptanes to H2S and for efficient removal of H2S in the downstream ZnO beds. The impurities are absorbed on the Hydrogenator catalyst, which is duly considered in its operating life. Some of typical reactions are shown below. (R stands for a Hydrocarbon radical)

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Olefin saturation: R=R + H2 RH-RH (1) Hydrogenation of organic sulphur and chlorine compounds to form H2S and HCl: RSH + H2 RH + H2S (2) RCl + 1/2 H2 RH + HCl (3) RISR2 + 2H2 RIH + R2H + H2S (4) RISSR2 + 3H2 RIH + R2H + 2H2S (5) C2H5 SH + H2 C2H6 + H2S (6) C6+H5SH + H2 C2H6 + H2S (7) CH3S C2 H5 + 2H2 C2H6 + H2S (8) C2 H5SS C2H5 + 3H2 2C2H6 + 2H2S (9) C4 H8S + 2H2 C4H10 + H2S (10) (Tetra hydrothiophene) C4H4S + 4H2 C4H10 + H2S (11) (Thiophene) COS + H2 CO + H2S (12) Because of the very low levels of sulphur compounds found in most Naphtha feed stocks, any temperature rise observed across catalyst bed is usually a result of olefin saturation. However, generally no exotherm in bed is seen, as olefin content of SRN is extremely low.

Feed Desulphurization and Dechlorination:

The chlorides and sulphur are poisons for the downstream pre-reformer and the reformer. HCl is absorbed on a chlorine guard catalyst bed located above the ZnO beds to avoid formation of Zinc chloride. The sulphur in form of H2S is removed in the Desulfurizer containing zinc oxide. The zinc oxide catalyst will remove hydrogen sulfide to levels <0.1 ppmw. The reactions involved are: HCl + Na-Aluminate NaCl + H2O (13) ZnO + H2S ZnS + H2O (14)

Prereforming and Reforming Steam Reforming of Naphtha takes place in two Reactors, Adiabatic Pre-Reformer & Tubular Reformer. Both Reactors are having Nickel based Catalyst. In the Adiabatic Pre-Reformer having CRG Catalyst all heavier Hydrocarbons are converted to Hydrogen, Carbon Monoxide, Carbon Dioxide & Methane. In the Tubular Reformer having a Catalyst ICI-25-4, ICI-57-4G Hydrogen is produced from Methane & Steam by Reforming.

The reactions taking place in the Pre-reformer and the Reformer are: CnHm + nH2O nCO + (½m +n) H2 (Endothermic) (15) CO + H2O CO2 + H2 (Exothermic) (16)

For hydrocarbons with a carbon number higher as one (n>1) the equilibrium for reaction (15) at the outlet of the Pre-reformer will almost be completely to the CO side thus resulting in almost complete conversion of C2+. However, based on the competing methanation reaction, the CO &

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CO2 formed will get partly converted to methane. For methane, this reaction represents the equilibrium that will determine the methane content in the stream exit the Pre-reformer. The conversion of methane with steam to CO and hydrogen is strongly favoured by a high temperature, low pressure and high steam ratios. At the Reformer outlet, reaction number (15) will have approached near equilibrium represented by the ‘approach to methane equilibrium’. Reaction number (16) is generally referred to as the water gas shift reaction or simply the shift reaction. The mixture in the Reformer outlet will be essentially at equilibrium for this reaction. The conversion of carbon monoxide with water to carbon dioxide and hydrogen is strongly favoured by a low temperature and a high steam quantity, but is independent of pressure. Shift Conversion

The gas mixture, which leaves the Reformer, is essentially at equilibrium of the shift reaction. Further shift conversion is applied at lower temperatures to convert carbon monoxide to hydrogen. The reactors are operated at the temperatures consistent with the catalyst stability and design of heat recovery train, in order to optimize the hydrogen yield from the feedstock. The principal reaction is: CO + H2O CO2 + H2 (Exothermic) (17)

The outlet composition of the shift reactors is a function of both the equilibrium temperature and the catalyst activity. The optimum operation temperature at the inlet of the reactors will change while the catalyst ages and can be based on CO slip from the reactor. For the High Temperature Shift Reactor the start of run inlet temperature is 320◦C and can be increased over the life to 350oC to limit the CO slip. For the Low Temperature Shift Reactor start of run is at 190oC and over the catalyst life can be increased to 215◦C. In the High Temperature Shift Reactor, a copper promoted iron oxide catalyst is applied. In the Low Temperature Shift Reactor a copper based catalyst is applied in overall case Reaction equilibrium is controlled by the partial Pressure of CH4, H2, CO & CO2. The Reforming reactions are strongly Endothermic hence forward reactions are favoured by high Temperature as well as by low Pressure while the shift reaction is Exothermic and is strongly favoured by low Temperature and is largely unaffected by Pressure. To maximise overall efficiency of the conversion for higher yield of Hydrogen, reformers are operated at high Temperature and relatively lower Pressure.

Pressure Swing Adsorption (PSA)

PSA technology is used to produce very high purity hydrogen at pressure from the reformed gas. This is achieved by molecular sieves, which adsorb the contaminants and allow the hydrogen to pass. To regenerate the molecular sieves the adsorber is depressurized. This releases the contaminants and, after pressurization, the adsorber is ready for reuse. The contaminants, which are released at low pressure, are collected in the purge gas drum and are used to meet part of the heat demand of the reformer.

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Boiler Feed Water Conditioning

Process condensate from the heat recovery train, is recycled for preparation of boiler feed water and is supplemented by imported demineralised water. The process condensates is separated at two temperature levels and are fed to the degasifier. The balance requirement of demineralised water is preheated and fed to Degasifier. Dissolved gases such as oxygen, carbon dioxide etc. are removed in the Degasifier by stripping. The stripping is ensured by flash steam from boiler blow down together with HP steam generated within the unit. There is a chemicals additives unit for oxygen scavenging, deposit control and pH control.

Waste Handling

The waste streams in the process are handled as follows:

- The flue gases from the Reformer are sent to atmosphere via a stack.

- Flammable relieves from safety valves and operational upsets are routed to a flare header and connected to B.L.

- Blow down from the steam system is flashed and the condensate is cooled before sending it to the sewer system

- The vent form the Degasifier and other gases/vapours, e.g. steam that also have to be relieved from the unit in case of an emergency, are vented to the atmosphere in a safe location.

Capacity, Turndown Ratio and On-stream Factor The light gases from the LRU (OSBL) together with SR (light) naphtha form the feed of hydrogen generation plant.

Capacity The hydrogen unit is designed to produce 1250 kg/h of hydrogen with a minimum purity of 99.985 mol. %. The normal operation (design case) is based on 0.5 t/hr of naphtha and the balance of feed from LRU off-gases*. The plant operation only on light naphtha can deliver up to 1188 kg/h hydrogen based on the design case hardware. The plant minimum TURN DOWN is 30 % of design hydrogen capacity. *LRU off gas never taken as feed due to high dienes content With respect to the H2 plant, the feed gases are based on the composition as given in 2.2.1. only under “ex-LRU”.

On this basis, Capacity, H2 plant including PSA unit on product : 10,000 TPATurn-down Ratio :30% of designOn Stream days, days/year : 360 days of year

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UTILITIES:

Water Steam and condensate Fuel gas Coker naphtha Air Nitrogen Hydrogen

PROCESS DETAILS:

The Hydrogen unit contains the following process steps:

Feed preheating and hydrogenation

Feed desulfurization/dechlorination

Prereforming

Reforming

High and low temperature shift conversion

Hydrogen purification

Heat recovery

Steam system

Spill back system

Fuel system

Feed Preheating and Hydrogenation

The naphtha entering from the B.L. is pumped by the Naphtha Booster Pump 48-P-04A/B collected in the Naphtha Feed Surge Drum 48-V-02, which is blanketed by nitrogen. From there it is pumped by the Feed Pumps 48-P-01 A/B up to a pressure of 36.3 kg/cm2g. The LRU off-gases from battery limits are routed to Feed Gas K.O. Pot 48-V-01 to remove any liquid and are compressed by means of Feed Gas Compressor 48-K-01 A/B pressure of the off-gases is about 36 kg/cm2g. These two streams are mixed together for further processing. The process demand for feed is met by means of the recirculation from the discharge of 48-K-01A/B back to suction after cooling in Feed Compressor Recycle

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Cooler 48-E-01 against cooling water. This feed is additionally mixed with recycle hydrogen. The Hydrogen Recycle Compressor 48-K-02A/B, compresses the required amount of hydrogen from the PSA at about 20 kg/cm2g to the required pressure at the mixing point. This mixture is vaporized in the Feed Pre heater / Vaporizer 48-E-02. The recycle hydrogen provides the necessary quantity for conversion of olefins and other unsaturated organic compounds as well as ensuring adequate partial pressure of hydrogen for conversion of organic sulfur and chlorides in the hydrogenator 48-R-01.

The Feed Preheater/Vaporizer uses HP condensing steam to vaporize the naphtha. Complete vaporization is ensured by controlling the outlet temperature to achieve approx. 20C superheat in this case. The preheated and vaporized feed is then further superheated in Feed Preheater 48-E-24 in the convection section of the Steam Reformer. The outlet temperature at the exit of the 48-E-02 is set by the temperature needed at the exit of 48-E-24. For the design case, the temperature of the feed gas exit of 48-E-24 is 250C. The superheated feed from 48-E-24 is then routed to the Hydrogenator 48-R-01.

In the Hydrogenator all the unsaturated organic compounds like e.g. olefins in the feedstock reacts, over the nickel-molybdenum catalyst, with hydrogen contained in the feed gas. As a result of this highly exothermic reaction, the Hydrogenator outlet temperature is higher than the inlet temperature. In order to maintain this outlet temperature at about 360C, a part of the Hydrogenator effluent is recycled after cooling. This cooling is done in Hydrogenation Loop Cooler 48-E-03 against boiler feed water. This recycle is injected into the feed gas by means of the Recycle Gas Injector 48-J-01. This injector uses the energy contained in the feed gas itself to provide the work necessary to recycle the cooled Hydrogenator effluent. The mixed feed to 48-R-01 enters at a temperature of 300C. Due to the increased mass flow through the Hydrogenator, the temperature rise is limited to about 60C, thus obtaining an outlet temperature of about 360°C.

However, in the case of pure naphtha feedstock, due to lack of unsaturated compounds in the feed, there is no temperature rise in the Hydrogenator. Therefore the 100% naphtha feed is heated to about 360C in the combination of 48-E-02 / 48-E-24. In order to ensure that there is no drop in the mixed feed temperature to 48-R-01, the recycle cooling system has been provided with a bypass.

Feed Desulfurization / Dechlorination The hydrogenated gas then is routed to the desulfurization unit consisting of the Desulfurizers 48-R-02A/B. Each of these reactors contains a chloride removal bed as well as ZnO filled bed. The chloride removal bed comprises of sodium aluminate supported on alumina while the ZnO bed contains granulated ZnO with a cement binder.

The above reactors work on a lead-lag combination. Each reactor’s chloride bed and ZnO bed are designed to last up to 6 months of operation on mixed feed. When sulfur slip at > 0.2 ppmw is detected in the outlet of the lead reactor, it is isolated for removal of the spent

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absorbents and reloading of fresh alumina and ZnO. On being reintroduced into service, it then becomes the lag reactor.

There is no temperature rise in the process in these two reactors. However, due to heat losses, there is a small temperature drop in the system. Prereforming

The desulfurized feed is mixed with a controlled quantity of steam based on the calculated hydrocarbon weight flow and the required steam to feed ratio of 2.5 kg/kg. This mixture is routed to Prereformer feed Heater 48-E-22. After heating to about 450oC in this heater mounted in the convection section of the Reformer furnace, the gas is routed to the Prereformer 48-R-03 A/B. The temperature control at the inlet of 48-R-03A/B is achieved by varying the temperature of steam used for mixing. HP steam at 320C and saturated high pressure steam at 255C in combination provide the necessary temperature control needed. At any time, one reactor is on line and the other is on standby. The Prereformer is operated adiabatically and converts the feed gas to an equilibrium mixture of methane, carbon dioxide, carbon monoxide and hydrogen. This results in a feed which can be further superheated in the convection section itself, to minimize the Reformer duty. The prereforming of feedstock, containing higher hydrocarbons is overall exothermic in nature. This results in a temperature increase to 464 ◦C for the design feed case. If LRU unit is out of operation the amount of heavier hydrocarbons increases which results in outlet temperature of 475◦C. Due to the larger concentration of the higher hydrocarbons in the naphtha than in the LRU off-gases, the temperature increase in the case of 100% pure naphtha case is higher and the outlet temperature reaches 524◦C. The two Prereformer reactors enable a continuous operation of two years.

Reforming

The Prereformer effluent is mixed with additional quantities of steam and then superheated in the Reformer Feed preheater 48-E-21. The Reformer 48-F-01 is designed to operate at a steam to carbon ratio of 2.8 in the design case. This amounts to an overall steam to carbon ratio of about 2.7. The temperature at the exit of 48-E-21 is 630◦C. The Reformer 48-F-01 is top-fired and consists of 36 tubes with a heated length of 11.7 meters. The Reformer tubes have an ID of 110 mm and are filled with Ni based catalysts. The superheated gas is distributed into the Reformer tubes where the reforming reactions take place. The normal Reformer outlet temperature is 850◦C. The reforming duty is provided by purge gas and vaporized coker naphtha/straight run naphtha

High and Low Temperature Shift Conversion

In order to increase the hydrogen content in the syngas from the Reformer, the gross of the carbon monoxide is converted by steam to hydrogen and carbon dioxide in the HT Shift Reactor 48-R-04 The Reformer effluent is cooled against boiler quality water in the Process Gas Boiler 48-E-04 which has a temperature control valve in the boiler itself. This is achieved by means of an internal bypass. For the design case, the CO content

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in the syngas will be reduced to approximately 4.15 mol% in the efflux of 48-R-04. (dry basis, with a reactor inlet temperature of 340°C.) A further increase in the hydrogen content of the process gas is accomplished by the utilization of LT Shift Reactor 48-R-05. For the design feed, LT Shift Reactor reduces the CO content of the process gas further to approximate 0.57 mol% (dry basis), with an inlet temperature of 200°C.

Hydrogen Purification In the PSA the hydrogen is separated at about a temperature of 40°C from the process gas with a once through recovery of 89.5 %. The hydrogen leaving the PSA has a purity of min 99.9 mol%. The rest of the constituents of the process gas is removed as a purge gas and serves as the primary fuel for the reformer. The PSA purge gas leaves the PSA unit at a normal pressure of 0.33 kg/cm2 g. The product hydrogen is passed through a filter 48-G-01 to remove any fines , especially present in the initial phases of operation. A part of the pure hydrogen is recycled through the Hydrogen Recycle Compressor 48-K-02 A/B for the hydrodesulfurization. The rest of the pure hydrogen product is sent to B.L. under pressure control at a pressure of 20 kg/cm2g.. It is this pressure control which indirectly fixes the operating pressure of the reformer.

Heat Recovery Heat recovery from flue gas The heat of the flue gasses leaving the radiant section is recovered in the convection section by the 48-E-20 Shock Boiler, 48-E-21 Reformer Feed Preheater, 48-E-22 Prereformer Feed Preheater, 48-E-23 Steam Super heater, 48-E-24 Feed Preheater, and finally, a Combustion Air Preheaters 48-E-25 & 48-E-26 with an Economizer 48-E-27 in between the Air Preheaters to enable an acceptable stack temperature. These APH are being provided with bypass to take care of flue gas dew point. The flue gas is discharged to the atmosphere via the Flue Gas Fan 48-K-04 to the Stack 48-X-02 . The radiant box draft is maintained by the Flue Gas Fan and is achieved through controlling the motor of 48-K-04. The combustion air required to burn the fuels is provided by the Combustion Air Fan 48-K-03A/B.

Heat Recovery from Process gas

The Reformer effluent is cooled to the required inlet temperature of about 340C for the High Temperature Shift Reactor 48-R-04 in the Process Gas Boiler 48-E-04. Boiler water from Steam Drum 48-V-04 operating at a pressure of 42 kg/cm2g, under natural circulation, serves to remove this heat. The inlet temperature for Shift Reactor 48-R-04 is controlled by means of an internal bypass. The outlet temperature of the gas at HT shift is about 412C. The heat recovery from this effluent is achieved through steam superheating in 48-E-05 and boiler feed water preheating in 48-E-07. The inlet temperature to the LT Shift Reactor 48-R-05 is controlled by a process gas bypass around 48-E-07. To prevent boiler feed water from boiling in this exchanger, the exit boiler feed water temperature is controlled by a bypass of process gas

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around the second Boiler Feed Water Preheater, 48-E-06.

After the LT Shift Reactor, the process gas is further cooled to below the dew point of the process gas in the Boiler Feed Water Preheater 48-E-06. The remaining heat is recovered in the Demin Water Preheater 48-E-08. The hot process condensate is separated from the gas in 48-V-07 and the gas is further cooled to about 40C in the Process Gas Air cooler 48-AC-01 and the Process Gas Trim Cooler 48-E-09. The cold condensate is separated in 48-V-08 before the gas enters the PSA Unit 48-X-05.

Steam System The boiler feed water receives water from the following sources: 1. Process condensate from the Hot and Cold Separators 48-V-07 and 48-V-08.

2. Demineralised water, received at the B.L. at a normal operating pressure of 5.0 kg/cm2g and temperature of 25°C

The steam system consists of a Degasifier 48-V-06 operating at about 0.3 kg/cm2g. For the degasification, steam condensate from the Feed Preheater and flash blow down are added to provide the required heat for stripping. The process condensate and demineralised water are stripped in the Degasifier 48-V-06 and are collected in its sump.

This water is pumped by the Boiler Feed Water Pumps 48-P-02 A/B to the Steam Drum 48-V-06 operating at 42 kg/cm2g. Before entering the Steam Drum the water is preheated in the Boiler Feed Water Preheaters. To maintain below an acceptable level of contaminants in the boiler water, a part of the boiler water is continuously blown down. The blow down from the Steam Drum is flashed in Blow Down Flash Drum 48-V-05 to enhance heat recovery. The liquid portion of this flash is cooled against combustion air before discharge to sewer.

The generated steam is partly used as process steam for the steam reforming reactions in the Prereformer and Reformer. Further, steam is used as a heat source for feed preheating/ vaporizing in the Naphtha Feed Vaporizer 48-E-02 and as stripping steam make-up in the Degasifier for boiler feed water degassing. The balance steam is superheated in Steam Superheater 48-E-23. This is desuperheated as required by boiler feed water to comply with HP steam quality requirements and sent as export steam on pressure control to the battery limit.

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Fuel System

The following fuels are available to supply the required heat demand for the Reformer:

PSA purge gas

Coker naphtha fuel

Straight run naphtha

Refinery fuel gas

PSA purge gas is used as a priority fuel in the Reformer. Under normal conditions about 80% of the Reformer load is supplied by purge gas. Coker naphtha is used to meet the balance load. Using saturated HP steam vaporizes coker naphtha. Thus the makeup fuel is used in a vapor form in the burners. Coker naphtha from battery limit is received in the Coker Naphtha Fuel Surge Drum 48-V-10 which is provided with a nitrogen blanketing. From this vessel, Coker Naphtha Fuel Pump pumps the naphtha 48-P-03A/B and vaporized in Fuel Vaporizer 48-E-11A/B against saturated HP steam. A minimum flow of vaporized naphtha is returned from the vapor coker naphtha header. This return flow is condensed and put back into 48-V-10. The pressure in the coker naphtha fuel header is regulated by the combustion control of the reformer. Due to the possibility of fouling in the Coker Naphtha Fuel Vaporizer, a standby exchanger is provided. Further, a backup with refinery’s fuel gas is given from 48-V-01 Feed Gas Knock Out Drum outlet. Straight run naphtha which is the feed can also be used as fuel.feed naphtha from P04A/B discharge is routed to P05A/B discharge thus routed to coker naphtha fuel surge drum 48 V –10. Combustion Air Fan 48-K-03 supplies the combustion air. The combustion air is preheated to 460 0C in the convection section to reduce the fuel consumption. The combustion air is on flow control in order to ensure an optimum quantity and prevent under stoichiometric combustion. The excess air to ensure this is controlled at 10% at 100% operation. In view of the possible more stringent legislation on NOx emissions in the future, a provision is made in the Reformer convection section, (upstream the Economizer 48-E-27), which will allow installation of of a DeNOx unit at a later staDeNOx unit at a later stage.

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EFFLUENT TREATMENT PLANT

Industries wastewater treatment covers the mechanism and processes used to treat waters that have been contaminated in some way by anthropogenic industrial or commercial activities prior to its release into the environment or its re-use. Most Industries produce some wet waste although recent trends in the developed world have been to minimize such production or recycle such waste within the production process. However, many industries remain dependent on process that processes that produce wastewaters. So Industries produce wastewater, otherwise known as effluent, as a bi-product of their production. The effluent contains several pollutants, which can be removed with the help of an effluent treatment plant (ETP). The "clean" water can be safely discharged into the environment.

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TREATED EFFLUENT CHARACTERISTICS

PH 6.5 - 8.5 Oil < 5 ppm Sulfide < 0.25 ppm Phenol < 0.35 ppm TSS <10 ppm BOD <7.5 ppm

Design Flow Wet Weather Flow ( WWF ) = 550 m3/hr Dry Weather flow (DWF ) = 365 m3/hr

ETP SECTION SECTION 1 Physico – chemical Treatment for removal of Hydrocarbons, Sulphides and Total suspended solids. The API separator is provided for separation of coke fines coming from coke cutting section of DCU. API 1 has three segments where the coke fines settle, allowing clear water to flow into the open channel. There is also another coke settler near API 1 separator where coke cutting sump water comes into from coke cutting section of DCU.

SECTION 2 Biological treatment system incorporating activated sludge system for oxidising the organic matter.

SECTION 3 Tertiary treatment system comprising of pressure sand filter and activated carbon filters for treatment removal of TSS, odour, color and phenol.

SECTION 4 Sludge processing section comprises of oily and chemical sludge processing and disposal as a solid waste biogradable material.

SECTION 5 Chemical dosing system comprises of storage facilities of various chemicals and preparations of chemicals solution of standard concentration for injection at various stage during effluent treatment.

API SEPERATION Additional facility for separation of fuel oil from effluents and storage of waste oil effluents. 1> Blow down system 2> Dehydrating tanks 3> Oil settling basin 4> Emergency reservoir

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5> Saintary water basin 6> Coke fine settler 7> API solid removal system

API SOLID REMOVAL SYSTEM 1> Thickener 2> Lagoons

CHEMISTRY OF EFFLUENT

POLLUTANT TREATMENT METHOD 1> Free Oil Gravity separation 2> Emulsified Oil Chem destabilisation and floatation 3> Sulphide chemical oxides 4> Organic (BOD/COD ) Biological oxidation and sedimentation5> Settable solids sedimentation 6> Microbes Disinfection by chlorination 7> Suspended Solids sedimentation and filteration

BIOLOGICAL TREATMENT BOD ( Food ) + micro-organism = cellular matter + energy + CO2 + H2O

ACTIVATED SLUDGE PROCESS BOD + N + P + O2 + Bacteria = CO2 + H2O + energy + New bacteria cells Dead bacteria cells + O2 = CO2 + H2O + N + P

CHLORINATION HYDROLYSIS REACTION

Cl2 + H2O = HOCl + H+ + Cl

-

IONIZATION REACTION HOCl = H+

+ OCl-

EQUIPMENTS 1> Flash Mixer : Breaking oil emulsion and coagulate oil particles . It dose Acid ( HCL) whenever PH of effluent is required to be adjusted.

2> Flocculation : Provided to flocculate the coagulation formed in flash mixing tank. polyelectrolyte is added.

3> Aeration Tank : Provide to remove biodegradable organics contributing to BOD/COD.

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4> Polishing Section : Pressure sand filter are provided to remove the suspended solids and activated carbon filter are provided to remove the odour , color and organic compounds to meet the treated water quality (MINAS) for reverse in the refinery .

5> Sludge Thickener : This unit is provided to increase consistency of sludge for further treatment by centrifuge.

MSQU-MOTOR SPIRIT QUALITY UPGRADATION UNIT

MSQU consists of three cut splitter, SR light naptha splitter, naptha hydrotreatment and isomerisation units.

OBJECTIVES

To split indmax gasoline and wild naptha in three cut splitter and separator heart cut stream. To produce light naptha with reduced C7+ contents in naptha splitter from the field off SR

Naptha from existing splitter. To treat in the NHDT a mixture of the light naptha heart cut from three cuts splitter and

straight run light naptha in order to produce sulphur free stabilized naptha to feed the isomerization unit.

To increase the RON of the hydrotreated light naptha cut in the isomersation unit.

Purpose of three cut splitter is to split a blend of indmax gasoline and wild naptha into three cuts.

Purpose of light naptha hydrotreating unit is to produce a clean desulphurised naptha cut to be processed in the isomerisation unit after removal of all impurities.

Purpose of new straight run light naptha splitter column is to reduce the C7+ hydrocarbon compounds 1.58 wt% maximum in light naptha feed to NHDT unit.

Purpose of isomerisation unit is to increase and convert low octane straight chains to high octane branched isomers.

Purpose of deisohexaniser is to recycle the low octane C6 n-paraffins and methyl pentanes back to the reactor circuit to obtain high octane product.

REACTIONS

Hydrorefining - desulphurisation and denitrification takes place. Hydrogenation – saturation of olefins and diolefins take place. Benzene hydrogenation (exothermic) Isomerisation Naphthenes ring opening Hydrocracking

CATALYSTS

Benzene hydrogenation- Platinum on Alumina

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Isomerisation- Platinum on chlorinated Alumina

OPERATING CONDITIONS

SOR EORReactor inlet pressure kg/cm2gm 34.3 34.3Reactor inlet temperature ◦C 250 270Reactor outlet temperature ◦C 295 315

NAPTHA SPLITTER UNIT

This section comprises feed surge drum, naptha splitter and associated equipments. This section contain some free water.

Feed: straight run light naptha

Feed is sent at 63.1◦C. Naptha splitter operates at 1.5 / 1.9 kg/cm2gm (top/bottom) pressure. Naptha splitter reboiler works as a thermo siphon reboiler. Reboiler uses MP steam as the reboiling media. The naptha splitter column has a total of 45 trays.

NAPTHA HYDROTREATER UNIT

It is used to produce a clean desulphurised naptha cut to be processed in the isomerisation unit after removal of all impurities which are currently poisons for catalysts.

The reactor inlet temperature is controlled by regulating fuel gas flow rate to the burners. This temperature varies from 250 to 270◦C. First bed of the reactor is filled with (Ni-Mo) HR-195 catalyst and second bed is filled with HR 538.

ISOMERISATION UNIT

Isomerisation is a conversion of low octane straight chain compounds to higher octane branched isomers. The light hydrodesulphurised naptha feed is dried and passed over an activated chloride catalyst. Temperature is maintained at 122-160◦C to minimize hydrocracking.

The purpose of the stabilizer column is to remove light ends from reactor effluent before routing the effluent to deisohexaniser column.

The stabilizer reflux drum vent gas contains H2 and Cl2 which is removed by neutralization with caustic soda in a caustic scrubber.

The unit consists of

Feed driers and H2 driers Reactors Stabilizer Deisohexaniser

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Caustic scrubber Dryer regeneration Chloride injection facility

PROCESS VARIABLES

Reactor temperature Space velocity H2/HC ratio Feed composition Reactor outlet pressure Chloride injection

UTILITIES

Instrument air Utility air Cooling water system Nitrogen Steam Fire water HC closed sewer Electrical equipment Flare system

OIL MOVEMENT AND STORAGE

Oil movement and storage is the branch of production department . Oil India Ltd is the supplier of crude oil to the refinery.

The different finished products of the refinery are LPG, Reformer, Naphtha, Motor Spirit, Motor Spirit (Extra premium), Kerosene, ATF, HSD, HSD (low sulphur), HSD (winter grade), LDO, LSHS, RPC, sulphur , etc.

SECTIONS OF OM&S:

1. Receipt and blending section2. Dispatch section3. LPG section

Dispatches of finished products is done through tank trucks.

Receiving LPG from process unit into bullets and Horton spheres and mounted bullets.

Oil accounts section for accounting of production, stock and dispatches of products.

For all the finished products dispatch from the refinery central excise duty is to be on fort nightly basis.

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Bottom products from different units which are listed below are sent to the storage tanks

CDU, Kerosene treating unit, Delayed coking Unit, Naphtha splitter facilities, LPG recovery unit, ISOSIV Unit, INDMAX Unit, Hydrogen unit, Diesel Hydrotreating Unit, Sulphur Recovery Unit and Nitrogen Unit

FUNCTIONS OF OM&S:

Receipt, storage , accounting, preparation and supply of crude oil to CDU. Receipt and storage of intermediate and finished products from production unit. Blending of products and chemical dosing. Dispatch of finished products. Measurement of Petroleum products – Gauging and sampling. Maintaining central excise formalities. Recovery, Preparation and supply of slop for reprocessing. Filling and dispatch of LPG in bulk dispatches in bullets mounted on trucks.

Finished Products:

LPG Reformer Naphtha Motor Spirit Kerosene ATF (Aviation Turbine Fuel) High Speed diesel oil High Speed diesel oil (low sulphur) High Speed diesel oil (winter) Light diesel oil Raw petroleum coke Needle coke Sulphur

Intermediate Products:

CDU: LPG component, Light naphtha, heavy naphtha, SR kerosene –I , SR Kerosene-II, SR Gas oil, RCO

Naphtha splitter Facilities: Light Naphtha, Reformer Naphtha, Heavy Naphtha DCU: Coker Gasoline, coker kerosene- I, Coker Gas oil, Coker fuel oil, coker residual fuel

oil, RPC LRU: LPG component, refinery fuel gas, stabilized naphtha. ISOSIV Unit: Isosivate (P), Isosivate (N) INDMAX: LPG, INDMAX Gasoline, TCO, CLO Hydrogen Unit: Hydrogen Diesel Hydrotreating Unit: HSD, Kerosene/ATF Sulphur Recovery Unit: Sweet gas, sulphur

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Nitrogen Unit: Nitrogen gas

Chemicals Handled in OM&S:

IPN in HSD, pour point depressor in HSD, MFA and dye.

OM&S division is divided into:

Receipt and blending section Dispatch Section LPG Section

Receipt and Blending section:

This section deals with the following activities

Receipt of crude oil from OIL into crude oil tanks. Preparation of crude oil tanks and handling over the same to CDU. Production of slop tanks for slop processing in coking unit. Receipt of intermediate products from the process unit in tanks. Making finished products as per specifications by blending intermediate streams by inter tank

transfer. Dosing of cetane improver and production in HSD and LDO tanks respectively. Production of daily tank dip statement, 24 hours pumping reports and statements, statement

of finished products dispatched by tank truck, tank wagons for passing on the same to planning and coordination cell of process department.

Recovery of oil from oil separators and blown down system and supply the same to coking unit for slop processing.

Making products ready for pipeline dispatch as per pipeline pumping schedule. Loading of T/W.

Dispatch Section:

Dispatch of finished products through tank trucks. Dispatch of Petroleum coke to India Carbon Ltd(ICL), Guwahati Carbon Ltd (GCL) and

others. Unloading of tank trucks. 3 modes of product movements: tank wagons (rails), tank truck(road), pipeline. Product dispatches by road are ATF, SRN, HSD, LDO, LPG, RPC, SULFUR. Products unloaded by TTL: white oil: reformat, LN (Digboi), coke, Naptha(Digboi), Black

oil: FO, CVFO and LSHS.

LPG Section :

Receiving LPG from process unit into bullets and Horton spheres and mounted bullets. Dispatch of LPG in bulk in bullets mounted on trucks.

BLENDING TECHNIQUES:

1) Flash Point blending

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The flash point of the blend can be computed using flash point blending index chart

Flash point index of the blend IB= VxIx +VyIy

Vx = volume percent of compound X in blend

Ix= Flash point of component X in blend

Vy= volume percent of component y in blend

Iy = Flash point of component Y in blend.

2) Pour Point blending:

The pour point of the blend is obtained by pour point blending index chart

Pour Point index of the blend IB= VxIx +VyIy

Vx = volume percent of compound X in blend

Ix = Pour point of compound X in Blend

Vy= volume percent of component y in blend

Iy = Pour point of component Y in blend.

3) Viscosity Blending:

Kinematic viscosity can be obtained using ‘REFUTAS’ viscosity blending chart

The viscosity function of the blend F(V)B = Wx f(V)x + Wy f(V)y

Wx = weight percent of component X in the blend

Wy = weight percent of component Y in the blend

f(V)x = viscosity function of component X

f(V)y = Viscosity function of component Y

F(V)B = viscosity function of blend V

4) Reid Vapour pressure :

The Reid vapour pressure is determined by vapour pressure index chart

Reid vapour pressure of the blend LB =Vx Lx + Vy Ly

Lx = vapour pressure index of component X

Ly = vapour pressure of component Y

5) Octane Blending :

Octane Blending is done by using LB Value method as

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RN ¿∑k=0

n On BnVnBn Vn

On = RON clear of components

Rn = RON clear of blends

Bn = B values of the compounds

Vn = volume fraction of components

Advantages in Blending Operations:

Uniform Mixing and no layering. Less number of tank requirements Less time required for tank preparation Less number samples for preparation Power saving due to circulation. Less quality give away.

DESCRIPTION OF STORAGE TANKS

FIXED ROOF TANKS

They are used for storing products of low volatility made of vertical cylindrical plates with cone rods fixed over the plate supported by internal truss

Accessories

Man ways for internal access on the shell and roof Clean out man ways for internal cleaning Flame arrays for breather valve combination Datum plate Dip hatch with reference height marked on it Level indicator ( mechanical float type with low accuracy, these are mostly not working

and obsolete) Side entry mixer Stream heating coils with inlet and outlet Jet mixing nozzles for mixing product components Drain nozzles for water cleaning Foam connection nozzles for fire fighting Spiral stairway for climbing for dipping, sampling, inspection, maitanence, etc Temperature gauges (mostly not working)

Products like SKO, HSD, LDO, LSHS and RCO are stored in fixed roof tank.

FLOATING ROOF TANK

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It is used for storing products with higher vapour pressure. The roof resting on the liquid contributes to the minimization of the vapour space between the liquid and the roof bringing about and increased operational safety and minimum vapour loss. It is provided with annular pontoon around the periphery. Foam type seal is used to seal off clearance between rim of the rrof and the tank shell.

Accessories

Man ways for internal access on the shell and roof Vents- rim vent- bleeder-vent gauge hatch with cover and reference height making over it Level indicator Product inlet and outlet nozzles Emergency roof drains roof drain- nozzles foam connection spiral stairway

FLOATING CUM FIXED TANK

It is very much suited for volatile products in which entry of rain water not allowed. Used to storing ATF, reformate and naptha. It have pan type floating roof without drainage system. They have fixed roof having opening to permit plenty of the seals in the floating desk. These tanks are provided with inverted cove type bottom so that accumulated water can be taken out.

Accessories

man ways for internal axis, on the shell, pan and roof vent on roof gauging datum plate level indicator foam connection nozzles inlet and outlet nozzles vertical ladder

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