INTODUCTION:Petroleum is a naturally occurring liquid found in rock formations. It consists of a complex mixture of hydrocarbons of various molecular weights, plus other organic compounds. It is generally accepted that oil, like other fossil fuels, formed from the fossilized remains of dead plants and animals by exposure to heat and pressure in the Earth's crust over hundreds of millions of years. Over time, the decayed residue was covered by layers of mud and silt, sinking further down into the Earth’s crust and preserved there between hot and pressured layers, gradually transforming into oil reservoirs.

The most prolific and dynamic industries of this century are petroleum and petrochemical. In recent decades, the energy industry has experienced significant changes in oil market dynamics, resource availability and technological advancement. However our dependence on fossil fuels as our primary energy source has remained unchanged. It has been estimated that global energy consumption will grow about 50% by the end of the first quarter of the 21 s t century and about 90% of the energy is projected to be supplied by fossil fuels such as oil, natural gas and coal. This significantly reveals the magnitude, economic edifice and necessity of this industry. In this supply and demand scenario, the need is for the development of upgrading processes in order to fulfill market demand as well as to satisfy environmental regulations. From the most primitive methods of extraction and refining of petroleum, great transformation has occurred throughout these years to materialize the modern refinery. INDIAN OIL CORPORATION LTD. (IOCL) has been the pioneer of petroleum refining in India over the last few decades.

IOCL: An Overview

Indian Oil Corporation Ltd. (IOCL) is a major diversified, transnational, integrated energy company, with national leadership and a strong environment conscience, playing a national role in oil security & public distribution. Indian Oil Corporation Ltd. (IndianOil) is India's largest commercial enterprise. Beginning in 1959 as Indian Oil Company Ltd., Indian Oil Corporation Ltd. was formed in 1964

with the merger of Indian Refineries Ltd. (established 1958). IndianOil and its subsidiaries account for 49% petroleum products market share, 40.4% refining capacity and 69% downstream sector pipelines capacity in India.There are ten refineries under Indian Oil Corporation Limited (IOCL) located at

Guwahati (Assam) Barauni (Bihar) Baroda (Gujarat) Haldia (W.B.) Mathura (U.P) Panipat (Hr.) Koyali Paradweep (Orissa) Bongaigaon (Assam) Digboi (Assam)

The combined rate capacity of these ten refineries is 49.30MMPTA. IOC accounts for 42% of India’s total refining capacity.

HALDIA REFINERY (IOCL)

Haldia Refinery, one of the seven operating refineries of Indian Oil, was commissioned in January 1975. It is situated 136 km downstream of Kolkata in the district of Purba Medinipur, West Bengal, near the confluence of river Hooghly and Haldia.

From an original crude oil processing capacity of 2.5 MMTPA, the refinery is operating at a capacity of 5.8 MMTPA at present. Capacity of the refinery was increased to 2.75 MMTPA through de-bottlenecking in 1989-90. Refining capacity was further increased to 3.75 MMTPA in 1997 with the installation/commissioning of second Crude Distillation Unit of 1.0 MMTPA capacity. Petroleum products from this refinery are supplied mainly to eastern India through two product pipelines as well as through barges, tank wagons and tank trucks. Products like MS, HSD and Bitumen are exported from this refinery. Haldia Refinery is the only coastal refinery of the corporation and the lone lube flagship, apart from being the sole producer of Jute Batching Oil. Diesel Hydro

Desulphurization (DHDS) Unit was commissioned in 1999, for production of low Sulphur content (0.25% wt) High Speed Diesel (HSD). With augmentation of this unit, refinery is producing BS-II and Euro-III equivalent HSD (part quantity) at present. Resid Fluidized Catalytic Cracking Unit (RFCCU) was commissioned in 2001 in order to increase the distillate yield of the refinery as well as to meet the growing demand of LPG, MS and HSD. Refinery also produces eco friendly Bitumen emulsion and Microcrystalline Wax. A Catalytic Dewaxing Unit (CIDWU) was installed and commissioned in the year 2003 for production of high quality Lube Oil Base Stocks (LOBS), meeting the API Gr-II standard of LOBS.

Finished products from this refinery cover both fuel oil products as well as lube oil products.

Fuel oil products include:

LPG Naphtha Motor Spirit ( MS ) Mineral Turpentine Oil ( MTO ) Superior Kerosene ( SK ) Aviation Turbine Fuel ( ATF ) Russian Turbine Fuel ( RTF ) High Speed Diesel ( HSD ) Jute Batching Oil ( JBO ) Furnace Oil ( FO )

Lube oil base stocks are: Inter Neutral HVI grades Heavy Neutral HVI grades Bright Neutral HVI grades

Beside the above, Slack Wax, Carbon Black Feed Stock (CBFS), Bitumen and Sulphur are the other products of this refinery.

There are four main units in this refinery.

1. FUEL OIL BLOCK (FOB)

2. LUBE OIL BLOCK (LOB)

3. DIESEL HYDRO-DE SULPHURISATION BLOCK (DHDS)

4. OIL MOVEMENT AND STORAGE (OM&S) BLOCK

Two new units namely Sulphur Recovery Unit (SRU) and Resid Fludised Catalytic Cracking Unit (RFCCU) have been installed and are operating under DHDS BLOCK .

Haldia Refinery also possesses a captive Thermal Power Station (TPS), also a Quality Control (QC) and Technical Services department.

Block Flow Diagram of Haldia Refinery

Crude

CDU

1

CDU

2

Fuel GasLPG

SR Naph

Kero Cut

St.Run G.O

JBO

RCO

ATU

Desulphurised Fuel Gas

SRU SulphurLPGNaphtha

90 – 140°CCRU MS( 3 GRADES)

C5 – 90°C

KHDSMTORTF/ATFKerosene

DHDS HSD (2 GRADES)

HGU

H2

JBO (2 GRADES)

VDU1

VDU2

IFO

GOSO

LO / IO / HO

SR

PDA

DAO

FEUNMP

SDU HFU70 N GR-II150 N GR-I / II500 N GR-I / II850 N150 BS GR-I/II

FCCU

Ext.

S.Wax

LO

Asp.

VBU FO (2 GRADES)

BTU Bitumen(3GRADES)Bit Eml.

CBFS

MCW MCW

CDWU

Fig: 01

FIRE & SAFETY:FIRE :

Fire is a rapid , self sustained oxidation process accompanying by the release of energy in the form of heat and light of varying intensity.

Fire results from the combustion of fuel, heat & oxygen.

Fire triangle:

Three elements are necessary for initiation of fire:

1. Fuel in the form of vapor, liquid or solid.

2. A source of ignition is sufficient to initiate and propagate the fire.

3. Oxygen is sufficient proportion to form a combustible mixture.

Combustion process is observed in two modes:

For flaming combustion to occur, solid or liquid fuel must be converted into vapor which then mixes with air and reacts with oxygen.

Smoldering combustion, on the other hand , involves a reaction between oxygen and the surface of the fuel: this a complex process and in general occurs with solid fuels.

Fig-02

FIRE TRIANGLE

OXYGEN HEAT

FUEL

EXTINGUISGING MEDIA: Foam, carbon-dioxide, dry chemical powder, water.

SAFETY:

The main & utmost thing , which is to be known to all is the safety during working in an industry. A person in an industry should well aware about the safety rules to keep him safe & others from any unwanted mishap.

The main principle points which one should keep in mind are:

1. One should ware safety helmet to avoid injury.

2. The second important thing is the safety shoes.

3. The third important thing is that one should use Safety jackets.

4. When a person is poling heavy material he should wear PVC gloves.

These are the major things which one should maintain during work. But there are many small things which should be maintained properly.

a. A person should wear safety goggles during welding.

b. When a person is working at a high construction He should wear safety belts.

c. A person should use a ladder having rubber covered legs, neither can he slip.

d. When a person is working in a chemically hazard place he should use gas mask.

e. One should keep safe distance from furnace & should operate it very carefully.

f. Workers should keep in mind that not to work near inflammable gases.

g. The cylinder should store in proper manner &in proper places.

h. One should always keep safe distance from pit.

i. The fire extinguisher should keep in proper places & after work workers should keep it back in the proper place.

j. If any problem occur regarding safety workers should immediately inform his higher officers.

These are some safety associated rule which one should keep in mind.

But these rule do not work until a person has a sense of safety.

Another main important thing is workers should know how to fight with fire. To know this we have to know first what fire is.

In industrial language fire is nothing but a combination of heat, inflammable material, oxygen, free radicals.

This is called fire tetrahedron. If on of the side is removed then it can be controlled.

[Note: During fight with fire with CO2 one should always about the direction of air flow, because one may feint if he is in wrong direction.]

FUEL OIL BLOCK (FOB):It was commissioned in August 1974, originally designed for processing Light Iranian Aghajari crude but presently crudes like Arab Mix (lube bearing) and Dubai crude (non-lube bearing)( 60:40 wt ratio) are processed. The capacity has been increased from 2.5 MMPTA to 6.0 MMPTA.

Fuel oil block produces fuel oil from crude and this block consist of eight subunits as given below:

CRUDE DISTILLATION UNIT (Unit 11 & 16)1. Prefractionator section2. Topping Section: Atmospheric distillation unit (ADU)3. Naphtha stabilization unit4. Naphtha re distillation unit

GAS PLANT (Unit 12)1. De-ethaniser2. Amine-washing of LPG3. De-propaniser

MEROX UNIT (Unit 13)1. LPG extractive merox2. ATF/ Gasoline sweetening merox

NAPTHA HYDRO DESULPHURIZATION UNIT-(NHDT) (Unit 21)

CATALYTIC REFORMING UNIT (Unit 22)

KHDS UNIT (Kero Hydro Desulphurization Unit)( Unit 23)

CRUDE DISTILLATION UNIT (Unit 11 & 16):Flow sheet (CDU):Fig-03

Crude Pre heat exchanger

Crude oil120-1300C

DesalterCrude oil

95% desalted

2nd heat exchanger

Heat Exchanger

Furnace

Kerosene storage

JBO Storage

HSD storage

KHDS (UNIT _23)

Pref-ract-iona-tor

Crude at 180-200oC

O/H gasoline IBP-140oC

Pf crude Crude oil 260-265oC

C

Total gasoline IBP- 140oC

Heavy naphtha 110-120oC

Kerosene/ATF

140-271oC/140-240oC

High speed diesel (271-320oC)

Jute batching oil 320-360oC ( JBOC)

Crude oil 350-360oC

320-380oC (JBOP)

S

Fig-04

Fig-05

CStabilizing column

Gas plant unit UNIT-12

D

Naptha redistilla-tion column

Caustic wash Naphtha

storage

Gasoline merox unit

Catalytic reforming unit (unit22)

DDe - ethanizer

Fuel gas system

DEA WashLPG MEROX treatment plant

Caustic separation unit

De- Propanizer

Motor spirit blending

LPG storage

VB Gasoline

Propane Deasphalt unit

Total gasoline IBP-140oC

very low boiling Hydrocarbon( C3-C4)

H2S

C5-1400C cuts

C5-90oC boiling hydrocarbon cuts

Excess ( 90oC-140oC) boiling hydrocarbon cuts

H2S+Aminemercaptan

Mercaptan free LPG

Propane

butane

Octane improvement

90-140oC boiling hydrocarbon cuts

PRINCIPLE OF OPERATION:

Before feeding to the desalter, crude oil is heated to 120oC-130oC in the first set of pre heat exchangers. In the desalter, the crude is desalted to an extent of 95%. Crude is then heated to 260oC-265oC in the second set of heat exchangers. It is thereafter heated to 350-360oC in furnace and thereafter fractionated in Atmospheric Distillation Unit to the following streams having separate B.P. ranges.

STREAMS APPROX. B.P. RANGE ( OC )

Total Gasoline IBP-140

Heavy Naphtha 140-160

Kerosene/ATF 160-271 160-240

HSD 271-320 240-320

Jute Batching Oil JBO (c) / JBO (p) 320-360 320-330

Reduced Crude 360+ 385+ >400+

OVERHEAD (IBP-140 O C CUT) REFINING

In the CDU, IBP-140OC cut is fractionated into two products in stabilization column:

Overhead product: very low boiling hydrocarbons up to butane (C4) which is routed to the gas plant

Bottom product: C5 –140OC cut which is sent to the to Naphtha re-distillation columns.

z

In GAS PLANT overhead product from stabilizer column is fed to the de-ethaniser. Overhead stream containing ethane is sent to fuel gas system of refinery, while

bottom product is amine washed for H2S removal (crudes being processed now contain low H2S in the LPG range), hence amine washing is not required.

After amine washing, this stream is sent to Unit-13 i.e. Merox treatment plant where mercaptan is removed. If the crude contains small amount of H2S column 12C02 is bypassed as in that case amine washing is not essential.

a) In MEROX TREATMENT UNIT ( Unit-13 ), light petroleum gas ( LPG ) obtained from gas plant is caustic washed and sent to LPG extractor (13C01) where counter-current flow is observed . It is then sent to LPG storage. A part of merox treated product is fractionated in depropaniser column (12C07) to produce propane according to the requirement of Propane deasphalting unit of Lube Oil Block (LOB). There is provision for blending bottom product (C4) with Motor sprit (MS).

SPLITTING OF C5-140OC CUT: C5-140 OC cut is fractionated in Naphtha Redistillation Unit (11C05) into two streams.

i) C5 – 90OC stream is routed to unit-14 for caustic wash and removal of H2S and finally sent to naphtha storage.

ii) 90OC-140OC cut from bottom of 11C05 is used as fed stack for catalytic reforming unit (unit 21& 22). Excess amount is sent to unit-14 inlet to mix with C5-90OC cut.

b) PRODUCTION OF KEROSENE/ATF/MTO/RTF: These products are obtained from kerosene draw-off and sent to intermediate storage tanks for subsequent treatment in KERO-HDS unit (unit-13), which will be described in relevant section. In kero-redistillation column 11C06, top product is routed to ATF or MTO tanks and the bottom product is sent to SK or HSD pool. Dosing i.e. addition of external material is an important part of this present section.

REDUCED CRUDE UTILIZATION

Reduced crude is sent to VDU i.e. vacuum distillation unit (unit-31) for further fractionation into lube oil distillation cuts.

PROCESS DESCRIPTION

a) CRUDE OIL PUMPING : From storage crude is pumped to first set of heat exchanger by crude feed pumps 11P02A and 11P02B before desalting . A pressure switch to start up the spare pump is provided in case of low discharge pressure of the running up.

b) PREHEATING OF CRUDE BEFORE DESALTER: The pumped crude is taken to first set of heat exchanger for preheating where they get warmed by exchanging heat with following streams:

Top circulating reflux in 11C01 SR gas oil in 11E04A & 11E04B Reduced crude in 11E03A & 11E03B Kerosene in 11E02

c) DESALTING OF CRUDE: An oil-water emulsion is prepared by adding water either at the inlet of 11E01 or at the upstream of de-Salter main valve (11PIDC06) or at both places by using pumps.After proper mixing, the crude experiences an alternating electrostatic field in the de-Salter. As a consequence, brine is settled at the bottom and crude oil floats above brine section. This brine water from bottom of 11B02 is sent to sour-stripper whereas desalted crude from 11B02 top are pumped by 11P02A, 11P02B, 11P02C which are booster pumps in nature.

d) PRETREATMENT OF CRUDE AFTER DESALTING: After desalting operation, crude is again preheated to around 265OC in a second set of preheat exchangers. In this case, crude gets warmed by the exchange of heat with the following:

Kero CR reflux in 11E05A/B/C JBO in 11E06 RCO in 11E07A/B/C Gas oil (diesel) in 11E08A/B

Diesel CR reflux in 11E09A/B/C/D RCO in 11E10A/B/C/D/E

e) HEATING IN THE FURNACE: Crude oil after preheating is heated in the furnace 11F01. This particular furnace has four passes in each of which flow is controlled by individual pass control valves numbered 11FRCV10/11/12/13.In the furnace, heating of oil takes place in convection zone and radiation zone where partial vaporization also occurs. It is then sent to flush zone of the column under temperature control.

f) FRACTIONATION: Here crude oil is fractionated into different streams, description of which is given below:

1) Top circulating reflux: It is withdrawn from 39th tray at about 160OC and pumped by the pumps 11P08A/B. This reflux is cooled to 90OC in 11E01 by exchanging heat with crude oil.

2) Overhead steam: Gasoline vapor and stream from the top of the column are condensed in 11E22A/B/C. Temperature of 125OC is maintained at the top by means of external reflux. Condensed gasoline vapors and water goes to accumulator 11b01 where 1.8-2.8 kg/cm2 pressure is maintained.

3. Kerosene circulating reflux: From tray no.28, Kero-CR is drawn off by pumps 11P09A/B Heat recovery is done by method of reflux in naphtha redistillation reboiler . 11E12 under temperature control and in the exchanger 11E05A/B/C with crude oil. Reflux is then returned to column under flow control.

4. Kerosene drawn off: Kerosene drawn off from 27th tray is sent under level control to the stripper 11C02A. Lighter ends are stripped off by steam. The kerosene from stripper bottom is sent to storage under flow control after exchanging heat with crude oil in 11E02 and by water in cooler 11E18.

5. Diesel circulating reflux: From 19th tray, Diesel CR is withdrawn and pumped by 11P10 or 11PO93. Heat recovery from C.R. is performed by heating stabilizer bottom in the stabilizer reboiler 11E11 under temperature control and by heating crude oil in exchangers’ 11E09A/B/C/D.

6. Diesel drawn off: Diesel oil (gas oil) is drawn off from 19th tray in which level is controlled by 11LC14 and is sent to the stripper 11CO2B. Lighter ends are stripped off by steam which returns to column.

7. Heavy naphtha drawn off: Heavy naphtha is withdrawn from 35th tray . This is sent to stripper 11CO2D under level control 11LIC01. Light ends are stripped off by steam. H.C. vapor and steam return to the column 11C01 and H.N. (heavy naphtha) coming from stripper bottom is pumped by 11P25A/B and ultimately sent to HSD unit or storage.

8. JBO drawn off: From 12th tray JBO is drawn off and sent to stripper 11C02 from bottom of which JBO is pumped by 11P06A/B. heat is recovered from exchanger 11E06 and 11E16. JBO is then sent to storage after cooling in water cooler 11E20.

9. Reduced crude oil: Bottom of column 11C01 is stripped for removal of lighter ends and Reduced Crude Oil (R.C.O.) is cooled by exchanging heat with crude oil in exchanger 11E10A/B/C/D/E/F, 11E07A/B/C/D and 11E03A/B & is sent directly as feed to VDU at the temperature of about 110OC.

GAS PLANT OF FOB (UNIT-12):PURPOSE: The function of gas plant is to remove the lighter ends such as methane, ethane from LPG in de ethaniser and to scrub LPG with amine solution to remove H2S before feeding of LPG to de propaniser.

FEED: Butane (C4 from 11C04)

Propane (purity 97.5%)

Butane composition (C4 77 wt% & C5 1.1%)

LPG vapors

PROCESS DESCRIPTION

There are three sections in this plant:

1. De-ethaniser 2. Amine wash column 3. depropaniser

De-ethaniser: Here feed is discharged of stabiliser overhead pump, which after being heated by exchangers enters the 16th tray of de-ethaniser column. (Total no. of trays in this column are 24).

Amine wash column: In this column H2S is removed by washing with lean amine (DEA) solution. LPG from the column bottom goes through feed heater.

De-propaniser: From LPG merox unit the product LPG coming out is splitted out into three sections.

a. Major part to LPG storage.

b. A part to LPG vaporizer.

c. Third part to depropaniser for separation of propane and butane.

Feed is heated by depropaniser bottom in heat exchanger and enters the 14 th tray of column. Overhead vapor is controlled by a pressure-controller. The column bottom is reboiled by steam in a reboiler in which butane is the main component. The bottom steam is cooled in water coolers and sent to LPG storage.

MEROX UNIT OF FOB ( UNIT-13):PURPOSE: LPG contains mercaptans, which are detrimental to the LPG burners. Therefore it is necessary to remove mercaptans from LPG. This is done by MEROX process. It involves the catalytic oxidation of mercaptans to harmless disulphide. Chemical reactions involved in this process are:

RSH (mercaptan) + NaOH = NaSR + H2O

2NaSR + H2O + 1/2 O2 = 2 NaOH + R-S-S-R

(Sodium mercaptide) (Disulphide)

SPECIFICATION OF THE FEED STOCK

Steam Sp.gravity

( at 60OF )

Total Sulphur

( wt. % maxim)

Mercaptan Sulphur

(wt % maxim)

V.B. gasoline 0.740 1.0 0.50

S.R. gasoline 0.671 1.0 0.85

Caustic Regeneration: Caustic from merox unit is heated in a double pipe heat exchanger and enters the oxidizer vessel where mercaptans get oxidized to disulphides and mixture goes to disulphide separators where the disulphide oil is separated as two layers. Regenerated caustic is sent for recirculation.

Propane Production: a part of merox treated LPG is fractionated in De-propaniser column of gas plant to produce propane. Bottom product is send to LPG.

Splitting of C5-1400C cut: In naphtha redistillation column this portion is fractionated into C5-90 and 90-140from overhead is routed for caustic wash to remove H2S and then sent to naphtha storage.90-140 cut from bottom is used as feed stock for CRU unit.

Amine regeneration: Objective of this unit is to remove H2S from H2S rich amine received from DEA wash column from gas plant. From Amine absorber of lube hydro finishing unit and fuel gas amine absorption unit H2S is stripped off from amine with the help of steam. Lean amine after removal is recirculated to gas plant, fuel gas amine absorption and LUBE HUF, stripped H2S is sent to sulphur recovery unit for sulphur production.

NAPTHA HYDROTREATMENT UNIT (UNIT 21):PURPOSE: Pretreatment of naphtha is a hydro treatment process in which specific cut is treated to remove undesirable materials prior it goes to Reforming Unit as feed.Raw naphtha cut cannot be fed into the reformer directly. Chemicals like; Sulphur, Nitrogen, Water, Halogens, Olefins and Metals act as poison to reformer

catalyst. The removal of these poisonous materials is done by a hydro treatment process, which is called Pretreatment of Naphtha or naphtha-HSD process.

THEORY OF HYDROTREATMENT:

SULPHUR COMPOUNDS: Removal of sulphur compounds is essential to avoid poisoning of catalyst. Beside this sulphur removal helps to improve the other quantities of gasoline like lead susceptibility, color stability, corrosion rates etc.Different types of S-compounds e.g. mercaptans, sulfides, thiophenes etc. are also present in crude. In operating condition and in presence of catalyst the S-compound reacts with H2 and form H2S.

REACTIONS:

R-SH (Thiol) + H2 = R-H + H2S

R-S-S-R ( Disulfides) + 3H2 = 2R-H + 2H2S

R-S-R’ ( Sulfides) + 2H2 = R-H + R'H + H2S

The allowable concentration of sulphur in reformer feed is preferably 10 ppm.

NITROGEN COMPOUNDS: Though possibility of presence of nitrogenous compounds in naphtha is very low but basic and non-basic types of compounds are found. .

Basic type is pyridine and quinoline and non-basic type is car bozo, indoles and pyrroles.

Pyridine + 5H2 = C2H6 + C3H 8 + NH3 Indole + 4H2 = C5H12 + NH3

The allowable limit of nitrogen in reformer feed is less than 1 ppm.

METAL COMPOUNDS: These may be present as contaminants of Na,As, Pb, Ni,Cu etc. Allowable limit is As: 1 ppb ( Pb + Cu ) : 1ppb

WATER: As water is also a poison for reforming catalyst, its content should be within specified limit in reforming feed.

OXYGEN COMPOUNDS: Sometimes phenolic compounds are present in naphtha and are removed as water. Maximum allowable limit of water is 20 ppm.

PROCESS DESCRIPTION

90-140 cut naphtha is taken from storage by pumping and mixed with hydrogen make-up gas from CRU recycle compressor discharge.The mixture is then heated in reactor where in presence of Co-Mo catalyst S, N etc are converted to H2S, NH3

and olefins get saturated and deposited on metal catalyst. Catalyst is regenerated on furnace and reactor effluent after partly condensation during cooling, enter the separator drum .The gas from the top is recycled by reciprocating compressor. The liquid from the bottom is taken to stripper. Part of stripper bottom is sent to CRU whereas the sour gas leaving the overhead is sent to fuel gas system.

CATALYTIC REFORMING UNIT (UNIT-22 ):Petroleum naphtha consists mainly of paraffinic, napthenic and aromatic hydrocarbons. Their relative amounts depend on the crude origin. Aromatic content of crude is around 20.0% of total hydrocarbons. Naphthenic hydrocarbons consist of mainly cyclopentane, cyclohexane and their relative amount is also dependent on crude origin.

Among hydrocarbons the sequence of increasing octane nos. is as follows:

Paraffins < Iso-paraffins< Olefins< Napthenes< Aromatics

PURPOSE: Prevention of knocking under high compression ratios is achieved by increase in the octane value of the fuel in CRU. Upgrading low octane gasolines catalytically is known as catalytic reforming. The octane rating improvement is accomplished chiefly by reorienting or reforming the low octane components into high octane components. Much desired reformate is influenced by the characteristics of feed stock and catalyst.

PROCESS DESCRIPTION:

In CRU main categories of reactions are as follows:

Aromatization of napthenes and paraffin

Isomerisation of napthenes and paraffin

Hydro cracking of paraffin

Hydrogenation of paraffin

Olefinic hydrogenation

Other secondary reactions as demethanation, hydrosulphurisation etc.

Main types of reactions are described below.

AROMATISATION: This reaction is very fast and highly endothermic

( H = + 50 kcal/mole).In this reaction ,Octane No. increases and rate of this type of this type of reaction increases with increasing number of C atoms.

Example: n-Hexane Benzene

This type of reactions produces Hydrogen

ISOMERISATION: In this type of reactions hydrocarbons isomerise to produce higher octane no. hydrocarbons.

Example: Diethyl Cyclopentane Methyl Cyclohexane

HYDROCRACKING: In this type of reactions, napthenic and paraffinic hydrocarbons are broken and olefins are formed. When partial pressure of hydrogen is high, nearly all olefins become saturated by reaction with hydrogen.

Example: C10H 22 + H2 Methyl Pentane + C4H10

DEHYDROCYCLISATION: In this set of reaction, cyclisation of saturated open chain hydrocarbons occurs by removal of hydrogen.

Example: C7H6 Methyl Cyclohexane + H2

KERO HYDRO DE-SULPHURIZATION UNIT (UNIT23):FEED:

The unit processes four raw kerosene distillate cuts produced from Atmospheric Distillation Unit (ADU) of light Iranian Export Crude Oil.

1. TBP Fraction 140 – 271 OC

2. TBP Fraction 140 – 247 OC

3. TBP Fraction 140 – 240 OC

4. Mixture of TBP Fraction 140 – 271OC & TBP Fraction 170 – 271OC

FEED SPECIFICATIONS

Raw kerosene distillates are available from storage at the following conditions:

Temperature: 40 OC

Pressure: 1 kg/cm2 abs.

PRODUCT:

The unit can produce three different qualities of kerosene:

Superior Kerosene ( SK ) Mineral Terpentine Oil ( MTO ) Aviation Turbine Fuel ( ATF )

PROCESS DESCRIPTION:

FEED AND GAS PREHEATING SECTION

Raw kerosene feed from the storage is taken to the unit by pump 23P01A/B .The feed is subsequently blended with a mixture of recycle and make up gases available from discharge of the compressor 23K01A/B.Both liquid feed and gas stream are heated in heat exchanger 23E02A/B/C/D in the shell side while the hot reactor-effluent passes through the tube-side. Hot mixture of liquid and gas from 23E02A/B/C/D is taken to the furnace.

FURNACE AND REACTOR SECTION

Preheated kerosene and hydrogen are brought to the reaction temperature in the furnace 23F01.The heated feed then flows across a reactor 23R01 fitted with cobalt-molybdenum catalyst where the desulphurization reaction takes place. In reactor there is a distributor and 39 baskets in upper part of its section. During the catalyst regulation service air is introduced at the furnace inlet and at the same time an adequate quantity of medium pressure steam is also introduced. During start-up nitrogen is introduced to the reaction inlet.

EFFLUENT COOLING SECTION

The effluent from reactor is cooled and partially condensed in a series of heat exchangers. Finally, this effluent is sent to the separator drum 23B01.

The reactor effluent is split into two phases in the separator drum 23B01.

I. The liquid phase is sent into stripper column 23C01

II. One part of vapor is sent to Hydro finishing Unit of Lube Oil block. Another part is recycled along with makeup gas and compressed by two parallel reciprocating compressor 23K01A/B.

STRIPPING SECTION

The liquid from the separator drum is reheated in exchanger 23E04A/B and fed into stripper column 23C01.A part of the stripper bottom is reboiled in the heat exchanger 23e01 on the shell side. The entire stripper bottom is pumped by 23P03, cooled and sent to storage as finished product.The stripper overhead vapors after leaving the top of column 23C01,are first cooled and partially condensed in the water cooler 23B02 . The liquid distillate is returned as reflux by pump 23P02 to the top of stripper column 23C01.During Kero/MTO run total liquid distillate is refluxed. However during ATF run, excess liquid distillate is sent to overhead drum 11B01 of Atmospheric distillation Unit for recovery of light distillates .There is a provision for rooting this light distillate to storage tank.

RECOMPRESSING SECTION

The gas from reflux drum 23B02 goes via 23B02A to the first stage of the two parallel reciprocating compressors.

The gas, after cooling on water cooler is mixed with the steam from LOB before sending to the knockout drum 23B04. The condensed hydrocarbons from the drum are sent to stripper column. The vapor from the knockout drum are compressed in the second set of compressors and cooled in a water cooler. The vapor separated liquid hydrocarbons are sent to fuel gas system or amine unit. The condensed hydrocarbons are drained manually.

DHDS BLOCK:RESID FLUIDISED CATALYTIC CRACKING UNIT(unit 17/18/19):Fluid Catalytic Cracking Unit consists of the following sections:

Feed Preheat Section Reactor / Regenerator Section Flue Gas Section Catalyst handling section Main Fractionators Section Product Recovery Section Amine Treating Section

The main products coming out from FCCU are as follows:

Fuel gas L P G Gasoline

TCO (Total cycle oil) CLO (Clarified oil)

FEED PREHEAT SECTION:

Cold feed from FCCU Feed tank and feed from process units are combined and received to feed surge drum. Cold feed enters feed surge drum on level control and hot feed enters surge drum on flow control. A water boot on the drum allows for manual draining of any water, which may accumulate during start up upset conditions. Fresh feed is pumped by fresh feed pump to the feed preheat circuit. The feed preheat circuit comprises exchangers. The fresh feed is heated in these exchangers against HN lean oil, HCN, LCO, LCO pump around, HCO pump around and slurry pump around. The final feed preheat is accomplished in the fire heater before being send to the riser feed nozzles of the reactor.

REACTOR/REGENERATOR SECTION:The preheat feed is finely atomized and mixed with dispersion steam (MP steam) in feed injectors mixing chamber and injected into the reactor riser. Four numbers of feed injectors have been provided. Above the feed injectors, two numbers recycle oil injectors; one recycle slurry injector has been provided.The fine atomized feed contact hot regenerate catalyst and vaporizes immediately. The vaporized oil mixes with the catalyst particles and cracks into lighter, more valuable products. The heat required for the reaction is supplied by hot regenerated catalyst. The residence time in the riser is approximately 2.0 seconds at design conditions. Riser outlet temperature (ROT) is regulated by controlling the flow of regenerated catalyst which is admitted through the regenerated catalyst slide valve (RCSV).Catalyst is quickly separated from hydrocarbon/steam vapors in the initial separator, which is located at the end of the riser. Catalyst separation is necessary to avoid any undesirable continuation of reaction, which produces light gases at the expense of liquid products (gasoline and LCO).After exiting the initial separator the vapors pass through two high efficiency single state reactor cyclones to complete the catalyst separation from hydrocarbon products, thus minimizing the amount of catalyst lost to product. The reactor product vapors, containing a small amount of inert and steam, flow to the quench zone of main fractionators. Small quantities of catalyst contained in the product vapors are carried away from the fractionator’s slurry circuit.

Catalyst exiting the initial separator is pre-stripped with MP steam to reduce coke yield. The catalyst is further stripped by steam from main stream ring as the

catalyst flows down the stripper. A series of baffles enhance the contacting the steam and spent catalyst. The stripper used is fluidized by the stripping steam, which displaces the volatile hydrocarbon contained on and in the catalyst particles before they enter the first stage regenerator.

The stripped spent catalyst flows down the catalyst standpipe and through the spent catalyst slide valve (SCSV). This valve controls the stripper’s levels by regulating the flow of spent catalyst from the stripper.Spent catalyst flows to the first stage regenerator through a distributor, which drops catalyst on the regenerator catalyst bed. 60-70% of the coke is burnt in first stage regenerator and remainder in second stage regenerator.

Blower driven by steam turbine supplies combustion air for combustion process in regenerators. Atmospheric air is introduced to the air blower and discharged to first stage regenerator risers, 2nd stage regenerator rings; lift air, withdrawal-well ring, spent catalyst distributor sparer.

The hot regenerated catalyst flows from the second stage regenerator through a lateral to the withdrawal well (WDW). From WDW, catalyst flows down the 45 degree slanted wyes section to the reactor riser base where catalyst begins the upward flow toward the fresh feed injector.

First stage regenerator primary cyclones and first stage regenerator secondary cyclones separate the entrained catalyst from the flue gas exiting the first stage regenerator. Similarly second stage regenerator primary cyclones and second stage regenerator secondary cyclones separate the entrained catalyst from the flue gas exiting the second stage regenerator. Flue gas exiting both regenerators’ flow to the flue gas section.

FLUE GAS SECTION:

The flue gas from the first stage regenerator passes through a double disc slide valve, used for controlling the differential pressure between the first and second stage regenerators. Immediately downstream of the first stage regenerator slide valve is an orifice chamber designed to reduce the flue gas pressure.

The carbon monoxide rich flue gas exits the orifice chamber and enters to CO Incinerator to convert the carbon monoxide to carbon dioxide to comply with environmental emission requirements.

Hot CO Incinerator effluent combines with the second stage regenerator flue gas. This combined flue gas passes through the Flue Gas Cooler where the flue gas thermal energy is recovered by generating medium high-pressure superheated steam. The cooled flue gases flow to flue gas scrubber, which further reduces the catalyst fines and Sox in the flue gases. The off gases from the flue gas scrubber flow to a stack..

CATALYST HANDLING SECTION:

The catalyst handling section includes hoppers for storage and transfer of fresh, equilibrium and spent catalyst. The spent catalyst hopper is sized to hold the complete FCC circulating inventory plus 15 days of maximum catalyst withdrawal from regenerators. The equilibrium catalyst hopper is designed for mild temperature and should not hold hot catalyst.

Pressurized air is supplied from either the blower air or plant air systems. Hopper pressurization is required prior to loading of catalyst into the FCC.A steam ejector is provided for reducing the hopper pressure. The hopper pressure should be lowered using loading fresh catalyst and equilibrium catalyst into their respective hoppers. Blower air is used as the motive fluid to transport the catalyst between hoppers and regenerators. Batch loaders are used automatically to add fresh catalyst as well as equilibrium catalyst at desired rate.Air purgers must be maintained in the catalyst in the catalyst transfer line at all times to prevent hot catalyst from flowing back towards the loader.

Provisions are made for the loading and unloading of catalyst trucks/containers. Spent catalyst can be unloaded from the spent hopper into the trucks. The system is designed for great flexibility however the fresh and equilibrium catalyst hoppers are not designed to contain hot catalyst directly from regenerators.

MAIN FRACTIONATOR SECTION:

The reactor effluent comprised of cracked hydrocarbon vapors, steam and inert gases, enters the fractionators at the bottom of the quench section. In this section of the fractionators the superheated cracked vapors’ and inert are cooled and the bottom product is condensed.

The small amount of entrained catalyst in the cracked vapors is scrubbed out and drops to the bottom with the condensed product. The slurry pump around and

decanted oil product are withdrawn from the bottom of the fractionators and pumped by slurry pumped around pump through the fresh feed preheat exchangers steam generators and the boiler feed water preheater.

Entrained catalyst is removed from the decanted oil in the slurry oil filter.

The fractionators bottom liquid has a tendency for coking. Coking is promoted by high temperature and long residence time. To maintain the fractionator bottoms temperature at 360OC, a cold quench stream from the slurry pump around system is directly mixed, under temperature control at the slurry pump section, with the fractionator bottom liquid. Furthermore, steam is injected into the bottom liquid to counteract coke formation and to maintain catalyst and coke particles in suspension.In the fractionator the (Heavy Cycle Oil) HCO pump around is used to cool further the cracked vapors from the slurry section.

Heavy cycle oil (HCO) pump around, recycle and reflux are withdrawn from a total draw chimney tray. The reflux is pumped back to the wash tray below the HCO chimney tray on chimney tray level control. The HCO pump around circuit is utilised to preheat boiler feed water and to produce MHP steam in a steam generator.The HCO recycle flows to the HCO stripper on stripper level control where it is stripped of light components by the use of steam. Good stripping ensures a minimum of light components, which can crack into undesirable products once the HCO is reintroduced into the riser. The light cycle oil (LCO) pump around and product are withdrawn from a partial draw off chimney tray. The LCO PA is cooled down against the stripper reboiler, fresh feed, boiler feed water, demineralised water and finally air cooler before returning to the fractionator.The cooled net LCO product is blended with HCN to produce the TCO product. A portion of the cooled LCO stream is used for gland and flushing oil.

Sponge absorber lean oil is drawn out of the fractionator from a partial draw off chimney tray. The rich oil from the bottom of the absorber is then returned to the fractionator to recover the light ends absorbed in the sponge absorber.

The total fractionator overhead vapour consists of HCN, LCN, lighter hydrocarbons, steam and inert gases from the reactor plus the tower top reflux.

PRODUCT RECOVERY SECTION:

Two-stage centrifugal compressor compresses the wet gas from the fractionator overhead receiver. The hot gases discharged from the first stage partially

condensed against cooling water before entering the compressor inter stage drum.. The uncondensed vapour, the medium pressure distillate and the sour water are separated in this drum.

The uncondensed vapours are compressed by the second stage of the compressor. This & medium pressure distillate combined steam is then mixed with the rich oil from the primary absorber and entering the high-pressure separator. The uncondensed vapours are routed to the primary absorber for C3and C4 recovery.The primary absorber recovers 95%of the propane/propylene and 97%of the C4’s from the reactor effluent. The lean oils used for absorption.

Absorption is a physical mass transfer operation characterised by its exothermic nature, i.e. absorption of C3’s into the naphtha recycle increase the temperature of the resulting rich liquid.The unabsorbed vapors and the supplemental lean oil are separated in the absorber reflux drum. The unabsorbed vapors are routed to the sponge absorber.The rich oil from the bottom of the primary absorber flows to the high-pressure separator.The sponge absorber is a tower where essentially all of the C4’s and C3’s entrained in the absorber gas from the primary absorber are recovered. The lean oil used for absorption is cooled heavy naphtha from the fractionator. The rich sponge oil leaves the bottom of the sponge absorber is routed back to the fractionator for recovery of the light ends (C4’s and C5’s). The off gas from the sponge absorber flows to the amine unit for H2S and CO2 removal. The stripper is a tower to remove the inerts, C2’s and lighter hydrocarbons from the liquefied C3+ hydrocarbon stream to control the vapour pressure of the recovered LPG product downstream.

The stripper overhead vapours reconnected with the wet gas compressor second stage effluent, the compressor inter stage condensate, and the rich oil from the absorber. The stripper bottom stream flows to the debutanizer tower. This stream is heated and partially vapourised against debutanizer bottoms before entering the debutanizer. The debutanizer tower produces a totally condensed overhead mixed C3/C4 LPG product and a bottom C5+ product.The debutanizer overhead product is totally condensed against air cooler in the overhead. LPG product is pumped on flow control reset by reflux drum level control after being cooled against cooling water into battery limit temperature. Exchanging heat against the debutanizer feed cools the total debutanizer bottoms stream, comprised of the net naphtha product and supplemental lean oil recycle. The naphtha product is fed to the naphtha splitter supplemental lean oil recycle stream is further cooled & combined with the absorber overhead vapors. The debutanizer bottoms

product flashes before entering the naphtha splitter tower to separate the net naphtha product in the total feed into a light naphtha product (LCN) recovered overhead and a heavy naphtha product (HCN) from the bottom. The light naphtha is the overhead product. LCN product is cooled against cooling water and sent to Merox treating unit.

AMINE TREATING SECTION:

The absorber gas from the sponge absorber contains the majority of the H2S resulting from the cracking reaction plus all the CO2 entrained the regenerated catalyst as inert. These two acid gases are removed from the absorber gas before it is sent to the refinery fuel gas pool. Acid gas removal from the absorber gas is accomplished by contacting the sour gas with a 25wt% solution of diethanol-amine (DEA) in a absorption tower. The sponge absorber sour gas enters the sour gas KO (knock out) drum to separate any entrained liquid. Condensed/entrained hydrocarbon liquid is routed back to the fractionators on drum level control. The sour gas flows into the amine absorption column where it is contacted with the DEA solution for H2S and CO2 removal. The lean DEA solution feeds to top tray of the absorption column on flow control. The sweet gas leaves the top of the column, flows through the wet gas KO drum and then is routed to battery limits.The rich DEA from the amine absorption column and the condensed liquid from the sweet gas KO drum are all routed to the rich amine flash drum.. Any entrained hydrocarbons are flashed and sent to the CO incinerator to mix with the fuel gas stream. Wash water is fed to the top section of the flash drum to wash off any entrained amine solution in the flashed gas.The amine regenerator is to strip out the H2S and CO2 from the rich DEA solution. Stripped water is used as reflux and the stripped H2S and CO2 are routed to SRU. The lean amine solution from the bottom of the regenerator is cooled by exchanging heat against the rich amine solution and then is pumped and further cooled against air before feeding the amine absorption column. A very small amount of lean amine is recycled back to the amine regenerator vapor line serve as a corrosion inhibitor solution.

DIESEL HYDRO DE-SULPHURIZATION UNIT (UNIT25):The diesel hydro desulphurization unit (DHDS unit), Unit 25, is based on the Union fining Process from UOP and is designed to process distillate oil. Petroleum fractions contain various amount of naturally occurring contaminants including

sulphur, nitrogen and metals compounds. These contaminants may contribute to increased levels of air pollution, equipment corrosion and cause difficulties in the further processing the material.

The Union fining Process is a proprietary, fixed-bed, catalytic process developed by UOP for hydro treating a wide range of feedstock. The process uses a catalytic hydrogenation method to upgrade the quality of petroleum distillate fractions by decomposing the contaminants with a negligible effect on the boiling range of the bed. Union fining is designed primarily to remove sulphur and nitrogen. In addition, the process does the job of saturating olefins and aromatic compounds while reducing Conrad son Carbon and removing other contaminants such as oxygenates and organ metallic compounds.

The desired degree of hydro treating is obtained by processing the feed stock over a fixed bed of catalyst in the presence of large amount of hydrogen at temperature and pressures dependent on the nature of the feed and the amount of the contaminant removal required. The Union fining catalysts are formulated by composing varying amounts of Nickel or Cobalt with Molybdenum oxides on an alumina base.

The following chemical steps/reactions occur during the hydrotreating process:

1. Sulphur removal:

Feed stocks to the Union fining unit containing simple mercaptans, sulphides and disulphides are easily converted to H2S. Feed stocks containing heteroatomic, aromatic molecules are preceded by initial ring opening and then sulphur removal followed by saturation of the resulting olefin.

Mercaptan C-C-C-C-SH + H2 = C-C-C-C-H +H2S

Sulphide C-C-S-C-C + 2 H2 = 2 C-C-H + H2S

Disulphide C-C-S-S-C-C + 3H2 = 2 C-C-H + 2 H2S

2. Nitrogen removal:

Denitrogenation is generally more difficult than desulphurization. The denitrogenation of pyridine proceeds by aromatic ring saturation hydrogenolysis, and finally denitrogenation.

Pyridine Pyridine + 5 H2 = C-C-C-C-C (and iso-pentane) + NH3

Quinoline Quinoline + 4 H2 = Ph-C-C-C + NH3

Pyrrole Pyrrole + 4 H2 = C-C-C-C (and iso-butane) + NH3

3. Oxygen removal:

Organically combined oxygen is removed by hydrogenation of the carbon-hydroxyl bond forming water and the corresponding hydrocarbon.

Phenols Phenol + H2 = Benzene + H2O

4. Olefin saturation:

Olefin saturation reaction proceeds very rapidly and has high heat of reaction. Linear olefins C-C=C-C-C-C + H2 = C-C-C-C-C-C (and isomers)

5. Aromatic saturation:

Aromatic saturation reactions are the most difficult and are very exothermic. Benzene + H2 = Cyclohexane

6. Metal removal:

Metals are retained on the catalyst surface by a combination of adsorption and chemical reaction. Removal of metals normally occurs from the top of the catalyst bed and the catalyst has a certain maximum tolerance for retaining metals.

Metals contained in the crude oil are usually nickel and vanadium. Iron is found concentrated at the top of the catalyst beds as iron sulphides, which are corrosive products. Sodium, calcium and magnesium are present due to the contact of the bed with salted water or additives. Improper use of additives, to protect the fractionators overhead systems from corrosion or to control foaming, accounts for the presence of phosphorous and silicon. Lead may also deposit on the hydro treating catalyst beds from reprocessing leaded gasoline through the crude unit. The total metal retention capacity of the catalyst system can be increased by using a guard reactor or a guard bed of catalyst specially designed for demetallization.

7. Halide removal:

Organic halides such as chlorides and bromides are decomposed in the reactor. The inorganic ammonium halide salts, which are produced when the reactor effluent is cooled, are dissolved by injecting water into the reactor effluent, or removed with the stripper off gas.

Chlorine removal Ph-C-C-C-Cl + H2 HCl + Ph-C-C-C-H

HCl + NH3 NH4Cl

PROCESS DESCRIPTION

The DHDS unit consists of the following sections:

Storage and transfer section. Reaction section. Compression section. Fractionation section.

Diesel from FOB enters this unit and passes through two-filter separator of which one (25-FS-01 A&B) is gravity separator, which separates water, and another (25-FS-02) is magnetic filter separator – which separates magnetic metallic particles. The Diesel is then pumped and passed through three heat exchangers in series for preheating. This preheated and high-pressure diesel then enters into furnace and further heated there

Before entering the reactor, the diesel is mixed with hydrogen by means of two compressors – one is used for recycling hydrogen obtained from product stream, and another for make-up of hydrogen which comes from the Hydrogen plant (Unit – 24). It then enters two reactors in series (25-R-01 & 25-R-02). The outlet from the second reactor is used to preheat the diesel oil in three exchangers described above. The product from reactor i.e., diesel, hydrogen and H2S are separated in a separator vessel (25-V-02). H2 and H2S is sent to an absorber column (25-C-01) in which H2S is amine-washed using lean amine and the product rich amine is sent to ARU for lean amine regeneration. Diesel and dissolved H2S are sent to stripping column (25-C-02) with reflux in which diesel is found as bottom product. Top product is H2S, H2O and light hydrocarbons (C1 & C2) are pumped to absorber column (25-C-03) for amine wash. Amine washed H2S from bottom of 25-C-03 is sent to ARU and sweet light hydrocarbon is sent to fuel gas system.

AMINE REGENERATION UNIT (ARU) (UNIT-26):

The function of the unit is to supply lean amine to various units, by treating the rich amine. This treatment is done by continuous absorption process using an aqueous solution of basic alkanol amine, thus reducing H₂S and other acidic contaminants. The alkanol amines used are Mono Ethanol Amine (MEA) or Di Ethanol Amine (DEA). The ethanol amines have high affinity for H₂S and low solubility in hydrocarbons which enhances their suitability in this process.

BASIC CHEMISTRY:

Hydrogen Sulphide is a weak acid and ionizes in water to form hydrogen ion and sulphide ions:

H₂S + H₂O H₃O + HS ̄Ethanol amines are weak bases and ionize in water to form amine ions and hydroxyl ions:

For MEA: HO-C H₂-C H₂-N H₂ + H₂O HO-C H₂-C H₂-NH₃+ + OH ̄For DEA: (HO-C H₂-C H₂)₂-N H + H₂O (HO-C H₂-C H₂)₂-NH₂+ + OH ̄When H₂S dissolves into the solution containing the amine ions, it will react to form a weakly bonded salt of the acid and the base.

For MEA: HO-C H₂-C H₂-NH₃+ + HS ̄ HO-C H₂-C H₂-NH₃HS

For DEA: (HO-C H₂-C H₂)₂-NH₂+ + HS ̄ (HO-C H₂-C H₂)₂-NH₂HS

The sulphide ion is thus absorbed by the amine solution, whose overall reaction can be summarized as:

For MEA: HO-C H₂-C H₂-N H₂ + H₂S HO-C H₂-C H₂-NH₃HS

For DEA: (HO-C H₂-C H₂)₂-N H + H₂S (HO-C H₂-C H₂)₂-NH₂HS

PROCESS DESCRIPTION:

The rich amine system receives collected amine from the amine absorbers. The rich amine from the recycle gas scrubber and stripper gas amine absorber is fed to the

flash drum to separate any entrained liquid or gaseous hydrocarbon from the rich amine. Hydrocarbon vapour separated, which also contains H₂S is scrubbed with a small lean amine slip stream in the stack portion of the drum. Rich amine from the bottom of the flash drum is sent through the tube side of Rich amine heat exchanger unit where it is heated while the lean amine from the bottom of the amine stripper is cooled. The heated rich amine flows to stripper to strip nearly all of the H₂S, followed by further cooling in a Amine Stripper condenser, thus regenerating it to lean amine.

SULPHUR RECOVERY UNIT ( SRU )(UNIT-28):The Sulphur Recovery Unit is designed to recover sulphur from the sour vapours originating from the following sources.

Amine Regeneration Unit. Unit-26 Sour water stripper Unit-29

The process is a combination of conventional Claus process and the recently developed process for the selective oxidation of hydrogen sulphide.

The SRU consists of the following sections:

A knock out drum for the feed gas stream and fuel gas stream A Claus section, consisting of a thermal stage and three reactor stages A SUPER CLAUS stage A thermal incinerator, burning the tail gas and vent gas of the sulphur Degassing system Sulphur pit with degasifying facilities and sulphur yards.

FEED CHARACTERISTICS

The feedstock of the SRU is a mixture of the "Acid gas ex ARU" and "Acid gas ex SWS". The quality and quantity of H2S feed to the unit will vary depending on the shutdown of the various preceding units. The unit should be capable of converting 99% wt. of the H2S contained in the feed streams to sulphur in all cases.

PRODUCT CHARCTERISTICS

The product sulphur meets the following specification after degassing :

State: liquid sulphur Colour: bright yellow Purity: minimum 99.9% on dry basis H2S content: 10 PPM wt. maximumCATALYST AND CHEMICALS

CLAUS CATALYST: These catalysts are installed in the Claus reactor

1st & 2nd reactor: CRS-31, 85 wt % titanium oxide 2nd & 3rd reactor: 98 wt % alumina with 2400 wt ppmNa2O

2. SUPERCLAUS CATALYST: It is a catalyst for selective oxidation and consists of

Aluminium oxide 50% volume SiO2 with iron(III) oxide / phosphate 50% volumeThe catalyst is premixed by 50% / 50% volume basis by manufacturers.

3. CERAMIC BALLS: A layer of ceramic balls is installed in the reactor as support bed. Type of ceramic ball is Denstone 57.

4. CHEMICALS FOR BFW: In SRU, a phosphate injection system is provided to increase the pH of boiler feed water to the WHB's and condensers.

To increase the pH, a trisodium phosphate solution is injected and the concentration of phosphate solution in boilers and condensers is kept 50-100 ppm

CHEMICAL REACTIONS IN SRU

CLAUS SECTION The main reaction in this section takes place at main burner

H2S + 3/2 O2 SO2 + H2O + Heat

The major part of the residual H2S combines with the SO2 to form sulphur, according to the equilibrium reaction.

2 H2S + SO2 3/2 S2 + 2 H2O – Heat

By this reaction known as the Claus reaction, sulphur is formed in the main burner and reaction chamber.

SUPERCLAUS SECTION In this section partial oxidation of H2S takes place according to the reaction equation given bellow

2 H2S + O2 2/8 S8 + 2 H2O + Heat

PROCESS DESCRIPTION:

CLAUS SECTION: By the reactions described before, sulphur is formed in vapor phase in the main burner and combustion chamber. The primary function of waste heat boiler is to remove the heat generated in main burner. The secondary function of waste heat boiler is to utilize removed heat to produce MHP stream.The process gas from the waste heat boiler is passed into the 1st sulphur condenser, where the formed sulphur is removed from the gas.The process gas leaving the sulphur condenser still contains a considerable concentration of H2S and SO2. Therefore, the essential function of the following equipments is to convert these components to sulphur.

In the 1st, 2nd and 3rd reactor stages, the H2S and SO2 again react to form sulphur but this time at lower temperatures.

In the SUPERCLAUS stage, the remaining H2S is selectively oxidized to sulphur. For this reason it is essential that the combustion in the main burner is such that in

the downstream of the 3rd reactor stage, the amount of H2S in the range of 0.5 – 0.7 volume % and the SO2 concentration is as low as possible.

Before entering the 1st reactor, the process gas flow is heated by indirect steam to obtain the optimum temperature for a high conversion of H2S and SO2 to elemental sulphur and simultaneously a high conversion of COS and CS2 to H2S and SO2.The effluent gas from the 1st reactor is routed to 2nd sulphur condenser.The process gas flow is next routed to 2nd steam reheater and then to 2nd reactor where equilibrium is established. The sulphur is condensed in the 3rd sulphur condenser.

From the 3rd sulphur condenser, the process gas is routed to 3rd steam reheated, and then passed to the 3rd reactor where equilibrium is established. The sulphur is condensed in the 4th sulphur condenser.

SUPERCLAUS SECTION: The process gas from the 4th sulphur condenser is routed to the fourth steam re-heater then passed to the reactor. Before it enters the reactor, a controlled amount of air is added. Proper mixing is obtained in a static mixer. In the reactor sulphur S8 is formed according to the reaction mentioned before. The formed sulphur is condensed in the 5th sulphur condenser. A

Sulphur coalescer is installed downstream of the last sulphur condenser to separate entrained sulphur mist.

The sulphur condensed and separated in the condensers and coalescer is drained via the sulphur locks and the sulphur cooler into the sulphur pits.

The tail gas leaving the coalescer still contains an amount of H2S, which is dangerous if released directly to atmosphere. Therefore, the gas is thermally incinerated; converting residual H2S and sulphur vapour to SO2 in presence of oxygen. After the gas is cooled in incinerator, waste-heat boiler and super heater it is routed to the stack. In the incinerator and waste-heat boiler, MHP steam is produced and in the superheater MHP steam from the unit is superheated before evaporation.

SULPHUR STRIPPING PROCESS:

The process sulphur contains H2S partially dissolved and partially present in the form of polysulphides (H2SX). Without treatment of the sulphur, the H2S should be slowly released during storage and transport. An explosive mixture may be

created due to exceeding the lower explosive limit of H2S in air, which may vary from 3.7 volume % H2S at 130OC to 4.4 volume % H2S at ambient condition. The shell sulphur degassing process has been developed to degasify liquid sulphur to 10-ppm wt H2S/H2SX that is the safe level to avoid exceeding the lower explosive limit.

The function of this process is to enhance the decomposition of polysulfide and to strip the H2S from the sulphur. Simultaneously, the greater part is oxidized to sulphur. The air decreases the partial pressure of H2S and causes agitation and circulation of the sulphur.

In this way, the H2S content is reduced from approximately from 350 to less than 10 ppm wt. The reduced H2S together with the air is routed to the thermal incinerator, in which it is oxidized to SO2. The degassed sulphur is pumped on level control to sulphur yard.

MOTOR SPIRIT QUALITY UPGRADATION UNIT (MSQU)(UNIT-85/86/87):This unit is known as the Motor Spirit Quality Upgradation unit. The unit is commissioned with the aim to produce superior quality gasoline. Euro-II type MS have a RON value of 88 and sulpher content of 50 ppm, and that of the Euro-III is 91 and 150 respectively. The main product of MSQ unit is the Euro-III type gasoline.

NAPTHA PRODUC

LPG

MSQ UNIT (UNIT-85, 86, 87)

Other constrains of Euro-III type MS is aromatic content is 42%, benzene 1 %, olefin 21%, max by volume and the RVP is 0.6 kg/cm2. Hence the main objective of the unit is to convert the st chain hydrocarbons, C5-C6 paraffin to branch chain, or olefins to improve the octane number. As benzene is carcinogenic so benzene

SR NAPTHA NAPTHA SPLITTER UNIT 85

NHDT UNIT 85

ISOMERIZATION +

DIH + LPG RECOVERY

LPG

NHDT & CRU

UNIT 21 & UNIT 22

SHU

UNIT 87

FCC GASOLINE

FCC GASOLINE SPLITTER UNIT 87

PRIME G+ SELECTIVE DESULPHURIZATION UNIT

HEAVY FCC GASOLINE

PYROLYSIS GASOLINE

REFORMATE SPLITTER

ISOMERATE

HYDROGEN

MS PRODUCT

FCC GASOLINE HEART

Fig: 06

saturation is an important factor in this unit. Reactions of type desulferisation, isomerisation, and benzene saturation olefin saturations are done in these units. The light FCC gasoline obtained after gasoline splitting in unit 87 is blended with heavy reformate from unit 85, isomerate from unit 86, heart cut FCC gasoline from unit 87, and heavy gasoline after hydrodesulphurization in unit 87 are blended proportionately for octane improvement and desulfurisation in the blending header to get MS of desired octane number.

LUBE OIL BLOCK:

In lube oil block (LOB) the reduced crude oil from the Atmospheric Distillation Unit (ADU) is processed to produce lube base stock, slack wax, transfer oil feed stock (TOFS) etc.LOB contains the following 9 units:

Name of the Unit Unit No.

Vacuum Distillation Unit (VDU) U 31

Propane De asphalting Unit U 32

Furfural Extraction Unit U 33

Solvent De waxing Unit U 34

Hydro Finishing Unit U 35

Bitumen Treatment Unit U 36

Visbreaking Unit U 37

N-Methyl Pyrrolidine (NMP) Extraction Unit U 38

Micro crystalline wax unit U 39

Catalytic iso dewaxing unit(CIDWU) U 84

Lube Oil ( Base Stock ) Manufacturing:

Lube oil base stock manufacturing is basically a series of different secondary processing which a lube potent mother feed stock namely Reduced Crude oil undergoes. As it appears, Reduced Crude Oil is the bottom of the barrel of basic refining unit, Atmospheric Distillation Unit. So the overall intricacy and complexity of operation does not lie on individual processing unit but also managing the overall network in unison.

VDU

REDUCED CRUDE OIL

MP STEAM

VACUUM GAS OIL

SPINDLE OIL

LIGHT OIL

INTERMEDIATE OIL

HEAVY OIL

SHORT RESIDUE

FLUE GAS

VACUUM DISTILLATION UNIT

VACUUM DISTILLATION UNIT (UNIT-31)

Fig:07

PURPOSE :

To Vacuum Distill RCO from Crude Distillation Unit. Vacuum Distillate is feed stock for LOBS units or FCCU.

PRODUCTS :

Gas Oil ---- Diesel Component. Spindle Oil ---- Diesel Component or H-70 LOBS feed stock. Light Oil ---- 150 N grades LOBS feed stock or FCCU feed. Inter Oil ---- 500 N grade LOBS feed stock or FCCU feed. Heavy Oil ---- 850 N grades LOBS feed stock or FCCU feed. Vacuum Residue ---- Feed stock for PDA unit.

QUALITY MONITORING: Reduced crude oil from atmospheric unit or from tanks is the feed stock for Vacuum Distillation Unit. Reduced crude oil is preheated to 285 OC in preheat exchangers and then to 400 OC in the furnace. Steam is injected in the furnace to achieve vaporization / prevent coking of the furnace coils. The reduced crude is then fractionated under vacuum in the column (31C01) to obtain the following streams. A high vacuum condition and steam are utilized to maximize the distillate recovery from reduced crude.

Streams Approximate boiling range TBP ( oC )

Gas oil 265-362

Spindle oil 362-385

Light oil 385-462

Intermediate oil 465-504

Heavy oil 504-542

Short residue 542+

Spindle oil, Intermediate oil, Heavy oil distillate and Short residue are further processed to produce lubricating oil base stocks. Gas oil, Light oil and any surplus distillates are processed to saleable products.

PROCESS DESCRIPTION: Reduced crude received from the Atmospheric Distillation Unit or from Intermediate Storage Tanks (T-701/702) is the feed stock for Vacuum Distillation Unit. Reduced crude is preheated to 285 OC in a series of heat exchangers and then it is partially vaporized by further heating in furnace (31F1). The outlet temperature is controlled to maintain a flash zone temperature of 400 OC. Steam is injected in the vacuum heater with the feed and also introduced into the flash zone of the vacuum distillation tower. The bottom liquid is steam stripped in the section below the flash zone. Substantial quantities of steam in excess of that required for stripping is required in the vacuum tower to reduce the partial pressure of the oil present in the flash zone, to achieve required amount of oil vaporization at the flash zone temperature of 400 OC. About 30% of the required stripping steam is used as coil injection steam to

prevent coking of the furnace coils. The vapor leaving the flash zone of the vacuum tower passes through a demister pad to ensure removal of entrained asphaltenes. Most of the hydrocarbon vapor is condensed stepwise by top reflux as well as pump around sections and fractionated to produce five liquid side draw products. Some uncondensed and entrained gas oil with steam leave the top of the column and enter the vacuum system. The gas oil and the steam are condensed in surface condensers. The condensed oil is removed from the hot well and separated from water in separator (31B3).

Spindle oil, Intermediate oil and Heavy oil are provided with steam stripping facility. These products are routed to individual storage tanks. Excess quantities of these products are routed to Fuel oil, Visbreaking Unit and to internal fuel oil respectively. Unstripped light oil goes to either Visbreaking Unit or to fuel oil storage tanks. Light oil can also be routed to T-761. Short residue drawn from the bottom of the tower is sent to PDA and Visbreaking Units storage tanks. A small quantity of hot short residue is also routed periodically to Bitumen Unit and to TPS whenever required.

All products are cooled before sending to storage tanks by exchanging heat with feed and water in the coolers. Short residue feed to Bitumen Unit is sent hot after 31E11 or after 31-H-1a, b.

Vacuum in the tower is maintained by a set of booster and ejectors with surface condensers.

Operating conditions:

a) Feed inlet temperature 286 OC

b) Feed outlet temperature 400 OC

Vacuum column:

a) Flash zone pressure 100-125 mm Hg.

b) Flash zone temperature 380 OC

c) Top pressure 60-80 mm Hg.

d) Top temperature 80 OC

SOLVENT

FURNACEKOPot

PROPANE VESSEL

MIXING

TANK

EXTRACTION TOWERS

EVAPORATION TOWER

STRIPPER

EVAPORATION TOWER

STRIPPER

H.E.

COOLER

STEAM+SOLVENT

STEAM+SOLVENT

VM STEAM

VM STEAM

ASPHALT (TO STORAGE)

DE ASPHALTED OIL (TO RUNDOWN TANK)

SOLVENT

SHORT RESIDUE

PROPANE

ASPHALT + LITTLE AMOUNT OF SOLVENT

PROPANE DEASPHALTING UNIT (UNIT-32)

STEAM

Fig:08

e) Recycle to head temperature 375 OC

f) Column base temperature 350 OC

g) Stripping stream flow rate 6780 m3/hr.

Capacity:

336.28 ton/hr

PROPANE DEASPHALTING UNIT(UNIT-32):

This unit produces deasphalated oil (DAO) by removing asphalt from short residue obtained from Vacuum Distillation Unit (VDU).Solvent extraction process is chosen for removal of asphaltic material from short residue and deasphalted oil (DAO) is recovered. Propane is used as solvent and its properties near the critical temperature are required. Deasphalted oil is sent to Furfural Extraction Unit (FEU) for further processing as bright stocks. Asphalt is sent as fuel to TPS and as feed stocks to Bitumen and Visbreaking units.

PROCESS DESCRIPTION:

Extraction: The short residuum charged is mixed with propane extraction tower. Feed enters the extraction tower and the solvent is pumped into the bottom of the extraction tower. The heavy short residuum charge flows downwards while the light solvent flows countercurrent upwards.

Solvent recovery: The DAO-solvent mixture flows from the top of the extraction tower and the asphalt mixture is withdrawn from the bottom. DAO-solvent mixture flows under pressure control from top of the tower to the solvent evaporators 32C03 and 32C04 after getting heated through exchangers. The major position of solvent is evaporated here. Both evaporators are maintained at the required pressure level so that the vaporized solvent flows directly to the solvent condenser. The remaining amount of solvent in DAO is stripped off in the tower 32C06 by means of steam. The steam and solvent vapors pass overhead and DAO products. The steam and solvent vapors pass overhead and DAO products are pumped from the stripper bottom by 32P04 and level is controlled through a stripper. Asphalt solvent mixture is taken from bottom of the tower 32C01 under level control. The mixture is heated to about 225 OC in the furnace F1 in order to vaporize most of the solvent and to prevent foaming in the flash tower. Vaporized solvent is separated from asphalt in flash tower C-2.

Solvent specification

Name of component Weight %

Propane 97.5

Ethane 1.0

Butane By difference

OPERATING VARIABLES:

Operating variables and their effects are described below. The extraction column temperature and pressure gradient and solvent feed ratio are the most important among them.

1. Extraction temperature and temperature gradient: Above 38 OC propane has a negative temperature co-efficient in respect of asphalt and resin solubility. The top and bottom temperature are maintained at 68 OC and 52 OC respectively. These temperatures are raised depending on the feedstock and product quality that are desired. Increasing the top temperature will precipitate and further quantity of asphalts of gradually lower molecular weight. Feed temperature affects the top temperature to some extent. The bottom temperature is maintained constant by maintaining the solvent entry temperature for a steady degree of extraction.

2. Temperature of the evaporator and stripper: Top and bottom temperature are maintained in such a way that all propane and steam escape from overhead but no oil vapor should go with them.

3. Extraction tower pressure: Higher the pressure sharper the separation. Pressure is maintained at 40 kg/cm2, so that the solvent will remain in the liquid in the operating temperature.

4. Evaporator stripper pressure: Proper pressure gradient is maintained between C-3 and C-4 so that the liquid flow can be smooth. The pressure in the evaporator column will depend upon the pressure in propane condenser E-6. The pressure in the stripper and condenser should be sufficiently low for maximum solvent recovery.

5. Solvent feed ratio: Solubility of asphalt and resins in lower paraffinic hydrocarbons increases in the order C-4, C-3 , C-2 . Solvent composition is maintained for steady product quality.

FURFURAL EXTRACTION UNIT (UNIT-33):

FEED STOCK

TO ATMOSPHERE

VM STEAMFURFURAL

RAFFINATE

DE-AERATOR

EXTRACTOR

FURFURAL EXTRACTION UNIT (UNIT- 33)Fig:09

FEED STOCK: Vacuum distillate from VDU & DAO from PDA unit.

PURPOSE: To extract aromatics from distillates to improve VI of LOBS using Furfural as solvent.

PRODUCTS: Raffinate for further processing of LOBS and aromatics extract.

QUALITY MONITORING:

Raffinate: KV @ 100oC, RI, CCR.

Extract: Density.

The Furfural extraction unit includes the following sections:

1. De aeration

2. Furfural extraction

3. Raffinate separation

4. Extract separation

EXTRACT

5. Solvent recovery

From raffinate solution From extract solution

From water-furfural & furfural-water mixture

6. Neutralization with Na2CO3 solution

PROCESS DESCRIPTION:

1. De aeration section: Distillate oil is taken from the storage tanks and pumped using 33-P1-1/1R through heat exchangers 33-E-1A/B ( distillate oil vs. de aerator bottom ) and then through feed-steam heat exchangers 33-E-2A/B ( distillate oil vs. extract rundown or extract recycle ) and thereafter enters the de aerator column 33-C-1 . An absolute pressure of about 150 mm Hg. is maintained in 33-C-1 using ejector or condenser.

2. Furfural extraction section: De aerated distillate oil is pumped through a charge cooler and then enters the extractor in which two phases are formed. The raffinate with low content of furfural is discharged at the extractor top and the extractor is discharged at the bottom.

3. Raffinate separation: The raffinate enters a vessel 33-B-1 provided with an inert gas blanket from where it is pumped through heat exchangers and heated in furnace 33-F-1 from where it is discharged at 220 OC .

4. Extraction separation section: From the extractor the extract is pumped through a series of heat exchangers, temperature rising to 91 OC. A part of the furfural section is eliminated in the bottom portion of the extract pressure flash tower and the rest is heated to 230 OC in the extract furnace and then enters the extract pressure flash tower at the top .

5. Solvent recovery from raffinate solution : The solution at 220 OC enters the raffinate flash tower at 150 mm Hg. Furfural vapors discharged overhead at 114OC enters the cooler operating at 100 mm Hg from, where liquid furfural is pumped at 60 OC is pumped into the extractor .Temperature at the top of the raffinate flash tower is maintained by furfural reflux. The raffinate solution from the bottom of the raffinate flash tower is steam stripped. Furfural vapor and water vapor and water vapor discharged from the top at 70 OC pass through a cooler at 60 OC and then through a cooler at 60 OC and then through a vessel provided with an inert gas blanket.

6. Solvent recovery from extract solution: This is done in two stages:

a. Furfural vapor from the extract pressure flash tower at 180 OC are cooled in drying solvent tower to 165OC. The furfural vapors discharged from the top of the extract pressure flash tower (operates at 2-7 kg/cm2) enters the drying solvent tower via heat exchanger.

b. From the bottom of the extract pressure flash tower the extract solution containing a low quantity of furfural passes into extract vacuum flash tower at 150 mm Hg. from where furfural vapor is at 114 OC and passes into cooler . The extract still contains furfural and is steam stripped. From the bottom of the extract vacuum flash tower, furfural is pumped from the extract at 168-192 OC to steam generator from where it goes to storage tanks.

7. Neutralization with sodium carbonate solution: To prevent corrosion sodium carbonate solution is injected into following circuit:

Water vapor and furfural vapor

Furfural vapor and water vapor

SOLVENT DEWAXING UNIT (UNIT-34): Feedstock: Raffinate from furfural extraction unit.

Product: Dewaxed oil & Slack Wax.

Quality Monitoring:

DWO: Pour point, Flash point, KV @ 100oC & 40oC

Slack Wax: Flash Point.

Objective:

To remove paraffinic hydrocarbons to remove paraffinic hydrocarbons from the extract to the low pour point to make it suitable for low temperature application.

PROCESS:

TRAIN OF DP CHILLERS

LIQUID NH3 REFRIGERANTSECONDARY DILUTION SOLVENT

SDA DOSING (PRIMARY DILUTION SOLVENT)

FEED STOCK

WAX TO FCCU

SOLVENT + DWO

VM STEAM

SOLVENT RECOVERY SECTION

SOLVENT DRYING TOWER

ROTARY VACUUM FILTER

STRIPPER

SOLVENT DEWAXING UNIT (UNIT-34)

Fig:10

Extraction and crystallization to achieve dewaxing with the addition of SDA followed by filtration and solvent recovery.

Solvent:

MEK & Toluene in equal proportions. Toluene is oil solvent & MEK is antiwax solvent.

Antiwax Solvent:

Antiwax solvent, also called wax-rejecter (MEK) is used to avoid solubility of wax in oil solvent i.e., toluene. MEK is useful in this purpose for its poor oil miscibility character. Toluene and MEK should be blended in such a way so that it impose highest solvent effect on oil and little solvent effect on wax.

Crystallization:This process takes place with nucleation and growth. It is a very complex process in which both mass and heat transfer takes place in a multicomponent system like wax.

PROCESS DESCRIPTION:

The unit is subdivided into the following sections:

Feed solvent recovery section. Ammonia chilling section. Filtration section. Solvent recovery section. Refrigeration section.

Feed solvent recovery section: The molten waxy feed is mixed after primary dilution in various proportions depending on the grade and viscosity of lube raffinate. The solution is first heated in a steam heater to homogenize the feed mixture 5-10oC above its cloud point. The solution is cooled under controlled condition first in water cooler to the nucleation temperature then in a tank of scrapped surface exchangers and chillers employing cold filtrate and liquid ammonia as cooling medium respectively.

Ammonia chilling section: Feed mixture stream before joining from two feed streams into one are cooled to a temperature just above the cloud point to ensure that crystallization will start only in DP exchangers. The feed mixture is then distributed into seven parallel trains with each train comprising of two double pipe scrapped surface exchanger (LR) followed by three DP chillers (LR) in series. The secondary dilution is added at set temperature to each train at the out first DP chiller or at the first DP chiller. The exact location of secondary of solvent injection point can be varied and is chosen for different feed stocks as required.

Filtration section: The feed mixture stream after further chilling in third DP chiller of each train are joined and are routed to the filter feed drum. The territory dilution solvent is added before it goes to filter feed drum. The solvent train is

joint to both streams and used where it is necessary. The chilled feed mixture in the form slurry of wax crystal in oil and solvent flows by gravity from filter feed drum which is blanked with inert gas and is distributed to ten parallel filtration trains. The filter drum carrying filter media is submerged and rotates in the filter vat filled with the chilled slurry of dewaxed oil solvent mixture containing suspended wax crystal. Inert gas vacuum compressor produces the vacuum. As the wax cake is formed on the filter cloth the cold solvent at the filtering temperature washes it continuously. After the cold washed zone, the inert gas is drawn through the filter cloth in order to dry the cake. Blowing the chilled inert gas from inside the filter cloth then dislodges the washed cake. A doctor blade is gently removed the cake over to a rotating scroll conveys it to the filter boot (34-B-3). A steam coil in the filter boot heats up the wax mixture. The wax mixture is pumped by filter boot pumps to slack wax solvent recovery section. The dewaxed oil (DWO) mixed filtrate and the inert gas from filtrate receiver flows to inert gas drum to eliminate any entrainment before it enters to the inert vacuum compressor.

Solvent recovery section: The DWO mixture is heated and vaporized by the overhead vapor from the DWO first flash column (34-C-1) and DWO second flash column (34-C-2) by 34-E-5 A/B and 34-E-7 A/B/C/D exchangers. The bottom liquid is fed to second flash column (34-C-2). The overhead solvent of 34-C-3 vapors go for solvent drying (34-C-10) where bottom liquid of 34-C-3 flows by gravity to 18th

tray of DWO stripper (34-C-4). In DWO stripper superheated low pressure stream is introduced at the bottom to remove the remaining solvent from the DWO. The product DWO from 34-C-4 column, bottom is routed to storage.

Refrigeration section: The refrigeration section consists of three basic cycles’ compression, liquefaction and evaporation. It is a closed circuit system. Ammonia vapors rescued from the cooler, chiller, heat exchangers are send to the refrigeration section for the two cooling stages at –15oC and 30oC respectively. The plant is equipped with two centrifugal compressors for compression of such vapor.

HYDRO FINISHING UNIT (UNIT-35):

FURNACE

COMPRESSOR

K.O. DRUM

DWO OIL FEED

HYDROGEN GAS

AMINE SOLVENT

RICH AMINEE

SOUR WATER DRAIN

PRODUCT

STRIPPING STEAM

REGENERATED AMINE

OFF GAS

CATALYTIC REACTOR AMINE ABSORBER

SEPARATOR

STRIPPING COLUMN

STRIPPING COLUMN

H2 GAS

HYDRO FINISHING UNIT (UNIT-35)

Fig:11

OFF GAS

PURPOSE: To improve color of lube base stocks by removal of sulphur, oxygen and nitrogen in a reactor with Co-Mo catalyst.

FEEDSTOCK: DWO from SDU, CATALYST: HR 348 supplied by Procatalyse. High purity alumina extrudates impregnated with Ni-Mo oxides

QUALITY MONITORING: Color, KV @ 100oC, VI. Many reactions are involved during hydro finishing and we can distinguish the following:

1. Hydro-desulphurisation.

2. Mild hydro-de nitrogenation.

3. Olefins hydrogenation.

4. Mild aromatics hydrogenation.

5. Decomposition of other hetero molecules such as O2 compounds.

As a result of all these reactions the color and the color stability of the lube-based stocks are improved. The overall performance can be connected with the hydrodesulphurization performance.

PROCESS DESCRIPTION:

The following chemical reactions are involved:

Desulphurization: The sulfur is present in the feed under various forms such as mercaptans, sulphides, disulphide and combined form in cycles with aromatic character (thiophenic sulphur).The decomposition of sulphur compounds are illustrated here after:Mercaptans RHS + H2 = RH + H2S

Sulphides RSR' + 2 H2 = RH + R'H + H2S

All these reactions produce H2S consuming H2 and are exothermic. In hydrofinishing required reactions are mainly the desulphurization of sulphides, disulphides, mercaptans and partly of some sulphur combined form in such a way that some aromatic compounds with sulphur remain in the lubes. These compounds act as antioxidants and allow additive economy.

Mild hydro-denitrification: Nitrogen is contained essentially in heterocyclic compounds. When hydro finishing raffinates, a large part of undesired nitrogen compounds are removed at previous treatment which is solvent extraction. Nevertheless, for some typical highly nitrified crude some hydro-denitrification is required in hydrofinishing for reaching better cooler stability.Amines RNH2 + H2 = RH + NH3

The ultimate products of hydro-denitrification are hydrocarbons and ammonia.

Hydrogenation of olefins: Some olefins can be present in the raffinates but generally in low quantity. Most of them are saturated during hydrofinishing reactions. The corresponding measurement is the Bromine Number Value.

Very mild hydrogenation of aromatics: Normally in the hydrofinishing aromatics is not hydrogenated. Nevertheless, the analysis shows a slight decrease in aromatics in the stripped oil (the finished oil). This decrease is partially due to liberation of some aromatic rings towards the light compounds which are stripped to reach the required flash point.

Decomposition of oxygenated compounds and other reactions: Generally, the oxygenated compounds are mostly removed at the solvent extraction step. If still any, they will be removed with hydrofinishing.

The unit can be divided into two distinct sections viz.

1. Reaction section.

2. Stripping section.In the first section the reactions mentioned above is effected under controlled conditions while the second section describes the removal of the reactants, gas, etc. from the finished Lube Base Stocks.

BITUMEN TREATING UNIT(UNIT-36):In this unit two types of industrial grades are produced. But this unit today is fully closed and has been replaced. Now a day the asphalt produced from the propane deasphalting unit is directly mixed with the gasoline & aromatics from extract of UNIT-33 & UNIT-38 via pipeline with a suitable proportion and bitumen is produced and sends to OM&S for storage. Air is also blown through the pipeline and a continuous mixing is done. The length of the air to be blown depends on the penetration characteristics desired.Two types of grades are mainly produced:1. Industrial Grades.2. Straight Grades.

The feed stocks used are vacuum residue reduced crude oil, light oil, asphalt from PDA and heavy extracts from furfural extraction unit.

Penetration number is defined as the number of units of 1/10 mm, a standard needle with 100gms load penetration into the asphalt mass in 5 minutes of a standard test temperature.

BITUMEN TREATING UNIT (UNIT-36)

Fig:12

OPERATING VARIABLES:

1. Column Temperature

2. Air blowing rate

3. Residence time

VISBREAKING UNIT (UNIT – 37):Rightly viscous heavy oil products can be converted into lower viscous oil products by means of a thermal process called Visbreaking (Viscosity Breaking). The main purpose of the unit is cutting down the viscosity and pour point of

Flue gas

Bitumen

Steam Water

feed

Heat

Air

FURNACE

SOAKER VISBREAKER

FEED

GAS OIL QUENCH

GAS OIL

VB TAR (FOR FURTHER PROCESSING)

VISBREAKER UNIT (Unit-37) Fig:13

heavy residues, which constitute a stable fuel oil component. Gas and stabilized gasoline are also obtained.

The feed has the following characteristic:

Viscosity at 100oC = 5.05c.p.

Pour point = 27oC

Gas, gasoline and visbroken tar are the products of this process. Amine regeneration unit, Kero-HDS unit and hydrofinishing unit are all burned in the flare which was the main problem for decreasing air pollution so the installation of this unit became necessary. All the H2S from the units are recovered as elemental sulphur (about 99.9%). The design intention of SRU is to recover sulphur from the feed and to allow a maximum of 10 ppm of H2S in the final flue gas going to the stack.

FRACTIONATOR

VISBREAKER NAPTHA

NMP EXTRACTION UNIT (UNIT–38):The solvent used for extraction is NMP i.e., N-Methyl Pyrolidone. The unit handles 3 major streams extract, raffinate and water. The solvent recovery from both extract and raffinate phases is carried out in such a ppm level.

CBD

FEED

STEAM

SOLVENT NMP RAFFINATE (12-20% SOLVENT)

KNOCK OUT POT

DE-AERATOR

EXTRACTOR

EXTRACT (78-83% SOLVENT)

TO VACUUM CONDENSATE DRUM

TO SOLVENT DRYER

STEAM

EXTRACT R/D

VACUUM FLASH COLUMN

EXTRACT STRIPPER

NMP EXTRACTION UNIT (UNIT-38)

Fig:14

PROCESS DESCRIPTION :

The unit typically consists of the following section:

1. De aeration/extraction section: Objective of this section is to remove dissolved air in feed. Though NMP is thermally stable, dissolved air will accelerate its degradation. This is done in 38C01 through stripping steam.Objective of the extraction system is to extract out condensed aromatics and polar compounds from feed, to improve color, VI, flow characteristics of feed stock. This is done in 38C02, which is a 7 bed packed tower.

2. Raffinate recovery section: it separates raffinate from raffinate mix by vacuum flashing and steam stripping after heating in a raffinate mix furnace.

3. Extract recovery section: it separates solvent and extract from extract mix by carrying out flashing at different temperatures and pressures and finally stripping with steam at pressure below atmospheric.

4. Solvent drying section: to remove water coming along with solvent recovered at different recovery stages to a desired level of water in the solvent to be used as solvent in the solvent extraction column and as reflux in various section.

5. Solvent utility/conservation section.

MICRO CRYSTALLINE WAX UNIT (UNIT–39):Here the feed is wax separated from bright neutral which is produced from short residual. It mainly produces the product which is the base stock for the cosmetics and medicine industries. Here the temperature is raised by the transformer. After this it is send to separator after the series of heat exchangers to separate the nitrogen, sulphur, oxygen; and the finished product is obtained.

CATALYTIC ISODEWAXING UNIT (UNIT-84):OBJECTIVE: To produce Group-II & III grade LOBS.

MAJOR REACTIONS: Hydro treating, Catalytic De waxing & Hydro finishing.

FEED: 100N/ 150N/ 500N/ 150 BS & 500N raff & SL wax mixture & 500N slack wax.

THE PROCESS:

In this unit there are three reactors HDT, MSDW, HDF. In HDT the waxy feed is hydro treated in order to remove impurities like sulphur, nitrogen, oxygen which poisons the catalyst. In MSDW (Mobile selective dewaxing) the wax is removed in presence of catalyst. In HDF the product is hydro finished to improve its quality.

PROCESS DESCRIPTION:

Feed section: Waxy oil is first heat exchanged in heat exchangers 84-E-01.it is then filtered in oil feed filter. The feed is then passed to feed coalescer from where after coalescing it goes to oil feed surge drum 84-B-01.

Preheat Section: Feed is preheated in heat exchanger 84-E-02 with HDF reactor effluent. The recycle gas is added to it. It is again preheated in heat exchanger 84-E-03.Preheated feed is then heated in HDT reactor charge heater. 84-F-01.

Reaction and product separation: Heated feed goes to HDT reactor 84-R-01 where hydro treating reaction takes place where nitrogen is converted to NH3 while sulphur to H2S.Reaction is exothermic in nature, so interbred quenching is done to maintain reaction temperature. The reactor effluents are cooled in feed/HDT effluent heat exchanger 84-E-03. To maintain feed temperature to stripper some portion is bypassed. This partially cooled effluent is sent to HDT effluent stripper 84-C-01 where phase separation takes place.H2S and NH3 are stripped from resulting liquid phase using hydrogen make up gas. Column bottom liquid is routed to MSDW feed /effluent heat exchanger 84-E-06.A part of the liquid may b routed to raffinate stabilizer for stabilization. Vapor from stripper 84-C-01 is cooled in HDT stripper overhead/feed gas heat exchanger 84-E-04 and then air cooled in 84-EA-01while further cooling is done in train cooler84-E-05.

Low pressure recovery section: The liquids are stripped for the separation of naphtha and lighter material from the de waxed oil stream. The vapors are condensed and contacted with lean amine in the low pressure amine absorber, for H2S removal, before discharge into the fuel gas header. The bottom products are sent to the vacuum fractionators, where distillate and lighter material is

separated from the de waxed oil. The vapors are sent back to the furnace firebox. The de waxed products are vacuum dried and cooled.

OIL MOVEMENT AND STORAGE (OM & S)Imported crude brought by tankers stored in refinery storage tanks is processed subsequently in different units and finished petroleum products are obtained which are dispatched for marketing by tankers, barges, wagons, trucks and pipelines. The process is a continuous one and the oil movement and storage division of the production department plays an important role in maintaining smooth continuous and rated operation of the refinery.The broad functions of OM & S are listed as follows:

1) Receipt and storage - Crude oil from tankers - Intermediate and finished products from process units.2) Preparation and supply of feed to various units3) Blending of products4) Dispatch of products5) Supply of fuel oil to furnaces6) Unloading, storing, supplying various solvents and chemicals to units7) Recovery of steam condensate8) Accounting of petroleum products and observing necessary customs and excise formalities9) Effluent treatment 10) Flare system operations

In addition to the above, the following auxiliary functions are also connected to the OM&S division:

a. Calibration of tank wagons and tanks

b. Cleaning/Steam flushing of tank wagons

c. Decantation/ trans-shipment of tank wagons and tank Lorries.

CRUDE OIL RECEIPT:

Crude oil is received by the mode of water transport through tankers from the following countries

i) Middle East countries viz. Iran, Saudi Arabia, Kuwait

ii) Russia

In the process, a carrier agent is present here it being “The Shipping Corporation Of India Limited “. The cargo is received in two oil jetties; one uses hosepipe and the other uses Automatic Loading Machine.

A part of the crude are taken from the port, which is called “Port Sample"

OPERATIONS:

Crude oil received from tankers and after proper setting and draining is fed to the crude distillation unit. Intermediate products are received either by finished or semi-finished condition. Semi-finished products are converted to finished products either by blending or by further processing in other unit. Rail, road, sea/river, and pipelines as per plan then dispatch them.

MEASUREMENT OF PETROLEUM PRODUCTS:

Generally bulk oils are bought and sold on the basis of volume corrected to 15oC. Only LPG and bitumen are bought and sold on the basis of weight.

OM & S has the following sections:

Tank Farm Bitumen filling station Tanker truck loading LPG storage Effluent treatment plant

TANK FARM:Types of tanks:

Generally, the tanks used for storing petroleum products are:

i) Fixed cone roof type ii) Floating cone roof type

i. Fixed cone roof type tank

These are used for storing low volatile products. They have a vertical cylindrical structure with conical top made of welded steel. They are provided with manholes on the shell and roof, products inlet and outlet, ladder, gauging plate, gauging batch with reference mark, mechanical type level gauge, open vent with wire mesh, earthling connections. They are also provided with sampling devices, temperature gauge, and steam heating coils etc. as per service requirement. The welded steel plate at the bottom of the tank is placed on a specially prepared bed made of sand and bitumen. Insulation is also provided in such tanks when hot fluids are stored.

In order to prevent the tank from collapsing, when the stored liquid is being drained out a vent is provided at the fixed rooftop. The whole system is earthen to prevent generation of static electricity .It also contains a flame arrester. A breather valve is also provided to prevent air from into the system while the liquid is being drained out .For this reason, the system is blanketed with nitrogen.

ii. Floating roof type tank

These tanks are used for storing highly volatile products. They are vertical cylinder vessels having a roof, which normally floats on oil. In absence of stored oil, it rests on its legs. The other accessories are similar to that of fixed roof type. Haldia Refinery generally uses “Pontoon" type floating roofs. Other possible forms are double deck and pan type.

CALIBRATION OF TANKS:

All tanks for storing petroleum products are calibrated to have measurement of volume in terms of the level of liquid in the tank.

This height is measured along the vertical distance between a reference mark and the striking point on the tank floor, viz. datum plane. A calibration table is prepared for liquid volumes inside the tank at various heights after making

allowance for the volume displaced by the roof supports and the submerged portion of the pontoon ( for floating roof tanks only ) , heating coils and other fittings inside the tank .

Generally, the tanks are calibrated as per ISI standard. Tanks are calibrated by CPWD Engineers.

The measurement of petroleum involves three operations

i) Gauging the tanks

ii) Recording the temperature of the product

iii) Drawing a representative sample of the product

BITUMEN FILLING STATION: IOCL Haldia Refinery mainly produces straight grade bitumen ; 10- viscosity grade & 30- viscosity grade.

Bitumen filled by two methods: 1) bulk filling 2) drum filling

The temperature in the drum filling is kept low to diminish the problem of loading. This reduction in temperature is reduced by steam ejectors and heat exchangers.

The instruments used for filling:

1) Pump

2) Air control filling machine

3) Conveyor system

4) Valves

The capacity of vessels:

Drum - 150 kg net

Truck - 15-16 metric tons or more maximum up to 20 metric tons.

Diesel is used for maintaining the smoothness of the conveyor belt and removes the accumulation of bitumen in belt.

Capping machine is used for sealing the drum.

A special machine called Fork lift is used which can move 3-4 drum form the loading station to the field where it is stored.

The loading is controlled by several sensors which enable the empty drum to be placed at the proper level below the discharge pipe, proper positioning of the empty drum on the conveyor at the proper level below the discharge pipe and the exact amount of bitumen to be filled into each tank.

A total of 18,000 MT/a of bitumen are produced in Haldia Refinery.

TANKER TRUCK LOADING ( TTL ) UNIT :This is the unit where trucks and tankers are loaded with various finished products. There are 14 bays and each of these bays is used for loading trucks with one or two types of fuel. The products from the corresponding bays are:

Bay Products1 Aviation Turbine Fuel2 Naphtha3 Motor Spirit4 Aviation Turbine Fuel/PGMS5 Superior Kerosene Oil6 Superior Kerosene Oil7 Jute Batching Oil8 Jute Batching Oil9 High Speed Diesel

10 High Speed Diesel11 Aviation Turbine Fuel12 Furnace Oil13 Furnace Oil/Carbon Black Feed Stock

14 Furnace Oil

The loading is done mainly through automation. Some parts are done manually when required. The instrument used is MERCURY METER and PD METER (volumetric flow meter). The capacity of tank filled here are within 3000-6000 lt.

LIQUIFIED PETROLEUM GAS (LPG) STORAGE:INTRODUCTION TO LIQUIFIED PETROLEUM GAS (LPG) :

LPG is a mixture of mainly propane and butane including unsaturated hydrocarbons like propylene and butylenes. As per Indian Standard specification; it is characterized as:

a) Commercial butane

b) Commercial propane

c) Commercial propane & butane mixture

It is produced from processing of petroleum under pressure in liquid state. LPG is highly flammable. It is used as a domestic fuel for cooking. It also used for industrial purpose.

Handling of LPG requires basic knowledge of the nature and properties of LPG & constant vigilance with the knowledge and experience. LPG is compressed into liquid state for ease in storage and handling.

CHARACTERISTICS OF LIQUIFIED PETROLEUM GAS (LPG) :

a) It contains mainly C3 & C4 and unsaturated hydrocarbons like propylene and butylenes.

b) It has a typical vapour pressure of 7-8 kg/cm2 at 380C and density 0.54 gm/cc to 0.55 gm/cc.

c) At normal atmospheric pressure LPG exists as vapour, where it is in liquid state when stored under pressure in LPG storage vessels and cylinders.

d) In case of leakage to atmosphere the LPG vaporizes rapidly. This is a potentially dangerous situation as the spilling LPG vapour can get ignited from any source of ignition. In case liquid LPG spills out of container it vaporizes into very large volume i.e. over 250 times.

e) While evaporation, liquid LPG picks up heat from the surroundings and cools down; moisture present around it condenses.

f) LPG is heavier than air.

g) It is colourless in liquid and in vapour phase.

h) It is practically odourless. For easy leak detection Ethyl Marcaptan an odorant is added.

i) Small quantity of its vapour in air can form a flammable and explosive mixture.

j) When vaporized it leaves little or no residue.

SOURCES OF LPG IN HALDIA REFINERY:

UNITS UNIT NUMBER QUANTITY(m3/hr)CRUDE DISTILLATION UNIT-1 11 8-16

CRUDE DISTILLATION UNIT-2 16 5-12

FLUIDISED CATALYTIC CRACKING UNIT

18 28-32

MOTOR SPEED QUALITY CONTROL

86 1.5-3

A very small quantity is also produced from Hydro cracker Unit (HDCU)-unit91.

TYPES OF LPG:

TYPESFACTORS

STRAIGHT RUN CRACKED

PROPERTIES High octane number. Lower calorific value

as compared to cracked LPG.

Comparatively low octane number.

Higher calorific value.

USES Used as Auto LPG. For domestic use & commercial purposes.

LPG RECEIPT AND STORAGE:

The LPG produced from the above mentioned sources is collected and stored in LPG Storage Section. Well built pipe-lines with effective control valves, are used for transfer of LPG from the respective sources in the plant. In Haldia Refinery the storage equipments for LPG are:

a) Bullets

b) Horton Spheres

c) Mounded Bullets

All these storage units have : Two safety valves, pressure & temperature gauge, and have three control lines – inlet line, outlet line, vapour balance line.

STORAGE UNITS:

UNITS VOLUME OF EACH UNIT (m3) NUMBER OF EACH UNIT

BULLET 150 6

HORTON SPHERE 1500 4

MOUNDED BULLET 1500 3

Bullets

Bullets are long cylindrical shaped storage vessels. They are somewhat like pressure vessel, and maintain vapour liquid equilibrium inside it.

Horton Spheres

These are large spheres of 1500 m3 capacity used in Haldia Refinery of IOCL for storage of LPG.

The significance of the design of Horton spheres are:

(i) The spherical shape ensures less vapour formation since least area is provided, for same volume of liquid LPG, as compared with the other shapes of containers. Thus minimizing pressure build up inside the spheres and reducing chances of enormous explosions.

(ii) Uniform pressure distribution.

With these significances, Horton spheres stand as a more effective storage facility than Bullets. But it was seen that a problem arose as the supportive legs of the Horton spheres are susceptible to breakage.

Mounded Bullets

Mounded Bullet storage comprises a cylindrical shaped vessel surrounded by stones, sand, etc. to absorb the impact of any accidental explosion. It also does not have the problem of support as there was in Horton spheres. With 59m length, 6m diameter and 1500m3 capacity of the cylindrical vessel, Haldia refinery of IOCL has 3 such mounded bullets. Its design pressure is about (14.5kg/cm2) (g).

They are also subjected to cathodic protection to restrict rusting of the vessel body.

EFFLUENT TREATMENT PLANT (ETP):An effluent treatment plant has been installed for proper control of the unwanted material and for effective recovery of the oil. In ETP the TSS (Total suspended solid), BOD (Biological oxygen demand), COD (Chemical oxygen demand) of the water is properly regulated before water is discharged in the surroundings.

WASTE WATER COLLECTION SYSTEM IN HALDIA REFINERY:

The various liquid waste water from different units/areas in the refinery have been segregated into three basics streams .The segregation is based on the nature of waste water and the treatment require for the removal of the pollutants and contaminants from the waste water.

The waste water stream and there segregation as follows:

OILY SEWER:

The system is a broad network of the underground pipes (RCC/CS).The network covers whole refinery. It collects oil-water mixture from the refinery and offsite areas and delivers it to the influent sump in Effluent Treatment Plant. The waste water is brought here by the pipelines and through tankers. The ETP is in the lower side and all the units are on the upside, thus the oil flows to this network by gravity.

STROM WATER SEWER:

This system is a open channel network, this covers the whole refinery. The rain and the storm water are collected inside the dyke of the storage tank and drained to the network of ETP while draining this water also sometimes get mix up with the oil which is separated in this unit.

DOMESTIC SEWRAGE:

All the sanitary from toilets and the canteens provided in the refinery (including the administrative building) are connected to this system. This connection is made partly by gravity and partly by pumping.

FACTORS CAUSING WATER POLLUTION AT HALDIA REFINERY AND ITS EFFECTS:

1) OIL:

By the refinery operations, oil from various units, various tanks, loading areas get mixed up with water.

The oil has following effects:

i) It gives an unpleasant odour, colour to the water.

ii) Cannot be used for various purposes in industry and domestic use.

iii) When discharged in river it reduces algae, destroys the water plants and thereby reduces the fish food supply.

iv) Reduces the photosynthesis and the absorption of oxygen from atmosphere.

v) Affects the water life.

vi) Affects the human life when consumed.

Components in oil causing pollution:

a)Phenols:

This are generally the compounds which are produced during the cracking process in the reformer, visbreaking unit etc. Phenol is present in very low quantity in cru- ed oil also. Although present in very low amount it causes pollution. This gives unpleasant odour & toxic to human beings when consumed.

b) Sulphides:

The waste water generated at the distillation unit , visbreaker sour water stripper, kero hydro desulphurisation unit, Hydro finishing unit, spent caustic generated at

caustic wash and merox unit and crude oil tank draining sulphides. The effects of the sulphides are: causes bad odour, corrosive nature, reduces the oxygen in water by rapid consumption leading to death of water living organism.

c) Suspended solids:

These are the sand particles, silt, algae and some iron compounds. Effects of these suspended solids are: water becomes turbid, diminishes the sunlight penetration and thus reduces the photosynthesis and the replenishment of oxygen, deposition at the bottom affects the water bottom life.

d)Furfural:

The furfural is used in used in the FEU as solvent which at times it finds its way to water sewers. Its effects are: due to presence of this BOD/COD values will be high, the reduction of phenols, sulphides, oil in treatment plant becomes poor.

2) BIO-CHEMICAL OXYGEN DEMAND (BOD):

It is not a pollutant itself, but it’s a characteristic of water which in turn depends on other pollutant. The organism like bacteria and all other things in water utilizes dissolved oxygen in water for their respiration and multiplication. Thus there is loss of oxygen in water and this loss is normally made up by rearetion from atmosphere by using the aerobic bacteria. The water having pollutants will have high BOD value. Thus BOD is defined as the amount of oxygen expressed in milligrams per litre required to oxidize components of waste water biologically.

Effects of high BOD value are:

i) Survival of water bodies is endangered.

ii) The water bodies become anaerobic and give rise to smell.

iii) Water bodies become unfit for beneficial use

3) CHEMICAL OXYGEN DEMAND (COD):

The chemical oxygen demand (COD) test is commonly used to indirectly measure the amount of organic compounds in water. Most applications of COD determine the amount of organic pollutants found in surface water (e.g. lakes and rivers), making COD a useful measure of water quality. It is expressed in milligrams per

litre (mg/L), which indicates the mass of oxygen consumed per litre of solution. Older references may express the units as parts per million (ppm).

The difference between BOD & COD is only the testing method. In case of BOD testing, the oxygen requirements are determined by the use of bacteria & it takes 5 days for testing. However in case COD, the test method utilizes chemicals and hence can be completed in three hours. All impurities oxidized in the COD test may not be consumable by bacteria and COD values are always higher than BOD values.

EFFLUENT TREATMENT PRINCIPLES:

Treatment of the effluent from the various units of the whole chemical plant is given prodigious importance. The principle aim of ETP of Haldia Refinery is to obtain water which is recyclable for numerous purposes in the plant and also to make it safe for discharging in the outside environment. The effluent consisting of an emulsion of oil (form various units of plant) and water is treated via a series of unit operation mainly clarification and continuous settling. Effective chemical and biological treatments are also done to render flocculation, lowering BOD & COD of the water. These treatments have been described in the upcoming section.

The Haldia Refinery of IOCL has two sets of ETP: one which has been under operation for many years since its establishment while the other is a modernized plant, with employment of the latest methods of separation of oil water emulsion. The underlying principle of operation being the same, the two Effluent Treatment Plants differs in few unit operations and the types of equipments which have been installed.

The steps in waste water treatment are as follows:

a) Physical Treatment

b) Chemical Treatment

c) Biological Treatment

The reference flow sheet for the Effluent Treatment Plant (ETP): Fig-

PROCESS DESCRIPTION:

a) Physical Treatment:

Water waste of refinery contains coarse suspended and floating solids, oils etc. settle able pollutants. These need to be removed before the waste water is subjected to chemical and biological treatment. By physical treatment the pollutants are removed. Rakes and screens, grinder, grid chamber, grease traps, flocculation, sedimentation, sludge pumping etc. are common physical treatment operations. In Haldia Refinery, bar screen, wire mesh, and API Separator (in case of modernized installation Tilted Plate interceptor) are used for purpose of physical treatment. Effluent is first admitted through bar screen and then wire mesh where debris, rags etc. are removed & then sent through grid chamber to settle out suspended solids. The purpose of these two equipments is to protect the downstream mechanical equipment and avoid deposition in sumps and channels. The waste water with free oil and sludge is then routed through the API separators and then the primary sedimentation equipment. Here the velocity of the influent is slowed down considerably, at such a low velocity, the suspended particles of higher density are made to settle down and the oil of low density floats. In API around 50% to 60% of suspended solids are removed and 20% to 40% of the BOD at 20oC is achieved.

b) Chemical Treatment:

Chemical treatment followed by physical treatment reduces colloidal solids, inorganic chemicals, some portion of organic chemicals and the remaining suspending solids of the effluent.

Important unit operations and processes which are used for this purpose are:

i) Chemical coagulation, flocculation and sedimentation

ii) Filtration

iii) Ion exchange

iv) Reverse osmosis

v) Carbon adsorption

In Haldia refinery method number (i) along with oxidation of chemical both organic and inorganic (especially sulphide and phenolic compound) by chlorine is followed. Coagulation is the process in which chemical which is termed as coagulant are added to an aqueous system to create rapidly settling aggregate out of present. Flocculation is the second stage in the formation of this aggregate

which is achieved by gentle and prolonged mixing. Over here coagulation occurs in pre-aeration chamber. [the coagulant] solution and lime solution are added in pre-aeration chamber. Positively charged iron ions neutralize the negative charges of emulsified oil and hence releases the oil from water. These iron ions are hydrolyzed by hydroxides [like ] to form flocs. Dissolved in the effluent oxidizes the to flocs which settles at faster rate than . For highest efficiency a rapid and intimate mixing of

/ flocs with effluent is necessary before flocculation process begins, which is done in flash mixer chamber where a motor driven stirrer is rotating continuously.

Flocs so formed are too light to settle under gravity, thus from the flash mixer chamber the effluent goes to clariflocculator where slow stirring is done by two continuously rotating motor driven stirrer thus enabling flocculation i.e. agglomeration of small flocs. Entrainment and absorption of suspended particles (such as free oils, Fes etc.) occurs on the large surface area of the agglomerated

/ flocs which settle down at the clarifier zone of the clariflocculator.

c) Biological Treatment:

After physical and chemical treatment waste water is to biological treatment under aerobic condition (i.e. a condition denoting an excess of free dissolved oxygen (o2) in biological system) for further reduction of organic pollutant. The principles involved are to utilize naturally occurring bacteria to eat away or oxidize organic impurities there by reducing the concentration of pollutants. These bacteria simultaneously get biodegraded. The excess of bacteria is removed from the system periodically. The basic biochemical reaction for the stabilization of organic impurities under aerobic condition by micro-organisms in waste water is as follows:

The common systems for biological treatment are Trickling filter and Activated sludge tank also called as aeration tank or bio-reactor. Both are used in Haldia refinery.

In case of trickling filter (bio filter) system, waste water is sprayed on bed of stones. The aeration is form on the bottom of the stones upwards, due to

Organic impurities + microbes + O2 A more microbes +CO2 +H2O +waste energy

temperature difference of water and the ambient air, bacteria grows on the stone surface as a film which eats away organic impurities. These bacteria decay and wash out periodically. Fresh bacteria grow again on the stones.

In case of activated sludge tank, the bacteria are continuously mixed with waste water and aerated by motor operated aerators. Here also bacteria eat away impurities. The bacteria water (mixed liquor) is then sent to clarifier from aeration tank where bacteria mass separated from water. The bacteria mass is recycled back to aeration tank to maintain required level of bacteria in aeration tank.

Fig: 15

The balance of bacteria is sent to biological sludge lagoons (this operation is done periodically) for disposal. The water from clarifier goes to treated water pond, ready for disposal to river.

The nutrient used in Bio-reactor is Urea.

AN OVERVIEW ON THE EQUIPMENTS USED:PUMPS: A pump is a device used to move fluids, such as liquids or slurries.

It is a device which increases the discharge pressure.

Various types of pumps used in the plant are:

Centrifugal pumps

Positive displacement pumps:

Under it there are :

- Reciprocating pumps

- Gear pumps

Screw pump

CENTRIFUGAL PUMPS:

CENTRIFUGAL PUMP

Fig: 16

A centrifugal pump is a rotodynamic pump that uses a rotating impeller to increase the pressure and flow rate of a fluid. Centrifugal pumps are the most common type of pump used to move liquids through a piping system. The fluid enters the pump impeller along or near to the rotating axis and is accelerated by the impeller, flowing radially outward or axially into a diffuser or volute chamber, from where it exits into the downstream piping system. Centrifugal pumps are typically used for large discharge through smaller heads.

POSITIVE DISPLACEMENT PUMPS:

A positive displacement pump causes a fluid to move by trapping a fixed amount of it then forcing (displacing) that trapped volume into the discharge pipe. A positive displacement pump can be further classified according to the mechanism used to move the fluid:

RECIPROCATING PUMPS:

Reciprocating pumps are those which cause the fluid to move using one or more oscillating pistons, plungers or membranes (diaphragms).

Reciprocating-type pumps require a system of suction and discharge valves to ensure that the fluid moves in a positive direction. Pumps in this category range from having "simplex" one cylinder, to in some cases "quad" four cylinders or more. Most reciprocating-type pumps are "duplex" (two) or "triplex" (three) cylinder.

RECIPROCATING PUMP

Fig: 17

Furthermore, they can be either "single acting" independent suction and discharge strokes or "double acting" suction and discharge in both directions. The pumps can be powered by air, steam or through a belt drive from an engine or motor. This type of pump was used extensively in the early days of steam propulsion (19th century) as boiler feed water pumps. Though still used today, reciprocating pumps are typically used for pumping highly viscous fluids including concrete and heavy oils and special applications demanding low flow rates against high resistance.

GEAR PUMP:

This uses two meshed gears rotating in a closely fitted casing. Fluid is pumped around the outer periphery by being trapped in the tooth spaces. It does not travel back on the meshed part, since the teeth mesh closely in the centre. Widely used on car engine oil pumps.

SCREW PUMP:

GEAR PUMP

Fig: 18

Screw pumps are rotary, positive displacement pumps that can have one or more screws to transfer high or low viscosity fluids along an axis. A classic example of screw pumps is the Archimedes screw pump that is still used in irrigation and agricultural applications.

Although progressive cavity pumps can be referred to as a single screw pumps, typically screw pumps have two or more intermeshing screws rotating axially clockwise or counterclockwise. Each screw thread is matched to carry a specific volume of fluid. Like gear pumps, screw pumps may include a stationary screw with a rotating screw or screws. Fluid is transferred through successive contact between the housing and the screw flights from one thread to the next. Geometries can vary. Screw pumps provide a specific volume with each cycle and can be dependable in metering applications.

It is used mainly in water and water treatment applications.

VALVES:Valves are devices which regulate flow of fluids (gases, liquids, fluidized solids, or slurries) by opening, closing, or partially obstructing various passageways. Valves are technically pipe fittings, but are usually discussed as a separate category. In an open valve, fluid flows in a direction from higher pressure to lower pressure.

Valves used in the plants can be categorized into:

Butterfly valve

Check valve

SCREW PUMP

Fig: 19

Control valve

Gate valve

Globe valve

BUTTERFLY VALVE:

A butterfly valve is a valve which can be used for isolating or regulating flow. The closing mechanism takes the form of a disk. Operation is similar to that of a ball valve, which allows for quick shut off. Butterfly valves are generally favored because they are lower in cost to other valve designs as well as being lighter in weight, meaning less support is required. The disc is positioned in the center of the pipe, passing through the disc is a rod connected to an actuator on the outside of the valve. Rotating the actuator turns the disc either parallel or perpendicular to the flow. Unlike a ball valve, the disc is always present within the flow; therefore a pressure drop is always induced in the flow, regardless of valve position.

A butterfly valve is from a family of valves called quarter-turn valves. The "butterfly" is a metal disc mounted on a rod. When the valve is closed, the disc is turned so that it completely blocks off the passageway. When the valve is fully open, the disc is rotated a quarter turn so that it allows an almost unrestricted passage of the fluid. The valve may also be opened incrementally to throttle flow.

CHECK VALVE:

BUTTERFLY VALVE

Fig: 20

A check valve, a valve which normally allows fluid (liquid or gas) to flow through it in only one direction.

Check valves are two-port valves, meaning they have two openings in the body, one for fluid to enter and the other for fluid to leave. There are various types of check valves used in a wide variety of applications. Check valves are often part of common household items. Although they are available in a wide range of sizes and costs, check valves generally are very small, simple, and/or inexpensive. Check valves work automatically and most are not controlled by a person or any external control; accordingly, most do not have any valve handle or stem. The bodies (external shells) of most check valves are made of plastic or metal.

An important concept in check valves is the cracking pressure which is the minimum upstream pressure at which the valve will operate. Typically the check valve is designed for and can therefore be specified for a specific cracking pressure.

Heart valves are essentially inlet and outlet check valves for the heart ventricles, since the ventricles act as a pump.

CONTROL VALVE:

Control valves are valves used to control conditions such as flow, pressure, temperature, and liquid level by fully or partially opening or closing in response to signals received from controllers that compare a "setpoint" to a "process variable" whose value is provided by sensors that monitor changes in such conditions.

CHECK VALVE

Fig: 21

The opening or closing of control valves is done by means of electrical, hydraulic or pneumatic systems. Positioners are used to control the opening or closing of the actuator based on Electric, or Pnuematic Signals. These control signals, traditionally based on 3-15psi (0.2-1.0bar), more common now are 4-20mA signals for industry, 0-10V for HVAC systems, & the introduction of "Smart" systems, HART, Fieldbus Foundation, & Profibus being the more common protocols.

GATE VALVE:

A gate valve, also known as a sluice valve, is a valve that opens by lifting a round or rectangular gate/wedge out of the path of the fluid. The distinct feature of a gate valve is the sealing surfaces between the gate and seats are planar, so gate valves are often used when a straight-line flow of fluid and minimum restriction is desired. The gate faces can form a wedge shape or they can be parallel. Typical gate valves should never be used for regulating flow, unless they are specifically designed for that purpose. On opening the gate valve, the flow path is enlarged in a highly nonlinear manner with respect to percent of opening. This means that flow rate does not change evenly with stem travel. Also, a partially open gate disk tends to vibrate from the fluid flow. Most of the flow change occurs near shutoff with a relatively high fluid velocity causing disk and seat wear and eventual leakage if used to regulate flow.

CONTROL VALVE

Fig: 22

Typical gate valves are designed to be fully opened or closed. When fully open, the typical gate valve has no obstruction in the flow path, resulting in very low friction loss.

Gate valves are characterized as having either a rising or a no rising stem. Rising stems provide a visual indication of valve position because the stem is attached to the gate such that the gate and stem rise and lower together as the valve is operated. No rising stem valves may have a pointer threaded onto the upper end of the stem to indicate valve position, since the gate travels up or down the stem on the threads without raising or lowering the stem.

GLOBE VALVE:

A globe valve is a type of valve used for regulating flow in a pipeline, consisting of a movable disk-type element and a stationary ring seat in a generally spherical body.

GATE VALVE

Fig: 23

Globe valves are named for their spherical body shape with the two halves of the body being separated by an internal baffle. This has an opening that forms a seat onto which a movable plug can be screwed in to close (or shut) the valve. The plug is also called a disc or disk. In globe valves, the plug is connected to a stem which is operated by screw action in manual valves. Typically, automated valves use sliding stems. Automated globe valves have a smooth stem rather than threaded and are opened and closed by an actuator assembly. When a globe valve is manually operated, the stem is turned by a hand wheel.

Globe valves are used for applications requiring throttling and frequent operation.

FURNACE:Furnaces are used in the plant mainly for heating the fuel oil, heating of air. A many number of furnaces are used in the plant. Some furnaces are side by side or divided by walls.

GLOBE VALVE

Fig: 24

Furnaces are of different types:

Induced draft furnace

Forced draft furnace

Mixed draft furnace

In the industry most of the furnaces were mixed draft furnace.

DESCRIPTION OF FURNACE USED:

The furnace use was mixed draft furnace.

This furnace comprises of:

Convection zone

Radiation zone

Induced draft fan

Forced draft fan

Damper

Duck

Burner

Pipelines for steam & fuel oil

ID FAN

AIR

PREH

EATI

NG

SE

CTIO

N

DAMPER

AIR TO FD

CONVECTION ZONE

In furnace first the air is preheated; as the temperature of air has to be increased for lesser consumption of fuel. The air required for burning is obtained via use of Force draft fan.

Damper is used in the chimney which controls the flow of flue gas.

Steam and fuel oil is passed which is used for heating the oil and air.

The flue gas generated is hot air so the heat of it is utilized for preheating of air. This is done by the use of Induced draft fan as shown in the figure.

In the furnace the heating is done in two zones;

Convection zone

Radiation zone

FD FAN

AIR

BURNER

FO STEAM

VALVES

DUCK

FURNACE WORKING LAYOUT

Fig: 25

RADIATION ZONE

FURNACE

FEED IN

FEED OUT

The crude or feed is first heated in convection zone where the heating first takes place through convection heat transfer from hot air to the oil.

Then the final heating is done in the radiation zone where the maximum heating is done as in this mode the heat transfer is maximum.

Various valves are used which controls the flow of the fuel oil and the steam.

HEAT EXCHANGERS: A heat exchanger is a device built for efficient heat transfer from one medium to another. The media may be separated by a solid wall, so that they never mix, or they may be in direct contact. They are widely used in space heating, refrigeration, air conditioning, power plants, chemical plants, petrochemical plants, petroleum refineries, natural gas processing, and sewage treatment.

In company mainly shell and tube heat exchangers are used.

Two fluids, of different starting temperatures, flow through the heat exchanger. One flows through the tubes (the tube side) and the other flows outside the tubes

SHELL AND TUBE HEAT EXCHANGERS

Fig: 26

but inside the shell (the shell side). Heat is transferred from one fluid to the other through the tube walls, either from tube side to shell side or vice versa. The fluids can be either liquids or gases on either the shell or the tube side. In order to transfer heat efficiently, a large heat transfer area should be used, leading to the use of many tubes. In this way, waste heat can be put to use. This is an efficient way to conserve energy.

Heat exchangers with only one phase (liquid or gas) on each side can be called one-phase or single-phase heat exchangers. Two-phase heat exchangers can be used to heat a liquid to boil it into a gas (vapor), sometimes called boilers, or cool a vapor to condense it into a liquid (called condensers), with the phase change usually occurring on the shell side. Boilers in steam engine locomotives are typically large, usually cylindrically-shaped shell-and-tube heat exchangers. In large power plants with steam-driven turbines, shell-and-tube surface condensers are used to condense the exhaust steam exiting the turbine into condensate water which is recycled back to be turned into steam in the steam generator.

Among shell and tube heat exchangers the different types are:

U tube heat exchangers. Straight tube heat exchanger- one pass and two pass.

Fig: 27

PIPELINES:Pipeline transport is the transportation of goods through a pipe. Most commonly, liquid and gases are sent, but pneumatic tubes that transport solid capsules using compressed air are also used.As for gases and liquids, any chemically stable substance can be sent through a pipeline. Therefore sewage, slurry, water, or even beer pipelines exist; but arguably the most valuable are those transporting fuels: oil (oleoduct), natural gas (gas grid) and biofuels.

Pipelines are mainly used for transportation of:

Water Crude oil

Fig: 28

Fig: 29

Hydrogen gas Finished product

Fig: 30

CONTROL SYSTEMS:In the plant two types of control system is mainly used:

1. Distributed control systems (DCS)

2. Programmable logic control (PLC)

DISTRIBUTED CONTROL SYSTEM (DCS):

A distributed control system (DCS) refers to a control system usually of a manufacturing system, process or any kind of dynamic system, in which the controller elements are not central in location (like the brain) but are distributed throughout the system with each component sub-system controlled by one or more controllers. The entire system of controllers is connected by networks for communicati communication and monitoring.

DCS is a very broad term used in a variety of industries, to monitor and control distributed equipment.

Electrical power grids Chemical industries Refineries Water management systems

AN OVERVIEW OF PIPELINES

A DCS typically uses custom designed processors as controllers and uses both proprietary interconnections and communications protocol for communication. Input and output modules form component parts of the DCS. Distributed Control Systems (DCSs) are dedicated systems used to control manufacturing processes that are continuous or batch-oriented, such as oil refining, petrochemicals, central station power generation, pharmaceuticals, food & beverage manufacturing, cement production, steelmaking, and papermaking. DCSs are connected to sensors and actuators and use setpoint control to control the flow of material through the plant. The most common example is a setpoint control loop consisting of a pressure sensor, controller, and control valve.

PROGRAMMABLE LOGIC CONTROL (PLC):

A programmable logic controller (PLC) or programmable controller is a digital computer used for automation of electromechanical processes, such as control of machinery on factory assembly lines, amusement rides, or lighting fixtures. PLCs are used in many industries and machines. Unlike general-purpose computers, the PLC is designed for multiple inputs and output arrangements, extended temperature ranges, immunity to electrical noise, and resistance to vibration and impact. Programs to control machine operation are typically stored in battery-backed or non-volatile memory. A PLC is an example of a real time system since

OVERVIEW OF DCS ARRAGEMENTS

Fig: 31

output results must be produced in response to input conditions within a bounded time, otherwise unintended operation will result.

CONCLUSION:CONCLUSION:

FCCU is the most profitable unit in refinery and CRU is the next more profitable.

A new Hydrocracker project is also under operation.

PLC ARRANGEMENTS

Fig: 32

LPG bottling plant has been shifted to outside in refinery for safety purpose.

INDIAN OIL supplies many products to Bharat petroleum and other petrochemical industry.

We gain knowledge on various instruments and processes that we have studied in our course curriculum.

Full plant is running on DCS system but some controls are also done by PLC systems.

The main profit of IOCL Haldia refinery comes from crystalline wax.

Haldia refinery does not produces lube oil they produce the LOB( lube oil base stock)

Another important product which only produced in Haldia refinery is RTF-Russian turbine fuel.

DECLARATION

It was a learning experience for us. Not only did we learn about the details of the refining processes but also acquired knowledge about the proper mechanical operations of various equipments. The training provided us with the insight of how a refinery operates with the proper co-ordination between the management and the grass root level.

ARKO PRATIM SEN

BIJIT BISWAS

KOUSHIKA SARKAR

SUBHASANKAR SAMANTA

SUDHANYA CHOUDHURI

Department Of Chemical Engineering

HALDIA INSTITUTE OF TECHNOLOGY